Kathleen A. Lally - Vice President of Investor Relations Ralph Izzo - Chairman and CEO Caroline D. Dorsa - EVP and CFO

Kit Konolige - BGC Partners Ashar Khan - Visium Asset Management Julien Dumoulin-Smith – UBS Neel Mitra - Tudor, Pickering, Holt & Co. Daniel L. Eggers - Crédit Suisse Paul B. Fremont - Jefferies LLC Paul Patterson - Glenrock Associates LLC

[Call Starts Abruptly] As a reminder this conference is being recorded today, October 30, 2014, and will be available for telephone replay beginning at 2 o'clock p.m. Eastern today until 11:30 p.m. Eastern on November 6, 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 Kathleen A. Lally: Thank you Brent. Good morning and Thank you all for participating in PSEG's earnings call this morning. As you were aware, we released our third quarter 2014 earnings statements earlier this morning. The release and attachments as mentioned are posted on our website, www.pseg.com under the Investor section. We have also posted a series of slides that detail the operating results by company for the quarter. Our 10-Q for the period ended September 30, 2014, is expected to be filed shortly. I'm not going to 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 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, and for a reconciliation of operating earnings to GAAP results. I am now going to turn the call 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. And I'm not going to limit you but that's…

Nice try, Kathleen. Thank you, everyone, for joining us today. Earlier this morning, we reported operating earnings for the third quarter of 2014 of $0.77 per share compared with operating earnings of $0.76 per share in 2013’s third quarter. The results for the third quarter brings PSEG's operating earnings for the nine months ended September to $2.27 per share, which is a 9% increase over the $2.09 per share earned during the first nine months of last year. I'll refer you to slides four and five as they contain the detail on the results for the third quarter and for the nine months. PSEG earnings continued to benefit from the expansion of our regulated utility capital program. Our results also benefited from the focused [placement] controlling the growth and operating expenses which offset the impact of less favorable weather conditions on demand for electricity. Our major transmission projects are being completed on time and on budget. We completed the construction of the $390 million North Central Reliability line and placed the $400 million Burlington-Camden line into service as well. These two 230 kilovolt lines will improve the system’s power quality and voltage stability. Construction on the New Jersey portion of the Susquehanna-Roseland line was also completed in the quarter. The work to connect the western portion of this major 500 kilovolt project in Pennsylvania with New Jersey is underway and it’s planned to go into service around mid-2015. We are in the midst of engineering permitting and siding work on our remaining large projects as we also work on the upgrading conversion of lower voltage lines. These projects are all part of our planned $6.8 billion capital investment in transmission which provides for the double-digit growth in the PSE&G's earnings in 2014 as well as the anticipated double digit growth in rate base and earnings through 2016. We hope to add the proposed 500 kilovolt line at Artificial Island to our stable of transmission projects. We supplemented our original proposal to meet the stability issues in Artificial Island and expect to have a decision from PJM during the first quarter of next year. We've also accelerated the replacement of PSE&G's cast iron gas type system. Approximately $350 million of the $1.22 billion energy strong investment program approved by the BPU earlier this year is dedicated to this ongoing effort. This is an opportune time to pursue these investments. Major surcharges on customer's electric bills are scheduled to expire over the next two years and the bills of PSE&G's gas customers continue to benefit from the capable management of the company's natural gas storage and transportation contracts. The BPU approved on a provisional basis a 9% reduction in the gas rate paid by residential customers. The reduction which was effective on October 1 or just the few weeks ago is the latest in the series of reductions which has lowered customers' gas bills by 44% over the past five years. PSE&G has since indicated that it intends to implement an additional bill credit over the months of November, December and January that will return approximately $160 million to residential gas customers. The earnings growth enjoyed by PSE&G in the quarter offset the impact on earnings from the well-known reset in Power's capacity revenue. Lower operating cost helped to offset the impact of mild weather on energy pricing and earnings. We're in the midst of major change in the electricity market. An unprecedented amount of capacity is expected to retire over the next two years in response to environmental requirements and market economics. In addition the availability of low cost gas in the Marcellus and Utica basins and the lag in the development of infrastructure to move the gas to market has and is expected to continue to be a source of volatility in gas and electricity prices. The new dynamic implies that winter is as important to the power market as the summer as demand in the winter season can heavily influence forward prices. Power is well situated. Its fleet of base load intermediate and peaking generating assets benefits from access to low cost gas in the summer and from price volatility in the winter. The changing dynamic in the market creates a need to review maintenance practices to assure availability of our units during critical peak conditions. The changing market dynamic appears to be recognized by PJM. The change is proposed by PJM to the reliability pricing model, RPM as we often refer to with, are designed to incent operations related investments as much as they’re meant to encourage new investments in light of the events in the winter of 2014 and no new retirements of capacity over the next two to three years. PJM's proposal which provides for a change in the demand curve as well as its capacity performance proposal could provide greater visibility to much needed market driven price formation. Outside PJM, the potential to receive a seven year contracts for new capacity that clears the market in New England under its revised capacity construct has encouraged us to consider bidding a new 450 megawatt gas-fired combined cycle unit into next year's auction. The new unit which will be located at our existing Bridgeport Harbor site would represent a $600 million investment. I do want to emphasize however that we would only proceed with this project if it clears in the forward capacity auction. The potential investment in Bridgeport Harbor would represent the latest of several opportunities for PSEG. Over the past quarter Power has announced the plan to invest $120 million for an equity interest in the PennEast Pipeline. This 105 mile pipeline would bring gas from Pennsylvania into New Jersey and provide PSEG and its customers with increased access to low cost natural gas supply. Similarly, PSEG Long Island has updated its utility 2.0 proposal with a revised proposal to spend up to $345 million, meets the customer's desire for increased investment in energy efficiency demand resources and distributed generation. It also limits the impact on customer bills as the increased investment would be financed by the LIPA, the Long Island Power Authority. The inclusion of our performance incentive mechanism in the proposal provides PSEG Long Island the opportunity to earn an increased return. If preferred the proposal also reaffirms PSEG Long Island's original approach to fund new rate base like investments. So PSEG Long Island could benefit from the utility 2.0 investments through either the use of its own capital