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
07-31-12/10:00 am CT
Confirmation # 8666645
Page 1
ENTERGY CORPORATION
Moderator: Paula Waters
July 31, 2012
10:00 am CT
Operator: Please stand by. Good day everyone and welcome to the Entergy Corporation’s Second Quarter 2012 Earnings Release conference call.
Today’s call is being recorded. At this time for introductions and opening comments, I would like to turn the call over to the Vice President of Investor Relations, Ms. Paula Waters. Please go ahead.
Paula Waters: Good morning and thank you for joining us. We’ll begin this morning with comments from Entergy’s Chairman and CEO, Wayne Leonard. And then Leo Denault, our CFO, will review results.
In an effort to accommodate everyone with questions this morning, we request that each person ask no more than two questions.
As part of today’s conference call, Entergy Corporation makes certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements involve a number of risks and uncertainties and there are factors that could cause actual results to differ materially from those expressed or implied in the forward-looking statements. Additional information concerning these factors is included in the company’s SEC filings. Now I’ll turn the call over to Wayne.
ENTERGY CORPORATION
Moderator: Paula Waters
07-31-12/10:00 am CT
Confirmation # 8666645
Page 2
Wayne Leonard: Thanks Paula. Good morning everyone. I’ll start today with one of our key initiatives, the proposal for the utility operating companies to join the Midwest Independent Transmission System Operator, or MISO.
In May, the Louisiana Public Service Commission became the first retail regulator to approve, subject to certain conditions, the proposal by Entergy Louisiana and Entergy Gulf States Louisiana to transfer functional control of their transmission facilities to the MISO Regional Transmission Organization.
MISO change of control proceedings are in various stages of progress before retail regulators in Arkansas, Mississippi, New Orleans and Texas.
During the second quarter, the Arkansas Public Service general staff modified their position such that Entergy Arkansas should continue to progress toward joining MISO, and when certain conditions are met, the APSC would grant the full change of control.
An order from the Arkansas Public Service Commission could come at any time now. Testimony has been filed in the remaining three jurisdictions and subject to various conditions, commission staffs or the advisors and interveners in each proceeding generally have been supportive of, or at least have not expressed opposition to joining MISO, with the exception of course of the Southwest Power Pool.
We believe we should receive all the retail commission orders on MISO in 2012. Given this progress, final preparations are underway now to initiate the regulatory approval process with the proposed spin off and merger of the Entergy Operating Company’s transmission business with ITC Holdings Corp.
ENTERGY CORPORATION
Moderator: Paula Waters
07-31-12/10:00 am CT
Confirmation # 8666645
Page 3
The retail regulatory filings will describe, on both a qualitative and a quantitative basis, the benefits to customers and other stakeholders resulting from this superior, independent model for transmission operations that ITC provides as well as the improved financial flexibility and strength of the Entergy Utility Operating Companies following the completion of the transaction.
We expect to make the initial filings in Louisiana, followed by filings in other retail jurisdictions and at the Federal Energy Regulatory Commission over the next few months.
Concurrently, a fully functioning project management office is mapping out the processes, activities and plans for the targeted 2013 closing to assure a seamless transition.
In other Utility developments this quarter, Administrative Law Judges hearing the Entergy Texas rate case issued their Proposal for Decision in early July.
The ALJs recommended an overall $16.4 million base rate increase. However, the staff’s working papers that were used by the ALJs indicate an approximate $28.3 million retail base rate increase.
Further, the ALJs recommended a 9.8% allowed ROE. This compares to the adjusted $105 million base rate increase and ROE of 10.6% that was requested by Entergy Texas.
We should note that the recommendation affirmed in full Entergy Texas’ past fuel costs and made no adjustments to $408 million of the capital additions or over 99% of affiliate costs.
That is, the ALJs are not saying you are ineffective, inefficient, or imprudent.
ENTERGY CORPORATION
Moderator: Paula Waters
07-31-12/10:00 am CT
Confirmation # 8666645
Page 4
Instead the ALJs recommendation results from what we believe are misapplications of basic regulatory principles and practices. And these misapplications undermine the traditional ratemaking process and public policy objectives.
The end result makes it impossible for Entergy Texas to earn a fair return and that is a clear violation of some of the oldest, tested and affirmed principles of regulatory law, no matter how you get there.
In particular, we believe certain adjustments are clearly without basis or merit. For example, approximately $30 million of purchased capacity costs incurred after the end of the test year but in the allowed pro forma period when those rates will be in effect was suggested out with a sort of hyper-technical rationale that is at odds with the purpose of the regulation.
I won’t go through all the disagreements we have with the ALJs recommendation, but we strongly believe this is a fundamental misapplication of long-standing regulatory rules and practices in Texas, which provide for recovery of known and measurable costs.
Under the ALJ’s proposal, these non-fuel costs could not be recovered for up to two years. That is the time it takes to prepare and complete another rate case that includes a full year of the costs to be reflected in the test year itself. And if the timing isn’t perfect between the test year and historical costs, they may never be recovered.
That is why it is common practice in Texas and elsewhere to utilize pro-forma adjustments to the test year to eliminate discrepancies, particularly when you don’t use a formula rate plan or have extensive use of riders.
ENTERGY CORPORATION
Moderator: Paula Waters
07-31-12/10:00 am CT
Confirmation # 8666645
Page 5
Regarding regulatory decisions that discourage prudent capacity purchases that benefit customers, this will thwart the development of a robust, efficient, wholesale market if it’s allowed to stand.
A public utility must be afforded the opportunity not only of ensuring its financial integrity so that it can maintain its credit rating and attract additional capital as needed, but also of achieving returns on investment comparable to those of other companies having corresponding risk.
This is the law of the land. And it is without argument that the ALJ’s recommendation fails to acknowledge in any way how this proposal lines up against that basic litmus test.
The PUCT is scheduled to take up the proposal for decision making at the August 17 meeting. It is expected that a final decision will be made at this meeting, or by the next meeting on August 30 at the latest.
Entergy Texas has several other remedies available if the PUCT does not reverse the ALJ’s recommendation. Options include:
continuing to pursue the open rulemaking docket to establish a rider to recover capacity costs;.
filing for the authorized transmission and/or distribution riders to fully recover incremental investment costs above baselines set in this case;
preparing to file another base rate case if adequate recovery is not achieved in this proceeding; and of course, seeking relief through the legal process.
