Public Service Enterprise Group Incorporated

We'll conduct a question and answer session for members of the financial community. At that time, if you have a question, please press star followed by the number one on your telephone keypad. If you would like to withdraw your question, press the pound key. As a reminder, this conference is being recorded today, Thursday, May 2, 2019, and will be available for telephone replay today. beginning at 2 p.m. Eastern today until 11.30 p.m. Eastern on May 10, 2019. It will also be available as an audio webcast on PSG's corporate website at www.psg.com. I will now turn the conference over to Carlotta Chan. Please go ahead.

Thank you, Christa. 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 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 discussed 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 earnings period. I'll 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 Craig, Executive Vice President and Chief Financial Officer. At the conclusion of their remarks, there will be time for your questions, and we ask that you limit yourself to one question and one follow-up.

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 gap results for the first quarter were $1.38 per share compared with $1.10 per share in 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 settlement. At PSE&G, we continue to align our business objectives with New Jersey's energy and environmental policy goals. As a reminder, over the coming five years, PSE&G plans to invest approximately $11 to $16 billion dollars on programs which are expected to provide annual rate-based growth of 7% to 9%, starting from a 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 mains over the next five years and make other improvements to reduce methane leaks and ensure critical energy infrastructure is 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 PFDG Power, total generating output increased by 11% over Q1 2018, driven mainly by the additions of keys, and Sea Warren 7 in mid-2018, which have added to 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 signed 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 the 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 18th, the BPU Commission has voted to award Zero Emission Certificates, and I'm going to start calling them ZECs just for simplicity, to all three of PSEG's New Jersey nuclear power plants, Hope Creek, Salem 1, and Salem 2. The BPU order closely followed the legislation that established the ZEC program, and power began accruing the ZEC payments on April 18th. The 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 in what 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 reform to 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 inflation. In 2019, PSE&G will return an additional $380 million of tax reform 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 flowbacks reduce 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 most cost-effective way to achieve the state's energy efficiency savings targets because it accomplishes these targets while limiting growth in the customer bill and providing broad-based access to such benefits. Both of these important proposals are being evaluated by the VPU, and we expect to resolve them sometime during the third quarter. At Power, construction at Bridgeport Harbor is approaching completion, and the anticipated mid-2000 in-service will add another highly efficient, clean, and dispatchable combined-cycle gas turbine to Power's fossil fleet. The Keys and SeaWarm 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 an improvement to 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 pricing practices so that they reflect the marginal cost of serving loads. 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. PDM is required to make a compliance filing by July 31st, along with tariff change information by August 30th. FERC also directed the New York ISO to modify its pricing logic to allow 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 31st of next year, 2020. We continue to watch the broader package of price formation reforms as they wind their way through the FERC process. An interim order expected from the FERC to reform the PJM capacity auction process toward a, quote, just and reasonable construct remains pending. If PJM's proposal is approved, and with the receipt of ZECs, our New Jersey nuclear units will likely be subject to PJM's revised minimum offer price rule, or MOPR as I'll refer to it, In the interim, PJM has proposed a two-stage auction process, and we continue to believe that either of FERC's suggested alternatives or the PJM approach can accommodate nuclear units receiving ZECs in the capacity auction process. As you know, PJM has asked FERC to approve holding the 2022-2023 RPM auctions in August of this year based on existing rules. BSEG continues to participate in this case, and we are awaiting further guidance and certainty from the FERC with respect to the auctions. On a related note, on April 19th, following the BP-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. A higher contribution from regulated earnings at PSEG, which is approximately 75%, is driving this increase and 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 Nicole over to Dan for more details on our operating results, and we'll be available for your questions after these remarks.

