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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF
THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1999
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 1-5532-99
PORTLAND GENERAL ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)
OREGON (State or other jurisdiction 93-0256820
ofincorporation or organization) (I.R.S. Employer
Identification No.)
121 SW SALMON STREET, PORTLAND, OREGON 97204
(Address of principal executive offices) (zip code)
Registrant's telephone number, including area code: (503) 464-8000
Securities registered pursuant to Section 12(b) of the Act:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
Portland General Electric Company
8.25% Quarterly Income Debt Securities
(Junior Subordinated Deferrable Interest
Debentures, Series A) New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
TITLE OF CLASS
Portland General Electric Company,
7.75% Series, Cumulative Preferred Stock,
no par value None
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 ]
State the aggregate market value of the voting stock held by non-affiliates of
the registrant as of February 29, 2000: $0.
Indicate the number of shares outstanding of each of the registrant's classes
of common stock, as of February 29, 2000: 42,758,877 shares of Common Stock,
$3.75 par value. (All shares are owned by Enron Corp.)
DEFINITIONS
The following abbreviations or acronyms used in the text and notes are
defined below:
Abbreviations
OR ACRONYMS TERM
Beaver .......................... Beaver Combustion Turbine Plant
Boardman ........................ Boardman Coal Plant
BPA ............................. Bonneville Power Administration
Centralia ....................... Centralia Coal Plant
Colstrip ........................ Colstrip Units 3 and 4 Coal Plant
Coyote Springs .................. Coyote Springs Generation Plant
CUB ............................. Citizens' Utility Board
DEQ ............................ Oregon Department of Environmental Quality
Enron ........................... Enron Corp.
EFSC ............................ Energy Facility Siting Council
EPA ............................. Environmental Protection Agency
FERC ............................ Federal Energy Regulatory Commission
Financial Statements ............ Refers to Financial Statements of Portland
General Electric Company included in Part II,
Item 8 of this report.
KWh ............................. Kilowatt-Hour
MW .............................. Megawatt
MWa ............................. Average megawatts
MWh ............................. Megawatt-hour
NRC ............................. Nuclear Regulatory Commission
NYMEX ........................... New York Mercantile Exchange
OPUC or the Commission .......... Oregon Public Utility Commission
PGE or the Company .............. Portland General Electric Company
PUD ............................. Public Utility District
Regional Power Act .............. Pacific Northwest Electric Power Planning and
Conservation Act
SFAS ............................ Statement of Financial Accounting Standards
issued by the FASB
Trojan .......................... Trojan Nuclear Plant
USDOE ........................... United States Department of Energy
WAPA ............................ Western Area Power Administration
WNP-3 ........................... Washington Public Power Supply System Unit 3
Nuclear Project
WSCC ............................ Western Systems Coordinating Council
TABLE OF CONTENTS
PAGE
Definitions ............................................................. 2
PART I
Item 1. Business ........................................................ 4
Item 2. Properties ..................................................... 16
Item 3. Legal Proceedings .............................................. 19
Item 4. Submission of Matters to a Vote of Security Holders ............ 20
PART II
Item 5. Market for Registrant's Common Equity and
Related Stockholder Matters ................................... 21
Item 6. Selected Financial Data ....................................... 21
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations ........................... 22
Item 7A. Quantitative and Qualitative Disclosures About
Market Risk ................................................... 32
Item 8. Financial Statements and Supplementary Data ................... 33
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure ........................... 55
PART III
Item 10. Directors and Executive Officers of the Registrant ............ 56
Item 11. Executive Compensation ........................................ 59
Item 12. Security Ownership of Certain Beneficial Owners
and Management ................................................ 63
Item 13. Certain Relationships and Related Transactions ................ 63
PART IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K ........................................... 64
Signatures ............................................................. 65
Exhibit Index .......................................................... 66
PART I
ITEM 1. BUSINESS
GENERAL
PGE, incorporated in 1930, is an electric utility engaged in the
generation, purchase, transmission, distribution, and sale of electricity
in the State of Oregon. PGE also sells energy to wholesale customers
throughout the western United States. PGE's Oregon service area is 3,170
square miles, including 54 incorporated cities, of which Portland and Salem
are the largest, within a state-approved service area allocation of 4,070
square miles. PGE estimates that at the end of 1999 its service area
population was approximately 1.5 million, comprising about 44% of the
state's population. For the year 1999, the Company added approximately
15,000 customers, representing an annualized growth rate of about 2.5%. At
December 31, 1999, PGE served approximately 719,000 customers.
On July 1, 1997 Portland General Corporation (PGC), the former parent of
PGE, merged with Enron Corp. (Enron) with Enron continuing in existence as
the surviving corporation and PGE operating as a wholly owned subsidiary
subject to control by Enron.
On November 8, 1999, Enron announced that it had entered into a purchase
and sale agreement to sell PGE to Sierra Pacific Resources (Sierra) for
$2.1 billion, comprised of $2.02 billion in cash and the assumption of
Enron's approximately $80 million merger payment obligation. The proposed
transaction, which is subject to regulatory approval, is expected to close
in late 2000. On January 18, 2000, Sierra filed with the OPUC an
application to acquire PGE. On February 3, 2000, Sierra filed with the SEC
an application to acquire PGE and also to become a registered public
utility holding company.
As of December 31, 1999, PGE had 2,787 employees. This compares to 2,728
and 2,729 employees at December 31, 1998 and 1997, respectively.
Currently, 1,072 employees are covered under a three-year agreement with
Local Union No. 125 of the International Brotherhood of Electrical Workers
that is effective from March 1, 1998 through March 1, 2001.
OPERATING REVENUES
RETAIL
PGE serves a diverse retail customer base. Residential customers
constitute the largest customer class and account for approximately 45% of
total retail revenues, with commercial and industrial customers accounting
for 38% and 17%, respectively. Residential demand is highly sensitive to
the effects of weather, with company revenues highest during the winter
heating season. Electricity sales increased somewhat in 1999 due to the
effects of PGE's Customer Choice pilot program, which in 1998 allowed some
customers to buy their power from competing energy service providers; this
program terminated at the end of 1998. The commercial and industrial
classes are not dominated by any single industry. While the 20 largest
customers constitute about 18% of retail demand, they represent 8 different
industrial groups, including paper manufacturing, high technology, metal
fabrication, general merchandising and health services. No single customer
represents more than 3% of PGE's total retail load.
WHOLESALE
Wholesale electricity sales comprised about 26% of total operating revenues
in 1999, up from about 20% in 1998. Most of PGE's wholesale sales have
been to utilities and power marketers and have been predominantly short-
term. PGE will continue its participation in the wholesale marketplace in
order to balance its supply of power to meet the needs of its retail
customers, manage risk, and administer its current long-term wholesale
contracts. Such participation includes power purchases and sales resulting
from daily economic dispatch decisions for its own generation; this allows
PGE to secure power for its customers at the lowest cost available.
The following table summarizes operating revenues and MWh sales for the
years ended December 31:
1999 1998 1997
Operating Revenues (Millions)
Residential $ 438 $ 432 $ 391
Commercial(1) 367 345 354
Industrial 173 132 143
Tariff Revenues 978 909 888
Accrued (Collected) Revenues 26 (8) 10
Retail 1,004 901 898
Wholesale 355 234 497
Other 19 41 21
Total Operating Revenues $ 1,378 $1,176 $1,416
Megawatt-Hours Sold (Thousands)
Residential 7,404 7,101 6,999
Commercial(1) 7,392 6,781 6,973
Industrial 4,463 3,562 4,247
Retail 19,259 17,444 18,219
Wholesale 12,612 10,869 26,934
Total MWh Sold 31,871 28,313 45,153
Energy Delivered to ESP
Customers (2) - 1,292 2
Total MWh Sold and Delivered 31,871 29,605 45,155
(1) Includes public street lighting.
(2) Represents energy delivered to customers of Energy Service Providers
(ESPs) under PGE's Customer Choice pilot program.
For additional information on year-to-year revenue trends, see Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations.
REGULATION
PGE is subject to the jurisdiction of the OPUC, comprised of three members
appointed by Oregon's governor to serve non-concurrent four-year terms.
The Commission approves the Company's retail rates and establishes
conditions of utility service. The Commission further ensures that prices
are fair and equitable and provides PGE an opportunity to earn a fair
return on its investment. In addition, the Commission regulates the
issuance of securities and prescribes the system of accounts to be kept by
Oregon utilities.
PGE is also subject to the jurisdiction of the FERC with regard to the
transmission and sale of wholesale electric energy, licensing of
hydroelectric projects and certain other matters. 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.
Construction of new thermal generating facilities requires a permit from
the EFSC.
The NRC regulates the licensing and decommissioning of nuclear power
plants. In 1993 the NRC issued a possession-only license amendment to
PGE's Trojan operating license and in early 1996 approved the Trojan
Decommissioning Plan. Approval of the Trojan Decommissioning Plan by the
NRC and EFSC has allowed PGE to begin decommissioning activities, which are
proceeding satisfactorily and within approved cost estimates. After
receiving regulatory approval, PGE in 1999 shipped and disposed of the
Trojan reactor vessel as a single package called the Reactor Vessel and
Internals Removal Project (RVAIR). Equipment removal and disposal
activities will also continue in 2000. Trojan is subject to NRC regulation
until it is fully decommissioned, all nuclear fuel is removed from the
site, and the license terminated. The Oregon Department of Energy also
monitors Trojan. (For further information, see "Nuclear Decommissioning"
in Item 7. - "Management's Discussion and Analysis of Financial Condition
and Results of Operations").
REGULATORY MATTERS
ELECTRIC POWER INDUSTRY RESTRUCTURING
On July 23, 1999, Oregon's governor signed into law a State Senate Bill
(SB1149) that provides all industrial and commercial customers of investor-
owned utilities direct access to competing energy suppliers no later than
October 1, 2001. Residential customers will be able to purchase
electricity from a "portfolio" of rate options that will include a cost-of-
service rate, a new renewable resource rate, and a market-based rate.
SB1149 also provides for a 10-year public purposes charge equal to 3% of
retail revenues, designed to fund cost-effective conservation measures, new
renewable energy resources, and weatherization measures for low-income
housing. In addition, SB1149 provides for low-income electric bill
assistance through proportionate collections by affected utilities,
beginning in January 2000.
Also included in SB1149 is a requirement that investor-owned utilities
unbundle the costs of service into power generation, transmission,
distribution, and retail services. The law also provides for "transition"
charges and credits that would allow recovery on uneconomic utility
investment or a refund of benefits from economic utility investment.
Incentives for the divestiture of generation assets are authorized,
provided any divestiture does not deprive customers of the benefit of the
utility's or the region's low cost resources. SB1149 further requires that
its implementation have no material adverse impact on the ability of
investor-owned utilities to access cost-based power from the Bonneville
Power Administration for its residential and small farm customers.
In October 1999, the OPUC began a series of workshops designed to discuss
the issues associated with SB1149 and to develop administrative rules for
implementation of the law; PGE is participating fully in these workshops.
In February 2000, the OPUC began its formal rulemaking process with the
expectation that rules enabling utilities to develop tariffs will be
adopted in June 2000. Additional rulemakings regarding non-tariff-related
items are also expected. PGE expects to file its restructuring plan,
including associated tariffs, in time to allow for direct access by October
1, 2001.
LEAST COST ENERGY PLANNING
The OPUC adopted Least Cost Energy Planning for all energy utilities in
Oregon, with the goal of selecting the mix of resources that yields a
reliable supply of energy at the least cost to customers. PGE has received
acknowledgement of its 1998-1999 Integrated Resource Plan (IRP) from the
OPUC. This plan recognized fundamental changes occurring in the electric
industry and established a transition strategy for the next two years. It
maintained PGE's delivery capability and provided a bridge to a competitive
environment in which funding for public purposes is provided from a system
benefit charge.
PGE is currently holding a public process to obtain input from interested
parties for its next IRP, which is scheduled for completion by the end of
2000. This Plan will help shape PGE's resource decisions under new state
law adopted in 1999 that requires restructuring to be implemented by
October 1, 2001.
RESIDENTIAL EXCHANGE PROGRAM
In 1980, the Regional Power Act (RPA) was passed by Congress in response to
growing power supply and cost inequities between customers of government
and publicly-owned utilities, who have priority access to low-cost power
from the federal hydroelectric system, and the customers of investor-owned
utilities ("IOUs"). The RPA created the Residential Exchange Program to
ensure that all residential and
small farm customers in the region, the majority of which are served by
IOUs, receive similar benefits from the publicly funded federal power
system. Exchange benefits are passed directly to PGE's customers in the
form of price adjustments contained in OPUC-approved tariffs.
In accordance with federal recommendations and the intent of both parties
to replace the Residential Exchange Program with one providing more
predictable and stable cash payments by BPA, PGE and BPA in September 1998
signed a Residential Exchange Termination Agreement that provides for a
total of $34.5 million in BPA payments to PGE over two years. The
agreement continues to provide benefits to PGE's residential and small farm
customers through at least the June 2001 termination date of the agreement.
BPA has prepared its initial wholesale electric power and transmission rate
proposals for the period October 2001 through September 2006, reflecting
its intent to share the benefits of the Federal Columbia River Power
system, restore fish and wildlife, encourage conservation and renewables
development, and manage costs and risks. The rate case process is governed
by the Northwest Power Act and involves workshops and hearings that give
interested parties and participants the opportunity to participate fully in
the process. Although it is anticipated that customers of investor-owned
utilities will continue to receive benefits from the publicly funded
federal power system beyond the 2001 termination of the current agreement
with BPA, it has not yet been determined how this will be accomplished.
ENERGY EFFICIENCY
PGE has long promoted the efficient use of electricity. Current Demand
Side Management (DSM) programs provide a range of services to all classes
of PGE customers and seek to maximize those opportunities in which
efficiency measures are most cost-effective for both PGE ratepayers and
customers. To accomplish this, PGE focuses on both commercial and
industrial new construction, industrial process improvements, and
residential weatherization measures, including a program for low-income
families. In the past, the costs of DSM programs have been deferred and
amortized to expense over future periods. In response to new legislation
that encourages a competitive marketplace for energy services and provides
for a public service charge to fund conservation measures, PGE has
requested OPUC approval to immediately expense all future DSM expenditures.
PGE's current unamortized DSM investment would be amortized by the October
1, 2001 implementation of SB1149. These proposed changes, which would
result in an approximate 2.3% average rate increase, are currently under
review by the OPUC.
COMPETITION AND MARKETING
GENERAL
As electricity deregulation moves forward nationally, PGE continues to
maintain its commitment to service excellence while assisting in the
formation of a competitive electricity market in the Northwest. Its
Customer Choice pilot program was successfully implemented in 1998 and
provided valuable information on the effects of retail competition on PGE
and its customers. PGE will continue its efforts to bring market
conditions to the industry, working closely with customers and regulators
to achieve the state's policy goals. The outcome of these efforts to help
create a more competitive electricity market will depend in large part on
both statutory and regulatory changes.
RETAIL COMPETITION AND MARKETING
PGE operates within a state-approved service area and under current
regulation is substantially free from direct retail competition with other
electric utilities. PGE's competitors within its Oregon service territory
include other fuel suppliers, such as the local natural gas company, which
compete with PGE for the residential and commercial space and water heating
market. In addition, there is the potential for the loss of PGE service
territory from the creation of public utility districts or municipal
utilities by voters.
In September 1999, voters within the Columbia County cities of St. Helens,
Scappoose, and Columbia City approved annexation to the Columbia River
People's Utility District (CRPUD); voters within the Columbia County City
of Rainier approved annexation to the Clatskanie Public Utility District.
These annexations would provide for the transfer of approximately 7,300 PGE
customers to these two utility districts. In January 2000, a memorandum of
understanding was agreed upon by the parties that provides for the payment
of approximately $10 million to PGE from the utility districts in exchange
for the service territories of the four cities. The proposed sale is
subject to approval by the OPUC.
WHOLESALE COMPETITION AND MARKETING
Competition has transformed the electric utility industry at the wholesale
level. The Energy Policy Act, passed in 1992, opened wholesale competition
to energy brokers, independent power producers and power marketers, and
provided a framework for increased competition in the electric industry.
In 1996, the FERC issued Order 888 requiring non-discriminatory open access
transmission by all public utilities that own interstate transmission,
requiring investor-owned utilities to allow others access to their
transmission systems for wholesale power sales. This access must be
provided at the same price and terms the utilities would apply to their own
wholesale customers. It also requires reciprocity from municipals,
cooperatives, and federal power marketers receiving service under the
tariff and allows public utilities to recover stranded costs in accordance
with the terms, conditions and procedures set forth in the order.
