© 2024 Alpha Spread Limited. All Rights Reserved.
www.alphaspread.com is not operated by a broker, a dealer, or a registered investment adviser. Under no circumstances does any information posted on www.alphaspread.com represent a recommendation to buy or sell a security. The information on this site, and in its related newsletters, is not intended to be, nor does it constitute, investment advice or recommendations. The information on this site is in no way guaranteed for completeness, accuracy or in any other way. In no event shall Alpha Spread Limited be liable to any member, guest or third party for any damages of any kind arising out of the use of any content or other material published or available on www.alphaspread.com, or relating to the use of, or inability to use, www.alphaspread.com or any content, including, without limitation, any investment losses, lost profits, lost opportunity, special, incidental, indirect, consequential or punitive damages. Past performance is a poor indicator of future performance.
You don't have any saved screeners yet
Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
Ladies and gentlemen, thank you for standing by. My name is Maria, and I am your event operator today. I would like to welcome everyone to today's conference, Public Service Enterprise Group Second Quarter 2019 Earnings Conference Call and Webcast. [Operator Instructions].
As a reminder, this conference is being recorded today, July 30, 2019, and will be available for telephone replay beginning at 1 p.m. Eastern today until 11:30 p.m. Eastern on August 8, 2019. It will also be available as an audio webcast on PSEG's corporate website at www.pseg.com.
I would now like to turn the conference over to Carlotta Chan. Please go ahead.
Thank you, Maria. Good morning, and thank you for participating in our earnings call. PSEG's second quarter 2019 earnings release, attachments and slides detailing operating results by company are posted on our website at investor.pseg.com, and our 10-Q will be filed shortly. The earnings release and other matters discussed during today's call contain forward-looking statements and estimates that are subject to various risks and uncertainties. We also 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. We include reconciliations of our non-GAAP financial measures and the disclaimer regarding forward-looking statements on our IR website and in today's earnings materials.
I'll now turn the call over to Ralph Izzo, Chairman, President and Chief Executive Officer of PSEG. Joining Ralph on today's call is Dan Cregg, Executive Vice President and Chief Financial Officer. At the conclusion of their remarks, there will be time for your questions.
Thank you, Carlotta, and thank you all for joining us. PSEG reported non-GAAP operating earnings for the second quarter of 2019 of $0.58 per share versus $0.64 per share in last year's second quarter. PSEG's GAAP results for the second quarter were $0.30 per share compared with $0.53 per share in last year's second quarter.
Our results for the second quarter bring non-GAAP operating earnings for the first half of 2019 to $1.66 per share. This is a 3.1% increase over non-GAAP operating earnings of $1.61 per share for the first half of 2018 and reflects the growing contribution from our regulated operations. Earnings at PSE&G reflects the benefits of our continued investment in New Jersey's energy infrastructure and rate relief from the 2018 settlement of our distribution rate review. Slide 6 and 7 summarize the results for the quarter and the first half of 2019. We've had a constructive quarter with respect to several regulatory and policy matters that will advance our long-term strategy on several fronts. PSE&G has reached an agreement, in principle, with key parties in the Energy Strong II Infrastructure filing that will enable the continuation of increasing the resiliency and improving the reliability of critical energy infrastructure in New Jersey. PSE&G is working with the New Jersey Board of Public Utilities staff with Rate Counsel and other parties on finalizing a stipulation of settlement, which we will then submit to the New Jersey Board of Public Utilities for approval in September.
The agreement provides for $842 million of investment for projects that commence in the fourth quarter of this year and which are expected to be completed by December of 2023, providing an annual level of spend that is comparable to that of Energy Strong I. PSE&G would be eligible to recover $692 million on an accelerated basis, with the remaining $150 million recovered in a future rate case. The program is split $741 million to electric, which is approximately 1/2 of our requested amount, and $101 million to gas. PSE&G's original filing of the Energy Strong II Infrastructure plan outlined $2.5 billion of capital spend through the end of 2024, with $1.5 billion for electric infrastructure and $1 billion for gas infrastructure.
The energy efficiency component of PSE&G's Clean Energy Future filing, different from Energy Strong II, remains pending before the New Jersey Board of Public Utilities. We have reached an agreement in principle that extends the matter into 2020 in anticipation of finalization of the state's Energy Master Plan that authorizes in the interim PSE&G to continue work on four of its existing award-winning energy efficiency programs for an additional year. The clean energy filing is designed to achieve the electricity and gas energy savings goals outlined in 2018's Clean Energy Act, which requires the state utilities to implement energy efficiency programs to achieve annual savings of 2% and 0.75% for electric and gas usage, respectively. The agreement covering an extension of both the clean energy filing matter and the four existing energy efficiency programs will require New Jersey BPU approval.
With these recent updates, PSE&G remains on track to invest $2.7 billion in electric and gas infrastructure upgrades to its transmission and distribution facilities during 2019 to improve reliability and increase resiliency. We continue to forecast over 90% of PSEG's planned capital investment will be directed to the utility over the 2019 to 2023 time frame. Updating for the recent Energy Strong II agreement, PSE&G is narrowing its estimated capital spending range to $12 billion to $14.5 billion from what had been an estimate of $11 billion to $16 billion, which translates to a compound annual growth rate in rate base of 7.5% to 8.5% from the starting point of $19 billion at year-end 2018.
