UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
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☒ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 20202022 or
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☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from _____ to _____
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001-03280 |
(Commission File Number) |
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Public Service Company of Colorado |
(Exact name of registrant as specified in its charter) |
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Colorado | | 84-0296600 |
(State or Other Jurisdiction of Incorporation or Organization) | | (I.R.S.IRS Employer Identification No.) |
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1800 Larimer, Suite 1100 | Denver | Colorado | | 80202 |
(Address of Principal Executive Offices) | | (Zip Code) |
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303 | 571-7511 |
(Registrant’s Telephone Number, Including Area Code) |
Securities registered pursuant to Section 12(b) of the Act: | | | | | | | | | | | | | | |
Title of each class | | Trading SymbolSymbol(s) | | Name of each exchange on which registered |
N/A | | N/A | | N/A |
Securities registered pursuant to sectionSection 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. ☒ Yes ☐ No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. ☐ Yes ☒ No
Indicate by check mark whether the registrant (1) has 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) has been subject to such filing requirements for the past 90 days. ☒ Yes ☐ No
Indicate by check mark whether the registrant has 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). ☒ Yes ☐ No
Indicate by check mark whether the registrant is 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”, “smaller reporting company”, and “emerging growth company” in Rule 12b-2 of the Exchange Act. ☐ Large accelerated filer ☐ Accelerated filer ☒ Non-accelerated filer ☐ Smaller reporting company ☐ Emerging growth company
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. ☐
IndicateIndicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C.7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). ☐ Yes ☒ No
As of Feb. 17, 2021,23, 2023, 100 shares of common stock, par value $0.01 per share, were outstanding, all of which were held by Xcel Energy Inc., a Minnesota corporation.
DOCUMENTS INCORPORATED BY REFERENCE
The information required by Item 14 of Form 10-K is set forth under the heading “Independent Registered Public Accounting Firm – Audit and Non-Audit Fees” in Xcel Energy Inc.’s definitive Proxy Statement for the 20212023 Annual Meeting of Shareholders which definitive Proxy Statement is expected to be filed with the SEC on or about April 6, 2021. 11, 2023.Such information set forth under such heading is incorporated herein by this reference hereto.
Public Service Company of Colorado meets the conditions set forth in General Instructions I(1)(a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format permitted by General Instruction I(2).
TABLE OF CONTENTS
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PART I | | |
Item 1 — | | |
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Item 1A — | | |
Item 1B — | | |
Item 2 — | | |
Item 3 — | | |
Item 4 — | | |
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PART II | | |
Item 5 — | | |
Item 6 — | | |
Item 7 — | | |
Item 7A — | | |
Item 8 — | | |
Item 9 — | | |
Item 9A — | | |
Item 9B — | | |
Item 9C — | | |
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PART III | | |
Item 10 — | | |
Item 11 — | | |
Item 12 — | | |
Item 13 — | | |
Item 14 — | | |
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PART IV | | |
Item 15 — | | |
Item 16 — | | |
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This Form 10-K is filed by Public Service Company of Colorado (PSCo).PSCo. PSCo is a wholly owned subsidiary of Xcel Energy Inc. Additional information on Xcel Energy is available in various filings with the Securities and Exchange Commission.SEC. This report should be read in its entirety.
PART I
Definitions of Abbreviations
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Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former) |
e prime | e prime inc. |
NSP-Minnesota | Northern States Power Company, a Minnesota corporation |
NSP-Wisconsin | Northern States Power Company, a Wisconsin corporation |
PSCo | Public Service Company of Colorado |
SPS | Southwestern Public Service Company |
Utility subsidiaries | NSP-Minnesota, NSP-Wisconsin, PSCo and SPS |
WYCO | WYCO Development, LLC |
Xcel Energy | Xcel Energy Inc. and its subsidiaries |
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Federal and State Regulatory Agencies |
CPUC | Colorado Public Utilities Commission |
DOT | United States Department of Transportation |
EPA | United States Environmental Protection Agency |
FERC | Federal Energy Regulatory Commission |
IRS | Internal Revenue Service |
NERC | North American Electric Reliability Corporation |
PHMSA | Pipeline and Hazardous Materials Safety Administration |
SEC | Securities and Exchange Commission |
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Electric, Purchased Gas and Resource Adjustment Clauses |
CEPA | Colorado Energy Plan Adjustment |
DSM | Demand side management |
DSMCA | DSM cost adjustment |
ECA | Retail electric commodity adjustment |
FCA | Fuel clause adjustment |
GCA | Gas cost adjustment |
PCCA | Purchased capacity cost adjustment |
PSIA | Pipeline system integrity adjustment |
RES | Renewable energy standard |
RESA | RES adjustment |
SCA | Steam cost adjustment |
TCA | Transmission cost adjustment |
WCA | Wind cost adjustment |
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Other |
ADIT | Accumulated deferred income taxes |
AFUDC | Allowance for funds used during construction |
ALJ | Administrative Law Judge |
AMT | Alternative minimum tax |
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ARO | Asset retirement obligation |
ASC | FASBFinancial Accounting Standards Codification |
ASU | FASBBoard Accounting Standards Update |
Boulder | City of Boulder, COCodification |
C&I | Commercial and Industrial |
CACJA | Clean Air Clean Jobs Act |
CCR | Coal combustion residuals |
CCR Rule | Final rule (40 CFR 257.50 - 257.107) published by the EPA regulating the management, storage and disposal of CCRs as a nonhazardous waste |
CEO | Chief executive officer |
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CFO | Chief financial officer |
CIG | Colorado Interstate Gas Company, LLC |
COVID-19 | Novel coronavirus |
CWA | Clean Water Act |
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CWIP | Construction work in progress |
ELG | Effluent limitations guidelines |
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ETR | Effective tax rate |
FASB | Financial Accounting Standards Board |
GAAP | Generally accepted accounting principles |
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GHG | Greenhouse gas |
IPP | Independent power producing entity |
IRA | Inflation Reduction Act |
ISO | Independent System Operator |
ITC | Investment tax credit |
MDL | Multi-district litigation |
MGP | Manufactured gas plant |
Moody’s | Moody’s Investor Services |
Native load | Customer demand of retail and wholesale customers whereby a utility has an obligation to serve under statute or long-term contract |
NAV | Net asset value |
NOL | Net operating loss |
NOPR | Notice of proposed rulemaking |
O&M | Operating and maintenance |
PFAS | Per- and PolyFluoroAlkyl Substances |
Post-65 | Post-Medicare |
PPA | Purchased power agreement |
Pre-65 | Pre-Medicare |
PTC | Production tax credit |
REC | Renewable energy credit |
ROE | Return on equity |
ROU | Right-of-use |
RTO | Regional Transmission Organization |
S&P | Standard & Poor’s Global Ratings |
SERP | Supplemental executive retirement plan |
SPP | Southwest Power Pool, Inc. |
S&PTCA | Standard & Poor’s Global RatingsTransmission cost adjustment |
TCJA | 2017 federal tax reform enacted as Public Law No: 115-97, commonly referred to as the Tax Cuts and Jobs Act |
VaR | Value at Risk |
VIE | Variable interest entity |
WOTUSWACC | WatersWeighted Average Cost of the U.S.Capital |
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Measurements |
Bcf | Billion cubic feet |
KV | Kilovolts |
KWh | Kilowatt hours |
MMBtu | Million British thermal units |
MW | Megawatts |
MWh | Megawatt hours |
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Forward-Looking Statements |
Except for the historical statements contained in this report, the matters discussed herein are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements, including future sales, future bad debt expense, future operating performance, estimated base capital expenditures and financing plans, projected capital additions and forecasted annual revenue requirements with respect to rider filings and expectations regarding regulatory proceedings, as well as assumptions and other statements are intended to be identified in this document by the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” “will,” “would” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made and we expressly disclaim any obligation to update any forward-looking information.
The following factors, in addition to those discussed elsewhere in this Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2020 (including risk factors listed from time to time by PSCo in reports filed with the SEC, including “Risk Factors” in Item 1A of this Annual Report on Form 10-K hereto), could cause actual results to differ materially from management expectations as suggested by such forward-looking information: uncertainty around the impacts and duration of the COVID-19 pandemic; operational safety; successful long-term operational planning; commodity risks associated with energy markets and production; rising energy prices and fuel costs; qualified employee work force and third-party contractor factors; ability to recover costs; changes in regulation; reductions in our credit ratings and the cost of maintaining certain contractual relationships; general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of PSCo and its subsidiaries to obtain financing on favorable terms; availability or cost of capital; our customers’ and counterparties’ ability to pay their debts to us; assumptions and costs relating to funding our employee benefit plans and health care benefits; tax laws; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; seasonal weather patterns; changes in environmental laws and regulations; climate change and other weather; natural disaster and resource depletion, including compliance with any accompanying legislative and regulatory changes; and costs of potential regulatory penalties.
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Where to Find More Information |
PSCo is a wholly owned subsidiary of Xcel Energy Inc., and Xcel Energy’s website address is www.xcelenergy.com. Xcel Energy makes available, free of charge through its website, its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after the reports are electronically filed with or furnished to the SEC. The SEC maintains an internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically at http://www.sec.gov. The information on Xcel Energy’s website is not a part of, or incorporated by reference in, this annual report on Form 10-K.
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Forward-Looking Statements |
Except for the historical statements contained in this report, the matters discussed herein are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements, including those relating to future sales, future expenses, future tax rates, future operating performance, estimated base capital expenditures and financing plans, projected capital additions and forecasted annual revenue requirements with respect to rider filings, expected rate increases to customers, expectations and intentions regarding regulatory proceedings, and expected impact on our results of operations, financial condition and cash flows of resettlement calculations and credit losses relating to certain energy transactions, as well as assumptions and other statements are intended to be identified in this document by the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” “will,” “would” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we expressly disclaim any obligation to update any forward-looking information. The following factors, in addition to those discussed elsewhere in this Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2022 (including risk factors listed from time to time by PSCo in reports filed with the SEC, including “Risk Factors” in Item 1A of this Annual Report on Form 10-K), could cause actual results to differ materially from management expectations as suggested by such forward-looking information: operational safety; successful long-term operational planning; commodity risks associated with energy markets and production; rising energy prices and fuel costs; qualified employee work force and third-party contractor factors; violations of our Codes of Conduct; our ability to recover costs; changes in regulation; reductions in our credit ratings and the cost of maintaining certain contractual relationships; general economic conditions, including recessionary conditions, inflation rates, monetary fluctuations, supply chain constraints and their impact on capital expenditures and/or the ability of PSCo to obtain financing on favorable terms; availability or cost of capital; our customers’ and counterparties’ ability to pay their debts to us; assumptions and costs relating to funding our employee benefit plans and health care benefits; tax laws; uncertainty regarding epidemics, the duration and magnitude of business restrictions including shutdowns (domestically and globally), the potential impact on the workforce, including shortages of employees or third-party contractors due to quarantine policies, vaccination requirements or government restrictions, impacts on the transportation of goods and the generalized impact on the economy; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; seasonal weather patterns; changes in environmental laws and regulations; climate change and other weather events; natural disaster and resource depletion, including compliance with any accompanying legislative and regulatory changes; costs of potential regulatory penalties; regulatory changes and/or limitations related to the use of natural gas as an energy source; challenging labor market conditions and our ability to attract and retain a qualified workforce; and our ability to execute on our strategies or achieve expectations related to environmental, social and governance matters including as a result of evolving legal, regulatory and other standards, processes, and assumptions, the pace of scientific and technological developments, increased costs, the availability of requisite financing, and changes in carbon markets.
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Electric customers | 1.51.6 million | | | | PSCo was incorporated in 1924 under the laws of Colorado. PSCo conducts business in Colorado and generates, purchases, transmits, distributes and sells electricity in addition to purchasing, transporting, distributing and selling natural gas to retail customers and transporting customer-owned natural gas. |
Natural gas customers | 1.41.5 million | | |
Total assets | $20.423.6 billion | | |
Rate Base (estimated) | $13.314.9 billion | | |
ROE (net income / average stockholder's equity) | 8.06%8.23% | | |
Electric generating capacity | 6,2236,151 MW | | |
Gas storage capacity | 32.532.1 Bcf | | |
Electric transmission lines (conductor miles) | 24,38625,000 miles | | |
Electric distribution lines (conductor miles) | 78,48379,000 miles | | |
Natural gas transmission lines | 2,0582,000 miles | | | |
Natural gas distribution lines | 22,81524,000 miles | | | |
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Electric operations consist of energy supply, generation, transmission and distribution activities. PSCo had electric sales volume of 33,30133,526 (millions of KWh), 1.51.6 million customers and electric revenues of $3,116 (millions of dollars)$3,795 million for 2020.2022.
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Electric Operations (percentage of total) | | Sales Volume | | Number of Customers | | Revenues |
Residential | | 29 | % | | 86 | % | | 35 | % |
C&I | | 56 | | | 11 | | | 49 | |
Other | | 15 | | | 3 | | | 16 | |
Retail Sales/Revenue Statistics (a)
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| | 2022 | | 2021 |
KWH sales per retail customer | | 18,456 | | | 18,741 | |
Revenue per retail customer | | $ | 2,074 | | | $ | 1,975 | |
Residential revenue per KWh | | 13.62 | ¢ | | 12.46 | ¢ |
C&I revenue per KWh | | 9.86 | ¢ | | 9.37 | ¢ |
Total retail revenue per KWh | | 11.24 | ¢ | | 10.54 | ¢ |
(a)
See Note 6 to the consolidated financial statements for further information.
Sales/Revenue Statistics (a)
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| | 2020 | | 2019 |
KWH sales per retail customer | | 18,919 | | | 19,335 | |
Revenue per retail customer | | $ | 1,839 | | | $ | 1,812 | |
Residential revenue per KWh | | 11.46 | ¢ | | 11.09 | ¢ |
Large C&I revenue per KWh | | 6.51 | ¢ | | 6.43 | ¢ |
Small C&I revenue per KWh | | 9.71 | ¢ | | 9.38 | ¢ |
Total retail revenue per KWh | | 9.72 | ¢ | | 9.37 | ¢ |
(a) See Note 6 to the consolidated financial statements for further information.
Owned and Purchased Energy Generation — 20202022
Electric Energy Sources
Total electric energy generation by source (including energy market purchases) for the year ended Dec. 31, 2020:31:
*Distributed generation from the Solar*Rewards® program is not included (approximately 618 million KWh for 2020).Carbon–Free Energy
PSCo’s carbon–free energy portfolio includes wind, hydroelectric and solar power from both owned generating facilities and PPAs. Carbon–free percentages will vary year over year based on system additions, commodity costs, weather, system demand and transmission constraints.
See Item 2 — Properties for further information.
Carbon–free energy as a percentage of total energy for 2020:
* Includes biomass and hydroelectric.
Wind
Owned — Owned and operated wind farms with corresponding capacity:
| 2020 | | 2019 | |
2022 | | 2022 | | 2021 |
Wind Farms | Wind Farms | | Capacity (a) | | Wind Farms | | Capacity (b) | Wind Farms | | Capacity (MW) (a) | | Wind Farms | | Capacity (MW) (b) |
2 | 2 | | 1,059 MW | | 1 | | 582 MW | 2 | | | 1,059 | | 2 | | | 1,059 |
(a)Summer 20202022 net dependable capacity.
(b)Summer 20192021 net dependable capacity.
PPAs — Number of PPAs with capacity range: | 2020 | | 2019 | |
2022 | | 2022 | | 2021 |
PPAs | PPAs | | Range | | PPAs | | Range | PPAs | | Range (MW) | | PPAs | | Range (MW) |
17 | 17 | | 23 MW — 301 MW | | 20 | | 2 MW — 301 MW | 17 | | | 23 — 301 | | 17 | | | 23 — 301 |
Capacity — Wind capacity:Current wind capacity for owned wind farms and PPAs was 4,082 MW and 4,085 MW in 2022 and 2021, respectively.
Average Cost (Owned) — AverageIn 2022, the average cost per MWh of wind energy fromwas $11 per MWh for owned generation:
Average Cost (PPAs) — Average costgeneration and $38 per MWh under existing PPAs. In 2021, the average cost of wind energy was $17 per MWh for owned generation and $35 per MWh under existing PPAs:PPAs.
Wind Development
PSCo placed approximately 500 MW of owned wind and approximately 500 MW of PPAs into service during 2020:
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Project | | Capacity
|
Cheyenne Ridge | | 477 MW(a)(b)
|
Various PPAs | | ~500 MW(c)
|
(a)Summer 2020 net dependable capacity.
(b)Values disclosed are the maximum generation levels for these wind units. Capacity is attainable only when wind conditions are sufficiently available (on-demand net dependable capacity is zero).
(c)Based on contracted capacity.
Solar
PPAs — Solar energy PPAs:PPAs capacity by type:
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Type | | Capacity (MW) |
Distributed Generation | | 643 MW848 | |
Utility-Scale | | 306 MW732 | |
Total | | 949 MW1,580 | |
Average Cost (PPAs) — AverageThe average cost per MWh of solar energy under existing PPAs:PPAs was $69 per MWh and $67 per MWh in 2022 and 2021, respectively.
Solar Development — PSCo placed approximately 200 MW of PPAs into service during 2022 and expects to place approximately 800 MW (including storage) of PPAs into service during 2023.Other Carbon-Free Energy
PSCo’s other carbon-free energy portfolio includes hydro from owned generating facilities.
See Item 2 — Properties for further information.
Fossil Fuel Energy
PSCo’s fossil fuel energy portfolio includes coal and natural gas power from both owned generating facilities and PPAs.
See Item 2 — Properties for further information.
Coal
PSCo owns and operates coal units with approximately 2,0001,700 MW of total 20202022 net summer dependable capacity.capacity, which provided 27% of the PSCo energy mix in 2022.
The following are PSCo’s approved coal plant retirements. In addition, PSCo plans to continue to evaluate its coal fleet for other potentialApproved early coal plant retirements as part of state resource plans or other regulatory proceedings.retirements:
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Approved / Authorized |
Year | | Plant Unit | | Capacity |
2022 | | Comanche 1 | | 325 MW |
2025 | | Comanche 2 | | 335 MW |
2025 | | Craig 1 | | 42 MW(a)
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2028 | | Craig 2 | | 40 MW(a)
|
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Year | | Plant Unit | | Capacity (MW) | |
2025 | | Comanche 2 | | 335 | |
2025 | | Craig 1 | | 42 | (a) |
2025 | | Pawnee (b) | | 505 | |
2027 | | Hayden 2 | | 98 | (a) |
2028 | | Hayden 1 | | 135 | (a) |
2028 | | Craig 2 | | 40 | (a) |
2030 | | Comanche 3 | | 500 | (a) |
(a)Based on PSCo’s ownership interest.
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Proposed |
Year | | Plant Unit | | Capacity |
2027 | | Hayden 2 | | 98 MW(a)
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2028 | | Hayden 1 | | 135 MW(b)
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(a)Based on PSCo’s ownership of 37% of Unit 2.Reflects conversion from coal to natural gas.
(b)Based on PSCo’s ownership of 76% of Unit 1.
Coal Fuel Cost
— Delivered cost per MMBtu of coal consumed for owned electric generation and the percentage of total fuel requirements:requirements (coal and natural gas):
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| | Coal |
| | Cost | | Percent |
2020 | | $ | 1.41 | | | 51 | % |
2019 | | 1.45 | | | 55 | |
Plans for our remaining Colorado coal fleet will be outlined when PSCo submits its 2021 resource plan, which is expected to be filed in March 2021. | | | | | | | | | | | | | | |
| | Coal |
| | Cost | | Percent |
2022 | | $ | 1.48 | | | 55 | % |
2021 | | 1.43 | | | 62 | |
Natural Gas
PSCo has sixseven natural gas plants with approximately 2,9003,200 MW of total 20202022 net summer dependable capacity.capacity, which provided 32% of the PSCo energy mix in 2022.
See item 2 - Properties for further detail.
Natural gas supplies, transportation and storage services for power plants are procured to provide an adequate supply of fuel. Remaining requirements are procured through a liquid spot market. Generally, natural gas supply contracts have variable pricing that is tied to natural gas indices. Natural gas supply and transportation agreements include obligations for the purchase and/or delivery of specified volumes or payments in lieu of delivery.
Natural Gas Cost
— Delivered cost per MMBtu of natural gas consumed for owned electric generation and the percentage of total fuel requirements:requirements (coal and natural gas):
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| | Natural Gas |
| | Cost | | Percent |
2020 | | 3.01 | | | 49 | |
2019 | | 3.27 | | | 45 | |
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| | Natural Gas |
| | Cost | | Percent |
2022 | | $ | 7.09 | | | 45 | % |
2021 (a) | | 8.38 | | | 38 | |
(a)Reflective of Winter Storm Uri.
Capacity and Demand
Uninterrupted system peak demand and occurrence date:
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System Peak Demand (in MW) |
2020 | | 2019 |
6,899 | | | Aug. 17 | | 7,111 | | | July 19 |
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System Peak Demand (MW) |
2022 | | 2021 |
6,821 | | | Sept. 6 | | 6,958 | | | July 28 |
Transmission
Transmission lines deliver electricity over long distances from power sources to transmission substations closer to homes and businesses.customers. A strong transmission system ensures continued reliable and affordable service, ability to meet state and regional energy policy goals, and support for a diverse generation mix, including renewable energy. PSCo owns more than 24,000 conductor miles of transmission lines across its service territory.
During 2020, PSCo completedplans to build approximately 600 additional conductor miles of transmission lines, primarily as part of the following transmission projects:Colorado Power Pathway project estimated to be complete in 2027.
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Project | | Miles | | Size |
Pawnee-Daniels Park | | 113 | | | 345 KV |
Cheyenne Ridge | | 73 | | | 345 KV |
See Item 2 - Properties for further information.Distribution
Distribution lines allow electricity to travel at lower voltages from substations directly to homes and businesses.customers. PSCo has a vast distribution network, owning and operating approximately 79,000 conductor miles of distribution lines across our service territory, both above ground and underground.territory. To continue providing reliable, affordable electric service and enable more flexibility for customers, we are working to digitize the distribution grid, while at the same time keeping it secure.
See Item 2 - Properties for further information.
Natural gas operations consist of purchase, transportation and distribution of natural gas to end-use residential, C&I and transport customers. PSCo had natural gas deliveries of 324,533291,800 (thousands of MMBtu), 1.41.5 million customers and natural gas revenues of $1,024 (millions of dollars)$1,860 million for 2020.2022.
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Natural Gas (percentage of total) | | Deliveries | | Number of Customers | | Revenues |
Residential | | 36 | % | | 92 | % | | 65 | % |
C&I | | 16 | | | 7 | | | 26 | |
Transportation and other | | 48 | | | 1 | | | 9 | |
Sales/Revenue Statistics (a)
| | | 2020 | | 2019 | | 2022 | | 2021 |
MMBtu sales per retail customer | MMBtu sales per retail customer | | 101.10 | | | 109.80 | | MMBtu sales per retail customer | | 103 | | | 99 | |
Revenue per retail customer | Revenue per retail customer | | $ | 632.11 | | | $ | 748.34 | | Revenue per retail customer | | $ | 1,147 | | | $ | 797 | |
Residential revenue per MMBtu | Residential revenue per MMBtu | | 6.47 | | | 7.02 | | Residential revenue per MMBtu | | 11.14 | | | 8.35 | |
C&I revenue per MMBtu | C&I revenue per MMBtu | | 5.70 | | | 6.33 | | C&I revenue per MMBtu | | 10.40 | | | 7.35 | |
Transportation and other revenue per MMBtu | Transportation and other revenue per MMBtu | | 0.65 | | | 0.56 | | Transportation and other revenue per MMBtu | | 1.07 | | | 1.37 | |
(a)See Note 6 to the consolidated financial statements for further information.
Capability and Demand
Natural gas supply requirements are categorized as firm or interruptible (customers with an alternate energy supply).
Maximum daily output (firm and interruptible) and occurrence date:
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2020 | | 2019 |
MMBtu | | Date | | MMBtu | | Date |
1,931,888 | | | Feb. 4 | | 2,139,420 | | | March 3 |
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2022 | | 2021 |
MMBtu | | Date | | MMBtu | | Date (a) |
2,243,552 | | | Dec. 22 | | 2,316,283 | | | Feb. 14 |
(a)Reflective of Winter Storm Uri.
Natural Gas Supply and CostsCost
PSCo seeks natural gas supply, transportation and storage alternatives to yield a diversified portfolio, which increaseincreases flexibility, decreases interruption, and financial risks and economical rates. In addition, PSCo conducts natural gas price hedging activities approved by its state’s commissions.
Average delivered cost per MMBtu of natural gas for regulated retail distribution:
| 2020 | | 2019 | |
2022 | | 2022 | | 2021 (a) |
$ | 2.52 | | | $ | 2.95 | | 6.33 | | | $ | 6.06 | |
(a)Reflective of Winter Storm Uri.
PSCo has natural gas supply transportation and storage agreements that include obligations for purchase and/or delivery of specified volumes or to make payments in lieu of delivery.
Seasonality
Demand for electric power and natural gas is affected by seasonal differences in the weather. In general, peak sales of electricity occur in the summer months and peak sales of natural gas occur in the winter months. As a result, the overall operating results may fluctuate substantially on a seasonal basis. Additionally, PSCo’s operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer.
Competition
PSCo is subject to public policies that promote competition and development of energy markets. PSCo’s industrial and large commercial customers have the ability to generate their own electricity. In addition, customers may have the option of substituting other fuels or relocating their facilities to a lower cost region.
Customers have the opportunity to supply their own power with distributed generation including solar generation and in most jurisdictions can currently avoid paying for most of the fixed production, transmission and distribution costs incurred to serve them.
Colorado has incentives for the development of rooftop solar, community solar gardens and other distributed energy resources. Distributed generating resources are potential competitors to PSCo’s electric service business with these incentives and federal tax subsidies.
The FERC has continued to promote competitive wholesale markets through open access transmission and other means. PSCo’s wholesale customers can purchase their output from generation resources of competing suppliers or non-contracted quantities and use the transmission system of PSCo on a comparable basis to serve their native load.
FERC Order No. 1000 established competition for construction and operationownership of certain new electric transmission facilities. State utility commissionsfacilities under Federal regulations. Some states have also createdstate laws that allow the incumbent a Right of First Refusal to own these transmission facilities.
FERC Order 2222 requires that RTO and ISO markets allow participation of aggregations of distributed energy resources. This order is expected to incentivize distributed energy resource planning programs that promote competition for electric generation resources usedadoption, however implementation is expected to provide service to retail customers.
PSCo has franchise agreements with cities subject to periodic renewal; however, a city could seek alternative means to access electric power or gas, such as municipalization. No municipalization activities are occurring presently.
While facing these challenges, PSCo believes its rates and services are competitive with alternatives currently available.
Public Utility Regulation
See Item 7 for discussion of public utility regulation.
Environmental Regulation
Our facilities are regulated by federal and state agencies that have jurisdiction over air emissions, water quality, wastewater discharges, solid wastes and hazardous wastes or substances. Certain PSCo activities require registrations, permits, licenses, inspections and approvals from these agencies.
PSCo has received necessary authorizations for the construction and continued operation of its generation, transmission and distribution systems. Our facilities strive to operate in compliance with applicable environmental standards and related monitoring and reporting requirements.
However, it is not possible to determine when or to what extent additional facilities or modifications ofto existing or planned facilities will be required as a result of changes to regulations, interpretations or enforcement policies or what effect future laws or regulations may have. We may be required to incur expenditures in the future for remediation of MGPhistoric and current operating sites and other sites if it is determined that prior compliance efforts are not sufficient.
The Denver North Front Range Non-attainment Area does not meet either the 2008 or 2015 ozone National Ambient Air Quality Standard. Colorado will continue to consider further reductions available in the non-attainment area as it develops plans to meet ozone standards. Gas plants which operate in PSCo’s non-attainment area may be required to improve or add controls, implement further work practices and/or enhanced emissions monitoring as part of future Colorado state plans.waste treatment, storage and disposal sites.
There are significant environmental regulations to encourage use of clean energy technologies and regulate emissions of GHGs. PSCo has undertaken numerous initiatives to meet current requirements and prepare for potential future regulations, reduce GHG emissions and respond to state renewable and energy efficiency goals. Future environmental regulations may result in substantial costs.
Emerging Environmental Regulation
Clean Air Act — In July 2019,a June 2022 ruling, the EPA adopted the Affordable Clean Energy rule, which required statesUnited States Supreme Court held that an economy-wide approach to develop plans by 2022 for GHG reductionsreducing greenhouse gas emissions from coal-fired power plants. In a Jan. 19, 2021 decision,plants was not consistent with the U.S. Court of Appeals for the D.C. Circuit issued a decision vacating and remanding the Affordable Clean Energy rule. That decision,Air Act. Therefore, if not successfully appealed or reconsidered, would allow the EPA proceeds with new rules, it cannot set a standard based on economy-wide generation shifting to proceed with alternate regulation of coal-fired power plants, either reviving the Clean Power Plan or proposing additional regulation.other sources, such as renewable energy. It is too earlyanticipated that EPA will propose rules to predict an outcome, butlimit GHG emissions from new and existing coal and natural gas-fired electric generating units in 2023. If any new rules could require substantial additional investment, even in plants slated for retirement. PSCo believes based on prior state commission practices,that the cost of these initiatives or replacement generation would be recoverable through rates.rates based on prior state commission practices.
Coal Ash Regulation —In February 2023, the EPA entered into a Consent Decree, committing the agency to either issue new proposed rules by May 5, 2023, to regulate inactive CCR landfills under the CCR Rule for the first time, or to determine no such rules are necessary by that date. If proposed rules are issued in May, the EPA has committed to a May 2024 effective date for the new rules. Until proposed rules are issued, it is not certain what the impact will be on PSCo, seeksbut we anticipate that additional inactive ash units could become regulated for the first time. It is also anticipated that the EPA may issue other CCR proposed rules in 2023 that further expand the scope of the CCR Rule.
Emerging Contaminants of Concern — PFAS are man-made chemicals that are widely used in consumer products and can persist and bio-accumulate in the environment. PSCo does not manufacture PFAS but because PFAS are so ubiquitous in products and the environment, it may impact our operations. In September 2022, the EPA proposed to address climate changedesignate two types of PFAS as “hazardous substances” under the Comprehensive Environmental Response, Compensation, and potential climate changeLiability Act, specifically perfluorooctanoic acid and perfluorooctanesulfonic acid. This proposed rule could result in new obligations for investigation and cleanup wherever PFAS are found to be present. The impact the proposed regulation through effortsmay have on electric and gas utilities is currently uncertain.
Other
Our operations are subject to reduce its GHG emissions in a balanced, cost-effective manner.workplace safety standards under the Federal Occupational Safety and Health Act of 1970 (“OSHA”) and comparable state laws that regulate the protection of worker health and safety. In addition, the Company is subject to other government regulations impacting such matters as labor, competition, data privacy, etc. Based on information to date and because our policies and business practices are designed to comply with all applicable laws, we do not believe the effects of compliance on our operations, financial condition or cash flows are material.
As of Dec. 31, 2020,2022, PSCo had 2,3782,382 full-time employees and noone part-time employees,employee, of which 1,8821,852 were covered under collective-bargaining agreements.
Xcel Energy, which includes PSCo, is subject to a variety of risks, many of which are beyond our control. Risks that may adversely affect the business, financial condition, results of operations or cash flows are described below. Although the risks are organized by heading, and each risk is described separately, many of the risks are interrelated. These risks should be carefully considered together with the other information set forth in this report and future reports that Xcel Energy files with the SEC. You should not interpret the disclosure of any risk factor to imply that the risk has not already materialized. While we believe we have identified and discussed below the key risk factors affecting our business, there may be additional risks and uncertainties that are not presently known or that are not currently believed to be significant that may adversely affect our business, financial condition, results of operations or cash flows in the future.
Oversight of Risk and Related Processes
PSCo’s Board of Directors is responsible for the oversight of material risk and maintaining an effective risk monitoring process. Management and the Board of Directors’ committeesDirectors have responsibility for overseeing the identification and mitigation of key risks.
At a threshold level, PSCo maintains a robust compliance program and promotes a culture of compliance, beginning with the tone at the top. The risk mitigation process includes adherence to our codeCode of conductConduct and compliance policies, operation of formal risk management structures and overall business management. PSCo further mitigates inherent risks through formal risk committees and corporate functions such as internal audit, and internal controls over financial reporting and legal.
Management identifies and analyzes risks to determine materiality and other attributes such as timing, probability and controllability. Identification and risk analysis occurs formally through risk assessment conducted by senior management, the financial disclosure process, hazard risk procedures, internal audit and compliance with financial and operational controls. Management also identifies and analyzes risk through the business planning process, development of goals and establishment of key performance indicators, including identification of barriers to implementing our strategy. The business planning process also identifies likelihood and mitigating factors to prevent the assumption of inappropriate risk to meet goals.
Management communicates regularly with the Board of Directors and its sole stockholder regarding risk. Senior management presents and communicates a periodic risk assessment to the Board of Directors, providing information on the risks that management believes are material, including financial impact, timing, likelihood and mitigating factors. The Board of Directors regularly reviews management’s key risk assessments, which includes areas of existing and future macroeconomic, financial, operational, policy, environmental, safety and security risks.
The oversight, management and mitigation of risk is an integral and continuous part of the Board of Directors’ governance of PSCo. Processes are in place to ensureconfirm appropriate risk oversight, as well as identification and consideration of new risks.
Risks Associated with Our Business
Operational Risks
Our natural gas and electric generation/transmission and distribution operations involve numerous risks that may result in accidents and other operating risks and costs.
Our natural gas transmission and distribution activities include inherent hazards and operating risks, such as leaks, explosions, outages and mechanical problems. Our electric generation, transmission and distribution activities include inherent hazards and operating risks such as contact, fire and outages. These risks could result in loss of life, significant property damage, environmental pollution, impairment of our operations and substantial financial losses.
losses to employees, third-party contractors, customers or the public. We maintain insurance against most, but not all, of these risks and losses.
The occurrence of these events, if not fully covered by insurance, could have a material effect on our financial condition, results of operations and cash flows.flows as well as potential loss of reputation.
Other uncertainties and risks inherent in operating and maintaining PSCo's facilities include, but are not limited to:
•Risks associated with facility start-up operations, such as whether the facility will achieve projected operating performance on schedule and otherwise as planned.
•Failures in the availability, acquisition or transportation of fuel or other necessary supplies.
•The impactImpact of unusual or adverse weather conditions and natural disasters, including, but not limited to, tornadoes, icing events, floods and droughts.
•Performance below expected or contracted levels of output or efficiency (e.g., performance guarantees).efficiency.
•Availability of replacement equipment.
•Availability of adequate water resources and ability to satisfy water intake and discharge requirements.
•Availability or changes to wind patterns.
•Inability to identify, manage properly or mitigate equipment defects.
•Use of new or unproven technology.
•Risks associated with dependence on a specific type of fuel or fuel source, such as commodity price risk, availability of adequate fuel supply and transportation and lack of available alternative fuel sources.
•Increased competition due to, among other factors, new facilities, excess supply, shifting demand and regulatory changes.
Additionally, compliance with existing and potential new regulations related to the operation and maintenance of our natural gas infrastructure could result in significant costs. The PHMSA is responsible for administering the DOT’s national regulatory program to assure the safe transportation of natural gas, petroleum and other hazardous materials by pipelines. The PHMSA continues to develop regulations and other approaches to risk management to assure safety in design, construction, testing, operation, maintenance and emergency response of natural gas pipeline infrastructure. We have programs in place to comply with these regulations and systematically monitor and renew infrastructure over time; however, a significant incident or material finding of non-compliance could result in penalties and higher costs of operations.
Our natural gas and electric transmission and distribution operations are dependent upon complex information technology systems and network infrastructure, the failure of which could disrupt our normal business operations, which could have a material adverse effect on our ability to process transactions and provide services.
Our utility operations are subject to long-term planning and project risks.
Most electric utility investments are planned to be used for decades. Transmission and generation investments typically have long lead times and are planned well in advance of in-service dates and typically subject to long-term resource plans. These plans are based on numerous assumptions such as: sales growth, customer usage, commodity prices, economic activity, costs, regulatory mechanisms, customer behavior, available technology and public policy. Our long-term resource plan is dependent on our ability to obtain required approvals, develop necessary technical expertise, allocate and coordinate sufficient resources and adhere to budgets and timelines.
In addition, the long-term nature of both our planning processes and our asset lives are subject to risk. The electric utility sector is undergoing significant change (e.g,(e.g., increases in energy efficiency, wider adoption of distributed generation and shifts away from fossil fuel generation to renewable generation). Customer adoption of these technologies and increased energy efficiency could result in excess transmission and generation resources, downward pressure on sales growth, and potentially stranded costs if we are not able to fully recover costs and investments.
Changing customer expectations and technologies are requiring significant investments in advanced grid infrastructure, which increases exposure to technology obsolescence. Additionally, evolving stakeholder preference for lower emissions from generation sources and end-uses, like heating, may put pressure on our ability to recover capital investments in natural gas generation and delivery.
The magnitude and timing of resource additions and changes in customer demand may not coincide with evolving customer preference for generation resources and end-uses, which introduces further uncertainty into long-term planning. Efforts to electrify the transportation and building sectors to reduce GHG emissions may result in higher electric demand and lower natural gas demand over time. Additionally, multipleHigher electric demand may require us to adopt new technologies and make significant transmission and distribution investments including advanced grid infrastructure, which increases exposure to overall grid instability and technology obsolescence. Evolving stakeholder preference for lower emissions from generation sources and end-uses, like heating, may impact our resource mix and put pressure on our ability to recover capital investments in natural gas generation and delivery. Multiple states may not agree as to the appropriate resource mix, which may lead to costs to comply with one jurisdiction that are not recoverable across all jurisdictions served by the same assets.
We are subject to longer-term availability ofrequire inputs such as coal, natural gas uranium and water to cool our facilities. Lack of availability of these resources could jeopardize long-term operations of our facilities or make them uneconomic to operate.
Our utility operations are highly dependent on suppliers to deliver components in accordance with short and long-term project schedules.
Our products contain components that are globally sourced from suppliers who, in turn, source components from their suppliers. A shortage of key components in which an alternative supplier is not identified could significantly impact operations and project plans for PSCo and our customers. Such impacts could include timing of projects, including potential for project cancellation. Failure to adhere to project budgets and timelines adversely impacts our results of operations, financial condition or cash flows.
We are subject to commodity risks and other risks associated with energy markets and energy production.
