Ladies and gentlemen, thank you for standing by my name is Cristal and I'm your event operator today. I would like to welcome everyone to today's conference, Public Service Enterprise Group First Quarter 2019 Earnings Conference Call and Webcast [Operator Instructions] As a reminder, this conference is being recorded today, Thursday May 2, 2019 and will be available for telephone replay beginning at 2:00 PM Eastern today, until 11:30 PM Eastern on May 10, 2019. It will also be available as an audio webcast on PSEG's corporate website at www.pseg.com. I would now like to turn the conference over to Carlotta Chan. Please go ahead.

Thank you, Cristal. Good morning and thank you for participating in our earnings call. PSEG’s first quarter 2019 earnings release, attachments and slides detailing operating results by the company are posted on our website at investor.pseg.com and our 10-Q will be filed shortly. The earnings release and other matters discussed during today's call contain forward-looking statements and estimates that are subject to various risks and uncertainties. We also discuss non-GAAP operating earnings and non-GAAP adjusted EBITDA, which differ from net income as reported in accordance with generally accepted accounting principles in the United States. Reconciliations of our non-GAAP financial measures and a disclaimer regarding forward-looking statements are posted on our IR website and are included in today's our earnings release. I would now turn the call over to Ralph Izzo, Chairman, President and Chief Executive Officer of Public Service Enterprise Group. Joining Ralph on today's call is Dan Cregg, Executive Vice President and Chief Financial Officer. At the conclusion of their remarks, there will be time for your questions. [Operator Instructions].

