Ladies and gentlemen, thank you for standing by. My name is Tiffany, and I am your event operator today. I would like to welcome everyone to today’s conference, Public Service Enterprise Group Fourth Quarter and Full Year 2019 Earnings Conference Call and Webcast. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session for members of the financial community. As a reminder, this conference is being recorded today, Wednesday February 26, 2020 and will be available for telephone replay beginning at 1:00 o’ clock PM Eastern Time today until 11:30 PM Eastern Time on March 5th, 2020. It will also be available as an audio webcast on PSEG’s corporate website at www.pseg.com.

Thank you, Tiffany. Good morning. PSEG released its fourth quarter and full year 2019 earnings results earlier today. The earnings release attachments and slides detailing results by company are posted on the IR website and our 10-K will be filed shortly. The earnings release and other matters we will discuss on 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 recorded 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 included in today’s earnings materials. I will 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.

Thank you, Carlotta and good morning, everyone and thanks for joining us on the call today. PSEG reported non-GAAP operating earnings for the fourth quarter of $0.64 per share, that’s an increase of 14% versus non-GAAP results of $0.56 per share in the fourth quarter of 2018. Non-GAAP operating earnings for the full year were $3.28 per share, which are 5% higher than 2018’s non-GAAP results of $3.12 per share. We achieved solid operating and financial results in 2019, which marked the 15th consecutive year that PSEG delivered results within or above our original earnings guidance. Our GAAP results for 2019 of $3.33 per share, compared to net income of $2.83 per share for 2018 and reflected higher earnings due to several factors. These included, the conclusion of PSE&G’s 2018 distribution rate review, excuse me, a partial year of Zero Emissions Certificates or ZECs, as I’ll refer to them later on. Mark-to-Market gains and Nuclear Decommissioning Trust fund gains compared to losses in 2018 and higher pension credits from benefit plan changes in 2019. Net income for 2019 also included a loss recorded on the sale of PSEG Power’s ownership interest in the coal-fired Keystone and Conemaugh units in Pennsylvania that closed in the third quarter. Details on the results for the quarter and the full year can be found on Slides 6 and 7.

