UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-K
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/X/ |
ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934 |
OR
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/
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TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934 |
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For
the transition period from ___________ to
___________ |
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Commission
File
Number |
Exact
name of registrant as specified in its charter,
state
of incorporation,
address
of principal executive offices,
telephone
number |
I.R.S.
Employer
Identification
Number |
|
|
PUGET
ENERGY, INC.
A
Washington Corporation
10885
NE 4th
Street, Suite 1200
(425)
454-6363 |
91-1969407 |
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PUGET
SOUND ENERGY, INC.
A
Washington Corporation
10885
NE 4th
Street, Suite 1200
(425)
454-6363 |
91-0374630 |
Securities
registered pursuant to Section 12(b) of the Act:
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Title Of
Each Class |
Name
Of Each Exchange
On
Which Listed |
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Puget
Energy, Inc. |
Common
Stock, $0.01 par value |
NYSE |
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Preferred
Share Purchase Rights |
NYSE |
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Puget
Sound Energy, Inc. |
8.4%
Capital Securities |
NYSE |
Securities
registered pursuant to Section 12(g) of the Act:
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Title Of
Each Class |
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Puget
Sound Energy, Inc. |
Preferred
Stock (cumulative, $100 par value) |
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8.231%
Capital Securities |
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Puget
Sound Energy, Inc. meets the conditions set forth in General Instructions
I(1)(a) and (b) of Form 10-K and is therefore filing this Form 10-K with the
reduced disclosure format.
Indicate
by check mark whether the registrants: (1) have 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 registrants were
required to file such reports), and (2) have been subject to such filing
requirements for the past 90 days.
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. / /
Indicate
by check mark whether registrant is an accelerated filer (as defined in Exchange
Act Rule 12b-2).
| |
Puget
Energy, Inc. |
Yes |
/X/ |
No |
/
/ |
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Puget
Sound Energy, Inc. |
Yes |
/
/ |
No |
/X/ |
The
aggregate market value of the voting stock held by non-affiliates of Puget
Energy, Inc. as of the last business day of Puget Energy’s most recently
completed second fiscal quarter was approximately $2,127,279,000. The number of
shares of Puget Energy, Inc.’s common stock outstanding at February 23, 2005 was
99,889,474 shares.
All of
the outstanding shares of voting stock of Puget Sound Energy, Inc. are held by
Puget Energy, Inc.
Portions
of the Puget Energy, Inc. proxy statement for its 2005 Annual Meeting of
Shareholders to be filed with the Commission pursuant to Regulation 14A not
later than 120 days after December 31, 2004 are incorporated by reference in
Part III hereof.
This
Annual Report on Form 10-K is a combined report being filed separately by two
different registrants: Puget Energy, Inc. and Puget Sound Energy, Inc. Puget
Sound Energy, Inc. makes no representation as to the information contained in
this report relating to Puget Energy, Inc. and the subsidiaries of Puget Energy,
Inc. other than Puget Sound Energy, Inc. and its subsidiaries.
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4. Submission
of Matters to a Vote of Security Holders |
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5. Market
for Registrant’s Common Equity and Related Shareholder
Matters |
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6. Selected
Financial Data |
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7. Management’s
Discussion and Analysis of |
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8. Financial
Statements and Supplementary Data |
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9. Changes
in and Disagreements with Accountants on Accounting and Financial
Disclosure |
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10. Directors
and Executive Officers of the Registrants |
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11. Executive
Compensation |
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12. Security
Ownership of Certain Beneficial Owners and Management |
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13. Certain
Relationships and Related Transactions |
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14. Principal
Accountant Fees and Services |
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15. Exhibits,
Financial Statement Schedules |
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AFUDC |
Allowance
for Funds Used During Construction |
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BPA |
Bonneville
Power Administration |
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CAISO |
California
Independent System Operator |
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COE |
United
States Army Corps of Engineers |
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Dth |
Dekatherm
(one Dth is equal to one MMBtu) |
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Ecology |
Washington
State Department of Ecology |
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FASB |
Financial
Accounting Standards Board |
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FERC |
Federal
Energy Regulatory Commission |
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FIN |
Financial
Accounting Standards Board Interpretation |
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FPA |
Federal
Power Act |
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HCP |
Habitat
Conservation Plans |
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InfrastruX |
InfrastruX
Group, Inc. |
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kW |
Kilowatts
(one kilowatt equals one thousand watts) |
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kWh |
Kilowatt
Hours (one kWh equals one thousand watt hours) |
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LIBOR |
London
Interbank Offered Rate |
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LNG |
Liquefied
Natural Gas |
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MMBtu |
One
Million British Thermal Units |
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MMS |
Minerals
Management Service |
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MW |
Megawatts
(one MW equals one thousand kW) |
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MWh |
Megawatt
Hours (one MWh equals one thousand kWh) |
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NOPR |
Notice
of Proposed Rulemaking |
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NYSE |
New
York Stock Exchange |
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PCA |
Power
Cost Adjustment |
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PGA |
Purchased
Gas Adjustment |
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PG&E |
Pacific
Gas & Electric Company |
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PSE |
Puget
Sound Energy, Inc. |
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PUDs |
Washington
Public Utility Districts |
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Puget
Energy |
Puget
Energy, Inc. |
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PURPA |
Public
Utility Regulatory Policies Act |
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RFP |
Request
for Proposal |
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RTO |
Regional
Transmission Organization |
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SEC |
United
States Securities and Exchange Commission |
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SFAS |
Statement
of Financial Accounting Standards |
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SMD |
FERC
Standard Market Design |
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Washington
Commission |
Washington
Utilities and Transportation Commission |
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WECO |
Western
Energy Company |
Puget
Energy and Puget Sound Energy (PSE) are including the following cautionary
statements in this Form 10-K to make applicable and to take advantage of the
safe harbor provisions of the Private Securities Litigation Reform Act of 1995
for any forward-looking statements made by or on behalf of Puget Energy or PSE.
This report includes forward-looking statements, which are statements of
expectations, beliefs, plans, objectives, assumptions of future events or
performance. Words or phrases such as “anticipates,” “believes,” “estimates,”
“expects,” “intends,” “plans,” “predicts,” “projects,” “will likely result,”
“will continue” or similar expressions identify forward-looking
statements.
Forward-looking
statements involve risks and uncertainties that could cause actual results or
outcomes to differ materially from those expressed. Puget Energy’s and PSE’s
expectations, beliefs and projections are expressed in good faith and are
believed by Puget Energy and PSE, as applicable, to have a reasonable basis,
including without limitation management’s examination of historical operating
trends, data contained in records and other data available from third parties;
but there can be no assurance that Puget Energy’s and PSE’s expectations,
beliefs or projections will be achieved or accomplished.
In
addition to other factors and matters discussed elsewhere in this report, some
important factors that could cause actual results or outcomes for Puget Energy
and PSE to differ materially from those discussed in forward-looking statements
include:
Risks
relating to the regulated utility business (PSE)
| · |
governmental
policies and regulatory actions, including those of the Federal Energy
Regulatory Commission (FERC) and the Washington Utilities and
Transportation Commission (Washington Commission), with respect to allowed
rates of return, financings, industry and rate structures, transmission
and generation business structures within PSE, acquisition and disposal of
assets and facilities, operation, maintenance and construction of electric
generating facilities, operation of distribution and transmission
facilities (gas and electric), licensing of hydroelectric operations and
gas storage facilities, recovery of other capital investments, recovery of
power and gas costs, recovery of regulatory assets, and present or
prospective wholesale and retail
competition; |
| · |
financial
difficulties of other energy companies and related events, which may
affect the regulatory and legislative process in unpredictable ways and
also adversely affect the availability of and access to capital and credit
markets and/or impact delivery of energy to PSE from its
suppliers; |
| · |
wholesale
market disruption, which may result in a deterioration of market
liquidity, increase the risk of counterparty default, affect the
regulatory and legislative process in unpredictable ways, affect wholesale
energy prices and/or impede PSE’s ability to manage its energy portfolio
risks; |
| · |
the
effect of wholesale market structures (including, but not limited to, new
market design such as Grid West, a regional transmission organization, and
Standard Market Design); |
| · |
PSE
electric or gas distribution system failure, which may impact PSE’s
ability to adequately deliver gas supply to its
customers; |
| · |
weather,
which can have a potentially serious impact on PSE’s revenues and its
ability to procure adequate supplies of gas, fuel or purchased power to
serve its customers and on the cost of procuring such
supplies; |
| · |
variable
hydroelectric conditions, which can impact streamflow and PSE’s ability to
generate electricity from hydroelectric
facilities; |
| · |
plant
outages, which can have an adverse impact on PSE’s expenses as it procures
adequate supplies to replace the lost energy or dispatches a more
expensive resource; |
| · |
the
ability of gas or electric plant to operate as intended, which if not in
proper operating condition or design could limit the capacity of the
operating plant; |
| · |
the
ability to renew contracts for electric and gas supply and the price of
renewal; |
| · |
blackouts
or large curtailments of transmission systems, whether PSE’s or others’,
which can have an impact on PSE’s ability to deliver load to its
customers; |
| · |
the
ability to restart generation following a regional transmission
disruption; |
| · |
failure
of the interstate gas pipeline delivering to PSE’s system, which may
impact PSE’s ability to adequately deliver gas supply to its
customers; |
| · |
the
ability to relicense FERC hydroelectric projects at a cost-effective
level; |
| · |
the
amount of collection, if any, of PSE’s receivables from the California
Independent System Operator (CAISO) and other parties, and the amount of
refunds found to be due from PSE to the CAISO or other parties;
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| · |
industrial,
commercial and residential growth and demographic patterns in the service
territories of PSE; |
| · |
general
economic conditions in the Pacific Northwest, which might impact customer
consumption or affect PSE’s accounts receivable;
and |
| · |
the
loss of significant customers or changes in the business of significant
customers, which may result in changes in demand for PSE’s
services. |
Risks
relating to the non-regulated utility service business (InfrastruX Group,
Inc.)
| · |
the
ability of Puget Energy to complete a sale of its interests in InfrastruX
to a third party under reasonable terms; |
| · |
the
failure of InfrastruX to service its obligations under its credit
agreement, in which case Puget Energy, as guarantor, may be required to
satisfy these obligations, which could have a negative impact on Puget
Energy’s liquidity and access to capital; |
| · |
the
inability to generate internal growth at InfrastruX, which could be
affected by, among other factors, InfrastruX’s ability to expand the range
of services offered to customers, attract new customers, increase the
number of projects performed for existing customers, hire and retain
employees and open additional facilities; |
| · |
the
effect of competition in the industry in which InfrastruX competes,
including from competitors that may have greater resources than
InfrastruX, which may enable them to develop expertise, experience and
resources to provide services that are superior in quality or lower in
price; |
| · |
the
extent to which existing electric power and gas companies or prospective
customers will continue to outsource services in the future, which may be
impacted by, among other things, regional and general economic conditions
in the markets InfrastruX serves; |
| · |
delinquencies,
including those associated with the financial conditions of InfrastruX’s
customers; |
| · |
the
impact of any goodwill impairments on the results of operations of
InfrastruX arising from its acquisitions, which could have a negative
effect on the results of operations of Puget
Energy; |
| · |
the
impact of adverse weather conditions that negatively affect operating
conditions and results; |
| · |
the
ability to obtain adequate bonding coverage and the cost of such bonding;
and |
| · |
the
perception of risk associated with its business due to a challenging
business environment. |
Risks
relating to both the regulated and non-regulated
businesses
| · |
the
impact of acts of terrorism or similar significant
events; |
| · |
the
ability of Puget Energy, PSE and InfrastruX to access the capital markets
to support requirements for working capital, construction costs and the
repayment of maturing debt; |
| · |
capital
market conditions, including changes in the availability of capital or
interest rate fluctuations; |
| · |
changes
in Puget Energy’s or PSE’s credit ratings, which may have an adverse
impact on the availability and cost of capital for Puget Energy, PSE and
InfrastruX; |
| · |
legal
and regulatory proceedings; |
| · |
the
ability to recover changes in enacted federal, state or local tax laws
through revenue in a timely manner; |
| · |
changes
in, adoption of and compliance with laws and regulations including
environmental and endangered species laws, regulations, decisions and
policies concerning the environment, natural resources, and fish and
wildlife (including the Endangered Species
Act); |
| · |
employee
workforce factors, including strikes, work stoppages, availability of
qualified employees or the loss of a key executive;
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| · |
the
ability to obtain and keep patent or other intellectual property rights to
generate revenue; |
| · |
the
ability to obtain adequate insurance coverage and the cost of such
insurance; |
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the
impacts of natural disasters such as earthquakes, hurricanes, floods,
fires or landslides; |
| · |
the
impact of adverse weather conditions that negatively affect operating
conditions and results; |
| · |
the
ability to maintain effective internal controls over financial reporting;
and |
| · |
the
ability to maintain customers and
employees. |
Any
forward-looking statement speaks only as of the date on which such statement is
made, and, except as required by law, Puget Energy and PSE undertake no
obligation to update any forward-looking statement to reflect events or
circumstances after the date on which such statement is made or to reflect the
occurrence of unanticipated events. New factors emerge from time to time and it
is not possible for management to predict all such factors, nor can it assess
the impact of any such factor on the business or the extent to which any factor,
or combination of factors, may cause results to differ materially from those
contained in any forward-looking statement.
Puget
Energy, Inc. (Puget Energy) is an energy services holding company incorporated
in the State of Washington in 1999. All of its operations are conducted through
its subsidiaries, Puget Sound Energy, Inc. (PSE), a utility company, and
InfrastruX Group, Inc. (InfrastruX), a construction services company. Puget
Energy has no significant assets other than the stock of its subsidiaries.
Subject to limited exceptions, Puget Energy is exempt from regulation as a
public utility holding company pursuant to Section 3(a)(1) of the Public Utility
Holding Company Act of 1935. Puget Energy and PSE are collectively referred to
herein as “the Company.” The following table provides the percentages of Puget
Energy’s consolidated operating revenues and net income generated and assets
held by the reportable segments:
|
Segment |
Percent
of Revenue |
|
Percent
of Net Income |
|
Percent
of Assets |
|
| |
2004 |
2003 |
|
2002 |
|
2004 |
|
2003 |
|
2002 |
|
2004 |
|
2003 |
|
2002 |
|
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Puget
Sound Energy1 |
|
85.3 |
% |
85.4 |
% |
|
85.8 |
% |
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224.2 |
% |
|
98.1 |
% |
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87.4 |
% |
|
94.5 |
% |
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92.7 |
% |
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92.2 |
% |
|
InfrastruX |
|
14.4 |
% |
14.3 |
% |
|
13.8 |
% |
|
(127.8 |
)% |
|
1.5 |
% |
|
8.6 |
% |
|
4.3 |
% |
|
6.0 |
% |
|
5.5 |
% |
|
Other
subsidiaries |
|
0.3 |
% |
0.3 |
% |
|
0.4 |
% |
|
3.6 |
% |
|
0.4 |
% |
|
4.0 |
% |
|
1.2 |
% |
|
1.3 |
% |
|
2.3 |
% |
_______________________________
| 1 |
Net
income for PSE is presented as net income for common stock due to $5.2
million and $7.8 million of preferred stock dividend being treated as an
other deduction at Puget Energy in 2003 and 2002,
respectively |
Additional
financial data regarding these segments are included in Note 24, to the
Consolidated Financial Statements included with this report.
Puget
Energy Strategy
Puget
Energy is the parent company of the largest electric and natural gas utility
headquartered in the State of Washington, primarily engaged in the business of
electric transmission, distribution and generation and natural gas transmission
and distribution. Puget Energy’s business strategy is to generate stable
earnings and cash flow by focusing primarily on the regulated utility business
conducted through PSE. The key elements of this strategy include:
Focus
on regulated utility business. PSE
intends to continue to focus on its core electric and natural gas transmission
and distribution utility business, offering reliable electric and gas service at
a fair value to PSE’s customers.
Add
electric generation and delivery infrastructure to meet customer
needs. Ensuring
reliable, low-cost energy supply is one of PSE’s highest priorities. As regional
demand for energy continues to grow, PSE’s committed power supply resources will
not be adequate to meet anticipated demand, especially as existing long-term
power purchase contracts begin to expire. Accordingly, PSE is continually
seeking new electric power resource generation and long term purchase power
agreements to meet load requirements and ensure stable cost-based energy supply
within its service territory. During 2004, PSE made the following strides in
this goal:
| · |
Purchased
a 49.85% interest in a 250 MW capacity gas-fired generation facility in
western Washington, which went into service in April
2004. |
| · |
Signed
a two-year purchase power agreement in the second quarter 2004 with a
utility for 85 MW of energy with delivery beginning January 1,
2005. |
| · |
Signed
a non-binding letter of intent in September 2004 to purchase a wind
generation facility with up to 230 MW of generation to be developed in
central Washington State. |
| · |
Signed
a non-binding letter of intent in October 2004 to purchase a wind
generation facility with up to 150 MW of generation to be developed in
eastern Washington State. |
Rebuild
financial strength to fund energy infrastructure and manage energy
portfolio. PSE
intends to focus on the regulated business to improve its credit quality and
liquidity and to provide predictable earnings to attract investors in Puget
Energy.
Provide
return to Puget Energy shareholders through earnings growth and
dividends. Generate
return and attract equity capital through growth in PSE earnings and
dividends.
Achieve
PSE earnings growth. PSE
earnings will grow through rebuilding common equity and increasing ratebase by
adding generating and delivery resources where needed with timely cost recovery.
Puget Energy was able to invest additional capital in PSE through the sale of
its common stock.
After
completing a strategic review of InfrastruX, Puget Energy has decided to exit
the construction services sector. Puget Energy’s Board of Directors approved the
decision on February 8, 2005. The decision to exit the business is the result of
the Company’s need to invest in the core utility business to acquire or
construct energy generating resources and energy delivery infrastructure. During
2005, Puget Energy intends to monetize its interest in InfrastruX through sale
or third party recapitalization and invest the proceeds in PSE.
PUGET
SOUND ENERGY, INC.
PSE is a
public utility incorporated in the State of Washington. PSE furnishes electric
and gas service in a territory covering approximately 6,000 square miles,
principally in the Puget Sound region of the State of Washington.
At
December 31, 2004, PSE had approximately 1,001,200 electric customers,
consisting of 884,500 residential, 110,500 commercial, 3,900 industrial and
2,300 other customers; and approximately 672,000 gas customers, consisting of
619,000 residential, 50,200 commercial, 2,700 industrial and 100 transportation
customers. At December 31, 2004, approximately 324,200 customers purchased both
electricity and gas from PSE. For the year 2004, PSE added approximately 23,500
electric customers and approximately 27,400 gas customers, representing
annualized customer growth rates of 2.4% and 4.2% respectively. During 2004,
PSE’s billed retail and transportation revenues from electric utility operations
were derived 47% from residential customers, 44% from commercial customers, 7%
from industrial customers and 2% from transportation and other customers. PSE’s
retail revenues from gas utility operations were derived 63% from residential
customers, 30% from commercial customers, 5% from industrial customers and 2%
from transportation customers. During this period the largest customer accounted
for approximately 1% of PSE’s operating revenues.
PSE is
affected by various seasonal weather patterns throughout the year and,
therefore, utility revenues and associated expenses are not generated evenly
during the year. Variations in energy usage by consumers occur from season to
season and from month to month within a season, primarily as a result of weather
conditions. PSE normally experiences its highest retail energy sales in the
first and fourth quarters of the year. Sales of electricity to wholesale
customers also vary by quarter and year depending principally upon fundamental
market factors and weather conditions. PSE has a purchased gas adjustment (PGA)
mechanism in retail gas rates to recover variations in gas supply and
transportation costs. PSE also has a power cost adjustment (PCA) mechanism in
electric rates to recover variations in electricity costs on a shared basis
between customers and PSE.
In the
five-year period ended December 31, 2004, PSE’s gross electric utility plant
additions were $786 million and retirements were $290 million. In the five-year
period ended December 31, 2004, PSE’s gross gas utility plant additions were
$586 million and retirements were $74 million. In the same five-year period,
PSE’s gross common utility plant additions were $128 million and retirements
were $33 million. Gross electric utility plant at December 31, 2004 was
approximately $4.4 billion, which consisted of 60% distribution, 26% generation,
6% transmission and 8% general plant and other. Gross gas utility plant as of
December 31, 2004 was approximately $1.9 billion, which consisted of 85%
distribution, 7% transmission and 8% general plant and other. Gross common
utility general and intangible plant at December 31, 2004 was approximately $410
million.
INFRASTRUX
GROUP, INC.
InfrastruX
was incorporated in the State of Washington in 2000 to pursue the non-regulated
construction services business. InfrastruX provides infrastructure construction
services to the electric and gas utility industries. InfrastruX has acquired 12
companies, primarily in the Midwest, Texas, south-central and eastern United
States, that are engaged in some or all of the following services and activities
in their respective regions or nationally:
| · |
Electric:
Overhead and underground power line and cable construction, installation
and maintenance, including high-voltage transmission and distribution
lines, copper and fiberoptic cables; duct installation; revitalization and
damage prevention for underground power lines and cables using the
patented Cablecure® treatment; substation construction; and other
specialty services for new and existing
infrastructures. |
| · |
Gas:
Large-diameter pipeline installation and maintenance; service lines and
meters; conventional river crossings and bridge maintenance; cathodic
protection; power station fabrication and installation; vacuum excavation;
hydrostatic testing; internal pipeline inspection; product pipelines; and
other specialty services for distribution and transmission pipeline
services including small, mid-size and large-bore directional drilling for
virtually all pipeline diameters and soil
conditions. |
Following
a strategic review of InfrastruX conducted by Puget Energy management, on
February 8, 2005, Puget Energy’s Board of Directors decided to exit the utility
construction services sector. During 2005, Puget Energy intends to monetize its
interest in InfrastruX through a sale or third party recapitalization and to
invest the proceeds in PSE. The costs associated with exiting the InfrastruX
business cannot be quantified at this time. However, Puget Energy believes that
such costs will not be material given the effects of the impairment charge
recorded in the fourth quarter 2004.
InfrastruX
is affected by seasonal weather conditions and, therefore, revenues and
associated expenses are not generated evenly during the year. InfrastruX will
usually experience its highest revenues in the second and third quarter of the
year, as spring and summer months are routinely the most productive time of year
for the construction industry due to longer daylight hours and generally better
weather conditions.
InfrastruX’s
operating strategy revolves around leveraging the synergies of a core group of
outstanding infrastructure construction contractors whose asset base, expertise,
local knowledge, relationships and years of successful operations form a strong
base for a growing business. The ability to share workforce, production
equipment and expertise within and between regional geographies allows
InfrastruX to provide local support for its customers and also move quickly to
provide additional services as needs arise. The formation of regional service
centers in 2003, where appropriate, is providing enhanced oversight and control
as well as cost efficiencies surrounding back office operations, equipment
control and other operational areas.
The
construction services industry is both highly competitive and highly fragmented
as a result of low barriers to entry, the historical geographic segmentation of
utility customers and the natural limitations of service delivery. Competitors
of InfrastruX include large established and emerging national companies and many
smaller regional companies.
EMPLOYEES
At
February 23, 2005, Puget Energy and its subsidiaries had approximately 4,900
full-time employees:
|
Puget
Sound Energy |
2,200 |
InfrastruX |
2,700 |
|
Total
Puget Energy |
4,900 |
Approximately
1,100 PSE employees are represented by the International Brotherhood of
Electrical Workers Union (IBEW) or the United Association of Plumbers and
Pipefitters (UA). The labor contracts with the IBEW and UA run through 2007 and
2006, respectively.
Approximately
300 InfrastruX employees are represented by the IBEW, UA, United Steelworkers of
America, Laborers International Union of North America or other unions. Some
unions have annual contract renewals while others have multiple-year
contracts.
CORPORATE
LOCATION
Puget
Energy’s and PSE’s principal executive offices are located at 10885 NE
4th Street,
Suite 1200, Bellevue, Washington 98004 and the telephone number is (425)
454-6363.
AVAILABLE
INFORMATION
The
Company’s reports on Form 10-K, quarterly reports on Form 10-Q, current reports
on Form 8-K and amendments to those reports filed or furnished pursuant to
Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are available or
may be accessed free of charge through the Investors section of the Company’s
website at www.pse.com as soon as reasonably practicable after the reports are
electronically filed with, or furnished to, the SEC. It is not intended that the
Company’s website and the information contained therein or connected thereto be
incorporated into this Annual Report on Form 10-K. Information may also be
obtained via the SEC Internet website at www.sec.gov.
In
addition, the following corporate governance materials of the Company are
available in the Investors section of the Company’s website, and a copy will be
mailed upon request. Requests should be made to Puget Energy, Inc., Investor
Services, P.O. Box 97034, PSE-08S, Bellevue, Washington 98009-9734.
| · |
Corporate
Governance Guidelines; |
| · |
Corporate
Ethics and Compliance Code; |
| · |
Audit
Committee, Governance and Public Affairs Committee and Compensation and
Leadership Development Committee charters;
and |
| · |
Code
of Ethics for the Company’s Chief Executive Officer and senior financial
officers. |
If the
Company waives any material provision of its Code of Ethics for its Chief
Executive Officer and senior financial officers or its Corporate Ethics and
Compliance Code, or substantively changes the codes for any specific officer,
the Company will disclose that waiver on its website within five business
days.
NEW
YORK STOCK EXHANGE CERTIFICATION
On May 6,
2004, the Chief Executive Officer of Puget Energy and PSE filed a Section
303A.12(a) CEO Certification with the New York Stock Exchange. The CEO
Certification attests that the Chief Executive Officer is not aware of any
violations by the Company of NYSE’s Corporate Governance Listing
Standards.
PSE is
subject to the regulatory authority of (1) the Washington Commission as to
retail utility rates, accounting, the issuance of securities and certain other
matters and (2) FERC with respect to the transmission of electric energy, the
resale of electric energy at wholesale, accounting and certain other
matters.
ELECTRIC
REGULATION AND RATES
WASHINGTON
COMMISSION MATTERS
On
February 18, 2005, the Washington Commission approved a 4% general tariff
electric rate case increase to recover higher costs of providing electric
service to customers. The rate increase will increase electric revenues by
approximately $56.6 million annually effective March 4, 2005. In the order, the
Washington Commission also approved a capital structure containing 43% common
equity with a return on common equity of 10.3%. In the proceeding PSE had filed
a request for an increase of 7.1% or $99.8 million annually on final rebuttal
during the rate case, reflecting updated power costs for increases in natural
gas prices for generating plants.
The
Washington Commission issued an order on May 13, 2004 determining that PSE did
not prudently manage gas costs for the Tenaska electric generating plant and
ordered PSE to adjust its PCA deferral account to reflect a disallowance of
$25.6 million for the PCA 1 period (July 1, 2002 through June 30, 2003), which
was recorded by PSE as a Purchased Electricity expense in the second quarter
2004. The order also established guidelines for future recovery of Tenaska
costs. The amounts were determined to be a $25.6 million disallowance for the
PCA 1 period and an estimated disallowance of $11.3 million for the PCA 3 period
(July 1, 2004 to June 30, 2005), based upon applying the Washington Commission’s
methodology of 50% disallowance on the return on the Tenaska regulatory asset
due to projected costs exceeding the benchmark during the period. For the PCA 3
period, approximately $5.6 million was disallowed in the period July 1, 2004
through December 31, 2004, primarily as a reduction to Electric Operating
Revenue. While the Washington Commission did not expressly address the
disallowance for the PCA 2 period (July 1, 2003 through June 30, 2004), PSE
estimated the disallowance for the PCA 2 period to be approximately $12.2
million if the Washington Commission were to follow the same methodology as they
have ordered for the PCA 3 period. Therefore, PSE recorded a $12.2 million
disallowance to Purchased Electricity expense in the second quarter 2004 for the
50% disallowance of the return on the Tenaska regulatory asset in accordance
with the Washington Commission’s methodology discussed in their order of May 13,
2004 for a cumulative impact on earnings of $43.4 million in 2004 for the PCA 1,
PCA 2 and PCA 3 periods. PSE has filed the PCA 2 period compliance filing and
anticipates it will be concluded no later than the first quarter 2005. As a
result of the disallowance recorded, the PCA customer deferral was expensed and
a reserve was established for amounts not previously deferred under the PCA
mechanism. The reserve balance as of December 31, 2004 was $3.2 million, which
is expected to be utilized in 2005 as excess power costs are shared through the
PCA mechanism.
PSE filed
the PCA 2 period compliance filing in August 2004 and received an order from the
Washington Commission on February 23, 2005. In the PCA 2 compliance order, the
Washington Commission approved the Washington Commission staff’s recommendation
for an additional return related to the Tenaska regulatory asset in the amount
of $6.1 million related to the period July 1, 2003 through December 31, 2003.
Washington Commission staff’s recommendation was opposed by certain other
parties. This amount alters the PCA deferral and is subject to reconsideration
and appeal by other parties. Parties have 10 days from February 23, 2005 to file
for reconsideration and 30 days to appeal the order. Once the statutory appeal
process has concluded and the Washington Commission issues its final order, PSE
will determine if recording a regulatory asset is appropriate.
In the
May 13, 2004 order, the Washington Commission established guidelines and a
benchmark to determine PSE’s recovery on the Tenaska regulatory asset starting
with the PCA 3 period (July 1, 2004) through the expiration of the Tenaska
contract in the year 2011. The benchmark is defined as the original cost of the
Tenaska contract adjusted to reflect the 1.2% disallowance from a 1994 Prudence
Order.
The
Washington Commission guidelines for determining future recovery of the Tenaska
costs (gas costs, recovery of the Tenaska regulatory asset and return on the
Tenaska regulatory asset) are as follows:
| 1. |
The
Washington Commission will determine if PSE’s gas purchasing plan and gas
purchases for Tenaska are prudent through the PCA compliance filings.
|
| 2. |
If
PSE’s gas purchasing plan and gas purchases for Tenaska are prudent, and
if PSE’s actual Tenaska costs fall at or below the benchmark, it will
recover fully its Tenaska costs. |
| 3. |
If
PSE’s gas purchasing plan and gas purchases for Tenaska are prudent, but
its actual Tenaska costs exceed the benchmark, PSE will only recover 50%
of the lesser of: |
| a) |
actual
Tenaska costs that exceed the benchmark; or |
| b) |
the
return on the Tenaska regulatory asset. |
| 4. |
If
PSE’s gas purchasing plan or gas purchases are found to be imprudent in a
future proceeding, PSE risks disallowance of any and all Tenaska costs.
|
The
Washington Commission confirmed that if the Tenaska gas costs are deemed
prudent, PSE will recover the full amount of actual gas costs and the recovery
of the Tenaska regulatory asset even if the benchmark is exceeded.
In the
first quarter 2004, a counterparty of a physical gas supply contract for one of
PSE’s electric generating facilities notified PSE that it would be unable to
deliver physical gas supply beginning in November 2005 through the end of the
contract in June 2008. In October 2004, PSE and the counterparty reached a
settlement on the non-deliverable period of November 2005 through June 2008. The
agreement allows PSE to recover a portion of the present value of the difference
in future market prices of physical gas and the original contract price, for a
total recovery of approximately $10.1 million. In October 2004, PSE entered into
a new contract with another counterparty for the period November 2005 through
June 2008 to replace the physical gas supply from the previously mentioned
amended contract. Also, in the fourth quarter 2004, an accounting order was
approved by the Washington Commission to defer the counterparty settlement
amount as a regulatory liability and amortize the benefit over the period of
November 2005 through June 2008 as a reduction in Electric Generation Fuel
expense. In its accounting order, the Washington Commission reserved the right
to review the prudence of the level of settlement payments agreed to and the
cost of the replacement contract during any affected PCA periods going
forward.
On June
20, 2002, the Washington Commission issued final regulatory approval of the
comprehensive electric rate settlement submitted by PSE, key constituents and
customer groups, Washington Commission staff and the Washington State Attorney
General’s Public Counsel Section. The authorization granted PSE a 4.6% electric
general rate increase that began July 1, 2002, which was intended to generate
approximately $59 million in additional revenue annually. In addition, the
settlement provided for an 8.76% overall return on capital based on a projected
capital structure with an equity component of 40% and an authorized 11% return
on common equity. The settlement resolved all electric and gas cost allocation
issues and established an 8.76% overall return on capital.
The
settlement also included a Power Cost Adjustment (PCA) mechanism that triggers
if PSE’s costs to provide customers’ electricity falls outside certain bands
from a normalized level of power costs established in the electric general rate
case. The cumulative maximum pre-tax earnings exposure due to power cost
variations over the four-year period ending June 30, 2006 is limited to $40
million plus 1% of the excess. Upon expiration of the $40 million cumulative
cap, the annual power cost variability is subject to the bands in the table
below. All significant variable power supply cost drivers are included in the
PCA mechanism (hydroelectric generation variability, market price variability
for purchased power and surplus power sales, natural gas and coal fuel price
variability, generation unit forced outage risk and wheeling cost variability).
Upon
expiration of the cumulative cap, the most significant risks are hydroelectric
generation variability and wholesale market prices of natural gas and power. On
an annual July through June basis, the PCA mechanism apportions increases or
decreases in power costs, on a graduated scale, between PSE and its customers in
the following manner:
|
ANNUAL
POWER
COST
AVAILABILITY |
CUSTOMERS’
SHARE |
COMPANY’S
SHARE 1 |
|
+/-
$20 million |
0% |
|
100% |
|
|
+/-
$20 - $40 million |
50% |
|
50% |
|
|
+/-
$40 - $120 million |
90% |
|
10% |
|
|
+/-
$120 million |
95% |
|
5% |
|
__________________________
| 1 |
Over
the four-year period July 1, 2002 through June 30, 2006, the Company’s
share of pre-tax power cost variations is capped at a cumulative $40
million plus 1% of the excess. Power cost variation after June 30, 2006
will be apportioned on an annual basis, based on the graduated
scale. |
Interest
will be accrued on any overcollection or undercollection of the customers’ share
of the excess power cost that is deferred. PSE can request a PCA rate surcharge,
if for any 12-month period, the actual or projected deferred power costs exceed
$30 million. PSE’s cumulative share of the excess power costs through December
31, 2004 was $35.0 million, principally because of adverse hydroelectric
conditions, escalating wholesale gas and power costs in 2003 and 2004 and a May
2004 Washington Commission order in the PCA 1 compliance filing which stated PSE
was not prudent in managing the Tenaska electric generation facility gas cost
and ordered PSE to adjust its PCA deferral account to reflect a disallowance for
the PCA 1 period (July 1, 2002 through June 30, 2003). PSE’s share of the excess
power costs, including the effect of the Tenaska disallowance, was $36.5 million
in 2004 compared to $34.8 million in 2003. As a result of the Tenaska
disallowance reserve, any further increases in variable power costs in excess of
the cap under the PCA mechanism through June 2006 would be apportioned 99% to
customers and 1% to PSE. PSE is required to file a compliance filing with
the Washington Commission annually by August 31, in relation to the power costs
under the PCA mechanism for the relevant 12 month period ending June
30.
The
settlement also gave PSE the financial flexibility to rebuild its common equity
ratio to at least 39% over a three-and-one-half-year period, with milestones of
34%, 36% and 39% at the end of 2003, 2004 and 2005, respectively. If PSE should
fail to meet this schedule, it would be subject to a 2% rate reduction penalty.
As of December 31, 2004, PSE has restored its common equity ratio to a 40.1%
level, exceeding the required level for 2004 by 4.1%.
In the
settlement of the 2001 Electric General Rate Proceeding, the Washington
Commission and PSE agreed to create a limited-scope proceeding called a Power
Cost Only Rate Case (PCORC) that would periodically reset power cost rates. The
main objective of the PCORC proceeding is to provide for timely review of new
resource acquisitions and inclusion of those costs into rates by the time the
new resource goes into service. To achieve this objective, the Washington
Commission and PSE have agreed to a non-binding, expedited five-month timeline
rather than the statutory 11-month timeline that is allowed in a general rate
case.
On
October 24, 2003, PSE filed a PCORC proceeding under this 2001 rate case
provision for the acquisition and recovery in rates of a 49.85% interest in the
Frederickson 1 generating facility, located in Washington State. On April 23,
2004, the acquisition of the Frederickson 1 generating facility was approved by
FERC. Prior to that approval, on April 7, 2004, the Washington Commission issued
an order in PSE’s PCORC granting approval for the acquisition of the
Frederickson 1 generating facility as well. As a result of these approvals, PSE
completed the acquisition in the second quarter 2004. In its order, the
Washington Commission found the acquisition to be prudent and the costs
associated with the generating facility reasonable. The costs associated with
the generating facility, including projected baseline gas costs, are approved
for recovery in rates. The Washington Commission subsequently ordered on May 13,
2004, an increase of cost recovery in rates of $44.1 million annually, beginning
May 24, 2004, which includes the ownership, operation and fuel costs of the
Frederickson 1 generating facility.
RESIDENTIAL
AND SMALL FARM EXCHANGE BENEFIT CREDIT
In June
2001, PSE and Bonneville Power Administration (BPA) entered into an amended
settlement agreement regarding the Residential Purchase and Sale Program, under
which PSE’s residential and small farm customers receive the benefits of federal
power. Completion of this agreement enabled PSE to continue to provide a
Residential and Farm Energy Exchange Benefit Credit to residential and small
farm customers. The amended settlement agreement provides that, for its
residential and small farm customers, PSE will receive; (a) cash payment
benefits during the period July 1, 2001 through September 30, 2006, and (b)
benefits in the form of power or cash payments during the period October 1, 2006
through September 30, 2011. Under the amended settlement agreement regarding the
Residential Purchase and Sale Program, PSE reduces residential and small farm
customers’ revenue on a per kWh basis through the Residential and Farm Energy
Exchange Benefit Credit. The credit has no impact on PSE’s electric margin or
net income, as a corresponding reduction is included in purchased electricity
expenses.
In June
2002, PSE entered into an agreement with BPA, which modified the payment
provisions of the June 2001 amended settlement agreement to provide for
conditional deferral of payment by BPA of certain amounts to be paid under the
original agreement for an eight month period beginning February 2003, for a
total deferral of $27.7 million. Except for certain adjustments tied to a BPA
rate adjustment clause, BPA is to begin paying back the amount deferred with
interest over a 60-month period beginning October 1, 2006.
In
January 2003, PSE filed revised tariff sheets with the Washington Commission to
reflect this modification to the agreement between PSE and BPA. The Washington
Commission accepted the tariff changes and the Residential and Farm Energy
Exchange Benefit Credit was changed to $0.01740 per kWh from $0.01817 per kWh
for the period February 15, 2003 through September 30, 2006.
On June
30, 2003, BPA adopted its final Record of Decision in the February 2003 rate
case, which established a formula under the BPA rate adjustment clause to be
used in adjusting the rate that will affect the level of residential exchange
benefits for PSE’s customers. The adjustment under the formula went into effect
on October 1, 2003, resulting in both a reduction of benefits of $1.0 million a
month for a 12-month period and, under the modified amended settlement agreement
mentioned above, an offsetting acceleration of the payment of the
above-described $27.7 million deferral. The net result is no change in the cash
being received from BPA for the 12-month period, but a reduction in the total
benefits to be received in the October 1, 2003 through September 30, 2011
period.
In May
2004, PSE and BPA entered into an agreement that modified the payment of
benefits under the amended settlement agreement for the period October 1, 2006
through September 30, 2011. The agreement provides that all benefits in this
period will be in the form of cash payments only and defined a new methodology
to be used to calculate the residential benefits. In addition, PSE agreed to
waive payment of approximately one-half of an available reduction-in-risk
discount and deferred payment of the other half of the discount, plus interest,
until October 2007.
For 2004
and 2003, the Residential and Farm Energy Exchange Benefit credited to customers
was $182.6 million and $181.9 million, respectively, with a related offset to
power costs. PSE received payments from BPA in the amount of $175.9 million and
$147.9 million during 2004 and 2003, respectively. The difference between the
customers’ credit and the amount received from BPA either increases or decreases
the previously deferred amount owed to customers. The aggregated deferred amount
is recorded on PSE’s balance sheet as restricted cash. Absent certain
adjustments tied to the BPA rate adjustment clause described above, the modified
amended settlement agreement will provide for payments from BPA in the amount of
$630.6 million for the period January 2003 through September 2006 and for a
pass-through of the same amount to eligible residential and small farm
customers.
There are
several actions in the U.S. Ninth Circuit Court of Appeals against BPA, in which
the petitioners assert or may assert that BPA acted contrary to law or without
authority in deciding to enter into, or in entering into or performing, a number
of contracts, including the amended settlement agreement and the May 2004
agreement between BPA and PSE described above. BPA rates used in such amended
settlement agreement between BPA and PSE for determining the amounts of money to
be paid to PSE by BPA under the amended settlement agreement and other
agreements described above during the period October 1, 2001 through September
30, 2006 have been confirmed, approved and allowed to go into effect by FERC.
There are also several actions in the U.S. Ninth Circuit Court of Appeals
against BPA, in which petitioners assert that BPA acted contrary to law in
adopting or implementing the rates or rate adjustment clause upon which the
benefits received or to be received from BPA during the October 1, 2001 through
September 30, 2006 period are based. It is not clear what impact, if any, review
of such rates and the above described U.S. Ninth Circuit Court of Appeals
actions may have on PSE.
PSE’s
market-based rate tariff was accepted by FERC in an order dated January 29,
1999. Pursuant to this order, PSE is required to file an updated market power
analysis every three years. On August 11, 2004, PSE filed an updated market
power analysis with FERC as required by a FERC order dated May 13, 2004. The
August 11, 2004 filing was supplemented by additional filings on September 24,
2004 and November 19, 2004. On December 20, 2004, FERC issued an order (December
20 order) finding that PSE had not provided sufficient information for FERC to
determine if PSE had passed the generation market power screens with respect to
wholesale sales within PSE’s control area. The order instituted an investigation
under Section 206 of the Federal Power Act (FPA) and established a prospective
refund date of February 27, 2005. Both the proceeding and the refund effective
date affect only wholesale sales at market-based rates by PSE inside its own
control area. On February 1, 2005, PSE submitted to FERC additional information
in accordance with the December 20 order. PSE has been in discussions with FERC
staff to ensure that this supplemental filing addresses the staff’s issues.
Although PSE anticipates a favorable outcome to this matter, there can be no
assurance that the outcome will not materially impact PSE.
On
November 1, 1999, PSE acquired Encogen Northwest, LP (Encogen) whose sole asset
is a natural gas-fired cogeneration facility located in Washington State. With
the approval of the Washington Commission, the Encogen facility has been
operated as part of PSE’s least cost generation dispatch portfolio to serve its
native load obligations since it was acquired in 1999. Two wholly-owned
subsidiaries of PSE, GP Acquisition Corporation and LP Acquisition Corporation,
are the general and limited partners of Encogen, respectively. On December 29,
2004, PSE filed an application with FERC pursuant to Section 203 of the FPA to
transfer the Encogen facility to PSE and eliminate the various subsidiaries via
an Agreement and Plan of Merger (Merger). On February 15, 2005, FERC issued an
order authorizing the Encogen plant to be transferred to PSE. PSE anticipates
completing the Merger in 2005.
GAS
REGULATION AND RATES
In 2003,
the Washington Commission’s Pipeline Safety staff conducted a natural gas
standard inspection for three counties within Washington State in which PSE
operates gas pipelines. The inspection included a review of procedures, records
and operations and maintenance activities. On June 29, 2004, the Washington
Commission issued a complaint to PSE related to that inspection, alleging
certain violations of Washington Commission regulations. In December 2004, PSE
and the Washington Commission resolved the issues. PSE agreed to a penalty of
$0.5 million, and also agreed to update certain natural gas operating practices.
PSE’s financial results in 2004 reflect the impact of this penalty. In addition,
the resolution included the potential for future penalties of up to $0.2 million
in the next ten years if certain operational goals are not met. The Washington
Commission approved the settlement on January 31, 2005.
PSE has a
PGA mechanism in retail gas rates to recover variations in gas supply and
transportation costs. The PGA mechanism passes through to customers these
variations in gas rates, and therefore PSE’s gas margin and net income are not
affected by changes in the PGA rates. The following rate adjustments were
approved by the Washington Commission in relation to the PGA mechanism during
2004, 2003 and 2002:
|
EFFECTIVE
DATE |
PERCENTAGE
INCREASE
(DECREASE) IN RATES |
ANNUAL
INCREASE (DECREASE)
IN REVENUES
(DOLLARS IN MILLIONS) |
|
|
17.6% |
|
$121.7 |
|
|
|
13.3% |
|
78.8 |
|
|
|
20.1% |
|
103.6 |
|
|
|
(12.5)% |
|
(70.6 |
) |
|
|
(7.3)% |
|
(45.0 |
) |
|
|
(21.2)% |
|
(138.9 |
) |
On
February 18, 2005, the Washington Commission approved a 3.5% general tariff gas
rate case increase to recover higher costs of providing natural gas service to
customers. The rate increase will increase gas revenues by approximately $26.3
million annually, effective March 4, 2005. In the order, the Washington
Commission also approved a capital structure containing 43% common equity with a
return on common equity of 10.3%. In the proceeding, PSE had filed a request for
an increase of 6.3% or $46.2 million annually on final rebuttal during the rate
case for gas customers.
On August
28, 2002, the Washington Commission approved a 5.8% gas rate increase in general
rates to recover higher costs of providing natural gas services to customers.
The increase was intended to provide approximately $35.6 million annually in
revenues. This rate increase became effective September 1, 2002.
FEDERAL
REGULATION
Since the
mid-1990s, FERC has required public utilities operating under the FPA to provide
open access of their transmission systems to third parties under tariffs
approved by FERC. There has been no material effect on the financial statements
of PSE as a result of open access.
FERC
Order No. 2000, issued on December 20, 1999, required all utilities subject to
its jurisdiction that own, operate or control transmission facilities to either
voluntarily form or participate in a Regional Transmission Organization (RTO);
or, alternatively, describe its efforts to participate in an RTO or obstacles to
such participation. PSE has been an active participant in regional efforts to
form an RTO in the Pacific Northwest since issuance of Order No. 2000.
Currently, PSE is working with nine other utilities on the formation of an RTO
in the region known as Grid West. Any decision by PSE to participate in Grid
West (or other RTO proposal) will depend on the ultimate form of the
organization including terms and conditions for participation. Furthermore, any
such decision will require approval of FERC, the Washington Commission and the
boards of directors of the participating utilities. PSE cannot predict the
outcome of efforts to form or participate in an RTO or whether any future
decision to join (or not join) an RTO will have a material impact on the
financial condition, results of operations or liquidity of the
Company.
On July
31, 2002, FERC issued its Notice of Proposed Rulemaking on Remedying Undue
Discrimination through Open Access Transmission Service and Standard Electricity
Market Design (SMD NOPR). On April 28, 2003, FERC issued a white paper entitled
“Wholesale Power Market Platform” (White Paper) that significantly modified the
proposal outlined in the SMD NOPR. A modification of the wholesale electricity
markets as provided in either the SMD NOPR or the White Paper would have major
implications for the delivery of electric energy throughout the United States.
Major elements of FERC’s proposal include: (a) a change to allow FERC to
exercise jurisdiction over the non-rate terms and conditions for bundled retail
sales, but leave the rate component under state jurisdiction; (b) require
vertically integrated utilities to join an RTO or an Independent System Operator
(ISO) to operate their transmission systems; and (c) require regions to develop
an approach to manage congestion, encourage efficient use of the transmission
grid and promote the use of the lowest cost generation. State regulators,
congressional delegates and industry representatives have pointed out that the
western North American electricity market has unique characteristics that may
not readily lend itself to the market design proposed by FERC. In addition,
Congress has proposed, but not passed, draft legislation that would require FERC
to delay and reconsider its market design proposal. PSE cannot predict the
outcome of the SMD NOPR or whether the ultimate resolution will have a material
impact on the financial condition, results of operations or liquidity of the
Company.
STATE
REGULATION
The
electric utility business in the State of Washington is fully regulated and
provides service to its customers under cost-based tariff rates. PSE is not
aware of any proposals or prospects for retail deregulation in the State of
Washington.
Since
1986, PSE has been offering gas transportation as a separate service to
industrial and commercial customers who choose to purchase their gas supply
directly from producers and gas marketers. The continued evolution of the
natural gas industry, resulting primarily from FERC Orders 436, 500 and 636, has
served to increase the ability of large gas end-users to independently obtain
gas supply from third parties and transportation services directly from the
interstate pipelines or other third parties. Although PSE has not lost any
substantial industrial or commercial load as a result of such activities, in
certain years up to 160 customers annually have taken advantage of unbundled
transportation service. In 2004, 129 commercial and industrial customers, on
average, chose to use such service. The shifting of customers between sales and
transportation service does not materially impact utility margin, as PSE earns
similar margins on transportation service as it does on large-volume,
interruptible gas sales.
|
TWELVE
MONTHS ENDED DECEMBER 31 |
|
2004 |
|
2003 |
|
2002 |
|
Generation
and purchased power, MWh |
|
|
|
|
|
|
|
Company-controlled
resources |
|
|
7,048,270 |
|
|
6,965,840 |
|
|
6,996,276 |
|
|
Contracted
resources |
|
|
9,421,546 |
|
|
11,021,471 |
|
|
12,085,729 |
|
|
Non-firm
energy purchased1 |
|
|
6,164,457 |
|
|
5,179,302 |
|
|
4,795,045 |
|
|
Total
generation and purchased power |
|
|
22,634,273 |
|
|
23,166,613 |
|
|
23,877,050 |
|
|
Less:
losses and company use |
|
|
(1,432,686 |
) |
|
(1,338,401 |
) |
|
(1,341,126 |
) |
|
Total
energy sales, MWh |
|
|
21,201,587 |
|
|
21,828,212 |
|
|
22,535,924 |
|
|
Electric
energy sales, MWh |
|
|
|
|
|
|
|
|
|
|
|
Residential |
|
|
10,028,150 |
|
|
9,845,854 |
|
|
9,845,527 |
|
|
Commercial |
|
|
8,449,566 |
|
|
8,222,166 |
|
|
8,012,538 |
|
|
Industrial |
|
|
1,352,660 |
|
|
1,372,815 |
|
|
1,416,107 |
|
|
Other
customers |
|
|
94,034 |
|
|
93,438 |
|
|
90,840 |
|
|
Total
energy billed to customers |
|
|
19,924,410 |
|
|
19,534,273 |
|
|
19,365,012 |
|
|
Unbilled
energy sales - net increase (decrease) |
|
|
(40,217 |
) |
|
65,082 |
|
|
(102,811 |
) |
|
Total
energy sales to customers |
|
|
19,884,193 |
|
|
19,599,355 |
|
|
19,262,201 |
|
|
Sales
to other utilities and marketers1 |
|
|
1,317,394 |
|
|
2,228,857 |
|
|
3,273,723 |
|
|
Total
energy sales, MWh |
|
|
21,201,587 |
|
|
21,828,212 |
|
|
22,535,924 |
|
|
Less:
optimization purchases for sales to other utilities and
marketers |
|
|
-- |
|
|
(62,200 |
) |
|
(2,596,505 |
) |
|
Transportation,
including unbilled |
|
|
1,988,965 |
|
|
2,020,562 |
|
|
2,307,081 |
|
|
Net
electric energy sales and transported, MWh |
|
|
23,190,552 |
|
|
23,786,574 |
|
|
22,246,500 |
|
__________________________
| 1 |
Non-firm
energy purchased and Sales to other utilities and marketers in 2003 and
2002 were revised as a result of Emerging Issues Task Force Issue No.
03-11, “Reporting Realized Gains and Losses on Derivative Instruments That
Are Subject to FASB No. 133 and Not ‘Held for Trading Purposes’ as Defined
in Issue No. 02-03” (EITF No. 03-11), which became effective January 1,
2004. MWh from other utility and marketers/non-firm energy purchased in
2003 and 2002 were reduced 2,941,707 MWh and 2,789,353 MWh,
respectively. |
|
TWELVE
MONTHS ENDED DECEMBER 31 |
|
2004 |
|
2003 |
|
2002 |
|
Electric
operating revenues by classes (thousands): |
|
|
|
|
|
|
|
Residential |
|
$ |
628,869 |
|
$ |
603,722 |
|
$ |
616,522 |
|
|
Commercial |
|
|
580,973 |
|
|
556,038 |
|
|
536,021 |
|
|
Industrial
|
|
|
88,779 |
|
|
88,201 |
|
|
90,121 |
|
|
Other
customers |
|
|
58,007 |
|
|
54,259 |
|
|
26,500 |
|
|
Operating
revenues billed to customers1 |
|
|
1,356,628 |
|
|
1,302,220 |
|
|
1,269,164 |
|
|
Unbilled
revenues - net increase (decrease) |
|
|
(813 |
) |
|
4,193 |
|
|
(7,118 |
) |
|
Total
operating revenues from customers |
|
|
1,355,815 |
|
|
1,306,413 |
|
|
1,262,046 |
|
|
Transportation,
including unbilled |
|
|
10,707 |
|
|
11,542 |
|
|
15,551 |
|
|
Sales
to other utilities and marketers2 |
|
|
56,512 |
|
|
84,994 |
|
|
75,595 |
|
|
Less:
optimization purchases for sales to other utilities and
marketers |
|
|
-- |
|
|
(2,206 |
) |
|
(64,448 |
) |
|
Total
electric operating revenues |
|
$ |
1,423,034 |
|
$ |
1,400,743 |
|
$ |
1,288,744 |
|
|
Number
of customers served (average): |
|
|
|
|
|
|
|
|
|
|
|
Residential |
|
|
874,205 |
|
|
854,088 |
|
|
839,878 |
|
|
Commercial
|
|
|
109,660 |
|
|
108,479 |
|
|
104,273 |
|
|
Industrial
|
|
|
3,953 |
|
|
3,952 |
|
|
3,953 |
|
|
Other
|
|
|
2,194 |
|
|
2,060 |
|
|
1,932 |
|
|
Transportation |
|
|
17 |
|
|
16 |
|
|
16 |
|
|
Total
customers (average) |
|
|
990,029 |
|
|
968,595 |
|
|
950,052 |
|
|
Average
retail revenues per kWh sold: |
|
|
|
|
|
|
|
|
|
|
|
Residential |
|
$ |
0.0627 |
|
$ |
0.0617 |
|
$ |
0.0632 |
|
|
Commercial |
|
|
0.0688 |
|
|
0.0680 |
|
|
0.0675 |
|
|
Industrial |
|
|
0.0656 |
|
|
0.0650 |
|
|
0.0649 |
|
|
Average
retail revenue per kWh sold |
|
|
0.0655 |
|
|
0.0646 |
|
|
0.0651 |
|
|
Average
revenue billed to residential customers |
|
$ |
719 |
|
$ |
711 |
|
$ |
741 |
|
|
Average
kWh used by residential customers |
|
|
11,471 |
|
|
11,528 |
|
|
11,723 |
|
|
Heating
degree days |
|
|
4,421 |
|
|
4,527 |
|
|
4,946 |
|
|
Percent
of normal -
NOAA 30-year average |
|
|
91.8 |
% |
|
94.4 |
% |
|
103.1 |
% |
|
Load
factor |
|
|
53.5 |
% |
|
58.9 |
% |
|
61.6 |
% |
__________________________
| 1 |
Operating
revenues in 2004, 2003 and 2002 were reduced by $0.8 million, $7.7 million
and $12.7 million, respectively, as a result of the Company’s sale of
$237.7 million of its investment in customer-owned conservation measures
in 1995 and 1997. Beginning in July 2003, these related revenues were
consolidated as a result of Financial Accounting Standards Board
Interpretation No. 46. (See Operating Revenues-Electric in Management’s
Discussion and Analysis and Note 1 to the Consolidated Financial
Statements.) As of October 2004, the conservation trust bond was fully
redeemed and any excess collection was recorded as a reduction in
revenues. |
| 2 |
Sales
to other utilities and marketers in 2003 and 2002 were revised as a result
of Emerging Issues Task Force Issue No. 03-11, “Reporting Realized Gains
and Losses on Derivative Instruments That Are Subject to FASB No. 133 and
Not ‘Held for Trading Purposes’ as Defined in Issue No. 02-03” (EITF No.
03-11), which became effective January 1, 2004. Revenues from other
utilities and marketers in 2003 and 2002 were reduced by $108.7 million
and $77.1 million, respectively |
At December 31, 2004, PSE’s electric
power resources were approximately 4,351 MW. PSE’s historical peak load of
approximately 4,847 MW occurred on December 21, 1998. In order to meet an
extreme winter peak load, PSE supplements its electric power resources with
winter-peaking call options and other instruments that may include, but are not
limited to, weather-related hedges and exchange agreements. During 2004, PSE’s
total electric energy production was supplied 31.1% by its own resources, 23.1%
through long-term contracts with several of the Washington Public Utility
Districts (PUDs) that own hydroelectric projects on the Columbia River, and
18.6% from other firm purchases. Short-term wholesale purchases, net of sales to
other utilities and marketers, accounted for 22.7% of energy production in
2004.
The
following table shows PSE’s electric energy supply resources at December 31,
2004 and 2003, and energy production during the year:
| |
|
PEAK
POWER RESOURCES
AT DECEMBER 31, |
|
ENERGY
PRODUCTION |
|
| |
|
2004 |
|
2003 |
|
2004 |
|
2003 |
|
| |
|
MW |
|
% |
|
MW |
|
% |
|
MWh |
|
% |
|
MWh |
|
% |
|
Purchased
resources: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Columbia
River PUD contracts |
|
|
1,350 |
|
|
31.0 |
% |
|
1,349 |
|
|
30.0 |
% |
|
5,231,691 |
|
|
23.1 |
% |
|
5,191,346 |
|
|
22.4 |
% |
|
Other
hydroelectric1 |
|
|
177 |
|
|
4.1 |
% |
|
177 |
|
|
3.9 |
% |
|
600,557 |
|
|
2.7 |
% |
|
622,900 |
|
|
2.7 |
% |
|
Other
producers1 |
|
|
1,011 |
|
|
23.2 |
% |
|
1,210 |
|
|
26.9 |
% |
|
3,589,298 |
|
|
15.9 |
% |
|
5,207,225 |
|
|
22.5 |
% |
|
Short-term
wholesale energy purchases2 |
|
|
N/A |
|
|
N/A |
|
|
N/A |
|
|
N/A |
|
|
6,164,457 |
|
|
27.2 |
% |
|
5,179,302 |
|
|
22.4 |
% |
|
Total
purchased |
|
|
2,538 |
|
|
58.3 |
% |
|
2,736 |
|
|
60.8 |
% |
|
15,586,003 |
|
|
68.9 |
% |
|
16,200,773 |
|
|
70.0 |
% |
|
Company-controlled
resources: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Hydroelectric |
|
|
234 |
|
|
5.4 |
% |
|
304 |
|
|
6.7 |
% |
|
1,130,180 |
|
|
5.0 |
% |
|
1,238,900 |
|
|
5.3 |
% |
|
Coal |
|
|
677 |
|
|
15.6 |
% |
|
677 |
|
|
15.1 |
% |
|
5,119,002 |
|
|
22.6 |
% |
|
4,950,734 |
|
|
21.4 |
% |
|
Natural
gas/oil |
|
|
902 |
|
|
20.7 |
% |
|
778 |
|
|
17.4 |
% |
|
799,088 |
|
|
3.5 |
% |
|
776,206 |
|
|
3.3 |
% |
|
Total
Company-controlled |
|
|
1,813 |
|
|
41.7 |
% |
|
1,759 |
|
|
39.2 |
% |
|
7,048,270 |
|
|
31.1 |
% |
|
6,965,840 |
|
|
30.0 |
% |
|
Total |
|
|
4,351 |
|
|
100.0 |
% |
|
4,495 |
|
|
100.0 |
% |
|
22,634,273 |
|
|
100.0 |
% |
|
23,166,613 |
|
|
100.0 |
% |
__________________________
| 1 |
Power
received from other utilities is classified between hydroelectric and
other producers based on the character of the utility system used to
supply the power or, if the power is supplied from a particular resource,
the character of that resource. |
| 2 |
Short-term
wholesale purchases net of resales of 1,317,394 MWh and 2,228,857 MWh
account for 22.7% and 14.1% of energy production for 2004 and 2003,
respectively. |
PSE filed
its electric Least Cost Plan on April 30, 2003 with the Washington Commission.
The plan supported a strategy of diverse electric power resource acquisitions
including resources fueled by natural gas and coal, renewable resources (e.g.
wind) and shared resources. A Least Cost Plan Update was filed in August 2003,
which integrated efficiency programs into the resource mix. The Least Cost Plan
was followed with the proposed acquisition of a gas combined-cycle combustion
turbine, and the issuing of a wind resource Request for Proposal (RFP) in
December 2003. An all-source RFP was issued in February 2004. PSE is in the
process of updating its Least Cost Plan which is expected to be filed with the
Washington Commission in the first half of 2005.
Based
upon PSE’s projected customer usage for electricity and its current electric
generation resources, PSE projects that future energy needs will exceed current
purchased and Company-controlled power resources. The projected MW shortfall at
December 31, 2004 for the period 2006-2010 is as follows:
| |
2006 |
2007 |
2008 |
2009 |
2010 |
|
Projected
MW Shortfall1 |
208 |
263 |
305 |
360 |
457 |
__________________________
| 1 |
Estimated
using all resources under long-term contract and Company-controlled
resources. Also includes anticipated acquisitions of the Hopkins Ridge and
Wild Horse wind projects which are currently under
review. |
PSE
signed a non-binding letter of intent on October 29, 2004 to acquire a 100%
interest in a 150 MW (52 average MW) wind powered electric generation facility
to be developed in eastern Washington State. PSE anticipates spending up to $200
million on the project, which it will solely own once complete. This total
includes approximately $180 million to acquire and construct the wind plant, $10
million to fund upgrades to the transmission systems of BPA and other regional
transmission providers and approximately $10 million on financing and other
costs. The proposed purchase transaction could occur as early as the end of the
first quarter 2005, and if completed, construction on the project is anticipated
to be completed sometime between late 2005 and mid 2006.
On
September 1, 2004, PSE signed a second non-binding letter of intent to acquire a
100% interest in a 230 MW (77 average MW) wind powered electric generation
facility to be developed in central Washington State. The estimated cost of the
project is approximately $300 million, depending on design options. The proposed
transaction is anticipated to be completed on or before January 1, 2006 and
construction on the project is anticipated to be completed in 2006.
