NRG Energy, Inc. (NRG) Q4 2007 Earnings Report, Transcript and Summary

Good morning ladies and gentlemen and welcome to the NRG Energy's Fourth Quarter 2007 Earnings Results Conference Call. At this time all participants are in a listen-only mode. But, following the presentation we will conduct a question-and-answer session. [Operator Instructions]. Also note that today's conference is being recorded. And now I would like to turn the meeting over to Ms. Nahla Azmy. Please go ahead.

Thank you Sophie. Good morning and welcome to our fourth quarter 2007 earnings call. This call is being broadcast live over the phone and from our website at www.nrgenergy.com. You can access the call presentation and press release furnished with the SEC through a link on the Investor Relations page of our website. A replay and podcast of the call will be posted on our website. This call, including the formal presentation and the question-and-answer session will be limited to one hour. In the interest of time, we ask that you please limit yourself to one question with just one follow-up. And now for the obligatory Safe Harbor Statement, during the course of this morning's presentation, management will reiterate forward-looking statements made in today's press release regarding future events and financial performance. These forward-looking statements are subject to material risks and uncertainties that could cause actual results to differ materially from those in the forward-looking statements. We caution you to consider the important risk factors contained in our press release and other filings with the SEC that could cause actual results to differ materially from those in the forward-looking statements, in the press release, and this conference call. In addition, please note that the date of this conference call is February 28, 2008, and any forward-looking statements that we make today are based on assumptions that we believe to be reasonable as of this date. We undertake no obligation to update these statements as a result of future events. During this morning's call, we will refer to both GAAP and non-GAAP financial measures of the Company's operating and financial results. For complete information regarding our non-GAAP financial information, to 1most directly comparable GAAP measures and a quantitative reconciliation of these figures, please refer to today's press release and this presentation. And now with that I'd like to turn the call over to David Crane, NRG's President and Chief Executive Officer.

