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.
As a reminder, this conference is being recorded Tuesday, October 30, 2018, and will be available for telephone replay beginning at 1 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.
Thank you, Natalia. Good morning and thank you for participating in our earnings call. Earlier today, PSEG released earnings statements for the Q3 of 2018. These materials, including the release, attachments and accompanying slides detailing operating results by company, are posted 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 contain 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 of Public Service Enterprise Group. Joining Ralph on the call is Dan Craig, Executive Vice President and Chief Financial Officer.
At the conclusion of their remarks, there will be time for your questions. Ralph?
Thank you, Carlotta, and thank you all for joining us today. PSEG reported solid results for the Q3 and through 9 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 and 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 Q3 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.
3rd quarter net income and non GAAP operating earnings improved by 4% 16%, respectively, over 20 seventeen's 3rd quarter comparables. Our results for the quarter bring non GAAP operating earnings for the 9 months to 2 point $5.6 per share, an 8% increase over the $2.36 per share earned in the 9 months ended September 30, 2017. Slide 67 summarize the results for the quarter and the year to date periods. Throughout a very hot summer, both PSE and G and Power performed well. Therefore, our financial results reflect solid contributions from both businesses.
PSE and G's earnings increased by $0.05 per share, up 10% over Q3 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 conditioning throughout an extended summer that was the 2nd hottest in nearly half a century. Expanded investment in transmission and distribution infrastructure continues to benefit customers and have a favorable impact on PSE and G's rate base and earnings. We are on pace to spend $2,800,000,000 for the year and the utilities rate base is forecast to grow to almost $19,000,000,000 at year end. Based on our various investment programs, we remain comfortable with PSE and G's ability to achieve growth in rate base within our forecast of 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 and G recently filed several clean energy future 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 durations.
PSE and G's filing is designed to create an advanced technology network and upgrade 2,200,000 electric meters to smart meters by the year 2024. In addition, Energy Strong II, the proposed $500,000,000 5 year extension of our infrastructure reliability and resiliency investment program is pending at the BPU. Inclusive of the AMI initiative, PSE and G's 2018 to 2022 capital spending forecast range is $12,000,000,000 to $16,000,000,000 I now want to bring you up to date on PSE and G's distribution based 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 and G, BPU staff and rate council. This concludes the utility's first distribution rate review since 2010 and is expected to provide PSE and G's customers with rate stability, while allowing us to achieve 3 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 and M levels. The terms of the agreement provide an additional $212,000,000 in annual revenue and a flow back to customers of $225,000,000 in tax savings largely due to tax reform, resulting in a net $13,000,000 revenue reduction. When new distribution rates go into effect on November 1, a typical combined residential customer bill will be at levels that are 30% lower than they paid in 2,008 in nominal terms and 40% lower in real terms. The updated revenue requirements based upon the distribution rate base of $9,500,000,000 a return on equity of 9.6 percent and a 54 percent equity ratio. All of PSE and G's distribution investment programs will adopt the new ROE of 9.6 percent and equity percentage of 54% going forward.
PSE and 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 3 quarters of a percent 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 lost revenue recovery. Now let me turn my attention to PSEG Power.
Power's non GAAP operating earnings increased 23 percent to $0.39 per share over 20 seventeen's Q3 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 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 1300 megawatts of highly efficient capacity at Keyes and Sewaren 7 earlier this year leads the reconfiguration of Power's merchant fleet as demonstrated by this quarter's CCGT production.
The design of wholesale energy and capacity markets and where 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 spinning reserves, we don't expect PJM will reprioritize those efforts until after it implements fast start.
Getting energy prices right is critical to ensuring 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 0 Emissions Credit 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 ZEC as we refer to them. The BPU held 3 public hearings earlier 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 will make certification that the units will shut down within 3 years in the absence of a material financial change. In June 2018, FERC issued an order finding that PJM's current capacity market is unjust and unreasonable and established a proceeding to evaluate potential reforms. PSEG submitted comments in early October recommending the status quo remain in place, within the alternative, 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 recognized that energy and capacity payments, and now again I'm referring to the New Jersey ZEC law, were not sufficient to compensate nuclear units for the carbon attributes they provide and that ZECs 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 PGM 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 emission related goals. New York and Illinois have recently received appellate court affirmations from the 2nd and 7th Circuit Courts of Appeal, 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'll turn the call over to Dan to discuss our financial results in greater detail and I'll rejoin him for your questions after he's finished.
