Document/ExhibitDescriptionPagesSize 1: 10-Q Puget Energy 2nd Quarter 2007 Form 10-Q HTML 948K
10: 10-Q Puget Energy 2nd Quarter 2007 Form 10-Q -- PDF 315K
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2: EX-12.1 Puget Energy Computation of Ratios HTML 115K
3: EX-12.2 Puget Sound Energy Computation of Ratios HTML 115K
4: EX-31.1 Puget Energy CEO Certification HTML 12K
5: EX-31.2 Puget Energy CFO Certification HTML 12K
6: EX-31.3 Puget Sound Energy CEO Certification HTML 12K
7: EX-31.4 Puget Sound Energy CFO Certification HTML 12K
8: EX-32.1 CEO Certification HTML 10K
9: EX-32.2 CFO Certification HTML 10K
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 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
/ /
Puget
Sound Energy, Inc.
Large
accelerated filer
/ /
Accelerated
filer
/ /
Non-accelerated
filer
/X/
Indicate
by check mark whether the registrant is a shell company (as defined in Exchange
Act Rule 12b-2)
Puget
Energy, Inc.
Yes
/ /
No
/X/
Puget
Sound Energy, Inc.
Yes
/ /
No
/X/
As
of
July 25, 2007, (i) the number of shares of Puget Energy, Inc. common stock
outstanding was 117,024,977 ($.01 par value) and (ii) all of the outstanding
shares of Puget Sound Energy, Inc. common stock were held by Puget Energy,
Inc.
This Quarterly
Report on Form 10-Q is a combined quarterly report filed separately by two
different registrants, Puget Energy, Inc. (Puget Energy) and Puget Sound Energy,
Inc. (PSE). Any references in this report to the “Company” are to
Puget Energy and PSE collectively. PSE makes no representation as to
the information contained in this report relating to Puget Energy and the
subsidiaries of Puget Energy other than PSE and its subsidiaries.
Puget
Energy, Inc. (Puget Energy) and Puget Sound Energy, Inc. (PSE) are including
the
following cautionary statements in this Form 10-Q 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. However, 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 (gas and electric), licensing of hydroelectric operations
and
gas storage facilities, recovery of other capital investments, recovery
of
power and gas costs, recovery of regulatory assets and present or
prospective wholesale and retail competition;
·
Failure
to comply with new 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;
·
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 that impact customer loads;
·
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 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 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 gas or electric plant to operate as
intended;
·
The
ability to renew contracts for electric and gas supply and the price
of
renewal;
·
Blackouts
or large curtailments of transmission systems, whether PSE’s or others’,
which can 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 gas pipeline delivering to PSE’s system, which may
impact PSE’s ability to adequately deliver gas supply 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; and
·
The
ability to maintain effective internal controls over financial reporting
and operational processes.
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 Item 1A-“Risk Factors” in our most recent annual report on
Form 10-K and this quarterly report for updates.
Foreign
currency translation adjustment, net of tax of $0, $(167), $0 and
$(176),
respectively
--
(311
)
--
(327
)
Unrealized
gain from pension and postretirement plans, net of tax of $642, $78,
$1,285 and $78, respectively
1,193
145
2,386
145
Net
unrealized gains (losses) on derivative instruments during the period,
net
of tax of $(7,465), $(2,684), $(5,551) and $(9,646),
respectively
(13,863
)
(4,984
)
(10,309
)
(17,914
)
Reversal
of net unrealized gains (losses) on derivative instruments settled
during
the period, net of tax of $(585), $(5,345), $1,068 and $(5,323),
respectively
(1,086
)
(9,926
)
1,984
(9,885
)
Amortization
of cash flow hedge contracts to earnings, net of tax of $43, $102,
$86 and
$206, respectively
79
190
159
382
Settlement
of cash flow hedge contracts net of tax of $0, $7,463, $0 and $7,463,
respectively
--
13,860
--
13,860
Deferral
of cash flow hedges related to the power cost adjustment mechanism,
net of
tax of $0, $375, $0 and $3,366, respectively
--
696
--
6,252
Comprehensive
loss
(13,677
)
(330
)
(5,780
)
(7,487
)
Comprehensive
income
$
24,935
$
53,199
$
111,894
$
138,651
The
accompanying notes are an integral part of the financial
statements.
Unrealized
gain from pension and postretirement plans, net of tax of $642, $78,
$1,285 and $78, respectively
1,193
145
2,386
145
Net
unrealized gains (losses) on derivative instruments during the period,
net
of tax of $(7,465), $(2,684), $(5,551) and $(9,646),
respectively
(13,863
)
(4,984
)
(10,309
)
(17,914
)
Reversal
of net unrealized gains (losses) on derivative instruments settled
during
the period, net of tax of $(585), $(5,345), $1,068 and $(5,323),
respectively
(1,086
)
(9,926
)
1,984
(9,885
)
Amortization
of cash flow hedge contracts to earnings, net of tax of $43, $102,
$86 and
$206, respectively
79
190
159
382
Settlement
of cash flow hedge contracts net of tax of $0, $7,463, $0 and $7,463,
respectively
--
13,860
--
13,860
Deferral
of cash flow hedges related to the power cost adjustment mechanism,
net of
tax of $0, $375, $0 and $3,366, respectively
--
696
--
6,252
Comprehensive
loss
(13,677
)
(19
)
(5,780
)
(7,160
)
Comprehensive
income
$
24,681
$
30,081
$
111,356
$
96,779
The
accompanying notes are an integral part of the financial
statements.
Adjustments
to reconcile net income to net cash provided by operating
activities:
Depreciation
and amortization
135,441
128,429
Deferred
income taxes and tax credits, net
19,580
(11,562
)
Net
unrealized (gain) loss on derivative instruments
(4,246
)
825
Amortization
of gas pipeline capacity assignment
(5,411
)
(5,267
)
Cash
collateral paid from energy suppliers
--
(19,950
)
Decrease
in residential exchange program
(25,673
)
(7,529
)
Cash
receipt from lease purchase option settlement
18,909
--
Chelan
PUD contract initiation payment
--
(89,000
)
Power
cost adjustment mechanism
2,788
--
Storm
damage deferred costs
(16,359
)
(4,453
)
Other
8,374
28,851
Change
in certain current assets and liabilities:
Accounts
receivable and unbilled revenue
195,971
206,759
Materials
and supplies
(16,635
)
(3,146
)
Fuel
and gas inventory
19,945
3,420
Prepayments
and other
(25,726
)
(1,785
)
Purchased
gas adjustment receivable/payable
81,425
(5,638
)
Accounts
payable
(168,605
)
(165,884
)
Taxes
payable
8,814
(53,214
)
Accrued
expenses and other
410
7,479
Net
cash provided by operating activities
346,138
112,274
Investing
activities:
Construction
expenditures - excluding equity AFUDC
(375,677
)
(306,387
)
Energy
efficiency expenditures
(18,464
)
(13,846
)
Refundable
cash received for customer construction projects
9,179
7,739
Restricted
cash
(2
)
(3
)
Other
1,394
3,466
Net
cash used by investing activities
(383,570
)
(309,031
)
Financing
activities:
Change
in short-term debt, net
(38,201
)
168,099
Loan
from Puget Energy
164
--
Dividends
paid
(52,654
)
(57,411
)
Investment
from Puget Energy
2,740
62,986
Issuance
of bonds and notes
250,000
250,000
Redemption
of trust preferred stock
(37,750
)
(200,000
)
Redemption
of bonds and notes
(100,000
)
(46,000
)
Settlement
of cash flow hedge interest rate derivative
--
21,323
Issuance
and redemption cost of bonds and other
1,249
(2,598
)
Net
cash provided by financing activities
25,548
196,399
Net
decrease in cash
(11,884
)
(358
)
Cash
at beginning of year
28,092
16,709
Cash
at end of period
$
16,208
$
16,351
Supplemental
cash flow information:
Cash
paid for interest (net of capitalized interest)
$
91,666
$
88,958
Income
taxes paid
23,000
77,346
The
accompanying notes are an integral part of the financial
statements.
COMBINED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS
(1)
Summary
of Consolidation
Policy
Basis
of Presentation
Puget
Energy, Inc. (Puget Energy) is a holding company that owns Puget Sound Energy,
Inc. (PSE) and until May 7, 2006, InfrastruX Group, Inc.
(InfrastruX). PSE is a public utility incorporated in the state of
Washington that furnishes electric and 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 “theCompany.” 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 gas utility industries
primarily in the Midwest, Texas, south-central and eastern United States
regions.
The
consolidated financial statements contained in this Form 10-Q are
unaudited. In the respective opinions of the management of Puget
Energy and PSE, all adjustments necessary for a fair statement of the results
for the interim periods have been reflected and were of a normal recurring
nature. These condensed financial statements should be read in
conjunction with the audited financial statements (and the Combined Notes
thereto) included in the combined Puget Energy and PSE Report on Form 10-K
for
the year ended December 31, 2006.
The
preparation of financial statements in conformity with GAAP 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.
PSE
collected Washington State excise taxes (which are a component of general
retail
rates) and municipal taxes of $48.2 million and $122.9 million for the three
and
six months ended June 30, 2007, respectively, and $40.6 million and $105.2
million for the three and six months ended June 30, 2006,
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.
(2)
Earnings
per Common Share (Puget Energy
Only)
Puget
Energy’s basic earnings per common share have been computed based on weighted
average common shares outstanding of 116,659,000 and 116,567,000 for
the three and six months ended June 30, 2007, respectively, and 115,907,000
and
115,817,000 for the three and six months ended June 30, 2006,
respectively.
Puget
Energy’s diluted earnings per common share have been computed based on weighted
average common shares outstanding and issuable upon exercise of options or
expiration of vesting periods of 117,158,000 and 117,115,000 for the three
and
six months ended June 30, 2007, respectively, and 116,405,000 and 116,266,000
for the three and six months ended June 30, 2006, respectively. These
shares include the dilutive effect of securities related to employee and
director equity plans.
(3)
Accounting
for Derivative Instruments and Hedging
Activities
Statement
of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative
Instruments and Hedging Activities,” 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, “Accounting for the Effects of Certain
Types of Regulation,” 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 gas portfolios.