The Company's transmission system connects winter-peaking utilities in the
Northwest and Canada, which have access to low-cost hydroelectric
generation, with summer-peaking wholesale customers in California and the
Southwest, which have higher-cost fossil fuel generation. PGE has used
this system to purchase and sell in both markets depending upon the
relative price and availability of power, water conditions, and seasonal
demand from each market.
POWER SUPPLY
Growth within PGE's service territory has underscored the Company's need
for sources of reliable, low-cost energy supplies. The demand for energy
within PGE's service territory has experienced an average annual growth
rate of approximately 2.5% over the last 10 years and retail demand is
expected to continue this upward trend. PGE has relied increasingly on
short-term purchases to supplement its existing base of generating
resources and long-term power contracts to meet its energy needs. Short-
term purchases include both secondary as well as firm purchases for periods
of less than one year in duration. The availability of short-term firm
purchase agreements and PGE's ability to renew these contracts have enabled
PGE to minimize risk and enhance its ability to provide reliable low-cost
energy to retail customers. Increased competition has placed pressure on
the price of short-term power as well as enhanced its availability.
Northwest hydro conditions also have a significant impact on regional power
supply. Plentiful water conditions can lead to surplus power and the
economic displacement of more expensive thermal generation.
GENERATING CAPABILITY
PGE's existing hydroelectric, coal-fired, and gas-fired plants are
important resources for the Company, providing 1,998 MW of generating
capability (see Item 2. Properties, for a full listing of PGE's generating
facilities). PGE's lowest-cost producers are its eight hydroelectric
projects on the Clackamas, Sandy, Deschutes, and Willamette rivers in
Oregon. These facilities operate under federal licenses, which will be up
for renewal between the years 2001 and 2006. For further discussion of
hydroelectric project relicensing, see "Hydro Relicensing" in Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations.
In conjunction with its federal relicensing process, PGE has reached a
tentative agreement with the City of Portland, the State of Oregon, and the
National Marine Fisheries Service to decommission its 22-MW Bull Run
Hydroelectric Project, removing the Marmot and Little Sandy dams. The
purpose of the agreement is to improve habitat for salmon, steelhead, and
the other fish protected by the Endangered Species Act in the Little
Sandy/Bull Run watersheds. The cost of removing the dams, constructed in
the early 1900's, is estimated at $8 million. The regulatory approval
process and dam decommissioning are expected to take approximately three
years. In November 1999, PGE filed with the FERC a "Notice of Intent Not
to File Application for New License", providing formal notice that it does
not intend to relicense the Bull Run Project when its existing federal
license expires in November 2004. The retirement of the Bull Run Project is
not expected to have a material effect on the financial condition or
results of operations of the Company. There are no current plans to remove
any other of the Company's hydroelectric projects.
On November 1, 1998, PGE signed a definitive agreement to sell its 20%
interest in coal-fired generating Units 3 and 4 of the Colstrip power
plant, located in eastern Montana. The agreement, subject to both state
and federal approval, would transfer ownership of PGE's 296 MW interest in
the plant to PP&L Global, a subsidiary of PP&L Resources, for $230.4
million. On April 7, 1999, PGE filed an application for approval of the
sale with the OPUC; such application, as subsequently amended, included a
$26.6 million (excluding transition costs) retail rate reduction, to become
effective upon approval and sale. OPUC Staff recommended that approval of
the proposed sale be denied absent both a higher sales price and further
retail rate reduction. On February 29, 2000, the OPUC issued an order that
denied PGE's application to sell its interest in Units 3 and 4 of the
Colstrip power plant.
In December 1999, PGE reached preliminary agreement with the Confederated
Tribes of Warm Springs (Tribes) that would result in shared ownership and
control of the Company's 408-MW Pelton Round Butte Project, which provides
about 20% of the Company's power-generating capacity. The agreement with
the Tribes, who own some of the land on which the dams are located, would
take place in three stages over a proposed 50-year license period. PGE
would have majority ownership through most of the period and the Tribes
would have the option to increase their ownership share to slightly over
50% by 2037, beginning with the proposed purchase of a one-third interest
on December 31, 2001, in exchange for one-third of the net book value of
the project. PGE would no longer be required to pay annual rent to the
Tribes for use of their land. PGE would continue to operate the project,
which would be managed by a joint operating committee of PGE and the
Tribes, and its customers would continue to benefit from the Company's
guaranteed share of a relatively low-cost power supply. The agreement
requires the approval of tribal members in a referendum scheduled March 28,
2000; if approved, PGE and the Tribes would jointly pursue a 50-year
license from the FERC. The proposed sale will also require approval of the
OPUC. It is not anticipated that the proposed sale, if approved, will have
an adverse effect on the financial condition or results of operations of
the Company.
In December 1999, PGE sold its 2.5% undivided interest in the Centralia
Steam Electric Generating Plant, a 1,340-MW coal fired plant located in the
State of Washington, to Avista Corp. for approximately $3.5 million. PGE's
33 MW ownership share will be replaced by power purchases from the plant
during the first several months of 2000 and from market purchases
thereafter.
PGE's Coyote Springs generating station, a 241-MW combined cycle combustion
turbine plant, was completed in 1995 and designed and equipped for a second
unit to be built and jointly operated adjacent to it. The second unit
would share certain assets (termed "Common Facilities") with the first
unit, including equipment, real property, licenses, permits, and various
other assets sized to support a second unit. PGE has decided not to
develop the second facility, preferring a more flexible resource strategy,
and has received OPUC approval to sell an undivided 50% interest in the
Common Facilities to another party.
PURCHASED POWER
As PGE's existing base of generating resources is reduced, the Company will
continue to negotiate long-term and short-term contracts to meet the retail
load that it has an obligation to serve. Under the provisions of recent
state legislation (SB1149) allowing large industrial and commercial
customers direct access to competing energy suppliers, PGE will be
obligated to serve only residential and small commercial customers
beginning October 1, 2001. After October 1, 2001, this will be only its
residential and small commercial load. PGE has long-term power contracts
with four hydro projects on the mid-Columbia River, which provide PGE with
650 MW of firm capacity. PGE also has firm contracts, ranging in term from
one to thirty years, to purchase 519 MW, primarily hydro-generated, from
other Pacific Northwest utilities. In addition, PGE has a long-term
exchange contract with a summer-peaking Southwest utility to help meet its
winter-peaking requirements. These resources, along with short-term
contracts, provide PGE with sufficient firm capacity to serve its peak
loads.
SYSTEM RELIABILITY AND THE WSCC
PGE relies on wholesale market purchases within the WSCC in conjunction
with its base of generating resources to supply its resource needs and
maintain system reliability. The WSCC is the largest and most diverse of
the 10 regional electric reliability councils. Organized in 1967, it
provides coordination for operating and planning a reliable and adequate
electric power system for the western part of the continental United
States, Canada, and Mexico. It provides the forum for its member systems
to enhance communication, coordination, and cooperation in planing and
operating a reliable interconnected electric system. During the last few
years, the area covered by WSCC has become a dynamic marketplace for the
trading of electricity. This area, which extends from Canada to Mexico and
includes 14 Western states, has great diversity in climates and peak loads
occur at different times of the year in the different regions within the
WSCC area. Energy loads in the Southwest peak in summer due to air
conditioning; northern loads peak during winter heating months. According
to WSCC forecasts, the nearly 104 electric organizations participating in
the WSCC, which include utilities, independent power producers and
transmission utilities, have sufficient generating capacity to meet
forecast demand and energy requirements through the year 2009.
JANUARY RESERVE MARGIN
WSCC REGION
MEGAWATTS
2000 34,467
2001 34,133
2002 33,822
2003 32,940
2004 31,662
2005 31,496
2006 28,539
2007 27,834
2008 27,747
2009 26,320
During 1999, PGE's peak load was 3,544 MW, of which 31% was met through
short-term purchases. PGE's firm resource capacity, including short-term
purchase agreements, totaled approximately 5,333 MW as of December 31,
1999.
RESTORATION OF SALMON RUNS
The populations of many salmon species in the Pacific Northwest have shown
significant decline over the last several decades. A significant number of
these species have either been granted or are being evaluated for
protection under the federal Endangered Species Act (ESA). While long term
recovery plans for these species may include major operational changes to
the region's hydroelectric projects, including PGE's, the impacts to date
have been minimal. The biggest change has been modifying the timing of
releases of water stored behind the dams in the upper part of the Columbia
and Snake River basins. This change in water releases has resulted in
decreased energy generation in the fall and winter. Favorable hydro
conditions continued to help mitigate the effect of these actions in 1999.
In 1999, nine federal agencies involved in the management of the Columbia
River system formed a Federal Caucus to develop specific options for salmon
recovery. The Federal Caucus will continue its efforts throughout 2000,
coordinating with other regional efforts and forums to examine
opportunities for recovering listed salmon.
PGE continues to evaluate the impact of current and potential listings on
the operation of its hydroelectric projects on the Deschutes, Sandy,
Clackamas, and Willamette Rivers. PGE's ongoing hydroelectric relicensing
efforts, in addition to discussions with the listing agency, have begun
addressing issues associated with endangered salmon. Based on this, and
review of the proposed rules that have been issued thus far, PGE does not
anticipate any significant operational changes to its hydroelectric
projects during 2000 as a result of endangered salmon recovery measures.
FUEL SUPPLY
Fuel supply contracts are negotiated to support annual planned plant
operations. Flexibility in contract terms is sought to allow for the most
economic dispatch of PGE's thermal resources in conjunction with the
current market price of wholesale power.
COAL
BOARDMAN
PGE has agreements to purchase coal for Boardman that cover requirements
through the year 2000. Ample supplies exist to fuel Boardman's
requirements in future years. Coal purchases in 1999, totaling about 2
million tons, contained less than 0.4% of sulfur by weight and emitted less
than the EPA allowable limit of 1.2 pounds of sulfur dioxide per MMBtu when
burned. The coal, from surface mining operations in Wyoming and Utah, was
subject to federal, state and local regulations. Coal is delivered to
Boardman by rail under contracts with the Burlington Northern, Santa Fe,
and Union Pacific Railroads.
COLSTRIP
Coal for Colstrip Units 3 and 4, located in southeastern Montana, is
provided under contract with Western Energy Company, a wholly owned
subsidiary of Montana Power Company. The contract provides that the coal
delivered will not exceed a maximum sulfur content of 1.5% by weight. The
Colstrip plant has sulfur dioxide removal equipment to allow operation in
compliance with EPA's source-performance emission standards.
SULFUR TYPE OF POLLUTION
PLANT CONTENT CONTROL EQUIPMENT
Boardman, OR 0.4% Electrostatic precipitators
Colstrip, MT 0.7% Scrubbers and precipitators
NATURAL GAS
In addition to the agreements discussed below, the Company utilizes
short-term and spot market purchases to secure transportation capacity and
gas supplies sufficient to fuel plant operations. PGE remarkets any natural
gas and transportation capacity that are excess to its needs.
BEAVER
PGE owns 90% of the Kelso-Beaver Pipeline, which directly connects its
Beaver generating station to Northwest Pipeline, an interstate gas pipeline
operating between British Columbia and New Mexico. During 1999, PGE had
access to 76,000 MMBtu/day of firm transportation capacity, enough to
operate Beaver at a 70% load factor. In May 1999, PGE and B-R Pipeline
Co., a wholly owned subsidiary of U.S. Gypsum Co, filed a joint application
with the FERC for the sale by PGE of 12% of its interest (representing a
10.5% tenancy-in-common share) in the Kelso-Beaver Pipeline to B-R Pipeline
for approximately $2.5 million; the sale represents pipeline capacity in
excess of PGE's current or foreseeable needs. The sale has been approved
by the OPUC and has received preliminary approval, subject to environmental
review, by the FERC.
COYOTE SPRINGS
The Coyote Springs generating station utilizes 41,000 MMBtu/day of firm
transportation capacity on three interconnecting pipeline systems accessing
the gas fields in Alberta, Canada. Firm gas supplies for Coyote Springs
are purchased at market based prices up to two years prior to delivery
based on the anticipated operation of the plant. PGE believes that
sufficient gas is available in the marketplace to meet the full fuel
requirements of the plant.
ENVIRONMENTAL MATTERS
PGE operates in a state recognized for environmental leadership. PGE's
environmental stewardship policy emphasizes minimizing waste in its
operations, minimizing environmental risk, and promoting the wise use of
energy.
REGULATION
PGE's current and historical operations are subject to a wide range of
environmental protection laws covering air and water quality, noise, waste
disposal, and other environmental issues. The EPA regulates the proper
use, transportation, cleanup and disposal of polychlorinated biphenyls
(PCBs). State agencies or departments, which have direct jurisdiction over
environmental matters, include the Environmental Quality Commission, the
DEQ, the Oregon Office of Energy, and EFSC. Environmental matters
regulated by these agencies include the siting and operation of generating
facilities and the accumulation, cleanup, and disposal of toxic and
hazardous wastes.
CLEANUP
PGE is involved with others in the environmental cleanup of PCB
contaminants at various sites as a potentially responsible party (PRP).
The cleanup effort is considered complete at several sites, which are
awaiting consent orders from the appropriate regulatory agencies. These
and future cleanup costs are not expected to be material.
HARBORTON
PGE received a letter dated September 27, 1999, from the Oregon Department
of Environmental Quality (DEQ) requesting that PGE perform a voluntary
remedial investigation of its Harborton Substation Site to confirm whether
any regulated hazardous substances have been released from the substation
property into a portion of the Willamette River known as the Portland
Harbor. A 1997 investigation of the Portland Harbor conducted by an U.S.
Environmental Protection Agency (EPA) contractor purportedly revealed
significant contamination of sediments within the harbor. The DEQ has
advised PGE that, based on analytical results from the 1997 study, the EPA
is considering Portland Harbor for inclusion on the federal National
Priority List pursuant to the federal Comprehensive Environmental Response,
Compensation, and Liability Act. The DEQ directed that PGE perform a
remedial investigation pursuant to a DEQ approved Voluntary Agreement, and
that the work be coordinated with other Portland Harbor sediment
investigations currently being pursued by the DEQ that involve more than 50
PRPs. While PGE does not believe that it is responsible for any
contamination in Portland Harbor, PGE entered into the Voluntary Agreement
and will conduct an initial set of investigatory activities. Subsequent
investigations will almost certainly be required if any significant soil or
groundwater contamination is discovered during the course of the initial
investigation being conducted by PGE. Remedial activities, if any, that
PGE may ultimately perform with respect to this matter will depend on the
results of its investigations.
PGE does not expect this to have a material adverse impact on the financial
condition or results of operations of the Company.
AIR/WATER QUALITY
PGE's operations, principally its fossil-fuel electric generation plants,
are subject to the federal Clean Air Act (Act) and other federal regulatory
requirements. State governments are also charged with monitoring and
administering certain portions of the Act and are required to set
guidelines that at least equal federal standards. Oregon has air quality
standards that are more stringent than federal standards. The air
pollutants addressed under the Act that primarily affect PGE are sulfur
dioxide ("SO{2}"), nitrogen oxides ("NO{x}"), and particulate matter. PGE
manages its emissions through burning low sulfur fuel, emission controls,
emission monitoring and through good combustion controls.
The SO{2} emission allowances awarded under the Act, and those allowances
expected to be awarded annually in the future, are sufficient to operate
Boardman at a 60% to 67% capacity factor without having to further reduce
emissions. In addition, the number of emission allowances are sufficient
to operate Colstrip, which utilizes scrubbers. If necessary, PGE intends
to acquire a relatively small number of additional allowances in order to
meet excess capacity needs. PGE sold its share of Centralia to Avista
Corp. as of December 31, 1999, so PGE is no longer a party in meeting the
emission requirements for this plant. It is not yet known what impacts the
federal Ozone Transport, Regional Haze, or PM{2.5} regulations may have on
future plant operations, operating costs, or generating capacity.
Federal operating air permits, issued by the DEQ, have been obtained for
all of PGE's fossil fuel generating facilities, which includes its
combustion turbine plants. Two of these air permits (for the Beaver and
Boardman Plants) will require renewal applications due in July 2000. The
current permits are in effect until the renewal process is completed.
