Filed by Entergy Corporation Pursuant to Rule 425
Under the Securities Act of 1933
Subject Company: Entergy Corporation
Commission File No. 001-11299
ENTERGY CORPORATION
Moderator: Paula Waters
10-29-13/10:00 am CT
Confirmation # 8044514
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ENTERGY CORPORATION
Moderator: Paula Waters
October 29, 2013
10:00 am CT
Operator: Good day everyone and welcome to the Entergy Corporation Third Quarter 2013 Earnings Release conference call. Today’s call is being recorded.
At this time for introductions and opening remarks, I would like to turn the conference over to Vice President of Investor Relations, Ms. Paula Waters. Please go ahead.
Paula Waters: 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 the shares of ITC common stock to be issued to Entergy shareholders in connection with the proposed transaction, and the registration statement was declared effective by the SEC on February 25, 2013.
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Moderator: Paula Waters
10-29-13/10:00 am CT
Confirmation # 8044514
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ITC is expected to file a post-effective amendment to the registration statement. 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 shareholders in connection with the proposed transactions.
This registration statement includes a prospectus of TransCo related to the proposed transactions. Entergy also will 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 registration statements, prospectuses and other documents referenced above when they are 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 obtained free of charge from the SEC’s Web site 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.
Leo Denault: Thanks Paula and good morning everyone. I’ve been talking a lot lately about simplification. In my remarks, I will review the major events of the past three months and how they relate to that objective.
ENTERGY CORPORATION
Moderator: Paula Waters
10-29-13/10:00 am CT
Confirmation # 8044514
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As I know many of you are well aware, especially given the number of other earnings calls scheduled this week, the annual Edison Electric Institute Financial Conference is just around the corner. As such, we will focus the call today on updating you on developments in the past three months and defer more strategic updates to the conference.
Starting with the proposed transaction to spin-off and merge the transmission business with ITC Holdings, in September, Entergy Texas and ITC re-filed our application for transaction approval before the Public Utility Commission of Texas, acting on the opportunity the commissioners gave us in the August 9 open meeting.
The re-filed application put in the record the enhanced rate mitigation plan that includes a benefits test and mitigation of 100% of the effects of the weighted average cost of capital for retail customers as well as other testimony quantifying the benefits to customers. The Texas commissioners agreed to hear the matter directly next month and briefing will end in December.
In Mississippi, briefing concluded at the end of September and an order is now pending from the Commission. In Louisiana, a revised procedural schedule was set to conclude briefing on November 8. In Arkansas and New Orleans, we are working with the parties to come up with a new schedule. Efforts were temporarily suspended during the quarter until the re-filing in Texas was made, and in Missouri an order is pending.
These schedules, once set in each of the jurisdictions, will provide more insight about the potential timeline for the transaction. A revised closing date in 2014 has not been settled upon. It will take at least 60 to 90 days after all regulatory approvals are received to close the transaction.
Clearly that puts any closing after December 31, after which our definitive agreement with ITC may be terminated by either party if the transaction has not been consummated. We continue to believe this strategic imperative to execute on the ITC transaction will result in optimal value for all stakeholders.
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Moderator: Paula Waters
10-29-13/10:00 am CT
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While our operating companies are fully capable to own and operate the transmissions system, we know ITC’s independence, broader regional planning and sole focus will improve the reliability of the grid, reduce congestion, attract new generating resources other companies may be hesitant to build today and provide our transmission employees better opportunities for their future.
These benefits will ultimately lead to lower delivered energy cost for our customers and our communities, promoting the economic good and helping to attract new businesses and industries to our region.
Under the proposed rate mitigation plan, the risk of delivering on these economic and operational benefits rests with the Entergy operating companies and ITC.
That said, we know clarity on the future direction of our transmission system is needed for everyone, and we are committed to that clarity by early next year at the latest.
Another key element in the simplification effort is to resolve ongoing rate proceedings in all of our retail jurisdictions. Rate cases are a basic part of our business, but we know the number of outstanding cases at one time creates uncertainty for all of you.
We received two orders in August, one in Mississippi and one in New Orleans, on formula rate plan filings. On August 13, the Mississippi Public Service Commission unanimously approved a stipulated settlement between staff and Entergy Mississippi, resolving the 2012 test year FRP.
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Moderator: Paula Waters
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The settlement called for a $22.3 million rate adjustment to be implemented over nine months starting in September. The rate change, the first in four years, provides funds necessary for increased reliability and capacity for economic growth.
Also in August, the city council of New Orleans approved a black box settlement for Entergy New Orleans 2011 test year FRP filing. Under the approved settlement, electric rates will decrease by $1.6 million, relative to pre-October 2012 rates. There was no change in gas rates.
This marks the fifth electric and/or gas rate decrease in the last five years. The next step in New Orleans is likely a base rate case filing in mid-2014. However, we intend to discuss with the council and their advisors various rate-making alternatives to a full base rate case. Last month’s planned rate case filing was temporarily delayed to allow time for such alternatives to be explored and discussed.
Next in Arkansas, a final decision in the Entergy Arkansas rate case is expected by year end from the Arkansas Public Service Commission. Entergy Arkansas’ most recent filing in the scenario of joining the Midcontinent Independent System Operator only, reflected a $145 million base rate increase at a 10.4% ROE. About $49 million of the increase in base rates is a transfer of revenue already being recovered through riders that will terminate.
Regarding pending rate cases before the Louisiana Public Service Commission, we expect resolution by May of 2014. As a reminder, filings made in February requested base rate increases for the MISO-only scenario of $144 million for Entergy Louisiana and $24 million for Entergy Gulf States Louisiana. Both cases reflected a 10.4% ROE.
Entergy Louisiana and Entergy Gulf States Louisiana have agreed to delay testimony in both cases until later in November and early December, respectively, in order to continue to explore settlement options.
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Moderator: Paula Waters
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Confirmation # 8044514
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And in the case of Louisiana’s Algiers rate case before the city council, the advisors will file testimony in November. The final decision is expected by second quarter 2014.