The
following tables present 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 three and six months ended June 30, 2007 and June 30,2006:
The
Company
recorded a decrease of $1.5 million and an increase of $4.2 million in earnings
during the three and six months ended June 30, 2007, respectively, primarily
due
to the change in the mark-to-market valuation of a physically delivered gas
supply contract for electric generation that did not meet NPNS or cash flow
hedge criteria. The mark-to-market valuation in 2007 primarily
relates to a physical contract reserve that was released on a contract due
to
improved credit of a counterparty. At June 30, 2007, the
Company deferred a net unrealized day one loss of $10.0 million related to
a three and a half year locational power exchange contract. The fair
value of the exchange contract was based on a propriety model. The
deferred loss will be amortized over the term of the contract based upon the
power exchanged. Any future changes in the mark-to-market value will
be recorded through the income statement. The contract has an
economic benefit to the Company over its term and will help ease electric
transmission congestion across the Cascade Mountains during 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 same quantities of power at the Mid-Columbia trading hub
location.
The
amount of net unrealized gain (loss), net of tax, related to the Company’s cash
flow hedges under SFAS No. 133 consisted of the following at June 30, 2007
and
December 31, 2006:
Other
comprehensive income – unrealized gain (loss)
$ (3.4)
$ 4.9
The
Company’s energy derivative contracts designated as cash flow hedges that
represent forward financial purchases of natural gas supply for electric
generation from PSE-owned electric plants in future periods at June 30, 2007
and
December 31, 2006 are presented below:
If
it is
determined that it is uneconomical to run the plants in the future period,
the
hedging relationship is ended and the cash flow hedge is de-designated and
any
unrealized gains and losses are recorded in the income
statement. Gains and losses are recognized in energy costs and are
included as part of the PCA mechanism when these de-designated cash flow hedges
are settled.
The
following table presents derivative hedges of natural gas contracts to serve
natural gas customers at June 30, 2007 and December 31, 2006:
Due
to
the PGA mechanism, mark-to-market adjustments relating to the natural gas
business have been reclassified to a deferred account in accordance with SFAS
No. 71. The PGA mechanism passes increases and decreases in the cost
of natural gas supply to customers. As the gains and losses on the
hedges are realized in future periods, they will be recorded as gas costs under
the PGA mechanism.
At
June30, 2007, a portion of the ending balance in other comprehensive income relates
to previously settled treasury interest rate swap contracts which gave rise
to a
loss of $8.3 million after-tax and accumulated amortization.
(4)
Discontinued
Operations and Corporate Guarantees (Puget Energy
Only)
On
May 7,2006, Puget Energy sold InfrastruX to an affiliate of Tenaska Power Fund, L.P.
(Tenaska). Puget Energy accounted for InfrastruX as a discontinued
operation under SFAS No. 144, “Accounting for the Impairment or Disposal of
Long-Lived Assets” in 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 June 30, 2007, restricted
cash in the escrow account was $3.9 million, which is included in Puget Energy’s
balance sheets, representing management’s estimate of the aggregate fair value
of Puget Energy’s maximum risk of loss 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. The
representation and warranty obligation expires May 7, 2008.
Puget
Energy also agreed to indemnify Tenaska for certain costs and expenses incurred
after closing by InfrastruX related to an investigation of 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 June 30, 2007, a liability in the amount of $5.0
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. 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 reasonably estimated in accordance with SFAS No. 5,
“Accounting for Contingencies.”
Puget
Energy also provided an environmental guarantee as part of the sale
agreement. Under the terms of the agreement, Tenaska will be
responsible for the first $0.1 million of environmental claims, Tenaska and
Puget Energy will share the next $6.4 million equally and Puget Energy will
be
responsible for the next $3.5 million. Puget Energy believes it will
not have a future loss in connection with the environmental
guarantee.
The
following table summarizes Puget Energy’s income from discontinued
operations:
Three
Months Ended
June
30,
Six
Months Ended
June
30,
(Dollars
in Thousands)
2007
2006
2007
2006
Revenues
$
--
$
46,504
$
--
$
138,573
Operating
expenses (including interest expense)
--
(40,735
)
--
(128,634
)
Pre-tax
income
--
5,769
--
9,939
Income
tax expense
--
(2,260
)
--
(3,516
)
Puget
Energy carrying value adjustment of InfrastruX
--
--
--
7,269
Puget
Energy cost of sale related to InfrastruX, net of tax
--
--
--
(937
)
Puget
Energy deferred tax basis adjustment of InfrastruX
--
--
--
9,966
Gain
on sale, net of tax
12
29,764
12
29,764
Minority
interest in income of discontinued operations
--
(319
)
--
(584
)
Income
from discontinued operations
$
12
$
32,954
$
12
$
51,901
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 $6.7 million ($4.3
million after-tax) lower depreciation and amortization expense than otherwise
would have been recorded as continuing operations for the six months ended
June30, 2006. Puget Energy did not record any amortization expense
related to the intangible assets of InfrastruX in 2006.
(5)
Retirement
Benefits
The
Company has a defined benefit pension plan with a cash balance feature covering
substantially all PSE employees. Benefits are a function of age,
salary and service. Puget Energy also maintains a non-qualified
supplemental retirement plan for officers and certain director-level
employees.
The
following table summarizes the net periodic benefit cost for the three months
ended June 30:
Pension
Benefits
Other
Benefits
(Dollars
in thousands)
2007
2006
2007
2006
Service
cost
$
3,392
$
3,061
$
91
$
85
Interest
cost
6,686
6,163
379
358
Expected
return on plan assets
(9,679
)
(9,434
)
(205
)
(182
)
Amortization
of prior service cost
511
586
134
134
Recognized
net actuarial (gain) loss
1,420
1,246
(56
)
(127
)
Amortization
of transition obligation
--
--
105
105
Net
periodic benefit cost
$
2,330
$
1,622
$
448
$
373
The
following table summarizes
the net periodic benefit cost for the six months ended June 30:
Pension
Benefits
Other
Benefits
(Dollars
in thousands)
2007
2006
2007
2006
Service
cost
$
6,655
$
6,122
$
183
$
171
Interest
cost
13,256
12,329
759
716
Expected
return on plan assets
(19,429
)
(18,869
)
(410
)
(363
)
Amortization
of prior service cost
1,021
1,171
267
267
Recognized
net actuarial (gain) loss
2,594
2,499
(112
)
(254
)
Amortization
of transition obligation
--
--
209
209
Net
periodic benefit cost
$
4,097
$
3,252
$
896
$
746
The
Company previously disclosed in its financial statements for the year ended
December 31, 2006 that it expected contributions by the Company to fund the
pension and other benefits plans for the year ending December 31, 2007 to be
$4.5 million and $0.3 million, respectively. During the three and six
months ended June 30, 2007, the actual cash contributions to the pension plans
were $0.4 million and $0.9 million, respectively. Based on this
activity, the Company anticipates contributing an additional $3.6 million to
the
Company’s non-qualified pension plan in 2007. The full amount of the
pension plan funding for 2007 is for the Company’s non-qualified supplemental
retirement plan.
During
the three and six months ended June 30, 2007, actual other post-retirement
medical benefit plan contributions were less than $0.2 million and $0.7 million,
respectively, and the Company does not expect to make additional contributions
for the remaining period of 2007.
On
June20, 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. As of June 20, 2007, no new IBEW employees will receive a
retiree medical subsidy at retirement. Current IBEW employees with
less than five years of service will no longer receive a subsidy at retirement
and those employees with more than one year of service but less than five years
of service will receive a one-time cash payment that varies depending on the
years of employment with PSE. Current IBEW employees with five or
more years of service have a one-time opportunity to elect a cash payment in
lieu of continuing eligibility for the retiree medical subsidy. Once
elections are known, PSE will record a curtailment gain or loss in the third
quarter of 2007. The Company does not expect the curtailment gain or
loss to be material to its financial statements in 2007.
(6)
Income
Taxes
In
July
2006, Financial Accounting Standards Board (FASB) issued Interpretation No.
48
(FIN 48), “Accounting for Uncertainty in Income Taxes, an Interpretation of FASB
Statement No. 109,” 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 but accrued
$6.6 million in interest expense related to tax deductions for certain
capitalized internal labor and related overhead costs previously deducted before
repayment in 2005 and 2006. Additionally, the Company has accrued
$0.2 million and $0.6 million in interest expense for the three and six months
ended June 30, 2007, respectively, related to the tax deductions for the
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 IRS audit of
the Company’s 2001, 2002 and 2003 federal income tax returns, the IRS disallowed
the deduction, citing Revenue Ruling 2005-53. The Company believes
the original deductions were valid as filed and has formally appealed the IRS
adjustment. The Company repaid the tax benefits in 2005 and 2006 as
provided in the new Regulations, issued on August 2, 2005 (Regulation
1.263(a)-1). At December 31, 2006, the full tax benefit had been
repaid. The IRS national office is in the process of establishing
settlement guidelines which will apply to its settlement offers on this
issue. It is possible that this issue could be resolved in the next
12 months.
Based
on prior Washington Utilities and Transportation Commission (Washington
Commission) orders on this issue, it is management’s expectation that if the IRS
is ultimately successful in challenging some portion of the deduction the
Company could request rate recovery of the regulatory asset for the interest
accrued.
For federal income tax purposes, the Company has open tax years from 2001
through 2007. The Company continues its policy of classifying
interest and penalties as interest expense as other expense in the financial
statements.
(7)
Regulation
and Rates
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 the Goldendale
generating facility (Goldendale) ownership and operating costs through retail
electric rates. The requested electric rate increase is $64.7 million
or 3.7% annually. 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 rate case signed by PSE
and
certain other parties to the proceeding was filed with the Washington
Commission. The terms of the settlement agreement include an electric
rate increase of $64.7 million. Goldendale ownership and operating
costs are agreed upon as prudent, thus allowing for recovery of the costs
through electric retail rates and the parties agree to participate in a
collaborative effort to examine the rules and procedures of the Washington
Commission’s PCORC process. On August 2, 2007, the Washington
Commission approved the settlement agreement which provides for new
electric rates effective on September 1, 2007.