Great. Thank you, Ralph, and good morning, everyone. As Ralph said, PCG 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. 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 now 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 flowback of excess deferred taxes to customers. CSE&G's continued growth in transmission investment added $0.03 per share quarter-over-quarter net income comparisons. CSE&G implemented a $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 included a full quarter of rates implemented from the 2018 distribution rate case settlement, as well as recovery of investments made under the gas system modernization program, improved quarter-over-quarter net income comparisons by 8 cents, which is magnified by the seasonally strong winter usage for the first quarter. Electric margin was a penny per share higher than the first quarter of 2018, also the result of implementing new distribution base rates. Lowered distribution O&M expense added a penny 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 a penny per share versus the first quarter of 2018. Non-operating pension and OPEB added a penny per share versus last year. And 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 flowback 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 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 31st, 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. CSC&G's capital program remains on schedule. CSC&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. CSC&G continues to pursue its Energy Strong II infrastructure investment program before the BPU. Developed under the BPU's Infrastructure Investment Program, or IIP, The 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 DPU. 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 $1,230,000,000. Now moving to power, PCG Power reported non-GAAP operating earnings for the first quarter of 29 cents per share and non-GAAP adjusted EBITDA of $304,000,000. This compares to non-GAAP operating earnings of 33 cents per share and non-GAAP adjusted EBITDA of $313,000,000 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. PCG Power's results for the first quarter reflect an increase in capacity revenue of 5 cents per share compared to the first quarter of 2018. Recontracting reduced results by 8 cents per share, reflecting an approximate 3 cents per megawatt hour decline in the average hedge price compared to the year-ago quarter. Volume increases versus the year-ago period added a penny per share, and gas operations were lower by a penny per share versus the year-ago quarter. The absence of early spring outages occurred in the first quarter of 2018, produced a favorable O&M comparison of a penny 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 push power 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 1st, Both PJM and ISO New England capacity prices are scheduled to decline, with the average price received scheduled to decline to $115 per megawatt day in PJM and to $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 unit's 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 of 63% over the first quarter of last year, with the addition of keys and C-warrant. Lower spark spreads pressured realized margins as infrastructure build-out in the Marcellus Shale gas 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 in 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's 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's 832 reactor vessel bolts, it was determined that a higher number of bolts had 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 and materials on site 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 is no impact at Oak 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 to 62 terawatt hours. For the remainder of 2019, power has hedged 80 to 85 percent of total forecast production at an average price of $37 per megawatt hour. For 2020, power has hedged 50% to 55% of forecast production of 60 to 62 terawatt hours at an average price of $38 per megawatt hour. For 2021, output is forecast to be 60 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 a full-year production contribution of 1,300 megawatts of gas-fired combined cycle capacity, at the Keys Energy Center in Maryland and at Seaworn in New Jersey. It includes the mid-2019 operation of the 485 megawatt gas-fired combined cycle unit at Bridgeport and the mid-2021 retirement of the 383 megawatt Bridgeport Harbor coal-fired generating station. We continue to forecast powers non-GAAP operating earnings for 2019 and non-GAAP-adjusted EBITDA at $395 million to $460 million and at $1.3 billion to $1.130 billion, respectively. I'll briefly address operating results from Enterprise and Other, where for the first quarter we reported net income of $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 PCG Long Island, partially offset by higher interest expense at the parent. And the forecast for the year remains unchanged at $5 to $10 million. PCG 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 PCG Power represented 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. At Enterprise, we continue to forecast non-GAAP operating earnings for the full year of $3.15 per $3.35 per share. That concludes my remarks, and now I'll turn the call back over to Ralph, and we will both take your questions.

Crystal, I think we're ready for questions.

Thank you. Ladies and gentlemen, we will now begin the question and answer session for members of the financial community. If you have a question, please press star followed by the number one on your telephone keypad. If your question has been answered and you wish to withdraw your question, you may do so by pressing the pound key. If you are on a speakerphone, please pick up your handset before asking your question.

One moment for the first question. Your first question comes from the line of Char Perez with Guggenheim.

Hi, good morning. It's actually Constantine here for Char. How are you guys? Just a quick one. On the walks for power, you called out one cent of volume. Can you go a little bit behind that number and talk about some of the power-gas dynamics in the spread? Because the volume of generation was actually materially higher.

Yeah, I think if you... We 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 recontracting, both from a dollar per megawatt hour as well as a cent 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 margins, that's the derivation of the one cent per share.

Okay, and kind of one quick follow-up on that. On 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 you've seen?

You're talking about the aggregate fuel costs?

Yeah.