New Jersey continues to advance its Clean Energy Agenda and recently issued a draft Energy Master Plan to reach 100% clean energy by 2050. The Board of Public Utilities announced a total of six stakeholder meetings through early September and expects to finalize the draft Energy Master Plan in December. PSE&G believes our Clean Energy Future filings are aligned with the broad goals of the Energy Master Plan and notes the master plan's recognition of the benefits of electrifying transportation, energy storage and advanced meter infrastructure or smart meters and their importance to providing customers and utilities with essential information to facilitate energy efficiency and outage restoration. This type of data will accelerate service restoration times for customers during storms such as those we experienced last week in New Jersey.
Another part of Governor Murphy's Clean Energy Agenda includes the development of a robust offshore wind industry in the state. In June, the Board of Public Utilities awarded the first of three planned solicitations to Ørsted's 1,100-megawatt ocean wind project. We expect to make a decision on our option to pursue an equity interest in the ocean wind project in the coming months.
At PSEG Power, the BPU awarded Zero Emission Certificates, or ZECs, to Power's 3 New Jersey nuclear units on April 18 to help preserve the state's largest source of zero carbon generation. PSEG Power also completed its 1,800-megawatt combined cycle gas turbine construction program during the quarter, with the commercial operation of the Bridgeport Harbor 5 generating station in early June. In late June, PSEG Power announced the sale of its 776-megawatt interest in the Keystone and Conemaugh coal-fired generating units in Pennsylvania. The sale, expected to close later this year is subject to customary closing conditions and regulatory approvals, resulted in an after-tax impairment charge of $284 million that reduced net income in the second quarter. The transaction will allow us to dispose of a non-core asset and move PSEG Power closer to eliminating coal from its fuel mix. This process will be complete by mid-2021, when the Bridgeport Harbor 3 coal-fired generating plant is scheduled to be retired.
The sale announcement is part of the 2,400 megawatts of total coal-fired generation that PSEG Power will have either retired early or sold between 2017 and 2021, and further reduces the intensity of our carbon dioxide emissions. This move is on top of the fact that PSEG already has one of the lowest carbon emission rates among large U.S. power producers. PSEG Power's fleet has reduced its carbon emission intensity by more than 40% since 2005 and is about half the emission intensity compared to the country overall. This has been achieved by maintaining its nuclear units, investing in highly-efficient gas-powered generation units and renewables and exiting coal-fired generation assets.
As outlined during our May 29 investor conference of just a few months ago, PSEG continues to advance its climate strategy. Last week, we proactively established plans to reduce the carbon emissions of PSEG Power's generating fleet 80% by the year 2046 from 2005 levels, with a vision of net zero emissions by 2050. In support of these carbon reduction goals, PSEG also announced that it has no plans to build or acquire new fossil fuel power plants. However, we do plan to operate existing assets through their useful lives. PSEG also committed to reporting annually on sustainability and climate using the task force on climate related financial disclosures framework starting in 2020, which is when we will also issue our first climate report.
We continue to await a final order from the Federal Energy Regulatory Commission in their effort to reform the PJM capacity auction toward a just and reasonable construct. As I'm sure you know, on July 25, the FERC issued an order directing PJM to delay its August capacity auction until it can approve replacement auction rules. Given our second quarter results, we are affirming the full year forecast that PSEG's non-GAAP operating earnings at $3.15 to $3.35 per share. At the midpoint of our guidance, this represents over 4% growth in earnings over 2018's full year non-GAAP operating results of $3.12 per share. A higher percentage contribution from regulated earnings at PSE&G, which is approximately 75%, is driving this increase and offsetting challenging market conditions in the power and natural gas markets. And just as a reminder, our 2019 operating earnings guidance includes the benefits from a partial year of ZEC payments covering all three of our New Jersey nuclear plants.
I'd like to thank our employees for their tireless efforts to restore service to our customers in New Jersey who lost power as a result of severe storms last week. It's their commitment and ability to safely restore customers that continues to provide me with the confidence in our operating excellence model.
I'll 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.
Thank you, Ralph, and good morning, everyone. As Ralph said, PSEG reported non-GAAP operating earnings for the second quarter of 2019 of $0.58 per share versus $0.64 per share in last year's second quarter. We've provided you with information on Slide 11 regarding the contribution to non-GAAP operating earnings by business for the quarter, and Slide 12 contains a waterfall chart that takes you through the net changes quarter-over-quarter in non-GAAP operating earnings by major business.
