艾索倫電力 (EXC) 2013 Q4 法說會逐字稿

Good morning. My name is Amy and I will be your conference operator today. At this time, I would like to welcome everyone to the Q4 2013 earnings call. All lines have been placed on mute to prevent any background noise. After these speakers' remarks, there will be a question and-answer session. (Operator Instructions) Thank you.

Ravi Ganti, Vice President of Investor Relations, please go ahead.

Thank you. And good morning, everyone, and thanks for joining the fourth-quarter and full-year 2013 earnings conference call. Leading the call today are Chris Crane, Exelon's President and CEO; and Jack Thayer, Exelon's Executive Vice President and Chief Financial Officer. They are joined by other members of Exelon's senior management team, who will be available to answer your questions following their prepared remarks.

We issued an earnings release this morning along with the presentation, each of which can be found in the Investor Relations section of our website. The earnings release and other matters that we discuss during today's call contain forward-looking statements and estimates that are subject to various risks and uncertainties. Actual results could differ from the forward-looking statements based on factors and assumptions discussed in today's call, comments made during this call, and in the Risk Factors section of the earnings release. Please refer to today's 8-K and Exelon's other filings for a discussion of factors that may cause the results to differ from management's projections, forecasts and expectations.

Today's presentation also includes references to adjusted operating earnings and other non-GAAP measures. Please refer to the information contained in the Appendix of our presentation and the earnings release for reconciliation of non-GAAP measures to the nearest equivalent GAAP measures.

We have scheduled 60 minutes for this call. I now turn the call over to Chris.

Thank you, Ravi. Good morning to everybody. Before I talk about 2013, I'll give everybody a little bit of update on the systems status. This year, this winter has provided us with a lot of opportunities to perform storm recovery. In the last 36 hours, we were hit pretty hard with snow in the ComEd zone. The recovery went fairly well and fast, and we're back up and running at normal levels. BGE was hit by freezing rain and ice yesterday morning, knocking out, at the peak, 175,000 customers. As of early this morning, there were 45,000 customers left to recover. We have adequate resources on the system now.

PECO was the one that was most slammed by any of the utilities by this storm. Over 700,000 customers have been affected thus far, making it the second worst storm in PECO's history, only beat out by Superstorm Sandy. We had, yesterday, 3,500 resources on the ground in the recovery phase, and that is ramping up even more today. ComEd is dispatching over 300 of their resources and will continue to support in the recovery. As of this morning, there were still approximately 430,000 customers out, but we expect to make some solid results in the next couple of days. This could last for a few more days, and we're really focused on the health and safety of our customers with another storm coming in. So, the Company is doing everything possible to expedite the recovery there.

So, I will switch now to 2013. It was a strong year for operations. Each utility -- PECO, BGE and ComEd -- achieved top quartile, and best-ever outage frequency and customer satisfaction numbers. Nuclear delivered a capacity factor of 94% and an all-time high of generation output. Gas and hydro availability upon demand was over 99%. And renewable energy capture was 93%.

We have been confronted by low-power and gas prices, impacts of subsidized generation and sluggish load growth. But that said, we delivered on our financial plan. We achieved $2.50 a share, which was right in line with our guidance. And Jack will be providing more color on that in a minute. We continue to manage costs. O&M was better than planned, realizing $360 million in merger synergies and on track to $550 million promised by year-end.

Previous actions have ensured solid credit metrics and balance sheet strength that allows us to continue investing in growth. You know about the $15 billion in utility investment we've talked of. Jack is going to provide more color on that also in a minute. We added more than 1.3 million smart meters during 2013, and did other infrastructure upgrades, and system hardening and transmission projects. We added 158 megawatts of clean generation, primarily at our Antelope Valley Solar facility. And we have a substantial generation growth in our development pipeline for the next two to three years, approximately 500 megawatts in contracted wind, solar, and the completion of our nuclear power uprates.

Public policy remains a critical focus for us. At the utilities, we saw meaningful improvement in the fair return on our investments in Illinois and Maryland. Senate Bill 9 in Illinois allowed us to achieve our grid modernization programs, which is driving customer reliability. And we are having constructive results on rate cases in Illinois and in Maryland. It is clear that Exelon and other competitive generators are not fairly compensated for their reliable generation. We have been active in the PJM stakeholder processes since the auction results of last May to improve the rules. We continue to be a leading voice against subsidized generation and have had some successes. We will continue the advocacy process going forward.

Looking forward, we see some challenges, but we also do see some light at the end. Continued pressure from subsidies and lower commodity prices are present, but the recent weather events have resulted in price volatility that we haven't seen in a long time. This should result in supplier-side risk premium adjustments, which will assist in the market recovery, and given this and other fundamental shifts we remain positive.

Today, we are providing guidance range of $2.25 to $2.55 a share for the adjusted period earnings for 2014. And now I will turn it over to Jack to provide more details.

