艾索倫電力 (EXC) 2016 Q1 法說會逐字稿

Good morning and welcome to the Exelon Corporation Q1 2016 earnings conference call. My name is Kashanti and I will be facilitating the audio portion of today broadcast. All lines have been placed on mute to prevent any background noise. (Operator Instructions). At this time I would like to turn the show over to Dan Eggers, Senior Vice President of Investor Relations.

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 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 the 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 scheduled 45 minutes for today's call. I will now turn the call over to Chris Crane, Exelon CEO.

Good morning. Thanks for joining us this morning. Once again we had a great quarter financially where we closed near the upper end of the range even with the milder weather. Operationally our utilities and plants continue to operate at high levels.

The big news for the quarter is we closed the Pepco Holding transaction in March. We are excited to have Pepco Utilities as part of the Exelon family. We know this has been a long journey and it took much longer than any of us anticipated but we appreciate the patience of our investors as we pursued the merger, our employees who worked tirelessly from the inception to the completion of the deal and the many stakeholders who supported was critical to getting the deal done.

PHI is an important piece of our strategy to become a more regulated company with more stable earnings streams. While we are still in the early stages of integrating PHI, PHI's earnings outlook is consistent if not better than what we showed you at EEI. It brings meaningful benefits to our customers, communities in Delaware, District of Columbia, Maryland, New Jersey including bill credits and reliability investments. More than $500 million in total commitments have been made and will be achieved due to this merger.

We are now focused on integrating Pepco into Exelon. We will bring our management model and our best practices to improve the experience of our customers. The transaction confirms Exelon's role as a leader in the industry. We serve 10 million customers, more than any other utility company. We will spend nearly $23 billion in capital across our utilities in generating business over the next three years which is the second highest among our peers. We are the largest pure T&D by rate base and within the top five when including rate base generation.

We are the second largest generator of electricity in the country, the largest competitor by a factor of nearly two. While producing power at the lowest carbon intensity of any large generator. We are the leader in the retail electric provider in the country serving 139 terawatts. The culture of the industry leadership is found throughout our organization positioning us very well for the future.

Switching to operational performance, our first-quarter operating performance was strong and we are on track for a strong year. At our legacy utilities, our SAIFI and CAIDI are on track to meet reliability targets. We are in top quartile in both. At the GenCo, our nuclear plants ran at a capacity factor of 95.8%, our solar and wind assets outperformed their energy capture targets.

Switching to Illinois and the nuclear plants, while there is much to celebrate this quarter, we also need to make tough decisions on the future of Clinton and Quad Cities nuclear stations in Illinois. The Board has given me authority to go forward with early retirements for Clinton and Quad Cities plants. If for Clinton adequate legislation is not passed during the spring legislative session that is scheduled to end May 31 and if for Quad Cities adequate legislation is not passed and the plant has not cleared the upcoming PJM option, otherwise we plan to retire Clinton on June 1, 2017 and Quad Cities on June 1 with 2018. This is consistent with planned refueling outage and capacity market obligations.

We commit to our employees, we committed to our employees, our shareholders and the communities to try to find a path to profitability for our distressed assets. This is because these plants are vital to the communities that they are located in and provide economic and environmental value to the state. The state's own analysis showed that closing Clinton and Quad Cities would result in $1.2 billion in lost economic activity and 4200 jobs lost and a significant reduction of supply of reliable electricity for Illinois residents and businesses.

We worked hard over the last few years to find a path to sustainable profitability to bring $120 million in strategic capital to these plants, we have pursued legislation and regulatory market changes. We have been successful in some areas. The PJM market reforms that were put into place last year and cost reductions that we have achieved and the large number of stakeholders who have worked so hard to help in this fight. We have strong allies in our [comps], our employees, our plant communities that build sponsors and cosponsors, 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 have on them.

But for reasons outside of our control, we have not seen progress in the 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 have 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 process.

On a more positive note, we continue to see a pathway to reform in New York where Gov. Cuomo, the legislature, the Public Service Commission have recognized the 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 will 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 will 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 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 plan 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 realize 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 yet continue to invest $800 million per year to improve reliability, with 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 have filed distribution cases in all of PHI's jurisdictions and expect decisions in all cases by the middle of next year providing needed revenue relief. 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 Public Service Commission. The rate case includes 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 dollar 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 have 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 slides 33, 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 nonpower 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 the majority of (inaudible) 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 and 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 the 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 will be hosting an analyst day on August 10 in Philadelphia and we will 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. 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 will open the line up now for your questions.

(Operator Instructions). Stephen Byrd.

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 we could just go through the mechanics of if it was implemented, how it would work so we can start to think about modeling the impacts?

Sure, Steve, 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. The existing state RPS programs for renewables provide compensation to 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 of 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 is a payment for the state value of zero emission credits from nuclear plants which represents the difference between the needed revenues and the cost 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 them, 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, I think if you have additional questions perhaps after the call, we could work with Dan and Emily to set up a meeting and go through more programmatic details.

That is great. That is a great start. Thank you. Just shifting over to renewables more broadly, could you just speak to your degree of appetite for more acquisitions? It sounds like you will 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 will 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 projects. So we have some projects in the pipeline now and are reevaluating others to see if they would be viable to go forward in the near-term.

Understood. Thank you very much.

Steve Fleishman.

Good morning. A couple -- first, a logistical question. The Ginna $101 million that you mentioned that you are 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 is in our guidance.

Okay. Including any back from prior periods?

That is correct.

Okay. And then a question, 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 or last year or something of that sort?

