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EEI 2004 FINANCIAL REVIEW iii

Contents2004 Financial Highlights ............................................................................ iv

Abbreviations and Acronymns ..................................................................... iv

North American Electric Reliability Council (NERC) Regions .........................v

President’s Letter ........................................................................................ 1

Industry Financial Performance ................................................................... 7

Income Statement ................................................................................ 7

Non-Recurring and Extraordinary Activity ............................................ 16

Balance Sheet .................................................................................... 20

Cash Flow Statement .......................................................................... 25

Dividends ........................................................................................... 29

Electricity Sales and Revenues ............................................................ 32

Business Strategies ................................................................................... 43

Business Segmentation ...................................................................... 43

Mergers and Acquisitions ................................................................... 46

Divestitures ........................................................................................ 54

Construction ....................................................................................... 60

Fuel Sources ...................................................................................... 68

Capital Markets ......................................................................................... 77

Stock Performance ............................................................................. 77

Bond Ratings ..................................................................................... 82

Policy Overview ......................................................................................... 89

Legislative Summary ........................................................................... 89

Joint FERC and State Regulatory Issues .............................................. 93

State Issues ........................................................................................ 96

Environmental Issues ........................................................................ 110

Power Trading Sector ........................................................................ 114

Accounting Issues ............................................................................ 117

Finance & Accounting Division ................................................................ 119

List of U.S. Shareholder-Owned Electric Utilities ....................................... 123

iv EEI 2004 FINANCIAL REVIEW

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EEI 2004 FINANCIAL REVIEW v

vi EEI 2004 FINANCIAL REVIEW

EEI 2004 FINANCIAL REVIEW 1

Financial Review 2004

We all fi nd satisfaction in accom-plishment. And the industry should feel very satisfi ed about what it accom-plished in 2004. Electric utility stocks produced a 22.8% return in 2004, beating the broader stock indices. Last year also culminated a six-year period where EEI Index investors earned a 42.1% return, outperforming both the Dow Jones Industrial Average and the Standard & Poors 500.

These results build upon the numbers the industry posted in 2003. They also demonstrate what we can accomplish, both individually, and as an industry working together through EEI. But like the long-distance runner, we must now turn this feeling of satisfaction gained from a good start into the discipline and determination we will need for the challenges—familiar and new—that lie on the road ahead.

Foremost among them is meeting the country’s ever-growing demand for elec-tricity. The U.S. Energy Information Administration predicts it will climb 50% in the next 20 years. To ensure that this power stays affordable and reliable, a new generation of ‘baseload’ plants, those that run continuously to meet the country’s minimum or base demand for power, will be needed. So too will a transmission network that is strong and fl exible enough to deliver the electricity that powers society.

Building this new infrastructure will take investment. To stimulate it will take greater certainty on a number of national energy and environmental

issues. It will also require more coop-eration among regulators at the federal and state level.

Granted, these are goals that are by any estimate ambitious, but I am confident that if we maintain our resolve, they are hills we can climb successfully.

Continued Financial Progress

The industry’s financial progress in 2004 went beyond its outstanding stock performance. By continuing to emphasize dividends, debt reduction, and a focus on core operations, the industry enjoyed a positive free cash fl ow—excess cash that is available for expansion, dividends, debt reduction, and share repurchases—for the sec-ond consecutive year. The industry’s debt-to-capitalization ratio continued to improve too: 62.2% at the end of 2002; 61.5% at the end of 2003; and 58.3% at the end of 2004. Overall net income rose in 2004 for the second straight year.

The industry also acted through EEI to continue strengthening investor con-fi dence in 2004. With assistance from the Wall Street Advisory Group, efforts here included:

■ Maintaining a dialogue with the financial community to improve fi nancial disclosure.

■ Educating state utility commis-sioners through meetings with Wall Street representatives on how regula-tion impacts investment.

■ Encouraging discussions between credit rating agencies and utility chief fi nancial offi cers.

■ Developing financial information disclosure guidelines to ease Sar-banes-Oxley compliance and reassure investors.

■ Working with chief risk offi cers to produce uniform disclosure, gover-nance, and risk metrics.

■ Creating critical issue forums for the boards of directors of EEI and AGA member companies.

Energy Legislation

Comprehensive energy legislation is vital to enhancing our electricity infrastructure, providing greater cer-tainty, and with it, improving investor confi dence. Toward this goal, we are continuing to urge Congress to adopt comprehensive, national energy legisla-tion. Congress has considered enacting energy legislation since early 2001. Now, however, there is widespread agreement that the country must act. With gasoline, natural gas, and oil prices continuing to rise, the public wants a comprehensive energy bill.

President’s Letter

2 EEI 2004 FINANCIAL REVIEW

For our industry, maintaining reli-ability remains a paramount outcome for any energy bill. The electric utility industry and the North American Elec-tric Reliability Council (NERC) already have undertaken a number of actions to address the immediate problems that led to the blackout of 2003. These steps include:

■ Adding new audit programs.

■ Creating guidelines for disclosure of reliability violations.

■ Strengthening existing reliability standards and enhancing compliance with reliability rules.

■ Improving operator training.

■ Developing vegetation management practices around power lines.

This spring, NERC adopted new reliability standards. These are an im-portant landmark for the electric power industry. They clarify existing NERC reliability standards. And they create the foundation for adopting enforceable standards.

We are now asking Congress to pass an energy bill that makes these stan-dards mandatory, and creates an electric reliability organization to enforce them, with oversight by the Federal Energy Regulatory Commission (FERC). We also hope that Congress will resolve the contentious issues that can arise over sit-ing transmission infrastructure by giv-ing limited backstop siting authority to FERC. Congress can also simplify the often arduous mission of siting trans-mission on federal lands by designating the U.S. Department of Energy (DOE) as the lead federal agency.

Maintaining reliability depends on greater investment in transmission fa-cilities too. Shareholder-owned utilities

have already begun stepping up their investment. Between 1999 and 2003, for example, the industry’s transmission investment grew 12% annually, for a total of $17 billion. Looking ahead through 2008, preliminary data indi-cate that utilities have invested, or are planning to invest, $28 billion more—a 60% increase over the previous five years. But more will be needed.

The grid today is performing two tasks. It is ensuring that the nation’s retail electricity customers enjoy reliable and affordable electricity service. And, it is enabling the country’s wholesale electricity markets to move more and more electricity between regions.

To stimulate more transmission investment, we are asking Congress to reduce the depreciable lives of electric-ity transmission assets from 20 years to 15. We also believe Congress should give FERC the authority to provide transmission investment incentives and assure cost recovery for reliability investments.

Congress can also help the industry to attract new investment capital by repealing the Public Utility Holding Company Act (PUHCA). This out-dated statute limits investment in the regulated energy industry. As a result, billions of dollars of new capital that could help the industry grow is unable to go to work.

In addition to these legislative solu-tions, EEI is advocating that FERC adopt a number of regulatory policies to boost transmission investment. These include:

■ Establishing a durable regulatory framework that assures those who are willing to invest in the grid will be able to fully recover their invest-ment, along with their cost of capital, through electricity rates.

■ Encouraging a variety of corporate structures and business models for building transmission. Many differ-ent structures and business models can co-exist in a competitive whole-sale marketplace provided there are fair rules in place for all market participants.

■ Permitting utilities to include in their rate base construction work-in-prog-ress to improve cash fl ow and rate stability.

■ Allowing alternative transmission pricing and cost recovery approaches for states with renewable energy re-source goals so that their renewable resources that lack siting fl exibility can be developed.

■ Granting accelerated depreciation in ratemaking to improve fi nancial fl exibility and promote additional transmission investment.

■ Working closely with state regulators ■ Working closely with state regulators ■

to:– Allow full recovery of all pru-

dently incurred costs to design, study, pre-certify, and permit transmission facilities, as well as amend its own rules to allow full recovery of the prudently incurred costs of transmission projects that are later abandoned.

– Ensure that the appropriate regu-latory mechanisms are in place to allow for full cost recovery and the avoidance of unrecoverable or “trapped” costs, which arise when federal and state regulatory policies diverge.

While we will remain determined to push the 109th Congress to resolve their differences on adopting comprehensive energy legislation and move forward, the industry can point to two legisla-tive victories that helped to support its economic turnaround in 2004.


The fi rst, the dividend tax credit, was adopted in 2003, and gave our industry’s investors both significant relief from federal taxes on dividends, and increased bonus depreciation from 30% to 50% through 2004. Fifty-four percent of the EEI Index companies took advantage of the new credit and increased dividend payments in 2004, the largest percentage since 1993.

EEI has launched a grassroots cam-paign to encourage electric company shareholders, retirees, and employees to make the dividends and capital gains tax cuts, which are scheduled to sunset in 2008, permanent. For more information, I encourage you to visit:www.dividendtaxfairness.org.

Another victory for the industry came through the Foreign Sales Corporation/ Extraterritorial Income Exclusion (FSC/ETI) bill, which Congress passed last October. Among the many energy-re-lated components that will benefi t the industry this year and beyond are pro-visions to encourage investment in the transmission system, reinvigorate the renewable energy sector, and provide for a phased-in tax deduction—3% rising to 9%—for electricity generation.

Environmental Outlook

Effective multi-emission legislation also would be important to improving certainty for utilities and investors alike. We were disappointed earlier this year when the Energy Committee reached an impasse on the Clear Skies Act of 2005. Nonetheless, we believe that there is genuine interest in fi nding a multi-emission blueprint that a major-ity of lawmakers can support.

Sensible, multi-emission legisla-tion—consistent with the scope and

framework of the Clear Skies initia-tive—would address the overlapping requirements that complicate further cuts in sulfur dioxide (SO

2), nitrogen

oxides (NOX) and mercury emissions

from coal plants. It would necessitate the largest single capital investment in air pollution controls in the nation’s history. But it would allow us to build upon the dramatic emission reductions we have already made in a far more cost-effective and timely manner.

With multi-emission legislation now on hold in Congress, the U.S. Envi-ronmental Protection Agency (EPA) has issued its Clean Air Interstate and Clean Air Mercury rules. The two EPA rules closely mirror the proposed multi-emission legislation, but they have some major differences. The rules will es-sentially be another layer on top of the existing regulations. They also will do nothing to eliminate the litigation that is holding up further reductions, nor reduce the state-to-state differences in implementation.

Another environmental issue that the industry is addressing is climate change. EEI will continue to support climate-related legislation to promote technology research and development, provide policy and fi nancial incentives to encourage voluntary actions, and ensure that companies receive recogni-tion or registration of past and future actions and are not penalized for taking voluntary actions.

We will also continue to support the President’s climate plan and its goal to reduce U.S. greenhouse gas intensity (i.e., the ratio of greenhouse gases to GDP) by 18% in the next decade. Last December, the Power PartnersSM, who represent nearly 90% of the share-holder-owned electric generation in the country, signed an agreement with the

DOE to voluntarily reduce the power sector’s carbon intensity (carbon dioxide produced per kilowatt-hour of electric-ity generated) by the equivalent of 3 to 5% in this decade. This reduction will be in addition to the 15% drop in car-bon intensity the industry has registered over the past 25 years.

Voluntary actions are a critical fi rst step on the climate issue and we are pur-suing them. These actions let the power industry curb emissions now—without undermining the diversity of our elec-tricity supply, or the country’s economic competitiveness. The goal of the Power PartnersSM is ambitious, but achievable. Some companies individually may be able to exceed this goal, and, as an industry, we may be able to achieve a higher goal in the future.

Strengthening Regulatory Partnerships

With the industry continuing in a hybrid model of competition and regulation, greater cooperation be-tween FERC and the states, as well as greater coordination among the states themselves, will help to increase certainty. We are encouraging these partnerships.

The relationship between FERC and the states has become increasingly important now that FERC is creating its rules to govern the country’s developing wholesale electricity markets.

Since 1996, when it issued its Order 888 requiring transmission providers to offer non-discriminatory access to transmission services through an Open Access Transmission Tariff, the Com-mission has been aggressively develop-ing a regulatory framework to mitigate the potential of any power supplier


to exert market power—the ability to profi t by raising rates above competitive levels in a given market.

The Commission is now evaluating utility applications for market-based rate authority (MBR) by looking at all potential areas for a utility to exert market power—through concentration in generation, through its control over transmission facilities, by favoring its affi liate over others, or by erecting bar-riers to market entry.

If tests to assess market power do not accurately reflect true market conditions, or they are mistakenly ap-plied, the Commission’s market power determinations hold the potential to create substantial regulatory uncer-tainty. They could set back the plans of states and regulated utilities to provide a reliable and affordable power supply to their retail customers. This issue has already come up in the past few years when vertically integrated utilities announced plans to build new power plants or acquire an existing one from a merchant plant owner.

FERC’s concern has been that these utility actions to buy or build genera-tion could give them market power, and adversely impact wholesale market development. The states, on the other hand, looking for the least-cost option for their retail customers, typically have been in favor of the utility actions and have approved them.

The industry is committed to de-veloping robust, competitive wholesale markets. We will also continue to work with both federal and state authorities to prevent the potential for the abuse of market power in the interest of ensuring fair and effi cient competitive markets.

EEI’s Board of Directors unanimous-ly supported a framework last Decem-ber to help guide the development of

the country’s wholesale power markets and at the same time reinforce genera-tion and transmission adequacy. This framework emphasized that the deter-mination of market power must be done correctly and the rules must be applied fairly. Otherwise, the market could end up with fewer competitors, and consumers could be harmed. Moreover, competitive market rules should not favor one corporate structure, business model, or retail regulatory model over another. Many different structures and business models can and do co-exist in a competitive wholesale marketplace.

The industry is also encouraging FERC and the states to work closely together on resource procurement is-sues. In late July 2004, the Commission presented its guidelines for competitive energy solicitations in both rate and as-set transfer situations. These focus on transparency, clear product defi nition, clear evaluation criteria, and indepen-dent oversight.

Harmony is needed between the Commission’s goals for competitive wholesale markets and the states’ needs for resource adequacy, an affordable power supply for their retail customers, fuel diversity, and economic develop-ment.

Some state-driven efforts are focusing on an open price discovery process that offers the potential for securing ‘like-type’ resources at the lowest possible price and that helps assure the fairness of the solicitation process. Steps to increase certainty in the procurement process reduce the risk that a util-ity procurement decision will later be determined to be imprudent. These procurement processes address new uncertainties about the optimal tim-ing of purchases and, particularly with retail access, uncertainty about the size

of loads utilities will remain obligated to serve.

Greater cooperation among states themselves will be necessary as well for a number of policy and planning is-sues. The newly forming regional state committees (RSCs)—representing the states within a regional transmission organization (RTO)—are helping to facilitate planning and transmission siting issues.

The Organization of Midwest In-dependent System Operator States (OMS), the fi rst RSC, has been proac-tive since its inception in June 2003. Its three major functions are to advise MISO, advise FERC, and be a resource to the states. Similarly, the Southwest Power Pool (SPP) RSC has been work-ing actively on two key issues: a multi-state cost-benefi t analysis and the poli-cies concerning transmission upgrade and expansion cost allocation for the SPP RTO. Finally, the New England Governors’ Conference has fi led a com-prehensive plan for the New England RSC—NE-RSC—with FERC.

We have advocated a number of principles for forming RSCs and the role they should play. Among them are that RSCs should:

■ Consider individual state needs, but act in the best interest of its region.

■ Facilitate the necessary state regula-tory approvals for parties seeking to build new transmission facilities that cross state boundaries.

■ Minimize regulatory uncertainty and assist in a timely transition to regional wholesale electricity mar-kets, but not create another level of regulation.

■ Support timely recovery of costs as-sociated with forming and operating RTOs and ISOs.


It is important to note that in gaining these functions, RSCs should not be-come an additional level of regulation. Although some RSCs seek to pre-ap-prove RTO fi lings at FERC, or even seek authority to tell RTOs what they may fi le, the law is clear that interstate bulk power market issues are a federal responsibility and that state commis-sions should cooperate extensively in the development of regional markets, but cannot usurp the transmission own-ers’ authority to fi le their rates without prior review.

As we were in 2004, EEI will also continue to be very active in the states, the forum where most electric utilities earn roughly 80% of their earnings. Improving regulatory certainty here is particularly important. This is vital to encourage the infrastructure invest-ments necessary to provide safe, reli-able, and reasonably priced energy to consumers.

In particular, we are working to en-sure that state commissions:

■ Recognize the new role of risk man-agement in ratemaking.

■ Consider new approaches for pro-vider of last resort service that ensure full cost recovery.

■ Adopt new tools for determining cost of capital that refl ect this era of new risks for industry.

■ Recognize the relationship of return-on-equity to needed infrastructure investment.

■ Adopt new approaches to utility resource procurement to avoid af-ter-the fact prudence reviews and support full cost recovery.

■ Implement new rate designs to refl ect changing wholesale markets and unbundled utility structures.

■ Work with their state governors to support the Low Income Home Energy Assistance Program (LI-HEAP).

The industry produced remarkable value for its shareholders in 2004. Im-portantly, the results also signify a strong trend. Now, like that long-distance run-ner, we must keep up the pace. Given the determination and resolve we have already shown, however, I’m confi dent that we will reach the winner’s circle.

Tom KuhnPresidentEdison Electric Institute


INDUSTRY FINANCIAL PERFORMANCE

Industry Financial Performance

Income Statement

Summary

The industry showed continued progress during 2004 on its path to financial recovery as net income surged $10.5 billion to $26.1 billion, an increase of 67.2% from the $15.6 billion of 2003. This two-year stretch, highlighted by a refocusing on core businesses, returns the industry to the range of $15 to $20+ billion in annual net income that has characterized the past ten years. The single exception was the rare net loss in 2002 caused by a record high $24.9 billion in non-recur-ring charges. Although 2004 operating income rose by a healthy $2.4 billion, or 4.3%, the drastic leap in net income is primarily due to a positive $11.3 bil-lion change in non-recurring income between the two years.

Net Income Improves

Most companies produced higher net income in 2004, the result of improved operating income and reduced non-re-curring charges. Although the industry’s consolidated fi nancials are greatly infl u-enced by the larger companies, the fact that 44 of 72 companies (or 61.1% of the industry) grew earnings, provides further evidence of the widespread turn-

around. The following four summary line items, three of which are non-recur-ring in nature, impacted earnings the most: a $2.4 billion increase in operat-ing income, a $6.0 billion increase in non-recurring revenue, a $3.6 billion decrease in asset write-downs, and a $2.0 billion reduction (net of tax) in total extraordinary items. The industry also paid $4.3 billion more in income taxes in 2004.

Core Operations Show Gains

Energy operating revenues rose $18.7 billion, or 5.6%, to $353 billion in 2004

from $335 billion in 2003. Over the last two years, revenues have climbed $48.3 billion, or 15.8%, from the $305 billion level of 2002. High natural gas prices continued to produce rising revenues in the form of higher electricity rates for wholesale users and gas-generated electricity users (see chart on page 8), re-sulting from the pass-through of higher fuel costs through fuel-adjustment clauses in many regulated markets and because natural gas-fi red plants were the price-setting generators in many competitive markets.

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A 0.3% increase in electricity de-mand, coupled with an overall increase in electricity prices (see chart on page 8), created an $8.7 billion upswing in electricity revenues in 2004, or nearly one-half of the industry’s total revenue increase. The residential customer group produced $5.0 billion of the increase, followed by commercial cus-tomers at $2.5 billion and industrial customers at $1.2 billion. Although the total number of customers served, and of kilowatthours sold, grew by the modest amounts of 1.6% and 0.3%, respectively, in 2004, this marks a turnaround for the industry from the declines in these metrics during the 2000-2003 period due to retail com-petition in certain states and an overall economic downturn (see Electricity, Sales, and Revenues section).

Total operating expenses grew in lock-step with operating revenues on a percentage basis, rising 5.7%, or $16.2 billion, in 2004. This translated into a $2.4 billion, or 4.7%, increase in operating income for an industry that remains mostly regulated. Of the 72 companies included in the industry’s consolidated fi nancial statements, 45 companies, or 62.5% of the industry, increased operating income in 2004, and 44 companies or 61.1% improved their net income.

The operating margin data presented in the table to the right is organized into the following three categories:

i. “Regulated” (regulated assets > 80% of total assets),

ii. “Mostly Regulated” (regulated assets = 50% to 80% of total assets), and

iii. “Diversifi ed” (regulated assets < 50% of total assets).

As expected, the Regulated group of companies experienced the lowest per-cent change in operating income, with an overall 0.5% decrease, as 23 of 34 companies changed by 10% or less from 2003. Operating income for the Mostly Regulated group showed the greatest increase, rising 24.1%. This may be ex-plained in part by an overall refocus on regulated operations, as this transition continued during 2004. December 31, 2003 business segmentation data was used to categorize the companies.

Operating Margins

The industry’s operating margins are shown on pages 10-11. The average operating margin for each category is the unweighted average of the operating margin percentages shown, thus giving an equal weight to each company. The 2004 distribution of results between the three groups was similar to that of 2003, with the Regulated group of companies producing the highest oper-ating margin, at 15.8%, followed by the

Mostly Regulated group at 13.5%, and the Diversifi ed group at 12.7%.

Standard operating margin analysis can be somewhat misleading when ap-plied to the electric utility sector due to automatic adjustment clauses for electric generation fuel costs, purchased power and natural gas purchased for re-sale. These are usually referred to as fuel adjustment clauses (the most common term) in the case of electric distribution, and purchase gas adjustments (PGA) for natural gas distribution. Rising fuel and gas costs generally fl ow through to the end customer through these fuel adjustment and PGA clauses, increas-ing revenues and expenses by the same amount. When this happens (all other expenses being equal), revenue will rise but operating income will remain fl at, therefore operating margins will decline.

Most states that have not adopted electricity deregulation have fuel ad-justment clauses in place, although a handful do not, and some states that

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have adopted deregulation have done away with fuel adjustment clauses, although most have either retained or reinstated them in their newly competi-tive model. Where these clauses do not exist, utility earnings are impacted by swings in fuel input prices, prompt-ing companies to hedge as a means of reducing risk. A common practice of gas delivery companies is to stockpile natural gas during the summer months when prices are typically lower, and pass the savings to customers in the winter months. This supports overall usage levels, the fundamental component of operating income.

Consistent Core Operations

The industry’s aggregate earnings before non-recurring and extraordinary items barely changed in 2004, falling

slightly to $23.2 billion from $23.9 bil-lion in 2003. This metric has remained fairly consistent over the past four years while the industry’s net income has fl uctuated wildly. The exclusion of non-recurring items provides a more accurate picture of the industry’s core generation and energy distribution operations, especially for an industry that has gone from one extreme of “expansion through diversifi cation” to the other of “contraction by a refocus on core businesses” in a relatively short period of time. The relatively fl at movement of this trend line reveals the regulated underpinnings of the industry.

Non-Recurring Revenues Surge in 2004

Non-recurring revenue provided the biggest contribution to the overall in-

crease in net income in 2004, increasing $5.1 billion over the prior year. Almost all of this increase, $4.9 billion, relates to Pacifi c Gas & Electric’s emergence from Chapter 11 of the bankruptcy code (discussed later in this section). Gains on sales of assets rose by $893 million, from $572 million in 2003 to $1.5 billion in 2004. For the second straight year, this activity was wide-spread with 32 of the 72 electric com-panies selling assets for gains in 2004, up from 28 companies in 2003.

Interest Expense

Interest expense fell by $909 million or 3.9% in 2004. Low interest rates, debt retirements and debt refi nancings allowed two-thirds of the industry’s companies to reduce interest expense. The industry reduced total debt by an aggregate $21.0 billion (or 6.0%) to $328.7 billion at year-end, from $349.7 billion at year-end 2003. Several com-panies ran up large debt totals as they diversifi ed from the mid-1990s through 2001. Additionally, a continued low interest rate environment allowed some highly leveraged companies to refi nance and avoid a signifi cant hike in interest expense.

Asset Write-Downs Decline

Although the industry wrote down a sizeable $3.0 billion worth of assets in 2004, this is less than half of the $6.6 billion of write-downs in 2003, and below the $4.9 billion recorded in 2002. The collective $14.5 billion of write-downs (also called impairment charges) over this three-year period was primarily assigned to distressed genera-tion plants that operate in competitive markets. The write-down of these assets, which were largely constructed with debt fi nancing, refl ects the industry’s overbuild of competitive generation in certain regions.

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Minimal Extraordinary Items

Extraordinary items totaled ($184 million) in 2004, well below the ($2.2 billion) of 2003. The industry wound down its clean up (sell-off ) of under-performing non-core businesses in 2003, with $2.7 billion of discontinued operations charges. These included the sale of merchant generation projects, telecommunications subsidiaries and international investments. A record high $16.6 billion of discontinued op-erations charges were recorded in 2002, the initial year of the industry’s “back-to-basics” or “core-refocus” strategy.

EPS: Stock Offerings vs. Buybacks

Earnings per share (EPS) surged from $1.45 in 2003 to $2.34 in 2004, a 61.4% increase and a vast improvement from ($0.04) only two years ago. Al-though total income before non-recur-ring and extraordinary items declined by 3.2% in 2004, the decrease on a per-share basis was more pronounced,

shrinking 5.5% to $2.08 from $2.20. For the second straight year, common stock offerings were a popular means of raising capital and strengthening debt-to-capitalization ratios. The in-dustry issued $10.7 billion of common equity in 2004, slightly higher than the healthy $10.0 billion of 2003. From the perspective of the industry as a whole, the stock offerings by some companies were offset by $6.5 billion of common share repurchases by others. This unusu-ally high amount, far above the $120 million of repurchases in 2003, resulted from improved cash fl ows and the de-sire, in the case of some companies, to return cash to shareholders following painful corporate restructurings after the failed diversifi cation moves of the late 1990s.

Largest Company Gains

PG&E Corp.’s $4.1 billion increase in net income was by far the industry’s largest. In 2004, the company recorded

a $4.9 billion gain for its settlement reached with the California PUC re-garding the emergence of Pacifi c Gas & Electric, its operating utility, from Chapter 11 bankruptcy. Since the Cali-fornia energy crisis of 2000 and 2001, PG&E has had a number of extremely large non-recurring items, both gains and losses.

Duke Energy achieved the second largest improvement in net income, recording earnings of $1.5 billion in 2004 following a net loss of $1.3 bil-lion in 2003. Although Duke produced improved 2004 revenues in its three primary businesses (non-regulated gas & electric, regulated electric and regulated gas), the $2.8 billion swing on a year-to-year basis was mostly due to an impairment charge of $3.0 bil-lion in 2003. This diversifi ed energy company was the industry’s top revenue producer in 2004, and ranked third in market capitalization as of December 31, 2004.

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American Electric Power (AEP), the nation’s largest electricity generator and one of the largest electric utilities, with more than fi ve million customers covering its 11-state territory, improved net income by $979 million in 2004 due to a variety of factors. AEP’s $605 million discontinued operations charge in 2003 for its United Kingdom operations, and improved margins in both its electric utility and gas operations, contributed to the difference.

Exelon Corp.’s net income growth of $959 million in 2004 was closely tied to its core electric operations. As the nation’s leading producer of nuclear-generated power, Exelon’s profi t margins ben-efi ted in 2004 from high natural gas prices (natural gas generators are the marginal producers and price setters in many electricity markets around the country). This created sizeable profi ts for Exelon’s nuclear fl eet, whose production costs are considerably below those of gas-fi red generators.

Return of Rate Cases

The past three years were marked by an exit from non-core businesses, as companies regained their fi nancial footing by focus-ing on core competencies. This movement has brought regulatory relationships, and more specifi cally rate cases, back to the forefront of importance. At the heart of each rate case is the negotiation of an allowed return on equity (ROE). Average ROEs have declined each year since 2000, with an overall downward trend that dates back to the early 1990s. The primary reason has been the significant



decline in interest rates since the early 1990s, a key input into the determina-tion of regulated rates of return for this capital intensive industry. According to data from Regulatory Research As-sociates (RRA), the industry’s average ROE fell from 10.97% in 2003 to 10.73% in 2004. The average ROEs for electric utilities is presented in the table on page 13, based on an average of all cases decided in each year. Gas utilities show similar results, with average ROEs of 10.99% and 10.59% in 2003 and 2004 respectively.

There were 19 electric utility rate cases in 2004 compared to 22 in 2003. These numbers are down from the totals of the 1980s and early 1990s. RRA cites the following reasons for the decrease: industry restructur-ing/intensifying competition; more efficient utility operations; techno-logical improvements; relatively low infl ation and interest rates; accelerated depreciation/amortization programs; the increased utilization of settlements that do not specify return parameters; and the growing use of performance or price-based regulation.

Wholesale Market Development

Perhaps the biggest ongoing devel-opment for the industry is increased participation in Regional Transmission Organizations (RTOs) and Indepen-dent System Operators (ISOs) and the organized wholesale markets operated by these entities. Competitive wholesale markets are under way in fi ve RTO or ISO regions: PJM Interconnection, New England ISO, New York ISO, California ISO and Midwest ISO, with PJM considered to have the most fully functioning formal market. Overall RTO participation grew in 2004, particularly in the PJM Intercon-nection and Midwest ISO. Notably,

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American Electric Power and Dominion Resources joined the PJM Interconnec-tion in 2004. Even though a signifi cant percentage of generation, and therefore revenues, can be traced to the regulated utilities of these companies, a growing portion is being sold into these whole-sale power markets.

Summary

Although the industry’s net income rose by more than two-thirds, to $26.1 billion in 2004, income before non-recurring and extraordinary items remained steady for the fourth straight year. On an individual company basis, 2004 was a better year for over 60% of the industry in terms of earnings, with the largest increases tied to non-recurring activity. Higher electricity demand and electricity prices were the main contributors to the overall 4.7% increase in operating income. A primary concern going forward is the trend of declining ROEs, which have fallen (on average) in each of the past four years.

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This is especially concerning as capital expenditures are expected to increase to cover pollution control equipment and transmission and distribution spend-ing, all against the backdrop of what would appear to be an inevitable rise in interest rates.

Non-Recurring and Extraordinary Activity

The industry’s $2.9 billion net profi t from non-recurring and extraordinary activity in 2004 was a strong $11.2 bil-lion reversal of the $8.3 billion net loss of 2003 and a dramatic improvement over the industry’s record $24.9 billion net loss in 2002. This result provided further evidence of the industry’s suc-cessful transition to a core strengths focus and the near completion of the clean up of impaired merchant gen-eration assets and exit from non-core businesses that characterized 2002 and 2003. The 2004 fi gure also represented

the fi rst positive result for this metric since the start of the deregulation era in the mid-1990s.

The table “Aggregate Non-Recurring and Extraordinary Items 1999-2004” on page 17 presents the net total fi g-ure for the industry for each of the categories shown. In other words, the total fi gure shown is a composite of in-dividual company totals, both negative and positive, for each category. Many of the components of the $2.9 billion gain provide further evidence of the industry’s recovery.

■ The industry’s net gain on sale of assets rose to $1.46 billion in 2004 from $572 million in 2003.

■ Other non-recurring revenue jumped to $5.42 billion in 2004 from a $357 million in 2003. The majority of the 2004 fi gure resulted from a $4.9 billion gain recognized by the California utility PG&E due to its emergence from the Chapter 11 bankruptcy caused by the crisis in California’s electricity markets in 2001 and 2002.

■ Asset write-downs (also called im-pairment charges) fell to $2.99 billion in 2004 from $6.58 billion in 2003, a $3.6 billion year-to-year improvement.

■ The impact of discontinued opera-tions on the industry’s income was modestly positive in 2004, at $972 million. This represented a $3.7 billion turnaround from the $2.7 billion loss in 2003 and a dramatic reversal from the $16.6 billion loss from discontinued operations that the industry recognized in 2002.

■ As shown in the table “Gains (Losses) from the Sale of Assets” (page 18from the Sale of Assets” (page 18from the Sale of Assets” ( ), 26 page 18), 26 page 18companies sold assets for a total gain of $1.7 billion in 2004 compared with the 23 companies that sold as-



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sets for a total gain of $774 million in 2003. The nearly $1 billion im-provement likely refl ects write-downs taken in previous years combined with 2004’s strong fi nancial market environment, with bouyant valua-tions across most asset classes and a robust market for well-situated generation assets.

■ Total losses on asset sales were about fl at year-to-year. In 2004, six com-panies recognized a total of $242 million in losses on asset sales com-pared with the fi ve companies that recogized $202 million in losses in 2003.

The table “Individual Non-Recur-ring and Extraordinary Items” (page 19ring and Extraordinary Items” (page 19ring and Extraordinary Items” ( ) page 19) page 19presents the same underlying individual company data, but in a different way. Here, all individual non-recurring and extraordinary items across all categories (for the U.S. shareholder-owned electric utilities) that contributed positively to net income are totalled to produce the Gains total. All non-recurring and extraordinary items that represented charges against income are added to produce the Losses total.

By these measures, 2004 produced the strongest total gain, at $10.6 bil-lion, of any year since 2000. Even removing PG&E’s $4.9 billion gain from the total leaves $5.7 billion in

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gains, which would remain the strongest result since 2000. The $7.61 billion in losses recognized in 2004 was also an improvement over the $11.61 bil-lion in losses recognized in 2003, and sharply below the record $26.59 billion in losses that characterized 2002, the initial year of the industry’s return to core-strengths focus and its peak year for taking charges related to the exit from non-core businesses and other moves necessary to place the industry back on sound fi nancial footing.

Top 2004 Activity by Company

The table “Top Net Non-Recurring and Extraordinary Gains (Losses) 2004”

presents the top activity in 2004 ranked in terms of its impact at the individual company level, measured by the net total of gains and losses.

Clearly, the dominant single event in 2004 was PG&E’s emergence from Chapter 11 bankruptcy early in the year. On March 31, 2004, the com-pany recorded approximately a $4.9 billion non-recurring gain as a result of its settlement agreement with the California Public Utility Commis-sion (CPUC) to repair the damage to the company infl icted by the crisis in California’s electricity markets earlier this decade. Electricity rates to rate-payers were frozen in California begin-



ning in 1998 as a result of the state’s restructuring legislation, but wholesale rates paid by utilities for electricity for resale were not capped. During 2001 and 2002, wholesale rates skyrocketed due to strong summer demand and a faulty market structure that prevented price signals from being passed on to ratepayers. Utilities were unable to re-cover these rising costs in rates, and the resulting crisis forced several California utilities into bankruptcy. PG&E also recognized a $684 million non-cash

gain resulting from the emergence from Chapter 11 of the company’s former electricity generation and natural gas transport subsidiary, National Energy and Gas Transmission (NEGT), and the attendant cancellation of PG&E’s equity ownership in the entity. As of the close of 2004, PG&E has fully re-covered from the California crisis. The company now has an investment grade credit rating and is focused on its core utility business.

TECO’s $1.02 billion in non-recur-ring and extraordinary losses resulted primarily from $870.5 million of asset write-downs and $147.5 million in dis-continued operations charges resulting from its continued exit of the merchant power sector. The company expects to transfer ownership of its two largest re-maining merchant holdings, the Union and Gila River power stations, to the lenders by mid-2005. TECO is now focused principally on its core regulated Florida utilities, Tampa Electric and Peoples Gas Systems, along with its three profi table unregulated businesses, TECO Coal, TECO Transport, and its Guatemalan electricity operations.

CenterPoint Energy recorded a $977 million charge based on its analysis of the Texas Utility Commission’s delib-erations in the 2004 true-up proceed-ing, which reconciles excess earnings retained by utilities with their stranded costs, as defi ned under the state’s re-structuring legislation implemented in 1999. CenterPoint also recognized an after-tax loss of $133 million resulting from its interest in Texas Genco, which it divested in 2004.

TXU recorded a variety of charges and credits related to the complex restructuring the company undertook during 2004 in order to focus on its core electric operations in the ERCOT market.

NorthWestern emerged from bank-ruptcy in 2004 and recorded a $558.1 million gain from the cancellation of indebtedness through fresh-start reporting.

AEP’s $538 million in gains resulted primarily from asset sales undertaken to pay down debt and focus on its core electric operations in its regional footprint.

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Allegheny’s $444.3 million in losses related to its decision in the third quarter of 2004 to sell several non-core assets, which it then classifi ed as discontinued operations, including its merchant gas-fi red Lincoln generating facility, two other gas-fired peaking units in the midwest, and its West Virginia gas distribution assets. The moves were part of the company’s focus on reducing debt and returning its core generation and delivery operations to profi tability.

Edison International’s activity was a combination of $690 million of gains from discontinued operations (related to the sale of its international portfolio of power plants) and a $989 million write-down of impaired plant assets associated with the restructuring of domestic competitive power supply operations.

Balance Sheet

Summary

The industry’s balance sheet strength-ened noticeably in 2004, adding to the recovery that began in 2003 from the industry’s highly leveraged state at the close of 2002, the peak year for industry leverage. That year’s record high $24.9 billion in non-recurring and extraordi-nary charges represented the turning away from growth into competitive gen-eration and other non-core businesses that typifi ed many company strategies beginning with industry deregulation in the mid-1990s and the beginning of the back-to-basics approach (or more properly “core-strengths focus”) that has defi ned the industry since the start of 2003. While talk of implementing conservative spending measures and paring down debt heated up in 2002, it was not until 2003 that progress be-

came evident in the form of a stronger industry-wide balance sheet.

As was the case in 2003, the indus-try’s strengthened fi nancial profi le in 2004 was supported by another year of historically low interest rates, narrow corporate credit spreads, strong perfor-mance by utility stocks, accommodating financial markets that provided low cost capital to sellers of both debt and equity and that facilitated asset sales, and a second straight year of positive net income and positive free cash fl ow for the industry.

■ The industry’s capitalization struc-ture improved sharply in 2004. Long-term debt as a percent of total capitalization (debt-to-cap ratio) fell 3.3 percentage points (330 basis points), from 61.5% at December 31, 2003 to 58.2% at December 31, 2004. At year-end 2004, long-term debt as a percent of total capitaliza-tion stood a full four percentage points (400 basis points) below the 62.2% reading at year-end 2002.

■ Common equi ty in-creased to $219.6 billion, a $14.2 billion gain from the $205.4 billion at De-cember 31, 2003. The gain was driven by the industry’s $26.1 billion in net income combined with $10.7 billion in equity is-suance. This was offset by $6.5 billion of common share repurchases, primar-ily represented by TXU’s aggressive stock buyback program, and the net effect of the asset sales and con-tinued exit from non-core businesses that occurred during the year.

■ Total long-term debt—including current and non-current amounts, and after elimination of securitzation totals—declined by $22.6 billion to $309.0 billion at year-end 2004 from $331.5 billion at year-end 2003.

■ The industry’s total capitalization shrank by a modest $8.5 billion during 2004, from $539.5 billion to $531.0 billion, producing a slightly leaner industry overall by year-end.

Assets

Total gross property and equipment (P&E) grew for a fifth consecutive year, although the 3.5% growth in 2004 over 2003 marked a slowdown when compared with the 6.9% and 7.0% growth rates of 2003 and 2002, respectively. This metric showed steady growth across the industry in 2004, with only seven of the 72 companies in the EEI Index posting a decline in P&E. Transmission and distribution upgrades and the addition of regulated

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capacity accounted for the bulk of the overall gain.

The wind-down on the industry’s merchant generation build-out was evident in a second straight year of de-cline in construction work in progress (CWIP), which fell by $1.7 billion, or 7.0%, from $24.5 billion at year-end 2003 to $22.8 billion at year-end 2004. CWIP also decreased during 2003, by $8.5 billion or 26.6%, representing the fi rst decline since 1996. Prior to a mod-est 3.1% increase in 2002, CWIP had jumped by an average 31.0% from 1998 through 2001 during the height of the competitive generation build-out.

The industry’s divestitures, write-downs and exit of non-core businesses are evident in the aggregate $23.7 bil-lion decline in total investments and other assets from year-end 2003 to year-end 2004.

Total industry assets fell by $7.8 billion, or just under 1.0%, to $911.6

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billion at year-end 2004 from $919.5 billion at year-end 2003. Out of the 72 U.S. shareholder-owned electric utilities, 30 posted a decline in total assets compared with the remaining 42 who showed a gain. The table “Get-ting Leaner: Asset Reduction in 2004” shows the top ten contributors to the decline in total industry assets. As expected, these were companies who executed ag-gressive divestiture programs in 2004 in order to focus on core operations (see Divestiture section).

Liabilities and Equity

In 2003, for the third con-secutive year, the industry paid down short-term debt and increased long-term debt, supported by an accommodat-ing bond market and corporate borrowing costs that were at the lowest levels since the early

1960s. While the fi nancial markets in 2004 presented a repeat of the favorable environment of 2003, both industry debt trends were reversed in 2004.

The industry’s 2004 year-end short-term debt balance rose by a marginal $518 mil-lion to $11.5 billion, a total that remains far below the $60 billion level at year-end 2000, and one that preserves the strong progress made since then. The industry’s short-term debt load had grown dramatically during the 1997–2000 period to help fi nance the merchant generation build-out, merg-er and acquisition activity and expansion into diverse businesses.

Long-term debt, including both the current and non-current portions, fell by $20.9 billion to $328.7 billion at year-end 2004 from $349.7 billion at year-end 2003. (Unlike the capital-ization structure table, the industry’s



consolidated balance sheet includes securitization totals in the long-term debt fi gures). Long-term debt reduction was widespread across the industry, with 50 of the 72 U.S. shareholder-owned electric utilities reducing total long-term

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debt at year-end 2004 compared with the level at year-end 2003.

The industry’s total common equity rose $14.2 billion, or 6.9%, during 2004, to $219.6 billion at year-end, up from $205.4 billion at year-end 2003.

The gain was driven by the industry’s $26.1 billion of net income combined with $10.7 billion in equity issuance. This was offset by $6.5 billion of common share repurchases, primarily represented by TXU’s aggressive stock buyback program, and the net effect of



the industry’s asset sales and continued exit from non-core businesses. TXU achieved a radical restructuring dur-ing 2004 that resulted in the sale of its gas, telecom and international assets, a trimming of its capital structure, and a return of the company to its roots as a Texas utility. During 2004, TXU bought back $4.7 billion in stock, ac-counting for 72% of the industry’s $6.5 billion total. Nine other companies bought back stock in 2004. Wisconsin Energy’s $152.7 million of share repur-chases and PG&E’s $378 million were the industry’s two largest programs, after TXU’s.