Thank you Carlotta, and thank you all for joining us. Earlier today PSEG reported non-GAAP operating earnings for the first quarter of 2019 of $1.08 per share versus $0.97 per share in last year's first quarter. Our GAAP results for the first quarter were $1.38 per share compared with a $1.10 per share in the last year's first quarter, thereby demonstrating the growing contribution from our regulated operations as well as solid operating results from both businesses. Details on the results for the quarter can be found on Slide 6 of the earnings presentation. These results reflect the benefits from our continued investments in New Jersey energy infrastructure and a full quarter of new rates based upon PSE&G’s 2018 distribution rate case settlements. At PSEG, we continue to align our business objectives with New Jersey's energy and environmental policy goal. As a reminder, over the coming five years, PSE&G plans to invest approximately $11 billion to $16 billion on programs which are expected to provide annual rate based growth of 7% to 9% starting from 2018 year-end base of approximately $19 billion. In addition to investments that improve electric system reliability and resiliency. We recently began the second phase of the $1.9 billion gas system modernization program that will replace approximately 875 miles of gas lines over the next five years and make other improvements to reduce methane leaks and ensure critical energy infrastructure that’s available to support New Jersey's economy. Turning to operations, the first quarter of 2019 had slightly colder temperatures in comparison to the first quarter of 2018. At PSEG Power, total generating output increased by 11% over Q1 2018, driven mainly by the additions of Keys and Sewaren 7 in mid-2018 which have added the Power’s increasingly efficient and clean fleet allowing us to reliably supply the market with flexible dispatchable generation. Our fleet of nuclear generating plants also performed well in the quarter, evidenced by a 98% capacity factor. Notably Salem 1 just completed its first ever uninterrupted operating run between refueling outages, delivering a reliable source of carbon free energy in support of New Jersey's clean energy goals. As we recently celebrated Earth Week, I want to recognize that it was less than a year ago that New Jersey Governor Phil Murphy, signing two environmentally progressive bills into law, The Clean Energy Act and the Zero Emission Certificates program and the state has made much progress since then. The New Jersey Board of Public Utilities, the BPU was tasked with establishing and implementing the state's energy policy around the goals outlined in the Clean Energy act. These efforts include updating state's energy master plan by the end of this year, setting important targets for utilities to reduce energy usage. Developing the basis for New Jersey's first offshore wind solicitation for 1,100 megawatts in mid-2019, establishing a transition to a more cost effective approach for solar energy and carrying out the legislature's intent to preserve a major source of the state's carbon free electricity through the Zero Emission Certificates program. A vital step in reaching the state and Governor Murphy's clean energy goals. As you know, on April 18 the BPU commissioners voted to award Zero Emission Certificates and I'm going to start calling them ZEC, just simplicity, to all three of PSEG’s New Jersey nuclear power plants, Hope Creek, Salem 1 and Salem 2. The BPU order closely follows the legislation that established the ZEC program and Power began accruing the ZEC payments on April 18. This decision preserves over 90% of New Jersey's carbon free generation, saves thousands of direct and related jobs in Salem County and around the state prevents a significant rise in environmentally damaging air emissions, helps preserve fuel diversity and make no mistake, saves New Jersey electricity customers hundreds of millions of dollars and would have been even higher energy costs. Another way to keep bills as low as possible is by continuing to return the benefits of tax reforms of customers and there is good news on this front. PSE&G’s combined electric and gas residential customer bills are already 30% below where they were a decade ago and 40% lower when adjusted for insulation. In 2019 PSE&G will return an additional $380 million of tax reforms savings, primarily related to excess accumulated deferred income taxes in transmission and distribution rates. This is over and above the $262 million of annual rate reductions from the change to the corporate income tax rate from the 2017 federal tax act. These tax flow backs reduced customer bills as the utility continues to improve the reliability and resiliency of its T&D system, modernizing an aging infrastructure and advancing the state’s clean energy goals in a low interest rate environment. As I said, we continue to align our business objectives with New Jersey's energy and environmental policy goals. Our current capital spending plan and proposed investments in Clean Energy Future and Energy Strong II are perfect examples of that alignment. The second phase of Energy Strong will further strengthen and enhance the system reliability and resiliency and the energy efficiency portion of the Clean Energy Future filing, addresses the requirements in the Clean Energy Act to reduce electricity usage by 2% and natural gas usage by 0.75%. We consider our energy efficiency proposal to be the best and the most cost effective way to achieve the state's energy efficiency savings targets because that accomplishes these targets while limiting growth in the customer bill and providing broad-based access to such benefit. Both of these important proposals are being evaluated by the BPU and we expect to resolve them sometime during the third quarter. At Power, construction of Bridgeport Harbor is approaching completion and the anticipated mid-2019 service will add another highly efficient clean and dispatchable combined cycle gas turbine to Power’s fossil fleet. The Keys and Sewaren stations have continued to operate well since coming into service and drove a 63% increase in combined cycle output in Q1 2019. The completion of our 1, 800 megawatt combined cycle construction program will transform Power’s fossil fleet and bring in improvements of Power’s free cash flow generation as its ongoing capital needs decline. With respect to energy markets, FERC recently issued a ruling directing PJM and the New York ISO to change their fast-start tariff pricing practices, though they reflect the marginal cost of serving load. The FERC is directing PJM to make a series of tariff revisions to allow fast-start resources to set prices including restricting eligibility to fast-start resources that have a startup time of one hour or less and a minimum run time of one hour or less. PJM is required to make a compliance filing by July 31, along with tariff change information by August 30. FERC also directed the New York ISO to modify its pricing logic to a lot of the startup costs of fast-start resources to be reflected in prices. The New York ISO must make its compliance filing by year-end 2019 and implement the tariff changes by December 31 of next year 2020. We continue to watch the broader package of price sublimation reforms as they wind their way through the FERC’s process. An interim order expected from the FERC to reform the PJM capacity auction process toward a just a reasonable construct remains pending. If the PJM’s proposal was approved and with the receipt of ZEC, our New Jersey nuclear units, will undergo likely to subject to PJM’s revised Minimum Offer Price Rule or MOPR I'll refer to it. In the interim, PJM has proposed a two stage auction process and we continue to believe that either FERC suggested alternatives or the PJM approach can accommodate nuclear units receiving ZEC in the capacity auction process. As you know, PJM has asked FERC to approve holding 2022, 2023 RPM auction in August of this year based on existing rules. PSEG continues to participate in this case and we are awaiting further guidance and uncertainty from the FERC with respect to the auction. On a related note, on April 19, following the BPU’s ZEC decision, we withdrew our must offer exception filings and deactivation notices for the New Jersey nuclear units that we had submitted in compliance with the PJM auctions timeline. So given our first quarter results, we are affirming the full year forecast of PSEG’s non-GAAP operating earnings at $3.15 to $3.35 per share, at the midpoint of our guidance this represents over 4% growth in earnings over 2018’s full year non-GAAP results of $3.12 per share. At the midpoint of our guidance this represents over 4% growth in earnings over 2018 full year non-GAAP results of $3.12 per share. Higher contribution from regulated earnings at PSE&G which is approximately 75% is driving this increase in offsetting the challenging power market conditions. In addition, the benefit from a partial year of ZEC payments covering all three of our New Jersey nuclear plants has been reflected in our 2019 guidance. The focus and commitment of PSEG’s 13,000 employees to operational excellence supported our first quarter results and enables me to affirm our earnings guidance. I will now turn the call over to Dan for more details on our operating results and will be available for your questions after his remarks.

