NRG Energy Inc (NRG) 2005 Q3 法說會逐字稿

Greetings ladies and gentlemen and welcome to the NRG Energy third quarter release conference call. [OPERATOR INSTRUCTIONS] It's now my pleasure to introduce your host Ms. Nahla Azmy Director of Investor Relations for NRG Energy.

Thank you Ms. Azmy, you may begin.

Thank you, Dan.

Good morning and welcome to our third quarter 2005 earnings call.

This call is being Webcast live over the phone and from our Website at www.nrgenergy.com.

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

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

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

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

And now for the obligatory Safe Harbor statement.

During the course of this mornings 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 and the press release and this conference call.

In addition, please note that the date of this conference call is November 7, 2005, 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 obligations to update these statements as a result of future earnings - - or future events.

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

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

With the formalities of the out of the way, I would like to turn the call over to David Crane, NRG's President and Chief Executive Officer.

Thank you, Nahla.

I would like to add my personal welcome to all of you participating in this call.

And also a bit of an apology to those of you for whom this call is a bit of an inconvenience given your participation in the Edison Conference in Florida.

And by way of mitigation I'd only mention that it was they who changed the timing of their conference to be the last three days of the reporting calendar.

But in any case, we appreciate your participation.

We have lots of material to cover in a very limited amount of time and we have lots of material because it's been a very eventful quarter.

With me as always is our Chief Financial Officer, Bob Flexon.

But we are also joined today - - and another person who will be presenting is Kevin Howell who runs our Commercial Operations Group.

Kevin, as many of you know joined us in August, from Dominion where he was running Dominion Energy Clearinghouse.

We have asked Kevin to join us because we have been inundated over the past couple of weeks with questions about mark-to-market, collateral, emissions trading, et cetera.

And so, he will address some of those issues in his presentation and be available for questions.

We also have a special guest with us today, Thad Hill, Executive Vice President of Texas Genco.

He's not going to be presenting but he's available to answer any questions you might have about Texas Genco and their portfolio and the ERCOT market.

So, as Nahla said, I will be referring to a presentation, which you can find on the NRG Website, and starting on page four.

On page four, I've set forth what I consider to be the highlights for the quarter.

And if you'd put all of these highlights together and ask what it means, I can tell you what it means to me and what I hope will be your one take away point if you have to get back to the conference.

That point is that; the Company's performance and the activities during the quarter, in my mind, validates the robustness of NRG's unique version of the wholesale merchant generation business model.

The benefits of both scale and asset diversity both within region and between regions was demonstrated over and over again during the multiple weather events that occurred during the quarter.

The benefits of managing to a healthy balance sheet with plentiful liquidity was demonstrated during the extremely volatile commodity price environment that occurred in the immediate aftermath of each hurricane.

And the benefits of having an entire organization focused relentlessly on execution and portfolio management, as we were able to identify and address operational issues that had arisen in the previous quarter, during this quarter with an immediate positive impact.

At the same time, we learned lessons from the impact that the extreme commodity price volatility during the quarter placed on our forward hedge position.

Most importantly, we have already responded to those lessons learned in a variety of ways, one of the most notable of which is a structured transaction respective of our 2007 hedge position, that Kevin will describe to you during his presentation.

Now, with respect to the specific facts on slide four.

With respect to our adjusted EBITDA performance, both the mark-to-market adjustment and the change in our asset portfolio year-on-year tend to obscure the fact that we did significantly better in 2005 than in the third quarter of 2004.

In my mind, this validates our base case hedging strategy, which stated simply calls for heavily hedging forward our base load coal generation, while capturing the upside through our oil and gas peakers.

This is precisely what happened this quarter, as the biggest pop in our earnings was provided by our oil and gas units in the Northeast.

The improvement to our hedging strategy, which Kevin is introducing for 2007 and beyond, will allow us to capture our upside not only from our oil and gas units but also from our contracted base load coal units as well.

With respect to our liquidity, Bob is going talk about this topic at some length.

But let me just quickly summarize for you the key point about liquidity from my perspective.

As we had ample liquidity at all times during the quarter, at no time did we make a hurried or otherwise suboptimal decision with respect to the disposition of an asset or the unwinding of a contract in order to preserve or enhance our available liquidity.

At the same time, we recognize that particularly as we get bigger, holding on to a massive amount of cash to support our commercial operations activities is itself, suboptimal from a cash management perspective.

I believe this is one of the important but less appreciated aspects of the TGN transaction.

Texas Genco hedges much more efficiently from a cash collateral structure than we do due to their usage of a second lien structure involving same-way risk.

We expect the combined Company to predicate its commercial operations activities on a TGN-style second lien structure, reducing substantially the cash sensitivity of our current trading arrangements.

Turning to our debt to total cap ratio at the end of the quarter, uncharacteristically for us this ratio actually went up this quarter due our accelerated share repurchase early in August, but remains well within our target range of 45% to 55%.

I also would note, as I always do, that these percentages still include about $500 million of project level limited recourse debt, which I consider to be nonsupported.

