Public Service Enterprise Group Incorporated

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. At that time, if you have a question, you will need to press the star and the number 1 on your telephone keypad. To withdraw your question, please press pound and the number 1. As a reminder, this conference is being recorded today, Wednesday, February 26, 2020, and will be available for telephone replay beginning at 1 o'clock p.m. Eastern Time today until 1130 p.m. Eastern Time on March 5, 2020. 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, 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 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 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 Craig, 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 gap 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-emission 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 Conaway 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 six and seven. At PSE&G, net income grew by 17%, to $2.46 per share in 2019, and rate base grew to over $20 billion at year-end, representing an increase of 6%. We invested over $2.7 billion at PSE&G in 2019, directed at improving the reliability and resiliency of our transmission and distribution system, while also reducing methane emissions through the second phase of our gas system modernization program, or GSMP, as I will also refer to later on. PSE&G completed its energy-strong resilience work for nearly $200 million less than the authorized amount. and we finalized the second Energy Strong Agreement to invest an additional $842 million on system hardening to better adapt to a climate-challenged world. For 2019, PSE&G once again achieved top-coercile OSHA scores for safety and posted our best-ever J.D. Power scores for electric and gas customer satisfaction. We outpaced the industry the average industry improvement on metrics that consider total monthly costs, build clarity, fairness of pricing and options, and ability to manage monthly usage. We were also gratified to receive, for the 18th year in a row, PA Consulting's Reliability I Award as the most reliable electric utility in the Mid-Atlantic region. We remain strongly supportive of New Jersey Governor Murphy's goals of reaching reductions in electric usage of 2%, and gas usage of three-quarters of a percent within five years of programmatic energy efficiency implementation. Last week, we agreed to extend the procedural schedule of our Clean Energy Future energy efficiency proposal from March to the end of September 2020 in order to provide regulators with additional time to complete their review of our $2.5 billion filing, which is essential for New Jersey to reach its carbon neutral energy goal by 2050. This agreement was approved by the New Jersey Board of Public Utilities, our BPU, at their February 19th meeting. At the same time, our existing programs were authorized to invest an additional $111 million. Of note, the BPU lifted a statewide moratorium on Advanced Metering Infrastructure, AMI if you will, and directed the electric distribution companies to file new proposals, or in our case, to update previously filed proposals to install AMI across the state. This is a significant advance for customers as it will help them better manage their energy use and improve outage restoration times. AMI will also support the integration of EE programs, which can limit growth in the customer bill. We look forward to applying best practices learned from our experience installing about one million smart meters at PSEG Long Island over the last three years. In addition, the BPU staff has circulated draft procedural schedules covering the remaining $1 billion of proposed clean energy future investments in AMI, electric vehicles, and energy storage. The draft schedules outline concluding these cases by BPU decisions in the first quarter of 2021, or possibly later this year if settlements can be agreed to by the parties in the cases. Since we filed PSE&G's four-part Clean Energy Future program in January of 2019, much has happened on the clean energy front in New Jersey and surrounding states. Last April, the BPU awarded three years of ZECs to each of our New Jersey nuclear units, supporting their continued operation as New Jersey's largest source of baseload carbon-free generation. In June, the BPU awarded the state's first offshore wind solicitation, to the 1,100 megawatt ocean wind project. And at the start of 2020, New Jersey reentered the Regional Greenhouse Gas Initiative, or RGGI. Pennsylvania and Virginia are considering joining RGGI as well, which could address some of the price disadvantage or leakage experienced by lower carbon states surrounded by non-RGGI participants. The BPU finalized the state's energy master plan last month. which broadly supports the decarbonization and modernization of New Jersey's energy system in order to achieve its goal of 100% clean energy by 2050. A cornerstone of meeting that objective is retaining nuclear generation through 2050, maximizing energy efficiency, the deployment of offshore wind, and other renewable generation, as well as electrifying the transportation and building sectors. The final version of the Energy Master Plan also mentioned the BPU's intent to be more proactive in matters related to transmission siting, cost allocation, and financial returns determined by the Federal Energy Regulatory Commission, or FERC. This is an issue that has come into sharp focus following