or proving out the effectiveness of the programs and earning under the performance mechanism. PSE&G is also awaiting BPU's response to its request to invest approximately $100 million in programs that would extend existing energy efficiency offerings here in New Jersey. Together, if my math is right, these programs represent an investment opportunity of over $1.2 billion and extend the growth associated with our existing $13 billion capital program. These investments also provide our customers with access to low cost gas and cost effective technologies that reduce emissions as they also improve system reliability. Based on the strength of our results for the quarter and year-to-date we are raising the low end of our full year operating earnings guidance to $2.60 from $2.55 per share. And as we indicated last quarter we remain on track to achieve results at the upper end of our revised operating guidance of $2.60 to $2.75 per share. Our investments are meeting our expectations, our costs are under control and we remain well positioned to deploy our balance sheet to meet shareholder objectives for long-term growth. I'll now turn the call over to Caroline to review our operating results in greater detail. Caroline D. Dorsa: Thank you Ralph and good morning. I will review our quarterly operating earnings as well as the outlook for full year results by each subsidiary company. As Ralph said, PSEG reported operating earnings for the third quarter of 2014 of $0.77 per share versus $0.76 per share in last year's third quarter. And for the nine months ending September 30th we reported operating earnings of $2.27 per share versus $2.09 per share last year. Slide four and five provide a reconciliation of operating earnings to income from continuing operations and net income for the quarter and year-to-date. 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 those changes in operating earnings by business on a year-to-date basis. So now I’ll overview each company in more detail starting with PSE&G. As shown on slide 14 PSE&G reported operating earnings for the third quarter of $0.39 per share compared with $0.33 per share a year ago. PSE&G's earnings in the third quarter continue to benefit from the increase in the revenue associated with its expanded capital program particularly in transmission and a decline in operating profit. An approved increase in PSE&G's transmission revenue under its formula rate effective at the start of the year supported the quarter-over-quarter increase in the net earnings contribution from transmission of $0.04 per share bringing the total transmission-related earnings increase to $0.10 per share on a year-to-date basis. And the roll-in of our second capital infrastructure program or CIP II into our rates this past July improved earnings comparisons from distribution during the quarter by $0.01 per share. The decline in operating expenses particularly pension expense lead to an improvement in earnings of $0.02 per share. PSE&G's revenue was affected by weather conditions during the third quarter which was very mild relative to normal as well as relative to conditions in the year-ago quarter. On average, weather in the third quarter was 14% cooler than normal and 18% cooler than 2013's third quarter. The impact on demand from the mild weather reduced quarter-over-quarter earnings by $0.02 per share. PSE&G's earnings continue to benefit from a decline in financing cost which more than offset an increase in the level of debt on its balance sheet associated with higher levels of capital spending. The reduction in interest expense and a lower tax rate more than offset an increase in depreciation expense and netted to an increase in quarter-over-quarter earnings of $0.01 per share in the distribution business. Economic conditions in New Jersey, as evidenced by employment in the service territory continue to show signs of improvement. Adjusting for the weather, electric sales in the quarter grew by 0.4% and the improvement was led by an increase in demand from the residential sector and reflects some growth in the number of customers. On a year-to-date basis weather normalized electric sales grew by 1.1%. Weather normalized gas sales, while less impactful to results in the third quarter, advanced 1.9% in the quarter and 4% for the nine months ended September. Of course demand for gas continues to benefit from a decline in commodity prices and economic conditions. Customers will see a further decline in the commodity portion of their bills during the upcoming year. The BPU approved on a provisional basis an annual reduction of 9% in residential customer gas rate, that went into effect on October 1 of this year, and given the continued availability of low cost gas under the company's long-term supply arrangement PSE&G has since informed to BPU that it would be implementing an additional three months bill credit of 31% which would retire approximately $160 million to customers over the months of November, December and January of 2015. On the transmission front, PSE&G has filed for an update to its formula rate per transmission at the FERC. The update, which provides for a return on PSE&G's forecasted increase in its capital investment and transmission would increase 2015's annual transmission revenues by an estimated $182 million at the start of the New Year. You’ll recall that in 2014 we added a $171 million to our revenues which has resulted in year-to-date growth in earnings of $0.10 per share; something to keep in mind proportionally as you do our modeling for our filing for 2015. The BPU also found that all but $400,000 of PSE&G's $366 million of storm costs are prudent and recoverable in a future-based rate proceeding. The total spend breaks down as approximately a $126 million of major storm capital expenditures and incremental O&M of approximately $240 million. PSE&G is also awaiting a decision from the BPU on its request to invest approximately $100 million plus administrative cost on programs that would extend existing energy efficiency offerings in the residential multi-family, hospital and self-install markets. This program is not expected to have a major impact on customer rates and we expect a decision during the first half of next year. PSE&G is meeting its capital and operating benchmarks and earnings its authorized returns. For the year, we've made a slight modification to our forecast of PSE&G's operating earnings. The low end of the range has been increased to $710 million, bringing the rate -- excuse me -- bringing the range for operating earnings guidance to $710 million to $745 million from the prior $705 million to $745 million. Results for the remainder of the year will continue to reflect an increase in transmission and distribution revenue and a reduction in operating and maintenance expense, including importantly pension costs. With that let's now turn to Power. Power reported operating earnings for the third quarter of 2013 of $0.34 per share compared with $0.43 per share for the third quarter of 2013. Power's results reflect the full quarter impact of the scheduled reset in the average price received on PJM capacity as well as lower market prices for Energy. PJM capacity prices are reset to an average level of $166 per megawatt day on June 1 of 2014 from $242 per megawatt day in the prior capacity year. Recall that we enter a period where power's PJM fleet, based on the results of past auctions is expected to experience stable capacity prices in the range of $165 to $166 per megawatt day through May 31 of 2018. A decline in capacity revenues reduced Power’s quarter-over-quarter earnings by $0.09 per share. Mild weather conditions relative to a year ago and lower gas prices resulted in a return to a more average [spot] spread for our region than those we experienced during the hot summer last year and that reduce quarter-over-quarter earnings by $0.03 per share. A decline in Power's average hedge price for energy and lower market prices combined to further