Document/ExhibitDescriptionPagesSize 1: 10-Q Puget Energy 1st Quarter 2008 Form 10-Q HTML 731K
10: 10-Q Puget Energy 1st Quarter 2008 Form 10-Q -- PDF 283K
f10q050508
2: EX-12.1 Puget Energy Computation of Ratios of Earnings to HTML 108K
Fixed Charges
3: EX-12.2 Pse Computation of Ratios of Earnings to Fixed HTML 110K
Charges
4: EX-31.1 Puget Energy CEO Certification HTML 12K
5: EX-31.2 Puget Energy CFO Certification HTML 12K
6: EX-31.3 Pse CEO Certification HTML 12K
7: EX-31.4 Pse 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, a non-accelerated filer, or a smaller reporting company. See
definition of “large accelerated filer, accelerated filer and smaller reporting
company” in Rule 12b-2 of the Exchange Act.
Puget
Energy, Inc.
Large
accelerated filer
/X/
Accelerated
filer
/ /
Non-accelerated
filer
/ /
Smaller
reporting company
/ /
Puget
Sound Energy, Inc.
Large
accelerated filer
/ /
Accelerated
filer
/ /
Non-accelerated
filer
/X/
Smaller
reporting company
/ /
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act).
Puget
Energy, Inc.
Yes
/ /
No
/X/
Puget
Sound Energy, Inc.
Yes
/ /
No
/X/
As of
April 30, 2008, (i) the number of shares of Puget Energy, Inc. common stock
outstanding was 129,678,489 ($.01 par value) and (ii) all of the outstanding
shares of Puget Sound Energy, Inc. common stock were held by Puget Energy,
Inc.
Infrastructure
investors led by Macquarie Infrastructure Partners, the Canada Pension
Plan Investment Board and British Columbia Investment Management
Corporation, and also includes Alberta Investment Management,
Macquarie-FSS Infrastructure Trust and Macquarie Capital Group
Limited
This
-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 and 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 (natural gas and electric), licensing of hydroelectric
operations and natural gas storage facilities, recovery of other capital
investments, recovery of power and natural gas costs, recovery of
regulatory assets and present or prospective wholesale and retail
competition;
·
Failure
to comply with FERC or Washington Commission standards and/or rules, which
could result in penalties based on the discretion of either
commission;
·
Failure
to comply with electric reliability standards developed by the North
American Electric Reliability Corporation (NERC) for users, owners and
operators of the power system, which could result in penalties of up to
$1.0 million per day per violation;
·
Changes
in, adoption of and compliance with laws and regulations, including
decisions and policies concerning the environment, climate change,
emissions, natural resources, and fish and wildlife (including the
Endangered Species Act);
·
The
ability to recover costs arising from changes in enacted federal, state or
local tax laws through revenue in a timely manner;
·
Changes
in tax law, related regulations, or differing interpretation or
enforcement of applicable law by the Internal Revenue Service (IRS) or
other taxing jurisdiction, which could have a material adverse impact on
the financial statements;
·
Natural
disasters, such as hurricanes, windstorms, earthquakes, floods, fires and
landslides, which can interrupt service and/or cause temporary supply
disruptions and/or price spikes in the cost of fuel and raw materials and
impose extraordinary costs;
·
Commodity
price risks associated with procuring natural gas and power in wholesale
markets;
·
Wholesale
market disruption, which may result in a deterioration of market
liquidity, increase the risk of counterparty default, affect the
regulatory and legislative process in unpredictable ways, negatively
affect wholesale energy prices and/or impede PSE’s ability to manage its
energy portfolio risks and procure energy supply, affect the availability
and access to capital and credit markets and/or impact delivery of energy
to PSE from its suppliers;
·
Financial
difficulties of other energy companies and related events, which may
affect the regulatory and legislative process in unpredictable ways and
also adversely affect the availability of and access to capital and credit
markets and/or impact delivery of energy to PSE from it
suppliers;
·
The
effect of wholesale market structures (including, but not limited to,
regional market designs or transmission organizations) or other related
federal initiatives;
·
PSE
electric or natural gas distribution system failure, which may impact
PSE’s ability to deliver energy supply to its
customers;
·
Changes
in weather conditions in the Pacific Northwest, which could have effects
on customer usage and PSE’s revenues, thus impacting net
income;
·
Weather,
which can have a potentially serious impact on PSE’s ability to procure
adequate supplies of natural gas, fuel or purchased power to serve its
customers and on the cost of procuring such supplies;
·
Variable
hydro conditions, which can impact streamflow and PSE’s ability to
generate electricity from hydroelectric facilities;
·
Plant
outages, which can have an adverse impact on PSE’s expenses with respect
to repair costs, added costs to replace energy or higher costs associated
with dispatching a more expensive resource;
·
The
ability of natural gas or electric plant to operate as
intended;
·
The
ability to renew contracts for electric and natural gas supply and the
price of renewal;
·
Blackouts
or large curtailments of transmission systems, whether PSE’s or others’,
which can affect PSE’s ability to deliver power or natural gas to its
customers and generating facilities;
·
The
ability to restart generation following a regional transmission
disruption;
·
Failure
of the interstate natural gas pipeline delivering to PSE’s system, which
may impact PSE’s ability to adequately deliver natural gas supply or
electric power to its customers;
·
The
amount of collection, if any, of PSE’s receivables from the California
Independent System Operator (CAISO) and other parties and the amount of
refunds found to be due from PSE to the CAISO or other
parties;
·
Industrial,
commercial and residential growth and demographic patterns in the service
territories of PSE;
·
General
economic conditions in the Pacific Northwest, which might impact customer
consumption or affect PSE’s accounts receivable;
·
The
loss of significant customers or changes in the business of significant
customers, which may result in changes in demand for PSE’s
services;
·
The
impact of acts of God, terrorism, flu pandemic or similar significant
events;
·
Capital
market conditions, including changes in the availability of capital or
interest rate fluctuations;
·
Employee
workforce factors, including strikes, work stoppages, availability of
qualified employees or the loss of a key executive;
·
The
ability to obtain insurance coverage and the cost of such
insurance;
·
The
ability to maintain effective internal controls over financial reporting
and operational processes; and
·
With
respect to merger transactions Puget Energy announced on October 26,2007:
§
The
risk that the merger may not be consummated in a timely manner if at all,
including due to the failure to receive any required regulatory
approvals;
§
The
risk that the merger agreement may be terminated in circumstances that
require Puget Energy to pay a termination fee of up to $40.0 million, plus
out-of-pocket expenses of the acquiring entity and its members of up to
$10.0 million (or if no termination fee is payable, up to $15.0 million);
and
§
The
effect of the announcement of the merger on our business relationships,
operating results and business generally, including our ability to retain
key employees.
Any
forward-looking statement speaks only as of the date on which such statement is
made, and, except as required by law, Puget Energy and PSE undertake no
obligation to update any forward-looking statement to reflect events or
circumstances after the date on which such statement is made or to reflect the
occurrence of unanticipated events. New factors emerge from time to
time and it is not possible for management to predict all such factors, nor can
it assess the impact of any such factor on the business or the extent to which
any factor, or combination of factors, may cause results to differ materially
from those contained in any forward-looking statement. You are also
advised to consult Item 1A-“Risk Factors” in the Company’s most recent annual
report on Form 10-K.
Adjustments
to reconcile net income to net cash provided by operating
activities:
Depreciation
and amortization
75,367
69,609
Conservation
amortization
13,366
11,328
Deferred
income taxes and tax credits, net
22,327
11,148
Power
cost adjustment mechanism
(35
)
(104
)
Amortization
of gas pipeline capacity assignment
(2,614
)
(2,690
)
Non
cash return on regulatory assets
(3,363
)
(1,823
)
Net
unrealized loss on derivative instruments
88
(5,782
)
Non
cash Colstrip settlement
10,487
--
Change
in residential exchange program
(921
)
(8,111
)
Storm
damage deferred costs
(179
)
(16,759
)
Other
(37
)
6,258
Change
in certain current assets and liabilities:
Accounts
receivable and unbilled revenue
25,456
51,487
Materials
and supplies
930
(7,633
)
Fuel
and gas inventory
59,482
56,523
Prepaid
income taxes
41,271
497
Prepayments
and other
3,146
(1,833
)
Purchased
gas receivable/payable
(9,436
)
43,666
Accounts
payable
(17,884
)
(94,487
)
Taxes
payable
22,900
30,967
Accrued
expenses and other
11,397
7,298
Net
cash provided by operating activities
332,652
228,336
Investing
activities:
Construction
expenditures - excluding equity AFUDC
(126,646
)
(239,681
)
Energy
efficiency expenditures
(14,010
)
(8,964
)
Restricted
cash
(1
)
(1
)
Refundable
cash received for customer construction projects
1,185
4,456
Cash
proceeds from property sales
2,076
57
Other
(1,377
)
322
Net
cash used by investing activities
(138,773
)
(243,811
)
Financing
activities:
Change
in short-term debt, net
(158,882
)
133,440
Dividends
paid
(48,581
)
(26,255
)
Loan
(payment) from/to Puget Energy
14,234
73
Redemption
of bonds and notes
--
(100,000
)
Investment
from Puget Energy
--
1,705
Issuance
and redemption cost of bonds and other
3,979
5,104
Net
cash (used) provided by financing activities
(189,250
)
14,067
Net
increase (decrease) in cash from net income
4,629
(1,408
)
Cash
at beginning of year
40,773
28,092
Cash
at end of period
$
45,402
$
26,684
Supplemental
cash flow information:
Cash
payments for interest (net of capitalized interest)
$
38,642
$
32,009
Cash
refunds from income taxes
(39,730
)
--
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). PSE is a public utility incorporated in the state of
Washington that furnishes electric and natural gas services in a territory
covering 6,000 square miles, primarily in the Puget Sound
region.
The 2008
and 2007 consolidated financial statements of Puget Energy reflect the accounts
of Puget Energy and its subsidiary, PSE. PSE’s consolidated financial
statements include the accounts of PSE and its subsidiaries. Puget
Energy and PSE are collectively referred to herein as “the
Company.” The consolidated financial statements are presented after
elimination of all significant intercompany items and
transactions.
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, 2007.
The
preparation of financial statements in conformity with generally accepted
accounting principles (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 $76.6 million for the three months ended March 31,2008, and $74.6 million for the three months ended March 31,2007. 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 129,428,000 for the three months
ended March 31, 2008, and 116,479,000 for the three months ended March 31,2007.
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 129,940,000 for the three months ended March31, 2008, and 116,974,000 for the three months ended March 31,2007. 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” (SFAS No. 133), as amended, requires that
all contracts considered to be derivative instruments be recorded on the balance
sheet at their fair value. The Company enters into contracts to
manage its energy resource portfolio and interest rate exposure including
forward physical and financial contracts, option contracts and
swaps. The majority of these contracts qualify for the normal
purchase normal sale (NPNS) exception to derivative accounting rules provided
they meet certain criteria. Generally, NPNS applies if PSE deems the
counterparty creditworthy, if the counterparty owns or controls energy resources
within the western region to allow for physical delivery of the energy and if
the transaction is within PSE’s forecasted load requirements and adjusted from
time to time. Those contracts that do not meet NPNS exception or cash
flow hedge criteria are marked-to-market to current earnings in the income
statement, subject to deferral under SFAS No. 71, “Accounting for the Effects of
Certain Types of Regulation” (SFAS No. 71), for energy related derivatives due
to the Power Cost Adjustment (PCA) mechanism and Purchased Gas Adjustment (PGA)
mechanism.