Great. Thank you, Ralph and good morning, everybody. As Ralph said, PSEG reported non-GAAP operating earnings for the fourth quarter of 2019 of $0.64 per share versus $0.56 per share for the fourth quarter of 2018. Our earnings in the quarter brought non-GAAP operating earnings for the full year to $3.28 per share, just 5% higher than 2018’s non-GAAP operating earnings of $3.12 per share. And on Slide 6, we provide you with a reconciliation of non-GAAP operating earnings to net income for the quarter. We also provide you with information on Slide 12, regarding the contribution to non-GAAP operating earnings by business for the quarter. And Slides 13 and 15 contain waterfall charts that take you through the quarter-over-quarter and year-over-year net changes in non-GAAP operating earnings by major businesses. I’ll now review the company in detail starting with PSE&G. PSE&G reported net income for the fourth quarter of 2019 of $0.54 per share, compared with $0.47 per share for the fourth quarter of 2018. Full year 2019 net income was $1.250 billion or $2.46 per share, an improvement of over 17% compared with net income of $1.67 billion or $2.10 per share in 2018. As shown on Slide 17, PSE&G’s net income in the fourth quarter increased as a result of expanded investments in transmission and distribution infrastructure and distribution rate relief for the full quarter as new rates were put into effect on November 1st of 2018. Growth in PSE&G’s investment and transmission improved quarter-over-quarter net income comparisons by $0.04 per share. Gas margin improved by $0.02 per share as a result of rate relief and recovery of investment in gas distributions made under the gas system monetization program. Electric margin was flat in the quarter as one month of incremental rate relief versus 2018’s fourth quarter was offset by lower weather normalized volume and demand. Operating and maintenance expense improved by $0.02 per share compared with the prior quarter, reflecting lower tree trimming and preventative maintenance work. And in addition, retiree medical plan benefit changes implemented in 2019 at a $0.03 per share positive impact on net income compared for the year earlier quarter. These positives were partially offset by a $0.01 per share of higher depreciation expense on higher plant balances. A $0.01 of higher interest expense on higher debt outstanding and higher taxes and other items that were $0.02 on favorable compared to a year earlier quarter. For the full year, weather normalized residential electric sales were 0.2% lower, and weather normalized residential gas sales declined by 1.8%. Total electric and gas customers for the full year increased by 0.9% and point 0.6%, respectively. Last October, PSE&G updated its transmission formula rate filing for 2020 to implement a rate increase after having completed the return of excess deferred tax benefits in 2019. In 2019, PSE&G’s formula rate filing included the flow back to customers of the tax benefits related to accumulated deferred income taxes on an accelerated basis in a single year, which had the effect of lowering the annual revenue requirements and transmission revenue for 2019 after reflecting system investments. PSE&G’s investment of over $2.7 billion in its transmission and distribution infrastructure in 2019 resulted in 6% growth in rate base to over $20 billion. And of this amount, PSE&G’s investment in transmission represents 45% or just over $9 billion of the company’s consolidated rate base at the end of 2019. PSE&G’s net income for 2020 is forecasted at $1.310 billion to $1.370 billion. Now let’s turn to Power. PSEG Power reported non-GAAP operating earnings of $0.10 per share in the fourth quarter compared with non-GAAP operating earnings of $0.11 per share a year ago. The results for the quarter brought Power’s full year non-GAAP operating earnings to $409 million or $0.81 per share, compared to 2018’s non-GAAP operating earnings of $502 million or $0.99 per share. Power’s non-GAAP adjusted EBITDA for the quarter and the year amounted to $198 million and $1.035 billion, respectively. This compares with non-GAAP adjusted EBITDA for the fourth quarter of 2018 of $176 million and for the full year of $1.059 billion. The earnings release as well as slides 13 and 15 provide you with detailed analysis of Power’s operating earnings quarter-over-quarter and year-over-year from changes in revenue and cost. Power reported net income that increased by $0.39 per share and non-GAAP operating earnings that declined by $0.01 per share, compared with the fourth quarter of 2018, as shown on Slide 23. A scheduled decline in capacity prices in PJM and ISO-New England in the second half of 2019 reduced fourth quarter non-GAAP operating earnings comparisons by $0.11 per share. Lower generation output for the quarter also reduced comparisons by $0.02 per share. The benefits of a full quarter of ZEC revenues of $0.06 per share, and lower costs to serve of $0.05 cents per share were partly offset by a $0.03 per share decline from recontracting at lower market prices. Gas operations were flat as lower commodity prices pressured margins and limited off-system sales. The decline in our O&M expense improved comparisons by $0.03 per share, reflecting savings from the Keystone and Conemaugh’s sale and lower fall 2019 fossil outage expense that more than offset higher costs related to the Hope Creek refueling outage and Bridgeport Harbor 5 in-service as of mid-year 2019. Higher interest and depreciation expenses were offset by savings from retiring medical plan benefit changes that were implemented in 2019. And lower taxes