公共服務電力與天然氣 (PEG) 2017 Q3 法說會逐字稿

Ladies and gentlemen, thank you for standing by. My name is Shelby and I'll be your event operator today. I would like to welcome everyone to today's conference, Public Service Enterprise Group Third Quarter 2017 Earnings Conference Call and Webcast. (Operator Instructions) As a reminder, this conference is being recorded Tuesday, October 31, 2017, and will be available for telephone replay beginning at 1:00 p.m. Eastern Time today until 11:30 p.m. Eastern Time, November 7, 2017. 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 Kathleen Lally. Please go ahead.

Thank you, Shelby. Good morning. Thank you for participating in PSEG's call this morning. As you are aware, we released our third quarter 2017 earnings statements earlier today. The release and attachments, as mentioned, are posted on our website at www.pseg.com under the Investors section.

We also posted a series of slides that detail operating results by company for the quarter. Our 10-Q for the period ended September 30, 2017, is expected to be filed today.

As you know, the earnings release and other matters that we will discuss in today's call contain forward-looking statements and estimates that are subject to various risks and uncertainties. And although we may elect to update forward-looking statements from time to time, we specifically disclaim any obligation to do so unless required to do so.

Our release also contains certain non-GAAP operating information. Please refer to today's 8-K or other filings for a discussion of factors that may cause results to differ from management's projections, forecasts and expectations and for a reconciliation of our non-GAAP operating information to our GAAP results.

I would now like to turn the call over to Ralph Izzo, Chairman, President and Chief Executive Officer of Public Service Enterprise Group; and 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.

Thank you, Kathleen, and thank you, everyone, for joining us today. PSEG reported results for the third quarter having executed well on major operational and policy initiatives. Despite the impact of abnormally cool weather on sales and earnings, we remain within our non-GAAP operating earnings guidance for the full year of $2.80 to $3 per share.

Earlier this morning, we reported net income for the quarter of $0.78 per share, non-GAAP operating earnings for the third quarter of 2017 were $0.82 per share compared with net income of $0.64 per share and non-GAAP operating earnings for the third quarter of 2016 of $0.88 per share.

For the 9-month period, non-GAAP operating earnings were $2.36 per share, which is the same as non-GAAP operating earnings for 2016's first 9 months. Slides 5 and 6 contain the detail on the results for the quarter and the 9 months. At PSE&G, earnings per share declined $0.01 per share from the prior year comparable quarter. The results for the third quarter were affected by cooler than normal weather, which reduced demand for electricity from air conditioning. The weather comparisons to last year are stark. For instance, the measure of average temperature and humidity was 27% below the year-ago quarter and the number of hours at temperature equal to or greater than 90 degrees was 69% below the year-ago quarter.

PSE&G's expanded investment in transmission and distribution continue to benefit customers and had a favorable impact on PSE&G's earnings. PSE&G's rate base is forecasted to grow 12% in 2017, reaching $17 billion. The forecast is based on a continuation of PSE&G's investment program to upgrade its transmission and distribution infrastructure. The upgrades will entail full-year capital expenditures of approximately $3.1 billion. This figure is slightly less than our original budget of $3.4 billion and it's the result of some projects being moved to 2018 and improved efficiency related to the cost of other projects.

Based on further development of our various investment programs, we are increasingly comfortable with PSE&G's ability to achieve growth in rate base at the upper end of our forecast of 7% to 9% per year for the 5-year period ending in 2021. Our updated forecast assumes a reasonable reception by the New Jersey Board of Public Utilities to PSE&G's proposal to invest $540 million per year over 5 years to accelerate the pace of replacement of aging cast iron and unprotected steel mains and their associated services. Approval would support expansion and extension of the work currently being performed under the Gas System Modernization Program. This filing was made in July, and we expect the BPU to take action during the first half of 2018.

We also intend to request a multiyear extension of Energy Strong in the near term. PSE&G is in the final stages of work previously approved as part of Energy Strong to strengthen and harden infrastructure damaged during Hurricane Irene and Super Storm Sandy. The extension will address the remaining electric substations that need to be raised or protected in addition to other much needed work that enhances the resiliency of our system and reduces the risk of outages. That request, similar to GSMP 2, will be consistent with the BPU's draft regulation supporting multiyear capital investments under its Infrastructure Investment Program. If the draft regulations are approved, as we expect, before year-end, utilities will be able to proceed with 5-year investment programs that will allow more certainty in staffing and planning of work.

Now I want to bring you up-to-date on PSE&G's Distribution Base Rate Proceeding. As you may be aware, following discussions with BPU staff and Rate Counsel and as approved by the BPU at its October 20 meeting, the deadline for filing our distribution rate case was deferred from November 1 to no later than December 1 of this year. The change in the filing date is simply an administrative procedural matter. We will now be providing the BPU with 3 months of actual data and 9 months of forecast data for the same test year that will end on June 30, 2018.

The review of PSE&G's distribution rates, which is expected to result in a modest change in revenue, is primarily driven by the need to recover investments made outside of clause mechanisms since the last rate case to recover storm costs and to allow PSE&G to reset assumptions for growth in sales and O&M. As part of the filing, PSE&G will also be seeking approval to decouple electric and gas distribution revenue from sales volumes and demand, which would support larger scale energy efficiency investments.

We believe that with the right regulatory policies, the state's utilities can provide the energy infrastructure that meets customer requirements and creates a stronger and more efficient New Jersey.

