Entergy Corporation (ETR) Q1 2014 Earnings Report, Transcript and Summary

Good day everyone, and welcome to the Entergy Corporation First Quarter 2014 Earnings Results Conference Call. Today's conference is being recorded. And at this time, I would like to turn the call over to Vice President of Investor Relations, Ms. Paula Waters. Please go ahead, ma'am.

Good morning. Thank you for joining us. We'll begin today with comments from Entergy's Chairman and CEO, Leo Denault; and then Drew Marsh, our CFO, will review results. [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. By any objective measure, the first quarter of 2014 was extremely successful. Our operating groups provided excellent service to our customers under extreme conditions. Our commercial groups continued to provide growth opportunities while aggressively managing risks. Our support functions continued to evaluate and implement more standardized lower cost end-to-end business support processes, spanning multiple functions within the company. We continued our mission to support our communities through assistance programs and our direct contributions, and as a result, we created value for all 4 stakeholder groups: our customers, our owners, our employees and our community. This performance was achieved in both the Utility and at EWC, and our financial performance followed suit. Mainly, operational earnings per share were more than double those of last year, setting a new first quarter record and were driven by top line growth and lower costs. This quarterly performance, coupled with higher Northeast forward prices for the next 9 months, led us to raise 2014 earnings guidance by more than 20%. To be clear, weather is not a strategy. Colder-than-average temperatures for multiple stretches of time in the Northeast and in the 4-state Utility service territory had a significant impact, but weather is just one part of what we think is a strong overall story. We must perform day in and day out. To that end, our employees and equipment performed great this quarter. Let me give you some highlights. Starting with EWC, our nuclear plant performed well overall to help serve increased power needs due to increased demand in New York and New England over the past 3 months. To put this into perspective, the weather in this region, as measured by heating degree days, was 11% colder than normal and 13% colder than last year. As it relates to the EWC fleet operation, the EWC nuclear plant's first quarter 2014 forced loss rate improved by nearly 60%, with the shortest refueling outage ever at the Indian Point site at 24 days. We also successfully completed a refueling outage at the Palisades plant, which took a total of 56 days. Our outage performance would have been better, however. It took 15 days longer to make necessary and proactive replacement of plant components following a planned inspection. Another planned activity during the Palisades refueling outage was an inspection of the reactor vessel head in accordance with the revised NRC rule making on reactor vessel embrittlement. The inspection went as planned, and the results identified no discrepancies. We have a high confidence that our analysis supports operations through the end of Palisades operating life and that the NRC will approve our submittal reflecting just that. As it relates to our point of view on our hedging strategy, while we certainly have been challenged with lower market prices over the recent past due to lower natural gas prices and market design concerns, I believe we have been very consistent in communicating our bullish point of view related to the Northeast market. This point of view was based on our model-supported views surrounding undervalued forward heat rates generally due to a lack of liquidity. There are a few natural buyers and many more generators seeking to sell, resulting in a larger discount than at time of delivery, a robust winter demand picture for the Northeast region supporting natural gas prices and constrained Northeast infrastructure that offered asymmetric upside potential. While the severity of cold seen this past winter and the degree of price upside that was realized exceeded our point of view, we are directionally prepared to benefit from it due to our hedging practices. A few years ago, we made adjustments to our hedging strategy to incorporate more financial product, in part to protect our hedge portfolio against certain risks that include operational and liquidity risks and also to position our portfolio for asymmetric upside exposure in a cost-effective manner and to allow for more upside consistent with our bullish point of view on power pricing. It is important to note that we continue to remain bullish in the intermediate term as it relates to our point of view on Northeast gas and energy prices for the reasons I previously mentioned. That said, I'd like to talk about longer-term market issues. We believe the Northeastern U.S. energy market face several challenges which could lead to a repeat of the volatility experienced this past winter. Market design problems do not support the continued operation of critical generating resources in the region, resulting in declining reserve margins over time, a lack of fuel diversity in the region and an overreliance on natural gas. If we continue to see the Northeast power markets drive what should be economic units to retire prematurely and not fairly reward generators for the attributes they provide, including