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Public Service Enterprise Group Inc (NYSE:PEG)
Q4 2019 Earnings Call
Feb 26, 2020, 11:00 a.m. ET

Contents:

  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:

Operator

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. [Operator Instructions] As a reminder, this conference is being recorded today, Wednesday, February 26, 2020, and will be available for telephone replay beginning at 1:00 p.m. Eastern Time today until 11:30 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.

Carlotta N. Chan -- Senior Director, Investor Relations

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 Cregg, Executive Vice President and Chief Financial Officer. At the conclusion of their remarks, there will be time for your questions.

Ralph Izzo -- Chairman of the Board, President and Chief Executive Officer

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 guidance 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; 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 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 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-quartile 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 cost, bill 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 One 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 0.75% 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 the February 19 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; addressed schedules outlined 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 ZEC 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 citing, 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 $0.01 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 cost 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 build 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 and 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 PSEG Power for a moment. Power's non-GAAP operating earnings for the full year of $409 million or $0.81 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 reactor 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 Conemaugh, Power expects it will eliminate all coal-fired generation from its fuel mix by mid-2021, the scheduled early retirement of Bridgeport Harbor 3. 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 five 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 that capacity obligation. PJM is expected to update their price floors for all PJM nuclear units soon and will submit these default avoidable cost rates, or ACRs, to FERC in their compliance filing on March 18. 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 PJM 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 generation, such as offshore wind, which will have the net cost of new entry as it's price floor. That price flow 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 FirstEnergy.

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. PSEG'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 2020 to '24 time period is now $12 billion 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 billion to $15 billion and is projected to produce compound annual growth in rate base of 6.5% to 8%, starting from 2019 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 $0.20 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 Power's 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 U.N. 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 help 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.

Daniel J. Cregg -- Executive Vice President and Chief Financial Officer

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, 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. PES&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 $1.067 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 investment in Transmission and Distribution infrastructure and Distribution rate relief for the full quarter as new rates were put into effect on November 1, 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 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 had a $0.03 per share positive impact on net income compared to the year-earlier quarter. These positives were partially offset by $0.01 per share of higher depreciation expense on higher plant balances, $0.01 of higher interest expense on higher debt outstanding and higher taxes and other items that were $0.02 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 in 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 earning 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 cost to serve of $0.05 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 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 midyear 2019. Higher interest and depreciation expenses were offset by savings from retiree medical plan benefit changes that were implemented in 2019. And lower taxes improved non-GAAP operating earnings by $0.01 over the fourth 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 one 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 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 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 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 five 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. An update of Power's hedge position following the BGS auction in early February is provided on slide 27. PSEG Power is forecasting a decrease in output for both 2020 and 2021 to 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% 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 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 and Conemaugh, 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 three 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 $1.050 billion, respectively. Moving on to Enterprise and Other. For the fourth quarter of 2019, Enterprise and Other reported net income that increased by $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 2019 of $2 million, bringing 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 full year 2018. For 2020, Enterprise and Other is expected to produce a non-GAAP operating loss of $5 million, and this guidance reflects the 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 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 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. So 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 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.

Questions and Answers:

Operator

[Operator Instructions] Your first question comes from the line of Praful Mehta with Citigroup. Thanks so much. Hi, guys.

Ralph Izzo -- Chairman of the Board, President and Chief Executive Officer

Hi.

Praful Mehta -- Citigroup -- Analyst

Hi. So Ralph, on the PJM 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 the renewable mandates, 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?

Ralph Izzo -- Chairman of the Board, President and Chief Executive Officer

Yes. 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 capacity from carbon-free sources, 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 be New Jersey would have to have either a zonal or a 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 at 15%, 16%? If so, you're leaving behind a residual market that is protestingly 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 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 is that does experience some price depression, 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.

Daniel J. Cregg -- Executive Vice President and Chief Financial Officer

And Praful, just one thing to add. The 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.

Ralph Izzo -- Chairman of the Board, President and Chief Executive Officer

Yes. And you do know, Praful, I'm sure that the IMM numbers would suggest that our nuclear plant, should we choose to participate, would be certainly competitive.

Praful Mehta -- Citigroup -- Analyst

Right. No...