Now let me turn to PSEG Power. AT PSEG Power, non-GAAP operating earnings declined by 9% to $0.31 per share from the prior year comparable quarter. A lower average price on energy hedges was partially offset by Power's continued efforts to lower its costs and Power's favorable gas supply position. PSEG Power also made progress on construction activities related to its 3 new natural gas combined-cycle generation stations. The new stations will add 1,800 megawatts of efficient capacity over 2018 and 2019 and represent a reconfiguration of Power's merchant fleet that will improve its efficiency and competitive position in the market.

The design of the wholesale energy market and whether current policies provide adequate recognition of the cost for generation to be available is getting the attention it needs. The Department of Energy issued a notice of proposed rulemaking at the end of September regarding the need to properly value baseload generation with robust on-site fuel characteristics. We hope their interest in this important issue will jump-start efforts by the Federal Energy Regulatory Commission to implement improvements in the market. It is encouraging to see that FERC has acted quickly. To meet the DOE's 60-day requirement for a response, FERC requested comments on the DOE NOPR to be filed by October 23, with reply comments due on November 7. A response by the FERC to the DOE NOPR is anticipated by December 11 of this year.

PSEG filed comments in support of DOE's initiative to immediately address the erosion occurring and the resiliency of our electric grid due to the risk of premature retirements of baseload generation and the subsequent trend towards greatly reduced fuel diversity. We believe that the DOE NOPR is necessary to address the challenges facing distressed yet valuable resources such as nuclear in the absence of a market solution that recognizes the attributes of fuel diversity and resilience. We recommend that measures adopted in response to the DOE NOPR should be viewed as interim until effective mechanisms can be developed that recognize these attributes in the market.

The current market design distorts efficient outcomes due to the disharmony between price signals, public policies and generation dispatch. Implementing the DOE measure as an interim step would stabilize the earnings for qualified units until a comprehensive market-based solution can be integrated into RTO and ISO market designs. It is worth mentioning that a significant amount of generation that competes in the PJM market already falls under cost of service regulation. We believe that DOE NOPR also provides the necessary impetus to push for further action by FERC to address long-standing price formation reforms that would avoid some of the continued distortions of competitive market results that disadvantage baseload resources.

The PJM energy price formation proposal should be evaluated as part of the comprehensive solution to the challenges facing baseload units. As part of our response, we have requested that FERC promptly finalize the fast-start pricing reforms and direct PJM through the commission's Federal Power Act Section 206 authority to submit its energy price formation proposal, especially as it pertains to inflexible units. Getting energy prices right is critical to ensuring that the correct signals are sent to incent efficient investment as well as market exit.

PSEG Power is making every effort to preserve its nuclear asset base, working in concert with the industry to identify means of improving operating efficiency without sacrificing safety. PSEG Power is on track in 2017 to reduce the all-in cost per megawatt hour of its nuclear operations by 10% from the average cost experienced during the prior 3 years. But energy prices, influenced by the availability of natural gas, have declined by a greater degree during this time frame.

State action also remains critical to prevent the loss of these units. We believe state action can be done in a way that both maintains the integrity of the wholesale market and serves as a bridge until a regional or federal solution is in place. A strong legal foundation has been established for state action to preserve generating assets critical to meeting a state's emission-related goals and to maintain the benefits to the state's economy that comes with the safe, reliable operation of nuclear power.

Successful execution of PSEG's key policy and regulatory initiatives would assure the company's ability to provide customers with the service, reliability and resiliency that they have come to expect that is also affordable. Successful execution of our key policy and regulatory initiatives would also provide our shareholders with greater assurance of PSEG's ability to meet our objectives for returns and growth.

With that, I'll turn the call over to Dan to discuss our financials in greater detail.

Thank you, Ralph, and thanks, everyone, for joining us today. As Ralph said, PSEG reported net income for the third quarter of 2017 of $0.78 per share versus net income of $0.64 per share in last year's third quarter.

Non-GAAP operating earnings for the third quarter of 2017 were $0.82 per share versus non-GAAP operating earnings of $0.88 per share in last year's third quarter. The reconciliation of non-GAAP operating earnings to net income for the quarter and 9 months can be found on Slides 5 and 6. 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 major business and a similar chart on Slide 13 provides you with the changes in non-GAAP operating earnings by major business on a year-to-date basis. I'll now review each company in more detail.

Starting with PSE&G. PSE&G reported net income of $0.49 per share for the third quarter of 2017 compared with $0.50 per share for the third quarter of 2016. Results for the quarter are shown on Slide 15. Net income growth in the third quarter associated with PSE&G's expanded investment in transmission and electric and gas distribution facilities was offset by the impact on sales of weather conditions which were substantially cooler than experienced in the year-ago quarter and cooler than normal. Returns on PSE&G's expanded investment in transmission added $0.04 per share to net income in the quarter.

Incremental revenue associated with the recovery of PSE&G's Energy Strong investment infrastructure program, which added $0.02 per share to net income, was offset by a decline in weather-normalized electric sales and in electric demand-related revenues. Demand-related revenues were impacted by the significantly lower peak temperature hours, which, as Ralph mentioned, were 69% lower than the year-ago quarter and 47% below normal. Net income comparisons were also hurt weather conditions, which were approximately 27% cooler than conditions experienced during 2016 in the third quarter and 5% cooler than normal.

Electric sales, as a result of the cooler summer weather, declined 8.3% in the quarter. The decline was led by an approximate 14% decline in sales to residential customers. On a trailing 12-month basis, weather-normalized electric sales were flat year-over-year and gas sales on a similar basis increased 1.5%, led by the commercial sector.

The decline in electric residential sales reduced third quarter net income comparisons by $0.03 per share. An increase in depreciation expense of $0.01 per share associated with PSE&G's expanded capital base was offset by a decline in O&M expense. An absence of tax credits available in the year-ago quarter and other items reduced net income comparisons in the third quarter by $0.02 per share.

