UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
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x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2017
2023 or
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¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Commission File Number: 001-3280
Public Service Company of Colorado
(Exact name of registrant as specified in its charter)
For the transition period from _____ to _____ | | |
| 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 jurisdictionOther Jurisdiction of incorporationIncorporation or organization)Organization) | | (I.R.S.IRS Employer Identification No.) |
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| 1800 Larimer, Suite 1100 | Denver | Colorado | | 80202 |
(Address of principal executive offices)Principal Executive Offices) | | (Zip Code) |
Registrant’s telephone number, including area code: (303) 571-7511 | | | | | |
| 303 | 571-7511 |
| (Registrant’s Telephone Number, Including Area Code) |
Securities registered pursuant to Section 12(b) of the Act:None | | | | | | | | | | | | | | |
| Title of each class | | Trading Symbol(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. x☒ 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 x☒ 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. x☒ Yes ¨☐ No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 andof 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 and post such files). x☒ Yes ¨☐ No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulations S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x
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 |
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Large accelerated filer ¨
| | Accelerated filer ¨
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Non-accelerated filer x
| | Smaller reporting company ¨
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(Do not check if smaller reporting company) | | Emerging growth company ¨
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If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.¨☐
Indicate by check mark whether the registrant 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 Exchange Act). ¨☐ Yes x☒ No
As of Feb. 23, 2018,21, 2024, 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 20182024 Annual Meeting of StockholdersShareholders which definitive Proxy Statement is expected to be filed with the SEC on or about April 3, 2018. 9, 2024.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
Index
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| PART I | | |
PART I | |
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Item 1B — | | |
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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 PSCo. PSCo is a wholly owned subsidiary of Xcel Energy Inc. Additional information on Xcel Energy is available in various filings with the SEC. This report should be read in its entirety.
PART I
Item l — Business
DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS
Definitions of Abbreviations
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| Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former) |
| NCE | New Century Energies, 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 |
PSRISPS | P.S.R. Investments, Inc. |
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 |
CFTCCPUC | Commodity Futures Trading Commission |
CPUC | Colorado Public Utilities Commission |
D.C. CircuitDOT | United States Court of Appeals for the District of Columbia Circuit |
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 |
| DSM | Demand side management |
DSMCAECA | Demand side management cost adjustment |
ECA | Retail electric commodity adjustment |
| GCA | Gas cost adjustment |
PCCAPSIA | Purchased capacity cost adjustment |
PSIA | Pipeline system integrity adjustment |
RESARES | Renewable energy standard adjustment |
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| Other |
SCAAFUDC | Steam cost adjustment |
TCA | Transmission cost adjustment |
WCA | Windsource® cost adjustment
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Other Terms and Abbreviations |
AFUDC | Allowance for funds used during construction |
| ALJ | Administrative law judgeLaw Judge |
| APBO | Accumulated postretirement benefit obligation
| ARO | Asset retirement obligation |
ASCARRR | FASBApplication for Rehearing, Reargument, or Reconsideration |
| ASC | Financial Accounting Standards Board Accounting Standards Codification |
ASUC&I | FASB Accounting Standards Update |
C&I | Commercial and Industrial |
CAISOCCR | California Independent System OperatorCoal combustion residuals |
CAACCR Rule | Clean Air ActFinal rule (40 CFR 257.50 - 257.107) published by the EPA regulating the management, storage and disposal of CCRs as a nonhazardous waste |
CACJACEO | Clean Air Clean Jobs ActChief executive officer |
CO2
CFO | Carbon dioxide |
| Chief financial officer |
| CIG | Colorado Interstate Gas Company, LLC |
| CPCN | Certificate of public convenience and necessity
| CPP | Clean Power Plan
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| CWIP | Construction work in progress |
| ERCOT | Electric Reliability Council of Texas
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| ETR | Effective tax rate |
| FASB | Financial Accounting Standards Board
| GAAP | Generally accepted accounting principles |
| GHG | Greenhouse gas |
IRCIPP | Internal Revenue CodeIndependent power producing entity |
ITCISO | Independent System Operator |
| ITC | Investment tax credit |
JOAMGP | Joint operating agreement |
MGP | Manufactured gas plant |
| MISO | Midcontinent Independent Transmission System Operator, Inc.
Moody’s | Moody’s Investor Services |
MWTG | Mountain West Transmission Group |
| Native load | Customer demand of retail and wholesale customers whereby a utility has an obligation to serve under statute or long-term contract.contract |
| NAV | Net asset value |
| NOL | Net operating loss |
NOxO&M | Nitrogen oxide |
O&M | Operating and maintenance |
OCIPIM | Other comprehensive incomePerformance Incentive Mechanism |
PJMPFAS | PJM Interconnection, LLCPer- and PolyFluoroAlkyl Substances |
PMPost-65 | Particulate matterPost-Medicare |
| PPA | Purchased power agreement |
PRPPre-65 | Potentially responsible partyPre-Medicare |
PSIAPTC | Pipeline system integrity adjustment
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PTC | Production tax credit |
PVREC | Photovoltaic |
R&E | Research and experimentation |
REC | Renewable energy credit |
| ROE | Return on equity |
RPSROU | Renewable portfolio standardsRight-of-use |
SIPRTO | State implementation planRegional Transmission Organization |
SO2
S&P | Sulfur dioxideStandard & Poor’s Global Ratings |
SPPSERP | Supplemental executive retirement plan |
| SPP | Southwest Power Pool, Inc. |
Standard & Poor’sTCJA | Standard & Poor’s Ratings Services |
TCJA | 2017 federal tax reform enacted as Public Law No: 115-97, commonly referred to as the Tax Cuts and Jobs Act
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| VaR | Value at Risk |
MeasurementsVIE | Variable interest entity |
KVWACC | KilovoltsWeighted Average Cost of Capital |
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| Measurements |
KWhBcf | Kilowatt hoursBillion cubic feet |
MMBtuKV | Kilovolts |
| KWh | Kilowatt hours |
| MMBtu | Million British thermal units |
| MW | Megawatts |
| MWh | Megawatt hours |
GWh | Gigawatt hours |
COMPANY OVERVIEW
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| Where to Find More Information |
PSCo was incorporated in 1924 under the laws of Colorado. PSCo is a utility engaged primarilywholly 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 generation, purchase, transmission, distributionhistorical statements contained in this report, the matters discussed herein are forward-looking statements that are subject to certain risks, uncertainties and saleassumptions. 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 electricityoperations, 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 Colorado.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, 2023 (including risk factors listed from time to time by PSCo also purchases, transports, distributesin 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 sellsproduction; rising energy prices and fuel costs; qualified employee workforce 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; cybersecurity 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 and wildfire damages in excess of liability insurance coverage; regulatory changes and/or limitations related to the use of natural gas as an energy source; challenging labor market conditions and our ability to retail customersattract and transportsretain 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 | 1.6 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 | 1.5 million | | |
| Total assets | $24.6 billion | | |
| Rate Base (estimated) | $16.9 billion | | |
| GAAP ROE | 7.32% | | |
| Electric generating capacity | 6,203 MW | | |
| Gas storage capacity | 32.1 Bcf | | |
| Electric transmission lines (conductor miles) | 25,000 miles | | |
| Electric distribution lines (conductor miles) | 80,000 miles | | |
| Natural gas transmission lines | 2,000 miles | | | |
| Natural gas distribution lines | 23,000 miles | | | |
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Electric operations consist of energy supply, generation, transmission and distribution activities. PSCo provideshad electric utility service to approximately 1.5sales volume of 33,811 (millions of KWh), 1.6 million customers and natural gas utility service to approximately 1.4electric revenues of $3,731 million customers. All of PSCo’s retail electric operating revenues were derived from operations in Colorado. Although PSCo’s large C&I electric retail customers are comprised of many diversified industries, a significant portion of PSCo’s large C&I electric sales include: fabricated metal products, communications and health services. For small C&I customers, significant electric retail sales include the following industries: real estate and dining establishments. Generally, PSCo’s earnings contribute approximately 35 percent to 45 percent of Xcel Energy’s consolidated net income.for 2023.
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| Electric Operations (percentage of total) | | Sales Volume | | Number of Customers | | Revenues |
| Residential | | 28 | % | | 86 | % | | 35 | % |
| C&I | | 54 | | | 11 | | | 49 | |
| Other | | 18 | | | 3 | | | 17 | |
The wholesale customers served by PSCo comprised approximately 14 percent of its total KWh sold in 2017.
Retail Sales/Revenue Statistics (a)
PSCo owns the following direct subsidiaries: 1480 Welton, Inc. and United Water Company, both of which own certain real estate interests; and Green and Clear Lakes Company, which owns water rights and certain real estate interests. PSCo also holds a controlling interest in several other relatively small ditch and water companies. | | | | | | | | | | | | | | |
| | 2023 | | 2022 |
| KWH sales per retail customer | | 17,781 | | | 18,456 | |
| Revenue per retail customer | | $ | 2,006 | | | $ | 2,074 | |
| Residential revenue per KWh | | 13.69 | ¢ | | 13.62 | ¢ |
| C&I revenue per KWh | | 9.90 | ¢ | | 9.86 | ¢ |
| Total retail revenue per KWh | | 11.28 | ¢ | | 11.24 | ¢ |
PSCo conducts its utility business in the following reportable segments: regulated electric utility, regulated natural gas utility and all other. (a)See Note 156 to the consolidated financial statements for further discussion relating to comparative segment revenues,information.
Owned and Purchased Energy Generation — 2023
Electric Energy Sources
Total electric energy generation by source for the year ended Dec. 31:
Carbon–Free
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.
Wind
Wind capacity is shown as net incomemaximum capacity. Net maximum capacity is attainable only when wind conditions are sufficiently available
Owned — Owned and related financialoperated wind farms with corresponding capacity:
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| 2023 | | 2022 |
| Wind Farms | | Capacity (MW) | | Wind Farms | | Capacity (MW) |
| 2 | | | 1,059 | | | 2 | | | 1,059 | |
PPAs — Number of PPAs with capacity range: | | | | | | | | | | | | | | | | | | | | |
| 2023 | | 2022 |
| PPAs | | Range (MW) | | PPAs | | Range (MW) |
| 17 | | | 23 — 301 | | 17 | | | 23 — 301 |
Current contracted wind capacity for PPAs was 3,026 MW and 3,023 MW in 2023 and 2022, respectively.
