PACIFICORP 10K

10-K405 1 0001.htm PACIFICORP 10K

SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

(Mark One)

/X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended March 31, 2000
OR

/ / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

For the Transition period from _________ to _________

Commission File Number 1-5152

PACIFICORP
(Exact name of registrant as specified in its charter)

        State of Oregon                                 93-0246090
  (State or other jurisdiction            (I.R.S. Employer Identification No.)
of incorporation or organization)

  825 N.E. Multnomah, Portland, Oregon                   97232
(Address of principal executive offices)               (Zip Code)

Registrant's telephone number, including area code: (503) 813-5000

Securities registered pursuant to section 12(b) of the Act:

	Title of each Class	Name of each exchange on which registered
	8 3/8% Quarterly Income Debt Securities (Junior Subordinated Deferrable Interest Debentures, Series A) 8.55% Quarterly Income Debt Securities (Junior Subordinated Deferrable Interest Debentures, Series B) 8 1/4% Cumulative Quarterly Income Preferred Securities, Series A, of PacifiCorp Capital I 7.70% Cumulative Quarterly Income Preferred Securities, Series B, of PacifiCorp Capital II	New York Stock Exchange New York Stock Exchange New York Stock Exchange New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

Title of each Class

5% Preferred Stock (Cumulative; $100 Stated Value)
Serial Preferred Stock (Cumulative; $100 Stated Value)
No Par Serial Preferred Stock (Cumulative; Various Stated Values)

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES X NO ___

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X]

On May 1, 2000, the aggregate market value of the shares of voting and nonvoting common equity of the Registrant held by nonaffiliates was $0.

As of June 14, 2000, there were 297,324,604 shares of common stock outstanding. (All common shares are indirectly owned by ScottishPower.)

DOCUMENTS INCORPORATED BY REFERENCE

None.

TABLE OF CONTENTS

	Page No.
Definitions..................................................	ii
Part I Item 1. Business........................................ The Organization.............................. Domestic Electric Operations.................. Australian Electric Operations................ Other Operations.............................. Discontinued Operations....................... Employees..................................... Item 2. Properties...................................... Item 3. Legal Proceedings............................... Item 4. Submission of Matters to a Vote of Security Holders.......................................	1 1 2 16 24 25 25 25 28 29
Part II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters................... Item 6. Selected Financial Data......................... Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations........... Item 7A. Quantitative and Qualitative Disclosures about Market Risk............................. Item 8. Financial Statements and Supplementary Data..... Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure........	30 30 30 55 56 112
Part III Item 10. Directors and Executive Officers of the Registrant.................................... Item 11. Executive Compensation.......................... Item 12. Security Ownership of Certain Beneficial Owners and Management................................ Item 13. Certain Relationships and Related Transactions..	112 115 127 127
Part IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K...........................	128
Signatures..................................................	131

DEFINITIONS

When the following terms are used in the text they will have the meanings indicated:

Term	Meaning
Company.........................	PacifiCorp and its subsidiaries
Hazelwood.......................	Hazelwood Power Partnership, a 19.9% indirectly owned investment of Holdings
Holdings........................	PacifiCorp Group Holdings Company, a wholly owned subsidiary of the Company and its wholly owned subsidiary, PacifiCorp International Group Holdings Company
PFS.............................	PacifiCorp Financial Services, Inc., a wholly owned subsidiary of Holdings, and its subsidiaries
PacifiCorp......................	PacifiCorp, an Oregon corporation
Pacific Power...................	Pacific Power & Light Company, the assumed business name of the Company under which it conducts a portion of its retail electric operations
PPM.............................	PacifiCorp Power Marketing, Inc., a wholly owned subsidiary of Holdings
Powercor........................	Powercor Australia Ltd., an indirect, wholly owned subsidiary of Holdings, and its immediate parent companies, PacifiCorp Australia Holdings Pty Ltd and PacifiCorp Australia LLC
ScottishPower...................	Scottish Power plc, the indirect parent company of PacifiCorp
TPC.............................	TPC Corporation, a wholly owned subsidiary of Holdings until its sale in April 1999, and its subsidiaries
Utah Power......................	Utah Power & Light Company, the assumed business name of the Company under which it conducts a portion of its retail electric operations

PART I

ITEM 1. BUSINESS

THE ORGANIZATION

The Company is an electricity company in the United States and Australia. In the United States, the Company conducts its retail electric utility business as Pacific Power and Utah Power, and engages in power production and sales on a wholesale basis under the name PacifiCorp. Holdings owns the stock of subsidiaries conducting businesses not regulated as domestic electric utilities, including Powercor, the largest of the five electric distribution companies in Victoria, Australia.

The Company's strategic business plan is to focus on its electricity businesses in the western United States. As part of its strategic business plan, the Company will sell its other United States and international businesses, and has previously terminated all of its business development activities outside of the United States. During January 2000, the Company committed to seek a buyer for Powercor. Holdings continues to liquidate portions of the loan and leasing portfolio of PFS. PFS presently expects to retain only its tax-advantaged investments in leveraged lease assets and limit its pursuit of new tax-advantaged investment opportunities. See "AUSTRALIAN ELECTRIC OPERATIONS," "DISCONTINUED OPERATIONS," and "OTHER OPERATIONS."

On November 29, 1999, the Company and ScottishPower completed their proposed merger under which the Company became an indirect subsidiary of ScottishPower (the "Merger"). The Company continues to operate under its current name, and its headquarters will remain in Portland, Oregon. As a result of the Merger, the Company became part of a public utility holding company group. The Company's operations are now subject to the requirements and restrictions of the Public Utility Holding Company Act of 1935.

In the Merger, each share of the Company's stock was converted tax-free into a right to receive 0.58 American Depositary Shares ("ADS") (each ADS represents four ordinary shares) or 2.32 ordinary shares of ScottishPower. Cash was paid in lieu of fractional shares.

Effective November 30, 1999, the Company changed its fiscal year end from December 31 to March 31, which is the fiscal year end for ScottishPower. A report on Form 10-Q for the three-month transition period from January 1, 1999 through March 31, 1999 was filed with the Securities and Exchange Commission on January 13, 2000. The year ended March 31, 2000 and quarterly periods within that year are referred to as 2000. All future years refer to fiscal years ending March 31. The years ended December 31, 1998 and 1997 are referred to as 1998 and 1997, respectively. Powercor's fiscal year end remains December 31. Consequently, the Company's consolidated balance sheet and statements of consolidated income and consolidated cash flows as of and for year ended March 31, 2000 include Powercor's financial statements as of and for the year ended December 31, 1999.

As a result of the Merger, the Company has developed and commenced a transition plan (the "Transition Plan") to implement significant organizational and operational changes. For more information, see "ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - OVERVIEW OF 2000."

From time to time, the Company may issue forward-looking statements under the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 that involve a number of risks and uncertainties. Although the Company believes the expectations reflected in such forward-looking statements are based on reasonable assumptions, it can give no assurance that its expectations will be realized. Forward-looking statements involve known and unknown risks which may cause the Company's actual results to differ materially from those expected. The following factors are among the factors that could cause actual results to differ materially from the forward-looking statements: utility commission practices; regional, national and international economic conditions; weather variations affecting customer usage, competition in bulk power and natural gas markets and hydroelectric and natural gas production; hydro-facility relicensing; energy trading activities; environmental, regulatory and tax legislation, including industry restructure and deregulation initiatives; technological developments in the electricity industry; foreign exchange rates; proposed asset dispositions; and the cost of debt and equity capital. Any forward-looking statements issued by the Company should be considered in light of these factors.

The Company's 8 3/8% Quarterly Income Debt Securities (Junior Subordinated Deferrable Interest Debentures, Series A) and 8.55% Quarterly Income Debt Securities (Junior Subordinated Deferrable Interest Debentures, Series B) are traded on the New York Stock Exchange. The 8 1/4% Cumulative Quarterly Income Preferred Securities (Series A Preferred Securities) of PacifiCorp Capital I, a wholly owned subsidiary trust, and the 7.70% Cumulative Quarterly Income Preferred Securities (Series B Preferred Securities) of PacifiCorp Capital II, a wholly owned subsidiary trust, are also traded on the New York Stock Exchange.

DOMESTIC ELECTRIC OPERATIONS

The Company conducts its domestic retail electric utility operations as Pacific Power and Utah Power, and engages in wholesale electric transactions under the name PacifiCorp. Pacific Power and Utah Power provide electric service within their respective service territories. Power production, wholesale sales, fuel supply and administrative functions are managed on a coordinated basis.

Service Area

The Company serves approximately 1.5 million retail customers in service territories aggregating about 135,800 square miles in portions of six western states: Utah, Oregon, Wyoming, Washington, Idaho, and California. The Company's service area contains diversified industrial and agricultural economies. Principal industrial customers include oil and gas extraction, lumber and wood products, paper and allied products, chemicals, primary metals, mining companies, high technology, and agribusiness. Agricultural products include potatoes, hay, grain and livestock.

The Company is currently exiting operations in California. See "Proposed Asset Additions and Dispositions."

The geographical distribution of the Company's retail electric operating revenues for the year ended March 31, 2000 was Utah, 38%; Oregon, 33%; Wyoming, 13%; Washington, 8%; Idaho, 6%; and California, 2%.

Customers

Electric utility revenues and energy sales, by class of customer, for the year ended March 31, 2000, the three months ended March 31, 1999, and the years ended December 31, 1998 and 1997, were as follows:

	2000		1999		1998		1997
Operating Revenue (Dollars in millions): Residential Commercial Industrial Government, Municipal and Other Total Retail Sales Wholesale Sales and Market Trading Total Energy Sales Other Revenues Total Operating Revenues	$ 798.7 667.2 694.5 30.4 2,190.8 1,029.1 3,219.9 72.3 $3,292.2	25% 21 21 1 68 32 100%	$ 231.2 159.0 151.8 7.2 549.2 240.0 789.2 18.0 $ 807.2	30% 20 19 1 70 30 100%	$ 806.6 653.5 705.5 30.2 2,195.8 2,583.6 4,779.4 65.7 $4,845.1	17% 14 15 1 47 53 100%	$ 814.0 640.9 709.9 31.7 2,196.5 1,428.0 3,624.5 82.4 $3,706.9	22% 18 20 1 61 39 100%
Kilowatt-hours Sold (kWh in millions): Residential Commercial Industrial Government, Municipal and Other Total Retail Sales Wholesale Sales and Market Trading Total kWh Sold	13,028 12,827 20,488 663 47,006 34,327 81,333	16% 16 25 1 58 42 100%	3,773 2,993 4,627 153 11,546 9,636 21,182	18% 14 22 1 55 45 100%	12,969 12,299 20,966 651 46,885 94,077 140,962	9% 9 15 - 33 67 100%	12,902 11,868 20,674 705 46,149 59,143 105,292	12% 11 20 1 44 56 100%

The Company's service territory has complementary seasonal load patterns. In the western sector, customer demand peaks in the winter months due to space heating requirements. In the eastern sector, customer demand peaks in the summer when irrigation and cooling systems are heavily used. Many factors affect per customer consumption of electricity. For residential customers, within a given year, weather conditions are the dominant cause of usage variations from normal seasonal patterns. However, the price of electricity is also considered a significant factor.

During 2000, no single retail customer accounted for more than 2% of the Company's retail utility revenues and the 20 largest retail customers accounted for 14% of total retail electric revenues.

Competition

In many cases, customers have the option to switch energy sources for heating and air conditioning. In addition, certain of the Company's industrial customers are seeking choice of suppliers, options to build their own

generation or cogeneration, or the use of alternative energy sources such as natural gas. When a competitive marketplace exists, customers will make their energy purchasing decision based upon many factors, including price, service and system reliability.

During 2000, the Company continued to operate its electricity distribution and retail sales business as a regulated monopoly throughout most of its franchise service territories. However, the Company anticipates increasing competition, principally as a result of industry restructuring, deregulation and increased marketing by alternative energy suppliers.

Beginning in April 1998, California retail electric energy sales have been subject to open market competition. The Company's provision of tariffed services in California will continue to be regulated while any competitive sales of electricity will be unregulated. The other states in the Company's service territory have, to varying degrees, examined retail competition and industry restructuring, but only Oregon has enacted comprehensive legislation. Generally, the other states are moving more slowly towards competition than was originally anticipated by the Company. See "Regulation." The Company supports increased customer choice under terms and conditions that are equitable to all stakeholders.

During July 1999, legislation was enacted in Oregon that requires competition for industrial and large commercial customers of both the Company and Portland General Electric by October 1, 2001. Residential customers will have the option of selecting a cost of service rate or a portfolio of energy commodity rate options. The law generally exempts publicly-owned utilities and Idaho Power's Oregon service territory. The law authorizes the Oregon Public Utility Commission (the "OPUC") to make decisions on a variety of important issues, including the method for valuation of stranded costs/benefits, consumer protections, marketer certification, environmental issues, and competitive services. The legislation also calls for the establishment of a code-of-conduct for electric companies and their affiliates to protect consumers against anti-competitive practices. The legislation directs the investor-owned utilities to collect a 3% public benefit charge from all of its distribution customers. The Company is currently participating in the OPUC proceedings to establish the rules and procedures that will implement the new law. The Company will continue to evaluate the finance and accounting impacts, including the continued propriety of applying Statement of Financial Accounting Standards ("SFAS") No. 71, as the OPUC proceedings progress. The impacts, if any, are uncertain.

The Energy Policy Act, passed in 1992, opened wholesale competition to energy brokers, independent power producers and power marketers. In 1996, the Federal Energy Regulatory Commission (the "FERC") ordered all investor-owned utilities to allow others access to their transmission systems for wholesale power sales ("open access"). This access must be provided at the same price and terms the utilities would apply to their own wholesale customers. Competition is also influenced by availability and price of alternate energy sources and the general demand for electrical power.

The Company has formulated strategies to meet these challenges. The Company is marketing power supply services to other utilities in the western United States, including dispatch assistance, daily system load monitoring, backup power, power storage and power marketing, and services to retail customers that encourage efficient use of energy. Effective January 1, 1998, the California Public Utilities Commission (the "CPUC") adopted rules regulating the nontariffed sale of energy and energy products and services by utilities and their affiliates. The rules mandated a 10% rate reduction, which resulted in a $3.5 million annual reduction in revenues. The Company has decided to refrain from marketing products and services to retail customers in California but intends to continue limited trading in the wholesale business, selling to utilities in California and marketers elsewhere in the western United States.

The Company believes that the regulatory initiatives that are underway in each of the states may eventually bring competition for the electricity generation services. This change in the regulatory structure may significantly affect the Company's future financial position, results of operations and cash flows. The Company intends to seek regular price increases to the extent it underearns its allowed rate of return. This intention, consistent with the strategic direction implemented in 1998, provides a continued foundation for use of SFAS No. 71 in its financial statements. In 1999, the Company filed for rate increases before the state commissions in Oregon, Utah, Washington and Wyoming. See "Regulation."

Power and Fuel Supply

The Company's generating facilities are interconnected through its own transmission lines or by contract through the lines of others. Substantially all generating facilities and reservoirs located within the western states are managed on a coordinated basis to obtain maximum load carrying capability and efficiency.

The Company's transmission system connects with other utilities in the Pacific Northwest having low-cost hydroelectric generation and with utilities in California and the southwestern United States having higher-cost, fossil-fuel generation. The transmission system is available for common use consistent with open access regulatory requirements. In periods of favorable hydroelectric generation conditions, the Company utilizes lower-cost hydroelectric power to supply a greater portion of its load and sells its displaced higher-cost thermal generation to other utilities. In periods of less favorable hydroelectric generation conditions, the Company sells its excess thermal generation to utilities that are more dependent on hydroelectric generation than the Company. During the winter, the Company is able to purchase power from utilities in the southwestern United States, either for its own peak requirements or for resale to other regional utilities. During the summer, the Company is able to sell excess power to utilities in the southwestern United States to assist them in meeting their peak requirements. See "Wholesale Sales and Purchased Power."