Thank you, Chris. And good morning, everyone. I'm on slide 2. I will first discuss the fourth quarter of 2013 financial results, and then turn to 2014 earnings guidance, cash outlook, and other insights on 2014, including our gross margin update. We achieved operating earnings of $0.50 for the quarter and $2.50 per share for the year, in line with the midpoint of our guidance expectations of $2.40 to $2.60.

Turning to slide 3 and the quarter results for the utilities. 2013 was a banner year for our three utilities. Our utility customers are realizing the operating and cost benefits of the merger. Each -- BGE, ComEd, and PECO -- had its best operating year ever, tangible proof of the value of scale, and the ability to leverage experience across utility best practices and resources. Operating performance in each utility improved over 2012 in all key metrics, including safety, reliability, customer service, and customer satisfaction. For all three, reliability, customer satisfaction, and outage frequency, are in the top quartile of similar utilities in the United States. We continue to make capital investments to make our system even stronger and more reliable.

For the fourth quarter, ComEd delivered earnings of $0.13 per share and full-year earnings of $0.49 per share, at the top of our guidance range. Fourth-quarter earnings decreased $0.06 per share compared to the same period in 2012, related to the impacts of the October 12th distribution rate order, partially offset by favorable weather, volumes and customer mix.

PECO delivered earnings of $0.12 per share for the quarter and $0.46 per share for the year, exceeding our guidance range. Fourth-quarter earnings increased $0.02 per share over the same period last year. This is largely related to decreased storm costs and favorable weather. BGE's earnings were $0.06 per share for the fourth quarter and $0.23 per share for the full year, in the middle of our guidance range. Fourth-quarter earnings increased by $0.04 per share from the same quarter in 2012. Higher electric and gas distribution rates and lower storm costs drove the higher earnings.

In December, both ComEd and BGE received constructive results in their rate cases. The Illinois Commerce Commission approved an increase of $341 million for ComEd's delivery service revenue, nearly 95% of the original request -- a testament to the success of the formula rate mechanism. And the Maryland Public Service Commission approved an increase of $34 million for electric-base rates and $12 million for gas-base rates. The 2014 outlook for load growth remains modest. We expect less than 1% load growth at both PECO and BGE, and load growth to be flat to negative at ComEd.

At each utility, load growth is influenced by ongoing energy efficiency programs. PECO's modest growth of 0.3% reflects growth in manufacturing employment in the region. Strong growth in the residential sector is driving BGE's 0.6% expected load growth in 2014. There's more detail on load for the utilities that can be found on page 27 of the Appendix.

Turning to ExGen's results on slide 4, ExGen delivered earnings of $0.21 per share in the fourth quarter and $1.40 per share for the full year. For the quarter, ExGen's earnings decreased by $0.12 per share compared to the same quarter in 2012. The majority of the decrease was driven by lower realized energy prices across all regions. This was offset in part by higher capacity prices and lower O&M expense.

Looking ahead to 2014 on slide 5, we expect adjusted operating earnings in the $2.25 per share to $2.55 per share range, and $0.60 per share to $0.70 per share range for the first quarter. Lower total gross margin of ExGen, driven by lower energy prices, is the main driver of the year-over-year decrease. This is partially offset by higher returns at ComEd, driven by higher allowed ROE and the recovery of capital investments in the formula rate, as well as higher revenue at BGE. In addition, higher O&M costs, driven by inflation and the anticipation of average storm costs, offset in part by merger-related synergies and lower pension costs, contributed to the year-over-year earnings differences. More detail on the individual operating company drivers can be found in the Appendix.

Slide 6 provides our projected sources and uses of cash for 2014 compared to 2013 actuals. Cash from operations is expected to be $6.1 billion, which is an increase from 2013 of $75 million, due in part to higher distribution rates at ComEd, and favorable income taxes and other settlements, offset by lower gross margin at Exelon Generation. 2014 CapEx plans are largely consistent with our estimates provided at EEI.

I will discuss our O&M outlook on the next slide, but will first touch upon our financing plans for 2014. We are projecting $1.2 billion of long-term debt issuances by ComEd and PECO, with the proceeds to be used for refinancings and incremental capital investment at ComEd. In early January, we completed more than half of our 2014 financing plan for the $650 million ComEd first mortgage bond issuance. The transaction consisted of $300 million of five-year bonds with a coupon of 2.15%, and $350 million of 30-year bonds with a coupon of 4.7%. The proceeds served to retire $617 million of debt maturities in addition to general corporate purposes.

In addition to the maturity at ComEd, we had $525 million in maturities at ExGen, which retired with cash on-hand, improving our credit metrics as a nonregulated business. As we mentioned on the third-quarter call, we think we have an opportunity to redeploy capital for growth opportunities through project financing of certain assets in our existing portfolio. To that end, I am pleased to announce the closing of a $300 million L plus 425 term loan of ExGen Renewables 1.