reduce quarter-over-quarter earnings by $0.04 per share. Power's O&M expense was lower in the quarter relative to the level experienced in the year-ago quarter. The actions of major maintenance expense at the Bethlehem, New York facility in 2014 compared to the year ago quarter and lower nuclear outage related cost even with the impact of Salem’s extended outage in the quarter, combined with lower pension expense to improve Power's quarter-over-quarter earnings by $0.06 per share. A reduction in the tax rate and the other miscellaneous items more than offset an increase in depreciation and interest expense to improve quarter-over-quarter earnings by $0.01 per share. The availability of the Bethlehem, New York gas-fired combined cycle facility in 2014 led to a 4% improvement in the generating fleet’s output in the third quarter as production from the gas-fired combined cycle fleet increased 16% in the quarter to five terawatt hours or about 34% of output. Output of the nuclear fleet improved slightly from a year-ago levels. During the quarter the fleet operated at a capacity factor of 92% and produced 7.6 terawatt hours or about 52% of output. Production from the cold-fired and peaking units declined 8% during the quarter to 2.1 terawatt hours, about 14% of output due to planned outages as well as lower weather-related demand. Generation volumes in PJM overall were flat relative to year-ago levels. Power expects output for the full year to be approximately 53 to 55 terawatt hours. The forecast represents a slight increase in output on a year-over-year basis but is lower than our prior forecast for 2014 given year-to-date performance including the mild summer. Keep in mind we have scheduled fourth quarter outages at the Salem 1 and Peach Bottom 2 Nuclear facilities. Salem 1 begin a normal refueling outage earlier this month and Peach Bottom is undergoing work associated with its planned upgrade during a refueling outage. Approximately 80% to 85% of generation in the fourth quarter is hedged at an average price of $49 per megawatt hour. The average price for energy hedges in the full year is approximately $48 per megawatt hour versus the average hedge price for energy in 2013 of about $50 per megawatt hour. Power’s maintaining its forecast of economic generation for both 2015 and 2016 at 55 to 57 terawatt hours per year. This represents an increase in output from 2014’s forecast. For 2015 Power has maintained its average hedge position at 65% to 70% of forecast generation at an average price of $50 per megawatt hour. You will recall that Power increased its hedge activity earlier in the year in response to higher market prices. The current level of hedges is consist with past practice and continues to assume BGS volumes represent about 11 terawatt hours of demand, in line with the 2014 forecast for BGS volumes. In 2016 Power has increased its average hedge position to approximately 35% to 40% of its generation from 30% to 35%. Hedges in 2016 have been transacted at an average price overall of $49 per megawatt hour compared with our prior update which indicated average hedge prices for 2016 of $51 per megawatt hour. The decline in the average hedge price for 2016 reflects an increase in non-BGS related hedges, all done at market prices since our last update and you will recall you have seen this pattern from us in prior periods as we increase the proportion of non-BGS hedges in the third year out the weighted average math of putting in hedges at market prices relative to the representation of BGS in that total, and remember BGS goes in at a full requirement price less capacity, normally brings down the weighted average hedge price as we move through the year. For example in 2016, last quarter BGS represented about 30% of the total amount that was hedged in our disclosures last quarter and now it’s closer to 25%. One thing to note is that the prices that the new hedges were put on, the market prices for the new hedges are actually slightly higher than the energy component of BGS that cleared in February of 2014. So again our normal pattern as we layer in market hedges post the clearing of BGS in February. We’ve narrowed our range for Power’s 2014 operating earnings guidance to $575 million to $610 million from the prior $550 million to $610 million with full year operating results expected to be at the upper end of the range. Results for the remainder of the year are expected to be influenced by the reset in the average price received on PJM capacity that we just talked about and the decline in the average price of energy. Power’s O&M expense for the fourth quarter is expected to compare favorably with year ago levels, given a reduction in pension expense and the absence of major outage related work. We anticipate O&M for the full year will be flat versus 2013’s level of expense and this estimate as always assumes normal weather and normal operations. As we notified you earlier this year Power discovered errors in its cost based bids for its New Jersey fossil generating units in the PJM energy market as well as additional pricing errors and differences between the quantity of energy that Power offered into the energy market and the amounts for which Power was compensated in the capacity market. We have since been verbally notified by the FERC staff that they have initiated a preliminary non-public staff investigation into the matters discovered by Power. The investigation could result in the FERC seeking disgorgement of any over collected amounts, civil penalties and non-financial remedies. Power has implemented procedures and continues to develop processes to mitigate the risk of similar issues occurring in the future and as is usual in matters of this nature FERC investigation may take an extended period of time to resolve. We have not by the way changed the reserve we took in the first quarter which still stands at $25 million. Let me now turn briefly to the Enterprise and all other; PSEG Enterprise/Other reported operating earnings of $22 million or $0.04 per share in the third quarter of 2014 versus an operating loss of $4 million, or a $0.01 per share during the third quarter of 2013. The results reflect the inclusion of earnings from the operating contract of PSEG Long Island as well as a reduction in tax expense. The conclusion of an Internal Revenue Service audit for the tax years’ 2007 through 2010 resulted in a $121 million cash refund and a reduction in tax expense. The reduction in taxes improved quarter-over-quarter earnings comparisons by $0.02 per share from the closure of the audit. In October PSEG Long Island update its original Utility 2.0 proposal which called for PSEG Long Island to invest up to $200 million over four years in programs that would expand energy efficiency, demand resources and distributed generation on Long Island. The updated proposal calls for an increase in the size of the program to $345 million. As currently proposed PSEG could fund all or some of increased program and compensation for the part that is funded by LIPA could be performance based. We anticipated a decision on the Utility 2.0 proposal by year end. On the financing side we ended the quarter with cash on hand of $703 million, the growth in PSE&G’s earnings and cash flow and the cash generated by Power continue to support our financing requirements without the need to issue equity. Debt represented 41.6% of our consolidated capital structure and 31.6% of Power’s capitalization at the end of September. As Ralph mentioned earlier we have narrowed the range of our 2014 operating earnings guidance to $2.60 and $2.75 per share and continue to expect earnings to fall at the upper end of that range. 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 forecasted earnings for the year. PSEG Power is expected to reported earnings at the upper end of the forecast range for the year. That concludes my remarks and at this point we are now ready for your questions and I will turn it back over to Brent.