In the eventA significant increase in fuel costs increase,could cause a decline in customer demand, could declineadverse regulatory outcomes and an increase in bad debt expense may rise, which may have a material impact on our results of operations. Despite existing fuel cost recovery mechanisms, higher fuel costs could significantly impact our results of operations if costs are not recovered. Delays in the timing of the collection of fuel cost recoveries could impact our cash flows and liquidity.
A significant disruption in supply could cause us to seek alternative supply services at potentially higher costs andcosts. Additionally, supply shortages may not be fully resolved, which could cause disruptions innegatively impacts our ability to provide services to our customers. Failure to provide service due to disruptions may also result in fines, penalties or cost disallowances through the regulatory process. Also, significantly higher energy or fuel costs relative to sales commitments could negatively impactimpacts our cash flows and results of operations.
We also engage in wholesale sales and purchases of electric capacity, energy and energy-related products as well as natural gas. In many markets, emission allowances and/or RECs are also needed to comply with various statutes and commission rulings. As a result, we are subject to market supply and commodity price risk.
Commodity price changes can affect the value of our commodity trading derivatives. We mark certain derivatives to estimated fair market value on a daily basis. Settlements can vary significantly from estimated fair values recorded and significant changes from the assumptions underlying our fair value estimates could cause earnings variability. The management of risks associated with hedging and trading is based, in part, on programs and procedures which utilize historical prices and trends.
Public perception often does not distinguish between pass through commodity costs and base rates. High commodity prices that are being passed through to customer bills could impact our ability to recover costs for other improvements and operations.
Due to the inherent uncertainty involved in price movements and potential deviation from historical pricing, PSCo is unable to fully assure that its risk management programs and procedures would be effective to protect against all significant adverse market deviations. In addition, PSCo cannot fully assure that its controls will be effective against all potential risks, including, without limitation, employee misconduct.risks. If such controlsprograms and procedures are not effective, PSCo’s results of operations, financial condition or cash flows could be materially impacted.
Failure to attract and retain a qualified workforce could have an adverse effect on operations.
SpecializedThe competition for talent has become increasingly prevalent, and we have experienced increased employee turnover due to the condition of the labor market. In addition, specialized knowledge isand skills are required for many of our technical employeespositions, which may pose additional difficulty for construction and operation of transmission, generation and distribution assets. Our business strategy is dependent on our abilityus as we work to recruit, retain and motivate employees. There is competition and a tightening market for skilled employees.employees in this climate. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to new employees or future availability and cost of contract labor may adversely affect the ability to manage and operate our business. Inability to attract and retain these employees could adversely impactimpacts our results of operations, financial condition or cash flows.
Our operations use third-party contractors in addition to employees to perform periodic and ongoing work.
We rely on third-party contractors to perform operations, maintenance and construction work. Our contractual arrangements with these contractors typically include performance and safety standards, progress payments, insurance requirements and security for performance.
Poor vendor performance or contractor unavailability could impact ongoing operations, restoration operations, regulatory recovery, our reputation and could introduce financial risk or risks of fines.
Our employees, directors, third-party contractors, or suppliers may violate or be perceived to violate our Codes of Conduct, which could have an adverse effect on our reputation.
We are exposed to risk of employee or third-party contractor fraud or misconduct. All employees and members of the Board of Directors are subject to comply with our Code of Conduct and are required to participate in annual training. Additionally, suppliers are subject to comply with our Supplier Code of Conduct. PSCo does not tolerate discrimination, violations of our Code of Conduct or other unacceptable behaviors. However, it is not always possible to identify and deter misconduct by employees and other third-parties, which may result in governmental investigations, other actions or lawsuits. If such actions are taken against us we may suffer loss of reputation and such actions could have a material effect on our financial condition, results of operations and cash flows.
We are a wholly owned subsidiary of Xcel Energy Inc. Xcel Energy Inc. can exercise substantial control over our dividend policy and business and operations and may exercise that control in a manner that may be perceived to be adverse to our interests.
All of the members of our Board of Directors, as well as many of our executive officers, are officers of Xcel Energy Inc. Our Board of Directors makes determinations with respect to a number of significant corporate events, including the payment of our dividends.
We have historically paid quarterly dividends to Xcel Energy Inc. In 2020, 2019 and 2018 we paid $831 million, $457 million and $375 million of dividends to Xcel Energy Inc., respectively. If Xcel Energy Inc.’s cash requirements increase, our Board of Directors could decide to increase the dividends we pay to Xcel Energy Inc. to help support Xcel Energy Inc.’s cash needs. This could adversely affect our liquidity. The most restrictive dividend limitation for PSCo is imposed by its credit facility, which limits the debt-to-total capitalization ratio.
See Note 5 to the consolidated financial statements for further information.
Financial Risks
Our profitability depends on our ability to recover costs from our customers and changes in regulation may impair our ability to recover costs from our customers.
We are subject to comprehensive regulation by federal and state utility regulatory agencies, including siting and construction of facilities, customer service and the rates that we can charge customers.
The profitability of our operations is dependent on our ability to recover the costs of providing energy and utility services and earn a return on our capital investment. Our rates are generally regulated and are based on an analysis of our costs incurred in a test year. We are subject to both future and historical test years depending upon the regulatory jurisdiction. Thus, the rates we are allowed to charge may or may not match our costs at any given time. Rate regulation is premised on providing an opportunity to earn a reasonable rate of return on invested capital.
There can also be no assurance that our regulatory commissions will judge all our costs to be prudent, which could result in disallowances, or that the regulatory process will always result in rates that will produce full recovery.
Overall, management believes prudently incurred costs are recoverable given the existing regulatory framework. However, there may be changes in the regulatory environment that could impair our ability to recover costs historically collected from customers, or we could exceed caps on capital costs required by commissions and result in less than full recovery.
Changes in the long-term cost-effectiveness or to the operating conditions of our assets may result in early retirements of utility facilities. While regulation typically provides cost recovery relief for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs.
In a continued low interest rate environment there has been increased downward pressure on allowed ROE. Conversely, higherHigher than expected inflation or tariffs may increase costs of construction and operations. Also, rising fuel costs could increase the risk that we will not be able to fully recover our fuel costs from our customers.
Adverse regulatory rulings (including changes in recovery mechanisms) or the imposition of additional regulations could have an adverse impact on our results of operations and materially affect our ability to meet our financial obligations, including debt payments.payments and the payment of dividends on common stock.
Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships.
We cannot be assured that our current credit ratings will remain in effect, or that a rating will not be lowered or withdrawn by a rating agency. Significant events including disallowance of costs, use of historic test years, elimination of riders or interim rates, increasing depreciation lives, lower returns on equity, changes to equity ratios and impacts of tax policy may impact our cash flows and credit metrics, potentially resulting in a change in our credit ratings. In addition, our credit ratings may change as a result of the differing methodologies or change in the methodologies used by the various rating agencies.
Any credit ratings downgrade could lead to higher borrowing costs andor lower proceeds from equity issuances. It could also impact our ability to access capital markets. Also, we may enter into contracts that require posting of collateral or settlement if credit ratings fall below investment grade.
We are subject to capital market and interest rate risks.
Utility operations require significant capital investment. As a result, we frequently need to access capital markets. Any disruption in capital markets could have a material impact on our ability to fund our operations. Capital market disruption and financial market distress could prevent us from issuing short-term commercial paper, issuing new securities or cause us to issue securities with unfavorable terms and conditions, such as higher interest rates.rates or lower proceeds from equity issuances. Higher interest rates on short-term borrowings with variable interest rates could also have an adverse effect on our operating results.
We are subject to credit risks.
Credit risk includes the risk that our customers will not pay their bills, which may lead to a reduction in our liquidity and an increase in bad debt expense. Credit risk is comprised of numerous factors including the price of products and services provided, the economy and unemployment rates.
Credit risk also includes the risk that counterparties that owe us money or product will become insolvent and may breach their obligations. Should the counterparties fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected and incur losses.
We may have direct credit exposure in our short-term wholesale and commodity trading activity to financial institutions trading for their own accounts or issuing collateral support on behalf of other counterparties. We may also have some indirect credit exposure due to participation in organized markets, (e.g., the California Independent System Operator, SPP, PJM Interconnection, LLC, Midcontinent Independent System Operator, Inc. and the, Electric Reliability Council of Texas)Texas and California ISO), in which any credit losses are socialized to all market participants.
We have additional indirect credit exposure to financial institutions from letters of credit provided as security by power suppliers under various purchased power contracts. If any of the credit ratings of the letter of credit issuers were to drop below investment grade, the supplier would need to replace that security with an acceptable substitute. If the security were not replaced, the party could be in default under the contract.
As we are a subsidiary of Xcel Energy Inc., we may be negatively affected by events impacting the credit or liquidity of Xcel Energy Inc. and its affiliates.
If either S&P or Moody’s were to downgrade Xcel Energy Inc.’s debt securities below investment grade, it would increase Xcel Energy Inc.’s cost of capital and restrict its access to the capital markets. This could limit Xcel Energy Inc.’s ability to contribute equity or make loans to us or may cause Xcel Energy Inc. to seek additional or accelerated funding from us in the form of dividends. If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.
As of Dec. 31, 2020,2022, Xcel Energy Inc. and its utility subsidiaries had approximately $19.6$22.8 billion of long-term debt and $1.0$2.0 billion of short-term debt and current maturities. Xcel Energy Inc. provides various guarantees and bond indemnities supporting some of its subsidiaries by guaranteeing the payment or performance by these subsidiaries for specified agreements or transactions.
Xcel Energy also has other contingent liabilities resulting from various tax disputes and other matters. Xcel Energy Inc.’s exposure under the guarantees is based upon the net liability of the relevant subsidiary under the specified agreements or transactions. The majority of Xcel Energy Inc.’s guarantees limit its exposure to a maximum amount that is stated in the guarantees.
As of Dec. 31, 2020,2022, Xcel Energy had the following guarantees outstanding with a $2outstanding:
•$1 million maximum stated amount and immaterial exposure. Xcel Energy also had additional guarantees of $60
•$61 million at Dec. 31, 2020 for performance and payment of surety bonds for the benefit of itself and its subsidiaries, with total exposure that cannot be estimated at this time.
•$98 million for performance and payment of a capital services contract for solar generating equipment, with immaterial exposure.
If Xcel Energy Inc. were to become obligated to make payments under these guarantees and bond indemnities or become obligated to fund other contingent liabilities, it could limit Xcel Energy Inc.’s ability to contribute equity or make loans to us, or may cause Xcel Energy Inc. to seek additional or accelerated funding from us in the form of dividends. If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.
Increasing costs of our defined benefit retirement plans and employee benefits may adversely affect our results of operations, financial condition or cash flows.
We have defined benefit pension and postretirement plans that cover most of our employees. Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements of these plans. Estimates and assumptions may change. In addition, the Pension Protection Act sets the minimum funding requirements for defined benefit pension plans. Therefore, our funding requirements and contributions may change in the future. Also, the payout of a significant percentage of pension plan liabilities in a single year due to high numbers of retirements or employees leaving PSCo would trigger settlement accounting and could require PSCo to recognize incremental pension expense related to unrecognized plan losses in the year liabilities are paid. Changes in industry standards utilized in key assumptions (e.g., mortality tables) could have a significant impact on future obligations and benefit costs.
Increasing costs associated with health care plans may adversely affect our results of operations.
Increasing levels of large individual health care claims and overall health care claims could have an adverse impact on our results of operations, financial condition or cash flows. Health care legislation could also significantly impact our benefit programs and costs.
Federal tax law may significantly impact our business.
PSCo collects estimated federal, state and local tax payments through their regulated rates. Changes to federal tax law may benefit or adversely affect our earnings and customer costs. Tax depreciable lives and the valuevalue/availability of various tax credits or the timeliness of their utilization may impact the economics or selection of resources.Ifresources. If tax rates are increased, there could be timing delays before regulated rates provide for recovery of such tax increases in revenues. In addition, certain IRS tax policies such as tax normalization may impact our ability to economically deliver certain types of resources relative to market prices.
Macroeconomic Risks
Economic conditions impact our business.
Our operations are affected by local, national and worldwide economic conditions, which correlates to customers/sales growth (decline). Economic conditions may be impacted by recessionary factors, rising interest rates and insufficient financial sector liquidity leading to potential increased unemployment, which may impact customers’ ability to pay their bills which could lead to additional bad debt expense.
Additionally, PSCo faces competitive factors, which could have an adverse impact on our financial condition, results of operations and cash flows. Further, worldwide economic activity impacts the demand for basic commodities necessary for utility infrastructure, which may inhibit our ability to acquire sufficient supplies. We operate in a capital intensive industry and federal trade policy could significantly impact the cost of materials we use. There may be delays before these additional material costs can be recovered in rates.
We face risks related to health epidemics and other outbreaks, which may have a material effect on our financial condition, results of operations and cash flows.
The global outbreak of COVID-19 is impactingHealth epidemics continue to impact countries, communities, supply chains and markets. A high degree of uncertaintyUncertainty continues to exist regarding the pandemic,epidemics; the duration and magnitude of business restrictions re-shut downs, if any,including shutdowns (domestically and globally); the potential impact on the workforce including shortages of employees and third-party contractors due to quarantine policies, vaccination requirements or government restrictions; impacts on the transportation of goods, and the level and pace of economic recovery. While we are implementing contingency plans, there are no guarantees these plans will be sufficient to offsetgeneralized impact on the impact of COVID-19.economy.
Although the impact of the pandemic to the 2020 results was largely mitigated due to management’s actions, weWe cannot ultimately predict whether itan epidemic will have a material impact on our future liquidity, financial condition or results of operations. Nor can we predict the impact of the virus on the health of our employees, our supply chain or our ability to recover higher costs associated with managing through the pandemic. The impact of COVID-19 may exacerbate other risks discussed herein, which could have a material effect on us. The situation is evolving and additional impacts may arise.an outbreak.
Operations could be impacted by war, terrorism or other events.
Our generation plants, fuel storage facilities, transmission and distribution facilities and information and control systems may be targets of terrorist activities. Any disruption could impact operations or result in a decrease in revenues and additional costs to repair and insure our assets. These disruptions could have a material impact on our financial condition, results of operations or cash flows. The potential for terrorism has subjected our operations to increased risks and could have a material effect on our business. We have already incurred increased costs for security and capital expenditures in response to these risks. The insurance industry has also been affected by these events and the availability of insurance may decrease. In addition, insurance may have higher deductibles, higher premiums and more restrictive policy terms.
A disruption of the regional electric transmission grid, interstate natural gas pipeline infrastructure or other fuel sources, could negatively impact our business, brand and reputation. Because our facilities are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by the actions of a neighboring utility.
We also face the risks of possible loss of business due to significant events such as severe storms, severe temperature extremes, wildfires, widespread pandemic, generator or transmission facility outage, pipeline rupture, railroad disruption, operator error, sudden and significant increase or decrease in wind generation or a workforce disruption.
In addition, major catastrophic events throughout the world may disrupt our business. Xcel EnergyWhile we have business continuity plans in place, our ability to recover may be prolonged due to the type and extent of the event. PSCo participates in a global supply chain, which includes materials and components that are globally sourced. A prolonged disruption could result in the delay of equipment and materials that may impact our ability to connect, restore and reliably serve our customers.
A major disruption could result in a significant decrease in revenues, and additional costs to repair assets, and an adverse impact on the cost and availability of insurance, which could have a material impact on our results of operations, financial condition or cash flows.
PSCo participates in grid security and emergency response exercises (GridEx). These efforts, led by the NERC, test and further develop the coordination, threat sharing and interaction between utilities and various government agencies relative to potential cyber and physical threats against the nation’s electric grid.
A cyber incident or security breach could have a material effect on our business.
We operate in an industry that requires the continued operation of sophisticated information technology, control systems and network infrastructure. In addition, we use our systems and infrastructure to create, collect, use, disclose, store, dispose of and otherwise process sensitive information, including companyCompany data, customer energy usage data, and personal information regarding customers, employees and their dependents, contractors and other individuals.
Our generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets, as well as information processed in our systems (e.g., information regarding our customers, employees, operations, infrastructure and assets) could be affected by cyber security incidents, including those caused by human error. Our
The utility industry has been the target of several attacks on operational systems and has seen an increased volume and sophistication of cyber security incidents from international activist organizations, Nation Statesother countries and individuals. We expect to continue to experience attempts to compromise our information technology and control systems, network infrastructure and other assets. To date, no cybersecurity incident or attack has had a material impact on our business or results of operations.
Cyber security incidents could harm our businesses by limiting our generating, transmitting and distributing capabilities, delaying our development and construction of new facilities or capital improvement projects to existing facilities, disrupting our customer operations or causing the release of customer information, all of which would likely receive state and federal regulatory scrutiny and could expose us to liability.
Our generation, transmission systems and natural gas pipelines are part of an interconnected system. Therefore, a disruption caused by the impact of a cyber security incident ofon the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources of our third-party service providers’ operations, could also negatively impact our business.
Our supply chain for procurement of digital equipment and services may expose software or hardware to these risks and could result in a breach or significant costs of remediation. We are unable to quantify the potential impact of cyber security threats or subsequent related actions. Cyber security incidents and regulatory action could result in a material decrease in revenues and may cause significant additional costs (e.g., penalties, third-party claims, repairs, insurance or compliance) and potentially disrupt our supply and markets for natural gas, oil and other fuels.
We maintain security measures to protect our information technology and control systems, network infrastructure and other assets. However, these assets and the information they process may be vulnerable to cyber security incidents, including asset failure or unauthorized access to assets or information. A failure or breach of our technology systems or those of our third-party service providers could disrupt critical business functions and may negatively impact our business, our brand, and our reputation. The cyber security threat is dynamic and evolves continually, and our efforts to prioritize network protection may not be effective given the constant changes to threat vulnerability.
While the Company maintains insurance relating to cybersecurity events, such insurance is subject to a number of exclusions and may be insufficient to offset any losses, costs or damages experienced. Also, the market for cybersecurity insurance is relatively new and coverage available for cybersecurity events is evolving as the industry matures.
Our operating results may fluctuate on a seasonal and quarterly basis and can be adversely affected by milder weather.
Our electric and natural gas utility businesses are seasonal and weather patterns can have a material impact on our operating performance. Demand for electricity is often greater in the summer and winter months associated with cooling and heating. Because natural gas is heavily used for residential and commercial heating, the demand depends heavily upon weather patterns. A significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. Unusually mild winters and summers could have an adverse effect on our financial condition, results of operations or cash flows.
Public Policy Risks
Increased risks of regulatory penalties could negatively impact our business.
The Energy Act increased civil penalty authority for violation of FERC statutes, rules and orders. FERC can impose penalties of up to $1.5 million per violation per day, particularly as it relates to energy trading activities for both electricity and natural gas. In addition, NERC electric reliability standards and critical infrastructure protection requirements are mandatory and subject to potential financial penalties. Also, the PHMSA, Occupational Safety and Health Administration and other federal agencies have the authority to assess penalties.
In the event of serious incidents, these agencies may pursue penalties. In addition, certain states have the authority to impose substantial penalties. If a serious reliability, cyber or safety incident did occur, it could have a material effect on our results of operations, financial condition or cash flows.
The continued use of natural gas for both power generation and gas distribution have increasingly become a public policy advocacy target. These efforts may result in a limitation of natural gas as an energy source for both power generation and heating, which could impact our ability to reliably and affordably serve our customers.
In recent years, there have been various local and state agency proposals within and outside our service territories that would attempt to restrict the use and availability of natural gas. If such policies were to prevail, we may be forced to make new resource investment decisions which could potentially result in stranded costs if we are not able to fully recover costs and investments and impact the overall reliability of our service.
Environmental Policy Risks
We may be subject to legislative and regulatory responses to climate change, with which compliance could be difficult and costly.
Legislative and regulatory responses related to climate change may create financial risk as our facilities may be subject to additional regulation at either the state or federal level in the future. International agreements could additionally lead to future federal or state regulations.
In 2015, the United Nations Framework Convention on Climate Change reached consensus among 190 nations on an agreement (the Paris Agreement) that establishes a framework for GHG mitigation actions by all countries, with a goal of holding the increase in global average temperature to below 2º Celsius above pre-industrial levels and an aspiration to limit the increase to 1.5º Celsius.
The Biden Administration will establish a new nationally determined contribution for the United States. The Paris Agreement
International commitments and agreements could result in future additional GHG reductions in the United States. In addition, in 2023 the Biden Administration has announced plansEPA intends to implement new climate change programs, including potential regulation ofpublish draft regulations for GHG emissions targetingfrom the utility industry.
The Biden Administration has also announced a one year suspension of new oil and natural gas drilling on federal lands to allow for a review of oil and gas leasing regulations. The form of these regulations is uncertain, but, depending onpower sector consistent with the requirements imposed in the short and long term, they could impose substantial costs on our oil and gas customers or result in substantial increases to the cost of fuel we use in our electricity and gas businesses.agency’s Clean Air Act authorities.
Many states and localities continue to pursue their own climate policies. The steps Xcel Energy has taken to date to reduce GHG emissions, including energy efficiency measures, adding renewable generation orand retiring or converting coal plants to natural gas, occurred under state-endorsed resource plans, renewable energy standards and other state policies.
We may be subject to climate change lawsuits. An adverse outcome could require substantial capital expenditures and possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant and could affect results of operations, financial condition or cash flows if such costs are not recovered through regulated rates.
If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material effect on our results of operations, financial condition or cash flows.
Increased risks of regulatory penalties could negatively impact our business.
The Energy Act increased civil penalty authority for violation of FERC statutes, rules and orders. The FERC can impose penalties of up to $1.3 million per violation per day, particularly as it relates to energy trading activities for both electricity and natural gas. In addition, NERC electric reliability standards and critical infrastructure protection requirements are mandatory and subject to potential financial penalties. Also, the PHMSA, Occupational Safety and Health Administration and other federal agencies have the authority to assess penalties.
In the event of serious incidents, these agencies may pursue penalties. In addition, certain states have the authority to impose substantial penalties. If a serious reliability, cyber or safety incident did occur, it could have a material effect on our results of operations, financial condition or cash flows.
Environmental Risks
We are subject to environmental laws and regulations, with which compliance could be difficult and costly.
We are subject to environmental laws and regulations that affect many aspects of our operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances. Laws and regulations require us to obtain permits, licenses, and approvals and to comply with a variety of environmental requirements.
Environmental laws and regulations can also require us to restrict or limit the output of facilities or the use of certain fuels, shift generation to lower-emitting facilities, install pollution control equipment, clean up spills and other contamination and correct environmental hazards. Failure to meet requirements of environmental mandates may result in fines or penalties. We may be required to pay all or a portion of the cost to remediate sites where our past activities, or the activities of other parties, caused environmental contamination.
Changes in environmental policies and regulations or regulatory decisions may result in early retirements of our generation facilities. While regulation typically provides relief for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs.
We are subject to mandates to provide customers with clean energy, renewable energy and energy conservation offerings. It could have a material effect on our results of operations, financial condition or cash flows if our regulators do not allow us to recover the cost of capital investment or O&M costs incurred to comply with the requirements.
In addition, existing environmental laws or regulations may be revised, and new laws or regulations may be adopted. We may also incur additional unanticipated obligations or liabilities under existing environmental laws and regulations.
We are subject to physical and financial risks associated with climate change and other weather, natural disaster and resource depletion impacts.
Climate change can create physical and financial risk. Physical risks include changes in weather conditions and extreme weather events.
Our customers’ energy needs vary with weather. To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease. Increased energy use due to weather changes may require us to invest in generating assets, transmission and infrastructure. Decreased energy use due to weather changes may result in decreased revenues.
Climate change may impact the economy, which could impact our sales and revenues. The price of energy has an impact on the economic health of our communities. The cost of additional regulatory requirements, such as regulation of GHG, could impact the availability of goods and prices charged by our suppliers which would normally be borne by consumers through higher prices for energy and purchased goods. To the extent financial markets view climate change and emissions of GHGs as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less than ideal terms and conditions.
We establish strategies and expectations related to climate change and other environmental matters. Our ability to achieve any such strategies or expectations is subject to numerous factors and conditions, many of which are outside of our control. Examples of such factors include, but are not limited to, evolving legal, regulatory, and other standards, processes, and assumptions, the pace of scientific and technological developments, increased costs, the availability of requisite financing, and changes in carbon markets. Failures or delays (whether actual or perceived) in achieving our strategies or expectations related to climate change and other environmental matters could adversely affect our business, operations, and reputation, and increase risk of litigation.
Severe weather impacts our service territories, primarily when thunderstorms, flooding, tornadoes, wildfires and snow or ice storms or extreme temperatures (high heating/cooling days) occur. Extreme weather conditions in general require system backup and can contribute to increased system stress, including service interruptions. Extreme weather conditions creating high energy demand may raise electricity prices, increasing the cost of energy we provide to our customers.
To the extent the frequency of extreme weather events increases, this could increase our cost of providing service.service and result in more frequent service interruptions. Periods of extreme temperatures could also impact our ability to meet demand. Changes
More frequent and severe drought conditions, extreme swings in amount and timing of precipitation, resultingchanges in droughts or water shortages could adversely affect our operations. Drought conditions also contribute tovegetation, unseasonably warm temperatures, very low humidity, stronger winds and other factors have increased the increase induration of the wildfire season and the potential impact of an event. Also, the expansion of the wildland urban interface increases the wildfire risk from ourto surrounding communities and PSCo's electric generation facilities.and natural gas infrastructure.
Other potential risks associated with wildfires include the inability to secure sufficient insurance coverage, or increased costs of insurance, regulatory recovery risk, and the potential for a credit downgrade and subsequent additional costs to access capital markets.
While we carry liability insurance, given an extreme event, if PSCo was found to be liable for wildfire damages, amounts that potentially exceed our coverage could negatively impact our results of operations, financial condition or cash flows. Drought or water depletion could adversely impact our ability to provide electricity to customers, cause early retirement of power plants and increase the cost for energy. Adverse events may result in increased insurance costs and/or decreased insurance availability. We may not recover all costs related to mitigating these physical and financial risks.
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ITEM 1B — UNRESOLVED STAFF COMMENTS |
None.
Virtually all of the utility plant property of PSCo is subject to the lien of its first mortgage bond indenture.
| Station, Location and Unit | | Fuel | | Installed | | MW (a) | | |
Station, Location and Unit at Dec. 31, 2022 | | Station, Location and Unit at Dec. 31, 2022 | | Fuel | | Installed | | MW (a) | |
Steam: | Steam: | | | | | | | | Steam: | | | | | | | |
Comanche-Pueblo, CO (b) | Comanche-Pueblo, CO (b) | | Comanche-Pueblo, CO (b) | |
Unit 1 | | Coal | | 1973 | | 325 | | | |
Unit 2 | Unit 2 | | Coal | | 1975 | | 335 | | | Unit 2 | | Coal | | 1975 | | 335 | | |
Unit 3 | Unit 3 | | Coal | | 2010 | | 500 | | (c) | Unit 3 | | Coal | | 2010 | | 500 | | (b) |
Craig-Craig, CO, 2 Units (d) | | Coal | | 1979 - 1980 | | 82 | | (e) | |
Hayden-Hayden, CO, 2 Units (h) | | Coal | | 1965 - 1976 | | 233 | | (f) | |
Craig-Craig, CO, 2 Units | | Craig-Craig, CO, 2 Units | | Coal | | 1979 - 1980 | | 82 | | (c) |
Hayden-Hayden, CO, 2 Units | | Hayden-Hayden, CO, 2 Units | | Coal | | 1965 - 1976 | | 233 | | (d) |
Pawnee-Brush, CO, 1 Unit | Pawnee-Brush, CO, 1 Unit | | Coal | | 1981 | | 505 | | | Pawnee-Brush, CO, 1 Unit | | Coal | | 1981 | | 505 | | |
Cherokee-Denver, CO, 1 Unit | Cherokee-Denver, CO, 1 Unit | | Natural Gas | | 1968 | | 310 | | | Cherokee-Denver, CO, 1 Unit | | Natural Gas | | 1968 | | 310 | | |
Combustion Turbine: | Combustion Turbine: | | Combustion Turbine: | |
Blue Spruce-Aurora, CO, 2 Units | Blue Spruce-Aurora, CO, 2 Units | | Natural Gas | | 2003 | | 264 | | | Blue Spruce-Aurora, CO, 2 Units | | Natural Gas | | 2003 | | 264 | | |
Cherokee-Denver, CO, 3 Units | Cherokee-Denver, CO, 3 Units | | Natural Gas | | 2015 | | 576 | | | Cherokee-Denver, CO, 3 Units | | Natural Gas | | 2015 | | 576 | | |
Fort St. Vrain-Platteville, CO, 6 Units | Fort St. Vrain-Platteville, CO, 6 Units | | Natural Gas | | 1972 - 2009 | | 968 | | | Fort St. Vrain-Platteville, CO, 6 Units | | Natural Gas | | 1972 - 2009 | | 973 | | |
Manchief, CO, 2 Units (f) | | Manchief, CO, 2 Units (f) | | Natural Gas | | 2000 | | 250 | | |
Rocky Mountain-Keenesburg, CO, 3 Units | Rocky Mountain-Keenesburg, CO, 3 Units | | Natural Gas | | 2004 | | 580 | | | Rocky Mountain-Keenesburg, CO, 3 Units | | Natural Gas | | 2004 | | 580 | | |
Various locations, 8 Units | Various locations, 8 Units | | Natural Gas | | Various | | 251 | | | Various locations, 8 Units | | Natural Gas | | Various | | 251 | | |
Hydro: | Hydro: | | Hydro: | |
Cabin Creek-Georgetown, CO | Cabin Creek-Georgetown, CO | | Cabin Creek-Georgetown, CO | |
Pumped Storage, 2 Units | Pumped Storage, 2 Units | | Hydro | | 1967 | | 210 | | | Pumped Storage, 2 Units | | Hydro | | 1967 | | 210 | | |
Various locations, 8 Units | | Hydro | | Various | | 25 | | | |
Various locations, 6 Units | | Various locations, 6 Units | | Hydro | | Various | | 23 | | |
Wind: | Wind: | | Wind: | |
Rush Creek, CO, 300 units | Rush Creek, CO, 300 units | | Wind | | 2018 | | 582 | | (g) | Rush Creek, CO, 300 units | | Wind | | 2018 | | 582 | | (e) |
Cheyenne Ridge, CO, 229 units | Cheyenne Ridge, CO, 229 units | | Wind | | 2020 | | 477 | | (g) | Cheyenne Ridge, CO, 229 units | | Wind | | 2020 | | 477 | | (e) |
| | Total | | 6,223 | | | | Total | | 6,151 | | |
(a) Summer 2020Summer 2022 net dependable capacity.
(b)Based on PSCo’s ownership of In 2018, the CPUC approved early retirement of PSCo’s Comanche Units 1 and 2 in 2022 and 2025, respectively.67%.
(c) Based on PSCo’s ownership of 67%10%.
(d)Craig Unit 1 and 2 are expected to be retired early in 2025 and 2028, respectively.
(e) Based on PSCo’s ownership of 10%.
(f) Based on PSCo’s ownership of 76% of Unit 1 and 37% of Unit 2.
(g)(e) Values disclosed are the generation levels at the point-of-interconnection. Capacity is attainable only when wind conditions are sufficiently available (on-demand net dependable capacity is zero).available.
(h)(f) Hayden Unit 1 and 2 are expected to be retiredPurchased in 2028 and 2027, respectively.2022.
Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2020:2022:
| | | | | |
Conductor Miles | |
Transmission | |
| |
345 KV | 5,3895,418 | |
230 KV | 12,13112,141 | |
| |
138 KV | 92 | |
115 KV | 5,0925,011 | |
Less than 115 KV | 1,6821,839 | |
Total Transmission | 24,38624,501 | |
| |
Distribution | |
Less than 115 KV | 78,48379,331 | |
| |
Total | 102,869103,832 | |
PS
Co had 238 electric utility transmission and distribution substations at Dec. 31, 2022.
PSCo had 236 electric utility transmission and distribution substations at Dec. 31, 2020.
Natural gas utility mains at Dec. 31, 2020:2022:
| | | | | |
Miles | |
Transmission | 2,0582,067 | |
Distribution | 22,81523,542 | |
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ITEM 3 — LEGAL PROCEEDINGS |
PSCo is involved in various litigation matters in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for losses probable of being incurred and subject to reasonable estimation.
Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to, when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.
For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, would have a material effect on PSCo’s consolidated financial statements. Unless otherwise required by GAAP, legalLegal fees are generally expensed as incurred.
See Note 10 to the consolidated financial statements, Item 1 and Item 7 for further information.
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ITEM 4 — MINE SAFETY DISCLOSURES |
None.
PART II
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ITEM 5 — MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES |
PSCo is a wholly owned subsidiary of Xcel Energy Inc. and there is no market for its common equity securities.
See Note 5 to the consolidated financial statements for further information.
The dividends declared during 20202022 and 20192021 were as follows:
| (Millions of Dollars) | (Millions of Dollars) | | 2020 | | 2019 | (Millions of Dollars) | | 2022 | | 2021 |
First quarter | First quarter | | $ | 103 | | | $ | 99 | | First quarter | | $ | 129 | | | $ | 115 | |
Second quarter | Second quarter | | 465 | | | 105 | | Second quarter | | 132 | | | 120 | |
Third quarter | Third quarter | | 128 | | | 97 | | Third quarter | | 127 | | | 127 | |
Fourth quarter | Fourth quarter | | 128 | | | 177 | | Fourth quarter | | 119 | | | 104 | |
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ITEM 6 — SELECTED FINANCIAL DATA[RESERVED] |
Omitted per conditions set forth in general instructions I(1)(a) and (b) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).
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ITEM 7 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
Discussion of financial condition and liquidity for PSCo is omitted per conditions set forth in general instructions I(1)(a) and (b) of Form 10-K for wholly owned subsidiaries. It is replaced with management’s narrative analysis and the results of operations for the current year as set forth in general instructions I(2)(a) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).
Non-GAAP Financial Measures
The following discussion includes financial information prepared in accordance with GAAP, as well as certain non-GAAP financial measures such as electric margin, natural gas margin and ongoing earnings. Generally, a non-GAAP financial measure is a measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are adjusted from measures calculated and presented in accordance with GAAP.
PSCo’s management uses non-GAAP measures for financial planning and analysis, for reporting of results to the Board of Directors, in determining performance-based compensation and communicating its earnings outlook to analysts and investors. Non-GAAP financial measures are intended to supplement investors’ understanding of our performance and should not be considered alternatives for financial measures presented in accordance with GAAP. These measures are discussed in more detail below and may not be comparable to other companies’ similarly titled non-GAAP financial measures.
Electric and Natural Gas Margins
Electric margin is presented as electric revenues less electric fuel and purchased power expenses. Natural gas margin is presented as natural gas revenues less the cost of natural gas sold and transported. Expenses incurred for electric fuel and purchased power and the cost of natural gas are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues.Management believes electric and natural gas margins provide the most meaningful basis for evaluating our operations because they exclude the revenue impact of fluctuations in these expenses.
These margins can be reconciled to operating income, a GAAP measure, by including other operating revenues, cost of sales-other, O&M expenses, conservation and DSM expenses, depreciation and amortization and taxes (other than income taxes).
Earnings Adjusted for Certain Items (Ongoing Earnings)
Ongoing earnings reflect adjustments to GAAP earnings (net income) for certain items.
Management usesWe use these non-GAAP financial measures to evaluate and provide details of PSCo’s core earnings and underlying performance. Management believesWe believe these measurements are useful to investors to evaluate the actual and projected financial performance and contribution of PSCo. For the years ended Dec. 31, 20202022 and 2019,2021, there were no such adjustments to GAAP earnings and therefore GAAP earnings equal ongoing earnings.
20202022 Comparison to 20192021
PSCo’s net income was $588was $727 million for 2022, compared with $660 million for 2020, compared with $578 million for 2019. The increase reflected higher electric margin (wholesale transmission revenue and2021, driven by regulatory outcomes offset lower sales due to COVID-19), increased AFUDC and higher natural gas margin,favorable weather. Higher revenues were partially offset by additionalhigher depreciation, O&M expenses and taxes (other than income taxes).interest charges.
Electric Margin
Electric margin is presented as electric revenues less electric fuel and purchased power expenses. Expenses incurred for electric fuel and purchased power are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues.
Electric revenues and fuel and purchased power expenses are impacted by fluctuations in the price of natural gas and coal. However, these fluctuations have minimal impact on margin due to fuel recovery mechanisms. In addition, electric customers receive a credit for PTCs generated, which reduce electric revenue and margin (offset by lower tax expense).
Electric Revenues, Fuel and Margin:Purchased Power and Electric Margin
| (Millions of Dollars) | (Millions of Dollars) | | 2020 | | 2019 | (Millions of Dollars) | | 2022 | | 2021 |
Electric revenues | Electric revenues | | $ | 3,116 | | | $ | 3,033 | | Electric revenues | | $ | 3,795 | | | $ | 3,413 | |
Electric fuel and purchased power | Electric fuel and purchased power | | (1,132) | | | (1,083) | | Electric fuel and purchased power | | (1,485) | | | (1,336) | |
Electric margin | Electric margin | | $ | 1,984 | | | $ | 1,950 | | Electric margin | | $ | 2,310 | | | $ | 2,077 | |
Changes in Electric Margin:Margin
| | | | | | | | |
(Millions of Dollars) | | 20202022 vs. 20192021 |
Regulatory rate outcomesoutcome | | $ | 73150 | |
Sales and demand (a) | | 35 | |
Non-fuel riders | | 1623 | |
Wholesale transmission revenue (net) | | 127 | |
Conservation incentive | | 3 | |
Estimated impact of weather (net of decoupling) | | (2) | |
PTCs flowed back to customers (offset by lower ETR) | | (17) | |
Sales and demand(a)
| | (49) | |
Other (net) | | (2)18 | |
Total increase in electric margin | | $ | 34233 | |
(a)Sales excludes weather impact, net of decoupling, and demand revenue is not impacted by decoupling.
Natural Gas Margin
Natural gas margin is presented as natural gas revenues less the cost of natural gas sold and transported. Expenses incurred for the cost of natural gas sold are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues.
Natural gas expense varies with changing sales and the cost of natural gas. However, fluctuations in the cost of natural gas hasgenerally have minimal earnings impact on margin due to cost recovery mechanisms.
