公共服務電力與天然氣 (PEG) 2014 Q3 法說會逐字稿

As a reminder, this conference is being recorded today, October 30th, 2014 and will be available for telephone replay beginning at 2:00 PM Eastern today until 11:30 PM Eastern on November 6th, 2014. It will also be available as an audio webcast on PSEG's corporate website at www.pseg.com.

I would now like to turn the conference over to Kathleen Lally. Please go ahead.

Thank you, Brent.

Good morning. Thank you all for participating in PSEG's earnings call this morning.

As you are 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 risk 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 results also contains adjusted non-GAAP operating earnings. Please refer to today's 8K 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 am now going to turn the call over to Ralph Izzo, Chairman, President and Chief Executive Officer of Public Service Enterprise Group. And joining Ralph on the call is Caroline Dorsa, Executive Vice President and Chief Financial Officer. At the conclusion of their remarks there will be time for your questions. And I'm not going to limit you. (laughter)

Nice try, Kathleen. Thank you.

And 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 bring 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 will refer you to slides 4 and 5, as they contain the detail for the results in the third quarter and for the nine months.

PSEG earnings continue to benefit from the expansion of our regulated utility capital program. Our results also benefited from the focus placed on controlling the growth in 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 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 is planned to go into service around mid-2015.

We are in the midst of engineering, permitting, and siting work on our remaining large projects as we also work on the upgrade and 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 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 and artificial island to our stable of transmission projects. We supplemented our original proposal to meet the stability issues at artificial island and expect to have a decision during PJM in the first quarter next year.

We have also accelerated the replacement of the PSE&G's cast iron gas pipe 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 for 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, just a few weeks ago, is the latest in a series of reductions which have lowered customers' gas bills by 44% over the past five years. PSE&G has since indicated that to 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 powers incapacity revenues. Lower operating costs help to offset the impact of mild weather on energy pricing and earnings.

We are in the midst of major change in the electricity markets. 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 changes proposed by PJM to the reliability pricing model, RPM, as we often refer to it, are designed to incent operations-related investments as much as they're meant to encourage new investments in light of the events from the winter of 2014 and known retirements of capacity over the next two to three years.

PJM's proposals, which provide 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 contract 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 would 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's announced it plans to invest $100 million to $120 million for an equity interest in the Penn East 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. The revised proposal, to spend up to $345 million, meets the customers' 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 LIPA, the Long Island Power Authority. The inclusion of a 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 program and earning under the performance mechanism. PSE&G is also waiting the 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 will now turn the call over to Caroline to review our operating results in greater detail.

Thank you, Ralph, and good morning.

I will review our quarterly operating earnings, as well as the outlook full-year results, by each subsidiary company. As Ralph said, PSEG reported operating earnings of 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.

Slides 4 and 5 provide a reconciliation of operating earnings to income from continuing operations and net income for the quarter and year to date. We've also provide 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 will review 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 an increase in revenue associated with its expanded capital program, particularly in transmissions, and a decline in operating costs.

An approved increase in PSE&G's transmission revenue under its formula rate effective at the start of the year, supported a 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 CIP2, into our rates this past July improved earnings comparisons from distribution during the quarter by $0.01 per share. A decline in operating expenses, particularly pension expense, led 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 earnings continue to benefit from a decline in financing costs, which more than offset an increase on the level of debt on 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 0.04%. And the improvement was led by an increase in demand from the residential sector and reflects some growth in the number of customers. So 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 in 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 rates that went into effect on October 1st of this year. And given the continued availability of low-cost gas under the Company's long-term supply arrangements, PSE&G has since informed the BPU that it would be implementing an additional three-month bill credit of 31%, which would return 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 for transmission at the FERC. The update, which provides for a return on PSE&G's forecasted increase in its capital investment in 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 $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 proportionately, as you do your modeling for our filings 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 base rate proceeding. The total spend breaks down as approximately $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 costs, on programs that would extend existing energy efficiency offerings in the residential, multifamily, 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 earning its authorized return. 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 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 2014 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, 2014, from $242 per megawatt day in the prior capacity year.

Recall that we now 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 31st of 2018. Declining 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 spark spread for our region than those we experienced during the hot summer last year. And that reduced 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.

