Exelon Corporation (NYSE:EXC) Q3 2018 Earnings Conference Call November 1, 2018 10:00 AM ET
Daniel Eggers - SVP, Corporate Finance
Chris Crane - President and CEO
Joe Nigro - CFO
Jim McHugh - CEO, Constellation and EVP
Anne Pramaggiore - SVP and CEO of Exelon Utilities
Kathleen Barrón - SVP, Federal Regulatory Affairs and Wholesale Market Policy
Greg Gordon - Evercore ISI
Julien Dumoulin-Smith - Bank of America Merrill Lynch
Steve Fleishman - Wolfe Research
Michael Weinstein - Credit Suisse
Jonathan Arnold - Deutsche Bank
Good morning, ladies and gentlemen. Welcome to 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 place on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. [Operator Instructions]
At this time, I'd like 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'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 on Exelon's Web site. The earnings release and other matters which we'll 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, forecast 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. 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 and largely first quartile operations. As we stated previously, the Federal Courts of Appeal in Illinois and New York strongly affirm the legality of the ZEC.
And our focus on cost continues identifying an additional $200 million in gross savings, which are $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 are at $0.76 per share versus $0.85 per share last year. On a non-GAAP operating basis, we are at $0.80 per share, and again above the midpoint of our $0.80 to $0.90 range guidance that was provided.
Turning to slide six, our utilities continue to perform at higher 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 JV 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 is 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 SAIFI, or outage duration in CAIDI, which is -- the outage frequency is SAIFI, and CAIDI which is outage duration. ComEd and PHI performed in top decile for CAIDI. SAIFI 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, in our third quarter was -- excuse me, 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 result of our CCG's account Colorado Bend and Wolf Hollow being offline because of some turbine blades 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 performing normal maintenance that would have been required to have that shut down for next spring.
From a financial perspective, all repairs were covered under a warranty, and the markets impact from the plants being down are 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 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 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 from that quarter and start with the ZEC programs. As I said both the Seventh and the Second Court of Appeals dismiss challenges to the ZEC programs in Illinois and in New York respectively. In doing so each court found that the states have a 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 are rehearing an Illinois case which the court denied last month. The rulings were consistent with our expectations we're happy with the resigning information on these importantly stay clean energy policies. In New Jersey, the process for implementation of the ZEC program that remains on track to take effect early in the second quarter of 2019.
The Board of Public Utilities has finished his hearings on implementation of the ZEC program and the utilities have well tariffs to recover the ZEC related charges. We expect BPU to approve the changes later this month On the federal policy front, we think that FERC's June order took an important step followed by empowering the states to continue prioritizing zero carbon energy throughout the state-led procurements outside of the PJM capacity module. 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 is putting our generation fleet in a better position financially than the current market construct. We are pleased to have followers part of a coalition to support 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 with flexibility to conduct a capacity procurement of resources they list to support for the public policy reasons, and would protect consumers for paying thrice for capacity resources fits straight to a balance and the FERC is looking for to ensure states can meet their environmental goals, while protecting the competitive market. We plagued 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 vast 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 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 to $0.90 per share.
Exelon's 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 00:10:17 non-decoupled jurisdiction 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 lot of realized lower realized ERCOT prices versus the end of the second quarter, lower-than-expected generation performance with the unplanned outages that ERCOT CCGT as just discussed as well as one at [indiscernible] in addition to higher allocated transition costs. These were partially offset by realized gains from our nuclear decommissioning trust fund.
On slide nine, 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 rates associated with completely 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 margins 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 utilities and generation businesses that are pushing us up into the upper half of our range, particularly as we have overcome unexpected headwind including the challenging winter storms.
Moving to slide 11, improved operation 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 with DC settlement that took effect in June and August respectively. Delmarva's earned ROE include the benefits of interim rates came 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 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 utilities, our earned ROEs remained over 10% were 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 utilities.
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 million in annual electric distribution revenues offset by $71 million in tax saving benefits for customers for 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 under $24.1 million revenue deduction after incorporating tax reform May 20 backed on August 30. A final order which received on August 21 to the settlement we reached in June on the Delaware, Delmarva electric distribution case. The case will provided $7 million revenue decrease including the benefits of capture firm for customers.
On September 7, Delmarva Delaware entered into a settlement agreement in pending gas distribution base rate case that provides for revenue decrease of $3.5 million including tax benefits for customers. A final order is expected in the fourth quarter. We also have number of rate cases still in progress. We expect an order for BG&E spending gas rate case in January of 2019.
As a reminder, the case include the request that $60.7 million increase to its gas revenues for infrastructure investments since 2015 and moving $21.7 million in revenue currently being recovered with the STRIDE surcharge engine into base rate. We expect to receive an order from the Illinois Commerce Commission on standard formula rate case in the fourth quarter. And finally, on August 21st Atlantic City Electric filed a distribution base rate case with the New Jersey Board of Public Utilities seeking of 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 for support of regulatory backdrop that in turn we helping the lift earned ROE source their allocated levels across the Exelon utility levels. More detail on the rate cases that are scheduled to be found on slide 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 around $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 and utility investors. The first is the early completion of ComEd to $920 million Smart Meter Installation program. ComRD 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 in to the context, our ComED 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 improved it service offerings.
