Public Service Enterprise Group Incorporated (PEG) Q2 2016 Earnings Report, Transcript and Summary

Ladies and gentlemen, thank you for standing by. My name is Brent and I am your event operator today. I’d like to welcome everyone to today’s conference, Public Service Enterprise Group’s Second Quarter 2016 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 from members of the financial community. [Operator Instructions] As a reminder, this conference is being recorded today, Friday July 29, 2016 and will be available for telephone replay beginning at 2’clock p.m. Eastern today until 11:30 p.m. Eastern on August 5, 2016. It will also be available as an audio webcast on PSEG’s corporate website at www.pseg.com. I’d now like to turn the conference over to Kathleen Lally. Please go ahead.

Thank you, Brent. Good morning. Thank you all for participating in PSEG’s call this morning. As you are aware, we released our second quarter 2016 earnings statements earlier today. The release and attachments are posted on our website, www.pseg.com, under the Investor 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, 2016 is expected to be filed shortly. I won’t read the full 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 forward-looking statements from time to time, we specifically disclaim any obligation to do so, even if our estimate changes unless of course we are required to do so. Our release also contains adjusted non-GAAP operated earnings. Please refer 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 operating earnings to 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. Joining raffle on the call is Dan Craig, Executive Vice President and Chief Financial Officer. At the conclusion of their remarks, there will be time for your questions.

Thank you, Kathleen, and thank you everyone for joining us today. PSEG’s results for the second quarter were characterized by a tough environment for power markets, but also with continued growth associated with PSEG’s expanded capital program. Earlier this morning, we reported net income for the quarter of $0.37 per share. Operating earnings for the second quarter of 2016 were $0.57 per share; operating earnings were in with the $0.57 per share earnings in 2015 second quarter. The results for the quarter bring operating earnings for the first half of 2016 to $1.48 per share, which compares with operating earnings of $1.61 per share earned in 2015’s first half. Slides 4 and 5 contain the detail on the results for the quarter and the first half. PSE&G’s execution on its expanded capital investment program continues to provide a growing source of earnings and powers prudent management of reductions in O&M, minimize the impact of the extended outage at sale on earnings. PSE&G is on track to invest $3 billion in 2016 as part of its five-year, $12 billion capital program. PSE&G’s ability to earn its authorized return on investment continues to drive out forecast for double-digit growth in PSE&G’s 2016 earnings. We continue to look for opportunities to grow in a manner that meets customer demand for reliable, efficient and clean energy and provides the risk-adjusted return demanded by shareholders. In the past quarter, we have identified more than $500 million of additional investment opportunities at our regulated utility company, PSE&G. During the past quarter, PSE&G requested an extension from the New Jersey Board of Public Utilities of its existing land fill, brownfield solar program. The program would add 100 megawatts of grid-connected solar facilities over a five-year period at a cost of approximately $240 million. The program would also create 575 direct jobs in New Jersey during the construction period and allow all customers to share in the benefits of solar. We hope to see a decision on this request during the fourth quarter of this year. In addition, PSE&G has increased its estimate of distribution capital expenditures over 2016 through 2018 like $300 million to address what is commonly referred to as new business requests and to replace certain aging equipment and infrastructure. As I mentioned, these programs together would represent an increase of more than $500 million over PSE&G’s current plans to invest $12 billion over the five-year period ending 2020. PSE&G’s robust investment program will ensure that remains one of the most reliable utilities in the nation as was demonstrated during periods of intense heat and thunderstorm activity experienced over the past two weeks. The investment program will also improve on PSE&G’s growth and rate base currently forecasted at 8% per year for the five-year period ending 2020. The powers capital program is also an important response for the needs of today’s market, which requires that we operate at greater levels of reliability and efficiency. The planned replacement of older generating capacity at the Sewaren and Bridgeport station and new capacity at Keys amounts to 1,800 megawatts of new, clean and efficient gas fired capacity over the next three years. This will transform Power’s fleet and enhance its competitive position. We will see an increase in capacity. We will see an increase in reliability. We will see an increase in efficiency and we will see a reduction in carbon emission. Although Power has focused on the construction of the new combined cycle units, Power’s also committed to improving the efficiency of existing capacity and ensuring its long-term availability. This can be seen through completion of a small upgrade at its peaking stations which adds 14 megawatts to capacity. Power also plans to increase the efficiency and capacity of the Bethlehem Energy Center through advanced gas path upgrades of the turbines over 2017 and 2018. When completed, this work is expected to add 58 megawatts to BEC’s capacity. And the recent issuance of a final renewal permit of the Salem station that meets the requirements of Section 316b of the Clean Water Act helps to assure the long-term availability of this zero carbon generating resource. Finally, Power has made targeted reductions in its workforce and continues to identify additional means of reducing its cost structure to assure the availability and dispatch of the fleet in the current low-price environment. The power market over the short-term continues to be characterized by an oversupply of gas. The market, however, has shown signs of improvement as gas prices have responded to a decline in production. The improvement in the supply picture and the development of more outlets for supply has also led to an improvement in forward basis. As we’ve indicated in the past, we continue to expect basis to be seasonal that is positive in the winter and neutral to negative in the summer, until more takeaway capacity goes into operation. In May 2016, PJM announced the results of the RPM auction for the 2019, 2020 delivery year. Power cleared approximately 8,900 megawatts of its generating capacity at an average price of $116 per megawatt day. The average price received by Power while lower than prior auction continues to represent a premium to the average price for capacity in the RTO. Prices in the most recent auction reflect PJM’s downwardly revised demand forecast, changes in the emergency transfer limits due to its transition expansion and the effects of both new generation and unclear generation from the prior year’s auction. However, the results of the RPM auction were in line with our expectations. Nearly all of Power’s clear capacity in the latest auction complies with PJM’s capacity performance requirements and the fleet is expected to be in a position to meet PJM’s requirement that 100% of capacity for the 2020 to 2021 delivery year must meet those CP requirements. On the regulatory front, FERC has approved two of the five recommended steps to improve energy price formation. Further efforts to address transparency in the scheduling of capacity could lead to an approved alignment of prices with costs. The year has presented challenges. Looking forward to the second half of the year, we’re maintaining operating earnings guidance for 2016 of $2.80 to $3 per share. But it will be difficult to reach the upper end of the guidance even with an improvement in the power markets, expectations for warm summer weather, restoration of normal operations at Salem and ongoing cost control and management of O&M. Our highly skilled workforce has met the market’s challenges through the right sizing of resources and by identifying investments that meet customer needs. Our dedication to customer service, our strong balance sheet and our ability to invest in the future of the company are expected to drive long-term value creation. With that, I’ll turn the call over to Dan, who will discuss our financials in greater detail and then I’ll be available for your questions.

