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Public Service Enterprise Group Inc (PEG 0.32%)
Q3Â 2018 Earnings Conference Call
Oct. 30, 2018, 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 Natalia, and I am your event operator today. I would like to welcome everyone to today's conference, Public Service Enterprise Group Third Quarter 2018 Earnings Conference Call and Webcast. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session for members of the financial community. (Operator Instructions) As a reminder, this conference is being recorded, Tuesday, October 30, 2018, and will be available for telephone replay beginning at 1:00 p.m. Eastern today until 11: 30 p.m. Eastern on Thursday, November 8, 2018. 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 Chan -- Head of Investor Relations
Thank you, Natalia. Good morning and thank you for participating in our earnings call. Earlier today PSEG released earnings statements for the third quarter of 2018. These materials including the release attachments and accompanying slides detailing operating results by company are posted on the IR website at investor.pseg.com. Our 10-Q for the period ended September 30, 2018, will be filed shortly.
The earnings release and other matters we will discuss during today's call contains forward-looking statements and estimates that are subject to various risks and uncertainties. We will 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 are included in today's slides and in our earnings release.
I would now like to turn the call over to Ralph Izzo, Chairman, President and Chief Operating Officer (ph) of Public Service Enterprise Group. Joining Ralph on the 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?
Ralph Izzo -- Chairman of the Board, President & Chief Executive Officer
Thank you Carlotta, and thank you all for joining us today.
PSEG reported solid results for the third quarter and through nine months. We are updating full year non-GAAP operating earnings guidance by narrowing the range to $3.05 to $3.15 per share, with an increased contribution from PSE&G, balancing lower expected results at PSEG Power and the Parent. The midpoint of our guidance remains unchanged and continues to represent a 6% increase above 2017 full year results.
This morning we reported net income for the third quarter of $0.81 per share, and non-GAAP operating earnings of $0.95 per share versus net income of $0.78 per share, and non-GAAP operating earnings of $0.82 per share in the year-ago period. Third quarter net income and non-GAAP operating earnings improved by 4% and 16% respectively over 2017's third quarter comparables. Our results for the quarter bring non-GAAP operating earnings for the nine months to $2.56 per share, an 8% increase over the $2.36 per share earned in the nine months ended September 30, 2017.
Slides six and seven summarize the results for the quarter and the year-to-date periods. The threat of very hot summer, both PSE&G and Power performed well. Therefore our financial results reflect solid contributions from both businesses. PSE&G's earnings increased by $0.05 per share, up 10% over third quarter 2017 results, driven primarily by continued investment in transmission and distribution programs, focused on increasing system resiliency and reliability. Warmer than normal weather increased electric demand for air conditions throughout an extended summer that was the second hottest in nearly half a century. Expanded investment in transmission and distribution infrastructure continues to benefit customers and have a favorable impact on PSE&G's rate base and earnings.
We are on pace to spend $2.8 billion for the year and the utility's rate base is forecasted to grow to almost $19 billion at year-end. Based on our various investment programs, we remain comfortable with PSE&G's ability to achieve growth in rate base within our forecasted 8% to 10% per year for the 5-year period ending in 2022. We have made significant progress to date in our regulatory and policy partnerships. PSE&G recently filed several Clean Energy Future investment programs totaling $3.6 billion over six years. These filings continue the alignment of PSE&G's capital investment plans with New Jersey's energy policy goals by advancing a broad range of programs in Energy Efficiency, Electric Vehicle Infrastructure and Energy Storage. The inclusion of what we are calling Energy Cloud or AMI is consistent with the BPU's recommendations for improving storm response following the March 2018 nor'easters in which they directed each utility to submit a plan and cost benefit analysis for the implementation of AMI, focusing on reducing customer outages and outage duration.
PSE&G's filing is designed to create an advanced technology network and upgrade 2.2 million electric meters to smart meters by the year 2024. In addition, Energy Strong II, the proposed $2.5 billion 5-year extension of our infrastructure reliability and resiliency investment program is pending at the BPU. Inclusive of the AMI initiative, PSE&G's 2018 to 2022 capital spending forecast range is $12 billion to $16 billion.
I now want to bring up-to-date on PSE&G's distribution base rate case proceeding. As you may be aware at its regular meeting yesterday, the New Jersey Board of Public Utilities approved the settlement agreement between PSE&G, BPU staff and Rate Counsel. This concludes the utility's first distribution rate review since 2010, and is expected to provide PSE&G's customers with rate stability while allowing us to achieve three important outcomes: First, to recover investments made outside of clause mechanisms since 2010; second, to recover deferred storm costs; and third, to set revenues which reflect our current sales and O&M levels.
The terms of the agreement provides for an additional $212 million in annual revenue, and a flow back to customers of $225 million in tax savings largely due to tax reform, resulting in a net $13 million revenue reduction. When new distribution rates go into effect on November 1, a typical combined residential customer build will be at levels that are 30% lower than they paid in 2008 in nominal terms and 40% lower in real terms.
The updated revenue requirements based upon the distribution rate base of $9.5 billion, a return on equity of 9.6% and a 54% equity ratio, all of PSE&G's distribution investment programs will adopt the new ROE of 9.6% and equity percentage of 54% going forward. PSE&G's decoupling proposal was not adopted in the settlement. Decoupling of electric and gas distribution revenue from sales volumes and demands remains an essential element of larger scale energy efficiency investments. New Jersey's energy efficiency savings goals outlined in legislation passed last May require utilities to reduce customers annual electric and gas consumption by 2% and 0.75% respectively, and also provides for lost revenue recovery. We refiled our decoupling proposal as part of our Clean Energy Future filings, but we are open to other forms of timely loss revenue recovery.
Now let me turn my attention to PSEG Power. The Power's non-GAAP operating earnings increased 23% to $0.39 per share over 2017's third quarter comparable results, largely reflecting its lower corporate income tax rate and other tax benefits as well as a step up in capacity pricing this past June that will extend through May of 2019.
Despite favorable weather, higher natural gas prices, prices rose more than electric prices, which negatively impacted Power's results. These changes in market conditions have contributed to a reduction in Power's expected 2018 non-GAAP operating earnings. Power continues to anticipate completion of its combined cycle gas turbine construction program with Bridgeport Harbor 5 expected online in 2019. Moreover, the addition of 1,300 megawatts of highly efficient capacity at Keys and Sewaren 7 earlier this year, leads the reconfiguration of Power's merchant suite as demonstrated by this quarter's CCGT production. The design of wholesale energy and capacity markets and with the current policies and mechanisms provide adequate recognition of the cost per generation to be available, continues to attract needed attention. We are proactively engaged with the Federal Energy Regulatory Commission and PJM on several fronts. PJM energy price formation proposals continue to be evaluated as part of a comprehensive solution to the challenges facing baseload units. FERC is expected to issue an order by year end on its pending fast start proceeding and PJM anticipates implementation in 2019. We await other price reform filings at PJM such as the operating reserve demand curve enhancements and the spending reserves. But we don't expect PJM will reprioritize those efforts until after it implements fast start. Getting energy prices right is critical to ensuring efficient investment and market exit for generation assets.
