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Exelon Corp  (NYSE:EXC)
Q3 2018 Earnings Conference Call
Nov. 01, 2018, 10:00 a.m. ET

Contents:

  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:

Operator

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. (Operator Instructions)

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

Daniel Eggers -- Senior Vice President, Corporate Finance

Thank you, Jerome. Good morning everyone and thank you for joining our third quarter 2018 earnings conference call. With me in the call today are Chris Crane, Exelon's President and Chief Executive Officer; and Joe Nigro, Exelon's Chief Financial Officer. They are joined by other members of Exelon's senior management team who will be available to answer your questions following our prepared remarks. We issued our earnings release this morning along with the presentation both of which can be found in the Investor Relations section of Exelon's website.

The earnings release and other matters which we discuss during today's call contain forward-looking statements and estimates that are subject to various risks and uncertainties. Actual results could differ from our forward-looking statements based on factors and assumptions discussed in today's material and comments made during this call. Please refer to today's 8-K and Exelon's other SEC filings for discussions of risk factors and factors that may cause results to differ from management's projections, forecasts and expectations.

Today's presentation also references to adjusted operating earnings and other non-GAAP measures. Please refer to the information contained in the appendix of our presentation and our earnings release for reconciliations between the non-GAAP measures and the nearest equivalent GAAP measures. We've scheduled 45 minutes for today's call.

I'll now turn the call over to Chris Crane, Exelon's CEO.

Christopher Crane -- President and Chief Executive Officer

Thanks, Dan, and good morning everyone and thank you for joining us. Flipping to Slide 5, we delivered another strong quarter with earnings again at the upper end of our range which allows us to raise the lower end of our full year guidance. The utilities performed well with strong earned ROEs and largely first quartile operations. As we've stated previously, the Federal Courts of Appeal in Illinois and New York strongly affirmed the legality of the ZEC. And our focus on cost continues identifying an additional $200 million of gross savings which a $150 million of that will flow to the bottom line bringing our 6-year total savings to more than $900 million. Combined, this performance demonstrates our growing value. For the quarter, on a GAAP basis, we earned $0.76 per share versus $0.85 per share last year. On a non-GAAP operating basis, we 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 BGE improved their J.D. Power residential gas and electric scores over the last year with PECO receiving its highest ranking ever, placing second in the residential electric survey. Our customer service metrics are strong. BGE and ComEd are in the top decile for customer satisfaction and PHI is in top decile for its service levels.

Each of our utilities achieved top quartile reliability performance in 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, it remains that. Our metrics have continued to -- and improved since the beginning of the year. At ExGen our third quarter was 90 -- excuse me 39.7 terawatt hours of capacity factor at 93.6%. During the fourth hottest summer in nearly 125 years, we performed 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, one of the Colorado Bend units returned to service in October and the other will be back into service shortly. It's in the process of restart as we speak. We took advantage of the outage time for normal maintenance that will be required to have then shut down for next spring.

From a financial (Technical Difficulty) repairs we're covering under our warranty and the markets impact from the plants being down were well within our full range outage contingency plan. The plans 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 a Business Services company. As part of that effort with additional savings from our nuclear fleet, we're announcing a $200 million reduction to our run rate -- 2021 cost of which $150 million 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 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 plan to start rehearing in Illinois in this case which the court denied last month, the rulings were consistent with our expectations and we're happy with the resounding information 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 to ZEC program and the utilities have filed 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 forward by empowering the states to continue prioritizing zero carbon energy throughout the state-led procurements outside of the PJM capacity module. The number of proposals were filed in response to the order including from a diverse coalition of which Exelon is a member and PJM. We see all of the major proposals is putting our generation fleet in a better position financially than the current market construct. We are pleased to have filed this part of a coalition and 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 rate payer 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 the capacity procurement of resources they wish to support for the public policy reasons and would protect consumers for paying twice the 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 of the comments are due November 6 and it will be important for FERC to issue an order early next year to give the markets guidance going forward. As you know, we are still waiting for orders from FERC on the fast start and resiliency examination.