the FERC's November 2019 order, narrowing the methodologies used to determine the return on equity for a group of Midwest transmission owners. we are reaffirming the earnings sensitivity for transmission returns we have provided in the past, where each 10 basis point move in ROE from our base of 11.18% would result in a one cent per share change in annual utility earnings. I must tell you, the market appears to have assumed a reduction of PSE&G's transmission ROE as a result of the Midwest ROE order, and then some. I would point out that the Midwest ROE order appears far from final. The complexity, expense, and uncertainty on timing and which calculation methodologies FERC ultimately adopts makes the outcome of any potential complaint, should one be filed, difficult to predict. I also would like to address the Energy Master Plan's goal to maintain existing gas pipeline system reliability and safety while planning for future reductions in natural gas consumption tied to energy efficiency. We believe that it may become more difficult to site new natural gas infrastructure such as pipelines and power plants in New Jersey. That said, regulators have been publicly supportive of maintaining and modernizing existing gas infrastructure to ensure safety and to minimize harmful methane emissions. Both of these are benefits of our gas system modernization program. From a practical standpoint, 80% of New Jersey households already use natural gas to heat their homes or to cook. And in fact, many of our customers converted to natural gas from using oil or electricity for these purposes. Conversion costs per customer would be upwards of $10,000 or higher. This would be a significant economic burden on every household. and contrary to most customers' personal preferences. PSE&G customers enjoy the lowest natural gas prices in the region, so a mandated switch to electrification of homes would also diminish the decade-long price benefit shale gas has provided to New Jersey. Moreover, it would be worse for the environment until zero-carbon generation dominated the fuel mix. We strongly believe, and the BPU acknowledges, that natural gas and nuclear power are essential to New Jersey's energy mix and will remain that way for the foreseeable future. With this backdrop of clean energy progress, the urgency for needed climate action, and major elements of the 2018 Clean Energy Act awaiting implementation, PSE&G's $3.5 billion clean energy future filing is as important as ever to get done. Our proposed energy efficiency programs give every customer the opportunity to reduce their energy bills while lowering emissions. As part of the BPU-approved extension of the energy efficiency filing, PSE&G will expand investment in several of its existing programs by $111 million. The previous extension, authorized last fall, quickly sold out, underscoring the demand for our energy efficiency offerings. Providing universal access to energy efficiency is but one of the many ways we demonstrate our commitment to minimizing the customer build, as we have always recognized this to be a vitally important factor in our ability to make system investments in an affordable manner. In addition to the bill comparisons we've highlighted previously, and I will repeat here, that combined customer bills are 30% lower than they were 10 years ago and are 40% lower in real terms, it should be noted that over the 2018 to 2023 period, PSE&G will lower bills by nearly $3 billion. of tax reform-related benefits, with approximately $650 million in 2019 alone. Over half of that, $380 million, went to lower transmission bills. We're able to pass through these savings, in some cases on an accelerated basis. In 2019, PSE&G returned all eligible excess deferred tax balances at transmission, offsetting a scheduled formula rate increase that resulted in a $52 million rate reduction. We continue to be mindful that PSE&G's balance sheet strength enables us to pass through these savings on an accelerated basis, which in turn aids the affordability of investing in large infrastructure projects that benefit customers. Let me turn my attention to PSE&G Power for a moment. Power's non-GAAP operating earnings for the full year of $409 million or 81 cents per share, were 19% below 2018, reflecting the effect of recontracting at lower market prices and lower capacity revenues that were partly offset by ZECs starting in April. We completed Power's 1,800 megawatt combined cycle construction program with the placement into service of Bridgeport Harbor 5. We also made significant progress in replacing reactive vessel bolts at Salem 1. Power continues to exercise stringent cost discipline to remain competitive in a challenging market. PSEG Power made progress in 2019 to reduce the already low-carbon footprint of its 11-gigawatt fleet, with an output profile now comprised of over 50% baseload zero-carbon nuclear generation. Given the completed sale of nearly 800 megawatts of coal interest in Keystone and Conema, Power expects it will eliminate all coal-fired generation from its fuel mix by mid-2021, with the scheduled early retirement of Bridgeport Harbor III. On the power market and policy front, the recent capacity auction held in ISO New England produced a weak capacity clearing price that reflected a significantly lower demand forecast. However, our largest asset in New England is the new Bridgeport Harbor V combined cycle gas turbine. which, as you know, cleared the 2019-2020 auction and