NRG Energy Inc (NRG) 2008 Q2 法說會逐字稿

Good day, ladies and gentlemen. Welcome to the NRG Energy second-quarter 2008 earnings results conference call. I will now turn the meeting over to Ms. Nahla Azmy, Vice President, Investor Relations. Please go ahead.

Thank you, Jennifer. Good morning and welcome to our second-quarter 2008 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 for the SEC through a link on the Investor Relations page of our website. A replay of the call will be posted on our website. This call, including the formal presentation and question-and-answer session will be limited to one hour. In the interests of time, we ask that you please limit yourself to one question with just one follow-up.

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 July 29, 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, the most directly comparable GAAP measures, and a quantitative reconciliation of those figures, please refer to today's press release and this presentation.

Now, with that, I would like to turn the call over to David Crane, NRG's President and Chief Executive Officer.

Thank you, Nahla, and good morning, everyone, and thank you for joining us for this, our second-quarter 2008 earnings call, which is the 18th earnings call in the history of the new NRG. I'm joined here this morning by Bob Flexon, our Chief Operating Officer; and Clint Freeland, our Chief Financial Officer, both of whom will be giving part of the presentation. Also, by Mauricio Gutierrez, who runs our Commercial Operations group, and who will be available to answer questions to the extent appropriate.

So, let me start, and I will be referring to slides which appear on our website. Let me start with slide 4. Before I hand it to Bob, I'd like to give you my take on the highlights of our performance here today.

So, first, plant operating performance is the best it has been since I've been here at NRG, both in terms of safety and reliability. And that performance, I'm pleased to report, has been achieved across all regions and all types of plant.

Second, our Commercial Operations team has done a stunningly good job, both in capturing the value of our unhedged assets in real time, but also in adding another layer of baseload hedges during the period of high gas price volatility, which ended just recently.

And third, our financial team has steered a cautious course during a quarter in which the Wall Street contagion dictated caution and as a result, we easily weathered from a liquidity perspective, the mid-quarter spike in natural gas prices, which forced others in the industry to arrange emergency credit facilities. Indeed, during the second quarter, we substantially increased our net liquidity. I think this justifies our never-ending commitment to prudent balance sheet management, and I'm very pleased at the work that Clint and the team has done in this regard.

What all this means is that we achieved a first-half result that has enabled us to increase our full-year guidance by a substantial amount, while, as I mentioned before, at the same time building up our future profitability with hedges struck at price levels higher than we have generally realized in the past. In short, apart from the recent performance of our share price, there is precious little for me to complain about, either in terms of our current operating performance, or our future prospects. With that, I would like to hand it over to Bob Flexon.

Thank you, David. Like our first-quarter results earlier this year, the Company's operating performance during the quarter was outstanding. Slide 6 summarizes our year-to-date safety performance, the coal inventory position at June 30 and the quarterly and year-to-date generation.

Starting with safety, our recordable incident rate through June 30 was 0.92 versus 1.69 through June 2007, nearly a 46% improvement and top quartile performance as compared to industry average. Recordable incidents also declined over 40%, dropping from 27 through June of last year to 15 as of June 2008.

Over the remainder of the year, priorities for our safety program are the further development and use of leading safety indicators, preparing for and filing the applications for OSHA's highly regarded voluntary protection program for five of our sites later this year and early 2009, and continuing improvements to our preventative safety and reporting programs.

Coal inventories dropped during the second quarter to an average of 41 days on hand at June 30 versus 45 days at the end of the first quarter. The decline is primarily related to lower inventory levels at Big Cajun II and WA Parish facilities, resulting from rail and barge disruptions during the second quarter in connection with the Midwest floods and high water levels on the Mississippi. All shipping routes and modes have returned to normal operation and inventory levels are building at these locations. In addition to the transport issues, the baseload plants have improved their operating performance, resulting in higher consumption of coal.

Generation for the quarter and year-to-date increased over the same periods last year across all regions. The higher generation was attributable to higher demand for the intermediate and peaking generation and higher baseload generation due in part to improved reliability, which I will cover next.

Slide 7 provides quarterly and year-to-date equivalent availability factors and equivalent forced outage rates for baseload generation. In addition to the Company's employees safely performing their duties, the availability and performance results of our baseload fleet during 2008 has been equally extraordinary, leading the way for the achievement of our reported results.

All three regions with baseload generation have improved their year-on-year, quarterly and year-to-date forced outage rates, with the Texas and South Central regions achieving top decile performance levels. Highlighted on the bottom half of the slide is examples of reliability records being established daily across our facilities. Not included in this list is the potential that our south central region is on pace for, achieving their best annual EFOR at Big Cajun II in at least the last 15 years.

Reliability improvements have not been limited to baseload facilities but are also being achieved at intermediate and peaking facilities as well. Astoria, for example, with 520 MW of in-city peaking capacity for New York, has been called on nearly 900 times during the first half of 2008 and has achieved a start-up reliability rate of over 99%. Improved fleet reliability can be traced back to our FORNRG program, which is updated on slide 8.

Focus on ROIC at NRG or FORNRG, as it is known within our Company, is our cost and efficiency improvement initiative launched in 2005. The goal of FORNRG 1.0 has increased over time as we have hit our targets. Today, the goal is $250 million in cumulative improvements to pretax income and cash flows by the end of 2008. At December 31, 2007, $220 million of the $250 million have been achieved. For the first six months of 2008, an additional $21 million of benefits have been achieved, primarily through improved operations. Upon achievement of the $250 million target, expected by the fourth quarter, the Company intends to announce and launch FORNRG 2.0.

Turning to Commercial Operations on slide 9, unlike 2007, opportunities to add strategic power hedges in 2008 have been far more frequent. The second quarter experienced continued natural gas volatility and record prices. Taking advantage of this volatility and price environment, the Company added the equivalent of 18 million megawatt hours of power hedges in the form of power and natural gas sales during the second quarter. This follows the first-quarter addition of approximately 28 million megawatt hours of power equivalent hedges.