In 2023, the average cost of wind energy was $7 per MWh for owned generation and $42 per MWh under existing PPAs. In 2022, the average cost of wind energy was $11 per MWh for owned generation and $38 per MWh under existing PPAs.
PSCo anticipates development of approximately 1,850 MW of wind generation resources (1,550 MW Company Owned, 300 MW as PPAs), as part of the Colorado Resource Plan.
Solar
PPAs — Solar PPAs capacity by type:
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| Type | | Capacity (MW) | |
| Distributed Generation | | 887 | | |
| Utility-Scale | | 1,530 | | (a) |
| Total | | 2,417 | | |
(a)Includes battery storage capacity of 225 MW.
The average cost of solar energy under existing PPAs was $34 per MWh and $69 per MWh in 2023 and 2022, respectively.
PSCo anticipates development of approximately 1,700 MW of solar generation resources (650 MW Company Owned, 1,050 MW as PPAs) as part of the Colorado Resource Plan.
Other
PSCo’s other carbon-free energy portfolio includes hydro from owned generating facilities.
PSCo anticipates development of approximately 1,850 MW of storage capacity (400 MW Company Owned, 1,450 MW as PPAs) as part of the Colorado Resource Plan.
See Item 2 — Properties for further information.
Fossil Fuel
ELECTRIC UTILITY OPERATIONS
Public Utility Regulation
Summary of Regulatory Agencies and Areas of Jurisdiction— PSCo is regulated by the CPUC with respect to its facilities, rates, accounts, services and issuance of securities. PSCo is regulated by the FERC for its 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 mergersPSCo’s fossil fuel energy portfolio includes coal and natural gas transactionspower from both owned generating facilities and PPAs.
See Item 2 — Properties for further information.
Coal
PSCo owns and operates coal units with approximately 1,650 MW of total 2023 net summer dependable capacity, which provided 26% of the PSCo energy mix in interstate commerce. PSCo is not presently a member2023.
Approved early coal plant retirements:
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| Year | | Plant Unit | | Capacity (MW) | |
| 2025 | | Comanche 2 | | 330 | |
| 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.
(b)Reflects conversion from coal to natural gas.
Coal Fuel Cost — Delivered cost per MMBtu of an RTOcoal consumed for owned electric generation and does not operate within an RTO energy market. PSCo is authorized by the FERC to make wholesale electric sales at market-based prices to customers outside PSCo’s balancing authority area.percentage of total fuel requirements (coal and natural gas):
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| | Coal |
| | Cost | | Percent |
| 2023 | | $ | 1.57 | | | 54 | % |
| 2022 | | 1.48 | | | 55 | |
Fuel, Purchased Energy and Conservation Cost-Recovery Mechanisms —
Natural Gas
PSCo has several retail adjustment clausesseven natural gas plants with approximately 3,300 MW of total 2023 net summer dependable capacity, which provided 32% of the PSCo energy mix in 2023.
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 recover fuel, purchased energyis tied to natural gas indices. Natural gas supply and other resource costs:transportation agreements include obligations for the purchase and/or delivery of specified volumes or payments in lieu of delivery.
ECANatural Gas Cost — Recovers fuel and purchased energy costs. Short-term sales margins are shared with retail customers through the ECA. The ECA is revised quarterly.
PCCA — Recovers purchased capacity payments.
SCA — Recovers the difference between PSCo’s actualDelivered cost per MMBtu of fuelnatural gas consumed for owned electric generation and the amountpercentage of these costs recovered under its base steam service rates. The SCA rate is revised on a quarterly basis.
total fuel requirements (coal and natural gas):DSMCA — Recovers DSM, interruptible service costs and performance initiatives for achieving energy savings goals.
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| | Natural Gas |
| | Cost | | Percent |
| 2023 | | $ | 3.06 | | | 46 | % |
| 2022 | | 7.09 | | | 45 | |
RESA — Recovers the incremental costsPSCo anticipates development of compliance with the RES with a maximumapproximately 650 MW of two percentCompany Owned natural gas generation, as part of the customer’s bill.
Colorado Resource Plan to help ensure resiliency and reliability.WCA — Premium service for customers who choose to pay for renewable resources.
TCA — Recovers costs associated with transmission investment outside of rate cases.
CACJA — Recovers costs associated with the CACJA.
PSCo recovers fuel and purchased energy costs from its wholesale electric customers through a fuel cost adjustment clause approved by the FERC. PSCo’s wholesale customers pay the full cost of certain renewable energy purchase and generation costs through a fuel clause and in exchange receive RECs associated with those resources. The wholesale customers pay their jurisdictional allocation of production costs through a fully forecasted formula rate with true-up.
Capacity and Demand
Uninterrupted system peak demand and occurrence date:
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| System Peak Demand (MW) |
| 2023 | | 2022 |
| 6,909 | | | July 24 | | 6,821 | | | Sept. 6 |
Transmission
Transmission lines deliver electricity over long distances from power sources to substations closer to 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.
PSCo plans to build approximately 550 additional conductor miles of transmission lines related to the Colorado Power Pathway project estimated to be complete in 2027.
See Item 2 - Properties for further information.
Distribution
Distribution lines allow electricity to travel at lower voltages from substations directly to customers. PSCo has a vast distribution network, owning and operating approximately 80,000 conductor miles of distribution lines across our service territory.
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 289,163 (thousands of MMBtu), 1.5 million customers and natural gas revenues of $1,734 million for 2023.
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Natural Gas
(percentage of total) | | Deliveries | | Number of Customers | | Revenues |
| Residential | | 35 | % | | 92 | % | | 64 | % |
| C&I | | 16 | | | 7 | | | 26 | |
| Transportation and other | | 49 | | | 1 | | | 10 | |
Sales/Revenue Statistics (a)
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| | 2023 | | 2022 |
| MMBtu sales per retail customer | | 101 | | | 103 | |
| Revenue per retail customer | | $ | 1,061 | | | $ | 1,147 | |
| Residential revenue per MMBtu | | 10.97 | | | 11.14 | |
| C&I revenue per MMBtu | | 9.66 | | | 10.40 | |
| Transportation and other revenue per MMBtu | | 0.95 | | | 1.07 | |
(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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| 2023 | | 2022 |
| MMBtu | | Date | | MMBtu | | Date |
| 2,190,155 | | | Jan. 30 | | 2,243,552 | | | Dec. 22 |
Natural Gas Supply and Cost
PSCo seeks natural gas supply, transportation and storage alternatives to yield a diversified portfolio, which increases flexibility, decreases interruption, 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:
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 electric utility for each of the last three yearsoperations have historically generated less revenues and the forecast for 2018, assuming normalincome when weather conditions is as follows:
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| | System Peak Demand (in MW) |
| | 2017 | | 2016 | | 2015 | | 2018 Forecast |
| PSCo | 6,671 |
| | 6,585 |
| | 6,284 |
| | 6,462 |
|
The peak demand for PSCo’s system typically occursare warmer in the winter and cooler in the summer. Decoupling mechanisms mitigate the impacts of weather in certain jurisdictions. PSCo’s electric decoupling mechanism expired in September.
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 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 2017 system peakFERC has continued to promote competitive wholesale markets through open access transmission and other means. PSCo’s wholesale customers can purchase energy from competing generation resources and transmission services from other service providers to serve their native load.
FERC Order No. 1000 established competition for ownership of certain new electric transmission facilities under Federal regulations. Some states have state 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 adoption, however implementation is expected to vary by RTO/ISO and the near, medium, and long-term impacts of Order 2222 remain unclear.
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 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 what additional facilities or modifications to 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 historic and current operating sites and other 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
Power Plant Greenhouse Gas Regulations— In May 2023, the EPA published proposed rules addressing control of CO2 emissions from the power sector. The rule proposed regulations for new natural gas generating units and emission guidelines for existing coal and certain natural gas generation. The proposed rules create subcategories of coal units based on planned retirement date and subcategories of natural gas combustion turbines and combined cycle units based on utilization. The CO2 control requirements vary by subcategory. Until final rules are issued, it is not certain what the impact will be on PSCo. PSCo believes that the cost of these initiatives or replacement generation would be recoverable through rates based on prior state commission practices.
Coal Ash Regulation
In May 2023, the EPA published proposed rules to regulate legacy CCR surface impoundments at inactive facilities and previously exempt areas where CCR was placed directly on land at regulated CCR facilities under the CCR Rule for the first time. The proposed rule would subject these areas to the CCR Rule requirements, including groundwater monitoring, corrective action, closure, and post-closure care requirements, among other requirements, with several of the deadlines accelerated.
The EPA has committed to a May 2024 publication date for those new rules. It is also anticipated that the EPA may issue other CCR proposed rules in 2024 and 2025 that further expand the scope of the CCR Rule. Until final rules are issued, it is not certain what the impact will be on PSCo. PSCo. believes that the cost of these initiatives would be recoverable through rates based on prior state commission practices.
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 designate two types of PFAS as “hazardous substances” under the CERCLA. In March 2023, the EPA published a proposed rule that would establish enforceable drinking water standards for certain PFAS chemicals.
Final rules are expected in 2024. Costs are uncertain until a final rule is published.
The proposed rules could result in new obligations for investigation and cleanup. PSCo is monitoring changes to state laws addressing PFAS. The impact of these proposed regulations is uncertain.
Effluent Limitation Guidelines
In March 2023, the EPA released a proposed rule under the Clean Water Act, setting forth proposed Effluent Limitations Guidelines and Standards for steam generating coal plants. This proposed rule establishes more stringent wastewater discharge standards for bottom ash transport water, flue-gas desulfurization wastewater, and combustion residuals leachate from steam electric power plants, particularly coal-fired power plants. The impact of these proposed regulations is uncertain until a final rule is published.
Other
Our operations are subject to 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, 2023, PSCo had 2,352 full-time employees and ten part-time employees, of which 1,878 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.
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 have responsibility for overseeing the identification and mitigation of key risks.
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 Code of Conduct 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 confirm 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 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 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 supplies.
•Impact of adverse weather conditions and natural disasters, including, tornadoes, avalanches, icing events, floods, high winds and droughts.
•Performance below expected or contracted levels of output or 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 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 utility sector is undergoing significant change (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.
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. New data centers and crypto mining facilities could generate significant increase in demand. Higher 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 require inputs such as coal, natural gas and water. 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. 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 and the potential for project cancellation. Failure to adhere to project budgets and timelines could adversely impact 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.