Great. Thank you, Ralph, and thank you everyone for joining us on the call today. As Ralph said, PCG reported net income for the Q3 2018 of $0.81 per share and that versus net income of $0.78 per share in the last year's Q3. Non GAAP operating earnings for the Q3 of 2018 were $0.95 per share versus non GAAP operating earnings of $0.82 per share in last year's Q3. And a reconciliation of non GAAP operating earnings to net income for the quarter 9 months can be found on Slide 67.
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 and G. PSE and G reported net income of $0.54 per share for the Q3 of 2018. That's compared with $0.49 per share for the Q3 of 2017. Results for the quarter are shown on Slide 15.
Net income growth in the 3rd quarter was driven by continued investment 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 and G's expanded investment in transmission added $0.02 per share to net income in the quarter. Incremental revenue associated with recovery of PSE and G's Energy Strong and the gas system monetization 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 non service component of pension and other postretirement benefits or OPEB expenses resulted 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
$2 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 20 seventeen'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 and G reached the 2018 system peak of 9,978 Megawatts compared to 2017 system peak of 9,000 567 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 and G's distribution rate review achieved several regulatory priorities, mainly the recovery of Anand investments made since 2010 outside of the programs clause based recovery. In addition to the recovery of deferred storm costs dating back to 2011 and a true up of sales and cost estimates. New rates are based upon a distribution rate base of $9,500,000,000 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 and G's financial flexibility is essential to providing reliable service at the lowest cost. Going forward, PSE and G's distribution investment programs will adopt a new ROE rate and equity percentage established in the settlement agreement.
As Ralph mentioned, the net $13,000,000 revenue reduction takes into account an additional $212,000,000 in annual revenues, including storm cost recovery and an increase in depreciation expense, as well as a flow back to customers of $225,000,000 in tax savings, largely due to tax reform. PSE and G customers will benefit from $262,000,000 in annualized rate reductions to reflect savings from federal tax reform enacted in 2017. PSE and G filed 2 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 $100,000,000 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 $150,000,000 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 in 2018 from these two programs is forecast to be approximately $53,000,000 as we near completion of the 1st GSMP and Energy Strong programs. Once GSMP II begins, gas rates will adjust in December June of each year. PSE and G has invested approximately $2,300,000,000 for the 9 months ended September 30 in electric and gas distribution and transmission capital projects. For the full year, PSE and G expects to invest approximately 2,800,000,000 dollars on increasing system reliability and resiliency, upgrading critical infrastructure and supporting New Jersey's energy policy goals.
We continue to expect rate based growth at a CAGR of 8% to 10% over the 2018 to 2022 period. For the full year, we've increased PSE and 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 $1,055,000,000 to $1,070,000,000 up from $1,000,000,000 to $1,030,000,000 Now let's turn to Power. PSEG Power reported net income of $125,000,000 or $0.25 per share for the Q3 of 2018, compared with net income of $136,000,000 or $0.27 per share in the year ago quarter. Non GAAP operating earnings were 0 point quarter of 2018 compared to non GAAP operating earnings for the Q3 of 2017 of $0.31 per share. Non GAAP adjusted EBITDA for the Q3 of 2018 was $360,000,000 versus non GAAP adjusted EBITDA for 2017
of $356,000,000
Non GAAP adjusted EBITDA excludes the same items as our 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 1st 9 months of the year on Slides 2223. Power's net income in the 3rd quarter was impacted by a decline in average energy hedge 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 31 next year. Recontracting of hedges at lower prices and the market impact of lower spark spreads in PJM East reduced results by compared with the Q3 of 2017. Power experienced a $7 per megawatt hour decline in its average hedged energy price during the Q3, which is consistent with our expectations for the full year. The impact of placing the Keys and Sewaren combined cycle stations in service, along with higher demand, boosted generation volumes by 0 point 0 $6 per share. Higher O and M expense of 0
point
$0.02 per share both relate to the new combined cycle units placed in service versus the year ago quarter. And these impacts will continue to affect year over year comparisons in coming quarters given the in service of Keyes, Sewaren and ultimately Bridgeport Harbor V 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 pretax income improved net income comparisons by $0.07 per share. The anticipated benefit from the remeasurement of tax reserves associated with a nuclear carryback claim and the closure of IRS audits for the year 20112012, 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 Keyes 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 Q3 of 2018, up by 88% over the year ago quarter, primarily reflecting the production of the 2 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 3rd quarter on low storage levels and weather driven demand, but power prices didn't move up in conjunction with gas putting pressure on power spark spreads. Power's forecast of total output for 2018 has been raised modestly to 54 terawatt to 56 terawatt hours from last quarter's reduced estimate of 53 terawatt 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, PowerEdge hedged percent to 45 percent of output forecasted to be 62 terawatt hours to 64 terawatt hours at an average price of $36 per megawatt hour.
