Entergy Corporation (ETR) Q4 2013 Earnings Report, Transcript and Summary

Good day, everyone, and welcome to the Entergy Corporation Fourth Quarter 2013 Earnings Release Conference Call. Today's call is being recorded. At this time, for introductions and opening comments, I would like to turn the conference over to the Vice President of Investor Relations, Ms. Paula Waters. Please go ahead, ma'am.

Good morning, and thank you for joining us. We'll begin today with comments from Entergy's Chairman and CEO, Leo Denault; and Andrew Marsh, our CFO, will review results. [Operator Instructions] As part of today's conference call, Entergy Corporation makes certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements involve a number of risks and uncertainties, and there are factors that could cause actual results to differ materially from those expressed or implied in the forward-looking statements. Additional information concerning these factors is included in the company's SEC filings. Now I'll turn the call over to Leo.

Thanks, Paula, and good morning, everyone. 2013 was a good year, considering everything we set out to do and what was before us. Importantly, we maintained low rates for our customers, our employees had a great safety year, we contributed to our communities, and we put in place a platform of lower costs, improved risk profile and simplification our business while delivering strong financial results. Moreover, our strategic imperatives positioned us to execute on our strategy to aggressively grow our utility business, driven primarily by the economic renaissance that is unique to the Gulf South while we preserve the optionality and manage the risk in our merchant operations, Entergy Wholesale Commodities. So starting with the results. I'm pleased to report, after beginning the year with higher-than-expected pension costs pushing us towards the lower part of our guidance range, we delivered operational earnings of $5.36 per share. That's near the top of our guidance range of $5.40. We returned nearly $600 million in common stock dividends and maintained solid credit metrics for our owners. Our residential, commercial and industrial rates remain among the lowest in the nation. Our residential rates are in the lowest cost quartile in 4 of our 6 retail jurisdictions, and our low industrial rates are contributing to the regional industrial growth we're experiencing. In addition, our residential customers viewed us more favorably in 2013 than the year before. Overall, the percent reporting favorable views grew by 12 points to 78%. Also for our communities, Entergy and the Entergy Charitable Foundation invested more than $15 million of cash contributions to nonprofit partners, and our employees and volunteers logged more than 85,000 hours of volunteer service valued at approximately $2 million. What matters most to us is safety. Our employees reduced the OSHA recordable accident index by more than 30% for 2012 to a record low level. Our contractor safety did not match our employee results. We can and must do better as nothing is more important. Resolution of major strategic issues, our corporate reorganization and strong results set the stage for execution on our strategy for 2014 and beyond. I want to take the next few minutes to talk about what we mean by that. As I mentioned, our Utility strategy is to aggressively grow our business. Sales growth and productivity improvements have always been the most effective way to grow utility and keep customer bills low. For Entergy, we believe we can sustain this traditional utility model for the foreseeable future. It starts with the top line. Today, economic development activity is far beyond anything we have seen in a long time. Just last November, the International Energy Agency released its 2013 edition of the World Energy Outlook. In it, the, IEA points out that the significant regional disparity of global energy prices clearly favors the United States against rival industrial giants. Oil prices are more than 20x higher internationally than the equivalent U.S. natural gas price, and natural gas prices around the world are more than double what we pay here in the U.S. These spreads make new or expanded energy-intensive industrial production located in the U.S. competitive globally. Shale gas also contributes to our low industrial electricity rates, also helping industrial businesses to better compete. Combine these commodity price levels with business-minded state and local governments, communities that are receptive to industrial development, as well as the infrastructure in place to support it, and we see a great environment for economic development to flourish in our 4-state service territory. Over the next 3 years, we project 2% to 2.25% compound average annual sales growth, simply based on those new or expansion industrial projects we have line of sight on, either through signed electric service agreements or those in late-stage negotiations. While opportunities exist across our service territory, most identified to date are centered along the Louisiana Gulf Coast region. Drew will update you on recent efforts to serve this industrial load. But to give you a sense of the magnitude of the opportunity and why it is central to our Utility strategy, if we serve them all, it would increase the sum of the operating companies' peak load by almost 10%. The utility operating companies' objective, in conjunction with our state economic development agencies, is to attract these opportunities to our region and to serve them all reliably and cost-effectively. Even as our sales grow, we can continue to provide electricity from a fleet that has average emission rates well below the national average in both conventional pollutants and greenhouse gases. We also now have better access to a broader pool of resources to serve existing and new customers through our integration with the Midcontinent Independent System Operator. At midnight Eastern on December 19, the 6 utility operating companies cut over to operations in the MISO Regional Transmission Organization. Joining MISO marks completion of a decade-long objective. It was the largest RTO integration ever. MISO's ability to optimize unit commitment and dispatch across our regions is projected to save our customers hundreds of millions of dollars over the coming decade. In addition to energy cost benefits that result from the Day 2 market, utility operating companies' reserve margins collectively are now 1,000 megawatts lower, real savings to customers every year. The move to MISO also gives us improved flexibility to serve incremental sales growth. Serving these new customers may require additional investment in transmission. Regarding transmission, as you know, we jointly terminated the proposed transaction with ITC Holdings Corp. in December. While we believe that the transaction offered a way to lower delivered energy cost for our customers over the long term, simply put, we did not get the regulatory support we needed to close the deal. Our objective has always been to provide