Powers O&M expense was lower in the quarter relative to the level experienced in the year-ago quarter. The absence of major maintenance expense at the Bethlehem New York facility in 2014 compared to the year-ago quarter and lower nuclear outage-related costs, 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 other miscellaneous items more than offset an increase in depreciation in 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 5 terawatt hours, or about 34% of output. Output of the nuclear fleet improved slightly from 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 coal-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 level. Power expects output for the full year to be a 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 began a normal refueling outage earlier this month, and Peach Bottom is undergoing work associated with its planned uprate 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 per 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 is 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 had increased its hedge activity earlier in the year in response to higher market prices. The current level of hedges is consistent 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've 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 requirements 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 a 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 in which Power was compensated in the capacity market. We have since been verbally notified by FERC staff that they have initiated a preliminary non-public staff investigation into 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 $0.01 per share, during the third quarter of 2013. The results reflect the inclusion of earnings from the operating contract for 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 updated 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 the increased program in compensation for the part that is funded by LIPA could be performance-based. We anticipate 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 to $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 a contribution to earnings is expected to exceed 50% of our forecasted earnings for the year. PSEG Power is expected to report 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)

Kit Konolige with BGC.

Good morning, guys.

Good morning.

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 111D?

Sure, Kit. We've had lots of communication, staff to staff, with New Jersey DEP. I think it's pretty safe to assume that one of the areas we've be focusing on 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.

The second area that I'd put as sort of lower priority, is the opportunity to perhaps expand the purview of 111D to touch upon things that are electric related, but not specific to power plants in New Jersey. Our leading cause of CO2 emissions is transportation, so the possibility of extending 111D to electric transport and the possibility of expanding 111D to include methane leakage, fugitive emission of pipes that feed combined cycle units. But I'd put those two issues, electric transportation and methane leakage, as a distant second to the concern for the credit not given to nuclear.

What -- Ralph, do you have any sense of our A- if there's been any responsiveness at the state level to crediting nuclear and B- what kind of form would you like that to see and can we reasonably expect it to see -- to appear as?

I'd say that it's not much of an exaggeration to say that we are in lock step with the state on their perspectives on 111D. As you know, we have a very clean fleet. Nuclear is typically 55%, 57% of our yearly output (inaudible) 2%. But as to the details of how that would manifest itself, I'm not sure I want to get into that on this call. We can certainly talk more about this, hopefully, in Dallas, if you're at ETI.

But there's no space that I'm aware of, I'd hate to be absolutely definitive and say that there isn't any at all between us and the state's position. But I've been briefed on this a couple of times already and I think we're in lock step with the state, in terms of the issue.

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's isn't. Because as we've said many times, we thought ReGGIe was a good idea to serve as a template for national emissions trading program. (inaudible) and Congress to begin a national program. It doesn't seem wise for the state to diminish its economic competitiveness with respect to near by states in joining ReGGIe.

One other separate area. (inaudible - multiple speakers)

(laughter) Go ahead, Kit.

Last one. DR -- how do you expect that the play out? Obviously there are 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 know just what you and everyone else on the call knows about it. The court decisions were very comprehensive. Very deterministic, dispositive on the issue. I'm guessing, I'm inferring, that the recent stay is just out of a healthy degree of respect for FERC and the desire of the judicial branch to allow the executive branch to weigh its options. And not all a reflection that the courts decided what they previously ruled upon was any kind of backpedaling 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're going to adjust for that. That they are going to look for ways to allow DR to affect the demand curve. But I've 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 one responsibility, reliability. If they don't control the asset, I don't how much they're going to be of count on it. 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.

Great. Thanks.

Ashar Khan with Visium.

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? Remind us what the dates are on those things?

Sure, Ashar. So the auction is in February, I believe, and it is a three year forward. So it comes into service in 2018. I'm not sure what month exactly, but early or first half of 2018.

Penn East, we've been publicizing a target date of November of 2017. We have also been emphasizing that is a greenfield project. You can take those two emphases -- what's the plural of emphasis? (Laughter) And infer your own start up date for Penn East. It's a greenfield project and it will not be online before November of 2017. It wouldn't surprise me if it slips into 2018.

Okay. And, Ralph, is there any other transmission or any other projects 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 projects that are not in the CapEx plan. And they range from Bridgeport Harbour to Penn East. And I mentioned artificial island, which is about $250 million, in our resubmittal. I'm looking with a quizzical look at Kathleen and Caroline to see if we have publicly announced what we've put in the open window for PJM.