Great. Thank you, Ralph and good morning everyone. As Ralph said, PSEG reported non-GAAP operating earnings for the first quarter of 2019 of a $1.08 per share versus $0.97 per share in last year's first quarter. We provided you with information on Slide 10 regarding the contribution to non-GAAP operating earnings by business for the quarter and Slide 11 contains a waterfall that takes you through the net changes quarter-over-quarter in non-GAAP operating earnings by major business. And then I'll walk through each company in more detail starting with PSE&G. PSE&G as shown on Slide 13 reported net income for the first quarter of 2019 of $0.79 per share compared with $0.63 per share for the first quarter of 2018. PSE&G’s results were driven by a full quarter of new transmission and distribution rates in effect, a reduction in O&M expense, and a reduction in the utility’s effective tax rate to reflect the flow back of access deferred taxes to customers. PSE&G’s continued growth and Transmission investment headed $0.03 per share, quarter-over-quarter net income comparisons. PSE&G implemented $100 million annual increase in transmission revenue, under the company’s FERC-approved formula rate effective January 1, 2019. Transmission revenues are adjusted each year to reflect an update of the company's investment program for the coming year. Gas margin, which includes a full quarter of rates implemented from the 2018 distribution rate case settlement as well as the recovery of investments made under the Gas System Modernization Program, improved quarter-over-quarter net income comparisons by $0.08, which is magnified by the seasonally strong winter usage for the first quarter. Electric margin was a $0.01 per share higher than the first quarter of 2018, also the result of implementing new distribution base rates. Lower distribution O&M expense added $0.01 per share from the absence of four Nor’easters experienced in 2018’s first quarter. In addition, higher depreciation and interest expense, reflecting the utility’s expanded asset base, each reduced net income by $0.01 per share versus the first quarter of 2018. Non-operating pension and OPEB added $0.01 per share versus last year. A lower effective tax rate offset by other items had a positive $0.04 per share net income impact compared with the first quarter of 2018. The flow back of excess deferred taxes to customers, which reduces revenue as well as expense, will lower PSE&G’s effective tax rate and lower customer bills and the positive P&L impact of the tax rate reflected this quarter will largely reverse in the second quarter. Winter 2019 weather was 3% colder than 2018 and 2% colder than normal, but due to the gas weather-normalization clause, weather did not impact results compared with the first quarter of 2018. For the trailing 12-months ended March 31, weather-normalized electric sales were flat and weather-normalized firm gas sales were 3% higher, led by increased Commercial and Residential usage. Growth in the number of Residential customers continues to trend higher at about 1% per year. PSE&G’s capital program remains on schedule. PSE&G is expected to invest $2.7 billion in electric and gas infrastructure upgrades to its transmission and distribution facilities during 2019 to maintain reliability and increase resiliency. PSE&G continues to pursue its Energy Strong II infrastructure investment program before the BPU. Developed under the BPU’s Infrastructure Investment Program or IIP, Energy Strong II infrastructure plan outlines $2.5 billion of capital spend over the coming five years. And the pending Energy Efficiency component of PSE&G’s Clean Energy Future filing is also pending before the BPU. Designed to achieve the 2% electric and 0.75% gas energy savings goals outlined in 2018’s Clean Energy Act. And for PSE&G, we are maintaining our forecast of net income for 2019 of $1.2 billion to $1.230 billion. Now moving to Power. PSEG Power reported non-GAAP operating earnings for the first quarter of $0.29 per share and non-GAAP adjusted EBITDA of $304 million. This compares to non-GAAP operating earnings of $0.33 per share and non-GAAP adjusted EBITDA of $313 million for the first quarter of 2018. And our non-GAAP adjusted EBITDA excludes the same items as our non-GAAP operating earnings measure as well as income tax expense, interest expense depreciation and amortization expense. The earnings release and Slide 17 provide you with detailed analysis of the items having impact on Power’s non-GAAP operating earnings relative to net income quarter-over-quarter. And we've also provided you with more detail on Generation for the quarter on Slide 18. PSEG Power’s results for the first quarter reflecting increasing capacity revenue of $0.05 per share compared to the first quarter of 2018. Recontracting reduced results by $0.08 per share reflecting an approximate $0.03 per megawatt hour decline and the average hedge price compared to the year ago quarter. Volume increases versus the year-ago period added a $0.01 per share and gas operations were lower by $0.01 per share versus the year ago quarter. The absence of early Spring outages occurred in the first quarter of 2018 produce a favorable O&M comparison of a $0.01 per share in the first quarter of 2019. Higher depreciation and higher interest expense lowered net income comparisons by $0.04 per share versus the year-ago quarter. Taxes and other were a $0.02 per share benefit over the first quarter of last year. Gross margin in the first quarter declined to $31 per megawatt hour from $35 per megawatt hour in the year-ago quarter. Power prices were lower across PJM, New York and Maryland despite slightly cooler temperatures concentrated in February. The severity of weather this year did not pushed our prices higher as they did during the winter of 2018. Capacity revenues for the first five months of 2019 will be a positive comparison to the same period in 2018 and starting June 1, both PJM and ISO-New England capacity prices are scheduled to decline with the average price received scheduled to decline to $115 per megawatt in PJM and a $231 per megawatt day in ISO-New England. Coincident with the in-service date of Bridgeport Harbor 5, Power will begin to receive the $231 per megawatt day for the units 485 megawatt of capacity for seven years. Now let's turn to Power’s operations. Generation output increased compared with the first quarter of last year and output was driven by the addition of new combined cycle capacity. Power's gas-fired combined-cycle units produced 4.4 terawatt hours of output up 63% over the first quarter of last year with the addition of Keys and Sewaren. Lower spark spreads pressured realized margins as infrastructure build-out in the Marcellus shale region continues to erode Power’s gas cost advantage. Coal generated 1.4 terawatt hours, down slightly as a result of lower market demand in Connecticut. And Power’s nuclear fleet operated at an average capacity factor of 98% for the quarter, producing 8.2 terawatt hours of electricity representing 58% of the total generation of the fleet. Of note, Salem 1 strong performance was evidenced by its first ever continuous operating run between refueling outages going into its spring 2019 scheduled refueling. Salem 1 entered that refueling outage on April 12th during the scheduled inspection of the unit 832 reactor vessel bolts, it was determined that a higher number of bolts have degraded than originally projected. We anticipate replacing a total of 271 bolts during the current refueling outage, which is expected to extend the outage by about a month. We have the required tools materials onsite to complete the repairs. Some reactor vessel bolts were replaced at Salem 1 and Salem 2 in the past in 2016 and 2017 respectively during refueling outages at that time. And there was no impact at Hope Creek or Peach Bottom as the reactor vessel bolt issue really only affects pressurized water reactors. That said, Power continues to forecast output for the full year 2019 at 60 terawatt hours to 62 terawatt hours. For the remainder of 2019, Power has hedged 80% to 85% of total forecast production and an average price of $37 per megawatt hour. For 2020, power has hedged 50% to 55% of forecast production of 60 terawatt hours to 62 terawatt hours at an average price of $38 per megawatt hour. For 2021 output is forecast to be 60 terawatt hours to 62 terawatt hours with 25% to 30% of forecast output hedged at an average price of $39 per megawatt hour. The forecast for 2019 to 2021 includes generation associated with the full year production contribution of 1300 megawatts of gas-fired combined cycle capacity at the Keys Energy Center in Maryland and Sewaren in New Jersey includes the mid-2019 operation of the 485 megawatts of gas-fired combined cycle unit at Bridgeport and the mid 2021 retirement of 383 megawatt Bridgeport Harbor coal-fired generating station. We continue to forecast Power’s non-GAAP operating earnings for 2019 and non-GAAP adjusted EBITDA at $395 million to $460 million and at $1.30 billion to $1.130 billion respectively. I'll briefly address operating results from Enterprise and Other. For the first quarter, we reported net income of a $1 million versus net income of $5 million in the first quarter of last year and the net income in the first quarter reflects ongoing contributions from PSEG Long Island, partially offset by higher interest expense at the Parent. And the forecast for the year remains unchanged at $5 million to $10 million. PSEG closed the quarter with $65 million of cash on the balance sheet with debt at the end of March 31st representing 51% of our consolidated capital. Debt at PSEG Power represent 32% of its capital at the end of the quarter. Based on our strong balance sheet and credit metrics, we're able to fully fund our five year capital program without the need to issue equity. And at Enterprise, we continue to forecast non-GAAP operating earnings for the full year of $3.15, $3.35 per share. That concludes my remarks and I'll turn the call back over to Ralph, and we will both take your questions.