And finally in terms of plant operations, we did much better in total production this quarter than in the third quarter of '04.

And the e4 rate of our coal plants improved during the quarter and was significantly improved for this quarter relative to the second quarter of '05.

Again, our oil and gas plants led the way but our coal plants improved as well during the quarter, as some of the more benign operating procedures introduced during the quarter had a positive impact on forced outage rates.

We expect significantly more improvement next summer, as the result of the fall and spring outage work flow through to operational performance.

Now, turning to slide five, most of the tables on slide five substantiate the observations I just made, except for the table on the top left, which gives safety statistics.

As you can see, our OSHA incident rate bettered our second quarter result and continues to remain below the industry average.

We continue to have much we can do in this area to improve our proactive, preventative safety program in order to reduce in a sustained and meaningful way our incident rate.

Turning to slide six of the presentation, which is entitled Value Enhancing Growth, hopefully, you are getting tired of this slide, our sun diagram as we have shown it three quarters in a row.

I think the difference between when we have shown this slide in the past and showing it now is that I can say that we are actively proceeding on all four fronts.

We are pushing the envelope aggressively in all directions.

And again, there's much to be gained we believe when we get together with Texas Genco, as they have been doing a lot of these same things under a different name, particularly that they have engaged in the very effective cost reduction program.

Now turning to slide 7, which illustrates our focus on our ROIC and NRG program.

We speak about this program a lot as well, which is appropriate because we actually focus on it a lot internally.

The 2005 drivers under this program, which were designed to achieve $30 million in total incremental EBITDA benefits, are going to be exceeded this year, based largely on our current run rate from corporate initiatives.

As we have noted in the past, the operational savings and revenue enhancements at the plant level generally take longer to realize because in most cases they require physical changes to the plant, which can only be made during the fall and spring outage seasons.

As you can see from slide eight, we have a fairly full roster of modifications planned for each of our coal plants, designed to recover lost capacity, and/or improve the liability.

This is another area where we expect significant benefit to come from the combination with Texas Genco, as they have more experience than we do in evaluating the impact of backend controls on operations at coal fired units.

We have more experience than they do in cycling big coal-fired units as base intermediate load.

Clearly, there will also be synergies in the area of procurement, which is another key component on the focus of ROIC program.

Turning to slide nine, I would like to review briefly the market dynamics with respect to our fuel inputs.

Domestic gas production is still struggling with 5 billion cubic feet per day of Gulf of Mexico production still shut in.

And if - - Ivan is a reliable guide from last year, some of the post Ivan, Gulf of Mexico production will never come back.

With respect to coal, Powder River Basin coal prices are up substantially, with transportation out of the Powder River Basin still constrained and at times capricious.

And finally, the cost of sulfur emission credits are way up, presumably off the strength of greater than expected generation during the abnormally hot summer, forcing some generators to caught short to have to cover their position.

The question is; what have we done in response to this commodity environment?

First, with respect to emissions, we have sold about 30,000-tons of 2005 sulfur emission credits, which is about half of our excess credits.

And that's really the point that I wanted to emphasize, is the emission credits that we have sold during this quarter and actually after the third quarter are truly in excess of our needs.

And this excess was largely brought about because of the conversion of our coal fired fleet to Powder River Basin generation.

In addition, as the price of sulfur emissions have gone up, certain of marginal hours for some of our units, we have actually - - it's been made more sense economically to turn off those units and to sell the emission credits.

So in fact, the total amount of our excess emission credits actually goes up, as the sulfur prices increase.

With respect to our coal supply, we - - as you can see from the table on the bottom right-hand corner, on page nine, we actually added incrementally to our coal supply, particularly with respect to deliveries for 2007.

In addition, with respect to coal supply, because of the difficulties in terms of transportation, we continue to actively manage the - - our stockpiles on a day-to-day basis.

And we are working at all times to enhance our delivery, capability and optionality, particularly supplementing our normal rail delivery, with barges.

At this point, at all of our coal-fired units we have approximately a 15 to 25 day supply of coal.

And one other aspect of fuel inventory has to do with our oil supplies.

As a result of the unusually hot summer, oil inventories at our oil fired units were run down fairly substantially.

We are working on a daily basis to get those supplies back up in time for the winter peak season.

Now, turning to slide 10.

Slide 10, this is a graph that we have not shown before, which illustrates the same weighted risk embedded in our portfolio.

What it's showing is how the yearly economic value of the unhedged portion of our portfolio increases in value, as gas prices increased during the last quarter.

The three lines on this graph show the CAL (ph) '06 price for natural gas, the change in the value of our '06 portfolio and the change in the value of our '07.

You can see from this graph that there's a very high correlation.

You can also see that the value of both the '06 and '07 portions have increased but with the '07 position increasing significantly more because of its larger open position.

Besides the remaining open position associated with the base load coal units, both the '06 and '07 positions have benefited from increasing values of the oil units in the Northeast.

Now turning to slide 11, I would like to address certain special issues that affect the NRG portfolio.