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Capitalization by Segment

Capitalization Structure

The table “Capitalization Structure by Segment” (page Structure by Segment” (page Structure by Segment” (24) divides the industry into 24) divides the industry into 24three segments based on the level of regulated assets as a percent of total assets reported by each company at year-end 2003. A list of companies in each category is presented in the Income Statement section. The three categories are defi ned as follows:

Regulated - 80% to 100% of total reported assets are regulated. There are 34 com-panies in this group. Some of the larger names, in terms of total assets, are Ameren, Con-solidated Edison, FirstEnergy, MidAmerican Energy, PG&E and Xcel Energy.

Mostly Regulated - 50% to 80% of total reported assets are regulated. There are 27 companies in this group. Some of the larger names here, also in terms of total assets, are Ameri-can Electric Power Company, Dominion Resources, DTE Energy, Edison International

and Exelon.

Diversifi ed - less than 50% of total reported assets are regulated. There are 11 companies in this group, which includes Constellation Energy Group, Duke Energy, PPL, Public Service En-terprise Group and TXU.

■ The Mostly Regulated group ac-counts for the largest share of the industry’s $531.0 billion capitaliza-tion, at $231.7 billion or 43.6% of the total. Next is the Regulated group at $200.9 billion or 37.8%, followed by the Diversifi ed group at $98.4 billion or 18.5%.

■ All three segments reduced long-term debt, boosted equity and delevered their capitalization structure in 2004.

■ The Regulated group overtook the Mostly Regulated group as the least leveraged in 2004, although the aggregate numbers here were quite close to those of the Mostly Regu-lated Group. The Diversifi ed group remained the most levered, due in part to the ongoing restructurings there as well as the impact of TXU’s leveraged capital structure on this relatively small group of companies. TXU reduced its common equity by more than $5 billion in 2004, while long-term debt held steady at roughly $12.3 billion, and the company ended the year with a debt-to-cap ratio in excess of 80%.

■ Each segment shares the characteris-tic of a very wide range of debt-to-cap ratios among its members. While the fi gures are not presented in the table, the Regulated group consists of names such as Northeast Utilities and New England Power, whose debt is under 40% of total capital, as well as names such as TECO and DPL whose debt exceeds 70% of total capital. The Mostly Regulated group includes companies such as CenterPoint, Allegheny and CMS, whose debt exceeds 70% of total capital, as well as companies such as CH Energy, Exelon and Otter Tail, where debt is less than 40% of total capital. In the Diversifi ed Group, Allete’s sub-40% debt-to-cap ratio is offset by TXU’s levered balance sheet.

The data clearly shows that the industry as a whole, as well as all three segments (when the component com-panies are aggregated), is moving in the direction of reduced debt and reduced



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leverage. However, across the industry as a whole, and across each sector, com-panies are applying a very wide range of strategies to the management of capital structures. Back-to-basics is a phrase best restricted to the business strategies put in place by utilities to renew their focus on electricity generation, trans-mission, distribution and, in a number of cases, natural gas transmission and delivery. The fi nance side of the business is a different matter. Corporate fi nance theory, the structure of the fi nancial markets, types of investing institutions, available risk management tools, the de-mands of shareholders, and approaches to capital structure management have all evolved radically since the end of the regulated utility era. In that light, it is perhaps not surprising to see such a wide range of balance sheet strategies in place not only across the industry, but also within the three industry segments presented here.

Debt-to-Cap Ratio by Segment

The table “Debt-to-Cap Ratio by Segment: 2004 vs. 2003” (page 24Segment: 2004 vs. 2003” (page 24Segment: 2004 vs. 2003” ( ) page 24) page 24presents another view of the industry’s collective drive to reduce debt. The table shows the number of companies in each segment that ended 2004 with a lower debt-to-cap ratio, a higher debt-to-cap ratio or no change in the ratio, compared with year-end 2003. Fifty-three of the 72 U.S. shareholder-owned electric utilities, or about three-quarters of the industry, fi nished 2004 with a lower debt-to-cap ratio. Interestingly, the result was nearly identical across all three segments.

The industry is likely to face a num-ber of challenges, beginning in 2005, in its effort to preserve the gains made in 2003 and 2004. Capital spending was held to a minimum in 2003 and 2004 in order to free up cash to pay down

debt and, in some cases, to return cash to shareholders in the form of strength-ened dividends and share repurchases. Going forward, however, the demands placed on capital budgets to fund re-quired environmental capex, upgrades to the overburdened transmission grid, as well the next round of baseload ca-pacity now on the drawing board, will present new challenges to an industry eager to maintain a healthy fi nancial foundation. In this environment, up-coming rate cases and the willingness of regulators to allow capital spending to be captured in rate base are emerging key trends that will impact the industry’s fi nancial strength through the latter half of the decade.

Cash Flow Statement

The industry produced a posi-tive $4.0 billion in free cash fl ow in 2004, a 14.2% gain over the positive $3.5 billion of 2003. This key metric has improved for four straight years, achieving a positive reading in the last two, providing strong evidence of the industry’s recovery from the challenges of 2001 and 2002. The gain in free cash fl ow in 2004 was driven by improved cash fl ow from operations and a second straight year of relatively low capital expenditures.

Net cash provided by operating activities increased in 2004 by a steady $1.9 billion, or 3.3%, which was sup-ported by a $10.3 billion rise in the

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industry’s net income. The industry used a net $14.7 billion less for invest-ing activities in 2004, led by a $13.0 billion increase in net asset sales. Net cash used in fi nancing activities doubled to $35.5 billion, mostly due to a $23.8 billion reduction in long-term debt and a historically high $6.5 billion spent on common share repurchases.

Steady Gain in Operating Cash Flow

Net cash provided by operating ac-tivities rose $1.9 billion to $58.1 billion in 2004, a low but stable 3.3% growth over 2003’s $56.2 billion. Although net income over the last three years has been impacted by wild swings in non-recurring and extraordinary items, net cash provided by operating activities has remained steady for this mostly regulated industry. On an individual company basis, 44 of the industry’s 72 companies, or 61.1%, improved this metric in 2004.

Exelon led the industry in dollar terms, with a $1.0 billion increase

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in operating cash fl ow. As the nation’s leading producer of nuclear-gen-erated power, Exelon’s core operations bene-fi ted from high natural gas prices (natural gas generators are the mar-ginal producers and price setters in many elec-tricity markets around the country). This cre-ated sizeable profi ts for Exelon’s nuclear fleet, whose production costs are considerably below those of gas-fired gen-erators.

The nation’s second largest nuclear genera-

tor, Entergy Corp., recorded a $923 million increase in operating cash fl ow, the second highest in the industry. Entergy’s operational success has been recognized in its stock price, which produced a 210% return over the fi ve years ended December 31, 2004, the highest among the industry’s large-cap companies. Entergy’s success was founded on the dives-titure of over $5 billion in underperforming assets and a $3 billion investment in its core businesses—regulated utility operations and com-petitive nuclear generation. Entergy delivers electricity to customers in Arkansas, Louisiana, Mississippi, and Texas.

The industry used $25.6 billion in cash for investing activities in 2004, down $14.7 billion, or 36.4%, from the $40.3 billion of 2003. Capital expenditures were nearly unchanged at

$41.0 billion, only 1.4% above the $40.4 billion level of 2003. This is well below the $47.2 billion, $56.8 billion and $48.5 billion of capital expenditures in 2000, 2001, and 2002 respectively, a period when the industry expanded its competitive generation fl eet and boosted related transmission investment to connect to the grid.

Although asset purchases rose by $22 billion, this was more than offset by a $35 billion, or 59.7%, increase in cash generated from asset sales. These asset sales represented the industry’s exit from non-core operations, largely competitive generation. Many of these assets were placed for sale prior to 2004, with rising prices leading to sales completions in 2004. While some of these assets stayed within the industry, the net positive contribution to the industry’s cash fl ow was due to purchases by outsiders such as hedge funds and private equity investors (see Divestiture section).

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Industry Lowers Long-Term Debt

For the second straight year, the industry used a signifi cant amount of cash to strengthen balance sheets and improve debt-to-capitalization ratios. Net cash used in fi nancing activities more than doubled, from $17.4 billion in 2003 to $35.5 billion in 2004. By contrast, fi nancing activities provided a positive $2.5 billion in cash in 2002, a year in which many companies were not yet able to implement debt reduc-tion programs.

The industry shifted its focus to long-term debt reduction in 2004 following a substantial $18.7 billion reduction in short-term debt in 2003. Long-term debt fell by $23.8 billion in 2004, as many companies followed through on debt reduction strategies that were well received by investors and ratings agencies. The industry’s competitive generation build-out was fi nanced primarily with debt.

Although to a lesser extent than debt reduc-tion, equity offerings were also used to improve capitalization structures last year. The industry received $10.7 billion from common stock of-ferings in 2004, a 7.1% increase from the $10.0 billion in 2003. An un-usually high $13.1 bil-lion of stock was issued in 2002, the fi rst year of the industry’s comeback and the beginning of a three-year stretch of improving debt-to-cap ratios.

The industry’s debt-to-cap ratio fell from 62.2% at the year-end

2002 to 61.5% at year-end 2003 and to 58.2% at year-end 2004. The momen-tum, however, was somewhat offset by the unusually high $6.5 billion of com-

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mon share repurchases in 2004. Although a better debt-to-cap ratio was the main objective for many companies, some saw an opportunity to return available cash to shareholders through share buybacks. The latter op-tion was all the more attractive for companies that have suc-cessfully restructured from the failed diversifi cation strategies of the late 1990s.

Operating Cash Flow by Segment

The table titled “Net Cash Provided by Operating Ac-tivities” presents a breakdown of the percent change in this

metric by company category from 2003 to 2004. The industry is divided into three business segmentation categories:



� Regulated (regulated assets = 80% to 100% of total assets), Mostly Regulated (regulated assets = 50% to 80% of total assets), and Diversifi ed (regulated assets < 50% of total assets). Surprisingly, the Diversifi ed group experienced the least volatility, with a standard deviation of 49.5%.

Although industry operations overall remain predominantly regulated, the operating cash fl ow results suggest that a signifi cant amount of volatility remains. Fifty-two of 72 companies, 72.2% of the industry, experienced a double-digit percentage change in 2004, only slightly lower than the 74.0% result of 2003. On the other hand, there is some evidence that the industry is regain-ing its fi nancial stability following the turbulent stretch that began in 2001, as only 11 companies saw a change in excess of 50% in 2004, down from 17 companies in 2003.

Capex and Dividends

Capital expenditures remained nearly unchanged at a relatively low $41.0 billion in 2004, well below the $56.8 billion that was recorded in 2001, the height of the industry’s competitive generation build-out.

Dividends paid to common share-holders rose by $833 million, or 6.8%, to $13.1 billion in 2004. Thirty-fi ve of the industry’s 65 publicly traded compa-nies, or 53.8%, increased their dividend payment in 2004, the largest percentage since 1993 when 65.0% raised their dividend. Several factors have created the new appetite for dividends, includ-ing: 1) two straight years of improving, positive free cash flow, 2) reduced individual tax rates on dividends from the Jobs and Growth Tax Reconciliation Act of 2003 (effective through 2008), and 3) the industry’s overall “back-to-

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basics” focus on core electric operations, a reinvigorated version of the traditional utility operating strategy that targets a low but stable growth rate and a strong dividend (see Dividends section).

Free Cash Flow Improves for Fourth Straight Year

Free cash fl ow improved to $4.0 bil-lion in 2004, a $496 million or 14.3% increase over the $3.5 billion of 2003. Last year marked the second consecu-tive year of positive free cash fl ow and the fourth consecutive year that this measure has improved. The 2004 free cash fl ow increase resulted from the $1.9 billion increase in net cash provided by operating activities and the modest $548 million rise in capital expendi-tures, combined with the $833 million increase in common dividends paid. Unlike many industries that measure free cash fl ow as the difference between cash fl ow from operations and capital expenditures, the electric utility indus-try also deducts common dividends due to its strong tradition of dividend payments (free cash fl ow = cash fl ows from operations – capital expenditures – common dividends).

Just over one-half of the industry, 37 companies, showed improved free cash fl ow in 2004 compared to 35 com-panies that saw a decline. Dominion Resources, one of the nation’s largest producers of electric power and natural gas, had the largest gain at $1.1 billion. Dominion reduced capital expenditures by $687 million and increased cash from operations by $484 million. Do-minion cited strong results at its coal and nuclear facilities for the improved operating cash, as well as a $100 mil-lion savings attributed to its Six Sigma process improvements. Dominion paid $36 million more in dividends in 2004, its fi rst increase since 1994.

Going Forward

Several variables will affect free cash fl ow going forward, with the greatest impact expected to come from rising capital expenditures. Companies have already begun to spend more on air emissions control equipment to make plants compliant with the latest Envi-ronmental Protection Agency regula-tions, and spending on transmission and distribution system upgrades is also expected to rise. The use of cash to cover these costs, some of which may be captured in the rate base, may compete against a desire to use cash to increase the dividend and/or further reduce debt for some companies.

DIVIDENDS

STRENGTHENING CASH FLOWS LEAD TO WIDESPREAD DIVIDEND INCREASES IN 2004

2004 Summary

Shareholder-owned electric utilities implemented widespread dividend increases during 2004, as cash flow continued to strengthen due to the industry’s refocus on core operations over the past three years. Divestiture of non-core assets, reduced capital expenditures and rising earnings have enabled many companies to reach targeted debt-to-cap ratios and return cash to shareholders. The dividend tax reduction legislation enacted in 2003, which lowered dividend tax rates for most individuals to 15%, also supported the industry’s dividend increases.

Thirty-fi ve of the 65 EEI member companies (53.8% of the industry) increased dividends in 2004, the larg-est percentage since 1993 when 65.0% raised their dividend. No companies

cancelled their dividend in 2004, the fi rst year without a termination since 1999. Only one company reduced its dividend. This total of one adverse ac-tion (cancellation or reduction) is the lowest since 1993.

Many companies are returning to the traditional regulated utility model of low but stable earnings growth and a secure dividend as a means of provid-ing an attractive return to investors. This trend is evidenced by the $833 million, or 6.8%, rise in total common dividends paid from $12.3 billion in 2003 to $13.1 billion in 2004.

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Free Cash Flow Strengthens

2004 was the second straight year of positive free cash fl ow for the industry as a whole, and the fourth consecutive year that this measure has improved. The industry produced $4.0 billion of free cash fl ow in 2004, up slightly from $3.5 billion in 2003. By contrast, the industry’s average free cash fl ow from 2000-2002 was ($13.6 billion).

The industry posted strong earnings for the second consecutive year with $26.1 billion of net income in 2004, up $10.5 billion from $15.6 billion in 2003. The industry suffered a rare net loss in 2002 caused by a record high $24.9 billion in non-recurring charges. Part of the rebound over the last two years is due to the continued sale of non-core assets, which included mer-chant generation plants, international investments and telecommunications operations. In addition to an immedi-ate liquidity boost, these sales removed the drag on earnings from unsuccessful non-core ventures. Of the 65 companies in the EEI Index, 40 companies, or 61.5% of the industry, improved earn-ings in 2004.

Capital expenditures were nearly unchanged, rising $548 million or 1.4% to $41.0 billion in 2004 from $40.4 billion in 2003. This two-year stretch is relatively low compared to the $47.2, $56.8, and $48.5 billion levels in 2000, 2001, and 2002—a time when the industry was at the height of its competitive generation build-out. Of the three determinants of free cash fl ow (free cash fl ow = cash fl ow from operations less capital expenditures less common dividends), declining capital expenditures was the biggest contribu-tor to the signifi cant improvement from 2001 to 2004.

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Balance Sheets Improve

Also supporting dividends was the fact that some com-panies reached targeted debt-to-cap ratios during 2003, and more did so in 2004. The industry’s three-year path to recovery has been marked by a concerted effort to improve this ratio by issuing common equity and paying down debt. The industry’s year-end debt-to-cap ratio improved from 62.2% in 2002 to 61.5% in 2003 to 58.2% in 2004. As balance sheets and cash fl ows improved, credit ratings agencies took a more favor-able view of industry credit quality. Moody’s upgraded 20 electric utilities and down-graded 22 in 2004, a sharp contrast to Moody’s 11 up-grades and 68 downgrades in 2003 and fi ve upgrades and 113 downgrades in 2002.

Strong Earnings Reduce Payout Ratio

Despite rising dividend payments, the industry’s dividend payout ratio fell from 69.6% in 2003 to 51.6% in 2004, as stronger earnings more than offset dividend increases. Although some companies, such as Exelon and TXU, have implemented aggressive dividend increases over the past two years, most of the industry has taken a more mod-est approach. This is partly due to the ongoing cash commitment resulting from a dividend increase, the volatility of earnings and cash fl ows in recent years, and the expectation of a rebound in capital spending over the next several years. The industry remains under the watchful eye of the credit rating agen-cies who carefully scrutinize the impact

of higher dividends on future free cash fl ows. Yet even with the 2004 decline, the electric utility industry still pays out the highest percentage of earnings of all U.S. business sectors (see above). ve). ve

TXU and Exelon Take the Lead

TXU Corp. announced a 350% dividend increase (from 12.5 cents to 56.25 cents per share) in the fourth quarter of 2004 as part of its restructur-ing plan. TXU sold three subsidiaries last year, achieved a 42% reduction in debt, and enjoys favorable electricity pricing clauses which allow this owner of significant coal-fired and nuclear generation to adjust rates to natural gas prices twice a year. It should be noted that despite its large increase to $2.25 per year, TXU’s dividend is still slightly below the $2.40 it paid as recently as



2002, when it reduced its dividend due to liquidity concerns. Without TXU’s 350% hike, the average increase in 2004 among companies that raised their dividend falls from 18.7% to 9.0% (see below).

Exelon Corp. has increased its divi-dend fi ve times during the past two years, refl ecting its enviable cash posi-tion and its goal of attaining a dividend payout ratio of 50% to 60% in 2005. As the nation’s leading producer of nuclear-generated power, Exelon’s profi t margins benefi ted in 2004 from high natural gas prices (natural gas generators are the

marginal producers and price setters in many electricity markets around the country). This created sizeable profi ts for Exelon’s nuclear fl eet in 2004, whose production costs are considerably below those of gas-fi red generators. Exelon’s move was supported by a $1.0 billion or 30.0% increase in operating cash fl ows in 2004 and by its goal of achiev-ing a dividend payout ratio range that is consistent with its peer group of companies. Beginning in 2003, Exelon implemented a shift in dividend payout policy from using a strict percentage of regulated earnings to a balanced

approach that utilizes total company earnings.

Rising dividends were not unique to electric utilities in 2004. According to Standard & Poor’s, of the roughly 7,000 U.S. publicly owned companies that pay dividends, 1,745 posted an increase last year. That’s a 7.1% gain from 1,630 in 2003. Despite the relatively successful stock performance by utilities over the past fi ve years, the utilities sector remains on top in terms of dividend yield. The table on page 32 represents a dividend yield comparison among U.S. business sectors.

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Reduced Dividend Tax Rates

Electric utility stocks reaped the benefi ts of The Jobs and Growth Tax Relief Reconciliation Act of 2003 for the second straight year, as the dividend tax break for individuals drew investors to the industry. The legislation reduced individual tax rates on dividends to 15% for most tax brackets and 5% for the lowest two brackets. The legislation gave dividend paying stocks an advan-tage over bonds, as bond interest is still taxed as ordinary income. Although the tax break is effective through 2008, the Edison Electric Institute has already begun work to encourage its permanent extension.

Dividend Decreases

There were no dividend cancellations by shareholder-owned electric utilities in 2004, providing further evidence of the industry’s turnaround. By contrast, seven companies cancelled dividends during the 2001-2003 period, and four did so from 1996 through 2000 (see table on page 31). Despite the industry’s fi nancial recovery and the rebirth of dividends, some remaining liquidity challenges are evidenced by the seven companies, 10.8% of the industry, that did not pay dividends in 2003 and 2004. These are the only years since 1990 that this percentage has exceeded 10.0%.

One company reduced its dividend in 2004. Maine & Maritimes Corp. lowered its annual payment by 47%, from $1.52 to $0.80, in order to bring its dividend yield to approximately 5.2%. This new level provides for a sus-tainable dividend and also frees cash to support the execution of the company’s long-term growth strategy. The adjust-ment also aligns Maine & Maritimes’ dividend yield with its regional and sector peer group.

Dividends Drive Stock Gains

Dividend gains helped propel utility stock pric-es higher for the second straight year. Electric utili-ties averaged 20+ percent-age returns in 2003 and 2004, outperforming the broader markets over this two-year period. The very low interest rates of the last few years have supported these dividend-paying stocks, as income-oriented investors have looked be-yond the bond market for yield plays.

Balancing Dividends with Rising Capex

The widespread divi-dend increases of 2004 have created a signifi cant cash com-mitment going forward, and compa-nies will have to balance the need to maintain these dividends with a likely resurgence in capital spending. Fol-lowing a three-year decline in capex, in which companies wound down competitive generation expansion and related transmission investments, capex are expected to increase in 2005 and beyond. The primary near-term driver is environmental spending specifi cally the air emissions control equipment needed to make plants compliant with the latest EPA regulations. For example, AEP Corp. is projecting $3.7 billion in these expenditures from 2005-2010. Companies will also face increased costs from operating and maintaining the new equipment. Transmission and distribution investment should drive up capex in the long run too, although signifi cant transmission investment will likely happen only if the federal govern-

ment passes legislation that clarifi es sit-ing authority and provides investment incentives. Rising capex requirements are not necessarily bad news for utility investors. Increased environmental and transmission/distribution spending may create desirable growth opportunities for the industry if state regulators al-low these expenditures to be captured in rate base. However, any hesitation in this area may inject a new round of uncertainty into the industry’s dividend picture.

Electricity Sales and Revenues

Overview of 2004

In 2003, electric utilities operating in the United States faced a major sum-mertime blackout from Ohio to New York, a destructive hurricane (Isabel) that affected much of the East Coast,

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security concerns in the aftermath of the 9-11 terrorist attacks, and fear of cyber attacks on communications and control systems. Still, shareholder-owned electric utilities and their affi liated companies were able to reliably serve nearly three out of every four of the roughly 135 million U.S. electricity customers (including households, businesses and govern-mental entities), and generate electricity sales of 2.34 million GWh in 2003. Shareholder-owned utilities realized revenues of $180.2 billion during 2003 and accounted for 70% of all electricity sales and deliveries to U.S. consumers.

The U.S. shareholder-owned electric utilities saw similar challenges in 2004—a damaging hurricane season on the East

Coast, particularly in Florida; a U.S. industrial sector still trying to recover from the 2001-2002 recession; continued competition for customers in states that have implemented electric industry deregulation; and a dramatic rise in fossil fuel prices. Despite these challenges, in 2004 shareholder-owned electric utilities were able to expand their customer base by 1.6%, sell 0.3% more electricity, deliver 5.0% more energy, and generate 4.8% more revenue than they did the previous year. This marks a recovery of sorts for the industry, since from 2000 to 2003 it had lost customers and sales in states that implemented retail competition, and sales growth was lackluster because of the nationwide economic downturn.

Electricity Sales and Deliveries

The state of the U.S. economy, the weather and the price of electricity are the dominant factors that have determined nationwide elec-tricity sales over the past ten years. The 1990s saw unprecedented growth in the economy, generally normal weather conditions and stable energy prices. In addition, the growth of the digital economy in the 1990s resulted in increasing demand for both the quantity and quality (i.e., minimal disruptions, constant voltage and frequency) of electricity by both residential consumers and businesses. The un-employment rate dropped to 3.8% in March 2000, its lowest level in 30 years, according to the Department of Labor’s Bureau of Labor Statistics (BLS).

In contrast to the growth in the late 1990s, the fi rst few years of the 21st century have seen a recession, a lethargic economic recov-ery, atypical weather patterns and signifi cant increases in most energy prices. The growth of the U.S. economy, as measured by the Bureau of Economic Analysis’ infl ation-adjusted (real) gross domestic product (GDP), fell to an aver-age annual rate of only 2.5% in 2001–2004, about two-thirds of the 3.8% from 1995 through 2000. Although GDP growth in 2004 was 4.4%, equaling late-1990 levels, sustained growth in our nation’s economy has not been steady since 2001. For instance, the 2004 sea-sonally adjusted unemployment rate of 5.5% was an improvement over the 6.0% level in 2003, but far from the under 4.0% level of late

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2000. Not surprisingly, electricity sales by shareholder-owned electric utilities, which had been growing at an average rate of 3.0% per year between 1995 and 2000, declined to an average annual rate of only 0.4% for 2001-2004.

The slow growth rate in real GDP for 2001 through 2003 was due to many factors, including domestic security concerns following the 9-11 attacks, the global war on terrorism, signifi cant de-clines in U.S. stock values, labor down-

sizing by some of the nation’s largest compa-nies, corporate a c c o u n t i n g scandals, and the collapse of many of the “ d o t - c o m” c o m p a n i e s founded in the early 1990s. T h e e c o -nomic growth achieved in 2004 was in large part the result of the government’s efforts to stim-

ulate the economy in 2002 and 2003. The Federal Reserve cut the fed funds rate—the overnight loan rate to mem-ber banks—to levels not seen since the end of World War II, and the Congress passed tax cuts to encourage personal and business spending.

The historical relationship between GDP and electricity sales has been ana-lyzed by Lehman Brothers, a Wall Street investment bank. They found that prior to 1973, when the U.S. economy was largely driven by power-intensive manu-facturing and heavy industry, electricity sales growth exceeded that of GDP by a factor of 1.3 or higher. Over the past two decades, however, the services sector has been the primary driver of economic growth, and the ratio has fallen below 1.0. The ratio is now about 0.5 and likely to stay at this level for the foreseeable future. Lehman Brothers and the Energy Information Admin-istration (EIA), an agency within the Department of Energy, both believe that structural changes in the U.S. economy

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have made it less electricity intensive (i.e., the electric energy required per unit of GDP has declined).

Confi rming Lehman Brothers’ and EIA’s predictions, overall electricity sales in 2004 by shareholder-owned electric utilities increased 0.3% from the year earlier, continuing the slow/no growth trend seen over the recent past. This is in contrast with a 1.8% pattern of an-nual growth in the mid to late 1990s. Residential sales increased a healthy 2.4% in 2004 and commercial sales rose 1.2%. Although overall electricity sales increased in 2004, sales to industrial customers decreased by 3.6% largely because of weak industrial growth and the ability of large electricity users to buy directly from alternative energy providers or from power marketers selling electricity generated at merchant power plants. The increase in residen-tial electricity sales in 2004 marks the seventh consecutive year of increase, which has averaged almost 2.5% per year since 1998.

In contrast to electricity sales, elec-tricity deliveries by shareholder-owned utilities (i.e. power delivered over distribution networks) increased 5.0% nationwide in 2004 from the previous year. Consumers—residential, com-mercial and industrial—in some states can buy electric power from competing energy companies, but power distribu-tion is almost exclusively limited to traditional utilities with transmission and distribution (T&D) networks, including the metering systems that determine sales quantities. The 7.2% increase in both residential and com-mercial electricity deliveries in 2004 provides clear evidence that American homes and businesses continue to de-pend upon shareholder-owned utilities for reliable power delivery even when the electricity is generated by an alter-native energy supplier.

Housing Boom Offsets Slumping Industrial Sales

One of the brightest spots in the U.S. economy over the past few years has been the residential construction in-dustry. Encouraged by low interest rates on construction loans and mortgages, homebuilders started 1.96 million single- and multi-unit homes in 2004, the highest level since 1978, according to the Commerce Department’s Census Bureau. Over the past four years, hous-ing starts have shown an average annual growth rate of 5.7%, which explains in part why residential electricity sales have continued to rise despite slow economic growth and decreases in industrial elec-tricity sales.

Impact of Retail Competition

Another factor contributing to the slow growth in electricity sales by shareholder-owned electric utilities, in contrast to electricity deliveries, is retail competition, sometimes called “retail access” or “customer choice.” Customer choice enables consumers to switch from bundled service from a traditional utility—electricity and delivery by a sin-gle utility—to one company supplying electricity and another providing T&D service. Twenty states, and the District of Columbia, have implemented legisla-tion to permit electricity customers to choose an electricity supplier other than their traditional vertically integrated electric utility. These states are Arizona, California, Connecticut, Delaware, Illi-nois, Maine, Maryland, Massachusetts,



Michigan, Montana, Nevada, New Hampshire, New Jersey, New York, Ohio, Oregon, Pennsylvania, Rhode Island, Texas, and Virginia. California has suspended full implementation of its program, while Arkansas, New Mexico, Oklahoma, and West Virginia have delayed or repealed their retail competition plans over concerns about customer benefi ts.

In those states that have imple-mented retail competition, customer choice has reduced electricity sales by shareholder-owned electric utilities. At the end of 2004, state public util-ity commissions (PUCs) and public service commissions (PSCs) reported almost 3.1 million electricity custom-ers nationwide as having switched to an alternative power provider. This is almost a 20.0% increase from the 2.6 million customers that had switched to an alternative energy provider in 2003. Although this is only 5.4% of eligible

customers, it represents a greater por-tion of utility load since large consum-ers of electricity (e.g., commercial and industrial users) are more likely to shop for lower priced electricity.

Customer choice does not necessarily result in the loss of electricity sales since, in many states, shareholder-owned utilities or their holding company have formed affi liated retail power market-ing companies to compete for retail customers. In those states that publish customer-switching statistics, it appears that affi liated power marketers were able to retain roughly one out of every three customers choosing an alternative power supplier. At the end of 2004, the Federal Energy Regulatory Commission (FERC) had accepted market-based electricity rates filed by 591 power marketers—126 of which are affi liated with shareholder-owned electric utili-ties. Although all these companies are permitted to sell retail electricity, only

about 75 actually sold electricity during 2003, according to EIA.

To a lesser degree, shareholder-owned utilities and their affi liated power mar-keters are also losing sales to industrial and commercial customers that elect to self-generate. Today’s combined-cycle technology using natural gas can be more energy effi cient than traditional boiler/steam-turbine technology, par-ticularly when steam is required for in-dustrial processes and/or space heating. Increasingly, businesses are exploring self-generation alternatives to satisfy future energy needs, since at least in some areas of the country, the sale of excess electricity can be an additional source of revenue.

Weather Trends

The National Weather Service (NWS) reports that 2004 was the 24th warmest year in its 110 years of record keeping, averaging 53.5 degrees Fahren-

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heit (º F) for the contiguous U.S. The last fi ve 5-year periods (2000-2004, 1999-2003, 1998-2002, 1997-2001 and 1996-2000) were the warmest 5-year periods ever recorded by NWS, illustrating the anomalous warm tem-peratures of the last decade. NWS also recorded 2004 as the sixth wettest year

on record. Nationwide, the 2004 sum-mer season (June-August) was much cooler than average—the ninth cool-est on record—although the western third of the country was warmer than normal. During 2004, cooling degree-days, a measure of air conditioning demand, were 3.5% above the 34-year

historical average, but 1.6% lower than the previous year. Cooler 2004 summertime temperatures nationwide were evidenced by EEI’s Weekly Elec-tric Output system that recorded lower summer electricity production in 2004 than a year earlier. During July and August 2004, electricity produced by



all U.S. power plants reached 737,500 GWh, 2.8% less than the same period a year earlier.

The 2003-2004 winter season (De-cember, January, February) was near the 110-year average for the nation, with cooler than normal temperatures along the eastern seaboard and above average temperatures in the central U.S. Nationwide, heating degree-days in 2004 were 7.1% below the 34-year average and 4.3% below the 2003 levels. Most important for electricity custom-ers, warmer winter temperatures have helped to offset the higher summer temperatures experienced over the last decade, thereby holding down the rise in yearly electricity bills due to increased use of air conditioning.

Although the winter of 2003/2004 was near normal, the winters of 1997/1998, 1998/1999, and 1999/2000 were un-usually warm—almost 1º F warmer. Many explanations have been offered for the ten-year rise in temperatures in the contiguous United States. Whether from global warming or El Niño–La Niña, average annual temperatures na-tionwide have increased almost 1.5º F over the period 1995–2004. In the last ten years, summer and winter average temperatures have exceeded normal levels eight times, only twice dipping below normal. Similarly, average annual temperatures over the last ten years only fell below normal levels once.

Weather Events in 2004

Nine tropical systems affected U.S. electricity consumers during 2004. The estimated cost of damage to ho-meowners and businesses from 2004 hurricanes and tropical storms was over $42 billion, the costliest hurricane season ever according to the NWS. The second most costly year was 1992, at $35 billion, when Hurricane Andrew

devastated Homestead, Florida and surrounding areas.

Five hurricanes made landfall in the U.S. in 2004, although Hurri-cane Alex impacted North Carolina without offi cially coming ashore. The record number of hurricane landfalls is six, occurring in 1916 and 1985. An unprecedented four hurricanes (Char-ley, Frances, Ivan and Jeanne) left an estimated 6.0 million Florida utility customers without power during 2004, some for as long as a month. In com-parison, Hurricane Andrew left only 1.3 million utility customers without power. An estimated one in fi ve homes in Florida was damaged during August and September 2004 and 117 people lost their lives due to the storms.

Volatile Fuel Costs

Retail sales of electricity are also infl uenced by the price of electricity, which is in large part determined by the cost of the fuel used to generate it. U.S. infl ation, as measured by the BLS’s seasonally adjusted consumer price index (CPI), was 3.4% for 2004 compared to a more modest 1.9% in 2003. The core rate of infl ation was just 2.2%, almost double the 2003 rate, which was the lowest level in the last ten years. The core rate of infl ation excludes the volatile food and energy sectors from the mix, and enables economists to more easily identify underlying infl a-tion trends.

The same cannot be said for energy price infl ation, which surged more in 2002 through 2004 than during the entire 1990s. For example, the season-ally adjusted CPI for electricity averaged only 1.0% annually from 1994 to 2003, but was 2.8 and 2.2% in 2003 and 2004, respectively. This, however, was tame compared to what consumers had to pay for other forms of energy. From

December 2003 to December 2004, natural gas prices went up 16.7% on top of a 17.6 price rise in 2003. Home heating oil was up a whopping 40.0% in 2004, and gasoline (all grades) increased 26.0%, according to the BLS.

The seasonally adjusted CPI for all energy commodities refl ects the increas-ing cost of energy to American consum-ers. In the fi ve years from January 1995 to December 1999, overall energy prices increased 7.5%. In contrast, energy price infl ation was 37.9%—or an aver-age of 6.6% per year—for the fi ve years from January 2000 to December 2004. CPI data shows that energy price infl a-tion was 16.5% from January 2004 to December 2004.

Energy price volatility is not a new phenomenon to American residential consumers and businesses. Through energy efficiency and conservation, America energy consumers have done much since the energy crises of the 1970s to protect themselves from the adverse impacts of sharp price increases. The American economy appears to have weathered the most recent rounds of price increases, but world events still directly affect the sales of electric utilities and other energy providers. The continuing war on terrorism, political unrest in the Middle East, concerns about the Russian oil and gas industry, growing demand for energy in the third world, and potential domestic natural gas shortages affect world and domestic energy prices, generation fuel costs, and in turn, the price and quantity of elec-tricity sold in the United States.

Energy price volatility appears to be inevitable for the near future because of the current oil and gas supply-demand imbalances worldwide. For instance, some energy experts are predicting a natural gas shortage in the U.S. if



electric utilities and their affi liates lost nearly 6,500 industrial customers in 2003, while in 2004 they added over 43,000 energy-only industrial custom-ers. Undoubtedly most of the industrial customers gained were customers that had previously switched to alternative power suppliers in those states that have customer choice. Although revenues from industrial concerns increased in 2004, the amount of electricity sold to these fi rms decreased, likely refl ecting overseas outsourcing and the decline of manufacturing and heavy industry in the United States.

Average revenue on a unit basis (i.e., revenue per bundled kilowatthour sold and delivered) for 2004 exceeded 2003 levels for residential, commercial and industrial service. Residential revenue reached 9.07 cents/kWh in 2004—a 2.6% increase over the 2003 rate of 8.84 cents/kWh. The average commercial revenue in 2004 was 8.04 cents/kWh, up 1.5% from the previous year. Indus-trial revenue increased by 5.1%—5.33

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winter 2005/2006 temperatures are signifi cantly below normal. This would adversely affect shareholder-owned elec-tric utilities and their customers, since natural gas accounted for about 18% of the electricity produced nationwide in 2004, according to EIA. Electricity generation from natural gas grew 7.6% in 2004, a refl ection of the nation’s growing dependence on low-emission, gas-fi red combustion turbines (essen-tially stationary jet engines).

Electricity Revenues

Revenues from electricity sales and deliveries to all customer classes were $188.9 billion in 2004, an increase of 4.8% compared to 2003. Revenues from residential sales and deliveries were up 6.6% from the previous year, in part because of a 2.4% increase in electricity sales and a 7.2% increase in electricity deliveries (T&D service). Revenues from commercial customers were up 3.5%, again in part because of a 1.2% increase in sales and a 7.2%

increase in electricity delivery only. Un-like 2003, when a revenue decrease was recorded, industrial customer revenue increased 3.6% in 2004. This was not unexpected since shareholder-owned



cents/kWh for 2004 versus 5.07 cents/kWh for 2003. The relative stability of these revenue rates likely refl ects the competition developing for retail customers in states where customer choice and utility rate freezes have been implemented while the states consider or transition to full retail competition. Interestingly, revenue rates for shareholder-owned electric utilities have been trending downward since the mid 1990s. For instance, residential revenue rates reached a record of 8.95 cents/kWh in 1997, and only recorded a higher rate in 2004. Industrial and commercial rates have followed a similar pattern—peaking in 1991 and 1993 at 5.02 cents/kWh and 7.93 cents/kWh, respectively, and then declining until 2003, when the commercial and industrial revenue rates reached the levels of ten years earlier.

The ten-year trend of declining rates means that electric utilities received less money for their product and services in 2004 than they did in the 1990s. For instance, the 2004 residential revenue of 9.07 cents/kWh is only 0.18 cents higher than the 1995 rate. If residential revenue rates had kept pace with the overall CPI infl ation rate over this ten-year period, residential revenue rates would have been 11.04 cents/kWh in 2004. A similar analysis would have 2004 commercial revenue and industrial rates at 9.79 cents/kWh and 5.94 cents/kWh, respectively. Clearly, this trend was only possible because of stable energy prices in the 1990s and signifi cant cost cut-ting by electric utilities in the face of increasing competition in the early 2000s.

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The increase in industrial revenues from 2003 to 2004 is primarily the result of higher electricity prices, since shareholder-owned electric utilities sold and delivered less electricity to industrial customers. Together, sales to these customer classes dropped by 22,800 GWh, or 3.6%, from 2003 to 2004. The revenue decline from less sales was offset by higher prices in 2004, and resulted in a combined revenue increase of $1.33 billion, or 4.3%. Although the overall economy in 2004 was recovering from the 2001-2002 recession, manufacturing did not see the output growth of other sectors. Declining industrial sales can be blamed on the economy, but other factors also contributed to the decline, including customer choice, foreign outsourcing, increased attention to energy effi ciency and energy conservation, and increased reliance on self-generated power.

The total number of customers served by shareholder-owned utilities and their affi liates was 100.9 million in 2004, a 1.6% increase over 2003. Most of the 1.63 million increase came from a residential sector that showed a 1.29 million increase in customers. This increase is not surprising in light of the 1.96 million housing starts in 2004 reported by the Census Bureau. The underlying reasons for the 303,000 new commercial customers are less obvious. The increase may refl ect an improving economy after two years of slow GDP growth, a rising rate of new business formation and a decrease in business failures. The gain of 33,000 industrial customers, a 6.8% increase over 2003, is certainly due in large part to shareholder-owned utilities’ success in winning back customers under retail competition. Experience in states that have implemented customer choice has shown that large industrial electricity

users are much more likely to switch energy providers since the cost savings can be signifi cant. Because of this, retail power marketers, including those af-fi liated with shareholder-owned electric utilities, have actively pursued large electricity users—industrial plants and commercial businesses with multiple locations—before residential custom-ers. Where retail power marketers have acquired a substantial number of residential customers they have had to invest heavily in mass marketing, which reduces near-term profi tability.

Outlook

The future for retail competition nationwide is unclear, especially in light of California’s experience with utility restructuring and competition. State policy makers and regulators are adopting a more pragmatic approach to achieving and protecting customer ben-efi ts, which were once expected to fl ow almost automatically from competition. Additionally, excess utility generating capacity in some areas of the country has prompted state policy makers to postpone or abandon retail competi-tion, at least for smaller consumers. Regardless of state deregulation efforts, many shareholder-owned electric utili-ties across the country are restructuring —rationalizing asset portfolios, paring back non-core businesses, reducing operating expenses and emphasizing core operations—to remain competitive and keep electricity price increases to a minimum.

In summary, 2004 saw steady growth in the U.S. economy, with shareholder-owned electric utility and affi liate sales, deliveries and revenues increasing modestly. Summertime temperatures and cooling demands were less than the records experienced in previous years, but annual electricity sales grew mod-

estly because of an expanding customer base and successes in retail electric-ity markets. Continued growth of the U.S. economy, more widespread use of emerging electricity-based technologies, and a strong new home market should drive up the demand for electricity in the future. Average home size is increas-ing in both square footage and volume (i.e., higher ceilings) so electricity use for heating, cooling and lighting is expected to grow. Population shifts to warmer parts of the country should also lead to greater use of electricity for cooling.

EIA forecasts that the growth rate in annual electricity usage will average 1.9% over the next 20 years. In part, this is because sales growth is likely to be only about one-half of the GDP growth rate, if the historical trend between elec-tricity sales and GDP continues. EIA expects residential, commercial, and industrial electricity sales to increase 1.6%, 2.5%, and 1.3% per year, re-spectively. Despite these modest growth projections, shareholder-owned electric utilities and their affi liated power mar-keters can be expected to lead the way in meeting the nation’s growing demand for reliable, high-quality electricity.


