公共服務電力與天然氣 (PEG) 2011 Q4 法說會逐字稿

Ladies and gentlemen, thank you for standing by. My name is Brent and I am your event operator today. I'd like to welcome everyone to today's conference, Public Service Enterprise Group fourth 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 today, Thursday, February 23, 2012, and will be available for telephone replay beginning at 1.00 PM Eastern today until 11.30 PM Eastern on March 1, 2012. 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, ma'am.

Thank you, Brent. Good morning, everyone. Thanks for participating this morning in our earnings call. As you are aware, we released our fourth quarter and full year 2011 earnings statements earlier this morning. The release and attachments are posted on our website, which is www.pseg.com, under the investor section. We also posted a series of slides that detail the operating results by company for the quarter. Our 10-K for the period ended December 31, 2011, is expected to be filed shortly.

I won't go through the full disclaimer statement or the comments we have on the difference between operating earnings and GAAP results, but I do ask that you read all those comments contained in our slides and on our website. The disclaimer regarding forward-looking statements details the number of risks and uncertainties that could cause actual results to differ materially from forward-looking statements made therein. 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 estimates change, unless required by applicable securities laws.

We also present a commentary with regard to the difference between operating earnings and net income reported in accordance with generally accepted accounting principles in the United States. PSEG believes the non-GAAP financial measure of operating earnings provides a consistent and comparable measure of performance of metrics to help shareholders understand the trends in our performance. I'm now going 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 questions and we do ask that you limit yourself to one question and one follow-up. Thanks. Ralph?

Thank you, Kathleen, and thanks, everyone, for joining us today on this call. Earlier this morning we reported operating earnings for the fourth quarter and full year 2011. Our operating earnings of $0.47 per share in the fourth quarter brought operating earnings for the full year to $2.74 per share, at the upper end of our guidance for the year of $2.50 to $2.75 per share, and consistent with what we shared with you on our last quarterly call. Despite challenging conditions, the past year was one of significant accomplishment as we made progress in our investments designed to continually improve New Jersey's energy infrastructure. We received approval to extend and renew the Nuclear Regulatory Commission operating licenses for our Hope Creek and Salem stations.

Performance at our nuclear facilities remain strong. Hope Creek exceeded its best annual generation in 2011 by operating at a 98.7% capacity factor. Extension of what we call the operating excellence model that has been in place at Power's nuclear fleet has been applied to the operation of Power's fossil fleet which resulted in improved availability and record generation. The availability of 3,200 MW of natural gas combined cycle capacity overcame weakness in our coal-fire generation, once again highlighting both the benefits of the fleet's fuel diversity and our efforts to run the fleet with the maximum efficiency. Our employees performed heroically in responding to two of the most devastating storms in PSE&G history, an accomplishment that was saluted by state and municipal officials as well as customers, demonstrating what we have seen so many times before, that our people remain the foundation of our success. In the face of lower natural gas prices we are not standing still.

We made significant progress on our capital programs investing $2.1 billion in 2011 as we near completion of 400 MW of new peaking capacity in New Jersey and Connecticut while major transmission projects that will modernize the Northeast grid remain on track for service in 2014 and 2015. Our $750 million Susquehanna-Roseland transmission project, which we are building in conjunction with PPL Energy, is scheduled to be in service in June of 2015. Our other major transmission projects, north-central reliability and Northeast grid reliability, are undergoing citing approval and are scheduled to be in service in 2014 and 2015 respectively. We also received approval at year-end for incentive rate treatment on the $895 million Northeast grid project which includes a 25 basis point adder to our normal formula rate authorized return on equity. These investments support our local economy with jobs, they support our customers with improvement in system reliability, and with the operation of the Northeast grid, a reduction in congestion, and they benefit our shareholders by providing fair and reasonable risk-adjusted returns on capital.

We also received approval in New Jersey in 2011 to spend an additional $368 million on improving the reliability of our electric and gas distribution systems and to expand investment in energy efficiency programs. We've also increased our interest in solar with the $75 million investment in a 25 MW facility located in Arizona that will go into service later this year. This investment, as with our prior solar investments outside the utility, is supported by a long-term power purchase agreement with a credit worthy counter party. A reputation for reliability opened new business opportunities. We were awarded a 10-year contract I the Long Island Power Authority to manage their electric transmission and distribution system. The contract is effective beginning in January 2014. We have two years to prepare. I have no doubt our team will dedicate themselves to making this a success. These operational and capital investment success stories have been accompanied by a strong and improving balance sheet and a reduction in risk.

We've reached an agreement with the Internal Revenue Service that resolves all tax-related issues with regard to our LILO/SILO leases in a manner consistent with our expectations. We've also reached a settlement with Dynegy and we continue to monetize holdings portfolio of assets. Unfortunately, these accomplishments won't shield PSEG from the impact of lower natural gas prices on wholesale power markets. We are introducing operating earnings guidance for 2012 of $2.25 to $2.50 per share. The contribution to earnings from our regulated businesses is expected to grow year over year; however, it will not be enough to offset the impact of lower power prices on ourselves and our consolidated results. PSEG is forecasted contribute 45% to 2012 operating earnings, compared with 38% in 2011 and 25% as recently as 2008.