First, with respect to our Connecticut portfolio, and the status of the RMR filing, since the FERC issued its delay of LICAP implementation this past summer, on November 1 we filed for a new reliability-must-run agreement on certain of our Connecticut plants totaling 1,440-megawatts whose current RMR agreements will expire on December 31, 2005.

These past filings broke the unit's cost into two parts, a base RMR payment and an additional cost tracker for major and minor O&M purchases.

The new filing combines these two types of costs into a single RMR payment for each plant.

The total cost level for our current filing is $124 million per year, which is roughly comparable to the cost of the base RMR's and cost tracker for these same units in our 2004 filing, with additional common costs reallocated from the six units at Devon to the four units, which remain active.

The current filing is really only different from the prior RMR's in that it does not contemplate the sharing of market revenues.

The RMR's that are currently due to expire this December had an innovative sharing of market revenues in which we were able to keep 35% of energy market and related revenues and credit 65% against the fixed RMR payments.

Our new RMR filing is more traditional in that we don't keep any of the market revenues.

Under the statutes, the FERC is required to rule on our filing within 60 days, or approximately on January 1, 2006.

Now turning to slide 12.

With respect to the direct impact of hurricanes Katrina and Rita on our south central region, as illustrated by this slide, our generating assets generally lay between the destructive paths of the storms.

During the hurricane, and the following two days, we did experience a significant drop in sales due to Entergy Transmission suspending all firm transmission not needed for emergency system reliability.

Although it's impossible to distinguish hurricane damage from the normal constraints on the Entergy system, we believe that for the most part the transmission system is functioning similarly to prestorm operations.

And our normal merchant sales patterns have resumed.

Lost sales associated with the storms are hard to quantify, as many of the megawatts we had available for sale was due to the fact that the storms themselves reduced our load.

We have estimated the total direct net impact to NRG from these hurricanes to be $7 million, broken down approximately into $3 to $5 million for a transmission line that was damaged in the Lake Charles area and $1 to $2 million for a damaged substation.

We plan to seek recovery of a portion of these costs from FEMA but the likelihood of recovery at this point is uncertain.

Turning to slide 13.

Our brownfield program is still in its evolutionary stages but we continue to push forward with several projects.

As you are aware, the most advanced of our brownfield projects is Big Cajun II unit four, for which we've received a critical air permit approval in late August with a great deal of political support in Louisiana.

We are seeing a great deal of customer interest in buying from this new coal-fired unit, although finalizing several of these arrangements have been slightly delayed as our current and potential customers have been preoccupied with addressing the immediate aftereffects of the storms.

We remain on path to begin construction in mid 2006 with long term off taker arrangements in hand, and hope to provide you with the financial benefits and details around this project in the next couple of quarters.

Turning to slide 14 and in conclusion with respect to an update on the Texas Genco transaction, we have made our - - we have made all the necessary filings and I will say thanks to the professionalism and very high degree of cooperation between our staff, the Texas Genco staff and the South Texas Nuclear staff.

We already filed some of these applications in what I believe to be record time.

We are well along in our integration and financial planning and Bob will be talking more to you about the latter.

I want to conclude by saying that; what more I have learned about Texas Genco, its management and its people more generally and its assets since we announced this transaction on October 2, the more I'm convinced that there are many ways that we can and will work together, once the deal is consummated, to create value for our combined shareholders.

With that, I would like to turn it over to Bob Flexon.

Thank you, David, and good morning.

Today I will cover our third quarter results, liquidity at September 30, and update of our Texas Genco financing plans, and our outlook for the remainder of 2005.

Slide 16 highlights the significant factors affecting the quarter.

As David covered, the underlying asset performance and results for the third quarter were very good.

Strong demand for power, coupled with rising power prices, driven by a volatile gas environment, led to increased generation volumes for our oil and gas fired assets and higher margins for all of our assets.

In addition to higher margins, we also sold a portion of our 2005, emission credit position, which contributed approximately $22 million of EBITDA during the quarter.

Additionally, we continue to make progress with our four NRG initiatives, which contributed to our quarter-over-quarter decline in general and administrative expense.

Impacting the quarter and year-to-date financial results were significantly unrealized mark-to-market accounting losses associated with forward electric sales.

They mark-to-market accruals, while significant to reported results are economically neutral to the company, in that offsetting gains on underlying long positions will be recognized as powered is delivered and hedges settled.

I will cover mark-to-market results in further detail later.

Portfolio changes included the sale of infields, Kendall and contract expirations at West Coast Power and Rockford.

Slide 17 provides a financial summary of our Q3 and year-to-date performance.

For the third quarter, operating revenues increased $160 million, over Q3 2004, including, $173 million of net domestic unrealized mark-to-market losses, associated with forward electric sales, as compared to $4.7 million of similar losses in Q3 2004.

Without the mark-to-market losses, revenues increased by 54%.

Energy revenues driven by the rise in natural gas prices and higher generation volumes, increased by $395 million as compared to Q3 2004.

This increase was offset by $100 million in financially settled hedges, primarily in our coal-fired assets.