And I'll now review each company in more detail starting with PSE&G. PSE&G, as shown on Slide 16, reported net income to the second quarter of 2019 of $0.45 per share compared with $0.46 per share for the second quarter of 2018. For the first half of the year, net income was $1.24 per share, up 13.8% from $1.09 earned in the first half of 2018. PSE&G's results were driven by rate relief and investments in transmission and distribution, offset by the reversal of the lower tax rate in the first quarter that resulted from the flowback to customers of excess deferred income taxes and by unfavorable weather that resulted in lower electric demand. As a reminder, we mentioned on the first quarter call that a positive P&L impact of the effective tax rate reflected in last quarter's earnings would largely reverse in this second quarter.
PSE&G's growth in transmission investment added $0.04 per share to quarter-over-quarter net income comparisons. Unfavorable weather lowered results by $0.01 per share as a result of a mild spring and a cool early summer. Gas margin improved quarter-over-quarter net income comparisons by $0.02, benefiting from the 2018 distribution rate case settlement as well as the remaining recovery of investments made under our first GSMP program. Electric margin was flat compared to the year-ago quarter as rate relief was offset by lower demand. Higher O&M expense reduced net income by $0.01 per share. And in addition, higher depreciation and interest expense reflecting the utility's expanded asset base each reduced net income by $0.01 per share versus the second quarter of 2018.
Nonoperating pension and OPEB added $0.01 per share versus the second quarter of 2018. And the effective flow through taxes in the second quarter of 2019 had a negative $0.04 per share impact on net income compared with last year's second quarter, reflecting the reversal of a benefit seen in the first quarter this year when the flowback of excess deferred taxes to customers had a larger impact on revenue and tax expense. Adjusting for this item, utility earnings for the second quarter would have been $0.49 per share, up 6.5% from last year's results of $0.46 per share in the second quarter.
Weather for the second quarter of this year was unfavorable compared with weather experienced during last year's second quarter. Heating degree days were 23% lower, but due to the gas weather normalization clause, weather did not impact gas results. Early summer weather was cooler, causing lower electric demand, but on a trailing 12-month basis which provides long-term trending data, weather-normalized electric and gas sales were both relatively flat. Residential electric and gas customer growth continues to trend higher at approximately 1% per year.
PSE&G is on track to invest $2.7 billion in electric and gas infrastructure upgrades to its transmission and distribution facilities during 2019 to maintain reliability and increase resiliency. We continue to forecast over 90% of PSEG's planned capital investment will be directed at the utility over the 2019 to 2023 time frame. And updating for the recent Energy Strong II agreement, PSE&G is narrowing its estimated capital spend range to $12 billion to $14.5 billion from $11 billion to $16 billion, which translates to a compounded annual growth rate of 7.5% to 8.5% from the starting point of $19 billion of year-end 2018 rate base. And we are maintaining our forecast of PSE&G's net income for 2019 of $1.2 billion to $1.230 billion.
Now moving to Power. Power reported non-GAAP operating earnings in the second quarter of $0.13 per share and non-GAAP adjusted EBITDA of $211 million. This compares to non-GAAP operating earnings of $0.16 per share and non-GAAP adjusted EBITDA of $210 million for the second quarter of 2018. Our non-GAAP adjusted EBITDA excludes the same items as our non-GAAP operating earnings measure as well as income tax expense, interest expense, depreciation and amortization expense.
The earnings release and Slide 20 provide you with detailed analysis of the items having an impact on PSEG Power's non-GAAP operating earnings relative to net income quarter-over-quarter. And we've also provided you with more detail on generation for the quarter and for the first half of 2019 on Slides 21 and 22.
PSEG Power's results for the second quarter reflected the anticipated step down in capacity prices in both PJM and ISO New England that lowered results by $0.01 per share compared with last year's second quarter. Recontracting and market impacts reduced results by $0.03 per share and this reflects an approximately $3 per megawatt hour decline in the average hedge price compared with the year-ago quarter and lower realized margins. PSEG Power's 3 New Jersey nuclear plants were awarded Zero Emission Certificates starting on April 18, which added $0.05 compared with the year-ago quarter. Volume increases versus the year-ago quarter added $0.01 per share, and gas operations were lower by $0.02 per share versus the year-ago quarter, reflecting the absence of a cold April 2018 and reduced off-systems sales on lower gas prices. Higher depreciation and higher interest expense together lowered net income comparisons by $0.04 per share versus the year-ago quarter, and taxes and other were $0.01 per share benefit over last year's second quarter.
Gross margin in the second quarter declined to $33 per megawatt hour from $34 per megawatt hour in the year-ago quarter. Power prices and natural gas prices were lower across PJM New York and Maryland, reflecting unseasonably mild weather that also depressed load. Weather-related weakness in demand pressured power prices lower and accelerated the price reduction compared with natural gas, which compressed spark spreads.
As I've mentioned, capacity revenues for the first five months of 2019 were positive compared with the same period in 2018. But starting June 1, Power's average capacity prices declined as we move into a new energy year on June 1. In PJM, prices declined from $205 to $116 per megawatt day. And in ISO New England, prices declined from $314 to $231 per megawatt day. These lower average prices will continue through the first five months of 2020. Bridgeport Harbor 5 began commercial operations in June and started receiving capacity payments of $231 per megawatt day for the unit's 485 megawatts, which is locked in on an escalating basis for seven years.