PSE&G's 5-year capital investment plan includes approximately $6 billion to upgrade and expand transmission-related facilities and investment. PSE&G filed an update of its formula rate for transmission at the Federal Energy Regulatory Commission in October of 2017 and the update, which reflects an increase in the level of PSE&G's investment in transmission and a true-up of prior year results, provides for a $212 million increase in annual transmission revenues effective January 1, 2018.

PSE&G under Energy Strong and the clause mechanism therein, adjust electric rates 2 times per year, in March and September, and gas rates are adjusted each year in September. Under the clause mechanism for the Gas System Modernization Program, PSE&G adjusts gas rates in January of each year to reflect the investment made during the prior year. The combined annual revenue increase for the full year in 2017 for these 2 programs is forecasted to be approximately $56 million. As Ralph mentioned, PSE&G has agreed to delay the filing of its distribution rate case by 1 month to no later than December 1, 2017. This filing, as you recall, was agreed to as part of the Energy Strong settlement and provides the opportunity for PSE&G to recover capital investments made outside of existing clause mechanisms and update for other factors such as storm costs and changes in sales growth in O&M. The distribution base rate filing will be based on a test year ending June 2018 and a 10.3% return on equity and provide for a mid-single-digit increase in revenues, still leaving overall rates below the level coming out of our last distribution base rate case in 2010. The 1-month delay in the filing hasn't changed any of the economics associated with the request as the test year is unchanged, but allows 1 incremental month of actual results to be included in the filing.

PSE&G invested approximately $2.1 billion for the 9 months ended September 30 and electric and gas distribution and transmission capital projects designed to provide more reliable, safe and resilient service to its 2.2 million customers. For the year, PSE&G currently expects to invest $3.1 billion on upgrading its infrastructure, and this is slightly lower than the $3.4 billion we originally forecast for 2017. A delay in timing on some projects and greater cost-related efficiencies on others are the primary reasons for the decline in the forecasted spending for the full year. As Ralph mentioned, as a result of identifying incremental investments, we now expect PSE&G's investment program for the 5 years ended 2021 will provide growth in rate base off 2016 year-end amounts at the upper end of our 7% to 9% per year growth rate. This is driven by incremental investments in our GSMP 2 filing relative to what is reflected in our base capital plan and a planned expansion of our Energy Strong filing. These important initiatives build confidence in PSE&G's ability to extend its growth beyond the end of this decade. For 2017, we are maintaining our forecast of PSE&G's net income at $945 million to $985 million.

Now let's turn to Power. PSEG Power reported net income of $136 million or $0.27 per share for the third quarter of 2017 compared with net income of $139 million or $0.27 per share for the year-ago quarter. Non-GAAP operating earnings were $0.31 per share for the third quarter of 2017 compared to non-GAAP operating earnings for the third quarter of 2016 of $0.34 per share. Non-GAAP adjusted EBITDA for the third quarter of 2017 was $356 million versus non-GAAP operating EBITDA for 2016 of $387 million. Our 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 19 provide you with detailed analysis of the impact on Power's non-GAAP operating earnings quarter-over-quarter. And we've also provided you with more detail on generation for the quarter and the first 9 months of the year on Slide 20 and 21.

Power's net income in the third quarter was impacted by a decline in average energy hedge prices and the effect of cooler-than-normal weather on demand and output, which offset a decline in operating and maintenance expense.

During the quarter, non-GAAP operating earnings comparisons increased $0.01 per share as a result of higher capacity prices in New England and PJM. This increase in capacity prices occurred on June 1, 2017, and will run through May 31, 2018.

Lower average prices on energy hedges and a decline in market prices combined to reduce non-GAAP operating earnings comparisons by $0.05 per share, a 6% decline in output associated with the impact of cooler-than-normal weather on demand, reduced non-GAAP operating earnings comparisons by an additional $0.02 per share. Power's focus on improving operational efficiencies helped mitigate the impact of the decline in energy prices. The June 1, 2017 retirement of the Hudson and Mercer coal stations and a decline in nuclear plant-related O&M improved non-GAAP operating earnings by $0.02 per share and a decline in depreciation expense associated with the retirement of Hudson and Mercer, combined with a decline in interest expense and taxes, improved non-GAAP operating earnings comparisons by $0.01 per share.

Now let's turn to Power's operations. Output of Power's generating stations declined 6% in the quarter. The nuclear fleet's output increased 20% in the third quarter to 8.2 terawatt hours as the fleet's capacity factor improved to 96% from 80%. The quarter-over-quarter improvement was due to strong performance at Hope Creek, which operated at an average capacity factor of 98.4%; and the absence of an extended refueling outage and repairs at the Salem station in the year-ago quarter, which addressed the repair; and replacement of baffle bolts at Salem 1 and repair of a transformer at Salem 2. The nuclear fleet's performance for the third quarter brought the capacity factor for the 9 months ended September 30 to 95%.

As mentioned, cooler-than-normal weather limited energy pricing, peak demand requirements and utilization of the gas-fired combined-cycle and peaking fleet. Power's combined-cycle fleet experienced a 29% decline in output to 3.7 terawatt hours, while an increase in the price of gas improved the competitive position of the base load coal fleet.

As we indicated earlier this year, average hedge prices during the second, third and fourth quarters of the year were expected to decline by less than what we experienced in the first quarter and by less than the average decline of $5 per megawatt hour we anticipated for the full year. This reflects the absence of weather-related risk premium during the winter months that was experienced in prior years.