safe and reliable transmission service to our customers at a reasonable cost. We have a 100-year history of doing just that. Going forward, the utility operating companies will continue to maintain the existing transmission infrastructure and, alongside MISO and under its independent oversight, plan for new transmission facilities as needed to meet reliability standards. We will also participate actively in the MISO planning process to identify and build additional transmission projects to support public policy goals or provide congestion relief, where economic for customers, and other benefits consistent with the MISO planning criteria. Our transmission capital plan over the next 3 years reflects spending to implement the construction plan incorporated into the MISO planning process upon our entry. Joining MISO, any implementation of FERC Order 1000 adds a new dynamic. For example, our transmission spending in the coming years could increase for potential market efficiency projects -- for Multi-Value Projects, which are economically driven projects if approved by MISO because of the economic or public policy types of benefits they provide to our customers; or projects identified through interregional planning, evolving industry reliability standards, loading economic conditions, again to the benefit of our customers; or future transmission investment to meet requirements to serve the approximately $65 billion of potential economic development projects in a region. We could also see additional generation investment needs over time, both to replace aging resources and to meet sales growth. As we have -- invest for the future and the growth of our business, productivity improvements that help manage customer rates will also be critical. This is the reason for our HCM initiative. HCM was necessary to advance the Utility and EWC strategies. This required a complete reorganization and restructuring of our company. It was an arduous process for our employees. We restaffed the entire organization after designing a new structure to improve the efficiency and the effectiveness across the company. In the end, we eliminated approximately 800 positions, and the majority of the affected employees separated from the company last year. We also introduced changes to our employee benefits programs in late 2013. These types of changes are never easy for anyone, but they are necessary to maintain reasonable cost for our customers and position employees in the company to excel in the coming years. Our HCM was not just about cutting cost. It was also about expanding resources dedicated to functions central to our strategy. At the Utility, for example, economic development was elevated in the company, expanding the staff and resources dedicated to this effort. Working hand-in-hand with state and local government offices, the economic development teams are charged with attracting new projects to the region and removing barriers in the development process. At nuclear, we determined we needed more specific governance and oversight of the various functions as a method to help us improve performance at the plants. So we added operations oversight personnel at each site to ensure that the behaviors and performance at the plants meet our standards. Improving performance was a major goal for the nuclear organization's HCM effort. At the corporate level, we developed a new shared services model to improve efficiency, better support business operations and have a more engaged organization. In addition to growing sales through our economic development activities and improving productivity through programs like HCM and our transition to MISO, our regulatory constructs must support our efforts to grow the economies of our service territory. Constructive regulatory mechanisms, such as riders from the rate plans and the securitized recovery of storm cost and the establishment of storm reserves also improve the ability for a utility to reliably serve customers, make investments and maintain reasonable costs. We will continue to work with our retail regulators who have recognized the benefit of such constructive approaches in many ways over the years. The settlements of the 2 Louisiana rate cases approved by the LPSC in December were structured around our execution of these building blocks of our strategy. But we have more work to do to demonstrate to all of our retail regulators the value in progressive mechanisms. We need to collaboratively pursue mechanisms that will support prudent investment to the benefit of all stakeholders. Working together with our regulators, we need to continue to serve and advance the public interest. We also need to make sure that the traditional rate setting mechanisms are functioning properly. While the Arkansas Public Service Commission's rate case decision did give us some tools to prepare for the future, particularly those mechanisms designed to help us operate in MISO and facilitate Entergy Arkansas' exit from the System Agreement, we are very disappointed in the other portions of the decision that will make it more challenging for EAI to invest in expansion opportunities and technologies that foster the state's economic growth and public policy objectives. Clearly, one of the disappointments is the 9.3% authorized ROE, the lowest ROE of all Southern U.S. utilities. We're already seeing a negative customer impact of the order after Moody's upgraded the credit ratings of our other major operating companies in most of the utility space but not Entergy Arkansas. The upgrades came out of Moody's more favorable view of the relative credit supportiveness of the U.S. regulatory environment. Entergy Arkansas was one of a handful of companies whose ratings did not change despite being on review for possible upgrade. In its report, Moody's specifically pointed to the less-than-favorable rate case outcomes in May of 2010 and December of 2013. Moody's also pointed to more credit-supportive FRPs in other jurisdictions versus the traditional rate case framework. This obviously disadvantages EAI against other companies in their quest for growth and the capital to support that growth. At the end of January, we filed for rehearing and/or clarification of some of the issues to better understand how to address them going forward. While we are trying to resolve via the [indiscernible], the issues created by the current rate order, Entergy Arkansas intends to work constructively with the APSC to find a way to advance a regulatory environment which strengthens EAI's ability to serve its customers in the post-System Agreement environment and fosters the type of investment that helps grow the economy. We have a long history of FRPs in Mississippi and New Orleans. The FRP in Mississippi has served all stakeholders well over the years, linking return levels to performance on customer service reliability and customer rate metrics. The potential need for a rate case in 2014 arises from Entergy Mississippi's exit from the System Agreement next year, among other reasons. And they also give us opportunity