ITEM 2. PROPERTIES
PGE's principal plants and appurtenant generating facilities and storage
reservoirs are situated on land owned by PGE in fee or land under the
control of PGE pursuant to valid existing leases, federal or state
licenses, easements, or other agreements. In some cases meters and
transformers are located upon the premises of customers. The Indenture
securing PGE's first mortgage bonds constitutes a direct first mortgage
lien on substantially all utility property and franchises, other than
expressly excepted property. The map below shows PGE's Oregon service
territory and location of its generating facilities:
Generating facilities owned by PGE are set forth in the following table:
PGE NET
MW
FACILITY LOCATION FUEL CAPABILITY
WHOLLY OWNED:
Faraday Clackamas River Hydro 44
North Fork Clackamas River Hydro 54
Oak Grove Clackamas River Hydro 44
River Mill Clackamas River Hydro 25
Pelton Deschutes River Hydro 108
Round Butte Deschutes River Hydro 300
Bull Run Sandy River Hydro 22
Sullivan Willamette River Hydro 16
Beaver Clatskanie, OR Gas/Oil 500
Coyote Springs Boardman, OR Gas/Oil 241
PGE
JOINTLY OWNED: INTEREST
Boardman Boardman, OR Coal 348 @ 65.0%
Colstrip 3 & 4 Colstrip, MT Coal 296 @ 20.0%
Total 1,998
PGE holds licenses under the Federal Power Act for its hydroelectric
generating plants, as well as licenses from the State of Oregon for all
or portions of five of the plants. All of its licenses expire during the
years 2001 to 2006. The FERC requires that a notice of intent to
relicense these projects be filed approximately five years prior to
expiration of the license.
PGE filed for relicensing of the Pelton Round Butte Project in December
1998 and in December 1999 reached a preliminary agreement that would
result in shared ownership and control of the Project with the
Confederated Tribes of Warm Springs over a proposed 50-year license
period. PGE would remain as the operator of the Project.
PGE has reached a tentative agreement with the City of Portland, the
State of Oregon, and the National Marine Fisheries Service to
decommission the Bull Run Hydroelectric Project, removing the Marmot and
Little Sandy Dams. The purpose of the agreement is to improve habitat
for salmon, steelhead, and other fish protected by the Endangered Species
Act in the Little Sandy/Bull Run watersheds. In November 1999, PGE filed
with the FERC a "Notice of Intent Not to File Application for New
License" when its existing federal license expires in November 2004. The
regulatory approval process and dam decommissioning are expected to take
approximately three years.
PGE is actively pursuing the renewal of all other licenses for its
hydroelectric generating plants.
For further information see "Hydro Relicensing" in Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations.
Following the 1993 Trojan closure, PGE was granted a possession-only
license amendment by the NRC. In early 1996 PGE received NRC approval of
its Trojan decommissioning plan. See Note 11, Trojan Nuclear Plant, in
the Notes to the Financial Statements for further information.
LEASED PROPERTIES
PGE leases its headquarters complex in downtown Portland and the coal-
handling facilities and certain railroad cars for Boardman.
ITEM 3. LEGAL PROCEEDINGS
UTILITY
CITIZENS' UTILITY BOARD OF OREGON V. PUBLIC UTILITY COMMISSION OF OREGON
AND UTILITY REFORM PROJECT AND COLLEEN O'NEILL V. PUBLIC UTILITY COMMISSION
OF OREGON, Marion County Oregon Circuit Court, the Court of Appeals of the
State of Oregon, the Oregon Supreme Court.
The Citizens' Utility Board (CUB) appealed a 1994 ruling from the Marion
County Circuit Court that upheld the order of the OPUC in its Declaratory
Ruling proceeding (DR-10). In the DR-10 proceeding, PGE filed an
Application with the OPUC requesting a Declaratory Ruling regarding
recovery of the Trojan investment and decommissioning costs. On August 9,
1993 the OPUC issued the declaratory ruling. In its ruling, the OPUC
agreed with an opinion issued by the Oregon Department of Justice (Attorney
General) stating that under current law, the OPUC has authority to allow
recovery of and a return on Trojan investment and future decommissioning
costs.
In PGE's 1995 general rate case, the OPUC issued an order granting PGE full
recovery of Trojan decommissioning costs and 87% of its remaining
investment in the plant. The Utility Reform Project (URP) filed an appeal
of the OPUC's order. URP alleged that the OPUC lacked authority to allow
PGE to recover Trojan costs through its rates. The complaint sought to
remand the case to the OPUC and have all costs related to Trojan
immediately removed from PGE's rates.
The CUB also filed an appeal challenging the portion of the OPUC's order
issued in PGE's 1995 general rate case that authorized PGE to recover a
return on its remaining investment in Trojan. The CUB alleged that the
OPUC's decision was not based upon evidence received in the rate case, is
not supported by substantial evidence in the record of the case, was based
on an erroneous interpretation of law and is outside the scope of the
OPUC's discretion, and otherwise violates constitutional or statutory
provisions. The CUB sought to have the order modified, vacated, set aside
or reversed.
On April 4, 1996, a circuit court judge in Marion County, Oregon rendered a
decision that contradicted a November 1994 ruling from the same court. The
1996 decision found that the OPUC could not authorize PGE to collect a
return on its undepreciated investment in Trojan currently in PGE's rate
base. The 1994 and 1996 circuit court decisions were consolidated and
appealed to the Oregon Court of Appeals.
On June 24, 1998, the Court of Appeals of the State of Oregon ruled that
the OPUC does not have the authority to allow PGE to recover a rate of
return on its undepreciated investment in Trojan. The court upheld the
OPUC's authorization of PGE's recovery of its undepreciated investment in
Trojan and its costs to decommission Trojan.
On August 26, 1998, PGE filed a Petition for Review with the Oregon Supreme
Court, supported by amicus briefs filed by three other major utilities
seeking review of that portion of the Oregon Court of Appeals decision
relating to PGE's return on its undepreciated investment in Trojan. The
OPUC also filed such a petition for review.
Also on August 26, 1998, the Utility Reform Project filed a Petition for
Review with the Oregon Supreme Court seeking review of that portion of the
Oregon Court of Appeals decision relating to PGE's recovery of its
undepreciated investment in Trojan.
On April 29, 1999, the Oregon Supreme Court accepted the petitions for
review of the June 24, 1998, Oregon Court of Appeals decision.
On June 16, 1999, Oregon's governor signed Oregon House Bill 3220
authorizing the OPUC to allow recovery of a return on the undepreciated
investment in property retired from service. One of the effects of the
bill is to affirm retroactively the OPUC's authority to allow PGE's
recovery of a return on its undepreciated investment in the Trojan
generating facility.
Relying on the new legislation, on July 2, 1999, the Company requested the
Oregon Supreme Court to vacate the June 24, 1998, adverse ruling of the
Oregon Court of Appeals and affirm the validity of the OPUC's order
allowing PGE to recover a return on its undepreciated investment in Trojan.
The Utility Reform Project and the Citizens Utility Board, another party to
the proceeding, opposed such request on the ground that an effort was
underway to gather sufficient signatures to place on the ballot a
referendum to negate the new legislation; such effort by the referendum's
sponsors was successful and the referendum will appear on the November 2000
ballot. The Oregon Supreme Court has stated it will hold its review of the
Court of Appeals decision in abeyance until after the election.
COLUMBIA RIVER PEOPLE'S UTILITY DISTRICT V. PORTLAND GENERAL ELECTRIC
COMPANY
On December 1, 1998, the Columbia River People's Utility District (CRPUD)
filed an anti-trust complaint in Federal District Court that seeks to
overturn a 1984 Judgment and Acquisition Agreement that confirmed PGE's
exclusive right to serve Boise Cascade Corporation. The complaint seeks to
declare as invalid and unenforceable a provision establishing the amount to
be paid by CRPUD upon its condemnation of PGE facilities serving Boise
Cascade; the complaint also seeks an injunction barring PGE from enforcing
earlier agreements and judgments related to this matter. Attorney fees and
costs were sought but no claim was made for monetary damages.
On March 24, 1999, the Court entered Summary Judgment in favor of PGE.
On April 21, 1999, CRPUD filed a Notice of Appeal, with briefing and oral
argument to follow. A decision from the Ninth Circuit Court of Appeals may
be rendered in 2000.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
PGE is a wholly owned subsidiary of Enron, which owns all 42,758,877 shares
of PGE's outstanding stock. Aggregate cash dividends declared on common
stock were as follows (millions of dollars):
QUARTER 1999 1998
First $ 20 $ -
Second 20 16
Third 20 16
Fourth 21 17
PGE is restricted, without prior OPUC approval, from making any dividend
distributions to Enron that would reduce PGE's common equity capital below
48% of total capitalization.
ITEM 6. SELECTED FINANCIAL DATA
FOR THE YEARS ENDED DECEMBER 31
1999 1998 1997 1996 1995
(millions of dollars)
Operating Revenues $1,378 $1,176 $1,416 $1,110 $ 982
Net Operating Income 190 200 208 230 201
Net Income 128 137 126 156 93{1}
Total Assets $3,167 $3,162 $3,256 $3,398 $3,246
Long-Term Obligations{2} 763 876 1,038 963 931
NOTES TO THE TABLE ABOVE:
{1} Includes a loss of $50 million from regulatory disallowances.
{2} Includes long-term debt, preferred stock subject to mandatory
redemption requirements, long-term capital lease obligations, and
commercial paper to be refinanced.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
GENERAL
1999 COMPARED TO 1998
Portland General Electric's net income for 1999 was $128 million compared
to $137 million for 1998. Increased property, franchise, and income taxes,
as well as a reduction from 1998's gains on the sale of Company land were
primarily responsible for the decrease. These were partially offset by an
increased margin on higher electricity sales and by reduced interest
charges.
Retail revenues increased $103 million primarily due to higher energy sales
resulting from both the addition of 15,000 new customers as well as the
termination of 1998's Customer Choice pilot program which enabled
participating customers to purchase their electricity from other energy
service providers. Revenues from power delivery services to energy service
providers totaled $21 million last year; termination of the pilot program
in 1999 caused the decrease in Other operating revenues.
NET INCOME
(Millions)
1999 128
1998 137
1997 126
1996 156
1995 93
Wholesale revenues increased $121 million (52%) due to both higher energy
sales volume and prices. Increased energy sales resulted largely from
sales in the wholesale market of excess power obtained to meet higher
anticipated retail demand. Demand was lower than expected due to mild
temperatures in 1999.
OPERATING REVENUES
(Millions)
Retail Wholesale
1999 1004 355
1998 901 234
1997 898 497
1996 906 194
1995 877 95
Purchased power and fuel costs increased $197 million (45%) due to higher
prices for increased energy purchases. Higher regional power and gas
market prices increased the cost of firm power purchases, resulting in a
25% increase in average power prices. Purchases were made to supply
expected higher retail demand caused by weather volatility and customer
growth, including the return of those customers participating in 1998's
Customer Choice pilot program. Increased purchases also reflect PGE's
ability to purchase power at a price more economical than generation.
Company generation decreased from 37% to 32% of total power needs,
primarily due to the economic displacement of gas powered generation, which
declined about 21%. Coal and hydro generation approximated that of last
year.
RETAIL ENERGY SALES
Million MWh
1999 19.259
1998 18.736
1997 18.221
1996 17.559
1995 17.065
MEGAWATT-HOURS/VARIABLE POWER COSTS
Megawatt-Hours Average Variable
(thousands) Power Cost (Mills/KWh)
1999 1998 1999 1998
Generation 10,515 10,854 9.8 8.6
Firm Purchases 18,897 16,595 23.2 17.3
Spot Purchases 3,712 2,180 19.7 23.6
Total Send-Out 33,124 29,629 *19.5 *15.6
(* includes wheeling costs)
Operating expenses (excluding purchased power and fuel, depreciation and
taxes) increased $2 million, or less than 1%, as increased administrative
and delivery system costs were largely offset by reduced generating plant
expenses.
Depreciation and amortization expense increased $6 million (4%) primarily
due to the effect of 1998's non-recurring $4 million gain on the sale of
land formerly occupied by PGE's Western Division offices.
OPERATING EXPENSES
(Millions)
DEPRECIATION OPERATING COSTS VARIABLE POWER
1999 155 395 638
1998 149 386 441
1997 155 378 675
1996 162 410 308
1995 135 357 294
Taxes other than income taxes increased $4 million (7%) primarily due to
higher state property taxes, caused by increases in taxable values, and
city franchise fees that increased with higher electricity sales. Income
taxes increased $3 million (4%) primarily because of the reversal of pre-
1981 tax benefits related to the depreciation of certain regulatory assets;
this was partially offset by a small decrease in net taxable income for the
year.
Interest charges decreased $6 million (8%) due to a reduction in
outstanding debt.
1998 COMPARED TO 1997
Portland General Electric's net income for 1998 was $137 million compared
to $126 million for 1997. Net income in 1997 included the effect of a $14
million non-recurring loss provision associated with non-utility property.
PGE's operating performance reflected the addition of over 19,000 new
customers in a growing service territory.
Retail revenues increased $3 million, as the effects of warmer winter
weather and the move of about 8,700 customers to other energy service
providers under PGE's Customer Choice pilot program largely offset the
increase in customers served. Revenues from power delivery services to
energy service providers totaled $20 million for the year and caused the
increase in Other operating revenues.
Wholesale revenues decreased $263 million, or 53%, reflecting PGE's
decision to limit wholesale activities to transactions related to the
management of system power supplies and generation.
Purchased power and fuel costs decreased $234 million, or 35%, due almost
entirely to reduced wholesale trading activity. A 52% decrease in energy
purchases was offset somewhat by higher average prices (16.2 mills in 1997,
18.0 mills in 1998) caused largely by increased winter gas prices and tight
market conditions in the southwestern United States. Company generation
provided 37% of total power needs, up from 16% in 1997; coal and gas
powered generation almost tripled with average production costs
significantly less than the cost to purchase.
Operating expenses (excluding purchased power and fuel, depreciation and
taxes) increased $9 million, or 4%. The increase was due largely to the
payment of $12 million in Enron overhead costs and a $2 million increase in
production and distribution expenses; these were partially offset by a $5
million decrease in customer support, marketing, and sales expenses.
Depreciation and amortization expense decreased $6 million, or 4%. A $13
million decrease caused by the amortization of regulatory credits and the
gain on the sale of land formerly occupied by PGE's Western Division
offices was partially offset by a $7 million increase in depreciation
expense due to capital additions to PGE's distribution system.
Other Income increased $20 million, due largely to a $14 million after tax
loss provision recorded in 1997 for the future removal of non-utility
property. Also contributing to the 1998 increase were gains on sales of
non-utility land and timber.
CASH FLOW
CASH PROVIDED BY OPERATIONS is used to meet the day-to-day cash
requirements of PGE. Supplemental cash is obtained from external
borrowings as needed.
PGE maintains varying levels of short-term debt, primarily in the form of
commercial paper, which serves as the primary form of daily liquidity. In
1999, monthly balances ranged from $124 million to $266 million. PGE has
two committed borrowing facilities: a $200 million facility maturing in
July 2000 and a $100 million facility maturing in August 2000. Both
facilities are used as backup for PGE's commercial paper facility.
A significant portion of cash provided by operations comes from
depreciation and amortization of utility plant, charges which are recovered
in customer revenues but require no current period cash outlay. Changes in
accounts receivable and accounts payable can also be significant
contributors or users of cash.
Cash provided by operating activities totaled $236 million in 1999,
compared to $265 million in 1998. The decrease is due primarily to a
reduction from the amount received in 1998 from the Bonneville Power
Administration under terms of the Residential Exchange Termination
agreement.
INVESTING ACTIVITIES consist primarily of improvements to PGE's
distribution, transmission, and generation facilities, as well as energy
efficiency program expenditures. Capital expenditures of $188 million in
1999 were primarily for the expansion and upgrade of PGE's distribution
system and also include the $37 million purchase of previously leased
combustion turbine generators at the Beaver generating plant. Capital
expenditures are expected to approximate $180 million in 2000. Over the
next few years, anticipated expenditures are expected to approximate
current levels, with the majority of expenditures comprised of improvements
to the Company's expanding distribution system to support both new and
existing customers within PGE's service territory.
FINANCING ACTIVITIES provide supplemental cash for day-to-day operations
and capital requirements as needed. PGE relies on commercial paper
borrowings and cash from operations to manage its day-to-day financing
requirements. In 1999, PGE repaid $113 million in long-term debt,
including $94 million in matured First Mortgage Bonds, $9 million in other
long-term debt, and the early redemption of $10 million in 7 3/4 % First
Mortgage Bonds due in the year 2023, funded primarily through commercial
paper borrowings. The Company also repaid $30 million ($32 million less $2
million prepaid interest) in policy loans on corporate owned life
insurance.
During 1999, PGE's dividend payments totaled $83 million, consisting of
common stock dividends of $81 million paid to its parent and $2 million in
preferred stock dividends. In 1998, PGE's dividend payments totaled $51
million, consisting of common stock dividends of $49 million paid to its
parent and $2 million in preferred stock dividends.
