公共服務電力與天然氣 (PEG) 2011 Q2 法說會逐字稿

Ladies and gentlemen, thank you for standing by. Welcome to the Public Service Enterprise Group's second-quarter 2011 earnings conference call and webcast. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session for members of the financial community. (Operator Instructions)

As a reminder, this conference is being recorded Wednesday, August 3, 2011, and will be available for a telephone replay beginning at 1 p.m. Eastern Standard Time August 3, 2011 until August 10, 2011. 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, Natalia. Good morning, everyone; we appreciate you participating in our call this morning. As you are aware, PSEG released second-quarter 2011 earnings statements earlier this morning. The release and attachments are posted on our website at www.PSEG.com under the Investors section of the website.

We also posted a series of slides that detail the operating results by company for the quarter.

Our 10-Q for the period ended June 30, 2011 is expected to be filed shortly; in fact, most likely by this evening. I'm not going to read the full disclaimer statement or the comments we have made on the difference between operating earnings and GAAP results. 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 required to do so. Our release also contains adjusted non-GAAP operating earnings.

Please refer to today's 10-K or other filings for a discussion of factors that may cause results to differ from management's projections, forecasts and expectations, and for a reconciliation of operating earnings to GAAP results.

I would now like to turn the call over to Ralph Izzo, Chairman, President and Chief Executive Officer of Public Service Enterprise Group. Joining 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. We do ask that you limit yourself to one question and one follow-up, and we hope to have time for all. Thank you. Ralph.

Thank you, Kathleen, and thank you, everyone, for joining us today. Earlier this morning, we reported operating earnings for the second quarter of 2011 of $0.59 per share compared with operating earnings of $0.63 per share earned in 2010's second quarter.

The results for the quarter bring operating earnings for the first half of 2011 to $1.44 per share compared with operating earnings of $1.50 per share earned in 2010's first half.

We have achieved significant operational and regulatory successes during the past quarter. Although our results are being affected by lower realized energy prices, we are seeing the benefits of increased levels of investment at PSE&G, as well as the benefits to cost control and reliability that come with the operational focus of a dedicated workforce.

Regulatory approval for several important initiatives should allow PSEG to maintain its position as a reliable supplier of low-cost, clean energy for the long-term. The Nuclear Regulatory Commission approved PSEG's nuclear request to extend the operating license of the Hope Creek generating station and both Salem units for an additional 20 years. The approval was granted less than two years after PSEG Nuclear filed its request with the NRC in August of 2009. This timely response speaks to the community support enjoyed by Power in Salem County, the preparedness of our work force and the material condition of the facilities. The license renewal of these generating stations means clean nuclear energy will be available for New Jersey for years to come.

The NRC has also released its assessment of the US nuclear industry in response to the events at Fukushima earlier this year. We believe the report, which finds the US plants are operated in a safe manner, to be objective. Bill Levis, President of PSEG Power, and his team have worked closely with the NRC, as well as with state and local officials, to keep them informed about the operations at Salem and Hope Creek.

Also this quarter, the New Jersey Board of Public Utilities approved $368 million of additional spending by PSE&G on critical electric and gas infrastructure programs, as well as energy efficiency. These investments provide the opportunity to expand jobs at a time when the improvement in the economy appears to have stalled.

Similarly, the Federal Energy Regulatory Commission granted approval for incentive rate treatment effective on June 14, 2011 for three of the five 230-kilovolt projects with a total investment of about $1 billion. The incentive rate treatment covers approximately 80% of our request.

A history of continuous engagement with our employees has supported the resolution of a labor contract with one of our larger unions that balances the needs of all parties. A focus on cost control helps us earn our returns and provides the opportunity for the growth implied by our investment program.

We've been saying for some time that the future marketplace for energy will be influenced by environmental regulations. We are starting to see the forward market for energy beginning to reflect the impact of EPA proposals. Without an increase in price, it won't be economic to maintain the operation of older coal-fired facilities. Our investment in environmental upgrades at our coal stations supports their operation under the more stringent rules proposed by the EPA. The recognition of a similar level of cost by other suppliers in the region will help to levelize the cost of supply between Connecticut, New Jersey and surrounding states.

PSEG Power closed on the sale of the Odessa gas-fired generating plant in July for $335 million. The closing of the Odessa sale completed the Texas asset sale process announced by Power earlier this year under which Power receives a total of $687 million, which includes the sale of Guadalupe as well. We will use the proceeds from these asset sales and an already strong balance sheet to finance an expansion of our capital program, while still preserving substantial financial flexibility.

PSEG's capital investment program for 2011 through 2013 is now $6.9 billion compared to our prior forecast of capital spending over this period of $6.7 billion. As part of this revised forecast, PSE&G is now expected to invest $5.2 billion over this period, an increase of 15% from prior levels, or the potential for growth in rate base of 11% to 12% per year.

We are also evaluating the potential for increased investment under the State of New Jersey's energy master plan. This could entail increased investment in our gas distribution system for enhanced reliability, as well as the expansion of our investment in solar, depending upon the state's evaluation of the ability to meet its renewables promise at the least cost. And this growth, both planned and potential capital spending, can be financed without the need to access the equity markets.

We start 2011 with good results. The energy markets have been stronger than expected. We are, however, maintaining our forecast of operating earnings for 2011 of $2.50 to $2.75 per share. The expected decline in contracted energy and capacity prices from year-ago levels that were effective on June 1 will continue to have an impact on our full-year operating earnings.