The increased contribution to earnings from our more stable regulated business as well as the continued strength of Power's cash flow, and Power's strong credit metrics provides the support for our Board of Directors recent decision to increase the indicated annual dividend rate of the common dividend 3.6% to $1.42 per share from $1.37 per share. The decision represents a reset of the common dividend and a revision of our dividend policy. We will pay out a greater percentage of earnings as dividends under the new policy. You can expect future increases in the dividend based on growth from our regulated business and cash flow at Power. We are keenly aware of the importance you place on the dividend as a critical part of the return to expect from an investment in PSEG. The Board's action represents the 150 year that PSEG has indicated it will pay a dividend. We're proud of our record of returning cash to our shareholders and recognize the importance of maintaining a strong financial position that supports both the common dividend and our investment plans for growth.

Our focus on environmental responsibility has also positioned us well for the future. The delay in the implementation of the Cross State Air Pollution Rule, often referred to as CSAPR, along with lower prices for natural gas has had a negative impact on Power prices since the start of the year. We don't believe current Power prices fully reflect the impact of the cost of meeting new environmental requirements and we would expect over time to see a response in the marketplace. We believe the progress we've made on our operational, capital investment and financial goals will take us through this period of low Power prices and provide for sustainable growth and value over the long-term. I will now turn the call over to Caroline for more details on our results and will be available to answer your questions at the close of the call.

Thank you, Ralph, and good morning, everyone. As Ralph said, PSEG reported operating earnings for the fourth quarter of $0.47 per share versus operating earnings of $0.60 per share in last year's fourth quarter. Our earnings for the quarter brought operating earnings for the full year to $2.74 per share versus operating earnings of $3.12 per share last year. These results were at the upper end of our 2011 operating earnings guidance of $2.50 to $2.75 per share.

On slide 4, we have provided you with a reconciliation of operating earnings to income from continuing operations and net income for the quarter. As you can see on slide 10, PSEG Power provides the largest contribution to earnings. For the quarter, Power reported operating earnings of $0.27 per share compared with $0.42 per share last year. PSE&G reported operating earnings of $0.19 per share up from $0.16 per share last year. PSEG Energy Holdings contributed a small loss in operating earnings compared with operating earnings of $0.01 per share in the year-ago quarter and the parent company reported earnings of $0.01 per share compared with earnings of $0.01 per share in last year's fourth quarter. We provided you with waterfall charts on slide 11 -- slides 12 and 13 that take you through the net changes and quarter-over-quarter and year-over-year operating earnings by major business.

I'll now review each company in more detail starting with Power. As shown on slide 16, PSEG Power reported operating earnings for the fourth quarter of $0.27 per share compared with $0.42 per share a year ago. The results for the quarter brought Power's full-year operating earnings to $1.67 per share, Power's full-year 2011 results were at the upper end of guidance for the year. Power's results in the fourth quarter were affected primarily by a quarter-over-quarter decline in realized energy and capacity prices. Recall the capacity prices declined to $110 per MW day on June 1, 2011, from the prior $174 per MW day. The decrease in capacity revenues reduced Power's earnings in the quarter by $0.07 per share. A decline in energy prices under the basic generation service, or BGS contract, to $94.30 per MW hour also effective on June 1, 2011, from the prior contract price of $111.50 per MW hour, as well as migration and other re-contracting reduced earnings in the quarter by $0.05 per share.

Demand in the 2011 fourth quarter was affected by above normal temperatures which compared unfavorably with below normal temperatures in the year-ago quarter. A 4.8% decline in volume lowered earnings comparisons by about $0.01 a share. Higher depreciation expense and lower capitalized interest reduced Power's earnings by $0.02 per share. Power reduced its debt in the fourth quarter with the early redemption of $600 million of senior notes due in June of 2012. The premium paid on the early extinguishment of debt resulted in higher other expense in the quarter and reduced earnings by $0.02 per share. An increase in operating and maintenance expense reduced earnings by $0.01 per share and included in Power's operating and maintenance expense in the fourth quarter is a one-time cost of $0.03 per share associated with the cancellation and renegotiation of a major contractual arrangement for parts and services at our combined cycle facilities. A renegotiated services agreement is expected to yield net savings starting immediately in 2012, and will contribute to Power's efforts to control growth in O&M and over the long term. Other miscellaneous items added $0.01 per share to earnings.

Customer migration away from the BGS contract represented an estimated 34% of BGS volumes at year end. This level of migration was in line with expectations and compares with migration levels of 33% at the end of September of 2011, and 27% at the end of 2010. Overall average migration for 2011 was approximately 32%. We attribute approximately $0.02 per share of the reduction in Power's energy margin in the quarter to migration. The impact is the result of warmer than normal temperatures in December 2011 compared with colder than normal temperatures experienced in the year-ago period, which increased the effective headroom in the fourth quarter compared to year-ago levels.

