艾索倫電力 (EXC) 2008 Q1 法說會逐字稿

Good morning and welcome to the Constellation Energy earnings call. At this time, all participants are in listen-only mode. (OPERATOR INSTRUCTIONS) Today's conference is being recorded. If you have any objections you may disconnect at this time.

I would now turn the meeting over to the Vice President of Investor Relations and Financial Planning and Analysis for Constellation Energy, Mr. Kevin Hadlock. Sir, you may begin.

Good morning. I'm Kevin Hadlock, Vice President of Investor Relations and Financial Planning and Analysis. Welcome to our first quarter 2008 earnings call. Thanks for being with us today. Before we begin our presentation, let me remind you that our comments today will include forward-looking statements which are subject to certain risks and uncertainties. For a complete discussion of these risks, we encourage you to read our documents on file with the SEC. Our presentation today is being webcast and the slides are available on our website which you can access at constellation.com under investor relations. On slide three we will notice we will use non-GAAP financial measures in this presentation to help you understand our operating performance. We've attached an appendix to the charts on the website, reconciling non-GAAP measures to GAAP measures. With that I'd like to turn the time over to Mayo Shattuck, Chairman, President and CEO of Constellation Energy.

Thank you, Kevin. Thank you for joining us today. For the first quarter of 2008, we recorded adjusted earnings of $0.95 per share, $0.08 below the adjusted $1.03 earned during a strong first quarter last year. These results were in line with expectations and reflect solid operating performance. We are also reaffirming earnings guidance for 2008 of $5.25 to $5.75 per share. Now let's turn to slide five to review operating highlights from the first quarter. We achieved several key operating successes in the first quarter. Strong results from our generation fleet continue to be driven by the roll-off of below market hedges. Our nuclear plants also delivered particularly strong operating performance, as we successfully completed a planned outage at Calvert Cliffs Unit 1 in 19 days 15 hours setting a new record for the shortest refueling outage for any plant of its type. In addition, forced outages in the nuclear fleet were limited to less than three days.

We reached another milestone in our plans to develop and construct new nuclear plants by filing the a complete combined license application for Calvert Cliffs Unit 3. In addition, we continue to make progress working with the federal government to move the loan guarantee program forward. We also announced the acquisition of a partially complete Hillabee energy center in Alabama, which will complement our customer supply business in the southeast. Finally, we were able to come to an agreement with Maryland legislative and regulatory leaders on a comprehensive settlement of prior legal, regulatory and legislative issues. Moving over to slide six, I'll walk you through the specifics of that settlement. Late last week, governor O'Malley signed legislation passed by the general assembly finalizing our settlement agreement with Maryland. Under the settlement, all PSE cases, investigations, and pending litigation relating to the 1999 settlement agreement are satisfied and fully released. We believe this agreement provides far reaching benefits for our customers, our investors and the state. BGE residential electric customers will receive a $170 one-time credit and are relieved of any future potential liability for decommissioning of Calvert Cliffs.

A road map was established for future electric rate cases while improving BGE's earnings with negligible impact on customers. The legislation also eases investor ownership restrictions of regulated gas and electric utility holding companies, enabling an investor to own up to 20% without prior PSE approval. Transactions that directly affect BGE or are in excess of 20% will be subject to a 180-day PSE review. These changes provide us with greater strategic flexibility when pursuing investment partners to help finance large-scale capital intensive projects such as new nuclear. We share with state leaders to desire to develop new nuclear plants in Maryland so it was important that we agreed, all things being equal, that Calvert Cliffs would be our priority site should we move forward on plans for a new nuclear plant. This package incorporates a direct and significant consumer benefit while strengthening the strategic flexibility of Constellation Energy. Furthermore, it removes statutory barriers that could have slowed or limited the growth of our Company. All parties gained meaningfully in this carefully crafted settlement and the overarching value is a return to regulatory stability and normalcy.

There is commitment to putting the past behind us and focusing on discussions around the many energy related challenges and opportunities that lie in Maryland's future. As governor O'Malley was quoted as saying, we have huge challenges ahead, but I believe that some of the contentious and divisive issues of the past are now behind with us this agreement, unquote. At Constellation, we fully recognize that the expression of many different views and concerns about Maryland's future energy policy will continue and is like to spark rather intensive debates. However, we are confident we can go about these discussions in a constructive manner now that the past has been laid to rest.

Turning to slide 7, let me now turn to the market environment. As these charts indicate, and everyone on the call knows, crude oil, coal, and natural gas prices rose significantly in the first quarter. Oil was up 24%, coal increased 49%, and natural gas rose 24% since year end 2007. Despite the rise in these fuel inputs, power prices did not rise as quickly, resulting in a significant breakdown in the historic relationship between natural gas and power. We believe that this sharp decline in heat rates was a marked departure from a fairly steady trend that is not easily explained by energy fundamentals. This trend on heat rates is shown on slide eight. Over the past five years, we have seen essentially two eras in PGM forward heat rates, separated here by the blue line on the left. May 2003 through the first half 2004 was essentially the tail end of the power plant building boom that started in the early part of this decade. About 13,000 megawatts of new capacity came on line in 2003 and 2004 causing reserve margins to increase and heat rates to decrease as a result.