Forecasted output for 2018 to 2020 includes generation associated with Keyes and Sewaren as well as the mid-nineteen commercial start up of the 4 85 Megawatt gas fired combined cycle unit 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 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 $465,000,000 to 500,000,000 dollars and $1,045,000,000 to $1,100,000,000 respectively, from $485,000,000 to 5.60,000,000 and $1,075,000,000 to $1,180,000,000 respectively. Now turning to PSEG Enterprise and Other, reported net income of $9,000,000 or $0.02 per share for the Q3 of 2018 compared to net income of $13,000,000 or 0 point $2 per share for the
Q3 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 $25,000,000 from $35,000,000 reflecting those higher interest costs. PSEG closed the quarter ended September 30 with $88,000,000 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 and G issued $325,000,000 of 5 year, 3.25 percent medium term notes and $325,000,000 of 10 year, 3.65 percent medium term notes.
And PSE and G also retired $315,000,000 of 2.3 percent medium term notes at maturity. And as Ralph mentioned, we've 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, Natalie, we are now ready to take questions.
Ladies and gentlemen, we will now begin the question and answer session for members of the financial community.
And your first question is from
the line of Praful Mehta with Citigroup.
Hi, guys.
Hi, Praful. Hi. So maybe a specific question on the quarter first and then we'll get to all the market reform that's taking place. But starting with Slide 24, where you highlight gas prices went up and that's what pushed up your fuel cost. I wanted to understand why that didn't drive up power prices as well.
I mean, clearly that implies some reduction in the spark spread and wanted to understand why heat rates have been coming down. So if there's some color on that, that would be helpful.
Right. So there is strong correlation obviously, probably between gas and electric prices, but it's not perfect. One can only assume that there was some dispatching of coal that took place to keep a little bit of a lid on those power prices from moving perfectly in tandem. Dan, I don't know if you want to add to that.
Yes. 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 the 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.
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?
We never try to out guess the forward price curve, Praful, but we are seeing that with the opening of some pipelines that are taking Marcellus gas to regions other than the immediate 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 the forward curve is predicting whatever it's predicting right now.
Got you. Understood. And then quickly just going on to the market reform side, especially around capacity prices and capacity reform. 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?
So again, what we keep anchoring ourselves to is what FERC has espoused 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 the point of view of a resource designation. As I think I mentioned, our preference is the status quo, but notwithstanding an ability to preserve that status quo, we think that PJM's offered an intelligent alternative. There's some things that we would quarrel with perhaps their cutoff at the 20 megawatts level versus FERC's guidance that any and 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 transfer capabilities, there's demand side management, there's how different local delivery areas break out. 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 things being equal, that should remove the price suppression for unsubsidized units. And that will set a different market price. It's hard for me to see how that will be a lower market price. And as we pointed out the ZEC legislation in New Jersey always recognized that that payment, a 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 that 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 our 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? Then FERC gets its way, New Jersey gets its way and nobody customers are not burdened any more than was originally envisioned in the legislation.
And in fact, we'll achieve the savings that were envisioned in the legislation if the plants were to not operate.
And just one reminder as well, Praful, if you think about it, the next 3 capacity auctions have for the next 3 years, I should say, the capacity auctions have happened already. And what we will anticipate this coming April will be a determination related to ZECs for those same 3 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 for, reply comments are due on the 6th November, but this will all impact the period after those 3 years.