Recall Entergy Louisiana requested a $13 million base rate increase to be implemented over three years and a 10.4% ROE. This would be the first rate change in 12 years for the roughly 22,000 Entergy Louisiana customers located in the city of New Orleans and regulated by the city council.
This past quarter in Texas, Entergy Texas filed a request for a $38.6 million base rate increase, excluding new riders, and a 10.4% ROE. The test year in the 2013 rate case includes the majority of the third-party capacity costs disallowed in the 2011 rate case.
In addition, through a special circumstances request in the fuel and purchased power reconciliation, Entergy Texas is requesting recovery of approximately $21.5 million in capacity costs incurred from July 2011 through March 2013 not previously recovered in base rates. If approved, new rates go into effect as early as April of 2014.
Successfully clearing the decks of the majority of these rate cases by early next year is a key part of the simplification effort underway.
The system agreement is another area of complexity for all of us. Entergy Arkansas’ participation will terminate in December on the same day we plan to begin operating in MISO, followed by EMI’s exit in November of 2015.
Earlier this month on October 18, Entergy Texas provided its notice to terminate its participation in the system agreement, including filing it with the Federal Energy Regulatory Commission.
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Moderator: Paula Waters
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Prior to that on October 11, Entergy Services filed with FERC a change to the system agreement exit notice provision to 60 months from 96 months. FERC acceptance of the change in the notice period is required for it to become effective.
The FERC filing contemplates that the 60-month notice period will apply to ETI. Similarly, Entergy Texas’s notice contemplates that it will be governed by the 60-month notice period or such other period as approved by FERC.
The proposed amendment and ETI’s termination notice are without prejudice to continuing efforts among affected operating companies and their retail regulators to search for a consensual means of allowing ETI an early exit from the system agreement, which could be different from that proposed in the October 11 FERC filing.
Given that after the Entergy Texas exit, there will be only the three Louisiana-based operating companies remaining, it is reasonable to question whether the system agreement should remain in place.
The interpretation of the system agreement has been a constant source of litigation and complexity over the last 30 years. Addressing this will simplify and eliminate the uncertainty it has created for us as well as all of you.
Turning to EWC, improving results is a strategic imperative we have discussed throughout the year. Last quarter marks two steps in that ongoing effort.
First, in August Entergy signed agreements to sell Entergy Solutions District Energy to Brookfield Infrastructure for approximately $130 million. This was a small business you may not have even known we had.
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Moderator: Paula Waters
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The book value was approximately $100 million at September 30. It provides chilled water and steam to customers in Houston and New Orleans, a solid business with growth opportunities better suited in a larger portfolio that can capitalize on those opportunities for customers and our employees. Closing is expected by the fourth quarter.
Also in August we announced a decision to close the Vermont Yankee nuclear plant at the end of its current operating cycle. I can tell you the board of directors and the executive management team thoroughly reviewed all alternatives in coming to this difficult decision.
The employees at the plant operate it at world-class levels. In the decade of our ownership, Vermont Yankee has averaged a 92.4% capacity factor and it is currently in its fourth breaker-to-breaker run in that ten-year period.
While the plant had its opponents, we know the closure will be devastating to the community, including millions of dollars in taxes and other payments annually.
I want to personally thank all those who have stood by our side over the years. Operating through fourth quarter next year allows the immensely talented, dedicated and loyal Vermont Yankee workforce the best opportunity to plan their future. It allows the communities to begin planning for a future without Vermont Yankee as an operating asset, and it allows us to plan for an orderly shutdown and decommissioning process.
Shortly after announcing the decision to close VY, we amended our Certificate of Public Good application to operate through December 31, 2014. The CPG decision is now pending before the Vermont Public Service Board.
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Moderator: Paula Waters
10-29-13/10:00 am CT
Confirmation # 8044514
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Another area of uncertainty that is likely to continue for some time is license renewal at Indian Point. Unit 2 entered the period of extended operations at midnight on September 28 and continued operating under the Nuclear Regulatory Commission’s timely renewal provision.
Indian Point filed a timely application in 2007 and as such is authorized to continue operating while license renewal matters remain pending. The same will be true for Unit 3 after December 2015 if license renewal is still pending at that time as we expect. Given the number of issues and parties involved, we currently project final resolution of Indian Point’s license renewal application to take until 2018.
Indian Point continues to be a vital component of the region’s power supply and we are committed to its continued and safe operation. We continue to believe it meets all the requirements for a renewed operating license.
Today Indian Point is necessary to meet the reliability needs of the grid. That was only further evidenced by FERC’s approval of the new Lower Hudson Valley capacity zone in August.
We continue to expect implementation of that zone by April of next year. Given the importance of Indian Point to New York, we understand the need for contingency planning. It’s a prudent utility practice.
We also agree with the state’s priorities for grid reliability, a clean environment, low-cost energy, local economic prosperity and the critical importance of safety and security of the plant. In our view, Indian Point is the best answer to meet all of those needs. We also know there are other opinions.
For those seeking Indian Point’s early retirement, we believe the best course of action is to find common resolution given the benefits the plant provides.
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Moderator: Paula Waters
10-29-13/10:00 am CT
Confirmation # 8044514
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The final topic I wanted to cover this morning is an update on our strategic imperative to optimize through Human Capital Management or what we call HCM.
After completing a redesign of our company in July efforts immediately turned to re-staffing the organization to fit the required needs and skill sets.
We are over 2/3 of the way through this re-staffing process. And we will complete it by year end.
This process is providing many employees opportunities to expand their knowledge, skills and experience.
Overall however we expect to eliminate approximately 800 positions, the majority by the end of the year.
Job reductions are a difficult but necessary result of a restructured design to make the long term fundamental improvements needed for the business and support adapting to the changing needs of the industry, maintaining reasonable rates at the Utility to benefit existing customers directly and indirectly by attracting new customers to the region and improving financial results at EWC for plants that are challenged in the current low commodity price environment.
