NRG Energy Inc (NRG) 2005 Q2 法說會逐字稿

Good morning, ladies and gentlemen, and welcome to the NRG Energy second quarter earnings results conference call.

At this time, all participants are in a listen-only mode.

A brief question and answer session will follow the formal presentation. [ OPERATOR INSTRUCTIONS ] As a reminder, this conference is being recorded.

It is now my pleasure to introduce your host, Ms. Nahla Azmy , Director of Investor Relations for NRG Energy.

Thank you, Ms. Azmy, you may begin.

Thanks, Diego.

Good morning and welcome to our second quarter, 2005 earnings call.

This call is being broadcast live over the phone and from our website at www.NRGenergy.com.

You can access the call presentation and press release furnished with the SEC through our link on the Investor Relations page of our website.

A replay of the call will be posted on our website.

This call includes the formal presentation, and the question and answer session will be limited to one hour.

In the interest of time, we ask you please limit yourself to one question with just one follow-up.

And now for the obligatory Safe Harbor Statement.

During the course of this morning's presentation, management will reiterate forward-looking statements made in today's press release regarding future events and financial performance.

These forward-looking statements are subject to material risks and uncertainties that could cause actual results to differ materially from those in the forward-looking statements.

We caution you to consider the important risk factors contained in our press release and other filings with the SEC that could cause actual results to differ materially from those in the forward-looking statements in the press release and this conference call.

In addition, please note that the date of this conference call is August 9, 2005, and any forward-looking statements that we make today is based on assumptions that we believe to be reasonable as of this date.

We undertake no obligation to update these statements as a result of future events.

During this morning's call, we will refer to both GAAP and non-GAAP financial measures of the Company's operating and financial results.

For complete information regarding our non-GAAP financial information, the most directly comparable GAAP measures, and a quantitative reconciliation of those figures, please refer to today's press release and this presentation.

Now with the formalities of the way, I'd like to turn the call over 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 Chief Financial Officer who's going to walk through the second quarter numbers.

Both Bob and I our going to be referring to the slides, which I think are available on our website but we'll try and make the discussion so you can follow along even if you don't have access to a computer.

Before I turn it over to Bob, there are a great many topics that I want to talk about so I'll be touching upon these topics relatively superficially and hopefully I can come back and elaborate during the Q and A.

Suffice it to say, the last few months have been an eventful time for the Company and for the competitive power industry overall.

Turning to slide 4, financial results, all four of the financial data points which appear on this slide will be addressed by Bob, but I'd just what to make a couple of comments .

The Company's liquidity remains exceptionally strong, notwithstanding that we already had paid down $473 billion in debt this year and are free cash flow generation remains positive, even with the second quarter being predominately a shoulder season.

Our net debt to total capital ratio remains flat at 47 percent at the end of the second quarter, well within our targeted range of 45 to 55 percent.

However, this ratio as so calculated by the Company, includes all of our debt and as such, does not differentiate the $500 million of unsupported debt that we continue to carry on our balance sheet .

Strip that out of the calculation, and our net debt to total capital ratio reduces even further to 41 percent.

In short, we continue to enjoy the strongest balance sheet and the highest liquidity in our sector.

Our adjusted EBITDA result for the second quarter was $123 million, down from last year's $232 million.

The steep drop, year-on-year, is of course somewhat misleading given the contraction of the asset portfolio and the expiration of the CDWR contract, but embedded within that decline was an operational performance which was not up to our normal standard.

As illustrated on slide 5, we experienced exceptional electricity demand in June as a result of a sustained period of hotter than normal weather.

We, however, were unable to take full advantage of that market opportunity as we experienced extended and unplanned outages at our coal plants in the Northeast and at Big Cajun.

The loss of Big Cajun III for half of June, particularly impacted us given that loss output in our South Central region affects us both in terms of increased purchase power costs as well as the opportunity costs of lost sales.

Some of the operational issues which arose during the last portion of the second quarter, we already knew about and we're seeking to improve as part of the Focus on ROIC and NRG program.

But beyond F.O.R.NRG, we are doing a systematic loop problem analysis of our operational shortfalls.

The industry average for our full enforced outage rate at similar plants is 6.4 percent, while top core tile performance is 3.8 percent.

As you can see from the slide, we've been hovering in the 7 percent range and going up to 10 percent for the second quarter.

Given where we are, it's not unreasonable to believe that with a concerted effort we can can improve substantially.

In short, we must do better operationally and particularly in respect to reliability, and we will.

If you turn to slide 6 in the presentation, last quarter I told you that our OSHA incident rate was unacceptable and the deterioration in it from previous quarters was troubling.

This quarter we redoubled our efforts and managed to reverse the trend.

We will continue to stride to do better in all matters relating to safety as even with our annualized rate now below the industry average, there remains significant room for improvement.

Operationally, while we did have a weak quarter from the point of view of forced outage at our coal-fired plants, there were several noteworthy operational successes around the fleet.

In particular, our two New York City plants, Arthur Kill and Astoria, have been dispatched at a very high level both during and since the second quarter and they have responded with exceptional performance.

Astoria output was up 77 percent over the second quarter of '04, and Arthur Kill had its strongest showing in two years.

In upstate New York, Huntley 67 and 68 completed the PRB conversion and now can run on 100 percent PRB coal, although we still have the option to run on a western eastern coal blend if the economics dictate.