Got you. Very helpful color guys. Thanks so much.
Your next question is from the line of Julien Dumoulin Smith with Bank of America. [SPEAKER JULIEN DUMOULIN SMITH:]
Hey, good morning.
[SPEAKER JULIEN DUMOULIN SMITH:]
Good morning, Julien.
Hey. So perhaps to follow-up on Praful's question. Just with respect 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?
Yes. 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.
Got it. But maybe to be clear about it, your expectations going forward with respect to what you saw transpire in 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?
Well, I think there 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 can have upward pressure on pricing. And Ralph talked about on the longer term, if you see some takeaway capacity coming into the market, that's going to have a longer term effect. So I think you'll continue to see both shorter term and longer term impacts impacting market prices.
Got it. And did that have any bearing on the decision on the retail side at this point?
No. The retail side was, as you know, Julian, always a defensive excuse me, defensive plan, our part primarily targeted at 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 Keyes plant, with the strengthening of gas prices in the M3 zone, we've seen some decreased harm from basis to our fleet and the margins were so thin on the retail business. As you know, I've never been a huge fan of it that we just decided that it candidly was not in our best interest to continue to pursue it.
Got it. And then if you could clarify the comments on capacity. It seems that your thinking is 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?
So remember, BGS typically follows the RPM auction in terms of the energy year 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, right? As Dan pointed out, for the next 3 years, capacity prices are known, BGS has been layered into the tune of 100 percent next year, 2 thirds of the year after, 1 third of the year after that. So the timing of all this is that the PGM proposal would only apply if we did get the ZEC. We'll find out if we get the ZEC in April.
And at that point in time, assuming we get the ZEC and assuming that the PGM 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 of that. Typically, the LDCs put their comments in, 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 made comments shortly thereafter.
FERC finalizes the RPM auction in the April timeframe, we find out whether or not we get a ZEC in the same timeframe. The auction takes place in August. In the fall, we if we are a ZEC recipient and if the auction has taken place, per 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 all works just fine.
Excellent. Thank you all.
Your next question is from
the line of Greg Gordon with Evercore ISI.
Thanks. Good morning all. 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 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 Q2 going into the Q3 from the Q2, realized spark spreads were not very different from what the forward curve was telling us?
Yes, 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 out and out our volume amounts are down a little bit. So if you think about where we had them pegged at the beginning of the year and where they ended up, they're down about a 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 on an awful lot of our hedges are not perfect hedges at the exact generator bus 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.
Okay. So that basis is basically what it costs you to move the power to the hub where you're hedged?
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 it on at the Western Hub. And to the extent that you saw a 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.
Great. One last follow-up. The $0.06 that you booked on the mark to market associated with I forget exactly what it was, was it pension or associated with trust. Was that an expected item? Or was that something that was an unexpected benefit in the quarter, the tax reserves?
Yes, yes, yes, 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 carryback of losses back to an earlier year with higher tax rates. But the direct answer to your question was yes, that was expected.
Okay. So that wasn't an unexpected gift, that was in the guidance already?
That's right.
Thank you, guys.
Take care.
Hey, 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 the obvious when we initially give guidance at the beginning of the year, we give a range and we expect to somewhere in the middle, otherwise we wouldn't bias numbers one way or another. And typically at the end of the second quarter, we try not to change that because it's still early, there'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 towards the lower end of that range, but still within the range and the utility towards the upper end of that range, but still in the range. And then the 3rd 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 the utility occurred in the Q3. That's not the case.
Okay. Yes, that was my intuition. I just wanted to make sure I understood it. I appreciate you clarifying. Thank you.
Your next question is from the
line of Jonathan Arnold with Deutsche Bank.
Hi, good morning guys.
Hey, Jonathan.
Hey, Mig, great. Just I wanted along the lines of just where Greg was going, when we look at the Q4 guidance now for Power and where you were through the 9 months, I mean, the low end suggests that you might have as low a quarter as a $20,000,000 quarter in Q4. It just seems that that would be unusually low for you. So I'm just curious, is that some of these same issues sort of working into Q4 as well or there's something else about Q4 that's kind of in the plan that we maybe need to remember?