Over the long-term, a strong balance sheet and asset mix well-positioned to meet environmental regulations, a longer life for our nuclear facilities, an expanded capital program in areas that should provide the opportunity for good risk-adjusted growth and a focus on cost control should support our long-term objectives for top quartile shareholder returns.

And now Caroline will review our operating results in more detail.

Thank you, Ralph, and good morning, everyone. I will review our quarterly operating earnings, as well as the outlook for full-year operating results by subsidiary company. As Ralph said, PSEG reported operating earnings for the second quarter of 2011 of $0.59 per share versus operating earnings of $0.63 per share in last year's second quarter.

Slides 4 and 5 provide a reconciliation of operating income to income from continuing operations and net income for the quarter and the year to date. We have provided you with a waterfall chart on slide 11 that takes you through the net changes in quarter-over-quarter operating earnings by major business, and a similar chart on slide 13 that provides you with the changes in operating earnings by each business on a year-to-date basis.

So I will now review each company in more detail, starting with Power. As shown on slide 15, PSEG Power reported operating earnings for the second quarter of $0.36 per share compared with $0.45 per share a year ago. Power's second-quarter earnings were affected by a quarter-over-quarter decline in realized energy and capacity prices. A decline in capacity prices to $110 per megawatt day from $174 per megawatt day on June 1 of this year reduced Power's earnings by $0.02 per share.

The decline in energy prices under the most recent BGS contract to $94.30 per megawatt hour from $111.50 per megawatt hour, which was also effective on June 1, as well as the impact of other hedges, reduced earnings by $0.03 per share.

A 6% decline in volume in comparison to abnormally warm conditions during the year-ago period reduced earnings by $0.02 per share. An increase in customer migration from the BGS contract reduced earnings by $0.01 per share.

As we've said in the first quarter as well, higher depreciation expense, coupled with a decline in capitalized interest associated with the commercial operation of the backend technology at Hudson and Mercer, would have an impact on Power's earnings, and in the second quarter, these items reduced Power's earnings by $0.02 per share. An increase in O&M expense on the fossil stations reduced earnings by $0.01 a share.

The absence of trading-related losses experienced in the year-ago quarter and other miscellaneous items improved Power's earnings by $0.02 per share.

I would now like to go into a little more detail on the change in output and price experienced in the markets served by Power's generating fleet.

As I mentioned, total output declined by 6% in the quarter. This decline is partly the result of the more normal weather in June of this year compared with abnormally warm weather in the year-ago quarter. Coal-fired output declined 15% in the quarter. Our combined cycle units were also affected by the decline in weather-related demand, and experienced a 5% decline in output during the quarter from relatively high levels last year.

The nuclear fleet experienced a 2% decline in output. Power's nuclear fleet operated at an average capacity factor of 90.3% during the second quarter compared to an average capacity factor of 92.6% in the year-ago quarter.

Power's PJM-based assets, which provide 92% of the output generated in the quarter, experienced a 3% decline in output. The quarter-over-quarter reduction in output was mainly the result of a decline in output from our New Jersey-based coal stations, as output from the PJM-based combined cycle units actually increased by about 3%.

Although our results have been hurt by a decline in realized prices for hedged capacity and energy in the quarter, market prices have improved with an expansion in heat rates. And as I'll mention later in more detail, we are poised to take advantage of that.

Importantly, this improvement in market prices has also reduced the impact of migration on Power's earnings. Approximately 33% of BGS-related volume had migrated to third-party suppliers by the end of June compared with 31% at the end of the first quarter. This level of customer migration was slightly less than our forecast and a continuation of the pattern witnessed in the first quarter. So we are, as a result, reducing our full-year estimate of average customer migration to 34% from the prior 35%. This estimate assumes between 37% and 39% of customer load will have migrated from BGS by the end of that year.

Most importantly, however, headroom has declined during the quarter versus year-ago levels and our expectations. The continuation of these trends would result in headroom for the full year at levels experienced in 2010. Remember that abnormal conditions experienced in the second half of 2010 caused headroom to completely collapse two months of that second-half period.

The improved environment for pricing over the short term is partly the result of very warm weather conditions. As many of you may be aware, Newark hit a high of 108 degrees on July 22, and experienced a week-long period of sustained hot and humid weather. And of course, you will see these results as part of our third-quarter earnings.

Prices in the forward market also appear to anticipate the impact of new EPA rules governing the emission of sulfur and nitrous oxides. EPA's cross-state air pollution rules, often called CSAPR, which are the replacement for the Clean Air Transport Rule, proposes a greater reduction in SO2 and NOx for our New Jersey facilities than under the preliminary draft of the rule. The rule also exempts Connecticut and allow some trading of emission credits among the states subject to CSAPR, specifically among all the CSAPR states for NOx and among the 16 Group 1 states for SO2. New Jersey is part of that group of 16 Group 1 states.

Given the capital investments made by Power over the past five years in equipment to reduce the omission of sulfur and nitrous oxides, Power is in a good position in New Jersey and Pennsylvania to meet the requirements of CSAPR.

Let me move now briefly to our hedge position. On slide 20, we provide you with an update of Power's hedge position. For the balance of 2011, Power's baseload output is fully hedged at an average price of $68 per megawatt hour. With 30% to 35% of our intermediate load hedged, approximately 70% to 75% of total expected generation for that period is hedged at an average price of $68 per megawatt hour. Power's assets, by staying partially long in the summer as a result, are well-positioned to capture the improvement in margin from current pricing, as well as over the long term, as we typically hedge with this type of strategy.