Gas prices improved in the third quarter, but since Power prices didn't move in conjunction with gas, spark spreads declined relative to year-ago levels. Power's realized spark spreads held up better than the market, declining $1 per megawatt hour quarter-over-quarter given its beneficial gas supply position. And Power's beneficial gas supply position also held gross margins in the quarter to a decline of $1.50 per megawatt hour to $40 per megawatt hour. Power continues to forecast output for 2017 of 49 to 50 terawatt hours, approximately 86% of production for the remainder of the year of approximately 11 terawatt hours. It's hedged at an average price for $45 per megawatt hour. Power has hedged approximately 70% to 75% of 2018's forecast output of 52 to 54 terawatt hours at an average price of $41 per megawatt hour. And for 2019, Power has hedged 30% to 35% forecast output of 58 to 60 terawatt hours at an average price of $39 per megawatt hour.

The average price for energy hedge in 2019 is $2 per megawatt hour lower than our prior forecast and the reduction reflects a decline in market prices. The forecast of output for 2018 and 2019 remains unchanged from prior estimates. The forecasted increase in output in both 2018 and '19 reflects the commercial start-up in mid-'18 of 1,300 megawatts of new gas-fired combined-cycle capacity at the Keys Energy Center in Maryland and at Sewaren in New Jersey. And the forecast increase is also supported by the commercial start-up in mid-2019 of the 485-megawatt gas-fired combined-cycle facility in Bridgeport Harbor, Connecticut.

Our forecast of Power's full year 2017 non-GAAP operating earnings remains unchanged at $435 million to $510 million. The forecast represents non-GAAP adjusted EBITDA of $1,080,000,000 to $1,210,000,000.

Now let me turn briefly to PSEG Enterprise and Other, which reported net income of $0.02 per share for the third quarter of 2017 compared with a net loss of $0.13 per share for the third quarter of 2016. Results for the third quarter of 2016 were impacted by the impairment of the REMA leases. Non-GAAP operating earnings for the third quarter of 2017 were $0.02 per share compared with non-GAAP operating earnings of $0.04 per share for the third quarter of 2016.

The decrease in non-GAAP operating earnings quarter-over-quarter reflects the absence of certain tax items recognized in the third quarter of 2016 as well as higher interest expense at the parent. And the forecast for Enterprise and Other for the full year of 2017 non-GAAP operating earnings remains unchanged at $35 million.

PSEG also closed the quarter ended September of 2017 with $287 million of cash on its balance sheet and with debt at the end of the quarter representing approximately 49% of consolidated capital. PSEG Power had debt at the end of the quarter representing 31% of capital. And as Ralph mentioned, we are maintaining our guidance for 2017 non-GAAP operating earnings of $2.80 to $3 per share.

And Shelby, we are now ready to take questions.

(Operator Instructions) Your first question comes from Julien Smith from Bank of America Merrill Lynch.

So perhaps just to kick it off a little bit here on the New Jersey and some of the background of the politics there. I'd be curious, one, do you think there's potential for reform in New Jersey just given what's already going on at the FERC level? And then secondly, in that same vein of thinking, how do you think about the potential for a more comprehensive review of energy next (inaudible) you see there's some considerations with respect to solar in addition to the nuclear issues that you've addressed, as well as just your ongoing utility spend and the extension and expansion of those programs. So to the extent to which that legislation might be a fix for all, I'd be curious how that might be shaping up.

Sure, Julian. Yes. I do think that depending on what happens at the federal level, there remains the opportunity for New Jersey to recognize certain attributes that perhaps are not explicitly identified at the federal level. To the extent that the federal level does recognize the same attributes then you would not have redundant programs. So an example of that might be, you could have price formation improvements at the federal level just to make the market more efficient, sort of along the lines of what PJM has talked about with inflexible units. And that doesn't do anything explicitly for fuel diversity or resiliency, and therefore, New Jersey could have an overlay on top of that. Similarly, fuel diversity versus carbon would be mutually exclusive. But if both jurisdictions recognize carbon, then you would not have 2 programs overlapping each other. Those are just the types of examples I would think about in terms of state and federal programs being complementary versus redundant. To your second question, whenever you have a change in administration, and as you implied, Governor Christie is term-limited now, he is finishing his second term, there's a desire on the part of the new incoming administration to establish themselves in various ways. It could be environmental, it could be the economy, it could be education and both candidates have talked about their desire to look at things a little bit differently when it comes to energy policy discussions about REGI and green energy targets. And we absolutely -- as we've done for 110 years, we absolutely will work with the incoming administration to understand their policy objectives and inform the (inaudible) the implications, both positive and negative, of whatever wants to be done because, as we know, things cost money to do, but if the benefits outweigh the costs, then we're eager to help them pursue it. So yes, we will work closely with whoever the new governor is to help them formulate and execute their energy policy. Lastly, I think you're correct in your, if I could say, implicit remark that an ongoing investment in the infrastructure is something that, no matter who comes into office, we'll probably would be supportive of. And I do think that's correct. There's a widespread recognition on the part of regulators and policymakers that we have an aging infrastructure that's not perfectly suited for the growing dependency that people have on electricity nowadays. And the improvements we're making, we'll certainly continue to propose them and I think we'll be well received.

Excellent. Just a follow-up, again, congratulations on moving higher within your range here at the top end on the rate base side. Can you talk about reconciling that against earnings and some of the key factors that might be relevant in the current rate case and/or through the current period just in an attempt to reconcile the rate base trajectory against kind of hitting the upper end of that earnings? Perhaps, items might include like an authorized equity ratio or other deferred items in the context of this case that we should be paying attention to once it's filed?

