公共服務電力與天然氣 (PEG) 2014 Q2 法說會逐字稿

Ladies and gentlemen, thank you for standing by. My name is Kayla and I am your event operator today. I would like to welcome everyone to today's conference, Public Service Enterprise Group's second quarter 2014 earnings conference call and webcast. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session for members of the financial community.

(Operator Instructions)

As a reminder, this conference is being recorded today, July 30, 2014, and will be available for telephone replay beginning at 1:00 p.m. Eastern Standard Time today until 11:30 p.m. Eastern Standard Time on August 8, 2014. 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, Kayla. Good morning, everyone. Thank you for participating in PSEG's earnings call this morning. As you are aware, we released our second quarter 2014 earnings statements earlier today and, as mentioned, the release and attachments 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 June 30, 2014, is expected to be filed shortly. I don't go through and read the entire disclaimer statement or the comments we have on the difference between operating earnings and GAAP results but, 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 those statements from time to time, we specifically disclaim any obligation to do so, even if our estimate changes, unless we, of course, are required to do so.

Our release also contains adjusted non-GAAP operating earnings. Please refer to today's 8-K or other filings for a discussion of the factors that may cause those results to differ from Management's projections, forecasts, and expectations as well as for a reconciliation of operating earnings to GAAP results. I am now going 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 Caroline Dorsa, 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. Earlier this morning we reported operating earnings for the second quarter of 2014 of $0.49 per share, and that's to be compared with $0.48 per share earned in 2013's second quarter. The results for the quarter bring operating earnings for the first half of 2014 to $1.50 per share compared with operating earnings of $1.33 per share earned in 2013's first half.

Slides 4 and 5 contain the detail on the results for the quarter and the first half. Several results for the quarter are noteworthy. We continue to see benefits to earnings from the increased deployment of capital into our regulated company. Now, that's primarily in the form of transmission infrastructure, and we're completing major projects on time and on budget. From our perspective, we're delivering on the promise both for earnings growth and improvement in reliability associated with this multi-billion dollar investment program.

We've been able to supplement that growth with the continued focus on controlling O&M costs and supportive rate mechanisms have allowed us to earn the authorized return on our regulated Company's investment program. The improvement in earnings from our regulated company, PSE&G, offset the impact of mixed operating conditions during the quarter on Power's results. The costs related to the extended outages at the sale of two nuclear facilities and the gas-fired Linden combined cycle station masked the underlying strength of Power's operations.

The downtime at Linden during the quarter was longer than planned and associated with extensive work being done to test and complete the installation of equipment which has led to a 63-megawatt increase in the station's capacity. During a recent re-fueling outage at Salem, we discovered the need to make repairs to Salem 2's four reactor coolant pumps. The re-fueling outage was extended by approximately 60 days to complete the necessary repairs and the unit was returned to service on July 14.

The decision to keep a unit out of service is not made easily. However, only by taking the steps necessary in the short term in support of operational excellence will a key asset such as Salem be available on a reliable basis to provide substantial value for years to come.

I'm pleased to report that both Linden and Salem 2 have been operating essentially flawlessly since they returned to service. Keeping a focus on operational excellence is the primary means of assuring our customers and regulators that we operate our assets in a safe and reliable manner.

We have begun the work recently approved by the New Jersey Board of Public Utilities to protect and strengthen PSE&G's electric and gas distribution systems against severe weather conditions. The $1.22 billion Energy Strong investment program represents an initial phase of work designed to upgrade and improve the resilience of our system, and we intend to work with our regulators and other parties to consider additional measures at a later date.

This is an opportune time to pursue these investments. Major surcharges on customers' electric bills are scheduled to expire over the next two years and the bills for PSE&G's gas customers continue to benefit from the capable management of the Company's gas supply, storage, and transportation contracts.

In fact, PSE&G has filed for a further 9% reduction in the gas rate paid by residential customers. The reduction, which would be effective in time for this year's heating season, will be the latest in a series of reductions which have lowered the customers' gas bills by 44% in the past five years. The availability of low-cost gas from the Marcellus basin and the lack of infrastructure to move the gas to market has been a source of volatility in the power markets. Power's combined cycle assets in PJM enjoy an economic advantage given access to low-cost supplies in the Marcellus, particularly during the summer period.

As a practice we don't, as you well know, forecast results for PSE&G power beyond the current year and outside of what is implied by market prices, but we will make note of some consistent improvement in demand that is showing up here in our region. The results of PJM's recent capacity auction point to an improving market environment with the retirement of older inefficient generating capacity as environmental rules take effect. Power's assets in PJM will also once again receive a price that continues to reflect our asset's value given their location relative to load. So, for the next four years Power's assets will receive a price for capacity of approximately $166 per megawatt day.

The Power markets have gained greater clarity on another key environmental priority. We are pleased that the Environmental Protection Agency has issued its ruling on cooling water, commonly referred to as Section 316B. The agency's ruling substantially addresses many of our concerns and we are working with the appropriate state environmental agencies on permitting of our affected units.

On another environmental matter, the EPA also released its proposed rules concerning a reduction in CO2 from existing generating units. We are supportive of the administration's efforts to enforce the Clean Air Act. Power has made the necessary investments to meet existing air quality environmental requirements. And although we expect it may take some time to implement final rules regarding carbon, given the complexity of the proposal, Power's fleet should benefit given the generation profile that is almost 60% carbon free.