Our New York City gas plants followed up a strong second quarter performance with another strong quarter with megawatt hours sold up 92%.

Energy revenues increased by $98 million over Q3 '04, with prices driving 56% of that increase.

Energy revenues from oil-fired plants, Oswego, Vienna and the Neepol plants increased by $128 million, with 76% of the increase due to increased output.

Generation from these assets increased 327% versus the third quarter of last year.

Oswego and Vienna, which had limited run time during the mild summer of 2004, represented more than a third of the $128 million, with the balance being from the Neepol assets.

Output from our coal-fired assets was stable quarter-on-quarter yet energy revenues increased by $168 million due to the increase in power prices.

This increase was offset by $75 million in settled hedges.

Capacity revenues decreased by $34 million this quarter, due to the sale of Kendall and the May expiration of a contract at our Rockford facility.

As David covered earlier, we realized $25 million in other revenues during the quarter from the sale of surplus emission credits.

Costs of majority owned operations increased by $288 million, $271 million due to increased costs of energy.

Fuel gas cost increases $99 million, $62 million related to our New York City generation, equally due to increased volumes and prices.

Both our New York City and south central assets purchased gas this quarter for subsequent resale.

The additional costs associated with these sales total $37 million and make up the balance of the increased gas costs.

Fuel oil costs increased by $84 million. $80 million was related to our domestic oil-fired plants, with 75% of the increase due to higher output, and the remainder due to higher price.

Purchased energy increased this quarter over third quarter of 2004 by a total of $53 million.

Due to strong demand from its co-op and long term customers, south central needed to purchase more energy to meet its contract load demand.

Our south central region purchased nearly 822,000 more megawatt hours this quarter at $13.21 per megawatt hour, higher than Q3 2004.

Coal costs increased by $27 million quarter-over-quarter.

With generation from our coal assets relatively flat, the increase was primarily due to higher delivered coal costs.

As mentioned in earlier calls, our Indian River facility consumed a heavy mix of compliance coal, which has been subject to significant price increases quarter-over-quarter.

During the third quarter 2005, coal costs in the Northeast reflected a blend for delivered PRB coal of $33.81 per ton, as compared to $32.27 for the third quarter, an increase of 4.8%, whereas coal costs to deliver eastern coal this quarter was $77, versus $56.46 per ton in the third quarter 2004, a 34% increase.

Eastern coal accounted for approximately 24% of the coal consumed in the third quarter.

Including our south central region coal costs, the delivered cost of coal consumed by our North American generation fleet for the third quarter was $38.79 per ton, or $2.05 per million btu, versus $33.08 per ton, or $1.74 per million btu for the third quarter 2004.

We continue to make progress towards increasing our PRB coal mix.

In Q3 2005, our domestic mix of PRB coal consumed in the Northeast was 51% of the total tonnage versus 43% in Q3 '04.

The domestic mix of PRB coal consumed during the current quarter, including our south central operations, was 76%.

Net cash flow this quarter decreased by $312 million as shown on slide 18, primarily driven by two events, the stock buyback and the cash collateral costs.

On August 11, 2005 we completed the previously announced accelerated share repurchase.

We bought back, with an immediate reduction in our outstanding stock, $250 million of our common shares.

This item was included in cash flow used by financing activities.

The other significant cash movement this quarter is associated with cash collateral calls in support of our hedging activities.

Through September 30, we issued $598 million of cash collateral.

I will describe this in more detail on the next slide.

To finish up on this slide, these two significant uses of cash, were partially offset by the following sources -- $80 million net outstanding drawdown on the revolver, we have since repaid the revolver in full, $46 million drawdown by the Australia Flinders Operation, on their project debt, $25 million of net cash proceeds from the sale of Northbrook and Kendall.

And additionally we received $246 million in net proceeds from the issuance of preferred stock during the quarter, the proceeds of which were used to call back our high-yield bonds.

We had a number of large cash movements this quarter, as the liquidity slide on page 19 depicts.

In addition to the stock buyback and cash collateral costs, both of which reduced our domestic cash balances, we repatriated approximately $271 million of foreign cash.

Approximately $85 million of the repatriation was considered earnings and is eligible for the tax benefits under the American Jobs Creation Act of 2004.

This will result in a domestic tax cash expense of $6.7 million, which will be payable in the first quarter 26006.

The other significant cash movement this quarter, as just discussed, is the cash collateral calls in support of our hedging activities.

Through September 30, we posted $631 million of cash collateral, $598 million year to date and $427 million for the third quarter.

Rising forward power prices driven by the increase in natural gas prices drove the collateral requirements for forward sales entered into during 2004 and 2005.

The Company maintained throughout the period, adequate liquidity levels to meet all collateral requirements with existing cash and credit facilities.

There was no impact from the collateral requirements on our operations or commercial decision making.

Slide 20 shows the return of collateral based on the September 30 balances.

Assuming constant forward prices, we expect the majority of the posted cash and letters of credit to return over the next six months as the underlying trade contracts are settled and power is delivered.