Next year we will be fully engaged in making the new organizational vision a reality.
Given the progress to date we project savings both O&M and capital in the $200 million range in 2014. These savings estimates are incorporated in the 2014 earnings guidance initiated today the details of which Drew will review in a moment.
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Moderator: Paula Waters
10-29-13/10:00 am CT
Confirmation # 8044514
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We remain on track to get the full run rate of $200 million to $250 million in savings by 2016. And the total estimated cost to achieve these savings remains in the $145 million to $185 million range.
In closing I know it’s not news to any of you that we have a number of strategic imperatives underway enterprise-wide to address the challenges and opportunities facing us. Some of which have been under development for years like joining MISO, the imperative I didn’t go through in detail today.
Regarding MISO we believe we remain on track to begin operating in MISO on December 19 which we estimate will produce $1.4 billion in customer savings in the first decade.
These imperatives are the right thing to do. Simply put they are geared to improve cash flows and reduce risk.
Success will benefit all stakeholders whose futures are linked.
For our owners resolution of the current initiatives will help to clarify the future state and earnings and cash return opportunities and potential for both the Utility and EWC businesses reducing the range of uncertainty.
Operating more efficiently, reducing uncompensated risk and maintaining financial strength supports continued safe, secure and reliable electric and gas services at reasonable cost for our retail and wholesale customers.
Reliably delivered and reasonably priced electricity and gas helps to retain existing businesses and attract new ones to our communities.
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Moderator: Paula Waters
10-29-13/10:00 am CT
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This is particularly true in our Utility service territory today. The difference in worldwide oil and natural gas prices as well as other regional advantages has led to a window of opportunity.
There is now a $65 billion plus economic development pipeline of industrial projects in our four state region.
Helping to bring economic development to our Gulf region creates a multiplier effect of benefits to our communities.
In addition financial strength enables us to continue to provide philanthropy, volunteerism and advocacy in the communities we serve.
And for employees working for a solid company offers better financial security to them and their families, facilitates a productive day to day work environment and offers career advancement opportunities.
That is the mission of Entergy to create sustainable value for all of our stakeholders. Closing out strategic imperatives and simplifying our business will help us in that regard.
We’ve made some progress but more work is to be done. And now I’ll turn the call over to Drew.
Drew Marsh: Thank you Leo and good morning everyone. In my remarks today I will cover financial results for the quarter, 2014 earnings guidance and other forward-looking financial updates starting with the quarterly financial results.
Slide 2 summarizes third quarter 2013 results on an as reported and an operational basis. Operational earnings per share were $2.41 versus $1.95 a year ago.
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Moderator: Paula Waters
10-29-13/10:00 am CT
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Third quarter as reported earnings in both periods included special items for expenses associated with the decision to close Vermont Yankee and implementation of Human Capital Management imperative in 2013 as well as the spin merge of the transmission business of ITC in both 2012 and 2013.
The decision to close Vermont Yankee in third quarter 2013 resulted in a non-cash impairment of the carrying values of VY and related assets to the fair value of $62 million as well as other related charges including the effect of capital spending not chargeable to expense because of the plant’s shortened life.
Going forward we will continue to classify VY’s capital spending as operating expense and it will be reported as part of the asset impairment and related charges line item.
And we will include this expense as well as any VY severance and retention expenses as special items this year and next.
Slide 3 summarizes operational earnings per share by business segment including major drivers of period over period variances.
Third quarter operational earnings per share were higher than the same quarter last year. Results at Utility and Parent & Other increased while EWC results declined.
Utility operational earnings were $2.04 per share. This is higher than $1.72 earned in the third quarter of last year.
The overall increase was driven by higher net revenue, the lower effective income tax rate partially offset by higher non-fuel O&M and higher depreciation expense.
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Utility net revenue increased due to price and volume factors.
As we noted in previous quarters pricing adjustments included regulatory actions for productive generation investments placed in service in 2012.
These investments benefit customers through improved operational efficiency and a favorable environmental profile.
On a weather-adjusted basis billed retail sales increased quarter over quarter. The increase was driven by growth in the industrial customer class which is 2.7% higher than the same quarter a year ago.
The industrial sales increase was due primarily to growth in the chemicals and refining segments. The majority of the increase in the chemical segment was from chlor-alkali facilities as temporary weakness this past spring abated in part due to stronger global economic growth and in part due to demand pulls in the improving real estate and auto sectors.
The refining segment also benefited from an increase in exports. Residential and commercial sales results from the quarter reflect continued challenges from sluggish regional economic growth, increasing emphasis on energy efficiency and demand side management programs.
Moving away from the topline the effective income tax rate for the Utility was lower in the quarter compared to the same quarter a year ago.
In the current period we had favorable settlement in state income tax audits.
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This resulted in in the reversal of previously reported expense. Partially offsetting the overall Utility operational earnings increase were higher nonfuel operations and maintenance and depreciation expenses.
A portion of these expenses reflected investments placed in service in 2012 that were offset in net revenue. Other drivers contributed to the expense increases as well.
Details are provided in the Utilities section in Appendix B of our earnings release.
Before I move to EWC I’ll briefly discuss Parent & Other which had an operational loss of $0.09 per share compared to a loss of $0.26 per share in the same quarter last year.
The quarter over quarter improvement was driven by lower income tax expense due primarily to the planned utilization of Parent’s net operating loss.
The EWC operational earnings were $0.46 per share lower than the $0.49 per share in the third quarter last year.
The period over period decline was due partly to lower operational adjusted EBITDA which I’ll review shortly.
EWC results also reflected higher depreciation expense due to an item recorded in the prior period.
The overall earnings decrease was partially offset by a lower effective income tax rate on operational earnings. EWC’s effective income tax rate reflected resolution of a tax issue in the third quarter.
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Slide 4 summarizes EWC’s operational adjusted EBITDA for the third quarter of the current and prior years.
The $20 million decrease was due primarily to higher non-fuel O&M expense driven largely by increased pension expense.
