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(Parenthetical)
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EQUITY Statement
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22: R9 Summary of Consolidation and Significant HTML 39K
Accounting Policy
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Activities
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33: R20 Insider Trading Arrangements HTML 26K
34: R21 Summary of Consolidation and Significant HTML 29K
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Proceeding (Tables)
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Accounting Policy - Allowance for Credit Loss
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Activities Narrative (Details)
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Activities Derivative Assets and Liabilities
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Activities Net Amount of Derivatives Reported in
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Activities Recognized in Statement of Income
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Activities Contractual Contingent Liability
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(Details)
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(Details)
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Obligation (Details)
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(Details)
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UNITED
STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM ii10-Q/
ii[X]/
QUARTERLY
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Securities
Registered pursuant to Section 12(b) of the Securities Exchange Act of 1934
Title of each class
Trading Symbol(s)
Name of each exchange on which registered
N/A
N/A
N/A
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 registrant was required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.
Puget Energy, Inc.
iYes
/X/
No
/ /
Puget
Sound Energy, Inc.
iYes
/X/
No
/ /
Indicate by check mark whether the registrants have submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).
Puget
Energy, Inc.
iYes
/X/
No
/ /
Puget Sound Energy, Inc.
iYes
/X/
No
/ /
Indicate
by check mark whether the registrants are a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer", "accelerated filer," a smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Puget
Energy, Inc.
Large accelerated filer
/ /
Accelerated filer
/ /
iNon-accelerated Filer
/X/
Smaller reporting company
i/ /
Emerging
growth company
i/ /
Puget Sound Energy, Inc.
Large accelerated filer
/ /
Accelerated filer
/ /
iNon-accelerated
Filer
/X/
Smaller reporting company
i/ /
Emerging growth company
i/ /
If
an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. / /
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
i/X/
Puget Sound Energy, Inc.
Yes
/ /
No
i/X/
All
of the outstanding shares of voting stock of Puget Energy, Inc. are held by Puget Equico LLC, an indirect wholly-owned subsidiary of Puget Holdings LLC. All of the outstanding shares of voting stock of Puget Sound Energy, Inc. are held by Puget Energy, Inc.
Earnings Before Interest, Tax, Depreciation and Amortization
FASB
Financial Accounting Standards Board
GAAP
U.S. Generally Accepted Accounting Principles
GHG
Greenhouse gas
GRC
General Rate Case
IBEW
International
Brotherhood of Electrical Workers
ISDA
International Swaps and Derivatives Association
LIBOR
London Interbank Offered Rate
LNG
Liquefied Natural Gas
MMBtu
One Million British Thermal Units
MWh
Megawatt Hour (one MWh equals one thousand kWh)
NAESB
North American Energy Standards Board
NPNS
Normal
Purchase Normal Sale
PCA
Power Cost Adjustment
PCORC
Power Cost Only Rate Case
PGA
Purchased Gas Adjustment
PTCs
Production Tax Credits
PSE
Puget Sound Energy, Inc.
Puget Energy
Puget Energy, Inc.
Puget Holdings
Puget
Holdings LLC
Puget LNG
Puget LNG, LLC
SERP
Supplemental Executive Retirement Plan
UA
The United Association of Journeymen and Apprentices of the Plumbing and Pipefitting Industry of the United States and Canada
Washington Commission
Washington Utilities and Transportation Commission
WSPP
WSPP, Inc.
3
FILING
FORMAT
This combined Quarterly Report on Form 10-Q is separately filed by Puget Energy, Inc. (Puget Energy) and Puget Sound Energy, Inc. (PSE). Information in this filing relating to PSE is filed by PSE on its own behalf. PSE makes no representation as to information relating to Puget Energy (except as it may relate to PSE) or any other affiliate or subsidiary of Puget Energy. Any references in this report to “the Company” are to Puget Energy and PSE collectively.
FORWARD-LOOKING STATEMENTS
Puget Energy and PSE include 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,”“continues,”“could,”“estimates,”“expects,”“future,”“intends,”“may,”“might,”“plans,”“potential,”“predicts,”“projects,”“should,”“will likely result,”“will continue” or similar expressions are intended to identify certain of these forward-looking statements and may be included in discussion of, among other things, our anticipated operating or financial performance, business plans and prospects, planned capital expenditures and other future expectations. In particular, these include statements relating to future actions, business
plans and prospects, future performance expenses, the outcome of contingencies, such as legal proceedings, government regulation and financial results.
Forward-looking statements reflect current expectations and involve risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed. 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 risks that could cause actual results or outcomes for Puget Energy and PSE to differ materially from past results and those discussed in the 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), that may affect our ability to recover costs and earn a reasonable return, including but not limited to disallowance or delays in the recovery of capital investments and operating costs and discretion over allowed return on investment;
●
Changes in, adoption of and compliance with laws and regulations, including decisions and policies concerning the environment, climate change, greenhouse gas or other emissions or by-products of electric generation (including coal ash or other substances), natural resources, and fish and wildlife (including the Endangered Species Act) as well as the risk of litigation arising from such matters, whether involving
public or private claimants or regulatory investigative or enforcement measures;
●
Changes in tax law, related regulations or differing interpretation, or enforcement of applicable law by the Internal Revenue Service (IRS) or other taxing jurisdiction; and PSE's ability to recover costs in a timely manner arising from such changes;
●
Inability to realize deferred tax assets and use production tax credits (PTCs) due to insufficient future taxable income;
●
Accidents or natural disasters, such as hurricanes, windstorms, earthquakes, floods, landslides,
fires and wildfires (either affecting or caused by PSE's facilities or infrastructure), extreme weather conditions and other acts of God, terrorism, asset-based or cyber-based attacks, pandemic or similar significant events, which can interrupt service and lead to lost revenue, cause temporary supply disruptions and/or price spikes in the cost of fuel and raw materials, impose extraordinary costs, and can subject the Company to liability;
●
Commodity price risks associated with procuring natural gas and power in wholesale markets from creditworthy counterparties;
●
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, adversely affect the availability of and access to capital and credit markets and/or impact delivery of energy to PSE from its 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, blackouts or large curtailments of transmission systems (whether PSE's or others'), or failure of the interstate natural gas pipeline delivering to PSE's system, all of which can affect PSE's ability to deliver power or natural gas to its customers and generating facilities;
●
Electric plant generation and transmission system 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 generation resource;
●
The
ability to restart generation following a regional transmission disruption;
●
The ability of a natural gas or electric plant to operate as intended;
●
PSE's resource adequacy needs to meet the Clean Energy Transformation Act (CETA) and the Climate Commitment Act (CCA) requirements, through a combination of owned or contracted resources, may significantly increase power and gas costs if pricing pressures and supply constraints on resource acquisitions increase;
●
Changes in climate, weather conditions, or sustained extreme weather
events in the Pacific Northwest, which could have effects on customer usage and PSE's revenue and expenses;
●
Regional or national weather, which could impact PSE's ability to procure adequate supplies of natural gas, fuel or purchased power to serve its customers and the cost of procuring such supplies;
●
Variable hydrological conditions, which can impact streamflow and PSE's ability to generate electricity from hydroelectric facilities;
●
Variable wind conditions, which can impact PSE's ability to generate electricity from wind facilities;
●
The
ability to renew contracts for electric and natural gas supply and the price of renewal;
●
Industrial, commercial and residential growth and demographic patterns in the service territories of PSE;
●
General economic conditions in the Pacific Northwest, such as inflation, which may impact customer consumption or affect PSE's accounts receivable;
●
The loss of significant customers, changes in the business of significant customers or the condemnation of PSE's facilities as a result of municipalization or other government action or negotiated settlement,
which may result in changes in demand for PSE's services;
●
The failure of information systems or the failure to secure information system data, which may impact the operations and cost of PSE's customer service, generation, distribution and transmission;
●
Opposition and social activism that may hinder PSE's ability to perform work or construct infrastructure;
●
Capital market conditions, including changes in the availability of capital and interest rate fluctuations;
●
Employee
workforce factors including strikes; work stoppages; retirements; absences due to pandemics, accidents, natural disasters or other significant, unforeseeable events; availability of qualified employees or the loss of a key executive;
●
PSE's service territory operates within a region of high demand for skilled workers resulting in significant competition and inflated wages, which puts pressure on PSE's ability to attract, retain and compensate employees;
●
The ability to obtain insurance coverage, the availability of insurance for certain specific losses, including those arising from catastrophic events such as wildfires and the cost of such insurance;
●
Changes
in Puget Energy's or PSE's credit ratings, which may have an adverse impact on the availability and cost of capital for Puget Energy or PSE generally;
●
Deteriorating values of the equity, fixed income and other markets which could significantly impact the value of investments of PSE's retirement plan, post-retirement medical benefit plan trusts and the funding of obligations thereunder; and
●
Recent laws proposed or passed by various municipalities in PSE's service territory, including Seattle, seek to reduce or eliminate the use of natural gas in various contexts, such as for space, cooking, and water heating in new commercial and multifamily buildings. Such laws may
impact operations due to costs and delays from incremental permitting and other requirements that are outside PSE's control.
Any forward-looking statement speaks only as of the date on which such statement is made, and, except as required by law, the Company undertakes 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. For further information, see Part I, Item 1A, “Risk Factors” in the Company's most
recent Annual Report on Form 10-K for the year ended December 31, 2022.
Adjustments
to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization
i560,480
i492,854
Conservation
amortization
i87,522
i81,080
Deferred
income taxes and tax credits, net
(i127,228)
(i40,216)
Net
unrealized (gain) loss on derivative instruments
i201,230
(i59,939)
AFUDC
- equity
(i28,516)
(i21,396)
Other
non-cash
(i19,190)
(i23,189)
Funding
of pension liability
(i18,000)
(i18,000)
Regulatory assets
and liabilities
i134,755
i11,210
Purchased
gas adjustment
i174,840
i8,509
GHG
emission allowances
(i112,037)
i—
Other
long term assets and liabilities
(i24,545)
(i8,034)
Change
in certain current assets and liabilities:
Accounts receivable and unbilled revenue
i368,054
i126,460
Materials
and supplies
(i20,219)
(i14,003)
Fuel
and natural gas inventory
(i4,372)
(i44,789)
Prepayments
and other
i8,256
i12,048
Accounts
payable
(i288,415)
(i37,990)
Taxes
payable
i27,100
(i17,743)
Other
i9,518
i14,055
Net
cash provided by (used in) operating activities
i971,636
i674,867
Investing
activities:
Construction expenditures - excluding equity AFUDC
(i875,139)
(i720,703)
Other
i14,020
(i580)
Net
cash provided by (used in) investing activities
(i861,119)
(i721,283)
Financing
activities:
Change in short-term debt, net
(i357,000)
(i38,000)
Dividends
paid
(i50,637)
(i20,432)
Investment from Parent
i100,000
i50,000
Proceeds
from long-term debt and bonds issued
i396,488
i—
Other
i16,457
i15,796
Net
cash provided by (used in) financing activities
i105,308
i7,364
Net
increase (decrease) in cash, cash equivalents, and restricted cash
i215,825
(i39,052)
Cash,
cash equivalents, and restricted cash at beginning of period
i165,885
i96,247
Cash,
cash equivalents, and restricted cash at end of period
$
i381,710
$
i57,195
Supplemental
cash flow information:
Cash payments for interest (net of capitalized interest)
$
i172,869
$
i167,099
Cash
payments (refunds) for income taxes
i84,357
i75,100
Non-cash
financing and investing activities:
Accounts payable for capital expenditures eliminated from cash flows
$
i71,198
$
i70,610
The
accompanying notes are an integral part of the financial statements.
14
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
(1)iSummary
of Consolidation and Significant Accounting Policy
Basis of Presentation
Puget Energy is an energy services holding company that owns PSE. PSE is a public utility incorporated in the state of Washington that furnishes electric and natural gas services in a territory covering approximately i6,000 square miles, primarily in the Puget Sound region. Puget Energy also has a wholly-owned non-regulated subsidiary, Puget LNG, LLC (Puget LNG), which has the sole purpose of owning, developing and financing
the non-regulated activity of the Tacoma liquefied natural gas (LNG) facility. PSE and Puget LNG are considered related parties with similar ownership by Puget Energy. Therefore, capital and operating costs that are incurred by PSE and allocated to Puget LNG are related party transactions by nature.
In 2009, Puget Holdings, LLC (Puget Holdings), owned by a consortium of long-term infrastructure investors, completed its merger with Puget Energy (the merger). As a result of the merger, all of Puget Energy’s common stock is indirectly owned by Puget Holdings. The acquisition of Puget Energy was accounted for in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 805, “Business Combinations” (ASC 805) as of the date of the merger. ASC 805 requires the acquirer to recognize and measure identifiable assets acquired and liabilities assumed at fair value as of the merger
date.
The consolidated financial statements of Puget Energy reflect the accounts of Puget Energy and its subsidiaries. PSE’s consolidated financial statements include the accounts of PSE and its subsidiary. 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. PSE’s consolidated financial statements continue to be accounted for on a historical basis and do not include any ASC 805 purchase accounting adjustments. The preparation of financial statements in conformity with U.S. 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 revenue and expenses
during the reporting period. Actual results could differ from those estimates.
Greenhouse Gas Emission Allowances
PSE is required to obtain emission allowances or offset credits for greenhouse gas (GHG) emissions associated with electricity it generates or imports into Washington State and natural gas supplied to customers in accordance with the cap-and- invest program included in the Climate Commitment Act (CCA). PSE records allocated and purchased emission allowances at cost, similar to an inventory method and includes purchased emissions allowances in current assets and long-term assets reported in the "GHG emission allowances" line item on the consolidated balance sheets. PSE measures the compliance obligation at the weighted average cost of allowances held plus the fair value of additional allowances required to satisfy the obligation
after adjustment for applicable no-cost allowances received. PSE includes the obligation in current liabilities and long-term liabilities reported in the "Compliance obligations" line item on the consolidated balance sheets based on the dates the allowances are to be surrendered. Consistent with ASC 980, PSE defers costs and revenues associated with the cap-and-invest program through regulatory assets and liabilities.
Allowance for Credit Losses
The Company measures expected credit losses on trade receivables on a collective basis by receivable type, which include electric retail receivables, natural gas retail receivables, and electric wholesale receivables. The estimate of expected credit losses considers historical credit loss information that is adjusted for current conditions and reasonable and supportable forecasts.
15
i
The
following table presents the activity in the allowance for credit losses for accounts receivable for the nine months ended September 30, 2023 and 2022:
Puget Energy and Puget Sound Energy
Nine Months Ended September 30,
(Dollars in Thousands)
2023
2022
Allowance
for credit losses:
Beginning balance
$
i41,962
$
i34,958
Provision
for credit loss expense
i23,550
i18,874
Receivables
charged-off
(i29,005)
(i14,500)
Total
ending allowance balance
$
i36,507
$
i39,332
/
Tacoma
LNG Facility
In February 2022, the Tacoma LNG facility at the Port of Tacoma completed commissioning and commenced commercial operations. The Tacoma LNG facility provides peak-shaving services to PSE's natural gas customers, and provides LNG as fuel to transportation customers, mainly the marine market. In 2019, the Puget Sound Clean Air Agency issued the air quality permit for the facility, and the Pollution Hearings Control Board of Washington State upheld the approval following extended litigation. This decision was appealed with the Pierce County Superior Court by the Puyallup Tribe of Indians and nonprofit law firm Earthjustice and the case was granted direct review by the Pierce County Court of Appeals Division II where it is currently pending.
Pursuant to an order by the Washington Commission, PSE will be allocated approximately i43.0%
of common capital and operating costs, consistent with the regulated portion of the Tacoma LNG facility. The remaining i57.0% of common capital and operating costs of the Tacoma LNG facility will be allocated to Puget LNG. Per this allocation of costs, $i241.8 million
and $i249.1 million of non-utility plant operating cost is reported in the Puget Energy "Other property and investments" line item as of September 30, 2023 and December 31, 2022, respectively. Additionally, $i20.3 million
and $i7.8 million of operating costs are reported in the Puget Energy "Non-utility expense and other" financial statement line item for the nine months ended September 30, 2023, and September 30, 2022, respectively. Further, $i236.9 million
and $i245.7 million of natural gas plant related to PSE’s portion of the Tacoma LNG facility is reported in the PSE “Utility plant - Natural gas plant” financial statement line item as of September 30, 2023 and December 31, 2022, respectively, as PSE is a regulated entity.
Variable Interest Entities
In April 2017, PSE entered into a power purchase agreement (PPA) with Skookumchuck
Wind Energy Project, LLC (Skookumchuck) pursuant to which Skookumchuck would develop a wind generation facility and sell bundled energy and associated attributes, namely renewable energy certificates (RECs), to PSE over a term of i20 years. Skookumchuck commenced commercial operation in November 2020. In May 2020, PSE entered into a PPA with Golden Hills Wind Farm, LLC (Golden Hills) pursuant to which Golden Hills would develop a wind generation facility and sell bundled energy and associated attributes, namely RECs, to PSE over a term of i20
years. On April 29, 2022, Golden Hills commenced commercial operations. In February 2021, PSE entered into a PPA with Clearwater Wind Project, LLC (Clearwater) in which Clearwater would develop a wind generation facility and sell energy and associated attributes to PSE over a term of i25 years. On November 8, 2022, Clearwater commenced commercial operations. For each of the aforementioned PPAs, PSE has ino
equity investment in the generation facilities, but is the only customer of each facility. PSE has concluded that Skookumchuck, Golden Hills, and Clearwater represent variable interest entities (VIE) and that PSE is not the primary beneficiary of these VIEs since it does not control the commercial and operating activities of the facilities. Additionally, PSE does not have the obligation to absorb losses or receive benefits. As a result, PSE does not consolidate the VIEs.
Purchased energy of $i64.2 million
and $i20.6 million were recognized in purchased electricity on the Company's consolidated statements of income for the nine months ended September 30, 2023 and September 30, 2022, respectively. Additionally, $i10.9 million
and $i3.9 million were included in accounts payable on the Company's balance sheet as of September 30, 2023 and December 31, 2022, respectively.
(2) iNew
Accounting Pronouncements
Reference Rate Reform
In March 2020, the FASB issued Accounting Standards Update (ASU) 2020-04, "Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting”. ASU 2020-04 provides temporary optional
16
expedients and exceptions to the current guidance on contract modifications to ease the financial reporting burdens related to the expected market transition from London Interbank Offered Rate (LIBOR) and other interbank offered rates to alternative reference rates. In December 2022, the FASB issued ASU 2022-06,
"Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848". ASU 2022-06 postpones the sunset date of Topic 848 from December 31, 2022 to December 31, 2024. As of September 30, 2023, the Company is not aware of any current agreements that reference LIBOR and thus, has not utilized any practical expedients. The Company continues to assess other agreements to determine if LIBOR is included and if the expedients would be utilized through the allowed period of December 2024.
(3) iRevenue
i
The
following tables present disaggregated revenue from contracts with customers, and other revenue by major source for the three months ended September 30, 2023 and September 30, 2022:
1Other
includes $i9.4 million of Puget LNG revenues recorded at Puget Energy.
/
2Total other revenue includes revenues from derivatives and alternative revenue programs that are not considered revenues from contracts with customers.
1 Other
includes $i0.5 million of Puget LNG revenues recorded at Puget Energy.
2 Total other revenue includes revenues from derivatives and alternative revenue programs that are not considered revenues from contracts with customers.
17
The following
tables present disaggregated revenue from contracts with customers, and other revenue by major source for the nine months ended September 30, 2023 and September 30, 2022:
1
Other includes $i20.7 million of Puget LNG revenues recorded at Puget Energy.
2 Total other revenue includes revenues from derivatives and alternative revenue programs that are not considered revenues from contracts with customers.
