Dan L. Eggers - Senior Vice President-Investor Relations Christopher M. Crane - President, Chief Executive Officer & Director Jonathan W. Thayer - Chief Financial Officer & Senior Executive VP Joseph Nigro - Executive Vice President, Exelon; Chief Executive Officer, Constellation, Exelon Corp..

Steve Fleishman - Wolfe Research LLC Jonathan Philip Arnold - Deutsche Bank Securities, Inc. Julien Dumoulin-Smith - UBS Securities LLC Praful Mehta - Citigroup Global Markets, Inc. (Broker).

Good morning and welcome to the Exelon Corporation's Q1 2016 Earnings Conference Call. My name is Prasanthi and I'll be facilitating the audio portion of today's – and active broadcast. All lines have been placed on mute to prevent any background noise. For those of you on this stream, please take note of the options available in your event console.

At this time, I would like to turn the show over to Dan Eggers, Senior Vice President of Investors Relations..

Thank you, Prasanthi. Good morning, everyone, and thank you for joining our first quarter 2016 earnings conference call. Leading the call today are Chris Crane, Exelon's President and Chief Executive Officer; and Jack Thayer, Exelon's Chief Financial Officer.

They are joined by other members of Exelon's senior management team who will be available to answer your questions following our prepared remarks. We issued our earnings release this morning along with the presentation, both of which can be found in the Investor Relations section of the Exelon's website.

The earnings release and other matters which 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 our forward-looking statements based on factors and assumptions discussed in today's material, comments made during this call, and our Risk Factors section in the earnings release, and the 10-Q, which we expect to file on May 10.

Please refer to today's 8-K, the 10-Q, and Exelon's other filings for a discussion of factors that may cause 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 our earnings release for a reconciliation between the non-GAAP measures to the nearest equivalent GAAP measures. We've scheduled 45 minutes for today's call. I'll now turn the call over to Chris Crane, Exelon's CEO..

the PJM market reforms that were put into place last year, the cost reductions that we've achieved, and the large number of stakeholders who have worked so hard to help in this fight. We have strong allies in our cause, our employees, our plant communities, the bill sponsors and co-sponsors, our partners in labor, and our vendors among others.

I want to thank them all very much for their support and regret the impact on this decision that we have on them. But for reasons outside of our control, we have not seen progress in Illinois policy reforms, also the Supreme Court stay creates uncertainty regarding the EPA's Clean Power Plan.

Power prices have fallen to a 15-year low in PJM, causing the economics of Clinton and Quad Cities to further deteriorate. These plants have lost $800 million in cash flow from 2009 to 2015. Just to be clear, we are not covering our operating costs or our risks, let alone receiving a return on our invested capital.

We've done all we can up to this point and we continue to work through the spring legislative session to enact the much needed reforms. However, without adequate legislation we no longer see a path to profitability and no longer can sustain the ongoing losses.

On a more positive note, we continue to see a pathway to reform in New York where Governor Cuomo, the legislature, the Public Service Commission have recognized a need to preserve the state's nuclear plants.

New York is quickly moving forward to implement a clean energy standard that will allow us to continue to operate our challenged Ginna and Nine Mile plants. I'll turn the call over to Jack to discuss the first quarter results further..

Thank you, Chris, and good morning, everyone. My remarks today will cover our first quarter results, 2016 guidance, update our gross margin disclosures and provide an update on developments since Q4. I'll start on slide eight. As Chris stated, we had a strong quarter financially and operationally across the company.

For the first quarter we delivered adjusted non-GAAP operating earnings of $0.68 per share, near the top of our guidance range of $0.60 per share to $0.70 per share. This compares to $0.71 per share for the first quarter of 2015. Exelon's utilities delivered a combined $0.37 per share.

During the quarter, we saw unfavorable mild weather at PECO and ComEd versus planned, which was partially offset by lower bad debt expense at BGE. There are only eight days of PHI included in our results, which had a minimal impact on the quarter. Generation had a great quarter, earning $0.34 per share.

We had strong performance from our nuclear assets with better capacity factors than budgeted. And while weak power prices and lower volatility were a drag, our Constellation team delivered strong results. Our generation to load matching strategy continues to provide value and we benefited from a lower cost to serve our customers.

For the second quarter, we are providing guidance of $0.50 to $0.60 per share. This compares to our realized earnings of $0.59 per share for the second quarter of 2015. The appendix contains details on our first quarter financial results compared to the first quarter of 2015 results by operating company on slide 16 and 17.