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

Joseph Nigro -- Chief Financial Officer

Thank you, Chris, and good morning everyone. Turning to Slide 8, we had another strong quarter financially, delivering adjusted non-GAAP operating earnings of $0.88 per share which is at the upper end of our guidance range of $0.80 to $0.90 per share. Exelon's utilities less holding company expenses earned a combined $0.55 per share. Compared to our plans, 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.

This third quarter was impacted by lower realized ERCOT prices versus the end of the second quarter, lower-than-expected generation performance with the unplanned outages at our ERCOT CCGTs as just discussed as well as one at (inaudible). In addition, higher allocated transmission costs. These were partially offset by realized gains from our Nuclear Decommissioning Trust.

On Slide 9, 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 (ph) 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 to $3.20 per share to $3.05 to $3.20 per share. We are pleased with the strong operational results at both the utility and generation businesses that are pushing us up into the upper half of our range particularly as we have overcome unexpected headwinds including the challenging winter storms.

Moving to Slide 11. Improved operations at PHI and positive rate case outcomes are driving better earned ROEs. Pepco's higher ROE reflects last fall's distribution rate cases as well as the recent Pepco Maryland and DC settlement that took effect in June and August respectively. Delmarva's earned ROEs includes the benefits of internal rate which 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 utility, our earned ROEs remained over 10% were 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 underlines 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 Judge is 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 savings benefits for customers for a net $25 million revenue increase. We expect to receive an order in the fourth quarter. On August 9, the DC Commission approved the settlement that was reached in April based on a $24.1 million revenue reduction after incorporating tax reform. Rate 22 effect on August 13. A final order which received on August 21 for the settlement, we reached in June on the Delaware Delmarva electric distribution case. The case will provide a $7 million revenue decrease including the benefit to tax reform 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 a number of rate cases still in progress. We expect an order for BGE's pending gas rate case in January of 2019. As a reminder, the case includes the requested $60.7 million increase to its gas revenues for infrastructure investments since 2015 and moving $21.7 million in revenue currently being recovered via the STRIDE surcharge in the base rate. We expect to receive an order from the Illinois Commerce Commission on ComEd's standard formula rate case in the fourth quarter.

And finally, on August 21, the 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 its support of regulatory backdrop. That in turn is helping to lift earned ROEs toward their allocated levels across the acquired new settlement payments. 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 of capital at the utilities during the third quarter and are at $3.9 billion year-to-date. We remain confident in our ability to meet our $5.5 billion capital budget for 2018. This quarter, I would like to feature 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 7 years which is 3 years ahead of the original schedule and more than $20 million under budget. To help put this program into context, our ComEd team installed on average 2,400 smart meters per day over that 7-year span. In fact, one of our workers personally installed over 25,000 meters as part of this program.

The installation of smart meters on the ComEd system will allow customers to be better informed about their energy consumption that can help them save money and will allow ComEd to further improve its service offerings. In addition, it drives over $100 million of annual operational savings primarily from increased efficiencies in 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 Electric's Churchtown substation expansion project in Pennsville, 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 NiHub PJM West Hub and New York Zone A prices, and offset by weakening in our ERCOT spark spreads. Total gross margin is offset by lower mark-to-market of our hedging due to the higher power prices. For 2019 and 2020 open gross margin was up $250 million and $100 million respectively due to higher PJM West Hub prices and stronger ERCOT spark spreads.

In 2019, open gross margin was also up on higher NiHub and New York Zone A prices. Similar to 2018, the mark-to-market of our hedges is down both in '19 and '20 due to higher prices. We also executed $50 million of Power New Business in both 2018 and 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 programs in 2018 a 9% to 12% behind ratable in 2019 and 8% to 11% behind ratable in 2020 when considering cross commodity hedges where we have increased our concentration.

Turning to Slide 15. As Chris mentioned, we are announcing another round of O&M cost reductions as part of our continual efforts to evaluate our work passages 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 '21 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 Business Services Company or BSC which is part of the transformation efforts that Jack is leading. The $200 million of savings is a gross number with about half from ExGen and half from the BSC organization.