In the period from mid 2004 until the present, little new capacity has come on line given generally unattractive new build economics. With continuous demand growth, reserve margins have declined and heat rates have increased steadily, with a brief and temporary downward detour caused by the immediate natural gas price runup following hurricane Katrina in the fall of 2005. In the first quarter this year, forward heat rates departed dramatically from this long-term trend. With no shock event or long term supply and demand fundamental explanation to rationalize this dramatic move, we believe it is most likely explained by what will be temporary trading market dynamics as many financial players may have decreased their exposure to power product during the quarter. This phenomenon had an impact on our first quarter results, which John will address shortly. If the relationship between natural gas and power returns to the historical trend, based on increasing power prices, we would expect to see longer term upside.

Turning to slide nine, in closing, I am pleased with the performance of the Company during the first quarter. We were successful in putting the 1999 Maryland settlement behind us and are turning our full attention to the future. Our market leading customer businesses performed very well in a market environment that was complicated by overall economic conditions. We continue to see strong investment opportunities to support future business growth. We are also seeing attractive opportunities to expand our generation footprint in Maryland, Alberta, Alabama, and other parts of North America. We are reaffirming our 2008 earnings guidance of $5.25 to $5.75. For 2009 we continue to forecast earnings growth of 15 to 20% over 2008. Over the five-year planning horizon we continue to project an average growth rate of greater than 10%. With that, I'll turn the presentation over to John to review the financial results.

Thank you, Mayo. And good morning, everyone. Let's begin on slide 11. As Mayo discussed earlier, we saw strong performance in the first quarter. Let me start by highlighting several of our key financial successes. During the first quarter, we continued to transact opportunistically. As Mayo mentioned, we purchased the Hillabee energy center for approximately $155 million, which will be completed at about 45% of new build cost. The project is expected to be operational in 2010. Consistent with our invest, develop, harvest strategy in upstream gas, we executed the sale of a non-operating interest in producing wells to Constellation Energy partners recognizing a gain of $14 million. At BGE, beginning in January 2008, we implemented electric revenue decoupling for residential and small commercial customers to eliminate the effect of abnormal weather and usage patterns on our electric distribution volumes. Going forward these revenues will primarily be driven by customer growth and will not be affected by actual weather or usage conditions.

While going without any notice, we retired $145 million of BGE's long-term debt, eliminating the lien on Constellation's generating assets previously owned by the utility. As Mayo highlighted, we achieved a settlement in Maryland of prior legal, regulatory and legislative issues. As part of this settlement, we will contribute approximately $187 million as a one-time credit to residential customers. BGE customers will also be relieved of the potential future liability for decommissioning Calvert Cliffs. We do not anticipate the assumption of this potential decommissioning liability from BGE's customers will result in material incremental costs to Constellation when it is time to decommission the plant. In addition, BGE agreed to delay the next electric distribution rate case, such that new rates will be effective no earlier than October 2009 with the resulting increase in distribution rates capped at 5%. To bridge the gap, BGE will resume collection of $20 million per year of the residential provider of last resort, or polar return, beginning June 1st for two years. BGE will also implement revised depreciation rates effective June 1st resulting in an increase of $22 million to $24 million in annualized pretax earnings. We expect these two items will increase BGE's 2008 earnings by approximately $0.08 per share and 2009 earnings by $0.13 per share.

Now let's turn to slide 12 to discuss first quarter earnings. First quarter GAAP earnings were $0.81 per share. Let me walk you through the adjustments to GAAP. We had a $0.19 loss on economic nonqualifying hedges associated primarily with gas transportation. We also had a $0.04 favorable special item with BGE related to the $187 million customer credit that will be accrued in April. The credit causes a reduction in BGE's full-year effective tax rate which impacts all four quarters. Therefore, the impact of the lower effective tax rate on normal earnings will be classified as a special item in each quarter beginning in the first. Finally, synfuel earnings were positive $0.01 per share due to a true-up of the estimated 2007 phase-out. After special items, first quarter adjusted earnings were $0.95 per share, which was in line with our expectations, reflecting solid operating performance.

Two isolated market-driven effects tempered our results. First, the combination of a dramatic rise in coal prices and operational challenges at two coal suppliers led to defaults on their delivery obligations. This reduced first quarter earnings by $0.23 per share. Earnings were further suppressed by an additional loss of $0.21 per share due to hedging effectiveness in our merchant operations. Excluding these two items our earnings would have been $0.44 higher than reported. Looking at our segment performance in our first quarter compared to last year, merchant was down $0.04, the utility was up $0.01 and other non-regulated was down $0.05. Overall, adjusted earnings were down $0.08 per share. I will speak to the segment results in more detail on the next few pages.