locked in a $231 per megawatt day capacity payment for seven years, thereby limiting our exposure to this latest auction result. The long-awaited FERC capacity order to expand the application of the minimum offer price rule, and I'll just refer to that as MOPR going forward, puts PJM states that want to support clean energy resources on notice, that they will need to seek an alternative to the capacity market auction in order to procure their preferred resources and avoid the risk of costly double payments to satisfy their capacity obligation. PGM is expected to update their price floors for all PGM nuclear units soon and will submit these default avoidable cost rates, or ACRs, to FERC in their compliance filing on March 18th. The ACR will be used as the price floor for subsidized nuclear units and will likely determine whether our New Jersey nuclear units can clear the PGM capacity auction for the 2022-2023 energy year. As a reminder, our capacity revenues are locked in through May 2022. As the FERC order currently stands, the MOPR will also be applied to new state-supported renewable generations, such as offshore wind. which will have the net cost of new entry as its price floor. That price floor results in a very remote possibility of clearing the capacity auction, which has prompted several PJM states to consider a fixed resource requirement, or FRR, self-supply option. We will work cooperatively with the Board of Public Utilities in New Jersey and PJM to find the best path forward. whether that is to bid and clear the capacity auction under a business-as-usual scenario or seek the FRR alternative in partnership with New Jersey to preserve its preferred zero-carbon resources. And let's remember that the underlying rationale for FERC's action was to eliminate price suppression caused by units that were receiving out-of-market payments. Also at Power, we've reached an agreement to sell our interest in the Yards Creek Pump Storage Generating Station that we jointly own with First Energy. This sale reflects our ongoing commitment to optimize the value of the generating fleet. These proceeds will add to the improved cash flow at power, given the completion of the combined cycle construction program and power's declining capital needs. BSEG's long-term strategy to transition our business to a mostly regulated company with predictable cash flows is on track. our financial condition remains strong with a healthy balance sheet that provides us the ability to finance our five-year capital plans and provides the opportunity for growth in the common dividend without the need to issue equity. Our total capital program for the 20 to 24 time period is now $12 to $16 billion, with over 90% of that amount directed at regulated utility growth that improves the reliability and efficiency of our operations and supports New Jersey's energy policy goals. PSE&G's planned capital spending program over 2020 to 2024 is $11.5 to $15 billion, and it's projected to produce compound annual growth in rate base of 6.5 to 8%, starting from 2019's year-end base of just over $20 billion. So that denominator in the CAGR keeps growing. For 2020, we are forecasting consolidated non-GAAP operating earnings of $3.30 to $3.50 per share, which at the midpoint represents approximately a 4% increase, 3.6% to be precise, over 2019 results. Full year 2020 consolidated guidance remains at a consistent 20 cents band as provided in recent years. While subsidiary guidance ranges are modestly wider, to allow for variability by business that is often offset in consolidated results. The increase for 2020 is led by a higher contribution from regulated earnings at PSE&G approaching 80% of consolidated results, partially offset by an expected decline in powers results to account for lower expected market prices for energy and capacity. This guidance includes the benefit from a full year of ZECs for all three of our New Jersey nuclear plants. The Board of Directors' recent decision to increase the company's common dividend to the indicative annual level of $1.96 per share is the 16th increase in the last 17 years and reflects our commitment to returning capital to our shareholders, as well as preserving the financial flexibility to pursue growth. We finished 2019 well-positioned to execute on our policy and regulatory priorities, as well as our environmental, social, and governance priorities. PSEG recently adopted the Sustainability Accounting Standards Board, or SASB, disclosure practice, and incorporated the UN Sustainable Development Goals in our 2019 sustainability report. PSEG Power adopted a net zero by 2050 goal in July, assuming advancements in technology, public policy, and customer behavior. And this coming April, we expect to issue our first climate report using the Task Force on Climate-Related Financial Disclosures framework. PSEG was again named to the Dow Jones Sustainability Index for North America for the 12th consecutive year in 2019. Most recently, PSEG was recognized among America's most just companies for 2020 by Forbes and Just Capital. And Forbes included PSEG in its 2020 list of America's best employers for diversity for the third year in a row. With that in mind, I want to thank all of our employees for their dedication and customer commitment each and every day that helped make these results possible. I will now turn the call over to Dan for more details on our operating results, and we'll be available for your questions after his remarks.

