Kathleen A. Lally - Vice President of Investor Relations Ralph Izzo - Chairman, Chief Executive Officer, President, Chairman of Executive Committee, Chairman of PSEG Power LLC, Chairman of Public Service Electric & Gas Company, Chief Executive Officer of PSEG Power LLC and Chief Executive Officer of Public Service Electric & Gas Company Caroline D. Dorsa - Chief Financial Officer and Executive Vice President

Paul Patterson - Glenrock Associates LLC Paul B. Fremont - Jefferies & Company, Inc., Research Division Nathan Judge - Atlantic Equities LLP Jonathan P. Arnold - Deutsche Bank AG, Research Division Michael Goldenberg - Luminus Management, LLC Michael J. Lapides - Goldman Sachs Group Inc., Research Division Ashar Khan Julien Dumoulin-Smith - UBS Investment Bank, Research Division

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. [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 p.m. Eastern today until 11:30 p.m. 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. Kathleen A. Lally: Thank you, Brent, and 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 that 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 am now going to turn the call over to Ralph Izzo, Chairman, President and CEO 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 their questions, and we do ask that you limit yourself to one question and one follow-up. Thanks.

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 new nuclear facilities remained 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 operational Power's fossil fleet, which resulted in improved availability and record generation. The availability of 3,200 megawatts of natural gas combined cycle capacity overcame weakness in our coal-fired 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 2 of the most devastating storms in PSE&G's 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 in our capital programs, investing $2.1 billion in 2011 as we near completion of 400 megawatts 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 siding approval and is 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 an 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-megawatt 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 creditworthy counterparty. Our reputation for reliability opened new business opportunities. We were awarded a 10-year contract by the Long Island Power Authority to manage their electric transmission and distribution system. The contract is effective beginning in January 2014. We have 2 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 have 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 have 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 business is expected to grow year-over-year. However, it will not be enough to offset the impact of lower power prices on Power's earnings and our consolidated results. PSE&G is forecast to contribute 45% to 2012's 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 provided 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 in the dividend as a critical part of the return you expect from an investment in PSEG. The board's action represents the 105th year that PSEG has indicated will pay a dividend. We are 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 have made on our operational, capital investment and financial goals will take us through this period of low power prices and provide for sustainable growth in 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. Caroline D. Dorsa: 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've provided you with waterfall charts on Slide 11 and Slides 12 and 13 that take you through the net changes in 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 that capacity prices declined to $110 per megawatt day on June 1 of 2011 from the prior $174 per megawatt 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 megawatt hour also effective on June 1, 2011, from the prior contract price of $111.50 per megawatt 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 onetime 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. The 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 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 of 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 level. PSEG Power's nuclear and combined cycle fleet continued their strong performance with output for both improving quarter-over-quarter. This strength offset the 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 3,200 megawatts 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 at an 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 in an annual capacity factor of 98.7%. The combined cycle 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 megawatt hour compared with $54.30 per megawatt hour for 2010. Following the completion of New Jersey's BGS option in early February, Power's output for 2012 is approximately 75% to 80% hedged at an average price of $59 per megawatt hour compared with an average hedged price in 2011 of $68 per megawatt hour. For 2013, approximately 55% to 60% of Power's forecast output is hedged at an average price of $53 per megawatt 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 in output in 2012 to 53 terawatt hours from 2011's output of 54 terawatt hours. For 2013, we're currently assuming a further decline in output to 52 terawatt hours before a rebound in 2014 to 54 terawatt 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 megawatt 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 per 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 the 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 megawatt hour will be effective on June 1 of this year and replace the contract for $103.72 per megawatt 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 megawatt day are scheduled to replace contracts with an average price of $110 per megawatt 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. 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 cost, pension-related cost 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 plan's transmission-related spending over the 2012 to 2014 period is receiving incentive rate treatment that provides for recognition of in-rate base in the 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 of $530 million to $560 million compared to 2011's 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 $0.01 per 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 address 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 2 agreements were consistent with our expectations and will have no material impact on earnings, which 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 the 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 in 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 it's nonrecurring nature. Our forecast in capital spending for 2012 through 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% our 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 4 All, energy efficiency and capital infrastructure spending. And Power's capital program is devoted to our 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 redeemed $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 turn it back over to Brent for questions.

[Operator Instructions] Your first question comes from the line of Paul Patterson with Glenrock Associates. Paul Patterson - Glenrock Associates LLC: 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 sort of, I guess, concern by stakeholders about what the impact might be. Do you have any sense as to the issues that they're looking at or what that impact might be in terms of the HEDD decision by the government?

