艾索倫電力 (EXC) 2018 Q3 法說會逐字稿

Good morning, ladies and gentlemen. Welcome to the Exelon 2018 Third Quarter Earnings Conference Call. My name is Jerome, and I will be facilitating the audio portion of today's interactive broadcast. (Operator Instructions)

At this time, I would like to turn the show over to Mr. Dan Eggers, Senior Vice President, Corporate Finance. The floor is yours.

Thank you, Jerome. Good morning, everyone, and thank you for joining our third quarter 2018 earnings conference call. Leading the call today are Chris Crane, Exelon's President and Chief Executive Officer; and Joe Nigro, Exelon's Chief Financial Officer. They're joined by other members of Exelon 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 and comments made during this call. Please refer to today's 8-K and Exelon's other SEC filings for discussions of risk factors and factors that may cause results to differ from management's projections, forecasts and expectations. Today's presentation also 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 reconciliations between the non-GAAP measures and 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.

Thanks, Dan, and good morning, everyone, and thank you for joining us. Flipping to Slide 5. We delivered another strong quarter with earnings again at the upper end of our range, which allows us to raise the lower end of our full year guidance. The utilities performed well with strong earned ROEs and largely first quartile operations. As we stated previously, the Federal Courts of Appeal in Illinois and New York strongly affirmed the legality of the ZECs. And our focus on cost continues, identifying an additional $200 million in gross savings, which $150 million of that will flow to the bottom line, bringing our 6-year total savings to more than $900 million. Combined, this performance demonstrates our growing value. For the quarter, on a GAAP basis, we earned $0.76 per share versus $0.85 per share last year. On a non-GAAP operating basis, we are at $0.88 per share, and again, above the midpoint of our $0.80 to $0.90 range guidance that was provided.

Turning to Slide 6. Our utilities continue to perform at high levels across key customer satisfaction in operating metrics. The investments we are making in technology and infrastructure continue to improve reliability, which leads to greater customer satisfaction and ultimately supporting strong relations with our regulators and our legislatures -- legislators. PECO and BGE improved their J.D. Power residential gas and electric scores over the last year, with PECO receiving its highest ranking ever, placing second in the Residential Electric Survey. Our customer service metrics are strong. BGE and ComEd are in the top decile for customer satisfaction, and PHI is in top decile for its service levels. Each of our utilities achieved top quartile reliability performance in safety or outage duration. In CAIDI, which is the -- or outage frequency is safety and CAIDI, which is outage duration. ComEd and PHI performed in top decile for CAIDI. Safety, as we've discussed in the past, is our highest priority and remains that. Our metrics have continued to improve since the beginning of the year.

At ExGen, our third quarter was 39.7 terawatt hours of capacity factor at 93.6%. During the fourth hottest summer in nearly 125 years, we performed at 96.7% capacity factor and avoided 33 metric tons of carbon. Our gas and hydro fleet performed well, but below plan, with economic dispatch match at 95.8%. This lower performance was primarily the results of our CCGTs at Colorado Bend and Wolf Hollow being offline because of some turbine blade defects. The blades have been replaced. Wolf Hollow came back into service in late September. One of the Colorado Bend units returned to service in October and the other will be back in service shortly. It's in the process of restart as we speak. We took advantage of the outage time to perform normal maintenance that will be required to have then shut down for next spring.

From a financial perspective, all the repairs were covered under a warranty, and the market's impact from the plants being down were well within our full range outage contingency plan. The plants ran very well over the summer prior to the outages. And we are very pleased with the performance of the design and their durability. They remain an integral part of our Texas strategy.

Turning to Slide 7. As you know, we've had strong track record of finding efficiencies in the business and driving cost savings, which is why we created the business transformation team earlier this year to focus on our Business Services Company. As part of that effort, with additional savings from our nuclear fleet, we are announcing a $200 million reduction to our run rate 2021 cost, of which $150 million will reach the bottom line at ExGen. Joe's going to cover this in more detail during his remarks.