The
nature of serving regulated electric customers with its wholesale portfolio of
owned and contracted electric generation resources exposes the Company and its
customers to some volumetric and commodity price risks within the sharing
mechanism of the PCA. The Company’s energy risk portfolio management
function monitors and manages these risks using analytical models and
tools. The Company is not engaged in the business of assuming risk
for the purpose of realizing speculative trading revenues. Therefore,
wholesale market transactions are focused on balancing the Company’s energy
portfolio, reducing costs and risks where feasible and reducing volatility in
wholesale costs and margin in the portfolio. In order to manage risks
effectively, the Company enters into physical and financial transactions which
are appropriate for the service territory of the Company and are relevant to its
regulated electric and gas portfolios.
The following
table presents electric derivatives that are designated as cash flow hedges or
contracts that do not meet NPNS at March 31, 2008 and December 31,2007:
If it is
determined that it is uneconomical to operate PSE’s controlled electric
generating facilities in the future period, the fuel supply cash flow hedge
relationship is terminated and the hedge is de-designated which results in the
unrealized gains and losses associated with the contracts being recorded in the
income statement. As these contracts are settled, the costs are
recognized as energy costs and are included as part of the PCA
mechanism.
At
December 31, 2007, the Company had an unrealized day one loss deferral of $9.0
million related to a three-year locational power exchange contract which was
modeled and therefore the day one gain was deferred under EITF No.
02-3. The contract has economic benefit to the Company over its
terms. The locational exchange will help ease electric transmission
congestion across the Cascade Mountains during the winter months as PSE will
take delivery of energy at a location that interconnects with PSE’s transmission
system in western Washington. At the same time, PSE will make
available the quantities of power at the Mid-Columbia trading hub
location. The day one loss deferral was transferred to retained
earnings on January 1, 2008 as required by SFAS No. 157, “Fair Value
Measurements” and any future day one loss on contracts will be recorded in the
income statement beginning January 1, 2008 in accordance with the
statement.
The
following tables present the impact of changes in the market value of derivative
instruments not meeting NPNS or cash flow hedge criteria, and ineffectiveness
related to highly effective cash flow hedges, to the Company’s earnings during
the three months ended March 31, 2008 and March 31, 2007:
In the
first quarter 2007, the Company reversed a loss reserve due to credit worthiness
related to a physically delivered natural gas supply contract for electric
generation. The counterparty’s financial outlook had changed and
delivery was determined to be probable through the life of the contract, which
expires on June 30, 2008.
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 March 31, 2008 and
December 31, 2007:
At March31, 2008, the Company had total assets of $57.7 million and total liabilities of
$1.4 million related to hedges of natural gas contracts to serve natural gas
customers. All mark-to-market adjustments relating to the natural gas
business have been reclassified to a deferred account in accordance with SFAS
No. 71 due to the PGA mechanism. All increases and decreases in the
cost of natural gas supply are passed on to customers with the PGA
mechanism. As the gains and losses on the hedges are realized in
future periods, they will be recorded as natural gas costs under the PGA
mechanism.
(4)
Corporate Guarantees
(Puget Energy Only)
On May 7,2006, Puget Energy sold InfrastruX Group Inc. (InfrastruX) to an affiliate of
Tenaska Power Fund, L.P. (Tenaska) in an all-cash transaction. 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 a part of the transaction, Puget Energy made certain
representations and warrantees concerning InfrastruX and indemnified Tenaska
against certain future losses not to exceed $15.0 million. At the
time of the sale, Puget Energy purchased a warrantee insurance policy and
deposited $3.7 million into an escrow account, representing the full retention
under the insurance policy. Additionally at the time of sale, Puget
Energy recorded a $5.0 million loss reserve in connection with the
indemnifications, which represented management's measurement of the fair value
of the corporate guarantees using a probability weighted approach.
On April29, 2008, Puget Energy and Tenaska entered into a Joint Notice of Distribution
and Termination Agreement (Termination Agreement) that would result in the
extinguishment of all InfrastruX corporate guarantees made by Puget Energy in
connection with the sale of InfrastruX. Under the terms of the
Termination Agreement, Puget Energy has agreed to release approximately $3.6
million of the $4.0 million currently held in the escrow account balance to
InfrastruX and make an additional payment of approximately $3.2 million in the
second quarter 2008. In aggregate, payments will approximate the
remaining loss reserves recorded by Puget Energy at March 31, 2008 and thus will
not have a material impact on Puget Energy’s financial results for
2008.
(5)
Retirement
Benefits
The
Company has a defined benefit pension plan covering substantially all PSE
employees, with a cash balance feature for all but International Brotherhood of
Electrical Workers (IBEW) employees. Benefits are a function of age,
salary and service. Puget Energy also maintains a non-qualified
supplemental retirement plan for officers and certain director-level
employees.
The
following table summarizes the net periodic benefit cost for the three months
ended March 31:
Pension
Benefits
Other
Benefits
(Dollars
in Thousands)
2008
2007
2008
2007
Service
cost
$
3,288
$
3,263
$
43
$
91
Interest
cost
7,051
6,570
283
379
Expected
return on plan assets
(10,455
)
(9,750
)
(197
)
(205
)
Amortization
of prior service cost
315
511
21
134
Recognized
net actuarial (gain) loss
183
1,173
(199
)
(56
)
Amortization
of transition obligation
--
--
13
105
Net
periodic benefit cost
$
382
$
1,767
$
(36
)
$
448
The
Company previously disclosed in its financial statements for the year ended
December 31, 2007 that it expected to contribute $4.0 million and less than $0.1
million to fund the non-qualified pension and other benefits plans for the year
ending December 31, 2008, respectively. During the three months ended
March 31, 2008, the actual cash contributions to the Company’s non-qualified
pension plans were $0.4 million. Based on this activity, the Company
anticipates contributing an additional $3.6 million to the Company’s
non-qualified pension plan for the remaining period of 2008. During
the three months ended March 31, 2008, actual other post-retirement medical
benefit plan contributions were less than $0.1 million and the Company does not
expect to make additional contributions for the remaining periods of
2008.
(6)
Regulation
and Rates
On April11, 2007, the Washington Utilities and Transportation Commission (Washington
Commission) issued an accounting order that authorized PSE to defer certain
ownership and operating costs (and associated carrying costs) incurred related
to its purchase of the Goldendale electric generating facility (Goldendale)
during the period prior to inclusion in PSE’s retail electric rates in the Power
Cost Only Rate Case (PCORC). The deferral was for the time period
from March 15, 2007 through September 1, 2007, at which time the Company began
recovering Goldendale ownership and operation costs in electric
rates. As of March 31, 2008, PSE had established a regulatory asset
of $11.8 million. PSE anticipates amortization of the costs will
begin no later than November 2008 as determined in PSE’s pending general rate
case.
In May
2007, the Washington Commission Staff alleged that PSE’s natural gas system
service provider had violated certain Washington Commission recordkeeping
rules. The Washington Commission filed a complaint against PSE that
included Washington Commission Staff’s recommendation that PSE be assessed a
$2.0 million regulatory penalty. On April 3, 2008, the Washington
Commission issued an order approving a settlement agreement that requires PSE to
pay a regulatory penalty of $1.25 million, to establish a quality control
program to better monitor its subcontractors and to complete an independent
audit of natural gas system recordkeeping procedures. At March 31,2008, PSE adjusted its loss reserve to $1.25 million for this
penalty.
On May21, 2007, the Bonneville Power Administration (BPA) notified PSE and other
investor-owned utilities that BPA was suspending payments related to its
Residential Exchange Program (REP) due to adverse Ninth Circuit Court of Appeals
(Ninth Circuit) decisions issued on May 3, 2007. The Ninth Circuit
concluded in its decisions that certain BPA actions in entering into residential
exchange settlements in 2000 were not in accordance with the law. As
a result of the BPA suspension of payment, PSE filed revisions to the tariffs
which pass-through the benefits of the REP to all residential and small farm
customers. Under federal law investor-owned utilities receiving REP
benefits must pass-through the benefits to their residential and small farm
electric customers. The Washington Commission approved the tariff
revisions terminating the REP credit effective June 7, 2007.
At the
time of the suspension of payments, PSE had a credit of REP payments to
customers. Accordingly, in addition to terminating the REP credit,
PSE also filed an accounting petition seeking approval to record carrying costs
on the deferred asset balance until it is recovered from
customers. On August 29, 2007, the Washington Commission approved
PSE’s accounting petition to defer as a regulatory asset the excess REP benefit
provided to customers and accrue monthly carrying charges on the deferred
balance from June 7, 2007 until the deferral is recovered from customers or
BPA. As of March 31, 2008, PSE has recorded a regulatory asset,
including carrying costs, of $36.6 million.
On
December 17, 2007, BPA released a proposal for public comment which would
provide temporary, interim relief to the region’s investor-owned utilities until
final REP contracts are reached and executed which are planned to go into effect
October 1, 2008. These interim agreements are offered in exchange for
suspension of certain litigation activities, and will be trued-up to the actual
final REP benefits for each individual company as established in BPA’s upcoming
administrative proceedings. In March 2008,
BPA and PSE signed an agreement pursuant to which BPA (on April 2, 2008) paid
PSE $53.7 million in REP benefits for fiscal year ending September 30, 2008,
which payment is subject to true-up depending upon the amount of any REP
benefits ultimately determined to be payable to PSE.
On April10, 2008, the Washington Commission approved PSE’s tariff filing seeking to
pass-through the net amount of the benefits under the interim agreements to
residential and small farm customers. The Washington Commission also
approved PSE’s request to credit the regulatory asset amount of $33.7 million
against the $53.7 million payment and pass-through to customers the remaining
amount of approximately $20.0 million. These amounts will not affect
PSE’s net income. The accrued carrying charges on the regulatory
asset totaling $2.9 million at March 31, 2008 will be addressed in PSE’s pending
general rate case (Docket No. UE-072300).
In
November 2007, PSE was audited by the Western Electricity Coordinating Council
(WECC) under delegated authority of the North American Electric Reliability
Corporation (NERC), the FERC-certified Electric Reliability Organization
(ERO). Previously, PSE had submitted several self-reports and mitigation
plans to WECC for review and approval. The WECC audit team identified
four additional potential violations that were not previously
self-reported. In response, PSE submitted self-reports and mitigation
plans for the four violations. WECC issued the final audit report on
March 28, 2008. As of April 16, 2008, PSE had not received notice of
penalties, but has established a loss reserve of $0.6 million related to these
potential violations.
(7)
Litigation
Residential
Exchange. Petitioners in several actions in the Ninth Circuit
against BPA asserted that BPA acted contrary to law in entering into or
performing or implementing a number of agreements, including the amended
settlement agreement (and the May 2004 agreement) between BPA and PSE regarding
the REP. 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 were confirmed,
approved and allowed to go into effect by the Federal Energy Regulatory
Commission (FERC). Petitioners in several actions in the Ninth
Circuit against BPA also asserted that BPA acted contrary to law in adopting or
implementing the rates upon which the benefits received or to be received from
BPA during the October 1, 2001 through September 30, 2006 period were
based. 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
March 2008, BPA requested FERC to continue a stay of FERC’s review of such rates
in light of the reopened rate proceeding described below arising out of the
Ninth Circuit litigation.
On May 3,2007, the Ninth Circuit issued an opinion in Portland Gen. Elec. v. BPA,
No. 01-70003, in which proceeding the actions of BPA in entering into settlement
agreements regarding the BPA REP with PSE and with other investor-owned
utilities were challenged. In this opinion, the Ninth Circuit granted
petitions for review and held the settlement agreements entered into between BPA
and the investor-owned utilities being challenged in that proceeding to be
inconsistent with statute. On May 3, 2007, the Ninth Circuit also
issued an opinion in Golden
Northwest Aluminum v. BPA, No. 03-73426, in which proceeding the
petitioners sought review of BPA’s 2002-06 power rates. In this
opinion, the Ninth Circuit granted petitions for review and held that BPA
unlawfully shifted onto its preference customers the costs of its settlements
with the investor-owned utilities. On October 5, 2007, petitions for
rehearing of these two opinions were denied. On February 1, 2008, PSE
and other utilities filed in the U.S. Supreme Court a petition for a writ of
certiorari to review the decisions of the Ninth Circuit.