In Louisiana and New Orleans, annual formula rate plan filings were made in May. The Entergy New Orleans 2011 test year FRP filing reflected earnings below the bottom of the bandwidth, indicating a modest increase to electric and gas rates, totaling approximately $4 million.
ENTERGY CORPORATION
Moderator: Paula Waters
07-31-12/10:00 am CT
Confirmation # 8666645
Page 6
Entergy New Orleans also requested to accelerate funding of its cash storm reserves to allow it to meet the $75 million target by 2017 that was established by the City Council.
Under the FRP tariff, new rates would be effective in the first billing cycle in October. This year’s filing follows four straight years of rate decreases in New Orleans.
Even with these filed changes, electric rates for Entergy New Orleans customers would be nearly 20% below 2011 levels across the country for non-hydro and electric utilities.
Furthermore, rates for New Orleans customers would be among the five lowest in the country after factoring in a reasonable price for CO2 as a proxy for climate risk across the country.
The same general profile holds true for the rest of the operating companies explaining in part the strong economic development activity in our region.
The earned return reflected in the 2011 test year FRP filing for Entergy Gulf States Louisiana was above the bandwidth, indicating a cost of service decrease of $6.5 million.
In addition, the company is requesting adjustments outside the FRP primarily for lower capacity costs.
At Energy Louisiana the FRP filing reflected 2011 earnings consistent with the bandwidth and therefore no cost of service adjustments are necessary.
While Entergy Texas earned within its bandwidth with - or Entergy Louisiana, I’m sorry, earned within its bandwidth pursuant to the terms of the FRP. The company is requesting rate adjustments outside the FRP for capacity costs for PPAs not covered under the fuel clause.
ENTERGY CORPORATION
Moderator: Paula Waters
07-31-12/10:00 am CT
Confirmation # 8666645
Page 7
Both FRP filings with the LPSC are under review now, and the FRPs would require rate changes to be effective in September.
In addition, Entergy Louisiana’s recent FRP filing was supplemented to include the estimated first year impact of the Waterford 3 Generator Replacement Project.
Consistent with the previous LPSC order, rates will be updated upon completion of the project subject to a standard prudence review.
The Waterford 3 project continues to meet revised milestones to achieve the planned end of 2012 in service date. In early July, the steam generators arrived onsite. They are ready for installation during the fall refueling outage.
This Waterford 3 project is the second major capital project for the nuclear organization this year.
In the spring, the Extended Power Uprate project was installed at Grand Gulf during its refueling outage that concluded in June.
Plant personnel are in the process now of increasing production after achieving the Nuclear Regulatory Commission’s approval to operate at the higher power levels of 178 megawatts.
This 15% extended power uprate will make Grand Gulf the largest, single-unit nuclear plant of its type in the country.
One last comment relative to generation initiatives.
ENTERGY CORPORATION
Moderator: Paula Waters
07-31-12/10:00 am CT
Confirmation # 8666645
Page 8
In July, the APSC approved Entergy Arkansas’ request to acquire the Hot Spring power plant and to set a special rider to recover the costs at the 10.2% ROE established in the most recent rate case.
This follows the first quarter 2012 certification by the Mississippi Public Service Commission for Entergy Mississippi to acquire the Hinds plant. A separate proceeding on retail cost recovery remains pending in Mississippi.
Closing of the acquisition has been delayed pending U.S. Department of Justice review. We do not know where the DOJ is with its review of the transactions or to the extent to which its review has been or will be affected by the ongoing civil investigation of a competitive issues of the Utility Operating Companies.
The confidential nature of the DOJ review of the transactions and the civil investigation do not allow me to comment beyond the fact that the reviews are ongoing.
However, I can repeat that we believe the Operating Companies’ practices and policies at issue have satisfied all applicable laws and regulations.
In other Utility matters, last month the FERC issued a decision in the Entergy Arkansas opportunity sales case. As a reminder, this case concerns a limited amount of short-term wholesale energy sales, less than 1/2 of 1% of the total system sales to third parties from 2000 to 2009.
The FERC found that the sales in question were allowed under the system agreement, and made and priced in good faith but disagreed with after the fact accounting used to allocate the energy to supply those sales.
ENTERGY CORPORATION
Moderator: Paula Waters
07-31-12/10:00 am CT
Confirmation # 8666645
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We believe our actions were consistent with the system agreement, and as such have filed for re-hearing last week. FERC also set for hearing a separate proceeding to determine a re-allocation of costs among the Operating Companies consistent with its decision.
We have not completed the voluminous necessary calculations, and therefore, cannot quantify the effects of the re-allocation on individual Operating Companies at this time. We may not have a final FERC decision on this matter until 2014.
At Entergy Wholesale Commodities, the NRC renewed Pilgrim’s operating license through 2032 in late May, about two weeks before the original license was scheduled to expire.
The decision by the NRC came after an extensive and rigorous review spanning a 76-month period where the NRC spent more than 20,000 hours conducting inspections and reviews and soliciting active stakeholder participation.
The stated goal of the NRC is to complete these reviews in 30 months. While the Pilgrim license renewal was the longest to date, it is almost certain to be surpassed by the Indian Point process, given the number of issues and parties involved.
We filed the 20-year license renewal applications for Indian Point Units 2 and 3 in April 2007. The application date was more than five years before the expiration of the current operating licenses in September 2013 for Indian Point 2, and December 2015 for Unit 3.
And as such, meets the standard for the NRC’s timely renewal provision, which allows continued operation until the NRC takes action on the applications.
Current progress certainly points to timely renewal protection being applied for Indian Point 2 next year and likely for Indian Point 3 as well.
ENTERGY CORPORATION
Moderator: Paula Waters
07-31-12/10:00 am CT
Confirmation # 8666645
Page 10
Since 2007, the NRC issued the required safety evaluation report in 2009 and a supplemental environmental impact statement about a year later in 2010. Both these safety and environmental reports support issuance of the 20-year license renewal.
Supplements to these two reports are to be expected, as new regulatory guidance comes through to the NRC’s ongoing oversight as well as when open issues are resolved.
Safety report was first supplemented in August of last year. And another supplement is expected to be finalized by year-end. Around that time we’re expecting a finalized first supplement to the environmental report.
We do not expect any of these supplements to change the NRC Staff’s conclusion that there are no safety or environmental issues which would preclude the Indian Point units from operating safety for another 20 years.