ExGen Renewables 1 is the indirect holding company of Continental Wind, a $667 megawatt wind portfolio of 13 projects located in six states we financed in September of last year. This transaction had an order book that was well oversubscribed, consisting of high quality investors, resulting in us bringing in pricing by 25 to 50 basis points from our initial guidance. We think this serves as evidence that we have a strong portfolio of assets that can generate additional proceeds to deploy for the right growth opportunities.

Slide 7 shows our 2014 O&M forecast and our 2013 actual O&M. We project O&M for 2014 to be $6.575 billion, an increase of $100 million over last year. The O&M CAGR for the entire Company from 2014 to 2016 is a negative 0.6%, with ExGen O&M remaining roughly flat during that time period. This year-over-year variance is mostly driven by inflation and the anticipation of average storm costs at the utilities, offset by merger synergies, and favorable pension and OPEB costs. We expect to hit our run rate merger synergies target of $550 million in 2014.

On slide 8, as we told you at EEI, we are investing $15 billion in our three utilities over the planning period, resulting in consolidated rate-paced growth of between 5% and 7%. We are targeting a minimum 10% ROE at each utility by 2017. Our utilities provide stable earnings growth for the Company, and could fully fund the dividend in 2016. We expect consolidated utility earnings will grow 6% annually from 2013 to 2016. Slide 8 shows our projected utility earnings range from $1.10 to $1.40 in 2014, from $1.25 to $1.55 in 2016.

Slide 9 provides our fourth-quarter gross margin update. As a reminder, we have changed the format of our disclosures to include cost of sales in gross margin, as opposed to O&M and depreciation and amortization. We disclosed the implications of the format change in an 8-K in December, and have included that disclosure in the Appendix of this presentation. During the fourth quarter, 2014 power prices slightly increased in PJM East in the Midwest while decreasing in 2015 and 2016 across most regions. In 2014, total gross margin decreased by $50 million from our last disclosure. As you know, we are highly hedged in 2014, and this rounded variance is due to a few minor adjustments during finalization of our 2014 to 2018 long-range plan. As a result of the pricing decrease, total gross margin is down $100 million in both 2015 and 2016, since the third-quarter call.

In January, we experienced severe winter weather in our load-serving regions, as well as significant power and gas price volatility. Our balance generation to load strategy, as well as our geographic and commodity diversity, served us well in this challenging environment. On the generation front, our oil peaking fleet and other dispatchable generation allowed us to manage the higher loads due to the cold weather. However, we did experience some issues similar to other operators, including an outage at Calvert Cliffs, that will have an offsetting impact on the portfolio management results. We will provide more details about the financial impacts during our first-quarter earnings call.

Yesterday, ISO New England announced the preliminary results of their forward capacity auction for the planning year of 2017 and 2018. The clearing prices are $15 per kilowatt month in NEMA, and $7.025 per kilowatt month in the rest of the pool. These results are pending FERC approval. The clearing prices reflect the tightening supply and demand balance in New England after the announcements to retire baseload generation. Our New England capacity position, 2100 megawatts in NEMA, and 735 megawatts in the rest of the pool, will benefit from these higher year-over-year prices.

As you'll see in the Appendix, our forecasted generation has decreased by roughly 50% in New England. Exelon worked with the supplier to restructure certain terms of the fuel supply contracts, resulting in a more flexible and reliable supply contract. Despite the fact that our forecasted generation is lower, the changes to the fuel supply contract result in favorable gross margin variances in the portfolio that are included in the open gross margin forecast.

On slide 10, we believe that PJM prices will improve due to coal plant retirements and increased costs for some generators to comply with impending environmental regulations. Our current forecast has approximately 52 gigawatts of coal retiring in the Eastern interconnect through 2016, which includes approximately 24 gigawatts in the PJM footprint. While near-term, forward power markets have shown some improvement in recent weeks, we still see forward heat rates trading lower than our fundamentals would suggest, given the natural gas prices, expected retirements, a change in the PJM supply stack, and load assumptions.

Our hedging strategy continues to reflect this view. Our overall hedge percentage has increased due to two factors -- the restructuring of the New England fuel supply contract and shifting to a larger heat rate strategy in PJM. As of year-end 2013, we were 2% to 3% behind ratable in PJM, relying on an even larger amount of cross commodity hedges to capture our view that heat rates will expand.

At year-end, natural gas sales represent 12% to 15% of our hedges in 2015 and 2016. The changing fundamental drivers of the gas and power markets have already led to a significant amount of volatility so far in 2014 spot prices. The forward markets have modestly responded. We will continue to evaluate the amount of upside we see in the market, based on our fundamental views, and carry positions that will allow us to benefit as much as possible from the realization of these views, while meeting the other goals of our hedging policy.