In addition, we tried over $100 million in annual operational savings, primarily from increased efficiencies in the field operations, such as meter reading and avoided truck rolls. The 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 Electrics Churchtown Substation Expansion project in Pennsville, New Jersey. This $50 million projects entailed equipment upgrades for reliability and 230 kV, 138 kV and 69 kV expansion for additional transmission capacity. Construction also included installation up 2.1 miles of transmission line consisting of 59 new structures. The expansion improves reliability for our customers by replacing and upgrading our stated 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 our higher power. For 2018 open gross margin was up $100 million primarily due to higher NI Hub, PJM West Hub and New York Zone A prices and offset by weakening ERCOT spark spread.
Total gross margin is offset by lower mark-to-market of our hedging due to the higher price spikes. For 2019 and 2020, open gross margin was up $250 million and $100 million respectively with a higher PJM West Hub prices and stronger ERCOT spark spreads. In 2019, open gross margin was also up on higher NI Hub and New York Zone A prices. Similar to2018, the mark-to-market of our hedging is gambled 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% 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 OEM cost reductions as part of our continual efforts to evaluate our work practices, looking for ways to being more efficient teams and better in portraying evasion and technology.
With this new program, our gross run rate savings in 2021 will be $209 which we will ramp up over the next two years. These incremental savings will come from our Exelon Generation business primarily through even great efficiencies in our nuclear operations and at the Business Services Company or BSC, which is part of the transformation efforts that Jack has been leading. The $200 million of savings with the gross number with about half from ExGen and half from the BSC [indiscernible] 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 a $150 million of savings to flow through our bottom line is 2021, relative to our previous guidance, which we show on the lower left chart.
Exelon continues to embrace the culture of cost discipline and operational excellence. These costs updates our consistent with these cultural values. If we look at all the cost savings amounts since 2015, we have now reduced the O&M by over $900 million. It's due to hard work of all of our employees, we [indiscernible] every day to run the company more efficiently, while I'm hearing 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&P has placed our ratings for ExGen index one corporate on credit watch positive, recognizing the improvements in overall strength of our balance sheet.
Turning to the metrics, our consolidating corporate credit metrics remain above our target ranges and meaningfully above S&P thresholds. We are forecasting ExGen's 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 for the 3.0 times 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. Thank you.
Thanks, Joe. Turning to slide 17, as we have shown you, we have 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 and of course 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 starting at 6% to 8% EPS growth through 2021. We continue to use free cash flow from the GenCo up on the incremental equity needs at the utilities, pay down debt over the next four years at the GenCo and HoldCo and funds 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 in air pollution, while benefiting from regional markets. We will close uneconomic and sell assets were it does not make sense to accelerate our debt reduction plans, and maximize value to generation to the load matching strategies 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 up for questions. Thank you.
[Operator Instructions] Your first question comes from the line of Greg Gordon from Evercore. Greg, your line is now open.
Thanks. Good morning guys, 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 in the power…
Yes, and Texas, the interruption in Massachusetts, the higher FDR 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 get your numbers?
Let me start out with the Texas assets. So, I'll let Joe fill in on the rest of it. Those GE 7HA.200, these were the first serial numbers one and two. 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 one CT at Colorado Bend. We proactively shut the other three CTs down, replace them with the new design, had them back up and running, and as I said, we expect -- we're in the roll out phase now and the start-up phase of the fourth unit, and we feel confident in the design. GE has put us in inspection program together, that will be borescoping after so many hours of operation. They've responded well, the 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 FDRs 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 looked at how 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 orders for 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 one-time occurrences similarly on the transmission side. The favorability was driven on the realized liquid decommissioning trust gains. So I think when you look at it from our lens, you see these one-time items that are driving the overall results.
Great. Thanks. And one follow-up on Exgen and then one more if you let me, looking at the cost cuts, it's really quite an impressive, incremental change, you've got the costs declining from $4.65 billion to $4.175 billion in 2020 and a little bit more in 2021, $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, right-sizing the cost structure, but earnings aren't getting better." I would argue that cost cuts are permanent than -- and these back-wardated [ph] 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 talked about this before that we've lacked liquidity in the out years. It's a softer market. Our fundamentals still tell us that this back-wardated 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. We will constantly look at driving efficiencies. You can't have a company and operate with any aspect or entity within the company being inefficient. So, driving efficiencies has multiple benefits, but one of them is a 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 one I would add about the backwardation of the curve is, with the next couple of years showing 25 and 24 deal like in liquidity we're seeing net retirements of new builds over the next year between 20 and 23 that would lead us to believe that backwardation won't really subside. We've seen stock prices and I have even in some of the lowest delivered fuel price years cleared north of $26, $27. So you know the backwardation to your point is seems temporal great.
Okay. And then final question is you know 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 therefore try to get those better prices?
