Document/ExhibitDescriptionPagesSize 1: 10-K Puget Energy Form 2007 10-K HTML 2.85M
18: 10-K Puget Energy Form 2007 10-K -- f10k022908 PDF 1.04M
2: EX-3.I Restated Articles of Incorporation of Puget Energy HTML 50K
3: EX-4.1 Puget Sound Energy Eighty-Fifth Supplemental HTML 102K
Indenture
4: EX-4.22 Puget Sound Energy Thirty-Fourth Supplemental HTML 66K
Indenture
5: EX-4.23 Puget Sound Energy Thirty-Fifth Supplemental HTML 55K
Indenture
6: EX-10.44 Third Amendment to CEO Employment Agreement HTML 17K
7: EX-12.1 Puget Energy Statement of Ratios HTML 86K
8: EX-12.2 Puget Sound Energy Statement of Ratios HTML 88K
9: EX-21.1 Subsidiaries of Puget Energy HTML 9K
10: EX-21.2 Subsidiaries of Puget Sound Energy HTML 11K
11: EX-23.1 Consent of Pricewaterhousecoopers LLP HTML 11K
12: EX-31.1 Puget Energy Certification by CEO HTML 14K
13: EX-31.2 Puget Energy Certification by CFO HTML 14K
14: EX-31.3 Puget Sound Energy Certification by CEO HTML 14K
15: EX-31.4 Puget Sound Energy Certification by CFO HTML 14K
16: EX-32.1 CEO Certification HTML 12K
17: EX-32.2 CFO Certification HTML 12K
Securities
registered pursuant to Section 12(b) of the Act:
Title
Of Each Class
Name
Of Each Exchange
On
Which Listed
Puget
Energy, Inc.
Common
Stock, $0.01 par value
NYSE
Preferred
Share Purchase Rights
NYSE
Securities
registered pursuant to Section 12(g) of the Act:
Title
Of Each Class
Puget
Sound Energy, Inc.
Preferred
Stock (cumulative, $100 par value)
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 if the registrant is a well-known seasoned issuer, as defined in
Rule 405 of the Securities Act.
Puget
Energy, Inc.
Yes
/X/
No
/ /
Puget
Sound Energy, Inc.
Yes
/X/
No
/ /
Indicate by check mark if the
registrant is not required to file reports pursuant to Section 13 or Section
15(d) of the Act.
Puget
Energy, Inc.
Yes
/ /
No
/X/
Puget
Sound Energy, Inc.
Yes
/ /
No
/X/
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.
Puget
Energy, Inc.
Yes
/X/
No
/ /
Puget
Sound Energy, Inc.
Yes
/X/
No
/ /
Indicate
by check mark if disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K is not contained herein, and will not be contained, to the best
of registrant’s knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. / /
Indicate
by check mark whether registrant is a large accelerated filer, an accelerated
filer, or a non-accelerated filer. See definition of “accelerated
filer and large accelerated filer” in Rule 12b-2 of the Exchange
Act.
Puget
Energy, Inc.
Large
accelerated filer
/X/
Accelerated
filer
/ /
Non-accelerated
filer
/ /
Smaller
reporting company
/ /
Puget
Sound Energy, Inc.
Large
accelerated filer
/ /
Accelerated
filer
/ /
Non-accelerated
filer
/X/
Smaller
reporting company
/ /
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Act)
Puget
Energy, Inc.
Yes
/ /
No
/X/
Puget
Sound Energy, Inc.
Yes
/ /
No
/X/
The
aggregate market value of the voting stock held by non-affiliates of Puget
Energy, Inc., computed by reference to the price at which the common stock was
last sold, as of the last business day of Puget Energy’s most recently completed
second fiscal quarter was approximately $2,754,398,000. The number of
shares of Puget Energy, Inc.’s common stock outstanding at February 20, 2008 was
129,678,489 shares.
All of
the outstanding shares of voting stock of Puget Sound Energy, Inc. are held by
Puget Energy, Inc.
This
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.
Infrastructure
investors led by Macquarie Infrastructure Partners, the Canada Pension
Plan Investment Board and British Columbia Investment Management
Corporation, and also includes Alberta Investment Management,
Macquarie-FSS Infrastructure Trust and Macquarie Capital Group
Limited
Puget
Energy, Inc. (Puget Energy) and Puget Sound Energy, Inc. (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 and assumptions
of future events or performance. Words or phrases such as
“anticipates,”“believes,”“estimates,”“expects,”“future,”“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:
·
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, cost recovery, 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 (natural gas and electric), licensing of hydroelectric
operations and natural gas storage facilities, recovery of other capital
investments, recovery of power and natural gas costs, recovery of
regulatory assets and present or prospective wholesale and retail
competition;
·
Failure
to comply with FERC or Washington Commission standards and/or rules, which
could result in penalties based on the discretion of either
commission;
·
Failure
to comply with electric reliability standards developed by the North
American Electric Reliability Corporation (NERC) for users, owners and
operators of the power system, which could result in penalties of up to
$1.0 million per day per violation;
·
Changes
in, adoption of and compliance with laws and regulations, including
decisions and policies concerning the environment, climate change,
emissions, natural resources, and fish and wildlife (including the
Endangered Species Act);
·
The
ability to recover costs arising from changes in enacted federal, state or
local tax laws through revenue in a timely manner;
·
Changes
in tax law, related regulations, or differing interpretation or
enforcement of applicable law by the Internal Revenue Service (IRS) or
other taxing jurisdiction, which could have a material adverse impact on
the financial statements;
·
Natural
disasters, such as hurricanes, windstorms, earthquakes, floods, fires and
landslides, which can interrupt service and/or cause temporary supply
disruptions and/or price spikes in the cost of fuel and raw materials and
impose extraordinary costs;
·
Commodity
price risks associated with procuring natural gas and power in wholesale
markets;
·
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, negatively
affect wholesale energy prices and/or impede PSE’s ability to manage its
energy portfolio risks and procure energy supply, affect the availability
and access to capital and credit markets and/or impact delivery of energy
to PSE from its suppliers;
·
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 it
suppliers;
·
The
effect of wholesale market structures (including, but not limited to,
regional market designs or transmission organizations) or other related
federal initiatives;
·
PSE
electric or natural gas distribution system failure, which may impact
PSE’s ability to deliver energy supply to its
customers;
·
Changes
in weather conditions in the Pacific Northwest, which could have effects
on customer usage and PSE’s revenues, thus impacting net
income;
·
Weather,
which can have a potentially serious impact on PSE’s ability to procure
adequate supplies of natural gas, fuel or purchased power to serve its
customers and on the cost of procuring such supplies;
·
Variable
hydro 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 with respect
to repair costs, added costs to replace energy or higher costs associated
with dispatching a more expensive resource;
·
The
ability of natural gas or electric plant to operate as
intended;
·
The
ability to renew contracts for electric and natural gas supply and the
price of renewal;
·
Blackouts
or large curtailments of transmission systems, whether PSE’s or others’,
which can affect PSE’s ability to deliver power or natural gas to its
customers and generating facilities;
·
The
ability to restart generation following a regional transmission
disruption;
·
Failure
of the interstate natural gas pipeline delivering to PSE’s system, which
may impact PSE’s ability to adequately deliver natural gas supply or
electric power to its customers;
·
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;
·
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;
·
The
loss of significant customers or changes in the business of significant
customers, which may result in changes in demand for PSE’s
services;
·
The
impact of acts of God, terrorism, flu pandemic or similar significant
events;
·
Capital
market conditions, including changes in the availability of capital or
interest rate fluctuations;
·
Employee
workforce factors, including strikes, work stoppages, availability of
qualified employees or the loss of a key executive;
·
The
ability to obtain insurance coverage and the cost of such
insurance;
·
Future
losses related to corporate guarantees provided by Puget Energy as a part
of the sale of its InfrastruX subsidiary;
·
The
ability to maintain effective internal controls over financial reporting
and operational processes; and
·
With
respect to merger transactions Puget Energy announced on October 26,2007:
§
The
risk that the merger may not be consummated in a timely manner if at all,
including due to the failure to receive shareholder approval or any
required regulatory approvals;
§
The
risk that the merger agreement may be terminated in circumstances that
require Puget Energy to pay a termination fee of up to $40.0 million, plus
out-of-pocket expenses of the acquiring entity and its members of up to
$10.0 million (or if no termination fee is payable, up to $15.0
million);
§
Risks
related to diverting management’s attention from ongoing business
operations;
§
The
effect of the announcement of the merger on our business relationships,
operating results and business generally, including our ability to retain
key 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. You are also
advised to consult the quarterly reports on Form 10-Q and current reports on
Form 8-K, as well as Item 1A-“Risk Factors” on this Form 10-K.
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 subsidiary, Puget Sound Energy, Inc. (PSE), a utility
company. Puget Energy has no significant assets other than the stock
of PSE. On October 26, 2007, Puget Energy announced a merger with a
consortium of long-term infrastructure investors led by Macquarie Infrastructure
Partners, the Canada Pension Plan Investment Board and British Columbia
Investment Management Corporation, and also includes Alberta Investment
Management, Macquarie-FSS Infrastructure Trust and Macquarie Capital Group
Limited (collectively, the Consortium). At the effective time of the
merger, each issued and outstanding share of common stock of Puget Energy, other
than any shares in respect of which dissenter’s rights are perfected and other
than any shares owned by the Consortium, shall be cancelled and shall be
converted automatically into the right to receive $30.00 in cash, without
interest.
The
consummation of the merger is subject to the satisfaction or waiver of certain
closing conditions, including approval of the transaction by Puget Energy’s
shareholders, the termination or expiration of the waiting period under the
Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (the HSR Act)
and the receipt of several regulatory approvals, including those from the
Washington Utilities and Transportation Commission (Washington Commission) and
the Federal Energy Regulatory Commission (FERC). The merger is
expected to close during the fourth quarter 2008. On May 7, 2006,
Puget Energy sold its 90.9% interest in InfrastruX Group, Inc. (InfrastruX) and
therefore the financial position and results of operations for InfrastruX are
presented as discontinued operations. Puget Energy and PSE are
collectively referred to herein as “the Company.” The following table
provides the percentages of Puget Energy’s consolidated continuing operating
revenues and net income generated and assets held by the operating
segments:
Segment
Percent
of Revenue
Percent
of Net Income
Percent
of Assets
2007
2006
2005
2007
2006
2005
2007
2006
2005
Puget
Sound Energy
99.6%
99.7%
99.7%
99.7%
103.3
%
91.7%
98.9%
99.0%
94.8%
InfrastruX1
0%
0%
0%
0%
0
%
6.1%
0%
0%
4.2%
Other2
0.4%
0.3%
0.3%
0.3%
(3.3)%
2.2%
1.1%
1.0%
1.0%
_______________
1
InfrastruX
was sold in May 2006 and is presented on a discontinued operations basis
in 2005 and 2006 and therefore does not present operating
revenue.
2
Includes
subsidiaries of PSE and Puget Energy holding company operations. 2006
includes the impact of the establishment and funding of a charitable
foundation.
Puget
Energy Strategy
Puget
Energy is the parent company of PSE, the oldest and largest electric and natural
gas utility headquartered in the state of Washington, primarily engaged in the
business of electric transmission, distribution, generation and natural gas
transmission and distribution. Puget Energy’s business strategy is to
generate stable earnings and cash flow by offering reliable electric and natural
gas service in a cost effective manner through PSE.
Puget
Sound Energy, Inc.
PSE is a
public utility incorporated in the state of Washington in 1960. PSE
furnishes electric and natural 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, 2007, PSE had approximately 1,056,400 electric customers,
consisting of 933,200 residential, 116,400 commercial, 3,800 industrial and
3,100 other customers; and approximately 729,500 natural gas customers,
consisting of 673,600 residential, 53,100 commercial, 2,600 industrial and 100
transportation customers. At December 31, 2007, approximately 363,200
customers purchased both electricity and natural gas from PSE. In
2007, PSE added approximately 17,100 electric customers and 16,500 natural gas
customers, representing annualized customer growth rates of 1.6% and 2.3%,
respectively. During 2007, PSE’s billed retail and transportation
revenues from electric utility operations were derived 52.4% from residential
customers, 40.6% from commercial customers, 5.6% from industrial customers and
1.4% from other customers. PSE’s retail revenues from natural gas
utility operations were derived 62.6% from residential customers, 30.0% from
commercial customers, 4.8% from industrial customers and 2.6% from
transportation customers in 2007. During this period the largest
customer accounted for approximately 1.2% of PSE’s operating
revenues.
PSE is
affected by various seasonal weather patterns and therefore, utility revenues
and associated expenses are not generated evenly during the
year. Energy usage varies seasonally and monthly primarily as a
result of weather conditions. PSE 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 natural gas rates to recover variations in natural gas supply and
transportation costs. PSE also has a Power Cost Adjustment (PCA)
mechanism in retail electric rates to recover variations in electricity costs on
a shared basis with customers.
In the
five-year period ended December 31, 2007, PSE’s gross electric utility plant
additions were $2.2 billion and retirements were $365.4 million. In
the same five-year period, PSE’s gross gas utility plant additions were $766.0
million and retirements were $101.7 million. In the same five-year
period, PSE’s gross common utility plant additions were $178.0 million and
retirements were $53.7 million. Gross electric utility plant at
December 31, 2007 was approximately $5.9 billion, which consisted of 50.9%
distribution, 34.1% generation, 5.7% transmission and 8.9% general plant and
other. Gross gas utility plant at December 31, 2007 was approximately
$2.3 billion, which consisted of 90.7% distribution and 8.7% general plant and
other. Gross common utility general and intangible plant at December31, 2007 was approximately $506.2 million.
InfrastruX
Group, Inc.
InfrastruX,
is a utility construction services business. On May 7, 2006, Puget
Energy sold its 90.9% interest in InfrastruX to an affiliate of Tenaska Power
Fund, L.P. (Tenaska). Puget Energy accounted for InfrastruX as a
discontinued operation.
Employees
At
February 20, 2008, Puget Energy had no employees and PSE had approximately 2,600
full-time employees. Approximately 1,200 PSE employees are
represented by the International Brotherhood of Electrical Workers Union (IBEW)
or the United Association of Plumbers and Pipefitters (UA). The
current labor contracts with the IBEW and UA run through March 31, 2010 and
September 30, 2010, respectively.
Corporate
Location
Puget
Energy’s and PSE’s principal executive offices are located at 10885 NE 4th Street,
Suite 1200, Bellevue, Washington98004 and the telephone number is (425)
454-6363.
Available
Information
The
information required by Item 101(e) of Regulation S-K is incorporated herein by
reference to the material under “Available Information” in Item 10 of Part III
of this annual report.
New York Stock Exchange
Certification
On May22, 2007, the CEO of Puget Energy and PSE filed a Section 303A.12(a) CEO
Certification with the New York Stock Exchange (NYSE). The CEO
Certification attests that the CEO is not aware of any violations by the Company
of the NYSE’s Corporate Governance Listing Standards.
PSE is
subject to the regulatory authority of: (1) the FERC with respect to
the transmission of electric energy, the sale of electric energy at wholesale,
accounting and certain other matters; and (2) the Washington Commission as to
retail rates, accounting, the issuance of securities and certain other
matters.
Federal
Regulation
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
Independent System Operator (ISO); or, alternatively, to describe its efforts to
participate in an RTO/ISO or the obstacles to such participation. PSE
had been an active participant in regional efforts to form an RTO/ISO in the
Pacific Northwest since the issuance of Order No. 2000. PSE has
continued to work with the Bonneville Power Administration (BPA) and other
regional transmission owners to address the transmission related issues in the
region via a new organization known as ColumbiaGrid.
The
Energy Policy Act of 2005 (EPAct 2005) added a requirement for FERC to certify
an Electric Reliability Organization (ERO) to develop mandatory and enforceable
electric system reliability standards. FERC has certified the North
American Electric Reliability Corporation (NERC) as the ERO to develop these
standards subject to FERC review and approval. On March 16, 2007,
FERC issued Order 693, “Mandatory Reliability Standards for the Bulk-Power
System,” which imposes penalties of up to $1.0 million per day per violation for
failure to comply with new electric reliability standards. FERC
approved 83 reliability standards developed by NERC. The 83 standards
comprise 586 requirements and sub-requirements. PSE must comply with
the standards and requirements which apply to the NERC functions for which PSE
has registered. On June 18, 2007, the standards became mandatory and
enforceable under federal law. Additional standards continue to be
developed and will be adopted in coming months or years. PSE expects
that the existing standards will change often as a result of modifications,
guidance and clarification following industry implementation and ongoing audits
and enforcement.
Per NERC
and Western Electricity Coordinating Council (WECC) guidelines, users, owners
and operators of the bulk power system that self-report non-compliance with any
of the NERC standards and that submit mitigation plans to address the
non-compliance will not be subject to sanctions if the mitigation plans were
submitted on or before June 18, 2007 and approved by WECC. PSE’s
compliance with NERC standards will be audited at least every three
years. The first such audit was conducted during the fourth quarter
2007.
State
Regulation
PSE’s
retail electric service is fully regulated by the Washington
Commission. PSE is not aware of any proposals or prospects for retail
deregulation in the state of Washington.
PSE’s
retail natural gas service is also regulated by the Washington
Commission. Since 1986, PSE has been offering natural gas
transportation as a separate service to industrial and commercial customers who
choose to purchase their natural gas supply directly from producers and natural
gas marketers. PSE earns similar margins on transportation service
and large-volume, interruptible natural gas sales. Accordingly, the
shifting of customers between sales and transportation service does not
materially impact utility margins or net income.
On
December 17, 2007, PSE and the Consortium filed a joint application with the
Washington Commission seeking approval of the merger. A decision by
the Washington Commission is expected on September 2, 2008. If
approved, closing is expected to occur during the fourth quarter
2008.
Electric
Regulation and Rates
Power Cost Adjustment
Mechanism. On June 20, 2002, the Washington Commission
approved a PCA mechanism that triggers if PSE’s costs to provide customers’
electricity falls outside certain bands established in an electric rate
case. The cumulative maximum pre-tax earnings exposure due to power
cost variations over the four-year period ending June 30, 2006 was limited to
$40.0 million plus 1% of the excess. On January 5, 2007, the
Washington Commission approved the continuation of the PCA mechanism under the
same annual graduated scale without a cumulative cap for excess power
costs. All significant variable power supply cost variables
(hydroelectric and wind generation, market price for purchased power and surplus
power, natural gas and coal fuel price, generation unit forced outage risk and
transmission cost) are included in the PCA mechanism.
The PCA
mechanism apportions increases or decreases in power costs, on a calendar year
basis, between PSE and its customers on a graduated scale:
Annual Power
Cost
Variability
Customers’
Share
Company’s
Share1
+/-
$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 was capped at a cumulative $40
million plus 1% of the excess. Power cost variations after June30, 2006 are apportioned on an annual basis, on the graduated scale
without a cumulative cap.
Electric General Rate
Case. On December 3, 2007, PSE filed a general rate case with
the Washington Commission which proposed an increase in electric rates of $174.5
million or 9.5% annually, effective November 3, 2008. PSE requested a
weighted cost of capital of 8.6%, or 7.29% after-tax, and a capital structure
that included 45.0% common equity with a return on equity of
10.8%. PSE expects an order to be issued by the Washington Commission
no later than October 2008.
On
January 5, 2007, the Washington Commission issued its order in PSE’s electric
general rate case filed in February 2006, approving a general rate decrease for
electric customers of $22.8 million or 1.3% annually. The rates for
electric customers became effective January 13, 2007. In its order,
the Washington Commission approved a weighted cost of capital of 8.4%, or 7.06%
after-tax, and a capital structure that included 44.0% common equity with a
return on equity of 10.4%. The Washington Commission had earlier
approved (on June 28, 2006) a power cost only rate case (PCORC) increase of
$96.1 million annually, effective July 1, 2006.
Power Cost Only Rate
Case. A limited-scope proceeding called a PCORC was approved
in 2002 by the Washington Commission to periodically reset power cost
rates. In addition to providing the opportunity to reset all power
costs, the PCORC proceeding also provides for timely review of new resource
acquisition costs and inclusion of such costs in rates at the time the new
resource goes into service. To achieve this objective, the Washington
Commission approved an expedited five-month PCORC decision timeline rather than
the statutory 11-month timeline for a general rate case.
On March20, 2007, PSE submitted a PCORC filing to request approval of an updated power
cost baseline rate beginning September 2007. The PCORC filing also
requested recovery of ownership and operating costs of the Goldendale generating
facility (Goldendale) through retail electric rates. On May 23, 2007,
PSE filed updated power costs due to changes in market conditions of natural gas
and other costs which resulted in a revised proposed increase of $77.8 million
or 4.4% annually. On July 5, 2007, a settlement agreement in this
PCORC signed by PSE and certain other parties to the proceeding was filed with
the Washington Commission, the terms of which included an electric rate increase
of $64.7 million. On August 2, 2007, the Washington Commission
approved the settlement agreement and authorized an increase in PSE’s electric
rates of $64.7 million or an average increase of 3.7% annually effective
September 1, 2007. The investment in Goldendale was found
prudent, thus allowing for recovery of certain ownership and operating costs
through electric retail rates effective September 1, 2007 along with updating
other power costs.
In
accordance with the August 2, 2007 Washington Commission order approving the
PCORC settlement, PSE and other parties agreed to conduct a collaborative
stakeholder review of the PCORC process to consider the scope and timing of the
PCORC mechanism. The collaborative review included but was not
limited to: 1) the number of PCORCs that a company will be allowed to file in
any given year; 2) the number and timing of updates that a company may submit in
the PCORC process; 3) the items directly associated with power costs that may be
included and considered in a PCORC filing; and 4) whether the number and timing
of updates may vary depending on if other parties can easily
verify. On December 12, 2007, the collaboration filed a final report
with the Commission reporting that the parties were not able to reach agreement
on revisions to the PCORC mechanism and that the parties will address such
issues in the Company’s pending general rate case filing.
On April11, 2007, the Washington Commission approved PSE’s petition for issuance of an
accounting order that authorizes PSE to defer certain ownership and operating
costs (and associated carrying costs) related to the Company’s purchase of
Goldendale during the period prior to inclusion in PSE’s retail electric rates
in the PCORC. The deferral is for the time period from March 15, 2007
through September 1, 2007. As of December 31, 2007, PSE had
established a regulatory asset of $11.5 million. PSE anticipates
recovery of the costs will begin no later than November 2008 as determined in
PSE’s next general rate case.
On
October 20, 2005, the Washington Commission approved a PCORC filing that
increased electric rates 3.7% or $55.6 million annually. Included in
the increase is the recovery of capital and operating costs of the Hopkins Ridge
wind generating facility (Hopkins Ridge). The Hopkins Ridge wind
generating facility was completed on November 27, 2005. As a wind
generating facility, Hopkins Ridge is eligible for Federal Production Tax
Credits (PTCs) that will ultimately offset some of the costs associated with
generating power from Hopkins Ridge. The PTC is a tax credit provided
by the federal government for generating electricity from certain renewable
resources. The current amount of the tax credit is $0.02 per kilowatt
hour (kWh) for wind generation and may be subject to inflation adjustments over
time. The tax credit can be claimed for ten years for a new wind
project put into service prior to January 1, 2008. The use of the
credit is restricted to offset only 25.0% of current taxes
payable. Unused credits can be carried forward for up to 20
years. In the Washington Commission’s October 2005 order, a new
tariff schedule was approved which provides for the pass through to ratepayers
of all benefits of the PTCs of the Hopkins Ridge project. This
mechanism (a PTC Tracker) will pass through to the customer the actual PTCs of
the Hopkins Ridge project as they are generated. The PTC Tracker
would not be subject to the sharing bands in the PCA. The credits
passed through to the customer will be adjusted by the carrying costs of unused
PTCs. Since the customer receives the benefit of the tax credits as
they are generated and the Company does not receive a credit from the Internal
Revenue Service (IRS) until the tax credits are utilized, the Company is
reimbursed its carrying costs for funds through this calculation.
Gas
Regulation and Rates
Gas General Rate
Case. On December 3, 2007, PSE filed a general rate case with
the Washington Commission which proposed an increase in natural gas rates of
$56.8 million or 5.3% annually, effective November 3, 2008. PSE
requested a weighted cost of capital of 8.6%, or 7.29% after-tax, and a capital
structure that included 45.0% common equity with a return on equity of
10.8%. PSE expects an order to be issued by the Washington Commission
no later than October 2008.
On
January 5, 2007, the Washington Commission issued its order in PSE’s natural gas
general rate case, granting an increase in natural gas rates of $29.5 million or
2.8% annually, effective January 13, 2007, which resulted in an increase in
natural gas margin of approximately 9.8% annually. In its order the
Washington Commission approved the same weighted cost of capital of 8.4%, or
7.06% after-tax, and capital structure that included 44.0% common equity with a
return on equity of 10.4%, as allowed for the Company’s electric
operations.
Purchased Gas
Adjustment. PSE has a PGA mechanism in retail natural gas
rates to recover variations in natural gas supply and transportation
costs. Variations in natural gas rates are passed through to
customers, therefore PSE’s natural gas margin and net income are not affected by
such variations. On September 26, 2007, the Washington Commission
approved PSE’s requested revisions to its PGA tariffs resulting in a rate
decrease for natural gas customers of $148.1 million or 13.0% annually effective
October 1, 2007. The rate decrease was the result of lower costs of
natural gas in the forward market and a refund of the accumulated PGA payable
balance over a 12-month period beginning October 1, 2007. The PGA
rate change will decrease PSE’s revenue but will not impact the Company’s
natural gas margins or net income as the decreased revenue will be offset by
decreased purchased natural gas costs and decreased revenue sensitive
taxes.
The
following rate adjustments were approved by the Washington Commission in
relation to the PGA mechanism during 2007, 2006 and 2005:
At December 31, 2007, PSE’s electric
power resources had a total capacity of approximately 4,719 megawatts
(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 may supplement 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. When it is more economical to
purchase power than to run the Company’s generation, PSE will purchase in the
short-term markets.
The following table shows PSE’s
electric energy supply resources at December 31, 2007 and 2006 and energy
production during the year:
Peak
Power Resources
At
December 31
Energy
Production
At
December 31
2007
2006
2007
2006
MW
%
MW
%
MWh
%
MWh
%
Purchased
resources:
Columbia
River PUD contracts1
1,073
22.7%
1,164
26.1%
5,810,416
22.8%
5,692,366
23.1%
Other
hydroelectric2
168
3.6%
168
3.8%
570,639
2.2%
653,362
2.6%
Other
producers2
944
20.0%
932
20.9%
2,964,199
11.6%
3,279,575
13.3%
Wind
50
1.1%
--
--
8,570
0.2%
--
--
Short-term
wholesale energy purchases3
N/A
N/A
N/A
N/A
7,473,458
29.4%
8,185,276
33.2%
Total
purchased
2,235
47.4%
2,264
50.8%
16,827,282
66.2%
17,810,579
72.2%
Company-controlled
resources:
Hydroelectric
236
5.0%
234
5.3%
1,154,234
4.5%
949,276
3.9%
Coal
677
14.3%
677
15.2%
5,142,912
20.2%
4,800,028
19.5%
Natural
gas/oil4
1,192
25.3%
902
20.2%
1,310,625
5.1%
723,190
2.9%
Wind5
379
8.0%
379
8.5%
1,015,323
4.0%
372,829
1.5%
Total
company-controlled
2,484
52.6%
2,192
49.2%
8,623,094
33.8%
6,845,323
27.8%
Total
4,719
100.0%
4,456
100.0%
25,450,376
100.0%
24,655,902
100.0%
_______________
1
Net
of 59 MW of capacity delivered to Canada pursuant to the provisions of a
treaty between Canada and the US and Canadian Entitlement Allocation
agreements.
2
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.
3
Short-term
wholesale purchases net of resale of 2,253,055 MWh and 2,067,849 MWh
account for 22.5% and 27.1% of energy production for 2007 and 2006,
respectively.
PSE is required by the Washington
Commission to file electric and natural gas Integrated Resource Plans (IRP)
every two years. PSE filed its 2007 IRP on May 31, 2007 with the
Washington Commission. The plan supports a strategy of significantly
increasing energy efficiency programs, pursuing additional renewable resources
(primarily wind) and additional base load natural gas fired generation to meet
the growing needs of our customers. The 2007 IRP found that
developing new coal resources without a commercially viable means of mitigating
carbon emissions would not be prudent. PSE’s IRP analysis anticipates
the Company will need to acquire 550 additional MW of wind resources, 1,200 MW
of natural gas combined cycle resources and 314 average MW (aMW) of additional
energy efficiency resources by 2015. The actual resources acquired
and ownership structure of such resources will be determined through the
Company’s resource acquisition program that examines individual specific
acquisition and development opportunities.
In August 2006, PSE announced the
selection of seven projects for further consideration and possible negotiation
as a result of the 2005 Request for Proposal (RFP) process. PSE has
completed three transactions, including the purchase of Goldendale, a four-year
power purchase agreement for 150 MW of winter on-peak energy commencing in 2008
and a power purchase agreement executed on July 12, 2007 for a portion of the
output of Klondike Wind Power III, LLC, a wind-powered electric generating
facility in north-central Oregon which was completed in December
2007. Of the remaining four opportunities, PSE remains in discussion
on one project and has discontinued discussions on the other
three. In October 2007, PSE filed two draft RFPs with the Washington
Commission seeking approval to continue expansion of its energy-efficiency
programs and acquisition of power supplies. PSE released its final
RFPs in mid-January 2008. The first RFP seeks to broaden and expand
PSE’s program for helping customers conserve energy. The second RFP
asked outside power producers, marketers and power-plant developers to help PSE
procure up to 1,340 aMW of new electricity resources by 2015.
Based on PSE’s projected customer usage
for electricity and its current electric generation resources, PSE expects that
future energy needs will exceed current purchased and Company-controlled power
resources. The expected aMW shortfall for the period 2008 through
2011 is as follows:
2008
2009
2010
2011
Projected
aMW shortfall1
412
222
304
517
_______________
1
Monthly
average energy shortfall based on forecast January loads and estimated
using all energy resources under long-term contracts and
Company-controlled facilities.
PSE expects to address this shortfall
position with the use of a combination of new long-term power contracts and the
purchase or construction of additional generating resources.
Company
– Controlled Electric Generation Resources
At December 31, 2007, PSE owns or
controls the following plants with an aggregate net generating capacity of 2,484
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
Frederickson
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
Goldendale
Natural
gas combined cycle
277
2004
Frederickson
Unit 1 (49.85% interest)
Natural
gas combined cycle
137
2002
Encogen
Natural
gas cogeneration
167
1993
Crystal
Mountain
Internal
combustion
3
1969
Upper
Baker River
Hydroelectric
91
1959
Lower
Baker River
Hydroelectric
79
1925;
reconstructed 1960; upgraded 2001
Snoqualmie
Falls
Hydroelectric
44
1898
to 1911 & 1957
Electron
Hydroelectric
22
1904
to 1929
Wild
Horse
Wind
229
2006
Hopkins
Ridge
Wind
150
2005
Total
net capacity
2,484
Sumas
Cogeneration Facility
On December 10, 2007, PSE signed an
agreement to purchase the Sumas Cogeneration Facility (Sumas), a 125 MW capacity
natural gas cogeneration facility in the state of Washington, from the Sumas
Cogeneration Company, L.P. This purchase is anticipated to be
finalized in the second half of 2008.
FERC Hydroelectric Projects And
Licenses
As part
of its hydroelectric operations, PSE is required to obtain operating 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 for a 30 to 50 year
period. 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. FERC
regulates dam safety and administers proceedings under the Federal Power Act
(FPA) to license jurisdictional hydropower projects.
PSE owns
three operating hydroelectric projects: the Baker River project, the Snoqualmie
Falls project and the Electron project. PSE’s 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.
Baker River
project. The Baker River project’s current annual license
expires on April 30, 2008 and PSE submitted an application for a new license to
FERC on April 30, 2004. On November 30, 2004, PSE and 23 parties
(federal, state and local governmental organizations, Native American Indian
tribes, environmental and other non-governmental 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 for a new license of 45 years or more. The
proposed settlement would require an investment of approximately $360.0 million
over the next 30 years (capital expenditures and operations and maintenance
cost) in order to implement the conditions of the new license. The
proposed settlement is subject to additional regulatory approvals yet to be
attained from various agencies and other contingencies that have yet to be
resolved. FERC has not yet ruled on the proposed settlement and its
ultimate outcome remains uncertain.
Snoqualmie Falls
project. The Snoqualmie Falls project was granted a new
40-year operating license by FERC on June 29, 2004. On July 29, 2004,
the Snoqualmie Tribe filed a request for rehearing of the new license and a
request to stay the FERC license. On March 1, 2005, FERC issued an
Order on Rehearing and Dismissing Stay Request. Appeals to the U.S.
Court of Appeals by the Snoqualmie Tribe and by PSE have been
consolidated. Oral arguments were held on February 8,2007. An adverse ruling from the Court or adverse action by FERC if
the license issuance is remanded could impact PSE’s future use of this
generating asset. In addition, on December 6, 2007, PSE filed an
application for a non-capacity amendment to the 2004 license. The
application seeks to amend the license to account for technology improvements
and hydrologic and other changes that occurred post-license. The
ultimate outcome of the license amendment application remains
uncertain.
White River
project. The White River project was operated as a hydropower
facility until 2004. PSE is actively seeking to sell the project and
the municipal water rights associated with the project to one or more
entities. In June 2003, the Washington State Department of Ecology
(Ecology) approved an application for new municipal water rights related to the
White River project reservoir. After an appeal in July 2004, this
decision was remanded back to Ecology for further analysis of non-hydropower
operations. On December 21, 2006, PSE entered into a Purchase and
Sale Agreement with the Cascade Land Conservancy to sell certain rights and
interests in a portion of former project properties; however, this agreement has
lapsed and PSE is examining its options.
On April7, 2004, the Washington Commission approved PSE’s recovery on the unamortized
White River plant investment. At December 31, 2007, the White River
project net book value totaled $72.5 million, which included $41.9 million of
net utility plant, $17.3 million of capitalized FERC licensing costs, $6.7
million of costs related to construction work in progress and $6.6 million
related to dam operations and safety. On February 18, 2005, the
Washington Commission approved the recovery of the White River net utility plant
costs but did not allow current recovery of FERC licensing costs and other
related costs until all costs associated with selling the White River plant and
any sales proceeds are known. Any proceeds from the sale of the White
River assets and water rights will reduce the balance of the deferred regulatory
asset. Neither the outcome of this matter nor any potential
associated financial impacts can be predicted at this time.
Columbia River Electric Energy Supply
Contracts
During
2007, approximately 22.8% of PSE’s energy output was obtained at an average cost
of approximately $0.015 per kWh through long-term contracts with several of the
Washington Public Utility Districts (PUDs) that own and operate hydroelectric
projects on the Columbia River. PSE agrees to pay a proportionate
share of the annual debt service, operating and maintenance costs and other
expenses associated with each project. PSE’s payments are not
contingent upon the projects being operable.
As of
December 31, 2007, the Company was entitled to purchase portions of the power
output of the PUDs’ projects as set forth:
Company’s
Annual
Amount
Purchasable
(Approximate)
Project
Contract
Exp.
Year
License
Exp.
Year
%
of
Output
Megawatt
Capacity
Chelan
County PUD:1
Rock
Island Project
Original
units
2012
2029
50.0
}
248
Additional
units
2012
2029
50.0
Rocky
Reach Project
2011
2006
38.9
488
Douglas
County PUD:
Wells
Project
2018
2012
29.9
251
Grant
County PUD:2,3
Priest
Rapids Development
TBD
TBD
4.3
39
Wanapum
Development
2009
TBD
10.8
106
Total
1,132
_______________
1
On
February 3, 2006, PSE and Chelan entered into a new Power Sales Agreement
and a related Transmission Agreement for 25.0% of the output of Chelan’s
Rocky Reach and Rock Island hydro electric generating facilities located
on the mid-Columbia River in exchange for PSE paying 25.0% of the
operating costs of the facilities. The agreements terminate in
2031 and provide that PSE will begin to receive power upon expiration of
PSE’s existing long-term contracts with Chelan for the Rocky Reach and
Rock Island output (expiring in 2011 and 2012, respectively). PSE made a
non-refundable capacity reservation payment of $89.0 million as required
by the agreements. The Washington Commission determined the
prudence of PSE entering into the new Chelan contract and confirmed the
treatment of the $89.0 million as a regulatory asset as part of its order
in PSE’s General Rate Case on January 5, 2007.
2
Under
terms of the
2001 Grant contract extensions,
PSE will continue to obtain capacity and energy for the term of any new
FERC license to be obtained by Grant County PUD. The
new contracts’ terms
began in November of 2005 for the Priest Rapids Development and will
begin in
November of 2009 for the Wanapum
Development.
3
PSE’s
share of power from the 2001 contract declines over time as Grant County
PUD’s load increases. PSE’s share of the Wanapum Development
will remain at 10.8% until November 2009 and will be adjusted annually
thereafter for the remaining term of the new contracts. PSE’s
share of the Priest Rapids Development was 4.3% in 2007 and will be
adjusted annually for the remaining term of the new
contract.
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 generally is not obligated to make payments under these
contracts unless power is delivered.
Under a 1985 settlement agreement with
BPA, PSE is entitled to receive exchange energy from BPA during the months of
November through April, which amounts to 42 aMW of energy and 82 MW of capacity
for contract year 2007-2008. BPA has an option to request that PSE
deliver up to 42 aMW of exchange energy to BPA in all months except May, July
and August for contract year 2007-2008. The contract terminates June30, 2017, but may be terminated earlier under certain
circumstances.
On
October 1, 1989, PSE signed a contract with The Montana Power Company, now
NorthWestern Energy, for 71 aMW of energy (97 MW of peak capacity) through
December 2010. The contract deliveries are contingent on the combined
availability of Colstrip Units 3 & 4. The contract payments
consist of a fixed monthly payment and an energy payment based on commodity and
transportation costs for coal. The fixed payment may be reduced if
the delivered energy is less than the adjusted energy entitlement (equal to an
equivalent availability of approximately 73.0%) for the contract
year.
In
January 1992, PSE executed an agreement with Pacific Gas & Electric Company
(PG&E) to exchange 300 MW of capacity together with up to 413,000 megawatt
hours (MWh) of energy seasonally each year. No payments are made
under this agreement. PG&E provides power during the months of
November through February and PSE provides power during the months of June
through September. Each party may terminate the contract upon five
year prior notice.
Electric Energy Supply Contracts and
Agreements With Non-Utility Generators
As required by the federal Public
Utility Regulatory Policies Act (PURPA), PSE has entered into long-term firm
purchased power contracts with non-utility generators. The most
significant contracts are described below. PSE purchases the net
electrical output of these three projects at fixed and annually escalating
prices, intended to approximate PSE’s avoided cost of new generation projected
at the time these agreements were made.
As of
December 31, 2007, the Company purchased the power output from the
following:
Average
Plant
Contract
Megawatt
Megawatts
Contract
Type
Exp.
Year
Capacity
of
Energy
March
Point Cogeneration Company:
March
Point Phase I
Natural
gas cogeneration
2011
80
70
March
Point Phase II
Natural
gas cogeneration
2011
60
53
Tenaska
Washington Partners, LP
Natural
gas cogeneration
2011
245
216
Total
385
339
Electric
Transmission Contracts With Other Utilities
PSE has
entered into numerous transmission contracts with BPA to integrate electric
generation and contracted resources into PSE’s system. These
transmission contracts require PSE to pay for transmission service based on the
contracted MW level of demand, regardless of actual use. Any costs
incurred are recovered through the PCA mechanism.
Other
agreements provide actual capacity ownership or capacity ownership
rights. PSE’s annual charges are also based on contracted MW
volumes. Capacity on these agreements that is not committed is
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 have various terms and collectively have an
aggregate demand limit in excess of 3,550 MW.
PSE currently purchases a blended
portfolio of natural gas supplies ranging from long-term firm to daily 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
natural gas to serve its customers. All of PSE’s natural gas supply
is ultimately transported through the facilities of Northwest Pipeline GP (NWP),
the sole interstate pipeline delivering directly into western
Washington. Delivery of gas supply to PSE’s natural gas system is
therefore dependent upon the operations of NWP.
2007
2006
Peak
Firm Natural Gas Supply at December 31
Dth
per Day
%
Dth
per Day
%
Purchased
gas supply:
British
Columbia
204,500
21.3%
235,000
24.3%
Alberta
60,000
6.2%
60,000
6.2%
United
States
156,600
16.3%
145,700
15.1%
Total
purchased natural gas supply
421,100
43.8%
440,700
45.6%
Purchased
storage capacity:
Clay
Basin
91,000
9.5%
76,000
7.9%
Jackson
Prairie
55,100
5.7%
55,100
5.7%
AECO
hub - Canada
16,700
1.7%
16,700
1.7%
Liquefied
natural gas
70,500
7.3%
70,500
7.3%
Total
purchased storage capacity
233,300
24.2%
218,300
22.6%
Owned
storage capacity:
Jackson
Prairie
294,700
30.7%
294,700
30.5%
Propane-air
and other
12,500
1.3%
12,500
1.3%
Total
owned storage capacity
307,200
32.0%
307,200
31.8%
Total
peak firm natural gas supply
961,600
100.0%
966,200
100.0%
Other
and commitments with third parties
(41,600)
(44,400)
Total
net peak firm natural gas supply
920,000
921,800
All
peak firm gas supplies and storage are connected to PSE’s market with firm
transportation capacity.
PSE supplements its firm natural gas
supply portfolio by purchasing natural gas, injecting it into underground
storage facilities and withdrawing it during the peak winter heating season, for
baseload and peak-shaving purposes. 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 natural gas system. Peaking needs are also met
by using PSE-owned natural 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
natural 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.
Natural
Gas Supply Portfolio
For the 2007-2008 winter heating
season, PSE contracted for approximately 21.3% of its expected peak-day natural
gas supply requirements from sources originating in British Columbia, Canada
under a combination of long-term, medium-term and seasonal purchase
agreements. Long-term natural gas supplies from Alberta represent
approximately 6.2% of the peak-day requirements. Long-term and winter
peaking arrangements with U.S. suppliers make up approximately 16.3% of the
peak-day portfolio. The balance of the peak-day requirements is
expected to be met with natural gas stored at Jackson Prairie, Clay Basin and
AECO hub (AECO), LNG held at NWP’s Plymouth facility and propane-air gas and
other resources, which represent approximately 36.4%, 9.5%, 1.7%, 7.3% and 1.3%,
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. The January 2008
firm natural gas supply portfolio consisted of arrangements with 20 producers
and natural gas marketers, with no single supplier representing more than 4.2%
of expected peak-day requirements. Contracts have remaining terms
ranging from less than one year to seven years.
During 2007, approximately 34.4% of
natural gas supplies purchased by PSE originated in British Columbia while 18.5%
originated in Alberta and 47.1% originated in the United
States. PSE’s firm natural gas supply portfolio has flexibility in
its transportation arrangements so that some savings can be achieved when there
are regional price differentials between natural gas supply
basins. The geographic mix of suppliers and daily, monthly and annual
take requirements permit some degree of flexibility in managing natural gas
supplies during off-peak periods to minimize costs. Natural gas is
marketed outside PSE’s service territory (off-system sales) whenever on-system
customer demand requirements permit.
Natural
Gas Storage Capacity
PSE holds storage capacity in the
Jackson Prairie and Clay Basin underground natural gas storage facilities
adjacent to NWP’s pipeline and at AECO in Alberta, Canada adjacent to Nova Gas
Transmission, Ltd. (TransCanada-Alberta). These facilities represent
47.6% 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
natural gas over a relatively short time period. Combined with
capacity contracted from NWP’s one-third stake in Jackson Prairie, PSE has peak
firm withdrawal capacity of over 349,000 Dekatherm (one Dekatherm, or Dth, is
equal to one million British thermal units or MMBtu) per day and total firm
storage capacity of over 8,800,000 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 natural gas
requirements. PSE has been in the process of expanding the storage
capacity at Jackson Prairie since March 2003 and plans to continue through 2010
or 2011. At the end of this project, PSE will have added
approximately 2,000,000 Dth of additional working storage
capacity. In order to meet the growing peaking requirements in the
region, PSE and other owners of Jackson Prairie obtained FERC authorization on
February 5, 2007 to increase deliverability of the project from 884,000 Dth per
day to 1,196,000 Dth per day. PSE’s share of this expansion, 104,000
Dth per day, is expected to cost $15.0 million and to be in service by November
2008. 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. PSE holds 13,400,000 Dth of Clay Basin capacity
under two long-term contracts with remaining terms of five years and 12
years. PSE has exchanged 2,000,000 Dth of this Clay Basin capacity
for 2,000,000 Dth of AECO storage capacity, which includes withdrawal capacity
of approximately 16,700 Dth per day and terminates March 31,2008. Net of this and other releases, PSE’s maximum firm withdrawal
capacity and total storage capacity at Clay Basin is approximately 91,000 Dth
per day and exceeds 10,900,000 Dth, respectively.
LNG and Propane-Air
Resources
LNG and propane-air resources provide
natural gas supply on short notice for short periods of time. Due to
their typically high cost and slow cycle times, 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 natural gas as LNG at NWP’s Plymouth facility, which
is approximately three and one-half day’s 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
natural gas per day for up to 12 days directly into PSE’s distribution
system. PSE owns and operates a LNG peaking facility in Gig Harbor
with total capacity of 10,600 Dth.
Natural Gas Transportation
Capacity
PSE currently holds firm transportation
capacity on pipelines owned by NWP, Gas Transmission Northwest (GTN), Nova Gas
Transmission (NOVA), Foothills Pipe Lines (Foothills) and Westcoast Energy
(Westcoast). GTN, NOVA, and Foothills are TransCanada
companies. Accordingly, PSE pays fixed monthly demand charges for the
right, but not the obligation, to transport specified quantities of natural gas
from receipt points to delivery points on such pipelines each day for the term
or terms of the applicable agreements.
PSE holds firm year-round capacity on
NWP through various contracts. When market and operational conditions
allow, PSE participates in the secondary pipeline capacity market to achieve
savings for PSE’s customers. PSE holds approximately 520,000 Dth per
day of capacity on NWP that provides firm delivery to PSE’s service
territory. In addition, PSE holds approximately 414,000 Dth per day
of seasonal firm capacity on NWP to provide for delivery of natural gas stored
in Jackson Prairie and the Plymouth LNG facility during the heating
season. PSE has committed to additional firm seasonal capacity of
approximately 111,000 Dth per day commencing November 1, 2008 for a 20 year
term. PSE has firm transportation capacity on NWP that supplies
electric generating facilities with approximately 67,000 Dth per day, with a
remaining term of 11 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 one year to 11 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 GTN’s pipeline,
totaling approximately 90,000 Dth per day, has a remaining term of 16
years.
PSE’s firm transportation capacity on
Westcoast’s pipeline is approximately 97,000 Dth per day until October 31, 2012,
then approximately 86,000 Dth per day until October 31, 2014, then approximately
41,000 Dth per day until October 31, 2017 and thereafter approximately 15,000
Dth per day until October 31, 2018. PSE has other firm transportation
capacity on Westcoast’s pipeline, which supplies the electric generating
facilities, totaling approximately 22,000 Dth per day, with a remaining term of
seven years. PSE has firm transportation capacity on NOVA and
Foothills pipelines, totaling approximately 80,000 Dth per day, a portion of
which has a remaining term of 15 years. PSE has annual rollover
rights on the remainder of this capacity.
Capacity
Release
FERC provides a capacity release
mechanism as the means for holders of firm pipeline and storage entitlements to
temporarily or permanently 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 pipeline capacity not utilized
during off-peak periods through capacity release. Capacity release
benefits are passed on to customers through the PGA mechanism.
PSE
offers programs designed to help new and existing residential, commercial and
industrial 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. Energy efficiency programs reduce customer
consumption of energy thus reducing energy margins. The impact of
load reductions is adjusted in rates at each general rate case.
Since
1995, PSE has been authorized by the Washington Commission to defer natural 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, natural gas
energy efficiency expenditures have no impact on earnings.
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 mechanism, electric energy
efficiency expenditures have no effect on earnings.
PSE’s
2006-2007 two-year energy efficiency savings goals (40 aMW and 4.2 million
therms) were set based on the 2005 IRP and in conjunction with the Conservation
Resource Advisory Group (CRAG) per the terms of the 2002 Conservation
Stipulation Agreement. The 2007 electric annual “baseline” savings
goal of 18.3 aMW was agreed upon to reflect the new electric incentive-penalty
mechanism approved in the Company’s 2006 General Rate Case. The
two-year natural gas savings goal to avoid a “penalty” mechanism
remained at 4.2 million therms.
For the
two-year period, 2006-2007, PSE achieved 44.4 aMW and over 5.0 million therms of
cost-effective energy savings. For 2007 only, PSE achieved savings of
25.4 aMW and almost 2.7 million therms exceeding its goals and earning an
electric incentive of $3.4 million (75% to be collected in 2008 and 25% subject
to evaluation and collection in 2009) and avoiding any natural gas
penalty.
In 2007,
PSE and the CRAG met
regularly to share and discuss plans for energy efficiency programs, set targets
and budgets and agree on a course of action for 2008 and
2009. In setting these targets, PSE and the CRAG considered the
energy efficiency resource potential identified in the Company’s 2007 IRP, as
well as individual program cost effectiveness and market conditions. The
collaborative process resulted in establishing overall 2008-2009 biennial energy
efficiency acquisition targets and budgets for 53.3 aMW for electric programs
and 5.3 million therms for natural gas programs.
The
biennial electric savings target was further disaggregated to annual targets, as
required by electric incentive-penalty mechanism. Thus, PSE, in
consultation with the CRAG, has established a 2008 incentive threshold target
range of 22.2 aMW to 24.7 aMW. For 2008, an incentive will be paid to
the Company upon achieving savings of greater than or equal to 24.7
aMW. Conversely, if the Company achieves savings of 22.2 aMW or less,
a penalty will be assessed. The annual incentive threshold target
range for 2009 will be set prior to year-end 2008.
The
biennial natural gas savings target of 4.2 million therms is still subject to
the penalty mechanism established in the 2002 Conservation Stipulation
Agreement. If natural gas conservation savings are less than 75% of
the minimum goal, PSE will be subject to a penalty of $0.75
million. If savings are between 75% and 89% of the minimum, the
penalty is $0.5 million, and between 90% and 99% of the minimum, the penalty is
$0.2 million.
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.
Greenhouse Gas Policy
PSE recognizes the growing concern that
increased atmospheric concentrations of greenhouse gases contribute to climate
change. PSE believes that climate change is a very important issue
that requires careful analysis and responses. PSE’s policy is to take
cost-effective measures to mitigate and/or offset greenhouse gas emissions from
our energy activities while maintaining a dependable, cost-effective and diverse
energy portfolio mix that will sustain our customers’ needs now and into the
future. PSE is taking and will continue to take appropriate steps to
meet the goal of providing cost-effective and reliable energy while decreasing
the impact on climate change through the implementation of these
measures. The full PSE Greenhouse Gas Policy is available at
www.pse.com.
Regulation
Of Emissions
PSE facilities are subject to
regulation of emissions, including PSE’s interest in coal-fired, steam-electric
generating plants at Colstrip, Montana and its combustion turbine
units. There is no assurance that future environmental laws and
regulations affecting sulfur dioxide, carbon monoxide particulate matter or
nitrogen oxide emissions will not be more restrictive, or that restrictions on
greenhouse gas emissions, such as carbon dioxide, or other combustion
byproducts, such as mercury, may not be imposed at the federal or state
level.
Emissions
Inventory
During 2007, PSE’s total electric
retail load of 21.6 million MWh was served from a supply portfolio of owned and
purchased resources. Since 2002, PSE has voluntarily undertaken an inventory of
its greenhouse gas (GHG) emissions associated with this
portfolio. Such inventory follows the protocol established by the
World Resource Institute GHG Protocol (GHG Protocol). The most recent
data indicate that PSE’s total GHG emissions (direct and indirect) from its
electric supply portfolio in 2006 were 13.5 million tons
(CO2e). Approximately 43.7% of these emissions (approximately 5.9
million tons) are associated with PSE’s ownership and contractual interests in
the 2,200 MW Colstrip, Montana coal-fired steam electric generation facility
(Colstrip).
Colstrip is a significant part of the
diversified portfolio PSE owns and/or operates for its
customers. Consequently, while Colstrip remains a significant portion
of our overall GHG emissions, PSE’s overall emissions strategy demonstrates a
concerted effort to manage our customers’ needs with an appropriate balance of
new renewable generation, existing generation owned and/or operated by PSE and
significant energy efficiency efforts.