Thank you, Ralph, and thank you for everyone for joining us today. As Ralph said, PCG reported operating earnings for the second quarter of 2016 at $0.57 per share, the same as operating earnings at $0.57 per share in last year’s second quarter. The reconciliation of operating earnings to net income for the quarter can be found on Slide 4. We've also provided you with a water fall chart on slide 10 that takes you through the net changes and the quarter-over-quarter operating earnings by major business and a similar chart on slide 12 provides you with the changes on operating earnings by business on a year-to-date basis. I'll now review each company a little bit more detail starting with PSE&G. PSE&G reported net income for the second quarter of 2016 at $0.35 per share compared with $0.33 per share for the second quarter of 2015 or a 6% improvement in earnings. The results for the quarter are shown on slide 14. PSE&G's operating results for the second quarter reflect the impact of revenue growth associated with an expansion of the company's capital investment program. Returns on PSE&G's expanded investment and transmission added $0.03 per share to earnings for the quarter. An increase in depreciation and O&M expenses were $0.02 was partially offset by a decline in taxes and other items. The higher level of depreciation is related to the growth in capital spending and higher levels of O&M reflect increased spending on vegetation management. The New Jersey economy continues to show steady growth and employment levels have shown improvement from a year ago. The variability in quarterly data for weather normalized electric and gas sales has been high given extreme weather comparisons. Weather normalized electric sales reflect growth in residential and commercial customers, which is offset by the continuing decline in the industrial sector and increased energy efficiency measures. So, on a trailing 12-month basis, weather normalized electric sales were essentially flat. PSE&G's capital programming remains on schedule. PSE&G invested approximately $1.4 billion during the first half of the year as part of its planned 2016 capital program of $3 billion. As Ralph mentioned, PSE&G has identified investment opportunities which, if approved, will increase PSE&G’s five-year capital program by approximately $500 million to $12.5 billion. And you should expect the majority of this increase in spending will occur between 2016 and 2018. Once again, all of this growth will be funded without the need to issue new equity. As you may recall, PSE&G implemented $146 million increase in annual transmission revenue under the company's transmission formula rate filing which took effect this past January. This increase in revenue adjusted to reflect the impact of bonus depreciation and updates of spending in prior years will be reflected in PSE&G's earnings throughout the year. But I'll also remind you that the quarter-to-quarter earnings comparisons associated with PSE&G 's investment and transmission are not expected to be even during the second half of the year. The recognition of bonus depreciation for 2015 and some other expenses at the end of the year reduced PSE&G's fourth quarter 2015 earnings by about $0.04 per share. The contributions to earnings from energy's strong capital program will also be more evident during the second half of the year given growth in the energy strong-related spending and the shape of the rate structure which places more emphasis on the demand charges during the third quarter. We are increasing our forecast in PSE&G operating earnings for 2016 to $900 million to $935 million from $875 to $925 million. And the change incorporates cost-control efforts and a strong start to summer weather. Now let's turn to power. PSE&G Power reported a net loss for the quarter of $11 million or $0.02 per share compared with net income of $166 million or $0.33 per share for the year-ago quarter. Operating earnings were $0.18 per share for the second quarter of 2016 and adjusted EBITDA was $272 million as compared with operating earnings of $0.22 per share and adjusted EBITDA of $301 million for the second quarter of 2015. Our adjusted EBITA excludes the same items of operating earnings as well as income tax expense, interest expense, depreciation, and amortization and major maintenance at Power's fossil generating facilities. The earnings release and Slide 20 provide you with detailed analysis of Power’s operating earnings quarter-over-quarter. We've also provided you with more detail on generation for the quarter and the first half of the year on Slides 22 and 23. Power’s operating results for the second quarter reflect the impact of the known decline in PJM capacity revenues and average prices on energy hedges, in addition to the effect of an extended refueling outage at Salem 1. Decline in capacity revenue associated with the June 2015 retirement of capacity in PJM reduced quarter-over-quarter income by $0.02 per share. And capacity revenue during the second half of 2016 should approximate the revenues received during the last six months of 2015. Earnings comparisons in the quarter were also impacted by decline in the average price received on energy hedges as well as lower market prices and gas volumes, which together reduced Power’s quarter- over-quarter income by $0.03 per share. A decline in output reduced income by $0.01 per share. Reduction in O&M expense