improved non-GAAP operating earnings by a $0.01 over the prior year’s fourth quarter. Gross Margin in the fourth quarter stabilized at $31 per megawatt hour from the same level in 2018’s fourth quarter as a scheduled decline in capacity prices that began on June 1st in PJM and ISO-New England was largely offset by the ZECs awarded in April. For the year, gross margin declined to $32 per megawatt hour from $33 per megawatt hour, reflecting the average decline in 2019 hedge prices for energy of approximately $3 per megawatt hour. Now let’s start the Power’s operations. We’ve provided you with detail on generation for the quarter and for the year on Slides 24 and 25. Output from Power’s generating facilities in the fourth quarter declined by 6.2% from last year, primarily reflecting the sale at the end of the third quarter of the Keystone and Conemaugh coal-fired generating units, as well as an extended refueling outage at Hope Creek. Full year 2019 output of 57 terawatt hours was at the low end of our 57 terawatt to 69 terawatt hour forecast. The nuclear fleet operated at an average capacity factor of 81.9% in the quarter, resulting in a full year capacity factor of 88.7% and total production of approximately 30 terawatt hours. The combined cycle fleet operated at an average capacity factor of approximately 54.8% in the quarter, resulting in a full year capacity factor of 52.2% and total production of approximately 23 terawatt hours for the year, an increase of over 20% year-over-year reflecting the addition of Bridgeport Harbor 5 and high capacity factors achieved at the other two new combined cycle units Keys and Sewaren. Coal-fired generation for the quarter and the year was significantly reduced as a result of the sale of Keystone and Conemaugh. And update of Power’s hedge position following the BGS auction in early February is provided on Slide 27. PSEG Power’s forecasting a decrease in output for both 2020 and 2021, to 50 terawatt hours to 52 terawatt hours, down 2 terawatt hours since the third quarter 2019 update, primarily reflecting weak prices and lower market demand. Following the completion of the recent Basic Generation Service or BGS auction in New Jersey, approximately 85% to 90% of production for 2020 is hedged at an average price of $37 per megawatt hour. With baseload production hedged at approximately $1 lower than the average price in 2019. For 2021, Power has hedged 45% to 50% of forecast output of 50 terawatt hours to 52 terawatt hours, at an average price of $36 per megawatt hour, and for 2022 Power has hedged 20% to 25% of forecast output of 50 terawatt hours to 52 terawatt hours at an average price of $36 per megawatt hour. The forecast for 2020 to 2022 volumes fully reflects the sale of Keystone and Conemaugh, which had produced approximately 5 terawatt hours of annual generation in prior years, the generation from the 3 new CCGTs approximately 3 terawatt hours of low generation and each year consistent with current market conditions. And the planned retirement of 383 megawatts of coal-fired generation at the Bridgeport Harbor 3 stations in June of 2021. Power’s 2020 non-GAAP operating earnings and non-GAAP adjusted EBITDA forecast that is projected to be $345 million to $435 million and $950 million to 1.50 billion, respectively. Moving on to Enterprise and other for the fourth quarter of 2019, Enterprise and other reported net income that increased by a $0.01 per share and non-GAAP operating earnings that increased by $0.02 per share compared with the fourth quarter of 2018. Net income of $2 million for the fourth quarter of 2019 compared with a net loss of $5 million or $0.01 per share in the fourth quarter of 2018. And for the full year of 2019, PSEG Enterprise and other reported a net loss of $25 million or $0.06 per share, compared with net income of $6 million or $0.01 per share for all of 2018. Enterprise and other reported non-GAAP operating earnings for the fourth quarter of 2019 of $2 million bring full year results to $7 million or $0.01 per share, which compares to non-GAAP operating loss of $12 million or $0.02 per share in the fourth quarter of 2018 that brought results to $13 million or $0.03 per share for the full year of 2018. For 2020, Enterprise and others expected to produce a non-GAAP operating loss of $5 million and this guidance reflects a continued PSEG Long Island results that are more than offset by higher parent interest expense. PSEG concluded 2019 with $147 million of cash on hand, and debt representing 52% of our consolidated capital position. Power’s that was 33% of its total capital base and its yearend debt positions stood at just over 2.7 times in 2019 non-GAAP adjusted EBITDA. We expect internally generated cash flow will enable us to fund our current 2020 to 2024 capital program of $12 billion to $16 billion and accommodate incremental investment in previously identified opportunities without the need to issue equity, while providing the opportunity to grow our dividend. The recap regarding to non-GAAP operating earnings for 2020 of $3.30 to $3.50 per share at approximate 4% increase over 2019 with regulated operations at PSE&G approaching 80% of consolidated earnings. We also raised PSEG’s common dividend by $0.08 to the indicative annual level of $1.96 per share, a 4.3% increase over 2018. This level continues to represent about a 58% payout of consolidated earnings at the midpoint of 2020 guidance and is comfortably covered by utility-only earnings and has contributed to a 4.7% annual rate of growth in the dividend over the last five years. And with that, Tiffany, we are now ready to take some questions.