to explore other regulatory mechanisms such as formula rate plans that allow adjustments for known and measurable changes occurring in the rate effective period to better facilitate the coming investment needs. In Texas last week, Entergy Texas staff and the parties notified the Administrative Law Judges of significant progress towards settlement in a rate case. As a result, the schedule was suspended. Tomorrow, the parties will file a report regarding the status of the settlement and settlement documents. The rate case filing also seeks to set baselines for using the authorized capacity, distribution and transmission riders in coming years. These 3 riders provide a regulatory regime that addresses certain cost drivers without the need for a full base rate proceeding. Turning to EWC. Our strategy is to preserve optionality and manage risks through our operations; our hedging strategy; our regulatory efforts, most notably license renewable; our asset decisions; and our advocacy for wholesale market policies that adequately price the value of reliability, fuel diversity and environmental benefits. Take hedging for example. Several years ago, we expanded our use of options and collars that provided downside protection and offered some ability to receive higher prices if the market moved up, consistent with our analysis of the markets. As a result, last winter, and again this winter, we were able to capitalize on the run-up in power prices. This strategy contributed to our strong 2013 earnings performance and current position within the 2014 guidance range, and Drew will review that shortly. While this winter's much colder-than-normal weather has been a primary driver and was not an expected outcome in advance, the way we structured our hedge portfolio preserved optionality and is helping us to realize upside in the volatile energy market, consistent with our overall EWC strategy. High capacity price is also reflected in our strong 2013 results as supply and demand in the New York market began to tighten. Going into 2014, the new Lower Hudson Valley capacity zone is a source of potential uplift for Indian Point. More importantly, having it should contribute to improved reliability in New York. The new capacity zone was designed to create proper market incentives that encourage minimum resources in this constrained zone. FERC issued its decision on January 28 on the New York Independent System Operator's demand curve filing. Essentially, these demand curves will set the capacity price in each spot auction based on the level of demand bid in. Although we did not agree with some of the assumptions underlying the demand curves, the decision overall, including the rejection of the phase-in of the new zone, was a step in the right direction that will increase the market's ability to meet the region's goals. With this decision in hand, the LHV zone will be fully implemented effective May 1, 2014. Last week in New England, the 2017 to 2018 capacity auction cleared at over $7 per kilowatt-month for Rest-of-Pool, below new build but better than the sub-$3 clearing price in the last auction. Pilgrim and Rhode Island combined-cycle plant both cleared the auction as Rest-of-Pool resources. Despite these constructive capacity market outcomes, our market design challenges remain, and we are now seeing their seeds take root with more announced shutdowns. This shutdown of generation that would otherwise be economic in a well-functioning market will create a future point of disconnect. Something will have to give. In the meantime, we will continue to champion power market reform. And in the long run, we generally bullish on Northeast energy and capacity prices, and Drew will address in more detail this during his discussion. For Indian Point, we continue to preserve the option to operate the plant through our pursuit of the multistage, multilayer license renewal process. This process is likely to continue through at least 2018. A recap of recent developments is provided on Slide 28. For Vermont Yankee, the value of the option was not sufficient to maintain its operation, which led us to the difficult decision to close the plant. To manage the risks associated with the shutdown, we reached a settlement in December with the State of Vermont. We believe the Vermont Yankee settlement agreement is in the best interest of VY employees, the local community, our owners and the state. It resolves short-term issues and establishes a foundation for longer-term dialogue. Just signing the agreement resolved most of our pending litigations with the state. The remaining terms of the agreement are contingent upon Vermont Public Service Board approval by the end of March of the Certificate of Public Good to operate through the end of 2014. Closing one of our plants is the last thing we wanted to do, and economics drove the decision in Vermont. However, even with the closure, we preserved 85% of the optionality in the fleet. Despite the recent weather-driven run up in near-term prices, long-term sustained low-power and capacity prices continued to weigh on Fitzpatrick and Pilgrim and would at Palisades, if not for the power purchase agreement through early 2022 that supports the plant's operating costs. We continue to believe the rationale for separating merchant risk from the utility holding company remained valid. To that end, we have looked at a number of alternative to accomplish this over the last several years. Our conclusion, based on what we know today, is that we intend to own and operate this fleet for the foreseeable future. We know there's a lot of uncertainty on this point, so we felt it was important to let you know that, based on our current point of view, we have made no decision to close any other plants and are not actively considering selling any at this time. While this is our assessment today, our point of view is an evergreen process that will continue to evolve based on conditions in the commodity markets and operational and regulatory developments. 2013 had its challenges. We feel like we've taken a significant step forward. If 2013 was a year of transition, 2014 is the year of clarity. Entering today's call, I know many of you had questions about what our strategy is. My hope is I've cleared some of that up. To recap, we have put a platform and organizational structure in place to execute on our strategy, and our strategy is to aggressively grow the Utility business, driven primarily by the economic renaissance that is unique to the Gulf South, while we preserve the optionality and manage the risks associated with EWC. And as always, we're on the lookout for actions we can take to do better for our stakeholders. But I know you have more questions about what we are trying to do and what it all means financially and operationally into the future. We will give you a comprehensive update at our 2014 Analyst Day, which we're announcing today. It will be held on June 5th in New York City. We hope you'll mark your calendars. We want to see you all there. And now, I'll turn your call over to Drew.