The next milestone in the NRC process is the initial hearings before the Atomic Safety and Licensing Board scheduled to begin in October.
To date, the ASLB has submitted a total of 16 contentions, the most ever in a license renewal proceeding. And the ASLB is on track to hear possibly three to four times more contentions than have ever been heard in a license renewal proceeding.
Two contentions have been resolved, one in a settlement, the other in a commission order. Ten of the 14 remaining contentions are slighted for the Track 1 hearing this fall. No final schedule has been set for the remaining four issues.
ENTERGY CORPORATION
Moderator: Paula Waters
07-31-12/10:00 am CT
Confirmation # 8666645
Page 11
The NRC process allows for additional contentions to be filed after issuance of these supplemental reports, or after any new material information comes to light. And, as we’ve experienced in Pilgrim and Vermont Yankee, new contentions may be filed even after the record’s closed.
I won’t go over all the details of each contention. That would, well, take more time then you’ve got here today. But suffice it to say, these are complicated technical issues that take time to fully investigate, resolve and document.
The key takeaway from all this discussion is that the nature of the rigorous process before the NRC indicates it will be years until we reach final decisions before the Commission.
In conjunction with the NRC process, we also need resolution on the Water Quality Certification issue associated with the Clean Water Act and the Coastal Zone Management Act consistency determination.
On the first issue, last year we filed notice with the NRC that the New York State Department of Environmental Conservation - or DEC - had not issued a final decision on our Water Quality Certification application within the one-year time period that is required by law.
The NRC has not ruled on our filing, but if they agreed that a waiver has occurred that a new Water Quality Certification is not a requirement for the NRC’s issuance of Indian Point’s renewed licenses.
In any event, however, Indian Point must comply with New York Water Quality standards through the proceeding on the State Pollutant Discharge Elimination System permit, or SPDES.
ENTERGY CORPORATION
Moderator: Paula Waters
07-31-12/10:00 am CT
Confirmation # 8666645
Page 12
The department’s ALJ’s have combined the water quality certification and SPDES issues into one joint proceeding and are hearing that case in parallel with the NRC review of the waiver issue.
Hearings before the ALJs of the New York State DEC will resume this week regarding the best usages of the Hudson River and on the efficacy or performance of the wedgewire screen proposal that we’ve made.
These are just two of several issues in the water permitting and certification proceedings, but the central issue is the evaluation of what is the Best Technology Available, or BTA - operations with cooling towers or operations with our proposed wedgewire screen alternative.
And either of these options is required only if Indian Point is creating an adverse environmental impact, a point on which we obviously disagree with the state and that we have preserved for further litigation at a later date.
Portions of these proceedings date back to 2003 when the New York State DEC issued a draft SPDES permit for post license renewal periods suggesting cooling towers are BTA.
Since then, we filed expert testimony on how cooling towers don’t meet the BTA standards for a host of reasons, including that it is highly unlikely that cooling towers can even gain the required air permits or approval by local government due to zoning and other permitting issues.
And furthermore it is difficult to see how cooling towers could pass any reasonable cost benefit test compared to wedgewire screens, which the U.S. Supreme Court has ruled can be considered as an element of determining best technology available.
ENTERGY CORPORATION
Moderator: Paula Waters
07-31-12/10:00 am CT
Confirmation # 8666645
Page 13
Staff of the New York DEC has not yet filed its primary report or the basis for why they regard cooling towers as BTA. And no dates for hearing have been set for this threshold BTA issue to be argued in the sunshine before the assigned judges.
As it stands today we would expect these water quality proceedings to extend into at least 2013 and possibly well beyond that.
One last issue to report on water report. The first - the first gate under the law on water quality issues is whether Indian Point’s operation has an environmental impact on the Hudson River.
While the ALJ’s declined to hear this argument in this proceeding, it is fully supported by our research and evidence and ready to be presented on appeal should cooling towers somehow prevail in the joint water quality proceedings.
Secondly - and I know all of this starts to blend together over time as you hear this. But this is new and it’s certainly not trivial, so you might want to listen carefully.
Last week we filed with the NRC a supplement to the Indian Point license renewal application related to the state of New York’s requirement for a coastal zone management consistency determination under the federal Coastal Zone Management Act, or CZMA.
The supplement states that federal regulations make clear, given previous reviews of the Indian Point facilities, there is no need for a further state CZM review. And as a result, the NRC may issue the requested Indian Point renewed operating licenses without the need for an additional consistency review.
Let me amplify that point. Hang on just a second. Sorry - I’ve lost - I’ve lost about 10 pages of my script here.
ENTERGY CORPORATION
Moderator: Paula Waters
07-31-12/10:00 am CT
Confirmation # 8666645
Page 14
So let me amplify that point. The preambles of the federal regulations implementing the CZMA state, “In the event the state agency has previously reviewed a license or permit activity, further review is limited to cases where the activity will be modified substantially, causing new coastal zone effects.” That exception does not apply in the case of Indian Point since no change in operations is proposed for purposes of license renewal.
Prior CZMA consistency reviews were done for Unit Three and Unit Two in 2000 and 2001, respectively, when the New York Power Authority and Con Ed transferred ownership of the plants to Entergy.
In both instances, the state of New York determined that operation of the Indian Point facilities was consistent with the state’s Coastal Zone Management plan.
Based upon these and other prior reviews and the fact that it’s part of the license renewal proceedings, Indian Point’s continued operations will not be substantially different than when the prior reviews were conducted, we do not believe CZMA requires Indian Point to obtain another consistency review from the state of New York in connection with its license renewal applications.
In that - to that end, yesterday we filed with the ASLB a motion for declaratory order agreeing with our position. Responses by parties including the state of New York to our ASLB motion are due within 10 days, although extensions are possible.
We expect that once the parties have stated their positions the ASLB will set a process to resolve the issue and issue a decision. ASLB decisions are appealable to the Commissioners. But if not appealed, appealed, the decisions are final.
ENTERGY CORPORATION
Moderator: Paula Waters
07-31-12/10:00 am CT
Confirmation # 8666645
Page 15
In summary, we’ve made clear our position, supported by the expert opinion regarding the law and the consistency of prior reviews conducted on Indian Point that there is no basis to require a CZM determination as part of the license renewal process.