For 2012, hedges are in place for approximately 75% to 80% of expected baseload generation of 36 terawatt hours at an average price of $64 per megawatt hour. This equates to approximately 45% to 50% of expected total 2012 generation of 56 terawatt hours hedged at an average price of $64 per megawatt hour.

For 2013, approximately 35% to 40% of anticipated baseload output is hedged at an average price of $63 per megawatt hour, again, equating to a hedges on approximately 20% to 25% of estimated total generation of 56 to 58 terawatt hours at the average price of $63 per megawatt hour.

Our total hedge position for 2012 and '13 is slightly higher than our prior positions, if you are comparing it to first quarter. The prior positions were about 40% to 50% of total generation for 2012 hedged at $66 per megawatt hour, and 10% to 20% of 2013's total generation hedged at $69 per megawatt hour.

We are maintaining our forecast of Power's 2011 operating earnings at $765 million to $855 million. Although wholesale market prices have been stronger than forecast, Power's earnings during the remainder of the year will be influenced by a decline in contracted energy and capacity prices with the implementations of the new BGS and RPM capacity contracts at prices lower than year-ago levels.

Power's operating earnings in the second half of 2010 also benefited from those extreme weather conditions which supported output. While we have seen some of that in July, it is too early to forecast anything other than normal weather for the rest of the year.

Power's results during the remainder of 2011 will also continue to reflect the increase in depreciation expense that we have noted in the first and second quarters of the year.

Let's now turn to PSE&G. PSE&G reported operating earnings for the second quarter of 2011 of $0.21 per share compared with $0.15 per share for the second quarter of 2010, as you see on slide 23. PSE&G's results were driven by rate relief and improved returns on higher levels of capital investments. An increase in electric and gas rates that went into effect on June 7 and July 9 of 2010, respectively, improved earnings by $0.01 a share. An annualized increase in transmission revenue of $45 million, effective on January 1 of 2011, added $0.01 per share to results. And a return on investments made under capital adjustment clauses, supporting our investments in renewables and energy and gas infrastructure programs, added $0.02 per share to earnings.

Quarter-over-quarter earnings comparisons were also aided by weather in the heating season and by the implementation as part of the rate case settlement of the gas weather normalization clause. In the second quarter's heating season, it was cooler than last year but still warmer than normal. So this outcome added $0.02 per share to earnings.

Lower volumes quarter over quarter reduced earnings by $0.01 per share, and a reduction in operating and maintenance expense as a result of a decline in pension costs and the absence of a write-off that occurred in the second quarter of 2010 combined add $0.03 per share to earnings from O&M.

An increase in depreciation expense as a result of an increase in capital spending reduced earnings by $0.01 per share. Other miscellaneous items combined to reduce earnings by $0.01 per share.

As Ralph mentioned, PSE&G received important regulatory support for its investment programs. FERC granted approval for incentive rate treatment effective on June 14 of this year for three of the five 230-KB projects, with a total investment of about $1 billion. The incentive rate treatment covers 80% of our request and provides for recovery of construction work in progress and 100% recovery of prudently incurred abandonment costs. These projects are authorized to earn a return on equity of 11.68% under formula rates.

In addition, the New Jersey Board of Public Utilities recently approved an increase in PSE&G spending on energy efficiency programs and electric and gas infrastructure of about $368 million. The BPU order also requires an additional $96 million of base capital spending on electric and gas distribution. So PSE&G, as a result of the support of regulatory treatment, as well as an update of forecast spending on transmission, has increased its capital spending for the period 2011 through 2013 to $5.2 billion from the previous estimate of $4.6 billion.

The revised capital program will provide the opportunity for annual rate base growth, as Ralph mentioned, of 11% to 12% from the year-end 2010 period through the end of 2013.

PSE&G's investment in transmission represents more than 50% of the proposed capital spending program over this period. We are maintaining our forecast for PSE&G's 2011 operating earnings of $495 million to $520 million. PSE&G is expected to earn its authorized return on equity in both the distribution and transmission businesses. The return is the result of a full year of electric and gas rate relief granted in 2010, as well as increased transmission revenue.

Our forecast of operating earnings for the full year assumes PSE&G is able to maintain its returns, given a control of its expenses, as well as increased levels of capital investment.

Now let me turn to PSEG Energy Holdings. Holdings reported operating earnings of $0.01 per share for the second quarter of 2011 versus operating earnings of $0.02 per share during the second quarter of 2010. The decline in operating earnings for the quarter reflects the absence of tax benefits recognized in the second quarter of 2010 associated with the startup of solar projects in Ohio and Florida.

We're maintaining our full-year estimate of operating earnings for Holdings at zero to $5 million. Holdings remains focused on investing in renewable projects that provide a reasonable return and scaling back its investments in non-core areas.

Holdings currently has approximately $115 million invested in three solar projects with a capacity of 29 megawatts that meet our financial and operational goals. Our assessment is that it's difficult in the current market to find projects that meet our threshold for adequate returns, and Holdings is therefore scaling back its planned level of capital spending over the 2011 to 2013 period to $40 million from $570 million.

I'd also like to provide you with an update on one leveraged lease investment within a portfolio of assets held by PSEG Energy Resources, which is a subsidiary of Holdings. Roseton LLC and Danskammer LLC, indirect subsidiaries of PSEG, are the owner/lessors of the Roseton and Danskammer electric generating facilities, which are leased to indirect subsidiaries of Dynegy and Dynegy Holdings, Inc. or DHI.