Daniel J. Cregg -- Executive Vice President and Chief Financial Officer

For capacity growth.

Praful Mehta -- Citigroup -- Analyst

Yes. 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 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 FERC that New Jersey can get together and kind of solve the problem from an FRR perspective?

Ralph Izzo -- Chairman of the Board, President and Chief Executive Officer

So remember, our capacity prices are set through 2022. So we have a little bit of time there. Depending upon whether or not FERC responds promptly to the March 18 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, right, because we're still working on the 2019 auction just yet, for the 2024 energy year as a 2021 auction. So New Jersey has a little bit of time. And in conversations with CEF, we believe, and we're hearing from CEF 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 for 2024. It won't be a walk in the park.

Praful Mehta -- Citigroup -- Analyst

Got it fair enough. I'll get back into you guys. Lots more questions for Thank you.

Operator

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

Julien Dumoulin-Smith -- Bank of America -- Analyst

Thank you. Good morning, Kim.

Ralph Izzo -- Chairman of the Board, President and Chief Executive Officer

Raise your hand.

Julien Dumoulin-Smith -- Bank of America -- Analyst

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 the MISO situation. And specifically with the 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.

Ralph Izzo -- Chairman of the Board, President and Chief Executive Officer

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 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 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 with that at 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 differential is now sort of being positive 20 or negative 3. So there's been a bunch of advantages associated with the 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 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 surmise what those rules might be in the form of a 205. So I'm proud of every dollar we 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, so.

Julien Dumoulin-Smith -- Bank of America -- Analyst

Indeed. And then, if I may, just to follow up on the sort of bridging the two conversations in power and utilities. Obviously, pressure across the market and then also a potentially 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 and all of this] in light of the latest asset sale, too.

Ralph Izzo -- Chairman of the Board, President and Chief Executive Officer

Yes. No, 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, yes, we do have lowered 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 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 hit some part of CEF and what the BPU is 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 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. 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 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 the 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 say something that's quite valuable at a discount price, and we're not going to let them do that.

Daniel J. Cregg -- Executive Vice President and Chief Financial Officer

Yes. And I think, Julien, 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. It's going to trend toward 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, have 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 is approved and is moving forward. And so it 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 a lot of gas pipe, gas 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. It's approved through 2023. So you see some drop-off on the lower end of that range for that reason.

Julien Dumoulin-Smith -- Bank of America -- Analyst

Thank you.

Operator

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

Jonathan Arnold -- Vertical Research -- Analyst

Guys.

Daniel J. Cregg -- Executive Vice President and Chief Financial Officer

Hey,John.

Jonathan Arnold -- Vertical Research -- Analyst

Thank you. 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. 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?

Daniel J. Cregg -- Executive Vice President and Chief Financial Officer

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, toward the end of those programs, you may see some of that come through. And usually, there's a little bit of capital that a capital adder as we move toward the rate case here just based upon ultimately pulling capital together. So those are the two things that would come to mind related to that.

Jonathan Arnold -- Vertical Research -- Analyst

Okay. And as I look the orange and blue bits, 23 particularly, had really increased a lot versus what you were showing us just recently. So...

Ralph Izzo -- Chairman of the Board, President and Chief Executive Officer

An AMI is above in the cross hatch recent, Jonathan.

Jonathan Arnold -- Vertical Research -- Analyst

Okay. So that's not what's driving it. And then just sort of generally, when I sort of try to design numbers underlying the slide with the slide rule, it seems that you're spending through 2023 is probably up $1 billion, maybe a little more. And but the rate base is more or less spending up in the same place. Am I on base with that observation or not quite?

Daniel J. Cregg -- Executive Vice President and Chief Financial Officer

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

Jonathan Arnold -- Vertical Research -- Analyst

Just if you look at what your slide implies in terms of the 2022-2023 kind of time frame rate base. Although you've had all 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.

Daniel J. Cregg -- Executive Vice President and Chief Financial Officer

2023 ends up in the same place as what?

Jonathan Arnold -- Vertical Research -- Analyst

Same as before.

Daniel J. Cregg -- Executive Vice President and Chief Financial Officer

How it was.