Our liquidity to date remains comfortable at comfortable levels.

Since September 30 and through November 3, posted collateral declined to about $570 million, from the $759 million, thereby increasing our liquidity.

As mentioned earlier, the posted collateral supports our hedging program.

While all of our hedges are economic hedges, not all receive hedge accounting treatment.

Slide 21 shows on the left side, the economic hedges that did not receive hedge accounting treatment, at September 30, 2005, while the graph on the right depicts hedges that have been afforded hedge accounting treatment.

Both graphs also show the rolloff of the positions.

The rolloff of the mark-to-market accruals on the left will be reported as income in the quarter indicated as power is delivered and the transaction settles.

Of the $198 million, $42 million will roll off this year, $78 million in the first quarter of 2006, with the balance primarily rolling off during the remainder of 2006.

The mark-to-market impact fluctuates daily.

And as on October 31, 2005, the mark-to-market declined by approximately $20 million.

Back in August, we provided adjusted EBITDA guidance of $600 million, including year-to-date mark-to-market losses of $33 million and $419 million of cash flow from operations, as shown on slide 22.

With the strength of the Northeast asset performance during the third quarter, our continued progress in meeting the four NRG targets and the sale of emission credits we are raising the premark-to-market guidance from $633 million to $700 million.

As noted on the previous page, there's $156 million of mark-to-market losses associated with post-2005 transactions, resulting in a post mark-to-market guidance of $544 million.

Cash flow from operations guidance is $109 million, down $310 million from our previous guidance.

Major drivers of this update include the improved third quarter operating results, offset by the $426 million of cash collateral posted during the third quarter.

We included the fourth quarter return of $166 million in our guidance.

Collateral postings are included in the working capital.

Slide 23 sets forth our base case structure for financing the Texas Genco acquisition and establishing the Company's ongoing capital structure.

Consistent with our previous disclosures, we expect to launch all components of this financing plan at the beginning of 2006, although the Company is preparing for an earlier market launch if conditions indicate a more favorable market in December.

The financing objectives also remain unchanged, with covenant flexibility, asset backed collateral support and maintaining targeted balance sheet ratios as key deliverables.

Overall, and as slide 24 highlights, the third quarter operating performance and environment, combined with our progress in achieving our four NRG targets, allows to us raise our 2005 guidance.

Our capital allocation program, designed to support the operations, manage our capital structure and provide a return to shareholders met each of those objectives while maintaining ample liquidity throughout the quarter.

While volatility in the power and natural gas markets impacted collateral requirements, it also increased significantly the underlying value of the Company's asset portfolio.

I would now turn it to Kevin Howell, Executive Vice President of Commercial Operations.

Thanks, Bob.

I would like to start on slide 26.

We are always interested in locking in known attractive outcomes for our earnings when market volatility is in our favor.

With the runup in all energy commodities, we have evaluated a wider range of hedging strategies than has been traditional with NRG in order to achieve our three primary objectives.

First, putting a floor under our power revenue for our base load coal generation.

Second, preserving upside participation should the market move higher.

And third, using our collateral support in a more efficient manner than traditional swaps.

As a secondary priority we also seek to hedge with load contracts that provide incremental premium for services such as load following or congestion management.

Finally, we seek to hedge not only our absolute price exposure but also our basis exposure, which I will talk to further in just a minute.

While we view our hedge program as strategic, we view our near term commercial operations activity more tactically.

Our oil and gas units have extrinsic value that is best captured in real-time.

We also manage contractual assets, such as our gas transportation and storage agreements that have value beyond just serving our plants.

Much of our management basis also happens via our trading through optimal dispatch of the fleet, firm transmission and financial products such as FTR's.

Moving to slide 27.

As an example of how we execute our combined hedging and trading strategies I would like to focus on PJM.

Our primary asset of PJM is the Indian River coal plant.

The current hedges in our PJM portfolio, consist of load contracts from the BGS auction and various financial products.

Given that Indian River is on the east side of PJM, it tends to trade at a premium to the nodes on the west side of the system.

This is particularly true in times of high congestion, which actually enhances the value of both the plant and any hedges tied to PJM west.

In other words, our long asset position in eastern PJM rises in value relative to our short hedge position in western PJM, which may actually fall in value.

Moving to slide 28, with the recent sharp increases in prices and volatility, we wanted to lock in some additional upside in value for 2007 and beyond.

However, we wanted to lock in the value without subjecting ourselves to the mark-to-market swings and cash collateral calls that have so affected our current hedge position this quarter.

As such, we considered a variety of option structures such as ratio collars, which would have the effect of putting a floor on earnings and leave upside participation in the market and ensure we use our cash collateral in an efficient matter.

We have already begun to implement this strategy with respect to our 2007 Northeast asset position and would like to illustrate its effect on the next two slides.

On slide 29, this is a payoff chart demonstrating our earnings profile under a couple of scenarios.

The gray line running at roughly a 30-degree angle represents an unhedged - - represents unhedged generation.

You can see the symmetrical upside and the downside of the slope.