On slide 11, ExGen has shown strong financial metrics in cash flows to maintain its investment-grade rating, and pursue opportunistic growth investments as they arise. For 2013, ExGen had an FFO to debt ratio of more than 37%, and we expect this ratio to improve in 2014 to approximately 40%. ExGen's investment-grade credit rating and robust balance sheet allows us to pursue growth projects.

As we showed you at EEI, we have declining base CapEx at ExGen from 2013 to 2016. Our priority is the safety and reliability of these plants, and these cost reductions will not compromise our ability to achieve those priorities. Our base CapEx in prior years was higher to prepare for license extensions and mitigate asset management issues. We were also able to implement cost management programs, including reverse engineering, which contributed to the reductions. These CapEx reductions helped to mitigate the reduction in revenue net fuel.

Pension improvements are also contributing to our strong financial strength when looking at cash relative to earnings. The rising interest rate environment results in lower pension costs and contributions. For 2015, we are forecasting a $100 million decline in pension contributions versus expense. Further, ExGen has a favorable cash tax position. We have substantial near-term cash tax favorability compared to book taxes, due to bonus depreciation, use of NOLs, and other tax credits. Our longer-term tax position has increased tax capacity for growth opportunities in renewable generation.

All of these factors contribute to our financial flexibility and robust cash metrics, including EBITDA minus base CapEx of $1.5 billion to $1.8 billion, and free cash flow of $1.25 billion in 2014. We have the financial strength not only to see us through this period of low commodity prices but also to grow. Our healthy balance sheet, sustainable dividend, and our discipline, constitute a solid platform for sustained growth.

As a reminder, the Appendix includes several schedules that will help you in your modeling efforts. Now I will turn the call back to Chris for his concluding remarks before we open the call for question-and-answer.

Thanks, Jack. We continue to act aggressively on things we can control, and really work on things that we can influence. We believe in the power market recovery, as we have repetitively said, and we are managing our portfolio accordingly to maximize its profitability. Our investments in the utilities is a very high priority. The stable earnings and the cash flow provided will support a sustainable dividend going forward. We continue to focus on cost-cutting and driving the merger synergies, as we have discussed.

We talked about asset rationalization in the past. And despite our best-ever year in generation, some of our nuclear units are unprofitable at this point in the current environment, due to the low prices and the bad energy policy that we're living with. Assessing the market, operations, and commercial policy solutions is the focus right now. A better tax policy and energy policy would be the clear answer, but if we do not see a path to sustainable profits, we will be obligated to shut units down to avoid the long-term losses. And that decision path or process should bring us to some conclusion by year-end.

Our balance sheet strength enables us to invest in diversification. We will continue to add assets to the portfolio that are earnings and free cash flow-accretive. We will mitigate the market effects by pursuing aggressive cost cuts, asset rationalization, and deploying capital to drive growth.

With that, we will open it up for questions.

(Operator Instructions) Dan Eggers, Credit Suisse.

I was wondering maybe if Ken or somebody could just give some thoughts or some color on what's going on in the forward curves right now? And obviously, we've seen a lot of movement in the 2014 curve, but 2015 and 2016 has been pretty benign so far. Is there a liquidity issue out there? Is it fundamental issue? And when do you guys expect that to start to move?

Let us have Joe Nigro address that.

Hey, Dan. Good morning. I think there's a couple issues that we are dealing with. First, it's the end of the year. The WestHub power, if we use that as the first proxy, is up across the board. And really, that's being driven by the change in gas basis that we've seen in the mid-Atlantic. And we really haven't seen any heat rate expansion. We have price appreciation, if you look at the balance of 2014, and then 2015 and beyond, across the board at the WestHub on the back of the gas basis change.

The bigger issue is really in NI-Hub, because the gas basis really hasn't moved. If you look at 2015 through 2018 since the end of the year, we really haven't seen a change in gas basis, nor have we seen much of a change in the Henry Hub NIMEX price for natural gas. We have seen the calendar 2015 price at NI-Hub go up slightly, about $0.50 or so, I think it was as of last night, on an ATC basis, but we're actually down from 2016 to 2018. And I think your question about liquidity is spot-on.

There's absolutely no natural buyers on the forward curve in NI-Hub. And then on top of that, there is very little speculation being done in NI-Hub from a trading perspective. So when you marry those two things together, you just don't see it. And the last thing I would add is, if you remember, as we walked into the year, we saw the calendar 2014 ATC prices rise when the heat rates expand slightly. And I think it was the back of some retailers and others coming to market and cover, but we haven't seen any change on the backend. And I wouldn't expect to see that until we see liquidity improve.

And Dan, I would just add, given the January cold weather issues and severe price volatility, we've actually seen liquidity really back off just in recent weeks. So, the NI-Hub liquidity is probably about as bad as we've ever seen it. And really, even in 2015, -- there's almost no activity at this point.