DHI has guaranteed the payment obligation of the lessees to these PSEG entities. As a result of DHI's proposed transfer of substantially all of its coal and natural gas-fired generation assets, other than the Roseton and Danskammer facilities, to new, quote, bankruptcy remote subsidiaries, the PSEG entities filed suit against DHI in the Delaware Court of Chancery to halt DHI's proposed transfer and protect our rights under the DHI guarantees.

The PSEG entities request for a temporary restraining order was denied on Friday, July 29, and we have since sought review with the Delaware Supreme Court. As of June 30, 2011, the PSEG entities had a gross investment in these leases of $264 million. A foreclosure event could result in an after-tax charge between $170 million and $180 million. As part of this potential foreclosure event, PSEG could be required to pay approximately $100 million to satisfy income tax obligations. This potential cash tax obligation is fully reflected in the overall estimate of the aggregate after-tax charge that I just mentioned.

Please keep in mind that the numbers that I'm giving you here are worst-case scenario, and it is not a forecast of the outcome, as we continue to pursue our rights in this matter.

Please also note, however, that given its active litigation status, we won't be able to answer any questions related to the Dynegy matter in the Q&A.

Finally, let me just briefly mention what is happening on the financing side. PSEG ended the second quarter with $159 million in cash. As a reminder, PSEG Power retired $606 million of maturing 7.75% senior notes in April, using our cash on hand. And of course, cash at quarter-end doesn't reflect the receipt of the proceeds from the sale of Odessa, which occurred in July.

Also in April, PSEG, PSE&G and Power each entered into five-year credit facilities totaling $2.1 billion in credit capacity. The Company's total credit capacity is now $4.3 billion, an increase of $650 million since year-end. And of this amount, approximately $3.7 billion was available at the end of June.

Power's and PSE&G's operating cash flows have improved in 2011, primarily due to a decline in tax payments related to the benefits of bonus tax depreciation, which we have spoken about before.

The improvement in operating cash flow and the proceeds from asset sales have supported our financial strength. At the end of June, debt represented 42% of PSEG's capitalization and 35% of Power's capitalization, providing the Corporation with significant financial flexibility to meet the planned expansion in capital spending.

So overall, we are very pleased with the quarter and maintain our operating earnings guidance of $2.50 to $2.75 for 2011.

Beyond being pleased with the quarter, we're also pleased with the operational progress that we believe positions us for future financial success. Specifically, the nuclear license extensions; the success of our environmental program, which positions us to benefit from the upcoming regulations; the continued success of our cost management efforts; and the future opportunity to make significant regulated investments which support reliability for our customers, and can be accomplished with a balance sheet that supports a good return to our shareholders.

As power markets appear to improve, we can take advantage of that, while delivering at the same time a growing utility.

With that, we are now ready to take your questions. So, Natalia, I will turn it back over to you to introduce the Q&A.

(Operator Instructions) Dan Eggers, Credit Suisse.

Hey, good morning, guys.

Good morning, Dan.

I was wondering if you could just shed a little more light maybe on kind of what's been going on in New Jersey with the reviews under the Commission on the need for new generation resource on a long-run planning basis, and kind of what your input has been, where you see that process playing through.

And then, kind of given all that happened with LCAPP this year, are there mechanisms the state has available that if they wanted to force through new generation outside of the RPM process that you see their ability to do that?

Dan, I think there has been an announced schedule. I don't have specific dates. I believe there is another hearing expected in September.

But what is planned is that by the end of the year, the state would like to reach some kind of conclusion as to whether or not additional capacity is needed and how it can be secured in a least-cost manner.

I think a big question in the state's mind is what happens to the HEDD units that are under some ground-level ozone challenges in the 2015 timeframe. And in particular, a concern about the PS North zone, which fairly consistently prices higher in RPM than other areas.

The approach we are taking is that the sensible way to introduce new capacity into the region is by improving the efficiency of markets by making it more transparent and by reducing the risk of investors. And our advocacy has been to make some changes to the RPM process that are pretty straightforward, linking up the timeframe for RPM with the RTEP process, allowing a mechanism whereby people can get multiyear pricing as opposed to a one-year price three years out, clarifying the interconnection process so that say that there is a little greater certainty for investors who are proposing new generation plants, so they are not wondering what their interconnection costs will be.

All of those things derisk new investment, and therefore, I believe are a win for both the investor and the customer.

And it's quite contrary to the approach the state took in the LCAPP process, which exacerbated the risk for investors, because you didn't know as an incumbent whether or not somebody was going to intervene in markets. And I think that that approach is going to have a chilling effect on new investments until we come to some agreement on what the rules will be.

So I think that there is a legitimate concern on the part of the state about future supply and a genuine effort on their part to see how to incent that new supply, and in an intelligent dialogue going on among all players about how to do that in a way that is fair to existing investors and future investors. And that will play itself out over the next six months or so.

But we are very active participants in that discussion, and, as is always the case, look to do what is best for our customers as well as our investors.

Now, do you -- you have kind of given that government moves in one direction and they tend to get focused on one direction, unfortunately. When you think about kind of a revision of the PJM planning process and the time horizon to meet resource needs relative to the plant closures at the end of '15, can a solution be found in a timely fashion that meets the goals of where the state is headed? Or is there going to be -- is this going to become a more difficult process as the year moves on?

