NRG Energy Inc (NRG) 2008 Q1 法說會逐字稿

Good day, ladies and gentlemen.

Welcome to the NRG Energy first-quarter 2008 earnings results conference call.

I'd now like to turn the meeting over to Ms.

Nahla Azmy.

Please go ahead.

Thank you, Michelle.

Good morning and welcome to our first-quarter 2008 earnings call.

This call is being broadcast live over the phone and from our Web site 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 the Web site.

A replay and podcast of the call will be posted on our Web site.

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.

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 these 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 this press release and this conference call.

In addition, please note that the date of this conference call is May 1, 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 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'd like to turn the call over to David Crane, NRG's President and Chief Executive Officer.

Thank you, Nahla, and good morning, everyone.

Today, I'm joined by Bob Flexon, our Chief Operating Officer, and Clint Freeland, our Chief Financial Officer, both of whom will be giving part of the presentation today.

I'm also joined by Mauricio Gutierrez, who runs or Commercial Operations Group and who will be available to answer questions.

In addition to other colleagues from NRG, we have two new colleagues from NRG joining us.

Hopefully, you've all seen press releases on this recently.

We have Jonathan Baliff and Michael Liebelson with us.

Both joined the Company as Executive Vice Presidents enhancing what I believe to be already the best management team in the business.

Then for the first time ever on this, the 17th earnings call that we've made as the new NRG, we have two special guests from outside the Company with us today -- Yasuharu Igarashi, the President of Toshiba Power Systems, and Hiroshi Tsukamoto, the Senior Vice President of Toshiba America, both of whom are here as our special guests at NRG today as we are in the process of closing today the formation of Nuclear Innovation North America, or NINA, the joint venture that we've entered into with Toshiba not only to develop South Texas Projects 3 and 4, but also to develop other advanced boiler water reactor projects in North America.

So, welcome to Mr.

Igarashi and Mr.

Tsukamoto.

Now, I want to -- in terms of the style or the order of the presentation today, I want to remind anyone who is new to NRG or who may have missed our last earnings call in late February that we reorganized our executive management team on March 1.

As a result, on this call, Bob Flexon, who is now our Chief Operating Officer, will now review the Company's plant and commercial operations performance while Clint Freeland, our new CFO, will cover our quarterly financial results and give a snapshot of the Company's financial strength at this point.

In the broadest sense, our management restructuring was implemented in recognition of the fact that NRG's business has become increasingly bifocal since we began our Repowering program and our other growth initiatives.

Our increasingly complex and inter-related operational business is intensely internally focused, while our development business is relentlessly externally oriented.

While the focus is different, the two businesses are highly interdependent.

The development business in particular, built as it is around the redevelopment of our existing assets, would be starved for oxygen if the operating business did not continue to operate effectively on all fronts.

This quarter was a case and point.

The springboard for the significant advances that we achieved in our Repowering program was the solid operating performance that we've achieved across our plants, across all regions.

If you are following this presentation on slides, if you want to turn to Slide 4, plant operating performance was strong, as I said, in all plant and all regions, but led by the superior reliability results achieved by Big Cajun II in South Central and the astonishing performance of the South Texas Nuclear Project Units 1 and 2, which achieved its 12th quarter in a row with a 0.0% forced outage rate.

Building on that operating success and the financial strength it provides us, combined with our eternal corporate commitment to prudent balance sheet management, we focused this quarter on taking advantage of what I've characterized on this slide as the upwardly volatile commodity markets to lock in substantially more baseload hedges.

In all, we sold the equivalent of 28 million MW hours spread over the next five years at natural gas prices significantly higher than we had previously realized and far higher than we anticipated at the time we bought Texas Genco back in 2006.

Given that we continue to remain bullish, as we have been for a while on gas prices, it is important to point out that as large a position as 28 million MW hours may seem, it represents only 9% of our total baseload capacity over that period.

I'm going to talk a little bit more about that later.

Before I turn it over to Bob, I also want to mention on this page ITISA, because we have a very capable business operations group at this company.

ITISA in Brazil, obviously a noncore asset from the beginning.

When the new NRG got started at the beginning of 2004, there was actually a process underway to sell ITISA.

It looked, at that point, like we were going to get somewhere between 0 and $20 million in cash.

Even though we recognize that the business was noncore, we thought that was undervaluing the asset by a long shot, so we stopped that sales process.

We put ITISA into the hands of our business operation team.

They fixed it up, and this quarter, we sold ITISA for $288 million and $61 million of deconsolidated debt.

Of the $288 million, that will result in a net cash back to NRG of about $200 million.

So congratulations to Bob Henry and his Business Operations group.

With that, let me turn it over to Bob Flexon.

Thank you, David.

I will begin this morning with a review of our first-quarter operating performance on Slide 6, which in summary was excellent.

Starting with safety, our recordable incident rate during the first quarter was 0.74.

While we relentlessly strive to achieve a reportable incident rate of 0, our actual rate in the first quarter continued the progression we started several years ago towards that goal -- the recordable rate of 0.74, significantly below the industry average recordable rate of 3.9.

One of our important safety goals for 2008 is extending the number of our plant locations that participate in OSHA's highly regarded Voluntary Protection Program.

I will be providing updates on our progress during the course of the year.

Our baseload operating plants also put up very impressive numbers during the first quarter, contributing 641,000 MW hours of increased coal and nuclear generation versus the same period last year.

Baseload EFOR in the Texas and South Central regions were outstanding at 1.7% and 1.6%, respectively, while our Northeast region showed significant improvements quarter-over-quarter.

As David highlighted, STP our nuclear site, has now run 12 full quarters without a forced outage event.