And since BSC costs are shared roughly 50-50 between Exelon Generation and Exelon Utility we would expect our utility customers to benefit from $50 million in annual savings over time with the other $50 million flowing through Exelon Generation bottom line. When we include the $50 million of incremental direct savings at ExGen, we expect $150 million of savings to flow 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 hard work of all of our employees who strive every day to run the company more efficiently while adhering to our commitments to safety, reliability and community stewardship.

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

Christopher Crane -- President and Chief Executive Officer

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 course to preserve the ZEC program and are finding ways to operate more efficiently providing incremental cost savings as discussed. Our value proposition remains unchanged. We're focused on growing our utilities targeting a 6% to 8% EPS growth through 2021. We continue to use free cash flow from the GenCo to fund incremental equity needs at the utilities, pay down debt over the next 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 take -- open to the call up for questions. Thank you.

Questions and Answers:

Operator

(Operator Instructions) Your first question comes from the line of Greg Gordon from Evercore. Greg, your line is now open.

Greg Gordon -- Evercore ISI -- Analyst

Thanks. Good morning, guys. A couple of questions. First on the quarter. Everything seems really good on the utility side, 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?

Christopher Crane -- President and Chief Executive Officer

Are you talking about the operational issues around the GenCo or in the sub power segment?

Greg Gordon -- Evercore ISI -- Analyst

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

Christopher Crane -- President and Chief Executive Officer

Let me start out with the Texas assets so I'll let Joe fill in on the rest of it. Those GE7HA.20, these were the first serial numbers 1 and 2. We were aware as GE was that there was some difficulty with the first-stage blades. We had approximated a run period that we could operate the assets before putting in the fix. The fix was already under way 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, replaced them with the new design, had them back up and running. And as I said, we expect, we're in the rollout phase now and the start-up phase of the fourth unit and we feel confident in the design. GE has put us 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, I'll let Joe cover it.

Joseph Nigro -- Chief Financial Officer

Yeah. So, Greg I think the 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 pressures in Texas at the end of June and where they realized for the quarter, there was an impact with the difference there. As you know, the spot market prices were lower than when we walked into the quarter. On the transmission side, the costs were associated with Order 494 at FERC and that had a negative impact. So from our lens, when you talk about the Generation performance both at Mystic and at ERCOT, those are 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 early results.

Greg Gordon -- Evercore ISI -- Analyst

Great. Thanks. One follow up on ExGen and then one more if you'll hear me. Looking at the cost cuts, it's really quite an impressive incremental change. You've got the cost declining from $4.625 billion to $4.175 billion in 2020 and a little bit more in 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, 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. 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?

Christopher Crane -- President and Chief Executive Officer

We talked about this before that we lack liquidity in the outyears. 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-commodity hedges to be able to manage that. It's -- we will constantly look at driving efficiencies. You can't have a company that 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 anymore on that?

James McHugh -- Executive Vice President and Chief Executive Officer of Costellation

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

Greg Gordon -- Evercore ISI -- Analyst

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

Joseph Nigro -- Chief Financial Officer

Hey, Greg, it's Joe. The short answer is with that balance sheet capacity, we can be more aggressive. And as I mentioned in my remarks when you look at how far behind we are of our ratable plan and when you overlay that fact that we're using gases approximately for power we are carrying a very long open-power positioning in 2019 and 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 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 outyears and not leverage on the balance sheet allows us to do that.

Greg Gordon -- Evercore ISI -- Analyst

Thank you guys.

Christopher Crane -- President and Chief Executive Officer

Thanks, Greg.

Operator

Thank you, Greg. Your next question comes from the line of Julien Dumoulin-Smith from Bank of America. Julien, your line is now open.

Julien Dumoulin-Smith -- Bank of America Merrill Lynch -- Analyst

Hey, good morning everyone.

Christopher Crane -- President and Chief Executive Officer

Good morning. How you doing?

Julien Dumoulin-Smith -- Bank of America Merrill Lynch -- Analyst

Good. Excellent. So I wanted to follow a little bit up on the utility activities. Obviously good progress at PHI yet again. But I wanted to elaborate a little bit further on this. Obviously the cost reductions of say $50 million-ish accrued of 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 underearning relative to authorized level still. And then in tandem with that question if you could elaborate a little bit more on sort of the initial utility CapEx planning. Certainly this is a growing discussion of the 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.