Well, I think you're going to have a couple processes in parallel that I am optimistic will converge. I mean, PJM recognizing that it has, next May, another base residual auction coming up, it seems to me to be quite committed to a stakeholder process resulting in whatever modifications are needed to RPM sometime late this fall; I would say more of an October time frame.

The question then will be whether or not, as in any stakeholder process, the stakeholders who don't get everything they want are satisfied with that. And clearly a principal stakeholder in that process is the one we have talked about, namely, New Jersey.

I'm encouraged by the fact that in this multi-participant dialogue, which, by the way, FERC is an important constituency of, there appears to be a recognition that a lot of good stuff has come from the market. One of the things we didn't talk about in our prepared remarks is that in some pretty significant heat, we have not set all-time peaks. That is probably coming from the fact that DSM has been brought to the market and on much lower cost than new generation.

So you are seeing RPM, which is a nondiscriminatory method for bringing in all solutions on both the supply and the demand side, really having quite a powerful effect from a consumer point of view. And we like that approach, because, quite candidly, we are immodest enough to think that we are very strong competitors. And what we don't like is interventions in that that favor people who are not strong competitors.

So I do think that there are several processes going on under way at the same time. There is the PJM stakeholder process and there is the BPU process. And I would like to believe, and I do believe, that those processes will converge if we allow them to play out in a rational way.

I'm sorry. Just one last question, Ralph. But just on the peakers that are scheduled to close at '15, is there a potential -- real potential that that closure date can get extended for some period of time? Is there a process going on right now? Or is that realistically -- those are going to be done at the end of '15?

Yes, so there is a discussion underway right now with the Environmental Protection Agency. I mean, this is a classic example, Dan, of cost benefit. I'm not going to stand here and say that those peakers are the cleanest units in the fleet, and that there aren't new capacity that doesn't have the potential to be cleaner.

Clearly, those are 40-year-old FT4 units that are not the pride and joy of a Company that talks about its environmental friendliness. On the other hand, they are a hell of a lot cheaper insurance policy than building new peakers, or being replaced by combined cycle units, which would have a grossly underutilized capacity factor.

So the real question becomes, do you want to get a little bit more benefit out of the costs promised by those units for a couple of years in an economy that is really limping along, or do you want to be more aggressive on your environmental impact and retire them in '15? And that is the discussion we are having with all the relevant parties.

Okay, thank you.

Paul Fremont, Jefferies.

Thank you. I guess my first question is the lower coal volumes that we're seeing in Connecticut, is that -- should we assume that is going to continue going forward? And why such a steep drop-off in output levels in Connecticut?

Hi, Paul. Thanks for your question. Keep in mind, one of the things that you always have to look at on the year over year is the weather impact, right. So we had a significant weather impact in the business on a year-over-year basis in the second quarter. June was very warm last year. And in fact, if you look at our generation output, it was much higher than normal last year. So when you compare last year to this year, with normal weather versus very, very hot weather, you have that reduction that you would expect to see.

It is a little tricky, right, Paul, because we've had a warmer than normal June this year, but compared to the extremely warmer than normal June last year and when we do the year-over-year comparison, that output is down.

And when I look at utility O&M levels and the reduction in the second quarter, I mean are we going to see similar reductions in the second half of the year that you experienced in this quarter?

Right. So you remember that the utility post the rate case started some significant management as it always has, but with renewed vigor on O&M management. But two things keep in mind; so this year versus last year, we recently announced some changes to our pension program and that has a significant benefit to the utility. You would expect to see that continue, and we just announced that in this quarter.

But also keep in mind last year went we settled the rate case, one of the things that we did was we took a writeoff for some costs for our new customer system in the second quarter specifically that had a negative impact to O&M in the second quarter of 2010. So when you compare that quarter over quarter, we look more favorable now because we took a hit in the second quarter and it was $0.02.

So you will continue to see the utility's O&M management. You will continue to see good compares, O&M on a year-on-year basis. But you won't see replicated the kind of quarter over quarter because of that one-time effect that resulted from the rate case settlement.

And last question would be, I mean if one of the New Jersey plants were to succeed in next year's auction, can you give me a sense of what that would do to your pricing expectations in the auction?

Well, if one of that -- the answer to that, Paul, is no, because we don't reject the future auction. But it is pretty safe to say, however, if one of those plants succeeded, that would mean that capacity prices would have to be equal to or greater than 0.9 times MOPR. Because you can rest assured that everyone in those plants will be bidding the minimum price they could possibly bid, which will be a number that PJM will publish in January.

Any thoughts in terms of directionally in terms of MOPR next year versus this year? Would it be roughly the same, slightly higher?

So, what you have to ask yourself is what is happening to energy prices in '11 -- and we still have an important month to go -- versus what were energy prices doing in '08. And in '08, while we didn't have this kind of weather, we did have a fairly high gas price. And so '08 will be dropping off and '11 will be picking up. And then CONE will be updated, and typically that does tick up a modest amount. So those are the factors you have to factor in.

Thank you.

Paul Patterson, Glenrock Associates.

Good morning. On slide 25, the weather versus normal, I was wondering -- I'm sorry if I missed it -- but is there any quantification as to what weather year-to-date versus normal was in terms of a bottom-line impact? I sort of see where the utility is, but sort of -- it's a little more complicated maybe on the generation side.

Oh, on the generation side? Yes, so it is a penny for weather on the generation side of the business. And keep in mind, Paul, as we talk about weather, in each of our businesses, we have two different things going on, right.