Power continues advancing efforts to preserve its nuclear asset base. The BPU has begun implementation of New Jersey's Zero Emissions credits law signed by Governor Murphy this past May. We recently filed comments and responses to the BPU on the application and selection process for the New Jersey's ZEC as we refer to them. The BPU held three public hearings early in October, and an order establishing the ZEC application process is expected in November. In December, Power anticipates submitting applications for all three of its New Jersey nuclear plants, and we'll make the certification that the units will shut down within three years in the absence of a material financial change.
In June 2018 FERC issued an order of finding that PJM's current capacity market is unjust and unreasonable and establish the proceeding to evaluate potential reforms. PSEG submitted comments in early October recommending the status quo remain in place. Within the alternatives, we support PJM's capacity redesign proposals of a minimum offer price rule with few or no exemptions, which is consistent with FERC's direction and the resource carve-out option for supported resources subject to the MOPR.
The ZEC law recognize that energy and capacity payments are now -- again I'm referring to the New Jersey's ZEC law, were not sufficient to compensate nuclear units for the carbon attributes they provide, and that ZEC were additive to energy and capacity payments. We have initiated discussions on how the state can put in place a structure under existing laws to support nuclear resources in a redesigned PJM capacity market using the existing BGS mechanism. We continue to believe that this option requires no new legislation, and equally importantly places no additional burdens on customers. We will continue to advocate our views to establish a market design that satisfies FERC and that accommodates state interest in resource procurement with key attributes, while ensuring that price suppression is addressed.
A strong legal foundation has been established for state action to preserve generating assets critical to meeting a state's initial and related goals. New York and Illinois have recently received appellate court affirmations from the Second and Seventh Circuit Court of Appeals, respectively, concluding that those states have the authority to implement their ZEC program setting a positive legal precedent for New Jersey. We remain focused on the successful execution of our key policy and regulatory initiatives to provide our shareholders with greater assurance of PSEG's ability to meet our financial objectives for returns and growth. PSEG continues to perform at high levels, safely operating the system throughout a very hot summer, which is a testament to the dedication of our 13,000 associates in New Jersey, New York, Maryland and Connecticut.
With that, I will turn the call over to Dan to discuss our financial results in greater detail, and I'll rejoin for your questions after he is finished.
Daniel Cregg -- Executive Vice President And Chief Financial Officer
Great. Thank you, Ralph and thank you everyone for joining us on the call today.
As Ralph said, PSEG reported net income for the third quarter of 2018 of $0.81 per share, and that's versus net income of $0.78 per share in the last year's third quarter. Non-GAAP operating earnings for the third quarter of 2018 were $0.95 per share versus non-GAAP operating earnings of $0.82 per share in last year's third quarter. And reconciliation of non-GAAP operating earnings to net income for the quarter and nine months can be found on slides six and seven.
We've also provided you with a waterfall chart on slide 11 that takes you through the net changes in quarter-over-quarter non-GAAP operating earnings by each business, and a similar chart on slide 13 provides you with the changes in non-GAAP operating earnings by each business on a year-to-date basis. And I'll now review each company in more detail, starting with PSE&G.
PSE&G reported net income of $0.54 per share for the third quarter of 2018, that's compared with $0.49 per share for the third quarter of 2017. Results for the quarter are shown on slide 15. Net income growth in the third quarter was driven by continued investment in transmission and electric and gas distribution facilities, as well as the impact on sales of weather conditions which were substantially warmer than both the year-ago quarter as well as normal conditions.
Returns on PSE&G's expanded investment in transmission added $0.02 per share to net income in the quarter. Incremental revenue associated with recovery of PSE&G's Energy Strong and the Gas System Modernization Program added $0.02 per share. Favorable weather comparisons year-over-year added $0.03 per share, and higher volume and demand added $0.01 per share. Changes to the accounting treatment of the nonservice component of pension and other post-retirement benefits or OPEB expenses, resulting in a favorable $0.02. And these positive items were partially offset by an increase in operating and maintenance expense of $0.02 per share, driven by higher corrective maintenance work, higher depreciation expense of $0.02 per share reflecting higher plant balances and higher interest taxes and other of $0.01 per share.
As Ralph mentioned, electric sales reacted favorably to hot summer weather, and actual sales increased by 6% over 2017's mild third quarter. The THI or temperature-humidity index was 35% greater than in the year-ago quarter, and 25% warmer than normal. PSE&G reached the 2018 system peak of 9,978 megawatts compared to 2017 system peak of 9,567 megawatts. On a trailing 12-month basis, weather normalized electric sales were flat year-over-year. And gas sales on a similar basis increased 1.9%, led by the commercial sector and strong second quarter results.
The conclusion of PSE&G's distribution rate review achieved several regulatory priorities, mainly the recovery of non-investments made since 2010 outside of the programs with cost base recovery. In addition to the recovery of deferred storm cost dating back to 2011 and a true-up of sales end cost estimates. New rates are based upon the distribution rate base of $9.5 billion, a return on equity of 9.6% and a 54% equity ratio. We are pleased that the settlement recognized the need to maintain solid utility credit metrics, following the negative cash impacts that resulted from tax reform in 2017 as PSE&G's financial flexibility is essential to providing reliable service at the lowest cost. Going forward, PSE&G's distribution investment programs will adopt a new ROE rate and equity percentage established in the settlement agreement. As Ralph mentioned, the net $13 million revenue reduction takes into account an additional $212 million in annual revenues, including storm cost recovery and an increase in depreciation expense, as well as a flow back to customers of $225 million in tax savings, largely due to tax reform. PSE&G customers will benefit from $262 million in annualized rate reductions to reflect savings from federal tax reform enacted in 2017.
PSE&G filed two updates earlier this month to its Formula Rate for transmission at the Federal Energy Regulatory Commission. The first was an annual update reflecting our planned capital improvements with a focus on system reliability, and that provides for a $100 million increase in annual transmission revenues. The second filing adjusts our Formula Rate to provide a refund of our excess deferred income taxes due to federal tax reform, resulting in a refund of over $150 million. Both of these changes are expected to be effective January 1, 2019.