And finally, in Australia, we continue to make progress in bringing additional coal-fired generation back from retirement at Playford.

Turning to slide 7, we have sought on this slide to depict the coal transportation arrangements to all of our coal-fired plants.

Coal logistics have been of concern recently, largely due to recent problems in the Powder River Basin.

The May derailments on the Joined BN/UP rail line in the PRB, coupled with the slow downs of the major response from the railroad predict the been a few moments on the joint we went into the PRB, have resulted in significant congestion on that line.

While we have been impacted toa modest degree in the form of shorter than normal cycle times from the Basin to our power plants, we have been managing the situation aggressively and do not expect the net impact of the derailment to exceed, on average, one to three days of inventory at all of our plants that consume PRB coal.

I'd also mention that we have not changed the dispatch of our change as some people are doing in terms of turning off our coal units and turning on gas.

We've been more successful than some other PRB consumers in mitigating the impact on our plants of these rail transportation issues for three reasons.

First, we purchased and scheduled our PRB coal requirements for 2005 prior to the derailments.

Second, we are able to ship a substantial portion of our PRB contracted supply over the Burlington Northern's alternative northern route.

And, third, we are using our own rail cars, as we have now taken delivery of all 12 trains, 1540 cars in all which we procured last summer on a sale lease back basis.

I mention all of these reasons because we do not expect the current problems in the PRB to be corrected quickly.

Nonetheless, for the reasons I have noted, we don't expect material impact on our ability to get western coal to our plants.

Moreover, we retain the ability to benefit commercially during this challenging time in the coal transportation world, by leveraging off the flexibility which is the core strength of our long-term coal strategy.

That is 77 percent of our coal-fired megawatts can burn fuel from multiple sources delivered through multiple modes of transportation.

As the fiscal coal market becomes more constricted and the financial market becomes more volatile, the value of our flexibility is enhanced.

Now turning to slide 8, a key component of our operational strategy is to focus on ROIC program, among the objectives of which is to improve reliability, increase capacity, and reduce heat rate.

As our second quarter performance has demonstrated, this is the right time for these initiatives.

However, the pacing item for plant improvements tends to be the outage schedule and as such, they do not occur overnight and certainly not during the peak demand season.

Accordingly, as illustrated on this slide, the first year savings in the F.O.R.

NRG Program are largely headquarters initiatives and we are well on track to realize the benefit of those initiatives.

While it's too early to see bottom-line performance improvements in the Focus on ROIC Program at the operational level, we are making good progress in developing and refining initiatives included in the program and in improving our tracking methodology for the Company.

The 2006 outage planning and associate capital major maintenance process is well underway.

Turning to market developments on slide 9, the key pricing driver over the past few months, has been obviously the weather.

In the United States, a very cool spring gave way in early June to what has been an exceptionally hot summer.

As the graph in the upper left quadrant and the table on the lower left show on this slide, weather has led both to a substantial increase in year-on-year electric consumption and to new record peaks in many of our domestic markets.

During this prolonged weather event, we have been very focused on balancing our supply against our contracted demand, capturing upside where we are long to the market, and continue to extend out and upward our hedging program into the actively traded forward market.

We continue to pursue a strategy premised on hedging a substantial portion of our coal fleet under the positive influence of high forward gas prices versus historical levels, while maintaining upside from our intermediate and peaking fleet, particularly in the Northeast.

On a risk adjusted basis in this marketplace, we believe this balanced approach provides the greatest potential return given the mix of assets in our portfolio.

There are a couple of specific market to situations which I'd like to address.

First ,with respect to our south central region, it is not new news to anyone that follows this Company, that our South Central region is, at times, short of intermediate power.

The weather in South Central this June was above normal and, accordingly, our co-op load came in 5 percent higher than the same period in 2004.

Our mitigation strategy was prepared to mitigate our projected shorts, notwithstanding this increase in demand, but what has exacerbated our typical short position was the higher than average forced outage rate and the associated loss of production at Big Cajun.

Beyond the end of the second quarter for July and August, we did execute a series of summer-only hedging arraignments intended to procure comparatively lower costs, combined cycle capacity to hedge our physical load following the price risk and, second, to diversify our generation stacks so that we could more efficiently dispatch our entire portfolio.

As a result, our current firm capacity for the high summer period is sufficient to cover our projected maximum load plus a reserve of 15 percent.

We have, for example, sufficient length during the recent July heatwave as a result of these tolling agreements that we did not have to participate in a spot purchases to cover our demand, and indeed, we have favorably participated in the recent strength of spot power prices by selling a portion of our length into the market.

Finally, a brief comment on one other input commodity, and that's the emission credits.

The cost of emission credits, particularly SO2 credits, have increased substantially over the past several months and the price movements have become increasingly volatile.

With respect to SOX credits, NRG remains modestly long to our own requirements, but as the price of the emission credits increases, there will be more instances of marginal pricing hours during which it makes economic sense for our Company to sell our emission credits rather than operate our own machines.

Now turning to slide 10, as you can see from slide 10, 2007 dark spreads have widened as the backwardation of the gas curve has reduced substantially over the past few months.

We see this as an opportunity to begin hedging some of our coal-fired generation for 2007, consistent with our stated strategy.

If these spreads hold, we will be hedging at significantly wider than we are realizing in 2005.