EWC’s net revenue was flat quarter over quarter. The effects of higher capacity pricing offset other factors including lower energy pricing.
Slide 5 summarizes our operating cash flow performance. Operating cash flow was just under $1.1 billion for the quarter — $52 million higher than the same period a year ago. There were both positive and negative drivers.
One example on the positive side EAI received approximately $38 million from the Department of Energy for damages in their spent nuclear fuel disposal case.
The overall increase is partially offset by higher income tax payments.
Moving away from the quarterly results as part of today’s release we are providing forward-looking financial updates. Today’s updates include 2014 operational earnings guidance, our non-fuel O&M outlook and the preliminary three year capital plan.
You should note that our forward-looking financial updates reflect our business as it stands today. They do not reflect the proposed spinoff and merger with ITC which we continue to believe is in the best interest of all our stakeholders.
Slide 6 summarizes the 2014 operational earnings guidance we are initiating today at $4.60 to $5.40 per share.
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I wanted to highlight a few items beginning with the 2013 starting points. The business segment guidance midpoints have been adjusted consistent with current indications. The adjustments net to zero on a consolidated basis. Now let’s turn to 2014.
The Utility’s 2014 operational earnings guidance midpoint is $5.20 per share — $0.60 higher than the 2013 guidance midpoint.
The Utility’s 2014 guidance midpoint was consistent with the previous five year financial outlook of 6% annual compound growth rate on net income from 2009 to 2014.
Among the drivers 2014 reflects significant progress on our Human Capital Management imperative or HCM.
As Leo mentioned we are estimating total savings of approximately $200 million in 2014.
Our current 2014 estimate reflects approximately $180 million in O&M savings with the balance going to capital.
The O&M portion is expected to be realized approximately $125 million at Utility and approximately $55 million at EWC.
For the Utility, HCM savings affects two line items in our guidance table. Obviously it will reduce non-fuel O&M. It also reduces net revenue to the extent projected savings flow through rates to benefit our customers.
Utility net revenue assumptions for 2014 also reflect the conclusion of current rate proceedings.
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Moderator: Paula Waters
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We currently have five base rate proceedings in process as well as other requests for riders to recover specific costs such as MISO expenses.
In addition Utility net revenue reflects approximately 1.9% retail sales growth driven largely by strong growth in the industrial customer class including planned expansions.
This reflects chlor-alkali and steel mill expansions expected to come online beginning in the fourth quarter of 2013 and refinery expansion coming online in mid-2014.
Sales growth excluding the effects from industrial expansions is anticipated to be approximately 0.6% including our expectation of renewed growth in the residential class.
We talked about the significant economic development activities in our service area. In fact just last week, Entergy Gulf States Louisiana announced another contract to provide up to 30 megawatts of power for at least ten years to Methanex’s new methanol facility in Geismar.
Our 2014 guidance reflects industrial growth that is well within our line of sight. Finally the Utility midpoint reflects an approximate 33% effective income tax rate in 2014.
When calculating the effective income tax rate of the Utility note that the dividend income of the affiliate preferred is nontaxable. It provides a structural reduction as illustrated in the 10K.
Considering that effect leaves an approximate 36% effective tax rate from expected income tax benefits included in our guidance.
Now let’s turn to EWC. EWC’s 2014 operational earnings guidance midpoint is $0.85 per share which also reflects the savings from HCM as I mentioned earlier.
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Moderator: Paula Waters
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EWC’s net revenue includes an assumption for improved capacity pricing from the new Lower Hudson Valley capacity zone.
The guidance midpoint assumes uplift relative to the Rest of State associated with the LHV capacity zone of approximately $3 per kW-month on an annualized basis.
The uplift assumption represents our risk-weighted point of view reflecting different scenarios to consider potential outcomes of various factors including reference unit technology, demand curve zero crossing point, locational capacity requirements and the potential for various mitigation outcomes.
As you know it is not our practice to incorporate our point of view into our forward-looking disclosures. However given the significance of the change, the near term timing of implementation and the lack of market information we decided that it would be appropriate to incorporate a price view for LHV.
We will revert to using forward market prices in our forward-looking statements once the market more fully forms up.
Another key driver in EWC’s 2014 guidance is depreciation expense which is higher by approximately $0.25 per share and will reflect the key considerations.
For Vermont Yankee the decision to shut down the plant earlier than previously expected will result in higher year over year depreciation for that plant of $0.04 per share in 2014. Growing depreciable plant balances associated with capital investments also contributes to higher depreciation expense.
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And finally, one thing that may not have been on your radar we periodically conduct depreciation rate studies. The year over year change reflects the estimated effect of revised depreciation rates based on a new depreciation rate study.
In 2014 this expected change accounts for approximately 2/3 of the total year over year change or about $0.17 per share and will continue into future years. Keep in mind that the change in depreciation expense does not affect EWC’s operational adjusted EBITDA.
Before leaving this slide there are a few general assumptions I’d like to mention. First, the consolidated 2014 guidance reflects an approximate 36% effective income tax rate.
Next, the 2014 midpoint also assumes the pension discount rate of 4.75% compared to 4.36% in 2013. The final pension expense for 2014 will be based on interest rates, market results and other assumptions that will not be available until early next year.
Finally, Section 6 of our earnings release where we outline 2014 earnings guidance includes additional details on key assumptions as well as earning sensitivities for 2014.
Today we’re also updating our non-fuel O&M outlook. As you can see on slide 7 we are estimating total operational non-fuel O&M, including refueling outage expense, to be approximately $3.5 billion in 2013 and $3.35 billion in 2014. These estimates include Vermont Yankee expense.
The amount of VY direct costs in the 2013 base year is approximately $145 million. This 2014 estimate is consistent with our 2014 guidance midpoint and reflects HCM savings as we previously discussed as well as other year over year changes.