Great. Thank you, Ralph, and good morning, everybody. As Ralph said, PCG 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, which is 5% higher than 2018's non-GAAP operating earnings of $3.12 per share. And on slide six, 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 business. I'll now review each 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 $1,250,000,000, or $2.46 per share. an improvement of over 17% compared with net income of $1.067 million, 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 investment 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 in 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 distribution made under the gas system modernization 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 maintenance expense improved by two cents 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 had a three cent per share positive impact on net income compared to the year earlier quarter. These positives were partially offset by a penny per share of higher depreciation expense on higher plant balances, a penny of higher interest expense on higher debt outstanding, and higher taxes and other items that were two cents unfavorable compared to the 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 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% for 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 $1,310,000,000 to $1,370,000,000. Now let's turn to power. KCG Power reported non-GAAP operating earnings of 10 cents per share in the fourth quarter, compared with non-GAAP operating earnings of 11 cents per share a year ago. The results for the quarter brought Power's full-year non-GAAP operating earnings to $409,000,000, or 81 cents per share, compared to 2018's non-GAAP operating earnings of $502,000,000, or 99 cents per share. Power's non-GAAP-adjusted EBITDA for the quarter and the year amounted to $198 million and $1,035,000,000, respectively. This compares with non-GAAP-adjusted EBITDA for the fourth quarter of 2018 of $176 million and for the full year of $1,059,000,000. 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 2 cents per share. The benefits of a full quarter of ZEC revenues of 6 cents per share and lower costs to serve of 5 cents per share were partly offset by a 3 cent per share decline from recontracting at lower market prices. Gas operations were flat as lower commodity prices pressured margins and limited off-system sales. A decline in our O&M expense improved comparisons by 3 cents per share reflecting savings from the Keystone Economist sale and lower fall 2019 fossil outage expense that more than offset higher costs related to the Hope Creek refueling outage and Bridgeport Harbor Fives 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 penny 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 PGM and NYSO New England was largely offset by the ZEX 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 turn to 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 powers 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-Economa 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 to 59 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 Sea Warrant. Coal-fired generation for the quarter and the year was significantly reduced as a result of the sale of Keystone Economos. An update of Power's hedge position following the BGS auction in early February is provided on slide 27. PCG Power is forecasting a decrease in output for both 2020 and 2021. 50 to 52 terawatt hours down two terawatt hours since the third quarter 2019 update primarily reflecting weak prices and lower market demand following completion of the recent basic generation service or bgs auction in new jersey approximately 85 to 90 percent of production for 2020 is hedged at an average price of 37 dollars per megawatt hour with base load production hedged at approximately one dollar lower than the average hedge price in 2019. for 2021 power has hedged 45 to 50% of forecast output of 50 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 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 Economo, which had produced approximately five terawatt hours of annual generation in prior years, The generation from the three new CCGTs, approximately three terawatt hours of lower generation in each year consistent with current market conditions, and the planned retirement of 383 megawatts of coal-fired generation at the Bridgeport Harbor 3 Station in June of 2021. Power's 2020 non-GAAP operating earnings and non-GAAP adjusted EBITDA forecasted is projected to be $345 million to $435 million. and $950 million to $1.5 billion, respectively. Moving on to enterprise and other, for the fourth quarter of 2019, enterprise and other reported net income that increased by a penny per share and non-GAAP operating earnings that increased by two cents 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 penny per share, in the fourth quarter of 2018 For the full year of 2019, PCG Enterprise & Other reported a net loss of $25 million or $0.06 per share, compared with net income of $6 million or a penny per share for all of 2018. Enterprise & Other reported non-GAAP operating earnings for the fourth quarter of 2019 of $2 million, bringing full year results to $7 million or a penny 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 full year 2018. For 2020, Enterprise and others expected to produce a non-GAAP operating loss of $5 million, and this guidance reflects a continued PSCG Long Island results that are more than offset by a higher parent interest expense. PSCG concluded 2019 with $147 million of cash on hand. and debt representing 52% of our consolidated capital position. Tower's debt was 33% of its total capital base, and its year-end debt position stood at just over 2.7 times 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 to $16 billion and accommodate incremental investment in previously identified opportunities without the need to issue equity while providing the opportunity to grow our dividends. To recap, we're guiding to non-GAAP operating earnings for 2020 of $3.30 to $3.50 per share, an approximate 4% increase over 2019, with regulated operations at PSE&G approaching 80% of consolidated earnings. We also raised PSE&G'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. If you have a question, please press the star and the number 1 on your telephone keypad. If your question has been answered and you wish to withdraw your polling question, you may do so by pressing pound followed by the number 1. If you are on a speakerphone, please pick up your handset before entering your request. One moment, please, for the first question. Your first question comes from the line of Profel Meta with Citigroup. Thanks so much. Hi, guys.