Turning to slide nine, we are affirming our full-year guidance range of $2.40 to $2.70 per share which now includes the contribution from PHI and assumes an average of 926 million shares outstanding for 2016. This should help calibrate your segment models.

On slide 10, we are still working through a comprehensive financial plan now that we have closed the PHI deal, but want to address the pieces that we can today. We are reaffirming our earnings growth at our legacy utilities of 7% to 9% per year from 2015 to 2018.

On PHI, we are still working through the plan, but see the contribution equal to or better than what we showed you at EEI and consistent with sustaining our 7% to 9% utility growth target. On slide 11, to meet these growth targets we are going to be busy on the regulatory front. The PHI utilities have been out of rate cases for at least two years.

We are continuing to invest $800 million per year to improve reliability and customer service leading to the low-earned ROEs that we show on slide 30 in the appendix.

However, by the third quarter, we plan to file distribution cases in all of PHI's jurisdictions and expect decisions in all cases by the middle of next year providing needed revenue release. Atlantic City Electric and Pepco Maryland have already filed their cases.

ACE filed an electric distribution base rate case on March 22 with the New Jersey Board of Public Utilities requesting an $84 million revenue increase and a 10.6% return on equity. It also included PowerAhead, a five-year $176 million grid resiliency plan.

On April 19, Pepco requested a rate increase of $127 million with the Maryland's Public Service Commission. The rate cases include smart meter recovery and a two-year $32 million grid resiliency plan.

In addition to reducing the number and length of outages, Pepco's five-year smart grid program is generating nearly $4 in customer benefits for every $1 invested. In addition, ComEd made its annual formula rate filing with the Illinois Commerce Commission.

ComEd requested a revenue requirement increase of $138 million reflecting approximately $2.4 billion in capital investments made in 2015.

Those investments, which included $663 million for smart grid-related work has helped strengthen and modernize the electric system, resulting in record power reliability and customer satisfaction, operational savings, and new ways to save on electric bills for ComEd customers.

More details on the rate cases can be found on slide 33 – slides 34 through 37 in the appendix. Slide 12 provides our first quarter gross margin update. In 2016 total gross margin is flat to our last disclosure. During the quarter we executed on $200 million of power new business and $100 million of non-power new business.

We are highly hedged for the rest of this year and well-balanced on our generation to load matching strategy. Total gross margin decreased in the first quarter by $150 million in 2017 and $200 million in 2018, as PJM power prices moved approximately $1.60 to $2.10 lower since the beginning of the year.

We ended the quarter approximately 5% to 8% behind ratable in both of these years when considering cross-commodity hedges with a majority of modeling concentrated in the Midwest to align to our fundamental view of spot market upside at NiHub.

Power prices have risen since the start of the second quarter and we are timing our hedging activity to lock in the value of the recent price increases while remaining well positioned to capture our fundamental view. On slide 13, I wanted to give you a quick update on some tax implications that are associated with the completion of the PHI merger.

With the inclusion of PHI, we expect to realize $700 million to $850 million of additional cash from 2017 to 2019 related to legacy NOLs and the impacts of bonus depreciation.

However, now, as a very modest cash tax payer for 2018, we have less ability to take the domestic production activities deduction, or DPAD, in 2018 which effectively increases our overall consolidated tax rate by as much as 200 basis points or the equivalent of $0.06 to $0.08 per share in 2018.

Although this is a one-time negative impact to 2018 ExGen earnings, it comes with significant positive cash flow and we expect to return to normalized tax rates in 2019.

With the variability of interest rates, I'd like to remind you that ComEd's allowed ROE is based on a 30-year treasury rate plus 580 basis points, and thus sensitive to moves in this rate. Every 25 basis point move in treasury rates results in a $0.01 move in EPS. Before turning the call over to Chris, I wanted to raise a few scheduling points.

We'll be hosting an Analyst Day on August 10 in Philadelphia and we'll get details around shortly. Therefore, we will not be having a second quarter earnings call and will release earnings before Analyst Day. I will now turn the call back to Chris for his closing remarks..

Thanks, Jack. Just closing out on slide 14, the capital allocation philosophy. I want to cover that before we turn it over to Q&A, and take a moment to reiterate our capital allocation philosophy. Balance sheet strength remains a top financial priority.