Natural gas prices which traded in the first quarter as high as $10 per million BTU, at $9.43 per million BTU for 2009 and 2010 calendar strips, traded higher in the second quarter with peak prices during the second quarter higher by $2.47 per million BTU and $1.81 per million BTU, respectively. With power hedges closely aligned to fuel hedges, the Company's dark spread is substantially hedged over the next several years.

Slide 10 provides the gross margin sensitivities to gas and heat rate movements on an equal probability basis. What can be distinguished by the natural gas and heat rate bar charts is the greater leverage natural gas prices are likely to have on the portfolio as compared to heat rates. Looking at 2013 as an example, the gross margin impact of natural gas movements is over 4 times greater than heat rate changes on an equal probability basis.

The additional hedges added during the second quarter have reduced volatility impact of natural gas movements on the portfolio's future gross margins. For 2009 and 2010, the portfolio gross margin impact for $1 per million BTU natural gas price change has declined over 20% and 25%, respectively, since the first-quarter call.

Texas heat rates have continued to compress over the course of the year. We believe drivers of the decline include new generation along with the uncertainty on wind generation and transmission, which David will address. And the exit of financial participants from the market for liquidity and risk reduction reasons.

Our view remains that heat rates are overly compressed, reflecting all bearish sentiments, and will need to increase to justify new investments. Supporting our view is our Q2 results, which benefited from our open heat rate position.

Slide 11 provides details in our plan for complying with the Regional Greenhouse Gas Initiative, or RGGI, effective in 2009. The 10 Northeast states participating in RGGI released guidance on the first allowance auction to be held on September 25 for the auction of 12.6 million allowances. Four of the 10 states -- Delaware, New Hampshire, New Jersey, New York -- will not be contributing allowances to this first auction. The reserve price is $1.86 per credit and no single entity can buy more than 25% of offered allowances. The next auction is scheduled for December 17, 2008 with auctions quarterly thereafter. The December auction is expected to offer approximately 30 million allowances.

The Delaware legislature passed legislation which enabled RGGI and granted transitional allocations of CO2 allowances to in-state electric generators, 40% in 2009, declining by 8 percentage points annually for five years. NRG was allocated approximately 1.2 million allowances for 2009. Net of these allocations, NRG is expected to consume about 13.7 million allowances in 2009.

The Company's compliance plans, in addition to granted allowances, are participating in the auctions and secondary markets while pursuing qualifying carbon offsets. To help defer the cash costs of compliance, the Company has been monetizing a portion of our excess carbon credits on the Chicago Climate Exchange.

Slide 12 highlights our operational focal points for the balance of the year. First and foremost, we'll be keeping our eyes on the ball and build upon our first-half successes in safety and operations to make 2008 NRG's best year operationally. We will deliver the FORNRG 1.0 savings target and meet our financial goals. Finally, we'll position ourselves to be successful in 2009 by preparing for the upcoming winter season and RGGI compliance. I'll now turn to Clint for the second-quarter financial performance review.

Thank you, Bob. Starting on slide 14, NRG built upon its solid first quarter with an exceptional second quarter, generating $683 million in adjusted EBITDA, a 30% improvement over the second quarter of 2007. As David and Bob have indicated, these results are primarily due to outstanding plant operating performance throughout the fleet and a flexible Commercial Operations strategy, which enabled the Company to benefit from recent market volatility. Cash flow from operations totaled $376 million, a 7% improvement over the $353 million posted in the second quarter of last year.

The cash flow story for the quarter, however, was somewhat masked by movements in cash collateral postings related to NRG's short-term hedge positions. Excluding these collateral postings, cash flow from operations rose 65% to $554 million for the second quarter of 2008 versus $336 million last year. Coupled with a stronger than expected performance in the first quarter, particularly by the Company's South Central and Western regions, year-to-date adjusted EBITDA is well ahead of last year, totaling $1.21 billion for the first six months, an 18% increase compared to $1 billion in 2007.

Cash flow from operations for the first half of 2008 was $436 million, down slightly from last year's $459 million. However, excluding the effect of cash collateral postings on both years' results, cash flow from operations increased 36% from $562 million during the first half of 2007 to $764 million in 2008.

During periods of high commodity price volatility, liquidity becomes increasingly important, particularly when managing a significant hedging program. Notwithstanding the posting of an additional $178 million in net cash collateral during the second quarter, and internally funding $245 million in capital expenditures, NRG's total liquidity rose by $276 million as a $420 million increase in cash balances more than offset a $144 million reduction in letter of credit capacity.

Based on the better than expected year-to-date results, today we're raising our 2008 adjusted EBITDA guidance from $2.16 billion to $2.3 billion. For the remainder of the year, we assume normal weather patterns and no material changes to the Company's existing hedge position. While adjusted EBITDA guidance has been meaningfully raised we're maintaining our cash flow from operations guidance at $1.5 billion as higher collateral postings offset increased adjusted EBITDA.

Moving to slide 15, consolidated adjusted EBITDA during the second quarter increased 30% to $683 million compared to $524 million in 2007. As is evident from this regional breakout, Texas was the primary contributor to the year-over-year gain as exceptional baseload plant performance, a 24% increase in gas plant generation, higher average merchant energy prices, and advantageous hedge positions came together to drive the region's results for the quarter. This, along with a $29 million reduction in development expenses, primarily the result of capitalizing STP 3 and 4 costs and an $8 million partner reimbursement, more than offset the impact of lower contract energy margins.

The West region's adjusted EBITDA doubled to $18 million during the quarter compared to $9 million last year. The $9 million increase was primarily attributable to capacity revenues generated by the Long Beach facility, which went into service August 1 of last year.