Hi, Profel.

Hi. So, Ralph, on the PGM capacity auction, I'm sure you're expecting the question. Unfortunately, the way FERC has left it, it's going to be difficult to see how states stay in it if they really want to push their renewable mandates, especially, like you said, offshore wind, and we'll see how the net ACR comes out for nuclear demand. 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, Prof. 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 capacity from – carbon-free sources, and in particular 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, the 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 protestantly oversupplied and crushing capacity prices in that market. How is price set? 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 them important factors in any capacity, reliability construct that is created. So candidly, we've already filed comments, and by virtue of those comments, I think it's safe for me to say that we've said FERC didn't quite get this right. And it looks like the most likely outcome is folks that are not close to load centers and that are in other regions 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 in terms of its ability to be precise, and I'll end where I started, which is it depends.

And probably one thing to add, 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 was 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 know, Prof, I'm sure that the IMM numbers would suggest that our nuclear plants, should we choose to participate, would be certainly competitive.

Right. Yeah, no, thanks for all that, Kala, and obviously I do appreciate that nuclear should at least be based on IMM numbers. But I guess, given all of the it depends and uncertainty, from a timing perspective, if FERC were to go ahead, do you think New Jersey can react in time to get the FRR if that were 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 New Jersey can get together and kind of solve the problem from a 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 Kirk responds promptly 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. So the 2024 energy year is a 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, it's not 100% certain, but I do think that there will be adequate time for New Jersey to avoid double paying for capacity in 2024. It won't be a walk in the park.

Got it. Fair enough. I'll get back into you guys. Lots more questions, but thank you for that.