improved Power's quarter-over-quarter income by $0.07 per share. This improvement reflects the absence in 2016 of costs incurred during the second quarter of 2015 for the refueling outage at the Hope Creek nuclear plant which is 100% owned by Power and major maintenance work at our combined-cycle units. And the quarterly comparisons also benefited from targeted reductions in O&M at powers nuclear and fossil stations as well as from changes in the management of work schedules associated with the Salem 1 refueling outage which minimized the overall cost of the outage. As we mentioned during the first quarter earnings call, the Salem 1 refueling outage which began on April 14 would be extended to repair degraded baffle bolts. The bolt replacement has been completed and the unit is in the process of returning to service. During the quarter an increase in depreciation expense was offset by declining interest expense. However, an absence in 2016 of tax credits received in a year-ago quarter and other tax items contributed to a reduction in quarter-over-quarter income up $0.05 per share. Turning to Power’s operations, output at Power’s generating facilities declined 6% in the quarter as a result of lower wholesale market prices and reduced demand. Output from the gas fire combined-cycle fleet declined slightly to 4.4 terawatt hours from 4.6 terawatt hours given mild weather conditions relative to the year-ago quarter. Low gas prices impacted the dispatch of powers coal fire fleet and during the quarter the output from the coal fleet declined to 0.9 terawatt hours from 1.3 terawatt hours. Output from the nuclear fleet was largely unchanged in the quarter with 7 terawatt hours in this quarter versus 7.1 terawatt hours in the year-ago quarter. The impact of the extended outages at Salem was largely offset by an increase in output at Peach Bottom. In completion of the extended power operated at Peach Bottom, added 130 megawatts in the aggregate to Powers' interest in the station. Salem 2 was out of service for three days at the end of the quarter and remains out of service. The unplanned outage at Salem 2 is a result of an electrical fault in the reactor's non-nuclear balance of plan. The extension of the outage at Salem 1 into July and the unplanned outage at Salem 2 will have a continuing effect on performance in the third quarter. Power's gross margin in the second quarter declined to $38.54 per megawatt hour from $40.15 per megawatt hour. Power's margin in the quarter experienced only a modest benefit from the gas fire combined-cycle fleet's access to low-cost gas. A lack of demand and low volatility in the market, given an excess supply of gas, pressured spark spreads. The power markets over the last month have seen prices move to higher levels, given the impact on gas supply from hotter than normal weather and declines in production. An improvement in load and prices will help margins on base load units as an increase in regional gas prices, but also support margins at the gas fired combined-cycle fleet. For the year Power is revising its forecast of output to 50 to 52 terawatt hours from the prior forecast of 52 to 54 terawatt hours. And the updated forecast incorporates the results for the first half of the year and takes into account the extension of the outage of both units at Salem. As shown on Slide 26, approximately 75% to 80% of anticipated production for the second half 2016 of 25 to 26 terawatt hours is hedged at an average price of $50 per megawatt hour. For 2017 Power has hedged 55% to 60% of its forecast generation, up 53 to 55 terawatt hours at an average price of $48 of megawatt hour. And for 2018, Power has hedged approximately 25% to 30% of forecast generation of 58 to 60 terawatt hours at an average price of $46 per megawatt hour. The forecast and increase in output for 2018 reflects the commercial start-up of the new gas fired combined cycle capacity at the keys and C1 stations. The percentage of energy hedge for 2017 and 2018 is slightly greater than what we communicated to you earlier this year and in line with our practice. We've adjusted our forecast to Power's full year 2016 operating earnings to $460 million to $525 million from $490 million to $540 million. So, incorporate the results for the first half of the year. The revised forecast represents an adjusted EBITDA of $1.27 billion to $1.375 billion. I'll turn to PSEG Enterprise and other. The net income for PSEG Energy Holdings and Enterprise in the second quarter of 2016 was $19 million or $0.04 per share versus net income of $12 million or $0.02 per share for the second quarter of 2015. The increase in quarter-over-quarter income reflects contractual payments associated with the operation of PSEG Long Island and certain tax items at PSEG Energy Holdings. We raised our forecast for the full year of operations to $65 million. Our financial position remains strong. PSEG closed the quarter ended June 30, 2016 with $648 million of cash on its balance sheet with debt at the end of the quarter representing 45% of consolidated capital. During the quarter, Power issued $700 million of 3% five-year senior notes due in 2021. We do not foresee the need to issue equity to finance or expand the capital program. And as Ralph mentioned, we are maintaining our forecast of operating earnings for the full year of $2.80 to $3 per share. And with that, we'll be happy to take any questions.

