NRG Energy Inc (NRG) 2007 Q2 法說會逐字稿

Good morning, ladies and gentlemen.

Welcome to the NRG Energy second-quarter 2007 earnings results conference call.

I would now like to turn the meeting over to Miss Nahla Azmy, Vice President of Investor Relations.

Please go ahead, Ms.

Azmy.

Thank you, Sam.

Good morning and welcome to our second-quarter 2007 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 our 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 do ask what you please limit yourselves 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 August 2, 2007 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 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.

I'm joined here today by Bob Flexon, our CFO, as usual who will be doing part of the presentation.

But also, as we are originating this call from the West Coast, I'm also joined by our regional President for NRG West, Steve Hoffman.

Jan Paulin, who runs Padoma Wind, our wholly-owned winded subsidiary, and Drew Murphy, our General Counsel, and they will be available to answer any questions that you have about their areas of expertise.

I thought that, in a little bit of a departure from our normal way, looking at Slide 3 in terms of our presentation, rather than boring you with the same agenda we always show, that I would start by focusing on the current themes.

As usual, there's a lot going on at NRG but I think a little bit different maybe some other (inaudible) there's obviously been some noise swirling around the Company and the Company's capital structure in terms of the unrest in the market.

So, I really wanted to focus on these themes.

First and foremost, the reason that we are here in California is actually for the ribbon-cutting of the Long Beach Emergency Repowering project, which is the first started and the first completed of our 10,000 MW $16 billion repowering program.

I think it's a great project and a very significant project, and I'm going to talk more about that later.

Second, I want to just point all of your attention to the strength of our baseload hedging strategy.

Keep in mind that we have a quarter where there's been a significant decline in gas prices on the front end of the curve, and there's been absolutely no sustained period of hot weather in any of our core markets so far this summer.

Yet, our hedge position allows us not only to reaffirm our products but also to raise it.

The third thing I want to mention, in terms of what we always talk about, prudent balance-sheet management and the strength and flexibility of our capital structure.

There's obviously been quite a bit of speculation about whether we will force the previously announced Holdco structure into an uncertain debt market, and I think, today, we can end that speculation.

We will not do that.

Not only will we not, but we have alternatives which will allow us to reach all or close to all of our previously stated objectives of a 3% annual return of cash to our shareholders through dividends, share buyback or both.

Finally, the Repowering program, in general terms, after 15 months where we've been hard at it, we expended a considerable amount of time and money on the program, I really believe we're on the cusp of reaping significant rewards.

In addition to Long Beach, other projects are breaking through.

Most notably and most obviously, I'm extremely pleased with how our nuclear development project, STP 3 and 4, is shaping up on all levels and in all aspects.

While the time today is not quite right for a full briefing on that project, I look forward to being able to provide considerably more detail in the weeks to come.

Looking at slide 4 and highlighting the Long Beach project, just a little bit of a background -- this was a super fast-track project conceived, bid and constructed in response to a request for offers issued by Southern California Edison at the behest of the California Public Utility Commission last fall.

They wanted significant incremental capacity and they insisted that it be delivered with a high degree of assurance by yesterday, August 1, 2007.

In response to this RFO foe at Long Beach, which is a very old facility that we had previously mothballed, we went from 0 to 260 MW in nine months.

Indeed, the physicals construction was started and completed within four months.

Long Beach finished commissioning last week and was accepted by Southern California Edison in a ceremony which was held on site yesterday.

For those who understand what it takes to engineer, procure and construct power generation facilities and to secure the necessary permits in a place like Southern California, this result is truly extraordinary.

I'm not sure how many power companies in the world could have moved with such speed and effectiveness.

The Company put significant money at risk to achieve this result, but the reward is significant as well.

In less than 12 months, we took a plant that was costing us $2.5 million a year to mothball and turned into a $25 million a year productive asset.

I personally and publicly want to thank Steve Hoffman, our regional President, for all he did on this project, John Brewster, who headed up our new engineering procurement and construction function, Dave Harris, who led the construction effort, Bill Leonard and the entire team that did the work day-to-day for achieving this spectacular result.

Looking at Slide 5, again, I think this is not only a very good project but it has positive ramifications far beyond its immediate financial impact.

As I think I mentioned at the last quarter call, I think this type of super fast-track project is going to become increasingly prevalent as the authorities in all of our core markets recognize that the reserve margins are shrinking and they need solutions that will bring incremental capacity on in a very short period of time.

That obviously benefits people with existing sites.

They have a fundamental advantage in that, but to have existing sites in or near load centers I think puts us at a tremendous advantage.

In terms of our own assets, it allows us to utilize under-utilized or non-utilized, existing structure, and by so doing monetize that infrastructure.

Then also, in some ways, while there are risks, obviously, in redeveloping old sites and moving as quickly as I think these types of solicitations are going to require, there are also certain risks that we don't have.

In particular, we don't have to worry as much about the [Extra Now] lease since these plants will all have their fuel infrastructure in place in terms of fuel into the plant and transmission out of the plant.

Finally, it allows us to deploy our extremely skilled workforce not only in the existing units but on new units next or restored power units.

This project itself has allowed us to build up an EPC group which has implemented best processes and procedures in anticipation that they will be constructing bigger things in the months and years to come.

Now, turning from Long Beach to focusing on financial highlights, as usual, Bob is going to go into this in considerable detail, but from my perspective, financially it was a strong quarter for us, adjusted EBITDA up over 60%, quarter-on-quarter.

These results demonstrate very solid execution from all of our business segments, particularly Texas and the Northeast, and as always, supported by very solid plant and commercial operations activity.

While a significant portion of the upside was a result of the Texas hedge reset that we completed last November, there's also another part of the story.

The Northeast results, for example, more than doubling in the quarter due to improved generation, power capacity revenues, coupled with active commercial operations strategies that aided in offsetting the mild weather conditions in Texas and in the rest of the country.