With ongoing development
of state and federal initiatives intended to address climate change, the
challenge to develop strategic solutions is more complicated than
ever. However, PSE believes that now is the time to
act. Consequently, PSE included a carbon intensity goal into its most
recent IRP that will adhere to the objectives of our recently published
Greenhouse Gas Policy.
On May 18, 2005, the Environmental
Protection Agency (EPA) enacted the Clean Air Mercury Rule (CAMR) that will
permanently cap and reduce mercury emissions from coal-fired power
plants. The Montana Board of Environmental Review approved a more
stringent rule to limit mercury emissions from coal-fired plants on October 16,2006 (0.9 lbs/TBtu, instead of the federal
1.4 lbs/TBtu). The Colstrip owners are still evaluating the
potential impact of the new Montana rule and it is still unknown whether the new
rule will be appealed. Preliminary treatment technology studies
undertaken by the Colstrip owners estimate that PSE’s portion of the costs to
comply with the new rule could be as much as $75.0 million in construction
expenditures, but this number could change as new information becomes
available.
On June15, 2005, the EPA issued the Clean Air Visibility Rule to address regional haze
or regionally-impaired visibility caused by multiple sources over a wide
area. The rule defines Best Available Retrofit Technology (BART)
requirements for electric generating units, including presumptive limits for
sulfur dioxide, particulate matter and nitrogen oxide controls for large
units. In February 2007, Colstrip was notified by EPA that Colstrip
Units 1 & 2 were determined to be subject to the BART
requirements. PSE submitted a BART engineering analysis for Colstrip
Units 1 & 2 in August 2007. PSE cannot yet determine the need for
or costs of additional controls to comply with this rule.
Federal Endangered Species
Act
Since 1991, a total of seventeen
species of Northwest and Columbia River Basin salmon and steelhead have been
listed as threatened or endangered species under the Endangered Species Act,
which influences hydroelectric operations. While the most significant
impacts have affected the Mid-Columbia PUDs, certain Endangered Species Act
impacts may affect PSE operations, potentially representing cost exposure and
operational constraints. PSE is actively engaging the federal
agencies to address Endangered Species Act issues for PSE’s generating
facilities.
The executive officers of Puget Energy
as of February 28, 2008 are listed below. 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
60
Chairman,
President and Chief Executive Officer since May 2005; President and Chief
Executive Officer, 2002 – 2005. Director since January
2002.
J.
W. Eldredge
57
Vice
President, Controller and Chief Accounting Officer since May 2007; Vice
President, Corporate Secretary and Chief Accounting Officer 2005-2007;
Corporate Secretary and Chief Accounting Officer 1999 –
2005.
D.
E. Gaines
51
Vice
President Finance and Treasurer since March 2002.
E.
M. Markell
56
Executive
Vice President and Chief Financial Officer since May 2007; Senior Vice
President Energy Resources 2003 – 2007; Vice President Corporate
Development, 2002 – 2003.
J.
L. O’Connor
51
Senior
Vice President, General Counsel, Corporate Secretary and Chief Ethics and
Compliance Officer since May 2007; Senior Vice President, General Counsel,
Chief Ethics and Compliance Officer 2005-2007; Vice President and General
Counsel, 2003 - 2005.
The executive officers of Puget Sound
Energy as of February 28, 2008 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
60
Chairman,
President and Chief Executive Officer since May 2005; Director since
January 2002; President and Chief Executive Officer 2002 –
2005.
J.
W. Eldredge
57
Vice
President, Controller and Chief Accounting Officer since May 2007; Vice
President, Corporate Secretary, Controller and Chief Accounting Officer
2001-2007.
D.
E. Gaines
51
Vice
President Finance and Treasurer since March 2002.
K.
J. Harris
43
Executive
Vice President and Chief Resource Officer since May 2007; Senior Vice
President Regulatory Policy and Energy Efficiency 2005-2007; Vice
President Regulatory and Government Affairs, 2003 – 2005; Vice President
Regulatory Affairs, 2002 – 2003.
E.
M. Markell
56
Executive
Vice President and Chief Financial Officer since May 2007; Senior Vice
President Energy Resources 2003-2007; Vice President Corporate
Development, 2002 – 2003.
J.
L. O’Connor
51
Senior
Vice President, General Counsel, Corporate Secretary and Chief Ethics and
Compliance Officer since May 2007; Senior Vice President, General Counsel,
Chief Ethics and Compliance Officer 2005-2007; Vice President and General
Counsel, 2003 – 2005.
B.
A. Valdman
45
Executive
Vice President and Chief Operating Officer since May 2007; Senior Vice
President Finance and Chief Financial Officer 2003-2007. Prior
to joining PSE, he was a Managing Director with JP Morgan Securities,
Inc., 2000 – 2003.
The
following risk factors, in addition to other factors and matters discussed
elsewhere in this report, should be carefully considered. The risks
and uncertainties described below are not the only risks and uncertainties that
Puget Energy and PSE may face. Additional risks and uncertainties not
presently known or currently deemed immaterial also may impair PSE’s business
operations. If any of the following risks actually occur, Puget
Energy’s and PSE’s business, results of operations and financial conditions
would suffer.
RISKS
RELATING TO THE UTILITY BUSINESS
The
actions of regulators can significantly affect PSE’s earnings, liquidity and
business activities.
The rates that PSE is
allowed to charge for its services is the single most important item influencing
its financial position, results of operations and liquidity. PSE is
highly regulated and the rates that it charges its customers are determined by
the Washington Commission.
PSE is
also subject to the regulatory authority of the Washington Commission with
respect to accounting, the issuance of securities and certain other matters, and
the regulatory authority of FERC with respect to the transmission of electric
energy, the sale of electric energy at wholesale, accounting and certain other
matters. Policies and regulatory actions by these regulators could
have a material impact on PSE’s financial position, results of operations and
liquidity.
PSE’s
recovery of costs is subject to regulatory review and its operating income may
be adversely affected if its costs are disallowed or recovery is delayed.
The
Washington Commission determines the rates PSE may charge to its retail
customers based on a normalized cost of producing power. If in a
specific year PSE’s costs are higher than normal, rates will not be sufficient
to permit PSE to earn the allowed return or to cover its costs and recovery of
energy costs will be deferred until subsequent ratemaking
proceedings. In addition, the Washington Commission decides what
level of expense and investment is reasonable and prudent in providing
service. If the Washington Commission decides that part of PSE’s
costs do not meet the standard, those costs may be disallowed partially or
entirely and not recovered in rates. For these reasons, the rates
authorized by the Washington Commission may not be sufficient to earn the
allowed return or recover the costs incurred by PSE in a given
period.
The
PCA mechanism by which variations in PSE’s power costs are apportioned between
PSE and its customers is no longer subject to a cap, which could result in
significant increases in PSE’s expenses.
PSE has a
PCA mechanism that provides for recovery of power costs from customers or
refunding of power cost savings to customers, as those costs vary from the
“power cost baseline” level of power costs which are set in part based on
normalized assumptions about weather and hydro conditions. Excess
power costs or power cost savings will be apportioned between PSE and its
customers pursuant to the graduated scale set forth in the PCA
mechanism. Beginning after June 30, 2006, PSE’s share of power cost
variations is no longer capped. As a result, if power costs are
significantly higher than the baseline level, PSE’s expenses could significantly
increase.
PSE
may be unable to acquire energy supply resources to meet projected customer
needs or may fail to successfully integrate such acquisitions.
PSE
projects that future energy needs will exceed current purchased and
Company-controlled power resources. As part of PSE’s business
strategy, it plans to acquire additional electric generation and delivery
infrastructure to meet customer needs. If PSE cannot acquire further
additional energy supply resources at a reasonable cost, it may be required to
purchase additional power in the open market at a cost that could significantly
increase its expenses and reduce earnings and cash
flows. Additionally, PSE may not be able to timely recover some or
all of those increased expenses through ratemaking.
While PSE
expects to identify the benefits of new energy supply resources prior to their
acquisition and integration, it may not be able to achieve the expected benefits
of such energy supply sources.
The
Company’s cash flow and earnings could be adversely affected by potential high
prices and volatile markets for purchased power, increased customer demand for
energy, recurrence of low availability of hydroelectric resources, outages of
its generating facilities or a failure to deliver on the part of its
suppliers.
The
utility business involves many operating risks. If PSE’s operating
expenses, including the cost of purchased power and natural gas, significantly
exceed the levels recovered from retail customers for an extended period of
time, its cash flow and earnings would be negatively
affected. Factors which could cause purchased power and natural gas
costs to be higher than anticipated include, but are not limited to, high prices
in western wholesale markets during periods when PSE has insufficient energy
resources to meet its load requirements and/or high volumes of energy purchased
in wholesale markets at prices above the amount recovered in retail rates due
to:
·
Increases
in demand due, for example, either to weather or customer
growth;
·
Below
normal energy generated by PSE-owned hydroelectric resources due to low
streamflow conditions;
·
Extended
outages of any of PSE-owned generating facilities or the transmission
lines that deliver energy to load centers;
·
Failure
to perform on the part of any party from which PSE purchases capacity or
energy; and
·
The
effects of large-scale natural disasters, such as the hurricanes recently
experienced in the southern United
States.
PSE’s
electric generating facilities are subject to operational risks that could
result in unscheduled plant outages, unanticipated operation and maintenance
expenses and increased power purchase costs.
PSE owns and operates coal, natural
gas-fired, hydro, wind-powered and oil-fired generating
facilities. Operation of electric generating facilities involves
risks that can adversely affect energy output and efficiency
levels. Included among these risks are:
·
Increased
prices for fuel and fuel transportation as existing contracts
expire;
·
Facility
shutdowns due to a breakdown or failure of equipment or processes or
interruptions in fuel supply;
·
Disruptions
in the delivery of fuel and lack of adequate
inventories;
·
Labor
disputes;
·
Inability
to comply with regulatory or permit requirements;
·
Disruptions
in the delivery of electricity;
·
Operator
error;
·
Terrorist
attacks; and
·
Catastrophic
events such as fires, explosions, floods or other similar
occurrences.
PSE
is subject to the commodity price, delivery and credit risks associated with the
energy markets.
In
connection with matching loads and resources, PSE engages in wholesale sales and
purchases of electric capacity and energy, and, accordingly, is subject to
commodity price risk, delivery risk, credit risk and other risks associated with
these activities. Credit risk includes the risk that counterparties
owing PSE money or energy will breach their obligations. Should the
counterparties to these arrangements fail to perform, PSE may be forced to enter
into alternative arrangements. In that event, PSE’s financial results
could be adversely affected. Although PSE’s models take into account
the expected probability of default by counterparties, actual exposure to a
default by a particular counterparty could be greater than the models
predict.
To
lower its financial exposure related to commodity price fluctuations, PSE may
use forward delivery agreements, swaps and option contracts to hedge commodity
price risk with a diverse group of counterparties. However, PSE does
not always cover the entire exposure of its assets or positions to market price
volatility and the coverage will vary over time. To the extent PSE
has unhedged positions or its hedging procedures do not work as planned,
fluctuating commodity prices could adversely impact its results of
operations.
Conditions
that may be imposed in connection with hydroelectric license renewals may
require large capital expenditures and reduce earnings and cash flows.
PSE is in
the process of renewing the federal licenses for its Baker River hydroelectric
project and implementing the federal licensing requirements for the Snoqualmie
Falls hydroelectric project. The relicensing process is a political
and public regulatory process that involves sensitive resource
issues. PSE cannot predict with certainty the conditions that may be
imposed during the relicensing process, the economic impact of those
requirements, whether new licenses will ultimately be issued, modified, or
whether PSE will be willing to meet the relicensing requirements to continue
operating these hydroelectric projects.
Costs
of compliance with environmental, climate change and endangered species laws are
significant and the cost of compliance with new and emerging laws and
regulations and the incurrence of associated liabilities could adversely affect
PSE’s results of operations.
PSE’s operations are
subject to extensive federal, state and local laws and regulations relating to
environmental, climate change and endangered species protection. To
comply with these legal requirements, PSE must spend significant sums on
measures including resource planning, remediation, monitoring, pollution control
equipment and emissions related abatement and fees. New
environmental, climate change and endangered species laws and regulations
affecting PSE’s operations may be adopted, and new interpretations of existing
laws and regulations could be adopted or become applicable to PSE or its
facilities which may substantially increase environmental, climate change and
endangered species expenditures made by PSE in the future. Compliance
with these or other future regulations could require significant capital
expenditures by PSE and adversely affect PSE’s financial position, results of
operations, cash flows and liquidity. In addition, PSE may not be
able to recover all of its costs for such expenditures through electric and
natural gas rates at current levels in the future.
With respect to endangered
species laws, the listing or proposed listing of several species of salmon in
the Pacific Northwest is causing a number of changes to the operations of
hydroelectric generating facilities on Pacific Northwest rivers, including the
Columbia River. These changes could reduce the amount, and increase
the cost, of power generated by hydroelectric plants owned by PSE or in which
PSE has an interest and increase the cost of the permitting process for these
facilities.
Under
current law, PSE is also generally responsible for any on-site liabilities
associated with the environmental condition of the facilities that it currently
owns or operates or has previously owned or operated, regardless of whether the
liabilities arose before or during the time the facility was owned or operated
by PSE. The incurrence of a material environmental liability or the
new regulations governing such liability could result in substantial future
costs and have a material adverse effect on PSE’s results of operations and
financial condition.
Specific
to climate change, Washington State has adopted both a renewable portfolio
standard and greenhouse gas legislation, including an emission performance
standard provision. Recent U.S. Supreme Court decisions related to
climate change have also drawn greater attention to this issue at the federal,
state and local level. PSE cannot yet determine the costs of
compliance with the recently enacted legislation.
The
Company’s business is dependent on its ability to successfully access capital
markets.
The
Company relies on access to both short-term money markets as a source of
liquidity and longer-term capital markets to fund its utility construction
program and other capital expenditure requirements not satisfied by cash flow
from its operations. If the Company is unable to access capital on
reasonable terms, its ability to pursue improvements or acquisitions, including
generating capacity, which may be relied on for future growth and to otherwise
implement its strategy, could be adversely affected.
Capital
and credit market disruptions or a downgrade of the Company’s credit rating may
increase the Company’s cost of borrowing or adversely affect the ability to
access one or more financial markets.
A
downgrade in the Company’s credit rating could negatively affect its ability to
access capital and the ability to hedge in wholesale markets.
Standard
and Poor’s and Moody’s Investor Services rate PSE’s senior secured debt at
“BBB+” with a negative outlook and “Baa2” with a stable outlook,
respectively. Although the Company is not aware of any current plans
of S&P or Moody’s to lower their respective ratings on PSE’s debt, the
Company cannot be assured that such credit ratings will not be
downgraded.
Although
neither Puget Energy nor PSE has any rating downgrade provisions in
its credit facilities that would accelerate the maturity dates of outstanding
debt, 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 corporate credit ratings decline. A downgrade in
commercial paper ratings could preclude PSE’s ability to issue commercial paper
under its current programs.
Any
downgrade below investment grade of PSE’s senior secured debt could allow
counterparties in the wholesale electric, wholesale natural 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, all of which would expose PSE to additional
costs.
The
Company’s operating results fluctuate on a seasonal and quarterly basis.
PSE’s
business is seasonal and weather patterns can have a material impact on its
operating performance. Because natural gas is heavily used for
residential and commercial heating, demand depends heavily on weather patterns
in PSE’s service territory, and a significant amount of natural gas revenues are
recognized in the first and fourth quarters related to the heating
season. However, the recent increase in the price of natural gas as
well as conservation efforts may result in decreased customer demand, despite
normal or lower than normal temperatures. Demand for electricity is
also greater in the winter months associated with
heating. Accordingly, PSE’s operations have historically generated
less revenues and income when weather conditions are milder in the
winter. In the event that the Company experiences unusually mild
winters, results of operations and financial condition could be adversely
affected.
The Company
may be adversely affected by legal proceedings arising out of the electricity
supply situation in the western power markets, which could result in refunds or
other liabilities.
The
Company is involved in a number of legal proceedings and complaints with respect
to power markets in the western United States. Most of these
proceedings relate to the significant increase in the spot market price of
energy in western power markets in 2000 and 2001, which allegedly contributed to
or caused unjust and unreasonable prices and allegedly may have been the result
of manipulations by certain other parties. These proceedings include,
but are not limited to, refund proceedings and hearings in California and the
Pacific Northwest and complaints and cross-complaints filed by various parties
with respect to alleged misconduct by other parties in western power
markets. 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, individually or in the
aggregate, will not materially and adversely affect PSE’s financial condition,
results of operations or liquidity.
The
Company may be negatively affected by its inability to attract and retain
professional and technical employees.
The
Company’s ability to implement a workforce succession plan is dependent upon the
Company’s ability to employ and retain skilled professional and technical
workers in an aging workforce. Without a skilled workforce, the
Company’s ability to provide quality service to PSE’s customers and meet
regulatory requirements will be challenged and could affect
earnings.
The
Company may be adversely affected by extreme events in which the Company is not
able to promptly respond and repair the electric and gas infrastructure
system.
The
Company must maintain an emergency planning and training program to allow the
Company to quickly respond to extreme events. Without emergency
planning, the Company is subject to availability of outside contractors during
an extreme event which may impact the quality of service provided to PSE’s
customers. In addition, a slow response to extreme events may have an
adverse affect on earnings as customers may be without electricity and natural
gas for an extended period of time.
The
Company may be negatively affected by unfavorable changes in the tax laws or
their interpretation.
Changes
in tax law, related regulations, or differing interpretation or enforcement of
applicable law by the Internal Revenue Service or other taxing jurisdiction
could have a material adverse impact on the Company’s financial
statements. The tax law, related regulations and case law are
inherently complex. The Company must make judgments and
interpretations about the application of the law when determining the provision
for taxes. Disputes over interpretations of tax laws may be settled
with the taxing authority in examination, upon appeal or through
litigation. The Company’s tax obligations include income, real
estate, sales and use, business and occupation and employment-related taxes and
ongoing appeals issues related to these taxes. These judgments may
include reserves for potential adverse outcomes regarding tax positions that
have been taken that may be subject to challenge by the taxing
authorities.
RISKS
RELATING TO PUGET ENERGY’S PROPOSED MERGER AND CORPORATE STRUCTURE
There
are risks if the Company does not complete the proposed merger with the
Consortium.
If the
merger the Company announced on October 26, 2007 is not completed for
any reason, Puget Energy will remain an independent public company and the
common stock will continue to be listed and traded on the New York Stock
Exchange. While we expect that management will operate the business in a manner
similar to that in which it is being operated today, if the merger is not
completed, Puget Energy may suffer negative financial ramifications, including
the following:
·
The
current market price of Puget Energy’s common stock may reflect a market
assumption that the merger will occur, and a failure to complete the
merger could result in a negative perception by investors in Puget Energy
generally and could cause a decline in the market price of Puget Energy’s
common stock. This could affect Puget Energy’s ability to access the
equity markets to fund PSE’s construction program and working capital
needs.
·
Puget
Energy might be required to pay an up to $40.0 million termination fee,
and up to $10.0 million of expenses, to the Consortium, which could
adversely impact liquidity (or if no termination fee is payable, up to
$15.0 million).
As
a holding company, Puget Energy is subject to restrictions on its ability to pay
dividends.
As a
holding company with no significant operations of its own, the primary source of
funds for the payment of dividends to its shareholders is dividends PSE pays to
Puget Energy. PSE is a separate and distinct legal entity and has no
obligation to pay any amounts to Puget Energy, whether by dividends, loans or
other payments. The ability of PSE to pay dividends or make
distributions to Puget Energy, and accordingly, Puget Energy’s ability to pay
dividends on its common stock, will depend on its earnings, capital requirements
and general financial condition. If Puget Energy does not receive
adequate distributions from PSE, it may not be able to make or may have to
reduce dividend payments on its common stock.
PSE’s
payment of common stock dividends to Puget Energy is restricted by provisions of
covenants applicable to its preferred stock and long-term debt contained in its
restated articles of incorporation and electric and natural gas mortgage
indentures. Puget Energy’s Board of Directors reviews the dividend
policy periodically in light of the factors referred to above and cannot assure
shareholders of the amount of dividends, if any, that may be paid in the
future.
Future
sales of Puget Energy’s common stock on the public market could lower the stock
price.
Puget
Energy may sell additional shares of common stock in public offerings, through
the stock purchase and dividend reinvestment plan or through common stock
offering programs which it has entered into with two financial
institutions. Puget Energy cannot predict the size of future
issuances of common stock, or the effect, if any, that future issuances and
sales of shares of common stock will have on the market price of common
stock. Sales of substantial amounts of common stock, or the
perception that such sales could occur, may adversely affect the prevailing
market price of common stock.
The
market price for common stock is uncertain and may fluctuate
significantly.
Puget
Energy cannot predict whether the market price of its common stock will rise or
fall. Numerous factors influence the trading price of its common
stock. These factors may include changes in financial condition,
results of operations and prospects, legal and administrative proceedings and
political, economic, financial and other factors that can affect the capital
markets generally, the stock exchanges on which Puget Energy’s common stock is
traded and its business segments.
Certain
provisions of law, as well as provisions in the restated articles of
incorporation, bylaws and shareholders rights plan, may make it more difficult
for others to obtain control of Puget Energy.
Puget
Energy is a Washington corporation and certain anti-takeover provisions of
Washington laws apply and create various impediments to the acquisition of
control of Puget Energy or to the consummation of certain business
combinations. In addition, Puget Energy’s restated articles of
incorporation, bylaws and shareholders rights plan contain provisions which may
make it more difficult to remove incumbent directors or effect certain business
combinations with Puget Energy without the approval of the Board of
Directors. These provisions of law and of Puget Energy’s corporate
documents, individually or in the aggregate, could discourage a future takeover
attempt which individual shareholders might deem to be in their best interests
or in which shareholders would receive a premium for their shares over current
prices.
The principal electric generating
plants and underground natural 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.
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 and Proceeding
Relating to the Proposed Merger.
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 20, 2008, there were
approximately 34,100 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 2007 and
2006. Puget Energy and its predecessor companies have paid dividends
on common stock each year since 1943 when such stock first became publicly
held.
2007
2006
Price
Range
Dividends
Price
Range
Dividends
Quarter
Ended
High
Low
Paid
High
Low
Paid
March
31
$ 25.84
$
24.00
$ 0.25
$ 21.68
$ 20.26
$ 0.25
June
30
26.91
23.58
0.25
21.62
20.13
0.25
September
30
25.38
22.47
0.25
22.86
21.20
0.25
December
31
28.60
23.40
0.25
25.91
22.72
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 60.0% 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 Restated Articles of Incorporation and
electric and natural gas mortgage indentures. Under the most
restrictive covenants of PSE, earnings reinvested in the business unrestricted
as to payment of cash dividends were approximately $481.5 million at December31, 2007.
STOCK
PRICE PERFORMANCE
The chart below compares the five-year
cumulative total shareholder return (share price appreciation plus reinvested
dividends) of Puget Energy common stock to the cumulative total return of the
Standard & Poor’s 500 Stock Index (S&P 500) and the Edison Electric
Institute (EEI) Combination Gas & Electric Investor-Owned Utilities
Index.
Puget
Energy
Shareholder
Return
2002
2003
2004
2005
2006
2007
PSD
$ 100.00
$ 112.61
$ 122.21
$ 105.65
$ 137.12
$ 154.25
EEI
Gas & Electric Index
$ 100.00
$ 125.01
$ 155.74
$ 182.93
$ 220.94
$ 257.40
S&P
500 Index
$ 100.00
$ 128.69
$ 142.69
$ 149.70
$ 173.33
$ 182.85
This comparison assumes $100 was
invested on December 31, 2002 in: (a) Puget Energy common stock; (b) the S&P
500 Stock Index; and (c) the EEI Combination Gas & Electric Investor-Owned
Utilities Index. The graph then observes, in each case, stock price
growth and dividends paid (assuming dividends were reinvested) over five
years. The returns shown on the graph do not necessarily predict
future performance.
The following discussion and analysis
should be read in conjunction with the financial statements and related notes
thereto included elsewhere in this 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 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” and “Risk Factors” 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, Inc. (Puget
Energy) is an energy services holding company and all of its operations are
conducted through its subsidiary Puget Sound Energy, Inc. (PSE), a regulated
electric and natural gas utility company. Until May 7, 2006,
Puget Energy owned a 90.9% interest in InfrastruX Group, Inc. (InfrastruX), a
utility construction and services company that was sold to an affiliate of
Tenaska Power Fund, L.P. (Tenaska). Puget Energy is dependent upon
the results of PSE since PSE is its most significant asset. PSE is
the largest electric and natural gas utility in the state of Washington,
primarily engaged in the business of electric transmission, distribution,
generation and natural gas distribution. Puget Energy’s business
strategy is to generate stable earnings and cash flow by offering reliable
electric and natural gas service in a cost effective manner through
PSE. An overview of significant recent developments
affecting Puget Energy is provided below.
On
October 26, 2007, Puget Energy announced that it had entered into a definitive
Agreement and Plan of Merger, dated as of October 25, 2007, pursuant to which
Puget Energy will be acquired by a consortium of long-term infrastructure
investors led by Macquarie Infrastructure Partners, the Canada Pension Plan
Investment Board and British Columbia Investment Management Corporation, and
which also includes Alberta Investment Management, Macquarie-FSS Infrastructure
Trust and Macquarie Capital Group Limited (collectively, the
Consortium). At the effective time of the merger, each issued and
outstanding share of common stock of Puget Energy, other than any shares in
respect of which dissenter’s rights are perfected and other than any shares
owned by the Consortium, shall be cancelled and shall be converted automatically
into the right to receive $30.00 in cash, without interest.
The
consummation of the merger is subject to the satisfaction or waiver of certain
closing conditions, including the approval of the transaction by the affirmative
vote of two-thirds of the votes entitled to be cast thereon by Puget Energy’s
shareholders, the termination or expiration of the waiting period under the
Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (the HSR Act)
and the receipt of required regulatory approvals. On December 17,2007, PSE and the Consortium filed a joint application seeking approval of the
merger with the Washington Utilities and Transportation Commission (Washington
Commission). A decision by the Washington Commission is expected on
September 2, 2008. If approved, closing is expected to occur during
the fourth quarter 2008. On January 29, 2008, PSE and the Consortium
filed an application with the Federal Energy Regulatory Commission (FERC)
seeking approval of the proposed merger pursuant to section 203 of the Federal
Power Act. A decision by FERC is expected by May 29,2008.
The
merger agreement contains termination rights for both Puget Energy and the
Consortium under certain circumstances. In the event Puget Energy
elects to terminate the merger agreement under specified circumstances, it would
be required to pay to the acquiring entity either $30.0 million if the
termination is based on the submission of an alternative proposal meeting
certain requirements by a party with whom Puget Energy had been in discussions
prior to December 10, 2007, or $40.0 million if such fee becomes
payable in all other circumstances, plus, in each case, documented out-of-pocket
expenses of the Consortium of up to $10.0 million. In addition, Puget
Energy may be required to pay the Consortium documented out-of-pocket expenses
incurred by the Consortium not in excess of $15.0 million if the merger
agreement is terminated due to a breach of the terms of the Merger Agreement by
Puget Energy and such breach is incurable or has not been cured within a
specified time. The acquiring entity may be required to pay Puget
Energy an amount equal to $130.0 million if the merger agreement is terminated
due to a breach of the terms of the merger agreement by the acquiring entity and
such breach is incurable or has not been cured within a specified
time.
Puget
Energy faces uncertainties in the future regarding both electric and natural gas
customer growth and sales growth. The number of electric customers is
expected to continue to grow at a rate of growth based on a forecasted slowing
of regional population growth. Aside from the impact of fluctuations
in weather, residential electric use per customer is expected to continue a
long-term trend of slow decline based on continued energy efficiency
improvements combined with the impact of higher retail
rates. Electric residential usage per customer in 2007 was higher
than 2006 due to colder weather.
The
number of natural gas customers is expected to grow at rates slightly above
electric customers due to the continued opportunity for conversion of existing
electric customers to natural gas. Aside from weather impacts,
residential natural gas use per customer is also expected to continue a
long-term trend of decline based on continued energy efficiency
improvements. Natural gas residential usage per customer in 2007 was
higher than 2006 due to colder weather.
Puget
Sound Energy. PSE generates revenues primarily from the sale
of electric and natural gas services to residential and commercial customers
within Washington State. PSE’s operating revenues and associated
expenses are not generated evenly throughout 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 and subsequently higher
power costs during the winter heating season in the first and fourth quarters of
the year and its lowest sales in the third quarter of the
year. Varying wholesale electric prices and the amount of
hydroelectric energy supplies available to PSE also make quarter-to-quarter
comparisons difficult.
As a regulated utility company, PSE is
subject to 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 natural gas and electric distribution and transmission lines; increasing
regulatory standards for system reliability and wholesale market stability over
time and significant evolving environmental legislation.
On
December 3, 2007, PSE filed a general rate case with the Washington Commission
which proposed an increase in electric rates of $174.5 million or 9.5% annually
and an increase in natural gas rates of $56.8 million or 5.3% annually,
effective November 3, 2008. A decision is expected in October
2008.
PSE’s main business objective is to
provide reliable, safe and cost-effective energy to its customers. To
help accomplish this objective, PSE seeks to become more energy efficient and
environmentally responsible in its energy supply portfolio on an ongoing
basis. PSE filed its Integrated Resource Plan (IRP) on May 31, 2007
with the Washington Commission. The plan supports a strategy of
significantly increasing energy efficiency programs, pursuing additional
renewable resources (primarily wind) and additional base load natural gas fired
generation to meet the growing needs of its customers. In October
2007, PSE filed two draft Request for Proposals (RFPs) with the Washington
Commission to continue expansion of its energy-efficiency programs and power
supplies. PSE has issued the RFPs and expects bids to be submitted by
the end of February 2008 with a short list of projects identified by
mid-2008. PSE’s previous IRP and RFP in 2005 resulted in the
selection of seven projects for further consideration and possible
negotiation. PSE has completed three transactions, including the
purchase of the Goldendale generating facility (Goldendale), a four-year power
purchase agreement for 150 megawatts (MW) of winter on-peak energy commencing in
2008 and a power purchase agreement for a portion of the output of Klondike Wind
Power III, LLC, a wind-powered electric generating facility in north-central
Oregon. Of the remaining four opportunities, PSE remains in
discussion on one project and has discontinued discussions on the other
three.
NON-GAAP
FINANCIAL MEASURES
The following discussion includes
financial information prepared in accordance with generally accepted accounting
principles (GAAP), as well as two other financial measures, Electric Margin and
Gas Margin, that are considered “non-GAAP financial
measures.” Generally, a non-GAAP financial measure is a numerical
measure of a Company’s financial performance, financial position or cash flows
that exclude (or include) amounts that are included in (or excluded from) the
most directly comparable measure calculated and presented in accordance with
GAAP. The presentation of Electric Margin and Gas Margin is intended
to supplement investors’ understanding of the Company’s operating
performance. Electric Margin and Gas Margin are used by the Company
to determine whether the Company is collecting the appropriate amount of energy
costs from its customers to allow recovery of operating costs. Our
Electric Margin and Gas Margin measures may not be comparable to other
companies’ Electric Margin and Gas Margin measures. Furthermore,
these measures are not intended to replace operating income as determined in
accordance with GAAP as an indicator of operating performance.
FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Puget
Energy
All the
operations of Puget Energy are conducted through its subsidiary PSE and until
May 7, 2006, InfrastruX. Net income in 2007 was $184.5 million on
operating revenues from continuing operations of $3.2 billion as compared to
$219.2 million on operating revenues from continuing operations of $2.9 billion
in 2006 and $155.7 million on operating revenues from continuing operations of
$2.6 billion in 2005. Income from continuing operations in 2007 was
$184.7 million as compared to $167.2 million in 2006 and $146.3 million in
2005. Net income for 2006 and 2005 includes the results of
discontinued operations for InfrastruX.
Basic
earnings per share in 2007 was $1.57 on 117.7 million weighted-average common
shares outstanding as compared to $1.89 on 116.0 million weighted-average common
shares outstanding in 2006 and $1.52 on 102.6 million weighted-average common
shares outstanding in 2005. Diluted earnings per share in 2007 was
$1.56 on 118.3 million weighted-average common shares outstanding as compared to
$1.88 on 116.5 million weighted-average common shares outstanding in 2006 and
$1.51 on 103.1 million weighted-average common shares outstanding in
2005. Included in basic earnings per share was $0.45 and $0.09 for
2006 and 2005, respectively, related to discontinued
operations. Included in diluted earnings per share was $0.44
and $0.09 for 2006 and 2005, respectively, related to discontinued
operations.
Net
income for 2007 was positively impacted by higher energy margins driven by
increased sales volumes and favorable hydroelectric conditions. Net
income was negatively impacted by higher operation and maintenance expense,
taxes other than income taxes net of revenue sensitive taxes and increases in
depreciation and interest expenses, including costs related to the addition of
new generating resources and energy delivery infrastructure
investments. During the fourth quarter 2007, Puget Energy incurred
$8.1 million in costs related to the proposed merger with the
Consortium. Net income in 2006 was positively impacted by income from
discontinued operations of InfrastruX of $51.9 million
(after-tax). The income from discontinued operations included a gain
on disposal of $29.8 million (after-tax) resulting from the sale of
InfrastruX. The increase was partially offset by establishment and
funding of a charitable foundation of $15.0 million ($9.75 million
after-tax). Puget Energy’s income from discontinued operations for
2006 includes $7.3 million related to the reversal of a carrying value
adjustment recorded in 2005 as well as $10.0 million related to the anticipated
realization of a deferred tax asset associated with the sale of the
business.
2007 compared to
2006
Puget Sound
Energy
Energy
Margins. The
following table displays the details of electric margin changes from 2006 to
2007. 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.
Electric
Margin
(Dollars
in Millions)
Twelve
Months Ended December 31
2007
2006
Change
Percent
Change
Electric
operating revenue1
$
1,997.8
$
1,777.7
$
220.1
12.4
%
Less:
Other electric operating revenue
(41.9
)
(51.8
)
9.9
19.1
Add:
Other electric operating revenue – gas supply resale
1.5
16.4
(14.9
)
(90.9
)
Total
electric revenue for margin
1,957.4
1,742.3
215.1
12.3
Adjustments
for amounts included in revenue:
Pass-through
tariff items
(43.0
)
(35.9
)
(7.1
)
(19.8
)
Pass-through
revenue-sensitive taxes
(133.6
)
(117.4
)
(16.2
)
(13.8
)
Net
electric revenue for margin
1,780.8
1,589.0
191.8
12.1
Minus
power costs:
Purchased
electricity1
(895.6
)
(917.8
)
22.2
2.4
Electric
generation fuel1
(143.4
)
(97.3
)
(46.1
)
(47.4
)
Residential
exchange1
52.4
163.6
(111.2
)
(68.0
)
Total
electric power costs
(986.6
)
(851.5
)
(135.1
)
(15.9
)
Electric
margin2
$
794.2
$
737.5
$
56.7
7.7
%
_______________
1
As
reported on PSE’s Consolidated Statement of Income.
2
Electric
margin does not include any allocation for amortization/depreciation
expense or electric generation operation and maintenance
expense.
Electric margin increased $56.7 million
in 2007 as compared to 2006. The increase was primarily due to
recovery of ownership and operating costs of new generation facilities included
in the power cost only rate case (PCORC) rate increase of 3.7% effective
September 1, 2007 and in the general rate decrease of 1.3% effective January 13,2007, which increased electric margin by $46.2 million. The increase
in electric margin also benefited from higher production of low cost
hydroelectric power and company-owned generating facilities which resulted in a
$10.3 million increase in electric margin due to overrecovery of power costs in
2007 as compared to 2006 and a $16.4 million increase in margin due to an
increase in retail sales volume of 2.5%. These increases were
slightly offset by a $16.9 million decrease in margin due to an increase of
Production Tax Credits (PTCs) provided to customers. PTCs provided to
customers through lower rates are recovered through a lower effective tax
rate.
The
following table displays the details of gas margin changes from 2006 to
2007. Gas margin is natural gas sales to retail and transportation
customers less pass-through tariff items and revenue-sensitive taxes, and the
cost of natural gas purchased, including natural gas transportation costs to
bring natural gas to PSE’s service territory.
Gas
Margin
(Dollars
in Millions)
Twelve
Months Ended December 31
2007
2006
Change
Percent
Change
Gas
operating revenue1
$
1,208.0
$
1,120.1
$
87.9
7.8
%
Less:
Other gas operating revenue
(17.4
)
(16.5
)
(0.9
)
(5.5
)
Total
gas revenue for margin
1,190.6
1,103.6
87.0
7.9
Adjustments
for amounts included in revenue:
Pass-through
tariff items
(9.6
)
(7.1
)
(2.5
)
(35.2
)
Pass-through
revenue-sensitive taxes
(95.2
)
(86.3
)
(8.9
)
(10.3
)
Net
gas revenue for margin
1,085.8
1,010.2
75.6
7.5
Minus
purchased gas costs1
(762.1
)
(723.2
)
(38.9
)
(5.4
)
Gas
margin2
$
323.7
$
287.0
$
36.7
12.8
%
_______________
1
As
reported on PSE’s Consolidated Statement of Income.
2
Gas
margin does not include any allocation for amortization/depreciation
expense or electric generation operations and maintenance
expense.
Gas
margin increased $36.7 million in 2007 as compared to 2006. Gas
margin increased $26.7 million due to a 2.8% general rate increase effective
January 13, 2007 which increased gas margin by approximately 9.8% as a result of
recovering ownership and operating costs of natural gas plant. In
addition, an increase of 3.8% in natural gas therm volume sales increased gas
margin $11.0 million. These increases were slightly offset by a
change in customer usage and pricing which resulted in a $1.0 million decrease
to margin.
Electric
Operating Revenues. The
table below sets forth changes in electric operating revenues for PSE from 2006
to 2007.
(Dollars
in Millions)
Twelve
Months Ended December 31
2007
2006
Change
Percent
Change
Electric
operating revenues:
Residential
sales
$
951.1
$
788.2
$
162.9
20.7
%
Commercial
sales
748.8
702.8
46.0
6.5
Industrial
sales
105.2
103.0
2.2
2.1
Other
retail sales, including unbilled revenue
31.7
35.4
(3.7
)
(10.5
)
Total
retail sales
1,836.8
1,629.4
207.4
12.7
Transportation
sales
9.4
11.5
(2.1
)
(18.3
)
Sales
to other utilities and marketers
109.7
85.0
24.7
29.1
Other
41.9
51.8
(9.9
)
(19.1
)
Total
electric operating revenues
$
1,997.8
$
1,777.7
$
220.1
12.4
%
Electric
retail sales increased $207.4 million for 2007 as compared to 2006 due primarily
to a decrease in the benefits of the Residential Exchange Benefit credited to
residential and small farm customers, which reduced electric operating revenue
by $54.9 million in 2007 as compared to $171.3 million in 2006 (an increase in
revenue of $116.4 million). The credit also reduced power costs by a
corresponding amount with no impact on earnings. The Residential
Exchange Benefit was suspended effective June 7, 2007 due to adverse rulings
from the Ninth Circuit Court of Appeals (Ninth Circuit) which states that
Bonneville Power Administration (BPA) actions in entering into residential
exchange settlement agreements with investor owned utilities were not in
accordance with the law. The PCORC rate increases of July 1, 2006 and
September 1, 2007 offset by the electric general rate decrease of January 13,2007 increased electric retail sales along with an increase in retail sales
volumes. The electric tariff changes increased electric operating
revenues by $59.3 million for 2007 as compared to 2006. Retail
electricity usage increased 535,301 megawatt hours (MWh) or 2.5% for 2007 as
compared to the same period in 2006, which resulted in an increase of
approximately $41.2 million in electric operating revenue. The
increase in electricity usage was related in part to 2.0% higher average number
of customers served in 2007 as compared to 2006. These increases were
offset by a decrease in revenue related to production tax credits of $30.8
million given to customers in 2007 as compared to a credit of $13.9 million in
2006.
Transportation
sales decreased $2.1 million in 2007 as compared to 2006 as a result of
transportation customers balancing their scheduled load. During 2006,
transportation customers purchased power in excess of their scheduled load
whereas for the same period in 2007, the scheduled load was less than actual
usage. This decrease was offset by an increase in sales volume of
39,988 MWh or 1.9%.
Sales to
other utilities and marketers increased $24.7 million for 2007 as compared to
2006 due to an increase in sales volume of 185,206 MWh or 9.0%, which resulted
in a $9.0 million increase. In 2007, PSE’s average wholesale sales
price to other utilities and marketers increased $0.0076 as compared to 2006
which resulted in an increase of approximately $15.7 million.
Other
electric revenues decreased $9.9 million for 2007 as compared to 2006 primarily
due to gains from natural gas financial hedges on natural gas sold to third
parties in 2006 that did not recur in 2007.
The
following electric rate changes were approved by the Washington Commission in
2007 and 2006:
The
rate increase is for the period July 1, 2006 through December 31,2006. The annualized basis of the PCORC rate increase is $96.1
million.
Gas
Operating Revenues. The
table below sets forth changes in gas operating revenues for PSE from 2006 to
2007.
(Dollars
in Millions)
Twelve
Months Ended December 31
2007
2006
Change
Percent
Change
Gas
operating revenues:
Residential
sales
$
756.2
$
697.6
$
58.6
8.4
%
Commercial
sales
363.0
335.7
27.3
8.1
Industrial
sales
57.7
57.1
0.6
1.1
Total
retail sales
1,176.9
1,090.4
86.5
7.9
Transportation
sales
13.7
13.3
0.4
3.0
Other
17.4
16.4
1.0
6.1
Total
gas operating revenues
$
1,208.0
$
1,120.1
$
87.9
7.8
%
Gas
retail sales increased $86.5 million for 2007 as compared to 2006 due to the
approval of a 2.8% general natural gas rate increase effective January 13, 2007,
higher Purchased Gas Adjustment (PGA) mechanism rates and increased customer
natural gas usage. The natural gas general rate increase provided an
additional $26.9 million in gas revenues for 2007 as compared to
2006. The approval by the Washington Commission of the PGA mechanism
rate increase effective October 1, 2006 increased rates by 10.2% annually and
then the approval of a rate decrease effective October 1, 2007 decreased rates
13.0% annually. The PGA mechanism passes through to customers
increases or decreases in the natural 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 natural gas pipeline
transportation costs. PSE’s gas margin and net income are not
affected by changes under the PGA mechanism. For 2007, the effects of
the PGA mechanism rate changes provided a net increase of $9.7 million in gas
operating revenues. The remaining increase in gas retail revenues was
primarily due to higher gas sales of 41.6 million therms or $43.3 million for
2007 as compared to 2006, which was related in part to a 2.6% increase in
customers.
The
following natural gas rate changes were approved by the Washington Commission in
2007 and 2006:
Operating
Expenses. The
table below sets forth significant changes in operating expenses for PSE from
2006 to 2007.
(Dollars
in Millions)
Twelve
Months Ended December 31
2007
2006
Change
Percent
Change
Purchased
electricity
$
895.6
$
917.8
$
(22.2
)
(2.4
)%
Electric
generation fuel
143.4
97.3
46.1
47.4
Residential
exchange
(52.4
)
(163.6
)
111.2
68.0
Purchased
gas
762.1
723.2
38.9
5.4
Unrealized
(gain)/loss on derivative instruments
(2.7
)
0.1
(2.8
)
*
Utility
operations and maintenance
403.7
354.6
49.1
13.8
Non-utility
expense and other
12.4
4.5
7.9
175.6
Depreciation
and amortization
279.2
262.3
16.9
6.4
Conservation
amortization
40.0
32.3
7.7
23.8
Taxes
other than income taxes
288.5
255.8
32.7
12.8
_______________
*
Percent
change not applicable or
meaningful
Purchased electricity expenses
decreased $22.2 million in 2007 as compared to 2006 due primarily to a decrease
in purchased power of 983,297 MWh or 5.5%, resulting in a decrease of $46.6
million, offset by an increase in wholesale market prices which caused an
increase of $16.7 million. Contributing to the decrease in purchased
power was the increase in electric generation at company-owned
facilities. The Power Cost Adjustment (PCA) mechanism reflected a
$9.4 million decrease in the deferral of power costs for 2007 as compared to
2006 due to an increase in the overrecovery of allowable power costs shared with
customers due to lower power costs in 2007 as compared to
2006. Transmission and other power supply expenses increased by $17.1
million in 2007 as compared to 2006 due in part to increased kilowatt hour (kWh)
sales to customers which increased transmission costs.
The July9, 2007 Columbia Basin Runoff Forecast published by the National Weather Service
Northwest River Forecast Center indicated that the total forecasted runoff above
Grand Coulee Reservoir for the period April through September 2007 was 99% of
normal, which compares to 106% of normal runoff observed for the same period in
2006. The January 2008 Early Bird Columbia Basin Runoff Forecast
published by the National Weather Service Northwest River Forecast Center
indicated that the total forecasted runoff above Grand Coulee Reservoir for the
period January through July 2008 would be 100% of normal.
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 regulated power portfolio through short-term
and intermediate-term off-system physical purchases and sales and through other
risk management techniques.
Electric generation fuel
expense increased $46.1 million in 2007 as compared to 2006 primarily due to the
addition of the Goldendale generating facility in 2007 which contributed $32.7
million to the cost of fuel and an increase of $8.7 million due to higher
volumes of electricity generated at Colstrip which increased coal costs in 2007
as compared to 2006. In addition, higher cost of natural gas fuel at
PSE’s other combustion turbines contributed $4.7 million in 2007 as compared to
2006.
Residential exchange credits
associated with the Residential Purchase and Sale Agreement with the BPA
decreased $111.2 million in 2007 as compared to 2006 as a result of lower
residential and small farm customer electric credit in rates effective October1, 2006. The residential exchange credit provided to residential and
small farm customers was suspended effective June 7, 2007 due to an adverse
ruling from the U.S. Court of Appeals of the Ninth Circuit (Ninth Circuit) which
states that BPA actions in entering into residential exchange settlement
agreements with investor owned utilities were not in accordance with the
law. The residential exchange credit is a pass-through tariff item
with a corresponding credit in electric operating revenue; thus, it has no
impact on electric margin or net income.
Purchased gas expenses
increased $38.9 million in 2007 as compared to 2006 primarily due to an increase
in PGA rates as approved by the Washington Commission and higher customer therm
sales. The PGA mechanism allows PSE to recover expected natural gas
costs, and defer, as a receivable or liability, any natural gas costs that
exceed or fall short of this expected natural gas cost amount in PGA mechanism
rates, including accrued interest. The PGA mechanism payable balance
at December 31, 2007 was $77.9 million as compared to a receivable balance at
December 31, 2006 of $39.8 million. PSE is authorized by the
Washington Commission to accrue carrying costs on PGA receivable and payable
balances. A receivable balance in the PGA mechanism reflects an
underrecovery of market natural gas cost through rates. A payable
balance reflects overrecovery of market natural gas cost through
rates.
Unrealized gain on derivative
instruments increased $2.8 million in 2007 as compared to 2006
primarily as a result of the unrealized gain related to a physical natural gas
supply contract for PSE’s electric generating facilities offset by the
settlement of a portion of the gain. The mark-to-market gain or loss
on the physical natural gas supply contracts is the difference between the
forward market price of natural gas and the contract price for natural gas based
on volumes purchased. As the contracts near termination, the gain or
loss will continue to reverse due to settlement of the contract on a monthly
basis and the mark-to-market value will decrease as long as the price for
natural gas is at or near the current forward market price.
Utility operations and maintenance
expense increased $49.1 million in 2007 as compared to 2006 primarily due
to higher operating and maintenance costs of $16.0 million at PSE’s generating
facilities. The increase in costs at PSE’s generating facilities is
primarily due to the addition of Wild Horse which began operations on December22, 2006 and Goldendale, which was acquired during February
2007. Wild Horse operations and maintenance expense is fully
recovered in rates and beginning September 1, 2007, Goldendale is fully
recovered in rates. Customer service and support services costs
increased $19.7 million due to higher costs associated with salaries, benefits,
consultants and bad debt reserve. The balance of the increases was
the result of infrastructure reliability work performed on the utility’s
transmission and distribution systems..
Non-utility expense and other
increased $7.9 million in 2007 as compared to 2006 primarily due to an increase
in PSE’s long-term share-based incentive plan costs based on an increase in
performance modifiers.
Depreciation and amortization
expense increased $16.9 million in 2007 as compared to 2006, which include the
benefit of the deferral of Goldendale ownership and operating costs of $10.8
million which, had it not been included, would have resulted in an increase to
depreciation and amortization expense of $27.7 million for 2007 as compared to
2006. Also contributing to the increase in depreciation and
amortization was $13.5 million from placing Wild Horse into service on December16, 2006, $2.7 million from placing Goldendale into service on February 22, 2007
and $11.5 million from other depreciable property placed into service in 2007
and 2006. On August 2, 2007, the Washington Commission approved a
PCORC settlement agreement filed July 5, 2007 finding the acquisition of
Goldendale to be prudent. The Goldendale deferral of ownership and operating
costs ceased to be effective September 1, 2007, when PSE was authorized to begin
recovering the costs in rates.
Conservation amortization
increased $7.7 million in 2007 as compared to 2006 due to higher authorized
recovery of electric and natural gas conservation
expenditures. Conservation amortization is a pass-through tariff item
with no impact on earnings.
Taxes other than income taxes
increased $32.7 million in 2007 as compared to 2006 primarily due to a property
tax settlement in 2006 with the Washington State Department of Revenue which
resulted in lower property valuations in 2006. The increases also
reflect an additional plant placed in service as well as revenue sensitive taxes
due to increased revenue.
Other
Income, Other Expenses, Interest Expense and Income Tax
Expense. The table below sets forth significant changes for
PSE from 2006 to 2007.
(Dollars
in Millions)
Twelve
Months Ended December 31
2007
2006
Change
Percent
Change
Interest
expense
$
206.5
$
168.9
$
37.6
22.3
%
Income
tax expense
74.2
98.7
(24.5
)
(24.8
)
Interest expense increased
$37.6 million for 2007 as compared to 2006. The increase was driven
primarily by additional debt financing in 2007 during which average balances
were higher than 2006 levels as a result of financing the Company’s construction
and plant acquisition projects and higher interest rates. The
increase was also driven by more favorable pricing on natural gas purchases in
2007 which resulted in the interest-bearing PGA transferring from a receivable
balance in 2006 to a payable balance in 2007.
Income tax expense decreased
$24.5 million in 2007 as compared to 2006. The effective tax rate was
lower due to higher tax credits associated with the production of wind-powered
energy (PTCs). The PTCs for 2007 were $20.2 million as compared to
$7.0 million in 2006. These additional credits were made available
due to the addition of Wild Horse, which was placed in service in December
2006. In addition, income tax expense benefited from a true-up of the
prior year federal income tax provision which resulted in a benefit in 2007
versus an expense in 2006.
2006 compared to
2005
Puget Sound
Energy
Energy
Margins. The
following table displays the details of electric margin changes from 2005 to
2006. 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.
Electric
Margin
(Dollars
in Millions)
Twelve
Months Ended December 31
2006
2005
Change
Percent
Change
Electric
operating revenue1
$
1,777.7
$
1,612.9
$
164.8
10.2
%
Less:
Other electric operating revenue
(51.8
)
(62.5
)
10.7
17.1
Add:
Other electric operating revenue – gas supply resale
16.4
26.1
(9.7
)
(37.2
)
Total
electric revenue for margin
1,742.3
1,576.5
165.8
10.5
Adjustments
for amounts included in revenue:
Pass-through
tariff items
(35.9
)
(26.9
)
(9.0
)
(33.5
)
Pass-through
revenue-sensitive taxes
(117.4
)
(104.9
)
(12.5
)
(11.9
)
Net
electric revenue for margin
1,589.0
1,444.7
144.3
10.0
Minus
power costs:
Purchased
electricity1
(917.8
)
(860.4
)
(57.4
)
(6.7
)
Electric
generation fuel1
(97.3
)
(73.3
)
(24.0
)
(32.7
)
Residential
exchange1
163.6
180.5
(16.9
)
(9.4
)
Total
electric power costs
(851.5
)
(753.2
)
(98.3
)
(13.1
)
Electric
margin2
$
737.5
$
691.5
$
46.0
6.7
%
_______________
1
As
reported on PSE’s Consolidated Statement of Income.