In May
2007, following the Ninth Circuit’s issuance of these two opinions, BPA
suspended payments to PSE under the amended settlement agreement (and the May
2004 agreement). On August 29, 2007, the Washington Commission
approved PSE’s accounting petition to defer as a regulatory asset the excess BPA
Residential Exchange benefit provided to customers and accrue monthly carrying
charges on the deferred balance from June 7, 2007 until the deferral is
recovered from customers or BPA. As of March 31, 2008, PSE has a
regulatory asset, including carrying cost, of $36.6 million. On
October 11, 2007, the Ninth Circuit remanded the May 2004 agreement to BPA in
light of the Portland Gen.
Elec. V. BPA opinion and dismissed the remaining three pending cases
regarding settlement agreements.
On
February 8, 2008, BPA issued a notice reopening its WP-07 rate proceeding to
respond to the various Ninth Circuit opinions. In the notice, BPA
proposed to adjust its fiscal year 2009 rates and to determine the amounts of
Residential Exchange benefits paid since 2002 that may be
recovered. BPA is proposing to determine an amount that was
improperly passed through to residential and small farm customers of PSE and the
other regional investor-owned utilities during the 2002 to 2008 rate periods and
to recover this amount over time by reducing future benefits under the
REP. The amount to be recovered over future periods from PSE’s
residential and small farm customers in BPA’s initial proposal is approximately
$150.0 million. However, this is an initial proposal and is subject
to BPA’s rate case process resulting in a final decision in approximately August
2008, and is also subject to subsequent administrative and judicial
review.
In March
2008, BPA and PSE signed an agreement pursuant to which BPA made a payment to
PSE related to the REP benefits for the fiscal year ending September 30, 2008,
which payment is under such agreement subject to true-up depending upon the
amount of any REP benefits ultimately determined to be payable to
PSE. In March and April 2008, Clatskanie People’s Utility District
filed petitions in the Ninth Circuit for review of BPA actions in connection
with offering or entering into such agreement with PSE and similar agreements
with other investor-owned utilities.
It is not
clear what impact, if any, such reopened rate proceeding, development or review
of such rates, review of such agreements and the above described Ninth Circuit
litigation may ultimately have on PSE.
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.
Lockyer Case. In
March and April 2008, FERC issued orders establishing procedures for the Lockyer
remand. The orders commence a seller-by-seller inquiry into the
transaction reports filed by entities that sold power in California during
2000. The inquiry is to determine if the transaction reports as filed
masked the gathering of more than 20% of the market during the period, by that
seller. PSE is confident that it will not be found to have possessed
20% of any relevant market during any relevant time. The order also
mandates a settlement process before an Administrative Law Judge. The
California parties sought rehearing of these orders on April 21,2008.
California Receivable and California
Refund Proceeding. On March 18, 2008, the California Independent System
Operator (CAISO) filed a status report with its calculations of interest owed by
and owing to parties. The report also identified further work to
perform in the CAISO’s “who owes what to whom” calculation. On March25, 2008, FERC issued an order addressing, among other things, 11 pending
rehearing requests by the California parties – all of which the order
rejected.
Orders to Show
Cause. On June 25, 2003, FERC issued two show cause orders
pertaining to its western market investigations that commenced individual
proceedings against many sellers. One show cause order investigated
26 entities that allegedly had potential “partnerships” with
Enron. PSE was not named in that show cause order. On
January 22, 2004, FERC stated that it did not intend to proceed further against
other parties.
The
second show cause order named PSE (Docket No. EL03-169) and approximately 54
other entities that allegedly had engaged in potential “gaming” practices
in the CAISO and California PX markets. PSE and FERC staff filed a
proposed settlement of all issues pending against PSE in those proceedings on
August 28, 2003. The proposed settlement, which admits no wrongdoing
on the part of PSE, would result in a payment of a nominal amount to settle all
claims. FERC approved the settlement on January 22,2004. The California parties filed for rehearing of that
order. On March 17, 2004, PSE moved to dismiss the California
parties’ rehearing request and awaits FERC action on that motion.
Pacific Northwest Refund
Proceeding. In October 2000, PSE filed a complaint at FERC
(Docket No. EL01-10) against “all jurisdictional sellers” in the Pacific
Northwest seeking prospective price caps consistent with any result FERC ordered
for the California markets. FERC dismissed PSE’s complaint, but PSE
challenged that dismissal. On June 19, 2001, FERC ordered price
caps on energy sales throughout the West. Various parties, including
the Port of Seattle and the cities of Seattle and Tacoma, then moved to
intervene in the proceeding seeking retroactive refunds for numerous
transactions. The proceeding became known as the “Pacific Northwest
Refund Proceeding,” though refund claims were outside the scope of the
original complaint. On June 25, 2003, FERC terminated the proceeding
on procedural, jurisdictional and equitable grounds and on November 10, 2003,
FERC on rehearing, confirmed the order terminating the proceeding. On
August 24, 2007, the Ninth Circuit issued a decision concluding that FERC should
have evaluated and considered evidence of market manipulation in California and
its potential impact in the Pacific Northwest. It also decided that
FERC should have considered purchases made by the California Energy Resources
Scheduler and/or the California Department of Water Resources in the Pacific
Northwest Proceeding. On December 17, 2007, PSE and Powerex
separately filed requests for rehearing with the Ninth Circuit of this
decision. Those requests remain pending. PSE intends to
vigorously defend its position in this proceeding, but it is unable to predict
the outcome of this matter.
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 (1) seepage from two different wastewater pond areas caused
groundwater contamination and threatened to contaminate domestic water wells and
the Colstrip water supply pond, and (2) seepage from the Colstrip water supply
pond caused structural damage to buildings and toxic mold. Plaintiffs
were seeking compensatory (including but not limited to unjust enrichment and
abatement) and punitive damages. After a failed attempt at settlement
in 2004, PSE established a reserve of approximately $0.7 million, of which $0.5
million was for PSE’s share of costs to extend city water to 13 plaintiffs and
PSE reduced its reserve to approximately $0.2 million. Discovery was
completed and trial was scheduled for June 2008.
Recent
developments in the litigation have caused PSE to change its
reserve. On February 15, 2008, plaintiffs submitted supplemental
expert disclosures which, among other things, alleged new abatement claims
significantly higher than prior allegations. On April 11, 2008 the
trial court judge issued an order denying defendant’s motion to dismiss
plaintiffs’ substantial unjust enrichment claims. On April 22, 2008
the trial court judge issued an order that PSE along with two other defendants
would be held liable on all counts, including a finding of malice for punitive
damages, as a discovery sanction. Although the defendants
submitted a motion for reconsideration of this sanction on April 25, 2008, the
defendants reached agreement on a global settlement with all plaintiffs on April29, 2008 and PSE’s share of that settlement is approximately $10.7
million. PSE expects settlement documents to be finalized in the
second quarter 2008 and as a result have increased the reserve to $10.7
million. PSE is also evaluating whether it will file an accounting
petition to defer such costs.
The
Minerals Management Service of the United States Department of Interior
(MMS) has issued a series of orders to Western Energy Company (WECO) to pay
additional taxes and royalties concerning coal WECO sold to the owners of
Colstrip 3 & 4, and similar orders have been issued in the administrative
appellate process. The orders assert that additional royalties are
owed in connection with payments received by WECO from Colstrip 3
& 4 owners (including PSE) for the construction and operation of a
conveyor system that runs several miles from the mine to Colstrip 3 &
4. The state of Montana has also issued a demand to WECO consistent
with the MMS position. WECO has challenged these orders, and the
issue has been on appeal for several years. WECO has won
some points during the appellate process that have reduced the claims--but under
applicable law, to pursue the appeals, the principal in dispute cannot be paid,
which causes interest to accrue. Moreover, because the conveyor
system continues to be used, the amount in
dispute grows. In the aggregate, the accrued
interest--plus unasserted claims to bring the amount
current--could make the total claim (principal plus interest) pertaining to
PSE’s 25% project share as high as $10 million. PSE is unable to
predict the ultimate outcome of this dispute. PSE believes a future loss
in connection with this dispute is reasonably possible but not probable, and has
not recorded a loss reserve. Proceeding Relating to the Proposed
Merger. On October 26, 2007 and November 2, 2007,
two separate lawsuits were filed against the Company and all of the members of
the Company’s Board of Directors in Superior Court in King County,
Washington. The lawsuits, respectively, are entitled, Tansey v. Puget Energy, Inc.,
et al., Case No. 07-2-34315-6 SEA and Alaska Ironworkers Pension Trust v.
Puget Energy, Inc., et al., Case No. 07-2-35346-1
SEA. The lawsuits are both denominated as class actions purportedly
on behalf of Puget Energy’s shareholders and assert substantially similar
allegations and causes of action relating to the proposed merger. The
complaints allege that Puget Energy’s directors breached their fiduciary duties
in connection with the merger and seek virtually identical relief, including an
order enjoining the consummation of the merger. Pursuant to a court
order dated November 26, 2007, the two cases were consolidated for all
purposes and entitled In re
Puget Energy, Inc. Shareholder Litigation, Case No. 07-2-34315-6
SEA.
On
February 6, 2008, the parties entered into a memorandum of understanding
providing for the settlement of the consolidated lawsuit, subject to customary
conditions including completion of appropriate settlement documentation,
confirmatory discovery and court approval. Pursuant to the memorandum
of understanding, the Company agreed to include certain additional disclosures
in its proxy statement relating to the merger. The Company does not
admit, however, that its prior disclosures were in any way materially misleading
or inadequate. In addition, the Company and the other defendants in
the consolidated lawsuit deny the plaintiffs’ allegations of wrongdoing and
violation of law in connection with the merger. The settlement, if
completed and approved by the court, will result in dismissal with prejudice and
release of all claims of the plaintiffs and settlement class of the Company’s
shareholders that were or could have been brought on behalf of the plaintiffs
and the settlement class. In connection with such settlement, the
plaintiffs intend to seek a court-approved award of attorneys’ fees and expenses
in an amount up to $290,000, which the Company has agreed to pay. At
March 31, 2008, the Company has a loss reserve of $290,000 recorded at March 31,2008 related to this matter.
(8)
Related
Party Transactions
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 March 31, 2008 and December 31, 2007, the outstanding
balance of the Note was $30.0 million and $15.8 million, respectively and the
interest rate was 3.57% and 5.31%, respectively. The outstanding
balance and the related interest under the Note are eliminated by Puget Energy
upon consolidation of PSE’s financial statements. The $30.0 million
credit facility with Puget Energy is unaffected by the pending
merger.
During
2007, the Company purchased certain insurance policies from AEGIS and had three
insurance claim receivables from AEGIS totaling $7.7 million and $15.2 million
at March 31, 2008 and December 31, 2007, respectively. One
nonemployee director of Puget Energy and PSE also serves on the board of AEGIS
and a PSE management employee serves on one of AEGIS’ risk management
committees.
(9)
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 two counterparties during the three months ended March 31, 2008
may be considered variable interest entities. Consistent with FIN
46R, PSE submitted requests for information to those two entities; however, the
entities 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.
Sumas
Cogeneration Company, L.P. (Sumas), an entity that potentially could have been
considered a variable interest entity prior to May 7, 2007, delivered a letter
to PSE on May 7, 2007, stating that it had sold its dedicated natural gas
reserves to a third party and that it no longer intended to deliver energy to
PSE through the remaining term of the contract, which expires on April 15,2013. The last energy delivered to PSE by Sumas occurred on March 15,2007. Following negotiations to resolve the breach of contract with
Sumas on December 7, 2007, PSE and Sumas signed a Membership Interest Purchase
and Sale Agreement for the acquisition of the 125 MW power plant located in
Sumas, Washington. Sumas also agreed to transfer an undivided
ownership interest in the pipeline easements to PSE. PSE expects the
transaction to close in the second half of 2008, after it receives approval from
FERC and presidential permits to operate the natural gas pipeline.