On
May21, 2007, the Bonneville Power Administration (BPA) informed PSE and other
investor-owned utilities that BPA was suspending payments related to its
residential exchange program due to an adverse Ninth Circuit Court of Appeals
(Ninth Circuit) decision of May 3, 2007. The Ninth Circuit concluded
in its decision that certain BPA actions in entering into residential exchange
settlements in 2000 were not in accordance with the law. BPA has
suspended payments under the residential exchange program until final decisions
by the Ninth Circuit are determined. As a result of the BPA
suspension of payment, PSE filed for suspension of the Residential Exchange
Credit electric tariff which is a pass-through of the benefits of the
Residential Exchange. The Washington Commission approved the
suspension of electric tariff effective June 7, 2007 to all residential and
small farm customers. As of June 30, 2007, PSE had provided
residential and small farm customers more benefits under the residential
exchange program than what BPA has reimbursed to PSE primarily due to the
seasonal nature of electric energy used by PSE’s electric
customers. As such, PSE has a regulatory asset representing an amount
receivable from its electric residential and small farm customers of $33.3
million. Under Federal law, investor-owned utilities receiving
residential exchange benefits must pass-through the benefits to their
residential and small farm electric customers.
PSE
has
an accounting petition pending before the Washington Commission requesting
deferred accounting treatment for amounts credited to customers under the
Residential Exchange Credit electric tariff that have not been reimbursed by
BPA. The accounting petition is seeking approval of recording
carrying costs on the deferred balance until the deferred balance is recovered
from customers. PSE is not currently accruing carrying costs on such
balances. Alternatively, PSE may seek recovery of the deferral
through the pass-through electric rate tariff if the accounting petition is
not
approved.
In
May
2007, the Washington Commission Staff alleged that PSE’s 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, “Accounting for
Contingencies” criteria for recording a loss contingency and thus recorded a
$2.0 million loss reserve. The Washington Commission investigation is
ongoing and a settlement conference is scheduled for mid-August
2007.
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 the Company will incur related to its purchase of Goldendale during the
period prior to inclusion in PSE’s retail electric rates in the
PCORC. PSE established a regulatory asset of $7.0 million at June 30,2007. Deferrals will continue until new rates are approved in the
PCORC proceeding, which is anticipated to be September 1, 2007.
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 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 PCORC increase of $96.1 million
annually effective July 1, 2006.
On
January 5, 2007, the Washington Commission also issued its order in PSE’s
natural gas general rate case, granting an increase for gas customers of $29.5
million or 2.8% annually, effective January 13, 2007.
On
June20, 2002, the Washington Commission approved a PCA mechanism that becomes
operative 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
ended 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 mechanism measurement period from January through December
starting in 2007. On January 5, 2007, the Washington Commission
approved the PCA mechanism for continuation 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.
(8)
Litigation
Residential
Exchange. Petitioners in several actions in the Ninth
Circuit against BPA asserted that BPA acted contrary to law in entering into
a
number of agreements, including the amended settlement agreement (and the May
2004 agreement) between BPA and PSE regarding the BPA Residential Purchase
and
Sale 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 entering into agreements
in
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
June 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. 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 have on
PSE.
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 Purchase and Sale 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. In May 2007, following the Ninth
Circuit’s issuance of these opinions, BPA suspended payments to PSE under the
amended settlement agreement (and the May 2004 agreement). As the
residential exchange benefits are a pass-through benefit, PSE currently cannot
predict any cash flow impact from these discussions other than what has already
been provided to customers.
Colstrip
Matters. 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. Discovery is ongoing. The trial is set for the first
quarter 2008. On March 29, 2007, a second complaint was filed on
behalf of two ranch owners alleging damage due to the Colstrip Units 3 & 4
effluent holding pond.
In
December 2003, the Environmental Protection Agency (EPA) issued an
Administrative Consent Order (ACO) which alleged violation of the Clean Air
Act
permit at Colstrip since 1980. The permit required Colstrip to
submit, for review and approval by the EPA, an analysis and proposal for
reducing emissions of nitrogen oxide to address visibility concerns upon the
occurrence of certain triggering events. The EPA asserts that
regulations it promulgated in 1980 triggered this
requirement. Although Colstrip owners believe that the ACO was
unfounded, the Colstrip owners entered into negotiations with the EPA and the
Northern Cheyenne Tribe. On May 14, 2007, the ACO was approved and
deemed entered by the Montana Federal District Court. The agreement
requires installation of low nitrogen oxide equipment on Colstrip Units 3 &
4, payment of a non-material penalty and financing of an energy efficiency
project on the Northern Cheyenne reservation. The estimated total
additional capital cost to PSE is $2.7 million.
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 and were
required to submit a BART engineering analysis for Colstrip Units 1 & 2 in
the third quarter of 2007. PSE cannot yet determine the need for or
costs of additional controls to comply with this rule, though any such costs
could be significant and would most likely be capitalized to plant.
Proceedings
Relating to the Western Power Market. PSE is vigorously
defending each case in the western power market
proceedings. 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/or
adversely affect PSE’s financial condition, results of operations or
liquidity.
CPUC
Decision. Proceedings, including filings of requests for
rehearing or further review, before the Ninth Circuit and/or FERC, continue
to
be stayed upon the Court’s own motion to allow for possible settlement
discussions to proceed. The matter is stayed until August 13,2007.
Lockyer
Case. On June 18, 2007, the U.S. Supreme Court denied the
petition that PSE and other energy sellers had submitted that sought Supreme
Court review of the Ninth Circuit decision. As such, this matter will
be remanded to FERC for further proceedings, but not before August 13, 2007,
when the stay of the mandate back to FERC expires.
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.
(9)
Related
Party Transaction
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. (PSE Funding),
a PSE
subsidiary, which is the London Interbank Offered Rate (LIBOR) plus a marginal
rate. At June 30, 2007, the outstanding balance of the Note was $24.5
million and the interest rate was 5.5%. The outstanding balance and
the related interest under the Note are eliminated by Puget Energy upon
consolidation of PSE’s financial statements.
(10)
Financings
On
June1, 2007, PSE redeemed all remaining $37.8 million of its 8.231% 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 sheet and referred to herein as
“Securities”). The purpose of the redemption was to reduce interest
costs by retiring higher cost debt. The Securities were redeemed at a
4.12% premium, or $39.3 million, plus accrued interest on the redemption
date.
On
June4, 2007, PSE issued $250 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 repay short-term debt, incurred in part
to redeem the Securities. The Notes are structured to be treated as
debt by the IRS, yet they are considered to have 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 June1,2017. They are presented on the balance sheet as a separate line item
in the redeemable securities and long-term debt.
In
March
2007, PSE entered into a five-year, $350 million credit agreement with a group
of banks. The agreement supports the Company’s energy hedging
activities. Pursuant to the Washington Commission order in PSE’s
electric and gas general rate cases issued on January 5, 2007, the costs of
this
hedging credit facility will be recovered through the PCA and PGA
mechanisms. Under the terms of the credit agreement, PSE pays a
floating interest rate on outstanding borrowings based either on the agent
bank’s prime rate or on LIBOR plus a marginal rate based on PSE’s long-term
credit rating at the time of borrowing. The facility can also be used
to provide letters of credit. PSE pays a commitment fee on any unused
portion of the credit agreement based on long-term credit ratings of
PSE.
In
March
2005, PSE entered into a five-year, $500 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 million facility.
(11)
Other
FASB
Interpretation No. 46R, “Consolidation of Variable Interest Entities” (FIN 46R)
requires that if a business entity has a controlling financial interest in
a
variable interest entity, the financial statements of the variable interest
entity must be included in the consolidated financial statements of the business
entity. The Company has evaluated its power purchase agreements and
determined that three counterparties during the six months ended June 30, 2007
may be considered variable interest entities. Consistent with FIN
46R, PSE submitted requests for information to those parties; however, the
parties have refused to submit to PSE the necessary information for PSE to
determine whether they meet the requirements of a variable interest
entity. PSE also determined that it does not have a contractual right
to such information. PSE will continue to submit requests for
information to the counterparties in accordance with FIN 46R.
For
the
three 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 power purchase agreement
prices. PSE’s purchased electricity expense for the three months
ended June 30, 2007 and 2006 for these three entities was $30.6 million and
$37.1 million, respectively. PSE’s purchased electricity expense for
the six months ended June 30, 2007 and 2006 for these three entities was $97.2
million and $95.9 million, respectively.
One
of
these counterparties, Sumas Cogeneration Company, LP (Sumas), delivered a letter
to PSE on May 7, 2007, stating that it had sold its dedicated 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. PSE
and Sumas have initiated discussion relating to Sumas’ actions under the
contract, but PSE cannot yet determine what may result from such
discussions.
The
EPA
required states to produce regulations by November 15, 2006 to bring their
mercury emissions in line with those mandated by the Clean Air Mercury
Rule. The Montana Board of Environmental Review approved the state’s
regulation to limit mercury emissions from coal-fired plants on October 16,2006. The new rule takes a two-tiered approach to reducing mercury
emissions, allowing power plants burning lower-quality lignite coal to release
more emissions than plants burning cleaner sub-bituminous coal, such as
Colstrip. The new rule has a more stringent limit than the federal
rule (0.9 lbs/Trillion British thermal unit (TBtu), instead of the federal
1.4
lbs/TBtu), but includes a cap-and-trade provision as well as alternative
emission limits for plants that have tried to meet the new standards but have
demonstrated that they cannot. The Colstrip owners are still
evaluating the potential impact of the new rule and have not determined whether
the new rule will be appealed.
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 June 30, 2007 were approximately $12.0
million. PSE estimates the total remediation cost to be approximately
$15.0 million. At June 30, 2007, PSE had an insurance receivable
recorded in the amount of $12.6 million associated with this fuel
spill. PSE has also filed a petition with the Washington Commission
to defer costs associated with the remediation effort. The Washington
Commission has not yet ruled on this matter.