A significant increase in fuel costs could cause a decline in customer demand, adverse regulatory outcomes and an increase in bad debt expense 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 alternatives at potentially higher costs. Additionally, supply shortages may not be fully resolved, which negatively 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 negatively impacts 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 passed through to customer bills could impact our ability to recover costs for other improvements and operations.
Due to the 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. If such programs 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.
The competition for talent has become increasingly prevalent, and we have experienced increased employee turnover due to the condition of the labor market and decisions related to strategic workforce planning. In addition, specialized knowledge and skills are required for many of our positions, which may pose additional difficulty for us as we work to recruit, retain and motivate employees in this climate.
Failure to hire, adequately train replacement employees, transfer knowledge/expertise 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 impact our results of operations, financial condition or cash flows.
Our businesses have collective bargaining agreements with labor unions. Failure to renew or renegotiate these contracts could lead to labor disruptions, including strikes or boycotts. Such disruptions or any negotiated wage or benefit increases could have a material adverse impact to our results of operations, financial condition or cash flows.
National unionization efforts could affect our business, as an increase in unionized workers could challenge our operational efficiency and increase costs.
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 compliance with our Code of Conduct and are required to participate in annual training. Additionally, suppliers are subject to compliance 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. 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 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 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 for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs.
Higher 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 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.
Our credit ratings are subject to change and our credit ratings may 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 or 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 commercial paper, issuing new securities or cause us to issue securities with unfavorable terms and conditions, such as higher interest 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 cash flow and 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., SPP, Midcontinent Independent System Operator, Inc. 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 Investor Services 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, 2023, Xcel Energy Inc. and its utility subsidiaries had approximately $24.9 billion of long-term debt and $1.3 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, 2023, Xcel Energy had the following guarantees outstanding:
•$951 million for performance and payment of Capital Services, LLC contracts for wind and solar generating equipment, with immaterial exposure.
•$100 million for performance on tax credit sale agreements of its subsidiaries, with immaterial exposure.
•$75 million 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.
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 value/availability of various tax credits or the timeliness of their utilization may impact the economics or selection of resources. 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 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.
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 PSCo occurredbasic 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.
The oil and gas industry represents our largest commercial and industrial customer base. Oil and natural gas prices are sensitive to market risk factors which may impact demand.
We face risks related to health epidemics and other outbreaks, which may have a material effect on July 19, 2017. The 2017 system peak demand was higher than 2016our financial condition, results of operations and cash flows.
Health epidemics impact countries, communities, supply chains and markets. Uncertainty continues to exist regarding epidemics; the duration and magnitude of business restrictions including shutdowns (domestically and globally); the potential impact on the workforce including shortages of employees and third-party contractors due to warmer Julyquarantine policies, vaccination requirements or government restrictions; impacts on the transportation of goods, and the generalized impact on the economy.
We cannot ultimately predict whether an epidemic will have a material impact on our future liquidity, financial condition or results of operations. Nor can we predict the impact on the health of our employees, our supply chain or our ability to recover higher costs associated with managing 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 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, 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. While 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, 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.
A cybersecurity 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 Company 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 cybersecurity incidents, including those caused by human error.
The utility industry has been the target of several attacks on operational systems and has seen an increased volume and sophistication of cybersecurity incidents from international activist organizations, other 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.
Cybersecurity incidents could harm our businesses by limiting our generation, transmission and distribution 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 cybersecurity incident on 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.
Generative Artificial Intelligence, such as large language models like ChatGPT, present a range of challenges and potential risks as we consider impacts to the business. These challenges involve navigating the complexities of creating and deploying AI models that generate content autonomously. Data privacy, legal concerns, and security issues are all risks as this technology continues to be adopted.
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 cybersecurity threats or subsequent related actions. Cybersecurity incidents and regulatory action could result in a material decrease in revenues and may causesignificant 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 cybersecurity 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 cybersecurity 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, cybersecurity 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.
International commitments and agreements could result in future additional GHG reductions in the United States. In addition, in 2023 the EPA intends to publish draft regulations for GHG emissions from the power sector consistent with the 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 and 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.
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 and result in more frequent service interruptions. Periods of extreme temperatures could also impact our ability to meet demand.
More frequent and severe drought conditions, extreme swings in amount and timing of precipitation, changes in vegetation, unseasonably warm temperatures, very low humidity, stronger winds and other factors have increased the duration of the wildfire season and the potential impact of an event. Also, the expansion of the wildland urban interface increases the wildfire risk to surrounding communities and PSCo's electric and natural gas infrastructure.
Other potential risks associated with wildfires and other climate events 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.
| | |
| ITEM 1B — UNRESOLVED STAFF COMMENTS |
None.
PSCo is a wholly owned subsidiary of Xcel Energy. As such, its cybersecurity processes are maintained by Xcel Energy management and governed by its Board of Directors.
As described in Item 1A – Risk Factors, Xcel Energy operates in an industry that requires the continued operation of sophisticated information technology, control systems and network infrastructure, as such, our business is subject to the risk of interruption by cybersecurity incidents that range from attacks common to most industries, such as phishing and denial-of-service, to attacks from more sophisticated adversaries, including nation state actors, that target the critical infrastructure used in the operation of our business.
Xcel Energy has a security risk program in place to identify, assess, manage and report material risks from cybersecurity incidents. As a utility provider, Xcel Energy complies with reliability standards imposed by NERC, including critical infrastructure protection standards related to both cybersecurity and physical security. These standards imposed by NERC, in alignment with the NIST Cybersecurity Framework, are the basis for which Xcel Energy has designed the cybersecurity control framework within its security risk program.
Annually, as part of Xcel Energy’s enterprise risk program, an integrated cybersecurity risk identification and assessment is completed across Xcel Energy’s business, including generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets as well as information processed in our systems (including systems hosted by third parties) that could be affected by cybersecurity incidents. This analysis includes the impact, likelihood, timeframe and controllability of cybersecurity risks and is presented to the Board of Directors. Management monitors and reviews the results of this analysis, integrating them into the enterprise risk assessment processes and implements appropriate mitigating actions as needed.
Xcel Energy’s cybersecurity policies, standards, practices and readiness are regularly assessed by third-party consultants. These partners are engaged to perform independent penetration testing and other security related services to assist in the prevention, detection, monitoring, mitigation and remediation of cybersecurity incidents and risks. The results of these assessments are communicated to management and the Board of Directors by the Chief Security Officer.
Xcel Energy employs a comprehensive risk based approach to assess the magnitude and significance of a vendor’s risk to Xcel Energy. Certain third-party service providers are subject to vendor security risk assessments at the time of integration, contract execution/renewal, and upon detection of any increase in risk profile. Xcel Energy uses a variety of inputs in such risk assessments, including information supplied by providers and third parties (including information analysis centers that share daily threat intelligence and improve organizational agility associated with management of cybersecurity risks). In addition, Xcel Energy requires certain third-party service providers to meet appropriate security requirements, controls and responsibilities. Xcel Energy deploys periodic monitoring activities to assess compliance with our cybersecurity control framework and investigates security incidents that have impacted our third-party service providers as appropriate.
Management has assigned responsibility for the security risk program to the Chief Security Officer who has extensive experience in critical infrastructure protection, including multiple years of experience with the Department of Defense. The Chief Security Officer is informed about and monitors prevention, detection, mitigation and remediation efforts through a team of security professionals, many of whom are Certified Information Systems Security Professionals, Certified Information Security Managers or have received other cybersecurity certifications. The team has extensive experience selecting, deploying and operating cybersecurity technologies, initiatives and processes that aid in preventing, remediating and mitigating known and unknown cybersecurity threats.
The Chief Security Officer or members of management brief the Board on routine and regular cybersecurity risk and threat updates, typically on a quarterly basis. In the event of a significant threat or incident, management and the Chief Security Officer leverage Xcel Energy’s incident response processes to assess impacts and resolve incidents. When a significant cybersecurity incident occurs, management communicates with the Board of Directors and relevant committees.
The Board of Directors oversees the risks associated with cybersecurity and the physical security of our assets, with information security matters being discussed at each regular board meeting as well as at the ONES and Audit Committee meetings throughout the year.
While the ONES Committee has primary committee responsibility for cybersecurity due to the operational issues involved, the Board of Directors has determined that the topic is of sufficient importance to warrant this comprehensive oversight approach. Augmenting such oversight efforts, the Board conducts drills to practice its response in a possible emergency situation to ensure it is well prepared and positioned to perform in a possible crisis.
Cybersecurity risks are a part of Xcel Energy’s normal course of business. To date, no cybersecurity incident or attack has had a material impact on our business or results of operations. As of Feb. 21, 2024 there have been no material cybersecurity incidents to report.
Virtually all of the utility plant property of PSCo is subject to the lien of its first mortgage bond indenture.
| | | | | | | | | | | | | | | | | | | | | | | |
| Station, Location and Unit at Dec. 31, 2023 | | Fuel | | Installed | | MW (a) | |
| Steam: | | | | | | | |
| Comanche-Pueblo, CO | | | | | | | |
| Unit 2 | | Coal | | 1975 | | 330 | | |
| Unit 3 | | Coal | | 2010 | | 500 | | (b) |
| Craig-Craig, CO, 2 Units | | Coal | | 1979 - 1980 | | 82 | | (c) |
| Hayden-Hayden, CO, 2 Units | | Coal | | 1965 - 1976 | | 233 | | (d) |
| Pawnee-Brush, CO, 1 Unit | | Coal | | 1981 | | 505 | | |
| Cherokee-Denver, CO, 1 Unit | | Natural Gas | | 1968 | | 310 | | |
| Combustion Turbine: | | | | | | | |
| Blue Spruce-Aurora, CO, 2 Units | | Natural Gas | | 2003 | | 264 | | |
| Cherokee-Denver, CO, 3 Units | | Natural Gas | | 2015 | | 576 | | |
| Fort St. Vrain-Platteville, CO, 6 Units | | Natural Gas | | 1972 - 2009 | | 1,022 | | |
| Manchief, CO, 2 Units . | | Natural Gas | | 2000 | | 250 | | |
| Rocky Mountain-Keenesburg, CO, 3 Units | | Natural Gas | | 2004 | | 592 | | |
| Various locations, 8 Units | | Natural Gas | | Various | | 247 | | |
| Hydro: | | | | | | | |
| Cabin Creek-Georgetown, CO | | | | | | | |
| Pumped Storage, 2 Units | | Hydro | | 1967 | | 210 | | |
| Various locations, 6 Units | | Hydro | | Various | | 23 | | |
| Wind: | | | | | | | |
| Rush Creek, CO, 300 units | | Wind | | 2018 | | 582 | | (e) |
| Cheyenne Ridge, CO, 229 units | | Wind | | 2020 | | 477 | | (e) |
| | | | Total | | 6,203 | | |
(a)Summer 2023 net dependable capacity. Wind is presented as net maximum capacity.