How and when the processes will advance from here will be determined by the ASLB. It’s important to keep in mind under federal regulations the NRC is the ultimate decision maker on whether changes have been made that warrant additional review.
As a reminder, the federal law also states as national policy the preference for continuing to use already developed areas - again, like the Indian Point facilities - instead of developing new greenfield areas within coastal zones.
And furthermore, New York State’s federally approved Coastal Management Program cites the location of nuclear facilities in the coastal zone - including Indian Point - as demonstrating the state’s recognition of the national interest of energy facilities.
Regarding that last point, there is good reason as to why Entergy Point serves the national interest. Indian Point is safe, secure and vital. It’s the only plant in the country to voluntarily submit to an extensive Blue Ribbon Panel audit, which it passed with flying colors in 2008. The conclusion of the panel of experts was unequivocal - Indian Point is a safe plant.
Before closing, I want to highlight a few recent awards recognizing the operational strengths of our organization. In a report issued by J.D. Powers and Associates earlier this month, all of Entergy’s Utility Operating Companies showed gains in the 2012 Electric Utility Residential Customer Satisfaction Study.
ENTERGY CORPORATION
Moderator: Paula Waters
07-31-12/10:00 am CT
Confirmation # 8666645
Page 16
In fact, Entergy New Orleans was named the most improved utility company. This contrasts to the results overall, where the National Customer Satisfaction Index declined by three points - the second consecutive year of decline.
The key factor for the industry, of course, was the negative impact on perception of power quality and reliability due to part - due in part to severe storms that affected several parts of the country.
In May, Nuclear operations once again received Top Industry Practice awards from the Nuclear Energy Institute for innovative improvements in cost and safety practices at Pilgrim and Arkansas Nuclear One. This is the tenth consecutive year we received nuclear honors in the NEI TIP’s award program.
And finally, I’m pleased to report that once again Entergy scored a perfect 10.0 global rating from GovernanceMetrics International in July 2012 for best-in-class corporate governance.
Entergy has maintained this rating in each of the quarterly periods since 2006, with the exception of one small dip in early 2011. Establishing stringent corporate governance standards and living up to them every day in everything we do is an absolute necessity to us and to maintain the trust that you have placed in us.
We demand it of ourselves, and I can assure you the board of directors demands it in not only of us but of themselves as well.
And now I’ll turn the call over to Leo.
Leo Denault: Thank you Wayne, and good morning everyone.
In my remarks today, I will cover second quarter 2012 financial results, our cash performance for the quarter, and then add a few closing remarks.
ENTERGY CORPORATION
Moderator: Paula Waters
07-31-12/10:00 am CT
Confirmation # 8666645
Page 17
Starting with our financial results on slide 2, higher overall second quarter 2012 earnings were driven by higher results at both the Utility and EWC compared to a year ago, and lower results at Parent & Other.
Second quarter earnings included a special item for expenses incurred in connection with the proposed spin-off and merger of Entergy’s transmission business with ITC Holdings. Spending on our spin-merge initiative reduced the quarter’s earnings per share by $0.05 at the Utility.
Now let’s turn to operational results for the quarter. Slide 3 summarizes the major drivers for operational earnings. Utility results were higher than a year ago, due primarily to a reduction in income tax expense. This was partially offset by lower net revenue and higher non-fuel operation and maintenance expenses.
An agreement with the IRS regarding storm cost financings in Louisiana for hurricanes Katrina and Rita reduced income tax expense by $180 million for the affected companies - Entergy Louisiana and Entergy Gulf States Louisiana.
The Companies also recorded regulatory charges totaling $101 million after-tax to reflect an agreement to share the tax benefits with Louisiana customers. The net effect of these items increased Utility earnings by $0.44 per share.
Excluding the regulatory charge, Utility net revenue was modestly higher this quarter compared to a year ago. The increase was due largely to positive weather-adjusted sales growth. After excluding the effects of weather, billed retail sales increased 4%.
ENTERGY CORPORATION
Moderator: Paula Waters
07-31-12/10:00 am CT
Confirmation # 8666645
Page 18
The Entergy region benefited from a reasonably healthy economy. Industrial sales continued to grow from expansions. However, overall weather-adjusted sales growth through the second quarter is roughly consistent with what we expected.
While the effect of weather was positive for the quarter, it was lower than the significantly warmer-than-normal temperatures last year. On a year-to-date basis, the weather effect was negative and well below last year.
Higher non-fuel operation and maintenance expense partially offset the earnings increase. O&M for the quarter reflected higher compensation and benefits costs driven primarily by pension expense.
Fossil and distribution spending also increased over last year due in part to increased Fossil outage spending, with timing differences also contributing to both.
Slide 4 summarizes EWC’s operational adjusted EBITDA for the second quarters of the current and previous years. The quarter-over-quarter decline was due primarily to lower net revenue and increased non-fuel operation and maintenance expense.
EWC’s net revenue reflected lower energy pricing for its nuclear fleet. Nuclear generation also declined as a result of additional refueling and unplanned outage days. Lower production was offset by the exercise of re-supply options under power purchase contracts.
The non-nuclear portfolio partially offset lower net revenue from EWC’s nuclear fleet - the RISEC plant acquired last December was the driving factor.
Higher non-fuel operation and maintenance expense also contributed to the decrease in operational adjusted EBITDA. The increase was due primarily to higher compensation and benefits costs - again, primarily pensions. The RISEC acquisition also contributed to higher non-fuel O&M.
ENTERGY CORPORATION
Moderator: Paula Waters
07-31-12/10:00 am CT
Confirmation # 8666645
Page 19
While EWC’s operational adjusted EBITDA declined, its earnings increased quarter-over-quarter. The increase was due primarily to two items not included in adjusted EBITDA - lower decommissioning expense and a lower effective income tax rate.
Operational results at the Parent & Other disclosure segment declined due primarily to higher income tax expenses on Parent & Other activities. The income tax expense increase reflected the net effect of favorable tax items recorded in both quarters - the 2011 effect exceeded the current quarter.
Slide 5 provides a recap of our cash flow performance for the quarter. Operating cash flow for the current quarter was $587 million, or $67 million lower than the same quarter last year. The decrease was due to lower net revenue at EWC and a regulatory refund to a wholesale customer at the Utility.
Slide 6 summarizes our 2012 earnings guidance, which ranges from $3.49 to $4.29 per share on an as-reported basis, and $4.85 to $5.65 per share on an operational basis.