So in the weather for the Utility, we're often very focused on the gas business, because the gas business supports the heating season and that is a big contributor from a weather perspective to PSE&G. And so that is the gas discussion that I commented on earlier in my remarks, of a $0.02 impact from the weather.

For PSEG Power, we're typically talking about the electric side and the air-conditioning season, right. So even in this quarter, I am effectively talking about both, right -- I am having an impact for the air-conditioning season in June not being as robust as last year's June; and then for PSE&G, I'm talking about the heating season at the beginning of the second quarter.

So if you look at the overall for the businesses, if you look at our waterfall on page 11, you can see that for PSEG Power for the quarter, it is a $0.02 negative in total for volume and weather. And then if you look at PSE&G for volume and weather, you have a positive one penny. And, you know, weather desegregation from volume can be a little bit tricky. So if you think about that together, you've got a little bit of positive for the gas business in PSE&G.

Right. I guess what I am thinking is -- I am wondering versus normal.

Oh, so -- well, for Power, weather this year was closer to normal, particularly in the second quarter closer to normal. And as I mentioned relative to PSE&G, it was cooler than last year, but still a little warmer than normal for the heating season. So it is normal on -- [seems] on the electric side relative to air-conditioning, if you will, for this quarter. And still a little warmer than normal, so that is one of the negatives on the heating season side for PSE&G.

So the generation wasn't impacted by weather that much?

The generation was impacted by weather and volume to the extent of about $0.02 for the quarter.

For the quarter versus the other quarter. But I guess versus normal, I'm just looking at this -- it didn't have a big impact versus normal.

No, not a big impact versus normal. Remember, when we do quarter over quarter, the compare to last year's second quarter was an extraordinarily warm quarter, and therefore a lots of weather-based air-conditioning utilization.

Okay. And then just finally, we've got more clarity on the EPA; obviously, on your CapEx program. And we have a pretty accommodating debt market, it seems. Is there any thought about maybe changing the debt-equity mix going forward? Or what are your thoughts when you look at the future here and your strong balance sheet and what have you and opportunities that might be there?

I think, Paul, we are still marching to the same tune in terms of wanting to preserve FFO to debt ratios at Power in the mid-30s, and preserving the Utility capital structure as per the regulatory agreements. And clearly, we are stronger than those measures right now at Power, but we do think we have some opportunities for further investment; we talked about some of them on the call today. We are looking forward to the six-month discussion on finalizing the energy master plan and what that might mean. And we are looking forward to further clarification on some of the EPA rules and what that could mean for transmission enhancements going forward to preserve liabilities when units come out.

So we are not, at this point, interested in changing the capital structure of the business or how we run it. But we do think that the $670 million increase in PSE&G investments from the last time we spoke may hold the opportunity for further revisits as E&P plays out. Caroline, if you wanted to add anything to that.

Yes, I would just add having the financial flexibility on the balance sheet gives us the opportunity to consider all this, of course, without issuing equity. And when you look at the increases in the capital expenditures for PSE&G, as Ralph mentioned, the $670 million, from what we last discussed, keep in mind that although transmission is the significant portion -- the single biggest portion of the three items there -- as we've talked about a lot of our transmission capital expenditures, as we talk about programs like Susquehanna Roseland and the Northeast grid, outside the 2013 period, if you looked at our total CapEx, [why] those particular projects, we've still got slightly in excess of $900 million in completion of those projects, particularly Susquehanna Roseland and the Northeast grid, that are outside the forecast we've given you through 2013. So there is a lot of money that we expect to be putting to work in the Utility, and our balance sheet supports our ability to do that. Not just what we forecast through '13, but that additional amount that goes from completing these important reliability projects that we have been talking about for quite a while.

Okay, great. Thanks a lot.

Jonathan Arnold, Deutsche Bank.

Hi, good morning. Just a quick clarification. What does your CapEx forecast assume for the timing of specifically Susquehanna Roseland?

Oh, sure. For Susquehanna Roseland, we're basically still on the same timing that we have talked about before. And that is the eastern portion done by mid-'14, and the western portion, meaning the part with the transfer capacity from Susquehanna, done by mid-'15. And based on discussions that have been underway at various forums, including with the federal government, we are still keeping with that timeline.

And is that commensurate with sort of a decision being pushed into early '13, which is what I think your last disclosure was?

No, we talked about the fact that we had just gotten notified last quarter when we were on the call relative to reconsideration. But we are still working on the expected timeline of a decision by the Parks Department relative to the route by October of 2012, which we still think is a fair way to think about how that program will roll out.

So if that doesn't occur -- if there is further slippage, that would affect the dates you just -- we just talked about?

It could. Always, slippage could affect the dates. But at this point, we don't have any information that suggests to us that we need to change the expected dates at this point.

Okay. Then could I just -- on the capital discussions that you were just having, it seems like you have kind of dialed back a decent amount of spending that was going to have happened at Holdings. And then most of the additional is going into the Utility, which I imagine would be kind of primarily financed at the Utility level.

Just what is the -- the incremental kind of reason for, I guess, holding back within -- is there more spending you see potentially out of some of the things you talked about at Power or outside of PSE&G? Or is it using the flexibility to bolster the Utility? I'm just kind of not fully clear.

No, no, that is a good question, Jonathan. So the way we think of it is, we look at the opportunities. And one of the things that we always talk about is the discipline in investment strategy and maturing, that we can put our capital to work at good risk-adjusted returns for our shareholders.