Turning to slide 13, BGE's first quarter 2008 adjusted earnings of $0.37 per share were toward the upper end of the first quarter guidance range of $0.33 to $0.38 per share. Compared to the prior year, BGE was up $0.01 on an adjusted basis due to higher transmission revenue, favorable gas supply revenue, favorable storm expenses and share accretion. These positive items were partially offset by higher interest expense and other costs. Let's turn to slide 14 to discuss the merchant business. Our merchant business performed steadily during the quarter in somewhat tumultuous markets. Before I get to the details of our merchant results I wanted to highlight a few factors that had a meaningful impact, since we will return to them as I discuss the various areas. First, energy prices increased dramatically, although North American power did lag noticeably. Coal led the way, up about 50% since the beginning of the year. This dramatic coal price increase meaningfully benefited our coal supply business, and we were able to transact to rebalance our portfolio and capture gains. This benefit was partially offset by isolated production problems at two of a smaller coal suppliers. I'll talk more about both effects.

Second, we saw sharp declines in forward heat rates despite normal weather and stable to declining reserve margins deviating from a fairly strong trend. If forward heat rates revert back to a trend that reflects market fundamentals, we would see some longer term upside given that natural gas prices increased dramatically in the quarter. Not surprisingly, this decoupling of the historical relationship between gas and power did result in some unrealized losses in the quarter, due to the requirements of FAS 133 which I will discuss in greater detail shortly. Finally, given the potential for a recessionary economy, commercial and industrial customers appear to be shifting away from long-term fixed price contracts to month-to-month purchases. It seems interesting to note that, given the recent heat rate compression, the opposite approach may be more advantageous. While our win rates, renewal rates and unit margins remain steady, less demand for fixed price products effectively limits the size in the future. We expect this trend to reverse itself, but it may take a supply shock event to shift buying patterns away from the short-term products that are riskier for the buyer toward longer term fixed price product.

Now let's turn to slide 15 to review the merchant first quarter results. Compared to the first quarter of last year, merchant adjusted earnings were down $0.04 per share. On the positive side, generation was up $0.12. The primary drivers were the impact of the shorter planned refueling outage at Calvert Cliffs which was favorable $0.06 and higher energy capacity prices, as below market hedges continue to roll off, added $0.07. Customer supply was unfavorable $0.02 per share. And global commodities was down $0.07 compared to the first quarter of 2007. I will cover the drivers to customer supply and global commodities in a moment. Lastly higher net interest expense and other items reduced earnings by $0.07 per share versus last year.

Turning to slide 16, this chart provides an update on how changes in market forward prices and hedging activity affect generation EBITDA. For 2008 we are forecasting unhedged EBITDA of $2.85 billion. Netting the hedging impacts at $1.77 billion, our hedged EBITDA is forecast to be $1.1 billion. You will note that unhedged EBITDA is forecast to decline over the next three years due to the backward dated power curve, higher coal prices, and the estimated cost of carbon credits. However, as our hedges on the generation fleet continue to reprice at higher levels, the hedge impact diminishes significantly, resulting in hedged EBITDA of approximately $1.8 billion by 2011.

Turning to slide 17. As you see in the chart on the top of the slide, during the quarter, customer supply realized gross margin of $82 million. This was right in line with our first quarter expectations. Year-over-year, this was a decline of $23 million from the first quarter of 2007. A portion of this reduction is due to a change in how we measure our business performance. Part of the merchant integration efforts were directed at consolidating our risk management activities. As we explained in January, results from customer supply will include the effects of variable load risk and customer attrition. On the other hand, any impacts to risk management activities will be reported in portfolio management and trading. As a result, $8 million of variable load costs appears in the wholesale power results in 2008, while any such expense in 2007 would have been included in portfolio management and trading.

Conversely, $2 million of positive portfolio management results appeared in retail power's first quarter 2007 results and would not appear there in 2008. The remaining difference is primarily due to reduced wholesale power backlog of $30 million, reduced realized retail power gross margin of $14 million, offset by increased retail gas new business of $27 million which was driven by strong marked to market results. The retail power retention rate was 53%, about the same as the first quarter of 2007. However, including the customers that remain on a month-to-month basis, our retention rate jumped to 75%, up from last year's rate of 69%. Our retention rates and win rates were consistent with recent history. However, customers appear to be selecting shorter term products in the current market.

Looking forward, ask price margins were $3.17 per megawatt hour, down a bit from the $3.31per megawatt hour level first quarter 2007 but still healthy. Retail gas retention rates remain strong at 98%, and realized margins improved by $0.04 per decatherm over last year. In summary, our customer supply business, wholesale power, retail power and retail gas are on track to achieve their 2008 earnings targets. As we mentioned in January, due to lower sales volumes and tightening margins at the end of 2007, we did not expect wholesale power or retail power performance to match 2007's strong results.