Thank you, Leo, and good morning, everyone. Today, I will review the financial results for the quarter, highlights from the full year, then I'll spend some time discussing our forward outlook. Starting with Slide 2, our fourth quarter 2013 results are shown on an as-reported net operational basis. Fourth quarter operational earnings per share were $1 in 2013 compared to $1.72 in 2012. The decline was largely due to the income tax benefits recorded in the prior period. There were other largely offsetting items, which I'll discuss momentarily. Operational earnings excluded special items from the ITC transaction, the Vermont Yankee closure decision and HCM implementation. Regarding HCM, the net charge was $60 million on a pretax basis. This included about $110 million from pretax expenses, net of approximately $50 million from regulatory assets. Turning to operational results by segment on Slide 3. Earnings per share at the Utility and Parent & Other decreased, while EWC results were higher. Starting with Utility, operational earnings per share were $0.86. This was lower than the $1.63 earned in fourth quarter of 2012. As expected, income tax expense was a driver, due to the prior period benefit. Recall, in fourth quarter 2012, income tax expense was reduced approximately $155 million as a result of an IRS settlement. Partially offsetting in 2013 result was an approximately $0.08 per share of income tax benefit, including the reversal of previously accrued interest after resolving an IRS audit. Utility also saw strong results in net revenue. We talked about pricing factors throughout the year. The benefits from conducted 2012 investments were realized in 2013 results. Utility retail sales were also higher this quarter, on both an as-reported and a weather-adjusted basis. Weather-adjusted sales increased 1.5% quarter-over-quarter driven by strong industrial growth, which is 3.2% higher than the fourth quarter of 2012 period. The increased sales came largely from existing refining chemicals and small industrial customers, and very little was a direct result of expansion. Generally improving economic conditions in the U.S. and abroad, bolstered by the persistent strong spreads between natural gas and oil as well as U.S. gas to global gas, helped drive the industrial customer performance. Although weather in the fourth quarter was helpful, residential sales continued to reflect challenges from uneven regional economic growth and a continued emphasis on energy efficiency and [indiscernible] management program. Now let's quickly cover Parent & Other. P&O had an operational loss of $0.34 per share compared to a loss of $0.24 per share in the same quarter last year. The decline results from tax on the sale of EWC's District Energy business being recognized as a tax-paying entity, which is in Parent & Other. At EWC, operational earnings were $0.48 per share, higher than the $0.33 in the prior period. Outside of EBITDA, the increase was due largely to changes in consolidated tax benefits and realized gains from routine rebalancing of the decommissioning trust fund. Turning to EWC EBITDA drivers on Slide 4. $28 million decrease was due to several factors, some of which offset. First, we closed on the District Energy sale for a $44 million pretax gain. Next, we recognized a mark-to-market loss of approximately $45 million due to rising prices. Nuclear volumes improved, while all -- overall prices were largely flat. O&M was also higher due primarily to compensation and benefits drivers such as pension and an adjustment of fourth quarter 2012 following resolution of litigation on spent fuel. Regarding the mark-to-market recognition, as you know, we have a comprehensive hedging strategy to manage commodity, operational and liquidity risks while providing asymmetrical upside opportunity and downside protection. During December, forward prices moved above our protective call strike. And with better visibility of operational and liquidity risks, we made forward sales against those options, locking in incremental margin for early 2014. Unlike the majority of our commercial activity that is accounted for under hedge accounting, when we hedge our hedge, these forward sales do not qualify for hedge accounting treatment. Market prices continued to increase after the forward sales were completed, which drove the negative mark. When these positions settle in the first quarter, we'll realize both the reversal of this mark-to-market loss as well as the locked-in margins on these transactions. At the end of the day, our activities have been consistent with the hedging strategy we've talked about for the past several years. The only difference is the late 2013 increase in market prices, which highlights the option value inherent to the EWC business and our ability to capture it through our hedging strategy while still managing risk. Moving to operating cash flow on Slide 5. OCF was $990 million in the current quarter, $270 million higher than 2012. The increase reflected higher utility net revenue, lower spending on nuclear refueling outages and lower storm spending. On the flip side, higher pension funding partially offset the increases. Now I'll review highlights from the full year results starting on Slide 6. On an operational basis, as we have said, 2013 earnings per share ended the year at $5.36, down from $6.23. The year-over-year drivers are similar to our quarterly discussion. The largest driver was income tax expense, especially at the utility, in 2012 and partially offset by customer sharing. In 2013, we also saw an increase in Utility net revenue. A portion of the net revenue increase was to recover higher operating expenses. On Slide 7, the EWC's operational adjusted EBITDA declined year-over-year due mainly to higher