No.

We have not So there are other things we are working on right now. Nothing that is staggering or tilts the balance sheet. But we are always looking at ways to improve the system. And we will definitely have an update for you on that in a not very distant future, actually.

Okay. Thank you, sir.

Thank you. Next question.

Julien Dumoulin-Smith with UBS.

First off, good morning. Perhaps a 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, are there other asset types? Again, you've done a few solar projects. Are we thinking about a scaling up of spend in this business at all, just as the way to deploy dollars and your access balance sheet?

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 just 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 they're MPV positive. That there's near-term visibility to accretion.

The balance sheet gives us room to do both, in both businesses. There's no shortage of us trolling around looking for these opportunities. There is a long list of those we walked away 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. Caroline, you want (inaudible)?

Absolutely. And I think when we look at this kind of opportunities, as Ralph said, we are disciplined in looking at the MPV, using the right hurdle rates. I think the thing that makes us interested in considering Bridgeport, is you think about the capacity construct there and what they've put in place, giving a seven-year incentive. Which really helps us think through how to make that work for a new investment. So those kind of constructs that truly can confer something, really can encourage new investment, we think are very good

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 shift the BGS contracts that 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've received -- we 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 passed through. I believe there was a similar ruling on SREC issues a couple of years ago.

In general, I think the BPU has recognized that if they want to continue to have a fully competitive active BGS market, that things that are outside of the control of the BGS suppliers have to be adjusted on an as-grow basis. But they have not opined specifically on an incremental capacity auction change that could come out of the PJM's most recent concern asset performance.

But presumably that would be something you would be seeking?

Absolutely. Absolutely.

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 been yet to be worked out. But it would be safe to assume that they would be in the same vicinity as a what a regulated return would achieve, if the investment had delivered upon the promised operational performance. Right?

So don't think of this as having an effective ROE of 20% to 30%. And don't think of it as something that would be south of 10%. It's just, okay, if we think this light bulb is to do X and it does X, then alright that seemed to have been a prudent investment. But there's a slight increase in risk that's taken as a result in that kind of mechanism.

And just keep in mind as you are thinking about the modeling for Long Island, I know you know this, but just to reinforce, right, 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're making. So that's the base contract that's currently in force, something here would be additional.

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 --

Yes. The numbers we gave earlier, Julien, our original program of $200 million and 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.

Right. Okay. Thank you.

Next question.

Neil (inaudible) with Tudor Pickering.

Hi. Good morning. I had a question about the Penn East pipeline and the off take agreements. How does that benefit you? Is at the utility with lower gas prices for PSE&G? Or is it kind of lower gas prices to fuel your combined cycle plants?

Good morning, Neil. It's the same exact sequencing of uses as we have today. It's either 125,000 or 150,000 bcf a day (inaudible - multiple speakers). 125,000 bcf a day. So the priority customer would be the utility -- regulated distribution gas customer, they'd get first dibs at that. Second, would be off system sales. And then lastly would be power as used for burning in its plants.

What tends to happen under those three-tier prioritization, is that power really it 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% of the gas to power burns is from the (inaudible) region. It could go up on a (inaudible) basis from there.

Got it. Great, thank you. And then secondly, with the CCGT expansion in New England, could you just generally give your thoughts on the New England market? It's obviously gone very quickly from an oversupply to an under supply. And just wanted to get your thoughts on capacity and energy -- looking at that project.

So I think there's two things that are important in the New England market. Number one, is what you just mentioned, that it went to an under supply condition as assets announce and carry through on their retirement. But number two, is really what Caroline pointed out, which is the risk-reward profile has shifted to be a little bit saner when you're making an investment and you want to recover 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, and 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 site. We have both access to gas and we will build it for dual fuel.

Lastly, on the capacity market, in addition to the seven year construct, the change on the slope on demand curve allowing for return of sort of missing money that has plagued that region.

Okay, great. Perfect. Thank you.

Thank you, next question.

Dan Eggers with Credit Suisse.

Good morning, guys. Caroline, I hate to bring up of a numbers questions on the call but when I look at the fourth quarter guidance for Power, kind of filling in with the range what you guys have full year guidance at, 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 baseline perspective?