In April 1999, PGE filed a $200 million shelf registration statement with
the Securities and Exchange Commission for the purpose of issuing long-term
debt from time to time, as determined in light of market conditions and
other factors, the proceeds from which will be used to refund fixed and
variable rate securities, reduce commercial paper borrowings, and fund
planned construction and other expenditures. Subject to the above factors,
PGE expects to issue debt under this shelf filing in March 2000. In July
1999, PGE received approval from the Federal Energy Regulatory Commission
to issue short-term debt, including commercial paper, credit facilities,
and other evidences of indebtedness up to $350 million. This approval is
effective for two years and replaces and supercedes PGE's prior approval
from the FERC authorizing short-term borrowing of $250 million. On August
6, 1999, PGE entered into a $100 million
revolving credit facility with two
commercial banks. This facility, combined with the Company's existing $200
million revolving credit facility, effectively increases the total
committed credit for PGE to $300 million. These facilities are used
primarily as backup for commercial paper and borrowings from commercial
banks under uncommitted lines of credit.
In July 1999, Duff & Phelps Credit Rating Co. (DCR) assigned initial
ratings to PGE's debt, with senior secured debt rated 'AA-', senior
unsecured debt rated 'A+', preferred stock and junior subordinated debt
rated 'A', and commercial paper rated 'D1'. Also in July, Moody's
Investors Services (Moody's) changed PGE's rating outlook from 'stable' to
'positive'.
On November 8, 1999, in response to the announced purchase and sale
agreement for PGE and uncertainties regarding the future status of certain
OPUC stipulations that were agreed to in its 1997 merger with Enron, credit
rating agencies reviewed their ratings of the Company. DCR placed the
Company on Rating Watch--Uncertain, Moody's placed PGE's ratings on review
for possible downgrade, and Standard and Poor's placed the ratings of the
Company on CreditWatch with negative implications. On November 11, 1999,
Moody's confirmed the Prime-1 short-term debt rating for commercial paper
issued by PGE.
The issuance of additional First Mortgage Bonds and preferred stock
requires PGE to meet earnings coverage and security provisions set forth in
the Articles of Incorporation and the Indenture securing its First Mortgage
Bonds. As of December 31, 1999, PGE has the capability to issue preferred
stock and additional First Mortgage Bonds in amounts sufficient to meet its
capital requirements.
FINANCIAL AND OPERATING OUTLOOK
PORTLAND GENERAL ELECTRIC COMPANY - ELECTRIC UTILITY
PROPOSED ACQUISITION
On November 8, 1999, Enron announced that it had entered into a purchase
and sale agreement to sell PGE to Sierra Pacific Resources (Sierra) for
$2.1 billion, comprised of $2.02 billion in cash and the assumption of
Enron's approximately $80 million merger payment obligation. The proposed
transaction, which is subject to regulatory approval, is expected to close
in late 2000. On January 18, 2000, Sierra filed with the OPUC an
application to acquire PGE. On February 3, 2000, Sierra filed with the SEC
an application to acquire PGE and also to become a registered public
utility holding company.
REGULATION AND COMPETITION
STATE
The electric power industry continues to experience change. The impetus
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 customers have a choice of energy
supplier. Federal laws and regulations now provide for open access to
transmission systems and several states have adopted or are considering new
regulations to allow open access for all energy suppliers.
In 1999, Oregon's governor signed into law deregulation legislation giving
industrial and commercial customers of investor-owned utilities direct
access to energy suppliers and residential customers access to a portfolio
of rate options.
PGE recognizes that when a competitive marketplace exists, customers will
make their energy purchasing decisions based upon many factors, including
price, service and system reliability. To meet these competitive
challenges, PGE is participating in restructuring processes that will
determine the shape of future markets and is pursuing strategies that
capitalize on its competitive position, including the development and
delivery of innovative products and services. PGE continues to develop its
competitive strategy as legislation, regulation and market opportunities
continue to evolve.
Federal
The Energy Policy Act of 1992 (Energy Act) set the stage for change in
federal regulations aimed at increasing wholesale competition in the
electric industry. The Energy Act eased restrictions on independent power
production and granted authority to the FERC to mandate open access for the
wholesale transmission of electricity.
The FERC has taken steps to provide a framework for increased competition
in the electric industry. In 1996 the FERC issued Order 888 requiring non-
discriminatory open access transmission by all public utilities that own
interstate transmission. The final rule requires utilities to file tariffs
that offer others the same transmission services they provide themselves
under comparable terms and conditions. This rule also allows public
utilities to recover stranded costs in accordance with the terms,
conditions and procedures set forth in Order 888. The ruling requires
reciprocity from municipals, cooperatives and federal power marketers
receiving service under the tariff. The new rules became effective in July
1996 and have resulted in increased competition, lower prices and more
choices to wholesale energy customers.
Further legislation to restructure the electric industry, including retail
choice, is under active consideration at the federal level. Congressional
committee hearings on electricity restructuring are expected to continue,
although there remains considerable uncertainty regarding their ultimate
outcome.
In 1998, PGE filed an application with the FERC to increase its rates for
transmission service, in accordance with the terms of FERC Order 888
requiring open-access transmission by public utilities. Revised rates were
implemented on February 11, 1999, with final settlement and filing on March
1, 1999. PGE continues to formulate strategies to meet the challenges of
wholesale competition.
RETAIL CUSTOMER GROWTH AND ENERGY SALES
During 1999, weather adjusted retail energy sales grew 2.1%. Commercial and
manufacturing sales increased by 3.9% and 0.3% respectively. The addition
of over 15,000 customers resulted in residential sales growth of 2.0%. PGE
forecasts retail energy sales growth of approximately 3.5% in 2000 with the
rebound in the manufacturing sector.
WHOLESALE SALES
The availability of electric generating capability in the Western U.S., the
entrance of numerous wholesale marketers and brokers into the market, and
open access transmission are contributing to increasing competitive
pressure on the price of power. In addition, the development of financial
markets, including the NYMEX electricity contract, has led to enhanced
price discovery available for market participants, further adding to the
downward pressure on wholesale prices and margins. During 1999, PGE's
wholesale sales accounted for about 26% of total revenues and 40% of total
energy sales. PGE will continue its participation in the wholesale
marketplace in order to balance its supply of power to meet the needs of
its retail customers, manage risk, and administer its current long-term
wholesale contracts.
POWER & FUEL SUPPLY
PGE's base of hydro and thermal generating capacity, supplemented by its
existing firm power contracts and the availability of competitively-priced
wholesale energy within the region, provide the Company with the
flexibility needed to respond to seasonal fluctuations in the demand for
electricity within its service territory.
PGE has long-term power contracts with four hydro projects on the mid-
Columbia River providing capability of 650 MW, and has also relied
increasingly upon short-term purchases to meet its energy needs. The
Company anticipates that an active wholesale market and a surplus of
generating capacity within the WSCC should provide sufficient wholesale
energy available at competitive prices to supplement its generation and
purchases under existing firm power contracts.
Though early forecasts indicate above-average water conditions for 2000,
efforts to restore salmon runs on the Columbia and Snake rivers may
somewhat reduce the amount of water available for generation, which could
affect the availability and price of purchased power. Additional factors
that could affect the availability and price of purchased power include
weather conditions in the Northwest during winter months and in the
Southwest during summer months, as well as the performance of major
generating facilities in both regions.
During 1999, PGE generated approximately 32% of its total load requirement,
compared to approximately 37% in 1998. Short-term and long-term purchases
were utilized to meet the remaining load.
In February 1999, PGE elected to exercise its option to purchase the six
combustion turbine generators at Beaver for their $37 million fair market
value. The generators, previously operated under terms of a 25-year lease
that expired in August 1999, produce a net output of approximately 500 MW
in combined-cycle configuration.
RESTORATION OF SALMON RUNS - PGE continues to evaluate the impact of
current and potential listings of salmon species for protection under the
federal Endangered Species Act on its purchased power supply and the
operation of its hydroelectric projects on the Deschutes, Sandy, Clackamas,
and Willamette Rivers.
ASSET SALES
In November 1998, PGE signed an agreement to sell its 20% interest in coal-
fired generating Units 3 and 4 of the Colstrip power plant to PP&L Global
for $230.4 million, subject to approval of the OPUC. In late February
2000, the OPUC denied the Company's application to sell its interest in the
plant. In September 1999, voters within four Columbia County cities
approved annexation, and transfer of approximately 7,300 PGE customers, to
two separate public utility districts. Upon OPUC approval, PGE would
receive approximately $10 million in exchange for its service territory in
these four cities. In December 1999, PGE sold its 2.5% interest in the
Centralia Steam Electric Generating Plant to Avista Corp. for approximately
$3.5 million; the Company has an agreement to purchase power from the plant
during the first several months of 2000. In February 2000, PGE announced
an agreement with the Confederated Tribes of the Warm Springs (Tribes)
allowing the purchase of portions of the Pelton Round Butte hydroelectric
project over a 50-year license period. PGE would remain as the operator of
the project, which provides about 20% of the Company's power-generating
capacity.
HYDRO RELICENSING
PGE HYDRO - PGE's eight hydroelectric plants provide economical generation
and flexible load following capabilities; in 1999, they produced 2.8
million MWh of renewable energy, about 9% of PGE's total load. The plants
operate under federal licenses, which will be up for renewal between the
years 2001 and 2006.
Numerous meetings were conducted in 1999 in support of relicensing PGE's
hydroelectric projects on the Clackamas, Sandy, and Willamette Rivers;
licenses on these plants, with combined generating capacity of 203 MW,
expire in 2004 and 2006. Should relicensing not be completed prior to the
expiration of the original licenses, it is anticipated that PGE will be
issued annual licenses at substantially identical terms and conditions
until such time as final relicensing has been completed.
In May, PGE, with support of the City of Portland and state and federal
agencies, decided to prepare a license surrender application for its 22-MW
Bull Run Project on the Sandy River instead of continuing the process of
preparing and filing a new operating license application. In November, PGE
filed with the FERC a "Notice of Intent Not to File Application for New
License", providing formal notice that it does not intend to relicense the
Bull Run Project when its existing federal license expires in November
2004. Uncertainty in upcoming relicensing, mitigation, and operating and
maintenance costs were key factors in deciding to retire the Bull Run
Project.
PGE continued the relicensing process for its 408-MW Pelton Round Butte
Project throughout 1999, filing a final license application in December.
The Confederated Tribes of Warm Springs, currently the licensee for a
powerhouse located at a reregulating dam within the project, also proceeded
with their competing relicensing process for the entire project and
submitted a final license application. As a result of ongoing discussions
in 1998 and 1999, PGE and the Tribes reached a preliminary agreement that
would result in shared ownership and control of the project, which provides
about 20% of the Company's power-generating capacity.
MID-COLUMBIA HYDRO - PGE's long-term power purchase contracts with certain
public utility districts in the state of Washington expire between 2005 and
2018. Certain Idaho Electric Utility Co-operatives have initiated
proceedings with the FERC seeking to change the allocation of generation
from the Priest Rapids and Wanapum dams between electric utilities in the
region upon expiration of the current contracts. In early 1998, the FERC
ruled that the portion of the output from these dams made available to
purchasers such as PGE be reduced to 30%, and that such purchases be at
market-based rather than cost-based prices. This decision could change both
PGE's percentage share and the price of power from these facilities,
although such changes are not yet determinable.
For further information regarding the power purchase contracts on the mid-
Columbia dams, including Priest Rapids and Wanapum, see Note 7,
Commitments, in the Notes to Financial Statements.
NUCLEAR DECOMMISSIONING
PGE currently estimates the total cost to decommission Trojan at $339
million (nominal dollars), with approximately $114 million expended through
1999. The total estimate assumes that the majority of decommissioning
activities will be completed after the spent fuel has been transferred to a
temporary dry spent fuel storage facility in 2002. The plan anticipates
final site restoration activities will begin in 2018 after PGE completes
shipment of spent fuel to a USDOE facility (see Note 11, Trojan Nuclear
Plant, in the Notes to Financial Statements, for further discussion of the
decommissioning plan).
In 1999, PGE made significant progress in decommissioning Trojan. In
August, PGE shipped the Trojan reactor vessel as a single package, called
the Reactor Vessel and Internals Removal Project, to be disposed of at the
Hanford Nuclear Reservation. This precedent-setting project saved several
million dollars compared to the conventional segmentation approach.
PGE expects remaining transition activities to be extended through 2002 due
to the continuing delay of the Independent Spent Fuel Storage Installation
project. Transition activities are comprised of operating and maintaining
the spent fuel pool and securing the plant until fuel is transferred to dry
storage. PGE anticipates total 2000 decommissioning costs of approximately
$42 million, compared to about $41 million in 1999.
These efforts position PGE to safely dispose of all radiological hazards,
other than spent nuclear fuel, on the Trojan site and to initiate a final
radiation survey to prove these hazards are no longer present.
Decommissioning is proceeding within approved cost estimates.
YEAR 2000
A Year 2000 problem was anticipated which could have resulted from the use
in computer hardware and software of two digits rather than four digits to
define the applicable year. The use of two digits was a common practice
for decades when computer storage and processing was much more expensive
than today. When computer systems must process dates both before and after
January 1, 2000, two-digit year "fields" may create processing ambiguities
that can cause errors and system failures. For example, computer programs
that have date-sensitive features may recognize a date represented by "00"
as the year 1900 instead of 2000.PGE estimates total expenditures related
to Year 2000 issues will approximate $20-22 million, about 90% of which has
been spent to date. Pursuant to an April 1999 accounting order from the
OPUC, PGE has capitalized approximately $10 million of incremental Year
2000 costs, which will be amortized over a 5-year period beginning January
1, 2000. The order defers to a future proceeding whether PGE will be
allowed to recover the balance of any unamortized costs in rates.
PGE's efforts related to Year 2000 issues resulted in several company-wide
system improvements that will benefit the Company and its customers in the
future. These include an automated phone system
capable of handling three
times the number of phone calls as the older system, an upgrade Energy
Management System, desktop computer upgrades that incorporate newest
technologies, replacement of meter reading equipment, creation of
contingency plans that can be used in the event of natural disasters, and a
system of satellite phones for emergency communication between generating
plants, load dispatchers, power marketing and substation operations.
The year 2000 problem has caused no material disruption to PGE's mission-
critical facilities or operations. PGE will remain vigilant for Year 2000
related problems that may yet occur, due to hidden defects in computer
hardware or software at PGE or PGE's mission-critical external entities.
PGE anticipates that the Year 2000 problem will not create material
disruptions to its mission-critical facilities or operations, and will not
create future material costs.
NEW ACCOUNTING STANDARDS
In June 1998, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for
Derivative Instruments and Hedging Activities." SFAS No. 133 established
accounting and reporting standards requiring that every derivative
instrument (including certain derivative instruments embedded in other
contracts) be recorded on the balance sheet as either an asset or liability
measured at its fair value. The statement requires that changes in the
derivative's fair value be recognized currently in earnings unless specific
hedge accounting criteria are met. Special accounting for qualifying
hedges allows a derivative's gains and losses to offset related results on
the hedged item in the income statement, and requires that a company must
formally document, designate and assess the effectiveness of transactions
that receive hedge accounting.
In June 1999, the FASB issued SFAS No. 137, which deferred the effective
date of SFAS No. 133 to fiscal years beginning after June 15, 2000. A
company may implement SFAS No. 133, as of the beginning of any fiscal
quarter after issuance; however, the statement cannot be applied
retroactively. PGE does not plan to adopt SFAS No. 133 early and believes
that the statement will not have a material impact on its accounting for
price risk management activities or physical based contracts.
INFORMATION REGARDING FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K includes forward-looking statements within
the meaning of Section 27A of the Securities Act of 1933 and Section 21E of
the Securities Exchange Act of 1934. Although PGE believes that its
expectations are based on reasonable assumptions, it can give no assurance
that its goals will be achieved. Important factors that could cause actual
results to differ materially from those in the forward-looking statements
herein include political developments affecting federal and state
regulatory agencies, the pace of electric industry deregulation in Oregon
and in the United States, environmental regulations, changes in the cost of
power, adverse weather conditions, and the effects of the Year 2000 date
change during the periods covered by the forward-looking statements.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK
The Company is exposed to market risk arising from the need to purchase
fuel for its generating units (both natural gas and coal) as well as the
purchase of power to meet the needs of its retail customers. This price
and location risk is mitigated by PGE's use of swaps, futures and options.
The use of these instruments during the year and their estimated fair
values at December 31, 1999 and 1998 were not material.
In 1998, PGE entered into an interest rate swap agreement to manage
interest rate exposure and cancelled these swap agreements in 1999 with an
immaterial gain.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL REPORTING
The following financial statements of Portland General Electric Company and
subsidiaries (collectively, PGE) were prepared by management, which is
responsible for their integrity and objectivity. The statements have been
prepared in conformity with generally accepted accounting principles and
necessarily include some amounts that are based on the best estimates and
judgments of management.
The system of internal controls of PGE is designed to provide reasonable
assurance as to the reliability of financial statements and the protection
of assets from unauthorized acquisition, use or disposition. This system
is augmented by written policies and guidelines and the careful selection
and training of qualified personnel. It should be recognized, however,
that there are inherent limitations in the effectiveness of any system of
internal control. Accordingly, even an effective internal control system
can provide only reasonable assurance with respect to the preparation of
reliable financial statements and safeguarding of assets. Further, because
of changes in conditions, internal control system effectiveness may vary
over time.
