艾索倫電力 (EXC) 2013 Q1 法說會逐字稿

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

Mr. Ganti, you may begin your conference.

Thank you, Bridget, and good morning, everyone. Welcome to Exelon's first-quarter 2013 earnings conference call. Thank you for joining us today.

We issued our earnings release this morning. If you haven't received it, the release is available on Exelon's website.

The earnings release and other matters we will discuss in today's call contain forward-looking statements and estimates that are subject to various risks and uncertainties as well as adjusted non-GAAP operating earnings. Please refer to the 8-K and other filings for a discussion of factors that may cause results to differ from management's projections, forecasts and expectations and for a reconciliation of operating to GAAP earnings.

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 executive management team who will be available to answer your questions. We have currently scheduled 60 minutes for this call.

I will now turn the call over to Chris Crane, Exelon's CEO.

Thanks, Ravi, and good morning to everybody and thank you for joining us. We had a very successful first quarter. We delivered on our financial expectations while having a great quarter from an operational perspective.

We had to make a hard decision, a critical choice to resize our dividend within the quarter. I think we struck the right balance between a strong balance sheet and returning value to the shareholder. It was the right decision to pursue our goal of long-term value return and since January, the stock performance is indicative of the removal of the dividend uncertainty overhang, the beginning of the market recovery and in general, a bullish view on natural gas.

From a financial perspective the first-quarter operating earnings as announced this morning were $0.70 per share. It is the top of our guidance range that we had previously given of $0.60 to $0.70 per share. Jack is going to provide more detail in his comments on the drivers around that.

Our second-quarter guidance that we are providing is a range of $0.50 to $0.60 per share for operating earnings which allows us to reaffirm our year guidance of $2.35 to $2.65 per share.

Operations remained strong while the full-year gross margin expectations at Constellation is marginally lower. As you will see in the hedge disclosure, it is in line with our expectations and Jack and Ken will provide more color during the call on the aspects of that. At present we see no reason to depart from our full-year range.

Focusing on an operational update the fleet operated at an excellent level in the quarter. The nuclear fleet capacity factor was 96.4% compared with 93.6% for the same quarter last year. Nuclear set a first quarter fleet record for generation at ownership beating our 2007 by some 575 gigawatt hours. That is the fourth best quarter in the history of Exelon from a capacity factor standpoint.

Our fossil and renewable fleet had a strong quarter as well with the fossil availability at 98.4% and solar and wind energy capture rate at 94.9%.

BGE throughout the quarter had a very constructive rate case and Jack is going to provide some more details on that.

Switching to, Illinois Senate Bill 9, we hope will be enacted this year. We are on a good path there. It was passed with a veto-proof majority in the Senate and the House. We are waiting on the Governor to act. Once enacted on, we can start executing our plan of grid modernization including the installation of the smart meters and improving the reliability of the infrastructure.

Focusing on a market update, the power prices have improved since the beginning of the year as we have all seen. We continue to monitor the markets closely to inform our hedging strategy. We do believe as we previously said there is more upside remaining in the outer years.

Gas prices have picked up in the near-term while holding a flat trajectory in the out years. However, there is more support for a bullish view towards gas in the forwards.

Fundamentals point to our existing view of the $4 to $6 an MMBTU for natural gas in the '15 to '16 range. We are constantly tailoring the hedge program to these views. Ken will be available to answer more questions in that area on the call.

As we focus our look toward the balance of the year, our highest priority is maintaining our focus on safety, operations and financial discipline. Delivering on the financial results we promised will help us realize the synergy targets for the successful merger. We are on track right now to complete the $550 million run rate on synergies by the end of 2014.

Looking at the growth project update, we continue to make progress on our projects that we previously announced. We successfully installed 69 megawatts of solar as part of our AVSR in the first quarter and expect to build out another 132 megawatts in the balance of the year.

The smart meter installation in two of the three utilities continues. BGE installed 127,000 meters so far and 750,000 are expected by year end.