For the
two power purchase agreements that may be considered variable interest entities
under FIN 46R as of the first quarter 2008, 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 March 31, 2008 was $54.9 million for the two entities and for the
three months ended March 31, 2007 was $66.6 million for the three
entities.
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 U. S. Environmental Protection Agency (EPA). The
Notice stated that PSE had met the requirements of the Order and the
accompanying scope of work. Total removal costs as of March 31, 2008
were approximately $14.1 million. PSE estimates the total remediation
cost to be approximately $15.0 million, which has been accrued or
paid. At March 31, 2008, PSE had an insurance receivable recorded in
the amount of $7.6 million associated with this fuel release. PSE
received a partial payment of $5.0 million on this receivable in January
2008. On February 13, 2008, the U.S. Department of Justice, on behalf
of the EPA, notified PSE of its intent to issue a fine of $0.5 million under the
Clean Water Act. PSE has since agreed to pay this fine. On
April 15, 2008, the Washington State Department of Ecology fined PSE $0.4
million as a civil penalty pursuant to the Clean Water Act. PSE
reserved $1.0 million for the penalties in 2006.
As of
March 31, 2008, PSE had $18.1 million in insurance receivables recorded related
to two property damage claims and a general liability claim. As of
March 31, 2008, PSE has received $8.8 million in payments from the insurers
associated with these claims. $10.1 million of the receivable balance
represents an estimate based on the cost that would have been incurred to
repair, rather than replace, the damaged parts. If PSE does not
receive full recovery of this receivable, the accrued amount will be recorded to
utility plant.
(10)
New
Accounting Pronouncements
On
September 15, 2006, FASB issued SFAS No. 157, which clarifies how companies
should use fair value measurements in accordance with GAAP for recognition and
disclosure purposes. SFAS No. 157 establishes a common definition of
fair value and a framework for measuring fair value under GAAP, along with
expanding disclosures about fair value to eliminate differences in current
practice that exist in measuring fair value under the existing accounting
standards. The definition of fair value in SFAS No. 157 retains the
notion of exchange price; however, it focuses on the price that would be
received to sell the asset or paid to transfer a liability (i.e. an exit price),
rather than the price that would be paid to acquire the asset or received to
assume the liability (i.e. an entrance price). Under SFAS No. 157, a
fair value measure should reflect all of the assumptions that market
participants would use in pricing the asset or liability, including assumptions
about the risk inherent in a particular valuation technique, the effect of a
restriction on the sale or use of an asset, and the risk of
nonperformance. To increase consistency and comparability in fair
value measures, SFAS No. 157 establishes a three-level fair value hierarchy to
prioritize the inputs used in valuation techniques between observable inputs
that reflect quoted market prices in active markets, inputs other than quoted
prices with observable market data, and unobservable data (e.g. a company’s own
data).
SFAS No.
157 is effective for fiscal years beginning after November 15, 2007, which was
January 1, 2008, for the Company. On February 28, 2008, the FASB
issued a final FASB Staff Position (FSP) that partially deferred the effective
date of SFAS No. 157 for one year for non-financial assets and non-financial
liabilities that are recognized or disclosed at fair value, except for those
that are recognized or disclosed at fair value on an annual or more frequent
basis. The Company adopted SFAS No. 157 on January 1, 2008,
prospectively, as required by the Statement, with certain
exceptions, including the initial impact of changes in fair value
measurements of existing derivative financial instruments measured initially
using the transaction price under EITF 02-3. On January 1, 2008, the
difference between the carrying amounts and the fair values of those instruments
originally recorded under guidance in EITF 02-3 was recognized as a
cumulative-effect adjustment to the opening balance of retained
earnings. SFAS No. 157 nullified a portion of EITF
02-3. Under EITF 02-3, the transaction price presumption prohibited
recognition of a trading profit at inception of a derivative unless the positive
fair value of that derivative was substantially based on quoted prices or a
valuation process incorporating observable inputs. For transactions
that did not meet this criterion at inception, trading profits that had been
deferred were recognized in the period that inputs to value the derivative
became observable or when the contract performed.
On March19, 2008, FASB issued SFAS No. 161, “Disclosures about Derivative Instruments
and Hedging Activities – An Amendment of FASB Statement No. 133” (SFAS No.
161). SFAS No. 161 is effective for the fiscal years and interim
years beginning after November 15, 2008, which will be the quarter ended March31, 2009 for the Company. SFAS No. 161 requires companies with
derivative instruments to disclose information that should enable financial
statement users to understand how and why a company uses derivative instruments,
how derivative instruments and related hedged items are accounted for under SFAS
No. 133 and how derivative instruments and related hedged items affect a
company’s financial position, financial performance and cash
flows. SFAS No. 161 requirements will impact the following derivative
and hedging disclosures: objectives and strategies, balance sheet, financial
performance, contingent features and counterparty credit risk. The
Company is currently assessing the impact of SFAS No. 161.
(11)
Fair
Value Measurements
Effective
January 1, 2008, the Company adopted SFAS No. 157 which clarifies how companies
should use fair value measurements and requires enhanced disclosures about
assets and liabilities carried at fair value.
As
defined in SFAS No. 157, fair value is the price that would be received to sell
an asset or paid to transfer a liability in an orderly transaction between
market participants at the measurement date (exit price). However, as
permitted under SFAS No. 157, the Company utilizes a mid-market pricing
convention (the mid-point price between bid and ask prices) as a practical
expedient for valuing the majority of its assets and liabilities measured and
reported at fair value. The Company utilizes market data or
assumptions that market participants would use in pricing the asset or
liability, including assumptions about risk and the risks inherent in the inputs
to the valuation technique. These inputs can be readily observable,
market corroborated, or generally unobservable. The Company primarily
applies the market approach for recurring fair value measurements and endeavors
to utilize the best available information. Accordingly, the Company
utilizes valuation techniques that maximize the use of observable inputs and
minimize the use of unobservable inputs.
PSE
values derivative instruments based on daily quoted prices from numerous
independent energy brokerage services. When external quoted market
prices are not available for derivative contracts, PSE uses a valuation model
that uses volatility assumptions relating to future energy prices based on
specific energy markets and utilizes externally available forward market price
curves. All derivative instruments are sensitive to market price
fluctuations that can occur on a daily basis. The Company is focused
on commodity price exposure and risks associated with volumetric variability in
the natural gas and electric portfolios. It is not engaged in the
business of assuming risk for the purpose of speculative trading. The
Company hedges open natural gas and electric positions to reduce both the
portfolio risk and the volatility risk in prices. The exposure
position is determined by using a probabilistic risk system that models 100
scenarios of how the Company’s natural gas and power portfolios will perform
under various weather, hydro and unit performance conditions. PSE has
not made any material changes during the reporting period to those techniques or
models.
The
Company is able to classify fair value balances based on the observability of
those inputs. SFAS No. 157 establishes a fair value hierarchy that
prioritizes the inputs used to measure fair value. The hierarchy
gives the highest priority to unadjusted quoted prices in active markets for
identical assets or liabilities (Level 1 measurement) and the lowest priority to
unobservable inputs (Level 3 measurement). The three levels of the
fair value hierarchy defined by SFAS No. 157 are as follows:
Level 1 –
Quoted prices are available in active markets for identical assets or
liabilities as of the reporting date. Active markets are those in
which transactions for the asset or liability occur in sufficient frequency and
volume to provide pricing information on an ongoing basis. Level 1
primarily consists of financial instruments such as exchange-traded derivatives
and listed equities.
Level 2 –
Pricing inputs are other than quoted prices in active markets included in Level
1, which are either directly or indirectly observable as of the reported
date. Level 2 includes those financial instruments that are valued
using models or other valuation methodologies. These models are
primarily industry-standard models that consider various assumptions, including
quoted forward prices for commodities, time value, volatility factors, and
current market and contractual prices for the underlying instruments, as well as
other relevant economic measures. Substantially all of these
assumptions are observable in the marketplace throughout the full term of the
instrument, can be derived from observable data or are supported by observable
levels at which transactions are executed in the
marketplace. Instruments in this category include non-exchange-traded
derivatives such as OTC forwards and options.
Level 3 –
Pricing inputs include significant inputs that are generally less observable
from objective sources. These inputs may be used with internally
developed methodologies that result in management’s best estimate of fair
value. Level 3 instruments include those that may be more structured
or otherwise tailored to customers’ needs. At each balance sheet
date, the Company performs an analysis of all instruments subject to SFAS No.
157 and includes in Level 3 all of those whose fair value is based on
significant unobservable inputs.
The
following table sets forth by level within the fair value hierarchy the
Company’s financial assets and liabilities that were accounted for at fair value
on a recurring basis as of March 31, 2008. As required by SFAS No.
157, financial assets and liabilities are classified in their entirety based on
the lowest level of input that is significant to the fair value
measurement. The Company’s assessment of the significance of a
particular input to the fair value measurement requires judgment and may affect
the valuation of fair value assets and liabilities and their placement within
the fair value hierarchy levels. The determination of the fair values
incorporates various factors required under SFAS No. 157. These
factors include not only the credit standing of the counterparties involved and
the impact of credit enhancements (such as cash deposits, letters of credit and
priority interests), but also the impact of the Company’s nonperformance risk on
its liabilities.
The
Company believes an analysis of energy derivative instruments classified as
Level 3 should take into account the fact that these items are generally
economically hedged as a portfolio with instruments that may be classified in
Levels 1 and 2. Realized gains and losses on energy derivatives for
Level 3 recurring items are included in Energy Costs in PSE’s income statement
under purchased electricity, electric generation fuel or purchased gas when
settled.
Unrealized
gains and losses for Level 3 on energy derivatives recurring items are included
in net unrealized (gain) loss on derivative instruments in PSE’s income
statement. SFAS No. 157 requires that financial assets and
liabilities be classified in their entirety based on the lowest level of input
that is significant to the fair value measurement. As of March 31,2008, energy derivative instruments are classified in Level 3 because Level 3
inputs are significant to their fair value measurement; however, the valuation
of these derivative instruments is primarily based upon observable inputs (Level
2), and the net unrealized gain recognized during the reporting period is
primarily due to a significant increase in observable prices.
Energy
derivatives transferred out represent existing assets or liabilities that were
either previously classified as Level 3 for which the lowest significant input
became observable during the period.
The
Company does not believe that the fair values diverge materially from the
amounts the Company currently anticipates realizing on settlement or
maturity.
Other
financial items valuation is described in Note 4 “Corporate
Guarantees.”
(12)
Agreement
and Plan of Merger (Puget Energy
only)
On
October 26, 2007, Puget Energy announced that it had entered into a definitive
Agreement and Plan of Merger, dated as of October 25, 2007, pursuant to which
Puget Energy will be acquired by a consortium of long-term infrastructure
investors led by Macquarie Infrastructure Partners, the Canada Pension Plan
Investment Board and British Columbia Investment Management Corporation and also
includes Alberta Investment Management, Macquarie-FSS Infrastructure Trust and
Macquarie Capital Group (collectively, the Consortium). At the
effective time of the merger, each issued and outstanding share of common stock
of Puget Energy, other than any shares in respect of which dissenter’s rights
are perfected and other than any shares owned by the Consortium, shall be
cancelled and shall be converted automatically into the right to receive $30.00
in cash, without interest.