(b)Based on PSCo’s ownership of 67%.
(c)Based on PSCo’s ownership of 10%.
(d)Based on PSCo’s ownership of 76% of Unit 1 and 37% of Unit 2.
(e)Net maximum capacity is attainable only when wind conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2023 the Company’s wind facilities had a weighted-average capacity factors of 43%.
Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2023:
| | | | | |
| Conductor Miles | |
| Transmission | |
| |
| 345 KV | 5,421 | |
| 230 KV | 12,244 | |
| |
| 138 KV | 92 | |
| 115 KV | 4,994 | |
| Less than 115 KV | 1,782 | |
| Total Transmission | 24,533 | |
| |
| Distribution | |
| Less than 115 KV | 80,176 | |
| |
| Total | 104,709 | |
PSCo had 235 electric utility transmission and distribution substations at Dec. 31, 2023.
Natural gas utility mains at Dec. 31, 2023:
| | | | | |
| Miles | |
| Transmission | 2,024 | |
| Distribution | 23,494 | |
| | |
| 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. Legal fees are generally expensed as incurred.
See Note 10 to the consolidated financial statements, Item 1 and Item 7 for further information.
| | |
| ITEM 4 — MINE SAFETY DISCLOSURES |
None.
PART II
| | |
| 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 2023 and 2022 were as follows:
| | | | | | | | | | | | | | |
| (Millions of Dollars) | | 2023 | | 2022 |
| First quarter | | $ | 183 | | | $ | 129 | |
| Second quarter | | 189 | | | 132 | |
| Third quarter | | 161 | | | 127 | |
| Fourth quarter | | 72 | | | 119 | |
| | |
| 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 ongoing earnings. Generally, a non-GAAP financial measure is a measure of a company’s financial performance, financial position or cash flows that is 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.
Earnings Adjusted for Certain Items (Ongoing Earnings)
Ongoing earnings reflect adjustments to GAAP earnings (net income) for certain items.
We use this non-GAAP financial measure to evaluate and provide details of PSCo’s core earnings and underlying performance. For instance, to present ongoing earnings, we may adjust the related GAAP amounts for certain items that are non-recurring in nature. We believe this measurement is useful to investors to evaluate the actual and projected financial performance and contribution of our subsidiaries. This non-GAAP financial measure should not be considered as an alternative to measures calculated and reported in accordance with GAAP.
The following table provides a reconciliation of GAAP earnings (net income) to ongoing earnings:
| | | | | | | | | | | | | | |
| (Millions of Dollars) | | 2023 | | 2022 |
| GAAP net income | | $ | 695 | | | $ | 727 | |
| Loss on Comanche Unit 3 litigation | | 35 | | | — | |
| Workforce reduction expenses | | 20 | | | — | |
| Less: tax effect of adjustment | | (13) | | | — | |
| Ongoing earnings | | $ | 737 | | | $ | 727 | |
Comanche Unit 3 Litigation — In the third quarter of 2023, PSCo recognized a $34 million loss due to a jury verdict in Denver County District Court awarding CORE lost power damages and other costs. PSCo intends to file an appeal of this decision. Given the non-recurring nature of this specific item, it has been excluded from ongoing earnings.
Workforce Reduction — In 2023, Xcel Energy implemented workforce actions to align resources and investments with our evolving business and customer needs, and streamline the organization for long-term success. Xcel Energy initiated a voluntary retirement program, under which approximately 400 eligible non-bargaining employees retired. Xcel Energy also eliminated approximately 150 non-bargaining employees through an involuntary severance program.
Total Xcel Energy workforce reduction expenses of $72 million were recorded in the fourth quarter of 2023, of which $20 million was attributable to PSCo. Given the non-recurring nature of this item, it has been excluded from ongoing earnings.
2023 Comparison to 2022
PSCo’s GAAP net income was $695 million for 2023, compared to $727 million for 2022. Ongoing net income was $737 million for 2023, compared to $727 million for 2022. Ongoing earnings primarily reflects higher recovery of infrastructure investment and lower O&M expenses, which were partially offset by increased depreciation, interest charges and unfavorable weather.
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 Purchased Power and Electric Margin
| | | | | | | | | | | | | | |
| (Millions of Dollars) | | 2023 | | 2022 |
| Electric revenues | | $ | 3,731 | | | $ | 3,795 | |
| Electric fuel and purchased power | | (1,364) | | | (1,485) | |
| Electric margin | | $ | 2,367 | | | $ | 2,310 | |
Changes in Electric Margin
| | | | | | | | |
| (Millions of Dollars) | | 2023 vs. 2022 |
| Regulatory rate outcome | | $ | 56 | |
| Non-fuel riders | | 26 | |
| Wholesale transmission revenue (net) | | 6 | |
| Estimated impact of weather (net of decoupling) | | (23) | |
Sales and demand (a) | | (5) | |
| | |
| | |
| Other (net) | | (3) | |
| Total increase | | $ | 57 | |
(a)Sales excludes weather impact, net of partial decoupling (mechanism expired in September).
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 generally have minimal earnings impact due to cost recovery mechanisms.
Natural Gas Revenues, Cost of Natural Gas Sold and Transported and Natural Gas Margin
| | | | | | | | | | | | | | |
| (Millions of Dollars) | | 2023 | | 2022 |
| Natural gas revenues | | $ | 1,734 | | | $ | 1,860 | |
| Cost of natural gas sold and transported | | (910) | | | (1,053) | |
| Natural gas margin | | $ | 824 | | | $ | 807 | |
Changes in Natural Gas Margin
| | | | | | | | |
| (Millions of Dollars) | | 2023 vs. 2022 |
| Regulatory rate outcomes | | 47 | |
| Estimated impact of weather | | $ | (12) | |
| | |
| | |
| | |
| | |
| Other (net) | | (18) | |
| Total increase | | $ | 17 | |
Non-Fuel Operating Expenses and Other Items
O&M Expenses — O&M expenses decreased $40 million in 2023. The decrease was primarily due to impact of management cost containment efforts, the timing of regulatory deferrals and the exit of our appliance repair services business, offset by the impact of inflationary pressures, including labor.
Depreciation and Amortization— Depreciation and amortization increased $76 million in 2023. The increase was primarily due to system expansion and new electric and natural gas depreciation rates.
Interest Charges — Interest expenses increased $41 million in 2023. The increase was largely due to increased long-term debt levels to fund capital investments and higher interest rates.
| | |
| 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. PSCo requests changes in utility rates through commission filings. Changes in operating costs can affect PSCo’s financial results, depending on the timing of rate cases 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 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 the SPP Western Energy Imbalance Service market, an energy imbalance market. |
| DOT | | Pipeline safety compliance. |
Recovery Mechanisms | | | | | | | | |
| Mechanism | | Additional Information |
| Colorado Energy Plan Adjustment | | Recovers the early retirement costs of Comanche Units 1 and 2 to a maximum of 1% of the customer’s bill. |
| Decoupling | | Mechanism to true-up revenue to a baseline amount for residential (excluding lighting and demand) and metered non-demand small C&I classes (pilot program ended Sept. 2023, with amortization of previously deferred amounts expected through 2026). |
| DSM Cost Adjustment | | Recovers electric and gas DSM, interruptible service costs and performance incentives for achieving energy savings goals. |
| ECA | | Recovers fuel and purchased energy costs. Short-term sales margins are shared with customers. The ECA is revised quarterly. |
| Fuel 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. |
| Purchased Capacity Cost Adjustment | | Recovers purchased capacity payments. |
| RES Adjustment | | Recovers the incremental costs of compliance with the RES with a maximum of 1% of the customer’s bill. |
| Steam Cost Adjustment | | Recovers fuel costs to operate the steam system. The Steam Cost Adjustment rate is revised quarterly. |
| Transmission Cost Adjustment | | Recovers costs between rate cases for transmission projects that result in a net increase in capacity or are part of an approved wildfire mitigation plan. |
| | |
| Transportation Electrification Plan | | Recovers costs associated with the investment in and adoption of transportation electrification infrastructure. |
| | |
Pending and Recently Concluded Regulatory Proceedings
Colorado Electric Rate Case — In 2022, PSCo filed a Colorado electric rate case seeking a revised net increase of $253 million. The total request reflected a $303 million increase, which includes $50 million of authorized costs previously recovered through various rider mechanisms. The request was based on a 10.25% ROE, an equity ratio of 55.7% and a 2023 forecast test year with a 2023 average rate base of system peak assumes normal weather conditions.$11.3 billion.
In September 2023, the CPUC approved a settlement between PSCo and various parties, which included the following terms:
•Retail revenue increase (excluding rider roll-ins) of $95 million (2.96%), based on a 2022 historic test year using year-end rate base with forward looking known and measurable adjustments. Energy Sources•Weighted-average cost of capital of 6.95% (based on 55.69% equity ratio and Related Transmission Initiatives9.3% ROE).
•Termination of the revenue decoupling pilot.
•Continuation of previously authorized trackers and deferrals.
Rates became effective in September 2023.
Colorado Resource Plan— In August 2022, the CPUC approved a settlement for the Colorado Resource Plan, which provides for an expected carbon reduction and the retirement of PSCo’s remaining coal plant by the end of 2030.
In September 2023 (updated in October 2023), PSCo filed its recommended Preferred Portfolio of resources, which proposed a total of 7,521 MW of generation resources, including 4,716 owned MW and 2,805 purchased power MW. The filing also included several other alternative portfolios.
In December 2023, the CPUC approved an alternative portfolio of 5,835 MW. The decision provides an opportunity to assess timing and levels of incremental renewable resources in the Just Transition Plan filing expected to be submitted by June 1, 2024.