Ladies and gentlemen, we will now begin the question-and-answer session for members of the financial community. [Operator Instructions] You first question comes from the line of Jonathan Arnold with Deutsche Bank. Please go ahead.

Hi, Jonathan. Are you there?

Mr. Arnold, please make sure your line is not on mute.

Power is still working in this building so...

Your next question comes from the line of Travis Miller with Morningstar. Please go ahead.

Good morning. Thanks.

Hey, Travis. Good morning.

I was wondering if we look ahead more generally to 2019, 2020 when you guys have your new plant online, and PJM in your region and the other plants that are proposed, what are your thoughts on spark spreads? Obviously, we've seen what's happened in the capacity markets. But what are your thoughts on what happens to spark spreads?

Well, so Travis, I mean by that point, we will have grid plans up – we will have one in Connecticut, one in New Jersey and one in Maryland and it really will depend upon the infrastructure that's being built in each of those locations. As you know, all of those sites do have gas on the property. But we're seeing an increased importance in regional spark spreads. Right now in our region we're seeing sparks spreads giving our access to natural gas with that $20, down at Pepco. It's pretty close to that, the forwards they are saying it could be as high as $23 still I mean we certainly make these investment decisions on the expectation that the combination of either locked in or anticipated capacity prices plus those spark spreads would allow us to recover our cost of capital and then some. So as you know, our history is we don't – we don't usually pick numbers that are different than what the market is telling us. So right now, the local spark spreads defined region by region is in the $20 range.

Okay. So pretty flat type of curve that you think.

I think the dynamic will be modified as the infrastructure gets built.

Okay.

Now for a good six months or so.

Great, and then on the - you guys have been benefiting for quite a while on that Marcellus gas basis at Power. When does that cycle off in terms of incremental growth? When does it stop being a net benefit I suppose, relative to the previous years?