Turning to slide 11, the other area of volatility and significant price movements that we have seen are the three main constituents of the cost side of the dark spread.

Coal commodity prices, coal transportation costs, and the cost of emission credits.

All three components have been moving up substantially over the past few months, but as you can see from this slide 11, we are very substantially hedged.

Indeed, we're more hedged with respect to the supply and transportation of the underlying commodity than we are with respect to the forward sale of the coal car generation itself.

We continue to reduce our dependence on eastern coal through PRB coal conversions at our western New York plants.

Now, based on our projections, 93 percent of our coal portfolio is based on western low-sulfur coal.

PRB prices have climbed steadily since the beginning of the year taking a noticeable jump in the past several weeks in response to the congestion on the joint rail line out of the PRB.

The impact of higher PRB prices on our cost of coal is minimized since we hedged our 2005-2006 requirements last year.

In addition, as reported last quarter, we have hedged 100 percent of our coal transportation requirements through long-term agreements at attractive base rates.

Our transportation agreements range in terms from 3 to 10 years.

As I said, we were able to lock in these contracts at attractive base rates, we, as others, have experienced a modest rise in coal transportation costs, largely attributed to fuel surcharges pass throughs which are embedded in these contracts.

In short, we remain very pleased with the status of our coal strategy and believe the decision to lock in as much commodity and transportation as we could last year, as well as the decision to hedge much of the coal-fire generation itself, was the right decision and will only add further to the Company's competitive advantage over time.

Now turning to a different matter in external events, in the energy bill, which just has passed Congress.

The last few months have been an extremely eventful time as we've worked hard as a Company to deal with a variety of legislative and regulatory initiatives with a significant and potential impact on us.

The energy bill, which just passed, contains no direct benefit to NRG, but overall it's a big win for us as this bill were returned back the tide of anti competition plus the bill preserves the authority of FERC as it seeks to encourage the further development of competitive markets in the power generation sector.

The critical market component still under development is the design and introduction of locational capacity payments in all competitive markets so that investment can be attracted to the power generation sector in a timely and orderly fashion in order to ensure reliable and efficient energy prices.

As we've tried to depict on slide 13, with respect to locational capacity in markets, slow but steady progress continues in NEPOOL PJM and California, and the New York locational capacity market continues to be improved.

All these markets are moving in a positive direction and we continue to be bullish on capacity market reform and believe the introduction of some form of LICAP in all of these markets will occur.

The only question is when and in what form.

Capacity markets offer two real benefits.

There's the one that everyone focuses on, which is the higher revenue opportunities, but they've already been demonstrated and shown that they create substantial incentives for load serving entities to hedge their capacity price risks through long-term contracts for new power plants.

Our objective is to be the competitive provider of choice for such contracts based on the locational value of many of our existing sites and the creative strength of our Brownfield redevelopment efforts.

Turning to slide 14, typically we show a different visual to show our potential sources of intrinsic growth in the near to medium term.

We recast that slide into this one this quarter to give a general sense of quantum.

Over a few years, we believe we can take this Company that is currently in a steady state basis of 6 to $700 million per year EBITDA company and turn it into an 8 to $900 million per year company.

We've already discussed a few of the growth drivers including successful implementation of our Focus on ROIC and NRG Program, enhancing our commercial operations activities, and capturing the benefits of newly-introduced capacity markets.

What is part of our internal growth strategy, but held apart because it will take a couple of additional years to realize, is our Brownfield Development Program.

Our Brownfield Program remains in a comparatively early stage overall but good progress is being made on several fronts at projects in various stages of development.

Among the most advanced projects, the fourth pole unit at Big Cajun is likely to get it's necessary permits in the near future and there has been a great deal of customer interest in buying from this new coal-fired unit.

Likewise, our development efforts around El Segundo and Long Beach are making some progress in securing commercial offtake and various plans are advancing around our critical Northeast assets.

I remain highly confident that between our Brownfield program and other perspective capital initiatives, we will be in a position to reinvest all or a major portion of our cash in our business in a value enhancing way.

However, it would be unrealistic for me to ask you to believe that will be in a position to redeploy that capital effectively over the next few months.

Power plant development is, in essence, a lengthy process.

This capital allocation problem is one that Bob and I and the rest of the NRG team have been evaluating over the past few months.

As we have sought to illustrate through the simplified decision tree on slide 13, we have moved deliberately, we have explored countless capital allocation options and at the end of the day, for this Company, with this amount of cash, at this point in time, I have no doubt that the accelerated share repurchase auction we are taking and that Bob will be explaining to you in just a minute, is the best choice for the Company and for its equity and debt stakeholders.

For those on the call who have been with us since December 2004, I needn't remind you that for this Company, still just 20 months since emergence, dealing with a capital allocation of this kind is a very high quality problem to have.

So, with that, I will pass the line over to Bob Flexon to outline the mechanics of this capital market Initiative.

Thank you, David, and good morning.

As David just covered, we are very pleased to announce the $250 million accelerated share repurchase.

Before I discuss our second quarter results and 2005 outlook, I'll cover the details of this transaction and our underlined decision process.

In prior earnings calls, we have discussed the primary goals of NRG's capital allocation philosophy.

Reinvesting in our existing operations and growth opportunities that generate economic profit, managing our capital structure to the targeted range, and providing an efficient return of capital to our shareholders.