COMPANY
– CONTROLLED ELECTRIC GENERATION
RESOURCES
At
December 31, 2004, PSE has the following plants with an aggregate net generating
capacity of 1,813 MW:
|
PLANT
NAME |
PLANT
TYPE |
NET
CAPACITY (MW) |
YEAR
INSTALLED |
|
Colstrip
Units 1 & 2 (50% interest) |
Coal |
307 |
|
1975
& 1976 |
|
Colstrip
Units 3 & 4 (25% interest) |
Coal |
370 |
|
1984
& 1986 |
|
Fredonia
Units 1 & 2 |
Dual-fuel
combustion turbines |
207 |
|
1984 |
|
Fredrickson
Units 1 & 2 |
Dual-fuel
combustion turbines |
147 |
|
1981 |
|
Whitehorn
Units 2 & 3 |
Dual-fuel
combustion turbines |
147 |
|
1981 |
|
Fredonia
Units 3 & 4 |
Dual-fuel
combustion turbines |
107 |
|
2001 |
|
Frederickson
Unit 1 (49.85% interest) |
Natural
gas combined cycle |
124 |
|
2002;
Purchased 2004 |
|
Encogen |
Natural
gas cogeneration |
167 |
|
1993 |
|
Crystal
Mountain |
Internal
combustion |
3 |
|
1969 |
|
Upper
Baker River |
Hydroelectric |
91 |
|
1959 |
|
Lower
Baker River |
Hydroelectric |
79 |
|
Reconstructed
1960;
Upgraded
2001 |
|
Snoqualmie
Falls |
Hydroelectric |
42 |
|
1898
to 1911 and 1957 |
|
Electron |
Hydroelectric |
22 |
|
1904
to 1929 |
COLSTRIP
GENERATING FACILITY
In June
2004, PSE and Western Energy Company (WECO), the supplier of coal to Colstrip
Units 1 & 2, entered into a binding arbitration and settled a dispute
concerning prices paid for coal supplied. The binding decision retroactively set
a new baseline cost per ton of coal purchased by PSE for Colstrip Units 1 &
2 supplied from July 31, 2001, and is applicable for the remaining term of the
coal supply agreement through December 2009. The decision resulted in a $6.9
million charge that was recorded in the second quarter 2004. Of the $6.9 million
charge, $5.0 million was included in the PCA mechanism. PSE had previously
accrued a $1.6 million reserve in the fourth quarter 2003 related to the
arbitration.
On April
29, 2004, the Minerals Management Service of the United States Department of the
Interior (MMS) issued an order to WECO to pay additional royalties concerning
coal purchased by PSE for Colstrip Units 3 & 4. The order seeks payment of
an additional $1.1 million in royalties for coal mined from federal land between
1997 and June 30, 2000. During that period, PSE’s coal price was reduced by a
settlement agreement entered into in February 1997 among PSE, WECO and Montana
Power Company that resolved disputes that were then pending. The order seeks to
impute the price charged to PSE based on the other Colstrip Units 3 & 4
owners’ contractual amounts. PSE is supporting WECO’s appeal of the order, but
is also evaluating the basis of the claim. PSE accrued a loss reserve in the
amount of $1.1 million in connection with this matter in the second quarter
2004.
In
addition, the MMS issued two orders to WECO in 2002 and 2003 to pay additional
royalties concerning coal sold to Colstrip Units 3 & 4 owners. The orders
assert that additional royalties are owed as a result of WECO not paying
royalties in connection with revenue received by WECO from the Colstrip Units 3
& 4 owners under a coal transportation agreement during the period October
1, 1991 through December 31, 2001. PSE’s share of the alleged additional
royalties is $1.8 million, which is equivalent to PSE’s 25% ownership interest
in Colstrip Units 3 & 4. Other parties may attempt to assert claims against
WECO if the MMS position prevails. The transportation agreement provides for the
construction and operation of a conveyor system that runs several miles from the
mine to Colstrip Units 3 & 4. WECO has appealed these orders and PSE is
monitoring the process. PSE believes that the Colstrip Units 3 & 4 owners
have reasonable defenses in this matter based upon its review. Neither the
outcome of this matter nor the associated costs can be predicted at this
time.
In
September 2004, the owners of Colstrip Units 1 & 2 (PSE and PPL Montana)
entered into a tentative settlement agreement with certain homeowners in the
Colstrip town site area concerning a lawsuit filed in May 2003. In December
2004, the plaintiffs retained new counsel and postponed further settlement
discussions until more discovery is completed. The lawsuit alleged certain
domestic water wells may have been contaminated by seepage from a Colstrip Units
1 & 2 effluent holding pond. The tentative settlement agreement would
require extending municipal water to the homeowners and abandoning the existing
wells. The total estimated cost of the settlement ranges from $1.4 million to
$1.5 million. As a result of this tentative settlement agreement, PSE recorded a
$0.7 million reserve in the third quarter 2004 for its 50% ownership of the
Colstrip Units 1 & 2 project. The settlement agreement would not resolve
certain other claims by residents within the city limits. PSE cannot predict the
outcome or any potential financial impact of the claims by the residents within
the city limits at this time.
FERC
HYDROELECTRIC PROJECTS AND LICENSES
As part
of its hydroelectric operations, PSE is required to obtain licenses from FERC. A
typical license contains mandatory conditions of operation, such as flow rate
requirements, adherence to certain ramping protocols for outages, maintenance of
reservoir levels, equipment upgrade projects, and fish and wildlife mitigation
projects. The licensing and relicensing processes involve harmonizing
conflicting rights and obligations of numerous governmental, non-governmental
and private parties, and dealing with issues that may include environmental
compliance, fish protection and mitigation, water quality, Native American
rights, title claims, operational and capital improvements, and flood control.
As a result, a number of political, compliance and financial risks can arise
from the licensing and relicensing processes.
PSE owns
three hydroelectric projects: the Baker River project, the Snoqualmie Falls
project and the Electron project. The White River project ceased operations as a
hydroelectric generating resource in January 2004. The Baker River and
Snoqualmie Falls projects are operating under the jurisdiction of FERC. FERC
regulates dam safety and administers proceedings under the FPA to license
jurisdictional hydropower projects. FERC licenses are generally issued for a
term of 30 to 50 years.
Baker
River project. The Baker
River project consists of the Lower Baker Development (constructed in 1925) and
the Upper Baker Development (constructed in 1959). The Baker River project’s
current license expires on April 30, 2006, and PSE submitted an application for
a new license to FERC on April 30, 2004. On November 30, 2004, PSE and 23
parties comprised of federal, state and local governmental organizations, Native
American Indian tribes, environmental and other nongovernmental entities filed a
proposed comprehensive settlement agreement on all issues relating to the
relicensing of the Baker River project. The proposed settlement includes a set
of proposed license articles and, if approved by FERC without material
modification, would allow a new license for 45 years or more. The proposed
settlement would require an investment of approximately $360 million (capital
expenditures and operations and maintenance cost) in order to implement the
conditions of the new license over the next 30 years. The proposed settlement is
subject to contingencies that have yet to be resolved and is subject to
additional regulatory approvals yet to be attained from various agencies. FERC
has not yet ruled on the proposed settlement and its ultimate outcome remains
uncertain. Assuming that settlement contingencies are resolved and additional
regulatory approvals are obtained in a timely manner and on favorable terms, a
decision by FERC could occur by April 2006.
Snoqualmie
Falls project. The
Snoqualmie Falls project, built in 1898, had its original license issued May 13,
1975, which was made effective retroactive to March 1, 1956, and expired on
December 31, 1993. PSE filed its application to relicense the project on
November 25, 1991, and operated the project pursuant to annual licenses issued
by FERC since the original license expired. On June 29, 2004, FERC granted PSE a
new 40-year operating license for the Snoqualmie Falls project. PSE estimates
that the investment required to implement the conditions of the new license
agreement will cost approximately $44 million. These conditions include modified
operating procedures and various project upgrades that include better protection
of fish, development of riparian habitat to promote fish propagation, increased
minimum flows in the Snoqualmie River during low-water periods and the
development of recreational amenities near the down-river power house. On July
29, 2004, the Snoqualmie Tribe and certain other parties filed a request for
rehearing of the new license and a request to stay the FERC license. FERC has
not ruled on this request and the outcome remains uncertain. In the meantime,
because a stay has not been issued, the Company is proceeding with its plan of
rehabilitation necessary to comply with the terms of the new license.
Electron
project. The
Electron project was built in 1904. The project’s capacity is currently 22 MW.
In 1977, the project was determined to be a “pre-1935” project under the FPA and
therefore not subject to FERC jurisdiction. In this status, the project can
continue to operate without a FERC license absent “post-1935” construction of a
nature sufficient to invoke FERC’s jurisdiction. PSE does not anticipate
undertaking any betterments or improvements to the project that would entail
“post-1935” construction.
The
project also operates in compliance with the terms and conditions of a “Resource
Enhancement Agreement” with the Puyallup Indian Tribe. This agreement resolved
the Tribe’s long-standing claims for resource and other damages allegedly
associated with the construction and operation of the project. The agreement
also provides that in 2018 PSE must decide to either retire the project by 2026
or, in lieu of retirement, undertake significant upgrades that would likely
invoke FERC jurisdiction. The outcome of these deliberations is not expected to
have a material impact upon the financial condition, results of operations or
liquidity of the Company.
White
River project.
The White
River project was built in 1911 and was operated as a hydropower facility until
January 15, 2004. PSE submitted a license application to FERC in 1983, and in
December 1997, FERC issued a proposed license for the project. PSE appealed the
1997 license because it contained terms and conditions that would render ongoing
operations of the project uneconomic relative to alternative resources. In
November 2003, PSE determined that it could no longer continue to economically
operate the project due to additional conditions primarily related to two
listings under the Endangered Species Act. On December 23, 2003, PSE notified
FERC that it rejected the 1997 license for the White River project and on
January 15, 2004, generation of electricity ceased at the White River project.
PSE is actively seeking to sell the project to one or more entities interested
in maintaining the reservoir for commercial purposes.
In the
PCORC Order issued on April 7, 2004, the Washington Commission approved PSE’s
recovery on the unamortized White River plant investment. At December 31, 2004,
the White River project net book value totaled $65.1 million, which included
$46.4 million of net utility plant, $14.8 million of capitalized FERC licensing
costs, $3.1 million of costs related to construction work in progress, and $0.8
million related to dam operations and safety. PSE sought recovery of the
relicensing, other construction work in progress and dam operations and safety
costs totaling $18.7 million in its general rate filing of April 2004, over a
10-year amortization period. In the third quarter 2004, the Washington
Commission staff recommended that PSE be allowed recovery of the White River net
utility plant costs noted above, but defer any amortization of the FERC
licensing and other costs until all costs and any sales proceeds are known. In
its February 18, 2005 general rate case order, the Washington Commission found
this treatment reasonable, and adopted all of the staff recommendations.
In
January 2001, certain environmental groups gave notice of their intent to sue
for alleged violations of the Endangered Species Act, but no such lawsuit has
been filed. In May 2004, the Puyallup Indian Tribe gave PSE notice of intent to
sue for an alleged violation of water quality laws associated with the release
of water from the White River project reservoir. No such lawsuit has been filed
and PSE is in discussion with the Puyallup Indian Tribe regarding their
concerns. Additionally, PSE has sought, and is awaiting, further direction from
the Washington State Department of Ecology (Ecology) as to whether any
additional actions are necessary to maintain compliance with applicable water
quality laws.
Homeowners
and others interested in preserving the project reservoir (Lake Tapps) have
expressed concern over the possible loss of the reservoir and there has been a
solicitation of interest in a potential lawsuit against PSE to preserve the
reservoir, but no such lawsuit has been filed to date.
In
September 2004, the Company renewed its contract with the United States Army
Corps of Engineers (COE) to maintain operation of the White River diversion dam
to support the COE’s ongoing operation of its Mud Mountain Dam fish passage
facilities. The agreement provides for reimbursement of a portion of PSE’s
operating costs and directs PSE to operate the diversion dam in accordance with
measures determined by federal agencies to be necessary to protect listed
species and habitat. This contract expires in September 2005, although the COE
has expressed its desire to extend the term for a period of time necessary to
allow the COE to develop a plan to acquire the diversion dam from the
Company.
In June
2003, Ecology approved an application for new municipal water rights related to
the White River project reservoir. This approval was sought in connection with
PSE’s ongoing efforts to sell the White River project to be used for commercial
purposes. An appeal of Ecology’s decision approving the new municipal water
rights was subsequently filed with the Washington State Pollution Control
Hearings Board. In July 2004, this decision was remanded back to Ecology for
further analysis of non-hydropower operations. The Company has been advised by
Ecology that Ecology anticipates issuing a revised decision by the end of 2005;
however, no firm date has been set for any such revised decision. Any proceeds
from the sale of the White River water rights will reduce the balance of the
deferred regulatory asset. Neither the outcome of this matter nor any potential
associated costs can be predicted at this time.
COLUMBIA
RIVER ELECTRIC ENERGY SUPPLY CONTRACTS
During
2004, approximately 23.1% of PSE’s energy output was obtained at an average cost
of approximately $0.0146 per kWh through long-term contracts with several of the
Washington PUDs that own and operate hydroelectric projects on the Columbia
River. PSE’s purchases of power from the Columbia River projects are on a “cost
of service” basis under which PSE pays a proportionate share of the annual debt
service and operating and maintenance costs of each project in proportion to the
contractual shares that PSE has rights to from such project. Such payments are
not contingent upon the projects being operable, which means PSE is required to
make the payments even if power is not being delivered. These projects are
financed through substantially level debt service payments, and their annual
costs may vary over the term of the contracts as additional financing is
required to meet the costs of major repairs, replacements, license requirements,
or changes to annual operating and maintenance expenses are
required.
PSE has
contracted to purchase from Chelan County PUD (Chelan) a 50% share of the output
of the original units of the Rock Island project, which percentage will remain
unchanged for the duration of the contract which expires in 2012. PSE has also
contracted to purchase the output of the additional Rock Island units for the
duration of the contract. As of December 31, 2004, PSE’s aggregate capacity from
all units of the Rock Island project was 413.9 MW. PSE’s share of output of the
additional Rock Island units may be reduced by up to 10% per year. On July 1,
2000, Chelan began withdrawing 5% of the power from the additional Rock Island
units for use in meeting its local load. The maximum withdrawal that Chelan may
make from the additional units is 50%. The schedule of withdrawals by Chelan for
the additional Rock Island units is as follows:
|
|
WITHDRAWAL
PERCENTAGE |
PSE
% OF CAPACITY AFTER
WITHDRAWAL |
|
|
10% |
65% |
|
|
10% |
55% |
|
|
5% |
50% |
PSE has
contracted to purchase from Chelan 38.9% (505 MW of peak capacity as of December
31, 2004) of the annual output of the Rocky Reach project, which percentage
remains unchanged for the remainder of the contract which expires in
2011.
PSE has
contracted to purchase from Douglas County PUD 31.3% (261 MW as of December 31,
2004) of the annual output of the Wells project, the percentage of which remains
unchanged for the remainder of the contract which expires in 2018. Early in
2003, the Colville Confederated Tribes (Colville Tribe) presented a claim to
Douglas County PUD based upon allegedly unpaid past annual charges for the Wells
Hydroelectric project for the use of Colville Tribal lands. The Colville Tribe
also claimed that annual charges would be due for periods into the future. On
November 1, 2004, Douglas County PUD entered into a settlement with the Colville
Tribe concerning claims that the Colville Tribe had asserted against Douglas
County PUD for the use by the Wells project of Tribal lands. PSE approved the
settlement and participated in the filing Douglas County PUD made on November
23, 2004 seeking FERC approval. The settlement was approved in a FERC order on
February 11, 2005. It is unlikely that any party will seek a rehearing of that
FERC order, of which the deadline for doing so is March 13, 2005. When the
settlement becomes final, the effects on PSE will be through modestly increased
power costs, and a reduction in the amount of power delivered to PSE due to the
allocation to the Colville Tribe. The Colville Tribe’s allocation will be
treated as an encroachment to the project, thus reducing the amount of power
available for purchase by others.
PSE has
contracted to purchase from Grant County PUD 8.0% (72 MW as of December 31,
2004) of the annual output of the Priest Rapids Development and 10.8% (98 MW of
peak capacity as of December 31, 2004) of the annual output of the Wanapum
Development, which percentages remain unchanged for the remainder of the
original contract terms which expire in 2005 and 2009, respectively. On December
28, 2001, PSE signed a contract offer for new contracts for the Priest Rapids
and Wanapum Developments. On April 12, 2002, PSE signed amendments to those
agreements which are technical clarifications of certain sections of the
agreements. Under the terms of these contracts, PSE will continue to obtain
capacity and energy for the term of any new FERC license to be obtained by Grant
County PUD. Grant County PUD filed an application for new license for the Priest
Rapids project on October 29, 2003. The new contracts’ terms begin in November
2005 for the Priest Rapids Development and in November 2009 for the Wanapum
Development. Unlike the current contracts, in the new contracts, PSE’s share of
power from the developments declines over time as Grant County PUD’s load
increases.
On March
8, 2002, the Yakama Nation filed a complaint with FERC which alleged that Grant
County PUD’s new contracts unreasonably restrain trade and violate various
sections of the FPA and Public Law 83-544. On November 21, 2002, FERC dismissed
the complaint while agreeing that certain aspects of the complaint had merit. As
a result, FERC has ordered Grant County PUD to remove specific sections of the
contract which constrain the parties to the Grant County PUD contracts from
competing with Grant County PUD for a new license. A rehearing was requested but
was denied by FERC on April 16, 2003. Both the Yakama Nation and Grant County
PUD have appealed the FERC decision and the appeals have been consolidated in
the Ninth Circuit Court of Appeals.
ELECTRIC
ENERGY SUPPLY CONTRACTS AND AGREEMENTS WITH OTHER
UTILITIES
PSE has
entered into long-term firm purchased power contracts with other utilities in
the West region. PSE is generally not obligated to make payments under these
contracts unless power is delivered.
Under a
1985 settlement agreement with BPA relating to Washington Public Power Supply
System Nuclear Project No. 3 (WNP-3), in which PSE had a 5 percent interest, PSE
is entitled to receive exchange energy from BPA during the months of November
through April. The power PSE receives, which amounts to 47 average MW of energy
and 82 MW of capacity for contract year 2004-2005, is tied to the equivalent
annual availability factor of several surrogate nuclear plants similar in design
to WNP-3. BPA has an option to request that PSE deliver up to 63 MW of exchange
energy to BPA in all months except May, July and August for contract year 2004 -
2005. The contract terminates June 30, 2017, but may be ended earlier if the
number of surrogate operating years of the longest running surrogate unit is
less than 30 years.
On
October 1, 1989, PSE signed a contract with The Montana Power Company, which
subsequently sold its utility assets to NorthWestern Corporation (NorthWestern)
in 2002. Under the contract, NorthWestern provides PSE 71 average MW of energy
(97 MW of peak capacity) over a 21-year period. This contract expires in
December 2010. On November 1, 2004 NorthWestern emerged from bankruptcy
protection under Chapter 11 of the U.S. Bankruptcy Code. PSE has several
long-term contracts with NorthWestern under which PSE jointly owns facilities or
purchases power or transmission services from NorthWestern. During the
bankruptcy proceeding NorthWestern affirmed its continued performance under all
of these agreements.
In
January 1992, PSE executed an exchange agreement with Pacific Gas & Electric
Company (PG&E). Under the agreement, 300 MW of capacity together with up to
413,000 MWh of energy are exchanged seasonally each year. No payments are made
under this agreement. PG&E is a summer peaking utility and provides power
during the months of November through February. PSE is a winter peaking utility
and provides power during the months of June through September. Each party may
terminate the contract upon notifying the other party at least five years in
advance.
In
February 1996, a 10-year power exchange agreement between PSE and Powerex (a
subsidiary of a British Columbia, Canada utility) became effective. Under this
agreement, Powerex pays PSE for the right to deliver up to 1,200,000 MWh
annually to PSE at the Canadian border in exchange for PSE delivering power to
Powerex at various locations in the United States. The agreement also allows
Powerex to make up any exchange volumes not used up to two years after the end
of the annual period.
ELECTRIC
ENERGY SUPPLY CONTRACTS AND AGREEMENTS WITH NON-UTILITY
GENERATORS
As
required by the federal Public Utility Regulatory Policies Act, PSE has entered
into long-term firm purchased power contracts with non-utility generators. The
most significant of these are the contracts described below which PSE entered
into in 1989, 1990, and 1991 with operators of natural gas-fired cogeneration
projects. PSE purchases the net electrical output of these three projects at
fixed and annually escalating prices, which were intended to approximate PSE’s
avoided cost of new generation projected at the time these agreements were made.
On
February 24, 1989, PSE executed a 20-year contract to purchase 108 average MW of
energy and 123 MW of capacity, beginning in April 1993, from Sumas Cogeneration
Company, LP, which owns and operates a natural gas-fired cogeneration project
located in Sumas, Washington.
On June
29, 1989, PSE executed a 20-year contract to purchase 70 average MW of energy
and 80 MW of capacity, beginning October 11, 1991, from the March Point
Cogeneration Company (March Point), which owns and operates a natural gas-fired
cogeneration facility known as March Point Phase I located at the Equilon
refinery in Anacortes, Washington. On December 27, 1990, PSE executed a second
contract (having a term coextensive with the first contract) to purchase an
additional 53 average MW of energy and 60 MW of capacity, beginning in January
1993, from another natural gas-fired cogeneration facility owned and operated by
March Point, which facility is known as March Point Phase II and is located at
the Equilon refinery in Anacortes, Washington.
On March
20, 1991, PSE executed a 20-year contract to purchase 216 average MW of energy
and 245 MW of capacity, beginning in April 1994, from Tenaska Washington
Partners, LP, which owns and operates a natural gas-fired cogeneration project
located near Ferndale, Washington. In December 1997 and January 1998, PSE and
Tenaska Washington Partners entered into revised agreements in which PSE became
the principal natural gas supplier to the project and power purchase prices
under the Tenaska contract were revised to reflect market-based prices for the
natural gas supply. PSE obtained an order from the Washington Commission
creating a regulatory asset related to the $215 million restructuring payment.
Under terms of the order, PSE was allowed to accrue as an additional regulatory
asset one-half the carrying costs of the deferred balance over the first five
years, which ended December 2002. The balance of the regulatory asset at
December 31, 2004 was $202.0 million, which will be recovered in electric rates
through 2011.
In
December 1999, PSE bought out the remaining 8.5 years of one of the natural gas
supply contracts serving Encogen from Cabot Oil & Gas Corporation (Cabot)
which provided approximately 60% of the plant’s natural gas requirements. PSE
became the replacement gas supplier to the project for 60% of the supply under
the terms of the Cabot agreement. The balance of the regulatory asset at
December 31, 2004 was $9.3 million, which will be recovered in electric rates
through 2008.
ELELCTRIC
TRANSMISSION CONTRACTS WITH OTHER UTILITIES
PSE has
entered into numerous transmission contracts with BPA to integrate electric
generation resources and energy contracts into the PSE system to serve native
load. These transmission contracts specify that PSE will pay for transmission
service based on the contracted megawatt level of demand, regardless of actual
use. Other agreements, notably the Westside Northern Intertie Agreement and the
AC Intertie Capacity Ownership Agreement provide capacity ownership type rights
to PSE. PSE’s annual charges are also based on contracted megawatt amounts.
Capacity on these agreements that are not committed for native load or other
uses are available for sale to third parties on PSE’s Open Access Same Time
Information System (OASIS). PSE purchases short term transmission services from
a variety of providers, including BPA.
The
transmission agreements with BPA provide, among other things, the integration of
PSE’s energy resources including PSE’s share of the Mid-Columbia hydroelectric
projects, the Colstrip project and the PG&E exchange. The agreements have
various terms ranging from specified dates in the 1 to 14 year time frame to
life-of-facilities, the latter being in effect as long as the transmission
facilities themselves are fully functional. Collectively, the agreements have an
aggregate demand limit in excess of 2,200 MW.
In April
2004, PSE entered into a two-year contract with BPA to integrate the output of
PSE’s recently acquired share of the Frederickson 1 plant. The hourly demand
limit of this contract is 150 MW.
PSE’s
transmission expenses for integrating its firm resources was $34.7 million in
2004. The transmission rates used by BPA for these contracts are effective
through September 30, 2005. BPA rates change from time to time based upon BPA’s
rate cases.
On
December 6, 2004, BPA offered a proposed transmission rate case settlement
agreement to BPA’s transmission customers. Under the terms of the settlement
agreement, the BPA IR Rate, the rate at which PSE receives the vast majority of
its transmission service from BPA, will increase 17.6%. On January 6, 2005, BPA
reached settlement with all its customers. BPA must file the settlement
agreement with FERC and wait for FERC’s approval before rates can go into
effect. It is anticipated that rates will go into effect October 1,
2005.
|
TWELVE
MONTHS ENDED DECEMBER 31 |
|
2004 |
|
2003 |
|
2002 |
|
Gas
operating revenues by classes (thousands): |
|
|
|
|
|
|
|
|
Residential |
|
$ |
478,969 |
|
$ |
401,717 |
|
$ |
428,569 |
|
|
Commercial
firm |
|
|
187,262 |
|
|
149,671 |
|
|
167,434 |
|
|
Industrial
firm |
|
|
30,472 |
|
|
24,164 |
|
|
28,312 |
|
|
Interruptible |
|
|
46,900 |
|
|
34,046 |
|
|
48,889 |
|
|
Total
retail gas sales |
|
|
743,603 |
|
|
609,598 |
|
|
673,204 |
|
|
Transportation
services |
|
|
12,968 |
|
|
13,796 |
|
|
12,851 |
|
|
Other |
|
|
12,735 |
|
|
10,836 |
|
|
11,100 |
|
|
Total
gas operating revenues |
|
$ |
769,306 |
|
$ |
634,230 |
|
$ |
697,155 |
|
|
Number
of customers served (average): |
|
|
|
|
|
|
|
|
|
|
|
Residential |
|
|
605,505 |
|
|
583,439 |
|
|
565,003 |
|
|
Commercial
firm |
|
|
48,457 |
|
|
46,813 |
|
|
45,916 |
|
|
Industrial
firm |
|
|
2,678 |
|
|
2,685 |
|
|
2,727 |
|
|
Interruptible |
|
|
576 |
|
|
611 |
|
|
650 |
|
|
Transportation |
|
|
129 |
|
|
134 |
|
|
122 |
|
|
Total
customers |
|
|
657,345 |
|
|
633,682 |
|
|
614,418 |
|
|
Gas
volumes, therms (thousands): |
|
|
|
|
|
|
|
|
|
|
|
Residential |
|
|
489,036 |
|
|
500,116 |
|
|
500,672 |
|
|
Commercial
firm |
|
|
217,346 |
|
|
216,951 |
|
|
218,716 |
|
|
Industrial
firm |
|
|
36,751 |
|
|
36,890 |
|
|
39,142 |
|
|
Interruptible |
|
|
65,425 |
|
|
61,739 |
|
|
81,045 |
|
|
Total
retail gas volumes, therms |
|
|
808,558 |
|
|
815,696 |
|
|
839,575 |
|
|
Transportation
volumes |
|
|
201,642 |
|
|
209,497 |
|
|
207,852 |
|
|
Total
volumes |
|
|
1,010,200 |
|
|
1,025,193 |
|
|
1,047,427 |
|
|
Working
gas volumes in storage at year end, therms (thousands): |
|
|
|
|
|
|
|
Jackson
Prairie |
|
|
70,986 |
|
|
60,365 |
|
|
64,583 |
|
|
Clay
Basin |
|
|
55,044 |
|
|
49,314 |
|
|
51,225 |
|
|
Average
therms used per customer: |
|
|
|
|
|
|
|
|
|
|
|
Residential |
|
|
808 |
|
|
857 |
|
|
886 |
|
|
Commercial
firm |
|
|
4,485 |
|
|
4,634 |
|
|
4,763 |
|
|
Industrial
firm |
|
|
13,723 |
|
|
13,739 |
|
|
14,354 |
|
|
Interruptible |
|
|
113,585 |
|
|
101,046 |
|
|
124,685 |
|
|
Transportation |
|
|
1,563,116 |
|
|
1,563,410 |
|
|
1,703,705 |
|
|
Average
revenue per customer: |
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
$ |
791 |
|
$ |
689 |
|
$ |
759 |
|
|
Commercial
firm |
|
|
3,864 |
|
|
3,197 |
|
|
3,647 |
|
|
Industrial
firm |
|
|
11,379 |
|
|
9,000 |
|
|
10,382 |
|
|
Interruptible |
|
|
81,424 |
|
|
55,722 |
|
|
75,214 |
|
|
Transportation |
|
|
100,527 |
|
|
102,955 |
|
|
105,336 |
|
|
Average
revenue per therm sold: |
|
|
|
|
|
|
|
|
|
|
|
Residential |
|
$ |
0.979 |
|
$ |
0.803 |
|
$ |
0.855 |
|
|
Commercial
firm |
|
|
0.862 |
|
|
0.690 |
|
|
0.766 |
|
|
Industrial
firm |
|
|
0.829 |
|
|
0.655 |
|
|
0.723 |
|
|
Interruptible |
|
|
0.717 |
|
|
0.551 |
|
|
0.603 |
|
|
Average
retail revenue per therm sold |
|
|
0.920 |
|
|
0.747 |
|
|
0.802 |
|
|
Transportation |
|
|
0.064 |
|
|
0.066 |
|
|
0.062 |
|
PSE
currently purchases a blended portfolio of gas supplies ranging from long-term
firm to daily gas supplies from a diverse group of major and independent natural
gas producers and marketers in the United States and Canada. PSE also enters
into short-term physical and financial fixed price derivative instruments to
hedge the cost of gas to serve its customers. All of PSE’s gas supply is
ultimately transported through the facilities of Williams Northwest Pipeline
Corporation (NWP), the sole interstate pipeline delivering directly into the
western Washington area. Delivery of gas supply to PSE’s gas system is therefore
dependent upon the operations of NWP.
| |
|
2004 |
|
2003 |
|
|
PEAK
FIRM GAS SUPPLY AT DECEMBER 31 |
|
|
Dth
per Day |
|
|
% |
|
|
Dth
per Day |
|
|
% |
|
Purchased
gas supply: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
British
Columbia |
|
|
198,000 |
|
|
22.7 |
% |
|
171,000 |
|
|
20.0 |
% |
|
Alberta |
|
|
50,000 |
|
|
5.7 |
% |
|
78,000 |
|
|
9.2 |
% |
|
United
States |
|
|
145,000 |
|
|
16.6 |
% |
|
100,000 |
|
|
11.7 |
% |
|
Total
purchased gas supply |
|
|
393,000 |
|
|
45.0 |
% |
|
349,000 |
|
|
40.9 |
% |
|
Purchased
storage capacity: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Clay
Basin |
|
|
48,000 |
|
|
5.5 |
% |
|
55,800 |
|
|
6.5 |
% |
|
Jackson
Prairie |
|
|
55,100 |
|
|
6.3 |
% |
|
55,100 |
|
|
6.4 |
% |
|
LNG |
|
|
70,500 |
|
|
8.1 |
% |
|
70,500 |
|
|
8.2 |
% |
|
Total
purchased storage capacity |
|
|
173,600 |
|
|
19.9 |
% |
|
181,400 |
|
|
21.1 |
% |
|
Owned
storage capacity: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jackson
Prairie |
|
|
294,700 |
|
|
33.7 |
% |
|
294,700 |
|
|
34.4 |
% |
|
Propane-air
and other |
|
|
12,500 |
|
|
1.4 |
% |
|
30,500 |
|
|
3.6 |
% |
|
Total
owned storage capacity |
|
|
307,200 |
|
|
35.1 |
% |
|
325,200 |
|
|
38.0 |
% |
|
Total
peak firm gas supply |
|
|
873,800 |
|
|
100.0 |
% |
|
855,600 |
|
|
100.0 |
% |
|
Other
and commitments with third parties |
|
|
(53,100 |
) |
|
|
|
|
(53,200 |
) |
|
|
|
|
Total
net peak firm gas supply |
|
|
820,700 |
|
|
|
|
|
802,400 |
|
|
|
|
All peak firm
gas supplies and storage are connected to PSE’s market with firm transportation
capacity.
For
baseload and peak-shaving purposes, PSE supplements its firm gas supply
portfolio by purchasing natural gas, injecting it into underground storage
facilities and withdrawing it during the peak winter heating season. Storage
facilities at Jackson Prairie in western Washington and at Clay Basin in Utah
are used for this purpose. Jackson Prairie is also used for daily balancing of
load requirements on PSE’s gas system. PSE has been in the process of expanding
the storage capacity at Jackson Prairie since March 2003, and plans to continue
doing so through 2008. At the end of this project, PSE will have added
approximately 2,000,000 Dekatherms (one Dekatherm, or Dth, is equal to one
million British thermal units or MMBtu) of additional working storage capacity.
Peaking needs are also met by using PSE-owned gas held in NWP’s liquefied
natural gas (LNG) facility at Plymouth, Washington, by producing propane-air gas
at a plant owned by PSE and located on its distribution system, and by
interrupting service to customers on interruptible service rates.
PSE
expects to meet its firm peak-day requirements for residential, commercial and
industrial markets through its firm gas purchase contracts, firm transportation
capacity, firm storage capacity and other firm peaking resources. PSE believes
it will be able to acquire incremental firm gas supply to meet anticipated
growth in the requirements of its firm customers for the foreseeable
future.
GAS SUPPLY PORTFOLIO
For the
2004-2005 winter heating season, PSE contracted for approximately 22.7% of its
expected peak-day gas supply requirements from sources originating in British
Columbia, Canada under a combination of long-term, medium-term and seasonal
purchase agreements. Long-term gas supplies from Alberta represent approximately
5.7% of the peak-day requirements. Long-term and winter peaking arrangements
with U.S. suppliers make up approximately 16.6% of the peak-day portfolio. The
balance of the peak-day requirements is expected to be met with gas stored at
Jackson Prairie, gas stored at Clay Basin, LNG held at NWP’s Plymouth facility
and propane-air and other resources, which represent approximately 40.0%, 5.5%,
8.1% and 1.4%, respectively, of expected peak-day requirements. PSE also has the
ability to curtail service to industrial and commercial customers on
interruptible service rates during a peak-day event.
During
2004, approximately 32% of gas supplies purchased by PSE originated in British
Columbia while 20% originated in Alberta and 48% originated in the United
States. The current firm, long-term gas supply portfolio consists of
arrangements with 12 producers and gas marketers, with no single supplier
representing more than 4% of expected peak-day requirements. Contracts have
remaining terms ranging from less than one year to ten years.
PSE’s
firm gas supply portfolio has flexibility in its transportation arrangements so
that some savings can be achieved when there are regional price differentials
between gas supply basins. The geographic mix of suppliers and daily, monthly
and annual take requirements permit some degree of flexibility in managing gas
supplies during off-peak periods to minimize costs. Gas is marketed outside
PSE’s service territory (off-system sales) whenever on-system customer demand
requirements permit.
GAS STORAGE CAPACITY
PSE holds
storage capacity in the Jackson Prairie and Clay Basin underground gas storage
facilities adjacent to NWP’s pipeline. These facilities represent 45.5% of the
expected peak-day portfolio. The Jackson Prairie facility, operated and
one-third owned by PSE, is used primarily for intermediate peaking purposes
since it is able to deliver a large volume of gas over a relatively short time
period. Combined with capacity contracted from NWP’s one-third stake in Jackson
Prairie, PSE has peak firm delivery capacity of over 349,000 Dth per day and
total firm storage capacity exceeding 8,100,000 Dth at the facility. The
location of the Jackson Prairie facility in PSE’s market area increases supply
reliability and provides significant pipeline demand cost savings by reducing
the amount of annual pipeline capacity required to meet peak-day gas
requirements. The Clay Basin storage facility is a supply area storage facility
that is used primarily to reduce portfolio costs through injections and
withdrawals that take advantage of market price volatility and is also used for
system reliability. After the release of capacity in 2004, PSE retained maximum
firm withdrawal capacity of over 60,000 Dth per day from the Clay Basin facility
with total storage capacity of almost 7,419,000 Dth. The Clay Basin capacity is
held under two long-term contracts with remaining terms of 8 and 15 years. The
capacity release contracts PSE has with multiple parties at the Clay Basin
storage facility have remaining terms of three months as of December 31, 2004,
with automatic renewal for 12-month terms. PSE’s maximum firm withdrawal
capacity and total storage capacity at Clay Basin is over 110,000 Dth per day
and exceeds 13,000,000 Dth, respectively, when PSE has not released any of the
capacity.
LNG
AND PROPANE-AIR RESOURCES
LNG and
propane-air resources provide gas supply on short notice for short periods of
time. Due to their typically high cost, these resources are normally utilized as
the supply of last resort in extreme peak-demand periods, typically lasting a
few hours or days. PSE has a long-term contract for storage of 241,700 Dth of
PSE-owned gas as LNG at NWP’s Plymouth facility, which equates to approximately
three and one-half days supply at a maximum daily deliverability of 70,500 Dth.
PSE owns storage capacity for approximately 1.5 million gallons of propane. The
propane-air injection facilities are capable of delivering the equivalent of
10,000 Dth of gas per day for up to twelve days directly into PSE’s distribution
system.
In 2004,
a 6,000 Dth capacity LNG storage facility was completed in Gig Harbor. The
purpose of the facility is to provide a supplemental supply of natural gas
during periods of high demand, improve overall system reliability and eliminate
the need for portable LNG operations in the Gig Harbor area. Included in the
facility are a transport trailer, storage tank, transfer station and send out
skid.
GAS
TRANSPORTATION CAPACITY
PSE
currently holds firm transportation capacity on pipelines owned by NWP, Gas
Transmission Northwest, TransCanada Pipelines, Ltd. (TransCanada), and Duke
Energy Gas Transmission (Westcoast). Accordingly, PSE pays fixed monthly demand
charges for the right, but not the obligation, to transport specified quantities
of gas from receipt points to delivery points on such pipelines each day for the
term or terms of the applicable agreements.
PSE and
WNG CAP I, a wholly-owned subsidiary of PSE, hold firm year-round capacity on
NWP through various contracts. PSE and WNG CAP I participate in the secondary
pipeline capacity market to achieve savings for PSE’s customers. As a result,
PSE and WNG CAP I hold approximately 465,000 Dth per day of capacity due to
capacity release and segmentation transactions on NWP that provides firm
delivery to PSE’s service territory. In addition, PSE holds approximately
413,000 Dth per day of seasonal firm capacity on NWP to provide for delivery of
stored gas during the heating season. PSE has firm transportation capacity on
NWP that supplies the Frederickson 1 generating facility of approximately 22,000
Dth per day, with a remaining term of 14 years. PSE has released certain
segments of its firm capacity with third parties to effectively lower
transportation costs. PSE’s firm transportation capacity contracts with NWP have
remaining terms ranging from less than 1 year to 12 years. However, PSE has
either the unilateral right to extend the contracts under their current terms or
the right of first refusal to extend such contracts under current FERC orders.
PSE’s firm transportation capacity on Gas Transmission Northwest’s pipeline,
totaling approximately 90,000 Dth per day, has a remaining term of 19 years.
PSE’s
firm transportation capacity on Westcoast’s pipeline, totaling approximately
40,000 Dth per day, has a remaining term of 10 years for approximately 25,000
Dth per day and a remaining term of 14 years for approximately 15,000 Dth per
day. PSE has other firm transportation capacity on Westcoast’s pipeline, which
supplies the Frederickson 1 generating facility, totaling approximately 22,000
Dth per day, with a remaining term of 10 years. PSE’s firm capacity on
TransCanada’s Alberta and British Columbia transportation systems, totaling
approximately 80,000 Dth per day, phases in year to year renewal rights
beginning in 2006. In addition, PSE has firm transportation capacity on
TransCanada’s pipelines commencing in 2008 with a term of 15 years, totaling
approximately 8,000 Dth per day.
During
2003, NWP took one of its two parallel pipelines serving western Washington from
British Columbia out of service as a result of a second failure of the affected
pipeline. Together, these two pipelines had the ability to flow approximately
1,300,000 Dth per day of gas from British Columbia. The loss of the affected
pipeline reduced this ability to approximately 950,000 Dth per day. Subsequent
to testing and remediation efforts, portions of the affected line were returned
to service in 2004, increasing the ability to flow gas from British Columbia to
approximately 1,100,000 Dth per day. If the affected pipeline is not completely
returned to service, the loss could potentially decrease PSE’s overall NWP
capacity by 5%. In December 2004, NWP filed a request for authorization from
FERC to replace all of the lost capacity through construction of new facilities.
NWP expects to complete such Capacity Replacement project by the end of 2006.
The cost of the Capacity Replacement project is expected to increase the cost
for services that PSE receives from NWP by approximately 20% beginning in 2007.
PSE expects that the increase will be entirely recoverable from customers
through the existing PGA mechanism. To date, the loss of capacity has not
adversely impacted PSE’s ability to serve its gas customers, but customers on
interruptible tariff rate schedules could be curtailed during peak events. PSE
expects to continue meeting its customer needs throughout the pipeline capacity
replacement period, and PSE has back-up oil supply for its combustion
turbines.
FERC
provided a capacity release mechanism as the means for holders of firm pipeline
and storage entitlements to temporarily relinquish unutilized capacity to others
in order to recoup all or a portion of the cost of such capacity. Capacity may
be released through several methods including open bidding and by
pre-arrangement. PSE continues to successfully mitigate a portion of the demand
charges related to both storage and NWP pipeline capacity not utilized during
off-peak periods through capacity release. WNG CAP I was formed to provide
additional flexibility and benefits from capacity release. Capacity release
benefits are passed on to customers through the PGA mechanism.
PSE
offers programs designed to help new and existing customers use energy
efficiently. PSE uses a variety of mechanisms including cost-effective financial
incentives, information and technical services to enable customers to make
energy-efficient choices with respect to building design, equipment and building
systems, appliance purchases and operating practices.
Since May
1997, PSE has recovered electric energy efficiency (or conservation)
expenditures through a tariff rider mechanism. The rider mechanism allows PSE to
defer the efficiency expenditures and amortize them to expense as PSE
concurrently collects the efficiency expenditures in rates over a one-year
period. As a result of the rider, electric energy efficiency expenditures have
no effect on earnings.
Since
1995, PSE has been authorized by the Washington Commission to defer gas energy
efficiency (or conservation) expenditures and recover them through a tariff
tracker mechanism. The tracker mechanism allows PSE to defer efficiency
expenditures and recover them in rates over the subsequent year. The tracker
mechanism also allows PSE to recover an Allowance for Funds Used to Conserve
Energy on any outstanding balance that is not being recovered in rates. As a
result of the tracker mechanism, gas energy efficiency expenditures have no
impact on earnings.
Energy
efficiency programs reduce customer consumption of energy thus impacting energy
margins. The impact of load reductions are adjusted in rates at each general
rate case.
The
Company’s operations are subject to environmental laws and regulation by
federal, state and local authorities. Due to the inherent uncertainties
surrounding the development of federal and state environmental and energy laws
and regulations, the Company cannot determine the impact such laws may have on
its existing and future facilities. (See Note 23 to the Consolidated Financial
Statements for further discussion of environmental sites.)
REGULATION OF
EMISSIONS
PSE has
an ownership interest in coal-fired, steam-electric generating plants at
Colstrip, Montana, which are subject to regulation of emissions and other
regulatory requirements. PSE also owns combustion turbine units in western
Washington, which are capable of being fueled by natural gas or diesel fuel.
These combustion turbines are operated to comply with emission limits set forth
in their respective air operating permits.
There is
no assurance that in the future, environmental regulations affecting sulfur
dioxide, carbon monoxide particulate matter or nitrogen oxide emissions may not
be further restricted, or that restrictions on greenhouse gas emissions, such as
carbon dioxide, or other combustion byproducts, such as mercury, may not be
imposed.
In
December 2003, Colstrip Units 1 & 2 and 3 & 4 received an information
request from the Environmental Protection Agency (EPA) relating to their
compliance with the Clean Air Act New Source Review regulations. PSE is
currently in discussions with the EPA concerning the information request.
Neither the outcome of this matter nor any potential associated costs can be
predicted at this time
FEDERAL
ENDANGERED SPECIES ACT
Since the
1991 listing of the Snake River Sockeye salmon as an endangered species, a total
of eight species of salmon and steelhead have been listed as endangered species,
which influences operations. Most directly associated with project operations,
the Upper Columbia River Steelhead and the Upper Columbia Spring Chinook were
listed as endangered species by the National Marine Fisheries Service in August
1997 and March 1999, respectively. To address this exposure, the Mid-Columbia
PUDs initiated consultation with federal and state agencies, Native American
tribes and non-governmental organizations to secure operational protection
through long-term settlements and habitat conservation plans (HCPs) for each
affected project. The agreement provisions include fish protection and
enhancement measures for the next 50 years. The HCPs received the support of the
resource agencies, have been adopted by FERC and generally obligate the PUDs to
achieve certain levels of passage efficiency for downstream migrants at their
hydroelectric facilities and to fund certain habitat conservation measures.
Grant County PUD reached an agreement with the various parties in 2004 in a form
substantially similar to the HCPs adopted by Douglas County PUD and Chelan
County PUD. FERC issued an order approving that settlement and terminating the
Mid-Columbia fish proceeding as to all parties on December 16,
2004.
The
proposed listings of Puget Sound Chinook salmon and spring Chinook salmon as
endangered species for the upper Columbia River were approved in March 1999. The
Company does not expect the listing of spring Chinook salmon as an endangered
species for the upper Columbia River to result in markedly differing conditions
for operations from previous listings in the area.
The
completed listings of Coastal/Puget Sound Distinct Population Segment of Bull
Trout as an endangered species in the fall of 1999 and Puget Sound Chinook
salmon in the winter of 2001 are causing a number of changes to operations of
governmental agencies and private entities in the region, including PSE. These
changes may adversely affect hydroelectric plant operations and permit issuance
for facilities construction, and increase costs for processes and facilities.
Because PSE relies substantially less on hydroelectric energy from the Puget
Sound area than from the Mid-Columbia River and also because the impact on PSE
operations in the Puget Sound area is not likely to impair significant
generating resources, the impact of listing for Puget Sound Chinook salmon and
Bull Trout, while potentially representing cost exposure and operational
constraints, should be proportionately less than the effects of the Columbia
River listings. PSE is actively engaging the federal agencies to address
Endangered Species Act issues for PSE’s generating facilities. Consultation with
federal agencies is ongoing.
The
executive officers of Puget Energy as of December 31, 2004 are listed below.
Puget Energy considers the Chief Executive Officer of InfrastruX to be an
executive officer of Puget Energy. For their business experience during the past
five years, please refer to the table below regarding Puget Sound Energy’s
executive officers. Officers of Puget Energy are elected for one-year
terms.
|
NAME |
AGE |
OFFICES |
|
S.
P. Reynolds |
56 |
President
and Chief Executive Officer since January 2002. Director since January
2002. |
|
J.
W. Eldredge |
54 |
Corporate
Secretary and Chief Accounting Officer since April 1999.
|
|
D.
E. Gaines |
47 |
Vice
President Finance and Treasurer since March 2002. |
|
M.
T. Lennon |
42 |
President
and Chief Executive Officer of InfrastruX since April 2003, President of
InfrastruX, 2002 - 2003. Prior to joining InfrastruX, he served as
Managing Director of Lennon Smith Advisors, LLC, an investment banking
firm, 2000 - 2002. |
|
J.
L. O’Connor |
48 |
Vice
President and General Counsel since January 2003. |
|
B.
A. Valdman |
41 |
Senior
Vice President Finance and Chief Financial Officer since January 2004.
|
The
executive officers of Puget Sound Energy as of December 31, 2004 are listed
below along with their business experience during the past five years. Officers
of Puget Sound Energy are elected for one-year terms.
|
NAME |
AGE |
OFFICES |
|
S.
P. Reynolds |
56 |
President
and Chief Executive Officer and Director since January 2002; President and
Chief Executive Officer of Reynolds Energy International, 1998 -
2002. |
|
D.
P. Brady |
40 |
Vice
President Customer Services since February 2003; Director and Assistant to
Chief Operating Officer, 2002 - 2003. Prior to joining PSE, he was
Managing Director of Irvine Associates Merchant Banking Group, 2001 -
2002; Executive Vice President-Operations of Orcom Solutions, 2000 -
2001. |
|
P.
K. Bussey |
48 |
Vice
President Regional and Public Affairs since September 2003. Prior to
joining PSE, he was President of the Washington Round Table, 1996 -
2003. |
|
J.
W. Eldredge |
54 |
Vice
President, Corporate Secretary, Controller and Chief Accounting Officer
since May 2001; Corporate Secretary, Controller and Chief Accounting
Officer, 1993 - 2001. |
|
D.
E. Gaines |
47 |
Vice
President Finance and Treasurer since March 2002; Vice President and
Treasurer, 2001 - 2002; Treasurer, 1994 - 2001. |
|
K.
J. Harris |
40 |
Vice
President Regulatory and Government Affairs since February 2003; Vice
President Regulatory Affairs, 2002 - 2003; Director Load Resource
Strategies and Associate General Counsel, 2001 - 2002; Associate General
Counsel, 1999 - 2001. |
|
J.
L. Henry |
59 |
Senior
Vice President Energy Efficiency and Customer Services since February
2003; Director of Major Accounts, 2001 - 2003; Director Construction and
Technical Field Services 2000 - 2001. |
|
E.
M. Markell |
53 |
Senior
Vice President Energy Resources since February 2003; Vice President
Corporate Development, 2002 - 2003. Prior to joining PSE, he was Chief
Financial Officer, Club One, Inc., 2000 - 2002. |
|
S.
McLain |
48 |
Senior
Vice President Operations since February 2003; Vice President Operations -
Delivery, 1999 - 2003. |
|
J.
L. O’Connor |
48 |
Vice
President and General Counsel since January 2003. Prior to joining PSE,
she was interim General Counsel, Starbucks Corporation, 2002; Senior Vice
President and Deputy General Counsel, Starbucks Corporation, 2001 - 2002;
Vice President and Assistant General Counsel, Starbucks Corporation, 1998
- 2001. |
|
J.
M. Ryan |
42 |
Vice
President Risk Management and Strategic Planning since April 2004; Vice
President Energy Portfolio Management, 2001 - 2004. Prior to joining PSE,
she was Managing Director of North American Marketing of TransAlta USA,
2001; Managing Director Origination of Merchant Energy Group of the
Americas, Inc., 1997 - 2001. |
|
B.
A. Valdman |
41 |
Senior
Vice President Finance and Chief Financial Officer since December 2003.
Prior to joining PSE, he was Managing Director with JP Morgan Securities,
Inc., 2000 - 2003 and a member of the Natural Resource Group of JP Morgan
Securities, Inc. since 1993 and a banker with JP Morgan since
1987. |
|
P.
M. Wiegand |
52 |
Vice
President Project Development and Contract Management since July 2003;
Vice President Corporate Planning, 2003; Vice President Corporate Planning
and Performance, 2002 - 2003; Vice President Risk Management and Strategic
Planning 2000 - 2002. |
The
principal electric generating plants and underground gas storage facilities
owned by PSE are described under Item 1, Business - Electric Supply and Gas
Supply. PSE owns its transmission and distribution facilities and various other
properties. Substantially all properties of PSE are subject to the liens of
PSE’s mortgage indentures. PSE’s corporate headquarters is housed in a leased
building located in Bellevue, Washington.
InfrastruX
operates a fleet of vehicles and equipment that it uses in its utility
construction business. Its fleet is composed of owned and leased trucks and
other specialized equipment such as backhoes, trenchers, boring machines, cranes
and other equipment required to perform its work. InfrastruX owns some of the
facilities out of which it operates and rents the remaining facilities. The
majority of InfrastruX’s owned facilities are subject to liens under existing
debt and lines of credit. InfrastruX’s corporate headquarters is housed in a
leased building located in Bellevue, Washington.
See the
section under Item 7, Management’s Discussion and Analysis of Financial
Condition and Results of Operations-Proceedings Relating to the Western Power
Market.
Contingencies
arising out of the normal course of the Company’s business exist at December 31,
2004. The ultimate resolution of these issues are not expected to have a
material adverse impact on the financial condition, results of operations or
liquidity of the Company.
Puget
Energy’s common stock, the only class of common equity of Puget Energy, is
traded on the New York Stock Exchange under the symbol “PSD.” At February 23,
2005, there were approximately 40,400 holders of record of Puget Energy’s common
stock. The outstanding shares of PSE’s common stock, the only class of common
equity of PSE, are held by Puget Energy and are not traded.
The
following table shows the market price range of, and dividends paid on, Puget
Energy’s common stock during the periods indicated in 2004 and 2003. Puget
Energy and its predecessor companies have paid dividends on common stock each
year since 1943 when such stock first became publicly held.
| |
2004 |
|
2003 |
| |
PRICE
RANGE |
DIVIDENDS |
|
PRICE
RANGE |
DIVIDENDS |
|
QUARTER
ENDED |
HIGH |
LOW |
PAID |
|
HIGH |
LOW |
PAID |
|
March
31 |
$23.92 |
|
$21.59 |
|
$0.25 |
|
|
$23.00 |
|
$18.10 |
|
$0.25 |
|
|
June
30 |
22.88 |
|
20.51 |
|
0.25 |
|
|
24.40 |
|
20.78 |
|
0.25 |
|
|
September
30 |
23.00 |
|
21.05 |
|
0.25 |
|
|
24.17 |
|
21.02 |
|
0.25 |
|
|
December
31 |
24.81 |
|
22.27 |
|
0.25 |
|
|
23.99 |
|
22.14 |
|
0.25 |
|
The
amount and payment of future dividends will depend on Puget Energy’s financial
condition, results of operations, capital requirements and other factors deemed
relevant by Puget Energy’s Board of Directors. The Board of Directors’ current
policy is to pay out approximately 60% of normalized utility earnings in
dividends.
Puget
Energy’s primary source of funds for the payment of dividends to its
shareholders is dividends received from PSE. PSE’s payment of common stock
dividends to Puget Energy is restricted by provisions of certain covenants
applicable to preferred stock and long-term debt contained in PSE’s Articles of
Incorporation and electric and gas mortgage indentures. Under the most
restrictive covenants of PSE, earnings reinvested in the business unrestricted
as to payment of cash dividends were approximately $274.4 million at December
31, 2004.
The
following tables show selected financial data. Puget Energy became the holding
company for PSE on January 1, 2001 pursuant to a plan of exchange in which each
share of PSE common stock was exchanged on a one-for-one basis for Puget Energy
common stock. Puget Energy results are not on a comparable basis as InfrastruX
had acquisitions from 2000 to 2003.
|
Puget
Energy
Summary
of Operations
(Dollars
in Thousands, Except Per Share Data) |
|
Years
Ended December 31 |
2004 |
20031 |
2002 |
20012 |
20003 |
|
Operating
revenue 4 |
$ |
2,568,813 |
$ |
2,382,803 |
$ |
2,315,181 |
$ |
2,886,560 |
$ |
3,302,296 |
|
Operating
income |
|
216,751 |
|
305,175 |
|
309,669 |
|
297,121 |
|
363,872 |
|
Net
income before cumulative effect of
accounting
change |
|
55,022 |
|
116,366 |
|
110,052 |
|
113,175 |
|
193,831 |
|
Net
income from continuing operations5 |
|
55,022 |
|
116,197 |
|
110,052 |
|
98,426 |
|
184,837 |
|
Basic
earnings per common share from
continuing
operations |
|
0.55 |
|
1.23 |
|
1.24 |
|
1.14 |
|
2.16 |
|
Diluted
earnings per common share from continuing operations |
|
0.55 |
|
1.22 |
|
1.24 |
|
1.14 |
|
2.16 |
|
Dividends
per common share |
$ |
1.00 |
$ |
1.00 |
$ |
1.21 |
$ |
1.84 |
$ |
1.84 |
|
Book
value per common share |
|
16.25 |
|
16.71 |
|
16.27 |
|
15.66 |
|
16.61 |
|
Total
assets at year end |
$ |
5,833,369 |
$ |
5,699,002 |
$ |
5,772,133 |
$ |
5,668,481 |
$ |
5,677,266 |
|
Long-term
obligations |
|
2,212,532 |
|
1,969,489 |
|
2,160,276 |
|
2,127,054 |
|
2,170,797 |
|
Preferred
stock subject to mandatory redemption |
|
1,889 |
|
1,889 |
|
43,162 |
|
50,662 |
|
58,162 |
|
Corporation
obligated, mandatorily redeemable preferred securities of subsidiary trust
holding solely junior subordinated debentures of the
corporation |
|
-- |
|
-- |
|
300,000 |
|
300,000 |
|
100,000 |
|
Junior
subordinated debentures of the corporation payable to a subsidiary trust
holding mandatorily redeemable preferred securities |
|
280,250 |
|
280,250 |
|
-- |
|
-- |
|
-- |
__________________________
| 1 |
In
2003, FASB issued Interpretation No. 46 (FIN 46) which required the
consolidation of PSE’s 1995 Conservation Trust Transaction. As a result,
revenues and expense increased $5.7 million with no effect on net income,
and assets and liabilities increased $4.2 million in 2003. FIN 46 also
required deconsolidation of PSE’s trust preferred securities that are now
classified as junior subordinated debt. This deconsolidation has no impact
on assets, liabilities, receivables or earnings for
2003. |
| 2 |
In
2001, SFAS No. 133 was implemented, which required derivative instruments
to be valued at fair price. |
| 3 |
Amounts
represent PSE activity prior to the formation of Puget Energy as a holding
company of PSE on January 1, 2001. |
| 4 |
Operating
Electric Revenues and Purchased Electricity expenses in 2003 and 2002 were
revised as a result of implementing Emerging Issues Task Force Issue No.
03-11, “Reporting Realized Gains and Losses on Derivative Instruments That
Are Subject to FASB No. 133 and Not ‘Held for Trading Purposes’ as Defined
in Issue No. 02-03” (EITF No. 03-11), which became effective on January 1,
2004. Operating Electric Revenues and Purchased Electricity expense for
Puget Energy and Puget Sound Energy were reduced by $108.7 million and
$77.1 million in 2003 and 2002, respectively, with no effect on net
income. Information for 2001 and 2000 is not available, and therefore
revenue and expense were not adjusted for the effects of EITF No. 03-11 in
those years. |
| 5 |
Net
income in 2000 includes preferred stock dividend accrual at PSE, which is
treated as an other deduction at Puget Energy starting January 1,
2001. |
|
Puget
Sound Energy
Summary
of Operations
(Dollars
in Thousands) |
|
Years
Ended December 31 |
2004 |
20031 |
2002 |
20012 |
2000 |
|
Operating
revenue 3 |
$ |
2,198,877 |
$ |
2,041,016 |
$ |
1,995,652 |
$ |
2,712,774 |
$ |
3,302,296 |
|
Operating
income |
|
288,241 |
|
297,904 |
|
294,593 |
|
288,480 |
|
363,8872 |
|
Net
income before cumulative effect
of
accounting change |
|
126,192 |
|
120,055 |
|
108,948 |
|
119,130 |
|
193,831 |
|
Income
for common stock from
continuing
operations |
|
126,192 |
|
114,735 |
|
101,117 |
|
95,968 |
|
184,837 |
|
Total
assets at year end |
$ |
5,564,087 |
$ |
5,359,104 |
$ |
5,453,390 |
$ |
5,439,253 |
$ |
5,677,266 |
|
Long-term
obligations |
|
2,064,360 |
|
1,950,347 |
|
2,021,832 |
|
2,053,815 |
|
2,170,797 |
|
Preferred
stock subject to mandatory redemption |
|
1,889 |
|
1,889 |
|
43,162 |
|
50,662 |
|
58,162 |
|
Corporation
obligated, mandatorily
redeemable
preferred securities of
subsidiary
trust holding solely junior
subordinated
debentures of the corporation |
|
-- |
|
-- |
|
300,000 |
|
300,000 |
|
100,000 |
|
Junior
subordinated debentures of the
corporation payable to a
subsidiary trust
holding
mandatorily redeemable preferred
securities |
|
280,250 |
|
280,250 |
|
-- |
|
-- |
|
-- |
__________________________
| 1 |
In
2003, FASB issued Interpretation No. 46 (FIN 46) which required the
consolidation of PSE’s 1995 Conservation Trust Transaction. As a result,
revenues and expense increased $5.7 million with no effect on net income,
and assets and liabilities increased $4.2 million in 2003. FIN 46 also
required deconsolidation of PSE’s trust preferred securities that are now
classified as junior subordinated debt. This deconsolidation has no impact
on assets, liabilities, receivables or earnings for
2003. |
| 2 |
In
2001, SFAS No. 133 was implemented, which required derivative instruments
to be valued at fair price. |
| 3 |
Operating
Electric Revenues and Purchased Electricity Expenses in 2003 and 2002 were
revised as a result of implementing Emerging Issues Task Force Issue No.
03-11, “Reporting Realized Gains and Losses on Derivative Instruments That
Are Subject to FASB No. 133 and Not ‘Held for Trading Purposes’ as Defined
in Issue No. 02-03” (EITF No. 03-11), which became effective on January 1,
2004. Operating Electric revenues and Purchased Electricity expense for
Puget Energy and Puget Sound Energy were reduced by $108.7 million and
$77.1 million in 2003 and 2002, respectively, with no effect on net
income. Information for 2001 and 2000 is not available, and therefore
revenue and expense were not adjusted for the effects of EITF No. 03-11 in
those years. |
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL
CONDITION AND RESULTS OF
OPERATIONS
The
following discussion and analysis should be read in conjunction with the
financial statements and related notes thereto included elsewhere in this annual
report on Form 10-K. The discussion contains forward-looking statements that
involve risks and uncertainties, such as Puget Energy’s and Puget Sound Energy’s
(PSE) objectives, expectations and intentions. Words or phrases such as
“anticipates,” “believes,” “estimates,” “expects,” “ plans,” “predicts,”
“projects,” “will likely result,” “will continue” and similar expressions are
intended to identify certain of these forward-looking statements. However, these
words are not the exclusive means of identifying such statements. In addition,
any statements that refer to expectations, projections or other
characterizations of future events or circumstances are forward-looking
statements. Readers are cautioned not to place undue reliance on these
forward-looking statements, which speak only as of the date of this report.
Puget Energy’s and PSE’s actual results could differ materially from results
that may be anticipated by such forward-looking statements. Factors that could
cause or contribute to such differences include, but are not limited to, those
discussed in the section entitled “Forward-Looking Statements” included
elsewhere in this report. Except as required by law, neither Puget Energy nor
PSE undertakes an obligation to revise any forward-looking statements in order
to reflect events or circumstances that may subsequently arise. Readers are
urged to carefully review and consider the various disclosures made in this
report and in Puget Energy’s and PSE’s other reports filed with the United
States Securities and Exchange Commission that attempt to advise interested
parties of the risks and factors that may affect Puget Energy’s and PSE’s
business, prospects and results of operations.
OVERVIEW
Puget Energy is an energy services
holding company, and all its operations are conducted through its two
subsidiaries. These subsidiaries are PSE, a regulated electric and gas utility
company, and InfrastruX, a utility construction and services company. On
February 8, 2005, following a strategic review of InfrastruX, Puget Energy’s
Board of Directors decided to exit the utility construction services sector.
Puget Energy intends to monetize its interest in InfrastruX through sale or
recapitalization and to invest the proceeds of such monetization in its
regulated utility subsidiary, PSE.
PUGET
SOUND ENERGY
PSE
generates revenues from the sale of electric and gas services, mainly to
residential and commercial customers within Washington State. A majority of
PSE’s revenues are generated in the first and fourth quarters during the winter
heating season in Washington State.
As a
regulated utility company, PSE is subject to Federal Energy Regulatory
Commission (FERC) and Washington Commission regulation which may impact a large
array of business activities, including limitation of future rate increases;
directed accounting requirements that may negatively impact earnings; licensing
of PSE-owned generation facilities; and other FERC and Washington Commission
directives that may impact PSE’s long-term goals. In addition, PSE is subject to
risks inherent to the utility industry as a whole, including weather changes
affecting purchases and sales of energy; outages at owned and non-owned
generation plants where energy is obtained; storms or other events which can
damage electric distribution and transmission lines; and energy trading and
wholesale market stability over time.