Ralph Izzo -- Chairman of the Board, President and Chief Executive Officer

We'll have that comparison...

Daniel J. Cregg -- Executive Vice President and Chief Financial Officer

Are you saying that as compared to...

Jonathan Arnold -- Vertical Research -- Analyst

Yes. I mean you would have to let me rephrase it. Has your 2023 vintage type of rate base forecast changed very much in aggregate once you have put all this together?

Daniel J. Cregg -- Executive Vice President and Chief Financial Officer

I think 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. So we can pull our slide rules together and kind of look through what's there. You're basically looking at what was a 7% to 8% increase off of 2019 versus a 6.5% at the lower end off of 2020, and you're seeing a 6% increase year-over-year. So net-net, that just becomes math.

Jonathan Arnold -- Vertical Research -- Analyst

Okay. So the destination does seem to be kind of not that different, not that...

Daniel J. Cregg -- Executive Vice President and Chief Financial Officer

Yes, I think that's fair, Jonathan.

Ralph Izzo -- Chairman of the Board, President and Chief Executive Officer

Yes, I don't think it's that different...

Daniel J. Cregg -- Executive Vice President and Chief Financial Officer

Yes. 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.

Jonathan Arnold -- Vertical Research -- Analyst

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

Daniel J. Cregg -- Executive Vice President and Chief Financial Officer

Oh, that Jonathan, that was from many years ago when we acquired a location in New York, which ultimately became the Bethlehem Energy Center. And we've built that. So I'm going to guess a couple of years to build that. It might have been in the 2001, 2002 time frame, 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. It was a fairly modest amount, but ultimately, it was just that accounting test as we went through it.

Jonathan Arnold -- Vertical Research -- Analyst

Okay. So it was none not one of your core assets. Okay.

Daniel J. Cregg -- Executive Vice President and Chief Financial Officer

Yes, noncash and relatively small amount.

Jonathan Arnold -- Vertical Research -- Analyst

Thank you.

Operator

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

Michael Lapides -- Goldman Sachs -- Analyst

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 2021 and '22 Transmission capex levels?

Daniel J. Cregg -- Executive Vice President and Chief Financial Officer

I would answer, generally, it's 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 run rate.

Michael Lapides -- Goldman Sachs -- Analyst

Okay. And the only reason why I asked 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 forecast were a couple of 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 spend, especially since the rollover seems to be occurring really next year, in 2021. Normally, it's kind of years three through five when you guys have forecast that out.

Ralph Izzo -- Chairman of the Board, President and Chief Executive Officer

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 PJM does with the RTEP. Much of the Transmission improvements now are end-of-life projects and 69kV upgrade projects. So the Susquehanna-Roseland type projects, the Northeast Carda 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.

Michael Lapides -- Goldman Sachs -- Analyst

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? Does that spin that's part of the ongoing dockets on the CEF that needs to get approved? And would I 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?

Ralph Izzo -- Chairman of the Board, President and Chief Executive Officer

Yes. So what so the BPU listed the moratorium, said, OK, based on some work that was done at Rockland Electric, and an independent consultant 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, OK, 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 2018. 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 pilot under the infrastructure improvement clause recovery mechanism. So I would think, I would hope that we 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.

Michael Lapides -- Goldman Sachs -- Analyst

Got it. And last question. Can you remind me on Energy Efficiency spend at PSE&G? How was that treated from an earnings perspective?

Ralph Izzo -- Chairman of the Board, President and Chief Executive Officer

Rate base 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 as a lost revenue component.

Michael Lapides -- Goldman Sachs -- Analyst

Got it. Thank you much appreciated, guys.

Operator

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

Paul Patterson -- Glenrock Associates -- Analyst

Good morning, how you doing?

Ralph Izzo -- Chairman of the Board, President and Chief Executive Officer

Hey, how you.

Paul Patterson -- Glenrock Associates -- Analyst

Just really quickly. Is there any reason to think that I mean, that there'd be a significant difference between the PJM's ACR values versus the IMM's?

Ralph Izzo -- Chairman of the Board, President and Chief Executive Officer

There's nothing that jumps out at us, Paul. They don't always agree, as you know, on either policy or their analysis. But there's nothing that jumps out at us at this moment right now.