Ladies and gentlemen, we will now begin the question-and-answer session for the members of the financial community. your first question comes from the line of Praful Mehta with Citigroup.

Thanks so much. Hi, guys.

Hi Praful.

Hi, Praful.

Hi. So, Ralph on the PJM capacity auction, I’m sure you’re expecting the question. Unfortunately the way FERC has lifted, it’s going to be difficult to see how states stay in it if they really want to push their renewable mandate especially like you said, offshore wind and we’ll see how the net ACR comes out from nuclear. But what is your view on that, if states were to separate or at least have their own FRR like you said, what does that mean for New Jersey? What does the process and timing take? And what does that mean for your portfolio in particular?

Yeah, so that’s a very – thanks, Praful that is a very complicated question. And so much of it is really summarized in two words, it depends. I don’t think New Jersey wants to pay twice for a capacity from carbon free sources and particularly from offshore wind. So under the current construct, which as you know, many people have filed for rehearing. But under the current construct, that would mean New Jersey would have to have either a zonal or statewide FRR which to me is suboptimal, right, because now you’re going to be solving a small problem with a rather large tool. If your aspirations are for 7,000 megawatts of offshore wind, you need to pull out 15,000 megawatts from the capacity market seems to be a bit of overkill. It also depends upon the design of the FRR. Are you taking out what is the engineering assessment of the reserve margin you need, 15%, 16%? If so, you’re leaving behind a residual market that is grotesquely oversupplied and crushing capacity prices in that market. How is price set? I mean, there’s just a ton of questions. What I feel good about is number one, we have an Energy Master Plan that says nuclear is important to 2050. So that has to be economically supported. Number two, we have fossil assets that are located close to the load centers and have deliverability advantages that will make some important factors in any capacity reliability construct that is created. So you know, candidly, we’ve already filed comments and by virtue of those comments, I think it’s for me to say that we’ve said FERC didn’t quite get this right. And it looks like – most likely outcome is folks that are not close the load centers and that are in other regions and may face a residual market that does experience some price suppression, which is the exact opposite of what FERC said they wanted to do. So everything I said after the first two words of it depends, you should take with a little bit of a very cloudy crystal ball of in terms of its ability to be precise, and I’ll end where I started, which is it depends.

And Praful and just one just to add the – as we mentioned in the prepared remarks that we will find out a little bit more from PJM on the 18th of March with respect to the ACRs, which is part of your question as well. So that depends as well, but we’ll get a little bit more insight and we anticipate that to come out on the 18th of March.

Yeah and you do not perform sure that the IMM numbers would suggest that our nuclear plant should we choose to participate would be certainly competitive –

Right now. Yeah, now thanks for all that color. And obviously I do appreciate that nuclear should at least based on IMM numbers. But I guess, given all of the – it depends and uncertainty from a timing perspective, if we’re good to go ahead, do you think New Jersey can react in time to get the FRR? If that was the path forward like you said, a big tool for a smaller problem. But if that was the only path forward, what is the timing expectation you think that FERC that beat that New Jersey can get together and kind of solve the problem from an FRR perspective?

So remember, our capacity prices are set for 2022. So we have a little bit of time there. Depending upon whether or not FERC responds properly to the March 18th filing that Dan referenced, it’s conceivable that the next auction would take place late in Q4 of this year, and New Jersey will not have offshore wind, collecting payments until sometime in 2024. So it doesn’t start paying double until the second auction from now, because we’re still working on the 19 auction just yet for the 2024 energy years, the 2021 auction. So New Jersey has a little bit of time and in conversations with staff, we believe and we’re hearing from staff that they also believe that they may not need legislation to go forward with an FRR. Now 100% certain but I do think that there will be adequate time for New Jersey to avoid double paying for capacity 2024 it won’t be a walk in the park.

Got it, fair enough. I’ll get back in queue guys. Lots more questions, but thank you for that.

Your next question comes from the line of Julien Dumoulin-Smith with Bank of America. Julien Dumoulin-Smith: Thank you. Good morning, team.

Good morning, Julien

How are you? Julien Dumoulin-Smith: Hey, excellent. So let me turn the subject to a slightly different more utility-oriented subject. The E&P talked at least a little bit about transmission returns. I’d be curious to get your latest thoughts on New Jersey specific dynamics. Obviously, you already alluded to in your prepared remarks to an ISO situation. And specifically with a New Jersey, do you think that there’s a potential to file like a 205 to get ahead of any kind of process in New Jersey? Or how do you see this playing out, if at all? Curious on your reaction there.