Yeah, the biggest difference there really is the two new units coming in. So the bump-up that you're seeing from from Keys and Seaworn running is giving you a much bigger aggregate gas burn for the quarter.

Oh, well, I'm talking kind of per unit of generation for the combined cycle. So that seems to be also up a bit. Is that just kind of gas basis dynamics?

Yeah, 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 2020 went down a bit, the range by about 5%. Is that just a factor of kind of how the total generation output has been forecast?

Yeah, it's that as well as, you know, in the first quarter of every year when 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 aggregates. So there's some rebalancing as we work our way through that quarter, and you're seeing a little bit of that. So it's not a material change to how we're doing anything. I think just as we walk through and we see a bigger opportunity to hedge all in one day with BGS, we do some balancing of that. I think that, coupled with as we were working through that quarter and thinking about the potential for where nuclear was pre-Zach determination, came into some of our thinking. Okay. It's not a macro change in how we're approaching things. I think it's just some nuances as we went through the quarter.

Okay. And the last quick one, just to reiterate, you mentioned that the CapEx plans are fully funded with no new equity, and that includes the top end of the range, which is the 9% scenario, right? Yep. Okay. Thanks. That answers it all for me. Thanks, guys.

Your next question comes from the line of Julian Dumoulin-Smith, with Bank of America.

Hi, good morning. Hey, so perhaps let's kick it off on the Zach side of the equation. Just going back to process-oriented questions, how do you think about the BPU and addressing some of the thornier issues around the implementation of MOPRs? Basically, how do you see the state moving forward and how do you see yourself processing just any potential carve-outs that you might need with respect to the units now that you've been formally allocated as X? And how do you see timeline for that playing out?

So Julian, that's a really good question, but a tough one to answer, right? So until we know what approach FERC is going to take, we're really just engaged in kind of quasi-philosophical conversations that I think the BPU Commission is kind of give a very clear answer to in terms of the value of nuclear by virtue of their vote. 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 methods that we would take. I think the most important thing that we should take away from the events of the past few weeks is the commitment the state has to keeping those plants online. further environmental benefits and broader issues.

Okay, all right, fair enough. And then I want 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 want 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 indeed other folks awarded projects or otherwise. I just want to make sure I understand. I know that there's been a public award with ORSTED, but I just want to understand more broadly your participation.

Yes, so a couple things. So we do have an MOU with ORSTED to provide energy management services. The BPU at present is entertaining bids that are inclusive of transmission construction. They could decide in phase two to do things differently than that, to separate the supply from the transmission. And I think we've made it pretty clear that we don't believe we have the skills, nor are we seeking to develop the skills to build the wind farm, but we think we have the skills to help with transmission. So we would have some flexibility in subsequent rounds to help folks with their transmission needs.

So basically, that wouldn't necessarily be exclusive of your partnership in this phase two. 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 of 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.

All right, excellent. Well, thank you very much. Best of luck. We'll talk soon. Thanks.

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

Hi, good morning, guys. Good morning, Jonathan. Could I just ask, Ralph, I missed some of the calls, so apologies if you covered this, but does the recent delay with the timing on the state's energy master plan update have any bearing on the regulatory process around your filings? And just could you give us some context there?

So, no, it does not. As you know, Jonathan, the Clean Energy Future Act, which is the one that's most specifically relevant to the targets and goals set by Governor Murphy, comes under a schedule that's determined by what we used to call the Reggie Statute. I don't know if we can call it that or not. But coincidentally, and here I'm going to go out a little bit on a limb, I just read a newspaper article this morning where the governor himself commented. So you're getting this third hand. I'm just quoting a newspaper article. I wasn't with the governor yesterday. where he said the reason for the delay is he wanted 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 newspaper's quote, and the fact that the BPU has had a lot of work to do. I mean, you've got this offshore wind solicitation the first time ever. You had the ZEC process the first time ever. And in the meantime, they have to regulate water companies, cable companies, solve our environmental remediation filings and various other kind of routine business that is a tremendous workload for them. So at the risk of perhaps maybe deviating a little bit from the prepared remarks of our number one person in the state, it's just a lot of work going on down there at this level.

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

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

Okay. And then I guess just is there any – Anything you'd like to share about what we should be at least conceptually expecting out of your analyst day at the end of the month?