The as-reported earnings guidance range was updated to include specials recorded in the current quarter. The as-reported guidance does not reflect any potential future expenses for the special item in connection with the proposed spin-merge of Entergy’s transmission business. As-reported earnings guidance will be updated to reflect this special item as actual costs are incurred throughout 2012.
ENTERGY CORPORATION
Moderator: Paula Waters
07-31-12/10:00 am CT
Confirmation # 8666645
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On our last earnings call, we identified several challenges that had developed during the first quarter. At that time, we also had other significant uncertainties such as the pending appeal of the foreign tax credit decision.
While we still have our biggest quarter to go, as we sit here today we are well-positioned relative to our full year guidance range. Current indications point to the higher end of the range.
As we head into the second half of the year, we remain focused on continuing to produce positive financial results as well as strong operational performance.
And we remain focused beyond 2012 as well. As we look ahead in 2013, I want to offer some initial thoughts.
Turning to Slide 7, at the Utility we work to get the right regulatory constructs in place to provide every jurisdiction the opportunity to earn its allowed return. One example is the Texas rate case that Wayne discussed earlier, which will have a bearing on 2013 and beyond.
We also have other upcoming rate cases. Entergy Louisiana and Entergy Gulf States Louisiana will file rate cases in January of next year. Entergy Arkansas is also expected to have a rate case tied to its exit from the System Agreement at year end. All are likely to take most of next year to complete.
Further, the timing and execution of our investment program will affect results.
At EWC one of the most significant variables is the price of power - both energy and capacity. Commodity markets continue to challenge margins.
ENTERGY CORPORATION
Moderator: Paula Waters
07-31-12/10:00 am CT
Confirmation # 8666645
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However, fundamental indicators in the natural gas market, such as narrowing storage surpluses, falling rig counts, and low liquids margins, appear to be signaling that we’re moving off of a bottom and into more constructive territory.
The appendix to this webcast presentation includes details on the current state of the market for energy and capacity prices for EWC.
Protecting the long-term value of our nuclear assets is a key priority. That includes managing the license renewal process for Indian Point - for the Indian Point units - as well as defending the license renewals already received from the NRC.
In the meantime, we’re utilizing hedging strategies to protect near-term value, while retaining longer-term options.
For both businesses, managing costs remains at the forefront. However, as we’ve seen this year, some things like pension expense are driven by external factors we don’t control. Efforts are underway to determine opportunities to mitigate cost pressures now and over the long term.
At the Parent, we are always looking for opportunities to improve business results. For example, last week we received authorization to execute a $500 million commercial paper program at the Parent. The CP program will provide a cost effective source of capital as well as incremental financial flexibility.
At current rates, borrowing from the commercial paper market would be about 100 basis points below the rate on the revolver, which will provide interest savings and bottom-line earnings.
We are now finalizing plans to implement this program in the third quarter, assuming market conditions stay favorable.
ENTERGY CORPORATION
Moderator: Paula Waters
07-31-12/10:00 am CT
Confirmation # 8666645
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Every day we focus on safety, operational excellence, risk management, and discipline to capital deployment. Whether managing the current year or planning ahead, the goal is to deliver results that will create tangible long-term value for our stakeholders.
And now the Entergy team is available for your questions.
Operator: And ladies and gentlemen if you’d like to ask a question, please press the star key followed by the digit 1 on your telephone keypad. If you are joining us on a speakerphone please make sure your mute function is turned off to allow your signal to reach our equipment. Once again that is star 1 for questions.
We’ll pause for a few moments to assemble the queue.
We’ll take our first question from Steve Fleishman with Bank of America.
Steve Fleishman: Yes. Hi. Good morning everyone.
Wayne Leonard: Good morning Steve.
Leo Denault: Hey Steve.
Steve Fleishman: I guess on the last earnings call Wayne you brought up the concept of looking at strategic options for the unregulated generation business.
Could you just update us on any thought process there?
ENTERGY CORPORATION
Moderator: Paula Waters
07-31-12/10:00 am CT
Confirmation # 8666645
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Wayne Leonard: Well I’ll let - Leo and his team has been working on this but, you know, I think one of the things that we kind of emphasized that given the uncertainty in a lot of these marketplaces and with environmental regulations and other types of things that we almost have to go back. One of the additional things we’re doing is going back to when we tried to form Enexus.
And our opinion at the time, you know, of course it was these businesses don’t belong together for a number of reasons. They’re financed differently. They have different credit metrics, things of that nature.
And but then as power prices have fallen and things of that nature, then credit metrics and credit quality, you know, become a real issue for this on a standalone basis as its structured for the wholesale business.
And but nonetheless we still believe it should be separated from the Utility.
So one of the other options is to look at transactions or assets or whatever that impact positively credit quality so we can get back to maybe the notion of separating the two businesses so rather than focused just on a functional, you know, adding power maybe it’s something else.
And I’m going to let Leo kind of expand his thoughts on the idea.
Leo Denault: Yes Steve. The bottom line is if you go all the way back to the kinds of things we would have been looking at at the time we came up with the separation concept, a lot of those ideas haven’t gone away. As we’ve always looked at that portfolio, ways to grow the business, ways to protect the business, ways to enhance the credit quality of the business, ways to provide liquidity to the business, we continue to look at all of those kinds of opportunities whether they involve internal moves or transaction-based ideas.
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And really could run the gambit of ways to improve the credit quality, improve the margins, improve the valuation and to make sure that we continue to protect not only the parent company but the utilities as well.
Steve Fleishman: Okay. One other question, just Leo thank you for giving some of those 2013 drivers and beyond; is there just maybe kind of a punch line of what you’re trying to highlight with these? These seem generally the stuff that we normally kind of you’ve highlighted in the past.
Was there any - is it mainly these rate cases that…?
Leo Denault: Well you really - Steve just to give you all a indication of what’s going to drive 2013 and beyond and the timing of when those things actually show up during the year as much as anything else.
Steve Fleishman: Okay. Great, thanks. I’ll stop at my allowed two.
Leo Denault: Thanks Steve.
Operator: And we’ll hear next from Dan Eggers of Credit Suisse.
Dan Eggers: Hey good morning guys.
Wayne Leonard: Hey Dan.