The Company owns or has interests in generating plants with an aggregate nameplate rating of 8,331 megawatts ("MW") and plant net capability of 7,829 MW. See "ITEM 2. PROPERTIES." With its present generating facilities, under average water conditions, the Company expects that approximately 6% of its energy requirements for 2001 will be supplied by its hydroelectric plants and 64% by its thermal plants. The balance of 30% is expected to be obtained under long-term purchase contracts, and interchange and other purchase arrangements. During 2000, approximately 7% and 61% of the Company's energy requirements were supplied by its hydroelectric and thermal generation plants, respectively, and the remaining 32% by purchased power.

The Company currently purchases 1,100 MW of firm capacity annually from the federal Bonneville Power Administration ("BPA") pursuant to a long-term agreement. The purchase amount declines to 925 MW annually beginning in July 2000, declining to 750 MW annually in July 2003 and again to 575 MW in July 2004 through August 2011. The Company's annual payment under this agreement for the period ended March 31, 2000 was $74 million. The agreement provides for the amount of the payment to decline proportionately as the amount of power purchased declines and also to change at the rate of change of BPA's average system cost. The next change to BPA's average system cost is expected to occur in 2001 and will be determined by BPA in future rate proceedings.

Under the requirements of the Public Utility Regulatory Policies Act of 1978, the Company purchases the output of qualifying facilities constructed and operated by entities that are not public utilities. During 2000, the Company purchased an average of 112 MW from qualifying facilities, compared to an average of 98 MW in 1998. See Note 14 of Notes to the Consolidated Financial Statements under ITEM 8 for additional details relating to the Company's purchase of power under long-term arrangements.

The Company plans and manages its capacity, energy purchases and energy resources based on critical water conditions. Under critical or better water conditions in the Pacific Northwest, the Company believes that it has adequate reserve capacity for its requirements. The Company's historical total firm peak load (including both retail and firm wholesale sales) of 12,301 MW occurred on February 10, 1998, and its historical on-system firm peak load of 7,909 MW occurred on December 21, 1998.

Wholesale Sales and Purchased Power

Wholesale sales of power contribute significantly to total revenues even though the Company has scaled back wholesale sales from 1998 levels. The Company's wholesale sales complement its retail business and enhance the efficient use of its generating capacity. In 2000, the Company's wholesale revenues decreased 60% and its wholesale energy volume sold decreased 64% from the prior year. Wholesale sales accounted for 42% of the Company's total energy sales and 32% of its total energy revenues in 2000.

In addition to its base of thermal and hydroelectric generation assets, the Company utilizes a mix of long-term and short-term firm power purchases and nonfirm purchases to meet its load obligations and to make sales to other utilities. Long-term firm power purchases supplied 10% of the Company's total energy requirements in 2000. Short-term firm and nonfirm power purchases

supplied 22% of the Company's total energy requirements in 2000. See Note 14 of Notes to the Consolidated Financial Statements under ITEM 8 for further discussion on long-term firm power purchases requirements.

Asset Sales

On May 4, 2000, the utility partners (including the Company) who owned the 1,340 MW coal-fired Centralia Power Plant sold the plant and the adjacent coal mine, wholly owned and operated by the Company, to TransAlta for approximately $500 million, subject to certain post-closing adjustments. The Company operated the plant and owned a 47.5% share. After the return to customers, required by the regulatory approvals, the Company estimates a $14 million loss will be realized on the sale. The timing of this return to customers varies by state. The sale was pursued by the owners, in part, because of emerging deregulation, competition in the electricity industry and the need for environmental compliance expenditures. Pursuant to the sale, TransAlta has agreed to assume the reclamation costs for the Centralia coal mine. At March 31, 2000, the Company had approximately $26 million accrued for its share of the Centralia mine reclamation costs, which was used to reduce the selling price and has been incorporated into the estimate of net loss on the sale.

Proposed Asset Additions and Dispositions

In July 1998, the Company announced its intention to sell its California electric distribution assets. This action was in response to the continued decline in earnings on the assets and the changes in the legislative and regulatory environments in California. On July 15, 1999, the Company signed a definitive agreement for the sale of the assets to Nor-Cal Electric Authority for $178 million. The Company does not expect to incur a material gain or loss on this sale. On August 16, 1999, the Company filed an application with the CPUC for approval of the sale. FERC approved the sale on January 28, 2000. The sale is expected to close in the fall of 2000.

On April 12, 2000, the Company announced the closure of the Trail Mountain Mine in the fall of 2001 after the lease is mined out. This will result in the eventual displacement of 200 employees. The mine is located in Central Utah and supplies fuel to the Hunter Plant. The fuel for the Hunter Plant will be provided by the Company's Deer Creek Mine and other Utah mines. With the early closure of the mine, there may be additional reclamation costs for which the Company would seek recovery through future rate cases.

Projected Demand

The Company continues to benefit from positive economic conditions in several portions of its service territory and retail energy sales for the Company have experienced compound annual growth of 2.0% since 1994. The Company is seeing a turnaround from the downturn in international economic conditions, particularly in the Far East and Japan, that negatively impacted the Company's service territories in the Pacific Northwest and many of the industries the Company serves. The Company is pursuing price increases in jurisdictions where it does not earn an appropriate rate of return and will seek operating efficiencies as outlined in a transition plan which resulted from the Merger.

For the periods 2001 to 2004, the average annual growth in retail kilowatt hour ("kWh") sales in the Company's franchise service territories is estimated to be about 1.4%. During this period, the Company may lose retail energy sales to other suppliers in connection with deregulation of the electric industry. As the electric industry evolves toward deregulation, the Company expects to have opportunities to sell any excess power in wholesale markets. The Company's actual results will be determined by a variety of factors, including the outcome of deregulation in the electric industry, economic and demographic growth, and competition.

Environmental Issues

Federal, state and local authorities regulate many of the Company's activities pursuant to laws designed to restore, protect and enhance the quality of the environment. These laws have increased the cost of providing electric service. The Company is unable to predict what material impact, if any, future changes in environmental laws and regulations may have on the Company's consolidated financial position, results of operations, cash flows, liquidity, and capital expenditure requirements.

All of the Company's mining operations are subject to reclamation and closure requirements. The Company monitors these requirements and annually revises its cost estimates to meet existing legal and regulatory requirements of the various jurisdictions in which it operates. Compliance with future requirements could result in higher expenditures for both capital improvements and operating costs.

Air Quality. The Company's operations, principally its fossil fuel-fired electric generating plants, are subject to regulation under the Federal Clean Air Act, individual state clean air requirements and in some cases local air authority requirements. The primary air pollutants of concern are sulfur dioxide ("SO₂"), nitrogen oxides ("NO_x"), particulate matter (currently PM₁₀) and opacities. In addition, visibility requirements impact the coal-burning plants. Although not presently regulated, emissions of carbon dioxide ("CO₂") and mercury from coal-burning facilities generally are of increasing public concern.

The United States Environmental Protection Agency (the "EPA") has recently commenced enforcement actions against the owners of certain coal-fired generating plants in the eastern and midwestern United States. The EPA is alleging that the plant owners have failed to obtain the necessary permits under the Clean Air Act in connection with certain alleged modifications at the plants and that the owners have failed to install additional pollution control equipment as required. If the EPA is successful in asserting its position, the companies named in the action will be required to make significant capital expenditures to install pollution control equipment. The Company does not have an ownership interest in any of the plants involved in these matters, and the Company is not a party to any of these actions. Nevertheless, the Company has become aware that the EPA is engaged in fact-finding with respect to many coal-fired generating plants in the country. The Company is unable to predict the outcome of the EPA's fact-finding effort.

Pollutants -- Emission controls, low sulfur coal, plant operating practices and continuous emissions monitoring are all utilized to enable coal-burning plants to comply with opacity, visibility and other air quality requirements. All of the Company's coal-burning plants burn low sulfur coal and are equipped with controls to limit emissions of particulate matter. Many of the Company's coal-burning plants, representing the majority of its installed capacity, have been equipped with controls which reduce the quantity of SO₂ emissions. The SO₂ emission allowances awarded to the Company under the Federal Clean Air Act, and those allowances expected to be awarded annually in the future, are sufficient to enable the Company to meet its current and expected future requirements. In addition, the Company has taken advantage of opportunities to sell SO₂ allowances to other entities.

Visibility -- Various federal and state agencies, as well as private environmental awareness groups, have raised concerns about perceived visibility degradation in some areas which are in proximity to some of the Company's coal-burning plants. Numerous visibility studies have been completed or are in the process of completion near Company coal-burning plants in Colorado, Utah, Washington and Wyoming. To date, no additional emission control requirements at Company facilities have resulted directly from these studies, although the potential exists for significant additional control requirements if visibility degradation in the study areas is reasonably attributed to the Company's coal-burning plants. The EPA also has implemented new regulations addressing regional haze. These proposed regulations have the potential to impose significant new control requirements on certain of the Company's older coal-burning plants that are not otherwise subject to the most stringent emission limits.

Climate Change -- CO₂ emissions are the subject of growing world-wide discussion and action in the context of global warming, but such emissions are not currently regulated. All of the Company's coal-burning plants emit CO₂. In late 1997, the United States and other parties to the United Nations Framework Convention on Climate Change adopted the Kyoto Protocol regarding the control and reduction of so-called greenhouse gas emissions (including CO₂). The United States signed the protocol in November 1998, but the United States Senate has not yet ratified it. The Kyoto Protocol, if ultimately ratified, has the potential to impose significant new costs and operational restrictions on the Company's coal-burning plants.

Mercury -- The Company's coal-burning plants, along with all other major coal-burning plants in the United States, are participating in an effort to gather additional information about mercury emissions pursuant to a request issued by the EPA. Based in part on this effort, the EPA is scheduled to decide during calendar 2000 whether to regulate mercury emissions from coal-burning plants. If passed, new mercury emission requirements have the potential to impose significant new control and operational constraints on the Company's coal-burning plants.

Air Operating Permits -- The Company has received Title V Air Operating Permits for all of its coal and natural gas-fired power plants. In 1998, a citizen group challenged the issuance of the operating permits for the Company's Naughton and Jim Bridger power plants, but the EPA still has not yet

acted on that challenge. The Company believes that it currently has all required permits and management systems in place to assure compliance with operating permit requirements.

Enforcement -- In addition to general regulation, the Company is subject to ongoing enforcement action by regulatory agencies and private citizens regarding compliance with air quality requirements. A federal lawsuit filed in 1996 by the Sierra Club against the owners, including the Company, of units one and two of the Craig Generating Station alleged, among other things, violations of opacity requirements. The lawsuit seeks civil monetary penalties and an injunction. See "ITEM 3. LEGAL PROCEEDINGS."

Electromagnetic Fields. A number of studies continue to examine the possibility of adverse health effects from electromagnetic fields ("EMF"), without conclusive results. Certain states and cities have enacted regulations to limit the strength of magnetic fields at the edge of transmission line rights-of-way. Other than in California, none of the state agencies with jurisdiction over the Company's operations have adopted formal rules or programs with respect to magnetic fields or magnetic field considerations in the siting of electric facilities. The CPUC has issued an interim order requiring utilities to implement no-cost or low-cost mitigation steps in the design of new facilities. It is uncertain whether the Company's operations may be adversely affected in other ways as a result of EMF concerns.

Endangered Species. Protection of the habitat of endangered and threatened species makes it difficult and more costly to perform some of the core activities of the Company, including the siting, construction and operation of new and existing transmission and distribution facilities, as well as generating plants. In addition, endangered species issues impact the relicensing of existing hydroelectric generating projects, generally raising the price the Company must pay to purchase wholesale power from hydroelectric facilities owned by others and increasing the costs of operating the Company's own hydroelectric resources. These actions could also result in further restrictions on timber harvesting and adversely affect electricity sales to Domestic Electric Operations' customers in the wood products industry.

Environmental Cleanups. Under the Federal Comprehensive Environmental Response, Compensation and Liability Act and similar state statutes, entities that disposed of or arranged for the disposal of hazardous substances may be liable for cleanup of the contaminated property. In addition, the current or former owners or operators of affected sites also may be liable. The Company has been identified as a potentially responsible party in connection with a number of cleanup sites because of current or past ownership or operation of the property or because the Company sent hazardous waste or other hazardous substances to the property in the past. The Company has completed several cleanup actions and is actively participating in investigations and remedial actions at other sites. The costs associated with those actions are not expected to be material to the Company's consolidated financial position, results of operations, cash flows, liquidity, or capital expenditure requirements.

Water Quality. The Federal Clean Water Act and individual state clean water regulations require a permit for the discharge of waste water, including storm water runoff from the power plants and coal storage areas, into surface waters. Also, permits may be required in some cases for discharges into ground waters. The Company believes that it currently has all required permits and management systems in place to assure compliance with permit requirements.

Regulation

The Company is subject to the jurisdiction of public utility regulatory authorities of each of the states in which it conducts retail electric operations as to prices, services, accounting, issuance of securities and other matters. Commissioners are appointed by the individual state's governor for varying terms. The Company is a "licensee" and a "public utility" as those terms are used in the Federal Power Act and is, therefore, subject to regulation by the FERC as to accounting policies and practices, certain prices and other matters. Most of the Company's hydroelectric plants are licensed as major projects under the Federal Power Act and certain of these projects are licensed under the Oregon Hydroelectric Act. As a result of the Merger, the Company is also subject to the requirement and restrictions of the Public Utility Holding Company Act of 1935.

The Company is currently in the process of relicensing or preparing to relicense 16 separate hydroelectric projects under the Federal Power Act. These projects, some of which are grouped together under a single license, represent approximately 1,000 MW, or about 94% of the Company's total hydroelectric nameplate capacity and about 14% of its total generating capacity. In the new licenses, the FERC is expected to impose conditions designed to address the impact of the projects on fish and other environmental concerns. See "Environmental Issues - Endangered Species." The Company is unable to predict the impact of imposition of such conditions, but capital expenditures and operating costs are expected to increase in future periods. In addition, the Company may refuse to accept renewed licenses for certain projects if the terms of renewal would make the projects uneconomical to operate. The Company has agreed to remove the Condit dam at a cost of approximately $16 million.

During 1998, the Company filed new depreciation rates with the respective regulatory commissions in the states of Oregon, Utah and Wyoming based upon a depreciation study. New depreciation rates were filed in Washington as part of a general rate case filing. The Utah Public Service Commission (the "UPSC") approved new depreciation rates in an order dated January 6, 2000. The OPUC approved new depreciation rates in an order dated May 31, 2000. Stipulated rates have been agreed upon in Wyoming, with a final order still pending. The impact of the proposed changes in depreciation is being incorporated into the current general rate cases in Oregon and Washington and the next general rate case in the other states. Based on the depreciation rates that have been approved and are pending approval, annual depreciation expense would be increased by approximately $20 million. The increase in depreciation expense is primarily due to revisions of the estimated costs of removal for steam production and distribution plant. For the period April 1, 2000 to March 31, 2002, the Utah and Wyoming commissions have ordered a reversal of a portion of previously accrued depreciation. These reversals in total, for all states, will amount to approximately $14 million per year.

Between February 10 and April 6, 2000, the Company received approval orders from all states in which the Company operates for the sale of the Company's interests in the Centralia plant and mine. The sale was completed on May 4, 2000. FERC approved the sale on January 13, 2000. For additional information on the sale of Centralia, see "Asset Sales."

Merger Orders

On June 10, 1999, the CPUC issued an order approving the Merger. The CPUC conditioned its approval on the Company's acceptance of requirements which primarily addressed the Commission's ability to continue to regulate the Company's California service territory.

On November 22, 1999, the Wyoming Public Service Commission ("WPSC") issued an order approving the Merger. The Company agreed to make an informational filing in 2001 that guarantees reflection of $4 million per year in merger savings in future rate cases. The Company separately agreed to limit any rate increase filing in 1999 to $12 million and in the following year to $8 million plus the effect of any change in depreciation rates. See "Regulation."

On October 6, 1999, the OPUC issued an order approving the Merger. As part of this approval, the Company agreed to provide a merger credit to retail customers of $12 million per year for three years beginning in calendar 2001 and $15 million in calendar 2004. In calendar 2003 and 2004, $9 million and $12 million, respectively, of the credit can be partially or wholly eliminated to the extent that merger-related cost savings are reflected in prices.