Before I conclude, I want to bring you up to date on matters relating to Power's trading arm, Energy Resources and Trade, which we commonly refer to as ER&T. As you recall, we indicated with our release of first-quarter results that Power informed FERC, PJM, and the independent market monitor of PJM that it found errors in some components of its cost-based bids for its New Jersey fossil generation units. We began an internal investigation and have since notified FERC, PJM, and the IMM that we identified and corrected additional errors.

We are working with the appropriate parties but cannot provide you with a timetable as to when this issue will be resolved or whether or not we will be required to recognize another charge against Power's earnings. We take pride in our performance and candidly we did not live up to our own standards of applying sufficient rigor in this area, but I can assure you that we corrected all identified errors and we are instituting new processes and controls to reduce the likelihood of a recurrence of the situation. This issue does not change the strong underlying operating performance of Power's fleet of assets that continue to provide solid earnings and good cash flow given the fleet's favorable location close to load, its dispatch flexibility, and fuel diversity.

Despite Power's strengths, we have nonetheless changed the profile of our earnings over the past several years. Our investment program focused on improving reliability and expanding the transmission system, has yielded the anticipated outcomes. PSE&G remains on course to achieve double-digit growth in operating earnings during 2014 as its contribution to earnings is expected to exceed 50% of our forecast for the year. The Energy Strong related capital investment provides further support for our forecast of double-digit growth in PSE&G's rate base and earnings over the next several years.

Given the strength of Power's operations in the first half of the year and the growth of PSE&G, we feel comfortable saying we expect operating earnings for the full year to be at the upper end of our range of guidance of $2.55 to $2.75 per share, assuming normal weather and operations. The growth in our capital program doesn't diminish the strength of our financial position and our balance sheet. We remain well positioned to deploy that balance sheet strength to meet shareholder objectives for long-term growth. And, with that, I'll turn the call over to Caroline who will discuss our financials in greater detail.

Thank you, Ralph, and thank you, everyone, for joining us this morning. As Ralph said, PSEG reported operating earnings for the second quarter of 2014 of $0.49 per share versus operating earnings of $0.48 per share in last year's second quarter. We provide you with a reconciliation of operating earnings to income from continuing operations and net income for the quarter on slide 4. We've also provided you a waterfall chart on slide 10 that takes you through the net changes in quarter-over-quarter operating earnings by major business and a similar chart on slide 12 that provides you with the changes in operating earnings by each business on a year-to-date basis.

So, I'll now review each company in more detail starting with PSE&G. PSE&G reported operating earnings for the second quarter of 2014 of $0.30 per share compared to $0.24 per share for the second quarter of 2013, and results for the quarter are shown on slide 14. PSE&G's operating earnings continue to benefit from an increase in revenue associated with an expansion of its capital program and tight control of its operating costs. PSE&G's results for the quarter were also aided by a reduction in financing costs as weather normalized sales growth which remains consistent in the slowly improving economy.

A FERC approved increase in PSE&G's transmission revenue under the Company's formula rate was effective on January 1, 2014. The increase supported a quarter-over-quarter improvement in the net earnings contribution from transmission of $0.03 per share. Weather conditions during the quarter were unfavorable relative to normal and in comparison to conditions experienced in the year-ago quarter, and these conditions reduced quarterly earnings comparisons by $0.01 per share and offset the favorable impact on earnings from continued growth in demand for gas.

PSE&G's focus on controlling the growth in operating expenses, including a decrease in pension expense, led to an improvement in quarter-over-quarter earnings of $0.02 per share. And although the level of debt on PSE&G's balance sheet has grown consistent with the expansion of its capital program, the actual overall cost of debt has declined as a result of the refinancing of higher cost debt and a decline in interest rates. This reduction in financing cost improved earnings comparisons quarter-over-quarter by $0.01 per share.

The service area continues to experience a slow improvement in underlying economic conditions. Sales data for the first half of the year, which in general is more reflective of trends than quarterly data, indicate weather normalized demand for gas grew by 4.4% as a decline in prices and an improvement in the economy continue to support demand. Weather normalized electric sales increased by 1.6% during the first half.

Demand from residential customers grew in line with customer growth of about 0.5% as demand from the commercial and industrial sectors improved by 2.1% and 1.7% respectively over the six-month period. The New Jersey Board of Public Utilities, or BPU, approved PSE&G's Energy Strong settlement during May. The agreement calls for PSE&G to invest $1.22 billion over the next three to five years to improve the resiliency of its electric and gas grid. The addition of Energy Strong brings PSE&G's five-year capital program to approximately $11.3 billion versus our prior forecast of $10.1 billion in spending over the 2014 to 2018 time period, and will provide further support for our double-digit earnings growth in PSE&G's rate base, as we've mentioned before.

PSE&G's operating earnings increased 22% during the first half of the year and supports maintenance of our forecast for a growth in operating earnings for 2014 to $705 million to $745 million. Results for the remainder of the year will continue to reflect an increase in transmission revenue and a reduction in operating and maintenance costs, including pension expense.