So when we look at the three businesses, we look at the opportunities we see in each of those businesses. So for Power, we have not adjusted the forecast because the significant CapEx for EPA-related or environmental is basically completed, as you know. The things that are still in for Power's capital spending are things like the peakers that we have bid and cleared in previous capacity auctions, and things like the nuclear-operated Peach Bottom, which we still forecast, which you know has a good return for us.

When we look at PSE&G, we increased this capital spending because of the opportunities we saw to put money to work at a good risk-adjusted return, whether it is formula rate for transmission or incremental spending that was authorized by the BPU that enhances customer reliability.

When we look at Holdings, it is not a matter of saying that because we had the opportunity to increase PSE&G that we had to decrease Holdings. Because as we just talked about on the last question, our balance sheet gives us the strength to really pursue those areas across our businesses that have good returns.

What we are saying at this point is in the Holdings business, some of the returns that we see some of these solar projects clearing at are not the kinds of returns that we think make sense from a shareholder perspective on a risk-adjusted basis.

So it is not about we have to reduce one to increase the other, because we have the balance sheet to pursue these three businesses robustly. It is really about where are the opportunities and where might the opportunities appear to be at this point less robust.

I just want to add one thought to your comment about the Utility financing. Keep in mind, of course, that when we talk about these Utility capital expenditures, you should always assume in your model that the financing of them is consistent with the Utility's capital structure; i.e., an equity ratio of 51.2, which means that you've got about half of the spend being financed by debt and the other half is financed by the Company overall.

So what that effectively means is the utility gets to keep its earnings and cash flow to reinvest in its business, because Power is generating cash flow in excess of its needs, and that cash flow supports our ability to support the shareholder dividend and to make other investments in the business.

So each business keeps an appropriate capital structure. It is opportunistic across all three, based on opportunities. It's not a bad place to be when you have a balance sheet that allow you to say you can increase one without having to take down the other, but just pursue opportunities across your businesses wherever you find them.

Is it fair to say that that Utility plan you have now is self-financing, as in the equity is coming out of retained earnings, and the debt you will finance in the market?

No, so we finance the debt in the market to keep that capital structure, right. And then the Utility generates cash flow, keeps its cash flow, and we put money in or take money out, just depending on how the spend rolls out over time, to enable to keep that capital structure.

So I think the way I would suggest you think about it is Power has the excess cash flow that supports the shareholder dividend and putting money into the other businesses as need be. And the Utility grows its debt consistent with its capital structure, and keeps its cash flow. And then we balance whether there is net money moving up or down from the Utility, based on the progression of the capital expenditures and based on the cash flow.

Based off this next three-year forecast that you have before us now, is the Utility consuming some cash or is it actually still self-financing?

On this period that we are talking about here, Utility is a net cash consumer to some extent. But remember, one of the other things that is positive for both of our businesses over this period is bonus depreciation. So don't forget, as you think about the forecasts that we have given before -- and we have given that stacked bar chart for cash flow -- both of our businesses, both Power and the Utility, significantly benefit from bonus depreciation. And you may recall that we talked about its impact over this period, actually out through 2013, to be a net impact in both businesses net of $800 million. About $900 million this year and next, offset by about $100 million going the other way as, if you will, the tax depreciation unwinds versus normal.

And that benefit was a little more than half to the Utility and a little less than half to Power. So versus what you would normally think of when you put capital to work, the cash flow benefits from the tax depreciation make that a higher number than your models might otherwise normally assume.

But, Jonathan, just to be sure -- Caroline has already said it a couple of times -- PSEG is self-financing.

I thought she just said it wasn't.

PSEG, the parent.

The parent.

Oh, the parent, excuse me, yes --.

Versus PSE&G.

Right.

And within the competitive businesses, for want of a better term, should we think that you have dry powder currently within the plan that you could deploy without incremental equity needs, that you are holding back for things we don't yet know about? Or how should we think about that?

So, the first part of your question, in terms of dry powder, the answer is yes. Those kinds of debt to cap ratios that I mentioned in my prepared remarks of 42% for the Company and about 35% for Power, right, in terms of debt-to-cap, give us FFO ratios for Power, for example, that are well in excess of what we need as a floor for our solid BBB rating. So we have dry powder that we can put incremental financing in Power, but it is not to do things that we're holding back or not telling you about.

When we see good opportunities that provide good returns, I think the real bottom line to that is we have the balance sheet that, if we see those, we can go get them. And we can go get opportunities if we see them in Power and Holding without putting anything at risk on the ability to execute the PSE&G plan.

Okay, thanks a lot. Sorry for so many questions on that.

No, that's fine. Thank you.

Gregg Orrill, Barclays Capital.

Thanks very much. Just wanted to follow up on capacity rules. There was the FERC Technical Conference last week -- technical conference at FERC about PJM. And one of the things that PJM brought up was a five- to nine-year timeline for new capacity in the auction. Where do you see that consensus developing in the discussion right now?

Well, Greg, that is an impossible question to answer. I don't think there is a consensus right now, except to say that most folks realize that a 40-year asset life with a one-year price signal, we could do better than that.

So whether it is going to be three or five or seven -- it is not going to be nine or 15. But my prediction -- and it is just that -- maybe I do want Kathleen to read the disclaimer statement now -- is that it will be something greater than one, in the three- to five-year timeframe is just an educated guess.

Okay. And then maybe just touching on the head rules, again. Is there any way to know or what is your view maybe on how much of that capacity has been taken in PJM auctions, such that if the rules did come down 2015, how would that have a financial impact?