Dan Eggers: I’m just wondering if we’d go back to the kind of the MISO conversation and the ITC transaction. If you think about timing and kind of potential delays to getting the filings done for ITC, is there something structurally you’re seeing that is slowing down that process and, you know, what is the level of confidence we’ll see a filing get done in the third quarter?
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Wayne Leonard: You know Theo Bunting is, you know, really heading that process up as the CO of our Utility.
But Dan I don’t think there’s anything structurally that’s holding it up. It’s our commitment, you know, is to put on the strongest possible case in an area that, you know, is kind of new to a lot of the parties to the case and we want to make sure that we fully support and emphasize how important this is. We’re bringing together, you know, two companies, Entergy and ITC, along with a number of outside experts who believe very strongly and have evidence to support why the independent model is so much better than what - how we’re doing it today.
And just bringing all that different points of view and testimony together so it’s clearly everybody’s on the same page and it’s clear to the Commission and other intervenors in the case, has been a little more challenging probably than we might have expected. We thought that we would be able to make our first filing in Louisiana near the end of this month. We gave ourselves kind of another week to button everything up and we’re just not quite there yet.
Now, you know, Leo and Theo are having meetings this week to try to resolve any issues that we feel like are not supported as well as we want to get that analysis into testimony so it reads, you know, typically the way we would do it or ITC would do it when you’re just doing it on your own.
So there’s nothing structural. It’s just complicated when you involve more parties. And we want to get it right.
Theo you have anything to add or…?
Theodore Bunting: Yes, I would like to add something Dan. I mean, you know, I agree with a lot of - most all the things Wayne said. The other thing I think you need to consider is, you know, we’re doing this in multiple jurisdictions. And we’re trying to do this in a manner that would allow us to make those filings in those jurisdictions with not much passage of time between filings.
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So obviously we have to think about, you know, how do we ensure we incorporate all the items we need to consider relative to those jurisdictions so that when we start that process we don’t get any significant slowdown.
You know I do think as Wayne said, you know, there’s still some things we need to work through. We’ll be working through those things over the next few weeks. And, you know, we’ll begin that filing process.
Dan Eggers: Great, thank you. And I guess just Leo on the tax issues for the year is there anything else we should be looking at that you could provide a benefit for this year and did you anticipate, you know, this level of benefit showing up in the guidance when you guys updated it this spring?
Leo Denault: Well when we updated the guidance this year obviously we had the possibility of both positive and negative items in the tax arena. We knew we were working obviously on a settlement but at the same point in time we had the appeal of the foreign tax credit decision which had already been lost in a different jurisdiction at a different district for which we had provided a reserve last year.
So that could have been the positive that you saw this quarter because of the win. But if we had lost that case it was a significantly larger negative possibility.
So, you know, we had indications around both of those things but they were unknown at the time and could have gone either direction.
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There’s always a few things in the hopper as you know based on the size and number of the positions that we’ve got in front of us at the moment that may or may not turn out, may or may not happen, could go to litigation like the foreign tax credit case or could be settled. Just depends on where you are in the audit cycle and what issues are available there.
We had taken some of that into consideration when we reset the guidance. Remember the 22 cents. I think we characterized that as “other”. In the improvement in the original guidance, some of that was taken into consideration - tax items that may or may not occur. And I think we even mentioned that at the time.
Dan Eggers: Okay, thank you guys.
Leo Denault: Thank you.
Operator: We’ll hear next from Greg Gordon with ISI Group.
Greg Gordon: Thanks. Good morning.
Leo Denault: Morning Greg.
Wayne Leonard: Hi Greg.
Greg Gordon: I’m focusing on table 4 on page 3. Your weather adjusted sales growth has been quite robust. You make some comments in there about growth, industrial sales growth particularly in Louisiana. You also had retail sales growth.
Can you extrapolate A, on what’s going on in terms of residential growth, what that’s so strong? What types of industrial activity you are seeing that are leading to this type of growth?
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And then the decline in the refineries, could we characterize that as seasonal because as I understand it they were down for maintenance and therefore that should be additive when they come back?
It’s really a very positive underlying theme here.
Wayne Leonard: Okay Theo you want to take that?
Theodore Bunting: Sure. Greg as Leo mentioned in his opening comments obviously on the residential, let’s start with the residential side first, you know we are seeing some impacts from still a fairly strong economy in our region especially when you compare it to what’s going on nationally.
Also I think you have to think about some of the things we had last year that didn’t necessarily repeat themselves this year. We had certain events last year that had a dampening effect on sales. For instance, the flooding we had from the Mississippi River that, you know, that reduced sales volumes.
And also I think you - you know, last year we had fairly extended periods of, you know, extreme weather, high bills and, you know, generally, you know, customers respond to that. So, you know, we probably had some amount of customer response, you know, relative to bills last year.
And also I think Leo mentioned the fact that our - may have mentioned the fact that, you know, our billing cycles this year for the quarter had a few days beyond what we would have seen last year as well.
And all of those things really cobbled together had some effect on the year-over-year change. I think if you go back and if you look at the residential growth year-over-year last year it was
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actually slightly negative. So, you know, given that, you know, we saw fairly robust change year-over-year but again as Leo said earlier I think we still fundamentally feel like we’re where we - about where we expected to be at this point in time relative to sales.
In terms of industrials, I think it’s the chemicals that continued to, you know, show fairly strongly, in terms of segments, in the second quarter. And a lot of that is relative to facilities expansions. And as we go through the year we’ll likely see some of that moderate as, you know, we’re kind of seeing those expansions and when they hit in various points in times, you know, in prior years.
And, you know, there are - obviously we do get outages in certain areas in terms of customers, you know, bringing their facilities down for various reasons. And that, you know, can move our industrial sales, you know, up and down as you compare period-to-period.
Greg Gordon: Okay, thank you.
Operator: We’ll take our next question from Julien Dumoulin-Smith with UBS.
Julien Dumoulin-Smith: Hi. Good morning.
Wayne Leonard: Morning Julien.
Julien Dumoulin-Smith: Hey just on the Texas rate case here just if things don’t turn out as positively with the final rec here in August, what are the various avenues? And you kind of alluded to them quickly on the opening statement.
But if we were to see a move towards a capacity type rider when would that happen or alternatively if we weren’t at what point, you know, down the line say six months, you know, a year from now do we see another filing just to be a little bit more explicit about the timeline?
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Wayne Leonard: And Theo?