So I don’t know how to predict whether or not there’ll be a 205 at all, Julien, I mean, we’ve often talked about a 206. And there, there is a high threshold for someone who files a 206. I think we have to do a better job here quite candidly reminding people of the enormous value of our transmission investments over the years, right. If I take you back to August of 2003, when the grid was very different in its structure and how much more improved that is now from a reliability point of view, we’ve literally reduced transmission outages by 300% I believe over that period of time. Once upon a time when there was low cost fuel for generators in the West, New Jersey faced prices with that $20 basis uplift in the east. And nowadays, the nature of that low cost fuel in the West has changed from coal to gas, but it’s lower cost fuel. In the West, New Jersey doesn’t have any natural gas and basis differentials now that have been positive 20 or negative 3, there’s been a bunch of advantages associated with transmission and we still have no shortage of 90 year old transmission assets that need to be replaced. Having said that, we are not likely to file a 205 to change our ROE, because we really don’t know what the FERC rules are going to be it is pretty clear to me that FERC as professionally as possible as assumingly possible basically said, oops, maybe we need to rethink what we did here. And I believe the Chairman himself and so that they are open to potentially rehearing this case. So, a 206 filing is extremely complicated. It takes many years, just take a look at what happened in New England, take a look at what happened in the Midwest. And that’s when people knew what the methodology was going to be. So now in the absence of a known methodology with that complexity, I think it’s not particularly beneficial to our customers or to us to begin to go in and talk to semis, what those rules might be in the form of a 205 filing. So I’m proud of every dollar we spent on transmission and the customer benefits we’ve delivered and as soon as FERC get the rule straight and maybe we can have an intelligent conversation with our regulators and our customers about what is a fair return. But right now the market seems to have anticipated every bit and then some so. Julien Dumoulin-Smith: Indeed. And then if I may, just to follow-up on the sort of bridging the two conversations in power and utility, obviously pressure across the market and then also potentially a slowing utility growth trajectory even on the margin. How do you think about the Power business again, strategically as you think about dividends and cash flow required back into the utility again, trying to bridge that financing conversation against both sides of this business?

Yeah, okay. So – Julien Dumoulin-Smith: In light of the latest asset sale too.

Yeah. So first of all that remember because of the delay in CEF combined with the 6% growth in rate base, which was part of a 17% growth in utility earnings. Yeah, we do lower the bottom end of our rate base growth to 6.5%, but I would take issue with the slowing utility growth, I think that we are very mindful of customer bills and the impact and the customer value creation associated with the type of investments we are making, right? We’re not here to just grow the rate base, we’re here to reward shareholders by doing better things for customers. And so that’s 6.5% to 8%, I would still say is not only robust, but at the risk of being a little bit. But it’s real. So let me just leave it at that since that is describing it, and so 6.5% of programs that and things that we know and 8% is if we get some part of CEF and with the BPU saying, please bring in an AMI or modify your AMI proposal, I think it’s safe to assume that some part of CEF both the EE and AMI will be approved. Now, in terms of Power to your – to the heart of your question, I just, sorry, Julien but I just want to take issue with some of the assumptions behind the question. You know, we’re making progress. We’ve sold Keystone and Conemaugh because that made sense. We’re selling Yards Creek because that makes sense. Right now we’re not selling best line, because it seems that we can get more value out of it than the market was willing to pay for it. And utilities can be almost 80% of our earnings, this year it was 90% of our capital deployed in that direction in the next five years. So the cash flow from Power is an attractive way to fund utility operations. The debt capacity of Power is an attractive way for us to fund the equity component of the utility and we’ll keep doing that. But as people come forward and say, we can make better use of that asset fill in the blank if what that asset is, then, we’re more than happy to have a conversation and those conversations take place all the time. And sometimes they’re fruitful and other times we realize people are just trying to say something that’s quite valuable at a discount price and we’re not going to let them do that. Julien Dumoulin-Smith: All right, thank you guys.

And I think, Julien, you know, the only other thing to add really is, if you think about it, we have talked for a long time about a growing base of rate base is going to trend towards the potential for a lower growth rate off of that because of the higher base. And that’s a little bit about what you see from the standpoint of the range that we have put out. In addition to the fact, if you think about some of the clauses that are in place related to GSMP, related to Energy Strong of five-year run rates, which run through 2023. The five-year plan that we talk about now runs through 2024. So remember, the low end of the range is what we know as a person is moving forward. And so a fall off one year within our five-year forecast from the standpoint of what is approved. And we’ve also talked about there’s a lot of gas pipe, cast iron pipe that’s out there that has a longer run rate from the standpoint of being able to move through all that to eliminate all the methane leaks that come from that. So I think some consistency with that that’s not approved as yet into 2024 is approved through 2023. So you see some drop off on the lower end of that range for that. Julien Dumoulin-Smith: Thank you.