Thank you, Nahla and good morning everyone. I am joined here today as usual by Bob Flexon, our company's Chief Financial Officer; Kevin Howell, Head of Commercial Operations; Drew Murphy, our General Counsel, Krishnan Kasiviswanathan, our Chief Risk Officer, John Ragan, our Northeast President. Northeast region had a phenomenal year last year and for reasons that should be obvious from anyone who has read the earnings release by Clint Freeland and Maurizio Guacharo. This is the call... first call of the year where we normally set the stage for the year ahead and we are going to do some of that. We're also going to talk about the changes in the orientation that were announced in the press release today, because they are a little bit out of the ordinary, but as I said in the press release today. These are evolutionary changes rather than revolutionary changes in the way that company is organized and this is actually the end of an organizational process rather than the beginning and that these changes were determined and decided upon last July and we've been working through to this conclusion today. So, I am going to be referring as we go through the presentation to slides which appear on the website and I'll be referring to those. So, stay on slide three, table of content. Actually after 15 quarters of using the same format in the last few quarters, we have actually not even had a table of content, so our only remark now is that this is actually the orientational format that we will be using going forward. I will be giving the operational review this quarter but in subsequent quarters it will be given by Bob Flexon and so lets begin. On slide 4, since we have a lot of information to go over today as always and there is a lot of information on our earnings release, I want to fly for you the three things that I think are most important about today's announcement. First, with respect to the company's full year 2007 financial performance, to me the key number is $1.25 billion, that's our free cash flow results before special environmental projects and growth CapEx. This healthy result which exceeds our guidance meets directly to the double-digit free cash flow yield, which you can find tabulated in Bob's section of the presentation and which remains the fundamental investment proposition of this company. I have said on these calls and in many one-on-one meetings in the past, we managed this business for cash and this result proves that 2007 was no exception. Second, while our company has adopted a slightly more conservative posture with respect to our liquidity in light of the current capital market environment, we have never been more strongly positioned both from the point of view of our current liquidity and in terms of how we collateralize our commercial operations activities. Perhaps, more importantly the current capital market environment has not effected our commitment, which we first made approximately one year ago to return to our shareholders on an annual basis at least 3% of our market cap either by way of a share buyback or through common stock dividend. And indeed, we are disclosing today that we have already begun the share buyback program for 2008 having repurchased $100 million worth of our shares in the last few months, of course, prior to entering the current close period. And third, while the development process for new power plants particularly those involving new technologies remains very lengthy, we made meaningful progress across almost all of our development efforts in 2007 and we are positioned to put further distance between us and our competitors in this area in 2008. Moving to slide 5, in 2007 you can see some of the highlights of how we executed across our major areas of day-to-day business. I can't go over all of these because of time, but would like to highlight a couple of items. First of all, in terms of asset sales, as we have always told you we are always looking to optimize our asset portfolio both core and non-core. With respect to non-core assets, our record has been to act deliberately to ensure that we realize maximum value and that has worked for us through more than 20 asset disposals which we have carried out over the last four years. Almost all of which have exceeded market expectations in terms of sales proceeds. This is the approach we have taken with respect to our Brazilian project, ITISA in recent months. We have a binding sales agreement for $288 million and we expect when that project closes to be able to repatriate to the United States about $250 million net cash. The project is not yet closed, we expect it to close by the end of second quarter. Not all approvals have been obtained yet but we are confident as to what has been obtained, that there is no obstacle that we see to closing out this transaction. With respect to safety, NRG ended 2007 with an initial recordable injury rate of 1.6 to the 20% improvement and well beyond the 2006 industry average of 3.9. This is an important milestone for our company because 1.6 processing the top quartile within the power industry. This great result was achieved only by an all hands on deck effort at all NRG locations and at all levels of the organization. I want to commend everyone at NRG for their contribution to this result and I want to particularly commend the plans that either are participating in the OSHA Voluntary Protection Program at this time or are going through the lengthy application process now. In terms of plant operations, there was an equally broad and deep level of accomplishment across our fleet. So, again I can only note a couple of the two highlights. The first is that we contributed mildly to keeping the lights on in Southern California, first through our timely completion of the emergency repowering of the Long Beach plant in time to support included during the late summer heat waves, where the plants made 36 starts with 99% of reliability. And secondly during the late fall California wildfires, which disrupted transmission in the San Diego County forcing the Carlisle to rely totally on the very limited in county generation like ours to keep the lights on. Similarly in New York City our Arthur Kill plant was repeatedly dispatched as a mail order. So much so that the energy production for the year was up 97% and the plant responded with admirable reliability. The other highlight that I want to mention was our South Texas nuclear plant. At this point, everyone knows that we've applied to build a new nuclear plant at STP, STP 3 and 4. But quite distinct from that effort is the exceptional work the STP operating team has done with STP 1 and 2. I could recite the numerous operational words that this plant received in 2007 but suffice it to say that for the year STP was again the top generating two unit sites in the United States. These special performances feed in to the fleet performance statistics which appear on page 6. Although, our 2007 base load equivalent for solid rate performance was down year-on-year, it remained much better than two years ago. I don't intend to try and explain this result away to you because as a company which bases it's operations on a philosophy of continuous improvement, we are not happy they have taken a step backward from 2006 to 2007. And we hope and expect to change the direction of this bar chart in 2008. However, there are two significant mitigating factors. The first is that only four out of the 20 operating core units in our fleet had a preponderance of the unsatisfactory E-4 performance. This allows us to concentrate our focus on those units as we troubleshoot the problems. The second mitigating factor is as demonstrated in the upper left, one of our principal for NRG objectives was to capture nameplate base load capacity. And our achievements in this area had a positive impact that exceeded the impact of the incrementally higher E-4 rates. Despite the E-4 results our total fleet generation was up year-on-year. The substantial increase in production in STP I already mentioned is noteworthy, but also there is the enormous decrease in energy sales from our Texas gas plants. This has nothing to do with the reliability of those plants, but was a result of the extraordinarily wet and mild summer in Texas last year. We expect our Texas gas unit to do much better in 2008 assuming normalized summer weather. And finally, on this slide I want to talk a bit about our coal inventory because I know that the coal world is abuzz with red hot coal pricing that people are telling you will last forever. As you can see from this chart, our aggregate inventory levels stand at approximately 45 days as of the end of January. We opportunistically increased our inventory prior to the current run up in coal prices. And if you now turn over to slide 7, you will see our total fuel position longer term, 100% contracted for 2008, 93% for 2009, 64% for 2010, and so on. And please keep in mind as you consider our exposure to higher coal pricing that Eastern Coal represents only a fraction of the coal that we consume. It is so little in fact that less than 1 million tons a year of Eastern Coal that we use is subsumed in this table on the lower right in the category labeled other. The other important point, you need to understand about NRG and coal consumption is that even among Powder River Basin coals NRG uses much more 8,400 BTU coal than 8,800 coal. And 8,400 BTU coal is even less suited to the international on the Eastern Coal markets than the 8,800, and has resulted and subject to considerably less pricing pressure in recent months. The other point I want to make on slide 7 is actually about the non-event. You will note if you compare our hedging chart on the left to the one that we showed last quarter there has been essentially no change in our hedging profile. This means that it's been almost a year since we engaged in significant additional hedging activity, and to me that is the beauty of our strategy. We can sit out the market when gas and storage is high and gas price volatility is low as they both have been and as such we consider ourselves a patient ball waiting for the time when strong fundamentals and weather push gas prices above our targets enabling us to lock in long-term prices at favorable levels. On slide 8, this slide goes hand in hand with the prior hedging slide and again, there is very little change. We've the fundamental short-to-medium term risk posture that we think provides the best risk adjusted return to our shareholders, low-to-moderate gas price sensitivity over the next few years and much greater exposure to increases and base load heat waves. Now turning to slide 9, I want to highlight one another benefit of our hedging strategy which is highly topical at this point in time. We run sensitivities of our earnings general economic recession using the 1990 recession as our guide because we think that recession is more similar to what the country is facing now. But, on the assumption that the expected recession that we face now would be significantly longer and harder than the one that occurred in 1990. On these assumptions, the negative impact on our 2008 EBITDA would be significantly less than 1% of the total. I also want to point out that, you know, while not being an economist or an expert on these things, I ask the question, how much of the recession we'll face in two of our core regions, Texas and Louisiana with crude oil prices hovering at a $100 per barrel even if there is a national recession? But all the same, impact on us less than 1% of our EBITDA in 2008. As such, I think it's fair to say that while NRG may not be recession proved, we are highly recession resistant. These discussions are merits of our hedging strategy over the past few slides provides an appropriate point of departure for me to discuss the management changes that are being announced today. I am firmly convinced that this company and you as shareholders have benefited enormously from the hedging strategy including the hedge reset of November 2006, which was implemented by our commercial operations group over the past three years. While speaking on these quarterly calls and otherwise and to investors and one-on-ones in that industry conferences we generally have not sought to feature the invaluable role played by our comm ops team in the success of this company. We have kept a low key because comm ops generally doesn't like to give any signals to the market as to what they are thinking and also a little bit more selfishly for reasons of human resource retention we don't like to flaunt to the market how good our team is. So, when we board that tact to go wider and basically say that NRG has the most capable asset base trading and marketing team in the business. And the person who has built that team and led it to considerable success that it and we have achieved is Kevin Howell. What has also impressed me in working with Kevin over the past three years is not only what he and his team has achieved but also how they have achieved it. As AEP and others found out several years ago, there is considerable challenging grafting or developing a hyper aggressive and self interested trading and marketing team on top of it generating asset base and a power plant company culture. Kevin has built a team that functions effectively and pretty much harmoniously along side our plant operations. This has taken a Gus touch with respect to personnel both his own team and his colleagues and Senior Management. I can say I have learned more about personnel management from Kevin Howell then I have from any other single person in my entire career. It is these management qualities that cause me to ask Kevin to take on the role of Chief Administrative Officer. A post from which he will be responsible for ensuring that NRG has all the capabilities that we need both in terms of software and by that I actually mean the right people and hardware to realize all the extraordinary opportunities that currently are presented to us in our marketplace. With Kevin in-charge I am confident that we will have the tools that we need to achieve our destiny as a company. Now before I see the floor to Bob Flexon for his 16th and last quarterly turn as the Chief Financial Officer of NRG Energy, I want to take a quick look back of what has been accomplished on his watch. I could think of no more fitting testament to Bob Flexon then as you might say to go to the numbers. Slide 10 attempts through a long series of financial metrics to show that financial strength of this company at the time of Bob's arrival in early 2004 and where we are now. I know of no other Chief Financial Officer certainly not in this industry who have achieved so much starting with so little in such a short time as Bob Flexon. Now reassuringly large numbers, you on the phone have been with us since the beginning and have witnessed the financial strengthening of this company over the past four years. I know you don't need to be convinced of what Bob Flexon has accomplished with this company and this balance sheet. And he assures me that the company's progress in this area has been so obvious that there are only three people in the whole financial world who don't get it. Unfortunately as you can tell from the bottom at this page, those three people are named Mr. Standard, Mr. Poors and Mr. Moody's. When I think that we have one major rating agency that has not acknowledged any improvement in our financial conditions since our inception and we have another major rating agency that has had us on negative outlook for 14 months notwithstanding our $2.7 billion of current liquidity, I am literally at a loss for words. But maybe my speechlessness is a function of what my daddy used to say, David, he would say, never try to rationalize the irrational, never try to defend the indefensible. Anyway trying to get back on the high road here, it's been my immense honor and pleasure to work with Kevin and Bob in their current positions as they are Head of Commercial Operations and CFO respectively and I look forward with great anticipation to working with them in their new positions as Chief Administrative Officer and Chief Operating Officer. Now I know, I probably should say something at this point in time about Clint and Maurizio only because they are both sitting here at this room looking at me. But rather than sing their praises now I would rather do that after they prove themselves to you the owners of this company. But I would say that they have been a big part working with their teams and with their extremely capable colleagues, they have been a big part of this success for this company today. And suffice it to say that the three of us, Kevin, Bob and myself have total confidence that they will succeed in their new positions and they have our full support. So, with that I'll turn it over to Bob Flexon.