Theodore Bunting: It sounded like you had a number of questions there Julien. And I’m trying to go through them.
Yes, I guess the first thing I would - make sure we all understand is where we’re at today is, you know, we basically have a - kind of a proposal for decision. It’s not an order from the Commission, and, you know, that’s still forthcoming. And, you know, part of that, obviously of what we would do relative to that would have a lot to do what - with what comes out of that Commission order.
I would say it’s not unusual in Texas for the Commission to not accept, you know, all aspects of a PFD. And as Wayne talked about earlier in terms of various riders that are in place today in the current rate construct in Texas, obviously those would be opportunities for us given - once we know the outcome of the case itself. And obviously, you know, to talk about what we might do and when we might do it at this point in time is probably a little premature because we don’t have the outcome of the case yet.
The capacity rider is, it’s in a rulemaking phase, and, you know, we are working and will continue to work to move that along. Also as Wayne mentioned in his opening script, a big part of what’s at issue in the case as it relates to the recommendation of the ALJs is capacity.
And if, in fact, just assuming for a second that we don’t fundamentally get what we believe is appropriate treatment relative to that, then we would obviously try to and try to ensure that we move that rulemaking along in order to get proper alignment of the regulatory construct in Texas with what we fundamentally believe is appropriate in what’s taking place there.
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Wayne Leonard: To add, you know, I think like Theo said, we need to get the order out of the Commission. Hopefully it will undo some of these - what we think are inappropriate adjustments. But it won’t just be for the outcome, it will be the tone set in the order. Hopefully it would give us some guidance that will be instructive to which way best to proceed.
You know, obviously we want to - we don’t want to start a war with the Commission by going one way if they would prefer another. We’re hopeful that they will acknowledge that this does not give us the opportunity to earn a fair return, and they will fix that or give us strong guidance on how to fix that ourselves.
Julien Dumoulin-Smith: All right, great. Thank you very much.
Operator: We’ll take our next question from Paul Patterson with Glenrock Associates.
Paul Patterson: Good morning.
Wayne Leonard: Morning.
Paul Patterson: Greg asked that question on sales growth. I was wondering though on the - one of the Commissioners in Louisiana is talking about changing the ROE kind of significantly on the downward side. And I was wondering if you could sort of elaborate if, you know, if he’s being joined by anybody else or if he’s kind of an outlier on that and any thoughts you have on that.
Wayne Leonard: Theo’s maybe closer to it, but, you know, as you know in this interest rate environment, I suspect there isn’t a commission around the country who don’t have at least one commissioner who’s bringing the issue up - is it appropriate? It’s a good question. You know, obviously it’s - interest rates are much lower than we’re used to, and the - we - in like Louisiana specifically, we really have not heard a lot on that issue. We do have one Commissioner a little more outspoken on it. But again, that’s fairly common I think across the country.
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But Theo, why don’t you?
Theodore Bunting: Yes, I think also one thing that you’ll note in Louisiana, that issue has come before the Commission at least on maybe one - couple of occasions, and they’ve just not moved it along. And as Wayne said I think, you know, we have one Commissioner there who is very interested in looking into this.
But I think you also have to consider - and I think they have to consider - you know, interest rates is really just one input into that entire process of defining what’s an appropriate ROE. You also have to think about, you know, risk premiums, and you also have to think about the fact that, you know, there’s a legal standard around what is the appropriate ROE. And that ROE basically, you know, should be set such that, you know, you can maintain the financial integrity of the company, you can raise capital on reasonable terms, you know, such that, you know, the utility can discharge its public duty relative to the customers.
And in this period of time where, you know, we’re seeing fairly extensive capital investment across the utility industry and, you know, I think regulators really need to think about and consider, you know, all of these elements as you think about what is the appropriate ROE for a utility.
Paul Patterson: Okay, great. And then on the stock buybacks, repurchases, any thoughts, you know, sort of at this point in time? I know you’ve got a lot of things going on, you know, a lot of initiatives, obviously the ITC stuff and everything else. How should we think about - your thoughts about stock repurchases, given everything that you’re looking at and what have you?
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Wayne Leonard: Leo?
Leo Denault: Well, obviously we haven’t - didn’t have any stock repurchases in the quarter. We’ve completed $150 million of the $500 million of authority that we have at the moment, so there’s $350 million left. Just philosophically, the way the repurchase program works is based on the results out of EWC and/or any kind of transactional based results that we have. For example, if we sold an asset or what have you, the dividend is usually paid for by the Utility. So that’s the construct around it.
And depending on what capital expenditures are, the cash flow may or may not be used for that. So, for example, at the end of last year when we acquired the RISEC plant, we spent over $300 million on that plant. That’s part of what goes into the decision-making process around the repurchase. So I guess at the moment we haven’t done any recently. We typically don’t signal what we are or aren’t going to do but just philosophically to know that, you know, transactions and/or EWC non-utility earnings, that’s where that buyback money comes from.
Paul Patterson: Okay, thanks a lot.
Leo Denault: Thank you.
Operator: We’ll take our next question from Stephen Byrd with Morgan Stanley.
Stephen Byrd: Good morning.
Wayne Leonard: Good morning, Stephen.
Stephen Byrd: You’ve been making progress at the state level in moving towards membership in MISO, and in the filings, you know, obviously comes up the discussion of distinguishing between MISO
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membership and approving the ITC sale. Can you talk about just the general feedback that you’ve been receiving at the state level to the ITC sale element relative to MISO, you know, appreciating that that’s a later element. But just nonetheless, any color on the feedback you’ve received at the state level?
Wayne Leonard: Ok Theo, why don’t you go ahead and take that?
Theodore Bunting: Yes, Stephen, I’m not sure I - the audible level of your - well, it’s fairly low. Let me see if I can repeat your question on what you were asking. Well, you’re asking as to in the MISO proceedings, is - are we getting questions around the ITC sale and/or - just want to make sure I understand what your question was.
Stephen Byrd: Yes, I think that my focus really was just on - in your conversations about the overall ITC transaction at the state level, which, you know, that understandably will come up as part of the MISO proceedings. Can you just talk generally to the feedback that you’ve been receiving at the state level relating to the ITC transaction?