Christopher Crane -- President and Chief Executive Officer

I'll let Anne to take that.

Anne Pramaggiore -- Senior Executive Vice President and Chief Executive Officer, Exelon Utilities

Sure. Good morning, Julien. So a couple of responses to your questions. As we think about moving forward, obviously we're going to blend the $50 million into the LRP over time. It's not the sitting there right now but we'll look at that as we do the next LRP iteration. And certainly our focus on O&M is to be flat to declining at the utilities and that's the goal as we move forward to manage back 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 as we're filing annually, we've got to stay up 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 (ph) rider in Maryland Disc (ph) rider in Delaware and the IIT (ph) rider in New Jersey that we're looking to placed about $358 million of capital investment in right now. Interim rates at New Jersey is helping us close that lag gap. And we're looking at multiyear rate plan in DC. We've been invited to make that filing and we'll be doing that shortly.

So just got an outright provision at PECO authority for the commission to look at that, so that's something we'll be looking at going forward. So those are all the ways we're looking to close in on that ROE number. Obviously looking at, lag is our biggest sort of earn to allow gap but also looking at other disallowances too. But really trying to tighten up on the lag. So that's how we're thinking about on the ROE going forward. On the capital side, the question that you asked we've got -- we look at $5 billion a year a little bit plus north of that going forward for the foreseeable future. We have continuing modernization work at the utilities.

PECO for the 12 kV conversions were closer work. At ComEd we've got the FEJA, voltage optimization work that's about $500 million right there. BG&E has got big gas investment and PHI has got of a lot of material condition work, manhole refurbishment substation rebuilds, that sort of thing. We've got $1.5 billion in our gas program over the next LRP period. We've got close to $1 billion in security programs across the utilities over the LRP. So there's a lot of work to do. We always, always book ended with questions of affordability and that's why we stay tied on O&M. And we look at energy efficiency programs to give customers the ability to reduce usage and manage bills more tightly. And so we're always looking at the affordability side of it and our utilities fits 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'll below the national average on four and we're right at the national average on the other two bills.

Julien Dumoulin-Smith -- Bank of America Merrill Lynch -- Analyst

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

Kathleen Barron -- Senior Vice President of Governmental & Regulatory Affairs & Public Policy

Hi, Julien, this is Kathleen. I can take that question. As you know, reflect how much are going into FERC on November 6 with the expectation that the commission would address the paper hearing sometime in the January time frame. I think the commission is well aware that the market is looking for guidance as Chris said on what the rules are going to be going forward. And importantly the states need to know what changes that they need to make to their clean energy policies to accommodate the new rules coming out of FERC. So we will look to them to provide that guidance in the January time frame.

As you know we'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 asset base they wish to support and to procure them directly to a state-led procurement. That is going to be an important change that we're looking for FERC to make in this next order based on the record in front of them, as an overwhelming amount of support from all partners (ph) 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.

Julien Dumoulin-Smith -- Bank of America Merrill Lynch -- Analyst

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

Kathleen Barron -- Senior Vice President of Governmental & Regulatory Affairs & Public Policy

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's 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 they have adequate time before the rules change in the tariff.

Julien Dumoulin-Smith -- Bank of America Merrill Lynch -- Analyst

Great. Thank you.

Operator

Thank you, Julien. Your next question comes from the line of Steve Fleishman from Wolfe Research. Steve, your line is now open.

Steve Fleishman -- Wolfe Research -- Analyst

Thank you. I'll actually just ask one question. The PJM from the standpoint of not -- obviously you have different stakeholders in lot of areas, 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?

Christopher Crane -- President and Chief Executive Officer

No we definitely see this as a positive to create clarity and a more rewarding market going forward. We've lacked the clarity because we've isolated at times on programs. I think this is where we'll be able to create clarity, capital allotment, allocation will be much clear on where we'll be putting capital and what units we'll be operating and what units will be operating. And 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.

Steve Fleishman -- Wolfe Research -- Analyst

Okay. Thank you.

Operator

Thank you, Steve. Your next question comes from the line of Michael Weinstein from Credit Suisse. Michael, your line is now open.