PGE assessed its internal control system as of December 31, 1999, 1998 and
1997, relative to current standards of control criteria. Based upon this
assessment, management believes that its system of internal controls was
adequate during the periods to provide reasonable assurance as to the
reliability of financial statements and the protection of assets against
unauthorized acquisition, use or disposition.
Arthur Andersen LLP was engaged to audit the financial statements of PGE
and issue reports thereon. Their audits included developing an overall
understanding of PGE's accounting systems, procedures and internal controls
and conducting tests and other auditing procedures sufficient to support
their opinion on the financial statements. Arthur Andersen LLP was also
engaged to examine and report on management's assertion about the
effectiveness of PGE's system of internal controls over financial reporting
and the protection of assets against unauthorized acquisition, use or
disposition. The Reports of Independent Public Accountants appear in this
Annual Report.
The adequacy of PGE's financial controls and the accounting principles
employed in financial reporting are under the general oversight of the
Audit Committee of Enron's Board of Directors. No member of this committee
is an officer or employee of Enron or PGE. The independent public
accountants have direct access to the Audit Committee, and they meet with
the committee from time to time, with and without financial management
present, to discuss accounting, auditing and financial reporting matters.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Shareholders of Portland General Electric
Company:
We have examined management's assertion that the system of internal control
of Portland General Electric Company and its subsidiaries as of December
31, 1999, 1998 and 1997, was adequate to provide reasonable assurance as to
the reliability of financial statements and the protection of assets
against unauthorized acquisition, use or disposition, included in the
accompanying report on Management's Responsibility for Financial Reporting.
Management is responsible for maintaining effective internal control over
the reliability of the financial statements and the protection of assets
against unauthorized acquisition, use or disposition. Our responsibility
is to express an opinion on management's assertion based on our
examination.
Our examination was made in accordance with standards established by the
American Institute of Certified Public Accountants and, accordingly,
included obtaining an understanding of the system of internal control over
financial reporting and the protection of assets against unauthorized
acquisition, use or disposition, testing and evaluating the design and
operating effectiveness of the system of internal control and such other
procedures as we considered necessary in the circumstances. We believe that
our examination provides a reasonable basis for our opinion.
Because of inherent limitations in any system of internal control, errors
or irregularities may occur and not be detected. Also, projections of any
evaluation of the system of internal control to future periods are subject
to the risk that the system of internal control may become inadequate
because of changes in conditions, or that the degree of compliance with the
policies or procedures may deteriorate.
In our opinion, management's assertion that the system of internal control
of Portland General Electric Company and its subsidiaries as of December
31, 1999, 1998, and 1997 was adequate to provide reasonable assurance as to
the reliability of financial statements and the protection of assets
against unauthorized acquisition, use or disposition is fairly stated, in
all material respects, based upon current standards of control criteria.
Arthur Andersen LLP
Portland, Oregon
February 29, 2000
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Shareholders of Portland General Electric
Company:
We have audited the accompanying consolidated balance sheets of Portland
General Electric Company (an Oregon corporation), and subsidiaries as of
December 31, 1999 and 1998, and the related consolidated statements of
income, retained earnings and cash flow for each of the three years in the
period ended December 31, 1999. 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. 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, the financial statements referred to above present fairly,
in all material respects, the financial position of Portland General
Electric Company and subsidiaries as of December 31, 1999 and 1998, and the
results of their operations and their cash flows for each of the three
years in the period ended December 31, 1999, in conformity with accounting
principles generally accepted in the United States.
Arthur Andersen LLP
Portland, Oregon
February 29, 2000
PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31 1999 1998 1997
(MILLIONS OF DOLLARS)
OPERATING REVENUES $ 1,378 $ 1,176 $ 1,416
OPERATING EXPENSES
Purchased power and fuel 638 441 675
Production and distribution 135 134 132
Administrative and other 115 114 107
Depreciation and amortization 155 149 155
Taxes other than income taxes 61 57 56
Income taxes 84 81 83
1,188 976 1,208
NET OPERATING INCOME 190 200 208
OTHER INCOME (DEDUCTIONS)
Miscellaneous 13 13 (21)
Income taxes (6) (1) 13
7 12 (8)
INTEREST CHARGES
Interest on long-term debt and 61 68 69
other
Interest on short-term borrowings 8 7 5
69 75 74
NET INCOME 128 137 126
PREFERRED DIVIDEND REQUIREMENT 2 2 2
INCOME AVAILABLE FOR COMMON STOCK $ 126 $ 135 $ 124
PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
FOR THE YEARS ENDED DECEMBER 31 1999 1998 1997
(MILLIONS OF DOLLARS)
BALANCE AT BEGINNING OF YEAR $ 356 $ 270 $ 292
NET INCOME 128 137 126
MISCELLANEOUS - - (2)
484 407 416
DIVIDENDS DECLARED
Common stock - cash 81 49 47
Common stock - property - - 97
Preferred stock 2 2 2
83 51 146
BALANCE AT END OF YEAR $ 401 $ 356 $ 270
The accompanying notes are an integral part of these consolidated financial
statements.
PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
AT DECEMBER 31 1999 1998
(MILLIONS OF DOLLARS)
ASSETS
ELECTRIC UTILITY PLANT - ORIGINAL COST
Utility plant (includes Construction work
in progress of $44 and $35) $ 3,295 $ 3,182
Accumulated depreciation (1,430) (1,363)
1,865 1,819
OTHER PROPERTY AND INVESTMENTS
Contract termination receivable 85 95
Receivable from parent 89 97
Nuclear decommissioning trust, at market
value 42 72
Corporate owned life isurance, less loans
of $0 and $32 85 63
Miscellaneous 17 15
318 342
CURRENT ASSETS
Cash and cash equivalents - 4
Accounts and notes receivable 140 135
Unbilled and accrued revenues 49 45
Inventories, at average cost 37 28
Prepayments and other 41 31
267 243
DEFERRED CHARGES
Unamortized regulatory assets 691 731
Miscellaneous 26 27
717 758
$ 3,167 $ 3,162
CAPITALIZATION AND LIABILITIES
CAPITALIZATION
Common stock equity
Common stock, $3.75 par value per
share, 100,000,000 shares
authorized, 42,758,877 shares
outstanding $ 160 $ 160
Other paid-in capital - net 480 480
Retained earnings 401 356
Cumulative preferred stock
Subject to mandatory redemption 30 30
Long-term obligations 701 744
1,772 1,770
CURRENT LIABILITIES
Long-term debt due within one year 32 102
Short-term borrowings 266 105
Accounts payable and other accruals 167 145
Accrued interest 11 11
Dividends payable 1 1
Accrued taxes 12 35
489 399
OTHER
Deferred income taxes 351 351
Deferred investment tax credits 36 39
Trojan decommissioning and transition costs 234 274
Unamortized regulatory liabilities 197 237
Miscellaneous 88 92
906 993
$ 3,167 $ 3,162
The accompanying notes are an integral part of these consolidated financial
statements.
PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOW
FOR THE YEARS ENDED DECEMBER 31 1999 1998 1997
(MILLIONS OF DOLLARS)
CASH FLOWS FROM OPERATING ACTIVITIES:
Reconciliation of net income to net cash
provided by (used in) operating activities
Net income $ 128 $ 137 $ 126
Non-cash items included in net income:
Depreciation and amortization 155 149 155
Deferred income taxes and investment
tax credit (3) (5) (58)
Other non-cash expenses 24 - 24
Changes in working capital:
(Increase) decrease in receivables (9) (8) 27
Increase (decrease) in payables (1) (50) 51
Other working capital items - net (18) (1) (1)
Other - net (16) 43 35
NET CASH PROVIDED BY OPERATING ACTIVITIES: 236 265 359
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (188) (144) (180)
Other - net 14 (4) (28)
NET CASH USED IN INVESTING ACTIVITIES (174) (148) (208)
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayment of long-term debt (113) (214) (115)
Issuance of long-term debt and
commercial paper 161 148 8
Dividends paid (83) (51) (65)
Repayment of loans on corporate
owned life insurance (32) - -
Other - net 1 1 5
(66) (116) (167)
NET CASH USED IN FINANCING ACTIVITIES:
INCREASE (DECREASE) IN CASH
AND CASH EQUIVALENTS (4) 1 (16)
CASH AND CASH EQUIVALENTS,
THE BEGINNING OF YEAR 4 3 19
CASH AND CASH EQUIVALENTS,
END OF YEAR $ - $ 4 $ 3
Supplemental disclosures of cash flow
information
Cash paid during the year:
Interest, net of amounts capitalized $ 60 $ 63 $ 71
Income taxes 139 133 96
The accompanying notes are an integral part of these consolidated financial
statements.
PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES NOTES TO FINANCIAL
STATEMENTS
NATURE OF OPERATIONS
On July 1, 1997 Portland General Corporation (PGC), the former parent of
PGE, merged with Enron Corp. (Enron) with Enron continuing in existence as
the surviving corporation. PGE is currently a wholly owned subsidiary of
Enron and subject to control by the Board of Directors of Enron. PGE is
engaged in the generation, purchase, transmission, distribution, and sale
of electricity in the State of Oregon. PGE also sells energy to wholesale
customers, predominately utilities, marketers and brokers throughout the
western United States. PGE's Oregon service area is 3,170 square miles,
including 54 incorporated cities, of which Portland and Salem are the
largest, within a state-approved service area allocation of 4,070 square
miles. At the end of 1999, PGE's service area population was approximately
1.5 million, comprising about 44% of the state's population and serving
approximately 719,000 customers.
On November 8, 1999, Enron announced that it had entered into a purchase
and sale agreement to sell PGE to Sierra Pacific Resources (Sierra) for
$2.1 billion, comprised of $2.02 billion in cash and the assumption of
Enron's approximately $80 million merger payment obligation. The proposed
transaction, which is subject to regulatory approval, is expected to close
in late 2000.
On January 18, 2000, Sierra filed with the OPUC an application to acquire
PGE. On February 3, 2000, Sierra filed with the SEC an application to
acquire PGE and also to become a registered public utility holding company.
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
CONSOLIDATION PRINCIPLES
The consolidated financial statements include the accounts of PGE and its
majority-owned subsidiaries. Intercompany balances and transactions have
been eliminated.
BASIS OF ACCOUNTING
PGE and its subsidiaries' financial statements conform to accounting
principles generally accepted in the United States. In addition, PGE's
accounting policies are in accordance with the requirements and the rate
making practices of regulatory authorities having jurisdiction. PGE's
consolidated financial statements do not reflect an allocation of the
purchase price that was recorded by Enron as a result of the PGC merger.
USE OF ESTIMATES
The preparation of financial statements requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities at the date of the financial statements and the reported
amounts of revenues and expenses during the reporting period. Actual
results could differ from those estimates.
RECLASSIFICATIONS
Certain amounts in prior years have been reclassified for comparative
purposes.
REVENUES
PGE accrues estimated unbilled revenues for services provided from the
meter read date to month-end.
PURCHASED POWER
PGE credits purchased power costs for the benefits received through a power
purchase and sale contract with the BPA. Reductions in purchased power
costs that result from this exchange are passed directly to PGE's
residential and small farm customers in the form of lower prices. PGE and
the BPA reached a new agreement in September 1998, which will continue to
provide benefits to PGE's residential and small farm customers through at
least June 30, 2001.
DEPRECIATION
PGE's depreciation is computed on the straight-line method based on the
estimated average service lives of the various classes of plant in service.
Depreciation expense as a percent of the related average depreciable plant
in service was approximately 4.2% in 1999 and 4.3% in 1998 and 1997.
The cost of renewal and replacement of property units is charged to plant,
while repairs and maintenance costs are charged to expense as incurred.
The cost of utility property units retired, other than land, is charged to
accumulated depreciation.
PGE exercised its option to purchase six leased combustion turbine
generators at the Beaver generating plant for approximately $37 million at
the August 1999 termination of the lease. No gain or loss was recognized
on this transaction.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFDC)
AFDC represents the pre tax cost of borrowed funds used for construction
purposes and a reasonable rate for equity funds. AFDC is capitalized as
part of the cost of plant and is credited to income but does not represent
current cash earnings. The average rate used by PGE was 5.3%.
INCOME TAXES
PGE's federal income taxes are a part of its parent company's consolidated
federal income tax return. PGE pays for its tax liabilities when it
generates taxable income and is reimbursed for its tax benefits by the
parent company on a stand-alone basis. Deferred income taxes are provided
for temporary differences between financial and income tax reporting.
Amounts recorded for Investment Tax Credits (ITC) have been deferred and
are being amortized to income over the approximate lives of the related
properties, not to exceed 25 years. See Note 3, Income Taxes, for more
details.
CASH AND CASH EQUIVALENTS
Highly liquid investments with original maturities of three months or less
are classified as cash equivalents.
REGULATORY ASSETS AND LIABILITIES
The Company is subject to the provisions of Statement of Financial
Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain
Types of Regulation". When the requirements of SFAS No. 71 are met, PGE
defers certain costs, which would otherwise be charged to expense if it is
probable that future prices will permit recovery of such costs. In
addition, PGE defers certain revenues, gains, or cost reductions which
would normally be reflected in income but through the rate making process
ultimately will be refunded to customers. Regulatory assets and liabilities
reflected as deferred charges and other liabilities in the financial
statements are amortized over the period in which they are included in
billings to customers.
Amounts in the Consolidated Balance Sheets as of December 31 relate to the
following:
1999 1998
(millions of dollars)
Unamortized regulatory assets:
Trojan-related $398 $438
Income taxes recoverable 165 165
Debt reacquisition costs 23 25
Conservation investments - secured 61 64
Energy efficiency programs 22 21
Miscellaneous 22 18
Total $691 $731
Unamortized regulatory liabilities:
Deferred gain on SCE termination $ 81 $ 92
Merger payment obligation 88 96
Miscellaneous 28 49
Total $197 $237
As of December 31, 1999, a majority of the Company's regulatory assets and
liabilities are being reflected in rates charged to customers. Based on
rates in place at year-end 1999, the Company estimates that it will collect
substantially all of its regulatory assets within the next 12 years.
CONSERVATION INVESTMENTS - SECURED - In 1996, $81 million of PGE's energy
efficiency investment was designated as Bondable Conservation Investment
upon PGE's issuance of 10-year 6.91% Conservation Bonds collateralized by
OPUC-assured future revenues. These bonds provide savings to customers
while granting PGE immediate recovery of its prior energy efficiency
program expenditures. Revenues collected from customers fund the debt
service obligation on the conservation bonds. At December 31, 1999, the
outstanding balance on the bonds was $61 million.
DEFERRED GAIN ON SOUTHERN CALIFORNIA EDISON COMPANY (SCE) TERMINATION - In
1996, PGE and SCE entered into a termination agreement for the Power Sales
Agreement between the two companies. The agreement requires that SCE pay
PGE $141 million over 6 years ($15 million per year in 1997 through 1999
and $32 million per year in 2000 through 2002). The gain is being
recognized in income consistent with current rate making treatment.
MERGER PAYMENT OBLIGATION - Pursuant to the Enron/PGC merger agreement, PGE
customers are guaranteed $105 million in compensation and benefits, payable
over an eight-year period, in the form of reduced prices. These benefits
are being paid by Enron, received by PGE, and passed on to PGE's retail
customers.
NOTE 2 - EMPLOYEE BENEFITS
PENSION AND OTHER POST-RETIREMENT PLANS
PGE participates in a non-contributory defined benefit pension plan (the
Plan) with other affiliated companies. Substantially all of the plan
members are current or former PGE employees. The plan's assets are held in
a trust.
PGE also participates in non-contributory post-retirement health and life
insurance plans ("Other Benefits" below). Employees are covered under a
Defined Dollar Medical Benefit Plan which limits PGE's obligation by
establishing a maximum contribution per employee. Contributions are made
to a voluntary employee's beneficiary association to fund these plans.