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The three-year outlook indicates a compound annual growth rate of 0.5% to 2.5%. As you think about the current three-year view with VY ceasing operations by the end of 2014 the same range would apply to the 2013 base year but excluding VY direct costs from the base year. Just a reminder, the 0.5% to 2.5% is the three-year CAGR. Growth rates can vary from year to year.
Consistent with past practice, we’re also providing our preliminary three-year 2014-2016 capital plan in Appendix E of the release. You can see on slide 8 the preliminary plan totals $6.8 billion; roughly in line with the previous three-year period.
In closing, in a couple of weeks we’ll be at the EEI Financial Conference and will have the opportunity to meet with many of you. Needless to say, we as a company and as an industry have many topics to cover. While at EEI we’ll review some of the topics we’ve discussed today.
Overall topics we expect to discuss are current initiatives such as ITC, current regulatory dockets and rate cases and our Human Capital Management program. Other subjects include: Opportunities for our region’s economic development pipeline, investment opportunities at the Utility, efforts to improve EWC results and any other topics of interest.
I look forward to seeing you at EEI and now the Entergy team is available for questions.
Operator: If you would like to ask a question please signal by pressing star 1 on your telephone keypad. If you are using a speakerphone please make sure your mute function is turned off to allow your signal to reach our equipment. As a reminder, we ask that all participants limit themselves to one question and one follow up question. Again, press star 1 to ask a question.
And we will go first to Greg Gordon with ISI Group.
Greg Gordon: Thanks. My first question is on the expense outlook. So I know the guidance midpoint of $5 is unchanged from - but the components have changed significantly. And specifically the
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guidance midpoint at the beginning of the year for parent and other was 50 cents. It’s been rebased to 85 cents in the context of the current $5 guidance and rises to $1.05 next year. Can you take us through the progression from 50 cents to 85 cents to $1.05? And then I have a follow up.
Leo Denault: I’ll let Drew handle that, Greg.
Drew Marsh: Okay, well as you know…
Greg Gordon: Thank you.
Drew Marsh: …the parent and other is primarily comprised of interest expense and taxes. And of course there’s the affiliate-preferred expenses in there as well so that’s certainly contributing as that’s grown.
The primary thing to think about is the tax piece of this. And, you know, particularly as we move into 2014, you know, we have historically used a weighted average sort of probability expectation of what our income tax is.
And we’ve placed that in the parent at the beginning of the year given the uncertainty of where it may ultimately shake out. This year we have a better expectation of where it would probably land and that’s at the utility so, you know, we’ve highlighted some of those utility income tax benefits that I discussed a minute ago. That’s the primary driver that you see kind of moving forward.
Greg Gordon: Okay great. And then my follow up question is on the CAPEX guidance. It looks to me, based on where your 2014 rate bases are going to end up, based on looking at your rate case filings, etcetera, that at the level of CAPEX spending minus the level of depreciation you’ve laid out on your slides that the rate base growth profile looks like it’s more or less the same rate, i.e. around 6% that it had been in the past.
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So assuming consistent rate treatment wouldn’t it be fair to assume that your earnings growth aspiration would be consistent with that through ’16?
Leo Denault: You’re jumping ahead of us a little bit on that, Greg, in terms of providing any kind of forward looking outlook of - we’ll discuss a little bit of that when we get to EEI in terms of what the opportunities are going forward and where we see the utility. But right now we’re not really prepared to go out beyond 2014.
Greg Gordon: I’m sorry, but arithmetically - but arithmetically it looks like rate CAPEX minus depreciation you’re growing at about a 6% rate from ’14 to ’16 based on what you outlined, is that fair?
Leo Denault: You know, there’s other components of rate base. But, you know, the pieces you’re looking at have, you know, but there’s deferred taxes and other things that go into that - into that calculation as well. And I’m not trying to argue the math with you. And I apologize, I’m just not prepared to go beyond 2014 right now.
Greg Gordon: Okay, Leo. See you at EEI. Thanks.
Leo Denault: Sorry about that, Greg. I appreciate the question though.
Operator: And we will now go to Paul Patterson with Glenrock Associates.
Paul Patterson: Good morning. Can you hear me?
Leo Denault: Yes we can.
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Paul Patterson: Just wanted to touch base on the depreciation study. It sounded like quite a significant move in expected depreciation because of it. And I was just wondering if you could just elaborate a little bit more as to what went into that?
Leo Denault: Yeah, Drew…
Drew Marsh: Yeah, so, you know, we use a group method of depreciation which means that, you know, from time to time we have to do an updated depreciation study and to sort of reflect consistency with our actual experience.
And we alluded to it very briefly on the last call but didn’t really give it a full discussion. You know, ultimately the effect is to take away large increases that we would expect to see towards the end of life for the nuclear assets and sort of make the depreciation more ratable like you would expect under normal situations when you kind of go forward.
You know, as you think about depreciation it’s a zero sum game. You know, by the time you get to the end of the life of an asset you’re going to have to depreciate all of it and so we’re - it’s a little more ratable now with the new depreciation study.
Paul Patterson: Okay so we...
(Crosstalk)
Drew Marsh: And of course it doesn’t affect the cash flow at EWC.
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Paul Patterson: Okay so it would suggest that the detriment in value that we’d be seeing in later years is now being brought forward. And so I guess near term the EPS would be more conservative in terms of the value of those plants. Is that the way to think of it?
Drew Marsh: Yeah, on an EPS basis, yes.
Paul Patterson: Okay.
Drew Marsh: Not on an EBITDA basis. I think it would be about the same that we were seeing before.
Paul Patterson: Okay. And then moving to slide 18 on EBITDA basis you guys show an increase now in 2014 versus 2013 versus last quarter. And I was wondering you mention a few things on the slide, one of which has to do with Vermont Yankee. And I’m wondering whether or not the fuel expense is being reflected in EBITDA since the expense I believe is being amortized. That’s number one.
And then number two what’s leading to those changes? I mean, I realize that there’s a change in prices; that would be benefit I guess. If you could just elaborate, sort of just give us a little bit more quantification or sensitivity to that.
