公共服務電力與天然氣 (PEG) 2010 Q2 法說會逐字稿

(Operator Instructions). As a reminder, this conference is being recorded Friday, July 30, 2010, and will be available for telephone replay beginning at 1 PM Eastern time today until eleven-thirty PM Eastern time on August 6, 2010. 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 Kathleen Lally. Please go ahead.

Thank you for participating in our call this morning. As you are aware, we released our second quarter 2010 earnings statements earlier today. Those statements, and the attachments related to them are posted on our website at www.PSEG.com, under the Investors section. We also posted a series of slides shortly before the call that detail operating results by Company for the quarter. Our 10-Q for the period ended June 30, 2010, 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.

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. 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 8-K or other filings for a discussion of factors that may cause results to differ from management's projections, forecasts, and expectations, and for a reconciliation of operating earnings to GAAP results. I would now like to turn the call over to Ralph Izzo, Chairman, President, and Chief Executive Officer of Public Service Enterprise Group. Joining 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 ask that you limit yourself to one question and one follow-up.

Thank you, Kathleen, and thank you, everyone, for joining us today. Earlier this morning, we reported operating earnings for the second quarter of 2010, of $0.65 per share, compared with operating earnings of $0.63 per share earned in 2009's second quarter. Our operating earnings for the quarter include $0.04 per share of somewhat unusual charges at PSE&G and Power, which Caroline will discuss in greater detail. Overall, operating earnings in the quarter benefited from extremely warm weather conditions, and the availability of our generating facilities to respond to the change in the demand. Notwithstanding national GDP growth statistics, the economy does appear to be in a trough. We experienced a small increase in weather-normalized electric sales, but as you know from my constant harping on this issue, weather-normalized sales is as much art as it is science, so it's too early to be excited about growth.

I do want to recognize the important contribution made by our employees to our results. Their focus on cost control and operational efficiency provides significant support to our earnings. O&M levels at PSE&G, excluding a one-time charge in the quarter and those at Power were lower than a year ago as our employees continue to perform at the top of their field. Perhaps the most significant development in the second quarter was that reached a settlement of PSE&G's rate case with an increase in rates effective before the start of the critical Summer period for electric demand. The New Jersey Board of Public Utilities approved the settlement of our electric and gas rate case, which provided PSE&G with an annual increase in revenue of $100 million.

The agreement provides for a 10.3% return on equity, and a 51.2% common equity ratio. The return agreed upon in this case will also be applied to the capital programs approved in 2009 for contemporaneous returns. Those were the capital stimulus, Solar 4 All Solar, and energy efficiency programs, all of which are still under way. As part of the settlement, we agreed to refund $122 million to electric customers over a 24 month period to resolve an issue held over from electric deregulation. The rate agreement didn't provide for the trackers on capital and pension costs that were part of our requests, but the agreement represents a reasonable balance of our needs for an improvement in return and the desire by our customers for a limit on price increases during a still difficult economic period. We intend to operate within the parameters of the rate agreement. We will more closely align our capital and O&M budgets with revenue to ensure our ability to earn the authorized return. As a result, PSE&G will be reducing its distribution-related capital expenditures, the portion that is subject to the usual regulatory lag, by $140 million a year over 2010, 2011, and 2012.

On the transmission front, we notified PJM that the in-service date for the Eastern portion of the Susquehanna Roseland transmission line will be delayed by two years to mid-2014 given the delay in the receipt of needed environmental permits. Given this delay in permitting, the in-service date for the western portion of the line is also expected to be delayed until mid-2015. We are committed to meeting the long term reliability requirements of the electric grid in partnership with our regulators and PJM. At this time, we are still assessing the cost and schedule effects on our construction program and it is too soon to provide you with a revised forecast.

Now, with regard to our other major capital programs, we remain on track to complete the construction of the back end technology projects on our Hudson and Mercer generating unit by year-end 2010. The installation of this equipment on these coal facilities will conclude a major upgrade that places PSEG Power in a very good position to meet more restrictive environmental requirements, including EPA's recently proposed clean air transport rules.

As part of the upgrade of our generating fleet, we are also investing in new peaking generation. Favorable pricing in the recently concluded RPM auction for the 2013 and 2014 year supported Power's bid to construct 89 megawatts of peaking capacity at the Carney station that will be in service June of 2013. This is in addition to the 178 megawatts of new peaking capacity that will be placed into service with Carney in June of 2012. These units will replace older, less efficient capacity.

On a separate matter, but one I suspect you are all following, markets have steadied over the past month in response to strong weather-related demand but natural gas pricing remains low in the forward markets, and without significant change, would affect margins given our base load hedge position beyond 2010 and our continuing hedging program consistent with our established practice. We are responding by controlling the growth in our cost structure without sacrificing the reliability which is so important to our customers. In conclusion, the locational value of our generating assets was reaffirmed in the last RPM auction, and our distribution rate case has been finalized. Our financial position remains strong. Investments at PSE&G are expected to provide for organic growth at returns in line with authorized levels.