2
Electric
margin does not include any allocation for amortization/depreciation
expense or electric generation operation and maintenance
expense.
Electric margin increased $46.0 million
in 2006 as compared to 2005 primarily due to the effects of the general rate
case rate increase effective March 4, 2005 and the PCORC rate increases
effective November 1, 2005 and July 1, 2006 which increased margin by $27.5
million. Retail customer kWh sales (residential, commercial and
industrial customers) increased 3.1% in 2006 as compared to 2005, which provided
$21.8 million to electric margin. Electric margin also increased by
$12.9 million due to overrecovery of excess power cost under the PCA
mechanism. Electric margin increased by $1.2 million due to the
reduction of the Tenaska disallowance in the PCA mechanism. These
increases were partially offset by a $11.2 million decrease related to PTCs
provided to customers through tariff rates, which are trued-up to actual PTCs
taken in an annual true-up process and the non-recurring benefit of a February23, 2005 Washington Commission order allowing recovery of power costs that
lowered electric margin by $6.0 million.
The
following table displays the details of gas margin changes from 2005 to
2006. Gas margin is gas sales to retail and transportation customers
less pass-through tariff items and revenue-sensitive taxes, and the cost of
natural gas purchased, including natural gas transportation costs to bring
natural gas to PSE’s service territory.
Gas
Margin
(Dollars
in Millions)
Twelve
Months Ended December 31
2006
2005
Change
Percent
Change
Gas
operating revenue1
$
1,120.1
$
952.5
$
167.6
17.6
%
Less:
Other gas operating revenue
(16.5
)
(17.2
)
0.7
4.1
Total
gas revenue for margin
1,103.6
935.3
168.3
18.0
Adjustments
for amounts included in revenue:
Pass-through
tariff items
(7.1
)
(5.7
)
(1.4
)
(24.6
)
Pass-through
revenue-sensitive taxes
(86.3
)
(73.1
)
(13.2
)
(18.1
)
Net
gas revenue for margin
1,010.2
856.5
153.7
17.9
Minus
purchased gas costs1
(723.2
)
(592.1
)
(131.1
)
(22.1
)
Gas
margin2
$
287.0
$
264.4
$
22.6
8.5
%
_______________
1
As
reported on PSE’s Consolidated Statement of Income.
2
Gas
margin does not include any allocation for amortization/depreciation
expense or electric generation operations and maintenance
expense.
Gas
margin increased $22.6 million in 2006 as compared to 2005. Gas
margin increased $12.6 million due to a 4.7% increase in natural gas therm
volume sales; $7.0 million of the increase was a result of the natural gas
general tariff rate case which was effective March 4, 2005. These increases were
partially offset by a $1.5 million decrease in margin related to customer mix
and pricing.
Electric
Operating Revenues. The
table below sets forth changes in electric operating revenues for PSE from 2005
to 2006.
(Dollars
in Millions)
Twelve
Months Ended December 31
2006
2005
Change
Percent
Change
Electric
operating revenues:
Residential
sales
$
788.2
$
690.2
$
98.0
14.2
%
Commercial
sales
702.8
629.0
73.8
11.7
Industrial
sales
103.0
93.9
9.1
9.7
Other
retail sales, including unbilled revenue
35.4
23.3
12.1
51.9
Total
retail sales
1,629.4
1,436.4
193.0
13.4
Transportation
sales
11.5
9.0
2.5
27.8
Sales
to other utilities and marketers
85.0
105.0
(20.0
)
(19.0
)
Other
51.8
62.5
(10.7
)
(17.1
)
Total
electric operating revenues
$
1,777.7
$
1,612.9
$
164.8
10.2
%
Electric
retail sales increased $193.0 million for 2006 as compared to 2005 due primarily
to rate increases related to the PCORC and the electric general rate case and
increased retail customer usage. The PCORC and electric general rate
case provided a combined additional $68.7 million to electric operating revenues
for 2006 as compared to 2005. Retail electricity usage increased
626,207 MWh or 3.1% for 2006 as compared to 2005. The increase in
electricity usage was mainly the result of a 1.6% higher average number of
customers served in 2006 as compared to 2005.
During
2006, the benefits of the Residential and Small Farm Energy Exchange Benefit
credited to residential and small farm customers reduced electric operating
revenues by $171.3 million as compared to $189.0 million for
2005. This credit also reduced power costs by a corresponding amount
with no impact on earnings.
Transportation
sales increased $2.5 million for 2006 as compared to 2005 due to an increase in
sales volume of 61,524 MWh or 3.0%.
Sales to
other utilities and marketers decreased $20.0 million as compared to 2005 due
primarily to a decrease in the wholesale market price of electricity in 2006 as
compared to 2005 offset by an increase of 180,842 MWh in 2006 from
2005.
Other
electric revenues decreased $10.7 million in 2006 as compared to 2005, primarily
associated with natural gas purchased for electric generation needs that was
subsequently sold rather than used by PSE or gains from electric generation
financial derivatives on natural gas sold. The following electric
rate changes were approved by the Washington Commission in 2006 and
2005:
The
rate increase is for the period July 1, 2006 through December 31,2006. The annualized basis of the PCORC rate increase is $96.1
million.
Gas
Operating Revenues. The
table below sets forth changes in gas operating revenues for PSE from 2005 to
2006.
(Dollars
in Millions)
Twelve
Months Ended December 31
2006
2005
Change
Percent
Change
Gas
operating revenues:
Residential
sales
$
697.6
$
592.4
$
105.2
17.8
%
Commercial
sales
335.7
281.3
54.4
19.3
Industrial
sales
57.1
48.3
8.8
18.2
Total
retail sales
1,090.4
922.0
168.4
18.3
Transportation
sales
13.3
13.3
--
0.0
Other
16.4
17.2
(0.8
)
(4.7
)
Total
gas operating revenues
$
1,120.1
$
952.5
$
167.6
17.6
%
Gas
retail sales increased $168.4 million for 2006 as compared to 2005 due to higher
Purchased Gas Adjustment (PGA) mechanism rates in 2006, approval of a 3.5% gas
general rate increase effective March 4, 2005 and higher retail customer natural
gas usage. The Washington Commission approved a PGA mechanism rate
increase effective October 1, 2005 that provided $113.2 million in gas revenues
for 2006 as compared to 2005. In addition, the natural gas general
rate case increase provided an additional $7.0 million in gas operating revenues
for 2006 as compared to in 2005. The remaining increase in gas retail
revenues was primarily due to a 3.0% increase in customers and higher natural
gas sales of 48.4 million therms or $43.8 million for 2006 as compared to
2005.
The
following natural gas rate changes were approved by the Washington Commission in
2006 and 2005:
Operating
Expenses. The
table below sets forth significant changes in operating expenses for PSE from
2005 to 2006.
(Dollars
in Millions)
Twelve
Months Ended December 31
2006
2005
Change
Percent
Change
Purchased
electricity
$
917.8
$
860.4
$
57.4
6.7
%
Electric
generation fuel
97.3
73.3
24.0
32.7
Residential
exchange
(163.6
)
(180.5
)
16.9
9.4
Purchased
gas
723.2
592.1
131.1
22.1
Utility
operations and maintenance
354.6
333.3
21.3
6.4
Non-utility
expense and other
4.5
7.5
(3.0
)
(40.0
)
Depreciation
and amortization
262.3
241.6
20.7
8.6
Conservation
amortization
32.3
24.3
8.0
32.9
Taxes
other than income taxes
255.8
233.8
22.0
9.4
Purchased electricity expenses
increased $57.4 million in 2006 as compared to 2005 primarily due to a 3.1%
increase in retail customer sales volumes and a 9.6% increase in wholesale sales
volumes. Total purchased power for 2006 increased 904,560 MWh, or a
5.4% increase over 2005. Increase in the purchased power
volumes offset by slightly lower wholesale prices caused an increase of $19.2
million in 2006. The increase in costs also reflected the recovery of
previously deferred excess power costs of $12.7 million due to lower power costs
in 2006 than the baseline PCA mechanism rate as compared to a deferral of excess
power costs of $15.7 million in 2005. Also contributing to the
increase in costs was a Washington Commission order that allowed PSE to reflect
additional power costs totaling $6.0 million during the PCA 2 period of July 1,2003 through December 31, 2003 in 2005. In addition, transmission and
other expenses increased $5.0 million due in part to increased kWh sales to
customers.
PSE’s
hydroelectric production and related power costs in 2006 were positively
impacted by above-normal precipitation and snow pack in the Pacific Northwest
region, which resulted in the runoff above Grand Coulee Reservoir to be 106% of
normal as compared to a below normal runoff of 88% in 2005.
Electric generation fuel
expense increased $24.0 million in 2006 as compared to 2005 primarily due to an
increase of $17.4 million in the cost of fuel at PSE-controlled combustion
turbine generating facilities due to higher costs of natural gas offset by
slightly lower volumes of electricity generated and an increase in the cost of
coal at Colstrip generating facilities of $6.6 million compared to
2005.
Residential exchange credits
associated with the Residential Purchase and Sale Agreement with the BPA
decreased $16.9 million in 2006 as compared to 2005 as a result of lower
residential and small farm customer electric rates. The residential
exchange credit is a pass-through tariff item with a corresponding credit in
electric operating revenue; thus, it has no impact on electric margin or net
income. Effective October 1, 2006, the annual payment PSE receives
from BPA decreased to $105.5 million for the period through September 30,2007. This had no impact on PSE’s earnings as the payment is passed
through to customers through a lower residential exchange tariff
credit.
Purchased gas expenses
increased $131.1 million in 2006 as compared to 2005 primarily due to an
increase in PGA rates as approved by the Washington Commission and higher
customer therm sales. The PGA mechanism allows PSE to recover
expected natural gas costs, and defer, as a receivable or liability, any natural
gas costs that exceed or fall short of this expected natural gas cost amount in
PGA mechanism rates, including accrued interest. The PGA mechanism
receivable balance at December 31, 2006 and December 31, 2005 was $39.8 million
and $67.3 million, respectively. PSE is authorized by the Washington
Commission to accrue carrying costs on PGA receivable balances. A
receivable balance in the PGA mechanism reflects a current underrecovery of
market natural gas cost through rates. For further discussion on PGA
rates see Item 1 – Business - Gas Regulation and Rates.
Utility operations and maintenance
expense increased $21.3 million in 2006 as compared to 2005 primarily due
to higher production costs of $11.9 million related to major overhauls of
Colstrip Units 1 and 4, the Hopkins Ridge wind project which became operational
on November 26, 2005, soil remediation costs at PSE’s Crystal Mountain electric
generation station site and costs to repair a failure of PSE’s Whitehorn Unit 2
combustion turbine generator. $7.2 million of the increase was due to
higher electric distribution system restoration costs as a result of a series of
severe winter storms. In addition, customer service and call center
costs increased $3.8 million and gas operations and distribution costs increased
$2.0 million. These increases were slightly offset by a decrease of
$3.6 million in other expenses. PSE anticipates operation and
maintenance expense to increase in future years as investments in new generating
resources and energy delivery infrastructure are completed. The
timing and amounts of increases will vary depending on when new generating
resources come into service.
A series
of severe wind storms occurred during 2006 for which PSE incurred significant
costs, including a wind storm that occurred in December 2006 that resulted in a
loss of electric service to over 700,000 of PSE’s customers. PSE
incurred over $72.0 million in estimated costs related to this wind storm, the
majority of which were deferred in accordance with the Washington Commission’s
orders. In total, PSE deferred $92.3 million of storm costs in 2006
as a result of a Washington Commission order that allowed deferral of qualified
storm costs in excess of $7.0 million. Qualifying storm costs are
those that exceed the Institute of Electrical and Electronics Engineers (IEEE)
standard for determining system average interruption duration
index.
Non-utility operations and
maintenance expense decreased $3.0 million in 2006 as compared to 2005
primarily due to expenses for several energy efficiency projects for the United
States Navy which were completed in 2005.
Depreciation and amortization
expense increased $20.7 million in 2006 as compared to 2005 due primarily to the
effects of new generating facilities, electric distribution system plant and
natural gas distribution system plant placed in service, of which $8.1 million
is from placing the Hopkins Ridge wind project in service on November 26,2005.
Conservation amortization
increased $8.0 million in 2006 as compared to 2005 due to higher authorized
recovery of electric and natural gas conservation
expenditures. Conservation amortization is a pass-through tariff item
with no impact on earnings.
Taxes other than income taxes
increased $22.0 million in 2006 as compared to 2005 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. Excluding the impact of revenue sensitive
taxes, taxes other than income taxes decreased $3.8 million primarily as a
result of a 2006 property tax reduction settled with the Washington State
Department of Revenue in August 2006 which resulted in a lower valuation for tax
purposes in 2006 as compared to 2005.
Other
Income, Other Expenses, Interest Expense and Income Tax
Expense. The table below sets forth significant changes in
other income and interest charges for PSE from 2005 to 2006.
(Dollars
in Millions)
Twelve
Months Ended December 31
2006
2005
Change
Percent
Change
Other
income
$
28.2
$
12.0
$
16.2
135.0
%
Other
expenses
6.6
4.8
1.8
37.5
Interest
expense
169.0
165.0
4.0
2.5
Income
taxes
98.7
87.1
11.6
13.3
Other income increased $16.2
million in 2006 as compared to 2005 primarily due to an increase in the accrual
of carrying costs on regulatory assets of $12.2 million and an increase of $4.2
million in the equity portion of allowance for funds used during construction
(AFUDC).
Other expenses increased by
$1.8 million due to regulatory penalties incurred in 2006.
Interest expense increased
$4.0 million in 2006 as compared to 2005 due primarily to interest expense of
$6.4 million related to an increase in debt due to construction projects offset
by an increase in the debt AFUDC credit.
Income taxes increased $11.6
million in 2006 as compared to 2005 due to higher taxable income slightly offset
by a lower effective tax rate influenced by PTCs.
InfrastruX
On May 7,2006, Puget Energy sold its 90.9% interest in InfrastruX to an affiliate of
Tenaska Power Fund, L.P. (Tenaska), resulting in after-tax cash proceeds of
approximately $95.9 million, an after-tax gain of $29.8 million for
2006. Puget Energy accounted for InfrastruX as a discontinued
operation under Statement of Financial Accounting Standards (SFAS) No. 144,
“Accounting for the Impairment or Disposal of Long-Lived Assets” (SFAS No. 144)
in 2005 and 2006.
Under the
terms of the sale agreement, Puget Energy remains obligated for certain
representations and warranties made by InfrastruX concerning its business
through May 7, 2008. Puget Energy obtained a representation and
warranty insurance policy and deposited $3.7 million into an escrow account as
retention under the policy. As of December 31, 2006, long-term
restricted cash in the amount of $3.8 million was included in the accompanying
balance sheets and represented Puget Energy’s maximum exposure related to those
commitments. At December 31, 2007, the amount was $4.0
million. Puget Energy also agreed to indemnify the purchaser for
certain potential future losses related to one of InfrastruX’s subsidiaries
through May 7, 2011, with the maximum amount of loss not to exceed $15.0
million. A liability in the amount of $5.0 million was included in
the accompanying balance sheets as of December 31, 2006, which represents Puget
Energy’s estimate of the fair value of the amount potentially payable using a
probability-weighted approach to a range of future cash flows. At
December 31, 2007, the amount was $3.2 million. Puget Energy also
provided an environmental guarantee as part of the sale
agreement. Puget Energy believes it will not have a future loss in
connection with the environmental guarantee.
For 2006,
Puget Energy reported InfrastruX related income from discontinued operations,
including gain on sale, of $51.9 million compared to $9.5 million for 2005 (in
each case, net of taxes and minority interest). Puget Energy’s income
from discontinued operations for 2006 includes $7.3 million related to the
reversal of a carrying value adjustment recorded in 2005 as well as $10.0
million related to the anticipated realization of a deferred tax asset
associated with the sale of the business.
InfrastruX’s operating revenue through
May 7, 2006 was $138.6 million compared to $393.3 million for the twelve months
ended December 31, 2005. Pre-tax income for the twelve months ended
December 31, 2006 was $9.9 million compared to $36.4 million for the same period
in 2005.
Capital
Resources and Liquidity
Capital
Requirements
Contractual
Obligations and Commercial Commitments
Puget Energy. The
following are Puget Energy’s aggregate consolidated (including PSE) contractual
obligations and commercial commitments as of December 31:
Non-qualified
pension and other benefits funding and payments
41.6
5.8
8.1
8.0
19.7
Other
obligations
7.7
7.7
--
--
--
Total
contractual cash obligations
$
13,759.3
$
1,841.9
$
2,676.3
$
1,656.9
$
7,584.2
Puget
Energy
Amount
of Commitment
Expiration
Per Period
Commercial
Commitments
(Dollars
in Millions)
Total
2008
2009-
2010
2011-
2012
2013
& Thereafter
Indemnity
agreements 2
$
7.2
$
4.0
$
--
$
3.2
$
--
Credit
agreement - available 3
734.1
--
--
--
734.1
Receivables
securitization facility
4
48.0
--
--
48.0
--
Energy
operations letter of credit
7.4
7.4
--
--
--
Total
commercial commitments
$
796.7
$
11.4
$
--
$
51.2
$
734.1
_______________
1
See
“Fredonia 3 and 4 Operating Lease” under “Off-Balance Sheet Arrangements”
below.
2
Under
the InfrastruX sale agreement, Puget Energy is obligated for certain
representations and warranties concerning InfrastruX’s business and
anti-trust inquiries. The fair value of the business warranty
was $4.0 million at December 31, 2007 and the obligation expires on May 7,2008. Puget Energy also agreed to indemnify the buyer relating
to an inquiry of an InfrastruX subsidiary and the fair value of the
warranty was $3.2 million at December 31, 2007. See
“InfrastruX” above for further discussion.
3
At
December 31, 2007, PSE had available a $500.0 million and a $350.0 million
unsecured credit agreement, each expiring in April 2012. The
credit agreement provides credit support for letters of credit and
commercial paper. At December 31, 2007, PSE had $7.4 million
outstanding under four letters of credit, and $108.5 million commercial
paper outstanding, effectively reducing the available borrowing capacity
to $734.1 million.
4
At
December 31, 2007, PSE had available a $200.0 million receivables
securitization facility that expires in December 2010. $152.0
million was outstanding under the receivables securitization facility at
December 31, 2007 thus leaving $48.0 million available. The
facility allows receivables to be used as collateral to secure short-term
loans, not exceeding the lesser of $200.0 million or the borrowing base of
eligible receivables, which fluctuate with the seasonality of energy sales
to customers. See “Receivables Securitization Facility" below
for further discussion.
Puget Sound
Energy. The following are PSE’s aggregate contractual
obligations and commercial commitments as of December 31:
Non-qualified
pension and other benefits funding and payments
41.6
5.8
8.1
8.0
19.7
Other
obligations
7.7
7.7
--
--
--
Total
contractual cash obligations
$
13,775.1
$
1,857.7
$
2,676.3
$
1,656.9
$
7,584.2
Puget Sound Energy. The
following are PSE’s aggregate commercial commitments as of December 31,2007:
Puget
Sound Energy
Amount
of Commitment
Expiration
Per Period
Commercial
commitments
(Dollars
in Millions)
Total
2008
2009-
2010
2011-
2012
2013
& Thereafter
Credit
agreement - available 2
$
734.1
$
--
$
--
$
--
$
734.1
Receivables
securitization facility 3
48.0
--
--
48.0
--
Energy
operations letter of credit
7.4
7.4
--
--
--
Total
commercial commitments
$
789.5
$
7.4
$
--
$
48.0
$
734.1
_______________
1
See
note 1 above.
2
See
note 3 above.
3
See
note 4 above.
Off-Balance
Sheet Arrangements
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 31,2007, PSE’s outstanding balance under the lease was $48.3
million. The expected residual value under the lease is the lesser of
$37.4 million or 60.0% 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
PSE’s
construction programs for generating facilities, the electric transmission
system and the natural gas and electric distribution system are designed to meet
continuing customer growth and to support reliable energy
delivery. The cash flow construction expenditures, excluding equity
AFUDC and customer refundable contributions was $720.4 million in
2007. The anticipated utility construction expenditures, excluding
AFUDC, for 2008, 2009 and 2010 are:
Capital
Expenditure Projections
(Dollars
in Millions)
2008
2009
2010
Energy
delivery, technology and facilities
$
595.0
$
568.0
$
743.0
New
resources
72.0
220.0
514.0
Total
expenditures
$
667.0
$
788.0
$
1,257.0
The
proposed utility construction expenditures and any new generation resource
expenditures that may be incurred are anticipated to be funded with a
combination of cash from operations, 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.
Capital
Resources
Cash
From Operations
Cash
generated from operations for 2007 was $564.0 million, which is 72.2% of the
$780.7 million used for utility construction expenditures and other capital
expenditures. For 2006, cash generated from operations was $185.5
million which is 23.7% of the $783.4 million used for utility construction
expenditures and other capital expenditures.
The overall cash generated from
operating activities for 2007 increased $378.5 million as compared to
2006. The increase was primarily the result of $102.2 million less
income tax paid in 2007, the collection of the purchased gas receivable of $90.2
million in 2007, the increase in the collection of $73.5 million in accounts
receivable, a cash receipt of $18.9 million from the lease purchase option
settlement for the Bellevue offices and $63.1 million less cash paid for storm
damage costs. In addition, there were costs incurred in 2006 which
did not recur in 2007, including the Chelan PUD contract initiation payment of
$89.0 million, cash collateral re-payment to energy suppliers for $22.0 million
and proceeds from the sale of InfrastruX of $29.8 million. The
increase in cash generated from operating activities for 2007 was partially
offset by a decrease of $88.7 million in payments made for accounts payable
related to energy purchases and a $22.5 million increase in payments to
customers related to the Residential Exchange program.
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 depends 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 natural gas mortgage indentures,
restated articles of incorporation and certain loan agreements. Under
the most restrictive tests, at December 31, 2007, PSE could issue:
·
approximately
$592.0 million of additional first mortgage bonds under PSE’s electric
mortgage indenture based on approximately $986.7 million of electric
bondable property available for issuance, subject to an interest coverage
ratio limitation of 2.0 times net earnings available for interest (as
defined in the electric utility mortgage), which PSE exceeded at December31, 2007;
·
approximately
$507.0 million of additional first mortgage bonds under PSE’s natural gas
mortgage indenture based on approximately $845.0 million of natural gas
bondable property available for issuance, subject to interest coverage
ratio limitations of 1.75 times and 2.0 times net earnings available for
interest (as defined in the gas utility mortgage), which PSE exceeded at
December 31, 2007;
·
approximately
$1.0 billion of additional preferred stock at an assumed dividend rate of
7.8%; and
·
approximately
$763.5 million of unsecured long-term
debt.
At
December 31, 2007, PSE had approximately $4.5 billion in electric and natural
gas ratebase to support the interest coverage ratio limitation test for net
earnings available for interest.
Credit
Ratings
Neither
Puget Energy nor PSE has any debt outstanding that would accelerate debt
maturity upon a credit rating downgrade. However, a ratings downgrade
could adversely affect the 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 borrowing costs 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 prompt
counterparties on a contract-by-contract basis in the wholesale electric,
wholesale natural 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.
Standard
& Poor’s does not rate PSE’s credit
facilities.
2
On
October 26, 2007, Standard& Poor’s placed the ratings of Puget Energy
(BBB-) and PSE (BBB-/A-3) on CreditWatch with negative
implications. The CreditWatch listing reflects the possibility
that debt ratings for Puget Energy could be lowered dependent on the final
outcome of regulatory approval proceedings.
3
On
October 29, 2007, Moody’s placed the Ba1 Issuer rating of Puget Energy on
review for possible downgrade. Moody’s also affirmed the
long-term ratings of PSE and changed its rating outlook to stable from
positive. On this same date, Moody’s placed PSE’s P-2
short-term rating for commercial paper under review for possible
downgrade.
Shelf
Registrations, Long-Term Debt and Common Stock Activity
On March16, 2006, Puget Energy and PSE filed a shelf registration statement with the
Securities and Exchange Commission for the offering of:
·
common
stock of Puget Energy;
·
senior
notes of PSE, secured by first mortgage
bonds;
·
preferred
stock of PSE; and
·
trust
preferred securities of Puget Sound Energy Capital Trust
III.
The
registration statement is valid for three years and does not specify the amount
of securities that the Company may offer. The Company is subject to
restrictions under PSE’s indentures and articles of incorporation on the amount
of first mortgage bonds, unsecured debt and preferred stock that the Company may
issue.
On June1, 2007, PSE redeemed the remaining 8.231% Capital Trust Preferred Securities
(classified on the balance sheet as Junior Subordinated Debentures of the
Corporation Payable to a Subsidiary Trust Holding Mandatorily Redeemable
Preferred Securities and referred to herein as “Securities”). The
purpose of the redemption was to help reduce interest costs by retiring higher
cost debt. The remaining $37.8 million of the Securities outstanding
were redeemed on June 1, 2007 at a 4.12% premium, or $39.3 million, plus accrued
interest on the redemption date.
On June4, 2007, PSE issued $250.0 million of Junior Subordinated Notes (Notes) due June
2067. The Notes bear a fixed rate of interest of 6.974% for the first
ten and a half years with interest payable semiannually in May and November of
each year, after which the notes will bear a variable rate of interest (3-month
LIBOR plus 2.35%). Proceeds were used to fund the redemption of the
remaining $37.8 million 8.231% Securities and to repay short-term
debt. The Notes are structured to be treated as debt by the Internal
Revenue Service (IRS), yet they are considered to contain equity-like
characteristics by the credit rating agencies. In addition, the Notes
contain a call option feature and are callable in whole or in part by PSE on or
after June 1, 2017. They are presented on the balance sheet as a
separate line item in the redeemable securities and long-term debt.
Puget
Energy completed the sale of 12.5 million shares of common stock pursuant to the
stock purchase agreement the Company announced on October 25, 2007, among Puget
Energy and a consortium of long-term infrastructure investors led by Macquarie
Infrastructure Partners (collectively the Purchasers). The Purchasers
paid an aggregate offering price of $295.9 million. The securities
were sold in a private placement, without registration under the Securities Act
of 1933. Puget Energy intends to use the net proceeds from the
issuance to invest in PSE for capital expenditures, debt redemption and working
capital.
Based on
PSE’s goal to become energy self-sufficient, it is expected that further
issuances of debt, equity or a combination of the two will be necessary in the
future. The structure, timing and amount of such financings depend on
market conditions and financing needed.
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. PSE was not
significantly impacted by the current credit environment.
PSE
Credit Facilities
The
Company has three committed credit facilities that provide, in aggregate, $1.05
billion in short-term borrowing capability. These include a $500.0
million credit agreement, a $200.0 million accounts receivable securitization
facility and a $350.0 million credit agreement to support hedging
activity.
Credit
Agreements. In March 2007, PSE entered into a five-year,
$350.0 million credit agreement with a group of banks. The agreement
is used to support the Company’s energy hedging activities and may also be used
to provide letters of credit. The interest rate on outstanding
borrowings is based either on the agent bank’s prime rate or on LIBOR plus a
marginal rate related to PSE’s long-term credit rating at the time of
borrowing. PSE pays a commitment fee on any unused portion of the
credit agreement also related to long-term credit ratings of PSE. At
December 31, 2007, there were no borrowings or letters of credit outstanding
under the credit facility.
In March
2005, PSE entered into a five-year $500.0 million unsecured credit agreement
with a group of banks. In March 2007, PSE restated this credit
agreement to extend the expiration date to April 2012. The agreement
is primarily used to provide credit support for commercial paper and letters of
credit. The terms of this agreement, as restated, are essentially
identical to those contained in the $350.0 million facility described
above.
At
December 31, 2007, there was $7.4 million outstanding under four letters of
credit and $108.5 million commercial paper outstanding, effectively reducing the
available borrowing capacity under the two credit agreements to $734.1
million.
Receivables Securitization
Facility. PSE entered into a five-year Receivables Sales
Agreement with PSE Funding, Inc. (PSE Funding), a wholly owned subsidiary, on
December 20, 2005. Pursuant to the Receivables Sales Agreement, PSE
sells all of its utility customer accounts receivable and unbilled utility
revenues to PSE Funding. In addition, PSE Funding entered into a Loan
and Servicing Agreement with PSE and two banks. The Loan and
Servicing Agreement allows PSE Funding to use the receivables as collateral to
secure short-term loans, not exceeding the lesser of $200.0 million or the
borrowing base of eligible receivables which fluctuate with the seasonality of
energy sales to customers. All loans from this facility will be
reported as short-term debt in the financial statements. The PSE
Funding facility expires in December 2010, and is terminable by PSE and PSE
Funding upon notice to the banks. There were $152.0 million in loans
that were secured by accounts receivable pledged at December 31,2007. The remaining borrowing base of eligible receivable at December31, 2007 was $48.0 million.
Demand Promissory Note. On
June 1, 2006, PSE entered into a revolving credit facility with its parent,
Puget Energy, in the form of a Demand Promissory Note (Note). Through
the Note, PSE may borrow up to $30.0 million from Puget Energy, subject to
approval by Puget Energy. Under the terms of the Note, PSE pays
interest on the outstanding borrowings based on the lowest of the
weighted-average interest rate of (a) PSE’s outstanding commercial paper
interest rate; (b) PSE’s senior unsecured revolving credit facility; or (c) the
interest rate available under the receivables securitization facility of PSE
Funding, a PSE subsidiary, which is the LIBOR rate plus a marginal
rate. At December 31, 2007, the outstanding balance of the Note was
$15.8 million. The outstanding balance and the related interest under
the Note are eliminated by Puget Energy upon consolidation of PSE’s financial
statements.
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 $9.8 million (399,993
shares) in 2007 as compared to $13.5 million (615,648 shares) in
2006. The proceeds from sales of stock under the Stock Purchase and
Dividend Reinvestment Plan are used for general corporate
needs. Pending the outcome of the merger, Puget Energy does not
intend to fund the Stock Purchase and Dividend Reinvestment Plan with authorized
but unissued shares.
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 (NYSE) at market prices.
Other
IRS Audit. As a
matter of course, the Company’s tax returns are routinely audited by federal,
state and city tax authorities. In May 2006, the IRS completed its
examination of the company’s 2001, 2002 and 2003 federal income tax
returns. The Company formally appealed the IRS audit adjustment
relating to the Company’s accounting method with respect to capitalized internal
labor and overheads. In its 2001 tax return, PSE claimed a deduction
when it changed its tax accounting method with respect to capitalized internal
labor and overheads. Under the new method, the Company could
immediately deduct certain costs that it had previously
capitalized. In the audit, the IRS disallowed the
deduction.
Through
September 30, 2005, the Company claimed $66.3 million in accumulated tax
benefits. PSE accounted for the accumulated tax benefits as temporary
differences in determining its deferred income tax
balances. Consequently, the repayment of the tax benefits did not
impact earnings but did have a cash flow impact of $33.2 million in the fourth
quarter 2005 and $33.1 million in 2006. As of December 31, 2006, the
full tax benefit had been repaid.
During
2007, the IRS national office established settlement guidelines which the
appeals office will use in reaching settlements with taxpayers. The
effect of the settlement guidelines shift some of the benefits claimed in 2001
through 2004 into 2005 and 2006. As a result, the Company has accrued
interest in the amount of $5.5 million.
On
October 19, 2005, PSE filed an accounting petition with the Washington
Commission to defer the capital costs associated with repayment of the deferred
tax. The Washington Commission had reduced PSE’s ratebase by $72.0
million in its order of February 18, 2005. The accounting petition
was approved by the Washington Commission on October 26, 2005, for deferral of
additional capital costs beginning November 1, 2005 using PSE’s allowed net of
tax rate of return. The Washington Commission granted cost recovery
of these deferred carrying costs over two years, beginning January 13,2007.
In its
2003 tax return, the Company claimed a deduction for a portion of the California
Independent System Operator (CAISO) receivable. Upon examination, the
IRS claimed that the deduction was not valid for the 2003 tax
year. The Company formally appealed. In appeals, the
Company and the IRS agreed to move the deduction from 2003 to
2005. In the fourth quarter 2007, the Company recorded interest
expense in the amount of $2.2 million to reflect the transfer of the deduction
from 2003 to 2005. In addition, it is management’s expectation that
the Company could request rate recovery of the regulatory asset for the interest
accrued.
Tenaska Disallowance. The
Washington Commission issued an order on May 13, 2004 determining that PSE did
not prudently manage natural gas costs for the Tenaska electric generating plant
and ordered PSE to adjust its PCA deferral account to reflect a disallowance of
accumulated costs under the PCA mechanism for these excess costs. The
increase in purchased electricity expense resulting from the disallowance
totaled $7.8 million, $9.0 million and $4.1 million in 2007, 2006 and 2005,
respectively. The order also 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.
In August 2004, PSE filed the PCA 2
period compliance 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 $6.0
million related to the period July 1, 2003 through December 31,2003.
The
Washington Commission confirmed that if the Tenaska natural gas costs are deemed
prudent, PSE will recover the full amount of actual natural gas costs and the
recovery of the Tenaska regulatory asset even if the benchmark is
exceeded. Due to fluctuations in forward market prices of natural
gas, the amount and timing of any potential disallowance related to Tenaska can
change significantly day to day. The projected costs and projected
benchmark costs for Tenaska as of December 31, 2007 based on current forward
market natural gas prices are as follows:
(Dollars
in Millions)
2008
2009
2010
2011
Projected
Tenaska costs *
$
241.6
$
262.7
$
260.4
$
240.7
Projected
Tenaska benchmark costs
182.9
189.9
197.4
205.5
Over benchmark
costs
$
58.7
$
72.8
$
63.0
$
35.2
Projected
50% disallowance based on Washington Commission
methodology
$
6.4
$
4.9
$
3.1
$
1.1
_______________
*
Projection
will change based on market conditions of natural gas and replacement
power costs.
Regulatory Matters. On December 15, 2006, FERC began an audit
of PSE’s Open Access Transmission Tariff and Standards of Conduct for the period
January 1, 2004 through December 31, 2006. The focus of the audit is
PSE’s operation of its electric transmission system and tariff and its energy
trading function. The audit is on-going and as of February 28, 2008,
an audit report has not been issued. PSE expects a draft audit report
to be issued for PSE review in the first quarter 2008 with a final report
shortly thereafter. The FERC audit team has identified several areas
of concern, but at this point PSE is not aware which of these issues, if any,
will be included in the final audit report. While FERC has authority
to assess regulatory penalties for non-compliance with their regulatory
policies, PSE is not able to predict the outcome of the audit at this
time.
In November 2007, PSE was audited
by the Western Electricity Coordinating Council (WECC) under delegated authority
of the NERC, the FERC-certified Electric Reliability Organization
(ERO). Previously PSE had submitted several self reports and
mitigation plans to WECC for review and approval. The WECC audit team
told PSE of four additional preliminary alleged violations (without any
specified penalties) that were not previously self reported. In response,
PSE submitted self reports and mitigation plans for the four
violations. WECC has accepted the self reports and mitigation
plans. The ultimate result of the audit, including the nature or amount of
any penalties, cannot be predicted at this time.
On December 18,2007, PSE received a data request from the Investigations Division of the Office
of Enforcement at FERC seeking information about certain natural gas pipeline
capacity release transactions PSE entered into in 2006 and 2005. PSE
responded to the data requests on January 23, 2008 and met with FERC staff on
January 31, 2008. At this meeting, PSE discussed with FERC staff
additional transactions discovered in the course of responding to the data
requests that potentially may be in violation of FERC regulations. PSE
received additional data requests from FERC on February 20, 2008. PSE is
not able to predict the outcome of this investigation at this
time.
Proceedings
Relating to the Western Power Market
The
following discussion summarizes the status as of the date of this report of
ongoing proceedings relating to the western power markets to which PSE is a
party. PSE is vigorously defending each of these
cases. 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.
California Receivable and California
Refund Proceeding. Since 2001, PSE has held a receivable
relating to unpaid bills for power that PSE sold in 2000 into the markets
maintained by the CAISO. At December 31, 2007, the net receivable for
such sales was approximately $21.1 million. PSE’s ability to recover
all or a portion of this amount is uncertain. At this time,
management believes there is no reasonable basis under applicable financial
accounting standards to adjust PSE’s net receivable because the outcome of
further court and FERC actions is uncertain and any likely financial impact
cannot be quantified.
In 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). FERC also ordered that if the refunds required by the
formula it adopted would cause a seller to recover less than its actual costs
for the refund period, the seller is allowed to document its costs and limit its
refund liability commensurately. Consistent with those orders, PSE
filed a fuel cost adjustment claim and a portfolio cost
claim. Recovery of those amounts is uncertain, but the amount owed to
PSE under all FERC orders to date is included in the PSE net receivable
amount. FERC has not issued a final order determining “who
owes how much to whom” in the California Refund Proceeding and it is not
clear when such an order will be issued.
In the
course of the California Refund Proceeding, FERC has issued dozens of
orders. Most have been taken up on appeal before the Ninth Circuit,
which has issued opinions on some issues in the last several
years. These cases are described below in the section, “California
Litigation.”
California
Litigation. Lockyer v.
FERC. 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. This case was originally presented
to FERC upon complaint that the adoption and implementation of market rate
authority was flawed. FERC dismissed the complaint after all sellers
refiled summaries of transactions with California entities during 2000 and
2001. 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 remands to FERC
the question of whether to allow refunds. On December 28, 2006, PSE
and several other energy sellers filed a petition for a writ of certiorari to
the U.S. Supreme Court, but the petition was not granted and the matter was
remanded to FERC for further proceedings on December 4, 2007. 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.
CPUC v. FERC. On
August 2, 2006, the Ninth Circuit decided that FERC erred in excluding potential
relief for tariff violations for periods that pre-dated October 2, 2000 and
additionally ruled that FERC should consider remedies for transactions
previously considered outside the scope of the proceedings. The
August 2, 2006 decision may adversely impact PSE’s ability to recover the full
amount of its CAISO receivable. The decision may also expose PSE to
claims or liabilities for transactions outside the previously defined “refund
period.” At this time the ultimate financial outcome for PSE is
unclear. Rehearing by the Ninth Circuit on this matter was sought on
November 16, 2007. The rehearing petition has not been acted
upon. In addition, parties have been engaged in court-sponsored
settlement discussions, and those discussions may result in some
settlements. PSE is unable to predict either the outcome of the
proceedings or the ultimate financial effect on PSE.
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 investigated
26 entities that allegedly had potential “partnerships” with
Enron. PSE was not named in that show cause order. On
January 22, 2004, FERC stated that it did not intend to proceed further against
other parties.
The
second show cause order 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 a nominal amount to settle all
claims. FERC approved the settlement on January 22,2004. The California parties filed for rehearing of that
order. On March 17, 2004, PSE moved to dismiss the California
parties’ rehearing request and awaits FERC action on that motion.
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 ordered
for the California markets. FERC dismissed PSE’s complaint, but PSE
challenged that dismissal. On June 19, 2001, FERC ordered price
caps on energy sales throughout the West. Various parties, including
the Port of Seattle and the cities of Seattle and Tacoma, then moved to
intervene in the proceeding seeking retroactive refunds for numerous
transactions. The proceeding became known as the “Pacific Northwest
Refund Proceeding,” though refund claims were outside the scope of the
original complaint. On June 25, 2003, FERC terminated the proceeding
on procedural, jurisdictional and equitable grounds and on November 10, 2003,
FERC on rehearing, confirmed the order terminating the proceeding. On
August 24, 2007, the Ninth Circuit issued a decision concluding that FERC should
have evaluated and considered evidence of market manipulation in California and
its potential impact in the Pacific Northwest. It also decided that
FERC should have considered purchases made by the California Energy Resources
Scheduler and/or the California Department of Water Resources in the Pacific
Northwest Proceeding. On December 17, 2007, PSE and Powerex
separately filed requests for rehearing with the Ninth Circuit of this
decision. Those requests remain pending. PSE intends to
vigorously defend its position in this proceeding, but it is unable to predict
the outcome of this matter.
Wah Chang Suit. In
June 2004, Wah Chang, an Oregon company, filed suit in federal court against
Puget Energy and PSE, among others. The complaint is similar to the
allegations made in other cases that were dismissed as having no
merit. The case was dismissed on the grounds that FERC has the
exclusive jurisdiction over plaintiff’s claims. On March 10, 2005,
Wah Chang filed a notice of appeal to the Ninth Circuit. Oral
argument took place on April 10, 2007 and the Ninth Circuit issued an opinion
affirming the lower court’s dismissal of the case on November 20,2007. Wah Chang filed a petition for rehearing; on January 15, 2008,
the Ninth Circuit denied rehearing.
Proceeding
Relating to the Proposed Merger
On
October 26, 2007 and November 2, 2007, two separate lawsuits were
filed against the Company and all of the members of the Company’s Board of
Directors in Superior Court in King County, Washington. The lawsuits,
respectively, are entitled, Tansey v. Puget Energy, Inc.,
et al., Case No. 07-2-34315-6 SEA and Alaska Ironworkers Pension Trust v.
Puget Energy, Inc., et al., Case
No. 07-2-35346-1 SEA. The lawsuits are both denominated as class actions
purportedly on behalf of Puget Energy’s shareholders and assert substantially
similar allegations and causes of action relating to the proposed
merger. (See Note 24 for more information regarding the proposed
transaction.) The complaints allege that the Company’s directors
breached their fiduciary duties in connection with the merger and seek virtually
identical relief, including an order enjoining the consummation of the
merger. Pursuant to a court order dated November 26, 2007, the
two cases were consolidated for all purposes and entitled In re Puget Energy, Inc. Shareholder
Litigation, Case No. 07-2-34315-6 SEA.
On
February 7, 2008, the parties entered into a memorandum of understanding
providing for the settlement of the consolidated lawsuit, subject to customary
conditions including completion of appropriate settlement documentation,
confirmatory discovery and court approval. Pursuant to the memorandum
of understanding, the Company has agreed to include certain additional
disclosures in its proxy statement relating to the merger. The
Company does not admit, however, that its prior disclosures were in any way
materially misleading or inadequate. In addition, the Company and the
other defendants in the consolidated lawsuit deny the plaintiffs’ allegations of
wrongdoing and violation of law in connection with the merger. The
settlement, if completed and approved by the court, will result in dismissal
with prejudice and release of all claims of the plaintiffs and settlement class
of the Company’s shareholders that were or could have been brought on behalf of
the plaintiffs and the settlement class. In connection with such
settlement, the plaintiffs intend to seek a court-approved award of attorneys’
fees and expenses in an amount up to $290,000, which the Company has agreed to
pay.
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 natural gas is determined by reviewing
historical billed therms to therms delivered to customers, which vary little
from year to year. 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
or upon the sale of assets. The recognition of revenue is in
conformity with generally accepted accounting principles, which require the use
of estimates and assumptions that affect the reported amounts of
revenue.
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” (SFAS No. 71). 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, 2007 in the amount of $794.2 million and $288.3 million,
respectively, and regulatory assets and liabilities of $838.5 million and $191.6
million, respectively, at December 31, 2006. 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 that
vary from baseline rates over a graduated scale. 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” (SFAS No. 133), 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 natural gas portfolios, Puget Energy enters into contracts to
purchase or sell electricity and natural gas. These contracts are
considered derivatives under SFAS No. 133 unless a determination is made that
they qualify for the 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 purchase and normal sale 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 and 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 energy portfolio management
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. The Company is focused
on commodity price exposure and risks associated with volumetric variability in
the natural gas and electric portfolios. It is not engaged in the
business of assuming risk for the purpose of speculative trading. The
Company hedges open natural gas and electric positions to reduce both the
portfolio risk and the volatility risk in prices. The exposure
position is determined by using a probabilistic risk system that models 100
scenarios of how the Company’s natural gas and power portfolios will perform
under various weather, hydro and unit performance conditions.
Pension and Other Postretirement
Benefits. Puget Energy has a qualified defined benefit pension
plan covering substantially all employees of PSE. Qualified pension
expense of $2.8 million and $1.0 million was recorded in 2007 and 2006,
respectively, and income of $2.6 million was recorded in the financial
statements for 2005. Of these amounts, approximately 58.6%, 56.6% and
63.0% offset utility operations and maintenance expense in 2007, 2006 and 2005,
respectively, and the remaining amounts were capitalized. It is
expected that PSE will recognize qualified pension income of $3.0 million in
2008.
PSE’s
pension and other postretirement benefits income or costs depend on several
factors and assumptions, including plan design, timing and amount of cash
contributions to the plan, earnings on plan assets, discount rate, expected
long-term rate of return, mortality 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 its projected benefit obligation. The
Company has selected an expected return on plan assets based on a historical
analysis of rates of return and the Company’s investment mix, market conditions,
inflation and other factors. The Company’s accounting policy for
calculating the market-related value of assets is based on a five-year smoothing
of asset gains/losses measured from the expected return on market-related
assets. This is a calculated value that recognizes changes in fair
value in a systematic and rational manner over five years. The same
manner of calculating market-related value is used for all classes of assets,
and is applied consistently from year to year. During 2007, PSE made
no cash contributions to the qualified defined benefit plan and expects to make
no contributions in 2008.
The
following table reflects the estimated sensitivity associated with a change in
certain significant 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 2007
Pension
Expense
(increase)
decrease
(Dollars
in Thousands)
Pension
Benefits
Other
Benefits
Pension
Benefits
Other
Benefits
Increase
in discount rate
50
basis points
$ (21,207)
$ (2,485)
$ (2,196)
$ (251)
Decrease
in discount rate
50
basis points
23,230
2,691
2,384
270
Increase
in return on plan assets
50
basis points
*
*
(2,355)
(75)
Decrease
in return on plan assets
50
basis points
*
*
2,355
75
_______________
*
Calculation
not applicable.
California
Receivable. 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 was $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, 2007, such remaining
receivables were approximately $21.1 million.
Based on
the calculation of existing FERC orders issued to date, PSE has determined that
the receivable balance at December 31, 2007 is collectible from the
CAISO. However, PSE’s ability to collect all or a portion of this
amount may be impaired by future FERC orders or decisions by the Ninth
Circuit.
Stock
Compensation. Effective January 1, 2006, the Company adopted
the fair value recognition provisions of SFAS No. 123R (revised 2004),
“Share-Based Payment” (SFAS No. 123R), using the modified-prospective transition
method. Results for prior periods have not been restated, as provided
for under the modified-prospective method. Prior to 2006, stock-based
compensation plans were accounted for according to Accounting Principles Board
(APB) No. 25, “Accounting for Stock Issued to Employees” (APB No. 25), and
related interpretations as allowed by SFAS No. 123, “Accounting for Stock-Based
Compensation” (SFAS No. 123). 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”
(SFAS No. 148). The Company applied SFAS No. 123 accounting to stock
compensation awards granted subsequent to January 1, 2003, while grants prior to
2003 continued to be accounted for using the intrinsic value method of APB No.
25.
The
adoption of SFAS 123R resulted in a cumulative benefit from an accounting change
of $0.1 million, after tax, for the quarter ended March 31, 2006. The
cumulative effect adjustment is the result of the inclusion of estimated
forfeitures occurring before award vesting dates in the computation of
compensation expense for unvested awards. As a result of adopting
SFAS No. 123R on January 1, 2006, the Company’s income before income taxes and
net income from continuing operations for the twelve months ended December 31,2006 was $0.1 million and $0.1 million higher, respectively, than if it had
continued to account for share-based compensation under SFAS No. 123 due to the
inclusion of estimated forfeitures in compensation cost.
The fair
value of the stock-based grants is based on the closing price of the Company’s
common stock on the date of measurement and historical performance of the
certain share grants and prospective analysis using the Capital Asset Pricing
Model and expected EPS growth rates. Based on this analysis, the
Company’s total shareholder returns would need to significantly increase as
compared to other companies to have a material impact on the Company’s financial
statements. Shares granted prior to 2006 were valued using the
Black-Scholes option pricing model.
New
Accounting Pronouncements
On
September 15, 2006, FASB issued SFAS No. 157, “Fair Value Measurements” (SFAS
No. 157), which clarifies how companies should use fair value measurements in
accordance with GAAP for recognition and disclosure. SFAS No. 157
establishes a common definition of fair value and a framework for measuring fair
value under GAAP, along with expanding disclosures about fair value measurements
to eliminate differences in current practice that exist in measuring fair value
under the existing accounting standards. The definition of fair value in SFAS
No. 157 retains the notion of exchange price; however, it focuses on the
price that would be received to sell the asset or paid to transfer the liability
(i.e., an exit price), rather than the price that would be paid to acquire the
asset or received to assume the liability (i.e., an entry price). Under SFAS
No. 157, a fair value measure should reflect all of the assumptions that
market participants would use in pricing the asset or liability, including
assumptions about the risk inherent in a particular valuation technique, the
effect of a restriction on the sale or use of an asset, and the risk of
nonperformance. To increase consistency and comparability in fair value
measures, SFAS No. 157 establishes a three-level fair value hierarchy to
prioritize the inputs used in valuation techniques between observable inputs
that reflect quoted prices in active markets, inputs other than quoted prices
with observable market data and unobservable data (e.g., a company’s own
data). SFAS No. 157 is effective for fiscal years beginning after
November 15, 2007, which is the year beginning January 1, 2008, for the
Company. On February 6, 2008, the FASB decided to issue a final
FASB Staff Position (FSP) that would partially defer the effective date of SFAS
No. 157 for one year for nonfinancial assets and nonfinancial liabilities that
are recognized or disclosed at fair value, except for those that are recognized
or disclosed at fair value on an annual or more frequent basis. The
Company adopted SFAS No. 157 on January 1, 2008, prospectively, as required by
the Statement, with certain exceptions, including the following noted in
paragraph 37 (a) of the statement, “A financial instrument that was measured at
fair value at initial recognition under Statement 133 using the transaction
price in accordance with the guidance in footnote 3 of Emerging Issues Task
Force (EITF) Issue No. 02-3, “Issues Involved in Accounting for Derivative
Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and
Risk Management Activities” (EITF No. 02-3), prior to the initial adoption of
this Statement.” At the date this Statement is initially applied to
the financial statements, a difference between the carrying amounts and the fair
values of those instruments shall be recognized as a cumulative-effect
adjustment to the opening balance of retained earnings.
The
Company estimates that the impact of the adoption of SFAS No. 157 to its
statement of financial position and results of operations to be a cumulative
effect adjustment to retained earnings of $9.0 million before tax as a result of
recording a deferred loss on net derivative assets and liabilities.
In July
2006, Financial Accounting Standards Board (FASB) issued Interpretation No. 48,
“Accounting for Uncertainty in Income Taxes, an Interpretation of FASB Statement
No. 109” (FIN 48), which clarifies the accounting for uncertainty in income
taxes recognized in the financial statements in accordance with FASB Statement
No. 109, “Accounting for Income Taxes.” FIN 48 requires the use of a
two-step approach for recognizing and measuring tax positions taken or expected
to be taken in a tax return. First, a tax position should only be
recognized when it is more likely than not, based on technical merits, that the
position will be sustained upon examination by the taxing
authority. Second, a tax position that meets the recognition
threshold should be measured at the largest amount that has a greater than 50%
likelihood of being sustained.
FIN 48
was effective for the Company as of January 1, 2007. As of the date
of adoption, the Company had no material unrecognized tax
benefits. As of December 31, 2007, the Company had no material
unrecognized tax benefits. As a result, no interest or penalties were
accrued for unrecognized tax benefits during the year.
The
Company has energy risk policies and procedures to manage commodity and
volatility risks. The Company’s Energy Management Committee establishes the
Company’s energy risk management policies and procedures, and monitors
compliance. The Energy Management Committee is comprised of certain Company
officers and is overseen by the Audit Committee of the Company’s Board of
Directors.
The
Company is focused on commodity price exposure and risks associated with
volumetric variability in the natural gas and electric portfolios. It
is not engaged in the business of assuming risk for the purpose of speculative
trading. The Company hedges open natural gas and electric positions
to reduce both the portfolio risk and the volatility risk in
prices. The exposure position is determined by using a probabilistic
risk system that models 100 scenarios of how the Company’s natural gas and power
portfolios will perform under various weather, hydro and unit performance
conditions. The objectives of the hedging strategy are
to:
·
ensure
physical energy supplies are available to reliably and cost-effectively
serve retail load;
·
manage
energy portfolio risks prudently to serve retail load at overall least
cost and limit undesired impacts on PSE’s customers and shareholders;
and
·
reduce
power costs by extracting the value of the Company’s
assets.