As you may notice, there is no bar for our South Central region, as quarter-over-quarter results were virtually flat. Increases in capacity revenue from new peaks set in 2007, higher contract revenue from fuel pass-throughs to co-op customers, and increased generation was offset by higher purchased power, increased transmission costs and unrealized losses on forward physical sales.

Adjusted EBITDA for NRG's Northeast region decreased $18 million quarter over quarter from $131 million in 2007 to $118 million in 2008. During the quarter, the region benefited from a 6% increase in generation, primarily at Indian River and Huntley, and a 9% increase in net capacity revenues. This was more than offset, though, by a combination of lower net contract revenues as the costs to serve those contracts rose in line with market prices and higher coal costs at our Indian River and Somerset plants.

As you know, we routinely adjust our EBITDA to add back the impact of unrealized mark-to-market activity, whether positive or negative, related to asset-backed positions that are economic hedges of our portfolio but do not meet the accounting requirements for deferral under cash flow hedge treatment. The dramatic change in commodity prices seen during the second quarter had a meaningful impact on the value of our hedges as shown by the $543 million non-cash mark-to-market loss, as shown on the slide. Over 60% of the $543 million mark-to-market adjustment is due to hedge ineffectiveness, mainly on our Texas gas swaps, resulting from the sharp rise in forward gas prices during a time when power prices did not increase at the same rate. The longer-term gas and power price correlation, however, remains effective.

Another 21% of the mark-to-market is from Northeast forward energy sales that do not qualify for cash flow hedge accounting treatment, while another 12% comes from gas swaps used to hedge Texas baseload plants where the hedges cannot be perfectly matched with the shape of the expected monthly generation.

In summary, the story of the second quarter was outstanding commercial and operating performance in Texas, where the fleet ran exceptionally well during a period of higher prices and volatility. This, together with lower development expenses and the West region's repowering contributions, resulted in a significant improvement over 2007.

Slide 16 shows our results for the first half of 2008 compared to the first half of 2007. I would note that with all of the portfolio changes in recent years, that this is the first time that we've had virtually no changes in our asset base year over year, making this a more direct comparison between the periods. Adjusted EBITDA for the first half of 2008 increased 18% to $1.2 billion compared to $1 billion for 2007, as three of our four core regions posted double to triple-digit year-over-year gains. Texas was up 29%; South Central increased 47%; and the West more than doubled.

As shown on the slide, Texas led the way during the first half, primarily due to a strong second quarter as I just described. Increased merchant margins, exceptional operations, and decreased development costs drove adjusted EBITDA for the region up $181 million compared to the first half of 2007.

South Central's adjusted EBITDA increased by $26 million from $55 million in the first half of 2007 to $81 million in 2008. Fewer planned outages and lower EFOR rates resulted in an 8% increase in coal generation, which, when coupled with an only modest increase in co-op load resulted in more power being available to sell in the higher priced merchant market and reduced need for purchased power to meet our load obligations. The resulting 45% increase in merchant sales and 16% reduction in purchased power volumes, together with effective cost containment, drove the year-to-date improvement.

The West region's adjusted EBITDA rose to $35 million in the first half of 2008 compared to $14 million in the previous year. This increase was primarily related to capacity revenues from Long Beach, which was not yet in service this time last year.

Adjusted EBITDA for NRG's Northeast region decreased $14 million year over year as higher capacity revenue was more than offset by lower contract and energy margins. Capacity revenue increased primarily due to the initiation of the RPM capacity market in PJM in June of 2007, a new RMR agreement at our Norwalk Harbor facility, and effective hedging of our New York capacity. Higher capacity revenues were more than offset by lower net contract revenues, as the costs to serve those contracts rose in line with market prices; and reduced energy margins, which declined due to the retirement of Huntley 65 and 66 in June of 2007; and higher fuel costs at Indian River and Somerset.

As I discussed earlier, we experienced significant non-cash mark-to-market losses primarily related to an upward movement in the natural gas curve during the second quarter. Of the $713 million loss recorded for the first six months of the year, more than half was related to Texas gas swap ineffectiveness; 20% was due to Northeast forward energy sales; and 18% was due to the shaping of hedges compared to forecasted monthly generation. For additional detail, we have included a slide in the appendix, which provides more detail on the impact of commodity price movements given our hedge position on our income statement and balance sheet.

Slide 17 shows NRG's cash flow generation during the first half of 2008. Cash flow from operations fell $23 million from $459 million in the first half of 2007 to $436 million for the first half of 2008. But, if we net out the impact of cash collateral movements to see the true cash generation of the business, cash from operations rose 36% from $562 million to $764 million. Virtually all of this year-over-year increase in cash from operations net of collateral is attributable to second-quarter adjusted EBITDA improvement. NRG's free cash flow during the first half of 2008 was $32 million compared to $226 million in 2007, as both environmental and repowering investments accelerated.

The year-over-year increase in environmental CapEx is related to the two back-end control projects at our Huntley and Dunkirk locations. Repowering investments increased in 2008 as we moved forward with various investments, including the Sherbino and Elbow Creek Wind Farms, the Cedar Bayou IV combined cycle plant in Texas, and the Cos Cob peaker facility in Connecticut.

Repowering investments to date also include payments on one set of additional wind turbines, initial work toward our previously announced El Segundo project, and continued investment in the STP 3 and 4 initiative, net of the $50 million contribution received from our partner, Toshiba.

Moving to slide 18, NRG's liquidity program remains a differentiating factor for the Company. With one of the most active hedging programs in the industry, and facing one of the more volatile commodity and financial environments in many years, we were able to navigate our way through the quarter, not only sustaining our liquidity but increasing it.