I think, Paul, it's Ralph. PJM always has made it clear that they try 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. But PJM has always had the ability to come out with additional parameters I think in the early April timeframe. And all they're doing this year is saying: "Look, in light of all the changes in terms of the courts staying CSAPR and in terms of the MACT Rule 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, that I think what they're 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've been able to do in the past, but I think what they're signaling through all this is that we've better check the website in early April to see what, if any changes exist in the planning parameters, and HEDD is part of that overall environmental mix. Paul Patterson - Glenrock Associates LLC: Also in the same timeframe, the Independent Market Monitor filed at FERC some concerns regarding the minima price rule and the methodology that might be used by some to effectively get around the minima per price rule rendering it ineffective, is what he stated. Do you guys share those concerns? Or I mean I don't remember seeing anything like this really from anyone else.

Yes. I think we do share those concerns in the following way, right? 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 doing is saying, "Look, we have a Brattle Report that has a 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 at this set a cost of capital of 5%," as opposed to I think Brattle has an 8.5% number in there. 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 because, 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 reasonable market expectations. So I think he's doing a good job of trying to make sure that we preserve the integrity of the competitive marketplace. Paul Patterson - Glenrock Associates LLC: What if FERC doesn't clarify it? I mean in other words what if the ruling stands as it is now? Do you know what happens?

No, I don't know what happens, we'll have to stayed tune to [indiscernible] I mean the risk you have is that people 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. Paul Patterson - Glenrock Associates LLC: Just finally the life of the contract, is there a new strategy here or is there -- I mean. How does it fit your entire strategy? Is there any sort of EPS outlook or sort of financial fall process we should be thinking about with respect to that?

Life is 2014. We don't guide beyond '12. But life is similar to the Queen's Creek investment that we're making on the PPA-supported solar project. We look for opportunities to deploy our capital consistent with our expertise. But I think, Paul, by my count, were pretty high above the one question per... Ask accounting before I start getting stressed.

Next question comes from the line of Paul Fremont with Jefferies. Paul B. Fremont - Jefferies & Company, Inc., Research Division: 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, is there any expected contribution from the sale of coal in your 2012 guidance? I think it amounted to about $0.08 in 2011? Caroline D. Dorsa: Paul, it's Caroline. 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 the terawatt hour forecast 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're our best estimates at this time, but we'll 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've 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 have in 2011. Paul B. Fremont - Jefferies & Company, Inc., Research Division: We should assume the guidance excludes coal sales right? Caroline D. Dorsa: Yes.

Your next question comes from the line of Nathan Judge with Atlantic Equities. Nathan Judge - Atlantic Equities LLP: Just wanted to inquire a bit more into the volume assumptions, just kind of following up the last question. With regard to capacity factors, what assumptions are you making regarding capacity factors for your natural gas plants?

I think those, Nathan, are in the 50% to 60% range. It varies. The Linden units and Bergen units have slightly different numbers. But consistent with what they were in the past year and consistent with our current price curve for 2012 and '13. Nathan Judge - Atlantic Equities LLP: 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 in the 85% or so range?

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

Your next question comes from the line of Jonathan Arnold with Deutsche Bank. Jonathan P. Arnold - Deutsche Bank AG, Research Division: One question I have just relates to the amount of weather headwind you have versus normal in 2011? You didn't call it out as a factor in the outlook, unless I missed it. And it seems to be flattish versus 2010, but 2010 was decently above normal, so is that -- what is the number embedded in guidance for kind of weather returning to normal effectively? Caroline D. Dorsa: Oh, sure, Jonathan, this is Caroline. 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, right? 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 again 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, I'm sorry, on Page 13 for 2011, you can see that it's a net $0.01 for PSE&G and then you see for PEG 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. Jonathan P. Arnold - Deutsche Bank AG, Research Division: So your forecasting based on normal for this year and that's a headwind of $0.03 or $0.04, did I hear that right? Caroline D. Dorsa: From last year. Jonathan P. Arnold - Deutsche Bank AG, Research Division: From last year, yes, okay. And then one thing we noticed was that you had a 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 in the end of the year or was that just more normal? Given what the, I guess, the weather story I guess may have some something to do with it. Caroline D. Dorsa: Good question Jonathan. Relative to cash flow, we had very good cash flow for the full year. And keep in mind, the full year cash flow for the total company, if you look at cash from ops, for example, significantly higher than cash from ops for 2010, so we'll just give you the full number. It's about $3.6 billion in cash from ops this year versus $2.2 billion in cash from ops in 2010. What you're seeing through the year in 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 periods. Other things of course that contribute to overall cash, even though they're 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 and expect to have an 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 reversed, 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 billion, you find that $1.9 billion is from Power and $1.6 billion is from the Utility. Of course, the Utility finances itself of half its debt for its CapEx and it's CapEx is very significant but you're seeing strong cash generation from both of the businesses. Jonathan P. Arnold - Deutsche Bank AG, Research Division: If I may, could I just revisit on the HEDD rules about do you have 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 HEDD units. Clearly they will not be allowed to operate with the water injection improvements we've 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 that all into our thinking in the next 3 to 4 months. Jonathan P. Arnold - Deutsche Bank AG, Research Division: Okay, but wouldn't that have to be sooner than that because I guess you have to decide before the auction?