PSE’s
main operational goal has been to provide reliable, safe and cost-effective
energy to its customers. To help accomplish this goal, PSE is attempting to be
more self-sufficient in energy generation resources. Owning more generation
resources rather than purchasing power through contracts and on the wholesale
market is intended to allow customers’ rates to remain stable. PSE is
continually exploring new electric-power resource generation and long-term
purchase power agreements to meet this goal. During 2004, PSE made progress in
reaching this goal:
| · |
Purchased
a 49.85% interest in a 250 MW capacity gas-fired generation facility in
western Washington, which went into service in April
2004. |
| · |
Signed
a two-year purchase power agreement in the second quarter 2004 with
another utility for 85 MW of energy with delivery beginning January 1,
2005. |
| · |
Signed
a non-binding letter of intent in September 2004 to purchase a wind
generation facility with up to 230 MW of generation to be developed in
central Washington State. |
| · |
Signed
a non-binding letter of intent in October 2004 to purchase a wind
generation facility with up to 150 MW of generation to be developed in
eastern Washington State. |
These
transactions and proposed transactions are part of PSE’s long-term electric
Least Cost Plan that was filed August 29, 2003 with the Washington Commission.
The plan supports a strategy of diverse resource acquisitions including
resources fueled by natural gas and coal, renewable resources and shared
resources. PSE is in
the process of updating its Least Cost Plan and expects to file the updated plan
with the Washington Commission in the first half of 2005.
INFRASTRUX
Following
a strategic review of InfrastruX conducted by Puget Energy management, on
February 8, 2005, Puget Energy’s Board of Directors decided to exit the utility
construction services sector. During 2005, Puget Energy intends to monetize its
interest in InfrastruX through a sale or third party recapitalization and to
invest the proceeds in PSE. The costs associated with exiting the InfrastruX
business cannot be quantified at this time. However, Puget Energy believes that
such costs will not be material given the effects of the impairment charge
recorded in the fourth quarter 2004.
InfrastruX
generates revenues mainly from maintenance services and construction contracts
in the Midwest, Texas, south-central and eastern United States. Generally, the
majority of its revenues are generated during the second and third quarters,
which are typically the most productive quarters for the construction industry
due to longer daylight hours and generally better weather conditions.
InfrastruX
is subject to risks associated with the construction industry, including
inability to adequately estimate costs of projects that are bid on under
fixed-fee contracts; continued economic downturn that limits the amount of
projects available thereby reducing available profit margins due to increased
competition; the ability to integrate acquired companies within its operations
without significant cost; and the ability to obtain adequate financing and
bonding coverage to continue expansion and growth.
InfrastruX’s
main goals have been continued growth and expansion into underdeveloped utility
construction markets and to utilize its acquired entities to capitalize on depth
of expertise, asset base, geographical location and workforce to provide
services that local contractors cannot provide. InfrastruX has acquired 12
entities since 2000.
FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
PUGET
ENERGY
All the
operations of Puget Energy are conducted through its subsidiaries, PSE and
InfrastruX. Net income in 2004 was $55.0 million on operating revenues of $2.6
billion compared to $116.2 million on operating revenues of $2.4 billion in 2003
and $110.1 million on operating revenues of $2.3 billion in 2002.
Basic
earnings per share in 2004 were $0.55 on 99.5 million weighted average common
shares outstanding compared to $1.23 on 94.8 million weighted average common
shares outstanding in 2003 and $1.24 on 88.4 million weighted average common
shares outstanding in 2002. Diluted earnings per share in 2004 were $0.55 on
99.9 million weighted average common shares outstanding compared to $1.22 on
95.3 million weighted average common shares outstanding in 2003 and $1.24 on
88.8 million weighted average common shares outstanding in 2002.
Net
income in 2004 was adversely impacted by an InfrastruX non-cash goodwill
impairment charge of $91.2 million ($76.6 million after tax and minority
interest) and a $43.4 million ($28.2 million after-tax) disallowance of the
return on the Tenaska gas supply regulatory asset as a result of a Washington
Commission order in PSE’s Power Cost Only Rate Case (PCORC). Net income was also
negatively impacted by an increase in depreciation expense of $10.0 million,
primarily due to the acquisition of Frederickson 1 and other PSE infrastructure
projects. These negative impacts were offset by improved electric margins of
$5.9 million compared to 2003 and lower interest expense at PSE of $13.0
million. In addition, 2004 was not impacted by one-time tax benefits of $7.9
million or the write-down of $6.1 million in the carrying value of a non-utility
venture capital investment in 2003. Net income in 2004 was positively impacted
by a $4.3 million increase in InfrastruX’s net income, excluding the goodwill
impairment charge and net of minority interest. The net income increase at
InfrastruX was due to improved operating efficiencies and improvements in
weather conditions compared to 2003, which positively impacted
productivity.
Net
income in 2003 was positively impacted by an increase in PSE’s net income of
$10.9 million due to increased electric and gas margins primarily from a general
gas rate increase effective September 1, 2002 and from increased sales volumes
for electric and gas loads compared to 2002. In addition, net income in 2003 was
positively impacted by lower interest expenses of $11.5 million. This was offset
by a $6.1 million downward adjustment in the carrying value of a non-utility
venture capital investment in the fourth quarter 2003; a $4.8 million increase
in depreciation and amortization; and an $11.7 million decrease in gains on
derivative instruments due to a 2002 gain from de-designated contracts from a
non-creditworthy counterparty under Statement of Financial Accounting Standards
(SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities.”
In addition, federal tax benefits decreased in 2003 to $9.3 million compared to
$10.3 million in 2002. Net income was also negatively impacted by a decrease in
InfrastruX’s net income of $7.7 million in 2003 compared to 2002, net of
minority interest, due to unusually wet weather affecting productivity in the
first quarter 2003 and increased competition in the marketplace.
PUGET
SOUND ENERGY
PSE’s
operating revenues and associated expenses are not generated evenly during the
year. Variations in energy usage by consumers occur from season to season and
from month to month within a season, primarily as a result of weather
conditions. PSE normally experiences its highest retail energy sales during the
heating season in the first and fourth quarters of the year. Varying wholesale
electric prices and the amount of hydroelectric energy supplies available to PSE
also make quarter-to-quarter comparisons difficult.
PUGET
SOUND ENERGY
2004 COMPARED
TO 2003
ENERGY
MARGINS
|
|
The
following table displays the details of electric margin changes from 2003
to 2004. |
| |
|
ELECTRIC
MARGIN |
|
|
(DOLLARS
IN MILLIONS)
TWELVE
MONTHS ENDED DECEMBER 31 |
|
2004 |
|
2003 |
|
CHANGE |
|
PERCENT
CHANGE |
|
|
Electric
retail sales revenue |
|
$ |
1,310.9 |
|
$ |
1,272.7 |
|
$ |
38.2 |
|
|
3.0 |
% |
|
Electric
transportation revenue |
|
|
10.7 |
|
|
11.5 |
|
|
(0.8 |
) |
|
(7.0 |
) |
|
Other
electric revenue-gas supply resale |
|
|
11.5 |
|
|
9.1 |
|
|
2.4 |
|
|
26.4 |
|
|
Total
electric revenue for margin |
|
|
1,333.1 |
|
|
1,293.3 |
|
|
39.8 |
|
|
3.1 |
|
|
Adjustments
for amounts included in revenue: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pass-through
tariff items |
|
|
(25.4 |
) |
|
(45.2 |
) |
|
19.8 |
|
|
43.8 |
|
|
Pass-through
revenue-sensitive taxes |
|
|
(94.2 |
) |
|
(91.0 |
) |
|
(3.2 |
) |
|
(3.5 |
) |
|
Residential
exchange credit |
|
|
174.5 |
|
|
173.8 |
|
|
0.7 |
|
|
0.4 |
|
|
Net
electric revenue for margin |
|
|
1,388.0 |
|
|
1,330.9 |
|
|
57.1 |
|
|
4.3 |
|
|
Minus
power costs: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel |
|
|
(80.7 |
) |
|
(65.0 |
) |
|
(15.7 |
) |
|
(24.2 |
) |
|
Purchased
electricity, net of sales to other utilities and marketers |
|
|
(660.3 |
) |
|
(635.2 |
) |
|
(25.1 |
) |
|
(4.0 |
) |
|
Total
electric power costs |
|
|
(741.0 |
) |
|
(700.2 |
) |
|
(40.8 |
) |
|
(5.8 |
) |
|
Electric
margin before PCA |
|
|
647.0 |
|
|
630.7 |
|
|
16.3 |
|
|
2.6 |
|
|
|
|
|
(36.5 |
) |
|
-- |
|
|
(36.5 |
) |
|
* |
|
|
Tenaska
reserve turnaround |
|
|
10.5 |
|
|
-- |
|
|
10.5 |
|
|
* |
|
|
Power
cost deferred under the PCA mechanism |
|
|
19.1 |
|
|
3.5 |
|
|
15.6 |
|
|
* |
|
|
Electric
margin |
|
$ |
640.1 |
|
$ |
634.2 |
|
$ |
5.9 |
|
|
0.9 |
% |
_________________________________
* Percent
change not applicable.
Electric
margin increased $5.9 million in 2004 compared to 2003 due primarily to an
increase in kWh sales and the PCORC rate increase. PSE incurred $34.8 million in
excess power costs in 2003 before reaching the $40 million PCA mechanism cap in
2003. In addition, the PCORC rate increase of 3.2% related to the Frederickson 1
generating facility became effective on May 24, 2004. This rate increase
provided an additional $6.5 million to electric margin in 2004 to recover
utility operation and maintenance costs, depreciation and property taxes related
to the Frederickson 1 generating facility. Also, retail customer kWh sales
(residential, commercial and industrial customers) increased 1.5% in 2004
compared to 2003, which along with a change in customer class usage provided an
additional $11.7 million to electric margin. These increases were partially
offset by the disallowance of certain gas costs for the Tenaska generating
facility also ordered in the PCORC, which resulted in a $43.4 million reduction
of electric margin in 2004. In addition, a charge of $3.6 million associated
with Colstrip Units 1 & 2 coal supply repricing arbitration and Colstrip
Units 3 & 4 royalty charge resulted in a negative impact to electric margin.
Electric margin is electric sales to retail and transportation customers less
pass-through tariff items and revenue-sensitive taxes, and the cost of
generating and purchasing electric energy sold to customers including
transmission costs to bring electric energy to PSE’s service
territory.
The
following table displays the details of gas margin changes from 2003 to
2004.
| |
|
GAS
MARGIN |
|
|
(DOLLARS
IN MILLION)
TWELVE
MONTHS ENDED DECEMBER 31 |
|
2004 |
|
2003 |
|
CHANGE |
|
PERCENT
CHANGE |
|
Gas
retail revenue |
|
$ |
743.6 |
|
$ |
609.6 |
|
$ |
134.0 |
|
|
22.0 |
% |
|
Gas
transportation revenue |
|
|
13.0 |
|
|
13.8 |
|
|
(0.8 |
) |
|
(5.8 |
) |
|
Total
gas revenue for margin |
|
|
756.6 |
|
|
623.4 |
|
|
133.2 |
|
|
21.4 |
|
|
Adjustments
for amounts included in revenue: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas
revenue hedge |
|
|
-- |
|
|
0.2 |
|
|
(0.2 |
) |
|
* |
|
|
Pass-through
tariff items |
|
|
(3.6 |
) |
|
(3.8 |
) |
|
0.2 |
|
|
5.3 |
|
|
Pass-through
revenue-sensitive taxes |
|
|
(59.3 |
) |
|
(48.5 |
) |
|
(10.8 |
) |
|
(22.3 |
) |
|
Net
gas revenue for margin |
|
|
693.7 |
|
|
571.3 |
|
|
122.4 |
|
|
21.4 |
|
|
Minus
purchased gas costs |
|
|
(451.3 |
) |
|
(327.1 |
) |
|
(124.2 |
) |
|
(38.0 |
) |
|
Gas
margin |
|
$ |
242.4 |
|
$ |
244.2 |
|
$ |
(1.8 |
) |
|
(0.7 |
)% |
_________________________________
* Percent
change not applicable.
Gas
margin decreased $1.8 million in 2004 compared to 2003 primarily due to overall
warmer weather in 2004 compared to 2003, partially offset by customer additions
in 2004. Heating degree days decreased 2.3% in 2004 compared to 2003, which
resulted in a 1.5% reduction in therm sales. Gas margin is gas sales to retail
and transportation customers less pass-through tariff items and
revenue-sensitive taxes and the cost of gas purchased, including gas
transportation costs to bring gas to PSE’s service territory.
ELECTRIC
OPERATING REVENUES
The table
below sets forth changes in electric operating revenues for PSE from 2003 to
2004.
|
(DOLLARS
IN MILLIONS)
TWELVE
MONTHS ENDED DECEMBER 31 |
|
2004 |
|
2003 |
|
CHANGE |
|
PERCENT
CHANGE |
|
Electric
operating revenues: |
|
|
|
|
|
|
|
|
|
|
Residential
sales |
|
$ |
628.9 |
|
$ |
603.7 |
|
$ |
25.2 |
|
|
4.2 |
% |
|
Commercial
sales |
|
|
581.0 |
|
|
556.0 |
|
|
25.0 |
|
|
4.5 |
|
|
Industrial
sales |
|
|
88.8 |
|
|
88.2 |
|
|
0.6 |
|
|
0.7 |
|
|
Transportation
sales |
|
|
10.7 |
|
|
11.5 |
|
|
(0.8 |
) |
|
(7.0 |
) |
|
Sales
to other utilities and marketers |
|
|
56.5 |
|
|
82.8 |
|
|
(26.3 |
) |
|
(31.8 |
) |
|
Other |
|
|
57.1 |
|
|
58.5 |
|
|
(1.4 |
) |
|
(2.4 |
) |
|
Total
electric operating revenues |
|
$ |
1,423.0 |
|
$ |
1,400.7 |
|
$ |
22.3 |
|
|
1.6 |
% |
Electric
operating revenues increased $22.3 million in 2004 compared to 2003 due to
increases in residential and commercial customer usage and the effect of the
PCORC rate increase. Residential and commercial electricity usage increased
182,296 MWh or 1.9% and 227,400 MWh or 2.8%, respectively, from 2003. The
increase in electricity usage was mainly the result of a higher average number
of customers served in 2004 compared to 2003. Average customers for the
residential and commercial customer classes increased 2.4% and 1.1%,
respectively, from 2003. In addition, the PCORC rate increase became effective
on May 24, 2004 and provided a $24.5 million increase in electric operating
revenue, net of a $5.8 million rate reduction due to the Tenaska
disallowance.
Sales to
other utilities and marketers decreased $26.3 million from 2003 primarily due to
higher retail electric sales, which reduced excess generation for sale to the
wholesale market. In 2003, warmer than normal temperatures, mainly in the first
quarter, and improved hydroelectric conditions as compared to the original
hydroelectric forecast provided excess energy supplies for sale to the wholesale
market.
During
2004, the benefits of the Residential and Farm Energy Exchange Benefit credited
to customers reduced electric operating revenues by $182.6 million compared to
$181.9 million in 2003. This credit also reduces power costs by a corresponding
amount with no impact on earnings. See Item 1, Business - Regulation and Rates -
Residential and Small Farm Exchange Benefit Credit for further
discussion.
During
2003, PSE collected in its electric general rate tariff as a reduction to
revenue and remitted to a grantor trust $7.7 million. This was a result of PSE’s
1995 sale of future electric revenues associated with its investment in
conservation assets. The impact of the 1995 sale of revenue was offset by
reductions in conservation amortization and interest expense. PSE’s 1995
conservation trust transaction was consolidated in the third quarter 2003 to
meet the guidance of Financial Accounting Standards Board (FASB) Interpretation
No. 46 (FIN 46) and, as a result, revenues increased $5.7 million in 2004 while
conservation amortization and interest expense increased by a corresponding
amount with no impact on earnings. The 1995 conservation trust assets were fully
satisfied during September 2004.
GAS
OPERATING REVENUES
The table
below sets forth changes in gas operating revenues for PSE from 2003 to
2004.
|
(DOLLARS
IN MILLIONS)
TWELVE
MONTHS ENDED DECEMBER 31 |
|
2004 |
|
2003 |
|
CHANGE |
|
PERCENT
CHANGE |
|
Gas
operating revenues: |
|
|
|
|
|
|
|
|
|
Residential
sales |
|
$ |
479.0 |
|
$ |
401.7 |
|
$ |
77.3 |
|
|
19.2 |
% |
|
Commercial
sales |
|
|
225.8 |
|
|
178.2 |
|
|
47.6 |
|
|
26.7 |
|
|
Industrial
sales |
|
|
38.8 |
|
|
29.7 |
|
|
9.1 |
|
|
30.6 |
|
|
Transportation
sales |
|
|
13.0 |
|
|
13.8 |
|
|
(0.8 |
) |
|
(5.8 |
) |
|
Other |
|
|
12.7 |
|
|
10.8 |
|
|
1.9 |
|
|
17.6 |
|
|
Total
gas operating revenues |
|
$ |
769.3 |
|
$ |
634.2 |
|
$ |
135.1 |
|
|
21.3 |
% |
Gas
operating revenues increased $135.1 million or 21.3% in 2004 compared to 2003
due primarily to higher Purchased Gas Adjustment (PGA) mechanism rates in 2004.
The PGA mechanism rate charged to customers has increased twice since April 2003
reflecting the higher cost of natural gas provided to customers. On September
24, 2003, the Washington Commission approved a PGA mechanism rate increase of
13.3% annually across all classes of customers effective October 1, 2003. In
addition, the Washington Commission approved a third PGA mechanism rate increase
effective October 1, 2004 that increased rates 17.6% annually. The PGA mechanism
passes through to customers increases or decreases in the gas supply portion of
the natural gas service rates based upon changes in the price of natural gas
purchased from producers and wholesale marketers or changes in gas pipeline
transportation costs. PSE’s gas margin and net income are not affected by
changes under the PGA mechanism. For 2004, the effects of the PGA mechanism rate
increases provided an increase of $137.0 million in gas operating revenues.
These rate increases were partially offset with lower therm sales due to 2.3%
fewer heating degree days in 2004 compared to 2003.
OPERATING
EXPENSES
The table
below sets forth significant changes in operating expenses for PSE and its
subsidiaries from 2003 to 2004.
|
(DOLLARS
IN MILLIONS)
TWELVE
MONTHS ENDED DECEMBER 31 |
|
2004 |
|
2003 |
|
CHANGE |
|
PERCENT
CHANGE |
|
Purchased
electricity |
|
$ |
723.6 |
|
$ |
714.5 |
|
$ |
9.1 |
|
|
1.3 |
% |
|
Electric
generation fuel |
|
|
80.8 |
|
|
65.0 |
|
|
15.8 |
|
|
24.3 |
|
|
Purchased
gas |
|
|
451.3 |
|
|
327.1 |
|
|
124.2 |
|
|
38.0 |
|
|
Utility
operations and maintenance |
|
|
291.2 |
|
|
289.7 |
|
|
1.5 |
|
|
0.5 |
|
|
Depreciation
and amortization |
|
|
228.6 |
|
|
220.1 |
|
|
8.5 |
|
|
3.9 |
|
|
Conservation
amortization |
|
|
22.7 |
|
|
33.5 |
|
|
(10.8 |
) |
|
(32.2 |
) |
|
Taxes
other than income taxes |
|
|
209.0 |
|
|
194.9 |
|
|
14.1 |
|
|
7.2 |
|
|
Income
taxes |
|
|
77.1 |
|
|
70.9 |
|
|
6.2 |
|
|
8.7 |
|
Purchased
electricity expenses
increased $9.1 million in 2004 compared to 2003 as a result of a $36.5 million
disallowance associated with the Tenaska generating facility as ordered by the
Washington Commission in the PCORC. This decrease was partially offset by lower
purchases of electricity due to increased generation at PSE generating
facilities. Total generation at PSE generating facilities in 2004 increased
82,430 MWh or 1.2% in 2004 compared to 2003.
PSE’s
hydroelectric production and related power costs in 2004 and 2003 have continued
to be negatively impacted by below-normal winter precipitation and reduced snow
pack in the Pacific Northwest region. The January 3, 2005 Columbia Basin Runoff
Summary published by the National Weather Service Northwest River Forecast
Center indicated that the total observed runoff above Grand Coulee Reservoir for
the period January through December 2004 was 88% of normal, which compares to
87% of normal for the same period in 2003. PSE cannot determine if this trend of
lower than normal runoff will continue in future years nor what impact such a
trend may have on the amount of electricity that will need to be purchased. PSE
had previously reached the $40 million cumulative cap under the PCA mechanism in
2003 primarily due to increased power costs and adverse hydroelectric
conditions. In 2004, PSE fell below the $40 million cumulative cap due to the
Tenaska disallowance. Under the PCA mechanism, continued excess power costs and
further increases in variable power costs through June 30, 2006 will be
apportioned 99% to customers and 1% to PSE. PSE has reserved the Tenaska
disallowance and as a result any future excess power costs will be offset by the
reserve. For further discussion see Item 1 - Business - Regulation and Rates -
Electric Regulation and Rates - Washington Commission Matters.
To meet
customer demand, PSE economically dispatches resources in its power supply
portfolio such as fossil-fuel generation, owned and contracted hydroelectric
capacity and energy, and long-term contracted power. However, depending
principally upon availability of hydroelectric energy, plant availability, fuel
prices and/or changing load as a result of weather, PSE may sell surplus power
or purchase deficit power in the wholesale market. PSE manages its core energy
portfolio through short-term and intermediate-term off-system physical purchases
and sales, and through other risk management techniques.
Electric
generation fuel expense
increased $15.8 million in 2004 compared to 2003 as a result of higher fuel
costs for PSE-controlled gas-fired generation facilities and the addition of the
Frederickson 1 generating facility, which was purchased and went into service in
April 2004. In addition, the 12 months ended December 31, 2004 includes a $6.9
million charge related to a binding arbitration settlement between PSE and
Western Energy Company (WECO), the supplier of coal to Colstrip Units 1 & 2.
The binding decision retroactively set a new baseline cost per ton of coal
supplied from July 31, 2001, and is applicable to the remaining term of the coal
supply agreement through December 2009. Of the $6.9 million charge, $5.0 million
is included in the PCA mechanism. PSE had previously accrued a reserve of $1.6
million in the fourth quarter 2003 related to the arbitration.
The 12
months ended December 31, 2004 also includes a loss reserve of $1.1 million
recorded in the second quarter 2004 related to an order issued to WECO by the
Minerals Management Services of the United States Department of the Interior
(MMS) on April 29, 2004, to pay additional royalties concerning coal purchased
by PSE for Colstrip Units 3 & 4. The order seeks payment of royalties for
coal mined from federal land between 1997 and June 30, 2000. During that period,
PSE’s coal price was reduced by a settlement agreement entered into in February
1997 among PSE, WECO and Montana Power Company that resolved disputes that were
then pending. The order seeks to impute the price charged to PSE based on the
other Colstrip Units 3 & 4 owners’ contractual amounts. PSE is supporting
WECO’s appeal of the order, but is also evaluating the basis of the claim.
In
addition, the MMS issued two orders to WECO in 2002 and 2003 to pay additional
royalties concerning coal sold to Colstrip Units 3 & 4 owners. The orders
assert that additional royalties are owed as a result of WECO not paying
royalties in connection with revenue received by WECO from the Colstrip Units 3
& 4 owners under a coal transportation agreement during the period October
1, 1991 through December 31, 2001. PSE’s share of the alleged additional
royalties is $1.8 million, which is equivalent to PSE’s 25% ownership interest
in Colstrip Units 3 & 4. Other parties may attempt to assert claims against
WECO if the MMS position prevails. The transportation agreement provides for the
construction and operation of a conveyor system that runs several miles from the
mine to Colstrip Units 3 & 4. WECO has appealed these orders and PSE is
monitoring the process. Based upon its review, PSE believes that the Colstrip
Units 3 & 4 owners have reasonable defenses in this matter. Neither the
outcome of this matter nor the associated costs can be predicted at this
time.
Purchased
gas expenses
increased $124.2 million in 2004 compared to 2003 primarily due to an increase
in PGA rates as approved by the Washington Commission. The PGA mechanism allows
PSE to recover expected gas costs, and defer, as a receivable or liability, any
gas costs that exceed or fall short of this expected gas cost amount in PGA
mechanism rates, including accrued interest. The PGA mechanism had a receivable
balance at December 31, 2004 of $19.1 million compared to a liability balance of
$12.0 million at December 31, 2003. A receivable balance in the PGA mechanism
reflects a current underrecovery of market gas cost through rates and a
liability balance reflects a current overrecovery of gas cost. For further
discussion on PGA rates see Item 1 - Business - Gas Regulation and Rates.
Utility
operations and maintenance expense
increased $1.5 million in 2004 compared to 2003 which includes a decrease of
$1.8 million related to low-income program costs that are passed-through in
retail rates with no impact on earnings. As a result, the pre-tax impact on net
income from utility operations and maintenance was an increase of $3.3 million
due primarily to a $3.2 million increase in storm damage costs primarily from a
severe ice storm that hit the Pacific Northwest in January 2004. PSE anticipates
operation and maintenance expense to increase in future years as PSE invests in
new generating resources and energy delivery infrastructure.
Depreciation
and amortization expense
increased $8.5 million in 2004 compared to 2003 due primarily to the effects of
new plant placed in service during 2004, including $80.8 million in costs for
the Frederickson 1 generating facility and $32.8 million for the Everett Delta
gas transmission line. PSE anticipates depreciation expense will increase in
future years as PSE invests in new generating resources and energy delivery
infrastructure.
Conservation
amortization
decreased $10.8 million in 2004 compared to 2003 due to the conservation trust
assets being fully amortized in September 2004. Conservation amortization is a
pass-through tariff item with no impact on earnings.
Taxes
other than income taxes
increased $14.1 million in 2004 compared to 2003 primarily due to increases in
revenue-based Washington State excise tax and municipal tax due to increased
operating revenues. Revenue sensitive excise and municipal taxes have no impact
on earnings.
Income
taxes
increased $6.2 million in 2004 compared to 2003 as a result of the
non-recurrence in 2004 of $9.3 million in income tax benefits in 2003 offset by
a one-time income tax benefit of $1.4 million in 2004 related to a 2001 tax
audit.
OTHER
INCOME, INTEREST CHARGES AND PREFERRED STOCK DIVIDENDS
The table
below sets forth significant changes in other income, interest charges and
preferred stock dividends for PSE and its subsidiaries from 2003 to
2004.
|
(DOLLARS
IN MILLIONS)
TWELVE
MONTHS ENDED DECEMBER 31 |
|
2004 |
|
2003 |
|
CHANGE |
|
PERCENT
CHANGE |
|
|
Other
income (net of tax) |
|
$ |
4.4 |
|
$ |
1.6 |
|
$ |
2.8 |
|
|
175.0 |
% |
|
Interest
charges |
|
|
166.4 |
|
|
179.4 |
|
|
(13.0 |
) |
|
(7.2 |
) |
|
Preferred
stock dividends |
|
|
-- |
|
|
5.2 |
|
|
(5.2 |
) |
|
(100.0 |
) |
Other
income increased
$2.8 million (after-tax) due to the non-recurrence of a $4.0 million investment
write-down in 2003 related to a non-utility venture capital investment and a
$0.9 million collection in 2004 of a note previously written-off in 2002. These
increases were partially offset with the non-recurrence of a $1.9 million gain
from a security sale in 2003 and the non-recurrence of gains on corporate life
insurance of $1.7 million in 2003.
Interest
charges decreased
$13.0 million in 2004 due to the redemption of $157.7 million of long-term debt
with rates ranging from 6.07% to 7.80% in 2004, partially offset with the
issuance of $200 million of variable-rate senior notes in July
2004.
Preferred
stock dividends
decreased $5.2 million in 2004 due to the redemption on November 1, 2003 of the
7.45% series preferred stock not subject to mandatory redemption. The series was
redeemed at par value plus accrued dividends.
INFRASTRUX
2004 COMPARED
TO 2003
The table
below sets forth significant changes in revenues and expenses for InfrastruX
from 2003 to 2004.
|
(DOLLARS
IN MILLIONS)
YEARS
ENDED DECEMBER 31 |
|
2004 |
|
2003 |
|
CHANGE |
|
PERCENT
CHANGE |
|
Operating
revenue: |
|
|
|
|
|
|
|
|
|
|
Non-utility
construction services |
|
$ |
369.9 |
|
$ |
341.8 |
|
$ |
28.1 |
|
|
8.2 |
% |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
operations and maintenance |
|
$ |
320.2 |
|
$ |
302.4 |
|
$ |
17.8 |
|
|
5.9
|
% |
|
Depreciation
and amortization |
|
|
18.3 |
|
|
16.8 |
|
|
1.5 |
|
|
8.9 |
|
|
Goodwill
impairment |
|
|
91.2 |
|
|
-- |
|
|
91.2 |
|
|
* |
|
|
Income
taxes |
|
|
(1.8 |
) |
|
1.6 |
|
|
(3.4 |
) |
|
(212.5 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
charges |
|
$ |
6.5 |
|
$ |
5.5 |
|
$ |
1.0 |
|
|
18.2 |
% |
|
Minority
interest |
|
|
7.1 |
|
|
(0.2 |
) |
|
7.3 |
|
|
* |
|
________________________________
* Percent
change not applicable.
InfrastruX
revenues increased
$28.1 million due in part to the acquisition of one company late in the second
quarter 2003 which added $12.4 million to revenues. Revenues from existing
companies increased $8.7 million in 2004 compared to 2003 due to strong
performance in the electric transmission sector of the construction services
industry and new business in the Midwest region of the United States.
Other
operations and maintenance expenses increased
$17.8 million due to increased utility construction in 2004 compared to 2003 and
the acquisition of one company late in the second quarter 2003, which accounted
for $11.8 million of the increase.
Depreciation
and amortization expense
increased $1.5 million in 2004 compared to 2003 primarily due to an increase in
assets through a company acquisition late in the second quarter 2003 which
accounted for $0.8 million of the increase and implementation of an integrated
information technology platform across InfrastruX.
Goodwill
impairment. In the
fourth quarter 2004, as part of the required annual goodwill impairment review
as required by Statement of Financial Accounting Standards (SFAS) No. 142,
“Goodwill and Other Intangible Assets,” InfrastruX recorded a non-cash, pre-tax
goodwill impairment charge of $91.2 million. This charge reflected Puget
Energy’s estimated fair value for InfrastruX in light of ongoing challenges in
the utility construction services sector.
Income
taxes decreased
$3.4 million in 2004 compared to 2003. Included in the change was a $25.0
million deferred income tax benefit associated with the goodwill impairment
charge, offset by a $18.0 million valuation allowance against the deferred tax
benefit as Puget Energy does not expect to utilize the full benefit. The
remaining change in income tax was primarily the result of higher taxable income
at InfrastruX in 2004 compared to 2003.
Interest
charges
increased $1.0 million in 2004 compared to 2003 primarily due to a higher
average debt balance in 2004 than in 2003 and higher interest
rates.
Minority
interest increased
$7.3 million in 2004 compared to 2003 as a result of the change in net loss
associated with the goodwill impairment charge in 2004.
PUGET
SOUND ENERGY
2003 COMPARED
TO 2002
ENERGY
MARGINS
The
following table displays the details of electric margin changes from 2002 to
2003.
| |
|
ELECTRIC
MARGIN |
|
|
(DOLLARS
IN MILLIONS)
TWELVE
MONTHS ENDED DECEMBER 31 |
|
2003 |
|
2002 |
|
CHANGE |
|
PERCENT
CHANGE |
|
Electric
retail sales revenue |
|
$ |
1,272.7 |
|
$ |
1,260.9 |
|
$ |
11.8 |
|
|
0.9 |
% |
|
Electric
transportation revenue |
|
|
11.5 |
|
|
15.6 |
|
|
(4.1 |
) |
|
(26.3 |
) |
|
Other
electric revenue-gas supply resale |
|
|
9.1 |
|
|
(20.4 |
) |
|
29.5 |
|
|
144.6 |
|
|
Total
electric revenue for margin |
|
|
1,293.3 |
|
|
1,256.1 |
|
|
37.2 |
|
|
3.0 |
|
|
Adjustments
for amounts included in revenue: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pass-through
tariff items |
|
|
(45.2 |
) |
|
(32.1 |
) |
|
(13.1 |
) |
|
(40.8 |
) |
|
Pass-through
revenue-sensitive taxes |
|
|
(91.0 |
) |
|
(88.5 |
) |
|
(2.5 |
) |
|
(2.8 |
) |
|
Residential
exchange credit |
|
|
173.8 |
|
|
150.0 |
|
|
23.8 |
|
|
15.9 |
|
|
Net
electric revenue for margin |
|
|
1,330.9 |
|
|
1,285.5 |
|
|
45.4 |
|
|
3.5 |
|
|
Minus
power costs: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel |
|
|
(65.0 |
) |
|
(113.5 |
) |
|
48.5 |
|
|
42.7 |
|
|
Purchased
electricity, net of sales to other
utilities
and marketers |
|
|
(635.2 |
) |
|
(557.1 |
) |
|
(78.1 |
) |
|
(14.0 |
) |
|
Total
electric power costs |
|
|
(700.2 |
) |
|
(670.6 |
) |
|
(29.6 |
) |
|
(4.4 |
) |
|
Electric
margin before PCA |
|
|
630.7 |
|
|
614.9 |
|
|
15.8 |
|
|
2.6 |
|
|
Power
cost deferred under the PCA mechanism |
|
|
3.5 |
|
|
-- |
|
|
3.5 |
|
|
* |
|
|
Electric
margin |
|
$ |
634.2 |
|
$ |
614.9 |
|
$ |
19.3 |
|
|
3.1 |
% |
_________________________________
* Percent
change not applicable.
Electric
margin increased $19.3 million for 2003 compared to 2002 due primarily to the
non-recurrence of losses associated with the resale of gas supply for electric
generation in 2002 and increased MWh sales of 1.5%. Electric margin is electric
sales to retail and transportation customers less pass-through tariff items and
revenue sensitive taxes, and the cost of generating and purchasing electric
energy sold to customers including transmission costs to bring electric energy
to PSE’s service territory.
The
following table displays the details of gas margin changes from 2002 to
2003.
| |
|
GAS
MARGIN |
|
(DOLLARS
IN MILLIONS)
TWELVE
MONTHS ENDED DECEMBER 31 |
|
2003 |
|
2002 |
|
CHANGE |
|
PERCENT
CHANGE |
|
Gas
retail revenue |
|
$ |
609.6 |
|
$ |
673.2 |
|
$ |
(63.6 |
) |
|
(9.4 |
)% |
|
Gas
transportation revenue |
|
|
13.8 |
|
|
12.9 |
|
|
0.9 |
|
|
7.0 |
|
|
Total
gas revenue for margin |
|
|
623.4 |
|
|
686.1 |
|
|
(62.7 |
) |
|
(9.1 |
) |
|
Adjustments
for amounts included in revenue: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas
revenue hedge |
|
|
0.2 |
|
|
0.6 |
|
|
(0.4 |
) |
|
(66.7 |
) |
|
Pass-through
tariff items |
|
|
(3.8 |
) |
|
(2.3 |
) |
|
(1.5 |
) |
|
(65.2 |
) |
|
Pass-through
revenue-sensitive taxes |
|
|
(48.5 |
) |
|
(54.3 |
) |
|
5.8 |
|
|
10.7 |
|
|
Net
gas revenue for margin |
|
|
571.3 |
|
|
630.1 |
|
|
(58.8 |
) |
|
(9.3 |
) |
|
Minus
purchased gas costs |
|
|
(327.1 |
) |
|
(405.0 |
) |
|
77.9 |
|
|
19.2 |
|
|
Gas
margin |
|
$ |
244.2 |
|
$ |
225.1 |
|
$ |
19.1 |
|
|
8.5 |
% |
Gas
margin increased $19.1 million in 2003 compared to 2002 due to the effects of
the gas general rate increase effective September 1, 2002 that resulted in a
$24.2 million increase in revenues in 2003. The increase was offset by a 2.1%
decline in therm sales in 2003. Gas margin is gas sales to retail and
transportation customers less pass-through tariff items and revenue-sensitive
taxes and the cost of gas purchased, including gas transportation costs to bring
gas to PSE’s service territory.
ELECTRIC
OPERATING REVENUES
The table
below sets forth significant changes in electric operating revenues for PSE from
2002 to 2003.
(DOLLARS
IN MILLIONS)
TWELVE
MONTHS ENDED DECEMBER 31 |
|
2003 |
|
2002 |
|
CHANGE |
|
PERCENT
CHANGE |
|
Electric
operating revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
sales |
|
$ |
603.7 |
|
$ |
616.5 |
|
$ |
(12.8 |
) |
|
(2.0 |
)% |
|
Commercial
sales |
|
|
556.0 |
|
|
536.0 |
|
|
20.0 |
|
|
3.7 |
|
|
Industrial
sales |
|
|
88.2 |
|
|
90.1 |
|
|
(1.9 |
) |
|
(2.1 |
) |
|
Transportation
sales |
|
|
11.5 |
|
|
15.6 |
|
|
(4.1 |
) |
|
(26.2 |
) |
|
Sales
to other utilities and marketers |
|
|
82.8 |
|
|
11.1 |
|
|
71.7 |
|
|
* |
|
|
Other |
|
|
58.5 |
|
|
19.4 |
|
|
39.1 |
|
|
201.5 |
|
|
Total
electric operating revenues |
|
$ |
1,400.7 |
|
$ |
1,288.7 |
|
$ |
112.0 |
|
|
8.7 |
% |
________________________________
*
Percent
change not applicable.
Electric
operating revenues increased $112.0 million in 2003 compared to 2002 due
primarily to an increase of $71.7 million in wholesale electric sales to other
utilities and marketers from greater surplus volumes. Wholesale sales volumes
increased by 640,176 MWh or 94.5% compared to 2002. Retail sales volumes
increased 337,154 MWh or 1.8% as a result of increased usage by commercial
customers in 2003 compared to 2002. Electric operating revenues also increased
by $27.4 million due primarily to the non-occurrence of 2002 losses on the sale
of excess gas supply used for electric generation.
During
2003, the benefits of the Residential and Farm Energy Exchange Credit to
customers reduced revenues by $181.9 million compared to $156.8 million in 2002.
This credit also reduced power costs by a corresponding amount with no impact on
earnings.
During
2003, PSE collected in its electric general rate tariff as a reduction to
revenue and remitted to a grantor trust $7.7 million compared to $12.7 million
for 2002 as a result of PSE’s 1995 sale of future electric revenues associated
with its investment in conservation assets. The impact of the sale of revenue
was offset by reductions in conservation amortization and interest expense.
PSE’s 1995 conservation trust transaction was consolidated in the third quarter
2003 to meet the guidance of FIN 46 and, as a result, revenues increased $5.7
million while conservation amortization and interest expense increased by a
corresponding amount with no impact on earnings. This amount was also forwarded
to the grantor trust and any cash balance at the grantor trust was reported as
restricted cash on the balance sheet.
GAS
OPERATING REVENUES
The table
below sets forth significant changes in gas operating revenues for PSE from 2002
to 2003.
(DOLLARS
IN MILLIONS)
TWELVE
MONTHS ENDED DECEMBER 31 |
|
2003 |
|
2002 |
|
CHANGE |
|
PERCENT
CHANGE |
|
Gas
operating revenues: |
|
|
|
|
|
|
|
|
|
|
Residential
sales |
|
$ |
401.7 |
|
$ |
428.6 |
|
$ |
(26.9 |
) |
|
(6.3 |
)% |
|
Commercial
sales |
|
|
178.2 |
|
|
209.5 |
|
|
(31.3 |
) |
|
(14.9 |
) |
|
Industrial
sales |
|
|
29.7 |
|
|
35.1 |
|
|
(5.4 |
) |
|
(15.4 |
) |
|
Transportation
sales |
|
|
13.8 |
|
|
12.9 |
|
|
0.9 |
|
|
7.0 |
|
|
Other |
|
|
10.8 |
|
|
11.1 |
|
|
(0.3 |
) |
|
(2.7 |
) |
|
Total
gas operating revenues |
|
$ |
634.2 |
|
$ |
697.2 |
|
$ |
(63.0 |
) |
|
(9.0 |
)% |
Regulated
gas utility revenues in 2003 compared to 2002 decreased by $63.0 million or 9.0%
due primarily to lower PGA mechanism rates in 2003 as a result of refunding the
previous overcollection of PGA mechanism gas costs. In addition, warmer
temperatures in 2003 resulted in 8.5% fewer heating degree days as compared to
2002 resulting in lower therm sales.
PGA
mechanism rates charged to customers were lower in 2003 compared to 2002 as a
result of rate decreases of 7.3% and 12.5% which took effect September 1, 2002
and November 1, 2002, respectively, offset by a rate increase of 20.1% which
took effect April 10, 2003, and another rate increase of 13.3% effective October
1, 2003.
OTHER
OPERATING REVENUES
Other
operating revenues decreased $3.8 million in 2003 compared to 2002 primarily due
to a decrease in property sales gains for Puget Western, Inc., a PSE subsidiary,
which generates a majority of its revenue through the development and sale of
property.
OPERATING
EXPENSES
The table
below sets forth significant changes in operating expenses for PSE and its
subsidiaries from 2002 to 2003.
(DOLLARS
IN MILLIONS)
TWELVE
MONTHS ENDED DECEMBER 31 |
|
2003 |
|
2002 |
|
CHANGE |
|
PERCENT
CHANGE |
|
Purchased
electricity |
|
$ |
714.5 |
|
$ |
568.2 |
|
$ |
146.3 |
|
|
25.7 |
% |
|
Electric
generation fuel |
|
|
65.0 |
|
|
113.5 |
|
|
(48.5 |
) |
|
(42.7 |
) |
|
Residential
exchange power cost credit |
|
|
(173.8 |
) |
|
(149.9 |
) |
|
(23.9 |
) |
|
(15.9 |
) |
|
Purchased
gas |
|
|
327.1 |
|
|
405.0 |
|
|
(77.9 |
) |
|
(19.2 |
) |
|
Unrealized
(gain) loss on derivative instruments |
|
|
0.1 |
|
|
(11.6 |
) |
|
11.7 |
|
|
100.8 |
|
|
Utility
operations and maintenance |
|
|
289.7 |
|
|
286.2 |
|
|
3.5 |
|
|
1.2 |
|
|
Depreciation
and amortization |
|
|
220.1 |
|
|
215.3 |
|
|
4.8 |
|
|
2.2 |
|
|
Conservation
amortization |
|
|
33.4 |
|
|
17.5 |
|
|
15.9 |
|
|
90.9 |
|
|
Taxes
other than income taxes |
|
|
194.9 |
|
|
202.4 |
|
|
(7.5 |
) |
|
(3.7 |
) |
|
Income
taxes |
|
|
70.9 |
|
|
52.8 |
|
|
18.1 |
|
|
34.2 |
|
Purchased
electricity expenses
increased $146.3 million in 2003 compared to 2002. PSE’s hydroelectric
production and related power costs in 2003 were negatively impacted by
below-normal winter precipitation and snow pack in the Pacific Northwest region
associated with an El Nino weather condition. The January 25, 2004 Columbia
Basin Runoff Summary published by the National Weather Service Northwest River
Forecast Center indicated that the total observed runoff above Grand Coulee
Reservoir for the period January through December 2003 was 87% of normal. This
compared to 108% of normal for the same period in 2002.
Electric
generation fuel expense
decreased $48.5 million in 2003 compared to 2002 as a result of lower fuel costs
for PSE-controlled gas-fired generation facilities and the result of not
operating the generating facilities due to available lower-cost wholesale power
supply.
Residential
exchange credits
associated with the Residential Purchase and Sale Agreement with Bonneville
Power Administration (BPA) increased $23.9 million in 2003 compared to 2002 due
to the impact of a full year’s increased Residential and Farm Energy Exchange
credit rate. The rate increased in January, March and October of 2002 for
residential and small farm customers. Discussion of the amended Residential
Purchase and Sale Agreement between PSE and BPA can be found under Item 1 -
Business - Regulation and Rates - Residential and Small Farm Exchange Benefit
Credit. The residential exchange credits are passed through to eligible
residential and small farm customers by a corresponding reduction in
revenues.
Purchased
gas expenses
decreased $77.9 million in 2003 compared to 2002 primarily due to a 2.1%
decrease in sales volume, which was partially offset by an increase in PGA
rates. The PGA mechanism allows PSE to recover expected gas costs. PSE defers,
as a receivable or liability, any gas costs that exceed or fall short of the
amount in PGA mechanism rates and accrues interest under the PGA mechanism. The
PGA liability balance at December 31, 2003 was $12.0 million compared to a
liability balance of $83.8 million at December 31, 2002.
Unrealized
losses on derivative instruments
increased $11.7 million in 2003 compared to 2002 as a result of unrealized
losses on gas hedge contracts that were de-designated in the fourth quarter of
2001 and settled in 2002. The unrealized gains and losses recorded in the income
statement are the result of the change in the market value of derivative
instruments not meeting cash flow hedge criteria.
Utility
operations and maintenance expense
increased $3.5 million in 2003 compared to 2002, which included an increase of
$3.3 million related to a full year of low-income program costs that were
passed-through in retail rates with no impact on earnings. As a result, the
pre-tax impact on net income from utility operations and maintenance expense was
an increase of $0.2 million due primarily to an increase in electric overhead
and underground line costs, gas distribution main costs, least cost planning
costs, due diligence costs for power resource acquisition, certain costs
associated with preparing the PCORC and meter reading expenses. The overall
increase in utility operations and maintenance expenses was partially offset by
a $2.0 million reduction of production operations and maintenance costs in 2003
compared to 2002 due to decreased operating costs of PSE’s combustion turbine
plants which were operated at lower levels in 2003 than in 2002 due to lower
wholesale power prices. In addition, PSE’s Personal Energy
ManagementTM
energy-efficiency program costs decreased $6.3 million in 2003 compared to 2002
reflecting a decreased emphasis on the program in light of relatively moderate
energy prices and cancellation of the Time of Use program in November 2002. Also
included in the results was pension income related to PSE’s defined benefit
pension plan which is allocated between capital and operations and maintenance
expense based on the distribution of labor costs in accordance with FERC
guidelines. As a result, approximately 67.0% of the annual qualified pension
income of $12.9 million for 2003 was recorded as a reduction in operations and
maintenance expense compared to 66.8% or $17.7 million for 2002. During the
fourth quarter 2003, the Pacific Northwest region was hit by a severe windstorm
that caused significant damage to PSE’s electric distribution system. The
windstorm was considered a “catastrophic event” under Washington Commission
guidelines and as a result, PSE was able to defer the repair cost of $10.1
million for later recovery in retail rates.
Depreciation
and amortization expense
increased $4.8 million in 2003 compared to 2002 due primarily to the effects of
a new plant placed in service during the past year.
Conservation
amortization
increased $15.9 million in 2003 compared to 2002 due to increased conservation
expenditures and the result of consolidating the off-balance sheet conservation
trust beginning July 1, 2003 in accordance with FIN 46. The consolidation of the
conservation trust increased conservation amortization by $5.7 million for the
period July through December 2003. Pass-through conservation costs are recovered
through an electric conservation rider, a gas conservation tracker mechanism and
a conservation trust rate schedule with no impact to earnings.
Taxes
other than income taxes
decreased $7.5 million in 2003 compared to 2002 primarily due to the 2002
property tax expense of $5.2 million related to the State of Oregon property tax
bills covering a six-year period ending June 30, 2001 not recurring in 2003, a
$1.4 million reduction in expense in the second quarter 2003 related to the
settlement of the State of Oregon property tax bills and a $2.8 million decrease
in revenue-based Washington State excise tax and municipal tax. This was offset
by a $1.6 million increase in Washington State property taxes.
Income
taxes
increased $18.1 million in 2003 compared to 2002 as a result of increased income
offset by true-ups related to filing the prior year’s income tax returns, which
reduced income tax expense by $3.0 million and a $6.2 million reduction in tax
expense related to the favorable resolution of a federal income tax matter from
1997 to 2002 in the second quarter 2003. The increase was also the result of
2002 tax benefits totaling $10.3 million. The $10.3 million was composed of a
$4.1 million refund related to the audit of the Company’s 1998 and 1999 federal
income tax returns, a $3.5 million reduction to income tax expense representing
an adjustment to 2001 federal income tax based on the 2001 federal tax return
and a $2.7 million reduction in expense related to a refund of federal income
taxes for 2000.
OTHER
INCOME, INTEREST CHARGES AND PREFERRED STOCK DIVIDENDS
The table
below sets forth changes in other income, interest charges and preferred stock
dividends for PSE and its subsidiaries from 2002 to 2003.
(DOLLARS
IN MILLIONS)
TWELVE
MONTHS ENDED DECEMBER 31 |
|
2003 |
|
2002 |
|
CHANGE |
|
PERCENT
CHANGE |
|
|
Other
income (net of tax) |
|
$ |
1.6 |
|
$ |
5.2 |
|
$ |
(3.6 |
) |
|
(69.2 |
)% |
|
Interest
charges |
|
|
179.4 |
|
|
190.9 |
|
|
(11.5 |
) |
|
(6.0 |
) |
|
Preferred
stock dividends |
|
|
5.2 |
|
|
7.8 |
|
|
(2.6 |
) |
|
(33.3 |
) |
Other
income, net of
federal income tax, decreased $3.6 million compared to 2002 reflecting a $4.0
million after-tax downward adjustment of the carrying value of a non-utility
venture capital investment in the fourth quarter 2003.
Interest
charges
decreased $11.5 million for 2003 compared to 2002 primarily due to a decrease in
long-term and short-term debt outstanding of $12.0 million and the maturity of
$72.0 million of Medium-Term Notes with interest rates ranging from 6.20% to
7.02% during 2003, the early redemption of $123.0 million of Medium-Term Notes
with interest rates ranging from 7.19% to 8.59% during 2003, and the refinancing
of $161.9 million of Pollution Control Bonds with interest rates ranging from
5.875% to 7.25% to rates ranging from 5.00% to 5.10%. The decrease in interest
expense was partially offset by the issuance of $150 million of senior notes,
with an interest rate of 3.36%, in May 2003. PSE was able to pay maturing notes
and redeem other notes mainly with additional equity investments by Puget Energy
in 2003 and 2002.
Preferred
stock dividends decreased
$2.6 million in 2003 compared to 2002 due to the redemption of the 7.45% series
preferred stock not subject to mandatory redemption for both sinking fund
requirements and total redemption of the remaining shares in the series at par
value plus accrued dividends in 2003.
INFRASTRUX
2003
COMPARED TO 2002
The table
below sets forth significant changes in revenues and expenses for InfrastruX
from 2002 to 2003.
(DOLLARS
IN MILLIONS)
TWELVE
MONTHS ENDED DECEMBER 31 |
|
2003 |
|
2002 |
|
CHANGE |
|
PERCENT
CHANGE |
|
|
Non-utility
construction services revenue |
|
$ |
341.8 |
|
$ |
319.5 |
|
$ |
22.3 |
|
|
7.0 |
% |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
operations and maintenance |
|
$ |
302.4 |
|
$ |
270.7 |
|
$ |
31.7 |
|
|
11.7 |
% |
|
Depreciation
and amortization |
|
|
16.8 |
|
|
13.5 |
|
|
3.3 |
|
|
24.4 |
|
|
Income
taxes |
|
|
1.6 |
|
|
6.7 |
|
|
(5.1 |
) |
|
(76.1 |
) |
Non-utility
construction services revenue
increased $22.3 million in 2003 due primarily to acquisitions of several
companies during 2002 and 2003, which contributed to an increase of $44.4
million. Excluding the impact of acquisitions, InfrastruX revenue decreased
$22.1 million from 2002 due primarily to general market weakness and changing
activities on certain lines of business. InfrastruX records revenues as services
are performed or on a percent of completion basis for fixed-price
projects.
Other
operations and maintenance expenses
increased $31.7 million in 2003 compared to 2002 due primarily to acquisitions
of several companies during 2002 and 2003, which contributed to an increase of
$37.1 million. Excluding the impact of acquisitions, operations and maintenance
expenses decreased $5.4 million from 2002 due to lower productivity. The
decrease, excluding the impact of acquisitions, was not proportionate to the
decline in revenues due to the impact of severe wet weather on productivity
during the first quarter 2003 as well as the high costs of completing work in
low-volume activities in 2003.
Depreciation
and amortization expense
increased by $3.3 million in 2003 compared to 2002 due to acquisitions during
2003 and 2002, which were not owned during the full year of 2002.
Income
taxes
decreased $5.1 million in 2003 compared to 2002 due to lower
income.
CAPITAL
RESOURCES AND LIQUIDITY
CAPITAL
REQUIREMENTS
CONTRACTUAL
OBLIGATIONS AND COMMERCIAL COMMITMENTS
Puget
Energy. The
following are Puget Energy’s aggregate consolidated (including PSE) contractual
and commercial commitments as of December 31, 2004:
|
Puget
Energy |
|
|
|
|
|
CONTRACTUAL
OBLIGATIONS
(DOLLARS
IN MILLIONS) |
Total |
2005 |
2006-
2007 |
2008-
2009 |
2010
&
Thereafter |
|
Long-term
debt |
$ |
2,251.4 |
$ |
38.9 |
$ |
552.0 |
$ |
339.5 |
$ |
1,321.0 |
|
Short-term
debt |
|
8.3 |
|
8.3 |
|
-- |
|
-- |
|
-- |
|
Junior
subordinated debentures payable
to
a subsidiary trust 1 |
|
280.3 |
|
-- |
|
-- |
|
-- |
|
280.3 |
|
Mandatorily
redeemable preferred stock |
|
1.9 |
|
-- |
|
-- |
|
-- |
|
1.9 |
|
Service
contract obligations |
|
168.6 |
|
21.5 |
|
48.6 |
|
47.7 |
|
50.8 |
|
Capital
lease obligations |
|
7.0 |
|
2.0 |
|
3.6 |
|
1.4 |
|
-- |
|
Non-cancelable
operating leases |
|
129.5 |
|
19.3 |
|
37.3 |
|
26.8 |
|
46.1 |
|
Fredonia
combustion turbines lease 2 |
|
65.3 |
|
4.6 |
|
8.6 |
|
8.3 |
|
43.8 |
|
Energy
purchase obligations |
|
4,988.2 |
|
929.4 |
|
1,491.0 |
|
1,278.2 |
|
1,289.6 |
|
Financial
hedge obligations |
|
20.0 |
|
6.2 |
|
11.9 |
|
1.9 |
|
-- |
|
Pension
funding |
|
45.7 |
|
4.3 |
|
8.2 |
|
9.8 |
|
23.4 |
|
Total
contractual cash obligations |
$ |
7,966.2 |
$ |
1,034.5 |
$ |
2,161.2 |
$ |
1,713.6 |
$ |
3,056.9 |
|
|
|
|
|
Amount
of Committment
Expiration Per Period |
|
COMMERCIAL
COMMITMENTS
|
Total |
2005 |
2006-
2007 |
2008-
2009 |
2010
&
Thereafter |
|
Guarantees
3 |
$ |
131.0 |
$ |
-- |
$ |
131.0 |
$ |
-- |
$ |
-- |
|
Liquidity
facilities - available 4 |
|
349.5 |
|
-- |
|
349.5 |
|
-- |
|
-- |
|
Lines
of credit - available 5 |
|
53.6 |
|
25.4 |
|
28.2 |
|
-- |
|
-- |
|
Energy
operations letter of credit |
|
0.5 |
|
0.5 |
|
-- |
|
-- |
|
-- |
|
Total
commercial commitments |
$ |
534.6 |
$ |
25.9 |
$ |
508.7 |
$ |
-- |
$ |
-- |
_______________________
| 1 |
In
1997 and 2001, PSE formed Puget Sound Energy Capital Trust I and Puget
Sound Energy Capital Trust II, respectively, for the sole purpose of
issuing and selling preferred securities (Trust Securities) to investors
and issuing common securities to PSE. The proceeds from the sale of Trust
Securities were used by the Trusts to purchase Junior Subordinated
Debentures (Debentures) from PSE. The Debentures are the sole assets of
the Trusts and PSE owns all common securities of the Trusts.
|
| 2 |
See
“Fredonia 3 and 4 Operating Lease” under “Off-Balance Sheet Arrangements”
below. |
| 3 |
In
May 2004, InfrastruX signed a three-year credit agreement with a group of
banks to provide up to $150 million in financing. Under the credit
agreement, Puget Energy is the guarantor of the line of credit. Certain
InfrastruX subsidiaries also have certain borrowing capacities for working
capital purposes of which Puget Energy is not a
guarantor. |
| 4 |
At
December 31, 2004, PSE had available a $350 million unsecured credit
agreement expiring in June 2007 and a $150 million receivables
securitization facility that expires in December 2005. At December 31,
2004, PSE had no amounts of receivables available for sale under its
receivables securitization facility. See “Accounts Receivable
Securitization Program” under “Off-Balance Sheet Arrangements” below for
further discussion. The credit agreement and securitization facility
provide credit support for an outstanding letter of credit totaling $0.5
million, thereby effectively reducing the available borrowing capacity
under these liquidity facilities to $349.5 million.
|
| 5 |
Puget
Energy has a $15 million line of credit with a bank. At December 31, 2004,
$5.0 million was outstanding, leaving $10.0 million available to borrow
under the agreement. Puget Energy reduced the borrowing capacity under
this line of credit to $5.0 million on February 1, 2005. InfrastruX has
$186.7 million in lines of credit with various banks to fund capital
credit requirements of InfrastruX and its subsidiaries. InfrastruX and its
subsidiaries had $139.3 million outstanding under their credit agreements
and letters of credit of $3.8 million at December 31, 2004, effectively
reducing the available borrowing capacity under these lines of credit to
$43.6 million. |
Puget
Sound Energy. The
following are PSE’s aggregate contractual and commercial commitments as of
December 31, 2004:
|
Puget
Sound Energy |
|
|
|
Payments
Due Per Period |
CONTRACTUAL
OBLIGATIONS
(DOLLARS
IN MILLIONS) |
Total |
2005 |
2006-
2007 |
2008-
2009 |
2010
&
Thereafter |
|
Long-term
debt |
$ |
2,095.4 |
$ |
31.0 |
$ |
406.0 |
$ |
337.4 |
$ |
1,321.0 |
|
Junior
subordinated debentures payable
to
a subsidiary trust 1 |
|
280.3 |
|
-- |
|
-- |
|
-- |
|
280.3 |
|
Mandatorily
redeemable preferred stock |
|
1.9 |
|
-- |
|
-- |
|
-- |
|
1.9 |
|
Service
contract obligations |
|
168.6 |
|
21.5 |
|
48.6 |
|
47.7 |
|
50.8 |
|
Non-cancelable
operating leases |
|
116.4 |
|
12.8 |
|
31.6 |
|
26.0 |
|
46.0 |
|
Fredonia
combustion turbines lease 2 |
|
65.3 |
|
4.6 |
|
8.6 |
|
8.3 |
|
43.8 |
|
Energy
purchase obligations |
|
4,988.2 |
|
929.4 |
|
1,491.0 |
|
1,278.2 |
|
1,289.6 |
|
Financial
hedge obligations |
|
20.0 |
|
6.2 |
|
11.9 |
|
1.9 |
|
-- |
|
Pension
funding |
|
45.7 |
|
4.3 |
|
8.2 |
|
9.8 |
|
23.4 |
|
Total
contractual cash obligations |
$ |
7,781.8 |
$ |
1,009.8 |
$ |
2,005.9 |
$ |
1,709.3 |
$ |
3,056.8 |
| |
|
|
|
Amount
of Commitment
Expiration Per Period |
|
|
Total |
2005 |
2006-
2007 |
2008-
2009 |
2010
&
Thereafter |
|
Liquidity
facilities - available 3 |
$ |
349.5 |
$ |
-- |
$ |
349.5 |
$ |
-- |
$ |
-- |
|
Energy
operations letter of credit |
|
0.5 |
|
0.5 |
|
-- |
|
-- |
|
-- |
|
Total
commercial commitments |
$ |
350.0 |
$ |
0.5 |
$ |
349.5 |
$ |
-- |
$ |
-- |
_______________________
OFF-BALANCE
SHEET ARRANGEMENTS
ACCOUNTS
RECEIVABLE SECURITIZATION PROGRAM
In order
to provide a source of liquidity to PSE at an attractive cost, PSE entered into
a Receivables Sales Agreement with Rainier Receivables, Inc., a wholly owned
subsidiary of PSE in December 2002. Pursuant to the Receivables Sales Agreement,
PSE sold all its utility customers’ accounts receivable and unbilled utility
revenues to Rainier Receivables. Concurrently with entering into the Receivables
Sales Agreement, Rainier Receivables entered into a Receivables Purchase
Agreement with PSE and a third party. The Receivables Purchase Agreement allows
Rainier Receivables to sell the receivables purchased from PSE to the third
party. The amount of receivables sold by Rainier Receivables is not permitted to
exceed $150 million at any time. However, the maximum amount may be less
than $150 million depending on the outstanding eligible amount of PSE’s
receivables, which fluctuate with the seasonality of energy sales to
customers.
The
receivables securitization facility is the functional equivalent of a revolving
line of credit secured by receivables. In the event Rainier Receivables elects
to sell receivables under the Receivables Purchase Agreement, Rainier
Receivables is required to pay fees to the purchasers that are comparable to
interest rates on a revolving line of credit. As receivables are collected by
PSE as agent for the receivables purchasers, the outstanding amount of
receivables held by the purchasers declines until Rainier Receivables elects to
sell additional receivables to the purchasers.
The
receivables securitization facility expires in December 2005, but is terminable
by PSE and Rainier Receivables upon notice to the receivables purchasers. At
December 31, 2004, Rainier Receivables had fully utilized its $150 million
available balance under the receivable securitization facility, and therefore
had no additional available balances to be sold under it.
During
the years ended December 31, 2004 and 2003, Rainier Receivables sold a
cumulative $600.2 million and $348.0 million of receivables,
respectively.
FREDONIA
3 AND 4 OPERATING LEASE
PSE
leases two combustion turbines for its Fredonia 3 and 4 electric generating
facility pursuant to a master operating lease that was amended for this purpose
in April 2001. The lease has a term expiring in 2011, but can be canceled by PSE
at any time. Payments under the lease vary with changes in the London Interbank
Offered Rate (LIBOR). At December 31, 2004, PSE’s outstanding balance under the
lease was $56.3 million. The expected residual value under the lease is the
lesser of $37.4 million or 60% of the cost of the equipment. In the event the
equipment is sold to a third party upon termination of the lease and the
aggregate sales proceeds are less than the unamortized value of the equipment,
PSE would be required to pay the lessor contingent rent in an amount equal to
the deficiency up to a maximum of 87% of the unamortized value of the
equipment.