1
Other includes $i0.6 million of Puget LNG revenues recorded at Puget Energy.
2 Total other revenue includes revenues from derivatives and alternative revenue programs that are not considered revenues from contracts with customers.
18
Transaction
Price Allocated to Remaining Performance Obligations
In December 2020, Puget LNG entered into a contract with one customer where Puget LNG is selling LNG over a i10-year delivery period beginning April 2024. The contract requires the customer to purchase a minimum annual quantity even if the customer does not take delivery. The price of the LNG includes a fixed charge, a fuel charge that includes both a market index and fixed margin component and other variable consideration. The fixed transaction price is allocated to the remaining performance obligations which is determined by the fixed charge components multiplied by the outstanding minimum annual
quantity. iBased on management’s best estimate of commencement, the Company expects to recognize this revenue over the following time periods:
Puget
Energy
(Dollars in Thousands)
2024
2025
2026
2027
2028
Thereafter
Total
Remaining
performance obligations
$
i15,359
$
i19,710
$
i19,454
$
i19,454
$
i19,454
$
i102,135
$
i195,566
The
Company has elected the optional exemption in ASC 606, "Revenues from Contracts with Customers", under which the Company does not disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. The primary sources of variability are (a) fluctuations in market index prices of natural gas used to determine aspects of variable pricing and (b) variation in volumes that may be delivered to the customer. Both sources of variability are expected to be resolved at or shortly before delivery of each unit of LNG or natural gas. As each unit of LNG or natural gas represents a separate performance obligation, future volumes are wholly unsatisfied.
(4) iAccounting
for Derivative Instruments and Hedging Activities
PSE employs various energy portfolio optimization strategies but is not in the business of assuming risk for the purpose of realizing speculative trading revenue. The nature of serving regulated electric customers with its portfolio of owned and contracted electric generation resources exposes PSE and its customers to some volumetric and commodity price risks within the sharing mechanism of the Power Cost Adjustment. Therefore, wholesale market transactions and PSE's related hedging strategies are focused on reducing costs and risks where feasible, thus reducing volatility in costs in the portfolio. In order to manage its exposure to the variability in future cash flows for forecasted energy transactions, PSE utilizes a programmatic hedging strategy, which extends out ithree
years. PSE's hedging strategy includes a risk-responsive component for the core natural gas portfolio, which utilizes quantitative risk-based measures with defined objectives to balance both portfolio risk and hedge costs.
PSE's energy risk portfolio management function monitors and manages these risks using analytical models and tools. In order to manage risks effectively, PSE enters into forward physical electric and natural gas purchase and sale agreements, fixed-for-floating swap contracts, and commodity call/put options. Currently, the Company does not apply cash flow hedge accounting and therefore records all mark-to-market gains or losses through earnings.
The Company manages its interest rate risk through the issuance of mostly fixed-rate debt with varied maturities. The Company utilizes internal cash from operations, borrowings under its commercial paper program
and its credit facilities to meet short-term funding needs. The Company may enter into swap instruments or other financial hedge instruments to manage the interest rate risk associated with these debts.
19
i
The following table presents the volumes, fair values and classification of the Company's derivative instruments recorded on the balance sheets:
1 Balance
sheet classification: Current and Long-term Unrealized gain on derivative instruments.
2 Balance sheet classification: Current and Long-term Unrealized loss on derivative instruments.
3 All fair value adjustments on derivatives relating to the natural gas business have been deferred in accordance with ASC 980, “Regulated Operations,” due to the purchased gas adjustment (PGA) mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers.
* Electric portfolio derivatives consist of electric generation fuel of i320.0 million
British Thermal Units (MMBtu) and purchased electricity of i2.9 million Megawatt hours (MWhs) at September 30, 2023, and i234.9 million MMBtus and i5.3 million
MWhs at December 31, 2022.
/
It is the Company's policy to record all derivative transactions on a gross basis at the contract level without offsetting assets or liabilities. The Company generally enters into transactions using the following master agreements: WSPP, Inc. (WSPP) agreements, which standardize physical power contracts; International Swaps and Derivatives Association (ISDA) agreements, which standardize financial natural gas and electric contracts; and North American Energy Standards Board (NAESB) agreements, which standardize physical natural gas contracts. The Company believes that such agreements reduce credit risk exposure because
such agreements provide for the netting and offsetting of monthly payments as well as the right of set-off in the event of counterparty default. The set-off provision can be used as a final settlement of accounts which extinguishes the mutual debts owed between the parties in exchange for a new net amount. For further details regarding the fair value of derivative instruments, see Note 5, "Fair Value Measurements," in the Combined Notes to Consolidated Financial Statements included in Item 1 of this report.
20
i
The
following tables present the potential effect of netting arrangements, including rights of set-off associated with the Company's derivative assets and liabilities:
Gross Amount Recognized in the Statement of Financial Position1
Gross Amounts Offset in the Statement of Financial Position
Net of Amounts Presented in the Statement of Financial Position
Gross Amounts Not Offset in the Statement of Financial Position
(Dollars
in Thousands)
Commodity Contracts
Cash Collateral Received/Posted
Net Amount
Assets:
Energy derivative contracts
$
i681,650
$
i—
$
i681,650
$
(i125,334)
$
i—
$
i556,316
Liabilities:
Energy
derivative contracts
$
i143,342
$
i—
$
i143,342
$
(i125,334)
$
(i5,661)
$
i12,347
_______________
/
1
All derivative contract deals are executed under ISDA, NAESB, and WSPP master agreements with right of set-off.
i
The following table presents the effect and classification of the realized and unrealized gains (losses) of the Company's derivatives recorded on the statements of income:
Puget
Energy and Puget Sound Energy
Three Months Ended September 30,
Nine Months Ended September 30,
(Dollars in Thousands)
Classification
2023
2022
2023
2022
Gas for power derivatives:
Unrealized
Unrealized
gain (loss) on derivative instruments, net
$
i38,966
$
(i28,197)
$
(i75,373)
$
i42,094
Realized
Electric
generation fuel
(i23,442)
i73,723
i51,253
i116,853
Power
derivatives:
Unrealized
Unrealized gain (loss) on derivative instruments, net
(i17,271)
(i34,512)
(i125,857)
i17,845
Realized
Purchased
electricity
i25,076
i4,398
i72,208
i11,443
Total
gain (loss) recognized in income on derivatives
$
i23,329
$
i15,412
$
(i77,769)
$
i188,235
/
21
The
Company is exposed to credit risk primarily through buying and selling electricity and natural gas to serve its 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 credit analysis, exposure measurement, and exposure monitoring and mitigation.
The Company monitors counterparties for significant swings in credit default swap rates, credit rating changes by external rating agencies, ownership changes or financial distress. Where deemed appropriate, the Company may request collateral or other security from its counterparties to mitigate potential credit default losses. Criteria employed in this decision include, among other things, the perceived creditworthiness of the counterparty and the expected credit exposure.
It is possible
that volatility in energy commodity prices could cause the Company to have material credit risk exposure 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 September 30, 2023, approximately i99.5% of the Company's energy portfolio exposure, excluding normal purchase normal sale (NPNS) transactions, is with counterparties that are rated investment grade by rating agencies and i0.5%
are either rated below investment grade or not rated by rating agencies. The Company assesses credit risk internally for counterparties that are not rated by the major rating agencies.
The Company computes credit reserves at a master agreement level by counterparty. The Company considers external credit ratings and market factors in the determination of reserves, such as credit default swaps and bond spreads. The Company recognizes that external ratings may not always reflect how a market participant perceives a counterparty's risk of default. The Company uses both default factors published by Standard & Poor's and factors derived through analysis of market risk, which reflect the application of an industry standard recovery rate. The Company selects a default factor by counterparty at an aggregate master agreement level based on a weighted average default tenor for that counterparty's deals. The default tenor is
determined by weighting the fair value and contract tenors for all deals for each counterparty to derive an average value. The default factor used is dependent upon whether the counterparty is in a net asset or a net liability position after applying the master agreement levels.
The Company applies the counterparty's default factor to compute credit reserves for counterparties that are in a net asset position. The Company calculates a non-performance risk on its derivative liabilities by using its estimated incremental borrowing rate over the risk-free rate. Credit reserves are netted against the unrealized gain (loss) positions. The majority of the Company's derivative contracts are with financial institutions and other utilities operating within the Western Electricity Coordinating Council. PSE also transacts power futures contracts on the Intercontinental Exchange (ICE), and natural gas contracts on the ICE natural
gas exchange (NGX) platform. Execution of contracts on ICE requires the daily posting of margin calls as collateral through a futures and clearing agent. As of September 30, 2023, PSE had cash posted as collateral of $i22.1 million related to contracts executed on the ICE platform. In August 2022, PSE entered into a standby letter of credit agreement with TD Bank allowing standby letter of credit postings of up to $i50.0
million as a condition of transacting on the ICE NGX platform. As of September 30, 2023, PSE had ino cash posted with ICE NGX and $i7.0 million
issued under the standby letter of credit agreement. PSE did not trigger any collateral requirements with any of its counterparties nor were any of PSE's counterparties required to post collateral resulting from credit rating downgrades during the three months ended September 30, 2023.
i
The following table presents the aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position and the amount of additional collateral the Company could be required to post:
1 Represents
the derivative fair value of contracts with contingent features for counterparties in net derivative liability positions. Excludes NPNS, accounts
payable and accounts receivable.
2 Failure by PSE to maintain an investment grade credit rating from each of the major credit rating agencies provides counterparties a contractual right to
demand collateral.
3Collateral requirements may vary based on changes in the forward value of underlying transactions relative to contractually defined collateral thresholds.
/
22
(5) iFair
Value Measurements
ASC 820 established a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy categorizes the inputs into three levels with the highest priority given to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority given to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:
Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Level 1 primarily consists of financial instruments such as exchange-traded derivatives and listed equities. Equity securities that are also classified as cash equivalents are considered Level 1 if there are unadjusted quoted prices in active
markets for identical assets or liabilities.
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 reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. Instruments in this category include non-exchange-traded derivatives such as over-the-counter forwards and options.
Level 3 - Pricing inputs include significant inputs that have little or no observability as of the reporting date. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value.
Financial assets and liabilities measured at fair
value are classified in their entirety in the appropriate fair value hierarchy 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. The Company primarily determines fair value measurements classified as Level 2 or Level 3 using a combination of the income and market valuation approaches. The process of determining the fair values is the responsibility of the derivative accounting department, which reports to the Controller and Principal Accounting Officer. Inputs used to estimate the fair value of forwards, swaps and options include market-price curves, contract terms and prices, credit-risk adjustments, and discount factors. Additionally, for options, the Black-Scholes option valuation model and implied
market volatility curves are used. Inputs used to estimate fair value in industry-standard models are categorized as Level 2 inputs as substantially all assumptions and inputs are observable in active markets throughout the full term of the instruments. On a daily basis, the Company obtains quoted forward prices for the electric and natural gas markets from an independent external pricing service.
The Company considers its electric and natural gas contracts as Level 2 derivative instruments as such contracts are commonly traded as over-the-counter forwards with indirectly observable price quotes. However, certain energy derivative instruments with maturity dates falling outside the range of observable price quotes or that are transacted at illiquid delivery locations are classified as Level 3 in the fair value hierarchy. Management's assessment is based on the trading activity in real-time and forward electric and natural
gas markets. Each quarter, the Company confirms the validity of pricing-service quoted prices used to value Level 2 commodity contracts with the actual prices of commodity contracts entered into during the most recent quarter. The Company’s environmental compliance obligation is categorized in Level 2 of the fair value hierarchy and is measured at fair value using a market approach based on quoted prices from an independent pricing service.
Assets and Liabilities with Estimated Fair Value
The carrying values of cash and cash equivalents, restricted cash, and short-term debt as reported on the balance sheet are reasonable estimates of their fair value due to the short-term nature of these instruments and are classified as Level 1 in the fair value hierarchy. The carrying value of other investments of $i44.3 million
and $i55.0 million at September 30, 2023 and December 31, 2022 respectively, are included in "Other property and investments" on the balance sheet. These values are also reasonable estimates of their fair value and classified as Level 2 in the fair value hierarchy as they are valued based on market rates for similar transactions.
23
i
The
fair value of the long-term notes was estimated using the discounted cash flow method with the U.S. Treasury yields and the Company's credit spreads as inputs, interpolating to the maturity date of each issue. The carrying values and estimated fair values were as follows:
1 The
carrying value includes debt issuances costs of $i21.4 million and $i21.5 million for September 30, 2023 and December 31, 2022, respectively,
which are not included in fair value.
2 The carrying value includes debt issuances costs of $i21.6 million and $i21.4 million for September 30,
2023 and December 31, 2022, respectively, which are not included in fair value.
/
Assets and Liabilities Measured at Fair Value on a Recurring Basis
i
The following
table presents the Company's financial assets and liabilities by level, within the fair value hierarchy, that were accounted for at fair value on a recurring basis:
The
following table presents the Company's reconciliation of the changes in the fair value of Level 3 derivatives in the fair
value hierarchy:
i
Puget
Energy and Puget Sound Energy
Three Months Ended September 30,
(Dollars in Thousands)
2023
2022
Level 3 Roll-Forward Net Asset/(Liability)
Electric
Natural Gas
Total
Electric
Natural Gas
Total
Balance
at beginning of period
$
i57,907
$
i104
$
i58,011
$
i5,916
$
(i717)
$
i5,199
Changes
during period:
Realized and unrealized energy derivatives:
Included in earnings1
(i12,551)
i—
(i12,551)
i6,939
i—
i6,939
Included
in regulatory assets / liabilities
i—
i3,808
i3,808
i—
(i4)
(i4)
Settlements
(i9,752)
(i351)
(i10,103)
(i12,080)
i502
(i11,578)
Transferred
into Level 3
i—
i—
i—
i—
i—
i—
Transferred
out of Level 3
i—
i—
i—
i—
i—
i—
Balance
at end of period
$
i35,604
$
i3,561
$
i39,165
$
i775
$
(i219)
$
i556
/
Puget
Energy and Puget Sound Energy
Nine Months Ended September 30,
(Dollars in Thousands)
2023
2022
Level 3 Roll-Forward Net Asset/(Liability)
Electric
Natural Gas
Total
Electric
Natural Gas
Total
Balance
at beginning of period
$
i116,078
$
(i127)
$
i115,951
$
(i42,752)
$
(i2,120)
$
(i44,872)
Changes
during period:
Realized and unrealized energy derivatives:
Included in earnings2
(i47,613)
i—
(i47,613)
i50,572
i—
i50,572
Included
in regulatory assets / liabilities
i—
i3,852
i3,852
i—
i481
i481
Settlements
(i33,078)
(i334)
(i33,412)
(i7,314)
i1,097
(i6,217)
Transferred
into Level 3
i—
i—
i—
i—
i—
i—
Transferred
out of Level 3
i217
i170
i387
i269
i323
i592
Balance
at end of period
$
i35,604
$
i3,561
$
i39,165
$
i775
$
(i219)
$
i556
_______________
1 Income
Statement locations: Unrealized gain (loss) on derivative instruments, net. Amounts include unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $(i1.2) million and $(i8.8)
million for the three months ended September 30, 2023 and 2022, respectively.
2 Income Statement locations: Unrealized gain (loss) on derivative instruments, net. Amounts include unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $(i19.8) million and $i31.2
million for the nine months ended September 30, 2023 and 2022, respectively.
Realized gains and losses on energy derivatives for Level 3 recurring items are included in energy costs in the Company's consolidated statements of income under purchased electricity, electric generation fuel or purchased natural gas when settled. Unrealized gains and losses on energy derivatives for Level 3 recurring items are included in net unrealized (gain) loss on derivative instruments in the Company's consolidated statements of income.
The Company does not use internally developed models to make adjustments to significant unobservable pricing inputs. The only significant unobservable input into the fair value measurement of the Company's Level 3 assets and liabilities
is the forward price for electric and natural gas contracts. The weighted average price is calculated as the total market value divided by the total volume of the Company's Level 3 electric and natural gas commodity contracts, respectively, as of the reporting date.
25
i
The following table presents the forward price ranges for the Company's Level 3 commodity contracts as of September 30,
2023:
Puget Energy and Puget Sound Energy
Fair
Value
Range
(Dollars in Thousands)
Assets1
Liabilities1
Valuation Technique
Unobservable Input
Low
High
Weighted Average
Electric
$
i47,644
$
i12,040
Discounted
cash flow
Power prices (per MWh)
$
i58.38
$
i170.03
$
i100.28
Natural
gas
$
i4,714
$
i1,153
Discounted
cash flow
Natural gas prices (per MMBtu)
$
i1.58
$
i7.88
$
i4.50
_______________
1 The
valuation techniques, unobservable inputs and ranges are the same for asset and liability positions.
The following table presents the forward price ranges for the Company's Level 3 commodity contracts as of December 31, 2022:
Puget
Energy and Puget Sound Energy
Fair Value
Range
(Dollars in Thousands)
Assets1
Liabilities1
Valuation Technique
Unobservable Input
Low
High
Weighted Average
Electric
$
i119,093
$
i3,015
Discounted
cash flow
Power prices (per MWh)
$
i55.79
$
i291.03
$
i131.51
Natural
gas
$
i959
$
i1,086
Discounted
cash flow
Natural gas prices (per MMBtu)
$
i3.84
$
i7.00
$
i4.87
_______________
1 The
valuation techniques, unobservable inputs and ranges are the same for asset and liability positions.
/
The significant unobservable inputs listed above would have a direct impact on the fair values of the above instruments if they were adjusted. Consequently, significant increases or decreases in the forward prices of electricity or natural gas in isolation would result in a significantly higher or lower fair value for Level 3 assets and liabilities. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets. As of September 30, 2023
and December 31, 2022, a hypothetical ii10/%
increase or decrease in market prices of natural gas and electricity would change the fair value of the Company's derivative portfolio, classified as Level 3 within the fair value hierarchy, by $i20.7 million and $i37.6 million,
respectively.
Long-Lived Assets Measured at Fair Value on a Nonrecurring Basis
Puget Energy records the fair value of its intangible assets in accordance with ASC 360, “Property, Plant, and Equipment,” (ASC 360). The fair value assigned to the power contracts was determined using an income approach comparing the contract rate to the market rate for power over the remaining period of the contracts incorporating non-performance risk. Management also incorporated certain assumptions related to quantities and market presentation that it believes market participants would make in the valuation. The fair value of the power contracts is amortized as the contracts settle.
ASC 360 requires long-lived assets to be tested for recoverability whenever events or changes in circumstances indicate that
its carrying amount may not be recoverable. One such triggering event is a significant decrease in the forward market prices of power.
As of September 30, 2023, Puget Energy completed valuation and impairment testing of its power purchase contracts classified as intangible assets and determined that ino impairment was needed. These intangible assets exist as a result of the merger in 2009, at which time the consolidated assets and liabilities were revalued in accordance with ASC 805, "Business
Combinations."
(6) iRetirement Benefits
PSE has a defined benefit pension plan (Qualified Pension Benefits) covering a substantial majority of PSE employees. For employees hired prior to 2014, pension benefits earned are a function of age, salary, years of service and, in the case of employees in the cash balance formula
plan, the applicable annual interest crediting rates. Effective January 1, 2014, all new
26
United Association of Journeymen and Apprentices of the Plumbing and Pipefitting Industry of the United States and Canada (UA) represented employees hired or rehired receive annual pay credits of i4.0% of eligible pay each year in
the cash balance formula of the defined pension plan. Effective January 1, 2014 for non-represented employees, and December 12, 2014 for employees represented by the International Brotherhood of Electrical Workers (IBEW), newly hired or rehired employees receive annual employer contributions of i4.0% of eligible pay each year into the cash balance formula of the defined benefit pension or 401k plan account. PSE also
has a non-qualified Supplemental Executive Retirement Plan (SERP) for certain key senior management employees that closed to new participants in 2019. Effective 2019, PSE has an officer restoration benefit for new officers who join PSE or are promoted, such that company contributions under PSE’s applicable tax-qualified plan, which otherwise would have been credited if not for the IRS limitations, are credited at i4.0% of earnings to an account with the Deferred Compensation Plan.
