艾索倫電力 (EXC) 2002 Q4 法說會逐字稿

Good morning, everyone. I'd like everyone to please take a seat because we're going to start very soon.

Thank you. Good morning, everyone, I'm Paul Allen, welcome to our 2003 presentation of our annual business plan and outlook. We'll be presenting the fourth quarter 2002 results and an overview of your performance. Everyone should have a set of materials, includes slides and a press release.

The not, there are extra copies in the back of the room. This event is being both web cast and is available for a listen-only conference call. We will not be taking questions from phoning-in. In a moment, as soon as everyone has had a chance to get seated, I'll ask our chairman and chief executive officer Mayo Shattuck to start the presentation.

We will take questions from the audience here in the hotel after the full presentation has been delivered. Mayo it's all yours.

Thank you Paul and good morning, everybody. Before we begin our presentation, let me remind that you our comments today will include forward-looking statements subject to certain risks and uncertainties.

For a complete discussion of these risks we edge encourage you to the S.E.C. We aid you in understanding our earnings.

Our presentation today is web cast and the slides are available on our Website which you can access at Constellationenergy.com under investor relations. As many of you know here 2002 was my first full year at Constellation, when we presented to you last year at this time I was only 100 days into the job; which was just enough time to pull together a coherent plan of action along with a specific set of objectives.

Primary among those are guidance. No doubt the environment were worse than we expected. The weather was fortunately better than we expected and the accounting industry entered the fray to make everything a bit more complicated than we expected.

Nevertheless we were steadfast in our determination to deliver and we report on our achievements in the last year and more importantly to expand on a strategy we have a great deal of confidence in. Here is our agenda for the morning. I'll give you the overview sand after that Tom Brooks will talk about our competitive supply organization.

Then Michael Wallace, the president of our generation group will talk about our fleet, Frank Heintz, the president of BGE will find a few minutes, lastly the Follin Smith our CFO will discuss or financials.

I'd like to introduce a few people in the audience from the company who will not be speaking but available for questions. Tom Rezin our treasurer, Tom Brady, who oversees New Energy, Tom Collins our chief risk officer, Peter Jensen, the CFO of Constellation Power Source, Brian Stanton who most of you know our outgoing director of investor relations and starting tomorrow Brian is going to take a whole new course and move into our six sigma group. I want to congratulate him on a job very well done in the last year and a half. Replacing Brian is Jack Thayer who is joining us from Deutsche Banc this month.

By now I hope you have all had to review our earnings press release. For the fourth quarter we earned 41 cents per share excluding special items, full year to 2.52 excluding special items. As you recall in January we provided 2002 guidance of 2.65 to 2.75 per share.

In the second quarter of '02 we recharacterized our load serving business to physical resulting from a shift from mark-to-market to accrual accounting and this had lower earnings.

Our 2002 earnings would have been 32 cents higher or 2.84 a share, 18% increase. We are very proud of this accomplishment, in fact we believe we are one of the very few energy companies that we monitor who has managed to exceed the guidance established in January of '02. Let me pause for a moment to reflect on our accomplishment in what we think is a remarkable year especially with the turbulent environment.

One of my priorities was to foster a new culture of openness in which we provide best in class disclosure and better insight how we make money. I'm very pleased in our progress in this area and renew our commitment to you to continue to give you the information that you need. I also introduced a new structure and processes for risk management which I believe put us at the forefront of the industry. When we met last year we promised we would focus on crisp execution. [gap] As a result we met or exceeded our guidance for the last five quarters.

We also made great progress in integrating our new acquisitions, nine mile point and New Energy into the Constellation family. Perhaps more importantly we were one of the first companies to confront the real realities of a very changing environment. Recognizing that a strong and stable balance sheet would mean the difference between success and failure in the rapidly changing energy markets we acted aggressively to improve our balance sheet selling $700 million in non core assets and turning out $2.5 million of long term debt.

These actions have given us one of the balance sheets in the industry put us in the position of being able to control our own destiny as our industry continues to evolve. We aggressively renegotiate our contract with the California Department of water resources earlier this year which allowed us to resolve a significant uncertainty while providing greater visibility into our earnings.

We proactively shifted the focus of our competitive supply business to accrual well before the accounting industry saw the light in this manner and finally we sharpened our focus on the right business model large commercial and industrial customers and we moved to expand that business platform with the acquisitions of New Energy, Alliance and Fellon-McCord. We want to spend a good deal of time with you today describing this business model first because it has changed from the model of the past and second because the balance provided by a large scalable competitive supply business will deliver an earnings and cash flow structure which has greater predictability and lower volatility.

Throughout the highest level what will Constellation look like in 2003?

We expect our revenues to be about $7 billion this year. Our T and D business BGE will represent about 7% of that. Merchant will rent represent about 74%. I want to draw your attention to the 17% EBIT contribution we expect from our competitive supply business in '03.

This component of our merchant is our growth engine and I will describe this in some detail in a moment. The real simple terms we generate and we sell. This chart provides a volume metric view of our business.

We expect to generate 50 million megawatt hours this year, 63% of our generation is in PGM where we have tremendous asset and knowledge base. We will sell 100 megawatt hours, 24 million of them is to BGE's electric regulated customers. Our competitive supply business will sell about 80 million megawatt hours, 52 million to wholesale customers other than BGE primarily in New England an Texas and 28 million to large commercial and industrial customers all over the country. We serve these obligations to through owned generation and other contractual supply sources.

We first look at the generation piece. We will own more than 12,000 megawatts by mid 2003 when our new high desert plant in California comes on line. The rest of our fleet is located in PJM Texas New York, mid Conn, Florida and the west including our qualified facilities. [Inaudible] from this plants is largely sold forward at very long term contracts. About 50% of our merchant gross margin is related to servicing BGE.

We also derive a significant portion of our gross margin with plants with multiyear purchase agreements. We have good field diversity, with large contribution from economic base load coal and nuclear plant. Oil and gas fired will account for about 12% of our expected megawatt hours this year mostly under long term contracts keeping us relatively well insulated from the potential of declining spark spreads.

Now to the other end of the value chain, selling to customers. Our regulated utility will have revenues of about $1.4 billion in '03, the gross margin of 1.2 billion and EBITDA of about 600 million. The utility will generate cash flow for debt reduction of about $170 million this year. This is a good stable business that generates strong cash flow. Our merchant business described as the combination of our generation and competitive supply business will have revenues of about 5.1 billion in '03 with gross margin of 1.7 billion and EBITDA of 900 million. The merchant will generate cash flow for debt reduction of about $148 million this year.

Pulling away the generation fleet from the merchant we have a competitive supply business which is our growth engine. This comprises CPI whole sale load operation, new energy's commercial, and industrial operation in our recent alliance Fellon-McCord acquisition. This business will have revenues of 3.2 billion this year and gross margin of 364 million. I'll talk more about this in a minute and ask Tom Brooks to expand on it.

In 2003, we intend to continue to sharpen our focus on our business model. We think one of the key lessons of '02 is the advantage of providing value added services in addition to selling the commodity that we generate. Being a pure commodity provider almost guarantees that you'll get the lowest possible margin for your product. The key is to do something more than push power on to the grid and take the prevailing price.

Getting that enhanced relative margin is the fundamental objective of our competitive supply model. 2001 and 02 demonstrated that merchant prices will be cyclical. We are trying to build a business model to create earnings growth. In fact while prices have improved spark spreads have remained under pressure as gas prices have risen faster than power prices due to a combination of supply constraints. While this may paint a bleak picture our business model allows us to grow earnings in a weak spark spread for two reasons.

First, full and nuclear make up the alignment share of our expected output this year, which means that our exposure to gas prices and sparks spreads is fairly minimum. As I showed you earlier we expect gas fired generation to account for only 12% of the megawatt hours we will generate this year. They are mostly under long term contracts.

And secondly we are focusing on competitive supply to enhance our margin. Before I move on I should mention, a trading support our competitive supply business in a number of ways but we are not counting on proprietary trading to contribute to our 2003 earnings. Let me take a few minutes to explain this competitive supply business.

Many of you have asked how constellation plans to grow earnings in an environment where so many other power suppliers are struggling.

The answer is our business model is different. At the heart of our business are customers with complex needs that are not easily met with publicly traded energy products or with bilateral contracts generators.