On October 14, 1999, the Washington Utilities & Transportation Commission (the "WUTC") approved the Merger. As part of this approval, the Company agreed to provide retail customers a merger credit of $3 million per year for four years beginning in calendar 2001. The credit can be wholly or partially eliminated in all years to the extent that merger-related cost savings are reflected in prices.

On November 15, 1999, the Idaho Public Utilities Commission (the "IPUC") approved the Merger. As part of this approval, the Company agreed to provide a $1.6 million per year merger credit to retail customers for four years beginning in calendar 2000. The credit can be wholly or partially eliminated in years three and four to the extent that merger-related cost savings are reflected in prices.

On November 24, 1999, the UPSC approved the Merger. As part of this approval, the Company agreed to provide a merger credit for retail customers of $12 million per year for four years beginning in calendar 2000. The credit can be wholly or partially eliminated in years three and four to the extent that merger-related cost savings are reflected in prices.

The Company's total obligation for merger credits described above is $133.4 million over the period ending December 31, 2004. Of this amount, $57.2 million must be provided without offset or reduction of any kind and, accordingly, the Company has recorded $57.2 million as a liability and current expense in its financial statements for the year ended March 31, 2000. The

remaining $76.2 million obligation of the Company with respect to merger credits is subject to possible offset if the Company demonstrates in a future rate case, to the satisfaction of the respective commissions, that merger-related cost reductions have occurred and are being reflected in rates. This $76.2 million obligation will be reflected in future periods.

A summary of regulatory and legislative developments in the states where the Company conducts its distribution and retail electric operations is set forth below.

Utah. On March 4, 1999, the UPSC ordered the Company to reduce revenues in Utah by $85 million, or 12%, annually. The ordered reduction was the culmination of a general rate case that began in 1997. Additionally, the UPSC ordered a refund to be issued through a credit on customer bills of $40 million. The Company recorded a $38 million reduction in revenues in 1998 and recorded the remaining $2 million in the three months ended March 31, 1999. The refund covers the period from March 14, 1997 to February 28, 1999. The beginning date is consistent with the timing of Utah legislation imposing a moratorium on rate changes after the Utah Division of Public Utilities (the "UDPU") and the Utah Committee of Consumer Services (the "UCCS") requested a general rate case. The $85 million reduction commenced on March 1, 1999. The order also reduced the Company's authorized rate of return on equity from 12.1% to 10.5%.

On September 20, 1999, the Company filed for a rate increase before the UPSC. The Company asked for an increase of $67 million, or 9.9%, based on a test year ended December 31, 1998 and a requested 11.25% return on equity. On March 15, 2000, the Company filed a revised request of $55.2 million. On May 24, 2000, the Company received an order from the UPSC authorizing the Company to increase prices in Utah for residential, irrigation, small commercial and lighting customers by 4.24% and large commercial and industrial customers by less than 1%. The price increase is expected to result in annual revenues of $17 million. The order allowed a rate of return on equity of 11% and was effective on May 25, 2000.

The 2000 Utah legislative session passed a bill that could significantly change the way in which utilities are regulated in the state. The bill provides guidelines under which the interests of all parties will be protected and balanced in the ratemaking process. It directs the UPSC to determine fair rates by balancing the interests of utility customers with the need of utilities to maintain financial stability. This legislation also streamlines state government by consolidating the UDPU and the UCCS into one agency - the Office of Public Advocate. The bill modifies the nature of UPSC proceedings by encouraging and providing an opportunity for timely and reasonable settlements without restricting the rights of all interested persons to participate in a formal administrative process. Finally, the legislation requires Utah regulators to reflect "known and measurable" changes to financial data when hearing a rate case. This bill is effective July 1, 2001.

The Utah legislature also passed a bill extending the life of a legislative task force created in 1997 to study restructuring issues. The bill authorizes this task force to meet as often as twice a month to prepare legislation to implement an electrical restructuring plan for presentation and consideration in the 2001 legislative session, unless it is not in Utah's best interest to do so.

Oregon. The OPUC and the Company have agreed to an Alternate Form of Regulation ("AFOR") for the Company's Oregon distribution business. The AFOR allows for index-related price increases in 1998, 1999 and 2000, with an annual cap of 2% of distribution revenues in any one year and an overall cap of 5% over the three-year period. The annual revenue increase for the twelve months ended December 31, 1999 was approximately $6.2 million. The AFOR also includes incentives to invest in renewable resources and penalties for failure to maintain the service quality levels. On April 30, 1999, the Company filed for changes in the prices it charges Oregon customers under the AFOR. The filing also contained a request to increase the revenues collected under the Company's system benefits charge. The changes were approved by the OPUC in June 1999, and became effective July 1, 1999. This resulted in a price increase of approximately 1.3%, or $9 million annually, in Oregon. On April 28, 2000, the Company made an additional AFOR filing for a price increase of 1.8%, or $14 million annually. Of this amount, approximately $10 million is offset by costs mandated by regulators.

On November 5, 1999, the Company filed for a general rate increase in Oregon. The Company is asking for an increase of $61.8 million, or 8.5%. The Company's effective date for this increase is expected to be in the fall of 2000. The OPUC staff has submitted a preliminary report raising issues that in the aggregate could produce a $101 million rate reduction after giving effect to the Centralia sale. The staff testimony is due in June 2000 and hearings are scheduled for August 2000.

During July 1999, legislation was enacted in Oregon that requires competition for industrial and large commercial customers of both the Company and Portland General Electric by October 1, 2001. See "Competition."

Wyoming. On July 26, 1999, the Company filed for a rate increase before the WPSC. The Company requested an increase of $12 million, or 4.9%, based on a test year ended December 31, 1998. The Company has also stipulated that any rate increase filings through May 2001 will not exceed $8 million plus the effects of any change in depreciation rates. On May 23, 2000, the Company received an order from the WPSC authorizing the Company to increase prices in Wyoming, resulting in increased annual revenues of $11 million. The order allowed a total rate of return of 8.85%, a return on common equity of 11.25% and was effective May 25, 2000. The WPSC did not allow recovery of approximately $1 million of the requested $12 million increase allocated to partial requirements industrial customers, finding that the cost of service study was not sufficient to support the increase to this class. The Company is in the process of refiling for this $1 million increase with a supplemental cost of service study.

Washington. On November 23, 1999, the Company filed for a rate increase before the WUTC. This rate increase contains two phases. In the first phase, the Company is asking for an increase of $14.6 million, or 8.10%. Including the systems benefit charge, which will be used to fund conservation and new renewable development projects, this increase is $17.4 million, or 9.64%. In the second phase, the Company is requesting an increase of $11.2 million, or 5.65%. The effective date for phase one of this proposed tariff increase is expected to be in the fall of 2000, and phase two would become effective one year following the effective date of phase one.

Idaho. On April 28, 2000, the Company filed documents with the IPUC to implement the next step in the gradual retirement of a BPA energy credit. The proposed reduction in the credit would increase electric prices for the Company's residential and irrigation customers in southeastern Idaho. The filing, once approved by the IPUC, would reduce the credits from the BPA and increase residential prices 3.35%, or $1 million, and irrigation prices 8%, or $2 million. These price increases phase out the BPA credit and do not have any impact on earnings.

Congress created the federal credit in 1980 to share the benefits of federally owned hydroelectric plants with customers of investor-owned utilities in the Columbia River drainage area. Congress recommended in 1995 that the current exchange method be phased out by June 2001. In 1997, the Company reached a settlement with BPA to implement the order of Congress. The settlement provided credits of $48 million over five years for the Company's customers, which lessens the impact of price increases as the BPA exchange credit is phased out.

The Company intends to seek recovery of all of its prudent costs, including stranded costs, in the event of deregulation. However, due to the current lack of definitive legislation, the Company cannot predict whether it will be successful. At March 31, 2000, the Company's SFAS No. 71 regulatory assets for all states totaled $703 million, of which approximately $310 million is applicable to generation. The Company has no regulatory assets outside of Domestic Electric Operations. Because of the potential regulatory and/or legislative action in Utah, Oregon, Wyoming, Idaho and Washington, the Company may have regulatory asset write offs and charges for impairment of long-lived assets in future periods relating to the generation portion of its business. Impairment would be measured in accordance with SFAS No. 121, which requires the recognition of impairment on long-lived assets when book values exceed expected future cash flows. Integral parts of future cash flow estimates include estimated future prices to be received, the expected future cash cost of operations, sales and load growth forecasts and the nature of any legislative or regulatory cost recovery mechanisms.

Construction Program

The following table shows actual construction costs for 2000 and the Company's estimated construction costs for 2001 through 2003, including costs of acquiring demand-side resources. The estimates of construction costs for 2001 through 2003 are subject to continuing review and appropriate revision by the Company and are based on the Company's transition plan.

	Actual	Estimated
	2000	2001	2002	2003
	(Dollars in millions)
Information Systems Transmission Distribution Production Other Total	$ 28 17 240 150 75 $510	$ 63 56 196 104 10 $429	$ 60 53 140 104 23 $380	$ 41 68 120 98 11 $338

AUSTRALIAN ELECTRIC OPERATIONS

Powercor

General

Powercor, an indirect, wholly owned subsidiary of Holdings, is the largest electricity distribution company ("Distribution Company") in Victoria, Australia, based on sales volume, revenues, geographic scope and number of customers. Powercor's principal business segments are its Distribution Business and its Supply Business. The Distribution Business consists of the distribution of electricity to approximately 570,000 customers within Powercor's distribution area, covering from the western suburbs of Melbourne to central and western Victoria. The Supply Business consists of the purchase of electricity from generators and the sale of such electricity to customers in Powercor's distribution service area and other parts of Victoria, New South Wales ("NSW"), the Australian Capital Territory ("ACT") and Queensland. Powercor's distribution service area covers approximately 57,900 square miles (64% of the total area of Victoria), has a population of approximately 1.5 million (32% of Victoria's population) and accounts for 26% of Victoria's Gross State Product. In 1999, Victoria accounted for approximately 25% of Australia's total population, approximately 32% of Australia's manufacturing industry output and approximately 26% of Australia's Gross Domestic Product, although it represents only approximately 3% of the total area of Australia.

During January 2000, the Company decided to seek a buyer for Powercor. Powercor's fiscal year end remains December 31.

Distribution Business

Powercor's Distribution Business consists of the ownership, management and operation of the electricity distribution and subtransmission network in its distribution service area. The primary activity of the Distribution Business is the receipt of electricity from Victoria's high voltage transmission system (the "Grid") and the distribution of electricity to customers in Powercor's distribution service area. Substantially all of the Distribution Business is a regulated monopoly. Almost all customers within Powercor's distribution service area are connected to its distribution network, whether electricity is supplied by Powercor or another retail supplier. In 2000, the Distribution Business generated all of Powercor's operating income.

The Distribution Business has grown in both its customer base and the volume of electricity distributed, primarily reflecting economic growth in Victoria generally and Powercor's distribution service area in particular. The following table sets forth the volumes of electricity distributed by Powercor for the years indicated. See "Regulation-Distribution Pricing Regulation" below.

Electricity distributed by the Distribution Business (kWh in millions)	2000	1998
Residential............... Commercial................ Industrial................ Other..................... Total.....................	2,778 1,691 3,592 550 8,611	2,730 1,634 3,378 545 8,287

The Distribution Business of Powercor has not experienced significant competition. Powercor believes that the economics underlying building and maintaining a duplicate distribution network in its distribution service area will restrict the introduction of another network. However, to the extent customers establish or increase their own generation capacity, establish their own private distribution networks, become directly connected to the Grid, or relocate operations outside Powercor's distribution service area, such customers would not require the distribution services of Powercor except in certain cases for standby connection services. As of December 31, 1999, Powercor had not lost any distribution revenues to customers as a result of self-generation, cogeneration or the establishment of private distribution networks. Although Powercor believes that it has effective strategies in place to minimize this type of load loss, there can be no assurance, particularly in view of its large industrial customer base, that the Distribution Business will not experience loss of revenues in the future as a result of such competition.

The major operating expenses of the Distribution Business are distribution use-of-system costs, use-of-transmission-system fees and connection service charges. The use-of-transmission-system fees and connection service charges, regulated by the Tariff Order (see "Regulation - The Tariff Order" below), are payable to the Victorian Energy Network Corporation ("VENCORP"), a corporate body established under Victoria's Electricity Industry Act 1993 (the "EIA"),

and the company that owns and maintains the Grid, GPU Power Net Victoria ("GPU"), respectively. The fees paid constitute VENCORP's and GPU's costs associated with operation, maintenance and administration of the Grid. The distribution use-of-system costs are Powercor's fundamental operating expenses that result from operating and maintaining its distribution network. Unlike use-of-transmission-system fees and connection service charges, Powercor has the ability, and, given the current distribution price-cap regulatory structure, a significant incentive, to control such distribution use-of-system costs through a variety of cost reduction initiatives. However, there can be no assurance that Powercor's cost efficiency initiatives will yield sufficient savings to increase Powercor's margins from the Distribution Business to offset any network tariff reductions that may result from the Office of Regulator General's (the "ORG") review of distribution tariffs charged by Distribution Companies beginning in 2001, as described below under "Regulation-Distribution Pricing Regulation."

Supply Business

The Supply Business conducts the commercial functions of purchasing, marketing and selling of electricity and is responsible for the management of the price, purchasing and volume risks associated with such functions and end-use demand management. Supply Business customers are subject to partial competition, which is progressing toward full competition beginning January 1, 2001. See "Regulation-Supply Pricing Regulation" below.

The customer metered sites, energy usage in millions of kWh and percentages, as well as percentages of Powercor's revenues from the Supply Business for franchise customers in Powercor's distribution service area and for contestable customers are set forth below:

2000	Customer Sites		Energy Usage		Revenues
2000	No.	%	kWh	%	%
Franchise Customers..... Contestable Customers... Total...................	566,753 4,060 570,813	99.3 0.7 100.0	4,121 7,395 11,516	36 64 100	55 45 100

1998	Customer Sites		Energy Usage		Revenues
1998	No.	%	kWh	%	%
Franchise Customers..... Contestable Customers... Total...................	560,729 3,983 564,712	99.3 0.7 100.0	4,225 7,663 11,888	36 64 100	56 44 100

The customer metered sites, energy usage in millions of kWh and percentages of Powercor's revenues from the Supply Business for residential, commercial, industrial and other customers for the years 2000 and 1998 are set forth below:

	Customer Sites⁽¹⁾		Energy Usage		Revenues
	No.	%	kWh	%	%
Residential Customers 2000............... 1998...............	474,592 467,505	83.2 82.8	2,819 2,725	24.5 22.9	36.7 34.7
Commercial Customers 2000............... 1998...............	50,943 50,768	8.9 9.0	4,081 3,952	35.4 33.2	33.9 33.1
Industrial Customers 2000............... 1998...............	9,237 10,400	1.6 1.8	4,090 4,689	35.5 39.4	23.2 26.1
Other Customers⁽²⁾ 2000............... 1998...............	36,041 36,039	6.3 6.4	526 522	4.6 4.5	6.2 6.1
Total Customers 2000............... 1998...............	570,813 564,712	100.0 100.0	11,516 11,888	100.0 100.0	100.0 100.0

____________
(1) Connections as of the date shown.
(2) Other customers include farm customers and public lighting.

The Supply Business revenue is derived from major industries such as chemicals, petroleum, food and beverage, wholesale and retail, metal processing and transport equipment. No single customer accounted for more than 3% of Powercor's total revenues in 2000.

Powercor purchases all of its power for sale to franchise customers, other than cogeneration output, through the competitive wholesale market for electricity in Victoria (the "Pool"). As of December 13, 1998, the respective state wholesale markets consolidated to a National Electricity Market ("NEM") which is operated by the National Electricity Market Management Company ("NEMMCO"). There are two major components of the wholesale electricity market: (i) the competitive energy market, centered primarily around the Pool, which establishes the spot price for the sale of electricity by generators to suppliers and (ii) the contract trade, which involves bilateral financial contracts between electricity buyers and sellers outside the Pool that are used to hedge against Pool price volatility. The principal function of the Pool is to allow market forces rather than monopolized central planning to determine the amount, mix and cost characteristics of generating plants and the level and shape of demand of suppliers.