Natural Gas Revenues, Cost of Natural Gas Sold and Margin:Transported and Natural Gas Margin
| (Millions of Dollars) | (Millions of Dollars) | | 2020 | | 2019 | (Millions of Dollars) | | 2022 | | 2021 |
Natural gas revenues | Natural gas revenues | | $ | 1,024 | | | $ | 1,161 | | Natural gas revenues | | $ | 1,860 | | | $ | 1,355 | |
Cost of natural gas sold and transported | Cost of natural gas sold and transported | | (374) | | | (526) | | Cost of natural gas sold and transported | | (1,053) | | | (606) | |
Natural gas margin | Natural gas margin | | $ | 650 | | | $ | 635 | | Natural gas margin | | $ | 807 | | | $ | 749 | |
Changes in Natural Gas Margin:Margin
| | | | | | | | |
(Millions of Dollars) | | 20202022 vs. 20192021 |
Estimated impact of weather | | $ | 29 | |
Regulatory rate outcomes | | $ | 1923 | |
Infrastructure and integrity riders | | 115 | |
| | |
Conservation incentiveWinter Storm Uri disallowances | | 1 (4) | |
Estimated impact of weather | | (11) | |
Transport sales | | (2) | |
Sales decline | | (2) | |
Other (net) | | (1)5 | |
Total increase in natural gas margin | | $ | 1558 | |
Non-Fuel Operating Expenses and Other Items
Taxes (Other than Income Taxes)O&M Expenses — — Taxes (other than income taxes)O&M expenses increased $28$74 million or 14%, year-to-date,year-to-date. The increase was primarily due to higher property taxes.inflation and impacts of supply chain constraints; operational activities (vegetation management and repairs/maintenance); costs for technology and customer programs; bad debt; and other.
Depreciation and Amortization — Depreciation and amortization increased $53$104 million, or 9%, year-to-date, primarily driven by normal system expansion, new depreciation rates implemented in March 2020 and the Cheyenne Ridge wind farm going into service.year-to-date. The increase in depreciation was partially offset by a decrease in amortization of the pension regulatory asset.
AFUDC, Equity and Debt— AFUDC increased by $16 million year-to-date, primarily due to the Cheyenne Ridge wind farm.capital investment and new electric and natural gas depreciation rates.
Income TaxesInterest Charges — Income tax expense decreased $35 Interest expenses increased $28 million for 2020,year-to-date. The increase was primarily driven by an increase in wind PTCs and an increase in plant-related regulatory differences. Wind PTCs are credited to customers (recorded as a reduction to revenue) and do not have a material impact on net income. The ETR was 7.1% for 2020 compared with 12.2% for 2019, largely due to the adjustments referenced above.higher long-term debt levels to fund capital investments and higher interest rates.
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Public Utility Regulation |
The FERC and state and local regulatory commissions regulate PSCo. PSCo is subject to rate regulation by state utility regulatory agencies, which have jurisdiction with respect to the rates of electric and natural gas distribution companies in Colorado.
Rates are designed to recover plant investment, operating costs and an allowed return on investment. Our utility subsidiaries requestPSCo requests changes in utility rates for utility services through filings with governing commissions.commission filings. Changes in operating costs can affect PSCo’s financial results, depending on the timing of rate case filingscases and implementation of final rates. Other factors affecting rate filings are new investments, sales, conservation and DSM efforts, and the cost of capital.
In addition, the regulatory commissions authorize the ROE, capital structure and depreciation rates in rate proceedings. Decisions by these regulators can significantly impact PSCo’s results of operations.operations and credit quality.
See Rate Matters within Note 10 to the consolidated financial statements for further information.
Summary of Regulatory Agencies / RTO and Areas of Jurisdiction | | | | | | | | |
Regulatory Body / RTO | | Additional Information on Regulatory Authority |
CPUC | | Retail rates, accounts, services, issuance of securities and other aspects of electric, natural gas and steam operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Certifies the need and siting for generating plans greater than 50 MW. Pipeline safety compliance. |
FERC | | Wholesale electric operations, accounting practices, hydroelectric licensing, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with the NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce. Wholesale electric sales at cost-based prices to customers inside PSCo’s balancing authority area and at market-based prices to customers outside PSCo’s balancing authority area. PSCo holds a FERC certificate that allows it to transport natural gas in interstate commerce without PSCo becoming subject to full FERC jurisdiction. |
RTO | | PSCo is not presently a member of an RTO and does not operate within an RTO energy market. However, PSCo does make certain sales to other RTO’s, including SPP and participates in a joint dispatch agreement with neighboring utilities. |
DOT | | Pipeline safety compliance. |
Recovery Mechanisms | | | | | | | | |
Mechanism | | Additional Information |
ECA | | Recovers fuel and purchased energy costs. Short-term sales margins are shared with customers through the ECA.customers. The ECA is revised quarterly. |
PCCAPurchased Capacity Cost Adjustment | | Recovers purchased capacity payments. |
SCASteam Cost Adjustment | | Recovers fuel costs to operate the steam system. The SCASteam Cost Adjustment rate is revised quarterly. |
DSMCADSM Cost Adjustment | | Recovers electric and gas DSM, interruptible service costs and performance initiatives for achieving energy savings goals. |
RESARES Adjustment | | Recovers the incremental costs of compliance with the RES with a maximum of 1% of the customer’s bill. |
CEPAColorado Energy Plan Adjustment | | Recovers the early retirement costs of Comanche units 1 and 2 to a maximum of 1% of the customer’s bill. |
WCAWind Cost Adjustment | | Recovers costs for customers who choose renewable resources. |
TCATransmission Cost Adjustment | | Recovers costs for transmission investment between rate cases. |
CACJA | | Recovers costs associated with the CACJA. |
FCAFuel Clause Adjustment | | PSCo recovers fuel and purchased energy costs from wholesale electric customers through a fuel cost adjustment clause approved by the FERC. Wholesale customers pay production costs through a forecasted formula rate subject to true-up. |
GCA | | Recovers costs of purchased natural gas and transportation and is revised quarterly to allow for changes in natural gas rates. |
PSIAPipeline system integrity adjustment | | Recovers costs for transmission and distribution pipeline integrity management programs.programs (rider ended on Dec. 31, 2022). |
Decoupling | | Mechanism to true-up revenue to a baseline amount for residential (excluding lighting and demand) and metered non-demand small C&I classes. Represents approximately $51M for differences |
Transportation Electrification Plan | | Recovers costs associated with the investment in sales to the baseline amount. Amounts refunded or surcharged to customers may be limited to a refund cap.and adoption of transportation electrification infrastructure. |
Pending and Recently Concluded Regulatory Proceedings | | | | | | | | | | | | | | | | | | | | |
Proceeding | | Amount (in millions) | | Filing Date | | Approval |
2020 Natural Gas Rate Case | | $77 | | February 2020 | | Received |
2019 Electric Rate Case | | 108 | | May 2019 | | Received |
2019 Natural Gas Rate Case Appeal | | N/A | | April 2019 | | Pending |
Wildfire Protection Rider | | 325 | | July 2020 | | Pending |
Transportation Electrification Plan Rider | | 110 - 138 | | May 2020 | | Received |
Additional Information:
2020Colorado Natural Gas Rate Case —In October 2020, the CPUC approved a settlement resulting in a net increase of $77 million. This increase reflects a $94 million increase in base rate revenue, partially offset by $17 million of costs previously recovered through the Pipeline Integrity rider. Rates will be implemented on April 1, 2021 (retroactive to November 2020).
2019 Electric Rate Case — In 2019,January 2022, PSCo filed a request with the CPUC seeking a net increase to retail natural gas rates of $107 million. The total change to base rates is $215 million, which reflects the transfer of $108 million previously recovered from customers through the pipeline system integrity adjustment rider. The request was based on a 10.25% ROE, an equity ratio of 55.66% and a 2022 current test year with a projected rate base of $3.6 billion.
PSCo’s request also included step revenue increases of $40 million (effective Nov. 1, 2023) and $41 million (effective Nov. 1, 2024) related to continued capital investment.
In October 2022, the CPUC approved a rate increase net of approximately $108rider roll-ins of $64 million. In February 2020, the CPUC issued an initialThe decision forreflects a net rate increasestated WACC of $35 million. In July 2020, the CPUC’s final written decision on rehearing was received and resulted in an additional increase of approximately $12 million annually.
In December 2020, the CPUC denied PSCo’s request of6.7%, a $5 million surcharge for changes to the revenue increase from the effective date of rates, based on the CPUC’s decision on rehearing. PSCo has appealed this decisionhistoric test year with the District Court of Denver County.
2019 Phase I Electric Rate Case Appeal — In August 2020, PSCo filed an appeal with the Denver District Court seeking a review of CPUC decisions on gain on sales and losses of assets, oil and gas royalty revenues and Board of Director’s equity compensation. PSCo plans to seek consolidation of this appeal with the appeal of the surcharge decision in this same proceeding.
2019 Natural Gas Rate Case Appeal — In April 2019, PSCo filed an appeal seeking judicial review of the CPUC’s prior ruling regarding PSCo’s natural gas rate case (filed in June 2017 and approved in December 2018). The appeal requested review of the following: denial of a return on the prepaid pension and retiree medical assets; the use of a capital structure not based on the actual historical test year; and use of an average rate base methodology rather than a year-end rate base methodology.and $16 million of incremental depreciation expense. PSCo has the option to determine its ROE within a range of 9.2% to 9.5% and its equity ratio within a range of 52% to 55%, as long as it results in a WACC of 6.7%. The CPUC denied the 2023-2024 step increases. Base rates were placed in effect November 1, 2022.
Colorado Electric Rate Case — In November 2022, PSCo filed an electric rate case seeking a net increase of $262 million, or 8.2%. The total request reflects a $312 million increase, which includes $50 million of authorized costs currently recovered through various rider mechanisms. The request is based on a 10.25% ROE, an equity ratio of 55.7% and a 2023 forecast test year with a 2023 year-end rate base of $11.3 billion. PSCo requested rates effective in September 2023. A procedural schedule is expected to be established by the CPUC in the first quarter of 2023.
Colorado Resource Plan— In August 2022, the CPUC approved an updated settlement, which will result in the further acceleration of the retirement of the Comanche Unit 3 coal plant, an expected carbon reduction of at least 85% and an 80% renewable mix by 2030. The CPUC deferred a decision on the method of cost recovery for the retiring coal units to a separate docket, which will consider accelerated depreciation, creation of regulatory assets and securitization. PSCo filed the recovery method docket in the fourth quarter of 2022.
Key settlement terms include:
•Early retirement of Hayden: Unit 2 in 2027 (was 2036); and Unit 1 in 2028 (was 2030).
•Conversion of the Pawnee coal plant to natural gas by no later than Jan. 1, 2026.
•Early retirement of Comanche Unit 3 by Jan. 1, 2031 (was 2070) with reduced operations beginning in 2025.
•Addition of ~2,400 MW of wind.
•Addition of ~1,600 MW of universal-scale solar.
•Addition of 400 MW of storage.
•Addition of 1,300 MW of flexible, dispatchable generation.
•Addition of ~1,200 MW of distributed solar resources through our renewable energy programs.
In December 2022 the Company commenced the request for proposal process for generation resources with a bid receipt date of March 2020, The District Court of Denver County ruled in favor of allowing1, 2023. After reviewing the prepaid pension assetsbids received, PSCo will file a report with the CPUC with recommended resource acquisitions and a CPUC decision on the resources to be includedacquired is expected in October 2023.
Decoupling Filing—PSCo has a decoupling program, effective April 1, 2020 through Dec. 31, 2023. The program applies to Residential and metered small C&I customers who do not pay a demand charge. The program includes a refund and surcharge cap not to exceed 3% of forecasted base rate base; but upheld the CPUC’s treatmentrevenue for a specified period.
In October 2021, a settlement was reached on Winter Storm Uri costs and also addressed certain components of the retiree medical assets2020 decoupling refunds.
In April 2022, PSCo made its annual filing on this matter. In December 2022, the ALJ approved a settlement between PSCo, CPUC Staff and capital structure methodology. In March 2021,the UCA. The settlement requires PSCo expects to file a motionpetition for declaratory judgment to implementaddress the District Court’s decision on treatment of any expired balance under the prepaid pension asset3% soft cap provisions.
As of Dec. 31, 2022, PSCo has recognized a refund for the applicable period of Jan. 1, 2018 through Oct. 31, 2020.
Wildfire Protection Rider —InResidential customers and a surcharge for small C&I customers based on 2020, PSCo requested to establish a rider to recover incremental costs associated with system investments to reduce wildfire risk. The rider would be effective in June 2021 and continue through 2025. The Office of Consumer Counsel and CPUC Staff are supportive of the wildfire mitigation program as proposed, but oppose rider recovery and instead recommend deferral of certain costs with recovery in a future rate case. A CPUC decision is expected in the second quarter of 2021.
Wildfire Protection capital investment is projected to be approximately $325 million. Forecasted annual revenue requirements from 2021 through 2025:
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(Millions of Dollars) | | 2021 | | 2022 | | 2023 | | 2024 | | 2025 |
Forecasted annual revenue requirement | | $ | 17 | | | $ | 24 | | | $ | 29 | | | $ | 32 | | | $ | 34 | |
2022 results.Transportation Electrification Plan Transmission Cost Adjustment — In January 2021,December 2022, the CPUC approved PSCo's Transportation Electrification Plan, which authorizes rider recoverysuspended PSCo’s request for 2023 TCA rate changes. The CPUC Staff protested the TCA on the grounds that only projects resulting in new transmission should be included and no repair or replacement of new electric vehicle utility programs forexisting infrastructure should be included. The CPUC consolidated the residential, commercial, multi-family and public charging sectors. The approval establishes utility-owned charging infrastructure and chargers and amortization of rebates for electric vehicles. The Transportation Electrification Plan approval authorizes approximately $110 million in spending with flexibility up to approximately $138 million over three years.
Advanced Grid Rider
In 2020, PSCo requested to establish a rider to recover incremental costs associatedmatter with the Advanced Grid Intelligence and Security initiative. The rider would be effective in May 2021 and continue through 2025. In October 2020, an Administrative Law Judge issued The Recommended Decision granting the Office of Consumer Counsel motion to dismiss the Advanced Grid Rider. PSCo has chosen not to appeal the Administrative Law Judge’s Recommended Decision.
The PSCo portion of the Advanced Grid Intelligence and Security capital investment is projected to be approximately $850 million. Forecasted annual revenue requirements from 2021 through 2025 are as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
(Millions of Dollars) | | 2021 | | 2022 | | 2023 | | 2024 | | 2025 |
Forecasted annual revenue requirement | | $ | 53 | | | $ | 69 | | | $ | 83 | | | $ | 89 | | | $ | 99 | |
pending electric rate case for assessment.
PSCo KEPCO Filing
ECA Fuel Recovery — In September 2020,December 2022, PSCo filed withits first quarter 2023 ECA Advice Letter, which sought to recover $123 million of under-recovered 2022 fuel costs over two quarters (instead of the typical one). In December 2022, the CPUC found that the $123 million should be removed from the proposed ECA rates and required PSCo to file a separate application to recover these fuel costs. Proposed ECA rates were updated to remove the 2022 under-recovered balance and were implemented on Jan. 1, 2023. In February 2023, PSCo submitted an interim ECA filing which included $70 million of the 2022 under-recovered costs. A filing for the remaining amount is anticipated in the first quarter of 2023.
GCA NOPR— In June 2021, the CPUC issued a NOPR addressing the recovery of costs through the GCA. The CPUC has reopened the GCA NOPR and proposed a 2-step process aimed at 1) considering near term process changes to the GCA and 2) a longer term process to evaluate potential performance incentive structures. In step 1, consensus proposed rule amendments to update the process and filing requirements for GCA and related filings have been submitted to the CPUC for approvalconsideration. PSCo worked with other utilities and stakeholders regarding consensus proposed rule amendments for step 2, including a provision that each LDC bring forward its own performance incentive mechanism in a future filing. In December 2022, the CPUC approved the consensus proposal.
In February 2023, the Governor of Colorado issued an open letter to terminate a solar PPA with KEPCO Solar of Alamosa, Inc.the CPUC, utilities, and establish a regulatory assetother stakeholders directing agencies to recover transaction costs of approximately $41 million. By terminating the PPA, customers would save approximately $38 million over an 11-year period. A CPUC decisiontake additional steps to address energy costs. It is expectedlikely this request will result in the second quarteropening of 2021.
Natural Gas LDCadditional dockets to further explore the GCA and Emission Reductions
In October 2020,other related mechanisms. Additionally, the CPUC opened a docket to investigate topics related to natural gas emissions in relation to statewide emission reduction goals. The first meeting was held in November 2020, in which subject matter experts discussed greenhouse emission reductions required from the natural gas industry in regard to the statewide goals.
Resource Plan
PSCo is expected to file its next Electric Resource Plan on March 31, 2021. The filing will propose the future of the remaining coal plants in Colorado and PSCo’s plan to achieve it’s 80% carbon emissions reduction target by 2030. A CPUC decision is expected in 2022.
PSCo — Comanche Unit 3
PSCo is part owner and operator of Comanche Unit 3, a 750 MW, coal-fueled electric generating unit. In January 2020, the unit experienced a turbine failure causing the unit to be taken offline for repairs, which were completed in June 2020. During start-up the unit experienced a loss of turbine oil, which damaged the plant. Comanche Unit 3 recommenced operations in January 2021. Replacement and repair of damaged systems in excess of a $2 million deductible are expected to be recovered through insurance policies. PSCo obtained replacement power costs of approximately $16 million during the outage. In October 2020, the CPUC initiated a non-adjudicatory review of Comanche Unit 3’s performance. A report on performance is expected to be issued in March 2021. At this stage of the regulatory review, the resulting recommendations of the CPUC’s staff cannot be determined.
Boulder Municipalization
In 2011, Boulder passed a ballot measure authorizingLegislature announced the formation of an electric municipal utility. Subsequently, there have been various legal proceedings in multiple venues.a Joint Select Committee to investigate the source of rising utility rates and explore potential actions to prevent future price instability.
Natural Gas Planning NOPR — In September 2020, the City Council voted to approve a settlement between PSCo and Boulder officials to end the city’s municipalization effort. The settlement resulted in a 20-year franchise arrangement (with multiple opt-out conditions), an energy partnership and an undergrounding agreement. It also established the municipalization process if Boulder exercised an opt-out. In December 2020, PSCo filed the franchise agreement withOctober 2021, the CPUC issued a NOPR to implement recent state legislation requiring natural gas utilities to develop clean heat plans to meet state greenhouse gas emission reduction targets, as well as updated demand-side management criteria. Additionally, the proposed rules included new comprehensive natural gas infrastructure planning requirements and is currently awaiting a decision.related Certificate of Public Convenience and Necessity application procedures, changes in natural gas line extension policy, and details on emission accounting related to clean heat plans. PSCo recommended changes to the proposed rules, which may be incorporated into the final rules issued in the first quarter of 2023.
Purchased Power and Transmission Service Providers
PSCo expects to meet its system capacity requirements through electric generating stations, power purchases, new generation facilities, DSM options and expansion of generation plants.
Purchased Power — PSCo purchases power from other utilities and IPPs. Long-term purchased power contracts for dispatchable resources typically require capacity and energy charges. It also contracts to purchase power for both wind and solar resources. PSCo makes short-term purchases to meet system load and energy requirements, replace owned generation, meet operating reserve obligations, or obtain energy at a lower cost.
Energy Markets — PSCo is working towards joiningplans to join the SPP Western Energy Imbalance Service Market in 2022.April 2023. This market was developed byis an incremental step in the California ISO and allows PSCo access to a real-time energyparticipation in the organized wholesale market. The Western Energy Imbalance Market allowsimbalance markets allow participants to buy and sell power close to the time electricity is consumed and gives system operators real-time visibility across neighboring grids. The result improves balancing supply and demand at a lower cost.
Purchased Transmission Services — In addition to using its own transmission system, PSCo has contracts with regional transmission service providers to deliver energy to its customers.
Wholesale and Commodity Marketing Operations
PSCo conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy related products. PSCo uses physical and financial instruments to minimize commodity price and credit risk and hedge sales and purchases. PSCo also engages in trading activity unrelated to hedging.these hedging activities. Sharing of any margin is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement.
Supply Chain
PSCo’s ability to meet customer energy requirements, respond to storm-related disruptions and execute our capital expenditure program are dependent on maintaining an efficient supply chain. Manufacturing processes have experienced disruptions related to scarcity of certain raw materials and interruptions in production and shipping. These disruptions have been further exacerbated by inflationary pressures, labor shortages and the impact of international conflicts/issues. PSCo continues to monitor the situation as it remains fluid and seeks to mitigate the impacts by securing alternative suppliers, modifying design standards, and adjusting the timing of work.
Electric Distribution and Transmission Transformers
The availability of certain transformers is an industry-wide issue that has been significantly impacted and in some cases may result in delays in projects and new customer connections. PSCo continues to seek alternative suppliers and prioritize work plans to mitigate impacts of supply constraints.
Marshall Wildfire
In December 2021, a wildfire ignited in Boulder County, Colorado (the “Marshall Fire”), which burned over 6,000 acres and destroyed or damaged over 1,000 structures. Boulder County authorities are currently investigating the fire and have not yet determined a cause. There were no downed power lines in the ignition area, and nothing the Company has seen to this point indicates that our equipment or operations caused the fire.
In Colorado, the standard of review governing liability differs from the “inverse condemnation” or strict liability standard utilized in California. In Colorado, courts look to whether electric power companies have operated their system with a heightened duty of care consistent with the practical conduct of its business, and liability does not extend to occurrences that cannot be reasonably anticipated. In addition, PSCo has been operating under a commission approved wildfire mitigation plan and carries wildfire liability insurance.
In March 2022, a class action suit was filed in Boulder County pertaining to the Marshall Fire. In the remote event PSCo was found liable related to this litigation and were required to pay damages, such amounts could exceed our insurance coverage and have a material adverse effect on our financial condition, results of operations or cash flows. In June 2022, Plaintiffs served the class action lawsuit. In July 2022, PSCo filed a Motion to Dismiss. The District Court judge presiding over the case denied PSCo’s Motion to Dismiss in December 2022.
Inflation Reduction Act
In August 2022, the IRA was signed into law.
Key provisions impacting PSCo include:
•Extends current PTC and ITC for renewable technologies (e.g., wind and solar).
•Restores full value of the PTC and ITC for qualifying facilities placed in-service after 2021.
•Creates a PTC for solar, clean hydrogen and nuclear.
•Establishes an ITC for energy storage, microgrids, interconnection facilities, etc.
•Allows companies to monetize or sell credits to unrelated parties.
PSCo anticipates the IRA will drive significant customer savings for both new and existing Company owned renewable projects, assuming appropriate regulatory mechanisms and development of a market for the sale of tax credits. The IRA is expected to allow PSCo to monetize tax credits more efficiently with the incremental benefits passed through to customers.
In addition, the IRA created a new corporate AMT. PSCo does not anticipate AMT having a material cash impact based on current estimates and our interpretation of AMT application.
Winter Storm Uri
In February 2021, the United States experienced Winter Storm Uri. Extreme cold temperatures impacted certain operational assets as well as the availability of renewable generation. The cold weather also affected the country’s supply and demand for natural gas. These factors contributed to extremely high market prices for natural gas and electricity. As a result of the extremely high market prices, PSCo incurred net natural gas, fuel and purchased energy costs of approximately $610 million (largely deferred as regulatory assets).
In May 2021, PSCo filed a request with the CPUC to recover $263 million in weather-related electric costs, $287 million in incremental natural gas costs and $4 million in incremental steam costs over 24 months with no financing charge.
In May 2022, an ALJ recommended full recovery of all costs with no cost disallowances. In July 2022, the CPUC approved a partial settlement providing full recovery of fuel costs, with the exception of an $8 million disallowance, over 24 months for electric and 30 months for natural gas customers.
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ITEM 7A — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
Derivatives, Risk Management and Market Risk
PSCo is exposed to a variety of market risks in the normal course of business. Market risk is the potential loss that may occur as a result of adverse changes in the market or fair value offor a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk.
See Note 8 to the consolidated financial statements for further information.
PSCo is exposed to the impact of adverse changes in price for energy and energy-related products, which is partially mitigated by the use of commodity derivatives. In addition to ongoing monitoring and maintaining credit policies intended to minimize overall credit risk, management takes steps to mitigate changes in credit and concentration risks associated with its derivatives and other contracts, including parental guarantees and requests of collateral. While PSCo expects that the counterparties will perform underon the contracts underlying its derivatives, the contracts expose PSCo to certain credit and non-performance risk.
Distress in the financial markets may impact counterparty risk and the fair value of the securities in the pension fund and PSCo’s ability to earn a return on short-term investments.fund.
Commodity Price Risk — PSCo isWe are exposed to commodity price risk in itsour electric and natural gas operations. Commodity price risk is managed by entering into long and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products and fuels used in generation and distribution activities.
Commodity price risk is also managed through the use of financial derivative instruments. PSCo’sOur risk management policy allows itus to manage commodity price risk within each rate-regulated operation per commission approved hedge plans.
Wholesale and Commodity Trading Risk — PSCo conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. PSCo’s risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee.
Fair value of net commodity trading contracts as of Dec. 31, 2020:2022:
| | | Futures / Forwards Maturity | | Futures / Forwards Maturity |
(Millions of Dollars) | (Millions of Dollars) | | Less Than 1 Year | | 1 to 3 Years | | 4 to 5 Years | | Greater Than 5 Years | | Total Fair Value | (Millions of Dollars) | | Less Than 1 Year | | 1 to 3 Years | | 4 to 5 Years | | Greater Than 5 Years | | Total Fair Value |
PSCo (a) | PSCo (a) | | $ | — | | | $ | 1 | | | $ | — | | | $ | — | | | $ | 1 | | PSCo (a) | | $ | 10 | | | $ | 3 | | | $ | 3 | | | $ | — | | | $ | 16 | |
PSCo (b) | PSCo (b) | | (25) | | | (39) | | | (13) | | | — | | | (77) | | PSCo (b) | | (56) | | | (15) | | | 8 | | | — | | | (63) | |
| | $ | (25) | | | $ | (38) | | | $ | (13) | | | $ | — | | | $ | (76) | | | $ | (46) | | | $ | (12) | | | $ | 11 | | | $ | — | | | $ | (47) | |
| | | Options Maturity | | Options Maturity |
(Millions of Dollars) | (Millions of Dollars) | | Less Than 1 Year | | 1 to 3 Years | | 4 to 5 Years | | Greater Than 5 Years | | Total Fair Value | (Millions of Dollars) | | Less Than 1 Year | | 1 to 3 Years | | 4 to 5 Years | | Greater Than 5 Years | | Total Fair Value |
| PSCo (b) | PSCo (b) | | $ | 13 | | | $ | 16 | | | $ | 1 | | | $ | — | | | $ | 30 | | PSCo (b) | | $ | 40 | | | $ | 7 | | | $ | — | | | $ | — | | | $ | 47 | |
|
(a)Prices actively quoted or based on actively quoted prices.
(b)Prices based on models and other valuation methods.
Changes in the fair value of commodity trading contracts before the impacts of margin-sharing for the years ended Dec. 31:
| (Millions of Dollars) | (Millions of Dollars) | | 2020 | | 2019 | (Millions of Dollars) | | 2022 | | 2021 |
Fair value of commodity trading net contracts outstanding at Jan. 1 | Fair value of commodity trading net contracts outstanding at Jan. 1 | | $ | (57) | | | $ | 1 | | Fair value of commodity trading net contracts outstanding at Jan. 1 | | $ | (15) | | | $ | (46) | |
Contracts realized or settled during the period | Contracts realized or settled during the period | | 2 | | | (11) | | Contracts realized or settled during the period | | (8) | | | 4 | |
Commodity trading contract additions and changes during the period | Commodity trading contract additions and changes during the period | | 9 | | | (47) | | Commodity trading contract additions and changes during the period | | 23 | | | 27 | |
Fair value of commodity trading net contracts outstanding at Dec.31 | Fair value of commodity trading net contracts outstanding at Dec.31 | | $ | (46) | | | $ | (57) | | Fair value of commodity trading net contracts outstanding at Dec.31 | | $ | — | | | $ | (15) | |
At Dec. 31, 2020, aA 10% increase and 10% decrease in forward market prices for PSCo’s commodity trading contracts through the forward curve would increasehave likewise increased and decreased pretax income from continuing operations, by approximately $7 million whereas a 10% decrease would decrease pretax income from continuing operations by approximately $7 million. Atat Dec. 31, 2019, a 10% increase in market prices for commodity trading contracts would increase pretax income from continuing operations by approximately $32022 and $10 million whereas a 10% decrease would decrease pretax income from continuing operations by approximately $3 million.at Dec. 31, 2021. Market price movements can exceed 10% under abnormal circumstances.
PSCo’s commodity trading operations measure the outstanding risk exposure to price changes on contracts and obligations that have been entered into, but not closed, using an industry standard methodology known as VaR. VaR expresses the potential change in fair value onof the outstanding contracts and obligations over a particular period of time under normal market conditions.
The VaRs for the NSP-Minnesota and PSCo commodity trading operations, excluding both non-derivative transactions and derivative transactions designated as normal purchase,purchases and normal sales, calculated on a consolidated basis using a Monte Carlo simulation with a 95% confidence level and a one-day holding period, were as follows:
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(Millions of Dollars) | | Year Ended Dec. 31 | | VaR Limit | | Average | | High | | Low |
2020 | | $ | 1 | | | $ | 3 | | | $ | 1 | | | $ | 2 | | | $ | 1 | | |
2019 | | < 1 | | 3 | | | 1 | | | 1 | | | < 1 | |
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(Millions of Dollars) | | Year Ended Dec. 31 | | | | Average | | High | | Low |
2022 | | $ | 2 | | | | | $ | 1 | | | $ | 5 | | | $ | — | | |
2021 | | $ | 1 | | | | | $ | 2 | | | $ | 52 | | | $ | 1 | | |
A short-term increase in VaR occurred during the week of Feb. 12, 2021 through Feb. 18, 2021. On Feb. 17, 2021, the portfolio VaR reached a high of $52 million. This increase in VaR was driven by the unprecedented market conditions during Winter Storm Uri. Prior to this weather event, VaR was $1 million and returned to $1 million by Feb. 19, 2021.
Interest Rate Risk — PSCo is subject to interest rate risk. PSCo’s risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives such as swaps, caps, collars and put or call options.derivatives.
A 100 basis point change in the benchmark rate on PSCo’s variable rate debt would impact pretax interest expense annually by approximately $3 million and an immaterial amount in 20202022 and 2019,2021, respectively.
See Note 8The value of pension and postretirement plan assets and benefit costs are impacted by changes in discount rates and expected return on plan assets. PSCo’s ongoing pension and postretirement investment strategy is based on plan-specific investment recommendations that seek to optimize potential investment risk and minimize interest rate risk associated with changes in the consolidated financial statements for further information.obligations as a plan’s funded status increases over time. The impacts of fluctuations in interest rates on pension and postretirement costs are mitigated by pension cost calculation methodologies and regulatory mechanisms that minimize the earnings impacts of such changes.
Credit Risk — PSCo is also exposed to credit risk. Credit risk relates to the risk of loss resulting from counterparties’ nonperformance on their contractual obligations. PSCo maintains credit policies intended to minimize overall credit risk and actively monitormonitors these policies to reflect changes and scope of operations.
At Dec. 31, 2020,2022, a 10% increase in commodity prices would have resulted in an immaterial increase in credit exposure while a decrease in prices of 10% would have resulted in an immaterial decrease in credit exposure. At Dec. 31, 2019, a 10% increase in commodity prices would have resulted in a decrease in credit exposure of $3$13 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $6 million. At Dec. 31, 2021, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $7$6 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $5 million.
PSCo conducts credit reviews for all wholesale, trading and non-trading commodity counterparties and employs credit risk controls, such as letters of credit, parental guarantees, master netting agreements and termination provisions. Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. Distress in the financial markets could increase PSCo’s credit risk.
Fair Value Measurements
PSCo uses derivative contracts such as futures, forwards, interest rate swaps, options and FTRs to manage commodity price and interest rate risk. Derivative contracts, with the exception of those designated as normal purchase-normal sale contracts,purchases and normal sales, are reported at fair value.
PSCo’s investments held in rabbi trusts, pension and other postretirement funds are also subject to fair value accounting.
Commodity Derivatives — PSCo continuously monitors the creditworthiness of the counterparties to its commodity derivative contracts and assesses each counterparty’s ability to perform on the transactions. The impact of discounting commodity derivative assets for counterparty credit risk was not material to the fair value of commodity derivative assets at Dec. 31, 2020.
Adjustments to fair value for credit risk of commodity trading instruments are recorded in electric revenues. Credit risk adjustments for other commodity derivative instruments are recorded as other comprehensive income or deferred as regulatory assets and liabilities. Classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. The impact of discounting commodity derivative liabilities for credit risk was immaterial at Dec. 31, 2020.
See Notes 8 and 9 to the consolidated financial statements for further information.
Natural Gas Fuel and Electricity Purchases
In February 2021, the United States experienced winter storm Uri and extreme cold temperatures in the central United States. This severe weather event increased the demand for natural gas used in our electric and natural gas businesses. Certain operational assets were impacted by extreme cold temperatures and the cold further impacted the availability of renewable generation across the region (which typically acts as a hedge against commodity prices) contributing to extremely high market prices for natural gas and electricity. As a result, electric and natural gas fuel costs increased approximately $650 million. These amounts are preliminary estimates through Feb. 16, 2021 and are subject to final settlement.
PSCo has fuel recovery mechanisms to recover the increased cost of natural gas and electricity. However, given the impact of these higher costs to our customers during a pandemic, we expect our regulator to undertake a heightened review and we intend to work with our commission to recover these costs over time to help mitigate the impacts on customer bills. PSCo is taking action to increase planned debt issuances to ensure adequate liquidity for the timing difference between fuel payments and revenue collection from customers and to address any potential need to post collateral.
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ITEM 8 — FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
See Item 15-1 for an index of financial statements included herein.
See Note 14 to the consolidated financial statements for further information.
Management Report on Internal Control Over Financial Reporting
The management of PSCo is responsible for establishing and maintaining adequate internal control over financial reporting. PSCo’s internal control system was designed to provide reasonable assurance to Xcel Energy Inc.’s and PSCo’s management and board of directors regarding the preparation and fair presentation of published financial statements.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
PSCo management assessed the effectiveness of PSCo’s internal control over financial reporting as of Dec. 31, 2020.2022. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework (2013). Based on our assessment, we believe that, as of Dec. 31, 2020,2022, PSCo’s internal control over financial reporting is effective at the reasonable assurance level based on those criteria.
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/s/ BEN FOWKEROBERT C. FRENZEL | | /s/ BRIAN J. VAN ABEL |
Ben FowkeRobert C. Frenzel | | Brian J. Van Abel |
Chairman, Chief Executive Officer and Director | | Executive Vice President, Chief Financial Officer and Director |
Feb. 17, 202123, 2023 | | Feb. 17, 202123, 2023 |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholder and the Board of Directors of Public Service Company of Colorado
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Public Service Company of Colorado and subsidiaries (the "Company") as of December 31, 20202022 and 2019,2021, the related consolidated statements of income, comprehensive income, cash flows and common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 2020,2022, and the related notes and the schedule listed in the Index at Item 15 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 20202022 and 2019,2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020,2022, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulatory Assets and Liabilities - Impact of Rate Regulation on the Financial Statements — Refer to Notes 4 and 10 to the consolidated financial statements.
Critical Audit Matter Description
The Company is subject to rate regulation by state utility regulatory agencies, which have jurisdiction with respect to the rates of electric and natural gas distribution companies in Colorado. The Company is also subject to the jurisdiction of the Federal Energy Regulatory Commission for its wholesale electric operations, hydroelectric generation licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with North American Electric Reliability Corporation standards, asset transactions and mergers and natural gas transactions in interstate commerce, (collectively with state utility regulatory agencies, the “Commissions”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation affects multiple financial statement line items and disclosures, including property, plant and equipment, regulatory assets and liabilities, operating revenues and expenses, and income taxes.
The Company is subject to regulatory rate setting processes. Rates are determined and approved in regulatory proceedings based on an analysis of the Company’s costs to provide utility service and a return on, and recovery of, the Company’s investment in assets required to deliver services to customers. Accounting for the Company’s regulated operations provides that rate-regulated entities report assets and liabilities consistent with the recovery of those incurred costs in rates, if it is probable that such rates will be charged and collected. The Commissions’ regulation of rates is premised on the full recovery of incurred costs and a reasonable rate of return on invested capital. Decisions by the Commissions in the future will impact the accounting for regulated operations, including decisions about the amount of allowable costs and return on invested capital included in rates and any refunds that may be required. In the rate setting process, the Company’s rates result in the recording of regulatory assets and liabilities based on the probability of future cash flows. Regulatory assets generally represent incurred or accrued costs that have been deferred because future recovery from customers is probable. Regulatory liabilities generally represent amounts that are expected to be refunded to customers in future rates or amounts collected in current rates for future costs.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of part of the cost of recently completed plant, and 3) a refund due to customers. Given that management’s accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:
•We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the recognition of regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
•We read relevant regulatory orders issued by the Commissions for the Company, regulatory statutes, interpretations, procedural schedules and memorandums, filings made by intervenors, experts’ testimony and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions’ treatment of similar costs under similar circumstances. We also evaluated regulatory filings for any evidence that intervenors are challenging full recovery of the cost of any capital projects. If the full recovery of project costs is being challenged by intervenors, we evaluated management’s assessment of the probability of a disallowance. We evaluated the external information and compared to the Company’s recorded regulatory assets and liabilities for completeness.