Ladies and gentlemen we will now begin the question-and-answer session for members of the financial community. (Operator Instructions). Your first question comes from the line of Kit Konolige with BGC. Please go ahead with your question. Kit Konolige - BGC Partners: Good morning, guys. Caroline D. Dorsa: Good morning. Kit Konolige - BGC Partners: A couple of related areas, first of all, can you give us a sense of what kind of response you’ve seen in New Jersey so far to -- as far as working with the commission and the authorities in general on 111(d)?

Sure, we had lots of communication [stuff this past] with New Jersey DEP. I think it’s pretty safe to assume that one of the areas they would be focusing on was the amount of credit or candidly the lack of credit given for nuclear output and the feeling that the cleaner states in our case are being somewhat penalized. Second area that I’d put sort of a lower priority the opportunity to perhaps expand the purview of 111(d) to touch upon things that are electric related but not specific to power plants in New Jersey. Our leading clause is get [permission] for transportation so the possibility of expanding 111(d) to include electric transport and the possibility of expanding 111(d) to include methane leakage fugitive emissions from the pipe [inaudible] combined cycle units. But I put those two issues, electric transportation and methane leakage as a distant second to the concern for the credit not given to nuclear. Kit Konolige - BGC Partners: What, Ralph do you have any sense of our A; if there is been any responsiveness at the state level to crediting nuclear and B; what kind of form would you like that to see or can we reasonably expect that to see -- to appear as?

Yes, so I would say that it’s not much of an exaggeration to say that we are in lock step with the state on that perspectives on 111(d). As you know Kit we have a very clean fleet, nuclear typically is 55%, 57% of our yearly output, the third quarter was 52%. But as to the details of how that would manifest itself I am not sure I want to get into that on this call. We could certainly talk more about that hopefully in Dallas if you are at the [DEI] but there is no space that I am aware and hate to be absolutely definitive and say that there isn’t any at all between us and the state’s position but I have been briefed on this couple of times already and I think we’re in lock step with the state in terms of the… Kit Konolige - BGC Partners: Let me ask about one particular area. You used to be in Reggie and now you're not. So is that something you’d like to see reinstated?

No, it isn’t because as we’ve said many times we thought Reggie was a good idea to serve as a template for a national emissions trading program and appetizing Congress to begin a national program. It doesn’t seem wise for the state to diminish its economic competitiveness with respect to nearby states and joining Reggie. Kit Konolige - BGC Partners: One other separate area…

Go ahead Kit. Kit Konolige - BGC Partners: All right, last one. DR how do you expect that the play out? Obviously there are still legal issues pending. And then one way or another presumably PJM and FERC have to figure things out and possibly states as well.