Powercor is a party to a series of bilateral financial "vesting contracts" that have been structured to hedge the price for Powercor's forecasted franchise energy requirements through December 31, 2000. These vesting contracts take the form of two-way and one-way contracts. Two-way vesting contracts are structured such that generators and Distribution Companies, including Powercor, compensate each other for the difference between the system marginal price, which is the spot price payable to generators in the wholesale market via the Pool, and the contract price up to a specified price cap. One-way vesting contracts provide for amounts to be paid by generators to Distribution Companies for differences when the system marginal price is above a specified price cap. As franchise customers of the Supply Business become contestable, the notional amount of the vesting contracts is reduced accordingly.

Powercor also has hedging contracts that relate to contestable customer loads in order to manage electricity price risk. Historically, Powercor has hedged each electricity sales contract with a back-to-back purchase contract. Increasingly, however, as the contestable customer market grows and as the Australian electricity futures market develops, Powercor is hedging its supply obligations on a portfolio-wide basis. Powercor's policy is to hedge most of its supply obligations and to monitor the financial risk exposure of its unhedged positions.

As of January 1, 2001, all customers in Victoria, the ACT and NSW are scheduled to be contestable, eliminating the use of vesting contracts. Powercor is currently investigating hedging options in preparation for a fully contestable market. Powercor believes that full retail competition in Victoria will be phased in over six months from the official January 1, 2001 start date.

Regulation

Powercor is the largest of the five distribution businesses ("DBs") formed when the Victorian State Government decided to privatize, and eventually deregulate, its electricity industry. As the Victorian market becomes more open to competition and additional customers can choose their energy supplier, Powercor and the other DBs will continue to maintain a monopoly on their individual network areas. These businesses derive much of their revenue from the network fee that is paid for the use of the distribution system.

The ORG. The Victorian government established the ORG pursuant to the Office of the Regulator-General Act 1994 to regulate different Victorian industries. In the context of regulating activities within the electricity industry, the ORG has powers under the EIA. The ORG's functions pursuant to the EIA include granting licenses to generate, transmit, distribute or supply electricity, ensuring compliance with industry codes and rules, administering cross-ownership provisions and administering the Victorian Electricity Supply Industry Tariff Order (the "Tariff Order").

Licenses. Unless covered by an exemption, the EIA prohibits, without a relevant license, the activities of generation of electricity for supply or sale, transmission, distribution, supply or sale of electricity or operation of a wholesale electricity market. Licenses are issued by the ORG after the applicant has satisfied specific criteria and subject to the satisfaction of ongoing conditions, such as continued compliance with industry codes and rules.

Powercor has an exclusive license to distribute electricity to franchise customers in its distribution service area. This will expire on January 1, 2001. Powercor also has nonexclusive licenses to supply electricity to all customers in its distribution service area and elsewhere in Victoria, NSW, ACT and Queensland. See "Supply Pricing Regulation." The Hazelwood Partnership has a license to generate and sell electricity to the wholesale market in Victoria and NSW. See "Hazelwood" below.

The Tariff Order. Pursuant to the EIA, the Tariff Order regulates charges for connection to, and use of, the transmission system, distribution use-of-system charges that can be levied by Distribution Companies and tariffs for the sale of electricity to franchise customers until December 31, 2000. The ORG is charged with the regulatory oversight of the Tariff Order. The Tariff Order is the key instrument the ORG uses to regulate network prices in the Victorian electricity supply industry.

Distribution Pricing Regulation. Under distribution licenses granted by the ORG, the Distribution Companies are able to levy the following charges, which include their profit: (i) network tariffs, which include recovery of distribution use-of-system costs, use-of-transmission-system fees and GPU connection service charges, (ii) connection charges for connecting customers to the network, taking into account that a portion of the costs of connection are recovered through network tariffs and (iii) charges for other services, which are required to be fair and reasonable. The level of distribution charges, as one element of the network tariffs, is regulated under the Tariff Order through December 31, 2000 pursuant to a formula. The formula is the Consumer Price Index for Melbourne ("CPI") minus a fixed percentage ("X"), or CPI-X. This formula attempts to ensure that the annual increase in the weighted average of distribution charges (weighted by the forecast quantity of electricity to be delivered and adjusted for under and over recovery in previous financial years) does not exceed CPI-1%.

Existing network tariffs are subject to review by the ORG within the framework of, and the principles set forth in, the Tariff Order. In particular, the Tariff Order provides that the ORG, in connection with such review of network tariffs, can only reset the network tariffs for a period of not less than five years, the ORG must utilize price capping and not rate of return regulation and the ORG must consider the need to (i) provide each Distribution Company with incentives to operate efficiently, (ii) ensure a fair sharing of benefits achieved through efficiency between customers and Distribution Companies and (iii) ensure appropriate incentives for capital expenditures and maintenance of the distribution networks. The ORG released a draft Distribution Price Review determination in mid-May 2000. This draft suggested reducing Powercor's regulated distribution revenue in 2001 to $168.7 million (as converted using the May 31, 2000 currency exchange rate of 0.58). This is largely driven by a

proposed reduction in the regulated rate of return from 11.9% to 7.4% (pre-tax, real). This would result in an average real network tariff cut of 20.6% on January 1, 2001, and an average real reduction of 1% each year thereafter. This is a preliminary report, and a final determination will be made in September 2000 following further consultation.

Supply Pricing Regulation. Under the retail portions of their licenses, Distribution Companies are required, pursuant to the Tariff Order, to supply electricity to franchise customers through December 2000, at prices no greater than the prices specified in the applicable Maximum Uniform Tariff ("MUT") for such customers. The prices specified in the MUTs are therefore fully regulated and inclusive of all network and distribution related charges and energy costs. Powercor's MUTs are adjusted annually by a percentage equal to CPI minus a fixed percentage. Commencing July 1, 2000, the annual adjustments for large and medium businesses will be the CPI and will be the CPI-1% for medium and small businesses and residential and rural customers. The CPI for the years ended December 31, 1999, 1998 and 1997 was 1.8%, 1.2% and 0.2%, respectively.

Prices charged to contestable customers are subject to competitive forces and, therefore, are not directly regulated by the ORG, in contrast to prices charged to franchise customers. Prices to contestable customers include regulated network charges (transmission and distribution) and competitively determined energy supply charges.

Customers in Victoria, the ACT and NSW with annual consumption in excess of 160 megawatt hours ("MWh") per year are now contestable. Customers with usage of 160 MWh per year or less are not currently contestable but will become contestable on January 1, 2001 in Victoria, the ACT and NSW.

Customers in Queensland with annual consumption of 200 kWh per year can now choose their electricity retailer and there are plans to introduce contestability for all customers on January 1, 2001.

For a description of Powercor's properties, see "ITEM 2. PROPERTIES - AUSTRALIA."

Environmental Issues

The nature of Powercor's operations exposes it to risks of varying degrees associated with bushfires and other environmental issues.

Approximately 63% of Powercor's assets are located in fire prone zones. Powercor and its predecessors have developed a comprehensive bushfire risk management and mitigation system to reduce bushfire exposure. This system is based on regular inspections of poles and conductors and the identification and reporting of maintenance items existing on the network that may contribute to an electrically initiated bushfire.

Powercor is subject to various Australian federal and Victorian state environmental regulations, the most significant of which is the Victorian Environment Protection Act of 1970 ("VEPA"). The VEPA regulates, in particular, the discharge of waste into air, land and water, site

contamination, the emission of noise and the storage, recycling and disposal of solid and industrial waste. The VEPA established the Environment Protection Authority ("Authority") and grants the Authority a wide range of powers to control and prevent environmental pollution. These powers include issuing approvals for construction of works that may cause noise or emissions to air, water or land, waste discharge licenses and pollution abatement notices. Powercor believes it is currently in material compliance with the provisions of the VEPA and no licenses or work approvals from the Authority are currently required for activities undertaken by Powercor.

Hazelwood

General

Hazelwood Pacific Pty Ltd ("Hazelwood Pacific"), an indirect, wholly owned subsidiary of Holdings, holds a 19.9% interest in the Hazelwood Power Partnership (the "Hazelwood Partnership"), which owns a 1,600 MW, brown coal-fired thermal power station (the "Hazelwood Plant") and the adjacent brown coal mine (the "Hazelwood Mine") in Victoria, Australia. The Hazelwood Partnership is composed of Hazelwood Pacific, an affiliate of National Power Corporation PLC ("National Power") (71.94%), and two companies associated with the Commonwealth Bank group of Australia (8.16%). National Power oversees the Hazelwood Plant operations and the Company oversees operations at the Hazelwood Mine. In the fourth quarter of 1998, the Company announced its intent to sell its equity interest in the Hazelwood Partnership and began soliciting bids. Accordingly, the Company recorded a pretax loss of $28 million ($17 million after-tax) to reduce its carrying value in the Hazelwood Power Station to its estimated net realizable value less selling costs.

Through December 2001, Hazelwood Pacific estimates that its contribution to the capital expenditure commitments of the Hazelwood Plant will be $8 million and $6 million for the years 2000 and 2001, respectively. The investment is accounted for on an equity basis. For 1999 and 1998, equity losses from Hazelwood were $2.6 million and $5.5 million, respectively.

The Hazelwood Partnership sells its power through the National Electricity Market and enters into bilateral financial contracts with Australian distribution companies, such as Powercor. Prices vary with weather, economic growth and other factors affecting the supply of and demand for power. Power prices tend to be lowest during Australia's summer months (the fourth and first calendar quarters), except during periods of unusually high temperatures.

For a description of Hazelwood properties, see ITEM 2. PROPERTIES - AUSTRALIA.

Environmental Issues

The operations of the Hazelwood Partnership are subject to environmental regulation. The Hazelwood Partnership is required to obtain licenses from the Authority in connection with certain of its operations, including operations involving the emission or discharge of pollutants. These licenses are generally issued to the Hazelwood Partnership in the ordinary course of business and are terminable upon breach or violation.

The Hazelwood Plant is fired by brown coal and consequently emits more greenhouse gas per unit of power produced than is emitted by power plants fired by black coal or natural gas. The Australian government has participated in negotiations with governments of other countries with respect to greenhouse gas emission levels. As a result of the December 1997 Kyoto Climate Change Conference, the Australian government committed to limitations on greenhouse gas emissions. It is anticipated that the Australian government will introduce some measures to control greenhouse gas emissions. Such measures could increase capital expenditures at the Hazelwood Plant and could have the effect of making brown coal fired generators less competitive.

OTHER OPERATIONS

Financial Services

PFS is a holding company principally engaged in holding investments in tax advantaged and leveraged lease assets (primarily aircraft).

PFS made its last investment in aircraft or loans relating to aircraft in 1992. At March 31, 2000, 100% of the aircraft in PFS's portfolio investment were Stage III noise compliant. At March 31, 2000, PFS's aviation finance portfolio had total leveraged lease and other financial assets of $326 million (28 aircraft), representing approximately 76% of PFS's consolidated assets.

PFS has four plants in the Birmingham, Alabama area which produce a synthetic coal fuel designed to qualify for tax credits under Section 29 of the Internal Revenue Code. The technology utilized by the plants is licensed from Covol Technologies, Inc.

US Competitive Energy Businesses

The Klamath Cogeneration Project is a 484 MW natural gas-fired power plant under construction near Klamath Falls, Oregon. The City of Klamath Falls owns the plant and PPM is under contract for management, operations and fuel supply. In addition, upon commercial operation, PPM will purchase 227 MW of output from the plant for resale to third parties, and market on behalf of the City the remaining output to municipal and commercial buyers in the Pacific Northwest and northern California. The plant was financed in April 1999 with proceeds from revenue bonds issued by the City of Klamath Falls. Construction began in June 1999 and the plant has a planned commercial operation date of July 2001.

During October 1998, the Company decided to cease operations of its energy trading business in the eastern United States (see "DISCONTINUED OPERATIONS"). The Company amended its FERC tariff to allow PPM to engage in trading business in the western United States. Certain regulatory constraints, however, preclude this business from utilizing the Company's utility assets. The business may add assets in the western United States to support its marketing and trading activity.

International Operations

Beginning in October 1998, the Company decided to focus on its western United States electric business and to sell or shut down all international businesses and activities, subject to achieving reasonable economic and other terms. The process of exiting the international businesses is nearing completion.

DISCONTINUED OPERATIONS

The Company's discontinued energy trading business includes the eastern United States electricity trading operations of PPM and the natural gas marketing and storage operations of TPC. PPM's wholesale power trading activities in the eastern United States have been discontinued, and all forward energy trading has been closed. On April 1, 1999, Holdings sold TPC to NIPSCO Industries, Inc. for $150 million. Exiting these energy trading activities resulted in a net after-tax gain of $1 million in the first quarter of 2000.

EMPLOYEES

PacifiCorp and its subsidiaries had 8,832 employees on March 31, 2000. Of these employees, 7,681 were employed by PacifiCorp and its mining affiliates, 1,043 were employed by Powercor and 108 were employed by PPM, PFS and other subsidiaries.

As a result of the Merger, the Company has developed and commenced the Transition Plan to implement significant organizational and operational changes. As part of this Transition Plan, the Company expects to reduce its work force company-wide by approximately 1,600 over the next five years, mainly through early retirement, voluntary severance and attrition. For more information, see "ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - OVERVIEW OF 2000."

Approximately 55% of the employees of PacifiCorp and its mining affiliates are covered by union contracts, principally with the International Brotherhood of Electrical Workers, the Utility Workers Union of America and the United Mine Workers of America. Due to changes in Australian laws, information concerning union membership is no longer available to employers.

In the Company's judgment, employee relations are satisfactory.

ITEM 2. PROPERTIES

UNITED STATES

The Company owns 52 hydroelectric generating plants and has an interest in one additional plant, with an aggregate nameplate rating of 1,068 MW and plant net capability of 1,131 MW. It also owns or has interests in 17 thermal-electric generating plants with an aggregate nameplate rating of 7,231 MW and plant net capability of 6,666 MW. The Company also jointly owns one wind power generating plant with an aggregate nameplate rating of 33 MW and plant net

capability of 33 MW. The following table summarizes the Company's existing generating facilities:

	Location	Energy Source	Installation Dates	Nameplate Rating (MW)	Plant Net Capability (MW)
HYDROELECTRIC PLANTS Swift Merwin Yale Five North Umpqua Plants John C. Boyle Copco Nos. 1 and 2 Plants Clearwater Nos. 1 and 2 Plants Grace Prospect No. 2 Cutler Oneida Iron Gate Soda Fish Creek 33 Minor Hydroelectric Plants	Cougar, WA Ariel, WA Amboy, WA Toketee Falls, OR Keno, OR Hornbrook, CA Toketee Falls, OR Grace, ID Prospect, OR Collingston, UT Preston, ID Hornbrook, CA Soda Springs, ID Toketee Falls, OR Various	Lewis River Lewis River Lewis River N. Umpqua River Klamath River Klamath River Clearwater River Bear River Rogue River Bear River Bear River Klamath River Bear River Fish Creek Various	1958 1932-1958 1953 1949-1956 1958 1918-1925 1953 1914-1923 1928 1927 1915-1920 1962 1924 1952 1896-1990	240.0 135.0 134.0 133.5 80.0 47.0 41.0 33.0 32.0 30.0 30.0 18.0 14.0 11.0 89.2*	265.6 144.0 134.0 138.5 90.0 54.5 41.0 33.0 36.0 29.1 28.0 20.0 14.0 12.0 90.9*
Subtotal (53 Hydroelectric Plants)				1,067.7	1,130.6
THERMAL ELECTRIC PLANTS Jim Bridger Huntington Dave Johnston Naughton Hunter 1 and 2 Hunter 3 Cholla Unit 4 Wyodak Carbon Craig 1 and 2 Colstrip 3 and 4 Hayden 1 and 2 Blundell Gadsby Little Mountain Hermiston James River	Rock Springs, WY Huntington, UT Glenrock, WY Kemmerer, WY Castle Dale, UT Castle Dale, UT Joseph City, AZ Gillette, WY Castle Gate, UT Craig, CO Colstrip, MT Hayden, CO Milford, UT Salt Lake City, UT Ogden, UT Hermiston, OR Camas, WA	Coal-Fired Coal-Fired Coal-Fired Coal-Fired Coal-Fired Coal-Fired Coal-Fired Coal-Fired Coal-Fired Coal-Fired Coal-Fired Coal-Fired Geothermal Gas-Fired Gas-Fired Combined Cycle Black Liquor	1974-1979 1974-1977 1959-1972 1963-1971 1978-1980 1983 1981 1978 1954-1957 1979-1980 1984-1986 1965-1976 1984 1951-1955 1971 1996 1996	1,529.6* 996.0 816.7 707.2 727.9* 495.6 414.0 289.7* 188.6 172.1* 155.6* 81.3* 26.1 251.6 16.0 310.6* 52.2	1,406.7* 895.0 772.0 700.0 662.5* 460.0 380.0 268.0* 175.0 165.0* 144.0* 78.0* 23.0 235.0 14.0 236.0* 52.0
Subtotal (17 Thermal Electric Plants)				7,230.8	6,666.2
OTHER PLANTS Foote Creek Subtotal (1 Other Plant)	Arlington, WY	Wind Turbines	1998	32.6* 32.6	32.6* 32.6
Total Hydro, Thermal and Other Generating Facilities (71)				8,331.1	7,829.4

----------
*Jointly owned plants; amount shown represents the Company's share only.