The following table provides a reconciliation of the changes in the plans'
benefit obligations and fair value of plans' assets, a statement of the
funded status, and components of net periodic pension expense (in
millions):
PENSION BENEFITS OTHER BENEFITS
1999 1998 1999 1998
RECONCILIATION OF BENEFIT
OBLIGATION:
Obligation at January 1 $284 $254 $ 29 $ 26
Service cost 8 7 1 0
Interest cost 20 18 2 2
Plan amendments 6 - - -
Curtailments(a) (8) - - -
Participants' contributions - - - 1
Actuarial loss (gain) (25) 18 (1) 2
Benefit payments (18) (13) (2) (2)
Obligation at December 31 $267 $284 $ 29 $ 29
RECONCILIATION OF FAIR VALUE OF PLAN ASSETS:
Fair value of plan assets
at January 1 $401 $375 $ 33 $ 32
Actual return on plan assets 55 38 3 1
Participants' contributions - - 1 1
Company contributions 1 1 - 1
Benefit payments (18) (13) (2) (2)
Fair value of plan assets at
December 31 $439 $401 $ 35 $ 33
FUNDED STATUS:
Funded status at December 31 $172 $117 $ 6 $ 4
Unrecognized transition (asset) (9) (11) 4 4
Unrecognized prior service cost 13 11 2 2
Unrecognized gain (162) (117) (13) (10)
Prepaid Pension Cost $ 14 $ 0 $ (1) $ 0
ASSUMPTIONS:
Discount rate used to calculate
benefit obligation 7.75% 6.75% 7.75% 6.75%
Rate of increase in future
compensation levels 4.0 - 9.5% 4.0-9.5% 4.0-9.5% 4.0-9.5%
Long-term rate of return
on assets 9.00% 9.00% 9.50% 9.50%
COMPONENTS OF NET PERIODIC PENSION EXPENSE:
Service cost $ 8 $ 7 $ 1 $ 1
Interest cost on benefit
obligation 20 18 2 2
Expected return on plan assets (31) (28) (2) (2)
Amortization of transition asset (2) (2) - -
Amortization of prior service
cost 1 1 - -
Recognized gain (3) (3) (1) (1)
Effect of curtailment(a) (5) - - -
Net periodic pension
(benefit) $ (12) $ (7) $ 0 $ 0
(a). Represents one-time nonrecurring event associated with certain union
employees ceasing participation in the pension plan as a result of union
negotiations.
Included in the above Pension Benefits amounts are the unfunded obligations
for the supplemental executive retirement plan. At December 31, 1999 and
1998, respectively, the projected benefit obligation for this plan was $12
million and $13 million.
For measurement purposes, a 10.0% annual rate of increase in the per capita
cost of covered health care benefits was assumed for 2000. The rate was
assumed to decrease .5% per year to 5.0% in 2010 and remain at that level
thereafter. Assumed health care cost trend rates have a significant effect
on the amounts reported for the health care plans. A one-percentage point
change in assumed health care cost trend rates would have the following
effects (in millions):
1-Percentage 1-Percentage
POINT POINT
INCREASE DECREASE
Effect on total of service and
interest cost components $0.1 $(0.1)
Effect on post-retirement benefit
obligation $0.8 $(0.8)
DEFERRED COMPENSATION
PGE provides certain employees with benefits under an unfunded Management
Deferred Compensation Plan (MDCP). Obligations for the MDCP were $34
million and $29 million at December 31, 1999 and 1998, respectively.
EMPLOYEE STOCK OWNERSHIP PLAN
PGE participated in the PGH Retirement Savings Plan through June 30, 1999.
On July 1, 1999, the plan merged into the Enron Savings Plan and PGE
continued participation. The successor plan includes an Employee Stock
Ownership Plan (ESOP). One-half of employee contributions up to 6% of base
pay are matched by employer contributions in the form of Enron common
stock.
ALL EMPLOYEE STOCK OPTION PLAN
Enron stock options were granted to PGE employees on December 31, 1997. The
options were granted at the fair value of the stock at the date of the
grant. One-third of the options vested in 1998, one-third vested in 1999,
and one-third will vest in 2000. PGE pays Enron the estimated value of the
shares vesting each year. The fair value of shares that vested in 1999 and
1998 were $4 million and $5 million, respectively. It is estimated that
shares valued at $4 million will vest in 2000. The value is calculated
using the Black-Scholes option-pricing model.
NOTE 3 - INCOME TAXES
The following table shows the detail of taxes on income and the items used
in computing the differences between the statutory federal income tax rate
and PGE's effective tax rate (millions of dollars):
1999 1998 1997
Income Tax Expense
Currently payable
Federal $ 78 $ 75 $114
State and local 16 13 14
94 88 128
Deferred income taxes
Federal (1) (1) (45)
State and local 2 (1) (9)
1 (2) (54)
Investment tax credit adjustments (4) (4) (4)
$ 91 $ 82 $ 70
Provision Allocated to:
Operations $ 84 $ 81 $ 83
Other income and deductions 7 1 (13)
$ 91 $ 82 $ 70
Effective Tax Rate Computation:
Computed tax based on statutory federal
income tax ratesapplied to income before
income taxes $ 77 $ 77 $ 69
Flow through depreciation 7 4 6
State and local taxes - net 11 7 13
State of Oregon refund - - (9)
Investment tax credits (4) (4) (4)
Excess deferred tax (1) (1) (1)
Other 1 (1) (4)
$ 91 $ 82 $ 70
Effective tax rate 41.5% 37.5% 35.7%
As of December 31, 1999 and 1998, the significant components of PGE's
deferred income tax assets and liabilities were as follows (millions of
dollars):
1999 1998
DEFERRED TAX ASSETS
Depreciation and amortization $ 24 $ 27
SCE termination payment 36 42
Other regulatory liabilities 15 14
Employee fringe benefits 15 15
Other 5 4
95 102
DEFERRED TAX LIABILITIES
Depreciation and amortization $(356) $(378)
Price risk management (9) (9)
Trojan abandonment (55) (56)
Other regulatory assets (16) (3)
Other (10) (7)
(446) (453)
Total $(351) $(351)
PGE has recorded deferred tax assets and liabilities for all temporary
differences between the financial statement basis and tax basis of assets
and liabilities.
NOTE 4 - COMMON AND PREFERRED STOCK
COMMON STOCK CUMULATIVE PREFERRED
NUMBER $3.75 PAR NUMBER NO- PAR PAID-IN
(millions of dollars OF SHARES VALUE OF SHARES VALUE CAPITAL
except share amounts)
December 31, 1997 42,758,877 $160 300,000 $30 $480
December 31, 1998 42,758,877 160 300,000 30 480
December 31, 1999 42,758,877 160 300,000 30 480
CUMULATIVE PREFERRED STOCK
PGE has authorized 30 million shares of cumulative preferred stock, no par
value; there are 300,000 shares of the 7.75% series outstanding. The 7.75%
series preferred stock has an annual sinking fund requirement, which
requires the redemption of 15,000 shares at $100 per share beginning in
2002. At its option, PGE may redeem, through the sinking fund, an
additional 15,000 shares each year. All remaining shares shall be
mandatorily redeemed by sinking fund in 2007. This series is only
redeemable by operation of the sinking fund.
No dividends may be paid on common stock or any class of stock over which
the preferred stock has priority unless all amounts required to be paid for
dividends and sinking fund payments have been paid or set aside,
respectively.
COMMON DIVIDEND RESTRICTION OF SUBSIDIARY
Enron is the sole shareholder of PGE common stock. PGE is restricted from
paying dividends or making other distributions to Enron without prior OPUC
approval to the extent such payment or distribution would reduce PGE's
common stock equity capital below 48% of its total capitalization.
NOTE 5 - CREDIT FACILITIES AND DEBT
At December 31, 1999, PGE had committed lines of credit totaling $300
million. Credit lines of $200 million, with an annual fee of 0.10%, expire
in July 2000; credit lines of $100 million, with an annual fee of 0.125%,
expire in August 2000. These lines of credit, which do not require
compensating cash balances, are used primarily as backup for both
commercial paper and borrowings from commercial banks under uncommitted
lines of credit.
Unused committed lines of credit must be at least equal to the amount of
PGE's commercial paper outstanding. Commercial paper and lines of credit
borrowings are at rates reflecting current market conditions.
Short-term borrowings and related interest rates were as follows:
1999 1998
(millions of dollars)
AS OF YEAR-END
Aggregate short-term debt outstanding
Commercial paper $266 $105
Weighted average interest rate*
Commercial paper 6.1% 5.2%
Committed lines of credit $300 $200
FOR THE YEAR ENDED:
Average daily amounts of short-term
debt outstanding
Commercial paper $162 $113
Weighted daily average interest rate*
Commercial paper 5.5% 5.4%
Maximum amount outstanding during the year $266 $144
* Interest rates exclude the effect of commitment fees, facility fees
and other financing fees.
The Indenture securing PGE's First Mortgage Bonds constitutes a direct
first mortgage lien on substantially all utility property and franchises,
other than expressly excepted property.
Schedule of long-term debt at December 31 1999 1998
(millions of dollars)
First Mortgage Bonds
Maturing 1999 - 2004 6.47% - 8.88% $ 170 $ 219
Maturing 2005 - 2008 7.15% - 9.07% 68 113
Maturing 2021 - 2023 7.75% - 9.46% 160 170
398 502
Pollution Control Bonds
Port of Morrow, Oregon, variable rate,
due 2013 & 2031 (Average rate 3.4% for
1999, 3.5% for 1998) 6 6
Port of Morrow, Oregon, variable rate,
due 2031 & 2033 (4.60% fixed rate to 2003) 23 23
City of Forsyth, Montana, variable rate, due
2033 (4.60%-4.75% fixed rate to 2003) 119 119
Port of St. Helens, Oregon, variable rate due
2010 & 2014 (4.80% - 5.25% fixed rate to 2003) 47 47
Port of St. Helens, Oregon, due 2014 (7.13%
fixed rate) 5 5
200 200
Other
8.25% Junior Subordinated Deferrable Interest
Debentures, due December 31, 2035 75 75
6.91% Conservation Bonds maturing monthly to 2006 61 68
Capital lease obligations - 1
Unamortized debt discounts (1) -
135 143
733 846
Long-term debt due within one year (32) (102)
Total long-term debt $ 701 $ 744
The following principal amounts of long-term debt (excluding commercial
paper) become due through regular maturities (millions of dollars):
2000 2001 2002 2003 2004
Maturities:
PGE $32 $53 $23 $49 $55
NOTE 6 - OTHER FINANCIAL INSTRUMENTS
FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value
of each class of financial instrument for which it is practical to estimate
that value.
CASH AND CASH EQUIVALENTS - The carrying amount of cash and cash
equivalents approximates fair value because of the short maturity of those
instruments.
OTHER INVESTMENTS - Other investments approximate market value.
REDEEMABLE PREFERRED STOCK - The fair value of redeemable preferred stock
is based on quoted market prices.
LONG-TERM DEBT - The fair value of long-term debt is estimated based on the
quoted market prices for the same or similar issues or on the current rates
offered to PGE for debt of similar remaining maturities.
INTEREST RATE SWAPS - At December 31, 1998, PGE had entered into interest
rate swap agreements with a notional principal amount of $142 million to
manage interest rate exposure. In March 1999, PGE cancelled these
agreements; the amount received at cancellation was not material.
The estimated fair values of debt and equity instruments are as follows
(millions of dollars):
1999 1998
Carrying Fair Carrying Fair
Amount Value Amount Value
Preferred stock subject to mandatory
redemption $ 30 $ 32 $ 30 $ 35
Long-term debt including
current maturities $734 $714 $845 $892
Interest rate swaps in net
receivable position $ - $ - $ - $ 1
NOTE 7 - COMMITMENTS
NATURAL GAS AGREEMENTS
PGE has long-term agreements for transmission of natural gas from domestic
and Canadian sources to natural gas-fired generating facilities. The
agreements provide firm pipeline capacity. Under the terms of these
agreements, PGE is committed to paying capacity charges of approximately
$15 million annually in 2000 through 2004 and $107 million over the
remaining years of the contracts. PGE's capacity payments amounted to $16
million in 1999 and 1998, and $16 million in 1997. These contracts expire
at varying dates from 2001 to 2015. PGE has the right to assign unused
capacity to other parties.
PURCHASE COMMITMENTS
Certain commitments have been made related to capital expenditures planned
for 2000. Obligations related to these expenditures totaled $8 million as
of December 31, 1999. Cancellation of these purchase agreements could
result in cancellation charges. In addition, PGE is committed to its hydro
relicensing efforts, and has certain obligations related to these projects.
PURCHASED POWER
PGE has long-term power purchase contracts with certain public utility
districts in the state of Washington and with the City of Portland, Oregon.
PGE is required to pay its proportionate share of the operating and debt
service costs of the hydro projects whether or not they are operable.
Selected information is summarized as follows (millions of dollars):
ROCKY PRIEST PORTLAND
REACH RAPIDS WANAPUM WELLS HYDRO
Revenue bonds
outstanding at
December 31, 1999 $229 $169 $186 $183 $ 33
PGE's current share of:
Output 12.0% 13.9% 18.7% 20.3% 100%
Net capability
(megawatts) 154 131 194 171 36
Annual cost, including debt service:
1999 $ 6 $ 4 $ 6 $ 6 $ 4
1998 6 4 6 6 4
1997 7 3 4 6 4
Contract expiration
date 2011 2005 2009 2018 2017
PGE's share of debt service costs, excluding interest, will be
approximately $6 million for 2000, $7 million for 2001 through 2002, $8
million for 2003, and $7 million for 2004. The minimum payments through
the remainder of the contracts are estimated to total $66 million.
PGE has entered into long-term contracts to purchase power from other
utilities in the region. These contracts will require fixed payments of up
to $20 million in 2000 and $19 million in 2001 through 2003. After that
date, capacity contract charges will average $19 million annually until
2016. Long-term contract payments amounted to $22 million in 1999, $22
million in 1998, and $23 million in 1997.
LEASES
PGE has operating lease arrangements for its headquarters complex,
coal-handling facilities and certain railroad cars for Boardman. PGE's
aggregate rental payments charged to expense totaled $24 million in 1999,
$23 million in 1998, and $24 million in 1997.
Future minimum lease payments under non-cancelable leases are as follows
(millions of dollars):
YEAR ENDING OPERATING LEASES
DECEMBER 31 (NET OF SUBLEASE RENTALS)
2000 $ 20
2001 20
2002 10
2003 10
2004 10
Remainder 157
Total $227
Included in the future minimum operating lease payments schedule above is
approximately $109 million for PGE's headquarters complex.
NOTE 8 - PROPERTY DIVIDEND
During 1997, PGE transferred its rights and certain obligations under the
WNP-3 Settlement Exchange Agreement (WSA) and the long-term power sale
agreement with the Western Area Power Administration (WAPA) to Enron in the
form of a special non-cash dividend.
NOTE 9 - JOINTLY OWNED PLANT
At December 31, 1999, PGE had the following investments in jointly owned
generating plants (millions of dollars):
MW PGE % PLANT ACCUMULATED
FACILITY LOCATION FUEL CAPACITY INTEREST IN SERVICE DEPRECIATION
Boardman Boardman,OR Coal 561 65.0 $381 $221
Colstrip
3&4 Colstrip,MT Coal 1,556 20.0 455 250
The dollar amounts in the table above represent PGE's share of each jointly
owned plant. Each participant in the above generating plants has provided
its own financing. PGE's share of the direct expenses of these plants is
included in the corresponding operating expenses on PGE's consolidated
income statements.
NOTE 10 - LEGAL MATTERS
TROJAN INVESTMENT RECOVERY - On June 24, 1998, the Oregon Court of Appeals
ruled that the OPUC does not have the authority to allow PGE to recover a
rate of return on its undepreciated investment in the Trojan generating
facility. The court upheld the OPUC's authorization of PGE's recovery of
its undepreciated investment in Trojan.
The Court of Appeals decision was a result of combined appeals from earlier
circuit court rulings. In April 1996, a Marion County Circuit Court judge
ruled that the OPUC could not authorize PGE to collect a return on its
undepreciated investment in Trojan, contradicting a November 1994 ruling
from the same court upholding the OPUC's authority. The 1996 ruling was
the result of an appeal of PGE's 1995 general rate order, which granted PGE
recovery of, and a return on, 87% of its remaining investment in Trojan.
On August 26, 1998, PGE and the OPUC filed a petition for review with the
Oregon Supreme Court, supported by amicus briefs filed by three other major
utilities seeking review of that portion of the Oregon Court of Appeals
decision relating to PGE's return on its undepreciated investment in Trojan
Also on August 26, 1998, the Utility Reform Project filed a petition for
review with the Oregon Supreme Court seeking review of that portion of the
Oregon Court of Appeals decision relating to PGE's recovery of its
undepreciated investment in Trojan.
On April 29, 1999, the Oregon Supreme Court accepted the petitions for
review of the June 24, 1998, Oregon Court of Appeals decision.
On June 16, 1999, Oregon's governor signed Oregon House Bill 3220
authorizing the OPUC to allow recovery of a return on the undepreciated
investment in property retired from service. One of the effects of the
bill is to affirm retroactively the OPUC's authority to allow PGE's
recovery of a return on its undepreciated investment in the Trojan
generating facility.
