Exelon Corp (EXC) — Q3 2018 Earnings Call Transcript

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'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, forecasts and expectations. Today's presentation also references 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. On slide five, we delivered another strong quarter with earnings again at the upper end of our range, allowing us to raise the lower end of our full year guidance. The utilities did well with strong earned ROEs and mostly first quartile operations. As previously mentioned, the Federal Courts of Appeal in Illinois and New York strongly affirm the legality of the ZEC. Our focus on cost continues to identify an additional $200 million in gross savings, with $150 million of that contributing to the bottom line, bringing our six-year total savings to over $900 million. Combined, this performance demonstrates our increasing value. For the quarter, on a GAAP basis, we reported $0.76 per share compared to $0.85 per share last year. On a non-GAAP operating basis, we reported $0.80 per share, again above the midpoint of our guidance range of $0.80 to $0.90. Turning to slide six, our utilities are performing at higher levels across key customer satisfaction and operating metrics. Our investments in technology and infrastructure continue to enhance reliability, leading to greater customer satisfaction and stronger relations with our regulators and legislators. PECO and BG improved their JV power residential gas and electric scores over the past year, with PECO achieving its highest ranking ever, placing second in the residential electric survey. Our customer service metrics are strong. BGE and ComEd rank in the top decile for customer satisfaction, and PHI is also in the top decile for its service levels. Each of our utilities achieved top quartile reliability performance in outage frequency (SAIFI) and outage duration (CAIDI). ComEd and PHI performed in the top decile for CAIDI. As we have discussed previously, SAIFI remains our highest priority, and our metrics have continued to improve since the start of the year. At ExGen in our third quarter, we achieved a capacity factor of 39.7 terawatt hours at 93.6%. During the fourth hottest summer in nearly 125 years, we achieved a 96.7% capacity factor while avoiding 33 metric tons of carbon emissions. Our gas and hydro fleet performed well but was slightly below plan, with an economic dispatch match at 95.8%. This lower performance was mainly due to two of our CCG's units, Colorado Bend and Wolf Hollow, being offline due to some turbine blade defects. The blades have been replaced, and Wolf Hollow returned to service in late September. One of the Colorado Bend units returned to service in October, while the other is in the process of restarting. We took advantage of the downtime to perform normal maintenance that would have been required during a shutdown next spring. From a financial perspective, all repairs were covered under warranty, and the market impact from the plants being down is well within our full range outage contingency plan. The plants performed very well over the summer prior to the outages, and we are pleased with their design and durability, as 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 its 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 in empowering the states to continue prioritizing zero carbon energy throughout the state-led procurements outside of the PJM capacity module. A number of proposals were filed in response to the order, including from a diverse coalition of which Exelon is a member 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 be 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 other nuclear generators in PJM. Our proposal will provide states with flexibility to conduct a capacity procurement of resources they wish to support for the public policy reasons, and would protect consumers from paying three times 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 plan to submit comments that 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 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 lower realized ERCOT prices versus the end of the second quarter, lower-than-expected generation performance with the unplanned outages at ERCOT CCGTs as just discussed as well as one at a plant, 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 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 margins from 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 headwinds 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 and DC settlement that took effect in June and August respectively. Delmarva's earned ROE includes the benefits of interim rates that 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 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 utilities, our earned ROEs remain over 10% but modestly dipped from last quarter. Our overall earned ROEs for Exelon utilities were modestly higher than last quarter at 9.6%, well within our earned ROE target of 9% to 10% that underlies our earnings outlook for 2019 and beyond. We are pleased with our overall utility performance but have plans for continued improvement to bring PHI closer to the rest of our 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 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 deduction after incorporating tax reform. A final order which was received on August 21 is the settlement we reached in June on the Delaware, Delmarva electric distribution case. The case will provide a $7 million revenue decrease including the benefits of captured firm for customers. On September 7, Delmarva Delaware entered into a settlement agreement in a 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 BG&E's pending gas rate case in January of 2019. As a reminder, the case includes the request for a $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 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 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 is helping to lift earned ROE to our allocated levels across the Exelon utility levels. More detail on the rate cases that are scheduled can 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 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 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, we realized over $100 million in 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 entails equipment upgrades for reliability and 230 kV, 138 kV and 69 kV expansions 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 our stated equipment and by expanding regional transmission capacity which has the benefits of reducing congestion for 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 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 to 2018, the mark-to-market of our hedging is depressed 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 be more efficient teams and better in portraying evasion 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 greater 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 is a gross number with about half from ExGen and half from the BSC. 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's bottom line. When we include the $50 million of incremental direct savings at ExGen, we expect $150 million of savings to flow through our bottom line in 2021, relative to our previous guidance that we showed 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 amounts since 2015, we have now reduced the O&M by over $900 million. It's due to the hard work of all of our employees, we commit every day to run the company more efficiently, while adhering to our commitments to safety, reliability and community stewardship. Turning to slide 16, we remain committed to our strong balance sheet and investment grade credit ratings. And to that end, since our last earnings call S&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, we had a strong quarter both financially and operationally. We are becoming stronger in these areas thanks to the hard work and dedication of our employees. We also achieved key wins to maintain the ZEC programs and are discovering ways to operate more efficiently, leading to additional cost savings. Our value proposition remains the same. We are aiming for 6% to 8% EPS growth at our utilities through 2021. We are utilizing free cash flow from the GenCo to meet additional equity needs at the utilities, reduce debt over the next four years at both the GenCo and HoldCo, and to support faster dividend growth. We will focus on maximizing value at the ExGen by ensuring fair compensation for our carbon-free generation fleet, backing appropriate price formation in PJM and resiliency initiatives at FERC, and advocating for capacity market reforms that help states protect citizens from carbon and air pollution while taking advantage of regional markets. We will exit unprofitable investments and sell assets where necessary to speed up our debt reduction plans and enhance value through load-matching strategies. We will maintain strong investment-grade credit metrics and consistently grow our dividend at 5% through 2020. Operator, we can now open the call for questions. Thank you.