In addition to providing pension benefits, PSE provides legacy group health care and life insurance benefits
(Plan) for certain retired employees. These benefits are provided principally through an insurance company. The insurance premiums, paid primarily by retirees, are based on the benefits provided during the prior year.
Puget Energy's retirement plans were remeasured as a result of the merger in 2009, which represents the difference between Puget Energy and PSE's retirement plans. The components of service cost are included within utility operations and maintenance for PSE and within non-utility expense and other for Puget Energy while all non-service cost components are included in other income.
For further information, see Note 13, "Retirement Benefits" in the Combined Notes to Consolidated Financial Statements included in Item 8 of the Company's Form 10-K for the period ended December 31, 2022.
i
The
following tables summarize the Company’s net periodic benefit cost for the three and nine months ended September 30, 2023 and 2022:
The
aggregate expected contributions by the Company to fund the qualified pension plan, SERP and the other postretirement plans for the year ending December 31, 2023, are expected to be at least $i18.0 million, $i3.5 million
and $i0.2 million, respectively. The Company contributed $i18.0 million
to fund the qualified pension plan during the nine months ended September 30, 2023 and the nine months ended September 30, 2022. In addition, the Company contributed $i3.0 million and $i1.5 million
to fund the SERP during each of the nine months ended September 30, 2023 and the nine months ended September 30, 2022, respectively. The Company contributed an immaterial amount to fund the other postretirement plans.
(7) iRegulation and Rates
General Rate Case
On
December 22, 2022, the Washington Commission issued an order on PSE’s 2022 general rate case (GRC), which was filed on January 31, 2022 that approved a weighted cost of capital of i7.16%, or i6.62%
after-tax, a capital structure of i49.0% in common equity in 2023 and 2024, and a return on equity of i9.4%. On January 6, 2023, the Washington Commission approved
PSE’s natural gas rates in its compliance filing with an overall net revenue change of $i70.8 million or i6.4% in 2023 and $i19.5
million or i1.7% in 2024, with an effective date of January 7, 2023. On January 10, 2023, the Washington Commission approved PSE’s electric rates in its compliance filing with an overall net revenue change of $i247.0
million or i10.8% in 2023 and $i33.1 million or i1.3%
in 2024 with an effective date of January 11, 2023. Per the 2022 GRC Final Order in Docket No. UE-220066, power cost only rate case (PCORC) rates were set to izero as of January 11, 2023 and PSE agreed not to file a PCORC during 2023 and 2024, the period covered by the itwo-year
rate plan agreed to in the GRC settlement.
Prior rates were subject to the 2019 GRC and included a weighted cost of capital of i7.39% or i6.8% after-tax,
a capital structure of i48.5% in common equity, and a return on equity of i9.4%. The annualized overall rate impacts were an electric revenue increase of $i48.3
million, or i2.3%, and a natural gas increase of $i4.9 million, or i0.6%,
effective October 1, 2021. For further information, see Note 4, "Regulation and Rates" in the Combined Notes to Consolidated Financial Statements included in Item 8 of the Company's Form 10-K for the period ended December 31, 2022.
Climate Commitment Act Deferral
On December 29, 2022, PSE filed accounting petitions with the Washington Commission requesting authorization to defer costs and revenues associated with the Company’s compliance with the Climate Commitment Act (CCA) codified in law within Revised Code of Washington (RCW) 70A.65. On February 28, 2023, in Order 01 under Docket No. UE-220974 and UG-220975, the Washington Commission
granted PSE approval to defer the cost of emission allowances to comply with the
29
CCA and the proceeds from no-cost allowances consigned to auction beginning January 1, 2023. This accounting treatment is necessary in order for PSE to defer and seek recovery of CCA costs that are not currently included in rates. As of September 30, 2023, PSE deferred $i144.2
million and $i67.2 million of CCA compliance costs for natural gas and electric liabilities, respectively. Additionally, PSE will consign for auction at least the minimum amount of no-cost emission allowances allocated for natural gas operations in compliance with the CCA, the proceeds of which will be used for the benefit of natural gas customers, as determined by the Washington Commission. PSE will not record a regulatory liability to defer the proceeds until consigned allowances are sold at auction. As of September 30, 2023,
PSE recorded $i108.5 million related to the proceeds from the sale of consigned GHG emission allowances.
In October 2022, the Washington Department of Ecology (WDOE) published final regulations to implement the cap and invest program. The WDOE also indicated that they will have subsequent rulemakings that will build off initial rulemaking as program implementation gets underway and progress with Washington State carbon goals are evaluated. One component of the CCA rules stipulates the WDOE shall provide
qualifying electric utilities, such as PSE, with no-cost allowances based on the cost burden of the program to electric customers, which is derived using a forecast of emissions. An additional component of the CCA rules stipulates that the allocation of no-cost allowances is adjusted over time to take into account the cumulative total of no-cost allowances an electric utility has been given relative to its reported GHG emissions. Such adjustments will be made through a WDOE adjustment in the fourth quarter of the following year. WDOE has indicated that such adjustment would take into account the cumulative total of allowances an electric utility has received relative to its reported GHG emissions. WDOE would add allowances to an electric utility's account if such account has an allowance deficit, and WDOE would add fewer allowances to an electric utility's account going forward if such account had previously allocated excess allowances. WDOE has not provided further
guidance or rules specifying how such adjustments will be determined. As a result, the Company cannot predict the impact of such adjustments.
WDOE provided an initial allocation of no-cost allowances on April 24, 2023. However, qualifying electric utilities were allowed to submit revised emissions forecasts approved by the Washington Commission to WDOE by July 30, 2023, and the WDOE, if appropriate, may adjust the initial allocation schedule of no-cost allowances to reflect such revised 2023 emissions forecasts. PSE filed its revised forecast of 2023 emission under Docket No. UE 220797, which was approved by the Washington Commission on July 27, 2023 and approved by the WDOE on September 27, 2023. Accordingly, the Company's
compliance obligation as of September 30, 2023 reflects the revised allowance allocation.
Following the September 27, 2023 WDOE decision, PSE's no-cost allowance allocation will be set for 2023 until the fourth quarter of 2024 when there is an opportunity to request a "true-up" of no-cost allowances under the aforementioned adjustment mechanism. However, as of September 30, 2023, due to the uncertainty around implementation of the adjustment mechanism PSE did not adjust the CCA electric compliance obligation anticipating an adjustment to no cost allowances to reported 2023 electric GHG emissions and does not plan to make such adjustment until a formal true-up allocation has been granted by the WDOE.
Revenue
Decoupling Adjustment Mechanism
In June 2021, the Washington Commission approved the multi-party settlement agreement, which was filed within PSE’s PCORC filing. As part of this settlement agreement, the electric annual fixed power cost allowed revenue was updated to reflect changes in the approved revenue requirement and took effect on July 1, 2021.
In September 2021, the Washington Commission approved the 2019 GRC filing. As part of this filing, the annual electric and natural gas delivery cost allowed revenue was updated to reflect changes in the approved revenue requirement. The changes took effect on October 1, 2021.
On January 6, 2023, the Washington Commission approved the natural
gas 2022 GRC filing. As part of this filing, the annual natural gas delivery allowed revenue was updated to reflect changes in the approved revenue requirement. Additionally, the Commission approved the removal of the earnings test from the decoupling mechanism in accordance with RCW 80.28.425(6). The changes took effect on January 7, 2023.
On January 10, 2023, the Washington Commission approved the electric 2022 GRC filing. As part of this filing, the annual electric delivery and fixed power cost allowed revenue was updated to reflect changes in the approved revenue requirement. Additionally, the Commission approved the removal of the earnings test from the decoupling mechanism in accordance with RCW 80.28.425(6). The changes took effect on January 11, 2023.
On
September 30, 2023, PSE performed an analysis to determine if electric and natural gas decoupling revenue deferrals would be collected from customers within 24 months of the annual period, per ASC 980. If not, for GAAP purposes only, PSE would need to record a reserve against the decoupling revenue and corresponding regulatory asset balance. Once the reserve is probable of collection within 24 months from the end of the annual period, the reserve can be recognized as decoupling revenue. Based on the analyses, iiiino///
reserve adjustment was recorded as of September 30, 2023 and 2022.
30
Power Cost Adjustment Mechanism
PSE currently has a power cost adjustment (PCA) mechanism that provides for the deferral of power costs that vary from the “power cost baseline” level of power costs. The “power cost baseline” levels are set, in part, based on normalized assumptions about weather and hydroelectric conditions. Excess power costs or savings are apportioned between PSE and its customers pursuant to the graduated scale set forth in the PCA mechanism and will trigger a surcharge or refund
when the cumulative deferral trigger is reached.
iEffective January 1, 2017, the following graduated scale is used in the PCA mechanism:
Company’s
Share
Customers' Share
Annual Power Cost Variability
Over
Under
Over
Under
Over or under collected by up to $17 million
i100
%
i100
%
i—
%
i—
%
Over
or under collected by between $17 million - $40 million
i35
i50
i65
i50
Over
or under collected beyond $40 + million
i10
i10
i90
i90
/
For
the nine months ended September 30, 2023, in its PCA mechanism, PSE over recovered its allowable costs by $i66.2 million of which $i38.5 million was apportioned
to customers and $i3.6 million of interest was accrued on the deferred customer balance. This compares to an under recovery of allowable costs of $i12.5 million for the nine months ended September
30, 2022, of which izero was apportioned to customers and accrued $i1.0 million of interest on the total deferred customer balance.
Power Cost Adjustment Clause
PSE exceeded the $i20.0 million cumulative deferral balance in its PCA mechanism in 2022. During 2022, actual power costs were higher than baseline power costs, thereby, creating an under-recovery of $i110.1
million. Under the terms of the PCA’s sharing mechanism for under-recovered power costs, PSE absorbed $i39.0 million of the under-recovered amount, and customers were responsible for the remaining $i71.1 million, or $i76.4
million including interest and adjusted for revenue sensitive items. On April 28, 2023, PSE filed the 2022 PCA report under Docket No. UE-230313 that proposed a recovery of the deferred balance, which included a revenue requirement increase of i0.9% in overall bill for all customers, with rates proposed to go into effect from December 1, 2023 through December 31, 2024.
PSE also exceeded the $i20.0
million cumulative deferral balance in its PCA mechanism in 2021, as actual power costs were higher than baseline power costs, thereby, creating an under-recovery of $i68.0 million. PSE absorbed $i31.3 million of the under-recovered amount, and
customers were responsible for the remaining $i36.7 million, or $i38.4 million including interest. In October 2022, the Washington Commission approved PSE's 2021 PCA report that proposed to recover the deferred balance for the 2021 PCA period by
keeping the current rates and allowing recovery from January 1, 2023 through November 30, 2023.
On September 29, 2023, PSE filed its variable power cost rates update as part of the 2022 GRC Order requirement under Docket No. UE-220066. The filing, which is pending approval from the Washington Commission, is set to be effective January 1, 2024 through December 31, 2024.
Purchased Gas Adjustment Mechanism
In October 2021, the Washington Commission approved PSE's request for PGA rates in Docket No. UG-210721, effective November
1, 2021. As part of that filing, PSE requested an annual revenue increase of $i59.1 million, where PGA rates, under Schedule 101, increase annual revenue by $i80.6
million, and the tracker rates under Schedule 106, decrease annual revenue by $i21.5 million. Those annual 2021 PGA rate increases will be set in addition to continuing the collection on the remaining balance of $i69.4
million under Supplemental Schedule 106B, which were set, in effect, through September 30, 2023 per the 2019 GRC.
In October 2022, the Washington Commission approved PSE's request for PGA rates in Docket No. UG-220715, effective November 1, 2022. As part of that filing, PSE requested an annual revenue increase of $i155.3 million, where PGA rates, under Schedule 101, increase annual revenue by $i142.1
million, and the tracker rates under Schedule 106 increase annual revenue by $i13.2 million.
In November 2022, the FERC approved a settlement of a counterparty, FERC Docket No. RP17-346. Under the terms, PSE was allocated $i24.2 million
related to PSE natural gas services, which was recorded on December 31, 2022 and included below. The 2022 GRC order requires PSE to amortize the refund in 2023 as a credit against natural gas costs and therefore pass back the refund to customers through the PGA mechanism.
On October 26, 2023, the Washington Commission approved PSE's request for PGA rates in Docket No. UG-230769, effective November 1, 2023. As part of that filing, PSE requested an annual revenue decrease of $i309.4
million, where PGA
31
rates, under Schedule 101, decrease annual revenue by $i93.9 million, and the tracker rates under Schedule 106, decrease annual revenue by $i215.5
million. The annual 2023 PGA rate decreases include the aforementioned counterparty settlement pass back of $i28.1 million under Supplemental Schedule 106B.
The Washington Commission has defined deferrable weather-related events and provided that costs in excess of the annual cost threshold may be deferred for qualifying damage costs that meet the modified Institute of Electrical and Electronics Engineers outage criteria for system average interruption duration index. For the nine months ended September 30, 2023, PSE incurred $i6.1 million in weather-related electric transmission and distribution system restoration costs related to 2023
and 2022 storms, of which the company deferred izero and $i2.1 million as regulatory assets related to storms that occurred in 2023 and 2022, respectively. This compares to $i6.8 million
incurred in weather-related electric transmission and distribution system restoration costs for the nine months ended September 30, 2022, of which the Company deferred $i0.2 million as regulatory assets related to storms that occurred in 2021. Under the 2017 GRC Order, the storm loss deferral mechanism approved the following: (i) the cumulative annual cost threshold for deferral of storms under the mechanism at $i10.0 million;
and (ii) qualifying events where the total qualifying cost is less than $i0.5 million will not qualify for deferral and these costs will also not count toward the $i10.0 million
annual cost threshold.
Environmental Remediation
The Company is subject to environmental laws and regulations by the federal, state and local authorities and is required to undertake certain environmental investigative and remedial efforts as a result of these laws and regulations. The Company has been named by the Environmental Protection Agency, the WDOE and/or other third parties as potentially responsible or liable at several contaminated sites and former manufactured gas plant sites. In accordance with the guidance of ASC 450, “Contingencies,” the Company reviews its estimated future obligations and will record adjustments, if any, on a quarterly basis. The adjustments recorded are based on the best estimate or the low end of a range of reasonably possible costs expected to be incurred by the Company based on its currently understood
legal exposure at applicable sites. It is reasonably possible that incurred costs exceed the recorded amounts due to changes in laws and/or regulations, higher than expected costs due to changes in labor market or supply chain, and/or the discovery of new or additional contamination. The Company currently estimates that a significant portion of its past and future environmental remediation costs are recoverable from insurance companies, from third parties or from customers under a Washington Commission order.
32
i
The
following table summarizes changes in the Company's environmental remediation regulatory assets during the nine months ended September 30, 2023 and 2022.
1 Driven
in significant part by the Quendall Terminals site on Lake Washington in Renton, Washington. The site represents contaminated facilities from a long defunct creosote manufacturer which had purchased waste products from PSE predecessors.
/
i
The following table summarizes changes in the Company's environmental remediation liabilities during the nine months ended September 30,
2023 and 2022.
1 Driven
in significant part by the Quendall Terminals site on Lake Washington in Renton, Washington. The site represents contaminated facilities from a long defunct creosote manufacturer which had purchased waste products from PSE predecessors.
(8) iCommitments and Contingencies
Legal Matters
Washington Climate
Commitment Act
In 2021, the Washington Legislature adopted the CCA, which establishes a GHG emissions cap-and-invest program that caps GHG emissions beginning on January 1, 2023, and makes further reductions to the cap annually through 2050. WDOE published final regulations to implement the program on September 29, 2022, which became effective on October 30, 2022. WDOE also indicated that there will be subsequent rulemakings and interpretations that will build off initial rulemaking as program implementation proceeds and Washington state carbon goals are evaluated.
One component of the CCA rules stipulates that GHG emissions associated with exported electricity are covered emissions and require an allowance offset to the extent these
exports are not sourced from a non-emitting resource. Another component of the CCA rules stipulates GHG emissions associated with imported electricity are covered emissions and require an allowance offset for the first jurisdictional deliverer serving as the electricity importer for that electricity. Per RCW 70A.65.010(42)(d), imported electricity does not include electricity imports of unspecified electricity that are netted by exports of unspecified electricity to any jurisdiction not covered by a linked program by the same entity within the same hour. Under this definition, hourly power transmission data is required to determine PSE’s net imported electricity compliance obligation. Although the Company is actively engaged in determining the hourly net generation, imports and exports, the methodology for netting these components by hour that will be required by the WDOE to calculate the compliance obligation is uncertain, and PSE expects further rulemaking and
agency interpretations to clarify this uncertainty in future periods. Due to the estimation uncertainty as of the date of this disclosure, the company considered a range of outcomes depending on the proportion of exported electricity that is sourced from non-emitting resources and whether all unspecified electricity imports and exports fully net on an hourly basis, none net, or a portion do. As of September 30, 2023, the Company's estimated the range of possible outcomes to be between $i66.1 million and $i202.1 million
depending on the methodology applied in netting unspecified electricity imports and
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exports. Since no amount in the range represents a better estimate than any other amount, the Company accrued to the minimum amount in the range. As existing uncertainties are resolved in future periods, any change in compliance costs as a result of such estimated additional liabilities would be deferred under ASC 980 as a regulatory asset as an increase the electric compliance costs consistent with Docket No. UE-220974, as these amounts will be recoverable from customers in future utility rates.
Colstrip
PSE has a i50%
ownership interest in Colstrip Units 1 and 2 and a i25% interest in each of Colstrip Units 3 and 4, which are coal-fired generating units located in Colstrip, Montana. PSE has accelerated the depreciation of Colstrip Units 3 and 4 to December 31, 2025 as part of the 2019 GRC. The 2017 GRC repurposed PTCs and hydro-related treasury grants to recover unrecovered plant costs and to fund and recover decommissioning and remediation costs for Colstrip Units 1 through 4. On September 2, 2022, PSE and Talen Energy reached
an agreement to transfer PSE's ownership interest in Colstrip Units 3 and 4 to Talen Energy on December 31, 2025. Management evaluated Colstrip Units 3 and 4 and determined that the applicable held for sale accounting criteria were not met as of September 30, 2023 and December 31, 2022. As such, Colstrip Units 3 and 4 are classified as electric utility plant on the Company's balance sheet as of September 30, 2023 and December 31, 2022.
Consistent with a June 2019 announcement, Talen permanently shut down Units 1 and 2 at the end of 2019 due to operational losses associated with the Units. Colstrip Units 1 and 2 were retired effective December
31, 2019. The Washington Clean Energy Transformation Act requires the Washington Commission to provide recovery of the investment, decommissioning, and remediation costs associated with the facilities that are not recovered through the repurposed PTCs and hydro-related treasury grants. The full scope of decommissioning activities and costs may vary from the estimates that are available at this time.
In May 2021, PSE along with the Colstrip owners, Avista Corporation, PacifiCorp and Portland General Electric Company, filed a lawsuit against the Montana Attorney General challenging the constitutionality of Montana Senate Bill 266. On September 28, 2022, the magistrate judge in the District Court proceeding issued a recommendation to the presiding U.S. District Court Judge that a permanent injunction against enforcement of Senate Bill 266 be granted. In October 2022, the
U.S. District Court Judge accepted in full the magistrate judge's recommendation for a permanent injunction against enforcement of Senate Bill 266. The Court entered judgment and a permanent injunction in favor of PSE and the Colstrip owners on November 15, 2022. No party filed a notice of appeal.