•We obtained management’s analysis and correspondence from counsel, as appropriate, regarding regulatory assets or liabilities not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.
| | |
/s/ DELOITTE & TOUCHE LLP |
Minneapolis, Minnesota |
February 17, 202123, 2023 |
|
We have served as the Company’s auditor since 2002. |
PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(amounts in millions)
| | | Year Ended Dec. 31 | | Year Ended Dec. 31 |
| | 2020 | | 2019 | | 2018 | | 2022 | | 2021 | | 2020 |
Operating revenues | Operating revenues | | | | | | | Operating revenues | | | | | | |
Electric | Electric | | $ | 3,116 | | | $ | 3,033 | | | $ | 3,031 | | Electric | | $ | 3,795 | | | $ | 3,413 | | | $ | 3,116 | |
Natural gas | Natural gas | | 1,024 | | | 1,161 | | | 1,015 | | Natural gas | | 1,860 | | | 1,355 | | | 1,024 | |
Other | Other | | 43 | | | 43 | | | 40 | | Other | | 53 | | | 47 | | | 43 | |
Total operating revenues | Total operating revenues | | 4,183 | | | 4,237 | | | 4,086 | | Total operating revenues | | 5,708 | | | 4,815 | | | 4,183 | |
| Operating expenses | Operating expenses | | Operating expenses | |
Electric fuel and purchased power | Electric fuel and purchased power | | 1,132 | | | 1,083 | | | 1,157 | | Electric fuel and purchased power | | 1,485 | | | 1,336 | | | 1,132 | |
Cost of natural gas sold and transported | Cost of natural gas sold and transported | | 374 | | | 526 | | | 428 | | Cost of natural gas sold and transported | | 1,053 | | | 606 | | | 374 | |
Cost of sales — steam and other | Cost of sales — steam and other | | 13 | | | 17 | | | 15 | | Cost of sales — steam and other | | 18 | | | 15 | | | 13 | |
Operating and maintenance expenses | Operating and maintenance expenses | | 811 | | | 810 | | | 788 | | Operating and maintenance expenses | | 905 | | | 831 | | | 811 | |
Demand side management expenses | Demand side management expenses | | 141 | | | 136 | | | 142 | | Demand side management expenses | | 133 | | | 132 | | | 141 | |
Depreciation and amortization | Depreciation and amortization | | 655 | | | 602 | | | 561 | | Depreciation and amortization | | 848 | | | 744 | | | 655 | |
Taxes (other than income taxes) | Taxes (other than income taxes) | | 234 | | | 206 | | | 202 | | Taxes (other than income taxes) | | 272 | | | 256 | | | 234 | |
Total operating expenses | Total operating expenses | | 3,360 | | | 3,380 | | | 3,293 | | Total operating expenses | | 4,714 | | | 3,920 | | | 3,360 | |
| Operating income | Operating income | | 823 | | | 857 | | | 793 | | Operating income | | 994 | | | 895 | | | 823 | |
| Other (expense) income, net | Other (expense) income, net | | (1) | | | 3 | | | 2 | | Other (expense) income, net | | (2) | | | 4 | | | (1) | |
Allowance for funds used during construction — equity | Allowance for funds used during construction — equity | | 35 | | | 22 | | | 56 | | Allowance for funds used during construction — equity | | 32 | | | 28 | | | 35 | |
| Interest charges and financing costs | Interest charges and financing costs | | Interest charges and financing costs | |
Interest charges — includes other financing costs of $7, $7 and $7, respectively | | 238 | | | 235 | | | 208 | | |
Interest charges — includes other financing costs of $8, $8 and $7, respectively | | Interest charges — includes other financing costs of $8, $8 and $7, respectively | | 271 | | | 243 | | | 238 | |
Allowance for funds used during construction — debt | Allowance for funds used during construction — debt | | (14) | | | (11) | | | (22) | | Allowance for funds used during construction — debt | | (11) | | | (9) | | | (14) | |
Total interest charges and financing costs | Total interest charges and financing costs | | 224 | | | 224 | | | 186 | | Total interest charges and financing costs | | 260 | | | 234 | | | 224 | |
| Income before income taxes | Income before income taxes | | 633 | | | 658 | | | 665 | | Income before income taxes | | 764 | | | 693 | | | 633 | |
Income tax expense | Income tax expense | | 45 | | | 80 | | | 113 | | Income tax expense | | 37 | | | 33 | | | 45 | |
Net income | Net income | | $ | 588 | | | $ | 578 | | | $ | 552 | | Net income | | $ | 727 | | | $ | 660 | | | $ | 588 | |
See Notes to Consolidated Financial Statements
PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(amounts in millions)
| | | Year Ended Dec. 31 | | Year Ended Dec. 31 |
| | 2020 | | 2019 | | 2018 | | 2022 | | 2021 | | 2020 |
Net income | Net income | | $ | 588 | | | $ | 578 | | | $ | 552 | | Net income | | $ | 727 | | | $ | 660 | | | $ | 588 | |
| Other comprehensive income (loss) | Other comprehensive income (loss) | | Other comprehensive income (loss) | |
| Pension and retiree medical benefits: | Pension and retiree medical benefits: | | Pension and retiree medical benefits: | |
| Reclassification of loss (gain) to net income, net of tax of $1, $(1) and $0, respectively | | 2 | | | (3) | | | 0 | | |
Net pension and retiree medical gain arising during the period, net of tax of $—, $— and $—, respectively | | Net pension and retiree medical gain arising during the period, net of tax of $—, $— and $—, respectively | | (1) | | | — | | | — | |
Reclassification of loss to net income, net of tax of $—, $— and $1, respectively | | Reclassification of loss to net income, net of tax of $—, $— and $1, respectively | | — | | | — | | | 2 | |
Derivative instruments: | Derivative instruments: | | Derivative instruments: | |
Reclassification of loss to net income, net of tax of $0, $0 and $0, respectively | | 1 | | | 2 | | | 1 | | |
Reclassification of loss to net income, net of tax of $—, $— and $—, respectively | | Reclassification of loss to net income, net of tax of $—, $— and $—, respectively | | 1 | | | 2 | | | 1 | |
| Total other comprehensive income (loss) | Total other comprehensive income (loss) | | 3 | | | (1) | | | 1 | | Total other comprehensive income (loss) | | — | | | 2 | | | 3 | |
Total comprehensive income | Total comprehensive income | | $ | 591 | | | $ | 577 | | | $ | 553 | | Total comprehensive income | | $ | 727 | | | $ | 662 | | | $ | 591 | |
See Notes to Consolidated Financial Statements
PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(amounts in millions)
| | | Year Ended Dec. 31 | | Year Ended Dec. 31 |
| | 2020 | | 2019 | | 2018 | | 2022 | | 2021 | | 2020 |
Operating activities | Operating activities | | | | | | Operating activities | | | | | |
Net income | Net income | $ | 588 | | | $ | 578 | | | $ | 552 | | Net income | $ | 727 | | | $ | 660 | | | $ | 588 | |
Adjustments to reconcile net income to cash provided by operating activities: | Adjustments to reconcile net income to cash provided by operating activities: | | Adjustments to reconcile net income to cash provided by operating activities: | |
Depreciation and amortization | Depreciation and amortization | 656 | | | 607 | | | 566 | | Depreciation and amortization | 854 | | | 754 | | | 656 | |
Deferred income taxes | Deferred income taxes | 2 | | | 97 | | | 24 | | Deferred income taxes | (10) | | | 21 | | | 2 | |
| Allowance for equity funds used during construction | Allowance for equity funds used during construction | (35) | | | (22) | | | (56) | | Allowance for equity funds used during construction | (32) | | | (28) | | | (35) | |
Provision for bad debts | Provision for bad debts | 24 | | | 17 | | | 16 | | Provision for bad debts | 38 | | | 26 | | | 24 | |
Net realized and unrealized hedging and derivative transactions | (14) | | | 62 | | | (6) | | |
| Changes in operating assets and liabilities: | Changes in operating assets and liabilities: | | Changes in operating assets and liabilities: | |
Accounts receivable | Accounts receivable | (51) | | | (22) | | | (43) | | Accounts receivable | (227) | | | (58) | | | (51) | |
Accrued unbilled revenues | Accrued unbilled revenues | (5) | | | 20 | | | (18) | | Accrued unbilled revenues | (169) | | | (52) | | | (5) | |
Inventories | Inventories | (27) | | | (27) | | | (20) | | Inventories | (86) | | | (71) | | | (27) | |
Prepayments and other | (8) | | | (29) | | | 13 | | |
Other current assets | | Other current assets | 12 | | | (23) | | | (8) | |
Accounts payable | Accounts payable | (14) | | | (44) | | | 69 | | Accounts payable | 183 | | | 66 | | | (14) | |
Net regulatory assets and liabilities | Net regulatory assets and liabilities | 58 | | | 35 | | | (15) | | Net regulatory assets and liabilities | 82 | | | (526) | | | 58 | |
Other current liabilities | Other current liabilities | 45 | | | 0 | | | (13) | | Other current liabilities | 8 | | | 30 | | | 45 | |
Pension and other employee benefit obligations | Pension and other employee benefit obligations | (41) | | | (47) | | | (44) | | Pension and other employee benefit obligations | (13) | | | (53) | | | (41) | |
Other, net | Other, net | (4) | | | 3 | | | (17) | | Other, net | (112) | | | (19) | | | (18) | |
Net cash provided by operating activities | Net cash provided by operating activities | 1,174 | | | 1,228 | | | 1,008 | | Net cash provided by operating activities | 1,255 | | | 727 | | | 1,174 | |
| Investing activities | Investing activities | | Investing activities | |
Utility capital/construction expenditures | Utility capital/construction expenditures | (1,671) | | | (1,691) | | | (1,577) | | Utility capital/construction expenditures | (1,880) | | | (1,604) | | | (1,671) | |
Investments in utility money pool arrangement | Investments in utility money pool arrangement | (122) | | | (641) | | | (634) | | Investments in utility money pool arrangement | (45) | | | (273) | | | (122) | |
Repayments from utility money pool arrangement | Repayments from utility money pool arrangement | 122 | | | 641 | | | 654 | | Repayments from utility money pool arrangement | 45 | | | 273 | | | 122 | |
| Net cash used in investing activities | Net cash used in investing activities | (1,671) | | | (1,691) | | | (1,557) | | Net cash used in investing activities | (1,880) | | | (1,604) | | | (1,671) | |
| Financing activities | Financing activities | | Financing activities | |
Proceeds from (repayments of) short-term borrowings, net | 136 | | | (307) | | | 307 | | |
Proceeds from short-term borrowings, net | | Proceeds from short-term borrowings, net | 146 | | | 11 | | | 136 | |
Borrowings under utility money pool arrangement | Borrowings under utility money pool arrangement | 1,189 | | | 100 | | | 780 | | Borrowings under utility money pool arrangement | 1,199 | | | 743 | | | 1,189 | |
Repayments under utility money pool arrangement | Repayments under utility money pool arrangement | (1,171) | | | (61) | | | (780) | | Repayments under utility money pool arrangement | (1,199) | | | (800) | | | (1,171) | |
Proceeds from issuance of long-term debt | Proceeds from issuance of long-term debt | 735 | | | 928 | | | 691 | | Proceeds from issuance of long-term debt | 686 | | | 737 | | | 735 | |
Repayments of long-term debt | Repayments of long-term debt | (400) | | | (400) | | | (300) | | Repayments of long-term debt | (300) | | | — | | | (400) | |
Capital contributions from parent | Capital contributions from parent | 856 | | | 638 | | | 252 | | Capital contributions from parent | 569 | | | 650 | | | 856 | |
Dividends paid to parent | Dividends paid to parent | (831) | | | (457) | | | (375) | | Dividends paid to parent | (491) | | | (467) | | | (831) | |
| Net cash provided by financing activities | Net cash provided by financing activities | 514 | | | 441 | | | 575 | | Net cash provided by financing activities | 610 | | | 874 | | | 514 | |
| Net change in cash and cash equivalents | Net change in cash and cash equivalents | 17 | | | (22) | | | 26 | | Net change in cash and cash equivalents | (15) | | | (3) | | | 17 | |
Cash and cash equivalents at beginning of period | 11 | | | 33 | | | 7 | | |
Cash and cash equivalents at end of period | $ | 28 | | | $ | 11 | | | $ | 33 | | |
Cash, cash equivalents and restricted cash at beginning of period | | Cash, cash equivalents and restricted cash at beginning of period | 25 | | | 28 | | | 11 | |
Cash, cash equivalents and restricted cash at end of period | | Cash, cash equivalents and restricted cash at end of period | $ | 10 | | | $ | 25 | | | $ | 28 | |
| Supplemental disclosure of cash flow information: | Supplemental disclosure of cash flow information: | | Supplemental disclosure of cash flow information: | |
Cash paid for interest (net of amounts capitalized) | Cash paid for interest (net of amounts capitalized) | $ | (211) | | | $ | (209) | | | $ | (187) | | Cash paid for interest (net of amounts capitalized) | $ | (250) | | | $ | (230) | | | $ | (211) | |
Cash paid for income taxes, net | Cash paid for income taxes, net | (23) | | | (5) | | | (116) | | Cash paid for income taxes, net | (79) | | | (14) | | | (23) | |
| Supplemental disclosure of non-cash investing and financing transactions: | Supplemental disclosure of non-cash investing and financing transactions: | | Supplemental disclosure of non-cash investing and financing transactions: | |
Accrued property, plant and equipment additions | Accrued property, plant and equipment additions | $ | 197 | | | $ | 234 | | | $ | 142 | | Accrued property, plant and equipment additions | $ | 233 | | | $ | 157 | | | $ | 197 | |
Inventory transfers to property, plant and equipment | Inventory transfers to property, plant and equipment | 35 | | | 32 | | | 37 | | Inventory transfers to property, plant and equipment | 12 | | | 10 | | | 35 | |
Operating lease right-of-use assets | Operating lease right-of-use assets | 14 | | | 654 | | | 0 | | Operating lease right-of-use assets | 140 | | | — | | | 14 | |
Allowance for equity funds used during construction | Allowance for equity funds used during construction | 35 | | | 22 | | | 56 | | Allowance for equity funds used during construction | 32 | | | 28 | | | 35 | |
See Notes to Consolidated Financial Statements
PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(amounts in millions, except share and per share)
| | | Dec. 31 | | Dec. 31 |
| | | 2020 | | 2019 | | | 2022 | | 2021 |
Assets | Assets | | | | | Assets | | | | |
Current assets | Current assets | | | | | Current assets | | | | |
Cash and cash equivalents | Cash and cash equivalents | | $ | 28 | | | $ | 11 | | Cash and cash equivalents | | $ | 10 | | | $ | 25 | |
Accounts receivable, net | Accounts receivable, net | | 342 | | | 304 | | Accounts receivable, net | | 562 | | | 374 | |
Accounts receivable from affiliates | Accounts receivable from affiliates | | 8 | | | 53 | | Accounts receivable from affiliates | | 11 | | | 13 | |
Accrued unbilled revenues | Accrued unbilled revenues | | 298 | | | 294 | | Accrued unbilled revenues | | 519 | | | 350 | |
Inventories | Inventories | | 189 | | | 192 | | Inventories | | 319 | | | 245 | |
Regulatory assets | Regulatory assets | | 121 | | | 64 | | Regulatory assets | | 411 | | | 353 | |
Derivative instruments | Derivative instruments | | 21 | | | 7 | | Derivative instruments | | 65 | | | 39 | |
Prepayments and other | Prepayments and other | | 82 | | | 56 | | Prepayments and other | | 103 | | | 104 | |
Total current assets | Total current assets | | 1,089 | | | 981 | | Total current assets | | 2,000 | | | 1,503 | |
| Property, plant and equipment, net | Property, plant and equipment, net | | 17,470 | | | 16,155 | | Property, plant and equipment, net | | 19,652 | | | 18,444 | |
| Other assets | Other assets | | | | | Other assets | | | | |
Regulatory assets | Regulatory assets | | 1,059 | | | 1,038 | | Regulatory assets | | 1,277 | | | 1,293 | |
Derivative instruments | Derivative instruments | | 16 | | | 0 | | Derivative instruments | | 22 | | | 27 | |
Operating lease right-of-use assets | Operating lease right-of-use assets | | 500 | | | 574 | | Operating lease right-of-use assets | | 437 | | | 409 | |
Other | Other | | 231 | | | 260 | | Other | | 231 | | | 246 | |
Total other assets | Total other assets | | 1,806 | | | 1,872 | | Total other assets | | 1,967 | | | 1,975 | |
Total assets | Total assets | | $ | 20,365 | | | $ | 19,008 | | Total assets | | $ | 23,619 | | | $ | 21,922 | |
| Liabilities and Equity | Liabilities and Equity | | | | | Liabilities and Equity | | | | |
Current liabilities | Current liabilities | | | | | Current liabilities | | | | |
Current portion of long-term debt | Current portion of long-term debt | | $ | 0 | | | $ | 400 | | Current portion of long-term debt | | $ | 250 | | | $ | 300 | |
Borrowings under utility money pool arrangement | | 57 | | | 39 | | |
| Short-term debt | Short-term debt | | 136 | | | 0 | | Short-term debt | | 294 | | | 147 | |
Accounts payable | Accounts payable | | 452 | | | 573 | | Accounts payable | | 764 | | | 531 | |
Accounts payable to affiliates | Accounts payable to affiliates | | 58 | | | 44 | | Accounts payable to affiliates | | 75 | | | 69 | |
Regulatory liabilities | Regulatory liabilities | | 100 | | | 69 | | Regulatory liabilities | | 59 | | | 95 | |
Taxes accrued | Taxes accrued | | 251 | | | 202 | | Taxes accrued | | 242 | | | 252 | |
Accrued interest | Accrued interest | | 61 | | | 53 | | Accrued interest | | 59 | | | 58 | |
Dividends payable to parent | Dividends payable to parent | | 105 | | | 112 | | Dividends payable to parent | | 120 | | | 104 | |
Derivative instruments | Derivative instruments | | 27 | | | 9 | | Derivative instruments | | 30 | | | 30 | |
Operating lease liabilities | Operating lease liabilities | | 97 | | | 86 | | Operating lease liabilities | | 80 | | | 84 | |
Other | Other | | 84 | | | 99 | | Other | | 115 | | | 109 | |
Total current liabilities | Total current liabilities | | 1,428 | | | 1,686 | | Total current liabilities | | 2,088 | | | 1,779 | |
| Deferred credits and other liabilities | Deferred credits and other liabilities | | | | | Deferred credits and other liabilities | | | | |
Deferred income taxes | Deferred income taxes | | 1,897 | | | 1,851 | | Deferred income taxes | | 1,983 | | | 1,960 | |
Deferred investment tax credits | | 20 | | | 23 | | |
| Regulatory liabilities | Regulatory liabilities | | 2,337 | | | 2,037 | | Regulatory liabilities | | 2,489 | | | 2,397 | |
Asset retirement obligations | Asset retirement obligations | | 399 | | | 324 | | Asset retirement obligations | | 476 | | | 422 | |
Derivative instruments | Derivative instruments | | 51 | | | 53 | | Derivative instruments | | 9 | | | 29 | |
Customer advances | Customer advances | | 168 | | | 173 | | Customer advances | | 144 | | | 160 | |
Pension and employee benefit obligations | Pension and employee benefit obligations | | 161 | | | 212 | | Pension and employee benefit obligations | | 13 | | | 23 | |
Operating lease liabilities | Operating lease liabilities | | 432 | | | 518 | | Operating lease liabilities | | 379 | | | 351 | |
Other | Other | | 156 | | | 150 | | Other | | 198 | | | 190 | |
Total deferred credits and other liabilities | Total deferred credits and other liabilities | | 5,621 | | | 5,341 | | Total deferred credits and other liabilities | | 5,691 | | | 5,532 | |
| Commitments and contingencies | Commitments and contingencies | | 0 | | 0 | Commitments and contingencies | |
Capitalization | Capitalization | | | | | Capitalization | | | | |
Long-term debt | Long-term debt | | 5,724 | | | 4,985 | | Long-term debt | | 6,610 | | | 6,167 | |
Common stock — 100 shares authorized of $0.01 par value; 100 shares outstanding at Dec. 31, 2020 and Dec. 31, 2019, respectively | | 0 | | | 0 | | |
Common stock — 100 shares authorized of $0.01 par value; 100 shares outstanding at Dec. 31, 2022 and Dec. 31, 2021, respectively | | Common stock — 100 shares authorized of $0.01 par value; 100 shares outstanding at Dec. 31, 2022 and Dec. 31, 2021, respectively | | — | | | — | |
Additional paid in capital | Additional paid in capital | | 5,770 | | | 4,940 | | Additional paid in capital | | 6,992 | | | 6,426 | |
Retained earnings | Retained earnings | | 1,846 | | | 2,083 | | Retained earnings | | 2,260 | | | 2,040 | |
Accumulated other comprehensive loss | Accumulated other comprehensive loss | | (24) | | | (27) | | Accumulated other comprehensive loss | | (22) | | | (22) | |
Total common stockholder's equity | Total common stockholder's equity | | 7,592 | | | 6,996 | | Total common stockholder's equity | | 9,230 | | | 8,444 | |
Total liabilities and stockholder's equity | Total liabilities and stockholder's equity | | $ | 20,365 | | | $ | 19,008 | | Total liabilities and stockholder's equity | | $ | 23,619 | | | $ | 21,922 | |
See Notes to Consolidated Financial Statements | See Notes to Consolidated Financial Statements | See Notes to Consolidated Financial Statements |
PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
(amounts in millions, except share data)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Common Stock | | | | Accumulated Other Comprehensive Income (Loss) | | Total Common Stockholder’s Equity |
| Shares | | Par Value | | Additional Paid In Capital | | Retained Earnings | | |
| | | | | | | | | | | |
Balance at Dec. 31, 2017 | 100 | | | $ | 0 | | | $ | 4,033 | | | $ | 1,822 | | | $ | (27) | | | $ | 5,828 | |
| | | | | | | | | | | |
Net income | | | | | | | 552 | | | | | 552 | |
Other comprehensive income | | | | | | | | | 1 | | | 1 | |
Common dividends declared to parent | | | | | | | (391) | | | | | (391) | |
Contribution of capital by parent | | | | | 308 | | | | | | | 308 | |
Balance at Dec. 31, 2018 | 100 | | | $ | 0 | | | $ | 4,341 | | | $ | 1,983 | | | $ | (26) | | | $ | 6,298 | |
| | | | | | | | | | | |
Net income | | | | | | | 578 | | | | | 578 | |
Other comprehensive income | | | | | | | | | (1) | | | (1) | |
Common dividends declared to parent | | | | | | | (478) | | | | | (478) | |
Contribution of capital by parent | | | | | 599 | | | | | | | 599 | |
Balance at Dec. 31, 2019 | 100 | | | $ | 0 | | | $ | 4,940 | | | $ | 2,083 | | | $ | (27) | | | $ | 6,996 | |
| | | | | | | | | | | |
Net income | | | | | | | 588 | | | | | 588 | |
Other comprehensive income | | | | | | | | | 3 | | | 3 | |
Common dividends declared to parent | | | | | | | (824) | | | | | (824) | |
Contribution of capital by parent | | | | | 830 | | | | | | | 830 | |
Adoption of ASC Topic 326 | | | | | | | (1) | | | | | (1) | |
Balance at Dec. 31, 2020 | 100 | | | $ | 0 | | | $ | 5,770 | | | $ | 1,846 | | | $ | (24) | | | $ | 7,592 | |
| | | | | | | | | | | |
See Notes to Consolidated Financial Statements |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Common Stock | | | | Accumulated Other Comprehensive Income (Loss) | | Total Common Stockholder’s Equity |
| Shares | | Par Value | | Additional Paid In Capital | | Retained Earnings | | |
| | | | | | | | | | | |
Balance at Dec. 31, 2019 | 100 | | | $ | — | | | $ | 4,940 | | | $ | 2,083 | | | $ | (27) | | | $ | 6,996 | |
| | | | | | | | | | | |
Net income | | | | | | | 588 | | | | | 588 | |
Other comprehensive income | | | | | | | | | 3 | | | 3 | |
Common dividends declared to parent | | | | | | | (824) | | | | | (824) | |
Contribution of capital by parent | | | | | 830 | | | | | | | 830 | |
Adoption of ASC Topic 326 | | | | | | | (1) | | | | | (1) | |
Balance at Dec. 31, 2020 | 100 | | | $ | — | | | $ | 5,770 | | | $ | 1,846 | | | $ | (24) | | | $ | 7,592 | |
| | | | | | | | | | | |
Net income | | | | | | | 660 | | | | | 660 | |
Other comprehensive income | | | | | | | | | 2 | | | 2 | |
Common dividends declared to parent | | | | | | | (466) | | | | | (466) | |
Contribution of capital by parent | | | | | 656 | | | | | | | 656 | |
| | | | | | | | | | | |
Balance at Dec. 31, 2021 | 100 | | | $ | — | | | $ | 6,426 | | | $ | 2,040 | | | $ | (22) | | | $ | 8,444 | |
| | | | | | | | | | | |
Net income | | | | | | | 727 | | | | | 727 | |
| | | | | | | | | | | |
Common dividends declared to parent | | | | | | | (507) | | | | | (507) | |
Contribution of capital by parent | | | | | 566 | | | | | | | 566 | |
| | | | | | | | | | | |
Balance at Dec. 31, 2022 | 100 | | | $ | — | | | $ | 6,992 | | | $ | 2,260 | | | $ | (22) | | | $ | 9,230 | |
| | | | | | | | | | | |
See Notes to Consolidated Financial Statements |
PUBLIC SERVICE COMPANY of COLORADO
Notes to Consolidated Financial Statements
| | |
1. Summary of Significant Accounting Policies |
General — PSCo is engaged in the regulated generation, purchase, transmission, distribution and sale of electricity and in the regulated purchase, transportation, distribution and sale of natural gas.
PSCo’s consolidated financial statements include its wholly-owned subsidiaries. In the consolidation process, all intercompany transactions and balances are eliminated. PSCo has investments in several plants and transmission facilities jointly owned with nonaffiliated utilities.
PSCo’s proportionate share of jointly owned facilities is recorded as property, plant and equipment on the consolidated balance sheets, and PSCo’s proportionate share of the operating costs associated with these facilities is included in its consolidated statements of income.
PSCo’s consolidated financial statements are presented in accordance with GAAP. All of PSCo’s underlying accounting records also conform to the FERC uniform system of accounts or to systems required by variousits state regulatory commissions.commission. Certain amounts in the consolidated financial statements or notes have been reclassified for comparative purposes; however, such reclassifications did not affect net income, total assets, liabilities, equity or cash flows.
PSCo has evaluated events occurring after Dec. 31, 20202022 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation.
Use of Estimates — PSCo uses estimates based on the best information available in recording transactions and balances resulting from business operations.
Estimates are used onfor items such as plant depreciable lives or potential disallowances, AROs, certain regulatory assets and liabilities, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs. Recorded estimates are revised when better information becomes available or actual amounts can be determined. Revisions can affect operating results.
Regulatory Accounting — PSCo accounts for income and expense items in accordance with accounting guidance for regulated operations. Under this guidance:
•Certain costs, which would otherwise be charged to expense or other comprehensive income, are deferred as regulatory assets based on the expected ability to recover the costs in future rates.
•Certain credits, which would otherwise be reflected as income or other comprehensive income, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred.
Estimates and assumptions for recovery of recovering deferred costs and returningrefund of deferred credits are based on specific ratemaking decisions, precedent or precedent for each item.other information available. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process.
If changes in the regulatory environment occur, PSCo may no longer be eligible to apply this accounting treatment and may be required to eliminate regulatory assets and liabilities from its balance sheet.liabilities. Such changes could have a material effect on PSCo’s results of operations, financial condition and cash flows.
See Note 4 for further information.
Income Taxes — PSCo accounts for income taxes using the asset and liability method, which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the consolidated financial statements. PSCo defers incomeIncome taxes are deferred for all temporary differences between pretax financial and taxable income and between the book and tax bases of assets and liabilities.
PSCo uses rates that are scheduled to be in effect when the temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the period that includes the enactment date.
The effects of PSCo’s tax rate changes that are attributable to the utility subsidiaries are generally subject to a normalization method of accounting. Therefore, the revaluation of most of itsthe utility subsidiaries’ net deferred taxes upon a tax rate reduction results in the establishment of a net regulatory liability, which would be refundable to utility customers over the remaining life of the related assets. PSCo anticipates that a tax rate increase would predominantly result in the establishment of a regulatory asset, subject to an evaluation of whether future recovery is expected.
Reversal of certain temporary differences are accounted for as current income tax expense due to the effects of past regulatory approval.practices when deferred taxes were not required to be recorded due to the use of flow through accounting for ratemaking purposes.
Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize it over the book depreciable lives of the related property. The requirement to defer and amortize these credits specifically applies to certain federal ITCs, as determined by tax regulations and PSCo tax elections. For tax credits only appliesotherwise eligible to federal ITCs related to public utility property. Utilitybe recognized when earned, PSCo considers the impact of rate regulation also has resulted in the recognition ofto determine if these credits and related adjustments should be deferred as regulatory assets and liabilities related to income taxes. or liabilities.
Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized. Utility rate regulation has resulted in the recognition of regulatory assets and liabilities related to income taxes.
PSCo follows the applicable accounting guidance to measuremeasures and disclosediscloses uncertain tax positions that it has taken or expects to take in its income tax returns. PSCo recognizes aA tax position is recognized in itsthe consolidated financial statements when it is more likely than not that the position will be sustained upon examination based on the technical merits of the position. Recognition of changes in uncertain tax positions are reflected as a component of income tax expense.
PSCo reports interestInterest and penalties related to income taxes are reported within other (expense) income or interest charges in the consolidated statements of income.
Xcel Energy Inc. and its subsidiaries, including PSCo file consolidated federal income tax returns as well as consolidated or separate state income tax returns. Federal income taxes paid by Xcel Energy Inc. are allocated to its subsidiaries based on separate company computations. A similar allocation is made for state income taxes paid by Xcel Energy Inc. in connection with consolidated state filings. Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries.
See Note 7 for further information.
Property, Plant and Equipment and Depreciation in Regulated Operations — Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and AFUDC. The cost of plant retired is charged to accumulated depreciation and amortization. Amounts recovered in rates for future removal costs are recorded as regulatory liabilities. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance costs are charged to expense as incurred. Maintenance and replacement of items determined to be less than a unit of property are charged to operating expenses as incurred. Planned maintenance activities are charged to operating expense unless the cost represents the acquisition of an additional unit of property or the replacement of an existing unit of property.
Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable. A loss is recognized in the current period if it becomes probable that part of a cost of a plant under construction or recently completed plant will be disallowed for recovery from customers and a reasonable estimate of the disallowance can be made. For investments in property, plant and equipment that are abandoned and not expected to go into service, incurred costs and related deferred tax amounts are compared to the discounted estimated future rate recovery, and a loss is recognized, if necessary.
PSCo records depreciationDepreciation expense is recorded using the straight-line method over the plant’s commission approved useful life. Actuarial life studies are performed and submitted to the state and federal commissions for review. Upon acceptance by the various commissions, the resulting lives and net salvage rates are used to calculate depreciation. Plant removal costs are typically recognized at the amounts recovered in rates as authorized by the appropriate regulatory entities. The amount ofapplicable regulator. Accumulated removal costs are based on current factors usedreflected in existing depreciation rates.the consolidated balance sheet as a regulatory liability. Depreciation expense, expressed as a percentage of average depreciable property, was approximately 3.4% in 2022, 3.2% in 2021 and 3.1% in 2020, 2.9% in 2019 and 2.6% in 2018.2020.
See Note 3 for further information.
AROs — PSCo accounts forrecords AROs under accounting guidance that requiresas a liability for the fair value of an ARO to be recognized in the period in which it is incurred if(if it can be reasonably estimated,estimated), with the offsetting offsetting/associated asset retirement costs capitalized as a long-lived asset. The liability is generally increased over time by applying the effective interest method of accretion and the capitalized costs are typically depreciated over the useful life of the long-lived asset. Changes resulting from revisions to the timing or amountamounts of expected asset retirement cash flows are recognized as an increase or a decrease in the ARO.
See Note 10 for further information.
Benefit Plans and Other Postretirement Benefits — PSCo maintains pension and postretirement benefit plans for eligible employees. Recognizing the cost of providing benefits and measuring the projected benefit obligation of these plans requires management to make various assumptions and estimates.
Certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are deferred as regulatory assets and liabilities, rather than recorded as other comprehensive income, based on regulatory recovery mechanisms.
See Note 9 for further information.
Environmental Costs — Environmental costs are recorded when it is probable PSCo is liable for remediation costs and the liabilityamount can be reasonably estimated. Costs are deferred as a regulatory asset if it is probable that the costs will be recovered from customers in future rates. Otherwise, the costs are expensed. If anFor certain environmental expense iscosts related to facilities currently in use, such as for emission-control equipment, the cost is capitalized and depreciated over the life of the plant.
Estimated remediation costs are regularly adjusted as estimates are revised and remediation proceeds.is performed. If other participating potentially responsible parties exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for PSCo’s expected share of the cost.
Future costs of restoring sites are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses. Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability.
See Note 10 for further information.
Revenue from Contracts with Customers — Performance obligations related to the sale of energy are satisfied as energy is delivered to customers. PSCo recognizes revenue that corresponds to the price of the energy delivered to the customer. The measurement of energy sales to customers is generally based on the reading of their meters, which occurs systematically throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and the corresponding unbilled revenue is recognized.
PSCo does not recognize aA separate financing component of its collections from customers is not recognized as contract terms are short-term in nature. PSCo presents its revenuesRevenues are net of any excise or sales taxes or fees.
See Note 6 for further information.
Cash and Cash Equivalents — PSCo considers investments in instruments with a remaining maturity of three3 months or less at the time of purchase to be cash equivalents.
Accounts Receivable and Allowance for Bad Debts — Accounts receivable are stated at the actual billed amount net of an allowance for bad debts. PSCo establishes an allowance for uncollectible receivables based on a policy that reflects its expected exposure to the credit risk of customers.
As of Dec. 31, 20202022 and 2019,2021, the allowance for bad debts was $29 $54 million and $21$40 million, respectively.
Inventory — Inventory is recorded at the lower of average cost or net realizable value and consisted of the following: | (Millions of Dollars) | (Millions of Dollars) | | Dec. 31, 2020 | | Dec. 31, 2019 | (Millions of Dollars) | | Dec. 31, 2022 | | Dec. 31, 2021 |
Inventories | Inventories | | | | | Inventories | | | | |
Materials and supplies | Materials and supplies | | $ | 63 | | | $ | 63 | | Materials and supplies | | $ | 80 | | | $ | 70 | |
Fuel | Fuel | | 73 | | | 77 | | Fuel | | 68 | | | 71 | |
Natural gas | Natural gas | | 53 | | | 52 | | Natural gas | | 171 | | | 104 | |
Total inventories | Total inventories | | $ | 189 | | | $ | 192 | | Total inventories | | $ | 319 | | | $ | 245 | |
Fair Value Measurements — PSCo presents cash equivalents, interest rate derivatives and commodity derivatives at estimated fair values in its consolidated financial statements.
Cash equivalents are recorded at cost plus accrued interest; money market funds are measured using quoted NAVs. For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used to establishestimate fair value. For commodity derivatives, the most observable inputs available are generally used to determine the fair value of each contract. In the absence of a quoted price, PSCo may use quoted prices for similar contracts or internally prepared valuation models may be used to determine fair value.
For the pension and postretirement plan assets and nuclear decommissioning fund, published trading data and pricing models, generally using the most observable inputs available, are utilized to estimatedetermine fair value for each security.
See Notes 8 and 9 for further information.
Derivative Instruments — PSCo uses derivative instruments in connection with its commodity trading activities, and to manage risk associated with changes in interest rate,rates, and utility commodity price and commodity trading activities,prices, including forward contracts, futures, swaps and options. Any derivative instruments not qualifying for the normal purchases and normal sales exception are recorded on the consolidated balance sheets at fair value as derivative instruments. Classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship.
Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability. Classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.
Gains or losses on commodity trading transactions are recorded as a component of electric operating revenues and interest rate hedging transactions are recorded as a component of interest expense.revenues.
Normal Purchases and Normal Sales — PSCo enters into contracts for purchases and sales of commodities for use in its operations. At inception, contracts are evaluated to determine whether they contain a derivative, exists and/orand if so, whether an instrumentthey may be exempted from derivative accounting if designated as a normal purchasepurchases or normal sale.sales.
See Note 8 for further information.
Commodity Trading Operations — All applicable gains and losses related to commodity trading activities are shown on a net basis in electric operating revenues in the consolidated statements of income.
Commodity trading activities are not associated with energy produced from PSCo’s generation assets or energy and capacity purchased to serve native load. Commodity trading contracts are recorded at fair market value and commodity trading results include the impact of all margin-sharing mechanisms.
See Note 8 for further information.information
Other Utility Items
AFUDC — AFUDC represents the cost of capital used to finance utility construction activity. AFUDCactivity and is computed by applying a composite financing rate to qualified CWIP. The amount of AFUDC capitalized as a utility construction cost is credited to other nonoperating income (for equity capital) and interest charges (for debt capital). AFUDC amounts capitalized are included in PSCo’s rate base for establishing utility rates.base.
Alternative Revenue — Certain rate rider mechanisms (including decoupling and DSM programs) qualify as alternative revenue programs. These mechanisms arise from costs imposed uponinstances in which the utility by action ofregulator authorizes a regulatorfuture surcharge in response to past activities or legislative body related to an environmental, public safety or other mandate.completed events. When certain criteria are met, including expected collection within 24 months, revenue is recognized, equal to the revenue requirement, which may include incentives and return on rate base items.
Billing amounts are revised periodically for differences between total amount collected and revenue earned, which may increase or decrease the level of revenue collected from customers. Alternative revenues arising from these programs are presented on a gross basis and disclosed separately from revenue from contracts with customers.
See Note 6 for further information.
Conservation Programs — PSCo has implemented programs to assist its retail customers in conserving energy and reducing peak demand on the electric and natural gas systems. These programs include approximately 20 unique DSM products, pilots and services for C&I customers, as well as approximately 23 DSM products, pilots and services for residential and low-income customers. Overall, the DSM portfolio provides rebates and/or incentives for nearly 1,000 unique measures.
The costs incurred for DSM programs are deferred if it is probable future revenue will be provided to permit recovery of the incurred cost. Revenues recognized for incentive programs designed for recovery of DSM program costs and/or conservation performance incentives are limited to amounts expected to be collected within 24 months from the annual periodyear in which they are earned.
PSCo’s DSM program costs are recovered through a combination of base rate revenue and rider mechanisms. Regulatory assets are recognized to reflect the amount of costs or earned incentives that have not yet been collected from customers.
EmissionEmissions Allowances — EmissionEmissions allowances are recorded at cost, including broker commission fees. The inventory accounting model is utilized for all emissionemissions allowances and any sales of these allowances are included in electric revenues.
RECs — Cost of RECs that are utilized for compliance is recorded as electric fuel and purchased power expense. PSCo records that cost as a regulatory asset when the amountAn inventory accounting model is recoverable in future rates.used to account for RECs.
Sales of RECs are recorded in electric revenues on a gross basis. Cost of these RECs and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense.
| | |
2. Accounting Pronouncements |
Recently Adopted
Credit Losses— In 2016,As of Dec. 31, 2022, there was no material impact from the FASB issued Financial Instruments - Credit Losses, Topic 326 (ASC Topic 326), which changes how entities account for losses on receivables and certain other assets. The guidance requires use of a current expected credit loss model, which may result in earlier recognition of credit losses than under previous accounting standards.