At PECO, we have installed 158,000 during the first quarter with another 160,000 expected by mid June and the ComEd installation schedule is predicated based off of Senate Bill 9's approval as I previously mentioned. So overall, a very solid quarter continuing to deliver on the promises.

And now I will turn the call over to Jack to provide more details on the financial update.

Thank you, Chris, and good morning everyone. I will now review the first-quarter financial results, our second-quarter guidance range, the updates to our hedge disclosures and discuss our balance sheet and cash flow outlook.

I will start with our financial results on slide four. Operating earnings for the first quarter of this year were $0.70 per share, at the top end of our first-quarter guidance range of $0.60 to $0.70 per share. This compares to earnings of $0.85 per share that we reported during the first quarter of 2012.

The key drivers of the reduction in earnings quarter over quarter were merger related share count differential and lower ExGen gross margin primarily related to a combination of lower realized prices and lower capacity revenues. These impacts were partially offset by favorable weather at the utilities and the addition of a full quarter of earnings from the legacy Constellation businesses.

We delivered earnings at the top end of our first-quarter guidance range through a number of smaller positive variances that include our nuclear fleet achieving a 96.4% capacity factor and favorable interest on tax related items. We also benefited from approximately $0.04 per share of favorable O&M timing variances primarily related to projects and outage timing. We expect this timing benefit to reverse over the remainder of 2013.

Portfolio management results were unfavorable plan for the quarter. Specifically we sold our excess length early in the quarter in advance of an expected decline in prices due to moderate weather. Prices subsequently increased and our generating fleet did not participate in this upward movement.

Our updated edging disclosure reflects this first-quarter weakness. Importantly while a near-term headwind, this shift in pricing is a long term benefit to the behind ratables hedging strategy we pursued for 2014 and beyond.

Starting with second-quarter results, we will be able to update you on year-over-year progress for BGE and ExGen and a more comparable view similar to the slides in the appendix detailing ComEd and PECO's quarter-over-quarter drivers.

As you saw from our earnings release, our GAAP earnings for the first quarter are a loss of $0.01 per share which is $0.71 lower than our non-GAAP results but in line with our expectations. Three main items accounted for this variance.

As you will recall during the first quarter, we disclosed that we will be taking a onetime non-cash charge of approximately $265 million or $0.31 per share in connection with our reevaluation of the like-kind exchange position from our ComEd asset sales in 1999.

The remaining two items are the amortization of commodity contract intangibles related to the merger and changes in the mark to market of our hedges in the first quarter. The mark to market impact of the loss of $0.27 per share is expected given the increase in commodity prices during the first quarter.

For the second quarter, we are providing guidance of $0.50 to $0.60 per share. This compares to our realized earnings of $0.61 per share during the same period last year. The main drivers for this decline are similar to the first quarter explanations with power prices and capacity prices down from 2012 and includes the offset of improved rates at ComEd and BGE.

I want to remind you that in the second quarter of 2012 we recorded a write down of a regulatory asset at ComEd based on the ICC order in May of 2012. This was partially reversed in the fourth quarter of 2012 after the October rehearing.

For the full year 2013, we are reaffirming our guidance range of $2.35 to $2.65 per share.

Now I will provide the gross margin update for Exelon generation. Slide five provides the first-quarter hedge disclosure compared to the data as of December 31, 2012. As you can see forward power prices increased in nearly all regions. In particular, West Hub and NiHub increased by $2 per megawatt hour or more across all of the years. This increase reflects two key factors -- rising natural gas prices and expansion of heat rates in these regions. Importantly we believe that the markets are beginning to reflect some of the $3 to $6 per megawatt hour of fundamental upside that we had discussed previously.

As of the end of the first quarter we believe the upside is closer to $2 to $4 per megawatt hour. We still see a disconnect in forward heat rates compared to what a fundamental forecast would indicate given current natural gas prices, expected retirements and load assumptions.

Importantly, ours is not the only voice highlighting the supply-demand imbalance. We believe we are beginning to see this shared view materialize due to several factors. The spot market saw increased weather-driven volatility during the first quarter and there seems to be a moderately more bullish sentiment across the industry around the natural gas and power markets.