Drew Marsh: Well I’ll answer the first one, then I’ll turn the second one over to Bill. Fuel amortization is in the EBITDA number for Vermont Yankee.
Paul Patterson: So that’s being reflected in slide 18, the expense of fuel, the noncash expense of fuel?
Drew Marsh: Yes. You know, one thing to think about there is, you know, fuel is - as part of the write down you write down all of the assets at Vermont Yankee not just the actual plant itself. So it includes part of the fuel so you see the fuel going down as well there.
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Paul Patterson: Okay so that’s benefitting EBITDA?
Drew Marsh: Yes.
Paul Patterson: Okay.
Bill Mohl: As it relates to the revenue side of things from a capacity perspective Drew mentioned the fact that we, you know, included Lower Hudson Valley in our projections for 2014 basically assuming a $3 a kW-month increase over rest of state prices. So that’s included in our numbers here.
Paul Patterson: Was that a change from last quarter?
Bill Mohl: Yes. I think last quarter - we’ve typically been talking in a range of what we’ve expected. And I think even on the last call there was a little bit of confusion in terms of what was actually included. But in terms of how much was included over rest of state so this is much more specific that we’re including the $3/kW-month on an annualized basis for Lower Hudson Valley.
Drew Marsh: Right. And I’ll just add, Paul, that, you know, we have historically used market views. And there wasn’t a market view of Lower Hudson Valley. And so we didn’t have it, you know, what we had was effectively a rest of state view on our - at our last call. And so this time we are explicitly pointing out that we’re putting a point of view in place for Lower Hudson Valley since there’s no specific price targets out there. And we’ll go back to a market view once that develops.
Paul Patterson: Okay thanks a lot.
Leo Denault: Thank you.
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Operator: And once again, as a reminder, we ask all participants to limit themselves to one question and one follow up question. And we will now go to Jonathan Arnold with Deutsche Bank.
Jonathan Arnold: Good morning, guys.
Leo Denault: Good morning, Jonathan.
Jonathan Arnold: One question on VY, when you made the announcement about the shutdown you’d said it was expected to be sort of a negligible contribution to 2013 at the bottom line. So firstly I guess is that still the case? And then you’ve given us an EBITDA number for ’14 but with all these other moving parts can you kind of comment on sort of how much is the actual depreciation associated with VY in ’14? And what would your sort of net income type expectation be embedded in these numbers in ’14?
Leo Denault: I’ll let Drew answer it. Obviously when you say negligible in 2013 certainly the - on an operational basis it’s negligible. On an as-reported basis I wouldn’t necessarily call the impairment negligible. But…
(Crosstalk)
Jonathan Arnold: Okay fair enough, Leo. You said around breakeven operational…
(Crosstalk)
Leo Denault: Operational, operational.
Drew Marsh: That’s right. And I think that’s still - that’s still the case. You know, I think it’s a little better, as we’ve pointed out, because of like the fuel write down. And we’re seeing a little bit that in ’14. In
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’14 there’s a little more EBITDA pick up because of the fact that we’re not actually having a refueling outage in that particular year. And so - so that’s what your - that’s part of the driver for the improvement in EBITDA in ’14 which we wouldn’t have normal - otherwise seen under normal operating conditions.
Jonathan Arnold: Okay. And you attributed 4 cents of the 25 cent depreciation delta to VY. But can you give us the - what is the number as opposed to the delta?
Drew Marsh: I don’t have the exact depreciation for total VY in front of me but we can follow up with that offline.
Jonathan Arnold: Okay. And then just on one other topic if I may? You have - in the non-fuel O&M outlook slide - if we’re reading this rightly the 1/2 to 2 1/2%, you know, should be looked at, you know, net of the VY costs firstly is that correct? So…
Drew Marsh: Yeah, I mean, what we’re trying to point out is, you know, you could take the $145 million of direct costs out of sort of our base year of 2013. And you can still apply the 1/2 to 2 1/2% compound annual growth rate to that. And that would be sort of a revised view of where we might get to in 2016.
Jonathan Arnold: Okay. So if that holds though — looking at the slide — you have this step down in the underlying costs. And then you have - the CAGR is still up to 2 1/2% in 16. I mean when you do the math on - so what looks like a somewhat quantifiable step-down in 14 — to get to 2 1/2% growth CAGR for three years compound by 16, you’d have to have some pretty - some much higher percentages than that.
What kinds of things could drive you to the high end of the range - I guess is my question. Or am I missing something on the map?
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Drew Marsh: Yes. I think the big things are, like, pension expenses - could be a big driver, you know. If we were to acquire more assets within the utility — for example — you know, that certainly adds more O&M expenses. Those are the kinds of things that could drive it up, you know. If there are additional regulatory costs, you know, that’s something that’s certainly grown outside of, you know, typical inflation growth rates over the last few years. Those are the kinds of things that could push it up.
You know, given our current expectation, 2 1/2% is probably on the, you know, it is on the high side obviously. I don’t think under normal operating conditions we would expect to get all the way back to 2 1/2%. But those are the kind of things that we are trying to account for given the uncertainty associated with, you know, where the portfolio may go or where, you know, pension expenses may go. That kind of thing.
Jonathan Arnold: So it includes potential portfolio additions — that presumably would have revenues associated with it — at the high end?
Drew Marsh: Using two - yes, 2 1/2% is accounting for the possibility of that. That’s not to say that that’s what we are going out to do right now. It’s just within the range.
Jonathan Arnold: But in order for it to be that high, would it require that? Or is that do you just - I’m just not sure how significantly to take that as part of this answer.
Drew Marsh: I mean you are asking what could drive it up there. That’s what we were thinking about when we put a number out there like that.
Jonathan Arnold: Okay. Can you share with us what you’re trying to achieve? What’s your budget, you know, if not much else changed?
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Drew Marsh: Outside of the 1/2 to 2 1/2% growth area? I mean I think that’s where we are generally targeting. I mean that’s what our - we’re trying to achieve, you know, the low end of that range and, you know, and in an ideal world we might even beat it.