Michael Weinstein -- Credit Suisse -- Analyst

Hi, guys, thanks for taking my questions. Two quick questions. The first one is do you think that the uncertainties surrounding FERC and surrounding new rules for capacity and energy. Do you think also (ph) uncertainty is delaying newbuild 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 then the second question I'll just ask it right now. Is -- Public Service Enterprise Group just announced that they're pulling out of the retail business. Is this a potential opportunity for Constellation?

Christopher Crane -- President and Chief Executive Officer

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

James McHugh -- Executive Vice President and Chief Executive Officer of Costellation

Hi, Michael, it's Jim McHugh. I can speak to the retail question. I think with the announcement 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 if you take as noted that they're going to supply their contracts as they roll off. We'll obviously be there to serve customers as the No. 1 C&I customer and the No. 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 lots of success also just finding new products and solutions for customers in both residential space and C&I space. So we'll keep taking advantage of those opportunities that are in front of us.

Michael Weinstein -- Credit Suisse -- Analyst

Great. Thank you very much.

Operator

Thank you, Michael. Your next question comes from the line of Jonathan Arnold from Deutsche Bank. Jonathan, your line is now open.

Jonathan Arnold -- Deutsche Bank -- Analyst

Good morning, guys.

Christopher Crane -- President and Chief Executive Officer

Hi, Jon.

Jonathan Arnold -- Deutsche Bank -- Analyst

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

Kathleen Barron -- Senior Vice President of Governmental & Regulatory Affairs & Public Policy

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 tap to decarbonizing is a policy that uses all zero carbon resources. And so, to the extent, states want to act to increase their clear energy ambition. We would be expected -- we would expect that all assets including ours would be able to participate in that type of a policy.

And FERC allowing the states to go ahead and procure clean capacity directly allows them to do so in a way that's going to be able to keep cost down for customers and achieve the clean energy goals at the same time. So we would look to that kind of structure to the extent that FERC puts this carve-out in the tariffs 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 to the existing BGS structure there would not need -- there would not be a need for incremental legislation to allow that state's procurement effects (ph) to flow through the BGS. So that's why I said I think the answer is different depending on which jurisdiction you're in.

Jonathan Arnold -- Deutsche Bank -- Analyst

Okay, great. I'm just willing to see if you provide that on the individual state, so thank you. Could I just have one quick follow up on the cost savings? You've obviously laid out how you expect them to be timed the Q3 '18 cost reductions. Can you remind us how much of the $250 million you've announced last year was flowing into ExGen? And maybe was sort of the sequencing in there in terms of how those ramp up as we try to unravel the numbers on, I guess in Slide 15?

Christopher Crane -- President and Chief Executive Officer

Yeah. That is in the numbers. I think we're looking for the page. Now Joe has got it.

Joseph Nigro -- Chief Financial Officer

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

Jonathan Arnold -- Deutsche Bank -- Analyst

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

Joseph Nigro -- Chief Financial Officer

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

Jonathan Arnold -- Deutsche Bank -- Analyst

Okay. All right. Thanks for that.

Operator

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.

Christopher Crane -- President and Chief Executive Officer

Thanks again everybody for joining. Thanks for the questions, hopefully we covered everything. Any other concerns, please get a hold of IR, myself and I would 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.

Operator

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

Duration: 48 minutes

Call participants:

Daniel Eggers -- Senior Vice President, Corporate Finance

Christopher Crane -- President and Chief Executive Officer

Joseph Nigro -- Chief Financial Officer

Greg Gordon -- Evercore ISI -- Analyst

James McHugh -- Executive Vice President and Chief Executive Officer of Costellation

Julien Dumoulin-Smith -- Bank of America Merrill Lynch -- Analyst

Anne Pramaggiore -- Senior Executive Vice President and Chief Executive Officer, Exelon Utilities

Kathleen Barron -- Senior Vice President of Governmental & Regulatory Affairs & Public Policy

Steve Fleishman -- Wolfe Research -- Analyst

Michael Weinstein -- Credit Suisse -- Analyst

Jonathan Arnold -- Deutsche Bank -- Analyst

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