And can I ask, kind of on that point we've seen multiple retailers drop out of the business in January already. What kind of landscape are you guys seen today as far as competitors and maybe more departures in the business, I guess, A? And then, B, are you having more conversations with customers looking to maybe reconfigure how their buying power to get into more firm contracts and things like that?

There's a couple of data points to that. The first is there were a couple of wholesale POLR procurements done in January. And I would tell you versus what we have seen in the previous year, you saw some increased risk premiums and in some cases higher margins. I think that's the first data point. The BGS auction will take place next week, the fixed price portion next week, and I think we will get another insight as to how people are thinking about it.

From a retail perspective, it's really too early to tell. But I think you are right on that we have seen a number of folks announce either getting out of the business or they're going to scale down their business. We have seen small defaults, which aren't unexpected in this kind of environment. I would fully expect that folks are going to take a pause here to reassess the risk/reward of selling these load-following products. And when you think about the impending retirements that we've been talking about, if you use PJM as a proxy with some of the changes coming in as it relates to like demand response bidding, and just the gas basis issues we've seen this winter, pretty much all over the Eastern interconnect, I think it's safe to say that we are going to expect people here to reassess what they think the value of a load-following contract is. And we would expect to see the volatility in our margins increase through time, both retail and wholesale load-following contracts.

And Dan, I would just reiterate what Jack said. Our matched load to gen strategy really has played out well here in January. While others are concerned about uncontrolled costs to serve load, with our robust asset base, our portfolio management capability on the wholesale side has allowed us to take those issues off the table, and let our retail team focused on what the customers need, whether they are concerned about prices, if they are indexed or exposed at all, and how we can help them get through this. I think that's our advantage in our mass gen-to-load strategy, and I think it puts us well ahead of a lot of our competitors.

So can I just take that to mean in the first quarter, that even with this volatility in January and into February on retail, the generation has offset that? So there has been kind of a net neutral so it hasn't hurt or helped appreciably?

It's early to talk, but we are right on plan. We don't have any concerns about this weather and the volatility that has been in the market.

Excellent. Thank you, guys.

Steven Fleishman, Wolfe Research.

A couple questions -- first, and I'm not sure you can answer this, but on the nuclear plants that are losing money in this environment, is there a way to give us a sense of how much lost earnings there is, let's say, in 2014 from plants that are not economic right now?

Yes. We are not putting that out yet. When we know it -- if we have to make a decision at the end, we will tell you the upside. But we don't have that number to publish yet.

Okay. And then you mentioned -- I guess you didn't mention this in your remarks, but on the bottom of slide 12, you talk about that you believe you are going to have positive earnings CAGR off of this 2014 guidance over the long-term. Should we assume that assumes your kind of $2 to $4 power price recovery thought? Or is that something where, even without all of that, given potential savings on new shutdowns and other things you're doing, that that might be possible even without that?

Let me ask Jack to go through the logic there.

Steve, so it incorporates a number of things. It incorporates our fundamental views both around power prices as well as capacity. And that provides -- that would provide an important part of that positive earnings growth offsetting the declines that the forwards would suggest in the business. We also have a continued focus on costs that we are pursuing and building on top of the $550 million of savings from the merger. And we expect that to also be additive. And then we have factored in the available capital on balance sheet space that we have, and the opportunity to use that for further investment in organic growth or potential acquisitions or other means of growing our EPS base.

Okay. Great. Thank you very much.

Jonathan Arnold, Deutsche Bank.

One sort of strategic question -- this might be for Jack. But Jack, if volatility and the recent volatility we have seen is kind of what's going to ultimately inform the forwards, why not use some of that financial flexibility to be substantially less hedged?

Let's have Joe Nigro talk about that.

At this point in the cycle, if we talked about 2015 and 2016, which are really the two primary forward years that we are hedging, we've never had a larger open power position at this point in the forward hedging cycle. So we talked a lot, and Jack's script mentioned some of the things that we did in the fourth quarter, in terms of selling gas and rotating out of a very long position. As we -- and we took advantage of the price rise we saw in natural gas from about mid-October through the end of the year. In early January, the gas market actually came off some, and we took the opportunity to buy back a lot of those hedges that we had put on. So we are still carrying a very long open power position.

The second thing I would add to that is, there has been some movement in prices when we talk about West Hub and NI-Hub in 2015, in certain seasons like summer and winter. And we compare that to where we think ultimately they should settle, given the fuel price environment we are in. And there may be an opportunity to rotate the positions and make power sales where we think it's appropriate on a seasonal basis. But sitting here today, we have never had a larger open power position at this point in the forward commodity cycle.

Okay. And I just wondered -- you mentioned this restructuring of the gas, or I guess it's gas, the fuel supply on New England, which -- but if you are going to generate a lot less, presumably that was a low-price contract that's going to not be a low price any more. So, I'm curious -- is there a gain associated with that? And when -- did it show up in 2013? Is it something that will be in 2014? Or am I not thinking about that right?