As outlined here, total liquidity stood at right over $2.6 billion at the end of the second quarter, up $276 million since March 31. This increase was attributable to a $420 million increase in cash balances net of a $178 million increase in cash collateral, resulting from strong operating cash flow and the receipt of the ITISA sale proceeds in April. Partially offsetting this increase in cash was a $144 million decline in letter of credit capacity as additional LCs were posted in support of commercial operations activities.

The cornerstone of our liquidity program, though, is our first lien collateral structure, which is represented on the bottom right side of this slide. As we've discussed previously, we are able to hedge up to 80% of our baseload capacity for the next five years under this structure and the size limit of this program is based on volumes hedged, not the dollar value of underlying notional positions. As such, the capacity of this program does not change as commodity prices move. As you can see, peak annual utilization is in 2009 with 72% of our capacity that year currently committed to strategic hedges, falling to 15% for existing hedges in 2013.

This lien capacity, coupled with our significant available liquidity, positions the Company to continue to protect and enhance the value of our fleet through both short and long-term hedging strategies while exploring ways to remove impediments to efficient capital allocation.

Given the Company's stronger than expected financial performance during the first half of the year, we are updating our full-year 2008 guidance, as outlined on slide 19. We are increasing adjusted EBITDA guidance by $140 million from $2.16 billion currently to $2.3 billion. With increasing collateral requirements in recent months, we are maintaining our cash flow from operations guidance at $1.5 billion as cash margin postings offset a portion of the increase in adjusted EBITDA.

Also impacting cash flow guidance is an increase in forecasted cash tax payments for the year as a result of the sale of ITISA during the second quarter.

Previously, we expected to become a full taxpayer beginning in the second quarter of 2009. However, with our higher earnings this year, we expect to use our remaining postbankruptcy NOL this year and become a cash taxpayer by year end. As such, we expect our cash tax rate in 2009 to be approximately 30%, which is lower than the marginal tax rate due to a continuing $130 million limitation related to our prebankruptcy NOL.

While cash flow from recurring operations remains virtually unchanged, we expect our free cash flow to increase approximately $70 million due to our updated plans for environmental CapEx at our Big Cajun facility. So, as we look out to the rest of the year, we expect to see continued strong free cash flow from recurring operations before environmental and repowering CapEx and, at yesterday's closing share price, a recurring free cash flow yield of 15%.

Slide 20 outlines our 2008 capital allocation plan, as it stands at midyear. As I mentioned earlier, the primary focus during the second quarter was on our investment programs, where we invested a total of $245 million -- $44 million in maintenance CapEx; $43 million in environmental CapEx, primarily on AQCS projects at our Huntley and Dunkirk facilities; and $158 million on repowering initiatives, primarily wind, Cedar Bayou IV and Cos Cob. Year-to-date CapEx investments have totaled $426 million, with $97 million in maintenance CapEx, $61 million in environmental CapEx, and $218 million in repowering investments.

On the capital side, $188 million in consolidated debt has been repaid to date, not including the $300 million Term Loan B pre-payment at the end of 2007, and $140 million of the targeted $300 million in share repurchases have been completed. In light of the turmoil in the financial markets during the second quarter, which coincided with an unprecedented run-up in natural gas prices, we adopted a cautious approach to liquidity conservation. Nonetheless, we remain committed to completing the remaining $160 million in share repurchases for this year's program and to settle out the CSF I options when they expire in December.

With that, I will turn it over to you, Dave.

Thank you, Clint. Now, this is the part of the presentation where I usually talk a little bit about the Company's strategy going forward. And I think I may depart from tradition to some extent because I think most people on the phone have a pretty good idea of what the Company's strategy is going forward and it hasn't really changed over the last three months.

What I would like to do is look a little bit more at the situation as it exists today.

And, as I look at the situation, as I look at this Company over the -- and think about the past 12 months, I see a situation in which the 12-month forward gas curve has gone up by 18%. We have during that 12-month period increased our EBITDA guidance now 3 times, twice in 2007 and now once in 2008. We filed the first applications for a nuclear plant in the United States in 29 years and we have sold 12% of our nuclear development company for $300 million. We have successfully completed two repowering projects, Cos Cob and Long Beach, and we have three construction projects, Sherbino, Elbow Creek, and Cedar Bayou IV, which are proceeding on time and on budget. And we have been awarded power purchase agreements, long-term PPAs, for our El Segundo repowering project in the State of California and our GenConn project in the state of Connecticut. Yet, during that 12-month period, our stock is down more than 10%. That's from where it was 12 months ago.

Since I'm sure that this question is as much on your mind as it is on our minds, and we are all shareholders here, I thought I would do what I can to try and identify the issues which could be overhanging our stock and analyze whether those issues are legitimate material concerns to NRG going forward or simply market phobias more or less indiscriminantly held against us during this time of relentless and apparently endemic pessimism on Wall Street.

So, I came up with five phobias which are listed on this slide 22. I can't guarantee that this is an exhaustive list, but if you can name others, we would be happy to address them during the Q&A that's going to follow my comments.

So, let's start on slide 23, with one of the more recent phobias, which is dark spread compression. This concern was the catalyst for the sell-side report a few weeks ago directed at Mirant, which seemed to have sent a little shrapnel into us as well.

On this slide, let's start with the obvious. We don't burn much Eastern coal. We are completely hedged in 2008. And we're almost completely hedged in 2009, and we have a very high level of coal inventory in stock. But you knew all these facts since we have reported on them before. So we tried on this slide to make our analysis more quantitative and more comprehensive. And given that the market seems to be enamored with the idea of open EBITDA, we thought we would look at it on an open dark spread basis for 2009, by looking at the dark spread from both ends, from the cost push end and the revenue pull from the beginning of 2008 until now.

You can see that the increase in the gas curve since the beginning of the year plus the reduction in SO2 costs has swamped the deterioration in heat rate and the modest increase in Western coal prices, leaving for NRG an almost $7.00 per megawatt hour improvement in the dark spread since the beginning of the year.