Turning to slide 18, this chart highlights low commodities contribution margin compared to first quarter 2007. As you can see in the column on the left global commodities contribution margin, excluding the impact of hedging effectiveness and the isolated defaults by two coal suppliers, was $217 million in the first quarter, up $84 million or 63% from the first quarter of 2007. Structured products produced gains of $239 million, an increase of $160 million over the first quarter of 2007. For the past several years, as market conditions dictate, we often transact to realize gains or rebalance the risk characteristics of our structured products portfolio. While we have traditionally reported this as structured products activity, at a management level, decisions are made as part of overall portfolio management. In the past quarter, an historically unprecedented jump in coal prices caused us to realize some gains in our coal portfolio that resulted from the price move.

We also realized gains embedded in a unit contingent PPA from a nuclear unit, reducing exposure to performance risk, as we have done and reported on several occasions in the past. While we are obviously not expecting the dramatic run-up in coal prices to create the magnitude of opportunity that it did, activity of this type was envisioned in our 2008 plan. We may see further opportunities over the balance of the year, though we would not expect them to be as large as those that we saw in the first quarter. Our energy investments contributed $26 million, an increase of $21 million from the first quarter of 2007. Approximately $14 million of this came from the sale of producing gas wells to Constellation Energy partners. Offsetting these increases, portfolio management and trading lost $47 million in the first quarter of 2008. This was a decrease of $97 million from the first quarter of 2007.

Given our approach of managing the value of our entire portfolio centrally, including structured product contracts, energy investment assets, and portfolio management and trading activity, we were pleased with the total performance. As we expect to do in a fairly tumultuous market environment, we experienced gains in some areas and losses in others, resulting in a total performance that was fairly strong. We have already mentioned the sharp drop in heat rates. A direct impact of that drop was the increase in hedging effectiveness experienced in the first quarter. While some quarters will have large hedging effectiveness results, our expectation is that over time hedging effectiveness has the cumulative impact of zero. The dramatic runup in coal prices discussed earlier created operational challenges for two of our coal suppliers that sold forward coal in anticipation of increased production and coal availability. As a result, they defaulted on their contracts and we recorded a $68 million loss in the first quarter.

Turning to slide 19, looking to the future, the merchant continued to build a strong backlog of earnings in the first quarter. After accounting for backlog impact of the structured transactions I just discussed, global commodities added $201 million to its backlog. The customer supply group contributed $40 million to its backlog. While less than our expectations, it is consistent with our experience of customers deferring the decision to enter into longer term contracts. As customers eventually stop purchasing on a month-to-month basis we expect to see the pace of building backlog to increase. As mentioned earlier, we added to our generation portfolio with the purchase of the Hillabee energy center. While we include the projected earnings through 2012 from this acquisition in our generation EBITDA, we show here our estimate of future earnings as if we had sourced a 15-year toll at comparable economics. In total for the first quarter, we added over $360 million to our future earnings.

Turning to slide 20, and a discussion on cash flow, we have refined our cash flow reporting to more closely align with our GAAP cash flow statement. The new cash flow reporting format shown here provides more insight into operating cash flow and clearly breaks out the amortization of acquired contracts and structured deals. In the additional modeling session, we have provided a description of the unamortized energy contracts and annual amortization of these items. Adjusted cash flow from operating activities was a positive $474 million during the first quarter. Adjusting for investing activities, free cash flow was a use of $196 million, primarily driven by the purchase of Hillabee and planned capital expenditures. Cash flow from financing activities, which primarily reflect dividends paid and net debt maturities, was a use of $237 million resulting in a change in net cash of $433 million in the first quarter.

Turning to slide 21, the balance sheet and associated credit metrics continue to be very strong. Total debt outstanding decreased slightly to $4.8 billion in the quarter, reflecting debt maturities at BGE. Equity increased during the quarter, primarily driven by price movements and contract expiration on our hedging activities which, is captured in accumulated other comprehensive income. The result in changes on the capital structure leaves a net debt to total capital metrics in line with year end 2007. Adjusted net debt to adjusted total capital saw a slight deterioration in the quarter, due to an increase in the third party collateral held and a change in accumulated other comprehensive income described above. As will you recall, all these metrics exclude the impact of the BGE securitization debt.

We expect an improvement in the ratio of funds from operations to debt from 2007 levels, largely due to the elimination of the drag created by fuel expenses deferred under Senate Bill 1 rate phase-in plan in 2007. As we have mentioned in prior presentations, we primarily focus on the FFO to debt ratio which is currently the most important ratio for the rating agencies. When the rating agencies look at this metric, they increase the amount of debt by imputing debt from power purchase agreements, pension obligations, trading activities and other comparable activities. They also adjust funds from operations for imputed interest. As a result, they arrive at a much different ratio. Looking at 2008, we estimate the Standard & Poor's would calculate FFO to debt in the 24 to 28% range versus our forecast of 40 to 45%.