The allocation of capital is influenced by our expected near and long-term levels of free cash flow, the timing of cash reinvestment for our business growth opportunities, and the current makeup of our overall capital structure.

With the Company's liquidity in excess of a billion dollars at June 30, 2005, and free cash flow for the second half of the year expected to exceed $250 million, the Company has the opportunity today to make a substantial return of capital to our shareholders.

We considered and evaluated several alternatives to accomplish this and concluded a share repurchase was the best alternative at this time.

For the following reasons.

First, we have ample liquidity and a bullish free cash flow outlook.

Second, a share repurchase allows us to immediately reduce our cash balances and thirdly, this transaction will provide an efficient, meaningful and immediate return of capital to shareholders while maintaining and even enhancing our capital structure.

Slide 16 provides three principal elements of the transaction.

Step 1, on August 11, we will issue to CSFB, in a private transaction, $250 million of a new perpetual preferred security which can be settled in year 10 with a coupon of 3.625 percent.

As settlement, the Company will pay CSFB $250 million in cash, and if our common stock is greater than 150 percent of the closing price on August 10th, 2005, the Company will settle on the value in excess of 150 percent in cash or shares.

If our share price is below the August 10th, 2005 closing price, CSFB will pay the Company in either shares or cash for the difference.

We elected to issue the preferred shares as it was the most cost-effective way to increase our restricted payments basket, which limit the amount of cash available for the return to shareholders.

Issuing the preferred stock increases the restricted payments basket by $245 million at a cost of just over 1.5 percent of the added capacity.

The preferred shares will be considered mezzanine financing on our balance sheet, thereby credit neutral to slightly positive.

Step 2 of the transaction is to use the expanded restricted payments basket capacity along with cash on hand, to execute an accelerated share repurchase agreement, or ASR.

On August 11, 2005 we will repurchase with an immediate reduction in our outstanding stock, $250 million of our common shares at the August 10th, 2005 closing price.

At the completion of the ASR, there will be a cash or net share settlement for share price fluctuations.

Price fluctuations per the agreement have a limited range, 97 percent to 103 percent of the August 10th, 2005 closing price.

The final step in this transaction will be to exercise our clawback rights for approximately $229 million of our 8 percent bonds under the high yield indenture at 108 percent of par.

To do this, consent from our first lien debt holders is necessary.

We received this consent on August 5th.

Proceeds from the issuance of the preferred stock will be used to fund the clawback of our bonds.

Slide 17 illustrates the our capital structure remains well within our targeted range both pre and post transaction.

Our net debt to capital remains at 47 percent while our gross debt to capital shows a slight improvement.

Net cash flow for the Company also improved by approximately $9 million a year with the retirement of the 8 percent notes and the issuance of the 3.625 percent preferred securities.

In summary, this transaction accomplishes a cost effective and meaningful return of capital to our shareholders.

The Company's liquidity, as shown on slide 18, is approximately $1 billion after giving effect for the share repurchase.

With our free cash flow outlook of the remainder of the year, we expect our liquidity to return to the pre-transaction level of approximately $1.2 billion by year-end.

The pro forma liquidity number is after reducing our debt balances by over 700 million in 2005 and cash collateral postings of $157 million to support our hedging activities through June 30th.

I'll now cover our second quarter and year-to-date results.

Slide 19 provides a financial summary of our performance for the second quarter, 2005.

As you may recall, approximately $60 million of 2005 revenues were marked to market and recorded in the fourth quarter of 2004. $51million of this revenue was settled in the first half of 2005, of which 8.4 million pertained too the second quarter.

Operating revenues were $585 million, a slight increase over the second quarter, 2004.

Energy revenues accounted for $361 million versus $333 million in Q2, '04.

This increase was primarily due to increased merchant revenues from our New York City assets, which increased quarter-over-quarter generation by 90 percent.

Contributing $37 million in additional energy revenues, $27 million of which, is due to higher generation with the balance being higher prices.

With their location advantage, our New York assets, Astoria and Arthur Kill, increased their generation with a higher demand driven by competitor outages and hot June weather.

Our Connecticut oil generating assets also reported higher energy revenues quarter-over-quarter.

Of $17 million due to higher generation, as outages of other local suppliers and the June weather increased demand.

Energy revenues in the second quarter of '04 included the one-time $38 million settlement received from Connecticut Light and Power.

Capacity revenues were down this quarter from $161 million to $141 million.

This decrease resulted from the sale of Kendall, which earned $15 million in capacity revenues in the second quarter of last year, and the May expiration of the Rockford contract.

Other revenues were impacted by the $11.5 million in lower expense reimbursement from the Connecticut RMR agreement.

As part of that agreement, we were reimbursed up to $30 million over a two-year period from maintenance-related expenses.

We have been fully reimbursed at this point.

This decrease was offset by $7 million in lower contract amortization and $5 million in unrealized mark-to-market gains.

Net income for the quarter totaled approximately $24 million versus 83 million in the second quarter of last year.

In addition to the revenue changes, the largest quarter over quarter change was higher cost of majority-owned operations.

The cost of majority-owned operations increased by $83 million, $74 million due to increased energy.

Primarily fuel costs from the higher generation at our gas and oil-fired plants.

Fuel gas costs increased $30 million, $24 million due to increased generation at our New York City asset.