Our efforts to improve fleetwide plant reliability began several years ago as part of FOR NRG, or focus on ROIC.

While there will likely be times in the future where we will experience higher EFOR numbers, our continued focus on safely running and maintaining our assets will drive reliability over the long-term.

We continued building our coal inventory as we prepare for the peak summer season and anticipate the South Central BCII outage and the coal barge unloading area later this year.

The inventory levels above the targeted range primarily relate to PRB 8400 used in our South Central and Texas locations.

For the first time in several quarter, our Commercial Operations Group resumed their forward hedging of energy from our baseload portfolio.

Slide 7 provides the current hedged levels of our baseload portfolio with the additional hedged position added in 2008, highlighted by the striped bar.

With this year's rapid increase in natural gas prices and calendar strip prices for 2009 trading as high as $10.66 per million Btu and the 2010 to 2013 calendar strips trading from the mid to high $9 per million Btu, our commercial operations team added approximately 28 million MW hours during 2008 of baseload hedges covering the periods from 2009 to 2013.

Looking across the years, our hedge levels for energy and fuel are largely imbalance, thereby effectively locking in the dark spreads.

In-city capacity market prices for 2008 have declined versus 2007 primarily for three reasons -- NISO's New York City capacity mitigation plan for pivotal suppliers, increase in demand response from last summer, and changed bidding behavior of competitor generation as part of the Keyspan/National Grid merger.

The majority of our in-city 2008 capacity had previously been hedged.

The decline in market prices for rest-of-state New York resulted from the reduction of the installed reserve margin requirement from 16.5% to 15% that effectively decreased the UCAP requirement by 484 MW and continued PGM capacity imports of over 1200 MW.

Similar to in-city capacity, a portion of our 2008 rest-of-state capacity had previously been hedged by our Commercial Operations team.

Following a winter of coal price volatility, market prices for PRB 8800 have settled in at the $14 to $15 per ton price range, while the market for PRB 8400 is currently trading around $10 per ton.

In addition to our 45-day coal inventory supply, our coal needs are nearly completely hedged through 2009.

Since well over 90% of our coal needs are met with PRB coal and lignite, we have not experienced any unusual supply or reliability issues that have occurred recently in the market.

We do import 0.4 tons of international coal, which have experienced delivery issues, which our coal team has addressed.

Slide 8 provides the gross margin sensitivities to gas and heat rate movements.

Compared to our year-end earnings call, the impact of our additional hedges can be seen in the reduced volatility natural gas movements will have on the portfolio's future margins.

For 2009 and 2010, the gross margin portfolio impact of a $1 per million BTU natural gas price change has declined over 52% and 25%, respectively, since our previous disclosure during our year-end call.

The impact of fee rate changes on the portfolio's 2008 gross margin is relatively unchanged since year-end, and we continued to carry an open heat rate position into 2008.

Forward heat rates in Houston, shown on the upper right-hand corner of the slide, have declined reflecting higher gas price environment and uncertainty of impact of possible new builds and the potential longer-term impact of wind generation.

Slide 9 covers our significant Repowering and construction activities.

Both the Cedar Bayou 4 and Cos Cob projects progress as expected during the quarter and remain on schedule and on budget.

El Segundo initiated limited demolition work on retired units 1 and 2 to in connection with its recent award, 550 MW PPA from Southern Cal Edison.

The commercial operating date for Cos Cob is one month from today, followed by Cedar Bayou in June of 2009.

The environmental projects in western New York, in accordance with the consent decree to reduce SO2, NOx and particulates, have progress as expected.

Tie-ins for the Huntley unit 67 and 68 will occur during the fourth quarter, during scheduled outages, and start up by year-end.

Work on the Dunkirk units is targeted for completion in Q2 2009 for units 3 and 4 and Q1 2010 for units 1 and 2.

Planning and finalizing cost estimates for the South Central environmental projects continued during the quarter.

With the uncertainty around care and (inaudible) requirements, we are delaying the environmental spend and have revised our 2008 South Central environmental CapEx forecast downward from $133 million to $69 million.

I will now turn to Clint for the first-quarter financial review.

Thank you, Bob.

Starting on Slide 11, NRG has a solid first quarter as the Company generated adjusted EBITDA of $525 million compared to $500 million in the first quarter of 2007.

As David and Bob have indicated, our South Central region had an outstanding quarter and accounted for a significant portion of the Company's year-over-year gain.

Cash flow from operations was $60 million versus $106 million in last year's first quarter, as cash collateral outflows, working capital adjustments, and timing of interest payments more than offset the improvement in adjusted EBITDA.

I would note, however, that a significant portion of these cash of flows are timing-related, and we expect them to either reverse or be smoothed out during the year.

Taking our first quarter into account, we've updated our forecast for the year and we're reaffirming our adjusted EBITDA guidance of $2.16 billion in cash flow from operations guidance of $1.5 billion for the full year.

We continue to make progress on our 2008 capital allocation plan, as we completed $40 million in share repurchases and $143 million in debt repayments between the year-end earnings call on February 28, 2008 and the end of the first quarter on March 31.

This brings aggregate share repurchases and debt repayments to $140 million and $454 million, respectively, under the 2008 capital allocation plan since its commencement in December 2007.

As we look forward to the remainder of 2008, we intended to complete the capital structure portion of our capital allocation plan with the repurchase of an additional $160 million in common shares, settlement of the common stock call options related to the CSF-1 structure, and repayment of $68 million in consolidated project debt.

The investment component of the 2008 capital allocation plan remains on track as well, as the Company invested a total of $71 million in maintenance and environmental CapEx in our existing fleet and $93 million in Repowering growth investments during the first quarter.