Trade power company form a large uniform block, whereas typical customer's need is a complicated shaped quantity. We sell power with value added cost management services acting as an extension of our customer's procurement function. Unlike other commodity cost, which industrial customers manage internally, managing energy costs is complex and most industrial customers do not want to build the capability in-house.

On the wholesale side we are filling a need that our customers cannot meet on their own. They need power but they do not own generation assets as a result of deregulation. Why don't they buy it themselves? Because providing fixed price power in the right amount and shape requires skill and expertise that these utilities do not have and are not likely to develop.

We get the higher margin because we evaluate, assume and manage the risk that the customers want to mitigate. We differentiate ourselves with our skill in risk management and with our customer service. We tailor extensive and comprehensive contracts to our customers' needs and stay highly involved in helping them manage through their regulatory processes.

We also act in an advisory capacity to help industrial customers to understand and manage their energy costs. The customers usually want stable and predictable energy cost, but they do not want to invest the market savvy personnel regulatory monitoring and sophisticated infrastructure required to hedge in a regionally stabilized commodity.

Constellation educates customes, give them the benefit of our experience, expertise and market access. We act as an extension of their procurement function, analyzing the usage patter and suggesting alternative production cost at lower cost. Our goal is to become an integral and not easily changed part of our customers operations. We believe energy cost management for customers is the fundamental business that will not go away.

Our customers need an experienced supplier and they are willing to pay a premium for it. In fact on average we receive an increment of $3 to $5 per megawatt hour for our services versus what we could get if we simply sold power on to grid. Our goal has been and will continue to be to capture the highest possible margin we can relative to our competitors by adding value to the commodity we sell. Now, we believe that this model can grow for a number of reasons.

First of all, we have been rapidly growing our competitive supply business for the last several years, and our growth has been accelerating as we expand outside of our home region in the PGM. We have already contracted a level of business for 2003 equal to the level we delivered in 2002. And we have 11 months to go.

The underlying deregulated power market is itself large and currently fragmented and we believe that we are now the largest provider of power and energy cost management to this market.

Of the megawatts that are free to choose, we believe that we currently have only about 11% market share. But as the leader in this fragmented market we have a strong competitive advantage in our customer relationships, our technology infrastructure, our intellectual capital and our five years experience in evaluating, assuming and managing the unique risks associated with energy cost management and load shipment.

And finally the playing field is rapidly becoming devoid of competitors as troubled companies have been forced to [inaudible]. The barriers to competition in this business will not be incremental or significant the learning curve is high.

We have been sharpening our skills and building the infrastructure since 1997, not only do we have a world class risk management organization build on Goldman Sachs DNA, we have the benefit of over 180 years in the utility business. We understand outage risk and estimate load.

As a founding member of PGM we manage transmission constraints. In short we see ample opportunities to expand our business model and grow our market share. We are in the early stages of a new wave of consolidation in this industry. We are not consolidating assets as much as customers.

Our New Energy and alliance acquisitions require what we believe is a fraction of their true value.

Another key focus for 2003 will be to exploit our underperforming asset base by purchase pursuing initiatives across the country. We generated strong productivity results in '02 and we are off to a good start this year. BGE led the way with a systematic productivity improvement initiated in '01 and in 2002 called achieving operational excellence.

The generation group and the support staffs also generated substantial cost reductions in 2002. In total we generated 68 million in productivity gains last year.

This year, we are reevaluating everything we do, making our compensation and benefit structure more efficient and reengineering processes and systems.

We have launched the six sigma initiative to help us leverage productivity. With a variety of initiatives, we expect to save an additional 67 million to shareholders this year.

In total, we expect our cost to be 133 million or 49 cents per share lower than it would have been had these initiatives not been a priority focus for us.

Better yet we still see plenty of opportunity that will take us a number of years to realize. We expect earnings for 2003 to be between 265 and 285 this year a range of five to 13% over 2002 results. For the next several years we still believe a growth rate of about 10% is about right.

As Folling will explaining this is an average growth rate. Expect 2004 to be well below 10%. Significant building blocks, full contribution from our high desert planned in California, significant cash flows and accrual earnings in our competitive supply business including New Energy and the implementation of EITF in 02-03, generator replacements in '03 and additional traction on productivity initiatives.

Hopefully you all saw last Friday that we increased our dividend by 8%, 24 cents to 26 cents per quarter.

When I look back on the challenges we faced in '02 I'm very proud that we produced the strong financial results that allowed us to improve our balance sheet, best in growth opportunities, and raise our dividend. I think very few companies in our sector can make the same statement.

Our growth is to provide -- our goal is to provide a superior return to our shareholders with a combination of stock price appreciation and dividends. We believe that strong earnings growth will drive stock price appreciation and plan to supplement that with sustainable dividend.

We think 3% is about the right yield to create superior return given our growth prospects. We also want to deliver regular increases in our dividend to our shareholders.

We are very pleased with the returns we are able to deliver relative to other power companies and other equity investment alternatives in 2002. We intend to continue superior returns to our shareholders. And now I'd like to turn over the next piece to Tom Brooks who runs CPS.

Good morning.

As Mayo told you we are excited about expanding our supply business. The needs of our distribution utilities customers continue to grow and in an increasingly fragmented market we're seeing great opportunities to grow our share.

With the addition of New Energy and alliance we see tremendous new opportunities to see the needs of commercial and industrial customers. As an integrated energy company we believe that a fundamental source of value is the ability to provide high value energy products and services to customers on a long term basis, enhancing the margins we can earn on the commodity we produce.

I'll discuss the outlook for our competitive supply business which is the combination of our existing wholesale business and our New York commercial and industrial marketing capability. But before I do that though I want to cover the highlights of our strong 2002 results within our base wholesale risk management and load serving business.

With declining spark spreads, low realized price volatility and diminished market liquidity, 2002 presented an opportunity for making money and we all observed the challenges firsthand.

On the other hand, there were many opportunities for growth. The keys to capturing the opportunities were having the right business model and a strong balance sheet. We had both in and our results were certainly more reflective of opportunities than challenges. I'd like to focus on three successes within our wholesale business.

First, good results on managing the merchant fleet's gross margin, second, strong growth in new gross margin, and third, a significant reduction in the market risk in our overall portfolio. In 2002, our merchant fleet's gross margin was generally in line with our expectations, in spite of broadly adverse market conditions.

For example, 2002 realized gas power spark spreads were significantly lower than forward price levels at the beginning of the year. So any gas-fired generators that were not forward-hedged suffered.

Similarly, in spite of hot weather and high loads this past summer, actual spot power prices were significantly lower and less volatile than in the past several years. This made it a challenging year for merchant generators.

Before the start of 2002, we had a strong view of the market's direction. We acted decisively by forward-hedging more than 90% of our expected volumes. As a result of our proactive conservative approach, as well as strong operational performance from the fleet, our merchant gross margin was in line with our expectation.

In addition to protecting our merchant fleet's gross margin through effective hedging, we doubled our new gross margin from $139 million in 2001 to $284 million in 2002. We also improved earnings quality. The duration on the $284 million of new gross margin was less than two years compared to about four years for the whole mark-to-market portfolio at the end of the first quarter 2002.

About 45% of our $284 million in margin came from providing the standard products to load serving customers including blocks of on peak and off peak energy as well as load-following products with a fixed predetermined shape. 30% came from providing load-following or variable quantity products through which we help our customers to manage their demand variability.

The remaining 25% came mostly from the sale of hedge products that our load business enabled us to provide to other generators.

As to customer mix, about two-thirds of our margin came from business with utilities aggregators and industrial end-user. 2002 was a great year for us. But it was built on a strong foundation of growth.

Our results were driven by the fact the that our distribution utility customers still need to procure power for their end users, regardless of of turmoil in the merchant energy sector. Our focus on this segment as well as the strength of our balance sheet have made us an incredible attractive supplier.

With the extension of our commercial supply segment, we see equally attractive growth opportunities in the coming year. The growth trend also highlights the success we've had in originating and hedging mark-to-market earnings.

You've heard plenty from us in the last year about our emphasis on accrual-based earnings. We moved proactively on the issue. This has accelerated our transition. So much reduced two aspects of our load business will still yield ongoing mark-to-market earnings.

One is our customer marketing activity. We're in daily contact with customers who need to hedge their own price risk. Sometimes with derivative instruments that we can provide and manage.

In a market where our customers have fewer counterparties to choose from we find we can provide a service at attractive margins to us.