We continue to reduce the potential tax risk associated with our lease portfolio. Only three leases remain in our lease portfolio, our LILO/SILO lease portfolio, after Holdings terminated one additional lease this quarter. The results for the first half of the year coupled with the implementation of an increase in electric and gas rates, support reaffirmation of our operating earnings guidance for 2010 of $3.00 to $3.25 per share. Over the long term, we remain advantaged by the location of our assets, the configuration of our fleet of assets, our environmental position, and our financial strength, and before I turn the call over to Caroline, I would like to say that I was honored and gratified to recently accept on behalf of PSEG's employees the 2010 EEI Edison Award. The award represents recognition of the dedication of all 10,000-plus employees to operational excellence, disciplined investment and financial strength. Although the award acknowledges past accomplishments, the foundation is in place at PSEG to support our goals to improving shareholder value as we work toward protecting the environment and maintaining reliability, and now Caroline will review our operating results in further detail.

Thank you, Ralph, and good morning everyone. I'll now 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 2010 of $0.65 per share versus operating earnings of $0.63 per share in last year's second quarter. Slide four of our deck provides a reconciliation of operating income to income from continuing operations and net income for the quarter.

As you can see on slide nine, PSEG Power continues to provide the largest contribution to earnings. Power reported operating earnings of $0.47 per share compared with $0.50 per share last year. PSE&G reported operating earnings of $0.15 per share, compared with $0.09 per share last year. Energy Holdings reported operating earnings of $0.02 per share, compared with $0.04 per share a year ago, and the parent Company reported earnings of $0.01 per share compared with a negligible contribution to earnings the year ago. We've 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.

So now I'll review each Company in more detail, starting with Power. As shown on slide 14, Power reported operating earnings for the second quarter of $0.47 per share compared with $0.50 per share a year ago. Please note that Power's results for the quarter have been adjusted to reflect the impact of the October 1, 2009 transfer of the Texas gas fired assets from Holdings to Power. As we did in the last quarter, we've adjusted the prior year quarter to include the results from Texas, so that you have meaningful year on year comparisons.

The operating environment in the quarter benefited from extremely warm weather conditions, sharp contrast to the operating environment of a year ago. A 20% increase in generation volume during the quarter improved Power's earnings by $0.05 per share. This increase in volume more than offset the impact of lower Power prices which reduced Power's quarter-over-quarter earnings by $0.03 per share. The decline in pricing includes the impact of customer migration away from BGS, which amounted to approximately $0.01 per share, so the net effects of price and volume is an increase of $0.02 per share this quarter.

Just a few words on migration. The impact of migration on Power's results is slightly higher than our forecast. Although the absolute level of migration, as measured by volume, is in fact in line with our expectations, the base energy price is lower than expected, causing the margin loss from migration to be higher than our previous forecast. You may recall that we had said that expected margin erosions from migration in 2010 would be no greater than the $0.08 per share impact on earnings experienced during 2009. In other words, we didn't expect the further decline in year on year earnings due to migration.

This was based upon the assumption that an increase in customer migration to a level of about 22 to 24% by this quarter would be offset by a smaller pricing differential between BGS and market prices versus last year. Estimated migration volumes are consistent with our forecast through the second quarter; however, while the differential between BGS and market prices is lower than it was last year, it's still a wider gap than we expected. So should the market dynamics continue as they have in the first half of the year? We could experience incremental loss in earnings from the impact of migration for the full year of about $0.02 to $0.04 per share including the $0.01 that we reported this quarter.

The increase in volume and lower average prices resulted in gross margins for the quarter of $51 per megawatt hour compared with $63 per megawatt hour during the second quarter of 2009. Power's gross margins in the quarter were significantly influenced by an increase in generation from its coal fired fleet and a higher cost of fuel compared with year ago levels, and this relationship is shown on slide 18. In general, we would not expect to see gross margins on a per megawatt hour basis in 2010 like we saw last year. Margin rates in 2009 in large part reflected extremely low weather-related demand, declining economic activity, and comparatively low gas prices relative to the cost of coal, resulting in a reduced dispatch of our full fleet.

If we look back to the second quarter of 2008, when Power's fleet dispatch was more similar to the experience we have in 2010, gross margins of $51 per megawatt hour for the second quarter of this year compare well to $50 per megawatt hour for the second quarter of 2008. The decline in power pricing over the past two years has largely been matched by a decline in fuel costs.

Earnings comparisons and margins in 2010 also reflect an impairment of excess sulfur dioxide and mission allowances, which reduced earnings by $0.02 per share. This was one of the expense items included in operating earnings that Ralph referred to earlier in his comments. The recent release of the EPA's transport rule has had an impact on the trading and value of these allowances. Half of the total impairment value, or about $0.01 per share, reduced the gross margin for the assets in PJM in the second quarter results.