PSCo implemented the guidance using a modified-retrospective approach, recognizing a cumulative effect charge of $1 million (after tax) to retained earnings on Jan. 1, 2020. Other than first-time recognition of an allowance for bad debts on accrued unbilled revenues, the Jan. 1, 2020,recent adoption of ASC Topic 326 did not have a significantnew accounting pronouncements, nor expected material impact from recently issued accounting pronouncements yet to be adopted, on PSCo’s consolidated financial statements.
| | |
3. Property, Plant Property and Equipment |
Major classes of property, plant and equipment
| (Millions of Dollars) | (Millions of Dollars) | | Dec. 31, 2020 | | Dec. 31, 2019 | (Millions of Dollars) | | Dec. 31, 2022 | | Dec. 31, 2021 |
Property, plant and equipment, net | Property, plant and equipment, net | | | | | Property, plant and equipment, net | | | | |
Electric plant | Electric plant | | $ | 15,736 | | | $ | 14,362 | | Electric plant | | $ | 15,771 | | | $ | 16,543 | |
Natural gas plant | Natural gas plant | | 5,037 | | | 4,631 | | Natural gas plant | | 5,949 | | | 5,471 | |
Common and other property | Common and other property | | 1,191 | | | 1,113 | | Common and other property | | 1,415 | | | 1,224 | |
Plant to be retired (a) | Plant to be retired (a) | | 225 | | | 260 | | Plant to be retired (a) | | 1,305 | | | 182 | |
CWIP | CWIP | | 510 | | | 913 | | CWIP | | 877 | | | 681 | |
Total property, plant and equipment | Total property, plant and equipment | | 22,699 | | | 21,279 | | Total property, plant and equipment | | 25,317 | | | 24,101 | |
Less accumulated depreciation | Less accumulated depreciation | | (5,229) | | | (5,124) | | Less accumulated depreciation | | (5,665) | | | (5,657) | |
Property, plant and equipment, net | Property, plant and equipment, net | | $ | 17,470 | | | $ | 16,155 | | Property, plant and equipment, net | | $ | 19,652 | | | $ | 18,444 | |
(a)Includes regulator-approved retirementsAmounts as of Dec. 31, 2021 include Comanche Units 1 and 2 and jointly owned Craig Units 1 and 2. Following the June 2022 approval of PSCo’s revised resource plan settlement, amounts as of Dec. 31, 2022 include the addition of Comanche Unit 1. Also includes PSCo’s planned retirement3, Hayden Units 1 and 2 and coal generation assets at Pawnee pending facility gas conversion as well as the removal of jointly owned CraigComanche Unit 2.
1 that was retired in 2022. Amounts are presented net of accumulated depreciation.
Joint Ownership of Generation, Transmission and Gas Facilities
Jointly owned assets as of Dec. 31, 2020:2022:
| (Millions of Dollars, Except Percent Owned) | (Millions of Dollars, Except Percent Owned) | | Plant in Service | | Accumulated Depreciation | | CWIP | | Percent Owned | (Millions of Dollars, Except Percent Owned) | | Plant in Service | | Accumulated Depreciation | | | Percent Owned |
Electric generation: | Electric generation: | | | | | | | | | Electric generation: | | | | | | | |
Hayden Unit 1 | Hayden Unit 1 | | $ | 153 | | | $ | 92 | | | $ | 0 | | | 76 | % | Hayden Unit 1 | | $ | 157 | | | $ | 99 | | | | 76 | % |
Hayden Unit 2 | Hayden Unit 2 | | 150 | | | 73 | | | 0 | | | 37 | | Hayden Unit 2 | | 151 | | | 81 | | | | 37 | |
Hayden common facilities | Hayden common facilities | | 42 | | | 25 | | | 0 | | | 53 | | Hayden common facilities | | 42 | | | 29 | | | | 53 | |
Craig Units 1 and 2 | Craig Units 1 and 2 | | 81 | | | 44 | | | 0 | | | 10 | | Craig Units 1 and 2 | | 82 | | | 51 | | | | 10 | |
Craig common facilities | Craig common facilities | | 39 | | | 24 | | | 0 | | | 7 | | Craig common facilities | | 39 | | | 24 | | | | 7 | |
Comanche Unit 3 | Comanche Unit 3 | | 899 | | | 137 | | | 16 | | | 67 | | Comanche Unit 3 | | 918 | | | 174 | | | | 67 | |
Comanche common facilities | Comanche common facilities | | 25 | | | 2 | | | 0 | | | 82 | | Comanche common facilities | | 28 | | | 3 | | | | 82 | |
Electric transmission: | Electric transmission: | | Electric transmission: | | | |
Transmission and other facilities | Transmission and other facilities | | 176 | | | 59 | | | 2 | | | Various | Transmission and other facilities | | 186 | | | 72 | | | | Various |
Gas transmission: | Gas transmission: | | Gas transmission: | | | |
Rifle, CO to Avon, CO | Rifle, CO to Avon, CO | | 22 | | | 8 | | | 0 | | | 60 | | Rifle, CO to Avon, CO | | 25 | | | 9 | | | | 60 | |
Gas transmission compressor | Gas transmission compressor | | 8 | | | 1 | | | 0 | | | 50 | | Gas transmission compressor | | 8 | | | 2 | | | | 50 | |
Total(a) | Total(a) | | $ | 1,595 | | | $ | 465 | | | $ | 18 | | | Total(a) | | $ | 1,636 | | | $ | 544 | | | | |
(a)Projects additionally include $10 million in CWIP.
PSCo’s share of operating expenses and construction expenditures is included in the applicable utility accounts. Respective owners are responsible for providing their own financing.
| | |
4. Regulatory Assets and Liabilities |
Regulatory assets and liabilities are created for amounts that regulators may allow to be collected or may require to be paid back to customers in future electric and natural gas rates. PSCo would be required to recognize the write-off of regulatory assets and liabilities in net income or other comprehensive income if changes in the utility industry no longer allow for the application of regulatory accounting guidance under GAAP.
Components of regulatory assets: | (Millions of Dollars) | (Millions of Dollars) | | See Note(s) | | Remaining Amortization Period | | Dec. 31, 2020 | | Dec. 31, 2019 | (Millions of Dollars) | | See Note(s) | | Remaining Amortization Period | | Dec. 31, 2022 | | Dec. 31, 2021 (a) |
Regulatory Assets | Regulatory Assets | | | | | | Current | | Noncurrent | | Current | | Noncurrent | Regulatory Assets | | | | | | Current | | Noncurrent | | Current | | Noncurrent |
Pension and retiree medical obligations | Pension and retiree medical obligations | | 9 | | Various | | $ | 28 | | | $ | 478 | | | $ | 23 | | | $ | 494 | | Pension and retiree medical obligations | | 9 | | Various | | $ | 3 | | | $ | 367 | | | $ | 26 | | | $ | 331 | |
Net AROs (b) | | Net AROs (b) | | 1, 10 | | Various | | — | | | 212 | | | — | | | 154 | |
Deferred natural gas, electric, steam energy/fuel costs | | Deferred natural gas, electric, steam energy/fuel costs | | One to three years | | 312 | | | 200 | | | 218 | | | 320 | |
Depreciation differences | Depreciation differences | | One to 11 years | | 16 | | | 154 | | | 15 | | | 140 | | Depreciation differences | | One to ten years | | 16 | | | 187 | | | 16 | | | 173 | |
Net AROs (a) | | 1, 10 | | Various | | 0 | | | 132 | | | 0 | | | 119 | | |
Recoverable deferred taxes on AFUDC | Recoverable deferred taxes on AFUDC | | Plant lives | | 0 | | | 110 | | | 0 | | | 105 | | Recoverable deferred taxes on AFUDC | | Plant lives | | — | | | 119 | | | — | | | 116 | |
Excess deferred taxes — TCJA | Excess deferred taxes — TCJA | | 7 | | Various | | 3 | | | 56 | | | 3 | | | 55 | | Excess deferred taxes — TCJA | | 7 | | Various | | 2 | | | 54 | | | 2 | | | 56 | |
Environmental remediation costs | | Environmental remediation costs | | Various | | 6 | | | 26 | | | 1 | | | 8 | |
Grid modernization costs | | Grid modernization costs | | Three years | | 14 | | | 22 | | | — | | | 35 | |
Conservation programs (c) | | Conservation programs (c) | | 1 | | One to two years | | 8 | | | 16 | | | 11 | | | 11 | |
Gas pipeline inspection costs | | Gas pipeline inspection costs | | One to two years | | — | | | 13 | | | — | | | 12 | |
Purchased power contract costs | Purchased power contract costs | | Term of related contract | | 3 | | | 22 | | | 2 | | | 24 | | Purchased power contract costs | | Term of related contract | | 3 | | | 16 | | | 3 | | | 19 | |
Property tax | Property tax | | Various | | 16 | | | 21 | | | 1 | | | 30 | | Property tax | | Various | | 8 | | | 2 | | | 16 | | | 16 | |
Conservation programs (b) | | 1 | | One to two years | | 11 | | | 11 | | | 8 | | | 11 | | |
Gas pipeline inspection costs | | One to two years | | 0 | | | 9 | | | 0 | | | 8 | | |
Losses on reacquired debt | | Term of related debt | | 1 | | | 3 | | | 1 | | | 4 | | |
Contract valuation adjustments (c) | | 1, 8 | | Term of related contract | | 6 | | | 0 | | | 3 | | | 0 | | |
Recoverable purchased natural gas and electric energy costs | | Less than one year | | 6 | | | 0 | | | 0 | | | 0 | | |
Other | Other | | Various | | 31 | | | 63 | | | 8 | | | 48 | | Other | | Various | | 39 | | | 43 | | | 60 | | | 42 | |
Total regulatory assets | Total regulatory assets | | $ | 121 | | | $ | 1,059 | | | $ | 64 | | | $ | 1,038 | | Total regulatory assets | | $ | 411 | | | $ | 1,277 | | | $ | 353 | | | $ | 1,293 | |
(a)Prior period amounts have been restated to conform with current year presentation.
(b)Includes amounts recorded for future recovery of AROs.
(b)(c)Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.
(c)Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.
Components of regulatory liabilities:
| (Millions of Dollars) | (Millions of Dollars) | | See Note(s) | | Remaining Amortization Period | | Dec. 31, 2020 | | Dec. 31, 2019 | (Millions of Dollars) | | See Note(s) | | Remaining Amortization Period | | Dec. 31, 2022 | | Dec. 31, 2021 (a) |
Regulatory Liabilities | Regulatory Liabilities | | | | | | Current | | Noncurrent | | Current | | Noncurrent | Regulatory Liabilities | | | | | | Current | | Noncurrent | | Current | | Noncurrent |
Deferred income tax adjustments and TCJA refunds (a)(b) | Deferred income tax adjustments and TCJA refunds (a)(b) | | 7 | | Various | | $ | 5 | | | $ | 1,368 | | | $ | 5 | | | $ | 1,403 | | Deferred income tax adjustments and TCJA refunds (a)(b) | | 7 | | Various | | $ | 2 | | | $ | 1,298 | | | $ | 2 | | | $ | 1,328 | |
Plant removal costs | Plant removal costs | | 1, 10 | | Various | | 0 | | | 615 | | | 0 | | | 351 | | Plant removal costs | | 1, 10 | | Various | | — | | | 705 | | | — | | | 651 | |
Effects of regulation on employee benefit costs (b)(c) | Effects of regulation on employee benefit costs (b)(c) | | Various | | 0 | | | 203 | | | 0 | | | 183 | | Effects of regulation on employee benefit costs (b)(c) | | Various | | — | | | 227 | | | — | | | 216 | |
Renewable resources and environmental initiatives | Renewable resources and environmental initiatives | | Various | | 0 | | | 59 | | | 0 | | | 45 | | Renewable resources and environmental initiatives | | Various | | — | | | 141 | | | — | | | 91 | |
Revenue decoupling | Revenue decoupling | | One to two years | | 10 | | | 41 | | | 0 | | | 0 | | Revenue decoupling | | One to two years | | — | | | 55 | | | 9 | | | 41 | |
ITC deferrals | ITC deferrals | | 1 | | Various | | 0 | | | 40 | | | 0 | | | 26 | | ITC deferrals | | 1 | | Various | | 1 | | | 41 | | | — | | | 42 | |
Conservation programs (c) | | 1 | | Less than one year | | 39 | | | 0 | | | 30 | | | 0 | | |
Deferred electric, natural gas and steam production costs | | Less than one year | | 17 | | | 0 | | | 8 | | | 0 | | |
Formula rates | | Formula rates | | One to two years | | 16 | | | — | | | 10 | | | — | |
Conservation programs | | Conservation programs | | 1 | | Less than one year | | 19 | | | — | | | 34 | | | — | |
Deferred natural gas, electric, steam energy/fuel costs | | Deferred natural gas, electric, steam energy/fuel costs | | Less than one year | | 3 | | | — | | | 29 | | | — | |
Other | Other | | Various | | 29 | | | 11 | | | 26 | | | 29 | | Other | | Various | | 18 | | | 22 | | | 11 | | | 28 | |
Total regulatory liabilities | | | $ | 100 | | | $ | 2,337 | | | $ | 69 | | | $ | 2,037 | | |
Total regulatory liabilities (d) | | Total regulatory liabilities (d) | | $ | 59 | | | $ | 2,489 | | | $ | 95 | | | $ | 2,397 | |
(a)Prior period amounts have been restated to conform with current year presentation.
(b)Includes the revaluation of recoverable/regulated plant ADITaccumulated deferred income taxes and revaluation impact of non-plant ADITaccumulated deferred income taxes due to the TCJA.
(b)(c)Includes regulatory amortization and certain 2018 TCJA benefits approved by the CPUC to offset the prepaid pension asset.
(c)(d)Includes costsRevenue subject to refund of $0 million and $2 million for conservation programs, as well as incentives allowed2022 and 2021, respectively, is included in certain jurisdictions.other current liabilities.
At Dec. 31, 2020 and 2019, PSCo’s regulatory assets not earning a return primarily includedinclude the unfunded portion of pension and retiree medical obligations and net AROs.AROs (i.e. deferrals for which cash has not been disbursed). In addition, PSCo’s regulatory assets included $195$538 million and $160$639 million at Dec. 31, 20202022 and 2019,2021, respectively, of past expenditures not earning a return. Amounts are predominately related to funded pension obligations, property taxes,purchased natural gas and electric energy costs (including certain costs related to Winter Storm Uri), sales true-up and revenue decoupling, various renewable resourcesresources/environmental initiatives and certain environmental initiatives.prepaid pension amounts.
| | |
5. Borrowings and Other Financing Instruments |
Short-Term Borrowings
PSCo meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility and the money pool.
Money Pool — Xcel Energy Inc. and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings between the utility subsidiaries. Xcel Energy Inc. may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy Inc.
Money pool borrowings for PSCo were as follows:borrowings:
| (Millions of Dollars, Except Interest Rates) | (Millions of Dollars, Except Interest Rates) | | Three Months Ended Dec. 31, 2020 | | Year Ended Dec. 31 | (Millions of Dollars, Except Interest Rates) | | Three Months Ended Dec. 31, 2022 | | Year Ended Dec. 31 |
| 2020 | | 2019 | | 2018 | | 2022 | | 2021 | | 2020 |
Borrowing limit | Borrowing limit | | $ | 250 | | | $ | 250 | | | $ | 250 | | | $ | 250 | | Borrowing limit | | $ | 250 | | | $ | 250 | | | $ | 250 | | | $ | 250 | |
Amount outstanding at period end | Amount outstanding at period end | | 57 | | | 57 | | | 39 | | | 0 | | Amount outstanding at period end | | — | | | — | | | — | | | 57 | |
Average amount outstanding | Average amount outstanding | | 104 | | | 59 | | | 7 | | | 25 | | Average amount outstanding | | 21 | | | 29 | | | 12 | | | 59 | |
Maximum amount outstanding | Maximum amount outstanding | | 218 | | | 250 | | | 50 | | | 156 | | Maximum amount outstanding | | 165 | | | 250 | | | 243 | | | 250 | |
Weighted average interest rate, computed on a daily basis | Weighted average interest rate, computed on a daily basis | | 0.08 | % | | 0.60 | % | | 2.29 | % | | 1.93 | % | Weighted average interest rate, computed on a daily basis | | 3.12 | % | | 1.66 | % | | 0.07 | % | | 0.60 | % |
Weighted average interest rate at end of period | Weighted average interest rate at end of period | | 0.07 | | | 0.07 | | | 1.63 | | | N/A | Weighted average interest rate at end of period | | N/A | | N/A | | N/A | | 0.70 | |
Commercial Paper — Commercial paper borrowings for PSCo were as follows:borrowings:
| (Millions of Dollars, Except Interest Rates) | (Millions of Dollars, Except Interest Rates) | | Three Months Ended Dec. 31, 2020 | | Year Ended Dec. 31 | (Millions of Dollars, Except Interest Rates) | | Three Months Ended Dec. 31, 2022 | | Year Ended Dec. 31 |
| 2020 | | 2019 | | 2018 | | 2022 | | 2021 | | 2020 |
Borrowing limit | Borrowing limit | | $ | 700 | | | $ | 700 | | | $ | 700 | | | $ | 700 | | Borrowing limit | | $ | 700 | | | $ | 700 | | | $ | 700 | | | $ | 700 | |
Amount outstanding at period end | Amount outstanding at period end | | 136 | | | 136 | | | 0 | | | 307 | | Amount outstanding at period end | | 294 | | | 294 | | | 147 | | | 136 | |
Average amount outstanding | Average amount outstanding | | 8 | | | 30 | | | 154 | | | 55 | | Average amount outstanding | | 155 | | | 71 | | | 26 | | | 30 | |
Maximum amount outstanding | Maximum amount outstanding | | 136 | | | 230 | | | 432 | | | 309 | | Maximum amount outstanding | | 294 | | | 328 | | | 322 | | | 230 | |
Weighted average interest rate, computed on a daily basis | Weighted average interest rate, computed on a daily basis | | 0.19 | % | | 1.59 | % | | 2.67 | % | | 2.28 | % | Weighted average interest rate, computed on a daily basis | | 4.24 | % | | 2.56 | % | | 0.19 | % | | 1.59 | % |
Weighted average interest rate at end of period | Weighted average interest rate at end of period | | 0.20 | | | 0.20 | | | N/A | | 2.95 | | Weighted average interest rate at end of period | | 4.73 | | | 4.73 | | | 0.22 | | | 0.20 | |
Letters of Credit — PSCo uses letters of credit, typically with terms of one year, to provide financial guarantees for certain operating obligations. At Dec. 31, 20202022 and 2019,2021, there were $827 million and $9$8 million of letters of credit outstanding under the credit facility, respectively. The contract amounts of these letters of credit approximate their fair value and are subject to fees.
Credit Facility — In order to use its commercial paper program to fulfill short-term funding needs, PSCo must have a revolving credit facility in place at least equal to the amount of its commercial paper borrowing limit and cannot issue commercial paper in an aggregate amount exceeding available capacity under this credit facility. The credit facility provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.
Amended Credit Agreement— In June 2019, PSCo entered into an amended five-year credit agreement with a syndicate of banks. The amended credit agreement has substantially the same terms and conditions as the prior credit agreement with the exception of the maturity, which is June 2024.
Features of PSCo’s credit facility:
| Debt-to-Total Capitalization Ratio (a) | Debt-to-Total Capitalization Ratio (a) | | Amount Facility May Be Increased (millions) | | Additional Periods for Which a One-Year Extension May Be Requested (b) | Debt-to-Total Capitalization Ratio (a) | | Amount Facility May Be Increased (millions of dollars) | | Additional Periods for Which a One-Year Extension May Be Requested (b) |
2020 | | 2019 | | | | | |
2022 | | 2022 | | 2021 | | | | |
44 | 44 | % | | 44 | % | | $ | 100 | | | 2 | 44 | % | | 44 | % | | $ | 100 | | | 2 |
(a) The credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65%.
(b) All extension requests are subject to majority bank group approval.
The credit facility has a cross-default provision that provides PSCo would be in default on its borrowings under the facility if PSCo or any of its subsidiaries whose total assets exceed 15% of PSCo’s consolidated total assets, default on indebtedness in an aggregate principal amount exceeding $75 million.
If PSCo does not comply with the covenant, an event of default may be declared, and if not remedied, any outstandingoutstanding amounts due under the facility can be declared due by the lender. As of Dec. 31, 2020,2022, PSCo was in compliance with all financial covenants.
PSCOPSCo had the following committed credit facility available as of Dec. 31, 2020 (millions)2022 (in millions of dollars):
| Credit Facility (a) | Credit Facility (a) | | Drawn (b) | | Available | Credit Facility (a) | | Drawn (b) | | Available |
$ | 700 | | | $ | 144 | | | $ | 556 | | 700 | | | $ | 321 | | | $ | 379 | |
(a)This credit facility matures in June 2024.September 2027.
(b)Includes letters of credit and outstanding commercial paper.
All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. PSCo had0 no direct advances on the facility outstanding at Dec. 31, 20202022 and 2019.2021.
Long-Term Borrowings and Other Financing Instruments
Generally, the property of PSCo is subject to the lienslien of its first mortgage indenture.indenture for the benefit of bondholders. Debt premiums, discounts and expenses are amortized over the life of the related debt. The premiums, discounts and expenses for refinanced debt are deferred and amortized over the life of the new issuance.
Long-term debt obligations for PSCo as of Dec. 31 (millions(in millions of dollars):
| Financing Instrument | Financing Instrument | | Interest Rate | | Maturity Date | | 2020 | | 2019 | Financing Instrument | | Interest Rate | | Maturity Date | | 2022 | | 2021 |
First mortgage bonds | First mortgage bonds | | 3.20 | | | Nov. 15, 2020 | | 0 | | | 400 | | First mortgage bonds | | 2.25 | % | | Sept. 15, 2022 | | $ | — | | | $ | 300 | |
First mortgage bonds | First mortgage bonds | | 2.25 | | | Sept. 15, 2022 | | 300 | | | 300 | | First mortgage bonds | | 2.50 | | | March 15, 2023 | | 250 | | | 250 | |
First mortgage bonds | First mortgage bonds | | 2.50 | | | March 15, 2023 | | 250 | | | 250 | | First mortgage bonds | | 2.90 | | | May 15, 2025 | | 250 | | | 250 | |
First mortgage bonds | First mortgage bonds | | 2.90 | | | May 15, 2025 | | 250 | | | 250 | | First mortgage bonds | | 3.70 | | | June 15, 2028 | | 350 | | | 350 | |
First mortgage bonds | First mortgage bonds | | 3.70 | | | June 15, 2028 | | 350 | | | 350 | | First mortgage bonds | | 1.90 | | | Jan. 15, 2031 | | 375 | | | 375 | |
First mortgage bonds (a) | First mortgage bonds (a) | | 1.90 | | | Jan. 15, 2031 | | 375 | | | 0 | | First mortgage bonds (a) | | 1.875 | | | June 15, 2031 | | 750 | | | 750 | |
First mortgage bonds (b) | | First mortgage bonds (b) | | 4.10 | | | June 1, 2032 | | 300 | | | — | |
First mortgage bonds | | First mortgage bonds | | 6.25 | | | Sept. 1, 2037 | | 350 | | | 350 | |
First mortgage bonds | | First mortgage bonds | | 6.50 | | | Aug. 1, 2038 | | 300 | | | 300 | |
First mortgage bonds | | First mortgage bonds | | 4.75 | | | Aug. 15, 2041 | | 250 | | | 250 | |
First mortgage bonds | First mortgage bonds | | 6.25 | | | Sept. 1, 2037 | | 350 | | | 350 | | First mortgage bonds | | 3.60 | | | Sept. 15, 2042 | | 500 | | | 500 | |
First mortgage bonds | First mortgage bonds | | 6.50 | | | Aug. 1, 2038 | | 300 | | | 300 | | First mortgage bonds | | 3.95 | | | March 15, 2043 | | 250 | | | 250 | |
First mortgage bonds | First mortgage bonds | | 4.75 | | | Aug. 15, 2041 | | 250 | | | 250 | | First mortgage bonds | | 4.30 | | | March 15, 2044 | | 300 | | | 300 | |
First mortgage bonds | First mortgage bonds | | 3.60 | | | Sept. 15, 2042 | | 500 | | | 500 | | First mortgage bonds | | 3.55 | | | June 15, 2046 | | 250 | | | 250 | |
First mortgage bonds | First mortgage bonds | | 3.95 | | | March 15, 2043 | | 250 | | | 250 | | First mortgage bonds | | 3.80 | | | June 15, 2047 | | 400 | | | 400 | |
First mortgage bonds | First mortgage bonds | | 4.30 | | | March 15, 2044 | | 300 | | | 300 | | First mortgage bonds | | 4.10 | | | June 15, 2048 | | 350 | | | 350 | |
First mortgage bonds | First mortgage bonds | | 3.55 | | | June 15, 2046 | | 250 | | | 250 | | First mortgage bonds | | 4.05 | | | Sept. 15, 2049 | | 400 | | | 400 | |
First mortgage bonds | First mortgage bonds | | 3.80 | | | June 15, 2047 | | 400 | | | 400 | | First mortgage bonds | | 3.20 | | | March 1, 2050 | | 550 | | | 550 | |
First mortgage bonds | First mortgage bonds | | 4.10 | | | June 15, 2048 | | 350 | | | 350 | | First mortgage bonds | | 2.70 | | | Jan. 15, 2051 | | 375 | | | 375 | |
First mortgage bonds (b) | First mortgage bonds (b) | | 4.05 | | | Sept. 15, 2049 | | 400 | | | 400 | | First mortgage bonds (b) | | 4.50 | | | June 1, 2052 | | 400 | | | — | |
First mortgage bonds (b) | | 3.20 | | | March 1, 2050 | | 550 | | | 550 | | |
First mortgage bonds (a) | | 2.70 | | | Jan. 15, 2051 | | 375 | | | 0 | | |
Unamortized discount | Unamortized discount | | (30) | | | (24) | | Unamortized discount | | (37) | | | (33) | |
Unamortized debt issuance cost | Unamortized debt issuance cost | | (46) | | | (41) | | Unamortized debt issuance cost | | (53) | | | (50) | |
Current maturities | Current maturities | | 0 | | | (400) | | Current maturities | | (250) | | | (300) | |
Total long-term debt | Total long-term debt | | $ | 5,724 | | | $ | 4,985 | | Total long-term debt | | $ | 6,610 | | | $ | 6,167 | |
(a)20202021 financing.
(b)20192022 financing.
Maturities of long-term debt:
| (Millions of Dollars) | (Millions of Dollars) | | (Millions of Dollars) | |
2021 | | $ | 0 | | |
2022 | | 300 | | |
2023 | 2023 | | 250 | | 2023 | | $ | 250 | |
2024 | 2024 | | 0 | | 2024 | | — | |
2025 | 2025 | | 250 | | 2025 | | 250 | |
2026 | | 2026 | | — | |
2027 | | 2027 | | — | |
Deferred Financing Costs — Deferred financing costs of approximately$46 $53 million and $41$50 million, net of amortization, are presented as a deduction from the carrying amount of long-term debt as of Dec. 31, 20202022 and 2019,2021, respectively. PSCo is amortizing these financing costs over the remaining maturity periods of the related debt.
Capital Stock — PSCo has authorized the issuance of preferred stock.
| Preferred Stock Authorized (Shares) | Preferred Stock Authorized (Shares) | | Par Value of Preferred Stock | | Preferred Stock Outstanding (Shares) 2020 and 2019 | Preferred Stock Authorized (Shares) | | Par Value of Preferred Stock | | Preferred Stock Outstanding (Shares) 2022 and 2021 |
10,000,000 | 10,000,000 | | | $ | 0.01 | | | 0 | | 10,000,000 | | | $ | 0.01 | | | — | |
Dividend Restrictions — PSCo’s dividends are subject to the FERC’s jurisdiction, which prohibits the payment of dividends out of capital accounts. Dividends are solely to be paid from retained earnings.
Revenue is classified by the type of goods/services rendered and market/customer type. PSCo’s operating revenues consisted of the following:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended Dec. 31, 2020 |
(Millions of Dollars) | | Electric | | Natural Gas | | All Other | | Total |
Major revenue types | | | | | | | | |
Revenue from contracts with customers: |
Residential | | $ | 1,073 | | | $ | 650 | | | $ | 12 | | | $ | 1,735 | |
C&I | | 1,512 | | | 225 | | | 27 | | | 1,764 | |
Other | | 48 | | | 0 | | | 0 | | | 48 | |
Total retail | | 2,633 | | | 875 | | | 39 | | | 3,547 | |
Wholesale | | 212 | | | 0 | | | 0 | | | 212 | |
Transmission | | 62 | | | 0 | | | 0 | | | 62 | |
Other | | 56 | | | 125 | | | 0 | | | 181 | |
Total revenue from contracts with customers | | 2,963 | | | 1,000 | | | 39 | | | 4,002 | |
Alternative revenue and other | | 153 | | | 24 | | | 4 | | | 181 | |
Total revenues | | $ | 3,116 | | | $ | 1,024 | | | $ | 43 | | | $ | 4,183 | |
| | | Year Ended Dec. 31, 2019 | | Year Ended Dec. 31, 2022 |
(Millions of Dollars) | (Millions of Dollars) | | Electric | | Natural Gas | | All Other | | Total | (Millions of Dollars) | | Electric | | Natural Gas | | All Other | | Total |
Major revenue types | Major revenue types | | | | | | | | | Major revenue types | | | | | | | | |
Revenue from contracts with customers: | Revenue from contracts with customers: | Revenue from contracts with customers: |
Residential | Residential | | $ | 1,006 | | | $ | 750 | | | $ | 11 | | | $ | 1,767 | | Residential | | $ | 1,341 | | | $ | 1,203 | | | $ | 15 | | | $ | 2,559 | |
C&I | C&I | | 1,579 | | | 281 | | | 28 | | | 1,888 | | C&I | | 1,843 | | | 479 | | | 32 | | | 2,354 | |
Other | Other | | 50 | | | 0 | | | 0 | | | 50 | | Other | | 52 | | | — | | | — | | | 52 | |
Total retail | Total retail | | 2,635 | | | 1,031 | | | 39 | | | 3,705 | | Total retail | | 3,236 | | | 1,682 | | | 47 | | | 4,965 | |
Wholesale | Wholesale | | 166 | | | 0 | | | 0 | | | 166 | | Wholesale | | 286 | | | — | | | — | | | 286 | |
Transmission | Transmission | | 52 | | | 0 | | | 0 | | | 52 | | Transmission | | 88 | | | — | | | — | | | 88 | |
Other | Other | | 32 | | | 107 | | | 0 | | | 139 | | Other | | 53 | | | 151 | | | — | | | 204 | |
Total revenue from contracts with customers | Total revenue from contracts with customers | | 2,885 | | | 1,138 | | | 39 | | | 4,062 | | Total revenue from contracts with customers | | 3,663 | | | 1,833 | | | 47 | | | 5,543 | |
Alternative revenue and other | Alternative revenue and other | | 148 | | | 23 | | | 4 | | | 175 | | Alternative revenue and other | | 132 | | | 27 | | | 6 | | | 165 | |
Total revenues | Total revenues | | $ | 3,033 | | | $ | 1,161 | | | $ | 43 | | | $ | 4,237 | | Total revenues | | $ | 3,795 | | | $ | 1,860 | | | $ | 53 | | | $ | 5,708 | |
| | | Year Ended Dec. 31, 2018 | | Year Ended Dec. 31, 2021 |
(Millions of Dollars) | (Millions of Dollars) | | Electric | | Natural Gas | | All Other | | Total | (Millions of Dollars) | | Electric | | Natural Gas | | All Other | | Total |
Major revenue types | Major revenue types | | | | | | | | | Major revenue types | | | | | | | | |
Revenue from contracts with customers: | Revenue from contracts with customers: | Revenue from contracts with customers: |
Residential | Residential | | $ | 991 | | | $ | 606 | | | $ | 11 | | | $ | 1,608 | | Residential | | $ | 1,174 | | | $ | 816 | | | $ | 12 | | | $ | 2,002 | |
C&I | C&I | | 1,560 | | | 224 | | | 25 | | | 1,809 | | C&I | | 1,660 | | | 308 | | | 30 | | | 1,998 | |
Other | Other | | 48 | | | 0 | | | 0 | | | 48 | | Other | | 49 | | | — | | | — | | | 49 | |
Total retail | Total retail | | 2,599 | | | 830 | | | 36 | | | 3,465 | | Total retail | | 2,883 | | | 1,124 | | | 42 | | | 4,049 | |
Wholesale | Wholesale | | 175 | | | 0 | | | 0 | | | 175 | | Wholesale | | 228 | | | — | | | — | | | 228 | |
Transmission | Transmission | | 54 | | | 0 | | | 0 | | | 54 | | Transmission | | 75 | | | — | | | — | | | 75 | |
Other | Other | | 55 | | | 84 | | | 0 | | | 139 | | Other | | 44 | | | 159 | | | — | | | 203 | |
Total revenue from contracts with customers | Total revenue from contracts with customers | | 2,883 | | | 914 | | | 36 | | | 3,833 | | Total revenue from contracts with customers | | 3,230 | | | 1,283 | | | 42 | | | 4,555 | |
Alternative revenue and other | Alternative revenue and other | | 148 | | | 101 | | | 4 | | | 253 | | Alternative revenue and other | | 183 | | | 72 | | | 5 | | | 260 | |
Total revenues | Total revenues | | $ | 3,031 | | | $ | 1,015 | | | $ | 40 | | | $ | 4,086 | | Total revenues | | $ | 3,413 | | | $ | 1,355 | | | $ | 47 | | | $ | 4,815 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended Dec. 31, 2020 |
(Millions of Dollars) | | Electric | | Natural Gas | | All Other | | Total |
Major revenue types | | | | | | | | |
Revenue from contracts with customers: |
Residential | | $ | 1,073 | | | $ | 650 | | | $ | 12 | | | $ | 1,735 | |
C&I | | 1,512 | | | 225 | | | 27 | | | 1,764 | |
Other | | 48 | | | — | | | — | | | 48 | |
Total retail | | 2,633 | | | 875 | | | 39 | | | 3,547 | |
Wholesale | | 212 | | | — | | | — | | | 212 | |
Transmission | | 62 | | | — | | | — | | | 62 | |
Other | | 56 | | | 125 | | | — | | | 181 | |
Total revenue from contracts with customers | | 2,963 | | | 1,000 | | | 39 | | | 4,002 | |
Alternative revenue and other | | 153 | | | 24 | | | 4 | | | 181 | |
Total revenues | | $ | 3,116 | | | $ | 1,024 | | | $ | 43 | | | $ | 4,183 | |
Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense.
Effective income tax rate for years ended Dec. 31: | | | | | | | | | | | | | | | | | | | | |
| | 2022 | | 2021 (c) | | 2020 (c) |
Federal statutory rate | | 21.0 | % | | 21.0 | % | | 21.0 | % |
State income tax on pretax income, net of federal tax effect | | 3.5 | | | 3.6 | | | 3.6 | |
Increases (decreases) in tax from: | | | | | | |
Wind PTCs (a) | | (14.3) | | | (14.3) | | | (10.3) | |
Plant regulatory differences (b) | | (4.5) | | | (4.6) | | | (5.0) | |
Other tax credits, net NOL & tax credit allowances | | (1.1) | | | (1.0) | | | (1.1) | |
Other, net | | 0.2 | | | 0.1 | | | (1.1) | |
Effective income tax rate | | 4.8 | % | | 4.8 | % | | 7.1 | % |
(a)Wind PTCs are credited to customers (reduction to revenue) and do not materially impact net income.
(b)Regulatory differences for income tax primarily relate to the credit of excess deferred taxes to customers through the average rate assumption method. Income tax benefits associated with the credit of excess deferred taxes are offset by corresponding revenue reductions and additional prepaid pension asset amortization.
(c)Prior period amounts have been restated to conform with current year presentation.
Components of income tax expense for the years ended Dec. 31:
| | | | | | | | | | | | | | | | | | | | |
(Millions of Dollars) | | 2022 | | 2021 | | 2020 |
Current federal tax expense | | $ | 39 | | | $ | 16 | | | $ | 44 | |
Current state tax expense | | 11 | | | — | | | 4 | |
Current change in unrecognized tax benefit | | — | | | (1) | | | (3) | |
Deferred federal tax benefit | | (32) | | | (13) | | | (26) | |
Deferred state tax expense | | 21 | | | 31 | | | 26 | |
Deferred change in unrecognized tax expense | | 1 | | | 3 | | | 2 | |
Deferred ITCs | | (3) | | | (3) | | | (2) | |
Total income tax expense | | $ | 37 | | | $ | 33 | | | $ | 45 | |
Components of deferred income tax expense as of Dec. 31:
| | | | | | | | | | | | | | | | | | | | |
(Millions of Dollars) | | 2022 | | 2021 | | 2020 |
Deferred tax expense excluding items below | | $ | 23 | | | $ | 63 | | | $ | 46 | |
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities | | (32) | | | (42) | | | (43) | |
Tax expense allocated to other comprehensive income, and other | | (1) | | | — | | | (1) | |
Deferred tax (benefit) expense | | $ | (10) | | | $ | 21 | | | $ | 2 | |
Components of the net deferred tax liability as of Dec. 31:
| | | | | | | | | | | | | | |
(Millions of Dollars) | | 2022 | | 2021 (a) |
Deferred tax liabilities: | | | | |
Differences between book and tax bases of property | | $ | 2,315 | | | $ | 2,226 | |
Regulatory assets | | 246 | | | 255 | |
Deferred fuel costs | | 125 | | | 126 | |
Operating lease assets | | 112 | | | 106 | |
Pension expense and other employee benefits | | 27 | | | 23 | |
Other | | 11 | | | 4 | |
Total deferred tax liabilities | | $ | 2,836 | | | $ | 2,740 | |
| | | | |
Deferred tax assets: | | | | |
Regulatory liabilities | | $ | 295 | | | $ | 320 | |
Tax credit carryforward | | 385 | | | 276 | |
Operating lease liabilities | | 112 | | | 106 | |
Bad debts | | 14 | | | 10 | |
NOL carryforward | | 9 | | | 46 | |
Deferred ITCs | | 7 | | | 8 | |
Tax credit valuation allowances | | (6) | | | (8) | |
Rate refund | | 21 | | | 8 | |
Other | | 16 | | | 14 | |
Total deferred tax assets | | $ | 853 | | | $ | 780 | |
Net deferred tax liability | | $ | 1,983 | | | $ | 1,960 | |
(a) Prior periods have been reclassified to conform to current year presentation.