The red line depicts the payoff curve of a long at the money put position, net of any up-front premium.

The yellow line depicts the slope of a short $10 out of the money call position for 50% of the volume under the long put.

The blue line depicts the blend of all of the above.

You will note that we have effectively put a floor on the down side where our only cost was the premium.

We participate in 100% of the upside for the first $10 move and then we participate 50% thereafter.

Slide 30, this is a complimentary slide that shows the collateral support of the position we just described.

The red line is unhedged generation, which requires no support.

The blue line is a long put position, which also requires no collateral support since we are along the option.

The yellow line depicts the support of a traditional swap structure as it moves into the money.

The pink line depicts the 50% ratio short call structure as moves into the money.

The benefits of this structure are twofold as we have less collateral support and are still participating in the upside market move.

While an important transaction for us more importantly, it is a good example of one type but by no means the only type of transaction structure we intend to employ going forward to optimize the value for NRG assets.

I will now turn the presentation back to David.

Thanks, Kevin.

Thank you, Kevin and as I said, Kevin will be available to answer your questions, which will occur in just a couple of minutes.

For those who are following along with the presentation, there are two concluding slides, slides 32 and 33.

One highlights, in a modest amount of detail, the various fronts upon which we are moving now, and will continue to be moving on once the Texas Genco transaction closes to enhance shareholder value.

The other explains from a broader perspective, the NRG business model and the advantages we bring to the implementation.

The point I would like to end with is this; we emerged from chapter 11, now I guess almost two years ago, with a comparative advantage relative to our competitors.

I believe that over the ensuing two years we have continuously added to that advantage through the effective execution of this strategy.

Until the Texas Genco transaction, though, that improvement had been gradual.

But quite frankly, the TGN transaction, in my opinion, puts us in a position to lap the field.

As we look forward, I see tremendous opportunity and optionality in how we navigate through the dynamic landscape of our industry and our commodity price environment, with the goal always of creating ever more value for our shareholders.

And with that, Operator, I turn it back to you to open the floor for questions and answers.

[ OPERATOR INSTRUCTIONS ] Our first question is coming from Elizabeth Parrella of Merrill Lynch.

Please proceed with your question.

Thank you.

Just a question to clarify on the 2007 hedging strategy.

You mentioned you hedged 30% on peak of your coal generation.

Is that - - looking at on peak of coal production exclusive of the amount that's tied up in the Cajun contract, meaning you are looking at the truly unhedged or kind of Northeast/mid-Atlantic piece?

Elizabeth that's correct.

Okay.

So it's 30% of that is kind of open block?

Yes.

Okay.

And then a follow-up question for Bob.

Can you just give us kind of an update on - - if you can, on what type of rule of thumb for changes in collateral going forward based on changes in gas prices based on what you have done today, not assuming any kind of change in the strategy yet with respect to the Genco structure?

Yes, Elizabeth, you mentioned collateral not so much on the EBITDA impact of GAAP.

If you can give us both that would be great.

On the gas we still estimate that the - - if we look at this year, the dollar movement of gas will have a very minor impact on the earnings, given the hedge position, I would say it's less than $5 million.

For 2006, we've talked about it before publicly and we've done a retest of our numbers.

And we still estimate that our sensitivity to gas in '06 on EBITDA is in the $15 to $20 million range.

And then on collateral, the rule of thumb that we use is gas moves $1, then the impact on collateral is about, call it $120 million.

So, if power prices move $1, it's about $15 million.

So, you get that relationship there.

It's about eight times on the power versus the gas.

And then - - on that collateral impact is with respect to 2006?

Yes that's on where we are today.

Okay.

Based upon our current hedge positions.

Yes, all of this is before Texas Genco.

Okay.

And just going back to your EBITDA comment on the '06 EBITDA, $1 change in gas, 15 to 20 million impact on EBITDA that's kind of relative to today's gas prices or it doesn't really matter what gas prices start with?

It just doesn't matter where you start with.

It's the sensitivity of the movement from where from where we are.

Thank you very much.

Our next question is coming from Brian Chin of Citigroup.

Please proceed with your question.

Congratulations on a great quarter.

Question for you on the El Segundo contract.

Can we get any little bit of clarity there, beyond what you have given out in the press release?

The El Segundo RMR status or you mean the contract that’s currently - -?

Tolling contract.

Well, the - - that contract goes until the spring, I think until May 1.

But that's still I think the guidance is - -

I think the existing RMR contract goes to May.

And then there's a two-year toll that we have entered into beyond that, that we roll into.

But - - Brian is that the detail you wanted?

Actually, I will ask you offline later on what I was looking for.

That's great.

Thanks a lot.

Our next question is coming from John Kiani of Credit Suisse First Boston.

Please proceed with your question.

Good morning.

I jumped on the call just a few minutes late, so I apologize if you have already gone over this.

Can you give us an update, perhaps on the RFP process for the Big Cajun expansion?

And perhaps your level of conviction in that, especially in the wake of the hurricane?