A decline in margin associated with other trading-related activity reduced Power's earnings in the quarter by $0.02 per share. This represents the mark-to-market of an estimated decline in value on non-BGS-related full requirements contracts associated with a decline in volume. While these contracts including the impact of the marks to market remain profitable, this decline is in line with our experience from earlier in the year. For the most part, we serve these contractual commitments from the market and our approach is to hedge the volume committment with supply contracts when we enter into the full requirement transaction. We adjust these hedges as volume shifts, as opposed to running the portfolio with any type of overhedged exposure. An increase in the effective tax rate reduced earnings by $0.02 per share and a decline in depreciation expense on O&M offset an increase in interest expense.

The nuclear generating units operated by Power performed at an average capacity factor of 88% during the quarter, resulting in a capacity factor of 92.5% for the first half of the year. The results for the quarter include the effect of the planned 25 day refueling outage at Salem One. Including Power's 50% interest in the Peach Bottom unit, the fleet operated at an average capacity factor during the quarter of 92.6%. Performance in the second half of the year will be impacted by an unplanned 17 day outage at Salem One during the month of July to repair a transformer. The unit returned to service on July 24th. The unplanned outage is expected to reduce Salem's capacity factor for the full year by 5%; however, given year-to-date positive results for the rest of the nuclear fleet, this outage at Salem One is expected to lower the full year capacity factor for the fleet by approximately half a percentage point to 91%.

Generation from the coal fired fleet increased 77% during the quarter in response to weather related demand, and improvement in dark spreads from levels experienced in the second quarter of 2009. The combined cycle fleet benefited from market opportunities, operating at an average capacity factor of 53% in the quarter. Power's operating earnings for 2010 are forecast to be from $1.06 billion to $1.135 billion, compared to operating earnings from 2009 of $1.205 billion. Full year operating earnings will be affected by continued lower energy prices.

Power's coal and nuclear production is 100% hedged for 2010 at an average price of $72 per megawatt hour, versus average hedge prices for 2009 of $78 per megawatt hour. Included in that calculation is the fact that the 2007 BGS contract for $98.88 per megawatt hour, which affected Power's margins through May of this year was replaced by the 2010 contract for $95.77 per megawatt hour. Power continues to hedge as expected generation in future years, consistent with past practice. At mid 2010, approximately 66% of Power's anticipated coal and nuclear generation is hedged for 2011, with hedges in place for about 26% of Power's anticipated base load generation for 2012.

Power's full year operating earnings forecast also reflects factors discussed this morning and last quarter. Specifically, the impact of greater than anticipated erosion in margin from BGS customer migration, the impact of volume declines on other full requirements contracts, the impact of the unscheduled outage of Salem One, the impact of a one-time increase in taxes related to the enactment of the healthcare legislation, which we discussed in the first quarter, and the impairment of sulfur dioxide emission allowances. These items will be partially offset by an increase in generation volume, a decline in depreciation expense, and continued focus on O&M.

Let's now turn to PSE&G. PSE&G reported operating earnings for the second quarter of 2010 of $0.15 per share compared with $0.09 per share for the second quarter of 2009, as shown on slide 22. PSE&G's results were influenced by warmer than normal weather, the temperature humidity index or THI, a measure of heat-related discomfort, was 41% above normal during the second quarter and 131% higher than year ago levels. An increase in weather-related sales added about $0.01 per share, an increase in demand-related revenues aided PSE&G's earnings by $0.03 per share. Extremely hot periods during the day can have a significant impact on those commercial and industrial build electric demands.

Higher transmission revenues added $0.01 per share to earnings. A decrease in operation and maintenance expense was offset by an increase in depreciation. Included in the second quarter's O&M expense for PSE&G is a one-time $0.02 per share charge related to expenses disallowed as part of the rate case settlement. PSE&G's strong expense management enabled the Company to show a decrease in O&M even after absorbing this charge.

And on the rate case, just to recap, the New Jersey Board of Public Utilities approved an increase in PSE&G's electric rates of $73.5 million on June 7th and the BPU subsequently approved an increase in gas rates of $26.5 million on June 18th. The rate increase provides for a 10.3% return on equity, and a 51.2% equity ratio. As part of the agreement, the rate of return authorized in this case will also apply to the investment programs approved in 2009. As of June 30th, total expenditures since inception of the capital stimulus and energy efficiency economic stimulus project were $354 million and $44 million respectively. Spending on Solar 4 All since inception totaled $71 million.