Yes. So our last base rate case was in 2010 and we've done a very good job of controlling O&M expense, but circumstances have conspired against us by having a complete absence of load growth over that time, so even a very good job of controlling O&M expense loses out to no load growth. We've also, as you know, had some of our clauses anticipate this rate case. So we had some unrecovered CapEx and then we had some modest investment levels above depreciation that served to build the rate case to levels that were not commensurate with what was in the 2010 rate case. That's a really long-winded way of saying we need some rate relief, but we've managed our overall portfolio well enough that we are describing this as a kind of a middle single-digit type of rate increase, which will be far below the compounding of CPI over the last 7 years that one might otherwise have expected. So I think it'll be something that is easily explained. Now the 7% to 9% CAGR in rate base is more a prospective conversation. My last 3 minutes was really looking in the rearview mirror, but now as I look out the windshield, now basically, we have, as you know, in our 7% number, programs that were wholly approved, then the 7% to 9% number anticipated some fairly high degree of confidence in some program extensions and I think what you're hearing in our voices today is that, that confidence has grown as we've been able to put our engineers to work and understand some of the parts of the system, both gas and electric, that needs strengthening. So as you think ahead to earnings, and, as you know, we don't forecast earnings beyond the current year, the 3 levers you have in the regulated utility are earnings grow with load. I think, Kathleen, again, we're seeing 0.4%, 0.5%. Is that forecasted?

Within the last 12, that's about right.

And then you subtract from that O&M. We've been pretty good at controlling that. And you add to that the clauses that we expect to get recovery of. So it's 2 additions and 1 subtraction and you'll get pretty close to what the utility should look like in the coming 5 years.

Got it. So let me just make sure what I'm hearing you say is, it shouldn't be all that different notwithstanding any kind of uncertainties with respect to the [K]?

Yes, I think, that's correct within the limitation of -- as you know, we don't smooth for pensions, so some massive change in pension funding, which we don't expect. We're 92% funded right now. But the equity ratio could be adjusted in the case to -- we're probably going to ask for a skosh more. Is that a word? A bit more than we used to have in the past. And so yes, the case could set a new base from which that upper end of the 7% the 9% can grow.

Your next question comes from Praful Mehta of Citigroup.

So I got the point on the [SECs] and the DOE being mutually exclusive. Just wanted to understand, given, Ralph, your initial comments on the DOE initiative, how do you see it playing out? Like do you see it as a dollar per megawatt? Dollar per megawatt hour? Do you see -- how do you see that actually playing out? And do you see that how much, in terms of benefit, do you expect for your facilities?

Yes, so Praful, so of course, boy, I wish I could answer that definitively. But let me answer it in the way which we proposed that it be played out, which may or may not have any bearing with what actually happens. In our comments to FERC we basically said, first of all, bringing PJM in under Section 206 to do what PJM says needs to be done is a no-brainer. So the inflexible unit treatment, the fast-start reforms, that is long overdue and needs to be done. And that is the easy part. Others have estimated that could be anywhere from $2 to $4 per megawatt hour. Others have estimated that. Secondly, as it specifically pertains to the DOE recommendation put forth in a NOPR, we have pointed out that there is a substantial portion of PJM that is competitively positioned in the market, but yet receives cost of service rates from their state regulators. And on an interim basis, that can be replicated at the federal level through a version of RMR type, reliability must-run type contracts for the units that are at risk of premature retirement. And that would be an interim solution until one comes up with a market-based solution that values the diversity associated with these different fuel types. We have proposed one method that relates to tranching of the capacity markets. Others have proposed methods that relate to scarcity pricing in energy markets for different fuels, but that permanent solution will involve a longer discussion with affected stakeholders. So really, it's 3 steps. It's, "Hey, there's plenty of evidence already that fast start and inflexible unit price formation needs to be fixed now and can happen now. An interim solution for at risk premature retirement using a cost to service methodology can be put in place very easily and then the longer-term market-based solution, there are known solutions and options that people can pursue, but a more fulsome discussion would not be inappropriate in that regard."

Got you. That's very helpful color, Ralph. And secondly, in terms of long-term views, I know you've talked about, long term, the generation business probably not being a part of the consolidated business over the long term. Now given what's happening with the IPP space and either companies going public or shrinking, given the mergers, how do you see that playing out? Do you see -- has that changed in any way? Do you now see PEG Power being more part of the business going forward? Or has that -- the view on separation still hold at this point?

No, the view still holds, but I think it's pretty obvious to us, at least, that, right now, in the short term, with all of the conversations taking place at FERC, at DOE, at the state, with new entrants being formed and anticipating the Vistra-Dynegy combination, with old entrants exiting in terms of public markets, anticipating the Calpine going private. I think it's a -- this is a good time to just sort of wait and let something settle out a bit, right? So we're in great shape. Power is a cash generator and earnings producer. In about 15 months, Power will be a healthy free cash flow generator. The utility has an insatiable appetite for that cash. So we're not in any hurry during this period of tremendous change. All healthy, all very healthy given the dialogues taking place at FERC and given the dialogue taking place at the state to let it kind of play out while we enjoy the benefits of the 2 companies being together. That doesn't change the fact that we continually assess our strategic flexibility going forward on whether these 2 businesses belong together or not. And I stand by my prior belief that I think, over the long term, they do diverge.

Got you. And just to be clear, that time of change is what, a 2, 3-year period, while all of this kind of settles down? Do you see...

I did make that mistake about 3 or 4 years ago. And I may not be the smartest person in the world but I do learn from those mistakes. I'm not going to give you a time frame. Nice try, though, Praful. Kathleen started like choking me. So my voice broke a little bit, that's the reason.

Your next question comes from Greg Gordon of Evercore ISI.

It's Kevin here. I just wanted to see if you could quantify the uplift in PJM price reform as it's currently being contemplated.