Let's now turn to Power. PSE&G Power reported operating earnings of $0.17 per share for the second quarter of 2014 compared with operating earnings of $0.24 per share for the second quarter of 2013. The decline in Power's results for the quarter is the result of the impact on production and O&M expenses associated with the extended outage at the Salem 2 nuclear facility and the maintenance outage at the Linden gas-fired combined cycle facility during which we also upgraded the equipment to increase that station's capacity.

Power's quarterly earnings comparisons continue to benefit from a net increase in capacity revenue. Power received capacity prices of $242 per megawatt day during the first two months of the quarter versus $153 per megawatt day in the year-ago period before capacity prices reset to $166 per megawatt day effective June 1 of this year. This net increase in capacity prices improved quarter-over-quarter earnings by $0.04 per share. The capacity price benefit plus benefits from lower cost gas offset a decline in average hedge prices and the negative impact from relatively lower market prices in the east resulting from transmission and generation outages outside of our region.

Incremental production at the coal-fired and peaking stations partly offset the lower production due to the outages at Salem 2 and the completion of the capacity upgrade work at Linden. The net reduction in output, however, reduced earnings quarter-over-quarter by $0.03 per share. Operation and maintenance expense, or O&M expense, was higher than the year-ago quarter. Again, the costs associated with the outage and upgrade work at Linden and the repair at Salem more than offset the benefit from lower pension expense and, altogether, reduced quarter-over-quarter earnings by $0.04 per share. An increase in depreciation expense was offset by a reduction in the tax rate and other miscellaneous items.

Output from Power's fleet was 5% lower in the second quarter compared to year-ago levels. Power determined in mid May, at the conclusion of Salem 2's normal refueling outage, that it was necessary to extend the outage to inspect and repair the reactor's coolant pumps. The unit was returned to service on July 14. The extended outage reduced the nuclear fleet's output in the quarter by 9% to 6.5 terawatt hours, 54% of our generation, and lowered the nuclear fleet's average capacity factor in the quarter to 80.5%.

Production from the gas-fired combined cycle fleet declined 11% in the quarter to 3.6 terawatt hours, 30% of production -- 30% of our production as Linden was out of service early in the quarter to complete maintenance and the work associated with the 63-megawatt increase in the unit's capacity which is now in place. Production from the coal-fired and peaking units increased 27% to 1.9 terawatt hours, or 16% of generation, with improved market economics. Power was able to meet its hedged obligations from its own generation despite the decline in output given the fleet's net long position and the availability of the coal-fired units.

Power has reduced the upper end of its forecasted output for the full year to 56 to 57 terawatt hours from the previous 56 to 58 terawatt hours to take into account the results for the second quarter. Our forecast, which represents an increase in output for the year of 4% to 6%, continues to assume normal operations and weather. Approximately 70% to 75% of generation for the second half of the year is hedged at $50 per megawatt hour. Power has slightly increased its forecast of economic generation for 2015 and 2016 to 55 to 57 terawatt hours per year from the previous 54 to 56 terawatt hours to take into account normal operations and our estimates of economic dispatch.

Power's taken advantage of the strength in market prices earlier this year to hedge the gas-fired combined cycle fleet into the third quarter and also increase the percent of generation hedged in 2015 and 2016 to the upper end of the normal limits that we would normally see at this time. That's in order to take advantage of some opportunities we saw to lock in heat rate and spark spread. Liquidity has improved somewhat into 2016, but generally speaking we can think of liquidity as poorer the further you get beyond 2015.

Power's combined cycle fleet also benefits in the summer months from its access to low-cost Marcellus gas. Economics are particularly compelling as gas prices have declined more than Power prices, which has allowed Power to do that heat rate lock-in. For 2015, Power has hedged 65% to 70% of its forecast generation at an average price of $50 per megawatt hour. For 2016, Power has hedged approximately 30% to 35% of its generation at an average price of $51 per megawatt hour. Hedged data for 2015 reflects a change in our forecast of the BGS volumes.

As a result of the extreme volatility in market prices for energy experienced earlier in the year, we have seen some return of customers to the BGS contract, but not a lot. So, our forecast for 2015 now assumes BGS volumes represent 11 terawatt hours of demand, more in line with the forecast volumes for 2014 than our prior forecast which had assumed BGS volumes of 10 terawatt hours as we move into 2015.

As Ralph mentioned, we are working with FERC, PJM, and the independent market monitor, or IMM, to determine the impact of identified errors in our bidding processes. We recorded a charged operating earnings of $25 million or $0.03 per share in the first quarter based on the information available at that time. Upon discovery of the errors, we initiated an investigation and identified additional errors in our bids and further determined that the quantity of energy that Power offered into the day-ahead energy market for its fossil peaking units differed from the amounts for which Power was compensated in the capacity market for those units.

Based on information currently available to us, we've generally not seen an impact on our real-time operations for these units. We informed the FERC, PJM, and the IMM of these additional issues and we have corrected these errors. We have not recorded an additional charge to income in the second quarter over the amount we reserved earlier this year. PSEG doesn't have access to PJM's proprietary data to determine if the differences in quantity had any impact and, if so, the level of that impact.

However, FERC has the authority to investigate the matter which could result in FERC seeking disgorgement of any over collected amounts, civil penalties, and non-financial remedies. The forecast range of Power's operating earnings for 2014 remains unchanged at $550 million to $610 million with full-year operating earnings expected to be at the upper end of the range assuming normal weather and normal unit operations. Our forecast includes all of the issues we just discussed, including the $0.03 per share charge in the first quarter related to the items I just discussed.