Other Commitments and Contingencies
In addition to the contractual obligations and consolidated commercial commitments disclosed in the Company's Annual Report on Form 10-K for the year ended December 31, 2022, during the nine months ended September 30, 2023, the Company entered into new Electric Portfolio and Electric Wholesale Market Transaction contracts with estimated payment obligations totaling
$i4.2 billion through 2051.
For further information, see Part II, Item 8, Note 16, "Commitments and Contingencies" in the Company’s Annual Report on Form 10-K for the year ended December 31, 2022.
(9) iiLeases/
As
of September 30, 2023, there have been no material changes regarding the Company's leases. For further information, see Part II, Item 8, Note 9, "Leases" in the Company’s Annual Report on Form 10-K for the year ended December 31, 2022.
Leases Not Yet Commenced
On September 20, 2023, PSE entered into a tolling agreement to purchase the energy and capacity associated with a i132.5
MW facility. The tolling agreement represents a lease to PSE, and is expected to commence in October 2025. PSE expects the future minimum lease payments to be $i91.0 million over the ifive year period
beginning in October 2025.
(10) iOther
Long-Term Debt
In March 2022, Puget Energy issued $i450.0 million
of senior secured notes at an interest rate of i4.224%. The notes mature on March 15, 2032 and pay interest semi-annually on March 15 and September 15of each year. Proceeds from the issuance of the notes were invested in short-term money market funds, and then used to repay Puget Energy's $i450.0 million
i5.625% notes that were originally scheduled to mature in July 2022.
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In April 2022, Puget Energy redeemed the $i450.0 million
i5.625% senior secured notes due July 2022 and paid related expenses for a total redemption price of $i457.2 million, which includes repayment of the $i450.0 million
principal amount and $i7.2 million of accrued interest expense.
On May 18, 2023, PSE issued $i400.0 million of green senior secured notes at an
interest rate of i5.448%. The notes mature on June 1, 2053 and pay interest semi-annually in arrears on June 1 and December 1 of each year, commencing December 1, 2023. Net proceeds from the issuance of the notes were deposited into the Company's general account and will be earmarked for allocation to eligible projects, as defined in PSE's sustainable financing framework, which was published in May 2023. Eligible projects are expenditures incurred and investments made related to development and acquisition of some or all of the following types of projects: (i)
renewable energy, (ii) energy efficiency, (iii) clean transportation, (iv) biodiversity conservation, (v) climate change adaptation, (vi) water and wastewater management, (vii) pollution prevention and control, and (viii) green innovation.
Short-Term Debt
As of September 30, 2023, there was ino amount outstanding under the commercial paper program at PSE. For further information, see Part II, Item 8, Note 8, "Liquidity Facilities and Other Financing Arrangements"
in the Company's Annual Report on Form 10-K for the year ended December 31, 2022.
Credit Facilities
In May 2022, Puget Energy entered into an $i800.0 million credit facility to replace the existing facility. The terms and conditions, including fees, financial covenant, expansion feature and credit spreads remain substantially the same. The base interest rate on loans has changed to the Secured
Overnight Financing Rate (SOFR), as the LIBOR was discontinued on June 30, 2023. The proceeds of the Puget Energy credit facility are to be used for general corporate purposes. The maturity date of the credit facility is May 14, 2027. As of September 30, 2023, $i244.2 million was drawn and outstanding under the facility.
In September 2022, Puget Energy
borrowed $i50.0 million on the credit facility and contributed the proceeds to PSE as an equity contribution. The equity proceeds were used for general corporate purposes. In August 2023, Puget Energy borrowed $i100.0 million on the credit facility and contributed
the proceeds to PSE as an equity contribution. The equity proceeds will be used for general corporate purposes.
In May 2022, PSE entered into an $i800.0 million credit facility to replace the existing facility. The terms and conditions, including fees, financial covenant, expansion feature and credit spreads remain substantially the same. The base interest rate on loans has changed to the SOFR, as the LIBOR was discontinued on June 30, 2023. The proceeds of the PSE credit facility
are to be used for general corporate purposes. The maturity date of the credit facility is May 14, 2027. As of September 30, 2023, ino amount was drawn under PSE's credit facility.
For further information, see Part II, Item 8, Note 7, "Long-Term Debt" and Note 8, "Liquidity Facilities and Other Financing Arrangements" in the Company's Annual Report on Form 10-K for the year ended December 31,
2022.
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Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis is intended to promote understanding of the results of operations and financial condition, is provided as a supplement to, and should be read in conjunction with the financial statements and related notes thereto included elsewhere in this report on Form 10-Q. This section generally discusses the results of operations and changes in financial condition
for the period ended September 30, 2023 compared to 2022. For discussion related to the results of operations and changes in financial condition for the period ended September 30, 2022 compared to 2021 refer to Part I, Item 2, Management's Discussion and Analysis of Financial Condition and Results of Operations in our period ended September 30, 2022, Form 10-Q, which was filed with the United States Securities and Exchange commission (SEC). The discussion contains forward-looking statements that involve risks and uncertainties, such as Puget Energy, Inc. (Puget Energy) and Puget Sound Energy, Inc. (PSE) objectives, expectations and intentions. Words or phrases such as “anticipates,”“believes,”“continues,”“could,”“estimates,”“expects,”“future,”“intends,”“may,”“might,”“plans,”“potential,”“predicts,”“projects,”“should,”“will likely result,”“will continue” and similar expressions are intended to identify certain of these forward-looking statements. However, these words are not the exclusive means of identifying such statements. In addition, any statements that refer to expectations, projections or other characterizations of future events or circumstances are forward-looking statements. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this report. Puget Energy's and PSE's actual results could differ materially from results that may be anticipated by such forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those discussed in the section entitled “Forward-Looking Statements” included elsewhere in this report and in
the section entitled "Risk Factors" included in Part I, Item 1A in Puget Energy's and PSE's Form 10-K for the period ended December 31, 2022. Except as required by law, neither Puget Energy nor PSE undertakes any obligation to revise any forward-looking statements in order to reflect events or circumstances that may subsequently arise. Readers are urged to carefully review and consider the various disclosures made in this report and in Puget Energy's and PSE's other reports filed with the SEC that attempt to advise interested parties of the risks and factors that may affect Puget Energy's and PSE's business, prospects and results of operations.
Overview
Puget
Energy is an energy services holding company and substantially all of its operations are conducted through its wholly-owned subsidiary PSE, a regulated electric and natural gas utility company. PSE is the largest electric and natural gas utility in the state of Washington, primarily engaged in the business of electric transmission, distribution and generation and natural gas distribution. Puget Energy's business strategy is to generate stable cash flows by offering reliable electric and natural gas service in a cost-effective manner through PSE. Puget Energy also has a wholly-owned non-regulated subsidiary, Puget LNG, LLC (Puget LNG), which has the sole purpose of owning, developing and financing the non-regulated activity of the Tacoma liquefied natural gas (LNG) facility. All of Puget Energy's common stock is indirectly owned by Puget Holdings, LLC (Puget Holdings). Puget Holdings is owned by a consortium of long-term infrastructure investors including the British
Columbia Investment Management Corporation (BCIMC), the Alberta Investment Management Corporation (AIMCo), Ontario Municipal Employee Retirement System (OMERS), PGGM Vermogensbeheer B.V., Macquarie Washington Clean Energy Investment, L.P., and Ontario Teachers’ Pension Plan Board. Puget Energy and PSE are collectively referred to herein as “the Company.”
PSE generates revenue and cash flow primarily from the sale of electric and natural gas services to residential and commercial customers within a service territory covering approximately 6,000 square miles, principally in the Puget Sound region of the state of Washington. PSE continually balances its load requirements, generation resources, purchase power agreements, and market purchases to meet customer demand. The Company's external financing requirements principally reflect the cash needs of its construction program, its schedule of maturing debt and certain operational
needs. PSE requires access to bank and capital markets to meet its financing needs.
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Factors and Trends Affecting PSE's Performance
PSE’s ongoing regulatory requirements and operational needs necessitated the investment of substantial capital in 2023 and will continue to do so in future years. Because PSE intends to seek recovery of such investments through the regulatory process, its financial results depend heavily upon favorable outcomes from that process. The principal business, economic and other factors that affect PSE’s operations and financial performance include:
•The rates PSE is allowed to charge
for its services;
•PSE’s ability to recover power costs that are included in rates which are based on volume;
•Weather conditions, including the impact of temperature on customer load; the impact of extreme weather events on budgeted maintenance costs; meteorological conditions such as snow-pack, stream-flow and wind-speed which affect power generation, supply and price;
•The effects of climate change, including changes in the environment that may affect energy costs or consumption, increase the Company’s costs, or adversely affect its operations;
•Regulatory decisions allowing PSE to recover purchased power and fuel costs, on a timely basis;
•PSE’s
ability to supply electricity and natural gas, either through company-owned generation, purchase power contracts or by procuring natural gas or electricity in wholesale markets;
•Deferral of excess revenues if earnings exceed PSE's authorized rate of return (ROR) by more than 0.5%;
•Availability and access to capital and the cost of capital;
•Regulatory compliance costs, including those related to new and developing federal regulations of electric system reliability, state regulations of natural gas pipelines and federal, state and local environmental laws and regulations, such as the Climate Commitment Act (CCA);
•Wholesale commodity prices of electricity and natural gas;
•Increasing
capital expenditures with additional depreciation and amortization;
•Failure to complete capital projects on schedule and within budget or the abandonment of capital projects, either of which could result in the Company’s inability to recover project costs;
•Tax reform, the effect of lower tax rates, and regulatory treatment of excess deferred tax balances on rate base and customer rates;
•General economic conditions, such as inflation, in PSE's service territory and its effects on customer growth and use-per-customer;
•Federal, state, and local taxes;
•Employee workforce factors, including potential strikes, work stoppages, transitions
in senior management, and loss or retirement of key personnel and availability of qualified personnel;
•The effectiveness of PSE’s risk management policies and procedures;
•Cyber security attacks, data security breaches, or other malicious acts that cause damage to the Company’s generation and transmission facilities or information technology systems, or result in the release of confidential customer, employee, or Company information;
•Acts of war or terrorism locally or abroad, or the impact of civil unrest to infrastructure or preventing access to infrastructure and its impact on the supply chain and prices of goods and services;
•Natural disasters such as wildfires, earthquakes, hurricanes, floods,
landslides, and windstorms, and the rise in frequency and magnitude of these extreme temperature events, and possible accidents, explosions, fires or mechanical breakdowns affecting or caused by PSE’s facilities or infrastructure may increase the Company's costs, impact our generation, transmission, and distribution systems, subject the Company to increased liability, and/or adversely affect its operations;
•Risks due to pandemics, including supply shortages, rising costs, disruption to vendor or customer relationships, the potential for reputational harm, the impact of government, business and company closure of facilities, customer or contract defaults; concerns of safety to employees and customers, potential costs due to quarantining of employees and work-from-home policies, and the Company's and vendor staffing levels resulting from vaccination mandates; and
•Legislative,
regulatory, code, and/or ordinance changes that impact natural gas availability, delivery systems, and/or restrictions.
Regulation of PSE Rates and Recovery of PSE Costs
PSE's regulatory requirements and operational needs require the investment of substantial capital in 2023 and future years. As PSE intends to seek recovery of these investments through the regulatory process, its financial results depend heavily upon
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outcomes from that process. The rates that PSE is allowed to charge for its services influence
its financial condition, results of operations and liquidity. PSE is highly regulated and the rates that it charges its retail customers are approved by the Washington Utilities and Transportation Commission (Washington Commission). The Washington Commission has traditionally required these rates be determined based, to a large extent, on historic test year costs plus weather normalized assumptions about hydroelectric conditions and power costs in the relevant rate year. Incremental customer growth and sales typically have not provided sufficient revenue to cover general cost increases over time due to the combined effects of regulatory lag and attrition. Absent a resolution for the impact of lag and attrition, the Company will need to seek rate relief through a rate case with the Washington Commission. The Washington Commission determines whether the Company's expenses and capital investments are reasonable and prudent for the provision of cost-effective, reliable
and safe electric and natural gas service. If the Washington Commission determines that a capital investment is not reasonable or prudent, the costs (including return on any resulting rate base) related to such capital investment may be disallowed, partially or entirely, and not recovered in rates.
Washington state law also requires PSE to pursue electric conservation that is cost-effective, reliable and feasible. PSE’s mandate to pursue electric conservation initiatives may have a negative impact on the electric business financial performance due to lost margins from lower sales volumes as variable power costs are not part of the decoupling mechanism. The Washington Commission and Washington state law also set natural gas conservation achievement standards for PSE. The effects of achieving these standards will, however, have only a slight negative impact on natural gas business financial performance due to the natural
gas business being almost fully decoupled.
In May 2021, the Washington Governor signed legislation passed by the state legislature that would require investor-owned utilities to file a multiyear rate plan for two, three, or four years as part of a general rate case (GRC) filed with the Washington Commission on or after January 1, 2022. For the initial rate year, the legislation requires the Washington Commission to ascertain and determine the fair value for rate-making purposes of the property in service as of the date that rates go into effect. Utilities would be bound to the first and second year of a multiyear rate plan and can file for a new rate plan in years three or four. If a company earns greater than a half percent above its authorized rate of return on a regulated basis, revenues above the level must be deferred for refunds to customers or another determination
by the Washington Commission in a subsequent adjudicative proceeding. The Washington Commission must also set performance measurements to assess a natural gas or electric company operating under a multiyear rate plan.
General Rate Case Filing
PSE filed a GRC which included a three-year multiyear rate plan with the Washington Commission on January 31, 2022, requesting an overall increase in electric and natural gas rates of 13.6% and 13.0% respectively in 2023; 2.5% and 2.3%, respectively in 2024; and 1.2% and 1.8%, respectively, in 2025. PSE requested a return on equity of 9.9% in all three rate years. PSE requested an overall rate of return of 7.39% in 2023, 7.44% in 2024, and 7.49% in 2025. The filing requested recovery of forecasted plant additions through 2022 as required by RCW 80.28.425
as well as forecasted plant additions through 2025, the final year of the multiyear rate plan.
On December 22, 2022, the Washington Commission issued an order on PSE’s 2022 GRC, which approved with conditions, three settlement agreements which cover a two-year period beginning January 1, 2023. The ruling provided for a weighted cost of capital of 7.16%, or 6.62% after-tax, and a capital structure of 49.0% in common equity in 2023 and 2024, with a return on equity of 9.4%. The order also provided for an update to power costs in 2023 and 2024 and authorizes PSE to seek recovery of the costs related to the Tacoma LNG Facility concurrent with its 2023 purchased gas adjustment (PGA) filing. The LNG rate adjustment was filed with the Washington Commission on May 25, 2023 and is
pending approval, but with a revised procedural schedule extended until April 25, 2024. PSE was also allowed to file two additional trackers that will request to recover all rate base, depreciation, and operations and maintenance (O&M) expenses related to investments under the Company’s Clean Energy Implementation Plan (CEIP) and Transportation Electrification Plan. The Transportation Electrification Plan tariff was approved with an effective date of March 1, 2023. On June 6, 2023, the Washington Commission approved PSE’s CEIP, subject to conditions. The CEIP tariff was filed with the Washington Commission on July 17, 2023 and was approved on August 24, 2023.
On December
27, 2022, PSE submitted compliance filings, including an update to power costs, and revised tariff sheets to comply with the order. On January 6, 2023, the Washington Commission rejected the compliance filing, in part, and required a revised compliance filing specific to electric rates to remove an additional $135.8 million related to PSE’s recovery of projected costs related to the modeling of the CCA impacts on PSE’s use of natural gas and coal-fired resources that had been included as part of PSE's update to power costs in the compliance filing.
Natural gas rates became effective on January 7, 2023, resulting in an overall net revenue change of $70.8 million in 2023 and $19.5 million in 2024, representing increases of 6.4% and 1.65%, respectively. On January 10, 2023,
the Washington Commission accepted the revised compliance filing with electric rates going into effect on January 11, 2023. The revisions reflected an overall net revenue change of $247.0 million in 2023 and $33.1 million in 2024, which represents an increase of 10.75% and 1.33%, respectively. Per the 2022 GRC Final Order in Docket No. UE-220066, PCORC rates were set to zero as
38
of January 11, 2023 and PSE agreed not to file a PCORC during 2023 and 2024, the period covered by the two-year rate plan agreed to in the GRC settlement.
Prior rates were subject to the 2019 GRC and included a weighted cost of capital of 7.39%
or 6.8% after-tax, a capital structure of 48.5% in common equity, and a return on equity of 9.4%. The annualized overall rate impacts were an electric revenue increase of $48.3 million, or 2.3%, and a natural gas increase of $4.9 million, or 0.6%, effective October 1, 2021. For further information, see Note 4, "Regulation and Rates" in the Combined Notes to Consolidated Financial Statements included in Item 8 of the Company's Form 10-K for the period ended December 31, 2022.
Climate Commitment Act Deferral
On December 29, 2022, PSE filed accounting petitions with the Washington Commission requesting authorization to defer costs and revenues associated with the Company’s compliance with
the CCA codified in law within Revised Code of Washington (RCW) 70A.65. On February 28, 2023, in Order 01 under Docket No. UE-220974 and UG-220975, the Washington Commission granted PSE approval to defer the cost of emission allowances to comply with the CCA and the proceeds from no-cost allowances consigned to auction beginning January 1, 2023. This accounting treatment is necessary in order for PSE to defer and seek recovery of CCA costs that are not currently included in rates. As of September 30, 2023, PSE deferred $144.2 million and $67.2 million of CCA compliance costs for natural gas and electric liabilities, respectively and PSE recorded $108.5 million related to the proceeds from the sale of consigned GHG emission allowances. For further details, see Note 7, "Regulation and Rates," in the Combined Notes
to Consolidated Financial Statements included in Item 1 of this report.
Revenue Decoupling Adjustment Mechanism
While fluctuations in weather conditions will continue to affect PSE's billed revenue and energy supply expenses from month to month, PSE's decoupling mechanisms, Schedule 142 tariffs, assist in mitigating the impact of weather on operating revenue and net income. The Washington Commission has allowed PSE to record a monthly adjustment to its electric and natural gas operating revenues related to electric transmission and distribution, natural gas operations and general administrative costs and fixed production costs from most residential, commercial and industrial customers to mitigate the effects of abnormal weather, conservation impacts and changes in usage patterns per customer. As a result, these electric and natural gas revenues
are recovered on a per customer basis regardless of actual consumption levels. PSE's energy supply costs, which are part of the power cost adjustment (PCA) and PGA mechanisms, are not included in the decoupling mechanism. The revenue recorded under the decoupling mechanisms will be affected by customer growth and not actual consumption except for fixed production costs, which are held at the level of cost from the most recent rate proceeding and are not impacted by customer growth. Following each calendar year, PSE will recover from, or refund to, customers the difference between allowed decoupling revenue and the corresponding actual revenue during the following May to April time period.
On January 6, 2023, the Washington Commission approved the natural gas 2022 GRC filing. As part of this filing, the annual gas delivery allowed revenue was updated to reflect changes in
the approved revenue requirement. Additionally, the Commission approved the removal of the earnings test from the decoupling mechanism in accordance with RCW 80.28.425(6). The changes took effect on January 7, 2023.
On January 10, 2023, the Washington Commission approved the electric 2022 GRC filing. As part of this filing, the annual electric delivery and fixed power cost allowed revenue was updated to reflect changes in the approved revenue requirement. Additionally, the Commission approved the removal of the earnings test from the decoupling mechanism in accordance with RCW 80.28.425(6). The changes took effect on January 11, 2023.