The
following table presents electric derivatives that are designated as cash flow
hedges or contracts that do not meet Normal Purchase Normal Sale (NPNS) at
December 31, 2007 and December 31, 2006:
If it is
determined that it is uneconomical to operate PSE’s controlled electric
generating facilities in the future period, the fuel supply cash flow hedge
relationship is terminated and the hedge is de-designated which results in the
unrealized gains and losses associated with the contracts being recorded in the
income statement. As these contracts are settled, the costs are
recognized as energy costs and are included as part of the PCA
mechanism.
At
December 31, 2007, the Company had an unrealized day one loss deferral of $9.0
million related to a three year locational power exchange contract which was
modeled and therefore the day one loss was deferred under EITF No.
02-3. The deferred loss is being amortized over the term of the
contracts. Any future changes in the mark-to-market value will be
recorded through the income statement. The contracts have economic
benefit to the Company over their terms. The locational exchange will
help ease electric transmission congestion across the Cascade Mountains during
the winter months as PSE will take delivery of energy at a location that
interconnects with PSE’s transmission system in Western
Washington. At the same time, PSE will make available the quantities
of power at the Mid-Columbia trading hub location.
The
following table presents the impact of changes in the market value of derivative
instruments not meeting NPNS or cash flow hedge criteria to the Company’s
earnings during the twelve months ending December 31, 2007 and December 31,2006:
(Dollars
in millions)
2007
2006
Change
Increase
(decrease) in earnings
$
2.7
$(0.1)
$
2.8
The
Company recorded an increase in earnings for the change in the market value of
derivative instruments not meeting the normal purchase normal sale exception or
cash flow hedge criteria under SFAS No. 133 of $2.7 million for 2007 compared to
a decrease in earnings of $0.1 million for 2006. The increase in
earnings in 2007 primarily relates to the unrealized gain associated with a
physically delivered natural gas supply contract for electric generation that
did not meet NPNS or cash flow hedge criteria.
The
amount of unrealized gain, net of tax, related to the Company’s energy-related
cash flow hedges under SFAS No. 133 consisted of the following at December 31,2007 and December 31, 2006:
At
December 31, 2007, the Company had total assets of $11.3 million and total
liabilities of $17.3 million related to hedges of natural gas contracts to serve
natural gas customers. 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. All increases and
decreases in the cost of natural gas supply are passed on to customers with the
PGA mechanism. As the gains and losses on the hedges are realized in
future periods, they will be recorded as natural gas costs under the PGA
mechanism.
A
hypothetical 10.0% increase in the market prices of natural gas and electricity
would increase the fair value of qualifying cash flow hedges by $31.6 million,
net of tax, and would decrease the fair value of those contracts
marked-to-market in earnings by $0.1 million, net of tax.
Prices
based on models and other valuation methods
--
9.9
1.4
0.7
12.0
Total
$
(10.0
)
$
9.9
$
1.4
$
0.7
$
2.0
Credit
Risk
The Company is exposed to credit risk
primarily through buying and selling electricity and natural gas to serve
customers. Credit risk is the potential loss resulting from a
counterparty’s non-performance under an agreement. The Company
manages credit risk with policies and procedures for, among other things,
counterparty analysis, exposure measurement, exposure monitoring and exposure
mitigation. The Company has entered into master netting arrangements 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.
It is possible that extreme volatility
in energy commodity prices could cause the Company to have credit risk exposures
with one or more counterparties. If such counterparties fail to
perform their obligations under one or more agreements, the Company could suffer
a material financial loss. However, as of December 31, 2007,
approximately 99.8% of the counterparties comprising the sources of our energy
portfolio are rated at least investment grade by the major rating agencies and
0.2% are either rated below investment grade or are not rated by rating
agencies. The Company assesses credit risk internally for
counterparties that are not rated.
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 anticipated 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 on fixed rate debt as of December 31, 2007 or 2006; however from
time to time the Company may enter into treasury lock or forward starting swap
contracts to hedge interest rate exposure related to anticipated debt
issuance. The carrying amounts and the fair values of the Company’s
debt instruments are:
PSE’s
carrying value and fair value of fixed-rate long-term debt was the same as
Puget Energy’s debt in 2007 and
2006.
The
ending balance in other comprehensive income related to the forward starting
swaps and previously settled treasury lock contracts at December 31, 2007 is a
net loss of $8.2 million after tax and accumulated amortization. This
compares to a loss of $8.5 million in other comprehensive income after tax and
accumulated amortization at December 31, 2006. 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.
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.
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 Chairman of the Board, the Board members are
independent of the Company and its
management.
·
All
members of our key Board committees – the Audit Committee, the
Compensation and Leadership 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 Corporate Ethics and Compliance 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 the Chief
Ethics and Compliance 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.
Management
is confident that the internal control structure is operating effectively and
will allow the Company to meet the requirements under Section 404 of the
Sarbanes-Oxley Act of 2002.
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 audit conducted in accordance with auditing standards prescribed by the
Public Company Accounting Oversight Board, 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.
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.
To the
Board of Directors and Shareholders of Puget Energy, Inc.:
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, 2007 and 2006, and the results
of their operations and their cash flows for each of the three years in the
period ended December 31, 2007 in conformity with accounting principles
generally accepted in the United States of America. In addition, in our opinion,
the financial statement schedules listed in the accompanying index present
fairly, in all material respects, the information set forth therein when read in
conjunction with the related consolidated financial statements. Also in our
opinion, the Company maintained, in all material respects, effective internal
control over financial reporting as of December 31, 2007, based on criteria
established in Internal Control - Integrated Framework issued by the Committee
of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s
management is responsible for these financial statements and financial statement
schedules, for maintaining effective internal control over financial reporting
and for its assessment of the effectiveness of internal control over financial
reporting, included in Management’s Report on Internal Control Over Financial
Reporting appearing under Item 9A. Our responsibility is to express
opinions on these financial statements, on the financial statement schedules,
and on the Company’s internal control over financial reporting based on our
integrated audits. We conducted our audits in accordance with the
standards of the Public Company Accounting Oversight Board (United
States). Those standards require that we plan and perform the audits
to obtain reasonable assurance about whether the financial statements are free
of material misstatement and whether effective internal control over financial
reporting was maintained in all material respects. Our audits of the
financial statements included 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. Our audit of
internal control over financial reporting included obtaining an understanding of
internal control over financial reporting, assessing the risk that a material
weakness exists, and testing and evaluating the design and operating
effectiveness of internal control based on the assessed risk. Our
audits also included performing such other procedures as we considered necessary
in the circumstances. We believe that our audits provide a reasonable basis for
our opinions.
As
discussed in Note 13 to the consolidated financial statements, the Company
changed the manner in which it accounts for uncertain tax positions in
2007.
As
discussed in Note 16 to the consolidated financial statements, the Company
changed the manner in which it accounts for share-based compensation in
2006.
As
discussed in Note 14 to the consolidated financial statements, the Company
changed the manner in which it accounts for defined pension and other
postretirement benefit plans in 2006.
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.
To the
Board of Directors and Shareholder of Puget Sound Energy, Inc.:
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, 2007 and 2006, and the results
of their operations and their cash flows for each of the three years in the
period ended December 31, 2007 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. Also in our
opinion, the Company maintained, in all material respects, effective internal
control over financial reporting as of December 31, 2007, based on criteria
established in Internal Control - Integrated Framework issued by the Committee
of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s
management is responsible for these financial statements and financial statement
schedule, for maintaining effective internal control over financial reporting
and for its assessment of the effectiveness of internal control over financial
reporting, included in Management’s Report on Internal Control Over Financial
Reporting appearing under Item 9A. Our responsibility is to express
opinions on these financial statements, on the financial statement schedule, and
on the Company’s internal control over financial reporting based on our
integrated audits. We conducted our audits in accordance with the
standards of the Public Company Accounting Oversight Board (United
States). Those standards require that we plan and perform the audits
to obtain reasonable assurance about whether the financial statements are free
of material misstatement and whether effective internal control over financial
reporting was maintained in all material respects. Our audits of the
financial statements included 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. Our audit of
internal control over financial reporting included obtaining an understanding of
internal control over financial reporting, assessing the risk that a material
weakness exists, and testing and evaluating the design and operating
effectiveness of internal control based on the assessed risk. Our
audits also included performing such other procedures as we considered necessary
in the circumstances. We believe that our audits provide a reasonable basis for
our opinions.
As
discussed in Note 13 to the consolidated financial statements, the Company
changed the manner in which it accounts for uncertain tax positions in
2007.
As
discussed in Note 16 to the consolidated financial statements, the Company
changed the manner in which it accounts for share-based compensation in
2006.
As
discussed in Note 14 to the consolidated financial statements, the Company
changed the manner in which it accounts for defined pension and other
postretirement benefit plans in 2006.
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.
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
--
37,750
Long-term
debt:
First
mortgage bonds and senior notes
2,446,500
2,571,500
Pollution
control revenue bonds:
Revenue
refunding 2003 series, due 2031
161,860
161,860
Junior
subordinated notes
250,000
--
Long-term
debt due within one year
(179,500
)
(125,000
)
Total
long-term debt excluding current maturities
2,678,860
2,608,360
Total
capitalization
$
5,202,703
$
4,764,028
*
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.
Foreign
currency translation adjustment, net of tax of $0, $(176) and $(49),
respectively
--
(327
)
(91
)
Unrealized
gain from pension and postretirement plans, net of tax of $16,083, $2,376
and $0, respectively
29,869
2,873
925
Net
unrealized gain (loss) on energy derivative instruments during the period,
net of tax of $(6,776), $(17,669) and $26,799 respectively
(12,584
)
(32,813
)
49,770
Reversal
of net unrealized gains (losses) on energy derivative instruments settled
during the period, net of tax of $6,017, $(2,972) and $(10,319),
respectively
11,174
(5,519
)
(19,164
)
Settlement
of financing cash flow hedge contracts, net of tax of $0, $7,239 and
$(12,363), respectively
--
13,443
(22,960
)
Amortization
of financing cash flow hedge contracts to earnings, net of tax
of $171, $289 and $245, respectively
317
537
455
Deferral
of energy cash flow hedges related to the power cost adjustment mechanism,
net of tax of $0, $3,367 and $6,949, respectively
--
6,253
12,905
Other
comprehensive income (loss)
28,776
(15,553
)
21,840
Comprehensive
income
$
213,240
$
203,663
$
177,566
The
accompanying notes are an integral part of the consolidated financial
statements.
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
--
37,750
Long-term
debt:
First
mortgage bonds and senior notes
2,446,500
2,571,500
Pollution
control revenue bonds:
Revenue
refunding 2003 series, due 2031
161,860
161,860
Junior
subordinated notes
250,000
--
Long-term
debt due within one year
(179,500
)
(125,000
)
Total
long-term debt excluding current maturities
2,678,860
2,608,360
Total
capitalization
$
5,184,840
$
4,740,282
*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.
Unrealized
gain from pension and postretirement plans, net of tax of $16,083, $2,376
and $0, respectively
29,869
2,873
925
Net
unrealized gains (losses) on energy derivative instruments during the
period, net of tax of $(6,776), $(17,669), and $26,799,
respectively
(12,584
)
(32,813
)
49,770
Reversal
of net unrealized gains (losses) on energy derivative instruments settled
during the period, net of tax of $6,017, $(2,972) and
$(10,319), respectively
11,174
(5,519
)
(19,164
)
Settlement
of financing cash flow hedge contracts, net of tax of $0, $7,239 and
$(12,363), respectively
--
13,443
(22,960
)
Amortization
of financing cash flow hedge contracts to earnings, net of tax of $171,
$289 and $245, respectively
317
537
455
Deferral
of energy cash flow hedges related to power cost adjustment mechanism, net
of tax of $0, $3,367 and $6,949, respectively
--
6,253
12,905
Other
comprehensive income (loss)
28,776
(15,226
)
21,931
Comprehensive
income
$
219,903
$
161,514
$
168,700
The
accompanying notes are an integral part of the consolidated financial
statements.
Puget
Energy, Inc. (Puget Energy) is a holding company that owns Puget Sound Energy,
Inc. (PSE) and until May 7, 2006, a 90.9% interest in InfrastruX Group, Inc.
(InfrastruX). PSE is a public utility incorporated in the state of
Washington that furnishes electric and natural gas services in a territory
covering 6,000 square miles, primarily in the Puget Sound region.
The 2007
consolidated financial statements of Puget Energy reflect the accounts of Puget
Energy and its subsidiary, PSE. 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. Certain amounts previously reported have been
reclassified to conform to current year presentations with no effect on total
equity or net income. The reclassification relates to the income
statements of Puget Energy and PSE, which have been changed from a utility
presentation format based on Federal Energy Regulatory Commission (FERC)
guidelines to a presentation based on generally accepted accounting principles
(GAAP).
The 2006
consolidated financial statements of Puget Energy reflect the accounts of Puget
Energy and its subsidiaries, PSE and InfrastruX. Puget Energy holds
all the common shares of PSE and until May 7, 2006, a 90.9% interest in
InfrastruX. The results of PSE and InfrastruX are presented on a
consolidated basis. The financial position and results of operations
for InfrastruX are presented as discontinued operations. At the time
that it was owned by Puget Energy, InfrastruX was a non-regulated utility
construction service company incorporated in the state of Washington, which
provides construction services to the electric and natural gas utility
industries primarily in the Midwest, Texas, south-central and eastern United
States regions.
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, 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 and major maintenance 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, are 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 historical
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 Statement
of Financial Accounting Standards (SFAS) No. 144, “Accounting for the Impairment
or Disposal of Long-Lived Assets” (SFAS No. 144). SFAS No. 144
establishes accounting standards for determining if long-lived assets, including
assets to be disposed of, are impaired and how losses, if any, should be
recognized. The Company believes that the present value of the
estimated future cash inflows from the use and eventual disposition of
long-lived assets is sufficient to recover their carrying values.
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 2007, 2006 and 2005; depreciable gas utility plant was
3.4% in 2007, 3.3% in 2006 and 3.4% in 2005; and depreciable common utility
plant was 5.1% in 2007, 5.1% in 2006 and 4.8 % in 2005. Depreciation
on other property, plant and equipment is calculated primarily on a
straight-line basis over the useful lives of the assets. The cost of
removal is collected from PSE’s customers through depreciation expense and any
excess is recorded as a regulatory liability.
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 $4.8 million and $0.8 million at December 31, 2007 and 2006,
respectively. The restricted cash balance in both 2007 and 2006
includes $0.8 million which represents funds held by Puget Western, Inc., a PSE
subsidiary, for a real estate development project. $4.0 million
represents management’s estimate of the aggregate fair value of the amount
potentially payable under certain representations and warranties made by
InfrastruX concerning its business.
Material
and Supplies
Material
and supplies consists primarily of materials and supplies used in the operation
and maintenance of electric and natural gas distribution and transmission
systems as well as spare parts for combustion turbines used for the generation
of electricity. These items are recorded at lower of cost or market
value using the weighted-average cost method.
Fuel
and Gas Inventory
Fuel and
gas inventory is used in the generation of electricity and for future sales to
the Company’s natural gas customers. Fuel inventory consists of coal,
diesel, and natural gas used for generation. Gas inventory consists
of natural gas and liquefied natural gas (LNG) held in storage for future
sales. These items are recorded at lower of cost or market value
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). SFAS No. 71 requires the Company to defer certain costs that
would otherwise be charged to expense, if it were 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. In most cases, the Company
classifies regulatory assets and liabilities as long-term assets or
liabilities. The exception is the purchased gas adjustment payable
which is a current liability.
The
Company was allowed a return on the net regulatory assets and liabilities of
8.75% for electric rates beginning July 1, 2002 and natural gas rates beginning
September 1, 2002 through March 3, 2005 and 8.4%, or 7.01% after-tax,
for both electric and natural gas rates for the period March 4, 2005 through
January 12, 2007. Effective January 13, 2007 based on the 2006
general rate case, the Company is allowed a return on the net regulatory assets
and liabilities of 8.4% or 7.06% after tax, for both electric and natural gas
rates. The net regulatory assets and liabilities at December 31, 2007
and 2006 included the following:
(Dollars
in Millions)
Remaining
Amortization
Period
2007
2006
PURPA
electric energy supply contract buyout costs
0.5
to 4 years
$
140.6
$
167.9
Storm
damage costs -
electric
*
127.4
101.1
Chelan
PUD contract initiation
**
105.2
95.5
Deferred
income taxes
***
104.9
115.3
White
River relicensing and other costs
****
72.5
69.1
Environmental
remediation
****
37.8
36.3
Deferred
AFUDC
30
years
36.3
33.3
Residential
Exchange
****
35.7
--
Investment
in Bonneville Exchange Power contract
9.5
years
33.5
37.0
Tree
watch costs
7.3
years
15.3
19.8
Colstrip
common property
16.5
years
11.8
12.5
Goldendale
****
11.5
--
Hopkins
Ridge prepaid transmission upgrade
*****
7.2
8.9
PGA
deferral of unrealized (gain) losses on derivative
instruments
***
6.0
54.8
Carrying
costs on income tax payments
2
years
3.4
6.2
Power
cost adjustment (PCA) mechanism
***
3.1
6.4
Various
other regulatory assets
1
to 28.5 years
42.0
34.6
Purchased
gas adjustment (PGA) receivable
***
--
39.8
Total
regulatory assets
$
794.2
$
838.5
Cost
of removal
******
$
(137.9
)
$
(127.1
)
Purchased
gas adjustment (PGA) payable
***
(77.9
)
--
Deferred
credit gas pipeline capacity
4
to 10.8 years
(33.4
)
(44.4
)
Summit
Purchase Option Buy-Out
****
(18.9
)
--
Deferred
gains on property sales
2
years
(12.7
)
(11.1
)
Gas
supply contract settlement
0.5 year
(1.9
)
(5.7
)
Various
other regulatory liabilities
3.1
to 8.5 years
(5.6
)
(3.3
)
Total
regulatory liabilities
$
(288.3
)
$
(191.6
)
Net
regulatory assets and liabilities
$
505.9
$
646.9
_______________
*
Amortization
period for storm costs deferred in 2006 to be determined in a future
Washington Commission rate proceeding.
**
Amortization
period will start in 2011 for a 20-year period.
***
Amortization
period varies depending on timing of underlying
transactions.
****
Amortization
period to be determined in a future Washington Commission rate
proceeding.
*****
Amortization
varies and based upon BPA tariff rate and FERC interest
rate.
******
The
balance is dependent upon the cost of removal of underlying assets and the
life of utility plant.
If the
Company, at some point in the future, determines that all or a portion of the
utility operations no longer meets 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 Financial Accounting Standards Board (FASB) Statement No. 71” (SFAS No.
101). 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
(SEC), the Company reclassified from accumulated depreciation to a regulatory
liability $137.9 million and $127.1 million in 2007 and 2006, 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 to interest expense and as a non-cash
item to other income. Cash inflow related to AFUDC does not occur
until these charges are reflected in rates.
The AFUDC
rate allowed by the Washington Utilities and Transportation Commission
(Washington Commission) for natural gas utility plant additions was 8.4%
beginning March 4, 2005 and 8.76% for the period September 1, 2002 through March3, 2005. The allowed AFUDC rate on electric utility plant was 8.4%
beginning March 4, 2005 and 8.76% for the period July 1, 2002 through March 3,2005. 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 $4.4
million for 2007, $2.7 million for 2006 and $2.8 million for
2005. The deferred asset is being amortized over the average useful
life of the Company’s non-project electric utility plant.
California
Receivable
PSE
operates within the western wholesale market and has made sales into the
California energy market. 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. The amount of the
receivable, $21.1 million at December 31, 2007 is subject to the outcome of the
ongoing litigation.
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 revenue 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 or upon the sale of assets. Revenue from retail sales is
billed based on tariff rates approved by the Washington Commission.
PSE
collected Washington State excise taxes (which are a component of general retail
rates) and municipal taxes of $229.0 million, $203.7 million and $178.0 million
for 2007, 2006 and 2005, respectively. The Company’s policy is to
report such taxes on a gross basis in operating revenues and taxes other than
income taxes in the accompanying consolidated statements of income.
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. 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.
Puget
Energy’s allowance for doubtful accounts at December 31, 2007 and 2006 was $5.5
million and $2.8 million, respectively.
Self-Insurance
The
Company currently has no insurance coverage for storm damage and environmental
contamination that would occur in a current year on company-owned
property. The Company is self-insured for a portion of the risk
associated with comprehensive liability, workers’ compensation claims and
catastrophic property losses other than those which are storm
related. The Washington Commission has approved the deferral of
certain uninsured storm damage costs that exceed $7.0 million of qualifying
storm damage costs for collection in future rates if the outage meets the
Institute of Electrical and Electronics Engineers (IEEE) outage criteria for
system average interruption duration index.
Federal
Income Taxes
Puget
Energy and its subsidiaries file consolidated federal income tax
returns. Income taxes are allocated to the subsidiaries on the basis
of separate company computations of taxable income or loss. The
Company provides for deferred taxes on certain assets and liabilities that are
reported differently for income tax purposes than for financial reporting
purposes, as required by SFAS No. 109, “Accounting for Income Taxes” (SFAS No.
109). Uncertain tax positions are accounted for under FASB
Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (FIN
48). The Company classifies interest as interest expense and
penalties as other expense in the financial statements.
Energy
Efficiency
PSE
offers programs designed to help new and existing residential, commercial and
industrial 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. Energy efficiency programs reduce customer
consumption of energy thus reducing energy margins. The impact of
load reductions is adjusted in rates at each general rate case.
Since
1995, the Company has been authorized by the Washington Commission to defer
natural 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,
natural gas energy efficiency expenditures have no impact on
earnings.
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.
As part
of the Company’s 2006 General Rate Case, the Washington Commission agreed to
have the Company collect an incentive through rate riders if the Company
exceeded the annual 2007 electric annual baseline savings goal of 18.3
aMW. In 2007, PSE achieved 25.4 aMW of cost-effective energy savings
thus exceeding its goals and earning an electric incentive of $3.4
million. The Company recognized $2.5 million in other income for the
year ended December 31, 2007, and will collect this amount from rate riders from
April 2008 through March 2009. The remaining 25%, still subject to
evaluation, was not recognized into income for the year ended December 31, 2007
because the evaluation process was not complete. Once the evaluation
process is completed, then the remaining amount will be recognized into income,
and the Company will collect this amount from rate riders from April 2009
through March 2010.
Rate
Adjustment Mechanisms
The
Company has a Power Cost Adjustment (PCA) mechanism that provides for a rate
adjustment process if PSE’s costs to provide customers’ electricity falls
outside certain bands from a normalized level of power costs established in an
electric rate case. On October 20, 2005, the Washington Commission
approved an amendment to the PCA mechanism changing the PCA period to a calendar
year beginning January 1, 2007. The Washington Commission also made
provision to reduce the graduated scale to half the annual excess power costs
for the period July 1, 2006 through December 31, 2006 without a cap on excess
power costs. 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” (SFAS No. 133), are deferred in proportion
to the cost-sharing arrangement under the PCA mechanism. On January10, 2007, the Washington Commission approved the PCA mechanism with the same
annual graduated scale but without a cap on excess power costs.
The
graduated scale is as follows:
Annual
Power Cost Variability
July
– December 2006 Power Cost Variability1
Customers’
Share
Company’s
Share2
+/-
$20 million
+/-
$10 million
0%
100%
+/-
$20 million - $40 million
+/-
$10 - $20 million
50%
50%
+/-
$40 million - $120 million
+/-
$20 - $60 million
90%
10%
+/-
$120 + million
+/-
$60 million
95%
5%
_______________
1
In
October 2005, the Washington Commission in its power cost only rate case
order made a provision to reduce the power cost variability amounts to
half the annual power cost variability for the period July 1, 2006 through
December 31, 2006.
2
Over
the four-year period July 1, 2002 through June 30, 2006 the Company’s
share of pre-tax cost variation was capped at a cumulative $40.0 million
plus 1% of the excess. Power cost variation after December 31,2006 will be apportioned on an annual basis, based on the graduated scale
without a cap.
The
differences between the actual cost of PSE’s natural gas supplies and natural
gas transportation contracts and costs 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 the PGA mechanism
rates, including interest.
Natural
Gas Off-System Sales and Capacity Release
The
Company contracts for firm natural gas supplies and holds firm transportation
and storage capacity sufficient to meet the expected peak winter demand for
natural 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, the Company holds contractual rights to natural 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 natural gas sales,
exchanges and capacity releases. The Company sells excess natural gas
supplies, enters into natural gas supply exchanges with third parties outside of
its distribution area and releases to third parties excess interstate natural
gas pipeline capacity and natural gas storage rights on a short-term basis to
mitigate the costs of firm transportation and storage capacity for its core
natural gas customers. The proceeds from such activities, net of
transactional costs, are accounted for as reductions in the cost of purchased
natural 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 natural
gas.
Accounting
for Derivatives
The
Company follows the provisions of SFAS No. 133, “Accounting for Derivative
Instruments and Hedging Activities” (SFAS No. 133), as amended by SFAS No. 138
and SFAS No. 149 which require 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 (NPNS)
exception for the purpose of serving retail load. However, those
contracts that do not meet the NPNS exception are derivatives and, pursuant to
SFAS No. 133, are reported at their fair value on 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 in earnings. 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 in offsetting
cash flows attributable to 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 natural gas for
the Company’s retail natural 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.
Stock-Based
Compensation
Prior to
2006, the Company had various stock-based compensation plans which were
accounted for according to Accounting Principles Board (APB) No. 25, “Accounting
for Stock Issued to Employees,” and related interpretations as allowed by SFAS
No. 123, “Accounting for Stock-Based Compensation” (SFAS No. 123). 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”
(SFAS No. 148). The Company applied SFAS No. 123 accounting to stock
compensation awards granted subsequent to January 1, 2003, while grants prior to
2003 continued to be accounted for using the intrinsic value method of APB No.
25. Effective January 1, 2006, the Company adopted the fair value
recognition provisions of SFAS No. 123R, “Share-Based Payment” (SFAS No. 123R),
using the modified-prospective transition method. Under that
transition method, compensation cost recognized in 2006 includes: (a)
compensation cost for all share-based payments granted prior to, but not yet
vested as of January 1, 2006, based on the grant date fair value estimated in
accordance with the original provisions of SFAS No. 123 and (b) compensation
cost for all share-based payments granted subsequent to January 1, 2006, based
on the grant date fair value estimated in accordance with the provisions of SFAS
No. 123R. Results for prior periods have not been restated, as
provided for under the modified-prospective method.
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 as of December 31, 2005 would have been
as follows:
(Dollars
in Thousands, except per share amounts)
Years
Ended December 31
2005
Net
income, as reported
$
155,726
Add:
Total stock-based employee compensation expense included in net income,
net of tax
1,652
Less:
Total stock-based employee compensation expense per the fair value method
of SFAS No. 123, net of tax
(2,195
)
Pro
forma net income
$
155,183
Earnings
per common share:
Basic
as reported
$
1.52
Diluted
as reported
$
1.51
Basic
pro forma
$
1.51
Diluted
pro forma
$
1.51
Debt
Related Costs
Debt
premiums, discounts, expenses and amounts received or incurred to settle hedges
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.
Earnings
Per Common Share (Puget Energy Only)
Basic
earnings per common share has been computed based on weighted-average common
shares outstanding of 117,673,000, 115,999,000 and 102,570,000 for 2007, 2006
and 2005, respectively. Diluted earnings per common share has been
computed based on weighted-average common shares outstanding of 118,344,000,
116,457,000 and 103,111,000 for 2007, 2006 and 2005, respectively,
which includes the dilutive effect of securities related to employee stock-based
compensation plans. In 2007, 1,300 shares related to stock options
were excluded from the diluted weighted-average common share calculation due to
their anti-dilutive effect. In 2006, 46,000 shares related to stock
options were excluded from the diluted weighted-average common share calculation
due to their antidilutive effect.
Accounts
Receivable Securitization Program
On
December 20, 2005, PSE entered into a five-year Receivable Sales Agreement with
PSE Funding, Inc. (PSE Funding), a wholly owned, bankruptcy-remote subsidiary of
PSE, formed for the purpose of purchasing customers’ accounts receivable, both
billed and unbilled. The results of PSE Funding are consolidated in
the financial statements of PSE. The accounts receivable are sold at
estimated fair value, based on the present value of discounted cash flows taking
into account anticipated credit losses, the speed of payments and the discount
rate commensurate with the uncertainty involved. The PSE Funding
agreement replaces the Rainier Receivables securitization facility that was
terminated on December 20, 2005. In addition, PSE Funding entered
into a Loan and Servicing Agreement with PSE and two banks. The Loan
and Servicing Agreement allows PSE Funding to use the receivables as collateral
to secure short-term loans, not exceeding the lesser of $200.0 million or the
borrowing base of eligible receivables which fluctuate with the seasonality of
energy sales to customers. The PSE Funding receivables securitization
facility expires in December 2010, and is terminable by PSE and PSE Funding upon
notice to the banks. PSE Funding had $152.0 million of loans secured
by accounts receivable pledged as collateral at December 31, 2007.
Consolidated
Statements of Cash Flows
PSE funds
cash dividends paid to the shareholders of Puget Energy. These funds
are reflected in the Consolidated Statement of Cash Flows of Puget Energy as if
Puget Energy received the cash from PSE and paid the dividends directly to the
shareholders.
Comprehensive
Income
Comprehensive
income includes net income, the minimum pension liability, unrealized gains and
losses on derivative instruments, reversals of unrealized gains and losses on
derivative instruments, settlements and amortization of cash flow hedge
contracts and deferrals of cash flow hedges related to the power cost
mechanism. The following table presents the Company’s accumulated
other comprehensive gain (loss) net of tax at December 31:
(Dollars
in Thousands)
2007
2006
Unrealized
gains (losses) on derivatives during the period
$
(3,000
)
$
9,584
Reversal
of unrealized (gains) losses on derivatives during the
period
6,483
(4,691
)
Adjustment
to PCA
--
--
Settlement
of cash flow hedge contract
13,443
13,447
Amortization
of cash flow hedge contracts
(21,652
)
(21,972
)
Minimum
pension liability adjustment
--
(4,413
)
Unrealized
gain and prior service cost on pension plans
On
September 15, 2006, FASB issued SFAS No. 157, “Fair Value Measurements” (SFAS
No. 157), which clarifies how companies should use fair value measurements in
accordance with GAAP for recognition and disclosure. SFAS No. 157
establishes a common definition of fair value and a framework for measuring fair
value under GAAP, along with expanding disclosures about fair value measurements
to eliminate differences in current practice that exist in measuring fair value
under the existing accounting standards. The definition of fair value in SFAS
No. 157 retains the notion of exchange price; however, it focuses on the
price that would be received to sell the asset or paid to transfer the liability
(i.e., an exit price), rather than the price that would be paid to acquire the
asset or received to assume the liability (i.e., an entry price). Under SFAS
No. 157, a fair value measure should reflect all of the assumptions that
market participants would use in pricing the asset or liability, including
assumptions about the risk inherent in a particular valuation technique, the
effect of a restriction on the sale or use of an asset, and the risk of
nonperformance. To increase consistency and comparability in fair value
measures, SFAS No. 157 establishes a three-level fair value hierarchy to
prioritize the inputs used in valuation techniques between observable inputs
that reflect quoted prices in active markets, inputs other than quoted prices
with observable market data, and unobservable data (e.g., a company’s own
data). SFAS No. 157 is effective for fiscal years beginning after
November 15, 2007, which will be the year beginning January 1, 2008, for the
Company. SFAS No. 157 standardizes the measurement of fair
value when it is required under GAAP, a framework for measuring fair value and
expands disclosure about such fair value measurements. On February 6,2008, the FASB decided to issue a final FASB Staff Position (FSP) that would
partially defer the effective date of SFAS No. 157 for one year for nonfinancial
assets and nonfinancial liabilities that are recognized or disclosed at fair
value, except for those that are recognized or disclosed at fair value on an
annual or more frequent basis. The Company adopted SFAS No. 157 on
January 1, 2008, prospectively, as required by the Statement, with certain
exceptions, including the following noted in paragraph 37 (a) of the statement,
“A financial instrument that was measured at fair value at initial recognition
under Statement 133 using the transaction price in accordance with the guidance
in footnote 3 of EITF Issue No. 02-3, “Issues Involved in Accounting for
Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy
Trading and Risk Management Activities,” prior to the initial adoption of this
Statement (EITF No. 02-3). At the date this Statement is initially
applied to the financial statements, a difference between the carrying amounts
and the fair values of those instruments shall be recognized as a
cumulative-effect adjustment to the opening balance of retained
earnings.
The
Company estimates that the impact of the adoption of SFAS No. 157 to its
statement of financial position and results of operations to be a cumulative
effect adjustment to retained earnings of $9.0 million before tax as a result of
recording a deferred loss on net derivative assets and
liabilities.
On
September 29, 2006, FASB issued SFAS No. 158, “Employer’s Accounting for Retired
Benefit Pension and Other Postretirement Plans.” See Note 14,
“Retirement Benefits” for discussion of this statement.
In July
2006, FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income
Taxes, an Interpretation of SFAS No. 109” (FIN 48), which clarifies the
accounting for uncertainty in income taxes recognized in the financial
statements in accordance with SFAS No. 109, “Accounting for Income
Taxes.” FIN 48 requires the use of a two-step approach for
recognizing and measuring tax positions taken or expected to be taken in a tax
return. First, the tax position should only be recognized when it is
more likely than not, based on technical merits, that the position will be
sustained upon examination by the taxing authority. Second, a tax
position, that meets the recognition threshold, should be measured at the
largest amount that has a greater than 50.0% likelihood of being
sustained.
FIN 48
was effective for the Company as of January 1, 2007. As of the date
of adoption, the Company had no material unrecognized tax
benefits. As of December 31, 2007, the Company had no material
unrecognized tax benefits. As a result, no interest or penalties were
accrued for unrecognized tax benefits during the year.
In
December 2004, FASB issued SFAS No. 123R, which revises SFAS No. 123. 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 requires 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. Effective January 1, 2006, the Company adopted the fair value
recognition provisions of SFAS No. 123R, using the modified-prospective
transition method.
In March
2005, FASB issued Interpretation No. 47 (FIN 47), which finalized a proposed
interpretation of SFAS No. 143, “Accounting for Conditional Asset Retirement
Obligations” (SFAS No. 143). The 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. FIN 47 was effective for the year ended December 15, 2005
and was required to be accounted for as a cumulative effect of an accounting
change. The Company adopted FIN 47 in the fourth quarter 2005, which
resulted in the recognition of a cumulative effect for the asset retirement
obligations amounting to $0.1 million after-tax.
On May 7,2006, Puget Energy sold InfrastruX to an affiliate of Tenaska Power Fund, L.P.
(Tenaska). After repayment of debt, adjustments for working capital,
transaction costs and distributions to minority interests, Puget Energy received
after-tax cash proceeds of approximately $95.9 million for its 90.9% interest in
InfrastruX in the second quarter 2006. The sale resulted in an
after-tax gain of $29.8 million for the twelve months ended December 31,2006. Puget Energy accounted for InfrastruX as a discontinued
operation under SFAS No. 144 in 2005 and 2006.
As part
of the transaction, Puget Energy made certain representations and warranties
concerning InfrastruX. Puget Energy obtained a representation and
warranty insurance policy and deposited $3.7 million into an escrow account to
serve as retention under the policy. At December 31, 2007, restricted
cash in the escrow account was $4.0 million, which is included in the
accompanying balance sheets, representing management’s estimate of the aggregate
fair value of Puget Energy’s maximum exposure related to those representations
and warranties. Should Tenaska make any such claims against Puget
Energy, payment for the claims would be made from the escrow account, and total
payments are limited to $3.7 million plus any interest earned while the funds
are held in the escrow account. The obligation expires May 7,2008.
Puget
Energy also agreed to indemnify Tenaska for certain potential future losses
related to one of InfrastruX’s subsidiary companies. Under the
indemnity agreement, Puget Energy is also liable for refunding a portion of the
purchase price paid by Tenaska for InfrastruX if the subsidiary does not achieve
certain operating results during the measurement year. The maximum
obligation of Puget Energy for defense costs and a refund of a portion of the
purchase price is capped at $15.0 million. Tenaska has notified Puget
Energy that 2008 will be the measurement year for purposes of calculating the
potential purchase price refund obligation. At December 31, 2007, a
liability in the amount of $3.2 million is included in the accompanying balance
sheets; that amount represents Puget Energy’s estimate of the fair value of the
amount potentially payable using a probability-weighted approach to a range of
future cash flows. Puget Energy has made payments totaling $1.8
million related to the guarantee. The obligation expires May 7,2011.
Puget
Energy’s accounting policy for its representations and warranties loss reserve
and the indemnity agreement is to reduce the loss reserve only when the
guarantee expires or is settled. Any increase to the loss reserves
subsequent to the initial recognition would be determined if it is probable that
a future event will occur confirming the additional loss and the amount of the
additional loss can be estimated.
Twelve
Months Ended
December
31,
(Dollars
in Thousands)
2007
2006
1
2005
Revenues
$
--
$
138,573
$
393,294
Goodwill
impairment
--
--
--
Operating
expenses (including interest expense)
--
(128,605
)
(356,934
)
Pre-tax
income
--
9,968
36,360
Income
tax expense
--
(3,544
)
(12,204
)
Puget
Energy carrying value adjustment of InfrastruX
--
7,269
(7,269
)
Puget
Energy cost of sale related to InfrastruX, net of tax of $(114), $(505)
and $(2,799)
(212
)
(937
)
(5,195
)
Puget
Energy deferred tax basis adjustment of InfrastruX
--
9,966
--
Gain
on sale, net of tax of $0, $16,027 and $0
--
29,765
--
Minority
interest in income of discontinued operations
In
accordance with SFAS No. 144, InfrastruX discontinued depreciation and
amortization of its assets effective February 8, 2005. This
discontinuation of depreciation and amortization resulted in $16.8 million
($10.8 million after-tax) and $6.7 million ($4.3 million after-tax) lower
depreciation and amortization expense than otherwise would have been recorded as
continuing operations for 2006 and 2005, respectively. Puget Energy
recorded $0.2 million of amortization expense related to the intangible assets
of InfrastruX for 2005.
Electric,
gas and common utility plant classified by prescribed accounts at original
cost:
Distribution
plant
10-50
$
5,107,272
$
4,887,304
Production
plant
35-125
2,021,239
1,694,569
Transmission
plant
45-65
334,958
331,210
General
plant
5-35
372,369
367,806
Whitehorn
capital lease
3
22,840
23,004
Construction
work in progress
NA
267,594
206,459
Intangible
plant (including capitalized software)
3-50
322,005
297,939
Plant
acquisition adjustment
NA
77,871
77,871
Underground
storage
25-60
24,492
24,389
Liquefied
natural gas storage
25-45
14,310
14,217
Plant
held for future use
NA
8,623
8,315
Other
NA
6,299
5,595
Plant
not classified
NA
153,943
--
Less:
accumulated provision for depreciation
(3,091,176
)
(2,757,632
)
Net
utility plant
$
5,642,639
$
5,181,046
Jointly
owned generating plant service costs are included in utility plant service
cost. 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, 2007. These amounts are also
included in the Utility Plant table above.
Company’s Share
Jointly
Owned Generating Plants
(Dollars
in Thousands)
Energy
Source
(Fuel)
Company’s
Ownership
Share
Plant
in
Service
at
Cost
Accumulated
Depreciation
Colstrip
Units 1 & 2
Coal
50
%
$
230,216
$
(147,475
)
Colstrip
Units 3 & 4
Coal
25
%
480,849
(277,909
)
Colstrip
Units 1 – 4 Common Facilities
Coal
*
252
(162
)
Frederickson
1
Gas
49.85
%
73,772
(8,712
)
_______________
*
The
Company’s ownership is 50% for Colstrip Units 1 & 2 and 25% for
Colstrip Units 3 & 4.
Financing
for a participant’s ownership share in the projects is provided by such
participant. The Company’s share of related operating and maintenance
expenses is included in corresponding accounts in the Consolidated Statements of
Income.
Non-Utility
Plant
(Dollars
In Thousands)
At
December 31
2007
2006
Non-utility
plant
$
3,040
$
2,948
Less:
accumulated provision for depreciation
(445
)
(446
)
Net
non-utility plant
$
2,595
$
2,502
Non-utility
plant is composed primarily of land and land rights that are not included in
rate-based property. Non-utility plant and accumulated depreciation
are included in “other” under “Other Property and Investments” in the Puget
Energy and PSE balance sheets.
The
Company identified various asset retirement obligations under SFAS No. 143 upon
initial adoption, and in 2005 identified additional asset retirement obligations
to replace bare steel natural gas pipe and for the future removal of wind
turbine generators. In March 2005, FASB issued FIN 47, “Accounting
for Conditional Asset Retirement Obligations” (ARO), which provides guidance on
when an asset retirement obligation that is conditional on a future event should
be recognized. The Company adopted FIN 47 in the fourth quarter 2005
which resulted in the recognition of additional ARO. FIN 47 also
requires that if an entity has any ARO for which no amount has been recognized,
the existence of the ARO must be disclosed with the reasons why the liability
has not been recognized.
Prior to
the adoption of FIN 47, the Company recognized an obligation to:
·
dismantle two leased electric
generation turbine units and deliver the turbines to the nearest railhead
at the termination of the lease in 2009;
·
remove certain structures as a
result of re-negotiations with the Department of Natural Resources of a
now expired lease;
·
restore ash holding ponds at a
jointly owned coal-fired electric generating facility in
Montana;
·
replace all unprotected bare
steel natural gas pipe in its service territory by 2015 as a result of a
January 31, 2005 Washington Commission order; and
·
remove wind turbine generators
and related equipment, improvements and fixtures at the termination of the
related leases.
The adoption of FIN 47 in the fourth quarter 2005 resulted in
recognition of additional AROs to:
·
dispose of treated wood
poles;
·
dispose of oil containing PCBs
and the related equipment that held the oil;
·
remove asbestos in facilities
that have been identified for remodeling or demolition; and
·
disconnect abandoned pipelines,
purge the pipelines of natural gas and cut and cap their supplies of
natural gas.
In 2006,
the Company recognized an ARO for the decommissioning costs of the Frederickson
facility at the end of its service life and costs related to wood poles, natural
gas mains and contaminated oil in equipment placed in service in
2006. In 2007, the Company recognized an ARO related to a settlement
agreement requiring the company to replace steel wrapped services categorized as
being identified for replacement or priority replacements.
The
following table describes all changes to the Company’s asset retirement
obligation liability:
(Dollars
in Thousands)
At
December 31
2007
2006
Asset
retirement obligation at beginning of year
$
28,356
$
28,274
Liability
recognized in transition
--
--
New
asset retirement obligation liability recognized in the
period
1,733
487
Liability
settled in the period
(1,597
)
(1,351
)
Accretion
expense
1,116
946
Asset
retirement obligation at December 31
$
29,608
$
28,356
The
Company has identified the following obligations which were not recognized at
December 31, 2007:
·
a
legal obligation under Federal Dangerous Waste Regulations to dispose of
asbestos-containing material in facilities that are not scheduled for
remodeling, demolition or sale. The disposal cost related to
these facilities could not be measured since the retirement date is
indeterminable; therefore, the liability cannot be reasonably estimated
currently;
·
an
obligation under Washington state law to decommission the wells at the
Jackson Prairie natural gas storage facility upon termination
of the project. Since the project is expected to continue as
long as the Northwest pipeline continues to operate, the liability cannot
be reasonably estimated currently;
·
an
obligation to pay its share of decommissioning costs at the end of the
functional life of the major transmission lines. The major
transmission lines are expected to be used indefinitely, therefore the
liability cannot be reasonably estimated currently;
·
a
legal obligation under the state of Washington environmental laws to
remove and properly dispose of certain under and above ground storage fuel
tanks. The disposal costs related to under and above ground
storage tanks could not be measured since the retirement date is
indeterminable; therefore the liability cannot be reasonably estimated
currently;
·
a
potential legal obligation, arising (if at all) upon the expiration of an
existing FERC hydropower license, were FERC to then order project
decommissioning. Regardless, given the value of ongoing
generation, flood control, and other benefits provided by these projects,
PSE believes that the potential for decommissioning is both remote and
cannot be reasonably estimated; and
·
an
obligation related to a special use permit for the Crystal Mountain
generator site to remove certain structures, improvements and restore the
site upon abandonment, termination, revocation or cancellation of the
permit. The Company intends to renew its permit upon expiration
and therefore, a liability cannot be reasonably
estimated.
The pro
forma asset retirement obligation liability balances as if SFAS No. 143, as
interpreted by FIN 47, had been adopted on December 31, 2004 (rather than
December 31, 2005) are as follows:
(Dollars
in Thousands)
Pro
forma amounts of liability for asset retirement obligation at December 31,2004
$
25,297
The pro
forma income statement effect as if SFAS No. 143, as interpreted by FIN 47, had
been adopted on December 31, 2004 (rather than December 31, 2005) is as
follows:
(Dollars
in Thousands, except per share amounts)
2005
Net
income, as reported
$
155,726
Add:
SFAS No. 143 transition adjustment, net of tax
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 $65.0, subject to adjustments. The Rights expire on December 21,2010, unless redeemed or exchanged earlier by Puget Energy.
Immediately
prior to the execution of the merger agreement announced on October 26, 2007,
the Company and the Rights agent (Wells Fargo Bank, N.A.) entered into an
amendment to the Rights agreement. The amendment provides that
neither the execution of the merger agreement nor the execution of the stock
purchase agreement (relating to the sale of 12.5 million shares of Puget
Energy’s common stock to certain members of the Consortium that closed on
December 3, 2007), nor the consummation of the transactions contemplated by
these agreements will trigger the provisions of the Rights
agreement. The amendment also provides that the Rights shall expire
at the effective time (as defined in the merger agreement), if the Rights have
not otherwise terminated.
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 Restated 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 $481.5 million at December 31, 2007. For the years
2007, 2006 and 2005, the aggregate dividends per share declared by Puget Energy
were $1.00, $1.00 and $1.00, respectively.
PSE paid
cash dividends on its common stock to Puget Energy of $108.4 million, $109.8
million and $89.2 million for 2007, 2006 and 2005, respectively.
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. At December 31, 2007, there were 25,689 shares of the
4.70% Series and 9,417 shares of the 4.84% Series 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 Securities
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 8.4%,
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. On
June 30, 2006, PSE called all of PSE’s 8.4% Capital Trust Preferred Securities
(classified as junior subordinated debentures of the corporation payable to a
subsidiary trust holding mandatorily redeemable preferred securities on the
balance sheets). The Capital Trust II Securities were redeemed at par
and dividends relating to the preferred securities were paid and included in
interest expense. The Capital Trust Preferred Securities were
redeemed using the proceeds of senior notes issued at an interest rate of
6.724%.
First
Mortgage Bonds, Senior Notes and Junior Subordinated Notes
(Dollars
in Thousands)
At
December 31
Series
Due
2007
2006
Series
Due
2007
2006
7.02
%
2007
$
--
$
20,000
5.197
%
2015
$
150,000
$
150,000
7.04
%
2007
--
5,000
7.35
%
2015
10,000
10,000
7.75
%
2007
--
100,000
7.36
%
2015
2,000
2,000
3.363
%
2008
150,000
150,000
6.74
%
2018
200,000
200,000
6.51
%
2008
1,000
1,000
9.57
%
2020
25,000
25,000
6.53
%
2008
3,500
3,500
7.15
%
2025
15,000
15,000
7.61
%
2008
25,000
25,000
7.20
%
2025
2,000
2,000
6.46
%
2009
150,000
150,000
7.02
%
2027
300,000
300,000
6.61
%
2009
3,000
3,000
7.00
%
2029
100,000
100,000
6.62
%
2009
5,000
5,000
5.483
%
2035
250,000
250,000
7.12
%
2010
7,000
7,000
6.724
%
2036
250,000
250,000
7.96
%
2010
225,000
225,000
6.274
%
2037
300,000
300,000
7.69
%
2011
260,000
260,000
6.974
%
2067
250,000
--
6.83
%
2013
3,000
3,000
6.90
%
2013
10,000
10,000
Total
$
2,696,500
$
2,571,500
On March16, 2006, Puget Energy and PSE filed a shelf registration statement with the
Securities and Exchange Commission for the offering of common stock, senior
notes, preferred stock, and trust preferred securities of Puget Sound Energy
Capital Trust III. The registration statement is valid for three years and does
not specify the amount of securities that the Company may offer.
On June30, 2006, PSE completed the issuance of $250.0 million of senior secured notes
at a rate of 6.724%, which are due on June 15, 2036. The net proceeds
from the issuance of the senior notes of approximately $247.8 million were used
to redeem $200.0 million of 8.40% Capital Trust Preferred Securities, which were
redeemed at par on June 30, 2006, and to repay a portion of PSE’s short-term
debt.
On
September 18, 2006, PSE completed the issuance of $300.0 million of senior
secured notes at a rate of 6.274%, which are due on March 15,2037. The net proceeds from the issuance of the senior notes of
approximately $297.4 million were used to repay PSE’s outstanding short-term
debt which was incurred primarily to fund construction programs.
On June1, 2007, PSE redeemed the remaining 8.231% Capital Trust Preferred Securities
(classified on the balance sheet as Junior Subordinated Debentures of the
Corporation Payable to a Subsidiary Trust Holding Mandatorily Redeemable
Preferred Securities and referred to herein as Securities). The
purpose of the redemption was to help reduce interest costs by retiring higher
cost debt. The remaining $37.8 million of the Securities outstanding
were redeemed on June 1, 2007 at a 4.12% premium, or $39.3 million, plus accrued
interest on the redemption date.
On June4, 2007, PSE issued $250.0 million of Junior Subordinated Notes (Notes) due June
2067. The Notes bear a fixed rate of interest for the first ten and a
half years with interest payable semiannually in May and November of each year,
after which the notes will bear a variable rate of interest (3-month LIBOR plus
2.35%). Proceeds were used to fund the redemption of the remaining
$37.8 million 8.231% Securities and to repay short-term debt. The
Notes are structured to be treated as debt by the Internal Revenue Service
(IRS), yet they are considered to be similar to equity by the credit rating
agencies. In addition, the Notes contain a call option feature and
are callable in whole or in part by PSE on or after June 1,2017. They are presented on the balance sheet as a separate line item
in the redeemable securities and long-term debt.
Substantially
all utility properties owned by the Company are subject to the lien of the
Company’s electric and natural 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, 2007, the earnings available
for interest exceeded the required amount.
Pollution
Control Bonds
The
Company has two series of Pollution Control Bonds outstanding. 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.
(Dollars
in Thousands)
At
December 31
Series
Due
2007
2006
2003A
Series -
5.00%
2031
$
138,460
$
138,460
2003B
Series -
5.10%
2031
23,400
23,400
Total
$
161,860
$
161,860
Long-Term
Debt Maturities
The
principal amounts of long-term debt maturities for the next five years and
thereafter are as follows:
On June1, 2006, PSE entered into a revolving credit facility with its parent, Puget
Energy, in the form of a Demand Promissory Note (Note). Through the
Note, PSE may borrow up to $30.0 million from Puget Energy, subject to approval
by Puget Energy. Under the terms of the Note, PSE pays interest on
the outstanding borrowings based on the lowest of the weighted-average interest
rate of (a) PSE’s outstanding commercial paper interest rate; (b) PSE’s senior
unsecured revolving credit facility; or (c) the interest rate available under
the receivable securitization facility of PSE Funding, Inc., a PSE subsidiary,
which is the London Interbank Offered Rate (LIBOR) plus a marginal
rate. At December 31, 2007 and 2006, the outstanding balance of the
Note was $15.8 million and $24.3 million, respectively, and the interest rate
was 5.31% and 5.54%, respectively. The outstanding balance and the
related interest under the Note are eliminated by Puget Energy upon
consolidation of PSE’s financial statements. The $30.0 million credit
facility with Puget Energy is unaffected by the pending merger.
During
2007, the Company purchased certain insurance policies from AEGIS and had two
insurance claim receivables totaling $15.2 million due from AEGIS as of December31, 2007. One nonemployee director of Puget Energy and PSE also
serves on the board of AEGIS and a PSE management employee serves on one of
AEGIS’ risk management committees.
At
December 31, 2007, PSE had borrowing arrangements that included a five-year
$500.0 million unsecured credit agreement with a group of banks, a separate
five-year $350.0 million unsecured credit agreement with the same group of
banks, a five-year $200.0 million receivables securitization program and a $30.0
million demand promissory note with Puget Energy. These arrangements
provide PSE with the ability to borrow at different interest rate options and
include variable fee levels. Puget Energy has no bank credit
facilities of its own.