So as a result of our solid financial performance year-to-date and our fully hedged position for the balance of the year, we're in a position to raise our EBITDA guidance by $50 million.

I believe that, particularly in light of the mild weather and the falling gas prices, it's quite a strong statement about the soundness of our baseload hedging strategy and the strength of our execution across all regions and all functions.

Now, moving from financial to operational, looking at Slide 7, starting with safety in the top left chart, we are pleased with the improvement in our OSHA reportable rates as we move down to 1.7 from 2.0 at year-end.

This has been driven by material improvements in the West Coast where we had 0 recordables, even with a construction project, and also improvements in the Northeast.

As mentioned on the last call, the staff and plant management at five of the NRG classic plants are working together to qualify for OSHA's VPP program which has been such a success at our Texas plants.

Thanks to their focus and hard work of the employees at those plants, four of these five plants and 0 injuries today.

Moving to key operational performance metrics, the E-4 results on the bottom left chart -- statistically, we were flat year-on-year in the second quarter, but embedded within these statistics are two factors that merit specific mention.

In our last call on May 2, I noted that Indian River unit IV, which is the biggest unit at Indian River, suffered condenser and water wall issues throughout the first part of the year, leading to a pre-outage E-4 rate of over 20%.

Indian River IV completed a ten-week outage in late May.

The unit's performance, post-outage, has improved significantly but it's probably been insufficient time to draw any definitive conclusions.

The second statistical driver hurting group E-4 relates to transmission constraints around our Dunkirk plant, which have led to higher forced outage rates at that plant.

While this affects E-4 rates, it does not impact revenues as NRG recovers these transmission constraint margins in the day-ahead market.

Moving to the right-hand chart, you can see that our generation was down, quarter-on-quarter, largely driven by the mild summer weather in Texas.

You can particularly see this in terms of the level of generation from the gas plants in Texas.

Nuclear plant generation is down as well, but that's actually just as a result of the 18-month refueling cycle that nuclear plants are on, so that's not a performance issue.

So, production is down year-on-year.

Shifting to the figures on coal inventory in the bottom-right quadrant, despite challenges to railroad and mine performances during the second quarter due to adverse weather conditions, we continue to maintain a very healthy coal inventory position with aggregate inventory levels above our targeted range of 25 to 30 days.

As we said before, we've built these inventory levels across our fleet in excess of our expected coal burn in order to mitigate the risk of transportation or supply disruptions in the future.

Turning to the overall FORNRG program, which is depicted on Slide 8, again we show the multi-year EBITDA targets for this program, this time divided by functional areas rather than by regions.

The aggregate numbers' objectives have not changed, upwards or downwards, since we last updated these targets, nor has our confidence that we will achieve these targets.

What I'd like to do today hopefully is shed a little more light on the significant portion of the annual FORNRG savings which we have generated in the past and expect to generate in the future from sources other than improved plant performance.

Looking at Slide 9, we have spoken a lot about -- we have spoken some about these FORNRG initiatives (technical difficulty) areas, but I'd like to give a little more detail.

I mean, on the right side of this slide, actually you can see that there are significant initiatives underway with respect to plant operations within that group to drive top-quartile reliability and performance from our baseload plants in particular.

I mean, the only thing I really need to add here is just to remind people that the FORNRG program, in terms of the plants, does not incorporate Texas, as the Texas fleet is already operating in the top decile of national performance.

In terms of corporate, we have been quite successful in executing projects and initiatives that have resulted in the reduction of insurance premia due to improved plant performance, reduced tax and cash outflows due to efficiencies in our tax structures, and in better cash-management practices.

A principle area of current focus for us is now procurement.

We see such significant opportunity embedded in this area that we have segregated procurement from corporate and operations.

We have several procurement-related initiatives underway or under consideration which give us confidence not only that we will meet our current FORNRG targets but raise the possibility that there could be additional upside if we are particularly affected in the execution of these procurement initiatives.

One such service is fleet-wide maintenance and outage services.

We are in the absolute final stages of completing an arrangement with [Fleur], which will encompass our outage planning, scheduling, execution and continuous improvement functions.

Working with [Fleur], we expect to be better able to achieve economies across our fleet, standardize on Best Practices, and leverage [Fleur's] experience and depth with the intent of reducing outage durations, forced outage rates, third-party reportable industries, and our nonfuel O&M costs.

With the outstanding historical performance of NRG Texas, we see greater opportunity in managing the maintenance of our plants as a fleet versus a regional approach.

Today, across all of NRG, we utilize over 600 vendors for these services and as a result of these new initiatives will reduce that to a fraction over the coming 12 to 18 months.

The arrangement with [Fleur] will be a performance-based agreement that creates a high degree of alignment between us.

Their compensation will be based on our plants meeting E-4 O&M costs, safety and other key performance metrics.

As such, not only do we expect significant actual cost savings out of the arrangement with [Fleur] but we also expect that improved outage planning and execution will enhance our ability to meet and exceed our operational performance targets as well.

Finally, the alliance with [Fleur] also has one defensive benefit; it will allow us to better manage labor constraints that are forecasted in the coming years through improved resource planning and leveraging -- I'm sorry, leveraging [Fleur's] capabilities and sourcing qualified labor to meet our needs.

Now, switching to Commercial Ops, starting on Slide 10, this slide is a reminder that our commercial operations function is tasked first and foremost with maximizing the value of our assets, then taking positions wherever possible that reduce the inherent commodity risk of our physical portfolio, and finally in trading around the assets to maximize extrinsic value.

These are our three objectives in that order of priority.

In terms of meeting these objectives, our Commercial Ops group has had an outstanding year-to-date.

In particular, they correctly anticipated the relative softness of the summer market and sold forward much of our peaking capacity prior to the beginning of the summer.

As such, even though the output statistics that I showed before for our peaking plants are off significantly from last summer, the actual earnings of these plants has been healthy.

This performance by our commercial operations group is a very significant reason why we are in a position to raise guidance today.