Right. That's what I meant. Jonathan P. Arnold - Deutsche Bank AG, Research Division: I just felt that you had to make -- and may be have to make a decision kind of slightly sooner than that.

Yes. No, the May auction is the key date.

Your next question comes from the line of Michael Goldenberg with Luminus Management. Michael Goldenberg - Luminus Management, LLC: 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 of '13 and '14 and at what price? I don't know if you have these numbers ready, but if you do that'll be helpful. Caroline D. Dorsa: Yes. We didn't give the numbers on a per quarter basis so we don't typically do that. We tend to give you the updated values for the current period and the subsequent 2. Keep in mind, sort of 2 things that are going on here, last time we reported, we reported for the end of Q3. Now we're reporting for the '12, '13 and '14, not the end of Q4? So you've got the 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 that the size of BGS. So these numbers, relative to, if you go back to our prior quarter disclosure, they wouldn't be 3 months of hedging they would be 3 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. Michael Goldenberg - Luminus Management, LLC: Okay, one other thing then I wanted to ask. I'm looking at the BGS auction results premiums, the $47, $48, $46 on Slide 22. Okay, so...

That's not all premium, Michael. Before we go any further, I wish you were right, but I know what you're referring to. Michael Goldenberg - Luminus Management, LLC: Yes, so the part of that I'm confused about, historically, I understand some of these line items were not pure dollars, but more of a percentage premium over the round-the-clock price. And I see round-the-clock price have fallen substantially, yet that premium, or whatever you want to call that figure, hasn't 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 towards its target has increased. Our transmission investments, while it's reduced congestion in overall net gain to the customer and has enhanced reliability, nonetheless, that is an increasing portion of the customer bill and the 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 today going to do it today. But I will go so far as to say, under penalty of nasty looks from Caroline, that we never valuated on a percentage basis, we put dollars and cents into that green box. Michael Goldenberg - Luminus Management, LLC: 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.

Well, they'll also be affected by whether or not the marginal unit is coal or gas and what's the relative value of those 2. So the answer to your question is, yes, but it's not limited to what you just said. Michael Goldenberg - Luminus Management, LLC: Would it be fair... Caroline D. Dorsa: Keep in mind for others listening as you took off these items, remember that a number of these are pass-throughs like transmission, like capacity, like green-nose or cost to serve and so when we talk about risk premium, right, it's embedded in the green but, as Ralph said, isn't -- by far not the entire green. Michael Goldenberg - Luminus Management, LLC: Absolutely. Would it be fair to say that as headroom increases or switching becomes easier for customers, the risk premium portion will grow? Caroline D. Dorsa: We've typically said that our expectation is that what's 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 is 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 ambient level of 0 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 level continued to increase although headroom was decreasing until we got to the recent period in the fourth quarter. So how people think about risk premiums from migration, in general we think people price that in, hard to tell what people would price in any particular auction given some of the frankly changing market dynamics of migration throughout 2011 versus where we ended at the end of the year.

Your next question comes from the line of Michael Lapides with Goldman Sachs. Michael J. Lapides - Goldman Sachs Group Inc., Research Division: Actually 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 in to your broader or 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've been anticipating solar being competitive with commercial technology probably for 3 or 4 decades now. And while the cost curve has come down on solar, it's been continued to be outdistanced by the improvements 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, based on corporate strategy on a space that require subsidies for sustainability. I'm just not in... Michael J. Lapides - Goldman Sachs Group Inc., Research Division: 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-based growth and CapEx trajectory along with whatever cash E&G creates in 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 3 or so of CapEx per year in '13 and '14, that's a pretty decent step up.