PSE&G also agreed to refund $122 million to Electric customers over a 24 month period to resolve a longstanding issue associated with the state's deregulation law. The refund was recognized as a charge against income from continuing operations and net income of $0.14 per share in the second quarter, and will affect PSE&G's cash flow over a 24 month period beginning in June of 2010. PSE&G earned an average return on equity in its Electric and gas distribution businesses of 8.3% for the 12 months ended June 30, 2010. Each one percentage point improvement represents $0.07 per share in earnings on an annualized basis.

Turning to guidance for the utility, PSE&G's operating earnings for 2010 are forecasted to be from $425 million to $455 million compared to 2009's operating earnings of $321 million. Operating earnings will be influenced by a full year of return on capital projects approved by the BPU in 2009, the increase in electric and gas distribution rates, an increase in transmission revenue effective at the beginning of the year, growth in weather normalized sales and continued focus on operating expenses. PSE&G is in the midst of reviewing its capital and operating expense budgets to better align with costs to ensure its ability to earn its authorized return. As a result of this review, PSE&G has reduced its projected capital spending on distribution-related projects by $140 million a year over 2010 through 2012.

Keep in mind these are not the clause related projects earned in contemporaneous returns. Spending on those programs continues on schedule. As Ralph indicated earlier, PSE&G notified PJM that we have not obtained certain environmental approvals that are required for the completion of the Eastern and Western segments of the Susquehanna Roseland Transmission Line in order to meet the June 2012 in service date. Therefore, PSE&G doesn't expect the eastern portion of the line to be in service before June of 2014 and doesn't expect the western portion of the line to be in service before June of 2015. PSE&G is reviewing its plans for transmission related capital spending to insure we are investing sufficiently to support the reliability of the system for our customers and will provide an update of these programs and their capital costs when our review is complete.

Let's turn now to PSEG Energy Holdings. Energy Holdings reported operating earnings of $0.02 per share for the second quarter of 2010 versus operating earnings of $0.04 per share during the second quarter of 2009. The results for 2009 have been adjusted to reflect the transfer of the Texas gas fired generating assets to Power during the fourth quarter of 2009. The decline in operating earnings for the quarter reflects lower gains on lease sales and lower project earnings, which together reduced quarter-over-quarter earnings by $0.05 per share. After-tax benefits associated with the start up of solar projects in Ohio and Florida added $0.02 per share to earnings, and a decline in interest expense aided earnings comparisons by $0.01 per share.

Holdings terminated one cross border lease during the quarter and the successful termination has reduced Holdings' potential cash tax liability for LILO/SILO leases to $550 million at the end of June, and leaves Holdings with only three LILO/SILO leases remaining in the portfolio. Holdings' operating earnings for 2010 are forecast at $30 million to $40 million compared with 2009's operating earnings of $43 million. The decline reflects the loss on income of terminated leases, and a reduction in the anticipated gains from termination of leases, since a majority of the terminations occurred last year.

Finally, operating earnings at the parent company were $0.01 a share in the second quarter compared to a nominal contribution in the year ago period, and for the year, operating earnings are forecast to be in the range of $5 million to $15 million, in line with the $10 million contribution to 2009's operating earnings from the parent Company. As Ralph indicated, we're maintaining our forecast of 2010 operating earnings of $3 to $3.25 per share and just to recap, we had some unusual items this quarter which we included in operating earnings, in addition to the MTC charge, which is included in income from continuing ops. Affecting operating earnings, we had a rate case-related charge at PSE&G which increased O&M by $0.02 per share, and we had the SO2 admission allowance impairment of $0.02 per share, which hurt PSEG Power's margins in the quarter, but as we said, we did get a boost from the weather of about $0.05 to $0.06 per share if you combine the effects at Power and the utility.

Slide 31 provides a break down of the expectations for 2010 operating earnings by Company that I just mentioned. A full year improvement in returns at PSE&G is expected to offset the impact of lower prices at PSEG Power, and a decline in income from Holdings Lease portfolio. Finally, just a note, we completed several financings during the quarter at both Power and PSE&G, with funds used to finance our capital program and redeem higher cost debt facilities. The financings also extended the maturity of our debt profile, taking advantage of the favorable fixed income market conditions that we've experienced during the year. That completes my remarks and with that we're ready for your questions so I'll turn it back over to Trinity to queue the questions.

(Operator Instructions). Your first question is from Jonathan Arnold with Deutsche Bank.

Good morning.

Good morning, Jon.

My question is when I read your comments in the release around maintaining guidance, it seems to fairly explicitly say that the hot Summer weather has been behind you being able to hold the numbers unchanged and I was wondering if you could maybe quantify how much weather is effectively being carried in guidance year-to-date, does it include some benefit from July and I think the comment that Caroline just made on $0.05 to $0.06 was specific to Q2, so can you give us a bit more help on that?