Results for the remainder of the year will be influenced by a reset in the average price received on PJM capacity to $166 per megawatt day which started in June from the $242 per megawatt day we've seen previously as well as a decline in the average price of energy hedges. O&M expense is expected to compare favorably in the second half of the year given a reduction in pension expense and the absence of major outage-related work in the year-ago period. For the full year, however, Power's O&M is expected to be flat against 2013's experience given the increased cost associated with the extended outages.

Let me now turn brief briefly to PSEG Enterprise and other. Operating earnings for PSEG Energy Holdings/Enterprise in the second quarter of 2014 were $7 million or rounded about $0.02 per share versus operating earnings of $2 million or basically breakeven results during the second quarter of 2013. The results for 2014 reflect the inclusion of earnings from PSEG Long Island's operating contract and the absence of some charges in the year-ago quarter.

PSEG Long Island filed its first utility 2.0 proposal on July 1 of this year. The proposal calls for investing $200 million in energy efficiency, demand response programs, distributed generation, and related programs over a four-year period beginning in 2015, and we expect a response to our proposal by year end. We continue to forecast full-year operating earnings for PSEG Enterprise and other of $35 million to $40 million.

Just a brief note on financing. During the quarter, PSE&G issued a total of $500 million of medium term notes consisting of $250 million of five-year notes at 1.8% and 30-year notes of 4%. These funds will be used to meet PSE&G's capital requirements. PSE&G's capital budget is currently 15% to 20% greater than what we told you in the spring and is now expected to approximate $11.3 billion over the five-year period from 2014 to 2018 which brings our plans for our consolidated PSEG capital spending to $13 billion over that same period.

We ended the quarter with debt representing 42% of consolidated capital. The improvement in PSE&G's earnings and cash flow as well as our continued strong earnings in cash generated by Power support our financing requirements without the need to issue equity. And as I think we've demonstrated with the growth in PSE&G's capital program, we continue to seek opportunities to deploy our investment capacity to drive growth.

We continue to forecast operating earnings for the full year of $2.55 to $2.75 per share, but we do anticipate the results for the full year to be at the upper end of our range, assuming normal weather and normal unit operations. And, with that, we're ready for your questions. So, Kayla, I'll turn it back to you.

(Operator Instructions)

Your first question is from Kit Konolige with BGC. Please proceed with your question.

Good morning.

Good morning, Kit.

Caroline, you just mentioned that the Company continues to see opportunities to redeploy cash flow to drive growth. Can you -- certainly, transmission investments are one major area there. Maybe you can outline for us -- are there other areas that you see -- and Energy Strong I guess I should say as well. So those strike me as the two big buckets. What else should we be looking for? And are there other arenas that you're considering that may not be front and center now, but could be an afterburner effect later on?

Sorry to disappoint you, but Ralph will answer that instead of Caroline. Yes, so, we only talk about things that are fully baked. But because this question comes up so often, I will just give you a couple of examples.

We have been in conversation with the BPU staff about a modest, by our definition modest, $100-million energy efficiency program. Ralph LaRossa is the incoming Chair of the American Gas Association. He was in DC yesterday, where he heard nothing but concern expressed by the Obama administration and many other attendees on methane emissions -- fugitive methane emissions from gas pipes.

[BPU] has consistently supported a gas cast iron main infrastructure replacement program, and you will probably see that as the first thing in Energy Strong that we go in for an increase on. We had our first public hearing on Long Island over Utility 2.0, a $200-million program we put in. And I would say that if there was one message that came from that meeting, it was that we were being too timid and it needed to be bigger.

Now, that's only one of several hearings that we'll have on the subject. We'll get a chance to refresh that proposal in October.

So, the [RTEP] I believe came out just this past month, if I'm not mistaken. It usually comes out in June. I shouldn't say whether or not it did come out in June this year. And we'll be looking at the PJM open window on some of the problems identified in there, and I don't want to give a number there because I just heard from Ralph only a day ago on that, and that number moves around depending on the engineering analysis.

So, I just mentioned a few things that all start at nine figures. And, as Caroline mentioned, I think our five-year capital program increased by 50% from last year to this year, and it's now up by 23% between March and July. So, I don't want to guarantee that that's what will happen on the next quarterly call, but we don't seem to be running out of infrastructure needs in this region.

Excellent. And just to focus on one item of infrastructure, can you give us the outlook for the artificial island project with the reconsideration now, and how we mark our score cards to see this going forward?

Well, I was hoping that you would have the answer for that.

Yes, sure.

This is witnessing the making of sausage, the making of law, the making of everything else. In defense of PJM, and they don't need me to defend them, this is a brand new tariff in response to a brand new regulation and a first-time major process. So, we're seeing growing pains. I would be less than 100% candid if I didn't express disappointment at the Board's action last week.

Having said that, what the Board said is they are inviting the finalists -- and we are one of the four finalists, down from whatever the original number was, which was a number I think at least double that, and they want some more information. And I don't even know the exact nature of the additional information they want. I do know that we're going to do $2.2 billion of transmission this year, on top of $1.6 billion of transmission last year. We've got a great team, and we will be able to answer any one of their questions and outshine the competition. So, I think it's just growing pains of a brand new tariff and a brand new program that PJM is experiencing right now.