The customer transactions I'm referring to you are generally simple. Such as buying a fixed quantity of power from a generator, or selling a fixed quantity of power to a distributor. Second, we may see mark-to-market gains from rating. In order to manage our market price risk and understand the markets that shape our business, we must have a strong trading capability.

We've lowered our value at risk significantly, and our presence in these markets may yield Mark market opportunity. So while we do expect some ongoing mark-to-market activity we are not dependent on it. We expect only 3% of 2003 gross margin come from mark-to-market sources.

Finally, on results, let me touch briefly on our risk position. Over the year, we reduced our value at risk by more than 70%. Returning to pre 2000 VAR levels. Our VAR at the end of the fourth quarter stood at $3.1 million at a 95% confidence interval. Looking forward, our expectation is to maintain risk positions at historic levels. We also maintained high hedge ratios for the merchant fleet.

While percent hedge ratios do not fully address all the factors driving uncertainty, to realize gross margin, they do serve as a good directional metric to the extent to which commodity price changes will have an impact on our gross margin. So while hedging flat power and fuel prices is only part of our risk management efforts, it is an important one. We anticipate maintaining high hedge ratios throughout 2003.

For the coming year, our expected fuel input and power output volumes are more than 90% hedged. Manage of our hedges dynamically so is the ratios do change marginally, we expect to maintain a conservative posture through the balance of 2003. I've reviewed the 2002 results from our wholesale business. Now, let me look forward to the outlook for our competitive supply business.

Including commercial and industrial, and wholesale customers. Customers need a more tailored set of energy products than those typically traded among power marketers in the wholesale market. These are customers with a fundamental need to manage their energy supply cost in an environment made more complicated by a deteriorating credit quality of any potential suppliers.

The products we typically provide is a variable quantity of energy, capacity, ancillary service and cost management. Providing these products requires us to understand our customer's needs well. We are effectively providing an outsourced energy procurement service.

Generally demanding a much greater depth of expertise in the commodity only wholesale market. Over the last five years, we've made a significant investment in capital to develop our capability.

This started with a combination of the risk management expertise we derived through Goldman Sachs with a physical experience that came from our heritage and deepened with the New Energy and alliance. Finally, our substantial footing in the generation business and our financial strength are key resources.

Given the events of the last 18 months, distribution and C and I customers want to do business with suppliers who have both the financial and the physical capability to perform on their commitments.

To give you a better sense of the services we provide to our customers, let me highlight a couple of typical customer relationships. First is with National Grid U.S.A. National grid owns five distribution utilities in the Northeast serving over 3 million electric customers and a half million natural gas customers in New York and New England with a combined peak electric load of 12,000 megawatts.

Our relationship benefits there complementary interests. National grid's distribution utilities were required to sell their generation assets while retaining the obligation to serve their customers load. National grid strategy focuses solely on the network business, with the intention to exit the generation supply business altogether.

We have become the largest supplier in New York and New England. We provide more than 3000 megawatts of block power, full requirements in block power relying on power generated from our own generation as well as market sources.

We've assumed many of the operational administrative and risk management aspects of administering part of national grid's QF power purchase agreements serving part of its load. On the commercial and industrial side, Constellation New Energy began serving Verizon communications in New York in 1998.

Since then we extended the service to include service in Pennsylvania and California. Today we provide more than 100 megawatts to Verizon across the country. They are a good example of a large company seeking innovative approaches to energy cost management. Verizon know the markets in which it buys energy where price matters a great deal. Service matters too.

In addition to energy comply, we provide Verizon with demand management service, to enable better energy cost management. Verizon continues to select us because we have been flexible and responsive to Verizon's needs. Turning to the size of our competitive supply markets, here's our current assessment.

On the T and D side our target market consists of distribution utilities, minis and co-ops, who do not maintain an in-house supply function. We estimate the T and D market to be a little under 100,000 megawatts. On the C and I side our target market consists of large commercial and industrial customers we estimate currently to be over 100,000 megawatts.

The size of this combined target market is nearly 170,000 megawatts of peak load, smaller than the sum of the constituent segments because of some overlap. Looking out over a two-year time horizon we expect this target market to expand to nearly 190,000 megawatts mainly as a result of regulatory driven growth.

On an ongoing basis we define annual market potential as the sum of four basic elements. First, potential customers in the target market who are not currently served by any competitive supplier. Second, expected turnover of customers under contract with us, and other suppliers, as their contracts expire.

Third, load portfolio acquisitions from suppliers who are exiting the business, and fourth, regulatory-driven market growth.

These four components yield an annual market potential of 145,000 megawatts through 2004 since roughly 40,000 megawatts of current load is not rolled over by that. You see the greatest potential in the Midwest Texas mid Atlantic and the northeast. There are all regions where we currently have a core presence.

We currently have 18,700 megawatts of contract under contract for 2003, 14,100 megawatts wholesale and 46,000 megawatts C and I implying a share of the wholesale and C and I segments 14 and a half percent and 4 ½% respectively with a 11% blended share. We see the potential to grow our peak load by 15 to 25% per year based on two factors. First, a bottom up analysis of the opportunities we are pursuing now for 2003.

And second, the assumption that we will at least retain our current 11% share of 2004 market. The figure shows our expectations for how our peak load will grow over the next 24 months. We will still be serving one-third of our load currently under contract at the end of 2004.

Building on this core position, we expect to increase our share of the total target market from 11% to 15%, renewals of load currently under contract, new businesses and some load portfolio contract acquisitions. As a result of thumb, for every percentage point that we can increase our market share we add between 15 and 20 million to our annual gross margin.

We face the outlook that Follin will discuss on the assumption of merely retaining our current share of new opportunities. However, given our current momentum, we'd hope to increase our share by the end of 2004. In addition to the outlook for the size of our target market, let me give you a sense of the unit margins we have earned.

As you see here, over the past two years, our typical gross margin per megawatt hour in the wholesale segment have ranged from $2.50 to $6 a megawatt hour. P and I margins gi cents to a dollar higher. Importantly we've not seen margins decline over the last two years.

While we certainly do not sell every megawatt we generate through the competitive supply business, we have substantial impacts on our generation fleet. Selling the undifferentiated commodity at the liquid hub generally achieve a price at or slightly below mid market. By selling value added products through our competitive supply approach, we're able to achieve much higher margins.

There are two reasons for this. First, by providing more products to these customers, we're able to capture value for a more complete set of generating unit's capability, including capacity value, ancillary services and load following capability. Much harder to capture value for these products in the standard wholesale market particularly in a environment of declining price volatility.

Second, there is a significant service component to the completive supply product, which our customers value. To close, the market outlook for our competitive supply model is as strong as we've experienced in the last five years. Margins appear relatively stable. Our expansion into the commercial and industrial market looks like it will provide great opportunities to leverage our existing wholesale platform.

And we think the competitive supply business model will enable us to achieve higher long-term margins from our generation. Now I'd like to turn the podium over to Michael Wallace.

Good morning. In the next few minutes I will discuss our generation fleet, the results realized in '02, our performance against industry comparisons, and plans for '03 and beyond. Our high desert plant, the last of our plants under construction, will come on line mid year and will bring our total fleet to more than 12,000 megawatts.

With that addition and improved performance of the existing fleet we wilt increase our production by more than 10% this year compared to last year. As Mayo indicated we have a balanced fuel mix with the bulk of our production shown on the right coming from reliable low-cost nuclear plants.

Our generation assets are principally located in regions where we have a significant load-serving presence PJM in the northeast and where we are increasing our market presence, Texas, the midwest and California. The gross margin contribution from our generation fleet is largely accounted for by our nuclear plants, Baltimore plants, and national plants with PPAs.

Our national plants without PPAs are solid performers which contribute as market conditions permit, moreover, we value the objectionality and fuel diversity they bring to our portfolio and future value to our merchant business. Through '01 through '03 and into the future our fleet will operate at increasing production levels. The production dip in '02 is largely due to the spring outage at Calvert Cliffs during which we experienced an unusually long outage duration which I will address further in a minute.

The increased generation is due to the addition of the new national plant's performance improvement especially at our nuclear plant, result in increased capability for various units in our fleet.

While O&M costs increased from 02 to 03 due to additional of a full year of our new national plant and a half year for a high desert, the overall trend for declining O&M costs comes from several sustainable initiatives some of which will summarize.