Yeah, you know, Dan's going to probably slam on my instep. You can expect to catch up on your sleep. No, I mean, we'll bring you up to date on details, but it's really going to be steady as she goes. I mean, we're on a really good trajectory, and I expect to stay on that trajectory, and we'll just – reaffirm that with some nice backup data and interesting stuff. And we'll be serving breakfast, Jonathan, so you can still come.

Okay. But I guess there's been some, just back to my other question, the BPU has obviously agonized over the ZEC decision, and there's been quite a lot of public dialogue about pressure on rates. You've made your comments today, Ralph, about how rates would have been higher absent the decision they made. Can you sort of share any comments on sort of general tone of the discussion as we move forward from that decision?

Sure. Look, I don't think it's excessive on my part to really extend congratulations to the BPU commissions. This was a really hard decision for two reasons, right? It's a decision that is better for the state and the planet, but for. And those are always the toughest decisions, right? 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 15 million tons of carbon. They avoided pounds and pounds of mercury and NOx. They avoided thousands of jobs lost. So that's a tough case to make. It's all based upon studies and analysis. Plus, they did it by... raising the collection of revenues from the state's ratepayers of $300 million. No regulator ever likes to do that. It's two-thirds of which is ours and a third of which is excellence. So I think that was an incredibly courageous but right decision for the state of New Jersey, and again, at the risk of being a bit dramatic for the planet. So that's the color you heard, is that, goodness gracious, but for doing this, things would be a lot worse, and I've got to Somehow I, the regulator, have to not only step up and make that decision but explain it to people who are candidly more concerned with whether or not the kids are doing their homework and whether or not their boss is giving them a hard 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 just give them a ton of credit for doing the right thing, especially in light of the candidly, some of the work that was done by the Levitan folks, which I think was not the best work.

Yeah, Jonathan, I mean, I think from our perspective on that front, if you think about and read through what was done, it seems to us that they pretty clearly did not follow what was in the legislation itself. And there were particular elements of the legislation, the market risk, the operating risks that were part of the analysis in the legislation, but were not part of the Levitan report that was pulled together. So we were 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 choice to follow the legislation that was in place. And I think that that departed from what Levitan had pulled together and put in front of them. So to their credit, I think they got to the right place, and they acknowledged that with some direct language within the order. And I think that helped to set the record straight as well.

Okay, I appreciate the call. Thank you very much.

Your next question comes from the line of Paavo Muchta with Citigroup.

Hi, guys. Hi, so one of the long-awaited fast-track reform has come as well. So I just wanted to check with you on that in terms of was it in line with the expectations? Is the move in the curve fully priced in for this reform? And did you kind of see the move that you expected? How do you kind of see this fast-track reform kind of playing out?

So, Prabhupada, we had heard, just as everyone else did, 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. All we 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. 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 the fact that it was already priced in. 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 in. We just operate the business based on what it's telling us is available in terms of purchasing and sales.

Gotcha. 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 wanted 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?

Yeah, Prof, 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 on 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 could end up in 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.

Gotcha. That's helpful to prong the 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 you have the right kind of generation mix at this point? Just wanted to understand how you look at that.

Yeah, first of all, I like the – the environmental signature of the fleet, and I like the heat rate of the fossil units. But we're always willing to listen to people who are willing to offer an attractive price. I don't think we want to get into acquisition or merger discussions on the phone. I mean, that's just because we don't comment on them 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 are core, what isn't core, and we talk about that as a board on a regular basis.

Gotcha. Well, thanks so much, guys.