So on DR I mean I know just what you and everyone else in the call knows about it right. I mean the court decisions were very comprehensive, very deterministic, it is positive on the issue I’m guessing I am inferring that the recent stay is just out of healthy degree of respect for FERC and the desire of the judicial branch to allow the executive branch to weigh its options, not at all reflection that the court decided that what they had previously ruled upon was any kind of back peddling whatsoever. So I think DR is likely to come out of energy and capacity markets in the future. Now PJM has gone on record saying that they are going to adjust for that, that they are going to look for ways to allow DR to effect the demand curve but I have got to believe that once that very transparent efficient market whereby DR providers are paid a revenue stream goes away, that that’s going to candidly diminish the amount of DR that’s available and remember RPM stands for reliability pricing model. That’s PJM’s number responsibility, reliability and if they will control the asset I don’t know how much they are going to be able to count on that. So you add that to the removal of the 2.5% hold back and I think all that weighs very positively for people with iron in the ground and generation assets that are there when needed. Kit Konolige - BGC Partners: Great, thank you.

Your next question comes from the line of Ashar Khan with Visium. Please go ahead with your question. Ashar Khan - Visium Asset Management: Good morning and congratulations. Can you just talk a little bit about the plant in Connecticut, if it gets into the auction when it comes online? And also on the Power’s investment in the pipe, when that comes into line as to when those would be helpful to earnings? If you can just remind us what the dates are on those things?

Sure Ashar. So the auction is in February I believe and it’s a three year forward. So it comes into service in 2018. I am not sure what month exactly but early -- first half of 2018. PennEast we have been publicizing a target date of November of ’17. We’ve also been emphasizing that it’s a Greenfield project. You could take those two emphases -- what’s the plural of emphasis - and infer your own startup date for PennEast, but it’s a Greenfield project and it will not be online before November of ’17. It wouldn’t surprise if it slips into ‘18. Ashar Khan - Visium Asset Management: Okay. And Ralph, any other transmission or any other projects which can you just talk about or anything which might be on the drawing board which is not in the CapEx plan?

So I listed about $1.2 billion worth of project that are not in the CapEx plan and they range from Bridgeport Harbor to PennEast and I mentioned Artificial Island which is about $250 million in our re-submittal. And I am looking with a critical look at Kathleen and Carol to see whether or not we have publicly announced what we have put in the open window for PJM. Kathleen A. Lally: No.

We have not okay. So there are other things we are working on right now, nothing that’s staggering or tilts the balance sheet but we are always looking at ways to improve the system and we’ll definitely have an update for you on that in the not very distant future. Ashar Khan - Visium Asset Management: Okay, thank you sir. Kathleen A. Lally: Thank you, next question.

Your next question comes from the line of Julien Dumoulin-Smith with UBS. Please go ahead with your question. Julien Dumoulin-Smith – UBS: First off, good morning. Perhaps to follow-up on the last question. I was curious, how are you thinking about the Power strategy overall? I would just be curious the extent to which you are reinvesting potentially meaningful dollars in New England? Are there other markets, more broadly other asset types, again you have done a few solar projects, are we thinking about a scaling up of spend in this business at all just as a way to deploy dollars in your excess balance sheet?

So Julien good morning. We like the integrated model we love the regulated utility business, we love the power generation business. We look at every project, whether it’s a solar farm in California, we have closed on one recently, or bidding a combined cycle unit in New England or building more transmission on a discounted cash flow basis with different hurdle rates and make sure that they are NPV positive, that there is near-term visibility to the accretion and the balance sheet gives us room to do both in both businesses. So where there is no shortage of us strolling around looking for these opportunities and there is a long list of those we’ve walked from, because others had a different point of view of what the future held. But no, you shouldn’t interpret the Bridgeport Harbor project as any shift in our affection for the regulated utility or anything of that nature. I don’t know, Caroline you may want to add to that. Caroline D. Dorsa: Absolutely and I think when we look at these kind of opportunities, as Ralph said, we are disciplined in looking at the NPV, using the right hurdle rates. I think the thing that makes us interesting in Bridgeport is you think about the capacity construct there and what they put in place giving a seven year incentive which really helps us think through how to make that work for new investment. So those kinds of constructs that truly can convert something really can encourage new investment and we think are very good. Julien Dumoulin-Smith – UBS: Excellent, and then turning to the BGS auction, can we talk briefly about the ability to pass through capacity, transitionally capacity increases as a result of the capacity performance scheme? And any ability from a regulatory perspective to have to shift the BGS contracts, they will allow that?

So that has not been decided formally at this point, Julien. I would point out that as Caroline mentioned a moment ago we have put in for a transmission formula rate adjustment of north of $180 million and the BPU has made it a policy that transmission increases are pass through. I believe there was a similar ruling on SREC issues a couple of years ago. So in general I think the BPU has recognized that if they want to continue to have a fully competitive active BGS market the things that are outside of the control of the BGS suppliers have to be adjusted on an as-go basis. But they have not opined specifically on an incremental capacity auction change that could come out of a PJM’s most recent concern over asset performance. Julien Dumoulin-Smith – UBS: But presumably that’s something you would be seeking?

Absolutely. Julien Dumoulin-Smith – UBS: And then lastly, just a quick one, energy efficiency and just the broad call it, LIPA plan. Can you talk about the incentive in terms of EPS, perhaps a bit more explicit range? Just to give us some kind of sense of what of this could ultimately drive?

