Public Service Enterprise Group Incorporated (PEG) Q3 2018 Earnings Report, Transcript and Summary

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. [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.

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 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 Cregg, 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 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 6 and 7 summarize the results for the quarter and the year-to-date periods. Now throughout a 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 conditioning 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 five 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 durations. 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, five 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 you 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 bill 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 requirement is based upon a 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. 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 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 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. 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 the new – of New Jersey’s zero-emission 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 three 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 a 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 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. But then 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 recognize that energy and capacity payments, and 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 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 and 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 interests 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 Second and Seventh Circuit courts of appeal, respectively, concluding that those states have the authority to implement their ZEC programs, 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, 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 a reconciliation of non-GAAP operating earnings to net income for the quarter and nine months can be found on slides 6 and 7. 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 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, 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 a 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 an on investments made since 2010 outside of the programs with cost base recovery, in addition to the recovery 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 $9.5 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 to 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 in 2018 from these two programs is forecast to be approximately $53 million as we near completion of the first GSMP and 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 $1,055,000,000 $1,070,000,000, up from a $1 billion to $1,030,000,000. 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 the $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 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 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 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 of 2018 and will run through May 31 of next year. Recontracting of hedges at lower prices and the market impact of lower spark spread in PJM East reduced results by $0.10 per share compared with the third quarter of 2017. Power experienced a $7 per megawatt 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 in service, along with higher demand, boosted generation volumes by $0.06 per share. Higher O&M expense of $0.01 per share reflects new unit 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 the 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 five 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 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 to 56 terawatt-hours from last quarter’s reduced estimate of 53 to 55 terawatt-hours. For the remainder of 2018, Power has hedged 80% to 85% of total forecasted production of 13 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 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 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-2019 commercial startup of the 485-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, 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 $1,045,000,000 to $1,100,000,000, respectively, from $485 million to $560 million and $1,075,000,000 to $1,180,000,000, 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 30 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 $350 million of 2.3% 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.

[Operator Instructions] And your first question is from the line of Praful Mehta with Citigroup.

Hi guys. 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 costs, 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 heat rates have been coming down. So just some color on that, that’d be helpful.

All right. So there is 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 a lid 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 that 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.

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 is not more of a permanent issue?

We never had tried out just before a price curve, Praful. But we are seeing that with the opening of some pipelines that are taking Marcellus gas to regions other than the Mid – 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.

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 are some things we would quarrel with, perhaps the – their cutoff at the 20-megawatt 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 transport capability. There’s the 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 other things being equal, that should remove the price suppression for unsubsidized units. And that will set a different market price. I – 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 payment, as 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 the – 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 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 in the legislation if the plants were to not operate.

And just one reminder as well, Praful, if you think about it, the next three capacity auctions have – or the next three 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 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 for, reply, comments, are due on the 6th of November, but this will all impact the period after those three years.

Got you. very helpful for the color thanks so much.

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

Hi, good morning. So maybe perhaps to follow-up on Praful’s question. Just back to the forward hedges that you all disclosed in your slide. 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 cycles 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 the 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 have 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 is going to have an upward pressure on pricing. And Ralph talked about on the longer term as 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, Julien, always a defensive plan now 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 Keys plant, with the strengthening of gas prices in the M3 zone, we’ve seen some decrease 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 can – 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 you’re 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 three years, capacity prices are known, BGS has been layered in to the tune of 100% next year, 2/3 the year after, 1/3 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’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 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 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 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 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 will work just fine.

Actual 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 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.

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 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 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 a 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 cost you to move the power to the hub where you’re hedged?

That’s right. So for instance, if you think about our nuclear facilities, you’ve 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 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 the nuclear...

Yes, yes.

Trust? Was that an expected item? Or was that something that was an unexpected benefit in the quarter, the tax reserves?

Yes, yes, yes. So what that is, that’s a – that’s not on the NDT because you mentioned trust. Really what that is, is just the 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 was an unexpected gift that was in the guidance already?

That’s right.

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 the 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, during 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 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, the utility occurred in the third quarter. 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. So just I wanted – along the lines of just where Greg was going, I – when we look at the fourth quarter guidance now for Power and where you were through the nine months, I know – the low end suggests 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 sort of working into Q4 as well? Or is there something else by Q4 that’s kind of in the plan that we maybe need to remember?

