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. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question and answer session.
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 Q3 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'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 and comments made during this call. Please refer to today's AK 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 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 1st quartile operations. As we've stated previously, the federal courts of appeal in Illinois and New York strongly affirm the legality of the ZECs. And our focus on cost continues identifying an additional $200,000,000 of gross savings, which $150,000,000 of that will flow to the bottom line, bringing our 6 year total savings to more than $900,000,000 Combined, this performance demonstrates our growing value.
For the quarter, on a GAAP basis, we earned 0.7 $6 per share versus $0.85 per share last year. On a non GAAP operating basis, we earned $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 and 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 legislators. PECO and BG improved their J.
D. Power residential gas and electric scores over the last year with PECO receiving its highest ranking ever, placing 2nd in the residential electric survey. Our customer service metrics are strong. BG 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 KD, which is the outage frequency of safety and KD, which is outage duration, ComEd and PHI performed in top decile for KD.
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 XGen, our 3rd quarter was 39.7 terawatt hours of capacity factor of 93.6. During the 4th hottest summer in nearly 125 years, we performed at a 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. 1 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 for normal maintenance that would be required to have been 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're 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 $200,000,000 reduction to our run rate 2021 costs, of which $150,000,000 will reach the bottom line at ExGen. Joe is 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 7th and the 2nd court of appeals dismissed challenges to the ZEC programs in Illinois and New York respectively. In doing so, each cohort 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 plaintiffs sought rehearing 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 Q2 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 approve 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 0 carbon energy throughout the state led procurements outside of the PJM capacity model. 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 as 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 would provide states the flexibility to conduct a capacity procurement of resources they wish to support for the public policy reasons and would protect consumers for 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 market's 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 Utilities less 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 non decoupled jurisdictions, including PECO, Atlantic City Electric and Delmarva, Delaware.
Generation earned $0.33 per share in the Q3, which was slightly behind our plan. The Q3 was impacted by lower realized or cup prices versus the end of the second quarter, lower than expected generation performance with the unplanned outages at our ERCOT CCGT that just discussed as well as one at Mystic 89, in addition higher allocated transmission costs. These were partially offset by realized gains from our nuclear decommissioning truck. On Slide 9, we show our quarter over quarter walk. The $0.88 per share in the Q3 of this year was $0.03 per share higher than the Q3 of 2017.
Overall, the utility earnings were collectively up $0.07 per share compared with last year, driven primarily by higher rate base, new rates 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 Q4 of 2017 and higher planned nuclear outage days, partially offset by contribution from a full quarter of Illinois debt 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 utilities 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 ROE.
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 August respectively. Delmarva's earned ROEs include the benefits of interim rates that became that became effective during the Q1 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 improved 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 Q4 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 Utility 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 front. 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 $96,000,000 in annual electric distribution revenues offset by $71,000,000 in tax saving benefits for customers for a net $25,000,000 revenue increase.
We expect to receive an order in the 4th quarter. On August 9, the DC Commission approved the settlement that was reached in April based on a $24,100,000 revenue reduction after incorporating tax reform. Rate 22 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 $7,000,000 revenue decrease, including the benefits of tax reform for customers.
On September 7, Delmarva, Delaware entered into a settlement agreement in the pending gas distribution base rate case that provides for a revenue decrease of $3,500,000 including tax benefits for customers. A final order is expected in the Q4. We also have a number of rate cases still in progress. We expect an order for BG and E's pending gas rate case in January of 2019. As a reminder, the case includes a requested $60,700,000 increase to its gas revenues for infrastructure investments since 2015 and moving $21,700,000 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's standard formula rate case in the 4th quarter. And finally, on August 21st, the Atlantic City Electric filed a distribution based rate case with the New Jersey Board of Public Utilities seeking a revenue increase of $109,000,000 and we expect an order in the second half of twenty nineteen. 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 Exelon Utility Payments. More detail on the rate cases in their schedules can be found on Slides 24 through 30 in the appendix. Turning to Slide 13, we invested $1,400,000,000 of capital at the utilities during the Q3 and are at $3,900,000,000 year to date.