Turning to slide 22, this chart shows our excess liquidity which was $3.1 billion at the end of March. The top blue line represents our cash balances plus our bank lines, the total of which was approximately $5.7 billion at the end of March. The green line on the bottom of the chart shows our bank line usage as we post letters of credit with counter parties. At the end of the first quarter we had posted about $2.6 billion in letters of credit. Turning to slide 23, consistent with the approach we introduced in January for the first quarter of 2008, we are not providing specific earnings guidance for the second quarter. Alternatively, we are providing a few key operating and financial metrics. First, we are providing a BGE earnings range of $0.04 to $0.08 a share. This compares to our second quarter 2007 earnings of $0.08 per share, reflecting higher costs, partially offset by favorable polar margins and transmission revenue.

I will also note that we expect to recognize the $187 million credit to BGE customers in the second quarter and report a special item of approximately $0.70 per share. For generation, we are providing a hedged EBITDA forecast of $130 million, which is $47 million lower than the hedged EBITDA of $177 million earned in the second quarter of 2007. The 2008 refueling outage and higher costs to improve fossil plant reliability are the key drivers. The final metric provided is customer supply backlog, which is expected to be $257 million in the second quarter of 2008. Because we he did not measure 2007 backlog in a manner comparable to today, we are not providing an estimate for the second quarter last year. However, as a point of reference, total realized customer supply gross margin in the second quarter of 2007 was $217 million. That concludes our prepared remarks. We'll now turn the call over to the operator for questions.

Thank you. We'll now begin the question-and-answer session. [OPERATOR INSTRUCTIONS] Our first question comes from Dan Eggers from Credit Suisse.

Good morning. Just thinking a little bit about PM&T and kind of the loss in the quarter, a better performance elsewhere, do we need to think about reshuffling expectations for the full year from those different businesses or is the expectation that you're going to make up the loss plus the full-year contribution you expected to see out of trading? Where does that level of confidence come from?

I guess, Dan, Tom Brooks. I guess I would say, of course we've reaffirmed for the year, and probably I wouldn't -- in terms of -- I don't precisely know what you mean by reshuffling expectations, but I think the short answer would be no. Obviously we've stated our confidence on the year. In terms of the -- sort of the characterization of portfolio management trading in one category and structured products in another, we've reported earnings in that format for several -- or in those -- separated the distinction between portfolio management and trading and structured transactions for several years now. At a management level, as I think John highlighted, in terms of the way we manage the overall portfolio, these are very similar activities. So in terms of the structured products gains, the principal driver was significant increases of coal prices that created opportunities that we acted on quickly to capture gains, and I think the combination of $47 million of traditional -- what we would traditionally characterize as portfolio management and trading losses combined with $239 million of structured products gain sort of reflects the overall -- overall pretty strong performance out of our portfolio management at the management level.

Just looking at the heat rate movements and PJM in the quarter, kind of the disruption that had on results, if there is not a return to kind of a more normal expectation for heat rates, does that cast any shadow over full-year contribution, or has everything been marked down to reflect this world, and if we see a normalization you should pick some of that back up as the year goes along?

I'm sorry, Dan, the question was if it --

What happens if the doesn't recover, and what happens if it does? If it does, is it easier to get to your targets? And if it doesn't, have you already reflected all of that nonrecovery in your numbers?

Yes.

Easy. Okay. And I guess, Mayo or John, you guys had talked earlier about being at the high end of the guidance range for this year previously, kind of being a little bit behind on some of the trade/structured products side a bit it seems, then kind of a little bit of down visible earnings contribution in the second quarter. What is your level of confidence you are still going to be at the high end of guidance this year?

Yeah, I mean, this is John Collins. In fact, as you know we're maintaining guidance in the range of $5.25 to $5.75 per share for the year. We would say, based on where we're at to date and the current market conditions, we do not have the exact same level of confidence around hitting the mid to upper end of the guidance range, but we do still see opportunities to do that. So we haven't changed our guidance at this point in time.

Okay. Thank you.

Our next question comes from John Kiani of Deutsche Bank.

Good morning.

Good morning, John.

I have a few questions. What were -- outside of the transport that you mentioned, John, what were the positions and the associated hedges that were disqualified? Were there some accrual positions and some hedges that obviously, as you mentioned, disqualified -- what were those actually?

There actually is -- I don't know if you're confusing two concepts. In the nonqualifying hedges, the two components that are in there are gas transportation and gas storage, and the vast majority of that was gas transportation. So just as a way we have to manage those, we assume they're nonqualifying hedges. The other piece, I don't know if you're getting --

I'm sorry, I meant the FAS 133 hedge ineffectiveness. I misspoke.

That's what I thought, so that's where I was going to go.

Thank you.

The FAS 133 hedge ineffectiveness is really a result of how we manage primarily generation length out the curve where you get into more illiquid market where we primarily use gas to hedge forward generation length positions. With the breakdown of the heat rates that we saw in the first quarter, it's primarily the driver to that position. So it was the primary driver. And the two things that really happened -- and the other piece of it would have been international freight business where we also saw some correlation breakdowns. But hedge ineffectiveness, as I think as you're aware, is broken down into two pieces. There's the piece that's between 80 and 125% of the relationship, and once you're below 100% or above 100%, you then -- within that range, you then have to just basically take that delta or dollar value offset to earnings. Once you go outside those ranges, 80 to 125%, the whole hedge is disqualified and you basically then have to take the whole change in value to earnings. When we look at that $63 million in the first quarter, $25 million was due to the correlation failures outside the 80/125, and roughly $38 million was related to the dollar value offset or the relationship between the 80 and 125.