So therein lies the value of a diversified fleet. One would expect that as infrastructure gets built from the region to mostly Southeastern markets that you'll see an increase – a decrease in price in other parts of the country which don't have that access, and an increase in price here which will diminish our regional sparks spread advantage but that should also then help our nuclear plants. So it's been an ongoing source of pride for us that diversity of technology and fuel allows us to deliver some consistency in terms of the margins that we – that we're able to capture. And then of course, one cannot ignore the seasonal variations that will persist even once the infrastructure gets built.

Sure. Okay. Thanks. I always appreciate the thoughts.

Your next question comes from the line of Julien Dumoulin-Smith with UBS. Please go ahead.

Hi. Good morning. Can you hear me?

Yes, Julien. Good morning.

So I wanted to ask kind of a bigger picture strategic question about the fate of nuclear in New Jersey, if you can think through that with us. What is your current positioning on the need for support and the price for carbon in New Jersey specifically? Perhaps not just with respect to RGGI, but looking at parallels from New York, how are you positioned in this state?

Yes. Julien, thank you for asking the question because I want to make sure that there's clarity of understanding around that. There's a lot going on in the nation around nuclear. I don't know the latest numbers. I think 10 to 15 plants are rumored to be at risk of retiring. Half a dozen have retired. Our dilemma is that as active industry participants, frustrated by an absence of carbon value given to nuclear plants and seeing what's happening around us, is we're trying to engage policy makers in a conversation that nuclear is not getting the credit it deserves. Our challenge is our plants are quite healthy economically, so notwithstanding the importance of carbon, I think the motivation in other markets are some of the near-term economic consequences of shutting those plants given their lack of profitability. So we don't have that situation. We're glad we don't have that situation. But it does – it does sort of impair our ability to have the same level of interest and participation in the discussion. So we've been talking about fuel diversity. We've been talking about 90 plus percent capacity factors and what it would mean should long-term forces require the replacement of that. Whatever those long-term forces might be but it is kind of a difficult conversation to have given how many pressing problems are staring policy makers in the face right this minute. So on the one hand, yes, I don't want to go on ad nauseum. We feel strongly that nuclear is not getting the credit, i.e., price it deserves but we cannot and we do not make the claim that our plants are at any kind of economic risk in the near term the way others are.

So perhaps to expand on that, no specific efforts in New Jersey and/or thoughts on kind of nascent efforts at PJM to perhaps more appropriately price in diversity?

No, no, no. We are having early conversations that – in both forms – about what that kind of more accurate representation of the value could look like. And we're informing people who don't study this stuff as much as we do about what’s being proposed in the New York State and what's been discussed in Connecticut and what didn't happen in Vermont and Massachusetts and Wisconsin and what that led to and what doesn't appear to be happening in Illinois. So we're not just walking around saying, boy, I wish the world was different. We're talking to people who care about these things, about what the consequences have been and – in places were nothing took place and what would happen – what's being proposed in other places. At PJM, I think there's much more of a focused on reliability associated with such large quantities of baseload power that don't have the seasonal challenges of access to gas and back-up fuels. But I think that historically PJM of course has not viewed itself, nor should it, as an implementer of environmental policy. So the conversation can be broader at the State level than the stakeholder process at PJM.

Got it, and then completely separate question, just in terms of Power. Are you still thinking about expanding the footprint of Power? Obviously you have been through the different diversification efforts. Where you think you are with respect to having an adequate scale in that business, and/or desirability of further investments? I will leave it there.

Yes. No, no. So I think some power has some – has stated its desire to expand in New England, New York and PJM. We think that those are the most efficient markets given the combination of energy and capacity value in all three of them. We have also said that we do not anticipate any new build. We thought we have three very unique situations but in the flat demand world with pretty much an over-supply condition, arguably all three locations but certainly in two of them, injecting new supply does not appear to be a winning proposition. From the point of view of a power scale, I mean, in terms of its reach, I'd like to see it have a little bit more of a robust portfolio outside of PJM than it currently has, but its certainly would be one of the largest, if not the largest, independent power producer on its own if that is where you're headed with that question. Power doesn't have a lot of megawatts, but it's financial strength and its profitability I think are quite unique. And something that we are very proud of and we work hard to preserve that in making our operating and investment decisions. So there’s – so the way we – we intend in the near-term to grow Power is the way we’ve been trying to which is through selective acquisitions of existing supply. As you know, we’ve not been successful at doing that. The one project we landed was the keys project and there probably because our perception of construction risk management was different than others. So I hope that answers your question.

Yes, absolutely. Thank you very much.