Of course. 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 first time as a full quarter -- last quarter it was just a month -- is capacity. Capacity on a quarter-over-quarter basis, just like you saw this quarter is a $0.09 impact.

So you have to start there. That's significant dollars. But of course, we knew that, right? We took that into our account in our guidance all through the year. That's the number one thing that I would suggest that you consider.

Of course, going the other direction, as you we expect favorability in the O&M, as I mentioned, so that's going to little bit in a positive direction. And then the normal unit operations. Keep in mind that 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.

If you think about the pushes and pulls you've got Salem 1, you've got Peach Bottom in the recent and 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 the positive direction, so full-year, we're guiding to about flat. You can pretty easily do the math.

We were worse in O&M in the first two orders, better in this quarter and anticipate better in the fourth quarter. And then of course, is just the normal operations and whatever the weather is at the beginning of the winter. So all in, we still expect to be at the upper end of the range. We peeled the bottom, but we 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.

Okay. So the $0.23 or whatever it is, you take out the $0.09 of capacity revenues, which would get you to kind of $0.14, which is above the implied range right now. So there's just some other maintenance issues that will bring you down from the high end. Is that the right way to think about it? (inaudible - multiple speakers)

That's right. Think about the outages I just mentioned, but still consider us -- we're talking about the high end of the range.

Okay. And then, can we talk a little bit on the gas basis side note, 25% of gas generation came from WTI. How does the benefit of the basis arbitrage look full-year or year-to-date, 2014 versus 2013?

Yes, sure. Year-to-date, not as strong as 2013. So let's wind back and remember what happened in 2013. We saw the WTI differential really appear in 2013 at the end of the second quarter. And that WTI differential became pretty wide as we got into the summer of 2013. Remember, we talked about differentials being as much as $2. And then, of course, there was that warm weather and the warm weather is what drove and kept that differential from the WTI price to the actual market price for the energy.

This summer was quite different with the cooler weather right on a WTI basis, depending on where you compared to last year or normal, 13% to 18% lower in terms of weather. It only makes sense if you cite THI.

What we actually have is lighted gas costs are still lower, the problem was for the summer with the lower demand and the cooler weather, the differential of WTI to thinking about where energy is priced in our market -- looking at Z-6 or [techo M3) that brought those prices down. So what happened was the differential really collapsed.

WTI was still cheaper than Henry Hub, but the differential moved together. As opposed to last summer which moved much more widely apart, because of the low demand for the power.

Now keep in mind as we think about WTI going forward, think about WIT for us, we had that access it's about 25% of Power's overall gas use, as Ralph just mentioned. And I think what we're still expecting to see -- and you can see it if you look at monthly data going forward -- is a choppiness to the pattern of how to think about basis.

Just like we've seen, actually now for the last two winters, the months make a difference. And so as we come into 2015, we still expect to see benefit from having WTI. It's really just about how that basis differential moves relative from power prices.

So the winter periods and strong summer periods, we would still expect to see some basis differential in our favor. This was just a tough summer because the low demand led to the lower power prices. Not because WTI prices came up, because power prices came down.

Last year, you may recall we had $0.03 from the WTI 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 Sparks Red going back to a normal level going versus that expanded spark we had, given the differential last summer

Thank you for that. I appreciate it

Sure. Next question

Paul Fremont with Jefferies.

Thank you very much. I guess my first question is at a proposed cost of about $600 million it works out to about 1330 per KW. How confident are you in your ability to build to that level? And I know that others in the region have experienced problems building in the Northeast.

Yes. Good morning, Paul. I think you are obviously quoting round numbers. The team is running through details right now, filing permit applications. 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. That one we have well in hand. We don't want to give you an exact amount on our what kind of bids we're getting from folks in terms of engines. It would just be too easy to back calculate what we might bid in an auction and that wouldn't help anyone.

And then, Caroline, just a follow-up on the last question. You, I think provided the quarter contribution as been zero this quarter, versus $0.03 in the third quarter last year. What would be the year-to-date numbers on WTI?

Year-to-date numbers in terms of the gas benefit -- we had about a $0.03 benefit in the first quarter. Remember it was a strong winter. So it's about neutral on a year-to-date basis. At zero.

And last year, year-to-date?