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

Yeah, hey, guys. How's it going? Yeah, my first question, I just wanted to circle back on what Jonathan was asking about a little bit earlier and maybe put a finer point on it. Just curious, just given the commentary that was made at the BPU meeting itself on DEX and then some of what we've seen at the state level post 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 have been consistent that the investment needs are enormous, that the thing that we all have to be respectful of are 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 feather in programs using some combination of IIP or other clause mechanisms that keeps those rates fixed in real terms. So to just let rates inch up in terms of 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 at the same time, that some higher cost supply options are desired, carbon-free supply options, right? So I think the state and the BPU commission has showed their strong commitment to low carbon energy by doing what I would argue is the second cheapest way to reduce carbon by keeping existing nuclear plants alive 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 through energy efficiency, which has a negative cost for a ton 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. The aspirations are there. We're all lined up from the governor to the BPU to the company. It's doing that while respecting the customer bill that I think we're collectively trying to figure out. So I think the merits of what we proposed hasn't changed. The concern for the customer's bill hasn't changed. You just need to make sure that you pace things in a way that respects all of those aspirations. Be mindful of the bill. and to be mindful of the environmental objectives.

Okay, I appreciate that. And just as a follow-up, 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 tie-in that we should be looking at?

Well, I think those are confidential, Michael, so we really – I mean, we are still in settlement discussions. I think I can go that far, but it won't surprise you to know that there was some other business that stepped in front of that – For us and the staff, and we're having to ask them to have settlement discussions while they're looking at three first-time-ever solicitations for offshore wind. I mean, they are just so busy down there, and they have 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 yesterday. 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 can see the seat toll numbers basically said that there's greater transfer capability into PS North, PS Zone, and Eastern MAC. There's less transfer capability into MAC. And not surprising, demand was down across the board. So we... We haven't done our analysis yet on what we think that implies. And with all due respect, Michael, 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. It's sort of like, yeah, we know things, but we can't tell them. But at this point, we don't even know things.

Okay. Fair enough. Thank you.

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

Hi, this is talking from Greg's team. Hey, thank you for taking my question. I had 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 call around this price dynamic? Is this something you think permanent or temporary in nature?

Talking, I think I would point you more towards the forward curves than anyplace 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 what weather looks like is going to have an impact as we step forward.

Understood.

That's helpful. Thank you.

Your next question comes from the line of Michael Lapidus with Goldman Sachs. Hey, guys. Thanks for taking my question.

Real quick, Ralph, what are the 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 a second ago to the question that – that was asked about what we expect out of RPM. I mean, were it not for our 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 flood-prone areas. So I think from the point of view of traditional infrastructure and resiliency and reliability, we've had a long history of very, very favorable feedback on how prudently we've gone about doing that. But we really are now trying to recognize the increased urgency around taking actions to preempt to degree C rise. Now, New Jersey's not alone, and we need more than New Jersey to act on this. But right now, we have a very strong policy mindset that says we should do as much as we can, and others will follow suit. 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 a really good line of sight when you think about transmission capex for 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?

Yeah, so it's definitely more in the latter category. I think we're, for the foreseeable future, past our 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 to the bulk power system's reliability in the face of generation construction and retirement decisions. And even though PGM 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 of our sub-transmission and bringing it into the transmission domain. So it would be smaller projects.

Got it. Thank you, Ralph. Much appreciated.

You're welcome.

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

Good morning. Thank you.

Hi, Travis.

Just real quick, back to the offshore wind. If the BPU or any of the solicitation, if they don't, breakout transmission. Is that an area where you might be interested in a JV or some other kind of partnership where you took on the transmission and other parts of it 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 ORSDA that we consider transmission to be part of that. In phase two, we would have some flexibility to work with others or to resume that relationship with ORSDA. I wouldn't want to predetermine that decision because we have a fair amount of work to do in phase one just yet.

Okay. And does the MOU specifically break out CAPEX designation, or is that just a

General partnership. Always publicly discloses that it allows us to offer energy management services to horseback.

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

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

Okay. The 38 and the 39. Okay. Very good. Thanks a lot.

Your next question comes from the line of Andrew Weisel with Scotia Howard Wheels.

Hey, everyone.

I'm all set. Actually, I was trying to withdraw, but it wasn't fast enough. Thank you. See you soon.

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

Thanks, Christelle. And thanks, everyone, for participating and for your questions. So, again, as you know, our long-term strategy is to transition our business to a mostly regulated company with 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 earnings are coming from the utility, but as we look ahead to the five-year capital program, 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 its free cash flow improve this year. It's going to continue to support our investment programs and our dividend growth. It's going to enable PSEG to meet the objectives of that five-year capital plan without the need to issue equities. 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, Dan says. 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.