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

Thank you. Good morning, Tim. Good morning, Julian. Good morning. Hey, excellent. So let me turn the subject to a slightly different, more utility-oriented subject. The EMP 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 the MISO situation. And specifically within 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? I'm curious on your reactions there.

So I don't know how to predict that. Whether or not there'll be a 205 at all, Julian, I mean, we've often talked about a 206, and there is a high threshold for someone who files a 206. I think we have to do a better job here, quite candidly, of 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 it 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 that had a $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 still a lower-cost fuel in the West. New Jersey doesn't have any natural gas, and basis differentials now instead of being positive 20 or negative 3. So 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 seems pretty clear to me that FERC has, as professionally as is humanly possible, basically said, oops, maybe we need to rethink what we did here. And I believe the chairman himself has said 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 start to surmise what those rules might be in the form of a 205. So I am proud of every dollar we've spent on transmission and the customer benefits we've delivered. And as soon as FERC gets the rules straight, then 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.

Indeed. And then if I may, just to follow up on this, sort of bridging the two conversations between 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 against 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.

As well as in light of the latest asset sale, too.

Yeah. So, first of all, 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-based 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. 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 6.5% to 8% I would still say is not only robust, but at the risk of being a little bit, well, it's real. So let me just leave it at that instead of describing it. And so 6.5% is programs 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 EE and AMI, will be approved. Now, in terms of power, to the heart of your question, I just, sorry, Julian, but I just wanted to take issue with some of the assumptions behind the question. You know, we're making progress. We've sold Keystone Conoma because that made sense. We're selling Yards Creek because that makes sense. Right now, we're not selling Bethlehem because it seems that we can get more value out of it than the market was willing to pay for it. And the utility is going to be almost 80% of our earnings this year with 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 as to 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 take something that's quite valuable at a discount price, and we're not going to let them do that.

All right. Thank you, guys.

And I think, Julian, 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, five-year run rates which run through 2023 the five-year plan that we talked about now runs through 2024 so remember the low end of the range is what we know is approved and is moving forward and so kind of fall off one year within our five-year forecast from the standpoint of what is approved and we've also talked about there's there's a lot of gas pipe cast iron pipe that's out there that has a 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. It's approved through 2023. So you see some drop-off on the lower end of that range for that reason.

Thank you.

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

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, electric distribution. Can you just remind us what's in that piece? Is the AMI in there, or? Is that sort of still up in the green hashed out section?

No, Jonathan, I think there's maybe two things that you can think about a little bit from that perspective. One is the fact that, and I just referenced Energy Strong and GSMP, and there's usually some of what we call 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 adder as we move towards a rate-based year just based upon ultimately pulling capital together. So those are the two things that would come to mind related to this.

Okay. The orange and blue bits, 23 particularly, have really increased a lot versus what you were showing us most recently.

Okay. And AMI is above in the cross-hatch reason, John.

Okay, so that's not what's driving it. And then just sort of generally when I sort of try to define the numbers underlying the slide with a kind of slide rule effort, it seems that you're spending through like the 2023 is probably up half a billion dollars, maybe a little more, but the rate base is more or less ending up in the same place. Am I on base with that observation, or not quite?

With respect to, I'm not quite sure I fully follow your question.

Just look at what your slide implies in terms of the 2023 timeframe rate base. Although you've had all of this moving around on the CapEx, it looks like it ends 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 what?

It was before.

Oh, as it was before. I'll have that comparison. You're saying as compared to a... Yeah, I mean, let me rephrase it.

Has your 2023 vintage type of rate-based forecast changed very much, you know, in aggregate, once you put all this together?

I think from the... From the lower end of the range, I would say no. And what you're seeing on the top end of the range basically is inclusive of both the CEF potential as well as the IIP potential. But 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 that just becomes math.

Okay. The destination does seem to be kind of not that different. I think that's fair, John.

I don't think it's that different if it's different. Okay. And I think the pendency 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 violence.