The average cost of gas, FOB supply point, burned across North American plants in the second quarter was $7.90 per million BTU versus $6.14 a per million BTU in the second quarter of 2004.

Fuel oil costs increased by $28.6 million with 52 percent of this increase due to higher generation from our domestic oil generating plants.

Purchased energy also increased this quarter over second quarter, 2004 as South Central experienced unplanned outages and bought energy to meet its contract load.

Purchased energy increased at our South Central region by nearly $24 million for 400,000 megawatt hours this quarter at $11.21 per megawatt higher than Q2, 2004.

Coal costs decreased by $3.7 million quarter-over-quarter.

This resulted from 22 percent lower generation from our domestic coal-fired units as compared to the second quarter of 2004.

Partly offsetting the lower generation, was an increase in coal prices quarter-over-quarter.

Our Indian River facility consumed a heavy mix of low sulphur compliance coal, which has been subject to significant price increases quarter-over-quarter.

In Q2, 2005 our domestic mix or PRB coal consumed in the Northeast was 53 percent of the total tonnage versus 42 percent in 2004.

During the second quarter, 2005, coal costs in the Northeast reflected a blend for delivered PRB coal of $31.12 and delivered Eastern coal of $69.81, versus $29.45 and $53.48 respectively in the second quarter of 2004.

The delivered cost of coal consumed by our North American generation fleet for the second quarter was $35.08 per ton or $1.92 per million BTU, versus $31.91 per ton or $1.59 per million BTU for the second quarter, 2004.

The Company's North American operations consumed 2.4 million tons of coal during the second quarter, of which 80 percent was PRB.

In Q2, 2004 total tonnage was to 2.8 million tons of which 74 percent was PRB blend.

Also increasing the cost of majority-owned operations over the second quarter last year, was higher operations and maintenance costs, which increased by $13.6 million.

This is driven by increased planned outages versus last year.

Our South Central, Western New York and Indian River plants all had scheduled major outages in the first half.

Adjusted EBITDA quarter-on-quarter decreased by $110 million, the primary drivers of this decrease included $71 million due to changes in our portfolio mix for the 2004 sale of Kendall, the 2005 sale of Enfield, and the December 2004 expiration of West Coast Power contracts.

The $5 million mark-to-market gain in the Northeast region, $20 million in lower regional margins primarily due to unplanned outages at Huntley and Big Cajun, and the unplanned extended outage at Indian River, $13 million increase in operating expenses and $9 million increase in general and administrative costs, primarily related to increased insurance expense and other corporate costs.

These adjusted EBITDA results do not include approximately $8 million of the 60 million mark-to-market gain we recorded in 2004.

Our year-to-date financials reflect a somewhat similar story to the second quarter results.

Slide 20 shows the adjusted EBITDA decreased by $213 million, nearly half due to the portfolio changes discussed earlier.

In addition to the planned and unplanned outages discussed earlier, the unseasonably mild weather in Australia, primarily in the first quarter, impacted this region's results.

Other items of note for the first half year, year-to-date we have recorded $33 million in unrealized mark-to-market losses, and general and administrative costs have increased $24 million primarily related to increased insurance expense, audit expenses and Sarbanes-Oxley compliance.

Slide 21 shows our operating results by segment.

The planned and unplanned outages at two of our core regions, the Northeast and South Central, impacted results decreasing generation and increasing maintenance expense.

Year-to-date, the $33 billion mark-to-market loss for the 2004 mark-to-market adjustment which accelerated $51 million of first half of 2005 revenues into 2004, impacted our Northeast region.

West Coast results are impacted by the expiration of the West Coast Power contract.

The drivers of the second quarter cash flow, shown on slide 22, during the quarter were $57 million of semi-annual interest paid on high yield notes, $50 million West Coast Guard dividend included in other cash and noncash items offset by changes in accrued tax accounts, $41 million increase in working capital driven by $83 million from an increase in accounts receivable due to the strong June generation, $20 million coal and inventory increase, as we prepared for the summer season offset by a similar increase in accounts payable.

Other net sources of working capital for the quarter were increases in accruals and other liabilities.

The asset divestitures reflect the proceeds from the Enfield sale on April 1st, 2005.

Capital expenditures to date were $25 million for the quarter, and $37 million year-to-date with a full year plan of $125 million.

Debt repayments of $26 million during the quarter included the $10 million pay down of Australian debt, $4 million in dividends and scheduled amortization.

Slide 23 provides our outlook for the year.

Guidance for adjusted EBITDA and cash flow from operations is $600 million and $419 million respectively.

While we experienced unplanned outages and decreased generation during the first half of the year and recorded year-to-date mark-to-market losses of $33 million, the start to the third quarter traditionally our strongest quarter, and our progress with full energy initiatives offset this decline.

Cash flow from operations includes the impact of increased collateral requirements during the second quarter.

In addition, the Company has substantially hedged the downside risk to the 2005 gross margin.

Slide 24 bridges the 2005 outlooks provided at different points in time earlier this year.

Mark-to-market gains and losses will continue to fluctuate driven primarily by power prices, and our guidance includes the $33 million of mark-to-market losses as of June 30, 2005.

Of this amount, $31 million is related to forward power sales to post 2005 so there will be continued volatility with this number.

The guidance also includes $21 million of the $30 million target for NRG 2005 savings, which have been locked in for the year.