Your next question comes from the line of Jonathan Arnold from Vertical Research.

Hi guys.

Hi, Jonathan.

Hi, Jonathan. Good to hear from you.

Thank you. Likewise. Just a quick on the CapEx updated slide. I just was curious, in 2023 there’s obviously a big increase in the orange segment, the electric distribution is. Can you just remind us as what in that, is the AMI in there or is that sort of still up in the green hashed out ZECs?

No, Jonathan, I think there’s a maybe two things that you can think about a little bit from that perspective. One is the fact that it and I just referenced Energy Strong and GSMT and there’s usually some of what we called stipulated base within the overall spend that is there and that spend can tend to lag a little bit across the five-year period of the clauses that we have. So to the extent that the stipulated base comes through, towards the end of those programs, you may see some of that come through. And usually there’s a little bit of capital that have been – capital add or as we move towards the rate case here just based upon ultimately pulling capital together. So those are the two things that would come to mind related to –

Okay. As I look, the orange and blue that’s 23 particularly had really, really increased the law versus what he was showing us just recently.

An AMI is above in the crosshatch reason, Jonathan for this month.

Okay, so that’s not what’s driving it. And then just to generally when I try to design the numbers underlying with slide was that, you know, a slight rule. But it seems that you’re spending through like the 2023 is probably out $0.5 billion, maybe a little more and, but the rate base is more or less pending up in the same place in the same place. Like on base with that observation or –

With respect to – I’m not quite sure, I fully follow this question.

Just as you look at what your slide implies in terms of 2023 kind of timeframe, rebase. You know, although you’ve had all this moving around on the CapEx, it looks like it adds up in more or less the same place, I just want to make sure I’m right about that.

2023 ends up in the same place as well.

It was before.

We’ll have that comparison.

You’re saying that as compared to –

Yeah, I mean – let me rephrase, how your 2023 vintage type of rate base forecast changed very much in aggregate. Once you put all this together.

I think from the lower end of the range, I would say now, and what you’re seeing on the top end of the range basically is inclusive of both the CEF potential as well as the IIT potential. So we can we can pull our slide rules together and kind of look through what’s there.

Okay –

You’re basically looking at what was a 7% to 8% increase off of ‘19 versus a 6.5% at the lower end off of ‘20. And you’re seeing a 6% increase year-over-year. So net-net, that just becomes math.

Okay. And the destination does seem to be kind of not that different –

Yeah, I think that’s fair, Jon. I don’t think it’s that different –

Okay.

And I think the dependency of CEF is a part of that, that’s been – what’s been the biggest part of our range and remains that way, because we are still in progress with respect to those filings.

Perfect. And then just one other thing. What was the goodwill impairment at Power that you took in the quarter?

Oh, Jonathan that was from any years ago, when we acquired a location in New York which ultimately became the Bethlehem Energy Center and we built that. So I’m going to guess a couple of years to build that it might have been in the 2001-2002 timeframe, something like that. We acquired a site of the Albany Steam station from Niagara Mohawk. And at the time of that acquisition, there was some goodwill that came on the books and that goes through an annual impairment test. And that was impaired as we went through this year. It was a fairly modest amount, but ultimately, it was just that accounting test as –

Okay. But it wasn’t sort of a not one of your core asset?

Yeah, non-cash and relatively small math.

Thank you.

You’re welcome.

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

Hey, guys. Just a quick question on the transmission CapEx embedded in the five-year outlook. I’m just curious, how much clarity do you have at this point in time on 21 and 22 transmission CapEx levels?

I would answer generally is a very high degree. If you think about a lot of those projects, they end up being multiyear projects. And so a lot of that spend is not awaiting approval in those years. It’s more related to spend on projects that have a longer-term runway.

Okay, and the only reason why I asked that question is historically, if you go back over time, when y’all put out a five-year forecast of transmission spend, what the actual spend in years three through five were versus what the forecasts were a couple of years earlier turned out to be vastly different numbers. I’m just curious before looking at something where there could be a significant uptick relative to what we’re seeing on Slide 19 in terms of expected transmission spend, especially since the rollover seems to be occurring really next year in ’21, normally it’s kind of years three through five when you guys have forecast that out.