PSEG Power's nuclear and combined cycle fleet continued their strong performance with output for both improving quarter over quarter. This strength offset a decline in the dispatch of Power's intermediate load coal units which continue to be affected by a decline in spark spreads. Power's ability to meet demand from its 3200 MW of combined cycle capacity has been an important support of margins in this current environment. The continued improvement in the forced outage rates at our combined cycle facilities helped produce record output from these facilities in 2011. This increase in output coupled with market spark spreads provided more profit from our combined cycle fleet than we've seen in the recent past.

PSEG Power's nuclear fleet operated average capacity factor of 91.3% during the quarter, resulting in a capacity factor for 2011 of 92.8%. The Hope Creek nuclear facility, 100% owned by Power, produced record levels of generation in 2011, operating at an annual capacity factor of 98.7%. The combined cycles fleet's strong fourth quarter operations resulted in an average capacity factor of 54%. This enhanced Power's profitability as Power was able to take advantage of the expansion in spark spreads in the quarter as they have all year. The reduction in market pricing during the quarter and year resulted in average gross margins for 2011 of $52 per MW hour compared with $54.30 per MW hour for 2010.

Following the completion of New Jersey's BGS auction in early February, Power's outlook for 2012 is approximately 75% to 80% hedged at an average price of $59 per MW hour compared with an average hedge price in 2011 of $68 per MW hour. For 2013, approximately 55% to 60% of Power's forecast output is hedged at an average price of $53 per MW hour. These figures reflect assumed customer migration levels of between 36% and 40% at the end of 2012 versus 34% at the end of 2011 followed by a further expected small increase in 2013. Our hedging data is based on a forecast decline and output in 2012 to 53 TW hours from 2011's output of 54 TW hours. For 2013, we are currently assuming a further decline in output to 52 TW hours before a rebound in 2014 to 54 TW hours.

Since our last update in November of 2011, the market price for gas has declined more sharply than the cost of coal. This discrepancy has widened the cost of operating our coal units versus our gas units by approximately $8 per MW hour, and this is before we factor in the cost of operating the back-end technology. We would need to see an increase in the price of gas of about $2 MMBtu or a decline in the cost of coal to correct the economic differential in dispatching our gas fleet versus our coal fleet. Keep in mind that this gas price change is from today's levels, so it is really a snapshot at a point in time and not a forecast of the long-term differential nor does it reflect seasonality that we would expect to see, but it is, in fact, exactly these market dynamics which frankly makes us pleased to have the largest fleet of combined cycle gas units that operate in PJM.

Power's operating earnings for 2012 are forecast at $575 million to $665 million. The decline in forecast operating earnings is due to lower energy prices in 2012, due to the roll off of high-priced legacy hedges. The recently completed BGS auction, which cleared in the PSE&G zone, at a price of $83.88 per MW hour will be effective on June 1 of this year and replace the contract for $103.72 per MW hour which expires on May 31. As I indicated, we are also assuming an increase in the level of migration during 2012 from 2011 as well as an expansion in headroom. Capacity revenues are expected to be flat with year-ago levels as contracts priced at an average revenue of $152 per MW day are scheduled to replace contracts with an average price of $110 per MW day on June 1 of this year.

Let's now turn to PSE&G. PSE&G reported operating earnings for the fourth quarter of 2011 of $0.19 per share, compared with $0.16 per share for the fourth quarter of 2010 as we show on slide 25. PSE&G's full-year 2011 operating earnings were $521 million, or $1.03 per share, slightly in excess of guidance, compared with operating earnings of $430 million, or $0.85 per share, for 2010. PSE&G's results benefited from increased levels of capital investment and a tight control on operating expenses which offset the revenue impact of warmer than normal weather and the cost of storm-related outages. An annualized increase in transmission revenue of $45 million effective at the start of the year added $0.02 per share to earnings in the quarter. The return on investments made under capital adjustment clauses supporting investments in energy efficiency, solar, and electric and gas infrastructure programs added $0.01 per share to results.

Warmer than normal weather, compared to the fourth quarter of 2010, reduced earnings by $0.02 per share. A decline in pension costs -- pension-related costs more than offset the impact of the October 2011 snowstorm and increased tree trimming work on operating expenses. Higher levels of capital investment led to an increase in depreciation expense which reduced quarterly earnings comparisons by $0.01 per share and the year-end adjustment to PSE&G's tax rate and other items added $0.03 per share to results.

Electric and gas sales comparisons in the fourth quarter were affected by warm weather and weak economic conditions. Heating degree days in the fourth quarter were 24% below the level experienced in 2010's fourth quarter, and 18% below normal. Weather-normalized electric sales declined 4.4% in the quarter from year-ago levels, resulting in a 2.3% decline in weather-normalized electric sales for the full year. The decline was led by reduced demand from the commercial and industrial sectors. On a weather-normalized basis, gas sales increased by 0.8% in the fourth quarter, resulting in a 1.9% growth for the year. The improvement here in the quarter as well as for the year was led by the commercial and industrial sector. Gas sales to the residential sector improved and while this does not necessarily indicate a rebound in the economy, it does suggest that customers may not have increased conservation efforts in response to low economic growth.