BUSINESS STRATEGIES

Business StrategiesBusiness Segmentation

Summary

Regulated electric revenues increased by $6.1 billion, or 3.3%, in 2004. However, the overall share of industry revenue coming from this core seg-ment decreased to 54.6% in 2004 from 55.9% in 2003. The percentage decline is due to the continued rise in natural gas prices through 2004, as evidenced

by the double-digit percentage revenue gains in the industry’s natural gas distri-bution, natural gas and oil exploration & processing, and natural gas pipeline operations, which increased as a group by $7.3 billion, or 12.5%. The trend of surging gas revenues outpacing ris-ing electric revenues was a replay of the prior year, although it was more pro-nounced in 2003 as gas-related revenues rose by $14.4 billion, or 31.6%, from 2002. Over the last two years, surging natural gas prices have boosted total rev-

enues for the three natural gas categories by over $20 billion, or nearly 50%.

The percentage of the industry’s total assets used for regulated electric activities increased from 56.8% at year-end 2003 to 59.2% at year-end 2004. The industry’s regulated electric assets increased by a net value of $17.5 billion in 2004, far more than for any other business segment, reflecting the indus-try’s focus on core operations, typically the electric utility. The second largest

Business Segmentation — RevenuesU.S. SHAREHOLDER-OWNED ELECTRIC UTILITIES

($ Millions) 2004 2003r Difference

Regulated Electric Competitive EnergyNatural Gas Distribution Natural Gas and Oil Exploration & ProcessingNatural Gas Pipeline

Other Eliminations/Reconciling Items

Total Revenues

190,478 73,276 38,370 14,378 12,906 19,259 (15,228)

333,440

184,381 68,600 34,509 12,398 11,429 18,439 (14,958)

314,799

6,097 4,676 3,861 1,979 1,477 820 (270)

18,641

3.3% 6.8% 11.2%16.0%

12.9% 4.4% 1.8%

5.9%

% Change

r = revised

Note: Difference and Percent Change columns may reflect rounding. Totals may reflect rounding.

Source: Based on segment reporting from annual reports of the 65 companies represented in the EEI Index.


BUSINESS STRATEGIES

regulated category, natural gas distribu-tion, produced the second highest asset increase, at $3.5 billion or 5.9%. If the two regulated groups are combined, the industry grew its regulated assets by $21.0 billion, or 3.7%, in 2004.

Regulated Electric

Regulated electric, the industry’s largest segment, produced $192 bil-lion of the industry’s 2003 revenues and accounted for $524 billion of the industry’s total assets at year-end. This segment includes generation, trans-mission and distribution of regulated electricity to residential, commercial and industrial customers. Although regulated electric revenues increased by a healthy $6.1 billion, or 3.3%, in 2004, the overall share of total industry rev-enues derived from the regulated elec-tric segment fell slightly, from 55.9% in 2003 to 54.6% in 2004. Stronger pricing in the competitive electricity markets and rising natural gas prices

created the sharper growth in the other business segments in 2004.

The share of industry revenue pro-duced by regulated electric operations began to decline in the mid-1990s fol-lowing the initial deregulation of the industry, and then fell sharply beginning in 2000 as many companies moved ag-gressively into merchant power genera-tion, trading and marketing, and other diversified businesses. The subsequent contraction in the wholesale energy business, following the collapse of En-ron and the decline in wholesale electric-ity prices caused by excess generation capacity and a soft economy, produced a downturn in the trading and marketing of wholesale power and led the industry to re-focus on state-regulated electricity operations.

Of the 65 companies for which business segmentation data was gath-ered, 45, or 69.2%, increased their net regulated assets in 2004. To gain a bet-ter perspective on the relative growth

of the regulated electric segment, a comparison of regulated electric assets to total industry assets was calculated for 2003 and 2004. Forty companies, or 61.5% of the industry, increased this ratio in 2004 from 2003, providing strong evidence that most companies are refocusing on their core electric operations. Going forward, the likely increase in the industry’s capital expen-ditures may serve as a key growth area, as companies look to incorporate these costs into rate base. In the near term, the industry faces increased spending on air emissions control equipment in order to make plants compliant with the latest Environmental Protection Agency (EPA) regulations. Over a lon-ger-term horizon, considerable capital investment will be needed to upgrade the transmission and distribution in-frastructure nationwide.

Southern Company is a good ex-ample of a utility with a strong regulated focus. Based in Atlanta, Southern’s five

Business Segmentation — AssetsU.S. SHAREHOLDER-OWNED ELECTRIC UTILITIES

($ Millions) 2004 2003r Difference

Regulated Electric Competitive EnergyNatural Gas Distribution Natural Gas Pipeline Natural Gas and Oil Exploration & Processing

Other Eliminations/Reconciling Items

Total Assets

523,983148,650 62,905 32,146 19,979 97,427 (39,106)

845,984

506,441154,404 59,413 31,645 19,038 120,252 (39,183)

852,011

17,542 (5,754) 3,492 501 942 (22,826) 77

(6,103)

3.5% (3.7%) 5.9% 1.6% 4.9%

(19.0%) (0.2%)

% Change

(0.7%)

r = revised

Note: Difference and Percent Change columns may reflect rounding. Totals may reflect rounding.

Source: Based on segment reporting from annual reports of the 65 companies represented in the EEI Index.


BUSINESS STRATEGIES

Revenue Breakdown 2004U.S. SHAREHOLDER-OWNED ELECTRIC UTILITIES

Revenue Breakdown 2003rU.S. SHAREHOLDER-OWNED ELECTRIC UTILITIES

r = revised

Source: EEI Finance Department and Company Annual Reports

RegulatedElectric 54.6%

Natural Gas and Oil Exploration & Processing

Natural Gas Distribution

11.0%

Natural Gas Pipeline

3.7%

4.1%

Competitive Energy 21.0%

Other 5.5%




10.5%


3.5%

3.8%


Other 5.6%

electric utility subsidiaries serve 4.2 mil-lion customers, primarily in Alabama, Georgia, Florida, Mississippi and Geor-gia. In 2004, over 90% of Southern’s revenues came from its regulated opera-tions, with its regulated electric assets comprising just under 90% of total assets. Beginning with the spin-off of its competitive energy subsidiary, Mirant Corporation, in September of 2000, Southern’s solid financial performance has been rewarded with a 153.8% total shareholder return for the five-year period ending December 31, 2004, ranking it fifth among the EEI Index large-cap companies.

Competitive Energy

Competitive energy revenues rose by $4.7 billion, or 6.8%, to $73.3 billion in 2004. Although most electric utility companies have refocused attention on the regulated side of the business, com-petitive energy activities remain a core strategy for some. Competitive energy includes the generation and/or sale of electricity in competitive markets, in-

cluding wholesale and competitive retail transactions. Wholesale buyers typically include other electric utilities seeking to supplement generation capacity, re-gional power pools and large industrial customers. Competitive energy also includes the trading and marketing of natural gas. Competitive energy assets decreased by $5.7 billion, or 3.7%, in 2004, providing more evidence of the industry’s refocus on regulated electric activities. Several companies sold non-core competitive generation assets in 2004, with the proceeds used to reduce debt, fund capital expenditures, and/or increase dividends. Purchases of com-petitive generation assets by investors outside the industry, such as private equity firms and hedge funds, helps explain the 3.7% decline. Had these assets simply changed hands within the industry, the net effect would have been a wash.

Exelon Corporation, headquartered in Chicago, has the industry’s largest competitive energy operation with $16.4 billion in assets at year-end 2004.

This was over one-third of Exelon’s total assets. The merger of Exelon and Pub-lic Service Enterprise Group (PSEG) would place the combined entity far into the lead in the competitive energy arena. PSEG reported $12.7 billion of competitive energy assets at year-end 2004.

Natural Gas

Natural gas distribution, pipeline and exploration & processing activities generated more than $65.7 billion, or 18.8%, of the industry’s revenues in 2004, up from 17.8% in 2003. Contin-ued rising natural gas prices drove the increase, which was even more drastic in 2003 when surging gas prices boosted this measure up from a 15.2% share of total revenue in 2002. All three natural gas-related segments (distribution, pipe-line, and exploration & processing) pro-duced double-digit percentage growth in revenues in 2004, led by a 16.0% growth in natural gas and oil explora-tion & processing. In dollar terms, gas distribution provided more than half, or


BUSINESS STRATEGIES

$3.9 billion, of the overall $7.3 billion increase for the natural gas-related cat-egories. The natural gas category focuses on the delivery of natural gas to homes, businesses and industries throughout the United States, while the pipeline business concentrates on the transmis-sion and storage of natural gas for local distribution companies, marketers and traders, electric power generators and natural gas producers. Among the natural gas-related segments, natural gas distribution provided the largest dollar growth, with a $3.5 billion increase, and the largest percentage growth, at 5.9%, in assets in 2004.

Forty-five of sixty-five companies, or over two-thirds of the industry, increased the ratio of regulated assets (i.e., regulated electric and natural gas distribution) to total assets at year-end 2004 when compared with year-end 2003. This demonstrates the current trend of a widespread refocusing on the regulated side of the business, given its predictable cash flows and stability,

as the industry completes its financial turnaround.

KeySpan Corporation, based in Brooklyn, New York, derives the major-ity of its revenues from regulated gas and electric operations. In 2004, KeySpan’s gas distribution and regulated electric segments produced 66.3% and 26.1%, respectively, of its total revenues, com-bining for a total of 92.4% of revenues from regulated sources. KeySpan is the fifth largest distributor of natural gas in the United States and the largest electric generator in New York State. Although much smaller than its regulated gas and electric segments, KeySpan’s third larg-est business segment is gas exploration and production.

Other

The business segment called “Other” refers to all business activities not clas-sified in the previously mentioned cat-egories. As the electric power industry restructured in response to deregulation,

Asset Breakdown As of December 31, 2004

U.S. SHAREHOLDER-OWNED ELECTRIC UTILITIES




7.1%


3.6%

2.3%


r = revised

Source: EEI Finance Department and Company Annual Reports

Asset Breakdown As of December 31, 2003r

U.S. SHAREHOLDER-OWNED ELECTRIC UTILITIES

Other 11.0%




6.7%


3.6%

2.1%


Other 13.5%

a number of traditional electric utilities broadened their businesses to include opportunities outside their central fo-cus. Hawaiian Electric Industries, Inc. (HEI) is a good example of this. HEI’s subsidiary American Savings Bank, accounted for 19% of HEI’s revenues in 2004 and over half of its assets at year-end 2004.

Mergers and Acquisitions

Utility M&A activity — defined as mergers or acquisitions of whole operating companies — remained rela-tively quiet during 2004 when measured in terms of the absolute number of transactions. Three new deals were an-nounced, one was withdrawn and one was completed. This mirrored 2003’s two announcements, one withdrawal and one completion.

Defined by deal size and by the mo-tive for the transaction, however, 2004 marked an inflection point of sorts in the industry’s approach to whole


BUSINESS STRATEGIES

company deals with the December 20 announcement of Exelon Corporation’s intention to acquire Public Services En-terprise Group (PSEG). The prospective merger, if approved by regulators, will create the nation’s largest utility and was widely seen as the industry’s first truly strategic merger in several years —as opposed to recent deals motivated by financial distress on the part of the acquired company.

Market reaction was favorable. Both companies’ stocks rose more than 5% in the week following the announce-ment, giving credence to the view that

the transaction may mark the end of the industry’s “back-to-basics” phase and inaugurate a new era where growth through merger and acquisition of core utility businesses is well-received by shareholders and seen as the industry’s best bet for creating earnings growth.

A Year of Caution

Most M&A-related activity during 2004, however, took the form of discus-sion rather than action, and took place within a “What’s Next?” context for utility company strategies. From 2002 through most of 2004, the industry

focused on repairing balance sheets strained by the ill-fated expansion into unregulated businesses during the late 1990s, the crisis in California’s electric-ity markets, the Enron collapse and the failure of electricity trading and market-ing to evolve as a profitable business. By late 2004, this process was largely com-plete. Divestiture of non-core assets, exit of non-core businesses segments, debt refinancings and debt retirements strengthened many company balance sheets and averted liquidity crises. Most companies have now resolved on a busi-ness model centered around some com-

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BUSINESS STRATEGIES

bination of core regulated utility/competitive power supply operations, albeit with a wide variation across the industry in the relative contribution of each.

While these trends were largely complete by the end of 2004, an overall climate of caution nonetheless per-vaded disposition of free cash flow during the year. Wary credit ratings agencies kept the industry on a relatively tight leash, observing that utility M&A has gener-ally not been favorable for bondholders. Shareholders demonstrated a strong pref-erence that companies use cash flow to improve and maintain financial strength, or pay it out as dividends rather than spend it on growth-related mergers. Companies focused on returning cash to shareholders in the form of dividend increases and, in some cases, share buybacks.

The Growth Gap?

By late 2004, however, the idea of earnings growth through M&A began to resurface in the context of a perceived earnings growth gap for the industry—the pre-sumed clash between Wall Street’s expectation of 5% to 10% earnings growth and the industry’s low-single-digit core, organic growth rate. The industry’s back-to-basics (or perhaps more properly “back to core-strengths”) focus has run its course in terms of its ability to produce earnings gains driven by cost containment and the divesting of non-core businesses. And a new round of expansion into competitive, higher-growth businesses is as all but out of the question. Mergers of complementary core utility businesses, with cost savings generated by elimination of duplicative overhead, began to be seen as the most likely means for companies to satisfy shareholder expectations.

The basic premise of the existence of a growth gap was not universally accepted, however. Some analysts and CEOs maintained that utility companies can do

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just fine with a slow growth in rate base accompanied by a reasonably high rate of return on capital and a dependable dividend—and attract investors seeking a bond surrogate, especially in light of the favorable 15% tax rate on dividends.

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BUSINESS STRATEGIES

The strong performance of the stocks of such traditional utilities in 2004 gave support to that point of view. Although just how small a utility can be and suc-cessfully pursue that strategy remained an open question.

The counter-argument held that scale matters. Cost pressures on the regulated side of the business from escalating fuel costs (which in turn highlight the advantage of a diverse fuel portfolio), rising environmental capex (when not captured in rate base), climbing pension and healthcare costs, and reliability-related expenditures in the transmission and distribution areas will eventually squeeze smaller utilities. On the deregulated side, geographical scale and diversity, and a strong balance sheet that supports counter-party credit confidence, will become increasingly important prerequisites for competitive success. The proposed Exelon/PSEG merger presented a case study of that thinking.

Ameren Acquires Illinois Power

In the one completed transaction of 2004, Ameren Corporation acquired Illinois Power Company (IP) from Dynegy, Inc. in a transaction valued at approximately $2.3 billion. Ameren assumed $1.8 billion in IP debt and preferred stock, placed $100 million in a six-year escrow account for con-tingent environmental liabilities and paid the balance in cash. In addition to IP’s transmission and distribution system assets, the acquisition included the purchase of Dynegy’s 20% interest in Electric Energy, Inc.—the owner of a 1,086 MW, Joppa, Ill., coal-fired power plant. Prior to the acquisition, Ameren owned 60% of Electric Energy.

Discussions between the two com-panies commenced in December 2003

when Exelon withdrew its bid for IP when the Illinois state legislature failed to pass a measure that would have al-lowed a rate increase for infrastructure improvements. Ameren did not require any special legislation to complete the deal, agreed to spend between $275 mil-lion and $325 million on infrastructure investment during the first two years of ownership, and agreed to keep IP’s headquarters in Decatur for at least five years. Ameren also agreed to limit workforce reductions to a maximum of 25 employees for a period of four years, other than what occurs naturally through retirements and voluntary de-partures. The deal moved quickly. It was formally announced February 3 and closed October 1.

The two companies’ contiguous and intertwined service territories made the acquisition a strategic fit for Ameren’s core electric and natural gas delivery businesses, and Ameren expects the acquisition to be accretive by 5 cents to 10 cents per share in 2005. The deal was arguably a distressed sale from Dynegy’s perspective, who took advantage of the chance to reduce outstanding debt and focus on its core com-petitive power gen-eration and natural gas liquids businesses. Ameren intends to recapitalize IP and will seek restoration of an investment grade rating over the long term. Ameren completed similar, accretive acquisitions of regulated utilities in 1997 (CIPS) and 2004 (CILCO), and called the IP deal a “carbon copy” of those deals.

PNM Resources Bids for TNP

On July 25, New Mexico-based PNM Resources, Inc. announced an agreement to buy TNP Enterprises, Inc., a privately held Texas utility with two operating subsidiaries, Texas-New Mexico Power Co. and First Choice Power, Inc., who together serve some 475,000 customers in west Texas and New Mexico. The purchase price in-cludes $189 million in stock and cash plus the assumption of approximately $835 million in debt. If approved, the deal will provide relief to TNP’s highly levered capital structure and offer PNM an expanded customer base in New Mexico and entry to the ERCOT mar-ket. The combined entity would have more than $2.3 billion in revenue, total assets of $4.7 billion and 2,461 MW of generation, and would serve 716,000 electric and 459,000 gas customers in the Southwest.

PNM expects the acquisition to be at least 10% accretive to earnings and 20% accretive to free cash flow during the first full year after closing. PNM also indicated it will maintain its cur-

Merger Impacts 1995–2004U.S. SHAREHOLDER-OWNED ELECTRIC UTILITIES

Date No. of Utilities Change

Source: EEI Finance Department

12/31/9512/31/9712/31/9912/31/0012/31/0112/31/0212/31/0312/31/04

98968371696565 – 65 –

N/A (2.04%)(13.54%)(14.46%) (2.82%) (5.80%)

Declined 33.7% since December 1995

Note: Based on completed mergers


BUSINESS STRATEGIES

rent dividend policy of paying out 50% to 60% of regulated earnings after the deal is completed. In early 2005, PNM reached agreement with Texas state regulators that included a two-year rate freeze. FERC approved the deal on March 2, 2005.

Exelon to Buy PSEG

The biggest utility M&A news story of 2004 was Exelon’s late December move to acquire PSEG in what was hailed as the industry’s first truly strate-gic merger in several years. The primary motivation for the alliance, cited by both companies, is the ability to create efficiencies at all levels of the com-bined company, including generation, transmission, distribution and power marketing, which will also help to cre-ate better earnings predictability. As the industry’s largest operator of nuclear plants, with 17 units and 18 GW of capacity, Exelon can bring economies of scale and operating expertise to PSEG’s three nuclear plants. Analysts also observed that Exelon will ben-efit from PSEG’s experience in buying energy at generation supply auctions, expected in Illinois after 2006. Standard and Poor’s (S&P) said the deal should be supportive of PSEG credit quality, which had suffered from nuclear plant outages. The transaction is expected to be immediately accretive to earnings for both companies after closing.

If the deal is approved by regula-tors, the combined company will have approximately $27 million in annual revenues, $3.2 billion in net income, 52,000 MW of generation capacity, nearly $80 billion in assets, and will serve approximately 7 million electric and 2 million gas customers in Illinois, New Jersey and Pennsylvania.

The proposed transaction will take the form of a merger whereby each com-

mon share of PSEG converts to 1.225 shares of Exelon. PSEG stockholders will own 32%, or 306 million of com-bined company’s shares, with Exelon shareholders owning 650 million or 68%. SNL Energy placed the transac-tion value at $25.7 billion—composed of an offer value of $12.3 billion, plus assumption of total debt and pension liabilities of $14.6 billion, less cash and cash equivalents of $1.26 billion. By SNL’s calculations, the transaction value implies a multiple of 2.4X last twelve months (LTM) revenue, 8.4X LTM EBIDTA, 4.1X adjusted operat-ing cash flow and 90.2% of total assets. The $51.28 per share offer price was an 8.5% premium over PSEG’s $47.27 closing price on December 17.

The Federal Energy Regulatory Commission (FERC) expressed confi-dence that it could approve the deal, and said it would apply a delivered price test to measure the impact on whole-sale market competition. In an early February 2005 filing with the FERC, Exelon and PSEG proposed divesting 2,900 MW, including 1,000 MW of peaking and 2,900 MW of mid-merit capacity. The companies do not plan to divest any nuclear plants, but proposed a “virtual divestiture” of 2,600 MW of baseload capacity, which would allow the combined entity to retain ownership of all nuclear generation while transfer-ring control of the output through life-of-unit energy contracts or swap rights with generation outside of PJM. The proposed merger requires approval from New Jersey, New York, Pennsylvania and Illinois state regulators, the FERC, the Nuclear Regulatory Commission (NRC), and an anti-trust review by the Department of Justice or the Federal Trade Commission. It is expected to take at least a year to close.

Private Equity Buyers Struggle

The one withdrawn deal highlighted another notable trend in 2004—the difficulty faced by private equity inves-tors seeking ownership of a regulated public utility. On December 30, 2004, private equity partnership Saguaro Util-ity Group, L.P. abandoned its year-long attempt to acquire the Arizona utility holding company UniSource Energy Corp., owner of regulated utilities Tuc-son Electric Power and UniSource Energy Services. In December 2003, Saguaro—an investor group comprised of Kohlberg, Kravis, Roberts & Co. (62% ownership), JP Morgan (31%) and Wachovia Capital (7%)—offered $25.25 per share for UniSource, a 30% premium to the market price. The $3 billion deal would have retired $260 million of debt at Tucson Electric Power but added some $400 million of new debt at the holding company level. Despite a March 29, 2004 shareholder approval of the proposed acquisition, the deal struggled from the outset. Following the announcement, S&P’s Credit Rating Services put Tucson Electric on “credit watch with negative implications” due to the proposed rise in parent company debt, and state regula-tor Arizona Corporation Commission (ACC) never gained comfort with the deal’s increased leverage. Despite Sa-guaro meeting ACC requests for $500 million in planned debt retirement by 2008 as well as ring-fencing safeguards for the regulated utilities, and despite support for the deal by Arizona busi-ness and charitable groups, the ACC decided on December 21, 2004 to reject the proposed acquisition assert-ing that the deal was not in the public interest. Rather than press the ACC to reconsider, Saguaro walked away from the deal.


BUSINESS STRATEGIES

Texas Pacific Group (TPG) also faced a stiff headwind in its attempts to buy the Oregon regulated utility Portland General Electric Co. (PGE) from bankrupt Enron. In November 2003, TPG offered $2.35 billion for the utility in a proposal that included payment of $1.25 billion in cash and the assumption of $1.1 billion in debt. In order to get the deal done, Oregon Electric Utility Company (the holding company created to own PGE) would have assumed some $1.7 billion in debt, a level that regulators believed would have resulted in a below-investment-grade rating. TPG did not offer a rate concession in its initial filing with the Oregon PUC in March 2004, and in July 2004 the PUC staff recommended rejection of the deal on the grounds that it was too heavy on debt and light on rate relief. By late 2004, TPG had agreed to provide a $43 million credit to ratepayers over time, but the Oregon Public Utility Commission (OPUC) sought $75 million.

An element of drama was injected into deal discussions in early 2005 when local Oregon media reported the existence of due diligence docu-ments prepared by TPG that outlined scenarios in which it could resell PGE within 5 years for a $1 billion profit, running counter to the private equity firm’s public position that it would own the utility for at least 7 to 12 years. The documents also outlined aggressive cost cutting strategies, including sizeable lay-offs of PGE managers, customer service staff and plant employees. TPG said the documents were taken out of context, and represented only initial hypotheti-cal scenarios that the firm had prepared in advance of its first meeting with PGE in 2002. They did not represent its current plans for the utility. On March 10, 2005 however, the three-member

OPUC voted unanimously to deny the sale citing concerns that leverage at the holding company level and TPG’s short-term focus could result in a di-minished credit rating for PGE and higher rates. TPG had also promised to offer PGE more than $1 billion in contractual protection against Enron-related liabilities, but the OPUC placed little value on that, arguing that current legal protections are adequate and that PGE is not a distressed company, either operationally or financially. TPG was left with the option of presenting a new bid for PGE.

The challenges faced by Saguaro and TPG in 2004 certainly raised the bar for private equity firms seeking ownership of a regulated public utility. Coming to the table with cash proved not to be enough. Instead, crafting deals that offer rate concessions, that assuage regulators’ fears of excessive leverage, and that demonstrate a long-term commitment to stable ownership would seem to be requirements for success. Whether such deals are possible with private equity buyers remains to be seen.

M&A in the New Era

Intense regulatory oversight and regulatory veto-power over utility merg-ers and acquisitions makes them far more difficult to execute than mergers in most other industries, but the events of 2004 suggest that utility deals can get done provided they are artfully structured. Shareholders will support deals that achieve tangible operating efficiencies, that are earnings accretive, and that do not represent forays into businesses that are outside the utility’s core-strengths focus. Credit ratings agencies will look favorably on deals that preserve or enhance credit strength. State regulators have shown an aversion to increased leverage, but will support

transactions that deliver clear benefits to ratepayers, usually defined as some form of rate concession. And FERC has suggested that it will allow transactions that, through Regional Transmission Organization (RTO) participation, divestiture of generation and/or other market power mitigation measures, preserve and protect wholesale market competition. Barring a repeal of the Public Utility Holding Company Act (PUHCA), such deals will most likely be found where utilities have contiguous or adjoining territories, where synergies are clear, where FERC’s market power concerns are manageable, and where cost savings are sizeable enough to cre-ate benefits for both shareholders and ratepayers. At year-end 2004, the con-sensus view across the industry was that back-to-basics has about run its course as a foundation for company strategies, and that such M&A deals may represent the strategy of choice for utilities seeking earnings growth above and beyond that available from organic growth in their core territories.


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BUSINESS STRATEGIES

Divestitures

Divestiture activity in 2004 was in many ways a continuation of the trends that characterized 2003. The industry’s back-to-basics focus led to a continued strategic emphasis by most utilities on strengthening regional footprints, exit-ing international operations, divesting their lowest-returning assets (such as merchant generation and trading and marketing operations), exiting non-core businesses and focusing on core operations. Generally, core operations were characterized as some combina-tion of a regulated utility segment and a rationalized competitive generation portfolio, with a wide variation across the industry in the relative contribu-tion of each depending on the utility’s chosen corporate strategy and the nature of the regulatory regime in the markets in which it operates. The forces that restrained whole company M&A during most of 2004—Public Utility Holding Company Act (PUHCA) restrictions that thwart roll-ups and geographical expansion, credit ratings agencies wary of debt financed deals, lengthy and complex regulatory approvals, and a stock market that rewarded financial conservatism and a sturdy dividend —made divestiture of assets and groups of assets the primary outlet for compa-nies seeking to strategically reposition and rationalize asset portfolios. As was the case in 2003, divestiture proceeds were generally applied to the repayment of debt and the deleveraging of balance sheets. The following were some of the key themes related to generation dives-titures in 2004:

■ For the second straight year, the capital markets were highly accom-modative to borrowers. Despite widespread investor expectations that

interest rates would rise markedly during 2004, the 10-year Treasury in fact stayed under 4.5% for most of the year, and corporate credit spreads remained at historically tight levels. Given a lack of compelling values in the equity markets and the very low yields across the bond market, institutional investors continued to pour money into private equity part-nerships and hedge funds in search of higher returns. Private equity and hedge fund capital supported bids across the industry for divested generation assets. Analysts noted that private equity buyers participated in most of the auctions held in 2004, and some of the largest generation transactions in 2004 involved private equity buyers.

■ The stiff headwinds that private equity players faced in their efforts to acquire a whole utility operat-ing company in 2004 were notably absent in the market for generation assets, where the regulatory landscape is far less complex than it is for whole company deals. Indeed, financial players may have an advantage over regulated utilities when buying di-vested merchant generation because they do not face the same degree of market power scrutiny by the Fed-eral Energy Regulatory Commission (FERC).

■ Hedge funds have been active buyers of distressed merchant plant project financings in recent years. This type of debt traded at 40% to 50% of par a few years ago, but prices appreciated to 75% to 90% of par during 2004, indicative of investors’ stretch for yield and willingness to embrace risk. The era in which hedge funds could buy distressed merchant debt on the cheap probably ended in 2004.

■ Soaring natural gas prices supported profitability of competitive coal-fired generation, boosting cash flows for distressed companies with coal-fired merchant assets. As a result, they were generally able to avoid selling these assets at fire sale prices. Combined with their ability to easily refinance debt, this has enabled them to avoid major asset sell-offs.

■ Analysts noted that the strongest pric-ing was awarded to divested genera-tion assets with long-term contracts, assets well-placed in power markets with little capacity overhang or located in transmission constrained areas where generation is valuable. Merchant plants in markets with sig-nificant excess capacity and without long-term contracts remained harder to sell; there was little activity in that end of the market. The fact that merchant plants changed hands at all in 2004 was, in itself, noteworthy however. Some analysts estimated that one-half of plant transactions in 2004 involved merchant plants without long-term contracts, and one banker termed 2004 the “year of the merchant deal.”

■ In this environment, bank lend-ers who had taken possession of plants continued to hold out for higher prices. Some estimates are that 17,000 MW to 20,000 MW of generation is now in hands of lenders.

CenterPoint Divests Texas Genco

The $3.65 billion sale of CenterPoint Energy, Inc.’s generation subsidiary, Texas Genco, to a consortium of private equity firms was the largest purchase of power plants in the U.S. by a non-util-ity since deregulation. Announced in July, the transaction offered a showcase


BUSINESS STRATEGIES

of the forces that defined much plant divestiture activity in 2004.

The plan to sell Texas Genco was developed to comply with Texas’ 1999 restructuring law, and the divestiture now allows CenterPoint to fully con-centrate on its electricity and natural gas delivery operations. In the two-part deal, CenterPoint received $2.9 billion for its 81% stake in Texas Genco—$2.2 billion in 2004 for 11 coal, lignite and gas-fired power plants, and an addi-tional $700 million in April 2005 for its share of the South Texas Project nuclear plant. The company used the proceeds to pay down approximately $2 billion in debt in 2004, and plans to further reduce debt in 2005. GC Power Ac-quisition, the entity that acquired Texas Genco and its 14,000 MW Texas-based generation portfolio, is equally owned by four private equity firms—The

Blackstone Group, Hellman & Fried-man, Kohlberg Kravis Roberts and Texas Pacific Group.

The deal was emblematic of what attracts many private equity investors to generation assets. Texas Genco’s mer-chant portfolio of fossil and nuclear gen-eration is highly profitable in the Texas market, where the high cost of natural gas sets electricity rates and burdens the profitability of other, gas-fired merchant plants. Previous to the buyout, Center-Point had spun off 19% of the company in the form of a tracking stock. Despite strong price appreciation in 2003, the Texas Genco shares were not followed on Wall Street due to their small float, relatively light trading volume, modest dividend and a perception of complex-ity regarding accurately analyzing the value inherent in the situation. Analysts suggested that Texas Genco’s debt-free

capital structure offered the private eq-uity group flexibility to take on leverage and reduce the cost of capital, and that strategic plant expansions and fuel port-folio management could boost earnings. The investor group was expected to run Texas Genco with rolling capacity auc-tions and without long-term contracts. Notably, Kohlberg Kravis Roberts and Texas Pacific group were thwarted by regulators in their attempts to acquire regulated utilities in 2004. Their suc-cess in structuring a winning bid for Texas Genco demonstrates the lower bar financial players face when it comes to acquiring merchant assets.

Duke Divests Merchant, International Assets

Duke Energy Corporation realized over $3.1 billion in proceeds in 2004 in an aggressive portfolio realignment

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that ridded the company of a number of merchant plants, some partially constructed merchant plants and inter-national investments in the Asia-Pacific region and in Europe. The $3.1 billion figure, which included $750 million in tax benefits and $840 million in debt reduction, helped the company reduce its debt by $4.6 billion and lower its debt as a percentage of total capital to 51% by year-end. Early in 2004, Duke had set a goal of raising $1.5 billion through asset sales, but crossed that mark before mid-year.

Duke pared its merchant fleet by a third in a May 2004 agreement to sell eight merchant plants in the southeast U.S. to distressed private equity firm MatlinPatterson, who has been active in the utility sector. The 5,300 MW package included three combined-cycle and five simple-cycle gas-fired plants. Notably, only one of the eight plants had a long-term power contract. Duke received $425 million cash, a $50 mil-lion note and some $500 million in tax benefits. The transaction eliminates Duke’s merchant exposure in the south-east U.S. region.

Duke expects that its 2004 merchant divestitures will help cut losses in its merchant division, Duke Energy North America (DENA), by nearly half in 2005. Late in 2004, Duke announced it is seeking merchant generation venture partners to help it form a merchant gen-eration platform with the scope, scale and fuel diversity required to provide an attractive return on investment, and to give the venture some measure of influence over electricity market public policy in its market territories.

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TXU Restructures

Arguably the most radical restructur-ing among shareholder-owned electrics in 2004 occurred at TXU Corporation. Led by a new CEO who took control in February 2004, TXU divested debt-laden international operations, telecom and natural gas assets, reduced outstanding shares by 37%, restruc-tured its balance sheet, and reformed the company around its core opera-tions—competitive generation/electric-ity marketing and regulated electric transmission/distribution operations in its Texas ERCOT market. The largest of the divestitures were:

■ In April, the company sold its tele-communications business for $527 million in cash;

■ In June, it sold intrastate gas trans-portation subsidiary TXU Fuel to Energy Transfer Partners, L.P. for $500 million in cash;

■ In July, it completed the sale of TXU Australia to Singapore Power Ltd. for $1.9 billion in cash and $1.7 billion in assumed debt; and

■ In October, it divested TXU Gas to Atmos Energy for $1.9 billion in cash. TXU Gas was a largely regu-lated natural gas transmission and distribution business.

Overall, the transactions generated more than $6.5 billion in cash and divested debt. Combined with cash from operations, refinancings and other asset sales, TXU repurchased $6.7 billion in common equity and other securities with minimal impact on free cash flow in 2004, according to the company. Market reaction to the company’s restructuring was extraor-dinarily favorable. TXU was the third best performing stock in the S&P 500 during 2004.

AEP Completes Sales of Non-Core Assets

American Electric Power Co., Inc. (AEP) was another large utility who substantially completed its program of selling non-core assets in order to sim-plify its asset base and return its focus to core electric operations in its regional footprint—consisting of operations in the eastern (Indiana, Kentucky, Michi-gan, Ohio, Tennessee, Virginia and West Virginia) and eastern southwest (Arkansas, Louisiana, Oklahoma, and Texas) regions of the U.S. In January, AEP completed divestiture of its natural gas assets in the U.S. with the sale of 98% of its interest in Houston Pipe Line company. The company also sold some 4,000 MW of coal-fired generation in the U.K., its share of a power plant in China, four domestic plants and AEP Coal assets in Ohio and Kentucky. AEP also sold most of its Texas generating assets, but the sales were driven primar-ily to establish its level of stranded cost recovery under Texas restructuring law. AEP used the roughly $1.4 billion in divestiture proceeds to pay down debt, achieving its goal of debt below 60% of capitalization by year’s end.

Other Business Segment Divestiture Activity

Roughly 20 of the 65 publicly traded companies in the EEI universe of share-holder-owned electric utilities engaged in some type of divestiture of non-core operations last year, as shown in the table “Divestiture of Non-Core Opera-tions.” The list was created by reviewing letters to shareholders in 2004 annual reports, and by referencing discussion of 2004 events in company 10Ks. If a company viewed its divestiture activity as significant enough to mention in its letter to shareholders, it was included in the table. The motive given for the di-

vestiture was also recorded and included in the table.

Common themes seen in 2004, as in 2003, were a desire to exit under-performing and/or non-core businesses, rationalize asset portfolios, reduce debt, and focus on core generation and energy supply operations. For some utilities, this meant exiting merchant genera-tion entirely and focusing on regulated electricity and gas transmission and distribution. Others, however, retain a competitive generation portfolio (although generally with long-term contracts in place, therefore not mer-chant generation in the strictest sense) as a key element of core operations. In general, 2004 was another year of asset and business line rationalization, as utilities focused on honing in on an optimal business model that maximizes risk-adjusted return and is best suited for the regulatory regimes and business opportunities in their power markets and operating territories.

Nuclear Consolidation Continues

A trend over the past several years has been the ongoing consolidation of ownership of nuclear plants due to the efficiencies achieved through economies of scale and the specialized knowledge required to operate nuclear reactors. While top nuclear owner Exelon’s merger with PSEG exemplified this on the M&A front, the trend was also ap-parent in the divestiture arena.

On December 22, Alliant Energy Corporation put its 583 MW Duane Arnold nuclear plant up for sale. Alliant owns 70% of the plant through its Iowa utility Interstate Power and Light; two local utility co-ops own the remaining 30%. Duane Arnold’s operating license is set to expire in 2014, and Alliant stated that the plant’s customers and Al-


BUSINESS STRATEGIES

Construction

Introduction

The industry’s priority in 2004 was to focus on core utility operations, pay down debt, and return cash to shareholders. In light of this, capital expenditures rose only minimally, from $40.4 billion in 2003 to $40.9 billion in 2004 (page 61).

Shareholder-owned electric utilities placed 8,813 MW of new capacity on-line in 2004, down from 30,187 MWin 2003. Despite an overall generation surplus in 2004, local shortages re-mained in some regions of the country. An aging and overburdened transmis-sion infrastructure compounded the problem, making it diffi cult to transfer the power to capacity constrained areas. Most transmission facilities were built by vertically integrated utilities more than 30 years ago for the primary purpose of delivering power to local metropolitan areas within the utility’s

liant shareholders will be better served if the plant is sold to a company that spe-cializes in nuclear generation, who can better mitigate the fi nancial uncertainty attendant to the relicensing process. Also during 2004, Alliant attempted to close on the November 2003 an-nounced sale of its share of the 574 MW Kewaunee nuclear plant to third-ranked nuclear owner, Dominion Resources, Inc. Alliant owns a 41% share of the plant through its Wisconsin Power and Light subsidiary; the remaining 59% is owned by Wisconsin Public Service. The two owners had struck a deal with Dominion in November 2003 to sell the plant for $220 million in a transac-tion that included a long-term purchase agreement between Dominion and the two utilities for the plant’s output. The Wisconsin Public Service Commission rejected the sale in a December 2004 ruling, citing concern over the loss of regulatory oversight should the plant become an exempt wholesale genera-tor under Dominion’s ownership, and be regulated by FERC and not by the state. (The Commission approved the

sale in March 2005 when the deal was restructured to address its concerns.)

On June 10, 2004, Constellation Energy Group, Inc. closed on its pur-chase of the 495 MW Ginna nuclear plant from Energy East Corporation subsidiary Rochester Gas & Electric Corporation (RG&E). Constellation paid $457.3 million for the plant, and received $200.8 million in decommis-sioning funds as part of the deal. RG&E will buy 90% of the plant’s output under a power purchase agreement through June 2014.

While the industry’s second ranked nuclear owner, Entergy Corporation, was not on the buy side of either of the two transactions, the company stated in 2004 that nuclear generation is a core part of its growth strategy and that it is actively seeking acquisition opportunities.

High natural gas prices have pro-duced strong profits for baseload nuclear generation in many electricity markets, enhancing the value of these assets. However, the industry’s emphasis

on fuel portfolio diver-sity, along with the profi t-ability of these plants, has caused some to predict that single-plant own-ers may favor retaining ownership while farming out operations to a more experienced operator through a management services arrangement or an operating lease. This allows the owner to retain control over the facility’s output, while the fleet operator profits from running the plant using best practices developed at its own facilities.

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territory. In order to serve the needs of competitive wholesale markets, this same infrastructure is now being used to transfer power over much larger distances and across multiple utility territories, putting additional strain on the system.

The industry has responded to this by reversing a trend of declining transmission investments. Over the past fi ve years, transmission spending has increased at an annual rate of 5.6% percent. In 2004, shareholder-owned electric utilities invested $4.5 billion in transmission. Distribution spending was also up, reaching $13.0 billion, a 14% increase. This was due in part to recovery from one of the most devastating hurricane seasons in history.

Generation

The overall surplus of capacity nationwide persisted during 2004 due to the competitive generation build-out of previous years. In fact, assuming all generating units ran at only 50% capacity, there still would have been excess capacity. However, some regional markets remained capacity constrained. Cali-fornia, for example, imported electricity from nearby states and continued to face the threat of rolling blackouts on peak summer days (see chart on page 62).

The combination of new plant construction and expan-sions of existing plants added 8,813 MW to the grid in 2004, compared to 30,187 MW in 2003. Tight capital expenditure

budgets and existing surplus capacity led to more projects being cancelled than completed. About 6,305 MW of the total capacity increase was due to new plant construction and 2,508 was due to expansion projects at existing plants, including nuclear plant uprates.

ECAR saw the greatest increase in capacity with SERC not far behind. In each region, two new combined cycle natural gas plants were built, accounting for the majority of the increase.

Only MAPP, MAAC and FRCC saw more capacity brought online than put on hold or cancelled in 2004. No projects were cancelled in these regions. By contrast, ERCOT and SPP brought no new capacity online, can-celing 500 MW and 2,000 MW respectively. This may indicate that most of the country’s surplus capacity exists in ERCOT and SPP and that the Midwest, mid-Atlantic, and Florida brought needed generation online in 2004.


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New Plant Construction

Just 12 new plants were built in 2004 by shareholder-owned electric utilities, consisting of nine natural gas plants, two wind plants and one biomass plant. There was an increasing focus on renew-able energy, as six additional states either passed legislation or began to imple-ment a renewable portfolio standard (RPS). This included Colorado, which became the fi rst state to enact an RPS via a voter ballot initiative. By Decem-ber 31, 2004, 18 states and the District of Columbia had a RPS in place, with specifi c requirements varying by state.

The primary renewable fuel of choice in 2004 was wind, with two wind plants totaling 305 MW coming online. The economics of wind power are improv-ing, particularly in light of high natural gas prices. However, siting wind plants continues to be a challenge, as the best locations are often far from existing transmission lines. The on again/off again federal production tax credit has led to peaks and valleys of wind construction. The credit, originally

enacted in 1992, provides a 1.8 cent per kWh credit for electricity gener-ated from wind for the fi rst ten years of operation. This has encouraged invest-ment and helped make the technology cost competitive with other generation sources. The 305 MW of new capacity

in 2004 was less than half the 656 MW of wind generation that came online in 2003, due in part to the expiration of the credit at the end of 2003. Late in 2004 however, Congress approved an extension of the wind energy tax credit through the end of 2005.