No. It's -- as we look at this, the way it's flowing through our financial figures, you see it in the hedge disclosure. We restructured a long-dated fuel supply contract that was a positive margin overall. You're right -- we had a substantial decrease in the output of our generation up in New England that you see in the disclosure, to the tune of about 50%. The way the mechanics work in the disclosure is such that we reduced our power new business to go, and we added the value of that contract that we monetized into our estimated open gross margin. So the net change to the bottom line is zero, but it's just more locked-in cash flow.

So, Jonathan, a big driver of this is around making sure we have fuel reliability and flexibility, and can run the plants when they're most needed on the system. That was a huge driver in doing that.

So was there a financial impact from the restructuring?

The financial impact, as you see, if you look at our hedge disclosures quarter-over-quarter -- for example, in 2014, you'll see -- you'll notice we reduced our power new business to go by $150 million. We reduced it by $100 million in 2015. A portion -- a good portion of that is the benefit of this contract and the locked-in cash flows. So we reduced the power new business to go, and we've grossed up the open gross margin for that value.

Okay. Sorry to kind of keep on this, but does that mean there's not a sort of upfront gain associated with it?

Well, what they're trying to tell you -- it's built into the numbers you're looking at. There was an optimization that needed to be done for reliability on the system that drove the contract restructuring. We were compensated for that and it's in the numbers. And it is positive, but it's in the numbers you're seeing.

Okay. Can you quantify it?

No. There's terms under the deal -- no.

Okay. And then just finally, Chris, on your last comment around assets and everything, at EEI, you were -- you talked a little about PPAs. And then there was a sort of potential path to addressing economic situation of some of the nukes. And then there was a story about something being negotiated in Illinois around Quad Cities. Can you comment at all about that?

Yes. Somebody ran with the story that was not true. We are not negotiating with the State of Illinois on PPAs. What my statement was at EEI, and it's still a path forward, we would like to get longer-term contracts on especially the MISO asset. It is not being compensated for the reliability. And we have origination folks out working on that, but it's not with a state entity; it's through multiple paths to other parties that are securing long-term needs. We will continue to work on that. As you know, there's not many of those deals out there. But MISO would be our target to try to find those opportunities.

Okay. Thank you very much, guys.

Hugh Wynne, Sanford Bernstein.

Chris, you'd talked a couple times about your efforts to achieve changes in energy policy that might benefit the Company. And I was wondering if you could expand on that a little bit, in particular, what you are hoping to see done on renewables and on CO2 regulation? And perhaps what you think may play out on those two fronts?

Sure. Our biggest push right now is, at the federal and the state level, is to stop subsidizing generation. That's renewables and other sources of generation. It skews the market; it doesn't give any of us the right signal. Should we be investing? Should we be shutting down? And we think that good policy for the competitive market is let the assets compete. So, we have done a lot of work the last couple of years trying to tell that story. And we hope that it's continuing or will start to resonate with more stakeholders as we go forward.

The other thing that we are continuing to push on and explore -- we do not get compensated, as others, for reliable baseload generation. When we load a core in a nuclear reactor, we can run for up to two years with very reliable generation. We are not depending on the wind, the sun or the flow of any fuel through a pipe. It's there. So we think the capacity markets, if not the energy markets, should reflect the reliability and the dependability of those. And Joe Dominguez and our regulatory folks continue to work in market space to try to find opportunities to improve the rules around that. And we will continue to push it.

As far as greenhouse gases, we are not advocating for a carbon bill. We spent a lot of time working on that in the past. And Washington, I don't think, is the place to try to resolve that issue right now. We continue to watch what the EPA is doing and what they have under their jurisdiction right now, as it's been pointed out to regulate going forward. We'll monitor that. We'll inform how we make our investments around that, or how we would make our disclosures around that. But we are not in the advocacy spot right now in that area.

Okay, understood. Could you maybe just elaborate a little bit on what type of compensation you think would be appropriate for the reliable baseload, as opposed to what you are receiving already in capacity markets?

Yes. I will let Joe Dominguez touch on that.

Sure. So when we are talking about reliability, it's often described as fuel diversity or not allowing the RTO's to get too long gas because of these volatility risks. The way I think that is being translated in stakeholder space is, you increase the requirements for firm fuel. And so, obviously, a nuclear unit has firm fuel. We load up 18 months of fuel in the core. And the thought is that, especially coming out of these winter events, the gas units will be required to have something that looks like firm fuel.

And that may involve firm transport requirements; it may ultimately involve a winter peaking season, where there's an examination of whether sufficient gas can be provided to cover all the megawatts that are bid in the auction. But those are the discussions that are occurring. We think that will put upward pressure in the capacity market, and allow nuclear units to benefit from the firm fuel they have and the reliability they provide in the system.