Well, Jonathan, we forecast normal weather for the rest of the year and you're right, the $0.05 to $0.06 was Q2 but don't forget, we keep a lot in our operating earnings numbers. We literally had the storm of the century in the utility in Q1. We have the SO2 allowance, disallowance in Q2, we have training cost write-off in the utility and there may be some other charges that we've taken. Medicare tax effect, so we're going to be where we thought we would be at the end of the year, as is normally the case, we're getting there slightly differently than we thought. We're getting hurt by a few things we didn't expect and for a change of pace, we're getting helped by a few things we didn't expect.

But am I right that while you forecast normal weather for the rest of the year, you obviously have you're commenting you have a benefit from post June weather but that will be offset by other pieces?

Yes, we certainly did have that benefit, obviously as I mentioned depending on how you count the numbers in the utility from the fixed demands in addition to the observed increase in volume, we did benefit from weather as we cited to about $0.05 to $0.06 per share this quarter and obviously July has been warm earlier in the quarter but we don't predict higher weather out to the rest of the year, we just predict normal weather.

And we've included Salem.

That was going to be my other question. Is there any chance you could quantify the potentially the financial impact of the Salem outage?

It just gets very complicated. It changes dispatch costs. It changes pricing. Suffice to say that we're not happy about being out for 17 days and we're delighted the unit is back.

Okay, and I think that's it. Thank you.

Thank you.

Your next question comes from the line of Andrew Levi with Tudor, Pickering.

Hi guys. A couple questions. Just on the Salem issue, was there any replacement power costs that you can quantify? Or did you have sufficient generation to replace it?

Well, the way we generally run the portfolio was that we sell everything into the market and then we source from the market to meet our hedges and if I'm not mistaken, we were probably about 95% hedged through that period so technically we had sufficient generation to cover but it's--

More expensive?

The base load unit with the FT4 engine that's a peaking unit right now.

I get it but you can't quantify that as you said to Jonathan, and then on the lease side, just make sure I'm understanding the slide correctly. So your exposure is still $550 million but you've taken reserve of 320; is that correct?

So the exposure is $550 million and just to remind you what that means, the exposure of $550 million is if we were to settle at 100% for all of the remaining exposure, I'm not saying we do that but that's how to think about the big number, in terms of the $320 million, that's actually cash on deposit with the IRS, so that's really about reducing the interest cost that accrues against those exposures at an IRS rate which is higher than a market-rate so the way I would encourage you to think about it is total exposure of $550 million at 100% settlement if we don't terminate anymore leases which that depends on the economics of those negotiations but for a $550 million exposure, $320 million is already deposited so when you think about what a settlement would mean in terms of new cash, financing, balance sheet, that number is $230 million so that's the way I think about it.

Got it and that's basically your reserve number, there's nothing else that you've reserved or gave to the IRS however you want to say it besides the $320 million, right?

Right. So the $320 million is the cash that's on deposit with the IRS and for the moneys on deposit. The reserves in terms of the books, we believe that we're adequately and appropriately reserved. That's a totally separate calculation of course from the cash.

Okay and is there a number you can give us on the reserve?

No, we don't specifically break out those reserve numbers.

Okay, thank you very much, and one more point. Keep the lights on in Maplewood. They went out again.

Oh, geez, Andrew.

Okay? It's every Summer so see if you can keep the lights on. That's all I ask. Thank you.

You're welcome.

Your next question is from Dan Eggers with Credit Suisse.

Hi good morning. Can we talk a little bit more about the customer migration trends I guess? Number one, it sounds like you've stopped seeing people leave. Is that still accurate and then second, as far as the additional costs are concerned, how much of that is going to continue beyond this year? Should we assume that the higher drainage on EPS is going to be a sustained pressure looking forward?

So just to comment on how we think about the loss. So as we mentioned, we have lost migration to a level of about 22% to 24% and that's not inconsistent with our expectations of the volume. The real effect this quarter that we pointed out was a little different than what we thought last quarter when we're talking about migration is the fact that the prices in the market, the delta between the BGS sort of net realized price and the prices in the market, that gap was a little higher than we thought. That's what lead to the penny this quarter and our sort of guidance expectation that we might in fact see a real decrease this year, year-over-year about $0.02 to $0.04, so the migration volumes consistent with what we saw, the pricing in the market is a little worse so you have a year on year impact.

In terms of thinking about the long term but we don't really forecast certainly not beyond this year, I would encourage you to keep in mind that as you think about the whole migration trend and its impact to us, it really depends upon the factors of market prices and the BGS price level so you know when you look forward in BGS next year for example, you have a BGS price of $111 rolling off and lower price rolling on, all of that is something to keep in mind as you think about what's that delta, and you could envision that delta getting smaller from BGS effect. We obviously can't forecast the market but that's what causes this observed slowdown in the rate of migration from the high levels you saw last year in the second quarter where we went from essentially almost no migration up to levels of 19% by the end of the year.

Okay, and then on the Roseland delays, can you provide me with a little more context on what's going on as far as the delays and permits, what the major issues are right now, how you see them getting resolved and when you could realistically start to spend money without having to say exactly how the delays are going to shape out dollar wise?