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MidAmerican Ener-gy and FPL Group built wind farms in Iowa and Wyoming, respectively, ac-counting for the new 2004 capacity. MidAmerican’s Storm Lake Wind Farm is part of a larger $323 mil-lion project to build wind facilities at two different locations in Iowa, for a total of 310 MW of capac-ity. The Storm Lake site consists of 107 1.5 MW wind turbines. FPL’s Wyo-ming Wind Energy Center, estimated to cost $150 million, consists of 80 1.8 MW wind turbines totaling 144 MW of capacity, and is Wyoming’s largest wind farm.

Arizona Public Service (APS), Pin-nacle West’s regulated subsidiary, built the Eager Biomass plant in 2004. The plant is expected to utilize 96 tons of wood to produce 3 MW of electricity, using trees cleared from nearby forests as a part of thinning efforts to control forest fi res. The plant, likely to be the fi rst of several, will help APS meet its obligation under Arizona’s renewable portfolio standard, which requires that

1.1% of APS’ generation come from renewable sources by 2007. Project cost was approximately $4 million.

The top fi ve owners of new plants that came online in 2004 are shown in the table below. With the excep-tion of MidAmerican’s capacity, which included some wind, all was combined cycle natural gas generation. These top fi ve owners accounted for 81% of the 6,305 MW of capacity from new plants that came online in 2004.

New plants built in the competitive sector continued to outnumber those

built in rate base, although the trend is shifting toward construction taking place in rate base where cost recovery is more certain.

Expansions of Existing Plants

Natural gas also accounted for the bulk of plant expansion projects in 2004, although 14 nuclear plants received uprates, accounting for that sector’s capacity additions (see chart on page 64).

Nuclear plant license renewals con-tinued in 2004 with an additional 11 plants fi ling applications with the Nu-clear Regulatory Commission (NRC) (see page 65). Several utilities, including Dominion, Exelon and Entergy, formed consortiums that received funding from the Department of Energy (DOE) to study potential sites for a next genera-tion nuclear plant.

On Hold/Cancelled Plants

Surplus capacity and rising natural gas prices have led many utilities to put plant construction projects on hold or to cancel them. In 2003, 100 projects totaling 27,110 MW were placed on hold or cancelled compared to the 30,187 MW that came online. In 2004,the amount of capacity put on hold or

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cancelled (15,397 MW) nearly doubled the capacity that came online, but was almost half of what was put on hold or cancelled in 2003. As with the capacity additions, natural gas plants account for the bulk of those projects put on hold or cancelled (see chart at right).

MAIN saw the most activity in both 2003 and 2004. Madison Gas and Electric cancelled two wind projects. Wisconsin Public Service and Wisconsin Electric Power each cancelled several natural gas plants in Wisconsin, and Cinergy, FirstEnergy and CMS Energy all cancelled natural gas projects in Illinois.

Environmental Capital Expendi-tures

Even though President Bush’s Clear Skies legislation was not enacted in 2004, existing federal environmental

regulations (such as the Clean Air Act) and anticipation of future regulations drove investments in emissions reduc-tion technologies. Some companies are choosing to make upgrades in advance

of anticipated regulations, while oth-ers are waiting until requirements are known to ensure greater certainty that they are making economical invest-ments.

Facing pressure from investors and other stakeholders, American Elec-tric Power (AEP), Cinergy and TXU released reports in 2004 that assessed financial risks from possible future regulation of greenhouse gas emissions. Each utility focused on different aspects of environmental compliance, but all three highlighted regulatory uncertainty as the largest risk since the many emis-sion control proposals currently being considered by Congress differ in ap-proach and requirements

AEP modeled the various costs asso-ciated with proposed emissions control legislation and regulation, and conclud-ed it would have to spend a minimum of $3.5 billion through 2010 on compli-ance. Cinergy laid out a program that will budget approximately $1.6 to $2.1 billion over the next ten years to install scrubbers and mercury control equip-ment, regardless of whether emission control policies are enacted. Cinergy

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plans to focus on its largest plants fi rst, embarking on projects that would be required under a variety of regulatory scenarios. Once the regulatory environ-ment is more certain, it plans to expand the program to smaller facilities. TXU described its internal procedures for evaluating the impact of pro-posed regulations, and outlined its approach to risk mitigation. This includes increasing renewable generation and research and devel-opment of new emission reduction technologies.

Each company expects that, once regulations are fi nalized, in-vestments in environmental control technologies will be recoverable through rates in regulated environ-ments and through market-based rates in deregulated environments. Four additional utilities (Southern Co., Progress Energy, DTE Energy and FirstEnergy) announced dur-ing 2004 that they plan to release similar reports.

Transmission

While a surplus of generation ca-pacity currently exists for the nation as a whole, the opposite is true for transmission. Signifi cant attention was

placed on transmission in 2004 due to increasing congestion, but few major projects were completed. Building new transmission lines continues to be a challenge. Siting of new lines requires


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complex permitting procedures and lengthy review processes that increase the risk of delays and disapprovals. Financing of transmission built outside of a vertically integrated utility is also burdened by uncertainty over transmis-sion business models, whether costs can be recovered in rates, and what kind of return on investment can be expected. Despite these barriers, transmission spending by the industry as a whole in 2004 increased over 2003, and a hand-ful of new projects were completed.

The Data

Total transmission capital expendi-tures in 2004 increased for the fi fth year in a row, to $4.5 billion (preliminary). Increases in transmission investment from 2000 to 2004 averaged $220 mil-lion per year (+5.6% annually). Some of the most signifi cant increases over the past fi ve years were made by Dominion, Southern Co., Entergy, Northeast Utili-ties, Edison International (Southern California Edison Co.), Pacificorp, American Transmission Company, PNM Resources and Sierra Pacific Resources.

Of the total transmission capital expenditure, approximately 47% was

spent on transmission line equipment (i.e. conductors, towers, poles, etc.) and approximately 53% was spent on transmission station construction (i.e. transformers, etc.). The majority of transmission projects completed in 2004 were focused on smaller lines di-rected at solving local concerns. There continued to be a lack of investment in long distance lines that cross utility or regional boundaries, partially because of the uncertainty for cost recovery. Local fi xes with direct impacts on a utility’s customer base are more likely to be approved by regulators for cost recovery than are larger projects that create benefi ts both within and outside of the utilities’ customer base.

The Challenges

Transmission line congestion in-creased again in 2004, particularly through the fi rst half of the year, peak-ing in July (see chart above). Overall, the number of Transmission Loading Relief (TLR) procedures, which occur when line congestion increases to the point where service may be curtailed, increased 16% over 2003 and 55% over 2002.

In an effort to address rising conges-tion, the DOE held a workshop and so-licited comments on the Department’s procedures for identifying and remedy-ing National Interest Electric Transmis-sion Bottlenecks. The California Path 15 transmission line and the Southwest Connecticut and Northwest Vermont areas were identifi ed as among the worst bottlenecks in the country.

The completion of the California Path 15 upgrade was a major success story in 2004, and established a model for how government and industry can cooperate to build needed transmission. The Path 15 transmission network con-nects northern and southern California. After the crisis in California in 2001, it was identifi ed by DOE as one of the worst transmission bottlenecks in the country. DOE subsequently asked the Western Area Power Administration (WAPA) to work with private industry to relieve the congestion. WAPA part-nered with Pacifi c Gas & Electric Co. and Trans-Elect to build an 84-mile 500 kV AC transmission line. Completed in December 2004, the project cost $250 million and increased transmis-sion capacity by 1500 MW. Trans-Elect provided most of the fi nancing and retained most of the transmission rights. The California Independent System Operator (ISO) operates the line.

In the northeastern U.S., as in most other regions, it is very diffi cult to site new lines. Even projects planned along existing transmission corridors face opposition. Southwestern Connecticut was identified by the New England ISO as having particularly congested transmission, costing consumers over $300 million annually. Yet local utili-ties experienced signifi cant opposition from communities concerned over the health impact of a proposed new line. The Connecticut Siting Council spent


BUSINESS STRATEGIES

most of 2004 hearing comments and reviewing studies of the technological feasibility and reliability impact of burying segments of the new line un-derground, even at a cost that could exceed $1 billion.

Vermont experienced similar prob-lems with the $130 million Northwest Vermont Reliability Project, a plan to construct a 52-mile 345 kV line (to be built alongside an existing line) and to replace two 46 kV and 34.5 kV lines with 115 kV lines. Local towns and the Conservation Law Foundation argued that the local utility should implement demand side management programs and explore other alternatives before constructing new lines.

Individual states have taken differ-ent approaches to solving transmission problems. In the West, state legislatures have established transmission authori-ties to overcome barriers to construc-tion. Western states have also been working together through the Western Governor’s Association to solve energy issues. The Wyoming state legislature established a transmission authority in 2004 to streamline siting and con-struction in order to improve access to generation and to facilitate the export of Wyoming energy. The new transmission authority will consist of a five member board appointed by the governor and will offer up to $1 billion in credit to public and private developers who fund new transmission projects. As a last resort, the new authority may develop projects on its own.

In Minnesota, five utilities with transmission assets created a consor-tium, called CapX 2020, to study the adequacy of the Minnesota transmission infrastructure for current and future demand, and to develop a plan for ad-dressing deficiencies. In other states,

legislators, regulators, and utilities have been exploring solutions to transmis-sion congestion by providing greater certainty for cost recovery. Options considered include laws that provide for pre-approval of guaranteed cost recovery and allow rate adjustments prior to beginning projects.

Cooperation among utilities, fed-eral and state governments, and local communities is becoming essential for building new transmission facilities.

Distribution

Distribution lines, typically less than 39 kV, connect retail users to local sub-stations. They are typically less costly and less controversial to build than transmission lines, although in recent years the issue of burying the lines un-derground has sparked heated debate in local communities over cost, reliability and aesthetics. In 2004, spending on distribution lines by shareholder-owned electric utilities jumped from $11.4 bil-lion to $13.0 billion. Companies that saw the largest increases over 2003 were Vectren, UniSource Energy and Westar Energy.

The 2004 hurricane season was one of the most devastating in recent memory, leaving Florida utilities with repair costs that exceeded storm damage reserves. The four hurricanes that struck Florida in September 2004 caused over $1.3 billion in damage to the state’s shareholder-owned utilities (primarily to transmission and distribution sys-tems). Hardest hit were FPL Group and Progress Energy, with approximately $890 million and $398 million in as-sociated costs, respectively. The utilities pursued a mix of solutions, including seeking reimbursement through a sur-charge on customer bills.

In the wake of the hurricanes, lo-cal policymakers and communities in Florida have been debating the ad-vantages and disadvantages of burying more lines. Above ground lines are more susceptible to storm damage but easier and cheaper to repair. Underground lines are more aesthetically appealing, but cost an estimated ten times more to install than above ground lines, and it often takes longer to locate and fix prob-lems. Only about 40% of Florida Power & Light Co.’s distribution lines are underground vs. 84% of the company’s new lines. In general, underground lines fared better through the hurricanes, but the high costs of burying the wires and determining cost recovery continue to be impediments for undergrounding existing lines. Over the past ten years, about half of the investment in new distribution lines by the U.S. share-holder-owned electric utilities has been for underground lines.

Looking Forward

While the industry had a surplus of capacity in 2004, projections show that demand will catch up with supply by the end of the decade, and utilities are now planning how to best meet future demand. Rate caps imposed by deregulation will be expiring in many states over the next few years, which may prompt some utilities to look to rates to pay for new infrastructure investments.

State renewable portfolio standards are expected to continue to grow in popularity, and a trend is developing where clean but non-renewable gen-eration, such as integrated gasification combined cycle (IGCC) coal plants and emissions-free nuclear plants, are being considered for inclusion in a RPS. Lack of transmission access to prime renewable resources will increasingly be


BUSINESS STRATEGIES

Fuel Sources

Summary

The importance of a diverse fuel portfolio continued to be evident dur-ing 2004. Natural gas prices remained at historically high levels in response to supply constraints, which in turn resulted in higher power prices for ratepayers in regions dependent on natural gas generation, especially the Northeast. Yet natural gas as a source of electric generation increased slightly during the year, primarily because the majority of new plant additions in 2004 were gas-fired plants.

a problem as utilities attempt to meet state RPS requirements. Wind, in par-ticular, faces this challenge as the best locations are often far from transmission lines. In some cases, companies are ex-ploring co-locating wind turbines and new coal plants to solve transmission siting and interconnection issues for the wind turbine and emissions concerns for the coal plant.

Regional cooperation and state trans-mission authorities in western states are looking to export power and improve access to renewable energy resources based on the Wyoming model. The Montana, North Dakota and South Da-kota state legislatures each approved the formation of transmission authorities in early 2005. In addition, the Western Governor’s Association is studying ways for western states to work together to solve energy concerns, including build-ing long distance interstate transmission lines that deliver power (particularly renewables) to regions where additional power is needed.

Over the next few years, the industry expects to make additional investments in generation, transmission and dis-tribution to meet growing, long-term energy demand. In 2004, over 12,000 MW of new plant projects were an-nounced, up from the nearly 9,000 MW that were announced in 2003. The ma-jority are still natural gas plants, but coal is closing the gap. In a high natural gas price environment, even with the ad-dition of emissions control equipment, coal plants are price competitive and provide the added benefit of reliance on an abundant domestic fuel source. About half of this announced capacity has completed the feasibility/permitting stage or is under construction. AEP and Cinergy are identifying potential sites for state-of-the art IGCC plants, and Entergy, Exelon, Dominion Resources

and others are working with DOE and NRC to identify possible locations for a next generation nuclear plant. For the near term, new plants are likely to be built in the regulated sector so that costs can be recovered in rate base. Nearly two-thirds (8,000 MW) of the plants announced in 2004 are expected to be regulated plants.

Proposed transmission projects in the East are focused on relieving congestion and improving reliability. Projects in the West are geared toward exporting excess power from states with lower de-mand (like New Mexico) to those with higher demand (like California). EEI’s annual survey (administered in spring 2005) showed that shareholder-owned electric utilities are planning to invest over $23 billion in transmission over the 2005-2008 timeframe, including $5.7 billion in 2005. This continues the trend of steady increases in spending on transmission since 1999.

Having largely recovered from the financial difficulties of recent years, the industry is now poised to increase capital investment.

High natural gas prices have led to revived interest in coal and nuclear gen-eration for long-term baseload require-ments. While spot market coal prices reached new highs in 2004, utilities were largely protected as most received deliveries through long-term contracts. Eastern coal prices rose due to mine permitting challenges, reserve degra-dation (which resulted in decreasing productivity and rising operating costs) and a heightened demand for Eastern coal in the international market.

The utility industry has been plan-ning for the additional capacity needed to meet long-term growth in electricity demand and to mitigate exposure to high fuel prices. This was evident in utility announcements in 2004 of plans for new coal and renewable generation. Also evident was momentum toward re-energizing the nuclear industry as seen in a cost-sharing program between the U.S. Department of Energy and the nuclear industry to identify new sites for nuclear plants, to develop advanced nuclear generation technologies, and to test regulatory processes that would lead to an application to the NRC to build the first new nuclear plant in years.

In 2004, several utilities (includ-ing American Electric Power, Cinergy and TXU) responded to shareholder requests to report on the business and financial risks they face from the possi-bility of stricter emissions regulations in response to global warming. There was also increased political momentum na-tionwide in 2004 in support of renew-able energy. A number of states adopted renewable portfolio standards (RPS), and renewables are becoming attractive to utilities as a mechanism for hedging fuel portfolios against higher fossil fuel prices, especially natural gas.


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Coal

Coal is the primary fuel used for electric generation in the United States. In 2004, 50.0% of electricity was gener-ated from coal versus 50.8% in 2003. According to EIA’s U.S. Coal Supply and Demand: 2004 Review, U.S. coal exports in 2004 rose 11.6% from 2003 and imports increased 8.9%. U.S. coal production levels increased 3.7% in 2004 compared to a 2.3% decline in 2003. Total domestic coal consump-tion increased 0.9% in 2004, while total consumption by the electric power sector rose 1.0%.

The price of exported U.S. coal reached new levels, increasing by 50.4% to $54.11 per short ton by year-end in response to the tightening supply in the world market and the weakening U.S. dollar. China’s strong economy boosted already strong coal demand and restrict-ed supply to world markets as China shifted from being a net exporter of coal to a net importer. Strong economic growth increased demand for U.S. coal in several other Asian countries as well, including Japan, Korea, Taiwan and India. Additionally, European demand skyrocketed in 2004 as Europe experi-enced one of the hottest summers on

record and a drought forced cutbacks at nuclear plants due to cooling water shortfalls.

Coal prices to electric utilities in-creased in 2004 for the fourth straight year, rising from 125.0 cents/million Btu in 2003 to 134.0 cents/million Btu in 2004. Prices increased most sig-nificantly for Eastern coal sold on the spot market. However, since utilities typically enter long-term contracts for coal delivery, most were able to protect themselves from rising coal prices in 2004. In general, the effect of higher coal prices will be staggered among utili-ties and not fully felt until 2006.


BUSINESS STRATEGIES

The total cost to produce electric-ity with coal, including fuel costs plus operations and maintenance (O&M), is significantly lower than with natural gas or oil, and marginally less than nuclear. In 2003, the average cost to produce electricity from coal was $18.12 MWh ($13.41 fuel, $4.71 O&M). 2004 cost data will be released by the EIA in the fall of 2005. Despite the upward trend in coal prices, coal remains a dependable and economical fuel source that can produce low-cost electricity. The U.S. has vast domestic coal resources, with enough recoverable coal to last over 200 years if current consumption and recov-ery rates continue. The United States also has the largest share of the world’s recoverable reserves, at 25%, followed by the former Soviet Union and China with 23% and 12%, respectively. Be-cause of these advantages, many utilities are emphasizing coal in their long-term fuel portfolio planning and regulators are generally supportive. In 2004, for example, Colorado state regulators ap-proved the construction of a new Xcel Energy 750 MW coal facility. This was the first coal plant approved by the state in 23 years.

Transportation of coal from the mine to the generator continued to pose dif-ficulties in 2004 as railroads experienced bottlenecks from record levels of com-modities being moved to meet strong domestic and international demand. Several utilities experienced delays in coal delivery as a result. Railroads had reduced their labor forces during the 2001 economic downturn, and during 2004 the largest railroads in the West (Union Pacific Railroad and Burlington Northern Santa Fe Railway) and the largest in the East (CSX Corporation) were overwhelmed by surging coal demand.

Erratic coal deliveries resulted in low coal stocks for utilities. According to EIA, year-end 2004 coal stocks in the electric power sector declined by 12.2% from 2003 levels, to 106.7 million short tons in 2004 versus 121.6 million short tons in 2003. Even though utilities could have replenished coal stocks by purchasing on the spot market, several refrained due to concern that this would bump deliveries of less expensive coal already purchased through long-term contracts. While most utilities currently have long-term contracts with railroads, many contracts will expire in the next several years. Railroads are seeking to secure longer-term (i.e. three-year) con-tracts at rates that are more expensive than current contracts.

Eastern coal prices rose throughout the year due to a large supply and demand imbalance in the central and northern Appalachian regions. In ad-dition to the recovering U.S. economy and the cost advantage of coal over natural gas and petroleum, coal prices were pushed higher by rising interna-tional demand for metallurgical coal, which originates primarily from eastern mines. Mine investment over the past few years has been relatively low in this region for several reasons. Legal challenges have prolonged the environ-mental review needed to obtain mining permits to open new or expand current mines, and eastern reserve degradation has resulted in decreased productivity and increasing operating costs. More-over, there were six sizable bankruptcies in the region during 2002-2003, and the affects of those on production were still felt during 2004. Well-financed companies are now acquiring some of the bankrupt companies, and high spot prices are providing incentives for new investment in the region.

Utilities are attracted to western coal from the Powder River Basin (PRB) because it is less expensive than east-ern coal. The PRB is relatively easy to mine because coal is close to the earth’s surface, and it has low sulfur content. On the other hand, PRB coal produces more ash and carbon dioxide than East-ern coal and it has a lower Btu content, making it impossible for some coal-fired plants to use it.

The abundant supply of coal in the U.S., rising natural gas prices and regu-latory mandates such as the Environ-mental Protection Agency’s new Clean Air Interstate Rule (CAIR) have encour-aged utilities to develop technologies that remove or minimize emissions. Integrated gasification combined cycle plants (IGCC), which received a great deal attention in 2004, turn coal into gas and remove sulfur dioxide, carbon dioxide, and other emissions before electricity is generated. Currently, there are four coal-fired IGCC facilities in operation around the world, and two are in the U.S. Five new IGCC plants, with a total capacity of 2,900 MW, are in the planning stage in the U.S. American Electric Power (AEP) and PSI Energy (a subsidiary of Cinergy Corporation) are each considering constructing an IGCC plant. AEP is making progress in siting a 1,200 MW IGCC plant in either south-ern Ohio, northern Kentucky or West Virginia. AEP plans to construct at least one commercial, baseload IGCC plant by 2010. PSI Energy signed a letter of intent with General Electric and Bechtel to study the feasibility of building a 500 MW to 600 MW IGCC plant. Since cost estimates for building these plants run up to $1.0 billion, the utilities are seeking commitments from regulators for rate recovery.


BUSINESS STRATEGIES

In order to comply with state and federal emissions standards, companies that use coal for electric generation have been making large investments to re-duce emissions, and a number of states have allowed emissions remediation equipment to be captured in rate base. Cinergy, for example, was granted a rate increase in May 2004 by the Indiana Utility Regulatory Commission. Elec-tricity rates for customers of Cingery’s subsidiary, PSI Energy, will increase on average by 8.36%. The main reason

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Cinergy cited for the rate increase was the huge capital investment needed to comply with current environmental regulations. In anticipation of stronger environmental rules, Cinergy’s utility operating companies began an environ-mental construction program in 2004 to reduce overall plant emissions. The estimated cost is approximately $1.8 billion over the next five years.

As part of President Bush’s Clean Coal Power Initiative, the U.S. Depart-ment of Energy (DOE) will provide

approximately $280.0 million through 2007 to support de-velopment of technologies that reduce coal-fired plant emissions. In 2004, Wisconsin Energy (We Energies) received $24.8 million to test the Electric Power Research Institute’s (EPRI) patented TOX-ECON™ process that can reduce mercury emissions by as much as 90.0%, and possibly reduce sulfur dioxide (SO

2) and nitrogen oxide

(NOx). We Energies will test the

process at its Presque Isle Power Plant in Marquette, Michigan in a five-year pilot project. Another company that received funding under DOE’s Clean Coal Power Initiative was Southern Company. Southern will build a 285 MW coal gasification plant in Orange County, Florida, and estimates that the plant will emit 25% less carbon dioxide than current plants, and significantly less SO

2,

NOx and mercury.

Duke Energy, in a voluntary agreement with the South Caro-lina Department of Health & En-vironmental Control, will install $7.2 million worth of additional air pollution controls to a 370 MW coal plant in the state. Under an agreement reached with the Colorado Public Utilities Com-

mission in 2004, Xcel Energy will install pollution controls at its proposed 750 MW Comanche 3 plant near Pueblo, Colorado. The company also agreed to retrofit the 660 MW of existing coal capacity at the facility.

In response to shareholder requests, American Electric Power (AEP), Cin-ergy, and TXU released reports during 2004 on the business and financial risks the companies face as a result of emissions from coal-fired plants and


BUSINESS STRATEGIES

the potential for enactment of future federal legislation that would limit CO

2 emissions in response to global

warming concerns. Southern Company, FirstEnergy, Progress Energy and DTE Energy have also agreed to issue reports at their annual stakeholder meetings in the spring of 2005.

Nuclear

The share of total electricity gener-ated from nuclear energy rose from 19.7% in 2003 to 19.9% in 2004. The increase was due in part to fewer plant outages in 2004 than in 2003 from scheduled maintenance, operational issues and/or refueling. FirstEnergy Corporation’s Davis-Besse plant, for example, came back online in 2004 fol-lowing an outage of nearly two years for reactor replacement, refueling and other equipment improvements. The high cost of natural gas also contributed to the increase. In 2003, the average cost to produce electricity from nuclear power was $18.86 MWh ($5.03 fuel, $13.83 non-fuel O&M) compared with $54.48 MWh ($48.69 fuel, $5.79 non-fuel O&M) from natural gas.

Nuclear energy produces no emis-sions, is relatively inexpensive compared to other fuels, and the uranium used to fuel nuclear plants is domestically abun-dant. Nuclear power is a partial solution to the nation’s dependence on imported fossil fuels and growing demand for power. Due to these advantages, interest in building nuclear generation mounted in 2004. There are currently 103 op-erating nuclear reactors in the U.S., operated by 32 companies. According to the Nuclear Energy Institute (NEI), nuclear power currently accounts for the largest percentage of electric genera-tion in seven states—Vermont (73.7%), South Carolina (54.5%), Connecticut (54.4%), New Jersey (51.9%), Illinois

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(50.1%), New Hampshire (43.0%), and New York (29.8%).

Nuclear energy also received support in 2004 from the Bush administration, who views it as a long-term solution to high natural gas and petroleum prices, and as a means to reduce emissions. Through the DOE’s Nuclear Power 2010 Program, the agency is seeking to reduce technical, regulatory and institutional barriers to the deployment of new nuclear facilities. This govern-ment/industry cost-sharing program was announced in 2002 and seeks to identify sites for new nuclear power plants, to develop advanced nuclear plant technologies, and to test the regu-latory processes involved with seeking NRC approval to build and operate an advanced nuclear power plant. DOE is funding part of the costs associated with

the Early Site Permit (ESP) applications that Dominion, Entergy and Exelon have submitted to the NRC. The ESP permits allow the companies to “bank” the sites approved by the Nuclear Regu-latory Commission (NRC) for up to 20 years. These permits serve as a way to prevent future siting challenges. In February 2005, the Bush Administra-tion also signed a multilateral agreement with 11 countries aimed at accelerating research and development of next gen-eration nuclear energy technologies.

The DOE is also working with the utility industry to develop guidance for application preparation for combined nuclear plant construction and operat-ing licenses (COL). COLs grant permis-sion to build and operate a new plant, thereby addressing all public regulatory and safety concerns prior to the start of


BUSINESS STRATEGIES

construction. Three industry consortia have submitted applications to DOE in order to test the COL process, includ-ing NuStart Energy Development LLC (a partnership of 11 energy companies that includes Constellation Genera-tion Group, Entergy Nuclear, Exelon Generation, Southern Company, Duke Energy, Progress Energy and Florida Power & Light); a group led by Do-minion; and one led by the Tennessee Valley Authority (TVA).

For nuclear power to achieve wide-spread public support, however, the spent fuel storage issue must be re-solved. In the late 1980s, the U.S. Congress selected Yucca Mountain in Nevada (outside Las Vegas) as a reposi-tory for spent fuel, but there remains strong political opposition to the plan due to the perception that transporting radioactive spent fuel across country entails risk of a catastrophic accident or terrorist attack, and there is strong

opposition to the Yucca Mountain project from state government offi cials in Nevada. Nuclear generators in the U.S. can safely store spent nuclear fuel on site, but a permanent long-term solution is lacking.

Natural Gas

Despite high natural gas prices, natu-ral gas as a source of electric generation rose from a 17.1% share of generation in 2003 to 18.1% in 2004, primarily because the majority of new plants that came online during the year were fi red by natural gas. The average price utili-ties paid for natural gas rose from 551.0 cents/million Btu in 2003 to 605.0 cents/million Btu in 2004.

Strong industrial and utility sector demand for natural gas continues to strain available supply, while current domestic sources of natural gas are in decline and natural gas producers are having a hard time developing new

sources because many are located on federal lands closed to drilling. Other federal and state restrictions prevent drilling onshore and offshore in both the east and west coasts, the eastern Gulf of Mexico, and across large portions of the Rocky Mountains. These areas are believed to contain natural gas, but are essentially closed to exploration.

According to the EIA, the majority of natural gas consumed in the U.S. comes from domestic gas production. The rest comes from imports, primarily from Canada which provides approxi-mately 15.0% of the total U.S supply. The American Gas Foundation expects that by 2020, this will decline to 8.0% as Canada aims to meet its growing domestic demand and the Western Canadian Sedimentary Basin reaches maturity. The group estimates that approximately 93.0% of the world’s natural gas reserves are located outside of North America.

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BUSINESS STRATEGIES

Importation of liquefied natural gas (LNG) has been widely touted as a solution to current supply prob-lems. The EIA reported that in 2004 LNG imports increased 29%, yet this increased the country’s total natural gas supply by only 3%. Trinidad and Tobago currently supply the U.S. with approximately 75.0% of its imported LNG. Other countries that export to the U.S. include Algeria, Nigeria, Qatar, Oman and Malaysia. Critics of LNG argue that it only increases dependence of foreign fuel, and there are problems using the natural gas transportation and generation infrastructure due to LNG’s high BTU content.

There are five LNG terminals in the U.S. The Federal Energy Regulatory Commission (FERC) is responsible for onshore facility approval and has given the go-ahead for construction of eight additional terminals. Maritime Admin-istration (MARAD)/Coast Guard are responsible for deepwater and offshore port approval, and they have approved two more. Twenty-two additional ter-minals have been proposed by develop-ers, but there is substantial opposition to construction of new LNG terminals in most prospective locations, centering primarily around the NIMBY (not in my back yard) problem. Calpine, for example, decided to cancel a potential project due to community opposition. There have also been siting disputes between states and the FERC. In California, the FERC issued an order stating that siting authority for new LNG terminals lies with the federal government, while the California Public Utilities Commission (CPUC) argued that states should have this role. The CPUC has filed at the U.S. Court of Appeals challenging FERC’s decision. If LNG is to play a role in meeting long-term demand, greater certainty

is clearly needed regarding who has siting authority. The Energy Policy Act of 2005, if passed, will give this to the FERC, streamlining the approval process for the development of these facilities. Due to the recent natural gas generation build-out (beginning in the mid-1990s), the majority of new plants placed online in recent years have been natural gas-fired. Therefore, strong de-mand for natural gas will likely continue well into the future.

Other

In 2004, 9.0% of total electricity generation was derived from “Other” sources, defined as hydropower and renewables, versus 9.3% in 2003. However, considerable political mo-mentum in favor of renewable energy was evident in 2004, driven by high and volatile fossil fuel costs, increasing public support for clean energy and the growing concern over global warming. Several states adopted Renewable Port-folio Standards (RPS) in 2004, which require utilities serving load in the state to supply a certain percentage of power from renewable sources. RPS have now been implemented in 18 states plus the District of Columbia.

Renewal of the federal Production Tax Credit (PTC) for wind, biomass, solar and geothermal energy was an enormous impetus to renewable energy construction in 2004. Energy compa-nies building wind generation receive a tax credit of 1.8 cents per kWh of electricity produced in the first 20 years of a project. In 2004, this production tax credit was renewed and extended through January 2006, and the Bush administration’s budget proposal in-cludes the assumption that the tax credit will be extended though fiscal year 2007. So far, the PTC has been subject to annual approval, creating a boom and

bust cycle for renewable construction. A more permanent credit would create greater certainty for renewable energy developers. Rising natural gas and coal prices (which fuel the majority of U.S. power generation), coupled with the PTC, make renewables an increasingly attractive means for utilities to diversify fuel portfolios.

Despite the environmental benefits of renewable energy, persistent NIMBY issues continue to thwart development in some areas of the country. One of the most publicized cases of 2004 concerned the Cape Wind project. If approved, this project would be the first offshore wind farm in the United States, located five miles off the south coast of Cape Cod, Massachusetts on Horseshoe Shoal. Cape Wind would provide 420 MW of capacity, and con-sist of 130 wind turbines. The project is opposed by some vacation homeowners and tourist industry groups who con-sider it a potential eyesore that could degrade the area’s appeal as a vacation destination. The project is currently under review. A draft Environmental Impact Statement was issued in No-vember 2004 and public hearings were conducted. Approximately 4,000 com-ments were received.

Some utilities are responding to ratepayers’ requests for clean energy by offering renewable power at a premium to standard electric rates. Through FPL’s Sunshine Energy Program, for example, rate payers have the option to choose energy from renewable sources (i.e. wind, solar, and hydro). Participating customers continue to pay standard rates for the energy consumed each month, but also pay a $10 monthly surcharge that covers the costs of gen-erating a fixed 1,000 kWh of electricity from clean sources.


BUSINESS STRATEGIES

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BUSINESS STRATEGIES

2004 was a challenging year for hydroelectric generation, as lower than normal rainfall occurred in many areas with hydro facilities. While the cost to produce electricity from hydro is less than from coal, nuclear and natural gas, the unpredictable nature of water flow reduces supply certainty. In the beginning of 2005, Avista Utilities announced that due to a warm, dry 2004-2005 winter, hydro operations are expected to be below normal and other resources will be tapped to meet demand in 2005. The company oper-ates eight hydroelectric facilities that can generate 980 MW. Avista estimates that hydro generation will be 80% of the normal rate in 2005.

Oil

Oil accounted for 3.0% of electricity generation in 2004 compared to 3.1% in 2003. The average cost utilities paid for oil rose from 485.0 cents/million Btu in 2003 to 514.0 cents/million Btu. The average cost to produce electricity from oil in 2003 was $60.97 MWh ($49.33 fuel, $11.64 non-fuel O&M).

Oil prices remained extraordinarily high and volatile throughout 2004. Strong economic growth in develop-ing nations, such as India and China, is straining global production capac-ity. Factors that inhibited production included the war in Iraq, damage to offshore oil platforms in the Caribbean, civil unrest in oil-producing Nigeria, and the failure of OPEC to bring prices down by dipping into sparse capacity. Oil prices were at record levels when measured in nominal terms during 2004, but when adjusted for inflation the price of oil remained below its his-toric peak reached in 1981.


CAPITAL MARKETS

Capital MarketsSTOCK PERFORMANCE

EEI Index Outperforms Overall Markets, Up 22.8% In 2004

For the second straight year, electric utility stocks produced total shareholder returns in excess of 20%. The industry gained 22.8% in 2004, besting the broader stock indices and the vast ma-jority of other business sectors (See table page 78). This follows a 23.5% advance by the industry in 2003, a year in which electric utility stocks slightly trailed the overall market gains.

Although many forces within and outside the industry affect stock per-formance, a re-emphasis on dividends (supported by reduced dividend tax

rates enacted in 2003), debt reduction, and the refocus on core operations were three widespread strategies that sup-ported the industry’s drive to rev up its stock performance in the last two years. In some cases, companies repurchased shares of stock, which often resulted in a bump in stock price. Continued low interest rates, receptive capital markets, and relatively strong economic growth were the main forces outside the indus-try that promoted stock price increases in 2004.

Another key contributor to the industry’s recent stock performance is the recovery of stocks that were beaten down to low levels in recent years. Four such companies led all electric utilities in 2004 and fi ve topped the list of best performers in 2003. Prior to its resurgence, the industry suffered

overall losses of (8.8%) and (14.7%) in 2001 and 2002, a time when many companies received credit downgrades and began to sell underperform-ing assets. It should be noted that this two-year downslide mirrored the broader indices.

Now that the indus-try has shown fi nancial improvement and has been rewarded with a

rebound in stock prices, investors will start to ask the growth question. Capital expenditures are expected to rise, as are interest rates, both of which will cut into recently available cash. Rising interest rates will also make dividend paying stocks less attractive, in the same man-ner that bond values fall when interest rates increase.

A Better Year for Everyone

Investor confi dence in the electric utility industry also rose due to con-tinued fi nancial improvement in 2004. The industry’s consolidated balance sheet strengthened with a debt-to-capitaliza-tion ratio of 58.2% as of December 31, 2004, steadily improving from 61.5% on December 31, 2003 and 62.2 % on December 31, 2002.

Net income improved for the second consecutive year, following a rare net loss in 2002. The 2002 loss was tied to record-high write-offs and impairment charges that were spread across the industry. The write-offs represented a mass exit from underperforming non-core businesses, while the impairments involved a reassessment of asset values, mostly generation. The bulk of this industry cleanup took place in 2002 with some remaining in 2003, allowing net income to return to more familiar territory over the last two years.

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CAPITAL MARKETS

The industry also produced positive free cash fl ow for the second straight year, while improving this measure for the fourth consecutive year. One strik-ing aspect of this improvement is that the electric utilities, as opposed to the practices of other industries, apply a more stringent calculation of free cash fl ow by subtracting common dividends, which are so important to electric utility investors.

The Dividend Boost

Electric utilities took advantage of recent legislation that reduced dividend tax rates—35 of 65 companies (53.8% of the industry) increased dividend payments in 2004, the industry’s larg-est increase since 1993, when 65.0% of companies raised their dividend. A key provision of the Jobs and Growth Tax Relief Reconciliation Act of 2003 re-duced individual tax rates on dividends to 15% for most tax brackets and 5% for the lowest two brackets. Previously, investors had to treat dividends as or-dinary income. This tax break provides an advantage for dividend paying stocks over bonds as well, as bond interest is still taxed as ordinary income.

This wave of dividend increases was not unique to electric utilities. Standard & Poor’s reports that about 7.1% more of publicly owned companies that pay dividends reported increases in 2004, compared to the previous year. It should also be noted that 2004 dividend in-creases for some electric utilities merely brought them closer to levels paid prior to their reductions in 2002 and 2003.

Low interest rates and an overall “flight to quality investments” also supported the boost in dividend-paying stocks. As interest rates fall or remain low, such stocks gain appeal, in the same manner that bond values move inversely

to interest rates. There is also an appetite among investors for income-producing investments, as the stock market correc-tion that followed the technology boom is still a recent memory.

Improved Credit Quality

Perhaps the biggest turnaround for the industry in 2004 was in credit qual-ity. Following a three-year period of downgrades—starting with, essentially, the California energy crisis in late 2000 and, on its heels, the collapse of Enron and trading markets—the industry’s credit report card showed great improve-ment in 2004. Credit rating upgrades and downgrades were nearly even, after three years of downgrades greatly out-numbering upgrades. For example, the industry’s downgrade to upgrade ratio was 9:1 in 2002. Increasing net income, decreasing debt-to-capitalization ratios, and positive and growing free cash fl ow are the fi nancial signs that prompted the ratings recovery in 2004.

Much to everyone’s surprise, interest rates did not rise in 2004. Borrow-ing and refi nancing at favorable rates

continued throughout 2004, even for companies rated below investment grade. Credit spreads continued to nar-row throughout the year. Companies took advantage of historically low rates to improve their fi nancial situation by: refi nancing to lower interest expense, improving free cash fl ow, and reducing improving free cash fl ow, and reducing debt. With these improvements came enhanced credit quality and higher stock prices.

Business Segmentation

Which types of companies per-formed best in 2004? There are three basic industry segments, characterized in terms of the proportion of regulated assets to total assets:

■ Regulated—more than 80%;Regulated—more than 80%;R

■ Mostly Regulated—50-80%; and

■ Diversifi ed—less than 50%.

The Diversifi ed companies produced the largest return — 44.1% — in 2004, followed by the Mostly Regulated group at 20.5%, and the Regulated companies at 14.6% (see table on page 79). Lead-on page 79). Lead-on page 79

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CAPITAL MARKETS

ing the Diversifi ed group by a large margin was TXU Corporation, whose stock performance surged 177.3% in 2004. This was due to several reasons: a restructuring plan that included stock repurchases, the sale of three TXU subsidiaries, and a 42% reduc-tion in debt; and the announcement of a 350% dividend increase that took effect in 2005. (Another key reason for the success is the earnings boost from favorable adjustment clauses, which allow this producer of signifi cant coal-fi red and nuclear generation to adjust rates to natural gas prices twice a year.) Remove TXU from the Diversified

group, however, and the group’s return falls to 24.0%, in line with the other categories. All three categories moved in relative harmony with the largest number of companies producing 10-25% returns, and only a few companies having negative returns.

A fourth group of companies, the comeback stocks, depict the rebounding nature of the successful stock returns in 2003 and 2004. This group of eight companies, selected from the three gen-eral categories, includes two recovering California utilities and six companies that underwent signifi cant restructuring over the past two years. The stock price

of each of these companies plunged in 2002, followed by an average return of 68.1% in 2003 and 58.6% in 2004, for a two-year total return of 166.5%. Overall, 61 companies or 95.3% of the EEI Index utilities had a positive return in 2004, with 45 companies or 70.3% of the industry experiencing double-digit percentage growth.

Long-Term Perspective

Electric utility stocks greatly out-performed the broader indices during the 2000-2004 period. Investors were rewarded with a 74.6% return over this time, compared to 1.8% and (11.0%)

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CAPITAL MARKETS

returns for the Dow Jones Industrial Average (DJIA) and S&P 500 Index respectively.

This success must be placed in proper perspective, as most of this difference occurred in 2000, along with the rela-tive gains by electric utilities in 2004. Electrics surged by 48.0% in 2000, due to a combination of sector rotation and aggressive growth forecasts, many of which were never realized. This was also the fi rst year of a three-year correction for the broader markets. If 1999 results (where the EEI Index was -18.6%), the DJIA was 27.2%, and the S&P 500 was 21.0%) are added to create a six-year picture from 1999-2004, the overall results are much closer, with the EEI Index at 42.1%, DJIA at 29.6%, and S&P 500 at 7.8%.

Entergy Corp. achieved the highest total return for large cap companies for

the fi ve-year period ending December 31, 2004, the second consecutive year it received this distinction. The company’s results continue to be driven by a refo-cused strategy, adopted in 1998, which combines operational excellence with portfolio management. By executing on this strategy, Entergy’s reliability and customer service metrics demon-strated double-digit improvement. This was recently recognized when Entergy received NEI’s Top Industry Practice Award and EEI’s outstanding electric service company award for national ac-counts. Large cap companies are defi ned as those with a market capitalization of $5.0 billion or greater. The leading large cap returns over the last fi ve years are as follows:

1 Entergy Corp. 210.0 2 Exelon Corp. 195.3 3 PPL Corp. 177.9

4 Sempra Energy 158.05 Southern Co. 153.8

Green Mountain Power Corp. led all small cap companies with an impressive 372.6% return for the fi ve-year period ending December 31, 2004. This fully integrated electric utility began a radi-cal transformation nearly fi ve years ago by reengineering its work processes, resulting in productivity gains. They also invested in technology and focused on customer service. These changes yielded regulatory confi dence and led to full cost recovery in recent rate-setting proceedings.