Turning to Slide 11, one of the critical benefits of our long-term hedging strategy is that we can pick our spots as to when we hedge.

That being said, given the trend during the quarter in gas prices, it should not come as a surprise to you that we have not added much in the way of medium to long-term hedges.

Early in the quarter, while gas prices were still robust, we increased our hedge position in 2008 by 3%, as shown in this graph on the left.

Since then, average prices have retraced and are currently below our target prices for incremental hedges.

We continue to monitor our position for 2009 through 2012 and expect to execute additional hedges optimistically as prices rise within the range of our expectations, given our fundamentally bullish point of view.

On the fuel side and specifically commenting on coal, near-term Powder River Basin prices continue to strengthen through the second quarter of '07 as the market responded to lower-than-expected coal-production volume in the Powder River Basin.

However, we have not been affected by the increase in near-term PRB prices as we hedge beyond our requirements in 2007 at prices below current market levels.

Cal '08 and '09 Powder River Basin prices rose during the second quarter in response to the higher prices at the front end of the curve.

As with the last quarter, we had an opportunity to add approximately 3.6 million tons in additional PRB hedges for our plants in the 2009-2010 timeframe at prices well below current market.

We are comfortably hedged, in terms of coal for 2008 and 2009, and will continue to look for opportune times to add to our limited needs in the years to come.

One commodity -- before I leave the slide, one commodity fuel which we have not previously commented upon but which questions have arisen recently is uranium.

Uranium procurement for us is managed by the STP operating company, subject of course to the oversight of NRG and the other partners in the project.

The units at STP are 100% hedged in terms of uranium through 2012.

We do not expect the South Texas project will need to be back in the uranium market until such time as the market settles down.

Turning to Slide 12, looking at heat-rate sensitivity, we continue to retain significant heat-rate upside on our baseload fleet.

We do that by using gas swaps rather than power swaps in terms of our hedging, particularly in the out years.

You can see the sensitivity to heat rates on the right-hand side of this slide.

We will continue to focus on converting some of the existing natural gas hedges to power hedges in order to capture the forecasted heat-rate expansion in the medium term.

As you can see come at the front end -- as the front end of the curve has dropped, 2009 and 2010 have risen to the point where rotation from gas to power begins to make sense.

Overall, however, we continue to maintain our view that we should retain significant heat-rate upside, particularly for 2011 and beyond.

Also on this slide, I wanted to preview the commodity price rationale for the Cedar Bayou IV plant which we are announcing today.

Using the heat-rate chart on the left, we depict two heat-rate curves, one from late last year which reflected the depressed curve which, at the time, was anticipating an overbuild situation in Texas.

Since the cancellation of the coal plants, heat rates have corrected and now reflect at least for a couple years in the 2009 and 2010 timeframe and imply a breakeven heat rate for a greenfield combined (inaudible) unit.

But what should be interesting to you is the broken line on this slide depicting our breakeven for Cedar Bayou 4, which demonstrates our cost advantage which we have largely due to the fact that we have an existing site, the existing equipment value.

These are concepts which I will discuss a little bit in greater detail in the Repowering section.

Finally, in terms of Commercial Ops, looking at Slide 13, I just want to make sure that, in this summer of mild weather and unremarkable loan demand, everyone recognizes the ever-increasing value of our peaking fleet as merchant market fundamentals improve.

It's actually enigmatic that, as reserve margins tighten in all of our core markets, the utilization of our oil and gas fleet, which is over 13,000 MW, will increase.

As such, these plants represent an enormous out-of-the-money call option on the improving heat-rate environment.

For the present at least, there's very little evidence to suggest that there is going to be a wave of new builds that will threaten this improved market situation.

Indeed, notwithstanding our success with Long Beach, given the relative dearth of development activity around our industry today, it's hard to imagine that even a concerted effort, were it to be begun today to add new generation, would have much of the impact in any year prior to 2011.

Turning to Slide 14, capacity market auctions could continue to be a positive story for the Company and a positive development since last year.

Capacity market auctions are clearing at higher price levels than anticipated.

We expect that, again, given the supply/demand situation, capacity in markets will continue to be strong.

We believe that this is going to continue in part because while capacity payments are increasing, the levels of the capacity payments are not sufficient to keep up with the substantial increase in the costs of new power generation capacity.

That, in fact, is the main reason, over the recent past and will be in the future, that a new generation supply will be inhibited.

Turning to the Repowering program, on Slide 15, I believe that, with each passing day, our Repowering program adds more value to NRG and its shareholders with our ever-increasing early entry advantage and the opportunity to participate in the longer-term growth prospects of the strengthening power sector fundamentals.

This slide shows the range of developments which we have underway and their relative impact on various key factors.

I want to mention again that we're joined here by Jan Paulin, who runs out Wind business and would be happy to answer any questions.

That's an area we haven't focused on too much on past quarterly calls.

The other thing I would just say about this slide -- obviously, you see the importance of the nuclear project, particularly in terms of the avoidance of carbon, which is becoming an increasing issue.

So, we believe it's going to be a very eventful fall for our nuclear project.

The thing I want to tell you about that in terms of this call is "stay tuned".

But today, while nuclear project maybe tomorrow's story, today's story is Cedar Bayou.

If we look at Slide 16, Cedar Bayou is a new, combined-cycle project that we are announcing in Texas using new equipment held or acquired in the gray market at an existing site using existing site personnel, being developed and constructed in partnership with a like-minded partner.

The net effect of this collaboration -- a sharing of the responsibility for the project with a capable and financially well-supported partner and an overall net cash cost of installed capacity to us of about $400 per KW, which is a cost considerably below what we believe is to be the greenfield cost of a new, combined-cycle plant today.

Turning to Slide 17, Cedar Bayou 4 has significant other competitive advantages.

Its time-to-market is significantly less than for a greenfield CC GT, again to the existing site, the equipment on hand and the existing infrastructure.

Further, as you can tell by this chart, its location in ERCOT in the Houston zone -- it's the low marginal cost unit in the Houston zone and is often constrained and has little to no new supply coming before the end of the decade.