Your next question comes from the line of Praful Mehta with Citigroup. Please go ahead.

All right. Thank you. So just following-up on that question on the future of Power, there looks to be clearly some Texas generation that will be in the market soon. Is there an interest in partnering up with Texas, or is Texas not a market that you look to enter?

No. Praful, you may recall was just a few years ago that we exited Texas. It’s not a market that we would want to re-enter at this time.

Fair enough. All right, and secondly in terms of capacity prices, I know you mentioned in your prepared remarks that you weren't surprised by the current capacity trend. I wanted to get a sense for how you are looking at long-term capacity prices in PJM, and also, what was driving or what is minimum threshold that you looked at when you were making your investment decisions, that instead of a particular price that you thought capacity prices need to stay at to hit your IRR?

So in terms of longer-term, as you know, we don’t forecast prices. What we think will be different about next-year’s auctions than this year’s are a couple factors. Number one is the requirement that 100% of the assets be CP compliant. Number two, we will have a market effect due to a recent announcement, an April announcement by ConEdison that a wheel that they were party to – they will no longer make use of and that wheel had the effect of a net transfer into our region of about 400 megawatts which will now no longer be the case. Also, we don’t anticipate the kind of step change in PJM’s demand forecast that took place prior to the last auction. We have been the primary builder of major transmission and while we still have a very robust transmission program, most of those projects are not involved in significant transfer capability, they’re more at the 69 to 230 KV level within the zone. The second half of your question, what did we look at. So we do have an internal rate of return expectation. That is well-above our utility return expectations. And we look at the combination of energy margin and capacity margin when making that decision. Suffice it to say, obviously the fact that we’re going ahead and building the prices that we realized last year in the auction and this year in Connecticut were sufficient for us to go ahead. So there’s no one magic number in terms of capacity that says go ahead and build, it’s the combination of capacity and energy together over the long term, that we look at.

Fair enough. Thanks so much guys.

You’re welcome.

[Operator Instructions] Your next question comes from the line of Brian Chin with Bank of America. Please go ahead.

Hi. Good morning.

Good morning, Brian.

Good morning, Brian.

We've seen a number of your peers announce greater investment in utility scale renewables, while I appreciate your earlier comment that you're not looking to expand in Power, I was wondering if you can comment on renewable outlook in the Northeast, given just how quickly renewable costs has been declining, and how improvements in technology have changed the landscape from the last couple years?

Sure, Brian. First, we don’t have any peers. That’s number one. I’m sorry. It’s just a personal point of view. Number two, in terms of renewables, you know we’ve been active on two fronts. On the unregulated side, we have about 300 megawatts that are in 12 or 14 states. I’ve lost track. And we specifically embarked on a crawl-walk-run strategy, I'd say right now we are jogging. And those projects have done well. Everyone of them have met their pro formas. In fact, most one of them has slightly exceeded their pro formas. Most of our solar investment, however, has been concentrated in PSE&G and that’s been a blended of rooftop funded solar, where we don’t own the assets, but we have regulatory assets that support the rooftop and then grid connected. As you know, in New Jersey, grid connected is measured in single-digit megawatt as opposed to double or triple digital megawatts. Notwithstanding the impressive price improvements of these installations, they still are substantially above conventional technology power prices. So our estimates right now are that, in New Jersey, people pay anywhere from $4 to $6 a month for solar energy and that’s typical residential homeowner obviously, the average homeowner means that there’s a bunch of people pay more, a bunch of people pay less. In all of our customer survey information suggest that, that is at or above the level that people are comfortable paying. So our pursuit of solar in PSE&G is really driven by the RPS and the desire to achieve those policy-mandated targets at as low a price as possible and doing things three and four megawatts at a time on landfill. It’s a lot less expensive than giving them two to three kilowatt hours at a time on roof tops. But one has to be careful, even three and five megawatts at a time as to what the bill impact is. So we’re long-standing fans of solar. We are not apologists for it, but we do have to balance the bill impacts. So we pursue those opportunities in-state in accordance with the RPS, and in other states in accordance with those utilities needs to meet their RPS and secure those investments through power purchase agreements.

Got it. Thank you very much. That’s all I got.

Your next question comes from the line of Shahriar Pourreza with Guggenheim. Please go ahead.

Hey, Dan and Ralph.

Hey. Good morning.