I'll turn it now to the policy updates for the quarter and start with the ZEC programs. As I said, both the seventh and the second Court of Appeals dismissed challenges to the ZEC programs in Illinois and New York, respectively. In doing so, each court found that the states have the right to choose generation sources based on attributes they prefer, such as environmental performance, and that these programs are not tethered to the market. The plaintiff SAIFI hearing in Illinois case, which the court denied last month, the rulings were consistent with our expectations. We're happy with the resounding affirmation on these important State Clean Energy Policies. In New Jersey, the process for implementation of the ZEC program there remains on track to take effect early in the second quarter of 2019. The Board of Public Utilities has finished its hearings on implementation of the ZEC program, and the utilities have filed tariffs to recover the ZEC-related charges. We expect the BPU to accrue the changes later this month.

On the federal policy front, we think that FERC's June order took an important step forward by empowering the states to continue prioritizing zero carbon energy throughout the state-led procurements outside of the PJM capacity module. A number of proposals were filed in response to the order, including from a diverse coalition of which Exelon is a member, and PJM. We see all of the major proposals is putting our generation fleet in a better position financially than the current market construct. We are pleased to have filed as part of a coalition that supports the rights of states to advance their clean energy goals. Slide 22 gives a lot more detail on the coalition but it includes consumer ratepayer advocates, attorney generals, national environmental groups, renewable energy trade associations, public power and the other nuclear generators in PJM. Our proposal will provide states the flexibility to conduct the capacity procurement of resources they wish to support for the public policy reasons and would protect consumers from paying twice for capacity resources. It strikes the balance that FERC is looking for to ensure states can meet their environmental goals, while protecting the competitive market. Reply to the comments are due November 6, and it will be important for FERC to issue an order early next year to give the markets guidance going forward. As you know, we are still waiting for orders from FERC on the Fast Start and resiliency examination.

But with that, now I'll turn it over to Joe to walk through the numbers.

Thank you, Chris, and good morning, everyone. Turning to Slide 8. We had another strong quarter financially delivering adjusted non-GAAP operating earnings of $0.88 per share, which is at the upper end of our guidance range of $0.80 to $0.90 per share. Exelon's utilities west holding company expenses earned a combined $0.55 per share. Compared to our plan, we benefited from reduced storm activity and favorable weather in our nondecoupled jurisdictions, including PECO, Atlantic City Electric and Delmarva, Delaware. Generation earned $0.33 per share in the third quarter, which was slightly behind our plan. The third quarter was impacted by lower realized ERCOT prices versus the end of the second quarter, lower-than-expected Generation performance with the unplanned outages at our ERCOT CCGTs, as Chris discussed as well as one in Mystic 8, 9 in addition to higher allocated transmission costs. These were partially offset by realized gains from our nuclear decommissioning trust fund.

On Slide 9, we show our quarter-over-quarter walk. The $0.88 per share in the third quarter this year was $0.03 per share higher than the third quarter of 2017. Overall, the utility earnings were collectively up $0.07 per share compared with last year, driven primarily by higher rate base, new rate associated with completed rate cases and favorable weather. Generation earnings were down $0.03 per share compared with last year, driven largely by the absence of EGTP gross margin from the deconsolidation in the fourth quarter of 2017 and higher planned nuclear outage days, partially offset by contribution from a full quarter of Illinois ZEC revenues and savings from tax reform.

Turning to Slide 10. We are raising the lower end of our 2018 EPS guidance range from $2.90 to $3.20 per share to $3.05 to $3.20 per share. We are pleased with the strong operational results at both the utility and generation businesses that are pushing us up into the upper half of our range, particularly as we have overcome unexpected headwinds, including the challenging winter storms.

Moving to Slide 11. Improved operations at PHI and positive rate case outcomes are driving better earned ROEs. Pepco's higher ROE reflects last fall's distribution rate cases as well as the recent Pepco Maryland and DC settlement that took effect in June and August, respectively. Delmarva's earned ROEs include the benefits of interim rate that became effective during the first quarter, with final rates for Delmarva electric effective September 1 and favorable weather at Delmarva, Delaware during the quarter. At Atlantic City Electric, we saw higher earnings from last fall's rate case settlement as well as favorable weather during the quarter, which improves 12-month trailing ROE significantly from last quarter. As we have previously discussed, trailing 12-month ROEs for all of our PHI utilities should continue to improve next quarter as the FAS 109 charges from the fourth quarter of 2017 drop out of the calculation. For the legacy Exelon utilities, our earned ROEs remained over 10%, but modestly dipped from last quarter. Our overall earned ROEs for Exelon utilities were modestly higher than last quarter at 9.6%, well within our earned ROE target of 9% to 10% that underlies our earnings outlook for 2019 and beyond. We are pleased with our overall utility performance but have plans for continued improvement to bring PHI closer to the rest of our utility.