Our distribution infrastructure programs, Energy Strong and GSMP continue to perform as expected. The combined annual revenue increase for the full year 2018 from these two programs is forecasted to be approximately $53 million as we near completion of the first GSMP in Energy Strong programs. Once GSMP II begins, gas rates will adjust in December and June of each year. PSE&G has invested approximately $2.3 billion for the nine months ended September 30 in electric and gas distribution and transmission capital projects. For the full year, PSE&G expects to invest approximately $2.8 billion on increasing system reliability and resiliency, upgrading critical infrastructure, and supporting New Jersey's energy policy goals. We continue to expect rate base growth at a CAGR of 8% to 10% over the 2018 to 2022 period. For the full year we've increased PSE&G's forecast of net income for 2018 to reflect the impact of higher sales margins largely due to weather with the range now forecast to be $1,055 million to $1,070 million, up from a $1 billion to $1,030 million.
Now let's turn to Power. PSEG Power reported net income of $125 million or $0.25 per share for the third quarter of 2018 compared with net income of $136 million or $0.27 per share in the year-ago quarter. Non-GAAP operating earnings were $0.39 per share for the third quarter of 2018 compared to non-GAAP operating earnings for the third quarter of 2017 of $0.31 per share. Non-GAAP adjusted EBITDA for the third quarter of 2018 was $360 million versus non-GAAP adjusted EBITDA for 2017 of $356 million. Non-GAAP adjusted EBITDA excludes the same items as on non-GAAP operating earnings measure as well as income tax expense, interest expense and depreciation and amortization.
The earnings release and slide 21 provide you with detailed analysis of the impact of Power's non-GAAP operating earnings quarter-over-quarter. We've also provided you with more detail on generation for the quarter and the first nine months of the year on slides 22 and 23. Power's net income in the third quarter was impacted by a decline in average energy hedged prices and lower realized margins despite the effect of warmer-than-normal weather on demand and output. During the quarter, non-GAAP operating earnings comparisons increased $0.05 per share as a result of the higher capacity prices in New England and PJM. The increase in capacity prices occurred on June 1, 2018, and will run through May 31st of next year.
Recontracting of hedges at lower prices and the market impact of lower spark spreads in PJM East reduced results by $0.10 per share compared with the third quarter of 2017. Power experienced a $7 per megawatt hour decline in its average hedged energy price during the third quarter, which is consistent with our expectations for the full year. The impact of placing the Keys and Sewaren combined cycle stations and service along with higher demand boosted generation volumes by $0.06 per share. Higher O&M expense of $0.01 per share reflects new units start up expenses at Keys and Sewaren, and higher depreciation of $0.02 per share and a higher interest expense of $0.02 per share, both relate to the new combined cycle units placed in service versus a year-ago quarter. And these impacts will continue to affect year-over-year comparisons in coming quarters given the in-service of Keys, Sewaren and ultimately Bridgeport Harbor 5 next year.
A reduction in the corporate tax rate from federal tax reform combined with the impact of less taxes due to year-over-year from lower pre-tax income, improved net income comparisons by $0.07 per share. The anticipated benefit from the remeasurement of tax reserves associated with the nuclear carryback claim and the closure of IRS audits for the year 2011 and 2012 added $0.06 per share compared to year earlier results. These tax benefits were slightly offset by a $0.01 per share impact related to a newly enacted New Jersey surtax.
Now let's turn to Power's operations. Output of Power's generating stations increased 24% in the quarter, reflecting the higher output of the combined cycle fleet with Keys and Sewaren in commercial operation. Power's gas-fired combined cycle fleet operated at an average capacity factor of 68% and produced 7 terawatt hours of output during the third quarter of 2018, up by 88% over the year-ago quarter, primarily reflecting the production of the two new units. Pennsylvania coal generation output also improved to 1.3 terawatt hours and operated at 79% capacity factor in the quarter. For the year-to-date period, Power's nuclear fleet operated at an average capacity factor of 93%, producing 23.7 terawatt hours and representing 57% of Power's total generation.
Gas prices improved in the third quarter on low storage levels and weather-driven demand, but Power prices didn't move up in conjunction with gas putting pressure on Power's spark spreads. Power's forecast of total output for 2018 has been raised modestly to 54 terawatt hours to 56 terawatt hours from last quarter's reduced estimate of 53 terawatt hours to 55 terawatt hours. For the remainder of 2018, Power has hedged 80% to 85% of total forecasted production of 13 terawatt hours to 15 terawatt hours at an average price of $37 per megawatt hour. For 2019, Power has hedged 70% to 75% of forecasted production of 58 terawatt hours to 60 terawatt hours at an average price of $36 per megawatt hour. For 2020, Power has hedged 40% to 45% of output forecasted to be 62 terawatt hours to 64 terawatt hours at an average price of $36 per megawatt hour. The forecasted output for 2018 to 2020 includes generation associated with Keys and Sewaren, as well as the mid-'19 commercial start-up of the 485 megawatt gas powered combined cycle units at Bridgeport Harbor.
In addition, Power has decided to exit the retail electric marketing business after determining it would not provide a material enhancement to its hedging activity. Power has therefore ceased taking on new customers but will continue to meet all obligations to existing customers through the end of their contracts. Our forecast of Power's non-GAAP operating earnings for 2018 and non-GAAP adjusted EBITDA has been updated to $465 million to $500 million, and $1,045 million to $1,100 million respectively, from $485 million to $560 million, and $1,075 million to $1,180 million
respectively.
Now turning to PSEG Enterprise and other. Reported net income of $9 million or $0.02 per share for the third quarter of 2018 compared to net income of $13 million or $0.02 per share for the third quarter of 2017. The decrease in net income year-over-year reflects higher interest expense at the Parent, partially offset by lower taxes and other items. The forecast of PSEG Enterprise and other's full year 2018 non-GAAP operating earnings has been reduced to $25 million from $35 million reflecting those higher interest costs.
PSEG closed the quarter ended September 30th with $88 million of cash on its balance sheet with debt at the end of the quarter representing approximately 51% of consolidated capital. And Power's debt at the end of the quarter represented 34% of capital. In September, PSE&G issued $325 million of five-year 3.25% medium term notes and $325 million of 10-year 3.65% medium term notes. And PSE&G also retired $315 million of 2.3% medium term notes at maturity. And as Ralph mentioned, we narrowed our guidance for full year 2018 non-GAAP operating earnings to $3.05 to $3.15 per share, while maintaining the midpoint of guidance at $3.10 per share.
And with that, Natalia, we are now ready to take questions.
Questions and Answers:
Operator
Ladies and gentlemen, we will now begin the question-and-answer session for members of the financial community. (Operator Instructions) And your first question is from the line of Praful Mehta from Citigroup.
Praful Mehta -- Citigroup Inc -- Analyst
Hi guys.
Ralph Izzo -- Chairman of the Board, President & Chief Executive Officer
Hi, Praful.