On
May30, 2007, PSE agreed to extend the terms of the existing leases of its Bellevue
corporate office complex from 10 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 removal of the purchase option. PSE intends to file
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.
(12)
New
Accounting Pronouncements
In
September 2006, FASB issued SFAS No, 157, “Fair Value
Measurements”. SFAS No. 157 establishes a common definition for fair
value to be applied to GAAP, a framework for measuring fair value, and expands
disclosure about such fair value measurements. SFAS No. 157 is
effective for fiscal years beginning after November 15, 2007 which will be
the
calendar year beginning January 1, 2008 for the Company. The Company
is currently assessing the impact of SFAS No. 157 on its financial
statements.
Item
2. Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
The
following discussion of the Company’s financial condition and results of
operations contains forward-looking statements that involve risks and
uncertainties, such as statements of the Company’s plans, objectives,
expectations and intentions. Words such as “anticipates,”“believes,”“estimates,”“expects,”“future,”“intends,”“plans,”“projects,”“predicts,”“will likely result,” and “will continue” and similar expressions are used to
identify 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. The
Company’s actual results could differ materially from those anticipated in these
forward-looking statements for many reasons, including the factors described
below and under the caption “Forward-Looking Statements” at the beginning of
this report. You should not place undue reliance on these
forward-looking statements, which apply only as of the date of this Form
10-Q.
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 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 substantially 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 gas service
in a
cost effective manner through PSE.
Puget
Sound Energy
PSE
generates revenues from the sale of
electric and gas services, mainly to residential and commercial customers within
Washington State. PSE’s operating revenues and associated expenses
are not generated evenly during the year. Variations in energy usage
by consumers occur from season to season and from month to month within a
season, primarily as a result of weather conditions. PSE normally
experiences its highest retail energy sales 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 Federal Energy Regulatory Commission (FERC) and Washington Utilities
and Transportation Commission (Washington Commission) regulation which may
impact a large array of business activities, including limitation of future
rate
increases related to retail rates, transmission rates and wholesale power sales;
directed accounting requirements that could 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 contracted generation plants where energy is obtained; storms or
other
events which can damage gas and electric distribution and transmission lines;
wholesale market stability over time and significant evolving environmental
legislation.
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. PSE is
continually exploring new electric-power resource generation and long-term
purchase power agreements to meet this goal on an ongoing basis. On
February 21, 2007, PSE acquired the Goldendale generating facility (Goldendale),
a 277 megawatt (MW) capacity natural gas generating facility in the state of
Washington, from the Calpine Corporation through its bankruptcy
proceeding. PSE paid $120.0 million for such generating facility plus
transaction costs totaling $2.4 million. PSE is seeking recovery of
related ownership and operating costs in a Power Cost Only Rate Case (PCORC)
rate case filed on March 20, 2007 with the Washington Commission. PSE
filed a settlement agreement in the PCORC rate case on July 5, 2007 which
approved the Goldendale acquisition. PSE is awaiting approval from
the Washington Commission on the matter.
On
May 31, 2007, PSE filed its 2007
Integrated Resource Plan (IRP) with the Washington Commission. The
plan supports a strategy of diverse acquisitions to cost-effectively meet
growing demand for energy and reduce carbon emissions. According to
the IRP, PSE can secure additional power supplies through heightened
energy-efficiency efforts and expanded wind-power generation. PSE
believes that a cost-effective and environmentally responsible way to
source generation will likely include additional natural gas-fired
resources.
In
August 2006, PSE announced the
selection of seven projects for further discussion and possible negotiation
as a
result of the 2005 request for proposal process. Of the seven, PSE
has completed three, which include the purchase of Goldendale, the purchase
of
150 MW of winter, on-peak energy under a four-year power purchase agreement
which commences in 2008, and on July 12, 2007, the execution of a power purchase
agreement for a portion of the output of Klondike Wind Power III, LLC, a
wind-powered electric generating facility scheduled to be completed in fall
2007
in north-central Oregon. Of the remaining four, 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. PSE’s
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.
Results
of Operations
Puget
Energy
All
the
operations of Puget Energy are conducted through PSE and until May 7, 2006,
InfrastruX. Net income for the three months ended June 30, 2007 was
$38.6 million on operating revenues of $661.1 million compared to net income
of
$53.5 million on operating revenues from continuing operations of $574.4 million
for the same period in 2006. Net income for 2006 includes the results
of discontinued operations for InfrastruX.
Basic
and
diluted earnings per share for the three months ended June 30, 2007 were $0.33
compared to basic and diluted earnings per share for the three months ended
June30, 2006 of $0.46. Included in the basic and diluted earnings per
share for the three months ended June 30, 2006 were earnings per share related
to discontinued operations of InfrastruX of $0.28. Electric margin
increased $32.6 million and gas margin increased $8.1 million for the three
months ended June 30, 2007, compared to the same period in
2006. Offsetting
the
increases in margin were an increase of $15.3 million related to utility
operation and maintenance, a $1.9 million increase in non-utility operation
and
maintenance and other expenses, a $1.2 million increase in depreciation
and amortization, an increase in other expenses of $2.0 million due to the
accrual of a gas pipeline penalty proposed by Washington Commission Staff,
a
$7.9 million increase in interest expense due to higher debt levels, a decrease
of $1.7 in the unrealized gain on derivative instruments and an increase in
income taxes of $6.8 million. Net income for the three months ended
June 30,2006
was positively impacted by income from discontinued operations from InfrastruX
of $33.0 million (after-tax). The income from discontinued operations
for the three months ended June 30, 2006 includes a gain on disposal of $29.8
million (after-tax) resulting from the sale of InfrastruX. The
increase was partially offset by a charitable contribution of $15.0 million
($9.75 million after-tax) to the Puget Sound Energy Foundation (Foundation)
formed on May 12, 2006.
For
the
six months ended June 30, 2007, Puget Energy’s net income was $117.7 million on
operating revenues from continuing operations of $1.7 billion compared to net
income of $146.1 million on operating revenues from continuing operations of
$1.5 billion for the same period in 2006. Basic and diluted earnings
per share for the six months ended June 30, 2007 were $1.01 and $1.00,
respectively, compared to basic and diluted earnings per share of $1.26 for
the
same period in 2006.
Net
income for the
six months ended June 30, 2007 was positively impacted by increased electric
and
gas margins of $27.4 million and $18.2 million, respectively, compared to the
same period in 2006. Net income was negatively impacted by an
increase of $26.1 million related to utility operation and maintenance, an
increase in depreciation and amortization of $7.0 million and a $15.4 million
increase in interest expense due to increased debt levels. Net
income for the six months ended June 30, 2006 was positively impacted by income
from discontinued operations of InfrastruX of $51.9 million
(after-tax). The income from discontinued operations for the six
months ended June 30, 2006 included a gain on disposal of $29.8 million
(after-tax) resulting from the sale of InfrastruX. The increase was
partially offset by the charitable contribution of $15.0 million ($9.75 million
after-tax) by Puget Energy.
Puget
Sound Energy
PSE’s
operating revenues and associated expenses are not generated evenly during
the
year. Variations in energy usage by customers 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. Power cost recovery is seasonal, with underrecovery
normally in the first and fourth quarters and overrecovery in the second and
third quarters. Varying wholesale electric prices and the amount of
hydroelectric energy supplies available to PSE also make quarter to quarter
comparisons difficult.
Energy
Margins
The
following table displays the details of electric margin changes for the three
months ended June 30, 2007 compared to the same period in
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.
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 $32.6 million for the three months ended June 30, 2007 compared
to the same period in 2006 due to lower purchased electricity costs related
to
increased production of low cost hydroelectric power and company-owned
generating facilities. The PCORC rate increase of 5.9% effective July1, 2006, net of a 1.3% general rate decrease effective January 13, 2007
increased electric margin by approximately $9.6 million due in part to the
recovery of the Wild Horse wind project (Wild Horse). In addition, a
1.8% increase in retail-sales volumes increased electric margin $2.6
million. These increases were partially offset by a decrease in
electric margin of $3.7 million 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. Such
favorable changes in the allocation of power costs between PSE and the customer
may not be repeated in the future and should not be considered a recurring
element in operating income for the quarter.
The
Power
Cost Adjustment (PCA) mechanism allows PSE to recover power costs according
to
certain terms. The PCA mechanism was revised effective July 1, 2006
resulting in a shift in PSE’s power cost recovery between quarters and within
the calendar year. The increase in the second quarter 2007 electric
margin reflects $23.5 million related to the PCA mechanism. PSE
overrecovered power costs under the PCA mechanism by $36.5 million in the second
quarter 2007 compared to $13.0 million in the second quarter 2006.
The
following table displays the details of electric margin changes for the six
months ended June 30, 2007 compared to the same period in
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.
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 $27.4 million for the six months ended June 30, 2007 compared
to the same period in 2006 due to lower purchased electricity related to the
increased production from low-cost hydroelectric generation and company-owned
generating facilities. The PCORC rate increase of 5.9% effective July1, 2006 net of a 1.3% general rate decrease effective January 13, 2007 increased
electric margin by $16.9 million due in part to the recovery of Wild
Horse. In addition, a 2.4% increase in retail sales volumes increased
electric margin by $7.7. These increases were partially offset by a
decrease in electric margin of $8.5 million due to an increase of PTCs provided
to customers. PTCs provided to customers through lower rates are
recovered through a lower effective tax rate.
The
PCA
mechanism allows PSE to recover power costs according to certain
terms. The PCA mechanism was revised effective July 1, 2006 resulting
in a shift in PSE’s power cost recovery between quarters and within the calendar
year. The increase in the second quarter 2007 electric margin
reflects $23.5 million related to the PCA mechanism. PSE
overrecovered power costs under the PCA mechanism by $36.5 million in the second
quarter 2007 compared to $13.0 million in the second quarter 2006. In
the first quarter 2007, PSE’s power cost underrecovery was $13.6
million. During the first quarter 2006, power cost underrecovery did
not affect earnings because PSE’s maximum exposure under the PCA mechanism was
limited by a $40.0 million cap in effect during the
period. Therefore, PSE’s net power cost overrecovery for the six
months ended June 30, 2007 was $22.9 million compared to $13 million for the
same period in 2006, or $9.9 million related to the PCA
mechanism. Such favorable changes in the allocation of power costs
between PSE and the customer may not be repeated in the future and should not
be
considered a recurring element in operating income.