So most of my questions were answered, but just curious, Ralph, you've, historically on the Power side, you have talked about still having potentially, and let me know if I'm putting words in your mouth, of an interest in the U.S. nuclear business given your diversified fleet at PEG Power, but one of the curtailments of that business has been the mechanisms or lack of mechanisms or the constructs haven't been appropriate. But now that you are looking at some of what's happening in your surrounding states, that environment could be potentially improving. So when you look at Power, you look at its balance sheet and you look at selective acquisitions to increase scale, what you're seeing around you, does it open up the doors of maybe looking at nuclear?

No, Shah. I mean, let me make sure I interpreted the question correctly in terms of new nuclear power, the economics just aren’t there. Every indication of the availability of natural gas and the duration of that availability, and the likely price range that we would see, would suggest that new nuclear and emerging company would not be an economic wise thing to do.

No, I think what I am relating to is pre-existing nuclear assets that could potentially have contracted cash flows for the next few years.

Yes, I mean, if you had contracted cash flows and they met the hurdle rate, we think that nuclear has a long-term future. But as we were saying just a few minutes ago with Julien and Praful, others seem to, invariably when we show up to buy an existing asset, they add a couple dollars to the forward price curve and we don’t tend to win. So in terms of purchasing existing assets so much is driven by the kind of the winner’s curse and your view of where forward prices are going and our is I think more disciplined approach of saying that we are not smarter than the market. So I would think that the practicality of that would be somewhat limiting.

Got it. Thanks.

Your next question comes are the line of Michael Lapides with Goldman Sachs. Please go ahead.

Hey guys. Question on the regulated site on E&G and it's actually a handful of questions. First of all, the $300 million increase in distribution CapEx, can you talk a little bit about how you get cost recovery on that, and whether, if it is not being tracked, does that increase the potential for regulatory lag at E&G over the next couple of years?

Yes. So, Michael, thanks for the question. So two things; number one, part of that $300 million is what's called new business, so there's new revenue that comes with new business. But equally, if not more importantly, as you know, we have to go in for a rate case in November of 2017. So we are doing some things that need to be done, and we are timing them as such that they will fit into the rate base for the test year. So they will be covered by the rate case with minimalist – if any regulatory lag at all.

Got it. Another thing, how are you thinking about the ability to manage O&M at E&G over the next – really what's in 2016 guidance but also how you're thinking about it over the next one to two years, maybe 2017, 2018 both core O&M and then when you think about what's happened with interest rates, discount rates and what it means for the pension component of your O&M and E&G.

Yes. I'll let Dan talk about the pension. But we don't look at O&M on an – it's time to check out O&M perspective. We look at it every day. So we just extended contracts with six out of our eight unions, not all of them were in the utility, but our three largest utility unions were included in that six out of eight, and those were all at reasonable escalation. They were wage increases of 3% per year, but benefit trade-offs that reduced the over-all O&M growth. So we kept utility O&M growth to a little bit over CPI, I think it's 2%-ish, thereabouts. I don't remember exactly CPIs, but I know what our O&M growth rate has been – is just little bit over 2%. We just pay attention to that every day. We are not believers in getting inefficient before rate case, and taking costs out of the business right after it. That is – first of all, it is not a great way to build confidence with regulators, and it's not a good way to manage the operation. In terms of pension, yes, lower interest rates are not going to be great for the PBO, but strong market performance which we've seen will be. But Dan, you may want to add some more color to that.

No, I mean, I think that's exactly right and it's a little bit of a wait and see. I think a lot on the PBO side, exactly what Ralph referenced. The discount rate is going to be determined really when we get to the end of the year. So that’s uncertain until we get there and returns have been doing pretty well. So I think, keeping an eye on those things as we move toward year end, will track where we go in the pension. And in the interim, just try to manage overall and stand whether it storms, whether it's any new requirements we have for inspections or veg management and trying to manage it as a whole which I think we've done successfully in the past and we would intend to do into the future is how we'll go forward.

Dan, have you ever talked about what the sensitivity is to every 25 basis points change in the interest rate? For pension O&M. Sorry.

Yes. Ultimately, it is going to have an impact those on what the obligation turns out to be, and the components of what your returns are. And yes, we do look at that internally to try to see where it goes, but fact of the matter is at the end of the day, the discount rate is going to be the discount rate. So it's something that we need to manage having come at us because we can't control that as a rate itself.

Got it. Thanks, guys. I'll follow-up offline. Much appreciated.

Thanks, Mike.

Your next question comes from the line of Jonathan Arnold with Deutsch bank. Please go ahead.