So Kevin, what we quoted is what other sources have talked about. If you just take Dan's comments about 55 terawatt hours, every dollar's worth $55 million pretax. So if it's $2 to $4, I've just thrown 3 if statements in there, so please be aware of that, you come up with the impact on us. Dan, did you want to add some color to that?

I think that's right. I think there's been an awful lot of people that have put out some numbers on it and they have actually coalesced around that range pretty tightly. So we'll see, as these different initiatives get done, what it ends up looking like. But I think that seems to be a reasonable place a lot of the pundits are at and we think it's a pretty reasonable as well, Kevin.

Okay. So now, how would that impact your hedging? Would it -- would you like hedge less or stop hedging '19 if you start to see progress? Or how would you think about that?

So we have constantly disciplined ourselves to staying within a certain range in terms of how much we hedge. We have various parameters, gross margin at risk, standard VAR calculations. We do allow our ER&T folks, our trading organization, to float high and low in that range depending upon what's going on. To the extent that the whole market anticipates price formation, you should start seeing that in the forward price curve and therefore our hedging approach would stay the same. We do challenge ourselves, if we think the market is missing something to make darn sure that we can figure out why the market would be missing it before we would push one boundary or another. But in general, we'll run the place the way we always have, which is to not assume we're smarter than the market and to just stay within those limits. But again, those limits are a range and we do let our folks have some flexibility within that range.

(Operator Instructions) Your next question comes from Christopher Turnure of JPMorgan.

I wanted to get maybe a little bit more detail on the rate case, the test year and, in particular, kind of the true-up and what's included in that. I guess that would kind be a third quarter event after the test year ends on June 30, but I'm just trying to get a sense as to how next year will shape up there and what the rate case will ultimately include in terms of timing coming out of the gate.

Yes. So, Chris, so we had originally planned to file November 1 per the agreement we made back in May of 2014 coming out of Energy Strong. There was widespread recognition that, that would be a 2 and 10 and there was preference for 3 months of actuals and 9 months of forecast as opposed to 2 months of actuals and 10 months of forecast. And that was the primary driver behind the 1-month delay, if you will. So there's no -- nothing mystical or profound going on there. So the test year still ends in June of '18. As I mentioned before, we're expecting a mid-single-digit requested increase that will still keep rates below where they were in 2010 when we had our last base rate case. And remember, we have $250 million of GSMP stipulated rate base that was not covered by GSMP. We have about $100 million of Energy Strong, above the $1 billion that was in the clause. We have storm recovery costs, that's, I think, $200-something million that was deemed prudent but hasn't been returned to us yet. We have some new business that added to the CapEx. And candidly, we had some additional capital that was above depreciation levels that we've accumulated over the course of the years. So we would anticipate rates going into effect October-November of next year and I don't want to front run the filing. We owe it to the board's staff to let them be the first ones to read the details. But Dan, if you want to add any color?

Just one thing, Chris. It sounded like your question was implying there would be a rate case and then there would be a true-up afterwards. And the way that we described the rate case is, basically, it is a trueing up of a host of the things that Ralph's just talked about. So we will come out of the rate case with the rates that are set within that case. And historically, we've seen a settlement in these cases in the state and that may well be where it ends up going, but we'll see. We would look for rates next fall. Usually these have taken about a year, and we would hope to anticipate that we could get rates maybe in like the October range. But it's a little different than our transmission formula rate, which is filed, those rates going into effect for the following year and then there is a separate true-up that happens the year after that. So just, for clarity's sake, there's no true-up after the rate case. The rate case itself will true up our distribution rates and we would anticipate the new rates would be in effect, say, October of next year.

And just for -- I think most of you know this, but our rate base is roughly half transmission, half distribution right now. So tiny bit more distribution.

Okay. That was all very helpful context and everything, but that's kind of what I was driving at there, towards the end, Dan, just that the distribution rate case itself, would have a 9-month forecasted test year, but that, itself, would never be trued up during the rate case process.

Yes. So the 9 months, it will be a 12-year -- 12-month test year and it will start with 3 months of actuals and 9 months of forecasts. And then, as we step through, we'll update those as we go forward.

Okay. So you would have some update? On O&M or something during the process?

Yes. Yes.

Okay. Got you. And then just on the request for decoupling. Can you help put that into context for me, just kind of understanding your motivation for that and maybe how you think it may or may not be perceived by interveners?

Yes, Chris. So we've had a series of energy efficiency filings approved over the past 7 or so years. I think the total amount is about $400 million, the most recent one was $69 million this past summer. And we have basically worked around this issue of fixed cost recovery with the stakeholders in these processes. And it's kept us from doing something in a much grander scale and we've simply decided that with the prospect of a new administration coming in and ongoing indication that there are market imperfections that keep customers from investing in energy efficiency, despite the compelling economics of that, that we would like to do this in a much, much more significant way, but we're not going to do it and suffer fixed cost losses, the absence of recovery of fixed costs. So given the tariff-free design involved with decoupling, we thought, well, since we're going in for a rate case, now is a good time to raise the issue. And that's the motivation. The motivation really is not so much of this rate case, but the rate case is an opportunity to pave the way for significant energy efficiency proposals early next year.

Your next question comes from Travis Miller of Morningstar, Inc.

I was wondering if we could boil down all of these power market tissues into 2 buckets, the price formation bucket and the fuel diversity bucket. How do you think about, in the next 2 to 3 years, perhaps even more, of capital investment based on what happens in either of those 2 buckets? So what happens to capital investment depending on the outcome of price formation? What happens to capital investment based on an outcome in fuel diversity?