The
following table displays the details of gas margin changes for the three months
ended June 30, 2007 compared to the same period in 2006. Gas margin
is gas sales to retail and transportation customers less pass-through tariff
items and revenue-sensitive taxes, and the cost of gas purchased, including
gas
transportation costs to bring gas to PSE’s service territory.
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 $8.1 million for the three months ended June 30, 2007 compared
to the same period in 2006 primarily due to a 2.8% general rate increase
effective January 13, 2007 which increased gas margin $5.4 million, a 3.1%
increase in gas therm volume sales which contributed $1.7 million to gas margin
and change in customer usage and pricing which increased gas margin by $1.0
million.
The
following table displays the details of gas margin changes for the six months
ended June 30, 2007 compared to the same period in 2006. Gas margin
is gas sales to retail and transportation customers less pass-through tariff
items and revenue-sensitive taxes, and the cost of gas purchased, including
gas
transportation costs to bring gas to PSE’s service territory.
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 $18.2 million for the six months ended June 30, 2007 compared
to the same period in 2006 primarily due to a 2.8% general rate increase
effective January 13, 2007 which increased gas margin $12.6 million and a 3.6%
gas therm volume sales increase which increased gas margin $5.5
million.
Electric
Operating Revenues
The
table
below sets forth changes in electric operating revenues for PSE for the three
months ended June 30, 2007 compared to the same period in 2006.
Electric
retail sales increased $44.9 million for the three months ended June 30, 2007
compared to the same period in 2006 due primarily to rate increases related
to
the PCORC rate increase of July 1, 2006 and increased retail sales volumes
offset by the electric general rate decrease of January 13, 2007. The
electric tariff changes provided $18.4 million to electric operating revenues
for the three months ended June 30, 2007 compared to the same period in
2006. Retail electricity usage increased 86,835 megawatt hours (MWh)
or 1.8% for the three months ended June 30, 2007 compared to the same period
in
2006, which resulted in an increase of approximately $6.4 million in electric
operating revenue. The increase in electricity usage was primarily
related to 2.4% higher average number of customers served in 2007 compared
to
2006. During the three month period ended June 30, 2007, the benefits
of the Residential and Farm Energy Exchange Benefit credited to customers
reduced electric operating revenues by $18.4 million compared to $40.5 million
for the same period in 2006. This credit also reduced power costs by
a corresponding amount with no impact on earnings. The Residential
and Farm Energy Exchange Benefit was suspended to residential and small farm
customers 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.
Sales
to
other utilities and marketers increased $10.3 million for the three months
ended
June 30, 2007 compared to the same period in 2006 due to an increase in
wholesale market prices in 2007 compared to 2006 partially offset by a decrease
in sales volume of 147,774 MWh or 18.8%.
The
table
below sets forth changes in electric operating revenues for PSE for the six
months ended June 30, 2007 compared to the same period in 2006.
Electric
retail sales increased $104.7 million for the six months ended June 30, 2007
compared to the same period in 2006 due primarily to rate increases related
to
the PCORC rate increase of July 1, 2006 offset by the electric general rate
decrease of January 13, 2007 and increased retail sales volumes. The
electric tariff changes provided $36.7 million to electric operating revenues
for the six months ended June 30, 2007 compared to the same period in
2006. Retail electricity usage increased 258,637 MWh or 2.4% for the
six months ended June 30, 2007 compared to the same period in 2006, which
resulted in an increase of approximately $19.1 million in electric operating
revenue. The increase in electricity usage was related to 2.3% higher
average number of customers served in 2007 compared to 2006. During
the six month period ended June 30, 2007, the benefits of the Residential and
Farm Energy Exchange Benefit credited to customers reduced electric operating
revenues by $54.5 million compared to $99.8 million for the same period in
2006. This credit also reduced power costs by a corresponding amount
with no impact on earnings.
Sales
to
other utilities and marketers increased $13.7 million for the six months ended
June 30, 2007 compared to the same period in 2006 due to an increase in
wholesale market prices in 2007 compared to 2006 partially offset by a decrease
in sales volume.
Other
electric revenues decreased $3.3 million for the six months ended June 30,2007
compared to the same period in 2006, primarily due to gains from 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:
Gas
retail sales increased $32.5 million for the three months ended June 30, 2007
compared to the same period in 2006 due to higher Purchased Gas Adjustment
(PGA)
mechanism rates, the approval of a 2.8% general gas rate increase effective
January 13, 2007 and increased customer gas usage. The Washington
Commission approved a PGA mechanism rate increase effective September 27, 2006
that increased rates 10.2% annually. The PGA mechanism passes through
to customers increases or decreases in the gas supply portion of the natural
gas
service rates based upon changes in the price of natural gas purchased from
producers and wholesale marketers or changes in gas pipeline transportation
costs. PSE’s gas margin and net income are not affected by changes
under the PGA mechanism. For the three months ended June 30, 2007,
the effects of the PGA mechanism rate increases provided an increase of $16.3
million in gas operating revenues. The gas general rate case provided
an additional $5.4 million in gas revenues for the three months ended June30,2007 as compared to the same period in 2006. The remaining increase
in gas retail revenues was primarily due to higher gas sales of 6.2 million
therms or $5.8 million for the three months ended June 30, 2007 compared to
the
same period in 2006, which was related to a 2.6% increase in
customers.
The
table
below sets forth changes in gas operating revenues for PSE for the six months
ended June 30, 2007 compared to the same period in 2006.
Gas
retail sales increased $92.5 million for the six months ended June 30, 2007
compared to the same period in 2006 due to higher PGA mechanism rates, the
approval of a 2.8% general gas rate increase effective January 13, 2007 and
increased customer gas usage. The Washington Commission approved a
PGA mechanism rate increase effective September 27, 2006 that increased rates
10.2% annually. The PGA mechanism passes through to customers
increases or decreases in the gas supply portion of the natural gas service
rates based upon changes in the price of natural gas purchased from producers
and wholesale marketers or changes in gas pipeline transportation
costs. PSE’s gas margin and net income are not affected by changes
under the PGA mechanism. For the six months ended June 30, 2007, the
effects of the PGA mechanism rate increases provided an increase of $52.9
million in gas operating revenues. The gas general rate case provided
an additional $12.6 million in gas revenues for the six months ended June 30,2007 as compared to the same period in 2006. The remaining increase
in gas retail revenues was primarily due to higher gas sales of 21.4 million
therms or $21.4 million for the six months ended June 30, 2007 compared to
the
same period in 2006, which was related to a 2.7% increase in
customers.
The
following gas rate adjustments were approved by the Washington Commission in
2007 and 2006:
The
table
below sets forth changes in non-utility operating revenues for PSE for the
six
months ended June 30, 2007 compared to the same period in 2006.
Non-utility
operating revenues
increased $4.9 million for the six months ended June 30, 2007 compared to the
same period in 2006 primarily due to additional property sales during 2007
by
PSE’s real estate subsidiary.
Operating
Expenses
The
table
below sets forth significant changes in operating expenses for PSE and its
subsidiaries for the three months ended June 30, 2007 compared to the same
period in 2006.
The
table
below sets forth significant changes in operating expenses for PSE and its
subsidiaries for the six months ended June 30, 2007 compared to the same period
in 2006.
Purchased
electricity expenses decreased $15.1 million and increased $14.7
million for the three and six months ended June 30, 2007, respectively, compared
to the same periods in 2006. The decrease for the three months ended
June 30, 2007 was primarily the result of increased production from low cost
hydroelectric power and company-owned renewable and thermal generating
facilities. PSE’s hydroelectric power increased 4.0% for the three
months ended June 30, 2007 as compared to the same period in
2006. Total purchased power for the three months ended June 30, 2007
decreased 523,053 MWh or 11.5% compared to the same period in
2006. The PCA mechanism reflected an overrecovery of allowable power
costs of $23.5 million, $16.9 million of which results from a change in the
PCA
mechanism sharing bands as compared to the prior period when PSE was subject
to
the $40.0 million cumulative cap on power cost variations. The change
in the PCA mechanism sharing bands at January 2007 resulted in a significant
decrease in overrecovery benefits provided to customers in 2007 as compared
to
2006. Such favorable changes in the allocation of power costs between
PSE and the customer may not be repeated in the future and should not be
considered a recurring element in operating income. PSE is allowed to
recover power cost through the PCA mechanism on a shared basis with customers
if
actual costs are outside the normalized level established in
rates. The increase for the six months ended June 30, 2007 was
primarily the result of higher wholesale market prices offset by a decrease
in
purchased power of 386,112 MWh or 4.1%, resulting in an increase of $16.3
million. The decrease in purchased power is related to increased
production from hydroelectric power and company-owned renewable and thermal
generating facilities. Increases in transmission and other expenses
contributed $7.9 million due in part to increased kilowatt hour (kWh) sales
to
customers. The PCA mechanism reflected an overrecovery of allowable
power costs of $9.9 million for the six months ended June 30, 2007.
The
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 2007 is 102% of normal. PSE’s hydroelectric production
and related power costs in 2006 for the January to July period 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 which occurred in the first quarter of 2006.
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 $9.4 million and $13.9 million for
the three and six months ended June 30, 2007, respectively, compared to the
same
periods in 2006. The increase for the three months ended June 30,2007 was the result of an increase of $6.3 million primarily due to the
operations of Goldendale which was acquired on February 21, 2007 and an increase
in electric generation and the cost of coal at Colstrip generating facilities
of
$3.1 million compared to the same period in 2006 due to higher volumes of
electricity generated at Colstrip combined with an increase in the cost of
coal. The increase for the six months ended June 30, 2007 was the
result of an increase of $8.6 million primarily due to the operations of
Goldendale and an increase in electric generation and the cost of coal at
Colstrip generating facilities of $5.3 million due to higher volumes of
electricity generated at Colstrip combined with an increase in the cost of
coal
in 2007 compared to 2006.