Good morning, guys. Sorry. I was offline when I called before. Ralph, you've mentioned a sort of some level of interest in the retail business as a way of past market, I believe. Can you update us on your thoughts there and obviously a large booklet one would imagine would have had some sort of geographic interest to you just transacted and with someone else was that bigger type of portfolio that you might be interested in? Or any perspective that might be great.

Sure, Jonathan. First of all, it was good to hear you. I was a little concerned when you disappeared on us before. No, we remain interested in retail for our defensive purposes, managing basis risk and not as a significant growth opportunity by any stretch of the imagination. We've looked at some boutique shops including the transaction you just referenced right now. I suspect that we are going to run into the same issues in looking at those types of potential tuck-in acquisitions as we do in power plants that our discipline, somewhat I consider an approach to pricing these things will result in us perhaps not being able to roll up what we need to roll up from an inquisitive point of view. So we are starting to pay our attention to just building some capability in-house because again, our ambitions here are modest. They're defensive and it's conceivable that an organic approach could be quite a bit more profitable point of view from return expectations. Sorry, Jonathan. I seem to have left a deafening silence.

Sorry. I had the mute button on again. What stage would you describe that sort of internal look at? Have you started to sort of keep together or are you just thinking about it?

We've hired some folks and we've started looking around it kind of systems that we would need that are a little different from the systems we have now. We're preparing to file the necessary documents one needs to be certified or licensed. I figured the exact terminology to engage in this business – be a separate and different function than our current wholesale trading arm.

Okay. But it's actually something you're – it's beginning to move on, but nothing small.

Correct.

Okay. Thank you very much.

You're welcome.

[Operator Instructions] Your next question comes from the line of Anthony Crowdell with Jefferies. Please go ahead.

Good morning. I just had a quick question on I guess the hedge volumes slide 26. I look at the 18 hedge volumes. It doesn't look like there was a big change in the percentage hedge from the first quarter announcement, but the price change went from $54 to $46. Can you provide any clarity on that?

Yes, Anthony, I think we were up at the midpoint of those reigns split up about 5% from the first quarter until now. There's a piece that is about a huge move – a piece of it is as well is that earlier in our over-all hedging trajectory, more of the volume is BGS-oriented. So if you think about what that price is, it includes some non-pure energy items. And as we step further through our hedging, we end up with a little bit more just kind of blocked pure energy trades, which tends to have a more moderating effect on the price itself.

Okay. Great. You're saying earlier in the near when you hedged, I guess, the first hedges you put on a more BGS-oriented hedges and as you move throughout the year and you lay on more hedges, that's more of just an energy market?

So if you think about when the BGS auction happens in February of 2015, you'll have that stuff and going into 2018 and then 2016 we'll have the same effect on 2018. So that accounts for a higher percentage of the volume earlier on and as we step into some of the energy hedges, that number tends to go down a little bit by virtue of the nature of the hedge that we're putting on.

It's like the wedding of Cana, I guess; the better wine first. Thanks for your help.

Good one, Anthony.

Thanks, Anthony.

That's great.

[Operator Instructions] We will pause for just a moment.

Brent, that was probably a great note to end on, if there are no further questions.

Nobody wants to follow that comment.

Okay. Mr. Izzo, Mr. Cregg, there are no further questions at this time. Please continue with your presentation.

So I'm told by Kathleen that many of you folks had a very busy morning with some other calls, so I always am grateful for your participation with a special thank you today given how much was going on prior to us. So in keeping with prior practices, let me just summarize what I hope were the key takeaways for you. The utility growth driven by customer needs and policy maker priorities is really continuing unabated rather than showing up year after each investor meeting telling you about what we found, we're trying to do a better job of keeping you apprised of things as we locate them. So we have about a little bit over $500 million of new stuff that we'll be doing, $300 million which we'll definitely going to do and a couple hundred million of which we're waiting for BPU feedback on. Power remains quite focused on markets managing its costs, its performance and its investment decisions with a real disciplined adherence to what the market is telling us. So some challenging price environments, some great O&M control. And then third and final take away is that this balance sheet remained strong. There's no change in our dividend policy. We continue to have the belief or the opportunity for sustained growth in that dividend that continues and yet these expanding investment needs at the utility and opportunities at the utility can be met without any new equity. So I think we are on a little hiatus for a couple weeks and we will be back on the road in September and certainly see all of you early in November. So thanks very much for joining us. Have a great rest of summer, folks.

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