The Federal Energy Regulatory Commission, or FERC, granted incentive rate-making treatment for the $895 million Northeast grid reliability project at the end of 2011. The rate-making treatment, which is effective on January 1 of this year, provides for construction work in progress in rate base, recovery of abandonment costs, and a 25 basis point adder to return on equity. The adder brings the allowed return on equity for this project to 11.93%. So, just to recap, approximately $1.8 billion of our planned transmission-related spending over the 2012 to 2014 period is receiving incentive rate treatment that provides for recognition of in-rate base of construction work in progress, is allowed to recover abandonment and is allowed to return a return on equity of 12.9% for the Susquehanna-Roseland project and a return on equity of 11.9% for Northeast grid. The remainder of the investment in transmission is allowed to earn a return of 11.7%, again under formula rate treatment.

PSE&G also received approval under its formula rate program to implement its requested increase in transmission revenue of $94 million effective on January 1 of this year. PSE&G's operating earnings for 2012 are forecast at $530 million to $560 million, compared to 2011 operating earnings of $521 million. Anticipated operating earnings growth reflects an increase in transmission revenue and capital infrastructure investments, which are expected to offset a forecast increase in pension expense and higher depreciation levels. The forecast also assumes that PSE&G continues to return -- to earn its authorized return on equity.

Let's move now to PSEG Energy Holdings. Energy Holdings reported a small loss in operating earnings for the fourth quarter of $1 million, compared to operating earnings of $5 million or $0.01per share in the fourth quarter of 2010. The results for the fourth quarter brought Energy Holdings full-year 2011 operating earnings to $5 million or $0.01 per share, which were at the upper end of expectations. The results for 2011 compare with 2010's operating earnings of $49 million, or $0.10 per share. Energy Holdings fourth quarter operating earnings reflect lower asset sale gains than those recorded in the year-ago quarter. We will be consolidating Energy Holdings operating earnings in 2012 with the parent company and for both together we forecast operating earnings in 2012 of $35 million to $45 million, compared with 2011's operating earnings of both together of $23 million.

I'll add just a few other items of interest before we close out the call. We closed out a number of items which bring clarity and represent a reduction in financial risk. First, we entered into a definitive agreement with the Internal Revenue Service in January 2012 that settles the tax treatment for our cross-border leases for all tax years. In addition, we closed tax audit years through 2003, and together those two agreements were consistent with our expectations and will have no material impact on earnings but should eventually yield a net refund of approximately $100 million.

Second, Energy Holdings reached a settlement agreement in December of 2011 with Dynegy in regard to lease arrangements for the Roseton and Danskammer facilities leased to subsidiaries of Dynegy Holdings LLC. As you may recall, we recorded a full reserve for Energy Holdings investment and the lease receivable from that entity in the third quarter. Under the settlement, we received $7.5 million in January 2012, and we expect to receive an agreed upon $110 million claim payable through a mix of cash and securities upon final approval of the reorganization by the bankruptcy court. Keep in mind that this amount may be modified as the final settlement addresses the claims of all parties. Therefore, our forecast of operating earnings doesn't reflect the $7.5 million received in January or any assumptions for the potential settlement and ultimate value of securities we may receive. All settlement values received will be recorded below our operating earnings line, consistent with our recording for the full reserve in 2011. Energy Holdings also sold its investment in an office building in Denver, Colorado in December of 2011 for $215 million which resulted in an after-tax gain of $34 million recorded below the operating earnings line given its nonrecurring nature.

Our forecast of capital spending for 2012 to 2014 is contained on slide 33. As you can see, we anticipate capital spending for this period of approximately $6.9 billion. Of this amount, more than 50% are transmission investments at PSE&G for which we get contemporaneous recovery given FERC-approved formula rate treatment. In addition, recall that we have state approved capital cost recovery mechanisms for our solar for all energy efficiency and capital infrastructure spending. And Power's capital program is devoted toward completion of new peaking capacity in New Jersey and Connecticut as well as its share of the upgrade cost at Peach Bottom.

We ended 2011 with a strong balance sheet. At year-end we had cash of $834 million on the balance sheet and debt represented 41% of consolidated capital. During the quarter, PSEG Power regained $600 million of senior notes with an interest rate of 6.95% that were due in 2012, and with this reduction, debt represented 34% of PSEG Power's capitalization at year end. The company's financial strength and low-cost asset portfolio position it well in this period of low energy prices. We have the financial strength to finance our capital program without the need to access the equity markets and strong cash flow generation from Power, as well as expectations for growth from PSE&G, also as Ralph mentioned, supports our announced growth in the common dividend.

As Ralph indicated we are guiding toward operating earnings for 2012 of $2.25 to $2.50 per share. For the long-term, we have a well-positioned fleet of competitive generating units that provide upside amid stronger markets. And, with that, which closes out my remarks but not your questions, I will turn it back over to Brent for questions.

Thank you. Ladies and gentlemen we will now begin the question-and-answer session for members of the financial community. (Operator Instructions) Your first question comes from the line of Paul Patterson with Glenrock Associates.

Good morning. I wanted to touch base with you on the HEDD ruling and there was a notification that was put out by PJM last week regarding that and the EPA and concern by stakeholders about what the impact might be. Do you have any sense as to the issues they're looking at or what that impact might be in terms of the HEDD decision by the government?