Other Income Tax Matters — NOL amounts represent the tax loss that is carried forward and tax credits represent the deferred tax asset.
NOL and tax credit carryforwards as of Dec. 31 were as follows:
| | | | | | | | | | | | | | |
(Millions of Dollars) | | 2022 | | 2021 |
Federal NOL carryforward | | $ | 5 | | | $ | 161 | |
Federal tax credit carryforwards | | 368 | | | 259 | |
State NOL carryforwards | | 223 | | | 342 | |
State tax credit carryforwards, net of federal detriment (a) | | 16 | | | 17 | |
Valuation allowances for state credit carryforwards, net of federal benefit (b) | | (6) | | | (8) | |
(a)State tax credit carryforwards are net of federal detriment of $4 million and $5 million as of Dec. 31, 2022 and 2021.
(b)Valuation allowances for state tax credit carryforwards were net of federal benefit of $2 million as of Dec. 31, 2022 and 2021.
Federal carryforward periods expire starting 2033 and state carryforward periods expire between 2024 and 2041.
Federal Tax Loss Carryback ClaimsClaims — In 2020, Xcel Energy identified certain expenses related to tax years 2009 - 2011 that qualify for an extended carryback claim. PSCo is not expected to accrue any income tax expense related to this adjustment.
Unrecognized Tax Benefits
Federal Audit — PSCo is a member of Xcel Energy affiliated group that files a consolidated federal income tax return. StatueThe statute of limitations applicable to Xcel Energy’s consolidated federal tax returns expire as follows: | | | | | | | | |
Tax Year(s) | | Expiration |
2014 - 2016 | | July 2021March 2024 |
2019 | | October 2023 |
Additionally, the statute of limitations related to certain federal tax credit carryforwards will remain open until those credits are utilized in subsequent returns. Further, the statute of limitations related to the additional federal tax loss carryback claim referenced abovefiled in 2020 has been extended. Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of this issue; however, the outcome and timing of a resolution is unknown.
In 2017, the IRS concluded the audit of tax years 2012 and 2013 and proposed an adjustment that would impact Xcel Energy’s NOL and ETR. Xcel Energy filed a protest with the IRS. In April 2020, Xcel Energy and Appeals reached an agreement and 0 material adjustments were required.
In 2018, the IRS began an audit of tax years 2014 - 2016. In July 2020, Xcel Energy and the IRS reached an agreement and the related benefit was recognized.
State Audits — PSCo is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Dec. 31, 2020,2022, PSCo’s earliest open tax yearyears that isare subject to examination by state taxing authorities under applicable statutes of limitations is 2009. are as follows:
| | | | | | | | | | | | | | |
State | | Tax Year(s) | | Expiration |
Colorado | | 2014-2016 | | March 2025 |
Colorado | | 2018 | | September 2023 |
There are currently 0no state income tax audits in progress.
Unrecognized Tax Benefits — Unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual ETR. In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain, but for which there is uncertainty about the timing of such deductibility.timing. A change in the periodtiming of deductibility would not affect the ETR but would accelerate the payment to the taxing authority to an earlier period.authority.
Unrecognized tax benefits - permanent vs temporary:
| (Millions of Dollars) | (Millions of Dollars) | | Dec. 31, 2020 | | Dec. 31, 2019 | (Millions of Dollars) | | Dec. 31, 2022 | | Dec. 31, 2021 |
Unrecognized tax benefit — Permanent tax positions | Unrecognized tax benefit — Permanent tax positions | | $ | 7 | | | $ | 7 | | Unrecognized tax benefit — Permanent tax positions | | $ | 11 | | | $ | 9 | |
Unrecognized tax benefit — Temporary tax positions | Unrecognized tax benefit — Temporary tax positions | | 2 | | | 5 | | Unrecognized tax benefit — Temporary tax positions | | 2 | | | 2 | |
Total unrecognized tax benefit | Total unrecognized tax benefit | | $ | 9 | | | $ | 12 | | Total unrecognized tax benefit | | $ | 13 | | | $ | 11 | |
Changes in unrecognized tax benefits:
| (Millions of Dollars) | (Millions of Dollars) | | 2020 | | 2019 | | 2018 | (Millions of Dollars) | | 2022 | | 2021 | | 2020 |
Balance at Jan. 1 | Balance at Jan. 1 | | $ | 12 | | | $ | 10 | | | $ | 10 | | Balance at Jan. 1 | | $ | 11 | | | $ | 9 | | | $ | 12 | |
Additions based on tax positions related to the current year | Additions based on tax positions related to the current year | | 2 | | | 1 | | | 1 | | Additions based on tax positions related to the current year | | 2 | | | 2 | | | 2 | |
Additions for tax positions of prior years | Additions for tax positions of prior years | | 6 | | | 1 | | | 0 | | Additions for tax positions of prior years | | — | | | — | | | 6 | |
Reductions for tax positions of prior years | Reductions for tax positions of prior years | | (11) | | | 0 | | | 0 | | Reductions for tax positions of prior years | | — | | | — | | | (11) | |
Settlements with taxing authorities | | 0 | | | 0 | | | (1) | | |
Balance at Dec. 31 | Balance at Dec. 31 | | $ | 9 | | | $ | 12 | | | $ | 10 | | Balance at Dec. 31 | | $ | 13 | | | $ | 11 | | | $ | 9 | |
Unrecognized tax benefits were reduced by tax benefits associated with NOL and tax credit carryforwards:
| (Millions of Dollars) | (Millions of Dollars) | | Dec. 31, 2020 | | Dec. 31, 2019 | (Millions of Dollars) | | Dec. 31, 2022 | | Dec. 31, 2021 |
NOL and tax credit carryforwards | NOL and tax credit carryforwards | | $ | (8) | | | $ | (8) | | NOL and tax credit carryforwards | | $ | (12) | | | $ | (11) | |
Net deferred tax liability associated with the unrecognized tax benefit amounts and related NOLs and tax credits carryforwards were $6 million and $5 million for Dec. 31, 2020 and Dec. 31, 2019, respectively.
As the IRS progresses its review of the tax loss carryback claims and as state audits resume, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $3$5 million in the next 12 months.
Payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards.
Interest payable related to unrecognized tax benefits:
| (Millions of Dollars) | (Millions of Dollars) | | 2020 | | 2019 | | 2018 | (Millions of Dollars) | | 2022 | | 2021 | | 2020 |
Payable for interest related to unrecognized tax benefits at Jan. 1 | Payable for interest related to unrecognized tax benefits at Jan. 1 | | $ | (1) | | | $ | (1) | | | $ | 0 | | Payable for interest related to unrecognized tax benefits at Jan. 1 | | $ | — | | | $ | — | | | $ | (1) | |
Interest income (expense) related to unrecognized tax benefits | | 1 | | | 0 | | | (1) | | |
Interest income related to unrecognized tax benefits | | Interest income related to unrecognized tax benefits | | — | | | — | | | 1 | |
Payable for interest related to unrecognized tax benefits at Dec. 31 | Payable for interest related to unrecognized tax benefits at Dec. 31 | | $ | 0 | | | $ | (1) | | | $ | (1) | | Payable for interest related to unrecognized tax benefits at Dec. 31 | | $ | — | | | $ | — | | | $ | — | |
NaN No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2020, 20192022, 2021 or 2018.
Other Income Tax Matters — NOL amounts represent the tax loss that is carried forward and tax credits represent the deferred tax asset.
NOL and tax credit carryforwards as of Dec. 31 were as follows:
| | | | | | | | | | | | | | |
(Millions of Dollars) | | 2020 | | 2019 |
Federal tax credit carryforwards | | $ | 143 | | | $ | 83 | |
State NOL carryforwards | | 190 | | | 388 | |
State tax credit carryforwards, net of federal detriment (a) | | 18 | | | 18 | |
Valuation allowances for state credit carryforwards, net of federal benefit (b) | | (8) | | | (8) | |
(a)State tax credit carryforwards are net of federal detriment of $5 million as of both Dec. 31, 2020 and 2019.
(b)Valuation allowances for state tax credit carryforwards were net of federal benefit of $2 million as of both Dec. 31, 2020 and 2019.
Federal carryforward periods expire between 2031 and 2040 and state carryforward periods expire between 2021 and 2033.
Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense.
Effective income tax rate for years ended Dec. 31: | | | | | | | | | | | | | | | | | | | | |
| | 2020 | | 2019 | | 2018 |
Federal statutory rate | | 21.0 | % | | 21.0 | % | | 21.0 | % |
State income tax on pretax income, net of federal tax effect | | 3.6 | | | 3.6 | | | 3.7 | |
Increases (decreases) in tax from: | | | | | | |
Wind PTCs | | (10.3) | | | (7.5) | | | (0.6) | |
Plant regulatory differences (a) | | (5.0) | | | (3.3) | | | (4.5) | |
Other tax credits, net NOL & tax credit allowances | | (1.1) | | | (1.3) | | | (0.6) | |
Amortization of excess nonplant deferred taxes | | (0.2) | | | (0.2) | | | (1.4) | |
Change in unrecognized tax benefits | | (0.2) | | | 0.3 | | | 0.1 | |
Other, net | | (0.7) | | | (0.4) | | | (0.7) | |
Effective income tax rate | | 7.1 | % | | 12.2 | % | | 17.0 | % |
.(a) Regulatory differences for income tax primarily relate to the credit of excess deferred taxes to customers through the average rate assumption method. Income tax benefits associated with the credit of excess deferred credits are offset by corresponding revenue reductions and additional prepaid pension asset amortization.
Components of income tax expense for the years ended Dec. 31:
| | | | | | | | | | | | | | | | | | | | |
(Millions of Dollars) | | 2020 | | 2019 | | 2018 |
Current federal tax expense (benefit) | | $ | 44 | | | $ | (9) | | | $ | 79 | |
Current state tax expense (benefit) | | 4 | | | (5) | | | 14 | |
Current change in unrecognized tax benefit | | (3) | | | (1) | | | (1) | |
Deferred federal tax (benefit) expense | | (26) | | | 61 | | | 5 | |
Deferred state tax expense | | 26 | | | 33 | | | 17 | |
Deferred change in unrecognized tax expense | | 2 | | | 3 | | | 2 | |
Deferred ITCs | | (2) | | | (2) | | | (3) | |
Total income tax expense | | $ | 45 | | | $ | 80 | | | $ | 113 | |
Components of deferred income tax expense as of Dec. 31:
| | | | | | | | | | | | | | | | | | | | |
(Millions of Dollars) | | 2020 | | 2019 | | 2018 |
Deferred tax expense excluding items below | | $ | 46 | | | $ | 132 | | | $ | 75 | |
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities | | (43) | | | (35) | | | (51) | |
Tax expense allocated to other comprehensive income, adoption of ASC Topic 326, adoption of ASU No. 2018-02, and other | | (1) | | | 0 | | | 0 | |
Deferred tax expense | | $ | 2 | | | $ | 97 | | | $ | 24 | |
Components of the net deferred tax liability as of Dec. 31:
| | | | | | | | | | | | | | |
(Millions of Dollars) | | 2020 | | 2019 (a) |
Deferred tax liabilities: | | | | |
Differences between book and tax bases of property | | $ | 2,132 | | | $ | 2,039 | |
Regulatory assets | | 257 | | | 253 | |
Operating lease assets | | 129 | | | 148 | |
Pension expense and other employee benefits | | 19 | | | 22 | |
Other | | 6 | | | 7 | |
Total deferred tax liabilities | | $ | 2,543 | | | $ | 2,469 | |
| | | | |
Deferred tax assets: | | | | |
Regulatory liabilities | | $ | 319 | | | $ | 327 | |
Tax credit carryforward | | 161 | | | 101 | |
Operating lease liabilities | | 129 | | | 148 | |
Bad debts | | 8 | | | 5 | |
NOL carryforward | | 7 | | | 14 | |
Deferred ITCs | | 5 | | | 6 | |
Tax credit valuation allowances | | (8) | | | (8) | |
Other | | 25 | | | 25 | |
Total deferred tax assets | | $ | 646 | | | $ | 618 | |
Net deferred tax liability | | $ | 1,897 | | | $ | 1,851 | |
(a) Prior periods have been reclassified to conform to current year presentation.2020.
| | |
8. Fair Value of Financial Assets and Liabilities |
Fair Value Measurements
Accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires disclosures about assets and liabilities measured at fair value. A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance.value.
•Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quotedobservable actual trading prices.
•Level 2 — Pricing inputs are other than quotedactual trading prices in active markets but are either directly or indirectly observable as of the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts or priced with models using highly observable inputs.
•Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 areinclude those valued with models requiring significant management judgment or estimation.
Specific valuation methods include:
Cash equivalents— The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted net asset value.
Interest rate derivatives — The fairFair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.
Commodity derivatives — The methodsMethods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2 classification. When contractual settlementscontracts relate to inactive delivery locations or extend to periods beyond those readily observable on active exchanges, or quoted by brokers, the significance of the use of less observable forecasts of forward prices and volatilitiesinputs on a valuation is evaluated and may result in Level 3 classification.
Derivative InstrumentsActivities and Fair Value Measurements
PSCo enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to manage risk in connection with changes in interest rates and utility commodity prices and vehicle fuel prices.
Interest Rate Derivatives — PSCo enters into various instrumentscontracts that effectively fix the yield or priceinterest rate on a specified principal amount of a hypothetical future debt issuance. These financial swaps net settle based on changes in a specified benchmark interest rate, for anacting as a hedge of changes in market interest rates that will impact specified anticipated debt issuance for a specific period.issuances. These derivative instruments are generally designated as cash flow hedges for accounting purposes, with changes in fair value prior to settlementoccurrence of the hedged transactions recorded as other comprehensive income.
As of Dec. 31, 2020,2022, accumulated other comprehensive loss related to settled interest rate derivatives included $1 million of net losses expected to be reclassified into earnings during the next 12 months as the hedged transactions impact earnings, including forecasted amounts forearnings. As of Dec. 31, 2022, PSCo had no unsettled hedges, as applicable.interest rate derivatives.
Wholesale and Commodity Trading Risk— PSCo conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. PSCo is allowed to conduct these activities within guidelines and limitations as approved by its risk management committee, comprised of management personnel not directly involved in the activities governed by this policy.
Derivative instruments entered into for trading purposes are presented in the consolidated statements of income as electric revenues, net of any sharing with customers. These activities are not intended to mitigate commodity price risk associated with regulated electric and natural gas operations. Sharing of these margins is determined through state regulatory proceedings as well as the operation of the FERC-approved joint operating agreement.
Commodity Derivatives — PSCo enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric and natural gas operations, as well as for trading purposes.operations. This could include the purchase or sale of energy or energy-related products, natural gas to generate electric energy, natural gas for resale, and vehicle fuel.
When PSCo enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers, but maythe instruments are not betypically designated as qualifying hedging transactions. The classification of unrealized losses or gains on these instruments as a regulatory asset or liability, if applicable, is based on approved regulatory recovery mechanisms.
As of Dec. 31, 2020,2022, PSCo had 0no commodity contracts designated as cash flow hedges.
PSCo enters into commodity derivative instruments for trading purposes not directly related to commodity price risks associated with serving its electric and natural gas customers. Changes in the fair value of these commodity derivatives are recorded in electric operating revenues, net of amounts credited to customers under margin-sharing mechanisms.
Gross notional amounts of commodity forwards and options:
| (Amounts in Millions) (a)(b) | (Amounts in Millions) (a)(b) | | Dec. 31, 2020 | | Dec. 31, 2019 | (Amounts in Millions) (a)(b) | | Dec. 31, 2022 | | Dec. 31, 2021 |
MWh of electricity | MWh of electricity | | 17 | | | 9 | | MWh of electricity | | 8 | | | 15 | |
MMBtu of natural gas | MMBtu of natural gas | | 93 | | | 32 | | MMBtu of natural gas | | 43 | | | 71 | |
(a)Not reflective of net positions in the underlying commodities.
(b)Notional amounts for options included on a gross basis, but are weighted for the probability of exercise.
Consideration of Credit Risk and Concentrations — PSCo continuously monitors the creditworthiness of the counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. The impactImpact of credit risk was immaterial to the fair value of unsettled commodity derivatives presented on the consolidated balance sheets.
PSCo’s most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to its wholesale, trading and non-trading commodity activities. At
As of Dec. 31, 2020, 42022, four of PSCo’s 10ten most significant counterparties for these activities, comprising $99$51 million or 66%53% of this credit exposure, had investment grade credit ratings from S&P Global Ratings, Moody’s Investor Services or Fitch Ratings. NaNFour of the 10ten most significant counterparties, comprising $19$25 million or 13%26% of this credit exposure, were not rated by these external ratings agencies, but based on PSCo’s internal analysis, had credit quality consistent with investment grade. NaNTwo of these significant counterparties, comprising $19$21 million, or 13%21%, of this credit exposure, had credit quality less than investment grade, based on external and internal analysis. NaNSeven of these significant counterparties are independent system operators, municipal, cooperative electric entities, Regional Transmission OrganizationsRTOs or other utilities.
Qualifying Cash Flow Hedges — Financial impact of qualifying interest rate and vehicle fuel cash flow hedges on PSCo’s accumulated other comprehensive loss, included in the consolidated statements of common stockholder’s equity and in the consolidated statements of comprehensive income:
| | | | | | | | | | | | | | | | | | | | |
(Millions of Dollars) | | 2020 | | 2019 | | 2018 |
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1 | | $ | (24) | | | $ | (26) | | | $ | (27) | |
After-tax net realized losses on derivative transactions reclassified into earnings | | 1 | | | 2 | | | 1 | |
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31 | | $ | (23) | | | $ | (24) | | | $ | (26) | |
Impact of derivative activity: | | | | | | | | | | | | | | |
| | Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: |
(Millions of Dollars) | | Accumulated Other Comprehensive Loss | | Regulatory (Assets) and Liabilities |
Year Ended Dec. 31, 2020 | | | | |
Other derivative instruments | | | | |
Natural gas commodity | | $ | 0 | | | $ | (10) | |
Total | | $ | 0 | | | $ | (10) | |
| | | | |
Year Ended Dec. 31, 2019 | | | | |
Other derivative instruments | | | | |
Natural gas commodity | | $ | 0 | | | $ | (5) | |
Total | | $ | 0 | | | $ | (5) | |
| | | | |
Year Ended Dec. 31, 2018 | | | | |
Other derivative instruments | | | | |
Natural gas commodity | | $ | 0 | | | $ | 8 | |
Total | | $ | 0 | | | $ | 8 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | Pre-Tax (Gains) Losses Reclassified into Income During the Period from: | | | |
(Millions of Dollars) | | Accumulated Other Comprehensive Loss | | Regulatory Assets and (Liabilities) | | Pre-Tax Gains (Losses) Recognized During the Period in Income | |
Year Ended Dec. 31, 2020 | | | | | |
Derivatives designated as cash flow hedges | | | |
Interest rate | | $ | 1 | | (a) | $ | 0 | | | $ | 0 | | |
Total | | $ | 1 | | | $ | 0 | | | $ | 0 | | |
Other derivative instruments | | | |
Commodity trading | | $ | 0 | | | $ | 0 | | | $ | 3 | | (b) |
Natural gas commodity | | 0 | | | 8 | | (c) | (8) | | (c) |
Total | | $ | 0 | | | $ | 8 | | | $ | (5) | | |
(a)Recorded to interest charges.
(b)Recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate.
(c)Amounts for the year ended Dec. 31, 2020, included 0 settlement gains or losses on derivatives entered to mitigate natural gas price risk for electric generation recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset or liability, as appropriate. Remaining settlement losses for the years ended Dec. 31, 2020, relate to natural gas operations and are recorded to cost of natural gas sold and transported. These losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset or liability, as appropriate.
| | | | | | | | | | | | | | | | | | | | | | | |
| | Pre-Tax (Gains) Losses Reclassified into Income During the Period from: | | | |
(Millions of Dollars) | | Accumulated Other Comprehensive Loss | | Regulatory Assets and (Liabilities) | | Pre-Tax Gains (Losses) Recognized During the Period in Income | |
Year Ended Dec. 31, 2019 | | | | | |
Derivatives designated as cash flow hedges | | | |
Interest rate | | $ | 2 | | (a) | $ | 0 | | | $ | 0 | | |
Total | | $ | 2 | | | $ | 0 | | | $ | 0 | | |
Other derivative instruments | | | |
Commodity trading | | $ | 0 | | | $ | 0 | | | $ | 3 | | (b) |
Natural gas commodity | | 0 | | | 1 | | (c) | (4) | | (c) |
Total | | $ | 0 | | | $ | 1 | | | $ | (1) | | |
(a)Recorded to interest charges.
(b)Recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate.
(c)Amounts for the year ended Dec. 31, 2019, included 0 settlement gains or losses on derivatives entered to mitigate natural gas price risk for electric generation recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset or liability, as appropriate. Remaining settlement losses for the years ended Dec. 31, 2019, relate to natural gas operations and are recorded to cost of natural gas sold and transported. These losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset or liability, as appropriate.
| | | | | | | | | | | | | | | | | | | | | | | |
| | Pre-Tax (Gains) Losses Reclassified into Income During the Period from: | | | |
(Millions of Dollars) | | Accumulated Other Comprehensive Loss | | Regulatory Assets and (Liabilities) | | Pre-Tax Gains (Losses) Recognized During the Period in Income | |
Year Ended Dec. 31, 2018 | | | | | |
Derivatives designated as cash flow hedges | | | |
Interest rate | | $ | 1 | | (a) | $ | 0 | | | $ | 0 | | |
Total | | $ | 1 | | | $ | 0 | | | $ | 0 | | |
Other derivative instruments | | | |
Commodity trading | | $ | 0 | | | $ | 0 | | | $ | 3 | | (b) |
Natural gas commodity | | 0 | | | (4) | | (c) | (3) | | (c) |
Total | | $ | 0 | | | $ | (4) | | | $ | 0 | | |
(a)Recorded to interest charges.
(b)Recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate.
(c)Amounts for the year ended Dec. 31, 2018, included $1 million of settlement losses on derivatives entered to mitigate natural gas price risk for electric generation recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset or liability, as appropriate. Remaining settlement losses for the years ended Dec. 31, 2018, relate to natural gas operations and are recorded to cost of natural gas sold and transported. These losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset or liability, as appropriate.
PSCo had 0 derivative instruments designated as fair value hedges during the years ended Dec. 31, 2020, 2019 and 2018.
Credit Related Contingent Features — Contract provisions for derivative instruments that PSCo enters into, including those accounted for as normal purchase-normalpurchase and normal sale contracts and therefore not reflected on the consolidated balance sheets, may require the posting of collateral or settlement of the contracts for various reasons, including if PSCo’s credit ratings are downgraded below its investment grade credit rating by any of the major credit rating agencies. AtAs of Dec. 31, 20202022 and 2019,2021, there were 0no derivative instruments in a liabilityliabilities position with such underlying contract provisions.
Certain contracts also contain cross default provisions that may require the posting of collateral or settlement of the contracts if there was a failure under the other financing arrangements related to payment terms or other covenants. As of Dec. 31, 2020,2022 there were approximately $46 million ofno derivative instruments in a liability position with such underlying contract provisions. As of Dec. 31, 2021, there were approximately $16 million of derivative liabilities position with such underlying contract provisions.
Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that PSCo’s ability to fulfill its contractual obligations is reasonably expected to be impaired. PSCo had 0no collateral posted related to adequate assurance clauses in derivative contracts as of Dec. 31, 20202022 and 2019.2021.
Recurring Derivative Fair Value Measurements
Impact of derivative activity:
| | | | | | | | | | | | | | |
| | Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: |
(Millions of Dollars) | | Accumulated Other Comprehensive Loss | | Regulatory (Assets) and Liabilities |
Year Ended Dec. 31, 2022 | | | | |
Other derivative instruments | | | | |
Natural gas commodity | | $ | — | | | $ | (15) | |
Total | | $ | — | | | $ | (15) | |
| | | | |
Year Ended Dec. 31, 2021 | | | | |
Other derivative instruments | | | | |
Natural gas commodity | | $ | — | | | $ | (1) | |
Total | | $ | — | | | $ | (1) | |
| | | | |
Year Ended Dec. 31, 2020 | | | | |
Other derivative instruments | | | | |
Natural gas commodity | | $ | — | | | $ | (10) | |
Total | | $ | — | | | $ | (10) | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | Pre-Tax (Gains) Losses Reclassified into Income During the Period from: | | | |
(Millions of Dollars) | | Accumulated Other Comprehensive Loss | | Regulatory Assets and (Liabilities) | | Pre-Tax Gains (Losses) Recognized During the Period in Income | |
Year Ended Dec. 31, 2022 | | | | | |
Derivatives designated as cash flow hedges | | | |
Interest rate | | $ | 1 | | (a) | $ | — | | | $ | — | | |
Total | | $ | 1 | | | $ | — | | | $ | — | | |
Other derivative instruments | | | |
Commodity trading | | $ | — | | | $ | — | | | $ | 7 | | (b) |
Natural gas commodity | | — | | | 8 | | (c) | (17) | | (c)(d) |
Total | | $ | — | | | $ | 8 | | | $ | (10) | | |
Year Ended Dec. 31, 2021 | | | | | |
Derivatives designated as cash flow hedges | | | |
Interest rate | | $ | 2 | | (a) | $ | — | | | $ | — | | |
Total | | $ | 2 | | | $ | — | | | $ | — | | |
Other derivative instruments | | | |
Commodity trading | | $ | — | | | $ | — | | | $ | 12 | | (b) |
Natural gas commodity | | — | | | 4 | | (c) | (15) | | (c)(d) |
Total | | $ | — | | | $ | 4 | | | $ | (3) | | |
Year Ended Dec. 31, 2020 | | | | | |
Derivatives designated as cash flow hedges | | | |
Interest rate | | $ | 1 | | (a) | $ | — | | | $ | — | | |
Total | | $ | 1 | | | $ | — | | | $ | — | | |
Other derivative instruments | | | |
Commodity trading | | $ | — | | | $ | — | | | $ | 3 | | (b) |
Natural gas commodity | | — | | | 8 | | (c) | (8) | | (c)(d) |
Total | | $ | — | | | $ | 8 | | | $ | (5) | | |
(a)Recorded to interest charges.
(b)Recorded to electric revenues. Presented amounts do not reflect non-derivative transactions or margin sharing with customers.
(c)Recorded to cost of natural gas sold and transported. These losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset, as appropriate.
(d)Relates primarily to option premium amortization.
PSCo had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2022, 2021 and 2020.
Recurring Fair Value Measurements— PSCo’s derivativeDerivative assets and liabilities measured at fair value on a recurring basis were as follows: | | | Dec. 31, 2020 | | Dec. 31, 2019 | | Dec. 31, 2022 | | Dec. 31, 2021 |
| | Fair Value | | Fair Value Total | | Netting (a) | | Total | | Fair Value | | Fair Value Total | | Netting (a) | | Total | | Fair Value | | Fair Value Total | | Netting (a) | | Total | | Fair Value | | Fair Value Total | | Netting (a) | | Total |
(Millions of Dollars) | (Millions of Dollars) | | Level 1 | | Level 2 | | Level 3 | | Level 1 | | Level 2 | | Level 3 | | (Millions of Dollars) | | Level 1 | | Level 2 | | Level 3 | | Level 1 | | Level 2 | | Level 3 | |
Current derivative assets | Current derivative assets | | | | | | | | | | | | | | | | | | | | | | | | | Current derivative assets | | | | | | | | | | | | | | | | | | | | | | | | |
Other derivative instruments: | Other derivative instruments: | | | Other derivative instruments: | | |
Commodity trading | Commodity trading | | $ | 1 | | | $ | 41 | | | $ | 1 | | | $ | 43 | | | $ | (28) | | | $ | 15 | | | $ | 2 | | | $ | 11 | | | $ | 1 | | | $ | 14 | | | $ | (10) | | | $ | 4 | | Commodity trading | | $ | 16 | | | $ | 220 | | | $ | 1 | | | $ | 237 | | | $ | (184) | | | $ | 53 | | | $ | 12 | | | $ | 97 | | | $ | — | | | $ | 109 | | | $ | (81) | | | $ | 28 | |
Natural gas commodity | Natural gas commodity | | 0 | | | 6 | | | 0 | | | 6 | | | 0 | | | 6 | | | 0 | | | 3 | | | 0 | | | 3 | | | 0 | | | 3 | | Natural gas commodity | | — | | | 12 | | | — | | | 12 | | | — | | | 12 | | | — | | | 11 | | | — | | | 11 | | | — | | | 11 | |
Total current derivative assets | Total current derivative assets | | $ | 1 | | | $ | 47 | | | $ | 1 | | | $ | 49 | | | $ | (28) | | | $ | 21 | | | $ | 2 | | | $ | 14 | | | $ | 1 | | | $ | 17 | | | $ | (10) | | | $ | 7 | | Total current derivative assets | | $ | 16 | | | $ | 232 | | | $ | 1 | | | $ | 249 | | | $ | (184) | | | $ | 65 | | | $ | 12 | | | $ | 108 | | | $ | — | | | $ | 120 | | | $ | (81) | | | $ | 39 | |
| Noncurrent derivative assets | Noncurrent derivative assets | | | | | | | | | | | | | | | | | | | | | | | | | Noncurrent derivative assets | | | | | | | | | | | | | | | | | | | | | | | | |
Other derivative instruments: | Other derivative instruments: | | | Other derivative instruments: | |
Commodity trading | Commodity trading | | $ | 1 | | | $ | 27 | | | $ | 8 | | | $ | 36 | | | $ | (20) | | | $ | 16 | | | $ | 1 | | | $ | 8 | | | $ | 1 | | | $ | 10 | | | $ | (10) | | | $ | 0 | | Commodity trading | | $ | 12 | | | $ | 32 | | | $ | 9 | | | $ | 53 | | | $ | (31) | | | $ | 22 | | | $ | 10 | | | $ | 28 | | | $ | 54 | | | $ | 92 | | | $ | (65) | | | $ | 27 | |
Total noncurrent derivative assets | Total noncurrent derivative assets | | $ | 1 | | | $ | 27 | | | $ | 8 | | | $ | 36 | | | $ | (20) | | | 16 | | | $ | 1 | | | $ | 8 | | | $ | 1 | | | $ | 10 | | | $ | (10) | | | $ | 0 | | Total noncurrent derivative assets | | $ | 12 | | | $ | 32 | | | $ | 9 | | | $ | 53 | | | $ | (31) | | | $ | 22 | | | $ | 10 | | | $ | 28 | | | $ | 54 | | | $ | 92 | | | $ | (65) | | | $ | 27 | |
| Current derivative liabilities | Current derivative liabilities | | | | | | | | | | | | | | | | | | | | | | | | | Current derivative liabilities | | | | | | | | | | | | | | | | | | | | | | | | |
Other derivative instruments: | Other derivative instruments: | | Other derivative instruments: | |
Commodity trading | Commodity trading | | $ | 1 | | | $ | 46 | | | $ | 7 | | | $ | 54 | | | $ | (33) | | | $ | 21 | | | $ | 2 | | | $ | 17 | | | $ | 0 | | | $ | 19 | | | $ | (13) | | | $ | 6 | | Commodity trading | | $ | 5 | | | $ | 237 | | | $ | 1 | | | $ | 243 | | | $ | (223) | | | $ | 20 | | | $ | 6 | | | $ | 90 | | | $ | 16 | | | $ | 112 | | | $ | (85) | | | $ | 27 | |
Natural gas commodity | Natural gas commodity | | 0 | | | 6 | | | 0 | | | 6 | | | 0 | | | 6 | | | 0 | | | 3 | | | 0 | | | 3 | | | 0 | | | 3 | | Natural gas commodity | | — | | | 10 | | | — | | | 10 | | | — | | | 10 | | | — | | | 3 | | | — | | | 3 | | | — | | | 3 | |
Total current derivative liabilities | Total current derivative liabilities | | $ | 1 | | | $ | 52 | | | $ | 7 | | | $ | 60 | | | $ | (33) | | | $ | 27 | | | $ | 2 | | | $ | 20 | | | $ | 0 | | | $ | 22 | | | $ | (13) | | | $ | 9 | | Total current derivative liabilities | | $ | 5 | | | $ | 247 | | | $ | 1 | | | $ | 253 | | | $ | (223) | | | $ | 30 | | | $ | 6 | | | $ | 93 | | | $ | 16 | | | $ | 115 | | | $ | (85) | | | $ | 30 | |
| Noncurrent derivative liabilities | Noncurrent derivative liabilities | | | | | | | | | | | | | | | | | | | | | | | | | Noncurrent derivative liabilities | | | | | | | | | | | | | | | | | | | | | | | | |
Other derivative instruments: | Other derivative instruments: | | Other derivative instruments: | |
Commodity trading | Commodity trading | | $ | 1 | | | $ | 24 | | | $ | 46 | | | $ | 71 | | | $ | (20) | | | $ | 51 | | | $ | 1 | | | $ | 47 | | | $ | 15 | | | $ | 63 | | | $ | (10) | | | $ | 53 | | Commodity trading | | $ | 7 | | | $ | 40 | | | $ | — | | | $ | 47 | | | $ | (38) | | | $ | 9 | | | $ | 3 | | | $ | — | | | $ | 101 | | | $ | 104 | | | $ | (75) | | | $ | 29 | |
Total noncurrent derivative liabilities | Total noncurrent derivative liabilities | | $ | 1 | | | $ | 24 | | | $ | 46 | | | $ | 71 | | | $ | (20) | | | $ | 51 | | | $ | 1 | | | $ | 47 | | | $ | 15 | | | $ | 63 | | | $ | (10) | | | $ | 53 | | Total noncurrent derivative liabilities | | $ | 7 | | | $ | 40 | | | $ | — | | | $ | 47 | | | $ | (38) | | | $ | 9 | | | $ | 3 | | | $ | — | | | $ | 101 | | | $ | 104 | | | $ | (75) | | | $ | 29 | |
|
(a)PSCo nets derivative instruments and related collateral on its consolidated balance sheetsheets when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2020 and 2019.agreement. At Dec. 31, 20202022 and 2019,2021, derivative assets and liabilities include 0no obligations to return cash collateral, respectively.collateral. At Dec. 31, 20202022 and 2019,2021, derivative assets and liabilities include rights to reclaim cash collateral of $5$46 million and $3$14 million, respectively. The counterpartyCounterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.
Changes in Level 3 commodity derivatives for the years ended Dec. 31, 2020, 2019 and 2018:derivatives:
| | | Year Ended Dec. 31 | | Year Ended Dec. 31 |
(Millions of Dollars) | (Millions of Dollars) | | 2020 | | 2019 | | 2018 | (Millions of Dollars) | | 2022 | | 2021 | | 2020 |
Balance at Jan. 1 | Balance at Jan. 1 | | $ | (13) | | | $ | 0 | | | $ | 0 | | Balance at Jan. 1 | | $ | (63) | | | $ | (44) | | | 13 |
| Settlements(a) | Settlements(a) | | 0 | | | (2) | | | 0 | | Settlements(a) | | 12 | | | 4 | | | — | |
Net transactions recorded during the period: | Net transactions recorded during the period: | | Net transactions recorded during the period: | |
Losses recognized in earnings (a) | | (31) | | | (11) | | | 0 | | |
Gains (losses) recognized in earnings (a) | | Gains (losses) recognized in earnings (a) | | 60 | | | (23) | | | (31) | |
| Balance at Dec. 31 | Balance at Dec. 31 | | $ | (44) | | | $ | (13) | | | $ | 0 | | Balance at Dec. 31 | | $ | 9 | | | $ | (63) | | | $ | (44) | |
(a)Level 3 losses recognized in earnings areRelates to commodity trading and is subject to substantial offsetting losses and gains ofon derivative instruments categorized as levels 1 and 2 in the income statement.
PSCo recognizes transfers between levels as of the beginning of each period. There were 0 transfers of amounts between levels for derivative instruments See above tables for the years ended Dec. 31, 2020, 2019income statement impact of derivative activity, including commodity trading gains and 2018.losses.
Fair Value of Long-Term Debt
As of Dec. 31, other financial instruments for which the carrying amount did not equal fair value:
| | | 2020 | | 2019 | | 2022 | | 2021 |
(Millions of Dollars) | (Millions of Dollars) | | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value | (Millions of Dollars) | | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value |
Long-term debt, including current portion | Long-term debt, including current portion | | $ | 5,724 | | | $ | 7,040 | | | $ | 5,385 | | | $ | 6,039 | | Long-term debt, including current portion | | $ | 6,860 | | | $ | 5,881 | | | $ | 6,467 | | | $ | 7,291 | |
Fair value of PSCo’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. Fair value estimates are based on information available to management as of Dec. 31, 20202022 and 2019,2021, and given the observability of the inputs, fair values presented for long-term debt were assigned as Level 2.
| | |
9. Benefit Plans and Other Postretirement Benefits |
Pension and Postretirement Health Care Benefits
Xcel Energy, which includes PSCo, has several noncontributory, qualified, defined benefit pension plans that cover almost all employees. All newly hired or rehired employees participate under the Cash Balance formula, which is based on pay credits using a percentage of annual eligible pay and annual interest credits. The average annual interest crediting rates for these plans was 2.24, 3.115.14, 2.26 and 3.862.24 percent in 2020, 2019,2022, 2021, and 2018,2020, respectively. Some employees may participate under legacy formulas such as the traditional final average pay or pension equity. Xcel Energy’s policy is to fully fund into an external trust the actuarially determined pension costs recognized for ratemaking and financial reporting purposes, subject to the limitations of applicable employee benefit and tax laws.
In addition to the qualified pension plans, Xcel Energy maintains a SERP and a nonqualified pension plan. The SERP is maintained for certain executives who participated in the plan in 2008, when the SERP was closed to new participants. The nonqualified pension plan provides benefits for compensation that is in excess of the limits applicable to the qualified pension plans, with distributions funded by Xcel Energy’s consolidated operating cash flows.
Obligations of the SERP and nonqualified plan as of Dec. 31, 20202022 and 20192021 were $43$11 million and $39$43 million, respectively, of which $2$1 million and $3$2 million was attributable to PSCo in 20202022 and 2019,2021, respectively. Xcel Energy recognized net benefit cost for financial reporting for the SERP and nonqualified plans of $6$17 million in 20202022 and $4 million in 2019,2021, respectively, of which immaterial amounts were attributable to PSCo.