In summary, the story for the first quarter is that we remain undeterred in the focused execution of our financial strategy, which includes regular return of capital to shareholders, reinvesting in the fleet, growth investments through RepoweringNRG, and capturing value through incremental long-term baseload hedging.

This is all made possible because of our unwavering commitment to the bedrock principle of prudent balance sheet management, which is evidenced by our strong and multifaceted liquidity program and manageable leverage profile.

While the volatile and unpredictable financial and commodity markets we face today demonstrate the value of this approach, this company's commitment and my personal commitment to this principle will not change.

Moving to Slide 12, consolidated adjusted EBITDA during the first quarter of 2008 increased 5% to $525 million compared to $500 million in the first quarter of 2007.

This $25 million improvement was primarily driven by an outstanding performance in the Company's South Central region, where strong plant operations, sound cost-containment and efficient commercial operations drove a $28 million or 80% increase in adjusted EBITDA.

Improved EFOR rates at our Big Cajun II facility led to a 12% increase in coal generation during the period.

This, coupled with only a 1% increase in co-op load requirements due to mild weather, benefited region in two ways.

First, we were able to sell additional MW into higher-priced merchant markets.

Second, we were able to reduce our power purchases by 22% to serve our load contracts.

Additional upside in the region came from an increase in capacity revenues resulting from higher co-op peakloads last summer and new RPM payments for the region's Rockford facility.

The West region's adjusted EBITDA more than tripled from $5 million during first three months of 2007 to $17 million in the first three months of 2008.

This $12 million increase was primarily attributable to capacity revenues generated by the Company's Long Beach facility, which was successfully repowered in 2007 and placed into service on August 1 of last year.

Adjusted EBITDA for NRG's Northeast region improved $4 million year-over-year.

Capacity revenues for the business rose by $27 million, 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 in Connecticut, and effective hedging of our New York capacity.

These higher capacity revenues were offset, however, by lower net contract revenue and reduced merchant energy margins due to the retirement of Huntley 65 and 66 in June 2007.

The Texas region's adjusted EBITDA was flat year-to-year at $292 million.

That was a notable achievement, though, because contract prices under long-term power supply agreements inherited in the Texas Genco acquisition were, on average, $2 per MW hour lower this year compared to last year.

The negative impact of these contracts, coupled with a one-time reserve for the settlement of a take-or-pay coal contract, was offset by an 8% increase in STP 1 and 2 generation, higher merchant energy prices, regularly scheduled sales of excess emissions credits, and reduced development expenses for STP 3 and 4.

On January 1, 2008, NRG began capitalizing all new costs associated with STP 3 and 4, with the STP 3 and 4 project, and that account for the decline in regional development expense.

The $19 million decline in quarter-over-quarter EBITDA for corporate is due to lower interest income, interest Padoma expenses related to wind development activities, and intercompany elimination of emissions credit sales.

So, taken as a whole, a solid start to 2008, with South Central hitting on all cylinders, the West regions seeing the fruits of its repowering efforts, and the Northeast and Texas offsetting contract pricing pressure with strong plant and commercial operations performance.

Moving to Slide 13 which outlines the Company's cash flow during the first quarter, it's important to note, for those who may be new to energy NRG, that the Company's EBITDA and cash flow tend to be seasonal with the majority of annual earnings being generated in the second half of each year.

Turning to first-quarter results, despite the increase in adjusted EBITDA, cash from operations declined by $46 million to $60 million for the first quarter of 2008.

This decline was largely due to higher collateral postings, increased working capital and additional cash interest payments.

Between year-end 2007 and the end of the first quarter of 2008, NRG's net cash collateral postings rose by $150 million from $71 million at year-end to $221 million, as the significant increase in commodity prices required us to post additional cash against our marginable commercial operations positions.

At this time, we expect between $130 million and $140 million of this net cash collateral to be returned to NRG by year-end as the underlying commodity positions settle during the year.

Cash interest expense was higher during the period due to the timing of payments on the debt incurred with the hedge reset transaction in November of 2006.

While annual payments on the $1.1 billion note are scheduled for January and July of each year, the first payment after issuance was not due until July of 2007.

As such, we did not have an interest payment on those notes in January of 2007, but we did in January of 2008, which resulted in a negative variance to first quarter of last year of $42 million.

This was partially mitigated by lower interest payments on the Company's first lien debt due to lower outstanding balances, lower underlying LIBOR rates, and a 25 basis point reduction in LIBOR spread.

The reduction in cash from operations during the first quarter was significantly offset by a $21 million year-over-year reduction in maintenance CapEx resulting primarily from higher spend during the first quarter of 2007 related to one-time plant improvements at STP 1 and 2.

If we exclude the effects of cash collateral, free cash flow from recurring operations increased slightly year-over-year from $138 million in 2007 to $143 million in 2008.

Free cash flow for the Company during the first quarter declined $103 million to -$118 million, compared with the first quarter of 2007.

Aggregate CapEx was $57 million higher during the first quarter of this year than the same period last year, primarily due to higher Repowering investments, including $47 million in wind turbine payments related to our Elbow Creek development in Texas, $22 million for the Cedar Bayou 4 project, $12 million in capitalized costs for STP 3 and 4, and $10 million at El Segundo, in preparation for new construction next year to support a ten-year power purchase agreement recently awarded to the site.

The impact of the $60 million in cash from operations, coupled with the $164 million in capital spend, can be seen on Slide 14, which outlines the Company's change in liquidity since year-end 2007.

Aggregate liquidity during first quarter declined by $374 million from $2.715 billion at December 31, 2007 to $2.341 billion at the end of March 2008.

$288 million of the decline in liquidity was due to the previously mentioned CapEx investments during the period, coupled with debt repayment and share repurchases.