So the root cause issue here really is the National Park Service and the challenges are getting highly reviewed with permits there, so we've spent a little under $75 million to date. The delays are likely to result in an increase in cost and some rearrangement of how that money gets spent. I would not think of it just as a two year shift out, but in fairness to the State environmental reviews, they are asking themselves, well, if you don't know for sure what and when the western piece will go into effect, and the overall line is needed for reliability, does it make sense to move aggressively on the Eastern piece? So the real root cause issue Dan, is the national park service an d I guess they're now saying Fall of 2012 is when they will complete their review and just yesterday, they announced I don't know if it was six or five alternate scenarios which will now have to comment on and review, so the larger transmission projects are a siting challenge. I think we've all known that all along. There's plenty of transmission work to be done at the smaller voltages, but we continue to work with our regulators and work with PJM to make sure the lights stay on notwithstanding whatever happened in Maplewood the last few weeks, which I'm unaware of, but I'll find out after this call so that's what I'd say. The we'll core of the issue is the Park Service delay and the resultant impact it had on the State and their willingness to try to understand what the overall line benefits will be versus partial line benefits.

Can you remind me how long the construction period is post permitting, how long it will take to build the lines both the Eastern and Western Lines and then what was the split on CapEx between the two sides?

Well you would think that would be an easy question to answer, right? But the question becomes when do you get permits to do what part of the line? So for example, if you had State permits to work outside of the Park Service you can get a good portion of the line under way. I think we've estimated publicly that between 70% to 80% of the line CapEx was on the Eastern portion, but if the permit for the Eastern portion are held up until the Western portion is fully approved, of course in fairness, to regulators we never used to talk about an Eastern or Western portion, Susquehanna to Roseland line, right? And it needs to be one overall comprehensive project, so it's not just as straightforward as one might guess so if everything is held up until everything is approved, then you're looking at a two to three year construction program.

And I guess last question on this. Is this going to do anything to affect either system reliability or any of the assumptions that PJM had as far as previous capacity options?

Well, yes and yes. We weren't building this line because we thought we had spare time on our hands. PJM does a fairly rigorous engineering analysis and there are reliability concerns and that doesn't mean that on June 12 of 2012 that there will be blackouts. This is all risk-based analysis and clearly, the longer you allow uncorrected constraints to persist the more the risk is of significant events. That doesn't mean there will be a significant event. One could point to the fact that we had a significant event in August of 2003 and you'd have multiple ways of solving reliability concerns.

One way is through transmission and another is through pricing signals sent to capacity Markets to relieve constraints so this will have upward pressure on capacity prices. We don't forecast prices and it will have increased risk on reliability but that does not mean at the risk of repeating myself too many times that the lights will definitely go out. There are other factors that policy makers have to weigh, some of which are the impacts on national parks and that's the dialogue we find ourselves in.

Okay, thank you guys.

Your next question comes from the line of Paul Fremont with Glenrock Associates.

Hi, it's Paul Patterson. What I wanted to touch base with you on is just a few quick items. The SO2, could you just elaborate a little bit more about the disallowance what happened there and what caused it?

Sure. So we have SO2 allowances that we hold on our books, and just if you want the accounting, the lower of cost or market hold of those allowances. These are allowances that came on to our books related to asset acquisitions of a number of years ago. The SO2 market is a traded market so you can observe the prices in the market. They have typically for many years been well above the carrying value on our books for these allowances. What happened if you look at this market and there's actually an article in the journal a couple weeks about this, when the EPA draft rules came out, there was an expectation these allowances would not be able to be used for some of the purposes that have previously thought they would be useful relative to EPA regulation so the value of those traded allowances went down very significantly, in fact if you just looked at that value from the beginning of June on the traded market to the end of June you would see those allowances in price eroding from the high teens to about $4.

Okay.

And in there that crossed our basis so we obviously take that.

Sure, okay, and then on the Polar contracts you mentioned, you mentioned they were in line with what you experienced in the past. Do you see any change in that in terms of the load and is that mostly, well I'd assume it's not, is that industrial or economic or do you think it's more of a customer switching situation?

So it's a combination of commercial and industrial and residential full requirements, provider of last resort like contracts. Not dissimilar from BGS except we're supplying those not from our assets but from the market and that's why we mark them to market and what you're seeing in our numbers as we update those marks for a change in value to those contracts we take that through the P & L immediately and it is primarily from customer switching and primarily in the commercial and industrial. We don't see much of it happening on the residential side, we don't see much of it happening on the residential side in BGS either, primarily commercial and industrial so as those expectations based on that migration occurs we have to adjust our hedges to make sure we're hedged consistent with our volume expectations.

Okay so is it trending in the direction you would expect it to? It would indicate perhaps it isn't because your hedging is more than it should be. Is that correct?