So, Mike, I mean, I think you could – rest assured that we’re putting out there the best of our knowledge right now. We have said in the past that some of the larger projects, which tended to make the future a little bit lumpier so to speak as new projects were approved. Those large projects are not in the forecast. We don’t envision any, I mean, we never say never depending on what PJM does with the RTEP. Much of the transmission improvements now our end of life projects and 69 kV upgrade projects. So the Susquehanna-Roseland type projects, the Northeast Corridor projects, which could take something that was at x and make it much bigger than x as it gets approved are not likely to show up in the near-term.

Got it. And then one follow-on, I just want to make sure, can you remind me what happens now on the AMI process? Is that spin that’s approved? Is that spin that’s part of the ongoing dockets on the CEF that needs to get approved? And what I, you know, and if it’s a separate part of that, when does that kind of roll in? Is that just part of the energy cloud docket?

Yep. So the BPU lifted the moratorium said okay, based upon some work that was done at brought from electric and independent consultant for this makes sense, we should do this statewide. So they put forth a procedural schedule, which would – if it were fully litigated in its outcome, based on our experience that would wrap up sometime in Q1 of next year. And I said to utilities, okay, please submit your filing, you could do it under the rubric of the infrastructure improvement program, which you may recall was passed in December of 18th. Since we already have a filing in, we don’t need to write a new filing. So we’re going to simply take the AMI component of our CEF, the energy cloud components, and make sure it doesn’t need to be tweaked in any way and pilot under the infrastructure improvement clause recovery mechanism. So I would think I would hope that we’d have a very strong opportunity to come to a negotiated settlement on that since everybody recognizes the value of AMI and since the recovery mechanism in the IIT is pretty well documented and has been used extensively. So maybe this is something we can actually get done this year. But we’ll see.

Got it. And last question. Can you remind me on energy efficiency spin that PSE&G. How was that treated from an earnings perspective?

Right base rate of return. And we’ve had a mechanism in all of our prior programs which continues in this case, it will recover, we have the opportunity to recover the lost revenue through an administrative fee that is set in a way that allows us to run the programs and have the opportunity if we run them efficiently to recover that as that lost revenue –

Got it. Thank you. Much appreciated, guys.

Your next question comes from the line of Paul Patterson with Glenrock Associates.

Good morning. How’re you doing?

Good.

Paul, how are you?

Just really quickly, is there any reason to think that I mean, that there be a significant difference between the PJM’s ACR values versus the IMMs?

There’s nothing that jumps out at us. Paul, they don’t always agree as you know on either policy or other analyses, but there’s nothing that jumps out of this at this moment right now.

Okay. And then with respect to the FRR, if that’s the route that’s taken, how should we think about the amount of capacity that New Jersey would be procuring, I guess. And, you know, how it would be selected, I guess?

That’s really to be determined that. We would want to work with the state to make sure that reliability concerns are met with that the state doesn’t oversupply itself and therefore pay more people than it needs to, but that all needs to be determined.

I guess they would provide information to PJM to ensure that they have actually met the requirements that they need to meet. So you can, I think you can think about the concept of needing to meet the reliability is being consistent with PJM from the standpoint of what kind of a credit you would give two particular types of units like a solar unit wouldn’t get a megawatt for megawatts credit, because it’s not the dispatchable that but I think that the details are to be determined.

So it will basically one would normally think that it would be basically the PJM rules for capacity and what have you, and what their – what the goal is for reserve margin for PJM? Is that how we should probably think about it or –

That’s the way I think about it, Paul, because, you know, clearly, you want to avoid the free rider case, because New Jersey is not going to sever its interconnections to the rest of PJM. And if and we’re not suggesting this, but a New Jersey designed an FRR, that created greater opportunities for reliability concerns in New Jersey to be backstopped by the rest of PJM. But the New Jersey’s to pay for it. That does not seem to be fair. But yes, I mean, I think that we all know that PJM right now has reserved margins that exceed its stated requirements. And presumably, if New Jersey just follow the PJM FRR requirements, that would be more akin to what they’ve traditionally said in the 16% range, not in the 20% plus range and that’s why I think there ought to be concerned about the residual markets.