Turning specifically to our nuclear plants and reviewing benchmark comparisons, I would like to focus on production cost which is the relevant cost benchmark for nuclear units. The combined nuclear fleet realized improved production cost as measured by dollars per megawatt hour for this past year. For 2003, our plan continues the trend for improved production cost, with an objective of realizing top quartile benchmark performance, at Nine Mile Point by the end of this year and achieving a similar level of performance by the end of 2004.

Turning now to our Baltimore fossil plants, we look at benchmark data for non fuel O&M per installed kilowatt, and appropriate benchmark for fossil unit that we dispatch as base load plants.

With a 20% workforce reduction, and O&M cost improvements over the past 15 months we have attained top quartile performance levels. This performance will be sustained going forward. Our national plants include the four peak added in 2001, RIO, Nogales and Oleander added in 2002, and high desert which comes on line this year, in the aggregate that's over 4,000 megawatts.

Our benchmark comparison here again O&M per installed kilowatt is excellent. Performance for this year has been better than top Decile and we expect to stay there going forward. This performance is reflective of the top-notch team we have, which includes many individuals who came from our other Constellation plants.

To summarize the past few slides, our generation group has demonstrated solid performance in the areas of safety, production and cost with a passion for improvement that is benchmark driven. But it is the concrete initiatives that we implement going forward that will make our future performance a reality.

Let me highlight just a few items in that regard. With our 2002 steam generator replacement outage on unit No. 1 taking a disappointing 126 days, we undertook a number of actions in preparing to execute a similar scope of work on unit No. 2 this year.

As a result of increased management involvement, establishing an integrated team with our contractor, revising critical technical processes and a number of other measures, we have high confidence in completing this outage in 98 days.

Our earnings guidance is based on a range around this duration. Our nuclear productivity enhancements include initiatives under way at both plants which address organization, work processes, and staffing levels. Well into these initiatives, we have already experienced good results.

Our teams are maintaining their focus on plant safety and reliability, as we continue to improve the productivity of our operations. Our national plant initiatives are aimed at improving our bottom line performance in the immediate term, while maintaining our greatest focus on reliability.

With the startup of high desert this summer and a full year of operation in 2004, we expect to go through some typical startup challenges to plant reliability. Nevertheless, we also expect to move quickly back above 85% reliability as we gain experience operating this unit.

Finally, as we look at our Baltimore fossil plants, reliability is also a key metric. Even as we have experienced a significant reduction in the workforce, our team has improved the reliability of the operations to a level of 90% for 2002. Moreover, we are working to lower our fuel cost through developing greater operating flexibility, allowing the use of a broader range of coals, including the burning of lower cost coal based fuels.

These will improve the economic dispatch for these units. This morning I have had time to highlight only a few of the initiatives that we are undertaking to increase the value we are creating by our generation fleet.

They and many others are captured in the process we began last June which worked through goals, objectives, benchmarking and GAAP analysis leading to critical initiatives which are our focus this year. In summary, important results have been achieved. We have realize a number of productivity improvements this past year. Our generation production level is up, and our costs are down, and those trends will continue.

Our focus is on benchmark, top decile and top quartile performance and actions to get there. Moreover we are positioned to take on opportunities to expand our operations and grow our merchant fleet business in collaboration with our competitive supply colleagues. I would now like to turn the podium over to Frank Heintz, president of BG&E.

Good morning. In the next several minutes I'll highlight key attributes of our Baltimore Gas & Electric Company, review 2002 achievements and the outlook for 2003. BGE is a regulated distribution utility producing stable earnings with modest growth characterized by a low risk financial profile. Our mission to safely, economically reliably and profitably deliver gas and electricity to our customers.

We are regulated by the Maryland Public Service Commission and the FERC and we maintain good relationship with these regularities. Our revenue mix is 50% residential 40% commercial and 10% industrial. So we're not as sensitive to economic ups and downs as other utilities with a larger percentage of industrial load. We have a solid franchise in an economically healthy region. The company is growing at the rate of 20,000 gas and electric hookups per year with delivery volumes expanding at approximately 1 ½% annually.

Let me underscore that BGE's bred and butter earnings are from delivering energy not selling commodity. Our electric delivery rates were established in a 1999 regulatory settlement and are frozen through June 2004 for business customers and June 2006 for residential customers.

Importantly during this rate-freeze period, all the productivity gains that we achieve will pass through to shareholders. This is provided a clear incentive to aggressively pursue cost improvement programs which we did very successfully in 2002, and will continue this year. Since July 2000, all BGE customers have had choice for electric power supply. And as shown on this slide our price freeze commodity service bases out in stages through July 2006.

To manage the commodity risk BGE has locked in wholesale supply contracts throughout the rate-freeze period. Currently pending before the Maryland PFC is a comprehensive settlement establishing a provider of last resort rule for four years following the rate freeze per period.

A bidding process will select wholesale suppliers and to establish market base retail rates. Essentially BGE will be insulated from supply and price risk while maintaining a profit potential. The principal source of BGE's gas earnings is the distribution function, not gas commodity sales.

At just over 20% of our earnings is produced by the gas business. Because of a weather-adjusted rate mechanism, these are our stable and predictable revenues. All of our gas customers have freedom of choice for gas supply. We have a profit sharing formula to incentive BGE to make economical gas purchases for our supply customers. BGE's management is focusing on cost production, increased productivity and improvement in operational performance. Last year I appeared before you and I described plans for BGE's major reengineering project called achieving operational excellence.

I'm pleased to report this effort produced the productivity gains that we anticipated, reducing our staffing by 550 employees. At the same time we have seen improvements in a variety of performance measures. During 2002, J. D. Power and Associates conducted three customer satisfaction surveys.

These showed that BGE is a customer satisfaction leader among eastern utilities. Benchmarking studies show our strides in cost control as well. An analysis of FERC data shows that BGE to move into the first quartile for O&M cost control in gas and electric service. BGE exceeded its 2002 earnings target producing earnings per share of 92 cents. Also, BGE continued to deliver strong positive cash flow. This year can, we will continue BGE's journey to operational excellence. We're intended upon managing O&M while improving and maintaining service reliability and customer care.

That means adherence to the discipline of cost control, standardization highly efficient work management and steady improvement in key performance metrics. Along with other units we will be implementing six sigma process improvements during 2003. We intend to be a six sigma leader in the utility industry.

I can summarize by assuring you that 2003, BGE will continue a trend of crisp execution and strong performance. Now, I'd like to turn the podium over to Follin Smith.

Good morning, everyone. Actually I'll be speaking to you from the special podium. For speakers who are under six feet tall. I'll provide some detail in our 2002 results. And review our outlook for 2003 earnings cash flow and balance sheet. And finally I'll discuss the building blocks for growth we see beyond 2003. Starting with our fourth quarter and full year results, fourth quarter reported earnings were 39 cents per share.

Excluding special items of negative 2 cents, earnings were 41 cents per share which compares to guidance of 33 to 43 cents. Special items of negative 2 cents, 4 cents of workforce reduction cost partially offset by two cents in gain from the sale of non core assets. Earnings were up one cent or 3% from the fourth quarter of 2001 level of 40 cents per share.

Had we not shifted our load-serving business from mark-to-market to accrual, our earnings would have been about ten cents per share higher or 51 cents. Looking at the segments, the merchant business earned 22 cents per share, in line with guidance of 15 to 24 cents. Compared to last year's fourth quarter, earnings of 31 cents declined by nine cents.

In essence, the drag of our new build plants which earned less than their carrying costs, higher coal cost and an outage at our nine mile nuclear plant, we are largely offset a higher mark to market earnings and the addition of new energy now had we not shifted our load serving business from mark-to-market to accrual, merchant earnings would have been ten cents per share higher or 32 cents. Our mark-to-market gross margin was 66 million compared to the fourth quarter 2001 level of 48 million.

New origination was 28 million for the fourth quarter, we also originated transactions with a present value of 37 million, which will be recognized in future periods gross margins.

Turning to the utility, BGE earned 22 cents per share, versus our guidance of 18 to 19 cents due to colder than normal weather. BGE earnings were nine cents better than last year's fourth quarter. As the fourth quarter was affected by the colder weather in central Maryland, lower interest expense were partially offset by the 3 sent negative impact of a one-time disallowance by the Maryland PSB hearing examiner of an item we believed was a recoverable cost. While we're contesting it we've appropriately reserved it.

Our other nothing regulated lost three cents per share compared to loss of four cents a share last year. The primary driver versus the fourth quarter 2001 was improved international performance resulting from higher volume of our Panama company. Adjusting 2002 for the impact of the shift to mark-to-market to accrual for our load truck business, earnings are up from 2001 by 43 cents or 18%.