nonfuel O&M. Again, the gain on the sale of District Energy was largely offset by the mark-to-market recognition. Our year-on-year operating cash flow is summarized on Slide 8. OCF was about $3.2 billion in 2013, up approximately $250 million. Full year drivers were similar to the quarter. In addition, receipt of proceeds from spent fuel litigation and higher income tax payments were also factors for the full year. Moving away from results, I'll now turn to our forward-looking financial update, starting on Slide 9. Keeping with past practice, we updated a few line items from the guidance table for late 2013 variances, including final results, weather, the District Energy sale and Utility income taxes. We have affirmed our operational earnings guidance range, but things have changed since we initiated in October. This year, the final pension and OPEB discount rates are higher than the 4.75% previously assumed. Pension expense will be lower, resulting in a benefit of $0.09 per share relative to the guidance assumption. Also, as of December 31, average revenue in 2013 for EWC's nuclear fleet has increased to approximately $55 per megawatt-hour, $4 higher than assumed in guidance. This $4 does not include the turnaround of the fourth quarter mark-to-market recognition. Offsetting, we're seeing headwinds to our capacity price assumptions. Our current full year estimate for the new LHV zone is now lower than we expected in October by a little over $1 per kW-month. You see the anticipated effect of these changes to EWC's EBITDA outlook on Slide 10. We also recently identified additional work that must be completed during Palisades' refueling outage that will increase both the duration and cost of the outage. Also, the Arkansas rate case outcome was clearly disappointing for earnings. Overall, however, indications for the year are positive. And with current expectations, we are near the top of the range. Beyond that is our goal, and our goal is achievable. But not everything is within our control, namely weather and market prices, and there's still 11 months to go in the year. We'll be able to better assess changes to 2014 guidance range with more confidence once we are further into the year. Looking beyond 2014, we have reviewed our strategy to position Utility and EWC for potential upturn. I'd like to touch on how that strategy aligns with our financial outlook. As Leo said, one key element of our strategy is managing our cost structure. Previously, we provided a 3-year O&M outlook of 1.5% to 2.5% compound annual growth rate off of the 2013 base year, excluding [ph] VY direct costs. That is shown on Slide 11. Today, we are affirming our O&M outlook, and we'd also like to provide some additional clarification. We previously indicated that we did not expect to reach the top of the range under normal operating conditions. Assuming normal operations, we expect to be near the bottom end of our outlook. Obviously, there's still potential for variability from typical drivers or unanticipated changes, such as changes in plant operating needs or even acquisitions, which we've previously noted. For EWC, with the exception of LHV, we use market forwards. Market prices beyond 2014 have not yet moved as much with the recent cold. But our outlook remains bullish, and we note the irony between triggering the cap in the ISO New England forward capacity auction for '17 and '18 and a backwardated heat rate curve to that point. Another important component of our growth strategy is our Utility sales growth outlook. We talk a lot about the unique economic development opportunity we have in the Gulf region. To help you better understand and track this opportunity, we're providing Slide 12, which we will update periodically. As you can see, as of December 31, we had approximately 85 projects totaling 2,400 megawatts in our potential pipeline. Potential means that the project has been announced, signed or is under development with a strong possibility of being completed in our service area and served by Entergy. Some of these projects will materialize within our 3-year outlook. Some are longer term. On the 2,400 megawatts, we had signed contracts to serve over 1,000 megawatts, and just under 500 megawatts are under construction. One example of a high-potential project under contract is Sasol's planned ethane cracker. In December, Entergy Gulf States Louisiana entered into a 6-year, up to 200-megawatt electric service agreement, Power Sasol's planned ethane cracker, the fourth such agreement announced in 2013. Also, none of our potential pipeline projects have been canceled or completed since EEI. Slide 13 recaps the 3-year outlook for each of our business segments. Note that the Utility 3-year outlook of 5% to 7% is based on a 2013 estimate in November, which translates to $950 million to $1 billion of net income by 2016. And that assumes a statutory tax rate in 2016. From a financing perspective, current outlook continues to solidly support the dividend at its current $3.32 per share level. Planned investment can be funded through an estimated $3.2 billion to $3.4 billion per year operating cash flow and incremental debt capacity for the period paid [ph] earnings. Finally, investment-grade credit continues to be a priority for us. In late January, as Leo said, several of our operating companies benefited from Moody's new regulatory review and received upgrades. For productive investments, those companies should have improved access to capital at attractive terms that will benefit customers. Executing on our strategy to achieve or even surpass our 3-year outlook will enable us to maintain solid credit metrics and continue to provide a competitive return of capital to our owners. And now, the Entergy team is available for questions.