Cristal, I think we're ready for the questions.

[Operator Instructions] Your first question comes from the line of Shahriar Pourreza with Guggenheim.

Hi good morning. It's actually Constantine here for Shahriar How are you guys.

Hi Constantine.

Just a quick one, on the walk for Power, you called out $0.01 of volume. Can you go a little behind that number? And talk about some of the power gas dynamics and the spreads because the volume generation is actually materially higher?

Yes. I think if you take a look and we can talked a little bit during the prepared remarks on the call about some of the pressures with respect to the power markets in general and we laid out the overall impact that we saw from re-contracting both from $1 per megawatt hour as well as a $0.01 per share. So if you just take a look at kind of comparing volumetrically year-over-year and looking at the incremental volume and the incremental margin that's the clear vision of the $0.01 per share.

Okay. And kind of one quick follow-up on the Slide 18 with the cost of gas for the generation, those seem to be up materially per unit. Is that just a factor of gas takeaway capacity that we're seeing?

I think you are talking about the aggregate fuel costs?

Yes.

Yes. That's there is biggest difference there, really as the two new units coming in. So the bump up that you're seeing from Keys and Sewaren running is just giving you a much bigger aggregate gas burn for the quarter.

I'm talking kind of per unit generation for the combined cycle. Does that seem to be also up a bit, as just the kind gas based dynamics?

Yes. it’s a little bit of basis, but more broadly gas prices as well Constantine.

Okay. And just one housekeeping item on the hedge percentages. The hedge percentage for 2021 was down a bit of the range by about 5%. Is that just a factor of kind of how the total generation output has been forecasted?