Xcel Energy, which includes PSCo, basesInvestment-return assumption considers the investment-return assumption on expected long-term performance for each of the asset classes in its pension and postretirement health care portfolios. For pension assets,portfolio. Xcel Energy considers the historical returns achieved by its asset portfolioportfolios over the past 20-years or longer period,long time periods, as well as the long-term projected return levels projected and recommended by investment experts. Xcel Energy Inc. and PSCo continually review pension assumptions.
Pension cost determination assumes a forecasted mix of investment types over the long-term.
•Investment returns in 2022 were below the assumed level of 6.39%.
•Investment returns in 2021 were above the assumed level of 6.38%.
•Investment returns in 2020 were above the assumed level of 6.84%.
•Investment returns in 2019 were above the assumed level of 6.84%.
•Investment returns in 2018 were below the assumed level of 6.84%.
•In 2021,2023, PSCo’s expected investment-return assumption is 6.38%6.53%.
Pension plan and postretirement benefit assets are invested in a portfolio according to Xcel Energy’s return, liquidity and diversification objectives to provide a source of funding for plan obligations and minimize contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the asset allocation given the long-term risk, return, correlation and liquidity characteristics of each particular asset class.
There were no significant concentrations of risk in any industry, index, or entity. Market volatility can impact even well-diversified portfolios and significantly affect the return levels achieved by the assets in any year.
State agencies also have issued guidelines to the funding of postretirement benefit costs. PSCo is required to fund postretirement benefit costs in irrevocable external trusts that are dedicated to the payment of these postretirement benefits. These assets are invested in a manner consistent with the investment strategy for the pension plan.
Xcel Energy’s ongoing investment strategy is based on plan-specific investment recommendations that seek to minimize potential investment and interest rate risk as a plan’s funded status increases over time.
The investment recommendations consider many factors and generally result in a greater percentage of long-duration fixed income securities being allocated to specific plans having relatively higher funded status ratios and a greater percentage of growth assets being allocated to plans having relatively lower funded status ratios.
Plan Assets
For each of the fair value hierarchy levels, PSCo’s pension plan assets measured at fair value:
| | | Dec. 31, 2020 (a) | | Dec. 31, 2019 (a) | | Dec. 31, 2022 (a) | | Dec. 31, 2021 (a) |
(Millions of Dollars) | (Millions of Dollars) | | Level 1 | | Level 2 | | Level 3 | | Measured at NAV | | Total | | Level 1 | | Level 2 | | Level 3 | | Measured at NAV | | Total | (Millions of Dollars) | | Level 1 | | Level 2 | | Level 3 | | Measured at NAV | | Total | | Level 1 | | Level 2 | | Level 3 | | Measured at NAV | | Total |
Cash equivalents | Cash equivalents | | $ | 75 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 75 | | | $ | 46 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 46 | | Cash equivalents | | $ | 52 | | | $ | — | | | $ | — | | | $ | — | | | $ | 52 | | | $ | 49 | | | $ | — | | | $ | — | | | $ | — | | | $ | 49 | |
Commingled funds | Commingled funds | | 518 | | | 0 | | | 0 | | | 388 | | | 906 | | | 497 | | | 0 | | | 0 | | | 355 | | | 852 | | Commingled funds | | 355 | | | — | | | — | | | 317 | | | 672 | | | 492 | | | — | | | — | | | 409 | | | 901 | |
Debt securities | Debt securities | | 0 | | | 270 | | | 1 | | | 0 | | | 271 | | | 0 | | | 241 | | | 2 | | | 0 | | | 243 | | Debt securities | | — | | | 286 | | | 1 | | | — | | | 287 | | | — | | | 360 | | | 2 | | | — | | | 362 | |
Equity securities | Equity securities | | 27 | | | 0 | | | 0 | | | 0 | | | 27 | | | 30 | | | 0 | | | 0 | | | 0 | | | 30 | | Equity securities | | 17 | | | — | | | — | | | — | | | 17 | | | 24 | | | — | | | — | | | — | | | 24 | |
Other | Other | | 2 | | | 2 | | | 0 | | | 0 | | | 4 | | | (41) | | | 1 | | | 0 | | | (7) | | | (47) | | Other | | — | | | 3 | | | — | | | — | | | 3 | | | — | | | 3 | | | — | | | 12 | | | 15 | |
Total | Total | | $ | 622 | | | $ | 272 | | | $ | 1 | | | $ | 388 | | | $ | 1,283 | | | $ | 532 | | | $ | 242 | | | $ | 2 | | | $ | 348 | | | $ | 1,124 | | Total | | $ | 424 | | | $ | 289 | | | $ | 1 | | | $ | 317 | | | $ | 1,031 | | | $ | 565 | | | $ | 363 | | | $ | 2 | | | $ | 421 | | | $ | 1,351 | |
(a)See Note 8 for further information on fair value measurement inputs and methods.
For each of the fair value hierarchy levels, PSCo’s proportionate allocation of the total postretirement benefit plan assets that were measured at fair value:
| | | Dec. 31, 2020 (a) | | Dec. 31, 2019 (a) | | Dec. 31, 2022 (a) | | Dec. 31, 2021 (a) |
(Millions of Dollars) | (Millions of Dollars) | | Level 1 | | Level 2 | | Level 3 | | Measured at NAV | | Total | | Level 1 | | Level 2 | | Level 3 | | Measured at NAV | | Total | (Millions of Dollars) | | Level 1 | | Level 2 | | Level 3 | | Measured at NAV | | Total | | Level 1 | | Level 2 | | Level 3 | | Measured at NAV | | Total |
Cash equivalents | Cash equivalents | | $ | 24 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 24 | | | $ | 20 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 20 | | Cash equivalents | | $ | 28 | | | $ | — | | | $ | — | | | $ | — | | | $ | 28 | | | $ | 25 | | | $ | — | | | $ | — | | | $ | — | | | $ | 25 | |
Insurance contracts | Insurance contracts | | 0 | | | 45 | | | 0 | | | 0 | | | 45 | | | 0 | | | 45 | | | 0 | | | 0 | | | 45 | | Insurance contracts | | — | | | 36 | | | — | | | — | | | 36 | | | — | | | 46 | | | — | | | — | | | 46 | |
Commingled funds | Commingled funds | | 64 | | | 0 | | | 0 | | | 61 | | | 125 | | | 62 | | | 0 | | | 0 | | | 68 | | | 130 | | Commingled funds | | 47 | | | — | | | — | | | 56 | | | 103 | | | 57 | | | — | | | — | | | 68 | | | 125 | |
Debt securities | Debt securities | | 0 | | | 207 | | | 0 | | | 0 | | | 207 | | | 0 | | | 203 | | | 1 | | | 0 | | | 204 | | Debt securities | | — | | | 153 | | | 1 | | | — | | | 154 | | | — | | | 194 | | | 1 | | | — | | | 195 | |
Other | Other | | 0 | | | 3 | | | 0 | | | 0 | | | 3 | | | 0 | | | 2 | | | 0 | | | 0 | | | 2 | | Other | | — | | | (1) | | | — | | | — | | | (1) | | | — | | | 2 | | | — | | | — | | | 2 | |
Total | Total | | $ | 88 | | | $ | 255 | | | $ | 0 | | | $ | 61 | | | $ | 404 | | | $ | 82 | | | $ | 250 | | | $ | 1 | | | $ | 68 | | | $ | 401 | | Total | | $ | 75 | | | $ | 188 | | | $ | 1 | | | $ | 56 | | | $ | 320 | | | $ | 82 | | | $ | 242 | | | $ | 1 | | | $ | 68 | | | $ | 393 | |
(a)See Note 8 for further information on fair value measurement inputs and methods.
Immaterial assets were transferred in or out of Level 3 for 2022. No assets were transferred in or out of Level 3 for 2020. Immaterial assets were transferred in or out of Level 3 for 2019.2021.
Funded Status — Benefit obligations for both pension and postretirement plans increaseddecreased from Dec. 31, 20192021 to Dec. 31, 2020,2022, due primarily to decreasesbenefit payments and increases in discount rates used in actuarial valuations. Comparisons of the actuarially computed benefit obligation, changes in plan assets and funded status of the pension and postretirement health care plans for PSCo are as follows:
| | | Pension Benefits | | Postretirement Benefits | | Pension Benefits | | Postretirement Benefits |
(Millions of Dollars) | (Millions of Dollars) | | 2020 | | 2019 | | 2020 | | 2019 | (Millions of Dollars) | | 2022 | | 2021 | | 2022 | | 2021 |
Change in Benefit Obligation: | Change in Benefit Obligation: | | | | | | | | | Change in Benefit Obligation: | | | | | | | | |
Obligation at Jan. 1 | Obligation at Jan. 1 | | $ | 1,330 | | | $ | 1,229 | | | $ | 380 | | | $ | 377 | | Obligation at Jan. 1 | | $ | 1,363 | | | $ | 1,428 | | | $ | 369 | | | $ | 415 | |
Service cost | Service cost | | 30 | | | 26 | | | 1 | | | 1 | | Service cost | | 29 | | | 32 | | | 1 | | | 1 | |
Interest cost | Interest cost | | 46 | | | 52 | | | 13 | | | 16 | | Interest cost | | 41 | | | 39 | | | 10 | | | 11 | |
Plan amendments | | 0 | | | 0 | | | 0 | | | 0 | | |
Actuarial loss | | 102 | | | 108 | | | 52 | | | 12 | | |
| Actuarial gain | | Actuarial gain | | (317) | | | (57) | | | (55) | | | (31) | |
Plan participants’ contributions | Plan participants’ contributions | | 0 | | | 0 | | | 6 | | | 7 | | Plan participants’ contributions | | — | | | — | | | 7 | | | 7 | |
Medicare subsidy reimbursements | Medicare subsidy reimbursements | | 0 | | | 0 | | | 1 | | | 1 | | Medicare subsidy reimbursements | | — | | | — | | | 1 | | | 2 | |
Benefit payments | Benefit payments | | (80) | | | (85) | | | (38) | | | (34) | | Benefit payments | | (84) | | | (79) | | | (37) | | | (36) | |
Obligation at Dec. 31 | Obligation at Dec. 31 | | $ | 1,428 | | | $ | 1,330 | | | $ | 415 | | | $ | 380 | | Obligation at Dec. 31 | | $ | 1,032 | | | $ | 1,363 | | | $ | 296 | | | $ | 369 | |
Change in Fair Value of Plan Assets: | Change in Fair Value of Plan Assets: | | | | | | | | | Change in Fair Value of Plan Assets: | | | | | | | | |
Fair value of plan assets at Jan. 1 | Fair value of plan assets at Jan. 1 | | $ | 1,124 | | | $ | 966 | | | $ | 401 | | | $ | 372 | | Fair value of plan assets at Jan. 1 | | $ | 1,351 | | | $ | 1,283 | | | $ | 393 | | | $ | 404 | |
Actual return on plan assets | Actual return on plan assets | | 189 | | | 197 | | | 32 | | | 52 | | Actual return on plan assets | | (276) | | | 102 | | | (46) | | | 15 | |
Employer contributions | Employer contributions | | 50 | | | 46 | | | 3 | | | 4 | | Employer contributions | | 40 | | | 45 | | | 3 | | | 3 | |
Plan participants’ contributions | Plan participants’ contributions | | 0 | | | 0 | | | 6 | | | 7 | | Plan participants’ contributions | | — | | | — | | | 7 | | | 7 | |
Benefit payments | Benefit payments | | (80) | | | (85) | | | (38) | | | (34) | | Benefit payments | | (84) | | | (79) | | | (37) | | | (36) | |
Fair value of plan assets at Dec. 31 | Fair value of plan assets at Dec. 31 | | $ | 1,283 | | | $ | 1,124 | | | $ | 404 | | | $ | 401 | | Fair value of plan assets at Dec. 31 | | $ | 1,031 | | | $ | 1,351 | | | $ | 320 | | | $ | 393 | |
Funded status of plans at Dec. 31 | Funded status of plans at Dec. 31 | | $ | (145) | | | $ | (206) | | | $ | (11) | | | $ | 21 | | Funded status of plans at Dec. 31 | | $ | (1) | | | $ | (12) | | | $ | 24 | | | $ | 24 | |
Amounts recognized in the Consolidated Balance Sheet at Dec. 31: | Amounts recognized in the Consolidated Balance Sheet at Dec. 31: | | | | | | | | | Amounts recognized in the Consolidated Balance Sheet at Dec. 31: | | | | | | | | |
Noncurrent assets | | Noncurrent assets | | 8 | | | 6 | | | 24 | | | 24 | |
Noncurrent liabilities | Noncurrent liabilities | | (145) | | | (206) | | | (11) | | | 21 | | Noncurrent liabilities | | (9) | | | (18) | | | — | | | — | |
Net amounts recognized | Net amounts recognized | | $ | (145) | | | $ | (206) | | | $ | (11) | | | $ | 21 | | Net amounts recognized | | $ | (1) | | | $ | (12) | | | $ | 24 | | | $ | 24 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | Postretirement Benefits |
Significant Assumptions Used to Measure Benefit Obligations: | | 2022 | | 2021 | | 2022 | | 2021 |
Discount rate for year-end valuation | | 5.80 | % | | 3.08 | % | | 5.80 | % | | 3.09 | % |
Expected average long-term increase in compensation level | | 4.25 | % | | 3.75 | % | | N/A | | N/A |
Mortality table | | Pri-2012 | | Pri-2012 | | Pri-2012 | | Pri-2012 |
Health care costs trend rate — initial: Pre-65 | | N/A | | N/A | | 6.50 | % | | 5.30 | % |
Health care costs trend rate — initial: Post-65 | | N/A | | N/A | | 5.50 | % | | 4.90 | % |
Ultimate trend assumption — initial: Pre-65 | | N/A | | N/A | | 4.50 | % | | 4.50 | % |
Ultimate trend assumption — initial: Post-65 | | N/A | | N/A | | 4.50 | % | | 4.50 | % |
Years until ultimate trend is reached | | N/A | | N/A | | 7 | | 4 |
Accumulated benefit obligation for the pension plan was $1,353$992 million and $1,267$1,291 million as of Dec. 31, 20202022 and 2019,2021, respectively.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | Postretirement Benefits |
Significant Assumptions Used to Measure Benefit Obligations: | | 2020 | | 2019 | | 2020 | | 2019 |
Discount rate for year-end valuation | | 2.71 | % | | 3.49 | % | | 2.65 | % | | 3.47 | % |
Expected average long-term increase in compensation level | | 3.75 | % | | 3.75 | % | | N/A | | N/A |
Mortality table | | Pri-2012 | | Pri-2012 | | Pri-2012 | | Pri-2012 |
Health care costs trend rate — initial: Pre-65 | | N/A | | N/A | | 5.50 | % | | 6.00 | % |
Health care costs trend rate — initial: Post-65 | | N/A | | N/A | | 5.00 | % | | 5.10 | % |
Ultimate trend assumption — initial: Pre-65 | | N/A | | N/A | | 4.50 | % | | 4.50 | % |
Ultimate trend assumption — initial: Post-65 | | N/A | | N/A | | 4.50 | % | | 4.50 | % |
Years until ultimate trend is reached | | N/A | | N/A | | 5 | | 3 |
Net Periodic Benefit Cost (Credit) — Net periodic benefit cost (credit), other than the service cost component, is included in other income (expense) income in the statements of income.
Components of net periodic benefit cost (credit) and amounts recognized in other comprehensive income and regulatory assets and liabilities:
| | | Pension Benefits | | Postretirement Benefits | | Pension Benefits | | Postretirement Benefits |
(Millions of Dollars) | (Millions of Dollars) | | 2020 | | 2019 | | 2018 | | 2020 | | 2019 | | 2018 | (Millions of Dollars) | | 2022 | | 2021 | | 2020 | | 2022 | | 2021 | | 2020 |
Service cost | Service cost | | $ | 30 | | | $ | 26 | | | $ | 29 | | | $ | 0 | | | $ | 1 | | | $ | 1 | | Service cost | | $ | 29 | | | $ | 32 | | | $ | 30 | | | $ | 1 | | | $ | 1 | | | $ | — | |
Interest cost | Interest cost | | 46 | | | 52 | | | 47 | | | 13 | | | 15 | | | 15 | | Interest cost | | 41 | | | 39 | | | 46 | | | 10 | | | 11 | | | 13 | |
Expected return on plan assets | Expected return on plan assets | | (70) | | | (69) | | | (69) | | | (17) | | | (19) | | | (23) | | Expected return on plan assets | | (78) | | | (73) | | | (70) | | | (15) | | | (16) | | | (17) | |
Amortization of prior service credit | Amortization of prior service credit | | (3) | | | (3) | | | (3) | | | (4) | | | (5) | | | (6) | | Amortization of prior service credit | | — | | | — | | | (3) | | | (2) | | | (4) | | | (4) | |
Amortization of net loss | Amortization of net loss | | 30 | | | 25 | | | 31 | | | 1 | | | 3 | | | 4 | | Amortization of net loss | | 23 | | | 32 | | | 30 | | | 1 | | | 3 | | | 1 | |
Settlement charge (a) | Settlement charge (a) | | 0 | | | 3 | | | 5 | | | 0 | | | 0 | | | 0 | | Settlement charge (a) | | 3 | | | — | | | — | | | — | | | — | | | — | |
Net periodic pension cost (credit) | Net periodic pension cost (credit) | | 33 | | | 34 | | | 40 | | | (7) | | | (5) | | | (9) | | Net periodic pension cost (credit) | | 18 | | | 30 | | | 33 | | | (5) | | | (5) | | | (7) | |
Effects of regulation | Effects of regulation | | 4 | | | 4 | | | (4) | | | 3 | | | 1 | | | 2 | | Effects of regulation | | 4 | | | — | | | 4 | | | 3 | | | 2 | | | 3 | |
Net benefit cost (credit) recognized for financial reporting | Net benefit cost (credit) recognized for financial reporting | | $ | 37 | | | $ | 38 | | | $ | 36 | | | $ | (4) | | | $ | (4) | | | $ | (7) | | Net benefit cost (credit) recognized for financial reporting | | $ | 22 | | | $ | 30 | | | $ | 37 | | | $ | (2) | | | $ | (3) | | | $ | (4) | |
Significant Assumptions Used to Measure Costs: | Significant Assumptions Used to Measure Costs: | | | | | | | | | | | | | Significant Assumptions Used to Measure Costs: | | | | | | | | | | |
Discount rate | Discount rate | | 3.49 | % | | 4.31 | % | | 3.63 | % | | 3.47 | % | | 4.32 | % | | 3.62 | % | Discount rate | | 3.08 | % | | 2.71 | % | | 3.49 | % | | 3.09 | % | | 2.65 | % | | 3.47 | % |
Expected average long-term increase in compensation level | Expected average long-term increase in compensation level | | 3.75 | | | 3.75 | | | 3.75 | | | N/A | | N/A | | N/A | Expected average long-term increase in compensation level | | 3.75 | | | 3.75 | | | 3.75 | | | N/A | | N/A | | N/A |
Expected average long-term rate of return on assets | Expected average long-term rate of return on assets | | 6.84 | | | 6.84 | | | 6.84 | | | 4.50 | | | 4.50 | | | 5.30 | | Expected average long-term rate of return on assets | | 6.39 | | | 6.38 | | | 6.84 | | | 4.10 | | | 4.10 | | | 4.50 | |
(a)A settlement charge is required when the amount of all lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In 2019 and 2018,2022, as a result of lump-sum distributions during eachthe plan year, PSCo recorded a total pension settlement charge of $3 million and $5 million, respectively.million. An immaterial amount was recorded in the income statement in 2019 and 2018.2022. There were no settlement charges recorded to the qualified pension plans in 2021 or 2020.
| | | Pension Benefits | | Postretirement Benefits | | Pension Benefits | | Postretirement Benefits |
(Millions of Dollars) | (Millions of Dollars) | | 2020 | | 2019 | | 2020 | | 2019 | (Millions of Dollars) | | 2022 | | 2021 | | 2022 | | 2021 |
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: | Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: | | | | | | | | | Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: | | | | | | | | |
Net loss | Net loss | | $ | 432 | | | $ | 482 | | | $ | 81 | | | $ | 45 | | Net loss | | $ | 325 | | | $ | 313 | | | $ | 53 | | | $ | 48 | |
Prior service credit | Prior service credit | | (1) | | | (4) | | | (6) | | | (10) | | Prior service credit | | (1) | | | (1) | | | — | | | (2) | |
Total | Total | | $ | 431 | | | $ | 478 | | | $ | 75 | | | $ | 35 | | Total | | $ | 324 | | | $ | 312 | | | $ | 53 | | | $ | 46 | |
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates: | Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates: | | | | | | | | | Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates: | | | | |
Current regulatory assets | Current regulatory assets | | $ | 25 | | | $ | 22 | | | $ | 0 | | | $ | 0 | | Current regulatory assets | | $ | 3 | | | $ | 24 | | | $ | — | | | $ | — | |
Noncurrent regulatory assets | Noncurrent regulatory assets | | 404 | | | 452 | | | 75 | | | 35 | | Noncurrent regulatory assets | | 320 | | | 288 | | | 53 | | | 46 | |
Deferred income taxes | | 1 | | | 1 | | | 0 | | | 0 | | |
| Net-of-tax accumulated other comprehensive income | Net-of-tax accumulated other comprehensive income | | 1 | | | 3 | | | 0 | | | 0 | | Net-of-tax accumulated other comprehensive income | | 1 | | | — | | | — | | | — | |
Total | Total | | $ | 431 | | | $ | 478 | | | $ | 75 | | | $ | 35 | | Total | | $ | 324 | | | $ | 312 | | | $ | 53 | | | $ | 46 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Measurement date | | Dec. 31, 20202022 | | Dec. 31, 20192021 | | Dec. 31, 20202022 | | Dec. 31, 20192021 |
Cash Flows — Funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other calculations prescribed by the requirements of income tax and other pension-related regulations. Required contributions were made in 20182020 —- 20212023 to meet minimum funding requirements. Total voluntary and required pension funding contributions across all 4four of Xcel Energy’s pension plans were as follows:
•$12550 million in January 2023, of which none was attributable to PSCo.
•$50 million in 2022, of which $40 million was attributable to PSCo.
•$131 million in 2021, of which $45$46 million was attributable to PSCo.
•$150 million in 2020, of which $50 million was attributable to PSCo.
•$154 million in 2019, of which $46 million was attributable to PSCo.
•$150 million in 2018, of which $22 million was attributable to PSCo.
The postretirement health care plans have no funding requirements other than fulfilling benefit payment obligations when claims are presented and approved. Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities.
Xcel Energy’s voluntary postretirement funding contributions were as follows:
•$1012 million expected in January 2021,2023, of which an immaterial amount$3 million is attributable to PSCo.
•$1113 million during 2020,2022, of which $3 million was attributable to PSCo.
•$15 million during 2019,2021, of which $4$3 million was attributable to PSCo.
•$11 million during 2018,2020, of which $5$3 million was attributable to PSCo.
Targeted asset allocations:
| | | Pension Benefits | | Postretirement Benefits | | Pension Benefits | | Postretirement Benefits |
| | | 2020 | | 2019 | | 2020 | | 2019 | | | 2022 | | 2021 | | 2022 | | 2021 |
Domestic and international equity securities | Domestic and international equity securities | | 35 | % | | 37 | % | | 15 | % | | 15 | % | Domestic and international equity securities | | 33 | % | | 33 | % | | 16 | % | | 15 | % |
Long-duration fixed income securities | Long-duration fixed income securities | | 35 | | | 30 | | | 0 | | | 0 | | Long-duration fixed income securities | | 38 | | | 37 | | | — | | | — | |
Short-to-intermediate fixed income securities | Short-to-intermediate fixed income securities | | 13 | | | 14 | | | 72 | | | 72 | | Short-to-intermediate fixed income securities | | 9 | | | 11 | | | 71 | | | 71 | |
Alternative investments | Alternative investments | | 15 | | | 17 | | | 9 | | | 9 | | Alternative investments | | 18 | | | 17 | | | 12 | | | 8 | |
Cash | Cash | | 2 | | | 2 | | | 4 | | | 4 | | Cash | | 2 | | | 2 | | | 1 | | | 6 | |
Total | Total | | 100 | % | | 100 | % | | 100 | % | | 100 | % | Total | | 100 | % | | 100 | % | | 100 | % | | 100 | % |
The asset allocations above reflect target allocations approved in the calendar year to take effect in the subsequent year
Plan Amendments —In 2018, the PSCo postretirement plan was amended to add the 5% cash balance formula.
In 2020 and 2019, there wereThere was no significant plan amendments made in 2022 or 2020 which affected the projected benefit obligation.
In 2021, Xcel Energy amended the Xcel Energy Pension Plan and Xcel Energy Inc. Nonbargaining Pension Plan (South) to reduce supplemental benefits for non-bargaining participants as well as to allow the transfer of a portion of non-qualified pension obligations into the qualified plans.
Projected Benefit Payments
PSCo’s projected benefit payments:
| (Millions of Dollars) | (Millions of Dollars) | | Projected Pension Benefit Payments | | Gross Projected Postretirement Health Care Benefit Payments | | Expected Medicare Part D Subsidies | | Net Projected Postretirement Health Care Benefit Payments | (Millions of Dollars) | | Projected Pension Benefit Payments | | Gross Projected Postretirement Health Care Benefit Payments | | Expected Medicare Part D Subsidies | | Net Projected Postretirement Health Care Benefit Payments |
2021 | | $ | 83 | | | $ | 31 | | | $ | 2 | | | $ | 29 | | |
2022 | | 83 | | | 31 | | | 2 | | | 29 | | |
2023 | 2023 | | 82 | | | 30 | | | 2 | | | 28 | | 2023 | | $ | 82 | | | $ | 31 | | | $ | 2 | | | $ | 29 | |
2024 | 2024 | | 82 | | | 30 | | | 2 | | | 28 | | 2024 | | 82 | | | 30 | | | 2 | | | 28 | |
2025 | 2025 | | 82 | | | 29 | | | 2 | | | 27 | | 2025 | | 82 | | | 29 | | | 2 | | | 27 | |
2026-2030 | | 393 | | | 130 | | | 12 | | | 118 | | |
2026 | | 2026 | | 82 | | | 29 | | | 2 | | | 27 | |
2027 | | 2027 | | 81 | | | 28 | | | 2 | | | 26 | |
2028-2032 | | 2028-2032 | | 388 | | | 124 | | | 11 | | | 113 | |
Defined Contribution Plans
Xcel Energy, which includes PSCo, maintains 401(k) and other defined contribution plans that cover most employees. Total expense to these plans for PSCo was approximately $12 million in 20202022, 2021 and $11 million in 2019 and 2018.2020.
| | |
10. Commitments and Contingencies |
Legal
PSCo is involved in various litigation matters in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for losses probable of being incurred and subject to reasonable estimation.
Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories.
In such cases, there is considerable uncertainty regarding the timing or ultimate resolution, of such matters, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, would have a material effect on PSCo’s consolidated financial statements. Unless otherwise required by GAAP, legalLegal fees are generally expensed as incurred.
Gas TradingComanche Unit 3 Litigation — e primeIn 2021, CORE filed a lawsuit in Denver County District Court, alleging PSCo breached ownership agreement terms by failing to operate Comanche Unit 3 in accordance with prudent utility practices. In January 2022, the Court granted PSCo’s motion to dismiss CORE’s claims for unjust enrichment, declaratory judgment and damages for replacement power costs. In April 2022, CORE filed a supplement to include the January 2022 outage and damages related to this event. Also in 2022, CORE sent notice of withdrawal from the ownership agreement based on the same alleged breaches. In February 2023, CORE disclosed its expert witness, who estimated damages incurred of $270 million. Also in February 2023, the court granted PSCo’s motion precluding CORE from seeking damages related to its withdrawal as part of the lawsuit. PSCo continues to believe CORE's claims are without merit and disputes CORE’s right to withdraw.
Rate Matters
PSCo is a wholly owned subsidiary of Xcel Energy. e prime wasinvolved in various regulatory proceedings arising in the businessordinary course of natural gas trading and marketing but has not engaged in natural gas trading or marketing activities since 2003. Multiple lawsuits involving multiple plaintiffs seeking monetary damages were commenced against e prime and its affiliates, including Xcel Energy, between 2003 and 2009 alleging fraud and anticompetitive activities in conspiring to restrain the trade of natural gas and manipulate natural gas prices. Cases were all consolidatedbusiness. Until resolution, typically in the U.S. District Court in Nevada.
NaN cases remain active which include an MDL matter consistingform of a Colorado purported class (Breckenridge)rate order, uncertainties may exist regarding the ultimate rate treatment for certain activities and transactions. Amounts have been recognized for probable and reasonably estimable losses that may result. Unless otherwise disclosed, any reasonably possible range of loss in excess of any recognized amount is not expected to have a Wisconsin purported class (Arandell Corp.).
Breckenridge/Colorado — In February 2019,material effect on the MDL panel remanded Breckenridge back to the U.S. District Court in Colorado. In December 2020, a settlement in principle was reached for approximately $3 million. The parties have sought and are awaiting court approval of settlement.
Arandell Corp. — In February 2019, the case was remanded back to the U.S. District Court in Wisconsin.
Xcel Energy has concluded that a loss is remote for the remaining lawsuit.consolidated financial statements.
Environmental
New and changing federal and state environmental mandates can create financial liabilities for PSCo, which are normally recovered through the regulated rate process.
Site Remediation
Various federal and state environmental laws impose liability where hazardous substances or other regulated materials have been released to the environment. PSCo may sometimes pay all or a portion of the cost to remediate sites where past activities of PSCo’s predecessors or other parties have caused environmental contamination. Environmental contingencies could arise from various situations, including sites of former MGPs; and third-party sites, such as landfills, for which PSCo is alleged to have sent wastes to that site.
Historical MGP, Landfill and Disposal Sites
PSCo is currently investigating, remediating or performing post-closure actions at 3two historical MGP, landfill or other disposal sites across its service territory.territory, excluding sites that are being addressed under current coal ash regulations (see below).
PSCo has recognized its best estimate of costs/liabilities that will result from final resolution of these issues,issues; however, the outcome and timing isare unknown. In addition, there may be insurance recovery and/or recovery from other potentially responsible parties, offsetting a portion of costs incurred.
Environmental Requirements — Water and Waste
Coal Ash Regulation — PSCo’s operations are subject to federal and state regulations that impose requirements for handling, storage, treatment and disposal of solid waste.Under the CCR Rule, utilities are required to complete groundwater sampling around their CCRapplicable landfills and surface impoundments. Currently,impoundments as well as perform corrective actions where offsite groundwater has been impacted.
As of Dec. 31, 2022, PSCo has 6five regulated ash units in operation.
PSCo is conducting groundwater samplingcurrently exploring an agreement with a third party that would excavate and monitoringprocess ash for beneficial use (at two sites) and implementing assessment of corrective measuresperform restoration at certain CCR landfills and surface impoundments. Increases above background concentrations were detectedone site at 4 locations.
Subsequently, assessment monitoring samples were collected at these locations. As a result, PSCo is evaluating options for corrective action at 2 locations, 1 of which indicates potential offsite impacts to groundwater. Until PSCo completes its assessments, it is uncertain what impact, if any, there will be on the operations, financial condition or cash flows.
In August 2020, the EPA published its final rule to implement a cease receipt and initiate a closure date of April 2021 for all CCR impoundments affected by the August 2018 D.C. Circuit ruling. The D.C. Circuit concluded that the EPA cannot allow utilities to continue to use unlined impoundments (including clay lined impoundments) for the storage or disposal of coal ash. This final rule required Xcel Energy to expedite closure plans for 1 impoundment.
PSCo is pursuing options to build an alternative bottom ash collection system that will be constructed and in service in advance of the April 11, 2021 deadline. Once the alternative bottom ash system is operational, the existing impoundment will initiate closure per the CCR Rule.
Closure costs for existing impoundments are included in the calculation of the ARO.
Federal CWA WOTUS Rule —In April 2020, the EPA and U.S. Army Corps of Engineers (“Agencies”) replaced the 2015 WOTUS rule and narrowed the definition of WOTUS (“2020 WOTUS Rule”). The new definition simplifies the process whether waters are subject to CWA jurisdiction and streamlines the permitting process.
In June 2020, the U.S. District Court for the District of Colorado stayed the effective date of the 2020 WOTUS Rule in Colorado, where the pre-2015 definition of WOTUS is now in effect. Regardless of which definition is applicable in the states in which we operate, PSCo does not anticipate that compliance costs will be material.
Federal CWA ELG — In 2015, the EPA issued a final ELG rule for power plants that discharge treated effluent to surface waters as well as utility-owned landfills that receive CCRs. In October 2020, the EPA published a final rule revising the regulations.
The retirement of units affected by the final ELG rule is subject to regulatory approval.The exact total cost of ELG compliance is therefore uncertain but PSCodoes not anticipate that compliance costs will be material.
Federal CWA Section 316(b) — The federal CWA requires the EPAapproximately $45 million. An estimated liability has been recorded and amounts are expected to regulate cooling water intake structures to assure that these structures reflect the best technology available for minimizing impingement and entrainment of aquatic species. PSCo estimates the likely cost for complying with impingement and entrainment requirements is immaterial. PSCo anticipates these costs will be fully recoverable through regulatory mechanisms.
Environmental Requirements — Air
Regional Haze Rules — The regional haze program requires sulfur dioxide, nitrogen oxideInvestigation and particulate matter emission controls at power plantsfeasibility studies for additional corrective action related to reduce visibility impairment in national parksoffsite groundwater are ongoing (three sites). While the results are uncertain, additional costs are estimated to be up to $35 million. A liability has been recorded for the portion estimable/probable and wilderness areas. The program includes best available retrofit technology and reasonable further progress. The regional haze first planning period requirements were approved by the EPA and implemented by 2016.
All states are now subject to a second round of regional haze planning/rulemaking, focusing on additional reductions to meet reasonable progress requirements. Any additional impacts to PSCo facilities are expected to be minimal.fully recoverable through regulatory mechanisms.
AROs — AROs have been recorded for PSCo’s assets.
PSCo’s AROs were as follows:
| | | 2020 | | 2022 |
(Millions of Dollars) | (Millions of Dollars) | | Jan. 1, 2020 | | Amounts Incurred (a) | | Amounts Settled (b) | | Accretion | | Cash Flow Revisions (c) | | Dec. 31, 2020 | (Millions of Dollars) | | Jan. 1, 2022 | | Amounts Incurred (a) | | | Accretion | | Cash Flow Revisions (b) | | Dec. 31, 2022 |
Electric | Electric | | | | | | | | | | | | | Electric | | | | | | | | | | | |
Steam, hydro and other production | Steam, hydro and other production | | $ | 100 | | | $ | 0 | | | $ | 0 | | | $ | 4 | | | $ | 33 | | | $ | 137 | | Steam, hydro and other production | | $ | 152 | | | $ | 34 | | | | $ | 6 | | | $ | (12) | | | $ | 180 | |
Wind | Wind | | 16 | | | 26 | | | (3) | | | 1 | | | 0 | | | 40 | | Wind | | 42 | | | — | | | | 2 | | | — | | | 44 | |
Distribution | Distribution | | 14 | | | 0 | | | 0 | | | 1 | | | 0 | | | 15 | | Distribution | | 16 | | | — | | | | 1 | | | — | | | 17 | |
Natural gas | Natural gas | | Natural gas | | | |
Transmission and distribution | Transmission and distribution | | 190 | | | 0 | | | 0 | | | 8 | | | 5 | | | 203 | | Transmission and distribution | | 204 | | | — | | | | 10 | | | 20 | | | 234 | |
Miscellaneous | Miscellaneous | | 3 | | | 0 | | | 0 | | | 0 | | | 0 | | | 3 | | Miscellaneous | | 8 | | | — | | | | — | | | (7) | | | 1 | |
Common | | |
Miscellaneous | | 1 | | | 0 | | | 0 | | | 0 | | | 0 | | | 1 | | |
| Total liability | Total liability | | $ | 324 | | | $ | 26 | | | $ | (3) | | | $ | 14 | | | $ | 38 | | | $ | 399 | | Total liability | | $ | 422 | | | $ | 34 | | | | $ | 19 | | | $ | 1 | | | $ | 476 | |
(a)Amounts incurred relatedrelate to the Cheyenne Ridge wind farm placed in service in 2020.steam production pond remediation costs.
(b)Amounts settled related to removal of wind facilities.
(c)In 2020,2022, AROs were revised for changes in timing and estimates of cash flows. Revisions in steam, hydro, and other production AROs primarily related to changes in cost estimates for remediation of ash containment facilities. Changes in gas transmission and distribution AROs were primarily related to changes in labor rates coupled with increased gas line mileage and number of services.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2019 |
(Millions of Dollars) | | Jan. 1, 2019 | | Accretion | | Cash Flow Revisions (a) | | Dec. 31, 2019 (b) |
Electric | | | | | | | | |
Steam, hydro and other production | | $ | 102 | | | $ | 5 | | | $ | (7) | | | $ | 100 | |
Wind | | 14 | | | 1 | | | 1 | | | 16 | |
Distribution | | 13 | | | 1 | | | 0 | | | 14 | |
Miscellaneous | | 3 | | | 0 | | | (3) | | | 0 | |
Natural gas | | | | | | | | |
Transmission and distribution | | 201 | | | 9 | | | (20) | | | 190 | |
Miscellaneous | | 4 | | | 0 | | | (1) | | | 3 | |
Common | | | | | | | | |
Miscellaneous | | 1 | | | 0 | | | 0 | | | 1 | |
Total liability | | $ | 338 | | | $ | 16 | | | $ | (30) | | | $ | 324 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2021 |
(Millions of Dollars) | | Jan. 1, 2021 | | | | | | Accretion | | Cash Flow Revisions (a) | | Dec. 31, 2021 |
Electric | | | | | | | | | | | | |
Steam, hydro and other production | | $ | 137 | | | | | | | $ | 5 | | | $ | 10 | | | $ | 152 | |
Wind | | 40 | | | | | | | 2 | | | — | | | 42 | |
Distribution | | 15 | | | | | | | 1 | | | — | | | 16 | |
Natural gas | | | | | | | | | | | | |
Transmission and distribution | | 203 | | | | | | | 9 | | | (8) | | | 204 | |
Miscellaneous | | 3 | | | | | | | — | | | 5 | | | 8 | |
Common | | | | | | | | | | | | |
Miscellaneous | | 1 | | | | | | | (1) | | | — | | | — | |
Total liability | | $ | 399 | | | | | | | $ | 16 | | | $ | 7 | | | $ | 422 | |
(a)In 2019,2021, AROs were revised for changes in timing and estimates of cash flows. Changes in gas transmission and distribution AROs were primarily related to increased gas line mileage and number of services, which were more than offset by decreased inflation rates. Revisions in steam, hydro, and other production AROs primarily related to changes in cost estimates for pond remediation.