fuel supply diversity and reliability as well as environmental benefit, what was a volatile outlier this winter and last could become a recurring situation. In addition, this year's winter exposed serious infrastructure limitations -- limitation, which constrained the operation of some resources during periods of high demand. For example, there is simply not enough natural gas pipeline capacity in New England to serve both heating demand and natural gas by power plants during extreme cold. Concern over this lack of pipeline and delivery systems in New England is shared by the Obama administration. Earlier this week, the U.S. Secretary of Energy met with 150 state officials and industry executives, environmentalists and others in New England as part of a federal review of energy issues ordered by the President. The region is evaluating the situation, but any solution, whether new pipelines or gas by wire, that is new transmission lines into New England from Canada or other places, will be difficult, expensive and will take a considerable amount of time. Whether any of these options deliver the most reasonably priced power to consumers or meets regional environmental, price stability, economic growth and other objectives is unclear. We believe the markets today are not structured to value these attributes. We are committed to constructively addressing these market issues with regulators and other stakeholders, and we are seeing signs of progress. For example, the downward sloping demand curve in New England's next forward capacity market is a start. A sloping demand curve is important because it values all resources, not just at the point of resource inadequacy. The Federal Energy Regulatory Commission has ordered ISO New England to have this in place by the next forward capacity auction. However, keep in mind that price signal won't be realized until mid-2018. And making exceptions for renewables, as was proposed by ISO New England in April filing with FERC, further undermined the efficient operation of the market. Poor market design and continued interference with market mechanisms is what has led ISO New England to the place they are today, the declining market margin, inadequate research diversity and the risk of additional retirements in the region. We will continue to constructively work with the stakeholders in New England to develop proposed market design changes. In New York, we have also seen progress as it relates to improved market design, yet future challenges do remain. To give the market proper pricing signals for locational capacity needs, the Lower Hudson Valley zone, approved by FERC, will become effective next week. The summer strip auction covering the months of May through October cleared at nearly $10 a kilowatt month. This summer and May monthly auctions cleared at similar levels. All in all, these pricing data points demonstrate the need for capacity to supply customers in the constrained zone of New York. To summarize, these operational hedging and market advocacy activities of the past 3 months are focused on advancing our EWC strategy of preserving optionality and managing risk. What has transpired illustrates ways the portfolio has option value, and we have the ability to capture that value book now into the immediate future given the realities of this market. Realizing that requires the plans being online both now through solid operations and in the future, including the license renewal of [indiscernible] a balanced hedging strategy takes us towards our point of view but maintaining adequate downside protection and continued emphasis on changes in market design so that the reliability, fuel diversity and environmental attributes provided by these units are both valued and compensated. The Utility also performed well this quarter. Our performance in storm restoration illustrates our capability and dedication when more than 13,000 employees, contractors and mutual assistant workers responded to 4 ice storms from January through March. Our employees are not only storm tested. They are leaders in storm restoration and proactively keeping our customers informed during outages as recognized by J.D. Power and Associates. It was unprecedented when our utilities were the top 5 performers in proactive outage communications in J.D. Power's 2013 Electric Utility Residential Customer Satisfaction Study, but we did it again, as reported earlier this month, in the 2014 study. Also exemplifying our strong performance is the fact we earned yet again the Edison Electric Institute's storm Recovery and Assistance Awards for 2013. Entergy has earned EEI's Emergency Recovery Award or Emergency Assistance Award every year for 16 consecutive years, the only utility in the country to do so. Also during the quarter, our weather-adjusted sales growth was solid for our residential, commercial and industrial segments. For industrial customers, expansions make up 1/3 of the growth this quarter. This is not new. In fact, in the last 5 years, since 2008, we have seen over 50 expansions by our current industrial customers as well as a couple of new major facilities. Expansions during this time have driven an average industrial growth rate of nearly 2% per year. The factors driving the economics of these historical expansion projects are similar to the factors we are projecting for new facilities in the coming years, namely favorable domestic input energy prices against competitors in other countries, infrastructure