These pro forma earnings of 284 compared to January guidance of 265 to 275 per share. This chart walks from 2001 to this pro forma number for 2002. The building blocks that contributed to 2002 earnings growth were largely in line with the guidance that we gave you last January, with a few exceptions. Interest expense at the merchant was 9 cents higher due to the conservative balance sheet management actions that we undertook.

Our other non regulated was ten cents lower than our guidance. The primary drivers was mild weather home products business and the weak stock market which negatively impacted our investment portfolio which is being liquidated. BGE's earnings were nine cents per share higher than our forecast of 6 cent improvement primarily due to weather. Lastly our competitive supply business was much stronger than included in our initial guidance this year.

As you recall this time last year we built conservative expectations of 6 cents per share year-over-year growth for CPS. In total, competitive supply earnings were up 47 cents per share which includes the 32-cent impact of the shift from mark-to-market to accrual. The strength of that business was the key to our successfully transitioning our load- serving business from mark-to-market to accrual earnings without actually reporting a year over year decrease in earnings.

Now, let me turn to our outlook for 2003. Our guidance range for 2003 is 265 to 285 which represents growth of five to 13% over 2002. This range excludes the one-time cumulative adjustment effect of EITF 02-03 and FAS 143 implementation. It also includes gains from non core assets and exclude any production cost and we will have 2 million in cost related to prior workforce reduction initiatives which cannot be pre accrued.

This chart walks through the factors that will contribute to our 2003 earnings growth. We've used the middle of the guidance range for this analysis, and that's not to imply that 275 is more likely than either 265 or 285. First we've broken out for you the entire 2003 E and L impact of our portfolio of new gas-fired plants, including all plant costs and allocated interest expense.

We expect our new build plants to add five cents per share in 2003. As you know, in 2002 we brought on three new gas fired plants and we expect our high desert combined cycle plant to come on line in mid 2003. The favorable impact of the sale of high desert's output to CDWR will more than offset the negative impact of the rest of the portfolio of new-build plants.

Including the new build plants we expect our merchant margin to contribute an additional 18 cents per share. That figure includes the gross margin associated with our competitive supply business including new energy and alliance and includes margin from both mark-to-market and accrual sources.

And I'll spend time on this element of earnings in a few minutes. BGE gross margin will grow by the equivalent of 7 cents per share in 2003. We expect productivity initiatives to improve earnings by 24 cents in 2003. Here's a breakdown of the cost savings we're counting on.

Our generation operations has several initiatives, lowering generation costs to top 4 benckmark and undertaking the strategic sourcing initiatives, lower purchased input cost. BGE will continue the solid progress it mate made in 2002, enhancing six sigma launch.

Benchmarking our staff against best in class companies and have initiated several large six sigma projects to drive efficiencies through this organizations. The most immediate benefit will come from our project to consolidate and accommodate our I.T. infrastructure. Finally we've taken several actions to lower our benefit cost across the country including a more cost effective vacation policy and various medical benefits we designed such as a more appropriate cost sharing with retirees and a redesigned medical and prescription plan.

We've experienced a normal wage and general inflation in the area of about 2% with the exception of two areas where we had rapid cost increases. Insurance costs are up 13 million, driven by hardening insurance market conditions, most notably property terrorism and D and O insurance.

Excluding the favorable effect of the benefit cost productivity initiatives, benefits are up about $5 million. As we discussed in our third quarter call, the adoption of FAS 143 accounting for asset retirement obligations will reduce net nuclear decommissioning expense by 5 cents per share. Including interest expense associated with the new build plants and the new energy acquisition interest expense will be higher driving a negative five cent per share impact. This is a result of our prudent balance sheet strengthening action which reduce risk.

Excluding depreciation associated with the new build plants, depreciation will be 11% higher. The primary drivers with the steam generator replacement in Counter Cliff spending on systems enhancements. Now I'd like to dig into the details of our earnings by segment. First the merchant.

In total, we expect merchant gross margin of 1. 758 billion up 149 million from 2002. We expect our PJM fleet to deliver total gross margin of 843 million or 48% of our total merchant gross margin. Merchant primary PJM customer is of course BGE.

Year over year increase of 8 million in our PJM gross margin reflects the renegotiated coal contract and anticipated shorter refueling and steam generator replacement outage at Cal vert cliffs.

Our PJM earnings are relatively stable from a commodity price prospective, earnings under contract represent 87% of total revenue. We're largely hedged on the power we will sell into the market with an overall 94% of PJM revenues hedged. 87% of our fuel costs are hedged. Our coal costs will be around 41 dollars per ton this year.

Also you see a 20 million line item labeled other costs which includes ISO and RTO fees, ash handling that type of thing. The space platform is sensitive to weather variations and availability of our plants. We assumed that after allowing for plant outages our fleet will be available on average around 93%. Equivalent to our 2002 average availability of 93%.

Perspective on our single largest availability risk, one week summer outage at Calvert cliffs will cost us about 5 million in gross margins. We have certain plants under long term power purchase agreements or PPAs representing 30% or 526 million gross margin. Four plants contribute to this piece of our gross margin.

Our Nine Mile Point nuclear plant, our high desert Oleander and university park new build plant, gross margin we earned is primarily from capacity payment. The increase in gross margin from 407 million in 2002 to 526 million is due to the commencement of operation at high desert, increased operation at Nine Mile Point and full year of operation at Oleander.

Next page we provide take away detail for your use in modeling the profitability drivers at these plants. A few facts are worth noting.

These are very long term PPAs. Nine Mile Point is 90% sold-forward through 2009, high desert through 2010 and our other plants including Oleander and university park are substantially sold forward through 2009.

Also worth noting, the three gas fired are sold under tolling agreements, low risk capacity payment drive their income. High desert we have conservatively assumed a 65% factor. In 2003 we will see a negative line item that we expect to recur replacement power cost to the satisfy our contract.

This will be a favorable variance in future years. Competitive supply includes the wholesale load-serving business where we serve distribution utilities primarily in New England and in Texas as well as New Energy and alliance with commercial and industrial businesses.

We expect gross margin of 364 million up from 249 million in 2002. An important phenomenon with a competitive supply earnings is the implementation of EITF 02-03. This change has a very positive impact on our future earnings. It better aligns our earnings and cash flow going forward.

Now, I apologize to those of you who are very familiar with energy accounting but several of you have asked me to explain accounting for energy contracts so here goes.

Now as you know in October the FASB rescinded EITF 98 ten which required energy trading contracts be mark-to-market.

The decision is consistent with the way we've been transitioning to accrual our load serving business in Texas and New England.

Now, as background a key determine as to whether most businesses mark-to-market a contract is whether or not it is a derivative under FAS 133. Load serving and unit contingent contracts typically are not derivative of the amount of power traded is not a specified quantity. An energy EITF 9310 had required that non derivative energy contracts should be mark-to-market if they were energy trading in contracts and the FASB rescinded that EITF in October.

Now, only derivatives will be mark-to-market and not all derivatives will be mark-to-market. Those which are normal purchase, normal sale such as physical power transactions associated with our physical assets will be accounted for as accrual. And also, when a derivative is a cash flow hedge, for instance a derivative hedging part of the output of our derivative plants it will be mark-to-market through income with the upshot being equivalent to accrual accounting.

Finally when we book a derivative contract and it shows a day-one gain, gains will have to be going forward if gains resulted from liquid and forward curves. We do all of our mark-to-market contracts to determine which categorization each will receive.

Some are hedges, some continue to be mark-to-market and those which relate to non realized derivatives, which relate to unrealized non derivative contracts will have to be reversed. Now, to implement EITF 0203, we will take a one-time cumulative adjustment of 425 million pretax, or 263 million after tax. That has two significant pieces.

First, we have 375 million of non derivative, which will be recognized in future periods earnings. Second, we will reverse 50 million of assets not in our mark-to-market asset, the largest of these is the $40 million Texas asset which it was mark-to-market in early 2002. As to what happened to the mark-to-market asset in total, it was $517 million at year end 2002.

As I said, $375 million related to non derivatives and was reversed in the one-time cumulative adjustment. We identified $58 million in contracts which are normal purchase normal sale or qualifying hedges. These positions will be reclassified to risk management and other assets. And they'll amortize into earnings with the accrual positions that they hedge.