The
consummation of the merger is subject to the satisfaction or waiver of certain
closing conditions, including the receipt of shareholder approval of the merger
and approval of it by various state and federal regulatory
authorities. As of the date of this 10-Q, some of these conditions
have been satisfied while others remain outstanding or in process. On
April 16, 2008, Puget Energy shareholders approved the merger by more than the
required two-thirds vote. Also, on April 17, 2008, FERC conditionally
approved the transaction pursuant to section 203 of the Federal Power Act
subject to reviewing the final conditions of merger approval by the Washington
Commission. On December 17, 2007, PSE and the Consortium filed a
joint application seeking approval of the merger with the Washington
Commission. According to the procedural schedule set in the merger
proceeding, a decision by the Washington Commission is expected on September 2,2008. If approved by the Washington Commission and assuming receipt
of approval by the other remaining federal authorities, closing is expected to
occur during the fourth quarter 2008.
Further
information regarding the terms of the merger, including a copy of the Agreement
and Plan of Merger, is included in Puget Energy’s Definitive Proxy Statement
relating to the merger, filed with the Securities and Exchange Commission on
February 16, 2008.
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 or phrases 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. Readers 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 natural
gas utility company. Puget Energy is dependent upon the results of
PSE since PSE is its most significant asset. PSE is the largest
electric and natural gas utility in the state of Washington, primarily engaged
in the business of electric transmission, distribution, generation and natural
gas distribution. Puget Energy’s business strategy is to generate
stable earnings and cash flow by offering reliable electric and natural gas
service in a cost effective manner through PSE.
Puget Energy
Merger
On October 26, 2007, Puget Energy
announced that it had entered into a definitive Agreement and Plan of Merger,
dated as of October 25, 2007, pursuant to which Puget Energy will be acquired by
a consortium of long-term infrastructure investors led by Macquarie
Infrastructure Partners, the Canada Pension Plan Investment Board and British
Columbia Investment Management Corporation and also includes Alberta Investment
Management, Macquarie-FSS Infrastructure Trust and Macquarie Capital Group
(collectively, the Consortium). At the effective time of the merger,
each issued and outstanding share of common stock of Puget Energy, other than
any shares in respect of which dissenter’s rights are perfected and other than
any shares owned by the Consortium, shall be cancelled and shall be converted
automatically into the right to receive $30.00 in cash, without
interest.
The
consummation of the merger is subject to the satisfaction or waiver of certain
closing conditions, including the receipt of shareholder approval of the merger
and approval of it by various state and federal regulatory
authorities. As of the date of this 10-Q, some of these conditions
have been satisfied while others remain outstanding or in process. On
April 16, 2008, Puget Energy shareholders approved the merger by more than the
required two-thirds vote. Also, on April 17, 2008 the Federal Energy
Regulatory Commission (FERC) conditionally approved the transaction pursuant to
section 203 of the Federal Power Act subject to reviewing the final conditions
of merger approval by the Washington Utilities and Transportation Commission
(Washington Commission). On December 17, 2007, PSE and the Consortium
filed a joint application seeking approval of the merger with the Washington
Commission. According to the procedural schedule set in the merger
proceeding, a decision by the Washington Commission is expected on September 2,2008. If approved by the Washington Commission and assuming receipt
of approval by the other remaining federal authorities, closing is expected to
occur during the fourth quarter 2008.
Further
information regarding the terms of the merger, including a copy of the Agreement
and Plan of Merger, is included in Puget Energy’s Definitive Proxy Statement
relating to the merger, filed with the Securities and Exchange Commission on
February 16, 2008.
Puget Sound
Energy
PSE generates revenues primarily from
the sale of electric and natural gas services to residential and commercial
customers within Washington State. PSE’s operating revenues and
associated expenses are not generated evenly throughout the
year. Variations in energy usage by consumers occur from season to
season and from month to month within a season, primarily as a result of weather
conditions. PSE normally experiences its highest retail energy sales
and subsequently higher power costs during the winter heating season in the
first and fourth quarters of the year and its lowest sales in the third quarter
of the year. Varying wholesale electric prices and the amount of
hydroelectric energy supplies available to PSE also make quarter-to-quarter
comparisons difficult.
As a regulated utility company, PSE is
subject to FERC and Washington Commission regulation which may impact a large
array of business activities, including limitation of future rate increases;
directed accounting requirements that may negatively impact earnings; licensing
of PSE-owned generation facilities; and other FERC and Washington Commission
directives that may impact PSE’s long-term goals. In addition, PSE is
subject to risks inherent to the utility industry as a whole, including weather
changes affecting purchases and sales of energy; outages at owned and contracted
generation plants where energy is obtained; storms or other events which can
damage natural gas and electric distribution and transmission lines; increasing
regulatory standards for system reliability; and wholesale market stability over
time and significant evolving environmental legislation.
PSE’s main business objective is to
provide reliable, safe and cost-effective energy to its customers. To
help accomplish this objective, PSE seeks to become more energy efficient and
environmentally responsible in its energy supply portfolio on an ongoing
basis. PSE filed its most recent Integrated Resource Plan (IRP) on
May 31, 2007 with the Washington Commission. The plan supports a
strategy of significantly increasing energy efficiency programs, pursuing
additional renewable resources (primarily wind) and additional base load natural
gas fired generation to meet the growing needs of its
customers.
Non-GAAP
Financial Measures – Energy Margins
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. The
Company’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 its subsidiary
PSE. Net income for the three months ended March 31, 2008 was $79.8
million on operating revenues of $1.1 billion as compared to net income of $79.1
million on operating revenues of $1.0 billion for the same period in
2007.
Basic and
diluted earnings per share for the three months ended March 31, 2008 were $0.62
and $0.61, respectively, as compared to basic and diluted earnings per share for
the three months ended March 31, 2007 of $0.68. Net income for the
three months ended March 31, 2008 as compared to the same period in 2007, was
positively impacted by a $25.4 million increase in electric margin and a $12.5
million increase in gas margin. Net income was negatively impacted by
a $14.0 million increase in utility operation and maintenance which includes the
impact of a $10.5 million charge related to PSE’s share of the settlement of a
lawsuit against the Colstrip electric generating station project owners, an
increase in depreciation and amortization of $5.8 million and an increase in
taxes other than income taxes, net of revenue sensitive taxes, of $5.4
million. Net income was also negatively impacted due to lower real
estate sales by a PSE subsidiary of $7.7 million ($5.4 million after-tax) and by
a $5.9 million decrease in the Statement of Financial Accounting Standards
(SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities”
(SFAS No. 133) unrealized gain for PSE. In the first quarter 2008,
Puget Energy incurred $1.3 million in costs related to the proposed merger with
the Consortium.
Puget Sound
Energy
PSE’s
operating revenues and associated expenses are not generated evenly throughout
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 March 31, 2008 as compared to the same period in
2007. Electric margin is electric sales to retail and transportation
customers less pass-through tariff items and revenue-sensitive taxes, and the
cost of generating and purchasing electric energy sold to customers, including
transmission costs to bring electric energy to PSE’s service
territory.
Add:
Other electric operating revenue-gas supply resale
2.6
1.7
0.9
52.9
Total
electric revenue for margin
596.5
518.3
78.2
15.1
Adjustments
for amounts included in revenue:
Pass-through
tariff items
(12.9
)
(11.2
)
(1.7
)
(15.2
)
Pass-through
revenue-sensitive taxes
(41.6
)
(36.6
)
(5.0
)
(13.7
)
Net
electric revenue for margin
542.0
470.5
71.5
15.2
Minus
power costs:
Purchased
electricity1
(272.8
)
(282.1
)
9.3
3.3
Electric
generation fuel1
(47.0
)
(26.1
)
(20.9
)
(80.1
)
Residential
exchange1
--
34.5
(34.5
)
(100.0
)
Total
electric power costs
(319.8
)
(273.7
)
(46.1
)
(16.8
)
Electric
margin2
$
222.2
$
196.8
$
25.4
12.9
%
____________________________
1
As
reported on PSE’s Consolidated Statement of Income.
2
Electric
margin does not include any allocation for amortization/depreciation
expense or electric generation operation and maintenance
expense.
Electric
margin increased $25.4 million for the three months ended March 31, 2008 as
compared to the same period in 2007. A Power Cost Only Rate Case
(PCORC) rate increase of 3.7% effective September 1, 2007, net of a 1.3% general
rate decrease effective January 13, 2007, contributed an increase to electric
margin of $6.1 million. Also driving the higher electric margin was a
4.1% increase in retail sales volumes which increased electric margin $7.8
million and an $11.0 million reduction in excess power costs ($13.5 million for
the three months ended March 31, 2007 as compared to $2.5 million for the same
period in 2008). Power cost recovery is seasonal with underrecovery
in the first and fourth quarters and overrecovery in the second and third
quarters.
The following table
displays the details of gas margin changes for the three months ended March 31,2008 as compared to the same period in 2007. Gas margin is natural
gas sales to retail and transportation customers less pass-through tariff items
and revenue-sensitive taxes, and the cost of natural gas purchased, including
natural gas transportation costs to bring 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 $12.5 million for the three months ended March 31, 2008 as
compared to the same period in 2007 primarily due to an 8.1% gas therm volume
sales increase resulting in $8.8 million increase to gas
margin. Additionally, there was a $5.4 million increase due to a 2.8%
general rate increase effective January 13, 2007 which had a 9.8% effect on gas
margin. The increases were offset by a $1.7 million decrease related
to industrial usage and pricing.
Electric
Operating Revenues
The table
below sets forth changes in electric operating revenues for PSE for the three
months ended March 31, 2008 as compared to the same period in 2007.
Electric
retail sales increased $79.3 million for the three months ended March 31, 2008
as compared to the same period in 2007 due primarily to a decrease of $36.1
million in the benefits of the Residential and Farm Energy Exchange Benefit
credited to customers during the three-month period ended March 31,2008. This credit also reduced power costs by a corresponding amount
with no impact on earnings. The Residential Exchange Program (REP)
Benefit was suspended effective June 7, 2007 due to adverse rulings from the
Ninth Circuit Court of Appeals (Ninth Circuit) which state that Bonneville Power
Administration (BPA) actions in entering into residential exchange settlement
agreements with investor-owned utilities were not in accordance with the
law. The PCORC rate increase of September 1, 2007 offset by the
electric general rate decrease of January 13, 2007 increased electric operating
revenues by $11.9 million for the three months ended March 31, 2008 as compared
to the same period in 2007. Retail electricity usage increased
246,493 megawatt hours (MWh) or 4.1% for the three months ended March 31, 2008
as compared to the same period in 2007, which resulted in an increase of
approximately $22.4 million in electric operating revenue. The
increase in electricity usage was primarily related to 1.7% higher average
number of customers served in 2008 as compared to 2007.
Sales to
other utilities and marketers decreased $1.2 million for the three months ended
March 31, 2008 as compared to the same period in 2007 primarily due to a
decrease in sales volume of 172,066 MWh or 41.3% as a result of decreased
surplus energy, which resulted in a decrease of $12.7 million. This
decrease was partially offset by higher wholesale prices in the first quarter
2008 as compared to the same period in 2007, which increased sales by $11.5
million.
The following electric rate changes
were approved by the Washington Commission in 2007:
Gas
retail sales decreased $23.9 million for the three months ended March 31, 2008
as compared to the same period in 2007 due to lower Purchased Gas Adjustment
(PGA) mechanism rates and offset by increased customer natural gas
usage. The Washington Commission approved a PGA mechanism rate
increase effective October 1, 2007 that decreased rates 13.0%
annually. The PGA mechanism passes through to customers increases or
decreases in the natural gas supply portion of the natural gas service rates
based upon changes in the price of natural gas purchased from producers and
wholesale marketers or changes in natural gas pipeline transportation
costs. PSE’s gas margin and net income are not affected by changes
under the PGA mechanism. For the three months ended March 31, 2008,
the effects of the PGA mechanism rate resulted in a decrease of $60.9 million in
gas operating revenues. The PGA mechanism decrease was offset by
higher natural gas sales of 32.9 million therms or $37.4 million for the three
months ended March 31, 2008 as compared to the same period in 2007, which was
related to colder temperatures for the three months ended March 31, 2008 as
compared to the same period in 2007 and a 2.4% increase in the number of
customers.