On September 30, 2023, PSE performed an analysis
to determine if electric and natural gas decoupling revenue deferrals would be collected from customers within 24 months of the annual period, per ASC 980. If not, for GAAP purposes only, PSE would need to record a reserve against the decoupling revenue and corresponding regulatory asset balance. Once the reserve is probable of collection within 24 months from the end of the annual period, the reserve can be recognized as decoupling revenue. Based on the analyses, no reserve adjustment was recorded as of September 30, 2023 and 2022.
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The Washington Commission approved the following PSE requests to change rates for prior deferrals under its electric and natural
gas decoupling mechanisms:
1 For electric and natural gas rates effective May 1, 2023, May 1, 2022 and May 1, 2021, there were no excess earnings that impacted the approved revenue change.
2 For the electric rates effective May 1, 2022, there was $8.0 million of excess deferred revenues for delivery and fixed power costs which could not be set in rates until May 1, 2023 due to
the 3% rate cap.
3 For the electric rates effective May 1, 2021, there was $24.1 million of excess deferred revenues for delivery and fixed power costs which could not be set in rates until May 1, 2022 due to the 3% rate cap.
4 The 2019 GRC final order lengthened the recovery period from the original one-year recovery to a two-year recovery of April 2022. The remaining decoupling amortization balances for delivery and fixed power costs of $1.7 million were included in electric decoupling mechanism tariff rates, effective May 1, 2022.
Electric Rates
The
following electric rate schedules were filed with the Washington Commission or approved by the Washington Commission after the Form 10-K for the period ended December 31, 2022 was filed on February 23, 2023 along with the comparison period, if applicable. For further information on prior filings, see Management's Discussion and Analysis, "Regulation of PSE Rates and Recovery of PSE Costs" included in Item 7 of the Company's Form 10-K for the period ended December 31, 2022.
Bill Discount Rate Rider
The Schedule 129D rider tariff implements surcharges to collect the costs incurred by the Company in providing the rate discounts specified in Schedule 7BDR, including administrative costs approved
in Docket No. UE-230692.
The following table sets forth bill discount rate adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective dates:
The Schedule 141CEI tariff implements surcharges to collect the costs incurred and associated with the Company’s CEIP. This schedule will recover the costs associated with the Company’s approved CEIP in Docket No. UE-210795 that are not recovered in the other tariff schedules.
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The
following table sets forth clean energy implementation tracker rate adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective dates:
The Schedule 120 tariff electric conservation rider collects revenue to cover the costs incurred in providing services and programs for conservation. Rates change annually on May 1 to collect the annual budget that started the prior January and to true-up for actual compared to forecast conservation expenditures from the
prior year, as well as actual compared to the forecasted load set in rates.
The following table sets forth conservation rider rate adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective dates:
Effective Date
Average Percentage Increase (Decrease) in Rates
Increase (Decrease) in Revenue (Dollars in Millions)
The Schedule 129 low income tracker tariff recovers changes in costs for the low income bill payment assistance program as approved in Docket No. UE-011570. The annual filing requests these changes through the existing low income program funding mechanism previously approved by the Washington Commission. The mechanism allows PSE to periodically adjust its electric rates to reflect
changes in actual sales and costs. Rates change annually on October 1. Included in the electric rate effective October 1, 2022, is the recovery of $25.6 million from the COVID-19 bill assistance program established in Docket No. U-200281 and deferred under the accounting petition approved in Docket No. UE-200780.
The following table sets forth the low income program funding adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE's revenue based on the effective dates:
PSE updated its Schedule 95 tariff rates in the Power Cost Adjustment Clause tariff to reflect the transition fee as required by Section 12 of the Special Contract, a non-prescribed commercial/industrial
rate contract. Additionally, Schedule 95 rates also include portions of fixed power cost adjustments per the allowed decoupling rate re-allocation resulting from a Special Contract customer becoming a transportation customer as well as small variable power cost adjustments.
PSE exceeded the $20.0 million cumulative deferral balance in its PCA mechanism in 2022. During 2022, actual power costs were higher than baseline power costs, thereby, creating an under-recovery of $110.1 million. Under the terms of the PCA’s sharing mechanism for under-recovered power costs, PSE absorbed $39.0 million of the under-recovered amount, and customers were responsible for the remaining $71.1 million, or $76.4 million including interest and adjusted for revenue
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sensitive
items. On April 28, 2023, PSE filed the 2022 PCA report under Docket No. UE-230313 that proposed a recovery of the deferred balance, which included a revenue requirement increase of 0.9% in overall bill for all customers, with rates proposed to go into effect from December 1, 2023 through December 31, 2024.
PSE also exceeded the $20.0 million cumulative deferral balance in its PCA mechanism in 2021, as actual power costs were higher than baseline power costs, thereby, creating an under-recovery of $68.0 million. PSE absorbed $31.3 million of the under-recovered amount, and customers were responsible for the remaining $36.7 million, or $38.4 million including interest. In October 2022, the Washington Commission approved PSE's 2021 PCA report that proposes to recover the deferred
balance for 2021 PCA period by keeping the current rates and allowing recovery from January 1, 2023 through November 30, 2023.
On September 29, 2023, PSE filed its variable power cost rates update as part of the 2022 GRC Order requirement under Docket No. UE-220066. The filing, which is pending approval from the Washington Commission, is set to be effective January 1, 2024 through December 31, 2024.
The following table sets forth the variable power cost rates update and Schedule 95 Supplemental PCA mechanism approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue
based on the effective dates:
Effective Date
Average Percentage Increase (Decrease) in Rates
Increase (Decrease) in Revenue (Dollars in Millions)
1 The
Schedule 95 Supplemental PCA mechanism rates from the prior year that recover the 2022 imbalance (effective December 1, 2023).
Power Cost Adjustment Mechanism
PSE currently has a PCA mechanism, Schedule 95 Supplemental tariff, that provides for the deferral of power costs that vary from the “power cost baseline” level of power costs. The “power cost baseline” levels are set, in part, based on normalized assumptions about weather and hydroelectric conditions. Excess power costs or savings are apportioned between PSE and its customers pursuant to the graduated scale set forth in the PCA mechanism and will trigger a surcharge or refund when the cumulative deferral trigger is reached.
Effective January
1, 2017, the following graduated scale is used in the PCA mechanism:
Company's Share
Customers’ Share
Annual Power Cost Variability
Over
Under
Over
Under
Over
or under collected by up to $17 million
100%
100%
—%
—%
Over or under collected by between $17 million - $40 million
35
50
65
50
Over or under collected beyond $40 + million
10
10
90
90
For
the nine months ended September 30, 2023, in its PCA mechanism, PSE over recovered its allowable costs by $66.2 million of which $38.5 million was apportioned to customers and $3.6 million of interest was accrued on the deferred customer balance. This compares to an under recovery of allowable costs of $12.5 million for the nine months ended September 30, 2022, of which zero was apportioned to customers and $1.0 million of interest was accrued on the total deferred customer balance.
Property Tax Tracker
The purpose of the Schedule 140 tariff property tax tracker is to pass through the cost of all property taxes incurred by the Company. The mechanism acts as a tracker rate schedule and collects the total amount of property taxes assessed. The
tracker is adjusted each year in May based on that year's assessed property taxes and true-up from the prior year.
42
The following table sets forth property tax tracker mechanism rate adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective dates:
Effective Date
Average Percentage Increase (Decrease) in
Rates
Increase (Decrease) in Revenue (Dollars in Millions)
The residential exchange program, Schedule 194, passes through the residential exchange program benefits that PSE
receives from the Bonneville Power Administration (BPA). Rates change biennially.
The following table sets forth residential exchange benefit adjustments approved by the Washington Commission in Docket No. UE-230792 and UE-210757 and the corresponding expected annual impact on PSE’s revenue based on the effective dates:
Effective Date
Average
Percentage
Increase (Decrease)
in
Rates
Increase (Decrease) in Revenue (Dollars in Millions)
The purpose of this schedule is to recover costs approved during a
multiyear rate plan period that are not subject to refund and that are above the level of base rates set in the multiyear rate plan as authorized and approved in Docket No. UE-220066 and UE-230320.
The following table sets forth rates not subject to refund rate adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective dates:
The purpose of this schedule is to charge customers the provisionally approved rates subject to refund approved in a multiyear rate plan, for property granted provisional approval for recovery as authorized and approved in Docket No. UE-220066 and UE-230320.PSE will file an annual review March 31st of each year, which will be reviewed by the Washington Commission.
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The following table sets forth rates subject to refund rate adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective dates:
The following natural gas rate schedules were filed with the Washington Commission or approved by the Washington Commission after the Form 10-K for the period ended December 31, 2022 was filed on February 23, 2023 along with the comparison period, if applicable. For further information on prior filings, see Management's Discussion and Analysis, "Regulation of PSE Rates and Recovery of PSE Costs" included in Item 7 of the Company's Form 10-K for the period ended December
31, 2022.
Bill Discount Rate Rider
The purpose of the Schedule 129D tariff bill discount rate rider is to collect the costs incurred by the Company in providing the rate discounts specified in Schedule 23BDR, including administrative costs approved in Docket No. UG-230693.
The following table sets forth bill discount rate adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective dates:
Effective
Date
Average Percentage Increase (Decrease) in Rates
Increase (Decrease) in Revenue (Dollars in Millions)
Climate Commitment Act - Greenhouse Gas Emissions Cap and Invest Adjustment
The Schedule 111 tariff is to implement a surcharge to recover the costs and to provide benefits through credits to certain customers from the Company’s implementation of Washington
State greenhouse gas (GHG) emission cap and invest program as prescribed by the CCA and codified in law within RCW 70A.65.
On June 9, 2023, PSE filed with the Washington Commission under Docket No. UG-230470 a proposal to recover the estimated ongoing allowance costs during the period of August through December 2023. Concurrently, PSE proposed to pass back credits to customers from estimated auction proceeds to be received in 2023, proportionally over the same period. Overall, the proposal included a new revenue requirement of $104.7 million related to the Washington state carbon reduction charge, mitigated by a new revenue requirement decrease of $87.9 million related to the Washington state carbon reduction credit, with an effective date of October 1, 2023.
On October
26, 2023, the Washington Commission approved PSE's request for CCA rates in Docket No. UG-230756, effective November 1, 2023. PSE requested cost recovery of the CCA allowance costs that have been or will be deferred from January 2023 through September 2023 (“the deferral period”). This tariff filing also apportions auction proceeds to be received by PSE in the latter half of 2023 to the deferral period to be passed back to customers as an offset to the CCA allowance costs. The establishment of these deferrals is consistent with the approved accounting petitions in Dockets No. UG-220975 and UG-230471, as part of this filing PSE requested an annual revenue increase of $27.2 million.
44
The following table
sets forth the GHG emissions cap and invest adjustment approved by the Washington Commission and the corresponding expected annual impact on PSE's revenue based on the effective dates:
Effective Date
Average Percentage Increase (Decrease) in Rates
Increase (Decrease) in Revenue (Dollars in Millions)
The Schedule 120 tariff natural gas conservation rider collects revenue to cover the costs incurred in providing services and programs for conservation. Rates change annually on May 1 to collect the annual budget that started the prior January and to true-up for actual compared to forecast conservation expenditures from the prior year, as well as actual compared to the forecasted
load set in rates.
The following table sets forth conservation rider rate adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE's revenue based on the effective dates:
Effective Date
Average Percentage Increase (Decrease) in Rates
Increase (Decrease) in Revenue (Dollars in Millions)
The Schedule 129 low income tracker tariff recovers changes in costs for the low income bill payment assistance program as approved in Washington Commission Docket No. UG-011571. The annual filing requests these changes through the existing low income program funding mechanism previously approved by the Washington Commission. The mechanism allows PSE to periodically adjust its natural
gas rates to reflect changes in actual sales and costs. Rates change annually on October 1.
The following table sets forth the low income program funding adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE's revenue based on the effective dates:
Effective Date
Average Percentage Increase (Decrease) in Rates
Increase (Decrease) in Revenue (Dollars in Millions)
The purpose of the Schedule 140 tariff property tax tracker mechanism is to pass through the cost of all property
taxes incurred by the Company. The mechanism removed property taxes from general rates and included those costs for recovery in an adjusting tariff rate. After the implementation, the mechanism acts as a tracker rate schedule and collects the total amount of property taxes assessed. The tracker is adjusted each year in May based on that year's assessed property taxes and true-up from the prior year.
45
The following table sets forth property tax tracker mechanism rate adjustments approved by the Washington Commission and the corresponding impact on PSE's revenue based on the effective dates:
Effective
Date
Average Percentage Increase (Decrease) in Rates
Increase (Decrease) in Revenue (Dollars in Millions)
PSE has PGA mechanisms, Schedule
101 and Schedule 106 tariffs, that allow PSE to recover expected natural gas supply and transportation costs and defer, as a receivable or liability, any natural gas supply and transportation costs that exceed or fall short of this expected natural gas cost amount in PGA mechanism rates, including accrued interest. PSE is authorized by the Washington Commission to accrue carrying costs on PGA receivable and payable balances. A receivable or payable balance in the PGA mechanism reflects an under recovery or over recovery, respectively, of natural gas cost through the PGA mechanism. Rates typically change annually on November 1, although out-of-cycle rate changes are allowed at other times of the year if needed.
In October 2021, the Washington Commission approved PSE's request for November 2021 PGA rates in Docket No. UG-210721, effective November 1, 2021. As part of that
filing, PSE requested an annual revenue increase of $59.1 million; where PGA rates, under Schedule 101, increase annual revenue by $80.6 million, and the tracker rates under Schedule 106, decrease annual revenue by $21.5 million. The annual 2021 PGA rate increases were in addition to continuing the collection on the remaining balance of $69.4 million under Supplemental Schedule 106B, which were set, in effect, through September 30, 2023 per the 2019 GRC.
In October 2022, the Washington Commission approved PSE's request for PGA rates in Docket No. UG-220715, effective November 1, 2022. As part of that filing, PSE requested an annual revenue increase of $155.3 million; where PGA rates, under Schedule 101, increase annual revenue by $142.1 million, and the tracker rates under Schedule 106, increase annual revenue by $13.2 million.
In
November 2022, the Federal Energy Regulatory Commission (FERC) approved a settlement of a counterparty, FERC Docket No. RP17-346. Under the terms, PSE was allocated $24.2 million related to PSE natural gas services, which was recorded on December 31, 2022 and included in the table below. The 2022 GRC order requires PSE to amortize the refund in 2023 as a credit against natural gas costs and therefore pass back the refund to customers through the PGA mechanism.
On October 26, 2023, the Washington Commission approved PSE's request for PGA rates in Docket No. UG-230769, effective November 1, 2023. As part of that filing, PSE requested an annual revenue decrease of $309.4 million, where PGA rates, under Schedule 101, decrease annual revenue by $93.9 million, and the tracker rates
under Schedule 106, decrease annual revenue by $215.5 million. The annual 2023 PGA rate decreases include a counterparty settlement pass back of $28.1 million under Supplemental Schedule 106B.
The purpose of this schedule is to recover costs approved during a multiyear rate plan period that are not subject to refund and that are above the level of base rates set in the multiyear rate plan
as authorized and approved in Docket No. UG-220067 and Docket No. UG-230323.
46
The following table sets forth rates not subject to refund rate adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective dates:
The purpose of the Schedule 141R tariff is to charge customers the provisionally approved rates subject to refund approved in a multiyear rate plan, for property granted provisional approval for recovery as authorized and approved in Docket No. UG-220067 and Docket No. UG-230323.
The following table sets forth rates subject to refund rate adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective dates:
For additional information, see Note 7, "Regulation and Rates" in the Combined Notes to Consolidated Financial Statements included in Item 1 of this report.
Access to Debt Capital
PSE relies on access to bank borrowings and short-term money markets as sources of liquidity and longer-term capital markets to fund its utility construction program, to meet maturing debt obligations
and other capital expenditure requirements not satisfied by cash flow from its operations or equity investment from its parent, Puget Energy. Neither Puget Energy nor PSE have any debt outstanding whose maturity would accelerate upon a credit rating downgrade. However, a ratings downgrade could adversely affect the Company's ability to refinance existing or issue new long-term debt, obtain access to new or renew existing credit facilities and increase the cost of issuing long-term debt and maintaining credit facilities. For example, under Puget Energy's and PSE's credit facilities, the borrowing costs increase as their respective credit ratings decline due to increases in credit spreads and commitment fees. If PSE is unable to access debt capital on reasonable terms, its ability to pursue improvements or generating capacity acquisitions, which may be relied on for future growth and to otherwise implement its strategy, could be adversely affected. PSE monitors the
credit environment and expects to continue to be able to access the capital markets to meet its short-term and long-term borrowing needs.
Regulatory Compliance Costs and Expenditures
PSE's operations are subject to extensive federal, state and local laws and regulations. These regulations cover electric system reliability, natural gas pipeline system safety and energy market transparency, among other areas. Environmental laws and regulations related to air and water quality, including climate change and endangered species protection, waste handling and disposal (including generation by-products such as coal ash), remediation of contamination and siting new facilities also impact the Company's operations. PSE must spend significant resources to fulfill requirements set by regulatory agencies, many of which have greatly expanded mandates
on measures including resource planning, remediation, monitoring, pollution control equipment and emissions-related abatement and fees.
In 2021, the Washington Legislature adopted the CCA, which establishes a GHG emissions cap-and-invest program that caps GHG emissions beginning on January 1, 2023 and makes further reductions to the cap annually through 2050. The
47
Washington Department of Ecology (WDOE) published final regulations to implement the program on September 29, 2022, which became effective on October 30, 2022. WDOE also indicated that it will have subsequent rulemakings
that will build off initial rulemaking as program implementation gets underway and progress with Washington State carbon goals are evaluated. For further details on the CCA see Part I Item 1 "Recent and Future Environmental Law and Regulation" in the Company’s Annual Report on Form 10-K for the year ended December 31, 2022. Based on the rules passed in 2022, there is potential for PSE’s compliance with the CCA to result in increased costs to customers or amounts that PSE may not be able to recover through electric and natural gas rates. Potential risks associated with CCA compliance could include: the evolving nature of the CCA rulemaking as indicated by WDOE, market uncertainty based on rule interpretation during implementation, unresolved recovery methodology for CCA’s impact on energy costs, company costs, customer rate impacts, and cash, liquidity and credit volatility. Such risks associated with the CCA
are evaluated by PSE for potential impacts to the estimated liability to comply with the program as well as the likelihood that may make a loss contingency both probable and reasonably estimable. Management’s assessment to determine whether a loss is probable or reasonably possible and to whether a loss or range of losses is estimable often involves judgement.
Compliance with these or other future regulations, such as those pertaining to climate change, could require significant capital expenditures by PSE and may adversely affect PSE's financial position, results of operations, cash flows and liquidity.
Other Challenges and Strategies
Competition
PSE’s
electric and natural gas utility retail customers generally do not have the ability to choose their electric or natural gas supplier; therefore, PSE’s business has historically been recognized as a natural and regulated monopoly. However, PSE faces competition from public utility districts and municipalities or efforts by citizens organizing to form such entities that want to establish their own government-owned utility, as a result of which PSE may lose a number of customers. PSE also faces increasing competition for sales to its retail customers through alternative methods of electric energy generation, including solar and other self-generation methods. In addition, PSE’s natural gas customers may elect to use heating oil, propane or other fuels instead of using and purchasing natural gas from PSE.
Results
of Operations
Puget Sound Energy
The following discussion should be read in conjunction with the unaudited consolidated financial statements and the related notes included elsewhere in this document. The following discussion provides the significant items that impacted PSE’s results of operations for the three months and nine months ended September 30, 2023 and September 30, 2022.