Approved portfolio includes the following resources:
| | | | | | | | | | | |
| Generation Resource (in MW) | Company Owned | PPAs | Total |
| Wind Resources | 1,325 | | 375 | | 1,700 | |
| Solar | 858 | | 760 | | 1,618 | |
| Storage | 500 | | 1,348 | | 1,848 | |
| Natural Gas | 450 | | 219 | | 669 | |
| Total | 3,133 | | 2,702 | | 5,835 | |
PSCo expects to meetinvest approximately $4.8 billion in generation resources under the alternative portfolio for the benefit of its customers and achieving the state’s clean energy goals. The CPUC did not approve the May Valley to Longhorn Transmission Line, which was estimated at $250 million.
In December 2023, the CPUC approved two PIMs associated with the generation projects in the portfolio, including a two-way sharing measure related to capital construction costs and another related to ongoing levelized energy costs. These PIMs will be further defined in the written order and related proceedings throughout 2024.
In February 2024, PSCo filed an ARRR to seek approval for an updated portfolio, reflecting inclusion of certain back-up bids and clarifications of the application of PIMs.
Colorado Natural Gas Rate Case — In January 2024, PSCo filed a request with the CPUC seeking an increase to retail natural gas rates of $171 million, or an approximately 9.5% increase in the average residential customer bill. The request is based on a 2023 test year, a 10.25% ROE, an equity ratio of 55% and a $4.2 billion retail rate base which includes projected capital additions through Dec. 31, 2023.PSCo has requested a proposed effective date of Nov. 1, 2024.
PSCo has proposed to defer collection of the increased rates until Feb. 15, 2025 (following the expiration of the rider to recover Winter Storm Uri costs) to mitigate customer bill impacts, with revenues for the deferred period collected over a 12-month period beginning on that date.
The request supports fundamental infrastructure investments to serve customers, consistent with PSCo’s obligation to provide safe, reliable service while enabling PSCo to continue to be a leader of the clean energy transition in partnership with the CPUC to achieve clean heat goals.
| | | | | | |
| Revenue Request (millions of dollars) | | |
| Changes since 2022 rate case: | | |
Plant related investments(a) | | $ | 145 | |
| Operations and maintenance, amortization and other expenses | | 23 | |
| Property tax expense | | 10 | |
| Sales growth | | (7) | |
| | |
| | |
| | |
| Total base revenue request | | $ | 171 | |
| | |
| | |
(a)Includes approximately $32 million as a result of the increase in ROE from 9.2% to 10.25%.
ECA Fuel Recovery — In December 2022, PSCo filed to recover $123 million of under-recovered 2022 fuel costs over two quarters. 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 costs.
In 2023, PSCo submitted interim ECA filings to recover $70 million and $25 million, respectively, of the 2022 under-recovered costs.
In the third quarter, PSCo and CPUC Staff filed a settlement allowing for collection of the remaining amount, which after final adjustments was $37 million. In December 2023, the ALJ issued a recommended decision approving the settlement in full. Recovery of costs is expected to begin in the second quarter of 2024.
Colorado Legislation — In May 2023, Colorado Senate Bill 23-291 passed and was signed into law. The bill includes a number of topics including natural gas and electric fuel incentive mechanisms, natural gas planning rules, regulatory filing requirements, and non-recovery of certain expenses (e.g., certain organizational or membership dues, tax penalties or fines).
In November 2023, the CPUC approved PSCo’s natural gas price risk management plan, establishing upper and lower limits for changes in the GCA rate. As a result costs above the upper limit are deferred for future recovery, with interest, and costs below the lower limit are deferred as a reserve against future cost increases.
The legislation also calls for the CPUC to adopt rules to establish fuel cost mechanisms to align the financial incentives of a utility with the interests of the utility’s customers by Jan. 1, 2025. The CPUC issued a request for initial comments on a potential mechanism under which gas utilities would share a percentage, subject to an annual cap, of cost changes in the GCA. A formal rulemaking is expected to commence in the first half of 2024.
Purchased Power and Transmission Service Providers
PSCo meets its system capacity and energy requirements through existingits fleet of owned and purchased electric generating stations, power purchases, new generation facilities, DSM optionsresources and, phased expansionwhen required, the use of existing generation at select power plants.demand-side management programs.
Purchased Power— PSCo has contracts to purchasepurchases power from other utilities, energy marketers and IPPs.independent power producers. Long-term purchased power contracts for dispatchable resources typically require a periodic capacity charge and an energy chargecharges. Much of PSCo’s long-term purchased power is for energy actually purchased. PSCo also contracts to purchase power for both wind, solar and solarstorage resources. In addition, PSCo makes short-term purchases to meet system load and energy requirements, to replace generation from company-owned units underout of service for maintenance, or during outages, to meet operating reserve obligations, or to obtain energy at a lower cost.
Energy Markets — PSCo joined the SPP Western Energy Imbalance Service Market in April 2023. This market is an incremental step in the participation in an organized wholesale market. Energy imbalance 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 PSCo’sits customers.
Rush Creek Wind Ownership Proposal — In 2016, the CPUC granted PSCo a CPCN to build, own and operate a 600 MW wind generation facility in Colorado at Rush Creek. The CPCN includes a hard cost-cap of $1.096 billion (including transmission costs) and a capital cost sharing mechanism between customers and PSCo of 82.5 percent to customers and 17.5 percent to PSCo for every $10 million the project comes in below the cost-cap.
All major contracts required to complete the project have been executed. PTC components for safe harboring the facility have been fabricated and construction began in April 2017.
Investment costs will be recovered through the RESA and ECA riders until PSCo’s next rate case following Rush Creek’s in-service date. The wind generation facility is anticipated to be in service in October 2018.
Colorado Energy Plan (CEP) — In 2016, PSCo filed its 2016 Electric Resource Plan (ERP) which included the estimated need for additional generation resources through spring of 2024. In 2017, PSCo filed an updated capacity need with the CPUC of 450 MW in 2023.
In August 2017, PSCo and various other stakeholders filed a stipulation agreement proposing the CEP, an alternative plan that increases the amount of new resources sought under the ERP. The CEP would increase PSCo’s potential capacity need up to 1,110 MW due to the proposed retirement of two coal units. The major components include:
Early retirement of 660 MWs of coal-fired generation at Comanche Units 1 (2022) and 2 (2025);
Accelerated depreciation for the early retirement of the two Comanche units and establishment of a regulatory asset to collect the incremental depreciation expense and related costs;
A RFP for up to 1,000 MW of wind, 700 MW of solar and 700 MW of natural gas and/or storage;
Utility ownership targets of 50 percent renewable generation resources and 75 percent of natural gas-fired, storage, or renewable with storage generation resources;
Reduction of the RESA rider, from two percent to one percent effective beginning 2021 or 2022; and
Construction of a new transmission switching station to further the development of renewable generating resources.
Hearings were held in February 2018 with two parties opposing both the coal retirements and utility ownership. Fifteen parties in the proceeding support the CEP. The CPUC is expected to rule on the stipulation agreement in March 2018. PSCo is currently evaluating bids from a RFP and anticipates filing its recommended portfolios in April 2018. A CPUC decision on the recommended portfolio is anticipated in the summer of 2018.
Boulder, Colorado Municipalization — In 2011, in the City of Boulder, Colorado (Boulder), voters passed a ballot measure authorizing the formation of an electric municipal utility, subject to certain conditions. Since that time, there have been various legal proceedings in multiple venues with jurisdiction over Boulder’s plan. In 2014, the Boulder City Council passed an ordinance to establish an electric utility. PSCo challenged the formation of this utility as premature and the Colorado Court of Appeals ruled in PSCo’s favor, vacating a lower court decision. Subsequently, the Colorado Supreme Court granted Boulder’s petition to review the Court of Appeals decision and oral arguments were held on Feb. 14, 2018. A ruling on the petition is anticipated in 2018.
In 2015, the Boulder District Court (District Court) affirmed a prior CPUC decision that Boulder cannot serve customers outside its city limits; these customers were included in Boulder’s plan at the time. The District Court also ruled the CPUC has jurisdiction over the transfer of any facilities to Boulder and in determining how the systems are separated. Further, the District Court found that the CPUC must give approval before Boulder files any condemnation proceeding. Boulder does not have authorization to initiate a condemnation proceeding at this time.
Boulder has filed multiple separation applications, the most recent one being in May 2017, which was challenged by PSCo and other intervenors. In September 2017, the CPUC issued a written decision, agreeing with several key aspects of PSCo’s position, stating PSCo is not required to undertake many of Boulder’s proposals, such as acting as a financier and contractor for Boulder. Additionally, the CPUC approved the designation of some electrical distribution assets for transfer, subject to Boulder completing certain items, including:
Filing an agreement between Boulder and PSCo providing permanent rights for PSCo to place and access facilities in Boulder needed to continue to serve its customers;
Filing a complete and accurate revised list of distribution assets desired to be transferred; and
Filing an agreement to address payments from Boulder to PSCo for costs of Boulder’s municipalization efforts.
Boulder has requested that the CPUC grant an extension through March 13, 2018 to complete such filings. Once those filings have been submitted, additional hearings may be held.
In November 2017, Boulder voters passed certain measures regarding Boulder’s pursuit of municipalization, including an extension and increase of the Utility Occupational Tax for funding Boulder’s exploration of municipalization.
MWTG — PSCo, along with nine other electric service providers from the Rocky Mountain region, have been considering creating and operating a joint transmission tariff to increase wholesale market efficiency and improve regional transmission planning. In September 2017, the MWTG determined that membership in the SPP RTO could provide opportunities to reduce customer costs, and maximize resource and electric grid utilization. In October 2017, the MWTG commenced negotiations with SPP through the SPP public stakeholder process.
SPP’s Board of Directors and organizational groups have begun to address the MWTG’s proposed terms for integration into the SPP RTO. Should the MWTG decide to move forward, SPP would make filings with the FERC and PSCo would make filings with the CPUC and the FERC, in the later part of 2018. If approved, MWTG operations within the SPP RTO would not be expected to begin until late 2019 at the earliest. PSCo recently engaged a consultant to conduct an analysis of the benefits associated with membership in the SPP RTO. The analysis assumed gas price forecasts that are lower than gas price forecasts used by the other MWTG utilities in their analysis of the benefits associated with membership in the SPP RTO. PSCo is in the process of evaluating that analysis.