and regional benefits of consolidating and expanding in the Gulf South versus other parts of the country and supportive communities and constructive regulation. The next phase in this regional industrial expansion has the potential for a significantly greater impact. That's what we have been analyzing and preparing for this past year. We've identified around $65 billion of high potential projects through 2019. Noteworthy developments include a ruling on the air permit for the new Big River steel plant in Arkansas that is expected tomorrow. If approved, construction could start this summer. In Louisiana, an expansion of an existing steel mill began operation late last year and ramped up faster than expected this quarter. In Mississippi, teams worked with local communities to qualify 4 large industrial sites in 4 counties. We expect to complete this process by November 2014. Finally, in Texas, there was a groundbreaking to build the largest methanol production plant in the United States at a cost of approximately $1 billion, which will bring in approximately 3,000 construction jobs and approximately 240 permanent jobs in the Beaumont area of our service territory. Some of these projects we have contracts to serve, others we are working on. The bottom line is for us to help bring these projects home to our community. The economic impact from the direct jobs, ancillary companies and services, new customers, taxes and other resulting effects will benefit our business in the long term, even as it benefits our communities, customers and employees in the short term. That is why economic development is central to our Utility strategy, and we are looking into all areas to support and promote it. One example of how we can support economic development is in the regulatory arena. Entergy Louisiana and Entergy Gulf States Louisiana notified the Louisiana Public Service Commission this week that they will file a study in June containing a preliminary analysis of the business combination of the 2 companies. This is a study we agreed to complete in connection with the resolution of the company's rate cases. While we expect to learn more once we complete the study, we anticipate that a larger company would be more nimble and efficient, benefiting our 4 key stakeholders and simplifying the regulatory process for our regulators. The combination could improve financial flexibility, helping to finance the Utility's investment required to serve new industrial customers and supporting the state in bringing to Louisiana jobs and regional economic growth opportunities. We continue to make progress on other regulatory agenda items in support of our Utility strategy. In Texas, earlier this month, we filed a unanimous settlement in a rate case allowing for an $18.5 million base rate increase and 2 limited term riders to recover cost. The return on equity of 9.8% reflected in the settlement matches what was authorized in the 2011, 2012 rate cases. The settlement also sets baselines for future use of the purchased capacity cost, distribution and transmission riders. The unanimous settlement is now before the Public Utility Commission of Texas, and a decision is expected next month. In Arkansas, the commission took up our rehearing request for the 2013 rate case, including our request to review the low authorized ROE and a financing formula for construction projects that do not fully compensate Entergy Arkansas for its cost. The next steps are up to the Arkansas Public Service Commission, but we are cautiously optimistic that we are able to explain our concerns about how the prior order hinders our shared objective of economic growth in the state. Again, to take a step back from the details, this quarter, our utilities performed when needed most. We responded to numerous storms while maintaining safe and reliable service. We saw strong retail sales growth, including industrial sales, and we continue to make progress in our regulatory jurisdictions for constructive outcome that align the interest of our 4 stakeholders. It should not surprise you that industrial expansion in the Gulf region is one of the topics we will explore on June 5 at our Analyst Day. While we are actively preparing for our event, I wanted to give you a preview. On a macro basis, there are 2 things trending in our favor; the industrial renaissance that is currently impacting our service territory and the market price of power. We plan to explore with you why we are so optimistic about both of these market conditions and why they can coexist. We can position ourselves to succeed when we recognize opportunities such as these. We are not simply passive participants. We see that as a duty and a privilege, to have a role in bringing these benefits home to our stakeholders. So the second broad area we plan to cover on June 5 is what we are doing to capture these market opportunities. Our goal is to give a better picture of our strategy and levers that not only meet but exceed your expectations. We know that will be a tall order, and it certainly won't all be solved in one day. But rest assured I and the entire executive leadership team are committed to explaining our strategy and why we believe it can be successful, to providing a clear roadmap of where we're headed and then most importantly, to continue to mobilize the entire organization to deliver on our commitments. The first quarter is a sample of what we know is possible. With that, I'll turn the call over to Drew.