Well some of these contracts were in place from a number of years ago so as we update them, as we see switching data then we need to take updates to those contracts. That's what you're really seeing happening. It's not easy to forecast the migration but as we see it, when we update our hedges then we update our markets.

And then the PSEG power depreciation could you remind me what's causing the decline again?

Sure. So when we were, we talked about this I think first quarter or fourth quarter.

Right.

It changed and updated some of the asset lives of some of our facilities as we put in place for example, the back end technologies and those updates to asset lives, pushing them out, reduced our depreciation calculations on an annual basis. Anything else you wanted to make a comment?

Yes, on the SO2 Paul to go back to your initial question we've not given up the ghost either in terms of possible legislative remedy although that would be a challenging thing to do nor in terms of comments on EPA's proposed rule and we're not alone. We do think that what the agency proposed is punitive towards those companies like ours who got out in front of the need to reduce SO2 and NOX and took early actions and thereby created those allowances which we're now not getting credit for so not suggesting we'll win that battle but it's one we'll be waging with others.

Thanks a lot. That's interesting, and the other thing I wanted to simply ask was sort of what the economy and industrial sales and what we're seeing on the gas. I know it's a small part of the business but it did seem the industrial gas sales seemed to be declining quite a bit. Could you just sort of elaborate a little bit what you're seeing on that and what's causing that and just in general, it seems the industrial electricity growth doesn't seem to be there either, where we're seeing that perhaps in other areas around the country, we are seeing restocking or whatever happening in different areas. I was just wondering if you could comment a little about the economy and what might be driving those figures?

New Jersey has a challenging industrial economic environment, while that's been going on for well over a decade and it's just a continuation of a movement towards more of a commercial service sector economy here in New Jersey and that's why we focus more on the residential and commercial sector and our electric not to say we don't value our industrial customers. Similarly on the gas side of the story is pretty much the same, a movement away of the manufacturing sector. Most of our sales on the gas side are residentially driven and are starting to show quite a bit of a rebound.

Great. Thanks a lot.

Your next question is from Paul Fremont with Jefferies.

Thank you very much. I think the differentials between PJM West and PSEG were much narrower in 2009 relative to where they had been historically. Can you update us and give us a sense of where those differentials are today or are they closer to 2009 or are they back closer to levels that they had been historically?

I think in general, we've seen those numbers coming down, Paul, but I think and we often get this question. One of the things that I've observed has been now this is somewhat of an anomalous set of circumstances but if you look at what this has done in the past few months you've seen them come up quite a bit. Now what is different about the past few months than what has been in place for the past two years. I still believe that basis has dropped in the past two years because you've had a drop in demand that creates excess supply in both regions and you had a shift in the marginal unit with coal prices stabilizing to increase and gas prices coming down, so it's just been the pure fundamentals of what's the marginal unit and what is that marginal unit on a basis of fuel and what's that marginal unit on the basis of demand and as you've seen as gas comes down and demand comes down and then the East and West part looking for similar and basis starts to shrink, it's not a function of demographic shift or location all value associated with being close to load and in fact as we saw 90 to 100-degree weather drive demand and gas prices no longer dropped, basis resumed its upward march, so as we see gas prices steady and I think we've started to see them steady and as we see a return to demand which we have not seen in its full glory quite yet for the economic reasons we've talked about, we started to see a modest upward movement in basis in the outyears, not to the level we had experienced in 2008 but we started seeing a modest increase.

And can you put some numbers around that? So for instance year-to-date what's the basis?

There's a reason why I'm reluctant to do that and you'll know what I'm about to say Paul is that's part of the green part of the BGS bar chart that we show folks and we try not to break that out for competitive reasons and basis is not a fully liquid traded product.

If basis ends up structurally lower than where it has been in the past, does that essentially create an additional profit incentive for customers to shop?

No, because customer shopping is the difference between the Polar contract and the market, and that will, if you believe the market dynamics will not be spikey will take care of itself and you have to believe that basis is structurally going away of you believe structurally that demand is not coming back and gas is going to be competitive with coal into the long term future. You have to believe both of those factors.

I'm just saying that the historical bids would have been in an environment of much higher basis differential, right? So to the extent that is lower than where sort of the existing bids were which make up most of the price today, that creates a potential additional incentive.

Well, I think the key question is what do people forecast for that future and how do they bid in not just their expectation but the risk around that expectation, right, since we know that part of what drives the BGS pricing is pricing and not just the expectation of the value but the variation around those values and so if there's still uncertainty around things like basis like other things, you see sometimes they get priced in and what we would call that margin for risk premium which as we said before we think has some benefit to us because of obviously having the assets in the market and the ability to dispatch to serve that load in the most efficient way.

Thank you very much.

Thank you.

Your next question comes from the line of Ashar Khan with Incremental Capital.