Of course, the key, here, as you can tell from the comparison with the Eastern coal burner on the right, is our reliance on Western coal. We continue to see no basis for believing that Powder River Basin prices are destined to link to global oil prices through fuel switching in Europe and the several other leaps of faith that would be required in order to make that connection a pricing reality. As such, we don't believe we bear any material risk of dark spread compression.

So, moving on to the second phobia, the carbon overhang. So much has been written by others and so much has been said by us on this topic since Dan's report last November that I simply wanted to give our current take on the prospects for federal carbon legislation. To us, the key is the 10 primarily Democratic senators from the heartland who voted for cloture on Lieberman-Warner but then went on the record to say that they would not have voted for the bill itself in its present form. In our opinion, it doesn't matter what happens in the fall election. The concerns of those senators need to be accommodated for legislation to be moved out of Congress and onto the next President's desk.

Moreover, we think it is clear that climate change legislation itself, with the inherent prospect of a substantial carbon charge imposed on the American consumer, cannot pass at all in the current high energy cost environment unless it is coupled with additional elements that hold out at least the prospect of lower future energy costs. This means to us at the very least a nuclear title, which of course by that, I mean a series of provisions designed to incentivize and clear obstacles for the so-called nuclear renaissance.

Obviously, a nuclear title, almost whatever it included, would benefit us and our NINA subsidiary directly. And I also think that the bill would need to have an electric car title, which should benefit the entire electric industry over time, as transportation evolves into the biggest source of electricity demand growth in the years and decades to come.

In summary, whether you are evaluating NRG from the perspective of carbon risk in the short term, the medium term, or the long term, we feel that the Company is better positioned today than we have been at anytime over the past 12 months.

Now, on to wind and its impact on heat rates in Texas. No doubt the prospect of a flood of zero marginal cost wind farms has significantly affected the psychology of the ERCOT forward heat rate market. Indeed, in our opinion, the market has overreacted. On slide 25, we try to break through the negative market psychology in order to get to the likely physical reality.

This slide of course shows the merit order supply stack that we project for ERCOT in 2015 relative to 2008. To the extent that wind power depends on actual electricity sales for its economics, the key is the number of hours during the year that wind can avail itself of the CCGT marginal cost unit during off-peak hours. This is the cliff that you can see depicted in these supply stacks about one-third of the way over from the left.

What this slide demonstrates is that with a full 18 gigawatt wind buildout, this benefit is likely to be eroded relative to what wind projects are realizing today. Furthermore, there are important issues in terms of the pace of transmission construction, and most importantly, reliability. We think that the PUCT and the ERCOT officials in Texas are very mindful of the billions of dollars it's going to take to build the CREZ transmission system, and we feel that they are equally mindful of the billions more that it will take to build and maintain the quick-start gas-fired backup capacity that's needed to firm the wind.

We believe in the future, perhaps in the very near future, ERCOT will begin to consider the topic of who pays for ancillary services, what wind firming capacity is necessary, and how and who will pay for that? In short, when it comes to wind in Texas and its impact on forward heat rates, stay tuned. The market has oversold it, and we're due for a reality check.

In short, it feels a lot like when the market actually believed that TXU was going to bring 11 coal plants online in the 2010 to 2012 time-frame and then at which point, when it became clear that that was not going to happen, that the forward heat rates in Texas rebounded nicely.

Next up on the phobia list is environmental CapEx. When the DC circuit recently struck down the EPA's Clean Air Interstate Rule and when the Clean Air Mercury Rule was vacated as well, it changed the regulatory basis for some but not all of our spend on environmental retrofits. As a result, and skipping several intermediate steps to get to the bottom line, the net effect on us is a six-year environmental CapEx spend, which is currently projected to be about $70 million less in aggregate. Plus, we project about a $400 million net shift out of the 2008 to 2010 time-frame in our total environmental spend, with it being shifted into the 2011 to 2013 time-frame, as depicted by the bar chart on the left.

So, from our perspective, the post-CAIR, post-CAMR world provides a modest respite in terms of near-term environmental CapEx but is otherwise not materially different for NRG.

Finally, the fifth phobia, which is the all-purpose catchall, that the threat of economic recession and the impact of reduced economic activity on future electricity demand growth. While recession and reduced demand growth are obviously a concern, particularly in such a high energy price environment, there are two important mitigating factors which benefit our Company.

The first is our hedge program. As demonstrated by the hedging information previously provided by Bob, we believe the Company has basically hedged its way through the current recession given that most recessions in American history have not exceeded 15 to 24 months in length.

The second mitigant is Texas. It has been our supposition for some time that the energy-based economy of Texas would be fairly immune to a national recession in a world of $100 plus oil. While it's still in the early months, and as such it's maybe too soon to draw final conclusions, the charts on the right side of this page comparing electricity demand growth in ERCOT to PJM on a weather-adjusted or weather-normalized basis for 2007 and year-to-date 2008 would tend to support our supposition. Even weather normalized, in 2008, Texas is growing at an average pace of a little bit more than 2% per annum, which actually is putting electricity demand growth in Texas ahead of its growth rate from 2007.

While PJM by comparison is experiencing a year-on-year drop, again weather normalized, from about 2.5% per annum in 2007 to almost flat in 2008. With nearly 65% of our overall energy production in Texas, this obviously is an important advantage or an important mitigant for us.

Finally, in conclusion, the impact of these five phobias on our Company and our stock appear to us at least to be considerably overblown. The Company has performed magnificently year-to-date, rewarding all of its shareholders with a robust first-half financial result, and we are well positioned to deliver a similarly positive result over the balance of the year and in the months and years to come.

So, thank you, and I think we'll open the lines now for questions and answers.

(Operator Instructions). John Kiani, Deutsche Bank.