Fuel Supply and Costs
The following table shows the delivered cost per MMBtu of each significant category of fuel consumed for owned electric generation, the percentage of total fuel requirements represented by each category of fuel and the total weighted average cost of all fuels.
|
| | | | | | | | | | | | | | | | | | |
| | | Coal | | Natural Gas | | Weighted Average Owned Fuel Cost |
| PSCo Generating Plants | | Cost | | Percent | | Cost | | Percent | |
| 2017 | | $ | 1.56 |
| | 70 | % | | $ | 3.82 |
| | 30 | % | | $ | 2.25 |
|
| 2016 | | 1.75 |
| | 72 |
| | 3.79 |
| | 28 |
| | 2.33 |
|
| 2015 | | 1.75 |
| | 75 |
| | 3.89 |
| | 25 |
| | 2.29 |
|
See Items 1A and 7 for further discussion of fuel supply and costs.
Fuel Sources
Coal— PSCo normally maintains approximately 35 - 50 days of coal inventory. Coal supply inventories at Dec. 31, 2017 and 2016 were approximately 48 and 36 days of usage, respectively. PSCo has contracted for coal supply to provide 75 percent of its 9.1 million tons of estimated coal requirements in 2018, and a declining percentage of requirements in subsequent years. PSCo’s general coal purchasing objective is to contract for approximately 75 percent of requirements for the first year, 40 percent of requirements in year two, and 20 percent of requirements in year three. Remaining requirements will be filled through the procurement process or over-the-counter transactions.
PSCo has coal transportation contracts that provide for delivery of 100 percent its coal requirements in 2018 and 2019. Coal delivery may be subject to interruptions or reductions due to operation of the mines, transportation problems, weather and availability of equipment.
Natural gas— PSCo uses both firm and interruptible natural gas supply in combustion turbines and certain boilers. Natural gas supplies for PSCo’s power plants are procured under contracts to provide an adequate supply of fuel. However, as natural gas primarily serves intermediate and peak demand, any remaining forecasted requirements are able to be procured through a liquid spot market. The majority of natural gas supply under contract is covered by a long-term agreement with Anadarko Energy Services Company and the balance of natural gas supply contracts have variable pricing features tied to changes in various natural gas indices. PSCo hedges a portion of that risk through financial instruments. See Note 10 to the consolidated financial statements for further discussion.
Most transportation contract pricing is based on FERC approved transportation tariff rates. Certain natural gas supply and transportation agreements include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery.
At Dec. 31, 2017, PSCo’s commitments related to gas supply contracts, which expire between 2021 through 2023, were approximately $545 million and commitments related to gas transportation and storage contracts, which expire between 2018 through 2040, were approximately $620 million.
At Dec. 31, 2016, PSCo’s commitments related to gas supply contracts were approximately $654 million and commitments related to gas transportation and storage contracts were approximately $573 million.
PSCo has limited on-site fuel oil storage facilities and primarily relies on the spot market for incremental supplies.
Renewable Energy Sources
PSCo’s renewable energy portfolio includes wind, hydroelectric, biomass and solar power from both owned generating facilities and PPAs. As of Dec. 31, 2017, PSCo was in compliance with mandated RPS, which requires generation from renewable resources of 20.0 percent of electric retail sales.
Renewable energy as a percentage of PSCo’ total energy:
|
| | | | | | |
| | | 2017 | | 2016 |
| Renewable | | 27.7 | % | | 28.3 | % |
| Wind | | 23.7 |
| | 23.7 |
|
| Hydroelectric, biomass and solar | | 3.9 |
| | 4.6 |
|
PSCo also offers customer-focused renewable energy initiatives. Windsource allows customers to purchase electricity from renewable sources. The number of customers utilizing Windsource increased to approximately 50,000 in 2017 from 46,000 in 2016.
Additionally, to encourage the growth of solar energy on the system, customers are offered incentives to install solar panels on their homes and businesses under the Solar*Rewards® program. Over 34,900 PV systems with approximately 310 MW of aggregate capacity have been installed in Colorado as of Dec. 31, 2017 and over 32,500 PV systems with approximately 276 MW of aggregate capacity were installed as of Dec. 31, 2016. Additionally, 33 community solar gardens with 33.5 MW of capacity have been completed in Colorado as of Dec. 31, 2017.
Wind— PSCo acquires the majority of its wind energy from PPAs. Currently, PSCo has 18 of these agreements in place, with facilities ranging in size from two MW to over 300 MW.
PSCo had approximately 2,560 MW of wind energy on its system at the end of 2017 and 2016. In addition to receiving purchased wind energy under these agreements, PSCo typically receives wind RECs which are used to meet state renewable resource requirements.
The average cost per MWh of wind energy under these contracts was approximately $42 in 2017 and 2016. The cost per MWh of wind energy varies by contract and may be influenced by a number of factors including regulation, state-specific renewable resource requirements, and the year of contract execution. Generally, previously executed contracts continued to benefit from improvements in wind technology, excess capacity among manufacturers, and motivation to commence new construction prior to the anticipated expiration of the federal PTCs. In December 2015, the federal PTCs were extended through 2019 with a phase down on sites that began construction in 2017.
WholesaleCapability and Commodity Marketing OperationsDemand
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:
| | | | | | | | | | | | | | | | | | | | |
| 2023 | | 2022 |
| MMBtu | | Date | | MMBtu | | Date |
| 2,190,155 | | | Jan. 30 | | 2,243,552 | | | Dec. 22 |
Natural Gas Supply and Cost
PSCo seeks natural gas supply, transportation and storage alternatives to yield a diversified portfolio, which increases flexibility, decreases interruption, financial risks and economical rates. In addition, PSCo conducts various wholesale marketingnatural gas price hedging activities approved by its state’s commissions.
Average delivered cost per MMBtu of natural gas for regulated retail distribution:
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 warmer in the winter and cooler in the summer. Decoupling mechanisms mitigate the impacts of weather in certain jurisdictions. PSCo’s electric decoupling mechanism expired in September.
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 the purchasesolar generation 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 and sharing of any margins is determined through state regulatory proceedings as well as the operationcan 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 approved JOA. has continued to promote competitive wholesale markets through open access transmission and other means. PSCo’s wholesale customers can purchase energy from competing generation resources and transmission services from other service providers to serve their native load.
FERC Order No. 1000 established competition for ownership of certain new electric transmission facilities under Federal regulations. Some states have state 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 adoption, however implementation is expected to vary by RTO/ISO and the near, medium, and long-term impacts of Order 2222 remain unclear.
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 further discussion.discussion of public utility regulation.
Environmental Regulation
Summary of Recent Federal Regulatory Developments
The FERC has jurisdiction over rates for electric transmission service in interstate commerceOur facilities are regulated by federal and electricity sold at wholesale, hydro facility licensing, natural gas transportation, asset transactions and mergers, accounting practices and certain other activities of PSCo, including enforcement of NERC mandatory electric reliability standards. State and localstate agencies that have jurisdiction over manyair emissions, water quality, wastewater discharges, solid 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 PSCo’s activities,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 what additional facilities or modifications to 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 historic and current operating sites and other 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
Power Plant Greenhouse Gas Regulations— In May 2023, the EPA published proposed rules addressing control of CO2 emissions from the power sector. The rule proposed regulations for new natural gas generating units and emission guidelines for existing coal and certain natural gas generation. The proposed rules create subcategories of coal units based on planned retirement date and subcategories of natural gas combustion turbines and combined cycle units based on utilization. The CO2 control requirements vary by subcategory. Until final rules are issued, it is not certain what the impact will be on PSCo. PSCo believes that the cost of these initiatives or replacement generation would be recoverable through rates based on prior state commission practices.
Coal Ash Regulation
In May 2023, the EPA published proposed rules to regulate legacy CCR surface impoundments at inactive facilities and previously exempt areas where CCR was placed directly on land at regulated CCR facilities under the CCR Rule for the first time. The proposed rule would subject these areas to the CCR Rule requirements, including regulationgroundwater monitoring, corrective action, closure, and post-closure care requirements, among other requirements, with several of retailthe deadlines accelerated.
The EPA has committed to a May 2024 publication date for those new rules. It is also anticipated that the EPA may issue other CCR proposed rules in 2024 and 2025 that further expand the scope of the CCR Rule. Until final rules are issued, it is not certain what the impact will be on PSCo. PSCo. believes that the cost of these initiatives would be recoverable through rates based on prior state commission practices.
Emerging Contaminants of Concern
PFAS are man-made chemicals that are widely used in consumer products and environmental matters.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 designate two types of PFAS as “hazardous substances” under the CERCLA. In March 2023, the EPA published a proposed rule that would establish enforceable drinking water standards for certain PFAS chemicals.
Final rules are expected in 2024. Costs are uncertain until a final rule is published.
The proposed rules could result in new obligations for investigation and cleanup. PSCo is monitoring changes to state laws addressing PFAS. The impact of these proposed regulations is uncertain.
Effluent Limitation Guidelines
In March 2023, the EPA released a proposed rule under the Clean Water Act, setting forth proposed Effluent Limitations Guidelines and Standards for steam generating coal plants. This proposed rule establishes more stringent wastewater discharge standards for bottom ash transport water, flue-gas desulfurization wastewater, and combustion residuals leachate from steam electric power plants, particularly coal-fired power plants. The impact of these proposed regulations is uncertain until a final rule is published.
Other
Our operations are subject to 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 matters discussed below, see Note 11 to the accompanying consolidatedeffects of compliance on our operations, financial statements for a discussioncondition or cash flows are material.
As of other regulatory matters.Dec. 31, 2023, PSCo had 2,352 full-time employees and ten part-time employees, of which 1,878 were covered under collective-bargaining agreements.
Xcel Energy, which includes PSCo, attemptsis subject to mitigatea 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 regulatory penaltiesthe 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.
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 have responsibility for overseeing the identification and mitigation of key risks.
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 Code of Conduct and compliance policies, operation of formal risk management structures and overall business management. PSCo further mitigates inherent risks through formal training on prohibited practicesrisk committees and acorporate 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 function that reviews interactionwith 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 markets under FERCBoard of Directors and CFTC jurisdictions. Public campaignsits 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 conducted to raise awarenessmaterial, 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 publicBoard of Directors’ governance of PSCo. Processes are in place to confirm 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 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 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 supplies.
•Impact of adverse weather conditions and natural disasters, including, tornadoes, avalanches, icing events, floods, high winds and droughts.