NOTE: Hydroelectric project locations are stated by locality and river
watershed.

The Company's generating facilities are interconnected through its own transmission lines or by contract through the lines of others. Substantially all generating facilities and reservoirs located within the Pacific Northwest region are managed on a coordinated basis to obtain maximum load carrying capability and efficiency. Portions of the Company's transmission and distribution systems are located, by franchise or permit, upon public lands, roads and streets and, by easement or license, upon the lands of other third parties.

For a discussion of the sale of the Centralia plant and mine, see "Asset Sales."

Substantially all of the Company's electric utility plants are subject to the lien of the Company's Mortgage and Deed of Trust.

The following table describes the Company's recoverable coal reserves as of March 31, 2000, excluding the Centralia mine, which was subsequently sold. All coal reserves are dedicated to nearby Company operated generating plants. Recoverability by surface mining methods typically ranges between 90% and 95%. Recoverability by underground mining techniques ranges from 50% to 70%. The Company considers that the respective coal reserves assigned to the Craig, Dave Johnston, Huntington, Hunter and Jim Bridger plants, together with coal available under both long-term and short-term contracts with external suppliers, will be sufficient to provide these plants with fuel that meets the Clean Air Act standards effective in 1999, for their current economically useful lives. The sulfur content of the coal reserves ranges from 0.43% to 0.84% and the British Thermal Units value per pound of the reserves ranges from 7,600 to 11,400. Coal reserve estimates are subject to adjustment as a result of the development of additional data, new mining technology and changes in regulation and economic factors affecting the utilization of such reserves.

Location	Plant Served	Recoverable Tons (in Millions)
Craig, Colorado Glenrock, Wyoming Emery County, Utah Rock Springs, Wyoming	Craig Dave Johnston Huntington and Hunter Jim Bridger	51(2) 1(1)(5) 82(1)(3) 112(4)

____________

(1)  These coal reserves are mined by subsidiaries of the Company.
(2)  These coal reserves are leased and mined by Trapper Mining, Inc., a Delaware nonstock corporation operated on a cooperative basis, in which the Company has an ownership interest of approximately 20%.
(3)  These coal reserves are in underground mines and include the Mill Fork Track of 36 million tons.
(4)  These coal reserves are leased and mined by Bridger Coal Company, a joint venture between Pacific Minerals, Inc., a subsidiary of the Company, and a subsidiary of Idaho Power Company. Pacific Minerals, Inc. has a two-thirds interest in the joint venture.
(5)  The Company ceased mining operations at this location in October 1999.

Most of the Company's coal reserves are held pursuant to leases from the federal government through the Bureau of Land Management and from certain states and private parties. The leases generally have multi-year terms that may be renewed or extended and require payment of rentals and royalties. In addition, federal and state regulations require that comprehensive environmental protection and reclamation standards be met during the course of mining operations and upon completion of mining activities. In 2000, the Company expended $10.6 million of reclamation costs and accrued $4.9 million of estimated final mining reclamation costs. Final mine reclamation funds have

been established with respect to certain of the Company's mining properties. At March 31, 2000, the Company's pro rata portion of these reclamation funds totaled $67.0 million and the Company had an accrued reclamation liability of $138.7 million at March 31, 2000.

AUSTRALIA

Powercor's electrical distribution network, located in Victoria, Australia, comprises: (i) 66 kilovolts ("kV") and 22 kV subtransmission lines and underground subtransmission cables that transport wholesale energy from 12 terminal stations owned by GPU and controlled, under lease, by the Victoria Power Exchange; (ii) 53 zone substations that transform electricity to lower voltages (22 kV and below) and then distribute the energy through the distribution network; and (iii) 22 kV, 11 kV and 6.6 kV distribution lines, including distribution substations that transform electricity to low voltages (415 volts and below) suitable for connection to the majority of the customers. In addition, Powercor leases its principal executive offices at 40 Market St, Melbourne in Victoria under a four-year lease with an option to renew for another eight years.

The Hazelwood Plant has four stages, each with two 200 MW boiler and turbo generator units, and was constructed progressively between November 1964 and August 1971. The plant has eight units, all of which were in service at March 31, 2000. The Hazelwood Mine has between 400 million and 450 million recoverable tons of brown coal, which is expected to provide the Hazelwood Plant with sufficient quantities of coal. The Hazelwood Plant and Mine are anticipated to be sold along with Powercor. For a discussion of the proposed sale of Powercor, see "ITEM 1. BUSINESS - AUSTRALIAN ELECTRIC OPERATIONS - Powercor - General."

ITEM 3. LEGAL PROCEEDINGS

The Company and its subsidiaries are parties to various legal claims, actions and complaints, two of which are described below. Although it is impossible to predict with certainty whether or not the Company and its subsidiaries will ultimately be successful in its legal proceedings or, if not, what the impact might be, management believes that disposition of these matters will not have a material adverse effect on the Company's consolidated financial results.

On October 9, 1996, the Sierra Club filed an action against the Company and the other joint owners of Units 1 and 2 of the Craig Electric Generating Station (the "Station") under the citizen's suit provisions of the Federal Clean Air Act alleging, based upon reports from emissions monitors at the Station, that over 14,000 violations of state and federal opacity standards have occurred over a five-year period at Units 1 and 2 of the Station. (Sierra Club v. Tri-State Generation and Transmission Association, Inc., Public Service Company of Colorado, Inc., Salt River Project Agricultural Improvement and Power District, PacifiCorp and Platte River Power Authority, Civil Action No. 96-B2368, US District Court for the District of Colorado). The Company has a 19.28% interest in Units 1 and 2 of the Station, which is operated by Tri-State Generation and Transmission Association and located in Craig, Colorado.

The action seeks injunctive relief requiring the defendants to operate the Station in compliance with applicable statutes and regulations, the imposition of civil penalties, litigation costs, attorneys' fees and mitigation. The Federal Clean Air Act provides for penalties of up to $27,500 per day for each violation, but the level of penalties imposed in any particular instance is discretionary. The complaint alleges that the Company and Public Service Company of Colorado are responsible for the alleged violations beginning with the second quarter of 1992, when they acquired their interests in the Station, and that the other owners are responsible for the alleged violations during the entire period. The complaint alleges that there were approximately 10,000 violations since the second quarter of 1992. On March 18, 1999, the district court issued its order regarding summary judgment motions filed by the parties. The court ruled, among other things, that the emission monitors may be used by the plaintiff to establish violations of opacity standards, but that the plant owners are entitled to prove that the reported information is flawed.

Over the period from November 1997 to May 1998, Powercor entered into 11 electricity hedging contracts with a NSW State-owned generator (the "Generator") for the supply of electricity between 1998 and 2008. The contracts were designed to support the long-term supply of electricity by Powercor to its customers and to minimize Powercor's exposure to large fluctuations in the spot electricity price. When the wholesale market price for electricity moved against the Generator in May 1998, the Generator denied that any final and binding contracts had been entered into with Powercor, as both parties had not signed final versions of the confirmations setting out the terms and conditions of each transaction. However, an ISDA Master Agreement was in place between the parties which governed the negotiation, contracting and settlement process of individual contracts between them.

The Generator refused to honor the contracts and Powercor commenced proceedings against the Generator, claiming in the Supreme Court of Victoria that the contracts were valid and enforceable. (Powercor Australia Ltd. v. Pacific Power, Commercial List No. 4931, Case No. 2067 of 1998, Supreme Court of Victoria.) In December 1999, a ruling was issued in favor of Powercor. Specific performance was ordered of the 11 electricity hedge contracts, which were in dispute. Further, the following orders were made requiring payments by the Generator to Powercor: the Generator made payment of $29 million on December 17, 1999 attributable to the performance of the contracts from July 1, 1998 to judgment. This amount reflects the difference between actual payments and payments under the hedges plus interest of $1 million; and the Generator made payment of $2 million on December 24, 1999 as an agreed sum for legal expenses and other costs relating to the proceedings.

On December 21, 1999, the Generator appealed the judgments, declarations and orders on 80 grounds, including substantially all of the key aspects of the decision. The appeal is listed for hearing on October 2, 2000 for eight days.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

No information is required to be reported pursuant to this item.

PART II

ITEM 5.  MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
         MATTERS

PacifiCorp is a subsidiary of ScottishPower, which owns all 297,324,604 shares of PacifiCorp's outstanding common stock. Therefore, there is no public market for PacifiCorp's common stock. Dividend information required by this item is included under "Quarterly Financial Data" on page 111 of this Report.

The Company is restricted from paying dividends or making other distributions to ScottishPower without prior OPUC approval to the extent such payment or distribution would reduce the Company's common stock equity below a specified percentage of its total capitalization. The percentage of total capitalization is between 35% after December 31, 1999 to 40% after December 31, 2004. In addition, the Company must give the OPUC 30 days prior notice of any special cash dividend or any transfer involving more than five percent of PacifiCorp's retained earnings in a six-month period.

Under the Public Utility Holding Company Act of 1935, the Company may pay dividends out of capital or unearned surplus only with SEC approval. Dividends from earned surplus are permitted without approval.

ITEM 6.  SELECTED FINANCIAL DATA

The information required by this item is included under "Selected Financial Information" on page 106 of this Report.

ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
         RESULTS OF OPERATIONS

OVERVIEW OF 2000

During 2000, the Company began to see the results of its plan to focus on its electricity businesses in the western United States and reduce costs. In April 1999, the Company sold TPC for $150 million. In January 2000, the Company decided to seek a buyer for its Australian utility, Powercor. The Company will seek to sell Hazelwood along with Powercor.

On November 29, 1999, the Company and ScottishPower completed the Merger under which the Company became an indirect subsidiary of ScottishPower. The Company continues to operate under its current name, and its headquarters will remain in Portland, Oregon. As a result of the Merger, the Company became part of a public utility holding company group. The Company's operations are now subject to the requirements and restrictions of the Public Utility Holding Company Act of 1935.

In the Merger, each share of the Company's stock was converted tax-free into a right to receive 0.58 ADS (each ADS represents four ordinary shares) or 2.32 ordinary shares of ScottishPower. Cash was paid in lieu of fractional shares.

As a result of the Merger, the Company has developed and commenced its Transition Plan to implement significant organizational and operational changes. These changes are intended to lead to improved service to customers, continued strong investment in communities and enhanced value for shareholders. The Transition Plan is the outcome of an intense five-month review of the Company's business. More than 200 initiatives and changes have been proposed. By 2004, the initiatives are expected to deliver annual cost savings from 1998 levels of $300 million in operating expenses and $250 million in capital expenditures. The Company intends to invest approximately $150 million over the same period for training and new technology. The Company expects to reduce its work force company-wide by approximately 1,600 over the same five-year period, mainly through early retirement, voluntary severance and attrition. The cost of the early retirement offering will not be determinable until the end of June 2000, the deadline for election by eligible employees. The Company intends to seek regulatory orders to recover costs incurred under the Transition Plan.

A new management structure has been established, including key appointments from ScottishPower, the Company and also from well-known US companies.

Unless otherwise stated, references below to periods in 2000 are to periods in the fiscal year ended March 31, 2000, while references to periods in 1998 and 1997 are to periods in the years ended December 31, 1998 and 1997, respectively.

Australian Electric Operations' financial results for the year ended December 31, 1999 are included in PacifiCorp's financial results for the year ended March 31, 2000. For purposes of this discussion, these financial results are referred to as results for "2000".

Earnings Overview of the Company

Earnings (loss) on common stock For the year/Millions of dollars	March 31,	December 31,
	2000	1998	1997
Domestic Electric Operations Australian Electric Operations Other Operations Continuing Operations Discontinued Operations Extraordinary item Earnings (loss) on common stock	$ 10.9 39.0 13.8 63.7 1.1 - $ 64.8	$ 130.5 13.0 (52.2) 91.3 (146.7) - $ (55.4)	$ 165.5 54.2 (9.6) 210.1 446.8 (16.0) $ 640.9

In 2000 and 1998, the Company incurred a series of nonrecurring items, including ScottishPower merger costs, special charges, discontinued operations of certain businesses and acquisition transaction costs. The table below sets forth the effects of these items to assist the reader.

Effects of nonrecurring items on earnings:

For the year/Millions of dollars	March 31, 2000	December 31, 1998
Earnings (loss) on common stock - as reported Remove Discontinued Operations Loss of discontinued operations Provision for losses of discontinued operations Gain on sale of discontinued operations Earnings from Continuing Operations Adjustments - Domestic Electric Operations Special charges ScottishPower merger costs Write off of projects under construction Adjustments - Australian Electric Operations Write down of Hazelwood Adjustments - Other Operations ScottishPower merger costs TEG costs and option losses Gain on sale of TEG shares Write down of other energy businesses Earnings - Excluding nonrecurring items	$ 64.8 - - (1.1) 63.7 - 177.1 14.5 - 3.1 - - - $258.4	$(55.4) 41.7 105.0 - 91.3 76.5 13.2 - 17.4 - 55.4 (9.8) 32.4 $276.4^(a)

(a) In 1998, the Company reported earnings excluding nonrecurring items of $300 million. Included in the calculation of $300 million were Utah rate order adjustments similar to those recorded in 2000 operations. Accordingly, those adjustments are not shown above as nonrecurring.

Earnings on common stock for the Company increased $120 million in 2000 compared to 1998. The Company's 2000 earnings of $65 million reflected $180 million for ScottishPower merger costs and $15 million relating to write-offs of projects under construction.

The Company's 1998 loss of $55 million included special charges of $77 million relating to the Company's early retirement program announced in January 1998 and the additional early retirement offer announced in the fourth quarter of 1998, $13 million for ScottishPower merger costs, $55 million relating to the write off of costs associated with The Energy Group PLC ("TEG") transaction and the closing of foreign currency options in April 1998 associated with the terminated bid for TEG and a $10 million gain on sale of TEG shares. In addition, the Company recorded charges in 1998 of $155 million, which included $105 million relating to the provision for losses on disposition of TPC and the eastern U.S. energy trading segment, $17 million relating to the write down of the Company's investment in Hazelwood, and $32 million relating to the provision for losses on disposition of other energy development businesses.

Excluding these nonrecurring items, the Company's 2000 earnings on common stock from continuing operations would have been $258 million compared to $276 million in 1998, a decrease of $18 million.

The following table shows where ScottishPower merger costs have been recorded in the Company's financial results.