Thank you David and good morning. Today I'll provide our customary review of the fourth quarter and full year 2007 financial performance, update our guidance for 2008, and set forth our 2008 capital allocation plan along with the necessary implementation steps. Also in response to request for the first time I'll provide adjusted EBIT information on our portfolio assuming a limited to unhedged position. Slide 12, provides an overview of our financial performance and plans. 2007 adjusted EBITDA of $2.28 billion was well in excess of our initial 2007 guidance of $2.05 billion with $20 million below our November 2007 target of $2.3 billion primarily due to the impairment of two commercial paper investments and higher than expected outage cost in December. Although full year adjusted EBITDA came in slightly below November guidance, our free cash flow from recurring ops exceeded our November target coming in at $1.25 billion. The 2007 recurring free cash flow yield was a very healthy 12.8%. As we typically do, our capital allocation plans for 2008 are off to an early start with the December 2007 launch and January 2008 completion of $100 million of common share repurchases. In addition, our Board authorized in February 2008 an additional $200 million in share repurchases, which we expect to be complete by November 2008. On December 31, 2007, we prepaid $300 million of our term loan B, by doing so we achieved a corporate debt to corporate EBITDA ratio as defined in the credit agreement below 3.5 to 1. By achieving this threshold the company benefits by receiving a 25 basis point step down and the interest rate charge from $2.8 billion term loan B and $1.3 billion synthetic LC facility. Slide 13 provides additional high level financial comparisons for the 2007 results. The left hand side of the slide shows the free cash flow and the primary reason for the actual result is $75 million higher than guidance excluding collateral. As I noted a moment ago, the free cash flow yield on primary shares outstanding was 12.8%, while the fully diluted calculation resulted in a yield of 11.2%. Adjusted EBITDA for 2007 was $2.279 billion, a 52% increase or $779 million higher compared to 2006. We were $21 million below guidance mainly due to the commercial paper impairment of two investments and higher than expected outage cost. Liquidity has improved dramatically from last year while our net debt-to-capital ratio also showed significant improvement as compared to 2006. For a more detailed look at the fourth quarter results please turn to slide 14. The fourth quarter 2007 adjusted EBITDA results increased $182 million to $518 million compared to 2006. The current quarter revenues and margins benefited from $169 million increase in the Texas region from the November 2006 contract hedge reset. Energy margins for the quarter increased by a $149 million as the increase in revenue from the hedge reset was slightly offset by lower prices from bilateral contracts and other merchant energy sale. Generation in the Texas region was up a net 297,000 megawatt hours, this increase in generation quarter-over-quarter reflected exceptional operating performance at STP contributing 577,000 megawatt hour increase, which was partly offset by reduced gas plant generation as slightly lower coal fire generation from unplanned outages at Limestone and WA Parish. The Northeast reported improved results compared to 2006 for the fourth quarter adjusted EBITDA of $113 million, a $51 million increase from the $62 million reported in last year's fourth quarter. The quarterly adjusted EBITDA improvement was driven by increased energy margins and capacity revenue. Energy margins benefited from higher prices and increased generation. At Indian River, generation increased 23% as demand rose from favorable pricing in colder weather in December. While the generation increased 96%, while capacity revenues in the northeast region increased by $26 million for the quarter mostly due to the transition capacity market in EPU which started in December of 2006 and the new RPM capacity market in PJM, which started in June of '07. South Central's fourth quarter adjusted EBITDA declined by $35 million compared to 2006. Energy margins were $30 million lower during the quarter mostly due to the major plant outage of Big Cajun unit 3, higher coal cost, and higher transmission cost. The outage resulted in lower merchant sales and required increased purchase power to fill our load requirements. Development expenses in the fourth quarter are $28 million lower than the fourth quarter of '06 as we received a $39 million reimbursement from our partner CPS for development expenses for the STP 3 and 4 nuclear project. As I noted earlier, we recognized during the quarter an $11 million impairment on two commercial paper investments. These losses on previously highly rated paper were triggered by the liquidity constraints in the money market at the time of the fall and the issuers inability to refinance its maturing commercial paper. Our cash is currently invested in money market funds backed by U.S. treasuries. Our full year's earnings comparison are illustrated on slide 15, our adjusted EBITDA excluding mark-to-market activity grew $777 million with many of the same factors that influence our three month comparisons also appearing in the 12-month comparison. Again the Texas revenues attributable to last November's hedge reset and the Northeast capacity revenue programs and the significant increase in development spending are the primary factors. These and other key contributors to the year-over-year improvement include $123 million and $8 million for the full year inclusion of Texas and West regional results respectively. $594 million from the year-to-date impact of the hedge reset on Texas contract revenue, $170 million higher Northeast margins due to the combined impacts of higher generation and higher realized prices within the region. $130 million of increased capacity revenues of which $80 million was in the Northeast and $65 million increase in net development expenses mainly to support STP coal submission, which was a net cost after reimbursement of $52 million in 2007. In the Texas region again from the hedge reset, higher base load generation of $1.4 million megawatt hours and higher merchant margins on bilateral fields executed by our comm ops group helped to offset 35% decline in Texas gas generation and reduce contract revenue resulting in increased energy margins of $577 million year-over-year. O&M expenses within the Texas region increased by $30 million mainly due to increased average and other cost at our Parish facility and the gas plants and increases in property taxes. Northeast gross margins benefited from 6% increase in generation due to colder weather in 2007 versus 2006, higher realized prices, increased capacity revenues, and increased generation at afforestation. Average realized power prices in the Northeast rose an average 9% compared to last year. This combined with 6% increase in Northeast generation lead to $170 million increase in energy margins. Capacity revenues in the Northeast increased by $81 million in 2007 when compared to 2006, $39 million in EPU primarily from new LFRM market in transition, capacity payment introduced in the fourth quarter of '06, $36 million in PJM mostly from the IPM market which started on June 1, 2007. Net sales of excess emission allowances for the entire company decreased by $32 million due to the combination of increased generation in the Northeast and decreased market prices. Development cost for Repowering projects totaled $101 million including $52 million for STP after recognizing the $39 million of reimbursement and $17 million for wind project. G&A cost increased by $26 million year-over-year exclusive of January 2007 for Texas, due to higher wage and benefit cost triggered over the higher corporate head count and wage benefit increases. Franchise taxes in Louisiana increased by $5 million, due to the higher levels of the company's capitalization from the Genco acquisition. Free cash flow generation remains the core strength of this company as illustrated on slide 16. Although slightly below adjusted EBITDA guidance, free cash flow from recurring operations was $38 million higher than guidance primarily due to $43 million in higher than forecasted working capital improvement fully offsetting the $37 million greater than expected collateral requirements and $21 million in lower maintenance CapEx primarily due to project delays and lower than expected cost. Recurring free cash flow yields for 2007 were 12.8% and 11.2% on basic and fully diluted shares outstanding. Repowering CapEx was lower than guidance due to the timing of wind power investments. As shown on slide 17, the combination of the free cash flow results in our active management of the balance sheet and credit facilities resulted in the company's 2007 year-end liquidity increasing over 2006 by nearly $500 million. Even more impressive is that this increase is net of the $200 million reduction we made to the LC facility during 2007. Primary cash uses during the year included debt repayments of $408 million and common share repurchases of $353 million. As we reported in Q3 the company now has the rate under its credit agreement to grant a first lien