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. If you would like to ask questions during this time, please press star, then the number 1 on your telephone keypad. If you would like to withdraw your question, press the pound key. At this time, I would like to turn the show over to Mr. Daniel 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'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 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 scheduled 45 minutes for today's call. I'll now turn the call over to Chris Crane, Exelon's CEO.
Thanks, Dan. Good morning, everyone, and thank you for joining us. Flipping to slide five, 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 in largely first quartile operations. As we've stated previously, the federal courts of appeal in Illinois and New York strongly affirmed the legality of the ZECs. 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 six-year total savings to more than $900 million. Combined, this performance demonstrates our growing value. For the quarter, on a GAAP basis, we earned $0.66 per share versus $0.85 per share last year.
On a non-GAAP operating basis, we earned $0.88 per share, again, above the midpoint of our $0.80-$0.90 range guidance that was provided. Turning to slide seven, 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 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. PHI is in the top decile for its service levels.
Each of our utilities achieved top quartile reliability performance in or outage duration in CAIDI, which is outage frequency of SAIFI, 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 a 96.7% capacity factor and avoided 33 metric tons of carbon. Our gas and hydro fleet performed well, below plan, with economic dispatch match at 95.8%. This lower performance was primarily the result 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. 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 would be required to have been shut down for next spring. From a financial perspective, all the repairs were covered under a warranty. The market's impact on 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. 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 seven.
As you know, we've had a 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 Exelon 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 costs, 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 plaintiffs sought rehearing in Illinois' case, which the court denied last month. The rulings were consistent with our expectations. We are 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 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 zero 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, in 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 6th, 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. With that, now I'll turn it over to Joe to walk through the numbers.
Thank you, Chris. Good morning, everyone. Turning to slide eight. 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-$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 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 that Chris discussed, as well as one at Mystic 8 and 9. In addition, higher allocated transmission costs.
These were partially offset by realized gains from our nuclear decommissioning trust. On slide nine, we show our quarter-over-quarter walk. The $0.88 per share in the third quarter of 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 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 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-$3.20 per share to $3.05-$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 D.C. settlement that took effect in June and August respectively. Delmarva's earned ROEs include the benefits of interim rates that became effective during the first quarter, with final rates for Delmarva Electric effective September 1st, 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 ROEs 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 utility, 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%-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 utilities.
Turning to slide 12, we remain busy on the regulatory front. On October 18th, 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 9th, the D.C. 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 13th. A final order was received on August 21st for the settlement we reached in June on the Delmarva Delaware electric distribution case. The case will provide a $7 million revenue decrease, including the benefits of tax reform for customers.
On September 7th, Delmarva Power 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 a 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 Rider into base rates. We expect to receive an order from the Illinois Commerce Commission on ComEd's standard formula rate case in the fourth quarter.
Finally, on August 21st, Atlantic City Electric filed a 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 Exelon utility panels. More detail on the rate cases and their schedules can be found on slides 24 through 30 in the appendix. Turning to slide 13, we invested $1.4 billion in 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 two 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 seven years, which is three 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 seven-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 in annual 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 Pennsauken, New Jersey. This $50 million project entailed 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 2020, primarily as a result of higher power prices. For 2018, open gross margin was up $100 million, primarily due to higher NYISO Hub, PJM Western Hub, and NYISO 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 power prices. For 2019 and 2020, open gross margin was up $250 million and $100 million respectively, due to higher PJM Western Hub prices and stronger ERCOT spark spreads. In 2019, open gross margin was also up on higher NYISO Hub and NYISO Zone A prices. Similar to 2018, the mark-to-market of our hedges is down both in 2019 and 2020 due to higher prices.
We also executed $50 million of power new business in both 2018 and 2019, and executed $50 million 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%-12% behind ratable in 2019, and 8%-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 and technology. With this new program, our gross run rate savings in 2021 will be $200 million, which we will ramp up over the next two years.
These incremental savings will come from our Exelon Generation business, primarily through even greater efficiencies in our nuclear operations, and at the Exelon Business Services Company, or BSC, which is part of the transformation efforts that Jack has been leading. The $200 million of savings is a gross number with about half from ExGen and half from the BSC organization. Since BSC costs are shared roughly 50/50 between Exelon Generation and Exelon Utilities, we would expect our utility customers to benefit from $50 million of annual savings over time. With the other $50 million flowing through Exelon Generation's bottom line. When we include the $50 million of incremental direct savings at ExGen, we expect $150 million 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&M by over $900 million. 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 investor-grade credit ratings. To that end, since our last earnings call, S&P has placed our ratings at ExGen and Exelon Corporation 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&P thresholds.
We are forecasting ExGen leverage to be 2.5 times 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 3.0 times debt to EBITDA level. Look for us to focus on debt reduction at both the HoldCo and GenCo. I will now turn the call back to Chris. Thank you.
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%-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 four 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 open the call up for questions. Thank you.
Ladies and gentlemen, in order to ask questions, press star, then the number one on your telephone keypad. Again, it's star, then the number one on your telephone keypad. We'll pause for just a moment to compile the Q&A roster. Your first question comes from the line of Greg Gordon from Evercore. Greg, your line's now open.
Thanks. Good morning, guys. Couple questions. First on the quarter. Everything seems really good on the utility side, and the underlying operations at the GenCo look decent, too. 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 7HA.02, these were the serial numbers 1 and 2. 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 three CTs down, replaced 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 fourth unit, and we feel confident in the design.