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, your – you’ll have to carve out some of the onetime 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 shorter months in the fourth quarter, and you also have a lot of the outages that were going on during some of those shorter months. So you 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 100s 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?

So we’ll update that in a week or so, Jonathan, rather than trying to give that piecemeal here today.

Okay will guess 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, that was – so first of all, I can’t give you the details as to a settlement discussion because those are all confidential, but 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 it’ll – 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 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 contempering this type of recovery of both – of investments being made as well as trueing up for what might have been anticipated to be revenues versus what’s realized and revenues either in six months or annual filings or things of that nature. So...

And then...

Yes. Okay?

Yes. 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 changed 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 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, $0.03 of that in the quarter. And volume and demand was 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.

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 the 2017 summer was a little bit milder. But they’re almost the same at – 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.

Hi 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 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? Or 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 had GSMP II approved in April and we had our conference in May. So that was at Cannacord. 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 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 $3.6 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 six-year program. So if you’re trying to look at it within a five-year horizon that we normally talked about – that we talk 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 five-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.

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 intervenor requests come in at a slightly lower number?

Yes, it assumes approved as filed for the periods within that five-year period, and it also assumes that there’s 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.

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 numbers actually usually, as you rolled forward a year or two, came in higher as PJM recognized the incremental needs or as you recognized an incremental need 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 – 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 five-year capital plan at this time.

Okay. Last item, a little bit housekeeping. O&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 for – you’re talking about for the quarter for PSE&G, the $0.02 incremental O&M?

Yes.

All of that $0.02 drops to the bottom line, if that’s your question.

Got it. Okay, got it thanks Dan.

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 your – what you’re expecting in – if fast-start is adopted?

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 – in 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? And I don’t know the answer to that, but that’s the two considerations you have to make, right. So should fast-start result in an increase? Absolutely. Is 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 Shar Pourreza with Guggenheim Partners.

Hi, good morning guys. 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. So – and then – and it’s a big number, and we 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 how we should...

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 by the same stroke and you don’t want to pay for that market in its entirety up front. So there’s a little bit of a delicate timing of how much you do and when you do it that 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 our talking about $5 to $10 of – per megawatt-hour of incremental cost when you layer it in with wind or sort of solar on two to four hours of sort of storage. Are you seeing figures like that? Or seeing a higher figure? Because if you use two to four, it seems like you could probably get something that’s economically viable, right?

Yes, yes. So I’m not – 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 $3 to $5 per megawatt-hour. And I’d rather not do that in real time, which is short, but I will take that as a homework assignment.

Okay, great. I’ll bother Dan later.

Sure.

And then just lastly...

Nice, Shar.

What drove – no problem. What drove the lower capacity factors on your new gas assets for the third quarter? And just as a...

I didn’t actually – was it a Hope Creek outage? Was it like a 100% ownership of Hope Creek?

Yes. I think they’re at 93% – we had a huge outage. It’s nothing but kind of your normal outages that occurred at the time.

Okay, thank guys terrific. Dan, I’ll follow up with you after the call.

Thanks, Shar.

Your next question is from the line of Angie Storozynski with Macquarie.

Thank you. So two questions. One, FERC has just updated its ROE – its transmission 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 three methodologies that FERC are using all 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.

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, the – 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.

Great. Thank you.

Your next question is from the line of Andrew Weisel with Scotia Howard Weil.

Hey, thanks for squeezing me, and good afternoon. We’re past the hour here. A 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 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 it 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 other smaller adjustments and you could get to that range.

Okay. And those smaller adjustments, should we think of those as sort of onetime? Or will that carry through?

I think more onetime than not.

I think one – another one, Andrew, just is we may be a little bit conservative on the timing of the rate case.

Oh, I see. Okay. Good. Then the other question I had on AMI. You mentioned 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, so 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?

Well, 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’re right. But the second is the 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 packaged 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. Yes, that’s correct. And we didn’t go into details, but we did – CEF is really three separate filings that were all put in at the same time. But that’s correct.

Okay, thanks for everyone.

We have reached the allotted time for questions. Mr. Izzo, Mr. Cregg, please continue with any closing remarks.

Okay. Well, thank you there. So hopefully, the takeaway 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 the 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.

Well, ladies and gentlemen, that does conclude your conference call for today. You may disconnect, and thank you for participating.