Theodore Bunting: Yes, and I made a huge mistake. I said sale. It’s not a sale. It’s a spin-merge, and I hope I don’t - I don’t think I used that term in my testimony that I plan to file, but in any case. You know, it does come up from time to time, but we try to make sure folks understand that they are separate processes. They’re separate transactions. They’re separate steps. Obviously we need to get to MISO to an RTO in order to, you know, fully to effectuate the ITC transaction.
And as we’ve said to many of the regulators, I mean we are focused on getting to MISO - getting to an RTO. And that’s part of the reason, I think while you’ve seen some passage of time and some separation as it relates to the filings around the ITC transaction is that we are, you know, we’re trying to work through within the various jurisdictions that MISO process and move the various Commissions along and the other parties to get through that MISO process and get our MISO approvals. But it does come up from time to time.
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Wayne Leonard: Yes, I think, you know, the discussions I’ve been involved in, I think it’s actually been very encouraging. The regulators have been very interested in trying to understand more. You know, when we proposed similar - actually I guess it wasn’t all that similar - a few years ago, it was a hostile environment with regard to - some type of divestiture of the transmission system.
They have - the questions we’ve gotten have been very much on point with regard to how things will change. The overall feeling seems to be, you know, that they - that given the amount of merchant capacity we have in our territory, given some of the feedback that they’ve gotten from some of the merchants and some of the extensive audits and - that we’ve had relative to some of the merchants’ concerns and other concerns, they understand that this needs some sort of resolution other than continuing to try to just regulate this thing to death.
Separating it resolves, you know, all those issues and eliminates any perception along with it solves a lot of problems for Entergy with regard to credit quality and that just lowers rates for customers and ensures reliability. And we’ve had really good dialog I think with the Commissions.
And the big concern - the biggest concern that I’ve heard, you know, is to try to explain exactly how giving up jurisdiction, you know, because FERC would have ultimate authority on how they maintain authority to execute their job - assuring reliability at a fair price and all those types of things - and they don’t want to end up just as another intervenor at FERC. And so that’s kind of I think been - working through the process, trying to make sure that that doesn’t happen, has been the - really the issue with them, but again it’s been very constructive.
Stephen Byrd: Great, thank you very much.
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Operator: And our final question comes from Michael Lapides with Goldman Sachs.
Michael Lapides: Hey guys. I just want to make sure I’m following the rate changes you expect between now and maybe the year end of 2013, kind of following on some of Leo’s comments. You discussed the Texas rate case, I guess the question is, do you think you would file another case and have new rates in place before year end ‘13?
Then the Louisiana formula rate plan adjustments that are outlined in the appendices, do you expect incremental adjustments before the actual Louisiana rate changes or rate cases kind of resolve? And then the timing of an Arkansas case, how early would you file? When do you think rates would go into effect there? And apologies, a fourth item, how do we think about how Grand Gulf’s uprate will impact rates?
Wayne Leonard: I think that Theo’s getting a good introduction here to his new job, but he’s - like we’ve said before, he’s certainly up to the challenge and probably the most knowledgeable person we’ve ever had in this job. So we’ll let him prove it right now.
Theodore Bunting: I think he’s asking me to prove that, because he personally wants me to make sure if I can actually remember all the questions. You know, I’ll start maybe in reverse order. Grand Gulf, I don’t think, as you know - may know Grand Gulf is FERC regulated.
And there is a specific tariff around, you know, how costs through the unit power purchase agreement of SERI and the various operating companies, you know, how that cost flows from Grand Gulf or from SERI to the operating companies and the various operating companies have different regulatory mechanisms in place to recover costs associated with those billings from SERI. And they vary a little bit jurisdiction to jurisdiction, but they all have, you know, fairly, you know, timely mechanisms in place to recover costs associated with Grand Gulf.
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In terms of filings, I mean obviously we would expect a filing in Arkansas consistent with its departure from the System Agreement, and obviously that’s targeted for the end of 2013. You know, Louisiana when you talked about FRPs, you know, Wayne talked a little bit about the FRP results as it related to our filings based on the 2011 test year. And I think as Leo mentioned, you know, we would be making rate case filings in Louisiana in January of 2013 to basically reset rates.
Depending upon the length of the proceeding, you know, potentially you could have some impact from that decision relative to that case in 2013, but that will be a function of the procedural schedule that obviously we will get once we make those particular filings.
As it relates to - trying to remember what other questions you had - you know, Mississippi, we made our FRP filing, no changes relative to that filing, based on - again a 2011 test year. And was there another jurisdiction that I’m - was there a jurisdiction I missed?
Michael Lapides: When would you - if you - if Texas rate case resolves in the next month or so, when do you expect you would be back in filing for a new base rate increase?
Theodore Bunting: I think it’s premature to talk about that at this point. We don’t have an order out of Texas, and you know, and so until we get an order and realistically see where we are, you know, we’ll evaluate that and make an assessment as to what is the appropriate time to file.
Michael Lapides: Okay, thank you guys. Much appreciated.
Operator: And at this time we have no further time for any other questions. I’d like to turn the call back over to our speakers for any closing or final remarks.
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Paula Waters: Thank you, Deanna, and thanks to all for participating this morning. Before we close, we remind you to refer to our release and website for Safe Harbor and Regulation G compliance statements. Our call was recorded and can be accessed on our website or by dialing 719-457-0820, replay code 8666645.
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-off and merger of Entergy’s transmission business with ITC Holdings Corp. The telephone replay will be available through August 7, 2012. This concludes our call. Thank you.
Operator: Again this does conclude today’s conference. We thank you for your participation. You may now disconnect.
END
Entergy Forward-Looking Information
In this communication, and from time to time, Entergy 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: (i) Entergy’s Form 10-K for the year ended December 31, 2011; (ii) Entergy’s Form 10-Q for the quarter ended March 31, 2012; and (iii) 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 release 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 approval by ITC Holdings Corp. shareholders.
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Additional Information and Where to Find It
ITC and Transco will file registration statements with the Securities and Exchange Commission (SEC) registering shares of ITC common stock and Transco common units to be issued to Entergy shareholders in connection with the proposed transactions. ITC will also file a proxy statement with the SEC that will be sent to the shareholders of ITC. Entergy shareholders are urged to read the prospectus and/or information statement that will be included in the registration statements and any other relevant documents, because they contain important information about ITC, Transco and the proposed transactions. ITC shareholders are urged to read the proxy statement and any other relevant documents because they contain important information about Transco and the proposed transactions. The proxy statement, prospectus and/or information 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.