GE has put an inspection program together that will be bore scoping after so many hours of operation. They've responded well. There's solid engineering confirmed by independent assessments, 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.
Yeah. 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 [inaudible] at FERC, and that had a negative impact. 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. I think when you look at it from our lens, you see these one-time items that are driving the lower results.
Great. Thanks. On 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 billion to $4.175 billion in 2020 and a little bit more in 2021, $450 million savings, the gross margins declined by $700 million. Skeptical investors look at this and say, "Well, you guys are doing a yeoman's job here rightsizing 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. 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. We're managing the book in that manner, maintaining as much margin open and using cross-commodity hedges to be able to manage that. We will constantly look at driving efficiencies. You can't have a company operate with any aspect or entity within the company being inefficient. 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?
Yeah. I think the only thing I would add about the backwardation of the curve is, with the next couple of years, say in 2025 and 2024, due to lack of liquidity, we're seeing net retirements of new builds over the next few years between 2020 and 2023. That would lead us to believe that backwardation won't realize in spot. We've seen spot prices at NiHub even in some of the lowest delivered fuel price years clear north of $26, $27. The backwardation to your point seems temporal, Greg.
Okay. 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 hedge less and take more of your power into the spot and therefore try to get those better prices?
Yeah, Greg, it's Joe. The short answer is, with that balance sheet capacity, we can be more aggressive. As I mentioned in my remarks, when you look at how far behind we are with 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 2020. 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. 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. 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's now open.
Hey, good morning, everyone.
Good morning. How you doing?
Good. Excellent. I wanted to follow a little bit up on the utility activities. Obviously, good progress at PHI, yet again. I wanted to elaborate a little bit further on this. Obviously, the cost reductions of, say, $50 million-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 levels still. In tandem with that question, if you could elaborate a little bit more on the sort of initial utility CapEx planning. Certainly, there's 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.
I'll let Anne take that.
Sure. Good morning, Julien. 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. 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 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. 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, DSIC 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. We're looking at a multi-year rate plan in D.C. We've been invited to make that filing, and we'll be doing that shortly. Just got an alt rate provision at PECO, authority for the commission to look at that. 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 lag is our biggest sort of earn to allow gap, also looking at other disallowances, too. Really trying to tighten up on the lag.
That's how we're thinking about on the ROE going forward. On the capital side, the question that you asked. We look at $5 billion a year, a little bit plus north of that going forward for the foreseeable future. We have continuing modernization work at the utilities. PECO, 4-12 kV conversions, recloser work at ComEd.
We've got the PECO voltage optimization work. That's about $500 million right there. BGE's got big gas investment, and PHI's got a lot of material condition work, manhole refurbishment, substation rebuilds, that sort of thing. We've got a billion and a half in our gas programs over the next LRP period. We've got close to $1 billion in security programs across the utilities over the LRP. There's a lot of work to do. We always bookend it with questions of affordability, and that's why we stay tight on O&M. We look at energy efficiency programs to give customers the ability to reduce usage and manage bills more tightly. We're always looking at the affordability side of it. 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 four, we're right at the national average on the other two bills.
Got 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 MOPR? 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. I think the commission's well aware that the market is looking for guidance, as Chris said, on what the rules are going to be going forward. 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. 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.
Your question was specific to MOPR, 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.
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, some may be able to use existing structures. Some may need to adopt new structures, including through legislation. There will be, in the states where there is a need for legislation, a premium on moving quickly. 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, Julien. Your next question comes from the line of Steve Fleishman from Wolfe Research. Steve, your line's now open.
Thank you. I will actually just ask one question. 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?
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 allocation will be much clearer on where we'll be putting capital, what units we'll be operating, and what units won't be operating. 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. Michael, your line's now open.
Hi, guys. Thanks for taking my questions. Hey, two quick questions. The first one is, do you think that the uncertainty surrounding FERC and surrounding new rules for capacity and energy, do you think 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 up the next year or two?
I think.
The 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. 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.
We have to see what comes out of the resiliency review on how the market values different sources of firm fixed fuel. 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. 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 1 C&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&I space. 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. Jonathan, your line's now open.
Good morning, guys.
Hi, John.
Just 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. Is it fair to say, from where you sit today, that you think Illinois would have to legislate? 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. 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. To the extent states want to act to increase their clean energy ambition, we would expect that all assets, including ours, would be able to participate in that type of policy. 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.
We would look to that kind of structure to the extent 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 be a need for incremental legislation to allow that state's procurement of ZECs to flow through the BGS. That's why I said I think the answer is different depending on which jurisdiction you're in.
Okay, great. I was just wanting to see if you'd 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 2018 cost reductions. Can you remind us how much of the $250 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 it's slide 15?
Yeah, that is in the numbers. I think we're looking for the page now. Joe's got it.
The $250 last year, all of it is flowing into ExGen. The reductions were taken at ExGen across the platform of nuclear Constellation in our portfolio.
The timing, Joe? Is it kind of across the period into 2020, or is most of it kind of already there in nine-
2019. 2019, you'll get to run rate year.
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 ahold of IR or myself, and we'd be glad to continue to discuss them. Thanks to the team, all the 34,000-plus employees at Exelon for delivering another strong quarter. Talk to you soon. Thanks. Bye.
Thank you. That concludes today's webcast. Thank you all for participating. You may now disconnect.