On March 25, 2008, NRG offered its first lien lenders $146 million as required under the excess cash flow provision in its loan documents.

As expected, virtually all of the offer was accepted, approximately $143 million.

Turning to share repurchases, in March 2008, as the CSF-1 restructuring was being finalized, the Company repurchased $40 million of common stock, or 938,000 common shares, at an average price of $42.65.

This, together with the previously announced $15 million share repurchases in January 2008, brought total first-quarter 2008 share repurchases to 1.3 million shares for total consideration of $55 million.

Liquidity was further impacted by the issuance of an $87 million letter of credit in support of NRG's equity commitment to the Sherbino wind project, our 50%-owned joint venture in Texas with British Petroleum.

This letter of credit will be returned to NRG once our full equity commitment has been funded, which is expected by year-end.

As highlighted on the bottom right of this slide, the liquidity numbers presented here do not include the net cash proceeds from the sale of Etisa, our Brazilian asset, on April 28, 2008.

Gross proceeds received at closing were $288 million.

However, we expect net, after-tax cash proceeds to NRG to ultimately be approximately $200 million to $210 million.

Having a large and efficient liquidity program enabled NRG to continue to aggressively pursue value-accretive initiatives during the quarter, even in the face of a very challenging credit market.

I would also note that the value of this program, coupled with improvements in the Company's leverage metrics, was recently acknowledged by Moody's ratings agency, as they removed the negative watch from our corporate credit ratings and upgraded NRG's liquidity rating from SGL-2 to SGL-1.

As we look forward to the rest of 2008, we are maintaining our annual EBITDA and cash flow from operations guidance as outlined on Slide 15.

One of the things that we will be keeping our eye on over the rest of the year is cash collateral movements, the expected rolloff schedule, and its impact on cash from operations guidance.

While maintenance CapEx remains on target, we do expect environmental CapEx during 2008 to decline by $72 million, compared to previous guidance, primarily due to a delay in the start of environmental projects at Big Cajun II and Indian River.

Our Repowering investments guidance of $642 million includes Repowering CapEx of $605 million, including $72 million for the recently announced El Segundo project, $87 million for our equity investment in Sherbino, offset by the $50 million investment in NINA by Toshiba.

Therefore, we expect our free cash flow for the year to increase by $33 million from previous guidance from $249 million to $282 million.

I would note that the positive impact of redeploying the net cash proceeds from the sale of ETISA is not reflected in this cash flow slide.

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 a double-digit recurring free cash flow yield.

Turning to Slide 16, we have made significant progress towards delivering on the targets outlined under the 2008 capital allocation program.

To date, we have completed $140 million of the targeted $300 million in share repurchases.

We anticipate executing opportunistic share repurchases throughout the year for the remaining $160 million to reach our stated goal by year-end.

While we have completed the CSF-1 restructuring, pushing out the maturity of the financing to June 2010, we only extended the settlement of the embedded call options by 30 days to the end of December of 2008, and we intend to settle them at that time.

We've also made significant strides in reducing our debt with a total of $154 million in repayments during 2008.

This, coupled with the previously announced $300 million prepayment in December 2007, brings total debt reduction under the current plan to $454 million.

We anticipate an additional $68 million in scheduled debt repayments, most of which are project-related, during the balance of the year.

As I mentioned previously, our investment programs are all on track for the year, so as we move forward, we expect to meet or exceed the capital allocation targets we've put forth for this year.

With that, I will turn it back to you, David.

Thank you, Clint.

Well, in a few minutes -- I want to take a few minutes, before we open the ones to questions, to focus on one of our initiatives.

If you turn to Page 18, you'll see several of the long-standing corporate initiatives.

These initiatives I think in many ways define NRG, and certainly they drive our efforts at value creation for all of our stakeholders.

Today, I want to focus just a few comments on just one of these, and that's the activities of our Commercial Operations Group.

I want to talk about the Commercial Operations Group this quarter not only because they had another exceptional quarter in this case angina assets, but they did so notwithstanding the unusually tumultuous market conditions that existed, as the problems on Wall Street, particularly the problems around Bear Stearns, from time to time infected the commodity markets.

In that regard, it's important that you understand what we do and what we do not do because, as prices rise and markets swing, it becomes inevitable that related commodity prices occasionally delink and correlations temporarily breakdown.

This leads to mark-to-market swings in our accounting results which, given higher price levels and increased hedging activity, are somewhat bigger this quarter than previously.

So if we turn to Page 19, I want to start by reminding you of what our Commercial Operations Group is tasked with doing.

Their mission is to systematically but opportunistically reduce the risk inherent in being fundamentally long physical generation, in an immensely capital intensive, highly cyclical commodity business.

They do this in multiple ways, through filling gaps in our load-serving obligations, managing basis risk, interfacing and taking our open position to market, procuring fuels and emission credits to the extent needed, and implementing our baseload hedging strategy.

The CommOps group also looks to capture the extrinsic value around our generating assets and the core commodities which we either use or produce at our plants.

While we see ever-increasing value creation opportunities in this area, our activities remain closely tied, in terms of geography and scale, to our own physical operations.

On Page 20, I also want to remind you in very simple terms of the key commodity exposures associated with our business, which price direction favor us -- since they are not all intuitive -- and our general outlook with respect to ease.

Leaving aside the all-important natural gas question for a moment, rising E rates and capacity price levels obviously are good for us, and the outlook is generally in the right direction in both of these areas, even though out-year heat rates have compressed substantially over the past few months and New York capacity payments have dropped as a result of regulatory changes affecting the New York market.

Perhaps the most surprising aspect on this page actually has to do with SO2 prices.