Now let's turn to PSEG Power's operations. Generation output increased by 0.8 terawatt hours to a total of 13.1 terawatt hours, driven by the addition of new combined cycle capacity compared with last year's second quarter. PSEG Power's combined cycle fleet produced 4.8 terawatt hours of output, up 36%, primarily from the benefit of a full quarter of production from Keys and Sewaren and the addition of Bridgeport Harbor 5 late in the second quarter.
Wholesale energy prices were affected by declines in the price of gas and weak demand, given the mild temperatures in the spring and early summer, which also limited the dispatch of older, less efficient combined cycles in an increasingly efficient PJM market. Lower spark spreads continue to pressure realized margins as infrastructure buildout in the Marcellus Shale region continues to erode Power's gas cost advantage and power prices fell more than gas prices.
Coal generated 1.2 terawatt hours, slightly down as a result of lower market demand, and Power's nuclear fleet operated at an average capacity factor of 84.4% for the quarter, producing 7.1 terawatt hours and representing 54% of total generation. Salem 1 completed its 26th refueling outage and returned to service in mid-June after completing the reactor bolt replacements we discussed last quarter. During the one month outage extension, Power's nuclear team successfully replaced 272 of the unit's 832 reactor vessel bolts. Over the next few operating cycles, PSEG Power plans to proactively address the remaining reactor vessel bolts identified for replacement at Salem 1 and Salem 2. That said, lower prices for power and natural gas as well as the expected sale of PSEG Power's interests in Keystone and Conemaugh have prompted a reduction in projected volumes for the remainder of 2019 as well as 2020 and 2021 from our previous 60 to 62 terawatt hours. The sale of Keystone and Conemaugh is expected to lower volumes by 1.2 terawatt hours in 2019 and by 5 terawatt hours in each of 2020 and 2021. And PSEG Power is now forecasting output for the remainder of 2019 of 30 to 32 terawatt hours and has hedged approximately 85% to 90% of production at an average price of $38 per megawatt hour.
For 2020, Power has hedged 65% to 70% of forecast production of 52 to 54 terawatt hours at an average price of $38 per megawatt hour. And Power is also forecasting output of 2021 of 52 to 54 terawatt hours, with approximately 25% to 30% of this output hedged at an average price of $39 per megawatt hour. The forecast for 2019 to 2021 volumes includes generation from recent additions of the three new combined cycle units, lower volumes from current market conditions and the announced sale of Keystone and Conemaugh. We continue to forecast Power's non-GAAP operating earnings for 2019 and non-GAAP adjusted EBITDA at $395 million to $460 million and $1.030 billion to $1.130 billion, respectively.
Now let me briefly address operating results for Enterprise and other. For the second quarter, we reported a net loss of $34 million or $0.07 per share compared to a net loss of $3 million or $0.01 per share for the second quarter of 2018. Non-GAAP operating loss for the second quarter of 2019 was $2 million compared to non-GAAP operating earnings of $11 million for the second quarter of 2018.
During the second quarter of 2019, Energy Holdings completed its annual review of the estimated residual values embedded in its leverage leases. An impairment of $32 million after-tax was recorded in net income as a result of the expected future adverse market conditions related to the residual value of the coal-fired Powerton unit lease. This compares with an impairment of $14 million after-tax related to liquidity challenges at NRG REMA in the year-ago quarter. Results of this quarter also reflect lower investment income at Energy Holdings related to the absence of a onetime gain last year as well as higher interest expense at the parent versus the year-ago period. For 2019, the forecast of PSEG Enterprise and other net income remains unchanged at $5 million to $10 million.
Our financial position remains strong. PSEG closed the quarter with $82 million of cash on the balance sheet and with debt at the end of June representing 52% of our consolidated capital, and debt at PSEG Power representing 32% of its capital at the end of the quarter. During the quarter, PSEG issued $715 million of five year senior notes at favorable interest rates and repaid $350 million of a term loan that matured in June of 2019. PSE&G issued a total of $750 million of 10 and 30 year secured medium-term notes at interest rates of 3.2% and 3.85% respectively and retired $250 million of maturing 1.8% medium-term notes. We continue to expect to fully fund PSEG's updated five year, $13 billion to $15.5 billion capital investment program over the 2019 to 2023 period without the need to issue new equity. And as Ralph mentioned, we continue to forecast non-GAAP operating earnings for the full year of $3.15 to $3.35 per share.
That concludes my remarks, and we are now ready to take your questions. Maria?
[Operator Instructions]. Our first question is from Praful Mehta of Citigroup.
So I guess the big move between last quarter and this quarter has been power prices in your power markets. So wanted to get a little bit more perspective on what you think has been the big driver that's driving this drop in pricing? And do you see this as more structural? Or do you see this as more onetime or short-term in nature?
Praful, so hard to answer that question, and we've heard everything that ranges from a move on the part of certain active participants in the market to fix a position issue that they had to the fact that there's no doubt that we are seeing limitations to the amount of infrastructure that can move gas to this region, and therefore, the potential for an oversupply of natural gas prices, keeping prices low, which is a continuation of the pattern we've seen over the past few years, right?