•Performance below expected or contracted levels of output or 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 issuesin design, construction, testing, operation, maintenance and emergency response of interacting with our electric systems. Whilenatural 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 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 utility sector is undergoing significant change (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.
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. New data centers and crypto mining facilities could generate significant increase in demand. Higher 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 require inputs such as coal, natural gas and water. 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. 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 and the potential for project cancellation. Failure to adhere to project budgets and timelines could adversely impact 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.
A significant increase in fuel costs could cause a decline in customer demand, adverse regulatory outcomes and an increase in bad debt expense 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 alternatives at potentially higher costs. Additionally, supply shortages may not be fully resolved, which negatively 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 negatively impacts 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 passed through to customer bills could impact our ability to recover costs for other improvements and operations.
Due to the 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. If such programs 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.
The competition for talent has become increasingly prevalent, and we have experienced increased employee turnover due to the condition of the labor market and decisions related to strategic workforce planning. In addition, specialized knowledge and skills are required for many of our positions, which may pose additional difficulty for us as we work to recruit, retain and motivate employees in this climate.
Failure to hire, adequately train replacement employees, transfer knowledge/expertise 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 impact our results of operations, financial condition or cash flows.
Our businesses have collective bargaining agreements with labor unions. Failure to renew or renegotiate these contracts could lead to labor disruptions, including strikes or boycotts. Such disruptions or any negotiated wage or benefit increases could have a material adverse impact to our results of operations, financial condition or cash flows.
National unionization efforts could affect our business, as an increase in unionized workers could challenge our operational efficiency and increase costs.
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 compliance with our Code of Conduct and are required to participate in place,annual training. Additionally, suppliers are subject to compliance 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. 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 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 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 for these types of changes, there is no guaranteeassurance that regulators would allow full recovery of all remaining costs.
Higher than expected inflation or tariffs may increase costs of construction and operations. Also, rising fuel costs could increase the compliance programsrisk that we will not be able to fully recover our fuel costs from our customers.
Adverse regulatory rulings (including changes in recovery mechanisms) or other measures willthe 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 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.
Our credit ratings are subject to change and our credit ratings may be sufficientlowered 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 ensure against violations.
Public Utility Regulatory Policies Act (PURPA) Enforcement Complaint against CPUC —In December 2016, Sustainable Power Group, LLC (sPower) petitioned the FERC to initiate an enforcement action in federal court against the CPUC under PURPA. The petition asserts that a December 2016 CPUC ruling, which indicated that a qualifying facility must be a successful bidderequity ratios and impacts of tax policy may impact our cash flows and credit metrics, potentially resulting in a PSCo resource acquisition bidding process, violated PURPA and FERC rules.change in our credit ratings. In January 2017, PSCo filed a motion to intervene and protest, arguing that the FERC should decline the petition. The CPUC filed a similar pleading. sPower has proposed to construct 800 MW of solar generation and 700 MW of wind generation in Colorado and seeks to require PSCo to contract for these resources under PURPA.
If sPower were to prevail, PSCo’s ability to select generation resources through competitive bidding would be negatively affected. However, due to a lack of quorum at the FERC, the FERC did not act on that petition within the sixty days contemplated by PURPA. Subsequently sPower filed a complaint for declaratory and injunctive relief in the United States District Court for the District of Colorado (District Court) requesting that the court find the bidding requirement in the CPUC qualifying facility rules to be unlawful. PSCo intervened in that proceeding and the CPUC filed a motion to dismiss. In June 2017, the United States Magistrate Judge issued a recommendation to the District Court that sPower’s complaint be dismissed because sPower failed to establish that it faced a substantial risk of harm. In October 2017, the District Court denied the CPUC’s motion to dismiss and instead allowed sPower to file an amended complaint. The case effectively started over and PSCo intervened. The CPUC filed a motion to dismiss the amended complaint which is currently pending before the District Court. The timing of a resolution in this case is unclear.
Electric Operating Statistics
Electric Sales Statistics |
| | | | | | | | | | | | |
| | Year Ended Dec. 31 | |
| | 2017 | | 2016 | | 2015 | |
| Electric sales (Millions of KWh) | | | | | | |
| Residential | 9,107 |
| | 9,272 |
| | 9,112 |
| |
| Large commercial and industrial | 6,449 |
| | 6,371 |
| | 6,596 |
| |
| Small commercial and industrial | 12,796 |
| | 12,890 |
| | 12,750 |
| |
| Public authorities and other | 274 |
| | 268 |
| | 242 |
| |
| Total retail | 28,626 |
| | 28,801 |
| | 28,700 |
| |
| Sales for resale | 4,851 |
| | 4,672 |
| | 3,581 |
| |
| Total energy sold | 33,477 |
| | 33,473 |
| | 32,281 |
| |
| | | | | | | |
| Number of customers at end of period | | | | | | |
| Residential | 1,252,376 |
| | 1,235,378 |
| | 1,218,662 |
| |
| Large commercial and industrial | 340 |
| | 337 |
| | 337 |
| |
| Small commercial and industrial | 160,406 |
| | 159,299 |
| | 158,086 |
| |
| Public authorities and other | 54,110 |
| | 54,048 |
| | 53,944 |
| |
| Total retail | 1,467,232 |
| | 1,449,062 |
| | 1,431,029 |
| |
| Wholesale | 43 |
| | 34 |
| | 26 |
| |
| Total customers | 1,467,275 |
| | 1,449,096 |
| | 1,431,055 |
| |
| | | | | | | |
| Electric revenues (Thousands of Dollars) | | | | | | |
| Residential | $ | 1,033,324 |
| | $ | 1,063,526 |
| | $ | 1,060,626 |
| |
| Large commercial and industrial | 421,068 |
| | 414,797 |
| | 433,061 |
| |
| Small commercial and industrial | 1,227,886 |
| | 1,204,881 |
| | 1,220,064 |
| |
| Public authorities and other | 52,834 |
| | 54,070 |
| | 52,783 |
| |
| Total retail | 2,735,112 |
| | 2,737,274 |
| | 2,766,534 |
| |
| Wholesale | 167,971 |
| | 152,375 |
| | 180,716 |
| |
| Other electric revenues | 100,725 |
| | 159,703 |
| | 168,007 |
| |
| Total electric revenues | $ | 3,003,808 |
| | $ | 3,049,352 |
| | $ | 3,115,257 |
| |
| | | | | | | |
| KWh sales per retail customer | 19,510 |
| | 19,876 |
| | 20,055 |
| |
| Revenue per retail customer | $ | 1,864 |
| | $ | 1,889 |
| | $ | 1,933 |
| |
| Residential revenue per KWh | 11.35 |
| ¢ | 11.47 |
| ¢ | 11.64 |
| ¢ |
| Large commercial and industrial revenue per KWh | 6.53 |
| | 6.51 |
| | 6.57 |
| |
| Small commercial and industrial revenue per KWh | 9.60 |
| | 9.35 |
| | 9.57 |
| |
| Total retail revenue per KWh | 9.55 |
| | 9.50 |
| | 9.64 |
| |
| Wholesale revenue per KWh | 3.46 |
| | 3.26 |
| | 5.05 |
| |
|
| | | | | | | | | | | | | | | | | |
| | Year Ended Dec. 31 |
| | 2017 | | 2016 | | 2015 |
| | Millions of KWh | | Percent of Generation | | Millions of KWh | | Percent of Generation | | Millions of KWh | | Percent of Generation |
| Coal | 14,609 |
| | 44 | % | | 15,895 |
| | 47 | % | | 18,601 |
| | 54 | % |
| Natural Gas | 9,195 |
| | 28 |
| | 8,632 |
| | 25 |
| | 7,948 |
| | 23 |
|
Wind (a) | 7,804 |
| | 24 |
| | 8,106 |
| | 24 |
| | 6,699 |
| | 19 |
|
| Hydroelectric | 624 |
| | 2 |
| | 1,179 |
| | 3 |
| | 662 |
| | 2 |
|
Other (b) | 670 |
| | 2 |
| | 393 |
| | 1 |
| | 705 |
| | 2 |
|
| Total | 32,902 |
| | 100 | % | | 34,205 |
| | 100 | % | | 34,615 |
| | 100 | % |
| |
|
| |
|
| | | | | | | | |
| Owned generation | 23,053 |
| | 70 | % | | 22,753 |
| | 67 | % | | 22,981 |
| | 66 | % |
| Purchased generation | 9,849 |
| | 30 |
| | 11,452 |
| | 33 |
| | 11,634 |
| | 34 |
|
| Total | 32,902 |
| | 100 | % | | 34,205 |
| | 100 | % | | 34,615 |
| | 100 | % |
| |
(a)
| This category includes wind energy de-bundled from RECs and also includes Windsource RECs. PSCo uses RECs to meet or exceed state resource requirements and may sell surplus RECs. |
| |
(b)
| Distributed generation from the Solar*Rewards program is not included, and was approximately 393, 396 and 245 million net KWh for 2017, 2016, and 2015, respectively. |
NATURAL GAS UTILITY OPERATIONS
Overview
PSCo operates a natural gas local distribution company in Colorado. The most significant developments in the natural gas operations of PSCo are uncertainty regarding political and regulatory developments that impact hydraulic fracturing, safety requirements for natural gas pipelines and the continued trend of declining use per residential and small C&I customer,addition, our credit ratings may change as a result of improved building construction technologies,the differing methodologies or change in the methodologies used by the various rating agencies.
Any credit ratings downgrade could lead to higher appliance efficiencies,borrowing costs or 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 conservation. From 2000interest rate risks.
Utility operations require significant capital investment. As a result, we frequently need to 2017, average annual salesaccess 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 commercial paper, issuing new securities or cause us to issue securities with unfavorable terms and conditions, such as higher interest 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 cash flow and 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., SPP, Midcontinent Independent System Operator, Inc. 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 Investor Services 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 typicalcapital 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, 2023, Xcel Energy Inc. and its utility subsidiaries had approximately $24.9 billion of long-term debt and $1.3 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, 2023, Xcel Energy had the following guarantees outstanding:
•$951 million for performance and payment of Capital Services, LLC contracts for wind and solar generating equipment, with immaterial exposure.
•$100 million for performance on tax credit sale agreements of its subsidiaries, with immaterial exposure.
•$75 million 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.
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 residentialwould 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 declined 17 percent, while costs. Tax depreciable lives and the value/availability of various tax credits or the timeliness of their utilization may impact the economics or selection of resources. 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 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.