Okay, John, so that's -- I see what you're saying. That's helpful. So is the right way to think about it is that you were long power -- in other words, sounds like you said there's generation length. So did you maybe buy power from generators, or you're just long power from generators fairly far out on the curve, and in order to hedge that long power position you bought gas as a hedge against it?

John, Tom Brooks. Effectively, of course, we're naturally long power in our portfolio, owing to the fact that we own power plants.

Right.

And to some extent out the curve in less liquid locations where it's not necessarily easy on a forward basis to sell power, we will to a certain degree, sell gas instead of power. And this tends to be a fairly stable relationship, so historically, has generally been a reasonably stable and effective hedging approach. In the first quarter, of course, that historically stable relationship, the forward relationship between gas prices and power prices broke down a bit. So fundamentally, there's not a lot of news here, other than the fact that since this forward correlation broke down, the requirements of FAS 133 caused us to take some unrealized losses to current earnings.

I see. So whatever long power position there was, generating assets or whatever, you sold gas as a hedge against it, and the heat rate moved downward, and that was the exposure, both from an economic perspective and also from a hedge ineffectiveness perspective?

Right. And because, as John highlighted, the correlation of that fell outside the range required in the fairly complicated accounting standard FAS 133, since that correlation breakdown occurred, this required us, as John highlighted, to take -- to take unrealized losses to current earnings.

Okay. That's helpful. Then another question I have is related to VAR. Can you tell us what your average and max VAR were during the quarter?

Yes, we can.

Hold on one second.

The average VAR at the 95% confidence interval for the quarter, for total marked to market portfolio, was $17.1 million, and the high was $22.3 million.

Is that an overnight or a seven-day?

That's a one-day overnight 95% confidence interval calculation.

Thank you. I think you mentioned some gains or asset sales that were included in the merchant results. Can you talk about those a little bit more, please?

John, this is Tom again. Two basic categories in structured products, and as an overarching comment, of course this category of activity transacting to -- entering into structured transactions to capture gains as market prices move during the year, this has been a fundamental part of our operating approach for several years now. We've reported several such transactions directly over the years, and certainly as part of our 2008 operating plan, as we highlighted in January, these sorts of activities transacting to realized gains was part of our operating plan. The '08 operating plan contemplated, of course, a range of scenarios, but, effectively embedded in that plan was gains of this type in the range of $100 million to $200 million. So we experienced gains of $239 million, as John indicated, in the first quarter. So, a bit above our full-year expectation, and certainly faster than our full-year expectation, but fundamentally coal prices, of course, increased quite dramatically. We saw opportunities, and we absolutely moved quickly to transact to realize gains and rebalance the risk characteristics of our coal supply portfolio. Fundamentally that was the principal driver.

In addition -- and there were, several transactions in our coal portfolio that enabled to us do that. Our coal team in London was very adept at acting quickly to capture the mark opportunity that was created. In addition, we entered into a transaction of a type we've entered into in prior years and reported on in prior years, which was we effectively sold a unit contingent long power purchase position, which had been purchased several years ago at much lower prevailing market prices. As market prices increase on such unit contingent power positions, our exposure to counter party performance risk increases. So on a repeated basis over the last several years, we've transacted, in effect, selling these positions as a means of reducing our net exposure to counter party performance risk. So we did that as well this quarter. Again, something that we've done several times and reported on several times in the past. And again, the type of transaction that was absolutely contemplated in our 2008 operating plan.

If I could add just two things, to what Tom said, number one is that the same market environments that allowed us to capture those coal price increases was the same environment that caused us to have the two producers default on their contracts, high prices, operational issues. What you basically were able to do is take advantage of market opportunities to balance the portfolio appropriately. Secondly, while we were able to capture these upside from these coal transactions, at the same time we were able to increase backlog going forward. It's a very positive result on both parts of the equation there.

Okay. That's helpful. Thank you.

Our next question comes from Greg Gordon from Citigroup.

Good morning, Greg.

Thanks. Good morning. So given that you started to answer my question, you gave a backlog number in the analyst presentation in January, backlog numbers for structured products of about $150 million in '08, $160 million in '09, $110 million in 2010, just eyeballing the bar charts. Did you monetize a big chunk of that future value to take in those gains in the first quarter or did you, in fact, build on the total backlog in the first quarter relative to what you disclosed in the analyst presentation?

We definitely built in net -- built on the backlog. So as John indicated, we added, in global commodities, about $200 million to the backlog, net of the backlog reduction impact of the transactions through which we realized gains. So fundamentally, and this has been a basic management metric we've followed for years, we obviously want to be adding to our total -- creating total economic value in a quarter, and we think in terms of the change in the backlog, we did that. We took -- we saw market opportunities to realize some gains in market conditions that made that attractive. We did so. We also added to the backlog to a degree that exceeded by $200 million the amount of -- the backlog reduction that resulted from the transactions through which we realized those gains.