So you know we have stated that it is 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 has controllable. So you would see the run rate to be similar to what has happened in the past.

On this point, so for 2017, the cost exceeded available market revenues or that current marks by $140 million. But I think importantly and Joe raised this point, it is not the whole picture. The closure also avoids millions of dollars in bases and unit contingent risks that we face by operating the plants. Stated differently in order to reverse course we would need Illinois as well as New York to provide a structure that allows us to cover our cash cost plus normal operating risk in order to reverse this course.

Okay. And $140 million, that is kind of cash flow, does that include like CapEx or is that just kind of cash flow without CapEx?

That is cash flow.

One last question just on the -- in the event legislation doesn't happen and you need to shut the plants, 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 can start out with parent guarantees but you have to have it funded over a ten-year period, I think 60% by the end of a fifth year and the rest by the end of the 10 years.

Okay, those numbers in the 10-K are still good then so just can use those.

They are updated in the Q.

That will be coming Tuesday.

Okay, thank you.

Jonathan Arnold.

Good morning, guys. Just to clarify one thing on the current proposal, I think was emerged last night around the legislation so originally this would have applied 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?

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 it is 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.

Sort a f nuance of how the legislation is worded effectively?

That is correct. Make the same offer to you, Jonathan, if you would like after the call. We can sit down and work through some of the details.

Okay. That would be great.

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

Okay. So that was one thing. Second thing in your fourth quarter deck, you had this forecast around leverage ratios and the like going out through 2018 which I believe was assuming that Pepco would not happen. This was at ExGen. Can you give us a sense of how that progression would look if you market to the with Pepco scenario?

Sure, so Jonathan, we still anticipate reducing leverage at ExGen by $3 billion over the five-year planning period. Albeit this is not to the extent that we would have under the standalone scenario as ExGen's free cash flow is now being deployed to help fund PHI's capital spending program and we will provide more detail on the puts and takes on that at the analyst day in August.

So $3 billion is the new ExGen delivering number?

That is right and that is over the next five years. We have a large maturity and I believe it is 2019 that we would look to retire that maturity.

So that is over five years?

That is 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.

That is again over five rather than three?

That is correct.

Okay, great. Thank you. And then I guess you mentioned in the prepared remarks that price rebounded?

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

So whereas you had 2.3 in 2018 it is now 2.7 after five years?

Yes.

Okay, great. Thank you. And then you mentioned the prices have rebounded. Can you give us a rough sense of how the kind of gross margin mark would look if you used more like today's prices?

Jonathan, good morning. It is 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 have seen and 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 are higher at West Hub than we were at the end of the year so we would have recovered all of 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 are probably seeing it actually go over where it ended the quarter.

Great, okay. That is it. Thank you very much, guys.

Julien Dumoulin-Smith.

Hi, good morning. So perhaps to follow up on the same theme, can you elaborate a little bit on the balance of the new 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 are 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 are looking at Ginna and Nine Mile, one. We know about Oyster Creek and it is 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 will have to watch the capacity auction clearing in the out years. It is 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 if you will what the earned ROE is embedded at Pepco for 2016, just what is a baseline on the Pepco side as far as you see it post the close?

I think we included on the slide, I believe it is 30, the earned for 2015. Obviously while we are in pendency during the rate cases that obviously there is regulatory lag so we are going to see that decline. But we will have a much deeper dive in the PHI as part of the August Pep meeting. You can see on slide 29 the rate base statistics and I think it can work through some assumptions on regulatory lag using that information.

Got it. Perhaps not to jump the gun too much on the analyst day but what is the thought process on the baseline for 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 forecast or projected at EEI using PHI's internal forecasts 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 have experience within Maryland, Pennsylvania and Illinois.

You wouldn't roll it forward though?

I'm not's certain I understand. What you mean roll it forward?

The seven and nine just roll forward the CAGR off of 2016 base?

We will address that at the analyst day.

No worries. Thank you.

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

Got it. Thank you.

Brian Chin.

Going over to slide 13, the EPS impact that you have 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 have got on the second row, right?

That is right, Brian.

Okay, great. 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 strip?

That is correct.

Great. Thanks a lot.

Praful Mehta.

So just on the leverage a little bit just to ensure we understand, both at the holding company level and at ExGen, you have kind of talked about the ExGen debt and what you see over the 20 -- the 5-year period. How are you looking at holding company debt given the leverage you have assumed post Pepco transaction? Is there any objective to delever a little bit at the holding company as well?

So as you have heard us comment in the past, we do target a 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 will also see us consider to the extent we have available cash, 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 the GenCo is in those out years.

Got you. And just as we think about from a 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 for the next two-, three-year period?

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

Got you. Thank you. Finally, we saw that the power new business and the to go business, the EBITDA or the gross margin of that is going from [$215] million in 2016 up to about $1 billion by 2018. Could you just give us a little bit of context of what is driving that significant ramp up in that side of the business?

Joe Nigro

It is Joe Nigro. That is pretty standard shape that we have it. If you go back and look at disclosures over the years, you would expect to see much less new business in the prompt years, and the prompt is in this case 2016 than you would in the out years for example 2017 and 2018. Embedded in that power new business is s things like the execution of our retail business and the margins associated with that.

So as we get closer to the spot period, more and more of those contracts get layered in we begin to reduce that bucket of power new business. There are 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 are very comfortable with the notice that we put out there.

Got you. Thank you so much, guys.

(Operator Instructions). This does conclude today's conference call. You may now disconnect.