ScottishPower Merger Costs For the year/Millions of dollars	March 31, 2000	December 31, 1998	March 31, 2000	December 31, 1998
	Pretax		After-tax
Included in Domestic Electric operating expenses Employee related expenses (severance, retention, etc.) Legal fees, contracted services and other expenses Total merger costs included in operating expenses	$ 12.7 3.3 16.0	$ - - -	$ 7.9 2.0 9.9	$ - - -
Included within ScottishPower merger costs - Domestic Electric Employee related expenses (severance, retention, etc.) Merger credits Stamp tax Banking fees Legal fees, contracted services and other expenses Total included within ScottishPower merger costs - Domestic Electric	23.7 57.2 77.8 19.4 12.4 190.5	0.5 - - 6.2 6.5 13.2	22.1 35.5 77.8 19.4 12.4 167.2	0.5 - - 6.2 6.5 13.2
Included within ScottishPower merger costs - Other Operations	5.0	-	3.1	-
Total included within ScottishPower merger costs	195.5	13.2	170.3	13.2
Total ScottishPower merger costs	$211.5	$ 13.2	$180.2	$ 13.2

Domestic Electric Operations' contribution to earnings on common stock was $11 million in 2000. After adjusting earnings by $192 million for ScottishPower merger costs and a write-off of projects under construction, the contribution was $203 million. Domestic Electric Operations' contribution to earnings on common stock in 1998 was $131 million. After adjusting earnings by $90 million for special charges and other adjustments, the contribution was $221 million. The $18 million decrease from 1998 earnings was the result of several factors, including lower wholesale margins in the western United States.

Australian Electric Operations' contribution to earnings was $39 million in 2000. After adjusting earnings by $1 million for currency exchange rate fluctuations, the contribution was $38 million. The currency exchange rate for converting Australian dollars to United States dollars averaged 0.65 in 2000 compared to 0.63 in 1998, a 3% increase. The 2000 earnings were impacted by increased network revenues due to the effects of contestability. The 1998 earnings of $13 million included the impact of the $17 million write down of the Company's investment in the Hazelwood Power Station.

Other Operations reported net income of $14 million in 2000 as compared to a loss of $52 million in 1998. The 2000 results included $3 million in expenses relating to ScottishPower merger costs, as well as a decrease in interest income of $31 million. An income increase at PFS's synthetic fuel producing businesses in 2000 totaled $13 million. After-tax losses associated with exiting energy development businesses were approximately $7 million in 2000 and $19 million in 1998. The 1998 results included $32 million in losses relating to the decision to exit the energy development businesses, $55 million in costs associated with the Company's terminated bid for TEG and closing foreign currency options in April 1998, and a gain of $10 million relating to the sale of TEG shares.

Discontinued Operations reported a net after-tax gain on exiting discontinued operations of $1 million in 2000 compared to losses in 1998 of $147 million. The 1998 results included $105 million for the losses anticipated to dispose of TPC and exit the eastern United States energy trading business and a loss of $42 million relating to these operations prior to discontinuance.

FORWARD-LOOKING STATEMENTS

The information in the tables and text in this document includes certain forward-looking statements that involve a number of risks and uncertainties that may influence the financial performance and earnings of the Company. When used in this "Management's Discussion and Analysis of Financial Condition and Results of Operations," the words "estimates," "expects," "anticipates," "forecasts," "plans," "intends" and variations of such words and similar expressions are intended to identify forward-looking statements that involve risks and uncertainties. There can be no assurance the results predicted will be realized. Actual results will vary from those represented by the forecasts, and those variations may be material.

The following are among the factors that could cause actual results to differ materially from the forward-looking statements: utility commission practices; regional, national and international economic conditions; weather variations affecting customer usage; competition and prices in electric power and natural gas markets and hydroelectric and natural gas production; hydro-facility relicensing; energy trading activities; environmental, regulatory and tax legislation, including industry restructure and deregulation initiatives; technological developments in the electricity industry; foreign exchange rates; proposed asset dispositions; and the cost of debt and equity capital. Any forward-looking statements issued by the Company should be considered in light of these factors.

DOMESTIC ELECTRIC OPERATIONS

REVENUES

Revenues For the year/Millions of dollars	March 31,	December 31,
Revenues For the year/Millions of dollars	2000	1998	1997
Wholesale sales and market trading Residential Industrial Commercial Other	$1,029.1 798.7 694.5 667.2 102.7 $3,292.2	$2,583.6 806.6 705.5 653.5 95.9 $4,845.1	$1,428.0 814.0 709.9 640.9 114.1 $3,706.9

Energy Sales For the year/Millions of kWh	March 31,	December 31,
Energy Sales For the year/Millions of kWh	2000	1998	1997
Wholesale sales and market trading Residential Industrial Commercial Other	34,327 13,028 20,488 12,827 663 81,333	94,077 12,969 20,966 12,299 651 140,962	59,143 12,902 20,674 11,868 705 105,292

Total Domestic Electric Operations' revenues decreased $1.55 billion, or 32%, from 1998 to $3.29 billion in 2000 primarily due to a decrease in wholesale revenues of $1.55 billion. Retail revenues were flat compared to 1998, remaining at $2.20 billion.

Wholesale revenues decreased $1.55 billion, or 60%. The decrease in revenues was driven by a 64% decline in energy volumes. Short-term firm and spot market sales volumes decreased 75%, creating a $1.56 billion decrease in revenues. Sales prices for short-term firm and spot market sales averaged $27 per megawatt hour ("MWh") in 2000 compared to $26 per MWh in 1998, resulting in $24 million in additional revenues. Decreased long-term firm contract prices lowered wholesale revenues by $19 million in 2000. The decline in energy volumes is consistent with the Company's decision to scale back short-term wholesale sales.

Short-Term Firm and Spot Market Sales

For the year	March 31,	December 31,
For the year	2000	1998	1997
Total sales volume (thousands of MWh) Average sales price ($/MWh) Revenues (millions)	19,768 $ 27.11 $ 536	80,097 $ 25.88 $ 2,073	44,927 $ 20.35 $ 914

Residential revenues were down $8 million, or 1%. Excluding the impact of the sale of the Company's distribution assets in Montana in 1998, residential revenues were up $5 million, energy volumes were up 2% and customer growth was 3%. Growth in the average number of residential customers added $20 million to revenues. Price increases in Oregon added $6 million to revenues in 2000. A

rate order issued by the Utah Commission in 1998 decreased residential revenues by $36 million in 2000. This decrease was partially offset by the one-time Utah rate order refund that reduced revenues by $16 million in 1998.

Industrial revenues were down $11 million, or 2%. Excluding the impact of the Montana sale, industrial revenues were down $2 million, energy volumes were down 1% and average number of customers declined 2%. The Company participated in open access pilot programs in Oregon, which ended in 1998, that reduced revenues $10 million in 2000. Increased irrigation usage added $5 million to industrial revenues in 2000. The Utah rate order decreased industrial revenues by $17 million in 2000. This decrease was offset by the one-time Utah rate order refund that reduced revenues in 1998 by $8 million and other changes in the average price for electricity, which added $10 million in 2000.

Commercial revenues were up $14 million, or 2%. Excluding the impact of the Montana sale, commercial revenues were up $24 million, energy volumes were up 6% and customer growth was 3%. Growth in the average number of commercial customers added $24 million to revenues and volume increases added $16 million to revenues. The Utah rate order decreased commercial revenues by $33 million in 2000. This decrease was partially offset by the one-time Utah rate order refund that reduced revenues in 1998 by $13 million and other changes in the average price for electricity, which added $6 million in 2000.

Other revenues increased by $7 million, or 7%. The primary cause of this favorable variance was an $11 million increase in wheeling revenues resulting from new contracts for transmitting electricity for other companies across the Company's system and increased volume under existing wheeling contracts.

1998 compared to 1997 - Revenues rose 31%, or $1.14 billion, in 1998 primarily due to increased wholesale energy volumes and sales prices. A 59% increase in wholesale energy volumes sold increased wholesale revenues by $917 million and higher sales prices in short-term firm and spot market sales increased wholesale revenues by $242 million. Residential revenues decreased $7 million primarily due to the Utah rate order and decreased customer usage, partially offset by customer growth. Commercial revenues increased $13 million primarily due to customer growth and increased customer usage, partially offset by the effect of the Utah rate order. Other revenues decreased $18 million primarily due to revenue adjustments relating to changes in property tax legislation.

OPERATING EXPENSES

For the year/Millions of dollars	March 31,	December 31,
For the year/Millions of dollars	2000	1998	1997
Purchased power Fuel Other operations and maintenance Depreciation and amortization Administrative, general and taxes-other Special charges	$ 957.9 484.8 556.3 406.0 299.4 - $2,704.4	$2,497.0 477.6 457.3 386.6 331.4 123.4 $4,273.3	$1,296.5 454.2 470.0 389.1 325.4 170.4 $3,105.6

Operating expenses decreased $1.57 billion, or 37%, to $2.70 billion in 2000, primarily as a result of a $1.54 billion decrease in purchased power costs.

In addition to base energy and capacity from its thermal and hydroelectric resources, the Company utilizes a mix of long-term, short-term and nonfirm power purchases to meet its own retail load commitments and to make wholesale power sales to other utilities. Purchased power expense decreased $1.54 billion, or 62%, to $958 million in 2000. The lower expense was primarily due to a 61 million MWh decrease in short-term firm and spot market energy purchases, a 77% decrease from 1998, which decreased purchased power expense by $1.58 billion. Short-term firm and spot market purchase prices averaged $28 per MWh in 2000 versus $26 per MWh in 1998, a 9% increase. The increase in purchase prices added $42 million to costs in 2000. The reduced level of power purchases in 2000 is consistent with the Company's decision to scale back short-term wholesale sales.

Short-Term Firm and Spot Market Purchases

For the year	March 31,	December 31,
For the year	2000	1998	1997
Total purchase volume (thousands of MWh) Average purchase price ($/MWh) Expenses (millions)	18,713 $ 28.13 $ 526	79,693 $ 25.88 $ 2,062	45,772 $ 19.04 $ 871

Fuel expense was up $7 million, or 2%, to $485 million in 2000. Thermal generation increased 1% to 52.4 million MWh. Increased expense from the higher generation was partially offset by lower cost per MWh. The average cost per MWh decreased to $9.25 from $9.37 in 1998 due to improved operating efficiencies at Company-operated mines. Hydroelectric generation remained flat compared to 1998.

Other operations and maintenance expense increased $99 million, or 22%, to $556 million in 2000. In 2000, the Company completed an analysis of construction projects and determined to abandon a number of early stage projects. Write-offs of these assets were $23 million pretax. Increased tree trimming added $6 million to expenses, increased materials and contracts primarily relating to steam plant overhaul costs added $11 million, increased employee costs added $9 million and write-offs of obsolete inventory added $4 million. An increasing amount of work relating to expense rather than

capital projects resulted in $14 million of additional transmission and distribution expenses. Customer accounting, service and sales expenses increased $8 million due to increased collection activity. Employee costs resulting from higher than normal employee turnover added $2 million to expenses. Costs related to the Foote Creek wind turbines, placed in service at the end of 1998, also added $2 million to expenses. In addition, operations and maintenance was up $15 million due to costs reclassified from administrative and general upon conversion to the SAP software operating environment.

Depreciation and amortization expense increased $19 million, or 5%, to $406 million primarily due to increased plant in service and increased depreciation on the new SAP software system.

Administrative, general and taxes - other expenses decreased $32 million, or 10%, to $299 million. This decrease included $15 million of costs reclassified to operations and maintenance expense upon conversion to SAP. In addition, pension costs decreased $4 million in 2000 due to favorable returns on plan assets. Costs of converting to SAP decreased $4 million, other consulting services also decreased $9 million and Year 2000 conversion costs decreased $3 million. Increased employee costs relating to the Merger of $14 million were completely offset by decreased labor and other employee expenses.

Special charges recorded in 1998 were the costs of early retirement and cost reduction programs implemented in the first and fourth quarters of 1998. The net work force reduction was approximately 930 positions and the Company recorded $77 million of after-tax charges in 1998 relating to the programs.

1998 compared to 1997 - Operating expenses increased $1.17 billion in 1998 due to higher purchased power volumes and prices. Short-term firm and spot market energy purchases increased 33.9 million MWh, a 74% increase from 1997, which increased purchased power expense by $937 million. Short-term firm and spot market purchase prices were, on average, 36% higher in 1998, which added $255 million to purchased power costs. Special charges decreased $47 million in 1998. Special charges in 1998 consisted of the costs of an early retirement and cost reduction program. Special charges in 1997 included the Glenrock mine closure costs of $64 million, the write-off of deferred regulatory pension costs of $87 million, and impairment charges on information system assets of $19 million.

OTHER INCOME AND EXPENSE

Interest expense was $51 million lower primarily due to the dividends received from Holdings that were used to pay down intercompany debt owed to Holdings and some external debt. ScottishPower merger costs were $177 million higher primarily due to taxes paid for stock transfers to complete the Merger and the merger credits ordered in various states. Other income increased $7 million primarily due to decreased new product expense and a settlement received from the federal government for loss of coal rights upon creation of a new national park in Utah. Income tax expense was $125 million, an increase of $22 million, primarily due to an increase in nondeductible merger transaction costs, partially offset by the decline in taxable income. See Note 15 of Notes to the Consolidated Financial Statements under ITEM 8.

1998 compared to 1997 - Other expenses increased $20 million in 1998, which included $13 million of ScottishPower merger costs and $6 million of higher minority interest expense relating to the issuance of quarterly income preferred securities in August 1997. Income tax expense decreased $9 million due to the decline in pretax income.

INDUSTRY CHANGE, COMPETITION AND DEREGULATION

Industry Change - The electric power industry continues to experience change. The key driver for this change is public, regulatory and governmental support for replacing the traditional cost-of-service regulatory framework with an open market competitive framework where the customers have a choice of energy supplier. The pace at which this change will occur has slowed as regulators and legislators struggle with conversion and implementation issues. However, federal laws and regulations have been amended to provide for open access to transmission systems, and various states have adopted or are considering new regulations to allow open access for all energy suppliers. For additional information concerning the regulatory, competitive and environmental issues facing the Company, see "ITEM 1. BUSINESS - DOMESTIC ELECTRIC OPERATIONS - Regulation," "- Competition" and "- Environmental Issues."

AUSTRALIAN ELECTRIC OPERATIONS

Powercor's principal businesses are to sell electricity to franchise and contestable customers inside and outside its franchise area and to provide electricity distribution services to customers within its regulated network distribution service area. Franchise customers are those customers that cannot yet choose an electricity supplier, while contestable customers have the opportunity to choose suppliers. Powercor purchases all of its electricity supply from a national electricity market.

Victoria and NSW are currently divided between franchise and contestable customers. Customers in both states with annual consumption of more than 160 MWh are now contestable. Customers with usage of 160 MWh per year or less will become contestable on January 1, 2001 in Victoria, the ACT and NSW. If a Powercor customer chooses a different retailer, Powercor will continue to receive network distribution revenues associated with that customer. Powercor was granted licenses to sell electricity to customers in the States of Queensland and ACT in early 1998.

Australian Electric Operations' financial results for the year ended December 31, 1999 are included in PacifiCorp's financial results for the year ended March 31, 2000. For purposes of this discussion, these financial results are referred to as "2000" results.

In 2000, Australian Electric Operations contributed earnings of $39 million compared to $13 million in 1998. Operating expense reductions increased the contribution to earnings, however, lower market prices resulting from an increasing level of deregulation, partially offset by lower purchased power expense, caused margins on energy sold to decline. Also, in 1998, Australian Electric Operations recorded a $17 million loss on the write down of its investment in Hazelwood to estimated net realizable value less selling costs.

Currency Risks - Australian Electric Operations' results of operations and financial position are translated from Australian dollars into United States dollars for consolidation into the Company's financial statements. Changes in the prevailing exchange rate may have a material effect on the Company's consolidated financial statements. The average currency exchange rate for converting Australian dollars to United States dollars was 0.65 in 2000 compared to 0.63 in 1998, a 3% increase for the year. The effect of the exchange rate fluctuation was an increase of $1 million in net income in 2000. The currency exchange rate at May 31, 2000 was 0.58. The following discussion excludes the effects of the higher currency exchange rate in 2000.