Greg, it's Joe. The short answer is with that balance sheet capacity we can't be more aggressive. And as I mentioned in my remarks when you look at how far behind we are a ratable plan and when you overlay the fact that we're using gas as a proxy for power we are carrying a very long opening power position in 2019 and 2020, and when we're able to do that think 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.
Thank you, guys.
Thank you, Greg. Your next question comes from the line of Julien Dumoulin-Smith from Bank of America. Julien, your line is now open.
Hey, good morning, everyone.
Good morning. How are you doing?
Good, excellent. So I wanted to follow a little bit up on the utility activities, obviously good progress of THI, and again but I wanted to elaborate a little bit further on this. Obviously the cost reductions of say $50ish million accrued in 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 under earning relative to authorized level still. And then in tandem with that question if you could elaborate a little more on the sort of initial utility CapEx planning, certainly there is 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. Good morning, Julien. Yes, so a couple of responses to your questions. As we think about moving forward, obviously we're going to blend $50 million into the LRP over time, and it's not sitting with 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 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, you know the first thing we're doing is to looking at how -- we're filing annually how do we reduce lag? What are the ways is we file it annually, we've got to stay our 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, disk rider in Delaware and the IIT 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 to close that lag gap, and we're looking at multiyear rate plan in DC. We've been invited to make that filing, and we'll be doing that shortly. So we've 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, we're looking at lags are biggest sort of currency allowed GAAP that also looking at other disallowances too, but really trying to take enough 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, a little bit plus north of that going forward for the foreseeable future.
We have continuing modernization work at the utilities. PECO afford 12-kV conversions were closer work, at ComEd, we've got the 00:36:31 voltage optimization work that's about $500 million right there. BG&E's got big DaaS investment, and PHI's got a lot of material condition work 00:36:41 refurbishments, substation rebuilds, and that sort of things. We've got $1.5 billion in our gas program over the next LRP period. We've got close to a $1 billion in security programs across the utilities over the LRP. So there's a lot of work to do. We always, always book-ended 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 those 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 a percentage of income or percentage of proportion of build to income. We're pretty good, we're below the national average on four and we're right at the national average on the other two builds.
Got it. A quick clarification as a follow up here in PJM, I know I appreciate your comments at the outside. 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 the MOPR just real quickly if you can?
Hi, Julien, it's Kathleen. I can take that question. As you know, the five 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 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, we have to leave the auction until August to give states sometime to react, not just your question was specific to MOPR, but important for us is the ability of states to carve out the [indiscernible] they wish to support and to procure them directly to 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 as overwhelming amount of support from all supporters of the stakeholder community and the states. To put that change into the tariff and to give states options 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 sometime?
Obviously the states have different structures that will need to examine and obviously the states have different structures, that they'll need to examine and some may be able to use existing structure, 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 our effort to take that into account and to make sure that they 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 is now open.
Thank you. I will actually just ask one question. The PGM from a standpoint of not obviously you have different stakeholders in relative 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, we've [indiscernible] the times on programs, I think this is where we'll be able to create clarity, capital allotment will allocation will be much clear on what we're - 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.
Okay. Thank you.
Thank you, Steve. Your next question comes from the line of Michael Weinstein from Credit Suisse. Michael, your line is 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 taking also some uncertainty is delaying a 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 two. And my second question, I'll just ask it right now is a 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 in economics and unless we get the economics to support new asset entry, you will get 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 from fixed view. So, there will 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? Just a second you can…
-- into new assets when you are not going to get a recovery or return on your capital.
Hi, Michael, it's Jim here. I can speak to that question. I think you know with the 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 you know if you think it's noted, that they're going to supply their contracts as they roll off. We'll obviously there to serve customers as the number one C&I customer and the number two resi customer in the country, so a lot for the business and they will alone. I think for us, we have that scale, we've developed that scale over the years through acquisitions and in 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 the residential space and C&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 as Jonathan Arnold from Deutsche Bank. Jonathan, your line is now open.
Good morning, guys.
Just to pick up on the discussion around the state legislation and potentially not leading legislation, and Kathleen I heard your comments that you know there could be different answers depending on which state you're talking about. But is it fair to say, the way you said 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?
You're correct, Jonathan. I agree with your assessment in Illinois, there will be a need for legislation legislation to adjust those changes in rules. And I think a positive for us is that we are seeing not just here but across the country our growing sentiment among environmental groups and policymakers that the fastest and cheapest path to de-carbonizing 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 as FERC for allowing the states to go ahead and procure a clean capacity directly allows them to do so in a way that's going to be able to keep costs down per customers and achieve clean energy goals at the same time.
So we would look to that kind of structure to the extent you know the FERC puts this car down in the tariff you know in Illinois. And here in New Jersey given the way that the state law is written there and the authority at that DPU level to do the 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 of that 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 waiting 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've obviously laid out how you expect that to be timed the Q3 2018 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 I guess is slide 15.
Yes, that is in a 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 nuclear constellation in our…
And the timing, Joe, is it kind of across the period until 2020 or most of it going to already there in…
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 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.
Thank you. And that concludes today's webcast. Thank you all for participating. You may now disconnect.