Green Mountain recorded double-digit returns in each year, culminating with a 26.2% return in 2004. Only two other EEI Index companies, Ha-waiian Electric Industries and South-ern Company, recorded double-digit returns in all fi ve years. The top small cap performances for the 2000-2004 period were:

1 Green Mountain 372.6 Power Corp.

2 Central Vermont 185.3 Public Service Corp.

3 PNM Resources, Inc. 176.8

4 Hawaiian Electric 171.0 Industries, Inc.

5 WPS Resources Corp. 162.2

NSTAR represents a model of con-sistency, as this Massachusetts transmis-sion and distribution company delivered positive total shareholder returns in each of the last eight years (1997-2004), the only electric utility company to do so. Its overall return of 183.0% over this period was highlighted by double-digit returns in four of the years. NSTAR’s success can be traced to its operational effi ciency, with net income growing in seven of the past eight years.

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CAPITAL MARKETS

Outlook

In 2005, Congress will attempt to pass a comprehensive energy bill, which failed to pass in 2004. With ris-ing gasoline and natural gas prices, the public is acutely aware that the country’s energy situation needs to be addressed. Reliability and the development of competitive wholesale electric power markets are among the key concerns from electric companies. Add to that the fact that from a long-term perspec-tive, the dividend tax reductions phase out after 2008.

Inevitably, interest rates will climb in the near-term, adversely affect-ing electric utilities in two ways. For starters, borrowing costs will rise for this capital-intense industry, thereby lowering a company’s bottom line. In addition, dividend paying stocks be-come less attractive in an environment of rising interest rates, much like a bond investment.

Although positive free cash fl ow has returned and dividend payments are on the rise, these two interacting items will continue to require close scrutiny. The expectation is that the industry will face renewed high levels of capital expenditures in the near-term to meet environmental compliance rules and upgrade the transmission and distribu-tion systems. Where does a company grow operating income to cover the higher construction costs? This be-comes a more pointed question now that higher dividend commitments are in place. Most companies have wrung out considerable operational effi ciencies over the last two years, and mergers and acquisitions may be the growth answer in only a few isolated instances. In this environment, regulatory hearings (rate cases) and success in competitive whole-

sale markets become the primary focal points for electric utilities to grow earnings and reward their investors with a steady total return – just as they received in the fully regulated days.

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CAPITAL MARKETS

Bond Ratings

Increased stability and a much im-proved downgrade-to-upgrade ratio characterized bond rating activity in 2004. Ratings actions declined by 56% and upgrades nearly matched down-grades, reversing a three-year trend that was dominated by deteriorating credit quality. A signifi cantly improved indus-try fi nancial profi le was the driver of this favorable change, with a strengthened capitalization structure, improving free

cash fl ow, and surging net income sig-naling the industry’s turnaround. The industry’s credit profi le strengthened as the year progressed, with upgrades out-pacing downgrades during the second half of 2004 (see below). Even though overall downgrades outnumbered up-grades for the entire year, the industry’s mean credit rating improved at all three of the major ratings agencies. For Standard & Poor’s, this translated into a solid BBB average, two notches into investment grade, at the end of 2004.

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The 2001-2003 Credit Collapse

Starting in the mid-1990s, many electric utility holding companies diversifi ed away from core regulated utility operations and incurred large amounts of debt. One result was a mass build-out of competitive generation, almost all of it gas-fi red, in pursuit of perceived higher growth opportunities in newly developed wholesale power markets. By late 2001, falling power prices and escalating natural gas prices squeezed margins, and many companies


CAPITAL MARKETS

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faced serious fi nancial challenges as competitive generation, power trad-ing, and other diversifi ed businesses greatly underperformed the traditional regulated utility model.

These events led to the industry’s rapid credit deterioration from the fourth quarter of 2001 through 2003. The ratings agencies, relatively quiet and predictable back in the fully regu-lated days, began suddenly impacting the industry like never before. For ex-ample, Standard & Poor’s (S&P) issued 253 downgrades and only 20 upgrades over this nine-quarter period, for an unheard of downgrade-to-upgrade ratio of nearly 13:1. The table above gives a breakdown of activity by the three ma-jor agencies (S&P, Moody’s, and Fitch Ratings) from 2001-2004.

Ratings Activity Stabilizes in 2004

Although downgrades continued to outnumber upgrades by a slim margin in 2004 at each of the ratings agencies, a signifi cant decline in overall ratings activity and a much improved ratio of downgrades to upgrades signaled a turnaround from the credit downslide of 2001-2003. The total of 110 ratings actions (downgrades plus upgrades) in 2004 was far below the 207, 298, and 251 ratings changes in 2001, 2002, and 2003 respectively (page 842003 respectively (page 842003 respectively ( ). Overall page 84). Overall page 84ratings actions were more company specifi c in 2004, whereas affi liate conta-gion, underperforming diversifi ed busi-nesses, and enhanced counterparty risk created widespread and adverse ratings activity in 2002 and 2003. For purposes here, ratings activity was scored based on occurrence and not on the number of notches that changed. For example,

a three-notch increase is scored as one upgrade.

In addition to the decline in ratings activity, the industry also earned a much improved downgrade to upgrade ratio in 2004. This ratio was just above 1:1 for all three agencies after soaring to levels exceeding 25:1 in 2002 (page levels exceeding 25:1 in 2002 (page levels exceeding 25:1 in 2002 (84). Stronger balance sheets, improved 84). Stronger balance sheets, improved 84free cash fl ow, and the widespread exit of non-core businesses were the main reasons for the improvement. Although the industry’s 59 downgrades in 2004 is nothing to ignore, these setbacks are more specifi c to company situations and are no longer a part of sweeping correction across the industry.

With the widespread downgrades of 2001-2003, a new reality has developed with regard to a benchmark rating for the industry. Prior to 2001, the median rating for the industry hovered around A-. By the end of 2004, the median rat-


CAPITAL MARKETS

ing for S&P was solidly fi xed at BBB. Although some companies are still on the mend, it is widely accepted that the industry standard going forward will be in the BBB to BBB+ range, about one to two notches below the historical benchmark rating. This adjustment is due to the added risk that utilities are now faced with compared to the com-pletely regulated landscape that they operated in prior to deregulation. The charts on page 85 present an industry breakdown of investment grade and sub-prime ratings for year-end 2003 and 2004.

Average Rating Improves in 2004

Although total downgrades outnum-bered upgrades in 2004, a snapshot of credit quality at year-end shows a slight improvement from 2003 to 2004. There are two reasons for this. First, this year-end comparison (page 85year-end comparison (page 85year-end comparison ( ) includes page 85) includes page 85one rating per overall entity. Thus a company with several operating utilities

would only have one rating here. By contrast, the upgrade and downgrade data is based on all industry activity, regardless of multiple occurrences at affiliated companies. Second, some companies experienced dramatic leaps in credit quality in one rating change during 2004. For example, S&P raised Pacifi c Gas & Electric, NorthWestern Corp., and Illinois Power by ten, eight, and seven notches respectively in single upgrades.

All three agencies rated the industry slightly better in 2004, based on a non-weighted average. For example, S&P’s average rating on December 31, 2003 was a strong BBB-, but below BBB. By the end of 2004, it was slightly above BBB. Besides the different metrics and priorities that each ratings agency em-ploys, further differences in the mean rating arise due to the slightly different group of companies that each rates.

Financial Condition Strengthens

Balance sheets continued to strength-en in 2004 as seen in the ongoing improvement in the industry’s debt-to-capitalization (debt-to-cap) ratio. This metric fell to 58.2% as of December 31, 2004, down from 61.5% at year-end 2003 and 62.2% in 2002. The falling debt-to-cap ratio is due to a combina-tion of debt retirement and common equity issuance. The industry’s debt-to-cap ratio would have improved even more if not for the $6.5 billion of stock repurchases in 2004. At this point, the ratings agencies are comfortable with the capitalization structure for the ma-jority of companies. The exception to this is the handful of merchant genera-tion companies that operate primarily in competitive markets and remain highly leveraged. Many of these companies do not appear in our consolidated fi nan-cials, as operating a regulated electric utility is not a primary part of their business.

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CAPITAL MARKETS

The industry’s debt reduction was also driven by an ongoing improve-ment in free cash fl ow. Free cash fl ow (measured as cash fl ows from operating activities less capital expenditures less common dividends) was positive for the second consecutive year and improved for the fourth straight year. Declining capital expenditures were the biggest contributor to this four-year trend, as the industry wound down its competi-tive generation build-out over the last two years. Capital expenditures hovered around $40 billion in both 2003 and 2004, after climbing to $47.2, $56.8, and $48.5 billion in 2000, 2001, and 2002 respectively.

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Investor confi dence in the industry was solidifi ed by the $10.5 billion surge in net income in 2004, rising 67% from $15.6 billion in 2003 to $26.1 billion in 2004. Forty-four of seventy-two companies, 61.1% of the industry, im-proved net income over the prior year. Discontinued operations charges had a much smaller affect in 2004 with a positive $972 million impact on earn-ings compared to negative net charges of $2.7 billion in 2003 and $16.6 billion in 2002. The nearly $20 billion in dis-continued operations charges over this two-year period represents the industry’s mass exodus from non-core businesses,

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reversing much of the diversifi cation that took place from the mid-1990s to 2001.

NorthWestern, PG&E, Illinois Power Post Gains

NorthWestern Corporation and Pacifi c Gas and Electric Company both emerged from bankruptcy in 2004, up-lifting credit ratings that had bottomed out. S&P raised NorthWestern’s (NW) rating from D to BB- in October of 2004, just prior to its effective reorga-nization on November 1. This seven-notch improvement still leaves NW three notches below investment grade.

Source: Standard & Poor’s


CAPITAL MARKETS

NW fi led for Chapter 11 in September of 2003 in order to signifi cantly reduce debt, improve its capital structure and ensure the long-term fi nancial health of its core utility operations. The company’s financial challenges were mostly due to the implementation of a diversifi cation strategy and a large amount of debt incurred as part of that strategy. The diversifi cation included in-vestments in retail propane, networked communication solutions, and heating and air conditioning businesses. Over the past year, NW has sold non-core assets, reduced debt, and improved its overall operating effi ciencies to bring an end to its short-lived diversifi cation.

Pacifi c Gas and Electric Company, the operating utility under PG&E Corp., emerged from bankruptcy early in 2004. The reorganization began three years earlier, in April of 2001, when Pacifi c Gas and Electric faced serious financial challenges in the wake of California’s failed restructuring plan. In April 2004, S&P boosted Pacifi c Gas and Electric’s rating by an astonishing 12 notches from the lowest depths of a D rating to investment grade status at BBB-. It should be noted that PG&E Corp. is currently not rated, therefore Pacifi c Gas and Electric serves as its proxy in our ratings research. At this time, nearly 100% of PG&E Corp.’s assets fall under this regulated operating utility. Both PG&E and NW reinstated their dividends in the fi rst quarter of 2005, providing further evidence that both companies are regaining fi nancial strength.

The acquisition of Illinois Power (IP) by Ameren Corporation propelled IP’s credit quality from well below invest-ment grade to above investment grade during 2004, a recognition made by the three ratings agencies. S&P, Fitch, and Moody’s raised IP’s rating by eight, seven, and six notches respectively.

Although Moody’s initially raised IP’s rating by two notches (Caa1 to B2) in February when the Ameren deal was announced, all three agencies awarded IP with the largest increases into in-vestment grade status in early October, following the deal’s completion on September 30, 2004. A parallel look at

the differing ratings scales used by the three major ratings agencies is presented below.

Ameren’s purchase ended a four-year roller coaster ride for Illinois Power while under the ownership of Dynegy Inc., a Houston-based energy company. Dynegy’s financial problems, which

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CAPITAL MARKETS

began in late 2001 with the collapse of wholesale power markets, were magni-fi ed by high debt levels taken on to fund acquisitions. The contagion that Illinois Power suffered from its parent company was reflected in its credit ratings, buried far below investment grade at the end of 2003 (Moody’s = Caa1, S&P = B, Fitch = CCC+). Exelon Corporation appeared to be the initial savior in 2003 with its announcement to acquire IP, but that deal fell through in December of 2003. This left the door open for Ameren, a logical fi t with its quality credit rating (entrenched at A3 for Moody’s and A- for S&P and Fitch) and presence in Illinois.

Edison International (EIX) con-tinued its climb back to prime credit status, with signifi cant ratings increases from Moody’s and Fitch in 2004. Its long journey goes back to 2001, when EIX was severely downgraded amid the California Energy crisis. EIX’s Fitch and Moody’s ratings climbed three and two notches respectively. By the end of 2004, Moody’s rated EIX as invest-ment grade and both S&P (A-) and Fitch (BB) had it within striking range of investment grade status. In award-ing the two-notch increase to EIX in August of 2004, Moody’s cited a more constructive regulatory environment and a substantially improved fi nancial profi le at Southern California Edison, EIX’s principle electric utility. Moody’s also cited strong liquidity and plans to reduce debt at holding company Edison International in support of the upgrade.

Aquila, CMS Energy, and Xcel Energy each received upgrades of two notches in 2004, with Moody’s provid-ing the higher rating in each case. All three companies are bouncing back from downgrades in the 2002-2003 period that were due to underperform-ing unregulated investments.

New Benchmark Rating

A new industry benchmark rating is forming in the BBB/BBB+ range (Baa2/Baa1 for Moody’s), refl ecting the higher risk of today’s fragmented regu-latory landscape. This is down slightly from the A/A- average ratings in the fully regulated days. Company efforts toward obtaining higher than average ratings will depend on overall business models and decisions on how to best reward shareholders. A stable fi nancial environment has returned for most of the industry and the “back to core busi-nesses” approach has been well received by the ratings agencies. Going forward, the key ratings challenges center around state regulatory relationships and whether companies can recover rising costs such as environmental compliance equipment and pension funding, as well as timely cost recovery of rising fuel costs. Capital expenditures are expected to increase over the immediate-term to strengthen transmission and distribu-tion reliability, a cost that this industry typically fi nances with debt.


CAPITAL MARKETS


POLICY OVERVIEW

Policy Overview

Introduction

America’s electric utilities continue to work closely with legislators and regulators to promote policies that ensure an affordable and reliable sup-ply of electricity for consumers while also powering our nation’s economic growth. The enactment of the Ameri-can Jobs Creation Act of 2004 was one of the most notable legislative ac-complishments of 2004 for the electric utility industry, yet more remains to be done in 2005.

The electric utility industry has made considerable progress in strength-ening reliability since the August 2003 blackout. However, congressional ac-tion is needed to provide for mandatory, enforceable reliability standards, and to encourage critically needed infrastruc-ture enhancements. Comprehensive energy legislation moving through the 109th Congress would stimulate transmission investment and facilitate transmission siting, establish a national electric reliability organization, and promote a diverse supply of fuels from which to generate electricity. Together, these measures will signifi cantly en-hance reliability over the long term.

Utilities are encouraging the Fed-eral Energy Regulatory Commission (FERC) and the states to work more

closely to enhance reliability, facilitate transmission infrastructure investment, and support the development of a strong, competitive wholesale electric-ity market. FERC should recognize regional differences and respect the role of the states in making retail service, planning, resource adequacy, fuel sup-ply, and cost recovery decisions.

At the state level, the industry is entering a new era of rate cases that will require utilities and regulators to build a new collaborative relationship while addressing the many complex issues involved in updating utility revenues and rates in restructured markets. The evolving wholesale and retail market-place will focus new attention on cost of capital, resource procurement, alterna-tive regulation, risk management, and provider of last resort issues.

By continuing to reduce its air emis-sions signifi cantly, the electric power industry is making major contributions to improving our nation’s environment. The Environmental Protection Agency (EPA) recently issued the Clean Air Interstate and the Clean Air Mercury Rules, which will dramatically reduce levels of sulfur dioxide (SO

2), nitrogen

oxides (NOx), and mercury. While

the industry supports EPA’s policy objectives, a new approach is needed. Congress should pass sensible multi-emission legislation to streamline and

clarify the current regulatory system and to provide greater certainty, while also cutting SO

2, NO

x, and mercury by

nearly 70% compared to 2002 levels.

The following articles present an overview of the legislative and regula-tory policies affecting electric utilities and the industry’s leadership on these issues.

Legislative Summary

Congress made limited progress on legislative issues in 2004, as lawmakers spent much of the year focused on the elections. The 108th Congress ended in November 2004, and the new Con-gress got underway in January 2005, with leadership in both the House and the Senate vowing to move quickly on comprehensive energy legislation. Poli-cymakers also are expected to consider a number of other legislative initiatives critical to the electric utility industry during this session.

This legislative summary is current as of May 26, 2005. Please visit EEI’s Web site, www.eei.org, for the most up-to-date information.


POLICY OVERVIEW

The American Jobs Creation Act of 2004

In October 2004, President Bush signed into law the “American Jobs Cre-ation Act of 2004,” otherwise known as the FSC/ETI bill. This legislation replaced the U.S. export tax regime to bring the United States into compliance with international trade obligations. The legislation has major, positive implications for the electric utility in-dustry. It included a phased-in tax de-duction (3% rising to 9%) for domestic manufacturing activities, including the production of electricity.

The legislation also expanded and enhanced the Section 45 renewable energy tax credit for wind, biomass (closed- and open-loop), solar, geother-mal, and refi ned coal resources. The credit lasts for fi ve years or ten years (depending on fuel source), as long as the property is placed in service by December 31, 2005.

The bill also included a “Transco” provision for dispositions of transmis-sion property to implement Federal En-ergy Regulatory Commission (FERC) or state restructuring policy. The sale of the property must occur prior to January 1, 2007, and the gain from such sales would be paid ratably over an eight-year period (with reinvestment obligations). Finally, the bill repealed a 4.3-cent tax on rail and inland waterway barge fuels.

Also of signifi cance, the FSC/ETI conference agreement did not include onerous revenue measures (included in the Senate-passed version of the bill) that would have denied tax deductions for ordinary and necessary business expenses for compliance (including ne-gotiated settlements) with civil laws or to compensate the government or other persons for compensatory damages.

The legislation also did not include a retroactive tax proposal for cross-border leases; the bill applies only to leases en-tered into after March 12, 2004.

Bankruptcy Reform

On April 20, 2005, President Bush signed into law comprehensive bank-ruptcy reform legislation, which in-cludes provisions that would provide companies greater certainty when they net their trading positions and trade with end users. Both of these changes will improve liquidity in energy mar-kets.

Comprehensive Energy Policy

In November 2004, congressional leaders made one last attempt before adjournment to enact components of major energy legislation, but their ef-forts fell short. The session’s end meant the demise of the H.R. 6 conference agreement on comprehensive energy legislation, which had passed the House of Representatives but was fi libustered in the Senate.

With the start of the 109th Congress in January 2005, the process of produc-ing an energy bill started anew, but for the most part the debate focused on essentially the same issues. In the spring of 2005, the House of Representatives passed a revised version of the energy bill, also numbered H.R. 6, which was substantially similar to the 108th Congress conference report in most respects, including critical electricity provisions.

In mid-May 2005, after months of informal staff discussions, the Energy and Natural Resources Committee re-ported their version of comprehensive energy legislation to the full Senate by a bipartisan vote of 21-1. Senate debate on the bill was scheduled to begin in

mid-June around the time this report went to press. At the same time, in re-sponse to growing public concern about record-high gasoline, oil, and natural gas prices, President Bush called for fi nal enactment of energy policy legislation by August 2005.

Electricity Provisions

The electricity provisions of the bill passed by the House in the spring of 2005 are largely similar to those in the conference agreement from the previ-ous Congress. They would establish a self-regulating reliability organization, with FERC oversight, to develop and enforce mandatory reliability rules on all market participants. The bill would repeal and modernize the Public Utility Holding Company Act (PUHCA) and reform the mandatory purchase obliga-tion under the Public Utility Regulatory Policies Act (PURPA). In reaction to FERC’s standard market design (SMD) proposal, the bill also seeks to protect the priority of “native load” customers to a utility’s transmission system.

The House bill includes a number of transmission-related provisions to encourage investment in new trans-mission, to facilitate the siting of new transmission lines on both federal and private lands, and to enhance reliability of the transmission grid. The bill would grant FERC limited authority to require open-access transmission for the large government-owned utilities and electric cooperatives. It also would give FERC backstop authority to site certain trans-mission lines where states have failed to act within a defi ned period of time.

The bill contains provisions to co-ordinate the federal permitting process with the state process and ensure more timely decisions. The Department of Energy (DOE) would have lead-agency authority to establish binding deadlines


POLICY OVERVIEW

for decisions by other federal agencies and the responsibility to develop a single environmental record of review, thereby eliminating multiple and duplicative environmental analyses. The bill also requires FERC to issue a rule providing transmission rate incentives and allows for the recovery of all prudent reliability investments. The House chose to drop language, which had been included in the previous year’s bill, addressing “participant funding” of transmission line expansions and upgrades.

H.R. 6 also contains significant consumer protection provisions. The bill provides more explicit direction to FERC on public interest factors it should consider in reviewing electric utility mergers, while also expediting the merger review process. The bill prohibits deceptive round-trip trad-ing and the fi ling of false information, and clarifi es the Commodity Futures Trading Commission’s anti-fraud and manipulation authority. It provides FERC with greater enforcement author-ity, the ability to impose higher penalties on companies that violate the Federal Power Act, and refund authority for overcharges by large government-owned utilities.

In mid-May 2005, the Senate Energy Committee met to mark up its version of the energy bill (S. 10) following months of discussions between Energy Committee Chairman Pete Domenici (R-NM) and Ranking Member Jeff Bingaman (D-NM) on how to modify last year’s bill in an effort to reach a more bipartisan proposal.

The electricity title contains impor-tant provisions, including creation of a self-regulating reliability organization that can establish mandatory reliability rules; FERC backstop siting authority and reform of the federal transmission

permitting process; transmission pric-ing incentives; slightly greater FERC authority over transmission owned by government-owned utilities and electric cooperatives; and PURPA reform.

Tax Implications

In April 2005, the House Ways and Means Committee reported legislation that was incorporated into the compre-hensive energy bill (H.R. 6) that passed the House. The bill includes many favorable provisions to the electric utility industry. It would reduce depreciable lives for electric transmission assets and natural gas distribution lines from 20 years to 15 years. The provision to reduce depreciable lives for electric trans-mission assets will encourage investment in modernization and expansion of U.S. transmission capacity.

The legislation provides for 60-month amortization of pollution control facili-ties for power plants built after 1975; currently this accelerated amortization is only available for equipment added to generating plants placed in service before 1976. This tax relief can be a signifi cant economic incentive for utilities to deploy new environmental technologies on electric generating plants.

Additional tax provisions of impor-tance to the industry within the bill include provisions to update the tax treatment of nuclear decommissioning trust funds and to treat the Section 29 (non-conventional fuels) credit as a general business credit, thus allowing a carryback and carryforward of the credit.

As of this writing, the Senate Finance Committee is expected to mark up an energy tax title in mid-June, and it is uncertain which of the industry’s tax priorities will be included in a Senate bill.

Hydro Licensing Reform

Both the House and Senate versions of the energy bill contain provisions to improve the hydro-licensing process. Specifi cally, the bills would allow an applicant for a license or license renewal to propose alternative conditions to the mandatory conditions proposed by a federal resource agency.

LIHEAP

The Low Income Home Energy Assistance Program (LIHEAP) is the primary federal program available to help low-income households pay their home energy bills. In 2004, Congress renewed LIHEAP funding at $1.9 bil-lion, with an additional $300 million allocated for unanticipated needs.

EEI, working with a broad coalition of other interested organizations, has requested that Congress provide at least $3 billion in regular LIHEAP funds for fi scal year 2006. H.R. 6 dramatically increases funding for LIHEAP—autho-rizing $3.4 billion in regular funds—as well as for low-income weatherization programs and state energy programs to improve energy effi ciency. The Sen-ate version of the energy bill does not include LIHEAP funding language because LIHEAP funding is not juris-dictional to the Energy Committee.

The comprehensive energy bill also includes wide-ranging provisions on energy effi ciency and conservation, oil and gas development, nuclear, coal, alternative fuels, and research and de-velopment. As of this writing, the full Senate is expected to vote on its version of the energy bill in late June. If the bill passes the Senate, the House and the Senate would then meet in confer-ence to work out differences between the bills.


POLICY OVERVIEW

Environmental Legislation

Multi-Emission Legislation

A well-designed multi-emission ap-proach to air quality regulation offers the best strategy for further reducing power plant emissions of sulfur dioxide (SO

2),

nitrogen oxides (NOx), and mercury.

Enactment of sensible multi-emission legislation is a key objective for EEI and its member companies.

Early in 2005, leaders of the Senate Environment Committee indicated that they planned to move aggressively on a multi-emission bill. The Commit-tee conducted hearings in late January and early February. The focus of those hearings was S. 131, The Clear Skies Act of 2005.

S. 131 is based on the Administra-tion’s Clear Skies Initiative, a multi-emission approach designed to achieve air quality objectives while streamlining the regulatory process; maintaining fuel diversity; allowing flexible, market-based approaches to emissions reduc-tion; and reducing compliance costs. It projects reductions of power-plant emissions—SO

2, NO

x, and mercury—

by about 70% compared to 2002 levels. The Clear Skies Initiative would provide greater business certainty by eliminating multiple, overlapping regulations and establishing specifi c emission-reduction requirements that will not change for a defi ned period of time.

On March 9, the Senate Environ-ment and Public Works Committee met and voted 9-9 on the manager’s amendment to S. 131. While Senators from both sides of the aisle expressed frustration that the Committee had been unable to resolve concerns about S. 131 and break a tie vote to move it to the Senate fl oor, many expressed a desire to continue working toward a compromise. As such, it appears the

possibility still exists for developing a sensible multi-emission bill in this Congress.

Global Climate Change

In the 108th Congress, Senators John McCain (R-AZ) and Joe Lieberman (D-CT) co-sponsored a bill (S. 139) that would impose mandatory cap-and-trade limits and mandatory reporting require-ments on greenhouse gas emissions. Floor consideration of a substitute for S. 139 took place in October 2003, and the substitute was defeated by a vote of 43-55. Senators McCain and Lieber-man did not attempt to offer S. 139, or similar legislation, to another legislative vehicle in 2004.

In 2005, congressional interest in climate issues is exemplified by the number of climate-related proposals already introduced in the 109th Con-gress. Senator Chuck Hagel (R-NE) has introduced several climate-related bills that address carbon intensity, tech-nology development and transfer, and tax credits and financial incentives. Senators McCain and Lieberman are expected to attempt again to offer a mandatory cap-and-trade amendment to another legislative vehicle in 2005.(Their reintroduced bill is S. 342.) Climate issues have been raised in the context of the multi-emission legislation debate. And, in all likelihood, consider-ation of climate issues will occur during the energy bill debate.

Finance/Taxation Issues

Regulatory Issues

The Internal Revenue Service (IRS) proposed regulations in March 2003 that signifi cantly modify current tax law normalization rules. The proposed regulations would deny the normaliza-tion method of accounting for electric generating assets that are sold by a

regulated company to an unregulated company. Of particular concern to utilities is the proposal to make the new rules retroactive. Normalization regulations were expected to be fi nal-ized by the end of June 2004. As of this writing, the regulations are still pending at the IRS.

In May 2004, the IRS issued pro-posed regulations that defi ne solid waste as not including radioactive waste (rad-waste). EEI fi led comments in August 2004 to the IRS opposing these regula-tions as being inconsistent with historic tax law and contrary to government policy. The IRS held a hearing on this issue on August 11, 2004. As of this writing, the radwaste regulations are still pending at the IRS.

Income Tax Allowances

On May 4, 2005, FERC adopted a policy to permit cost-of-service rates to refl ect income tax liability for all public utility assets, including assets owned by partnerships. This policy corrected a mistaken view that partnerships did not incur a tax liability that should be treated as a cost for rate purposes. EEI took the lead in convincing FERC to revise this policy.

Hours-of-Service Regulations

Hours-of-service regulations ad-ministered by the U.S. Department of Transportation (DOT) limit the ability of utility line workers who drive trucks to respond to emergencies and make critical repairs following natural disas-ters, accidents, and “routine” power outages. New, more stringent regula-tions would further limit the fl exibility that utility management needs to deploy crews and equipment. Often, utility crews are needed to work beyond DOT daily and weekly limits to protect public safety and ensure reliability.


POLICY OVERVIEW

For years, the electric utility industry has pursued several legislative remedies, including seeking a permanent exemp-tion from the regulations for utility line workers. Currently, a temporary partial one-year exemption is in effect; this exemption expires on December 31, 2005.

A permanent exemption for utility service vehicle drivers from the Hours of Service regulations is included in the House’s version of the highway reautho-rization bill (H.R. 3), which passed on March 10, and also is included in the bill that passed the Senate on May 17.

On May 26, the highway bill, which was set to expire on May 31, 2005, was given a one-month extension until June 30 to provide time for House and Sen-ate conferees to resolve the differences between the two versions of the bill. It appears that these efforts could be derailed, however, given White House threats to veto a transportation bill that exceeds $284 billion in spending over fi scal years 2004-2009. The current Senate bill exceeds $295 billion over the six-year period.

As a backstop, EEI is working with appropriators to pursue another one-year delay in implementation and enforcement of the Hours of Service regulations as they pertain to utility service vehicle drivers in the fi scal year 2006 transportation spending bill.

Rail Transportation

In spring of 2005, bipartisan legisla-tion was introduced in the House and Senate to address problems affecting captive rail shippers of coal, includ-ing many utilities, and other bulk commodities. On April 27, Senator Conrad Burns (R-MT) and nine oth-ers introduced S. 919, the “Railroad Competition Act of 2005,” which

includes Surface Transportation Board (STB) reforms and other measures to provide captive rail customers better access to railroad competition where it exists, including requiring rate quotes from rail carriers and eliminating “paper barriers” to competitive access. On May 3, similar legislation, H.R. 2047, was introduced in the House by Representative Richard Baker (R-LA) and 12 others.

Telecommunications

Utility deployment of broadband over power lines (BPL) received a ma-jor boost in October 2004 when the Federal Communications Commission (FCC) issued BPL interference rules favorable to the industry. At the same time, FERC and FCC issued a joint public statement encouraging acceler-ated BPL deployment.

In the fi rst half of 2005, Congress began what was expected to be a multi-year effort to update some of the nation’s telecommunications laws. Some of the changes could affect the ability of utili-ties to engage in ventures such as BPL. See the State Issues section for more information on BPL.

Joint FERC and State Regulatory Issues

As the electric power industry con-tinues its progression toward a hybrid model of competition and regulation, the need for the Federal Energy Regula-tory Commission (FERC) and the states to work closely together to benefi t the ultimate customer is becoming even more important.

Fostering effective transmission policy, managing transmission infra-structure development, strengthening reliability, measuring market power,

pursuing more efficient wholesale markets, and encouraging resource adequacy and competitive procure-ment—all these require a partnership between FERC and the states based on cooperation and understanding. In some cases, congressional action also is needed.

Competitive Wholesale Electric Markets

In January 2005, EEI’s Board of Directors adopted a Framework for the Continuing Development of a Compet-itive Wholesale Market for the Benefi t of Consumers. The framework strongly supports the development of competi-tive wholesale markets because properly structured competitive wholesale mar-kets benefi t consumers. The benefi ts of robust wholesale competition can be achieved only if a strong, effective state-federal working relationship is established on all regulatory matters that provide the stability and certainty needed to attract investment.

Regulatory authority over U.S. elec-tricity markets is divided between state and federal authorities and is likely to remain so for the foreseeable future. At the federal level, FERC is promoting policies for the development of com-petitive wholesale electric markets ca-pable of serving large regions. States are responsible for the regulatory structure for providing retail electric service, but have different views on what is the best model. Currently, about one-third of the states provide for retail competition and two-thirds do not.

States and FERC want to assure just and reasonable rates to their customers and to make certain there are adequate electric generation resources. States want to continue to take the lead on policies concerning electric resource adequacy and procurement relating to


POLICY OVERVIEW

fuel supply choices and environmental aspects of electric generation.

EEI companies support pursu-ing more effective wholesale markets throughout the United States because properly structured competitive whole-sale markets benefi t consumers. Robust wholesale competition offers the po-tential of substantial benefi ts to con-sumers in terms of lower costs, greater effi ciency in the use of generation and transmission resources, and enhanced reliability.

EEI Adopts Principles on Transmission Investment

In March 2005, EEI’s Board of Di-rectors adopted Principles on Transmis-sion Investment that identify the actions that FERC can take to eliminate im-pediments to improving our transmis-sion infrastructure. While a complete copy of these principles is available on EEI’s Web site, www.eei.org, following are those of particular concern to the electric utility industry:

First, FERC should endorse policies that provide regulatory certainty with respect to attractive returns, incentives, cost recovery, and cost allocation, re-gardless of business model or corporate structure. FERC must establish and put into effect a durable regulatory frame-work that allows electric utilities to in-vest in transmission infrastructure, and recover that investment, along with the cost of capital, through electricity rates. Such a framework is essential to raising the substantial and near unprecedented amount of capital necessary to construct needed, cost-effective transmission facilities in the United States.

Second, FERC should establish returns on equity (ROE) that are suf-fi cient to attract the signifi cant amounts of capital that will be necessary to meet

the industry’s construction objectives. EEI also is supportive of FERC’s pro-posed ROE incentives for transmission independence. However, EEI strongly believes that FERC policy should not fa-vor one corporate structure or business model over another. Many different structures and business models for the construction of transmission can coexist in a competitive wholesale marketplace, provided there are fair rules in place for all market participants.

Third, FERC must recognize that confl icting federal and state regulatory policies can result in unrecoverable or trapped costs. FERC, working in co-operation with the states, must ensure that the revenue requirement authorized by FERC for all prudently incurred transmission investment is permitted by the states to be fully refl ected in retail rates.

Fourth, FERC should give serious consideration to allowing construc-tion work in progress (CWIP) in rate base, accelerating book appreciation, and allowing full abandoned plant cost recovery for transmission projects that are approved. Adopting CWIP in rate base and accelerating book depreciation improve the generation of cash and reduce the industry’s dependence on capital markets. This will lower the cost of capital and facilitate greater amounts of transmission investment. In addi-tion, where states require purchases of renewable resources that lack siting fl ex-ibility, FERC should allow alternative transmission pricing and cost recovery approaches to support the building of transmission facilities to help achieve state renewable resource goals.

Lastly, EEI members support re-gional transmission planning and siting practices that can identify cost-saving opportunities and facilitate construc-tion. States within a region should be

encouraged to streamline their siting processes and consider regional needs. Regional state committees, where ap-plicable, should facilitate state approv-als and assist coordination activities. EEI supports federal energy legislation providing backstop siting authority to FERC and improved federal permitting processes for transmission lines.

Both integrated utilities and stand-alone transmission companies are committed to building transmission facilities for which they can obtain cost recovery. Industry plans suggest that a remarkable opportunity for transmis-sion investment is within reach. FERC can support this growth by aggressively pursuing policies that ensure regulatory certainty and cost recovery. This will bolster efforts to build more transmis-sion in the future, which in turn, will enhance reliability as well as local, regional, and interregional wholesale electricity markets.

Transmission Infrastructure Development

Greater competition in electricity markets is expanding the use of the nation’s electric transmission grid. Built originally to serve existing and future loads, interconnect neighboring utili-ties, and support reliability, the grid also is now being used to support a larger number of wholesale transactions across regions. EEI’s members continue to ac-tively invest in the transmission system in order to meet these needs.

Historical and projected data dem-onstrate that both integrated companies and stand-alone transmission compa-nies are making increasing investments in transmission. Reversing a trend of declining transmission investment, from 1999 to 2003 annual transmis-sion investment by shareholder-owned utilities increased 12% annually and


POLICY OVERVIEW

totaled nearly $18 billion over the period. From 2004-2008, preliminary data indicate that utilities have invested or are planning to invest $28 billion, a 60% increase over the earlier period.

Utilities will continue to build trans-mission facilities for which they can obtain cost-recovery. However, existing impediments continue to frustrate and delay transmission investment. Fed-eral and state regulatory and legislative policies are needed to eliminate these impediments.

Reliability Update

In August 2003, large portions of the Midwest and northeastern United States, as well as Ontario, Canada, expe-rienced an electric power blackout. An estimated 50 million people and 61,800 MW of electric load were affected. Since then, the electric power indus-try, working closely with the North American Electric Reliability Council (NERC) and FERC, has made great strides in improving grid reliability:

Reliability Readiness Audits

NERC has established a program to audit the readiness of all reliabilitycoordinators and control areas in North America to perform their assigned reli-ability responsibilities. In addition to providing an independent review of control area and reliability coordinator operations, the audits identify areas for improvement and help these entities achieve excellence from a reliability operations standpoint. As of mid-May 2005, 49 of the highest priority audits had been completed. These audits will continue on a three-year cycle.

New Reliability Standards

In February 2005, NERC’s Board of Trustees unanimously agreed to adopt a comprehensive set of reliability stan-

dards for the bulk electric system. The new reliability standards incorporate the NERC operating policies, planning standards, and compliance requirements into an integrated and comprehensive set of measurable reliability standards. The new standards will apply to all enti-ties that play a role in maintaining the reliability of the bulk electric system in the United States and Canada. NERC developed these reliability standards using its American National Standards Institute-accredited standards develop-ment process.

Vegetation Management

NERC is developing a new reli-ability standard for vegetation man-agement—the practice of ensuring that trees and other vegetation do not interfere with power lines. The drafting team is currently reviewing the fi rst set of comments submitted by interested companies in February 2005. Once the drafting team has completed review of all comments and made appropriate changes to the standard, the standard will be reposted for additional industry review.

Market Power

The relationship between FERC and the states has become increasingly important now that FERC is creating its rules to govern the country’s developing wholesale electricity markets. Since 1996, when it issued its Order 888 re-quiring transmission providers to offer non-discriminatory access to transmis-sion services through an Open Access Transmission Tariff, the Commission has been aggressively developing a regulatory framework to mitigate the potential of any power supplier to exert market power—the ability to profi t by raising rates above competitive levels in a given market.

The Commission is now evaluating utility applications for market-based rate authority by looking at all poten-tial areas for a utility to exert market power—in generation, through control over transmission facilities, with the even-handedness of the applicant’s busi-ness transactions with affi liated compa-nies compared to others, and through its ability to erect barriers to market entry. If mistakenly applied, however, the Commission’s market power rul-ings hold the potential to set back the plans of states and regulated utilities to provide a reliable and affordable power supply to their retail customers. This issue has already arisen in the past few years when vertically integrated utilities announced plans to build new power plants or acquire an existing one.

FERC is concerned that these util-ity actions to buy or build generation could give them market power, and has placed them under great scrutiny. The states, on the other hand, looking for the least-cost option for their retail customers, typically have been in favor of the utility actions and have approved them. The electric utility industry is committed to developing robust, com-petitive wholesale markets, and EEI will continue to work with both federal and state authorities to prevent the potential abuse of market power in the interest of ensuring fair and effi cient competitive markets.

Resource Adequacy and Competitive Procurement

Recent decisions by FERC involv-ing resource procurement and affi liate transactions have highlighted the need for improved federal-state coordination. In those decisions, the Commission has indicated that it will require companies seeking FERC approval of power pur-chase and resource asset transfers involv-


POLICY OVERVIEW

ing affi liates to meet four guidelines. The guidelines focus on transparency, clear product defi nition, clear evalua-tion criteria, and independent oversight. EEI has encouraged FERC to apply its guidelines fl exibly, allowing a variety of approaches to show lack of affi liate preference and to accommodate state concerns.

The Resource Planning and Procure-ment Forum between state commission-ers and members of FERC was held in mid-May 2005 in Chicago, Illinois. The FERC commissioners and state regulators agreed to the establishment of an informal Staff Task Force to study best practices and matters pertinent to resource procurement issues. This agreement represented a concrete step that will allow state and federal regula-tors to continue their dialog for the purpose of developing a better under-standing of state and federal interests in the resource procurement area, narrow-ing differences between state and federal regulators, sharing relevant informa-tion, and helping both state and federal regulators to use their respective powers in a complementary manner. EEI sup-ports these efforts and will continue to attend and participate.

The most pressing issue in competi-tive markets today is to decide how to facilitate investment in new baseload plants along with the need to enhance our transmission infrastructure. EEI recommends that regional market structures should provide accurate price signals and stable, coordinated, and reasonable federal and state regulatory policies to promote efficient invest-ment and ensure long-term resource adequacy. EEI also recommends that affi liates should be allowed to compete in competitive procurements conducted

by regulated utilities to serve their own retail customers.

Transactions with affi liates should be conducted in a fair and transparent manner to protect against bias and favor to the affi liate of such a regulated utility, a determination that state commissions are well positioned to make. Competi-tive solicitations should not be the only option, and EEI supports FERC’s policy to continue to allow other approaches. EEI also has encouraged FERC to apply competitive solicitation guidelines truly as guidelines, not rigid requirements.

Conclusion

As the electricity business contin-ues to evolve at the wholesale and retail level, so must the relationship between federal and state regulators. New challenges posed by the growth of regional markets and strains on the transmission system are best addressed by working closely together in a spirit of cooperation and understanding. With a common goal to guide everyone—af-fordable, reliable power with greater regulatory certainty—the future will look bright indeed.

State Issues: The New Era of Rate Cases

With state commissions facing 40 or more new rate cases over the next several years, commissioners will need to decide a range of issues that will determine utilities’ fi nancial performance in the years ahead, including their ability to rebuild credit ratings. Many of these cases will address the need to update revenues and rates frozen during the transition to competitive retail mar-kets. All told, $40 billion or more in

revenues will be at issue in this new era of rate cases.

As the industry prepares for new rate cases, one fundamental concern is that many utilities, and many commissions, face signifi cant skills defi cits related to cost-of-service rate making. With attri-tion, retirements, and a prolonged lack of rate case activity, many organizations do not have the skills and experience needed to tackle the complex issues involved in updating utility revenues and rates in restructured markets.

The National Association of Regula-tory Utility Commissioners (NARUC) is providing training to help regulators prepare for this new era of rate cases. EEI also is providing training to mem-bers, focusing on cost-of-service ac-counting and rate making, and sharing information on recent innovations that address common restructuring-related problems and issues.