Again, this slide doesn't even show the operating synergies that come from colocation and that we have a highly experienced team in place at Cedar Bayou already on site, and that's staffing the new unit and will require only 16 additional personnel.

Turning to Slide 18 and the activities at Padoma Wind, we've made significant strides under Jan's leadership in wind development and expect to be announcing final details of our first few projects in the months to come.

We've reached a stage of advanced development with respect to three wind projects in particular totaling 442 MW gross, 350 MW net, to the Company.

Accordingly, the Company has secured wind turbines from General Electric and Siemens for two of the projects; for the third project, the partner is supplying the wind turbines.

Two of these projects are located in Texas, one of which is scheduled to commence construction this fall while the other is scheduled to commence construction in the summer of 2008.

The third project is in Southern California with construction planned for the early summer of 2009.

These three projects represent a significant total cash outlay close to $700 million in total, but due to the necessity in this market of ordering the wind turbines early, that cash outlay is a bit front-end loaded for us in 2007.

By 2008, we will be arranging nonrecourse debt finance and possibly tax equity on these projects, and the cash requirements will drop significantly.

The other good thing about wind projects obviously is that, like Long Beach, they don't require several years of construction in order to begin generating revenue.

Our 2008 projects will begin producing revenue in 2009.

Turning to Slide 19 and a word on carbon, the purpose of this slide is just to demonstrate to you that we've thought through the carbon issue and are well advanced in structuring our activities to take into account the carbon-constrained business environment that we anticipate and that we're taking into account from all angles.

First, on the policy front, we believe there's growing momentum for implementing federal legislation on carbon in the near-term.

We're actively engaged with key policymakers in this process in order to help ensure a reasonable outcome.

To us, a reasonable outcome is an outcome that actually may do something about greenhouse gas emissions but does so in a way that doesn't gut our industry or damage the American economy by causing natural gas prices to skyrocket.

In order to help achieve this objective, we've entered various coalitions with key stakeholders from industry and also non-nongovernmental organizations, environmental groups, labor groups and the like.

We're doing this to increase our own effectiveness in this process.

Second, we've been enhancing our capabilities to manage carbon risk commercial front.

On May 30, we announced that we joined the Chicago Climate Exchange, which is the world's first voluntary and legally binding greenhouse gas emission reduction registry and trading program.

We believe that this provides NRG with significant opportunity to address climate change issues with limited downside, as it sets us up to develop our own trading capabilities in carbon emissions in advance of potential federal legislation -- track our net long emissions position for Phase I and Phase II, and help us better understand emerging potential carbon offsets.

We also issued an RFP this past February seeking 10 million-ton [carbon] allowance high-quality offsets for [Reggie].

This process has been very useful for us in providing insights into the cost of offsets.

We're pleased with the results of the indicative bids which were received last April.

We saw quite a few proposals for reasonably priced, high-quality offsets which were more than adequate to cover the amount requested in the bid.

We look forward to the final stage of this process, which our final bid is due in August.

Third, what you have heard most often, in terms of our carbon policies, our attempt through the projects and RepoweringNRG is to create a natural hedge to carbon in the form of low-carbon generation resources.

We've plans to meet this country's needs for new generation while increasing our own low and no-carbon portfolio, which will be commercially enhanced by the emerging national carbon policy.

Now, before I end and pass it over to Bob, I'd like to discuss our projected environmental spend, which is directed obviously at the traditional pollutants.

That's set forth on Slide 20.

You will note that we've changed our previous projection from a single point, which was 1.3 billion, to a range of 1 billion to 1.5 billion.

We're doing this for the simple reason that, for the remediation efforts which we have not yet contracted for or begun to implement, the two main variables that influence our cost, namely the capital cost of remediation and the environmental regulations which we are required to comply with, are both so volatile and subject to change that, at this point, that giving a single-point estimate is really quite silly.

At this point, the main swing factor in the range being provided is around our Indian River plant, where we are still locked in discussions with the environmental authorities about the timing and nature of our compliance.

The range in our environmental CapEx estimate represents the full range of potential outcomes.

We will provide an uptake sometime in the next few months as the situation is resolved.

Now, turning to Slide 21, I simply wanted to flag one other area of current management focus and management development in the Company, which is the building up of our EPC group and particularly of our construction management capability.

One of the more significant reasons that our G&A spend is above budget this year is due to the earlier-than-expected buildup of this group and that buildup of G&A spend.

That's the bad news.

The good news is that we're building up this group in order to handle the significant increase in projects that are actually under construction that we expect to break ground on in the very near future, in the next few months.

Today, we've successfully completed one project, Long Beach, but you can appreciate that the construction management resources and back-office support, which will be required when we're simultaneously constructing several projects in multiple markets, will be commensurately larger.

We are prepared for this construction load now.

Finally, on Slide 22, by way of conclusion, I'm trying to depict visually what hopefully you all have gathered from my comments today, which is the interconnectivity and mutually reinforcing value creation of all that we're doing at NRG.

While it sometimes [seems] internally, as we are constantly moving in every direction at once, we actually are moving at all times to advance all aspects of our business which need to be advanced to ensure that we can create value for our shareholders while effectively managing the risks inherent in our business.

Bob?

Thank you, David, and good morning.

Today, I will provide our customary review of our second-quarter financial performance, along with an updated 2007 outlook.

In connection with our Repowering advancements announced today, I will provide additional information on the timing of capital expenditures and preliminary financing plans.

My final topic will address capital allocation, the planned formation of the Holdco structure, and how the current credit market volatility may impact its implementation.

While we continue to review our alternatives, I will highlight right now that we will not put the Company at risk by entering an unstable credit market.

We stand by our commitment of returning capital to shareholders.

Should we elect to delay initiation of the common stock dividend, we will increase our common share repurchases in 2008.

Let's begin with a review of the second-quarter results.