That leaves a new mark-to-market asset at January 1st, 2003, of only 84 million. This chart demonstrates how the $425 pretax cumulative tax adjustment will be reflected in future earnings. Power is delivered and we are paid. You can see that the patterns of future earnings are not regular, reflecting the terms of the underlying contracts and their underlying hedges.

In New England you'll note that we have a number of very long dated contracts which is based on preference and regulatory circumstances, our customers. In 2003, these preexisting contracts will add 19 cents to earnings and 38 cents in 2004. This change will bring our future earnings and cash flow into much greater alignment, and we're very positive about it.

We anticipate that our existing contracts will result in $182 million of gross margin in 2003. The wholesale contracts include our pool and Texas portfolio, including the RIO, we expect to deliver 46 million megawatts of power next year under existing contracts at an average of about $4 per megawatt hour.

The C and I contracts have a higher margin than the wholesale contracts.

These portfolios are managed on a hedged basis.

We estimate our customers' load and enter into a contractual entitlement. We are estimating new business growth of 109 million. Tom outlined earlier we expect wholesale load, new wholesale load of about 20 million megawatt hours at a $3 margin. For new energy, we have forecast growth consistent with past performs.

Renewal customers represent approximately 40% of next year's new forecast. We assumed that 77% of all customers whose contracts expire choose to renew with New Energy at 77% renewal factor is conservative compared to an actual renewal factor of 79% in 2001, and 83% in 2002. Finally we've assumed that we will obtain 33% of new contracts at New Energy. This is consistent with 2002 growth in new megawatt hours and less than the 50% growth experienced in 2001. We have assumed no new growth at Alliance in 2003. We need a little time to understand and integrate this acquisition before increasing growth expectation.

Now as you know, purchase accounting requires that tangible assets such as energy contracts, be am ore amortized over their lives. In 2003 we will have purchase contract amortization of 37 million for new energy and alliance. This amortization will decline in 2004 as purchase contracts run off providing a boost to 2004 and 2005 net income.

Finally we've estimated mark-to-market margin at 110 million down 40% from last year's level.

Mark-to-market margin will represent only 3% of total company gross margins. We expect 13 million of gross margin primarily related to our three peaking plants which are not sold forward.

We have been extremely conservative in our view on both forward prices and our ability to capture volatility value out of these spark spread options due to the market's excess capacity and high gas prices. Gross margin from our qualifying facilities will be flat in 2003.

As you'll recall we reversed 9 million in reserves in 2002 due to the fact that PG&E and S.E.C. restructured and paid outstanding receivables. This negative comparisong will be offset by increased performance at COSI, a qualified facility operator and several of our qualifying facility plants. Now, to go a bit further than the typical hedged -- hedged statistic, percent hedge statistic we illustrate here the potential sensitivity of market price changes of our portfolio.

As you know 2002 and 2001 were periods of substantial market price turbulence. What we did in this analysis is supplied 2001 and 2002 actual market price change ranges, for the January 1st, 2003 forward curve, and our actual portfolio.

As you can see, the impact of environments where prices were extreme that in such a extreme fashion would be relatively limited in our ability that reflects our conservative hedging approach. On cost and low growth margin, we will see higher O&M and depreciation and amortization expenses in 2003 due to a new full built plant which came on line in 2002, and six months of operations at our high desert plant we also have a full year of New Energy and alliance cost, these increases are partially offset by the productivity savings that I've described. As I mentioned earlier, interest expense will be higher as a result of the new build plants New Energy and our decision to strengthen our balance sheet. In total we expect the merchants earnings to be between $1.68 and $1.88 per share.

Now, turning to the utility, we expect BGE to earn between 92 and 1.02 per share in 2003 up from 92 cents a share in 2002. The main driver of the year-over-year earnings increase is lower interest expense. To you, turning to our capital spending and cash flow outlook.

Our 2002 cash flow was very strong. Even with the new energy and Alliance acquisition, we generated almost $600 million of cash flow for debt reduction. We monetized 708 million in non core assets in 2002. We realized an additional 78 million in January of 2003, and expect to have sold an additional 50 million by year end to bring our two-year total to 836 million. Our capital spending plans for 2003 is declining from 2002 with a completion of all scheduled new development.

The installation of SCRs at the Wagner and key stone plants. Special items in 2003 including the unit 2 generation replacement plant at Calvert cliffs, pollution control and equipment work on our I.T. system. By 2005, capital spending trends down with the completion of these major projects. This chart outlines projected 2003 cash flow by segment. We expect to generate almost 400 million in cash flow paid on debt. BGE is still the biggest cash flow generator the merchant is strongly cash flow offset as well. Now turning to balance sheet matters.

As I've said our net debt decreased by more than 500 million in 2002. Our equity balance increased 100 million to 4.2 billion at year end as earnings of over 525 million were partially offset by the pension charge to equity, 118 million and dividend.

Our debt to total capital ratio improved by 55% at year end 2001 to 52% at year end 2002. Looking forward, two non cash special items, which will negatively affect reported earnings and equity by $195 million in 2003. Earlier I described the 263 million one-time impact of implementing EITF 0203. Implementation of FAS 143 will favorably affect equity by 68 million primarily to a lower liability at Calvert Cliff it. We estimated a gain of 145 million on our October 31st conference call.

We indicated that the gain was sensitive to interest rate and a1% decrease in rate would reduce the gain by 28 million, and indeed since October 31, the Lehman triple D utility index is down by 225 basis points driving the change.

Bringing cash flow and equity together, we expect our debt to total capital ratio to decline on a comparable basis by 4% points this year to 48%. Then 46 which was released last week will require that the high desert operating lease be brought on balance sheet the second half of 2003.

This accounting change does not affect cash flows or coverage ratios at all, but it does increase the reported debt to total capital ratio. Including high desert we'll be at 52% at year end 2003. We think it's notable that even including all the non-cash charges and accounting changes, and adding off-balance-sheet debt. Our debt to total capital ratio will have improved by 3 percentage point, in 2001 by nearly 55% and 52% at year end 2003. Looking beyond 2003, our long term organic growth target is 10%.

As Mayo said we expect 2004 to be well above 10%. While we're not prepared to give specific point guidance, we can provide some insight into the drivers of 2004 growth. First of all, we expect continued growth from our competitive supply business.

But as I showed earlier the EITF 02-03 contract realization will add 19 cents per share. We'll see the full benefit of our new build program in 2004 when high desert will add another 14 cents per share. We expect growth from New Energy to add to the bottom line helped by the beginning of the wind-down of purchase accounting amortization of contracts that were booked when we acquired them. 2004 will see an 8 cent per share benefit from having both units at Calvert Cliffs up following the steam generator replacement.

We put a conservative place holder initiative, partially offset by inflationary factors. We expect customer growth at BGE. On the negative side on the water fall, another group of customers will roll off of standard offer service in 2004 but they'll move off of rates at about 45 dollars per megawatt hour on to default rates of about $38.

If you recall, as you'll recall, this essentially means that the merchant will receive a lower price from the power itself to BGE customers if prices remain at current low-forward price levels. Finally our capital spending on Calvert Cliffs and our I.T. systems will drive a 11 sent increase in depreciation expense. As you can see in 2004 we have a terrific number of positive factors and very few negatives.

Now, while the crystal ball is less clear beyond 2004, we see continued strong growth opportunities. We have several good building blocks for 2005. We expect the merchant to continue to grow. In addition, we'll have contracts booked in 2002 and 2003, which will be realized in 2004, indeed 10 cents of the accrual contracts booked in 2002 will be realized in '05. New Energy will have a significant boost to income as purchase contract amortization is completed.

A number of six sigma initiatives should bear significant fruit in 2005. Finally, because we will have achieved our target leverage ratio by early 2005, in this organic business plan, we've assumed that we would then undertake share repurchases maintaining a proper leverage ratio. This is very accretive.

Obviously, this part of the plan is least clear because if we undertake opportunities to invest, at returns above our cost of capital, our earnings should be higher. We think the right way to build an earnings forecast is to start with organic opportunity. We have in this presentation.

Partially offsetting these positives are competitive transition charge, revenues will decline in '05 and EITF 0203 contract realization will be lower than in '04. Let me wrap up by providing guidance for the first quarter of '03. We expect earnings of 33 to 43 cents per share compared to 49 cents in the first quarter of 2002.