Cost of Capital

Allowed returns on equity granted to shareholder-owned electric utilities in state rate cases averaged 10.73% in 2004, down from 10.97% in 2003, and 11.16% in 2002.1

Achieving allowed returns that equal, on an expected value basis, utilities’ market-determined cost of capital is critical for an industry that needs to fi -nance new infrastructure to continue to provide safe, reliable, and environmen-tally responsible service. For utilities and policy makers, the key challenge is to ensure that return on equity determi-nations refl ect the new shareholder risks new shareholder risks newpresent in restructured markets, includ-ing risks related to fi nancial leverage. Unfortunately, the most commonly used cost of capital methodology, the

____________________________________________________1Regulatory Research Associates, Major Rate Case Decisions, January-March 2005.


POLICY OVERVIEW

Capital Asset Pricing Model (CAPM), relies on a backward-looking statistical analysis, which may not capture risks recently introduced via restructuring (e.g., increasing dependence on pur-chased power, increased load volatility due to customer switching).

A second, longer-term challenge is to calibrate regulatory policies in terms of their impact on the utility’s overall risk profi le (and therefore, its cost of capi-tal). Investors and rating agencies are increasingly sensitive to the impact that regulatory policies can have on utility risk. By taking account of such impacts, policymakers can effectively manage utilities’ costs of capital over time.

Both of these challenges imply the need for dialogue with policymak-ers. In May 2004, EEI sponsored an unprecedented meeting in New York City that brought together 16 state utility commissioners to participate in separate meetings with credit rating agencies, investment bankers, and secu-rity analysts, who explained how they saw their unique roles in the evolving utility environment. In turn, commis-sioners shared their thoughts on how their policies and decisions could pro-vide the market with renewed certainty and, at the same time, ensure just and reasonable rates. This was the fi rst step in a program that has since featured ad-ditional trips to Wall Street and a series of Internet conferences—all designed to improve understanding between the fi nancial community and the public utility commissions (PUCs).

Resource Procurement

The most important regulatory risk factors that rating agencies consider in evaluating utility risk involve the poli-cies and procedures by which utilities procure resources in increasingly volatile

(Continued on Page 108)

and uncertain operating environments, and recover associated costs in rates. A growing number of states have revised their planning and approval procedures to provide increased regulatory certainty to support needed new investment in generation and delivery infrastructure.

During 2004, a number of states also gave approval for utilities to purchase generating assets from affi liates and/or third parties for inclusion in rate base. PUCs approved these transfers because they were very benefi cial for consum-ers: typically, plants were purchased at a deep discount from distressed owners. Nevertheless, many of the transactions raised market power concerns at the Federal Energy Regulatory Commission (FERC), which has been working to build competitive wholesale electricity markets and sees the growth of rate-based generation as undermining the development of markets.

Clearly, federal/state jurisdictional confl ict in the area of supply planning and procurement is not in the public interest. It creates new uncertainty, which may discourage needed invest-ment. It also may jeopardize states’ ability to make resource decisions that balance a range of legitimate state (and consumer) interests (e.g., reliability, fuel diversity, environmental protec-tion, counter-party exposure, economic development, etc.).

Alternative Regulation

A third issue that directly affects the bottom line is “alternative regulation,” defined as regulatory policies that provide explicit incentives for defi ned performance outcomes. During 2004, nine new alternative regulation plans were approved.2

The most common form was re-turn-on-equity-sharing plans, in which a revenue requirement is approved (including a nominal allowed rate of return) with the understanding that if actual returns fall within a “deadband” (e.g., nominal plus or minus 50 basis points), the utility will retain all gains or absorb all losses. Outside the deadband, shareholders and customers will share savings, or cost overages, according to predefi ned ratios.

Alternative regulatory plans can be effective vehicles for reducing the ad-ministrative cost of regulation, strength-ening effi ciency incentives, and gaining new marketing and pricing fl exibility. When properly designed and volun-tarily entered into, alternative regulation represents a win/win for consumers and shareholders, and will be important for the future success of regulated electric utilities.

Risk Management

Restructuring and competitive mar-kets have heightened major risks for the industry. These risks infl uence all utili-ties to varying degrees, affecting their ability to restore investor confi dence, attract capital to build needed new infrastructure, and grow the business. The increase in operating and regula-tory risks, and their impact on utility risk profiles, are the direct result of three things: the unpredictable nature of wholesale electric and fuel markets; market rules that are still unresolved or do not fully compensate utilities for such obligations as provider of last resort (POLR); and continued uncertainty in many other areas, such as ongoing environmental regulation. Underpin-ning those risks are questions about whether the returns on equity set by state commissions will adequately refl ect those risks.

____________________________________________________2Regulatory Research Associates, Alternative Regulatory Plans/Incentive Ratemaking, February 2005.


POLICY OVERVIEW

INITIATIVE:

MARKET POWER: MARKET-BASED RATE AUTHORITY, MARKET POWER SCREENS, AND VERTICAL MARKET POWER ANALYSIS

FERC IMPOSES NEW MARKET POWER TEST AND MITIGATION MEASURES IN 2001 AND AGAIN IN 2004.

SEE INVESTIGATION OF TERMS AND CONDI-TIONS OF PUBLIC UTILITY MARKET-BASED RATE AUTHORIZATIONS, DOCKET NO. EL01-118-000; SEE ALSO CONFERENCE ON SUPPLY MARGIN ASSESSMENT, DOCKET NO. PL02-8-000, AEP POWER MARKETING INC. ET, AL. DOCKET NOS. ER96-2495-000, ET AL.

FERC ESTABLISHES GENERIC RULEMAKING ON MARKET POWER ISSUES, INCLUDING DECEMBER 7, 2004 TECHNICAL CONFERENCE ON TRANS-MISSION MARKET POWER AND BARRIERS TO ENTRY.

SEE MARKET-BASED RATES FOR PUBLIC UTILI-TIES, DOCKET NO. RM04-7-000.

MAJOR PROPOSALS:

• ORIGINALLY, FERC IMPOSED A NEW MARKET POWER TEST AND MITIGATION MEASURES, THE SUPPLY MARGIN ASSESSMENT (SMA) TEST, TO DETERMINE WHETHER A SUP-PLIER IS PIVOTAL IN A CONTROL AREA. IF A SUPPLIER PASSES THE TEST, FERC WOULD GRANT MBR AUTHORITY.

• SUBSEQUENTLY, FERC REPLACED THE SMA TEST WITH TWO INDICATIVE SCREENS FOR ASSESSING MARKET POWER ON AN INTERIM BASIS AND MODIFIED THE MITIGATION PREVIOUSLY ANNOUNCED. PASSING BOTH SCREENS CREATES A REBUTTABLE PRE-SUMPTION THAT THE APPLICANT DOES NOT POSSESS MARKET POWER, WHILE FAILURE OF EITHER OF THE SCREENS CREATES A REBUTTABLE PRESUMPTION THAT IT DOES. TO REBUT THE PRESUMPTION OF MARKET POWER, THE APPLICANT MUST FILE A DELIV-ERED PRICE TEST AND DETAILED HISTORICAL DATA OR GO DIRECTLY TO MITIGATION.

• FERC ESTABLISHED A GENERIC RULEMAKING TO REVIEW THE APPROPRIATE ANALYSIS FOR GRANTING MARKET-BASED RATE AUTHORITY, ADDRESSING GENERATION MARKET POWER, TRANSMISSION MARKET POWER, OTHER BARRIERS TO ENTRY, AND AFFILIATE ABUSE AND RECIPROCAL DEALING.

MAJOR IMPLICATIONS:

• THE ORIGINAL SMA TEST WOULD EFFEC-TIVELY FORCE UTILITIES TO EITHER JOIN AN RTO OR TO LOSE MUCH OF THEIR ABILITY TO SELL AT MARKET-BASED RATES IN THEIR SERVICE TERRITORY. A GENERATION COM-PANY THAT OPERATES A LARGE AMOUNT OF CAPACITY IN A NON-ISO/RTO AREA WOULD FACE SIMILAR DIFFICULTIES.

• THE ORIGINAL SMA TEST WOULD HAVE FAILED TO ACCOUNT FOR COMMITMENTS OF GENERATION TO SERVE NATIVE LOAD AND LONG-TERM CONTRACTUAL OBLIGATIONS, CONSEQUENTLY RESULTING IN LARGE NUM-BERS OF APPLICANTS FAILING THE TEST AND BEING DENIED MBR AUTHORITY.

• THE NEW “MARKET SHARE SCREEN” DOES NOT ACCURATELY MEASURE MARKET POWER BECAUSE IT FAILS TO COMPARE SUPPLY WITH DEMAND.

• THE DELIVERED PRICE TEST (DPT) IS COSTLY, AND CONTAINS A “MARKET SHARE” COMPO-NENT.

• ONE PRONG OF THE DPT EXAMINES AN APPLICANT’S TOTAL CAPACITY WITHOUT REGARD TO ITS COMMITMENTS TO SERVE NATIVE LOAD AND CONTRACTUAL OBLIGA-TIONS.

• A COMPANY’S OPTIONS FOR DEMONSTRAT-ING LACK OF MARKET POWER MAY BE MORE CONSTRAINED ONCE IT FAILS THE DPT.

• FERC’S MARKET POWER INITIATIVES AND MITIGATION APPROACHS MAY CONFLICT WITH STATE RESOURCE ADEQUACY AND PROCUREMENT DECISIONS LEADING TO INCREASED REGULATORY UNCERTAINTY AND RESULT IN ADVERSE INVESTMENT DECISIONS FOR TRANSMISSION INFRASTRUCTURE IMPROVEMENTS.

• NUMEROUS UTILITIES HAVE FILED FOR MBR AUTHORIZATION UNDER THE NEW SCREENS.

• FERC HAS ISSUED SECTION 206 ORDERS AGAINST NUMEROUS UTILITIES.

FERC MILESTONES:

• NOVEMBER 20, 2001, IN DOCKET NO. EL01-118, FERC ISSUED ORDER ESTABLISHING REFUND EFFECTIVE DATE AND PROPOSING

TO REVISE MARKET-BASED RATE TARIFFS AND AUTHORIZATIONS. 97 FERC ¶ 61,220 (2001) (SMA ORDER), REHEARING TOLLED ON JANUARY 18, 2002.

• AUGUST 23, 2002, IN DOCKET NOS. PL02-8 AND ER96-2495 ET AL., FERC ISSUED SMA NOPR.

• APRIL 14, 2004, IN DOCKET NOS. ER96-2495 ET AL., FERC REPLACED THE SMA TEST WITH TWO INDICATIVE SCREENS FOR ASSESSING MARKET POWER ON AN INTERIM BASIS AND MODIFIED THE MITIGATION ANNOUNCED IN THE SMA ORDER. AEP POWER MAR-KETING, INC., ET AL., 107 FERC ¶ 61,018 (2004) (“APRIL 14 MARKET POWER SCREEN ORDER”). ON JUNE 7, 2004, FERC ISSUED A TOLLING ORDER AND GRANTED AN EXTEN-SION OF TIME FOR COMPLIANCE FILINGS. AEP POWER MARKETING, INC., ET AL., DOCKET NO. ER96-2495-018, ET AL., (JUNE 7, 2004 –UNPUBLISHED). ON JULY 8, 2004, FERC ISSUED AN ORDER ON REHEARING OF THE APRIL 14 MARKET POWER SCREEN ORDER. AEP POWER MARKETING, INC., ET AL., 108 FERC ¶ 61,026 (2004).

• APRIL 14, 2004, IN DOCKET NO. RM04-7-000, FERC ISSUED A NOTICE ESTABLISHING A GE-NERIC RULEMAKING PROCEEDING, 107 FERC ¶ 61,019 (2004). TO DATE, FERC HAS HELD A TECHNICAL CONFERENCE ON JUNE 9, 2004, WITH THE DEADLINE FOR COMMENTS ON THE CONFERENCE SET FOR JUNE 30, 2004.

• OCTOBER 6, 2004, IN DOCKET NO. RM04-14-000 FERC ISSUED A NOPR TO AMEND ITS REGULATIONS AND TO MODIFY THE MBR AUTHORITY OF CURRENT MBR SELLERS TO ESTABLISH A REPORTING OBLIGATION FOR CHANGES IN STATUS THAT APPLY TO PUBLIC UTILITIES AUTHORIZED TO MAKE WHOLESALE POWER SALES IN INTERSTATE COMMERCE AT MBR. COMMENT DEADLINE WAS NOVEMBER 15, 2004.

• DECEMBER 7, 2004, IN DOCKET NO. RM04-7-000, FERC HELD A TECHNICAL CONFERENCE ON TRANSMISSION MARKET POWER AND BARRIERS TO ENTRY. THE CONFERENCE FO-CUSED ON WHETHER THE PRO FORMA OATT ADEQUATELY MITIGATES VERTICAL MARKET POWER.

• DECEMBER 9, 2004, IN DOCKET NO. RM04-7-000, FERC ISSUED A NOTICE CONCERNING POST-TECHNICAL CONFERENCE COMMENTS. COMMENTS DEADLINE IS JANUARY 10, 2005.

Major FERC Initiatives 2002-2005 UPDATED MAY 6, 2005 (ONGOING)


POLICY OVERVIEW

• DECEMBER 15, 2004, FERC ISSUED ORDERS ON 16 PENDING MARKET-BASED RATE FIL-INGS, PERMITTING MARKET-BASED RATES TO STAY IN PLACE WITHOUT FURTHER PRO-CEEDINGS IN ABOUT HALF THE CASES. FOR THOSE FAILING THE NEW MARKET POWER SCREEN, THEIR FUTURE POWER SALES AT MARKET-BASED RATES WILL BE SUBJECT TO A POTENTIAL REFUND OBLIGATION.

• JANUARY 27-28, 2005, FERC HELD A TECHNI-CAL CONFERENCE TO EXAMINE AFFILIATE ABUSE/RECIPROCAL DEALING AND GENERA-TION MARKET POWER. EEI’S CONTESTABLE LOAD ANALYSIS PRESENTED.

• FEBRUARY 10, 2005, IN DOCKET NO. RM04-14, FERC ISSUES ORDER NO. 652, 110 FERC ¶ 61,097 (2005) (FILING REQUIREMENT FOR A CHANGE IN STATUS WILL BE GENERALLY TRIGGERED BY: (1) A CHANGE IN OWNER-SHIP OR CONTROL OF GENERATION OR TRANSMISSION FACILITIES OR INPUTS TO ELECTRIC POWER PRODUCTION (EXCLUDING FUEL); OR (2) AFFILIATION WITH ANY ENTITY NOT DISCLOSED IN THE FILING THAT OWNS OR CONTROLS GENERATION OR TRANSMIS-SION FACILITIES OR INPUTS TO ELECTRIC POWER PRODUCTION OR AFFILIATION WITH ANY ENTITY THAT HAS A FRANCHISED SER-VICE AREA.

INITIATIVE:

ELECTRIC RELIABILITY

• FERC ESTABLISHES RULEMAKING ON RELIABILITY REGULATION IN ABSENCE OF LEGISLATION.

• SEE RULES CONCERNING CERTIFICATION OF AN ELECTRIC RELIABILITY ORGANIZATION AND THE ESTABLISHMENT APPROVAL, AND ENFORCEMENT OF ELECTRIC RELIABILITY STANDARDS, DOCKET NO. RM 04-2-000.

• FERC DIRECTED TRANSMISSION PROVIDER REPORTING ON VEGETATION MANAGEMENT PRACTICES.

• SEE REPORTING BY TRANSMISSION PROVID-ERS ON VEGETATION MANAGEMENT PRAC-TICES RELATED TO DESIGNATED TRANSMIS-SION FACILITIES, DOCKET NO. EL04-52-000.

• FERC PROVIDES RELIABILITY POLICY STATE-MENT.

• SEE POLICY STATEMENT ON MATTERS RE-LATED TO BULK POWER SYSTEM RELIABILTY, DOCKET NO. PL04-5-000.

• SEE ALSO SUPPLEMENT TO THE POLICY STATEMENT ON MATTERS RELATED TO BULK POWER SYSTEM RELIABILITY, DOCKET NO. PL04-5-001.

• FERC DIRECTED SPECIFIED POWER GRID OPERATORS AND TRANSMISSION PROVIDERS TO REPORT ON TRAINING PRACTICES.

• SEE SURVEY ON OPERATOR TRAINING PRAC-TICES, DOCKET NO. EL05-24-000.

MAJOR PROPOSALS:

• FERC HELD A CONFERENCE TO DISCUSS THE BLACKOUT, THE STATUS OF NERC’S PROPOS-AL FOR AN ELECTRIC RELIABILITY ORGANIZA-TION AND TO SOLICIT STAKEHOLDER VIEWS ON HOW FERC AND THE INDUSTRY SHOULD PROCEED ON RELIABILITY IN THE ABSENCE OF LEGISLATION.

• FERC ISSUED VEGETATION MANAGEMENT REPORT DETAILING PROBLEMS WITH VEG-ETATION MANAGEMENT RELATED TO THE AUGUST 2003 BLACKOUT.

• FERC DIRECTED ALL TRANSMISSION PROVID-ERS TO REPORT ON VEGETATION MANAGE-MENT PRACTICES THEY NOW USE FOR TRANSMISSION LINES AND RIGHTS-OF-WAYS. FERC DIRECTED REPORTING TO FERC, STATE COMMISSIONS, NERC, AND THE RELEVANT RELIABILITY COORDINATORS. THIS REPORT WAS DUE ON JUNE 17, 2004.

• FERC ENDORSES NEED TO EXPEDITIOUSLY MOVE TO MAKE NERC STANDARDS CLEAR AND ENFORCEABLE. FERC FINDS THAT ORDER NO. 888’S REFERENCE TO “GOOD UTILITY PRACTICES” INCLUDES COMPLIANCE WITH NERC RELIABILITY STANDARDS.

• FERC AFFIRMS THAT PRUDENTLY INCURRED RELIABILITY COSTS WILL BE RECOVERABLE.

• FERC WILL ESTABLISH A TASK FORCE TO EXAMINE NERC FUNDING ISSUES.

• FERC WILL EXECUTE A MEMORANDUM OF UNDERSTANDING WITH NERC.

• FERC WILL CONSIDER UTILITY PROPOSALS FOR TARIFF LIMITATION OF LIABILITY ON A CASE-BY-CASE BASIS.

• FERC WAIVES CERTAIN REGULATIONS TO ALLOW SELECTED NARUC REPRESENTATIVES WHO WILL WORK WITH FERC STAFF TO RE-VIEW VEGETATION MANAGEMENT INFORMA-TION FILED WITH FERC BASED ON EXECU-

TION OF APPROPRIATE NON-DISCLOSURE AGREEMENT.

MAJOR IMPLICATIONS:

• CHAIRMAN WOOD INDICATED THAT IN THE ABSENCE OF ENERGY LEGISLATION, FERC WILL CONSIDER SETTING ITS OWN GRID RELIABILITY STANDARDS, POSSIBLY BY THE SUMMER OF 2004.

• FERC STAFF HAVE APPARENTLY BEEN ASKED TO DETERMINE THE FERC’S LEGAL ALTERNA-TIVES FOR ESTABLISHING MANDATORY RELI-ABILITY STANDARDS.

• FERC STAFF HAVE BEEN DIRECTED TO DEVELOP AN ORDER THAT WILL REQUIRE TRANSMISSION SYSTEM OPERATORS TO RE-PORT VIOLATIONS OF CURRENT RELIABILITY STANDARDS TO FERC.

• TRANSMISSION PROVIDERS MUST REPORT ON THEIR CURRENT VEGETATION MANAGE-MENT PRACTICES, LIST ALL OF THEIR DES-IGNATED TRANSMISSION FACILITIES, STATE HOW OFTEN THEY INSPECT THEIR FACILITIES FOR VEGETATION MANAGEMENT, PROVIDE DATES, METHODOLOGY AND OUTCOMES OF RECENT INSPECTIONS, AND DESCRIBE ANY FACTORS THAT MAY PREVENT OR DELAY VEGETATION MANAGEMENT ACTIVITIES.

• FERC WILL CONSIDER ON A CASE-BY-CASE BASIS UTILITY-SPECIFIC ACTION ON RELI-ABILITY.

• ON AUGUST 30, IN DOCKET NO. ER04-1160, MISO/ATC FILED TO MAKE REVISIONS TO THE MISO OATT WITH REGARD TO LIMITATION OF LIABILITY AND INDEMNIFICATION. COM-MENTS ARE DUE ON SEPTEMBER 20, 2004. ON OCTOBER 28, 2004, FERC ISSUED A LET-TER ORDER REJECTING AS DEFICIENT MISO’S FILING. ON NOVEMBER 24, 2004, MISO FILED AN AMENDMENT TO ITS LIABILITY LIMITA-TION FILING, FERC ACTION IS PENDING.

• FEBRUARY 9, 2005, IN DOCKET NO. PL04-5-001, FERC CLARIFIES THAT “GOOD UTILITY PRACTICE,” AS USED IN THE OATT, INCLUDES COMPLIANCE WITH NERC’S VERSION 0F RELI-ABILITY STANDARDS.

FERC MILESTONES:

• NOVEMBER 2003, THE JOINT U.S.-CANADA TAKS FORCE INTERIM BLACKOUT REPORT IS ISSUED DESCRIBING CAUSES OF AUGUST 14, 2003 BLACKOUT – PROBLEM OF CONDUCTOR CONTACT WITH TREES IDENTIFIED AS COM-MON AMONG OUTAGES.


POLICY OVERVIEW

• DECEMBER 1, 2003, IN DOCKET NO. RM04-2, FERC HELD A CONFERENCE ON ELECTRIC RELIABILITY ISSUES.

• MARCH 2, 2004, FERC ISSUED ITS UTILITY VEGETATION MANAGEMENT REPORT.

• APRIL 5, 2004. THE U.S.-CANADA TASK FORCE RELEASED ITS FINAL REPORT ON CAUSES AND RECOMMENDATIONS FROM THE AUGUST 14, 2003 BLACKOUT.

• APRIL 19, 2004, IN DOCKET NO. EL04-52, FERC ISSUED ORDER REQUIRING REPORTING ON VEGETATION MANAGEMENT PRACTICES RELATED TO DESIGNATED TRANSMISSION FACILITIES, 107 FERC ¶ 61,053 (2004).

• APRIL 19, 2004, IN DOCKET NO. PL04-5, FERC ISSUED POLICY STATEMENT ON MATTERS RE-LATED TO BULK POWER SYSTEM RELIABILITY, 107 FERC ¶ 61,052 (2004).

• MAY 14, 2004, THE U.S.-CANADA POWER SYSTEM OUTAGE TASK FORCE AND FERC CO-HOSTED A TECHNICAL WORKSHOP.

• JUNE 15, 2004, IN DOCKET NO. EL04-52, FERC ISSUED ORDER WAIVING CERTAIN REGULATIONS, 107 FERC ¶ 61,269 (2004).

• JUNE 15, 2004, FERC HELD TECHNICAL CON-FERENCE, IN DOCKET NO. PL04-5.

• DECEMBER 27, 2004, IN DOCKET NO. EL05-24-000, FERC DIRECTS SPECIFIED POWER GRID OPERATORS AND TRANSMISSION PROVIDERS TO REPORT BACK TO FERC ON TRAINING PRACTICES BY JANUARY 31, 2005. FERC WILL REPORT TO CONGRESS ON TRANSMISION PROVIDER TRAINING. 105 FERC ¶ 61,365 (2004).

• JANUARY 25, 2005, FERC ISSUES ORDER ON CLARIFICATION, 110 FERC ¶ 61,050 (2005) IN RESPONSE, AMONG OTHER THINGS, TO EEI REQUEST TO CLARIFY THAT A SINGLE RESPONSE PER ENTITY CONSTITUTES COM-PLIANCE WITH THE COMMISSON’S SURVEY REQUEST. FERC’S CONSULTANT EXPECTED TO REPORT TO FERC IN MAY AND FERC TO REPORT WITH RECOMMENDATIONS TO CON-GRESS IN FALL 2005.

• FEBRUARY 9, 2005, IN DOCKET NO. PL04-5-001, FERC ISSUED SUPPLEMENT TO POLICY STATEMENT ON MATTERS RELATED TO BULK POWER SYSTEM RELIABLITY, 110 FERC ¶ 61,096 (2005).

• APRIL 2005, FERC STAFF ISSUES REPORT ON INFORMATION TECHNOLOGY GUIDELINES FOR POWER SYSTEMS ORGANIZATIONS.

INITIATIVE:

TRANSMISSION PRICING POLICY

FERC PROPOSED PRICING INCENTIVES FOR PARTICIPATION IN RTOS.

SEE PROPOSED PRICING POLICY FOR EFFICIENT OPERATION AND EXPANSION OF TRANSMISSION GRID, DOCKET NO. PL03-1-000.

SEE IMPEDIMENTS TO INVESTMENT IN ELECTRIC TRANSMISSION INFRASTRUCTURE AND POTEN-TIAL SOLUTIONS, AD05-5-000.

MAJOR PROPOSALS:

• TRANSMISSION OWNERS THAT TRANSFER CONTROL TO AN RTO BY DECEMBER 31, 2004, WILL RECEIVE AN ADDER OF 50 BASIS POINTS TO THEIR ROE.

• INDEPENDENT TRANSMISSION COMPANIES (ITCS) THAT PARTICIPATE IN AN RTO AND THAT MEET THE INDEPENDENT OWNER-SHIP REQUIREMENT WILL QUALIFY FOR AN ADDITIONAL 150 BASIS POINTS APPLIED TO THE BOOK VALUE OF FACILITIES AT TIME OF DIVESTITURE.

• TRANSMISSION OWNERS THAT INVEST IN NEW TRANSMISSION, CONSISTENT WITH RTO PLANS, WOULD RECEIVE AN ADDITIONAL 100 BASIS POINTS.

MAJOR IMPLICATIONS:

• THE 50 BASIS POINTS IS POSITIVE, BUT ELIGI-BILITY MAY NOT INCLUDE COMPANIES THAT HAVE ALREADY TRANSFERRED CONTROL TO AN ISO.

• THE 150 BASIS POINTS IS POSITIVE, BUT FERC’S PROPOSAL CONTAINS A BIAS FOR DIVESTITURE.

• THIS POLICY COULD INCREASE TRANSMIS-SION COSTS AND ADVERSELY AFFECT THE ABILITY OF STATES AND CONSUMERS TO PROTECT RETAIL CONSUMERS.

• FERC PROVIDES INCENTIVES IN APPROV-ING VARIOUS RTOS, E.G., 50 BASIS POINTS TO RTO MEMBERSHIP IN MISO, 102 FERC ¶ 61,292 (2002), REH’G DENIED, 102 FERC ¶ 61,143 (2003)(MISO ROE SET AT 12.88%); SAME TO PJM, BUT NO 100 BASIS POINT ADDER FOR TRANSMISSION INVESTMENT. 104 FERC ¶ 61,124, REH’G, 105 FERC ¶ 61,123 (2003); SEE ALSO ALLEGHENY, 106 FERC ¶ 61,003 (2004). FOR RTO-NE, ISSUE OF WHETHER THE 100 BASIS POINT ADDER IS NECESSARY TO ENCOURAGE TRANSMISSION

INVESTMENT IN NEW TRANSMISSION FACILI-TIES SET FOR HEARING 106 FERC ¶ 61,280 (2004).

• FERC HAS ALSO ALLOWED FOR UTILITIES TO MODIFIY RATES TO INCLUDE CONSTRUCTION WORK IN PROGRESS (CWIP). SEE, E.G., ATC, 107 FERC ¶ 61,117 (2004).

FERC MILESTONES:

• JANUARY 15, 2003, FERC ISSUED PROPOSED PRICING POLICY. 102 FERC ¶ 61,032 (2003).

• APRIL 22, 2005, FERC HELD A TECHNICAL CONFERENCE, IN DOCKET NO. AD05-5 AND PL03-1, INTENDED TO EXAMINE IMPEDI-MENTS TO INVESTMENT IN ELECTRIC TRANS-MISSION INFRASTRUCTURE AND EXPLORE POTENTIAL SOLUTIONS, INCLUDING THE FORMATION OF NEW BUSINESS MODELS AS WELL AS APPROPRIATE RATEMAKING INCEN-TIVES THAT WOULD ENCOURAGE NEW IN-VESTMENT. DISCUSSION TOPICS INCLUDED: (1) INVESTMENT TRENDS IN TRANSMISSION; (2) CHALLENGES FACING CURRENT OWNERS OPERATORS AND USERS; (3) A CASE STUDY OF COOPERATION BETWEEN STATES AND PRIVATE INDUSTRY TO BUILD THE FRON-TIER LINE; (4) THE ROLE OF INDEPENDENT TRANSMISSION COMPANIES; AND (5) PAR-TICIPATION BY PUBLIC POWER.

• FERC HAS NOT ISSUED FINAL POLICY YET.

INITIATIVE:

STANDARDS OF CONDUCT

FERC ESTABLISHED NEW STANDARDS OF CON-DUCT FOR TRANSMISSION PROVIDERS AND ALL THEIR ENERGY AFFILIATES.

SEE STANDARDS OF CONDUCT FOR TRANSMIS-SION PROVIDERS, DOCKET NO. RM01-10-000.

MAJOR PROPOSALS:

• PROPOSED SET OF STANDARDS TO GOVERN RELATIONSHIPS BETWEEN REGULATED TRANSMISSION PROVIDERS AND ALL THEIR ENERGY AFFILIATES.

• REQUIRED SEPARATION OF THE TRANSMIS-SION FUNCTION FROM ALL ENERGY AFFILI-ATES, INCLUDING SALES AND MARKETING FUNCTION.

MAJOR IMPLICATIONS:

• THE FINAL RULE SIGNIFICANTLY CHANGES STANDARDS OF CONDUCT AS ORIGINALLY


POLICY OVERVIEW

IMPOSED ON TRANSMISSION PROVIDERS BY ORDER NO. 889.

• THE FINAL RULE DOES NOT ADOPT MANY OF THE RESTRICTIVE RECOMMENDATIONS IN THE NOPR.

• THE FINAL RULE REFLECTS MANY OF THE COMMENTS FROM EEI AND MEMBER COMPA-NIES.

• THE FINAL RULE REFLECTS EEI’S CONCERNS OVER IMPACT OF RULE WITH SARBANES-OXLEY REPORTING REQUIREMENTS BY AL-LOWING ALL SENIOR OFFICERS TO EXERCISE CORPORATE GOVERNANCE ROLE OVER TRANSMISSION AND OTHER FUNCTIONS.

• FERC APPROVED ISOS/RTOS ARE NOT SUB-JECT TO THE STANDARDS AND PARTICIPAT-ING UTILITIES MAY SEEK AN EXEMPTION.

• THE FINAL RULE ALLOWS FOR SHARING OF EMPLOYEES, INCLUDING SENIOR MAN-AGEMENT, FIELD MAINTENANCE, LEGAL, ACCOUNTING, ETC., BUT THEY CANNOT BE A CONDUIT OF TRANSMISSION INFORMATION.

• TRANSMISSION PROVIDERS MUST IDENTIFY A CHIEF COMPLIANCE OFFICER AND ALL OF-FICERS, DIRECTORS, AS WELL AS EMPLOYEES WITH ACCESS TO TRANSMISSION INFORMA-TION MUST BE TRAINED.

• THE FINAL RULE DOES NOT REQUIRE SEPA-RATION OF TRANSMISSION AND BUNDLED RETAIL OPERATIONS.

• ORGANIZATIONAL CHARTS AND OTHER COR-PORATE INFORMATION MUST BE POSTED ON OASIS.

• FERC PLANS AN AGGRESSIVE PROGRAM OF AUDITING AND ENFORCEMENT.

• COMPANIES MUST BE IN COMPLIANCE BY SEPTEMBER 22, 2004.

FERC MILESTONES:

• SEPTEMBER 27, 2001, FERC ISSUED NOPR. IV FERC STATS. & REGS. REGULATIONS PRE-AMBLES ¶ 32,555 (2001).

• MAY 21, 2002, FERC HELD TECHNICAL CON-FERENCE.

• NOVEMBER 23, 2003, FERC ISSUED ORDER NO. 2004, 105 FERC ¶ 61, 248 (2003).

• APRIL 16, 2004, FERC ISSUED ORDER NO. 2004-A, 107 FERC ¶ 61,032 (2004).

• AUGUST 2, 2004, FERC ISSUED ORDER NO. 2004-B, 108 FERC ¶ 61,118 (2004).

• DECEMBER 15, 2004, IN DOCKET NOS. PA04-11-000, AND PA04-13-000, FERC ISSUED ORDERS FINDING TWO ARIZONA UTILITIES IN VIOLATION OF RULES ON TRANSMISSION SERVICE AND ORDERD MONETARY AND PROCEDURAL CORRECTIONS.

• DECEMBER 21, 2004, FERC ISSUED ORDER NO. 2004-C, 109 FERC ¶ 61,325 (2004), REAFFIRMING ORDER NO. 2004, PROVIDING ADDITIONAL CLARIFICAITON TO SOME OF ITS PROVISIONS, INCLUDING DENYING REHEAR-ING ON EXEMPTIONS FOR ELECTRIC LOCAL DISTRIBUTION COMPANIES – MANY SUCH COMPANIES ARE NOT ENERGY AFFILIATES BECAUSE THEY DO NOT ENGAGE IN WHOLE-SALE MAREKT ACTIVITIES.

• MARCH 23, 2005, FERC ISSUED ORDER NO. 2004-D, 110 FERC ¶ 61,320 (2005) (ORDER ON REQUEST FOR CLARIFICATION THAT CA-NADIAN GAS DISTRIBUTION COMPANIES MAY QUALIFY FOR AN EXEMPTION FROM ENERGY AFFILIATE STATUS).

• MAY 6, 2005 FERC WILL HOLD TECHNICAL CONFERENCE ON STANDARDS OF CONDUCT.

INITIATIVE:

ENTERGY ICT PROPOSAL

SEE DOCKET NO. EL05-52-000

SEE ALSO DOCKET NO. ER03-1272-000

MAJOR PROPOSALS:

• FERC ACCEPTED ENTERGY’S PROPOSAL TO ESTABLISH AN INDEPENDENT COORDINATOR OF TRANSMISSION (ICT), BUT LIMITED EN-TERGY’S TRANSMISSION PRICING PROPOSAL TO TWO YEARS AND CONDITIONED THE ICT PROPOSAL TO ADD MONITORING AND REPORTING CONDITIONS. THE COMMISSION DIRECTED ENTERGY TO FILE ADDITIONAL TARIFF INFORMATION SPECIFYING THE RE-SPONSIBILITIES AND DUTIES OF THE ICT AND TO CLEARLY STATE THE ICT’S AUTHORITY REGARDING REQUESTS FOR TRANSMISSION SERVICE. FERC ALSO DIRECTED ENTERGY TO PROVIDE ADDITIONAL INFORMATION ON ITS METHOD FOR PROVIDING FIRM TRANSMIS-SION RIGHTS TO CUSTOMERS THAT PAY FOR TRANSMISSION UPGRADES. FERC ALSO STATED THE EXPECTATION THAT THE SOUTHWEST POWER POOL WOULD BECOME

ENTERGY’S ICT. FURTHER, FERC ENCOUR-AGED ENTERGY AND THE ICT TO REMOVE RATE PANCAKING FOR TRANSMISSION BETWEEN THE TWO SYSTEMS.

• FERC ALSO ISSUES ORDER HOLDING HEAR-ING IN ABEYANCE IN ER03-1272 INVOLVING INVESTIGATION INTO ENTERGY’S AVAILABLE FLOWGATE CAPACITY PROGRAM. 110 FERC ¶ 61,296 (2005).

MAJOR IMPLICATIONS:

• FERC’S APPROVAL OF THE ICT AND ITS SUC-CESSFUL IMPLEMENTATION MAY PROVIDE AN ALTERNATIVE RESTRUCTURING MODEL IN THOSE REGIONS THAT HAVE CHOSEN NOT FORM RTOS.

• ENTERGY WILL SUBMIT A NEW FILING TO FERC TO IMPLEMENT THE ICT PROPOSAL CONSISTENT WITH THE GUIDANCE PROVIDED IN THE MARCH 22 ORDER AND THE COMMIT-MENTS SET FORTH IN ENTERGY’S REQUEST FOR CLARIFICATION REGARDING THE RE-SPECTIVE ROLES OF ENTERGY AND THE ICT IN TRANSMISSION SYSTEM PLANNING AND THE START AND END DATES FOR THE INITIAL TWO-YEAR PERIOD OF ICT OPERATIONS.

FERC MILESTONES:

• MARCH 22, 2005, FERC ISSUES ENTERGY, 110 FERC ¶ 61,295 (2005) ORDER ON PETI-TION FOR DECLARATORY ORDER. ENTERGY MUST ADD MONITORING AND REPORTING REQUIREMENTS, AND FERC SAYS IT IS WILL-ING TO APPROVE ENTERGY’S TRANSMIS-SION PRICING PROPOSAL FOR A TWO-YEAR PERIOD.

• MARCH 22, 2005, FERC ISSUES ORDER HOLDING HEARING IN ABEYANCE IN ER03-1272 INVOLVING INVESTIGATION INTO ENTERGY’S AVAILABLE FLOWGATE CAPACITY PROGRAM. 110 FERC ¶ 61,296 (2005).

INITIATIVE:

POTENTIAL NEW TRANSMISSION SERVICES

SEE DOCKET NO. RM05-7-000 AND AD04-13-000

MAJOR PROPOSALS:

• BPA PLANS TO PROPOSE A “CONDITIONAL-FIRM PRODUCT” INTENDED TO OPTIMIZE USE THE EXISTING TRANSMISSION SYSTEM AND THE ABILITY TO OBTAIN TRANSMISSION SERVICE AS WELL AS PROVIDE CUSTOMERS WITH MORE FLEXIBILITY. BPA PROPOSED


POLICY OVERVIEW

THAT THIS NEW SERVICE WOULD PROVIDE FOR AS MANY MONTHS OF FIRM SERVICE AS POSSIBLE DURING THE YEAR, COMBINED WITH A CERTAIN NUMBER OF HOURS IDENTI-FIED FOR POTENTIAL UNAVAILABILITY OF CAPACITY OVER A SET NUMBER OF MONTHS, WEEKS, OR DAYS. BPA FURTHER PROPOSED THAT CUSTOMERS WOULD PAY FIRM TRANS-MISSION RATES FOR THE PERCENTAGE OF THE YEAR THAT THEY ARE GUARANTEED TO RECEIVE FIRM TRANSMISSION.

MAJOR IMPLICATIONS:

• AS STATE RENEWABLE PORTFOLIO REQUIRE-MENTS (RPS) COMPLIANCE INVOLVES RAPID GROWTH, RENEWABLE ENERGY WHOLESALE MARKETING ENTITIES WILL SEEK MORE ADVANTAGEOUS TRANSMISSION SERVICES. AS PART OF THIS, RENEWABLE ENERGY ADVOCACY INCREASINGLY CHALLENGES THERMAL RESOURCES FOR SCARCE DELIV-ERY SERVICES, ESPECIALLY IN WECC.

FERC MILESTONES:

• ON MARCH 16-17, 2005, FERC HELD A TECHNI-CAL WORKSHOP TO DEVELOP CLEAR DEFINI-TIONS FOR ADDITIONAL WHOLESALE ELECTRIC TRANSMISSION SERVICES, E.G., CONDITIONAL FIRM TRANSMISSION SERVICE, DEVELOP AP-PLICABLE PRO FORMA TARIFF LANGUAGE THAT COULD BE INCLUDED IN PUBLIC UTILITIES’ OATTS AND ADDRESS ATTENDANT ISSUES.

INITIATIVE:

WIND POWER INTERCONNECTION

SEE DOCKET NO. RM05-4-000

MAJOR PROPOSALS:

• SINCE THE INTERCONNECTION PROCEDURES ADOPTED IN ORDER NO. 2003 ARE TAILORED TO MORE TRADITIONAL POWER GENERA-TION SOURCES, FERC’S PROPOSAL WOULD INCLUDE CERTAIN TECHNICAL REQUIRE-MENTS THAT TRANSMISSION PROVIDERS MUST APPLY TO INTERCONNECTION SERVICE FOR WIND GENERATION PLANTS. THESE REQUIREMENTS WOULD BE APPLIED IN ADDITION TO THE STANDARD INTER-CON-NECTION PROCEDURES ADOPTED IN ORDER NO. 2003. FERC IS PROPOSING TO REQUIRE WIND PLANTS TO DEMONSTRATE THE ABIL-ITY TO CONTINUE OPERATION EVEN IF A LOW VOLTAGE CONDITION IS EXPERIENCED ON THE GRID, TO STABILIZE VOLTAGE LEVELS AND HELP THE TRANSMISSION GRID STAY IN BALANCE. WIND-POWERED FACILITIES FURTHER WOULD BE REQUIRED TO HAVE SUPERVISORY CONTROL AND DATA ACQUISI-

TION (“SCADA”) CAPABILITY TO ENSURE REAL-TIME COMMUNICATION WITH TRANS-MISSION PROVIDERS. FERC ALSO SOUGHT COMMENT ON WHETHER THERE ARE OTHER GENERATING TECHNOLOGIES THAT SHOULD COMPLY WITH THESE TECHNICAL REQUIRE-MENTS.

MAJOR IMPLICATIONS:

• PROPOSED APPENDIX G WOULD REQUIRE WIND FARMS TO MEET REQUIREMENTS FOR LOW VOLTAGE RIDE-THROUGH AND POWER FACTOR. THIS WOULD REMOVE EXISTING EXEMPTIONS PROVIDED FOR BY ORDER NO. 2003 (LGIA PROCEDURE). EEI SUPPORTS CONDITIONALLY REQUESTING THAT FERC RE-PLACE ITS REQUIREMENTS WHEN NERC OR REGIONAL COUNCILS ESTABLISH APPLICABLE STANDARDS.

FERC MILESTONES:

• JANUARY 24, 2005, FERC ISSUES INTERCON-NECTION FOR WIND ENERGY AND OTHER ALTERNATIVE TECHNOLOGIES, 110 FERC ¶ 61,036 (2005)(NOTICE OF PROPOSED RULE-MAKING)

• FEBRUARY 23, 2005, FERC HOLDS CONFER-ENCE TO DISCUSS DEVELOPMENT OF TRIBAL WIND ENERGY RESOURCES.