Praful Mehta -- Citigroup Inc -- Analyst
Hi. So may be a specific question on the quarter for us and then we'll get to all the market reforms that taking place. But starting with slide 24 where you highlight gas prices went up and that's what pushed up your fuel costs. I wanted to understand why that didn't drive up Power prices as well? I mean, really that implies some reduction in the stock spread and wanted to understand why heat rates has been coming down? So some color on that that would be helpful.
Ralph Izzo -- Chairman of the Board, President & Chief Executive Officer
Right. So there is a strong correlation, obviously, Praful, between gas and electric prices, but it's not perfect. One can only assume that there was some dispatching of coal that took place that keep a little bit of lid on those power prices from moving perfectly in tandem. Dan, I don't know if you want to add to that?
Daniel Cregg -- Executive Vice President And Chief Financial Officer
Yeah. I also think that the sourcing of gas matters as well and Leidy has been a very low cost source of gas for us and we saw a little bit of an uptick in Leidy prices, and Leidy doesn't necessarily drive all of the electric prices that we end up seeing. So depending upon what units are running, where the source of the gas is, you can see some different gas prices coming through. And I think the magnitude of gas that was used during the summer for gas generation as well as coming out of a winter where storage levels were low, it pushed gas up a little bit more for some of our units compared to what we saw from an electric pricing standpoint.
Praful Mehta -- Citigroup Inc -- Analyst
Got you. That's helpful. And so do you see this as a permanent kind of issue or is this something that happened more this quarter but it's not more of a permanent issue?
Ralph Izzo -- Chairman of the Board, President & Chief Executive Officer
We never tried out just before the price curve, Praful, but we are seeing that with the opening of some pipelines that are taking Marcellus gas to regions other than the Eastern region that the basis differential between Leidy and Henry Hub is changing with prices coming up in the region. Stronger pricing in M3, and if you believe historic correlations that should ultimately be reflected in Power prices, but -- and forward curve is predicting -- whatever it's predicting right now.
Praful Mehta -- Citigroup Inc -- Analyst
Got you. Understood. And then quickly just going onto the market reform side, especially around capacity prices and capacity reforms, given all the different proposals out there, Ralph, where do you see capacity -- this whole capacity reform process going? Do you see any downside risk to capacity prices through all this? And how do you see the BGS auction kind of fitting in from a legal perspective?
Ralph Izzo -- Chairman of the Board, President & Chief Executive Officer
So again, what we keep anchoring ourselves to is what FERC has filed in terms of their policy objectives, which is, A, to remove price suppression; and B, to allow states to do what they want to from a point of view of resource designation. As I think I mentioned, our preference is the status quo but not withstanding an ability to preserve that status quo we think that PJM's offer an intelligent alternative. There are some things we would quarrel with perhaps their cutoff at the 20 megawatt level versus FERC's guidance that any at all subsidized units should be subject to reform. But if you look at the approach PJM has suggested, it does point to higher capacity prices for unsubsidized units, all other things being equal. And as you know, Praful, there are many other factors to consider. There's transmission transport capability, there's demand management, there is how different local delivery areas breakout, but nonetheless when you remove supply, which is what PJM is proposing to do, from the setting of price, that should -- that without changing demand, as I said, all the things being equal, that should remove the price suppression for unsubsidized units. And that will set a different market price. I partially just see how that will be a lower market price.
And as we pointed out, the ZEC legislation in New Jersey always recognizes that payment has zero emission credit payment was for the carbon attributes of nuclear and was additive to the energy and capacity price, and the BGS auction clearly states that energy -- electricity will be secured at prevailing market rates for both energy and capacity. So we think -- and certainly the output from 30 terawatt hours of nuclear, which is what the New Jersey ZEC law targets is well within the capacity -- the overall need of BGS. I use the word capacity in the generic sense not in the industry sense of the word.
So I do think BGS can use up or consume or call for the 30 terawatt hours of nuclear at prevailing market prices for energy and capacity without any need for legislation, which would just be a win all around, right? And FERC get its way, New Jersey get its way, and nobody -- the customers are not burdened anymore than was originally envisioned in the legislation, and in fact will achieve the savings that were envisioned at the legislation as the plants were to not operate.
Daniel Cregg -- Executive Vice President And Chief Financial Officer
And just one reminder as well, Praful, as you think about, it's the next three capacity auctions have -- the next three years I should say, the capacity options have happened already. And what we will anticipate this coming April will be determination related to ZEC for those same three years. So this all that we're talking about is an important effort that's got to go on, and the next thing to look forward, reply comments are due on the 6th of November, but this will all impact the period after those three years.
Praful Mehta -- Citigroup Inc -- Analyst
Got you. Very helpful color guys. Thanks so much.
Operator
Your next question is from the line of Julien Dumoulin-Smith with Bank of America.
Julien Dumoulin-Smith -- Bank of America Merrill Lynch -- Analyst
Hey, good morning.
Ralph Izzo -- Chairman of the Board, President & Chief Executive Officer
Good morning, Julien.
Daniel Cregg -- Executive Vice President And Chief Financial Officer
Good morning, Julien.
Julien Dumoulin-Smith -- Bank of America Merrill Lynch -- Analyst
Hey, so Ralph to follow-up on Praful's question. Just going back to the forward hedges that you all disclosed in your slides, I mean obviously you had some impacts on sparks here in the latest quarter. Can you elaborate? Is that reflected in your expectations of realized energy prices in the hedges at this point? Or is it too much of noise?
Ralph Izzo -- Chairman of the Board, President & Chief Executive Officer
Yeah. I mean, to the extent that hedges were put on during that period, you would see it in the hedges. And as you know, we have kind of a mix within the intermediate combined cycle section of the overall fleet of some elements that are open and some that are hedges. But to the extent that those hedges are put on, I'd say, the only difference really is that, you're going to see the effect coming through the forward markets as opposed to just in the real-time and day ahead markets, but it's been a consistent phenomenon across both.
Julien Dumoulin-Smith -- Bank of America Merrill Lynch -- Analyst
Got it. But may be to be clear about it, your expectations going forward with respect to what you saw transpire and spark spread in the latest quarter, I mean is this more of an acute issue that you saw during the quarter or how do you think about that from an ongoing impact?
Daniel Cregg -- Executive Vice President And Chief Financial Officer
Well, I think they are both shorter term and longer-term impacts, right? So if you think about a couple of things that Ralph and I already talked about, I've talked about having some more extreme weather in the summer, having some lower inventory levels that need to be bought in, which going to have upward pressure on pricing. And Ralph talked about on the longer term that you see some takeaway capacity coming into the market that's going to have a longer-term effect. So I think you will continue to see both shorter term and longer term impacts -- impacting market prices.