I can tell you what it means for us, Travis. We're not deploying additional capital into the power generation business. We have 1,800 megawatts of 6,000 to 6,500 heat rate power plants coming online and we're quite happy with that. At the risk of speaking for others, which is always going to be wrong, you know that PJM, in particular, and many other markets are in an oversupply situation and there's been a reasonable demonstration of capital discipline in the most recent auctions that have taken place. So I think that the supply/demand imbalance that exists is a separate issue that will continue to impart that capital discipline and the price formation issue is just the recognition that if you want a market to be efficient, then price should determine who runs and who doesn't and you can't keep having uplift payments and side bar out of market payments guiding the dispatch of the system, which is what PJM has going on right now. I mean, price is not the sole determinant of how the system is dispatched. Then that's not a market, so that needs to be fixed. So 2 separate issues, I guess, is what I'm saying.

Okay. And could I read into that, that you don't think there would much capital investment in general across, certainly, the PJM region however this turns out?

I think you could, without question, read into it that that's our point of view. Again, I don't want to speak for others, but I know what our capital plans are, and it's to finish these 3 projects and generate some healthy free cash flow for the utility.

Your next question comes from Paul Patterson of Glenrock Associates.

So just to follow up on Travis' question, what we often see with these market reforms is that others seem to deploy capital and I'm just wondering, when you see this $2 to $4 price increase in -- with price formation or potentially seeing that, how long term do you think that would be? Or is the proposal -- it's hard for me to really completely get my arms around it, is it such that you would still see locational marginal pricing being set by inflexible units even with new entry showing up in the gas-fired area, if you follow me? I mean, how should we think about sort of the sustainability of something like price formation given what we've seen, quite frankly, with the capacity markets and other “market reforms” to change the price, if you follow me?

Sure, Paul. That's fair. I think that one has to realize that there are -- there's cyclicality in these markets that have different periodicity associated with them, right? There's cyclicality in fuel prices, there's cyclicality in boom-bust cycles associated with oversupply and undersupply. There's cyclicality in oversupply and undersupply as determined by power plants being built, as determined by pipelines being built. So to simply say that price formation will drive prices up $3, picking the midpoint in the range that Dan and I have talked about, which we don't attest to but simply quote from others, and then automatically concluding that that's going to lead to people running their numbers and assuming that, that number stays there and, after, they'll build plants, could be a bit risky, right? I mean, what does it mean for the timing of pipelines that may change the basis differential of gas in Western PJM versus Eastern PJM? What does it mean for future carbon constraints that may or may not be part of a subsequent administration in Washington? I think all of us want to go -- some people on this call may want to go see their children in their Halloween parades, otherwise I'd list 1,000 other factors that should be going into people's thought process before making those kind of investment decisions.

Look, no matter how you slice it, having a market that is working better by virtue of some of the changes that need to be made is going to get you to a better answer.

Okay. And then, with respect to the DOE proposal, I know this is kind of -- sort of moonshot question, I guess, maybe. But how much assets should we think about as being potentially -- if it were to be enacted for you guys, how should we think about what the potential impact might be there? How many units -- just how do we sort of quantify that? If that were to -- I know it's kind of a hard question, maybe, to answer, but, I mean, how would you suggest we think about it?

I think, Paul, the way I would break it down is based upon how they have the DOE describe the eligibility so, and one of the main ones is having 90 days of fuel on site. And if you think about what that means, that means our nuclear facilities, certainly. And it means our small interest in Keystone and Conemaugh.

So all those units would theoretically be able to get a rate-of-return rate base or what you're getting at the utility kind of thing?

We'll see how where the -- ultimately where the NOPR goes with it. But certainly, from an eligibility standpoint, those are the units that would come to mind.

Okay. And I guess, we don't have -- do we have like a -- what the asset -- what the rate base number would be, kind of, if you follow me, associate with that? Do you follow what I'm saying? I mean...

Yes, I mean, but there's a little bit of data related to some of the nuclear facilities in the Q, but it's not on an asset-by-asset basis from a book value perspective.

Okay. Well, I'll follow up afterwards. I mean, I just was wondering -- I was just curious if you had some sort of idea there, but I don't want to hold it up.

(Operator Instructions) Your next question comes from Michael Lapides of Goldman Sachs.

Easy question. On your 2017 CapEx guidance, the reduction of $300 million, can you give a little more detail about what's moving and does that get put back into a future year's CapEx? And if so, how far out into the future?

Yes, Michael. So it's always a bit of a split. I think we had referenced there were a couple things that were going on related to the total. Some is, frankly, just doing some work more efficiently, and I think there is a -- the majority of that is on Energy Strong. You heard Ralph talk a little bit earlier about $1 billion going through the clause and about $100 million that will await the rate case, and you'll remember it's about a $1.2 billion program. So frankly, some of that work was done more efficiently and I think that's a great outcome and it's great for customers and we're pleased to be able to do it that way. And we've had a little bit of the same on transmission, not a whole lot. And then, the balance really is timing and the timing is not anything that's going to move dollars out 3, 4, 5 years. It's a just living '17 out into '18. So in the aggregate, if you think of it, maybe about half and half, half being just efficiencies that we've brought to the process and about half being some capital that will move into next year.

So when you think about efficiencies, if I did half and half, do you think CapEx over the cycle by about $150 million and pushing out $150 million into next year kind of ballpark?

Yes. If you think about the $3.1 billion versus $3.4 billion that we talked about, that's about right. Yes.

That trend towards the upper end of the rate base growth through 2021 includes all of that [thinking].

Got it. And then one other. Just thinking about transmission rate base growth and transmission capital needs and kind of how you're thinking about whether there's any lumpiness in some of what PJM is trying to plan around, given what's happened with the ConEd wheel. How are you thinking about just whether there are any lumpy or larger scale projects coming down the pike with transmission? Or is it all going to be just lots and lots and lots of kind of small and midsized ones?