Yes, it's that as well as in the first quarter of every year, we have the BGS auction come through, by definition, taking on BGS and the size of the hedge all in one day ends up being a bigger impact in the aggregate. But there is some rebalancing as we work our way through that quarter, you're seeing a little bit of that. So it's not a material change to how we are doing anything, I think just as we walk through and when we see a bigger opportunity to hedge all in one day where BGS would do some balancing of that. I think that, coupled with the as we were working through that quarter and thinking about the potential for where our nuclear was pre-ZEC determination came into some of our thinking. So it's not a macro change and we're approaching things, I think it's just some nuances as we went through the quarter.

Okay. And I have last quick one just to reiterate. You mentioned the CapEx plans are fully funded with no new equity and that includes the top-end of the range versus the 9% is that right?

Yes.

Okay, thanks. That’s all from me.

Thanks guys.

Your next question comes from the line of Julien Dumoulin-Smith with Bank of America. Julien Dumoulin-Smith: Hi good morning.

Hi Julien.

Good morning. Julien Dumoulin-Smith: So perhaps let's kick it off on the ZEC side of the equation. Just going back to process-related questions, how are you thinking about the BPU in addressing some of the thornier issues around the implementation of MOPR, basically how do you see the state moving forward and how you do see yourself processing, just any potential carve-outs that you might need with respect to the units now that you've been formally allocated to ZECs? And how do you see timeline to that playing out?

So Julien, that's really good question, but it's tough one to answer, right. So until we know what approach FERC is going to take, we are really just engaged in [indiscernible] philosophical conversations. And I think the BPU commission is having a very clear answer to in terms of the value by virtue of their role. So the actual tactics that will be used to preserve the plants is really going to be a function of what FERC decides to do with RPM and we've talked in the past about some things that we've explored, whether it's BGS or possibly other message that we would take. I think the most important thing that we should take away from the events in the past few weeks because the state has plans to getting those plants online, where there are environmental benefits and weather issue. Julien Dumoulin-Smith: Okay. Alright, fair enough. And I wanted to turn it back to the offshore side of the equation. I know there's a formal partnership with Orsted Deepwater at this point. But I wanted to understand just perhaps a little bit broader your participation in the state? Could you have relationships elsewhere amongst the other participants? And how do you think about potentially broadening out your involvement on the transmission side here? If there are other – indeed, other folks awarded projects or otherwise? I just want to make sure I understand. I understand that’s public award with Orsted but I just want to understand broadly your participation?

Yes. So a couple of things. So we do have an MoU with Orsted to provide energy management. The BPU at present is entertaining bids that are inclusive of transmission construction. They could decide in Phase II to do things differently than that, to separate the supply from the transmissions. And I think we've made it pretty clear that we don't believe we have the skills nor we're seeking to develop the skills to build the wind farm, but we think we have the skills to help with the transmission. So we would have some flexibility in subsequent rounds to help folks with their transmission needs. Julien Dumoulin-Smith: So basically, they won’t necessarily be exclusive of your partnership in the Phase II? They could predict that– that separate transmission piece could pertain to any potential development?

Again, the answer to that is yes, provided the BPU decided to separate the supply from the transmission, which they have not decided to do. And we haven't taken a strong position on what's the better approach. It does appear that if you envision a long-term build-out offshore wind up and down the coast, then some comprehensive thinking of the transmission backbone is merited, but in the absence of that kind of coordinated effort, it really is a solicitation by solicitation decision that we'll have to respond to. Julien Dumoulin-Smith: All right, excellent. Well, thank you very much. Best of luck, we will talk to.

Thank you.

Your next question comes from the line of Jonathan Arnold with Deutsche Bank.

Hi, good morning guys.

Good morning Jonathan.

Can I just ask Ralph, I missed some of the quotes, of course you may be covered this, but just the recent delay with timing on the state’s Energy Master Plan update, do you have any battling on the regulatory process around your filings and just can you give us some context there?

So answer is no, it does not. As you know, Jonathan, the Clean Energy Future, which is the one that's most specifically relevant to the targets and goals set by Governor Murphy, comes under our schedule that's determined by what we used to call the [indiscernible] I don't know if we can call that or not. But coincidently, I just read a newspaper article this morning with the Governor himself commented. So you're getting this third-hand, I'm just quoting news paper article I wasn't with the governor yesterday. The reason for the delay is he wants to make sure that everyone who wanted to participate in a stakeholder process had a chance to do so. So I think it's a combination of that, which is straight from the newspapers quote and the fact that the BPU has had a lot of work to do. I mean you've got the offshore wind solicitation, the first-time ever you have the ZEC process the first time ever and in the meantime they have to regulate the water companies, cable companies, install our environmental remediation, the filings and various other kind of routine business that is a tremendous workload for them. So at the risk of perhaps may be deviating a little bit from the prepared remarks, since a number one person in the state is just a lot of work going on down there at that level.

Okay. And so you have the filing for energy efficiency, but what's the timing on other pieces of CEF?