Thank you, Leo, and good morning, everyone. Today, I will review the financial results for the quarter as well as our updated 2014 operational earnings guidance. Starting with Slide 2, our first quarter results for the current and prior years are shown on as-reported and an operational basis. Operational earnings per share were a robust $2.29 for the first quarter of 2014 compared to $0.94 in 2013. The significant increase was due largely to higher net revenue from EWC's Northeast nuclear fleet, while Utility net revenue was higher as well. Operational earnings excluded special items from the decision to close Vermont Yankee and HCM implementation. Earnings and operational results on Slide 3. Starting with Utility, operational earnings per share were $1.13. This is $0.40 higher than the $0.73 earned in the first quarter last year, and there are a few key drivers that I'll highlight starting with net revenue. As reported in the pre-release, weather was positive in the current period compared to the mild temperatures in the fourth -- first quarter of last year. In addition, positive weather-adjusted sales growth contributed about $0.05. On a weather-adjusted basis, billed sales were 2.1% higher than the comparable period. The increase was consistent across the residential, commercial and industrial customer classes, with industrial sales growth for the quarter at 2.5%. Industrial gains were broadly spread across multiple segments. The net effect of regulatory actions was also a factor for Utility net revenue but was largely offset by other line items and therefore contributed only about $0.03 to the quarterly earnings increase. The net revenue increases were partially offset by an unfavorable unbilled revenue variance of approximately $0.09 quarter-over-quarter. Besides net revenue, nonfuel O&M was also favorable quarter-over-quarter, reflecting lower pension expense from a higher discount rate as well as last year's cost reduction effort which resulted in fewer employees and changes in benefit plan. When taking into account expense increases that have designated net revenue recoveries, such as storm reserves and energy efficiency program cost, the quarter-over-quarter improvement was about $0.10. Now moving on to EWC. EWC's operational earnings of $1.39 per share in the first quarter of this year was higher than the $0.46 earned in the prior period. EWC results included an income tax benefit, which resulted from a change in New York State tax law. The change resulted in a onetime reduction in deferred taxes of approximately $21 million. Turning to EWC EBITDA drivers on Slide 4. The $261 million increase was driven by higher realized wholesale energy prices for EWC's Northeast nuclear assets. The average realized price for EWC's nuclear fleet was $89 per megawatt hour. Leo mentioned that our hedging strategy was part of the story for EWC's earnings this quarter. To add to that, I will simply remind you that we maintain upside in many of our contracted hedges through a protective call to address operational and liquidity risks in high-price environments like we experienced in the first quarter. This discipline actually reduces our overall risk profile. We view Slide 5 for some time to illustrate how our contracting strategy provides asymmetric upside opportunity. Note the positive slope to the line and higher prices, illustrating the protective call strategy. Also included in net revenue is certain mark-to-market activity, which includes a range of items. In the first quarter of this year, mark-to-market activity netted to approximately $21 million pretax, which includes the -- which included the positive turnaround of the $45 million pretax mark in the fourth quarter of 2013. A natural question is whether or not this quarter could repeat next year and beyond. As Leo discussed, we analyze and prepare for longer-term fundamental changes. We don't rely on weather to achieve our goals, but we do remain bullish on our point of view of energy pricing in the Northeast market. We witnessed higher volatility in these markets in the last 2 winters and believe this will continue in the foreseeable future due to constrained Northeast infrastructure. Looking forward to next year, should the same conditions repeat, we would expect to be able to again capitalize on the optionality of our portfolio. However, note that we will not have the benefit of a largely unhedged Vermont Yankee unit as we did this winter, and our revenue opportunity will depend on the specific positions we have. Recently, the cost of volatility has gone up, and some products we used this winter are more expensive or are currently not available from counter-parties for next winter. We are constantly evaluating the EWC portfolio to determine which product will best position us for 2015, while balancing cost and risk against our point of view. Nevertheless, if the same market conditions were to prevail next year, we think we could experience up to 80% of the first quarter 2014 EBITDA without changing our hedging philosophy. The bottom line is that our portfolio going forward still has plenty of price upside opportunity and embedded option value. Now moving on to operating cash flow shown on Slide 6. OCF was $767 million in the current quarter, up $223 million or more than 40% higher than 2013. Again, higher net revenue from EWC and Utility was the largest driver, demonstrating that the high-quality earnings we realized in the first quarter resulted in near-term cash flow. I'll now turn to 2014 operational earnings guidance on Slide 7. The strong first quarter results and increased volatility in Northeast Vermont and forward power markets pushed our 2014 earnings expectations above our original guidance range. Our revised operational earnings per share guidance range is $5.55 to $6.75. Starting with Utility net revenue, there are a few drivers to note. First, we had $0.18 of positive weather that was partially offset by unbilled revenue, as we noted earlier. Also, the outcome of some rate actions were different than originally planned last October. Looking forward, we still see 2014 Utility weather-adjusted retail sales on track to achieve the 1.9% growth we have previously noted. At EWC, based on realized prices to date and forwards at March 31, net revenue is expected to be significantly higher than we thought last October. Approximately $0.90 per share was realized in first quarter results, and approximately $0.45 per share is yet to come and still subject to market price variation. The revised midpoint also reflects combined negative $0.20 in O&M and other which is largely driven by the expectation for opportunistic spending in O&M, partly attributable to EWC performance this year and partly attributable to the potential to accelerate projects and in improving operation performance and reliability to benefit customers. Looking at the opportunities available to us now, this number may be lower over the balance of the year at both Utility and EWC. The higher expense is also net of the expected benefit from a higher pension discount rate. Moving down a line, we currently see a higher effective income tax rate which will reduce earnings by $0.05 per share. The overall variance is the net effect of changes in the 2 businesses. About half of the effective rate increase is simply due to the application of statutory rate, the incremental pretax earnings causing the overall effective tax rate to rise. At the same time, some of our expected Utility tax benefits are now more likely to fall into a future year. On the Utility segment, I will also note that most of the changes are not fundamental to the underlying strength of the business, and there's no change in our expectations in Utility earnings growth through 2016. Of course, we still may do better in 2014. Overall, our guidance range reflects our expectations of earnings and volatility today. Despite all that has happened, it's still early in the year, and undoubtedly, things will continue to evolve. We won't update the guidance range for changes as they arise unless we expect the year end operational results will likely end up outside the current range. The first quarter of this year was a good beginning. We created real value for our stakeholders and highlighted the optionality of EWC's business as well as the value of nuclear fuel diversity in the Northeast market. During the quarter, we've also seen encouraging signs for capacity auctions as well as improvements in forward power prices beyond 2014, moving towards our long-term bullish point of view. At Utility, with much of the uncertainty from 2013 behind us, we're focused on positioning ourselves to take advantage of the opportunities ahead. In particular, the strong economic development pipeline went beyond this year as seen in a new format on Slide 11. As Leo said, we'll delve deeper into these and other opportunities at the upcoming Analyst Day. We look forward to seeing you there, and now, the Entergy team is available for questions.