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

Oh, that Johnson, that was from, um, 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've been in the, 2001-2002 timeframe, something like that. We acquired a site of the old 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. fairly modest amount, but ultimately it was just that accounting test as we went through.

Okay.

But it was sort of not one of your core assets, I think. Yeah, non-cash and relatively small amount.

Thank you. You're welcome.

The next question comes from the line of Michael Lapidus with Goldman Sachs.

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

I would answer generally as a very high degree. If you think about a lot of those projects, they end up being multi-year 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 ask that question is historically, if you go back over time, when you 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 years earlier turned out to be vastly different numbers. I'm just curious if we're looking at something where there could be a significant uptick relative to what we're seeing on slide 19 in terms of expected transmission spins, 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, you never say never, depending on what PGM does with the RTEP. Much of the transmission improvements now are 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 if it's a separate part of it, when does that kind of roll in? Is that just part of the energy cloud docket?

Yep. So the BPU listed the moratorium, said, okay, based upon – Some work that was done at Rockland Electric and Independent Consult Report. 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 they 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 18. Since we already have a filing in, we don't need to write a new filing. So we are going to simply take the AMI component of our CEF, the energy cloud component, and make sure it doesn't need to be tweaked in any way and file it 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 and the IIP 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 spend at PSE&G, how is that treated from an earnings perspective?

Rate-based rate of return? And we've had a mechanism in all of our prior programs, which continues in this case, to 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 lost revenue.

Got it. Thank you. Much appreciated, guys.

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

Good morning. How are you doing? Hey, Paul. How are you? Just really quickly, is there any reason to think that there'd be a significant difference between the PGMs 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 their analyses, but there's nothing that jumps out at us 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. We would want to work with the state to make sure that reliability concerns are met, but that the state doesn't oversupply itself and therefore pay more people than it needs to, but that all needs to be determined.

And the state would provide information to PJM to ensure that they have actually met the requirements that they need to meet. So I think you can think about the concept of needing to meet the reliability as being consistent with PJM from the standpoint of what kind of a credit you would give to particular types of units. Like a solar unit wouldn't get a megawatt for megawatt credit because it's not dispatchable. But I think that the details are to be determined.

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

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

Absolutely. Okay. Thanks so much.

Tiffany, we'll take a final question.

Your next question will come from the line of Sharihar Pariza with Guggenheim Partners.

Hi, good morning. It's actually Constantine here for Shar. Hi, Constantine. Just a quick one. We're kind of flipping from distribution to transmission to generation 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, you have about 2.3 million customers, and what's kind of an efficient rate at which you think you would deploy AMI and kind of how to think about the trajectory overall?

So the annual rate, I don't have committed to memory, Constantine, but the $2.5 billion... Our energy efficiency was over 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 won't all get spent in six months, but if we could commit it based upon the demand for our programs, I'm very confident of that. The AMI estimate we've made is about a $500 million to $600 million investment, and that's for all 2 million electric customers. Our gas system is got a fairly extensive amount of 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 clearly is not going to hit. And we're just proposing $100 million for 30 megawatts. So if the state wants to really aggressively pursue that 2021 target, we could do a lot more. And then electric vehicles is a similar question of what is the appetite. We proposed a $300 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 the single biggest piece and the AMI probably being a little bit more of the back-end loaded piece once you get the approval and then during the deployment?

Yeah, I think that deployment's going to run a few years by the time you roll it out to everybody. 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. You're either going to roll out AMI or you're not. So it's got more of a binary aspect to it. And to do that full rollout is going to take, I don't know, maybe three or four years or so, depending upon the pace. So it'll take a little while to work through it 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. 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 and Orsted 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 Deepwater Wind, 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.

Okay, that's very helpful. And kind of 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 a lengthy public conversation about that until we resolve that with our future partners.

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

Mr. Izzo, Mr. Craig, 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 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 MOPR, 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 the utility role and energy efficiency that came out 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 customer. So I look forward to seeing you all 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.