Right. So put another way, you didn't rob Peter to pay Paul and make the earnings in the first quarter.

Yes.

Second question with regard to backlog, related to the coal business. Who were the counter parties that defaulted?

Well, I think they're both public. The first one was Black Diamond, which was the largest majority of the loss, and the other one was somewhat of a related party to Black Diamond because they did business with each other, a small company called Kyva. So were the two counter parties. These were coal suppliers where we had tonnage to be delivered from '08 basically through 2010. However, these contracts were derivatives and were marked to market. As a result we had to take the write-offs.

Pardon my ignorance, are they domestic providers?

They're both domestic, they're both central Appalachian. In some cases a specific type of coal. These were really isolated events, because in this price market, eventually most coal suppliers are doing much better. However, in the case of Black Diamond, they had a plan to increase their production quite rapidly over the next 12 to 18 months. However -- and so they had sold forward quite a bit of what they thought they were going to produce. They ran into operational problems in trying to bring some new mines on line, and their lender, CIT, which is very public, actually forced them into an involuntary bankruptcy. It's been converted to a voluntary Chapter 11 proceeding, and we're on the unsecured creditors committee. However, when you take a look at coal suppliers, most of them are performing much better in this marketplace, but it was the isolated operational event here. And then Kyva was buying from Black Diamond to meet their needs.

I guess you sort of answered my next question, which was, when you got into this coal business, there was a definitive increase in the number of counter parties that you were transacting with that don't have credit ratings for which you had to apply your own credit metrics, and you indicated in your K that a large majority of them were, from your perspective, investment grade. Should we begin to worry about your ability to effectively examine the credit of your counter parties as you expand?

I don't think that's the case. I think we have a very strong ability to examine the credit worthiness of our counter parties. I would correct one thing I think you said, Greg, though. There's very rarely you ever find a coal counter party that's investment grade. And in fact, if you looked at the change in the credit quality of our portfolio over the last two years, it's gone down to be less credit worthy, primarily driven by international coal and freight and domestic coal producers. So it's basically the best credits you find in the coal industry are generally in the mid to low BB range.

Two more questions.

Greg, let me had a one thing terms of your overarching question on the coal business. As John indicated, as you know, we're a supplier of coal, so he we purchase coal from producers, we deliver coal to customers that are consumers of coal. The majority of them electric utilities, of course. As John indicated, most coal producers have subinvestment grade balance sheets. Certainly as we assess those credits, we very much bear in mind the right weight risk that applies. That is to say, our exposure to those coal producers increases, if we've made long-term purchases, as coal prices go up. These subinvestment grade coal producers' financial strength also in general goes up as coal prices increase. So the phenomenon that causes our exposure to them, in general, also causes them to be more able to perform on all their obligations. So we regard the portfolio as containing a significant element of right way risk.

In this particular instance, a single counter party -- single producer, a small producer in the Appalachian region experienced some specific performance or production problems which were -- whose financial impact was exacerbated by the quick runup in coal prices. So this producer had production problems that caused them to be less able to produce coal than they thought they would be, in an environment where prices were much higher. So very quickly they got in a situation where they were in default. Importantly across the whole portfolio, back to your question, we don't think there's a big systematic risk, because these producers' ability to perform in general goes up in correlation with our exposure to them. We think this is very much an idiosyncratic situation, a specific production problem at a specific small producer. So we don't think it's reflective of some broader problem across the whole portfolio. That's not to say that such a thing could never happen again, but merely we don't think it's reflective of a bigger, broader problem across the whole portfolio.

Great. Couple more questions. One related to global commodities, the first question that was asked, just to restate it. You gave a specific breakdown of $441 million of expected EBIT from global commodities in your analyst presentation in January. You've obviously already exceeded the structured -- well, you've already exceeded what you would expect to have earned from certain aspects of that. Should we assume that $391 million of portfolio management and trading goal for 2008 is now significantly lower and is, in fact, going to be offset by the fact that you were able to take these gains in the quarter? And or are you still targeting that $441 million?

Hey, Greg, it's George Persky. Obviously, in global commodities we have a mix of businesses, and over the course of the year in aggregate, we still expect the combination of the three businesses to perform as expected. But obviously, inside every year there's variation in terms of what businesses are making the money and what businesses are not making the money. But in the case of portfolio management and trading, prior to this quarter we had 20 straight quarters of positive results, so it's not -- I don't think it's too far of a stretch to think that PM&T will get back to profitability for the balance of the year.

To the question of, could we make less in PM&T and more in structured products than was in our plan, sure. Does that reflect anything sort of material long-term in terms of the direction of the business? No.

And so that the overall target number is still achievable, in your mind, at this point in the year?

Yes.