[Operator Instructions] We'll take a question from Kit Konolige from BGC.

A couple of follow-up items. So can you go into a little more detail on the increase in the O&M spending? If I understood it correctly, I took away that it's an opportunistic spend due to the improved revenues and sort of reinvestment, if you will. Are there particular segments or companies or projects that you're spending that O&M in?

Thanks, Kit. Yes, so at EWC, that is certainly the case as well as the Utility. And so at EWC, part of that is paying people for the great performance that Leo talked about in the first quarter, and part of it is looking for opportunities to move projects forward if those arise. The challenge associated with those, of course, is that they are difficult projects to plan. It's not easy to move a lot of O&M forward like that, and so we are getting an early start on it. It's easier to pull back than it is to decide at the end of the year that you want to move a lot of O&M forward. At the Utility, we're a little ahead of -- in that same regard. It's something that's beneficial for customers in terms of rate stability if we can offset some of the beneficial weather. And since it's still early in the year, we don't know that we'll be able to actually have the opportunity at the Utility to do that. And we'll certainly be looking at each company, because not all Utility companies will likely have that same opportunity. So -- but that's what we're working on today. We're preparing. We're trying to form up projects, and we're looking for those opportunities. But there's no guarantee that we'll openly end up spending that O&M.

And on a separate area, you mentioned that -- if I heard it right, that 80% of the EBITDA in 2014 first quarter could recur in first quarter '15 and at $0.90 a share of the increase in the guidance range was due to the first quarter. First, just wanted to confirm that those were correct, and I just want to try to get an idea of how much of a, if you will, permanent baseline change there is here in level of EPS and EBITDA that will recur in '15 and forward. Obviously, forward prices have gone up some, and as you say, volatility has gone up and so on. If you can give us some idea of what we're looking at going forward, that would be a big help.

I'll start with the math part, and then I'll turn it over to Bill for the point of view discussion. So I think the math that you had, Kit, was correct, but I'd put a bunch of caveats in there as well. So those are -- it's 80% under the same market conditions that we see next year in the first quarter. And yes, that is against the $0.90 increase plus the part that we already had built into guidance. So it's the overall EBITDA that I was talking about when you look at it that way. And so part of that is from the fact that Vermont Yankee is not going to be in our portfolio next year. And part of that is, as you said, forward prices have already moved up, so we do have some still open positions in our remaining portfolio. They benefited from some of the price moves so far. And so you get up above what Vermont Yankee's contribution was this quarter, because some of our other positions have benefited from that early price rise. So with that, I think I'll turn...

This is Leo, Kit. Let me just jump in to make sure I -- I don't want you to -- I want to make sure you get the right specifics. The 80% Drew was talking about is if the same price volatility happened next first quarter that happened this first quarter, we're positioned that we can capture that value. If you want to look at -- when you were asking about permanent, the slide we have in the deck on EBITDA, that's where the market is today. And so you may not have been thinking this, but I just want to make sure. We're not saying that we already have 80% of what we've got this quarter -- first quarter next year. If the same thing happened, we're positioned to capture it. That's what Drew was trying to say.

It's the same market conditions but not the same weather, obviously.

Well, Kit, whatever reason. It might happen because of weather. It might -- that would probably be why it would happen.

I get it, okay. It's basically just removing the Vermont Yankee impact.

That and some of the price rise that we've already seen so far this year. As you said, [indiscernible] prices have come up a little bit already.

Our next question will come from Jonathan Arnold with Deutsche Bank.

Just a quick one on the -- in the Slide 21, you're just alluding to talking about just sort of the look at market today. Obviously, you don't specify the numbers, but it seems from the movement in the 2015 number in particular that it took -- probably up about $100 million of EBITDA outlook versus the prior version of this slide. I guess my question is, you've got 74% hedged. You now expect to realize 53% on that versus 49% before, which is a $4 uplift, and then the market pricing slide is also kind of a $4 uplift. And it seems 4x your generation ought to be closer to $150 million than $100 million. So is there some offset? Does my math make any sense there? And is there some offset embedded in there? Or are you sort of embedding some conservatism about next year in particular?

I'm not sure I followed all the way through on the last part, but I think it should all kind of hold together. I don't think there's any big offset built into the numbers that we're showing you there.

But your hedged is up $4, and your open is up $4, and you've got 35 terawatt hours. It just doesn't seem that the bar is moving as much as it should by some reasonable margin.

Well, there is a bit of rounding in there as well, but there's -- we don't have any unplanned or hidden offsets in there. We're showing you just the revenue uplift there.

Okay. And then if I may, on this discussion you just had about the 80% and the 20% if we have a repeat of this year's conditions next year. What -- can you be a bit more specific about what kinds of products that you use this year are not available in the market for next year and how you're -- and just some more color on how you're adapting to changes in available products in the market?

Sure. This is Bill. I think as we've explained previously, we use a variety of different products. So some of that includes unit contingent. Some of that includes cap collars. And we use a variety of different option structures, both European, which clear on a forward basis versus Asian options, which clear more on a daily basis. As you can appreciate, as the volatility in this market has increased and if you look at daily volatility from -- for example, from winter '13 to winter '14, we've probably seen a pickup of over 50% between '14 and '13. Obviously, some folks who were willing to sell those products in the past have reconsidered their risk profile. And so right now, they are not as willing to offer those products, and so we have to readjust our portfolio to what's actually available in the market to be able to capture that. However, as Drew said, we still believe we have the opportunity to capture a significant portion of those upside, but it will be a different portfolio and there will be different prices associated with the products available due to that increased volatility.