Paul, it's Ralph. Good morning to you.

Good morning.

PJM always has made it clear that they tried to give parameters prior to the RPM auction and in prior years those parameters have come out at different stages but you typically by the end of -- by the beginning of February we pretty much know what the conditions are for the auction and, but PJM has always had the ability to come out with additional parameters I think in the early April timeframe.

And all they are doing this year is saying, look, in light of all the changes in terms of the [court stay] in CSAPR and in terms of the (inaudible) having a little bit of a low bar for a fourth-year extension, a fairly sharp drop in prices in terms of gas and what that may or may not mean for coal units. I think what they are signaling is it's very likely that they will come out with some notification in early April that may revisit the planning parameters.

So, it's really not a change in what they have been able to do in the past, but I think what they are signaling through all of this is that we better check the website in early April to see what, if any, changes exist in the planning parameters, and HEDD is part of the overall environmental mix.

Also, in the same timeframe the Independent Market Monitor filed at FERC some concerns regarding the minimum offer price rule and the methodology that might be used by some to effectively get around the minimum offer price rule rendering it ineffective effectively is what he stated. Do you guys share those concerns or -- I don't remember seeing anything like this from really anyone else?

Yes, so I think we do share those concerns in the following way. I mean there are all kinds of assumptions that one can make in coming up with a need for revenue streams, capacity being one of those to make a commercially logical investment decision.

And I think what the monitor is during is saying, look, we have a [bridal] report that has reasonable set and what we want to do is differentiate on the basis of true construction efficiency, picking appropriate sites that have ready access to the grid as opposed to someone coming in and saying, look, interest rates are at an all-time low so I think I can finance this at a cost of capital of 5% as opposed to I think bridal has an 8.5% number.

So what he's trying to do is make sure that we narrow the set of parameters to those that truly differentiate one project from another and quite candidly I think that's doubly important at this point in time. As you know, there are some projects that really don't care what the clearing price is because they have guaranteed payments that are above a reasonable market expectation, so I think he's doing a good job of trying to make sure that we preserve the integrity of the competitive marketplace.

What if FERC doesn't clarify? In other words, what if the ruling stands as it is now? Do you know what happens?

No, I don't know what happens and we'll have to stay tuned to May. The risk you have is that people who have less to lose by bidding low, i.e., those who are subsidized, distort the market but don't care because they get their subsidy payments and that, I think, is very bad for customers over the long term.

Okay. Finally, the LIPA contract. Is there a new strategy here or is there -- how does it fit in with your entire strategy and is there any EPS outlook or financial thought process we should be thinking about with respect to that?

LIPA 2014, we don't guide beyond '12, but LIPA is very similar to the Queens Creek investment that we're making on PPA supported solar project. We look for opportunities to deploy our capital consistent with our expertise and -- but I think, Paul, by my count we're pretty high above the one question per --.

Okay. Sorry.

Okay. After counting four I start getting stressed.

Okay.

Next question?

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

Thank you very much. I'll try and stay within my allotted two questions. When I look at the lower volume guidance for '12 and '13, is it reasonable to assume that most of that lower volume is coming from reduced coal output? And my second question, is there any expected contribution from the sale of coal in your 2012 guidance? I think it amounted to about $0.08 in 2011?

Sure, Paul. It's Caroline. Good morning. So, relative to the first part of your question and how to think about the lower output, you're correct. It's essentially the lower assumptions relative to coal volumes as we roll out during the period.

Keep in mind as we give you these terawatt hour forecasts that you're seeing on our hedge page, they are estimates and you may recall as we update the hedges we often update the terawatt hours just depending on where the curves are at the moment, so they are our best estimates at this time, but will obviously keep them updated for you as we go.

Relative to coal sales, you're right, we had about $0.07 for coal sales in the full year with about $0.02 this quarter and we talked about the rest in the prior quarters. Relative to coal sales, we're looking at that opportunistically so there may be a little bit we can do in 2012 but we're not putting in any kind of a specific forecast at the levels at which we had for 2011.

We should assume the guidance excludes coal sales, right?

Yes.

Thank you.

Your next question comes from the line of Nathan Judge with Atlantic Equities.

Good morning.

Morning.

Just wanted to inquire a bit more into the volume assumptions, just following up the last question. With regard to capacity factors, what assumptions are you making regarding capacity factors for you natural gas plants?

Nathan, good morning. I think those are in the 50% to 60% range, it varies. The Linden units and Bergen units have slightly different numbers but consistent what they were in the past year and consistent with current price curve for 2012 and '13.

And as a follow-up to that, if gas prices were to perhaps remain at the level they are today in the front month throughout the remainder of the year, is there a reason why those gas plants wouldn't be able to run more than 85% or so range?

Physically, they're quite capable of putting out additional megawatt hours. It's just a question of what is the demand.

Okay. Thank you.

Your next question comes from the line of Jonathan Arnold with Deutsche Bank.

Yes, good morning.

Good morning.

One question I have just relates to the amount of weather headwind you had versus normal in 2011. You didn't call it out as a factor in the outlook unless I missed it. And it seemed to be flattish versus 2010, but 2010 was decently above normal. So, what is the number embedded in guidance for weather returning to normal effectively?