collateral position to commercial trading counter parties. During the third quarter, existing counter parties are transferred to a pari-passu first lien collateral position from the second lien position in exchange for the return of previously issued letters of credit. This transfer resulted in the return of $557 million in letters of credit. Since year-end an additional counter party has moved to the first lien position resulting in an additional $65 million of LC's being returned to the company. Our initial 2008 full year adjusted EBITDA outlook provided last November was $2.2 billion as shown on slide 18. To reflect the planned sale of our Brazilian subsidiary ITISA, we are removing the prospective second 2008 adjusted EBITDA contribution from our current year's guidance. ITISA had been expected to contribute approximately $40 million to the 2008 guidance, therefore our 2008 adjusted EBITDA guidance from recurring operations is now $2.16 billion. Our cash flow from operations guidance for 2008 remains at $1.5 billion, despite the drop in EBITDA from ITISA. This is due to an expected $42 million increase in return collateral compared to the $3 million return originally estimated. The decrease in cash interest cost reflects the extension of our non-recourse sub CSF 1 which I will cover shortly. Forecasted maintenance CapEx decreased by $17 million as we finalize our 2008 capital spending plan. The changes in environmental and Repowering investments from initial guidance are related more to the timing of projects primarily wind power rather than project scope changes. In response to request, slide 19 is a high level look at market EBITDA across our portfolio. While the application of market or open EBITDA varies from company to company, our objective here includes being transparent on items included, excluded, and how the numbers are derived. On the left hand side is our 2008 guidance which is based on market price curves adjusted for the hedged profile of the portfolio. At the bottom towards the right indicates the 2008 adjusted EBITDA guidance at 2.5 to $1 billion reflecting for the most part an unhedged profile using price curves as of December 31, 2007. The three budge to bridge the difference represents the impact of three primary groups of hedges; financial derivatives, normal purchase and sales contract, and South Central load contracts. The value ascribed to each of these three bars are based on December 31, 2007 market base price curves contained in our highly controlled risk system that supports our financial statements as well as our risk monitoring system. The indicative market price that is used at December 31, 2007 are shown in the grey box at top right hand side of the slide. In reality, hundreds of specifically tracked price curves within our risk valuation and monitoring systems are used to value the underlying positions. I have included the same indicative code of price curves as of February 25, 2008 as a comparison to the curves of December 31, 2007. Using the sensitivities provided in the blue box, you can adjust the market EBITDA for the various curve movements, for example the impact for the natural gas and coal price changes between the days of December 31, 2007 and February 25, 2008 results in the market EBITDA of $3.17 billion or $647 million increase. The EBITDA ratio in this example would be approximately 5.6 times. For clarity of disclosure certain contracts and transactions were excluded from the market EBITDA calculation such as the west region tolling agreement, the RMR contracts in EPU, nuclear fuel contracts, transportation contracts, and certain transmission contracts. The net derivative assets that are in the money in 2008 flip to a liability in subsequent years for a total net derivative liability of $473 million. The roll of schedule of the derivative liability is disclosed in our 10-K. The normal purchase of sales contracts which include coal, power and capacity contracts are below market at December 31, 2007 by $573 million with nearly 9% of the contract rolling off by the end of 2009. Going forward we will assess the value of providing this type of disclosure along with ways to improve it in future calls. Slide 20 provides a review of the capital allocated in 2007, consistent with our philosophy of pursuing a balanced approach highlighted are our primary allocation objective. During the year NRG invested almost $300 million in the existing fleet for maintenance and environmental CapEx and a light amount for RepoweringNRG initiatives including both direct investment and development spending. Simultaneously NRG continued to return capital to both debt and equity investors in roughly equal amount by repaying $408 million in debt and buying back $353 million in common stock. As outlined in the past our objectives continue to target a net debt to capital ratio of 45% to 60% of maximum corporate debt to corporate EBITDA ratio of 3.5 and return of capital to shareholders of approximately $250 million to $300 million per year. Slide 21 provides the capital allocation plan for 2008. As we begin 2008 our objectives remain the same, achieving balance across the program. Due to increasing environmental CapEx requirements we expect investment in the existing fleet to increase to $563 million net of tax exempt financing. At the same time we anticipate investing $321 million in Repowering growth initiatives net of non-recourse financing. Concerning debt management, NRG is committed to offering $446 million to its first lien lenders as part of an excess cash flow offer provision in its existing credit agreement and paying down an addition of $129 million in other debt primarily a capital lease. Since we believe that our lenders would accept a 100% of the required excess cash flow offer upon filing of our 10-K, we accelerated the repayment of our term loan B debt and prepaid $300 million on December 31, 2007. As a result of this payment we achieved the required leverage ratio resulting in a 25 basis points reduction, $300 million pre-payment will be credited against the required offer to first lien lenders resulting in a $146 million offer to lenders in the first quarter. For the capital return to shareholders, we also accelerated the initiation of the 2008 share buyback plan by purchasing $100 million of common shares during December and the first week of January 2008 at an average price of $41.99. In February 2008, the Board authorized to purchase an additional $200 million in share buyback bringing the total 2008 program to the targeted level of $300 million. We expect to complete these three purchases by November 2008. In order to have the necessary restricted payment for our free capacity under bond indentures to complete the authorized share repurchases, NRG and Credit Suisse have agreed to extend the maturity date of CSF 1 from October 2008 to June 2010, while the maturity date of the CSF 1 debt is being pushed out an additional 20 months, the call options in the structure will expire during November and December 2008, an extension of 30 days enabling the restricted payments capacity addition from the third quarter 2008 net income to be available for option settlement. By pursuing this refinancing NRG retains 100% of the upside associated with CSF I structure after the option settlement and shift the use of the RP capacity from debt repayment to common stock repurchases. As we look forward we see a clear path generating sufficient restrictive payments capacity to facilitate the return of at least $300 million prior to shareholders in 2008 and 2009. As slide 22 illustrates, with the natural expansion of the RP basket in 2008 from net income that was expected to be greater than $300 million combined with CSF I debt extension to 2010, we have sufficient RP capacity to complete the additional $200 million in share repurchases during 2008. The remaining capacity in 2008 currently estimated a greater than $130 million after settlement of the CSF I call options coupled with significantly higher basket additions in 2009 due to a higher expect net income to provide adequate RP rooms to deliver our targeted return to shareholders next year as well. Should additional capacity be needed NRG may consider extending the maturity of the CSF II structure currently scheduled for October 29 or may pursue other alternatives if March conditions allow. As my tenure as CFO at NRG is done, I am certainly proud of the many accomplishments our team has achieved recognizing that many more accomplishments remain in our future. As CFO I have had three goals [indiscernible] NRG in March 2004. Build a best in class financial team and control infrastructure that safeguards the investments of our stakeholders. Prudent balance sheet management that provides an ongoing returns to debt and equity holders and deliver our numbers. The people within CFO organization are very talented and very dedicated while time doesn't permit me to individually name everyone I would like to recognize for their contributions, I do want to recognize three of my direct reports who have been with me from the start; Carolyn Burke, Jim Eanglsti [ph] and Raymond Sword [ph]. I look forward to my new responsibilities, knowing my previous roles is in very good hands with Clint Freeland at the helm. I will now turn it back to David.