Or adjusted EBITDA guidance excludes unusual or non-recurring events and assumes normal weather patterns for the remainder of the year in our core markets.

I will now turn it back to David for final remarks and the Q&A session.

Thank you, Bob.

Before I open up the telephone lines for questions, I'd just like to make three points in conclusion, and three unrelated points.

First, if you look at slide26 of the slides, our conclusion slide, we've been pursuing a series of strategic financial and operational objectives for several quarters now and while we obviously had some operational hiccups during this second quarter, which we are aggressively moving to address, my view is that the Company remains well on track to achieve our longer-term objectives.

The second point I wanted to make, again, unrelated, is a simple and obvious observation but one which no one is saying so I will say it, and that is under the extreme duress of this continuous hot and humid weather that the Eastern interconnect has experienced over the last few weeks, the competitive market structure, and by that I mean the combination of independent power producers and the independent system operators who run the transmission system, has worked.

Power has been generated and transported smoothly and efficiently to the load serving entities.

Had the result been different, the opponents of competitive market solutions would have been quick to argue to a return to past.

The third and final conclusion I want to make is that all of us at NRG realize what's at stake, particularly over the last few weeks and the few weeks to come, that there's a lot for the Company to win and there's a lot that can be lost.

I want to end by expressing my gratitude to the men and women of NRG who'd been on the top of their games over the last few weeks..

In particular, I mention the team at Huntley who nursed unit 68 through the record temperatures and record prices last Thursday to get it through the peak period.

I'd like to thank the people at all of the high peaking units who we'll have to keep their units in readiness, 365 days of the year just for those few days when they're called upon and then when they're called upon, they have to come on.

And the people at Dover and Vienna have done well and of course the ultimate high peaking unit, Oswego, as well.

Finally I'd like to think the teams at Arthur Kill and Astoria for basically keeping the lights on in New York City over the last few weeks.

So, with that, Diego, I will turn it back to you to open the lines for questions and answers.

Ladies and gentlemen, at this time we will be conducting a question-and-answer session. [ OPERATOR INSTRUCTIONS ] Our first question comes from Andy Smith with J.P.

Morgan, please state your question.

Good morning, guys.

Good morning Andy.

I got a couple questions for you.

Can you guys give us -- and I may have missed this, I jumped on the call five minutes late, can you give us any sense of plant availability and the third quarter so far?

Plant availability and the third quarter so far, no, I could not give you that specific statistic at this point.

But no material outages or anything that you guys have seen that causes you any concern so far?

Well, I think the way, Andy, that we would characterize it is that particularly if you were saying relative to second quarter, that apart from Big Cajun, the rest of the fleet, I think there have been outages but they've being short.

We've managed to, as I mentioned with the comment with Huntley 168, pushed them into the weekends in the low price time so overall, if you're asking if we expect a duplication of the second quarter and the third quarter, outside of Louisiana I would say we do not, we've operated pretty well.

In Louisiana, I would have to say the Big Cajun has continued to struggle into July.

Having said that, I would just refer you back to the comments I made about our commercial operations activities with respect to South Central, where we've had tolling arrangements in place that while we still have to bypass power at the marginal costs of combined cycle units, have kept us from hemorrhaging in the third quarter to date in South Central.

Okay, and then on the outages is there any -- have you guys given any color, can you give us any color on incremental costs or CapEx which may be facing as a result of that?

And in conjunction with that are these very plant specific issues?

Is there anything you can extrapolate from this to other components of the fleet?

I think they're relatively quite plant specific, and I don't think, at this time, we expect any of the changes to be particularly capital intensive.

I mean -- the early, when we look at the root causes and, again, our immediate focus has been on Big Cajun, there are some measures we can take, some operational measures, some smaller equipment that we can try and fix.

So Idon't thank that this is about replacing major pieces of equipment.

Afterall most of this has to do with tube leaks, which are extremely annoying and always seem to happen at the worst time, but they're not capital intensive fixes.

Thank you.

Our next question comes from Lasan Johong with RBC Capital Markets.

Please state your question.

Good morning, everyone.

I'm trying to understand this perpetual preferred that you guys have are trying to do.

My understanding this perpetual preferred that you guys are trying to do with Street.

My understanding is that perpetual preferred $250 million principal payment with a 10-year term, so you have the option to buy it back in 10 years?

Yes, Lasan, at the end of year 10, CSFB has the right to put -- we have a right to call the security and then settle in the matter that I mentioned, the $250 million in cash plus then the adjustment depending on where the underlying share prices accompany itself.

After year 10, either party can call or put the shares.

And a delta is payable either in shares or cash?

Yes, at the Company's option.

And what if it is below 250?

What happens if our closing share price, at that point in time, is below the issuance price, and say just as an example, assuming our price at the end of business on the 10th is $40, to the extent that it is below $40, then CSFB will pay to the Company in either shares or cash the difference in value between the $250 million in the decline below the $40 per share.

For example --

I understand.

Not sure why you guys are doing it that way but I understand the mechanics of it.

A share repurchase program, $250 million you have outlined, it sounds like the reasoning for doing this is that you have enough cash to take care of everything and still have money left over to do this program, otherwise it kind of sits on the balance sheet idly doing very little.

Right, Lasan, and the way we see our free cash flow for the rest of the year is that we will replace that $250 million that we're going to use over the second six months of the year.