We expect the merchants earnings to raping between five cents negative to positive, compared to 18 cents in the first quarter of 2002. We are conservatively assuming lower mark-to-market earnings in the first quarter. In addition several unfavorable timing, new build plants have a more negative impact in the first quarter shoulder month. And we reversed the BGE and SCE in the first quarter when they began payments.

These negatives are partially offset by positive improvements in the PJM's income. We expect BGE to earn between 37 and 43 cents compared to 35 cents per share in 2002. The improvements driven by an assumed return to normal weather versus the mild winter of early 2002 by lower interest expense. The non regulated businesses will lose one to two cents per share compared of a loss of four cents in first quarter of 2002.

Now I'll turn the program back over to Mayo to wrap up.

Thank you, Follin. I know that's a lot to take in in an hour and 15 minutes so I thought I might just take one minute to give you the five take-aways. Besides the accounting lesson you got in EITF 02/03 which you'll all want to remember, there are five take-ways that I think are important. In my opinion, having been in the industry now for a little bit over a year, there's very definitely a generation centric focus amongst people in the industry and I think what we try to convey to you that along the value chain, there is margin at the customer level, and that we have migrated our platform to have a more balanced representation between generation and customer-driven margin.

And so first, we really do have a customer centric model. Secondly, the advantage of moving in that direction is not only balanced but we happen to find ourselves in a very fragmented market. We have leadership share, we are able to buy a couple companies that had leadership positions in this market, and quickly integrate it into our CPS-related platform. As our competitive supply business really is one of significant scale with competitors moving in the other direction.

That's a good place to be. We also try to emphasize our productivity initiatives. This is going to be a company that will be considered selling years from now as a top quartile hopefully top decile company. That is truly our objective. You have to keep in mind that we are coming still from a regulated environment.

There is a lot of work to do. Lot of money that can be squeezed out in a lot of areas. That's why we have taken this six sigma initiative as seriously as we have. When you visit us in Baltimore you will run into green and black belts and here the phraseology we are embarking on this program very seriously. I think fourth, because of these moves all of these accounting changes hopefully next year we will be talking 90% energy 10% accounting and not vice vice versa but we have created a business model here which we think has a stable and predictable cash flow. We are thrilled to be able to match our real business to where its net income is matched with cash.

And then lastly, when I first took this job with all the turbulence in the industry, and a lot of skepticism about growth, why would somebody stand up and say you are going to grow at 10%. I think what we tried to demonstrate to you is that we do -- we do have that promise, we're going to execute on that promise, and I turned to the management team on day 1 in this job and said it sounds to me like we're going to have to earn the right to grow.

That expression is something that we live with because we don't execute, we haven't earned the right to grow, if you're trying to reduce debt grow a business, pay a dividend, grow the dividend, no doubt execution has to be a core of what we do every day.

And I think that hopefully today, you have a sense of commitment to that by the senior management here today. So with that, let me open up the field. There are mikes in the middle. If you'd like to stand or get past one of these microphones, I'll open up the audience for any questions that you might have. Maybe you're all stunned by --

Good morning. Just a little bit of a follow-up on the mark-to-market. I'll bet you're having about a 40% reduction in mark-to-market gains, the $110 million pretax comes to about 40 cents after tax. Still seems to be substantial amount of mark to market gains.

And I'm wondering what you guys are doing differently, quite specifically compared to your competitors, that really allows you to continue to do so well in this field, that it's really an accomplishment this year, 2002, but also just going forward, although it's a reduction, it's still a substantial amount.

And I'm trying to get an idea as to what the Constellation advantage is either for your competitors with respect to the really quite compressive performance that you guys are projecting going forward and what you've achieved already?

Why don't I have Tom start on that to break that down a little bit.

Let's see, couple of comments. Number one, just as context I think it's important to bear in mind, as I tried to emphasize, that one of our key initiatives for 2003, absolutely risk ness of the mark-to-market portfolio, our value at risk by more than 70% across the board. So we've been very focuses on environment that changed quite a bit.

Terms of why are we very much a, we've been in for five years now principally focused on serving primary customer and this has been a customer base whose so I would say No. 1, a factor there is kind of business in the past full of opportunities.

Very focused on doing business, high quality credits, so strength of our balance sheet is a important factor. In terms of the kind of business forward, given the EITF 0203 rates, mark-to-market is certainly derivative. While this is not a primary area of focus for us, it is from time to time an outgrowth of our customer oriented load serving business. Sometimes our customers want to manage our own purchase power cost or generators may want to sell power under arrangements which from our point of view are derivatives. And so therefore, we'd account for them on a mark-to-market basis.

Over the second half of 2002, we did have a significant amount of this sort of customer-oriented derivatives activity, as part of -- as part of that mark-to-market gross margin and we'd expect to continue to see some of that in the future. Although again, mark-to-market margin represents only 3% of our 2003 gross margin outlook. So this is not something that we're tremendously dependent upon, it's more an outgrowth of our customer business.

Yes, but if you could be tax effective, I guess what I'm wondering though, if you could give us an idea who your biggest competitors are in this sector and who are you running into the most or are you running into no one because of quality issues but just who is the biggest the competitor that have you out there?

I would characterize it as quite regional at this point. Competitors are number one, people with reasonably strong balance sheet, and number 2, and this is the regional aspect, people who own generation in particular markets. So in the New England market for instance we are very active as a -- in the load-serving business.

Our main competitors there are people with strong balance sheets who own a good bit of generation. And that's -- that's really true, you know, across the various regional markets. It tends to be -- it tends to be those companies that are -- that have strong footings in the generation business.

Thank you.

Hi, first some specifics. I was wondering if you could say how much weather contributes to 2002 earnings for the fourth quarter and for the full year?

Seven cents.

Versus normal, right?

Since last year.

How about normal?

Last year of course had mild.

Okay. So the lower then versus -- and how much exactly was the mark-to-market in '02?

97

And then what is the exact number you're going to put in '03 for the EITF 0203? You gave it for 04 but I didn't see it for '03.

I think it's 19 cents. .

And then a couple of questions. I couldn't see in your press release a total O&M number so we can get a gauge of like how much we can -- how much is cost coding represent the total of O&M?

If you will pull it back we gave you O&M detail for both merchant and bulk for 2002 and 2003.

Okay. And then I guess I was surprised to see like even in '05 you're still expecting six sigma. Is there a range of a five-year number and how we should think of it coming in over time?

A number of the projects that we're implementing for six sigma and the rollout for six sigma, some of them are large. And six sigma is something that takes root and grows. And the third full year of the program would be typically what you would expect to really have these things start to snowball.

That will be 2005. What we've assumed in our plan is 70 to 80 million of productivity savings in '05, which beats inflation by about 15 cents per share. Given the initiatives that we've already launched and the time frame they will be to be complete, that is entirely reasonable. I'm convinced we can meet that.

With respect to dividend, you raised the diffident 8%. I was just curious if you kind of have a long term target for annual dividend growth.

I think that you know, the dividends policy what we're trying to signal to people is, number one, confidence in our future. Secondly, a payout ratio that we think this kind of climate is well balanced against what our growth opportunities are.

I think thirdly, we're obviously very cognizant of the importance of balance sheet management and debt reduction, probably tempering the payout to some extent. And then lastly the concept of really trying to balance stock price appreciation with a yield. Right now, we, you know, it's in the 3% neighborhood.

You know, we believe that in combination of our growth rate that's giving us an above-average return. So when you blend this mix together, we think that this is a prudent course, a prudent move, one that obviously we'd like to signal as sustainable directionally. And gives people some, you know, a sense of our own commitment and confidence in the numbers that we're putting out going forward.

So is the -- do you have a target payout then or should we expect to kind of stay flat from here?

You know, I think probably, you know, I'm not going to make a definitive statement on payout. It happens to remain about the same, given the 8% growth in the dividend. But I think it's something that we will monitor, I think, in this kind of environment, this payout is a prudent course and one that we should sustain for a while.

Okay. And then lastly, you've just filed a shelf offering, and it was I guess $2 billion, or yeah -- I was just curious about, like, expected uses of proceeds, if there were any like debt refinancing or things you were targeting during the year and if you could discuss the relative size seemed large for what I was expecting for like that needs so maybe was there some belief that there could be incremental spending on kind of new development opportunities at the competitive supply business and maybe an idea of what you would be spending on that business per year?

That's a far-reaching question. The shelf really was very ministerial. We had exhausted the last shelf and the prudent thing to do would be to file a new shelf. Actually I think our last shelf was about in size maybe a little bit larger, actually. 2 ½, yeah.