The increase in power prices drove increased open gross margin of approximately $350 million to $450 million per year in all periods. Factoring in the mark to market of existing hedges which decreased as prices moved higher, new hedging activity and changes to our targets, we see a cumulative increase of approximately $350 million across the three years in hedged gross margin.

You will notice that the Power New Business To-Go bucket shows a reduction across the years that reflects the hedging activity that took place during this quarter for 2014 and 2015. In 2013, there is a $50 million reduction in expected portfolio management gross margin contributions for the reasons I discussed on slide four.

Our hedging activity and the products we choose to hedge reflect our belief that prices will move even higher. We are approximately 3% behind ratable in 2014 and approximately 6% behind ratable in 2015. We continue to utilize natural gas sales and options in our hedging strategy to retain upside exposure to higher power prices and expanding heat rates while protecting against downside gas movements.

On slide six, we provide our view of our load expectations for the utilities. Overall we see continued slow growth. In 2013, ComEd expects total load to be similar to 2012 results with only a small decline of 0.1% on a weather normal basis. This is in line with projections of moderate economic growth offset by growing energy efficiency.

PECO expects overall growth of 0.5% which is 1% better than we believed at the time of our year-end call. This reflects economic growth in the region and an overall employment growth outlook.

BGE expects overall declines in load driven primarily by the bankruptcy of one of its largest industrial customers, RG Steel. Excluding this bankruptcy, 2013 load for BGE would have seen growth of 0.4% over 2012 levels driven by customer growth and the economy and offset by conservation programs.

Slide seven provides an update of our cash flow expectations for this year. We still project strong cash from operations of $5.8 billion. This estimate is down slightly about $125 million from our original projections. The primary drivers of the decline include lower net income at Exelon Generation related to the previously mentioned revision to our full-year portfolio management targets and timing of tax cash payments. We anticipate lower capital spend this year in part due to the cancellation of the Dresden and Quad Cities MUR projects.

On March 25, PECO announced that it will be utilizing its excess cash to redeem its preferred stock. The redemption date is today and the total stated value of preferred stock to be redeemed is $87 million.

As discussed previously, we also plan to call the $450 million of Constellation junior subordinated hybrid debt this quarter with a coupon of 8 5/8%. Additionally you can see that we expect to end the year with $1.35 billion of cash across the Company, the majority of which will be held at ExGen. Given the size of that balance, we are reviewing the need to refinance $500 million of debt that is maturing in January of 2014.

These actions are part of our plan to strengthen the balance sheet and maintain strong credit metrics as we mentioned during the year-end earnings conference call.

Most importantly all of our ratings outlooks are now stable. In an effort to clarify some of the metrics the rating agencies watch we have included a slide in the appendix showing the calculation of those metrics.

In closing on slide eight, we look ahead to significant events for the remainder of the year. On May 24, the 2016-2017 RPM auction results will be published. Results will largely depend on how much new generation bids in whether from new construction or through transmission access. We expect a resolution of SB9 in Illinois by the end of the second quarter which if passed, will increase operating revenues approximately $25 million and $65 million in 2013 and 2014, respectively.

Additionally under SB9, we will increase capital expenditures by approximately $35 million and $45 million in 2013 and 2014 respectively. We also recently filed our ComEd rate case which asked for an increase of $311 million. This reflects actual 2012 expenses and investments and forecasted 2013 capital additions to our distribution network.

The new rates are expected to take effect on January 1, 2014 after the ICC's review. This filing does not reflect the SB9 legislation which if it becomes effective would require us to update our filing.

We expect to file our next BGE rate case by the end of the second quarter. We are optimistic that we can build upon the constructive outcome from the last rate case where we received approximately 62% of our request for electric rate increase and 71% of our request for a gas rate increase. As a reminder, the appendix includes several schedules that will aid you in your modeling efforts.

And that concludes my comments. Now I will turn the call back over to Chris before we open the line for Q&A.