We remain confident in our ability to meet our $5,500,000,000 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 $920,000,000 smart meter installation program. ComEd installed more than 4,000,000 smart meters in just over 7 years, which is 3 years ahead of the original schedule and more than $20,000,000 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 spark 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 $100,000,000 in 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 $2,600,000,000 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 $50,000,000 project entailed equipment upgrades for reliability and 230, 138 and 69 kilobytes expansion for additional transmission capacity. Construction also included installation of 2.1 miles of transmission lines consisting of 59 new structures. The expansion improves reliability for our customers by replacing and up grading outdated equipment and by expanding regional transition 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 $50,000,000 in both 2019 2020, primarily as a result of higher power prices.
For 2018, open gross margin was up $100,000,000 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 hedges due to the higher pallet prices. For 2019 2020, open gross margin was up $250,000,000 $100,000,000 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 Illinois prices. Similar to 2018, the mark to market of our hedges is down both in 2019 2020 due to higher prices.
We also executed $50,000,000 of Power new business in both 2018 2019 and executed $50,000,000 of non power 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 concentrations. Turning to Slide 15. As Chris mentioned, we are announcing another round of O and 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 and technology. With this new program, our gross run rate savings in 2021 will be $200,000,000 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 BFC, which is part of the transformation efforts that Jack has been leading. The $200,000,000 of savings is a gross number with about half from ExGen and half from the BSC organization. And since BSC costs are shared roughly fifty-fifty between Exelon Generation and Exelon Utility, we would expect our utility customers to benefit from $50,000,000 of annual savings over time with the other $50,000,000 flowing through Exelon Generation's bottom line. When we include the $50,000,000 of incremental direct savings at ExGen, we expect $150,000,000 of savings to flow to 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 and M by over $900,000,000 It's due to the 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 ratings. And to that end, since our last earnings call, S and P has placed our ratings at ExGen and Exelon Corporate on credit watch 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 and P thresholds.
We are forecasting NexGen's leverage to be 2.5x debt to EBITDA at year end 2018, which is below our long term target of 3.0 times. On a recourse debt basis, we are at 2.0 times, 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 percent 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 on economic 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 it open to the call for questions. Thank
you. Your first question comes from the line of Greg Gordon from Evercore. Greg, your line is now open.
Thanks. Good morning, guys. A couple of 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 and
the power plant? In Texas, the interruption in Massachusetts, the higher FTR costs. 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 hit your numbers.
Let me start out with the Texas assets and I'll let Joe fill in on the rest of it. Those GE7 point two zero, these were the first serial numbers 12. We were aware as GE was that there was some difficulty with the 1st 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 been designed.
GE did give us very strong warranties on those assets and responded very well on the first failure on the one CT at Colorado Bend. We proactively shut the other 3 CTs down, replace them with a 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 4th unit and we feel confident in the design. GE has put us an inspection program together that will 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, 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 looked 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 4.94 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 one time 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 one time items that are driving the lower results.
Great, thanks. 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 costs declining from $4,625,000,000 to $4,175,000,000 in 2020 and a little bit more in 'twenty one, $450,000,000 savings, but the gross margins declined by $700,000,000 And so skeptical investors look at this and say, well, you guys are doing yeoman's job here, right sizing the cost structure, but earnings aren't getting better. I would argue that cost cuts are permanent and these backwardated 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 backwardated 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 quantity 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, 20 25
and 2024 due to lack of liquidity, we're seeing net retirements of new builds over the next year between 20 20 23 that would lead us to believe that backwardation won't realize in spot. We've seen spot prices at 9 Hub even in some of the lowest delivered fuel price here is clear north of $26 $27 So the backwardation to your point is it 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 to 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 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 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 2020. 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 views 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.
Thank you, guys.
Thanks, Greg.
Thank you, Greg. Your next question comes from the line of Julien Dumoulin Smith from Bank of America. Julien, your line is now open.
[SPEAKER JULIEN DUMOULIN SMITH:]
Hey, good morning, everyone.
Good morning.
How are you doing? [SPEAKER JULIEN DUMOULIN SMITH:] Good.
Excellent. So I wanted to follow a little bit 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 $50,000,000 ish accrue to the utilities. How does that play out in terms again increasing your ROE, right?