Sure, Jonathan. This is Caroline. Good morning. You're right. We talked about weather for the quarter. You saw some warmer than normal weather which obviously had a little bit of a negative, but keep in mind when we forecast and what we put in for guidance we always assume normal weather because it's too dangerous to assume anything other than that.

So, when you think about our results for the full year, remember we had a warmer than normal winter in the last few months, we had a hotter than normal summer this year but cooler than last year, and then you had a little bit cooler than normal earlier in the year.

So when we roll that together if you look at the full-year numbers for 2013 -- sorry, on page 13 for 2011, you can see that it is a net $0.01 for PSE&G and then you seeing for PSEG Power $0.03 which is all volume, some of which may have some implications for weather but it's a little hard to disaggregate, but as we forecast forward as we always do, we always forecast normal weather.

Just to remind you, the gas part of the utility, it does have a weather normalization clause.

So, then you're forecasting based on normal for this year and that's a headwind of $0.03 or $0.04? Did I hear that right?

From last year.

From last year.

From last year. Yes. Okay. And then one thing we noticed was that you had seasonally what looked like a much higher than normal operating cash flow in Q4, over $1 billion. Did something unusual happen in the cash flow statement operating at the end of the year or was that just more normal given what I guess the weather story may have had something to do with it?

So, good question, Jonathan. Relative to cash flow and we had very good cash flow for the full year and keep in mind the full-year cash flow for the total Company as you look at cash from ops, for example, significantly higher than cash from ops for 2010 so let me just give you the full number. So, it's about $3.6 billion in cash from ops this year versus $2.2 billion in cash from ops in 2010.

What you are seeing through the year and fourth quarter is just another piece of the full-year picture. Remember, we had a significant amount of bonus depreciation impact which was slightly in excess of $800 million and so when you look at that, that's a big adder to what's happening in cash from ops versus prior period.

Other things, of course, that contribute to overall cash even though they are not in cash from ops, keep in mind we sold the Texas plants earlier this year and so those things have an effect as well.

So, when you think about going forward, although the cash from ops this year is terrific and we're very pleased to have it, obviously it's not the run rate that you should expect as we think about cash from ops going forward because while we do intend -- expect to have impact from bonus depreciation in 2012, that estimate is about $300 million to $350 million.

Keep in mind bonus depreciation this year is at 50%, not the 100% we had in 2011 and then, of course, you're going to see that effectively reverse relative to what the tax depreciation would've been in the out years.

Just take a point to point out that one of the things that is interesting to look at relative to our cash from ops is you're seeing the utility being a very significant contributor now to cash from operations so when you disaggregate our 3.6, you find that $1.9 billion is from Power and $1.6 billion is from the utility. Of course the utility finances itself half with debt for its CapEx and its CapEx is very significant, but you're seeing strong cash generation from both the businesses.

Okay. And if I may, can I just revisit on the head rules, do you have a specific number of what you think you retire versus retrofit?

Jonathan, it's Ralph So we're looking at exploring several options in terms of the hedge units. Clearly, they will not be allowed to operate with the water injection improvements we have made, but we're going to look at different uses for those assets and perhaps the possibility of different environmental upgrades for them and we're going to factor all that into our thinking over the next three to four months.

Okay. So, wouldn't it have to be sooner than that because I guess you have to decide before the auction?

Well, right. That's what I meant.

You're meaning by three -- okay, fine. Sorry, I've asked enough. Thank you.

No. I added four to two and I got to May somehow so we're both --.

That's fine. I just thought that you maybe had to make a decision slightly sooner than that.

No, the May auction is the key date.

Thank you.

Next question?

Your next question comes from the line of Michael Goldenberg with Luminus Management.

Good morning.

Morning, Michael.

I'm having difficulty calculating, maybe you have these numbers ready because the total output is changing. How many terawatt hours did you contract in Q4 for base up for '12, '13 and '14 and at what price? I don't know if you have these numbers ready but if you do, that would be helpful.

It's Caroline. Good morning. We didn't give the numbers on a per-quarter basis, we don't typically do that. We tend to give you the updated values for the current period and the subsequent, too. Keep in mind sort of two things that are going on there. Last time we reported, we reported for the end of Q3, now we are reporting for the '12, '13 and '14, not the end of Q4.

So, you've got quarterly hedges plus what we've done in January through BGS, so it's really trying to make you as most up-to-date as possible given the fact of the size of BGS. So, these numbers relative to if you go back to our prior-quarter disclosure, it wouldn't be three months of hedging, they would be three months of hedging plus BGS and this is probably the best place to start as you do your hedging calculations and estimates for us going forward.

Okay. One other thing then I wanted to ask. I am looking at the BGS auction results premiums, the $47, $48, $46 on slide 22.

Right.

So --

That's not all premium, Michael, before we go any further. I wish you were right but, yes, I know what you are referring to.

Yes, so the part that I'm confused about historically I understand some of these line items were not pure dollars but more as a percentage premium over the round-the-clock price. And I see the round-the-clock price has fallen substantially yet that premium or whatever you want to call that figure has not declined nearly as much even though I believe some of the components were percentage based, not raw dollar based. Can you explain why that is?