Turning to Slide 12. We remain busy on the regulatory fronts. On October 18, the Administrative Law Judges presiding over PECO's electric distribution base rate case recommended the settlement with all parties be approved. The deal provides for an increase of $96 million in annual electric distribution revenues, offset by $71 million in tax saving benefits for customers for a net $25 million revenue increase. We expect to receive an order in the fourth quarter. On August 9, the DC commission approved the settlement that was reached in April based on a $24.1 million revenue reduction after incorporating tax reform. Rates went into effect on August 13. A final order was received on August 21 for the settlement we reached in June on the Delaware -- Delmarva electric distribution case. The case will provide a $7 million revenue decrease, including the benefit of tax reform for customers. On September 7, Delmarva, Delaware entered into a settlement agreement in its pending gas distribution base rate case that provides for a revenue decrease of $3.5 million, including tax benefits for customers. A final order is expected in the fourth quarter. We also have a number of rate cases still in progress. We expect an order for BGE's pending gas rate case in January of 2019. As a reminder, the case includes the requested $60.7 million increase to its gas revenues for infrastructure investments since 2015, and moving $21.7 million in revenue currently being recovered via the STRIDE surcharge into base rates. We expect to receive an order from the Illinois Commerce Commission on ComEd standard formula rate case in the fourth quarter.

And finally, on August 21, the Atlantic City Electric filed the distribution base rate case with the New Jersey Board of Public Utilities, seeking a revenue increase of $109 million, and we expect an order in the second half of 2019. The utilities and the regulatory teams are doing a lot of hard work to improve system reliability and performance for our customers and fostering a supportive regulatory backdrop. That, in turn, is helping to lift earned ROEs towards their allocated levels across the acquired new settlement payments. More detail on the rate cases and their schedules to be found on Slides 24 through 30 in the Appendix.

Turning to Slide 13. We invested $1.4 billion of capital at the utilities during the third quarter and are at $3.9 billion year to date. We remain confident in our ability to meet our $5.5 billion capital budget for 2018. This quarter, I would like to feature 2 projects within our portfolio of utility investments. The first is the early completion of ComEd's $920 million smart meter installation program. ComEd installed more than 4 million smart meters in just over 7 years, which is 3 years ahead of the original schedule and more than $20 million under budget. To help put this program into context, our ComEd team installed on average 2,400 smart meters per day over that 7-year span. In fact, one of our workers personally installed over 25,000 meters as part of this program. The installation of smart meters on the ComEd system will allow customers to be better informed about their energy consumption that can help them save money and will allow ComEd to further improve its service offerings. In addition, it drives over $100 million of annual operating -- operational savings, primarily from increased efficiencies in field operations, such as meter reading and avoided truck rolls. This smart meter installation program is part of the $2.6 billion Energy Infrastructure Modernization Act program.

The second project I want to highlight is Atlantic City Electric's Churchtown substation expansion project in Pennsville, New Jersey. This $50 million project entails equipment upgrades for reliability and 230, 138 and 69 kV expansion for additional transmission capacity. Construction also included installation of 2.1 miles of transmission line consisting of 59 new structures. The expansion improves reliability for our customers by replacing and upgrading outdated equipment and by expanding regional transmission capacity, which has the benefits of reducing congestion to our customers.

Turning to Slide 14. Relative to our last update, total gross margin was flat in 2018 and up $50 million in both 2019 and '20, primarily as a result of power -- of higher power prices. For 2018, Open Gross Margin was up $100 million, primarily due to higher NiHub, PJM West Hub and New York Zone A prices and offset by weakening ERCOT spark spreads. Total gross margin is offset by lower mark-to-market of our hedging due to the higher power prices. For 2019 and '20, Open Gross Margin was up $250 million and $100 million, respectively, due to higher PJM West Hub prices and stronger ERCOT spark spreads. In 2019, Open Gross Margin was also up on higher NiHub and New York Zone A prices. Similar to 2018, the mark-to-market of our hedges is down both in '19 and '20 due to higher prices. We also executed $50 million of power new business in both 2018 and '19 and executed $50 million of nonpower new business each year. From a hedging perspective, we ended the quarter in line with our ratable hedging program in 2018 and 9% to 12% behind ratable in 2019 and 8% to 11% behind ratable in 2020 when considering cross commodity hedges where we have increased our concentration.