No, I mean, 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 one time in the last year's Q4. So if you just go against that as a comparison, you have to carve out some of the one time items as you look at the 2 quarters compared to one another. So it's something to keep in mind in that regard.
But you do have a couple of shoulder months in the Q4 and you also have a lot of the outages that will go on during some of those shoulder months. So you can get some variability as you go year to year.
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 100 of 1,000,000. 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?
So we'll update that at EEI in a week or so, Jonathan, rather than trying to give that piecemeal here today.
Okay. Well, I guess we'll see you then. Thank you, guys.
Your next question is from
the line of Christopher Turnure with JPMorgan.
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?
Yes, Chris, so first of all, I can't give you the details 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 is appropriate to it, which may not have been more expected in a base rate filing.
Okay. That's helpful. And can you give us a sense as to what some of the other mechanisms might be there if it's not an outright decoupling mechanism?
I'd rather not go into that now since we haven't even sat down and gotten the discovery questions from the other parties. But there's all sorts of stuff that one can do to get contemporaneous type recovery of both of investments being made as well as truing up for what might have been anticipated to be revenues versus what's realized in revenues either in 6 months or annual filings or things of that nature.
My second question was on weather versus normal on the utility side. Can you quantify that for the quarter or the year to date? And then just related on the corporate side, anything change versus your original plan there other than just the interest rate on new debt?
Yes. 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 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, dollars 3 of that in the quarter and volumes demand about $0.02 year to date and about $0.01 on the quarter. So you can see it broken out pretty cleanly within the slides that we've 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.
Okay. And then just on those weather numbers, were those year over year or were those versus normal?
Those are year over year.
Okay. Any sense as to versus normal or is that something we could take offline?
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're almost the same if you take a look at versus last year versus looking at normal.
Okay. Thank you.
Your next question is from
the line of Michael Lapides with Goldman Sachs.
Hey, guys. Thanks for taking my question. Real quick, if I go back to the Analyst Day and look at the PSE and G forecast capital spend And then I think a little bit about some of the filings that you've made in the last few months. How should we think about where you're tracking and whether you think you're likely above what 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?
Yes. I mean, Mike, I think that we got GSMP II approved in April and we had our conference in May. So that was accounted for. And I think if you really look at the major areas that we were talking about, 1 was Energy Strong, Energy Strong II, I should say. And Energy Strong II, we talked about putting forth a $2,500,000,000 filing.
And in June, we put forth a $2,500,000,000 filing. And we said in May that we were going to put forth a clean energy filing of $2,900,000,000 and those programs and the magnitude of those programs is, were filed as we talked about with one exception and Ralph talked about that 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 $3,600,000,000 versus the 2,900,000,000 dollars and you can attribute the full amount of that delta to the AMI component of that filing. Now that'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 2 issues.
1, years is more than 5, but number 2, 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 'eighteen. And then similarly for Energy Strong 2, it's a 5 year program. And since it was filed into 'eighteen and we won't see an approval of that until the process runs, you're going to have some more spillover 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.
Meaning the 10% assumes you
get full approval of both of those of
Energy Strong II and the clean energy filing? Or does it assume something in the middle of what you asked for versus often where you see intervenal requests come in at a slightly lower number?
Yes. It assumes approved as filed for the periods within that 5 year period. And it also assumes that there's no other incremental programs for the balance of the 5 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 added.
Got it. And then one last one. How are you looking at the potential changes to transmission spend over the next 3 to 5 years versus what you laid out? I mean, if I go back over time, what you laid out in the Analyst Day for years 3 years 4 and beyond, the numbers actually usually as you rolled forward a year or 2 came in higher as PJM recognized incremental needs or as you recognized 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 the spin at the Analyst Day?
So is the question how does our forecast differ from our forecast?
Well, a little bit of are you seeing incremental opportunities that may not have been embedded in the forecast?
Yes. I think we're a few months away from when we put that forward, and is still how we are characterizing the 5 year capital plan at this time.
Okay. Last item, a little bit housekeeping. O and M at the utility year over year and sequentially was up a double digit percentage. How much of that drops to the bottom line? Meaning, I'm just looking at the quarter.
So you're talking about for the quarter for PSE and G, the $0.02 incremental O and M?