(b)Thereremediation of ash containment facilities. Changes in gas transmission and distribution AROs were no ARO amounts incurred or settledprimarily related to changes in 2019.labor rates coupled with increased gas line mileage and number of services.
Indeterminate AROs — Outside of the recorded asbestos AROs, other plants or buildings may contain asbestos due to the age of many of PSCo’s facilities, but no confirmation or measurement of the cost of removal could be determined as of Dec. 31, 2020.2022. Therefore, an ARO has not been recorded for these facilities.
Leases
PSCo evaluates contracts that may contain leases, including PPAs and arrangements for the use of office space and other facilities, vehicles and equipment. A contract contains a lease if it conveys the exclusive right to control the use of a specific asset. A contract determined to contain a lease is evaluated further to determine if the arrangement is a finance lease.
ROU assets represent PSCo's rights to use leased assets. The present value of future operating lease payments is recognized in current and noncurrent operating lease liabilities. These amounts, adjusted for any prepayments or incentives, are recognized as operating lease ROU assets.
Most of PSCo’s leases do not contain a readily determinable discount rate. Therefore, the present value of future lease payments is generally calculated using the estimated incremental borrowing rate (weighted-average(weighted average of 3.9%4.2%). PSCo has elected to utilize the practical expedient under which non-lease components, such as asset maintenance costs included in payments, are not deducted from minimum lease payments for the purposes of lease accounting and disclosure.
Leases with an initial term of 12 months or less are classified as short-term leases and are not recognized on the consolidated balance sheet.
Operating lease ROU assets:
| (Millions of Dollars) | (Millions of Dollars) | | Dec. 31, 2020 | | Dec. 31, 2019 | (Millions of Dollars) | | Dec. 31, 2022 | | Dec. 31, 2021 |
PPAs | PPAs | | $ | 591 | | | $ | 585 | | PPAs | | $ | 612 | | | $ | 600 | |
Other | Other | | 68 | | | 69 | | Other | | 80 | | | 77 | |
Gross operating lease ROU assets | Gross operating lease ROU assets | | 659 | | | 654 | | Gross operating lease ROU assets | | 692 | | | 677 | |
Accumulated amortization | Accumulated amortization | | (159) | | | (80) | | Accumulated amortization | | (255) | | | (268) | |
Net operating lease ROU assets | Net operating lease ROU assets | | $ | 500 | | | $ | 574 | | Net operating lease ROU assets | | $ | 437 | | | $ | 409 | |
ROU assets for finance leases are included in other noncurrent assets, and the present value of future finance lease payments is included in other current liabilities and other noncurrent liabilities.
PSCo’s most significant finance lease activities are related to WYCO, a joint venture with CIG, to develop and lease natural gas pipeline, storage and compression facilities. Xcel Energy Inc. has a 50% ownership interest in WYCO. WYCO leases its facilities to CIG, and CIG operates the facilities, providing natural gas storage and transportation services to PSCo under separate service agreements.
PSCo accounts for its Totem natural gas storage service and Front Range pipeline arrangements with CIG and WYCO, respectively, as finance leases.
Finance lease ROU assets:
| (Millions of Dollars) | (Millions of Dollars) | | Dec. 31, 2020 | | Dec. 31, 2019 | (Millions of Dollars) | | Dec. 31, 2022 | | Dec. 31, 2021 |
Gas storage facilities | Gas storage facilities | | $ | 201 | | | $ | 200 | | Gas storage facilities | | $ | 160 | | | $ | 201 | |
Gas pipeline | Gas pipeline | | 21 | | | 21 | | Gas pipeline | | 21 | | | 21 | |
Gross finance lease ROU assets | Gross finance lease ROU assets | | 222 | | | 221 | | Gross finance lease ROU assets | | 181 | | | 222 | |
Accumulated amortization | Accumulated amortization | | (90) | | | (82) | | Accumulated amortization | | (64) | | | (97) | |
Net finance lease ROU assets | Net finance lease ROU assets | | $ | 132 | | | $ | 139 | | Net finance lease ROU assets | | $ | 117 | | | $ | 125 | |
Components of lease expense:
| (Millions of Dollars) | (Millions of Dollars) | | 2020 | | 2019 | | 2018 | (Millions of Dollars) | | 2022 | | 2021 | | 2020 |
Operating leases | Operating leases | | | | | | | Operating leases | | | | | | |
PPA capacity payments | PPA capacity payments | | $ | 100 | | | $ | 98 | | | $ | 97 | | PPA capacity payments | | $ | 91 | | | $ | 102 | | | $ | 100 | |
Other operating leases (a) | Other operating leases (a) | | 13 | | | 14 | | | 14 | | Other operating leases (a) | | 20 | | | 16 | | | 13 | |
Total operating lease expense (b) | Total operating lease expense (b) | | $ | 113 | | | $ | 112 | | | $ | 111 | | Total operating lease expense (b) | | $ | 111 | | | $ | 118 | | | $ | 113 | |
Finance leases | Finance leases | | | | | | | Finance leases | | | | | | |
Amortization of ROU assets | Amortization of ROU assets | | $ | 7 | | | $ | 6 | | | $ | 6 | | Amortization of ROU assets | | $ | 4 | | | $ | 7 | | | $ | 7 | |
Interest expense on lease liability | Interest expense on lease liability | | 18 | | | 19 | | | 19 | | Interest expense on lease liability | | 16 | | | 17 | | | 18 | |
Total finance lease expense | Total finance lease expense | | $ | 25 | | | $ | 25 | | | $ | 25 | | Total finance lease expense | | $ | 20 | | | $ | 24 | | | $ | 25 | |
(a)Includes short-term lease expense of $1 million $2 millionfor 2022, 2021 and $1 million for 2020, 2019 and 2018, respectively.2020.
(b)PPA capacity payments are included in electric fuel and purchased power on the consolidated statements of income. Expense for other operating leases is included in O&M expense and electric fuel and purchased power.
Commitments under operating and finance leases as of Dec. 31, 2020:2022:
| (Millions of Dollars) | (Millions of Dollars) | | PPA (a) (b) Operating Leases | | Other Operating Leases | | Total Operating Leases | | Finance Leases | (Millions of Dollars) | | PPA (a) (b) Operating Leases | | Other Operating Leases | | Total Operating Leases | | Finance Leases |
2021 | | $ | 101 | | | $ | 15 | | | $ | 116 | | | $ | 24 | | |
2022 | | 84 | | | 15 | | | 99 | | | 21 | | |
2023 | 2023 | | 70 | | | 10 | | | 80 | | | 20 | | 2023 | | $ | 80 | | | $ | 18 | | | $ | 98 | | | $ | 18 | |
2024 | 2024 | | 63 | | | 10 | | | 73 | | | 20 | | 2024 | | 92 | | | 18 | | | 110 | | | 18 | |
2025 | 2025 | | 63 | | | 5 | | | 68 | | | 19 | | 2025 | | 91 | | | 12 | | | 103 | | | 18 | |
2026 | | 2026 | | 74 | | | 7 | | | 81 | | | 18 | |
2027 | | 2027 | | 44 | | | 7 | | | 51 | | | 16 | |
Thereafter | Thereafter | | 163 | | | 12 | | | 175 | | | 381 | | Thereafter | | 59 | | | 14 | | | 73 | | | 348 | |
Total minimum obligation | Total minimum obligation | | 544 | | | 67 | | | 611 | | | 485 | | Total minimum obligation | | 440 | | | 76 | | | 516 | | | 436 | |
Interest component of obligation | Interest component of obligation | | (74) | | | (8) | | | (82) | | | (352) | | Interest component of obligation | | (49) | | | (8) | | | (57) | | | (319) | |
Present value of minimum obligation | Present value of minimum obligation | | $ | 470 | | | $ | 59 | | | 529 | | | 133 | | Present value of minimum obligation | | $ | 391 | | | $ | 68 | | | 459 | | | 117 | |
Less current portion | Less current portion | | (97) | | | (7) | | Less current portion | | (80) | | | (3) | |
Noncurrent operating and finance lease liabilities | Noncurrent operating and finance lease liabilities | | $ | 432 | | | $ | 126 | | Noncurrent operating and finance lease liabilities | | $ | 379 | | | $ | 114 | |
| Weighted-average remaining lease term in years | Weighted-average remaining lease term in years | | 7.1 | | 38.0 | Weighted-average remaining lease term in years | | 5.4 | | 37.8 |
(a)Amounts do not include PPAs accounted for as executory contracts and/or contingent payments, such as energy payments on renewable PPAs.
(b)PPA operating leases contractually expire at various dates through 2032.
PPAs and Fuel Contracts
Non-Lease PPAs — PSCo has entered into PPAs with other utilities and energy suppliers with various expiration dates through 2033 for purchased power to meet system load and energy requirements, and operating reserve obligations.obligations and as part of wholesale and commodity trading activities. In general, these agreements provide for energy payments, based on actual energy delivered and capacity payments. Certain PPAs, accounted for as executory contracts with various expiration dates through 2027, contain minimum energy purchase commitments.requirements.
Included in electric fuel and purchased power expenses for PPAs accounted for as executory contracts were payments for capacity of $3 million, $2 million and $10 million $12 millionin 2022, 2021 and $21 million in 2020, 2019 and 2018, respectively.
Capacity and energy payments are contingent on the IPP meeting contract obligations, including plant availability requirements. Certain contractual payments are adjusted based on market indices. The effects of price adjustments on financial results are mitigated through purchased energy cost recovery mechanisms.
At Dec. 31, 2020,2022, the estimated future payments for capacity that PSCo is obligated to purchase pursuant to these executory contracts, subject to availability, were as follows:
| (Millions of Dollars) | (Millions of Dollars) | | Capacity | (Millions of Dollars) | | Capacity |
2021 | | $ | 3 | | |
2022 | | 3 | | |
2023 | 2023 | | 3 | | 2023 | | $ | 3 | |
2024 | 2024 | | 3 | | 2024 | | 3 | |
2025 | 2025 | | 3 | | 2025 | | 3 | |
2026 | | 2026 | | 1 | |
2027 | | 2027 | | — | |
Thereafter | Thereafter | | 5 | | Thereafter | | — | |
Total | Total | | $ | 20 | | Total | | $ | 10 | |
Fuel Contracts — PSCo has entered into various long-term commitments for the purchase and delivery of a significant portion of its coal and natural gas requirements. These contracts expire between 20212023 and 2060. PSCo is required to pay additional amounts depending on actual quantities shipped under these agreements.
Estimated minimum purchases under these contracts as of Dec. 31, 2020:2022:
| (Millions of Dollars) | (Millions of Dollars) | | Coal | | Natural gas supply | | Natural gas storage and transportation | (Millions of Dollars) | | Coal | | Natural gas supply | | Natural gas storage and transportation |
2021 | | $ | 132 | | | $ | 354 | | | $ | 116 | | |
2022 | | 61 | | | 119 | | | 115 | | |
2023 | 2023 | | 22 | | | 54 | | | 67 | | 2023 | | $ | 196 | | | $ | 504 | | | $ | 107 | |
2024 | 2024 | | 22 | | | 3 | | | 37 | | 2024 | | 99 | | | 6 | | | 106 | |
2025 | 2025 | | 23 | | | 0 | | | 36 | | 2025 | | 54 | | | — | | | 108 | |
2026 | | 2026 | | 33 | | | — | | | 110 | |
2027 | | 2027 | | 35 | | | — | | | 110 | |
Thereafter | Thereafter | | 47 | | | 0 | | | 475 | | Thereafter | | — | | | — | | | 475 | |
Total | Total | | $ | 307 | | | $ | 530 | | | $ | 846 | | Total | | $ | 417 | | | $ | 510 | | | $ | 1,016 | |
VIEs
Under certain PPAs, PSCo purchases power from IPPs for which PSCo is required to reimburse fuel costs, or to participate in tolling arrangements under which PSCo procures the natural gas required to produce the energy that it purchases. PSCo has determined that certain IPPs are VIEs. PSCo is not subject to risk of loss from the operations of these entities, and no significant financial support is required other than contractual payments for energy and capacity.
PSCo evaluated each of these VIEs for possible consolidation, including review of qualitative factors such as the length and terms of the contract, control over O&M, control over dispatch of electricity, historical and estimated future fuel and electricity prices, and financing activities. PSCo concluded that these entities are not required to be consolidated in its consolidated financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance. PSCo had approximately 1,5181,442 MW and 1,4421,518 MW of capacity under long-term PPAs at Dec. 31, 20202022 and 2019,2021, respectively, with entities that have been determined to be VIEs. These agreements have expiration dates through 2032.
| | |
11. Other Comprehensive Income |
Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31:
| | | 2020 | | 2022 |
(Millions of Dollars) | (Millions of Dollars) | | Gains and Losses on Cash Flow Hedges | | Defined Benefit Pension and Postretirement Items | | Total | (Millions of Dollars) | | Gains and Losses on Interest Rate Cash Flow Hedges | | Defined Benefit Pension and Postretirement Items | | Total |
Accumulated other comprehensive loss at Jan. 1 | Accumulated other comprehensive loss at Jan. 1 | | $ | (24) | | | $ | (3) | | | $ | (27) | | Accumulated other comprehensive loss at Jan. 1 | | $ | (21) | | | $ | (1) | | | $ | (22) | |
Other comprehensive loss before reclassifications | | Other comprehensive loss before reclassifications | | — | | | (1) | | | (1) | |
Losses reclassified from net accumulated other comprehensive loss: | | Losses reclassified from net accumulated other comprehensive loss: | |
Amortization of interest rate hedges | | Amortization of interest rate hedges | | 1 | | (a) | — | | | 1 | |
| Losses reclassified from net accumulated other comprehensive loss: | | |
Interest rate derivatives (net of taxes of $0 and $0, respectively) | | 1 | | (a) | 0 | | | 1 | | |
Amortization of net actuarial loss (net of taxes of $0 and $1, respectively) | | 0 | | | 2 | | (b) | 2 | | |
Net current period other comprehensive income (loss) | Net current period other comprehensive income (loss) | | 1 | | | 2 | | | 3 | | Net current period other comprehensive income (loss) | | 1 | | | (1) | | | — | |
Accumulated other comprehensive loss at Dec. 31 | Accumulated other comprehensive loss at Dec. 31 | | $ | (23) | | | $ | (1) | | | $ | (24) | | Accumulated other comprehensive loss at Dec. 31 | | $ | (20) | | | $ | (2) | | | $ | (22) | |
(a)Included in interest charges.
(b)Included in the computation of net periodic pension and postretirement benefit costs. See Note 9 for further information.
| | | 2019 | | 2021 |
(Millions of Dollars) | (Millions of Dollars) | | Gains and Losses on Cash Flow Hedges | | Defined Benefit Pension and Postretirement Items | | Total | (Millions of Dollars) | | Gains and Losses on Interest Rate Cash Flow Hedges | | Defined Benefit Pension and Postretirement Items | | Total |
Accumulated other comprehensive loss at Jan. 1 | Accumulated other comprehensive loss at Jan. 1 | | $ | (26) | | | $ | 0 | | | $ | (26) | | Accumulated other comprehensive loss at Jan. 1 | | $ | (23) | | | $ | (1) | | | $ | (24) | |
Losses (gains) reclassified from net accumulated other comprehensive loss: | | |
Interest rate derivatives (net of taxes of $0 and $0, respectively) | | 2 | | (a) | 0 | | | 2 | | |
Amortization of net actuarial gains (net of taxes of $0 and $(1), respectively) | | 0 | | | (3) | | (b) | (3) | | |
Losses reclassified from net accumulated other comprehensive loss: | | Losses reclassified from net accumulated other comprehensive loss: | |
Amortization of interest rate hedges | | Amortization of interest rate hedges | | 1 | | (a) | — | | | 1 | |
Amortization of net actuarial gains | | Amortization of net actuarial gains | | 1 | | | — | |
| 1 | |
Net current period other comprehensive income | Net current period other comprehensive income | | 2 | | | (3) | | | (1) | | Net current period other comprehensive income | | 2 | | | — | | | 2 | |
Accumulated other comprehensive loss at Dec. 31 | Accumulated other comprehensive loss at Dec. 31 | | $ | (24) | | | $ | (3) | | | $ | (27) | | Accumulated other comprehensive loss at Dec. 31 | | $ | (21) | | | $ | (1) | | | $ | (22) | |
(a)Included in interest charges.
(b)Included in the computation of net periodic pension and postretirement benefit costs. See Note 9 for further information.
PSCo evaluates performance based on profit or loss generated from the product or service provided. These segments are managed separately because the revenue streams are dependent upon regulated rate recovery, which is separately determined for each segment.
PSCo has the following reportable segments:
•Regulated Electric — The regulated electric utility segment generates, electricity which is transmittedtransmits and distributeddistributes electricity in Colorado. This segment includes sales for resale and provides wholesale transmission service to various entities in the United States. RegulatedThe regulated electric utility segment also includes PSCo’s wholesale commodity and trading operations.
•Regulated Natural Gas — The regulated natural gas utility segment transports, stores and distributes natural gas in portions of Colorado.
PSCo also presents All Other, which includes operating segments with revenues below the necessary quantitative thresholds. Those operating segments primarily include steam revenue, appliance repair services and non-utility real estate activities.
Asset and capital expenditure information is not provided for PSCo’s reportable segments because as an integrated electric and natural gas utility, PSCo operates significant assets that are not dedicated to a specific business segment, and reportingsegment. Reporting assets and capital expenditures by business segment would require arbitrary and potentially misleading allocations, which may not necessarily reflect the assets that would be required for the operation of the business segments on a stand-alone basis.
To report income from operations for regulated electric and regulated natural gas utility segments, the majority of costs are directly assigned to each segment. However, someCertain costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation allocators. Aallocators across each segment. In addition, a general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising.
PSCo’s segment information:
| (Millions of Dollars) | (Millions of Dollars) | | 2020 | | 2019 | | 2018 | (Millions of Dollars) | | 2022 | | 2021 | | 2020 |
Regulated Electric | Regulated Electric | | | | | | | Regulated Electric | | | | | | |
Operating revenues - external | | $ | 3,116 | | | $ | 3,033 | | | $ | 3,031 | | |
Operating revenues — external | | Operating revenues — external | | $ | 3,795 | | | $ | 3,413 | | | $ | 3,116 | |
Intersegment revenue | Intersegment revenue | | 1 | | | 1 | | | 0 | | Intersegment revenue | | 1 | | | 1 | | | 1 | |
Total revenues | Total revenues | | $ | 3,117 | | | $ | 3,034 | | | $ | 3,031 | | Total revenues | | $ | 3,796 | | | $ | 3,414 | | | $ | 3,117 | |
Depreciation and amortization | Depreciation and amortization | | 497 | | | 455 | | | 416 | | Depreciation and amortization | | 650 | | | 566 | | | 497 | |
Interest charges and financing costs | Interest charges and financing costs | | 173 | | | 173 | | | 142 | | Interest charges and financing costs | | 200 | | | 179 | | | 173 | |
Income tax expense | | 13 | | | 45 | | | 103 | | |
Income tax (benefit) expense | | Income tax (benefit) expense | | (11) | | | (16) | | | 13 | |
Net income | Net income | | 460 | | | 465 | | | 429 | | Net income | | 550 | | | 495 | | | 460 | |
Regulated Natural Gas | Regulated Natural Gas | | Regulated Natural Gas | |
Operating revenues - external | | $ | 1,024 | | | $ | 1,161 | | | $ | 1,015 | | |
Intersegment revenue | | 0 | | | 0 | | | 1 | | |
| Total revenues | Total revenues | | $ | 1,024 | | | $ | 1,161 | | | $ | 1,016 | | Total revenues | | $ | 1,860 | | | $ | 1,355 | | | $ | 1,024 | |
Depreciation and amortization | Depreciation and amortization | | 152 | | | 141 | | | 140 | | Depreciation and amortization | | 190 | | | 171 | | | 152 | |
Interest charges and financing costs | Interest charges and financing costs | | 50 | | | 50 | | | 43 | | Interest charges and financing costs | | 59 | | | 53 | | | 50 | |
Income tax expense | Income tax expense | | 29 | | | 33 | | | 13 | | Income tax expense | | 49 | | | 45 | | | 29 | |
Net income | Net income | | 126 | | | 119 | | | 121 | | Net income | | 180 | | | 168 | | | 126 | |
All Other | All Other | | All Other | |
Total revenues (a) | Total revenues (a) | | $ | 43 | | | $ | 43 | | | $ | 40 | | Total revenues (a) | | $ | 53 | | | $ | 47 | | | $ | 43 | |
Depreciation and amortization | Depreciation and amortization | | 6 | | | 6 | | | 5 | | Depreciation and amortization | | 8 | | | 7 | | | 6 | |
Interest charges and financing costs | Interest charges and financing costs | | 1 | | | 1 | | | 1 | | Interest charges and financing costs | | 1 | | | 2 | | | 1 | |
Income tax expense (benefit) | | 3 | | | 2 | | | (3) | | |
Net income (loss) | | 2 | | | (6) | | | 2 | | |
Income tax (benefit) expense | | Income tax (benefit) expense | | (1) | | | 4 | | | 3 | |
Net (loss) income | | Net (loss) income | | (3) | | | (3) | | | 2 | |
| Consolidated Total | Consolidated Total | | Consolidated Total | |
Total revenues (a) | Total revenues (a) | | $ | 4,184 | | | $ | 4,238 | | | $ | 4,087 | | Total revenues (a) | | $ | 5,709 | | | $ | 4,816 | | | $ | 4,184 | |
Reconciling eliminations | Reconciling eliminations | | (1) | | | (1) | | | (1) | | Reconciling eliminations | | (1) | | | (1) | | | (1) | |
Total operating revenues | Total operating revenues | | $ | 4,183 | | | $ | 4,237 | | | $ | 4,086 | | Total operating revenues | | $ | 5,708 | | | $ | 4,815 | | | $ | 4,183 | |
Depreciation and amortization | Depreciation and amortization | | 655 | | | 602 | | | 561 | | Depreciation and amortization | | 848 | | | 744 | | | 655 | |
Interest charges and financing costs | Interest charges and financing costs | | 224 | | | 224 | | | 186 | | Interest charges and financing costs | | 260 | | | 234 | | | 224 | |
Income tax expense | Income tax expense | | 45 | | | 80 | | | 113 | | Income tax expense | | 37 | | | 33 | | | 45 | |
Net income | Net income | | 588 | | | 578 | | | 552 | | Net income | | 727 | | | 660 | | | 588 | |
(a) Operating revenues include $5 million $5 million and $4 million of intercompanyother affiliate revenue for the years ended Dec. 31, 2020, 20192022, 2021 and 2018,2020, respectively. See Note 13 for further information.
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13. Related Party Transactions |
Xcel Energy Services Inc. provides management, administrative and other services for the subsidiaries of Xcel Energy Inc., including PSCo. The services are provided and billed to each subsidiary in accordance with service agreements executed by each subsidiary. PSCo uses services provided by Xcel Energy Services Inc. whenever possible. Costs are charged directly to the subsidiary and are allocated if they cannot be directly assigned.
Xcel Energy, Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS have established a utility money pool arrangement.
See Note 5 for further information.
Significant affiliate transactions among the companies and related parties for the years ended Dec. 31:
| (Millions of Dollars) | (Millions of Dollars) | | 2020 | | 2019 | | 2018 | (Millions of Dollars) | | 2022 | | 2021 | | 2020 |
Operating revenues: | Operating revenues: | | | | | | | Operating revenues: | | | | | | |
| Other | Other | | $ | 5 | | | $ | 5 | | | $ | 4 | | Other | | $ | 5 | | | $ | 5 | | | $ | 5 | |
Operating expenses: | Operating expenses: | | Operating expenses: | |
Other operating expenses — paid to Xcel Energy Services Inc. | Other operating expenses — paid to Xcel Energy Services Inc. | | 571 | | | 532 | | | 519 | | Other operating expenses — paid to Xcel Energy Services Inc. | | 670 | | | 617 | | | 571 | |
Interest expense | | Interest expense | | 2 | | | — | | | — | |
|
Accounts receivable and payable with affiliates at Dec. 31:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2020 | | 2019 |
(Millions of Dollars) | | Accounts Receivable | | Accounts Payable | | Accounts Receivable | | Accounts Payable |
NSP-Minnesota | | $ | 0 | | | $ | 1 | | | $ | 19 | | | $ | 0 | |
NSP-Wisconsin | | 0 | | | 1 | | | 0 | | | 0 | |
SPS | | 0 | | | 6 | | | 0 | | | 0 | |
Other subsidiaries of Xcel Energy Inc. | | 8 | | | 50 | | | 34 | | | 44 | |
| | $ | 8 | | | $ | 58 | | | $ | 53 | | | $ | 44 | |
| | |
14. Summarized Quarterly Financial Data (Unaudited) |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Quarter Ended |
(Millions of Dollars) | | March 31, 2020 | | June 30, 2020 | | Sept. 30, 2020 | | Dec. 31, 2020 |
Operating revenues | | $ | 1,057 | | | $ | 911 | | | $ | 1,081 | | | $ | 1,134 | |
Operating income | | 196 | | | 161 | | | 290 | | | 176 | |
Net income | | 129 | | | 108 | | | 218 | | | 133 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Quarter Ended |
(Millions of Dollars) | | March 31, 2019 | | June 30, 2019 | | Sept. 30, 2019 | | Dec. 31, 2019 |
Operating revenues | | $ | 1,223 | | | $ | 910 | | | $ | 1,044 | | | $ | 1,060 | |
Operating income | | 210 | | | 163 | | | 284 | | | 200 | |
Net income | | 139 | | | 102 | | | 204 | | | 133 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2022 | | 2021 |
(Millions of Dollars) | | Accounts Receivable | | Accounts Payable | | Accounts Receivable | | Accounts Payable |
NSP-Minnesota | | $ | 2 | | | $ | — | | | $ | — | | | $ | 16 | |
NSP-Wisconsin | | — | | | 2 | | | — | | | 2 | |
SPS | | — | | | 11 | | | — | | | 7 | |
Other subsidiaries of Xcel Energy Inc. | | 9 | | | 62 | | | 13 | | | 44 | |
| | $ | 11 | | | $ | 75 | | | $ | 13 | | | $ | 69 | |
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ITEM 9 — CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
None.
| | |
ITEM 9A — CONTROLS AND PROCEDURES |
Disclosure Controls and Procedures
PSCo maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the CEO and CFO, allowing timely decisions regarding required disclosure.
As of Dec. 31, 2020,2022, based on an evaluation carried out under the supervision and with the participation of PSCo’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and procedures, the CEO and CFO have concluded that PSCo’s disclosure controls and procedures were effective.
Internal Control Over Financial Reporting
No changes in PSCo’s internal control over financial reporting occurred during the most recent fiscal quarter ended Dec. 31, 2022 that materially affected, or are reasonably likely to materially affect, PSCo’s internal control over financial reporting. PSCo maintains internal control over financial reporting to provide reasonable assurance regarding the reliability of the financial reporting. PSCo has evaluated and documented its controls in process activities, general computer activities, and on an entity-wide level.
During the year and in preparation for issuing its report for the year ended Dec. 31, 20202022 on internal controls under section 404 of the Sarbanes-Oxley Act of 2002, PSCo conducted testing and monitoring of its internal control over financial reporting. Based on the control evaluation, testing and remediation performed, PSCo did not identify any material control weaknesses, as defined under the standards and rules issued by the Public Company Accounting Oversight Board, as approved by the SEC and as indicated in PSCo’s Management Report on Internal Controls over Financial Reporting, which is contained in Item 8 herein.
This annual report does not include an attestation report of PSCo’s independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by PSCo’s independent registered public accounting firm pursuant to the rules of the SEC that permit PSCo to provide only management’s report in this annual report.
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ITEM 9B — OTHER INFORMATION |
None.
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ITEM 9C — DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS |
Not applicable.
PART III
Items 10, 11 12 and 1312 of Part III of Form 10-K have been omitted from this report for PSCo in accordance with conditions set forth in general instructions I(1)(a) and (b) of Form 10-K for wholly-owned subsidiaries.
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ITEM 10 — DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE |
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ITEM 11 — EXECUTIVE COMPENSATION |
| | |
ITEM 12 — SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS |
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ITEM 13 — CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE |
Information required under this Item is contained in Xcel Energy Inc.’s definitive Proxy Statement for its 20212023 Annual Meeting of Shareholders, which is incorporated by reference.
| | |
ITEM 14 — PRINCIPAL ACCOUNTANT FEES AND SERVICES |
Information required under this Item (aggregate fees billed to us by Item 14 of Form 10-Kour principal accountant, Deloitte & Touche LLP (PCAOB ID No. 34)) is set forth under the heading “Independent Registered Public Accounting Firm - Audit and Non-Audit Fees”contained in Xcel Energy Inc.’s Proxy Statement for the 2021its 2023 Annual Meeting of Shareholders, which is expected to be filed with the SEC on or about April 6, 2021. Such information set forth under such heading is incorporated herein by this reference hereto.reference.
PART IV
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ITEM 15 — EXHIBIT AND FINANCIAL STATEMENT SCHEDULES |
| | | | | |
1 | Consolidated Financial Statements: |
| Management Report on Internal Controls Over Financial Reporting — For the year ended Dec. 31, 2020.2022. |
| Report of Independent Registered Public Accounting Firm — Financial Statements |
| Consolidated Statements of Income — For each of the three years ended Dec. 31, 2020, 20192022, 2021 and 2018.2020. |
| Consolidated Statements of Comprehensive Income — For each of the three years ended Dec. 31, 2020, 20192022, 2021 and 2018.2020. |
| Consolidated Statements of Cash Flows — For each of the three years ended Dec. 31, 2020, 20192022, 2021 and 2018.2020. |
| Consolidated Balance Sheets — As of Dec. 31, 20202022 and 2019.2021. |
| Consolidated Statements of Common Stockholder’s Equity — For each of the three years ended Dec. 31, 2020, 20192022, 2021 and 2018.2020. |
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2 | Schedule II — Valuation and Qualifying Accounts and Reserves for each of the years ended Dec. 31, 2020, 20192022, 2021 and 2018.2020. |
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3 | Exhibits |
* | Indicates incorporation by reference |
+ | Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors |
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Exhibit Number | Description | Report or Registration Statement | Exhibit Reference |
| | PSCo Form 10-Q for the quarter ended Sept. 30, 2017 | 3.01 |
| | PSCo Form 10-K for the year ended Dec. 31, 2018 | 3.02 |
| | Xcel Energy Inc. Form S-3 dated April 18, 2018 | 4(d)(3) |
| | PSCo Form 8-K dated Aug. 8, 2007 | 4.01 |
| | PSCo Form 8-K dated Aug. 6, 2008 | 4.01 |
| | PSCo Form 8-K dated Aug. 9, 2011 | 4.01 |
| | PSCo Form 8-K dated Sept. 11, 2012 | 4.01 |
| Supplemental Indenture No. 23, dated as of March 1, 2013, by and between PSCo andU.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating $250 million aggregate principal amount of 2.50% First Mortgage Bonds, Series No. 25 due March 15, 2023 and $250 million aggregate principal amount of 3.95% First Mortgage Bonds, Series No. 26 due March 15, 2043 | PSCo Form 8-K dated March 26, 2013 | 4.01 |
| | PSCo Form 8-K dated March 10, 2014 | 4.01 |
| | PSCo Form 8-K dated May 12, 2015 | 4.01 |
| | PSCo Form 8-K dated June 13, 2016 | 4.01 |
| | PSCo Form 8-K dated June 19, 2017 | 4.01 |
| Supplemental Indenture No. 28, dated as of June 1, 2018, by and between PSCo andU.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating $350 million aggregate principal amount of 3.70% First Mortgage Bonds, Series No. 31 due June 15, 2028, and $350 million aggregate principal amount of 4.10% First Mortgage Bonds, Series No. 32 due June 15, 2048 | PSCo Form 8-K dated June 21, 2018 | 4.01 |
| | PSCo Form 8-K dated March 13, 2019 | 4.01 |
| | PSCo Form 8-K dated August 13, 2019 | 4.01 |
| Supplemental Indenture No. 31, dated as of May 1, 2020, by and between PSCo andU.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating $375 million aggregate principal amount of 2.70% First Mortgage Bonds, Series No. 35 due Jan. 15, 2051 and $375 million aggregate principal amount of 1.90% First Mortgage Bonds, Series No. 36 due Jan. 15, 2031 | PSCo Form 8-K dated May 15, 2020 | 4.01 |
| | PSCo Form 8-K dated March 1, 2021 | 4.01 |
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| | PSCo Form 8-K dated March 26, 2013 | 4.01 |
| | PSCo Form 8-K dated March 10, 2014 | 4.01 |
| | PSCo Form 8-K dated May 12, 201517, 2022 | 4.01 |
| | PSCo Form 8-K dated June 13, 2016 | 4.01 |
| | PSCo Form 8-K dated June 19, 2017 | 4.01 |
| | PSCo Form 8-K dated June 21, 2018 | 4.01 |
| | PSCo Form 8-K dated March 13, 2019 | 4.01 |
| | PSCo Form 8-K dated August 13, 2019 | 4.01 |
| | PSCo Form 8-K dated May 15, 2020 | 4.0199.03 |
| | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008 | 10.02 |
| | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008 | 10.05 |
| | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2011 | 10.18 |
| | Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2016 | 10.01 |
| | Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2018 | 10.01 |
| | Xcel Energy Inc. Form 10-Q for the quarter ended March 31, 2020 | 10.02 |
| | Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2020 | 10.01 |
| | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008 | 10.17 |
| | Xcel Energy Inc. Definitive Proxy Statement dated April 6, 2010 | Appendix A |
| | Xcel Energy Inc. Form 10-Q for the quarter ended March 31, 2013 | 10.01 |
| | Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2009 | 10.08 |
| | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008 | 10.07 |
| | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2011 | 10.17 |
| | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2013 | 10.22 |
| | Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2016 | 10.01 |
| | Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2017 | 10.01 |
| | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018 | 10.34 |
| | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018 | 10.35 |
| | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2019 | 10.3310.32 |
| | Xcel Energy Inc. Definitive Proxy Statement dated April 5, 2011 | Appendix A |
| | Xcel Energy Inc. Form 8-K dated May 20, 2015 | 10.02 |
| | Xcel Energy Inc. Form 10-K10-Q for the yearquarter ended Dec. 31, 2020Sept. 30, 2021 | 10.2210.01 |
| | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018 | 10.36 |
| | Xcel Energy Inc. Form U5B dated Nov. 16, 2000 | H-1 |
| | Xcel Energy Inc. Form 8-K dated Dec. 3, 2004 | 99.02 |
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| ThirdFourth Amended and Restated Credit Agreement, dated as of June 7, 2019September 19, 2022, among PSCo, as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A. and Barclays Bank Plc,PLC, as Syndication Agents, and Citibank, N.A., MUFG Bank, Ltd., and Wells Fargo Bank, National Association, MUFG Bank, Ltd., and Citibank, N.A., as Documentation Agents | Xcel Energy Inc. Form 8-K dated June 7, 2019Sept. 19, 2022 | 99.03 |
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101.INS | Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document |
101.SCH | Inline XBRL Schema |
101.CAL | Inline XBRL Calculation |
101.DEF | Inline XBRL Definition |
101.LAB | Inline XBRL Label |
101.PRE | Inline XBRL Presentation |
104 | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) |
SCHEDULE II
Public Service Co. of Colorado and Subsidiaries Valuation and Qualifying Accounts Years Ended Dec. 31 | | | Allowance for bad debts | | Allowance for bad debts |
(Millions of Dollars) | (Millions of Dollars) | | 2020 | | 2019 | | 2018 | (Millions of Dollars) | | 2022 | | 2021 | | 2020 |
Balance at Jan. 1 | Balance at Jan. 1 | | $ | 21 | | | $ | 21 | | | $ | 20 | | Balance at Jan. 1 | | $ | 40 | | | $ | 29 | | | $ | 21 | |
Additions charged to costs and expenses | Additions charged to costs and expenses | | 24 | | | 17 | | | 16 | | Additions charged to costs and expenses | | 38 | | | 26 | | | 24 | |
Additions charged to other accounts (a) | Additions charged to other accounts (a) | | 4 | | | 6 | | | 5 | | Additions charged to other accounts (a) | | 18 | | | 4 | | | 4 | |
Deductions from reserves (b) | Deductions from reserves (b) | | (20) | | | (23) | | | (20) | | Deductions from reserves (b) | | (42) | | | (19) | | | (20) | |
Balance at Dec. 31 | Balance at Dec. 31 | | $ | 29 | | | $ | 21 | | | $ | 21 | | Balance at Dec. 31 | | $ | 54 | | | $ | 40 | | | $ | 29 | |
(a)Recovery of amounts previously written-off.
(b)Deductions related primarily to bad debt write-offs.
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Item 16 — Form 10-K Summary |
None.
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this annual report to be signed on its behalf by the undersigned thereunto duly authorized.
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| | PUBLIC SERVICE COMPANY OF COLORADO |
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Feb. 17, 202123, 2023 | | /s/ BRIAN J. VAN ABEL |
| | Brian J. Van Abel |
| | Executive Vice President, Chief Financial Officer and Director |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities on the date indicated above.
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/s/ BEN FOWKEROBERT C. FRENZEL | | /s/ ALICE K. JACKSONROBERT S. KENNEY |
Ben FowkeRobert C. Frenzel | | Alice K. JacksonRobert S. Kenney |
Chairman, Chief Executive Officer and Director | | President and Director |
(Principal Executive Officer) | | |
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/s/ BRIAN J. VAN ABEL | | /s/ JEFFREY S. SAVAGE |
Brian J. Van Abel | | Jeffrey S. Savage |
Executive Vice President, Chief Financial Officer and Director | | Senior Vice President, Controller |
(Principal Accounting Officer and Principal Financial Officer) | | (Principal Accounting Officer) |
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/s/ ROBERT C. FRENZEL | | |
Robert C. Frenzel | | |
Executive Vice President, Chief Operating Officer and Director | | |
SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(D) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT
PSCo has not sent, and does not expect to send, an annual report or proxy statement to its security holder.