So we don't have timing on that. And we just think discretion is a better part of valour, just given the workload down at the staff. We're just patiently waiting for that feedback on when they are ready to handle those other components. As you know, the EEPs, the energy efficient piece is $2.5 billion out of the $3.6 billion. So I just want to make sure we get that right before pressing on a couple of other components.

Okay. And then, I guess, just is there any you like to share about what we should be at least conceptually expecting out of your Analyst Day at the end of the month?

Yes. Dan is going to upload in a moment, but you can expect to catch up on your sleep. No, I mean, you will bring up the data in detail, but it's really going to be where she goes. I mean, we're in really good trajectory, and I expect to stay in that trajectory and will just reaffirm that with some nice backup data and interesting stuff.

We will be serving breakfast Jonathan, so you can still come.

Okay. I guess, there's some, just back to my other question, the BPU has obviously agonized over the FERC decision and this means there are quite a bit of public dialogue about pressure on rates. You've made your comments today, Ralph, about how rates would be higher, perhaps in the decision they make. Can you just sort of share any comments on sort of the general turn of the discussions from that decision?

Sure. Look, I don't think it's – expressed on my part is to really extend congratulations to the BPU Commissioners. This was a really hard decision for two reasons, right. It's a decision that is a better for the state and the planet, but for all and those are always the toughest decisions. It's not like you're doing something that fixes a situation, you're doing something to avoid a problem. So they avoided $400 million in higher bills, they avoided 16 million tons of carbon, they avoided pounds and pounds of mercury and NOx, they avoided thousand jobs of lose. So that's a tough case to make. It's all based upon studies and analysis. Plus they did by raising the collection of revenues in the states rate pay of $300 million. No regulatory ever likes to do that because its two-thirds, which is excellent. So I think that was an incredibly courageous, but right decision for the State of New Jersey, and again, the risk of being dramatic for the planet. So that's the color you heard is that goodness gracious. But for doing this, things will be a lot worse, and I've got somehow – I as a regulator has not only step to make that decision but explain it to people, we are candidly more concerned whether the kids are doing their homework and whether the boss is giving them right time and whether or not the house needs a new roof and not exactly as customers immerse deeply in the nuances of carbon emissions from gas plants versus coal plants versus nuclear plants. So I'll just give them a ton of credit for doing the right thing. Especially [indiscernible] of the, candidly, some of the work that was done by the Levitan folks which I think was not the best work.

It’s Daniel, I think from our perspective on that front, if you think about and read through what was done, it seems to us they pretty clearly did not follow what was in the legislation itself. And there are particular elements of the legislation, the market risk, the operating risk that were part of the analysis in the legislation, but we're not part of the Levitan report that was pulled together. So we're scratching our head a little bit, and I think to Ralph's point, that the Commissioners looked at what was there and made the right choices to follow the legislation that was in place. And I think that reported from Levitan that pulled together and put in front of them. So I think they got to the right place and acknowledge that with some direct language within the order and I think that helped to set the record straight as well.

I appreciate the color, thank you very much.

Your next question comes from the line of Praful Mehta with Citigroup.

Hi guys.

Hi Praful.

So one of the long-awaited fast-start reforms has come well, so I just wanted to check with you on that in terms of was it in line with the expectations? If the move in the curve fully priced in for this reform and did you kind of see the movement you expected? How do you kind of see this fast-start reform kind of playing out?

Look Praful , we have heard, just like everyone else's that there was a debate between one and two hours. And whether it's priced in or isn't priced in, we don't know. What we only know is that we run our business based upon the forward price curve. And if I'm not mistaken, we have not seen much movement satisfying that could be a function of the fact that there's a bunch of implementation work yet to come. Or it could be a function of factor that was already priced then. But again, I don't mean to be vague. I just think we don't try to guess what the forward price curve has or hasn't factored, we just operate the business based on what it's telling us, that is available and in terms of purchasing and sales.

Got it. Understood. Makes Sense. I guess on the refueling outage on the nuclear, it sounded like there was an extension of that by about a month, just wanting to understand why no impact on the annual. Is there some way to kind of offset that impact of an extension of the refueling outage?

Yes, Praful. I think it's two pieces. One is the fact that when we're providing ranges of output, you're within that range. So if you think about one unit, one month and 57%, you come down to a number that absolutely fits within that range. Probably a smaller thing to think about is that we have generation that's not far from where this facility is. And maybe thinking about, if you look at the interaction of what happened when Oyster Creek retired and we looked at nuclear generation went down in the state and gas generation went up in the state. So there's probably some aspect where we'll end up seeing some of that generation get replaced and it could end up being some of our units. But I think the more way to think about it is just the fact that we're providing a generation range and the magnitude of the incremental days on the outage will easily fit within that range from where we were to where we'll be on the other side.