Thanks. Good morning, guys, couple of questions.

Good morning.

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 with the Texas assets. I'll let Joe provide more details on that. Regarding the GE 7HA.200 units, these were the first two serial numbers. We were aware of the issues with the first stage blades, as was GE. We estimated a timeframe for operating the assets before implementing the fix, which was already in progress and designed. GE provided strong warranties for these assets and responded effectively to the initial failure of one CT at Colorado Bend. We took proactive measures by shutting down the other three CTs, replacing them with the updated design, and bringing them back online. Currently, we are in the rollout and startup phase of the fourth unit, and we are confident in the design. GE has established an inspection program that includes borescoping after a specified number of operating hours. Their response has been positive, and independent assessments have confirmed the solid engineering, so we believe those issues are behind us. We anticipate that we will be able to maintain the operation of these assets at very high capacity factors and efficiencies moving forward. I’ll leave the details on the FDRs and other matters to Joe.

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.

Thanks for the update. I have a follow-up regarding ExGen and another question. The cost reductions are impressive, with costs decreasing from $4.65 billion to $4.175 billion in 2020 and even more in 2021, which results in $450 million in savings. However, gross margins have declined by $700 million. This raises concerns for skeptical investors who may see the effective management of costs but question the lack of earnings improvement. I would argue that these cost reductions are likely to be lasting, while the lower power prices should be temporary. Can you reassure us that there is potential for positive operating leverage as time progresses and that the current low commodity and capacity prices are not permanent issues?

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 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. 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, seems temporal.

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 a 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 in 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 opening power position in 2019 and 2020, and when we're able to do that thanks to 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.

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 $50 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.

Good morning, Julien. In response to your questions, we plan to gradually incorporate $50 million into the long-range plan. This amount isn't currently allocated, but we will consider it in the next iteration of the LRP. Our aim for operations and maintenance is to maintain or reduce costs at the utilities as we progress. Regarding return on equity at the PHI and other utilities, our initial focus is on minimizing lag through our annual filings. We need to maintain our provision at DPL until 2020, but for the other utilities, we'll be filing annually and exploring additional options to reduce lag riders. We are currently investing approximately $358 million in capital across the stride rider in Maryland, disk rider in Delaware, and IIT rider in New Jersey. The interim rates in New Jersey are helping us address lag, and we are preparing a multiyear rate plan for DC following an invitation to file. We also have a provision at PECO for the commission to examine. All these efforts are aimed at enhancing our ROE. Regarding capital expenditures, we are looking at around $5 billion a year for the foreseeable future, including ongoing modernization at utilities. PECO is working on 12-kV conversions, ComEd is focused on voltage optimization with an investment of about $500 million, BG&E is making significant investments, and PHI is involved in refurbishment and rebuilding efforts. There’s also $1.5 billion allocated for our gas program and nearly $1 billion for security programs across utilities during the LRP. We continuously assess affordability, which is why we maintain strict controls on O&M. We also promote energy efficiency programs to empower customers to manage their usage effectively. Overall, our utilities perform well in terms of affordability, generally falling below the national average for the proportion of bills to income.

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 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 resources 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 an instance 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. I will actually just ask one question. The PJM 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 struggled at times on programs, I think this is where we'll be able to create clarity, capital allotment will allocation will be much clearer on what we're - where we'll be putting capital, what units will be operating, and what units won't be operating. So, 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.

Hi, guys. Thanks for taking my questions.

Hey, Michael.

Hey, two quick questions. The first one is do you think that the uncertainty surrounding FERC and surrounding new rules for capacity and energy is delaying new build or new start construction plans, if this is going to have an effect on tightening the market going over the next year or 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're not going to get a recovery or return on your capital? Just a second you can…

Okay, understood.

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 residential customer in the country, so a lot for the business and there will be 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.

Good morning, guys.

Hi, Jon.

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 right, Jonathan. I agree with your perspective on Illinois; there will need to be legislation to adjust those rules. A positive aspect for us is that there is a growing sentiment among environmental groups and policymakers nationwide that the quickest and most cost-effective way to achieve decarbonization is through a policy that embraces all zero carbon resources. Therefore, we anticipate that if states wish to enhance their clean energy ambitions, our assets, along with others, will be able to participate in those policies as FERC allows states to procure clean capacity directly. This approach can help keep costs manageable for customers while meeting clean energy objectives. We hope to see this framework if FERC implements it in the tariff in Illinois. In New Jersey, due to the current state law and the authority at the DPU level to manage capacity procurement through the existing BGS structure, there would be no need for additional legislation for that state's procurement process to function properly. That’s why I mentioned that the situation varies depending on the jurisdiction.

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 the numbers. I think we're looking for the page now Joe's got it.

The $250 million 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 run rate year.

Okay. All right. Thanks for that.

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.