We have a strong strategy to deliver stable growth, sustainable earnings, and an attractive dividend to our shareholders. We will be growing that dividend at 2.5% each year for the next three years, starting with the dividend payable in June.

From a capital deployment perspective, we will continue to harvest free cash flow from the generation business to invest primarily in our utilities to benefit our customers, invest in long-term contracted assets which meet our return requirements, and return capital to our shareholders. This is the right strategy for our markets and our assets.

Thanks and we'll open the line up now for your questions..

And we do have audio question from Stephen Byrd (17:13)..

Hey, Steve (17:15)..

Start on the Illinois legislation. And wonder if you could speak to the breadth of support that you have for the proposal. And then also if you could just go through the mechanics of if it was implemented, how it'd work? So we can start to think about modeling the impacts..

Joe, you want to cover that?.

Sure. Steve (17:36), the support is the same support we had for the original bill, labor, the host communities. And in addition, we now have the support of some groups that represent climate scientists and others that are concerned with greenhouse gas emissions.

In terms of how the program would work, let me just start with a policy analogy that I think all of you are familiar with. Existing state RPS programs for renewables provide compensation of qualified resources through renewable energy credits, RECs.

The REC value is the difference between available wholesale revenues and the costs needed to keep the existing renewables in operation and get new renewables built. All this is done in order to get the benefit of greenhouse gas reductions while protecting customers. If wholesale revenues go up, the needed REC payment goes down.

We see that happening every day in REC spot markets. The ZEC program is designed the same way. It's a payment for the state value of zero emission credits from nuclear plants which represents the difference between the needed revenues and the costs of operating the plants.

In the case of the New York and Illinois programs, the way it would work is that experts at the Commissions will determine on a prospective basis the cost of operating the plants plus risks, less available market revenues.

And where there is a delta between that, in other words where the costs and risks are not covered by available market revenues, the ZEC program will kick in and provide compensation for greenhouse gas avoidance. The program is not a PPA or a contractor difference. If revenues or costs are different, there is no true-up.

And – so, Steve (19:26), I think if you have additional questions, perhaps after the call we could work with Dan and Emily to set up a meeting, go through more programmatic details..

That's great. That's a great start. Thank you. And then just shifting over to renewables more broadly, could you just speak to your degree of appetite for more acquisitions? It sounds like you'll be a full taxpayer, I believe, in 2019, if I have that correct.

But just broadly, what degree of opportunities do you see out there in renewables? Is this an area that you would expect that you'll see further growth in?.

It is definitely throttled based off of our tax capacity and we are looking at that now. You do get a certain amount of dilution with delaying the benefits of the tax attributes of the project, so we have some projects in the pipeline now and are re-evaluating others to see if they're – they would be viable to go forward in the near-term..

Understood. Thank you very much..

And your next question comes from the line of Steve Fleishman..

Hi, Steve..

Hi. Good morning. A couple of – first, a logistical question.

The Ginna $101 million that you mentioned that you're getting, is that – is kind of a trued-up amount including past years, is that in your guidance for this year? Or is that kind of like a one-time item or how are you treating that?.

Steve, that's in our guidance..

Okay.

Including any back from prior periods?.

That's correct..

Okay.

And then a question just – is there any way you can give us some sense on the cash flow or losses from Clinton and Quad Cities, let's say, in your guidance for last year or something of that sort?.

So we've stated that it's greater than $800 million since 2009. There are some variables in there on cash savings going forward or cash losses going forward, power prices coming down, cost cutting initiatives; and we do have an element of overheads that would not be as controllable.

So you would see the run rate to be similar to what has happened in the past..

Okay..

Steve, you know, on this point – so for 2017, the cost exceeded available market revenues or at current marks (22:12) by $140 million. But I think importantly and Joe raised this point, it's not the whole picture. The closure also avoids millions of dollars in basis and unit-contingent risks that we face by operating the plants.

And stated differently, in order to reverse course we need Illinois as well as New York to provide a structure that allows us to cover our cash costs plus normal operating risks in order to reverse this course..

Okay.

And $140 million that's kind of cash flow? Does that include like CapEx, or is that just kind of cash flow without CapEx?.

That's cash flow..

Okay.

One last question just on the – in the event legislation doesn't happen and you need to shut the plants, what – is there any cost related to that?.

As you saw in the K, and we reiterate in the Q, there is some unfunded liabilities on the decommissioning trust. Those numbers are in there at full 100% ownership of the plants.