Thanks Bob. I know we have already taken up a great deal of time and those of you who were looking at slideshow are experiencing an anxiety that we are going to turn this into a Fidel Castro length earnings call. And as you look at those I know, if you don't need it I could spend an hour of course talking about these. I promise you now that I am not going to do this. Each of these things is highly important to our strategy and to the success of processes. Well I am going to say this, we are going to come back with this... whether industry or banking accounts for the response we ordered and we will find it and an appropriate formulation after all these topics has been thoroughly secured and if time is appropriate let me just make a few comments on these on the page starting with slide 24. As you all know and as you all are experiencing, in times like this when the rate is negative, that people see the negative view volatile portion. That is why I believe in NRG stock that is sort of target. And there are couple of things, but first any private legislation can be enacted is effective in financial advantage. I will walk into the end of next decade, it has to be and if we do nothing. And unlike many other companies, we chose not to adopt wait and see as we are aggressively pursuing compensation strategies that I outlined clearly at this time. Impending a carbon regulation from a very modest negative to a significant positive in the long term. Worth of a lavish focus on carbon has overlooked over the past few months is that there at least four dynamics underway in our industry, which are more immediate, more certain, and more impactful of carbon risks and all 4 of them are highly and inherently positive to NRG. These four are higher 4 gas prices, higher heat rates, new sources of capacity payments and the other increasing cost of new entrants, which tends to lift all boats in directly when it comes to income empowered generation. Not only are these four trends positive for NRG but we are not just a passive price taker with respect to these trends. As we try to depict on this slide we are pursuing a variety of programs make sure that we capture these trends to the fullest extent of our potential. One of the ways we do that is through RepoweringNRG and turning to slide 25, I want to actually start here with a bit of housekeeping. We announced this program in June of 2006 with an initial line up of 19 projects comprising 10,000 gross megawatts and costing at time an estimated $16 billion. While we said at that time that was a dynamic program and the projects would be added and others would be dropped and that we certainly would not achieve 100% success and I believe the analyst in the markets understood and believed all that. The original numbers that we have attached to the program, the 10,000 megawatts and the $16 billion, we fear is becoming etched in stone. So, to avoid that we are updating this list and we intend to do this once a year, and we are calculating the current estimate of the cost of the program. And there are three and so you can see that on the slide and there are three main points that I think you should take away from this update. The first is that while there is no definitive trend in the make up of the program our portfolio of new projects is definitely trending from black to green, from coal to new carbon. Second, is that true to our word we have been disappointed by our investment and we have dropped development projects that did not meet our risk profile or return criteria. A case in point is Big Cajun II-4 which was a fully permitted large scale traditional co-plan where which we dropped because we are only able to contract 450 megawatts out of 700 megawatts of name play capacity and that wasn't enough. And third, while the cost of building new generation has definitely gone up over the past two years as you can see from our estimate here, if you strip out risk premium and profit margin, the price of building things in this country has not gone up as astronomically as many have indicated. The overall team points I'd like to make is the development of power business particularly with these new technologies is a very long lead time item. We have made great progress over the last two years in terms of our development program and even more so in terms of our internal development capabilities. And now I think we have first mover advantage and I think one of the things you should be looking to us in the year ahead to show is how we are going to build on that first mover advantage and how we're going to turn that first mover advantage into shareholder value now not just several years down the road. Turning to slide 26, since the nuclear project is the centerpiece of our development effort, I want to give a kind of assessment... as a kind of where we are at. This is particularly the case because as many of you are aware, the Nuclear Regulatory Commission set aside a portion of our combined operating license application until we could provide proper support to those sections. They took this action at our company's specific request. Now to step back a little, at the outset of our planning for nuclear development we've identified the single most important issue as being determined who will take commercial and technical responsibility for building these new plants on a fixed price, fixed schedule basis. We've reasoned that such an arrangement would most likely only be available from someone who actually had successfully completed a new nuclear plant of the same design. That is what led us to the ABWR design which was first built in Japan in 1996, and that is what led us to Toshiba and Hitachi which are the only two companies in the world that had built an advanced nuclear plant on time and on budget. It turns out that we were extremely prescient in our thinking. It has become increasingly apparent and should be apparent to any of you who were trying in one way or another to invest in the so called nuclear renaissance, that the issue that is right now threatening to slow or stall the nuclear renaissance in the United States is not a regulatory problem with the NRC. The NRC has been tough but fair and they are extremely responsive. If not the rest of the government since spoke of legislative and executive branches now done virtually all that's been asked of them. What is threatening to slow or stall new nuclear in this country is whether the private sector in the United States, does it have what I call the will to build and let me emphasize that when I say slow to stall that was something about the nuclear renaissance in general and when I talk by walking the world to build I was referring to the industrial manufacturing and construction complex in the U.S. And that I want to remind you is why we went to Japan in the first place and to the companies which have actually done this work successfully with project managers and schedulers who are still in the business. In any case we are currently in the middle of finalizing the commercial arrangements with respect to engineering procurement and construction arrangements for STP 3 and 4. Those discussions are going very well but, even when working with people who had built these plants before, these are highly complex and important negotiations on sorts of levels and we would rather sacrifice a few months of permeating time while we get the arrangements right rather than burning the project with excessive cost or assume unmanageable completion risk as the owners of the plant. We recognized that we owe our stakeholders a full briefing on the RepoweringNRG and general on STP 3 and 4 in particular. We expect to be able to provide that detailed briefing some time in the next few months. At that time, with respect to STP, we expect to be able to provide you with substantial clarity as to the ownership off taken EPC arrangements, the base case project economics, the financing plan, and the path to regulatory approval. I'm confident that we are on the right track. Moving ahead, we add another zero carving developing pipeline on slide 27, actually today as speak we celebrate with British Petroleum in Texas for ground breaking of our first joint development project, the 150 megawatt plant at Sherbino which will be online by the fall of this year. We've other projects in advanced development and expect to announce other locations not too far in the future. The wind is an important part for both our RepoweringNRG and eco-NRG initiatives, and I couldn't be more pleased with what Jan Paulin and his team at Padoma have accomplished to-date. With the future prospects that they have in the pipeline and with the entrepreneurial developer ethos that they had brought to NRG. In closing there is a lot going on at NRG, as always and in terms of the potential value enhancement, ours is a target rich environment. We've listed on this last page some of our vehicles to capture this value and to echo my comments, at the beginning of the session we can enroll over the next several months pick up these topics with you one by one and cover them in much greater depth. But in many ways today's call is about management. I'm convinced we have the best management team in the business and today we are promoting and redeploying not only Bob Kevin, Maurizio and Clint, but several other key managers who are shifting their position or responsibilities as well. Each and everyone of us at NRG takes very seriously the premise that when you invest in NRG, you are investing with management and also with the 3000 highly capable individuals who made this company hum in 2007. So, with that operator, I think we have a few minutes for questions. Question And Answer