• MARCH 2, 2005, EEI SUBMITS COMMENTS IN DOCKET NO. RM05-4-000.

• COMMENTS ON NOPR DUE MAY 26, 2005.

INITIATIVE:

ENERGY IMBALANCE

SEE DOCKET NO. RM05-10-000 AND AD04-13-000

MAJOR PROPOSALS:

• FERC PROPOSED RULES TO ACCOMMODATE INTERMITTENT RESOURCES, INCLUDING WIND. THIS PROPOSAL WOULD ESTABLISH A NEW GENERATOR IMBALANCE SERVICE SCHEDULE UNDER THE OATT FOR INTERMIT-TENT RESOURCES. THE NEW PROPOSED SERVICE SCHEDULE SETS UP AN INTERMIT-TENT GENERATOR IMBALANCE BANDWIDTH OF PLUS OR MINUS TEN PERCENT FOR DIFFERENCES BETWEEN THE AMOUNT SCHEDULED TO BE GENERATED AND THE ACTUAL AMOUNT GENERATED FOR EACH HOUR. DEVIATIONS WITHIN THE PLUS OR MINUS 10 PERCENT BANDWIDTH WILL BE PRICED AT THE TRANSMISSION PROVIDER’S SYSTEM INCREMENTAL/DECREMENTAL COST AT THE TIME OF THE DEVIATION. DEVIATIONS

OUTSIDE THE BANDWIDTH WILL BE PRICED AT THE TRANSMISSION PROVIDER’S SYSTEM INCREMENTAL/DECREMENTAL COST PLUS OR MINUS 10 PERCENT.

• FERC’S PROPOSAL REITERATES THE EXISTING PRO FORMA TARIFF PROVISION THAT ALLOWS FOR THE MODIFICATION OF GENERATION SCHEDULES UP TO 20 MINUTES BEFORE THE HOUR TO MINIMIZE EXPOSURE TO THE COSTS ASSOCIATED WITH IMBAL-ANCES.

MAJOR IMPLICATIONS:

• FERC PROPOSES SEPARATE IMBALANCE PRO-VISIONS FOR INTERMITTENT RESOURCES. THIS PROPOSAL RAISES QUESTIONS FOR NETWORK RELIABILTY AND POTENTIAL GAM-ING IN GENERATION SCHEDULING.

• FERC PROPOSES WHERE A TRANSMISSION PROVIDER’S TARIFF INCLUDES A GENERATOR IMBALANCE CHARGE PROVISION MORE LE-NIENT THAN IN THIS PROPOSAL, FERC PRO-POSES THAT THE TRANSMISSION PROVIDER ASSESSES THE LESSER CHARGE. FERC DOES NOT PROPOSE TO MODIFY EXISTING ENERGY IMBALANCE SERVICE UNDER THE TARIFF AND SOUGHT COMMENT ON WHETHER GEN-ERATOR IMBALANCE PROVISIONS IN FUTURE INTERCONNECTION AGREEMENTS SHOULD CONFORM TO FERC’S PROPOSAL.

FERC MILESTONES:

• APRIL 14, 2005, FERC ISSUES NOTICE OF PROPOSED RULEMAKING IN IMBALANCE PROVISIONS FOR INTERMITTENT RESOURC-ES, IN DOCKET NOS. RM05-10-000 AND AD04-13-000.

INITIATIVE:

REACTIVE POWER PRICING

SEE DOCKET NO. AD05-1-000

SEE ALSO MISO, DOCKET NO. ER04-961-000

MAJOR PROPOSALS:

• JUNE 25, 2004, IN DOCKET NO. ER04-961-000, MISO AND AMERICAN TRANSMISSION COMPANY (ATC) PROPOSED TO COMPENSATE THOSE GENERATION RESOURCES NOT CUR-RENTLY COVERED BY THE EXISTING REAC-TIVE POWER RATE SCHEDULE

• OCTOBER 1, 2004, FERC REJECTED MISO’S PROPOSED REACTIVE POWER FILING AS UNDULY DISCRIMINATORY, BUT ALSO FOUND MISO’S EXISTING REACTIVE POWER RATE


POLICY OVERVIEW

SCHEDULE TO BE UNJUST, UNREASONABLE AND UNDULY DISCRIMINATORY FERC INDI-CATES THAT ALL PROVIDERS OF REACTIVE POWER SHOULD BE COMPENSATED UNDER COMPARABLE TERMS AND CONDITIONS.

• DECEMBER 15, 2004, FERC STAFF PRESENT REPORT REGARDING REATIVE POWER. THE REPORT DESCRIBES THE ROLE OF REACTIVE POWER IN ESTABLISHING RELIABLE POWER SYSTEMS, REGULATORY POLICY AND RECEIVE POWER PRICING AND MARKET DESIGN. THE REPORT ALSO EXAMINES THE PHYSICAL CHARACTERISTICS AND COSTS OF PRODUC-ING REACTIVE POWER.

MAJOR IMPLICATIONS:

• EXISTING REACTIVE POWER RATE SCHED-ULES MAY BE FOUND DISCRIMINATORY IN LIGHT OF FERC’S FINDINGS IN DOCKET NO. ER04-961-000.

• FERC MAY REQUIRE COMPENSATION FOR REACTIVE POWER FOR PRODUCTION WITHIN LEAD/LAG BAND IN ALL REGIONS.

• FERC MAY REQUIRE COMPARABLE PRICING OF REACTIVE POWER.

• FERC MAY REQUIRE CAPABILITY TsO BE TREATED DIFFERENTLY FROM PRODUCTION -- MORE TO BE PAID FOR DYNAMIC THAN STATIC CAPABILITY, AND WITH ALL SOURCES TO BE PAID SAME PRICE FOR PRODUCTION.

FERC MILESTONES:

• OCTOBER 1, 2004, IN DOCKET NO. ER04-961-000, FERC ISSUED MISO, 109 FERC 61,005 (2004) (REJECTING MISO’S REACTIVE POWER PRICING PROPOSAL).

• DECEMBER 15, 2004, IN DOCKET NO. AD05-1-000, FERC STAFF ISSUED REPORT ON REAC-TIVE POWER. THIS REPORT INCLUDED A DIS-CUSSION OF THE REGULATORY TREATMENT OF REACTIVE POWER, CURRENT ISSUES, AND IDENTIFIED PRICING AND PROCUREMENT OPTIONS. THE REPORT ALSO PROVIDED RECOMMENDATIONS, AND PRESENTED OVER 50 SPECIFIC QUESTIONS.

• MARCH 3, 2005, FERC HELD A TECHNICAL CONFERENCE TO ADDRESS REACTIVE POWER ISSUES ORGANIZED IN THREE PANELS AD-DRESSING: (1) RELIABILITY AND TECHNICAL ISSUES; (2) SHORT-TERM REACTIVE POWER ISSUES; AND (3) PROSPECTIVE REACTIVE POWER SOLUTIONS. SEVERAL EEI MEMBERS PARTICIPATED IN THE TECHNICAL CONFER-ENCE PROVIDING WITNESSES AND PRESEN-

TATIONS. EEI SUBMITTED COMMENTS IN THIS PROCEEDING ON APRIL 4, 2004.

• MARCH 8, 2005, FERC ISSUES MISO, 110 FERC ¶ 61,267 (2005), DENYING REHEARING.

INITIATIVE:

INTERLOCKING DIRECTORATES


MAJOR PROPOSALS:

• FERC IS PROPOSING TO AMEND ITS REGULA-TIONS TO CLARIFY THE TIME FRAME WITHIN WHICH INDIVIDUALS MUST FILE APPLICA-TIONS FOR AUTHORIZATION TO HOLD INTERLOCKING POSITIONS, AND INFORMA-TION PROVIDED IN CERTAIN INFORMATIONAL REPORTS REQUIRED FOR AUTOMATIC AUTHORIZATION OF CERTAIN INTERLOCKING POSITIONS.

MAJOR IMPLICATIONS:

• FERC WOULD REQUIRE PERSONS WANTING TO HOLD AN INTERLOCKING DIRECTORATE TO SEEK COMMISSION APPROVAL PRIOR TO ASSUMING THE DUTIES OF BOTH POSITIONS, RATHER THAN THE CURRENT OPTION OF APPLYING FOR PERMISSION UP TO 30 DAYS AFTER THE FACT - HOWEVER, THE COM-MISSION WOULD MAINTAIN THE CURRENT EXCEPTION FOR AFFILIATED UTILITIES, WITH A COUPLE MODIFICATIONS.

• FERC WOULD REQUIRE PERSONS PLANNING TO SERVE AS AN OFFICER OR DIRECTOR OF MULTIPLE AFFILIATED UTILITIES TO FILE AN INFORMATIONAL REPORT BEFORE HOLDING THE INTERLOCKING DIRECTORATE, RATHER THAN THE CURRENT OPTION OF FILING THE REPORT UP TO 30 DAYS AFTER THE FACT, AND TO INDICATE IN THE REPORT THE DATES THEY PLAN TO ASSUME THE OFFICER OR DI-RECTOR POSITIONS - THESE NEW REQUIRE-MENTS WOULD NOT APPLY TO PERSONS ALREADY AUTHORIZED TO HOLD THIS TYPE OF INTERLOCKING DIRECTORATE UNDER THE COMMISSION’S CURRENT RULES.

• FERC WOULD ELIMINATE THE CURRENT WAIVER OF THE PRECEDING REQUIREMENTS FOR PERSONS SERVING AS AN OFFICER OR DIRECTOR OF A COMPANY WITH MARKET BASED RATE AUTHORITY AND A UTILITY, UN-DERWRITER, OR SUPPLIER - THOSE PERSONS NOW SIMPLY FILE AN ABBREVIATED STATE-MENT ABOUT THE INTERLOCKING DIRECTOR-ATE WITHOUT A DEADLINE.

FERC MILESTONES:

• MARCH 25, 2005, FERC ISSUED NOTICE OF PROPOSED RULEMAKING, COMMISSION AUTHORIZATION TO HOLD INTERLOCKING DIRECTORATES, 110 FERC ¶ 61,343 (2005).

INITIATIVE:

RTO COST RECOVERY PRACTICES


MAJOR PROPOSALS:

• ON SEPEMBER 15, 2004, FERC INVITED COM-MENTS ON ITS ACCOUNTING AND FINANCIAL REPORTING REQUIREMENTS FOR OVERSIGHT OF RTO/ISO COSTS.

MAJOR IMPLICATIONS:

• FERC MAY CONSIDER CHANGES TO THE UNIFORM SYSTEM OF ACCOUNTS TO BETTER ACCOUNT AND REPORT RTO/ISO FINANCIAL INFORMATION.

• FERC MAY CONSIDER WHETHER RTOS/ISOS HAVE APPROPRIATE INCENTIVES TO BE COST EFFICIENT.

• FERC MAY CONSIDER CHANGES TO COST RECOVERY PRACTICES TO ENSURE THAT THE RATES CHARGED BY RTOS/ISOS AND THEIR MEMBER TRANSMISSION-OWNING PUBLIC UTILITIES ARE JUST AND REASONABLE.

• FERC MAY CONSIDER CHANGES TO EXISTING RATE REVIEW MECHANISMS, E.G., QUAR-TERLY AND ANNUAL FINANCIAL REPORTS.

FERC MILESTONES:

• SEPTEMBER 16, 2004, IN DOCKET NO. RM04-12-000, FERC ISSUED A NOTICE SEEKING COMMENTS. 108 FERC ¶ 61,237 (2004).

• FERC HAS NOT YET ISSUED AN ORDER IN THIS PROCEEDING.

INITIATIVE:

MIDWEST ISO START-UP

SEE DOCKET NO. ER04-691-014

MAJOR PROPOSALS:

• FERC ACCEPTED THE MISO CERTIFICATION THAT IT IS READY TO LAUNCH ITS ENERGY


POLICY OVERVIEW

MARKETS ON APRIL 1, 2005. MISO ENERGY MARKETS WILL OPERATE UNDER THE OPEN ACCESS TRANSMISSION AND ENERGY MARKETS TARIFF (TEMT), APPROVED IN AN AUGUST 2004 ORDER, REQUIRED FOR THE IMPLEMENTATION OF A MARKET-BASED CONGESTION MANAGEMENT PROGRAM AND ENERGY SPOT MARKETS. IMPLEMENTATION OF THE DAY 2 MARKET ON APRIL 1 INCLUDES A DAY-AHEAD ENERGY MARKET AND A REAL-TIME ENERGY MARKET, LOCATIONAL MARGINAL PRICING (LMP) AND A MARKET FOR FTRS. TO ADDRESS THE LACK OF HISTORY OF CENTRALIZED POWER POOL DISPATCH, FERC DIRECTED MISO TO IMPLE-MENT ADDITIONAL SAFEGUARDS TO ENSURE PROTECTIONS FOR WHOLESALE CUSTOM-ERS DURING STARTUP AND TRANSITION TO FULLY FUNCTIONING DAY 2 MARKETS.

• FERC ALSO ESTABLISHED MEASURES TO PROVIDE MARKET PARTICIPANTS IN LOAD POCKETS WITH ENHANCED PROTECTION AGAINST CONGESTION CHARGES ASSOCI-ATED WITH REMOTE NETWORK RESOURCES OR SYSTEM PURCHASES FROM OUTSIDE OF EXISTING LOAD POCKETS.

MAJOR IMPLICATIONS:

• THE MIDWEST ISO FORMALLY LAUNCHED ITS MIDWEST ENERGY MARKETS EARLY FRIDAY WHEN IT BEGAN CENTRALLY DISPATCHING WHOLESALE ELECTRICITY AND TRANSMIS-SION SERVICE THROUGHOUT MUCH OF THE MIDWEST. THE MIDWEST ISO NOW MANAGES ONE OF THE WORLD’S LARGEST CENTRALLY DISPATCHED ENERGY MARKETS, SPANNING 97,000 MILES OF TRANSMISSION LINES ACROSS 15 STATES AND THE PROVINCE OF MANITOBA WITH A PEAK LOAD OF 119,000 MW.

FERC MILESTONES:

• AUGUST 6, 2004, ORDER APPROVING MISO’S TEMT FOR DAY 2 OPERATIONS, 108 FERC ¶ 61,163 (2004).

• NOVEMBER 8, 2004, REHEARING ORDER OF AUGUST 6, 2004 ORDER. 109 FERC ¶ 61,157 (2004) (DIRECTS MISO TO CLARIFY FTR PRO-CEDURES, REVENUE REQUIREMENTS FROM LMP MARKETS, THE MUST OFFER REQUIRE-MENT, CREDIT POLICY, AND VARIOUS DEFINI-TIONS).

• DECEMBER 20, 2004, ORDER ACCEPTING MISO COMPLIANCE FILINGS, 109 FERC ¶ 61,285 (2004).

• MARCH 16, 2005, ORDER ON CERTIFICATION, 110 FERC ¶ 61,289 (2005), AND ON APRIL 1, 2005, MISO LAUNCHES ENERGY MARKETS.

• APRIL 15, 2005, FERC ADDRESSED RE-QUESTS FOR REHEARING OF ITS NOVEM-BER 8, 2004 ORDER ON TEMT. 111 FERC ¶ 61,043 (2005) (FERC ACCEPTS MISO SAFETY NET MITIGATION PLAN, PROPOSED TIME-LINE FOR LONG-TERM DAY-AHEAD MITIGA-TION, AND AFFIRMS PRIOR APPROVAL OF RESOURCE ADEQUACY REQUIREMENTS).

• APRIL 15, 2005, MISO, 111 FERC ¶ 61,053 (2005)(DIRECTS CHANGES TO MISO PENAL-TIES PROPOSAL FOR PHYSICAL WITHHOLD-ING, ACCEPTS CREDIT POLICY, COMMIS-SIONER KELLIHER DISSENTS, REITERATING VIEW THAT INAPPROPRIATE TO ALLOW MARKET MONITOR TO SET REFERENCE PRICES).

• APRIL 15, 2005, MISO, 111 FERC ¶ 61,042 (2005) (CONFIRMS THAT GFA PARTIES THAT DID NOT SETTLE PRIOR TO JULY 28, 2004 MAY NOT CHOOSE SETTLEMENT OPTION B; AFFIRMS DISTINCTION BETWEEN OPTION B GFAS AND CARVED-OUT GFAS WITH RESPECT TO PAYMENT OF SCHEDULE 16 COSTS; AFFIRMS THAT ALL GFA TRANSAC-TIONS SUBJECT TO SCHDULE 17 CHARGES; LOAD SERVED UNDER CARVED-OUT GFAS DOES NOT PAY ANY UPLIFT CHARGES).

INITIATIVE:

EXPEDITED TARIFF REVISIONS FOR RTO MARKETS

SEE DOCKET NO. PL05-2-000

MAJOR PROPOSALS:

• TO QUALIFY FOR EXPEDITED TARIFF REVI-SION PROCEDURES, THE TARIFF OR RULE FLAW SHOULD MEET THE FOLLOWING CRI-TERIA: (A) MATERIALLY ADVERSELY IMPACT THE MARKET (DUE TO THE UNANTICIPATED WORKINGS OF THE TARIFF OR UNAN-TICIPATED ACTIONS BY MARKET PARTICI-PANTS); (B) REQUIRE PROMPT ACTION TO PROSPECTIVELY REVISE THE TARIFF TO REMOVE THE ABILITY TO CAUSE SUCH MATERIAL ADVERSE IMPACTS; AND (C) BE SUSCEPTIBLE TO A CLEAR-CUT REVISION OR INTERIM TARIFF PROVISION OR MARKET RULE.

MAJOR IMPLICATIONS:

• FERC ESTABLISHED PROCESS TO PROMPTLY REVISE RTO/ISO TARIFF PROVISIONS AND MARKET RULES PROVEN TO BE FLAWED DUE TO UNFORESEEN ASPECTS OF IMPLE-MENTATION OR AS A RESULT OF MARKET PARTICIPANT BEHAVIOR.

• RTO/ISO MUST MAKE SECTION 205 PRO-POSAL FOR REMEDY TO FLAW AND REQUEST EXPEDITED PROCEDURES.

• RTO MARKET MONITOR CAN ALSO MAKE ITS VIEWS KNOWN TO FERC AND STAKEHOLD-ERS.

FERC MILESTONES:

• APRIL 7, 2005, FERC ISSUED EXPEDITED TARIFF REVISIONS FOR REGIONAL TRANS-MISSION OPERATORS AND INDEPENDENT SYSTEM OPERATORS, 111 FERC ¶ 61,009 (2005).

• APRIL 7, 2005, FERC ACCEPTED A TARIFF FIL-ING BY THE CAISO TO PROVIDE AN INTERIM SOLUTION TO THE PROBLEM OF EXCESSIVE COSTS INCURRED AS A RESULT OF THE MAN-NER IN WHICH IMPORT AND EXPORT BIDS FROM SYSTEM RESOURCES ARE CLEARED AND SETTLED. SEE CALIFORNIA INDEPEN-DENT SYSTEM OPERATOR CORPORATION, 111 FERC ¶ 61,008 (2005)

INITIATIVE:

REFERENCE PRICES IN RTO MARKETS


MAJOR PROPOSALS:

• FERC ISSUED A NOTICE INVITING COMMENTS ON THE ESTABLISHMENT AND USE OF REF-ERENCE PRICES IN ORDER TO LIMIT NON-COMPETITIVE RESULTS IN THE WHOLESALE ELECTRIC MARKETS. COMMENTS ARE DUE ON MAY 2, 2005.

MAJOR IMPLICATIONS:

• FERC HAS APPROVED REFERENCE PRICE METHODOLOGY FOR USE IN NE-RTO, NYISO, CAISO, AND MISO.

• MARKETS USE DIFFERENT METHODS OF REFERENCE PRICING CALCULATION.

• FERC APPEARS INTERESTED IN ISSUES OF DISCRETION IN SETTING REFERENCE PRICES, AND WHETHER THIS FUNCTION IS A PERMIS-SIBLE IMPLEMENTATION OF THE OATT.

FERC MILESTONES:

• APRIL 1, 2005, FERC ESTABLISHED REFER-ENCE PRICES FOR MITIGATION MARKETS OPERATED BY REGIONAL TRANSMISSION OR-


POLICY OVERVIEW

GANIZATIONS AND INDEPENDENT SYSTEM OPERATORS, DOCKET NO. PL05-6-000.

INITIATIVE:

AFFILIATE ABUSE

FERC HAS IMPOSED HIGHER SCRUTINY TO AFFILIATED ACQUISITIONS AND SUBJECTED COST-BASED AFFILIATE PPAS TO ITS RFP RE-QUIREMENTS.

SEE CINERGY, DOCKET NO. EC02-113; AMEREN, DOCKET NO. EC03-53-000; ENTERGY, DOCKET NO. ER03-583-000; SOUTHERN CALIFORNIA ED-ISON/MOUNTAINVIEW, DOCKET NO. ER04-316-000; ALLEGHENY DOCKET NO. ER04-730-000.

FERC HAS ESTABLISHED GENERIC RULEMAKING TO CONSIDER REGULATION OF RFP PROCE-DURES.

SEE SOLICITATION PROCESSES FOR ELECTRIC UTILITIES, DOCKET PL04-6-000.

MAJOR PROPOSALS:

• FERC, IN DOCKET NO. EC02-113, ANNOUNC-ES THAT UTILITY ACQUISITIONS OF AFFILI-ATED MERCHANT GENERATION MAY POSE POTENTIAL “SAFETY NET” PROBLEM AND FERC WILL PROSPECTIVELY APPLY HIGHER SCRUTINY TO INTERNAL TRANSFERS.

• FERC IDENTIFIES, IN DOCKET NO. EC03-53, THAT AMEREN’S ACQUISITION OF AF-FILIATED MERCHANT GENERATION POSES POTENTIAL “SAFETY NET” PROBLEM.

• FERC REQUIRED FULL COMPETITIVE SCREEN ANALYSIS AND REJECTS “INTRA-CORPORATE” NATURE OF TRANSACTION. FERC APPEARS CONCERNED THAT AFFILIATE ABUSE MAY CREATE BARRIERS TO ENTRY THAT WILL IMPEDE A VIBRANT COMPETITIVE WHOLESALE MARKET. FERC ALSO APPEARS CONCERNED ABOUT GENERATION ASSETS EXITING THE COMPETITIVE MARKET.

• ADMINISTRATIVE LAW JUDGE (ALJ), IN DOCKET NO. EC03-53, FINDS AMEREN TRANSACTION DOES NOT PRESENT AF-FILIATE ABUSE, REJECTS EXISTENCE OF “SAFETY NET,” WHICH IS CHARACTERIZED AS A STORY OF “REGULATORY FAILURE.”

• FERC, IN DOCKET NO. EC03-53 AFFIRMS THAT AMEREN TRANSACTION HAS NO ADVERSE IMPACT ON COMPETITION, BUT ANNOUNCES THAT FUTURE JURISDICTION-AL DISPOSITIONS BETWEEN AFFILIATES WILL BE SUBJECT TO SOLICITATION GUIDELINES, AND PRESERVES CONCEPT OF “SAFETY NET” PROBLEM.

• FERC, IN DOCKET NO. ER03-583, SUSPENDS ENTERGY’S AFFILIATED PPAS AND SETS A HEARING ON THE FAIRNESS OF THE RFP PRO-CESS.

• FERC, IN DOCKET NO. ER04-316, FOUND THAT MARKET PRICES ARE LOWER THAN COST-BASED PRICES IN SOME REGIONS NECESSITAT-ING PROTECTION FOR WHOLESALE POWER CUSTOMERS AGINST SELF-DEALING IN SUCH A MARKET. FERC ANNOUNCES THAT EDGAR GUIDELINES WILL APPLY TO COST-BASED PPAS AS WELL AS MARKET-BASED PPAS.

• FERC, IN DOCKET NO. ER04-730-000, GRANTED MARKET-BASED RATE SALES TO AN AFFILIATE. THE SALES WERE TO BE MADE PURSUANT TO A MASTER FULL REQUIREMENTS SERVICE AGREEMENT AND THREE TRANSACTION CON-FIRMATIONS RESULTING FROM A MARYLAND PUBLIC SERVICE COMMISSION SUPERVISED REQUEST FOR PROPOSAL PROCESS. THIS COMPETITIVE SOLICITATION SATISFIED FERC’S CONCERNS REGARDING AFFILIATE ABUSE.

MAJOR IMPLICATIONS:

• HOW CAN FERC AND STATE REGULATORS COORDINATE IN THE DESIGN AND OVERSIGHT OF SOLICITATION PROCESSES?

• COMMISSIONER KELLIHER, IN DOCKET NO. EC03-53, POINTED OUT THAT A COMPETITIVE SOLITATION POLICY WHILE APPROPRIATE UNDER SECTION 205 OF THE FEDERAL POWER ACT IS INAPPROPRIATE UNDER SECTION 203 OF THE FEDERAL POWER ACT.

• INCREASED REGULATION OF UTILITY ACQUISI-TIONS AND POWER PURCHASES WILL REDUCE CORPORATE FLEXIBILITY AND MAY INCREASE COST OF SERVING NATIVE LOAD.

• IN DOCKET NO. PL04-6, FERC WILL ADDRESS WHETHER THE FERC’S EDGAR POLICY TO ENSURE LEAST-COST OPTIONS ARE CHOSEN IN AFFILIATED MARKET–BASED RATE TRANSAC-TIONS IS ADEQUATE TO ENSURE THAT THE MOST COMPETITIVE POWER PROCUREMENT CHOICE IS BEING MADE BY UTILITIES IN SUCH TRANSACTIONS.

• IN DOCKET NO. PL04-6, FERC WILL CONSIDER ISSUES AS: (I) AN OUTREACH REQUIREMENT FOR CONSENSUS ON ISSUES REGARDING THE SOLICITATION DESIGN AND THE EVALUA-TION CRITERIA TO BE USED; (II) METHODS TO ENSURE THERE IS NO PREFERENTIAL DEALING AMONG AFFILIATES IN SOLICITING AND AWARD-ING PPAS; (III) TO WHAT EXTENT ARE TRANS-MISSION SERVICE AND MONOPOLY POWER FAC-TORS IN THE COMPETITIVE SOLICITATION AND; (IV) CRITERIA TO BE ESTABLISHED UNDER THE EDGAR POLICY TO ENSURE NON-DISCRIMINA-TION.

• IN DOCKET NO. PL04-6, FERC IS CONSIDER-ING, WHETHER A MARKET MONITOR OR INDEPENDENT ENTITY SHOULD OVERSEE THE ADMINISTRATION OF SOLICITATIONS INVOLVING AFFILIATES.

FERC MILESTONES:

• MAY 5, 2003, IN DOCKET NO. EC03-53, FERC ISSUED ORDER SETTING AMEREN APPLICA-TION FOR HEARING. 103 FERC ¶ 61,128 (2003).

• FEBRUARY 5, 2004, ALJ ISSUED INITIAL DECISION ON AMEREN APPLICATION.

• MAY 28, 2004, DOCKET NO. PL04-6, FERC ISSUED SOLICITATION PROCESS FOR PUBLIC UTILITIES TECHNICAL CONFERENCE.

• JUNE 10, 2004, DOCKET NO. PL04-6, TECH-NICAL CONFERENCE HELD.

• JULY 29, 2004, IN DOCKET NO. EC03-53, FERC ISSUED AMEREN, 108 FERC 61,081 (2004) (APPROVES TRANSACTION AND SETS NEW GUIDELINES).

• DECEMBER 13, 2004, FERC ISSUED CON-NECTIVE ENERGY SUPPLY, 109 FERC ¶ 61,385 (2004) RFP DOES NOT MEET OVER-SIGHT PRINCIPLE ANNOUNCED IN ALLEGH-ENY; HOWEVER COMMISSIONER KELLIHER DISSENTS ON THIS ISSUE.

• MARCH 23, 2005, FERC ISSUES ORDER ON REHEARING AND COMPLIANCE FOR SOUTH-ERN CALIFORNIA EDISON (MOUNTAINVIEW), DOCKET NO. ER04-316-000, 110 FERC ¶ 61,319 (2005) (DENIES REHEARING BUT ACCEPTS COMPLIANCE FILINGS).

INITIATIVE:

SMALL GENERATION INTERCONNECTION

FERC PROPOSED STANDARDIZED INTERCON-NECTION AGREEMENT AND PROCEDURES FOR SMALL GENERATORS (UP TO 20 MW).

SEE STANDARDIZATION OF SMALL GENERATOR INTERCONNECTION AGREEMENTS AND PROCE-DURES, DOCKET NO. RM02-12-000.

MAJOR PROPOSALS:

• THE PROPOSED RULE DRAWS SIGNIFI-CANTLY FROM THE IDEAS SUGGESTED BY NARUC.


POLICY OVERVIEW

• ADDRESSES COST RESPONSIBILITY FOR INTERCONNECTION FACILITIES AND UP-GRADES.

• LAYS OUT MILESTONES AND SETS FORTH A PROCESS FOR DISPUTE RESOLUTION.

• SETS UP ACCELERATED PROCEDURES TO CONNECT GENERATORS 10-20 MW;

• EXPEDITED PROCEDURES CONNECTING 2-10 MW AT LOW VOLTAGE AND SUPER EX-PEDITED PROCEDURES FOR GENERATORS <2 MW CONNECTING AT LOW VOLTAGE.

• PRICING POLICIES ARE THE SAME AS LARGE GENERATOR FINAL RULE.

• THE PROPOSED RULE MAY BE USED AS A MODEL BY STATE PUCS FOR INTERCONNEC-TION SUBJECT TO STATE JURISDICTION.

MAJOR IMPLICATIONS:

• NOPR RAISES VARIOUS REGULATORY CHAL-LENGES; E.G., STATE-FEDERAL JURISDIC-TION, RTO ROLES, TARIFFS AND COST RECOVERY “TRAPPED COSTS.”

• NOPR SUGGESTS THAT PROVIDER COALI-TION SUCCESSFULLY PERSUADED FERC ON SUBSIDY ISSUES, E.G., STUDY COSTS, INSURANCE.

• NOPR PROVIDES GREATER FLEXIBILITY FOR RTO AND ISO ENTITIES ON PROCEDURES AND COST RECOVERY, INDIRECT “INCEN-TIVE” FOR RTO FORMATION.

• DISTRIBUTED GENERATION INTERCONNEC-TION PROCESSES INVOKE NEED TO CARE-FULLY COORDINATE WITH TRANSMISSION NETWORK PLANNING AND OPERATIONS.

FERC MILESTONES:

• IN APRIL 2002 FERC ISSUED NOPR (CON-SISTING OF BOTH LARGE GENERATOR AND SMALL GENERATOR MATTERS), BUT SMALL GENERATOR PROPONENTS REQUESTED SEPARATE TREATMENT.

• AUGUST 16, 2002, FERC ISSUED SMALL GENERATOR ANOPR FOR GENERATORS UP TO 20 MW, INITIATING A STAKEHOLDER NE-GOTIATION PROCESS. COMMENTS ON THIS NOPR WERE DUE: OCT 3, 2003. 100 FERC ¶ 61,192 (2002).

• JULY 24, 2003, FERC ISSUED THE SMALL GENERATION NOPR WITH COMMENTS DUE ON OCTOBER 3, 2003. 104 FERC ¶ 61,104 (2003).

• CHAIRMAN WOOD MADE PUBLIC STATEMENTS THAT A FINAL RULE WOULD LIKELY BE ISSUED IN SUMMER 2004.

• ON AUGUST 12, 2004, FERC ISSUED A NOTICE OF REQUEST FOR SUPPLEMENTAL COMMENTS BY OCTOBER 1, 2004, ON THE PROGRESS THAT HAS BEEN MADE BY GROUPS OF STAKE-HOLDERS IN RESOLVING ISSUES.

• ON AUGUST 27, 2004, FERC ISSUED A NO-TICE OF A TECHNICAL CONFERENCE TO BE HELD ON SEPTEMBER 24, 2004 TO DISCUSS THE TECHNICAL REQUIREMENTS FOR THE INTERCONNECTION OF LARGE AND SMALL WIND GENERATORS AND OTHER ALTERNATIVE TECHNOLOGIES.

• SEPTEMBER 24, 2004, IN DOCKET NOS. RM02-12-000, ET AL., FERC HELD A TECHNICAL CONFERENCE RELATED TO THE ADOPTION OF CERTAIN REQUIREMENTS FOR THE INTERCON-NECTION OF LARGE WIND GENERATORS.

• OCTOBER 7, 2004, IN DOCKET NOS. RM02-12-000, ET AL., FERC ISSUED A NOTICE FOR POST-TECHNICAL CONFERENCE COMMENTS REGARDING THE ISSUES RAISED AT THE SEP-TEMBER 24, 2004 TECHNICAL CONFERENCE REGARDING WIND POWER.

• NOVEMBER 30, 2004, IN DOCKET NOS. RM02-12-000, ET AL., FERC EXTENDED THE COMMENT DEADLINE TO FEBRUARY 18, 2005, BUT REQUIRED CERTAIN PARTIES INCLUDING EEI, AND ITS RESPECTIVE MEMBERS, TO FILE A DETAILED STATUS REPORT ON OR BEFORE JANUARY 18, 2005.

• DECEMBER 1, 2004, IN DOCKET NO. AD04-13-000, FERC HELD A TECHNICAL CONFERENCE ON ASSESSING THE STATE OF WIND ENERGY IN WHOLESALE ELECTRICITY MARKETS.

• FERC HAS NOT INDICATED WHEN IT MAY ISSUE ANY FINAL RULE.

INITIATIVE:

INQUIRY REGARDING INCOME TAX ALLOWANCES


MAJOR PROPOSALS:

• FERC RAISES ISSUE OF WHETHER, IF EVER, IT IS APPROPRIATE TO PROVIDE AN INCOME ALLOWANCE FOR PARTNERSHIPS OR SIMILAR PASS-THROUGH ENTITIES THAT HOLDS INTER-EST IN A REGULATED PUBLIC UTILITY.

MAJOR IMPLICATIONS:

• FERC CONCLUDES THAT ALLOWANCE SHOULD BE PERMITTED ON ALL PART-NERSHIP INTERESTS, OR SIMILAR LEGAL INTERESTS, IF THE OWNER OF THAT INTEREST HAS AN ACTUAL OR POTENTIAL INCOME TAX LIABILITY ON THE PUBLIC UTILITY INCOME EARNED THROUGH THE INTEREST.

• THIS ORDER ALLOWS RATE RECOVERY OF THE INCOME TAX LIABILITY ATTRIBUTAT-ABLE TO REGULATED UTILITY INCOME WHICH WILL FACILITATE INVESTMENT IN PUBLIC UTILITY ASSESTS AS WELL AS JUST AND REASONABLE RATES.

FERC MILESTONES:

• DECEMBER 2, 2004, FERC ISSUES NOTICE OF INQUIRY REGARDING INCOME TAX AL-LOWANCES.

• EEI FILES COMMENTS.

• MAY 4, 2005, FERC ISSUES POLICY STATE-MENT ON INCOME TAX ALLOWANCES, 111 FERC ¶ 61,139 (2005).

INITIATIVE:

INQUIRY REGARDING INCOME TAX ALLOWANCES


MAJOR PROPOSALS:

• FERC RAISES ISSUE OF WHETHER, IF EVER, IT IS APPROPRIATE TO PROVIDE AN INCOME ALLOWANCE FOR PARTNERSHIPS OR SIMILAR PASS-THROUGH ENTITIES THAT HOLDS INTEREST IN A REGULATED PUBLIC UTILITY.

MAJOR IMPLICATIONS:

• FERC CONCLUDES THAT ALLOWANCE SHOULD BE PERMITTED ON ALL PART-NERSHIP INTERESTS, OR SIMILAR LEGAL INTERESTS, IF THE OWNER OF THAT INTEREST HAS AN ACTUAL OR POTENTIAL INCOME TAX LIABILITY ON THE PUBLIC UTILITY INCOME EARNED THROUGH THE INTEREST.

• THIS ORDER ALLOWS RATE RECOVERY OF THE INCOME TAX LIABILITY ATTRIBUTABLE TO REGULATED UTILITY INCOME WHICH WILL FACILITATE INVESTMENT IN PUBLIC UTILITY ASSESTS AS WELL AS JUST AND REASONABLE RATES.


POLICY OVERVIEW

FERC MILESTONES:

• DECEMBER 2, 2004, FERC ISSUES NOTICE OF INQUIRY REGARDING INCOME TAX AL-LOWANCES.

• EEI FILES COMMENTS

• MAY 4, 2005, FERC ISSUES POLICY STATE-MENT ON INCOME TAX ALLOWANCES, 111 FERC ¶ 61,139 (2005).

INITIATIVE:

PROMOTING REGIONAL TRANSMISSION PLANNING AND EXPANSION TO FACILITATE FUEL DIVERSITY INCLUDING EXPANDED USES OF COAL-FIRED RESOURCES

SEE DOCKET NO. AD05-3-000

MAJOR PROPOSALS:

• FERC PROPOSES A TECHNICAL CONFER-ENCE TO IDENTIFY REGIONAL SOLUTIONS TO PROMOTING REGIONAL TRANSMISSION PLANNING, EXPANSION AND ENHANCE-MENT TO FACILITATE FUEL DIVERSITY INCLUDING INTEGRATION OF COAL-FIRED RESOURCES TO THE TRANSMISSION GRID.

MAJOR IMPLICATIONS:

• TECHNICAL CONFERENCE ADDRESSES ISSUES SUCH AS (1) CLEAN COAL; (2) CURRENT STATE OF COAL GENERATION; (3) CURRENT INITIATIVES FOR REGIONAL TRANSMISSION PLANNING AND IMPROV-ING THE EXISTING EFFORTS; (4) VIEWS ON REGIONAL PLANNING FROM REGIONAL RELIABILTY COUNCILS AND STATE REPRE-SENTATIVES; AND (5) VIEWS ON REGIONAL PLANNING FROM THE COAL INDUSTRY.

FERC MILESTONES:

• FEBRUARY 16, 2005 FERC ISSUES NOTICE OF TECHNICAL CONFERENCE.

• MAY 13, 2005, FERC HOLDS TECHNICAL CONFERNCE.

INITIATIVE:

UTILITY ACQUISITION OF MERCHANT GENERATION

OKLAHOMA GAS & ELECTRIC, DOCKET NO. EC03-131-000

ACQUISITION AND DISPOSITION OF MERCHANT GENERATION ASSETS BY PUBLIC UTILITIES, DOCKET NO. PL04-9-000.

MAJOR PROPOSALS:

• FERC, IN DOCKET NO. EC03-131, FINDS OG&E’S ACQUISITION OF DISTRESSED GEN-ERATION TO SATISFY ITS NATIVE LOAD AND COMMITMENT TO STATE COMMISSION WOULD UNREASONABLY INCREASE ITS VERTICAL AND HORIZONTAL MARKET POWER.

• FERC, IN DOCKET NO. EC03-131, REJECTED REDUCING MARKET CONCENTRATION BY EXPANDING GEOGRAPHIC SCOPE OF THE MARKET BY INCREASING IMPORT CAPACITY.

• FERC, IN DOCKET NO. EC03-131, REJECTED NETTING ACQUIRED CAPACITY AGAINST CAPACITY UNDER EXPIRING PPAS.

• FERC, IN DOCKET NO. EC03-131, DID NOT ACCEPT THAT THE UTILITY’S OATT FULLY MITIGATES AGAINST ITS INCENTIVE TO USE ITS TRANSMISSION TO EXERCISE MARKET POWER.

• FERC ESTABLISHED PROCEEDING TO EXAMINE ISSUES RELATED TO ACQUISITIONS AND DISPOSITIONS BY PUBLIC UTILITIES.

MAJOR IMPLICATIONS:

• THE OG&E CASE RAISED THE ISSUE OF WHETHER OPERATION UNDER A FERC-AP-PROVED OATT IS SUFFICIENT TO MITIGATE VERTICAL MARKET POWER OR WHETHER TURNING OVER OPERATION OF TRANSMIS-SION TO AN INDEPENDENT SYSTEM OPERA-TOR MAY BE REQUIRED TO DEMONSTRATE NO INCREASE IN VERTICAL MARKET POWER.

• FERC FAILED, IN THE OG&E CASE, TO AC-COUNT FOR THE UTILITY’S OBLIGATIONS TO SELL POWER TO ITS NATIVE RETAIL LOAD.

• OG&E MAKES SETTLEMENT OFFER TO EXPAND ITS TRANSMISSION CAPABILITY THROUGH INCREASED INVESTMENT AS WELL AS TO MAKE INCREASED TRANSMISSION AVAILABLE TO INTERVENERS THROUGH RESCHEDULING AND ESTABLISHING AN INDEPENDENT MAR-KET MONITOR PENDING OG&E’S INTEGRATION INTO SPP.

• ON JULY 12, 2004, IN DOCKET NO. EL04-118-000, ENTERGY AND A MERCHANT GENERATOR SUBMITTED A REQUEST FOR DISCLAIMER OF JURISDICTION OVER THE SALE OF NON-AFFILIATED GENERATION FACILITY TO ENTERGY WITHOUT ANY FERC-JURISDICTIONAL TRANSMISSION FACILITIES.

FERC MILESTONES:

• FEBRUARY 16, 2005 FERC ISSUES NOTICE OF TECHNICAL CONFERENCE.

• MAY 13, 2005, FERC HOLDS TECHNICAL CONFERNCE.

• APPEALS TO FERC.

• JUNE 10, 2004, IN DOCKET NO. PL09, FERC HELD A TECHNICAL CONFERENCE ON AC-QUISITIONS AND DISPOSITIONS BY PUBLIC UTILITIES.

• JULY 2, 2004, FERC ISSUED ORDER APPROV-ING OG&E ’S REVISED SETTLEMENT OFFER. 108 FERC ¶ 61,004 (2004).

• SEPTEMBER 1, 2004, IN DOCKET NO. EC03-131 FERC TOLLED REHEARING ON JULY 2, 2004, ORDER.

INITIATIVE:

MARKET POWER: MARKET BEHAVIORAL RULES FOR MARKET-BASED RATE SELLERS

FERC IMPOSES BEHAVIORAL RULES ON ALL MBR SELLERS.