In late May at our conference, you stated that the Calpine deal would either happen or not happen by the end of the second quarter. And I guess we're one month beyond that time-frame now, and on slide 22, the Company highlighted potential overhangs on the stock. I actually think that this is a meaningful overhang on NRG's stock that wasn't discussed. Can you please tell me where you stand on that transaction?

Well, John, as you know, we don't comment on any discussions with anyone that's in progress or otherwise. Since I went to your conference at stupendous personal expense or corporate expense and outlined our rationale for the Calpine proposal we made at the time, I think if the people on the phone were paying attention to what we said at your conference, then there was a flurry of e-mails I think or press reports later that week, I think they know everything they need to know.

Well, as you mentioned I think during the presentation that you just gave, year-to-date long-term natural gas has increased over 50% -- 15%. Your market EBITDA or your open EBITDA has increased by almost $1 billion but the stock is down 17% year to date. Why isn't the Company looking at doing a $1 billion stock buyback to take advantage of the substantial dislocation between the stock price and the intrinsic value that has only increased over the last 12 months?

In the past, NRG has I think been very creative and opportunistic in using hybrid securities, converts, and other strategies to create substantial buyback capacity. Why isn't the Company taking advantage of this opportunity in the stock price right now?

Well, I mean, John, you know better than anyone that the direct answer to your question as to why we're not doing that is because of the limitations of the restricted payment basket. So the real question is, the Company's perpetual search for ways to free up more room in the restricted payment basket.

I think what Clint was trying to say is this is a very high level of focus for us. There are a variety of ways in which we can do that, and I think there's a slide back in the appendices that tries to articulate that. Because there's been a lot of focus from buy-side investors about that.

From our perspective, from my personal perspective, it is an intolerable situation for me that the Company sits here with $2.6 billion of liquidity and we have the freedom to distribute it in an optimized way. Right now, we have $180 million effective limitation, which I guess it will free up a little bit more at the third-quarter call. So, it's very high on our priority list.

Certainly, the idea of freeing up the restricted payment basket and then doing a big share buyback, that's something we would seriously consider as well. I guess a question I would have for you is, my understanding is that Mirant is in the middle of a $2.4 billion share buyback themselves and their stock seems to be dropping at the same pace as everyone else's. So, I would like to be persuaded that a major share buyback would be the panacea for all of our woes. But maybe that is a debate we can have off-line.

I think as you pointed out, David, Mirant is experiencing massive dark spread compression. So I think that's why their stock has dropped. And I think your Company is obviously in a completely different situation, where the intrinsic value has actually increased substantially over the last seven to eight months as opposed to having decreased, because Mirant and other companies are short Eastern coal while you all obviously own lignites, PRB and also nuclear generating assets, and yet, the stock is still down 17% year to date. And that's the opportunity to create additional value that I'm referring to.

I'm just a little bit confused as to why -- what the direction of the Company's capital allocation program is going in. Because I feel that the stock is materially undervalued, yet the Company is thinking about using it as currency when in my opinion, the best investment that NRG has right now is its own stock.

Well, I think John, you've got your opinion and I could respond to that. But I think at some point we need to take some other questions on the phone.

Okay. Thank you.

Dan Eggers, Credit Suisse.

I think John covered a lot of the capital allocation decisions. Clint, I was wondering if you could just give a little more color on some of the mark-to-market losses and the collateral postings, given the movement in commodity prices I guess since the close of the quarter, with them broadly down. Any insight you could share as far as where mark-to-markets would be going in the third quarter and any trends in collateral since then?

Sure, Dan. On the mark-to-market front, we've actually taken a pretty close look at that over the last few weeks. Obviously, there's been a significant decline in the gas market. And what we've seen is, based on calculations that we've just run in the last couple of days, that a lot of this ineffectiveness and mark-to-market that we experienced during the second quarter is reversing itself in a pretty significant way.

And so, I think we're seeing what we would have expected to see with gas prices coming down as much as they have. So, again, mark-to-market looks like at this point, with gas moving down, it is reversing itself quite meaningfully.

On the collateral front, since the end of the quarter, we've gotten about $60 million of net cash collateral back as a result of the reduction in gas prices. So, again, moving in the direction that you would expect to see.

And then just on the hedge ineffectiveness, was that all tied to 2008? Were you still deeming 2009 and beyond effective?

Really, it was across the years. So, it's not specific to 2008. There is effectiveness kind of sprinkled basically throughout the program. And it really has do with the fact that in all years, when we looked at the changes in natural gas prices, as of the end of the quarter on 6/30, we look at the change in gas price and then we look at the change in power prices. And basically in all years, what we saw is that natural gas prices during the quarter rose at a faster rate than power prices. And so, that led to some degree of ineffectiveness, really, throughout the hedge program.

Great. Thank you.

Lasan Johong, RBC Capital Markets.

I'm a little puzzled about the hedging strategy adopted in the second quarter. My understanding has always been that NRG prefers to lock away gas price volatility and keep its heat rate exposure open. And in the current markets where dark spread compression, which I agree with David, is kind of silly at this point and is meaningless, why would you hedge into that kind of dumb environment, if you would, that is driven by financial woes of the banks and other issues?

Lasan, on the hedging side, the hedges that we added during the second quarter were on the gas side. So we were locking in the higher power price. We already have the fuel hedged. So we were locking in very strong margins by locking in the gas piece.

But the point is that the power prices were understated relative to what it actually should be because of the heat rate compression. Am I wrong about that?

Well, we left the heat rate position open because we hedged it with the gas. So (multiple speakers). Right. We still keep the heat rate as an upside, which is similar to what we did in the second quarter. This year, we kept the heat rate open and it benefited us by doing so.

So you bought the power and sold gas short?

No. We basically just sold gas.

Oh, you just sold gas?

Yes.

I see.

Gas as a proxy for power.