Julien Dumoulin-Smith -- Bank of America Merrill Lynch -- Analyst
Got it. And did that have any bearing on the decision on the retail side at this point?
Daniel Cregg -- Executive Vice President And Chief Financial Officer
No. The retail side was -- as you know Julien, always defensive -- defensive plan outpark primarily targeted and trying to reverse some of the losses we've been realizing on -- from the point of view of wholesale market basis differentials. With the start of the Keys plant, with the strengthening of gas prices in the M3 zone, we've seen some decreased farm from basis to our fleet. And the margins were so thin on the retail business. As you know, there have been a huge benefit that we just decided that was not in our best interest to continue to pursue it.
Julien Dumoulin-Smith -- Bank of America Merrill Lynch -- Analyst
Got it. And then if could clarify the comments on capacity, it seems that you're thinking there is no need for legislation. Can you talk about timing for any potential, I suppose it would be a BPU-led effort to change BGS procurement relative to the implementation of MOPR. It would seem as if and you tell me if this is correct that there would not be application of MOPR for New Jersey next year and that would give you some runway to be able to implement for a 2020 auction?
Ralph Izzo -- Chairman of the Board, President & Chief Executive Officer
So remember, BGS typically follows the RPM auction in terms of the energy applicability. So the RPM auction that would have taken place in April but is now going to take place in August is input to the BGS auction that will take place in 2020. So we have plenty of time. And as Dan pointed out, for the next three years capacity prices are known, BGS has been layered in to the tune of 100% next year, two-third the year after, one-third the year after that, so the timing of all this is that the PJM proposal would only apply if we did get the ZEC. We will find out if you get the ZEC in April. And at that point in time, assuming we get the ZEC and assuming that the PJM proposal goes in as accepted, we have a full 10 months to get the BGS auction right. Of course we would do it much in advance, so that typically the LDCs put that comments in the fall for what BGS rule changes should take place if any in the following winter. So the way to think of this is, January FERC rules on the PJM proposal, we make comments shortly thereafter, FERC finalizes the RPM auction in the April time frame, we find out whether or not we get a ZEC in the same time frame, the auction takes place in August in the fall. We -- if we are a ZEC recipient and if the auction has taken place, the MOPR approach we would file with other LDCs for BGS to be the entity that secures the nuclear energy and capacity for the following February. So that was a long-winded way of saying, I think the timing will work just fine.
Julien Dumoulin-Smith -- Bank of America Merrill Lynch -- Analyst
Excellent. Thank you all.
Operator
Your next question is from the line of Greg Gordon with Evercore ISI.
Greg Gordon -- Evercore ISI -- Analyst
Thanks. Good morning all.
Ralph Izzo -- Chairman of the Board, President & Chief Executive Officer
Hi, Greg.
Greg Gordon -- Evercore ISI -- Analyst
I'm sorry to circle back to Power. But I just wanted to see if maybe we could get a clarification on why we saw you lower the guidance range now, because to the extent that you knew you were hedged at lower prices, right, that was a known factor that impacted the guidance range, and there was only a small portion of your combined cycle and peaking generation that was open to the market. And even though we know spark spreads were lower, it doesn't seem like there's enough volume there on an open basis to swing your numbers by the magnitude that the guidance range was reduced. So can you just -- is it possible for you to be a little bit more granular on just how much of this was known and how much of this was unknown? Because going into the second quarter -- going into the third quarter from the second quarter, realized spark spreads were not very different from what the forward curve was telling us.
Ralph Izzo -- Chairman of the Board, President & Chief Executive Officer
Yeah Greg, and you're right. So if you think about it as just a pure open volume and the delta on the open volume, you can have some impact, but it's not going to be as much as what you saw. I think that there's a couple other factors that are coming into play. One is that, just our volume amounts are down a little bit. So if you think about where we have them pegged at the beginning of the year and where they ended up, they are down about 1 terawatt hour. So we're down a little bit on volume.
And then the other factor is, some of the basis differentials that we end up seeing. And we have seen some lower eastern basis, we've talked about that a fair bit of late, and that comes through an awful lot of our hedges or not perfect hedges at the exact generator buzz where the generator is generating. To the extent that our hedges are at the West Hub, there is a little bit of an openness on that basis and we've seen some deterioration of the basis as well within the hedges. So I would point to those other factors as well to think about in addition to just the pure open position times at delta spark and the accumulation of those factors would get you to the delta that we're talking about.
Greg Gordon -- Evercore ISI -- Analyst
Okay. So that basis exactly what it caused you to move the Power to the Hub where you are hedged?
Daniel Cregg -- Executive Vice President And Chief Financial Officer
Right. So for instance if you think about our nuclear facilities, you got a lot of volume coming out of there but you don't have a lot of ways to transact at the nuclear location. So if you're going to put a forward sale on, for example, you might put in on at the Western Hub. And to the extent that you saw basis differential move between the Western Hub where your hedge was put on and where the actual generation is at nuclear, you're going to have some openness within a hedged amount of volume.
Greg Gordon -- Evercore ISI -- Analyst
Great. One last follow-up. The $0.06 that you booked on the mark-to-market associated with -- well I forgot exactly what it was, it was a pension or associated with the Nuclear Trust, was that an expected item or was that something that was an unexpected benefit in the quarter, the tax reserves?
Daniel Cregg -- Executive Vice President And Chief Financial Officer
Yes. So what that is, that's not on the NDT, because you mentioned Trust, really what that is, is just a more generic tax issue, generic meaning that it's on the company's taxes as opposed to the NDT. And it's a carry back of losses back to an earlier year with higher tax rates. But the direct answer to your question was, yes that was expected.
Greg Gordon -- Evercore ISI -- Analyst
Okay. So that was an unexpected gift that was in the guidance already?
Daniel Cregg -- Executive Vice President And Chief Financial Officer
That's right.
Greg Gordon -- Evercore ISI -- Analyst
Thank you guys. Take care.
Ralph Izzo -- Chairman of the Board, President & Chief Executive Officer
And Greg, just to go back to your question about the quarter versus -- and Dan's accurate answer about some of the cumulative impacts. I mean at the risk of stating, it's obvious when we initially give guidance at the beginning of the year, we give a range and we expect to be somewhere in the middle, otherwise we would advise them as one way or another. And typically, within the second quarter we try not to change that, because it's still early, it's a half year to go. It's not unreasonable to assume that we saw some creep of Power, as Dan mentioned, in terms of the volume reduction toward the lower end of that range but still within the range and utility toward the upper end of that range but still in the range, and then the third quarter just resulting in the need to redesignate the ranges. So long-winded way of saying, I wouldn't assume that all of the movement in Power or for that matter utility occurred in the third quarter. That's not the case.