Turning to Slide 15. As Chris mentioned, we are announcing another round of O&M cost reductions as part of our continual efforts to evaluate our work practices looking for ways to be more efficient, eliminate redundancies and better incorporate innovation in technology. With this new program, our gross run rate savings in '21 will be $200 million, which we will ramp up over the next 2 years. These incremental savings will come from our Exelon Generation business, primarily through even greater efficiencies in our nuclear operations and at the Business Services Company, or BSC, which is part of the transformation efforts that Jack is leading. The $200 million of savings is a gross number with about half from ExGen and half from the BSC organization. And since BSC costs are shared roughly 50-50 between Exelon Generation and Exelon utility, we would expect our utility customers to benefit from $50 million in annual savings over time with the other $50 million flowing through Exelon Generation bottom line. When we include the $50 million of incremental direct savings at ExGen, we expect $150 million of savings to flow through our bottom line in 2021 relative to our previous guidance, which we show on the lower left chart.

Exelon continues to embrace a culture of cost discipline and operational excellence. These cost updates are consistent with these cultural values. If we look at all the cost savings announced since 2015, we have now reduced O&M by over $900 million. It's due to hard work of all of our employees who strive every day to run the company more efficiently while adhering to our commitments to safety, reliability and community stewardship.

Turning to Slide 16. We remain committed to our strong balance sheet and investment-grade credit rating. And to that end, since our last earnings call, S&P has placed our ratings at ExGen and Exelon Corporate on CreditWatch Positive, recognizing the improvements in overall strength of our balance sheet.

Turning to the metrics. Our consolidated corporate credit metrics remain above our target ranges and meaningfully above S&P threshold. We are forecasting ExGen's leverage to be 2.5x debt to EBITDA at year-end 2018, which is below our long-term target of 3.0x. On a recourse debt basis, we are at 2.0x, which is well below our target range. We will continue to manage our balance sheet at ExGen over time to the 3.0x debt to EBITDA level. So look for us to focus on debt reduction at both the Holdco and Genco.

I will now turn the call back to Chris.

Thanks, Joe. Turning to Slide 17. As we have shown you, we had a strong quarter financially and operationally. We continue to get stronger on both fronts. This is due to the hard work and dedication of all of our employees every day. We also had important wins in the courts to preserve the ZEC programs and are finding ways to operate more efficiently, providing incremental cost savings as discussed. Our value proposition remains unchanged. We're focused on growing our utilities, targeting a 6% to 8% EPS growth through 2021. We continue to use free cash flow from the Genco to fund incremental equity needs at the utilities, pay down debt over the next 4 years at the Genco and Holdco and fund part of the faster dividend growth rate. We will stay focused on optimizing value at the ExGen by seeking fair compensation for our carbon-free generation fleet, supporting proper price formation in PJM and resiliency efforts at FERC and supporting capacity market reforms that will allow states to continue to protect citizens from carbon and air pollution, while benefiting from regional markets. We will close uneconomic and sell assets where it does not make sense to accelerate our debt reduction plans and maximize value through generation to the load matching strategy. We continue to sustain strong investment-grade credit metrics and grow our dividend consistently at 5% through 2020.

Operator, now we can take -- open to -- the call up for questions. Thank you.

(Operator Instructions) Your first question comes from the line of Greg Gordon from Evercore.

Couple questions. First, on the quarter. Everything seems really good on the utility side and the underlying operations at the Genco look decent too, but it was a little squishy around some of those operational issues. Can you just talk us through that and get us comfortable that they're sort of temporal and not structural?

Are you talking about the operational issues around the Genco in the power sector?

In the Texas and the NCI in Texas, the interruption in Massachusetts, the higher FDR -- FTR costs. So I just want to make sure we can be comfortable that they're not going to sort of run out into the future and impact your ability to future numbers.

Let me start out with the Texas assets, so I'll let Joe fill in on the rest of it. Those GE 7HA.20 (sic) [7HA.02], these were the first serial numbers, 1 and 2. We were aware as GE was that there was some difficulty with the first-stage blades. We had approximated a run period that we could operate the assets before putting in the fix. The fix was already underway and then designed. GE did give us very strong warranties on those assets and responded very well on the first failure on the 1 CT at Colorado Bend. We proactively shut the other 3 CTs down, replaced them with the new design, had them back up and running. And as I said, we expect we're in the rollout phase now and the startup phase of the fourth unit and we feel confident in the design. GE has put us an inspection program together that we'll be borescoping after so many hours of operation. They've responded well, the solid engineering, confirmed by independent assessment, so we feel that, that is behind us. And we'll be able to continue those assets to operate at -- incredibly high capacity factors and efficiencies going forward. On the FTRs and the other issues, I'll let Joe cover it.