In recent months, SOX prices have dropped well below the cost of new scrubbers.

The increasing disconnect between the cost of SOX credits and the cost of SOX compliance through the installation of new scrubbers has us reevaluating our compliance strategy around certain of our plants.

You'll be hearing more from us on this topic on future calls.

Now, turning on Page 21 to the most important topic for this call, which is natural gas, for at least the past two years, we entered the summer with a fundamentally bullish view on natural gas long-term, but a neutral to bearish view on gas prices short-term.

This year is different; we enter the summer basically as a double bull, bullish short-term, bullish long-term.

Short-term in some ways we think we're coming close to a perfect storm of bullish signals.

Let me just mention three -- first, lower inventory as a result of a late cold winter and domestic supply disruptions at the independent's hub; second, the prospect that unlike the last few years of either unseasonably hot early summer weather or an active hurricane season in the Gulf of Mexico; and third, the fact that, at present prices, it appears highly unlikely that spot LNG cargoes will keep the lid on this summer as they did last summer because of the higher spot prices for LNG in both Europe and Asia.

Long-term, the fundamentals remain as they have been.

International demand for transportable hydrocarbons continues to significantly outpace world supply and natural gas remains, as depicted by the graph on the right side of this Slide 21, by far the cheapest hydrocarbon in and around the petroleum complex.

Compounding the impact of robustly increasing international demand, the United States with its weak dollar and its addiction to cheap fossil fuels will increasingly have to resort to natural gas to meet its electricity demand growth, since non-natural gas-fired generation is simply not be added fast enough or on a sufficient scale to avoid substantially increased demand for natural gas over the short to medium-term.

Turning to Slide 22, our fundamental point of view on natural gas informs many different aspects of our business, but the most obvious and perhaps the most directly correlated to our future financial performance is the influence it has on how we execute our baseload hedging strategy.

We have made it clear for many quarters that our intention was to fill out a substantially hedged baseload position, but to do it opportunistically during times of commodity price strength.

As both Bob and I have discussed here today, after four quarters of virtually no baseload hedging activity, we made a very substantial 28 million MW hour move this quarter.

What the graph on the left shows is that hedging activity took place in a substantially higher pricing environment than had existed during the previous four quarters.

Beyond this, the point you should take away from this discussion is that NRG intends to act on its bullish point of view, with respect to natural gas, not simply by discarding its baseload hedge philosophy in favor of staying exposed to the market, but rather by substantially shifting northward the pricing points at which we intend to enter the market to fill our baseload hedge position.

This, from our point of view, is best for our shareholders because, while the alternative -- staying way long to the market -- may have superficial appeal to those who like to stare into the distance at the mirage of open EBITDA, at NRG, we prefer to execute a strategy that leads to the reality of higher EBITDA, one that high gas price hedges are realized.

Now, finally, in conclusion, I want to point out that, as always, there's much that remains for us to do.

Summer is on the horizon and financially for us in this industry, summer is our Christmas season.

This year looks like there's the potential for a significant gain, but everyone at NRG knows that it depends on our execution day in and day out.

It's not so much the senior executives who sit here with me in this room, but the 3000 men and women of NRG who make the machines hum every day who achieved this excellent first-quarter result.

So I want to thank all of them for a job well done, and I want to promise each of you on the phone that we will bring the same focus, dedication and professionalism to achieving strong results in the months and quarters to come.

So operator, with that, I'd like to turn it over to you to open the lines for questions and answers.

Thank you.

(OPERATOR INSTRUCTIONS).

Elizabeth Parrella, Merrill Lynch.

Yes, thank you.

One question for you -- could you talk a little bit about your reasoning as to not updating your market EBITDA slide that you included in the last quarter's call?

Clint?

Sure.

Elizabeth, I think our thought, at this point, is to update the market EBITDA slide when we provide annual guidance, typically during the third-quarter earnings call.

At that point, like we did last year, we provide our sensitivities for the year based on a number of different commodities.

So we believe that should give you a pretty good view into the potential performance, on an open EBITDA basis, of the Company for the year.

So at this point, I think our intention would be to refresh that analysis when we provide 2009 guidance on the third-quarter earnings call.

Okay.

A question on a different area -- you mentioned, with respect to your in-city capacity, that you had hedged I think you said the majority of it for 2008.

There is obviously a big change between the '07 price and the '08 market-clearing price.

Can you talk, give us a little bit more color on kind of relatively where your hedges are and also whether you've hedged any of it for 2009?

Elizabeth, we won't get specific on prices for 2008.

We do have some hedges on 2009 as well, but certainly the majority of the hedges we have are in '08.

Okay.

Some, but it sounds like not a majority for 2009, would that be fair?

That's correct.

Could I ask one other question, just in general on the hedging strategy?

It's sort of a two-part question.

Is there any kind of rule of thumb you can provide us in terms of sensitivity to additional collateral posting or sensitivity to changes in gas prices -- how much collateral you would have to post on the current hedges?

The other part of that question is can you just talk about what the capacity is under the first lien structure for doing more hedges?

Well, on the first one, the sensitivity of cash collateral postings, relative to increases or changes in gas prices, is basically a $1 move in gas prices across the board from 2008 to 2014, which obviously would be an enormous move.

It would be about an incremental $65 million in margin postings.

But again, that's gas.

I mean, we obviously trade in some other commodities as well.

On the first lien structure, Clint, do you want to talk about that?

I don't have the exact figures with me, but right now, we've got pretty significant room left under the first lien hedge program.

We can hedge up to 80% of our baseload capacity and typically, the hedges that we do, the longer-term strategic hedges or the hedges that are underneath that program.