Great. Okay. Thanks a lot.

Next question.

The next question is from Julien Dumoulin-Smith with UBS. Please proceed with your question.

Hi. Good morning.

Hi, Julien.

So, perhaps going back to the Energy Strong side of the equation, just following up there, obviously there is a number of things that didn't ultimately get put into that package. Is there a potential to go back and pick up some of those last items, and kind of reflect that in your CapEx here at some point?

So, the answer to that, Julien, is yes. I think, if I could steer you in certain directions, it's more likely that we'll go in first on the gas side, because that work is expected to be complete in a 2- to 3-year time frame, and just the fact that, not withstanding that that will be our fourth request for gas infrastructure improvement, these things take many months to get approved. So, we wouldn't wait until we were running out of work -- I'm sorry, running out of approval, because there's no chance that we will run out of work.

On the substation work, that really is scheduled to go five years, and candidly, we are not convinced that given the amount of transmission work that we have, and the 29 switching and substations that we plan to work on, that we want to put the system much more in a configuration that is as tenuous as it would be with all of that electrical work going on.

Some of the stuff that went away was making the distribution system smarter. That one is a little tougher to predict. So, a little bit of a long-winded answer, but the short answer is: There is no doubt that before the 3- to 5-year period is up we will be back in, and my prediction today would be that we would be back in on the gas pipe replacement, first and foremost.

Got you. Any sense of magnitude there, or is it still too early here -- ?

We've tended to talk about $250 million to $300 million a year, is about the size of the program that we can reasonably manage. If there were emergency issues, which we do not have, you'd somehow find a way to do more than that. But right now the emergent issue that seems to be coming up is the order-of-magnitude increase in greenhouse gas effect that comes from fugitive methane emissions, and the desire in the policy circles -- fairly prominent policy circles -- to do more about that.

Excellent. And then, going back to the artificial island side of the equation, just to be clear, is this really about capital costs and who can deliver the cheapest project, and is that where this is headed? I mean, it's tough to tell obviously; or is this about terms, conditions, ultimately indicating that you can partner with, or someone else can get involved in your territory?

No, I think it's more the former, but simply answering the question that way oversimplifies it, right? These are complicated engineering solutions to a sophisticated set of infrastructure -- assets in the infrastructure.

So, it would be a mistake for anyone to assume that just because a project is less expensive than another, that it is preferred from a consumer point of view. That's the equivalent of saying: Gee, I could buy that car for $10,000 and that car for $100,000; I should buy the $10,000 care. And then you'd fail to recognize but you needed that $100,000 crane because you're in the construction business, and the $10,000 smart car isn't going to quite help you be able to move equipment around. I'm sure I don't have the right brands and dollar amounts there, but you know my point, that these are not commodity services. These are sophisticated engineering services.

The terms and conditions issues that you allude to, I think it's fairly well understood that some people come in after the process and said: We'll guarantee a price. Well, a prudent buyer would say: Well, let me understand that guarantee. Is it bumper to tailpipe? Is it just the drive train, which doesn't fall apart, but for 200,000 miles, and now you've extended the warranty from 50,000 to 75,000 miles?

So, there are some terms and conditions elements. There are some pricing elements. And I think that's why the PJM Board simply said: Gee, we're getting a little bit more noise in the system than we'd like to under first time in a project. And I don't mean to speak for the PJM Board; I don't have that ability -- but let's just ask more questions. They did not come out and say: You picked the wrong project, by any stretch of the imagination. They just want more information on those issues that you implied would be front and center.

All right. Excellent. Thank you.

Next question.

The next question is from Paul Patterson with Glenrock Associates. Please proceed with your question.

Good morning.

Good morning, Paul.

There was some discussion surrounding the Pepco acquisition; and of course, you guys are located in New Jersey and I am sure you guys are aware of the press reports. I'm just wondering, philosophically, if you look at the potential amount of leverage that might be used in that transaction, and what you're seeing with respect to the discussion -- the CTA in New Jersey -- is there any change or thoughts that you guys might have in terms of leverage over the long term at Public Service?

Sure, Paul, it's Caroline. Thanks for your question. So, yes, we obviously saw what Exelon said in terms of how they were financing that acquisition. So, a part of that, I guess I'd characterize as not really surprising. We look at our own balance sheet, and we obviously are always in discussions with the rating agencies, given the fact that we don't have any parent leverage, right? We have the occasional commercial paper, but our long-term debt is at our operating companies.

We talk about investment capacity. We tend to talk to you about Power, and Power's debt-to-cap profile -- where that stands at the end of a period, and what its investment capacity is. But we've always recognized that we do have incremental investment capacity at the parent that we could deploy, and in conversations with the rating agencies, the deployment for that to regulated, right. Investments is something that works very well.

The way I look at that is, given where Power's performance has been, and, as I think we note where the Company ended the quarter, and Power, of course, ended the quarter at debt to cap at 32%, there is a significant amount of capacity at Power, but there also is that parent-related investment capacity. So, when we talk about things internally in terms of opportunities, some of the things that Ralph was mentioning earlier, we look at that from the perspective of having a balance sheet that has a lot of room, not just the room for Power, but also the room for parent if it's oriented toward regulated.