Residential
exchange credits associated with the Residential Purchase and Sale
Agreement with BPA decreased $21.1 million and $43.3 million for the three
and
six months ended June 30, 2007, respectively, compared to the same periods
in
2006 as a result of lower residential and small farm customer electric credit
in
rates effective October 1, 2006. 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. The
residential exchange credit provided to residential and small farm customers
was
suspended effective June 7, 2007.
Purchased
gas expenses increased $20.7 million and $64.7 million for the three
and six months ended June 30, 2007, respectively, compared to the same periods
in 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 gas costs, and defer, as a receivable or liability,
any
gas costs that exceed or fall short of this expected gas cost amount in PGA
mechanism rates, including accrued interest. The PGA mechanism
payable balance at June 30, 2007 was $41.6 million 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 gas cost through rates. A payable balance
reflects overrecovery of market gas cost through rates.
Unrealized
gain on derivative instruments decreased $1.7 million and increased
$5.1 million forthe three and six months ended June 30,2007, respectively, compared to the same periods in 2006. The
decrease for the three months ended June 30, 2007 was primarily the result
of
the reversal of the unrealized gain related to a physical gas supply contract
for PSE’s electric generating facilities. The mark-to-market gain
that was recorded is the difference between the forward market price of natural
gas and the contract price for natural gas based on volumes
purchased. As the contract nears termination in June 2008, the gain
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 prices of natural gas. The
increase for the six months ended June 30, 2007 is primarily the result of
the
unrealized gain of $5.8 million related to this physical gas supply contract
in
the first quarter 2007 offset by a decrease in the mark-to-market valuation
of
$1.0 million during the second quarter 2007 and the settlement of a portion
of
the gain of $0.5 million recorded in the second quarter 2007.
Utility
operations and maintenance expense increased $15.3 million and $26.1
million for the three and six months ended June 30, 2007, respectively, compared
to the same periods in 2006. The increases were the result of higher
operating and maintenance costs of $7.5 million and $11.1 million at PSE’s
generating facilities, due to the addition of Wild Horse which began operations
on December 22, 2006, Goldendale, which was acquired during February 2007,
Colstrip and higher expenses related to operating and maintaining PSE’s energy
delivery system. Wild Horse operations and maintenance expense is
fully recovered in rates. The balance of the increases were the
result of higher expenses of operating and maintaining PSE’s energy delivery
systems, support services and increased customer service costs.
Non-utility
expense and other increased $2.1 million and $3.9 million for the three
and six months ended June 30, 2007, respectively, compared to the same periods
in 2006 primarily due to an increase in PSE’s long-term share-based incentive
plan costs.
Depreciation
and amortization expense increased $1.2 million and $7.0 million for
the three and six months ended June 30, 2007, respectively, compared to the
same
periods in 2006. These increases include the benefit of the deferral
of Goldendale ownership and operating costs of $5.9 million and $6.9 million
for
the three and six months ended June 30, 2007, respectively, which, had it not
been included, would have resulted in an increase to depreciation and
amortization expense of $7.1 million and $13.9 million for the three and six
months ended June 30, 2007, respectively, as compared to the same periods in
2006. The increase in depreciation and amortization excluding the
Goldendale deferral was due to placing Wild Horse into service on December22,2006, placing Goldendale into service on February 22, 2007 and from other
depreciable property placed into service during 2007. PSE anticipates
the Goldendale deferral of ownership and operating costs to cease effective
September 1, 2007, pursuant to the terms of the PCORC settlement filed July5,2007.
Conservation
amortization increased $1.2 million and $3.6 million for the three and
six months ended June 30, 2007, respectively, compared to the same periods
in
2006 due to higher authorized recovery of electric conservation
expenditures. Conservation amortization is a pass-through tariff item
with no impact on earnings.
Taxes
other than income taxes increased $9.1 million and $16.5 million for
the three and six months ended June 30, 2007, respectively, compared to the
same
periods in 2006 due primarily to increases in revenue-based Washington State
excise tax and municipal tax due to increased operating
revenues. Revenue sensitive Washington State excise and municipal
taxes have no impact on earnings. Revenue sensitive taxes are
presented in the income statement on a gross basis.
Other
Income, Expense, Interest Charges and Income Tax Expense
The
table
below sets forth significant changes in other income, interest charges and
income taxes for PSE and its subsidiaries for the three months ended June 30,2007 compared to the same period in 2006.
Other
expenses increased $2.0 million for the three months ended June 30,2007 compared to the same period in 2006 primarily due to the accrual of a
recordkeeping violation penalty that could be assessed by the Washington
Commission, which is not tax-deductible.
Interest
expense increased $7.9 million due primarily to an increase in
outstanding debt as a result of additional borrowing related to Wild Horse,
Goldendale, pre-payment associated with the Chelan PUD long-term purchase power
agreement and system restoration expense incurred as a result of a severe
December 2006 wind storm.
Income
tax expense increased $1.5 million for the three months ended June 30,2007 compared to the same period in 2006 as a result of higher taxable income
offset by higher tax credits associated with the production of wind-powered
energy. The PTCs for the three months ended June 30, 2007 were $4.7
million compared to $0.9 million for the same period in 2006. These
additional credits were made available due to the addition of Wild Horse, which
was placed in service in December 2006.
The
table
below sets forth significant changes in other income, interest charges and
income taxes for PSE and its subsidiaries for the six months ended June 30,2007
compared to the same period in 2006.
Other
income increased $1.2 million for the six months ended June 30, 2007
compared to the same period in 2006 primarily due to an increase on the return
of the Chelan PUD regulatory asset offset by a decrease in the return of
regulatory assets that are currently being recovered in electric and gas
rates.
Other
expenses increased $1.6 million for the six months ended June 30, 2007
compared to the same period in 2006 primarily due to the accrual in the second
quarter 2007 of a recordkeeping violation penalty that could be assessed by
the
Washington Commission.
Interest
expense increased $15.4 million due primarily to an increase in
outstanding debt as a result of additional borrowing related to Wild Horse,
Goldendale, and other capital related electric and gas infrastructure projects,
along with pre-payment associated with the Chelan PUD long-term purchase power
agreement and system restoration expense incurred as a result of a severe
December 2006 wind storm.
Income
tax expense decreased $5.1 million for the six months ended June 30,2007 compared to the same period in 2006 due primarily to higher tax credits
associated with the production of wind-powered energy. The PTCs for
the six months ended June 30, 2007 were $12.2 million compared to $4.6 million
for the same period in 2006. These additional credits were made
available due to the addition of Wild Horse, which was placed in service in
December 2006.
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 June 30, 2007:
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
is $3.9 million at June 30, 2007 and the obligation expires on May7,2008. Puget Energy also agreed to indemnify the
buyer relating to an inquiry of an InfrastruX subsidiary and the
fair
value of the warranty was $5.0 million at June 30,2007.
3
At
June 30, 2007, PSE had available a $500.0 million and a $350.0 million
unsecured credit agreement expiring in April 2012. The credit
agreements provide credit support for letters of credit and commercial
paper. At June 30, 2007, PSE had $8.3 million for an
outstanding letter of credit and $239.9 million commercial paper
outstanding, effectively reducing the available borrowing capacity
to
$601.8 million.
4
At
June 30, 2007, PSE had available a $200.0 million receivables
securitization facility that expires in December 2010. $50.0 million
was
outstanding under the receivables securitization facility at June30, 2007
thus leaving $150.0 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 June 30, 2007:
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 lease in April
2001. The term of the lease expires 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 June 30, 2007, PSE’s
outstanding balance under the lease was $49.7 million. The expected
residual value under the lease is the lesser of $37.4 million or 60% of the
cost
of the equipment. In the event the equipment is sold to a third party
upon termination of the lease and the aggregate sales proceeds are less than
the
unamortized value of the equipment, PSE would be required to pay the lessor
contingent rent in an amount equal to the deficiency up to a maximum of 87%
of
the unamortized value of the equipment.
Utility
Construction Program
Utility
construction expenditures for generation, transmission and distribution are
designed to meet continuing customer growth and to improve efficiencies of
PSE’s
energy delivery systems. Construction expenditures, excluding equity
Allowance for Funds Used during Construction (AFUDC) and customer refundable
contributions, were $375.7 million for the six months ended June 30,2007. Utility construction expenditures, excluding AFUDC and
excluding new generation resources other than Wild Horse (which will be
determined as the Company proceeds through the integrated resource planning
process) are anticipated to be as follows in 2007, 2008 and 2009:
Capital
Expenditure Estimates
(Dollars
in Millions)
2007
2008
2009
Energy
delivery, technology and facilities
$
530
$
555
$
640
New
supply resources
120
70
210
Total
expenditures
$
650
$
625
$
850
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 any 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 the six months ended June 30, 2007 was $345.9
million which is 87.8% of the $394.1 million used for utility construction
expenditures and other capital expenditures. For the six months ended
June 30, 2006, cash generated from operations was $72.0 million which is 22.2%
of the $324.5 million used for utility construction expenditures and other
capital expenditures.
The
overall cash generated from operating activities for the six months ended June30, 2007 increased $273.9 million compared to the same period in
2006. The increase was primarily the result of costs incurred in 2006
that did not recur in 2007, including the Chelan PUD contract initiation payment
of $89.0 million and cash collateral repaid to energy suppliers of $20.0
million. Also contributing to the increase were collection of the
purchased gas receivable of $87.1 million, $77.3 million in income taxes paid
in
the first six months of 2006 compared to $23.0 paid in the same period in 2007
and a cash receipt PSE received of $18.9 million for the settlement of a
purchase option related to the lease for its corporate offices.
Financing
Program
Financing
utility construction requirements and operational needs are dependent upon
the
cost and availability of external funds through capital markets and from
financial institutions. Access to funds is dependent upon factors
such as general economic conditions, regulatory authorizations and policies,
and
Puget Energy’s and PSE’s credit ratings.