Non-GAAP Financial Measures - Electric and Natural Gas Margins
The following discussion includes financial information prepared in accordance with GAAP, as well as two other financial measures, electric margin and natural 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 includes adjustments that result in a presentation that is not defined by GAAP. The presentation of electric margin and natural gas margin is intended to supplement an understanding of PSE’s operating performance. Electric margin and natural gas margin are used by PSE to determine whether PSE is collecting the appropriate amount of revenue from its customers in order to provide adequate recovery of operating costs, including interest and equity returns. PSE’s electric margin and natural gas margin measures may not be comparable to other companies’ electric margin and natural 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.
48
The
following table presents operating income and a reconciliation of utility electric and natural gas margins to the most directly comparable GAAP measure, operating income:
Unrealized gain (loss) on derivative instruments, net
21,695
(62,709)
(201,230)
59,939
Utility
operation and maintenance
(179,630)
(157,246)
(549,118)
(488,479)
Non-utility expense and other
(3,342)
(10,673)
(18,076)
(35,329)
Depreciation
and amortization
(210,666)
(190,174)
(648,002)
(573,934)
Taxes other than income taxes
(73,638)
(71,099)
(297,534)
(278,458)
Operating
income (loss)
$
66,466
$
(24,637)
$
199,179
$
399,113
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Electric Margin
Electric
margin represents electric sales to retail and transportation customers less the cost of generating and purchasing electric energy sold to customers, including transmission costs, to bring electric energy to PSE's service territory.
The following chart displays the details of PSE's electric margin changes for the three months ended September 30, 2023 and 2022:
Electric operating revenues increased $56.3 million from the prior year primarily due to an increase in electric retail sales of $37.8 million, an increase in sales to other utilities of $38.3 million, an increase in decoupling revenue of $11.1 million, and an increase in other decoupling revenue of $7.9 million, partially offset by a decrease in transportation and other revenue of $38.8 million. These items are discussed in detail below.
•Electric retail sales increased $37.8 million due to an increase of $66.2 million in rates compared to the prior year and partially offset by $28.4 million from a decrease in retail electricity usage of 4.5%. The
increase in rates is primarily due to the tariffs filed pursuant to the Company's most recent GRC effective January 11, 2023. See "Regulation of PSE Rates and Recovery of PSE Costs" included in this Item 2 of this report and Part II, Item 7, Management's Discussion and Analysis, "Regulation of PSE Rates and Recovery of PSE Costs" included in the Company's Annual Report on Form 10-K for the period ended December 31, 2022 for electric rate changes. The decrease in retail usage was primarily due to a decrease in residential and industrial usage of 7.7% and 8.1%, respectively. Customer usage decreased due to a decrease in cooling degree days of 12.3% from lower temperatures in the three months ended September 30, 2023 as compared to 2022.
•Sales
to other utilities increased $38.3 million primarily due to a 84.8% increase in wholesale sales volume partially offset by a 30.5% decrease in electric wholesale sales price. Higher wholesale sales volumes were the result of increased volume from natural gas-fired generation, which increased 54.3% for the three months ended September 30,
50
2023 compared to 2022. Lower natural gas fuel prices made natural gas-fired generation more economic to dispatch for the three months ended September 30, 2023 compared to 2022.
•Decoupling revenue increased $11.1 million driven by increases in delivery and fixed production
cost (FPC) deferral revenues of $6.1 million and $4.9 million, respectively. This was primarily due to decreased usage and higher allowed rates per customer in the three months ended September 30, 2023 compared to 2022. As a result, actual electric revenues were higher than allowed decoupling deferral revenues by a smaller margin in the three months ended September 30, 2023 compared to 2022.
•Other decoupling revenue increased $7.9 million due to increased amortization rates for prior year overcollection deferrals and decreased amortization rates for undercollection deferrals in the three months ended September 30, 2023 compared to 2022. A higher percentage of amortization related to prior year overcollection resulted in more revenue
recognized in the three months ended September 30, 2023 compared to 2022.
•Transportation and other revenue decreased $38.8 million primarily due to a $42.2 million decrease in net wholesale non-core natural gas sales, which was partially offset by an increase of $3.7 million due to an IRS Private Letter Ruling in 2022, which included amortization to offset recovery through rates in 2022. The decrease in net wholesale non-core natural gas sales was driven by a $25.9 million decrease in wholesale non-core natural gas sales due to a 54.7% decrease in the average price of the natural gas sales. This decrease was partially offset by a $21.6 million decrease in the cost of the gas sold due to a lower average cost of natural gas sold. Additionally, the decrease in net wholesale natural gas sales was also driven by a $38.0 million increase
in natural gas financial hedging losses.
Electric Power Costs
Electric power costs increased $16.4 million primarily due to an increase of electric generation fuel costs of $22.2 million partially offset by a decrease of $7.0 million of purchased electricity costs. These items are discussed in detail below.
•Purchased electricity expense decreased $7.0 million primarily due to decreased wholesale purchase prices, which were 4.8% lower than in the three months ended September 30, 2023 compared to 2022, driven by open market purchases. The decrease from wholesale purchase prices was partially offset by a 2.2% increase in wholesale electricity purchase volumes.
•Electric
generation fuel increased $22.2 million primarily due to a $21.9 million increase in natural gas fuel costs as a result of increased production from PSE natural gas-fired generation, which increased 54.3% for the three months ended September 30, 2023 compared to 2022. Higher costs from increased production were partially offset by lower natural gas prices, which drove a 19.1% decrease in lower average unit production costs.
51
The following chart displays the details of PSE's electric margin changes for the nine months ended September 30, 2023 and 2022:
Electric operating revenues increased $396.4 million from the prior year primarily due to an increase in sales to other utilities of $204.9 million, an increase in electric retail sales of $183.7 million, an increase in other decoupling revenue of $19.8 million and an increase in decoupling revenue of $4.7 million, partially offset by a decrease in transportation and other revenue of $16.8 million. These items are discussed in detail below.
•Electric retail sales
increased $183.7 million due to an increase of $210.8 million in rates compared to the prior year partially offset by a decrease of $27.1 million due to load from a decrease in retail electricity usage of 1.3%. The increase in rates is primarily due to the tariffs filed pursuant to the Company's most recent GRC effective January 11, 2023. See "Regulation of PSE Rates and Recovery of PSE Costs" included in this Item 2 of this report and Part II, Item 7, Management's Discussion and Analysis, "Regulation of PSE Rates and Recovery of PSE Costs" included in the Company's Annual Report on Form 10-K for the period ended December 31, 2022 for electric rate changes. The decrease in retail usage was primarily due to a decrease in residential and industrial usage of 2.4% and 4.6%, respectively. Customer usage decreased due to a decrease in heating and cooling degree
days of 6.8% and 2.8%, respectively, in the nine months ended September 30, 2023 as compared to 2022.
•Sales to other utilities increased $204.9 million primarily due to a 119.9% increase in wholesale sales volume due to increased volume from PSE natural gas-fired generation, which increased 98.2% in the nine months ended September 30, 2023 compared to 2022. Lower natural gas fuel prices made natural gas-fired generation more economic to dispatch in the nine months ended September 30, 2023 compared to 2022.
52
•Decoupling
revenue increased $4.7 million driven by an increase in FPC deferral revenue of $12.2 million, partially offset by a decrease in delivery deferral revenues of $7.5 million. The decrease in delivery deferral revenue was primarily driven by increased actual rates, whereas the increase in FPC deferral revenue was primarily driven by decreased usage. Higher actual rates caused actual delivery revenue to be higher than allowed revenue by a greater margin in the nine months ended September 30, 2023 as compared to 2022. Decreased usage caused actual FPC revenue to be higher than allowed revenue by a smaller margin in the nine months ended September 30, 2023 as compared to 2022.
•Other decoupling revenue increased $19.8 million primarily due to changes in amortization
rates. In the current period, prior year overcollection deferrals from residential customers were amortized at a higher rate compared to the same period in 2022. A higher percentage of amortization related to prior year overcollection results in more revenue recognized in the current period. This was partially offset by a $3.0 million decrease related to GAAP alternative revenue program recognition guidelines. As of the period ended September 30, 2022, there were $3.0 million of deferred 2021 GAAP alternative decoupling revenues that were recognized. There were no such revenues recognized in 2023.
•Transportation and other revenue decreased $16.8 million primarily due to a $30.1 million decrease in net wholesale non-core natural gas sales, which was partially offset by an increase of $12.3 million was due to an IRS Private Letter
Ruling in 2022, which included amortization to offset recovery through rates in 2022 and a $2.5 million deferral for over recovery of 2023 Green Direct energy credits approved in the 2022 GRC. The decrease in net wholesale non-core gas sales was driven by a $20.2 million decrease in wholesale non-core natural gas sales due to a 21.3% decrease in the average price of the natural gas sales. This decrease was offset by a $33.1 million decrease in the cost of natural gas sold due to a lower average cost. Additionally, the decrease in net wholesale natural gas sales was also driven by a $43.0 million increase in natural gas financial hedging losses.
Electric Power Costs
Electric power costs increased $240.4 million primarily due to an increase of electric generation fuel costs of $129.4 million and an increase of $109.7 million
of purchased electricity costs. These items are discussed in detail below.
•Purchased electricity expense increased $109.7 million primarily due to increased wholesale purchase prices, which were 21.9% higher in the nine months ended September 30, 2023 compared to the same period in 2022, driven by open market purchases as well as new power purchase agreements beginning after March 31, 2022. The increase from wholesale purchase prices were partially offset by an 5.4% decrease in wholesale electricity purchase volumes.
•Electric generation fuel increased $129.4 million primarily due to a $126.9 million increase in natural gas fuel costs as a result of a 98.2% increase in PSE natural gas-fired
generation. Higher costs from increased production were partially offset by lower natural gas prices which drove a 11.9% decrease in average unit production costs.
53
Natural Gas Margin
Natural gas margin is natural gas sales to retail and transportation customers less the cost of natural gas purchased, including transportation costs to bring natural gas to PSE’s service territory. The PGA mechanism passes through increases or decreases in the natural gas supply portion of the natural gas service rates to customers 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 margin or net income is not affected by changes under the PGA mechanism because over- and under-recoveries of natural gas costs included in baseline PGA rates are deferred and either refunded to or collected from customers in future periods.
The following chart displays the details of PSE's natural gas margin changes for the three months ended September 30, 2023 and 2022:
Natural gas operating revenue increased $32.6 million primarily due to increases in retail sales of $30.0 million, decoupling revenue of $1.7 million, and other decoupling revenue of $1.5 million. These items are discussed in detail below.
•Natural gas retail sales revenue increased $30.0 million primarily due to an increase in rates of $22.5 million and an increase of $7.5 million driven by an increase in natural gas load of 4.3%. The increase in rates is primarily due to the tariffs filed pursuant to the Company's most recent PGA and GRC effective November
1, 2022 and January 7, 2023, respectively. See "Regulation of PSE Rates and Recovery of PSE Costs" included in this Item 2 of this report and Part II, Item 7, Management's Discussion and Analysis, "Regulation of PSE Rates and Recovery of PSE Costs" included in the Company's Annual Report on Form 10-K for the period ended December 31, 2022 for natural gas rate changes. The increase in load is primarily driven by a 6.6% and 2.5% increase in residential and commercial usage, respectively. Customer usage increased due to an increase in heating degree days of 126.4% from lower temperatures in the three months ended September 30, 2023 as compared to 2022.
54
•Decoupling
revenue increased $1.7 million primarily attributable to higher allowed rates in the current period compared to the same period in 2022, which resulted in allowed natural gas revenues being higher than actual natural gas revenues by a greater margin in the current period than in same period of 2022.
•Other decoupling revenue increased $1.5 million due to increased amortization rates for prior year overcollection deferrals and decreased amortization rates for undercollection deferrals compared to the same period in 2022. A higher percentage of amortization related to prior year overcollection results in more revenue recognized in the current period.
Natural Gas Energy Costs
•Purchased natural gas
expense increased $18.2 million due to an increase in the PGA rates in November 2022 and an increase in natural gas usage of 4.3% as stated in the natural gas retail sales section above. See "Regulation of PSE Rates and Recovery of PSE Costs" included in this Item 2 of this report for natural gas rate changes and details on the PGA.
55
Natural Gas Margin
The following chart displays the details of PSE's natural gas margin changes for the nine months ended September 30, 2023 and 2022:
Natural gas operating revenue increased $157.6 million primarily due to increases in retail sales of $143.8 million, other decoupling revenue of $6.8 million, and decoupling revenue of $6.1 million. These items are discussed in detail below.
•Natural gas retail sales revenue increased $143.8 million primarily due to an increase in rates of $165.5 million partially offset by a decrease of $21.6 million due to a decrease in natural gas load of 2.1%. The increase
in rates is primarily due to the tariffs filed pursuant to the Company's most recent PGA and GRC effective November 1, 2022 and January 7, 2023, respectively. See "Regulation of PSE Rates and Recovery of PSE Costs" included in this Item 2 of this report and Part II, Item 7, Management's Discussion and Analysis, "Regulation of PSE Rates and Recovery of PSE Costs" included in the Company's Annual Report on Form 10-K for the period ended December 31, 2022 for natural gas rate changes. The decrease in load is primarily driven by a 3.4% and 0.5% decrease in residential and commercial usage, respectively. Customer usage decreased due to a decrease in heating degree days of 6.8% from higher temperatures in the nine months ended September 30, 2023 as compared to
2022.
•Decoupling revenue increased $6.1 million primarily due to decreased usage and higher allowed rates in the current period compared to the same period in 2022. This resulted in allowed natural gas revenues being higher than actual natural gas revenues, whereas in the prior period, allowed revenues were lower than actual revenues.
•Other decoupling revenue increased $6.8 million due to increased amortization rates for prior year overcollection deferrals and decreased amortization rates for undercollection deferrals compared to the same period in 2022. A higher percentage of amortization related to prior year overcollection results in more revenue recognized in the current period.
56
Natural
Gas Energy Costs
•Purchased natural gas expense increased $98.8 million due to an increase in the PGA rates in November 2022 partially offset by a decrease in natural gas usage of 2.1% as stated in the natural gas retail sales section above. See "Regulation of PSE Rates and Recovery of PSE Costs" included in this Item 2 of this report for natural gas rate changes and details on the PGA.
57
Other
Operating Expenses and Other Income (Deductions)
The following chart displays the details of PSE's operating expenses and other income (deductions) for the three months ended September 30, 2023 and 2022:
•Net unrealized (gain) loss on derivative instruments changed $84.4 million to a net gain of $21.7 million for the three months ended September
30, 2023. The primary driver was the net settlements of natural gas trades previously recorded at a loss of $97.2 million, partially offset by electric trades previously recorded as a $20.7 million gain. Although electric and natural gas prices decreased, resulting in a $30.0 million loss for natural gas, the electric price decrease was offset by two winter capacity PPAs executed in late September 2022, resulting in a $38.0 million gain for electric. For further details, see Note 4, "Accounting for Derivative Instruments and Hedging" in the Combined Notes to Consolidated Financial Statements included in Item 1 of this report.
•Utility operations and maintenance expense increased $22.4 million primarily due to increases in the following: (i) $5.0 million in customer service expense due to increased low-income assistance, (ii) $4.7 million in administrative and general
expenses related to the CEIP and other strategic projects, (iii) $3.5 million in credit card processing fees, call center related expense, and collections and uncollectible accounts expenses, (iv) $2.6 million increase in distribution maintenance expense related to higher overhead line maintenance, (v) $2.4 million related to injuries and damages expense and (vi) $1.3 million in pension related expenses.
•Non-utility expense and other expense decreased $7.4 million primarily driven by a decrease of $7.2 million in biogas purchase expense primarily due to a decrease in biogas volume purchased in the three months ended September 30, 2023 compared to 2022.
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•Depreciation
and amortization expense increased $20.5 million due to: (i) $10.0 million increase in electric amortization from 2022 primarily driven by a $4.9 million increase in the Lower Snake River treasury grant amortization and $3.1 million addition of 2022 storm costs amortized in 2023, (ii) $7.0 million increase in natural gas distribution depreciation from 2022 primarily due to $219.4 million in net additions in natural gas distribution assets, (iii) $3.2 million increase in electric production depreciation from 2022 primarily due to $72.0 million in net additions of electric production assets, and (iv) $2.8 million increase in electric distribution depreciation from 2022 primarily due to $308.9 million in net additions of electric distribution assets. These increases were partially offset by a $2.0 million decrease in conservation amortization due to a decrease in conservation rider rates effective May
1, 2023, (see "Regulation of PSE Rates and Recovery of PSE Costs" included in this Item 2 of this report).
•Taxes other than income taxes increased $2.5 million primarily due to an increase of $3.7 million in municipal taxes which was driven by the increase in retail revenue in the three months ended September 30, 2023 as compared to 2022. The increase was partially offset by a decrease of $1.5 million in property taxes.
Other Income, Interest Expense and Income Tax Expense
•Other income/expense increased$5.9 million from net other income of $7.9 million in 2022 to net other income of $13.8 million
in 2023, due to an increase of $6.4 million in other income and a decrease of $0.5 million in other expense. The increase in other income was primarily due to: (i) $4.3 million increase in taxable interest and dividend income driven by increases to PCA customer interest and interest earned on short-term investments of excess cash and (ii) $3.2 million increase in allowance for funds used during construction (AFUDC) due to an increase in eligible CWIP. The increase in other income was partially offset by a decrease of $2.6 million in Advanced Metering Infrastructure (AMI) due to a change in AMI return deferral per the 2022 GRC.
•Interest expense increased $6.6 million primarily due to an increase of $5.4 million in interest expense due to the May 2023 PSE bond issuance and an increase of $2.9 million related to interest expense recognized on the PGA liability.
•Income
tax expense increased $9.2 million primarily driven by an increase in pre-tax book income.
59
Other Operating Expenses and Other Income (Deductions)
The following chart displays the details of PSE's operating expenses and other income (deductions) for the nine months ended September 30, 2023 and 2022:
•Net unrealized (gain) loss on derivative instruments changed $261.2 million to a net loss of $201.2 million for the nine months ended September 30, 2023. The primary driver was the change in the weighted average forward prices for electric and natural gas, which resulted in a decrease of $274.7 million. Specifically, electric prices decreased 74.5% resulting in $83.0 million in loss for electric and natural gas prices decreased 57.6% resulting in a $183.1 million loss for natural gas. Partially offsetting the decrease from the change in weighted average forward prices was the net settlement of electric trades and natural gas trades, which resulted in a net increase of $4.8 million. Specifically,
the net settlement of electric trades previously recorded as gains resulted in a $60.8 million decrease and the net settlement of natural gas trades previously recorded as loss resulted in a $65.6 million increase. For further details, see Note 4, "Accounting for Derivative Instruments and Hedging" in the Combined Notes to Consolidated Financial Statements included in Item 1 of this report.
•Utility operations and maintenance expense increased $60.6 million primarily due to increases in the following: (i) $16.7 million in customer service expense due to increased low-income assistance, (ii) $8.1 million in outside consulting fees related to corporate strategic planning, (iii) $5.1 million in major plant maintenance amortization expense, (iv) $4.9 million in pension related expenses, (v) $4.9 million related to injuries and damages expense, (vi) $4.6 million in administrative
and general expenses related to the CEIP and other strategic projects, (vii) $4.2 million in credit card processing fees and call center related expenses, (viii) $3.3 million in higher electric safety, training, crew standby, and other administrative expenses and (ix) $2.8 million increased generation operations expense and consumable costs. These increases were partially offset by a $5.6 million decrease in wind turbine maintenance in the nine months ended September 30, 2023 as compared to 2022
•Non-utility expense and other expense decreased $17.4 million primarily due to a decrease of $14.2 million in biogas
60
purchase expense,
driven by a decrease in both biogas volume purchased and average biogas price; and a decrease of $3.5 million in the long-term incentive plan, as compared to 2022, due to an increase in 2022 funding compared to 2023.