So the right thing for us to do is to get the shelf back on and as to use of proceeds, there is no definitive use of proceeds until we actually make a move.

Obviously, from the standpoint of acquisitions to the extent that we were to make acquisitions, I think that we feel quite strongly that any acquisitions would -- that we would put appropriate mix of equity and debt behind any acquisition to keep the balance sheet metrics about the same.

Our acquisition activity obviously was pretty vibrant last year, although in sort of two out of three areas, the -- most people talk about generation, number of plants available, that being one bucket.

Turns out we looked at 41 plants, we put indicative bids on 14 we won zero, and only two actually got sold. Which gives you a sense of what is happening in the business.

As long as our view of the forward price curve is more pessimistic than the seller, we are not going to get anything cleared in generation and that's fine. We can be patient and prudent on that front.

There are plenty of opportunities on the jean generation side over the next three years. Where we have been successful is in the acquisition of contractual assets, this is in Tom's arena where we are very active. Most companies that have been in trouble look to Constellation as one of the few sources that can actually understand the complexity of their books.

So to the extent that there's a low-serving obligation to a municipality in Texas that's available and we can buy it at unfair returns to us, we are all over that. And we're probably the best -- the best at it. So that category of contractual assets has been something that's very interesting, and will be even more interesting going forward.

And then lastly, is was the fundamental transformation that the company made in the past year by virtually of it's acquisition of New Energy, Alliance and Fellon-McCord because in essence there we were buying a sales and servicing infrastructure that allowed us to expand the competitive supply business into the commercial and industrial segment.

And being able to buy these businesses at, you know, extraordinarily low multiples of EBIT was a real victory for us we feel. Because it actually helped us define an entire business segment which we think has great growth prospect next to it. So I think it will change.

You know, one of the things that we hope to be proud of looking back over five years is to say that we were very disciplined about the timing and places that we allocated our scarce capital dollars during this, you know, wildly cyclical business.

And if we can sustain the type of discipline that we've had in the last year, in directing those dollars to places that have unfair returns, we're going to be pretty proud five years from now.

But it is disciplined, you do have to have a shelf in order to raise money along the way. But we'll be patient and I think prudent. And as you can see, the organic elements of our growth model right now are just fine to sustain ourselves for several years. So that by itself allows us to be patient.

Good morning. A couple of follow-ups on the mark-to-market questions. The $110 million you estimate is mark-to-market, is this your target or are there actually identified contracts you're working on or is this market share? And 2, is it all new contracts, or is some of it contract restructuring with

We've done a small mark-to-market activity year to date. But fundamentally that's our target, based on the level of activity we experienced principally in the second half of 2002 and projecting that out forward through 2003.

The 197 million mark-to-market in '02, what's the length of the contracts?

The statistic I cited to you was somewhat -- was not a direct answer to that question but I think a reasonably good answer to a related question. I told you that the average duration on the 284 million of new gross margin was a little bit less than two years.

New gross margin we represented as the sum of mark-to-market plus the present value of new load-serving transactions which we accounted for on an accrual basis or will account for on an accrual basis based on our shift in approach to managing the load business from trading to physical in the middle of the year.

So I think probably a reasonably accurate characterization to that question is slightly under two years.

[recording gap]

[gap] earnings were down fairly significantly, what was going on there?

We have in place a revenue adjustment formula so that from year to year, the revenues remain rather constant, notwithstanding the changes in weather. Last winter we had a rather slow sales because of the warmer winter.

This winter is starting off with higher volumes. But the mechanism we have in place moderates that in the billing process. So that we have a rather constant revenue stream.

The other effect that can come into play is our market-based rate mechanism which is a profit sharing mechanism by which we're in center to make prudent purchase for our gas customers. That can fluctuate from year to year depending on our sales and capacity.

Any other questions? There we go.

Hi, I have three questions on the merchant business. First of all, what is the impact of FAS 46 bringing high desert on line, the impact on the income statements?

Four cents.

Four cents to the negative, okay. Secondly, you identified that merchant year-over-year variance is a plus 18 cents. And you identified the decline in mark-to-market which amounts to roughly 34 cents. The EITF 02-03 benefits roughly 19 cents. Can you make up the difference to get us to the 18?

What I'd do is I will guide you back to the charts from the presentation which do a thorough walk-by part of the business year over year. What page is it? Go to page 73 in the presentation.

Okay.

You build plants, contribute an additional 5 cents. You're asking about the merchant margin 18 cents though?

I'm asking specific specifically about the merchant margin 18 cents.

What you've got is overall, a negative effect of the accounting change. In essence, the EITF contracts added 19 cents, offset by lower mark-to-market of 32 cents.

You have a competitive supply business and we gave you pretty significant detail on the competitive supply business up 25 cents year over year.

Our Calvert Cliffs outage drives a favorable 5 sense year-over-year and you can see those as you describe each element of earnings you can see those gross margins and you can see the addition of productivity offsetting natural blocks of O&M expense when you look at the below the line expense.

The competitive supply is 25 cents. How much of that is locked in versus new business? Was it pretty much a 60-40 mix?

You'll go back to chart 93 in the presentation.

Uh-huh.

What you see is $182 million of existing contracts, already-booked contracts, $109 million is new business. And then there's $110 million.

Okay. And then my last question is, again, on the mark-to-market. I understand that by participating in the derivative businesses going forward, you would have a projection of profitability from beginning to closure of a derivative contract.

What I'm curious about is how you take confidence in effectively projecting a cumulative mark at the interim point of an existing derivative portfolio, at any given point in time.

Because year end '03 is just as random a point in time as the end of the first quarter, as April 11th, et cetera. So how do you take the confidence to project mark-to-market of 110 in '03 and as a follow-on to that, you ought to be able to project quarterly marks, then, and what is the first quarter mark-to-market that you've incorporated in your guidance?

The 110 million represents our expectation of the mark-to-market value of new business entered into. When we enter into such new businesses, as we have in the past, we will vary substantially hedge that new business.

So it's not going to be dependent on market -- market price fluctuations over the course of the year, or require us to predict at this point in time what the price will be a year from now. That -- that business is a function of two things. Number one -- or that expectation of 110 million are a part of a function of two things.

No. 1, our recent experience, and that's a very realistic number based on our recent historic experience, and

No. 2, just the market conditions that prevail today. Again, we have a customer base that continues to have needs for cost management products, some of which may be derivatives, and frankly, this is -- this is a rather vacant market environment right now.

There were a great many more players in this business 18 months ago than there are today. So it's certainly not a principal area of focus or driver for us to attempt to originate new mark-to-market business. But when, in association with our competitive supply approach, we see opportunities to provide the sorts of hedges to customers, at margins that are attractive to us, and under structures where we can hedge our own risk, we'll probably do it.

Based on our very recent historic experience, that $110 million feels like a reasonable, in fact probably a conservative number for us.

But it certainly is not dependent upon, back to your question, our being able to predict the market price, quarter by quarter, for the next four quarters.

And what is the first quarter mark-to-market incorporated in the guidance?

Ten to $15 million.

Thank you.

Questions for Follin. The working capital was a huge contributor for this year and you have it next year. Can you elaborate on what the sources are? .

Are you talking about 2002 or 2003?

I would like to know where it came from in 2002 and where you expect it to go.

Sure. 84 million from cash from Constellation New Energy, where returned collateral prepayments dealing with higher credit quality counterparties. 38 million was an increase in interest payable, shifted from having commercial paper balances outstanding to long term debt which has semiannual interest payments, at the working capital source, $30 million was taxes payable.

And then we had a negative 48 million partially offsetting. Accounts receivable and payable was negative, buildup in year end '02 because of cold weather. We also had 148 million of deferred taxes in 2002 as a function of primarily accelerated depreciation due to the new build plant and secondly mark-to-market earnings not realized in the current period. And lastly we had -- that was the deferred tax component and lastly we had mark-to-market earnings. The -- you were talking about 2003 as well?

Yes.

Working capital, and other, in 2003, has two components. The biggest is deferred taxes will be in the area of 115 mill source, again primarily due to accelerated depreciation on the new build plant and a little bit mark-to-market earnings not realized.

And we're accounting on 15 million from working capital management action. We are working to manage payables terms and work to manage

Well, that may mark the end of a full two hours. So we thank you all very much for coming this morning. We will all be available for the next half hour so if you are for any further questions. We appreciate your attention. Thanks very much.

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