UTILITY
CONSTRUCTION PROGRAM
Utility
construction expenditures for generation, transmission and distribution are
designed to meet continuing customer growth and to improve efficiencies of PSE’s
energy delivery systems. Construction expenditures, excluding equity Allowance
for Funds Used During Construction (AFUDC), were $393.9 million in 2004. Utility
construction expenditures in 2005, 2006 and 2007 are expected to be $380
million, $400 million and $384 million, respectively, excluding amounts for new
generation resources currently under evaluation. New generation resources under
evaluation consist of two separate wind generation projects that are anticipated
to be completed in 2005 and 2006, respectively. The first project, if completed
in 2005, is anticipated to have a total cost of approximately $200 million. The
second project, if completed in 2006, is anticipated to have a total cost range
of approximately $300 to $350 million. The proposed utility construction
expenditures and new generation resource expenditures, if acquired, are
anticipated to be funded with a combination of short-term debt, long-term debt
and equity. Construction expenditure estimates, including the new generation
resources, are subject to periodic review and adjustment in light of changing
economic, regulatory, environmental and efficiency factors.
NEW
GENERATION RESOURCES
In April
2004, PSE completed the purchase of a 49.85% interest in Frederickson 1, a
gas-fired electric generating station located in western Washington. The
purchase has added $80.8 million in utility plant and approximately 124 MW of
electric generation capacity to serve PSE’s retail customers. PSE submitted a
PCORC in October 2003 to the Washington Commission to recover the cost of the
new generating facility and other power costs. The acquisition of Frederickson 1
was approved by the Washington Commission on April 7, 2004 and was also approved
by FERC under the Federal Power Act on April 23, 2004.
In
September and October 2004, PSE signed two non-binding letters of intent to
obtain a 100% ownership interest in both the proposed Wild Horse wind power
project (Wild Horse project) and the Hopkins Ridge wind power project (Hopkins
Ridge project). The projects are located in central and eastern Washington
State. The Wild Horse project is expected to have approximately 100 to 130 wind
turbines and generate from 150 to 230 MW of power or 77 average MW, depending on
the final design agreement. The Hopkins Ridge project is expected to generate
approximately 150 MW of power or 52 average MW. Both projects will require final
binding agreements between PSE and the developers. Such agreements are expected
to be executed in 2005.
OTHER
ADDITIONS
Other
property, plant and equipment additions were $15.5 million in 2004. Puget Energy
expects InfrastruX’s capital additions to be $18.0 million in 2005. Construction
expenditure estimates are subject to periodic review and adjustment in light of
changing economic, regulatory, environmental and efficiency
factors.
CAPITAL
RESOURCES
CASH
FROM OPERATIONS
Cash
generated from operations for the year ended December 31, 2004 was $456.4
million. During that period, $92.3 million in cash was used for AFUDC and
payment of dividends. Consequently, cash flows available for utility
construction expenditures and other capital expenditures were $364.1 million or
87.7% of the $415.4 million in construction expenditures (net of AFUDC and
customer refundable contributions) and other capital expenditure requirements
for 2004. For the year ended December 31, 2003, cash generated from operations
was $317.9 million, $90.0 million of which was used for AFUDC and payment of
dividends. Therefore, cash flows available for utility construction expenditures
and other capital expenditures were $227.9 million, or 77.1% of the $295.7
million in construction expenditures (net of AFUDC and customer refundable
contributions) and other capital expenditure requirements for 2003. The overall
cash generated from operating activities in 2004 increased $138.5 million
compared to 2003. The increase was partially the result of increases in PGA
rates in April 2003, October 2003 and October 2004, combined with lower cash
paid under the PGA mechanism for liability balances in 2003 for a total positive
cash flow of $40.8 million. Cash from operating activities also increased $27.7
million due to higher cash payments received from BPA than provided to customers
under the residential exchange program compared to 2003 when PSE provided
customers more cash than BPA paid to PSE. In addition, changes in deferred taxes
contributed $15.2 million to positive cash flow. In 2004, PSE did not fund the
qualified pension plan compared to funding $26.5 million in 2003, which
positively impacted cash flow from operating activities. Cash flow from
operating activities also improved $27.7 million through recovery of collateral
deposits in 2004 compared to a return of collateral deposits in 2003 from energy
supply counterparties.
FINANCING
PROGRAM
Financing
utility construction requirements and operational needs are dependent upon the
cost and availability of external funds through capital markets and from
financial institutions. Access to funds is dependent upon factors such as
general economic conditions, regulatory authorizations and policies, and Puget
Energy’s and PSE’s credit ratings.
RESTRICTIVE
COVENANTS
In
determining the type and amount of future financing, PSE may be limited by
restrictions contained in its electric and gas mortgage indentures, articles of
incorporation and certain loan agreements. The goodwill impairment at Puget
Energy does not cause any violations of financial covenants at Puget Energy or
PSE. Under the most restrictive tests, at December 31, 2004, PSE could
issue:
| · |
approximately
$281 million of additional first mortgage bonds under PSE’s electric
mortgage indenture based on approximately $468 million of electric
bondable property available for issuance, subject to an interest coverage
ratio limitation of 2.0 times net earnings available for interest, which
PSE exceeded at December 31, 2004; |
| · |
approximately
$417 million of additional first mortgage bonds under PSE’s gas mortgage
indenture based on approximately $695 million of gas bondable property
available for issuance, subject to an interest coverage ratio limitation
of 1.75 times net earnings available for interest, which PSE exceeded at
December 31, 2004; |
| · |
approximately
$486.3 million of additional preferred stock at an assumed dividend rate
of 6.625%; and |
| · |
approximately
$273.2 million of unsecured long-term debt. |
At
December 31, 2004, PSE had approximately $3.6 billion in electric and gas
ratebase to support the interest coverage ratio limitation test for net earnings
available for interest.
CREDIT
RATINGS
Neither
Puget Energy nor PSE has had any rating downgrade triggers that would accelerate
the maturity dates of outstanding debt. However, a downgrade in the companies’
credit ratings could adversely affect their ability to renew existing, or obtain
access to new, credit facilities and could increase the cost of such facilities.
For example, under PSE’s revolving credit facility, the spreads over the index
and commitment fee increase as PSE’s secured long-term debt ratings decline. A
downgrade in commercial paper ratings could preclude PSE’s ability to issue
commercial paper under its current programs. The marketability of PSE commercial
paper is currently limited by the A-3/P-2 ratings by Standard & Poor’s and
Moody’s Investors Service. In addition, downgrades in any or a combination of
PSE’s debt ratings may allow counterparties on a contract by contract basis in
the wholesale electric, wholesale gas and financial derivative markets to
require PSE to post a letter of credit or other collateral, make cash
prepayments, obtain a guarantee agreement or provide other mutually agreeable
security.
| |
Ratings |
| |
Standard
& Poor’s |
Moody’s |
|
Puget
Sound Energy |
|
|
|
Corporate
credit/issuer rating |
BBB- |
Baa3 |
|
Senior
secured debt |
BBB |
Baa2 |
|
Shelf
debt senior secured |
BBB |
(P)Baa2 |
|
Trust
preferred securities |
BB |
Ba1 |
|
Preferred
stock |
BB |
Ba2 |
|
Commercial
paper |
A-3 |
P-2 |
|
Revolving
credit facility |
* |
Baa3 |
|
Ratings
outlook |
Positive |
Stable |
|
Puget
Energy |
|
|
|
Corporate
credit/issuer rating |
BBB- |
Ba1 |
_______________________
*
Standard
& Poor’s does not rate credit facilities.
SHELF
REGISTRATIONS, LONG-TERM DEBT AND COMMON STOCK ACTIVITY
In
January 2004, Puget Energy and PSE filed a shelf registration statement with the
Securities and Exchange Commission for the offering, on a delayed or continuous
basis, of up to $500 million of:
| · |
common
stock of Puget Energy, and |
| · |
senior
notes of PSE, secured by a pledge of PSE’s first mortgage
bonds. |
On July
15, 2004, PSE issued $200 million in floating rate senior notes under its
existing $500 million shelf registration statement, reducing the available
balance for issuance under the shelf registration statement to $300 million. The
notes float at the three-month LIBOR rate plus 0.30%, (2.37% at December 31,
2004), mature on July 14, 2006, and can be redeemed at par any time after
January 15, 2005. PSE used the net proceeds from the sale of the floating rate
senior notes to repay outstanding amounts under its commercial paper and
accounts receivable securitization programs, including amounts incurred to repay
long-term debt, and also used the proceeds to redeem $55 million in principal of
first mortgage bonds at a premium of 3.68% on August 14, 2004. It is anticipated
that the $200 million in floating rate senior notes will be paid off with a
combination of long-term debt and internally generated funds.
During
2004, PSE redeemed the following long-term debt:
| · |
$18.5
million medium term notes with interest rates ranging from 6.07% to
6.10%; |
| · |
$30.0
million medium term notes at an interest rate of 7.80% in May
2004; |
| · |
$4.2
million conservation trust bonds at an interest rate of 6.45% during
2004; |
| · |
$55.0
million medium term notes at an interest rate of 7.35% in August 2004;
and |
| · |
$50.0
million medium term notes at an interest rate of 7.70% in December
2004. |
LIQUIDITY
FACILITIES AND COMMERCIAL PAPER
PSE’s
short-term borrowings and sales of commercial paper are used to provide working
capital and funding of utility construction programs.
In May
2004, PSE entered into a three-year, $350 million unsecured credit agreement
with a group of banks which replaced its previous $250 million unsecured credit
agreement. PSE also has a $150 million receivables securitization program which
expires in December 2005. At December 31, 2004, PSE had available $350 million
in the unsecured credit agreement and no amounts under its $150 million
receivable securitization facility, both of which provide credit support for
outstanding commercial paper and outstanding letters of credit. At December 31,
2004, there was $0.5 million outstanding under a letter of credit and no
commercial paper outstanding, effectively reducing the available borrowing
capacity under these liquidity facilities to $349.5 million.
In May
2004, InfrastruX entered into a three-year, $150 million credit agreement with a
group of banks, replacing its previous $150 million credit agreement. Puget
Energy is the guarantor of the line of credit. In addition, InfrastruX’s
subsidiaries have an additional $36.7 million in lines of credit with various
banks, for a total capacity for InfrastruX and its subsidiaries of $186.7
million under their line of credit agreements. Borrowings available for
InfrastruX are used to fund acquisitions and working capital requirements of
InfrastruX and its subsidiaries. At December 31, 2004, InfrastruX and its
subsidiaries had $139.3 million outstanding under their credit agreements and
letters of credit of $3.8 million, effectively reducing the available borrowing
capacity under these lines of credit to $43.6 million.
Puget
Energy has a $15 million credit agreement expiring in May 2006 with a bank. On
February 1, 2005, Puget Energy reduced the borrowing capacity of this credit
agreement to $5.0 million. Under the terms of the agreement, Puget Energy pays a
floating interest rate on borrowings based on LIBOR. The interest rate is set
for one, two, or three-month periods at the option of Puget Energy with interest
due at the end of each period. Puget Energy also pays a commitment fee on any
unused portion of the credit facility. Puget Energy had $5.0 million outstanding
under the credit agreement at December 31, 2004.
STOCK
PURCHASE AND DIVIDEND REINVESTMENT PLAN
Puget
Energy has a Stock Purchase and Dividend Reinvestment Plan pursuant to which
shareholders and other interested investors may invest cash and cash dividends
in shares of Puget Energy’s common stock. Since new shares of common stock may
be purchased directly from Puget Energy, funds received may be used for general
corporate purposes. Puget Energy issued common stock from the Stock Purchase and
Dividend Reinvestment Plan of $15.2 million (681,491 shares) in 2004 compared to
$15.5 million (721,340 shares) in 2003. The proceeds from sales of stock under
these plans are used for general corporate needs.
COMMON
STOCK OFFERING PROGRAMS
To
provide additional financing options, Puget Energy entered into agreements in
July 2003 with two financial institutions under which Puget Energy may offer and
sell shares of its common stock from time to time through these institutions as
sales agents, or as principals. Sales of the common stock, if any, may be made
by means of negotiated transactions or in transactions that may be deemed to be
“at-the-market” offerings as defined in Rule 415 promulgated under the
Securities Act of 1933, including in ordinary brokers’ transactions on the New
York Stock Exchange at market prices.
OTHER
TENASKA
DISALLOWANCE
The
Washington Commission issued an order on May 13, 2004 determining that PSE did
not prudently manage gas costs for the Tenaska electric generating plant and
ordered PSE to adjust its PCA deferral account to reflect a disallowance of
$25.6 million for the PCA 1 period (July 1, 2002 through June 30, 2003), which
was recorded by PSE as a Purchased Electricity expense in the second quarter
2004. The order also established guidelines for future recovery of Tenaska
costs. The amounts were determined to be a $25.6 million disallowance for the
PCA 1 period and an estimated disallowance of $11.3 million for the PCA 3 period
(July 1, 2004 to June 30, 2005), based upon applying the Washington Commission’s
methodology of 50% disallowance on the return on the Tenaska regulatory asset
due to projected costs exceeding the benchmark during the period. For the PCA 3
period, approximately $5.6 million was disallowed in the period July 1, 2004
through December 31, 2004, primarily as a reduction to Electric Operating
Revenue. While the Washington Commission did not expressly address the
disallowance for the PCA 2 period (July 1, 2003 through June 30, 2004), PSE
estimated the disallowance for the PCA 2 period to be approximately $12.2
million if the Washington Commission were to follow the same methodology as they
have ordered for the PCA 3 period. Therefore, PSE recorded a $12.2 million
disallowance to Purchased Electricity expense in the second quarter 2004 for the
50% disallowance of the return on the Tenaska regulatory asset in accordance
with the Washington Commission’s methodology discussed in its order of May 13,
2004 for a cumulative impact on earnings of $43.4 million in 2004 for the PCA 1,
PCA 2 and PCA 3 periods. As a result of the disallowance recorded, the PCA
customer deferral was expensed and a reserve was established for amounts not
previously deferred under the PCA mechanism. The reserve balance as of December
31, 2004 was $3.2 million, which is expected to be utilized in 2005 as excess
power costs are shared through the PCA mechanism.
PSE filed
the PCA 2 period compliance filing in August 2004 and received an order from the
Washington Commission on February 23, 2005. In the PCA 2 compliance order, the
Washington Commission approved the Washington Commission staff’s recommendation
for an additional return related to the Tenaska regulatory asset in the amount
of $6.1 million related to the period July 1, 2003 through December 31, 2003.
Washington Commission staff’s recommendation was opposed by certain other
parties. This amount alters the PCA deferral and is subject to reconsideration
and appeal by other parties. Parties have 10 days from February 23, 2005 to file
for reconsideration and 30 days to appeal the order. Once the statutory appeal
process has concluded and the Washington Commission issues its final order, PSE
will determine if recording a regulatory asset is appropriate.
In the
May 13, 2004 order, the Washington Commission established guidelines and a
benchmark to determine PSE’s recovery on the Tenaska regulatory asset starting
with the PCA 3 period (July 1, 2004) through the expiration of the Tenaska
contract in the year 2011. The benchmark is defined as the original cost of the
Tenaska contract adjusted to reflect the 1.2% disallowance from a 1994 Prudence
Order.
Below is
a summary of the Tenaska disallowances by quarter through December 31,
2004:
|
(DOLLARS
IN MILLIONS)
QUARTER
ENDING |
7/02
- 6/03
PCA
1
(ordered/final) |
7/03
- 6/04
PCA
2
(estimated) |
7/04
- 12/04
PCA
3
(estimated) |
Total |
|
|
$
25.6 |
|
$
-- |
$
37.8 |
|
|
-- |
-- |
2.8 |
2.8 |
|
|
-- |
-- |
2.8 |
2.8 |
|
Total |
$
25.6 |
|
$
5.6 |
$
43.4 |
The
Washington Commission guidelines for determining future recovery of the Tenaska
costs (gas costs, recovery of the Tenaska regulatory asset and return on the
Tenaska regulatory asset) are as follows:
| 1. |
The
Washington Commission will determine if PSE’s gas purchasing plan and gas
purchases for Tenaska are prudent through the PCA compliance filings.
|
| 2. |
If
PSE’s gas purchasing plan and gas purchases for Tenaska are prudent, and
if PSE’s actual Tenaska costs fall at or below the benchmark, it will
fully recover its Tenaska costs. |
| 3. |
If
PSE’s gas purchasing plan and gas purchases for Tenaska are prudent, but
its actual Tenaska costs exceed the benchmark, PSE will only recover 50%
of the lesser of: |
| a) |
actual
Tenaska costs that exceed the benchmark; or |
| b) |
the
return on the Tenaska regulatory asset. |
| 4. |
If
PSE’s gas purchasing plan or gas purchases are found to be imprudent in a
future proceeding, PSE risks disallowance of any and all Tenaska costs.
|
The
Washington Commission confirmed that if the Tenaska gas costs are deemed
prudent, PSE will recover the full amount of actual gas costs and the recovery
of the Tenaska regulatory asset even if the benchmark is exceeded. The projected
costs and projected benchmark costs for Tenaska have been updated as of December
31, 2004 to reflect higher forward gas prices and are as follows:
|
(DOLLARS
IN MILLIONS) |
|
2005 |
|
2006 |
|
2007 |
|
2008 |
|
2009 |
|
2010 |
|
2011 |
|
|
Projected
Tenaska costs * |
|
$ |
194.5 |
|
$ |
197.2 |
|
$ |
189.0 |
|
$ |
180.3 |
|
$ |
170.3 |
|
$ |
162.9 |
|
$ |
170.0 |
|
|
Projected
Tenaska benchmark costs |
|
|
159.7 |
|
|
167.9 |
|
|
175.2 |
|
|
182.2 |
|
|
189.5 |
|
|
197.2 |
|
|
213.8 |
|
|
Over
(under) benchmark costs |
|
$ |
34.8 |
|
$ |
29.3 |
|
$ |
13.8 |
|
$ |
(1.9 |
) |
$ |
(19.2 |
) |
$ |
(34.3 |
) |
$ |
(43.8 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Projected
50% disallowance based on Washington Commission
methodology |
|
$ |
10.5 |
|
$ |
8.8 |
|
$ |
5.8 |
|
$ |
1.6 |
|
$ |
-- |
|
$ |
-- |
|
$ |
-- |
|
_______________________
*
Projection
will change based on market conditions of gas and replacement power
costs.
PROCEEDINGS
RELATING TO THE WESTERN POWER MARKET
The
following discussion summarizes the status as of the date of this report of
ongoing proceedings in which PSE is a party relating to the Western power
markets. PSE intends to vigorously defend against each of these cases and does
not expect the ultimate resolution of these proceedings in the aggregate to have
a material adverse impact on the financial condition, results of operations or
liquidity of the Company. However, there can be no assurances in that regard
because litigation is subject to numerous uncertainties and PSE is unable to
predict the ultimate outcome of these matters. Accordingly, there can be no
guarantee that these proceedings, either individually or in the aggregate, will
not materially and adversely affect PSE’s financial condition, results of
operations or liquidity.
| 1. |
California
Receivable and California Refund Proceeding. In
2001, PG&E and Southern California Edison failed to pay the California
Independent System Operator Corporation (CAISO) and the California PX for
energy purchases. The CAISO in turn failed to pay various energy
suppliers, including PSE, for energy sales made by PSE into the California
energy market during the fourth quarter 2000. Both PG&E and the
California PX filed for bankruptcy in 2001, further constraining PSE’s
ability to receive payments due to bankruptcy court controls placed on the
distribution of funds by the California PX and the escrow of funds owed by
PG&E for purchases during the fourth quarter 2000 are owed by the
California PX. |
| a. |
California
Refund Proceeding. On
July 25, 2001, FERC ordered an evidentiary hearing (Docket No. EL00-95) to
determine the amount of refunds due to California energy buyers for
purchases made in the spot markets operated by the CAISO and the
California PX during the period October 2, 2000 through
June 20, 2001 (refund period). The CAISO continues its efforts
to prepare revised settlement statements based on newly recalculated costs
and charges for spot market sales to California during the refund period
and currently estimates that it will determine “who owes what to whom” in
early 2005. On September 2, 2004, FERC issued an order selecting Ernst
& Young LLP as the independent auditor of fuel cost allowance claims
made by sellers, including PSE. A review of that claim is pending,
awaiting further guidance from FERC.
Many of the
numerous orders that FERC issued in Docket No. EL00-95 are on appeal and
have been consolidated before the United States Court of Appeals for the
Ninth Circuit as a result of a case management conference conducted on
September 21, 2004. FERC filed the record on November 22, 2004. The Ninth
Circuit ordered on October 22, 2004 that briefing proceed in two rounds.
The first round is limited to three issues: (1) which parties are subject
to FERC’s refund jurisdiction in light of the exemption for
government-owned utilities in section 201(f) of the Federal Power Act
(FPA); (2) the temporal scope of refunds under section 206 of the FPA; (3)
which categories of transactions are subject to
refunds.
Procedures will be
established for the remaining issues, if necessary, after the court’s
disposition of the first round of issues. Following a second case
management conference on November 9, 2004, the Ninth Circuit consolidated
certain petitions for review for briefing of the first round of issues to
be completed by March 1, 2005 and set oral argument hearings for April 12
and 13, 2005. Opening briefs were filed on December 29, 2004. PSE joined
the brief of the Competitive Supplier Group, which argued that FERC has
proposed to require payment of refunds without proper notice to sellers,
without proper limits on the type of transactions affected and without a
finding that the transactions subject to refund in fact produced prices
that were just and reasonable. Respondents’ briefs in support of FERC were
due February 9, 2005. |
| b. |
CAISO
Receivable.
PSE has a bad debt reserve and a transaction fee reserve applied to the
CAISO receivable, such that PSE’s net receivable from the CAISO as of
December 31, 2004 is approximately $21.3 million. PSE estimates the range
for the receivable to be between $21.3 million and $22.4 million, which
includes estimated credits for fuel and power purchase costs and interest.
In its October 16, 2003 Order on Rehearing in this docket, FERC expressly
adopted and approved a stipulation that confirmed that two of PSE’s
“non-spot market” transactions are not subject to mitigation in the Refund
Proceeding. On October 17, 2003, PSE formally presented CAISO with a
request that payment be made on these amounts. The CAISO responded to the
letter on November 13, 2003, expressing an unwillingness to take the issue
up separately or in advance of its cost re-run activities. PSE continues
to pursue the issue in filings through FERC processes.
On May 6, 2004, the
Los Angeles Department of Water and Power filed a motion at FERC in Docket
No. EL00-95 requesting that FERC issue an order permitting monies to be
disbursed from the California PX Settlement Clearing Account and an escrow
account be established as part of PG&E’s bankruptcy proceeding. The
bulk of the monies owed by the CAISO, including the monies owed to PSE,
are held in those two accounts. PSE filed an answer in support of the
motion on May 21, 2004, and awaits an order from FERC. |
| 2. |
Pacific
Northwest Refund Proceeding. In
October 2000, PSE filed a complaint at FERC (Docket No. EL01-10) against
“all jurisdictional sellers” in the Pacific Northwest seeking prospective
price caps consistent with any result FERC supplied for the California
markets. FERC dismissed PSE’s complaint on December 15, 2000, although PSE
filed for rehearing in January 2001. When FERC issued its June 19, 2001
order in Docket No. EL00-95, imposing west-wide price constraints on
energy sales, PSE moved to withdraw its rehearing request and its
complaint in Docket No. EL01-10, on the basis that the relief PSE sought
was fully provided. Various parties, including the Port of Seattle and the
cities of Seattle and Tacoma, moved to intervene in the proceeding. They
asserted the ability to adopt PSE’s complaint to obtain retroactive
refunds for numerous transactions, including many that were not within the
scope of the PSE complaint. The proceeding became commonly referenced as
the “Pacific Northwest Refund Proceeding,” despite the fact that the
original complainant, PSE, did not seek retroactive refunds. A preliminary
evidentiary hearing was held in September 2001, and an Administrative Law
Judge recommendation against refunds followed. In December 2002, FERC
issued an order permitting additional discovery and the submission of any
additional evidence (parallel to the order issued in the California Refund
Proceeding) that reopened the matter to permit parties to introduce any
evidence they claimed to have of market manipulation. A few parties made
filings, asserting market manipulation in early March 2003, and numerous
parties, including PSE, responded to those allegations in late March 2003.
On June 25, 2003, FERC issued an order terminating the proceeding, largely
on procedural, jurisdictional and equitable grounds. Various parties filed
rehearing requests on July 25, 2003. On November 10, 2003, FERC affirmed
an order terminating the Pacific Northwest Refund Proceeding, (Docket No.
EL01-10), largely on procedural, jurisdictional and equitable grounds.
Seven petitions for review, including PSE’s, are now pending before the
United States Court of Appeals for the Ninth Circuit. Opening briefs were
filed on January 14, 2005. PSE’s opening brief addressed procedural flaws
underlying the action of FERC. Specifically, PSE argued that because PSE’s
complaint in the underlying docket was withdrawn as a matter of law on
July 9, 2001, FERC erred in relying on it to serve as the basis to
initiate a “preliminary” investigation into whether refunds for
individually negotiated bilateral transactions in the Pacific Northwest
were appropriate. Briefing is expected to be completed in the first half
of 2005. |
| 3. |
Orders
to Show Cause. On
June 25, 2003, FERC issued two show cause orders pertaining to its western
market investigations that commenced individual proceedings against many
sellers. One show cause order (Docket Nos. EL03-180, et seq.) sought to
investigate approximately 26 entities that allegedly had potential
“partnerships” with Enron. PSE was not named in that show cause order. In
an order dismissing many of the already-named respondents in the
“partnerships” proceeding on January 22, 2004, FERC stated that it did not
intend to proceed further against other parties.
|
The
second show cause order (Docket Nos. EL03-137, et seq.) named PSE (Docket No.
EL03-169) and approximately 54 other entities that allegedly had engaged in
potential “gaming” practices in the CAISO and California PX markets. PSE and
FERC staff filed a proposed settlement of all issues pending against PSE in
those proceedings on August 28, 2003. The proposed settlement, which admits no
wrongdoing on the part of PSE, would result in a payment of $17,092 to settle
all claims. FERC approved the settlement on January 22, 2004. The California
parties filed for rehearing of that order, repeating arguments that had already
been addressed by FERC. On March 17, 2004, PSE filed a motion to dismiss the
California parties’ rehearing request, and awaits FERC action on that
motion.
| 4. |
Port
of Seattle Suit. On
May 21, 2003, the Port of Seattle commenced suit in federal court in
Seattle against 22 energy sellers, alleging that their conduct during 2000
and 2001 constituted market manipulation, violated antitrust laws and
damaged the Port of Seattle. The Port had a contract to purchase its
energy supply from PSE at the time. The Port’s contract linked the price
of the energy sold to the Port to an index price for energy sold at
wholesale at the Mid-Columbia trading hub. The Port alleged that the
Mid-Columbia price was inten-tionally affected improperly by the
defendants, including PSE, and alleges damages of over $30 million. On May
12, 2004, the district court dismissed the lawsuit. The Port of Seattle
filed an appeal to the United States Court of Appeals for the Ninth
Circuit, and on September 13, 2004, filed a brief in the Ninth Circuit
arguing that the district court erred in dismissing its claims. Responses
to the Port’s brief were filed November 2, 2004. The parties await oral
argument to be scheduled. |
| 5. |
Wah
Chang v. Avista Corp., PSE and others. In
June 2004, Puget Energy and PSE were served a federal summons and
complaint by Wah Chang, an Oregon company. Wah Chang claims that during
1998 through 2001 the Company and other energy companies (and in a
separate complaint, energy marketers) engaged in various fraudulent and
illegal activities including the transmittal of electronic wire
communications to transmit false or misleading information to manipulate
the California energy market. The claims include submitting false
information such as energy schedules and bids to the California PX, CAISO,
electronic trading platforms and publishers of energy indexes, alleges
damages of not less than $30 million and seeks treble and punitive
damages, attorneys’ fees and costs. The complaint is similar to the
allegations made by the Port of Seattle currently on appeal in the Ninth
Circuit. The Judicial Panel on Multi District Litigation consolidated this
case with another pending Multi District case and transferred it to
Federal District Court in San Diego on August 20, 2004. The defendants in
both cases filed motions to dismiss on October 25, 2004. Wah Chang opposed
the motions to dismiss, and replies in support of the motions to dismiss
were filed on January 12, 2005. On February 11, 2005, approximately three
weeks after hearing oral argument, the Court dismissed both cases on the
grounds that FERC has the exclusive jurisdiction over plaintiff’s claims
and the filed rate doctrine and Federal preemption barred the court from
hearing the plaintiff’s claims. |
| 6. |
California
Litigation. Attorney
General Cases. On
May 31, 2002, FERC conditionally dismissed a complaint filed on March 20,
2002 by the California Attorney General in Docket No. EL02-71 that alleged
violations of the FPA by FERC and all sellers (including PSE) of electric
power and energy into California. The complaint asserted that FERC’s
adoption and implementation of market rate authority was flawed and, as a
result, individual sellers such as PSE were liable for sales of energy at
rates that were “unjust and unreasonable.” The condition for dismissal was
that all sellers refile transaction summaries of sales to (and, after a
clarifying order issued on June 28, 2001, purchases from) certain
California entities during 2000 and 2001. PSE refiled such transaction
summaries on July 1 and July 8, 2002. The order of dismissal went on
appeal to the Ninth Circuit Court of Appeals. On September 9, 2004, the
Ninth Circuit issued a decision on the California Attorney General’s
challenge to the validity of FERC’s market-based rate system (Lockyer
v. FERC).
This case was originally presented to FERC. The Ninth Circuit upheld
FERC’s authority to authorize sales of electric energy at market based
rates, but found the requirement that all sales at market-based rates be
contained in quarterly reports filed with FERC to be integral to a
market-based rate tariff. The California parties, among others, have
interpreted the decision as providing authority to FERC to order refunds
for different time frames and based on different rationales than are
currently pending in the California Refund Proceedings, discussed above in
“California Refund Proceeding.” The decision itself defers the question of
whether to seek refunds to FERC. PSE, along with other defendants in the
proceeding, sought rehearing of the Ninth Circuit’s decision on October
25, 2004. The Ninth Circuit has yet to issue an order on the rehearing
request. Because the current Ninth Circuit decision may open new periods
of transactions to refund claims under new theories, PSE cannot predict
the scope, nature or ultimate resolution of this case. That additional
uncertainty may make the outcomes of certain other western energy market
cases less predictable than previously
anticipated. |
In
addition, the day after the initial FERC decision in the Lockyer case,
the California Attorney General filed similar claims in state court in
California, including one suit against PSE. These complaints alleged that the
wholesale seller defendants in the California energy market engaged in
anti-competitive behavior in violation of the California Business Practices Act
for sales in the California energy market (Lockyer
v. Transalta). The
complaint asserted that each such “violation” subjects PSE to a fine of up to
$2,500 plus an award of attorneys’ fees and asserts that there were “thousands”
of such violations. Those cases were removed to federal court and dismissed. On
October 12, 2004, the Ninth Circuit issued a decision affirming the dismissal of
all 13 complaints filed by the California Attorney General, including a
complaint against PSE. The Ninth Circuit decision concluded that the opinions in
People
of the State of California ex rel. Bill Lockyer v. Dynegy, et
al. and
Public
Utility District No. 1 of Snohomish County v. Dynegy Power Marketing,
Inc.,
decided earlier this year by the Ninth Circuit, controlled the outcome of the
matters and warranted dismissal. Because no party sought rehearing or filed a
petition for certiorari to the Supreme Court of the United States, the Ninth
Circuit’s order is the final determination of this matter.
California
Class Actions. In May
2002, PSE was served with two cross-complaints, by Reliant Energy Services and
Duke Energy Trading & Marketing, respectively, in six consolidated class
actions filed in Superior Court in San Diego, California. Plaintiffs in the
lawsuit seek, among other things, restitution of all funds acquired by means
that violate the law and payment of treble damages, interest and penalties. The
cross-complaints asserted essentially that the cross-defendants, including PSE,
were also participants in the California energy market at the relevant times,
and that any remedies ordered against some market participants should be ordered
against all. Reliant and Duke also seek indemnification and conditional relief
as buyers in transactions involving cross-defendants should the plaintiffs
prevail. The case was removed to federal court and some of the newly added
defendants, including PSE, moved to dismiss the action. In December 2002, the
federal district court remanded the proceeding to state court, an action which
Duke and Reliant later appealed to the Ninth Circuit. The appeal stayed further
action in the state court proceeding pending the outcome of the appeal. The
cross-complaints and the addition of the 40 new defendants raised issues of
foreign sovereign immunity, jurisdiction and indemnity in the case, all of which
are now part of the appeal. In June 2003, PSE and other defendants filed motions
to respond to the indemnity issues. On May 13, 2004, the Ninth Circuit issued an
order granting PSE status as a cross-appellant but did not permit PSE to
participate in the oral argument heard on June 14, 2004. On December 8, 2004,
the Ninth Circuit issued an opinion affirming the district court’s decision to
remand the case to state court. Powerex filed a petition for rehearing which
argues that although not immune from suit, as a government entity it should be
allowed to litigate in federal, not state court. Powerex’s petition for
rehearing stays issuance of the mandate to remand pending the outcome of its
rehearing request.
CRITICAL
ACCOUNTING POLICIES AND ESTIMATES
The
preparation of financial statements in conformity with Generally Accepted
Accounting Principles requires that management apply accounting policies and
make estimates and assumptions that affect results of operations and the
reported amounts of assets and liabilities in the financial statements. The
following accounting policies represent those that management believes are
particularly important to the financial statements and that require the use of
estimates, assumptions and judgment to describe matters that are inherently
uncertain.
REVENUE
RECOGNITION
Utility
revenues are recognized when the basis of service is rendered, which includes
estimates to determine amounts relating to services rendered but not billed.
Unbilled electricity revenue is determined by taking MWh generated and purchased
less estimated system losses and billed MWh plus unbilled MWh balance at the
last true-up date. The estimated system loss percentage for electricity is
determined by reviewing historical billed MWh to generated and purchased MWh.
The estimated unbilled MWh balance is then multiplied by the estimated average
revenue per MWh. Unbilled gas revenue is determined by taking therms delivered
to PSE less estimated system losses, prior month unbilled therms and billed
therms. The estimated system loss percentage for gas is determined by reviewing
historical billed therms to therms delivered to customers. The estimated current
month unbilled therms is then multiplied by estimated average rate schedule
revenue per therm. Non-utility revenue is recognized when services are
performed, upon the sale of assets, or on a percentage of completion basis for
fixed-price contracts. The recognition of revenue is in conformity with
Generally Accepted Accounting Principles, which requires the use of estimates
and assumptions that affect the reported amounts of revenue.
The
following table represents the sensitivity of the estimate of system losses for
both electricity and gas in calculating unbilled revenues assuming an additional
0.1% increase in the estimated system loss factor since the last annual
true-up:
| |
GAS
REVENUE
DECREASE (MILLIONS) |
ELECTRIC
REVENUE
DECREASE (MILLIONS) |
|
0.1%
increase in loss factor |
$0.4 |
$0.6 |
REGULATORY
ACCOUNTING
As a
regulated entity of the Washington Commission and FERC, PSE prepares its
financial statements in accordance with the provisions of SFAS No. 71,
“Accounting for the Effects of Certain Types of Regulation.” The application of
SFAS No. 71 results in differences in the timing and recognition of certain
revenues and expenses in comparison with businesses in other industries. The
rates that are charged by PSE to its customers are based on cost base regulation
reviewed and approved by the Washington Commission and FERC. Under the authority
of these commissions, PSE has recorded certain regulatory assets and liabilities
at December 31, 2004 in the amount of $645.3 million and $185.7 million,
respectively, and regulatory assets and liabilities of $610.5 million and $176.7
million, respectively, at December 31, 2003.. PSE expects to fully recover these
regulatory assets and liabilities through its rates. If future recovery of costs
ceases to be probable, PSE would be required to write off these regulatory
assets and liabilities. In addition, if at some point in the future PSE
determines that it no longer meets the criteria for continued application of
SFAS No. 71, PSE could be required to write off its regulatory assets and
liabilities.
Also
encompassed by regulatory accounting and subject to SFAS No. 71 are the PCA and
PGA mechanisms. The PCA and PGA mechanisms mitigate the impact of commodity
price volatility upon the Company, and are approved by the Washington
Commission. The PCA mechanism provides for a sharing of costs and benefits that
are graduated over four levels of power cost variances with an overall cap of
$40 million (+/-) plus 1% of the excess over the $40 million cap over the
four-year period ending June 30, 2006. The PCA mechanism will continue after
July 1, 2006, within certain sharing bands. See Item 1 - Business - Regulation
and Rates - Electric Regulation and Rates for further discussion regarding the
PCA mechanism. The PGA mechanism passes through to customers increases and
decreases in the cost of natural gas supply. PSE expects to fully recover these
regulatory assets through its rates. However, both mechanisms are subject to
regulatory review and approval by the Washington Commission on a periodic
basis.
DERIVATIVES
Puget
Energy uses derivative financial instruments primarily to manage its energy
commodity price risks, and may enter into certain financial derivatives to
manage interest rate risk. Derivative financial instruments are accounted for
under SFAS No. 133, “Accounting for Derivative Instruments and Hedging
Activities,” as amended by SFAS No. 138 and SFAS No. 149. Accounting for
derivatives continues to evolve through guidance issued by the Derivatives
Implementation Group (DIG) of the Financial Accounting Standards Board (FASB).
To the extent that changes by the DIG modify current guidance, including the
normal purchases and normal sales determination, the accounting treatment for
derivatives may change.
To manage
its electric and gas portfolios, Puget Energy enters into contracts to purchase
or sell electricity and gas. These contracts are considered derivatives under
SFAS No. 133 unless a determination is made that they qualify for normal
purchases and normal sales exception. If the exception applies, those contracts
are not marked-to-market and are not reflected in the financial statements until
delivery occurs.
The
availability of the normal purchases and normal sales exception to specific
contracts is based on a determination that a resource is available for a forward
sale and similarly a determination that at certain times existing resources will
be insufficient to serve load. This determination is based on internal models
that forecast customer demand and generation supply. The models include
assumptions regarding customer load growth rates, which are influenced by the
economy, weather, the impact of customer choice and resource availability. The
critical assumptions used in the determination of the normal purchases and
normal sales exception are consistent with assumptions used in the general
planning process.
Energy
and financial contracts that are considered derivatives may be eligible for
designation as cash flow hedges. If a contract is designated as a cash flow
hedge, the change in its market value is generally deferred as a component of
other comprehensive income until the transaction it is hedging is completed.
Conversely, the change in the market value of derivatives not designated as cash
flow hedges is recorded in current period earnings.
PSE
values derivative instruments based on daily quoted prices from numerous
independent energy brokerage services. When external quoted market prices are
not available for derivative contracts, PSE uses a valuation model that uses
volatility assumptions relating to future energy prices based on specific energy
markets and utilizes externally available forward market price curves. All
derivative instruments are sensitive to market price fluctuations that can occur
on a daily basis.
PENSION
AND OTHER POSTRETIREMENT BENEFITS
Puget
Energy has a qualified defined benefit pension plan covering substantially all
employees of PSE. For 2004, 2003 and 2002, qualified pension income of $8.0
million, $12.9 million and $17.7 million, respectively, was recorded in the
financial statements. Of these amounts, approximately 63.3%, 67.0% and 66.8%
offset utility operations and maintenance expense in 2004, 2003 and 2002,
respectively, and the remaining amounts were capitalized.
PSE’s
pension and other postretirement benefits income or costs are dependent on
several factors and assumptions, including design of the plan, timing and amount
of cash contributions to the plan, earnings on plan assets, discount rate,
expected long-term rate of return and health care cost trends. Changes in any of
these factors or assumptions will affect the amount of income or expense that
Puget Energy records in its financial statements in future years and also its
projected benefit obligation.
The
follow table reflects the estimated sensitivity associated with a change in
certain actuarial assumptions (each assumption change is presented mutually
exclusive of other assumption changes):
| |
|
CHANGE
IN
ASSUMPTION |
|
IMPACT
ON PROJECTED
BENEFIT
OBLIGATION
INCREASE
(DECREASE) |
|
IMPACT
ON 2004 PENSION
INCOME
INCREASE
(DECREASE) |
|
|
(DOLLARS
IN THOUSANDS) |
|
|
|
PENSION
BENEFITS |
|
OTHER
BENEFITS |
|
|
|
|
|
Increase
in discount rate |
|
|
$ |
(20,548 |
) |
$ |
(3,635 |
) |
$ |
1,261 |
|
$ |
354 |
|
|
Decrease
in discount rate |
|
|
|
22,595 |
|
|
3,891 |
|
|
(48 |
) |
|
(377 |
) |
|
Increase
in return of plan assets |
|
|
|
* |
|
|
* |
|
|
2,370 |
|
|
71 |
|
|
Decrease
in return on plan assets |
|
|
|
* |
|
|
* |
|
|
(2,370 |
) |
|
(71 |
) |
________________________
*
Calculation not applicable.
Qualified
pension income is expected to decline to $2.5 million in 2005 as a result of
lower actual returns on pension assets during the last three years and declining
expected rates of return on pension fund assets. During 2004, PSE made no cash
contributions to the qualified defined benefit plan and expects to make no
contributions in 2005.
GOODWILL
AND INTANGIBLES (PUGET ENERGY ONLY)
On
January 1, 2002, SFAS No. 142, “Goodwill and Other Intangible Assets,” became
effective and as a result Puget Energy ceased amortization of goodwill. Puget
Energy performs an annual impairment review to determine if any impairment
exists. In performing the goodwill impairment test, Puget Energy compares the
present value of the future cash flows of estimated earnings of InfrastruX which
reflects prospective market price information from prospective buyers to the
adjusted carrying value of recorded equity. If goodwill is determined to have an
impairment, Puget Energy will record in the period of determination an
impairment charge to earnings.
Intangibles
with finite lives are amortized based on the expected pattern of use or on a
straight-line basis over the expected periods to be benefited. The goodwill and
intangibles recorded on the balance sheet of Puget Energy are the result of
acquisition of companies by InfrastruX. During 2004, Puget Energy recorded a
non-cash goodwill impairment charge of $91.2 million, or $76.6 million after-tax
and minority interest. As a result, the goodwill balance at December 31, 2004
was $43.5 million. Intangible assets have not been impaired and the balance at
December 31, 2004 was $16.7 million.
CALIFORNIA
RESERVE
PSE
operates within the western wholesale market and has made sales into the
California energy market. At December 31, 2000, PSE’s receivables from the CAISO
and other counterparties, net of reserves, were $41.8 million. PSE received the
majority of the partial payments for sales made in the fourth quarter 2000 in
the first quarter 2001 and has since received a small amount of payments. At
December 31, 2004, such receivables, net of reserves, were approximately $21.3
million.
During
2003, FERC issued an order in the California Refund Proceeding adopting in part
and modifying in part FERC’s earlier findings by the Administrative Law Judge.
Based on the order, PSE has determined that the receivables balance at December
31, 2004 is collectible from the CAISO.
NEW
ACCOUNTING PRONOUNCEMENTS
In
December 2004, FASB issued SFAS No. 123R, “Share-Based Payment” (SFAS No. 123R),
which revises SFAS No. 123, “Accounting For Stock-Based Compensation.” SFAS No.
123R requires companies that issue share-based payment awards to employees for
goods or services to recognize as compensation expense, the fair value of the
expected vested portion of the award as of the grant date over the vesting
period of the award. Forfeitures that occur before the award vesting date will
be adjusted from the total compensation expense, but once the award vests, no
adjustment to compensation expense will be allowed for forfeitures or
unexercised awards. In addition, SFAS No. 123R would require recognition of
compensation expense of all existing outstanding awards that are not fully
vested for their remaining vesting period as of the effective date that were not
accounted for under a fair value method of accounting at the time of their
award. SFAS No. 123R is effective for reporting periods beginning after June 15,
2005. The Company is currently evaluating what impact the application of SFAS
No. 123R will have on its operations. The Company had adopted the fair value
provisions of SFAS No. 123 “Accounting for Stock Based Compensation” in January
2003.
In
December 2004, FASB issued FASB Staff Position No. 109-1, “Application of FASB
Statement No. 109, Accounting for Income Taxes, to the Tax Deduction on
Qualified Production Activities Provided by the American Jobs Creation Act of
2004” (FSP No. 109-1). FSP No. 109-1 states that the staff position related to
deductions as a result of the American Jobs Creation Act (the Act) should be
treated as a “special deduction”, as described in SFAS No. 109, “Accounting For
Income Taxes” and therefore has no effect on deferred tax assets or liabilities
existing at the enactment date. The Company is currently evaluating the impact
of FSP No. 109-1 (which was effective upon issuance) and any deduction available
under the Act. Any deduction available, if determined, is applicable to the
Company’s 2005 tax year.
On May
19, 2004, FASB issued FASB Staff Position (FSP) No. 106-2 “Accounting and
Disclosure Requirements Related to Medicare Prescription Drug, Improvement and
Modernization Act of 2003” as the result of the new Medicare Prescription Drug
and Modernization Act which was signed into law in December 2003. The law
provides a subsidy for plan sponsors that provide prescription drug benefits to
Medicare beneficiaries that are equivalent to the Medicare Part D plan. Based on
an actuarial assessment, PSE will not be eligible for such subsidies, thus FSP
No. 106-2 will have no impact on PSE’s retiree medical plans.
The
Emerging Issues Task Force of the Financial Accounting Standards Board (EITF) at
its July 2003 meeting came to a consensus concerning EITF Issue No. 03-11,
“Reporting Realized Gains and Losses on Derivative Instruments That Are Subject
to FASB Statement No. 133 and Not ‘Held for Trading Purposes’ as Defined in
Issue No. 02-03.” The consensus reached was that determining whether realized
gains and losses on physically settled derivative contracts not held for trading
purposes are reported in the income statement on a gross or net basis is a
matter of judgment that depends on the relevant facts and circumstances. Based
on the guidance by EITF No. 03-11, the Company determined that its non-trading
derivative instruments should be reported net and implemented this treatment
effective January 1, 2004. As a result of the implementation, Electric Revenue
and Purchased Electricity Expense both decreased $108.7 million in 2003 and
$77.1 million in 2002, respectively, with no impact on financial position or net
income.
In March
2004, the EITF came to a consensus concerning EITF Issue No. 03-16, “Accounting
for Investments in Limited Liability Companies.” The consensus reached was that
an investment in a limited liability company should be accounted for using the
equity method for investments greater than 3% to 5%. The adoption of EITF No.
03-16 is effective for reporting periods beginning after June 15, 2004, with any
adjustments being accounted for as a cumulative effect of a change in accounting
principle. The Company reviewed its investments and determined one investment
held by PSE met the criteria established in EITF No. 03-16.
In May
2003, FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments
with Characteristics of Both Liabilities and Equity.” SFAS No. 150 establishes
the requirements for classifying and measuring as liabilities certain financial
instruments that embody obligations to redeem the financial instruments by the
issuer. The adoption of SFAS No. 150 is effective with the first fiscal year or
interim period beginning after June 15, 2003. However, on November 5, 2003 FASB
deferred for an indefinite period certain mandatorily redeemable noncontrolling
interests associated with finite-lived subsidiaries. The Company does not have
any noncontrolling interest in finite-lived subsidiaries and therefore is not
affected by the deferral. Prior periods will not be restated for the new
presentation.
SFAS No.
150 requires the Company to classify its mandatorily redeemable preferred stock
as liabilities. As a result, the corresponding dividends on the mandatorily
redeemable preferred stock are classified as interest expense on the income
statement with no impact on net income.
In
January 2003, FASB issued Interpretation No. 46, “Consolidation of Variable
Interest Entities” (FIN 46), as further revised in December 2003 with FIN 46R,
which clarifies the application of Accounting Research Bulletin No. 51,
“Consolidated Financial Statements,” to certain entities in which equity
investors do not have a controlling interest or sufficient equity at risk for
the entity to finance its activities without additional financial support. FIN
46R requires that if a business entity has a controlling financial interest in a
variable interest entity, the financial statements must be included in the
consolidated financial statements of the business entity. The adoption of FIN
46R for all interests in variable interest entities created after January 31,
2003 was effective immediately. For variable interest entities created before
February 1, 2003, it was effective July 1, 2003. The adoption of FIN 46R was
effective March 31, 2004. The Company has evaluated its contractual arrangements
and determined PSE’s 1995 conservation trust off-balance sheet financing
transaction meets this guidance, and therefore it was consolidated in the third
quarter 2003. As a result, electricity revenues for 2003 increased $5.7 million,
while conservation amortization and interest expense increased by the
corresponding amount with no impact on earnings. FIN 46R also impacted the
treatment of the Company’s mandatorily redeemable preferred securities of a
wholly owned subsidiary trust holding solely junior subordinated debentures of
the corporation (trust preferred securities). Previously, these trust-preferred
securities were consolidated into the Company’s operations. As a result of FIN
46R, these securities have been deconsolidated and were classified as junior
subordinated debentures of the corporation payable to a subsidiary trust holding
mandatorily redeemable preferred securities (junior subordinated debt) in the
fourth quarter 2003. This change had no impact on the Company’s results of
operations. The Company also evaluated its purchase power agreements and
determined that three counterparties may be considered variable interest
entities. As a result, PSE submitted requests for information to those parties;
however, the parties have refused to submit to PSE the necessary information for
PSE to determine whether they meet the requirements of a variable interest
entity. PSE also determined that it does not have a contractual right to such
information. PSE will continue to submit requests for information to the
counterparties on a quarterly basis to determine if FIN 46R is
applicable.
For the
three purchase power agreements that may be considered variable interest
entities under FIN 46R, PSE is required to buy all the generation from these
plants, subject to displacement by PSE, at rates set forth in the purchase power
agreements. If at any time the counterparties cannot deliver energy to PSE, PSE
would have to buy energy in the wholesale market at prices which could be higher
or lower than the purchase power agreement prices. PSE’s Purchased Electricity
expense for 2004 and 2003 for these three entities was $251.2 million and $273.9
million, respectively.
In June
2001, FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations,”
(SFAS No. 143), which is effective for fiscal years beginning after June 15,
2002. SFAS No. 143 requires legal obligations associated with the retirement of
long-lived assets to be recognized at their fair value at the time that the
obligations are incurred. Upon initial recognition of a liability, that cost
should be capitalized as part of the related long-lived asset and allocated to
expense over the useful life of the asset. The Company adopted the new rules on
asset retirement obligations on January 1, 2003. As a result, the Company
recorded a $0.2 million charge to income for the cumulative effect of this
accounting change.
In
November 2004, FASB reached a decision concerning a proposed interpretation of
SFAS No. 143 titled “Accounting for Conditional Asset Retirement Obligations.”
The proposed interpretation addresses the issue of whether SFAS No. 143 requires
an entity to recognize a liability for a legal obligation to perform asset
retirement when the asset retirement activities are conditional on a future
event, and if so, the timing and valuation of the recognition. The decision
reached by FASB was that there are no instances where a law or regulation
obligates an entity to perform retirement activities but then allows the entity
to permanently avoid settling the obligation. This, if part of the final issued
interpretation, could potentially have an impact on the Company as assets that
were previously considered outside the scope of SFAS No. 143 may be subject to
the terms of the proposed interpretation. FASB indicated that the final
interpretation is anticipated to be issued in the first quarter 2005, with an
effective date for fiscal years ending after December 15, 2005, and with any
adjustment accounted for as a cumulative effect of an accounting change. The
Company is currently evaluating what impact this proposed interpretation may
have on the Company if issued.
|
|
QUANTITATIVE
AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK |
ENERGY
PORTFOLIO MANAGEMENT
The
regulatory mechanisms of the PGA and the PCA mitigate the impact of commodity
price volatility on the Company. The PGA mechanism passes through increases and
decreases in the cost of natural gas supply to customers. The PCA mechanism
provides for a sharing of costs and benefits that are graduated over four levels
of power cost variances with an overall cap of $40 million (+/-) plus 1% of the
excess over the $40 million cap over the four-year period ending June 30, 2006.
The
Company is focused on commodity price exposure and risks associated with
volumetric variability in the gas portfolio and electric portfolio for its
customers. Gas and electric portfolio exposure is managed in accordance with
Company polices and procedures. The Risk Management Committee, which is composed
of Company officers, provide policy-level and strategic direction for management
of the energy portfolio. The Audit Committee of the Company’s Board of Directors
periodically assesses risk management policies.
The
nature of serving regulated electric customers with its wholesale portfolio of
owned and contracted resources exposes the Company and its customers to some
volumetric and commodity price risks within the sharing mechanism of the PCA.
The Company’s energy risk management function monitors and manages these risks
using analytical models and tools. The Company manages its energy supply
portfolio to achieve three primary objectives:
| · |
ensure
that physical energy supplies are available to serve retail customer
requirements; |
| · |
manage
portfolio risks to limit undesired impacts on the Company’s costs;
and |
| · |
maximize
the value of the Company’s energy supply
assets. |
The
Company is not engaged in the business of assuming risk for the purpose of
speculative trading revenues. Therefore wholesale market transactions are
focused on balancing the Company’s energy portfolio, reducing costs and risks
where feasible, and reducing volatility in wholesale costs and margin in the
portfolio. In order to manage risks effectively, the Company enters into
physical and financial transactions, which are appropriate for the service
territory of the Company and are relevant to its regulated electric and gas
portfolios.
The risk
metrics the Company employs are aimed at assessing exposure for the purposes of
developing strategies to reduce the potential exposure on a cost-effective basis
in regulated utility gas and electric portfolios. Specifically, the amount of
risk exposure is defined by time period and by portfolio. It is determined
through statistical methods aimed at forecasting risk.
The
energy risk management staff models forecasted load requirements and expected
resource availability, and projects the net deficit or surplus position
resulting from any imbalance between load requirements and existing resources.
However, the portfolios are subject to major sources of variability (e.g.,
hydroelectric generation, outage risk, regional economic factors,
temperature-sensitive retail sales and market prices for gas and power
supplies). At certain times, these sources of variability can mitigate portfolio
imbalances and at other times they can exacerbate portfolio imbalances. Because
of the volumetric and cost variability within the electric and gas portfolios,
the Company runs market simulations to model potential risk scenarios. In this
way, strategies can be developed to address the expected case as well as other
potential scenarios. Resources in the gas portfolio include gas supply
arrangements, gas storage and gas transportation contracts. Resources in the
electric portfolio include power purchase agreements, generating resources and
transmission contracts.
The
Company’s energy risk management staff develops hedging strategies to manage
deficit or surplus positions in the portfolios. The Company’s energy risk policy
states that hedging and optimization strategies will be consistent with Company
objectives. The Company relies on risk analysis, operational factors,
professional judgment of its employees and fundamental analysis. The Company
will engage in transactions that reduce risks in its electric and gas
portfolios, and optimize unused capacity where possible. Cost and reliability
factors are considered in its hedging strategies. The Company’s hedging
activities are aimed at removing risks from the Company’s electric and gas
portfolios, giving important consideration to cost of hedges and lost
opportunity in order to find a balance between price stability and least cost.
The hedge strategies for the gas and electric portfolios incorporate risk
analysis, operational factors and professional judgment of its employees as well
as fundamental analysis. Programmatic hedge plans are developed to ensure
disciplined hedging, and discretion is used in hedging within specific
guidelines of the programmatic hedge plans approved by the Risk Management
Committee. Most hedges can be implemented in ways that retain the Company’s
ability to use its energy supply optimization opportunities. Some hedges are
structured similarly to insurance instruments, where the Company pays an
insurance premium to protect against certain extreme conditions.
Without
jeopardizing the security of supply within its portfolio, the Company also
engages in optimizing the portfolio. Optimization may take the form of utilizing
excess capacity, shaping flexible resources to capture their highest value and
utilizing transmission capacity through third party transactions. As a result,
portions of the Company’s energy portfolio are monetized through the use of
forward price instruments which help reduce overall costs.
The
Company has entered into master netting agreements with counterparties when
available to mitigate credit exposure to those counterparties. The Company
believes that entering into such agreements reduces risk of settlement default
for the ability to make only one net payment. In addition, the Company believes
risk is mitigated with an improved position in potential counterparty bankruptcy
situations due to a consistent netting approach.
At
December 31, 2004, the Company was subject to a range of netting provisions,
including both stand alone agreements and the provisions associated with the
Western Systems Power Pool agreement of which many energy suppliers in the
western United States are a part.
Transactions
that qualify as hedge transactions under SFAS No. 133 are recorded on the
balance sheet at fair value. Changes in fair value of the Company’s derivatives
are recorded each period in current earnings or other comprehensive income.
Short-term derivative contracts for the purchase and sale of electricity are
valued based on daily quoted prices from an independent energy brokerage
service. Valuations for short-term and medium-term natural gas financial
derivatives are derived from a combination of quotes from several independent
energy brokers and are updated daily. Long-term gas financial derivatives are
valued based on published pricing from a combination of independent brokerage
services and are updated monthly. Option contracts are valued using market
quotes and a Monte Carlo simulation based model approach.
At
December 31, 2004, the Company had an after-tax net asset of approximately $20.0
million of energy contracts designated as qualifying cash flow hedges and a
corresponding unrealized gain recorded in other comprehensive income. Of the
amount in other comprehensive income, 99% of the mark-to-market gain beginning
February 1, 2005 has been reclassified out of other comprehensive income to a
deferred account in accordance with SFAS No. 71 due to the Company expecting to
reach the $40 million cap under the PCA mechanism. The Company also had energy
contracts that were marked-to-market at a gain of $1.2 million after-tax through
current earnings for the 12 months ended December 31, 2004. These mark-to-market
adjustments were primarily the result of excluding certain contracts from the
normal purchase normal sale exception under SFAS No. 133. A portion of the
mark-to-market adjustments beginning February 1, 2005, has been reclassified to
a deferred account in accordance with SFAS No. 71 due to the Company expecting
to reach the $40 million cap under the PCA mechanism. The Company also had a
liability of approximately $12.1 million of gas contracts. All mark-to-market
adjustments relating to the natural gas business have been reclassified to a
deferred account in accordance with SFAS No. 71 due to the PGA mechanism. The
PGA mechanism passes on to customers increases and decreases in the cost of
natural gas supply. A hypothetical 10% increase in the market prices of natural
gas and electricity would increase the fair value of qualifying cash flow hedges
by approximately $5.5 million after-tax and would increase current earnings for
those contracts marked-to-market in earnings by an immaterial
amount.
|
ENERGY
DERIVATIVE CONTRACTS
(DOLLARS
IN MILLIONS) |
|
AMOUNTS |
|
|
|
|
|
|
$ |
12.6 |
|
|
Contracts
realized or otherwise settled during 2004 |
|
|
|
|
(9.8 |
) |
|
Changes
in fair values of derivatives |
|
|
|
|
6.9 |
|
|
|
|
|
|
$ |
9.7 |
|
| |
FAIR
VALUE OF CONTRACTS WITH SETTLEMENT
DURING
YEAR |
|
SOURCE
OF FAIR VALUE
|
2005 |
2006-
2007 |
2008-
2009 |
2010
AND
THEREAFTER |
TOTAL
FAIR
VALUE |
|
Prices
actively quoted |
$
(3.8) |
$
6.3 |
$
-- |
$
-- |
$
2.5 |
|
Prices
provided by other external sources |
-- |
5.4 |
1.8 |
-- |
7.2 |
|
Prices
based on models and other valuation methods |
$
(3.8) |
$
11.7 |
$ 1.8 |
$
-- |
$
9.7 |
INTEREST
RATE RISK
The
Company believes its interest rate risk primarily relates to the use of
short-term debt instruments, variable-rate notes and leases and long-term debt
financing needed to fund capital requirements. The Company manages its interest
rate risk through the issuance of mostly fixed-rate debt of various maturities.
The Company utilizes bank borrowings, commercial paper, line of credit
facilities and accounts receivable securitization to meet short-term cash
requirements. These short-term obligations are commonly refinanced with
fixed-rate bonds or notes when needed and when interest rates are considered
favorable. The Company may enter into swap instruments or other financial hedge
instruments to manage the interest rate risk associated with these debts. The
Company did not have any swap instruments outstanding as of December 31, 2004 or
2003. The carrying amounts and the fair values of Puget Energy’s debt
instruments are:
| |
2004 |
|
2003 |
|
(DOLLARS
IN MILLIONS) |
CARRYING
AMOUNT |
|
|
CARRYING
AMOUNT |
FAIR
VALUE |
|
Financial
liabilities: |
|
|
|
|
|
|
Short-term
debt |
$
8.3 |
$
8.3 |
|
$
13.9 |
$
13.9 |
|
Long-term
debt -
fixed-rate1 |
2,051.4 |
2,194.8 |
|
2,216.3 |
2,409.6 |
|
Long-term
debt -
variable-rate1 |
200.0 |
199.9 |
|
-- |
-- |
______________________
| 1 |
PSE’s
carrying value and fair value of both fixed-rate and variable-rate
long-term debt in 2004 was $2,095.4 million and $2,238.7 million,
respectively. PSE’s carrying value and fair value of fixed-rate long-term
debt in 2003 was $2,053.0 million and $2,250.4 million,
respectively. |
In the
third quarter 2004, the Company entered into two treasury lock contracts to
hedge against potential rising interest rate exposure for a debt offering
anticipated to be performed in the first half of 2005. A treasury lock is a
financial arrangement between the Company and a counterparty whereby one of the
parties will be required to make a payment to the other party on a specific
valuation date based upon the change in value of a 30-year treasury bond. If
interest rates rise related to the hedged debt from the date of issuance of the
treasury lock instruments, the Company would receive a payment from the
counterparty for the change in the bond value. Alternatively, if interest rates
decrease related to the hedged debt from the date of issuance of the treasury
lock instruments, the Company would pay the counterparty for the change in bond
value. These treasury lock contracts were designated under SFAS No. 133 criteria
as cash flow hedges, with all changes in market value for each reporting period
being presented net of tax in other comprehensive income. All financial hedge
contracts of this type are reviewed by senior management and presented to the
Securities Pricing Committee of the Board of Directors, and are approved prior
to execution. At December 31, 2004, the unrealized loss associated with the two
treasury lock contracts was $11.3 million that qualify as cash flow hedges and
is included in other comprehensive income. A hypothetical 10% decrease in the
interest rate of a 30-year treasury note would result in an additional loss of
$12.1 million net of tax in other comprehensive income.
The
treasury lock contracts will settle completely in 2005.
|
TREASURY
LOCK CONTRACTS
(DOLLARS
IN MILLIONS) |
AMOUNTS |
|
|
$
-- |
|
Contracts
realized or otherwise settled during 2004 |
-- |
|
Changes
in fair values of derivatives |
(11.3) |
|
|
$
(11.3) |
|
|
FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA |
| |
|
|
|
|
|
|
|
|
|
|
| |
|
|
CONSOLIDATED
FINANCIAL STATEMENTS: |
|
| |
|
|
PUGET
ENERGY: |
|
|
|
|
| |
|
|
|
|
| |
|
|
|
|
| |
|
|
|
|
| |
|
|
|
|
| |
|
|
|
|
| |
|
|
PUGET
SOUND ENERGY: |
|
|
|
|
| |
|
|
|
|
| |
|
|
|
|
| |
|
|
|
|
| |
|
|
|
|
| |
|
|
|
|
| |
|
|
|
|
|
Combined
Puget Energy and Puget Sound Energy Notes to Consolidated Financial
Statements |
|
| |
|
|
|
|
| |
|
|
SCHEDULE: |
|
| |
|
|
|
|
| |
|
|
All
other schedules have been omitted because of the absence of the conditions
under which they are required, or because the information required is
included in the financial statements or the notes thereto. |
|
| |
|
Financial
statements of PSE’s subsidiaries are not filed herewith inasmuch as the
assets, revenues, earnings and earnings reinvested in the business of the
subsidiaries are not material in relation to those of PSE. |
|
and
PUGET
SOUND ENERGY, INC.