Absolutely. Okay. Thanks so much.

Tiffany, we’ll take a final question.

Your next question will come from the line of Shahriar Pourreza from Guggenheim Partners.

Hi morning. It’s actually Constantine here for Shah.

Hi, Constantine.

Hi, Constantine.

Just a quick on what kind of slipping from distribution to transmission to generation move fairly frequently. But just high level when we’re thinking about kind of the clean energy future programs and advanced metering kind of energy efficiency opportunities. With kind of this update that you’re potentially thinking about, how does that kind of translate into opportunity? And I’m just thinking in aggregate that you have about 2.3 million customers and what’s kind of an efficient rate of what you think you would deploy AMI and how to think about the trajectory overall?

So that the annual rate, I don’t have committed to memory, Constantine, but, you know, the $2.5 billion for energy efficiency was over to six years. And we are convinced that we can deploy that. Right now we have the authority to commit $111 million over the next six months that will all get spent in six months, that we pre-committed based upon the demand for our programs, I’m pretty confident – I’m very confident of that. The AMI estimate we’ve made is about $500 million to $600 million investment and that’s for 2 million electric customers. Our gas system is a fairly extensive amount of a drive by reading capability and on electric vehicles and storage, that’s the one that really is just a question of what is the regulatory appetite and enthusiasm. The state has a 600 megawatt battery storage goal for 2021, which is clearly is not going to hit. And we’re just proposing $100 million for 30 megawatts. So as the state wants to really aggressively pursue that 2021 target, we could do a lot more. And in electric vehicles are similar question of what is the appetite we proposed the $100 million program for a variety of different charging station infrastructure deployments. So in the aggregate if you add those numbers up, it’s $3.5 billion over six years with the EE being at single biggest piece and the AMI probably being a little bit more of the backend loaded piece as it once you get the approval and then are doing the deployment.

Yeah, the deployment is going to run a few years by the time you roll it out everything. I think a couple of unique aspects of the AMI is that, it certainly feels more like an all or none scenario, you’re not going to do every third house with AMI, it’s going to – you’re really going to roll out AMI you’re not. So it’s got a more of a binary aspect to it. And to do that full rollout is going to take, I don’t, maybe three or four years or so depending upon the pace. So it’ll take a little while to work through at all.

Okay, that’s very helpful. And just one quick follow-up on kind of offshore wind and the timing and kind of opportunities going forward. Kind of have you made the commitment or is there a timeline for making a commitment with Orsted and how are you positioning for any kind of future RFPs New Jersey or otherwise?

So we have not made the commitment yet. We do need to resolve that by the third quarter of this year, I think both we endorse that would like to see that sooner rather than later, but we don’t want to do that in the absence of being fully comfortable that our due diligence is complete. And we have retained ownership of another site that is a residual from our prior partnership with deep water win, which was acquired by Orsted, and that site has access really, I think to three states to Maryland, Delaware and New Jersey in terms of future solicitation.

I mean, that’s very helpful. And any way that you’re thinking about kind of partnerships and structures going forward or is it a little too early to tell?

Yeah, I mean, those discussions are underway with Orsted and I’d rather not have it a lengthy public conversation about that until we resolve that without our future partner.

Okay, that’s very helpful. Thanks so much.

Mr. Izzo and Mr. Cregg, that is all the time we have for questions. Please continue with your presentation or your closing remarks.

Yeah, so thank you for joining us today. And we will be on the road, the balance of next week and a few days after that. So we’d be more than happy to have to meet with folks and have further conversations. I know that there’s a little bit of a – there’s a fair amount to talk about in terms of the FERC Loper and the future of the regulatory decisions, but I must admit that we are encouraged by some of the things that have happened in New Jersey of late. You may recall the white paper on utility role and energy efficiency that came at the end of last year, the Energy Master Plan has come out, we are seeing procedural schedules for all aspects of our CEF filing and we do have an extension of $111 million for just the next six months. So I’d say that, of course, we’re never satisfied with pace, but we are directionally satisfied with the dialogue and the substance of our continued growth of the utility in ways that benefit the customers. So look forward to seeing you on the road. And thank you for joining us today.

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