Then I have some -- we can get into that off-line. Assuming the -- I'm assuming the sale of assets in the international was in the discontinued ops line; is that correct?

Yes, that's right.

Okay, great. That's it for me. Thank you very much.

Andy Smith, JPMorgan.

I wanted to see if you guys could talk a little bit in Texas about -- we saw some pretty high costs in the balancing market versus certainly just overall with the move in gas, saw some commodity price move. Could you guys talk a little bit about what the driver in the quarter was for the performance? Was it really more that kind of 15-minute increment, peakers in the balancing market, was it just overall commodity price? And then I had a follow-up question on that too.

Well, I mean, in terms of what made up the EBITDA increase for Texas, I think it was the full range, more output, better performance. Do we have the specific number? Have we tried to, Clint, isolate the number that came from sort of those pricing moments in May?

Well, we don't have a specific number for that. I don't think we've historically given out specific numbers for gas plant EBITDA.

But I think the way to think about it is during the second quarter, gas plant generation was up 24% year-over-year. And then when you look at on-peak power prices, on-peak power prices in Texas during the quarter I believe were up over 100%, about 130%. So, I think you can kind of use those as a proxy for the impact.

Yes. So, Andy, we don't have that specific number. I don't know; we can try and get it. But those moments that got a lot of headlines, they were actually relatively short-lived and for just a few weeks. So I'm not sure how much of an impact they would have. But, we can discuss internally and get back to you if that is an important number for you.

Well no, I was just looking more for your qualitative comments. And so it sounds like from what you just said qualitatively, you would say it was just overall better pricing fundamentals in Texas in the quarter.

Yes, Andy, the way that I would look at it qualitatively is that the price impact was the majority, call it upwards roughly three-quarters. And then the volume piece of it due to better generation, better reliability generation out of the gas plants was the lesser part of the two. So part of it was again the open heat rate position and the pricing and then, to a lesser extent the additional megawatts that we put out of the plants.

Okay, great. And then congestion charges were up fairly significantly in the second quarter as well. Do you guys have any exposure to that or did you have any exposure to that but either positive or negative?

Mauricio, do you --?

No, we didn't have anything meaningful. I mean we do participate in the basis market in Texas, but we were not affected adversely on the increase in congestion costs.

Okay, great. Thanks, guys.

Elizabeth Parrella, Merrill Lynch.

I wanted to ask regarding the RP basket, Clint, could you just remind us or tell us what they were at the end of June, both the bank and bond calculations versus where we were at the end of March?

Sure, Elizabeth. The RP basket in the bonds right now stands at I think $184 million. Under the bank it's $1.010 billion. And then, at the end of the first quarter, I believe it was $150 million under the bonds. And I don't recall what it was under the bank.

Okay. Just a question on -- a second question on a different area. In the wake of the CAIR ruling, have you looked at the carrying value of your emission allowances; particularly the ones in Texas that you value post or coming out of the Texas Genco acquisition; and whether you need to take any impairment on those? And if you do, would that go into the calculation of net income for the bond RP basket?

Elizabeth, we have taken a look at that. We looked at both our NOx and SOx credit bank, and just to be thorough, the NOx credits that we have are not impacted by the CAIR decision. Those are really for kind of local Houston, Galveston-area compliance.

On the SOx front, as you mentioned, really the only part of our bank that is affected by CAIR are the credits that we purchased as a part of the Texas Genco transaction. We looked at this over the past week because we know that a number of other companies have faced this issue. And based on our existing carrying and book value of those credits and based on our fundamental long-term view of what those credits are worth, we don't foresee any type of meaningful impairment at this time. Obviously, we will need to monitor that over time. But I don't at this point see any type of meaningful impairment associated with those.

Okay. So if there were impairment charges, they'd get included in the net income calculation for the bond RP?

We'd need to look at that. That may be considered an extraordinary event, given what gives rise to that impairment. But that would be something that we would have to look at more closely.

Okay. Thank you.

Michael Lapides, Goldman Sachs.

Congratulations on a really good quarter. I want to ask you about RGGI. What are you expecting is your '09 RGGI costs? I'm just trying to get your fundamental view a little bit on kind of the dollar per ton pricing for RGGI credits.

Go ahead, Mauricio.

Michael, this is Mauricio. I think there has been some price discovery on the over-the-counter market. We have seen price quotes anywhere between $7.50 to $8.50 per ton. Actually, our fundamental view is lower than that. And, so I would say it's probably in the neighborhood of $4 to $6 per ton range.

Okay, so if you're buying 12 to 13 million tons, we're talking south of $100 million.

I think, Michael, the way you should look at that though on a cash basis, there's two things to consider. One is how much gets passed through in the marketplace, for one. And the second point is, we have been monetizing some of our other excess carbon credits to offset some of those costs.

Okay. I had a question also and a real quick one, when I think about collateral cash postings. Under what scenarios does the collateral that you've already posted year-to-date not return back to you? Simply another spike in gas prices?

Yes, I think that's the case, Michael. If gas prices continue to rise, then it wouldn't. But again it's really more of a timing issue. Because as the underlying hedges roll off and are realized, that cash collateral would come back to us. So I think it's just a matter of timing, but again it may not come back to us in the time that we expect if gas prices continue to rise.

Got it. Okay. Thank you, guys.

Chris Taylor, Evergreen Investments.

I wanted to ask about slide 27. You're talking about being recession resistant. Have you done a similar analysis for price impact? Because obviously the last few recessions, we had fairly low energy prices. How much would the demand destruction be due to high electricity prices as opposed to a recession? Have you done such analysis?

Well, we did have an analysis which was based on historic. We didn't put it in here, but we tried to calculate it all the way through to sort of impact on natural gas prices. And again, this is just us sort of calculating things based on sort of historic patterns. And I think, Mauricio, tell me, it came out to about $0.30 --?