So, maybe that was the first largest announcement of use of that kind of capacity that we've seen, but we recognize that we have it as well, and of course, continuing to run our businesses appropriately and keeping the right capital structure at PSE&G, et cetera, and then seeking out regulated opportunities. So, I look at that as just reinforcing the fact that we have ample room.

Okay. And then, with respect to this PJM independent market monitor stuff, I wasn't completely clear exactly what you guys indicated happened. It suggested that there were some additional pricing areas in the cost-based bids that were identified with the quantity of energy that Power offered into the energy market that differed from the amount that Power was compensated in the capacity market for those units. I'm just trying to get an idea -- what does that actually mean, for somebody that is a little bit less sophisticated on what actually happened, I guess?

Yes. So, you got it right. In terms of -- in the first quarter, we talked about the cost-based bids. And then the incremental information that we identified during this quarter was other errors, but also this capacity issue. And so, let me just try to say it again.

So, we had -- we offer, of course, our units into the day-ahead energy market. We offer an amount of megawatts into the day-ahead energy market. And what we have seen is, at times, we did not offer the capacity into the day-ahead energy market that was equivalent to the amount of capacity that we have -- we were getting paid for from the capacity auction results.

So, as I said, generally speaking, what I'm talking about is offering into the day-ahead market that differential, not, generally speaking, impact on the real-time operation of the unit. So, it's about the bidding in the day-ahead, generally speaking, more than it is about the operation in the real-time. So, it's a differential.

And, as I said, we're in the process of investigating that, doing the analysis, and working with the IMM and PJM, and we've informed FERC. This day-ahead, this issue about the capacity difference, you may recall I mentioned in my remarks it's about our peakers. So, not about all of our units, but our fossil peaking units in the day-ahead market.

Okay. I got you. And then, finally, the methane emissions issue, and the policy objective and the opportunity, you mentioned that I think that this might start with nine figures. Could you give us a little bit more of a flavor of the total opportunity that might be involved in that? I noticed this other stuff that was coming out yesterday from the DOE, and I was thinking about this. Just any more you can share with us about what that could possibly mean, these methane leaks, plugging them up and the benefit there?

We have, I think I'm being told, 4,000 miles of cast iron main pipe that needs to be replaced. I don't know the amount of bare steel pipes that we have that needs to be replaced. And typically speaking, Energy Strong had how much for how many miles?

350.

350 miles. Yes, so, it's about $1.4 million per mile, Paul. So, you could take that 4,000 miles and multiply by $1.4 million. You get a really rough ballpark. Yes, it was $350 million in Energy Strong to replace 250 miles.

But for the methane escape issue, isn't that a climate issue that's separate from Energy Strong? I thought there was an additional amount.

Yes, that's correct, Paul. So, I was connecting two disparate thoughts. So, we've been on a longstanding program to replace our cast iron main because it is the oldest part of our gas distribution system. It's the leakiest part of our gas distribution system.

It doesn't have any safety consequences from the point of view of high pressure. It's a low-pressure, low-utilization system. But just from the point of view of good operational practices, you don't want leaky pipes.

What's been added to the calculation of why it's important to do it, is concern over the greenhouse gas effect associated with methane being, I think, I read estimates of 30 to 35 times more impactful per pound of CO2. So, that's just an added impetus for a program that's been under way for many years now to replace the cast iron main.

So, you don't have a dollar number?

Yes, so, if you wanted to replace all 4,000 miles, you can multiply that --

Okay. I got you. Thanks so much.

Thank you. Next question.

The next question is from Dan Eggers with Credit Suisse. Please proceed with your question.

Good morning, guys. Can you maybe give us an update or is there a way to quantify how much benefit you guys saw in the second quarter because of the advantaged gas supply contracts at Power? And how should we think about maybe the benefit in the third quarter this year versus last year, seeing how wide based this is today?

Yes. Sure, Dan. Thanks for the question. So, not much impact in the second quarter. So, about $0.01 -- even that's rounded into the numbers I gave you relative to overall pricing impacts offsetting capacity upsides. That's not surprising to us. Remember we talked about last year in the second quarter was when we actually first saw this differential come into play, and actually it had a similar impact in last year's second quarter, again, rounding to about $0.01.

You may remember it was the third quarter that we actually talked more about it because, with the summer season, we had a nice warm summer last year, you had that supply-demand imbalance. More supply trying to get on to the pipe, right. And so the differential widened out, and we got about $0.03-a-share benefit in the third quarter.

So, of course, this is a season where we haven't had as warm of weather as we would normally have at the end of the second quarter. It's cooler than normal, and cooler than last year. You're not seeing a lot of that benefit. Not surprising we wouldn't see as much.

So, differential for [LIDE] is ranging, and looking a little bit ahead, $0.50 to $1 right now, just given supply-demand issues as people refill storage. That's not surprising. We saw -- depending on those supply-demand conditions, you can see that basis really move around.

So, we still think -- obviously, we're well positioned, and whenever we can capture that advantage, we will take it, and you'll see it come through our numbers. Can't really forecast obviously the rest of this quarter. We will have to see what the summer turns out to be. It was cool at my house this morning, I don't know about yours, but we'll see how that goes.