Yes, so those details have yet to be worked out but it would safe to assume that they would in the same vicinity as what a regulated return would achieve if the investment had delivered upon the promise to operational performance, right. So don’t think of this as having an effective ROE of 20% or 30% and don’t think of it as something that would be south of 10%. It’s just okay if we think this LIPA is going to do X and it does X than in our eyes then that should have been a prudent investment but there is a slight increase in risk that’s taken as a result of that kind of mechanism. Caroline D. Dorsa: And just keep in mind as you are thinking about the modeling for Long Island and I know you know this but just to reinforce so we have $0.03 per share this year rising to $0.07 to $0.08 per share by 2016 and that does not include any potential uplift that we might get from these new proposals that we are making. So that’s the base contract that’s currently enforced something here would be additional. Julien Dumoulin-Smith – UBS: And a clarification there. Presumably you would achieve these targets over time such that you would not necessarily immediately hit the first year of the $345 million, the regulated return? Or is that…

The numbers we gave earlier Julien, our original program of $200 million, the expanded program of $345 million, both of those were four year programs. So you would not see all that programmatic emphasis or capital deployment take place in the first year, it would be over four years. Julien Dumoulin-Smith – UBS: All right. Okay so thank you. Kathleen A. Lally: Thank you. Next question?

Your next question comes from the line of Neel Mitra with Tudor Pickering. Please go ahead. Neel Mitra - Tudor, Pickering, Holt & Co.: Hi, good morning. I had a question about the PennEast Pipeline and the off take agreements how does that benefit you, is it at the utility with lower gas prices for PSE&G or is it kind of lower gas prices to fill your combined cycle plans?

Good morning Neil so it’s the same exact sequencing of uses as we have today. So 125,000 to 150,000 bcf a day -- 125 bcf a day. So the priority customer would be the utility regulated distribution gas customer, they get first [chance] at that. Second would be off system sales and then lastly would be power used for burning in its plant. So what tends to happen under those three tiered prioritizations is that Power really doesn’t get to make a lot of use of that additional low cost gas in the winter months. A little bit more but not a lot in the spring as we start to refill for storage reasons but gets to use a whole bunch of it in the summer when storage is completed and there’s no heating demand. Right now Power is using about 25% -- about 25% of the gas the Power burns is from the [inaudible] region it could go up on a percentage basis from that. Neel Mitra - Tudor, Pickering, Holt & Co.: Got it. Great, thank you and then secondly with the CCDT expansion in New England can you just generally give your thoughts on the New England market. It’s obviously gone very quickly from an oversupply to an undersupply and just wanted to get your thoughts on capacity and energy looking at that project?

So I think, there’s two things are important in New England market. Number one is what you just mentioned. They have gone through an undersupply condition as assets announced and carry through on their retirement. But number two is really what Caroline pointed out which is a risk reward profile has shifted to be a little bit saner when you’re making an investment and you want a recovery on your long run marginal cost not just your short run marginal cost. So the seven year capacity payment is extremely helpful there. I think the big question is the one that you hinted at in New England, that’s around energy markets, given the lack of infrastructure for natural gas into the region. You’re going to find people looking at assets that are near existing infrastructure and have a dual fuel capability and I'm pleased to say that we have both of those in our Bridgeport Harbor side we have both access to gas and we will go for dual fuel. Lastly on the capacity [margin] addition to the seven year construct, the change in the slope on demand curve allowing for return some of the missing money that plagued that region. Neel Mitra - Tudor, Pickering, Holt & Co.: Hey great, perfect, thank you. Kathleen A. Lally: Thank you. Next question?

Your next question comes from the line of Dan Eggers with Credit Suisse. Please go ahead. Daniel L. Eggers - Crédit Suisse: Hey, good morning guys. Kathleen A. Lally: Good morning.