But that is - that’s where we were comfortable putting out our guidance on 14 to 16 CAGR.
Jonathan Arnold: Thank you very much, Drew.
Operator: And we will now go to Dan Eggers with Credit Suisse.
Dan Eggers: Hi. Good morning guys.
Group: Good morning, Dan.
Dan Eggers: Hey Leo — just catching on kind of your ends of the EWC comments, you know, it seemed like you made, you know, note of the idea of maybe trying to find some sort of settlement or resolution on Indian Point, you know, given the time horizon to license extension – that sort of stuff.
Can you, you know, maybe share some color on, you know, kind of what the tone or interest is on that and, you know, whether that’s something you can realistically get down, you know, in some sort of timely fashion?
Leo Denault: You know, really Dan all I’m trying to say is nothing different than what we’ve said before. We really view Indian Point as a high quality asset — very vital to the region — and certainly provides the majority of the benefits that you would like to see in a power market in the economic environment. It provides jobs, it provides tax base, it provides reliability to the grid, it provides low cost clean energy. It provides all the things, you know, from a public policy standpoint that you would want.
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And certainly we recognize that there are some folks who would like it to not operate to the end of its license life and, you know, that’s certainly not the opinion that we have. We think it’s vital — not only today — but it’ll continue to be a vital part of that market for years to come. We’re just acknowledging that we know other people have a different point of view.
And if there’s something there that could result in common ground — where we could come up with as we’ve talked about before — the certainty equivalent of value and glide path for the market — we’d be willing to do it. But there’s no more emphasis on it than that. You know, it’s just something that we’re willing to explore.
Dan Eggers: Okay. Got it. And then on the ITC, you know, process with — I guess the commissioner coming out on Friday and saying that, you know, a vote or decision couldn’t presumably happen until January given their scheduling — and how that, you know, corresponds to a year end, you know, merger agreement date. Would you guys need to formally extend the merger agreement to keep the deal going beyond December? Or can you guys, you know, kind of function in an at will basis, you know, pending more regulatory action?
Leo Denault: Technically the merger agreement allows either of us to terminate the transaction after December 31st. How we’ll handle going beyond December 31st will be dependent on seeing the rest of the procedural schedule, seeing what comes out, you know, of Arkansas and New Orleans — for example. And then, obviously, something that ITC and us will have to consider, but we’re not prepared to go there at the moment.
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Dan Eggers: But just — from a just a technical perspective, would you guys need to sign a new agreement to go beyond, you know, the year-end 2013 or could you guys function without an explicit, you know, time extension involved?
Leo Denault: Technically speaking, we would not have to amend the agreement.
Dan Eggers: Okay. Thank you very much.
Operator: And we will now go to Julien Dumoulin-Smith with UBS.
Julien Dumoulin-Smith: Hi. Good morning. Can you hear me?
Male: Yes we can. Good Morning Julien.
Julien Dumoulin-Smith: Excellent. Thank you. First, just with regards to the $5.20 at the regulated utilities next year, how do you think about that within the context of your earned ROEs overall? I appreciate that you have pending rate cases etcetera. But generally speaking would you say that you’re earning your ROE in that $5.20? I suppose that was contemplated in your initial 6% growth CAGR I suppose.
Leo Denault: I’ll let Theo talk about what’s going on at each of the utilities to the extent that he can.
Theo Bunting: Hey Julian, this is Theo. Actually I think the last comment you made probably speaks to the best way to describe - respond to your question. You know, I can’t talk specific — I won’t respond specifically to kind of what the assumption was, but obviously the growth assumption in 2014 is consistent with — obviously — all of our other planning assumptions.
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And as you look at 2014 and you see that our growth assumption hits the 6%, you know, you would expect that if your planning assumptions are aligned, then that would produce something that would be relatively within the range of what we would expect to achieve from our earned ROE perspective as it relates to our allowed ROE’s.
With that said, the 2014 [sic] rate cases obviously don’t go full - don’t go in effect at the beginning of the year in their entirety. Some go in effect later in the year. And also there is still some small element of regulatory lag — obviously since you file the cases — from the time you file until the time rates go into effect.
But obviously when you see the 6% growth aspiration and 2014 achieving that, you know, you would - I think you would also point - I think we would also say that that moves us closer to our goal — obviously — which is to, you know, earn our allowed ROE’s within the context of the utility.
Julien Dumoulin-Smith: Great. Thank you. And then with regards to the latest update on guidance — I suppose in the preliminary release suggests that it was towards the midpoint now — can you talk to what changes occurred in the quarter that led to that decision? I suppose specifically I suppose the district sale appears to be reflected in your adjusted EBITDA in 13. Just perhaps the various walk — if you will — to get to that - the I suppose revised range within the 13 range?
Leo Denault: We didn’t change the range Julien. You’re just talking about the fact that we said we should be around the midpoint?
Julien Dumoulin-Smith: Yes, indeed.
Leo Denault: Okay. Drew, I don’t…
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Drew Marsh: Yes. I don’t think - I think our suggestion before was that, you know, we weren’t - I think at the beginning of the year we were suggesting that we were at the lower end of the range. And I think the - maybe the - after the first quarter or the second quarter we said that we were, you know, no longer in the lower end of the range. And so now we’re just saying we’re in the middle.
So I don’t think that from our perspective, you know, we’ve really moved a whole lot. And so you’re right that the District Energy sale is reflected in there. It’s about 15 cents and so that’s part of the overall piece. But, you know, as may recall — from the beginning of the year — you know, on January 1st we had about a 20 cent deficit on the pensions that we had to overcome because interest rates fell so far toward the end of last year.