Greg Gordon -- Evercore ISI -- Analyst
Okay. Yeah, that was my intuition. I just wanted to make sure I understood it. I appreciate you clarifying. Thank you.
Operator
Your next question is from the line of Jonathan Arnold with Deutsche Bank.
Ralph Izzo -- Chairman of the Board, President & Chief Executive Officer
Hi, Jonathan.
Jonathan Arnold -- Deutsche Bank -- Analyst
Hi, good morning guys.
Daniel Cregg -- Executive Vice President And Chief Financial Officer
Good morning, Jonathan.
Jonathan Arnold -- Deutsche Bank -- Analyst
Great. So just, I wanted -- along the lines of just where Greg was going. When we look at the fourth quarter guidance now for Power and where you were through the nine months, the low end suggest that you might have as low a quarter as a $20 million quarter in Q4. It just seems that that would be unusually low for you. So I'm just curious, is that some of the same issues that are working into Q4 as well or is there something else back Q4 that's kind of in the plan that we may be need to remember?
Daniel Cregg -- Executive Vice President And Chief Financial Officer
No, I think you can just kind of do the math over where we are now and what the range would imply. And I think you'd be north of the number that you gave. But maybe one thing to keep in mind, there was some tax benefits that came through more of a onetime in the last year's fourth quarter. So if you just go against that as a comparison, you would have to carve out some of the one-time items as you look at the two quarters compared to one another. So it's something to keep in mind in that regard. But you do have a couple of shorter months in the fourth quarter and you also have a lot of the outages that are going during some of those shorter months. So you can some variability as you go year-to-year.
Jonathan Arnold -- Deutsche Bank -- Analyst
Okay. And then on just -- could I ask on investment capacity? That slide was in the Analyst Day deck at somewhere sort of between I guess in the sort of high single hundreds of millions. And it was also in the September deck. And I guess with the rate case settlement and the transmission rate adjustments now in hand, is that still a good number or is there some -- is there an update there?
Daniel Cregg -- Executive Vice President And Chief Financial Officer
So we'll update that at EEI in a week or so, Jonathan rather than trying to give that piece here today.
Jonathan Arnold -- Deutsche Bank -- Analyst
Okay. Well I guess we'll see you then. Thank you guys.
Operator
The next question is from the line of Christopher Turner with JP Morgan.
Christopher Turner -- JP Morgan -- Analyst
Good morning. I think Ralph in your prepared remarks you mentioned the importance of decoupling to your long-term plan and New Jersey customers. Can you give us a sense as to what kind of might have been missing from the negotiations with intervenors, and if there's any kind of partial agreement heading into your energy future filing?
Ralph Izzo -- Chairman of the Board, President & Chief Executive Officer
Yeah, Chris. First of all, I can't give you the details, there's a settlement discussion, because those are all confidential. We can give you details on the outcome of that. However, it's not -- it won't come as a surprise to you to know that the principles in a base rate case are different than the principles, and I'm referring to participants here than in a strictly energy-efficiency conversation. So the Clean Energy Future filings will have a greater percentage of people who are interested in seeing that the green energy agenda of Governor Murphy being advocated and pushed forward, and that will therefore have the kind of center stage that's appropriate to it which may not have been more expected in the base rate filing.
Christopher Turner -- JP Morgan -- Analyst
Okay. That's helpful. And could you give us a sense as to what some of the other mechanisms might be there if it's not an outright decoupling that mechanism?
Ralph Izzo -- Chairman of the Board, President & Chief Executive Officer
I'd rather not go into that now since we haven't even sat down and got a discovery questions from the other parties. But there's all sort of stuff that one can do to get contempering (ph) this type recovery of both investments being made as well as chewing up for what might have been anticipated to the revenues versus what's realized in revenues either in six months or annual filings or things of that nature.
Christopher Turner -- JP Morgan -- Analyst
And then my second question was on weather versus normal on the utilities side. Can you quantify that for the quarter or the year-to-date? And then just related on the corporate side, anything changed versus your original plan there other than just the interest rate on new debt?
Daniel Cregg -- Executive Vice President And Chief Financial Officer
Yeah. So I can point you to the slides. If you take a look, you've got a breakout both of weather in particular as well as on volume, and demand sometimes can come into play there. So on the weather for the year-to-date for the utility, you can see we had about $0.04 delta, three of that in the quarter, and volumes (Technical Difficulty) about $0.02 year-to-date and about $0.01 in the quarter. So you can see it broken out pretty cleanly within the slides that we provided.
And then your question on interest, basically what we're seeing mainly at the Parent is just the increase in some of the shorter term debt that exists up there as we've stepped through the year, which has put a little bit of pressure on the aggregate numbers at the Parent.
Christopher Turner -- JP Morgan -- Analyst
Okay. And then just on those weather numbers, where those year-over-year or where those versus normal?
Daniel Cregg -- Executive Vice President And Chief Financial Officer
Those were year-over-year.
Christopher Turner -- JP Morgan -- Analyst
Okay. Any sense as to versus normal or is that something we could take offline?
Daniel Cregg -- Executive Vice President And Chief Financial Officer
It's pretty close. I think you might have seen just a little bit of an uptick because 2017 summer was a little bit milder, but they are almost the same if you take a look at versus last year versus looking at normal.
Christopher Turner -- JP Morgan -- Analyst
Okay. Thank you.
Operator
Your next question is from the line of Michael Lapides with Goldman Sachs.
Michael Lapides -- Goldman Sachs -- Analyst
Hey guys, thanks for taking my question. Real quick. If I go back to the Analyst Day and look at the PSE&G forecast capital spend, and then I think a little bit about some of the filings that you made in the last few months, how should we think about where you're tracking and whether you think you're likely above? What do you kind of highlighted back at the Analyst Day? I mean, the filings you've made are pretty large scale capital projects. Are you above where that would be if all of those come through? Are you kind of somewhere in that range? Just kind of walk us through how you're thinking about that right now.
Daniel Cregg -- Executive Vice President And Chief Financial Officer
Yeah. I mean, Mike I think that we have GSMP II approved in April and we had our conference in May, so that was a account for. And I think if you really look at the major areas that we were talking about, one was Energy Strong -- Energy Strong II I should say. In Energy Strong II, we talked about putting forth a $2.5 billion filing, and in June we put forth a $2.5 billion filing. And we said in May that we were going to put forth the Clean Energy filing of $2.9 billion, and those programs and the magnitude of those programs is -- were filed as we talked about with one exception, and Ralph talked about a little bit earlier today is the inclusion of AMI which was not in the filing at the time. So the programs that we filed aggregate to a capital investment of $3.6 billion versus the $2.9 billion, and you can attribute the full amount of that delta to the AMI component of that filing.