REVENUES

Revenues Millions of dollars	2000	1998	Change Due to Currency	Operating Variance
Powercor area Outside Powercor area Victoria New South Wales Australian Capital Territory Queensland Total Outside Powercor area Other revenue	$429.9 74.6 76.4 1.5 2.5 155.0 32.7 $617.6	$437.8 79.1 71.6 0.6 0.3 151.6 25.1 $614.5	$ 11.3 2.0 2.0 - 0.1 4.1 0.9 $ 16.3	$(19.2) (6.5) 2.8 0.9 2.1 (0.7) 6.7 $(13.2)

Energy Sales Millions of kWh	2000	1998	1997
Powercor area Outside Powercor area Victoria New South Wales Australian Capital Territory Queensland	6,855 2,293 2,271 35 62 11,516	7,233 2,396 2,241 12 6 11,888	7,410 2,262 1,372 - - 11,044

Australia reported 2000 revenues of $618 million, a $13 million, or 2%, decrease from 1998. The decrease was primarily attributable to a reduction in energy sales volumes of 372 million kWh, or 3%.

Inside Powercor's franchise area, revenues declined $19 million, $17 million due to a 378 million kWh decrease in volumes and $2 million due to price decreases for customers.

Energy volumes sold to contestable customers outside Powercor's franchise area were up 6 million kWh in 2000. This increase was primarily due to customer gains in Queensland, the ACT and NSW. The revenue increase resulting from the additional energy volumes sold was offset by lower rates, primarily in Victoria.

Other revenues increased $7 million in 2000 primarily due to recognition of a sales tax contract settlement payment received from the Australian Government of $4 million, and $4 million from construction projects for customers who own their own distribution assets, as well as refunds received with the dissolution of the Victoria Power Exchange of $2 million. These increases were offset due to $4 million for Tariff H revenue recognition in 1998.

1998 compared to 1997

Millions of dollars	1998	1997	Change Due to Currency	Operating Variance
Powercor area Outside Powercor area Victoria New South Wales Australian Capital Territory Queensland Total Outside Powercor area Other revenue	$437.8 79.1 71.6 0.6 0.3 151.6 25.1 $614.5	$538.6 98.7 46.0 - - 144.7 32.9 $716.2	$ (80.0) (14.5) (13.1) - - (27.6) (4.6) $(112.2)	$(20.8) (5.1) 38.7 0.6 0.3 34.5 (3.2) $ 10.5

Revenues increased $11 million, or 1%, in 1998 primarily due to an 8% increase in energy sales volumes. Increased market share in the contestable market in Victoria and NSW added $7 million and $39 million, respectively. Lower prices for contestable sales reduced revenues by $12 million. Revenues within Powercor's franchise area decreased $13 million due to lower average realized prices and $8 million due to a 177 million kWh decrease in volumes.

OPERATING EXPENSES

Millions of dollars	2000	1998	Change Due to Currency	Operating Variance
Purchased power Other operations and maintenance Depreciation and amortization Administrative, general and taxes - other	$260.0 104.3 57.9 70.3 $492.5	$255.0 140.1 58.2 46.7 $500.0	$ 6.8 2.7 1.5 1.8 $ 12.8	$ (1.8) (38.5) (1.8) 21.8 $(20.3)

Purchased power expense decreased $2 million, or 1%, in 2000. A favorable court ruling received on a contract dispute resulted in decreased expense of $24 million. A 6% decrease in purchased power volumes reduced costs by $16 million. These decreases were partially offset by increases of $11 million in payments to counterparties due to recalculation of contract fees and $24 million of increases in purchased power costs.

The power supplier in the contract dispute noted above did not meet its contractual obligation to deliver power to Powercor at the agreed upon rate, which forced Powercor to purchase power on the open market at a higher rate. On November 17, 1999, the Supreme Court of Victoria upheld the validity of these contracts and on December 14, 1999 ordered specific performance on the remaining contracts and payment of $29 million for failure to perform in the past. On December 21, 1999, the power supplier filed a notice of appeal seeking to overturn all of the judgments against it. The Company expects the decision to be upheld. See "ITEM 3. LEGAL PROCEEDINGS."

Other operations and maintenance expense decreased $39 million, or 27%, in 2000. The decrease in expense is related to an increase in external network revenue, accounted for on a net basis against other network costs, of $18 million relating to customers within Powercor's distribution area being supplied electricity by competitors, a decrease in external network fees of $11 million, a $9 million decrease due to reclassifying expenses to administrative and general, and a $1 million decrease in maintenance expense because of mild weather.

Administrative, general and taxes - other increased $22 million, or 47%, in 2000. An increase of $9 million was attributable to a reclassification of construction services expenses, for services provided to other companies, from other operations and maintenance. Restructuring costs increased $4 million over 1998. A project to help transition to full retail contestability increased expenses by $3 million, salaries and incentives increased $4 million, and legal fees due to the power supply contract dispute increased $1 million.

Interest expense decreased $1 million in 2000 to $58 million as a result of lower debt balances. Other expense decreased $30 million primarily due to the 1998 pretax write down of $28 million that reduced the carrying value of the Company's investment in the Hazelwood Power Station to its estimated net

realizable value less selling costs and $5 million in costs for removal of certain energy efficiency devices in connection with a product recall. Equity losses in Hazelwood were $3 million, a decrease of $3 million over 1998, primarily due to decreased maintenance costs. Income tax expense increased $16 million due primarily to an increase in taxable income.

1998 compared to 1997

Millions of dollars	1998	1997	Change Due to Currency	Operating Variance
Purchased power Other operations and maintenance Depreciation and amortization Administrative general and taxes - other	$255.0 140.1 58.2 46.7 $500.0	$308.5 134.0 67.1 56.1 $565.7	$(46.6) (25.6) (10.6) (8.6) $(91.4)	$(6.9) 31.7 1.7 (0.8) $25.7

Operating expenses increased $26 million, or 5%, in 1998. Increased sales to contestable customers outside Powercor's franchise area resulted in increased purchased power expense of $28 million and higher network fees of $40 million, which were partially offset by decreased purchased power prices of $35 million, and higher network revenues of $12 million from customers inside Powercor's franchise area that were serviced by other energy suppliers.

REGULATION

For additional information concerning the regulatory and environmental issues facing the Australian Electric Operations, see "ITEM 1. BUSINESS - AUSTRALIAN ELECTRIC OPERATIONS - Regulation" and "- Environmental Issues."

OTHER OPERATIONS

Earnings Contribution For the year/Millions of dollars	March 31,	December 31,
Earnings Contribution For the year/Millions of dollars	2000	1998	1997
PFS PGC Holdings and other: Write down of other energy businesses TEG costs and option losses Gain on sale of PGC Other	$ 15.5 - - - - (1.7) $ 13.8	$ 8.1 - (32.4) (45.6) - 17.7 $(52.2)	$ 30.2 10.4 - (64.5) 30.0 (15.7) $ (9.6)

During 2000, Other Operations included the activities of Holdings, PFS and energy development businesses. Other operations reported earnings of $14 million in 2000 compared to a loss of $52 million in 1998. The 2000 results include ScottishPower merger costs of $3 million. Interest income decreased $31 million as the result of cash dividends paid by Holdings to Domestic Electric in January 1999 and October 1998. This cash had been invested by Holdings in interest bearing instruments prior to payment of the dividends. Income at PFS's synthetic fuel producing businesses increased $13 million. The 1998 results included losses relating to the decision to shut down or sell the Company's other energy development businesses totaling $32 million. After-tax losses associated with exiting these businesses were approximately $7 million in 2000. In 1998, these businesses incurred $19 million of after-tax losses. In addition, 1998 included $55 million in costs associated with the Company's terminated bid for TEG and closing foreign currency options in April 1998 associated with the terminated bid for TEG, and a gain of $10 million relating to the sale of TEG shares.

PFS has tax-advantaged investments in leasing operations that consist principally of aircraft leases. For 2000, PFS reported net income of $16 million, a $7 million increase from 1998. This increase was primarily attributable to increased tax credits received on the sales of synthetic coal, which was offset by a decrease as a result of the sale of its affordable housing properties in 1998. PFS sold its investments in affordable housing in 1998 for $80 million, which approximated book value.

The energy development businesses that the Company decided to exit in 1998 are generally wholly owned subsidiaries of the Company or subsidiaries in which the Company has a majority ownership. The pretax loss associated with exiting the energy development businesses was $52 million in 1998 and was included in "Write down of investments in energy development businesses" on the income statement. The remaining values for these businesses were arrived at using cash flow projections and estimated market value for fixed assets. Some of these businesses have been exited through the discontinuance of their operations while others are being held for sale. The process of exiting these businesses is nearing completion.

1998 compared to 1997 - The $43 million decrease in earnings contribution of Other Operations in 1998 was primarily attributable to a loss of $32 million relating to the decision to shut down or sell the Company's energy development businesses. A loss of $54 million was associated with the Company's terminated bid for TEG, as well as $2 million relating to closing foreign exchange positions associated with the terminated bid. This loss was partially offset by a gain of $10 million relating to the sale of TEG shares.

Results from Other Operations in 1998 benefited from a $40 million after-tax increase in interest income and reduced interest expense as the result of cash received from 1997 asset sales.

In 1997, the Company completed the sale of its independent power subsidiary, Pacific Generation Company ("PGC"), for approximately $150 million in cash, resulting in a gain of $30 million. PGC contributed income of $10 million in 1997 prior to completion of the sale.

DISCONTINUED OPERATIONS

Discontinued operations reported earnings in 2000 of $1 million compared to losses of $147 million in 1998. The 1998 results included $105 million for the loss anticipated to exit the eastern United States energy trading business and a loss of $42 million for operating losses prior to the decision to exit. On April 1, 1999, Holdings sold TPC for $150 million. Exiting these energy trading activities resulted in a net after-tax gain of $1 million in 2000.

In 1998, the pretax loss associated with exiting the eastern United States energy trading business was $155 million. This loss consisted of write downs of intangible assets of $83 million and the costs to exit a portion of the business and sell another portion of the business of $72 million. The exiting costs included anticipated severance payments and operating costs to the selling date and selling expenses. The remaining values for these businesses represented the estimated market value of the fixed assets of the companies and the remaining working capital at the expected sale date.

LIQUIDITY AND CAPITAL RESOURCES

OPERATING ACTIVITIES

Cash flows from continuing operations increased $98 million from 1998 to 2000. This increase was largely due to cash expenditures in 1998 relating to taxes on 1998 and 1997 asset sales.

INVESTING ACTIVITIES

Investing in 2000 focused on continued capital spending to improve and expand existing operations. In addition, the Company disposed of non-strategic assets such as TPC in 2000 and the Montana electric distribution assets and the majority of the tax-advantaged investments in affordable housing owned by PFS in 1998.

On May 4, 2000, the utility partners who own the 1,340 MW coal-fired Centralia Power Plant sold the plant and the adjacent coal mine owned by the Company to TransAlta for approximately $500 million. For additional information concerning the sale of the Centralia plant and mine, see "ITEM 1. BUSINESS - DOMESTIC ELECTRIC OPERATIONS - Asset Sales."

On October 23, 1998, the Company announced its intent to exit its energy trading business in the eastern United States and its other energy development businesses. As a result, the Company recorded an after-tax loss of $137 million for these businesses. In addition, the Company recorded an after-tax loss of $17 million to reduce the Company's carrying value in the Hazelwood Power Station to its net realizable value less selling costs. On April 1, 1999, Holdings sold TPC for $150 million. Exiting these energy trading activities resulted in a net after-tax gain of $1 million in the first quarter of 2000. On July 9, 1998, the Company announced its intention to sell its California and Montana electric distribution assets. On November 5, 1998, the Company sold its Montana electric distribution assets to Flathead Electric Cooperative, Inc. and received proceeds of $89 million, net of taxes and customer refunds. The Company returned $4 million of the $8 million gain on the sale to Montana customers as negotiated with the Montana Public Service Commission and the Montana Consumer Counsel. For additional information on the sale of the California electric distribution assets, see "ITEM 1. BUSINESS - DOMESTIC ELECTRIC OPERATIONS - Proposed Asset Additions and Dispositions."

In October 1998, Holdings paid a dividend of $500 million to Domestic Electric. Domestic Electric used the proceeds to pay down intercompany debt owed to Holdings. In January 1999, Holdings paid a dividend of $660 million to Domestic Electric. Domestic Electric used the proceeds to pay down short-term debt and intercompany debt and temporarily invested the remainder in money market funds. In March 2000, Holdings paid a dividend of $49 million to Domestic Electric. Domestic Electric used the proceeds to pay down short-term debt and temporarily invested the remainder in money market funds.

The Company believes that its existing and available capital resources are sufficient to meet working capital, dividend and construction needs in 2001.

BID FOR THE ENERGY GROUP

During 1997 and 1998, the Company sought to acquire TEG, a diversified international energy group with operations in the United Kingdom, the United States and Australia. In March 1998, another United States utility made a tender offer at a price higher than the Company's offer and on April 30, 1998, the Company announced that it would not increase its revised offer for TEG.

The Company recorded an $89 million pretax charge ($55 million after-tax) to 1998 earnings, included in "TEG costs and option losses," for bank commitment and facility fees, foreign currency option contract expense, legal expenses and other related costs incurred since the Company's original bid for TEG in June of 1997. These costs had been deferred pending the outcome of the transaction.

Additionally, in connection with the attempt to acquire TEG, a subsidiary of the Company purchased approximately 46 million shares of TEG at a price of 820 pence per share, or $625 million. The Company recorded a pretax gain on the TEG shares of $16 million ($10 million after-tax) when they were sold on June 2, 1998.

Upon initiation of the original tender offer in June 1997, the Company also entered into foreign currency exchange contracts. The financing facilities associated with the June 1997 offer for TEG terminated upon referral to the Monopolies and Mergers Commission and the Company initiated steps to unwind its foreign currency exchange positions consistent with its policies on derivatives. As a result of the termination of these positions and initial option costs, the Company realized a pretax loss of approximately $106 million ($65 million after-tax) in the third quarter of 1997.

CAPITALIZATION

Millions of dollars (except percentages)	March 31, 2000		December 31, 1998
Long-term debt Common equity Short-term debt Preferred stock Preferred securities of Trusts Junior subordinated debentures Total Capitalization	$4,046 3,880 296 216 341 176 $8,955	45% 43 3 3 4 2 100%	$4,383 3,957 560 241 341 176 $9,658	45% 41 6 2 4 2 100%

The Company manages its capitalization and liquidity position in a consolidated manner through policies established by senior management and the Board of Directors. These policies, subject to periodic review and revision, have resulted from a review of historical and projected practices for businesses and industries that have financial and operating characteristics similar to the Company and its principal business operations.

The Company's policies attempt to balance the interests of all shareholders, ratepayers and creditors. In addition, given the changes that are occurring within the industry and market segments in which the Company operates, these policies are intended to remain sufficiently flexible to allow the Company to respond to these developments.

On a consolidated basis, the Company attempts to maintain total debt at 48% to 54% of capitalization. The debt to capitalization ratio was 48% at March 31, 2000. The Company also attempts to maintain a preferred stock ratio, including subordinated debt, at 8% to 12% of capitalization. The preferred stock ratio was 8% at March 31, 2000. The Company has made commitments in connection with the Merger not to reduce common equity, without approval, to below 35% of total capitalization, increasing over time to 40%.

VARIABLE RATE LIABILITIES

Millions of dollars	March 31, 2000	December 31, 1998
Domestic Electric Operations Australian Electric Operations Holdings and other Percentage of Total Capitalization	$ 764 258 - $1,022 11%	$ 830 278 12 $1,120 12%

The Company's capitalization policy targets consolidated variable rate liabilities at between 10% and 25% of total capitalization.

AVAILABLE CREDIT FACILITIES

At March 31, 2000, PacifiCorp had $800 million of committed bank revolving credit agreements. Regulatory authorities limit PacifiCorp to $1.5 billion of short-term debt, of which $109 million was outstanding at March 31, 2000. At March 31, 2000, subsidiaries of PacifiCorp had $723 million of committed bank revolving credit agreements. The Company had $429 million of short-term debt classified as long-term debt at March 31, 2000, as it had the intent and ability to support such short-term borrowings through the various revolving credit facilities on a long-term basis. See Notes 7 and 8 of Notes to Consolidated Financial Statements for additional information under ITEM 8.