So it this point, I believe the numbers are in the 50% to 55% of that available capacity going forward.

50% to 55% available?

No, I'm sorry, used.

Used to date.

Used to date.

And that's like a five-year number, Clint?

the 80% -- like through 2013, or is it shorter than that or --?

Yes, actually I have the numbers here.

Of the 80% amount that we can hedge under this program for 2009, we've used about 58% of that 80%.

For 2010, we've used 55% of that 80%.

For 2011, we've used about half.

Dan Eggers, Credit Suisse.

Good morning.

Welcome aboard, Jonathan.

The first question for you -- if you could talk a little bit about the contraction in Texas heat rates, what that one does from an accounting perspective to hedges in place; and then, two, how that is affecting or changing your thought process for hedging out forward power, given that heat rate is quite a bit lower than what we've seen in the past.

Well, let me hand that to Mauricio, because I'm not sure how much he's going to want to be telling you about the -- or how it's going to change our hedging strategy, but go ahead, Mauricio.

Sure.

Well, I mean, this was another quarter where we saw compression in heat rates in Texas through 2013.

I would say particularly on the north zone, which was more impacted by the uncertainty of wind generation.

My general take is this was driven primarily by the sharp increase in natural gas prices, which tend to naturally compress heat rates.

Two is the uncertainty around the buildup of transmission in Texas.

The latter, I think the relevancy is probably beyond this trading period, after 2012 and 2013.

You know, we continue to be bullish, and I think 2008 is an example of that.

While heat rates decrease 2009 and beyond, 2008 heat rates increase significantly, which is more in line with our expectations, at least in the next three to five years.

Given the market concerns about transmission, wind, etc., does that have any impact on your longer-term reinvestment strategy for Texas as far as building new plants, or do you think the market is overreacting to these potential supply events?

Well, I think this is -- the question of the transmission buildout to accommodate renewables in Texas is the big issue for the next few months.

In some ways, I think there is a bit of an overreaction of the market.

You know, I think, as we look in terms of our asset position, if you think about the impact of wind long-term in Texas, it's certainly, again depending on how much transmission is going to be built, it certainly can nick our baseload generation, which is the center of our profitability in Texas.

But I say nick because it would mainly impact our baseload generation off-peak and during the shoulder seasons.

I think where it has more direct impact is on the seven heat rate combined cycle plants, and we don't have many of those.

But there have been reports in the press about various people sort of looking, thinking twice about adding additional seven heat rate gas-fired combined-cycle plants.

I think it would be fair to say you to put us in that same category is that how much we would do of that certainly has to be taken into account, the wind impact.

John Kiani, Deutsche Bank.

Good morning.

I have a few questions.

First, can you provide a little bit more color on the improved performance and EBITDA contribution from South Central?

Yes.

Did you want to ask all your questions first or do you want to -- just so we can prepare ourselves?

Sure, sure.

The second question is what's your latest view on MIBRAG and the potential monetization of that asset?

Okay.

You're going to limit yourself to two?

Obviously you're scared of Nahla, okay.

I am very scared of Nahla.

Bob, do you want to talk about South Central?

John, on South Central, what you look at the EFOR rates, and I think the plant has done a great job over the past several quarters of improving it, but this really just dates back several years of being more judicious and making sure that we're doing all of the preventive maintenance we're supposed to be doing, we are reinvesting where we need to be.

We've got targets to make these plants just be top quartile or in Texas, top decile; we just continually strive for it.

Obviously, having the MW makes a significant difference for us.

We are committed to drive these plants, run them well and maintain them well to get these types of performance rates.

From a hedging perspective, it sounds like you all have done a good job of hedging the short position for the load following contract in the summer months out at least a few years.

Is that safe to assume?

Yes, I think that's the other part of it, too, John, on the reliability, where we try to minimize the cycling of the plant down in South Central by having [tolls] to back up some of the peak periods when the plant has to run up or the off-peak where it comes down.

We try to balance developer using those [toll] arrangements.

Okay, thanks.

That's helpful.

John, on your second point, we certainly are considering our MIBRAG options.

We tend to these things with the international assets in sequence, number one.

Number two, we are in a 50-50 partnership at MIBRAG and there's been a change in ownership of the 50% partner, you know, last November.

That has led subsequently to sort of occasional changes in personnel that we are dealing with.

So we would prefer to evaluate our options together with our 50% partner, because we've had trouble in the past trying to do something with the 50% partner not on board.

So you know, we're looking at the situation, considering what our options are for value optimization, but it's gone a little bit more slowly than we thought.

But we don't see any reason why we wouldn't be considering our options fully at this time.

(OPERATOR INSTRUCTIONS).

[Scott Thomas], Neuberger.

I just had a quick follow-up to Dan Egger's question from before.

David, you mentioned, in your comments, about the effects of some of the financial players in the markets maybe derisking and selling off and maybe affecting some of the heat rates in PJM in those markets.

Have you seen that more broadly in the Texas markets or in the West?

So the question is specifically about whether, you know, financial players in some distress are unloading positions because of financial distress and more in Texas than in PJM?

Is that the --?

Yes, just looking at the timing of when those heat rates may be moved down over the quarter, is there some -- can you make some educated guesses about whether that was a factor?

Well, you know, Mauricio is much more at the coal phase on this one, so Mauricio?

I would say that it hasn't spilled over to Texas, and my take is probably localized to the Northeast markets.

Okay, that was really it for me.

Thanks, guys.

[Ficus Dewevetti], Morgan Stanley.

Good morning, guys.

Just I know you guys are substantially hedged on your PRB purchases for awhile, but any thoughts on how that market and its pricing may be evolving over the longer term, given what we've been seeing in the Eastern markets?