But we still have that evergreen opportunity on the pipeline with those contracts that Power has. Residential customer, of course, gets the first claim. That's why you don't hear us talk about it in the winter, right, because the residential customer is using it for heating. But in the summer, where there is obviously not as much heating demand, we can get that benefit.

So, I still think it's something you should look to us to try to capture whenever we can. We will report on how we do at the end of the summer in the third quarter, but, as I said, not surprising that 2Q is about the same as last year's 2Q, and again, a reminder that that advantage Power has is an evergreen advantage. Overall, you may remember last year we said about 25% of the gas that we use for our generation on a net basis -- net 25% across the year is LIDE source, but it's peaky. It's peaky in that summer period; it's much less so in the winter.

Thank you for that. And, yes, it was cold in the city this morning, too.

That brings me to my next question. The guidance pointed to the top end of the range. How is that reflecting the absence of July weather so far?

So, Dan, whenever we give information, it's up to the minute. So, we obviously have taken into account July, and we've looked at a 10- to 14-day forecast, and all of that is factored in.

By the way, I just saw yesterday that it is being called the polar vortex again. So, evidently, in July, that's 74 degrees versus negative 17.

Yes, the recent weather and the near-term forecast is included in the upper end of the guidance. Thanks for asking that because, beyond that range, we would assume normal weather.

Okay. And then I guess just a last question, Caroline. How should we think about tax rate for this year, given the fact the rate came in lower in the second quarter, and what are the expectations for next year?

Yes, so, I think in terms of tax rate, you should pretty much think of our tax rate as relatively steady for the businesses. Sometimes we have small adjustments in the tax rate.

Just a little bit of benefit in Power for the tax rate this year. We close out audits. Obviously, sometimes that affects things. Production deduction -- you calculate that as you look at the overall amount of generation that you source from market versus what you produce. Those kinds of things I think of as noise. So, I would say think of your tax rate as basically consistent for Power and for the utility on a year-on-year basis.

The only thing that might bounce your tax rate a little bit on a core source business in Power and solar source goes into -- as the unit comes into service, you'd see that little bit of boost -- benefit, if you will, right, a little bit of benefit for the portion of the ITC that you see kind of run through the [P&Ls] as a permanent difference. Other than that, I think you should expect it to be pretty smooth.

Okay. Thank you very much.

Sure. Next question.

The next question is from Travis Miller with Morningstar. Please proceed with your question.

Morning. Thanks.

Good morning, Travis.

Wondering about the outage at Salem. Was there anything in the work that you did there that perhaps, I guess for lack of a better term, pulled-ahead work, or work that you would have done or had to do in a year or two years that you were able to do at this point? Is there anything in that --?

Nothing that would meaningfully change the duration of the next refueling outage, Travis. Believe me, that topic was front and center often, as we waited for the coolant pumps to come back from the refurbishment of the vendors. But by no means will we skip an outage, nor should you think of any material shortening of the next refueling outages, which will be 18 months from now.

Okay. Different topic: Now that you have certainty on the Energy Strong investment needs, what are your thoughts around equity needs and use of balance sheet right now and use of retained earnings, financing that?

So we consistently and remain firm in our belief that we do not have any need for outside equity for the fairly robust capital program we have. Caroline, you may want to add to that.

Yes, Travis, as I mentioned just earlier, we closed the quarter with the debt to cap for the Company at 42%, and for Power at 32%. We also talked about the fact that we know if we had more regulated investments to do, we even have parent debt capacity. So, there is a lot of room on the balance sheet. Not to say that we haven't used it, right?

We've consistently identified things, as Ralph has mentioned, to put balance sheet to work. But when I look at this, and then I look at the things that we were just talking about earlier, whether it's more on the gas side that we might be able to do next round of something following Energy Strong, more transmission and the open window, potential for artificial island if it comes our way, potential for more things that we might identify on an infrastructure basis. And those kinds of things that we identify, and they do add up, but none of them add up to suggest that the balance sheet we have can't support that and more.

And, of course, for things like transmission, as you know, under our formula rates, it's real-time, we're not lagging, and so cash comes back as well. So, I look at this and say: We have our conversations and talk about opportunities. We have a balance sheet that can support that, and nothing gets close to equity issuance.

Great. Thanks a lot.

Sure. Thank you. Next question.

And the next question is from Jonathan Arnold with Deutsche Bank. Please proceed with your question.

Good morning, guys.

Good morning, Jon.

I just wanted to understand a little better the thought process behind the charge related to the cost-base bidding issue. So, in the first quarter you identified the initial issue -- you took a charge, you didn't tell us how much it was. And then this quarter you are telling us how much that charge was. You've identified the issue might be broader to it, but you haven't added to the charge.

So, should we read into that that you feel that you took an adequate reserve, or you just have no way of estimating it? If that was case initially, why did you come up with $25 million? Any context you can give there, Ralph?

Sure. I'll answer that, Jonathan. So, thanks for asking the questions. We should be clear here.

So, as you recall, we said we took a charge in the first quarter. We didn't identify what it was. So, obviously that was a source of a lot of conversation. So, we thought it was appropriate to tell you what we took in the first quarter, which was the $25 million, the $0.03 a share. It was all embedded into Power's operating earnings for the first quarter.