The second-quarter 2007 EBITDA was $577 million versus $393 million for the same period last year, as shown on Slide 24.

After removing the forward mark-to-market impact from EBITDA, quarterly adjusted EBITDA increased about $205 million to $533 million, a stronger quarter than what we had forecasted.

Second-quarter gross margins benefited from the $156 million revenue increase in the Texas region from the November 2006 contract hedge reset.

Lower Texas gas generation versus the prior year, due to cooler weather and lower capacity revenues, are more than offset by a 5% increase in baseload generation and merchant revenues.

The Northeast had a strong second-quarter performance as gross margins increased by $48 million, mainly from a 9% increase from generation and higher pricing.

Gas generation at our Arthur Kill plant increased 108% during the quarter, versus the same period last year, as it was called upon frequently to reduce transmission constraints around New York City.

The 15% increase in natural gas prices during the quarter contributed to improved merchant and contracted power pricing.

South Central also reported a quarter-over-quarter improvement as margins were $12 million higher, driven by new contracts, increased merchant sales and new capacity and revenue billing peaks established during 2006.

Development spending on our RepoweringNRG projects was $36 million during the quarter, $23 million for the development of the two units at the STP nuclear generating station in preparation for the submission of the combined operating license application.

Our Padoma Wind subsidiary incurred $4 million of expenses in pursuit of wind development opportunities.

Other factors contributing to increased quarterly EBITDA are the increased gross margins in our West region and sales of excess submission credits.

West margins improved $5 million due to new tolling agreements in place at the region's Encina and El Segundo plants.

Net sales of emission allowances increased $9 million to $19 million as we monetized a portion of the excess [bank] when prices recovered during the quarter.

Taking a look at our first-half performance versus last year, our adjusted EBITDA, excluding mark-to-market activity, grew $421 million.

Key contributors to the year-over-year improvement included $123 million and $8 million, respectively, for the full-year inclusion of Texas and West regional results, $245 million from the year-to-date impact of the hedge reset, $115 million higher Northeast margins due to higher generation in pricing in the region, as well as increased capacity revenues.

These favorable results were partially offset by development expenses and a $43 million decline in sales of emission allowances.

Other factors influencing the first-half results included a $207 million decline in Texas capacity revenues due to a requested reduction in our participation in capacity auctions that was offset by increased contract and merchant revenues.

Cost of energy for Texas, excluding the additional month, declined year-over-year by $77 million.

Purchase power expenses decreased by $27 million due to improved plant availability in 2007.

In addition, peaking gas generation declined by 1 million MW hours, resulting in a gas cost decline of $83 million as cooler weather reduced peak demand.

O&M expenses increased by $16 million, mainly due to the spring 2007 STP nuclear refueling outage.

Northeast margins benefited from a 10% increase in generation due to a colder winter in 2007 versus 2006, higher power prices, increased capacity revenues, and the effect of transmission constraints in New York City.

Power prices in the Northeast rose, on average, up 12% compared to last year.

Energy revenues increased $105 million over the first half a last year.

Cost of energy increased $35 million due to higher oil and gas costs, due to the increase in generation.

Coal costs decreased despite higher generation due to the lower average price of purchased coal and the impact of the Indian River extended outage, which uses higher-cost bituminous coal.

Capacity revenues in the Northeast increased by $27 million over the first six months of 2006, $15 million in [NEPOL] $9 million in western New York, and $5 million in PJM.

[NEPOL] benefited from a new LFR end-market and transition capacity market introduced in the fourth quarter of last year, offset by the loss of the Devon RMR this year.

Western New York capacity prices increased 109% and PJM benefited from the new RPM capacity market.

Net sales of emission allowances decreased by $43 million primarily in the Northeast, due to the combination of increased generation and a 49% decrease in market prices.

Development costs for repowering projects totaled $59 million, including $39 million for STP and $6 million for wind projects.

G&A costs increased by $19 million -- I'm sorry, by $9 million exclusive of the January '07 Texas G&A over the first half '06, due to higher wage and benefit costs attributable to higher corporate headcount and wage or benefit increases.

Franchise taxes in Louisiana increased $7 million, due to higher levels of the Company's capitalization from the Texas Genco acquisition.

The cash flow for 2007 is shown on Slide 25.

The improvement in adjusted EBITDA was offset by higher working capital, collateral postings and increased interest payments.

The majority of the free cash flow decrease is due to the $375 million swing in collateral movements in support of commodity trading contracts.

This year, we paid out or returned $103 million in collateral to counterparties, mainly due to increasing gas prices, while in the first two quarters of 2006 we received a net $272 million due to decreasing gas prices in the first half of last year.

If the collateral swings are excluded, adjusted cash from operations was $230 million higher than 2006.

Cash interest payments increased for 2007 versus 2006 due to a full six months of interest related to debt incurred to finance the Texas Genco acquisition and additional debt associated with the hedge reset in November of 2006.

Cash flows to fund working capital increased by $142 million.

Accounts receivable balances increased by $192 million, mainly due to higher market and contract pricing.

Substantially all the Accounts Receivable increase is in current accounts, which have since been collected since the end of June.

Maintenance and Repowering CapEx were $131 million higher during the first quarter of 2007 versus '06.

We expended $205 million of capital in the first half of 2007, $109 million of which is normal maintenance projects, including the STP refueling expenditures of $14 million.

Repowering CapEx was $78 million, mostly due to Long Beach wind turbine deposits and Cedar Bayou.

Liquidity at June 30, as shown on Slide 26, was approximately $1.9 billion, down $373 million since December 2006 and $123 million since June 30, 2006.

The reduction in liquidity is mainly due to the $200 million reduction in the synthetic letter of credit capacity as part of our recent restructuring of the first lien credit facilities.

Operating cash flows of $459 million plus $29 million of proceeds from the sale of Red Bluff and Chowchilla were offset by $205 million in CapEx, $215 million in common share buybacks, $48 million in scheduled debt repayment, and $28 million in preferred dividend.