The bank
credit agreements allow the Company to make floating rate advances at either
LIBOR plus a spread or the banks’ prime rate and contain “credit sensitive”
pricing with various spreads associated with different credit rating
levels. Both bank credit agreements also allow for issuing standby
letters of credit up to the entire amount of the credit agreement and can be
used for commercial paper back-up. In March 2007, PSE amended the
$500.0 million credit agreement to extend the expiration date from April 2011 to
April 2012. This agreement is primarily used to backup PSE commercial
paper sales. There were no loans outstanding under the $500.0 million
credit agreement at December 31, 2007.
The
$350.0 million credit agreement was entered into in March 2007 and expires in
April 2012. The agreement is intended to provide credit support for
PSE’s energy hedging activities. Costs of this hedging credit
facility are recovered through the PCA and PGA mechanisms pursuant to an order
of the Washington Commission. There were no loans outstanding under
the $350.0 million credit agreement at December 31, 2007.
On
December 20, 2005, PSE entered into a five-year Receivable Sales Agreement with
PSE Funding, Inc. (PSE Funding), a wholly owned subsidiary of
PSE. Pursuant to the Receivables Sales Agreement, PSE sells all of
its utility customer accounts receivable and unbilled utility revenues to PSE
Funding. In addition, PSE Funding entered into a Loan and Servicing
Agreement with PSE and two banks. The Loan and Servicing Agreement
allows PSE Funding to use the receivables as collateral to secure short-term
loans, not exceeding the lesser of $200.0 million or the borrowing base of
eligible receivables which fluctuate with the seasonality of energy sales to
customers.
The PSE
Funding receivables securitization facility expires in December 2010, and is
terminable by PSE and PSE Funding upon notice to the banks. At
December 31, 2007, PSE Funding had $152.0 million of loans secured by accounts
receivable pledged as collateral. At December 31, 2006, PSE Funding
had $110.0 million of loans secured by accounts receivable pledged as
collateral.
The
following table presents the liquidity facilities and other financing
arrangements at December 31, 2007 and 2006.
(Dollars
in Thousands)
At
December 31
2007
2006
Committed
financing arrangements:
PSE
line of credit 1
$
500,000
$
500,000
PSE
hedging line of credit 2
350,000
--
PSE
receivables securitization program 3
200,000
200,000
Uncommitted
financing agreements:
Puget
Energy Demand Promissory Note 4
30,000
30,000
_______________
1
Provides
liquidity support for PSE’s outstanding commercial paper and letters of
credit in the amount of $115.9 million in 2007 and $218.5 million in 2006,
effectively reducing the available borrowing capacity under this credit
line to $384.1 million and $281.5 million, respectively. There
was $108.5 million of commercial paper outstanding at December 31, 2007,
and $218.0 million outstanding at
December 31, 2006.
2
Provides
credit support for PSE’s energy hedging activities. At December31, 2007, there were no loans or outstanding letters of credit under this
agreement.
3
Provides
borrowings secured by accounts receivable and unbilled
revenues. At December 31, 2007, PSE Funding had borrowed $152.0
million, leaving $48.0 million available to borrow under the
program. At December 31, 2006, PSE Funding had $110.0 million
of loans secured by accounts receivable pledged as collateral under the
accounts receivable securitization program.
4
A
demand promissory note with parent company, Puget Energy to borrow up to
$30.0 million subject to approval by Puget Energy. At December31, 2007 and 2006, the outstanding balance on the note was $15.8 million
and $24.3 million, respectively. While reflected on PSE’s
balance sheet, the outstanding balance and related interest are eliminated
on Puget Energy’s balance sheet upon
consolidation.
The following table presents the
carrying amounts and estimated fair values of the Company’s financial
instruments at December 31, 2007 and 2006.
2007
2006
(Dollars
in millions)
Carrying
Amount
Fair
Value
Carrying
Amount
Fair
Value
Financial
assets:
Cash
$
40.8
$
40.8
$
28.1
$
28.1
Restricted
cash
4.8
4.8
0.8
0.8
Equity
securities
1.5
1.5
2.0
2.0
Notes
receivable and other
70.2
70.2
71.1
71.1
Energy
derivatives
29.0
29.0
23.8
23.8
Long-term
restricted cash
--
--
3.8
3.8
Financial
liabilities:
Short-term
debt
$
260.5
$
260.5
$
328.0
$
328.0
Short-term
debt owed by PSE to Puget Energy1
15.8
15.8
24.3
24.3
Preferred
stock subject to mandatory redemption
1.9
1.2
1.9
1.3
Junior
subordinated notes
250.0
215.1
--
--
Junior
subordinated debentures of the corporation payable to a subsidiary trust
holding mandatorily redeemable preferred securities
--
--
37.8
43.2
Long-term
debt -
fixed-rate2
2,858.4
2,623.2
2,733.4
2,823.3
Energy
derivatives
27.0
27.0
71.0
71.0
_______________
1
Short-term
debt owed by PSE to Puget Energy is eliminated upon consolidation of Puget
Energy.
2
PSE’s
carrying value and fair value of fixed-rate long-term debt was the same as
Puget Energy’s debt in 2007 and
2006.
The
carrying amount of equity securities is considered to be a reasonable estimate
of fair value due to limited market pricing and based on the market value as
reported by the fund manager. 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 and are recorded at fair
value. The Company has a policy that financial derivatives are to be
used only to mitigate business risk.
The Company leases buildings and assets
under operating leases. In October 2006, the Company entered into an
agreement to purchase certain assets at the Whitehorn generating site, which
historically had been leased under an operating lease. The purchase
agreement resulted in the classification of the Whitehorn lease as a capital
lease. In accordance with SFAS No. 71, the amortization of the leased
asset has been modified so that total interest and amortization is equal to the
rental expense allowed for rate-making purposes. Interest accretion
for 2007 was $0.2 million and capital lease amortization was $0.6 million for
2007. Certain leases contain purchase options and renewal and
escalation provisions. Rent expense net of sublease receipts
were:
(Dollars
in Thousands)
At
December 31
2007
$
27,012
2006
24,184
2005
17,145
Payments received for the subleases of
properties were approximately $0.1 million, $0.1 million and $0.1 million for
2007, 2006 and 2005, respectively.
Future minimum lease payments for
non-cancelable leases net of sublease receipts are:
(Dollars
in Thousands)
At
December 31
Operating
Capital
2008
$
14,921
$
1,605
2009
14,569
23,453
2010
12,834
--
2011
13,306
--
2012
12,357
--
Thereafter
77,802
--
Total
minimum lease payments
$
145,789
$
25,058
PSE leases a portion of its owned
natural 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:
The
details of income taxes on continuing operations are as follows:
Puget
Energy
(Dollars
In Thousands)
2007
2006
2005
Charged
to operating expense:
Current:
Federal
$
3,238
$
57,526
$
142,004
State
(189
)
979
1,936
Deferred
- federal
69,966
34,485
(57,347
)
Deferred
investment tax credits
(433
)
(503
)
(553
)
Total
income taxes before cumulative effect of accounting change
72,582
92,487
86,040
Cumulative
effect of accounting change
--
48
(38
)
Total
income taxes from continuing operations
$
72,582
$
92,535
$
86,002
Puget
Sound Energy
(Dollars
In Thousands)
2007
2006
2005
Charged
to operating expense:
Current:
Federal
$
5,555
$
63,475
$
142,772
State
(189
)
979
2,705
Deferred
- federal
69,248
34,738
(57,864
)
Deferred
investment tax credits
(433
)
(503
)
(553
)
Total
income taxes before cumulative effect of accounting change
74,181
98,689
87,060
Cumulative
effect of accounting change
--
48
(38
)
Total
income taxes from continuing operations
$
74,181
$
98,737
$
87,022
The
following reconciliation compares pre-tax book income at the federal statutory
rate of 35% to the actual income tax expense in the Consolidated Statements of
Income:
Puget
Energy
(Dollars
In Thousands)
2007
2006
2005
Income
taxes at the statutory rate
$
89,966
$
90,947
$
81,275
Increase
(decrease):
Utility
plant differences
6,032
9,307
9,534
AFUDC
excluded from taxable income
(5,055
)
(7,987
)
(4,536
)
Capitalized
interest
3,649
5,806
3,026
Production
tax credit
(20,154
)
(7,019
)
(564
)
Other
- net
(1,856
)
1,481
(2,733
)
Total
income taxes
$
72,582
$
92,535
$
86,002
Effective
tax rate
28.2
%
35.6
%
37.0
%
Puget
Sound Energy
(Dollars
In Thousands)
2007
2006
2005
Income
taxes at the statutory rate
$
92,858
$
96,417
$
81,827
Increase
(decrease):
Utility
plant differences
6,032
9,307
9,534
AFUDC
excluded from taxable income
(5,055
)
(7,987
)
(4,536
)
Capitalized
interest
3,649
5,806
3,026
Production
tax credit
(20,154
)
(7,019
)
(564
)
Other
- net
(3,149
)
2,213
(2,265
)
Total
income taxes
$
74,181
$
98,737
$
87,022
Effective
tax rate
28.0
%
35.8
%
37.2
%
The Company’s deferred tax liability at December 31, 2007 and 2006 is composed
of amounts related to the following types of temporary differences:
Puget
Energy
(Dollars
In Thousands)
2007
2006
Utility
plant and equipment
$
717,661
$
643,885
Regulatory
asset for income taxes
104,928
115,305
Storm
damage
44,571
35,408
Other
deferred tax liabilities
62,395
38,256
Subtotal
deferred tax liabilities
929,555
832,854
Contributions
in aid of construction
(75,492
)
(58,038
)
Other
deferred tax assets
(39,913
)
(30,896
)
Subtotal
deferred tax assets
(115,405
)
(88,934
)
Total
$
814,150
$
743,920
Puget
Sound Energy
(Dollars
In Thousands)
2007
2006
Utility
plant and equipment
$
717,661
$
643,885
Regulatory
asset for income taxes
104,928
115,305
Storm
damage
44,571
35,408
Other
deferred tax liabilities
65,616
42,195
Subtotal
deferred tax liabilities
932,776
836,793
Contributions
in aid of construction
(75,492
)
(58,038
)
Other
deferred tax assets
(39,913
)
(30,897
)
Subtotal
deferred tax assets
(115,405
)
(88,935
)
Total
$
817,371
$
747,858
The above amounts have been classified
in the Consolidated Balance Sheets as follows:
Puget
Energy
(Dollars
In Thousands)
2007
2006
Current
deferred taxes
$
(4,011
)
$
(1,175
)
Non-current
deferred taxes
818,161
745,095
Total
$
814,150
$
743,920
Puget
Sound Energy
(Dollars
In Thousands)
2007
2006
Current
deferred taxes
$
(4,011
)
$
(1,175
)
Non-current
deferred taxes
821,382
749,033
Total
$
817,371
$
747,858
The Company calculates its deferred tax
assets and liabilities under SFAS No. 109. SFAS No. 109 requires
recording deferred tax balances, at the currently enacted tax rate, on assets
and liabilities that are reported differently for income tax purposes than for
financial reporting purposes. For ratemaking purposes, deferred taxes
are not provided for certain temporary differences. PSE has
established a regulatory asset for income taxes recoverable through future rates
related to those temporary differences for which no deferred taxes have been
provided, based on prior and expected future ratemaking treatment.
IRS
Audit
As a
matter of course, the Company’s tax returns are routinely audited by federal,
state and city tax authorities. In May 2006, the IRS completed its
examination of the company’s 2001, 2002 and 2003 federal income tax
returns. The Company formally appealed the IRS audit adjustment
relating to the Company’s accounting method with respect to capitalized internal
labor and overheads. In its 2001 tax return, PSE claimed a deduction
when it changed its tax accounting method with respect to capitalized internal
labor and overheads. Under the new method, the Company could
immediately deduct certain costs that it had previously
capitalized. In the audit, the IRS disallowed the
deduction.
Through
September 30, 2005, the Company claimed $66.3 million in accumulated tax
benefits. PSE accounted for the accumulated tax benefits as temporary
differences in determining its deferred income tax
balances. Consequently, the repayment of the tax benefits did not
impact earnings but did have a cash flow impact of $33.2 million in the fourth
quarter 2005 and $33.1 million in 2006. As of December 31, 2006, the
full tax benefit had been repaid.
During
2007, the IRS national office established settlement guidelines which the
appeals office will use in reaching settlements with taxpayers. The
effect of the settlement guidelines shift some of the benefits claimed in 2001
through 2004 into 2005 and 2006. As a result, in 2007 the Company has
accrued interest in the amount of $5.5 million.
On
October 19, 2005, PSE filed an accounting petition with the Washington
Commission to defer the capital costs associated with repayment of the deferred
tax. The Washington Commission had reduced PSE’s ratebase by $72.0
million in its order of February 18, 2005. The accounting petition
was approved by the Washington Commission on October 26, 2005, for deferral of
additional capital costs beginning November 1, 2005 using PSE’s allowed net of
tax rate of return. The Washington Commission granted cost recovery
of these deferred carrying costs over two years, beginning January 13,2007. In addition, it is management’s expectation that the Company
could request rate recovery of the regulatory asset for the interest
accrued.
In its
2003 tax return, the Company claimed a deduction for a portion of the California
Independent System Operator (CAISO) receivable. Upon examination, the
IRS claimed that the deduction was not valid for the 2003 tax
year. The Company formally appealed. In appeals, the
Company and the IRS agreed to move the deduction from 2003 to
2005. In the fourth quarter 2007, the Company recorded interest
expense in the amount of $2.2 million to reflect the transfer of the deduction
from 2003 to 2005.
Accounting
for Uncertainty in Income Taxes
In July
2006, the Financial Accounting Standards Board (FASB) issued Interpretation No.
48, “Accounting for Uncertainty in Income Taxes, an Interpretation of FASB
Statement No. 109” (FIN 48), which clarifies the accounting for uncertainty in
income taxes recognized in the financial statements in accordance with FASB
Statement No. 109, “Accounting for Income Taxes.” FIN 48 requires the
use of a two-step approach for recognizing and measuring tax positions taken or
expected to be taken in a tax return. First, a tax position should
only be recognized when it is more likely than not, based on technical merits,
that the position will be sustained upon examination by the taxing
authority. Second, a tax position that meets the recognition
threshold should be measured at the largest amount that has a greater than 50%
likelihood of being sustained.
FIN 48
was effective for the Company as of January 1, 2007. As of the date
of adoption, the Company had no material unrecognized tax
benefits. As of December 31, 2007, the Company had no material
unrecognized tax benefits. As a result, no interest or penalties were
accrued for unrecognized tax benefits during the year.
For
federal income tax purposes, the Company has open tax years from 2001 through
2007. The Company continues its policy of classifying interest as
interest expense and penalties as other expense in the financial
statements.
On September 29, 2006, FASB issued SFAS
No. 158, “Employers’ Accounting for Defined Benefit Pension and Other
Postretirement Plans” (SFAS No. 158). SFAS No. 158 is effective for
fiscal years ending after December 15, 2006, which is the year ended December31, 2006 for the Company. SFAS No. 158 was adopted prospectively as
required by the statement. SFAS No. 158 requires the Company to
report the overfunded or underfunded status of defined benefit postretirement
plans in the Company’s consolidated balance sheet. An overfunded
status would result in the recognition of an asset and an underfunded status
would result in the recognition of a liability. This amount is to be
measured as the difference between the fair value of plan assets and the
projected benefit obligation. The following table illustrates the
effect of applying SFAS No. 158 in 2006, the year of initial adoption by the
Company.
Before
Application
of
Statement 158
Adjustments
After
Application
of
Statement 158
(Dollars
in Thousands)
Pension
Plan
Other
Benefits
Pension Plan
Other
Benefits
Pension
Plan
Other
Benefits
Transition
Adjustments for Statement of Financial Position:
Prepaid
benefit cost
$
122,274
$
--
$
(122,274
)
$
--
$
--
$
--
Accrued
benefit (liability)
(33,056
)
(12,309
)
33,056
12,309
--
--
Intangible
asset
4,027
--
(4,027
)
--
--
--
Accumulated
other comprehensive income, (pre-tax)
6,789
--
29,647
(950
)
36,436
(950
)
Noncurrent
asset
--
--
101,708
--
101,708
--
Current
liability
--
--
(4,533
)
(50
)
(4,533
)
(50
)
Noncurrent
liability
--
--
(33,577
)
(11,309
)
(33,577
)
(11,309
)
Total
$
100,034
$
(12,309
)
$
--
$
--
$
100,034
$
(12,309
)
The Company has a defined benefit
pension plan covering substantially all PSE employees, with a cash balance
feature for all but IBEW employees. Benefits are a function of age,
salary and service. Puget Energy also maintains a non-qualified
supplemental retirement plan for officers and certain director-level
employees.
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)
2007
2006
2007
2006
Change
in benefit obligation:
Benefit
obligation at beginning of year
$
469,010
$
454,519
$
27,207
$
26,251
Service
cost
13,311
12,554
269
361
Interest
cost
26,513
24,668
1,249
1,522
Mergers,
sales and closures
--
--
(2,648
)
--
Amendment1
--
--
(306
)
--
Actuarial
loss (gain)
(16,621
)
4,774
(3,723
)
1,261
Benefits
paid
(28,849
)
(27,505
)
(3,184
)
(2,189
)
Benefit
obligation at end of year
$
463,364
$
469,010
$
18,864
$
27,206
_______________
1
The
Company has an amendment related to changes in eligibility
criteria. On June 20, 2007, the International Brotherhood of
Electrical Workers (IBEW) ratified a collective bargaining agreement with
PSE. The collective bargaining agreement included changes to
the Company’s subsidy for retiree medical insurance. Effective
June 20, 2007, IBEW-represented employees hired after June 20, 2002 will
not receive a retiree medical subsidy at
retirement.
Pension
Benefits
Other
Benefits
(Dollars
in Thousands)
2007
2006
2007
2006
Change
in plan assets:
Fair
value of plan assets at beginning of year
$
532,608
$
481,444
$
15,847
$
15,668
Actual
return on plan assets
52,444
75,278
499
1,699
Employer
contribution
2,326
3,391
1,538
669
Benefits
paid
(28,849
)
(27,505
)
(3,184
)
(2,189
)
Fair
value of plan assets at end of year
$
558,529
$
532,608
$
14,700
$
15,847
Funded
status at end of year
$
95,165
$
63,598
$
(4,164
)
$
(11,359
)
Pension
Benefits
Other
Benefits
(Dollars
in Thousands)
2007
2006
2007
2006
Amounts
recognized in Statement of Financial Position consist of:
Noncurrent
assets
$
132,276
$
101,708
$
--
$
--
Current
liabilities
(4,029
)
(4,533
)
(49
)
(50
)
Noncurrent
liabilities
(33,082
)
(33,577
)
(4,115
)
(11,309
)
Total
$
95,165
$
63,598
$
(4,164
)
$
(11,359
)
Amounts
recognized in Accumulated Other Comprehensive Income consist
of:
Net
loss (gain)
$
(5,407
)
$
29,984
$
(8,445
)
$
(6,341
)
Prior
service cost (credit)
4,409
6,452
433
2,862
Transition
obligations (assets)
--
--
250
2,529
Total
$
(998
)
$
36,436
$
(7,762
)
$
(950
)
The projected benefit obligation, fair
value of plan assets and the funded status, measured as the difference between
the fair value of plan assets and the benefit obligation for the qualified
pension plan were $426.3 million, $558.5 and $132.3 million, respectively, as of
December 31, 2007. For the non-qualified pension plan, the projected
benefit obligation, fair value of plan assets and the funded status were $37.1
million, $0.0 million and $(37.1) million, respectively, as of December 31,2007.
The projected benefit obligation, fair
value of plan assets and the funded status, measured as the difference between
the fair value of plan assets and the benefit obligation for the qualified
pension plan were $430.9 million, $532.6 million and $101.7 million,
respectively, as of December 31, 2006. For the non-qualified pension
plan, the projected benefit obligation, fair value of plan assets and the funded
status were $38.1 million, $0.0, and $(38.1) million, respectively, as of
December 31, 2006.
Pension
Benefits
Other
Benefits
(Dollars
in Thousands)
2007
2006
2005
2007
2006
2005
Components
of net periodic benefit cost:
Service
cost
$
13,311
$
12,553
$
11,549
$
269
$
361
$
305
Interest
cost
26,513
24,667
23,855
1,250
1,522
1,409
Expected
return on plan assets
(38,859
)
(37,572
)
(37,928
)
(826
)
(871
)
(878
)
Amortization
of prior service cost
2,041
2,341
2,867
353
534
466
Amortization
of net loss (gain)
5,187
5,230
3,354
(834
)
(273
)
(612
)
Amortization
of transition (asset) obligation
--
--
(163
)
234
418
418
Net
periodic benefit cost (income)
$
8,193
$
7,219
$
3,534
$
446
$
1,691
$
1,108
Curtailment/settlement
cost
1
$
--
$
--
$
--
$
708
$
--
$
--
_______________
1
As
part of the June 20, 2007 settlement, IBEW-represented employees with less
than five years of service would no longer receive a medical subsidy at
retirement and those employees with more than one year of service but less
than five years of service received a one-time cash
payment. Current IBEW-represented employees with five or more
years of service had a one-time opportunity to elect a cash payment that
varied depending on the years of employment with PSE in lieu of continuing
eligibility for the retiree medical subsidy. As a result of the
termination, the curtailment loss was $0.7
million.
Pension
Benefits
Other
Benefits
(Dollars
in Thousands)
2007
2006
2007
2006
Other
changes (pre-tax) in plan assets and benefit obligations recognized in
other comprehensive income:
(Increase)
decrease during year under SFAS 132R
$
--
$
(497
)
$
--
$
--
(Increase)
decrease due to adoption of SFAS 158
--
29,647
--
(950
)
Net
loss (gain)
(30,205
)
--
(3,396
)
--
Amortization
of net loss (gain)
(5,187
)
--
835
--
Mergers,
sales and closures
--
--
(3,356
)
--
Prior
service cost (credit)
--
--
(307
)
--
Amortization
of prior service cost
(2,042
)
--
(353
)
--
Amortization
of transition (asset) obligation
--
--
(234
)
--
Total
change in other comprehensive income for year
$
(37,434
)
$
29,150
$
(6,811
)
$
(950
)
The estimated net loss (gain) and prior
service cost (credit) for the pension plans that will be amortized from
accumulated other comprehensive income into net periodic benefit cost in 2008
are $0.7 million and $1.3 million, respectively. The estimated net
loss (gain), prior service cost (credit) and transition obligation (asset) for
the other postretirement plans that will be amortized from accumulated other
comprehensive income into net periodic benefit cost in 2008 are $(0.8) million,
less than $0.1 million and less than $0.1 million,
respectively.
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
2007
2006
2005
2007
2006
2005
Discount
rate
6.30%
5.80%
5.60%
6.30%
5.80%
5.60%
Rate
of compensation increase
4.50%
4.50%
4.50%
--
--
--
Medical
trend rate
--
--
--
9.00%
10.00%
11.00%
Pension
Benefits
Other
Benefits
Benefit
Cost Assumptions
2007
2006
2005
2007
2006
2005
Discount
Rate
5.80%
5.60%
5.60%
5.80%
5.60%
5.60%
Return
on plan assets
8.25%
8.25%
8.25%
3.9-8%
4.3-8%
4.3-8%
Rate
of compensation increase
4.50%
4.50%
4.50%
--
--
--
Medical
trend rate
--
--
--
10.00%
11.00%
12.00%
The
assumed medical inflation rate used to determine benefit obligations is 9.0% in
2008 grading down to 7.0% in 2010. A 1.0% change in the assumed
medical inflation rate would have the following effects:
2007
2006
(Dollars
in Thousands)
1%
Increase
1%
Decrease
1%
Increase
1%
Decrease
Effect
on post-retirement benefit obligation
$
216
$
(189
)
$
752
$
(666
)
Effect
on service and interest cost components
16
(15
)
42
(38
)
The Company has selected the expected
return on plan assets based on a historical analysis of rates of return and 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. The Company’s accounting
policy for calculating the market-related value of assets for the Company’s
retirement plan is as follows. The market-related value of assets is
based on a five-year smoothing of asset gains/losses measured from the expected
return on market-related assets. This is a calculated value that
recognizes changes in fair value in a systematic and rational manner over five
years. The same manner of calculating market-related value is used
for all classes of assets, and is applied consistently from year to
year.
The discount rate was determined by
using market interest rate data and the weighted-average discount rate from
Citigroup Pension Liability Index Curve. The Company also takes into
account in determining the discount rate the expected changes in market interest
rates and anticipated changes in the duration of the plan
liabilities.
The aggregate expected contributions by
the Company to fund the pension and other benefit plans for the year ending
December 31, 2008 are $4.0 million and less than $0.1 million,
respectively. The full amount of the pension funding for 2008 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:
2007
2006
Pension
Benefits
Other
Benefits
Pension
Benefits
Other
Benefits
Short-term
investments and cash
2.08%
--
2.7%
--
Equity
securities
54.83%
--
62.9%
--
Fixed
income securities
15.07%
12.3%
14.8%
13.4%
Mutual
funds (equity and fixed income)
28.02%
87.7%
19.6%
86.6%
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 are as follows:
(Dollars
in Thousands)
2008
2009
2010
2011
2012
2013-2017
Total
benefits
$
33,103
$
31,953
$
35,230
$
35,278
$
37,536
$
201,308
The Company has a Retirement Plan
Committee that establishes investment policies, objectives and strategies
designed to balance expected return with a prudent level of risk. All
changes to the investment policies are reviewed and approved by the Retirement
Plan Committee prior to being implemented.
The Retirement Plan Committee invests
trust assets 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 Plan Committee has established investment
allocation percentages by asset classes as follows:
Allocation
Asset
Class
Minimum
Target
Maximum
Equity
securities
35%
62%
85%
Fund
of Hedge Funds
5%
10%
15%
Tactical
Asset Allocation
--
5%
10%
Fixed-income
securities
15%
23%
30%
Real
estate and cash
--
--
15%
On May 19, 2004, FASB issued FASB Staff
Position No. 106-2, “Accounting and Disclosure Requirements Related to the
Medicare Prescription Drug, Improvement and Modernization Act of 2003” as the
result of the new Medicare Prescription Drug Improvement 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 new Medicare regulations issued in May 2005, the Company determined that it
provides benefits at a higher level than provided under Medicare Part D, and
therefore would qualify for federal tax subsidies.
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.
The Company’s contributions to the
Employee Investment Plans were $9.0 million, $7.9 million and $6.9 million for
the years 2007, 2006 and 2005, respectively. The Employee Investment
Plan eligibility requirements are set forth in the plan documents.
Prior to
2006, the Company had various stock-based compensation plans which were
accounted for according to APB No. 25, and related interpretations as allowed by
SFAS No. 123. 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. The Company applied SFAS No. 123 accounting to stock
compensation awards granted subsequent to January 1, 2003, while grants prior to
2003 continued to be accounted for using the intrinsic value method of APB No.
25. Effective January 1, 2006, the Company adopted the fair value
recognition provisions of SFAS No. 123R, using the modified-prospective
transition method. Under that transition method, compensation cost
recognized effective 2006 includes: (a) compensation cost for all share-based
payments granted prior to, but not yet vested as of January 1, 2006, based on
the grant date fair value estimated in accordance with the original provisions
of SFAS No. 123 and (b) compensation cost for all share-based payments granted
subsequent to January 1, 2006, based on the grant date fair value estimated in
accordance with the provisions of SFAS No. 123R. Results for prior
periods have not been restated, as provided for under the modified-prospective
method.
The
adoption of SFAS No. 123R resulted in a cumulative benefit from an accounting
change of $0.1 million, net of tax, for the quarter ended March 31,2006. The cumulative effect adjustment is the result of the inclusion
of estimated forfeitures occurring before award vesting dates in the computation
of compensation expense for unvested awards. For purposes of
determining stock compensation expense under SFAS No. 123R, forfeitures for
multi-year plans are calculated based on the historical average forfeiture rate
for vested cycles and are trued up to actual forfeiture experience in the year
of vesting.
As a
result of adopting SFAS No. 123R on January 1, 2006, the Company’s income before
income taxes and net income from continuing operations at December 31, 2006, was
$0.1 million and $0.1 million higher, respectively, than if it had continued to
account for share-based compensation under SFAS No. 123 due to the inclusion of
estimated forfeitures in compensation cost.
The
Company’s Long-Term Incentive Plan (LTI Plan), established in 1995 after
approval by shareholders, encompasses many of the awards granted to employees.
The plan was amended and restated in 2005, and approved by
shareholders. The LTI Plan applies to officers and key employees of
the Company and awards granted under this plan include stock awards, performance
awards or other stock-based awards as defined by the plan. Any shares
awarded are either purchased on the open market or are a new
issuance. The 2006 and 2007 cycles included a grant of restricted
stock, which was added to reduce the volatility of the
plan. Beginning with the 2004 share grants, plan participants meeting
the Company’s stock ownership guidelines can elect to be paid up to 50.0% of the
share award in cash. The maximum number of shares that may be
purchased or issued as new shares for the LTI Plan is 4,200,000.
Performance
Share Grants
The
Company generally awards performance share grants annually under the LTI
Plan. These are granted to key employees and vest at the end of three
years for grants made in 2004, 2005, 2006 and 2007. Grants made in
2003 vest over a four year period. The number of shares awarded and
expense recorded depends on Puget Energy’s performance as compared to other
companies and service quality indices for customer
service. Compensation expense related to performance share grants was
$2.3 million, $(1.6) million and $1.0 million for 2007, 2006 and 2005,
respectively. As of December 31, 2007, $2.8 million of total
unrecognized compensation cost, net of forfeitures, related to nonvested
performance share grants. That cost is expected to be recognized over
a weighted-average period of 1.6 years. The weighted-average fair
value per performance share granted for the years ended 2006 and 2005 was $24.77
and $21.19, respectively.
Performance
shares activity for the twelve months ended December 31, 2007 was as
follows:
Performance
Shares at December 31, 2006 were cancelled because performance modifiers
were not achieved.
Plan
participants meeting the Company’s stock ownership guidelines can elect to be
paid up to 50.0% of the share award in cash. The portion of the
performance share grants that can be paid in cash is classified and accounted
for as a liability. As a result, the compensation expense of these
liability awards is recognized over the performance period based on the fair
value (i.e. cash value) of the award, and is periodically updated based on
expected ultimate cash payout. Compensation cost recognized during
the performance period for the liability portion of the performance grants is
based on the closing price of the Company’s common stock on the date of
measurement and the number of months of service rendered during the
period. The equity portion is valued at the closing price of the
Company’s common stock on the grant date.
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 the LTI Plan (for a total of
300,000 non-qualified stock options) to the Chairman, President and Chief
Executive Officer. These options can be exercised at the grant date
market price of $22.51 per share and vest annually over four and five years
although the options would become fully vested upon a change of control of the
Company or an employment termination without cause. The options
expire ten years from the grant date and have a remaining contractual term of
approximately six years. All 300,000 options are fully vested and
remained outstanding and exercisable at December 31, 2007. The fair
value of the options at the grant date was $3.33 per
share. Compensation expense related to stock options was $0.0 for
each of 2007, 2006 and 2005, respectively. The total fair value of
stock options vested during 2007 and 2006 was $0.1 and $0.2 million,
respectively. The fair value of the stock option award was estimated
on the date of grant using the Black-Scholes option valuation
model.
Restricted
Stock
In 2007,
2006, 2005, 2004 and 2003, the Company granted 97,244 shares, 107,555 shares,
50,000 shares, 40,000 shares and 11,000 shares, respectively, of restricted
stock under the LTI Plan to be purchased on the open market or as a new
issuance. Under the 2007 and 2006 grants, the shares vest 15.0% in
year 1 on January 1, 25.0% vest in year 2 on January 1, and the remaining 60.0%
vest in year 3 on January 1, based upon a performance and service
condition. Under the 2005 grant, 40,000 shares vest in one
installment on May 6, 2008 based upon performance criteria and the remaining
10,000 shares vest equally over three years. The 2004 grant vests
8,000 shares in three years and the remaining 32,000 shares in four
years. For the 2003 grant, 1,000 vested in 2003 with the remaining
shares vesting evenly over the following five years.
Restricted
stock activity for the twelve months ended December 31, 2007 was as
follows:
There was
$2.0 million of total unrecognized compensation cost related to nonvested
restricted stock at December 31, 2007. That cost is expected to be
recognized over a weighted-average period of 1.9 years. Compensation
expense related to the restricted shares was $3.0 million and $2.0 million for
2007 and 2006, respectively. Dividends are paid on all outstanding
shares of restricted stock and are accounted for as a Puget Energy common stock
dividend, not as compensation expense. During 2007, 39,083 shares of
restricted stock vested and 3,435 shares of restricted stock were
forfeited. During 2006, 15,333 shares of restricted stock vested and
2,566 shares of restricted stock were forfeited. During 2005, 12,000
shares of restricted stock vested and no restricted stock was forfeited during
2005. The weighted-average fair value per restricted share vested for
the year ended 2005 was $22.85. The fair value of restricted shares
vested during 2007, 2006 and 2005 was $0.9 million, $0.3 million and $0.3
million, respectively. The fair value of the restricted stock is based on the
closing price of the Company’s common stock on the date of grant.
Restricted
Stock Units
In 2004,
the Company granted 10,000 restricted stock units outside of the LTI Plan but
subject to the terms and conditions of the plan. 2,000 shares vested
on January 8, 2007, 3,000 shares vested on January 8, 2008 and the remaining
5,000 shares will vest on May 6, 2008.
Restricted
stock units activity for the twelve months ended December 31, 2007 was as
follows:
There was
$0.01 million of total unrecognized compensation cost related to nonvested
restricted stock units as of December 31, 2007. That cost is expected
to be recognized on May 6, 2008. There were no restricted stock units
granted or forfeited during 2007 and 2006. The restricted stock units
will be settled in cash when they become vested at the end of each
cycle. 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 for 2007 and
2006. The fair value of the restricted stock units is based on the
closing price of the Company’s common stock at each reporting
period.
Retirement
Equivalent Stock
The
Company has a retirement equivalent stock agreement under which in lieu of
participating in the Company’s executive supplemental retirement plan, the
Chairman, 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. Retirement equivalent stock
activity is as follows:
Number
of Shares
Weighted-Average
Fair Value Per Share
Retirement
Equivalent Stock Awarded:
2003
4,319
$
22.05
2004
6,469
$
23.77
2005
6,063
$
24.70
2006
8,218
$
20.42
2007
9,476
$
25.36
The
shares vest over a period from January 1, 2002 to May 2008 at 15.0% per year for
the first six years and the remaining 10.0% in the seventh year. At
December 31, 2007, there were 8,636 total shares of nonvested retirement
equivalent stock units with a weighted-average grant date fair value of
$23.36. There was $0.1 million unrecognized compensation cost related
to nonvested retirement equivalent stock units as of December 31,2007. That cost is expected to be recognized over a weighted-average
period of one year. The equivalent value of dividends is paid on the
accumulated retirement equivalent stock units and added to the deferred
compensation account. Compensation expense related to the retirement
equivalent stock agreement was $0.1 million, $0.2 million and $0.1 million in
2007, 2006 and 2005, respectively. During 2007, 12,288 retirement
equivalent stock units vested. The fair value of the restricted stock
is based on the closing price of the Company’s common stock on the date of
grant.
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 85.0% of the lower of the
stock’s fair market price at the beginning or the end of the six-month
period. A maximum of 1,000,000 shares may be sold to employees under
the plan. At December 31, 2007, 554,277 shares could still be sold to
employees under the plan. In 2007 and 2006, 66,819 and 66,496 shares
were issued for the ESPP, respectively. Under SFAS No. 123 accounting
that the Company adopted in 2003 and under SFAS No. 123R, the ESPP is considered
to be compensatory and the amount is immaterial to the financial
statements. Dividends are not paid on ESPP shares until they are
purchased by employees and thus are accounted for as dividends, not compensation
expense. Cash received from the exercise of the ESPP during 2007 was
$1.4 million. The Company suspended further offerings in the ESPP
pending the outcome of the merger effective with the offering period beginning
January 1, 2008.
Non-Employee
Director Stock Plan
The
Company has a director stock plan for all non-employee directors of Puget Energy
and PSE. An amended and restated plan was approved by shareholders in
2005. Under the plan, which has a term through December 31, 2015,
non-employee directors receive a portion of their quarterly retainer fees in
Puget Energy stock except that 100.0% 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 choose to continue to
receive their entire retainer in Puget Energy stock. The compensation
expense related to the director stock plan was $0.6 million and $0.5 million in
2007 and 2006, respectively. The Company issues new shares or
purchases stock for this plan on the open market up to a maximum of 350,000
shares. As of December 31, 2007, 53,173 shares had been issued or
purchased for the director stock plan and 101,678 deferred, for a total of
154,851 shares. As of December 31, 2006, the number of shares that
had been purchased for the director stock plan was 34,166 and deferred was
92,807, for a total of 126,973 shares.
Option
Model Assumptions
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 outstanding in 2007 and 2006.
Stock
issuance cycle
2007
2006
2005
2004
2003
2002
Stock
options
Risk-free
interest rate
*
*
*
*
*
4.32
%
Expected
lives -
years
*
*
*
*
*
4.5
Expected
stock volatility
*
*
*
*
*
23.62
%
Dividend
yield
*
*
*
*
*
5.00
%
Performance
awards
Risk-free
interest rate
**
**
2.50
%
2.59
%
2.35
%
*
Expected
lives -
years
3.0
3.0
3.0
3.0
4.0
*
Expected
stock volatility
**
**
15.10
%
22.24
%
23.85
%
*
Dividend
yield
*
*
4.18
%
4.45
%
4.86
%
*
Employee
Stock Purchase Plan
Risk-free
interest rate
4.79
%
4.96
%
2.68
%
1.28
%
1.07
%
*
Expected
lives -
years
0.5
0.5
0.5
0.5
0.5
*
Expected
stock volatility
12.24
%
9.79
%
13.98
%
9.89
%
19.47
%
*
Dividend
yield
4.04
%
4.55
%
4.17
%
4.42
%
4.39
%
*
_______________
*
Not
applicable
**
Fair
value is determined by end of period market
value.
The
expected lives of the securities represent the estimated period of time until
exercise and are based on the vesting period of the award and the historical
exercise experience of similar awards. All participants were assumed
to have similar exercise behavior. Expected volatility is based on
historical volatility over the approximate expected term of the
option.
SFAS No.
133 as amended, requires that all contracts considered to be derivative
instruments be recorded on the balance sheet at their fair value. The
Company enters into 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 (NPNS) exception to derivative accounting
rules provided they meet certain criteria. Generally, NPNS applies if
PSE deems the counterparty creditworthy, if the counterparty owns or controls
energy resources within the western region to allow for physical delivery of the
energy and if the transaction is within PSE’s forecasted load requirements and
adjusted from time to time. Those contracts that do not meet NPNS
exception or cash flow hedge criteria are marked-to-market to current earnings
in the income statement, subject to deferral under SFAS No. 71 for energy
related derivatives due to the Power Cost Adjustment (PCA) mechanism and
Purchased Gas Adjustment (PGA) mechanism.
The
nature of serving regulated electric customers with its wholesale portfolio of
owned and contracted electric generation 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 portfolio 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 realizing 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 natural gas portfolios.
The
following table are electric derivatives that are designated as cash flow hedges
or contracts that do not meet Normal Purchase Normal Sale (NPNS) at December 31,2007 and December 31, 2006:
If it is
determined that it is uneconomical to operate PSE’s controlled electric
generating facilities in the future period, the fuel supply cash flow hedge
relationship is terminated and the hedge is de-designated which results in the
unrealized gains and losses associated with the contracts being recorded in the
income statement. As these contracts are settled, the costs are
recognized as energy costs and are included as part of the PCA
mechanism.
At
December 31, 2007, the Company had an unrealized day one loss deferral of $9.0
million related to a three year locational power exchange contract which was
modeled and therefore the day one gain was deferred under EITF No.
02-3. The deferred loss is being amortized over the term of the
contracts. Any future changes in the mark-to-market value will be
recorded through the income statement. The contracts have economic
benefit to the Company over their terms. The locational exchange will
help ease electric transmission congestion across the Cascade Mountains during
the winter months as PSE will take delivery of energy at a location that
interconnects with PSE’s transmission system in Western
Washington. At the same time, PSE will make available the quantities
of power at the Mid-Columbia trading hub location.
The
following table presents the impact of changes in the market value of derivative
instruments not meeting NPNS or cash flow hedge criteria to the Company’s
earnings during the twelve months ending December 31, 2007 and December 31,2006:
(Dollars
in millions)
2007
2006
Change
Increase
(decrease) in earnings
$
2.7
$
(0.1
)
$
2.8
The
amount of unrealized gain, net of tax, related to the Company’s energy-related
cash flow hedges under SFAS No. 133 consisted of the following at December 31,2007 and December 31, 2006:
At
December 31, 2007, the Company had total assets of $11.3 million and total
liabilities of $17.3 million related to hedges of natural gas contracts to serve
natural gas customers. 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. All increases and
decreases in the cost of natural gas supply are passed on to customers with the
PGA mechanism. As the gains and losses on the hedges are realized in
future periods, they will be recorded as natural gas costs under the PGA
mechanism.
In May
2003, approximately 50 plaintiffs brought an action against the owners of
Colstrip which has since been amended to add additional claims. The
lawsuit alleges that certain domestic water wells, groundwater and the Colstrip
water supply pond were contaminated by seepage from a Colstrip Units 1 & 2
effluent holding pond, that seepage from Colstrip Units 1 & 2 have decreased
property values and that seepage from the Colstrip water supply pond caused
structural damage to buildings and toxic mold. Plaintiffs are seeking
compensatory and punitive damages. Discovery is ongoing and trial is
scheduled for June 2008.
On March29, 2007, a second complaint related to pond seepage was filed on behalf of two
ranch owners alleging damage due to the Colstrip Units 3 & 4 effluent
holding pond. Discovery is on going and no trial date has been
set.
On May18, 2005, the Environmental Protection Agency (EPA) enacted the Clean Air
Mercury Rule (CAMR) that will permanently cap and reduce mercury emissions from
coal-fired power plants. The Montana Board of Environmental Review
approved a more stringent rule to limit mercury emissions from coal-fired plants
on October 16, 2006 (0.9 lbs/TBtu, instead of the federal
1.4 lbs/TBtu). The Colstrip owners are still evaluating the
potential impact of the new Montana rule and it is still unknown whether the new
rule will be appealed. Treatment technology studies undertaken by the
Colstrip owners estimate that PSE’s portion of the costs to comply with the
Montana rule could be as much as $11.0 million in construction expenditures
and as much as $9.0 million per year in operation and maintenance expenditures
but this number could change as new information becomes available. On
February 8, 2008, the District of Columbia Federal Court of Appeals vacated the
EPA CAMR rule. This action does not invalidate the rule adopted by
Montana.
On June15, 2005, the U. S. Environmental Protection Agency (EPA) issued the Clean Air
Visibility Rule to address regional haze or regionally-impaired visibility
caused by multiple sources over a wide area. The rule defines Best
Available Retrofit Technology (BART) requirements for electric generating units,
including presumptive limits for sulfur dioxide, particulate matter and nitrogen
oxide controls for large units. In February 2007, Colstrip was
notified by EPA that Colstrip Units 1 & 2 were determined to be subject to
the BART requirements, PSE submitted a BART engineering analysis for
Colstrip Units 1 & 2 in August 2007. PSE cannot yet determine the
need for or costs of additional controls to comply with this rule.
On
February 18, 2005, the Washington Commission issued a general rate case order
that defined deferrable catastrophic/extraordinary losses and provided that
costs in excess of $7.0 million annually may be deferred for qualifying storm
damage costs that meet the IEEE outage criteria for system average interruption
duration index. PSE’s storm accounting,
which allows deferral of certain storm damage costs, was subject to review by
the Washington Commission at the end of the current three-year period, which was
December 31, 2007. PSE filed an accounting petition with the
Washington Commission to extend the current deferral mechanism beyond December31, 2007 and this was approved by the Washington Commission on November 6,2007. Deferral of future storm damage costs will be determined in
PSE’s electric general rate case which is expected to conclude in November
2008. In 2007, PSE incurred $38.3 million in storm-related
electric transmission and distribution system restoration costs, of which $29.3
million was deferred for future recovery in electric rates. In 2006,
PSE incurred $103.2 million in storm-related electric transmission and
distribution system restoration costs, of which $92.3 million was
deferred.
Electric
General Rate Case
On
December 3, 2007, PSE filed a general rate case with the Washington Commission
which proposed an increase in electric rates of $174.5 million or 9.5% annually,
effective November 3, 2008. PSE requested a weighted cost of capital
of 8.6%, or 7.29% after-tax, and a capital structure that included 45.0% common
equity with a return on equity of 10.8%. An order from the Washington
Commission is expected in October 2008.
On
January 5, 2007, the Washington Commission issued its order in PSE’s electric
general rate case filed in February 2006, approving a general rate decrease for
electric customers of $22.8 million or 1.3% annually. The rates for
electric customers are effective beginning January 13, 2007. In its
order, the Washington Commission approved a weighted cost of capital of 8.4%, or
7.06% after-tax, and a capital structure that included 44.0% common equity with
a return on equity of 10.4%. The Washington Commission had earlier
approved (on June 28, 2006) a power cost only rate case (PCORC) increase of
$96.1 million annually effective July 1, 2006.
Power
Cost Only Rate Case
PCORC, a
limited-scope proceeding, was approved in 2002 by the Washington Commission to
periodically reset power cost rates. In addition to providing the
opportunity to reset all power costs, the PCORC proceeding also provides for
timely review of new resource acquisitions costs and inclusion of such costs in
rates at the time the new resource goes into service. To achieve this
objective, the Washington Commission approved an expedited five-month PCORC
decision timeline rather than the statutory 11-month timeline for a general rate
case.
On March20, 2007, PSE submitted a Power Cost Only Rate Case (PCORC) filing to request
approval of an updated power cost baseline rate beginning September
2007. The PCORC filing also requested recovery of ownership and
operating costs of the Goldendale generating facility (Goldendale) through
retail electric rates. On May 23, 2007, PSE filed updated power costs
due to changes in market conditions of natural gas and other costs which
resulted in a revised proposed increase of $77.8 million or 4.4%
annually. On July 5, 2007, a settlement agreement in this PCORC
signed by PSE and certain other parties to the proceeding was filed with the
Washington Commission, the terms of which included an electric rate increase of
$64.7 million. On August 2, 2007, the Washington Commission approved
the settlement agreement and authorized an increase in PSE’s electric rates of
$64.7 million or an average increase of 3.7% annually effective September 1,2007. The investment in Goldendale was found prudent, thus
allowing for recovery of certain ownership and operating costs through electric
retail rates effective September 1, 2007 along with updating other power
costs.
In
accordance with the August 2, 2007 Washington Commission order approving the
PCORC settlement, PSE and other parties agreed to conduct a collaborative
stakeholder review of the PCORC process to consider the scope and timing of the
PCORC mechanism. The collaborative review included but was not
limited to: 1) the number of PCORCs that a company will be allowed to file in
any given year; 2) the number and timing of updates that a company may submit in
the PCORC process; 3) the items directly associated with power costs that may be
included and considered in a PCORC filing; and 4) whether the number and timing
of updates may vary depending on if other parties can easily
verify. On December 12, 2007 the collaboration filed a final report
with the Commission reporting that the parties were not able to reach agreement
on revisions to the PCORC mechanism and that the parties will address such
issues in the Company’s pending general rate case filing.
On April11, 2007, the Washington Commission approved PSE’s petition for issuance of an
accounting order that authorizes PSE to defer certain ownership and operating
costs (and associated carrying costs) the Company incurred related to its
purchase of Goldendale during the period prior to inclusion in PSE’s retail
electric rates in the PCORC. The deferral is for the time period from
March 15, 2007 through September 1, 2007. As of December 31, 2007,
PSE had established a regulatory asset of $11.5 million including carrying
costs. PSE anticipates amortization of the costs will begin no later
than November 2008 as determined in PSE’s next general rate case.
Residential
Exchange Deferred Asset
On May21, 2007, the Bonneville Power Administration (BPA) notified PSE and other
investor-owned utilities that BPA was suspending payments related to its
residential exchange program due to adverse Ninth Circuit Court of Appeals
(Ninth Circuit) decisions of May 3, 2007. The Ninth Circuit concluded
in its decisions that certain BPA actions in entering into residential exchange
settlements in 2000 were not in accordance with the law. BPA
suspended payments under the residential exchange program as a result of the
Ninth Circuit decisions. As a result of the BPA suspension of
payment, PSE filed revisions to the tariffs which pass through the benefits of
the Residential Exchange to all residential and small farm
customers. The Washington Commission approved the termination of the
Residential Exchange Credit effective June 7, 2007. Under Federal
law, investor-owned utilities receiving residential exchange benefits must
pass-through the benefits to their residential and small farm electric
customers.
On August 29, 2007, the Washington
Commission approved PSE’s accounting petition to defer as a regulatory asset the
excess BPA Residential Exchange benefit provided to customers and accrue monthly
carrying charges on the deferred balance from June 7, 2007 until the deferral is
recovered from customers or BPA. The accounting petition sought
approval to record carrying costs on the deferred balance until the deferred
balance is recovered from customers. As of December 31, 2007, PSE has
recorded a regulatory asset of $35.7 million. On December 17,2007, BPA released a proposal for public comment which would provide temporary,
interim relief to the region’s investor-owned utilities until final Residential
Exchange Program (REP) contracts are reached and executed which are planned to
go into effect October 1, 2008 or 2009. These interim agreements are
offered in exchange for suspension of certain litigation activities, and will be
trued-up to the actual final REP benefits for each individual company as
established in BPA’s upcoming administrative proceedings.
Following
the close of the comment period on January 7, 2008, BPA will review all comments
received and issue a record of decision on whether to offer the proposed interim
agreements to customers. If BPA decides to offer the agreements, they
could be sent to the utilities for signature in February or March
2008. BPA is proposing to provide these interim benefits in one
lump-sum payment, and have said that utilities could receive their interim
payments as soon as five to ten working days after signing
agreements.
Natural
Gas System Recordkeeping Complaint
In May
2007, the Washington Commission Staff alleged that PSE’s natural gas system
service provider had violated certain Washington Commission recordkeeping
rules. The Washington Commission has since filed a complaint against
PSE that includes Washington Commission Staff’s recommendation that PSE be
assessed a $2.0 million regulatory penalty. As of June 30, 2007, PSE
management determined the penalty met the SFAS No. 5 criteria for recording a
loss contingency and recorded a $2.0 million loss reserve. The
Washington Commission investigation is ongoing.
Production
Tax Credit
On October 30, 2006, PSE revised its
PTC electric tariff to increase the revenue credit to customers from $13.1
million to $28.8 million, effective January 1, 2007. On December 12,2007, PSE revised its PTC electric tariff to decrease the revenue credit to
customers from $28.8 million to $28.6 million, effective January 12,2008. The credit is based on expected wind generation and reflects
the true-up of prior years’ credits provided to customers versus credits for
actual wind generation taken for federal income taxes and the addition of Wild
Horse to the wind portfolio. PSE will be revising its tariff
effective January 1, 2009 based on actual PTC results for 2008 and project 2009
PTCs based on a filing to be made in the fourth quarter 2008.
PCA
Mechanism
On June20, 2002, the Washington Commission approved a PCA mechanism that triggers if
PSE’s costs to provide customers’ electricity falls outside certain bands
established in an electric rate case. The cumulative maximum pre-tax earnings
exposure due to power cost variations over the four-year period ending June 30,2006 was limited to $40.0 million plus 1.0% of the excess. In October
2005, the Washington Commission approved a shift to an annual PCA measurement
period from January through December starting in 2007. On January 5,2007, the Washington Commission approved the continuation of the PCA mechanism
under the same annual graduated scale without a cumulative cap for excess power
costs. All significant variable power supply cost variables
(hydroelectric and wind generation, market price for purchased power and surplus
power, natural gas and coal fuel price, generation unit forced outage risk and
transmission cost) are included in the PCA mechanism.
The PCA
mechanism apportions increases or decreases in power costs, on a calendar year
basis, between PSE and its customers on a graduated scale:
Annual
Power Cost Variability
July
– December 2006 Power Cost Variability1
Customers’
Share
Company’s
Share2
+/-
$20 million
+/-
$10 million
0%
100%
+/-
$20 million - $40 million
+/-
$10 - $20 million
50%
50%
+/-
$40 million - $120 million
+/-
$20 - $60 million
90%
10%
+/-
$120 + million
+/-
$60 million
95%
5%
_______________
1
In
October 2005, the Washington Commission in its Power Cost Only Rate Case
order allowed for a reduction to the power cost variability amounts to
half the annual power cost variability for the period July 1, 2006 through
December 31, 2006.