Thank you, sir. [Operator Instructions]. At this time, our first question will come from John Kiani of Deutsche Bank. Please go ahead.

Good morning.

Good morning, John.

Congratulations on the promotions.

Thank you, hold on I'm sorry, you meant Bob.

I have some questions on slide 19, the market EBITDA slide. Bob, you were walking through this slide, if I am reading this correctly the 3.16 billion of market EBITDA using call 09 curves, it is just using the forwards curves. Do you have any numbers or analysis that you can share with us as to what that 3.16 billion of market EBITDA would look like with heat rate expansion and market recovery, some of your IPP peers show this figure, not with just the current forward, but what it looks like under market equilibrium type scenario, do you have any guidance or help you can give us on that?

Yeah, John included the sensitivities so if you look in my blue box on that slide, the last two lines in the blue box show the sensitivity around heat rates. So if you get a half heat rate improvement as an example, say an ERCOT [ph] you got an upside of about $200 million on an un-hedged power basis. So the sensitivity is right there, you can just pull it off the prices that are given in the grey box, come up with your own what you think heat rates could do and then you got the sensitivity there on how to do the math to adjust the EBITDA number from there.

Okay. Thanks and then, on the restrictive payments basket... I think you made some comments that '09 looks like... looks to be a year where you have incremental or better RP capacity, can you walk through that in a little bit more detail?

Sure, John when we filed the 10-K today, we will have the chart updated on our base load hedges that go up 2012 and the natural gas hedged price if you will on that chart for 2009 at a 73% hedge profile, the $7.70 which is $0.20 higher than what it is in 2008, plus you got 20%... 27% of the base load open. So, if you just take that higher hedged price in '09 versus '08 you are going to get a significantly higher net income in 2009 and 2008 and the basket expands based upon the net income calculation.

I see. Okay, thanks. That's helpful.

Thank you. And at this point, our next question will come from Elizabeth Parrella from Merrill Lynch, please go ahead.

Yes, thank you. Actually following up on that same line of questioning, Bob, your comments with respect to the RP expansion this year, does that assume no unrealized losses on mark-to-market activity or is that based on what you see those losses would be using the forward price of gas, how should we think about that?