Last year when the WTI differential really started to spread it was end of the second quarter. So there really wasn't a sort of first quarter last year for 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 is about neutral.

Great. Based on the modified CTA formula that was adopted by the NJ BPU, what type of adjustment should we assume for the PSE&G rate base, if you were to use that methodology?

Yes. We are very pleased, obviously, with the decision. We think that reflects the right balance from the perspective of the Company and the ratepayers. Thinking about our rate filing, which would be made by November 2017 and then the five year look-back period -- the impact for us is de minimis.

So really not something you should really 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 de minimis.

And you back out transmission.

And you back out transmission, as well. Right.

Great. Thank you, very much

Sure. Next question.

Paul Patterson with Glenrock Associates.

Hi. Can you hear me?

Yes, Paul.

You have sort of in a unique position in New York. And I was just wondering with the stuff going on there, with the reg. sort of really transformative potential for change in regulation -- what you guys see as potentially happening to energy and power prices in the state?

New York State?

Well, you guys have (inaudible - multiple speakers) --

We don't have it fully. (laughter)

That's a very complicated question, right?

I apologize then. Just sort of directionally, maybe?

I think that a lot of the distributed resources that are being advocated are going to put upward pressure on prices for customers. There are other reasons for doing things like rooftop solar and offshore wind as being advocated just off of Long Island. And those are capturing some of the environmental benefits that are not baked in. And right now they're missing (inaudible), 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 inroads to capturing the benefits associated with the (inaudible). We're 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. You're getting a benefit and you're having to pay for it.

There are some things that we can do in terms of making sure that some of the reinforcements that would have to be made in a distribution system are foregone or delayed as a result of, perhaps, some peak shaving or some broader demand response programs that we can target.

There are some parts on Long Island -- I think it from the South Fork, that is been a significant growth in peak demand that would otherwise command a need for some infrastructure that we'll be able to delay.

But it really is a much more complicated question then simply gee, will doing this lower everyone's bills and lower everyone's rate. The answer really depends on what this is and how aggressive one wants to be on the sort of green agenda.

Okay. Fair enough. And then just -- 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 added 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-a-vis these issues now as it was in comparison to maybe when the MOPER and LCAP issue was going on?

Good questions, Paul. We've had a bit of a change at the BPU, with all due respect to the commissioners who have gone off. We have two new commissioners to our quite astute about both energy policy, in the form of President Morose and terms of the technology -- strengths, weakness, limitations, in the form of and former assemblyman, (inaudible). He's an [electrical] engineer by training and he has 20 years at Bell Labs. This is a very intelligent man who understands the complexity of capital intensive infrastructure. And Rick is a well known entity in policy circles in New Jersey. And has actually worked in the energy sphere in the past. So I think those are two strong additions to balance the BPU.

The world is very different now from what it was in LCAP. In the LCAP days you had strong basis differentials West to East. You had a coal dominated West and a gas dominated East. And people always scratching their heads saying we don't understand why we pay so much in New Jersey. Sadly, last month the basis was the other way. It was lower in West than it was in the East. Gas has kind of change that whole dynamic. I think as a result you'll see people realizing that the market is working. It's doing what it is supposed to do. And prices are going up for everybody, I believe, in this new RPM market as the missing money appropriately gets restored.

No one likes to pay high prices for energy. There are no if and or buts around that. No one likes to see the lights go out either and we came dangerously close in 2014 and a similar winter in 2015 and it probably would go out. I think PJM is doing the right thing in trying to address that. And New Jersey knows that PJM is doing a better job than just of any place in the country in making sure those lights stay on

Great. Thanks a lot

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 (inaudible).

Thanks, Kathleen. I just want to reinforce three messages or comments made by Caroline and me earlier. First of all, the utility growth story is very much intact. Not only is it doing what we said it would do this year, but our filing at FERC 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 gas prices are doing, whatever coal prices are doing, but also how strong a performer it is and how well-positioned it is, even as we look forward to the ever-changing environmental rules and market design parameters.

We have dual fuel capability, we have units that are strong in high capacity factors, all of them will have a great position in the CP market, if the risk-reward profile in the details as we go forward is done sensibly. And I have every reason to believe that PJM will do that sensibly. Growth story intact at 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 the days ahead and hopefully for most of us that means at ETI in Dallas. Thank you for your time today

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