So you have new construction, low gas prices and that combines to low power prices in this market, and we see a little bit of relief in terms of the construction of pipeline capacity outside of our immediate region. That, of course, could, over the long term, give some support to gas prices in the region, which will help our nuclear plants. We still don't have the compliance filing from PJM on fast-start. That may help, but in theory, the forward price curve should have anticipated that already. I think given the level of candidly slow movement at FERC on things that range from capacity markets to the operating reserve demand curve, the market probably isn't pricing a lot in for some of these reforms.
So yes. So I think our answer is it's certainly not a temporary operation. There are some developments taking place in the market that are a combination of low gas, highly efficient combined cycle gas turbines that are creating a lower new normal. Whether or not $26 round-the-clock is the new normal, we're skeptical, but as is always the case, we run the company in accordance with the markets predicting and not any other point of view.
Got you. That's super helpful color. In that context then, does that change how you strategically look at the generation business in terms of like the whole spinoff and separation that at one time was on the table? Does that change your view in any way? Or is that still kind of keep the businesses together is still the focus?
No. So I think you can judge that question's answer by our actions, right? So you've seen us move on some "non-core assets." So we're pruning ourselves at Keystone, Conemaugh. You've seen us make sure that to the extent that we operate fossil units, we have a heat rate that's competitive and now with the addition of these three units, we're at a heat rate of just over 7,000 BTUs per kWh, even though the marginal heat rate in the area is closer to 9,000 or 10,000.
And the nuclear plants are really going to continue to operate as long as the state values those attributes. They are not in the money assets from a current market design, and it's only recognition of their carbon value that creates them as a viable market participant. So with all of that said, 90% of our investment is going to the utility and the ability of Power to generate a fairly healthy cash flow allows us to operate the combined entity without the need for any new equity. But however, you will see us continue to look at non-core assets the way we're looking at Keystone and Conemaugh.
Our next question comes from the line of Shahriar Pourreza of Guggenheim Partners.
So just on the stepdown of ES II from sort of what you've asked was, is there any sort of programs that were negotiated down? And curious if anything was eliminated or simply pushed out. And you're right in your prepared remarks the program is definitely comparable, but it seems like the prior program, ES I, supported more closely to the top end of your range, your prior range. So just trying to figure out what the delta is.
Sure. It's a good question. So the headline number of people reporting is light of what they expected and I respect that, it certainly is the case. But there are several things you have to look at beyond the headline number. First of all, we thought the program would be a five year program and as we've reported, this program is now scheduled to sunset at the end of 2020 surely. Secondly, the ask was for $1.5 billion in electric over that five year period, and we were granted $740 million of electric up until 2023. So that, depending on how you want to look at things, is at least 50% of the ask.
The big difference was really some policy daylight between us and the staff, and I'm going to defend the staff and defend ourselves at the same time at the risk of sounding hypocritical. We have seen, given the increased demand for natural gas in our region, electric generation is gas driven, residential customers are seeking more natural gas that whenever, and it's rare fortunately, but whenever there are issues with the interstate pipeline system is that we run into some operational challenges in terms of supplying natural gas to our customers. And candidly, there has been some fairly well-organized opposition to further construction of interstate pipelines into our region, right? So the new build that we're seeing in gas pipelines tends to be heading south of us much more than it is and directly into the Metropolitan New Jersey, New York region.
So we proposed a fairly large program that would deal with that issue, so that we would have a highly resilient gas distribution system and, candidly -- so we think that's a really good thing to do because even though we talk about lots of things around here, the number one thing our customers expect from us time and time again is reliability. Whether that's electric reliability or gas reliability, it's always reliability. And I think we proposed a very good program to enhance the reliability of our gas distribution system in the face of a limited new pipeline construction and the possibility of future operational challenges on the existing system.
And in light of all that the BPU staff believes they have on their hands in terms of demands on customer bills, not the least of which is our own gas system modernization program to replace an existing cast iron system and things like offshore wind and various other renewables targets that are included in solar expectations, they just did not have the appetite at this time to pay for what they do just more of an insurance program rather than a pressing operational correction such as Energy Strong II electric or gas system modernization.
So long-winded answer. Short answer is yes, there was a significant gas resiliency program that the staff simply did not want to do under a clause type recovery at this time, and that's understandable. We don't agree, but it's understandable.
Right. And just one follow-up, Ralph. As -- one of the strongest attributes of this story has always been about Power shrinking but PSE&G is growing, right? So our earnings mix is improving, we're getting more regulated. So as you sort of start to think about your current range, right, at your utility, are there items that we should be thinking about that could be incremental to your growth, not items that can sort of extend the runway but be incremental, but you're not ready to embed it in your plan?