Thanks, Jack. In conclusion, I want to reiterate a few things that you have heard us say previously. We will continue down the path that we laid out on our February 7 call which continues on -- with our primary goal remains strengthening the balance sheet, focusing on operations and looking for ways to improve operational efficiencies. We will continue to look for opportunities to grow the Company making opportunistic investments using our balance sheet strength where applicable and ensuring that actions will be accretive to the Company's financial health.

With that, we will open it up to questions.

(Operator Instructions). Greg Gordon, ISI Group.

So good quarter by the way and we are happy to see that pricing is starting to cooperate with your thesis. A few questions on those fronts and on cash flow.

So the powered new business to go versus the mark to market hedges and the open gross margin is it fair to -- I presume you have lowered again your expectations for margins and/or volumes given out in 2013, 2014 and 2015 just given the persistently low level of pricing and low level of volatility as it relates to competitive energy supply?

Let me have Ken address that and we'll circle back if you have a cash flow question.

So, Greg, that is not the case. Actually in 2013 we have reduced our target expectation for Power New Business To-Go essentially because we got defensive on natural gas prices early in the quarter and hedged the portfolio tightly and missed an opportunity to gain some upside from spot prices in the first quarter.

In 2014 and 2015 it is actually a very different story. We have actually achieved new business targets as or better than expected in those years and when we do achieve those targets what we do is we reduce the Power New Business To-Go line and it rolls into the mark to market of hedges. So our hedging position that we have had on that's associated with taking advantage of upside in the power markets is benefiting us in those two years.

A follow-up on free cash?

Yes. So when I look at page 18 where you show the buildup to your consolidated cash flow outlook, there is a lot of what I would call relatively small changes but the two big ones are a $225 million reduction in expected CFO from ExGen but then also a $325 million decline in expected other cash flows. Can you dig a little bit deeper into those two items?

Sure. As we have discussed previously, there are some puts and takes as you point out. So from a cash from operations, roughly $125 million decline relative to the expectations primarily related to ExGen tax timing offset on the CapEx side by the cancellation of Dresden and Quad Cities MUR. The primary driver of the change in cash relative to the beginning of year forecast is the lower financing at ComEd, $175 million and BGE of $[50] million.

I just want to understand why in the course of just the last several months since you just gave us your fiscal year outlook recently there has been such a dramatic change in the expected CFO from ExGen. Is it related to the hedging activity in the quarter, in the first quarter that went against you on gas or is it something else?

No, the breakdown at ExGen is -- of the roughly $250 million total change at ExGen specifically, roughly a third of that is cash tax timing offset by about $150 million of cash related net income.

On the positive, a reduction in CapEx which I described related to the MURs and then an increase in the dividend on the financing line so it is a net to the $250 million.

Okay and then at the bottom, the change in other it was a $400 million help on the year-end call and it is now only $75 million.

It is CP.

Okay, thank you.

Dan Eggers, Credit Suisse.

Ken, just looking at the move up in power prices and the strength, you have said that you guys hedged more aggressively early in the quarter and less later. Is there any relationship between the fact as you guys kind of took some liquidity pressure out of the market by selling, did that had an effect on power prices or did I misunderstand your first comments?

Really when I was referring to hedging and it was associated with our 2013 position so we took a low of 90% hedge position and took it to a high 90% hedge position in 2013 alone. We just felt like we got defensive on natural gas looking into early winter weather and obviously what has happened over the last five years has indicated the risk of natural gas prices falling. It didn't happen so we readjusted our portfolio in 2013.

In 2014 and 2015, our hedging posture has been consistent with what we've talked about for many quarters now. We've held our position of falling behind ratable, as Jack indicated, by about 6% in 2015. We have also held our position of utilizing natural gas and options to keep heat rate upside. That is another probably 8% in that 2015 portfolio. So we are maintaining a substantial upside position in our hedging program for 2015.

To make sure I understand you are 6% behind schedule and then because of the way you are hedging, leaving the upside open, it is more like you are 14% behind ratable, is that the right way to think about that?