•Depreciation and amortization expense increased $74.1 million due to: (i) $33.9 million increase in electric amortization from 2022 primarily driven by a $15.9 million increase in the Lower Snake River treasury grant amortization and a $9.0 million addition of 2022 storm cost amortized in 2023, (ii) $20.3 million increase in natural gas distribution depreciation from 2022 primarily due to $219.4 million in net additions in natural gas distribution assets, (iii) $8.1 million increase in electric distribution depreciation from 2022 primarily due to $308.9 million in net additions of electric distribution assets, (iv) $7.5 million increase in electric production depreciation
from 2022 primarily due to $72.0 million in net additions of electric production assets, (v) $6.4 million increase in conservation amortization due to an increase in conservation rider rates effective May 1, 2022, (see "Regulation of PSE Rates and Recovery of PSE Costs" included in this Item 2 of this report) and (vi) $5.3 million increase in natural gas amortization from 2022 primarily driven by a $3.4 million increase in Get To Zero natural gas tranche amortization. These increases were partially offset by a $3.9 million decrease in electric general plant and other depreciation from 2022 primarily driven by a $3.9 million decrease in asset retirement costs in 2023 compared to 2022.
•Taxes other than income taxes increased $19.1 million primarily due to a $14.0 million increase in municipal taxes and an increase of $10.7
million in state excise taxes, both of which were driven by the increase in retail revenue in 2023 as compared to 2022. The increases were partially offset by a decrease of $5.3 million in property taxes.
Other Income, Interest Expense and Income Tax Expense
•Other income/expense increased$14.9 million from net other income of $22.2 million in 2022 to net other income of $37.1 million in 2023, due to an increase of $13.6 million in other income and a decrease of $1.3 million in other expense. The increase in other income was primarily due to (i) $9.9 million in taxable interest and dividend income due to an increase in PCA customer interest and interest earned on short-term investments of excess cash, (ii) $7.2 million of AFUDC due to an increase
in eligible CWIP, (iii) $4.9 million in the non-service cost component of the qualified pension net periodic benefit cost for 2023 compared to 2022 and (iv) $2.3 million in gain on corporate life insurance policies. The increase in other income was partially offset by a decrease of $7.7 million in AMI due to a change in AMI return deferral per the 2022 GRC.
•Interest expense increased $14.4 million primarily due to: (i) an increase of $8.1 million in interest expense due to the May 2023 PSE bond issuance, (ii) an increase of $6.0 million related to interest expense recognized on the PGA liability, and (iii) an increase of $2.6 million related to interest expense recognized in conjunction with PSE's deferred compensation liability. These increases were partially offset by a decrease of $1.8 million in monetized PTC interest expense.
•Income
tax expense decreased $27.8 million primarily driven by a decrease in pre-tax book income.
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Puget
Energy
Primarily, all operations of Puget Energy are conducted through PSE. Puget Energy's net income (loss) for the three months ended September 30, 2023 and 2022 is as follows:
Puget Energy’s net income increased by $88.4 million. This is primarily attributable to an increase in PSE's net income of $81.2 million.and
a decrease in tax expense of $5.8 million due to the annualized effective tax rate method that results in a lower consolidated effective tax rate in 2023.
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Puget Energy's net income (loss) for the nine months ended September 30, 2023 and 2022 is as follows:
Puget Energy’s net income decreased by $193.3 million, which is primarily attributable to (i) a decrease in PSE's net income of $171.5 million, (ii) an increase in income tax expense of $22.2 million primarily driven by the unrealized gains and losses of net settlements on electric and natural gas trades, which decreased Puget Energy's effective tax rate in 2023 compared to 2022, (iii) a $4.6 million decrease in other income due to a decrease in pension non service cost and (iv) an increase in net loss of $1.3 million at Puget LNG due to additional operational expenses. These decreases were partially offset by a decrease in interest expense of $6.4 million primarily due to an increase of $8.5 million of Puget LNG interest expense, which is eliminated in the consolidated results for Puget Energy.
Capital
Requirements
Contractual Obligations and Commercial Commitments
In addition to the contractual obligations and consolidated commercial commitments disclosed in the Company's Annual Report on Form 10-K for the year ended December 31, 2022, during the nine months ended September 30, 2023, the Company entered into new Electric Portfolio and Electric Wholesale Market Transaction contracts with estimated payment obligations totaling $4.2 billion through 2051.
On September 20, 2023, PSE entered into a tolling agreement to purchase the energy and capacity associated with a 132.5MW facility. The tolling agreement represents a lease to PSE, and is expected to commence in October 2025. PSE expects
the future minimum lease payments to be $91.0 million over the five year period beginning in October 2025.
For further information, see Part II, Item 8, Note 16, "Commitments and Contingencies" in the Company's Annual Report on Form 10-K for the year ended December 31, 2022.
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Off-Balance Sheet Arrangements
As of September 30, 2023, the Company had no off-balance sheet arrangements that have or are reasonably likely to have a material effect on the Company's financial condition.
Utility
Construction Program
The Company’s construction programs for generating facilities, the electric transmission system, the natural gas and electric distribution systems and the Tacoma LNG facility are designed to meet regulatory requirements, support customer growth and improve energy system reliability. The Company had adjusted capital expenditures, resulting in an increase of $27.0 million compared to forecasted amounts for the nine months ended September 30, 2023. The increase was primarily due to (i) higher new customer construction projects and public improvement work specific to natural gas operations, (ii) timing of electric major projects specific to substation and transmission line work, (iii) timing of electric operations projects driven by pole replacements and electric first response construction efforts during the second and third quarter, (iv) timing of electric
reliability initiatives driven by cable remediation projects and (v) timing of the Lower Baker Dam grouting project expenditures. Construction expenditures, excluding equity AFUDC, totaled $875.4 million for the nine months ended September 30, 2023. Presently planned utility construction expenditures, excluding equity AFUDC, are as follows:
Capital Expenditure Projections
(Dollars
in Millions)
2023
2024
2025
Total energy delivery, technology and facilities expenditures
$1,146.7
$1,311.9
$1,304.2
The program is subject to change based upon general business, economic and regulatory conditions. Utility construction expenditures and any new generation resource expenditures may be funded from a combination of sources, which may include cash from operations, short-term
debt, long-term debt and/or equity. PSE’s planned capital expenditures may result in a level of spending that will exceed its cash flow from operations. As a result, execution of PSE’s strategy is dependent in part on continued access to capital markets.
Capital Resources
Cash from Operations
Puget
Sound Energy
Nine Months Ended September 30,
(Dollars in Thousands)
2023
2022
Change
Net income
$
42,403
$
213,950
$
(171,547)
Non-cash
items1
674,298
429,194
245,104
Changes in cash flow resulting from working capital2
99,922
38,038
61,884
Regulatory
assets and liabilities
134,755
11,210
123,545
Purchased gas adjustment
174,840
8,509
166,331
GHG emission allowances
(112,037)
—
(112,037)
Other
non-current assets and liabilities3
(42,545)
(26,034)
(16,511)
Net cash provided by operating activities
$
971,636
$
674,867
$
296,769
_______________
1 Non-cash
items include depreciation, amortization, deferred income taxes, net unrealized (gain) loss on derivative instruments, AFUDC-equity, production tax credits (PTCs) and other miscellaneous non-cash items.
2 Changes in working capital include receivables, unbilled revenue, materials/supplies, fuel/gas inventory, income taxes, prepayment, PGA, accounts payable and accrued expenses.
3 Other non-current assets and liabilities include funding of pension liability.
Cash generated from operations for the nine months ended September 30, 2023
increased by $296.8 million including a net income decrease of $171.5 million. The following are significant factors that impacted PSE's cash flows from operations:
•Cash flow adjustments resulting from non-cash items increased $245.1 million primarily due to: (i) a $261.2 million change from a net unrealized gain on derivative instruments of $59.9 million to a net unrealized loss on
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derivative instruments of $201.2 million, (ii) an increase in depreciation and amortization of $67.6 million, (iii) an increase of $6.4 million in conservation amortization and (iv) a $2.4 million increase due to deferral of energy exchange cost. The increases were partially offset by: (i) a decrease
in deferred income taxes of $87.0 million, and (ii) equity AFUDC of $7.1 million. For further details, see "Other Operating Expenses" in this Item 2 of this report.
•Cash flows resulting from changes in working capital increased $61.9 million primarily due to: (i) a cash inflow of $241.6 million due to the timing of accounts receivable collections, as the balance of account receivable decreased $368.1 million in the nine months ended September 30, 2023 compared to a decrease of $126.5 million during the same period in 2022, (ii) an increase of $44.8 million due to higher tax payable balance, and (iii) an increase of $40.4 million related to fuel and natural gas inventory, which increased $4.4 million in the nine months ended September 30, 2023 compared to a $44.8 million
increase during the same period in 2022 due to a continued decrease in natural gas prices since peaking in August 2022. The increases were partially offset by: (i) accounts payable decreased faster than the same period last year that led to increased cash outflows of $250.4 million, (ii) an increased cash outflow of $8.2 million related to higher incentive payments, and (iii) higher balances in materials and supplies increased cash outflow of $6.2 million.
•Cash flows resulting from regulatory assets and liabilities increased $123.5 million, which was primarily related to $108.4 million cash proceeds received from the sale of consigned GHG emission allowances, which is required to be returned to customers. In addition, a $12.5 million increase was related to major maintenance and major inspections at several generation stations in 2022, which led to higher cash outflow in the
nine months ended September 30, 2022 compared to the same period in 2023.
•Cash flow resulting from purchased gas adjustment increased $166.3 million, which was mainly driven by a decrease in actual natural gas cost and an increase in allowed PGA recovery in the nine months ended September 30, 2023 compared to 2022. Decreased natural gas prices led to a $40.1 million, or 13.5%, decrease in actual natural gas costs in the nine months ended September 30, 2023 compared to 2022. Meanwhile, the total amount of allowed PGA recovery in the nine months ended September 30, 2023 increased $98.3 million, or 32.2%, compared to 2022. In addition, there was a $27.9 million refund and interest
from a counterparty settlement received in January 2023.
•Cash flow resulting from GHG emission allowances decreased $112.0 million which was driven by obtaining Washington emission allowances for GHG emissions associated with the company's electric and natural gas business activities in compliance with the CCA. For further details, see Management's Discussion and Analysis, "Other" in Item 2 of this report.
•Cash flow resulting from other non-current assets and liabilities decreased $16.5 million driven by a $23.5 million decrease in pension liability offset with other immaterial changes in long-term assets and liabilities.
Puget
Energy
Nine Months Ended September 30,
(Dollars in Thousands)
2023
2022
Change
Net income
$
(84,641)
$
(62,861)
$
(21,780)
Non-cash items1
57,108
34,777
22,331
Changes
in cash flow resulting from working capital2
7,844
11,380
(3,536)
Other
non-current assets and liabilities3
(1,868)
(7,008)
5,140
Net cash provided by operating activities
$
(21,557)
$
(23,712)
$
2,155
_______________
1 Non-cash
items include depreciation, amortization, deferred income taxes, net unrealized (gain) loss on derivative instruments, AFUDC-equity, PTCs and
other miscellaneous non-cash items.
2 Changes in working capital include receivables, unbilled revenue, materials/supplies, fuel/gas inventory, income taxes, prepayments, PGA, accounts payable and accrued expenses.
3 Other noncurrent assets and liabilities include funding of pension liability.
Cash generated from operations for the nine months ended September
30, 2023, in addition to the changes discussed at PSE above, increased by $2.2 million compared to the same period in 2022, which includes a net income decrease of $21.8 million. The remaining change was primarily impacted by the factors explained below:
•Non-cash items increased $22.3 million primarily due to higher non-cash inflows of $21.8 million related to changes in deferred taxes.
65
•Changes in cash flow resulting from working capital decreased $3.5 million primarily due to a $5.4 million decrease related to the change in PSE's intercompany account receivable and account payable balances with Puget LNG and Puget Energy, which
are eliminated upon consolidation of Puget Energy.
•Changes in Other non-current assets and liabilities increased $5.1 million due to $2.7 million in nonrecurring fees incurred during the nine months ended September 30, 2022 related to the Puget Energy credit facility that was entered into in May 2022.
Financing Program
The Company’s external financing requirements principally reflect the cash needs of its construction program, its schedule of maturing debt and certain operational needs. The Company anticipates refinancing the redemption of bonds or other long-term borrowings with its
credit facilities and/or the issuance of new long-term debt. Access to funds depends upon factors such as Puget Energy’s and PSE’s credit ratings, prevailing interest rates and investor receptivity to investing in the utility industry, Puget Energy and PSE. The Company believes it has sufficient liquidity through its credit facilities and access to capital markets to fund its needs over the next twelve months.
Proceeds from PSE’s short-term borrowings and sales of commercial paper are used to provide working capital and the interim funding of utility construction programs. Puget Energy and PSE continue to have reasonable access to the capital and credit markets.
As of September 30, 2023, both Puget Energy and PSE have stable outlooks from Moody’s, Fitch, and S&P. Although neither Puget Energy nor PSE have any debt whose maturity
would be accelerated upon a ratings downgrade, Management continually monitors the credit rating environment for both Puget Energy and PSE as a credit rating downgrade may increase the cost of borrowing for Puget Energy and PSE in future long-term financings or under their existing credit facilities. Any increase in the cost of borrowing could negatively impact Puget Energy and PSE's future results of operations as well as future liquidity, access to debt capital resources and financial condition. Additionally, a ratings downgrade could impact the Company's ability to issue dividends. A downgrade to Puget Energy and PSE's credit ratings would not impact debt covenants under our existing credit facilities nor would it impact other contracts, as neither include credit rating triggering event clauses. A credit rating decrease for PSE could result in increased cash collateral required for commodity contracts, which would adversely affect PSE's liquidity. Management
cannot predict with certainty the actions credit agencies may take, if any, in response to weaker near term credit metrics, regulatory and rate recovery uncertainties, and management's efforts to contain the growth of capital and operating expenditures. Containing the growth of capital and operating expenditures will be limited, over the near term, due to continuing strategic and risk mitigation imperatives and the necessity of providing safe, reliable and resilient service levels to customers.
Puget Sound Energy
Credit Facility
In May 2022, PSE entered into a new $800.0 million credit facility to replace the existing facility. The terms and conditions, including fees, financial covenant, expansion feature and credit spreads remain substantially the same. The base interest rate on loans has changed
to the Secured Overnight Financing Rate (SOFR), as the London Interbank Offered Rate (LIBOR) was discontinued on June 30, 2023. The proceeds of the PSE credit facility are to be used for general corporate purposes. The maturity date of the credit facility is May 14, 2027. The credit facility includes a swingline feature allowing same day availability on borrowings up to $75.0 million and has an expansion feature which, upon receipt of commitments from one or more lenders, could increase the total size of the facility up to $1.4 billion.
The credit agreement is syndicated among numerous lenders and contains usual and customary affirmative and negative covenants that, among other things, place limitations on PSE's ability to transact with affiliates, make asset dispositions and investments or permit liens to exist. The credit
agreement also contains a leverage ratio that requires the ratio of (a) total funded indebtedness to (b) total capitalization to be 65.0% or less at all times. PSE certifies its compliance with such covenants to participating banks each quarter. As of September 30, 2023, PSE was in compliance with all applicable covenant ratios.
The credit agreement allows PSE to borrow at a prime based rate or to make floating rate advances at the SOFR, in either case, plus a spread that is based upon PSE's credit rating. PSE must pay a commitment fee on the unused portion of the credit facility. The spreads and the commitment fee depend on PSE's credit ratings. As of the date of this report, interest was calculated as SOFR plus 0.10% SOFR adjustment plus 1.25% spread over the adjusted SOFR rate and the commitment fee was 0.175%.
As of September 30,
2023, no amount was drawn under PSE's credit facility and no amount was outstanding under the commercial paper program. Outside of the credit agreement, PSE had a $2.1 million letter of credit in support of a long-term transmission contract and had $7.0 million issued under a standby letter of credit with TD Bank in support of natural gas purchases on the natural gas exchange (NGX) in Canada.
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Demand Promissory Note
In May 2023, PSE amended and restated its revolving credit facility with Puget Energy, in the form of a credit agreement and a demand promissory note (Note) pursuant to which PSE may borrow up to $200.0 million from Puget Energy subject to approval by Puget Energy. Under
the terms of the Note, PSE pays interest based on PE's credit facility interest rate, which is SOFR plus 0.10% SOFR adjustment plus 1.75% spread over the adjusted SOFR rate. As of September 30, 2023, PSE had no outstanding balance under the Note.
Debt Restrictive Covenants
The type and amount of future long-term financings for PSE may be limited by provisions in PSE's electric and natural gas mortgage indentures.
PSE’s ability to issue additional secured debt may also be limited by certain restrictions contained in its electric and natural gas mortgage indentures. Under the most restrictive tests at September 30, 2023, PSE could issue:
•Approximately
$1.4 billion of additional first mortgage bonds under PSE’s electric mortgage indenture based on approximately $2.4 billion 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 September 30, 2023; and
•Approximately $1.0 billion of additional first mortgage bonds under PSE’s natural gas mortgage indenture based on approximately $1.7 billion of natural gas bondable property available for issuance, subject to a combined natural gas and electric interest coverage test of 1.75 times net earnings available for interest and a natural gas interest coverage test of 2.0 times net earnings available for interest (as defined in the natural gas utility mortgage), both of which PSE exceeded at September 30,
2023.
At September 30, 2023, PSE had approximately $8.7 billion in electric and natural gas rate base to support the interest coverage ratio limitation test for net earnings available for interest.
Shelf Registrations
In August 2022, PSE filed an S-3 shelf registration statement under which it may issue up to $1.4 billion aggregate principal amount of senior notes secured by first mortgage bonds. As of the date of this report, $1.0 billion was available to be issued. The shelf registration will expire in August 2025.
Dividend Payment Restrictions
The payment of dividends by PSE to Puget Energy is restricted by provisions
of certain covenants applicable to long-term debt contained in PSE’s electric and natural gas mortgage indentures. At September 30, 2023, approximately $1.6 billion of unrestricted retained earnings was available for the payment of dividends under the most restrictive mortgage indenture covenant.
Beginning February 6, 2009, pursuant to the terms of the merger order by the Washington Commission, PSE may not declare or pay dividends if PSE’s common equity ratio, calculated on a regulatory basis, is 44.0% or below except to the extent a lower equity ratio is ordered by the Washington Commission. Also, pursuant to the merger order, PSE may not declare or make any distribution unless on the date of distribution PSE’s corporate credit/issuer rating is investment grade, or, if its credit ratings are below investment grade, PSE’s ratio
of earnings before interest, tax, depreciation and amortization (EBITDA) to interest expense for the most recently ended four fiscal quarter period prior to such date is equal to or greater than 3.0 to 1.0. The common equity ratio, calculated on a regulatory basis, was 49.2% at September 30, 2023, and the EBITDA to interest expense ratio was 5.2 to 1.0 for the twelve months ended September 30, 2023.
PSE’s ability to pay dividends is also limited by the terms of its credit facilities, pursuant to which PSE is not permitted to pay dividends during any Event of Default (as defined in the facilities), or if the payment of dividends would result in an Event of Default, such as failure to comply with certain financial covenants. At September 30, 2023, the Company was in compliance
with all applicable covenants, including those pertaining to the payment of dividends.