Puget
Energy, Inc. and Puget Sound Energy, Inc. (the Company) management assumes
accountability for maintaining compliance with our established financial
accounting policies and for reporting our results with objectivity and
integrity. The Company believes it is essential for investors and other users of
the consolidated financial statements to have confidence that the financial
information we provide is timely, complete, relevant, and accurate. Management
is also responsible to present fairly Puget Energy’s and Puget Sound Energy’s
consolidated financial statements, prepared in accordance with generally
accepted accounting principles.
Management,
with oversight of the Board of Directors, established and maintains a strong
ethical climate under the guidance of our Corporate Ethics and Compliance
Program so that our affairs are conducted to high standards of proper personal
and corporate conduct. Management also established an internal control system
that provides reasonable assurance as to the integrity and accuracy of the
consolidated financial statements. These policies and practices reflect
corporate governance initiatives that are compliant with the corporate
governance requirements of the Sarbanes-Oxley Act of 2002,
including:
| · |
Our
Board has adopted clear corporate governance
guidelines. |
| · |
With
the exception of the Chief Executive Officer, the Board members are
independent of the Company and its
management. |
| · |
All
members of our key Board committees - the Audit Committee, the
Compensation and Development Committee and the Governance and Public
Affairs Committee - are independent of the Company and its
management. |
| · |
The
independent members of our Board meet regularly without the presence of
Puget Energy and Puget Sound Energy
management. |
| · |
The
Charters of our Board committees clearly establish their respective roles
and responsibilities. |
| · |
The
Company has adopted a Compliance and Ethics Code with a hotline (through
an independent third party) available to all employees, and our Audit
Committee has procedures in place for the anonymous submission of employee
complaints on accounting, internal accounting controls, or auditing
matters. The Compliance Program is led by a senior officer of the
Company. |
| · |
Our
internal audit control function maintains critical oversight over the key
areas of our business and financial processes and controls, and reports
directly to our Board Audit Committee. |
PricewaterhouseCoopers
LLP, our independent registered public accounting firm, reports directly to the
Audit Committee of the Board of Directors. PricewaterhouseCoopers LLP’s
accompanying report on our consolidated financial statements is based on its
examination conducted in accordance with auditing standards generally accepted
in the United States, including a review of our internal control structure for
purposes of designing their audit procedures. Our independent registered
accounting firm has reported on the effectiveness of our internal control over
financial reporting as required under Section 404 of the Sarbanes-Oxley Act of
2002. The Company is confident in the effectiveness of our internal controls and
our ability to meet the requirements of this newly enacted
legislation.
We are
committed to improving shareholder value and accept our fiduciary oversight
responsibilities. We are dedicated to ensuring that our high standards of
financial accounting and reporting as well as our underlying system of internal
controls are maintained. Our culture demands integrity and we have confidence in
our processes, our internal controls, and our people, who are objective in their
responsibilities and who operate under a high level of ethical
standards.
|
/s/
Stephen P. Reynolds |
|
/s/
Bertrand A. Valdman |
|
/s/
James W. Eldredge |
|
Stephen
P. Reynolds |
|
Bertrand
A. Valdman |
|
James
W. Eldredge |
|
President
and Chief Executive Officer |
|
Senior
Vice President Finance
And
Chief Financial Officer |
|
Corporate
Secretary and
Chief
Accounting Officer |
We have
completed an integrated audit of Puget Energy, Inc.’s 2004 consolidated
financial statements and of its internal control over financial reporting as of
December 31, 2004 and audits of its 2003 and 2002 consolidated financial
statements in accordance with the standards of the Public Company Accounting
Oversight Board (United States). Our opinions, based on our audits, are
presented below.
Consolidated
financial statements and financial statement schedule
In our
opinion, the consolidated financial statements listed in the accompanying
index present fairly, in all material respects, the financial position of
Puget Energy, Inc. and its subsidiaries at December 31, 2004 and 2003, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 2004 in conformity with accounting principles
generally accepted in the United States of America. In addition, in our opinion,
the financial statement schedule listed in the accompanying index presents
fairly, in all material respects, the information set forth therein when read in
conjunction with the related consolidated financial statements. These financial
statements and financial statement schedule are the responsibility of the
Company’s management. Our responsibility is to express an opinion on these
financial statements and financial statement schedule based on our audits. We
conducted our audits of these statements in accordance with the standards of the
Public Company Accounting Oversight Board (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 of
financial statements includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
As
described in Note 2 to the consolidated financial statements, effective January
1, 2004, the Company changed its method of accounting for realized gains and
losses on physically settled derivative contracts not held for trading purposes
as required by EITF Issue No. 03-11 “Reporting Realized Gains and Losses on
Derivative Instruments That Are Subject to FASB Statement No. 133 and Not ‘Held
for Trading Purposes’ as Defined in Issue No. 02-03”. As described in Note 2 to
the consolidated financial statements, effective January 1, 2003, the Company
changed its method of accounting for asset retirement obligations as required by
Statement of Financial Accounting Standards No. 143 “Accounting for Asset
Retirement Obligations”.
Internal
control over financial reporting
Also, in
our opinion, management’s assessment, included in Management’s Report on
Internal Control Over Financial Reporting appearing under Item 9A, that the
Company maintained effective internal control over financial reporting as of
December 31, 2004 based on criteria established in Internal
Control - Integrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway Commission (COSO),
is fairly stated, in all material respects, based on those criteria.
Furthermore, in our opinion, the Company maintained, in all material respects,
effective internal control over financial reporting as of December 31, 2004,
based on criteria established in Internal
Control - Integrated Framework issued
by the COSO. The Company’s management is responsible for maintaining effective
internal control over financial reporting and for its assessment of the
effectiveness of internal control over financial reporting. Our responsibility
is to express opinions on management’s assessment and on the effectiveness
of the Company’s internal control over financial reporting based on our audit.
We conducted our audit of internal control over financial reporting in
accordance with the standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether effective internal control over
financial reporting was maintained in all material respects. An audit of
internal control over financial reporting includes obtaining an understanding of
internal control over financial reporting, evaluating management’s assessment,
testing and evaluating the design and operating effectiveness of internal
control, and performing such other procedures as we consider necessary in the
circumstances. We believe that our audit provides a reasonable basis for our
opinions.
A
company’s internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company’s internal control over
financial reporting includes those policies and procedures that (i) pertain
to the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company;
(ii) provide reasonable assurance that transactions are recorded as
necessary to permit preparation of financial statements in accordance with
generally accepted accounting principles, and that receipts and expenditures of
the company are being made only in accordance with authorizations of management
and directors of the company; and (iii) provide reasonable assurance
regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the company’s assets that could have a material effect on the
financial statements.
Because
of its inherent limitations, internal control over financial reporting may not
prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.
/s/PricewaterhouseCoopers
LLP
Seattle,
Washington
We have
completed an integrated audit of Puget Sound Energy, Inc.’s 2004 consolidated
financial statements and of its internal control over financial reporting as of
December 31, 2004 and audits of its 2003 and 2002 consolidated financial
statements in accordance with the standards of the Public Company Accounting
Oversight Board (United States). Our opinions, based on our audits, are
presented below.
Consolidated
financial statements and financial statement schedule
In our
opinion, the consolidated financial statements listed in the accompanying
index present fairly, in all material respects, the financial position of
Puget Sound Energy, Inc. and its subsidiaries at December 31, 2004 and 2003, and
the results of their operations and their cash flows for each of the three years
in the period ended December 31, 2004 in conformity with accounting principles
generally accepted in the United States of America. In addition, in our opinion,
the financial statement schedule listed in the accompanying index presents
fairly, in all material respects, the information set forth therein when read in
conjunction with the related consolidated financial statements. These financial
statements and financial statement schedule are the responsibility of the
Company’s management. Our responsibility is to express an opinion on these
financial statements and financial statement schedule based on our audits. We
conducted our audits of these statements in accordance with the standards of the
Public Company Accounting Oversight Board (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 of
financial statements includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
As
described in Note 2 to the consolidated financial statements, effective January
1, 2004, the Company changed its method of accounting for realized gains and
losses on physically settled derivative contracts not held for trading purposes
as required by EITF Issue No. 03-11 “Reporting Realized Gains and Losses on
Derivative Instruments That Are Subject to FASB Statement No. 133 and Not ‘Held
for Trading Purposes’ as Defined in Issue No. 02-03”. As described in Note 2 to
the consolidated financial statements, effective January 1, 2003, the Company
changed its method of accounting for asset retirement obligations as required by
Statement of Financial Accounting Standards No. 143 “Accounting for Asset
Retirement Obligations”.
Internal
control over financial reporting
Also, in
our opinion, management’s assessment, included in Management’s Report on
Internal Control Over Financial Reporting appearing under Item 9A, that the
Company maintained effective internal control over financial reporting as of
December 31, 2004 based on criteria established in Internal
Control - Integrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway Commission (COSO),
is fairly stated, in all material respects, based on those criteria.
Furthermore, in our opinion, the Company maintained, in all material respects,
effective internal control over financial reporting as of December 31, 2004,
based on criteria established in Internal
Control - Integrated Framework issued
by the COSO. The Company’s management is responsible for maintaining effective
internal control over financial reporting and for its assessment of the
effectiveness of internal control over financial reporting. Our responsibility
is to express opinions on management’s assessment and on the effectiveness
of the Company’s internal control over financial reporting based on our audit.
We conducted our audit of internal control over financial reporting in
accordance with the standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether effective internal control over
financial reporting was maintained in all material respects. An audit of
internal control over financial reporting includes obtaining an understanding of
internal control over financial reporting, evaluating management’s assessment,
testing and evaluating the design and operating effectiveness of internal
control, and performing such other procedures as we consider necessary in the
circumstances. We believe that our audit provides a reasonable basis for our
opinions.
A
company’s internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company’s internal control over
financial reporting includes those policies and procedures that (i) pertain
to the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company;
(ii) provide reasonable assurance that transactions are recorded as
necessary to permit preparation of financial statements in accordance with
generally accepted accounting principles, and that receipts and expenditures of
the company are being made only in accordance with authorizations of management
and directors of the company; and (iii) provide reasonable assurance
regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the company’s assets that could have a material effect on the
financial statements.
Because
of its inherent limitations, internal control over financial reporting may not
prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.
/s/PricewaterhouseCoopers
LLP
Seattle,
Washington
Puget
Energy Consolidated Statements of
|
(DOLLARS
IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
FOR
YEARS ENDED DECEMBER 31 |
|
2004 |
|
2003 |
|
2002 |
|
Operating
revenues: |
|
|
|
|
|
|
|
|
Electric |
|
$ |
1,423,034 |
|
$ |
1,400,743 |
|
$ |
1,288,744 |
|
|
Gas |
|
|
769,306 |
|
|
634,230 |
|
|
697,155 |
|
|
Non-utility
construction services |
|
|
369,936 |
|
|
341,787 |
|
|
319,529 |
|
|
Other |
|
|
6,537 |
|
|
6,043 |
|
|
9,753 |
|
|
Total
operating revenues |
|
|
2,568,813 |
|
|
2,382,803 |
|
|
2,315,181 |
|
|
Operating
expenses: |
|
|
|
|
|
|
|
|
|
|
|
Energy
costs: |
|
|
|
|
|
|
|
|
|
|
|
Purchased
electricity |
|
|
723,567 |
|
|
714,469 |
|
|
568,230 |
|
|
Electric
generation fuel |
|
|
80,772 |
|
|
64,999 |
|
|
113,538 |
|
|
Residential
exchange |
|
|
(174,473 |
) |
|
(173,840 |
) |
|
(149,970 |
) |
|
Purchased
gas |
|
|
451,302 |
|
|
327,132 |
|
|
405,016 |
|
|
Unrealized
(gain) loss on derivative instruments |
|
|
(526 |
) |
|
106 |
|
|
(11,612 |
) |
|
Utility
operations and maintenance |
|
|
291,232 |
|
|
289,702 |
|
|
286,220 |
|
|
Other
operations and maintenance |
|
|
322,517 |
|
|
303,972 |
|
|
273,157 |
|
|
Depreciation
and amortization |
|
|
246,842 |
|
|
236,866 |
|
|
228,743 |
|
|
Conservation
amortization |
|
|
22,688 |
|
|
33,458 |
|
|
17,501 |
|
|
Goodwill
impairment |
|
|
91,196 |
|
|
-- |
|
|
-- |
|
|
Taxes
other than income taxes |
|
|
221,981 |
|
|
208,395 |
|
|
215,429 |
|
|
Income
taxes |
|
|
74,964 |
|
|
72,369 |
|
|
59,260 |
|
|
Total
operating expenses |
|
|
2,352,062 |
|
|
2,077,628 |
|
|
2,005,512 |
|
|
Operating
income |
|
|
216,751 |
|
|
305,175 |
|
|
309,669 |
|
|
Other
income (deductions): |
|
|
|
|
|
|
|
|
|
|
|
Other
income |
|
|
4,292 |
|
|
1,564 |
|
|
5,458 |
|
|
Interest
charges: |
|
|
|
|
|
|
|
|
|
|
|
AFUDC |
|
|
5,420 |
|
|
3,343 |
|
|
1,969 |
|
|
Interest
expense |
|
|
(178,419 |
) |
|
(187,316 |
) |
|
(198,346 |
) |
|
Mandatorily
redeemable securities interest expense |
|
|
(91 |
) |
|
(1,072 |
) |
|
-- |
|
|
Preferred
stock dividends of subsidiary |
|
|
-- |
|
|
(5,151 |
) |
|
(7,831 |
) |
|
Minority
interest in earnings of consolidated subsidiary |
|
|
7,069 |
|
|
(177 |
) |
|
(867 |
) |
|
Net
income before cumulative effect of accounting change |
|
|
55,022 |
|
|
116,366 |
|
|
110,052 |
|
|
Cumulative
effect of implementation of accounting change (net of tax) |
|
|
-- |
|
|
169 |
|
|
-- |
|
|
Net
income |
|
$ |
55,022 |
|
$ |
116,197 |
|
$ |
110,052 |
|
|
Common
shares outstanding weighted average (in thousands) |
|
|
99,470 |
|
|
94,750 |
|
|
88,372 |
|
|
Diluted
shares outstanding weighted average (in thousands) |
|
|
99,911 |
|
|
95,309 |
|
|
88,777 |
|
|
Basic
earnings per common share before cumulative effect of
accounting
change |
|
$ |
0.55 |
|
$ |
1.23 |
|
$ |
1.24 |
|
|
Basic
earnings per common share for cumulative effect of accounting
change |
|
|
-- |
|
|
-- |
|
|
-- |
|
|
Basic
earnings per common share |
|
$ |
0.55 |
|
$ |
1.23 |
|
$ |
1.24 |
|
|
Diluted
earnings per common share before cumulative effect of
accounting
change |
|
$ |
0.55 |
|
$ |
1.22 |
|
$ |
1.24 |
|
|
Diluted
earnings per common share for cumulative effect of accounting
change |
|
|
-- |
|
|
-- |
|
|
-- |
|
|
Diluted
earnings per common share |
|
$ |
0.55 |
|
$ |
1.22 |
|
$ |
1.24 |
|
The
accompanying notes are an integral part of the consolidated financial
statements.
Puget
Energy Consolidated Balance Sheets
|
(DOLLARS
IN THOUSANDS)
AT
DECEMBER 31 |
|
2004 |
|
2003 |
|
Utility
plant: |
|
|
|
|
|
|
Electric
plant |
|
$ |
4,389,882 |
|
$ |
4,265,908 |
|
|
Gas
plant |
|
|
1,881,768 |
|
|
1,749,102 |
|
|
Common
plant |
|
|
409,677 |
|
|
390,622 |
|
|
Less:
Accumulated depreciation and amortization |
|
|
(2,452,969 |
) |
|
(2,325,405 |
) |
|
Net
utility plant |
|
|
4,228,358 |
|
|
4,080,227 |
|
|
Other
property and investments: |
|
|
|
|
|
|
|
|
Goodwill,
net |
|
|
43,503 |
|
|
133,302 |
|
|
Intangibles,
net |
|
|
16,680 |
|
|
18,707 |
|
|
Other |
|
|
257,785 |
|
|
250,084 |
|
|
Total
other property and investments |
|
|
317,968 |
|
|
402,093 |
|
|
Current
assets: |
|
|
|
|
|
|
|
|
Cash |
|
|
19,771 |
|
|
27,481 |
|
|
Restricted
cash |
|
|
1,633 |
|
|
2,537 |
|
|
Accounts
receivable, net of allowance for doubtful accounts |
|
|
216,304 |
|
|
227,115 |
|
|
Unbilled
revenues |
|
|
140,391 |
|
|
131,798 |
|
|
Purchased
gas adjustment receivable |
|
|
19,088 |
|
|
-- |
|
|
Materials
and supplies, at average cost |
|
|
107,356 |
|
|
85,128 |
|
|
Current
portion of unrealized gain on derivative instruments |
|
|
8,087 |
|
|
7,593 |
|
|
Prepayments
and other |
|
|
20,360 |
|
|
12,200 |
|
|
Total
current assets |
|
|
532,990 |
|
|
493,852 |
|
|
Other
long-term assets: |
|
|
|
|
|
|
|
|
Regulatory
asset for deferred income taxes |
|
|
127,252 |
|
|
142,792 |
|
|
Regulatory
asset for PURPA buyout costs |
|
|
211,241 |
|
|
227,753 |
|
|
Unrealized
gain on derivative instruments |
|
|
13,765 |
|
|
8,624 |
|
|
Power
cost adjustment mechanism |
|
|
-- |
|
|
3,605 |
|
|
Other |
|
|
401,795 |
|
|
340,056 |
|
|
Total
other long-term assets |
|
|
754,053 |
|
|
722,830 |
|
|
Total
assets |
|
$ |
5,833,369 |
|
$ |
5,699,002 |
|
The
accompanying notes are an integral part of the consolidated financial
statements.
Puget
Energy Consolidated Balance Sheets
|
(DOLLARS
IN THOUSANDS)
AT
DECEMBER 31 |
|
2004 |
|
2003 |
|
Capitalization: |
|
|
|
|
|
(See
Consolidated Statements of Capitalization ) |
|
|
|
|
|
|
Common
equity |
|
$ |
1,622,276 |
|
$ |
1,655,046 |
|
|
Total
shareholders’ equity |
|
|
1,622,276 |
|
|
1,655,046 |
|
|
Redeemable
securities and long-term debt: |
|
|
|
|
|
|
|
|
Preferred
stock subject to mandatory redemption |
|
|
1,889 |
|
|
1,889 |
|
|
Junior
subordinated debentures of the corporation payable to a subsidiary trust
holding
mandatorily
redeemable preferred securities |
|
|
280,250 |
|
|
280,250 |
|
|
Long-term
debt |
|
|
2,212,532 |
|
|
1,969,489 |
|
|
Total
redeemable securities and long-term debt |
|
|
2,494,671 |
|
|
2,251,628 |
|
|
Total
capitalization |
|
|
4,116,947 |
|
|
3,906,674 |
|
|
Minority
interest in consolidated subsidiary |
|
|
4,648 |
|
|
11,689 |
|
|
Current
liabilities: |
|
|
|
|
|
|
|
|
Accounts
payable |
|
|
239,520 |
|
|
214,357 |
|
|
Short-term
debt |
|
|
8,297 |
|
|
13,893 |
|
|
Current
maturities of long-term debt |
|
|
38,933 |
|
|
246,829 |
|
|
Purchased
gas adjustment liability |
|
|
-- |
|
|
11,984 |
|
|
Accrued
expenses: |
|
|
|
|
|
|
|
|
Taxes |
|
|
77,698 |
|
|
77,451 |
|
|
Salaries
and wages |
|
|
13,829 |
|
|
12,712 |
|
|
Interest |
|
|
29,005 |
|
|
32,954 |
|
|
Current
portion of unrealized loss on derivative instruments |
|
|
19,261 |
|
|
3,636 |
|
|
Tenaska
disallowance reserve |
|
|
3,156 |
|
|
-- |
|
|
Other |
|
|
61,155 |
|
|
46,378 |
|
|
Total
current liabilities |
|
|
490,854 |
|
|
660,194 |
|
|
Long-term
liabilities: |
|
|
|
|
|
|
|
|
Deferred
income taxes |
|
|
810,726 |
|
|
755,235 |
|
|
Long-term
portion of unrealized loss on derivative instruments |
|
|
249 |
|
|
-- |
|
|
Other
deferred credits |
|
|
409,945 |
|
|
365,210 |
|
|
Total
long-term liabilities |
|
|
1,220,920 |
|
|
1,120,445 |
|
|
Commitments
and contingencies |
|
|
|
|
|
|
|
|
Total
capitalization and liabilities |
|
$ |
5,833,369 |
|
$ |
5,699,002 |
|
The
accompanying notes are an integral part of the consolidated financial
statements.
Puget
Energy Consolidated Statements of
(DOLLARS
IN THOUSANDS)
AT
DECEMBER 31 |
|
2004 |
|
2003 |
|
Common
equity: |
|
|
|
|
|
|
Common
stock $0.01 par value, 250,000,000 shares authorized, 99,868,368 and
99,074,070 shares
|
|
$ |
999 |
|
$ |
991 |
|
|
Additional
paid-in capital |
|
|
1,621,756 |
|
|
1,603,901 |
|
|
Earnings
reinvested in the business |
|
|
13,853 |
|
|
58,217 |
|
|
Accumulated
other comprehensive income (loss) -
net of tax |
|
|
(14,332 |
) |
|
(8,063 |
) |
|
Total
common equity |
|
|
1,622,276 |
|
|
1,655,046 |
|
|
Preferred
stock subject to mandatory redemption -
cumulative -
$100 par value: * |
|
|
|
|
|
|
|
|
4.84%
series -150,000
shares authorized,
|
|
|
1,458 |
|
|
1,458 |
|
|
4.70%
series -150,000
shares authorized,
|
|
|
431 |
|
|
431 |
|
|
Total
preferred stock subject to mandatory redemption |
|
|
1,889 |
|
|
1,889 |
|
|
Junior
subordinated debentures of the corporation payable to a subsidiary trust
holding
mandatorily
redeemable preferred securities |
|
|
280,250 |
|
|
280,250 |
|
|
Long-term
debt: |
|
|
|
|
|
|
|
|
First
mortgage bonds and senior notes |
|
|
1,933,500 |
|
|
1,891,158 |
|
|
Pollution
control revenue bonds: |
|
|
|
|
|
|
|
|
Revenue
refunding 2003 series, due 2031 |
|
|
161,860 |
|
|
161,860 |
|
|
Other
notes |
|
|
156,105 |
|
|
163,313 |
|
|
Unamortized
discount -
net of premium |
|
|
-- |
|
|
(13 |
) |
|
Long-term
debt due within one year |
|
|
(38,933 |
) |
|
(246,829 |
) |
|
Total
long-term debt excluding current maturities |
|
|
2,212,532 |
|
|
1,969,489 |
|
|
Total
capitalization |
|
$ |
4,116,947 |
|
$ |
3,906,674 |
|
*
Puget Energy has 50,000,000 shares authorized for $0.01 par value preferred
stock. Puget Sound Energy has 13,000,000 shares authorized for $25 par value
preferred stock and 3,000,000 shares authorized for $100 par value preferred
stock. The preferred stock is available for issuance under mandatory and
non-mandatory redemption provisions.
The
accompanying notes are an integral part of the consolidated financial
statements.
Puget
Energy Consolidated Statements of
| |
|
Common
Stock |
|
|
|
|
|
Accumulated |
|
|
|
|
(DOLLARS
IN THOUSANDS)
FOR YEARS ENDED
|
|
Shares |
|
Amount |
|
Additional
Paid-in
Capital |
|
Retained
Earnings |
|
Other
Comprehensive
Income |
|
Total
Amount |
|
|
|
|
|
87,023,210 |
|
$ |
870 |
|
$ |
1,358,946 |
|
$ |
32,229 |
|
$ |
(29,321 |
) |
$ |
1,362,724 |
|
|
Net
income |
|
|
-- |
|
|
-- |
|
|
-- |
|
|
110,052 |
|
|
-- |
|
|
110,052 |
|
|
Common
stock dividend declared |
|
|
-- |
|
|
-- |
|
|
-- |
|
|
(105,687 |
) |
|
-- |
|
|
(105,687 |
) |
|
Common
stock issued: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
New
issuance |
|
|
5,750,000 |
|
|
57 |
|
|
114,639 |
|
|
-- |
|
|
-- |
|
|
114,696 |
|
|
Dividend
reinvestment plan |
|
|
801,205 |
|
|
8 |
|
|
16,900 |
|
|
-- |
|
|
-- |
|
|
16,908 |
|
|
Employee
plans |
|
|
68,252 |
|
|
1 |
|
|
550 |
|
|
-- |
|
|
-- |
|
|
551 |
|
|
Other |
|
|
(8 |
) |
|
-- |
|
|
(6,420 |
) |
|
(198 |
) |
|
-- |
|
|
(6,618 |
) |
|
Other
comprehensive income |
|
|
-- |
|
|
-- |
|
|
-- |
|
|
-- |
|
|
31,161 |
|
|
31,161 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
93,642,659 |
|
$ |
936 |
|
$ |
1,484,615 |
|
$ |
36,396 |
|
$ |
1,840 |
|
$ |
1,523,787 |
|
|
Net
income |
|
|
-- |
|
|
-- |
|
|
-- |
|
|
116,197 |
|
|
-- |
|
|
116,197 |
|
|
Common
stock dividend declared |
|
|
-- |
|
|
-- |
|
|
-- |
|
|
(93,965 |
) |
|
-- |
|
|
(93,965 |
) |
|
Common
stock issued: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
New
issuance |
|
|
4,650,600 |
|
|
47 |
|
|
102,231 |
|
|
-- |
|
|
-- |
|
|
102,278 |
|
|
Dividend
reinvestment plan |
|
|
721,340 |
|
|
7 |
|
|
15,447 |
|
|
-- |
|
|
-- |
|
|
15,454 |
|
|
Employee
plans |
|
|
59,475 |
|
|
1 |
|
|
1,616 |
|
|
-- |
|
|
-- |
|
|
1,617 |
|
|
Other |
|
|
(4 |
) |
|
-- |
|
|
(8 |
) |
|
(411 |
) |
|
-- |
|
|
(419 |
) |
|
Other
comprehensive loss |
|
|
-- |
|
|
-- |
|
|
-- |
|
|
-- |
|
|
(9,903 |
) |
|
(9,903 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
99,074,070 |
|
$ |
991 |
|
$ |
1,603,901 |
|
$ |
58,217 |
|
$ |
(8,063 |
) |
$ |
1,655,046 |
|
|
Net
income |
|
|
-- |
|
|
-- |
|
|
-- |
|
|
55,022 |
|
|
-- |
|
|
55,022 |
|
|
Common
stock dividend declared |
|
|
-- |
|
|
-- |
|
|
-- |
|
|
(99,386 |
) |
|
-- |
|
|
(99,386 |
) |
|
Common
stock issued: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
New
issuance |
|
|
5,195 |
|
|
-- |
|
|
68 |
|
|
-- |
|
|
-- |
|
|
68 |
|
|
Dividend
reinvestment plan |
|
|
681,491 |
|
|
7 |
|
|
15,170 |
|
|
-- |
|
|
-- |
|
|
15,177 |
|
|
Employee
plans |
|
|
107,612 |
|
|
1 |
|
|
2,617 |
|
|
-- |
|
|
-- |
|
|
2,618 |
|
|
Other
comprehensive loss |
|
|
-- |
|
|
-- |
|
|
-- |
|
|
-- |
|
|
(6,269 |
) |
|
(6,269 |
) |
|
|
|
|
99,868,368 |
|
$ |
999 |
|
$ |
1,621,756 |
|
$ |
13,853 |
|
$ |
(14,332 |
) |
$ |
1,622,276 |
|
Puget
Energy Consolidated Statements of
(DOLLARS
IN THOUSANDS)
FOR YEARS ENDED DECEMBER
31 |
|
2004 |
|
2003 |
|
2002 |
|
|
Net
income |
|
$ |
55,022 |
|
$ |
116,197 |
|
$ |
110,052 |
|
Other
comprehensive income, net of tax: |
|
|
|
|
|
|
|
|
|
|
|
Unrealized
holding losses on marketable securities during the period |
|
|
-- |
|
|
(45 |
) |
|
(1,359 |
) |
|
Reclassification
adjustment for realized gains on marketable securities
included
in net income |
|
|
-- |
|
|
(1,518 |
) |
|
-- |
|
|
Foreign
currency translation adjustment |
|
|
275 |
|
|
80 |
|
|
63 |
|
|
Minimum
pension liability adjustment |
|
|
157 |
|
|
(1,122 |
) |
|
(2,098 |
) |
|
Unrealized
gains on derivative instruments during the period |
|
|
6,820 |
|
|
8,576 |
|
|
2,853 |
|
|
Reversal
of unrealized (gains) losses on derivative instruments settled
during
the period |
|
|
(10,418 |
) |
|
181 |
|
|
31,702 |
|
|
Deferral
related to power cost adjustment mechanism |
|
|
(3,103 |
) |
|
(16,055 |
) |
|
-- |
|
|
Other
comprehensive income (loss) |
|
|
(6,269 |
) |
|
(9,903 |
) |
|
31,161 |
|
|
Comprehensive
income |
|
$ |
48,753 |
|
$ |
106,294 |
|
$ |
141,213 |
|
The
accompanying notes are an integral part of the consolidated financial
statements.
Puget
Energy Consolidated Statements of
(DOLLARS
IN THOUSANDS)
FOR YEARS ENDED DECEMBER
31 |
|
2004 |
|
2003 |
|
2002 |
|
Operating
activities: |
|
|
|
|
|
|
|
|
Net
income |
|
$ |
55,022 |
|
$ |
116,197 |
|
$ |
110,052 |
|
|
Adjustments
to reconcile net income to net cash provided by operating
activities: |
|
|
|
|
|
|
|
|
|
|
|
Depreciation
and amortization |
|
|
246,842 |
|
|
236,866 |
|
|
228,743 |
|
|
Deferred
income taxes and tax credits -
net |
|
|
72,702 |
|
|
57,470 |
|
|
151,318 |
|
|
Gain
from sale of securities |
|
|
-- |
|
|
(2,889 |
) |
|
-- |
|
|
Net
unrealized (gains) losses on derivative instruments |
|
|
(526 |
) |
|
106 |
|
|
(11,612 |
) |
|
Other
(including conservation amortization) |
|
|
10,103 |
|
|
18,683 |
|
|
(18,827 |
) |
|
Cash
collateral received from (returned to) energy supplier |
|
|
6,320 |
|
|
(21,425 |
) |
|
21,425 |
|
|
Increase
(decrease) in residential exchange program |
|
|
1,668 |
|
|
(25,989 |
) |
|
21,201 |
|
|
Goodwill
impairment |
|
|
91,196 |
|
|
-- |
|
|
-- |
|
|
Pension
plan funding |
|
|
-- |
|
|
(26,521 |
) |
|
-- |
|
|
Change
in certain current assets and liabilities: |
|
|
|
|
|
|
|
|
|
|
|
Accounts
receivable and unbilled revenue |
|
|
2,218 |
|
|
37,769 |
|
|
46,860 |
|
|
Materials
and supplies |
|
|
(22,228 |
) |
|
(14,727 |
) |
|
22,088 |
|
|
Prepayments
and other |
|
|
(8,159 |
) |
|
(738 |
) |
|
141 |
|
|
Purchased
gas receivable /liability |
|
|
(31,073 |
) |
|
(71,826 |
) |
|
121,039 |
|
|
Accounts
payable |
|
|
25,163 |
|
|
6,464 |
|
|
34,351 |
|
|
Taxes
payable |
|
|
247 |
|
|
13,405 |
|
|
(18,260 |
) |
|
Tenaska
disallowance reserve |
|
|
3,156 |
|
|
-- |
|
|
-- |
|
|
Accrued
expenses and other |
|
|
3,709 |
|
|
(4,939 |
) |
|
(4,603 |
) |
|
Net
cash provided by operating activities |
|
|
456,360 |
|
|
317,906 |
|
|
703,916 |
|
|
Investing
activities: |
|
|
|
|
|
|
|
|
|
|
|
Construction
and capital expenditures -
excluding equity AFUDC |
|
|
(409,403 |
) |
|
(285,510 |
) |
|
(235,786 |
) |
|
Energy
efficiency expenditures |
|
|
(24,852 |
) |
|
(18,579 |
) |
|
(11,356 |
) |
|
Restricted
cash |
|
|
905 |
|
|
20,106 |
|
|
(18,871 |
) |
|
Cash
received from sale of securities |
|
|
-- |
|
|
3,161 |
|
|
-- |
|
|
Refundable
cash received for customer construction projects |
|
|
13,424 |
|
|
5,045 |
|
|
5,787 |
|
|
Investments
by InfrastruX |
|
|
-- |
|
|
(10,659 |
) |
|
(41,602 |
) |
|
Other |
|
|
1,747 |
|
|
2,151 |
|
|
(15,761 |
) |
|
Net
cash used by investing activities |
|
|
(418,179 |
) |
|
(284,285 |
) |
|
(317,589 |
) |
|
Financing
activities: |
|
|
|
|
|
|
|
|
|
|
|
Decrease
in short-term debt -
net |
|
|
(5,596 |
) |
|
(33,402 |
) |
|
(301,281 |
) |
|
Dividends
paid |
|
|
(86,873 |
) |
|
(86,671 |
) |
|
(97,321 |
) |
|
Issuance
of common stock |
|
|
5,413 |
|
|
106,659 |
|
|
120,214 |
|
|
Issuance
of bonds and notes |
|
|
343,841 |
|
|
319,497 |
|
|
107,518 |
|
|
Redemption
of preferred stock |
|
|
-- |
|
|
(60,000 |
) |
|
-- |
|
|
Redemption
of mandatorily redeemable preferred stock |
|
|
-- |
|
|
(41,273 |
) |
|
(7,500 |
) |
|
Redemption
of trust preferred stock |
|
|
-- |
|
|
(19,750 |
) |
|
-- |
|
|
Redemption
of bonds and notes |
|
|
(308,708 |
) |
|
(357,510 |
) |
|
(119,281 |
) |
|
Other |
|
|
6,032 |
|
|
(10,359 |
) |
|
(4,363 |
) |
|
Net
cash used by financing activities |
|
|
(45,891 |
) |
|
(182,809 |
) |
|
(302,014 |
) |
|
Increase
(decrease) in cash from net income |
|
|
(7,710 |
) |
|
(149,188 |
) |
|
84,313 |
|
|
Cash
at beginning of year |
|
|
27,481 |
|
|
176,669 |
|
|
92,356 |
|
|
Cash
at end of year |
|
$ |
19,771 |
|
$ |
27,481 |
|
$ |
176,669 |
|
Supplemental
Cash Flow Information: |
|
|
|
|
|
|
|
|
|
|
|
Cash
payments for: |
|
|
|
|
|
|
|
|
|
|
|
Interest
(net of capitalized interest) |
|
$ |
182,419 |
|
$ |
192,845 |
|
$ |
200,392 |
|
|
Income
taxes (net refunds) |
|
|
(1,232 |
) |
|
(2,777 |
) |
|
(81,652 |
) |
The
accompanying notes are an integral part of the consolidated financial
statements.
Puget
Sound Energy Consolidated Statements of
(DOLLARS
IN THOUSANDS)
FOR YEARS ENDED DECEMBER
31 |
|
2004 |
|
2003 |
|
2002 |
|
Operating
revenues: |
|
|
|
|
|
|
|
|
Electric |
|
$ |
1,423,034 |
|
$ |
1,400,743 |
|
$ |
1,288,744 |
|
|
Gas |
|
|
769,306 |
|
|
634,230 |
|
|
697,155 |
|
|
Other |
|
|
6,537 |
|
|
6,043 |
|
|
9,753 |
|
|
Total
operating revenues |
|
|
2,198,877 |
|
|
2,041,016 |
|
|
1,995,652 |
|
|
Operating
expenses: |
|
|
|
|
|
|
|
|
|
|
|
Energy
costs: |
|
|
|
|
|
|
|
|
|
|
|
Purchased
electricity |
|
|
723,567 |
|
|
714,469 |
|
|
568,230 |
|
|
Electric
generation fuel |
|
|
80,772 |
|
|
64,999 |
|
|
113,538 |
|
|
Residential
exchange |
|
|
(174,473 |
) |
|
(173,840 |
) |
|
(149,970 |
) |
|
Purchased
gas |
|
|
451,302 |
|
|
327,132 |
|
|
405,016 |
|
|
Unrealized
(gain) loss on derivative instruments |
|
|
(526 |
) |
|
106 |
|
|
(11,612 |
) |
|
Utility
operations and maintenance |
|
|
291,232 |
|
|
289,702 |
|
|
286,220 |
|
|
Other
operations and maintenance |
|
|
1,342 |
|
|
1,203 |
|
|
1,602 |
|
|
Depreciation
and amortization |
|
|
228,566 |
|
|
220,087 |
|
|
215,317 |
|
|
Conservation
amortization |
|
|
22,688 |
|
|
33,458 |
|
|
17,501 |
|
|
Taxes
other than income taxes |
|
|
208,989 |
|
|
194,857 |
|
|
202,381 |
|
|
Income
taxes |
|
|
77,177 |
|
|
70,939 |
|
|
52,836 |
|
|
Total
operating expenses |
|
|
1,910,636 |
|
|
1,743,112 |
|
|
1,701,059 |
|
|
Operating
income |
|
|
288,241 |
|
|
297,904 |
|
|
294,593 |
|
|
Other
income (deductions): |
|
|
|
|
|
|
|
|
|
|
|
Other
income |
|
|
4,362 |
|
|
1,587 |
|
|
5,215 |
|
|
Interest
charges: |
|
|
|
|
|
|
|
|
|
|
|
AFUDC |
|
|
5,420 |
|
|
3,343 |
|
|
1,969 |
|
|
Interest
expense |
|
|
(171,740 |
) |
|
(181,707 |
) |
|
(192,829 |
) |
|
Mandatorily
redeemable securities interest expense |
|
|
(91 |
) |
|
(1,072 |
) |
|
-- |
|
|
Net
income before cumulative effect of accounting change |
|
|
126,192 |
|
|
120,055 |
|
|
108,948 |
|
|
Cumulative
effect of implementation of accounting change (net of tax) |
|
|
-- |
|
|
169 |
|
|
-- |
|
|
Net
income |
|
|
126,192 |
|
|
119,886 |
|
|
108,948 |
|
|
Less:
preferred stock dividends accrual |
|
|
-- |
|
|
5,151 |
|
|
7,831 |
|
|
Income
for common stock |
|
$ |
126,192 |
|
$ |
114,735 |
|
$ |
101,117 |
|
The
accompanying notes are an integral part of the consolidated financial
statements.
Puget
Sound Energy Consolidated Balance Sheets
(DOLLARS
IN THOUSANDS)
AT DECEMBER
31 |
|
2004 |
|
2003 |
|
Utility
plant: |
|
|
|
|
|
|
Electric
plant |
|
$ |
4,389,882 |
|
$ |
4,265,908 |
|
|
Gas
plant |
|
|
1,881,768 |
|
|
1,749,102 |
|
|
Common
plant |
|
|
409,677 |
|
|
390,622 |
|
|
Less:
Accumulated depreciation and amortization |
|
|
(2,452,969 |
) |
|
(2,325,405 |
) |
|
Net
utility plant |
|
|
4,228,358 |
|
|
4,080,227 |
|
|
Other
property and investments |
|
|
157,670 |
|
|
160,280 |
|
|
Current
assets: |
|
|
|
|
|
|
|
|
Cash |
|
|
12,955 |
|
|
14,778 |
|
|
Restricted
cash |
|
|
1,633 |
|
|
2,537 |
|
|
Accounts
receivable, net of allowance for doubtful accounts |
|
|
138,792 |
|
|
155,649 |
|
|
Unbilled
revenues |
|
|
140,391 |
|
|
131,798 |
|
|
Purchased
gas adjustment receivable |
|
|
19,088 |
|
|
-- |
|
|
Materials
and supplies, at average cost |
|
|
97,578 |
|
|
77,206 |
|
|
Current
portion of unrealized gain on derivative instruments |
|
|
8,087 |
|
|
7,593 |
|
|
Prepayments
and other |
|
|
6,247 |
|
|
6,285 |
|
|
Total
current assets |
|
|
424,771 |
|
|
395,846 |
|
|
Other
long-term assets: |
|
|
|
|
|
|
|
|
Regulatory
asset for deferred income taxes |
|
|
127,252 |
|
|
142,792 |
|
|
Regulatory
asset for PURPA buyout costs |
|
|
211,241 |
|
|
227,753 |
|
|
Unrealized
gain on derivative instruments |
|
|
13,765 |
|
|
8,624 |
|
|
Power
cost adjustment mechanism |
|
|
-- |
|
|
3,605 |
|
|
Other |
|
|
401,030 |
|
|
339,977 |
|
|
Total
other long-term assets |
|
|
753,288 |
|
|
722,751 |
|
|
Total
assets |
|
$ |
5,564,087 |
|
$ |
5,359,104 |
|
The
accompanying notes are an integral part of the consolidated financial
statements.
Puget
Sound Energy Consolidated Balance Sheets
(DOLLARS
IN THOUSANDS)
AT DECEMBER
31 |
|
2004 |
|
2003 |
|
Capitalization: |
|
|
|
|
|
(See
Consolidated Statements of Capitalization): |
|
|
|
|
|
|
Common
equity |
|
$ |
1,592,433 |
|
$ |
1,555,469 |
|
|
Total
shareholders’ equity |
|
|
1,592,433 |
|
|
1,555,469 |
|
|
Redeemable
securities and long-term debt: |
|
|
|
|
|
|
|
|
Preferred
stock subject to mandatory redemption |
|
|
1,889 |
|
|
1,889 |
|
|
Junior
subordinated debentures of the corporation payable to a subsidiary trust
holding
mandatorily
redeemable preferred securities |
|
|
280,250 |
|
|
280,250 |
|
|
Long-term
debt |
|
|
2,064,360 |
|
|
1,950,347 |
|
|
Total
redeemable securities and long-term debt |
|
|
2,346,499 |
|
|
2,232,486 |
|
|
Total
capitalization |
|
|
3,938,932 |
|
|
3,787,955 |
|
|
Current
liabilities: |
|
|
|
|
|
|
|
|
Accounts
payable |
|
|
229,747 |
|
|
206,465 |
|
|
Current
maturities of long-term debt |
|
|
31,000 |
|
|
102,658 |
|
|
Purchased
gas adjustment liability |
|
|
-- |
|
|
11,984 |
|
|
Accrued
expenses: |
|
|
|
|
|
|
|
|
Taxes |
|
|
81,634 |
|
|
82,342 |
|
|
Salaries
and wages |
|
|
13,829 |
|
|
12,712 |
|
|
Interest |
|
|
29,005 |
|
|
32,954 |
|
|
Current
portion of unrealized loss on derivative instruments |
|
|
19,261 |
|
|
3,636 |
|
|
Tenaska
disallowance reserve |
|
|
3,156 |
|
|
-- |
|
|
Other |
|
|
34,918 |
|
|
26,514 |
|
|
Total
current liabilities |
|
|
442,550 |
|
|
479,265 |
|
|
Long-term
liabilities: |
|
|
|
|
|
|
|
|
Deferred
income taxes |
|
|
787,179 |
|
|
731,944 |
|
|
Long-term
portion of unrealized loss on derivative instruments |
|
|
249 |
|
|
-- |
|
|
Other
deferred credits |
|
|
395,177 |
|
|
359,940 |
|
|
Total
long-term liabilities |
|
|
1,182,605 |
|
|
1,091,884 |
|
|
Commitments
and contingencies |
|
|
|
|
|
|
|
|
Total
capitalization and liabilities |
|
$ |
5,564,087 |
|
$ |
5,359,104 |
|
The
accompanying notes are an integral part of the consolidated financial
statements
Puget
Sound Energy Consolidated Statements of
|
(DOLLARS
IN THOUSANDS)
AT
DECEMBER 31 |
|
2004 |
|
2003 |
|
Common
equity: |
|
|
|
|
|
|
Common
stock ($10 stated value) -
150,000,000 shares authorized, 85,903,791 shares
outstanding. |
|
$ |
859,038 |
|
$ |
859,038 |
|
|
Additional
paid-in capital |
|
|
609,467 |
|
|
604,451 |
|
|
Earnings
reinvested in the business |
|
|
138,678 |
|
|
100,186 |
|
|
Accumulated
other comprehensive income (loss) - net of tax |
|
|
(14,750 |
) |
|
(8,206 |
) |
|
Total
common equity |
|
|
1,592,433 |
|
|
1,555,469 |
|
|
Preferred
stock subject to mandatory redemption - cumulative
$100
par value:* |
|
|
|
|
|
|
|
|
4.84%
series -
150,000 shares authorized,
|
|
|
1,458 |
|
|
1,458 |
|
|
4.70%
series -
150,000 shares authorized,
|
|
|
431 |
|
|
431 |
|
|
Total
preferred stock subject to mandatory redemption |
|
|
1,889 |
|
|
1,889 |
|
|
Junior
subordinated debentures of the corporation payable to a subsidiary trust
holding
mandatorily
redeemable preferred securities |
|
|
280,250 |
|
|
280,250 |
|
|
Long-term
debt: |
|
|
|
|
|
|
|
|
First
mortgage bonds and senior notes |
|
|
1,933,500 |
|
|
1,891,158 |
|
|
Pollution
control revenue bonds: |
|
|
|
|
|
|
|
|
Revenue
refunding 2003 series, due 2031 |
|
|
161,860 |
|
|
161,860 |
|
|
Unamortized
discount -
net of premium |
|
|
-- |
|
|
(13 |
) |
|
Long-term
debt due within one year |
|
|
(31,000 |
) |
|
(102,658 |
) |
|
Total
long-term debt excluding current maturities |
|
|
2,064,360 |
|
|
1,950,347 |
|
|
Total
capitalization |
|
$ |
3,938,932 |
|
$ |
3,787,955 |
|
*13,000,000
shares authorized for $25 par value preferred stock and 3,000,000 shares
authorized for $100 par value preferred stock, both of which are available for
issuance under mandatory and non-mandatory redemption
provisions.
The
accompanying notes are an integral part of the consolidated financial
statements.
Puget
Sound Energy Consolidated Statements of
|
(DOLLARS
IN THOUSANDS) |
|
Common
Stock |
|
Additional |
|
|
|
Accumulated
Other |
|
|
|
|
FOR
YEARS ENDED
|
|
Shares |
|
Amount |
|
Paid-in
Capital |
|
Retained
Earnings |
|
Comprehensive
Income |
|
Total
Amount |
|
|
|
|
|
85,903,791 |
|
$ |
859,038 |
|
$ |
382,592 |
|
$ |
55,345 |
|
$ |
(29,321 |
) |
$ |
1,267,654 |
|
|
Net
income |
|
|
-- |
|
|
-- |
|
|
-- |
|
|
108,948 |
|
|
-- |
|
|
108,948 |
|
|
Preferred
stock dividend declared |
|
|
-- |
|
|
-- |
|
|
-- |
|
|
(7,904 |
) |
|
-- |
|
|
(7,904 |
) |
|
Common
stock dividend declared |
|
|
-- |
|
|
-- |
|
|
-- |
|
|
(89,418 |
) |
|
-- |
|
|
(89,418 |
) |
|
Investment
received from Puget Energy |
|
|
-- |
|
|
-- |
|
|
115,736 |
|
|
-- |
|
|
-- |
|
|
115,736 |
|
|
Other |
|
|
-- |
|
|
-- |
|
|
7 |
|
|
-- |
|
|
-- |
|
|
7 |
|
|
Other
comprehensive income |
|
|
-- |
|
|
-- |
|
|
-- |
|
|
-- |
|
|
31,098 |
|
|
31,098 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
85,903,791 |
|
$ |
859,038 |
|
$ |
498,335 |
|
$ |
66,971 |
|
$ |
1,777 |
|
$ |
1,426,121 |
|
|
Net
income |
|
|
-- |
|
|
-- |
|
|
-- |
|
|
119,886 |
|
|
-- |
|
|
119,886 |
|
|
Preferred
stock dividend declared |
|
|
-- |
|
|
-- |
|
|
-- |
|
|
(5,562 |
) |
|
-- |
|
|
(5,562 |
) |
|
Common
stock dividend declared |
|
|
-- |
|
|
-- |
|
|
-- |
|
|
(81,109 |
) |
|
-- |
|
|
(81,109 |
) |
|
Investment
received from Puget Energy |
|
|
-- |
|
|
-- |
|
|
106,124 |
|
|
-- |
|
|
-- |
|
|
106,124 |
|
|
Other |
|
|
-- |
|
|
-- |
|
|
(8 |
) |
|
-- |
|
|
-- |
|
|
(8 |
) |
|
Other
comprehensive loss |
|
|
-- |
|
|
-- |
|
|
-- |
|
|
-- |
|
|
(9,983 |
) |
|
(9,983 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
85,903,791 |
|
$ |
859,038 |
|
$ |
604,451 |
|
$ |
100,186 |
|
$ |
(8,206 |
) |
$ |
1,555,469 |
|
|
Net
income |
|
|
-- |
|
|
-- |
|
|
-- |
|
|
126,192 |
|
|
-- |
|
|
126,192 |
|
|
Common
stock dividend declared |
|
|
-- |
|
|
-- |
|
|
-- |
|
|
(87,700 |
) |
|
-- |
|
|
(87,700 |
) |
|
Investment
received from Puget Energy |
|
|
-- |
|
|
-- |
|
|
5,016 |
|
|
-- |
|
|
-- |
|
|
5,016 |
|
|
Other
comprehensive loss |
|
|
-- |
|
|
-- |
|
|
-- |
|
|
-- |
|
|
(6,544 |
) |
|
(6,544 |
) |
|
|
|
|
85,903,791 |
|
$ |
859,038 |
|
$ |
609,467 |
|
$ |
138,678 |
|
$ |
(14,750 |
) |
$ |
1,592,433 |
|
Puget
Sound Energy Consolidated Statements of
|
(DOLLARS
IN THOUSANDS)
FOR
YEARS ENDED DECEMBER 31 |
|
2004 |
|
2003 |
|
2002 |
|
|
Net
income |
|
$ |
126,192 |
|
$ |
119,886 |
|
$ |
108,948 |
|
|
Other
comprehensive income, net of tax: |
|
|
|
|
|
|
|
|
|
|
|
Unrealized
holding losses on marketable securities during the period |
|
|
-- |
|
|
(45 |
) |
|
(1,359 |
) |
|
Reclassification
adjustment for realized gains on marketable securities
included
in net income |
|
|
-- |
|
|
(1,518 |
) |
|
-- |
|
|
Minimum
pension liability adjustment |
|
|
157 |
|
|
(1,122 |
) |
|
(2,098 |
) |
|
Unrealized
gains on derivative instruments during the period |
|
|
6,820 |
|
|
8,576 |
|
|
2,853 |
|
|
Reversal
of unrealized (gains) losses on derivative instruments settled
during
the period |
|
|
(10,418 |
) |
|
181 |
|
|
31,702 |
|
|
Deferral
related to power cost adjustment mechanism |
|
|
(3,103 |
) |
|
(16,055 |
) |
|
-- |
|
|
Other
comprehensive income (loss) |
|
|
(6,544 |
) |
|
(9,983 |
) |
|
31,098 |
|
|
Comprehensive
income |
|
$ |
119,648 |
|
$ |
109,903 |
|
$ |
140,046 |
|
The
accompanying notes are an integral part of the consolidated financial
statements.
Puget
Sound Energy Consolidated Statements of
|
(DOLLARS
IN THOUSANDS
FOR
YEARS ENDED DECEMBER 31 |
|
2004 |
|
2003 |
|
2002 |
|
Operating
activities: |
|
|
|
|
|
|
|
|
Net
income |
|
$ |
126,192 |
|
$ |
119,886 |
|
$ |
108,948 |
|
|
Adjustments
to reconcile net income to net cash provided by
operating
activities: |
|
|
|
|
|
|
|
|
|
|
|
Depreciation
and amortization |
|
|
228,566 |
|
|
220,087 |
|
|
215,317 |
|
|
Deferred
federal income taxes and tax credits -
net |
|
|
72,446 |
|
|
49,276 |
|
|
140,536 |
|
|
Gain
from sale of securities |
|
|
-- |
|
|
(2,889 |
) |
|
-- |
|
|
Net
unrealized (gain) loss on derivative instruments |
|
|
(526 |
) |
|
106 |
|
|
(11,612 |
) |
|
Other
(including conservation amortization) |
|
|
20,806 |
|
|
14,591 |
|
|
(8,277 |
) |
|
Cash
collateral received from (returned to) energy suppliers |
|
|
6,320 |
|
|
(21,425 |
) |
|
21,425 |
|
|
Increase
(decrease) in Residential Exchange Program |
|
|
1,668 |
|
|
(25,989 |
) |
|
21,201 |
|
|
Pension
plan funding |
|
|
-- |
|
|
(26,521 |
) |
|
-- |
|
|
Change
in certain current assets and current liabilities: |
|
|
|
|
|
|
|
|
|
|
|
Accounts
receivable and unbilled revenue |
|
|
8,264 |
|
|
33,370 |
|
|
61,539 |
|
|
Materials
and supplies |
|
|
(20,372 |
) |
|
(13,643 |
) |
|
21,755 |
|
|
Prepayments
and other |
|
|
38 |
|
|
2,622 |
|
|
(1,501 |
) |
|
Purchased
gas receivable / liability |
|
|
(31,073 |
) |
|
(71,826 |
) |
|
121,039 |
|
|
Accounts
payable |
|
|
23,282 |
|
|
12,863 |
|
|
38,893 |
|
|
Taxes
payable |
|
|
(707 |
) |
|
17,910 |
|
|
(13,646 |
) |
|
Tenaska
disallowance reserve |
|
|
3,156 |
|
|
-- |
|
|
-- |
|
|
Accrued
expenses and other |
|
|
(2,664 |
) |
|
(4,120 |
) |
|
277 |
|
|
Net
cash provided by operating activities |
|
|
435,396 |
|
|
304,298 |
|
|
715,894 |
|
|
Investing
activities: |
|
|
|
|
|
|
|
|
|
|
|
Construction
expenditures -
excluding equity AFUDC |
|
|
(393,891 |
) |
|
(269,973 |
) |
|
(224,165 |
) |
|
Energy
efficiency expenditures |
|
|
(24,852 |
) |
|
(18,579 |
) |
|
(11,356 |
) |
|
Restricted
cash |
|
|
905 |
|
|
20,106 |
|
|
(18,871 |
) |
|
Cash
received from sale of securities |
|
|
-- |
|
|
3,161 |
|
|
-- |
|
|
Refundable
cash received for customer construction projects |
|
|
13,424 |
|
|
5,045 |
|
|
5,787 |
|
|
Other |
|
|
1,444 |
|
|
3,671 |
|
|
(14,472 |
) |
|
Net
cash used by investing activities |
|
|
(402,970 |
) |
|
(256,569 |
) |
|
(263,077 |
) |
|
Financing
activities: |
|
|
|
|
|
|
|
|
|
|
|
Decrease
in short-term debt -
net |
|
|
-- |
|
|
(30,340 |
) |
|
(307,828 |
) |
|
Dividends
paid |
|
|
(87,700 |
) |
|
(86,671 |
) |
|
(97,321 |
) |
|
Issuance
of bonds and notes |
|
|
200,000 |
|
|
304,465 |
|
|
40,000 |
|
|
Redemption
of preferred stock |
|
|
-- |
|
|
(60,000 |
) |
|
-- |
|
|
Redemption
of mandatorily redeemable preferred stock |
|
|
-- |
|
|
(41,273 |
) |
|
(7,500 |
) |
|
Redemption
of trust preferred stock |
|
|
-- |
|
|
(19,750 |
) |
|
-- |
|
|
Redemption
of bonds and notes |
|
|
(157,658 |
) |
|
(356,860 |
) |
|
(117,000 |
) |
|
Investment
from Puget Energy |
|
|
5,016 |
|
|
106,124 |
|
|
115,736 |
|
|
Other |
|
|
6,093 |
|
|
(10,121 |
) |
|
(137 |
) |
|
Net
cash used by financing activities |
|
|
(34,249 |
) |
|
(194,426 |
) |
|
(374,050 |
) |
|
Increase
(decrease) in cash from net income |
|
|
(1,823 |
) |
|
(146,697 |
) |
|
78,767 |
|
|
Cash
at beginning of year |
|
|
14,778 |
|
|
161,475 |
|
|
82,708 |
|
|
Cash
at end of year |
|
$ |
12,955 |
|
$ |
14,778 |
|
$ |
161,475 |
|
Supplemental
Cash Flow Information: |
|
|
|
|
|
|
|
|
|
|
|
Cash
payments for: |
|
|
|
|
|
|
|
|
|
|
|
Interest
(net of capitalized interest) |
|
$ |
175,772 |
|
$ |
187,256 |
|
$ |
194,876 |
|
|
Income
taxes (net refunds) |
|
|
(1,042 |
) |
|
(1,456 |
) |
|
(81,973 |
) |
The
accompanying notes are an integral part of the consolidated financial
statements.
To
Consolidated Financial Statements of Puget Energy and Puget Sound
Energy
NOTE 1.
Summary
of Significant Accounting Policies
BASIS OF
PRESENTATION
Puget
Energy is an exempt public utility holding company under the Public Utility
Holding Company Act of 1935. Puget Energy owns Puget Sound Energy (PSE) and has
a 90.9% ownership interest in InfrastruX Group, Inc. (InfrastruX). PSE is a
public utility incorporated in the State of Washington and furnishes electric
and gas services in a territory covering 6,000 square miles, primarily in the
Puget Sound region. InfrastruX is a non-regulated construction service company
incorporated in the State of Washington, which provides construction services to
the electric and gas utility industries primarily in the Midwest, Texas,
south-central and eastern United States regions.
The
consolidated financial statements of Puget Energy include the accounts of Puget
Energy and its subsidiaries, PSE and InfrastruX. Puget Energy holds all the
common shares of PSE and holds a 90.9% interest in InfrastruX. The results of
PSE and InfrastruX are presented on a consolidated basis. PSE’s consolidated
financial statements include the accounts of PSE and its subsidiaries. Puget
Energy and PSE are collectively referred to herein as “the Company.” The
consolidated financial statements are presented after elimination of all
significant intercompany items and transactions. Minority interests of
InfrastruX’s operating results are reflected in Puget Energy’s consolidated
financial statements. Certain amounts previously reported have been reclassified
to conform with current year presentations with no effect on total equity or net
income.
The
preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities, and disclosure of
contingent 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.
UTILITY
PLANT
The cost
of additions to utility plant, including renewals and betterments, are
capitalized at original cost. Costs include indirect costs such as engineering,
supervision, certain taxes, pension and other employee benefits, and an
allowance for funds used during construction. Replacements of minor items of
property are included in maintenance expense. The original cost of operating
property is charged to accumulated depreciation and costs associated with
removal of property, less salvage, is charged to the cost of removal regulatory
liability when the property is retired and removed from service.
NON-UTILITY
PROPERTY, PLANT AND EQUIPMENT
The costs
of other property, plant and equipment are stated at cost. Expenditures for
refurbishment and improvements that significantly add to productive capacity or
extend useful life of an asset are capitalized. Replacement of minor items is
expensed, on a current basis. Gains and losses on assets sold or retired are
reflected in earnings.
ACCOUNTING
FOR THE IMPAIRMENT OF LONG-LIVED ASSETS
The
Company evaluates impairment of long-lived assets in accordance with SFAS No.
144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” SFAS No.
144 establishes accounting standards for determining if long-lived assets are
impaired and how losses, if any, should be recognized. The Company believes that
the net cash flows are sufficient to cover the carrying value of its
assets.
DEPRECIATION
AND AMORTIZATION
For
financial statement purposes, the Company provides for depreciation and
amortization on a straight-line basis. Amortization is comprised of software,
small tools and office equipment. The depreciation of automobiles, trucks,
power-operated equipment and tools is allocated to asset and expense accounts
based on usage. The annual depreciation provision stated as a percent of average
original cost of depreciable electric utility plant was 2.9% in 2004, 2003 and
2002; depreciable gas utility plant was 3.4% in 2004, 3.5% in 2003 and 3.3% in
2002; and depreciable common utility plant was 4.6% in 2004, 4.7% in 2003 and
4.3% in 2002. Depreciation on other property, plant and equipment is calculated
primarily on a straight-line basis over the useful lives of the
assets.
CASH
All
liquid investments with maturities of three months or less at the date of
purchase are considered cash. The Company maintains cash deposits in excess of
insured limits with certain financial institutions.
RESTRICTED
CASH
Restricted
cash represents cash to be used for specific purposes. The restricted cash
balance was $1.6 million at December 31, 2004. Approximately $1.1 million in
restricted cash represents funds held by Puget Western, Inc., a PSE subsidiary,
for a real estate development project. Approximately $0.4 million represents
funds held for payment of principal and interest for conservation trust debt and
approximately $0.1 million represents payments from the Bonneville Power
Administration under the Residential and Farm Energy Exchange Benefit Credit
program in excess of credits provided to customers.
MATERIAL
AND SUPPLIES
Material
and supplies consists primarily of materials and supplies used in the operation
and maintenance of the electric and gas systems, coal, diesel and natural gas
held for generation, and natural gas and liquefied natural gas held in storage
for future sales. These items are recorded at the lower of cost or market value,
primarily using the weighted average cost method.
REGULATORY
ASSETS AND LIABILITIES
The
Company accounts for its regulated operations in accordance with SFAS No. 71,
“Accounting for the Effects of Certain Types of Regulation.” SFAS No. 71
requires the Company to defer certain costs that would otherwise be charged to
expense, if it is probable that future rates will permit recovery of such costs.
Accounting under SFAS No. 71 is appropriate as long as rates are established by
or subject to approval by independent third-party regulators; rates are designed
to recover the specific enterprise’s cost of service; and in view of demand for
service, it is reasonable to assume that rates set at levels that will recover
costs can be charged to and collected from customers.