Yes, so from a heat rate perspective, we are more like 14% or 15%.

Can you just give a little color on what you guys are seeing in the retail markets as far as the competitiveness of that, is that landscape changing at all with movement in prices? And generally in the past with new energy when prices rose you saw more margin pressure in the business. Is that showing up right now because it didn't look like it showed up in the hedging disclosure you guys gave for non-Power New Business To-Go?

Dan, we have seen the same behavior in the retail market essentially over the past several quarters of margins being on the low end of expected ranges or experienced ranges. What is interesting and maybe a little bit different about the first quarter this year is that customers are actually pausing to decide to recontract and buy power because for the first time in a long time prices have not dropped going through a winter. And I believe a lot of customers were thinking that prices were going to go in a lower direction and it would be a great opportunity for them to lock-in fixed price over the next couple of years. Prices have actually gone up and you see a little bit of pausing from especially commercial industrial contracting perspective. So very challenging and competitive environment remains. We have maintained our expectations in the disclosure for this quarter and we will continue to see how this shakes out.

Okay, great. Thank you.

Jonathan Arnold, Deutsche Bank.

Good morning, guys. Excuse the background noise I'm sorry about that. Staying on hedging, I just want to make sure I understand the terminology correctly. When you say you are 6% behind ratable, does that mean 6 percentage points lower than you would otherwise be or is it a percentage?

It is 6 percentage points lower than we would otherwise be.

Okay, thank you. Is it reasonable to assume you are 3% behind in 2014, 6% behind in 2015 that as you are looking at 2016 which is obviously not on a slide yet, but you would be incrementally behind?

Yes, Jonathan, we will build a similar strategy and similar position in 2016 as we have in 2015. That is where we are.

Thank you.

Hugh Wynne, Sanford Bernstein.

My questions go to the assumptions underlying the expectation of continued $2.00 to $4.00 upside in the round the clock PJM price post-2015.

First on load growth, I wonder if you could tell me what your outlook is? I notice that at ComEd, PECO and BGE you had this large decline in load in 2012 and you are not expecting much of a recovery if any in 2013. What is your forecast for load growth across PJM in 2014, 2015?

It is well under 1% at this point in our model so we are not anticipating anything substantial or helpful on the load growth side when we are talking about our upside in power prices. It really is wholly driven by the retirement of the full asset.

Great. What is your expectation for -- I guess I would call it sort of loss of load to increased renewable generation? To what extent do you think load in PJM will be incrementally supplied by renewable generation and what impact do you think that has on prices?

If I understand your question correctly how much renewable generation do you think -- are you asking that?

Yes.

We obviously have seen the buildout of wind generation at the end of 2012 and with the PTC extension continue to anticipate significant wind development going forward in the next few years. So again, that is another obviously -- another incremental generation add to our models and quite frankly not a conservative assumption -- an incremental additional wind at significant levels and we still see the upside because of overtime.

Okay. Then in final question on this. The steam electric F1 guidelines have been published in their proposed form, have you altered in any way your expectation of plant retirements and what is your expectation currently?

Our expectation of plant retirements is relatively consistent, Hugh. We have a little over 20,000 megawatts of expected retirement in PJM, 47,000 in the entire Eastern interconnect and those assumptions haven't moved very much for us in the past few months.

Great, thank you very much.

Steven Fleishman, Wolfe Research.

Hi, good morning. Just a question on the kind of thought process on growth investments. Could you maybe give a little color of kind of the most likely areas that you would be looking at for growth investments and thoughts on -- let's say you could find a $500 million investment, would you likely need to finance, half debt, half stock at this point or could you finance things with all debt? Or do you really need to keep paying down debt the next couple of years before you could do that? Maybe just a little color on where you are on financing?

So as far as a growth strategy and where we are focusing, we have a significant area within utilities continuing to build out on the grid modernization, the smart meter installation and reinforcing the reliability of the system and we will continue to make those significant investments.