Great. So you are basically hoping that the requirement for firm fuel supply and transmission on the gas plants will drive capacity prices higher and you will benefit accordingly? Is that fair?

Yes, but I don't want to be limited to that. I think what we need to figure out for the abilities on the system is whether the gas units can perform fully during peak season. And now we are going to see a peak in the winter, and that's really what comes out of this. And I think the ISOs are going to examine a number of tasks. Requiring firm transport is one of them, but the other way to do it is to just whittle down the number of megawatts that are participating in the capacity auction. Either way, we will see some uplift in the current capacity market as a result of those efforts.

Got it. Okay, thank you very much.

Sure.

Michael Weinstein, UBS.

On that same topic, could you talk about the PJM parameters that were released? And what do you think about capacity imports into PJM and how that might be changing?

Joe --?

Well, I think the most significant on a ruling was limiting the sub-annual DR. And so we see the effect of that already. That was approved by FERC. FERC has not approved PJM's request on the import limits as yet. As you know, they issued a deficiency letter. Our review of the deficiency letter suggests that they could answer the questions relatively quickly, refile, and be in time for a decision by FERC in advance of the auction.

In terms of the planning parameters, I think they would modestly reduce the number of imports, the number of megawatts of imported generation in this next capacity auction. That's my read, based on what I've seen so far.

Modest reduction. A couple of technical questions -- concerning the interest on -- in ExGen, it just looks like, in the guidance, it went down to $325 million. And the run rate on the fourth quarter would seem to imply about $400 million. And net-debt, it looks like it actually increased. So I'm just wondering what's the cause of the decline in interest going forward?

Michael, I think we can -- I would say, broadly, that it's related to lower balance. And we have been refinancing at lower levels. But why don't we take the more specific modeling questions off-line?

No problem. And one last question is -- have you baked into guidance any of the uplift from January, like, any of the risk, increased risk premiums or anything like that, that might have happened or might be occurring, in your 2014 guidance?

No, we haven't. Whether you talk about it from a retail margin perspective or performance in January, none of that has been baked in.

We do think it should be and eventually will be. As we looked at these auctions or the muni aggregation process, we never could understand the numbers in some of the suppliers that were able to make. And so we didn't win a lot of those. We've pushed -- as we looked at our own models, the place that jumped out was the volume variability, the VLR that can be directly seen in a weather event like that. So we have previously priced that into our offerings that would -- that and portfolio management would protect us from events like we just went through. So that's why we're saying right now we're on plan.

Okay. Thank you very much.

Ali Agha, SunTrust.

Chris, as you are thinking through your strategic plan for 2014 and perhaps beyond that, but looking through this calendar year, where does the prospect for regulated utility M&A fit into your planning right now, if at all? What kind of priority would you give that to build up your regulated base?

So right now, we are not in a position where we would want to trade our equity for anything other than something that was a relative value deal. So if you look at -- we believe we are undervalued at this point and there is a market upside. Between the market upside and the current valuations we're being given, we think there's upside to that. So, we withhold the use of our equity only to something that would be a relative value deal that we could see the upside accretion in earnings and profitability.

Other things that would be looked at would just be balance sheet-type growth activities, as Jack has pointed out previously. So, off the balance sheet, we are willing to engage in anything that we can see on the near-term as a positive accretion in earnings, but not create a dilution of equity -- on the equity utilization, just because we think most are trading at a premium.

Okay, got it. Also to clarify, you pointed out earlier, also in slide 12, when you look at your planning period and think about ultimately ending up with a positive CAGR in earnings, are we looking at 2013 through 2018? Or through 2016? What's the planning period? Can you just define that?

2014 through 2018.

2014 through 2018? Got it. Thank you.

Jon Cohen, ISI Group.

Just a question on -- when you say you have balance sheet capacity, is that also looking out long-term through 2018? Or is that more over the next few years?

That's looking out throughout 2018. Clearly, we have more balance sheet capacity in the front years based on where the power curve is currently trending. To the extent that our fundamental view comes to fruition, then clearly, we will have a similar level of FFO relative to debt. And that would create incremental capacity. But consistent with prior comments, we think we have between $1 billion and $2 billion of balance sheet capacity to invest in growth.

Okay. And if your fundamental view on the power markets does not come to fruition, does that (multiple speakers) kind of eat away at that $1 billion to $2 billion?

(multiple speakers) That's how we arrive at the $1 billion to $2 billion; to the extent that our fundamental view comes to fruition, then it's meaningfully higher.

Okay, great. And then just one other question on the planning parameters. I noticed that PJM broke out ComEd and BGE as separate LDAs, even though it looks like there's plenty of import capacity. Can you just talk about what their thinking was around that? And does that help you at all?

Joe Dominguez will answer that.

Sure. PJM has a right under the tariff to separately model the zones when there are concerns that the megawatts of supply needed within the zone won't receive adequate compensation through the RTO pricing into the reliability criteria. As you indicated, the comment zone transmission, the CETO/CTEL ratio looks like it's pretty robust. BGE is a little bit tighter.