Got it. And that's helpful two-pronged color. And then I guess one final point, there seems to be a lot of generation assets pruning happening in terms of either rationalizing some assets, both buying and selling assets right now by a number of the other players in the space. How are you looking at the fleet? Is there an opportunity to rationalize anything or do you think, do you have the right kind of generation makes it this point? Just wanting to understand how you look at that?

Yes. First of all, I like the environmental signature of the fleet and I liked the heat rate of the fossil units. But we're always willing to listen to people who were willing to offer an attractive price. So that's – I don't think we want to get into the acquisition or merger discussions of the phone. I mean, that's just personal comment in general. But I'd say in general, we like what we've done with our fleet in terms of its efficiency, its dispatchability and its environmental footprint. But we always think about what our core, what is in core and we talked about that as a board on a regular basis.

Got it. Well, thanks so much guys.

Yes.

Your next question comes from the line of Michael Sullivan with Wolfe Research.

Yes. Hey guys, how's it going?

Fine.

Yes, my first question, I just wanted to circle back on what Jonathan was asking about a little bit earlier and may be put a finer point on it. Just curious, just given the commentary that was made at the BPU meeting itself on ZECs and then some of what we've seen at the state level posts that decision. Are you guys expecting any sort of reverberations, particularly as it relates to some of the filings on the regulated side that you have pending right now?

No. What I would say on that, Michael, is that we always – we have been consistent. That's the investment needs are enormous. That the thing that we all have to be respectful of the impacts on the customer bill. And right now, we are 30% below where we were 10 years ago in our customer bill, 40% if you factor in inflation. So we're 40% below in real terms, 30% nominal terms and what we've committed to our customers and what we've committed to ourselves is to whether in programs using some combination of IIP or other clause mechanisms that keeps those rates fixed in real terms. That's rate bunch up and comes out kind of CPI level growth rate. And now the challenge is to do that at the same time that people's dependency on electricity is increasing and therefore their need for greater resiliency is increasing. And as the same time that some higher costs supply options are desired, carbon-free supply options, right? So I think the state and the BPU commission showed their strong commitment to a low carbon energy by doing what I would argue is the second cheapest way to reduce carbon by keeping existing nuclear plants alive but at a cost of $10 per megawatt hour. We are now in discussions with them on the cheapest way to reduce carbon. And that's for energy efficiency, which has a negative cost percent of carbon reduced. And then there'll be other things that we'll chat with them about in terms of being able to take energy efficiency to the next level through advanced metering. And then to really tackle the number one source of carbon in New Jersey, which is transportation, through helping to build an electric vehicle infrastructure. So the aspirations of there were all lined up from the government to the BPU to the company. It's doing that while respecting the customer bill that I think we're collectively trying to figure it out. So I think the merits of what we've proposed hasn't changed, the concern for the customer's bill hasn't changed. You just need to make sure that you place things in a way that respects all of those aspirations, to be mindful of the bill and to be mindful of the environmental justice.

Okay. Appreciate that. And just as a followup specifically as it relates to the pending Energy Strong II filing that you have any update on the settlement discussions front there and any sort of timeline that we should be looking at?

I think that should be looking at confidential. Michael. So really – I mean, we are still in settlement discussions. I think I can go that far, but there were a lot surprises, that there were some other business that step in front of that for us then the staff and we're having to ask them to have settlement discussions while we're looking at three first time ever solicitations for offshore wind and, I mean, they are just so as we down there and there are so much work on their plate that we have to be respectful of that workload.

Okay. And then just my last one, switching over to power. I think we got the PJM parameters for this year’s auction history. Just curious if at a high level, you guys had any thoughts on what the implications might be for your fleet.

That’s tough to digest. You could see the total numbers basically said that there’s greatest transfer capability into PS North, PS Zone and Eastern Mac is less transfer capability into Mac. And not surprising demand was down across the board. So, we haven’t done our analysis yet on what we think that implies. And with all due respect, my belief is even after we do that analysis, we typically don’t tell anybody. So, we do get it right though. I hate to be such a jerk about it, but I sort of like, we know things that we can tell them. but at this point, we don’t even know things, so…

Okay. Fair enough. Thank you.

Your next question comes from the line of Greg Gordon with Evercore ISI.

Hi, this is [indiscernible] from Greg’s team. Hey, thank you for taking my question. I have a one quick question related to the power business. You noted that the realized spark spreads were pressured by rising gas prices. Can you please give us more color around this price dynamic? Is this something you think permanent or temporary in nature?

I think I would punch him more towards the forward curves then than any place else. And that’s what we always do reference with you and that’s how we think about it as we look forward. The main thing I would tell you is that as you look forward, they are going to continue to change. So, I think we’ve seen some pressure right now and as we look out into the forward curve, we’ve seen a little bit of tightening with respect to sparks and we’ll continue to watch them. And I think supply demand and overall use including whether it looks like it’s going to have an impact as we stepped forward.

Understood. That’s helpful. Thank you.

Your next question comes from the line of Michael Lapides with Goldman Sachs.