Yes, it's more the latter than the former. I think if you had gone back 3 or 4 years, you would have found more bigger, lumpier projects. A fair bit of what we are spending now is on 69 kV upgrades of 26 kV systems. And that actually moves capital from the distribution area into transmission as it goes up in voltage and those are smaller. Now a lot of them are still sizable projects, but smaller than, for instance, a Susquehanna-Roseland type of project that we talked about in the past. So there are more smaller projects as opposed to fewer larger projects that we've seen in the past that will move us forward. And in fact, as we think about our 2018 revenue number that we talked about, even within our prepared remarks, some of what you see there, it's a step up from what we have seen in some prior years. Even if you look back to last year, there's a pretty sizable step-up in the amount. Some of that is incremental capital year-over-year in both the return on that capital and the depreciation, the return of that capital will contribute to some of that increase. But you may recall last year, part of the number that we had from a revenue increase was inclusive of a true-up and that true-up was related to bonus depreciation. So a couple years back, the bonus depreciation extension took place. I don't think it was December 31, but it was awfully close to that and it was certainly after we had filed our October formula rate filing. So the impact of bonus depreciation in 2015, getting it approved, moved into 2016 after we had set our rates and a true-up in 2017 included the reduction in rate base for those excess deferred taxes for bonus depreciation. So on a year-over-year basis, you'll see a jump and a lot of that had to do with the fact that 2017 had a true-up reducing revenues for transmission related to that late enactment of bonus depreciation back in 2015.

Got it. Much appreciated. Maybe one last one. O&M at the utility has been very strong, meaning you've reduced O&M this year. How much of that is just one-off stuff related to maybe storms in 2016. And how much of that is kind of active O&M management?

It's the latter. It's active O&M management and we've kept O&M to a very manageable rate over, frankly, the last number of years and would look to continue to do so going forward.

Your next question comes from Jonathan Arnold of Deutsche Bank.

Just one on the hedging data. You mentioned that you'd had a $2 downtick in the average price to $39 for 2019 and the hedge amount only ticked up by 5%. Can you just remind us, does that include an estimate of the pricing on the open position? Or is that just the average price on the hedge piece?

It's the latter, Jonathan.

Okay. So then, I guess, following from that, then. Between -- over the last 4 quarters, it's ticked down from $43 to $39 and the hedging has gone from [15 to 30], how do we kind of reconcile that math?

Well, I think if you take a look at what the '19 -- 2019 forwards look like over that period, you've been in a $29, $30 rate. And what you're doing is you're pulling down from a BGS price in those out years, which is exclusive of the capacity components, but inclusive of the others. So it's not an unusual trend that we start in the out year of our 3-year cycle with BGS and then we layer on flat-block hedges as well as some other load deals in those flat-block hedges tend to come in at lower prices, in part, because the curve has come down but also because they're energy-only hedges.

Okay. So it's sort of those 2 things going on there. And then, but also the curve has sort of traded off in the quarter and then recovered a couple of dollars since. Is it fair to say these were sort of down in the heart of the third quarter or can you give us any sense there?

Yes. During the quarter, since our last update.

Okay. And then one other thing. Just on enterprises. Your guidance for '17, the $35 million number, is that still sort of the right ballpark going forward?

Yes. Yes, that's right.

I'm sorry. If you have 1 more question, otherwise, I know we've gone over our allotted hour's time, but I don't want to cut anybody off with a significant question, so we'll allow one more question.

Okay. Your final question comes from Ashar Khan of Verition.

Can I just ask you -- Ralph, can you just talk a little bit about the legislation, if -- when we should kind of expect it or what should we expect in the last 2 months starting tomorrow, I guess, November starts works in? And then, I just had one more question from Cregg, was that, could you remind us how much of the transmission increase went into effect on January 1 of this year? You said you were going to request something like $212 million, right, January 1, 2018. Could you remind us what that amount was for January 1, 2017?

So sure. We are just in a series of conversations with people right now. We're just making sure they understand what our nuclear plants mean to New Jersey. And yes, it is true that if New Jersey were to build a safety net so as to guarantee or assure the continued operation of those plants, it would have required legislation. But anything more than that would be premature to discuss, right? So there's just a lot of conversations that we're having with folks to say, if those plants weren't here, here's what happens. So and then we have 2017, Dan?

Yes. 2017 was $121 million, and that was down off of the last couple of years, which was $146 million and $182 million. And so it's moved around a fair bit and a lot of that is the bonus depreciation item that I talked about earlier.

So from $121 million, we are now going to like $212 million, right? Am I correct?

That's right.

So just to summarize what, hopefully, you heard from me and Dan this morning, our Power plant construction is on budget and on schedule, 3 power plants that we hope to have online in June of next year and the subsequent June. We have a very healthy dialogue that we are active participants and going on underway on wholesale power market design and reform taking place at FERC, at DOE and at the state level. For the utility, we're now pointing toward the upper end of rate base growth, that's 7% to 9% range. We're now thinking we'll be able to hit that upper end of the range between now and 2021. We have a very busy, but a constructive regulatory agenda coming up for PSE&G. We have GSMP in play. We have a rate case, we'll have Energy Strong 2 in the near term and, longer term, some energy efficiency. And we're happy to go over all of that and then some with you at EEI next week. I know we have a full set of meetings set up and if you're not on the meeting schedule, I'm sure you can corner one of us in the hallway. They wouldn't let me say it at the beginning of the script, but I wish everybody a happy Halloween now. And have a great holiday and a safe day. Thank you. We'll see you all next week.

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