But I think what this ultimately tells us is that, as we get into the auction period, bidding practice within those zones is going to be very critical. And what the cost of supply within the zones is, is going to be very critical. PJM, we think wisely, has taken steps to protect the reliability in those zones by separately modeling the LDAs.

Okay. And can you just clear up one thing? As a nuclear generator, what is your flexibility for bidding in avoided cost? I mean, it looks like they don't specify an avoided cost rate for nuclear; it's mostly for coal and other fossil units. Can you bid something other than just being a price taker?

The answer is yes, you can. There aren't the bulk rates, which is what you are pointing out. But there's nothing that prohibits a nuclear unit from bidding in ACR.

Okay, great. Thanks a lot.

Paul Fremont, Jefferies.

It looks like for the year 2014, the effective tax rate came in at 33.8%, which is well below your guidance of 37.4%. I guess my question is, what caused the tax rate to be significantly better? And also, I don't see sort of a consolidated effective tax rate that you are assuming for 2014, in your guidance.

We'll have our Tax VP address that -- Tom Terry.

The guidance you have been given is just a core effective tax rate. The effective tax rate in the financials, and what you will actually see realized, reflects the utilization of renewables credits, to drive that down substantially below what you would get just as an ongoing core tax rate.

So what is the consolidated tax guidance for 2014?

Do we give that guidance?

No. We don't provide that, Paul.

Oh, okay. And then can you -- is it, again, the renewable credits that's getting you to the much lower effective tax rate this year versus what you were originally guiding to?

Yes. Paul, you're seeing the continued buildout of AVSR; you're seeing a buildout of wind-generating assets through our renewables business. You should expect us to be a regular beneficiary of tax credits and lowering our overall tax liability on a cash basis, as well as that.

Even though you can't give sort of a consolidated effective tax rate, directionally, should we assume something similar to 2013 and 2014?

Let us step back and look at how we want to discuss that. We've got more renewables coming on. We've got a pipeline. It hasn't been something that we have talked about in the past. And I hate to do it on the fly right now, so let us regroup and we'll put something out or we'll address it on the next call.

Okay. And then just real quick, on the -- on your discussion of the supply disruptions and what you're going to talk about in the first quarter of 2014, will that discussion essentially only impact your 2014 number? Or could it also have an effect on sort of future periods that you include in your disclosures?

So, our disclosures are based off of the forward strip. Where we see the market on our short-term view doesn't come into our disclosures.

Joe, do you want to --

And, Paul, a couple of things. One thing is there's -- none of our January activity is in this disclosure we gave today. As you know, and you see in the disclosure, we have new business targets to go both on the power side and the non-power side. So any value created, whether it's in January or the balance of the first quarter, or changes we see in value for the balance of the year, would go towards meeting the business targets for the year.

In addition, I think the question you are raising is, what is the value on the forward curve of some of the activity and disruptions we've seen in January? As we've talked about, it's been much more significant in the front-end of the curve and very muted on the back-end of the curve. And we haven't seen anything in the two weeks since that's happened that led us to believe that retail is changing appreciably yet.

But I do think as we get to the end of the first quarter, we will have better insight as to what the impact is on the forward curve as we move through time, and what it means. But as of right now, our plan includes retail margins that we previously talked about, when you think about like C&I power, that don't get back to the middle of that $2 to $4 range. If we see that expand, we would take that into account and recognize it, to see how it helps meet our new business targets or possibly expand them.

Okay. And last question for me. We've seen announcements of new gas plant construction in PJM. Do you expect this to be limited to sort of a Pennsylvania Marcellus region? Or do you expect to see more activity in other parts of PJM?

Well, I think that there's a -- I think the general consensus is that you are going to see it more in the mid-Atlantic region. Prior to January 1, as you know, we saw substantial degradation in gas basis as it related to the mid-Atlantic and the Marcellus area. It's not unreasonable to think you could see this in Ohio as well, as the Utica Shale starts to build out as quickly as people expect.

I do think, though, since we've seen an uptick in the gas basis since the first of the year, we have to take a step back and pause, and reassess what the economic side of -- on these plants are, because there is going to be some very seasonal differences when you look at the curve being up. If you use M3 basis as a proxy, $0.30 to $0.35 on an annualized basis, there's a big winter component to that; whereas the summer and the shoulder months are still weak. But, in general, I think you would see it in that Marcellus and Utica region.

Thank you very much.

We have time for one last question.

And your final question comes from the line of Michael Lapides with Goldman Sachs.

Hey, guys, I'm going to make it easy on you -- asked and answered. I'll follow-up after the call.

Thanks.

So that ends our Q&A session. Thank you very much.

Thanks. Thank you.

This concludes today's conference call. You may now disconnect.