2
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 $40.0
million plus 1.0% of the excess. Power cost variation after
December 31, 2006 will be apportioned on a calendar year basis, without a
cumulative cap.
Accounting
Orders
On April26, 2006, the Washington Commission approved an accounting petition on a
temporary basis to defer an $89.0 million one-time capacity reservation charge
along with accrual of interest at the authorized after-tax rate of
return. As part of the general rate case order of January 5, 2007,
the Washington Commission approved the regulatory accounting treatment that had
been approved in the accounting petition. The payment was made in
relation to an agreement for the purchase of power from Chelan County PUD
(Chelan). PSE and Chelan have entered into an agreement which
provides for the purchase of 25% of the output of Chelan’s Rock Island (622
megawatts (MW)) and Rocky Reach (1,237 MW) dams on the Columbia
River. The agreement called for PSE to make a one-time payment of
$89.0 million on April 27, 2006. Then, upon the expiration of the
existing contracts in 2011, PSE will begin purchasing 25% of the output at the
projects’ costs for the next 20 years.
Gas
Regulation and Rates
Gas
General Rate Case
On
December 3, 2007, PSE filed a general rate case with the Washington Commission
which proposed an increase in natural gas rates of $56.8 million or 5.3%
annually, effective November 3, 2008. PSE requested a weighted cost
of capital of 8.6%, or 7.29% after-tax, and a capital structure that included
45.0% common equity with a return on equity of 10.8%. An order from
the Washington Commission is expected in October 2008.
On
January 5, 2007, the Washington Commission issued its order in PSE’s natural gas
general rate case, granting an increase for natural gas customers of $29.5
million or 2.8% annually, effective beginning January 13, 2007 which resulted in
an increase in gas margin of approximately 9.8% annually. In its
order the Washington Commission approved the same weighted cost of capital of
8.4% or 7.06% after-tax and capital structure that included 44.0% common equity
with a return on equity of 10.4%, consistent with the Company’s electric
operations.
Purchased
Gas Adjustment
PSE has a
Purchased Gas Adjustment (PGA) mechanism in retail natural gas rates to recover
variations in gas supply and transportation costs. Variations in gas
rates are passed through to customers, therefore PSE’s gas margin and net income
are not affected by such variations. On September 26, 2007, the
Washington Commission approved PSE’s requested revisions to its PGA tariffs
resulting in a rate decrease for gas customers of $148.1 million or 13.0%
annually effective October 1, 2007. The rate decrease was the result
of lower costs of natural gas in the forward market and a refund of the
accumulated PGA payable balance over a 12-month period beginning October 1,2007. The PGA rate change will decrease PSE’s revenue but will not
impact the Company’s natural gas margins or net income as the decreased revenue
will be offset by decreased purchased gas costs and decreased revenue sensitive
taxes.
The
following rate adjustments were approved by the Washington Commission in
relation to the PGA mechanism during 2007, 2006 and 2005:
The
Washington Commission issued an order on May 13, 2004 determining that PSE did
not prudently manage natural gas costs for the Tenaska electric generating plant
and ordered PSE to adjust its PCA deferral account to reflect a disallowance of
accumulated costs under the PCA mechanism for these excess costs. The
increase in purchased electricity expense resulting from the disallowance
totaled $7.8 million, $9.0 million and $4.1 million in 2007, 2006 and 2005,
respectively. The order also 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.
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, 2006, the White
River project net book value totaled $72.5 million, which included $41.9 million
of net utility plant, $17.3 million of capitalized FERC licensing costs, $6.7
million of costs related to construction work in progress and $6.6 million
related to dam operation and safety. PSE sought recovery of the
relicensing, other construction work in progress and dam operations and safety
costs 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. On February18, 2005, the Washington Commission agreed to allow PSE to recover the White
River net utility plant costs noted above. However, amortization of
the FERC licensing and other costs will not begin until all costs and any sales
proceeds are known.
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 February1, 2003, it was effective July 1, 2003. The adoption of FIN 46R was
effective March 31, 2004 for the Company. 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). This change had no
impact on the Company’s results of operations. The Company also
evaluated its power purchase 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
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.
One of
these counterparties, Sumas Cogeneration Company, L.P. (Sumas), delivered a
letter to PSE on May 7, 2007, stating that it had sold its dedicated natural gas
reserves to a third party and that it no longer intended to deliver energy to
PSE through the remaining term of the contract, which expires on April 15,2013. The last energy delivered to PSE by Sumas occurred on March 15,2007. Following negotiations with Sumas on December 7, 2007, PSE and
Sumas signed a Membership Interest Purchase and Sale Agreement for the
acquisition of the 125 MW power plant located in Sumas,
Washington. Sumas also agreed to transfer an undivided ownership
interest in the pipeline easements to PSE. PSE expects the
transaction to close in the second half of 2008, after it receives approval from
FERC and presidential permits to operate the natural gas pipeline.
For the
two remaining power purchase 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 power purchase
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 2007, 2006 and 2005
for these three entities was $216.5 million, $259.8 million and $267.0 million,
respectively.
On May30, 2007, PSE agreed to extend the terms of the existing leases of its Bellevue
corporate office complex from ten years to 15 years. PSE’s lease
agreement included a one-time right to purchase the office
complex. PSE elected to monetize the value of this purchase option
and negotiated for a cash payment of $18.9 million, net of transaction fees, in
exchange for the termination of the purchase option. PSE has filed an
accounting petition with the Washington Commission seeking deferred accounting
treatment of the net proceeds and amortization of the net proceeds to match the
near-term contractual lease payment increases. The Washington
Commission has not yet ruled on this matter.
As of
December 31, 2007, PSE had $25.1 million in insurance receivables recorded
related to two property damage claims and a general liability
claim. As of February 28, 2008, PSE has received $6.9 million in
payments from the insurers associated with these claims. Of the
remaining receivable balance, $7.6 million remains in review by the associated
insurance companies and any amount not recovered would be expensed in the period
that it is deemed nonrecoverable. An additional $10.1 million of the
receivable balance represents an estimate based on the cost that would have been
incurred to repair, rather than replace, the damaged parts. If PSE
does not receive full recovery of this receivable, the accrued amount will be
recorded to utility plant.
In a
decision issued in October 2007, the Washington State Supreme Court ruled that
certain job reporting practices involving the use of company vehicles are
compensable time under Washington State’s wage and hour laws. One
union representing a portion of PSE’s workforce claims its members should now be
compensated for PSE job site reporting practices as a result of this
decision. The extent of the claims and financial impact on PSE
currently is unknown.
In November,
2007, PSE was audited by the Western Electricity Coordinating Council (WECC)
under delegated authority of the NERC, the FERC-certified Electric Reliability
Organization (ERO). Previously PSE had submitted several self
reports and mitigation plans to WECC for review and approval. The
WECC audit team told PSE of four additional preliminary alleged violations
(without any specified penalties) that were not previously self reported.
In response, PSE submitted self reports and mitigation plans for the four
violations. WECC has accepted the self reports and mitigation
plans. The ultimate result of the audit, including the nature or
amount of any penalties, cannot be predicted at this
time.
For the
year ended December 31, 2007, approximately 22.8% of the Company’s energy output
was obtained at an average cost of approximately $0.015 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 pro rata share basis
under which the Company pays a proportionate share of the annual debt service,
operating and maintenance costs and other expenses associated with each project
in proportion to the contractual shares that PSE obtains from that
project. In these instances, PSE’s 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 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, 2007, the Company was entitled to purchase portions of the power
output of the PUDs’ projects as set forth in the following
tabulation:
Total
Bonds
Outstanding
12/31/072
(Millions)
Company’s
Annual Amount Purchasable (Approximate)
Project
Contract
Exp.
Date
License1
Exp.
Date
%
of
Output
Megawatt
Capacity
Cost3
(Millions)
Rock
Island
Original
units
2012
2029
$ 134.5
50.0
}
248
$ 34.0
Additional
units
2012
2029
323.9
50.0
Rocky
Reach 8
2011
2006
373.9
38.9
488
29.1
Wells
2018
2012
197.8
29.9
251
11.4
Priest
Rapids 4,5,6
TBD7
TBD7
257.2
4.3
39
12.4
Wanapum
4,5,6
2009
TBD7
432.5
10.8
106
5.4
Total
$
1,719.8
1,132
$ 92.3
_______________
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 re-financings, 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: 81.4% at Rock Island;
66.9% at Rocky Reach; and
30.6% at Wells. There
are no maturities beyond the contract expiration date for Priest Rapids
and Wanapum which
assumes a 40-year FERC license extension.
3
The components of
2007 costs associated with the
interest portion of debt service are: Rock Island, $12.4 million for all units; Rocky
Reach, $8.2 million; Wells,
$3.0 million; Priest Rapids,
$0.5 million; and Wanapum,
$2.1
million.
4
On December 28, 2001, PSE signed
a contract offer for three new contracts related to 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. On May27, 2005, PSE signed additional amendments to those agreements which
provided technical clarifications of certain sections of the agreements
and consolidated the terms into two contracts. 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. The new contracts’ terms begin in November of 2005
for the Priest Rapids Development and in November of 2009 for the Wanapum
Development. 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. In June 2007, Grant County PUD and
the Yakama Nation reached a settlement agreement which requires the PUD to
make a declining block of Priest Rapids Project Power, or its financial
equivalent, available to the Yakama Nation throughout the terms of the New
FERC license. In exchange for this consideration, the Yakama
Nation would dismiss their requests for onerous relicensing terms and
conditions. The Company will be paying its pro rata share of
the cost of the Yakama Nation settlement agreement which will be included
in annual power costs of the Priest Rapids
Project.
5
Grant
County PUD filed an “Application for New License for the Priest Rapids
Project” on October 29, 2003 and the original FERC license expired at the
end of October 2005. Grant County PUD continues to operate the
Priest Rapids Project under annual license extensions pending issuance of
a new FERC license and the new contracts will be concurrent with the new
license which will be at least 30 years.
6
Unlike
PSE’s expiring contracts with Grant County PUD, in the new contracts PSE’s
share of power from the Priest Rapids Development and Wanapum Development
declines over time as Grant County PUD’s load increases. PSE’s
share of the Wanapum Development will remain at 10.8% until November 2009
and will be adjusted annually thereafter for the remaining term of the new
contracts. PSE’s share of the Priest Rapids Development
declines to approximately 4.3% in 2006 and will be adjusted annually for
the remaining term of the new contract.
7
To
be determined. (See notes 4-6.)
8
On
February 3, 2006, PSE and Chelan entered into a new Power Sales Agreement
and a related Transmission Agreement for 25.0% of the output of Chelan’s
Rocky Reach and Rock Island hydroelectric generating facilities located on
the mid-Columbia River in exchange for PSE paying 25.0% of the operating
costs of the facilities. The agreements terminate
in 2031 and provide that PSE will begin to receive power upon expiration
of PSE’s existing long-term contracts with Chelan for the Rocky Reach and
Rock Island output (expiring in 2011 and 2012,
respectively). The agreements have been approved by both FERC
and the Washington Commission.
The
following table summarizes the Company’s estimated payment obligations for power
purchases from the Columbia River, contracts with other utilities and contracts
under non-utility generators under the Public Utility Regulatory Policies Act
(PURPA). These contracts have varying terms and may include
escalation and termination provisions.
(Dollars
in millions)
2008
2009
2010
2011
2012
2013
& There-
after
Total
Columbia
River projects
$
104.3
$
101.2
$
98.3
$
121.2
$
95.5
$
1,622.6
$
2,143.1
Other
utilities
101.0
176.1
172.9
125.2
114.6
417.5
1,107.3
Non-utility
generators
206.2
195.1
197.1
201.4
--
--
799.8
Total
$
411.5
$
472.4
$
468.3
$
447.8
$
210.1
$
2,040.1
$
4,050.2
Total
purchased power contracts provided the Company with approximately 9.4 million,
9.6 million, and 9.6 million megawatt hours (MWh) of firm energy at a cost of
approximately $390.6 million, $421.7 million and $419.7 million for the years
2007, 2006, and 2005, respectively.
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 (one million British thermal units, equal to one Dth) 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 natural gas is reflective of
the daily price of natural gas at the United States/Canada border near Sumas,
Washington. PSE has entered into financial arrangements to hedge
future natural gas supply costs associated with this obligation. The
Company has a maximum financial obligation under hedge agreements of $27.7
million in 2008. The Company has obligations for natural gas supply
amounting to $8.4 million in 2008 for the Tenaska plant.
As part
of its electric operations and in connection with the 1999 buyout of the Cabot
natural 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 natural 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 $4.7 million in 2008. 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 natural gas supply agreements that comprise 40% of the plant’s
requirements with remaining terms ranging of less than one year. The
obligation under this contract is $11.1 million in 2008. The Company
has other natural gas-fired generation facility obligations for natural gas
supply amounting to $19.5 million in 2008.
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
$242.9 million, $64.1 million and $4.6 million in 2008, 2009, and 2010
respectively.
Natural
Gas Supply
The
Company has also entered into various firm supply, transportation and storage
service contracts in order to ensure adequate availability of natural gas supply
for its firm customers. Many of these contracts, which have remaining
terms from less than one year to 20 years, provide that the Company must pay a
fixed demand charge each month, regardless of actual usage. The
Company contracts for all of its long-term natural gas supply on a firm basis,
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 2007 for firm natural gas supply, firm transportation service and firm
storage and peaking service of $1.8 million, $116.2 million and $9.3 million,
respectively. WNG CAP I, a PSE subsidiary, incurred demand charges in
2007 for firm transportation service of $4.3 million, which is included in the
total Company demand charges. The Company incurred demand charges in
2007 for firm transportation service for the natural gas supply for its
combustion turbines in the amount of $13.5 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)
2008
2009
2010
2011
2012
2013
& There-
after
Total
Firm
natural gas supply
$
1.0
$
0.5
$
0.5
$
0.5
$
0.0
$
--
$
2.5
Firm
transportation service
115.3
114.9
105.2
84.8
83.8
331.9
835.9
Firm
storage service
9.2
9.1
8.2
7.8
7.7
13.8
55.8
Total
$
125.5
$
124.5
$
113.9
$
93.1
$
91.5
$
345.7
$
894.2
Service
Contracts
On August30, 2001, PSE and Alliance Data Systems Corp. (Alliance Data) signed a contract
under which Alliance Data will provide data processing and billing services for
PSE. The obligations under the contract are $23.7 million in 2008,
$24.3 million in 2009, $25.0 million in 2010 and $17.0 million in
2011.
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 factored 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 is $6.5 million in 2008, $1.3
million in 2009, $1.2 million in 2010, $2.1 million in 2011, $1.4 million in
2012 and $12.5 million in the aggregate thereafter.
In March
2005, in connection with its purchase of the Hopkins Ridge wind power project,
PSE entered into an Operations, Maintenance and Warranty Agreement (OM&W
Agreement) with Vestas-American Wind Technology, Inc. (Vestas), pursuant to
which Vestas will operate, maintain, service and remedy any defects or
deficiencies in the constructed wind turbine generators (WTGs) at Hopkins Ridge
and their associated equipment on PSE’s behalf. Vestas also provides
certain warranties in relation to the availability, production and noise of the
Hopkins Ridge project. The OM&W Agreement provides for a
five-year term continuing until November 2010. The annual fee was
approximately $2.6 million in 2007 and will escalate on each January 1 during
the term by the Consumer Price Index.
In
September 2005, in connection with its purchase of the Wild Horse wind power
project, PSE entered into a Service & Maintenance Agreement and a Warranty
Agreement (the Agreements) with Vestas-American Wind Technology, Inc. (Vestas
American), pursuant to which Vestas American will operate, maintain, service and
remedy any defects or deficiencies in the constructed WTGs at Wild Horse and
their associated equipment on PSE’s behalf. Vestas American also
provides certain warranties in relation to the availability performance of the
Wild Horse project. The Agreements provide for a five-year term
continuing until November 2011. The annual fee was approximately $5.5
million in 2007 and will escalate each January 1 thereafter during the term by
the Gross Domestic Product Implicit Price Deflator (GDPIPD).
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 LIBOR. At December 31, 2007, PSE’s outstanding balance
under the lease was $48.3 million. The expected residual value under
the lease is the lesser of $37.4 million or 60.0% 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 87.0% of
the unamortized value of the equipment.
Surety
Bond
The
Company has a self-insurance surety bond in the amount of $10.1 million
guaranteeing compliance with the Industrial Insurance Act (workers’
compensation) and ten self-insurer’s pension bonds totaling $1.4
million.
Environmental
Remediation
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 (EPA), the Washington State Department of Ecology (Ecology)
and/or other third parties as potentially responsible at several contaminated
sites and manufactured natural 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 relevant sites. 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, subject to Washington Commission
review. The Company believes a significant portion of its past and
future environmental remediation costs are recoverable from insurance companies,
from third parties or from customers under a Washington Commission
order. At December 31, 2007, the Company had $1.9 million and $35.9
million in deferred electric and natural gas environmental costs,
respectively.
In
November 2006, PSE’s Crystal Mountain Generation Station had an accidental
release of approximately 18,000 gallons of diesel fuel. PSE crews and
consultants responded and worked with applicable state and federal agencies to
control and remove the spilled diesel. On July 11, 2007, PSE received
a Notice of Completion for work performed pursuant to the Administrative Order
for Removal from the EPA. The Notice stated that PSE had met the
requirements of the Order and the accompanying scope of work. Total
removal costs as of December 31, 2007 were approximately $14.0
million. PSE estimates the total remediation cost to be approximately
$15.0 million, which has been accrued or paid. At December 31, 2007,
PSE had an insurance receivable recorded in the amount of $12.6 million
associated with this fuel release. PSE received a partial payment of
$5.0 million on this receivable in January 2008. PSE has also
responded to a request for information under the Clean Water Act from the
EPA. On February 13, 2008, the Department of Justice
issued a letter to PSE seeking civil penalties pursuant to the Clean Water Act
on behalf of EPA and offering to discuss settlement of these claims as well as,
natural resource damage claims related to the diesel spill. PSE plans
to enter into such discussions with EPA. The Company believes its loss
reserve is sufficient.
Puget
Energy operates in one business segment referred to as the regulated utility
segment. The regulated utility segment includes the account
receivables securitization program. 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.
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.
Prior to
2005, InfrastruX was a reportable segment of Puget Energy. InfrastruX
was sold on May 7, 2006 and is not considered a reportable
segment. See Note 3 for InfrastruX summarized financial information
and discussion of discontinued operations.
2007
(Dollars
in Thousands)
Regulated
Utility
Other
Reconciling
Item
Puget
Energy
Total
Revenues
$
3,207,061
$
13,086
$
--
$
3,220,147
Depreciation
and amortization
279,014
208
--
279,222
Income
tax
70,794
1,788
--
72,582
Operating
income
439,433
1,601
--
441,034
Interest
charges, net of AFUDC
205,209
--
205,209
Net
income from continuing operations
184,049
627
--
184,676
Total
assets
7,513,884
84,852
--
7,598,736
Construction
expenditures - excluding equity AFUDC
737,258
--
--
737,258
2006
(Dollars
in Thousands)
Regulated
Utility
Other
Reconciling
Item
Puget
Energy
Total
Revenues
$
2,899,234
$
7,829
$
--
$
2,907,063
Depreciation
and amortization
262,129
212
--
262,341
Income
tax
96,727
(4,240
)
--
92,487
Operating
income
416,734
4,117
--
420,851
Interest
charges, net of AFUDC
168,139
--
--
168,139
Net
income from continuing operations
172,644
(5,420
)
--
167,224
Total
assets
6,993,131
72,908
--
7,066,039
Construction
expenditures - excluding equity AFUDC
749,516
--
--
749,516
2005
(Dollars
in Thousands)
Regulated
Utility
Other
Reconciling
Item
Puget
Energy
Total
Revenues
$
2,570,182
$
7,826
$
--
$
2,578,008
Depreciation
and amortization
241,385
249
--
241,634
Income
tax
85,169
871
--
86,040
Operating
income
385,816
4,481
--
390,297
Interest
charges, net of AFUDC
164,965
224
--
165,189
Net
income from continuing operations
228,030
4,293
--
232,323
Total
assets1
6,267,012
68,392
274,547
6,609,951
Construction
expenditures - excluding equity AFUDC
568,381
--
--
568,381
_______________
1
Reconciling
item consists of assets of InfrastruX which is presented as discontinued
operations.
On
October 26, 2007, Puget Energy announced that it had entered into a definitive
Agreement and Plan of Merger, dated as of October 25, 2007, pursuant to which
Puget Energy will be acquired by a consortium of long-term infrastructure
investors led by Macquarie Infrastructure Partners, the Canada Pension Plan
Investment Board and British Columbia Investment Management Corporation, and
also includes Alberta Investment Management, Macquarie-FSS Infrastructure Trust
and Macquarie Capital Group Limited (collectively, the
Consortium). At the effective time of the merger, each issued and
outstanding share of common stock of Puget Energy, other than any shares in
respect of which dissenter’s rights are perfected and other than any shares
owned by the Consortium, shall be cancelled and shall be converted automatically
into the right to receive $30.00 in cash, without interest.
The
consummation of the merger is subject to the satisfaction or waiver of certain
closing conditions, including the approval of the transaction by the affirmative
vote of two-thirds of the votes entitled to be cast thereon by Puget Energy’s
shareholders, the termination or expiration of the waiting period under the
Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (the HSR Act)
and the receipt of required regulatory approvals. On December 17,2007, PSE and the Consortium filed a joint application seeking approval of the
merger with the Washington Utilities and Transportation Commission (Washington
Commission). A decision by the Washington Commission is expected on
September 2, 2008. If approved, closing is expected to occur during
the fourth quarter 2008. On January 29, 2008, PSE and the Consortium
filed an application with FERC seeking approval of the proposed merger pursuant
to section 203 of the Federal Power Act. A decision by FERC is
expected by May 29, 2008.
The
merger agreement contains termination rights for both Puget Energy and the
Consortium under certain circumstances. In the event Puget Energy
elects to terminate the merger agreement under specified circumstances, it would
be required to pay to the acquiring entity either $30.0 million if the
termination is based on the submission of an alternative proposal meeting
certain requirements by a party with whom Puget Energy had been in discussions
prior to December 10, 2007, or $40.0 million if such fee becomes
payable in all other circumstances, plus, in each case, documented out-of-pocket
expenses of the Consortium of up to $10.0 million. In addition, Puget
Energy may be required to pay the Consortium documented out-of-pocket expenses
incurred by the Consortium not in excess of $15.0 million if the merger
agreement is terminated due to a breach of the terms of the Merger Agreement by
Puget Energy and such breach is incurable or has not been cured within a
specified time. The acquiring entity may be required to pay Puget
Energy an amount equal to $130.0 million if the merger agreement is terminated
due to a breach of the terms of the merger agreement by the acquiring entity and
such breach is incurable or has not been cured within a specified
time.
The
following discussion summarizes the status as of the date of this report of
ongoing proceedings relating to the western power markets to which PSE is a
party. PSE is vigorously defending each of these
cases. 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.
California Receivable and California
Refund Proceeding. Since 2001, PSE has held a receivable
relating to unpaid bills for power that PSE sold in 2000 into the markets
maintained by the CAISO. At December 31, 2007, the net receivable for
such sales was approximately $21.1 million. PSE’s ability to recover
all or a portion of this amount is uncertain. At this time there is
no reasonable basis under applicable financial accounting rules to adjust PSE’s
net receivable because the outcome of further court and FERC actions is
uncertain and any likely financial impact cannot be quantified.
In 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). FERC also ordered that if the refunds required by the
formula it adopted would cause a seller to recover less than its actual costs
for the refund period, the seller is allowed to document its costs and limit its
refund liability commensurately. Consistent with those orders, PSE
filed a fuel cost adjustment claim and a portfolio cost
claim. Recovery of those amounts is uncertain, but the amount owed to
PSE under all FERC orders to date is included in the PSE net receivable
amount. FERC has not issued a final order determining “who
owes how much to whom” in the California Refund Proceeding and it is not
clear when such an order will be issued.
In the
course of the California Refund Proceeding, FERC has issued dozens of
orders. Most have been taken up on appeal before the Ninth Circuit,
which has issued opinions on some issues in the last several
years. These cases are described below in the section, “California
Litigation.”
California
Litigation. Lockyer v.
FERC. 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. This case was originally presented
to FERC upon complaint that the adoption and implementation of market rate
authority was flawed. FERC dismissed the complaint after all sellers
refiled summaries of transactions with California entities during 2000 and
2001. 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 remands to FERC
the question of whether to allow refunds. On December 28, 2006, PSE
and several other energy sellers filed a petition for a writ of certiorari to
the U.S. Supreme Court, but the petition was not granted and the matter was
remanded to FERC for further proceedings on December 4, 2007. 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.
CPUC v. FERC. On
August 2, 2006, the Ninth Circuit decided that FERC erred in excluding potential
relief for tariff violations for periods that pre-dated October 2, 2000 and
additionally ruled that FERC should consider remedies for transactions
previously considered outside the scope of the proceedings. The
August 2, 2006 decision may adversely impact PSE’s ability to recover the full
amount of its CAISO receivable. The decision may also expose PSE to
claims or liabilities for transactions outside the previously defined “refund
period.” At this time the ultimate financial outcome for PSE is
unclear. Rehearing by the Ninth Circuit on this matter was sought on
November 16, 2007. The rehearing petition has not been acted
upon. In addition, parties have been engaged in court-sponsored
settlement discussions, and those discussions may result in some
settlements. PSE is unable to predict either the outcome of the
proceedings or the ultimate financial effect on PSE.
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 investigated
26 entities that allegedly had potential “partnerships” with
Enron. PSE was not named in that show cause order. On
January 22, 2004, FERC stated that it did not intend to proceed further against
other parties.
The
second show cause order 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 a nominal amount to settle all
claims. FERC approved the settlement on January 22,2004. The California parties filed for rehearing of that
order. On March 17, 2004, PSE moved to dismiss the California
parties’ rehearing request and awaits FERC action on that motion.
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 ordered
for the California markets. FERC dismissed PSE’s complaint, but PSE
challenged that dismissal. On June 19, 2001, FERC ordered price
caps on energy sales throughout the West. Various parties, including
the Port of Seattle and the cities of Seattle and Tacoma, then moved to
intervene in the proceeding seeking retroactive refunds for numerous
transactions. The proceeding became known as the “Pacific Northwest
Refund Proceeding,” though refund claims were outside the scope of the
original complaint. On June 25, 2003, FERC terminated the proceeding
on procedural, jurisdictional and equitable grounds and on November 10, 2003,
FERC on rehearing, confirmed the order terminating the proceeding. On
August 24, 2007, the Ninth Circuit issued a decision concluding that FERC should
have evaluated and considered evidence of market manipulation in California and
its potential impact in the Pacific Northwest. It also decided that
FERC should have considered purchases made by the California Energy Resources
Scheduler and/or the California Department of Water Resources in the Pacific
Northwest Proceeding. On December 17, 2007, PSE and Powerex
separately filed requests for rehearing with the Ninth Circuit of this
decision. Those requests remain pending. PSE intends to
vigorously defend its position in this proceeding, but it is unable to predict
the outcome of this matter.
Wah Chang Suit. In
June 2004, Wah Chang, an Oregon company, filed suit in federal court against
Puget Energy and PSE, among others. The complaint is similar to the
allegations made in other cases that were dismissed as having no
merit. The case was dismissed on the grounds that FERC has the
exclusive jurisdiction over plaintiff’s claims. On March 10, 2005,
Wah Chang filed a notice of appeal to the Ninth Circuit. Oral
argument took place on April 10, 2007 and the Ninth Circuit issued an opinion
affirming the lower court’s dismissal of the case on November 20,2007. Wah Chang filed a petition for rehearing; on January 15, 2008,
the Ninth Circuit denied rehearing.
Proceeding
Relating to the proposed merger
On
October 26, 2007 and November 2, 2007, two separate lawsuits were
filed against the Company and all of the members of the Company’s Board of
Directors in Superior Court in King County, Washington. The lawsuits,
respectively, are entitled, Tansey v. Puget Energy, Inc.,
et al., Case No. 07-2-34315-6 SEA and Alaska Ironworkers Pension Trust v.
Puget Energy, Inc., et al., Case No. 07-2-35346-1 SEA. The
lawsuits are both denominated as class actions purportedly on behalf of Puget
Energy’s shareholders and assert substantially similar allegations and causes of
action relating to the proposed merger. (See Note 24 for more
information regarding the proposed transaction.) The complaints
allege that Puget Energy’s directors breached their fiduciary duties in
connection with the merger and seek virtually identical relief, including an
order enjoining the consummation of the merger. Pursuant to court
order dated November 26, 2007, the two cases were consolidated for all
purposes and entitled In re
Puget Energy, Inc. Shareholder Litigation, Case No. 07-2-34315-6
SEA.
On
February 6, 2008, the parties entered into a memorandum of understanding
providing for the settlement of the consolidated lawsuit, subject to customary
conditions including completion of appropriate settlement documentation,
confirmatory discovery and court approval. Pursuant to the memorandum
of understanding, the Company has agreed to include certain additional
disclosures in its proxy statement relating to the merger. The
Company does not admit, however, that its prior disclosures were in any way
materially misleading or inadequate. In addition, the Company and the
other defendants in the consolidated lawsuit deny the plaintiffs’ allegations of
wrongdoing and violation of law in connection with the merger. The
settlement, if completed and approved by the court, will result in dismissal
with prejudice and release of all claims of the plaintiffs and settlement class
of the Company’s shareholders that were or could have been brought on behalf of
the plaintiffs and the settlement class. In connection with such
settlement, the plaintiffs intend to seek a court-approved award of attorneys’
fees and expenses in an amount up to $290,000, which the Company has agreed to
pay.
Proceedings
related to bonneville Power Administration
Petitioners
in several actions in the Ninth Circuit against BPA asserted that BPA acted
contrary to law in entering into or performing or implementing a number of
agreements, including the amended settlement agreement (and the May 2004
agreement) between BPA and PSE regarding the BPA Residential Exchange
Program. BPA rates used in such agreements between BPA and PSE for
determining the amounts of money to be paid to PSE by BPA under such agreements
during the period October 1, 2001 through September 30, 2006 have been
confirmed, approved and allowed to go into effect by
FERC. Petitioners in several actions in the Ninth Circuit against BPA
also asserted that BPA acted contrary to law in adopting or implementing the
rates upon which the benefits received or to be received from BPA during the
October 1, 2001 through September 30, 2006 period were based. The
parties to these various actions presented oral arguments to the Ninth Circuit
in November 2005. A number of parties have claimed that the BPA rates
proposed or adopted in the BPA rate proceeding to develop BPA rates to be used
in the agreements for determining the amounts of money to be paid to PSE by BPA
during the period October 1, 2006 through September 30, 2009 are contrary to law
and that BPA acted contrary to law or without authority in deciding to enter
into, or in entering into or performing or implementing such
agreements. In August 2007, BPA requested FERC to continue a stay of
FERC’s review of such rates in light of uncertainties created by the Ninth
Circuit litigation.
On May 3,2007, the Ninth Circuit issued an opinion in Portland Gen. Elec. v. BPA,
No. 01-70003, in which proceeding the actions of BPA in entering into settlement
agreements regarding the BPA Residential Exchange Program with PSE and with
other investor-owned utilities were challenged. In this opinion, the
Ninth Circuit granted petitions for review and held the settlement agreements
entered into between BPA and the investor-owned utilities being challenged in
that proceeding to be inconsistent with statute. On May 3, 2007, the
Ninth Circuit also issued an opinion in Golden Northwest Aluminum v.
BPA, No. 03-73426, in which proceeding the petitioners sought review of
BPA’s 2002-06 power rates. In this opinion, the Ninth Circuit granted
petitions for review and held that BPA unlawfully shifted onto its preference
customers the costs of its settlements with the investor-owned
utilities. On October 5, 2007, petitions for rehearing of these two
opinions were denied. On February 1, 2008, PSE and other utilities
filed in the Supreme Court of the United States a petition for a writ of
certiorari to review the decisions of the Ninth Circuit.
In May
2007, following the Ninth Circuit’s issuance of these two opinions, BPA
suspended payments to PSE under the amended settlement agreement (and the May
2004 agreement). On August 29, 2007, the Washington Commission
approved PSE’s accounting petition to defer as a regulatory asset the excess BPA
Residential Exchange benefit provided to customers and accrue monthly carrying
charges on the deferred balance from June 7, 2007 until the deferral is
recovered from customers or BPA. As of December 31, 2007, PSE has a
regulatory asset of $35.7 million. On October 11, 2007, the
Ninth Circuit remanded the May 2004 agreement to BPA in light of the Portland Gen. Elec. V. BPA
opinion and dismissed the remaining three pending cases regarding settlement
agreements. On February 8, 2008, BPA issued a notice commencing a
rate proceeding to respond to the various Ninth Circuit opinions. In
the notice, BPA proposed to adjust its Fiscal Year 2009 rates and to determine
the amounts of Residential Exchange benefits paid since 2002 that may be
recovered. BPA is proposing to determine an amount that was
improperly passed through to residential and small farm customers of PSE and the
other regional investor-owned utilities during the 2002 to 2008 rate period and
recovering this amount over time by reducing future benefits under the
Residential Exchange Program. The amount to be recovered over future
periods from PSE’s residential and small farm customers in BPA’s initial
proposal is $150.4 million. However, this is a initial proposal and
is subject to BPA’s rate case process resulting in a final decision in
approximately July. It is not clear what impact, if any, development
or review of such rates, review of such agreements and the above described Ninth
Circuit litigation may ultimately have on PSE.
The
following unaudited amounts, in the opinion of the Company, include all
adjustments (consisting of normal recurring adjustments) necessary for a fair
statement 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)
2007
Quarter
First
Second
Third
Fourth
Operating
revenues
$
1,003,904
$
661,138
$
601,680
$
953,425
Operating
income
158,060
102,048
54,488
126,438
Net
income before cumulative effect of accounting change
79,061
38,612
11,394
55,397
Net
income
79,061
38,612
11,394
55,397
Basic
earnings per common share
$
0.68
$
0.33
$
0.10
$
0.46
Diluted
earnings per common share
$
0.68
$
0.33
$
0.10
$
0.45
(Unaudited;
dollars in thousands except per share amounts)
2006
Quarter
First
Second
Third
Fourth
Operating
revenues
$
878,148
$
574,391
$
519,541
$
934,983
Operating
income
153,586
81,893
60,114
125,258
Net
income before cumulative effect of accounting change
92,520
53,529
15,922
57,156
Net
income
92,609
53,529
15,922
57,156
Basic
earnings per common share
$
0.80
$
0.46
$
0.14
$
0.49
Diluted
earnings per common share
$
0.79
$
0.46
$
0.14
$
0.49
Puget
Sound Energy
(Unaudited;
dollars in thousands)
2007
Quarter
First
Second
Third
Fourth
Operating
revenues
$
1,003,904
$
661,138
$
601,680
$
953,425
Operating
income
158,223
102,207
55,611
134,343
Net
income before cumulative effect of accounting change
78,777
38,357
12,046
61,947
Net
income
78,777
38,357
12,046
61,947
(Unaudited;
dollars in thousands)
2006
Quarter
First
Second
Third
Fourth
Operating
revenues
$
878,148
$
574,391
$
519,541
$
934,983
Operating
income
154,121
82,340
60,365
125,856
Net
income before cumulative effect of accounting change
Under the
supervision and with the participation of Puget Energy’s management, including
the President and Chief Executive Officer and Executive Vice President 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, 2007, the end of the period
covered by this report. Based upon that evaluation, the President and
Chief Executive Officer and Executive Vice President 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, 2007 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
Executive Vice President 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 Organizations 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, 2007.
Puget Energy’s effectiveness of
internal control over financial reporting as of December 31, 2007, 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 Executive Vice President 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, 2007, the end of the period covered by
this report. Based upon that evaluation, the President and Chief
Executive Officer and Executive Vice President 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, 2007, 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 Executive Vice
President 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 Organizations 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, 2007.
PSE’s
effectiveness of internal control over financial reporting as of December 31,2007 has been audited by PricewaterhouseCoopers LLP, an independent registered
public accounting firm, as stated in their report which is included
herein.
The
information called for in this item 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).
Board
of Directors
Ten
directors currently constitute the Company’s Board of Directors, which is
divided into three classes. Class I consists of four directors, Class
II consists of three directors and Class III consists of three
directors. Generally, one class of directors is elected each year to
a three-year term. Directors are elected to hold office until their
successors are elected and qualified, or until the directors’ earlier
resignation or removal. The members of Puget Energy’s Board of
Directors and Board Committees are the same as the members of PSE’s Board of
Directors and Board Committees.
Class
II – Terms Expiring in 2008
George W. Watson, age 60,
has been Executive Chairman of CriticalControl Solutions Corp. a firm offering
document imaging and workflow management software to governmental and energy
sector clients, located in Alberta, Canada since 2007. Prior to that he was
President and CEO of CriticalControl Solutions Corp. from 2003 to 2007 and
President and CEO of TransCanada Pipelines, Ltd., an energy company, from 1990
to 1999. He has been a director of Puget Energy and PSE since 2006. He also
serves on the boards of CriticalControl Solutions Corp., Canadian Spirit
Resources, Inc., Teekay Shipping LNG LLP, Badger Income Fund, Fortress Energy,
Inc. and Poplar Creek Resources, Inc.
William S. Ayer, age 53,
has been Chairman, President and Chief Executive Officer of Alaska Airlines,
Inc. and Alaska Air Group (air transportation) since 2003. He served as Alaska
Airlines’ President and Chief Operating Officer from November 1997 to January
2002, and as Chief Executive Officer from January 2002 to February 2003. Prior
to that, he served as Sr. Vice President Operations for Horizon Air, an Alaska
Airlines affiliate. Mr. Ayer has been a director of Puget Energy and PSE
since 2005. Mr. Ayer has been a director of Puget Energy and PSE
since 2005. Mr. Ayer also serves on the board of the Seattle Branch,
Federal Reserve Bank of San Francisco.
Sally G. Narodick,
age 62, is retired President of Narodick Consulting, which specialized in
strategic planning for the educational technology industry. She retired as Chief
Executive Officer of Apex Learning Inc., a venture-backed Internet distance
learning company, in 2000. Previously, she served as a Consultant on Strategic
Planning for Educational Technology software for IBM
Corporation. Ms. Narodick has been a director of Puget Energy
since its incorporation in 1999 and of PSE since 1989. Ms. Narodick also
serves as a director of Cray, Inc., Penford Corporation, SumTotal Systems, Inc.
and Solutia Inc.
Class
III – Terms Expiring in 2009
Craig W. Cole, age 58,
has been President and Chief Executive Officer of Brown & Cole Stores,
LLC (retail grocery) since 1989. Mr. Cole has served as a director of Puget
Energy and PSE since December 1999. In addition, he serves as a director of the
National Food Marketing Institute, Washington Food Industry, Brown & Cole
Stores, Inc. (and affiliated entities) and as a Regent of the University of
Washington.
Tomio Moriguchi, age 72,
has served as Chairman of Uwajimaya, Inc. (food and merchandise distributor)
since 1994. Prior to that he served as Chairman and Chief Executive Officer from
1994-2007. Mr. Moriguchi has been a director of Puget Energy
since its incorporation in 1999 and of PSE since 1988. Mr. Moriguchi also
serves as President of the Board of North American Post Publishing,
Inc.
Herbert B. Simon, age 64,
has been a member of Simon Johnson, L.L.C. (real estate and venture capital
projects investment company located in Tacoma, Washington) and its predecessor
company since 1985. Mr. Simon has served as a director of Puget Energy and
PSE since March 2006. In addition, Mr. Simon serves as a Regent of the
University of Washington.
Class
I – Terms Expiring in 2010
Phyllis J. Campbell,
age 56, was appointed the Lead Independent Director of the Boards of Puget
Energy and PSE in May of 2005. She has been President and Chief Executive
Officer of The Seattle Foundation (charitable foundation) since 2003. Prior to
that, she was Chair of the Community Board of U.S. Bank, Washington from
2001 to 2003 and President of U.S. Bank, Washington (financial institution)
from 1993 to 2001. Ms. Campbell has been a director of Puget Energy since
its incorporation in 1999 and of PSE since 1993. She also serves as a director
of Nordstrom, Inc., Alaska Air Group, Inc. and Joshua Green Corporation
(privately held).
Stephen E. Frank, age 66,
served as Chairman, President and Chief Executive Officer of Southern California
Edison (regulated utility) from 1995 until his retirement in January 2002. Prior
to that, he was President and Chief Operating Officer of Florida Power and Light
Company from 1990 to 1995. Mr. Frank has been a director of Puget Energy
and PSE since 2003. He also serves as a director of Associated
Electric & Gas Insurance Services, Northrop Grumman Corp. and
Washington Mutual, Inc.
Dr. Kenneth P. Mortimer,
age 70, is President Emeritus of the University of Hawaii and Western
Washington University. He is also Chancellor Emeritus of the University of
Hawaii at Manoa and Senior Associate of the National Center for Higher Education
Management Systems. Dr. Mortimer holds a Ph.D. degree from the University
of California at Berkeley and an MBA from the Wharton School of the University
of Pennsylvania. Dr. Mortimer has been a director of Puget Energy and PSE
since 2001.
Stephen P. Reynolds,
age 60, has been Chairman, President and Chief Executive Officer of Puget
Energy and PSE since May 2005, and was President and Chief Executive Officer
from January 2002 to April 2005. Mr. Reynolds has been a director of Puget
Energy and PSE since 2002. Mr. Reynolds also serves as a director of
Intermec, Inc. and Green Diamond Resources Company.
Executive
Officers
The
information required by this item with respect to Puget Energy is incorporated
herein by reference to the material under “Executive Officers of the
Registrants” in Part I of this report.
Audit
Committee
The Puget
Energy Board of Directors has established an Audit Committee in accordance with
section 3(a)(58)(A) of the Securities Exchange Act of 1934, as
amended. Directors Stephen E. Frank, Dr. Kenneth P. Mortimer, Sally
G. Narodick (Chair) and George W. Watson are the members of the Audit Committee.
Each
member of the Audit Committee is an independent director under SEC rules and
NYSE listing standards. The Board has determined that Ms. Narodick,
Mr. Frank and Mr. Watson meet the definition of “audit committee
financial expert” under SEC rules.
Additional
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.pugetenergy.com after the reports are electronically filed with,
or furnished to, the United States Securities and Exchange Commission
(SEC). Information may also be obtained via the SEC Internet website
at www.sec.gov.
In
addition, the following corporate governance materials of Puget Energy are
available by clicking on the section Corporate Governance at the Company’s
website www.pugetenergy.com, or a copy will be mailed to you upon written
request to Puget Energy, Inc., Investor Services, P.O. Box 97034, PSE-08N,
Bellevue, WA98009-9734, or by calling (425) 462-3898:
·
Corporate
Governance Guidelines;
·
Corporate
Ethics and Compliance Code;
·
Charters
of Board Committees; and
·
Code
of Ethics for our CEO and senior financial
officers.
If any
material provisions of our Corporate Ethics and Compliance Code or our Code of
Ethics are waived for our CEO or senior financial officers, or if any
substantive changes are made to either code as they relate to any director or
executive officer, we will disclose that fact on our website within four
business days. In addition, any other material amendments of these codes will be
disclosed.
Communications
with the Board
Shareholders
of Puget Energy and other interested parties may communicate with an individual
director or the Board of Directors as a group via U.S. Postal mail directed
to: Lead Independent Director of the Board of Directors, c/o Corporate
Secretary, Puget Energy, Inc., P.O. Box 97034, PSE-12, Bellevue, Washington98009-9734. Please clearly specify in each communication the applicable
addressee or addressees you wish to contact. All such communications will be
forwarded to the intended director or Board as a whole, as
applicable.
Section 16(a)
of the Securities Exchange Act of 1934 requires the directors and officers of
Puget Energy and PSE to file reports of ownership and changes in ownership with
respect to the equity securities of the Companies with the SEC. To the Company’s
knowledge, based on our review of the reports furnished to Puget Energy in 2007
and written representations that no other reports were required, all directors
and officers of Puget Energy who are subject to the Section 16 reporting
requirements filed the required reports on a timely basis in 2007.
Compensation
and Leadership Development Committee Interlocks and Insider
Participation
The
members of the Compensation and Leadership Development Committee are named in
their Committee Report on page 147. No members of the
Committee were officers or employees of Puget Energy or any of its subsidiaries
during the year, were formerly Puget Energy officers or had any relationship
otherwise requiring disclosure.
This
section provides information about the compensation program in place for the
Company’s named executive officers who are included in the Summary Compensation
Table on
page 148 — the CEO, the Chief Financial Officer and the four
other most highly compensated executive officers for 2007. It includes a
discussion and analysis of the overall objectives of our compensation program
and each element of compensation the Company provides.
Compensation
Program Objectives
The
Company’s executive compensation program has two main objectives:
·
Support
sustained Company performance by having talented people running the
business.
·
Align
compensation payment levels with achievement of Company
goals.
The
following is a discussion of the specific strategies used to accomplish each of
these objectives actions by the Compensation and Leadership Development
Committee (the Committee) and management to implement these
strategies.
1.
Our
objective of supporting sustained Company performance by having talented
people running the business is supported by the following
strategies:
·
Designing
and delivering compensation programs that attract, motivate, and retain a
talented executive team.
Several
factors are critical to attracting and retaining executives for the Company. One
is ensuring that total pay opportunity is competitive with similar companies so
that new executives will want to join the Company and current executives are not
hired away. As described below in the discussion of Compensation Pay Elements
(Review of Pay Element Competitiveness), the Committee annually compares
executive pay to external market data from similar companies in our industry.
Base pay and total direct compensation are targeted to the 50th percentile of
our comparator group. Individual pay adjustments are reviewed to see how they
position the executive in relation to the median of market pay, while also
considering the executive’s recent performance and experience level. The Company
may choose to pay an individual above or below the median level of market pay
when our executive has a role with greater or lesser responsibility than the
best comparison job or when our executive’s experience and performance exceed
those typically found in the market. The Committee determines the pay level for
Mr. Reynolds, the Chairman, President and CEO, and reviews and approves
Mr. Reynolds’ recommendations for pay levels of the other
executives.
Another
factor critical to motivating our executives, as well as attracting and
retaining them, is to provide incentive compensation for meeting and exceeding
target levels of annual and long-term goals. It is a highly competitive and
dynamic marketplace for talented executives, and other companies look to us when
hiring, as shown by one officer level executive recently leaving the Company. By
establishing goals, monitoring results, and providing payments and recognition
for accomplishment of results, the Company focuses executives on actions that
will improve the Company and enhance shareholder value, while also retaining key
talent.
A final
critical factor in attracting, motivating and retaining executives is providing
them with retirement income based upon annual salary and actual bonus paid, as
well as tenure. We recognize that executives choose to work for the Company from
a variety of other alternative organizations, and one financial goal of
employees is to provide a secure future for themselves and their families. The
Committee reviews the design of retirement programs provided by competing
companies and provides benefits that are commensurate with those of its
competitors.
·
Designing
and delivering incentive programs that support the Company’s business
direction as approved by the Board of Directors and align executive
interests with those of shareholders and
customers.
In
addition to rewarding performance that meets or exceeds goals, our annual and
long-term incentives help executives focus on the priorities of our shareholders
and customers. Both the annual incentive plan and the long-term incentive plan
measure and reward the Company’s performance on Service Quality Indices (SQIs).
These reporting measures were developed in collaboration with the Company’s
regulator and provide customers with a report card on the Company’s customer
service and reliability. In fact, we provide an annual accounting on these 11
measures to our customers each year. Additional key measures used for
determining incentives are Earnings Per Share (EPS) in the annual incentive plan
and Relative Total Shareholder Return (Relative TSR) in the long-term incentive
plan. EPS and Relative TSR are important shareholder performance measures, but
they also indicate to our customers that the Company will have the financial
strength needed for long-term sustainability.
·
Executing
the Company’s succession planning process to ensure that executive
leadership continues uninterrupted by executive retirements or other
personnel changes.
The
Chairman, President and CEO leads the talent reviews and succession planning
through meetings with his executive team. Each executive conducts talent reviews
of senior employees who have high potential for assuming greater responsibility
in the Company. The talent reviews include evaluations prepared within the
Company and by external organizational development consultants. The Committee
annually reviews these assessments of executive readiness, the plans for
development of the Company’s key executives, and progress made on these
succession plans. The Committee directly participates in discussion of
succession plans for the position of Chairman, President and CEO.
2.
Our
objective of aligning compensation payment levels with achievement of
Company goals is supported by the following
strategy:
·
Placing
a significant portion of each executive’s total direct compensation at
risk to align executive compensation with financial and operating
performance. Total direct compensation is base salary plus annual and
long-term incentive pay, and does not include retirement plan
accruals.
When
Company results are above expectations, total direct compensation is higher than
our target of the 50th percentile of our comparator group. If results are
below expectations, total direct compensation is lower than this targeted level.
As described above as “pay for performance,” the Company’s variable pay program
helps focus executives and creates a record of their results. When the
performance of the executive team and all employees is better than planned,
customers and shareholders benefit. Customers receive good customer service and
reliable energy supplies at the least cost. Shareholders have the opportunity to
receive dividends and increases in the value of their investment. By keeping a
significant portion of pay at risk, the Company will not pay for results unless
they are achieved. This is also why the Company targets the median pay of the
market when performance goals are met, but will pay higher when performance
exceeds targets.
Compensation
Program Elements
This
section continues the detailed discussion of the Company’s compensation program
by identifying the elements of the program and examining how these elements
function and why the Committee chooses to include the items in the compensation
program.
The
Company’s compensation policies encompass a mix of base salary, annual and
long-term incentive compensation, health and welfare benefits, retirement
programs, and a small number of perquisites. The Company also provides certain
change in control benefits to executives. The total package is designed to
provide participants with appropriate incentives that are competitive with the
comparator group and achieve current operational performance and customer
service goals as well as the long-term objective of enhancing shareholder value.
The Company does not have a specific policy regarding the mix of cash and
non-cash compensation elements, but arrives at a mix of pay by setting each
compensation element relative to market comparators. The Company delivers
compensation through cash and stock-based programs, because cash provides
liquidity for employees while stock increases the connection to shareholders.
Long-term performance-based incentives are designed to comprise the largest
portion of each executive’s incentive pay. As an example, the mix of annual
salary and annual and long-term incentive targets for the Chairman, President
and CEO in 2007, if all annual and long-term performance goals were achieved,
was 28% annual salary, 24% target annual incentive, and 48% target long-term
incentive. Annually the Committee reviews total compensation opportunity and
actual total compensation received over the prior years by each officer in the
form of a tally sheet. This review helps inform the Committee’s decisions on
program designs by allowing the Committee to review overall pay received in
relation to Company results.
Review
of Pay Element Competitiveness
In making
compensation decisions on base salary, annual and long-term incentive programs,
management prepares comprehensive surveys of pay for review by the Committee and
the Committee’s outside executive pay consultant, Towers Perrin. The surveys
summarize data provided by the Towers Perrin Energy Services survey for a
selection of utility and other companies that are most similar in scope and size
to Puget Energy. For the review of compensation pay levels and practices in
2006, we included the following utility companies that were all of similar scope
(generally $1.5 billion — $7.0 billion revenue and
$4.0 billion — $10.0 billion asset size) and also
participated in the Towers Perrin 2007 Energy Services survey:
1
Allegheny
Energy
7
MDU
Resources
13
Pinnacle
West Capital
2
Alliant
Energy
8
NSTAR
14
Portland
General Electric
3
Ameren
9
New
York Power Authority
15
SCANA
4
Atmos
Energy
10
Nicor
16
Westar
Energy
5
Avista
11
OGE
Energy
17
Wisconsin
Energy
6
Great
Plains Energy
12
PNM
Resources
Base
Salary
Base
salaries are generally targeted at the 50th percentile for the comparator
group. Actual salaries vary by individual and depend on additional factors, such
as expertise, individual performance achievement, level of experience and level
of contribution relative to others in the organization.
Generally,
base salaries for executives are administered on a subjective, individual basis
by the Committee using as a guideline, median salary levels of a select group of
electric and combination gas and electric companies and other comparable
companies from the group above, as well as internal equity among executives. We
recognize that it is necessary to provide executives with a portion of total
compensation that is delivered each month and provides a balance to other pay
elements that are at risk.