Well, I don't think that -- I would invite Mauricio if he has a different point of view, but focusing on Powder River Basin itself, you know, we see limited ability for what's going on with Eastern prices, in terms of the international demand, to actually pull Powder River Basin prices out of where they stand now.

Over the medium to long term, we think, with Powder River Basin, it is going to come back to what it's always come back to -- is making sure that the suppliers get a bit of a margin over their costs.

Their cause levels are rising, so maybe that supports pricing close to where they are.

But we don't see them blowing out from here, and that's particularly the case for 8400 Powder River Basin coal which, as we demonstrated on Slide 7, is the most substantial portion of what we buy.

Mauricio, do you -- no, Mauricio agrees.

David Silverstein, Merrill Lynch.

Thanks for the comments on the ERCOT market.

Just to touch base again on PJM, I know you guys don't have as many MW in the PJM market specifically, but what I was wondering is if you had any other theories as to why the sharp selloff has occurred in PJM in the face of just rising coal and natural gas prices.

You know, I think, if you look at (inaudible) margins and pipeline (inaudible) generation, it continues to be fundamentally strong.

I think this is probably just a short-term market trading dynamic.

Okay, thanks.

Lasan Johong, RBC Capital Markets.

I will ask two questions and then just shut up because I, too, am very scared of Nahla here.

Essentially my two questions are one is a matter of confusion because I'm a little puzzled as to how things are working in terms of your hedging policy.

My understanding is that I think, David, you're correct.

If you have a forward curve and you don't hedging against that forward curve, you're taking a view that prices are going to go above that forward curve.

On the other hand, if you take the opposite (inaudible) and say can I'm going to hedge 100% against that forward curve, then the view would be that you don't believe prices will be going up above that forward curve, and so the markets are being foolish and you're going to lock-in that price now.

How do you then juxtapose that position versus your position which I think is the correct one, that the natural gas fundamentals are very bullish?

If you look at Slide 21, the gap between oil and natural gas per mmBtu equivalent is very low.

As you correctly point out, that's probably going to move up.

So then it doesn't quite jive between one picture and other side.

That's my first question.

The second question is, in your alliance with Toshiba, if I'm not mistaken, Toshiba has said they would do four nuclear power plants together with NRG.

So I'm wondering if the $3800 KW pricing Toshiba is guaranteeing NRG would be extended to the other two projects and how Toshiba can achieve that if they don't know when these contracts would be signed and when the plant operations would start and when they would start building the assets.

With that, I will just shut up and let you guys answer.

Thank you.

Well, those are two good questions.

Let me tackle the Toshiba one first while it's fresh in my mind.

First of all, I don't recognize the $3800 number.

I think the number that we put for the actual EPC was a $2900 number.

But what we've said is Toshiba, at this point is -- it doesn't matter whether it's $2900 or $3800.

Toshiba at this point is guaranteeing neither of those numbers.

The reason they are not is for the very point that you raised, Lasan, which is no one can guarantee a number until they know when the plant is actually going to be built.

The process that we've entered into with Toshiba, as it has with price, is to establish a price now as if the plant was going forward, which is built around again for the EPC, the $2900, and then to have an open-book process with Toshiba on the key elements of the price until such time as we get the combined operating license from the NRC, which we expect sometime in late 2010 or 2011, at which point the price will be fixed.

You know, with any change that's been made from the baseline justified at that time, taking into account things that will also fluctuate between the time, such as exchange rate risk.

So, that process is one which we think protects the owner from the fact that one of the issues you have in the permitting process is that you have to commit to someone who is going to build the plant virtually right upfront.

It's virtually impossible, with the way the NRC approval process is, to have a meaningful competition between EPC suppliers at the time you get your combined operating license.

So the process we've worked out with Toshiba is one that gives the owner the grace level of safety that we will not be in a position where, having spent several years and hundreds of millions of dollars of development expenditure, we finally get to that nirvana state where the NRC has provided us with a combined operating license and suddenly the EPC contractor shows up and said "you know when I gave in that indicative number of $2500?

Well, it's actually $7500!

Take it or leave it." So, that's what we worked out with Toshiba.

The other thing I would mention is what Toshiba has agreed to do with respect to the other two units sites is actually -- has to do not only with the price but the full suite of commercial terms, in terms of performance obligations, payment terms and things like that.

In projects of this size, these are very, very important commercial terms.

So that what we've worked out with Toshiba.

On the hedging point, and again I will -- you know, Lasan, I don't agree -- I don't disagree with what you've said, but you've stated it in a very simplistic, binary way, either all in or all out.

You know, what we're saying is that there is somewhat of a middleway.

You have to keep in mind that we are sitting here with 23,000 MW of generation.

You know, the other IPP companies who also have significant generation, when they espouse the idea of staying open to the market, I don't really know what that means.

I don't follow them that closely.

But no one takes 23,000 NW into the day-ahead market.

So sooner or later, you have to hedge.

You know, our point is we are bullish on the market and we are now more bullish than we've been before.

So we have worked out, amongst our team, pricing points which the commercial operations team is going to enter the market and fill the position.

What I'm telling you today is that whole range of pricing points, over the course of the last three months, you know, we've shifted substantially northward.

So it should result in more actual EBITDA.

Again, at this company, we emphasize actual EBITDA, not theoretical EBITDA, through an open market concept.

You're right.

I guess one consequence of that is, if the market continues to rise, you know, obviously, you don't -- you maybe not get the peak of the peaks, but we're convinced that, with this market -- I mean with this approach, we capture the higher EBITDA that comes out of natural gas prices over time while insulating our shareholders to the fluctuations in the downward risk that always exists in this business and we've seen through several cycles in the past.