Well, in terms of these reverse RFP that we put out a few weeks ago.

That's right.

Well, between the reverse RFP and a variety of other sort of bilateral discussions that were already underway, our conviction that there are no shortage of people who would like to participate in the equity ownership and/or take an offtake from the plant for a long period of time is greater than it's ever been.

And so, I don't think that - - for us that's not the main issue of it.

The main issues have been, one is that we can't really settle out the project until the transmission costs are known.

And it's difficult to assess the transmission costs when hurricanes are tearing down the transmission system.

Right.

Every two to three weeks.

And secondly, quite frankly a lot of the load serving entities down there have just been preoccupied with the day-to-day.

And it's just moving a little bit slower.

But in terms of confidence that a coal-fired unit down there will attract a lot of load serving entities that want relief from the volatility of gas prices going forward, yes, our - - John, our conviction is stronger than ever before.

Good.

That sounds great.

Thank you.

Our next question is coming from Brian Taddeo of Bank of New York.

Hi, good morning.

A couple of things.

With regards to the emissions credits, I know you are talking about these being excess, is this something that you anticipate doing now each year out?

Will it be an ongoing thing for your guys?

Well, at this point, we have been selling only the excess credits for 2005 and we haven't sold any of the future credits.

But I would say that we would anticipate selling at the right prices.

Right now, our view point is that even though I think on Friday, sulfur credits touched $1,300 per ton, which is an extraordinary movement, even from when we thought 800 to 900 was high, we don't see anything bringing them back - - we don't see anything reeling in the price of emission credits in the near term.

So, at these price levels, we will be looking at selling more excess credits into the market.

Just as a follow-up, or my follow-up question, with regard to the RMR in Connecticut, any mention that the new RMR's do not contain the benefit from sharing revenue?

What was the benefit in '05, year-to-date, if you can tell us by having that benefit if it's going to go away?

Yes, I don't have that with me right now.

We'll try to get back to you on that.

And quite frankly I don't - - well, I could tell you the percentage was 35%, obviously.

But what it actually translates into, how much money that we had - - that we recouped under that, I cannot give you that number, but I will - - we'll look to providing that if we can, if it's not commercially sensitive.

Okay, thank you very much.

Our next question is coming from Jamie Waters of Intrinsic.

Please go ahead with your question.

Hi, good morning, guys.

Thanks for taking my question.

Just on the capital allocation issue, you made certain comments around a second lien structure for collateral on a go-forward basis.

You have increased the hedging of the book going forward.

Just wondering if there - - could you give us an update on capital allocation, specifically with respect to dividend potential going forward?

Well, Jamie, when we go and we put in our new financing structure early in 2006, the one thing that we are certainly looking for is more covenant flexibility and more flexibility around our restrictive payment baskets than what we have had to date.

We expect to right size these baskets to give us the capacity in a restricted payments baskets to be able to pay a dividend if the Board so chooses that we want to pay one.

So, our structuring will be built around the idea of having the capacity to do it.

Okay.

And Jamie, if I could just add; the fact that Texas Genco and NRG are the two companies in the industry that were actually explicitly contemplating paying a dividend, I think is one of the great strengths of the combined companies.

So, once we get past the initial financing exercises in the first quarter next year, it's certainly something that we'll look at quite seriously, subject to the Board's decision.

Okay.

And then one follow-up, I guess, with regard to the combined entity, would you expect to give an '06 combined outlook on the equity offering or would you be prepared to do that sooner?

I don't think we'll be doing it sooner.

We have got to review even our own formal guidance for 2006 with our Board in December.

And then we'll first have to get that completed.

And then once the Genco transaction closes, I would expect, as that closes we would come out with formal guidance at that point in time.

Okay.

Thanks, guys.

Thanks, Jamie.

Our next question is coming from Clark Orsky of KDP Investment Advisors.

Yes, I just had a question on the 8% note.

It looks like you took them down to about $1 billion and I'm just wondering what are the thoughts are there with that in terms of the refi?

Well, the 8% notes that we exercised some clawback in the third quarter, where we now fully have utilized our equity claw, to bring back a portion of the high yields.

As we go forward and do the restructuring, the likely scenario - - we continue to evaluate different ways of doing the refinancing, but a likely scenario for us is to bring back all the 8% notes to do a tender form.

Okay.

Thanks a lot.

Our next question is coming from Mitchell Spiegel of Credit Suisse First Boston.

Please proceed with your question.

Great.

Just a couple of questions.

First, can you give a sense on for fiscal year '05, the total amount of emission credit sales you are anticipating?

Well, the total amount for '05?

Yes.

Well, we - - I think with have sold about 30,000 tons.

We have about 60,000 tons in our excess.

And how many more we want to sell during the year I'm not going to tell you because that would be commercially sensitive.

Okay, but if you did 22 million in EBITDA, you would expect probably 40 million.

I'm trying to get a sense of the components of your $700 million EBITDA, how much that breaks out between the emission gains versus the improvement in the Northeast, et cetera.

I think that's actually in the presentation.