Well. I feel like we're the only company with about 7.5% to 8.5% CAGR. We're growing fast, but I promised myself I wouldn't whine today and there I go, I'm going to catch it from this. No, look, one of the things that I'm sure you're interested in is that we have predicted a third quarter resolution of the Clean Energy Future filing and that's not a third quarter resolution anymore, right? We basically have a continuation of our programs which were over, so -- but that's not what that filing is about. I mean, whatever it is, $35 million a year program is not what we're trying to achieve there. And that is really a healthy, great conversation that we're having with people about where the state is heading, whether or not you put the cart before the horse. In this case, we think the cart is the Energy Master Plan and we were the horse and others think that the Energy Master Plan is the horse and our filing should be the cart. So don't look past that. I know that the future is what matters, but that is still a $3.5 billion filing that is a drop in the bucket from an electric vehicle point of view and from an energy efficiency point of view in terms of the overall market need.
Then there are other things, Shar, that we think about all the time and talk about all the time that we're just not ready to discuss publicly. I am not trying to create any false expectation there, but there are always other ideas that we have that would benefit the state of New Jersey and that relate to primarily electricity and the infrastructure needed to keep the state's economy and quality of life at an elevated level.
The number one gating function is not ideas, it is impact on the customer's bill, which is why you see us looking at a different part of the customer's share of wallet. And that's what's so important about the Clean Energy Future filing, is that we're going to ask customers to actually pay us less while we make more because we're going to be doing things for them that right now others do for them, and that's an important consideration.
And I think the only thing I'd add, Shar, is just, if you think about the Governor's agenda, everything he is trying to do from a clean energy perspective, there's an awful lot of things that are out there that I think provide opportunities, but I also think it's a matter of working through all those things. And it's been a pretty heavy agenda to date, and I think that's going to continue, but part of that is what you're seeing with respect to letting the Energy Master Plan run its course through the balance of the year and working our way through the clean energy filing.
Right. And I think that's one of the things that's being overlooked today.
Our next question comes from the line of Angie Storozynski of Macquarie.
So I have a longer term question. So you mentioned that you are planning to operate your other conventional power plants over their useful life, which I understand as no plans to sell your gas plants. But the new gas plants are -- and actually existing ones as well, seem to be exposed to not only oversupply of natural gas but also offshore wind. You have this potential equity investment in offshore wind in New Jersey but even without that, it seems like the Northeastern New Jersey and Maryland as well likely will get additional offshore wind capacity. So how do you see that growth in offshore wind installations vis-à-vis your existing conventional gas plants?
So Angie, I'm so glad you asked that question because that's an important clarification. I think if we had been more precise, we would have said that if we had retained our gas plants, then their natural evolution would've been an 80% reduction in carbon emissions by the year 2046. The only thing that is in our plans right now is to not acquire any new or build any new. We were not walking ourselves into the continued ownership of the gas plants for 2046. So that is a gap in our communication that I'm glad you exposed.
So the main thesis that we're trying to achieve here is to get an important seat at the table on what constitutes a net zero conversation by 2050. And there are two things that we think are really important. Number one, that there was a technology gap to getting to net zero as of today, and that technology gap needs to be fixed. And a way to fix that technology gap is by giving clear signals in the market that carbon matters, call that a national energy price, call that a PJM energy -- carbon price, call it what you want, but we think that the market has not unleashed its fully creative forces in the absence of that price. And we've got this fairly inefficient mechanism where people have ZECs and RECs and every other alphabet soup you can apply going on a state-by-state basis.
The second thing we want to expose is that we're going to greatly improve our carbon emission rate when we sell Keystone, Conemaugh. The planet doesn't care that we sell Keystone, Conemaugh. This planet is still going to run. So this notion of what is our carbon intensity is not necessarily going to strike at the physical reality that needs to be achieved in terms of carbon reduction emissions -- reductions. So all we were pointing out is if we just continue -- if we were to continue to run our gas plants as planned, then we would be 80% lower by 2046 than we are today. That does not mean that we will -- doesn't mean that we won't, but doesn't mean that we will retain all ownership of the plants before them. I don't know, Dan, if you want to add to that?
No. I think that distinction is exactly right. It's not reflecting an early closure; it's reflecting running them through their useful life. But ownership, certainly just like Key/Con, certainly could change as we step through time.
And despite the...
Just one follow-up. I understand, okay, so you're not trying to say that you will or won't retain the ownership, but I'm just thinking that does it play a role, that decision on the future ownership of these assets, into your decision on having an equity stake in that Ørsted project in New Jersey?
So the Ørsted project in New Jersey, as you know, came about as a result of us having an early role in a predecessor company to Ørsted, where we owned an offshore land -- an offshore lease and that was acquired by Ørsted and given the state's commitment to build offshore wind, I think, somebody help me, is the contract price public? I think it is. Is it not?
Yes.
Yes. At $98.10 a share starting in 2024 installation per megawatt hour, we believe that's an economically viable project and want to participate in a way that matches our skill set. Having said that, I can't even begin to tell you what I would do to get a $98 per megawatt hour contract for our nuclear plants or our gas plants. I mean, it's at least 3x above market, and that's a decision the state has made. And it will, as you, correct, it will factor into probably the earlier-than-normally planned retirement of some inefficient gas units. But the absence of storage technology, the absence of demand-side management controls through advanced metering infrastructure necessitates the need for ongoing natural gas dispatchable power. And to the extent that those units become marginal units and don't realize any value in the energy markets, then the capacity market design will be instrumental to the reliability of the grid.