Our full-your outlook is outlined on Slide 27.

Similar to the first quarter, our second quarter came in a bit stronger than what we had forecasted.

As a result of this performance, along with the lower forecasted expenses for the second half of the year, we are raising our 2007 adjusted EBITDA guidance by $50 million to $2.2 billion for the second time this year.

Operating cash flow guidance increased $22 million, due to the increased EBITDA expectation partially offset by an increase in international cash taxes and a $20 million forecasted deliberative build in coal inventory.

Free cash flow from our base business, before Repowering capital and preferred dividends, is projected to be $1.07 billion for the full year, which represents a free cash flow yield of nearly 12%.

As shown on Slide 30, the full-year capital spend forecast, including Repowering, is $630 million.

The principle investments to be made during the second half of 2007 totaling $425 million includes maintenance, some of our larger maintenance CapEx in the second half of the year includes the Unit 8 at Parrish, reactor work at STP, transmission work in South Central.

Environmental will continue the [flu] gas desulfurization projects at Huntley at Dunkirk, and begin scrubber installation at Indian River and Big Cajun II.

Repowering with Long Beach complete in Q3, Cedar Bayou and wind projects drive the increase.

Financing alternatives associated with our capital spend include for Huntley and Dunkirk environmental investments.

We expect to pursue solid waste tax-exempt bonds during 2008 to fund a portion of the capital cost.

For Cedar Bayou, we are evaluating project-level financing alternatives which would reduce or completely eliminate our cash equity requirements.

For Padoma Wind, we are pursuing equipment and/or project-level financing ranging, depending on the project, from 50% to 80% of the total project cost.

Timing of the financings are in 2007 and 2008, as we balance the economics of carrying the cost versus delaying the funding.

Slide 29 provides a capital allocation update since our last earnings call.

First, I will cover how we are progressing with our 2007 goal of completing the $500 million Phase II buyback plan.

During the second quarter, we repurchased 2.7 million common shares for $113 million, bringing the 2007 year-to-date total to 5.7 million shares for $215 million.

This, combined with our previous purchases under Phase II, leaves us $53 million short of our $500 million target.

With the replenished restricted payments basket and recent declines in the equity markets, we will move quickly to complete the remaining buybacks.

I will switch to our forward 2008 and longer-term capital allocation plans.

First, let me summarize where we are today.

Since our May 2, 2007 first-quarter call, we have implemented a series of changes to our first lien credit agreement.

We lowered the interest rate pricing grid by 25 basis points, we received amendments, which other things permitted ongoing dividend as well as a series of other changes to support repowering efforts and increased liquidity.

The synthetic LC was reduced from $1.5 billion to $1.3 billion, and we put in place a $1 billion delayed draw term loan that's available to fund a newly formed holding company, which in turn would fund the capital contribution to NRG Energy, Inc.

or Opco, with the funds used to repay a portion of its outstanding term loan B.

This equity contribution will increase the restricted payments capacity on the Company's bond indentures, facilitating NRG's longer-term capital allocation plans.

Final regulatory approvals for the Holdco structure are pending and expected by Q4 2007.

Since announcing the structure on May 2, 2006, the credit markets have dramatically changed.

Trading levels for our bonds have declined from around 104% of par to the 95%/96% level.

Since the formation of Holdco would considered a Change In Control event under the bond indenture, bondholders of the right to put the bonds back to the Company at 101 if Holdco proceeds.

As a result, we will be closely monitoring the credit markets as we go into the fourth quarter.

If the market environment doesn't improve, Holdco formation would be delayed and the current Holdco financing option would likely expire.

The regulatory approvals, however, do not expire at year-end.

If the Holdco financing expires, our forward plan includes delaying the dividend and increasing 2008 share repurchases as an immediate near-term response, expanding our peak capacity under the indentures through opportunistic ideas currently being evaluated, and implementing Holdco at a time when credit markets have recovered.

While the decision on the formation of funding of Holdco is a fourth-quarter decision, the key take-aways that I stated at the outset are not putting the Company at risk by entering an unstable credit market, standing by our commitments to return capital to shareholders and in initiating additional share repurchases if dividend is delayed.

Slide 30 summarizes our 2007 financial objectives which we've shown throughout the year.

In summary, the 2007 financial performance for earnings and cash flow is shaping up to be a very solid year for the Company with additional upside.

The repowering is accreting value back to shareholders with the commissioning of Long Beach, while additional opportunities, such as Cedar Bayou 4 and wind power projects, are taking shape.

Finally, we remain committed to returning capital to our shareholders.

We will meet our shareholder return targets in 2008 and continue working towards implementing the longer-term structure.

I will turn it back to David for closing comments and questions.

Well, thanks, Bob.

Since we've taken up a lot people's time and I think some people have another commitment attend, Sam, I think we will open the lines directly for a Q&A.

Absolutely.

(OPERATOR INSTRUCTIONS).

John Kiani, Deutsche Bank.

Good morning, David, Bob.

Looking at the Cedar Bayou project and some of the information on the slides and some of the heat-rate forwards that you provided, can we infer at least the midteens or something like a midteens after-tax return on capital, sort of a base case?

And then with upside from there, if market heat rates rise in ERCOT with the declining reserve margin forecast?

Is that the right way to think about it?

Well, it depends how you look at it, John.

We look at it for the actual cash investment that we have to put in there.

It is a strong project with strong returns.

If we go to the point where we actually want to lever it and look at it on a levered basis, it's just an absolute winners since we could actually fund our entire cash contribution.

The strength of that project comes with, as David mentioned, leveraging the infrastructure of the plant.

Plus, we had equipment that we were just carrying on balance sheet ad idle, so we're putting that to work.

So when you look on the cash investment, it is a very strong return profile project.

All right.

Thank you.

Then do you have any recent thoughts or updates on [Mebrag] and any additional thoughts on your interest in monetizing that asset in Germany?