Michael, I don't know of anything that was percentage based, but if we just pick a couple of them, the capacity number you can get from the RPM auction and that's oscillated a bit. The green cost, quite candidly, is the renewable portfolio standard inches up toward its target has increased. Transmission investments, while it's reduced congestion and overall been a net gain to the customer and has enhanced reliability nonetheless is an increasing portion of the customer bill.

And the other risk premium is obviously highly sensitive and competitive information and varies upon your perspective of what the predominant risk is. Is it credit risk, is it migration risk. So, we've never broken that out, I'm not going to do it today, but I will go so far as to say under penalty of nasty looks from Caroline, that we never evaluated on a percentage basis, we put dollars and cents into that.

I guess what I was trying to say, for example, such thing as East/West differential or load shaping. Those numbers will be smaller if round-the-clock price is $40 than if round-the-clock price is $100, for example?

And they will also be affected by whether or not the marginal unit is coal or gas and what is the relative value of those two so the answer to your question is yes, but not -- it's not limited to what you just said.

Would it be fair --

I was just going to say, keep in mind for others listening and as you tick off these items, remember that a number of these are pass-throughs like transmission, like capacity, like green, those are cost of serve and so when we talk about risk premium it's embedded in the green, but as Ralph said, it's by far not the entire green.

Absolutely. Would it be fair to say that as headroom increases or as switching becomes easier for customers the risk premium portion will grow?

We've typically said that our expectation is that what is priced in has a higher risk premium for migration. Remember, you priced all those up as you think about BGS but, of course, what comes out as one number so then you really have to kind of disaggregate based on your own expectations.

But I think as we've talked about for a number of years, a few years ago we anticipated risk premium would increase for credit when credit was very challenged from the '08 to the '09 period and after that as '09 saw that significant ramp up really from almost an ambient level of zero of migration, you started to see what we anticipated as risk premium relative to migration.

For this past year, as you know, we saw migration levels continue to increase, although headroom was decreasing until we got to the recent period in the fourth quarter. So how people think about risk premiums for migration in general we think people price that in. Hard to tell what people would price it in any particular option given some of the frankly changing market dynamics of migration throughout 2011 versus where we ended at the end of the year.

Got it. Thank you very much.

You're welcome.

Next question?

Your next question comes from the line of Michael Lapides with Goldman Sachs.

Yes, guys, actually a couple of questions. One, and this is a little bit small but just trying to understand the strategic intent. The solar investments. Where does that fit into your broader near-term and long-term corporate strategy? As well as how you think about allocation of capital and how you think about having economies of scale in certain businesses versus others?

Michael, it's Ralph. I think your preface was exactly right, it is a smaller item. We have been anticipating solar being competitive with commercial technology probably for three or four decades now. And while the cost curve has come down on solar, it has continued to be outdistanced by the improvement in combined cycle units and gas extraction technologies and so forth. So, I put it in the category of remaining a potential participant in the future but we would not base a corporate strategy on a space that requires subsidies for sustainability.

And then a follow on this is also a little bit of a capital allocation question. When we look at your CapEx for '13 and '14 and the forward commodity curve with also the BGS contract that was just layered on, is it safe to assume that Power will be still upstreaming enough cash to fund the E&G's rate base growth and CapEx trajectory along with whatever cash E&G creates and kind of senior secured bonds at E&G or are there other alternatives that have to be thought about? And I ask that only with bill three or so of CapEx per year in '13 and '14, it's a pretty decent step up.

Thank you very much for the question. Caroline and I were remiss. It's our favorite comment to make that all of these capital upgrades and growth investments can be internally funded and there's no need for any outside equity. So, yes, Power has plenty of cash to dividend up to the payout so it can provide the equity for E&G.

Got it. Thank you.

Next question?

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

Hi. Good morning.

Good morning.

I guess if I can ask the question which Michael asked in a different way. The 14 hedges that you gave us the information about the price level, do you think they're above market or below market or at market?

Good morning. So, think about the 2014 hedges that we show you on page 19 of the deck. Keep in mind as we go out to 2014, most of what you're seeing here is BGS, because when you get in to that third year out and you know BGS is obviously a three-year rolling hedge program, markets are not very liquid as you go out to '14 and most of what we've got in these data are BGS.

So now when you think about BGS combined with some market hedges, keep in mind that the BGS price that we record here for hedging purposes is the total BGS price that we were just talking about in the PSE&G zone, for example, the $83.88 less the capacity dollarize to a per megawatt hour we sort of pull that out because we know people model that separately for us.

So it's mostly BGS. It's the result of the market of the BGS clear less capacity plus some smaller amount of the hedges that we're doing at market over the recent period, but it's not going to be from too long ago because there isn't a liquid market to hedge in 2014 if you go back before a few months ago so it is market.

So, what you're saying is if I can just assume it's that the price that you give us on the slide which is the $83.88 for the '12 auction, the only thing that you take out when you put in your energy component on the other slide is you only take out capacity, that's the only thing that you take out from there?