So these are challenges that we pay attention to every day, and we try to have good conversations, and we do, with PJM and with FERC and with the state. But yes, 3,500 megawatts of zero marginal cost, highly-subsidized offshore wind is going to have a negative effect on less efficient gas plants. There's no question about that, and we will be mindful of that in making all of our investment decisions going forward.
But ownership potential within the offshore wind opportunity is not premised on ownership or lack thereof of gas plants onshore.
Our next question comes from the line of Christopher Turnure of JP Morgan.
I was wondering if you guys can just give us any thoughts you might have on the next steps at FERC for PJM reform and any constraints on the commission or constraints that they might be thinking about that might make them want to act faster?
Chris, sometimes, I wish that we could have 20% of the Q&A reserved for us to ask you folks questions because there are some mysteries that we would love to see unshrouded as well. I'm going to quote for you what I've heard quoted of Chairman Chatterjee that they are working on this every hour of every day, every day of the week and they understand the importance of it and they're not delaying the August auction. The August auction is already a four month delay from what should have been a May auction.
There is a point of view, I think, that is not unreasonable that says, okay, when you have four people, there's a chance for a two, two vote, when you have three, there's no such chance for a two, two vote. I guess, there's a chance for one, one, one vote, I don't know. And that perhaps, there is some philosophical logjam that can be broken now. I do believe there are comments recorded in the press so that was not the issue. So if it's resolved by middle of September, then I suspect that, that might have been the issue. If it takes longer than that, then I think it's this challenge that has been quoted coming out of the Chairman that on the one hand, how do you protect states' rights to choose and on the other hand how do you allow regional market to operate efficiently. We're of the point of view that the market wasn't broken to begin with, but if you want to fix it, the best route that we've seen is the current PJM proposal. But that was a really long-winded way of saying you really have no clue what's going on there right now other than what has publicly been revealed.
Chris, maybe just to add to that. It has been a very long time since they have ruled. They have had a proposal in front of them for a long -- in front of them for a long time, and yet, when you read the order there, the words and especially some of the consenting opinions reflected some urgency, yet we haven't seen anything. So I think the potential breaking of a logjam, I mean, having an odd number of commissioners manned up helping, and I think that from folks we've talked to, it seems that maybe something in September. If you marry up that urgency with the fact that nothing has happened to date, some thing has got to change and maybe just going through an odd number of commissioners will get us there. But I think there's more speculation than knowledge right now, and we'll wait to see what happens.
Okay. I appreciate the commentary there on a difficult question. And then certainly I think, both of you have talked a lot about the Energy Master Plan and the potential settlement agreements around gas investment and what this all means for the future of the state. But just a little bit more tactically, as the negotiations continue until a final version here, do you have a sense of kind of where parties stand and what direction that final version might head versus the draft?
Chris, unfortunately, those negotiations are confidential. I think it's not a breach of confidentiality to realize that New Jersey is one of the few states that does not have decoupling on the electric side, and we recommended a mechanism to achieve that and then this is a much, much bigger program, literally in order of magnitude bigger than anything we've done in the past. However, everything we've done in the past has been received with accolades and tremendous support. So I don't think I want to get into anymore detail than that, given the importance of respecting the confidentiality of what's been discussed around the table.
But on the EMP, in particular, there is a series of six hearings that are scheduled related to the EMP and I think some of those are, I want to say, August 8 and another one into September. So there will be two hearings on each of those days where you can at least get a sense as to where all the parties are coming out. But from a timing perspective, year-end for conclusion of that EMP is what's anticipated.
I guess, kind of, so far, no major pushback to speak of when it comes to the anti-gas direction that the EMP is going at.
From a Clean Energy Future filing? I'm confused. I'm sorry, Chris, I'm not grasping the full...
So I was referring more just to the Energy Master Plan and the finalization of that and kind of the direction that, that's going to go in versus the draft.
No, no, no. One should not construe the decision on our Energy Strong II filings as having anything to do with whether or not natural gas pipelines into the state are problematic for Clean Energy Future. I think, if anything, you can just look at GSMP II to realize that the importance of making sure that our current distribution system is not leaking and is in fact operating well as a recognition of the -- certainly the near-term, near-term being next few decades, importance of natural gas.
Our next question comes from the line of Greg Gordon of Evercore ISI.
Most of my questions have been answered, but I was just hoping maybe we can go back over the numbers on the proposed settlement on Energy Strong and be clear on sort of like an apples-to-apples basis where that proposed settlement is versus what the initial ask was? And then also, given the -- when is it that we now think the more rational expectation is of getting a Clean Energy Future decision? Is that now is going to, I guess, be sequenced behind the Energy Master Plan filing, so that was just your whole cart-horse, horse-cart question?
That's right. Correct.
And so how do we think about the timing of that and what milestone should we be looking at to get a sense of where we end up?