We'll take our next question from Paul Fremont with Jefferies.

I think I just want to better understand the changes that are taking place in the Utility guidance for '14. I guess the starting point would be there's a $0.20 reduction in the midpoint, and that includes the $0.18 of positive weather in the first quarter. So are we really looking at sort of a delta here of $0.38? Is that...

Yes. This is Drew, Paul. That's a good question. So in the net revenue line, there is an offset to that $0.18 in our unbilled revenue category. And unbilled is something we don't normally talk about, because it's usually kind of plus or minus right around 0. But this quarter, it's a large number, and it has to do with sort of the estimates at the end of each quarter that we make. And so it was -- it's really sort of a holdover from the very end of '13 when it was really cold, those last couple of weeks in December. Those dollars have since gone into the build revenue category. And we're backing them out of the unbilled category, and you see the offset to the build. So it's about -- as I said, it's $0.09 quarter-over-quarter. It was about $0.10 between December and the first quarter of this year. So that's the biggest thing in that net revenue line that you're probably not seeing completely there.

Right. So that -- in other words, if that's $0.09 out of what would be potentially $0.38, what would be -- or is it $0.09 out of what really is $0.20? That's what I'm trying to figure out, because don't I need to add the...

If you're looking at $0.30, I think you're looking at quarter-to-quarter versus the $5.20 midpoint is just for 2014. And so our expectations for 2014 from the net revenue perspective have been largely met except you would say plus $0.18 for weather, minus $0.10 for unbilled and then a little other noise in there to get you that plus $0.05. And then...

Okay, so that -- but then that still leaves like $0.28. So in other words, I'm just trying to figure out what drove it -- what's driving the $0.28 and whether that's -- we should look at that as potentially recurring items or nonrecurring items?

I'm not sure I'm following where you're getting the $0.28 from. I'm sorry. I think when we said $0.28, it's plus $0.18 weather this quarter versus minus $0.10 first quarter of '13. So there's a $0.28 weather delta there. Is that what you're looking at?

No, I'm just taking the $0.20 change in the midpoint of the guidance, adding in the weather of $0.18 and then subtracting out the $0.09 or the $0.10 that you gave me for...

Okay. So then -- so if you come down on the guidance table, maybe what you're seeing is there's a bit of the opportunity spending, and then the other part is the taxes piece. There were some tax items that we thought would occur this year when we set guidance in October. It looks like those have pushed back a little bit, probably into '15, and so that has moved out. We don't -- we still think those things will happen. The timing has just changed on them. So those are the -- from the guidance table, those are the main drivers.

And the opportunity spend and the taxes together would sort of represent the difference? And -- because you also mentioned somewhere in there rate case outcomes.

Right, right. And so that's the smaller piece that's in that net revenue line item. That's part of what gets you down to the $0.05, and it has more to do with the Arkansas rate case at the end of the year probably than anything.

Okay. And still the expectation -- so even with sort of -- so in other words, if the Arkansas decision isn't reversed, you're still confident that you can come up with other offsets by '16 to get to the same $950 billion Utility net income number.

That's correct. That's correct. And as Leo said, we're looking for ways to exceed that. So we feel pretty good about where we are in terms of our 2016 number. Recall that, that doesn't include any tax benefit in it, and we have all the industrial renaissance and economic development opportunities in front of us. We think that's pretty safe right now.

Our next question will come from Dan Eggers with Credit Suisse. Daniel L. Eggers - Crédit Suisse AG, Research Division: Just on the hedging strategy, just make sure so I understand this, in the ratable or kind of point of view base that you guys are using, you didn't really increase hedge positions in the quarter. What is the thought process for adding on any out years as we move through this year? And what kind of percentage hedges do you want to have maybe going into 2015?

What -- I mean typically, we look at prompts here, we hedge 85% of that position. So that's kind of the guidelines that we followed and we'll expect to continue to follow. Of course this year, effectively, we were a little less than that due to the fact of the uncertainty around VY and how long that unit would run and the uncertainty around the CPG. But we would intend to be hedged in an 85% level. Daniel L. Eggers - Crédit Suisse AG, Research Division: Okay. And then on -- kind of with the MISO integration, you haven't had a little more time with it and then some of these issues that have come up between transfer between MISO classic and MISO South. Can you maybe give a little color on how you guys see that getting resolved, what impact that's had on even with the value proposition of joining MISO from what you guys originally anticipated? And is that going to have any bearing on potential CapEx opportunities with the MISO transformation?

[Indiscernible].