And so the way that we would have to handle that is – you know, you can start out with parent guarantees, but you have to have it funded over a 10-year period, I think 60% by the end of the fifth year, and then the rest by the end of the 10 years..

Okay.

Those numbers in the K are still good then, so that we just can use those?.

They're updated in the Q..

That'll be coming Tuesday..

Okay. Thank you..

And your next question comes from the line of Jonathan Arnold..

Hey, good morning, guys..

Good Morning..

Good Morning..

Just to clarify one thing on the current proposal that I think was emerged last night around the legislation.

So originally this applies to all nuclear plants in the state, but is it correct that this would just be Clinton and Quad? And can you just explain how that works in terms of the discussion of the ZEC structure?.

Joe?.

Sure. Jonathan, all plants could apply, but quite obviously the only plants that would receive revenue under this program would be those where the costs exceed the revenues. And so there is – it's a 20 terawatt-hour cap which has enough room in it to accommodate Clinton and Quad Cities.

And our expectation is that Exelon would seek to have those two plants participate. The other plants would not participate..

Okay.

And that's sort of nuanced in how the legislation's worded effectively?.

That's correct..

Okay..

It's the same offer to you, Jonathan; if you'd like, after the call, we could sit down and work through some of the details..

Okay. That'll be great. And is there any....

And, Jonathan, just to interject just to make the clear point, they would provide the opportunity to be compensated for cost plus risk..

Okay. That was one thing. The second thing, in your fourth quarter deck, you have this forecast around leverage ratios and the like going out through 2018, which, I believe, was assuming that Pepco would not happen. This was of the ExGen.

Can you give us a sense of how that progression would look if you kind of market to the – with Pepco scenario?.

Sure. So, Jonathan, we still anticipate reducing leverage of ExGen by $3 billion over the five-year planning period, albeit this is not to the extend that we would have under the standalone scenario, because ExGen's free cash flow is now being deployed to help fund PHI's capital spending program.

And we'll provide more detail on the puts and takes of that at the Analyst Day in August..

So $3 billion is kind of the new ExGen delevering number?.

That's right. That's over the next five years, we have a large maturity. And I believe it's 2019, that we would look to retire at maturity..

Okay.

So that's over five years?.

That's correct..

And then the 2.3 ExGen debt-to-EBITDA that you were looking at for 2018, roughly what does that look like now?.

It, over the five-year period, would go to right around three times..

So that's again over five years, rather than three years?.

That's correct..

Okay, great. Thank you. And then I guess you mentioned in the prepared remarks the prices have rebounded....

So, Jonathan – sorry, just let me correct, 2.7 times at the end of the five-year period..

So whereas you have 2.3 times in 2018, it's now 2.7 times after five years?.

Yes..

Okay, great. Thank you. And then you mentioned that prices have rebounded.

So can you give us a rough sense of how the kind of gross margin mark would look if you use more like today's prices?.

Yeah. Jonathan, good morning. It's Joe Nigro. I think if you look at our hedge disclosure at the end of the quarter and then factor in the changes since the end of March, you would see all of that drop in 2017 and 2018 being recovered. We've seen an appreciable move, as you know, in prices since the end of March.

We're actually higher in NiHub than we were at the end of the year. We're higher at West Hub than we were at the end of the year, so we would have recovered all that drop and probably adding to it.

We calculated that a couple of days ago, but the market has continued to move higher, so we probably have seen it actually go over where it ended the quarter..

Great. Okay. That's it. Thank you very much, guys..

Thanks..

And your next question comes from the line of Julien Dumoulin-Smith..

Yeah. Hi. Good morning..

Good morning..

So perhaps to follow up on the same theme, can you elaborate a little bit on the balance of the nuclear portfolio that is ex-Clinton, ex-Quad? How you think about their cash flow profile? And if you don't get this legislation, what the prospects are for further rationalization? I don't mean to jump the gun too much here, but just talking about the future a little bit more?.

So there's varying cash flows by assets depending on their location. They are positive at this point. If you look at the other units that are more challenged, you're looking at Ginna and Nine Mile. One – we know about Oyster Creek and it's coming up in 2019, the other one that has a real focus on it right now is Three Mile Island..

Got it. And specific to Illinois, is there any commentary around – so let's say we don't get it in 2016 or 2017, does that trigger another set of reviews? Again, not to push it too much..