Base
Salary Adjustments
The
Committee reviewed Mr. Reynolds’ performance and, based on his results and
market comparison, his base salary for 2007 was increased from $775,000 per
year to $800,000, a 3.23% increase. For the other named executives,
Mr. Reynolds evaluated their performance during 2006 and recommended
increases to the Committee based on individual performance. The recommended
increases were similar to the range of salary increases awarded to all
employees. The Committee reviewed market comparisons and found the proposed
increases appropriate. These increases were: Mr. Valdman, a 3.02% increase
to $375,000; Ms. O’Connor, a 3.81% increase to $300,000; Ms. McLain, a
0.73% increase to $275,000; Mr. Markell, a 2.61% increase to $275,000 (Mr.
Markell also received a promotional increase of 9.09% to $300,000 when he was
promoted on May 16, 2007 to Executive Vice President and Chief Financial
Officer); and Ms. Harris, a 5.66 % increase to $280,000 (Ms. Harris also
received a promotional increase of 7.14% to $300,000 when she was promoted on
May 16, 2007 to Executive Vice President and Chief Resource
Officer).
Annual
Incentive Compensation
In
addition to reviewing base salaries paid by our market comparator group, we also
review annual incentive payments through an annual review of total cash
compensation (base salaries plus incentives). Total cash compensation is
targeted at the 50th percentile of total compensation for the industry
comparator group if the Company’s annual performance goals are achieved at
target. If performance goals significantly exceed target, total cash
compensation can approach the 75th percentile.
All PSE
employees, including executive officers, participate in an annual incentive
program referred to as the “Goals and Incentive Plan.” The plan is designed to
provide financial incentives to executives for achieving desired annual
operating results while meeting the Company’s service quality commitment to
customers. The Company’s service quality commitment is measured by performance
against Service Quality Indices (SQIs), set forth below. These are the same SQIs
for which the company is accountable to the Washington Commission.
·
Customer
Satisfaction
¾
Overall
customer satisfaction, Customer access center, Gas field services and
Washington Commission complaints
·
Customer
Service
¾
Calls
answered “live”, On-time appointments and Disconnects for
non-pay
·
Safety
and Reliability
¾
Gas
emergency response, Electric emergency response, Non-storm outage
frequency and Non-storm outage
duration
The 2007
plan had a funding level based on Earnings Per Share (EPS) and attainment of
SQIs as shown in the table below. The Committee can adjust earnings per share
used in annual incentive calculation to exclude nonrecurring items that are
outside the normal course of business for the year. Individual awards were based
on performance against team and individual goals. Individual goals were
developed from the overall corporate goals for 2007:
·
Great Customer
Service — Provide noticeably-improved service to our customers
by leveraging new systems, improving processes and enhancing employee
development and training.
·
Generation and
Delivery — Manage our existing resources and acquire needed
new ones in a way that meets customers’ needs and provides a fair return
to shareholders.
·
Be a Good
Neighbor — Through our energy efficiency, corporate giving and
employee involvement efforts, demonstrate to our key constituents and
communities that we accept leadership responsibility in the effort to make
our region better.
·
Dedication to
Employees — Focus on safety, teamwork, process improvements,
technology and controls to make the Company truly a great place to
work.
·
Own it — Each
employee should manage the resources under their control as if they owned
them.
·
Learn from the past —
Examine past practices, including significant event response efforts, and
apply lessons learned to develop and implement solutions that add value
and enhance customer service and community
involvement.
Annual
Incentive Performance Payout Scale
Performance
2007
EPS
SQI*
Funding
Level
Maximum
$1.75
10/11
205%
Target
1.57
10/11
100%
Trigger
Payout Funding
1.43
10/11
30%
_________________
*
SQI
Results of 5/11 or better required for any incentive payout funding. SQI
results below 10/11 reduces funding (e.g. 9/11 = 90%, 8/11 = 80%
etc.).
2007
Actual Performance
$1.62
9/11
106.2%
Actual
performance for 2007 was better than the target level for EPS, but below target
for SQI achievement. Puget Sound Energy EPS was $1.62, and SQI achievement was 9
out of 11, leading to a funding level of 106.2% (118% x 90% =
106.2%).
For 2007,
the target incentives for this plan varied by executive officer as shown in the
table below. The maximum incentive for exceptional performance in this plan is
twice the target incentive. The performance goals for the named executives of
PSE included EPS performance and other specified operational goals. After
considering performance on individual and team goals, which were met by each
executive officer, the following amounts were paid at 106.2% of
target:
Name
Target
Incentive
(%
of Base Salary)
2007
Actual Incentive Paid
Stephen
P. Reynolds
85%
$722,160
Bertrand
A. Valdman
60%
238,950
Eric
M. Markell
60%
175,230
Kimberly
J. Harris
60%
175,230
Jennifer
L. O’Connor
45%
143,370
Susan McLain
45%
131,423
Long-Term
Incentive Compensation
Total
direct compensation (base salary, annual incentive and long-term incentives)
opportunities are designed to be competitive with market practices, generally
targeting the 50th percentile. The Puget Energy 2005 Long Term Incentive
Plan (LTIP), approved by shareholders in 2005, provides for several forms of
multi-year incentive grants, both equity and cash-based awards. Even though the
LTIP provides many types of awards, the Company’s use of the plan typically
divides into two types of grants — annual grants of Performance Shares and
Performance-Based Restricted Stock to all eligible employees, and new employment
grants to newly hired executives. The Company does not use stock options
frequently, even though permitted under the LTIP, because the Committee believes
that performance shares and performance-based restricted stock generally have
better incentive value for executives in a utility industry
company.
The
Company makes annual grants of Performance Shares and Performance-Based
Restricted Stock to PSE executives and key employees. The table below
shows the mix of grants for the cycles that were active in 2007. Beginning with
the 2006-2008 grant cycle, the committee began granting a combination of
Performance Shares and Performance-Based Restricted Stock. The committee adopted
a mix for grants of 50% each for executive officers, except the CEO is granted
70% Performance Shares and 30% Performance-Based Restricted Stock to better
align the CEO’s pay at risk with the overall Company performance.
Grant
Cycle
Performance
Shares
Performance
Based
Restricted
Stock
2005-2007
100%
0%
2006-2008*
50%
50%
2007-2009*
50%
50%
______________
*
CEO
grants are split 70% Performance Shares and 30% Performance-Based
Restricted Stock
The
Committee establishes the number of LTIP shares that will be paid to each plan
participant by evaluating the actual payment and forecast target payment of
long-term incentive awards of our market comparator group for comparable levels
of responsibility. The Committee generally does not consider previously granted
awards or the level of accrued value from prior programs when granting annual
incentive awards or making new LTIP grants. Each year’s grant is primarily
viewed in the context of the compensation opportunity needed to maintain the
Company’s competitive position relative to the comparator group. Target
Performance Share awards are calculated based on a percentage of annual salary,
and are translated into a target number of shares using the average of the month
ending stock prices from the three months prior to the start of the performance
period. Targets for 2007 were 170% of base salary for Mr. Reynolds, 110% for
Mr. Valdman, Mr. Markell and Ms. Harris, and 95% for Ms. O’Connor and Ms.
McLain.
The
points below summarize the performance measures and design of the LTIP grants
that are currently outstanding and those which completed during
2007.
Performance
Shares:
·
A
Performance Share grant establishes a target number of shares of stock
that will be paid to the participant if the Company achieves the targeted
level of performance during the multi-year performance cycle. The actual
award paid is based on Company performance relative to target, subject to
a minimum threshold level of performance.
·
The
performance share grant is calculated based on Puget Energy’s total
shareholder return relative to the EEI Combination Gas & Electric
Investor Owned Utilities Index and performance outcomes on a set of
service quality measures during the performance period. The grant requires
a threshold performance of relative total shareholder return at the
25th percentile, and pays at target level if total shareholder return
is at the 50th percentile and 10 out of 11 SQIs are
met.
·
At
the completion of the performance cycle, if the Performance Share grant is
paid, the participant receives shares of stock and a cash payment
equivalent to the dividends that would have been paid on this number of
shares during the performance period.
·
Participants
who are meeting or exceeding shareholder ownership guidelines may elect to
receive up to 50% of the value of the Performance Shares in
cash.
·
The
Performance Shares have interim calculations (“banking”) at the end of
Year 1 for 15% of the shares, at the end of Year 2 for 25%, and at the
conclusion of the performance period in Year 3 for the remaining 60% of
the shares.
Performance-Based
Restricted Stock:
·
A
Performance-Based Restricted Stock grant is a grant of shares that vest
based on a combination of continued service and attainment of Company
performance. The Performance-Based Restricted Stock vests in installments
over a three-year period only if a target service quality measure is met
and the participant remains employed with the Company.
·
Vesting
is based on the Company meeting or exceeding 8 out of 11 SQIs and the
participant continuing employment through the vesting dates at the end of
Year 1 (15% vesting), Year 1 (25% vesting) and Year 3 (60%
vesting).
LTIP
Performance:
·
2005-2007
Grant: Overall performance on the cumulative grant for the 3 year period
was 89.5%. Performance on relative TSR was at the 45.7 percentile
versus the comparator group and the service quality measures achieved 90%
of target. The plan had a performance share banking of: 13.4% in 2005;
22.4% in 2006 and 53.7% in 2007. Notwithstanding
the Company’s overall performance relative to the comparator group, actual
payments of Performance Share awards for the 2005-2007 LTIP cycle to
certain named executives were reduced by the Committee in order to correct
overpayments to the executives of a prior year’s award resulting from a
clerical error in the computation of the relevant year’s
TSR. The 2005-2007 LTIP cycle awards were reduced, in the case
of Mr. Reynolds by 11,871 shares, in the case of Mr. Valdman by 2,277
shares, in the case of Ms. McLain by 1,327 shares, in the case of Mr.
Markell by 1,132 shares, and in the case of Ms. Harris by 1,065
shares.
·
2006-2008
Grant: Overall performance on the cumulative grant for the first two years
was 140.75%. Performance on relative TSR was 80 percentile versus the
comparator group and the service quality measures achieved 90% of target.
The plan had a performance banking of: 16.1% in 2006 and 35.2% in
2007.
·
2007-2009
Grant: Overall performance for the first year of this grant was 140.75%.
Performance on relative TSR was at the 80.0 percentile versus the
comparator group and the service quality measures achieved 90% of target.
The plan had a performance share banking of 21.1% for the first
year.
New
employment grants, usually in the form of restricted stock, performance shares,
or in one case, non-qualified stock options, are made to attract an executive to
the Company, and often are also used to replace value the candidate would
forfeit from similar awards by moving to the Company.
Timing
of Grants
The
Committee approves LTIP grants in the first quarter of the year at the regular
meeting of the Committee, which typically is within a month after the Company
has publicly released a report of its annual earnings. Due to administrative
requirements, the Committee may make the effective date of grants up to five
business days after the date of Committee action. The Committee may also make
grants of stock options or stock appreciation rights to selected executive
officers in appropriate circumstances. These circumstances would generally
include the hiring of new executives or the need to retain current executive
officers. The Company’s policy for pricing stock options is to establish the
grant price as the fair market value of Puget Energy stock on the date that the
Committee approves the grant of stock options. The LTIP defines fair market
value as the average of the high and low price for Puget Energy stock on the
date of grant. The options granted at employment for Mr. Reynolds were
priced on January 8, 2002, the date that the Committee approved
Mr. Reynolds as President and CEO. There have been no option grants to
executives since these January 8, 2002 employment option
grants.
Stock
Ownership
The
Company has established stock ownership guidelines to be achieved over a
five-year period for PSE officers and key managers. For executives, holding a
certain amount of stock relative to their current income helps to strengthen
their alignment to shareholders. The guidelines range from five times base
salary for the Chairman, President and CEO to two times base salary for the
named executive officers to 50% of base salary for other key employees. Directly
owned shares, share equivalents in the deferred compensation plan, and
contingent shares in the LTIP that are forecast to be paid, count towards
meeting the stock ownership guidelines. The Company has determined that as of
December 31, 2007, all of the Named Executive Officers met or exceeded
their guidelines. Officers and directors of the Company are not allowed to own
derivatives of Puget Energy stock, nor are they allowed to own shares in margin
accounts.
Impact
of Accounting and Tax Treatment of Compensation
The
accounting treatment of compensation generally has not been a factor in
determining the amounts of compensation for our executive officers. However, the
Company considers the accounting impact of various program designs to balance
the potential cost to the Company with the benefit/value to the executive. The
Company considers the tax impact of long-term incentive compensation awards, and
therefore to the extent practical, strives to deliver pay that qualifies under
IRS section 162(m) as performance-based to obtain a corporate tax
deduction. Under 162(m), the Company may not deduct compensation expense for the
named executives if that expense is over one million dollars, except that
performance-based pay is excluded from the total pay applying to 162(m). Our
LTIP grants of performance-based restricted stock and performance shares are
designed to meet the performance-based qualification and therefore are fully tax
deductible. Only Mr. Reynolds has pay that normally exceeds the one million
dollar level, and the majority of this pay is performance-based and qualifies
for deduction under 162(m), although Mr. Reynolds received equity awards in
prior years that were not qualified under 162(m). The Committee has the right
under the 2005 LTIP to exercise its discretion to decrease, but not to increase,
the payment amount of LTIP awards from the grant’s performance-based
calculation.
The
Company maintains the SERP for executives to provide a benefit that is
coordinated with the tax-qualified PSE Retirement Plan. Without the addition of
the SERP, these executives would receive lower percentages of replacement income
during retirement than other employees. All the Named Executive Officers except
Mr. Reynolds participate in the SERP. When Mr. Reynolds was hired, he
elected to receive an annual contribution to his account in the Deferred
Compensation Plan for Key Employees in lieu of participating in the SERP, as
described in the following paragraph. He participates in the Retirement Plan.
Additional information regarding the Retirement Plan and the SERP, as well as
current balances, is shown in the “2007 Pension Benefits” table.
Retirement
Plans — Deferred Compensation Plan
The
Company’s Named Executive Officers are eligible to participate in the Deferred
Compensation Plan. The Deferred Compensation Plan provides executives an
opportunity to defer up to 100% of base salary, annual incentive bonus and
vested performance shares, plus receive additional Company contributions made by
PSE, into an account with four investment tracking fund choices. The funds
mirror performance in major asset classes of bonds, stocks, Puget Energy stock,
and an interest crediting fund that changes rate quarterly based on corporate
bond rates. Similar to the SERP, the Deferred Compensation Plan is intended to
allow the executives to defer current income, without being limited by the
Internal Revenue Code contribution limitations for 401(k) plans. The Company
contributions are also intended to restore benefits not available to executives
under PSE’s tax-qualified plans due to Internal Revenue Code limitations on
compensation and benefits applicable to those plans. Mr. Reynolds receives
an annual Company contribution to his Deferred Compensation account equal to 15%
of the base salary and annual incentive payment he received during the prior
year. This account is a feature of Mr. Reynolds’ employment agreement.
Additional information regarding the Deferred Compensation Plan and
Mr. Reynolds’ employment agreement arrangement, as well as current
balances, is shown in the “2007 Nonqualified Deferred Compensation”
table.
Post
Termination Benefits
The
Company provides change in control agreements to its Named Executive Officers to
establish in advance the terms of payments if the Company should have a change
in control. Change of control agreements are important for two reasons. First,
many executives when joining a new company require a level of assurance that
they will receive pay in the event of a change in control after they join the
company. Secondly, the Company provides change in control agreements so that the
executive officers are focused on the Company’s ongoing operations and not
distracted by the employment uncertainty that can arise in the event of a change
in control. In 2006, the Committee reviewed and amended existing change in
control arrangements in light of benchmarking information provided by Towers
Perrin, and believes that the amended arrangements provide competitive benefits.
The change in control agreements call for accelerated vesting of equity awards
in the event of a change in control, meaning that participants will receive
accelerated vesting even if their employment continues with the new company.
Payment of severance benefits, however, requires a “double trigger” of change in
control and the executive not continuing employment with the new company, except
Mr. Reynolds’ employment agreement provides that payment of severance
benefits will be made at the time of a change in control. The “Potential
Payments Upon Termination or Change in Control” section describes the change in
control agreements with the Named Executive Officers as well as other plans and
arrangements that would provide benefits on termination of employment, and the
estimated potential incremental payments upon termination or a change in control
based on an assumed termination or change in control date of December 31, 2007.
The definitive proxy statement relating to the merger describes the anticipated
amount of such benefits that would be provided upon occurrence of the
merger.
Other
Compensation
In
addition to base salary and annual and long-term incentive award opportunities,
the Company also provides the Named Executive Officers with benefits and
perquisites targeted to competitive practices. The executives participate in the
same group health and welfare plans as other employees. Company vice presidents
and above, including the executives, are eligible for additional disability and
life insurance benefits. The executives are also eligible to receive
reimbursement for financial planning, tax preparation, and legal services,
business club memberships and executive physicals. The reimbursement for
financial planning, tax preparation, and legal services is provided to allow
executives to concentrate on their business responsibilities. Business club
memberships are provided to allow access for business meetings and business
events at club facilities and executives are required to reimburse the Company
for individual use of club facilities. Perquisites do not make up a significant
portion of executive compensation, amounting to less than $10,000 in total for
each executive in 2007.
Relationship
Among Compensation Elements
A number
of compensation elements increase in absolute dollar value as a result of
increases to other elements. Base salary increases translate into higher dollar
value incentive opportunity for annual and long-term incentives, because each
plan operates with a target level award set as a percentage of base salary. Base
salary increases also increase the level of retirement benefits, as do actual
annual incentive plan payments. Some key compensation elements are excluded from
consideration when determining other elements of pay. Retirement benefits
exclude LTIP payments in the calculation of qualified retirement (pension and
401(k)) and SERP benefits.
The Board
of Directors of Puget Energy delegates responsibility to the Compensation and
Leadership Development Committee to establish and oversee the Company’s
executive compensation program. For a discussion of the Committee’s policies and
procedures, see the “Compensation and Leadership Development Committee”. Each
member of the committee meets the independence requirements of the SEC and the
NYSE.
The
Compensation and Leadership Development Committee has reviewed and discussed the
“Compensation Discussion and Analysis” with the Company’s management. Based on
this review and discussion, the committee recommended to the Board of Directors,
and the Board has approved, that the “Compensation Discussion and Analysis” be
included in the Company’s Annual Report on Form 10-K for the year ended
December 31, 2007 for filing with the SEC.
The
following information is furnished for the year ended December 31, 2007
with respect to the “Named Executive Officers” during 2007. The positions and
offices below are at Puget Energy and PSE, except that Mr. Valdman, Ms.
Harris and Ms. McLain are officers of PSE only. Salary compensation
includes amounts deferred at the officer’s election.
Name
and Principal Position
Year
Salary
Bonus
Stock
Awards1
Option
Awards1
Non-Equity
Incentive Plan Compensation2
Change
in Pension Value and Above Market DCP3
All
Other Compensation4
Total
Stephen
P.
Reynolds
Chairman,
President and Chief Executive Officer
2007
$794,896
$ --
$2,949,696
$ --
$722,160
$ 20,328
$330,647
$4,817,727
2006
769,901
--
1,757,969
99,793
614,672
28,882
277,221
3,548,438
Bertrand
A.
Valdman
Executive
Vice President and Chief Operating Officer
2007
$372,754
$ --
$ 747,622
$ --
$238,950
$107,558
$ 48,111
$1,514,995
2006
361,142
--
327,578
--
230,958
100,208
50,225
1,070,111
Eric
M.
Markell
Executive
Vice President and Chief Financial Officer
2007
$288,154
$ --
$ 447,382
$ --
$175,230
$175,460
$ 31,968
$1,118,194
2006
266,264
--
178,994
--
127,534
160,913
32,906
766,611
Susan
McLain
Senior
Vice President Operations
2007
$274,592
$ --
$ 454,672
$ --
$131,423
$ 85,929
$ 28,517
$ 975,133
2006
271,367
--
182,559
--
129,914
189,127
30,309
803,276
Jennifer
L.
O'Connor
Senior
Vice President and General Counsel, Chief Ethics and Compliance
Officer
2007
$297,754
$ --
$ 348,608
$ --
$143,370
$125,354
$
29,002
$ 944,088
2006
287,163
--
166,226
--
137,528
122,079
32,192
745,188
Kimberly
J.
Harris
Executive
Vice President and Chief Resource Officer
2007
$288,604
$ --
$ 315,034
$ --
$175,230
$ 74,582
$ 22,876
$ 876,326
2006
262,346
--
142,777
--
126,107
102,350
21,521
655,101
_______________
1
Reflects
accounting expense recognized during the year for all outstanding stock
awards, in accordance with SFAS No. 123R. This includes amounts
recognized for grants of performance-based LTIP awards made in and prior
to the year. The actual payment of the LTIP grants depends on Company
performance and requires a threshold performance before any payment is
made. Assumptions used in the calculation of these amounts are included in
footnote 16 to the Company’s audited financial statements for the
fiscal year ended December 31, 2007 included in the Company’s
Form 10-K filed with the SEC on February 29, 2008 (the “2007 Form
10-K”). A description of the LTIP grants appears in the “Compensation
Discussion and Analysis” section and the estimated threshold, target and
maximum amounts that might be paid for the 2007 LTIP grants is set forth
in the “2007 Grants of Plan-Based Awards” table. For Mr. Reynolds in 2006,
$99,793 represents accounting expense related to his stock options that
were fully vested in 2006.
2
Reflects
annual cash incentive compensation paid under the 2007 Goals &
Incentive Plan. These amounts are based on performance in 2007, but were
determined by the Compensation and Leadership Development Committee in
February 2008 and paid shortly thereafter or deferred at the officer’s
election. The 2007 Goals & Incentive Plan is described in further
detail under “Compensation Discussion and Analysis”. The threshold, target
and maximum amounts of annual cash incentive compensation that might have
been paid for 2007 performance is set forth in the “2007 Grants of
Plan-Based Awards” table.
3
Reflects
the aggregate increase in the actuarial present value of the officer’s
accumulated benefit under all pension plans during the year. The amounts
are determined using interest rate and mortality rate assumptions
consistent with those used in the Company’s financial statements and
includes amounts which the officer may not currently be entitled to
receive because such amounts are not vested. Information regarding these
pension plans is set forth in further detail under “2007 Pension
Benefits”. Mr. Reynolds does not participate in the SERP, and his
accumulated benefit shown is only from the qualified pension plan. Also
included in this column are the portion of Deferred Compensation Plan
earnings that are considered above market. These amounts for 2007 are:
Mr. Reynolds $420, Ms. O’Connor, $544; Ms. McLain, $315;
and Mr. Markell $252. These amounts for 2006 are: Mr. Reynolds, $423;
Ms. O’Connor, $567; Ms. McLain, $226; and Mr. Markell, $244. See the ”2007
Non-Qualified Deferred Compensation” table for all Deferred Compensation
Plan earnings.
4
All
Other Compensation is shown in detail on the table
below.
Detail
of All Other Compensation
Name
Perquisites
and
Other
Personal Benefits1
Tax
Reimbursements
Discounted
Securities Purchases
Payments/
Accruals
on Termination
Plans
Registrant
Contributions
to
Defined
Contribution Plans2
Insurance
Premiums
Other3
Stephen
P. Reynolds
$ 6,418
$ --
$ --
$ --
$
321,391
$ --
$
2,838
Bertrand
A. Valdman
9,367
--
--
--
37,636
--
1,108
Eric
M. Markell
3,597
--
--
--
27,141
--
1,230
Susan
McLain
--
--
--
--
26,241
--
2,276
Jennifer
L. O’Connor
2,000
--
--
--
26,317
--
685
Kimberly
J. Harris
6,332
--
--
--
15,536
--
1,007
_______________
1
Annual
reimbursement for financial planning, tax planning, and/or legal planning,
up to a maximum of $5,000 for Mr. Reynolds and Mr. Valdman,
$2,500 for other Named Executive Officers. During an executive’s initial
year, the reimbursement for financial, tax, and legal planning is higher,
recognizing the cost of the initial plans. None of the Named Executive
Officers received benefits for the initial plan, but if they had, the
maximum reimbursement would have been $9,500 financial planning and $5,000
legal (Mr. Reynolds and Mr. Valdman); $5,000 financial planning
and $2,500 legal (other executives). Club use is primarily for business
purposes, but Company club expense is included where the executive is also
able to use the club for personal use. Expenses for personal club use are
directly paid by the executive, not PSE.
2
Includes
Company contributions during 2007 to PSE’s Investment Plan (a tax
qualified 401k plan) and the Deferred Compensation Plan. For
Mr. Reynolds, this includes the Company contribution to the
Performance-Based Retirement Equivalent Stock Account, which is described
in more detail in the “2007 Nonqualified Deferred Compensation”
section.
3
Other
column includes:
Stephen
P. Reynolds
$2,838
imputed income of life insurance
Bertrand
A. Valdman
$1,108
imputed income on life insurance
Eric
M. Markell
$1,230
imputed income on life insurance
Susan
McLain
$2,276
imputed income on life insurance
Jennifer
L. O’Connor
$685
imputed income on life insurance
Kimberly
J. Harris
$1,007
imputed income on life insurance
2007
Grants of Plan-Based Awards
The
following table presents information regarding 2007 grants of annual incentive
awards and LTIP awards, including the range of potential payouts for the annual
incentive awards and performance share awards.
Estimated
Future Payouts under Non-Equity
Incentive
Plan Awards
Estimated
Future Payouts under Equity
Incentive
Plan Awards
Name
Grant
Date
Threshold
Target
Maximum
Threshold
Target
Maximum
Grant
Date
Fair
Market
Value
Stephen
P. Reynolds
Annual
Incentive (1)
1/1/2007
$
204,000
$
680,000
$
1,672,800
n/a
LTIP
PS (2)
3/1/2007
13,607
45,355
79,371
$
1,127,979
LTIP
RS (3)
3/1/2007
16,525
16,525
410,977
Bertrand
A. Valdman
Annual
Incentive (1)
1/1/2007
$
67,500
$
225,000
$
553,500
n/a
LTIP
PS (2)
2/28/2007
2,948
9,826
17,196
$
242,407
LTIP
RS (3)
2/28/2007
8,354
8,354
206,093
Eric
M. Markell
Annual
Incentive (1)
1/1/2007
$
49,500
$
165,000
$
405,900
n/a
LTIP
PS (2)
2/28/2007
1,867
6,223
10,890
$
153,521
LTIP
RS (3)
2/28/2007
5,291
5,291
130,529
Susan
McLain
Annual
Incentive (1)
1/1/2007
$
37,125
$
123,750
$
304,425
n/a
LTIP
PS (2)
2/28/2007
2,192
7,306
12,786
$
180,239
LTIP
RS (3)
2/28/2007
5,291
5,291
130,529
Jennifer
L. O’Connor
Annual
Incentive (1)
1/1/2007
$
40,500
$
135,000
$
332,100
n/a
LTIP
PS (2)
2/28/2007
2,037
6,789
11,881
$ 167,485
LTIP
RS (3)
2/28/2007
5,772
5,772
142,395
Kimberly
J. Harris
Annual
Incentive (1)
1/1/2007
$
49,500
$
165,000
$
405,900
n/a
LTIP
PS (2)
2/28/2007
1,901
6,336
11,088
$
156,309
LTIP
RS (3)
2/28/2007
5,387
5,387
132,897
_______________
1
Annual
Goals and Incentive Plan. As described in the “Compensation Discussion and
Analysis”, the plan has dual funding triggers in 2007 of $1.43 EPS and SQI
performance of 5/11. Payment would be $0 if either trigger is not met. The
threshold estimate assumes $1.43 EPS and SQI performance at 10/11. The
target estimate assumes $1.57 EPS and SQI performance at 10/11. The
maximum estimate assumes $1.76 EPS or higher and SQI performance at
11/11.
2
LTIP
Performance Shares for 2007-2009. As described in the “Compensation
Discussion and Analysis”, Performance Shares are calculated at the end of
the three year performance period based on Company results in relative TSR
and SQI performance. Threshold estimate assumes that Puget Energy’s TSR is
below the 25th percentile of the comparison group and the SQI result
is 10/11, for an overall payment of 30% of target. Target estimate assumes
that Puget Energy’s TSR equals the 50th percentile of the comparison
group and the SQI result is 10/11, for an overall payment of 100% of
target. Maximum estimate assumes that Puget Energy's TSR is at or above
the 85th percentile of the comparison group and the SQI result is
10/11, for an overall payment of 175% of target. Payments of Performance
Shares vary significantly and have paid at the following percentages of
target: 2000-2003, 110%, 2001-2004, 30%, 2002-2005, 20%, 2003-2006, 0%,
2004-2006, 17.5% and 2005-2007, 89.5%.
3
LTIP
Performance-Based Restricted Stock for 2007-2009. As described in the
“Compensation Discussion and Analysis”, the 2007-2009 plan included two
types of awards. The Performance-Based Restricted Stock grants vest based
on achievement of 8/11 SQIs and continued service during the performance
cycle. Target and Maximum estimates both assume that all shares
vest.
4
Grant
Date Fair Value is calculated as the target number of shares at the
closing price of Puget Energy stock on March 1, 2007 of $24.87 for
Mr. Reynolds and February 28, 2007 of $24.67 for the other Named Executive
Officers.
Outstanding
Equity Awards at 2007 Fiscal Year-End
The
following table provides information regarding outstanding stock options and
unvested stock awards held as of December 31, 2007.
Name
Number
of Securities Underlying Unexercised Options
Exercisable
Number
of
Securities
Underlying
Unexercised Options
Unexercisable
Equity
Incentive
Plan
Awards:
Number
of Securities Underlying Unexercised Unearned Options
Option
Exercise
Price
Option
Expiration
Date
Number
of Shares or
Units
of
Stock
Held
that
Have Not Vested
Market
Value
of
Shares or
Units
of Stock Held that
Have
Not
Vested
Equity
Incentive
Plan
Awards:
Number of Unearned Shares,
Units
or
Other
Rights
That Have Not Vested
Equity
Incentive
Plan Awards:
Market
or
Payout
Value
of
Unearned Shares, Units
or
Other
Rights
That
Have
Not
Vested
Stephen
P. Reynolds
(1)
300,000
0
0
$22.51
1/8/2012
40,000
$1,097,200
(2)
40,000
$1,097,200
(3)
25,790
707,410
73,195
2,007,746
(4)
9,570
262,502
83,848
2,299,940
Bertrand
A. Valdman
(5)
2,000
$ 54,860
(3)
5,785
158,683
19,706
$ 540,537
(4)
2,073
56,870
22,223
609,580
Eric
M. Markell
(3)
3,679
$ 102,787
12,764
$ 350,123
(4)
1,313
36,017
14,075
386,065
Susan
McLain
(3)
3,747
$ 98,378
12,925
$ 354,532
(4)
1,313
36,017
14,075
386,065
Jennifer
L. O’Connor
(3)
3,967
$ 108,808
12,545
$ 344,102
(4)
1,432
39,293
13,955
382,789
Kimberly
J. Harris
(3)
3,637
$ 99,776
12,390
$ 339,866
(4)
1,337
36,671
14,330
393,073
_______________
1
Stock
Option awards granted 1/8/2002. Restricted Stock and Restricted
Stock Unit Awards vest 15,000 shares 1/8/2008, and 25,000 shares May 6,2008.
2
Performance-Based
Restricted Stock grant will vest all 40,000 shares May 6,2008.
3
Long-Term
Incentive Plan grant for 2006-2008 cycle is forecast to finish between
target and maximum. Figures are shown at maximum.
4
Long-Term
Incentive Plan grant for 2007-2009 cycle is forecast to finish between
target and maximum. Figures are shown at
maximum.
5
Restricted
Stock award granted at hire will have remaining 2,000 shares vest
12/4/2008.
Stock
Vested in 2007
The
following table provides information regarding vesting of stock awards during
2007. No stock options were exercised during 2007.
Stock
Award
Name
Number
of Shares Acquired on Vesting
Value
Realized on Vesting
Stephen
P. Reynolds 1,2
69,063
$
1,894,398
Bertrand
A. Valdman 2,3
22,661
621,591
Eric
M. Markell 2
13,536
371,292
Susan
McLain 2
13,631
373,898
Jennifer
L. O'Connor 2
9,823
269,456
Kimberly
J. Harris
7,562
207,426
_______________
1
Vesting
of 8,000 shares of employment grant restricted stock on
1/8/2007.
2
Payment
of 2005-2007 LTIP cycle at 89.5% of target and vesting of 25% of 2006-2008
and 15% vesting of 2007-2009 Performance-Based Restricted Stock
grants.
3
Vesting
of part of employment grant Restricted
Stock
2007
Pension Benefits
Puget
Energy, PSE and its affiliates maintain two pension plans: the
Retirement Plan for Employees of Puget Sound Energy, Inc. (the “Retirement
Plan”) and the Puget Sound Energy, Inc. Supplemental Executive Retirement Plan
(the “SERP”). The following table provides information for each of the Named
Executive Officers regarding the actuarial present value of the officer’s
accumulated benefit and years of credited service under the Retirement Plan and
the SERP. The present value of accumulated benefits was determined using
interest rate and mortality rate assumptions consistent with those used in the
Company’s financial statements. Except as described below in footnote (1),
relating to Mr. Reynolds, each of the Named Executive Officers participates
in both plans.
Mr. Reynolds
participates in the Retirement Plan, but does not participate in the SERP.
In lieu of participating in the SERP, Mr. Reynolds receives an annual
credit of performance-based stock equivalents to a Performance-Based
Retirement Equivalent Stock Account in the Deferred Compensation Plan. The
value of this account at December 31, 2007 is shown in the “2007
Nonqualified Deferred Compensation Plan” table and the stock equivalent
program is further described in the narrative text accompanying that
table.
2
The
amounts reported in this column for each officer were calculated assuming
no future service or pay increases. Present values were calculated
assuming no pre-retirement mortality or termination. The values under the
Retirement Plan and the SERP are the actuarial present values as of
December 31, 2007 of the benefits earned as of that date and payable
at normal retirement age (age 65 for the Retirement Plan and
age 62 for the SERP). Future cash balance interest credits were
assumed to average 6.5% annually. The discount assumption is 6.3%,
and the post-retirement mortality assumption is based on the 1994 Group
Annuity Reserving Table (unisex). An applicable interest rate of 6% is
assumed for the purpose of converting annuity benefits to lump sum amounts
at retirement. These assumptions are consistent with the ones used for the
Retirement Plan and the SERP for financial reporting purposes. In order to
determine the change in pension values for the “Summary Compensation”
table, the values of the Retirement Plan and the SERP benefits were also
calculated as of December 31, 2006 for the benefits earned as of that
date. The discount assumption used in that calculation was 5.8%, which is
the assumption used for financial reporting purposes for 2006. Other
assumptions used to determine the value as of December 31, 2006 were
the same as those used for December 31, 2007.
3
As
described in footnote (2) above, the amounts reported for the SERP in
this column are actuarial present values, calculated using the actuarial
assumption used for financial reporting purposes. These assumptions are
different from those used to calculate the actual amount of benefit
payments under the SERP (see text below for a discussion of the actuarial
assumptions used to calculate actual payment amounts). For each
SERP-eligible Named Executive Officer who was vested in his or her SERP
benefit as of December 31, 2007, the following table shows the
estimated lump sum amount that would be paid to the Named Executive
Officer at age 62 (without discounting to the present), calculated as
if such Named Executive Officer had terminated employment on
December 31, 2007. For those Named Executive Officers who were not
vested in their SERP benefits as of December 31, 2007, the following
table reflects the fact that they are not yet vested by showing their
age 62 lump sum SERP benefit as
$0.
Executive
Lump
Sum
Vested
Amount
Bertrand
A. Valdman
$
776,663
$
776,663
Eric
M. Markell
678,005
678,005
Susan
McLain
1,831,756
1,831,756
Jennifer
L. O'Connor
625,626
--
Kimberly
J. Harris
900,255
900,255
Retirement
Plan
Under the
Retirement Plan, Puget Energy’s and PSE’s eligible salaried employees, including
the Named Executive Officers, accrue benefits in accordance with a cash balance
formula, beginning on the later of their date of hire or March 1, 1997. Under
this formula, for each calendar year after 1996, age-weighted pay credits are
allocated to a bookkeeping account (a “Cash Balance Account”) for each
participant. The pay credits range from 3% to 8% of eligible compensation.
Eligible compensation generally includes base salary and bonuses (other than
bonuses paid under the Puget Sound Energy Long Term Incentive Program for Senior
Management, signing, retention and similar bonuses), up to the limit imposed by
the Internal Revenue Code. For 2007, the Internal Revenue Code compensation
limit was $225,000. For 2008, it is $230,000. In addition, as of March 1, 1997,
the Cash Balance Account of each participant who was participating in the
Retirement Plan on March 1, 1997 was credited with an amount based on the
actuarial present value of that participant’s accrued benefit, as of
February 28, 1997, under the Retirement Plan’s previous
formula.
Amounts
in the Cash Balance Accounts are also credited with interest. The interest
crediting rate is 4% per year or such higher amount as PSE may determine.
For 2007 and 2008 the annual interest crediting rate is 6.5%.
A
participant’s Retirement Plan benefit generally vests upon the earlier of the
participant’s completion of three years of active service with Puget Energy, PSE
or their affiliates or attainment of age 65 (the Retirement Plan’s normal
retirement age). Normal retirement benefit payments begin to a vested
participant as of the first day of the month following the later of the
participant’s termination of employment or attainment of age 65. However, a
vested participant may elect to have his or her benefit under the Retirement
Plan paid, or commence to be paid, as of the first day of any month commencing
after the date on which his or her employment with Puget Energy, PSE and their
affiliates terminates. If benefit payments commence prior to the participant’s
attainment of age 65, then the amount of the monthly payments will be
reduced for early commencement to reflect the fact that payments will be made
over a longer period of time. This reduction is subsidized — that is, it is
less than a pure actuarial reduction. The amount of this reduction is, on
average, 0.30% for each of the first 60 months, 0.33% for each of the
second 60 months, 0.23% for each of the third 60 months and 0.17% for
each of the fourth 60 months that the payment commencement date precedes
the participant’s 65th birthday. Further reductions apply for each
additional month that the payment commencement date precedes the participant’s
65th birthday. As of December 31, 2007, all the Named Executive
Officers vested in their benefits under the Retirement Plan.
The
normal form of benefit payment for unmarried participants is a straight life
annuity providing monthly payments for the remainder of the participant’s life,
with no death benefits. The straight life annuity payable on or after the
participant's normal retirement age is actuarially equivalent to the balance in
the participant’s Cash Balance Account as of the date of distribution. For
married participants, the normal form of benefit payment is an actuarially
equivalent joint and 50% survivor annuity with a “pop-up” feature providing
reduced monthly payments (as compared to the straight life annuity) for the
remainder of the participant’s life and, upon the participant’s death, monthly
payments to the participant’s surviving spouse for the remainder of the spouse’s
life in an amount equal to 50% of the amount being paid to the participant.
Under the pop-up feature, if the participant’s spouse predeceases the
participant, the participant’s monthly payments increase to the level that would
have been provided under the straight life annuity. In addition, the Retirement
Plan provides several other annuity payment options and a lump sum payment
option that can be elected by participants. All payment options are actuarially
equivalent to the straight life annuity. However, in no event will the amount of
the lump sum payment be less than the balance in the participant’s Cash Balance
Account as of the date of distribution (in some instances the amount of the lump
sum distribution may be greater than the balance in the Cash Balance Account due
to differences in the morality table and interest rates used to calculate
actuarial equivalency) birthday. Further reductions apply for each additional
month that the payment commencement date precedes the participant’s
65th birthday.
If a
participant in the cash balance portion of the Retirement Plan dies while
employed by the Company, PSE or any of their affiliates, then his or her
Retirement Plan benefit will be immediately vested. If a vested participant dies
before his or her Retirement Plan benefit is paid, or commences to be paid, then
the participant’s Retirement Plan benefit will be paid to his or her
beneficiary(ies). If a participant dies after his or her Retirement Plan benefit
has commenced to be paid, then any death benefit will be governed by the form of
payment elected by the participant.
Supplemental
Executive Retirement Plan
The SERP
provides a benefit to participating executives that supplements the retirement
income provided to such executives by the Retirement Plan. PSE designates which
executives are eligible to participate in the SERP. As discussed in the
Compensation Discussion and Analysis on page 145, Mr. Valdman, Mr. Markell, Ms. Harris,
Ms. O’Connor and Ms. McLain participate in the
SERP.
A
participant’s SERP benefit generally vests upon the participant’s completion of
five years of participation in the SERP while employed by Puget Energy, PSE or
any of their affiliates. Mr. Markell, Ms. Harris and Ms. McLain are vested in
SERP benefit based on their years of service. By agreement with PSE,
Mr. Valdman became vested in his SERP benefit on the date he was hired. The
monthly benefit payable under the SERP to a vested participant (calculated in
the form of a straight life annuity payable for the participant’s lifetime
commencing at the later of the participant’s date of termination or attainment
of age 62) is equal to (1) below minus the sum of (2) and
(3) below:
(1)
One-twelfth
(1/12) of the participant’s highest average earnings times the
participant’s years of credited service (not in excess of 15) times
3--1/3%. For purposes of the SERP, “highest average earnings” means the
average of the participant’s highest three calendar years of earnings. The
three calendar years do not have to be consecutive, but they must be among
the last five calendar years completed by the participant prior to his or
her termination. “Earnings” for this purpose include base salary and
annual bonus, but do not include long-term incentive compensation. A
participant will receive one “year of credited service” for each
consecutive 12-month period he or she is employed by Puget Energy, PSE or
their affiliates. If a participant becomes entitled to disability benefits
under PSE’s long-term disability plan, then the participant’s highest
average earnings will be determined as of the date the participant became
disabled, but the participant will continue to accrue years of credited
service until he or she begins to receive SERP
benefits.
(2)
The
monthly amount payable (or that would be payable) under the Retirement
Plan to the participant in the form of a straight life annuity commencing
as of the first day of the month following the later of the participant’s
date of termination or attainment of age 62.
(3)
The
actuarially equivalent monthly amount payable (or that would be payable)
to the participant as of the first day of the month following the later of
the participant’s date of termination or attainment of age 62 from
any pension-type rollover accounts (including the Annual Cash Balance
Restoration Account) within the Deferred Compensation Plan. These accounts
are described in more detail in the “2007 Nonqualified Deferred
Compensation” section.
Normal
retirement benefits under the SERP generally are paid or commence to be paid as
of the first day of the month following the later of the participant’s
termination of employment or attainment of age 62. Except as provided
below, SERP benefits are normally paid in a lump sum that is equal to the
actuarial present value of the monthly straight life annuity benefit. A
participant may elect to have this lump sum transferred to the Deferred
Compensation Plan, rather than paid directly to the participant, after which it
will be paid in accordance with the provisions of the Deferred Compensation
Plan. In lieu of the normal form of payment, a participant may elect to receive
his or her SERP benefit in the form of monthly installment payments over a
period of two to 20 years, in a straight life annuity or in a joint and
survivor annuity with a 100%, 50% or 25% survivor benefit. All payment options
are actuarially equivalent to the straight life annuity. SERP benefits that were
vested as of December 31, 2004 (Pre-2005 SERP Benefits) are normally paid in the
form of a straight life annuity for single participants and in the form of an
actuarially equivalent joint and 50% surviving spouse annuity for married
participants. However, participants can elect any of the payment options
described above for their Pre-2005 SERP Benefits. Of the Named Executive
Officers, only Ms. McLain has Pre-2005 SERP Benefits. Mr. Markell is the
only Named Executive Officers eligible for early retirement benefit payments
under the SERP. Payments to the participant following termination of employment
of SERP benefits other than Pre-2005 SERP Benefits are generally delayed for six
months in accordance with the requirements of Section 409A of the Internal
Revenue Code.
If a
participant dies while employed by Puget Energy, PSE or any of their affiliates
or after becoming vested in his or her SERP benefit, but before his or her SERP
benefit has commenced to be paid, then the participant’s surviving spouse will
receive a lump sum benefit equal to the actuarial equivalent of the survivor
benefit such spouse would have received under the joint and 50% surviving spouse
annuity option. This amount will be calculated assuming the participant would
have commenced benefit payments in that form on the first day of the month
following the later of his death or attainment of age 62. The lump sum
benefit will then be reduced by one-third of one percent (1/3%) for each month
by which the participant’s date of death preceded what would have been his
62nd birthday. Distribution will be made to the participant’s surviving
spouse as soon as administratively practicable after the participant’s death. If
the participant is not married, then no death benefit will be paid. If a
participant dies after his or her SERP benefit has commenced to be paid, then
any death benefit will be governed by the form of payment elected by the
participant.
2007
Nonqualified Deferred Compensation
The
following table provides information for each of the Named Executive Officers
regarding aggregate executive and Company contributions and aggregate earnings
for 2007 and year-end account balances under the Deferred Compensation
Plan.
Name
Executive
Contributions
in
Last FY1
Registrant
Contributions
in
Last FY2
Aggregate
Earnings
in
Last
FY3
Aggregate
Withdrawals/
Distributions4
Aggregate
Balance
at
Last FYE5
Stephen
P. Reynolds
$
97,265
$
306,274
$
231,201
$
70,150
$
2,304,489
Bertrand
A. Valdman
32,797
21,936
8,910
--
160,054
Eric
M. Markell
17,755
13,250
13,536
--
187,794
Susan
McLain
41,131
13,516
49,238
--
553,261
Jennifer
L. O'Connor
10,617
10,617
13,592
--
249,566
Kimberly
J. Harris
--
--
19,937
--
187,511
_______________
1
The
amount in this column for each executive reflects elective deferrals by
the officer of salary, annual incentive compensation or vested performance
shares paid in 2007, the following amounts of salary: Mr. Reynolds,
$53,258; Mr. Valdman, $24,967; Mr. Markell, $17,755; Ms. McLain, $32,073;
Ms. O’Connor, $10,617; and Ms. Harris, $0. The following amounts of
incentive compensation: Mr. Reynolds, $44,007; Mr. Valdman, $7,830; Mr.
Markell, $0; Ms. McLain, $9,058; Ms. O’Connor, $0, and Ms. Harris,
$0.
2
The
amount reported in this column for each executive reflects contributions
by PSE consisting of the Annual Investment Plan Restoration Amount and
Annual Cash Balance Restoration Amount. For Mr. Reynolds, the amount
also includes $234,617 in value of performance-based stock equivalents
credited in the Deferred Compensation Plan’s Performance-Based Retirement
Equivalent Stock Account and calculated pursuant to his employment
agreement based on the closing price of Puget Energy stock on January 8,2007 of $24.76. These amounts are also included in the total amounts shown
in the All Other Compensation column of the “Summary Compensation”
table.
3
The
amount in this column for each officer reflects dividends on deferred
stock units and the change in value of other investment tracking
funds.
4
The
amount in this column for Mr. Reynolds reflects a scheduled interim
payment pursuant to the terms of the Deferred Compensation
Plan.
5
The
amount reported in this column for each executive includes stock unit
values based on the closing price of Puget Energy stock on
December 31, 2007 of $27.43. The aggregate balance for
Mr. Reynolds includes $236,888 of unvested performance-based stock
equivalents credited in the Deferred Compensation Plan’s Performance-Based
Retirement Equivalent Stock Account. The following amounts of salary from
2006 are included: Mr. Reynolds, $56,592; Mr. Valdman, $26,558; Mr.
Markell, $18,913; Ms. McLain, $27,421; Ms. O’Connor, $21,573; and Ms.
Harris, $0. The following amounts of incentive compensation from 2006 are
included: Mr. Reynolds, $53,200; Mr. Valdman, $10,013; Mr. Markell, $0;
Ms. McLain, $5,138; Ms. O’Connor, $475; and Ms. Harris, $0. The following
amounts of registrant contributions from 2006 are included: Mr. Reynolds,
$249,815; Mr. Valdman, $26,195; Mr. Markell, $14,020; Ms. McLain, $15,111;
and Ms. Harris, $0.
Deferred
Compensation Plan
The Named
Executive Officers are eligible to participate in the PSE Deferred Compensation
Plan.
Participants
may defer up to 100% of base salary, annual incentive compensation and vested
performance shares. In addition, each year, participants are eligible to receive
Company contributions to restore benefits not available to them under PSE’s
tax-qualified plans due to limitations imposed by the Internal Revenue Code. The
Annual Investment Plan Restoration Amount equals the additional matching
contribution under the 401(k) plan that would have been credited to a
participant's 401(k) plan account if the Internal Revenue Code limitations were
not in place and if deferrals under the Deferred Compensation Plan were instead
made to the 401(k) plan. The Annual Cash Balance Restoration Amount equals the
actuarial equivalent of any reductions in a participant's accrued benefit under
the Retirement Plan due to Internal Revenue Code limitations or as a result of
deferrals under the Deferred Compensation Plan. A participant must generally be
employed on the last day of the year to receive these Company contributions,
unless he or she retires or dies during the year in which case PSE will
contribute a prorated amount.
In lieu
of participation in the SERP, Mr. Reynolds receives an annual credit of
performance-based stock equivalents to his Deferred Compensation Plan’s
Performance-Based Retirement Equivalent Stock Account each January commencing on
January 1, 2003. The number of stock equivalents is determined by
calculating the number of shares obtained by taking 15% of Mr. Reynolds’
base salary and annual bonus for the preceding year and dividing that amount by
the average per-share closing price of Puget Energy stock on the last day of
October, November and December of the preceding year. The stock equivalents are
entitled to dividend equivalents equal to all dividends declared on Puget Energy
stock, which are then credited to the Performance-Based Retirement Equivalent
Stock Account as additional stock equivalents. The stock equivalents vest over
seven years from January 1, 2002 at 15% per year for the first six
years, with the balance vesting on May 6, 2008.
Participants
choose how to credit deferred amounts among four investment tracking funds. The
tracking funds mirror performance in major asset classes of bonds, stocks, Puget
Energy stock, and interest crediting. The tracking funds differ from the
investment funds offered in PSE’s 401(k) plan. The 2007 calendar year returns of
these tracking funds were:
Vanguard
Total Bond Market Index
7.05
%
Vanguard
500 Index
5.39
%
Puget
Energy Stock
11.90
%
Interest
Crediting Fund
6.20
%
Participants
may change how deferrals are allocated to the tracking funds at any time,
subject to insider trading rules and other Deferred Compensation Plan
restrictions that limit the transfer of funds into or out of Puget Energy stock.
Changes generally become effective as of the first trading day of the following
calendar quarter.
Participants
generally may choose how and when to receive payments under the Deferred
Compensation Plan. There are three types of in-service withdrawals. First, a
participant may choose an interim payment of deferred based salary, annual bonus
or vested performance shares by electing a payment date at the time of his or
her deferral election. The interim payment cannot occur earlier than the third
year following the year of the deferral election. Second, an in-service
withdrawal may also be made to a participant upon a qualifying hardship event
and demonstrated need. Third, only with respect to amounts deferred and vested
prior to 2005, the participant may elect an in-service withdrawal for any reason
by paying a 10% penalty. Payments upon termination of employment depend on
whether the participant is then eligible for retirement. If the participant's
termination occurs prior to his or her retirement date (generally the earlier of
attaining age 62 or age 55 with five years of credited service), the
participant will receive a lump sum payment of his or her vested account
balance. If the participant's termination occurs after his or her retirement
date, of the amounts that are initially deferred or that become vested after
December 31, 2004 the participant may choose to receive payments in a lump
sum or via one of several installment options based on the participant's vested
account balances. Mr. Reynolds and Mr. Markell are the only Named Executive
Officers currently retirement eligible. Payments to the participant following a
termination or retirement date are generally delayed for six months in
accordance with the requirements of Section 409A of the Internal Revenue
Code, except distributions of Puget Energy stock take place in the following
January (if later) and each January thereafter if applicable.
Potential
Payments Upon Termination or Change in Control
The
“Estimated Potential Incremental Payments Upon Termination or Change in Control”
table reflects the estimated amount of incremental compensation payable to each
of the Named Executive Officers following an executive’s termination of
employment in the event of (i) an involuntary termination without cause or
for good reason that is not in connection with a change in control; (ii) a
change in control; (iii) an involuntary termination without cause or for
good reason in connection with a change in control; (iv) retirement;
(v) disability; or (vi) death. The amounts shown assume that the
termination was effective as of December 31, 2007 and that the price of
Puget Energy stock upon which certain of the calculations are made was the
closing price of $27.43 on December 31, 2007. These amounts are estimates
of the incremental amounts that would be paid out to the executive upon such
terminations. The actual amounts to be paid out can only be determined at the
time of the executive’s termination. The Merger proxy statement describes the
anticipated amount of such benefits that would be provided upon occurrence of
the Merger.