And gentlemen, this is the operator. We are unable to hear you at this time. [Technical Difficulty]

The point I was making on the SPP MISO issue for the company, SPP filed a complaint at FERC seeking to -- in essence, to have FERC charge MISO for any excess capacity beyond the 1,000-megawatt limitation and the tie-in between MISO North and MISO South, the point being that we're in the initial stages of the litigation, if you will. We have not -- we've not ruled out the possibility or likelihood of resolving that issue by way of settlement. But if we were to ultimately go to hearing and if SPP were to maintain their position, that is essentially what they're seeking, to limit that inner regional dispatch to 1,000-megawatts and to issue that payment to SPP from MISO for any megawatts beyond that 1,000-megawatt capacity, so the debate is really about that. We don't have a point of view on how MISO would address it if FERC were to find that SPP's position was well founded. But again, it's early in the process, so we really don't know kind of how that plays out at that the moment. Daniel L. Eggers - Crédit Suisse AG, Research Division: If this were to not get resolved, would this affect the value proposition of you guys joining MISO?

No.

Next we'll hear from Steven Fleishman with Wolfe Research.

Just wanted to first clarify how the LHV pricing came in relative to your expectation of a $2 increase for the full year, maybe just some color on that.

Yes. I think, as you know, the LHV pricing came in for the summer strip rider a little bit under $10. May auction, spot auction was around $12.25. So that's in excess of our original estimate.

Okay.

Not a whole lot. No, not significantly higher, but I mean it was a limit bit higher than what we had used as our kind of midpoint.

Okay. It's really hard to tell, because the $2, like an average for the year.

That's right.

So if we were thinking about this for a summer strip, was it $1 or $2 or something like that above what you would have thought the summer strip price?

It's less than -- much less than $1 on an average basis.

Okay. So that's -- any LHV pricing that's assumed in the EBITDA -- any New York capacity pricing assumed in the EBITDA charts that you have should be pretty close even though you didn't update for that. It shouldn't be that different based on what came out.

No, that's right. It should be consistent with what came out.

Okay. One other question just on clarifying kind of your point of view on New England and the like. And one could argue that there's obviously some pretty severe constraints. We also did seem to have some relatively severe weather, maybe not as much just in New England but like kind of the whole regional area or maybe the whole northern part of the country. So when you're talking kind of the bullish point of view and keeping your strategy the same, is it -- in a normal winter weather situation, do you think there'd be this much extreme or still have kind of an extreme option value that things are that bad in New England, that even normal weather, you want to keep the big option position?

Yes. I mean, here's the way we think about it is, we've seen volatility in those markets in the last 2 winters, okay? And this winter, obviously, was more severe than the winter of 2013, but nevertheless, we saw volatility. Now take into consideration for 2014, you've got Salem Harbor coming off, that's about 750 megawatts. VY will be off in the first part of 2015. It'll actually shut down at the end of this year. And then you've got other units like Brayton Point that will come off in 2017. So you're losing a substantial amount of resources over the next 4 to 5 years. In fact, if you look at their overall portfolio, you're going to lose about 4,000 megawatts which represents about 10% of their generation -- over 10% of their generation capacity. And reserve margins, obviously, have declined to the point where FCA 8 resulted in a deficiency, and you went to basically new build prices for new resources. So there's a lot of dynamics going on there, but we believe that there will continue to be constraints. While there's a minimal amount of new pipeline capacity coming on due to compression projects, that type of thing, we don't believe it's adequate to replace the additional capacity that will be retired.

Next we'll hear from Paul Patterson with Glenrock Associates.

So I hear your comments with Steve on the markets and what have you, and I also heard your opening comments which sort of indicated substantial concern with the way the market's being structured and what have you. And so I guess so to follow-up on this, do you guys -- I mean, I know what you guys are planning in terms of your filings, and I've followed your Exelon and Entergy joint filing on the Forward Capacity 9. But is there a plan b if, in fact, we don't get the market structure that you guys contemplate? Or should we think, basically, that things are sort of going in your direction and you guys are cautiously optimistic, and we're going to be seeing this sort of process continue in the stakeholder process, what have you and see how it plays out? Or is there perhaps another strategy you guys might be thinking about to get more value for your generation plan?

Well, it gets to be a little bit complex, but let me lay this out. So we're working through the stakeholder process both in New York and in New England and at FERC, and we believe there's improvements to be made in the capacity market design. We believe there's improvements to be made in the energy market design, and we also believe that there are opportunities to be fairly compensated -- for generators to be fairly compensated based on the actual attributes they provide, for example, on-site fuel, 0 carbon emissions, et cetera. That is going to be a fairly lengthy process. We think we will see some immediate improvements, for example, in ISO New England with real-time energy pricing coming up by the end of this year. Leo mentioned the slope demand curve. In the interim, as we have mentioned, we expect to see quite a bit of volatility in the markets just due to the constraints themselves. And so when you say is there a plan b, I mean we're kind of working all of those in parallel and we expect to see some continued volatility until some of these market issues get resolved. And I think the polar vortex brought to the attention of all the markets and to the regulators that we've got some structural design issues that need to be addressed.