Okay. So let's do Energy Strong II first. To recall, we filed a $2.5 billion program over five years. Typically, these programs take about one year to resolve, so we are close to that one year mark coming up. And that request was $1.5 billion on electric and $1 billion on natural gas. And what we received was a program that we expect to see approved in September of this year, that will only run until December of '23 and of the $1.5 billion in electric, $741 million of that was approved. But importantly, just about every program that was asked for was approved, just not the dollar amount. So the prudency of the programs, I think, we feel really good about.
Conversely on the natural gas component, of the $1 billion that was requested, most of that, about $800 million of that was for this notion of resiliency of the distribution system. Basically more interconnections between our distribution pipes. And the -- then there was about $200 million in reinforcing some of our measurement, metering and regulating stations. And half of that smaller piece was approved, $100 million. So electric $740 million out of $1.5 billion; gas, $100 million out of $1 billion. A December '23 end date versus a five year program. And that ends up yielding an annual run rate that's about 10% less than the annual run rate of Energy Strong I.
On Clean Energy Future, the Energy Master Plan is scheduled to be finalized this December, end of the year, and a draft was issued already and the stakeholder hearings are already scheduled. So there should be no reason why the board can't complete that work by the end of the year. And then you may recall that the Clean Energy Act of May of 2018 had a requirement that rules be promulgated on the energy efficiency programs within a year, so we're late there. That year lapsed three months ago. So we are understanding of the full range of issues on the BPU staff plate, so we are expecting resolution of our filing early in 2020.
Our next question comes from the line of Travis Miller of Morningstar.
If I can go back real quick to that whole net zero concept and the vision there. I'm just wondering, one, does net zero means zero, such that by that -- through that vision, you wouldn't have any fossil fuel in your fleet at least? And then to more of the visionary aspect, do those plants even exist? Even if you don't own them, do you think they exist in a market where in an environment where we see a lot of the region going to kind of this idea of zero by 2050?
Yes, so Travis, so I apologize for repeating perhaps something I said before. One of the reasons why we made that commitment is because we want to engage actively in the discussion around net zero, because there is nobody who owns the definition of net zero. Typically, it refers to generation and the reason why the word net is inserted is that if you are still emitting carbon but you then come up with a way to extract carbon from the atmosphere, then your net effect is zero, right? So you're putting a ton of carbon into the air and you extract it by planting trees or coming up with some method to extract carbon dioxide and dissolving it in the ocean or something of that sort. That's typically what people refer to.
We think that, that is not what -- is not the full breadth of what matters to the planet. And you used a great example just a second ago, right? So if we won accolades for reducing our carbon footprint, but all we've done is sell the plant to somebody else who is still running it, the planet doesn't care about that. By same token, if we get approval of a multi-billion dollar clean energy filing and people use less energy, we don't get credit for that, we think we should. If we electrify transportation, we don't get credit for that, we think we should.
So we're just trying to remind people that the subject is complicated and never lose sight of what problem it is you're trying to solve whenever you engage in these policy discussions because sometimes we forget what problem we're trying to solve and we do crazy things like put production tax credits in place that produce negative marginal cost and put pressure on nuclear plants to retire. So there is no unique ownership of the term net zero, but typically speaking, nowadays, it refers to both the simultaneous production and removal of carbon dioxide from the atmosphere.
Okay. Yes, that's clear. So you do think there is a place for fossil fuel and the net zero or this is, kind of, zero-ish concept?
No, no. That's right. We do. I mean, carbon capture and storage would allow for fossil fuels to continue to operate.
Our next question comes from the line of Michael Lapides of Goldman Sachs.
[Technical Difficulty] Conemaugh sale deal, view that as accretive or dilutive or kind of neutral to EPS?
I think you cut out there in the beginning, but I think your question was, is the Keystone, Conemaugh sale accretive or dilutive. I think for '19, it doesn't really move the needle at all. And as we step forward, we would see some mild benefit.
Got it. And just trying to kind of think to the puts and takes of that, how material is the O&M and kind of what's the book value that you had prior to the write down? I'm just trying to think about backing out O&M and D&A, just to kind of think about the accretion impact of this?
Yes, I don't think we've had a separate disclosure of the O&M, but the book value was on the order of about $400 million or so.
Got it. Prior to the write down. Okay. And then one last thing. When you think about you need potential portfolio additions, including offshore wind, do you look at it and say, hey, we'd like to have a controlling position or we'd like to have an operating position, just given your history as a pretty strong operator of plants? Or are you willing to be a minority owner?
Yes. We're definitely willing to be a minority owner, it's something that's new to us, where we don't have that operating experience.
And Mr. Izzo and Mr. Cregg, at this time, we do not have any time for any further questions. I will turn the call back over to you for closing remarks.
Thank you, Maria. So thanks, everyone, for joining us today. I know that Dan and Carlotta and I have a bunch of plans to be on the road to visit with many of you, and we look forward to that. And we hope you enjoy the rest of the summer. Thanks for joining us.
Ladies and gentlemen, that does conclude the conference call for today. You may now disconnect. Thank you for your participation.