$0.35 to $0.50 per MMBtu, [in] the impact.

Yet, but I mean look, it's a calculation. We did the best we could. But that's what it came out to; it's obviously highly speculative -- but anyway.

So which are you more vulnerable to? Is it recession or high electricity prices, demand destruction?

More vulnerable to high electricity prices?

In terms of your volumes. Which are your volumes more sensitive to? A recession impact or a high electricity price impact? I mean we're seeing demand destruction in gasoline. It's logical to assume you would have something similar in electricity.

Well I think that probably the thing that's most sensitive to our portfolio right now, it's gas. It's how gas moves.

I'm not talking about your price impact. I'm talking about your volume impact.

Well, we are hedged for the next couple of years. So, the volume, since we're basically 90%-plus of our generation comes from baseload. So, if there is recession, you'd see the impact more being intermediate and peaking. We don't get much generation from that.

I agree with Bob. I think a recession-driven, steep drop-off in demand for natural gas has got to be what we would be most susceptible to. But since we take the benefit of natural gas through sale of our baseload solid fuel fired plants, where we're very heavily hedged for the next few years, again, that leads into our view and the expression that we think that we are recession resistant. But if you're looking for one thing, it would be that, a recession driving reduction in demand for natural gas.

Thanks.

Maura Shaughnessy, MFS.

Bob, congratulations on the safety and operations. Dave, I'm going to give you a second chance on the Calpine question thrown out there by John. We have an entity out there with a temporary management team, a bunch of new folks on the financial side. I can't keep track who is being put there. And statements by you that -- comments that this issue would come to a close sooner than it has. Obviously, there is no CEO there. The Board seemed to give you a bit of a Heisman, and both stocks have been hammered a bit. So we're in this wonderful land of uncertainty and I, as John, would actually in some respect put that at the number one list of the concerns.

Appreciate the craziness of the markets; we're all living it every day, and the understanding of maintaining liquidity and then given the RP basket and everything else put some constraints on some things. But, throwing an uncertain deal into a mix of a difficult market is not helping the cause. So, I'm going to give you a second chance, Dave, and just try to help us better understand what is going on, and especially with the prospects of buying a company that essentially has no management.

Well, Maura, I've been here for four years and for four years we've been identified with one or another company in this industry. And I can't remember the order of whether it was Dynegy, Mirant, Reliant, and now Calpine or some other order. But you know, the fact that I say I'm not going to comment on whether there are any discussions going on -- we also tend to say that in the opposite way, which is, we say there's always discussions going on with all people. We just don't comment on any type of transaction that's going. You can't read into that comment anything in particular about the Calpine situation.

If there is uncertainty that concerns yourself and John Kiani about a Calpine transaction that you don't like, again, I would refer back to the situation that existed at the end of May. In terms of at that point, we laid out what we thought was the strategic logic for a transaction with them in the letter. And we said in terms of whether the numbers work, that was something that we would have to determine on due diligence. I think that the market had that question as well.

If you and John put Calpine number one ahead of the five phobias I talked about today, that may be the case. I mean this is one of the frustrations of this market. I mean no one really knows what is causing any of these things. I would only point out that it's not just Calpine and NRG that have been hammered over the last two months. I think the entire sector has been hammered, and even the people who aren't rumored to be involved in anything.

And then, the second point I would say is, we're down 10% over the last 12 months. The Calpine thing sort of came up in May, right? So, maybe, again, you and John and I can take it off-line. I would like to understand why we didn't get the benefit of the favorable market conditions in terms of natural gas prices and other things over the last 10 months prior to the Calpine announcement.

But I'm sure that this answer is unsatisfactory to you. But we just can't get in the business -- I don't know any company that comments on transactions that may or may not be happening before they have happened.

But, Dave, but, again, you have said that in order to ever do something of this sort, you would have to do two or three weeks of due diligence at Calpine to understand the various issues from contracts to hedges and everything else; and none of that has changed.

None -- that we would have to do something like that in order to understand their -- no I don't -- that has not -- our viewpoint on that hasn't changed.

Okay. Thank you.

Nitin Dahiya, Lehman Brothers.

Without asking the views on Calpine, if the transaction were to happen, how do you plan to refinance the Calpine debt and if you have given any thought to that?

We're just -- I think we have exhausted the Calpine topic for today.

Fair enough. Just on the RP basket issue again. Now obviously the bonds are about 96 or 97. And would you again consider going back to the bondholders to seek an amendment there?

Also just based on where the bonds are trading versus CDS, it almost seems -- a market almost seems to expect that you would actually seek to relax that. Can you comment on that?

Our bondholders are a very significant part of our capital structure and have always been constructive in dialogues. Obviously, we have talked today about the RP restriction being something that we're focused on. And I guess all I would say is that we're certainly always open to a constructive dialogue with any member of our investment community, including the bondholders.

Is that -- then that possibility is on the table?

I'm not prepared right now to suggest that we are preparing any type of formal approach. All I would say is that that obviously is something we've thought about in the past and we'll continue to consider in the future.

Also, on slide 40, the restricted payment 101, when you look at the various clauses under the indenture where RP could be built, I suppose outside of fresh issuance, there is equity earning cash distributions from deconsolidated entities. Do any of your entities have that capacity?

Not at this point. I think what that's referring to is if we have an unrestricted subsidiary and that's a definition under the indenture, that to the extent that we receive any cash distributions from them, that that would increase the basket dollar for dollar. At this point, the only unrestricted subsidiaries that we have are the CSF I and CSF II structures. And I don't foresee that cash distribution as being a dynamic within the context of those.

Okay. Thank you very much.

Okay, Jennifer. We've gone a little bit longer. But thank everyone for participating in the call and we look forward to talking to you again next quarter. Thank you.

Ladies and gentlemen, this does conclude today's conference call. Thank you very much for your participation and have a nice day.