Okay. Going back to Forward Capacity Auction #9, there is this new entry pricing extension that's being proposed, and I was wondering if you could -- if you have any thoughts -- I mean, obviously you guys are against it. I understand that. But if you have any thoughts about what the -- I mean what the impact might be if that provision stays in the -- it could be whatever the proposal that New England put forth?

I'll make sure I understand. Are you talking about the exemption as it relates to the renewables associated with that and the slope demand curve?

Yes, the slope demand curve filing and the new entry pricing extension, they're going to increase by 40%, MISO proposing, from 5 to 7 years for new entry pricing.

Yes.

Right. And I'm just wondering if you have any thoughts about what that impact might be or if that's significant given the constraints you're talking about on the gas side or...

I think our point of view is, we're not necessarily probably hung up on the 5 to 7. What has -- the most challenging for us is that when the ISO sets -- has new capacity enter the market, they choose a number of $7 a kW/month to provide existing generators. And so we believe, with the slope demand curve, that we have the opportunity, depending on resource availability, to see additional upside probably somewhere -- to $10 or $11 of kW/month once that slope demand curve gets put in place.

Regardless of these other market design issues such as the extension and the exemption that you were discussing earlier, that even with those in place, you still think that the capacity price should probably get up there. Is that right?

We still think -- I mean, obviously, we're concerned about the exemptions because it's another intervention into kind of what's referred to as the competitive market. But we -- even with that, we believe that there is some additional upside from a capacity perspective, capacity pricing perspective.

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

I wanted to just talk through the low growth numbers that you're seeing which is obviously robust compared to the national average. Are there certain areas that stand out as the strongest areas of growth? And do those offer potentially more transmission spend than you've been currently contemplating?

Theo, you want to...

Steven, this is Theo. I guess we talked about that we would probably want to talk, to answer the second part of your question, really more around customer class maybe somewhat. And when we look at residential and commercial, I think for the past few years, we've expected what we saw last year, kind of a dip in growth, that being driven primarily by energy efficiency policies primarily at the federal level, somewhat around -- primarily around lighting. And I think what you're seeing now in 2014 and the first quarter as compared to 2013 is really a return to what we had probably seen on the simple average load growth 2010 through 2012 prior to 2013. So -- and it's something, I mean, we somewhat anticipated post the dip we saw in 2013. When you now talk about industrial and you talk about the industrial renaissance, we talked about fairly extensively, Leo mentioned on this call and we've talked about previously, as that growth shows up and it shows up to the extent that we've embedded it within the context of our guidance numbers and to the extent it shows up even greater, yes, there is the opportunity for additional transmission investment to connect that resources to that demand growth, to that load growth. We have some -- obviously, a transmission bill we have within the context of our current construction plan reflects the expectation we have relative to -- out to the 2.5%, 2.25% sales growth. But to the extent that growth goes beyond that, which, again, given what we're seeing we view as a possibility, there could be transmission to connect those load pockets, and we could do additional transmission spend associated with that.

Stephen, from a transmission point of view, obviously, the way to think about it is, we've got a plan. The construction plan of the $1.7 billion over the next 3-year period, that would include some of the economic development activity we have in our plan for that timeframe, the 2% to 2.25% load growth. The renaissance, the projects, the $65 billion that's been announced that we were talking about, that goes up to 2019, so that's even farther. To the extent that we pick up more, as Theo mentioned, there's an increment that could show up just in the base business. So you've got the current run rate. You got -- if we could outsize the growth on top of that outside growth, we get more -- against the other 2 buckets also, obviously, exists with the -- you look at the FERC Order 1000 issue MEP, MVP projects that's out there as well that we would anticipate participating in it at some level, certainly, within our service territory. And then there's that opportunity outside of it too, which we're certainly going to consider what we do there as well. So there's -- the transmission part of the business is actually more complicated and more interesting because of it given those different buckets that are all pretty robust at this moment. But the normal load growth in and of itself is pretty good based on what we've already got line of sight on. The incremental piece on that could make that even better if were successful in our strategy to attract and serve that load. And then we've got these other 2 buckets that we're evaluating, and certainly, we're going to have to make sure we do everything we can to do the right thing for our customers and work with our regulators on how we would all work through that. But that's an extremely interesting part of the business for us right now that we get to work through.

That's very helpful, and I just had a very quick factual question just on the EWC business. I assume that the forecast still includes the DOE nuclear waste disposal fee. Is that correct?

Yes. Well, Stephen, there's, as you know, the possibility that, that might not be in there. We sort of factored that into our midpoint, $6.15. If it comes in or I should say goes away sometime in June, it would be about $0.08.

Understood. But in the out year EBITDA numbers, you're still assuming that you still have to pay that fee?

That's correct.

At this time, I'll turn things back over to Ms. Paula Waters for any additional or closing remarks.

Thank you, Vicky, 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 6761108. The telephone replay will be available through noon, Central Time on Thursday, May 1, 2014. This concludes our call. Thank you.

Again, that does conclude today's teleconference. Thank you all for joining.