Good morning, Dan. Daniel L. Eggers - Crédit Suisse: Caroline I hate to bring up a number question on the call but when I look at the fourth quarter guidance for Power, kind of staying within the range of what you guys have for your guidance, basically it means you guys will earn somewhere between, I think $0.05 and $0.12 or $0.13, which is down quite a bit from prior years. Can you kind of walk me through what are the big drivers that’s going to lead to that much of a decline and then how we should think about that kind of for next year from a base line perspective? Caroline D. Dorsa: So thanks for the question Dan. We took up the bottom end of the range right, but we’ve also said that we expect to be at the high end of the range. The one thing I think you should always keep in mind as you do the quarter-over-quarter comparisons which you saw this quarter for the first time as the full quarter, right, last quarter was just a month, is capacity, right? So capacity on a quarter-over-quarter basis just like you saw this quarter is a $0.09 impact and so you have to start there right, that’s significant dollars, but of course we knew that. We took that into account in our guidance all the way through the year. So that’s the number one thing I would suggest that you consider. Of course going the other direction is we do expect favorability in the O&M, as I mentioned. So that’s going to go a little bit to positive direction and then the normal kind of unit operations, keep in mind we have Salem 1 and Peach Bottom outages which I mentioned during my remarks that Peach Bottom outage is a good one for us because it’s the EPU going into one of the units that will give us more megawatts for the future. So but those things obviously have an impact in the expected generation. So if you think about the pushes and pulls you’ve got Salem 1, you’ve got Peach Bottom in near term, before the winter period of course, you’ve got capacity at $0.09 going the negative direction, fully anticipated; you’ve got O&M going in the positive direction because full year we are guiding to about flat so you can pretty easily do the math. We were worse in O&M in the first two quarters, better in this quarter, anticipate to be better in the fourth quarter and then of course it’s just a normal operations and whatever the weather is at the beginning of the winter. So all in we still expect to be at that upper end of the range. We feel the bottom, but really haven’t changed our thinking which is with normal operations you’d see us be at the upper end, [which is what] drives the company to the upper end. Daniel L. Eggers - Crédit Suisse: Okay so the $0.23 or whatever it is you take out the $0.09 of capacity revenues, which will get you to kind of $0.14, which is above the implied range right now. There is some other maintenance issues that will bring you down toward the high end is that the right way to think about it? Caroline D. Dorsa: Yeah, that’s right, think about the outages I just mentioned but still consider us we’re talking about the high end of the range. Daniel L. Eggers - Crédit Suisse: Okay and then can we talk a little bit on the gas basis side, 25% of gas generation came from Leidy, how does the benefit of the basis arbitrage look full year, year-to-date ’14 versus ’13? Caroline D. Dorsa: Yeah, sure so the year-to-date not as strong as ’13. So let’s kind of wind back and look at what happened in ’13. We saw the Leidy differential really appear in ’13 at the end of the second quarter. And that Leidy differential became pretty wide as we got into the summer of 2013 and we talked about differentials being as much as $2. And then of course it was that warm weather and the warm weather is what drove and kept that differential from the Leidy price to the actual market price rate for the energy. This summer was quite different with the cooler weather on the CHI basis depending on weather compared to last year or normal 13% to 18% lower in terms of the weather. So extensive to the site CHI, what we actually have is Leidy gas costs are still lower the problem was for the summer with the lower demand and the cooler weather the differential of Leidy to thinking about where energy is priced in our market, looking at G6, [inaudible] that dropped those prices down. So what happened was the differential really collapsed. Leidy was still cheaper than Henry Hub but the differential moved together as opposed to last summer when it moved more widely apart because of the low demand for the power. Now keep in mind as we think about Leidy going forward you think about Leidy for us we have that access, it’s about 25% of Power’s overall gas usage as Ralph just mentioned and I think what we’re still expecting to see and you can see if you look at monthly data going forward is the choppiness to the pattern of how to think about basis. Just like we seen actually now for the last two winters the months make a difference so as we come into 2015 we still expect to see benefit from having Leidy, it’s really just about how that basis differential moves relative to power prices. And so the winter periods and the strong summer period we would still expect to see some basis differential on our favor. This was just a tough summer because the low demand led to the lower power prices, not because Leidy prices came up because power prices came down. Last year you may recall we had $0.03 from the Leidy benefit in the third quarter and that’s the $0.03 negative year-over-year I’m citing in this year’s third quarter that I attribute to weather. It’s really the spot spread going back to a normal level versus that expanded spot we had given the differential last summer. Daniel L. Eggers - Crédit Suisse: Thank you for that I appreciate it. Caroline D. Dorsa: Sure, next question.

Your next question comes from the line of Paul Fremont with Jeffries. Please go ahead. Paul B. Fremont - Jefferies LLC: Thank you very much. I guess my first question is at a proposed cost of about $600 million that would account to about 1330 per kw how confident are you in your ability to build at that level and I know that that others in the region have experienced a problems building in the Northeast?

Yeah so, good morning Paul you’re obviously quoting around numbers, the team is running through details right now. We’re filing permit applications so we just think of that as one significant figure and not three significant figures in terms of the accuracy. I think the bigger challenges people had in terms of building has been access to gas. That’s been the number one concern and that one we have well in hand. But we don’t want to give you an exact amount on our -- on what kind of bids are we getting from folks in terms of engines. We’re just [continuing] to the back calculating what we might been in the option and that wouldn’t help anyone. Paul B. Fremont - Jefferies LLC: And then Caroline, just a follow up on that last question, what would be the, you I think provided the quarter contribution as being zero this quarter versus $0.03 in the third quarter last year, what would be the year-to-date numbers on Leidy? Caroline D. Dorsa: Yeah so year-to-date numbers in terms of the gas benefit we had about $0.03 benefit in the first quarter, remember it was a strong winter so it’s about neutral on a year-to-date basis, about zero. Paul B. Fremont - Jefferies LLC: And last year, year-to-date? Caroline D. Dorsa: Last year when the Leidy differential really started to spread it was the end of the second quarter. So there really wasn’t sort of the first quarter of last year effect. So last year at this time it was about $0.03 and for the full year it was $0.05. But that included the fourth quarter so we haven’t got to the fourth quarter yet. So $0.05 full year, $0.03 to this point last year and this year it’s about neutral. Paul B. Fremont - Jefferies LLC: Great and based on the modified CTA formula that was adopted by the NJ BPU what type of adjustment should we assume for PSE&G rate base if you were to use that methodology? Caroline D. Dorsa: Yeah, so we’re very pleased obviously with the decision we think it reflects the right balance from the perspective of the company and the rate payers. Thinking about our rate filing which would be made by November of 2017 and then the five year look back period. The impact for us is di minimus. So really not something you really should be thinking too much about as we think about our rate case numbers going forward because by that period if you take a five year look back you do the adjustment you do the 75:25 it’s truly di minimus.