[Operator Instructions] We'll take our first question from Julien Dumoulin-Smith with UBS.

So first, just going back to the rate case strategy, you've talked about -- a lot about load growth here. You've also alluded to O&M inflation. Could you perhaps just talk Arkansas, Mississippi, just rate case filings expectations over the next couple of years and the ability to hit the 5% to 7%? What are you thinking right now in terms of going back in, rehearings, et cetera? If you could kind of delineate that.

Theo, you...

I'll start. This is Theo. I'll start with Arkansas. I mean, obviously, we've made a filing for our petition for rehearing, and we'll see how that goes. And that will obviously inform us in terms of what we do going forward. In Mississippi, we're still evaluating whether we need to file a rate case. But the -- we do know that 2013 test year for our fee filing is suspended. And if we do file a case, it'll be to prepare Entergy Mississippi for a post-System Agreement timing and also to move some of our power management riders that we recover certain costs around -- capacity costs around plants today into base rates. We also had a depreciation rate filing that we did or studied. I believe that was done in 2011. That could be operated in a rate case in Mississippi. But I think also, it will allow us the opportunity to explore some alternatives to unknown and measurable changes that could occur during a rate effective period, as Leo talked about in his opening comments. As you go forward, obviously, whether we file additional rate cases will be impacted by a couple of things you mentioned: where we see ourselves in terms of sales growth; the bearish regulatory mechanisms we have in play within some of these jurisdictions that might allow us to change the dollars we're recovering without necessarily filing a base rate case, for instance in Texas, where have rider opportunities. We have rider opportunities in other jurisdictions as well, Louisiana and the case I just mentioned, Mississippi. In certain cases, you can get recovery through riders, primarily around capacity, without filing base rate cases. As to where we go past the case that I just discussed, that'll have a lot to do with the cost structure, with sales growth, with the investment opportunities that we have overall and the mechanisms that are in play that will allow us to recover that without necessarily having to make a base rate case filing.

Great. And I suppose just following up on the ITC deal a little bit here, just thinking about ability to reinvest in the system, specifically on transmission. I'd be curious, is there an ability to ramp up spending there? Is this more about a wait-and-see in terms of what MISO opportunities might be forthcoming? Can you perhaps give us a little bit more context for what that opportunity might be, if it exists?

Julien, the -- where our transmission is today, we do have in -- as we said, over the next 3 years, $1.7 billion in our plan for transmission expenditures. As I mentioned in my comments, there are several things out there that could increase that if there are projects that are beneficial to customers that reduce congestion, that improve reliability, that provide access to generation within the MISO equipment, et cetera, or they -- any PMBP projects that would be out there, part of the Order 1000. So there are things out there just in the system as it stands. The other aspect is, as we start to get more line of sight on this economic development front, certainly if 2,400 megawatts show up or more, that's just what's been announced to date, and there's nothing in the commodity strips that would lead you to believe that, that renaissance is over, that's going to provide a situation where there might be more transmission investment as well if you start adding -- like the Sasol example that Drew gave us, 200 megawatts in one facility. Those sorts of things are going to have an impact. So there is the opportunity for that transmission investment to be larger if there are things that we can do to benefit customers or to hook up new customers. And it would appear that the market is ripe to have some of that happen, but it's a little early to tell right now.

We'll take our next question from Kit Konolige with BGC.

Just a couple of somewhat unrelated questions. On the impacts that have been -- increased the expectations for 2014 EPS to the top end of the range, I think you mentioned pension was a $0.09 positive, and the -- and then the -- it appeared that a significant driver was higher expected prices at the nuclear fleet, the EWC nuclear fleet. Did you quantify that? Or did I miss that?

Well, I think, Kit, if you look at the slide that shows the EBITDA for EWC, you could see where most of that is, particularly if you compare to kind of the last update we gave last quarter with the same slide. And so it's up considerably. And eyeballing it, $150 million, $175 million.

$150 million, $175 million. And this is due to just higher prices as a result of higher gas prices and cold weather and generally the '14 commodity prices being very robust recently?

Yes, and part of it is what we've seen very recently. There's still a good bit of it that is still to come. This is a mark of current expectations using forward prices as of December 31st. And so this includes -- at that point, it included the entire year of forward prices. So we -- obviously, we experienced some of that in January. Some of that has been realized early this month. But then, we have the full year still ahead of us.

Right. And then, to switch to your discussion of strategic outlook for the nuclear plants in EWC, it sounds as though there's a little bit of a change in tone, whereas previously, I think, for example, at EAI, you had said that if you own ETR, you should expect to own Indian Point. Now if you -- sounds like if you own ETR, you should expect to own all the currently held nuclear plants, with the exception of Vermont Yankee, obviously. What's been the change there? Was that the capacity pricing in New England that really made the difference? Or am I seeing a change where there really hasn't been one?

No, I think you're seeing a change, Kit. You could – [indiscernible] anything to do with the near-term pricing. It's really a function of -- we've been telling you for a while that we are exploring opportunities, and in the exploration of those opportunities, we didn't find anything that we liked, and we like owning them better. And so that's where we are at this point. Then we still own Vermont Yankee also. I mean, we'll continue to open it, even when it's being decommissioned. So there is a change. We still believe that the separation of the risks would make sense, but we also believe in creating value. And if we can't do it without the right amount of value, then we're going to continue to hold those ransom [ph]. As you say, our strategy is to preserve optionality in those plants, and we do that operating and through our hedging strategy and through the licensing process, I mean, obviously, to manage the risk as best we can. So you did pick up on a change.

We'll take our next question from Stephen Byrd with Morgan Stanley.

I wanted to follow up on Julien's question on transmission. And Leo, you talked about a couple of categories of potential spend over time. Could you talk a little bit to the process at MISO and just what we should be looking for or thinking about in terms of, for example, as customers start to show up as MISO continues its planning, how we should expect to start to see some of the these plans sort of come forward in terms of further spending on transmission?

Well, the majority of it is going to be -- is what's in our base plan. And then the next layers of it will be what comes about through just normal business. It's just such that our normal business includes some significant potential load, as it were. It's if they're industrial customers as opposed to the residential customers and industrial customers of size. So a lot of that, while it's in MISO and there's a planning process when it becomes part of the plan, it's not -- in the realm of outcome, I don't think it's significantly different than what we have in general and have traditionally had. We just might have an opportunity bigger than the $1.7 billion. And then, as it relates to the process, once we start to move in over the next few years with the Multi-Value Projects, NEP projects, the more FERC Order 1000 things, then we'll have to compete in that arena, and we would expect so to do so and to be successful.