Relying on the new legislation, on July 2, 1999, the Company requested the
Oregon Supreme Court to vacate the June 24, 1998, adverse ruling of the
Oregon Court of Appeals and affirm the validity of the OPUC's order
allowing PGE to recover a return on its undepreciated investment in Trojan.
The Utility Reform Project and the Citizens Utility Board, another party to
the proceeding, opposed such request on the ground that an effort was
underway to gather sufficient signatures to place on the ballot a
referendum to negate the new legislation; such effort by the referendum's
sponsors was successful and the referendum will appear on the November 2000
ballot. The Oregon Supreme Court has stated it will hold its review of the
Court of Appeals decision in abeyance until after the election.
At December 31, 1999, PGE's after-tax Trojan plant investment was $147
million. PGE is presently collecting annual revenues of approximately $18
million, representing a return on its undepreciated investment. Revenue
amounts reflecting a recovery of a return on the Trojan investment decline
through the recovery period, which ends in the year 2011.
Management believes that the ultimate outcome of this matter will not have
a material adverse impact on the financial condition of the Company.
However, it may have a material impact on the results of operations for a
future reporting period.
OTHER LEGAL MATTERS - PGE is party to various other claims, legal actions
and complaints arising in the ordinary course of business. These claims
are not considered material.
NOTE 11 - TROJAN NUCLEAR PLANT
PLANT SHUTDOWN AND TRANSITION COSTS - PGE is a 67.5% owner of Trojan. In
early 1993, PGE ceased commercial operation of the nuclear plant. Since
plant closure, PGE has committed itself to a safe and economical transition
toward a decommissioned plant. Transition costs associated with operating
and maintaining the spent fuel pool and securing the plant until fuel is
transferred to dry storage will be paid from current operating funds.
Delays have extended the expected completion date of transferring the fuel
to dry storage through 2002.
DECOMMISSIONING - In December 1997, PGE filed an updated decommissioning
plan estimate with the OPUC. The plan estimates PGE's cost to decommission
Trojan at $339 million reflected in nominal dollars (actual dollars
expected to be spent in each year). The primary reason for the reduction
from the $351 million estimated in 1994 is a lower inflation rate, coupled
with the acceleration of certain decommissioning activities and partially
offset by cost increases related to the spent fuel storage project. The
current estimate assumes that the majority of decommissioning activities
will occur between 1998 and 2004, while fuel management costs extend
through the year 2018. The original plan represents a site-specific
decommissioning estimate performed for Trojan by an engineering firm
experienced in estimating the cost of decommissioning nuclear plants.
Updates to the plan's original estimate have been prepared by PGE. Final
site restoration activities are anticipated to begin in 2018 after PGE
completes shipment of spent fuel to a USDOE facility (see the Nuclear Fuel
Disposal discussion below). Stated in 1999 dollars, the decommissioning
cost estimate is $297 million.
TROJAN DECOMMISSIONING LIABILITY
(millions of dollars)
Estimate - 12/31/94 $351
Updates filed with NRC - 11/16/95 7
Updates filed with OPUC - 12/01/97 (19)
339
Expenditures through 12/31/99 (114)
Liability - 12/31/99 225
Transition costs 9
Total Trojan obligations $234
PGE is collecting $14 million annually through 2011 from customers for
decommissioning costs. These amounts are deposited in an external trust
fund, which is limited to reimbursing PGE for activities covered in
Trojan's decommissioning plan. Funds were withdrawn during 1999 to cover
the costs of general decommissioning and activities in support of the
independent spent fuel storage installation and the reactor vessel and
internals removal project. Decommissioning funds are invested in
investment-grade preferred stock, tax-exempt bonds, and U.S. Treasury
bonds. Due to an increase in market interest rates during 1999, the market
value of trust investments declined, resulting in no investment gain for
the year. Year-end balances are valued at market.
DECOMMISSIONING TRUST ACTIVITY
(millions of dollars)
1999 1998
Beginning Balance $72 $84
Activity
Contributions 14 14
Gain 0 4
Disbursements (44) (30)
Ending Balance $42 $72
Earnings on the trust fund are used to reduce the amount of decommissioning
costs to be collected from customers. PGE expects any future changes in
estimated decommissioning costs to be incorporated in future revenues to be
collected from customers.
NUCLEAR FUEL DISPOSAL AND CLEANUP OF FEDERAL PLANTS - PGE contracted with
the USDOE for permanent disposal of its spent nuclear fuel in federal
facilities at a cost of 0.1 per net kilowatt-hour sold at Trojan
which the Company paid during the period the plant operated. Significant
delays are expected in the USDOE acceptance schedule of spent fuel from
domestic utilities. The federal repository, which was originally scheduled
to begin operations in 1998, is now estimated to commence operations no
earlier than 2010. This may create difficulties for PGE in disposing of
its high-level radioactive waste by 2018. However, federal legislation has
been introduced which, if passed, would require USDOE to provide interim
storage for high-level waste until a permanent site is established. PGE
intends to build an interim storage facility at Trojan to house the nuclear
fuel until a federal site is available.
The Energy Policy Act of 1992 provided for the creation of a
Decontamination and Decommissioning Fund to finance the cleanup of USDOE
gas diffusion plants. Funding comes from domestic nuclear utilities and
the federal government. Each utility contributes based on the ratio of the
amount of enrichment services the utility purchased to the total amount of
enrichment services purchased by all domestic utilities prior to the
enactment of the legislation. Based on Trojan's 1.1% usage of total
industry enrichment services, PGE's portion of the funding requirement is
approximately $17 million. Amounts are funded over 15 years beginning with
the USDOE's fiscal year 1993. Since enactment, PGE has made the first
seven of the 15 annual payments with the first payment made in September
1993.
NUCLEAR INSURANCE - The Price-Anderson Amendment of 1988 limits public
liability claims that could arise from a nuclear incident and provides for
loss sharing among all owners of nuclear reactor licenses. Because Trojan
has been permanently defueled, the NRC has exempted PGE from participation
in the secondary financial protection pool covering losses in excess of
$200 million at other nuclear plants. In addition, the NRC has reduced the
required primary nuclear insurance coverage for Trojan from $200 million to
$100 million following a 3 year cool-down period of the nuclear fuel that
is still on-site. The NRC has allowed PGE to self-insure for on-site
decontamination. PGE continues to carry non-contamination property
insurance on the Trojan plant at the $158 million level.
NOTE 12 - RELATED PARTY TRANSACTIONS
As part of its ongoing operations, PGE receives management services from
Enron and provides incidental services to Enron and its affiliated
companies. In 1999, approximately $23 million was paid to Enron for
allocated overhead and other direct costs, including PGE's $4 million share
of the Employee Stock Option Plan. In 1998, PGE paid $17 million to Enron
for management services, including $5 million for employee stock options;
in 1997, PGE paid $2 million to Enron for management services.
In 1999, PGE entered into an agreement to transfer corporate owned life
insurance investments, totaling $21 million, to an Enron affiliate. PGE
accrues interest on the accounts receivable balance at 9.5 percent per
annum. In 1998, PGE had $18 million in accounts receivable from affiliates
related to income tax settlements.
QUARTERLY COMPARISON FOR 1999 AND 1998 (UNAUDITED)
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 TOTAL
(MILLIONS OF DOLLARS)
1999
Operating revenues $299 $294 $408 $377 $1,378
Net operating income 58 40 39 53 190
Net income 45 26 24 33 128
Income available for
common stock 44 25 24 33 126
1998
Operating revenues $314 $260 $274 $328 $1,176
Net operating income 52 42 41 65 200
Net income 37 24 26 50 137
Income available for
common stock 36 25 25 49 135
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
DIRECTORS OF THE REGISTRANT (*)
JAMES V. DERRICK, JR., age 55 Director since 1997
Mr. Derrick has served as Executive Vice President and General Counsel of
Enron since July, 1999 and as Senior Vice President and General Counsel
from June 1991 until July 1999. Prior to joining Enron in 1991, Mr.
Derrick was a partner at the law firm of Vinson & Elkins L.L.P. for over
13 years.
PEGGY Y. FOWLER, age 48 Director since 1998
Ms. Fowler has served as President of Portland General Electric Company
since 1997. Served as Executive Vice President and Chief Operating
Officer of Portland General Electric from November, 1996 until appointed
to current position. Ms. Fowler also serves on the boards of George Fox
University, Goodwill Industries, Legacy Health System, and Life Wise, A
Premera Health Plan, Inc.
KEN L. HARRISON, age 57 Director since 1987
Mr. Harrison serves as a Director of Enron and has served as
Chairman and Chief Executive Officer of Portland General Electric Company
since 1988. Mr. Harrison is also a Director of Enron Broadband Services.
KENNETH L. LAY, age 57 Director since 1997
Mr. Lay has served as Chairman of the Board and Chief Executive Officer of
Enron since February, 1986. Mr. Lay is also a Director of Eli Lilly and
Company, Compaq Computer Corporation, EOTT Energy Corp. (the general
partner of EOTT Energy Partners, L.P.), Azurix Corp., and Trust Company of
the West.
JEFFREY K. SKILLING, age 46 Director since 1997
Since January 1, 1997, Mr. Skilling has served as President and Chief
Operating Officer of Enron. From June, 1995 until December, 1996, he
served as Chief Executive Officer and Managing Director of Enron North
America Corp. ("ENA"). From August, 1990 until June, 1995, Mr. Skilling
served ENA in a variety of senior managerial positions. Mr. Skilling is
also a director of Azurix Corp., Aquarion Company, TECO Energy, Inc.,
Hubbell, Inc., The Weir Group, PLC and Catalytica Inc.
(*) Directors of PGE hold office until the next annual meeting of
shareholders or until their respective successors are duly elected and
qualified.
EXECUTIVE OFFICERS OF THE REGISTRANT (*)
NAME AGE Business Experience
Ken L. Harrison 57 Appointed to current position of Chairman and Chief
Chairman and Executive Officer on December 7, 1988.
Chief Executive
Officer
Peggy Y. Fowler 48 Appointed to current position on June 24, 1997. Served
President and as Executive Vice President and Chief Operating Officer,
Chief Operating PGE from November, 1996 until appointed to current
Officer position. Served as Senior Vice President, Customer
Service and Delivery from September, 1995 until November,
1996. Served as Vice President, Distribution and Power
Production from January, 1990 to September, 1995.
Alvin L. Alexanderson
Senior Vice 52 Appointed to current position on December 12, 1995.
President, General Served as Vice President, Rates and Regulatory Affairs
Counsel and from February, 1991 until appointed to current position.
Secretary
Frederick D. Miller
Senior Vice 57 Appointed to current position on November 5, 1996.
President Served as Vice President, Public Affairs and Corporate
Public Policy and Services from October until November, 1996. Served as
Administrative Director of Executive Department, State of Oregon, from
Services 1987 until October, 1992.
Walter E. Pollock
Senior Vice 57 Appointed to current position on October 14, 1997.
President Served as Vice President, Enron Capital and Trade and
Power Supply Senior Vice President, First Point Utility Solutions from
November, 1996 until appointed to current position.
Served as Group Vice President, Marketing Conservation
and Production at Bonneville Power Administration (BPA)
from April, 1994 to November, 1996.
Arleen N. Barnett
Vice President 47 Appointed to current position on February 1, 1998.
Human Resources Served as Manager, Generating Division from 1987 to 1989
and Manager, Human Resources Operations from 1989 until
appointed to current position.
David K. Carboneau
Vice President 53 Appointed to current position in October, 1998. Served
Retail Services as President of First Point Utility Solutions until
appointed to current position. Served as Vice President,
Utility Service and Telecommunications from January, 1997
until July, 1997. Served as Vice President, Information
Technology from January, 1996 until January, 1997.
Served as Vice President, Thermal and Power Operations
from September, 1995 to January, 1996. Served as Vice
President, PGE Administration from October, 1992 to
September, 1995.
Stephen R. Hawke
Vice President 50 Appointed to current position on July 1, 1997. Served as
Delivery System General Manager, System Planning and Engineering until
Planning and appointed to current position. Served as Manager,
Engineering Response and Restoration from May, 1993 until May, 1995.
EXECUTIVE OFFICERS OF THE REGISTRANT (*) - CONTINUED
NAME AGE Business Experience
Ronald W. Johnson
Vice President 49 Appointed to current position May 1, 1999. Joined PGE's
Deputy General Legal Department in 1977. In 1989 became Deputy General
Counsel and Counsel, managing the Legal Department.
Assistant Secretary
Pamela G. Lesh
Vice President 43 Appointed to current position on December 31,1998. Served
Rates and as Vice President, Strategy and Product Management with
Regulatory ConneXt Corp. of Seattle since June, 1997. Previously
Affairs served at PGE as Vice President, Rates and Regulatory
Affairs from November, 1996 to June, 1997. Served as
Director, Regulatory Policy, from August, 1989 to
October, 1996.
Joe A. McArthur
Vice President 52 Appointed to current position on July 1, 1997. Served as
Substation and Manager of Western Region from May, 1996 until appointed
Line Crew to current position. Served as Manager, System Planning
Operations from May, 1995 to May, 1996. Served as Commercial and
Industrial Market Manager from 1993 to 1995.
James J. Piro
Vice President 47 Appointed to current position on February 23, 1998.
Business Served as General Manager, Planning Support and
Development Analysis from November, 1992 until appointed to current
position.
Stephen M. Quennoz
Vice President 52 Appointed to current position in October, 1998. Joined
Nuclear and PGE in 1991 and held the position of Trojan Site
Thermal Executive and Plant General Manager since 1993.
Operations
Christopher D. Ryder
Vice President 50 Appointed to current position on July 1, 1997. Served as
Customer Service General Manager, Customer Services and Southern Region
Delivery Operations from 1996 until appointed to current position.
Served as General Manager, Customer Services, Marketing
and Sales from 1992 to 1996.
Carl B. Talton
Vice President 55 Appointed to current position May 1, 1999. Joined PGE in
Government July, 1998 as Director of Economic Development. Prior to
Affairs and that worked 25 years for PacificCorp, where he held
Economic several management positions.
Development
Mary K. Turina
Vice President, 32 Appointed to current position on September 1,1999. Served
Finance as Controller, Chief Accounting Officer, Treasurer, and
Chief Financial Principal Financial Officer from May, 1999 to September,
Officer and 1999. Served as Controller and Assistant Treasurer from
Treasurer July, 1998 to May, 1999. Served as Manager of Risk
Management, Reporting and Control from March, 1996 to
July, 1998. Served as Senior Business Analyst from
1991 to 1996.
(*) Officers are listed as of February 29, 2000, they are elected for one-
year terms or until their successors are elected and qualified.
ITEM 11. EXECUTIVE COMPENSATION
Summary Compensation Table
The following indicates total compensation earned for the years ended
December 31, 1999, 1998, 1997 by the Chief Executive Officer and the
four most highly compensated executive officers of PGE.
Long-Term
Annual Compensation Compensation
Restricted All Other
Stock
Name and Principal
Position Year Salary(1) Bonus(2) Awards(3) Compensation(4)
Ken L. Harrison (5) 1999 $244,163 $ - $ - $28,959
Chairman, 1998 206,799 183,200 705,483 12,050
Chief Executive 1997 243,570 236,592 204,755 68,051
Officer
Peggy Y. Fowler 1999 267,502 400,000 - 16,646
President and Chief 1998 246,664 300,000 200,004 17,443
Operating Officer 1997 230,000 160,000 230,185 29,406
Walter E. Pollock (6) 1999 189,697 200,000 - 6,575
Senior Vice President, 1998 176,191 140,000 75,037 5,664
Power Supply 1997 37,500 24,000 - 826
Frederick D. Miller 1999 197,708 200,000 - 12,757
Senior Vice President, 1998 181,684 150,000 68,760 10,233
Public Policy and 1997 175,020 105,000 - 48,906
Administrative Services
James J. Piro 1999 169,089 110,000 - 5,874
Vice President, 1998 157,535 128,063 50,043 5,081
Business Development 1997 131,352 140,000 - 7,743
(1) Amounts shown include cash compensation earned and received by the
executive officer, as well as amounts earned but deferred at the
election of the officer.
(2) Bonuses include amounts, if any, converted to stock options and for
phantom stock at the election of the officer.
(3) Restricted stock awards are valued at the closing price of $20.7188 per
share of Enron common stock for the July 1, 1997 grant, which
vested 20% on July 1, 1998, and 20% on each of the following four
anniversaries of the date of grant. Dividend equivalents for the July
1, 1997 grant accrue from the date of grant and are paid upon vesting.
Restricted stock awarded to Mr. Harrison on October 12, 1998 is valued
at the $25.4688 per share closing price of Enron common stock on
that date; one-third of the shares vest on January 31 of each of the
next three years, beginning in 1999. Restricted stock awarded to other
officers was granted December 31, 1998, and is valued at the $28.5313
per share closing price of Enron common stock on that date.