SEE INVESTIGATION OF TERMS AND CONDI-TIONS OF PUBLIC UTILITY MARKET-BASED RATE AUTHORIZATIONS, DOCKET NO. EL01-118-00.

MAJOR PROPOSALS:

• FERC ESTABLISHED AN INVESTIGATION OF TERMS AND CONDITIONS OF PUBLIC UTILITY MBR AUTHORIZATIONS AND PROPOSED REVISIONS TO MBR TARIFFS AND AUTHORI-ZATIONS.

• FERC PROPOSED THAT MBR SELLERS OF WHOLESALE ELECTRIC POWER MUST IN-CORPORATE A LIST OF BEHAVIORAL RULES IN THEIR TARIFFS THAT ADDRESS: (I) UNIT OPERATIONS; (II) MARKET MANIPULATION; (III) COMMUNICATIONS; (IV) REPORTING; (V) RECORD RETENTION; AND (VI) RELATED TARIFF MATTERS.


POLICY OVERVIEW

(Continued from page 97)

MAJOR IMPLICATIONS:

• THE FINAL RULE INCLUDES AN INTENT ELEMENT – IT MUST BE PROVEN THAT PAR-TICIPANTS INTENDED TO MANIPULATE THE MARKET OR PRICES.

• FERC RETAINED ITS MONETARY REMEDIES TO DISGORGEMENT OF UNJUST PROFITS, BUT CHOSE NOT TO GO BEYOND THAT TO INCLUDE A “MAKE-THE-MARKET-WHOLE” APPROACH.

• THE WINDOW FOR FILING A COMPLAINT WAS EXTENDED FROM 60 TO 90 DAYS AND THE 90-DAY LIMIT WOULD APPLY TO FERC-INITIATED ACTIONS AS WELL.

• THE RULES WERE NOT TO BE INTERPRETED AS IMPOSING A MUST OFFER REQUIREMENT.

• THERE IS A PROVISION FOR A SAFE HARBOR SIMILAR TO THAT CONTAINED IN THE PRICE REPORTING INDICES POLICY STATEMENT.

• PAPER TRADES ARE NO LONGER PROHIB-ITED.

• UNLESS ENFORCEMENT POWER HAS BEEN EXPLICITLY DELEGATED TO AN RTO’S MARKET MONITORING UNIT, FERC RETAINS ENFORCE-MENT AUTHORITY.

• FERC WILL REPORT ANNUALLY ON THE EF-FECTIVENESS OF THESE NEW RULES.

In September 2004, as part of its continuing efforts to promote robust and transparent risk management practices, EEI unveiled a new template to provide a consistent way to modify existing wholesale electric power con-tracts for delivery into Midwest In-dependent System Operator (MISO) control areas.

Provider of Last Resort (POLR)

As states implemented retail com-petition, utilities in those states were required to continue serving custom-ers who did not select an alternative provider—at rates that no longer refl ected today’s costs. As ‘providers of last resort,’ these utilities must procure suffi cient supplies for an ever-changing customer base, meaning they may end up short (or long) and forced to buy (or sell) power in the wholesale market at prices they may not be able to recover.

POLR service—a.k.a., default ser-vice, standard offer service, basic generation service, price to beat—was established as a transitional mechanism on the way to full retail competition. Nevertheless, as the original obligation

expires, states are extending it for many customers—particularly residential customers—who are not served by alternative suppliers.

Based on their experience serving a partially regulated, partially deregulated customer base, utilities are seeking re-forms to POLR service. First, differ-ent policies should apply to different customer classes. Large commercial and industrial customers generally have ready access to market-based sup-pliers, suggesting it is time to consider removing the obligation to serve for large customers. Small customers, particularly low-income customers, are least served by the competitive retail market. These customers need policies that promote rate stability and provide limits on when and how a customer’s electricity can be shut off.

Rates for POLR service generally were set at a discount from historic levels and no longer refl ect how energy is procured in the competitive wholesale market. Nor do they send effi cient price signals to consumers. New rate designs should be implemented to recognize new market structures, costs, and risks.

Retail Competition

In 2002, Oregon became the last state to implement retail access. Since that time, fi ve states have delayed, sus-pended, or repealed retail access. But for the most part, the divide between the 25 states that implemented retail choice in the 1990s and the 25 that did not has hardened into a status quo that is sometimes referred to as a “hybrid” market structure.

There are several implications to this lack of closure on retail restructuring. For investors, the implication is that they have a “choice,” too. They can put their money to work in traditional, vertically integrated utilities operat-ing in exclusive service franchises; or unbundled “wires only” utilities op-erating in open-access environments; or competitive merchant generating companies. Predictably, investors will go where they fi nd the best combination of risk and return.

The hybrid market creates a number of challenges for utilities—particularly holding companies that operate in both “open” and “closed” states. Cost al-location, rate design, and regulatory policies are very different in closed vs. open markets. Ultimately, this means a

FERC MILESTONES:

• MAY 19, 2004, IN DOCKET NO. EL01-118, FERC ISSUED REHEARING OF MARKET BE-HAVIORAL RULE ORDER. 107 FERC ¶ 61,175 (2004).

• ON MAY 28, 2004, CINERGY FILED AN APPEAL IN THE DC CIRCUIT, CASE NO. 04-1168, CHALLENGING FERC’S MARKET BEHAVIORAL RULES AND FERC’S AUTHOR-ITY TO GRANT MARKET-BASED RATES.


POLICY OVERVIEW

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loss of operating effi ciency, because rate making cannot be standardized.

For policymakers—especially federal regulators—the hybrid market creates diffi culties in trying to craft uniform national policies. Wholesale markets and retail markets must work together, so wholesale regulatory policies must be coordinated with retail regulatory policies. This is very diffi cult when

some states retain vertically integrated utilities, and others are living with unbundled utilities. During 2004, the hybrid market produced a rift between FERC policies and jurisdiction over market power, and state policies and jurisdiction over resource planning and procurement. This rift will need to be addressed in the years ahead.

Disaster Recovery

In the wake of one of the most punishing hurricane seasons on record, EEI published a report that found that recovery from storms must be speedy and controlled, and that utilities must work with regulators in the future to en-sure that cost-recovery mechanisms are in place before storms hit. The study, “After the Disaster: Utility Restoration


POLICY OVERVIEW

Cost Recovery,” outlined steps that elec-tric utilities and state regulators should consider in establishing concrete, stable mechanisms to plan for and mitigate the massive cost of rebuilding electric sys-tems following a major weather event.

Released during NARUC’s Winter 2005 meeting, the report also showed that the economic cost of going without electric-ity for extended periods far outweighs the often substantial cost of storm recovery. Because of this, the report noted, electric utilities’ current practice of mobilizing outside restoration crews from near and far to rebuild damaged electric power systems as quickly as pos-sible following a natural disaster is just good business. The study is available on EEI’s Web site, www.eei.org.

Broadband Over Power Lines (BPL)

In October 2004, the Federal Com-munications Commission (FCC) issued changes to a rule governing the use of utilities’ transmission and distribution facilities for broadband over power lines (BPL). The ruling should help guide utilities considering the largely unex-plored BPL market. Included in the rule were new technical requirements for BPL devices (which communicate through electrical wires) that are de-signed to prevent interference with radio-based communications. The rule also detailed the frequencies that BPL operators must avoid in order to protect aeronautical and aircraft communica-tions. The FCC established a public database for identifying and resolving potential BPL interference.

BPL represents a business opportu-nity for electric utilities, which own the

primary asset. Currently, several utilities have begun pilot programs or have actu-ally entered the BPL market, including Cinergy, Consolidated Edison, Pepco, PPL, Progress, and Southern Company. The business models range from leasing line space to a third party to becoming an Internet service provider.

At its Winter 2005 meeting, NA-RUC’s BPL Task Force released its report calling for a light-handed approach to regulation of BPL, consistent with EEI’s position. The task force believes that it will be up to the states primarily to tailor appropriate regulatory responses. The task force also recommended that state commissions take the time to learn about BPL technology and “monitor BPL to see whether and how it actually delivers on its many promises.”

Conclusion

For electric utilities and utility com-missioners, this new era of rate cases will create a new set of risks and a new set of investor opportunities. Regulators will be challenged to rebalance their dual roles of setting rates of return suffi cient to attract capital from Wall Street while protecting the interests of consumers.

Bolstering utility credit quality and restoring investor confi dence in this sector will take time. However, if the key fi nancial and regulatory players can regularly share their views, such dialogue would greatly improve the industry’s fi nancial strength and fl exibility.

Environmental Issues

The electric power industry has reduced its air emissions signifi cantly since 1980, even as demand for elec-tricity has increased by 75% and our nation’s economy has grown by 101%.

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POLICY OVERVIEW

Clean Air Interstate Rule (CAIR)

On March 10, 2005, EPA issued the Clean Air Interstate Rule (CAIR), a rule that will achieve the largest re-duction in air pollution in more than a decade. EPA views utility SO

2 and

NOx emission reductions as the most

cost-effective way to address the re-gional transport contribution to levels of fi ne particle (PM2.5) and eight-hour ozone in areas exceeding the national standards. Accordingly, even though electric power generators already have reduced SO

2 and NO

x by 40% to date,

x by 40% to date,

x

EPA is seeking these additional major emission reductions.

By permanently capping emissions of SO

2 and NO

x from the power gen-

x from the power gen-

x

eration industry in the eastern United States, CAIR achieves large reductions of SO

2 and/or NO

x emissions across 28

eastern states and the District of Colum-bia. When fully implemented, CAIR will reduce SO

2 emissions in these states

by over 70% and NOx emissions by over

x emissions by over

x

60% from 2003 levels.

EPA’s analysis of the rule projects costs of $2.5 billion in 2010, rising to $4 billion in 2015, and $5.2 billion in 2020 (converted to 2004 dollars). EEI modeling projects costs of $27 billion through 2020 (2004 dollars), reaching $7.7 billion in the year 2020 alone, and installation of almost 140 GW of selec-tive catalytic reduction (for NO

x) or fl ue

gas desulfurization (for SO2) controls.

Whether states and other interested parties will challenge the rule has not yet been determined.

Clean Air Mercury Rule (CAMR)

On March 15, 2005, EPA issued the Clean Air Mercury Rule (CAMR)—the fi rst-ever federal rule to permanently cap and reduce mercury emissions from power plants. The rule establishes a

market-based cap-and-trade program under Section 111 of the CAA whereby states can choose either to participate or not participate. The rule requires emission reductions in two phases: a cap of 38 tons in 2010, and 15 tons after 2018, for a total reduction of 70% from current levels. CAMR builds on mercury co-benefi t reductions that will result from implementation of SO

2

and NOx emission caps under CAIR.

x emission caps under CAIR.

x

The cap-and-trade system estab-lished under the rule creates incentives for continued development and testing of promising mercury-control technolo-gies that are effi cient and effective, and that could later be used in other parts of the world. In addition, by making mer-cury emissions a tradable commodity, the system provides a strong motivation for some utilities to make early emission reductions and for continuous improve-ments in control technologies.

Also on March 15, 2005, in a sepa-rate but related action, EPA revised and reversed its December 2000 fi nding that it was “appropriate and necessary” to regulate coal- and oil-based power plants under Section 112 of the CAA. EPA took this action because it now be-lieves that the December 2000 fi nding lacked foundation and because recent information demonstrates that it is not appropriate or necessary to regulate coal- and oil-based utility units under Section 112.

Numerous states and environmental groups have fi led suit against EPA and challenged the Section 112 rule change and the new cap-and-trade program. A number of other states, business organizations, and industry groups will intervene in these cases in support of the rules.

Electric generators have cut sulfur di-oxide (SO

2) emissions by 40% during

that period, with meaningful reductions over the past ten years due primarily to implementation of the Clean Air Act’s (CAA’s) Acid Rain Program. The overall goal of the Acid Rain Program is to achieve substantial environmental and public health benefi ts through reduc-tions in emissions of SO

2and nitrogen

oxides (NOx), the primary causes of

acid rain.

Electric generators also have reduced NO

x emissions by about 40% since

1980, with signifi cant reductions over the past ten years attributable to the installation of state-of-the-art pollution-control technologies that meet the Acid Rain Program requirements and assist with Environmental Protection Agency (EPA) ozone-reduction regulations. One of these regulations, the “NO

x

SIP Call,” requires roughly 20 states to revise state plans to cut industrial NO

x

emissions during the summer months (May to September). When completed, the electric utility industry will have committed approximately $10 billion to install new pollution controls and will expend hundreds of millions in annual operation costs.

As a result, electric utilities will re-duce NO

x by 80% to 90% throughout

x by 80% to 90% throughout

x

most of the eastern United States dur-ing the 2005 summer ozone season. In addition, controls to reduce SO

2, NO

x,

and particulate matter currently are reducing mercury emissions by about 40%. This has all been done despite a steady climb in electricity demand, and without sacrifi cing the reliability and affordability of the electricity that is produced.

In 2005, EPA issued two major new regulations to further reduce SO

2, NO

x,

and mercury emissions:


POLICY OVERVIEW

The Benefi ts of Sensible Multi-Emission Legislation Over Regulation

At present, the United States is at an important crossroads as it prepares to take the next step in improving air qual-ity even further. One option leads down a regulatory path begun in March 2005 when EPA issued two new regulations designed to signifi cantly reduce emis-sions of SO

2, NO

x, and mercury from

power plants. The other path is legisla-tive, which would lead to faster, deeper, and, in all likelihood, more permanent results in improving air quality.

Why is legislation preferable to regulation? Because regulation under the Clean Air Act is fraught with un-certainty and delay. Power companies already are subject to roughly a dozen major air quality programs, often with overlapping or confl icting requirements. What’s more, federal environmental regulations are nearly always subject to litigation and indeed, the ink on the new EPA CAIR and mercury regula-tions was barely dry before lawsuits started cropping up. This litigation will mean several years of haggling between states, the EPA, and other parties to complete decision-making on imple-mentation—meaning that the precise requirements of CAIR and CAMR may not be known for several years.

A legislative multi-emission ap-proach to regulating power plant emis-sions would create a single set of caps on the amount of SO

2, NO

x, and mer-

cury that the power industry can emit nationwide. The industry would then meet the reduction mandates through a market-based system of buying and sell-ing emission credits. The emission caps would be fi rm, spelling out the amount and timing of emissions reductions, and be ensured by continuous emissions

monitoring and large penalties for non-compliance.

Sensible multi-emission legislation would achieve important air quality ob-jectives; streamline the regulatory pro-cess and reduce litigation; maintain fuel diversity; allow fl exible, market-based approaches to emissions reductions; and substantially reduce compliance costs.

Fuel Diversity and the Importance of Coal

To generate electricity, our nation’s electric companies rely on a diverse mix of fuel sources, including coal, nuclear energy, natural gas, fuel oil, hydropower and, to a lesser extent, other renewable resources—such as biomass, geother-mal, solar, and wind. Coal powers more than 50% of our electric generation and is the predominant fuel of choice in fi ve of the nine major regions of the coun-try. Under any future scenario, coal will be critical for providing baseload generation, but it faces some signifi cant environmental hurdles that must be addressed.

Achieving continuous improvement in the environmental performance of our coal-based generating fleet will require that the nation pursue an agreed-upon, aggressive, and sustained technology-development program. This will require billions of dollars in new investments shared by the public and private sectors.

No one technology will dominate; rather, a suite of technologies will be needed. These will include advanced pulverized coal and integrated gasifi ca-tion combined cycle (IGCC) technolo-gies developed to use the range of coals mined in the United States. Impor-tantly, not only are these advanced-coal technologies being designed and dem-onstrated to achieve ultra-low emissions

from coal-based plants, they are being developed to ensure reliability from coal use and continued low-cost electricity to the consumer.

The electricity generating industry, working in conjunction with the De-partment of Energy (DOE), is develop-ing the next generation of coal-based generating technologies though basic re-search and development, the Clean Coal Power Initiative, and the FutureGen project. It is vital that these programs, jointly funded by industry and DOE, continue to receive long-term funding so that the goal of moving promising technologies along the research and development path to full-scale com-mercial demonstration is achieved in a timely manner.

Dramatic and continuous reduc-tions in emissions from coal-based electricity generation using advanced technologies can be a reality. The alter-natives—regulation through litigation, uneven policymaking, and over-reliance on foreign energy sources—threaten economic and national security, and constrain our potential contributions to global emissions reductions through our technological leadership. Industry and government can and must agree on reasonable milestones that enable significant environmental progress, greater investment certainty, energy security, and the low-cost electricity that drives economic prosperity and a better quality of life.

Voluntary Actions to Reduce Greenhouse Gases

Leaders from the nation’s electric power sector signed an agreement in December 2004 with DOE that es-tablishes an important framework for the voluntary reduction of greenhouse gas (GHG) emission intensity over the


POLICY OVERVIEW

next decade. The heads of seven electric power organizations comprising Power PartnersSM signed an umbrella Memo-randum of Understanding (MOU) with DOE designed to implement President Bush’s goal of reducing GHG emis-sions intensity of the U.S. economy (measured as emissions per GDP) by 18% by 2012.

In addition to EEI, the other six organizations comprising Power Part-nersSM are the American Public Power Association, Electric Power Supply As-sociation, Large Public Power Council, National Rural Electric Cooperative Association, Nuclear Energy Institute, and Tennessee Valley Authority. These entities, representing all of the electric power generation in the United States, have pledged to reduce collectively the power sector’s GHG emissions intensity by an equivalent of 3-5% (measured as carbon emissions per unit of electricity produced) below 2000-2002 baseline levels, as determined over the 2010-2012 period.

The agreement creates a framework for cooperation between DOE and the electricity sector to encourage and develop expanded use of low-emission or emission-free technologies, such as nuclear, hydroelectric, wind, and other renewables, as well as effi cient natural gas and clean-coal technolo-gies. Moreover, the accord establishes a public-private partnership to promote technology research, development, and deployment. The MOU also estab-lishes goals for the overall public-private partnership, sets out general principles, and proposes actions to further the partnership’s objectives, the fi rst of its kind with the entire electricity sector.

Greenhouse Gas Emissions Registry Program

The GHG emissions registry was established as a voluntary program by section 1605(b) of the Energy Policy Act of 1992. The guidelines govern the voluntary reporting by utilities and other entities of GHG emissions and GHG reductions, avoidances, and sequestrations.

In November 2003, DOE released revised guidelines for the voluntary reporting of GHG emissions and re-duction efforts designed to improve the accuracy, verifi ability, and complete-ness of GHG emissions data reported under the registry program. These new guidelines represented another signifi -cant step toward the establishment of a broad national effort to reduce the GHG intensity of the U.S. economy and to address the risk of global climate change.

EEI actively participated in the public workshops held by DOE in April 2005, and by the U.S. Depart-ment of Agriculture in May 2005, and fi led extensive comments on the interim fi nal General Guidelines and proposed Technical Guidelines in June 2005. The guidelines encourage major U.S. companies and institutions to undertake comprehensive reviews of their GHG emissions and to take ac-tions to reduce emissions. The revised guidelines are designed to stimulate the type of broad, economy-wide effort that is needed to make substantial progress toward achieving President Bush’s goals for reducing the GHG intensity of the U.S. economy.

EEI member companies have been encouraged to use the 1605(b) program for reporting and registering GHG emissions intensity reductions and vol-untary activities to reduce GHGs. EEI

also is actively participating in related standards work by the International Organization for Standardization and the American Society of Testing and Materials.

Environmental Disclosure

Environmental liabilities have long been a topic covered in industry fi -nancial disclosures. Guidance on the nature of these disclosures is detailed in Securities and Exchange Commis-sion (SEC) regulations and guidelines issued by professional accounting stan-dard organizations. However, certain investors have an interest in data about social and environmental impacts reaching beyond that which has been traditionally discussed in formal, SEC-required disclosures for publicly held companies.

Efforts underway to compel addi-tional environmental disclosure include shareholder resolutions, the voluntary collection and ranking of environmental performance and disclosure practices by non-governmental organizations, some activity by investment banks and indexes, and calls for federal legislation to increase or require more prescrip-tive SEC disclosure requirements. In response to petitions from investors in 2004, American Electric Power, Cin-ergy, Southern Company, and TXU have issued reports addressing environ-mental policy and impacts from poten-tial regulations. There was a signifi cant increase in the number of similar peti-tions fi led early in 2005, resulting in additional commitments by member companies to produce such reports. In addition, Cinergy and Duke Energy highlighted the climate change issue in their 2004 annual reports.

EEI supports meaningful and trans-parent financial disclosure and will


POLICY OVERVIEW

The Power Trading Sector

Recent Developments and Current Status

Introduction

Trading in the energy sector has grown rapidly since the creation of the New York Mercantile Exchange’s (NYMEX) WTI crude oil, gasoline and heating oil contracts in the early 1980s, and the Henry Hub natural gas futures contracts in the early 1990s. The success of these NYMEX futures markets was reinforced by development of equally robust over-the-counter markets. Today, billions of dollars of ‘paper’ oil and gas contracts are traded daily, providing an array of opportunities to hedge oil and gas price risk exposures.

The success of these markets results from a wide variety of participants with wide ranging interests. Producers sell into forward markets to lock in production revenues. End users buy forward to meet budget targets. Refi ners buy crude oil while selling gasoline and heating oil futures to lock in refi nery margins or ‘crack spreads.’ Wholesalers buy winter supplies during the summer and provide opportunities for customers to lock in prices before the start of the heating season. Speculators and market makers round out the list of market participants. This abundance of market players, with diverse interests, results in a high degree of market liquidity.

The oil markets have depth and li-quidity because the industry’s wholesale and retail segments are comprehen-sively deregulated, both in the United States and in Europe. Each consumer —whether a large industrial user, in-dividual motorist or homeowner—is completely exposed to the vagaries of a

of additional environmental dis-closure. EEI also is identifying op-portunities to increase and improve outreach and communication about environmental issues with fi nancial and other stakeholders.

Water

Section 316(b) of the Clean Water Act requires that cooling water intake structures reflect the best technol-ogy available for minimizing “adverse environmental impacts” to aquatic organisms (e.g., fi sh). In September 2004, a new EPA rule became effective for cooling water intake structures at existing generating facilities. The fi nal rule meets environmental goals while providing owners of these facilities signifi cant compliance fl exibility. Im-portantly, it does not require owners of existing power plants to retrofi t cooling towers, which would have cost the in-dustry an estimated $40 billion.

The fi nal rule represents a workable approach toward the continued protec-tion of the environment; still, it does impose signifi cant new federal require-ments on the electric power industry. According to EPA, the rule will require 551 facilities to install technologies or perform studies demonstrating compli-ance. EPA estimates the rule collectively will cost affected facilities close to $400 million per year, while industry analyses conclude the true costs may be as much as two to 10 times EPA’s estimates.

Endangered Species Act: Greater Sage Grouse

The U.S. Fish and Wildlife Service (FWS) announced January 7, 2005, that the greater sage grouse does not warrant protection under the Endan-gered Species Act (ESA) at this time. However, the FWS stated the need

for continued efforts to conserve sage grouse and sagebrush habitat on a long-term basis. An ad hoc electric utility sage grouse working group has been formed to address the issue. Listing the sage grouse as threatened or endangered under ESA would have made it diffi cult and expensive to site, construct, and maintain transmission, distribution, and wind power facilities in most of the western United States.

Diverse Organizations Join Forces to Protect Birds

EEI, the Avian Power Line Interac-tion Committee, the National Rural Electric Cooperative Association, and the U.S. Fish and Wildlife Service an-nounced in April 2005 a joint initiative to encourage utilities to take additional steps to reduce the number of birds that are injured or killed as a result of coming into contact with power lines. Under the terms of the agreement, electric power companies are urged to develop and implement Avian Protection Plans, utility-specifi c programs designed to protect and conserve migratory birds by reducing the damage caused by avian interactions with electric utility facilities.

Conclusion

The electric power industry has made signifi cant progress in reducing emissions and improving environmental quality, and utilities are committed to building on this success. By working with policymakers and regulators to develop policies that achieve environ-mental goals, promote long-term energy security, make economic sense, and utilize voluntary initiatives, utilities will continue to demonstrate the industry’s commitment to environmental excel-lence.


POLICY OVERVIEW

complex and volatile global commodity market. Natural gas is somewhat less comprehensively “marketized” because the retail sector is still regulated in most areas. Individual homeowners remain under the umbrella of their local distri-bution company (LDC) and have few options to manage price risks. Some LDCs are active risk managers; others are not, choosing (or being required by regulators) to pass through market price fl uctuations to retail customers.

Amid the deregulation of U.S. electricity markets in the mid-1990s, many energy companies turned at-tention to the enormous potential for trading electricity products. By 2000, a half dozen major trading houses and a large number of mid-tier fi rms actively traded electricity. As with natural gas, the wholesale sector was the most ex-posed to electric price volatility. The retail sector remained largely regulated. Unlike oil and natural gas, however, power sector deregulation was initially limited to a few regions of the United States—the northeast, a few areas in the midwest, and California.

In 2001, the emerging power markets were severely tested by three develop-ments. The first, and perhaps most diffi cult, was the failure of California’s experiment with electric deregulation, which resulted in a near market collapse. Second was the implosion of Enron and subsequent decline in the fortunes of the other companies who sought to become powerhouses in nationwide electricity trading. Third was the decline of mer-chant generators, including the decrease in their credit capabilities and eventual pullback from trading.

The Glittering Ball Falls

The California crisis produced a number of ripple effects throughout power trading markets by highlight-ing unresolved problems that were damaging market integrity and market liquidity. Among these were:

■ Lack of clear rules for trading. The lines between ethical, unethical and illegal trading were too hazy, and allowed for gaming by aggressive traders.

■ Inaccurate reporting of trades to industry publications. When traders report falsely, or conspire to raise prices, a large portion of the market receives inaccurate price signals.

■ Inadequate market design. Many end user (utility) market participants were not allowed to hedge, leaving them exposed to price spikes. The resulting high purchase prices could not be passed through to customers, causing severe fi nancial strain for many companies.

The demise of Enron meant the withdrawal of a major provider of market liquidity and the disappearance of the main trading partner for many smaller fi rms. Enron’s widespread con-tract defaults shook the industry’s con-fi dence in the reliability of electricity contracts, and more importantly, shook confi dence in the integrity of the credit ratings of companies actively involved in trading power contracts. This drop in confi dence greatly damaged liquidity in the power markets.

The third test was the decline in the fortunes of merchant generators. From

the mid 1990s until 2002, optimism about the future of electric markets stimulated an enormous build-out of merchant, project-fi nanced power plants—primarily combined-cycle, nat-ural gas-fi red turbines. Approximately 200,000 MW of capacity was added to the grid. For a variety of reasons, this new capacity did not lead to a cor-responding decrease in older capacity, and the value of generation collapsed in both new capacity markets and in traditional markets, where capacity payments were usually part of bilateral contracts with utilities. Many merchant generators—already buffeted by the En-ron and California affairs—succumbed to bankruptcy.

This “perfect storm” created an enor-mous withdrawal of capital from the power trading sector. Not surprisingly, it also kept alive a long-running debate over the optimal form of restructuring. Ongoing experiments in market design range from perpetuation of traditional, vertically integrated utilities in some areas of the country to continued de-velopment of competitive markets in others.

Current State of the Market

Power markets are only now slowly recovering, and liquidity1 in the vari-ous types of contracts that constitute a healthy market is gradually increasing.As of early 2005, the greatest liquidity exists in short-term markets (day ahead, balance of the week, next week, balance of the month, and next month), but diminishes sharply in the longer-dated markets (month after next, next quarter,

____________________________________________________1Market liquidity refers to the ability to trade on short notice at low cost. Liquidity has both a price and a quantity dimension. The price dimension, known as the spread, refers to the cost of entering and liquidating a position (a “round-trip”), and is measured by the difference in the price at which traders are willing to sell (the ask), and the price at which they are willing to buy (the bid) in small volumes. The cost of buying or selling contracts is usually measured as half the spread, plus commission. The quantity dimension of liquidity, known as market depth, refers to the ease with which large buy or sell orders can be moved, and is measured by the relationship between the size of the buy [(respectively, or sell] ) order and its effect on the ask [(respectivelyor, bid] ) price. A market can be liquid along the dimension of low execution costs (i.e., low bid-ask spread) for small orders, yet be too shallow to handle large orders (i.e., large players cannot use the market without turning prices sharply against them).


POLICY OVERVIEW

next year, subsequent years). Liquid-ity is much better in market areas that have been established for years, specifi -cally, PJM Interconnection, ISO New England and New York ISO (in that order).

The charts on page 117 show how trading volume peaked in mid-2001 and declined sharply thereafter. It ap-pears that the activity bottomed in 2003 and began to increase again in mid-2004. These same trends are seen in day ahead markets and in longer-dated trading instruments.

Daily Volumes

Charts 1 and 2 show daily trading volume from January 2001 to January 2005. Chart 1 shows total reported trading volume for all markets in North America. Chart 2 shows volume in the actively traded Cinergy market.

While Cinergy market trading activity decreased significantly after mid-2001, it has remained moder-ately healthy and steady since then. The events of 2001 took a much greater toll on total North American trading, as trading in the less active regions essen-tially dried up. While the active Cinergy Hub has remained steady, trading in the other regions has begun to pick up such that overall volumes in early 2005 are twice 2003 levels.

Calendar Year Volumes

Chart 3 shows that trading in cal-endar year strips (a one-year contract for a specifi ed volume) peaked in early 2002, with over 3,000,000 MW per day traded on the Intercontinental Exchange. By mid-2003, trading in the one-year contracts had all but dried up completely. Since early 2004, trading volume has begun to increase and is now returning to pre-2002 levels.

Trading in contracts longer than one year has always been limited, but traders can now fi nd counter parties for almost any time frame for a price. In place of the large energy trading companies which have exited the market, hedge funds are now setting up shop and are proving to be active market participants, greatly enhancing market liquidity. While many of the remaining merchant energy companies would like to increase trading, most are cutting back due to the post-Enron stigma of this business and its negative impact on credit ratings. Hedge funds, on the other hand, trade to exploit market inefficiencies and are fi nding a ready niche in the power markets. As more funds get up and run-ning, we expect liquidity to continue to improve, particularly in deregulated market areas.

The Ability to Hedge

While it remains diffi cult to trade away longer-dated positions once these have been entered into, it is possible to fi nd counterparties willing to take them on. End users are becoming more interested in locking in costs as spot market prices become increasingly volatile. End users purchasing energy will generally fi nd counterparties will-ing to sell electricity for fixed-price contracts of up to fi ve years, or even longer. However, the lack of liquidity in the forward markets means that end users will pay a premium for a longer-term contract. The premium is directly related to the liquidity in the forward market as expressed in the bid-ask spread for a particular instrument. Less liquidity means a higher premium to hedge price risk.

Despite relatively low liquidity for most longer-dated contracts, electric-ity markets are functioning effectively enough to present buyers with competi-

tive offers from a number of suppliers —for either physical purchases or for fi nancial contracts that meet risk man-agement goals. As the electricity markets develop and mature, confidence of market participants will grow. This will draw additional new participants, such as hedge funds, and lead to higher levels of liquidity and lower costs for end users interested in mitigating risk.

Author Credits:

Energy Security Analysis, Inc.

Paul Flemming,Manager, Power and Gas Services

Edward Krapels, Director, Power and Gas Services

EEI’s Alliance of Energy Suppliers

Roger A. Kranenburg, CFADirector, Business Development


POLICY OVERVIEW

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Accounting Issues

Financial Accounting Standards Board (FASB)

The FASB issued a number of ac-counting rules that affect the industry’s accounting.

Share-Based Payment

FASB issued its Statement 123(R), Share-Based Payment. The Statement establishes standards for the account-ing of transactions in which an entity acquires goods or services by issuing its shares, share options, or other equity instruments (except for equity instru-ments held by an employee stock own-ership plan). A company shall recognize all equity-based awards to employees in the income statement based on their fair value. The fair value of the stock-based compensation will be recognized in a company’s financial statements over the period during which an employee is required to provide service in exchange for the award—the requisite service period.

Interpretation No. 47

FASB issued Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations to clarify that conditional asset retirement obliga-tion as used in FASB Statement No. 143, Accounting for Asset Retirement Obligations, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation is unconditional even though uncertainty exists about the timing and/or method of the settlement. The timing and/or method of the settlement may be con-ditional on a future event occurring. An entity is to recognize a liability for the


POLICY OVERVIEW

fair value of a conditional asset retire-ment obligation if the fair value of the liability can be reasonably estimated.

Under the Interpretation, an asset retirement obligation (ARO) would be reasonably estimable if a) it is evident that the fair value of the obligation is embodied in the acquisition price of an asset, b) there is an active market for the transfer of the obligation, or c) suffi cient information exists to apply an expected present value technique.

An entity would have sufficient information to apply an expected pres-ent value technique, and thus an ARO would be reasonably estimable, if either of the following conditions exists:

■ The settlement date and method of settlement for the obligation have been specifi ed by others.

■ The information is available to rea-sonably estimate 1) the settlement date or the range of the potential settlement dates, 2) the method of settlement or potential methods of settlement, and 3) the probabilities associated with the potential settle-ment dates and the potential meth-ods of settlement.

If there is not suffi cient information at the time the liability is incurred, a liability is to be recognized initially in the period in which suffi cient informa-tion becomes available to estimate its fair value.


FINANCE AND ACCOUNTING DIVISION

Finance and Accounting Division

The Business Services and Finance Division is part of EEI’s Business Ser-vices Group. This division provides the leadership and management for advocating industry policies and tech-nical research and enhancing the capa-bilities of individual members through education and information sharing. The division’s leadership is used in areas that affect the fi nancial health of the shareholder-owned electric utility industry, such as fi nance, accounting, taxation, internal auditing, investor relations, risk management, budgeting, and fi nancial forecasting. If you need research information about these issue areas, please contact an EEI Business Services and Finance Division staff member (listed in this section). Under the direction of both the Finance and the Accounting Executive Advisory Committees, the division provides staff representatives to work with issue area committees. These committees give member company personnel a forum for information exchange and training and an opportunity to comment on legislative and regulatory proposals.

Financial Info

A series of fi nancial reports on the shareholder-owned segment of the electric utility industry. Periodic reports include fi nancial statements, construc-tion, and stock performance. Special reports are also issued periodically on various topics, including cash fl ows, industry diversifi cation, dividend strate-gies, divestiture activity, and mergers and acquisitions.

Financial Review

An annual report that provides a review of the performance of the share-holder-owned electric utility industry. The report also provides an assess-ment of the economy, capital markets, construction programs, governmental policies and actions, regulatory trends, and related factors.

EEI Index

Quarterly stock performance of the U.S. shareholder-owned electric utili-ties. This index measures total return and provides company rankings for one- and fi ve-year periods.

Introduction to Depreciation and Net Salvage of Public Utility Plant and Plant of Other Industries (textbook copyright 2003)

This book provides a basic primer on the concepts of depreciation account-ing including fundamental principles, life analysis techniques, salvage and cost of removal analysis methods and depreciation rate calculation formulas and examples.

Introduction to Public Utility Accounting (textbook copyright 2001)

This renowned textbook provides a basic explanation of the fundamentals and practices of electric and gas utility accounting. Thoroughly updated and revised in 2001 with current accounting standards, regulatory requirements and industry trends, the textbook includes completely new chapters on Restructur-ing and Energy Trading—key issues in the rapidly evolving electric industry.

PublicationsSummary



Industry directories published by the Finance and Accounting Division:

■ Electric Utility Investor Relations Executives Directory

■ Chief Accounting Offi cers Directory

■ Accounting and Internal Audit Executives Directory

For more information, please visit the EEI Web site at www.eei.org.

Conference Highlights

Annual Financial Conference

This three-day conference is the premier annual fall gathering of utili-ties and the fi nancial community; it is attended by more than 1,200 senior executives, including many utility CEOs and CFOs, investment analysts, and commercial and investment bank-ers. General sessions cover topics of strategic interest to the fi nancial com-munity. Contact Debra Henry for more information.

International Financial Conference

This three-day conference, held each winter in London, provides a forum for global utility executives, security analysts, and other investors to meet in a common area for the purpose of information exchange on industry issues and competitive strategies across mul-tiple markets. Contact Debra Henry for more information.

Annual Finance Meeting

This two-day meeting is held in the spring in New York City. Attendance is limited to member company util-ity executives and Wall Street security analysts. Topics revolve around emerg-

ing industry issues and their fi nancial implications. The meeting facilitates investors meeting with utility executives on an individual basis. Contact Debra Henry for more information.

Investor Relations Meeting

This one-day meeting is held in the spring in New York City. It is a forum for utility investor relations executives that provides key information on evolv-ing industry issues and identifi es best practices within and outside the electric utility industry. Contact Debra Henry for more information.

Financial Analysts Seminar

This two-day seminar is held every other year in the spring in New York City. It is a seminar for fi nancial and security analysts new to the industry. Contact Debra Henry for more infor-mation.

Accounting Leadership Conference

This annual meeting covers current accounting and management issues for the chief accounting offi cers of EEI member companies. Contact David Stringfellow for more information.

Intermediate Tax School

Provides tax professionals a forum to discuss developing tax issues impacting our member companies. This two and half day training is held every other year. Contact Roger Kranenburg for more information.

Accounting Courses

Introduction to Public Utility Accounting

Provides utility personnel with the fundamentals of public utility account-ing. Directed toward recently hired staff in the accounting, auditing, and fi nan-cial areas. Contact David Stringfellow for more information.

Advanced Public Utility Accounting

Concentrates on specifi c advanced accounting topics and complex ac-counting issues affecting companies in the new competitive environment. Contact David Stringfellow for more information.

Utility Internal Auditor’s Training Course

Provides utility staff auditors and di-rectors with the fundamentals of public utility auditing and specifi c accounting issues including advanced internal au-diting topics. Contact David Stringfel-low for more information.

The EEI Business Services And Finance Division Staff

Richard McMahon Executive Director, Energy Supply(202) [email protected]

Mari SmallwoodAdministrative Assistant(202) [email protected]



Investor Relations Staff:

Debra HenryCoordinator, Investor Relations & Conference Services(202) [email protected]

Finance Staff:

Mark AgnewManager, Financial Analysis(202) [email protected]

Irene Ybadlit Administrative Assistant(202) [email protected]

Accounting Staff:

David Stringfellow, CPADirector of Accounting(202) [email protected]

Kim KingStaff Assistant (202) 508-5493 [email protected]

2005

40th EEI Financial ConferenceNovember 6-9, 2005Westin DiplomatHollywood, Florida

Electric Utility InvestorRelations Group Planning MeetingDecember 1, 2005(Closed meeting admittance by invitation only)Omni Berkshire – New York, NY

Finance Executive Advisory Committee MeetingDecember 2, 2005(Closed meeting admittance by invitation only)Omni Berkshire – New York, NY

2006

EEI Appearance Before Wall StreetJanuary (date to be announced)University ClubNew York, NY

EEI International Utility ConferenceFebruary 19–22, 2006London Hilton on Park LaneLondon, United Kingdom

Electric Utility InvestorRelations Group Planning MeetingGMay 23, 2006Waldorf=AstoriaNew York, NY

EEI Annual Finance Committee MeetingMay 24-25, 2006Waldorf=AstoriaNew York, NY

41st EEI Financial ConferenceNovember 5-8, 2006 Ceasar’s Palace Las Vegas, Nevada

Electric Utility InvestorRelations Group Planning Meeting

December 7, 2006(Closed meeting admittance by invitation only)Hotel to be announced – New York, NY

Finance Executive Advisory Committee Meeting

December 8, 2006(Closed meeting admittance by invita-tion only)Hotel to be announced – New York, NY

2007

42nd EEI Financial ConferenceNovember 4-7, 2007Walt Disney World DolphinLake Buena Vista, Florida

Edison Electric Institute Schedule of Upcoming Meetings

To assist in planning your schedule, here are meetings that may be of inter-est to you.

For further details, please contact either Debra Henry at 202/508-5496 or Mari Smallwood at 202/508-5501.

Future Finance Meetings



U.S. Shareholder-Owned Electric UtilitiesAllegheny Energy, Inc.

Allete, Inc.

Alliant Energy Corporation

Ameren Corporation

American Electric Power Company, Inc.

Aquila, Inc.

Avista Corporation

Black Hills Corporation

CenterPoint Energy, Inc.

Central Vermont Public Service Corporation

CH Energy Group, Inc.

Cinergy Corporation

Cleco Corporation

CMS Energy Corporation

Consolidated Edison, Inc.

Constellation Energy Group, Inc.

Dominion Resources, Inc.

DPL, Inc.

Duquesne Light Holdings, Inc.

DTE Energy Company

Duke Energy Corporation

Edison International

El Paso Electric Company

Empire District Electric Company

Energy East Corporation

Entergy Corporation

Exelon Corporation

FirstEnergy Corporation

FPL Group, Inc.

Great Plains Energy, Inc.

Green Mountain Power Corporation

KeySpan Corporation

Hawaiian Electric Industries, Inc.

IDACORP, Inc.

IPALCO Enterprises, Inc.

Maine & Maritimes Corporation

MDU Resources Group, Inc.

MGE Energy, Inc.

MidAmerican Energy Company

New England Power Company

Niagara Mohawk Power Corporation

NiSource, Inc.

Northeast Utilities

NorthWestern Corporation

NSTAR

OGE Energy Corporation

Otter Tail Corporation

PacifiCorp

Pepco Holdings, Inc.

PG&E Corporation

Pinnacle West Capital Corporation

PNM Resources, Inc.

Portland General Electric Company

PPL Corporation

Progress Energy, Inc.

Public Service Enterprise Group Inc.

Puget Energy, Inc.

SCANA Corporation

Sempra Energy

Sierra Pacific Resources

Southern Company

TECO Energy, Inc.

TNP Enterprises, Inc.

TXU Corporation

UIL Holdings Corporation

UniSource Energy Corporation

Unitil Corporation

Vectren Corporation

Westar Energy, Inc.

Wisconsin Energy Corporation

WPS Resources Corporation

Xcel Energy, Inc.

Note: Includes the 65 companies that comprise the EEI Index plus an additional 7 electric utilities (shown in italics) that are not listed on U.S. stock exchanges for one of the following reasons - they are subsidiaries of an independent power producer; they are subsidiaries of foreign-owned companies; or they were acquired by other investment firms.

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