And so I think that if you look across the businesses, I think there’s gives and takes at EWC — for example — with, you know, higher pricing in the first half of the year on energy, higher capacity pricing through the middle of the year, but some reductions from a volume perspective. And at the utility — I think there has been a little bit of negative weather and that’s offset, you know, a little bit lower growth — well I shouldn’t say it’s offset — it’s a little - there was a little bit lower growth than maybe we expected at the beginning of the year that’s been offset by some tax benefits and some other things. So I think actually — and I’ll probably mention that too — on the tax side, you know, we guided you at the beginning of the year to about a 34% effective tax rate.
And while we expect to do a little bit better than that by the end of the year, you know, we expect to still be around that 34% effective tax rate range.
Julien Dumoulin-Smith: Great. Well, thank you for the detail.
Leo Denault: Thanks Julien.
Operator: And we will take our last question from Steven Fleishman with Wolfe Research.
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Steven Fleishman: Yes. Hi, good morning.
Leo Denault: Good morning Steve.
Steven Fleishman: Just I want to think a little bit about kind of utility net of parent drag. When you look at the guidance for 14 — like you said — the $5.20 utility, $1.05 of parent drag — that’s about $4.15 net. Is that a good clean base to think of kind of the future growth for the kind of core utility business?
Leo Denault: Drew, you want to?
Drew Marsh: You’re asking about the affiliate preferred elements of that, Steve?
Steven Fleishman: Not necessarily specifically. Let me ask the question this way — so your 2013 initial guidance had $4.70 for the utility, 50 cents of parent drag, so a net of $4.20. So even though the utility has gone up a lot, it’s been all kind of absorbed by - in the 14 guidance, a much bigger parent drag. So I just want to kind of think about a moving forward basis. Is this kind of a clean year for utility net of parent from which to really think about, you know, growing the company?
Drew Marsh: Yes. I mean I think - let me answer it this way. I mean beyond 2014, you know, we should have a pretty good view of our rate cases as Leo mentioned earlier. And so that part will come into play. The HCM program should be in full swing and, you know, we’re going to try and get a better view of, you know, what, you know, we can do, you know, maybe even beyond HCM going forward. You know, we’re beginning to work on that.
And then, you know, a big piece of what the storyline is going to be beyond 2014 is going to be the possibilities with industrial growth at the utility. And whether or not our historical load growth can actually begin to move at a higher rate than what we’ve seen — thanks to sort of the industrial renaissance. And I think we’re going to talk a little bit more about that at EEI when we get there.
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Steven Fleishman: Great. Thank you very much.
Leo Denault: Thanks Steve.
Operator: That concludes today’s question and answer session. Ms. Waters, at this time, we’ll turn the conference back to you for any additional or closing remarks.
Paula Waters: Thank you Angela 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 Statement.
Our call was recorded and can be accessed on our website or by dialing 719-457-0820, replay code 8044514. The recording will be available as soon as practical after the transcript is filed with the U.S. Securities and Exchange Commission due to filing requirements associated with the proposed spin-merge transaction with ITC.
The telephone replay will be available through November 5th 2013. This concludes our call. Thank you.
Operator: Ladies and gentlemen, this concludes today’s conference. We thank you for your participation.
END
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Additional Information and Where to Find It
ITC filed a registration statement on Form S-4 (Registration No. 333-184073) 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. This registration statement was declared effective by the SEC on Feb. 25, 2013. ITC is also expected to file a post-effective amendment to the above registration statement. 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) and any other relevant documents because they contain important information about TransCo and the proposed transactions. In addition, on July 24, 2013, Mid South TransCo LLC (“TransCo”) filed a registration statement on Form S-4/S-1 (Registration No. 333-190094) with the SEC registering the offer and sale of TransCo common units to be issued to Entergy shareholders in connection with the proposed transactions. This registration statement includes a prospectus of TransCo related to the proposed transactions. Entergy will file a tender offer statement on Schedule TO with the SEC related to the exchange of shares of Entergy common stock for the TransCo common units. Entergy shareholders are urged to read the prospectuses 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 Schedule TO (when available) and any other relevant documents because they contain important information about ITC, TransCo and the proposed transactions. The registration statements, prospectuses, tender offer statement and other documents relating to the proposed transactions (when they are available) can be obtained free of charge from the SEC’s website at www.sec.gov. The documents, when available, can also be obtained free of charge from Entergy upon written request to Entergy Corporation, Investor Relations, P.O. Box 61000, New Orleans, LA 70161 or by calling Entergy’s Investor Relations information line at 1-888-ENTERGY (368-3749), or from ITC upon written request to ITC Holdings Corp., Investor Relations, 27175 Energy Way, Novi, MI 48377 or by calling 248-946-3000.
Entergy Forward-Looking Information
In this communication, and from time to time, Entergy Corporation makes certain “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Except to the extent required by the federal securities laws, Entergy undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.
Forward-looking statements involve a number of risks and uncertainties. There are factors that could cause actual results to differ materially from those expressed or implied in the forward-looking statements, including (a) those factors discussed in this communication and in: (i) Entergy’s most recent Annual Report on Form 10-K, any subsequent Quarterly Reports on Form 10-Q and (ii) Entergy’s other reports and filings made under the Securities Exchange Act of 1934; (b) uncertainties associated with rate proceedings, formula rate plans and other cost recovery mechanisms; (c) uncertainties associated with efforts to remediate the effects of major storms and recover related restoration costs; (d) nuclear plant relicensing, operating and regulatory risks, including any changes resulting from the nuclear crisis in Japan following its catastrophic earthquake and tsunami; (e) legislative and regulatory actions and risks and uncertainties associated with claims or litigation by or against Entergy and its subsidiaries; (f) conditions in commodity and capital markets during the periods covered by the forward-looking statements, in addition to other factors described elsewhere in this communication and subsequent securities filings and (g) risks inherent in the proposed spin-off and subsequent merger of Entergy’s electric transmission business with a subsidiary of ITC Holdings Corp. Entergy cannot provide any assurances that the spin-off and merger transaction will be completed and cannot give any assurance as to the terms on which such transaction will be consummated. The spin-off and merger transaction is subject to certain conditions precedent, including regulatory approvals and the availability of financing.