Now it's a 6-year program. So if you're trying to look at it within a 5-year horizon that we normally talked about -- that we talked about, you're going to have two issues, one six years is more than five, but number two, you're going to have some of that capital spill over the back end because it would not have been started at the beginning of 2018. And then similarly for Energy Strong II, it's a 5-year program. And since it was filed in 2018, then we won't see an approval of that until the process runs. You're going to have some more spill over there. But I think that's how you would think about the magnitude of the capital programs. And as we talked about at the time, the 8% to 10% CAGR on rate base growth really is simply with and without those two programs.
Michael Lapides -- Goldman Sachs -- Analyst
Meaning the 10% assumes you get full approval of both of those of Energy Strong II and the Clean Energy filing? Or does that assume some -- something in the middle of what you asked for versus often where you see intervenor request come in at a slightly lower number?
Daniel Cregg -- Executive Vice President And Chief Financial Officer
Yeah. It assumes approved as filed for the periods within that five-year period. And it also assumes that there is no other incremental programs for the balance of the five years. So if nothing else were to happen, but -- and we were to get every dollar as filed, we'd be at the 10%. Any reduction from as filed would lower that amount, and then anything else between now and then that is identified as incremental capital would be additive.
Michael Lapides -- Goldman Sachs -- Analyst
Got it. And then one last one. How are you looking at the potential changes to transmission spend over the next three to five years versus what you laid out? I mean, if I go back over time, what you laid out in the Analyst Day for years three and years four and beyond, the number is actually usually as you rolled for a year or two came in higher as PJM recognized incremental needs or as you recognize an incremental needs as you kind of got closer to those years occurring. How are you thinking about it now relative to what you put out back in at the Analyst Day?
Daniel Cregg -- Executive Vice President And Chief Financial Officer
So is the question how does our forecast differ from our forecast?
Michael Lapides -- Goldman Sachs -- Analyst
Well, little bit of -- are you seeing incremental opportunities that may not have been embedded in the forecast?
Daniel Cregg -- Executive Vice President And Chief Financial Officer
Yeah. I think we're a few months away from when we put that forward and it's still how we are characterizing the five-year capital plan at this time.
Michael Lapides -- Goldman Sachs -- Analyst
Okay. Last item, a little bit housekeeping. O&M at the utility year-over-year and sequentially it was up a double-digit percentage. How much of that drops to the bottom line, meaning I'm just looking at the quarter.
Daniel Cregg -- Executive Vice President And Chief Financial Officer
So you're talking about for the quarter for PSE&G, the $0. 02 incremental O&M?
Michael Lapides -- Goldman Sachs -- Analyst
Yes.
Daniel Cregg -- Executive Vice President And Chief Financial Officer
All of that $0.02 drops to the bottom line, if that's your question.
Michael Lapides -- Goldman Sachs -- Analyst
Okay. Got it. Thanks guys.
Daniel Cregg -- Executive Vice President And Chief Financial Officer
Thanks.
Operator
Your next question is from the line of Paul Fremont with Mizuho.
Paul Fremont -- Mizuho Securities -- Analyst
Thanks. Looking at fast start, I guess Exelon I think has put out estimates that would imply may be less than $2 per megawatt hour. And at your Analyst Day I think you were in the $1 to $3 range. Are you still at the same level in terms of where your -- what you're expecting in terms -- if fast start is adopted?
Ralph Izzo -- Chairman of the Board, President & Chief Executive Officer
So there's two schools of thought on this, right? Paul, one is that, in the aggregate fast start reserve margins in flexible units could be $3 to $5 with fast start being a significant down payment on that -- possibly in that $1 to $3 range. But the question is, what is the degree of at which the forward price curve already has incorporated that, if we believe that FERC is going to be issuing that decision fairly soon and PJM will be incorporating it in Q1. I don't know the answer to that, but that's the two considerations you have to make, right? So should fast start result to an increase? Absolutely. Is it already in the forward price curve? Depends on your confidence in the timing of the FERC decision.
Paul Fremont -- Mizuho Securities -- Analyst
Great. Thank you very much.
Operator
Your next question is from the line of Shar Pourreza with Guggenheim Partners.
Shahriar Pourreza -- Guggenheim Partners -- Analyst
Hey, good morning guys.
Ralph Izzo -- Chairman of the Board, President & Chief Executive Officer
Good morning, Shar.
Shahriar Pourreza -- Guggenheim Partners -- Analyst
You guys touched on most of the questions. Just real quick on the Clean Energy legislation versus what you proposed on slide 17. The storage mandate versus what you're proposing, correct me if I'm wrong, has incremental upside versus what your plan is?
Ralph Izzo -- Chairman of the Board, President & Chief Executive Officer
Yes. I think the storage goal is like 600 megawatts by 2025 or something like that. And then it's a big number. And we proposed 35 megawatts. So yes, there is upside there.
Shahriar Pourreza -- Guggenheim Partners -- Analyst
Would that be within -- is that a backend loaded or when do you think you will figure that out as far as how we should --
Ralph Izzo -- Chairman of the Board, President & Chief Executive Officer
One of the conversations we've been having with the policy figures is that, most of these technologies and battery storage is a great example, is something that we do believe has a healthy trajectory in terms of prices coming down in the future. So you want to both stimulate the market price, (inaudible) you don't want to pay for that market in its entirety upfront. So there's a little bit of a delicate timing of how much you do and when you do it, that is in interactive conversation that we do have with policy leaders both in the BPU and in the Governor's office in the legislation.
Shahriar Pourreza -- Guggenheim Partners -- Analyst
And then Ralph just on -- one of your peers is out talking about $5 to $10 per megawatt hour of incremental cost when you layered in with wind or sort of solar on two to four hours of sort of storage. Are you seeing figures like that or seeing higher figure? Because if you use two to four, it seems like you could probably get something that's economically viable, right?
Ralph Izzo -- Chairman of the Board, President & Chief Executive Officer
Yeah. On the -- I'm used to coating it in terms of capacity. And the number we use is $2 million to $3 million per megawatt. I'd have to work it backwards to see if I get to that $3 to $5 per megawatt hour, and I'd rather not do that in real time, which is, Shar, but I will take that as a homework assignment.
Shahriar Pourreza -- Guggenheim Partners -- Analyst
Okay. Great. I'll bother again later. And then just lastly, what's your -- no problem. What drove the lower capacity factors on your new gas assets for the third quarter?
Ralph Izzo -- Chairman of the Board, President & Chief Executive Officer
(Multiple Speakers) was it a home-free (ph) outage. Was it -- it's a 100% ownership of home-free, no?
Daniel Cregg -- Executive Vice President And Chief Financial Officer
And is there, 93% accretive future outage. It's nothing but kind of your normal outages at the time.