John, the [Mebrag] asset, what we're really waiting for now is -- we've always said that, with [Mebrag] like with Gladstone, one of the issues was that it is a highly structured project with all sorts of other parties that have rights.

The big thing, as you know, that has changed is that the ownership of our 50% partner in that project is in the process of changing.

While they are in that process, there is really very little discussion that can be had with either the existing management or the prospective new owner.

We expect that their transaction -- we're told their transaction will get all of the necessary approvals and likely close in September, and then we expect to have a full discussion with the new owners.

You know, we have certain rights that are triggered by a change in control and we're well where of what those rights are.

Thank you very much.

Elizabeth Parrella, Merrill Lynch.

First, if I could ask, on the development projects, David, you mentioned kind of stay tuned on STP into the weeks ahead.

Would that maybe suggest that you could be coming back to us with some news on that prior to the third-quarter call?

Then, just on the other development projects, can you talk a little bit about whether you've got more traditional TPAs on the wind projects, or if you are pursuing financial-type hedges on those as well as on Cedar Bayou?

Well, I will hand the question about the type of offtake arrangements on the wind to Jan.

On the nuclear project, the short answer, Elizabeth, is yes.

We would expect to be getting back to you with details prior -- I mean, assuming that the next quarter call is at its usual time at the beginning of November, we would be expecting to get back to you before that with significantly more detail about the nuclear project.

On the question of when, Jan, do you want to --?

Certainly.

On the issue of offtake on wind projects, it's really -- the strategy depends on the location of the projects.

The project in California, which we anticipate to build out in 2009, will be -- at that point in time, the offtake will be covered by a 25-year PPA with a fixed power price for the entire period.

In terms of the Texas projects, those will be selling power into the merchant market on the basis of achieving a probably five to seven-year hedge, power rate hedge, which is what we're currently in the process of negotiating with a short list of a number of banks.

Okay.

If I could follow-up with Bob just quickly on the capital allocation discussion?

Just to clarify, could you remind us what the regulatory approvals on Holdco are, where you are on that?

The changes to the senior credit facility, are any of those changes contingent on going ahead with Holdco, or is that deal completely done?

Lastly, if you could update us on just where the RP baskets are at the end of the quarter?

Okay.

On the regulatory, Elizabeth, there's three regulatory bodies that require approval.

We've received two of the three.

The third one that we're waiting for is the NRC.

We expect to have that, I would say, somewhere around early fourth quarter.

So they are all proceeding as we had planned.

As far as all of the refinancing that we did back on May 2, everything that we put in place around eliminating cross-defaults from project debt to the first lien or being able to provide liens -- or I'm sorry, collateral on a first lien basis, not a second-lien basis, or reduction of the pricing grid that mentioned a moment ago -- all of those stay.

The only thing that can go away is, at the end of December, the right for us to call $1 billion to fund the Holdco expires at the end of December, so that's the only thing that goes away.

The regulatory approvals stay, and they stay in place for quite a while.

So if the credit markets settle down and things get much better, whether it's the first quarter of next year or the second quarter, we can fund Holdco; we are set to go.

if I look back in time and said would I have done something differently, I probably would have initiated the Holdco approval process earlier than what we did.

We went the course of finance first and get the regulatory approval second.

Certainly, with hindsight, we probably should have gone for the approval earlier, but it doesn't expire, so we retain the option to do that.

Finally, on the RP baskets on the first lien, the bank baskets, at the end of June, we are, in round numbers, about $750 million on the bank side.

On the pond side at the end of June, we are around at $110 million or so.

Again, both of those baskets grow quarterly at this point in time.

Thank you.

Dan Eggers, Credit Suisse.

Good morning.

On the Repowering program, obviously there's a lot of benefit at Cedar Bayou for the site value and performing in a partner.

As we look at some of the other big projects you guys have identified, do you see similar opportunities where you can get a pretty big capital advantage by letting somebody come in and effectively farm into your economic interest?

You know, what kind of return advantage do you see versus a straight greenfield project?

Well, the short answer to the front part of your question is yes.

I mean, given that I think the paradigm of Cedar Bayou is one that we will be trying to use elsewhere, and the nature of virtually all of the projects in our Repowerings program, other than the wind projects, is that they are all at existing sides.

We certainly think that, when you get together with like-minded partners, who I think in the case of the Cedar Bayou project we are extraordinarily pleased to be partnered with Public Service of New Mexico and with their partner, Cascade.

But you know, not only do the partners bring more to the party but clearly there's the win-win possibility where you can pass some of the benefit of working off an existing site to them and then also monetize some for us by the fact that people reasonably expect they shouldn't get access to the site for free.

So I think we can see this, and we will be using that paradigm in bringing partners into a lot of our repowering projects over time.

In terms of the last part of your question, Dan, which I think was specifically what type of return advantage does it give us over a true greenfield, Bob, I've ever done that.

I mean I don't have a 200 basis point answer or anything to that.

Do you?

The rule of thumb that we've used on this when we looked across our projects -- and again, as David said, this is the strength of our Repowering program is what did in Long Beach or in Texas.

We've got some great opportunities in South Central and the Northeast.

But the general rule of thumb when we've looked at this, Dan, it's been about 10% to 15% cost advantage on the infrastructure.

Okay.

Then just one other question on the capturing heat rate expansion in Texas, with heat rates in '09 and '10 moving up you said even locking some in.

Is that a statement that you guys view the '09-'10 forwards as being a fair price or is there still room, in your view, for that to trend even higher from where we are today?

Well, I think, if Kevin Howell were here, he would completely obscure the answer to that question, so I think, in memory of his -- he is back in Princeton holding down the fort.

I would say that it's closer to fair value but I don't want to signal anything about our trading position vis-a-vis 2009-2010.

Fair enough.

Thank you.

Gregg Orrill, Lehman Brothers.

Thanks very much.

I wanted to return to Slide 12 on the hedge profile and heat rate sensitivities.