Yes.
All of that $0.02 drops to the bottom line, if that's your question.
Got it. Okay.
Yes.
Got it. Thanks, guys.
Thanks.
Your next question is from the line of Paul Fremont with Mizuho.
Thanks.
Looking at Fast Start, I guess, Exelon, I think, has put out estimates that would imply maybe 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 you're what you're expecting in terms if Fast Start is adopted?
So there's 2 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 significant down payment on that, possibly in that $1 to $3 range. But the question is, what is the degree of 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 Q1. I don't know the answer to that, but that's the 2 considerations you have to make, right. So should Fast Start result in an increase?
Absolutely. It already in the forward price curve? Depends on your confidence in the timing of the FERC decision.
Great. Thank you very much.
Your next question is from the line of Shahriar Pourreza with Guggenheim Partners.
Hey, good morning guys. Hi, Shahriar.
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?
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've proposed 35 megawatts. So yes, there is upside there.
Would that be within is that a back end loaded or when do you think you'll figure that out as far as
One of the conversations we've been having with the policy leaders 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, is an iterative conversation that we have that we is an iterative conversation that we have that we do have with policy leaders both in the BPU and in the Governor's office and the legislature.
And then Ralph just on one of your peers is out talking about $5 to $10 of per megawatt hour of incremental cost when you layer it in with wind or sort of solar on 2 to 4 hours of sort of storage. Are you seeing figures like that or seeing higher figure? Because if you use 2 to 4, it seems like you could probably get something that's economically viable, right?
Yes. So I'm not I'm used to quoting it in terms of capacity and the number we use is $2,000,000 to $3,000,000 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.
Okay, great. I'll bother Dan later. And then just lastly, what drove the lower capacity factors on your nuke assets for the Q3?
On your nuke? Was it a Hope Creek outage? Was it a 100% ownership of Hope Creek?
They're at 93% if we had a peach outage. It's nothing but kind of your normal outages.
Okay, got it.
Okay, thanks guys. Terrific. Dan, I'll follow-up with you after the call.
Thanks.
Your next question is from the line of Angie Storozynski with Macquarie.
Thank you. So two questions. 1, FERC has just updated its ROE methodology now, but there also seems to be some discussion about maybe 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?
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 3 methodologies that FERC are using all do then lead to a discussion about how does each specific company and its risk profile fit 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.
Okay. And then, so the equity layer at the utility under the rate case settlement or decision is now going to be 54%. I think you mentioned that 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?
No, Angie, our 51.2% 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.
That's great. Thank you.
You're welcome, Asia.
The next question is from
the line of Andrew Weisel with Scotia Howard Weil.
Hey, thanks for squeezing me in. I guess, good afternoon. We're past the hour here. Quick first one on the PSE and G guidance for the year, the midpoint essentially went up by $0.10 on an EPS basis. But when I look at the year to date weather benefit versus normal, that was only around $0.03 So what else is taking you ahead of the plan?
And would any of that be sustainable to benefit future years?
Yes. I think in addition to the area that's just labeled weather, 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 other modest items that would end up moving in north of that. So I think 2 things for you. 1 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 could get to that range.
Okay. The smaller adjustments, should we think of those as sort of one time or will that carry through?
I think more one time than that.
I think one of the one time adjustments, we may be a little bit conservative on the timing of the rate case.
I see. Okay. Good. Then the other question I had on AMI, you mentioned that the 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 utilities to file for cost benefit analysis. I guess my question is, is it a little premature to file for the $700,000,000 program now and how comfortable are you that it will be approved as part of the CES filing?
Well, we definitely do not think it's premature. There is a moratorium as you correctly pointed out, Andrew. 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're right. But the second is this huge initiatives 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 his priorities.
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? So that's a possibility?
Yes, that's correct. And we didn't go into details, but we did the CEF is really 3 separate filings that were all put in at the same time, but that's correct.
Okay. Thanks everyone.
We have reached the allotted time for questions. Mr. Izzo, Mr. Craig, please continue with any closing remarks.
Okay. Thank you there. So hopefully the takeaway from this call was 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 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 is 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. Ladies and gentlemen, that does conclude your conference call for today. You may disconnect and thank you for participating.