Restrictive
Covenants
In
determining the type and amount of future financing, PSE may be limited by
restrictions contained in its electric and gas mortgage indentures, articles
of
incorporation and certain loan agreements. Under the most restrictive
tests, at June 30, 2007, PSE could issue:
·
approximately
$608.0 million of additional first mortgage bonds under PSE’s electric
mortgage indenture based on approximately $1,013.3 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
June 30,2007;
·
approximately
$422.0 million of additional first mortgage bonds under PSE’s gas mortgage
indenture based on approximately $703.3 million of 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 June 30,2007;
·
approximately
$825.2 million of additional preferred stock at an assumed dividend
rate
of 6.9%; and
·
approximately
$718.4 million of unsecured long-term
debt.
At
June30, 2007, PSE had approximately $4.3 billion in electric and gas ratebase to
support the interest coverage ratio limitation test for net earnings available
for interest.
Credit
Ratings
Neither
Puget Energy nor PSE has any debt outstanding that would accelerate debt
maturity upon a credit rating downgrade. 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 PSE’s debt ratings may prompt counterparties to require
PSE to post a letter of credit or other collateral, make cash prepayments,
obtain a guarantee or provide other security.
The
ratings of Puget Energy and PSE, as of July 25, 2007, were as
follows:
Ratings
Standard
& Poor’s
Moody’s
Puget
Sound Energy
Corporate
credit/issuer rating
BBB-
Baa3
Senior
secured debt
BBB
Baa2
Shelf
debt senior secured
BBB
(P)Baa2
Junior
Subordinated Notes
BB
Ba1
Preferred
stock
BB
Ba2
Commercial
paper
A-3
P-2
Revolving
credit facility
*
Baa3
Ratings
outlook
Stable
Positive
Puget
Energy
Corporate
credit/issuer rating
BBB-
Ba1
____________
*
Standard
& Poor’s does not rate credit facilities.
Shelf
Registrations, Long-Term Debt and Common Stock Activity
On
June1, 2007, PSE redeemed the remaining 8.231% 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 sheet and referred to herein as “Securities”). The purpose of
the redemption is 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 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.
Liquidity
Facilities and Commercial Paper
PSE’s
short-term borrowings and sales of commercial paper are used to provide working
capital fund to utility construction programs and support the Company’s energy
hedging activities.
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
June 30, 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 June 30, 2007, there was $8.3 million outstanding under a
letter of credit and $239.9 million commercial paper outstanding, effectively
reducing the available borrowing capacity under the credit agreements to $601.8
million.
Receivables
Securitization Facility. PSE entered into a five-year
Receivable 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 are 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 was
$50.0 million in loans that were secured by accounts receivable pledged at
June30, 2007. The remaining borrowing base of eligible receivables at
June 30, 2007 was $150.0 million.
Demand
Promissory Note. On June 1, 2006, PSE
entered into an uncommitted revolving credit facility with its parent, Puget
Energy, pursuant to a Demand Promissory Note (Note) under which PSE may borrow
up to $30.0 million from 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. At June 30, 2007, the outstanding
balance of the Note was $24.5 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 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
under the Stock Purchase and Dividend Reinvestment Plan of $3.2 million (124,995
shares) and $6.5 million (255,891 shares) for the three and six months ended
June 30, 2007, respectively, compared to $3.4 million (164,784 shares) and
$6.9
million (331,635 shares) for the three and six months ended June 30, 2006,
respectively.
Common
Stock Offering Programs
To
provide additional financing options, Puget Energy entered into agreements
in
July 2003 with two financial institutions under which Puget Energy may offer
and
sell shares of its common stock from time to time through these institutions
as
sales agents, or as principals. Sales of the common stock, if any,
may be made by means of negotiated transactions or in transactions that may
be
deemed to be “at-the-market” offerings as defined in Rule 415 promulgated under
the Securities Act of 1933, including in ordinary brokers’ transactions on the
New York Stock Exchange at market prices.
Other
FERC
Hydroelectric Projects And Licenses
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 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.
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; the closing
of
the sale is subject to contingencies that have yet to be resolved. On
April 7, 2004, the Washington Commission approved PSE’s recovery on the
unamortized White River plant investment. At June 30, 2007, the White
River project net book value totaled $71.6 million, which included $42.6 million
of net utility plant, $16.9 million of capitalized FERC licensing costs, $7.0
million of costs related to construction work in progress and $2.2 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.
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.
Electric
Regulation and Rates
Integrated
Resource Plan. PSE filed its IRP on May 31, 2007 with the
Washington Commission. The plan supports a strategy of diverse
acquisitions to cost-effectively meet growing demand for energy and reduce
carbon emissions. According to the IRP, PSE can secure additional
power supplies through heightened energy-efficiency efforts and expanded
wind-power generation. PSE believes that a cost-effective and
environmentally responsible way to source generation will likely include
additional natural gas-fired resources. PSE’s analysis targets a need
to acquire 1,600 average megawatts (aMW) of additional power supply in the
next
decade and 2,600 aMW by 2025.
Mandatory
Electric Reliability Standards. 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 a
failing to comply with new electric reliability standards. FERC
approved 83 reliability standards developed by the North American Electric
Reliability Corporation (NERC). The 83 standards comprise 586
requirements and sub-requirements that PSE must comply with. On June18, 2007, the standards became mandatory and enforceable under federal
law. PSE expects that the existing standards will be constantly
changing due to modifications, guidance and clarification as a result of
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 are
submitted on or before June 18, 2007 and approved by WECC. In June
2007, PSE submitted self reports and mitigation plans to WECC for review and
approval. The financial impact to PSE of complying with Order 693, if
any, cannot now be determined.
Power
Cost Only Rate Case. On March 20, 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
Goldendale ownership and operating costs through retail electric
rates. The requested electric rate increase is $64.7 million or 3.7%
annually. 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 July5, 2007, a settlement agreement in this PCORC rate case signed by PSE and other
parties to the proceeding was filed with the Washington
Commission. The terms of the settlement agreement include an electric
rate increase of $64.7 million, Goldendale ownership and operating costs are
agreed upon as prudent, thus allowing for recovery of the costs through electric
retail rates and the parties agree to participate in a collaborative effort
to
streamline the Washington Commission’s PCORC process. On August 2,2007, the Washington Commission approved the settlement agreement which provides
for new electric rates effective September 1, 2007.
Accounting
Petition. On April 11, 2007, the Washington Commission
approved PSE’s petition for issuance of an accounting order that authorizes PSE
to defer certain costs the Company will incur related to its purchase of
Goldendale before the ownership and operating costs are included in PSE’s
electric retail customer rates. PSE established a regulatory asset of
$7.0 million at June 30, 2007.
Electric
General Rate Case. 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 were
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 PCORC increase of $96.1 million annually effective July 1,2006.
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. 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.
PCA
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 PCA mechanism for continuation 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.
Gas
Regulation and Rates
Gas
General Rate Case. On January 5, 2007, the Washington
Commission issued its order in PSE’s gas general rate case, granting a rate
increase for gas customers of $29.5 million or 2.8% annually, effective January13, 2007. 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.
Proceedings
Relating to the Western Power Market
Puget
Energy’s and PSE’s Report on Form 10-K for the year ended December 31, 2006
includes a summary relating to the western power market
proceedings. The following discussion provides a summary of material
developments in these proceedings that occurred during and subsequent to the
period covered by this report. 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/or
adversely affect PSE’s financial condition, results of operations or
liquidity.
CPUC
Decision. Proceedings, including filings of requests for
rehearing or further review, before the Ninth Circuit and/or FERC, continue
to
be stayed upon the Court’s own motion to allow for possible settlement
discussions to proceed. The matter is stayed until August 13,2007.
Lockyer
Case. On June 18, 2007, the U.S. Supreme Court denied the
petition for a writ of certiorari that PSE and other energy sellers had
submitted. As such, this matter will be remanded to FERC for further
proceedings, but not before August 13, 2007, when the stay of the mandate back
to FERC expires.
Colstrip
Matters
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. Discovery is
ongoing. The trial is scheduled for the first quarter
2008. On March 29, 2007, a second complaint was filed on behalf of
two ranch owners alleging damage due to the Colstrip Units 3 & 4 effluent
holding pond.
In
May 2005, the Environmental
Protection Agency (EPA) enacted the Clean Air Mercury Rule that will permanently
cap and reduce mercury emissions from coal-fired power plants. The
Montana Board of Environmental Review approved the state’s regulation to limit
mercury emissions from coal-fired plants on October 16, 2006. The new
rule has a more stringent limit than the federal rule (0.9 lbs/Trillion
British thermal units (TBtu), instead of the federal 1.4 lbs/TBtu), but
includes a cap-and-trade provision as well as alternative emission limits for
plants that have tried to meet the new standards but have demonstrated that
they
cannot. The Colstrip owners are still evaluating the potential impact
of the new 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 capital costs to comply with
the new rule could be as much as $75 million, but this number could change
as new information becomes available.
In
December 2003, the EPA issued an Administrative Consent Order (ACO) which
alleged violation of the Clean Air Act permit at Colstrip since
1980. The permit required Colstrip to submit, for review and approval
by the EPA, an analysis and proposal for reducing emissions of nitrogen oxide
to
address visibility concerns upon the occurrence of certain triggering
events. The EPA asserts that regulations it promulgated in 1980
triggered this requirement. Although Colstrip owners believe that the
ACO was unfounded, the Colstrip owners entered into negotiations with the EPA
and the Northern Cheyenne Tribe. On May 14, 2007, the ACO was
approved and deemed entered by the Montana Federal District
Court. The agreement requires installation of low nitrogen oxide
equipment on Colstrip Units 3 & 4, payment of a non-material penalty and
financing of an energy efficiency project on the Northern Cheyenne
reservation. The estimated total additional cost to PSE is $2.7
million.
In
June
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 and were
required to submit a BART engineering analysis for Colstrip 1 & 2 by May
2007; EPA recently extended that date to July 31, 2007. PSE cannot
yet determine the need for or costs of additional controls to comply with this
rule, through any such costs could be significant.
Sumas
Cogeneration Company Contract
Sumas
Cogeneration Company, LP (Sumas), delivered a letter to PSE on May 7, 2007,
stating that it had sold its dedicated 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. PSE and Sumas have
initiated discussion relating to Sumas’ actions under the contract, but PSE
cannot yet determine what may result from such discussions.