It has been pretty much all of it, so you could think of it as about 2000 megawatts or thereabouts. So that has cleared in prior auctions.

Okay, thank you.

And keep in mind, we are replacing that with our peakers; 270 megawatts of that is being replaced by the peakers that we previously bid and cleared that goes against that 2100.

Right.

Andy Leavy, Karras & Company.

Just as far as M&A -- what I mean by M&A, just more just looking at your Power assets, are you looking to add any Power assets, whether it is in your region or outside? I mean obviously, I know you just got rid of the Texas assets. But what are your thoughts there on just keeping what you've got, changing around what you got, adding to what you got?

Sure, Andy, so relative to Texas, you are right, we did just completed the Odessa transaction. And so that completes the sale of both of our assets, both Odessa and Guadalupe in the first quarter and the third quarter. And we are pleased with those results, as I am sure you know.

We are always looking for asset opportunities, focused more if you will on our core market, so PJM, New York, New England. And as we just talked about in the last -- two questions ago, we certainly have the balance sheet to do that.

What we look at are obviously those assets where we can see the opportunity for a positive NPV when we look at the long-term cash flow. So what that means is either assets where we see that opportunity just by doing the modeling, using forward curve assumptions, or assets where we see opportunities that we can perhaps bring some of the operational excellence focus that we have at Power to either run those units better or put them in the market through our hedging capabilities better. So we see our way clear to that money can be put to work at a positive NPV.

So we left Texas because it wasn't core market, but also because as we were looking at other assets in that market, we saw clearing prices that seemed to be much higher than we would ever want to spend to buy. And after you see that enough times, you ask yourself whether it makes sense to sell, given the value that might be there. So we are pleased with that result.

But that should be not be interpreted as we are not always looking for opportunities where we could add assets in our core markets. We absolutely are. They just have to meet our financial hurdles.

Great, thank you very much.

Operator, any last questions or --?

Julien Dumoulin-Smith, UBS.

Good afternoon. In light of what you guys have discussed thus far for Power, I just to want to make it explicit. You wouldn't expect paying down any further debt at Power, right? It seems as if you have achieved your 35% FFO targets, prospectively?

Right. So in terms of Power debt paydown, really the only major Power note that is up for maturity is not until next year. So the paydown that we made of the $600 million in April, you don't have anything close to that until next year. The next maturity is June of next year for significant dollars, of the $600 million.

Okay. And you wouldn't be refinancing that more likely than paying it down, correct?

Well, I mean, if you look at the capital structure and the cash needs, you would expect that Power would be doing refinancing over the planning horizon. That would just be consistent with the way we would fund the business.

Remember that our ability to pay down this debt in April was in part the reflection of the fact that we had Texas proceeds. So we are not expecting to have something like that in the upcoming period. We always try to keep the appropriate capital structure, not be too underlevered.

Right. And then maybe just a follow-up to that. You have kind of discussed or alluded to E&P opportunities on the gas side. Any kind of timing around that, sizing around that? Anything we should pay attention to in terms of getting the next data point around the CapEx cycle?

I wouldn't want to be precise about timing, Julien, but I think you are seeing a series of dialogues taking place. It really began with the water companies in New Jersey, who have been in a position -- I'm not an expert in this, so I may use words that are a little bit more aggressive than they need to be -- but it appears of underinvestment in their infrastructure, and the recognition by the Board of Public Utilities that this was partly a result of the regulatory lag that they were experiencing, and a desire to engage in them in a conversation around clause type recovery mechanisms for their business.

Then fast forward to this year, where we have had the benefit of two years of significant declines in gas prices -- I think PSE&G has reduced its gas supply rates by over 30% in that period of time -- and yet has an aging infrastructure. So rational thinking pointed both the BPU staff and us in the direction of, okay, if we have an aging infrastructure and we have an opportunity here with the availability of construction labor and greatly reduced gas prices to reinvest in that system to preserve its reliability going forward, now is a good time to be thinking of that.

So I believe all the gas utilities collectively are going in, in the not-too-distant future, with a similar proposal to what the water utilities have done. So we don't see ourselves as unique in terms of regulatory treatment with respect to that group. What makes us a little different is just the size of our system compared to the others.

And I think that is part and parcel of the E&P dialogue that is going on right now. So I don't want to say it is a September event or a December event, but it is an active discussion and one that is borne out of the confluence of lower gas prices, availability of construction labor and an aging infrastructure that could use some help. The energy master plan itself is expected to be finalized by the end of this year.

Great. Well, thank you very much.

Operator, since we are over the time, we are going to just conclude with some remarks from Ralph.

Thank you, Kathleen. So thanks again, everyone, for being on the call. Look, I'm not going to pretend I don't wish I could report on some fuel commodity price rise, but I can't look forward on that.

But I can tell you that we are beginning to see the expected effects of long overdue EPA regulations, driven by the Clean Air Act, and the benefit that this means to us given our advanced positioning with respect to environmental impact.

We also take pride in the long-term implications of our Salem and Hope Creek life extensions; the focus and discipline we apply to our investment portfolio, which is reflected most recently in the successful sale of our Texas assets; and the recasting of our capital program. Now you can see an even greater emphasis on regulated investments, and they range from energy efficiency to electric and gas distribution to transmission. And all of these at fair, risk-adjusted returns, and all of them yielding important customer benefits.

So all of this progress continues forward with the healthy balance sheet ensuring continued financial flexibility. So thank you for being with us and I wish you all a very happy remainder of the summer.

Thank you.

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