Okay. One more question. The hedged EBITDA, you gave an update on the hedged and unhedged EBITDA for the generation business. While the unhedged EBITDA is up, the hedged EBITDA at 8, 9 is actually down modestly, and up reasonably dramatically it at 10 and 11. Looks like the major reason for that is O&M. Can you talk about what adjustments have happened over the course of the quarter that affected the update of those metrics?

The total unhedged EBITDA, as you can -- you've done the math, obviously, already, the total unhedged EBITDA over the 9 to 12 period is up about $900 million from what we told you in January. Hedged EBITDA subpoena about $200 million, is significantly back end loaded it over the 9 to 12 period. In terms of the specific question as to '09, I believe, Andrew, most of that small negative was due to the way we -- we had a bit of a plan error with respect to the way we plan for the cost of SO2 emissions, which was a negative. Other than that, other than that, the arithmetic is pretty transparent. You know how prices moved, you know what our open positions were that we provided. So principally that slight downward was due to some plan issues.

Okay. So either more SO2 credits or higher pricing for SO2 credits or some combination of the above?

Yes, in fact, we missed the modeling of S02 credits appropriately in the plan we gave you back in January, so it's basically an impact in the $35 million to $40 million.

When the scrubbers are up and running that model error becomes not an issue any more?

It's specific to '09. It actually just was kind of like a bust. So it was just specific to '09.

Okay. Thank you, gentlemen.

Our next question comes from Greg Orrill from Lehman Brothers.

Thanks a lot. Two quick questions, first one being on heat rates, and just really what -- what's changed about your thesis on heat rates after seeing the downside year to date and what gets it back to where you think it should be? And then secondly, if you could address the second quarter generation EBITDA guidance being lower than Q2 '07.

I'll take the first one. I think John will take the second. Greg this is Tom Brooks. On the first one what has changed -- what has this done to change our thesis, nothing. As Mayo described, we look at this as a situation where heat rates over the last several years have done pretty much what you would intuitively expect. In the '03, '04 time frame, as significant new generation was being added, as reserve margins increased, we saw a trend of declining heat rates. Since then with little new capacity being added and demand continuing to grow, reserve margins have declined a bit, and heat rates have increased. And this has been a pattern with some ups and downs driven by various events, particularly hurricanes in the fall of '05, which influenced gas prices more than power. But it's been a fairly clear long-term trend.

What we saw in the first quarter of this year was a significant departure from that trend. We can't explain it, we don't think it's reflective of fundamentals. We think it could be, although this is purely speculative, reflective of perhaps financial players who have shifted their risk preferences away from power and toward much more liquid commodities, but that's only speculation on our part. We don't really know, of course, what's influenced this, but it's hard for us to imagine a circumstance where in an environment of continued declining reserve margins, heat rates should significantly reduce over a short period of time. So we think it's likely to rebound. And, in fact, in the first part of Q2, we've seen some rebound already.

On the second part of the question, you asked about the generation hedged EBITDA on the second quarter versus last year. Primarily it's just a couple real drivers there. In the second quarter of this year, we had a [Ganay] refueling outage, and Ganay so you remember is on an 18-month refueling outage, so we did not have any refueling outage at all in in 2007, so that actually reduces our generation EBITDA by about $27 million in the second quarter year-over-year. The other big piece of it is primarily as part of our plan, we are investing fairly heavily in the reliability improvements in our Baltimore-based combustion turbine fleet because of the requirements of RPM, and the potential penalties that exist if your plants don't operate as expected. That actually, year-over-year, is about a $12 million increase, and there's a lot of other factors that are going up and down in there, but those are the two biggest drivers of the year-over-year change in the generation EBITDA calculation.

Operator, we have time for one more question.

Jonathan Arnold from Merrill Lynch.

Good morning.

Good morning.

I just wanted to revisit this heat rate question a little further. Sorry to do that. But to what extent do you think it's possible that the presence of RPM capacity value had on the forward market is having an influence on heat rates as generators have that payment in their revenue stream going forward? And I guess secondly, another possible thought is around, as gas is spiking is, your nonfuel components of the cost stack are a smaller portion of the overall costs. Might it be that with higher gas prices, you are structurally going to see lower heat rates? Can you comment on those thoughts?

On -- let's see. On the first question, I would say it's certainly possible. Obviously the dynamics of forward markets are not always easy to discern, particularly in the short term. So it's certainly possible that the existence of the RPM program, the likelihood that the RPM program will continue to cause generators to invest capital is influencing forward heat rates. That certainly could be. I think we would doubt that such a view would cause anything close to the dramatic impact that we saw in the first quarter. So, a plausible hypothesis, but I don't think it explains what happened in Q1. In terms of -- on the second question, I think probably -- which to restate, I think was if gas prices increased from this level, could you simply -- could this actually influence heat rates themselves. And I suppose the answer to that too, is certainly yes, but that would require in the long term a shift in the generation mix away from gas into other fuel types. Could that happen at high gas prices? Absolutely. I doubt that effect would be this dramatically -- the potential for that effect would be anything close to this dramatically visible in the first quarter.

Thanks a lot.

Thank you all very much for attending this quarter, and we will see you next quarter.