Yes. So Greg, I think first thing is, as Chris mentioned, the Generation issues drove some of the underperformance at ExGen. In addition to that, when you look at power prices in Texas at the end of June and where they realized for the quarter, there was an impact with the difference there. As you know, the spot market prices were lower than when we walked into the quarter. On the transmission side, the costs were associated with Order 494 at FERC and that had a negative impact. So from our lens, when you talk about the Generation performance, both at Mystic and at ERCOT, those are onetime occurrences, similarly on the transmission side. The favorability was driven on the realized nuclear decommissioning trust gains. So I think when you look at it from our lens, you see these onetime items that are driving the lower results.

One follow-up on ExGen, and then one more if you'll humor me. Looking at the cost cuts, it's really quite an impressive incremental change. You've got the cost declining from $4.625 billion to $4.175 billion in 2020 and a little bit more in '21, $450 million savings but that gross margins declined by $700 million. And so skeptical investors look at this and say, "Well, you guys are doing yeoman's job here rightsizing the cost structure but earnings aren't getting better." I would argue that cost cuts are permanent and these backward-dated power prices are hopefully temporary. But can you give us some confidence that there's positive operating leverage here as we move through time? And that these lower commodity prices and capacity prices are not structural?

We've talked about this before that we lack liquidity in the out-years. It's a softer market. Our fundamentals still tell us that this backward-dated curve is not what we'll see as the prompt years come in. And so we're managing the book in that manner, maintaining as much margin open and using cross-commodity hedges to be able to manage that. It's -- we will constantly look at driving efficiencies. You can't have a company operate with any aspect or entity within the company being inefficient. So driving efficiencies has multiple benefits, but one of them is reduction in expense, and we'll continue to focus on that as we serve the customer. As far as the market issues, Jim or Joe, do you want to cover any more on that?

Yes. I think the only thing I would add about the backwardation of the curve is, with the next couple of years trading at $25 and $24 due to lack of liquidity, we're seeing net retirements of newbuilds over the next few years between $20 and $23. That would lead us to believe that backwardation won't realize in spot. We're seeing spot prices in NiHub even in some of the lowest delivered fuel price years clear, north of $26, $27. So the backwardation, to your point, is -- seems temporal, Greg.

Okay. And then final question is, given that the balance sheet is so strong and that the rating agencies are finally coming around considering higher credit ratings, how much balance sheet capacity does that create? And/or does it give you more latitude to have a more aggressive risk-management policy and take -- hedge less and take more of your power into the spot and, therefore, try to get those better prices?

Greg, it's Joe. The short answer is, with that balance sheet capacity, we can be more aggressive. And as I mentioned in my remarks, when you look at how far behind we are of our ratable plan and when you overlay the fact that we're using gas as a proxy for power, we are carrying a very long open power position in 2019 and '20. And then we're able to do that given the strength of the balance sheet that we have. We continue to challenge ourselves in this regard as well, and as Jim mentioned on our use of power, we're going to continue to be constructive in the way we manage the portfolio relative to what we think fair value is in the out-years and that leverage on the balance sheet allows us to do that.

Your next question comes from the line of Julien Dumoulin-Smith from Bank of America.

So I wanted to follow a little bit up on the utility activities. Obviously, good progress at PHI yet again. But wanted to elaborate a little bit further on this. Obviously, the cost reductions of, say, $50 million-ish accrued to the utilities, how does that play out in terms of, again, increasing your ROE, right? I gather the bulk of that would be moving back to customers over time. Although clearly, you're underearning relative to authorized level still. And then in tandem with that question, if you can elaborate a little bit more on the sort of initial utility CapEx planning. Certainly, this is a growing discussion of legislation in Illinois as well as a litany of other smaller programs, I think you've already alluded to a little bit, elsewhere across your utility system.

Yes, I'll let Anne take that.