And I thank you very much for that question. Caroline and I were remiss at 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 the dividend up to parents so that it can provide the equity for E&G.

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

Can I just, I guess, if I can ask a question, which Michael asked in a different way, the '14 hedges that you kind of gave us the information about the price level, do you think they are above market or below market or at market? Caroline D. Dorsa: So think about the 2014 hedges that we show you on Page 19 of the deck. Keep in mind that as we go out in 2014, most of what you're seeing here is BGS right? Because when you get into that third year out and you know BGS is obviously a 3-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 dollarized to a per megawatt hour, we pulled that out because 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 us few months ago, so it's market.

So what you're saying is, if I can assume 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 only thing that did take out from there? Caroline D. Dorsa: 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, which for 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 in the 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 that 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. Caroline D. Dorsa: That's right.

And Caroline, just based on, I guess, because you know you each BGS the way you do things are different and migration and all that, what would be a good rule of thumb to have per year of how much would be BGS and non-BGS? Caroline D. Dorsa: So good question, you're right. As migration has come up over the past few years we've tried to guide people to think about BGS as about 15 terawatt 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 haven't 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 terawatt hours.

15 out of the 53, right? Caroline D. Dorsa: 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 intermediate and the peaking, that's where we obviously dynamical put our units to market given market conditions and weather. So you'd never see us be 100%.

If I can end up with the last one, you've given us some indication of fuel cost going forward, you had it in other slides, I guess, you haven't. Could you just -- I don't if you can give us any kind of headwind as to what fuel cost would be, if the changes from what you presented in previous slides from the nuclear or coal site going forward for '12 and '13? Caroline D. Dorsa: Yes. Coal costs, when we look at the average coal cost for this year versus last year and that we were giving out in some of the slides that I know you're referring to, relatively similar on a year-on-year basis. And keep in mind you've got different types of coal, you've got the Adora coal for Bridgeport Harbor on in the high 40s and you've got the other types of met coal that we use in Hudson and Mercer, that's mid-40s, and then you've got the 20s, High load mid-20s for Keystone and Conemaugh. Not big changes there. Our dollar contract reprices 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've, I think, indicated to you pretty consistently and that is going up over time.

And nuclear would be the same, right? What you provided in the slides, if I'm right. Caroline D. Dorsa: That's slightly higher over the period, but not dramatically so.

Your next question comes from the line of Julien Dumoulin-Smith with UBS. Julien Dumoulin-Smith - UBS Investment Bank, Research Division: My first question relates to your revised dividend policy. If I understand correctly, you intend to grow the dividend, going forward, primarily off BPS growth at PSE&G coupled some with Power's cash flows versus your historic more typical pad 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 the PSE&G earnings? Should we think about linearly PSE&G grows some percentage off of that, 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?

Yes, Julien, it's Ralph. I wouldn't -- I think number one message you should take away is that we do expect to grow in the future, but not formulaically. So we're going to take into consideration the things that we've talked about so many -- with all of you in our meetings which is, that we look at where we are in the power cycle, and the commodity cycle, and what Power's cash flows are, we look at the relative mix of the 2 businesses, clearly the Utility being a growing portion of it, not just because Power's 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 businesses and where we are in the commodity cycle and what that means for Power's cash flows. -- Julien Dumoulin-Smith - UBS Investment Bank, Research Division: Great. Just more a structural question on demand response. Looking at the recent settlement between the DR guys and the EPA on behind-the-meter generation, it seems like that could be kind of a bigger deal particularly if that's overturned, ultimately. Do you guys have any comments, expectations around what that could do to capacity pricing, DR participation, et cetera?

We'll add to the mix. No, I think that goes back to some of the early questions that Paul Patterson and others have asked, right? Which is we'll see how it shakes out in May. Julien Dumoulin-Smith - UBS Investment Bank, Research Division: All right. Touché. Maybe a quick follow-up, if you'll let me a third here, on the HEDD rules, going back to it. Could you kind of comment, broadly speaking, I know you can't comment on the units, per se, but what kind of retro fit cost would you imagine, generically speaking, to comply with the rules? Is there any kind of 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're looking at FCR, that kind of 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 into what might be a reasonable bid, but we just can't say right now. Okay, I think, Kathleen is pointing at her watch. So I think 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. So the increase in the common dividend is but one indicator of our confidence in 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 in 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. Thank you all.

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