It's based on our forward view of net income, which is... which we just strike... when we strike that curve we don't forecast what mark-to-market gains and losses could be going forward. So, that will create some noise in the numbers on the net income. So, that's why... and that's one of the reasons Elizabeth that we leave as much room as we do while we show that 2008 will have greater than 130 million or actually be fairly higher than a pretty significant increase over that 130 that I show but that is kind of the cushion that we keep to be able to absorb changes caused by those types of fluctuations.

I mean that assumes I just wanted to be clear that assumes you would look to mark-to-market losses, which one would expect given where your hedges are for gas and where the current gas price is or does it just zero those out for the remainder of the year?

Yeah, I mean the way you need to look at that as well as make sure that greater than 300 million expansion, that's the fourth quarter of '07 result and then the first three quarters of 2008. So, you weight that risk on the next three quarters.

Okay. Okay, and then just with respect to the deal with Credit Suisse on rolling this out, if I understand it correctly their upside kind of a cap as of December end, they don't get anymore upside as the stock continues to move up?

Yeah, we are going to let the GAGR feature or the option feature in that structure, we'll settle that out in the fourth quarter. We are not going to roll that into the future. So, it would just be pure debt beyond November of this year and then we'll just settle that out and we'll keep a 100% of the upside of any share price movement within that structure.

Right. Now, my recollection is I think you accrue the interest on this sort of through October of 2008, if now there is going to be additional interest expense associated with rolling this out another 20 months?

Correct.

At the sort of same type of rate?

Yeah, actually the way we are structuring it is that we are going to... it is going to be a pretty much exactly the same rate. It would be the blended cost of like 7.5%.

Okay and then, just one another question. The hedging profile that you have given us on slide 7, you mentioned what the average gas price was for '08 and '09, is that going to be disclosed in the 10-K for all the years in that?

It is... it is disclosed and I think the slides that we showed earlier on the hedged profile, I believe... it is as of the end of January. And I think that matches up with our K.

Okay. Thanks very much.

Thanks.

Thank you; and our next question will now come from Michael Lapides of Goldman Sachs. Please go ahead.

Hi, guys congratulations on a great year. Can you provide a little bit of update on longer term bobs regarding your environmental CapEx on existing co-plant?

The... my consent, longer-terms, how long a term did you... I mean behind the multiyear...

Yeah, just in terms of what's contracted, what's not contracted, what you are saying in EPC cost?

Okay. If you want to?

Well, the environmental CapEx project for 2008 is 359, of that 359 about 223 is from Northeast. That construction is pretty well, it's under way and it's pretty well locked in. So that pretty much covers 2008. Towards the end of 2008, the South Central will start picking up and then in 2009 it becomes the higher level of spend. I think we are in the beginning process as of now of time most cost down, so that's in an earlier stage and then further out, the one that... really the one that up in the air right now is Indian weather which carry a pretty high environmental CapEx cost that's the very early stages and we're still wrestling our own minds whether or not we're going to make that level of investment or not. So, that's still up in the air.

What are your options if you decide not to make the investments in the divestiture?

Well, I mean...I think everything is on the table. We're going down certainly the path of making the investment, we're doing the permeating work that we need, so we are not delaying anything there. So, we're retaining that option to make sure that we do have time to make the environmental improvements but if we decide at some point that it is just not economic, the choices then are either you just run through the end date or you sell it or you look for some type of alternative plans for the site whether it's other forms of generation. So, I think everything is on the table with it. When you had this type of standard, this level of spend you are going to look 4 or 5 different paths to make sure you take the most favorable one from an economic standpoint as well.

Michael, just to add a little bit to that, it is difficult proposition for the Delmarva Peninsula, which is obviously geographically a peninsula is that there is definitely discomfort in that area with cold fire generation of any type as we found over the last year. But there is no gas pipeline down there. So, the options are pretty limited so that's the issue that not only we need to struggle with but, the people charged with maintaining responsibility for the grid in that area have to struggle with as well.

Got it, thank you guys, much appreciate it.

Thanks, Michael.

Thank you. And our next question will now come from Ryan Chin of Citi, please go ahead.

Hi, question on the market EBITDA slide, or South Central load contracts, and please correct me if I am wrong on this, but there were, if I remember on a couple of environmental CapEx provisions on those contracts, how is that embedded in your 1.2 billion number or is the 1.2 billion just the delta between the current contractual sales price in the current quarter?

Brian, it's the ladder, I didn't do anything to adjust for the environmental CapEx spend in the pass through. I am just literally as you describe just using current market price versus contracted market price.

Okay. So, if I want to think about this in an open EBITDA framework, what I probably need to think about then is what is the value of the environmental CapEx provisions that you have in those contracts as a reducer to the net present value negative impact of this contracture value here, is that correct?

I think that's correct Ryan, I would do that.

And then one other thing, just a qualitative question. Is that the ABWR [ph] contract at South Texas point from GE and then you have Toshiba and more pouring the concrete effectively. Given that Toshiba earns the Westinghouse house design, how has managing that relationship between those two camps been, can you comment on just what has been going on there, has there been any problems?

Well, Ryan we can comment on a little of it and most of it we can't comment on. What we can comment on is that you are right while Toshiba is also the owner of the AP1000 design, at no point in our dealings with Toshiba have we have ever seen any sense of compromise or priority of one over the other. I don't know how much you follow nuclear in Japan but ABWR is the chosen design of the Tokyo Electric Power Company and Tokyo Electric Power Company and the rest of the Japanese utility industry are quite insistent that Toshiba and Hitachi both support the ABWR design now and into the future. So, we have been 100% pleased with Toshiba's support and interest in the ABWR design, whatever they are doing with the AP1000 and the rest of your question about... I really rather not comment on at this point.

Fair enough, thank you.

Thank you. Our next question will now come from Gregg Orrill from Lehman Brothers, please go ahead.

Good morning.

Good morning Gregg.

Just coming back to slide 8 on the heat rate sensitivity, two questions, the first is you provided the sensitivity around one end in Btu per megawatt hour around the clock heat rates, how far do you think we are between now and for your base load fleet? And then secondly you left on the table the upside or the mid meridian [ph] and peaking part of your fleet, what would that also entail?

Well I am going to pass on to Kevin so he can give you on this patented/total non answers to that question.