Okay, great. And I wanted to shift gears over to Indian Point. You had, on Slide 28, given an update on the status. I wondered, on the Coastal Zone Management paths, if you could just speak to next steps we should be looking for. You gave an update on sort of all 3 elements of the coastal zone process, but I wondered if you could just give us a sense for what -- next steps on those different paths.

Yes. Stephen, a couple of things here. So first is the consistency filing itself, well, has been extended to the end of 2014. That's simply due to the need for the parties to work together, share more information, further vet issues. So we really -- so that was previously set for March and was moved back to the end of the year. As it relates to our other option on grandfathering, I think you're well aware of the fact we lost the initial decision on that. We are in the process of appealing that decision to the state courts. And we may have further appeals depending on the outcome of that case. That will probably take us through the end of 2014 as well. And then, of course, we have the previous review argument, which is kind of held in the background as another option that the NRC has not yet ruled on and is also being considered by the state of New York. So we think, through all these various processes, that this will go on for a period of time. And eventually, we plan to be successful with it, but obviously, a lot of uncertainty now with the various cases that are ongoing.

Our next question comes from Steven Fleishman with Wolfe Research.

A couple of questions. On the EWC outlook, it looked like '15, '16 was a little lower if I -- kind of my ruler was correct, than at EAI. Is that just updating this New York capacity assumption?

That's certainly in there, Steven. Yes, it's -- yes, I don't know that we're as precise with rulers, but yes, it's -- that's baked in there. That's part of it.

Okay. So it's -- I mean, it's about flattish, I guess, overall. So it's not that [indiscernible].

Yes, I mean, I would -- that's the way I would describe it. I mean, we haven't seen the energy markets really move upward in any material fashion since then, a little bit in '15. But the capacity prices has clearly, like we've said, been offsetting.

Okay, because the '15, '16 kind of switched a little bit. '16 looks like it's stepping down a little bit. I assume that's the capacity, and the energy has moved, okay. And on your utility sales growth and the -- all this new industrial load and potential, can -- I know you've probably answered this, but just how can we track what is in your forecast and what is not? And if you do better in terms of getting more load and customers, is that something that definitely benefits the bottom line? Or is there like a lag issue in terms of spending money to serve it? Just how should we think about kind of when you update this? What's in there? What's not? And is doing better just definitely an upside?

Yes, Steve, this is Theo. I think when you think about what's in it, what's was not, primarily -- I think did talk about this a little bit at EEI, if I recall. What's in and in the forecast is basically the things that we felt had a clear line of sight on, felt good about at that time, which primarily are things we've had signed agreements or arrangements in place or was very clear we were going to have such an arrangement. So that's what you have in the forecast. As we move forward, you see on Drew's slide, and I believe this is on Page 12, contracts signed. A lot of that will show up in that particular category. And basically, I believe maybe about 1/3 of that maybe shows up through 2016. So there's still amounts post the years 2016. So I think that's how you think about it. In terms of how it affects the bottom line, obviously, as the sales take place, depending on where you are within a process of your various regulatory mechanisms in those jurisdictions, will inform as to the impacts those will have. If there is investment associated with it, as Leo talked about, the transmission opportunity, obviously that investment would be incorporated, and you would have the sales, you would have the cost. As rates get reset, obviously the sales become a part of your revenue requirements, the costs become a part of your investment. And the investment, obviously, and the returns on it flow to the bottom line. The sales get -- become a part of that process of resetting rates

Steve, this is Leo. Just to kind of add to that, if you think about it, for the near term in particular, it would primarily be transmission investment. To the extent these are large loads, you would anticipate that the sales level would be significant enough to make it positive to the bottom line, even though there could be some lag in the recovery of the transmission investment. In the areas where you've got FRPs, you're going to have some catch-up in the next year. And then in the case of Texas, for example, you've got the transmission rider, which could help in some respects. But we're trying to put the regulatory mechanisms in place to mitigate any lag. But at the same point in time, the size of these could make a big difference in how this turns out as well.

Okay. So just one other clarification. If you announce another kind of new customer contract, let's say tomorrow, that could be already in your backlog? It's not necessarily incremental? Like not all these have already been announced?

That's correct. Yes, so that would move something from the potential pipeline maybe into the contracts signed line.

Our next question comes from Paul Patterson with Glenrock Associates.

The expectations for the new capacity zone in New York, I was wondering if you could just sort of give us a little bit more flavor as to what they might be. And the impact of Danskammer, if it's there or not there, do you guys have any sense -- sensitivity about that? Or any sense you could tell us about that?

Sure. This is Bill. As it relates to -- I think Drew mentioned in his script that as it relates to Lower Hudson Valley zone, we saw a decrease there from the plan that we had announced last fall probably a little over $1 a kW-month for LHV. We've seen -- our point of view for the rest of the state perhaps increased a little bit. So if you think about it in doing your analytics, you might want to think about it as right now, we're at probably a $2 a kW-month uplift for all of our New York ISO capacity, whereas previously, we had indicated a $3 a kW-month uplift for the LHV zone itself. Right now, that estimate does not assume that Danskammer is in service for this summer. My understanding of that right now is that, that is a issue which will be evaluated in March of this year, and we will know better then as to whether or not that is -- that plant will be able to operate and qualify as capacity for that zone.