So your point is correct, that we have cash to do a return to shareholders and we have the liquidity to invest in the business.

And what we try to do is look at the timing, the needs and the requirements and not ist there with a negative arbitrage on the balance sheet of these high cash balances.

And I assume the means you also expect to be able to get it back when and if that money is needed for reinvestment at a future date?

That's the philosophy we operate under.

We want to be prudent with our investors' money both from a debt and equity side and return it when we can.

And the philosophy that we run is when we need it, the capital markets will be there for us.

Thank you.

Our next question comes from David Silverstein with Merrill Lynch.

Please state your question.

Good morning.

On slide 23, you have a table that weights out sensitivity to earnings guidance for the year or EBITDA guidance for the year, I guess this is for the is for last six months of the year, it differs a little bit from the chart that you had for Q1 with respect to natural gas.

I was wondering what the reason for the change in the natural gas sensitivity number was, number one.

Number two, can you tell us is this compared with the current strip price or do you have another price for gas baked into your guidance?

David, on the sensitivities, there's some slight changes on the natural gas.

I think we had like $5 million, less than 5 at the prior quarter call.

It's a couple of things really coming into play to pick one up, for the shorter period.

You have higher volatility, so that's part of it.

The other part of is that we're not fully hedged on the off-peak sales on the natural gas side.

We are fully hedged on the on-peak sales, so basically they're the really the two reasons and still we see a very narrow band, so it's not necessarily an exact science dealing with the different correlations, but it's still in the same order of magnitude seeing that it will have relatively little impact on our results.

Okay, fair.

So Bob, in terms of the prices, though, that are baked into your guidance, for EBITDA guidance, we have obviously a dramatic change in the forward curve.

I'm just wondering what price you're using for gas reason in your guidance.

When we did our forecast, we will using a gas price of $7.56 per million BTU.

Okay, and has that not changed?

It has, it has certainly gone up since we had gone through our detailed analysis but, again, the impact on the results of the gas price movement is negligible.

Thank you.

Our next question comes from John Kiani with Credit Suisse First Boston, please state your question.

Good morning.

Good morning, John.

Just one or two quick questions.

Back when you all gave your full year '04 presentation and gave '05 EBITDA guidance initially, there was a slide that walked from '04 adjusted EBITDA to your '05 guidance, where you all showed about $33 million of O&M cost pressures and then another $35 million of property tax credit pressures.

It's my understanding that I guess a lot of the O&M cost pressures are really more temporary because of their due to the PRB conversion testing at Huntley and Dunkirk that are obviously going to be completed in '05 and then perhaps a little bit for Indian River in '06.

So I'd like to know is are those cost pressures really temporary and if so, are they included in your F.O.R.

NRG guidance and does that indicate potential upside from your F.O.R.

NRG guidance?

John, on the O&M side of it, what's driving about $33 million back them was an increase in the planned outages, year-over-year.

As you go forward in the future, the plants that get the major maintenance at different times and in some years, we have less planned major maintenance than other years.

PRB is a factor in that but it's probably a factor I'd say in about the $10 million range on the major maintenance side.

So the bigger driver there was just that we have major maintenance scheduled in western New York, Indian River, and South Central and just the second quarter alone, the planned maintenance was $16 million higher than what was in the prior year.

So, some of that is cyclical by nature.

On the the tax credit side, last year we had the I think the number you mentioned was the $35 million of tax credit --

Right, for the New York plant.

In the second quarter we, again, qualified for some tax credits that we didn't think we would be able to and, again, it was underneath part of the F.O.R.

NRG umbrella.

And included in the second quarter results are $16 million of tax credits.

And going forward, we expect to get another $5 million of tax credits that not baked into the guidance at this point in time.

Okay, and so just to clarify, the 10 million for PRB that's in that O&M line, that is not in the the the F.O.R.

NRG guidance?

That is not.

Okay, so that indicates that there is some potential upside above and beyond that?

Yes.

Okay and second question is, in regards to the perpetual preferred, is the correct way to think about it is that assuming your stock closes at $40 tomorrow, the strike on the preferred would be $60 a share.

Does that mean that you're short your own stock above $60, and if so, how would you hedge that exposure?

Well, you're right , we're basically selling our shares forward at $60, and to the extent that it gets above then there is the net settlement on that.

Okay, thank you.

Thanks, John.

Thank you.

Our next question comes from Brian Taddeo with Bank of New York.

Please state your question.

Hi, good morning.

Good morning.

Just to follow up on the plant outages, am I correct in understanding that all the plants are back and up and running at this point or are there still some that are down?

Well, if you're talking about sort of the extended outages that we're talking about in June, we don't have any plans on extended outage right now.

Quite frankly, over the last few weeks, virtually every unit in the the NRG system has been running at some point and so there are constantly issues with something at night, so I can't really even tell you right now whether there's any unit -- I did not check this morning to see whether there was any unit that sort of fell off overnight or was having trouble coming on line this morning.

So, but more broadly, we don't have any extended planned outages of any major outages or any minor units going on right now.

So, it's just Big Cajun that ran through July but that was the last of it?

If I heard you correctly.

Big Cajun's last extended outage, multi-week outage was in June.

But Big Cajun has been plagued five times over the last few weeks were one or more units have had to come down for a few days during peak periods.

Okay.