If you go to the other side of the business though we continue to look at mostly contracted type assets at this point and continue on with some wind development and also the development in the solar area, there's about $2 billion to $3 billion of growth in the next five years that is within the plan right now and none of that requires equity issuance. It is within the cash flow on the current balance sheet.

In this forward year, we are not refinancing or we are slowing on a refinancing and we are using cash to cover our capital obligations to strengthen the balance sheet. If something came along that was large enough that we thought was the right strategic fit but more importantly met the right financial hurdles, that evaluation would take into consideration if equity was required to cover the dilutive effect of the equity.

We don't see anything around that right now but that would be the hurdle that would have to be overcome before we would go there.

I think, Chris, that is right. The space on the balance sheet (technical difficulty) after that we would look at a balance sheet neutral (technical difficulty).

So just to clarify on the $2 billion to $3 billion, are those growth investments that are already in the CapEx plan or would that include potentially new things that haven't been identified yet?

There are plugs in that for new things that have not been identified yet.

Okay. Is there a way to get a sense of how much are those versus kind of core -- the spending already in Illinois and things like that?

The $2 billion to $3 billion, Steve, is actually room on the balance sheet for projects that have not been identified that are not included in our long-range plan that would be incremental and they would be in the areas as Chris described.

I think what we can do is follow back up with you and show you what is broken down right now on the regulated side for CapEx. What we know is in the pipeline and on the generation side and then the balance sheet space above that for the plugs that we have for additional growth. We will pull that together.

Okay. Thank you very much.

Julien Dumoulin-Smith, UBS.

First question here and this obviously has two sides to it. As you look at the 2 to 4, how much is attributable to changes in demand response rules -- obviously they can now set prices that seems pretty material?

And then secondly on the other half, how are you thinking about changes in the Edison Mission Compliance in Illinois and the delay from 2015 to 2017 and how does that work into your math both with regards to moving from 3 to 6 and in the remaining 2 to 4 that remains out there if you will?

Julian, focusing on the 2 to 4 question first, we don't have any modeling of increased volatility associated with scarcity pricing concepts or as you said, demand response energy bidding and setting price. This analysis is strictly about the generation stack and coal retirements and that kind of upside is incremental to the 2 to 4 so that is the first question.

The second question was about our assumptions of coal retirement. So we have taken into account the best available knowledge we have in the market about every coal plant. We did not estimate that all the coal plants you are referring to were going to be retired anyway. We have run our models and don't see really any incremental change in our estimate from that information.

And perhaps just a clarifying question there. Clearly Trona as an incremental cost of dispatch is somewhat relevant to this conversation. How much of that element given now that they have a delay for two years had been playing into your 2 to 4 -- or plays into your 2 to 4 today?

Little if none.

Great. Thank you very much for the clarification.

Stephen Byrd, Morgan Stanley.

Just want to follow up. Jack, you had mentioned given the cash position that you had that you continue to assess upcoming debt refinancings and you just sort of thinking through your options. I wonder if you could just talk a little bit more about that as you look at your cash balance over time and you look at the upcoming debt retirements. Just wasn't completely clear as to how to interpret the comment as you think about your options on the upcoming debt that is coming due?

Sure. So, Stephen, you can see that in this year we are using the $450 million to retire the 8 5/8% junior subordinated debt which is obviously a very accretive transaction given the current interest rate environment. We have roughly $615 million coming due at ExGen in 2014 and then $550 million at ExGen and another $800 million at holding company that matures in 2015. And part of the opportunity given the cash balance we have is to look at those maturities and determine whether it is appropriate given the other strategic hauls on the cash that we look at that and balance that against calling those bonds as they mature and not refinancing them.

Clearly if we do that, then we have substantial room in the balance sheet for the types of strategic investments that Chris discussed earlier. That really goes into forming up that $3 billion of incremental capacity for new growth investment.

Okay, thank you. And then more I think for Ken, just following a little bit up on Julian's question on demand response less on the energy side, maybe a little more on the capacity side. I was just curious as to your take on the recent decision from FERC about basically delaying the PJM demand response protocol changes? And just generally curious as to your take on where demand response is headed, have you seen more or less activity? What is your sense for the winds of change on demand response and how that is impacting the markets?