Okay. And any sense as to what that would be if they -- if it does show up?

I do not have that at this point in time.

Okay. Okay, great. And then just finally, with the mark-to-market loss reversal, I thought the explanation was really great. I just wasn't clear on the quantitative impact that, that had in terms of the impact for 2014 versus 2013 as a result of it.

Okay. So the mark-to-market loss in '13 was around $45 million pretax. And then we would see that uplift in '14. So in that -- it's in that EBITDA number that you're seeing in that chart on EWC.

Okay. And so that's not going to be there probably in 2015? So that's probably part of the reason why it goes down as well then?

That's correct. That's correct. And actually, some of it's at VY as well. That's -- for some of the hedges there. So that's one of the reasons why VY looks much larger than expected.

Our your next question comes from Michael Lapides with Goldman Sachs.

A couple of questions, a little bit unrelated to each other here. First, residential demand. As I understand it, you get a lot more of your Utility margin from the residential and small commercial customers than you do on the industrial side. Can you just talk a little bit about what you're seeing in residential demand? I mean, it's lagged industrial significantly. The major start-ups you're seeing in your service territory would imply a growth in job levels and improvement in unemployment rates, but it doesn't seem to be reflected in residential load levels.

Theo?

Sure. Mike, I think what you're seeing, I would believe, would be consistent with what you're seeing with other companies across the country. You're starting to see the effects of energy efficiency. And I think as we started the year of 2013 on our first call, we talked about our views of the impacts of that. And we would expect to see residential sales growth tempered. And, as you can see from our results for the year, they were actually slightly down a little bit. That's not inconsistent with our expectations. I will say the degree of which it's down is probably maybe a little more than we had expected, but not much. As it relates to kind of the economic change, I think what you see, obviously, is a net effect. We do see -- still see positive customer growth if you look at our customer count numbers. But what you're starting to see, again, I think, is a phenomenon that you see across the industry, which is usage per customer is going down. So while I don't -- I think that you are seeing some positive economic effects through actual increase in customer counts, energy efficiency, obviously, is having an impact on what you would see incrementally relative to those increased customer counts.

Can you talk a little bit about the utility margin, meaning how much as a percent of total comes from the 3 big customer classes? Just trying to kind of, I don't know, get my arms around demand levels, customer growth and megawatt levels on the industrial customer side versus what's happening -- actually happening to the Entergy Utility's margins.

Just in ballpark numbers, I think what you see, residential maybe is maybe even larger, around a $0.04 or so; commercial is $0.03; and maybe industrial, maybe somewhere around $0.02, generally speaking.

Got it, okay. Drew, a question for you just real quick. On cash versus GAAP taxes, what do you expect to be in the way of a cash taxpayer over the next few years? What's embedded in 2014 guidance?

Well, we haven't -- from a guidance perspective on earnings, we've put in -- I think it was about 36% for an effective tax rate. Given our NOL position, we would expect our cash tax rate to be lower than that, but we haven't put any guidance out for that specifically.

Materially lower? Like do you -- would expect to be a cash taxpayer? Or are you likely in non-cash tax paying status for a few years?

I wouldn't say we're in noncash tax paying status because we actually make deposits and those types of things as we go forward. So we will be paying some taxes, but it will be materially lower, I would expect, to the effective tax rate, at least for '14.

Got it. And how big is the NOL at the end of the year?

Well, that will be out in the K. Right now, I think it was at -- as of last year, it was still around a little over $12 billion. Most of that was tied up in the decommissioning election of cost of goods sold. About 3/4 of it was there.

Our your next question comes from Brian Chin with Merrill Lynch.

Could you just remind us again where the dividend policy is at? What's sort of the clean slate here?

As Drew mentioned, right now, the plan we have supports the dividend policy. The board will continue to look at where we stand at the dividend, as we have always been. The dividend comes from the utility, and anything that comes out of the merchant business is distributed differently. So that strategy or that outlook hasn't changed. As we look at the dividend, we would be looking at that as we grow, as the utility grows, as we look at the overall risk profile of the company and we look at the reinvestment needs that we have based on just how quickly the utility grows and what happens with the need for capital there. If it were to be above, just for example, the 3-year plan that we have now, if the load growth shows up the way we would like it to, which would be higher than the 2% to 2.25% range, then certainly that may increase the need for capital within the utility impact. Not only earnings growth that would give us the opportunity to pay a higher dividend but also the reinvestments we need to be returning to make it. So all of that's going to go into the mix, pretty much like it always has. But the bottom line of the utility pays the dividend and the merchant business cash flow is distributed differently is still the order of the day.

And we'd like to turn the conference back over to our speakers for any additional or closing remarks.

Thank you, David. 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 6761109. The telephone replay will be available through noon Central Time on Tuesday, February 18, 2014. This concludes our call. Thank you.

That does conclude today's conference. We thank you for your participation.