Sorry, Lasan, for the long answer, but I'm equally afraid of Nahla, so at this point, I will shut up!

(LAUGHTER)

[Miatan Tajilla], Lehman Brothers.

Good morning.

Now, the (inaudible) have come up to the 103, 104 level again, and obviously, last time the Company tried to (inaudible) the whole gross structure, but now the [bonds there are above] 101.

Do you think it's possible that you might come back to get approval even if you don't fund the whole co.

at this point?

You know, that's something that we constantly think about.

We always give thought to how to provide additional flexibility for capital allocation purposes.

You know, we have certainly noticed the rally in the high yield market and it's shone through in the prices for our bonds.

But at this point, I would say that it's not kind of on the forefront of our thinking.

Michael Lapides, Goldman Sachs.

Congrats on a good quarter.

Really two questions -- one on your hedging and hedging strategy.

If you kind of look at Page 22 and the implied gas price in some of your older hedges, it's pretty decently below where the current forward price of natural gas is.

Are you considering at all another hedge reset type of initiative?

That's question A.

Question B is on coal and it's really on rail.

Can you talk about trends you're seeing in terms of rail costs or rail contracting from the PRB to your plants or just from the PRB into the market in general?

Clint, do you want to -- as the architect of the first hedge reset, do you want to talk about hedge reset Part Deux?

Hi, Michael.

We've gotten that question a couple of times, and I think it's fair.

I guess the way that I would answer that is that, right now, that would not be a priory for us.

You know, one of the issues that you face just from a practical matter, even if you decided that you wanted to do something, is access to the debt markets.

I'm not sure that the credit markets would be there in the size that you'd need, in an efficient and price-competitive way to do that transaction.

But even if it were, I would say that, right now, that would not be a priority for us.

We think that, at this point, the open EBITDA analysis that we provide really kind of demonstrates the type of EBITDA and cash flow flow-through you would see with a hedge reset.

But I would just say, right now, it's not a priority for us.

What are we seeing in the coal/rail markets, Mauricio?

I mean, clear to the trends you saw, you know, moving north and we expect that trend to continue.

I guess that would be the short answer.

I don't believe we have disclosed in the past our specific transportation costs, and we're not going to do that on a going-forward basis.

Okay, one follow-up -- I will test Nahla here for a little bit -- going back to the guidance you gave and, Clint, I think you responded to this.

The annual guidance for '08 and more importantly the open kind of EBITDA guidance that you provided, I think it was around $3 billion on an open basis.

I don't remember what the gas price was that was embedded in that and what the sensitivity to the gas price was that was embedded in that.

You know, Michael, actually I don't have that sensitivity with me.

We will get that to you.

Okay, we will follow-up off-line.

Thank you.

Chris Taylor, Evergreen Investments.

Can you talk about heat rates, especially in Texas?

Because the way I look at it, and correct me if I'm wrong, I mean, you've hedged away your gas price risk but you've left open, to a large extent, your heat rate risk.

It seems like gas prices are going in your favor if you are unhedged, whereas heat rates are going against you, where you're not hedged.

Is that a fair way of looking at your 2008 outlook?

Well, I think it's a question of heat rates are expanding in 2008 and contracting in the out years.

So it depends on what you're talking about in Texas.

Is that --?

Well, the whole heat rate forward curve looks weird.

I mean, what's happening in Texas?

Why is Texas -- is it really just wind power?

What's happening to the heat rates in Texas?

Just give us a whole overview there.

Well, go ahead, Mauricio.

I guess we covered it, but I will expand again.

I think we do agree with you that the heat rates look weird through 2013.

I think it's probably an overreaction on the uncertainty of the transmission buildout to support I guess the potential wind generation in West Texas.

If you look specifically at 2008, our heat rates have increased significantly.

I think that is probably more in line with what we can expect, at least from now through 2011, 2012 when that transmission could potentially come online.

I mean, we maintain our bullish view on heat rates and I think that is consistent with our hedge position.

If I could just -- Chris, I don't know how long you've followed heat rates in Texas, but you know, there was a similar phenomena a couple of years back after TXU announced they were going to build an enormous number of baseload coal plants.

You know, it actually crushed the heat rates in Texas in years far beyond when any human being could conceivably build a coal plant.

So, I mean in a sense we're seeing the same thing.

I think that the market will get better knowledge about when the transmission could be built and how much will get built as the PUCT this summer goes through their hearings and makes a decision on how much transmission to build.

But as Mauricio says, we know of no plan that provides for substantial transmission of additional transmission to bring the wind power from West Texas into the populated parts of the state, certainly not into the south stone through 2012.

So, why heat rates before 2012 would be crushed over that, you know, is hard for us to understand.

The other phenomenon that we've seen is that heat rates in all markets tend to compress temporarily when forward gas prices are shooting up.

So that's -- but that's not a phenomenon that would be limited to Texas at this point.

That would probably also explain (inaudible) the Northeast.

And short-lived.

I mean, power tends to lag gas and at one point, we will catch up.

Yes.

So, we are not overly concerned about this, but you're right.

We are speaking during moments of heat rate aberration.

Operator, I think we have time for one more question.

Elizabeth Parrella, Merrill Lynch.

Thanks for allowing me a follow-up.

I guess I must not be sufficiently scared of Nahla.

I just wanted to ask Clint if he could give us an update on the level of the restricted payments basket.

Sure, Elizabeth.

As of the filing of the Q, we will have about $150 million in restricted payments capacity.

Okay.

Thanks to all of you very much.

Thank you, Elizabeth, and thank you all for participating in the call.

Ladies and gentlemen, this does conclude the conference call for today.

You may now disconnect your line, and have a great day.