Sure. Yes, so a couple responses to your questions. As we think about moving forward, obviously, we're going to blend $50 million into the LRP over time. It's not sitting there right now, but we'll look at that as we do the next LRP iteration. And certainly, our focus on O&M is to be flat to declining at the utilities, and that's the goal as we move forward to manage that side of the equation. As we think about what we're doing on ROEs and sort of developing that at the PHI utilities and the other utilities, the first thing we're doing is we're looking at how -- we're filing annually. How do we reduce lag? One of the ways is we file annually. We've got a stay out provision at DPL until 2020, but with the rest of the utilities, we'll be filing annually. We're looking at other mechanisms to reduce lag riders. We've got the STRIDE rider in Maryland, DISC rider in Delaware and the IIP rider in New Jersey that we're looking to place about $358 million of capital investment in right now. Interim rates at New Jersey is helping us close that lag gap. And we're looking at a multiyear rate plan in DC. We've been invited to make that filing, and we'll be doing that shortly. So just got an [outright] provision at PECO authority for the commission to look at that, so that's something we'll be looking at going forward. So those are all the ways we're looking to close in on that ROE number. Obviously, looking at -- lags are biggest sort of earn to allowed gap, but also looking at other disallowances too. But really trying to tighten up on the lag. So that's how we're thinking about on the ROE going forward. On the capital side, the question that you asked, we've got -- we look at $5 billion a year, little bit plus north of that going forward for the foreseeable future. We have continuing modernization work at the utilities. PECO 4 to 12 kV conversions for closer work. At ComEd, we've got the FEJA voltage optimization work, that's about $500 million right there. BGE has got big gas investment and PHI has got a lot of material condition work, manhole refurbishments, substation rebuild, that sort of thing. We've got $1.5 billion in our gas program over the next LRP period. We've got close to $1 billion in security programs across the utilities over the LRP. So there's a lot of work to do. We always, always bookend it with questions of affordability. And that's why we stay tight on O&M and we look at energy efficiency programs to give customers the ability to reduce usage and manage bills more tightly. So we're always looking at the affordability side of it, and our utilities sit pretty nicely. When you look at the national average on percentage of income or percentage of proportion of bill to income, we're pretty good. We're below the national average on 4 and we're right at the national average on the other 2 bills.

Got it. A quick clarification as a follow-up here on PJM. I appreciate your comments at the outset. Just timing-related, how you -- how do you see this going down with respect to, a, getting an approval out of FERC? But then, b, actually implementing a MOPR, just real quickly, if you can?

Julien, it's Kathleen. I can take that question. As you know, reply comments are going into FERC on November 6 with the expectation that the commission would address the paper hearing sometime in the January time frame. I think the commission is well aware that the market is looking for guidance, as Chris said, on what the rules are going to be going forward. And importantly, the states need to know what changes that they need to make to their Clean Energy Policies to accommodate the new rules coming out of FERC. So we will look to them to provide that guidance in the January time frame. As you know, they've delayed the auction until August to give states some time to react. Not just -- your question was specific to MOPR, but important for us is the ability of states to carve out the assets they wish to support and to procure them directly through a state-led procurement. That is going to be an important change that we are looking for FERC to make in its next order based on the record in front of them, they have an overwhelming amount of support from all quarters of the stakeholder community and the states to put that change into the tariff and to give states that option going forward to continue to support the clean generation that will help them achieve their carbon reduction goals.

So you don't see an issue with respect to getting clarity out of the states in time?

Obviously, the states have different structures that they'll need to examine. And some may be able to use existing structures, some may need to adopt new structures, including through legislation. So there will be a -- in the states where there is a need for legislation, a premium on moving quickly. Now that being said, I think it's also incumbent on FERC to take that into account and to make sure that states have adequate time before the rules change in the tariff.

Your next question comes from the line of Steve Fleishman from Wolfe Research.

I will actually just ask one question. The PJM from the standpoint of -- obviously, you have different stakeholders involved here, your states, customers, investors, et cetera. Just from an investor standpoint, and not everyone else, do you see the changes as proposed? Or as you would like to see them being kind of good for shareholders, neutral? How should we think of it just from an investor standpoint?

No, we definitely see this as a positive to create clarity and a more rewarding market going forward. We've lacked the clarity that we've isolated at times on programs. I think this is where we'll be able to create clarity, capital allotment will -- allocation will be much clearer on where we'll be putting capital, what units will be operating and what units won't be operating. So -- but we see this as definitely a benefit to the markets, which will be a benefit to the consumer, which will be a benefit to the shareholder.