I gather the bulk of that would be moving back to customers over time, although clearly you're under earning relative to authorized level still. And then in tandem with that question, if you could elaborate a little bit more on the sort of initial utility CapEx planning, certainly there's 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. Responses
to your questions.
As we think responses to your questions. As we think about moving forward, obviously, we're going to blend $50,000,000 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 and 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 looking at how we were filing annually, how do we reduce lag. One of the ways as 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, the Disc rider in Delaware and the IIP rider in New Jersey that we're looking to place about $358,000,000 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 D. C. We've been invited to make that filing and we'll be doing that shortly. So just got an alt reg provision at PECO authority for the commission to look at that.
So that's something we'll be looking at going forward. 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 allow GAAP, but also 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 $5,000,000,000 a year, a little bit plus north of that going forward for the foreseeable future.
We have continuing modernization work at the utilities. PICO, 4 kilobytes conversions, recloser work At ComEd, we've got the feature voltage optimization work that's about $500,000,000 right there. BG and E has got big gas investment and PHI has got a lot of material condition work, manhole refurbishments, substation rebuilds, that sort of thing. We've got $1,500,000,000 in our gas program over the next LRP period. We've got close to $1,000,000,000 in security programs across the utilities over the LRP.
So there's a lot of work to do. We always, always bookended with questions of affordability and that's why we stay tight on O and M and we look at energy efficiency programs to give customers the ability to reduce usage and manage builds more tightly. So we're always looking at the affordability side of it and our utilities fit 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 builds.
Got it. A quick clarification as a follow-up here on PJM. I appreciate your comments at the outset. Just timing related, how do you see this going down with respect to, A, getting an approval out of FERC, but then, B, actually implementing a moper just real quickly, if you can?
Hi, Julian. 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 timeframe. 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 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 timeframe. 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're looking for FERC to make in the 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.
Great. Thank
you. Thank you, Julian. Your next question comes from the line of Steve Fleishman from Wolfe Research. Steve, your line is now open.
Thank you. I will actually just ask one question. The PGM from the standpoint of not obviously, you have different stakeholders involved here, your states, customers, investors, etcetera. 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. We've vacillated 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 what we're where we'll be putting capital, what units we'll be operating and what units we'll 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.
Okay. Thank you.
Thank you, Steve. Your next question comes from the line of Michael Weinstein from Credit
Suisse. Hi, guys. Thanks for taking my questions. Two quick questions. The first one is, do you think that the uncertainty surrounding FERC and surrounding new rules for capacity and energy, it seems all this uncertainty is delaying new build or new start construction plans, if this is going to have an effect on tightening the market going over the next year or 2?
And my second question, I'll just ask it right now. Public Service Enterprise Group just announced that they're pulling out of the retail business. Is this a potential opportunity for Constellation?
First question, new builds are driven based off of market needs and economics. And unless we get the economics to support new asset entry, we're going to see what we've seen 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?
Hi, Michael, it's Jim McHugh. 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 number one C and I customer and the number 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 and I space. So we'll keep taking advantage of those opportunities that are in front of us.
Great. Thank you very much.
Thank you, Michael. Your next question comes from the line of Jonathan Arnold from Deutsche Bank.
Just to pick up on the discussion around states and legislation and potentially not leading 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 the way you sit today that you think 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 0 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 costs 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 that 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 PPU level to do a capacity procurement through the existing BGS structure, there would not need there would not a need for incremental legislation to allow that state's procurement of Zacks to flow through the BGS. So that's why I said I think the answer is different depending on which jurisdiction you're in.
Okay, great. I was just willing to see if you provide that on the individual states. So thank you. Could I just ask one quick follow-up on the cost savings? You obviously laid out how you expect them to be timed, the Q3 'eighteen cost reductions.
Can you remind us how much of the $250,000,000 you 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 has got it.
The $250,000,000 last year, all of it is flowing into ExGen. The reductions were taken at ExGen across the platform nuclear constellation in our fiber.
And the timing, Joe, is it kind of across the period into 2020? Or is most of it kind of already there in
2019? 2019, you'll get the run rate here.
Okay. All right. Thanks for that.
Thank you, Jonathan. 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 or myself and we'd 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.