Paul Patterson -- Glenrock Associates -- Analyst

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 how it would be selected, I guess?

Ralph Izzo -- Chairman of the Board, President and Chief Executive Officer

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.

Paul Patterson -- Glenrock Associates -- Analyst

Does that...

Daniel J. Cregg -- Executive Vice President and Chief Financial Officer

The state would provide information to PJM to ensure that they have actually met the requirements that they need to meet. So you can kind of 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 to particular types of units like a so you wouldn't get a megawatt per megawatt credit because it's not dispatchable. But I think that the details are to be determined.

Paul Patterson -- Glenrock Associates -- Analyst

So it would be it would basically one would normally think that it will 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?

Ralph Izzo -- Chairman of the Board, President and Chief Executive Officer

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 PJM. 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 PJM, but the 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 PJM right now has reserve margins that exceed its stated requirements. And presumably, if New Jersey just followed the PJM FRR requirements, that would be more akin to what they've traditionally said in the 16% range, not 20-plus percent range. And that's why I think there ought to be concerns about the residual market.

Paul Patterson -- Glenrock Associates -- Analyst

Absolutely. Okay. Thanks so much.

Ralph Izzo -- Chairman of the Board, President and Chief Executive Officer

Tiffany will take a final question.

Operator

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

Constantine -- Guggenheim Partners -- Analyst

Hi, morning. It's actually Constantine [Phonetic] here for sure.

Ralph Izzo -- Chairman of the Board, President and Chief Executive Officer

Hi, Constantine.

Constantine -- Guggenheim Partners -- Analyst

It's actually Constantine here for Shar. Just a quick one. We're kind of slipping 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, that 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 should we think about the trajectory overall? So the annual rate, I don't have it committed to memory, Constantine, but the $2.5 billion for 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 one will get spent in six months. But if we could commit it 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 all two million electric customers. Our gas system has got a fairly extensive amount of driveby 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 like 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 as the state wants to really aggressively pursue that 2021 target, we could do a lot more. And then electric vehicles is similar question of what is the appetite. We've proposed a $300 million program for a variety of different charging station infrastructure deployments. So in the aggregate, if we 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 in terms of once you get the approval and then are doing the deployment.

Daniel J. Cregg -- Executive Vice President and Chief Financial Officer

Yes. I think that deployment is going to run a few years by the time you roll it out to everybody. And 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 or 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 know, maybe three or four years or so, depending upon the pace. So it'll take a little bit of work through it all.

Constantine -- Guggenheim Partners -- Analyst

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 time line for making a commitment with orsted? And how are you positioning for any kind of future RFPs, New Jersey or otherwise?

Ralph Izzo -- Chairman of the Board, President and Chief Executive Officer

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.

Constantine -- Guggenheim Partners -- Analyst

Okay. That's very helpful. And kind of any way that you're thinking about kind of partnerships and structures going forward? Or is that a little too early to tell?

Ralph Izzo -- Chairman of the Board, President and Chief Executive Officer

Yes. I mean those discussions are under way with Orsted, and I'd rather not have a lengthy public conversation about that until we resolve that with our future partner.

Constantine -- Guggenheim Partners -- Analyst

That's very helpful. Thanks so much.

Operator

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

Ralph Izzo -- Chairman of the Board, President and Chief Executive Officer

Yes. So thank you for joining us today. And we will be on the road for 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 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 look forward to seeing you all on the road, and thank you for joining us today.

Operator

[Operator Closing Remarks]

Duration: 66 minutes

Call participants:

Carlotta N. Chan -- Senior Director, Investor Relations

Ralph Izzo -- Chairman of the Board, President and Chief Executive Officer

Daniel J. Cregg -- Executive Vice President and Chief Financial Officer

Praful Mehta -- Citigroup -- Analyst

Julien Dumoulin-Smith -- Bank of America -- Analyst

Jonathan Arnold -- Vertical Research -- Analyst

Michael Lapides -- Goldman Sachs -- Analyst

Paul Patterson -- Glenrock Associates -- Analyst

Constantine -- Guggenheim Partners -- Analyst

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