At this point we'll have to watch the capacity auction clearing in the out years. It's tight on energy at some of the assets, but they are positive..

Got it. Okay, great.

And then turning back to the utilities real quickly, can you comment, or I'm curious, if you will, what the earned ROEs embedded at Pepco for 2016 – just what's the baseline on the Pepco side as far as you see it post the close?.

Julien, in terms of – I think we included it on slide, I believe it's 30, the earned for 2015. Obviously, while we're in the pendency period during the rate cases that – obviously, there's regulatory lag, so we're going to see that decline, but we'll have a much deeper dive in the PHI as part of the August 10 meeting.

You can see on slide 29 the rate base statistics and I think can work through some assumptions on regulatory lag using that information..

Got it.

And perhaps not to jump the gun too much on the Analyst Day, but what is the thought process on the baseline for a future regulated CAGR?.

I think the thought is the 7% to 9% that we confirmed on the call and PHI is absolutely consistent with that expectation. We, as we mentioned, are seeing improvement relative to what we forecasted or projected at EEI using PHI's internal forecast.

And Dennis and team continue to work to identify further opportunities around efficiency as well as regulatory policy to work to get those earned and allowed ROEs in line with the success we've experienced within Maryland, Pennsylvania and Illinois..

Got it.

You wouldn't roll it forward though?.

I'm not certain I understand what do you mean roll it forward?.

The 7% to 9%, just roll it forward to CAGR off a 2016 base?.

We'll address that at the Analyst Day..

All right. No worries. Thank you..

I mean, embedded in there is 7% to 9% through 2018, so just thinking it through, it's in there..

Got it. Thank you..

And your next question comes from the line of Brian Chen (32:25)..

Hey, Brian (32:30)..

Going over to slide 13, the EPS impact that you've laid out in that top table, I just want to verify that that is not including the use of capital from that positive cash flow impact that you've got on the second row right?.

That's right, Brian (32:46)..

Okay. Great.

And then I just want to verify that Quad Cities didn't clear in the 2018 and 2019 auction, correct? So the closure of Quad Cities shouldn't have any sort of residual obligation that you have for the 2018, 2019 capacity through (33:03)?.

That's correct..

Great. Thanks a lot..

And your next audio question comes from Praful Mehta..

Hi, guys..

Good morning..

Good morning. So just on the leverage a little bit, just to ensure we understand both at the holding company level and at ExGen. You've kind of talked about the ExGen debt and what you see over the 20 – the five year period.

How are you looking at holding company debt given the leverage you've assumed post Pepco transactions? Is there any objective to delever a little bit at the holding company as well?.

So Praful, as you've heard us comment in the past, we do target at 20% FFO to debt on a consolidated basis and that was one of the benefits of adding PHI to the Exelon family. And so we will certainly be looking at our leverage ratios at the GenCo.

I think you'll also see us consider to the extend we have available cash at the holding company as well, we just need to see as we get further out what the realized power prices are and what the free cash flow coming off of the GenCo is in those five years..

Got you. And just so if you think about from the sources/uses perspective, the source is primarily out of ExGen coming to fund CapEx at the utilities and then deleveraging both at ExGen and the parent.

Is that a fair way to think of it or is there some cash generation coming out of the utilities as well over the next two year, three year period?.

I would say, on a net basis, utilities are consumers of cash. So you're correct. That ExGen cash flow as well as debt raise at the utilities is the primary source for funding the significant CapEx that we see, $25 billion over the next five years at the utilities..

Got you. Thank you. And then just finally, we saw that the power new business and the to-go business, the EBITDA, or the growth margin of that is going from $250 million in 2016 up to about a $1 billion by 2018.

Could you just give us a little bit of context of what's driving that significant ramp-up in that side of the business?.

Yeah. Hi. It's Joe Nigro. That's pretty standard shape that we have. If you go back and look at disclosures over the years, you would expect to see much less new business in the prompt years – in the prompt year, in this case 2016, than you would in the out years, for example, in 2017 and 2018.

Embedded in that power new business is things like the execution of our retail business and the margins associated with that. So as we get closer to the swap period more and more of those contracts get layered in, we begin to reduce that bucket of power new business.

I mean, there's other elements of our business that follow that same timing shape, so this isn't unique in the sense of seeing a ramp up between the prompt year to two years forward and we're very comfortable with the numbers that we've put out there..

Got you. Thank you so much guys..

And this does conclude today's conference call. You may now disconnect..

Thank you..