This is Joe Dominguez. Let me talk first about the FERC ruling. We see that as a process rolling essentially what FERC was saying is that PJM did not go through the appropriate process to make the tariff that would be required to implement the DR modifications that it has proposed.

We saw support for those proposals and some of the FERC commissioners orders there but it was really a process decision. That doesn't indicate a substantive view of the issue by FERC at this point.

On the demand response climate itself, demand response business continues to be consistent significant. Obviously we don't expect to see the kind of growth we saw over the past few years in demand response base but in our estimation there is still opportunity for growth in the demand response business and we will see in three weeks how much clears in the auction.

Excellent, thank you very much.

Michael Lapides, Goldman Sachs.

Two questions. One on the regulated business and one on the nonregulated. And ComEd just curious given the new legislation and assume that it becomes law either the governor signs it or it becomes law with a veto override, do you think that gives you the ability finally to earn your authorized on a forward test year forward rate base at ComEd? That is the question on the regulated side.

On the nonregulated side, we are seeing lots of development announcements or movement in PJM for new combined cycles, not tons but there is one or two companies privately held developers each looking to build a combined cycle or two or three. Just curious your views on the economics of new combined cycle in PJM?

We will get Anne to cover the first part.

Hi, Michael. This is Anne Pramaggiore. Your question on the gap between the earned to allowed ROE on ComEd, the legislation closes that gap (inaudible). We still have a number of items on appeal from the first formula rate base filing back in November of 2011 and that constitutes a portion of it. If we win those, we close the gap even further.

There will continue to be a somewhat of a gap left even after those two assuming we have positive results on those two outcomes. There's some structural items that the Commission has historically just not given us recovery -- some portion of advertising costs. There's a couple of other items. So there is a piece in there that we will have to deal with even after we get through the legislation and the court cases but those two efforts will substantially close that gap.

Got it. Okay,

On the nonregulated part, we are seeing OEM costs or construction costs coming down mostly because the technology -- the unit ratings on the assets are getting a little bit larger so the economics are improving but we still don't see the market signals or the capacity market showing us that it would be economic at this point for us to be building something. So there may be other opinions on market forwards that people are trying to be the first mover on but we are not seeing the market signals yet that would justify us going that direction.

Does that imply that some of the folks -- and I can think of two privately held developers that are each looking to build at least one combined cycle if not two in Pennsylvania. Do you worry that they are kind of jumping the gun a little bit and that even if they build -- even if they think the economics are good and you may not agree that it weighs on it for everyone?

No, what we worry about is that they try to bypass the rules of the capacity market or the revisions that we think are going through the capacity market. If they play up enough and they bid their costs as the rules, it is their option. We have still the low cost from the energy side -- the low-cost competitor assets that we can compete with them on that side as long as they play by the rules on the capacity side, we have no worry about them coming in.

Got it. Okay. Thanks, guys. Much appreciated.

Ali Agha, SunTrust.

First question on the non-power margin business, I see that outlook remains the same for 2014 and 2015. How much visibility do you have on that business sitting here today and what is the best way to gauge how accurate that outlook is?

Our outlook is consistent and the same on non-power business. A lot of that business is regular natural gas retail business that continues from a renewal perspective and has been very consistent for us. We also have some other services business that will regularly go from -- to go to execute it that we have been in these businesses for many years and so we feel comfortable with those estimates.

Again to you, one school of thought out there has been that some of the pickup in the forward curves has actually been due to the fact that in the near term gas prices have picked up because of the unusually cold weather and that as the weather settles down some of that may be given back. Do you buy into that or what do you think of that theory?

I do buy into a theory that says spot market prices do impact forward prices but what we are really talking about is the relationship of natural gas to power price and when natural gas prices were essentially flat from December 31 to March 31 and power prices went up, that doesn't associate with that theory at all.