Payments
Made Upon Termination
Regardless
of the manner in which an executive’s employment terminates, the executive is
entitled to receive amounts earned during the term of employment. These amounts,
which are not included in the “Estimated Potential Incremental Payments Upon
Termination or Change in Control” table, include:
·
Amounts
contributed by the executive under the PSE Investment Plan and Deferred
Compensation Plan; and
·
Amounts
accrued and vested through the PSE Retirement Plan and
SERP.
Payments
Made Upon Retirement
In the
event of the retirement of a Named Executive Officer, in addition to the items
identified above, the executive will receive the estimated incremental benefits
reflected in the table below as a result of the following:
·
Pro-rata
payment of Performance Awards, which will be paid based on the value at
the end of the year pro-rated through the month of retirement based on
Puget Energy’s relative Total Shareholder Return as of the quarter-end of
the quarter prior to retirement; and
·
Named
Executive Officers also receive a pro-rata payment of annual incentive
awards, which is paid pro-rata to the extent earned in the year following
retirement, provided the executive worked a minimum of 520 hours
during the year. No estimated amounts are shown in the table below for
annual incentive compensation earned in
2007.
Payments
Made Upon Disability or Death
In the
event of the disability or death of a Named Executive Officer, in addition to
the benefits listed above, the executive will receive benefits under the PSE
disability plan or life insurance plan available generally to all salaried
employees. These disability and life insurance amounts are not reflected in the
table below. The executive will also receive supplemental disability and life
insurance. The disability coverage is extended to include base salary and target
incentive pay. Life insurance benefit is provided at two times base salary and
target annual incentive bonus if the executive dies while employed by PSE with a
reduction for amounts payable under the applicable group policy, or a single sum
amount equal to the actuarial equivalent of the combined annual annuity benefit
if the executive dies after retiring.
Payments
Made Pursuant to Employment and Change in Control Agreements
Puget
Energy and Puget Sound Energy (together, the “Company”) entered into an
employment agreement with Mr. Reynolds as of January 1, 2002 to secure
his services as Chief Executive Officer and President. The agreement has an
initial term of three years after which time it will be automatically renewed
for one-year terms unless notice of termination is given by either party at
least 180 days prior to the expiration of the then current term. Pursuant
to the agreement, Mr. Reynolds was appointed to the Board of Directors and
the Board will recommend him for reelection during the term of the agreement.
The agreement was amended on May 10, 2005 and February 9, 2006. The
agreement provides for the following benefits, the estimated value of which is
included in the “Estimated Potential Incremental Payments Upon Termination or
Change in Control” table.
If at any
time the Company terminates Mr. Reynolds’ employment without cause, or
Mr. Reynolds terminates his employment with good reason, Mr. Reynolds
will then receive the following severance benefits:
·
An
amount equal to two times his then current annual base salary and target
annual incentive bonus;
·
Accelerated
two years of vesting in his Performance-Based Retirement Equivalent Stock
Account in the Deferred Compensation Plan; and
·
Accelerated
vesting of stock options granted under the
agreement.
If a
change in control occurs during the term of the employment agreement,
Mr. Reynolds will receive the following compensation and benefits at the
time of the change in control:
·
An
amount equal to three times his then current base salary and target annual
incentive bonus;
·
Accelerated
vesting of all outstanding equity awards;
·
Accelerated
vesting of his Performance-Based Retirement Equivalent Stock Account in
the Deferred Compensation Plan;
·
Continued
medical, dental and insurance benefits for a period of three years or
until he obtains similar coverage through another
employer; and
·
A
cash payment equal to any excise taxes imposed by Section 4999 of the
Internal Revenue Code due to payments received under the employment
agreement or any other payment or benefit from the Company, plus the
income taxes payable by him resulting from this cash
payment.
The
employment agreement contains a noncompetition covenant. Mr. Reynolds
commits that for a period of two years following his voluntary termination,
without good reason, he will not perform services for any person or entity
selling or distributing electric power or natural gas in Washington, Oregon or
Idaho, unless the Company consents in writing. The Company may enforce this
covenant through injunctive relief or other appropriate remedies.
The
employment agreement also contains an indemnification clause in favor of
Mr. Reynolds. The Company commits to defend, indemnify and hold harmless
Mr. Reynolds from all liabilities in connection with his service. As part
of that commitment, the Company will continue to cover him under the Company’s
directors’ and officers’ liability insurance for six years following his
termination of employment.
Under the
employment agreement, “change in control,”“good reason,” and “cause” have the
following meanings:
Change in Control means any
one of the following events: (i) any person becomes the beneficial owner of
more than 30% of Puget Energy’s common stock or voting securities, with certain
exceptions; (ii) the incumbent directors (including those nominees
subsequently nominated or appointed by incumbent directors) cease for any reason
to constitute at least a majority of the Board of Directors; and
(iii) consummation of a reorganization, merger, consolidation or other
business combination involving Puget Energy, or a sale of substantially all of
the assets of either of the Puget Energy or PSE, unless (x) after such
transaction the beneficial shareholders of the outstanding Puget Energy common
stock and voting securities entitled to vote on director elections immediately
prior to the transaction retain more than 60% of such common stock and voting
securities; (y) no beneficial shareholder owns 30% or more of the then
outstanding common stock or voting securities entitled to vote on director
elections, and (z) at least a majority of the directors resulting from such
transaction were incumbent directors at the time of executing the initial
agreement providing for such transaction.
Good Reason includes the
following actions by the Company: (i) assigning duties inconsistent with,
or taking actions in diminution of, his position (including status, offices,
titles and reporting requirements), authority, duties or responsibility under
the employment agreement; (ii) failing to comply with the provisions of the
employment agreement; (iii) requiring that he be based at any location
other than its corporate headquarters or relocating the corporate headquarters
more than 25 miles from Bellevue, Washington; and (iv) failing to
assign the employment agreement to a successor or the successor failing to
assume and be bound by it explicitly. Good Reason is triggered on a reasonable
determination by Mr. Reynolds that any of the above events has
occurred.
Cause means (i) the
willful and continued failure to substantially perform Mr. Reynolds’ duties
or (ii) the willful engaging in gross misconduct materially and
demonstrably injurious to the Company. Cause does not include any act or
omission believed to be in good faith and in the best interests of the
Company.
In
February 2006 PSE entered into amended change in control agreements with each of
Mr. Valdman, Ms. O’Connor, Ms. McLain and Mr. Markell (the
“Executives”), the terms of which are the same for all four Executives. If a
change in control occurs, for a period of two years following the change in
control of PSE (the “employment period”), the Executives will receive continued
base salary, annual incentive bonus and other incentive, savings and retirement
plans and programs applicable to PSE peer executives at comparable levels to
those prior to the change in control. These benefits are not reflected in the
“Estimated Potential Incremental Payments Upon Termination or Change in Control”
table.
At the
time of the change in control, the Executives will receive the following
benefits, the estimated value of which is included in the “Estimated Potential
Incremental Payments Upon Termination or Change in Control” table.
·
Accelerated
vesting in the SERP.
·
Accelerated
vesting of any outstanding equity awards.
·
A
cash payment in consideration of all outstanding performance awards equal
to the product of a deemed stock price (calculated based on the greater of
(i) the average last sales price of Puget Energy stock on the NYSE in
each of the 20 days preceding the change in control, and
(ii) the highest price per share actually paid in connection with the
change in control) multiplied by a deemed number of shares related to the
performance awards (calculated based on the greater of (x) the total
shares payable at the target award level on full vesting of each such
award, and (y) the shares payable on full vesting of each such award
if PSE achieved for each award cycle the same percentile ranking against
its designated universe of companies which the PSE had achieved for the
applicable cycle but ending with the fiscal quarter immediately prior to
the change in control).
After a
change in control, if at any time during the employment period PSE terminates an
Executive’s employment without cause or due to disability or death, or the
Executive terminates his or her employment with good reason, PSE will pay the
Executive:
·
A
lump sum in cash equal to (i) any accrued but unpaid base salary,
(ii) a pro rata portion of the Executive’s annual incentive bonus for
the year, (iii) any accrued paid time off pay, and (iv) a
severance benefit equal to three times the sum of the annual base salary
and the annual incentive bonus for which he or she was eligible for the
year in which the date of termination occurs, unless an acceptable release
is not executed by the Executive in which case the severance benefit will
equal one times such sum.
·
A
separate lump-sum supplemental retirement benefit equal to the difference
between (x) the actuarial equivalent of the amount he or she would
have received under the Retirement Plan and the SERP had his or her
employment continued until the end of the employment period, and
(y) the actuarial equivalent of the amount he or she actually
receives or is entitled to receive under the Retirement Plan and
SERP.
·
Continued
welfare and fringe benefits described above for the Executive and the
Executive’s family at least equal to those that would have been provided
if the Executive’s employment had not terminated through the remainder of
the employment period, except that if the Executive becomes re-employed
with another employer and is eligible to receive medical or other welfare
benefits under another employer-provided plan, the medical and other
welfare benefits received under the amended agreement will be secondary to
those provided by the other
employer.
If any
payments paid or payable under the amended change in control agreement or
otherwise are characterized as “excess parachute payments” within the meaning of
Section 280G the Internal Revenue Code, then PSE will make cash payment to
or on behalf of the Executive equal to any excise taxes imposed by
Section 4999 of the Internal Revenue Code due to payments received under
the amended agreement or any other payment or benefit from the Company, plus the
income taxes payable by him or her resulting from this cash
payment.
The
amended change in control agreements contain a confidentiality clause. The
Executives must keep confidential all secret or confidential information,
knowledge or data relating to the Company and its affiliates obtained during
their employment. The Executives may not disclose any such information,
knowledge or data after their respective terminations of employment unless PSE
consents in writing or as required by law. PSE cannot withhold or defer the
payment of any amounts otherwise due under the agreement based on an Executive’s
asserted violation of the confidentiality clause.
Under the
amended change in control agreements, “change in control” has the same meaning
as under Mr. Reynolds’ employment agreement. “Good reason” and “cause” have
the following meanings:
Good reason means
(i) the assignment of any duties inconsistent with, or taking action in
diminution of, the Executive’s position (including status, offices, titles and
reporting requirements), authority, duties or responsibilities; (ii) any
failure by PSE to comply with the provisions of the agreement regarding
compensation during the employment period; (iii) requiring the Executive to
be based at any location other than the Seattle/Bellevue metropolitan area;
(iv) any purported termination of the Executive’s employment other than as
expressly permitted by the amended agreement; and (v) PSE’s failure to
assign the amended agreement to a successor to PSE or failure of a successor to
PSE to explicitly assume and agree to be bound by the amended
agreement.
Cause means (i) the
willful and continued failure to substantially perform the Executive’s duties or
(ii) the willful engaging in gross misconduct materially and demonstrably
injurious to PSE. Cause does not include any act or omission believed to be in
good faith and in the best interests of PSE.
The table
below presents estimated incremental compensation payable to each of the Named
Executive Officers as described above. The incremental compensation is presented
in the following benefit categories:
·
Cash
severance: multiple of salary and target annual incentive; does
not reflect salary paid or annual incentive compensation earned in
2007
·
Stock
options: in-the-money value, as of December 31, 2007 of
unvested stock options that would vest
·
Service-based
stock awards: market value, as of December 31, 2007 of
unvested equity awards that would vest; includes Restricted Stock and
Restricted Stock Units
·
Performance-Based
Stock Awards: market value, as of December 31, 2007 of
unvested performance-based restricted stock awards that would
vest
·
Performance
Shares: amount calculated in accordance with formula in the
amended change in control agreements
·
Performance-Based
Retirement Equivalent Stock Account: market value, as of
December 31, 2007 of unvested portion of account that would
vest
·
SERP: estimated
actuarial value of the Executive’s supplemental pension benefits under the
amended change in control agreements
·
Health
and welfare benefits: estimated value of benefits continued
following the termination
·
Perquisites,
consisting of estimated value of continuation of financial planning and,
for Mr. Valdman, relocation allowance
·
Estimated
value of excise tax gross-up
Estimated
Potential Incremental Payments Upon Termination or Change in
Control
Involuntary
Termination w/o Cause or for Good Reason
Upon
Change in Control
After
Change in Control Involuntary Termination w/o Cause or for Good
Reason
SERP
values are shown as the estimated incremental value that the Named
Executive Officer would receive at age 62 as a result of the
termination event shown in the column, relative to the vested benefit as
of December 31, 2007. These values are based on interest rate and
mortality rate assumptions consistent with those used in the Company’s
financial statements.
Director
Compensation for Fiscal Year 2007
The
following table sets forth information regarding compensation for each of the
Company’s nonemployee directors for 2007. As described in further detail below,
the Company’s nonemployee director compensation program in 2007 consisted of
quarterly retainer fees of $20,000, payable in the form of Puget Energy shares
until a director owns a number of Puget Energy shares equal in value to two
years of retainer fees. Additional quarterly retainer amounts associated with
serving as lead director, chairing Board committees and serving on the Audit
Committee, and meeting fees are paid in cash. Directors may defer their cash or
stock fees into deferred stock units.
Name
Fees
Earned or
Paid
in Cash1
Stock
Awards2
Nonqualified
Deferred
Compensation
Earnings3
Total
William
S. Ayer
$ 27,750
$ 76,667
$ —
$104,417
Phyllis
J. Campbell
62,125
57,500
597
120,222
Craig
W. Cole
31,525
76,667
329
108,521
Stephen
E. Frank
46,625
76,667
—
123,292
Tomio
Moriguchi
25,525
76,667
—
102,192
Dr.
Kenneth P. Mortimer
56,682
51,110
—
107,792
Sally
G. Narodick
64,282
51,110
—
115,392
Herbert
B. Simon
27,750
76,667
—
104,417
George
W. Watson
29,525
76,667
—
106,192
_______________
1
The
amounts in this column reflect director compensation earned and paid in
cash, including amounts deferred under our Deferred Compensation Plan for
Nonemployee Directors. Mr. Watson received 1,145 deferred stock units
from deferrals of cash compensation totaling $29,525 in
2007.
2
The
amounts in this column reflect the dollar amount the Company recognized
for financial statement reporting purposes for 2007 in accordance with
SFAS No. 123R for stock awards granted in 2007. The
SFAS 123R fair value for these awards is equal to the fair market
value of the underlying Puget Energy stock on the date of
grant.
3
Represents
earnings accrued to deferred compensation considered to be above
market.
Nonemployee Director Compensation
Program. The Board believes that the level of nonemployee
director compensation should be based on Board and committee responsibilities
and be competitive with comparable companies. In addition, the Board believes
that a significant portion of nonemployee director compensation should align
director interests with the long-term interests of shareholders.
The 2007
compensation program for nonemployee directors was as follows:
·
A
base cash quarterly retainer fee of $20,000 payable in Puget Energy stock
until a director owns a number of Puget Energy shares equal in value to
two years of retainer fees.1
·
$1,600
for attendance at each Board and committee meeting, and $800 for each
telephonic meeting lasting 60 minutes or less, for the first two months of
2007 and $1,600 and $800, respectively, thereafter.2
Nonemployee
directors were paid the following additional cash quarterly retainer fees in
2007:
·
Lead
independent director, $3,7503
·
Chair
of the Audit Committee, $2,500
·
Chair
of the Compensation and Leadership Development Committee,
$2,000
·
Chair
of the Governance and Public Affairs Committees, $1,500
·
Each
member of the Audit Committee other than the chair,
$1,000
_______________
1
Prior
to March 1, the base cash quarterly retainer fee was $15,000, at least
two-thirds of which was payable in Puget Energy stock.
2
Prior
to March 1, the fee for attendance at each Board and committee meeting was
$1,250 and the fee for each telephonic meeting lasting 60 minutes or less
was $625.
3
Prior
to March 1, the lead independent director was paid a cash quarterly
retainer fee of $5,000.
To
facilitate the stock ownership guidelines described below, 100% of the quarterly
retainer fee is paid in the form of Puget Energy shares until a director owns a
number of Puget Energy shares equal in value to two years of retainer
fees.
After
meeting this ownership requirement, a portion of the base quarterly retainer for
a fiscal quarter is payable in shares of Puget Energy stock. Under the terms of
our Nonemployee Director Plan and Board policies as currently in effect, the
number of shares is determined by dividing two-thirds of the base quarterly
retainer by the fair market value of Puget Energy stock for the last business
day of a fiscal quarter. For this purpose, fair market value for a single
trading day is the average of the high and low trading prices for Puget Energy
stock as reported by the NYSE.
All
quarterly retainer and meeting attendance fees are paid on the last business day
of March, June, September and December. Nonemployee directors are reimbursed for
actual travel and out-of-pocket expenses incurred in connection with their
services. Directors who also serve as employees of the Company do not receive
compensation for their service on the Board or any committees.
Nonemployee
directors are eligible to participate in our matching gift program on the same
terms as all Puget Energy employees. Under this program, we will match up to a
total of $300 a year in contributions by a director to non-profit organizations
with an IRS 501(c)(3) tax exempt status that are located in and serve the people
of PSE’s service territory in Washington State.
Deferral of
Compensation. Nonemployee directors may defer receipt of all
or a part of their quarterly retainer fees that are required to be paid in Puget
Energy stock into unfunded deferred stock unit accounts under our Nonemployee
Director Plan. Deferred stock units earn the equivalent of dividends, which are
credited as additional deferred stock units. Nonemployee directors do not have
the right to vote or transfer the deferred stock units. Deferred stock units
will be distributed as shares of Puget Energy stock after retirement or other
termination of Board service.
Nonemployee
directors may also elect to defer all or a part of their fees payable in cash
under our Deferred Compensation Plan for Nonemployee Directors. Nonemployee
directors may allocate these deferrals into one or more “measurement funds,”
which currently include an interest crediting fund, an equity index fund, a bond
index fund and a Puget Energy stock fund. Nonemployee directors are permitted to
make changes in measurement fund allocations quarterly. Amounts allocated to the
Puget Energy stock fund are treated as deferred stock units that will earn the
equivalent of dividends, which are credited as additional deferred stock units.
Nonemployee directors do not have the right to vote or transfer the deferred
stock units. Amounts deferred will be paid at the time elected by the
nonemployee director, which must be at least three years after the date of
deferral. Amounts allocated to the Puget Energy stock fund are payable only in
Puget Energy stock. Other accounts are payable in cash.
Director Compensation Review
Practices. The Governance and Public Affairs Committee is
responsible for annually reviewing the Company’s nonemployee director
compensation practices in relation to comparable companies. Any changes to be
made to nonemployee director compensation practices must be recommended by the
Governance and Public Affairs Committee for approval by the full
Board.
Director Stock Ownership
Guidelines. The Board believes that nonemployee directors
should have a financial stake in the Company. The Board has adopted stock
ownership guidelines for nonemployee directors. The guidelines call for the
Company to pay the base quarterly retainer in the form of Puget Energy stock
until a director owns shares equal in value to the ownership target. Directors
and officers of the Company are not allowed to own derivatives of Puget Energy
stock, nor are they allowed to own shares in margin accounts.
Puget
Sound Energy
The
information called for in this item 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).
As of
December 31, 2007, all of the issued and outstanding shares of PSE’s common
stock were held beneficially and of record by Puget Energy.
Security
Ownership of Directors, Executive Officers and Certain Beneficial
Owners
The
following table shows the number of shares of common stock beneficially owned as
of February 15, 2008 by each director, by each executive officer named in the
Summary Compensation Table in Item 11 of Part III in this report, by the
directors and executive officers of the Company as a group and by each person or
group that we know owns more than 5% of our common stock. We consider
executive officers of PSE to be executive officers of the Company. No
director or executive officer owns more than 1% of the outstanding shares of
common stock. Puget Holdings LLC and its affiliates beneficially own
approximately 9.6%, Franklin Resources, Inc. and its affiliates beneficially own
approximately 8.6% of our common stock. Tradewinds Global Investors
LLC beneficially owns approximately 6.5% of our common
stock. Percentage of beneficial ownership is based on 129,678,489
shares outstanding as of February 15, 2008.
Beneficial
Ownership Table
Name
Number
of Beneficially
Owned Shares
Number
of Share
Interests Held 1
William
S. Ayer
--
8,782
Phyllis
J. Campbell
1,000
18,253
Craig
W. Cole
8,701
11,062
Stephen
E. Frank
--
13,083
Tomio
Moriguchi
1,571
23,793
Kenneth
P. Mortimer
2,852
6,650
Sally
G. Narodick
2,272
13,740
Herbert
B. Simon
--
5,271
Stephen
P. Reynolds
450,507 2
74,160
George
W. Watson
--
5,886
Eric
M. Markell
23,940
2,467
Susan
McLain
28,948 3
14,194
Jennifer
L. O’Connor
20,821
--
Bertrand
A. Valdman
38,039 3
1,275
All
directors and executive officers, including named executive officers, as a
group (21 persons)
682,517
208,867
Puget
Holdings LLC and affiliates
12,500,000
4
Franklin
Resources, Inc. and affiliates
11,092,300
5
--
Tradewinds
Global Investors, LLC
8,392,505
6
_______________
1
Includes
deferred stock units held in the Company Nonemployee Director Stock Plan
and the PSE Deferred Compensation Plans.
2
Includes
92,096 shares of restricted stock, 300,000 shares of common stock subject
to stock options that are currently exercisable and 950 shares held by Mr.
Reynolds’s wife.
3
Includes
shares held under the PSE Investment Plan for Employees (401(k)
Plan).
· MIP
A held 1,753,788 of the shares, over all of which MIP A has dispositive
power and voting power. The address of the principal office of MIP A, as
well as the Parent, MIP I and MIP C, is 125 West 55th Street, Level 22,
New York, NY10019.
· MIP I
held 1,830,864 of the shares, over all of which MIP I has dispositive
power and voting power.
· MIP C
held 393,158 of the shares, over all of which MIP C has dispositive
power and voting power.
· MFIT
held 465,404 of the shares, over all of which MFIT has dispositive power
and voting power. Its address of the principal office is Level 11,
1 Martin Place, Sydney, Australia NSW 2000.
· PMGH
held 1,988,905 of the shares, over all of which PMGH has dispositive power
and voting power. Its address of the principal office is 125 West
55th Street, Level 22, New York, NY10019.
· USRE
held 3,517,612 of the shares, over all of which USRE has dispositive power
and voting power. Its address of the principal office is One Queen Street
East, Suite 2600, P.O. Box 101, Toronto, Ontario, Canada
M5C 2W5.
· PIT
held 1,758,806 of the shares, over all of which PIT has dispositive power
and voting power. Its address of the principal office is c/o its Trustee
6860141 Canada Inc., British Columbia Investment Management
Corporation, Sawmill Point, Suite 301-2940 Jutland Road, Victoria,
British Columbia, Canada V8T 5K6.
· PIP2PX
held 490,707 of the shares, over all of which PIP2PX has dispositive power
and voting power. Its address of the principal office is 340 Terrace
Building, 9515-107 Street, Edmonton, Alberta, Canada
T5K 2C3.
· PIP2GV
held 300,756 of the shares, over all of which PIP2GV has dispositive power
and voting power. Its address of the principal office is 340 Terrace
Building, 9515-107 Street, Edmonton, Alberta, Canada
T5K 2C3.
5
Information
presented is based on a Schedule 13G filed on February 6, 2007
by Franklin Resources, Inc., Charles B. Johnson, Rupert H. Johnson,
Jr. and Franklin Advisers, Inc. This amount includes 11,092,300
shares of common stock beneficially owned by Franklin Advisers, Inc.
or Fiduciary Trust Company International, subsidiaries of Franklin
Resources, Inc. According to the Schedule 13G, Franklin
Advisers, Inc. has sole voting and investment power over 11,091,300
of the shares and Fiduciary Trust Company International has sole voting
and investment power over 1,000 of the shares. Each of the reporting
persons disclaims beneficial ownership of the shares. The address of
Franklin Resources, Inc. is One Franklin Parkway, San Mateo,
California94403.
6
Information
presented is based on a Schedule 13G filed on February 14, 2008 by
Tradewinds Global Investors, LLC. According to the Schedule 13G,
Tradewinds Global Investors, LLC has sole voting authority over 5,248,053
of the shares and sole dispositive power over 8,392,505 of the shares. The
address of Tradewinds Global Investors, LLC is 2049 Century Park East,
18th Floor, Los Angeles, California90067.
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).
The
following table sets forth information regarding Puget Energy common stock that
may be issued upon the exercise of options, warrants and other rights granted to
employees, consultants or directors under all of the Puget Energy existing
equity compensation plans, as of December 31, 2007:
Plan
Category
(a)
Number of
Securities to
be
Issued Upon Exercise
of
Outstanding Options,
Warrants
and Rights
(b)
Weighted-Average
Exercise
Price of
Outstanding
Options,
Warrants
and Rights
(c)
Number
of Securities
Remaining
Available for
Issuance
Under Equity
Compensation
Plans
(Excluding
Securities
Reflected
in Column (a))
Equity
compensation plans approved by security holders
40,000
$22.51
4,098,5471,2,3,4
Equity
compensation plans not approved by security holders
260,000
$22.51
--
Total
300,000
$22.51
4,098,547
The table
does not include 96,305 deferred stock units in the Company’s deferred
compensation plans that are payable in stock, plus cash for any fractional
shares, of which all are currently vested.
_______________
1
Includes
554,277 shares remaining available for issuance under Puget Energy’s
Employee Stock Purchase Plan.
2
Includes
3,349,12 shares remaining available for issuance under Puget Energy’s 2005
Long-Term Incentive Plan. Depending on the achievement level of
performance goals, the outstanding performance share grants may be paid
out at zero shares at a minimum achievement level, 499,423 shares at
a target level or 776,603 shares at a maximum level. Because there is
no exercise price associated with performance shares, such shares are not
included in the weighted-average price calculation.
3
In
addition to stock options, Puget Energy may also grant stock awards,
performance awards and other stock-based awards under the 2006 Long-Term
Incentive Plan.
4
Includes
195,149 shares available for issuance under Puget Energy’s
Nonemployee Director Stock Plan (Nonemployee Director Plan). The
Nonemployee Director Plan provides for automatic stock payments to each of
Puget Energy’s nonemployee directors. Each nonemployee director who is a
nonemployee director at any time during a calendar year may receive a
stock payment for all or a portion of the quarterly retainer paid to such
director. Effective July 1, 2003, the number of shares that will be
issued to each nonemployee director as a stock payment under the
Nonemployee Director Plan is determined by dividing two-thirds of the
quarterly retainer payable to such director for a fiscal quarter by the
fair market value of Puget Energy’s common stock on the last business day
of that fiscal quarter. The Nonemployee Director Plan provides that the
portion of the quarterly retainer that may be payable in stock will be
determined by the Governance and Public Affairs Committee from time to
time. A nonemployee director may elect to increase the percentage of his
or her quarterly retainer that is paid in stock up to 100%. A nonemployee
director may also elect to defer the issuance of shares under the
Nonemployee Director Plan in accordance with the terms of the
plan.
Summary
of Equity Compensation Plans Not Approved By Shareholders
Non-Plan
Grants
On
January 7, 2002, Puget Energy granted Stephen P. Reynolds, President and
Chief Executive Officer of Puget Energy and Puget Sound Energy, two
non-qualified stock option grants outside of any equity incentive plan adopted
by Puget Energy (Non-Plan Option Grants). These stock option grants were an
inducement to Mr. Reynolds’ employment and in lieu of participation in the
Company’s SERP. One of the Non-Plan Option Grants made to Mr. Reynolds is
for 150,000 shares of Puget Energy common stock and vests at a rate of
20% per year, for full vesting after five years. The other Non-Plan Option
Grant made to Mr. Reynolds is for 110,000 shares of Puget Energy
common stock and vests at a rate of 25% per year, for full vesting after
four years. The exercise price of both Non-Plan Option Grants is $22.51 per
share, equal to 100% of the fair market value of Puget Energy common stock on
the date of grant. As of December 31, 2007, all of the 260,000 shares
subject to the Non-Plan Option Grants remained outstanding. Except as expressly
provided in the option agreement relating to each of the Non-Plan Option Grants,
the Non-Plan Option Grants are subject to the terms and conditions of the
Company’s 2005 Long-Term Incentive Plan.
Upon a
change of control (as defined in the Employment Agreement between Puget Energy
and Mr. Reynolds, dated January 7, 2002), both Non-Plan Option Grants
will become fully vested and immediately exercisable. If Mr. Reynolds’
employment or service relationship with Puget Energy is terminated by Puget
Energy without cause or by Mr. Reynolds with good reason, the vesting and
exercisability of the Non-Plan Option Grants will be accelerated as follows:
(1) the vesting and exercisability of the 150,000 share Non-Plan
Option Grant will be accelerated such that the total number of shares vested and
exercisable will be calculated as if the option had vested on a daily basis over
the four-year period through the date of termination and (2) the vesting
and exercisability of the 110,000 share Non-Plan Option Grant will be
accelerated by two years. For purposes of the Non-Plan Option Grants, the terms
“cause” and “good reason” have the meanings given to them in the Employment
Agreement between Puget Energy and Mr. Reynolds, dated January 1,2002.
Subject
to the provisions regarding a change of control and termination of employment or
service relationship by Puget Energy without cause or by Mr. Reynolds for
good reason, as described above, upon termination of Mr. Reynolds’
employment or service relationship with Puget Energy for any reason, the
unvested portion of the Non-Plan Option Grants will terminate automatically and
the vested portion may be exercised as follows: (1) generally, on or before
the earlier of three months after termination and the expiration date of the
option, (2) if termination is due to retirement, disability or death, on or
before the earlier of one year after termination and the expiration date of the
option, or (3) if death occurs after termination, but while the option is
still exercisable, on or before the earlier of one year after the date of death
and the expiration date of the option. Pursuant to an amendment to the
Employment Agreement effective as of May 12, 2005 and February 28, 2008, in
consideration of Mr. Reynolds’ remaining Chief Executive Officer at least
through May 6, 2008, the post-termination exercise period for each of the
Non-Plan Option Grants was extended to January 7, 2012. In addition, a
second amendment to the Employment Agreement effective February 9, 2006
changed the definition of change of control to conform to the change of control
definition in the 2005 Long-Term Incentive Plan.
The
Non-Plan Option Grants provide for the payment of the exercise price of options
by any of the following means: (1) cash, (2) check, (3) tendering
shares of Puget Energy’s common stock, either actually or by attestation,
already owned for at least six months (or any shorter period necessary to avoid
a charge to Puget Energy’s earnings for financial reporting purposes) that on
the day prior to the exercise date have a fair market value equal to the
aggregate exercise price of the shares being purchased, (4) delivery of a
properly executed exercise notice, together with irrevocable instructions to a
brokerage firm designated by Puget Energy to deliver promptly to Puget Energy
the aggregate amount of sale or loan proceeds to pay the option exercise price
and any withholding tax obligations that may arise in connection with the
exercise or (5) any other method permitted by the plan
administrator.
Our Board
of Directors has adopted a written policy for the review and approval or
ratification of related person transactions. Under the policy, our directors and
executive officers are expected to disclose to our Chief Compliance Officer the
material facts of any transaction that could be considered a related person
transaction promptly upon gaining knowledge of the transaction. A related person
transaction is generally defined as any transaction required to be disclosed
under Item 404(a) of Regulation S-K, the SEC’s related person
transaction disclosure rule.
Any
transaction reported to the Chief Compliance Officer will be reviewed according
to the following procedures:
·
If
the Chief Compliance Officer determines that disclosure of the transaction
is not required under the SEC’s related person transaction disclosure
rule, the transaction will be deemed approved and will be reported to the
Audit Committee.
·
If
disclosure is required, the Chief Compliance Officer will submit the
transaction to the Chair of the Audit Committee, who will review and, if
authorized, will determine whether to approve or ratify the transaction.
The Chair is authorized to approve or ratify any related person
transaction involving an aggregate amount of less than $1.0 million
or when it would be impracticable to wait for the next Audit Committee
meeting to review the transaction.
·
If
the transaction is outside the Chair’s authority, the Chair will submit
the transaction to the Audit Committee for review and approval or
ratification.
When
determining whether to approve or ratify a related person transaction, the Chair
of the Audit Committee or the Audit Committee, as applicable, will review
relevant facts regarding the related person transaction, including:
·
The
extent of the related person’s interest in the
transaction;
·
Whether
the terms are comparable to those generally available in arms’ length
transactions; and
·
Whether
the related person transaction is consistent with the best interests of
the Company.
If any
related person transaction is not approved or ratified, the Committee may take
such action as it may deem necessary or desirable in the best interests of the
Company and its shareholders.
There
were no related person transactions required to be disclosed pursuant to
Item 404(a) of Regulation S-K in fiscal year 2007.
Board
of Directors and Corporate Governance
Independence
of the Board
The Board
has reviewed the relationships between Puget Energy (and its subsidiaries) and
each of its directors and has determined that all of the directors, other than
Stephen P. Reynolds, Puget Energy’s Chairman, President and Chief Executive
Officer (CEO), are independent under the NYSE corporate governance listing
standards and Puget Energy’s Corporate Governance Guidelines, which are
available at Puget Energy’s website, www.pugetenergy.com, by clicking on the
section Corporate Governance. In making these determinations, the Board has
established a categorical standard that a director’s independence is not
impaired solely as a result of the director, or a company for which the director
or an immediate family member of the director serves as an executive officer,
making payments to PSE for power or natural gas provided by PSE at rates fixed
in conformity with law or governmental authority, unless such payments would
automatically disqualify the director under the NYSE’s corporate governance
listing standards. The Board has also established a categorical standard that a
director’s independence is not impaired if a director is a director, employee or
executive officer of another company that makes payments to or receives payments
from Puget Energy, PSE, or any of their affiliates, for property or services in
an amount which is less than the greater of $1.0 million or one percent of
such other company’s consolidated gross revenues, determined for the most recent
fiscal year. These categorical standards will not apply, however, to the extent
that Puget Energy would be required to disclose an arrangement as a related
person transaction pursuant to Item 404 of
Regulation S-K.
In making
its independence determinations, the Board considered all relationships between
its directors and Puget Energy (and its subsidiaries), including some that are
not required to be disclosed in this report as related-person transactions.
Messrs. Ayer, Cole, Moriguchi and Simon serve as directors or officers of,
or otherwise have a financial interest in, entities that make payments to PSE
for energy services provided to those entities at tariff rates established by
the Washington Utilities and Transportation Commission. These transactions fall
within the first categorical independence standard described above. In addition,
PSE has entered into transactions with entities for whom Messrs. Cole,
Frank and Simon serve as directors or officers, or in which they otherwise have
a financial interest, that involve amounts that are less than the greater of
$1.0 million or 1% of those entities’ consolidated gross revenues. These
transactions fall within the second categorical standard described above. PSE
has also made a charitable contribution to an entity for which Ms. Narodick
served as director. Because these relationships either fall within the Board’s
categorical independence standards or involve an amount that is not material to
Puget Energy or the other entity, the Board has concluded that none of these
relationships impair the independence of the applicable directors.
Executive
Sessions
Non-management
directors meet in executive session on a regular basis, generally on the same
date as each scheduled Board meeting. Because the Chairman of the
Board is a member of management, the Lead Independent Director, Phyllis J.
Campbell, who is not a member of management, presides over the executive
sessions. Shareholders may communicate with the non-management directors of the
Board through the procedures described in Item 10 of Part III of this annual
report under the section “Communications with the Board.”
The
aggregate fees billed by PricewaterhouseCoopers LLP, the Company’s independent
registered public accounting firm, for the year ended December 31 were as
follows:
2007
2006
(Dollars
in Thousands)
Puget
Energy
PSE
Puget
Energy
PSE
Audit
fees1
$
1,695
$
1,680
$
1,653
$
1,530
Audit
related fees2
108
108
100
100
Tax
fees3
16
16
34
34
Total
$
1,819
$
1,804
$
1,787
$
1,664
_______________
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 Company’s Forms 10-Q and consents and reviews of documents filed with
the Securities and Exchange Commission. The 2007 fees are
estimated and include an aggregate amount of $1.4 million and $1.4 million
billed to Puget Energy and PSE, respectively, through December
2007. The 2006 fees include an aggregate amount of $1.1 million
and $1.0 million billed to Puget Energy and PSE, respectively, through
December 31, 2006.
2
Consists
of employee benefit plan audits and due diligence
reviews.
3
Consists
of tax consulting and tax return
reviews.
The Audit
Committee of the Company has adopted policies for the pre-approval of all audit
and non-audit services provided by the Company’s independent registered public
accounting firm. The policies are designed to ensure that the
provision of these services does not impair the firm’s
independence. Under the policies, unless a type of service to be
provided by the independent registered public accounting firm has received
general pre-approval, it will require specific pre-approval by an Audit
Committee. In addition, any proposed services exceeding pre-approved
cost levels will require specific pre-approval by an 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 registered public accounting
firm. With respect to each proposed pre-approved service, the
independent registered public accounting firm 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 pre-approval
decision to an Audit Committee at its next scheduled meeting. The
Audit Committees do not delegate responsibilities to pre-approve services
performed by the independent registered public accounting firm to
management.
For 2007
and 2006, all audit and non-audit services were pre-approved.
Financial Statement
Schedules. Financial Statement Schedules of the
Company, as required for the years ended December 31, 2007, 2006 and
2005, consist of the following:
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.
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.
Certain
of the following exhibits are filed herewith. Certain other of the
following exhibits have heretofore been filed with the Securities and Exchange
Commission and are incorporated herein by reference.
2.1
Agreement
and Plan of Merger, dated October 25, 2007, by and among Puget Energy,
Inc., Padua Holdings LLC, Padua Intermediate Holdings Inc. and Padua
Merger Sub Inc. (incorporated herein by reference to Exhibit 2.1 to the
Current Report on Form 8-K, dated October 29, 2007, Commission File No.
1-16305).
*
3(i).1
Restated
Articles of Incorporation of Puget Energy, as amended on May 8, 2007 and
May 10, 2007.
Amended
and Restated Bylaws of Puget Energy dated May 4, 2007 (incorporated herein
by reference to Exhibit 3(ii).1 to the Quarterly Report on Form 10-Q for
the quarterly period ended September 30, 2007, Commission File No. 1-16305
and 1-4393).
3(ii).2
Amended
and Restated Bylaws of PSE dated March 7, 2003 (incorporated herein by
reference to Exhibit 3(ii).2 to the Report on Form 10-K for the fiscal
year ended December 31, 2002, Commission File No. 1-16305 and
1-4393).
*
4.1
Fortieth
through Eighty-fourth Supplemental Indentures defining the rights of the
holders of PSE’s Electric Utility First Mortgage Bonds (incorporated
herein by reference to 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; Exhibit 2-m to
Registration No. 2-37645; Exhibits 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
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; Exhibit 4.2 to Current Report on Form 8-K dated
June 3, 2003; Exhibit 4.28 to Report on Form 10-K for fiscal year ended
December 31, 2004, Commission File No. 1-16305 and 1-4393; Exhibit 4.1 to
Current Report on Form 8-K, dated May 23, 2005, Commission File No.
1-16305 and 1-4393; Exhibit 4.30 to Report on Form 10-K for fiscal year
ended December 31, 2005, Commission file No. 1-16305 and 1-4393); and
Exhibit 4.1 to Current Report on Form 8-K dated September 14, 2006,
Commission File No. 1-4393 and Eighty-fifth Supplemental Indenture
defining the rights of the holders of PSE’s Electric Utility First
Mortgage Bonds (filed herewith).
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 Report on Form 10-Q for the
quarter ended June 30, 1998, Commission File No.
1-4393).
4.3
First
Supplemental Indenture defining the rights of the holders of PSE’s senior
notes, Series A (incorporated herein by reference to Exhibit 4-b to PSE’s
Report on Form 10-Q for the quarter ended June 30, 1998, Commission File
No. 1-4393).
4.4
Second
Supplemental Indenture defining the rights of the holders of PSE’s senior
notes, Series B (incorporated herein by reference to Exhibit
4.6 to PSE’s Current Report on Form 8-K, dated March 5, 1999, Commission
File No. 1-4393).
4.5
Third
Supplemental Indenture defining the rights of the holders of PSE’s senior
notes, Series C (incorporated herein by reference to Exhibit
4.1 to PSE’s Current Report on Form 8-K, dated November 2, 2000,
Commission File No. 1-4393).
First
Supplemental Indenture dated as of October 1, 1959 (incorporated herein by
reference to Exhibit 4-D to Registration No. 2-17876).
4.10
Sixth
Supplemental Indenture dated as of August 1, 1966 (incorporated herein by
reference to Exhibit to Form 8-K for month of August 1966, File No.
0-951).
4.11
Seventh
Supplemental Indenture dated as of February 1, 1967 (incorporated herein
by reference to Exhibit 4-M, Registration No. 2-27038).
4.12
Sixteenth
Supplemental Indenture dated as of June 1, 1977 (incorporated herein by
reference to Exhibit 6-05 to Registration No. 2-60352).
4.13
Seventeenth
Supplemental Indenture dated as of August 9, 1978 (incorporated herein by
reference to Exhibit 5-K.18 to Registration No.
2-64428).
4.14
Twenty-second
Supplemental Indenture dated as of July 15, 1986 (incorporated herein by
reference to Exhibit 4-B.20 to Form 10-K for the year ended September 30,
1986, File No. 0-951).
4.15
Twenty-seventh
Supplemental Indenture dated as of September 1, 1990 (incorporated herein
by reference to Exhibit 4-B.20, Form 10-K for the year ended September 30,1998, File No. 10-951).
4.16
Twenty-eighth
Supplemental Indenture dated as of July 31, 1991 (incorporated herein by
reference to Exhibit 4-A, Form 10-Q for the quarter ended March 31, 1993,
File No. 0-951).
4.17
Twenty-ninth
Supplemental Indenture dated as of June 1, 1993 (incorporated herein by
reference to Exhibit 4-A to Registration No. 33-49599).
4.18
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).
4.19
Thirty-first
Supplemental Indenture dated February 10, 1997 (incorporated herein by
reference to Exhibit 4.30 to the Report on Form 10-K for the fiscal year
ended December 31, 2002, Commission File No. 1-6305 and
1-4393).
4.20
Thirty-second
Supplemental Indenture dated April 1, 2005, defining the rights of the
holders of PSE’s gas utility First Mortgage Bond (Exhibit 4.22 to the
Report on Form 10-K for the fiscal year ended December 31, 2005,
Commission File No. 1-16305 and 1-4393).
4.21
Thirty-third
Supplemental Indenture dated April 27, 2005, defining the rights of the
holders of PSE’s gas utility First Mortgage Bond (Exhibit 4.23 to the
Report on Form 10-K for the fiscal year ended December31, 2005, Commission File No. 1-16305 and
1-4393).
*
4.22
Thirty-fourth
Supplemental Indenture dated April 28, 2006, defining the rights of the
holders of PSE’s gas utility First Mortgage Bond.
*
4.23
Thirty-fifth
Supplemental Indenture dated April 27, 2007, defining the rights of the
holders of PSE’s gas utility First Mortgage Bond.
4.24
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).
4.25
Loan
Agreement dated as of March 1, 2003, between the City of Forsyth, Rosebud
County, Montana and Puget Sound Energy (incorporated herein by
reference to Exhibit 4.25 to the Company’s Post-Effective Amendment No. 1
to Registration Statement on Form S-3, dated July 11, 2003, Commission
File No. 333-82490-02).
4.26
Unsecured
Debt Indenture between Puget Sound Energy and The Bank of New York Trust
Company, N.A. (as successor to 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, dated May 22, 2001,
Commission File No. 1-4393).
4.27
Second
Supplemental Indenture, dated as of June 1, 2007, between the Company and
The Bank of New York Trust Company, N.A., as Trustee (incorporated herein
by reference to Exhibit 4.1 to Puget Sound Energy’s Current Report on Form
8-K, dated June 1, 2007, Commission File No. 1-4393).
4.28
Form
of Replacement Capital Covenant (incorporate herein by reference to
Exhibit 4.2 to Puget Sound Energy’s Current Report on Form 8-K, dated June1, 2007, Commission File No. 1-4393).
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 (incorporated herein by reference to
Exhibit 13-d to Registration No. 2-24252).
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 (incorporated herein by reference to Exhibit 13-p to
Registration No. 2-24252).
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
(incorporated herein by reference to Exhibit 4-1-a to Registration No.
2-13979).
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 (incorporated herein by reference to Exhibit 4-c-1 to
Registration No. 2-13979).
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
(incorporated herein by reference to Exhibit 4-d to Registration No.
2-13347).
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 (incorporated herein by reference to Exhibit
13-h to Registration No. 2-15618).
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).
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 (incorporated herein by reference to Exhibit 13-1 to
Registration No. 2-21824).
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 (incorporated herein by reference to Exhibit 13-r to
Registration No. 2-21824).
10.10
Construction
and Ownership Agreement dated as of July 30, 1971 between The Montana
Power Company and PSE (incorporated herein by reference to Exhibit 5-b to
Registration No. 2-45702).
10.11
Operation
and Maintenance Agreement dated as of July 30, 1971 between The Montana
Power Company and PSE (incorporated herein by reference to Exhibit 5-c to
Registration No. 2-45702).
10.12
Contract
dated June 19, 1974 between PSE and P.U.D. No. 1 of Chelan County
(incorporated herein by reference to Exhibit D to Form 8-K dated July 5,
1974).
10.13
Transmission
Agreement dated April 17, 1981 between the Bonneville Power Administration
and PSE (Colstrip Project) (incorporated herein by reference to Exhibit
(10)-55 to Report on Form 10-K for the fiscal year ended December 31,
1987, Commission File No. 1-4393).
10.14
Transmission
Agreement dated April 17, 1981 between the Bonneville Power Administration
and Montana Intertie Users (Colstrip Project) (incorporated herein by
reference to Exhibit (10)-56 to 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) (incorporated herein by
reference to Exhibit (10)-57 to Report on Form 10-K for the fiscal year
ended December 31, 1987, Commission File No. 1-4393).
10.16
Colstrip
Project Transmission Agreement dated as of May 6, 1981 between PSE and
Owners of the Colstrip Project (incorporated herein by reference to
Exhibit (10)-58 to Report on Form 10-K for the fiscal year ended December
31, 1987, Commission File No. 1-4393).
10.17
Common
Facilities Agreement dated as of May 6, 1981 between PSE and Owners of
Colstrip 1 and 2, and 3 and 4 (incorporated herein by reference to Exhibit
(10)-59 to 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)
(incorporated herein by reference to Exhibit (10)-66 to 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) (incorporated herein by
reference to Exhibit (10)-74 to 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 (incorporated herein by
reference to Exhibit (10)-4 to 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
(incorporated herein by reference to Exhibit (10)-91 to 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
(incorporated herein by reference to Exhibit (10)-4 to Report on Form 10-Q
for the quarter ended March 31, 1991, Commission File No.
1-4393).
10.23
Agreement
for Firm Power Purchase dated March 20, 1991 between Tenaska Washington,
Inc., a Delaware corporation, and PSE (incorporated herein by reference to
Exhibit (10)-1 to Report on Form 10-Q for the quarter ended June 30, 1991,
Commission File No. 1-4393).
10.24
Amendment
of Seasonal Exchange Agreement, dated December 4, 1991 between Pacific Gas
and Electric Company and PSE (incorporated herein by reference to Exhibit
(10)-107 to 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 (incorporated herein by reference to
Exhibit (10)-108 to 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)
(incorporated herein by reference to Exhibit 10.115 to 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) (incorporated herein by reference to Exhibit 10.116 to
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
(incorporated herein by reference to 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 (incorporated herein by
reference to Exhibit 10-P to Form 10-K for the year ended September 30,1994, File No. 1-11271).
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. (incorporated herein by reference to Exhibit 10-2
to Form 10-Q for the quarter ended June 30, 2002, File No. 1-16305 and
1-4393).
10.32
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. (incorporated herein by reference to Exhibit 10-3 to
Form 10-Q for the quarter ended June 30, 2002, File No. 1-16305 and
1-4393).
10.33
Amended
and Restated Credit Agreement dated March 29, 2007 among PSE and various
banks named therein, Wachovia Bank National Association as administrative
agent. (incorporated herein by reference to Exhibit 10.1 to Current Report
on Form 8-K, dated April 3, 2007, Commission File No. 1-16305 and
1-4393).
10.34
Credit
Agreement dated March 29, 2007, among PSE and various banks named therein,
JP Morgan Chase Bank, N.A., as administrative agent, (incorporated herein
by reference to Exhibit 10.2 to Current Report on Form 8-K, filed on April3, 2007, Commission File No. 1-16305 and 1-4393).
10.35
Loan
and Serving Agreement dated December 20, 2005, among PSE, PSE Funding,
Inc., and J.P. Morgan Chase Bank as program agent (incorporated herein by
reference to Exhibit 10.2 to the Current Report on Form 8-K dated December22, 2005, Commission File No. 1-4393 and 1-16305).
Puget
Energy, Inc. Non-employee Director Stock Plan. (incorporated herein by
reference to Appendix B to definitive Proxy Statement, dated March 7,2005, Commission File No. 1-16305).
**
10.38
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.)
Amendment
No. 1 to 2005 Long-Term Incentive Plan of Puget Energy, Inc. (incorporated
herein by reference to Exhibit 10.1 to the Current Report on Form 8-K,
dated February 14, 2006, Commission File Nos. 1-16305 and
1-4393).
Nonqualified
Stock Option Grant Notice/Agreement with S. P. Reynolds, Chief Executive
Officer and President dated March 11, 2002 (incorporated herein by
reference to Exhibit 99.1 and Exhibit 99.2 to Form S-8 Registration
Statement dated March 18, 2002, Commission File No.
333-84426).
**
10.49
Puget
Sound Energy Amended and Restated Supplemental Executive Retirement Plan
for Senior Management dated October 5, 2004. (incorporated
herein by reference to Exhibit 10.55 to Report on Form 10-K for fiscal
year ended December 31, 2005, Commission File No. 1-16305 and
1-4393).
**
10.50
Puget
Sound Energy Amended and Restated Deferred Compensation Plan for Key
Employees dated January 1, 2003. (incorporated herein by
reference to Exhibit 10.56 to Report on Form 10-K for fiscal year ended
December 31, 2005, Commission File No. 1-16305 and
1-4393).
**
10.51
Puget
Sound Energy Amended and Restated Deferred Compensation Plan for
Nonemployee Directors dated October 1, 2000. (incorporated
herein by reference to Exhibit 10.57 to Report on Form 10-K for fiscal
year ended December 31, 2005, Commission File No. 1-16305 and
1-4393).
Performance-Based
Restricted Stock Award Agreement with S.P. Reynolds, Chief Executive
Officer and President, dated May 12, 2005 (incorporated herein by
reference to Exhibit 10.4 to the Current Report on Form 8-K, dated May 12,2005, Commission File Nos. 1-16305 and 1-4393).
**
10.54
Form
of Amended and Restated Change of Control Agreement between Puget Sound
Energy, Inc. and Executive Officers (incorporated herein by reference to
Exhibit 10.3 to the Current Report on Form 8-K, dated February 14, 2006,
Commission File Nos. 1-16305 and 1-4393).
**
10.55
Form
of Performance-Based Restricted Stock Award Agreement between Puget Sound
Energy and Key Employees (incorporated herein by reference to Exhibit 10.1
to the Current Report on Form 8-K, dated February 28, 2006, Commission
File No. 1-16305).
**
10.56
Summary
of Severance Benefit for B.A. Valdman, Senior Vice President Finance and
Chief Financial Officer (incorporated herein by reference to Exhibit 10.55
to Puget Energy’s Report on Form 10-K for the fiscal year ended December31, 2006, Commission File No. 1-16305 and 1-4393).
**
10.57
Restricted
Stock Award Agreement with B.A. Valdman, Senior Vice President Finance and
Chief Financial Officer, dated December 4, 2003 (incorporated herein by
reference to Exhibit 10.56 to Puget Energy’s Report on Form 10-K for the
fiscal year ended December 31, 2006, Commission File No. 1-16305 and
1-4393).
Statement
setting forth computation of ratios of earnings to fixed charges of Puget
Energy (2003 through 2007).
*
12.2
Statement
setting forth computation of ratios of earnings to fixed charges of Puget
Sound Energy (2003 through 2007).
*
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
– Eric M. Markell.
*
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 –
Eric M. Markell.
*
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 – Eric M.
Markell.
*
Filed
herewith.
**
Management
contract or compensating plan or
arrangement.
Dates Referenced Herein and Documents Incorporated by Reference