The standard on which we rely here in determining that charge is the accounting standard for contingency. You may be familiar with it, but, if not, let me be a little bit descriptive. The accounting guidelines for the time for which we took the charge in the first quarter essentially worked this way. You take a look at what a potential issue might be, if you need to take a charge or a reserve. And if you identify a particular number that you think is the most likely number, then you book that.

If you don't know a most likely number but you have a range of potential outcomes, all of which, given the level of uncertainty, you can't really ascribe differential probabilities to, then you book the low end of that range. And that's what we did in the first quarter. That's what the $25 million represented when we took the charge in the first quarter.

As I mentioned during the remarks and also in an earlier question, we've identified some additional errors, as well as this quantity matter that I was just describing before as well. And so, as we looked at the second quarter, we didn't have any basis on which to revise that number or change that number, and we determined that we would leave that number where it is. So that -- what I'm saying here is: You should not interpret that to say that is the best number, when we took the number. The charge in the first quarter, we were taking the low end of the range. And at this point, we don't have any sufficient additional information to change the value right now because we're in the process, as I mentioned, and that process could result in a change in the value.

Okay. Thank you, Caroline. One other follow-up on that. (multiple speakers) Is there any aspect of this which is ongoing affecting your earnings power at Power? Some of these changes in practice and systems you talked about -- are they -- are we going to notice any of that?

No. So, the guidance that we gave you, and the upper end of the range guidance, we're really talking about Power's operational earnings power. And Power's operational earnings power is unchanged in how we bid the units and how the units run and the capacity of having more megawatts. So, we don't see this as changing the ability of Power to continue to garner the value it garners from its location. So, I would say no to that.

This is something we need to work through, and we will update you as we go. And there may be more to say in subsequent quarters because we are just in the process now, but it doesn't change the fundamentals of how you should think about Power operating in the market.

This is more a retroactive thing that either penalties or disgorgement or whatever that may occur, but the go forward is not really affected?

You're correct. This is something that may result in incremental charges. It may result in penalties, but we just don't know enough right now to give you any guidance in that regard.

Okay. Do you have an update on when you think you might have some clarity on that? I apologize if you already said that.

No, that's okay, Jonathan. No, we actually don't. As I mentioned, or as we mentioned earlier and Ralph mentioned as well, we did inform FERC. We've been in discussions with PJM and the independent market monitors. So, there are many parties into this conversation, appropriately. So, we can't really give an estimate of the time frame at this point. We're continuing to obviously work with all those parties.

Thank you.

You're welcome. Next question.

The next question is from Paul Fremont with Jefferies. Please proceed with your question.

Thank you very much. Really, two things. One, could I get a reaction to the staff recommendation on the consolidated tax adjustment, and what that might mean for Public Service Enterprise -- for Public Service Electric and Gas?

Sure. So, the CTA, as recommended, of course, which is not final, right, it's just recommended, takes a view of taking a five-year look back from the date of filing. Also takes a view of separating out transmission from distribution, and then 75% to the Company, 25% for the benefit of the customer.

So, we think that is a very good outcome, and we think if that were to be the final rule, we think that would be fine from a PSE&G perspective, and would continue we think to appropriately reflect how to think about taxes and, therefore, appropriately encourage incremental investments. If that were the outcome, which, as I said, is not the final outcome, that would be a good outcome from our perspective.

Are you able to quantify the potential rate base impact if that recommendation were adopted?

It would be deminimis. It would not be material.

Okay. Then the second question I have is: You guys mentioned the 316B final rules at EPA. Where do you currently stand with the Salem water discharge permit?

So, I believe our sale and water discharge permit expired some years ago, and it's been held in advance. Had some very preliminary meetings with the DEP staff, not only on Salem, but some of our fossil units that now can have their permits refreshed, given the promulgation of the rule. I am pretty sure that the 316B rule, as proposed by EPA, named traveling restructuring as the best technology available for impingement. Entrainment is more of a site-specific determination. So, we'll -- the ink wasn't dry when we called up DEP and said let's talk about these permits.

So, you're essentially ruling that's consistent with the EPA standards then, at the state level?

That's right, Paul. That's right.

Okay.

I think we're going to move to closing comments right now, given the fact we're at the noon hour. So, I'm going to turn it back over to Ralph for closing comments before concluding.

Thanks, Kathleen. So, just to recap, we obviously had some help from the weather and the markets earlier in the year. Mostly weather early in the year, and a little more help from the markets early in the spring, which we were able to capitalize on in some of our hedging activity, as Caroline described for you. We're not getting any help from the weather lately, and we didn't do ourselves a favor with some of our operational challenges in the spring.

But when I add up all those challenges, whether it's weather or operational, I am pleased to guide you to the upper end of the range, even having put all of that into the stew, and I'm even more happy about the fact that all of those challenges are in the rearview mirror and that the plants are running well now. As Caroline's dialogue with Jonathan alluded to, even the bidding issues at our trading group we've corrected -- the errors that we were aware of have been corrected, and that's in the rearview mirror.

The balance sheet remains strong. The investment program is on track. We don't need new equity. We can do all of that and still support growth in the dividend.

So with that, I'd just say thank you for joining us on the call. We'll see you in various venues in the fall, and then I'm sure at EEI late in the fall. And that will be it from here. Thank you, all.

Thank you, operator. With that, we're going to conclude today's call.

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