So I think we are seeing more discussion in the market about this upside. We are not the only ones with the view anymore and as trading activity increases and liquidity increases we would expect that we will continue to see more of this upside over time.

Okay. Chris, one question for you. As you look at your portfolio today and you look at your mix, I know you have talked about that in the past, are you comfortable that this is the right mix of regulated versus non-regulated to support both your dividend plans and your investment grid aspirations over the longer term? Or do you think that there may be some changes at some point in the future?

No, definitely, we feel that we have the right mix and we have made the right call on the dividend that allows us to maintain a strong investment grade. As we discussed the sizing of the dividend, we are looking at the contribution of the regulated side on a more repetitive or consistent basis serving that while allowing the growth side -- the competitive side to continue to utilize the balance sheet space that it creates in its own earnings. So we feel very comfortable that we have gotten to the right spot to weather multiple business cycles.

And the volatility of earnings related to the commodity side, you are comfortable that that is the aspect of your portfolio?

Yes, we are very comfortable dealing with the volatility -- we would like for more volatility to come back but we are very comfortable with the volatility there.

Thank you.

Travis Miller, Morningstar.

A quick follow-up on the non-power gross margin. We see that didn't change between December and March. How much of that is due to volume? Volumes went up but margins came down and vice versa?

I would say none of it is due to volume. It is just a ratable non-power -- ratable non-power businesses that we execute on and when we execute on them, the numbers will move from to go to executed.

Okay. And then when we look at the merger back a year ago thinking about the synergies from that, you talked a lot about the retail wholesale pairing. How much have you realized of that, how much is there left to realize that? Can you just characterize how you have seen that part of the merger come through?

In matched load and generation space if that is part of your question, we have seen the benefits of having these combined businesses and the combined portfolio. We did see those benefits in our 2012 actual results. Obviously in 2013, you are hearing about a hedging position we took that isn't going to result in the same kind of numbers as we had last year from a portfolio management perspective. But we still have a lot of work to do on integrating systems and integrating the platform and we continue to work through that this year and we do expect to see consistently improved portfolio management and other earnings elements from the business when it is combined versus when it is not.

So as we disclosed last year and each year it gets harder to segregate, you are not keeping separate books anymore but as we told you at the end of last year, portfolio management on the integrated platform brought us another $400 million of gross margin.

And as Ken said this year, we took a combined bet on minimizing risk of gas going down in the first quarter but we will continue to see the benefits of optimization and we have already seen the benefits and reduced costs around liquidity as we collapsed those lines so the thesis of the merger has worked out to as we projected.

Could we see incremental upside to that 2 to 4 per megawatt hour number you have given out -- given the synergies, is there still enough left to go that you could see more upside?

We are holding at 2 to 4 and we are trying not to chase whether there could be another $0.25 here -- there is upside that is in this market in portfolio management and we will continue to watch that and report on it but our disclosures have an expectation of the synergies already in them.

Great. Very helpful. Thanks.

Paul Patterson, Glenrock Associates.

Just really quickly most of the questions have been answered but -- and I apologize if I missed this. But ERCOT looks like the hedged numbers went down and I know some of that probably has to do with the expected generation going up but even factoring for that, it appeared that you guys have less hedged I guess as I tried to back into it (multiple speakers) I'm sorry, go ahead.

That is exactly right. We had an increase in expected generation from improved sparks in ERCOT in '14 and '15. Quite frankly we did not hedge that increase so by design, the hedge disclosure is going to show that our hedge percentages have dropped because we have more megawatts to sell and we have not sold them. We believe there is substantial upside in ERCOT relative to current market prices and we are holding that position as such.

It kind of looked like actually the number might have changed that you actually might have reduced your position not just on a relative basis because the expected generation but because it just looked like actually perhaps the absolute number -- like you actually reduced your hedge position even if you hadn't expected an increase in generation output if you follow me.

Paul, we didn't. We didn't. We just held our position.

Okay. Thanks a lot.

With that, Bridget, we will close the call. Thank you very much for joining us.

Thank you. This does conclude today's conference call. You may now disconnect.