Good afternoon. I guess I just wanted to go over, I was looking through the rate base slide that you had provided for PSE& G and it showed transmission rate base growing by about I think it's approximately $600 million in 2011 and another $400 million in 2012. Should we change those numbers that are not anymore reflective? Do you have an update to provide us or when could you provide us an update on those rate base investment numbers?

So thanks for the question. In terms of thinking about the rate base, as we talked about, we aren't ready yet to provide an update on how to think about transmission capital spending for all of the reasons that Ralph mentioned related not only to Susquehanna Roseland but other things going on relative to transmission but we're doing all that work looking at the other reliability needs etc. We'll provide an update when we finish that review. For purposes of thinking about the rate base in general, I'll just remind you one thing we did mention on the call this morning was the fact that based on the receipt of the settlement, we have reduced our expected Capital Expenditures for the distribution side by $140 million per year and so when you think about the rate base growth, that part of our bar chart that's distribution, think of that as reduced by $140 million per year each year between 2010 and 2012.

That's the portion that as Ralph mentioned is subject to the regulatory lag so we want to take that out in the appropriate way we can think about your earnings calculation because we're continuing to spend on the other programs like the energy master plan, but it's just too early yet at this time with all of the things influx to revise that transmission capital expenditure forecast. We will do that as soon as we're able to do so.

Could you remind us how much this transmission line was in those two years?

The whole line was $750 million, I don't remember the two year spend.

Okay, I appreciate it. Thank you so much.

Sure.

Any other questions, Operator?

Yes, you have a question from Leslie Rich from JPMorgan.

My question has actually been answered, thank you.

Thank you.

Your next question is from Steve Fleishman with Banc of America.

Yes, my question has been answered as well.

Thanks, Steve.

Thank you.

(Operator Instructions).

We have time for one more question, Operator if there is one?

Yes, have a question from Neel Mitra with Simmons & Company.

Thank you. I just had a follow-up on Susquehanna Roseland. I was under the belief that the project had independent utility on the East side, so it would need to be built regardless of the West was ever built. Does that still hold true and then second part of the question was I think that the East part was built into the last capacity option and when do you think with the delay that it will be put back into the RPM auction?

So, Neil, depending on who you ask you'll get different answers to the independent utility. I would certainly agree with you, but some of our regulators do not, so there's a little bit of a difference of opinion around the independent utility issue, but we would agree with you. PJM would agree with you, and you're correct that it was originally factored into the base residual auction and normal PJM process at this point then would be to have an auxiliary auction to account for the change in the in service date.

Okay, and just on the migration patterns. Are you using more put options at this point to hedge that risk or are you thinking about utilizing more financial swaps, just what are your thoughts on hedging some of that risk away in outer years?

Yes, so that's a good question. We are recognizing the fact that migration, obviously a new phenomenon and trying to put some protection in place so that we have that opportunity, so yes, we are using to some extent, products like options when the premium obviously is worth the protection that provides. Keep in mind, of course that when we're talking about migration, we've talked about it on this call, two kind of separate buckets. One is in BGS where we're serving from our assets so we have that normal embedded flexibility if you will with our assets whereas we're not serving BGS with our assets, we can serve the market directly, versus the wholesale power trading portfolio where we are providing power under full requirement contracts that serve from the market and there, we use more of the types of instruments that you describe to protect us from those volume shifts because we are serving from the market. I'd say we have a pretty good balance of using both the direct like forward like products as well as the options as the team continually assesses how to think about migration as the data are updated.

Okay, thank you very much.

Thank you.

Thank you all. Just going to turn the call over to Ralph. As always, I do want to remind you if you do have questions after the call concludes please feel free to call the Investor Relations department at 973-430-6565. Thank you.

Thanks, Kathleen. So just at the risk of repeating some of what you already heard, our near term outlook really is just best described as steady as you go. The rate case is behind us and we won't see another BGS and RPM auction for another seven to 10 months so we're completely focused right now on O & M control and successfully executing our capital programs. The utility has a lot to do in its contemporaneous clause programs, the sole for all energy and efficiency stimulus and it has a fairly robust ongoing transmission construction program.

Similarly, power must finish its BET on time and under budget and lastly Holdings while completed to solar farms has one more we expect to finish some time in August. Longer term our environmental advantages, our portfolio dispatch, dispatch mix and our location are going to serve us well. We will continue our disciplined hedging strategy. It's helped us avoid precipitous declines in power prices. Candidly it will also have some opportunity costs if there are unexpected spikes in prices but this will allow us to benefit from long term price trends which we believe will be dominated by supply and demand dynamics with a significant environmental overlay, all of which we leave were well positioned to succeed in.

So thanks for being with us today. We hope you enjoy your summer. I'm sure we'll see some of you in the upcoming weeks and if not we look forward to seeing you at EEI in the Fall. Take care.

Thank you.

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