The
following natural gas rate adjustments were approved by the Washington
Commission in 2007:
The table
below sets forth changes in non-utility operating revenues for PSE for the three
months ended March 31, 2008 as compared to the same period in 2007.
Non-utility operating revenues
decreased $7.7 million for the three months ended
March 31, 2008 as compared to the same period in 2007 due to multiple
property sales during the first quarter 2007 by PSE’s real estate subsidiary
that did not occur in the first quarter 2008.
Operating
Expenses
The table
below sets forth significant changes in operating expenses for PSE and its
subsidiaries for the three months ended March 31, 2008 as compared to the same
period in 2007.
Purchased electricity expenses
decreased $9.3 million for the three months ended March 31, 2008 as compared to
the same period in 2007. This decrease was primarily due to a
reduction in the amount of purchased power, 335,446 MWh or 6.8%, because of
increased generation from the Frederickson and Goldendale combustion turbines,
Colstrip generation plant and PSE’s wind generation facilities, which resulted
in a gross reduction of $18.0 million in purchased electricity
expenses. This reduction was offset by an increase in wholesale
market prices and transmission, transmission and other power supply expenses of
$7.4 million and additional transmission expenses of $1.5 million due to
increased transmission volumes.
The May 1, 2008 Columbia Basin Runoff
Forecast published by the National Weather Service Northwest River Forecast
Center indicated that the total forecasted runoff above Grand Coulee Reservoir
for the period January through July 2008 is 95% of normal, which compares to
105% of normal runoff observed for the same period in 2007.
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 $20.9 million for the three months ended March 31, 2008, as
compared to the same period in 2007. The increase for the three
months ended March 31, 2008 was due in part to increased generation from
Goldendale and Frederickson combustion turbines which contributed $16.8 million
and $5.8 million, respectively, partially offset by lower costs of $2.1 million
at other combustion turbine generation facilities. Colstrip fuel
costs increased $0.5 million for the three months ended March 31, 2008, as
compared to the same period in 2007.
Residential exchange credits
associated with the REP with BPA decreased $34.5 million for the three months
ended March 31, 2008 as compared to the same period in 2007 as a result of the
suspension of the residential and small farm customer electric credit in rates
effective June 7, 2007. The suspension was due to an adverse ruling
from the Ninth Circuit which states that BPA actions in entering into
residential exchange settlement agreements with investor owned utilities were
not in accordance with the law. The REP credit is a pass-through
tariff item with a corresponding credit in electric operating revenue; thus, it
has no impact on electric margin or net income.
Purchased gas expenses
decreased $34.4 million for the three months ended March 31, 2008 as compared to
the same period in 2007 primarily due to an increase in PGA rates as approved by
the Washington Commission partially offset by higher customer therm
sales. The PGA mechanism allows PSE to recover expected natural gas
costs, and defer, as a receivable or liability, any natural gas costs that
exceed or fall short of this expected gas cost amount in PGA mechanism rates,
including accrued interest. The PGA mechanism payable balance at
March 31, 2008 was $68.4 million as compared to $77.9 million at December 31,2007. PSE is authorized by the Washington Commission to accrue
carrying costs on PGA receivable and payable balances. A receivable
balance in the PGA mechanism reflects an underrecovery of market natural gas
cost through rates. A payable balance reflects overrecovery of market
natural gas cost through rates.
Unrealized gain on derivative
instruments decreased $5.9 million for the three months ended
March 31, 2008 as compared to the same period in 2007. The decrease
was primarily the result of the reversal of a loss reserve for a physically
delivered natural gas supply contract for PSE’s electric generating facilities
during the three months ended March 31, 2007.
Utility operations and maintenance
expense increased $14.0 million for the three months ended March 31, 2008
as compared to the same period in 2007. The increase includes the
impact of a $10.5 million pre-tax charge related to PSE’s share of the
settlement of a lawsuit against the Colstrip electric generating station project
owners. The remaining increase was the result of a $2.6 million
increase in production operations and maintenance at PSE’s generating facilities
primarily due to the addition of Goldendale, which was acquired in February
2007, $2.4 million higher gas operations and distribution costs and a $1.5
million increase in customer service costs. Goldendale operations and
maintenance expense is fully recovered in rates beginning September 1,2007. These increases were partially offset by a decrease in
transmission and distribution operations and maintenance costs of $2.5 million
primarily due to a reduction in electric storm damage expense.
Non-utility expense and other
decreased $1.9 million for the three months ended March 31, 2008 as compared to
the same period in 2007 primarily due to a decrease in PSE’s long-term incentive
plan costs.
Depreciation and amortization
expense increased $5.8 million for the three months ended March 31, 2008 as
compared to the same period in 2007. The increase was primarily due
to the placement into service of the Goldendale project on February 22, 2007 as
well as the placement into service of other depreciable property during
2007. In addition, there was an increase of $1.0 million due to the
credit related to the deferral of Goldendale ownership and operating costs that
was discontinued September 1, 2007.
Conservation amortization
increased $3.1 million for the three months ended March 31, 2008 as compared to
the same period in 2007 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 $7.2 million for the three months ended March 31, 2008 as compared to
the same period in 2007 due primarily to additional plant placed in service
during 2007 which increase property taxes.
Other
Income, Other Expenses, Interest Expense and Income Tax Expense
The table
below sets forth significant changes in other income, other expenses, interest
expense and income tax expense for PSE and its subsidiaries for the three months
ended March 31, 2008 as compared to the same period in 2007.
Other income increased $2.0
million for the three months ended March 31, 2008 as compared to the same period
in 2007 primarily due a $0.9 million increase related to Washington Commission
allowance for funds used during construction, a $0.9 million increase due to
interest earned on the Residential Exchange regulatory asset and a $0.3 million
increase due to Goldendale regulatory assets.
Income tax expense increased
$1.7 million for the three months ended March 31, 2008 as compared to the same
period in 2007 due primarily to the increase in net income.
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 March 31, 2008:
Non-qualified pension and other benefits funding and
payments
39.9
4.1
8.1
8.0
19.7
Other obligations
18.2
18.2
--
--
--
Total
contractual cash obligations
$
13,982.7
$
1,538.7
$
2,920.5
$
1,868.7
$
7,654.8
Puget
Energy
Amount
of Commitment
Expiration
Per Period
Commercial
Commitments
(Dollars
in Millions)
Total
2008
2009-
2010
2011-
2012
2013
& Thereafter
Indemnity
agreements 2
$
7.2
$
4.0
$
--
$
3.2
$
--
Credit
agreement - available 3
826.0
--
--
--
826.0
Receivable
securitization facility 4
115.0
--
--
115.0
--
Energy
operations letter of credit
7.4
7.4
--
--
--
Total
commercial commitments
$
955.6
$
11.4
$
--
$
118.2
$
826.0
___________________
1
See
“Fredonia 3 and 4 Operating Lease” under “Off-Balance Sheet Arrangements”
below.
2
Under
the InfrastruX sale agreement, Puget Energy is obligated for certain
representations and warranties concerning InfrastruX’s business and
anti-trust inquiries. The fair value of the business warranty
is $4.0 million at March 31, 2008 and the obligation expires on May 7,2008. Puget
Energy also agreed to indemnify the buyer relating to an inquiry of an
InfrastruX subsidiary and the fair value of the warranty was $3.2 million
at March 31, 2008.
3
At
March 31, 2008, 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 March 31, 2008, PSE had $7.4 million outstanding
under four letters of credit and $16.6 million commercial paper
outstanding, effectively reducing the available borrowing capacity to
$826.0 million.
4
At
March 31, 2008, PSE had available a $200.0 million receivables
securitization facility that expires in December 2010. $85.0
million was outstanding under the receivables securitization facility at
March 31, 2008 thus leaving $115.0 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 March 31, 2008:
Non-qualified pension and other benefits funding and
payments
39.9
4.1
8.1
8.0
19.7
Other obligations
18.2
18.2
--
--
--
Total
contractual cash obligations
$
14,012.8
$
1,568.8
$
2,920.5
$
1,868.7
$
7,654.8
Puget
Sound Energy
Amount
of Commitment
Expiration
Per Period
Commercial
Commitments
(Dollars
in Millions)
Total
2008
2009-
2010
2011-
2012
2013
& Thereafter
Credit
agreement - available 2
$
826.0
$
--
$
--
$
--
$
826.0
Receivable
securitization facility 3
115.0
--
--
115.0
--
Energy
operations letter of credit
7.4
7.4
--
--
--
Total
commercial commitments
$
948.4
$
7.4
$
--
$
115.0
$
826.0
________________
1
See
note 1 under Puget Energy above.
2
See
note 3 under Puget Energy above.
3
See
note 4 under Puget Energy above.
Off-Balance
Sheet Arrangements
Fredonia 3 and 4 Operating
Lease. PSE
leases two combustion turbines for its Fredonia 3 and 4 electric generating
facility pursuant to a master operating lease that was amended for this purpose
in April 2001. The lease has a term expiring in 2011, but can be
canceled by PSE at any time. Payments under the lease vary with
changes in the London Interbank Offered Rate (LIBOR). At March 31,2008, PSE’s outstanding balance under the lease was $47.6
million. The expected residual value under the lease is the lesser of
$37.4 million or 60.0% of the cost of the equipment. In the event the
equipment is sold to a third party upon termination of the lease and the
aggregate sales proceeds are less than the unamortized value of the equipment,
PSE would be required to pay the lessor contingent rent in an amount equal to
the deficiency up to a maximum of 87.0% of the unamortized value of the
equipment.
Utility
Construction Program
PSE’s
construction programs for generating facilities, the electric transmission
system and the natural gas and electric distribution systems are designed to
meet continuing customer growth and to support reliable energy
delivery. The cash flow construction expenditures, excluding equity
Allowance for Funds Used During Construction (AFUDC) and customer refundable
contributions was $125.5 million for the three months ended March 31,2008. The anticipated utility construction expenditures, excluding
AFUDC, for 2008, 2009 and 2010 are:
Capital
Expenditure Estimates
(Dollars
in Millions)
2008
2009
2010
Energy
delivery, technology and facilities
$
595.0
$
568.0
$
743.0
New
supply resources
72.0
220.0
514.0
Total
expenditures
$
667.0
$
788.0
$
1,257.0
The
proposed utility construction expenditures and any new generation resource
expenditures that may be incurred are anticipated to be funded with a
combination of cash from operations, short-term debt, long-term debt and
equity. Construction expenditure estimates, including 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 three months ended March 31, 2008 was $334.6
million, which is 238.0% of the $140.6 million cash used for utility
construction expenditures and other capital expenditures. For the
three months ended March 31, 2007, cash from operations was $228.4 million,
which was 91.8% of the $248.7 million cash used for utility construction
expenditures and other capital expenditures.
The
overall cash generated from operating activities for the three months ended
March 31, 2008 increased $106.2 million as compared to the same period in
2007. The increase was primarily the result of lower cash payments of
$77.3 million related to accounts payable and lower cash payments of $16.6
million related to deferred storm damage costs. Cash from operations
increased due to the receipt of $42.4 million for an income tax refund and a
$11.0 million increase in deferred income taxes for 2008. Cash from
operations also increased due to $11.5 million increase in recovery of materials
and supplies, and fuel and gas inventories for the three months end March 31,2008 as compared to the same period in 2007. The increase in cash
from operations was also positively impacted by lower payments of $7.2 million
in 2008 as compare to 2007 related to the Residential Exchange Program and a
$5.0 million decrease in prepayments. These increases were partially
offset by a reduction in the purchased gas liability in 2008 of $9.4 million as
compared to an increase in the purchased gas liability in 2007 of $43.7 million
which accounted for a decrease in cash of $53.1 million. In addition,
the increase was offset by lower amount of cash collected from accounts
receivable of $23.9 million.