LIMITATIONS

In addition to the Company's capital structure policies, its debt capacity is also governed by its contractual commitments. PacifiCorp's principal debt limitation is a 60% debt to defined capitalization test contained in its principal credit agreements. Based on the Company's most restrictive agreement, management believes that PacifiCorp and its subsidiaries could have borrowed an additional $2.5 billion of debt at March 31, 2000.

Under PacifiCorp's principal credit agreements, it is an event of default if any person or group acquires 35% or more of PacifiCorp's common shares or if, during any period of 14 consecutive months, individuals who were directors of PacifiCorp on the first day of such period (and any new directors whose election or nomination was approved by such individuals and directors) cease to constitute a majority of the Board of Directors. However, no event of default occurred solely as a result of ScottishPower acquiring all of the outstanding common shares of PacifiCorp, or controlling the election or nomination of directors.

RISK MANAGEMENT

Risk is an inherent part of the Company's business and activities. The risk management process established by the Company is designed to identify, assess, monitor and manage each of the various types of risk involved in its business and activities. Central to its risk management process, the Company has established a risk management committee with overall responsibility for establishing and reviewing the Company's policies and procedures for

controlling and managing its risks. The senior risk management committee relies on the Company's treasury and risk management departments and its operating units to carry out its risk management directives and execute various hedging and energy trading strategies. The policies and procedures that guide the Company's risk management activities are contained in the Company's derivative policy.

The risk management process established by the Company is designed to measure quantitative market risk exposure and identify qualitative market risk exposure in its businesses. To assist in managing the volatility relating to these exposures, the Company enters into various derivative transactions consistent with the Company's derivative policy. That policy governs the Company's use of derivative instruments and its energy trading practices and contains the Company's credit policy and management information systems required to effectively monitor such derivative use. The Company's derivative policy provides for the use of only those instruments that have a close correlation with its portfolio of assets, liabilities or anticipated transactions. The derivative policy includes as its objective that interest rates and foreign exchange derivative instruments will be used for hedging and not for speculation. The derivative policy also governs the energy trading activities and is generally designed for hedging the Company's existing energy exposures but does provide for limited speculation activities within defined risk limits.

RISK MEASUREMENT

Value at Risk Analysis

The tests discussed below for exposure to interest rate and currency exchange rate fluctuations are based on a Value at Risk ("VAR") approach using a one-year horizon and a 95% confidence level and assuming a one-day holding period in normal market conditions. The VAR model is a risk analysis tool that attempts to measure the potential losses in fair value, earnings or cash flow from changes in market conditions and does not purport to represent actual losses in fair value that may be incurred by the Company. The VAR model also calculates the potential gain in fair market value or improvement in earnings and cash flow associated with favorable market price movements.

Sensitivity Analysis

The Company measures its market risk related to its commodities price exposure positions by utilizing a sensitivity analysis. This sensitivity analysis measures the potential loss or gain in fair value, earnings or cash flow based on a hypothetical immediate 10% change (increase or decrease) in prices for its commodity derivatives. The fair value of such positions are a summation of the fair values calculated for each commodity derivative by valuing each position at quoted futures prices or assumed forward prices.

EXPOSURE ANALYSIS

Interest Rate Exposure

The Company's market risk to interest rate changes is primarily related to long-term debt with fixed interest rates. The Company uses interest rate swaps, forwards, futures and collars to adjust the characteristics of its liability portfolio. This strategy is consistent with the Company's capital structure policy which provides guidance on overall debt to equity and variable rate debt as a percent of capitalization levels for both the consolidated organization and its principal subsidiaries.

The table below shows the potential loss in fair market value of the Company's interest rate sensitive positions as of December 31, 1998 and March 31, 2000, as well as the Company's quarterly high and low potential losses.

Millions of dollars	Confidence Interval	Time Horizon	12/31/98	2000 Quarterly High	2000 Quarterly Low	3/31/00
Interest Rate Sensitive Portfolio - FMV	95%	1 day	$(26.9)	$(38.3)	$(18.5)	$(18.5)

Because of the size of the Company's fixed rate portfolio and lower levels of short-term debt as a result of asset sales, the significant majority of this average daily exposure is a noncash fair market value exposure and generally not a cash or current interest expense exposure.

Currency Rate Exposure

The Company's market risk to currency rate changes is primarily related to its investment in the Australian Electric Operations. The Company uses currency swaps, currency forwards and futures to hedge its foreign activities and, where use is governed by the derivative policy, the Company utilizes Australian dollar denominated borrowings to hedge the majority of the foreign exchange risks associated with Australian Electric Operations. Results of hedging activities relating to foreign net asset exposure are reflected in the accumulated other comprehensive income section of shareholders' equity, offsetting a portion of the translation of the net assets of Australian Electric Operations.

Gains and losses relating to qualifying hedges of foreign currency firm commitments (or anticipated transactions) are deferred on the balance sheet and are included in the basis of the underlying transactions. To the extent that a qualifying hedge is terminated or ceases to be effective as a hedge, any deferred gains and losses up to that point continue to be deferred and are included in the basis of the underlying transaction. To the extent that anticipated transactions are no longer likely to occur, the related hedges are closed with gains or losses charged to earnings on a current basis.

In addition to the foreign currency exposure related to its investment in Australian Electric Operations, the Company also includes in the currency rate exposure VAR analysis the mark-to-market risk associated with its energy supply related contracts for differences supporting its commitment to the customers of Australian Electric Operations.

The table below shows the potential loss in pre-tax cash flow of the Company's currency rate sensitive positions as of December 31, 1998 and March 31, 2000, as well as the Company's quarterly high and low potential losses.

Millions of dollars	Confidence Interval	Time Horizon	12/31/98	2000 Quarterly High	2000 Quarterly Low	3/31/00
Currency Rate Exposure - Cash Flow	95%	1 day	$(0.9)	$(1.1)	$(0.8)	$(1.1)

Commodity Price Exposure

The Company's market risk to commodity price change is primarily related to its electricity commodities which are subject to fluctuations due to unpredictable factors, such as weather, which impacts supply and demand. The Company's energy trading activities are governed by the derivative policy and the risk levels established as part of that policy.

The Company's energy commodity price exposure arises principally from its electric supply obligation in the United States and Australia. In the United States, the Company manages this risk principally through the operation of its 7,829 MW generation and transmission system in the western Unites States and through its wholesale energy trading activities. Derivative instruments are not significantly utilized in the management of the Unites States electricity position. In Australia, the Victorian government currently limits the amount of generation that can be owned by an electric supply company and, as a result, the risk associated with Australian Electric Operations energy supply obligations is managed through the use of electricity forward contracts (referred to as "contracts for differences") with Victorian generators. Under these forward contracts, the Company receives or makes payment based on a differential between a contracted price and the actual spot market of electricity. Additionally, electricity futures contracts are utilized to hedge Domestic Electric Operations' excess or shortage of net electricity for future months. The changes in market value of such contracts have had a high correlation to the price changes of the hedged commodity. Derivative instruments, other than contracts for differences, are not significantly utilized in Australian Electric Operations' risk management process.

Gains and losses relating to qualifying hedges of firm commitments or anticipated inventory transactions are deferred on the balance sheet and included in the basis of the underlying transactions.

A sensitivity analysis has been prepared to estimate the Company's exposure to market risk related to commodity price exposure of its derivative positions for electricity. Based on the Company's derivative price exposure at March 31, 2000 and December 31, 1998, a near-term adverse change in commodity prices of 10% would negatively impact pre-tax earnings by $18 million and $16 million, respectively.

INFLATION

Due to the capital-intensive nature of the Company's core businesses, inflation may have a significant impact on replacement of property, acquisition and development activities and final mine reclamation costs. To date, management does not believe that inflation has had a significant impact on any of the Company's other businesses.

NEW ACCOUNTING STANDARDS

In June 1999, SFAS No. 137 was issued, which deferred the effective date of SFAS No. 133 to the fiscal years beginning after June 15, 2000. SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," requires an entity to recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. A company may implement SFAS No. 133, as of the beginning of any fiscal quarter after the June 1998 issuance; however, the statement cannot be applied retrospectively. The Company does not plan to adopt SFAS No. 133 early. Adoption of this standard will have an effect on the Company's financial position and results of operations; however, the magnitude of the effect will be determined by the hedges and derivatives that the Company has in place at the date of adoption of the standard. The effects in future periods will be dependent upon the derivatives and hedges in place at the end of each period and cannot be presently determined.

In July 1999, the EITF reached a consensus on Issue No. 99-9, "Effect of Derivative Gains and Losses on the Capitalization of Interest" ("EITF 99-9"). EITF 99-9 clarifies the application of SFAS No. 34, which establishes standards for capitalizing interest cost as part of the historical cost of acquiring certain assets, in conjunction with SFAS No. 133 (see discussion above). The Company anticipates that the cumulative effect of the adoption of EITF 99-9 at April 1, 2001 will be immaterial on the Company's financial position, results of operations and cash flows.

From November 29, 1999 to March 24, 2000, the SEC issued Staff Accounting Bulletins No. 100, 101 and 101A. The effect of adoption of these bulletins is not expected to have a material effect on the Company's financial position or results of operations.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The information required by this item is included under "Risk Management," and "Risk Measurement - Value at Risk Analysis," and "Sensitivity Analysis," and "Exposure Analysis - Interest Rate Exposure," "Currency Rate Exposure" and "Commodity Price Exposure" on pages 51 through 54 of this Report under ITEM 7.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Page

Index To Consolidated Financial Statements:
  Report of Management......................................
  Report of Independent Accountants.........................
  Independent Auditors' Report..............................
  Statements Of Consolidated Income For The Year Ended
    March 31, 2000, The Three Months Ended March 31,
    1999 And The Years Ended December 31, 1998 and 1997.....
  Statements Of Consolidated Cash Flows For The Year
    Ended March 31, 2000, The Three Months Ended
    March 31, 1999 And The Years Ended December 31,
    1998 and 1997...........................................
  Consolidated Balance Sheets As Of March 31, 2000
    And December 31, 1998...................................
  Statements Of Consolidated Changes In Common
    Shareholders' Equity For The Year Ended March 31,
    2000, The Three Months Ended March 31, 1999
    And The Years Ended December 31, 1998 and 1997..........
  Notes To Consolidated Financial Statements................

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64
65

REPORT OF MANAGEMENT

The management of PacifiCorp and its subsidiaries (the "Company") is responsible for preparing the accompanying consolidated financial statements and for their integrity and objectivity. The statements were prepared in accordance with generally accepted accounting principles. The financial statements include amounts that are based on management's best estimates and judgments. Management also prepared the other information in the annual report and is responsible for its accuracy and consistency with the financial statements.

The Company's financial statements were audited by PricewaterhouseCoopers LLP ("PricewaterhouseCoopers") with respect to the year ended March 31, 2000, or by Deloitte & Touche LLP ("Deloitte & Touche") with respect to prior periods, independent public accountants. Management made available to PricewaterhouseCoopers and Deloitte & Touche all the Company's financial records and related data, as well as the minutes of shareholders' and directors' meetings.

Management of the Company established and maintains an internal control structure that provides reasonable assurance as to the integrity and reliability of the financial statements, the protection of assets from unauthorized use or disposition and the prevention and detection of materially fraudulent financial reporting. The Company maintains an internal auditing program that independently assesses the effectiveness of the internal control structure and recommends possible improvements. PricewaterhouseCoopers and Deloitte & Touche considered that internal control structure in connection with their audits. Management reviews significant recommendations by the internal auditors, PricewaterhouseCoopers and Deloitte & Touche, concerning the Company's internal control structure and ensures appropriate cost-effective actions are taken.

The Company's "Guide to Business Conduct" is distributed to employees throughout the Company to provide a basis for ethical standards and conduct. The guide addresses, among other things, potential conflicts of interests and compliance with laws, including those relating to financial disclosure and the confidentiality of proprietary information.

Alan V. Richardson
President and Chief Executive Officer

Karen K. Clark
Chief Financial Officer

Report of Independent Accountants

To the Board of Directors and Shareholders of
PacifiCorp:

In our opinion, based on our audit and the report of other auditors, the accompanying consolidated balance sheet and the related statements of consolidated income, common shareholders' equity and cash flows present fairly, in all material respects, the financial position of PacifiCorp and its subsidiaries at March 31, 2000, and the results of their operations and their cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audit. We did not audit the financial statements of PacifiCorp Australia Limited Liability Company and its subsidiaries, a wholly-owned subsidiary, which statements reflect total assets of $1,855,035,000 as of December 31, 1999, and total revenues of $617,563,000 for the year ended December 31, 1999. Those statements were audited by other auditors whose report thereon has been furnished to us, and our opinion expressed herein, insofar as it relates to the amounts included for PacifiCorp Australia Limited Liability Company and its subsidiaries, is based solely on the report of the other auditors. We conducted our audit of these statements in accordance with auditing standards generally accepted in the United States, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit and the report of other auditors provide a reasonable basis for the opinion expressed above. The financial statements of the Company as of March 31, 1999 (not separately presented herein) and as of December 31, 1998, and for the three months ended March 31, 1999 and for each of the two years in the period ended December 31, 1998 were audited by other independent accountants whose report dated February 11, 2000 expressed an unqualified opinion on those statements.

PricewaterhouseCoopers LLP
Portland, Oregon
May 4, 2000, except for the fourth, fourteenth, and twentieth
paragraphs of Note 5, as to which the date is May 31, 2000

INDEPENDENT AUDITORS' REPORT

TO THE BOARD OF DIRECTORS AND SHAREHOLDERS OF PACIFICORP:

We have audited the accompanying consolidated balance sheet of PacifiCorp and subsidiaries as of December 31, 1998, and the related statements of consolidated income, consolidated changes in common shareholders' equity and consolidated cash flows for the three months ended March 31, 1999 and each of the years ended December 31, 1998 and 1997. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the consolidated financial position of PacifiCorp and subsidiaries at December 31, 1998, and the results of their operations and their cash flows for the three months ended March 31, 1999 and each of the years ended December 31, 1998 and 1997, in conformity with accounting principles generally accepted in the United States of America.

Deloitte & Touche LLP

Portland, Oregon
February 11, 2000

STATEMENTS OF CONSOLIDATED INCOME Millions of dollars	Year Ended March 31, 2000	Three Months Ended March 31, 1999	Years Ended
STATEMENTS OF CONSOLIDATED INCOME Millions of dollars	Year Ended March 31, 2000	Three Months Ended March 31, 1999	December 31, 1998	December 31, 1997
Revenues	$3,986.9	$ 959.8	$5,580.4	$4,548.9
Expenses Purchased power Other operations and maintenance Administrative and general Depreciation and amortization Taxes, other than income taxes Special charges Total	1,217.8 1,212.8 282.3 467.5 101.4 - 3,281.8	268.7 259.8 64.3 113.2 26.3 - 732.3	2,821.5 1,081.9 322.9 451.2 98.7 123.4 4,899.6	1,605.0 1,078.8 319.0 466.1 98.9 170.4 3,738.2
Income from Operations	705.1	227.5	680.8	810.7
Interest Expense and Other Interest expense Interest capitalized Losses from equity investments ScottishPower merger costs TEG costs and option losses Write down of investments in energy development companies Gain on sale of PGC Minority interest and other Total	341.4 (20.2) 2.6 195.5 - - - (30.8) 488.5	88.0 (3.4) 3.7 - - - - (10.0) 78.3	371.6 (14.5) 13.9 13.2 73.0 79.5 - (25.6) 511.1	437.8 (12.2) 12.8 - 105.6 - (56.5) (21.5) 466.0
Income from continuing operations before income taxes Income tax expense	216.6 134.0	149.2 57.9	169.7 59.1	344.7 111.8
Income from continuing operations before extraordinary item	82.6	91.3	110.6	232.9
Discontinued operations (less applicable income tax expense/(benefit): 2000/ $0.7, 1998/$(74.3) and 1997/$361.1)	1.1	-	(146.7)	446.8
Extraordinary loss from regulatory asset impairment (less applicable income tax benefit of $9.6)	-	-	-	(16.0)
Net Income (Loss)	$ 83.7	$ 91.3	$ (36.1)	$ 663.7
Earnings (Loss) on Common Stock	$ 64.8	$ 86.5	$ (55.4)	$ 640.9