Shahriar Pourreza -- Guggenheim Partners -- Analyst
Okay, got it. Okay. Thanks guys. Sure I think (inaudible) follow-up with you after the call.
Daniel Cregg -- Executive Vice President And Chief Financial Officer
Thank you.
Operator
Your next question is from the line of Angie Storozynski with Macquarie.
Angie Storozynski -- Macquarie -- Analyst
Thanks. So two questions. One, FERC has just updated its ROE -- its transmission ROE methodology now, but there also seems to be some discussion about may be changes to transmission ROE adders. What they should be actually related to? And I mean, what are your expectations about how those ROEs will be trending and if your existing projects will be impacted?
Ralph Izzo -- Chairman of the Board, President & Chief Executive Officer
So Angie, we're following the discussion -- as we understand it ROE adders and incentives have not been ruled on yet. We do have a rising interest rate environment, and the three methodologies that FERC are using, all due then lead to a discussion about how does each specific company and its risk profile sit within the range predicted by those three methodologies. So I'd say that, the ingredients to the stew are getting a little bit better known, but what the stew comes out tasting like still remains to be understood going forward.
Angie Storozynski -- Macquarie -- Analyst
Okay. And then for the equity layer at the utility under the rate case settlement or decision is now going to be 54%. I think you mentioned at the end of the quarter, it was 51%. So I mean, should I expect that there's going to be additional equity injection into the utility? And is it going to come from basically corporate level debt?
Daniel Cregg -- Executive Vice President And Chief Financial Officer
No Angie, our 51.2 (ph) was the stated rate from the last rate case, and our existing equity percentage was somewhere between 53%, 53.5%. So that delta is not as big as you might otherwise think, and just general corporate funds would fund that delta.
Angie Storozynski -- Macquarie -- Analyst
That's great. Thank you.
Daniel Cregg -- Executive Vice President And Chief Financial Officer
You're welcome, Angie.
Operator
Your next question is from the line of Andrew Weisel with Scotia Howard Weil.
Andrew Weisel -- Scotia Howard Weil -- Analyst
Hey, thanks for squeezing me in. And I guess, good morning or past the hour here. Quick first one, on the PSE&G guidance for the year, the midpoint essentially went up by $0.10 on an EPS basis. When I look at the year-to-date weather benefit versus normal, that was only about $0.03. So what else is taking you ahead of the plan? And would any of that be sustainable to benefit future years?
Daniel Cregg -- Executive Vice President And Chief Financial Officer
Yeah. I think in addition to the area that just labeled whether you've also got some volumes and demands which will give you probably another $0.02 or $0.03 or so. And then there's a couple of other modest items that would end up moving in north of that. So I think two things for you. One is, layer in the volume and demands incrementally to the weather amounts, which also tend to be fairly weather-related. And then you think about a couple of other smaller adjustments and you can get to that range.
Andrew Weisel -- Scotia Howard Weil -- Analyst
Okay. The smaller adjustments should we think of that a sort of one-time or would that carry through?
Daniel Cregg -- Executive Vice President And Chief Financial Officer
I think more of one-time (inaudible).
Ralph Izzo -- Chairman of the Board, President & Chief Executive Officer
I think one of the most -- I was just, there is maybe a little bit conservative on the timing of the rate case.
Andrew Weisel -- Scotia Howard Weil -- Analyst
Oh, I see. Okay. Good. Then the other question I had on the AMI. You mentioned there is a reaction to the March storms and improving reliability. My question is, can you remind us the history in the state? I believe the BPU chose not to continue a pilot program at one of your neighbors and they instead asked you to the utility to file for cost benefit analysis. I guess my question is, is it a little premature to file for the $700 million program now? And how comfortable are you that it will be approved as part of the CEF filing?
Ralph Izzo -- Chairman of the Board, President & Chief Executive Officer
We definitely do not think it's premature. There is a moratorium as you correctly pointed out Andrew, and -- but we think that there's a couple of factors that are materially different. One is the BPU announcement seeking the cost-benefit analysis and the concern over outages. You are right. But the second is this huge initiative that the Governor has embarked upon to really push forward on a Clean Energy agenda. And the value of information that one can extract from Advanced Metering Infrastructure to help customers use their energy more intelligently, translation, reduce their energy consumption is I think an important consideration for policymakers in achieving what the Governor has outlined as its priorities.
Andrew Weisel -- Scotia Howard Weil -- Analyst
Okay. And just to clarify, I believe this is the case, but it's certainly possible that the CEF could be approved without that. In other words it's not a package deal. Those the pieces could be treated individually, so it might end up looking like what you had talked about at the Analyst Day. Is that right? Is that a possibility?
Daniel Cregg -- Executive Vice President And Chief Financial Officer
Yes. That's correct. We didn't go into details, but we did -- the CEF is three separate filings that were all put in the same time. But that's correct.
Andrew Weisel -- Scotia Howard Weil -- Analyst
Okay. Thanks everyone.
Operator
We have reached the allotted time for questions. Mr. Izzo or Mr. Cregg, please continue with any closing remarks.
Ralph Izzo -- Chairman of the Board, President & Chief Executive Officer
Okay. Well thank you there. So hopefully the take away from this call is that the Utility and Power both have had some solid operating performance in terms of our traditional hallmark attributes, our reliability, our availability. The financial performance is on track albeit with a much stronger performance at the Utility and weaker performance at Power than had been anticipated at the start of the year. And I would say that we look forward to seeing you in San Francisco in 10 days where we can discuss these and other issues more fully and enjoy Halloween. New Jersey has a famous Mischief Night coming up, hopefully none of you are victims of that. But with that, we'll see you in about 12 days. Thanks all.
Operator
Ladies and gentlemen, that does concludes your conference call for today. You may disconnect, and thank you for participating.
Duration: 66 minutes
Call participants:
Carlotta Chan -- Head of Investor Relations
Ralph Izzo -- Chairman of the Board, President & Chief Executive Officer
Daniel Cregg -- Executive Vice President And Chief Financial Officer
Praful Mehta -- Citigroup Inc -- Analyst
Julien Dumoulin-Smith -- Bank of America Merrill Lynch -- Analyst
Greg Gordon -- Evercore ISI -- Analyst
Jonathan Arnold -- Deutsche Bank -- Analyst
Christopher Turner -- JP Morgan -- Analyst
Michael Lapides -- Goldman Sachs -- Analyst
Paul Fremont -- Mizuho Securities -- Analyst
Shahriar Pourreza -- Guggenheim Partners -- Analyst
Angie Storozynski -- Macquarie -- Analyst
Andrew Weisel -- Scotia Howard Weil -- Analyst
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