Financing
Program
Financing
utility construction requirements and operational needs are dependent upon the
cost and availability of external funds through capital markets and from
financial institutions. Access to funds depends upon factors such as
general economic conditions, regulatory authorizations and policies and Puget
Energy’s and PSE’s credit ratings.
Restrictive
Covenants
In
determining the type and amount of future financing, PSE may be limited by
restrictions contained in its electric and natural gas mortgage indentures,
restated articles of incorporation and certain loan agreements. Under
the most restrictive tests, at March 31, 2008, PSE could issue:
·
approximately
$592.0 million of additional first mortgage bonds under PSE’s electric
mortgage indenture based on approximately $986.7 million of electric
bondable property available for issuance, subject to an interest coverage
ratio limitation of 2.0 times net earnings available for interest (as
defined in the electric utility mortgage), which PSE exceeded at March 31,2008;
·
approximately
$507.0 million of additional first mortgage bonds under PSE’s natural gas
mortgage indenture based on approximately $845.0 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 natural gas utility mortgage), which PSE
exceeded at March 31, 2008;
·
approximately
$1.1 billion of additional preferred stock at an assumed dividend rate of
8.5%; and
·
approximately
$779.1 million of unsecured long-term
debt.
At March31, 2008, PSE had approximately $4.7 billion in electric and natural gas
ratebase to support the interest coverage ratio limitation test for net earnings
available for interest.
Credit
Ratings
Neither
Puget Energy nor PSE has any debt outstanding that would accelerate debt
maturity upon a credit rating downgrade. 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 April 25, 2008, were as
follows:
Ratings
Standard & Poor’s1,2
Moody’s3
Puget
Sound Energy
Corporate
credit/issuer rating
BBB-
Baa3
Senior
secured debt
BBB+
Baa2
Junior
subordinated notes
BB
Ba1
Preferred
stock
BB
Ba2
Commercial
paper
A-3
P-2
Revolving
credit facility
Note
1
Baa3
Ratings
outlook
Note
2
Note
3
Puget
Energy
Corporate
credit/issuer rating
BBB-
Ba1
Ratings
outlook
Note
2
Note
3
_______________
1
Standard
& Poor’s does not rate PSE’s credit
facilities.
2
On
October 26, 2007, Standard & Poor’s placed the ratings of Puget Energy
(BBB-) and PSE (BBB-/A-3) on CreditWatch with negative
implications. The CreditWatch listing reflects the possibility
that debt ratings for Puget Energy could be lowered dependent on the final
outcome of regulatory approval proceedings.
3
On
October 29, 2007, Moody’s placed the Ba1 Issuer rating of Puget Energy on
review for possible downgrade. Moody’s also affirmed the
long-term ratings of PSE and changed its rating outlook to stable from
positive. On this same date, Moody’s placed PSE’s P-2
short-term rating for commercial paper under review for possible
downgrade.
Shelf
Registrations, Long-Term Debt and Common Stock Activity
Liquidity
Facilities and Commercial Paper
PSE’s
short-term borrowings and sales of commercial paper are used to provide working
capital to fund utility construction programs. PSE has not been
significantly impacted by the current credit environment.
PSE
Credit Facilities
The
Company has three committed credit facilities that provide, in aggregate, $1.05
billion in short-term borrowing capability. These include a $500.0
million credit agreement, a $200.0 million accounts receivable securitization
facility and a $350.0 million credit agreement to support hedging
activity.
Credit
Agreements. In March 2007, PSE entered into a five-year,
$350.0 million credit agreement with a group of banks. The agreement
is used to support the Company’s energy hedging activities and may also be used
to provide letters of credit. The interest rate on outstanding
borrowings is based either on the agent bank’s prime rate or on LIBOR plus a
marginal rate related to PSE’s long-term credit rating at the time of
borrowing. PSE pays a commitment fee on any unused portion of the
credit agreement also related to long-term credit ratings of PSE. At
March 31, 2008, 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 March31, 2008, there was $7.4 million outstanding under four letters of credit and
$16.6 million commercial paper outstanding, effectively reducing the available
borrowing capacity under the two credit agreements to $826.0
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 were $85.0 million in loans that were
secured by accounts receivable pledged at March 31, 2008. The
remaining borrowing base of eligible receivables at March 31, 2008 was $115.0
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, a PSE subsidiary. At March 31, 2008, the outstanding balance
of the Note was $30.0 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 did not issue common
stock under the Stock Purchase and Dividend Reinvestment Plan for the three
months ended March 31, 2008 as compared to $3.2 million (130,896 shares) for the
three months ended March 31, 2007. The proceeds from sales of stock
under the Stock Purchase and Dividend Reinvestment Plan are used for general
corporate needs. Pending the outcome of the merger, Puget Energy does
not intend to fund the Stock Purchase and Dividend Reimbursement Plan with
authorized but unissued shares.
Common
Stock Offering Programs
To
provide additional financing options, Puget Energy entered into agreements in
July 2003 with two financial institutions under which Puget Energy may offer and
sell shares of its common stock from time to time through these institutions as
sales agents, or as principals. Sales of the common stock, if any,
may be made by means of negotiated transactions or in transactions that may be
deemed to be “at-the-market” offerings as defined in Rule 415 promulgated under
the Securities Act of 1933, including in ordinary brokers’ transactions on the
New York Stock Exchange at market prices.
Other
Regulation
and Rates
In
November 2007, PSE was audited by the Western Electricity Coordinating Council
(WECC) under delegated authority of the North American Electric Reliability
Corporation (NERC), the FERC-certified Electric Reliability Organization
(ERO). Previously, PSE had submitted several self-reports and
mitigation plans to WECC for review and approval. The WECC audit team
identified four additional potential violations that were not previously
self-reported. In response, PSE submitted self-reports and mitigation
plans for the four violations. WECC issued the final audit report on
March 28, 2008. As of April 16, 2008, PSE had not received notice of
penalties, but has established a loss reserve $0.6 million related to these
potential violations.
In May
2007, the Washington Commission Staff alleged that PSE’s natural gas system
service provider had violated certain Washington Commission recordkeeping
rules. The Washington Commission filed a complaint against PSE that
included Washington Commission Staff’s recommendation that PSE be assessed a
$2.0 million regulatory penalty. On April 3, 2008, the Washington
Commission issued an order approving a settlement agreement that requires PSE to
pay a regulatory penalty of $1.25 million, to establish a quality control
program to better monitor its subcontractors and to complete an independent
audit of natural gas system recordkeeping procedures. At March 31,2008, PSE adjusted its loss reserve to $1.25 million for this
penalty.
Accounting
Petition. On August 29, 2007, the Washington Commission
approved PSE’s accounting petition to defer as a regulatory asset the excess BPA
REP benefit provided to customers and accrue monthly carrying charges on the
deferred balance from June 7, 2007 until the deferral is recovered from
customers or BPA. As of March 31, 2008, PSE has recorded a regulatory
asset, including carrying costs, of $36.6 million.
On December 17, 2007, BPA released a
proposal for public comment which would provide temporary, interim relief to the
region’s investor-owned utilities until final REP contracts are reached and
executed which are planned to go into effect October 1, 2008. These
interim agreements are offered in exchange for suspension of certain litigation
activities and will be trued-up to the actual final REP benefits for each
individual company as established in BPA’s upcoming administrative
proceedings. In March 2008,
BPA and PSE signed an agreement pursuant to which BPA (on April 2, 2008) paid
PSE $53.7 million in REP benefits for fiscal year 2008, which payment is subject
to true-up depending upon the amount of any REP benefits ultimately determined
to be payable to PSE.
On April 10, 2008, the Washington
Commission approved PSE’s tariff filing seeking to pass-through the net amount
of the benefits under the interim agreements to residential and small farm
customers. The Washington Commission also approved PSE’s request to
credit the regulatory asset amount of $33.7 million against the $53.7 million
payment and pass-through to customers the remaining amount of approximately
$20.0 million. The accrued carrying charges on the regulatory asset
totaling $2.9 million at March 31, 2008 will be addressed in PSE’s pending
general rate case (Docket No. UE-072300).
Colstrip
Matters
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 (1) seepage from two different wastewater pond areas caused
groundwater contamination and threatened to contaminate domestic water wells and
the Colstrip water supply pond, and (2) seepage from the Colstrip water supply
pond caused structural damage to buildings and toxic mold. Plaintiffs
were seeking compensatory (including but not limited to unjust enrichment and
abatement) and punitive damages. After a failed attempt at settlement
in 2004, PSE established a reserve of approximately $0.7 million, of which $0.5
million was for PSE’s share of costs to extend city water to 13 plaintiffs and
PSE reduced its reserve to approximately $0.2 million. Discovery was
completed and trial was scheduled for June 2008.
Recent developments in the litigation have caused PSE to change its
reserve. On February 15, 2008, plaintiffs submitted supplemental
expert disclosures which, among other things, alleged new abatement claims
significantly higher than prior allegations. On April 11, 2008 the
trial court judge issued an order denying defendant’s motion to dismiss
plaintiffs’ substantial unjust enrichment claims. On April 22, 2008
the trial court judge issued an order that PSE along with two other defendants
would be held liable on all counts, including a finding of malice for punitive
damages, as a discovery sanction. Although the defendants
submitted a motion for reconsideration of this sanction on April 25, 2008, the
defendants reached agreement on a global settlement with all plaintiffs on April29, 2008 and PSE’s share of that settlement is approximately $10.7
million. PSE expects settlement documents to be finalized in the
second quarter 2008 and as a result have increased the reserve to $10.7
million. PSE is also evaluating whether it will file an accounting
petition to defer such costs.
The
Minerals Management Service of the United States Department of Interior
(MMS) has issued a series of orders to Western Energy Company (WECO) to pay
additional taxes and royalties concerning coal WECO sold to the owners of
Colstrip 3 & 4, and similar orders have been issued in the administrative
appellate process. The orders assert that additional royalties are
owed in connection with payments received by WECO from Colstrip 3
& 4 owners (including PSE) for the construction and operation of a
conveyor system that runs several miles from the mine to Colstrip 3 &
4. The state of Montana has also issued a demand to WECO consistent
with the MMS position. WECO has challenged these orders, and the
issue has been on appeal for several years. WECO has won
some points during the appellate process that have reduced the claims--but under
applicable law, to pursue the appeals, the principal in dispute cannot be paid,
which causes interest to accrue. Moreover, because the conveyor
system continues to be used, the amount in
dispute grows. In the aggregate, the accrued
interest--plus unasserted claims to bring the amount
current--could make the total claim (principal plus interest) pertaining to
PSE’s 25% project share as high as $10 million. PSE is unable to
predict the ultimate outcome of this dispute. PSE believes a future loss
in connection with this dispute is reasonably possible but not probable, and has
not recorded a loss reserve.
Proceedings
Relating to the Western Power Market
Puget
Energy’s and PSE’s Annual Report on Form 10-K for the year ended December 31,2007 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 that 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.
Lockyer Case. In
March and April 2008, FERC issued orders establishing procedures for the Lockyer
remand. The orders commence a seller-by-seller inquiry into the
transaction reports filed by entities that sold power in California during
2000. The inquiry is to determine if the transaction reports as filed
masked the gathering of more than 20% of the market during the period, by that
seller. PSE is confident that it will not be found to have possessed
20% of any relevant market during any relevant time. The order also
mandates a settlement process before an Administrative Law Judge. The
California parties sought rehearing of these orders on April 21,2008;
California Receivable and California
Refund Proceeding. On March 18, 2008, the California
Independent Systems Operator (CAISO) filed a status report with its calculations
of interest owed by and owing to parties. The report also identified
further work to perform in the CAISO’s “who owes what to whom”
calculation. On March 25, 2008, FERC issued an order addressing,
among other things, 11 pending rehearing requests by the California parties—all
of which the order rejected.