The
Company is allowed a return on the net regulatory assets and liabilities of
8.75% for electric rates beginning July 1, 2002 and gas rates beginning
September 1, 2002. The 2001 allowed rate of return was 8.94% for electric rates
and 9.15% for gas rates. The net regulatory assets and liabilities at December
31, 2004 and 2003 included the following:
|
(DOLLARS
IN MILLIONS) |
|
REMAINING
AMORTIZATION
PERIOD |
|
2004 |
|
2003 |
|
|
PURPA
electric energy supply contract buyout costs |
|
|
4
to 7 years |
|
$ |
211.2 |
|
$ |
227.8 |
|
|
Deferred
income taxes |
|
|
*** |
|
|
127.3 |
|
|
142.8 |
|
|
White
River relicensing and other costs |
|
|
* |
|
|
65.3 |
|
|
20.8 |
|
|
Investment
in Bonneville Exchange Power contract |
|
|
12
years |
|
|
44.1 |
|
|
47.6 |
|
|
Environmental
remediation |
|
|
* |
|
|
42.3 |
|
|
41.6 |
|
|
Deferred
AFUDC |
|
|
30
years |
|
|
30.4 |
|
|
30.3 |
|
|
Tree
watch costs |
|
|
10
years |
|
|
28.3 |
|
|
29.0 |
|
|
Storm
damage costs -
electric |
|
|
3.5
years |
|
|
21.1 |
|
|
26.0 |
|
|
Purchased
Gas Adjustment (PGA) receivable |
|
|
* |
|
|
19.1 |
|
|
-- |
|
|
Colstrip
common property |
|
|
19
years |
|
|
13.9 |
|
|
14.6 |
|
|
PGA
deferral of unrealized losses on derivative instruments |
|
|
*** |
|
|
12.1 |
|
|
3.3 |
|
|
Various
other regulatory assets |
|
|
1
to 26 years |
|
|
30.2 |
|
|
23.1 |
|
|
Power
Cost Adjustment (PCA) mechanism |
|
|
* |
|
|
-- |
|
|
3.6 |
|
|
Cost
of removal |
|
|
** |
|
|
(132.4 |
) |
|
(124.9 |
) |
|
PCA
deferral of unrealized gain on derivative instrument |
|
|
* |
|
|
(30.8 |
) |
|
(24.3 |
) |
|
Gas
Supply contract settlement |
|
|
3.5
year |
|
|
(10.1 |
) |
|
-- |
|
|
Deferred
gains on property sales |
|
|
3
years |
|
|
(4.5 |
) |
|
(10.1 |
) |
|
Tenaska
disallowance reserve |
|
|
1
year |
|
|
(3.2 |
) |
|
-- |
|
|
Purchased
Gas Adjustment payable |
|
|
*** |
|
|
-- |
|
|
(12.0 |
) |
|
Various
other regulatory liabilities |
|
|
1
to 22 years |
|
|
(4.7 |
) |
|
(5.4 |
) |
|
Net
regulatory assets and liabilities |
|
|
|
|
$ |
459.6 |
|
$ |
433.8 |
|
* Amortization
period to be determined.
** The
balance is dependent upon the cost of removal of underlying assets and the life
of utility plant.
*** Amortization
period varies depending on timing of underlying transactions.
If the
Company, at some point in the future, determines that all or a portion of the
utility operations no longer meet the criteria for continued application of SFAS
No. 71, the Company would be required to adopt the provisions of SFAS No. 101,
“Regulated Enterprises - Accounting for the Discontinuation of Application of
FASB Statement No. 71.” Adoption of SFAS No. 101 would require the Company to
write off the regulatory assets and liabilities related to those operations not
meeting SFAS No. 71 requirements. Discontinuation of SFAS No. 71 could have a
material impact on the Company’s financial statements.
In
accordance with guidance provided by the Securities and Exchange Commission, the
Company reclassified from accumulated depreciation to a regulatory liability
$132.4 million and $124.9 million in 2004 and 2003, respectively, for cost of
removal for utility plant. These amounts are collected from PSE’s customers
through depreciation rates.
ALLOWANCE
FOR FUNDS USED DURING CONSTRUCTION
The
Allowance for Funds Used During Construction (AFUDC) represents the cost of both
the debt and equity funds used to finance utility plant additions during the
construction period. The amount of AFUDC recorded in each accounting period
varies depending principally upon the level of construction work in progress and
the AFUDC rate used. AFUDC is capitalized as a part of the cost of utility plant
and is credited as a non-cash item to other income and interest charges
currently. Cash inflow related to AFUDC does not occur until these charges are
reflected in rates.
The AFUDC
rate allowed by the Washington Commission for gas utility plant additions was
8.76% beginning September 1, 2002 and 9.15% in 2001. The allowed AFUDC rate on
electric utility plant was 8.76% beginning July 1, 2002 and 8.94% in 2001. To
the extent amounts calculated using this rate exceed the AFUDC calculated rate
using the Federal Energy Regulatory Commission (FERC) formula, the Company
capitalizes the excess as a deferred asset, crediting miscellaneous income. The
amounts included in income were $1.4 million for 2004, $1.6 million for 2003 and
$2.6 million for 2002. The deferred asset is being amortized over the average
useful life of the Company’s non-project utility plant.
OTHER
COMPREHENSIVE
Items
present in the Consolidated Statements of Comprehensive Income for Puget Energy
and PSE are presented net of applicable tax at a 35% statutory
rate.
REVENUE
RECOGNITION
Operating
utility revenues are recorded on the basis of service rendered, which includes
estimated unbilled revenue. Sales to other utilities are recorded on a net
service rendered basis in accordance with Emerging Issues Task Force of the
Financial Accounting Standards Board (EITF) Issue No. 03-11 “Reporting Realized
Gains and Losses on Derivative Instruments That Are Subject to FASB No. 133 and
Not ‘Held for Trading Purposes’ as Defined in Issue No. 02-03.” Non-utility
subsidiaries recognize revenue when services are performed, upon the sale of
assets or on a percent of completion basis for fixed priced
contracts.
ALLOWANCE
FOR DOUBTFUL ACCOUNTS
An
allowance for doubtful accounts is provided for energy customer accounts based
upon a historical experience rate of write-offs of energy accounts receivable as
compared to operating revenues. The allowance account is adjusted monthly for
this experience rate. Energy accounts are considered past due 15 business days
after the billing cycle. Once an account is past due, a 1% late payment fee is
accrued per month for each month an account is past due. When an account is past
due, the Company may assist the customer with the use of special payment
arrangements. If no payment arrangements are made or if no contact is made from
the customer, the Company has the option of stopping service. Once service is
stopped or the customer leaves the service area, a final bill is mailed. Energy
accounts are deemed uncollectible 74 business days after the final bill due date
and are written off against the allowance account. The late payment fee
continues to be accrued on past due accounts until they are written
off.
Other
non-energy receivable balances are reserved for in the allowance account based
on facts and circumstances surrounding the receivable indicating some or all of
the balance is uncollectible. Once exhaustive efforts have been made to collect
these other receivables, the allowance account and corresponding receivable
balance are written off.
The
Company has provided for a $41.5 million reserve for fiscal 2000 sales
transactions related to the California Independent System Operator and
counterparties based upon probability of collection.
Puget
Energy’s allowance for doubtful accounts for 2004 and 2003 was $46.0 million and
$45.8 million, respectively. PSE’s allowance for doubtful accounts for 2004 and
2003 was $44.2 million and $44.0 million, respectively
SELF-INSURANCE
The
Company currently has no insurance coverage for storm damage and is self-insured
for a portion of the risk associated with comprehensive liability, workers’
compensation claims and catastrophic property losses other than storm related.
With approval of the Washington Commission, PSE is able to defer for collection
in future rates certain uninsured storm damage costs associated with major
storms.
FEDERAL
INCOME TAXES
The
Company normalizes, with the approval of the Washington Commission, certain
income tax items. Deferred taxes have been determined under SFAS No. 109.
Investment tax credits are deferred and amortized based on the average useful
life of the related property in accordance with regulatory and income tax
requirements. (See Note 12).
ENERGY
EFFICIENCY
The
Company offers programs designed to help new and existing customers use energy
efficiently. The primary emphasis is to provide information and technical
services to enable customers to make energy efficient choices with respect to
building design, equipment and building systems, appliance purchases and
operating practices.
Since May
1997, the Company has recovered electric energy efficiency expenditures through
a tariff rider mechanism. The rider mechanism allows the Company to defer the
efficiency expenditures and amortize them to expense as PSE concurrently
collects the efficiency expenditures in rates over a one-year period. As a
result of the rider mechanism, electric energy efficiency expenditures have no
impact on earnings.
Since
1995, the Company has been authorized by the Washington Commission to defer gas
energy efficiency expenditures and recover them through a tariff tracker
mechanism. The tracker mechanism allows the Company to defer efficiency
expenditures and recover them in rates over the subsequent year. The tracker
mechanism also allows the Company to recover an Allowance for Funds Used to
Conserve Energy on any outstanding balance that is not being recovered in rates.
As a result of the tracker mechanism, gas energy efficiency expenditures have no
impact on earnings.
Energy
efficiency programs reduce customer consumption of energy thus impacting energy
margins. The impact of load reductions are adjusted in rates at each general
rate case.
RATE
ADJUSTMENT MECHANISMS
The
Company has a power cost adjustment (PCA) mechanism that provides for an
automatic rate adjustment if PSE’s costs to provide customers’ electricity falls
outside certain bands from a normalized level of power costs established in the
electric general rate case. The Company’s cumulative maximum pre-tax earnings
exposure due to power cost variations over the four-year period ending June 30,
2006 is limited to $40 million plus 1% of the excess. All significant variable
power supply cost drivers are included in the PCA mechanism (hydroelectric
generation variability, market price variability for purchased power and surplus
power sales, natural gas and coal fuel price variability, generation unit forced
outage risk and wheeling cost variability). The PCA mechanism apportions
increases or decreases in power costs, on a graduated scale, between PSE and its
customers. Any unrealized gains and losses from derivative instruments accounted
for under SFAS No. 133, “Accounting for Derivative Instruments and Hedging
Activities,” are deferred in proportion to the cost-sharing arrangement under
the PCA mechanism once the Company reaches its cap of $40 million.
The
graduated scale is as follows:
|
ANNUAL
POWER COST VARIABILITY |
CUSTOMERS'
SHARE |
COMPANY'S
SHARE1 |
|
+/-
$20 million |
0% |
|
100% |
|
|
+/-
$20 million - $40 million |
50% |
|
50% |
|
|
+/-
$40 million - $120 million |
90% |
|
10% |
|
|
+/-
$120+ million |
95% |
|
5% |
|
_______________________
| 1 |
Over
the four-year period July 1, 2002 through June 30, 2006 the Company’s
share of pre-tax cost variation is capped at a cumulative $40 million plus
1% of the excess. Power cost variation after June 30, 2006 will be
apportioned on an annual basis, based on the graduated
scale. |
The
differences between the actual cost of PSE’s gas supplies and gas transportation
contracts and that currently allowed by the Washington Commission are deferred
and recovered or repaid through the purchased gas adjustment (PGA) mechanism.
The PGA mechanism allows PSE to recover expected gas costs, and defer, as a
receivable or liability, any gas costs that exceed or fall short of this
expected gas cost amount in PGA mechanism rates, including
interest.
NATURAL
GAS OFF-SYSTEM SALES AND CAPACITY RELEASE
The
Company contracts for firm gas supplies and holds firm transportation and
storage capacity sufficient to meet the expected peak winter demand for gas by
its firm customers. Due to the variability in weather, winter peaking
consumption of natural gas by most of its customers and other factors, however,
the Company holds contractual rights to gas supplies and transportation and
storage capacity in excess of its average annual requirements to serve firm
customers on its distribution system. For much of the year there is excess
capacity available for third-party gas sales, exchanges and capacity releases.
The Company sells excess gas supplies, enters into gas supply exchanges with
third parties outside of its distribution area and releases to third parties
excess interstate gas pipeline capacity and gas storage rights on a short-term
basis to mitigate the costs of firm transportation and storage capacity for its
core gas customers. The proceeds from such activities, net of transactional
costs, are accounted for as reductions in the cost of purchased gas and passed
on to customers through the PGA mechanism, with no direct impact on net income.
As a result, the Company nets the sales revenue and associated cost of sales for
these transactions in purchased gas.
ENERGY
RISK MANAGEMENT
The
Company serves its regulated electric customers with an electric portfolio of
owned and contracted resources. As a result, the portfolio exposes the Company
and its customers to some volumetric and commodity price risks within the
sharing mechanism of the PCA. The Company also serves its regulated gas
customers with a gas portfolio of contracted resources which exposes the
Company’s customers to commodity price risks in the PGA mechanism. The Company’s
energy risk management function monitors and manages these risks using
analytical models and tools. In addition, the Audit Committee of the Company’s
Board of Directors periodically assesses risk management policies.
The
Company manages its energy supply portfolio to achieve three primary
objectives:
| · |
ensure
that physical energy supplies are available to serve retail customer
requirements; |
| · |
manage
portfolio risks to limit undesired impacts on the Company’s costs;
and |
| · |
maximize
the value of the Company’s energy supply
assets. |
ACCOUNTING
FOR DERIVATIVES
The
Company follows the provisions of SFAS No. 133, “Accounting for Derivative
Instruments and Hedging Activities,” as amended by SFAS No. 138 and SFAS No.
149, which requires that all contracts considered to be derivative instruments
be recorded on the balance sheet at their fair value. Certain contracts that
would otherwise be considered derivatives are exempt from SFAS No. 133 if they
qualify for a normal purchase normal sale exception. The Company enters into
both physical and financial contracts to manage its energy resource portfolio.
The majority of these contracts qualify for the normal purchase normal sale
exception. However, those contracts that do not meet normal purchase or normal
sale exception are derivatives and, pursuant to SFAS No. 133, are reported at
their fair value in the balance sheet. Changes in their fair value are reported
in earnings unless they meet specific hedge accounting criteria, in which case
changes in their fair market value are recorded in comprehensive income until
the time the transaction that they are hedging is recorded as income. The
Company designates a derivative instrument as a qualifying cash flow hedge if
the change in the fair value of the derivative is highly effective at offsetting
the changes in the fair value of an asset, a liability or a forecasted
transaction. To the extent that a portion of a derivative designated as a hedge
is ineffective, changes in the fair value of the ineffective portion of that
derivative are recognized currently in earnings. Changes in the market value of
derivative transactions related to obtaining gas for the Company’s retail gas
business are deferred as regulatory assets or liabilities as a result of the
Company’s PGA mechanism and recorded in earnings as the transactions are
executed. In addition, once the Company reaches the $40 million PCA cap, any
unrealized gains or losses are deferred in proportion to the cost-sharing
arrangement under the PCA.
STOCK-BASED
COMPENSATION
The
Company has various stock-based compensation plans which, prior to 2003, were
accounted for according to APB No. 25, “Accounting for Stock Issued to
Employees,” and related interpretations as allowed by SFAS No. 123, “Accounting
for Stock-Based Compensation.” In 2003, the Company adopted the fair value based
accounting of SFAS No. 123 using the prospective method under the guidance of
SFAS No. 148, “Accounting for Stock-Based Compensation - Transition and
Disclosure.” The Company applies SFAS No. 123 accounting to stock compensation
awards granted from 2003 on, while grants that were made in years prior to 2003
are accounted for using the intrinsic value method of APB No. 25. Had the
Company used the fair value method of accounting specified by SFAS No. 123 for
all grants at their grant date rather than prospectively implementing SFAS No.
123, net income and earnings per share would have been as follows:
|
(DOLLARS
IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
YEARS
ENDED DECEMBER 31 |
|
2004 |
|
2003 |
|
2002 |
|
|
Net
income, as reported |
|
$ |
55,022 |
|
$ |
116,197 |
|
$ |
110,052 |
|
|
Add:
Total stock-based employee compensation expense
included
in net income, net of tax |
|
|
2,641 |
|
|
4,180 |
|
|
4,103 |
|
|
Less:
Total stock-based employee compensation expense per the
fair
value method of SFAS No. 123, net of tax |
|
|
(3,303 |
) |
|
(3,314 |
) |
|
(3,495 |
) |
|
Pro
forma net income |
|
$ |
54,360 |
|
$ |
117,063 |
|
$ |
110,660 |
|
|
Earnings
per common share: |
|
|
|
|
|
|
|
|
|
|
|
Basic
as reported |
|
$ |
0.55 |
|
$ |
1.23 |
|
$ |
1.24 |
|
|
Diluted
as reported |
|
$ |
0.55 |
|
$ |
1.22 |
|
$ |
1.24 |
|
|
Basic
pro forma |
|
$ |
0.55 |
|
$ |
1.24 |
|
$ |
1.25 |
|
|
Diluted
pro forma |
|
$ |
0.54 |
|
$ |
1.23 |
|
$ |
1.25 |
|
DEBT
RELATED COSTS
Debt
premiums, discounts and expenses are amortized over the life of the related
debt. The premiums and costs associated with reacquired debt are deferred and
amortized over the life of the related new issuance, in accordance with
ratemaking treatment. At times the Company will enter into treasury lock
transactions to hedge against the potential rising interest rates. The
transaction, when settled, will be amortized over the related debt issuance
life.
GOODWILL
AND INTANGIBLES (PUGET ENERGY ONLY)
On
January 1, 2002, SFAS No. 142, “Goodwill and Other Intangible Assets,” became
effective and as a result Puget Energy ceased amortization of goodwill. Puget
Energy performed an initial impairment review of goodwill and an annual
impairment review thereafter. The initial review was completed during the first
half of 2002, which did not result in an impairment charge. Goodwill is reviewed
annually to determine if any impairment exists. If goodwill is determined to
have an impairment, Puget Energy would record in the period of determination an
impairment charge to earnings. Intangibles with finite lives are amortized based
on the expected pattern of use or on a straight-line basis over the expected
periods to be benefited. The goodwill and intangibles recorded on the balance
sheet of Puget Energy are the result of several acquisitions of companies by
InfrastruX.
In 2004,
InfrastruX recorded a $91.2 million ($76.6 million after tax and minority
interest) impairment charge related to goodwill from acquired companies. See
Note 18.
EARNINGS
PER COMMON SHARE (PUGET ENERGY ONLY)
Basic
earnings per common share has been computed based on weighted average common
shares outstanding of 99,470,000, 94,750,000 and 88,372,000 for 2004, 2003 and
2002, respectively. Diluted earnings per common share has been computed based on
weighted average common shares outstanding of 99,911,000, 95,309,000 and
88,777,000 for 2004, 2003 and 2002, respectively, which includes the dilutive
effect of securities related to employee stock-based compensation
plans.
ACCOUNTS
RECEIVABLE SECURITIZATION PROGRAM
Rainier
Receivables, Inc. is a wholly owned, bankruptcy-remote subsidiary of PSE formed
in December 2002 for the purpose of purchasing customers’ accounts receivable,
both billed and unbilled, of PSE. Rainier Receivables and PSE have an agreement
whereby Rainier Receivables can sell, on a revolving basis, up to $150 million
of those eligible receivables. The current agreement expires in December 2005.
Rainier Receivables is obligated to pay fees that approximate the third-party
purchaser’s cost of issuing commercial paper equal in value to the interests in
receivables sold. At December 31, 2004, Rainier Receivables had sold $150
million of receivables compared to $111 million of receivables sold at December
31, 2003.
NOTE 2.
New
Accounting Pronouncements
In
December 2004, FASB issued SFAS No. 123R, “Share-Based Payment” (SFAS No. 123R),
which revises SFAS No. 123, “Accounting For Stock-Based Compensation.” SFAS No.
123R requires companies that issue share-based payment awards to employees for
goods or services to recognize as compensation expense, the fair value of the
expected vested portion of the award as of the grant date over the vesting
period of the award. Forfeitures that occur before the award vesting date will
be adjusted from the total compensation expense, but once the award vests, no
adjustment to compensation expense will be allowed for forfeitures or
unexercised awards. In addition, SFAS No. 123R would require recognition of
compensation expense of all existing outstanding awards that are not fully
vested for their remaining vesting period as of the effective date that were not
accounted for under a fair-value method of accounting at the time of their
award. SFAS No. 123R is effective for reporting periods beginning after June 15,
2005. The Company is currently evaluating what impact the application of SFAS
No. 123R will have on its operations. The Company had adopted the fair value
provisions of SFAS No. 123 “Accounting for Stock Based Compensation” in January
2003.
In
December 2004, FASB issued FASB Staff Position No. 109-1, “Application of FASB
Statement No. 109, Accounting for Income Taxes, to the Tax Deduction on
Qualified Production Activities Provided by the American Jobs Creation Act of
2004” (FSP No. 109-1). FSP No. 109-1 states that the staff position related to
deductions as a result of the American Jobs Creation Act (the Act) should be
treated as a “special deduction”, as described in SFAS No. 109, “Accounting For
Income Taxes” and therefore has no effect on deferred tax assets or liabilities
existing at the enactment date. The Company is currently evaluating the impact
of FSP No. 109-1 (which was effective upon issuance) and any deduction available
under the Act. Any deduction available, if determined, is applicable to the
Company’s 2005 tax year.
On May
19, 2004, FASB issued FASB Staff Position (FSP) No. 106-2 “Accounting and
Disclosure Requirements Related to Medicare Prescription Drug, Improvement and
Modernization Act of 2003” as the result of the new Medicare Prescription Drug
and Modernization Act which was signed into law in December 2003. The law
provides a subsidy for plan sponsors that provide prescription drug benefits to
Medicare beneficiaries that are equivalent to the Medicare Part D plan. Based
upon an actuarial assessment, PSE will not be eligible for such subsidies, thus
FSP No. 106-2 will have no impact on PSE’s retiree medical plans.
The
Emerging Issues Task Force of the Financial Accounting Standards Board (EITF) at
its July 2003 meeting came to a consensus concerning EITF Issue No. 03-11,
“Reporting Realized Gains and Losses on Derivative Instruments That Are Subject
to FASB Statement No. 133 and Not ‘Held for Trading Purposes’ as Defined in
Issue No. 02-03.” The consensus reached was that determining whether realized
gains and losses on physically settled derivative contracts not held for trading
purposes are reported in the income statement on a gross or net basis is a
matter of judgment that depends on the relevant facts and circumstances. Based
on the guidance by EITF No. 03-11, the Company determined that its non-trading
derivative instruments should be reported net and implemented this treatment
effective January 1, 2004. As a result of the implementation, Electric Revenue
and Purchased Electricity Expense both decreased $108.7 million in 2003 and
$77.1 million in 2002, respectively, with no impact on financial position or net
income.
In March
2004, the EITF came to a consensus concerning EITF Issue No. 03-16, “Accounting
for Investments in Limited Liability Companies.” The consensus reached was that
an investment in a limited liability company (LLC) should be accounted for using
the equity method for investments greater than 3% to 5%. The adoption of EITF
No. 03-16 is effective for reporting periods beginning after June 15, 2004, with
any adjustments being accounted for as a cumulative effect of a change in
accounting principle. The Company reviewed its investments and determined one
investment held by PSE met the criteria established in EITF No. 03-16.
In May
2003, FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments
with Characteristics of Both Liabilities and Equity.” SFAS No. 150 establishes
the requirements for classifying and measuring as liabilities certain financial
instruments that embody obligations to redeem the financial instruments by the
issuer. The adoption of SFAS No. 150 is effective with the first fiscal year or
interim period beginning after June 15, 2003. However, on November 5, 2003 FASB
deferred for an indefinite period certain mandatorily redeemable noncontrolling
interests associated with finite-lived subsidiaries. The Company does not have
any noncontrolling interest in finite-lived subsidiaries and therefore, is not
affected by the deferral. Prior periods will not be restated for the new
presentation.
SFAS No.
150 requires the Company to classify its mandatorily redeemable preferred stock
as liabilities. As a result, the corresponding dividends on the mandatorily
redeemable preferred stock are classified as interest expense on the income
statement with no impact on income for common stock.
In
January 2003, FASB issued Interpretation No. 46, “Consolidation of Variable
Interest Entities” (FIN 46), as further revised in December 2003 with FIN 46R,
which clarifies the application of Accounting Research Bulletin No. 51,
“Consolidated Financial Statements,” to certain entities in which equity
investors do not have a controlling interest or sufficient equity at risk for
the entity to finance its activities without additional financial support. FIN
46 requires that if a business entity has a controlling financial interest in a
variable interest entity, the financial statements must be included in the
consolidated financial statements of the business entity. The adoption of FIN 46
for all interests in variable interest entities created after January 31, 2003
was effective immediately. For variable interest entities created before
February 1, 2003, it was effective July 1, 2003. The adoption of FIN 46R was
effective March 31, 2004. The Company evaluated its contractual arrangements and
determined PSE’s 1995 conservation trust off-balance sheet financing transaction
met this guidance, and therefore it was consolidated in the third quarter 2003.
As a result, electricity revenues for 2003 increased $5.7 million, while
conservation amortization and interest expense increased by the corresponding
amount with no impact on earnings. FIN 46R also impacted the treatment of the
Company’s mandatorily redeemable preferred securities of a wholly owned
subsidiary trust holding solely junior subordinated debentures of the
corporation (trust preferred securities). Previously, these trust-preferred
securities were consolidated into the Company’s operations. As a result of FIN
46R, these securities have been deconsolidated and were classified as junior
subordinated debentures of the corporation payable to a subsidiary trust holding
mandatorily redeemable preferred securities (junior subordinated debt) in the
fourth quarter 2003. This change had no impact on the Company’s results of
operations. The Company also evaluated its purchase power agreements and
determined that three counterparties may be considered variable interest
entities. As a result, PSE submitted requests for information to those parties;
however, the parties have refused to submit to PSE the necessary information for
PSE to determine whether they meet the requirements of a variable interest
entity. PSE also determined that it does not have a contractual right to such
information. PSE will continue to submit requests for information to the
counterparties in the future to determine if FIN 46R is applicable.
For the
three purchase power agreements that may be considered variable interest
entities under FIN 46R, PSE is required to buy all the generation from these
plants, subject to displacement by PSE, at rates set forth in the purchase power
agreements. If at any time the counterparties cannot deliver energy to PSE, PSE
would have to buy energy in the wholesale market at prices which could be higher
or lower than the purchase power agreement prices. PSE’s Purchased Electricity
expense for 2004 and 2003 for these three entities was $251.2 million and $273.9
million, respectively.
In June
2001, FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations,”
(SFAS No. 143) which is effective for fiscal years beginning after June 15,
2002. SFAS No. 143 requires legal obligations associated with the retirement of
long-lived assets to be recognized at their fair value at the time that the
obligations are incurred. Upon initial recognition of a liability, that cost
should be capitalized as part of the related long-lived asset and allocated to
expense over the useful life of the asset. The Company adopted the new rules on
asset retirement obligations on January 1, 2003. As a result, the Company
recorded a $0.2 million charge to income for the cumulative effect of this
accounting change. (See Note 3.)
In
November 2004, FASB reached a decision concerning a proposed interpretation of
SFAS No. 143 titled “Accounting for Conditional Asset Retirement Obligations.”
The proposed interpretation addresses the issue of whether SFAS No. 143 requires
an entity to recognize a liability for a legal obligation to perform asset
retirement when the asset retirement activities are conditional on a future
event, and if so, the timing and valuation of the recognition. The decision
reached by FASB was that there are no instances where a law or regulation
obligates an entity to perform retirement activities but then allows the entity
to permanently avoid settling the obligation. This, if part of the final issued
interpretation, could potentially have an impact on the Company as assets that
were previously considered outside the scope of SFAS No. 143 may be subject to
the terms of the proposed interpretation. FASB indicated that the final
interpretation is anticipated to be issued in the first quarter 2005, with an
effective date for fiscal years ending after December 15, 2005, with any
adjustment accounted for as a cumulative effect of an accounting change. The
Company is currently evaluating what impact this proposed interpretation may
have on the Company if issued.
NOTE 3.
Utility
and Non-Utility Plant
|
UTILITY
PLANT
(DOLLARS
IN THOUSANDS)
AT
DECEMBER 31 |
ESTIMATED
USEFUL LIFE
(YEARS) |
|
2004 |
|
2003 |
|
|
Electric,
gas and common utility plant classified by
prescribed
accounts at original cost: |
|
|
|
|
|
|
|
Distribution
plant |
10-60 |
|
$
4,219,720 |
|
$
4,030,570 |
|
|
Production
plant |
40-100 |
|
1,150,781 |
|
1,144,354 |
|
|
Transmission
plant |
30-95 |
|
426,543 |
|
379,889 |
|
|
General
plant |
10-35 |
|
346,472 |
|
344,781 |
|
|
Construction
work in progress |
NA |
|
129,966 |
|
121,622 |
|
|
Intangible
plant (including capitalized software) |
3-29 |
|
283,179 |
|
270,235 |
|
|
Plant
acquisition adjustment |
21 |
|
76,623 |
|
76,623 |
|
|
Underground
storage |
50-80 |
|
23,089 |
|
22,362 |
|
|
Liquefied
natural gas storage |
14-50 |
|
12,345 |
|
2,348 |
|
|
Plant
held for future use |
-- |
|
7,296 |
|
7,608 |
|
|
Other
|
27-34 |
|
5,313 |
|
5,240 |
|
|
Less
accumulated provision for depreciation |
|
|
(2,452,969 |
) |
(2,325,405 |
) |
|
Net
utility plant |
|
|
$
4,228,358 |
|
$
4,080,227 |
|
NON-UTILITY
PLANT
(DOLLARS
IN THOUSANDS)
AT
DECEMBER 31 |
ESTIMATED
USEFUL LIFE
(YEARS) |
|
2004 |
|
2003 |
|
|
Non-utility
plant |
3-20 |
|
$
138,656 |
|
$
122,926 |
|
|
Intangibles |
5-20 |
|
24,056 |
|
23,985 |
|
|
Less
accumulated depreciation and amortization |
|
|
(52,947 |
) |
(36,272 |
) |
|
Net
non-utility plant and intangibles |
|
|
$
109,765 |
|
$
110,639 |
|
Non-utility
plant is composed primarily of the property, plant and equipment of InfrastruX.
Non-utility plant and accumulated depreciation is included in “other” under
“other property and investments” in the Puget Energy balance sheet. Intangibles
are composed of patents, contractual customer relationships and other
amortizable intangible assets of InfrastruX.
On
January 1, 2003, the Company adopted SFAS No. 143, “Accounting for Asset
Retirement Obligations.” SFAS No. 143 requires legal obligations associated with
the retirement of long-lived assets to be recognized at their fair value at the
time that the obligations are incurred. Upon initial recognition of a liability,
that cost is capitalized as part of the related long-lived asset and allocated
to expense over the useful life of the asset. The Company recorded an after-tax
charge to income of $0.2 million in the first quarter 2003 for the cumulative
effect of the accounting change. The cost of removal is collected from PSE’s
customers through depreciation expense and any excess is recorded as a
regulatory liability.
The
Company identified various asset retirement obligations at January 1, 2003,
which were included in the cumulative effect of the accounting change. The
Company has an obligation (1) to dismantle two leased electric generation
turbine units and deliver the turbines to the nearest railhead at the
termination of the lease in 2009; (2) to remove certain structures as a result
of renegotiations with the Department of Natural Resources of a now-expired
lease; (3) to replace or line all cast iron pipes in its service territory by
2007 as a result of a 1992 Washington Commission order; and (4) to restore ash
holding ponds at a jointly owned coal-fired electric generating facility in
Montana.
The
following table describes all changes to the Company’s asset retirement
obligation liability:
|
(DOLLARS
IN THOUSANDS)
AT
DECEMBER 31 |
|
2004 |
|
2003 |
|
|
Asset
retirement obligation at beginning of year |
|
$ |
3,421 |
|
$ |
-- |
|
|
Liability
recognized in transition |
|
|
-- |
|
|
3,592 |
|
|
Liability
settled in the period |
|
|
-- |
|
|
(261 |
) |
|
Accretion
expense |
|
|
95 |
|
|
90 |
|
|
Asset
retirement obligation at December 31 |
|
$ |
3,516 |
|
$ |
3,421 |
|
The pro
forma asset retirement obligation liability balances as if SFAS No. 143 had been
adopted on January 1, 2002 (rather than January 1, 2003) are as follows:
|
(DOLLARS
IN THOUSANDS) |
|
Pro
forma amounts of liability for asset retirement obligation at January 1,
2002 |
$
3,497 |
Pro
forma amounts of liability for asset retirement obligation at December 31,
2002 |
3,592 |
|
(DOLLARS
IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) |
|
2003 |
|
2002 |
|
|
Net
income, as reported |
|
$ |
116,197 |
|
$ |
110,052 |
|
|
Add:
SFAS No. 143 transition adjustment, net of tax |
|
|
169 |
|
|
-- |
|
|
Less:
Pro forma accretion expense, net of tax |
|
|
-- |
|
|
(62 |
) |
|
Pro
forma net income |
|
$ |
116,366 |
|
$ |
109,990 |
|
|
Earnings
per share: |
|
|
|
|
|
|
|
|
Basic
as reported |
|
$ |
1.23 |
|
$ |
1.24 |
|
|
Diluted
as reported |
|
$ |
1.22 |
|
$ |
1.24 |
|
|
Basic
pro forma |
|
$ |
1.23 |
|
$ |
1.24 |
|
|
Diluted
pro forma |
|
$ |
1.22 |
|
$ |
1.24 |
|
NOTE 4.
Preferred
Stock
On
November 1, 2003, all the authorized and outstanding 2.4 million shares of the
$25 par value 7.45% Series preferred stock not subject to mandatory redemption
were redeemed at par value plus accrued dividends. There were no other
redemptions or reacquired shares of this preferred stock series in
2003.
NOTE 5.
Preferred
Share Purchase Right
On
October 23, 2000, the Board of Directors declared a dividend of one preferred
share purchase right (a Right) for each outstanding common share of Puget
Energy. The dividend was paid on December 29, 2000 to shareholders of record on
that date. The Rights will become exercisable only if a person or group acquires
10% or more of Puget Energy’s outstanding common stock or announces a tender
offer which, if consummated, would result in ownership by a person or group of
10% or more of the outstanding common stock. Each Right will entitle the holder
to purchase from Puget Energy one one-hundredth of a share of preferred stock
with economic terms similar to that of one share of Puget Energy’s common stock
at a purchase price of $65, subject to adjustments. The Rights expire on
December 21, 2010, unless redeemed or exchanged earlier by Puget
Energy.
NOTE 6.
Dividend
Restrictions
The
payment of dividends on common stock is restricted by provisions of certain
covenants applicable to preferred stock and long-term debt contained in the
Company’s Articles of Incorporation and Mortgage Indentures. Under the most
restrictive covenants of PSE, earnings reinvested in the business unrestricted
as to payment of cash dividends were approximately $274.4 million at December
31, 2004. For the years 2004, 2003 and 2002, the aggregate dividends declared
per share were $1.00, $1.00 and $1.21, respectively.
Under the
general rate settlement, PSE must rebuild its common equity ratio to at least
39%, with milestones of 35% and 39% at the end of 2004 and 2005, respectively.
If PSE should fail to meet the schedule, it would be subject to a 2% rate
reduction penalty. The common equity ratio for PSE at December 31, 2004 was
40.1%.
NOTE 7.
Redeemable
Securities
| |
|
PREFERRED
STOCK SUBJECT TO
MANDATORY
REDEMPTION $100 PAR VALUE |
|
| |
|
4.70%
SERIES |
|
4.84%
|
|
7.75%
|
|
|
|
|
|
4,311 |
|
|
14,808 |
|
|
487,500 |
|
|
Acquired
for sinking fund: |
|
|
|
|
|
|
|
|
|
|
|
2002 |
|
|
-- |
|
|
-- |
|
|
(75,000 |
) |
|
2003 |
|
|
-- |
|
|
-- |
|
|
(75,000 |
) |
|
2004 |
|
|
-- |
|
|
-- |
|
|
-- |
|
|
Called
for redemption or reacquired and canceled: |
|
|
|
|
|
|
|
|
|
|
|
2002 |
|
|
-- |
|
|
-- |
|
|
-- |
|
|
2003 |
|
|
-- |
|
|
(225 |
) |
|
(337,500 |
) |
|
2004 |
|
|
-- |
|
|
-- |
|
|
-- |
|
|
|
|
|
4,311 |
|
|
14,583 |
|
|
-- |
|
See
“Consolidated Statements of Capitalization” for details on specific
series.
PREFERRED
STOCK SUBJECT TO MANDATORY REDEMPTION
The
Company is required to deposit funds annually in a sinking fund sufficient to
redeem the following number of shares of each series of preferred stock at $100
per share plus accrued dividends: 4.70% Series and 4.84% Series, 3,000 shares
each. All previous sinking fund requirements have been satisfied. The $100 par
value 7.75% Series preferred stock subject to mandatory redemption was fully
redeemed at $102.07 per share plus accrued dividends on August 15, 2003. At
December 31, 2004, there were 34,689 shares of the 4.70% Series and 18,192
shares of the 4.84% Series acquired by the Company and available for future
sinking fund requirements. Upon involuntary liquidation, all preferred shares
are entitled to their par value plus accrued dividends.
The
preferred stock subject to mandatory redemption may also be redeemed by the
Company at the following redemption prices per share plus accrued dividends:
4.70% Series, $101.00 and 4.84% Series, $102.00.
JUNIOR
SUBORDINATED DEBENTURES OF THE CORPORATION PAYABLE TO A SUBSIDIARY TRUST HOLDING
MANDATORILY REDEEMABLE PREFERRED SECRUITIES
In 1997
and 2001, the Company formed Puget Sound Energy Capital Trust I and Puget Sound
Energy Capital Trust II, respectively, for the sole purpose of issuing and
selling common and preferred securities (Trust Securities). The proceeds from
the sale of Trust Securities were used to purchase Junior Subordinated
Debentures (Debentures) from the Company. The Debentures are the sole assets of
the Trusts and the Company owns all common securities of the
Trusts.
The
Debentures of Trust I and Trust II have an interest rate of 8.231% and 8.40%,
respectively, and a stated maturity date of June 1, 2027 and June 30, 2041,
respectively. The Trust Securities are subject to mandatory redemption at par on
the stated maturity date of the Debentures. The Trust Securities in the Capital
Trust I may be redeemed earlier, under certain conditions, at the option of the
Company. The Capital Trust II Securities may be redeemed at any time on or after
June 30, 2006 at par, under certain conditions, at the option of the Company.
Dividends relating to preferred securities are included in interest expense for
all periods presented.
NOTE 8.
Long-Term
Debt
FIRST
MORTGAGE BONDS AND SENIOR NOTES
AT
DECEMBER 31 (DOLLARS IN THOUSANDS)
|
SERIES |
|
DUE |
|
2004 |
|
2003 |
|
SERIES |
|
DUE |
|
2004 |
|
2003 |
|
6.07% |
|
2004 |
|
$
-- |
|
$10,000 |
|
6.46% |
|
2009 |
|
150,000 |
|
150,000 |
|
6.10% |
|
2004 |
|
-- |
|
8,500 |
|
6.61% |
|
2009 |
|
3,000 |
|
3,000 |
|
7.70% |
|
2004 |
|
-- |
|
50,000 |
|
6.62% |
|
2009 |
|
5,000 |
|
5,000 |
|
7.80% |
|
2004 |
|
-- |
|
30,000 |
|
7.12% |
|
2010 |
|
7,000 |
|
7,000 |
|
6.92% |
|
2005 |
|
11,000 |
|
11,000 |
|
7.96% |
|
2010 |
|
225,000 |
|
225,000 |
|
6.93% |
|
2005 |
|
20,000 |
|
20,000 |
|
7.69% |
|
2011 |
|
260,000 |
|
260,000 |
|
Variable |
|
2006 |
|
200,000 |
|
-- |
|
6.83% |
|
2013 |
|
3,000 |
|
3,000 |
|
6.58% |
|
2006 |
|
10,000 |
|
10,000 |
|
6.90% |
|
2013 |
|
10,000 |
|
10,000 |
|
8.06% |
|
2006 |
|
46,000 |
|
46,000 |
|
7.35% |
|
2015 |
|
10,000 |
|
10,000 |
|
8.14% |
|
2006 |
|
25,000 |
|
25,000 |
|
7.36% |
|
2015 |
|
2,000 |
|
2,000 |
|
7.02% |
|
2007 |
|
20,000 |
|
20,000 |
|
6.74% |
|
2018 |
|
200,000 |
|
200,000 |
|
7.04% |
|
2007 |
|
5,000 |
|
5,000 |
|
9.57% |
|
2020 |
|
25,000 |
|
25,000 |
|
7.75% |
|
2007 |
|
100,000 |
|
100,000 |
|
7.35% |
|
2024 |
|
-- |
|
55,000 |
|
3.363% |
|
2008 |
|
150,000 |
|
150,000 |
|
7.15% |
|
2025 |
|
15,000 |
|
15,000 |
|
6.51% |
|
2008 |
|
1,000 |
|
1,000 |
|
7.20% |
|
2025 |
|
2,000 |
|
2,000 |
|
6.53% |
|
2008 |
|
3,500 |
|
3,500 |
|
7.02% |
|
2027 |
|
300,000 |
|
300,000 |
7.61% |
|
2008 |
|
25,000 |
|
25,000 |
|
7.00% |
|
2029 |
|
100,000 |
|
100,000 |
| |
|
|
|
|
|
|
|
Total |
|
$1,933,500 |
|
$1,887,000 |
In
January 2004, the Company filed a shelf-registration statement with the
Securities and Exchange Commission for the offering, on a delayed or continuous
basis, of up to $500 million of any combination of common stock of Puget Energy
and principal amount of senior notes secured by a pledge of first mortgage
bonds. In July 2004, PSE issued $200 million in floating rate senior notes under
its existing $500 million registration statement. The notes have a floating
interest rate which is based on the three-month LIBOR rate plus 0.30% (2.37% at
December 31, 2004), and mature in July 2006. The Company called and paid off
five series of first mortgage bonds in 2004, totaling $153.5 million. The
Company repaid the bonds using both cash on hand and proceeds from the $200
million floating rate senior notes.
Substantially
all utility properties owned by the Company are subject to the lien of the
Company’s electric and gas mortgage indentures. To issue additional first
mortgage bonds under these indentures, PSE’s earnings available for interest
must be at least twice the annual interest charges on outstanding first mortgage
bonds. At December 31, 2004, the earnings available for interest exceeded the
required amount.
POLLUTION
CONTROL BONDS
The
Company has outstanding two series of Pollution Control Bonds. On February 19,
2003, the Board of Directors approved the refinancing of all Pollution Control
Bonds series, which were issued in March 2003. Amounts outstanding were borrowed
from the City of Forsyth, Montana (the City). The City obtained the funds from
the sale of Customized Pollution Control Refunding Bonds issued to finance
pollution control facilities at Colstrip Units 3 & 4.
Each
series of bonds is collateralized by a pledge of PSE’s first mortgage bonds, the
terms of which match those of the Pollution Control Bonds. No payment is due
with respect to the related series of first mortgage bonds so long as payment is
made on the Pollution Control Bonds.
|
AT
DECEMBER 31
(DOLLARS
IN THOUSANDS) |
|
SERIES |
DUE |
2004 |
2003 |
|
2003A
Series -
5.00% |
2031 |
$
138,460 |
$
138,460 |
|
2003B
Series -
5.10% |
2031 |
23,400 |
23,400 |
|
Total |
|
$
161,860 |
$
161,860 |
CONSERVATION
TRUST FINANCINGS
In
October 2004, the 6.45% Conservation Trust Bonds matured. PSE originally
consolidated the 1995 Conservation Trust Bonds when FIN 46 went into effect in
July 2003. The balance at December 31, 2003 was $4.2 million.
LONG-TERM
REVOLVING CREDIT FACILITY (PUGET ENERGY ONLY)
Puget
Energy has a $15.0 million revolving credit facility available through a bank.
At December 31, 2004, there was $5.0 million outstanding at a weighted average
interest rate of 3.07%, leaving $10.0 million available under the facility. On
February 1, 2005, Puget Energy reduced the borrowing capacity under this credit
facility to $5.0 million.
InfrastruX
and its subsidiaries have signed credit agreements with several banks for up to
$186.7 million, which expire at various dates from 2005 to 2007. Under the
InfrastruX credit agreement, Puget Energy is the guarantor of $150.0 million of
the line of credit. InfrastruX has borrowed $143.1 million at a weighted average
interest rate of 2.96%, leaving a balance of $43.6 million available under the
lines of credit at December 31, 2004. InfrastruX also has $18.4 million in
equipment financing agreements with various vendors. These agreements mature at
various dates from 2005 to 2009 and carry interest rates up to
7.45%.
LONG-TERM
DEBT MATURITIES
The
principal amounts of long-term debt maturities for the next five years and
thereafter are as follows:
|
PUGET
ENERGY
(DOLLARS
IN THOUSANDS) |
2005 |
2006 |
2007 |
2008 |
2009 |
THEREAFTER |
|
Maturities
of: |
|
|
|
|
|
|
|
Long-term
debt |
$
38,933 |
$
292,276 |
$
259,866 |
$
181,089 |
$
158,441 |
$
1,320,860 |
|
PUGET
SOUND ENERGY
(DOLLARS
IN THOUSANDS) |
2005 |
2006 |
2007 |
2008 |
2009 |
THEREAFTER |
|
Maturities
of: |
|
|
|
|
|
|
|
Long-term
debt |
$
31,000 |
$
281,000 |
$
125,000 |
$
179,500 |
$
158,000 |
$
1,320,860 |
NOTE 9.
Liquidity
Facilities and Other Financing Arrangements
At
December 31, 2004, PSE had short-term borrowing arrangements that included a
$350 million unsecured line of credit agreement with a group of banks and a $150
million receivables securitization program. These arrangements provide PSE with
the ability to borrow at different interest rate options and include variable
fee levels. The line of credit agreement allows the Company to make floating
rate advances at the banks’ prime rate and Eurodollar advances at LIBOR plus a
spread, and contains “credit sensitive” pricing with various spreads associated
with various credit rating levels. The line of credit agreement also allows for
issuing standby letters of credit up to the entire line of credit agreement
amount. The line of credit agreement expires in June 2007.
PSE has
entered into a Receivables Sales Agreement with Rainier Receivables, Inc., a
wholly owned subsidiary of PSE, in December 2002. Pursuant to the Receivables
Sales Agreement, PSE sells all of its utility customer accounts receivable and
unbilled utility revenues to Rainier Receivables. In addition, Rainier
Receivables entered into a Receivables Purchase Agreement with PSE and a third
party. The Receivables Purchase Agreement allows Rainier Receivables to sell the
receivables purchased from PSE to the third party. The amount of receivables
sold by Rainier Receivables is not permitted to exceed $150 million at any
time. However, the maximum amount may be less than $150 million depending on the
eligible outstanding amount of PSE’s receivables which fluctuate with the
seasonality of energy sales to customers.
The
receivables securitization facility is the functional equivalent of a secured
revolving line of credit. In the event Rainier Receivables elects to sell
receivables under the Receivables Purchase Agreement, Rainier Receivables is
required to pay the purchasers fees that are comparable to interest rates on a
revolving line of credit. As receivables are collected by PSE as agent for the
receivables purchasers, the outstanding amount of receivables purchased by the
purchasers declines until Rainier Receivables elects to sell additional
receivables to the purchasers.
The
receivables securitization facility expires in December 2005, but is terminable
by PSE and Rainier Receivables upon notice to the receivables purchasers. During
the year ended December 31, 2004, Rainier Receivables had sold a cumulative
amount of $600.2 million in accounts receivable, and had $150.0 million of
accounts receivable sold under the program at December 31, 2004. There were no
additional amounts available to be sold under the program at December 31, 2004.
During the year ended December 31, 2003, Rainier Receivables had sold a
cumulative amount of $348.0 million in accounts receivable and had $111.0
million sold under the program at December 31, 2003.
In
addition, PSE has agreements with certain banks to borrow on an uncommitted, as
available, basis at money market rates quoted by the banks. There are no costs,
other than interest, for these arrangements. PSE also uses commercial paper to
fund its short-term borrowing requirements. The following table presents the
liquidity facilities and other financing arrangements at December 31, 2004 and
2003.
|
(DOLLARS
IN THOUSANDS)
AT
DECEMBER 31 |
|
2004 |
|
2003 |
|
Short-term
borrowings outstanding: |
|
|
|
|
|
|
|
|
InfrastruX
bank line of credit borrowings |
|
$ |
8,297 |
|
$ |
13,893 |
|
|
Weighted
average interest rate |
|
|
2.47 |
% |
|
2.59 |
% |
|
Financing
arrangements: |
|
|
|
|
|
|
|
|
Puget
Energy line of credit 1 |
|
$ |
15,000 |
|
$ |
15,000 |
|
|
InfrastruX
revolving credit facilities 2 |
|
|
186,725 |
|
|
184,725 |
|
|
PSE
line of credit 3 |
|
|
350,000 |
|
|
250,000 |
|
|
PSE
receivables securitization program 4 |
|
|
150,000 |
|
|
150,000 |
|
___________________
| 1 |
Includes
$5.0 million outstanding at December 31, 2004, leaving $10.0 million
available under the agreement. On February 1, 2005, Puget Energy reduced
the capacity to $5.0 million. |
| 2 |
The
revolving credit facility requires InfrastruX and its subsidiaries to
maintain certain financial covenants, including requirements to maintain
certain levels of net worth and debt coverage. The agreement also places
certain restrictions on expenditures, other indebtedness and executive
compensation. For 2004 and 2003, InfrastruX had $143.1 million and $155.6
million outstanding under the credit facilities, effectively reducing
available borrowing capacity to $43.6 million and $29.1 million,
respectively. |
| 3 |
Provides
liquidity support for PSE’s outstanding commercial paper and letters of
credit in the amount of $0.5 million in 2004 and 2003, effectively
reducing the available borrowing capacity under these credit lines to
$349.5 million and $249.5 million, respectively. There was no commercial
paper outstanding at December 31, 2004 and
2003. |
| 4 |
Provides
liquidity support for PSE’s outstanding letters of credit and commercial
paper. At December 31, 2004, PSE had sold $150.0 million in receivables,
leaving no amounts available to borrow under the receivables
securitization program. At December 31, 2003, PSE had sold $111.0 million
in receivables. |
NOTE 10.
Estimated
Fair Value of Financial Instruments
The
following table presents the carrying amounts and estimated fair values of the
Company’s financial instruments at December 31, 2004 and 2003.
| |
|
2004 |
|
2003 |
|
|
(DOLLARS
IN MILLIONS) |
|
CARRYING
AMOUNT |
|
FAIR
VALUE |
|
CARRYING
AMOUNT |
|
FAIR
VALUE |
|
Financial
assets: |
|
|
|
|
|
|
|
|
|
|
Cash |
|
$ |
19.8 |
|
$ |
19.8 |
|
$ |
27.5 |
|
$ |
27.5 |
|
|
Restricted
cash |
|
|
1.6 |
|
|
1.6 |
|
|
2.5 |
|
|
2.5 |
|
|
Equity
securities |
|
|
1.9 |
|
|
1.9 |
|
|
3.6 |
|
|
3.6 |
|
|
Notes
receivable and other |
|
|
71.4 |
|
|
71.4 |
|
|
63.6 |
|
|
63.6 |
|
|
Energy
derivatives |
|
|
21.9 |
|
|
21.9 |
|
|
16.2 |
|
|
16.2 |
|
|
Financial
liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term
debt |
|
$ |
8.3 |
|
$ |
8.3 |
|
$ |
13.9 |
|
$ |
13.9 |
|
|
Preferred
stock subject to mandatory redemption |
|
|
1.9 |
|
|
1.9 |
|
|
1.9 |
|
|
1.9 |
|
|
Junior
subordinated debentures of the corporation
payable
to a subsidiary trust holding mandatorily redeemable preferred
securities |
|
|
280.3 |
|
|
290.9 |
|
|
280.3 |
|
|
304.6 |
|
|
Long-term
debt -
fixed-rate1 |
|
|
2,051.4 |
|
|
2,194.8 |
|
|
2,216.3 |
|
|
2,409.6 |
|
|
Long-term
debt -
variable-rate1 |
|
|
200.0 |
|
|
199.9 |
|
|
-- |
|
|
-- |
|
|
Energy
derivatives |
|
|
19.5 |
|
|
19.5 |
|
|
3.6 |
|
|
3.6 |
|
____________________
| 1 |
PSE’s
carrying value and fair value of both fixed-rate and variable-rate
long-term debt in 2004 was $2,095.4 million and $2,238.7 million,
respectively. PSE’s carrying value and fair value of fixed-rate long-term
debt in 2003 was $2,053.0 million and $2,250.4 million,
respectively. |
The
carrying amount of equity securities is considered to be a reasonable estimate
of fair value. The fair value of outstanding bonds including current maturities
is estimated based on quoted market prices. The fair value of the preferred
stock subject to mandatory redemption is estimated based on dealer quotes. The
fair value of the junior subordinated debentures of the corporation payable to a
subsidiary trust holding mandatorily redeemable preferred securities is
estimated based on dealer quotes. The carrying values of short-term debt and
notes receivable are considered to be a reasonable estimate of fair value. The
carrying amount of cash, which includes temporary investments with original
maturities of three months or less, is also considered to be a reasonable
estimate of fair value.
Derivative
instruments have been used by the Company on a limited basis and are recorded at
fair value. The Company has a policy that financial derivatives are to be used
only to mitigate business risk.
In 2003,
PSE redeemed the 7.75% mandatorily redeemable preferred stock. 75,000 shares
were redeemed in February 2003 at the par value of $100 per share and the
remaining 337,500 shares were redeemed in August 2003 at $102.07 per share. Also
in 2003, 19,750 shares of the 8.231% Capital Trust I preferred stock were
redeemed at $990 per share, leaving 80,250 shares still outstanding. There was
no preferred stock redeemed in 2004.
NOTE 11.
Leases
All of
PSE’s leases are operating leases. Certain leases contain purchase options and
renewal and escalation provisions. Operating and capital lease payments net of
sublease receipts were:
|
(DOLLARS
IN THOUSANDS) |
PUGET
ENERGY |
PSE |
|
AT
DECEMBER 31 |
OPERATING |
CAPITAL |
OPERATING |
|
2004 |
$
25,751 |
$
2,086 |
$
17,618 |
|
2003 |
26,842 |
2,696 |
19,301 |
|
2002 |
26,386 |
2,486 |
20,176 |
Payments
received for the subleases of properties were approximately $0.1 million, $1.4
million and $2.6 million for the years ended December 31, 2004, 2003 and 2002,
respectively.
Future
minimum lease payments for non-cancelable leases net of sublease receipts
are:
|
(DOLLARS
IN THOUSANDS) |
PUGET
ENERGY |
PSE |
|
AT
DECEMBER 31 |
OPERATING |
CAPITAL |
OPERATING |
|
2005 |
$
19,311 |
$
1,988 |
$
12,791 |
|
2006 |
19,804 |
2,057 |
16,034 |
|
2007 |
17,500 |
1,558 |
15,524 |
|
2008 |
15,174 |
1,032 |
14,496 |
|
2009 |
11,591 |
343 |
11,459 |
|
Thereafter |
46,140 |
-- |
46,045 |
|
Total
minimum lease payments |
$
129,520 |
$
6,978 |
$
116,349 |
PSE
leases a portion of its owned gas transmission pipeline infrastructure under a
non-cancelable operating lease to a third party. The lease expires in 2009.
Future minimum lease payments to be received by PSE under this lease
are:
|
(DOLLARS
IN THOUSANDS)
AT
DECEMBER 31 |
2005 |
2006 |
2007 |
2008 |
2009 |
|
Lease
receipts |
$
1,182 |
$
1,182 |
$
1,182 |
$
1,182 |
$
985 |
In 2004,
Puget Energy acquired $2.1 million in assets under capital leases, which is a
non-cash investing activity for the Statement of Cash Flows for Puget
Energy.
NOTE 12.
Income
Taxes
The
details of income taxes are as follows:
|
PUGET
ENERGY
(DOLLARS
IN THOUSANDS) |
|
2004 |
|
2003 |
|
2002 |
|
Charged
to operating expense: |
|
|
|
|
|
|
|
|
Current
-
federal |
|
$ |
7,607 |
|
$ |
18,119 |
|
$ |
(84,149 |
) |
|
Current
-
state |
|
|
75 |
|
|
(2,046 |
) |
|
(774 |
) |
|
Deferred
-federal |
|
|
70,522 |
|
|
56,004 |
|
|
144,230 |
|
|
Deferred
-
state |
|
|
(2,647 |
) |
|
927 |
|
|
614 |
|
|
Deferred
investment tax credits |
|
|
(593 |
) |
|
(635 |
) |
|
(661 |
) |
|
Total
charged to operations |
|
|
74,964 |
|
|
72,369 |
|
|
59,260 |
|
|
Charged
to miscellaneous income: |
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
(5,344 |
) |
|
(288 |
) |
|
(3,276 |
) |
|
Deferred
|
|
|
2,470 |
|
|
(1,805 |
) |
|
1,228 |
|
|
Total
charged to miscellaneous income |
|
|
(2,874 |
) |
|
(2,093 |
) |
|
(2,048 |
) |
|
Cumulative
effect of accounting change |
|
|
-- |
|
|
(91 |
) |
|
-- |
|
|
Total
income taxes |
|
$ |
72,090 |
|
$ |
70,185 |
|
$ |
57,212 |
|
|
PUGET
SOUND ENERGY
(DOLLARS
IN THOUSANDS) |
|
2004 |
|
2003 |
|
2002 |
|
Charged
to operating expense: |
|
|
|
|
|
|
|
|
Current
-
federal |
|
$ |
5,825 |
|
$ |
22,154 |
|
$ |
(81,839 |
) |
|
Current
-
state |
|
|
(21 |
) |
|
(1,460 |
) |
|
(548 |
) |
|
Deferred
-federal |
|
|
71,966 |
|
|
50,880 |
|
|
135,884 |
|
|
Deferred
-
state |
|
|
-- |
|
|
-- |
|
|
-- |
|
|
Deferred
investment tax credits |
|
|
(593 |
) |
|
(635 |
) |
|
(661 |
) |
|
Total
charged to operations |
|
|
77,177 |
|
|
70,939 |
|
|
52,836 |
|
|
Charged
to miscellaneous income: |
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
(5,306 |
) |
|
(276 |
) |
|
(3,406 |
) |
|
Deferred
|
|
|
2,470 |
|
|
(1,805 |
) |
|
1,228 |
|
|
Total
charged to miscellaneous income |
|
|
(2,836 |
) |
|
(2,081 |
) |
|
(2,178 |
) |
|
Cumulative
effect of accounting change |
|
|
-- |
|
|
(91 |
) |
|
-- |
|
|
Total
income taxes |
|
$ |
74,341 |
|
$ |
68,767 |
|
$ |
50,658 |
|
The
following is a reconciliation of the difference between the amount of income
taxes computed by multiplying pre-tax book income by the statutory tax rate and
the amount of income taxes in the Consolidated Statements of Income for the
Company:
|
PUGET
ENERGY
(DOLLARS
IN THOUSANDS) |
|
2004 |
|
2003 |
|
2002 |
|
|
Income
taxes at the statutory rate |
|
$ |
42,016 |
|
$ |
65,295 |
|
$ |
58,846 |
|
|
Increase
(decrease): |
|
|
|
|
|
|
|
|
|
|
|
Depreciation
expense deducted in the financial statements in excess of tax
depreciation, net of depreciation treated as a temporary
difference |
|
|
10,723 |
|
|
9,130 |
|
|
10,041 |
|
|
AFUDC
included in income in the financial statements but excluded from taxable
income |
|
|
(2,270 |
) |
|
(1,809 |
) |
|
(1,387 |
) |
|
Accelerated
benefit on early retirement of depreciable assets |
|
|
(1,297 |
) |
|
(1,879 |
) |
|
(1,469 |
) |
|
Investment
tax credit amortization |
|
|
(593 |
) |
|
(635 |
) |
|
(661 |
) |
|
Energy
Efficiency expenditures - net |
|
|
(134 |
) |
|
8,096 |
|
|
6,259 |
|
|
Tax
benefit of reduced salvage values |
|
|
-- |
|
|
-- |
|
|
(10,193 |
) |
|
IRS
issue resolution |
|
|
-- |
|
|
(6,209 |
) |
|
-- |
|
|
Goodwill
impairment |
|
|
10,276 |
|
|
-- |
|
|
-- |
|
|
Valuation
allowance |
|
|
17,988 |
|
|
-- |
|
|
-- |
|
|
Preferred
stock dividends of subsidiary |
|
|
-- |
|
|
1,803 |
|
|
2,741 |
|
|
Sate
income taxes net of the federal income tax benefit |
|
|
(2,566 |
) |
|
(877 |
) |
|
(104 |
) |
|
Other
- net |
|
|
(2,053 |
) |
|
(2,730 |
) |
|
(6,861 |
) |
|
Total
income taxes |
|
$ |
72,090 |
|
$ |
70,185 |
|
$ |
57,212 |
|
|
Effective
tax rate |
|
|
62.2 |
% |
|
37.6 |
% |
|
34.0 |
% |
|
PUGET
SOUND ENERGY
(DOLLARS
IN THOUSANDS) |
|
2004 |
|
2003 |
|
2002 |
|
|
Income
taxes at the statutory rate |
|
$ |
70,187 |
|
$ |
66,028 |
|
$ |
55,862 |
|
|
Increase
(decrease): |
|
|
|
|
|
|
|
|
|
|
|
Depreciation
expense deducted in the financial statements
in
excess of tax depreciation, net of depreciation treated as a temporary
difference |
|
|
10,723 |
|
|
9,130 |
|
|
10,041 |
|
|
AFUDC
included in income in the financial statements
but
excluded from taxable income |
|
|
(2,270 |
) |
|
(1,809 |
) |
|
(1,387 |
) |
|
Accelerated
benefit on early retirement of depreciable assets |
|
|
(1,297 |
) |
|
(1,879 |
) |
|
(1,469 |
) |
|
Investment
tax credit amortization |
|
|
(593 |
) |
|
(635 |
) |
|
(661 |
) |
|
Energy
Efficiency expenditures - net |
|
|
(134 |
) |
|
8,096 |
|
|
6,259 |
|
|
Tax
benefit of reduced salvage values |
|
|
-- |
|
|
-- |
|
|
(10,193 |
) |
|
IRS
issue resolution |
|
|
-- |
|
|
(6,209 |
) |
|
-- |
|
|
Sate
income taxes net of the federal income tax benefit |
|
|
(14 |
) |
|
(949 |
) |
|
(356 |
) |
|
Other
- net |
|
|
(2,261 |
) |
|
(3,006 |
) |
|
(7,438 |
) |
|
Total
income taxes |
|
$ |
74,341 |
|
$ |
68,767 |
|
$ |
50,658 |
|
|
Effective
tax rate |
|
|
37.1 |
% |
|
36.5 |
% |
|
31.7 |
% |
The
Company’s deferred tax liability at December 31, 2004, 2003 and 2002 is composed
of amounts related to the following types of temporary differences:
|
PUGET
ENERGY
(DOLLARS
IN THOUSANDS) |
|
2004 |
|
2003 |
|
2002 |
|
|
Plant
and equipment |
|
$ |
665,407 |
|
$ |
622,462 |
|
$ |
588,182 |
|
|
Capitalized
overhead costs |
|
|
72,448 |
|
|
70,834 |
|
|
72,220 |
|
|
Software
amortization |
|
|
37,484 |
|
|
41,044 |
|
|
41,408 |
|
|
Pensions
and compensation |
|
|
15,367 |
|
|
16,890 |
|
|
29,099 |
|
|
Bonneville
Exchange Power |
|
|
14,078 |
|
|
15,204 |
|
|
15,537 |
|
|
Energy
Efficiency charges |
|
|
10,320 |
|
|
9,446 |
|
|
16,473 |
|
|
Other
deferred tax liabilities |
|
|
68,587 |
|
|
68,351 |
|
|
46,655 |
|
|
Subtotal
deferred tax liabilities |
|
|
883,691 |
|
|
844,231 |
|
|
809,574 |
|
|
Contributions
in aid of construction |
|
|
(41,525 |
) |
|
(46,520 |
) |
|
(44,770 |
) |
|
Goodwill |
|
|
(18,683 |
) |
|
4,192 |
|
|
2,106 |
|
|
Other
deferred tax assets |
|
|
(30,745 |
) |
|
(46,668 |
) |
|
(36,235 |
) |
|
Subtotal
deferred tax assets |
|
|
(90,953 |
) |
|
(88,996 |
) |
|
(78,899 |
) |
|
Valuation
allowance |
|
|
17,988 |
|
|
-- |
|
|
-- |
|
|
Subtotal
net deferred tax assets |
|
|
(72,965 |
) |
|
(88,996 |
) |
|
(78,899 |
) |
|
Total |
|
$ |
810,726 |
|
$ |
755,235 |
|
$ |
730,675 |
|
|
PUGET
SOUND ENERGY
(DOLLARS
IN THOUSANDS) |
|
2004 |
|
2003 |
|
2002 |
|
|
Plant
and equipment |
|
$ |
645,826 |
|
$ |
607,203 |
|
$ |
578,137 |
|
|
Capitalized
overhead costs |
|
|
72,448 |
|
|
70,834 |
|
|
72,220 |
|
|
Software
amortization |
|
|
37,484 |
|
|
41,044 |
|
|
41,408 |
|
|
Pensions
and compensation |
|
|
15,367 |
|
|
16,890 |
|
|
29,099 |
|
|
Bonneville
Exchange Power |
|
|
14,078 |
|
|
15,204 |
|
|
15,537 |
|
|
Energy
Efficiency charges |
|
|
10,320 |
|
|
9,446 |
|
|
16,473 |
|
|
Other
deferred tax liabilities |
|
|
63,926 |
|
|
64,511 |
|
|
43,710 |
|
|
Subtotal
deferred tax liabilities |
|
|
859,449 |
|
|
825,132 |
|
|
796,584 |
|
|
Contributions
in aid of construction |
|
|
(41,525 |
) |
|
(46,520 |
) |
|
(44,770 |
) |
|
Other
deferred tax assets |
|
|
(30,745 |
) |
|
(46,668 |
) |
|
(36,235 |
) |
|
Subtotal
deferred tax assets |
|
|
(72,270 |
) |
|
(93,188 |
) |
|
(81,005 |
) |
|
Total |
|
$ |
787,179 |
|
$ |
731,944 |
|
$ |
715,579 |
|
Deferred
tax amounts shown above result from temporary differences for tax and financial
statement purposes. Deferred tax provisions are not recorded in the income
statement for certain temporary differences between tax and financial statement
purposes because they are not allowed for ratemaking purposes.