In the EBITDA guidance for the full year it assumes that we do the 22 million of EBITDA impact with the credits that were sold to date.

It doesn't assume any additional credits - - emission credit sales.

It does not?

Does not.

Okay.

And in terms of the variance then at Big Cajun, are you still purchasing power in the open market to meet your contract commitments?

Well, it sort of depends on when you ask the question.

Right now during a shoulder season down there, while I don't have the up-to-the-date details, I would doubt that we are purchasing much, because this is the time of year where we are actually looking more to sell excess coal- fired generation down there.

So, it's normally just in the July through September, and then a little bit in the winter, when they go through cold spells that we are actually having to purchase power.

The - - obviously, the costs of purchased power was significantly higher this year, in part because of the weather, but also because the forced outage rate at Big Cajun was worse than we - - than last year.

Okay.

And then last question, in terms of structure for the acquisition, from - - just see if I understand it right, you are contemplating taking out all the Texas Genco debt, the 8% notes, the second lien at NRG, and doing all the financings at the holding company and making TGN a wholly owned subsidiary?

That our base plan, yes.

We now are looking at different scenarios but that's the base plan that we start with.

Okay thank you very much.

Our next question is coming from Michael Lipski of Deutsche Banc.

Gentlemen, good morning.

A quick question on the emission sales.

Obviously, 2005 emission credits are redeemable in perpetuity under Title IV.

And I wanted to be sure that -- you talked about these being excess allowances now but for the balance of your foreseeable and plannable years do you see these as excess emissions?

That's correct.

Okay and then my other - - one last question, on your statement of cash flow, for the nine months, you show a unrealized loss on derivatives of 252 million.

I could understand if you had just sold your power forward, why there would be a mark-to-market loss today, particularly in the summertime.

My question is if you have effectively collared your earnings so to speak - - I guess the question is, is it just the sheer magnitude of the hedging activity that you have engaged in in the period that leads to this big of loss?

I don't understand the $252 million number in the context of a costless collar on your earnings.

Michael, for the hedges that have been done to date, most of these hedges were put in place back in 2004, second and third quarter of 2004 and some in the fourth quarter of '04.

And so that's when the forward power prices were significantly lower than where they are today.

So the unrealized item in the cash flow statement is just doing the mark-to-market on all of our hedging activity.

And that's just the unrealized liability at this point in time.

So again, it's driven by two things.

One is the movement of power prices.

But second, the underlying reason is it's the forward power sales the way that we did it in 2004 and 2005, that's causing that unrealized number.

Okay.

Thank you very much.

Our next question is coming from Vladimir Jelisavcic of Longacre Management.

Please proceed with your question.

Good morning, gentlemen.

Very nice quarter.

Just had one question and then a follow-up.

Regarding page 10 of your slides, where you are showing the sensitivity to changes in gas prices, when you say portfolio value, what do you mean by that exactly?

Is that, overall EBITDA from all fuel sources when you are showing the percentage changes?

That's at a gross margin level.

That's just the mark-to-market of our portfolio at a gross margin level.

So, overall gross margin.

Okay.

And can you just give us a little bit of granularity about where most of that comes from?

Does it come from - -?

It comes from the Northeast.

It comes from the coal plants in the Northeast.

Well, it comes from the coal plants in the Northeast and the oil-fired plants as well.

Right.

And just regarding - - I appreciate that.

And then to follow up, just regarding the status of your Northeast assets, when you are speaking, on the following page 11 that NRG filed for new evergreen RMR on November 1, for Middleton, Montville and Devon, could you elaborate on what that means?

Have you just - - have you actually signed an RMR contract with the New England ISO or just taken other matters – just elaborate on that?

What it literally means is that we have just filed with the FERC - -

Right.

who makes the decision by January 1.

But then that decision is appealable.

So normally what happens, as a practical matter, certainly what happened when this - - when the current RMR was in put in place, was it's a combination of getting FERC's blessing but also negotiating with the Connecticut authorities.

And that's why the RMR that currently is in effect had the share of the market.

That was a atypical RMR agreement from FERC's perspective, but it was the subject to an agreement with the Connecticut authorities.

So, we have also - - in addition to filing a FERC, we have an ongoing dialogue with the Connecticut authorities.

And we hope that we can accelerate the process this time around, because we have a great deal of experience with each other.

So, we're hoping that this does not lead to any unusual or lengthy discussions.

Right, and when you say agreement with Connecticut authorities, David, do you mean on $124 million per year?

Well, yes.

It could be about the structure, but it normally comes down to dollars and cents.

And it's a written agreement?

Yes.

Okay.

Thank you very much.

Thank you, Vladimir.

[OPERATOR INSTRUCTIONS]

Well, operator, if there are no further questions, then it's almost 10:00, we're happy to wrap up.

And again, I want to thank everyone for participating in the call.

I apologize for the inconvenience.

And we look forward to seeing many of you at the Edison conference.

Thank you very much.

Ladies and gentlemen, this does conclude today's conference.

You may disconnect your lines at this time.

Thank you for your participation.