That's right. So, if you compare that slide for BGS to what you see on 19 for all years in which we put in BGS, whatever hedges we have for BGS in '12, '13 and '14, each year's layer is the BGS price that you see on 22 and for each year's layer we take out capacity and, of course, those are different prices and different years depending on the capacity clears. We put those into the numbers on 19 together with all of our other hedges whenever they were done at market at the time, we roll those together and that's what you see here on 19.

Okay, so it's a combination of BGS and non-BGS hedges?

That's right.

And, Caroline, just based on I guess because each BGS the way you do things are different and migration and all that, what would be a good rule of thumb to have for a year of how much would be BGS and non-BGS?

So, good question. You are right. As migration has come up over the past few years we've tried to guide people to think about BGS as about 15 TW hours when you're in the year where the BGS is full. So, for example, 2012 of course BGS hedges as you get out to '13 and '14 you have them layered in all the years so in a given year, so in the current year as you look at our total terawatt hours and our total terawatt hours hedged, think of BGS as about 15 TW hours.

15 out of the 53, right?

That's right. And of course 53 is the total volume. Keep in mind you'll never see us hedge to 100% because we would never be hedging up the stack for the high, [intermedian], the peaking, that's where we obviously dynamically put our units to market given market conditions and weather. So you would never see us be 100%.

If I could end up with the last one. Usually you give us some indication of fuel cost going forward. You had it in other slides, I guess you have. Could you just -- I don't know if you can give us any kind of headwind as to what fuel cost would be of the changes from what you presented in previous slides on the nuclear coal side going forward for '12 or '13?

Yes. So, coal costs when we look at the average coal cost for this year versus last year that we were giving out in some of the slides as I know you were referring to, relatively similar on a year-on-year basis and keep in mind you have got different types of coal. You've got the Adaro coal for Bridgeport Harbor in the high 40s and then you've got the other types of net coal that we use, Hudson and Mercer, that's mid-40s, and then you've got the 20's, high mid-20's for Keystone and [Conimaw]. Not big changes there.

Our Adaro contract re-prices at the end of the year as you may remember but not a lot of changes going on there. Of course gas, you know what's happening in the market and nuclear fuel contracted over the very long term as we, I think, indicated to you pretty consistently and that is going up over time.

And nuclear would be the same right? Which is provided in the slides if I'm right.

Slightly higher over the period but not dramatically so.

Okay, thank you so much.

You're welcome. Next question?

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

Hi, good morning.

Morning, Julien.

My first question relates to your revised dividend policy. If I understand correctly, you intent to grow the dividend going forward primarily off of EPS growth at PSE&G coupled somewhat with Power cash flows versus your historic more typical payout ratio.

Given the new strategy, what would you think about future growth of the dividend, particularly given that the dividend itself is structurally higher than that PSE&G earnings? Should we think about linearly PSE&G grows some percentage off that and we'll see some dividend increase going forward or just in light of compressing Power cash flows we should think about relatively flat in the near term?

It's Ralph. I think the number one message you should take away is that we do expect it to grow in the future but not formulaically, so we're going to take into consideration the things that we've talked about with all of the in our meetings which is that we look at where we are in the power cycle, in the commodity cycle and what Power's cash flows are.

We look at the relative mix of the two businesses. Clearly the utility being a growing portion of it not just because Power is shrinking which obviously is not the way we wanted to become a bigger portion, but because the utility itself is growing and it being a more stable mix. So, not formulaic, room for growth in the future. We will with our board look at the relative mix of business and where we are in the commodity cycle and what that means for Power's cash flows.

Great. Just more of a structural question again on demand response. Looking at the recent settlement between the DR guys and EPA on behind-the-meter generation, it seems like that could be a bigger deal particularly if that is overturned ultimately. Do you guys have any comments, expectations around what that could do to capacity pricing, TR participation, et cetera?

Add it to the mix. No. I think that goes back to some of the earlier questions that Paul Patterson and others have asked, which is we'll see how it shakes out in May.

Alright. Maybe a quick follow-up if you let me a third here. On the head rules going back to it, could you comment broadly speaking, I know you can't comment on the units, per se, but what kind of retrofit costs would you imagine generically speaking to comply with the rules? Is there any rule of thumb we can use to look at your portfolio and say X, Y and Z units may or may not choose to comply?

No, there really aren't, Julien, so we're looking at operating options and we are looking at SCR, that stretches the credibility of what you would do for some of these units given their size. So, we have a small team of people looking at all kinds of costs to factor in to what might be a reasonable bid but we just can't say right now.

Right. Thank you.

Okay, Kathleen is pointing at her watch. So, I think that she's trying to tell me that we have to wrap up the call. And I hope it is evident that we continue to work hard to ensure both the long-term operational and the financial success of PSEG. The increase in the common dividend is but one indicator of our confidence and the strength of the portfolio and our prospects for growth in the long term.

We've only had an hour to spend with you today, so we hope you'll be able to join us in New York on March 9 for what will be a full morning of discussion on these and other issues and our typical annual review of the business. So, thanks for being with us today and I hope to see you in about a week and a half. Great. Thank you all.

Ladies and gentleman, that does conclude your conference call for today. You may now disconnect and thank you again for your participation.