And you back out transmission. Caroline D. Dorsa: And you back out transmission as well right. Paul B. Fremont - Jefferies LLC: Great, thank you very much. Caroline D. Dorsa: Sure, next question.

Your next question comes from the line of Paul Patterson with Glenrock Associates. Please go ahead. Paul Patterson - Glenrock Associates LLC: Hi, can you hear me?

Yes Paul. Paul Patterson - Glenrock Associates LLC: You guys have a sort of unique position in New York and I was just wondering with the stuff going on there with the REV, I mean sort of really kind of transformative potential for change in regulation, what you guys see as potentially happening to energy and power prices in the state?

In New York State? Paul Patterson - Glenrock Associates LLC: Yeah well I mean you guys have LIPO, so I assume you guys are pretty focused on it. Caroline D. Dorsa: We don’t have it fully.

That’s a very complicated question. Paul Patterson - Glenrock Associates LLC: Okay, I apologize then, I mean just sort of directionally maybe?

Yeah well I think that a lot of the distributed resources that are being advocated, they are going to put upward pressure on prices for customers. I mean there are other reasons for doing things like with rooftop solar and offshore wind that’s being advocated just off of Long Island, and those are capturing some of the environmental benefits that are not baked in. Right now the missing [extra analogy] if you will. Having said that there are some other parts of the program, specifically energy efficiency which while they will also serve to increase rates they will bring overall bills down. So I think a lot depends upon how aggressive people want to be in making in-roads to capturing the benefits associated with the [extra analogies]. We are big advocates of this, both on Long Island and New Jersey but we never tell people that doing this stuff is going to lower their rates. It’s -- you’re getting a benefit you’re having to pay for it. So there are some things that we can do in terms of making sure that some of the reinforcements of that would have to be made in the distribution system are foregone or delayed as a result of perhaps some peak shaving or some broader demand response programs that we can target. And there are some parts on Long Island I think it’s on the South Fork where there’s been a significant growth in peak demand and otherwise command the need for some infrastructure that we will be able to delay. But it really is a much more complicated question than simply gee, we’re doing this to lower everyone’s bills and lower everyone’s rates. The answer really depends on what this is and how aggressive one wants to be on that sort of green agenda. Paul Patterson - Glenrock Associates LLC: Okay fair enough and then just on the -- as you know RPM has been controversial in the past and New Jersey has been sometimes apprehensive about it and I'm just wondering we’ve had several changes with the BPU and we’ve had the potential for several changes happening with DR and capacity performance and everything else, how would you describe the political situation or the general regulatory environment vis-à-vis these issues now as it was in comparison to maybe when the MOPR and the ALCAP issue was going on?

A good question Paul, yes so we had a bit of a change at the BPU. It was all due respect to the commissioners who’ve gone off. We have two new commissions who are quite astute about both energy policy in the form of President Mroz and in terms of the technology strength, weaknesses, limitations in the form of Former Assemblyman Chivukula. He’s a Nautical Engineer by training. He has spent 20 years at Bell Labs. This is a very, very intelligent man who understands the complexity of capital in terms of infrastructure and Rick is well known entity in policy circles in New Jersey and he has actually worked in the energy sphere in the past. So I think that those are two strong additions to balance the BPU. The world is very different now from where it was in El Cap where in the ALCAP days you had strong basis differentials West to East. You have a coal dominated West, the gas dominated East and people were always scratching their heads saying we don’t understand why we pay so much in New Jersey and sadly last month basis was the other way around. It was lower in the West than it was in the East and gas has kind of changed that whole dynamic and I think as a result you’ll see people realizing that the market is working, it’s doing what it’s supposed to do and prices are going to be going up for everybody I believe, and this is a new RPM market as the missing money, appropriately gets restored. So no one likes to pay high prices for energy, there’s no [inaudible] bucks around that but no one wants to see the lights go out either, we came dangerously close in ’14 and a similar winter in ’15 and they probably would go out. So I think PJM is doing the right thing in trying to address that and New Jersey knows that PJM has done a better job than just about any place in the country in making sure those lights stay on. Paul Patterson - Glenrock Associates LLC: Great, thanks a lot. Kathleen A. Lally: I think operator that’s all the time we have for questions. I’ll turn it over to Ralph for just some closing comments and see you at…

Thanks Kathleen. So just wanted to reinforce three messages or comments made by Caroline and me earlier. First of all the utility growth story is very much intact and not only is it doing what we said would do this year but following it for is very much exactly on where we said we would be for 2015. Secondly, hopefully you are as impressed by Power’s diverse asset base as we are in terms of not only its strong performance in current markets whatever the gas prices are doing, whatever coal prices are doing but also how strong a performance it is and how well positioned it is even as we look forward to the ever changing environmental rules and market design parameters. I think we have dual fuel capability, we have units that strong and high capacity factors, all of them have a great position in the CP market if the risk reward profile are in the details as we go forward, is done sensibly and I have every reason to believe that PGM moves you that sensibly. So growth story intact, with the utility Power’s diverse asset base once again demonstrating its strength and last but by no means least the balance sheet remains as strong as ever. So as Kathleen said we look forward to seeing you in days ahead and hopefully for most of us that means the [Inaudible]. Thank you for your time today.

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