Just wanted to follow-up on the SO2 credit conversation, what's the -- you mentioned there might be am influxtion point on what you'd rather sell them directly Do you have any idea what that price is, in running the plants?

Basically what it is is that we attribute the current cost of emission credits against the plant's cost basis as we figure out whether it can operate at above its marginal cost of production.

So if the attribution of sulfur credits to a plant is $5 per megawatt hour, it's basically without sulfur credits, it's going to earn less than $5, we turn it off and then we would sell the emission credit.

But it's a sliding scale, so the number of marginal hours where you would turn off the plant and sell the emission credits just increases the higher than the cost of what the emission credit is.

Right, do you have an idea of what that threshold is?

No, it's different for each plant.

And don't think there's a particular threshold.

Okay, thank you very much .

Our next question comes from Elizabeth Parella with Merrill Lynch.

Please state your question.

Yes, thank you.

This quarter a couple of generators, including with a decent size coal position, have talked about up with the better market conditions shortening the duration of the hedging strategy.

And yet it sounds like your view is still an inclination to put more for at least dark spread hedges on for '07, I'm just wondering if you could talk a little bit about that, whether that's dictated primarily by your view of gas prices and where they go from here on out.

But if you could elaborate a bit on that?

Well, Elizabeth, I think on the theory that pigs get fed and hogs get slaughtered.

The person who sort of goes short because they think why dark spreads are going to last forever lives to rule the day.

I have not listened to any of the peer group companies second quarter announcements, but my understanding was that one of the reasons they were talking about shortening the length of their hedges had to do with collateral.

For my point of view, of course no one likes to have a lot of collateral outstanding but quite frankly, if all the other companies in our sector who own coal plants in the Northeast, who are more capital constrained than we are, start to go shorter and shorter, there's more opportunity for us to do longer-term deals and to get paid properly for it.

I think the thing that has kept us from doing the longer-term deals is that since the forward market tends to have a bit of an ill liquidity discount in the out years, and because the price of electricity in the Northeast tends to follow gas prices where the curve has been backward dated, there was no reason to try and go out into 2007 or 2008 because you were giving up value because of the backwardation of the gas curve.

That has changed quite a bit , the gas curve has straightened out quite a bit, so I'm not saying that we're going out there crazy, doing multi-year deals, but we're not sitting here saying that we're going off the way everyone else is and going shorter and shorter.

We'll look for value at any length.

Okay, that's helpful, thank you.

Just a follow-up for Bob on the perpetual preferred, if at some point in the next 10 years, the security becomes in the money to CSFB, do you have to reflect it in your diluted share count or because you have the option of paying off the upside in cash, it doesn't get reflected at any point in the diluted share count?

Elizabeth the only portion that would get included in the diluted is the portion above the 50 percent premium.

So if the stock crossed over 60 --

-- right, you'd just take the equivalent value in terms of in shares, of the amount above the $60, and that would be considered in the diluted calculation.

But it would get included because you do have the option of paying it off in shares rather than being required to pay it off in cash?

That's correct.

Thank you.

Okay, operator, I think it's past 10:00, so I think we have time for one more question .

Thank you.

Our final question comes from Kit Conneledge with Morgan Stanley.

Please state your question.

Hi guys, thanks.

A lot of my questions have been answered.

I was wondering if you could just broadly give us an idea on the slide that shows the target out to 2010 for the $900 million in EBITDA.

I know you've talked about various initiatives that would get you there.

Since that's a new slide, is there anything new that you're working on there, any changes in timing there?

When are we going to see some of that start to appear?

Any color you could give us on that?

Well, Kit, first of all, that slide is depicted that way because you're the one that suggested that that would be a clearer way for us to show things.

And there isn't really anything new and it's sort of done the way it is because we're trying to be -- we don't want that slide on page 14 to suddenly appear in your research as our guidance for 2008 or 2009.

So, no, I don't want to give you any more details about -- You see how the colors are intentionally shaded together and there's no timetable, so we will be giving more clarity obviously with respect to 2006 and beyond, in the next quarterly calls because we're in the middle of our multi-year forecasting process.

We would certainly like our board to hear all these things before we start talking to you about it.

Fair enough.

Let me ask one specific question.

As a result, one of the items in the electricity title in the energy bill was that the FERC was supposed to pay something to the affect, of pay particular attention to the Northeastern Governors and so on who don't like LICAP as in the the ALJ's formulation.

Is it your expectation now that your LICAP payments for the Southwest Connecticut area are going to be lower than you would have thought otherwise?

Or do you think FERC is going to come in pretty much at the ALJ recommended?

You know, it's hard to speculate obviously on our government agency and where the come in, but I would say on the balance of probabilities, we think that FERC will endorse the ALJ levels.

Obviously we would argue quite to the contrary of certain of Northeastern Governors that, in fact, the levels themselves represent a compromise that's been pitched at a level that's too low to attract new investment to areas where it's needed.

So, we still hold out some hope that FERC will do the right thing and make them higher, but I think the most likely result is that they endorsed the ALJ's decision in the most substantive of ways.

Thank you.

Ladies and gentlemen, I will now turn the conference back over to your host to conclude.

Again, I would just like to thank everyone for their continued interest and the Company, and we look forward to discussing the Company's third quarter results with you in early November.

Thank you.

Thank you.

This concludes today's conference.

Thank you all for your participation.