Okay, when I think about it I mean clearly I think we saw along that we are still... rates which has led to our bias towards gas hedging against the fleet particularly in Texas and you know we have seen a nice recovery the rate still bullish from this point forward we are the absolute peak ins, I really don't want to get the same, what we think is left to the market but we are still bullish from this point on the heat rates and I am sorry what was the second part of your question?

You provided the sensitivity on base load to heat rate changes, what about the rest of the fleet just so that we can be comparable to what other companies are providing?

I think, remind me Bob, I think in the past we have kind of notionally said we think about our peaking assets as more kind of out of the money options that they tend to come into the money very quickly for short periods of time but try to model those in the forward market, you really don't throw off a lot of value from them. I think initially we have talked about those, the way we think about them in our forward guidance is around 100 million.

On the intermediacy of peaking, on the gross margin it's around $100 million to $150 million and if you had a heat rate movement of about 1 unit movement, the sensitivity is that is in the order of magnitude of around $60 million sensitivity.

Okay, thanks.

Thank you and our next question will now come from Anthony Crowdell from Jefferies.com. Please go ahead.

Good morning, this question is on New York City capacity market, are you seeing any changes in the capacity pricing and now that you see I think public service in New Jersey is trying to bring a line in to the New York City market and have you noticed any changes in the capacities?

Yeah, yeah our view is and I think we have the information on one of the web pages in here that we are seeing definite softness in the New York capacity market. It is already trending down. So that's the one soft spot in the terms of the Northeast capacity markets where all the other capacity markets were in... we are seeing strength and increasing strength but New York City is definitely trending down. That actually if you look at the tables at the top right hand-corner of page 7 you'll see some numbers on that.

Thank you.

Thank you and our next question at this time will come from Dan Eggers of Credit Suisse.

Just wanted to follow-up on the opening conversation just given by the breadth of where it looks, where it could be from where it is today, have you guys considered another hedge reset and is the market available to do that if you looked at it?

No, no we haven't looked at that and so that is not in our plans.

Okay, the next question is Exelon's proposed nuclear power station impacts us, it also has an ownership agreement with San Antonio, how does that affect your agreement on South Texas are we just seeing San Antonio being the power hungry right now?

You know, I don't want to know all the much obviously about the arrangement that San Antonio has with Exelon but certainly my general sense about the Exelon development is that they are tracking to quite a different timeframe from where we are in terms of the path that they are on. Obviously I don't want to speak for them but it just seems that the pace that they are going about it and going with the design, the sort of more futuristic design that has never been built before, I think they are trending towards the end of the decade rather than the middle of the decade as we are so. As far as I know the load in San Antonio grows quite quickly so it would be up to San Antonio but I don't see anyway in which they are sort of saying this it is either STP 3 and 4 or the Exelon 1. I would see probably more that they think about it is that they are load... base loads for 2 different time periods.

Thanks.

Operator, I think we probably... it's about 10 minutes after an hour, we probably have time for one more.

Certainly sir and our last question will now come from Nora Schonafi [ph] of MSF, please go ahead.

Good morning.

Good morning Nora.

A couple of quick questions, what is the expected cash tax rate for '08 and '09?

For 2008 I would use the, we have a forecast for 2008 of $27 million in cash taxes, for 2009 I'm using for our planning services a 25% cash tax rate and for 2010, I would use a range from 30% to 35% for cash taxes.

Okay, can you also just talk about what the major outage schedule is in 08 and '09 on the major plan, like STP or what have you?

Well, I know on STP that... they actually have two outages in '08 so that's a rare year. Beyond that I'm trying to think of anything else that is exceptional and John is there anything in the Northeast that strikes you as different year-on-year.

Well, in the fall of this year we will be doing the Hartley [ph]. The Hartley outage would be a little longer the one the back house installations. Other than that everything is fairly normal.

Yeah, is there something more specific that you are concerned about?

No, just wanted to be able to track that schedule.

I think the main year-on-year changes with STP, because with the 18 months schedule for 2 units their time is when they get through a whole year without one and then there are years where they have one and there are years like this one where they have two. So, given how many megawatt hours, that one is pretty significant but beyond that I think it is a pretty normal schedule.

Okay great. Last, but not least, I was just wondering, there has obviously been a fair amount of wind projects announced, in Texas particularly in West Texas. There is some reliability issues there, I guess there were even some yesterday on the overall wind side, how do we think about the expected heat rate expansion and just the overall reserve environment in ERCOT [ph] vis-à-vis some of the... all the noise around on the wind side?

Well, I think... I think you've raised a very important point and one that... obviously a highly topical after yesterday's wind event in Texas and you know I can't give you 100% clarity though. We look at it obviously from both sides, the impact on our fossil-fuel fired fleet and the fact that our subsidiary is successfully developing wind into that market. You know, I will make a couple of comments first in terms of what our overall portfolio, what we wanted to look like, we want to have wind in the portfolio, but I don't think anyone on the phone should think of NRG as becoming a wind play. We see wind is complimentary to our fossil-fuel fired plant and we look forward to sort of folding a few wind firms into the sort of seamless operations of our Texas fleet. The question that you've raised and that I was highlighted by yesterday's event is, I think a huge one for ERCOT, you know the system can go unstable because in the winter because 1500 megawatts of expected wind turns into 400 megawatts winds and then fossil has to scramble to come online and with several of our plants that had to scramble to fill the gap, that's a big issue and there is going to be a big debate. I think you probably read that ERCOT is commissioned to study, to try and decide how much transmission they should bring from the West Texas wind area into the markets and I think the question how you maintain systems to build in the face of massive wind portfolio is a big one. And so, I think that's probably the single biggest policy issue that... that's going to be addressed in any of our markets over the next 12 months. I know that's not an answer but that's the best I can... all I can tell you that we are fully engaged in thinking about this on all levels and obviously we'll provide our input whenever we can to whoever will listen.

Okay, Thanks again. I just wanted to say congratulations to Bob, thanks for doing such an awesome job over the last couple of years.

Great. Thanks Nora.

Okay, operator, with that again we appreciate everyone's effort, interest in the company and look forward to telling you next quarter.

Thank you. Ladies and gentlemen, this does concludes your conference call for today. Once again thank you for participating and at this time we ask that you please disconnect your lines. Have yourself a great day.