New
Accounting Pronouncements
In
September 2006, Financial Accounting Standards Board (FASB) issued SFAS No,
157,
“Fair Value Measurements”. SFAS No. 157 establishes a common definition
for fair value to be applied to GAAP, establishes a framework for measuring
fair
value, and expands disclosure about such fair value
measurements. SFAS No. 157 is effective for fiscal years beginning
after November 15, 2007 which will be the calendar year beginning January 1,2008 for the Company. The Company is currently assessing the impact of
SFAS No. 157 on its financial statements.
In
July
2006, FASB issued Interpretation No. 48 (FIN 48), “Accounting for Uncertainty in
Income Taxes, an Interpretation of FASB Statement No. 109,” 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 provides guidance on recognition threshold and
measurement attributed to a tax position taken or expected to be taken in a
tax
return. The tax positions 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. FIN 48 was effective for
the Company as of January 1, 2007. The Company has performed a review
of all open tax years (2001 through 2007) and identified one tax position that
must be reported under the provisions of FIN 48. The Company has
determined that the proper amount of interest to accrue under FIN 48 is $6.6
million as of January 1, 2007. See discussion at Note 6, “Income
Taxes.”
Item
3.
Quantitative and Qualitative Disclosure About Market
Risk
Energy
Portfolio Management
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 gas and electric portfolios. It is not
engaged in the business of assuming risk for the purpose of speculative
trading. The Company hedges open gas and electric positions to reduce
both portfolio risk and volatility risk in prices. The exposure
position is determined by using a probabilistic risk system that models 100
scenarios of how the Company’s 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;
·
prudently
manage energy portfolio risks 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
Company’s energy derivative contracts designated as cash flow hedges that
represent forward financial purchases of natural gas supply for electric
generation from PSE-owned electric plants in future periods at June 30, 2007
and
December 31, 2006 are presented below:
If
it is
determined that it is uneconomical to run the plants in the future period,
the
hedging relationship is ended and the cash flow hedge is de-designated and
any
unrealized gains and losses are recorded in the income
statement. Gains and losses when these de-designated cash flow hedges
are settled are recognized in energy costs and are included as part of the
PCA
mechanism.
The
amount of net unrealized gain (loss), net of tax, at June 30, 2007 and December31, 2006 related to the Company’s cash flow hedges under SFAS No. 133 recorded
in other comprehensive income is presented as follows:
All
mark-to-market adjustments relating to the natural gas business have been
reclassified to a deferred account in accordance with SFAS No. 71 due to the
PGA
mechanism. The PGA mechanism passes increases and decreases in the
cost of natural gas supply to customers. As the gains and losses on
the hedges are realized in future periods, they will be recorded as gas costs
under the PGA mechanism.
The
following tables present the impact of changes in the market value of derivative
instruments not meeting normal purchase normal sale or cash flow hedge criteria
to the Company’s earnings during the three and six months ended June 30, 2007
and June 30, 2006:
The
Company recorded a decrease of $1.5 million and an increase of $4.2 million
in
earnings during the three and six months ended June 30, 2007, respectively,
primarily due to the change in the mark-to-market valuation on a physical
delivered gas supply contract for electric generation that did not meet normal
purchase normal sale (NPNS) or cash flow hedge criteria. The
mark-to-market valuation in 2007 primarily relates to a physical contract
reserve that was released on a contract due to improved credit of a
counterparty. The contract had a short term asset of $4.2 million
which will settle over the next 12 months. At June 30, 2007, the
Company recorded a net unrealized loss of $10.0 million related to a three
and a
half year locational power exchange contract and deferred the day one loss
to
the balance sheet. The fair value of the exchange contract was based
on a propriety model. The deferred loss will be amortized over the
term of the contract based upon the power exchanged. Any future
changes in the mark-to-market value will be recorded through the income
statement. The contract has an economic benefit to the Company over
its term and will help ease electric transmission congestion across the Cascade
Mountains during 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 same
quantities of power at the Mid-Columbia trading hub location.
A
hypothetical 10.0% decrease in the market prices of natural gas and electricity
would decrease the fair value of qualifying cash flow hedges and comprehensive
income by $12.4 million after tax and would decrease the fair value of those
contracts marked-to-market in earnings by $0.7 million after tax.
Credit
Risk
The
Company is exposed to credit risk primarily through buying and selling
electricity and gas to serve its customers. Credit risk is the
potential loss resulting from 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.
It
is
possible that extreme volatility in energy commodity prices could cause the
Company to have sub-optimal 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 June 30, 2007, approximately 97% of
the Company’s energy portfolio was rated investment grade or higher by Standard
& Poor's Ratings Services and/or Moody's Investor Services,
Inc.
Interest
Rate Risk
The
Company believes its interest rate risk primarily relates to the use of
short-term debt instruments, variable-rate 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 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
ending balance in other comprehensive income related to the forward starting
swaps and previously settled treasury lock contracts at June 30, 2007 was a
net
loss of $8.3 million after-tax and accumulated amortization. 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.
Under
the supervision and with the
participation of Puget Energy’s management, including the Chairman, President
and Chief Executive Officer and the 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 June 30, 2007, the end of the period covered by this
report. Based upon that evaluation, the Chairman, President and Chief
Executive Officer and the 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 period ended June30, 2007 that have materially affected, or are reasonably likely to materially
affect, Puget Energy’s internal control over financial reporting.
Puget
Sound Energy
Evaluation
of Disclosure Controls and Procedures
Under
the supervision and with the
participation of PSE’s management, including the Chairman, President and Chief
Executive Officer and the 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
June 30, 2007, the end of the period covered by this report. Based
upon that evaluation, the Chairman, President and Chief Executive Officer and
the 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 period ended June 30,2007,
that have materially affected, or are reasonably likely to materially affect,
PSE’s internal control over financial reporting.
See
the
section titled “Proceedings Relating to the Western Power Market” under Item 2
“Management’s Discussion and Analysis of Financial Conditions and Results of
Operations” of this Report on Form 10-Q. Contingencies arising out of
the normal course of the Company’s business exist at June 30,2007. The ultimate resolution of these issues in part or in the
aggregate is not expected to have a material adverse impact on the financial
condition, results of operations or liquidity of the Company.
The
following risk factor is an update to the previously disclosed risk factors
by
Puget Energy and PSE in their Form 10-K, Item 1A for the period ending December31, 2006.
Costs
of compliance with environmental, climate change, and endangered species laws
are significant and the cost of compliance with new 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, during or after 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 a 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.
Item
4. Submission
of Matters to a Vote of Security Holders
Puget
Energy’s annual meeting of shareholders was held on May 4, 2007. At
the annual meeting, the shareholders elected one director to hold office until
the annual meeting of shareholders in 2008 and four directors to hold office
until the annual meeting of shareholders in 2010. The vote was as
follows:
Number
of Shares
For
Withheld
TERM
EXPIRING 2008
George
W. Watson
100,689,248
1,473,102
TERM
EXPIRING 2010
Phyllis
J. Campbell
100,814,867
1,347,483
Stephen
E. Frank
99,933,073
2,229,278
Dr.
Kenneth P. Mortimer
100,754,686
1,407,665
Stephen
P. Reynolds
100,411,751
1,750,600
There
were no broker non-votes.
Secondly,
the shareholders approved amendments to the Company’s Articles of Incorporation
to adopt a majority voting standard in uncontested elections of Puget Energy,
Inc. directors. The vote was as follows:
For
Against
Abstain
92,974,723
8,401,830
785,798
There
were no broker non-votes.
Third,
the shareholders approved amendments to the Puget Energy, Inc. Employee Stock
Purchase Plan, including increasing the number of shares available for purchase
under the Plan. The vote was as follows:
For
Against
Abstain
Broker
Non-Vote
82,277,072
2,590,612
829,162
16,465,505
Finally,
shareholders ratified the appointment of PricewaterhouseCoopers
LLP. The vote was as follows:
Pursuant
to the requirements of the Securities Exchange Act of 1934, each registrant
has
duly caused this report to be signed on their behalf by the undersigned
thereunto duly authorized.
PUGET
ENERGY, INC.
PUGET
SOUND ENERGY, INC.
/s/
James W. Eldredge
James
W. Eldredge
Vice
President, Controller and Chief Accounting Officer
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.
Amended
and Restated Credit Agreement, dated as of March 29, 2007, among
Puget
Sound Energy, Inc., the various financial institutions named therein,
and
Wachovia Bank, N.A., as Administrative Agent (incorporated herein
by
reference to Exhibit 10.1 to Puget Energy, Inc.’s Current Report on Form
8-K dated April 3, 2007, Commission File No. 1-16305).
4.2
Credit
Agreement, dated as of March 29, 2007, among Puget Sound Energy,
Inc., the
various financial institutions named therein, and JP Morgan Chase
Bank,
N.A., as Administrative Agent (incorporated herein by reference to
Exhibit
10.2 to Puget Energy, Inc.’s Current Report on Form 8-K dated April 3,2007, Commission File No. 1-16305).
4.3
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).
Statement
setting forth computation of ratios of earnings to fixed charges
(2002
through 2006 and 12 months ended June 30, 2007) for Puget
Energy.
12.2*
Statement
setting forth computation of ratios of earnings to fixed charges
(2002
through 2006 and 12 months ended June 30, 2007) for
PSE.
31.1*
Chief
Executive Officer certification of Puget Energy pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley
Act
of 2002.
31.2*
Chief
Financial Officer certification of Puget Energy pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley
Act
of 2002.
31.3*
Chief
Executive Officer certification of Puget Sound Energy pursuant to
18
U.S.C. Section 1350, as adopted pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
31.4*
Chief
Financial Officer certification of Puget Sound Energy pursuant to
18
U.S.C. Section 1350, as adopted pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
32.1*
Chief
Executive Officer certification pursuant to 18 U.S.C. Section 1350,
as
adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
2002.
32.2*
Chief
Financial Officer certification pursuant to 18 U.S.C. Section 1350,
as
adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
2002.
*
Filed
herewith.
Dates Referenced Herein and Documents Incorporated by Reference