The
Company calculates its deferred tax assets and liabilities under SFAS No. 109,
“Accounting for Income Taxes.” SFAS No. 109 requires recording deferred tax
balances, at the currently enacted tax rate, for all temporary differences
between the book and tax bases of assets and liabilities, including temporary
differences for which no deferred taxes had been previously provided because of
use of flow-through tax accounting for ratemaking purposes. Because of prior and
expected future ratemaking treatment for temporary differences for which
flow-through tax accounting has been utilized, a regulatory asset for income
taxes recoverable through future rates related to those differences has also
been established by PSE. At December 31, 2004, the balance of this asset was
$127.3 million.
Puget
Energy’s management has determined that a portion of the deferred tax asset
related to InfrastruX goodwill impairment will not be realized and has provided
a valuation allowance of $18.0 million at December 31, 2004 to reduce the
deferred tax asset to its estimated realizable value.
NOTE 13.
Retirement
Benefits
The
Company has a defined benefit pension plan with a cash balance feature covering
substantially all PSE employees. Benefits are a function of age, salary and
service. Additionally Puget Energy maintains a non-qualified supplemental
retirement plan for officers and certain director-level employees. The annual
measurement date is December 31 of each year.
In
addition to providing pension benefits, the Company provides certain health care
and life insurance benefits for retired employees. These benefits are provided
principally through an insurance company whose premiums are based on the
benefits paid during the year.
| |
|
PENSION
BENEFITS |
|
OTHER
BENEFITS |
|
|
(DOLLARS
IN THOUSANDS) |
|
2004 |
|
2003 |
|
2004 |
|
2003 |
|
Change
in benefit obligation: |
|
|
|
|
|
|
|
|
|
|
Benefit
obligation at beginning of year |
|
$ |
400,041 |
|
$ |
369,692 |
|
$ |
29,220 |
|
$ |
31,693 |
|
|
Service
cost |
|
|
10,343 |
|
|
8,284 |
|
|
189 |
|
|
175 |
|
|
Interest
cost |
|
|
24,082 |
|
|
24,406 |
|
|
1,670 |
|
|
1,828 |
|
|
Amendments |
|
|
-- |
|
|
940 |
|
|
-- |
|
|
-- |
|
|
Actuarial
(gain) loss |
|
|
37,628 |
|
|
19,354 |
|
|
963 |
|
|
(2,194 |
) |
|
Special
recognition of prior service costs |
|
|
-- |
|
|
190 |
|
|
-- |
|
|
-- |
|
|
Benefits
paid |
|
|
(32,357 |
) |
|
(22,825 |
) |
|
(2,050 |
) |
|
(2,282 |
) |
|
Benefit
obligation at end of year |
|
$ |
439,737 |
|
$ |
400,041 |
|
$ |
29,992 |
|
$ |
29,220 |
|
Change
in plan assets: |
|
|
|
|
|
|
|
|
|
|
Fair
value of plan assets at beginning of year |
|
$ |
428,586 |
|
$ |
343,960 |
|
$ |
15,431 |
|
$ |
16,160 |
|
|
Actual
return on plan assets |
|
|
51,395 |
|
|
79,488 |
|
|
1,184 |
|
|
98 |
|
|
Employer
contribution |
|
|
11,356 |
|
|
27,963 |
|
|
1,394 |
|
|
1,455 |
|
|
Benefits
paid |
|
|
(32,357 |
) |
|
(22,825 |
) |
|
(2,050 |
) |
|
(2,282 |
) |
|
Fair
value of plan assets at end of year |
|
$ |
458,980 |
|
$ |
428,586 |
|
$ |
15,959 |
|
$ |
15,431 |
|
|
Funded
status |
|
$ |
19,243 |
|
$ |
28,545 |
|
$ |
(14,033 |
) |
$ |
(13,789 |
) |
|
Unrecognized
actuarial (gain) loss |
|
|
72,428 |
|
|
48,217 |
|
|
(2,019 |
) |
|
(2,895 |
) |
|
Unrecognized
prior service cost |
|
|
12,760 |
|
|
15,949 |
|
|
2,403 |
|
|
2,712 |
|
|
Unrecognized
net initial (asset) obligation |
|
|
(163 |
) |
|
(1,267 |
) |
|
3,365 |
|
|
3,783 |
|
|
Net
amount recognized |
|
$ |
104,268 |
|
$ |
91,444 |
|
$ |
(10,284 |
) |
$ |
(10,189 |
) |
|
Amounts
recognized on statement of
financial
position consist of: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prepaid
benefit cost |
|
$ |
120,748 |
|
$ |
112,737 |
|
$ |
-- |
|
$ |
-- |
|
|
Accrued
benefit liability |
|
|
(32,042 |
) |
|
(38,704 |
) |
|
(10,284 |
) |
|
(10,189 |
) |
|
Intangible
asset |
|
|
7,351 |
|
|
9,043 |
|
|
-- |
|
|
-- |
|
|
Accumulated
other comprehensive income |
|
|
8,211 |
|
|
8,368 |
|
|
-- |
|
|
-- |
|
|
Net
amount recognized |
|
$ |
104,268 |
|
$ |
91,444 |
|
$ |
(10,284 |
) |
$ |
(10,189 |
) |
The
projected benefit obligation, accumulated benefit obligation and fair value of
plan assets for the non-qualified pension plan, which has accumulated benefit
obligations in excess of plan assets, were $38.9 million, $31.8 million and
none, respectively, as of December 31, 2004. For the qualified pension plan the
projected benefit obligation, accumulated benefit obligation and fair value of
plan assets were $400.9 million, $380.0 million and $459.0 million,
respectively, as of December 31, 2004.
The
projected benefit obligation, accumulated benefit obligation and fair value of
plan assets for the non-qualified pension plan which has accumulated benefit
obligations in excess of plan assets, were $45.0 million, $38.6 million and
none, respectively, as of December 31, 2003. For the qualified pension plan, the
projected benefit obligation, accumulated benefit obligation and fair value of
plan assets were $355.1 million, $339.7 million and $428.6 million,
respectively, as of December 31, 2003.
In
accounting for pension and other benefit obligations and costs under the plans,
the following weighted average actuarial assumptions were used:
| |
PENSION
BENEFITS |
|
OTHER
BENEFITS |
|
BENEFIT
OBLIGATION ASSUMPTIONS |
2004 |
2003 |
2002 |
|
2004 |
2003 |
2002 |
|
Discount
rate |
5.60% |
6.25% |
6.75% |
|
5.60% |
6.25% |
6.75% |
|
Rate
of compensation increase |
4.50% |
4.50% |
4.50% |
|
-- |
-- |
-- |
|
Medical
trend rate |
-- |
-- |
-- |
|
12.00% |
9.00% |
10.00% |
| |
|
|
|
| |
PENSION
BENEFITS |
|
OTHER
BENEFITS |
|
BENEFIT
COST ASUMPTIONS |
2004 |
2003 |
2002 |
|
2004 |
2003 |
2002 |
|
Discount
rate |
6.25% |
6.75% |
7.25% |
|
6.25% |
6.75% |
7.25% |
|
Return
on plan assets |
8.25% |
8.25% |
9.25% |
|
5-8.25% |
6-7.00% |
6-8.25% |
|
Rate
of compensation increase |
4.50% |
4.50% |
4.50% |
|
-- |
-- |
-- |
|
Medical
trend rate |
-- |
-- |
-- |
|
9.00% |
10.00% |
6.50% |
The
Company has used the expected return on plan assets based on an analysis of
rates of return over the past 50 years relevant to the Company’s investment mix,
market conditions, inflation and other factors. The expected rate of return is
reviewed annually based on these factors and adjusted
accordingly.
| |
|
PENSION
BENEFITS |
|
OTHER
BENEFITS |
|
|
(DOLLARS
IN THOUSANDS) |
|
2004 |
|
2003 |
|
2002 |
|
2004 |
|
2003 |
|
2002 |
|
Components
of net periodic benefit cost: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service
cost |
|
$ |
10,343 |
|
$ |
8,284 |
|
$ |
8,474 |
|
$ |
189 |
|
$ |
175 |
|
$ |
168 |
|
|
Interest
cost |
|
|
24,082 |
|
|
24,406 |
|
|
25,858 |
|
|
1,670 |
|
|
1,828 |
|
|
1,930 |
|
|
Expected
return on plan assets |
|
|
(39,106 |
) |
|
(38,880 |
) |
|
(43,032 |
) |
|
(858 |
) |
|
(934 |
) |
|
(906 |
) |
|
Amortization
of prior service cost |
|
|
3,189 |
|
|
3,220 |
|
|
2,990 |
|
|
309 |
|
|
309 |
|
|
90 |
|
|
Recognized
net actuarial gain |
|
|
1,128 |
|
|
(2,688 |
) |
|
(5,120 |
) |
|
(239 |
) |
|
(341 |
) |
|
(229 |
) |
|
Amortization
of transition (asset) obligation |
|
|
(1,104 |
) |
|
(1,104 |
) |
|
(1,136 |
) |
|
418 |
|
|
418 |
|
|
470 |
|
|
Plan
curtailment |
|
|
-- |
|
|
-- |
|
|
(1,353 |
) |
|
-- |
|
|
-- |
|
|
1,691 |
|
|
Special
recognition of prior service costs |
|
|
-- |
|
|
190 |
|
|
1,683 |
|
|
-- |
|
|
-- |
|
|
-- |
|
|
Net
pension benefit cost (income) |
|
$ |
(1,468 |
) |
$ |
(6,572 |
) |
$ |
(11,636 |
) |
$ |
1,489 |
|
$ |
1,455 |
|
$ |
3,214 |
|
The
aggregate expected contributions by the Company to fund the pension and other
benefit plans for the year ended December 31, 2005 are $2.0 million and $1.4
million, respectively. The full amount of the pension funding for 2005 is for
the Company’s non-qualified supplemental retirement plan.
The fair
value of the plan assets of the pension benefits and other benefits are invested
as follows at December 31:
| |
2004 |
|
2003 |
| |
PENSION
BENEFITS |
OTHER
BENEFITS |
|
PENSION
BENEFITS |
OTHER
BENEFITS |
|
Short-term
investments and cash |
2.4% |
100.0% |
|
3.0% |
100.0% |
|
Equity
securities |
67.8% |
-- |
|
63.8% |
-- |
|
Fixed
income securities |
18.2% |
-- |
|
22.9% |
-- |
|
Mutual
funds (equity and fixed income) |
11.6% |
-- |
|
10.3% |
-- |
The
expected total benefits to be paid under both plans for the next five years and
the aggregate total to be paid for the five years thereafter is as
follows:
|
(Dollars
in Thousands) |
2005 |
|
2006 |
|
2007 |
|
2008 |
|
2009 |
|
2010-2014 |
|
Total
benefits |
$29,768 |
|
$30,202 |
|
$31,256 |
|
$32,904 |
|
$33,253 |
|
$180,516 |
The
assumed medical inflation rate used to determine benefit obligations is 12.0% in
2005 grading to 6.0% in 2011. A 1% change in the assumed medical inflation rate
would have the following effects:
| |
2004 |
|
2003 |
|
|
(DOLLARS
IN THOUSANDS) |
1%
INCREASE |
|
1%
DECREASE |
|
1%
INCREASE |
|
1%
DECREASE |
|
Effect
on post-retirement benefit obligation |
|
$
552 |
|
|
$
(477 |
) |
|
$
589 |
|
|
$
(529 |
) |
Effect
on service and interest cost components |
|
31 |
|
|
(28 |
) |
|
38 |
|
|
(35 |
) |
The
Company has a Retirement Committee that establishes investment policies,
objectives and strategies for the purpose of obtaining the optimum return for
the pension benefit plans, while also keeping with the assumption of prudent
risk and the Retirement Committee’s total return objectives. All changes to the
investment policies are reviewed and approved by the Retirement Committee prior
to being implemented.
The
Retirement Committee contracts with investment managers who have historically
achieved above-median long-term investment performance within the risk and asset
allocation limits that have been established. Interim evaluations are routinely
performed with the assistance of an outside investment consultant. To obtain the
desired return needed to fund the pension benefit plans, the Retirement
Committee has established investment allocation percentages by asset classes as
follows:
| |
ALLOCATION |
|
ASSET
CLASS |
MINIMUM |
TARGET |
MAXIMUM |
|
Short-term
investments and cash |
-- |
|
-- |
|
5% |
|
|
Equity
securities |
40% |
|
70% |
|
95% |
|
|
Fixed-income
securities |
20% |
|
30% |
|
40% |
|
|
Real
estate |
-- |
|
-- |
|
10% |
|
NOTE 14.
Employee
Investment Plans
The
Company has qualified Employee Investment Plans under which employee salary
deferrals and after-tax contributions are used to purchase several different
investment fund options.
Puget
Energy’s contributions to the Employee Investment Plans were $7.6 million, $7.1
million and $6.9 million for the years 2004, 2003 and 2002,
respectively.
PSE’s
contributions to the Employee Investment Plan were $6.3 million, $6.1 million
and $6.1 million for the years 2004, 2003 and 2002, respectively. The Employee
Investment Plan eligibility requirements are set forth in the plan
documents.
NOTE 15.
Stock-based
Compensation Plans
The
Company has various stock compensation plans which, prior to 2003, were
accounted for according to APB No. 25, “Accounting for Stock Issued to
Employees,” and related interpretations as allowed by SFAS No. 123, “Accounting
for Stock-Based Compensation.” In 2003, the Company adopted the fair value based
accounting of SFAS No. 123 using the prospective method under the guidance of
SFAS No. 148, “Accounting for Stock-Based Compensation - Transition and
Disclosure.” The Company applies SFAS No. 123 accounting to stock compensation
awards granted from 2003 on, while grants that were made in years prior to 2003
are accounted for using the intrinsic value method of APB No. 25. Total
compensation expense related to the plans was $4.1 million, $6.4 million and
$6.3 million in 2004, 2003 and 2002, respectively.
The
Company’s shareholder-approved Long-Term Incentive Plan (LTI Plan) encompasses
many of the awards granted to employees. Established in 1995 and amended and
restated in 1997, the LTI Plan applies to officers and key employees of the
Company. Awards granted under this plan include stock awards, performance awards
or other stock-based awards as defined by the plan. Any shares awarded are
purchased on the open market. The maximum number of shares that may be purchased
for the LTI Plan is 1,200,000.
PERFORMANCE
SHARE GRANTS
Each year
the Company awards performance share grants under the LTI Plan. These are
granted to key employees and vest at the end of three years for grants made in
2004 and four years for grants made prior to 2004 with the final number of
shares awarded, and total expense recorded, depending on a performance measure.
Compensation expense related to performance share grants was $2.5 million, $5.1
million and $5.5 million for 2004, 2003 and 2002, respectively. The fair value
of the performance awards granted in 2004, 2003 and 2002 was $19.70, $17.29 and
$14.82, respectively. There were a total of 272,307 performance awards granted
in 2004 of which 16,046 were also forfeited in 2004. In 2003 and 2002 there were
349,912 and 248,158 awards granted, respectively, of which 79,749 and 40,640,
respectively, have been forfeited to date. As of December 31, 2004, there are
four active grant cycles for a total of 730,786 share grants outstanding
although they may not all be awarded.
STOCK
OPTIONS
In 2002,
Puget Energy’s Board of Directors granted 40,000 stock options under the LTI
Plan and an additional 260,000 options outside of the LTI Plan (for a total of
300,000 non-qualified stock options) to the president and chief executive
officer. These options can be exercised at the grant date market price of $22.51
per share and vest yearly over four and five years although vesting is
accelerated under certain conditions. The options expire 10 years from the grant
date. All 300,000 options remained outstanding at December 31, 2004, with
135,000 options exercisable. At December 31, 2003 and 2002, 67,500 options and 0
options, respectively, were exercisable. The fair value of the options at the
grant date was $3.37 per share. Following the intrinsic value method of APB 25,
no compensation expense was recorded for these options.
RESTRICTED
STOCK AND RESTRICTED STOCK UNITS
In 2004,
2003 and 2002 the Company granted 40,000 shares, 11,000 shares and 30,000
shares, respectively, of restricted stock under the LTI Plan to be purchased on
the open market. The 2004 grant vests 8,000 shares in three years, 12,000 shares
in four years and the remaining 20,000 shares in five years. Of the 2003 shares
issued, 1,000 vested in 2003 with the remaining shares vesting evenly over the
following five years. The 2002 shares were fully vested as of December 2003. In
2002, the Company also issued 50,000 shares of restricted stock outside of the
LTI Plan as approved by the Puget Energy Board of Directors. These shares were
recorded as a separate component of stockholders’ equity and vest evenly over a
five-year period. Compensation expense related to the restricted shares was $0.5
million, $0.6 million and $0.5 million in 2004, 2003 and 2002, respectively.
Dividends are paid on all outstanding restricted stock and are accounted for as
a Puget Energy common stock dividend, not as compensation expense. The weighted
average grant date fair value for all outstanding shares of restricted stock
granted in 2004, 2003 and 2002 was $23.55, $23.29 and $21.94,
respectively.
In 2004,
the Company also granted 10,000 restricted stock units outside of the LTI Plan
but subject to the terms and conditions of the plan. The units vest 2,000 shares
in three years, 3,000 shares in four years and the remaining 5,000 shares in
five years. These will be settled in cash as they become vested. Dividends are
paid on the outstanding stock units and are accounted for as compensation
expense. Compensation expense related to the restricted stock units agreement
was $0.1 million in 2004. The weighted average grant date fair value for the
restricted stock units was $23.55.
RETIREMENT
EQUIVALENT STOCK
The
Company has a retirement equivalent stock agreement in which in lieu of
participating in the Company’s executive supplemental retirement plan the
president and chief executive officer is granted performance-based stock
equivalents in January of each year, which are deferred under the Company’s
deferred compensation plan. In 2004 and 2003 the Company awarded 6,469 and 4,319
shares, respectively, which vest over a period of seven years from January 1,
2002 at 15% per year for the first six years and the remaining 10% in the
seventh year. Dividends are paid on the stock equivalents accumulated in the
deferred compensation account in the form of Puget Energy common stock, which is
added to the deferred compensation account. Compensation expense related to the
retirement equivalent stock agreement was $0.1 million in 2004 as well as in
2003. The weighted average grant date fair value for the retirement equivalent
stock was $23.77 and $22.05 for 2004 and 2003 respectively. There were no grants
in 2002.
EMPLOYEE
STOCK PURCHASE PLAN
The
Company has a shareholder-approved Employee Stock Purchase Plan (ESPP) open to
all employees. Offerings occur at six-month intervals at the end of which the
participating employees receive shares for 85% of the lower of the stock’s fair
market price at the beginning or the end of the six-month period. A maximum of
500,000 shares may be sold to employees under the plan. In 2004 and 2003, 52,716
and 38,940 shares were issued for the ESPP, respectively. In 2002, 18,252 shares
were issued and 19,407 shares were purchased for the plan. At December 31, 2004,
206,946 shares may still be sold to employees under the plan. Under the SFAS No.
123 accounting that the Company adopted in 2003, ESPP is considered to be
compensation expense. Total compensation expense related to the ESPP was $0.2
million in 2004 and $0.2 million in 2003. Dividends are not paid on ESPP shares
until they are purchased by employees and thus are accounted for as dividends,
not compensation expense. The weighted average fair value of the purchase rights
granted in 2004, 2003 and 2002 was $3.74, $4.25 and $4.19,
respectively.
INFRASTRUX
STOCK OPTION PLAN
The
InfrastruX stock option plan, established in 2000, has 3,862,500 shares of
InfrastruX stock authorized to be granted to officers, key employees and non
employee directors of InfrastruX. The options generally vest within four years
and expire 10 years from the grant date. The following summarizes InfrastruX
option information for 2004, 2003 and 2002:
| |
|
2004 |
|
2003 |
|
2002 |
|
| |
|
Shares
(in
thousands) |
|
Weighted
Average
Exercise
Price |
|
Shares
(in
thousands) |
|
Weighted
Average
Exercise
Price |
|
Shares
(in
thousands) |
|
Weighted
Average
Exercise
Price |
|
|
Outstanding
at beginning of year |
|
|
2,618 |
|
$ |
4.36 |
|
|
2,643 |
|
$ |
4.31 |
|
|
1,995 |
|
$ |
4.05 |
|
|
Granted |
|
|
10 |
|
|
5.00 |
|
|
176 |
|
|
5.00 |
|
|
725 |
|
|
5.00 |
|
|
Exercised |
|
|
-- |
|
|
-- |
|
|
-- |
|
|
-- |
|
|
-- |
|
|
-- |
|
|
Canceled |
|
|
(99 |
) |
|
4.75 |
|
|
(201 |
) |
|
4.20 |
|
|
(77 |
) |
|
4.09 |
|
|
Outstanding
at end of year |
|
|
2,529 |
|
$ |
4.35 |
|
|
2,618 |
|
$ |
4.36 |
|
|
2,643 |
|
$ |
4.31 |
|
|
Options
exercisable at year end |
|
|
2,056 |
|
$ |
4.20 |
|
|
1,837 |
|
$ |
4.12 |
|
|
802 |
|
$ |
4.02 |
|
|
Weighted
average fair value of options granted
during
the year |
|
$2.41 |
$2.41 |
$2.23 |
The
following summarizes InfrastruX’s outstanding option information at December 31,
2004:
| |
Shares
Outstanding
(in
thousands) |
Weighted
Average
Contractual
Life
(in
years) |
Weighted
Average
Exercise
Price |
|
Exercise
Prices |
|
|
|
|
$4.00 |
1,641 |
|
6.10 |
|
$
4.00 |
|
|
$5.00 |
888 |
|
7.47 |
|
5.00 |
|
| |
2,529 |
|
6.59 |
|
$
4.35 |
|
Stock
options awarded under the InfrastruX plan were generally granted at the
InfrastruX market price on the date of grant although some options were granted
at a discount requiring InfrastruX to record compensation expense. With those
options and the prospective adoption of SFAS No. 123 fair value accounting in
2003, InfrastruX recorded compensation expense related to options granted in
2004, 2003 and 2002 of $0.1 million, $0.2 million and $0.1 million,
respectively.
NON-EMPLOYEE
DIRECTOR STOCK PLAN
The
Company has a director stock plan approved in 1997 and effective beginning in
1998, for all non employee directors of Puget Energy and PSE. Under the plan,
which has a 10-year term, and which, subject to shareholder approval, will be
amended and restated at the May 2005 Annual Meeting, non employee directors
receive a minimum of two-thirds of their quarterly retainer fees in Puget Energy
stock except that 100% of quarterly retainers are paid in Puget Energy stock
until the director holds a number of shares equal in value to two years of their
retainer fees. Directors may optionally receive their entire retainer in Puget
Energy stock. The compensation expense related to the director stock plan was
$0.6 million, $0.4 million and $0.2 million in 2004, 2003 and 2002,
respectively. The Company issues new shares or purchases stock for this plan on
the open market up to a maximum of 100,000 shares. As of December 31, 2004,
15,230 shares had been issued or purchased for the director stock plan and
64,838 deferred, for a total of 80,068 shares. As of December 31, 2003 and 2002
the number of shares that had been purchased for the director stock plan was
9,902 and 6,916, respectively, and the number that had been deferred was 48,219
and 36,117, respectively, for a total of 58,121 and 43,033 shares,
respectively.
The
Company used the Black-Scholes option pricing model to determine the fair value
of certain stock-based awards to employees. The following assumptions were used
for awards granted in 2004, 2003 and 2002:
| |
|
2004 |
2003 |
2002 |
Stock
options |
|
|
|
|
|
|
|
|
|
|
|
Risk-free
interest rate |
|
|
-- |
|
|
-- |
|
|
4.32 |
% |
|
Expected
lives -
years |
|
|
-- |
|
|
-- |
|
|
4.50 |
|
|
Expected
stock volatility |
|
|
-- |
|
|
-- |
|
|
23.62 |
% |
|
Dividend
yield |
|
|
-- |
|
|
-- |
|
|
5.00 |
% |
|
InfrastruX
stock option plan |
|
|
|
|
|
|
|
|
|
|
|
Risk-free
interest rate |
|
|
2.8 |
% |
|
2.8 |
% |
|
4.05 |
% |
|
Expected
lives -
years |
|
|
4.0 |
|
|
4.0 |
|
|
4.0 |
|
|
Expected
stock volatility |
|
|
70.0 |
% |
|
70.0 |
% |
|
70.0 |
% |
|
Performance
awards |
|
|
|
|
|
|
|
|
|
|
|
Risk-free
interest rate |
|
|
2.59 |
% |
|
2.35 |
% |
|
4.0 |
% |
|
Expected
lives -
years |
|
|
3.0 |
|
|
4.0 |
|
|
4.0 |
|
|
Expected
stock volatility |
|
|
22.24 |
% |
|
23.85 |
% |
|
23.71 |
% |
|
Dividend
yield |
|
|
4.45 |
% |
|
4.86 |
% |
|
8.85 |
% |
|
Employee
Stock Purchase Plan |
|
|
|
|
|
|
|
|
|
|
|
Risk-free
interest rate |
|
|
1.28 |
% |
|
1.07 |
% |
|
1.65 |
% |
|
Expected
lives - years |
|
|
0.5 |
|
|
0.5 |
|
|
0.5 |
|
|
Expected
stock volatility |
|
|
9.89 |
% |
|
19.47 |
% |
|
26.97 |
% |
|
Dividend
yield |
|
|
4.42 |
% |
|
4.39 |
% |
|
5.81 |
% |
NOTE 16.
Accounting
for Derivative Instruments and Hedging Activities
SFAS No.
133, “Accounting for Derivative Instruments and Hedging Activities,” as amended
by SFAS No. 138 and SFAS No. 149, requires that all contracts considered to be
derivative instruments be recorded on the balance sheet at their fair value. The
Company enters into both physical and financial contracts to manage its energy
resource portfolio and interest rate exposure including forward physical and
financial contracts, option contracts and swaps. The majority of these contracts
qualify for the normal purchase normal sale exception. Those contracts that do
not meet normal purchase normal sale exception or cash flow hedge criteria are
marked-to-market to current earnings in the income statement, subject to
deferral under SFAS No. 71 “Accounting for the Effects of Certain Types of
Regulation,” (SFAS No. 71) for energy related derivatives due to the Power Cost
Adjustment (PCA) mechanism.
The
nature of serving regulated electric customers with its wholesale portfolio of
owned and contracted resources exposes the Company and its customers to some
volumetric and commodity price risks within the sharing mechanism of the PCA.
The Company’s energy risk management function monitors and manages these risks
using analytical models and tools.
The
Company is not engaged in the business of assuming risk for the purpose of
speculative trading revenues. Therefore, wholesale market transactions are
focused on balancing the Company’s energy portfolio, reducing costs and risks
where feasible, and reducing volatility in wholesale costs and margin in the
portfolio. In order to manage risks effectively, the Company enters into
physical and financial transactions, which are appropriate for the service
territory of the Company and are relevant to its regulated electric and gas
portfolios.
The
Company’s energy risk management staff develops hedging strategies for the
Company’s energy supply portfolio. The first priority is to obtain reliable
supply for delivery to the Company’s retail customers. The second priority is to
protect against unwanted risk exposure. The third priority is to optimize excess
capacity or flexibility within the energy portfolio.
The
Company has entered into master netting agreements with counterparties when
available to mitigate credit exposure to those counterparties. The Company
believes that entering into such agreements reduces risk of settlement default
for the ability to make only one net payment. In addition, the Company believes
risk is mitigated with an improved position in potential counterparty bankruptcy
situations due to a consistent netting approach.
At
December 31, 2004, the Company was subject to a range of netting provisions,
including both stand alone agreements and the provisions associated with the
Western Systems Power Pool agreement of which many energy suppliers in the
western United States are a part.
For the
year ended December 31, 2004, the Company recorded an increase in earnings of
approximately $0.5 million compared to a decrease of $0.1 million for 2003. Of
the 2004 gain, $0.7 million unrealized gain represented cash flow hedges that
were de-designated and reclassified from other comprehensive income into
earnings. As of December 31, 2004, the Company had an unrealized loss recorded
in other comprehensive income of $6.5 million after-tax related to contracts
which meet the criteria for designation as cash flow hedges under SFAS No. 133.
In 2004, a portion of the total unrealized gain of cash flow hedge transactions
in other comprehensive income and marked-to-market gain in the income statement
were deferred under SFAS No. 71 due to the Company expecting to reach the $40
million cap under the PCA mechanism in the first quarter 2005. When these
transactions are realized they will be reflected in the PCA mechanism
calculation. As of December 31, 2003, the Company had an unrealized gain
recorded in other comprehensive income of $0.2 million (net of tax) related to
energy contracts which meet the criteria for designation as cash flow hedges
under SFAS No. 133. The amount of cash flow hedges associated with these energy
contracts that will reverse and be settled into the income statement during 2005
is approximately $0.7 million.
PSE has a
contract with a counterparty whose debt ratings have been below investment grade
since 2002. The contract, a physical gas supply contract for one of PSE’s
electric generating facilities, was marked-to-market beginning in the fourth
quarter 2003. Although the counterparty continues to fully perform on the
physical supply contract, the counterparty’s credit ratings have remained weak.
Prior to October 1, 2003, the contract was designated as a normal purchase under
SFAS No. 133. PSE has concluded that it is appropriate to reserve the
mark-to-market gain on this contract due to the credit quality of the
counterparty in accordance with SFAS No. 133 guidance, as management deemed that
delivery is not probable through the term of the contract, which expires
December 2008. There was no impact on earnings for the 12 months ended December
31, 2004 and 2003.
In the
first quarter 2004, the counterparty of another physical gas supply contract for
one of PSE’s electric generating facilities notified PSE that it would be unable
to deliver physical gas supply beginning in November 2005 through the end of the
contract in June 2008. Since physical delivery for the life of the contract was
no longer probable, the contract no longer met the criteria for normal purchase
exception under SFAS No. 133. Therefore, the contract was marked-to-market in
the first quarter 2004, with an offsetting reserve for the portion of the
mark-to-market gain applicable to the impaired period of November 2005 through
June 2008. In October 2004, PSE and the counterparty reached a settlement on the
non-deliverable period of November 2005 through June 2008. The agreement allows
PSE to recover a portion of the present value of the difference in future market
prices of physical gas and the original contract price, for a total recovery of
approximately $10.1 million. In the fourth quarter 2004, an accounting order was
approved by the Washington Commission to defer the counterparty settlement
amount as a regulatory liability and amortize the benefit over the period of
November 2005 through June 2008 as a reduction in Electric Generation Fuel
expense. The amended contract meets the criteria for normal purchase exception
under SFAS No. 133 since delivery for the life of the contract is probable. In
October 2004, PSE entered into a new contract with another counterparty for the
period November 2005 through June 2008 to replace the physical gas supply from
the previously mentioned amended contract. This new contract meets the normal
purchase exception under SFAS No. 133.
The
Company entered into treasury lock transactions to hedge against the potential
rising treasury rate component of the interest rate on planned debt issuances.
The purpose of the treasury lock is to lock in the base component of the
interest rate on the planned issuance at current period favorable levels.
In the
third quarter 2004, the Company entered into two treasury lock contracts to
hedge against potential rising interest rate exposure for a debt offering
anticipated to be performed in the first half of 2005. A treasury lock is a
financial arrangement between the Company and a counterparty whereby one of the
parties will be required to make a payment to the other party on a specific
valuation date based upon the change in value of a 30 year treasury bond. If
interest rates rise related to the hedged debt from the date of issuance of the
treasury lock instruments, the Company would receive a payment from the
counterparty for the change in the bond value. Alternatively, if interest rates
decrease related to the hedged debt from the date of issuance of the treasury
lock instruments, the Company would pay the counterparty for the change in bond
value. These treasury lock contracts were designated under SFAS No. 133 criteria
as cash flow hedges, with all changes in market value for each reporting period
being presented net of tax in other comprehensive income. When these treasury
lock contracts are settled upon issuance of debt, any gain or loss will be
amortized from other comprehensive income to interest expense over the 30 year
life of the issued debt. At December 31, 2004, the unrealized loss associated
with these two treasury lock contracts was $11.3 million ($7.4 million net of
tax) and is included in other comprehensive income. Both treasury rate lock
hedges will settle in 2005.
NOTE 17.
Acquisitions
(Puget Energy Only)
During
2002, InfrastruX acquired 100% of three companies based in Texas for a total
price of $49.7 million, and during the second quarter 2003 acquired 100% of one
additional company based in New Mexico for $11.8 million. InfrastruX made no
acquisitions in 2004. All purchases were funded in the form of cash and
preferred or common stock.
These
companies provide utility infrastructure services which are relevant to
InfrastruX’s operating strategy including: installing, replacing and restoring
underground cables and pipes for utilities and telecommunications providers;
pipeline construction, maintenance and rehabilitation services for the natural
gas and petroleum industries, including directional drilling and vacuum
excavation; and distribution and transmission-oriented overhead electric
construction services to electric utilities and cooperatives.
The
acquisitions have been accounted for using the purchase method of accounting
and, accordingly, the operating results of these companies have been included in
Puget Energy’s consolidated financial statements since their acquisition dates.
Goodwill additions representing the excess of cost over the net tangible and
identifiable intangible assets at the time of purchase were approximately $7.7
million in 2003 and $23.5 million in 2002. Of the additions to goodwill in 2003
and 2002, no amounts were deductible for calculating income tax
expense.
The pro
forma combined revenue, net income and earnings per common share of Puget Energy
presented below give effect to the acquisitions as if they had occurred on
January 1, 2002. These results are not necessarily indicative of the results of
operations that would have occurred had the acquisitions of these companies been
consummated for the period for which they are being given effect. There were no
acquisitions in 2004.
|
(DOLLARS
IN THOUSANDS, EXCEPT
PER SHARE AMOUNTS)
(UNAUDITED)
FOR
THE YEARS ENDED DECEMBER 31 |
|
2003 |
|
2002 |
|
|
Operating
revenues |
|
$ |
2,396,802 |
|
$ |
2,391,981 |
|
|
Net
income |
|
|
116,636 |
|
|
112,813 |
|
|
Basic
earnings per common share |
|
$ |
1.23 |
|
$ |
1.28 |
|
|
Diluted
earnings per common share |
|
$ |
1.22 |
|
$ |
1.27 |
|
NOTE
18.
Goodwill
and Intangibles (Puget Energy Only)
Effective
January 1, 2002, Puget Energy adopted SFAS No. 142, “Goodwill and Other
Intangible Assets,” which required all goodwill amortization to cease on January
1, 2002. Puget Energy allocates goodwill to reporting units based on the excess
purchase price over tangible and identifiable intangible assets. SFAS No. 142
also requires Puget Energy to perform an annual impairment review of goodwill.
In addition to the annual review, Puget Energy is required to perform an
impairment review at the time an event or circumstance arises that would
indicate the fair value would be below its carrying value. In the fourth quarter
2004, as part of its annual goodwill review, Puget Energy recorded a non-cash
goodwill impairment of $91.2 million ($76.6 million after tax and after minority
interest) to operating expenses related to its investment in InfrastruX. The
valuation of the goodwill was based on the present value of the future cash
flows of estimated earnings of InfrastruX which reflect prospective market price
information from prospective buyers. In 2004, Puget Energy began evaluating its
strategic options for its InfrastruX investment and on February 8, 2005 Puget
Energy decided to exit this utility construction services business.
Identifiable
assets acquired as a result of acquisitions of companies are amortized based on
the expected pattern of use or on a straight-line basis over the expected
periods to be benefited, which ranges from 5 to 20 years. In 2004, a patent was
completed and added to intangibles for $0.1 million with an amortization period
of 16 years. In 2003, a total of $2.1 million was added to intangible assets
- assigned
$0.1 million to patents with an amortization period of 17 years, $1.7 million to
contractual customer relationships with an amortization period of 10 years and
$0.3 million to covenant not to compete with an amortization period of five
years. The total weighted average amortization period for the 2003 additions is
9.6 years.
|
(DOLLARS
IN THOUSANDS) |
|
Intangibles |
|
Accumulated
Amortization |
|
Net
Intangibles |
|
|
Covenant
not to compete |
|
$ |
4,178 |
|
$ |
2,748 |
|
$ |
1,430 |
|
|
Developed
technology |
|
|
14,190 |
|
|
3,163 |
|
|
11,027 |
|
|
Contractual
customer relationships |
|
|
4,702 |
|
|
1,374 |
|
|
3,328 |
|
|
Patents |
|
|
986 |
|
|
91 |
|
|
895 |
|
|
Total |
|
$ |
24,056 |
|
$ |
7,376 |
|
$ |
16,680 |
|
|
(DOLLARS
IN THOUSANDS) |
|
Gross
Intangibles |
|
Accumulated
Amortization |
|
Net
Intangibles |
|
|
Covenant
not to compete |
|
$ |
4,178 |
|
$ |
2,009 |
|
$ |
2,169 |
|
|
Developed
technology |
|
|
14,190 |
|
|
2,454 |
|
|
11,736 |
|
|
Contractual
customer relationships |
|
|
4,702 |
|
|
747 |
|
|
3,955 |
|
|
Patents |
|
|
915 |
|
|
68 |
|
|
847 |
|
|
Total |
|
$ |
23,985 |
|
$ |
5,278 |
|
$ |
18,707 |
|
The
identifiable intangible amortization expense for the year ended December 31,
2004 was $2.1 million compared to $2.1 million and $1.9 million for 2003 and
2002, respectively. The identifiable intangible assets amortization for future
periods based on the current acquisitions will be:
|
(Dollars
in Thousands) |
2005 |
2006 |
2007 |
2008 |
2009 |
|
Future
intangible amortization |
$
2,207 |
$1,732 |
$1,385 |
$1,301 |
$1,276 |
NOTE 19.
Tenaska
Disallowance
The
Washington Commission issued an order on May 13, 2004 determining that PSE did
not prudently manage gas costs for the Tenaska electric generating plant and
ordered PSE to adjust its PCA deferral account to reflect a disallowance of
$25.6 million for the PCA 1 period (July 1, 2002 through June 30, 2003), which
was recorded by PSE as a Purchased Electricity expense in the second quarter
2004. The order also established guidelines for future recovery of Tenaska
costs. The amounts were determined to be a $25.6 million disallowance for the
PCA 1 period and an estimated disallowance of $11.3 million for the PCA 3 period
(July 1, 2004 to June 30, 2005), based upon applying the Washington Commission’s
methodology of 50% disallowance on the return on the Tenaska regulatory asset
due to projected costs exceeding the benchmark during the period. For the PCA 3
period, approximately $5.6 million was disallowed in the period July 1, 2004
through December 31, 2004, primarily as a reduction to Electric Operating
Revenue. While the Washington Commission did not expressly address the
disallowance for the PCA 2 period (July 1, 2003 through June 30, 2004), PSE
estimated the disallowance for the PCA 2 period to be approximately $12.2
million if the Washington Commission were to follow the same methodology as they
have ordered for the PCA 3 period. Therefore, PSE recorded a $12.2 million
disallowance to Purchased Electricity expense in the second quarter 2004 for the
50% disallowance of the return on the Tenaska regulatory asset in accordance
with the Washington Commission’s methodology discussed in their order of May 13,
2004 for a cumulative impact on earnings of $43.4 million in 2004 for the PCA 1,
PCA 2 and PCA 3 periods. As a result of the disallowance recorded, the PCA
customer deferral was expensed and a reserve was established for amounts not
previously deferred under the PCA mechanism. The reserve balance as of December
31, 2004 was $3.2 million, which is expected to be utilized in 2005 as excess
power costs are shared through the PCA mechanism.
PSE filed
the PCA 2 period compliance filing in August 2004 and received an order from the
Washington Commission on February 23, 2005. In the PCA 2 compliance order, the
Washington Commission approved the Washington Commission staff’s recommendation
for an additional return related to the Tenaska regulatory asset in the amount
of $6.1 million related to the period July 1, 2003 through December 31, 2003.
Washington Commission staff’s recommendation was opposed by certain other
parties. This amount alters the PCA deferral and is subject to reconsideration
and appeal by other parties. Parties have 10 days from February 23, 2005 to file
for reconsideration and 30 days to appeal the order. Once the statutory appeal
process has concluded and the Washington Commission issues its final order, PSE
will determine if recording a regulatory asset is appropriate.
In the
May 13, 2004 order, the Washington Commission established guidelines and a
benchmark to determine PSE’s recovery on the Tenaska regulatory asset starting
with the PCA 3 period (July 1, 2004) through the expiration of the Tenaska
contract in the year 2011. The benchmark is defined as the original cost of the
Tenaska contract adjusted to reflect the 1.2% disallowance from a 1994 Prudence
Order.
Below is
a summary of the Tenaska disallowances by quarter through December 31,
2004:
|
(DOLLARS
IN MILLIONS)
QUARTER
ENDING |
|
|
7/02
- 6/03
PCA
1
(ordered/final |
) |
|
7/03
- 6/04
PCA
2
(estimated |
) |
|
7/04
- 12/04
PCA
3
(estimated |
) |
|
Total |
|
|
|
|
$ |
25.6 |
|
$ |
12.2 |
|
$ |
-- |
|
$ |
37.8 |
|
|
|
|
|
-- |
|
|
-- |
|
|
2.8 |
|
|
2.8 |
|
|
|
|
|
-- |
|
|
-- |
|
|
2.8 |
|
|
2.8 |
|
|
Total |
|
$ |
25.6 |
|
$ |
12.2 |
|
$ |
5.6 |
|
$ |
43.4 |
|
The
Washington Commission guidelines for determining future recovery of the Tenaska
costs (gas costs, recovery of the Tenaska regulatory asset and return on the
Tenaska regulatory asset) are as follows:
| 1. |
The
Washington Commission will determine if PSE’s gas purchasing plan and gas
purchases for Tenaska are prudent through the PCA compliance filings.
|
| 2. |
If
PSE’s gas purchasing plan and gas purchases for Tenaska are prudent, and
if PSE’s actual Tenaska costs fall at or below the benchmark, it will
recover fully its Tenaska costs. |
| 3. |
If
PSE’s gas purchasing plan and gas purchases for Tenaska are prudent, but
its actual Tenaska costs exceed the benchmark, PSE will only recover 50%
of the lesser of: |
| a) |
actual
Tenaska costs that exceed the benchmark or; |
| b) |
the
return on the Tenaska regulatory asset. |
| 4. |
If
PSE’s gas purchasing plan or gas purchases are found to be imprudent in a
future proceeding, PSE risks disallowance of any and all Tenaska costs.
|
The
Washington Commission confirmed that if the Tenaska gas costs are deemed
prudent, PSE will recover the full amount of actual gas costs and the recovery
of the Tenaska regulatory asset even if the benchmark is exceeded.
NOTE 20.
Colstrip
Matters
In
September 2004, the owners of Colstrip Units 1 & 2 (PSE and PPL Montana)
entered into a tentative settlement agreement with certain homeowners in the
Colstrip town site area concerning a lawsuit filed in May 2003. In December
2004, the plaintiffs retained new counsel and postponed further settlement
discussions until more discovery is completed. The lawsuit alleged certain
domestic water wells may have been contaminated by seepage from a Colstrip Units
1 & 2 effluent holding pond. The tentative settlement agreement would
require extending municipal water to the homeowners and abandoning the existing
wells. The total estimated cost of the settlement ranges from $1.4 million to
$1.5 million. As a result of this tentative settlement agreement, PSE recorded a
$0.7 million reserve in the third quarter 2004 for its 50% ownership of the
Colstrip Units 1 & 2 project. The settlement agreement would not resolve
certain other claims by residents within the city limits. PSE cannot predict the
outcome or any potential financial impact of the claims by the residents within
the city limits at this time.
In June
2004, PSE and Western Energy Company (WECO), the supplier of coal to Colstrip
Units 1 & 2, entered into a binding arbitration and settled a dispute
concerning prices paid for coal supplied. The binding decision retroactively set
a new baseline cost per ton of coal purchased by PSE for Colstrip Units 1 &
2 supplied from July 31, 2001, and is applicable for the remaining term of the
coal supply agreement through December 2009. The decision resulted in a $6.9
million charge that was recorded in the second quarter 2004. Of the $6.9 million
charge, $5.0 million was included in the PCA mechanism. PSE had previously
accrued a $1.6 million reserve in the fourth quarter 2003 related to the
arbitration.
On April
29, 2004, the Minerals Management Service of the United States Department of the
Interior (MMS) issued an order to WECO to pay additional royalties concerning
coal purchased by PSE for Colstrip Units 3 & 4. The order seeks payment of
an additional $1.1 million in royalties for coal mined from federal land between
1997 and June 30, 2000. During that period, PSE’s coal price was reduced by a
settlement agreement entered into in February 1997 among PSE, WECO and Montana
Power Company that resolved disputes that were then pending. The order seeks to
impute the price charged to PSE based on the other Colstrip Units 3 & 4
owners’ contractual amounts. PSE is supporting WECO’s appeal of the order, but
is also evaluating the basis of the claim. PSE accrued a loss reserve in the
amount of $1.1 million in connection with this matter in the second quarter
2004.
In
addition, the MMS issued two orders to WECO in 2002 and 2003 to pay additional
royalties concerning coal sold to Colstrip Units 3 & 4 owners. The orders
assert that additional royalties are owed as a result of WECO not paying
royalties in connection with revenue received by WECO from the Colstrip Units 3
& 4 owners under a coal transportation agreement during the period October
1, 1991 through December 31, 2001. PSE’s share of the alleged additional
royalties is $1.8 million, which is equivalent to PSE’s 25% ownership interest
in Colstrip Units 3 & 4. Other parties may attempt to assert claims against
WECO if the MMS position prevails. The transportation agreement provides for the
construction and operation of a conveyor system that runs several miles from the
mine to Colstrip Units 3 & 4. WECO has appealed these orders and PSE is
monitoring the process. PSE believes that Colstrip Units 3 & 4 owners have
reasonable defenses in this matter based upon its review. Neither the outcome of
this matter nor the associated costs can be predicted at this time.
On
December 5, 2003, Colstrip Units 1 & 2 and 3 & 4 received an information
request from the Environmental Protection Agency (EPA) relating to their
compliance with the Clean Air Act New Source Review regulations. PSE is
currently in discussions with the EPA concerning the information request.
Neither the outcome of this matter nor any potential associated costs can be
predicted at this time.
NOTE 21.
Taxes
Other Than Income Taxes
|
PUGET
ENERGY
(DOLLARS
IN THOUSANDS) |
|
2004 |
|
2003 |
|
2002 |
|
Taxes
other than income taxes: |
|
|
|
|
|
|
|
|
Real
estate and personal property |
|
$ |
45,121 |
|
$ |
45,660 |
|
$ |
48,890 |
|
|
State
business |
|
|
82,408 |
|
|
75,523 |
|
|
77,527 |
|
|
Municipal
and occupational |
|
|
72,405 |
|
|
64,861 |
|
|
67,770 |
|
|
Other |
|
|
39,479 |
|
|
38,273 |
|
|
37,029 |
|
|
Total
taxes other than income taxes |
|
$ |
239,413 |
|
$ |
224,317 |
|
$ |
231,216 |
|
|
Charged
to: |
|
|
|
|
|
|
|
|
|
|
|
Operating
expense |
|
$ |
221,980 |
|
$ |
208,395 |
|
$ |
215,429 |
|
|
Other
accounts, including construction work in progress |
|
|
17,433 |
|
|
15,922 |
|
|
15,787 |
|
|
Total
taxes other than income taxes |
|
$ |
239,413 |
|
$ |
224,317 |
|
$ |
231,216 |
|
|
PUGET
SOUND ENERGY
(DOLLARS
IN THOUSANDS) |
|
2004 |
|
2003 |
|
2002 |
|
Taxes
other than income taxes: |
|
|
|
|
|
|
|
|
Real
estate and personal property |
|
$ |
43,843 |
|
$ |
44,757 |
|
$ |
48,408 |
|
|
State
business |
|
|
82,408 |
|
|
75,524 |
|
|
77,527 |
|
|
Municipal
and occupational |
|
|
72,405 |
|
|
64,861 |
|
|
67,770 |
|
|
Other |
|
|
27,766 |
|
|
25,638 |
|
|
24,463 |
|
|
Total
taxes other than income taxes |
|
$ |
226,422 |
|
$ |
210,780 |
|
$ |
218,168 |
|
|
Charged
to: |
|
|
|
|
|
|
|
|
|
|
|
Operating
expense |
|
$ |
208,989 |
|
$ |
194,857 |
|
$ |
202,381 |
|
|
Other
accounts, including construction work in progress |
|
|
17,433 |
|
|
15,923 |
|
|
15,787 |
|
|
Total
taxes other than income taxes |
|
$ |
226,422 |
|
$ |
210,780 |
|
$ |
218,168 |
|
NOTE 22.
Other
On
September 24, 2004, the Washington Commission approved PSE’s request for a
Purchased Gas Adjustment (PGA) mechanism rate increase filed on August 31, 2004.
The approved request will increase rates and revenues by approximately 17.6% or
$121.7 million annually. The increase in PGA mechanism rates was to recover
higher market prices of natural gas sold to customers. The PGA mechanism passes
through to customers increases or decreases in the gas supply portion of the
natural gas service rates based upon changes in gas prices. PSE’s gas margin and
net income are not affected by the change in PGA mechanism rates.
In 2003,
the Washington Commission’s Pipeline Safety staff conducted a natural gas
standard inspection for three counties within Washington State in which PSE
operates gas pipelines. The inspection included a review of procedures, records
and operations and maintenance activities. On June 29, 2004, the Washington
Commission issued a complaint to PSE related to that inspection, alleging
certain violations of Washington Commission regulations. In December 2004, PSE
and the Washington Commission resolved the issues. PSE agreed to a penalty of
$0.5 million, and also agreed to update certain natural gas operating practices.
In addition, the resolution included the potential for future penalties of up to
$0.2 million in the next ten years if certain operational goals are not met. The
Washington Commission approved the settlement on January 31, 2005.
In
September 2004, a natural gas fire destroyed a home and took the life of a PSE
customer. The cause of the fire remains under investigation by PSE, the
Washington Commission and other parties. PSE has tendered the matter to its
general liability insurer. Neither the potential regulatory nor litigation
outcomes of this matter nor the final associated costs can be predicted at this
time.
On
February 18, 2005, the Washington Commission approved a 3.5% general tariff gas
rate case increase and a 4% general tariff electric rate case increase. The
increases were $26.3 million annually for gas customers and $56.6 million for
electric customers effective March 4, 2005. In the order, the Washington
Commission also approved a capital structure of 43% common equity with a return
on common equity of 10.3%.
On April
23, 2004, the acquisition of a 49.85% interest in the Frederickson 1 generating
facility was approved by FERC. Prior to that approval, on April 7, 2004, the
Washington Commission had issued an order in PSE’s power cost only rate case
granting approval for the acquisition of the Frederickson 1 generating facility.
As a result of these approvals, PSE completed the acquisition in the second
quarter 2004 and added $80.8 million in utility plant. In its order, the
Washington Commission found the acquisition to be prudent and the costs
associated with the generating facility reasonable. The costs associated with
the generating facility, including projected baseline gas costs, are approved
for recovery in rates. On May 13, 2004, the Washington Commission also approved
other adjustments to power costs that resulted in an increase of cost recovery
in rates of $44.1 million annually, beginning May 24, 2004, which includes the
ownership, operation and fuel costs of the Frederickson 1 generating
facility.
In
December 2003, PSE notified FERC that it rejected the 1997 license for the White
River project because the 1997 license contained terms and conditions that
rendered ongoing operations of the project uneconomical relative to alternative
resources. As a result, generation of electricity ceased at the White River
project on January 15, 2004. At December 31, 2004, the White River project net
book value totaled $65.1 million, which included $46.4 million of net utility
plant, $14.8 million of capitalized FERC licensing costs, $3.1 million of costs
related to construction work in progress and $0.8 million related to dam
operation and safety. PSE is sought recovery of the relicensing, other
construction work in progress and dam operations and safety costs totaling $18.7
million in its general rate filing of April 2004, over a 10-year amortization
period. In the third quarter 2004, the Washington Commission staff recommended
that PSE be allowed recovery of the White River net utility plant costs noted
above, but defer any amortization of the FERC licensing and other costs until
all costs and any sales proceeds are known. In its February 18, 2005 general
rate case order, the Washington Commission found this treatment reasonable, and
adopted all of the staff recommendations.
PSE has
minority ownership interests in a venture capital fund established as a limited
liability corporation that seeks long-term capital appreciation by making
capital investments in energy sector related businesses. The Company’s ownership
interest in the fund is less than 20% and the managing members of the limited
liability corporation have sole discretion over fund operations, management and
investment decisions. Under the terms of the limited liability corporation
agreement establishing the fund, the fund terminates December 31, 2007. The
Company’s carrying value of the investment in the fund totaled $1.9 million at
December 31, 2004, which includes a $6.1 million pre-tax loss on the Company’s
original cost basis in the fourth quarter 2003. Based on the guidance from EITF
No. 03-16, the Company started accounting for its investment in the fund using
the equity method accounting. The adoption of the equity method had no
cumulative effect on earnings for the year ended December 31, 2004 as PSE had
been carrying this investment at fair value, which represents the equity basis,
since December 31, 2003. The Company’s future funding obligation to this fund is
$0.3 million.
On
November 1, 1999, PSE acquired Encogen Northwest, LP (Encogen) whose sole asset
is a natural gas-fired cogeneration facility located in Washington State. With
the approval of the Washington Commission, the Encogen facility has been
operated as part of PSE’s least cost generation dispatch portfolio to serve its
native load obligations since it was acquired in 1999. Two wholly-owned
subsidiaries of PSE, GP Acquisition Corporation and LP Acquisition Corporation,
are the general and limited partners of Encogen, respectively. On December 29,
2004, PSE filed an application with FERC pursuant to Section 203 of the FPA to
transfer the Encogen facility to PSE and eliminate the various subsidiaries via
an Agreement and Plan of Merger (Merger). On February 15, 2005, FERC issued an
order authorizing the Encogen plant to be transferred to PSE. PSE anticipates
completing the merger in 2005.
NOTE 23.
Commitments
and Contingencies
For the
year ended December 31, 2004, approximately 23.1% of the Company’s energy output
was obtained at an average cost of approximately $0.0146 per kWh through
long-term contracts with several of the Washington Public Utility Districts
(PUDs) owning hydroelectric projects on the Columbia River.
The
purchase of power from the Columbia River projects is on a “cost-of-service”
basis under which the Company pays a proportionate share of the annual cost of
each project in direct proportion to the amount of power annually purchased by
the Company from such project. Such payments are not contingent upon the
projects being operable. These projects are financed through substantially level
debt service payments, and their annual costs should not vary significantly over
the term of the contracts unless additional financing is required to meet the
costs of major maintenance, repairs or replacements, or license requirements.
The Company’s share of the costs and the output of the projects is subject to
reduction due to various withdrawal rights of the PUDs and others over the lives
of the contracts.
As of
December 31, 2004, the Company was entitled to purchase portions of the power
output of the PUDs’ projects as set forth in the following
tabulation:
| |
|
|
TOTAL
BONDS |
COMPANY'S
ANNUAL AMOUNT |
| |
|
|
OUTSTANDING |
PURCHASABLE
(APPROXIMATE) |
| |
CONTRACT |
LICENSE 1 |
12/31/04
2 |
%
OF |
MEGAWATT |
COST
3 |
|
PROJECT |
EXP.
DATE |
EXP.
DATE |
(MILLIONS) |
OUTPUT |
CAPACITY |
(MILLIONS) |
|
Rock
Island |
|
|
|
|
|
|
|
Original
units |
2012 |
|
2029 |
|
$
115.8 |
|
50.0 |
} |
414 |
|
$
40.8 |
|
|
Additional
units |
2012 |
|
2029 |
|
328.4 |
|
75.0 |
|
Rocky
Reach |
2011 |
|
2006 |
|
383.0 |
|
38.9 |
505 |
|
24.7 |
|
|
Wells |
2018 |
|
2012 |
|
143.3 |
|
31.3 |
261 |
|
5.2 |
|
|
Priest
Rapids 4 |
2005 |
|
2005 |
|
179.7 |
|
8.0 |
72 |
|
2.4 |
|
|
Wanapum
4 |
2009 |
|
2005 |
|
181.6 |
|
10.8 |
98 |
|
3.3 |
|
|
Total |
|
|
$
1,331.8 |
|
|
1,350 |
|
$
76.4 |
|
_____________________
| 1 |
The
Company is unable to predict whether the licenses under the Federal Power
Act will be renewed to the current licensees. FERC
has issued orders for the Rocky Reach, Wells and Priest Rapids/Wanapum
projects under Section 22 of the Federal Power Act, which affirm
the
Company’s
contractual rights to receive power under existing terms and conditions
even if a new licensee is granted a license prior to expiration of the
contract term. |
| 2 |
The
contracts for purchases initially were generally coextensive with the term
of the PUD bonds associated with the project. Under the terms of some
financings and refinancings, however, long-term bonds were sold to finance
certain assets whose estimated useful lives extend beyond the expiration
date of the power sales contracts. Of the total outstanding bonds sold for
each project, the percentage of principal amount of bonds which mature
beyond the contract expiration date are: 53.4% at Rock Island; 60.0% at
Rocky Reach; and 6.6% at Wells. There are no maturities beyond the
contract expiration date of 2035 for Priest Rapids and
Wanapum
which assumes a 40-year FERC license extension. |
| 3 |
The
components of 2004 costs associated with the interest portion of debt
service are:
Rock Island, $22.6 million for all units; Rocky Reach, $9.4 million;
Wells, $7.7 million; Priest Rapids, $0.7
million; and Wanapum, $1.0
million. |
| 4 |
On
December 28, 2001, PSE signed a contract offer for new contracts for the
Priest Rapids and Wanapum Developments. On April 12, 2002, PSE signed
amendments to those agreements which are technical clarifications of
certain sections of the agreements. Under the terms of these contracts,
PSE will continue to obtain capacity and energy for the term of any new
FERC license to be obtained by Grant County PUD. Grant County PUD filed an
“Application for New License for the Priest Rapids Project” on October 29,
2003. The new contract terms begin in November of 2005 for the Priest
Rapids Development and in November of 2009 for the Wanapum Development.
Unlike the current contracts, in the new contracts PSE’s share of power
from the developments declines over time as Grant County PUD’s load
increases. On March 8, 2002, the Yakama Nation filed a complaint with FERC
which alleged that Grant County PUD’s new contracts unreasonably restrain
trade and violate various sections of the Federal Power Act and Public Law
83-544. On November 21, 2002, FERC dismissed the complaint while agreeing
that certain aspects of the complaint had merit. As a result, it has
ordered Grant County PUD to remove specific sections of the contract which
constrain the parties to the Grant County PUD contracts from competing
with Grant County PUD for a new license. A rehearing has been
requested. |
Early in
2003, the Colville Confederated Tribes (Colville Tribe) presented a claim to
Douglas County PUD based upon allegedly unpaid past annual charges for the Wells
Hydroelectric project for the use of Colville Tribal lands. The Colville Tribe
also claimed that annual charges would also be due for periods into the future.
On November 1, 2004, Douglas County PUD entered into a settlement with the
Colville Tribe concerning claims that the Colville Tribe had asserted against
Douglas County PUD for the use by the Wells project of Tribal lands. PSE
approved the settlement and participated in the filing Douglas County PUD made
on November 23, 2004 seeking FERC approval. The settlement was approved in a
FERC order on February 11, 2005. It is unlikely that any party will seek a
rehearing of that FERC order, of which the deadline for doing so is March 13,
2005. When the settlement becomes final, the effects on PSE will be through
modestly increased power costs, and a small reduction to the amount of power
delivered to PSE due to the allocation to the Colville Tribe. The Tribe’s
allocation will be treated as an encroachment to the project, thus reducing the
amount of power available for purchase by others.
The
Company’s estimated payments for power purchases from the Columbia River are
$79.9 million for 2005, $80.1 million for 2006, $83.2 million for 2007, $86.9
million for 2008, $89.7 million in 2009, and in the aggregate, $54.6 million
thereafter through 2018.
The
Company also has numerous long-term firm purchased power contracts with other
utilities in the region. The Company is generally not obligated to make payments
under these contracts unless power is delivered. The Company’s estimated
payments for firm power purchases from other utilities, excluding the Columbia
River projects, are $79.3 million for 2005, $81.5 million for 2006, $82.9
million for 2007, $83.7 million for 2008, $83.5 million in 2009 and in the
aggregate, $349.6 million thereafter through 2037. These contracts have varying
terms and may include escalation and termination provisions.