Proceeding
Relating to the Proposed Merger
On
October 26, 2007 and November 2, 2007, two separate lawsuits were
filed against the Company and all of the members of the Company’s Board of
Directors in Superior Court in King County, Washington. The lawsuits,
respectively, are entitled, Tansey v. Puget Energy, Inc.,
et al., Case No. 07-2-34315-6 SEA and Alaska Ironworkers Pension Trust v.
Puget Energy, Inc., et al., Case No. 07-2-35346-1
SEA. The lawsuits are both denominated as class actions purportedly
on behalf of Puget Energy’s shareholders and assert substantially similar
allegations and causes of action relating to the proposed merger. The
complaints allege that Puget Energy’s directors breached their fiduciary duties
in connection with the merger and seek virtually identical relief, including an
order enjoining the consummation of the merger. Pursuant to a court
order dated November 26, 2007, the two cases were consolidated for all
purposes and entitled In re
Puget Energy, Inc. Shareholder Litigation, Case No. 07-2-34315-6
SEA.
On
February 6, 2008, the parties entered into a memorandum of understanding
providing for the settlement of the consolidated lawsuit, subject to customary
conditions including completion of appropriate settlement documentation,
confirmatory discovery and court approval. Pursuant to the memorandum
of understanding, the Company agreed to include certain additional disclosures
in its proxy statement relating to the merger. The Company does not
admit, however, that its prior disclosures were in any way materially misleading
or inadequate. In addition, the Company and the other defendants in
the consolidated lawsuit deny the plaintiffs’ allegations of wrongdoing and
violation of law in connection with the merger. The settlement, if
completed and approved by the court, will result in dismissal with prejudice and
release of all claims of the plaintiffs and settlement class of the Company’s
shareholders that were or could have been brought on behalf of the plaintiffs
and the settlement class. In connection with such settlement, the
plaintiffs intend to seek a court-approved award of attorneys’ fees and expenses
in an amount up to $290,000, which the Company has agreed to pay. At
March 31, 2008, the Company has a loss reserve of $290,000 recorded at March 31,2008 related to this matter.
New
Accounting Pronouncements
On
September 15, 2006, FASB issued Statement of Financial Accounting Standards No.
157, “Fair Value Measurements” (SFAS No. 157), which clarifies how companies
should use fair value measurements in accordance with GAAP for recognition and
disclosure purposes. SFAS No. 157 establishes a common definition of
fair value and a framework for measuring fair value under GAAP, along with
expanding disclosures about fair value to eliminate differences in current
practice that exist in measuring fair value under the existing accounting
standards. The definition of fair value in SFAS No. 157 retains the
notion of exchange price; however, it focuses on the price that would be
received to sell the asset or paid to transfer a liability (i.e. an exit price),
rather than the price that would be paid to acquire the asset or received to
assume the liability (i.e. an entrance price). Under SFAS No. 157, a
fair value measure should reflect all of the assumptions that market
participants would use in pricing the asset or liability, including assumptions
about the risk inherent in a particular valuation technique, the effect of a
restriction on the sale or use of an asset and the risk of
nonperformance. To increase consistency and comparability in fair
value measures, SFAS No. 157 establishes a three-level fair value hierarchy to
prioritize the inputs used in valuation techniques between observable inputs
that reflect quoted market prices in active markets, inputs other than quoted
prices with observable market data and unobservable data (e.g., a company’s own
data).
SFAS No.
157 is effective for fiscal years beginning after November 15, 2007, which was
January 1, 2008, for the Company. On February 28, 2008, the FASB
issued a final FASB Staff Position (FSP) that partially deferred the effective
date of SFAS No. 157 for one year for non-financial assets and non-financial
liabilities that are recognized or disclosed at fair value, except for those
that are recognized or disclosed at fair value on an annual or more frequent
basis. The Company adopted SFAS No. 157 on January 1, 2008,
prospectively, as required by SFAS No. 157, with certain
exceptions, including the initial impact of changes in fair value
measurements of existing derivative financial instruments measured initially
using the transaction price under Emerging Issues Task Force (EITF) Issue No.
02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading
Purposes and Contracts Involved in Energy Trading and Risk Management
Activities” (EITF 02-3). On January 1, 2008, the difference between
the carrying amounts and the fair values of those instruments originally
recorded under guidance in EITF 02-3 was recognized as a cumulative-effect
adjustment to the opening balance of retained earnings. SFAS No. 157
nullified a portion of EITF 02-3. Under EITF 02-3, the transaction price
presumption prohibited recognition of a trading profit at inception of a
derivative unless the positive fair value of that derivative was substantially
based on quoted prices or a valuation process incorporating observable
inputs. For transactions that did not meet this criterion at
inception, trading profits that had been deferred were recognized in the period
that inputs to value the derivative became observable or when the contract
performed. SFAS No. 157 nullified this portion of EITF 02-3.
On March19, 2008, FASB issued SFAS No. 161, “Disclosures about Derivative Instruments
and Hedging Activities – An Amendment of FASB Statement No. 133” (SFAS No.
161). SFAS No. 161 is effective for the fiscal years and interim
years beginning after November 15, 2008, which will be the quarter ended March31, 2009 for the Company. SFAS No. 161 requires companies with
derivative instruments to disclose information that should enable financial
statement users to understand how and why a company uses derivative instruments,
how derivative instruments and related hedged items are accounted for under SFAS
No. 133 and how derivative instruments and related hedged items affect a
company’s financial position, financial performance and cash
flows. SFAS No. 161 requirements will impact the following derivative
and hedging disclosures: objectives and strategies, balance sheet, financial
performance, contingent features and counterparty credit risk. The
Company is currently assessing the impact of SFAS No. 161.
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 natural gas and electric portfolios. It
is not engaged in the business of assuming risk for the purpose of speculative
trading. The Company hedges open natural gas and electric positions
to reduce both the portfolio risk and the volatility risk in
prices. The exposure position is determined by using a probabilistic
risk system that models 100 scenarios of how the Company’s natural gas and power
portfolios will perform under various weather, hydro and unit performance
conditions. The objectives of the hedging strategy are
to:
·
Ensure
physical energy supplies are available to reliably and cost-effectively
serve retail load;
·
Manage
energy portfolio risks prudently to serve retail load at overall least
cost and limit undesired impacts on PSE’s customers and shareholders;
and
·
Reduce
power costs by extracting the value of the Company’s
assets.
The
following table presents electric derivatives that are designated as cash flow
hedges or contracts that do not meet Normal Purchase Normal Sale (NPNS) at March31, 2008 and December 31, 2007:
If it is
determined that it is uneconomical to operate PSE’s controlled electric
generating facilities in the future period, the fuel supply cash flow hedge
relationship is terminated and the hedge is de-designated which results in the
unrealized gains and losses associated with the contracts being recorded in the
income statement. As these contracts are settled, the costs are
recognized as energy costs and are included as part of the PCA
mechanism.
At December 31, 2007, the Company had an unrealized day one loss deferral of
$9.0 million related to a three-year locational power exchange contract which
was modeled and therefore the day one gain was deferred under EITF No.
02-3. The contract has economic benefit to the Company over its
terms. The locational exchange will help ease electric transmission
congestion across the Cascade Mountains during the winter months as PSE will
take delivery of energy at a location that interconnects with PSE’s transmission
system in western Washington. At the same time, PSE will make
available the quantities of power at the Mid-Columbia trading hub
location. The day one loss deferral was transferred to retained
earnings on January 1, 2008 as required by SFAS No. 157, “Fair Value
Measurements” and any future day one loss on contracts will be recorded in the
income statement beginning January 1, 2008 in accordance with the
statement.
The
following tables present the impact of changes in the market value of derivative
instruments not meeting NPNS or cash flow hedge criteria, and ineffectiveness
related to highly effective cash flow hedges, to the Company’s earnings during
the three months ended March 31, 2008 and March 31, 2007:
In the
first quarter 2007, the Company reversed a loss reserve due to credit worthiness
related to a physically delivered natural gas supply contract for electric
generation. The counterparty’s financial outlook had changed and
delivery was now probable through the life of the contract which expires June30, 2008.
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 March 31, 2008 and
December 31, 2007:
At March 31, 2008, the Company had total assets of $57.7 million and total
liabilities of $1.4 million related to hedges of natural gas contracts to serve
natural gas customers. All mark-to-market adjustments relating to the
natural gas business have been reclassified to a deferred account in accordance
with SFAS No. 71 due to the PGA mechanism. All increases and
decreases in the cost of natural gas supply are passed on to customers with the
PGA mechanism. As the gains and losses on the hedges are realized in
future periods, they will be recorded as natural gas costs under the PGA
mechanism.
A
hypothetical 10.0% decrease in the market prices of natural gas and electricity
would decrease the fair value of qualifying cash flow hedges by $43.5 million
after-tax, with a corresponding impact in comprehensive income and earnings (due
to ineffectiveness) of $42.7 million and $0.9 million, respectively, after-tax,
and would increase the fair value of those contracts marked-to-market in
earnings by $0.4 million after-tax.
Credit
Risk
The Company is exposed to
credit risk primarily through buying and selling electricity and natural gas to
serve customers. Credit risk is the potential loss resulting from a
counterparty’s non-performance under an agreement. The Company
manages credit risk with policies and procedures for, among other things,
counterparty analysis, exposure measurement, exposure monitoring and exposure
mitigation. The Company has entered into master netting arrangements
with counterparties when available to mitigate credit exposure to those
counterparties. The Company believes that entering into such
agreements reduces risk of settlement default for the ability to make only one
net payment.
It is possible that
extreme volatility in energy commodity prices could cause the Company to have
credit risk exposures with one or more counterparties. If such
counterparties fail to perform their obligations under one or more agreements,
the Company could suffer a material financial loss. However, as of
March 31, 2008, approximately 96% of the counterparties comprising the sources
of our energy portfolio are rated at least investment grade by the major rating
agencies. The Company assesses credit risk internally for
counterparties that are not rated.
Interest
Rate Risk
The
Company believes its interest rate risk primarily relates to the use of
short-term debt instruments, variable-rate notes and leases and anticipated
long-term debt financing needed to fund capital requirements. The
Company manages its interest rate risk through the issuance of mostly fixed-rate
debt of various maturities. The Company utilizes 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 March 31, 2008 was a net
loss of $8.1 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 March 31, 2008, 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 quarter
ended March 31, 2008 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 March 31, 2008, 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 quarter ended
March 31, 2008, 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 March 31,2008. 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.
There have been no material changes from the risk factors set forth in Part I,
Item 1A in the Company’s Annual Report on Form 10-K for the year ended December31, 2007.
Item
4. Submission
of Matters to a Vote of Security Holders
Puget Energy’s special meeting of shareholders was held on April 16,2008. At the special meeting, the shareholders approved by more than
two-thirds required vote a merger with the Consortium of North American
infrastructure investors. The vote on the proposals were as
follows:
Proposal
1: Approval of the Plan of Merger dated as of October 26, 2007
between Puget Energy, Puget Holdings LLC, Puget Intermediate Holdings Inc. and
Puget Merger Sub, Inc.
For
Against
Abstain
Broker
Non-Vote
101,640,757
2,362,394
1,408,869
--
Proposal 2: Approval to adjourn the special meeting to a later date,
if necessary, to permit solicitation of proxies.
In view of the pending merger with the Consortium, we have not established a
date for our 2008 annual meeting of shareholders. However, if, as may
become necessary, the annual meeting is held at some later time, we will inform
shareholders of the new date and the deadline for shareholders to submit
proposals that will be eligible for consideration for inclusion in our proxy
materials, which deadline will be a reasonable time before we begin to print and
send our proxy materials.
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
Statement
setting forth computation of ratios of earnings to fixed charges (2003
through 2007 and 12 months ended March 31, 2008) for Puget
Energy.
12.2
Statement
setting forth computation of ratios of earnings to fixed charges (2003
through 2007 and 12 months ended March 31, 2008) 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.
Dates Referenced Herein and Documents Incorporated by Reference