On the heat rate sensitivity of about 1 mmBtu change per MW hour, it about equates to about $400 million of EBITDA on knitting out your -- netting out your hedge position.

On a fully unhedged basis, what would the upside be there?

Yes, that's close to the fully unhedged -- I mean (multiple speakers).

I have to say, Gregg, I don't have the number off the top of my head but it looks a lot like the 2012 range.

You have to back out some of the hedges that we have.

But we are 23% hedged in 2012, so that probably represents a 75% (inaudible) position there.

But the 23%, that's largely Big Cajun as well, right, so it's actually even closer to it?

The 2012 in terms of the gas exposure is almost completely open.

You are probably in the $400 million to $450 million range, I would say, Gregg.

Okay.

Then, what can you tell us about estimate of overall construction cost on Cedar Bayou?

Could you be a little bit more specific?

I mean (multiple speakers).

You disclosed the equity contribution but sort of cost per KW of construction so we can just kind of get a feel for what [CCGTUs] cost at this point?

(multiple speakers).

Go ahead.

The total project cost, when we looked at the total project cost including the contributed assets, if you will, Gregg, and some of infrastructure, it is about a $300 million project.

Okay.

That's for the total construction and contribution of equipment and the like.

Great.

Then maybe the last question would be around what you're seeing in the -- as you implement your hedging program and are the commodities markets on kind of a daily basis, what sort of impact in terms of collateral or in doing business, what sort impacts you've seen there from the recent blowout in credit spreads?

In the collateral?

Yes.

We haven't seen any.

I don't know if it's the fact that the second lien structure, combined with LCs, insulates us from that.

I mean we will check but I mean, we've been through our risk review meetings and we've really -- we've seen nothing unsettling and no spillover from sort of the debt market into the trading (multiple speakers) credit.

First of all, from a leverage standpoint, we are about 95% fixed, so we're getting limited impact from the credit markets in general.

As far as the collateral markets, we are a net poster of collateral, and the amount of cash that folks owe us is small, so it's not a meaningful number.

Great.

Thanks a lot.

Michael Lapides, Goldman Sachs.

Easy quick one here -- can you talk a little bit about the potential addition or new unit at Big Cajun, where you are in discussions with that, and whether you have any additional thoughts regarding your gas assets in the state as well?

Gas assets in the state?

Meaning in Louisiana, Sterlington?

Well, the second part of your question, Michael, is that, in terms of gas assets in the state, the nature of our portfolio down there, where we are long high-peaking capacity and actually short-based immediate load, you know we've long aspired to be able to buy a 7 or 8 heat rate combined-cycle plants in that region.

I've never been able to because we could never get to the price level other people could get too, even though we thought that we had better uses for one servicing our co-op load.

So that situation hasn't fundamentally changed.

You know, we would like to but we're not going to throw silly money at it.

In terms of where we are at Big Cajun is that -- and I think that this is -- you know, we said from the beginning that, with the original 18 projects in the Repowerings program, there was no way that we were going to go 18 for 18, and that we were going to be financially disciplined.

You know, we haven't killed Big Cajun II-IV but we were unable -- I think we got commitments to I think something like 450 MW of the 700 MW and that just wasn't enough in that market.

You know, had that plant been located in a true, traded market, an ISO market, maybe that would've been enough, but down there, in a bilateral market, that could not get over the hurdle.

We sort of stalled at that number.

So where we are now is that we've been pushing forward with a smaller coal or petco-fired project next door, two miles down the road at Big Cajun I.

We expect to get the permit for a CFB there and arranging the offtake and the partners for a 200 MW project when you already had 450 signed up for a bigger project is quite an easier task.

It probably shifts the dynamic in terms of being a seller's market or a buyer's market.

So I think the answer to your question is that we're going to be pushing forward with Big Cajun I and then we will be optimistic with respect to Big Cajun II-IV.

A quick follow-up -- we've seen a couple of assets, combined-cycle type assets in that region trade hands, or announcements of transactions in the $320 to $350 per KW range.

Do you view that as kind of being a rich price for those type of assets?

It's interesting.

Michael, I can't really answer that question right now.

I think there is a spirited internal debate over whether that's a good price level or a bad price level.

Because you know, in that market, there's just not a lot of visibility beyond four or five years out, so you know, I think it's a close call at that level.

Okay, thank you.

One thing that I just want to correct myself -- I had a chance just to look up on the Cedar Bayou IV, I think the total all-in costs are closer to $400 million, so the total cost on the KW is over $700.

I was speaking from memory; I looked it up while you were going through (multiple speakers).

That's the actual Cedar Bayou costs.

I think people have to keep in mind that not only did we have the existing infrastructure, but a lot of the equipment we either had, as you said, in the warehouse, or we actually acquired some of the key equipment for that plant from other people who had stored equipment.

So that gives a market view of the true cost per KW.

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

Brian Russo, Landenburg Thalmann.

Good morning.

David, earlier you mentioned that the Commercial Ops group had anticipated softening in the summer market and sold the peaking capacity forward.

I'm just wondering.

Was that strictly related to your take on gas prices or was there something other, something else fundamentally in the market that went into that decision?

I think it was principally a view on gas prices.

I would like to say that they anticipated the summer weather being soft but I don't actually think that we had any greater insights into the lack of summer than anybody else.

So I think it was, you know, it was very much a view on the very near-term view of gas prices.

I mean, we remain extremely bullish on where gas prices are going in the long-term, but in the traded market over -- you know, in the (inaudible) and all, I think they thought it was a little high going into the summer.

Okay.

Then just quickly, that 239 million of shares outstanding used throughout the presentation, is that the fully diluted shares outstanding we should be using?

No, that's the primary.

Fully diluted I think is more like in the 270 range, 270, 280 range.

Right.

Okay, thank you.

Thank you, Brian.

Operator, thank you, thank everyone for participating on the call.

We are sorry we held you over.

Thank you.

Thank you.

Ladies and gentlemen, this does conclude your conference call.

Thank you for attending, and you may now disconnect your lines.