Your next question comes from the line of Michael Weinstein from Crédit Suisse.

Two quick questions. The first one is do you think that the uncertainty surrounding FERC and surrounding new rules for capacity in the energy. If also the uncertainty is delaying newbuild or new start construction plans, if this is going to have an effect on tightening the market over the next year or 2? And second question I'll just ask it right now is Public Service Enterprise Group just announced that they are pulling out of the retail business. Is this a potential opportunity for consolidation?

First question, newbuilds are driven based off of market needs and economics. And unless we get the economics to support new asset entry, you are going to see what we see in the last couple of years, the decline. Then we have to see what comes out of the resiliency review on how the market values different sources of firm fixed fuel. So there'll be an evolution before we'll see a real opening or a market response to the demand need for assets or investments to be made to come in. It's basic economics right now. The market is barely supporting the assets that are operating today, so why would you invest into new assets when you are not going to get a recovery or return on your capital.

Michael, it's Jim McHugh, and I can speak to the retail question. I think with announcements of folks leaving or coming into the retail market, we're always on top of that and looking for opportunities to look for value and acquire books of business. In this case, I think PSEG has noted that they're going to supply their contracts as they roll off. We'll obviously be there to serve customers as the #1 C&I customer and the #2 resi customer in the country to look for the business as they roll off. I think for us, we have that scale. We've developed that scale over the years through acquisitions and organic growth, and our platform is very capable of acquiring new customers and retaining existing customers pretty easily. We've been having a lot of success also just finding new products and solutions for customers in both residential space and C&I space. So we'll keep taking advantage of those opportunities that are in front of us.

Your next question comes from the line of Jonathan Arnold from Deutsche Bank.

Just to pick up on the discussion around the states and legislation and potentially not leaving legislation. Kathleen, I heard your comments that there could be different answers depending on which state you're talking about. But is it fair to say where you sit today that you think that Illinois would have to legislate? And then I'm curious what you think about the state of play in New Jersey?

No, you're correct, Jonathan. I agree with your assessment in Illinois. There will be a need for legislation to adjust to the change in rules. And I think a positive for us is that we are seeing, not just here, but across the country, a growing sentiment among environmental groups and policymakers that the fastest and cheapest path to decarbonizing is a policy that uses all zero carbon resources. And so to the extent states want to act to increase their clean energy ambition, we would be expected -- we would expect that all assets, including ours, would be able to participate in that type of policy. And FERC allowing the states to go ahead and procure clean capacity directly allows them to do so in a way that's going to be able to keep cost down for customers and achieve the clean energy goals at the same time. So we would look to that kind of structure to the extent the FERC puts this carve-out in the tariff in Illinois. In New Jersey, given the way that the state law is written there and the authority at the BPU level to do a capacity procurement through the existing BGS structure, there would not need -- there would not be a need for a incremental legislation to allow that state's procurement effects to flow through the BGS. So yes, that's why I said I think the answer is different depending on which jurisdiction you're in.

Okay. Great. I just wanted to see if you provide that on the individual state. Could I just ask 1 quick follow-up on the cost savings? You obviously laid out how you expect them to be timed, the Q3 '18 cost reductions. Can you remind us how much of the $250 million you've announced last year was flowing into ExGen? And maybe what the sort of sequencing is there in terms of how those ramp up as we're trying to unravel the numbers on, I guess, Slide 15?

Yes. That is in the numbers. I think we're looking for the page now, Joe's got it.

So the $250 million last year, all of it is flowing into ExGen. The reductions were taken at ExGen across the platform of nuclear, constellation and our fossil businesses.

And the timing, Joe, is it kind of across the period into 2020? Or is most of it kind of already there in '19?

'19. 2019, you'll get to run rate year.

That concludes the question-and-answer session of today's webcast. I'll hand the call over back to Mr. Chris Crane, CEO of Exelon Corporation.

Thanks again, everybody, for joining. Thanks for the questions. Hopefully, we covered everything. Any other concerns, please get a hold of IR, myself. And we will be glad to continue to discuss them. But thanks to the team, all the 34,000-plus employees at Exelon for delivering another strong quarter, and talk to you soon. Thanks. Bye.

Thank you. And that concludes today's webcast. Thank you all for participating, you may now disconnect.