Long Term Debt
On May 18, 2023, PSE issued $400.0 million of green senior secured notes at an interest rate of 5.448%. The notes mature on June 1, 2053 and pay interest semi-annually in arrears on June 1 and December 1 of each year, commencing December 1, 2023. Net proceeds from the issuance of the notes were deposited into the Company's general account and will be earmarked for allocation to eligible projects, as defined in PSE's sustainable financing framework, which was published in May 2023. Eligible projects are expenditures incurred and investments made related to development and acquisition of some or all of the
67
following
types of projects: (i) renewable energy, (ii) energy efficiency, (iii) clean transportation, (iv) biodiversity conservation, (v) climate change adaptation, (vi) water and wastewater management, (vii) pollution prevention and control, and (viii) green innovation.
For more information on the Company's long term debt, see Part II, Item 8, Note 7, "Long-Term Debt" and Note 8, "Liquidity Facilities and Other Financing Arrangements" in the Company's Annual Report on Form 10-K for the year ended December 31, 2022.
Puget Energy
Credit Facility
In May 2022, Puget Energy entered into a new $800.0 million credit facility to replace the existing facility. The terms and conditions, including fees, financial
covenant, expansion feature and credit spreads remain substantially the same. The base interest rate on loans has changed to the SOFR, as the LIBOR was discontinued on June 30, 2023. The proceeds of the PE credit facility are to be used for general corporate purposes. The maturity date of the credit facility is May 14, 2027. The Puget Energy revolving senior secured credit facility also has an accordion feature, upon receipt of commitments from one or more lenders, could increase the size of the facility up to $1.3 billion.
The revolving senior secured credit facility provides Puget Energy the ability to borrow based on a prime based rate or SOFR, in either case, plus a spread based on Puget Energy's credit ratings. Puget Energy must pay a commitment fee on the unused portion of the facility. As of September 30,
2023, there was $244.2 million drawn and outstanding under the facility. As of the date of this report, interest was calculated as SOFR plus 0.10% SOFR adjustment plus 1.75% spread over the adjusted SOFR rate and the commitment fee was 0.275%.
The revolving senior secured credit facility contains usual and customary affirmative and negative covenants. The credit agreement also contains a leverage ratio that requires the ratio of (a) total funded indebtedness to (b) total capitalization to be 65.0% or less at all times. As of September 30, 2023, Puget Energy was in compliance with all applicable covenants.
In September 2022, PE borrowed $50.0 million on the credit facility and contributed the proceeds to PSE as an equity contribution. The equity proceeds were used for general corporate purposes.
In
August 2023, PE borrowed $100.0 million on the credit facility and contributed the proceeds to PSE as an equity contribution. The equity proceeds will be used for general corporate purposes.
Shelf Registrations
In March 2022, Puget Energy filed an S-3 Registration statement under which it may issue up to $1.0 billion aggregate principal amount of senior notes secured by Puget Energy's assets. As of the date of this report, $550.0 million was available to be issued. The shelf registration will expire in March 2025.
Long-Term Debt
In March 2022, Puget Energy issued $450.0 million of senior secured notes at an interest rate of 4.224%. The notes mature on March 15, 2032,
and pay interest semi-annually on March 15 and September 15of each year. Proceeds from the issuance of the notes were invested in short-term money market funds, and then used to repay Puget Energy's $450.0 million 5.625% notes that were originally scheduled to mature July 2022.
In April 2022, Puget Energy redeemed the $450.0 million 5.625% senior secured notes due July 2022 and paid related expenses for a total redemption price of $457.2 million, which includes repayment of the $450.0 million principal amount and $7.2 million of accrued interest expense.
For further information, see Part II, Item 8, Note 7, "Long-Term Debt" and Note 8, "Liquidity Facilities and Other Financing Arrangements" in the Company's Annual Report on Form 10-K for the year ended December 31, 2022.
Dividend
Payment Restrictions
Puget Energy’s ability to pay dividends is also limited by the merger order issued by the Washington Commission in 2009. Pursuant to the merger order, Puget Energy may not declare or make a distribution unless on such date Puget Energy’s ratio of consolidated EBITDA to consolidated interest expense for the four most recently ended fiscal quarters prior to such date is equal to or greater than 2.0 to 1.0. Puget Energy's EBITDA to interest expense was 3.9 to 1.0 for the twelve months ended September 30, 2023.
At September 30, 2023, the Company was in compliance with all applicable covenants, including those pertaining to the payment of dividends.
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Other
New
Accounting Pronouncements
For the discussion of new accounting pronouncements, see Note 2, "New Accounting Pronouncements" in the Combined Notes to Consolidated Financial Statements included in Item 1 of this report.
Washington Clean Energy Transformation Act
In May 2019, Washington State passed the CETA, which supports Washington's clean energy economy and transitioning to a clean, affordable, and reliable energy future. The CETA requires all electric utilities to eliminate coal-fired generation from their allocation of electricity by December 31, 2025; to be carbon-neutral by January 1, 2030 through a combination of non-emitting electric generation, renewable generation, and/or alternative
compliance options; and makes it the state policy that, by 2045, 100% of electric generation and retail electricity sales will come from renewable or non-emitting resources. Clean energy implementation plans are required every four years from each investor-owned utility (IOU). The plan must propose interim targets for meeting the 2045 standard between 2030 and 2045 and describe an actionable plan that the IOU intends to pursue to meet the standard. The Washington Commission may approve, reject or recommend alterations to an IOU’s plan. The Company intends to seek recovery of any costs associated with CETA through the regulatory process. On December 17, 2021, PSE filed its Final CEIP, which proposed a plan for the implementation of CETA for 2022-2025 and project costs associated with its implementation. On June 6, 2023, the Washington Commission approved PSE’s CEIP,
subject to conditions. The CEIP tariff was filed with the Washington Commission on July 17, 2023 and approved with rates effective September 1, 2023.
Washington Climate Commitment Act
In 2021, the Washington Legislature adopted the CCA, which establishes a GHG emissions cap-and-invest program that caps GHG emissions beginning on January 1, 2023 and makes further reductions to the cap annually through 2050. The Washington Department of Ecology (WDOE) published final regulations to implement the program on September 29, 2022, which became effective on October 30, 2022. In general, the program will
require covered entities to obtain emission allowances or offset credits for covered emissions and the WDOE provides the annual allowance budget based on the cap. Allowances can be obtained through quarterly auctions, or bought and sold on a secondary market.
The CCA regulates PSE both as an electric utility and as a natural gas distribution utility. PSE is required to obtain emission allowances or offset credits for GHG emissions associated with electricity generated in or imported into the state to serve Washington State load, and all electricity generated by Washington State PSE facilities with total annual emissions exceeding 25,000 metric tons of carbon dioxide equivalent per year. As an electric utility subject to Washington’s CETA, which is discussed below, PSE will receive emission allowances at no cost through 2050 for direct emissions associated with electricity used to serve Washington State load to mitigate
impacts to ratepayers. PSE will also be required to obtain emission allowances for GHG emissions associated with natural gas supplied to customers and any facilities associated with its natural gas system with total facility emissions that exceed 25,000 metric tons of carbon dioxide equivalent per year. PSE will receive some emission allowances to cover its natural gas obligation at no cost to mitigate impacts to customers; the amount will be based on a percentage of baseline emissions (determined from 2015 - 2019 natural gas system related emissions) that will decline to mitigate rate impacts to certain natural gas customers. Offset credit use is limited and the WDOE will reduce the cap proportionally for any offsets used. In the first compliance period, 2023-2026, participating entities can cover up to 5% of their emissions with offset credits, and can cover an additional 3% with credits from projects on federally recognized Tribal lands. In the second compliance
period, 2027-2030, the general limit drops to 4%, with an additional 2% from projects on Tribal lands.
Related Party Transactions
In August 2015, PSE filed a proposal with the Washington Commission to develop a LNG facility at the Port of Tacoma. The Tacoma LNG facility provides peak-shaving services to PSE’s natural gas customers, and provides LNG as fuel to transportation customers, particularly in the marine market. Following a mediation process and the filing of a settlement stipulation by PSE and all parties, the Washington Commission issued an order on October 31, 2016, that allowed PSE’s parent company, Puget Energy, to create a wholly-owned subsidiary, named Puget LNG, which was formed on November 29, 2016, for the sole purpose of owning,
developing and financing the non-regulated activity of the Tacoma LNG facility. Puget LNG has entered into one fuel supply agreement with a maritime customer and is marketing the facility’s output to other potential customers.
In February 2022, the Tacoma LNG facility at the Port of Tacoma completed commissioning and commenced commercial operations. Pursuant to the Commission’s order, Puget LNG is allocated approximately 57.0% of the capital and operating costs of the Tacoma LNG facility and PSE will be allocated the remaining 43.0% of the capital and operating costs. PSE and
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Puget LNG are considered related parties with similar ownership by Puget Energy. Therefore, capital and operating costs that occur under PSE and are
allocated to Puget LNG are related party transactions by nature. Per this allocation of costs, $241.8 million of non-utility plant and $20.3 million of operating costs related to Puget LNG's portion of the Tacoma LNG facility are reported in the Puget Energy "Other property and investments" and "Non-utility expense and other" financial statement line items, respectively, as of September 30, 2023. The portion of the Tacoma LNG facility allocated to PSE is subject to regulation by the Washington Commission.
Integrated Resource Plans, Resource Acquisition and Development
The 2021 Integrated Resource Plan marked a major departure from past Integrated Resource Plans (IRP) due in large part to the passage of CETA. The new electric progress report rules, Washington Administrative
Code 480-100-625 Integrated Resource Plan Development and Timing, outlines the requirements for this report. The two-year progress report must be filed at least every two years after the utility files it’s IRP. The final 2023 Electric Progress Report and the Gas Utility IRP were filed on March 31, 2023.
On February 10, 2023 the FERC approved a voluntary regional resource adequacy program that PSE plans to participate in along with other utilities in the Western United States and Canada. The program is intended to help the region anticipate its future power supply needs as natural gas-fired and coal power plants retire and are replaced by variable renewable energy resources such as wind and solar.
For further information, see Part I, Item I “Integrated Resource Plans, Resource
Acquisition and Development” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2022.
Environmental Remediation
The Company is subject to federal and state requirements for protection of the environment, including those for release of hazardous materials and remediation of contaminated sites. A potentially responsible party has joint and several liability under existing U.S. environmental laws. In instances where we have been designated a potentially responsible party by the Environmental Protection Agency or state environmental agency, we are potentially liable for the cost of remediating contamination at current work sites and former work sites. Such sites include former manufactured gas plants operated by PSE predecessors, such as Gas Works Park on the shore
of Lake Union in Seattle, or contaminated facilities with other connections to PSE predecessors, such as the location of a long-defunct creosote manufacturer which had purchased waste products from PSE predecessors, the Quendall Terminals site on Lake Washington in Renton, Washington. In each case, PSE assesses, based on in-depth studies, expert analyses and legal reviews, our environmental remediation obligations related to contaminated sites, including assessments of ranges and probabilities of recoveries from other responsible parties and/or insurance carriers. PSE develops a range of reasonably estimable costs that includes a low and high end of a range for all remediation sites for which we have sufficient information. There are some potential remediation obligations where the costs of remediation cannot be reasonably estimated. Liabilities are recorded based on the best estimate or the low end of a range of reasonably possible costs expected to be incurred
to remediate sites. It is possible that costs are incurred in excess of the recorded amounts because of changes in laws and/or regulations, higher than expected costs and/or the discovery of new or additional contamination. The Company believes a significant portion of its past and future environmental remediation costs are recoverable from insurance companies, from third parties or from customers under a Washington Commission order.
For additional information see Item 8, Note 4, "Regulation and Rates" to the consolidated financial statements included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2022.
Human Capital
Information regarding the Company’s human capital measures and objectives is contained in the Environmental,
Social and Governance (ESG) report that can be found on the Company’s website, www.pse.com. The information on the Company’s website is not, and will not be deemed to be a part of this Quarterly Report on Form 10-Q or incorporated into the Company’s other filings with the SEC.
Other Legal Matters
On October 3, 2022, a putative class-action complaint was filed against PSE in the Pierce County Superior Court of Washington, alleging violations of state wage-and-hour laws. Subsequently, PSE removed the case from state court to the U.S. District Court for the Western District of Washington. Class has not been certified and the plaintiff currently seeks remand back to state court. The
case is in early stages of discovery and due to the inherent difficult of predicting the course of legal action relating to this class-action allegation, such as eventual scope, duration or outcome, the Company is currently unable to estimate the amount or range of any potential loss that could result from an unfavorable outcome arising from this matter.
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Item 3. Quantitative and Qualitative Disclosure about Market Risk
The Company is exposed to various forms of market risk, consisting primarily of adverse
changes in commodity prices, counterparty credit risk, as well as interest rate risk. PSE actively manages market risk and maintains risk policies and procedures designed to discourage unauthorized risk-taking, reduce commodity price volatility, and manage the various risks inherent to the energy portfolio. There have been no material changes to market risks affecting the Company from those set forth in Part II, Item 7A - "Quantitative and Qualitative Disclosures about Market Risk" in the Company’s Annual Report on Form 10-K for the year ended December 31, 2022.
Commodity Price Risk
The nature of serving regulated electric and natural gas customers with its portfolio of owned and contracted electric generation resources exposes PSE and its customers to some volumetric and commodity price
risks. PSE’s Energy Risk Management Committee establishes energy risk management policies and procedures to manage commodity and volatility risks and the related effects on credit, tax, accounting, financing and liquidity.
PSE's objective is to minimize 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. PSE hedges open natural gas and electric positions to reduce both the portfolio risk and the volatility risk in prices.
Counterparty Credit Risk
PSE 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. PSE manages credit risk with policies and procedures for counterparty analysis and measurement, monitoring and mitigation of exposure. Additionally, PSE has entered into commodity master arrangements (i.e., WSPP, Inc. (WSPP), International Swaps and Derivatives Association (ISDA) or North American Energy Standards Board (NAESB)) with its counterparties to mitigate credit exposure.
Interest Rate Risk
The Company believes its interest rate risk primarily relates to the use of short-term debt instruments, variable-rate leases and anticipated long-term debt financing needed to fund capital requirements. The Company manages its interest rate risk through the issuance of mostly fixed-rate debt with varied maturities. The Company utilizes internal cash from operations and borrowings under its commercial paper program,
and its credit facilities to meet short-term funding needs. During periods of financial market or interest rate volatility, the Company may utilize its credit facilities for short term funding needs instead of the commercial paper program. Credit facility borrowings are based on a more stable base rate and the credit spread is fixed. Short-term obligations are commonly refinanced with fixed-rate bonds or notes when needed and when interest rates are considered favorable. The Company may also enter into swaps or other financial hedge instruments to manage the interest rate risk associated with the debt.
Item 4. Controls and Procedures
Puget Energy
Evaluation
of Disclosure Controls and Procedures
Under the supervision and with the participation of Puget Energy’s management, including the President and Chief Executive Officer and 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 September 30, 2023, the end of the period covered by this report. Based upon that evaluation, the President and Chief Executive Officer 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 September 30, 2023 that have materially affected, or are reasonably likely to materially affect, Puget Energy’s internal control over financial reporting.
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Puget Sound Energy
Evaluation of Disclosure Controls and Procedures
Under the supervision and with the participation of PSE’s management, including the President and Chief Executive Officer and 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 September 30,
2023, the end of the period covered by this report. Based upon that evaluation, the President and Chief Executive Officer 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 September 30, 2023 that have materially affected, or are reasonably likely to materially affect, PSE’s internal control over financial reporting.
PART II OTHER INFORMATION
Item
1. Legal Proceedings
Contingencies arising out of the Company's normal course of business existed as of September 30, 2023. Litigation is subject to numerous uncertainties and the Company is unable to predict the ultimate outcome of these matters. For details on legal proceedings, see Note 8, "Commitments and Contingencies" in the Combined Notes to Consolidated Financial Statements included in Item 1 of this report and see "Other Legal Matters" included in this Item 2 of this report.
Given the size of the Company's operations, we have elected to adopt a threshold of $1.0 million in expected sanctions related to required disclosures of environmental proceedings to which the government is a party. As of the date of this filing, we are not aware of
any matters that exceed this threshold and meet the definition for disclosure.
Item 1A. Risk Factors
There have been no material changes from the risk factors set forth in Part I, Item 1A, "Risk Factors" in the Company's Annual Report on Form 10-K for the year ended December 31, 2022. Although the Company has not been materially affected, the following represents an ongoing risk that the Company continues to monitor.
Natural disasters such as wildfires and catastrophic events, including terrorist acts, may adversely affect PSE's business and expose the Company
to liability. Events such as wildfires, earthquakes, floods, tornadoes and other extreme weather events, explosions, vandalism, terrorist acts, and other similar occurrences, could damage PSE's operational assets, including utility facilities, information technology infrastructure, distributed generation assets and pipeline assets. Such events could likewise damage the operational assets of PSE's suppliers or customers. These events could disrupt PSE's ability to meet customer requirements, significantly increase PSE's response costs, cause reputational harm and significantly decrease PSE's revenues. Unanticipated events or a combination of events, failure in resources needed to respond to events, or a slow or inadequate response to events may have an adverse impact on PSE's operations, financial condition, and results of operations.
Wildfires and other natural disasters affecting PSE's infrastructure
may expose PSE to liability for personal injury, loss of life, and property damage. The risk of catastrophic and severe wildfires has increased in the western U.S. giving rise to the potential for large damage claims against utilities for fire-related losses. Climate change may worsen hot and dry summer conditions, which increase the likelihood and magnitude of damages that may be caused by fires burning into or allegedly originating from PSE’s equipment. Wildfires alleged to have been caused by PSE's transmission, distribution, or generation infrastructure, or that allegedly result from PSE’s or its contractors’ operating or maintenance practices, could expose PSE to claims for fire suppression and clean-up costs, evacuation costs, fines and penalties, and liability for economic damages, personal injury, loss of life, property damage, and environmental pollution, whether based on claims of negligence, trespass, or otherwise.
PSE
maintains insurance coverage for natural disasters and catastrophic events like wildfires, sabotage and terrorism, but insurance coverage is subject to the terms and limitations of the available policies and may not be sufficient in scope or amount to cover PSE’s ultimate liability. The availability of insurance coverage may be limited or may result in higher deductibles, higher premiums, and more restrictive policy terms. Coverage limits within insurance policies could result in material self-insured costs if there are events that are not covered by PSE’s insurance policies. PSE may be unable to fully recover costs in excess of insurance through customer rates or regulatory mechanisms and, even if such recovery is possible, it could take several years to collect. If the amount of insurance is insufficient or otherwise unavailable, and if PSE is unable to fully recover in rates the costs of uninsured losses, PSE’s financial condition, results of operations, or cash
flows could be materially affected.
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Item 5. Other Information
During the three months ended September 30, 2023, none of the Company’s directors or officers (as defined in Rule 16a-1(f) of the Securities Exchange Act of 1934) iiadopted/,
iiterminated/ or modified a Rule 10b5-1 trading arrangement or non-Rule 10b5-1 trading arrangement (as such terms are defined in Item 408 of Regulation S-K of the Securities Act of 1933).
Item
6. Exhibits
Included in the Exhibit Index are a list of exhibits filed as part of this Quarterly Report on Form 10-Q.
Financial statements from the Quarterly Report on Form 10-Q of Puget Energy, Inc. and Puget Sound Energy, Inc. for the quarter ended September
30, 2023 filed on November 1, 2023 formatted in Inline XBRL: (i) the Consolidated Statement of Income (Unaudited), (ii) the Consolidated Statements of Comprehensive Income (Unaudited), (iii) the Consolidated Balance Sheets (Unaudited), (iv) the Consolidated Statements of Cash Flows (Unaudited), (v) the Consolidated Statements of Common Shareholder's Equity (Unaudited), and (vi) the Notes to Consolidated Financial Statements
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Cover Page Interactive Data File (embedded within the Inline XBRL document).
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.