Aggregate restricted stock holdings listed below (including any annual
bonus converted to Phantom stock) are valued at $44.3750 per share, the
closing price of the Enron common stock on December 31, 1999.
AGGREGATE RESTRICTED STOCK HOLDINGS
AGGREGATE SHARES (#) VALUE
Ken L. Harrison 103,886 $4,609,941
Peggy Y. Fowler 21,536 955,660
Walter E. Pollock 4,204 186,553
Frederick D. Miller 6,340 281,338
James J. Piro 2,244 99,578
(4) Other compensation includes: (i) company-paid split dollar insurance
premiums; (ii) the dollar value of life insurance benefits as determined
under the Commission's methodology for valuing such benefits; (iii)
company contributions to the RSP and the MDCP; and (iv) earnings on
amounts in the MDCP which are greater than 120 percent of the federal
long-term rate which was in effect at the time the rate was set.
The following are amounts for 1999:
Split Dollar
Dollar Value of Contributions Above Market
Insurance Life to 401 (k) Interest on
Premiums Insurance MDCP MDCP Total
Ken L. Harrison $ 512 $ - $3,400 $25,047 $28,959
Peggy Y. Fowler 480 6,012 5,828 4,326 16,646
Walter E. Pollock - - 5,382 1,193 6,575
Frederick D. Miller 675 - 5,690 6,392 12,757
James J. Piro - - 4,797 1,077 5,874
(5) Mr. Harrison also served as an executive officer of Enron until July 1,
1999. The compensation shown represents the amount allocated to PGE.
(6) Mr. Pollock became a PGE employee October 1997.
The following lists information concerning options to purchase shares of
Enron common stock that were exercised by the officers named above during
1999 and the total options and their value held by each at December 31,
1999.
Aggregate Stock Options/SAR Exercised During 1999
and Stock Options/SAR Values at December 31, 1999
Shares Acquired Value Exercisable Unexercisable Exercisable Unexercisable
on Exercise Realized Shares Shares Amount Amount
Ken L. Harrison 154,000 $4,370,894 660,272 1,098,628 $9,680,058 $13,623,195
Peggy Y. Fowler 21,274 500,211 19,316 40,586 337,843 840,649
Walter E. Pollock 25,520 477,126 28,476 11,224 603,915 220,610
Frederick D. Miller 20,234 264,676 16,425 22,461 347,479 490,202
James J. Piro - - 78,774 17,640 2,139,891 415,443
Estimated annual retirement benefits payable upon normal retirement at age
65 for the named executive officers are shown in the table below. Amounts
in the table reflect payments from the Portland General Holdings, Inc.
Pension Plan and Supplemental Executive Retirement Plan ("SERP") combined.
Pension Plan Table
Estimated Annual Retirement Benefit
Straight-Life Annuity, Age 65
Final Average Years of Service
Earnings 15 20 25+
$ 175,000 $ 78,750 $ 91,875 $ 105,000
200,000 90,000 105,000 120,000
225,000 101,250 118,125 135,000
250,000 112,500 131,250 150,000
300,000 135,000 157,500 180,000
400,000 180,000 210,000 240,000
500,000 225,000 262,500 300,000
600,000 270,000 315,000 360,000
1,000,000 450,000 525,000 600,000
Compensation used to calculate benefits under the combined Pension Plan and
SERP is based on a three-year average of base salary and bonus amounts
earned (the highest 36 consecutive months within the last 10 years), as
reported in the Summary Compensation Table. SERP participants may retire
without age-based reductions in benefits when their age plus years of
service equals 85. Surviving spouses receive one half the participant's
retirement benefit from the SERP, plus the joint and survivor benefit, if
any, from the Pension Plan. In addition to the aforementioned annual
retirement benefits, an additional temporary Social Security Supplement is
paid until the participant is eligible for social security retirement
benefits. Retirement benefits are not subject to any deduction for social
security.
The following executive officers named in the table are participants in
both plans and have had the following number of service years with the
Company: Ken L. Harrison, 24; Peggy Y. Fowler, 25; Frederick D. Miller, 7.
James J. Piro and Walter E. Pollock are not participants in the SERP, but
do participate in the Pension Plan. Under the Company's SERP, the named
executives are eligible to retire without a reduction in benefits upon
attainment of the following ages: Ken L. Harrison, 59, Peggy Y. Fowler,
55; Frederick D. Miller, 62. Mr. Pollock and Mr. Piro are not participants
in the SERP.
EMPLOYMENT CONTRACTS
Ms. Fowler and Mr. Miller entered into employment agreements on July 1,
1997, the effective date of the merger between Enron and PGC, the former
parent of PGE. The employment agreements generally provide as follows:
(i) each agreement has a term of three years and expires on June 30, 2000;
(ii) each agreement provides for severance pay in the event of involuntary
termination by PGE based on the greater of two years or the remainder of
the term; (iii) the minimum salary for Ms. Fowler is $230,000 and the
minimum salary for Mr. Miller is $175,000 per year; the minimum guaranteed
annual cash incentive per year under such agreements is $115,000 for Ms.
Fowler and $52,500 for Mr. Miller; (iv) Mr. Miller's agreements provide for
the grant of 50,000 options to purchase shares of Enron common stock while
Ms. Fowler's provides for 60,000 options; (v) Mr. Fowler's agreement
provides for the grant of a number of restricted shares of Enron common
stock having a market value equal to such employee's annual base
pay which
will vest over a five year period; (vi) Ms. Fowler's and Mr. Miller's
agreements provide that the failure of PGE and the employee to extend or
enter into a new agreement for two years will be treated as involuntary
termination; (vii) each agreement provides for a supplemental retirement
benefit; (viii) each agreement provides that in the event that the
severance or other payments payable under the agreement for involuntary
termination constitute "excess parachute payments" within the meaning of
Section 280G of the code and the employee becomes liable for any tax
penalties, PGE will pay in cash to the employee an amount equal to such tax
penalties until the amount of the last gross up is less than one hundred
dollars; and (ix) each agreement includes a non-competition covenant.
Mr. Pollock entered into an employment agreement effective November 1,
1996. The agreement extended from the effective date until November 1,
1999, and provides for the following:
1. An initial base pay of $150,000.
2. A guaranteed bonus of 33% of base pay paid in 1996 and 1997, and a bonus
opportunity of 75% in 1998.
3. A grant of 39,300 shares of PGC stock under the Portland General
Corporation amended and restated 1990 Long-Term Master Plan which
converted to Enron common stock upon the merger and vested 100% on
November 4, 1999.
4. Remedy for breach clause, which provides for a payment of one times Mr.
Pollock's salary plus target incentive award if his employment is
terminated plus equivalent medical and dental coverage for 12 months for
Mr. Pollock and his dependents.
5. Noncompete and confidentiality clauses.
Mr. Piro entered into a retention agreement effective January 7, 1997. The
agreement extended two years from the date of the merger between PGC and
Enron and provided for the following:
1. No reduction of base pay during the agreement.
2. 12 months written notification prior to involuntary termination.
3. $10,000 plus one times Mr. Piro's base pay and target incentive in the
event of a breach of the agreement, where a breach is defined as
involuntary termination, diminishment of status, base pay or bonus
opportunity position and/or responsibilities or a requirement that Mr.
Piro relocate outside the Portland, Oregon geographic area without his
written consent. In addition to the payment, the company will provide
Mr. Piro and his dependents with equivalent medical and dental coverage
for up to 12 months.
4. Noncompete and confidentiality clauses.
COMPENSATION OF DIRECTORS
There are no compensation arrangements for or fees paid to Directors of
PGE.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
The Compensation and Management Development Committee of the Enron Board of
Directors is responsible for developing and administering compensation
philosophy. Salary increases, annual
incentive awards and long-term incentive grants are reviewed annually to
ensure consistency with Enron's total compensation philosophy. In 1999,
PGE's Chairman and Chief Executive Officer, Ken L. Harrison, participated
in those deliberations affecting the Company's executive officer
compensation.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
PGE is a wholly owned subsidiary of Enron.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
There are no relationships or transactions involving PGE's directors and
executive officers.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM
8-K
(A) INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
FINANCIAL STATEMENTS
Report of Independent Public Accountants
Consolidated Statements of Income for each of the three years
in the period ended December 31, 1999
Consolidated Statements of Retained Earnings for each of
the three years in the period ended December 31, 1999
Consolidated Balance Sheets at December 31, 1999 and 1998
Consolidated Statement of Cash Flows for each of the three
years in the period ended December 31, 1999
Notes to Financial Statements
FINANCIAL STATEMENT SCHEDULES
Schedules are omitted because of the absence of conditions
under which they are required or because the required
information is given in the financial statements or notes
thereto.
EXHIBITS
See Exhibit Index on Page 66 of this report.
(B) REPORT ON FORM 8-K
None
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be
signed on its behalf by the undersigned, thereunto duly authorized.
Portland General Electric Company
March 2, 2000 By /s/ Ken L. Harrison
Ken L. Harrison
Chairman and
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
/s/ Ken L. Harrison Chairman and
Ken L. Harrison Chief Executive Officer March 2, 2000
Vice President, Finance
/s/ Mary K. Turina Chief Financial Officer March 2, 2000
Mary K. Turina and Treasurer
/s/ Kirk M. Stevens Controller and March 2, 2000
Kirk M. Stevens Assistant Treasurer
*James V. Derrick
*Peggy Y. Fowler
*Ken L. Harrison Directors March 2, 2000
*Kenneth L. Lay
*Jeffrey K. Skilling
*By /s/ Mary K. Turina
(Mary K. Turina, Attorney-in-Fact)
PORTLAND GENERAL ELECTRIC COMPANY AND
SUBSIDIARIES
EXHIBIT INDEX
Number Exhibit
(2) PLAN OF ACQUISITION, REORGANIZATION, ARRANGEMENT, LIQUIDATION OR
SUCCESSION
* Amended and Restated Agreement and Plan of Merger, dated as of
July 20, 1996 and amended and restated as of September 24, 1996
among Enron Corp, Enron Oregon Corp and Portland General
Corporation [Amendment 1 to S4 Registration Nos. 333-13791 and
333-13791-1, dated October 10, 1996, Exhibit No. 2.1].
(3) ARTICLES OF INCORPORATION AND BYLAWS
* Copy of Articles of Incorporation of Portland General Electric
Company [Registration No. 2-85001, Exhibit (4)].
* Certificate of Amendment, dated July 2, 1987, to the Articles of
Incorporation limiting the personal liability of directors of
Portland General Electric Company [Form 10-K for the fiscal year
ended December 31, 1987, Exhibit (3)].
* Bylaws of Portland General Electric Company as amended on October
1, 1991 [Form 10-K for the fiscal year ended December 31, 1991,
Exhibit (3)].
* Bylaws of Portland General Electric Company as amended on May 1,
1998 [Form 10-K for the fiscal year ended December 31, 1998,
Exhibit (3)].
(4) INSTRUMENTS DEFINING THE RIGHTS OF SECURITY HOLDERS, INCLUDING
INDENTURES
* Portland General Electric Company Indenture of Mortgage and Deed
of Trust dated July 1, 1945.
* Fortieth Supplemental Indenture dated October 1, 1990 [Form 10-K
for the fiscal year ended December 31, 1990, Exhibit (4)].
* Forty-First Supplemental Indenture dated December 1, 1991 [Form
10-K for the fiscal year ended December 31, 1991, Exhibit (4)].
* Forty-Second Supplemental Indenture dated April 1, 1993 [Form 10-Q
for the quarter ended March 31,1993, Exhibit (4)].
* Forty-Third Supplemental Indenture dated July 1, 1993 [Form 10-Q
for the quarter ended September 30, 1993, Exhibit (4)].
* Forty-Fifth Supplemental Indenture dated May 1, 1995 [Form 10-Q
for the quarter ended June 30, 1995, Exhibit (4)].
PORTLAND GENERAL ELECTRIC COMPANY AND
SUBSIDIARIES
EXHIBIT INDEX
(4)
CONT
Other instruments, which define the rights of holders of long-term
debt not required to be filed, herein, will be furnished upon
written request.
(10) MATERIAL CONTRACTS
* Residential Purchase and Sale Agreement with the Bonneville Power
Administration [Form 10-K forthe fiscal year ended December 31, 1981,
Exhibit (10)].
* Power Sales Contract and Amendatory Agreement Nos. 1 and 2 with
Bonneville Power Administration [Form 10-K for the fiscal year ended
December 31, 1982, Exhibit (10)].
The following 12 exhibits were filed in conjunction with the 1985
Boardman/Intertie Sale:
* Long-term Power Sale Agreement dated November 5, 1985 [Form 10-K for
the fiscal year ended December 31, 1985, Exhibit (10)].
* Long-term Transmission Service Agreement dated November 5, 1985 [Form
10-K for the fiscal year ended December 31, 1985, Exhibit (10)].
* Participation Agreement dated December 30, 1985 [Form 10-K for the
fiscal year ended December 31, 1985, Exhibit (10)].
* Lease Agreement dated December 30, 1985 [Form 10-K for the fiscal year
ended December 31,1985, Exhibit (10)].
* PGE-Lessee Agreement dated December 30, 1985 [Form 10-K for the fiscal
year ended December 31, 1985, Exhibit (10)].
* Asset Sales Agreement dated December 30, 1985 [Form 10-K for the fiscal
year ended December 31, 1985, Exhibit (10)].
* Bargain and Sale Deed, Bill of Sale, and Grant of Easements and
Licenses, dated December 30, 1985 [Form 10-K for the fiscal year ended
December 31, 1985, Exhibit (10)].
* Supplemental Bill of Sale dated December 30, 1985 [Form 10-K for the
fiscal year ended December 31, 1985, Exhibit (10)].
* Trust Agreement dated December 30, 1985 [Form 10-K for the fiscal year
ended December 31, 1985, Exhibit (10)].
PORTLAND GENERAL ELECTRIC COMPANY AND
SUBSIDIARIES
EXHIBIT INDEX
Number Exhibit
(10)
CONT * Tax Indemnification Agreement dated December 30, 1985 [Form 10-K
for the fiscal year ended December 31, 1985, Exhibit (10)].
* Trust Indenture, Mortgage and Security Agreement dated December 30,1985
[Form 10-K for the fiscal year ended December 31, 1985, Exhibit (10)].
* Restated and Amended Trust Indenture, Mortgage and Security Agreement
dated February 27, 1986 [Form 10-K for the fiscal year ended December
31, 1997, Exhibit (10)].
* Portland General Holdings, Inc. Outside Directors' Deferred
Compensation Plan, 1997 Restatement dated June 25, 1997
[Form 10-K for fiscal year ended December 31, 1997, Exhibit 10].
* Portland General Holdings, Inc. Retirement Plan for Outside Directors,
1997 Restatement dated June 25, 1997 [Form 10-K for fiscal year ended
December 31, 1997, Exhibit 10].
* Portland General Holdings, Inc. Outside Directors' Life Insurance
Benefit Plan, 1997 Restatement dated June 25, 1997 [Form 10-K for
fiscal year ended December 31, 1997, Exhibit 10].
EXECUTIVE COMPENSATION PLANS AND ARRANGEMENTS
* Portland General Holdings, Inc. Management Deferred Compensation
Plan,
1997 Restatement dated June 25, 1997 [Form 10-K for fiscal year
ended December 31, 1997, Exhibit 10].
* Portland General Holdings, Inc. Senior Officers Life Insurance Benefit
Plan, 1997 Restatement Amendment No. 1 dated June 25, 1997 [Form 10-K
for fiscal year ended December 31, 1997, Exhibit 10].
* Portland General Electric Company Annual Incentive MasterPlan [Form
10-K for the fiscal year ended December 31, 1987, Exhibit (10)].
* Portland General Electric Company Annual Incentive Master Plan,
Amendments No. 1 and No. 2 dated March 5, 1990 [Form 10-K for the
fiscal year ended December 31, 1989, Exhibit (10)].
* Portland General Holdings, Inc. Supplemental Executive Retirement
Plan,
1997 Restatement dated June 25, 1997 [Form 10-K for fiscal year
ended December 31, 1997, Exhibit 10].
PORTLAND GENERAL ELECTRIC COMPANY AND
SUBSIDIARIES
EXHIBIT INDEX
Number Exhibit
(24) POWER OF ATTORNEY
Portland General Electric Company Power of Attorney (filed
herewith).
(27) FINANCIAL DATA SCHEDULE
UT (Electronic Filing Only).
* Incorporated by reference as indicated.
Note: The Exhibits furnished to the Securities and Exchange Commission
with the Form 10-K will be supplied upon written request and payment
of a reasonable fee for reproduction costs. Requests should be sent
to:
Kirk M. Stevens
Controller and Assistant Treasurer
Portland General Electric Company
121 SW Salmon Street, 1WTC0501
Portland, OR 97204