Hey guys, thanks for taking my question. Real quick. Ralph, how are you? What does a big things you’re looking for? What do you think some of the bigger things that could emerge out of the energy master plan coming out late in the year?

Well, for us, Michael, it would be the opening up of opportunities on the customer side of the meter. Whether that’s, energy efficiency, which we’ve clearly articulated, whether it’s electric vehicle infrastructure, whether it’s advanced metering infrastructure, which I guess is on the border. I don’t think, I’m not aware, at least of anyone who disputes our prudency and our thoughtfulness around the traditional investments we’ve made. Just going back to a second ago to the question that that was asked about what we expect out of RPM, I mean, whatnot for transmission investments, those transfer capability numbers would have been very different. So there’s huge consumer benefits to the transmission investments we’ve made and we all know about the benefits of the energy. Strong investments we’ve made in terms of lifting assets out of a flood prone areas. So, I think from my point of view of traditional infrastructure and resiliency and reliability, we’ve had a long history of very, very favorable feedback on how prudent we’ve gone about doing that. Well, we really are now trying to recognize the increased urgency around taking actions the preempt two degree seeing rise. Now, New Jersey is not alone, and we need more than New Jersey to act on this. But right now we have a very strong policy mindset this as we should do as much as we can and others will follow too. So out of the energy master plan, I’m looking for a reaffirmation of that commitment to environmental progressiveness that we’ve heard about, because we’re trying to lead the way on that front.

Got it. And then one question on utility side, just thinking about transmission spend, and I know you have really good line of sight when you think about transmission CapEx to the next year or so. How do you think about kind of year three and beyond whether there are any lumpy or large scale significant projects on the horizons like some of the ones you’ve done over the last three to five years or is it much more about lots and lots and lots of little bitty ones?

Yes. So it’s definitely more in the latter category. I think we’re, for the foreseeable future, past out peak transmission spend. Now the caveat you have to give for that as you know, is that the transmission is the first and last line of defense for the both Power systems reliability in the face of generation, construction and retirement decisions. And even though PJM does a good job of trying to allocate expenses associated with generator leads and things of that nature, the grid ultimately is a function of the physical proximity of supply to load. So barring some major, major changes in that dynamic, I think that you can safely assume we're in the mode of improving end-of-life facilities and maybe creating greater capability of our sub transmission and bringing it into the transmission domain. So it would be smaller project.

Got It. Thank you Ralph. Much appreciated.

You are welcome.

Your next question comes from the line of Travis Miller with Morningstar.

Good morning. Thank you.

Hi Travis.

Just real quick. So, back of the offshore wind, if the BBU or any of the solicitation that they don't break out transmission, is that an area where you might be interested in JV or some other kind of partnership or you took on the transmission and other parts of that and left the partner to do the heavy lifting, so to speak?

So right now Travis as we said, we have just an MoU with Orsted in Phase 1 and that’s for generic energy management services and we've been clear with everyone and with Orsted that we considered transmission to be part of that. In Phase 2, we would have some flexibility to work with others or to resume that relationship with Orsted. I wouldn't want to predetermine that that decision because we have a fair amount of work to do in Phase 1 just yet.

Okay. And does the MoU specifically break out CapEx designation or is that just a general partnership?

All we publicly disclose is that it allows us to offer energy management services to Orsted.

Okay. And then also real quick on the hedging disclosures, just remind me or clarify are the ZECs included in the 2020 and 2021 prices?

No. That's just a market oriented number that you're seeing Travis.

Okay. That's the 30 and the 39.

Yes.

Okay. Very good. Thanks a lot.

You next question comes from the line of Andrew Weisel with Scotia Howard Weil.

Hey everyone. [indiscernible] wasn't fast enough. Thank you. See you soon.

Thanks.

Thanks.

Mr. Izzo and Mr. Cregg, there are no further questions at this time. Please continue with your presentation or closing remarks.

Thanks Cristal and thanks everyone for participating and for your questions. So again, as you know, I mean our long-term strategies to transition our business to a mostly regulated company was predictable cash flows and every way we look at it that feels like it's on track to us. We have not only reached the point where 75% of non GAAP operating areas have come from utility, but as we look ahead to the five year capital program, a 90% of it and possibly more depending upon the outcome of the filings will be directed towards the regulated business. So that's going to improve the reliability and efficiency of our operations. It's going to benefit our customers and it's going to support New Jersey's energy policy goals. So Power is going to see it's free cash flow improved this year. It's going to continue to support our investment programs and dividend growth. It's going to enable PSEG to meet the objectives of that five year capital plan without the need to issue equity. So we like the trajectory we're on. Thank you again for joining us and hopefully we'll see everyone on May 29th at the New York Stock Exchange for our annual analyst day. Breakfast included then. So thanks, everyone. We'll see you soon. Take care.

Ladies and gentlemen that does conclude your conference call for today. You may disconnect. And thank you for your participation.