As
required by the federal Public Utility Regulatory Policies Act (PURPA), PSE
entered into long-term firm purchased power contracts with non-utility
generators. The Company purchases the net electrical output of four significant
projects at fixed and annually escalating prices, which were intended to
approximate the Company’s avoided cost of new generation projected at the time
these agreements were made. The Company’s estimated payments under these
contracts are $210.2 million for 2005, $215.4 million for 2006, $205.3 million
for 2007, $205.3 million for 2008, and $207.1 million for 2009, and in the
aggregate, $527.4 million thereafter through 2013.
The
following table summarizes the Company’s estimated obligations for future power
purchases:
|
(DOLLARS
IN MILLIONS) |
|
2005 |
|
2006 |
|
2007 |
|
2008 |
|
2009 |
|
2010
&
THERE-
AFTER |
|
TOTAL |
|
|
Columbia
River Projects |
|
$ |
79.9 |
|
$ |
80.1 |
|
$ |
83.2 |
|
$ |
86.9 |
|
$ |
89.7 |
|
$ |
54.6 |
|
$ |
474.4 |
|
|
Other
utilities |
|
|
79.3 |
|
|
81.5 |
|
|
82.9 |
|
|
83.7 |
|
|
83.5 |
|
|
349.6 |
|
|
760.5 |
|
|
Non-utility
generators |
|
|
210.2 |
|
|
215.4 |
|
|
205.3 |
|
|
205.3 |
|
|
207.1 |
|
|
527.4 |
|
|
1,570.7 |
|
|
Total |
|
$ |
369.4 |
|
$ |
377.0 |
|
$ |
371.4 |
|
$ |
375.9 |
|
$ |
380.3 |
|
$ |
931.6 |
|
$ |
2,805.6 |
|
Total
purchased power contracts provided the Company with approximately 9.4 million,
11.0 million and 12.1 million MWh of firm energy at a cost of approximately
$404.7 million, $479.2 million and $466.1 million for the years 2004, 2003 and
2002, respectively.
The
following table indicates the Company’s percentage ownership and the extent of
the Company’s investment in jointly owned generating plants in service at
December 31, 2004:
| |
|
|
COMPANY'S
SHARE |
|
(DOLLARS
IN MILLIONS) |
ENERGY
SOURCE
(FUEL) |
COMPANY'S
OWNERSHIP
SHARE |
PLANT
IN SERVICE
AT
COST |
ACCUMULATED
DEPRECIATION |
|
Colstrip
Units 1 & 2 |
Coal |
50% |
$
207 |
|
$
134 |
|
|
Colstrip
Units 3 & 4 |
Coal |
25% |
469 |
|
250 |
|
Financing
for a participant’s ownership share in the projects is provided for by such
participant. The Company’s share of related operating and maintenance expenses
is included in corresponding accounts in the Consolidated Statements of
Income.
As part
of its electric operations and in connection with the 1997 restructuring of the
Tenaska Power Purchase Agreement, PSE is obligated to deliver to Tenaska up to
48,000 MMBtu per day of natural gas for operation of Tenaska’s natural gas-fired
cogeneration facility. This obligation continues for the remaining term of the
agreement, provided that no deliveries are required during the month of May. The
price paid by Tenaska for this gas is reflective of the daily price of gas at
the United States/Canada border near Sumas, Washington. PSE has entered into a
financial arrangement to hedge a portion, 5,000 MMBtu to 10,000 MMBtu per day,
of future gas supply costs associated with this obligation. The Company has a
maximum financial obligation under this hedge agreement of $18.9 million in 2005
and $2.2 million in 2006.
As part
of its electric operations and in connection with the 1999 buyout of the Cabot
gas supply contract, PSE is obligated to deliver to Encogen up to 21,800 MMBtu
per day of natural gas for operation of the Encogen natural gas-fired
cogeneration facility. This obligation continues for the remaining term of the
original Cabot agreement. The Company entered into a financial arrangement to
hedge a portion of future gas supply costs associated with this obligation,
10,000 MMBtu per day, for the remaining term of the agreement. The Company has a
maximum financial obligation under this hedge agreement of $8.7 million in 2005,
$9.0 million in 2006, $9.2 million in 2007 and $9.6 million thereafter.
Depending on actual market prices, these costs will be partially, or perhaps
entirely, offset by floating price payments received under the hedge
arrangement. Encogen has two gas supply agreements that comprise 40% of the
plant’s requirements with remaining terms ranging from less than 1 year to 3.5
years. The obligations under these contracts are $14.1 million in 2005, $2.2
million in 2006, $2.5 million in 2007 and $1.4 million in the aggregate
thereafter.
PSE
enters into short-term energy supply contracts to meet its core customer needs.
These contracts are generally classified as normal purchases and normal sales or
in some cases recorded at fair value in accordance with SFAS No. 133 and SFAS
No. 149. Commitments under these contracts are $138.2 million in 2005 and $41.2
thereafter.
GAS
SUPPLY
The
Company has also entered into various firm supply, transportation and storage
service contracts in order to ensure adequate availability of gas supply for its
firm customers. Many of these contracts, which have remaining terms from less
than 1 year to 19 years, provide that the Company must pay a fixed demand charge
each month, regardless of actual usage. The Company contracts all its long term
firm gas service, which means the Company has a 100% daily take obligation and
the supplier has a 100% daily delivery obligation. The Company incurred demand
charges in 2004 for firm gas supply, firm transportation service and firm
storage and peaking service of $21.4 million, $63.6 million and $5.7 million,
respectively. WNG CAP I incurred demand charges in 2004 for firm transportation
service of $8.4 million which is included in the total Company demand
charges.
The
following table summarizes the Company’s obligations for future demand charges
through the primary terms of its existing contracts. The quantified obligations
are based on current contract prices and FERC authorized rates, which are
subject to change.
|
DEMAND
CHARGE OBLIGATIONS
(DOLLARS
IN MILLIONS) |
2005 |
2006 |
2007 |
2008 |
2009 |
2010
&
THERE-
AFTER |
TOTAL |
|
Firm
gas supply |
$
1.8 |
$
1.2 |
$
1.0 |
$
0.8 |
$
0.5 |
$
1.0 |
$
6.3 |
|
Firm
transportation service |
69.6 |
68.8 |
65.0 |
55.6 |
110.2 |
117.2 |
486.4 |
|
Firm
storage service |
11.5 |
10.5 |
7.7 |
7.7 |
7.7 |
40.2 |
85.3 |
|
Total |
$
82.9 |
$
80.5 |
$
73.7 |
$
64.1 |
$
118.4 |
$
158.4 |
$
578.0 |
SERVICE
CONTRACT
On August
30, 2001, PSE and Alliance Data Systems Corp. announced a contract under which
Alliance Data will provide data processing and billing services for PSE. In
providing services to PSE under the 10-year agreement, Alliance Data will use
ConsumerLinX software, PSE’s customer-information software developed by a former
subsidiary, ConneXt. Alliance Data acquired the assets of ConneXt, including the
exclusive use of the ConsumerLinX software for five years with an option for
renewal. Alliance Data will offer ConsumerLinX as part of its integrated,
single-source customer relationship management solution for large-scale,
regulated utility clients. The obligations under the contract are $22.2 million
in 2005, $22.8 million in 2006, $23.4 million in 2007, $24.0 million in 2008,
$24.6 million in 2009 and $42.3 million in the aggregate
thereafter.
In April
2004, PSE acquired a 49.85% interest in the Frederickson 1 generating facility.
As part of that acquisition, PSE became subject to an existing long-term parts
and service maintenance contract for the upkeep of the natural gas combined
cycle unit. The contract was initiated in December 2000, and runs for the
earlier of 96,000 factory fired hours or 18 years. The contract requires
payments based on both a fixed and variable cost component, depending on how
much the facility is used. PSE’s share of the estimated obligation under the
contract based on projected future use of the facility are $1.1 million in 2005,
$1.1 million in 2006, $5.1 million in 2007, $1.8 million in 2008, $1.1 million
in 2009, and $12.2 million in the aggregate thereafter.
FREDONIA
3 AND 4 OPERATING LEASE
PSE
leases two combustion turbines for its Fredonia 3 and 4 electric generating
facility pursuant to a master operating lease that was amended for this purpose
in April 2001. The lease has a term expiring in 2011, but can be canceled by PSE
at any time. Payments under the lease vary with changes in the London Interbank
Offered Rate (LIBOR). At December 31, 2004, PSE’s outstanding balance under the
lease was $56.3 million. The expected residual value under the lease is the
lesser of $37.4 million or 60% of the cost of the equipment. In the event the
equipment is sold to a third party upon termination of the lease and the
aggregate sales proceeds are less than the unamortized value of the equipment,
PSE would be required to pay the lessor contingent rent in an amount equal to
the deficiency up to a maximum of 87% of the unamortized value of the
equipment.
SURETY
BOND
The
Company has a self-insurance surety bond in the amount for $5.9 million
guaranteeing compliance with the Industrial Insurance Act (workers’
compensation) and nine self-insurer’s pension bonds totaling $1.5
million.
ENVIRONMENTAL
The
Company is subject to environmental laws and regulations by federal, state and
local authorities and has been required to undertake certain environmental
investigative and remedial efforts as a result of these laws and regulations.
The Company has also been named by the Environmental Protection Agency, the
Washington State Department of Ecology, and/or other third parties as
potentially responsible at several contaminated sites and manufactured gas plant
sites. PSE has implemented an ongoing program to test, replace and remediate
certain underground storage tanks (UST) as required by federal and state laws.
The UST replacement component of this effort is finished, but PSE continues its
work remediating and/or monitoring these sites. Remediation and testing of
Company vehicle service facilities and storage yards is also
continuing.
During
1992, the Washington Commission issued orders regarding the treatment of costs
incurred by the Company for certain sites under its environmental remediation
program. The orders authorize the Company to accumulate and defer prudently
incurred cleanup costs paid to third parties for recovery in rates established
in future rate proceedings. The Company believes a significant portion of its
past and future environmental remediation costs are recoverable from insurance
companies, from third parties or under the Washington Commission’s
order.
The
information presented here as it relates to estimates of future liability is as
of December 31, 2004.
ELECTRIC
SITES
The
Company has expended approximately $20.8 million related to the remediation
activities covered by the Washington Commission’s order and has accrued
approximately $1.7 million as a liability for future remediation costs for these
and other remediation activities. To date, the Company has recovered
approximately $20.0 million from insurance carriers.
Based on
all known facts and analyses, the Company believes it is not likely that the
identified environmental liabilities will result in a material adverse impact on
the Company’s financial position, operating results or cash flow.
GAS
SITES
The
Company has expended approximately $69.6 million related to the remediation
activities covered by a Washington Commission order and has accrued
approximately $30.6 million for future remediation costs for these and other
remediation sites. To date, the Company has recovered approximately $60.7
million from insurance carriers and other third parties. The Company expects to
recover legal and remediation activities from either insurance companies or
customers per Washington Commission orders.
Based on
all known facts and analyses, the Company believes it is not likely that the
identified environmental liabilities will result in a material adverse impact on
the Company’s financial position, operating results or cash flow.
LITIGATION
There are
several actions in the U.S. Ninth Circuit Court of Appeals against Bonneville
Power Administration (BPA), in which the petitioners assert or may assert that
BPA acted contrary to law or without authority in deciding to enter into, or in
entering into or performing, a number of contracts, including the amended
settlement agreement regarding the Residential Purchase and Sale Program and the
conditional settlement agreements between BPA and PSE which modified the payment
provisions of the Residential Purchase and Sale Program. BPA rates used in such
amended settlement agreement between BPA and PSE for determining the amounts of
money to be paid to PSE as residential exchange benefits during the period
October 1, 2001 through September 30, 2006 have been confirmed, approved and
allowed to go into effect by FERC. There are also several actions in the U.S.
Ninth Circuit Court of Appeals against BPA, in which petitioners assert that BPA
acted contrary to law in adopting or implementing the rates or rate adjustment
clause upon which the benefits received or to be received from BPA during the
October 1, 2001 through September 30, 2006 period are based. It is not clear
what impact, if any, review of such rates may have on PSE.
Other
contingencies, arising out of the normal course of the Company’s business, exist
at December 31, 2004. The ultimate resolution of these issues is not expected to
have a material adverse impact on the financial condition, results of operations
or liquidity of the Company.
NOTE 24.
Segment
Information
Puget
Energy operates in primarily two business segments: regulated utility operations
(PSE), which includes the account receivables securitization program, and
construction services (InfrastruX). Puget Energy’s regulated utility operation
generates, purchases and sells electricity and purchases, transports and sells
natural gas. The service territory of PSE covers approximately 6,000 square
miles in the State of Washington. InfrastruX specializes in construction
services to other gas and electric utilities primarily in the Midwest, Texas,
south-central and eastern United States.
One minor
non-utility business segment which includes two PSE subsidiaries, and Puget
Energy, is described as other. The PSE subsidiaries are a real estate investment
and development company and a holding company for a small non-utility wholesale
generator. Reconciling items between segments are not significant.
After
completing a strategic review of InfrastruX, Puget Energy has decided to exit
the utility construction services sector. Puget Energy’s Board of Directors
approved the decision on February 8, 2005. The decision to exit the business is
the result of the Company’s need to invest in the core utility business to
acquire or construct energy generating resources and energy delivery
infrastructure. During 2005, Puget Energy intends to monetize its interest in
InfrastruX through sale or third party recapitalization and invest the proceeds
in PSE.
|
2004
(DOLLARS
IN THOUSANDS) |
REGULATED
UTILITY |
INFRASTRUX |
OTHER |
RECONCILING
ITEM |
PUGET
ENERGY
TOTAL |
|
Revenues |
$
2,192,340 |
$
369,936 |
$
6,537 |
-- |
$
2,568,813 |
|
Depreciation
and amortization |
228,310 |
18,276 |
256 |
-- |
246,842 |
|
Goodwill
impairment |
-- |
91,196 |
-- |
-- |
91,196 |
|
Income
tax |
75,755 |
(1,793) |
1,002 |
-- |
74,964 |
|
Operating
income (loss) |
285,258 |
(70,928) |
2,421 |
-- |
216,751 |
|
Interest
charges, net of AFUDC |
166,411 |
6,460 |
219 |
-- |
173,090 |
|
Net
income (loss) |
123,401 |
(70,388) |
2,009 |
-- |
55,022 |
|
Goodwill,
net |
-- |
43,503 |
-- |
-- |
43,503 |
|
Total
assets |
5,511,631 |
251,097 |
70,641 |
-- |
5,833,369 |
|
Construction
expenditures - excluding equity AFUDC |
393,891 |
-- |
-- |
-- |
393,891 |
|
Additions
to other property, plant and equipment |
-- |
15,512 |
-- |
-- |
15,512 |
|
2003
(DOLLARS
IN THOUSANDS) |
|
|
OTHER |
RECONCILING
ITEM
2 |
|
|
Revenues1 |
$
2,034,973 |
$
341,787 |
$
6,043 |
-- |
$
2,382,803 |
|
Depreciation
and amortization |
219,851 |
16,779 |
236 |
-- |
236,866 |
|
Income
tax |
69,823 |
1,594 |
952 |
-- |
72,369 |
|
Operating
income |
295,219 |
7,452 |
2,504 |
-- |
305,175 |
|
Interest
charges, net of AFUDC |
179,437 |
5,485 |
123 |
-- |
185,045 |
|
Net
income |
119,144 |
1,766 |
438 |
(5,151) |
116,197 |
|
Goodwill,
net |
-- |
133,302 |
-- |
-- |
133,302 |
|
Total
assets |
5,281,474 |
342,332 |
75,196 |
-- |
5,699,002 |
|
Construction
expenditures - excluding equity AFUDC |
269,973 |
-- |
-- |
-- |
269,973 |
|
Additions
to other property, plant and equipment |
-- |
15,536 |
-- |
-- |
15,536 |
|
2002
(DOLLARS
IN THOUSANDS) |
|
|
|
|
|
|
Revenues1 |
$
1,985,899 |
$
319,529 |
$
9,753 |
-- |
$
2,315,181 |
|
Depreciation
and amortization |
215,097 |
13,426 |
220 |
-- |
228,743 |
|
Income
tax |
49,733 |
6,703 |
2,824 |
-- |
59,260 |
|
Operating
income |
289,511 |
15,595 |
4,563 |
-- |
309,669 |
|
Interest
charges, net of AFUDC |
190,861 |
5,516 |
-- |
-- |
196,377 |
|
Net
income |
104,044 |
9,455 |
4,384 |
(7,831) |
110,052 |
|
Goodwill,
net |
-- |
125,555 |
-- |
-- |
125,555 |
|
Total
assets |
5,323,129 |
319,248 |
129,756 |
-- |
5,772,133 |
|
Construction
expenditures - excluding equity AFUDC |
224,165 |
-- |
-- |
-- |
224,165 |
|
Additions
to other property, plant and equipment |
-- |
11,621 |
-- |
-- |
11,621 |
_____________________
| 1 |
Revenues
for the Regulated Utility segment were reduced $108.7 million and $77.1
million in 2003 and 2002, respectively as a result of a reclassification
from implementing EITF No. 03-11 on January 1, 2004. The reclassification
had no effect on financial position or results of
operations. |
| 2 |
Reconciling
item is preferred stock dividend accrual at PSE that is treated as an
other deduction at Puget Energy. |
The
following unaudited amounts, in the opinion of the Company, include all
adjustments (consisting of normal recurring adjustments) necessary for a fair
presentation of the results of operations for the interim periods. Quarterly
amounts vary during the year due to the seasonal nature of the utility business.
PUGET
ENERGY
|
(Unaudited;
dollars in thousands except per share amounts) |
|
|
|
|
|
|
|
|
2004
QUARTER |
|
FIRST |
|
SECOND1 |
|
THIRD |
|
FOURTH2 |
|
|
Operating
revenues |
|
$ |
743,470 |
|
$ |
515,939 |
|
$ |
514,951 |
|
$ |
794,452 |
|
|
Operating
income |
|
|
109,680 |
|
|
35,216 |
|
|
53,825 |
|
|
18,031 |
|
|
Other
income |
|
|
64 |
|
|
1,586 |
|
|
318 |
|
|
2,324 |
|
|
Net
income (loss) |
|
|
66,365 |
|
|
(6,780 |
) |
|
11,124 |
|
|
(15,687 |
) |
|
Basic
earnings per common share |
|
$ |
0.67 |
|
$ |
(0.07 |
) |
$ |
0.11 |
|
$ |
(0.16 |
) |
|
Diluted
earnings per common share |
|
$ |
0.67 |
|
$ |
(0.07 |
) |
$ |
0.11 |
|
$ |
(0.16 |
) |
| |
|
|
|
|
|
|
|
|
(Unaudited;
dollars in thousands except per share amounts) |
|
|
|
|
|
|
|
|
2003
QUARTER |
|
FIRST |
|
SECOND |
|
THIRD |
|
FOURTH |
|
|
Operating
revenues3 |
|
$ |
640,637 |
|
$ |
524,060 |
|
$ |
490,258 |
|
$ |
727,849 |
|
|
Operating
income |
|
|
91,385 |
|
|
66,407 |
|
|
54,389 |
|
|
92,994 |
|
|
Other
income |
|
|
704 |
|
|
2,247 |
|
|
2,663 |
|
|
(4,050 |
) |
|
Net
income before cumulative effect of accounting change |
|
|
42,889 |
|
|
20,598 |
|
|
9,885 |
|
|
42,993 |
|
|
Net
income |
|
|
42,720 |
|
|
20,598 |
|
|
9,885 |
|
|
42,993 |
|
|
Basic
earnings per common share |
|
$ |
0.46 |
|
$ |
0.22 |
|
$ |
0.10 |
|
$ |
0.44 |
|
|
Diluted
earnings per common share |
|
$ |
0.45 |
|
$ |
0.22 |
|
$ |
0.10 |
|
$ |
0.44 |
|
| |
|
|
|
|
|
|
|
|
(Unaudited;
dollars in thousands except per share amounts) |
|
|
|
|
|
|
|
|
2002
QUARTER |
|
FIRST |
|
SECOND |
|
THIRD |
|
FOURTH |
|
|
Operating
revenues3 |
|
$ |
720,997 |
|
$ |
529,803 |
|
$ |
442,577 |
|
$ |
621,804 |
|
|
Operating
income |
|
|
76,571 |
|
|
76,833 |
|
|
57,098 |
|
|
99,168 |
|
|
Other
income |
|
|
384 |
|
|
3,441 |
|
|
230 |
|
|
1,403 |
|
|
Net
income |
|
|
24,466 |
|
|
29,429 |
|
|
6,572 |
|
|
49,585 |
|
|
Basic
and diluted earnings per common share |
|
$ |
0.28 |
|
$ |
0.34 |
|
$ |
0.07 |
|
$ |
0.55 |
|
_____________________
| 1 |
The
second quarter 2004 includes a disallowance of $36.5 million or $23.7
million after-tax related to a Washington Commission order stating PSE did
not prudently manage gas costs for the Tenaska generating
facility. |
| 2 |
The
fourth quarter 2004 includes a non-cash goodwill impairment charge of
$91.2 million or $76.6 million after-tax and minority interest related to
goodwill at InfrastruX. |
| 3 |
Operating
revenues in 2003 and 2002 were revised as a result of a reclassification
due to Emerging Issues Task Force Issue No. 03-11, “Reporting Realized
Gaines and Losses on Derivative Instruments That Are Subject to FASB No.
133 and Not ‘Held for Trading Purposes’ as Defined in Issue No. 02-03,”
which became effective on January 1, 2004. First, second, third and fourth
quarter 2003 revenues were reduced by $35.3 million, $33.8 million, $25.3
million and $14.3 million, respectively. First, second, third and fourth
quarter 2002 revenues were reduced by $18.1 million, $11.0 million, $15.9
million and $32.1 million, respectively. The impact of EITF No. 03-11 had
no effect on financial position or results of
operations. |
(Unaudited;
dollars in thousands) |
|
|
|
|
|
|
|
|
|
|
2004
QUARTER |
|
FIRST |
|
SECOND
1 |
|
THIRD |
|
FOURTH |
|
|
Operating
revenues |
|
$ |
668,714 |
|
$ |
423,123 |
|
$ |
415,026 |
|
$ |
692,012 |
|
|
Operating
income |
|
|
108,845 |
|
|
30,704 |
|
|
50,363 |
|
|
98,330 |
|
|
Other
income |
|
|
68 |
|
|
1,570 |
|
|
356 |
|
|
2,368 |
|
|
Net
income (loss) |
|
|
66,898 |
|
|
(9,540 |
) |
|
9,647 |
|
|
59,187 |
|
| |
|
|
|
|
|
|
|
|
|
(Unaudited;
dollars in thousands) |
|
|
|
|
|
|
|
|
|
|
2003
QUARTER |
|
|
|
SECOND |
|
THIRD |
|
FOURTH |
|
|
Operating
revenues2 |
|
$ |
569,960 |
|
$ |
431,717 |
|
$ |
397,116 |
|
$ |
642,224 |
|
|
Operating
income |
|
|
93,935 |
|
|
62,120 |
|
|
51,046 |
|
|
90,803 |
|
|
Other
income |
|
|
691 |
|
|
2,309 |
|
|
2,620 |
|
|
(4,033 |
) |
|
Net
income before cumulative effect of accounting change |
|
|
48,270 |
|
|
19,614 |
|
|
9,488 |
|
|
42,683 |
|
|
Net
income |
|
|
48,101 |
|
|
19,614 |
|
|
9,488 |
|
|
42,683 |
|
| |
|
|
|
|
|
|
|
|
|
(Unaudited;
dollars in thousands) |
|
|
|
|
|
|
|
|
|
|
2002
QUARTER |
|
FIRST |
|
SECOND |
|
THIRD |
|
FOURTH |
|
|
Operating
revenues2 |
|
$ |
660,236 |
|
$ |
453,681 |
|
$ |
350,204 |
|
$ |
531,531 |
|
|
Operating
income |
|
|
74,732 |
|
|
72,724 |
|
|
51,367 |
|
|
95,769 |
|
|
Other
income |
|
|
309 |
|
|
3,455 |
|
|
210 |
|
|
1,241 |
|
|
Net
income |
|
|
25,698 |
|
|
28,839 |
|
|
4,701 |
|
|
49,709 |
|
_____________________
| 1 |
The
second quarter 2004 includes a disallowance of $36.5 million or $23.7
million after-tax related to a Washington Commission order stating PSE did
not prudently manage gas costs for the Tenaska generating
facility. |
| 2 |
Operating
revenues in 2003 and 2002 were revised as a result of a reclassification
due to Emerging Issues Task Force Issue No. 03-11, “Reporting Realized
Gaines and Losses on Derivative Instruments That Are Subject to FASB No.
133 and Not ‘Held for Trading Purposes’ as Defined in Issue No. 02-03,”
which became effective on January 1, 2004. First, second, third and fourth
quarter 2003 revenues were reduced by $35.3 million, $33.8 million, $25.3
million and $14.3 million, respectively. First, second, third and fourth
quarter 2002 revenues were reduced by $18.1 million, $11.0 million, $15.9
million and $32.1 million, respectively. The impact of EITF No. 03-11 had
no effect on financial position or results of
operations. |
Valuation
and Qualifying Accounts and Reserves
|
PUGET
ENERGY
(DOLLARS
IN THOUSANDS) |
|
BALANCE
AT
BEGINNING OF
PERIOD |
|
ADDITIONS
CHARGED TO
COSTS AND
EXPENSES |
|
DEDUCTIONS |
|
BALANCE
AT END
OF PERIOD |
|
|
|
|
|
|
|
|
|
|
|
|
Accounts
deducted from assets on balance sheet: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance
for doubtful accounts receivable |
|
$ |
4,359 |
|
$ |
7,668 |
|
$ |
7,507 |
|
$ |
4,520 |
|
|
Reserve
on wholesale sales |
|
|
41,488 |
|
|
-- |
|
|
-- |
|
|
41,488 |
|
|
Deferred
tax asset valuation allowance |
|
|
-- |
|
|
17,988 |
|
|
-- |
|
|
17,988 |
|
|
Tenaska
disallowance reserve |
|
|
-- |
|
|
36,490 |
|
|
33,334 |
|
|
3,156 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts
deducted from assets on balance sheet: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance
for doubtful accounts receivable |
|
$ |
3,863 |
|
$ |
9,387 |
|
$ |
8,891 |
|
$ |
4,359 |
|
|
Reserve
on wholesale sales |
|
|
41,488 |
|
|
-- |
|
|
-- |
|
|
41,488 |
|
|
Industrial
accident reserve |
|
|
2,000 |
|
|
-- |
|
|
2,000 |
|
|
-- |
|
|
Gas
transportation contracts reserve |
|
|
139 |
|
|
-- |
|
|
139 |
|
|
-- |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts
deducted from assets on balance sheet: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance
for doubtful accounts receivable |
|
$ |
5,488 |
|
$ |
11,191 |
|
$ |
12,816 |
|
$ |
3,863 |
|
|
Reserve
on wholesale sales |
|
|
41,488 |
|
|
-- |
|
|
-- |
|
|
41,488 |
|
|
Industrial
accident reserve |
|
|
-- |
|
|
4,000 |
|
|
2,000 |
|
|
2,000 |
|
|
Gas
transportation contracts reserve |
|
|
139 |
|
|
-- |
|
|
-- |
|
|
139 |
|
|
PUGET
SOUND ENERGY
(DOLLARS
IN THOUSANDS) |
|
BALANCE
AT
BEGINNING OF
PERIOD |
|
ADDITIONS
CHARGED TO
COSTS AND
EXPENSES |
|
DEDUCTIONS |
|
BALANCE
AT
END
OF
PERIOD |
|
|
|
|
|
|
|
|
|
|
|
|
Accounts
deducted from assets on balance sheet: |
|
|
|
|
|
|
|
|
|
|
Allowance
for doubtful accounts receivable |
|
$ |
2,484 |
|
$ |
7,343 |
|
$ |
7,157 |
|
$ |
2,670 |
|
|
Reserve
on wholesale sales |
|
|
41,488 |
|
|
-- |
|
|
-- |
|
|
41,488 |
|
|
Tenaska
disallowance reserve |
|
|
-- |
|
|
36,490 |
|
|
33,334 |
|
|
3,156 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts
deducted from assets on balance sheet: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance
for doubtful accounts receivable |
|
$ |
1,990 |
|
$ |
9,385 |
|
$ |
8,891 |
|
$ |
2,484 |
|
|
Reserve
on wholesale sales |
|
|
41,488 |
|
|
-- |
|
|
-- |
|
|
41,488 |
|
|
Industrial
accident reserve |
|
|
2,000 |
|
|
-- |
|
|
2,000 |
|
|
-- |
|
|
Gas
transportation contracts reserve |
|
|
139 |
|
|
-- |
|
|
139 |
|
|
-- |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts
deducted from assets on balance sheet: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance
for doubtful accounts receivable |
|
$ |
3,666 |
|
$ |
11,140 |
|
$ |
12,816 |
|
$ |
1,990 |
|
|
Reserve
on wholesale sales |
|
|
41,488 |
|
|
-- |
|
|
-- |
|
|
41,488 |
|
|
Industrial
accident reserve |
|
|
-- |
|
|
4,000 |
|
|
2,000 |
|
|
2,000 |
|
|
Gas
transportation contracts reserve |
|
|
139 |
|
|
-- |
|
|
-- |
|
|
139 |
|
|
|
CHANGES
IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE |
None.
PUGET
ENERGY
EVALUATION
OF DISCLOSURE CONTROLS AND PROCEDURES
Under the
supervision and with the participation of Puget Energy’s management, including
the President and Chief Executive Officer and Senior Vice President Finance and
Chief Financial Officer, Puget Energy has evaluated the effectiveness of its
disclosure controls and procedures (as defined in Rule 13a-15(e) under the
Securities Exchange Act of 1934) as of December 31, 2004, the end of the period
covered by this report. Based upon that evaluation, the President and Chief
Executive Officer and Senior Vice President Finance and Chief Financial officer
of Puget Energy concluded that these disclosure controls and procedures are
effective.
CHANGES
IN INTERNAL CONTROL OVER FINANCIAL REPORTING
There
have been no changes in Puget Energy’s internal control over financial reporting
during the quarter ended December 31, 2004 that have materially affected, or are
reasonably likely to materially affect, Puget Energy’s internal control over
financial reporting.
MANAGEMENT'S
REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Puget
Energy’s management is responsible for establishing and maintaining adequate
internal control over financial reporting (as defined in Rule 13a-15(f) under
the Securities Exchange Act of 1934). Under the supervision and with the
participation of Puget Energy’s President and Chief Executive Officer and Senior
Vice President Finance and Chief Financial Officer, Puget Energy’s management
assessed the effectiveness of internal control over financial reporting based on
the framework in Internal Control - Integrated Framework issued by the Committee
of Sponsoring Organization of the Treadway Commission. Based on the assessment,
Puget Energy’s management concluded that its internal control over financial
reporting was effective as of December 31, 2004.
Puget
Energy’s management assessment of the effectiveness of internal control over
financial reporting as of December 31, 2004, has been audited by
PricewaterhouseCoopers LLP, an independent registered public accounting firm, as
stated in their report which is included herein.
PUGET
SOUND ENERGY
EVALUATION
OF DISCLOSURE CONTROLS AND PROCEDURES
Under the
supervision and with the participation of PSE’s management, including the
President and Chief Executive Officer and Senior Vice President Finance and
Chief Financial Officer, PSE has evaluated the effectiveness of its disclosure
controls and procedures (as defined in Rule 13a-15(e) under the Securities
Exchange Act of 1934) as of December 31, 2004, the end of the period covered by
this report. Based upon that evaluation, the President and Chief Executive
Officer and Senior Vice President Finance and Chief Financial officer of PSE
concluded that these disclosure controls and procedures are effective.
CHANGES
IN INTERNAL CONTROL OVER FINANCIAL REPORTING
There
have been no changes in PSE’s internal control over financial reporting during
the quarter ended December 31, 2004, that have materially affected, or are
reasonably likely to materially affect, PSE’s internal control over financial
reporting.
MANAGEMENT'S
REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
PSE’s
management is responsible for establishing and maintaining adequate internal
control over financial reporting (as defined in Rule 13a-15(f) under the
Securities Exchange Act of 1934). Under the supervision and with the
participation of PSE’s President and Chief Executive Officer and Senior Vice
President Finance and Chief Financial Officer, Puget Sound Energy’s management
assessed the effectiveness of internal control over financial reporting based on
the framework in Internal Control - Integrated Framework issued by the Committee
of Sponsoring Organization of the Treadway Commission. Based on the assessment,
PSE’s management concluded that its internal control over financial reporting
was effective as of December 31, 2004.
PSE’s
management assessment of the effectiveness of internal control over financial
reporting as of December 31, 2004, has been audited by PricewaterhouseCoopers
LLP, an independent registered public accounting firm, as stated in their report
which is included herein.
PUGET
ENERGY
The
information required by this item with respect to Puget Energy is incorporated
herein by reference to the material under “Available Information” in Part I of
this report and “Proposal 1 - Election of Directors,” “Directors Continuing in
Office,” “Other Director Information,” “Board of Directors and Corporate
Governance” and “Security Ownership of Directors and Executive Officers--Section
16(a) Beneficial Ownership Reporting Compliance” in Puget Energy’s proxy
statement for its 2005 Annual Meeting of Shareholders (Commission file No.
1-16305). Reference is also made to the information regarding Puget Energy’s
executive officers set forth in Part I of this report.
PUGET
SOUND ENERGY
The
information called for by Item 10 with respect to PSE is omitted pursuant to
General Instruction I(2)(c) to Form 10-K (omission of information by certain
wholly owned subsidiaries).
PUGET
ENERGY
The
information required by this item with respect to Puget Energy is incorporated
herein by reference to the material under “Director Compensation,” “Executive
Compensation” and “Employment Contracts, Termination of Employment and
Change-In-Control Arrangements” in Puget Energy’s proxy statement for its 2005
Annual Meeting of Shareholders (Commission File No. 1-16305).
PUGET
SOUND ENERGY
The
information called for by Item 11 with respect to PSE is omitted pursuant to
General Instruction I(2)(c) to Form 10-K (omission of information by certain
wholly owned subsidiaries).
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
OWNERS AND MANAGEMENT
PUGET
ENERGY
EQUITY
COMPENSATION PLAN INFORMATION
The
information required by this item with respect to Puget Energy is incorporated
herein by reference to the material under “Equity Compensation Plan Information”
in Puget Energy’s proxy statement for its 2005 Annual Meeting of Shareholders
(Commission File No. 1-16305).
BENEFICIAL
OWNERSHIP
The
information required by this item with respect to Puget Energy is incorporated
herein by reference to the material under “Security Ownership of Directors and
Executive Officers” in Puget Energy’s proxy statement for its 2005 Annual
Meeting of Shareholders (Commission File No. 1-16305).
PUGET
SOUND ENERGY
EQUITY
COMPENSATION PLAN INFORMATION
The
information called for by this item with respect to PSE is omitted pursuant to
General Instruction I(2)(e) to Form 10-K (omission of information by wholly
owned subsidiaries).
BENEFICIAL
OWNERSHIP
As of
December 31, 2004, all of the issued and outstanding shares of PSE’s common
stock were held beneficially and of record by Puget Energy.
|
|
CERTAIN
RELATIONSHIPS AND RELATED TRANSACTIONS |
None.
|
|
PRINCIPAL
ACCOUNTANT FEES AND SERVICES |
The
aggregate fees billed by PricewaterhouseCoopers LLP, the Company’s independent
registered public accounting firm, for the year ended December 31 were as
follows:
| |
|
2004 |
|
2003 |
|
|
(DOLLARS
IN THOUSANDS) |
|
PUGET
ENERGY |
|
PSE |
|
PUGET
ENERGY |
|
PSE |
|
|
Audit
fees1 |
|
$ |
2,084 |
|
$ |
1,695 |
|
$ |
850 |
|
$ |
453 |
|
|
Audit
related fees2 |
|
|
82 |
|
|
82 |
|
|
261 |
|
|
147 |
|
|
Tax
fees3 |
|
|
59 |
|
|
55 |
|
|
200 |
|
|
168 |
|
|
Total |
|
$ |
2,225 |
|
$ |
1,832 |
|
$ |
1,311 |
|
$ |
768 |
|
_____________________
| 1 |
For
professional services rendered for the audit of Puget Energy’s and PSE’s
annual financial statements, reviews of financial statements included in
the Companies’ Forms 10-Q, and consents and reviews of documents filed
with the Securities and Exchange Commission. The 2004 fees are estimated
and include an aggregate amount of $1,251,000 and $1,156,000 billed to
Puget Energy and PSE, respectively through December 31, 2004. The 2003
fees include an aggregate amount of approximately $444,000 and $277,000
billed to Puget Energy and PSE, respectively, through December 31, 2003.
In 2004, audit fees included $1,284,000 and $1,120,000 for
professional services rendered for the audits of Puget Energy’s and PSE’s
assessment of, and the effectiveness of, internal controls over financial
reporting (Sarbanes-Oxley 404). |
| 2 |
Consists
of employee benefit plan audits, due diligence reviews and assistance with
Sarbanes-Oxley readiness. |
| 3 |
Consists
of tax planning, consulting and tax return
reviews. |
The Audit
Committees of the Company have adopted policies for the pre-approval of all
audit and non-audit services provided by the Company’s independent auditor. The
policies are designed to ensure that the provision of these services does not
impair the auditor’s independence. Under the policies, unless a type of service
to be provided by the independent auditor has received general pre-approval, it
will require specific pre-approval by the Audit Committee. In addition, any
proposed services exceeding pre-approved cost levels will require specific
pre-approval by the Audit Committee.
The
annual audit services engagement terms and fees, as well as any changes in
terms, conditions and fees relating to the engagement, are subject to specific
pre-approval by the Audit Committees. In addition, on an annual basis, the Audit
Committees grant general pre-approval for specific categories of audit,
audit-related, tax and other services, within specified fee levels, that may be
provided by the independent auditor. With respect to each proposed pre-approved
service, the independent auditor is required to provide detailed back-up
documentation to the Audit Committees regarding the specific services to be
provided. Under the policies, the Audit Committees may delegate pre-approval
authority to one or more of their members. The member or members to whom such
authority is delegated shall report any responsibilities to pre-approve services
performed by the independent auditor to management.
For 2004
all audit and non-audit services were pre-approved.
|
|
EXHIBITS,
FINANCIAL STATEMENT SCHEDULES |
| a) |
Documents
filed as part of this report: |
| 1) |
Financial
Statements.
See index on page 66. |
| 2) |
Financial
Statement Schedules.
Financial Statement Schedules of the Company located on page 123, as
required for the years ended December 31, 2004, 2003 and 2002, consist of
the following: |
| II. |
Valuation
of Qualifying Accounts |
| 3) |
Exhibits
- see index on page 129. |
Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act of
1934, each registrant has duly caused this report to be signed on its behalf by
the undersigned, thereunto duly authorized.
|
PUGET
ENERGY, INC. |
|
PUGET
SOUND ENERGY |
| |
|
|
|
/s/
Stephen P. Reynolds |
|
/s/
Stephen P. Reynolds |
|
Stephen
P. Reynolds |
|
Stephen
P. Reynolds |
|
President
and Chief Executive Officer |
|
President
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 each registrant and in the
capacities and on the dates indicated.
|
SIGNATURE |
TITLE |
DATE |
| |
(Puget
Energy and PSE unless otherwise noted) |
| |
|
|
|
/s/
Douglas P. Beighle |
Chairman
of the Board |
|
|
(Douglas
P. Beighle) |
|
|
| |
|
|
| |
|
|
|
/s/
Stephen P. Reynolds |
President,
Chief Executive Officer and |
|
|
(Stephen
P. Reynolds) |
Director |
|
| |
|
|
| |
|
|
|
/s/
Bertrand A. Valdman |
Senior
Vice President Finance and |
|
|
(Bertrand
A. Valdman) |
Chief
Financial Officer |
|
| |
|
|
| |
|
|
|
/s/
James W. Eldredge |
Corporate
Secretary and Chief |
|
|
(James
W. Eldredge) |
Accounting
Officer |
|
| |
|
|
| |
|
|
|
/s/
William S. Ayer |
Director |
|
|
(William
S. Ayer) |
|
|
| |
|
|
| |
|
|
|
/s/
Charles W. Bingham |
Director |
|
|
(Charles
W. Bingham) |
|
|
| |
|
|
| |
|
|
|
/s/
Phyllis J. Campbell |
Director |
|
|
(Phyllis
J. Campbell) |
|
|
| |
|
|
| |
|
|
|
/s/
Craig W. Cole |
Director |
|
|
(Craig
W. Cole) |
|
|
| |
|
|
| |
|
|
|
|
Director |
|
|
(Robert
L. Dryden) |
|
|
| |
|
|
| |
|
|
|
/s/
Stephen E. Frank |
Director |
|
|
(Stephen
E. Frank) |
|
|
| |
|
|
| |
|
|
|
/s/
Tomio Moriguchi |
Director |
|
|
(Tomio
Moriguchi) |
|
|
| |
|
|
| |
|
|
|
/s/
Dr. Kenneth P. Mortimer |
Director |
|
|
(Dr.
Kenneth P. Mortimer) |
|
|
| |
|
|
| |
|
|
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/s/
Sally G. Narodick |
Director |
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(Sally
G. Narodick) |
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3(i).1 |
|
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3(i).2 |
Restated
Articles of Incorporation of PSE (included as Annex F to the Joint Proxy
Statement/Prospectus filed February 1, 1996, Registration No.
333-617). |
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3(ii).1 |
|
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3(ii).2 |
|
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4.1 |
Fortieth
through Seventy-ninth Supplemental Indentures defining the rights of the
holders of PSE’s First Mortgage Bonds (Exhibit 2-d to Registration No.
2-60200; Exhibit 4-c to Registration No. 2-13347; Exhibits 2-e through and
including 2-k to Registration No. 2-60200; Exhibit 4-h to Registration No.
2-17465; Exhibits 2-l, 2-m and 2-n to Registration No. 2-60200; Exhibits
2-m to Registration No. 2-37645; Exhibit 2-o through and including 2-s to
Registration No. 2-60200; Exhibit 5-b to Registration No. 2-62883; Exhibit
2-h to Registration No. 2-65831; Exhibit (4)-j-1 to Registration No.
2-72061; Exhibit (4)-a to Registration No. 2-91516; Exhibit (4)-b to
Annual Report on Form 10-K for the fiscal year ended December 31, 1985,
Commission File No. 1-4393; Exhibits (4)-b and (4)-c to Registration No.
33-45916; Exhibit (4)-c to Registration No. 33-50788; Exhibit (4)-a to
Registration No. 33-53056; Exhibit 4.3 to Registration No. 33-63278;
Exhibit 4.25 to Registration No. 333-41181; Exhibit 4.27 to Current Report
on Form 8-K dated March 5, 1999; Exhibit 4.2 to Current Report on form 8-K
dated November 2, 2000; and Exhibit 4.2 to Current Report on Form 8-K
dated June 3, 2003). |
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4.2 |
Indenture
defining the rights of the holders of PSE’s senior notes (incorporated
herein by reference to Exhibit 4-a to PSE’s Quarterly Report on Form 10-Q
for the quarter ended June 30, 1998, Commission File No.
1-4393). |
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4.3 |
|
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4.4 |
|
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4.5 |
|
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4.6 |
|
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4.7 |
|
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4.8 |
|
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4.9 |
Amended
and Restated Declaration of Trust between Puget Sound Energy Capital Trust
and the First National Bank of Chicago dated June 6, 1997 (incorporated
herein by reference to Exhibit 4.2 of PSE’s Quarterly Report on Form 10-Q
for the quarter ended June 30, 1997, Commission File No.
1-4393). |
| |
4.10 |
Series
A Capital Securities Guarantee Agreement between PSE and the First
National Bank of Chicago dated June 6, 1997 (incorporated herein by
reference to Exhibit 4.3 of PSE’s Quarterly Report on Form 10-Q for the
quarter ended June 30, 1997, Commission File No.
1-4393). |
| |
4.11 |
First
Supplemental Indenture dated as of October 1, 1959 (Exhibit 4-D to
Registration No. 2-17876). |
| |
4.12 |
Sixth
Supplemental Indenture dated as of August 1, 1966 (Exhibit to Form 8-K for
month of August 1966, File No. 0-951). |
| |
4.13 |
Seventh
Supplemental Indenture dated as of February 1, 1967 (Exhibit 4-M,
Registration No. 2-27038). |
| |
4.14 |
Sixteenth
Supplemental Indenture dated as of June 1, 1977 (Exhibit 6-05 to
Registration No. 2-60352). |
| |
4.15 |
Seventeenth
Supplemental Indenture dated as of August 9, 1978 (Exhibit 5-K.18 to
Registration No. 2-64428). |
| |
4.16 |
Twenty-second
Supplemental Indenture dated as of July 15, 1986 (Exhibit 4-B.20 to Form
10-K for the year ended September 30, 1986, File No.
0-951). |
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4.17 |
Twenty-seventh
Supplemental Indenture dated as of September 1, 1990 (Exhibit 4-B.20, Form
10-K for the year ended September 30, 1998, File No.
10-951). |
| |
4.18 |
Twenty-eighth
Supplemental Indenture dated as of July 31, 1991 (Exhibit 4-A, Form 10-Q
for the quarter ended March 31, 1993, File No. 0-951). |
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4.19 |
Twenty-ninth
Supplemental Indenture dated as of June 1, 1993 (Exhibit 4-A to
Registration No. 33-49599). |
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4.20 |
Thirtieth
Supplemental Indenture dated as of August 15, 1995 (incorporated herein by
reference to Exhibit 4-A of Washington Natural Gas Company’s S-3
Registration Statement, Registration No. 33-61859). |
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4.21 |
|
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4.22 |
Unsecured
Debt Indenture between Puget Sound Energy and Bank One Trust Company, N.A.
dated as of May 18, 2001, defining the rights of the holders of Puget
Sound Energy’s unsecured debentures (incorporated herein by reference to
Exhibit 4.3 to Puget Sound Energy’s Current Report on Form 8-K, filed May
22, 2001, Commission File No. 1-4393). |
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4.23 |
First
Supplemental Indenture to the Unsecured Debt Indenture dated as of May 18,
2001 defining the rights of 8.40% Subordinated Deferrable Interest
Debentures due June 30, 2041 (incorporated herein by reference to Exhibit
4.4 to Puget Sound Energy’s Current Report on Form 8-K, filed May 22,
2001, Commission File No. 1-4393). |
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4.24 |
|
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4.25 |
Preferred
Securities Guarantee Agreement, dated May 18, 2001 between Puget Sound
Energy and Bank One Trust Company, N.A. for the benefit of the holders of
the trust preferred securities of the Puget Sound Energy Trust II
(incorporated herein by reference to Exhibit 4.5 to Puget Sound Energy’s
Current Report on Form 8-K, filed May 22, 2001, Commission File No.
1-4393). |
| |
4.26 |
Pledge
Agreement dated March 11, 2003 between Puget Sound Energy and Wells Fargo
Bank Northwest, National Association, as Trustee (incorporated herein by
reference to Exhibit 4.24 to the Company’s Post-Effective Amendment No. 1
to Registration Statement on Form S-3 dated July 11, 2003, Commission File
No. 333-82940-02). |
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4.27 |
|
|
* |
4.28 |
Eightieth
Supplemental Indenture dated as of April 30, 2004 defining the rights of
the holders of PSE’s First Mortgage Bonds. |
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10.1 |
First
Amendment dated as of October 4, 1961 to Power Sales Contract between
Public Utility District No. 1 of Chelan County, Washington and PSE,
relating to the Rocky Reach Project (Exhibit 13-d to Registration No.
2-24252). |
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10.2 |
First
Amendment dated February 9, 1965 to Power Sales Contract between Public
Utility District No. 1 of Douglas County, Washington and PSE, relating to
the Wells Development (Exhibit 13-p to Registration No.
2-24252). |
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10.3 |
Contract
dated November 14, 1957 between Public Utility District No. 1 of Chelan
County, Washington and PSE, relating to the Rocky Reach Project (Exhibit
4-1-a to Registration No. 2-13979). |
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10.4 |
Power
Sales Contract dated as of November 14, 1957 between Public Utility
District No. 1 of Chelan County, Washington and PSE, relating to the Rocky
Reach Project (Exhibit 4-c-1 to Registration No.
2-13979). |
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10.5 |
Power
Sales Contract dated May 21, 1956 between Public Utility District No. 2 of
Grant County, Washington and PSE, relating to the Priest Rapids Project
(Exhibit 4-d to Registration No. 2-13347). |
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10.6 |
First
Amendment to Power Sales Contract dated as of August 5, 1958 between PSE
and Public Utility District No. 2 of Grant County, Washington, relating to
the Priest Rapids Development (Exhibit 13-h to Registration No.
2-15618). |
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10.7 |
Power
Sales Contract dated June 22, 1959 between Public Utility District No. 2
of Grant County, Washington and PSE, relating to the Wanapum Development
(Exhibit 13-j to Registration No. 2-15618). |
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10.8 |
Agreement
to Amend Power Sales Contracts dated July 30, 1963 between Public Utility
District No. 2 of Grant County, Washington and PSE, relating to the
Wanapum Development (Exhibit 13-1 to Registration No.
2-21824). |
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10.9 |
Power
Sales Contract executed as of September 18, 1963 between Public Utility
District No. 1 of Douglas County, Washington and PSE, relating to the
Wells Development (Exhibit 13-r to Registration No.
2-21824). |
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10.10 |
Construction
and Ownership Agreement dated as of July 30, 1971 between The Montana
Power Company and PSE (Exhibit 5-b to Registration No.
2-45702). |
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10.11 |
Operation
and Maintenance Agreement dated as of July 30, 1971 between The Montana
Power Company and PSE (Exhibit 5-c to Registration No.
2-45702). |
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10.12 |
Contract
dated June 19, 1974 between PSE and P.U.D. No. 1 of Chelan County (Exhibit
D to Form 8-K dated July 5, 1974). |
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10.13 |
Transmission
Agreement dated April 17, 1981 between the Bonneville Power Administration
and PSE (Colstrip Project) (Exhibit (10)-55 to Annual Report on Form 10-K
for the fiscal year ended December 31, 1987, Commission File No.
1-4393). |
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10.14 |
Transmission
Agreement dated April 17, 1981 between the Bonneville Power Administration
and Montana Intertie Users (Colstrip Project) (Exhibit (10)-56 to Annual
Report on Form 10-K for the fiscal year ended December 31, 1987,
Commission File No. 1-4393). |
| |
10.15 |
Ownership
and Operation Agreement dated as of May 6, 1981 between PSE and other
Owners of the Colstrip Project (Colstrip 3 and 4) (Exhibit (10)-57 to
Annual Report on Form 10-K for the fiscal year ended December 31, 1987,
Commission File No. 1-4393). |
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10.16 |
Colstrip
Project Transmission Agreement dated as of May 6, 1981 between PSE and
Owners of the Colstrip Project (Exhibit (10)-58 to Annual Report on Form
10-K for the fiscal year ended December 31, 1987, Commission File No.
1-4393). |
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10.17 |
Common
Facilities Agreement dated as of May 6, 1981 between PSE and Owners of
Colstrip 1 and 2, and 3 and 4 (Exhibit (10)-59 to Annual Report on Form
10-K for the fiscal year ended December 31, 1987, Commission File No.
1-4393). |
| |
10.18 |
Amendment
dated as of June 1, 1968, to Power Sales Contract between Public Utility
District No. 1 of Chelan County, Washington and PSE (Rocky Reach Project)
(Exhibit (10)-66 to Annual Report on Form 10-K for the fiscal year ended
December 31, 1987, Commission File No. 1-4393). |
| |
10.19 |
Transmission
Agreement dated as of December 30, 1987 between the Bonneville Power
Administration and PSE (Rock Island Project) (Exhibit (10)-74 to Annual
Report on Form 10-K for the fiscal year ended December 31, 1988,
Commission File No. 1-4393). |
| |
10.20 |
Power
Sales Agreement between Northwestern Resources (formerly The Montana Power
Company) and PSE dated as of October 1, 1989 (Exhibit (10)-4 to Quarterly
Report on Form 10-Q for the quarter ended September 30, 1989, Commission
File No. 1-4393). |
| |
10.21 |
Amendment
No. 1 to the Colstrip Project Transmission Agreement dated as of February
14, 1990 among The Montana Power Company, The Washington Water Power
Company (Avista), Portland General Electric Company , PacifiCorp and PSE
(Exhibit (10)-91 to Annual Report on Form 10-K for the fiscal year ended
December 31, 1990, Commission File No. 1-4393). |
| |
10.22 |
Agreement
for Firm Power Purchase (Thermal Project) dated December 27, 1990 among
March Point Cogeneration Company, a California general partnership
comprising San Juan Energy Company, a California corporation;
Texas-Anacortes Cogeneration Company, a Delaware corporation; and PSE
(Exhibit (10)-4 to Quarterly Report on Form 10-Q for the quarter ended
March 31, 1991, Commission File No. 1-4393). |
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10.23 |
Agreement
for Firm Power Purchase dated March 20, 1991 between Tenaska Washington,
Inc., a Delaware corporation, and PSE (Exhibit (10)-1 to Quarterly Report
on Form 10-Q for the quarter ended June 30, 1991, Commission File No.
1-4393). |
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10.24 |
Amendment
of Seasonal Exchange Agreement, dated December 4, 1991 between Pacific Gas
and Electric Company and PSE (Exhibit (10)-107 to Annual Report on Form
10-K for the fiscal year ended December 31, 1991, Commission File No.
1-4393). |
| |
10.25 |
Capacity
and Energy Exchange Agreement, dated as of October 4, 1991 between Pacific
Gas and Electric Company and PSE (Exhibit (10)-108 to Annual Report on
Form 10-K for the fiscal year ended December 31, 1991, Commission File No.
1-4393). |
| |
10.26 |
General
Transmission Agreement dated as of December 1, 1994 between the Bonneville
Power Administration and PSE (BPA Contract No. DE-MS79-94BP93947) (Exhibit
10.115 to Annual Report on Form 10-K for the fiscal year ended December
31, 1994, Commission File No. 1-4393). |
| |
10.27 |
PNW
AC Intertie Capacity Ownership Agreement dated as of October 11, 1994
between the Bonneville Power Administration and PSE (BPA Contract No.
DE-MS79-94BP94521) (Exhibit 10.116 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1994, Commission File No.
1-4393). |
| |
10.28 |
Amendment
to Gas Transportation Service Contract dated July 31, 1991 between
Washington Natural Gas Company and Northwest Pipeline Corporation (Exhibit
10-E.2 to Form 10-K for the year ended September 30, 1995, File No.
11271). |
| |
10.29 |
Firm
Transportation Service Agreement dated January 12, 1994 between Northwest
Pipeline Corporation and Washington Natural Gas Company for firm
transportation service from Jackson Prairie (Exhibit 10-P to Form 10-K for
the year ended September 30, 1994, File No. 1-11271). |
| |
10.30 |
Puget
Energy, Inc. Non-employee Director Stock Plan. (incorporated herein by
reference to Exhibit 99.1 to Puget Energy’s Post Effective Amendment No. 1
to Form S-8 Registration Statement, dated January 2, 2001, Commission File
No. 333-41157-99.) |
|
** |
10.31 |
Amendment
No. 1 to the Puget Energy, Inc. Non-employee Director Stock Plan,
effective as of January 1, 2003 (Exhibit 10.94 to the Annual Report on
Form 10-K for the fiscal year ended December 31, 2002, Commission File No.
1-16305 and 1-4393). |
|
** |
10.32 |
Puget
Energy, Inc. Employee Stock Purchase Plan. (Incorporated herein by
reference to Exhibit 99.1 to Puget Energy’s Post Effective Amendment No. 1
to Form S-8 Registration Statement, dated January 2, 2001, Commission File
No. 333-41113-99.) |
|
** |
10.33 |
1995
Long-Term Incentive Compensation Plan. (Exhibit 10.108 to Annual Report on
Form 10-K for the fiscal year ended December 31, 2000, Commission File No.
1-4393 and 1-16305). |
|
** |
10.34 |
|
|
** |
10.35 |
Employment
agreement with S. P. Reynolds, Chief Executive Officer and President dated
January 7, 2002 (Exhibit 10.104 to the Annual Report on Form 10-K for the
fiscal year ended December 31, 2001, Commission File No. 1-16305 and
1-4393). |
| |
10.36 |
Credit
Agreement dated May 27, 2004, among InfrastruX Group, Inc. and various
Banks named therein, Union Bank of California as administrative agent.
(Exhibit 10.2, Form 10-Q for the quarterly period ended June 30, 2004,
Commission File No. 1-4393 and 1-16305). |
| |
10.37 |
Power
Sales Contract dated April 15, 2002, between Public Utility District No. 2
of Grant County, Washington, and PSE, relating to the Priest Rapids
Project. (Exhibit 10-1 to Form 10-Q for the quarter ended June 30, 2002,
File No. 1-16305 and 1-4393). |
| |
10.38 |
Reasonable
Portion Power Sales Contract dated April 15, 2002, between Public Utility
District No. 2 of Grant County, Washington, and PSE, relating to the
Priest Rapids Project. (Exhibit 10-2 to Form 10-Q for the quarter ended
June 30, 2002, File No. 1-16305 and 1-4393). |
| |
10.39 |
Additional
Power Sales Contract dated April 15, 2002, between Public Utility district
No. 2 of Grant County, Washington, and PSE, relating to the Priest Rapids
Project. (Exhibit 10-3 to Form 10-Q for the quarter ended June 30, 2002,
File No. 1-16305 and 1-4393). |
| |
10.40 |
Credit
Agreement dated May 27, 2004, covering PSE and various banks named
therein, Union Bank of California as administrative agent. (Exhibit 10.1,
Form 10-Q for the quarterly period ended June 30, 2004, Commission File
No. 1-4393 and 1-16305). |
| |
10.41 |
Receivable
Purchase Agreement dated December 23, 2002, among PSE, Rainier
Receivables, Inc., and Bank One, NA as agent (Exhibit 10.107 to the Annual
Report on Form 10-K for the fiscal year ended December 31, 2002,
Commission File No. 1-16305 and 1-4393). |
| |
10.42 |
Receivable
Sale Agreement dated December 23, 2002, among PSE and Rainier Receivables,
Inc. |
|
** |
10.43 |
Employment
agreement with J.M. Ryan, Vice President Energy Portfolio Management,
dated November 30, 2001 (Exhibit 10.109 to the Annual Report on Form 10-K
for the fiscal year ended December 31, 2002, Commission File No. 1-16305
and 1-4393). |
|
** |
10.44 |
Change-in-Control
Agreement with J.M. Ryan, Vice President, Energy Portfolio Management,
dated November 30, 2001 (Exhibit 10.110 to the Annual Report on Form 10-K
for the fiscal year ended December 31, 2002, Commission File No. 1-16305
and 1-4393). |
|
** |
10.45 |
Change-in-Control
Agreement with B. A. Valdman, Senior Vice President, Finance and Chief
Financial Officer, dated November 28, 2003 (Exhibit 10.86 to the Annual
Report on Form 10-K for the fiscal year ended December 31, 2003,
Commission File No. 1-16305 and 1-4393). |
|
** |
10.46 |
Change-in-Control
Agreement with S. McLain, Senior Vice President, Operations, dated March
12, 1999. (Exhibit 10.87 to the Annual Report on Form 10-K for the fiscal
year ended December 31, 2002, Commission File No. 1-16305 and
1-4393). |
|
** |
10.47 |
Employment
Agreement with M. T. Lennon, President and Chief Executive Officer of
InfrastruX, dated May 6, 2002 (Exhibit 10.88 to the Annual Report on Form
10-K for the fiscal year ended December 31, 2003, Commission File No.
1-16305 and 1-4393). |
|
** |
10.48 |
Restricted
Stock Award Agreement with S. P. Reynolds, Chief Executive Officer and
President dated, January 8, 2004 (Exhibit 10.90 to the Annual Report on
Form 10-K for the fiscal year ended December 31, 2003, Commission File No.
1-16305 and 1-4393). |
|
** |
10.49 |
Restricted
Stock Unit Award Agreement with S. P. Reynolds, Chief Executive Officer
and President dated, January 8, 2004 (Exhibit 10.91 to the Annual Report
on Form 10-K for the fiscal year ended December 31, 2003, Commission File
No. 1-16305 and 1-4393). |
|
** |
10.50 |
Restricted
Stock Award Agreement with S. P. Reynolds, Chief Executive Officer and
President dated, January 8, 2002 (Exhibit 99.1 to Form S-8 Registration
Statement, dated January 8, 2002, Commission File No.
333-76424). |
|
** |
10.51 |
Nonregulated
Stock Option Grant Notice/Agreement with S. P. Reynolds, Chief Executive
Officer and President dated March 11, 2002 (Exhibit 99.1 and Exhibit 99.2
to Form S-8 Registration Statement dated March 18, 2002, Commission File
No. 333-84426). |
|
* |
10.52 |
Change-in-Control
Agreement with E. M. Markell, Vice President Corporate Development, dated
May 7, 2003. |
|
* |
10.53 |
|
|
* |
10.54 |
InfrastruX
2000 Stock Incentive Plan Stock Option Grant Notice adopted January 26,
2001. |
|
* |
10.55 |
Puget
Sound Energy Amended and Restated Supplemental Executive Retirement Plan
for Senior Management dated October 5, 2004. |
|
* |
10.56 |
Puget
Sound Energy Amended and Restated Deferred Compensation Plan for Key
Employees dated January 1, 2003. |
|
* |
10.57 |
Puget
Sound Energy Amended and Restated Deferred Compensation Plan for
Nonemployee Directors dated October 1, 2000. |
|
** |
10.58 |
Summary
of Director Compensation (incorporated by reference to Exhibit 99.1 to
Current Report on Form 8-K, filed February 2, 2005, Commission File Nos.
1-4393 and 1-16305). |
|
* |
12.1 |
Statement
setting forth computation of ratios of earnings to fixed charges of Puget
Energy (2000 through 2004). |
|
* |
12.2 |
Statement
setting forth computation of ratios of earnings to fixed charges of Puget
Sound Energy (2000 through 2004). |
|
* |
21.1 |
Subsidiaries
of Puget Energy. |
|
* |
21.2 |
Subsidiaries
of PSE. |
|
* |
23.1 |
Consent
of PricewaterhouseCoopers LLP. |
|
* |
31.1 |
Certification
of Puget Energy - Certification Pursuant to 18 U.S.C. Section 1350, as
Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 -
Stephen P. Reynolds. |
|
* |
31.2 |
Certification
of Puget Energy - Certification Pursuant to 18 U.S.C. Section 1350, as
Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 -
Bertrand A. Valdman. |
|
* |
31.3 |
Certification
of Puget Sound Energy - Certification Pursuant to 18 U.S.C. Section 1350,
as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 -
Stephen P. Reynolds. |
|
* |
31.4 |
Certification
of Puget Sound Energy - Certification Pursuant to 18 U.S.C. Section 1350,
as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 -
Bertrand A. Valdman. |
|
* |
32.1 |
Certification
Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002 - Stephen P. Reynolds. |
|
* |
32.2 |
Certification
Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002 - Bertrand A.
Valdman. |
_____________________
** Management
contract or compensating plan or arrangement.