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.
The oil and gas industry represents our largest commercial and industrial customer base. Oil and natural gas prices are sensitive to market risk factors which may impact demand.
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.
Health epidemics impact countries, communities, supply chains and markets. Uncertainty continues to exist regarding epidemics; the duration and magnitude of business restrictions 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 generalized impact on the economy.
We cannot ultimately predict whether an epidemic will have a material impact on our future liquidity, financial condition or results of operations. Nor can we predict the impact on the health of our employees, our supply chain or our ability to recover higher costs associated with managing 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 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, 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. While we have business continuity plans in place, our ability to recover may be prolonged due to the typical small C&Itype 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, 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.
A cybersecurity 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 Company data, customer declined 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 cybersecurity incidents, including those caused by human error.
The utility industry has been the target of several attacks on operational systems and has seen an increased volume and sophistication of cybersecurity incidents from international activist organizations, other 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.
Cybersecurity incidents could harm our businesses by limiting our generation, transmission and distribution 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 cybersecurity incident on 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.
Generative Artificial Intelligence, such as large language models like ChatGPT, present a range of challenges and potential risks as we consider impacts to the business. These challenges involve navigating the complexities of creating and deploying AI models that generate content autonomously. Data privacy, legal concerns, and security issues are all risks as this technology continues to be adopted.
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 cybersecurity threats or subsequent related actions. Cybersecurity incidents and regulatory action could result in a material decrease in revenues and may causesignificant 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 cybersecurity 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 cybersecurity 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 weather‑normalized basis. Although wholesale price increases do not directly affect earnings becauseseasonal 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 cost recovery mechanisms, high pricesrevenues 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 encourage further efficiencyimpose 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, cybersecurity 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 bymay 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.
Pipeline Safety Act — The Pipeline Safety, Regulatory Certainty,Environmental Policy Risks
We may be subject to legislative and Job Creation Act (Pipeline Safety Act) requiresregulatory 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 verification of pipeline infrastructure recordsregulation 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 pipeline owners and operators to confirm the maximum allowable operating pressure of lines located in high consequence areas or more-densely populated areas. In April 2016, the PHMSA released proposed rules that address this verification requirement alongall countries, with a numbergoal 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.
International commitments and agreements could result in future additional GHG reductions in the United States. In addition, in 2023 the EPA intends to publish draft regulations for GHG emissions from the power sector consistent with the 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 and 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 changesand 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 gas transmission regulations. These changes include requirements around userecover all or a part of automaticthe cost of capital investment or remote-controlled shut-off valves, testing of certain previously untested transmission lines and expanding integrity management requirements. The Pipeline Safety Act also includes a maximum penalty for violating pipeline safety rules of $2 million per day for related violations.
PHMSA is currently working through the rule with its Pipeline Advisory Committee. Current estimates are the rule will likely go into effect in late 2018 or early 2019.
PSCo has been taking actions that were intendedO&M costs incurred to comply with the Pipeline Safety Actmandates, it could have a material effect on our results of operations, financial condition or cash flows.
We are subject to environmental laws and any related PHMSA regulations, as they become effective. PSCowith 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 generallyalso 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 distribution integrity management programsinfrastructure. 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 PSIA rider.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.
Public Utility RegulationSevere 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 and result in more frequent service interruptions. Periods of extreme temperatures could also impact our ability to meet demand.
SummaryMore frequent and severe drought conditions, extreme swings in amount and timing of Regulatory Agenciesprecipitation, changes in vegetation, unseasonably warm temperatures, very low humidity, stronger winds and Areasother factors have increased the duration of Jurisdiction—the wildfire season and the potential impact of an event. Also, the expansion of the wildland urban interface increases the wildfire risk to surrounding communities and PSCo's electric and natural gas infrastructure.
Other potential risks associated with wildfires and other climate events 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.
| | |
| ITEM 1B — UNRESOLVED STAFF COMMENTS |
None.
PSCo is regulateda wholly owned subsidiary of Xcel Energy. As such, its cybersecurity processes are maintained by Xcel Energy management and governed by its Board of Directors.
As described in Item 1A – Risk Factors, Xcel Energy operates in an industry that requires the continued operation of sophisticated information technology, control systems and network infrastructure, as such, our business is subject to the risk of interruption by cybersecurity incidents that range from attacks common to most industries, such as phishing and denial-of-service, to attacks from more sophisticated adversaries, including nation state actors, that target the critical infrastructure used in the operation of our business.
Xcel Energy has a security risk program in place to identify, assess, manage and report material risks from cybersecurity incidents. As a utility provider, Xcel Energy complies with reliability standards imposed by NERC, including critical infrastructure protection standards related to both cybersecurity and physical security. These standards imposed by NERC, in alignment with the NIST Cybersecurity Framework, are the basis for which Xcel Energy has designed the cybersecurity control framework within its security risk program.
Annually, as part of Xcel Energy’s enterprise risk program, an integrated cybersecurity risk identification and assessment is completed across Xcel Energy’s business, including generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets as well as information processed in our systems (including systems hosted by third parties) that could be affected by cybersecurity incidents. This analysis includes the impact, likelihood, timeframe and controllability of cybersecurity risks and is presented to the Board of Directors. Management monitors and reviews the results of this analysis, integrating them into the enterprise risk assessment processes and implements appropriate mitigating actions as needed.
Xcel Energy’s cybersecurity policies, standards, practices and readiness are regularly assessed by third-party consultants. These partners are engaged to perform independent penetration testing and other security related services to assist in the prevention, detection, monitoring, mitigation and remediation of cybersecurity incidents and risks. The results of these assessments are communicated to management and the Board of Directors by the CPUC with respectChief Security Officer.
Xcel Energy employs a comprehensive risk based approach to its facilities, rates, accounts, servicesassess the magnitude and issuancesignificance of securities. PSCo holds a FERC certificate that allows itvendor’s risk to transport natural gas in interstate commerce without PSCo becomingXcel Energy. Certain third-party service providers are subject to full FERC jurisdiction undervendor security risk assessments at the Federal Natural Gas Act.time of integration, contract execution/renewal, and upon detection of any increase in risk profile. Xcel Energy uses a variety of inputs in such risk assessments, including information supplied by providers and third parties (including information analysis centers that share daily threat intelligence and improve organizational agility associated with management of cybersecurity risks). In addition, Xcel Energy requires certain third-party service providers to meet appropriate security requirements, controls and responsibilities. Xcel Energy deploys periodic monitoring activities to assess compliance with our cybersecurity control framework and investigates security incidents that have impacted our third-party service providers as appropriate.
Management has assigned responsibility for the security risk program to the Chief Security Officer who has extensive experience in critical infrastructure protection, including multiple years of experience with the Department of Defense. The Chief Security Officer is informed about and monitors prevention, detection, mitigation and remediation efforts through a team of security professionals, many of whom are Certified Information Systems Security Professionals, Certified Information Security Managers or have received other cybersecurity certifications. The team has extensive experience selecting, deploying and operating cybersecurity technologies, initiatives and processes that aid in preventing, remediating and mitigating known and unknown cybersecurity threats.
The Chief Security Officer or members of management brief the Board on routine and regular cybersecurity risk and threat updates, typically on a quarterly basis. In the event of a significant threat or incident, management and the Chief Security Officer leverage Xcel Energy’s incident response processes to assess impacts and resolve incidents. When a significant cybersecurity incident occurs, management communicates with the Board of Directors and relevant committees.
The Board of Directors oversees the risks associated with cybersecurity and the physical security of our assets, with information security matters being discussed at each regular board meeting as well as at the ONES and Audit Committee meetings throughout the year.
While the ONES Committee has primary committee responsibility for cybersecurity due to the operational issues involved, the Board of Directors has determined that the topic is of sufficient importance to warrant this comprehensive oversight approach. Augmenting such oversight efforts, the Board conducts drills to practice its response in a possible emergency situation to ensure it is well prepared and positioned to perform in a possible crisis.
Cybersecurity risks are a part of Xcel Energy’s normal course of business. To date, no cybersecurity incident or attack has had a material impact on our business or results of operations. As of Feb. 21, 2024 there have been no material cybersecurity incidents to report.
Virtually all of the utility plant property of PSCo is subject to the DOTlien of its first mortgage bond indenture.
| | | | | | | | | | | | | | | | | | | | | | | |
| Station, Location and Unit at Dec. 31, 2023 | | Fuel | | Installed | | MW (a) | |
| Steam: | | | | | | | |
| Comanche-Pueblo, CO | | | | | | | |
| Unit 2 | | Coal | | 1975 | | 330 | | |
| Unit 3 | | Coal | | 2010 | | 500 | | (b) |
| Craig-Craig, CO, 2 Units | | Coal | | 1979 - 1980 | | 82 | | (c) |
| Hayden-Hayden, CO, 2 Units | | Coal | | 1965 - 1976 | | 233 | | (d) |
| Pawnee-Brush, CO, 1 Unit | | Coal | | 1981 | | 505 | | |
| Cherokee-Denver, CO, 1 Unit | | Natural Gas | | 1968 | | 310 | | |
| Combustion Turbine: | | | | | | | |
| Blue Spruce-Aurora, CO, 2 Units | | Natural Gas | | 2003 | | 264 | | |
| Cherokee-Denver, CO, 3 Units | | Natural Gas | | 2015 | | 576 | | |
| Fort St. Vrain-Platteville, CO, 6 Units | | Natural Gas | | 1972 - 2009 | | 1,022 | | |
| Manchief, CO, 2 Units . | | Natural Gas | | 2000 | | 250 | | |
| Rocky Mountain-Keenesburg, CO, 3 Units | | Natural Gas | | 2004 | | 592 | | |
| Various locations, 8 Units | | Natural Gas | | Various | | 247 | | |
| Hydro: | | | | | | | |
| Cabin Creek-Georgetown, CO | | | | | | | |
| Pumped Storage, 2 Units | | Hydro | | 1967 | | 210 | | |
| Various locations, 6 Units | | Hydro | | Various | | 23 | | |
| Wind: | | | | | | | |
| Rush Creek, CO, 300 units | | Wind | | 2018 | | 582 | | (e) |
| Cheyenne Ridge, CO, 229 units | | Wind | | 2020 | | 477 | | (e) |
| | | | Total | | 6,203 | | |
(a)Summer 2023 net dependable capacity. Wind is presented as net maximum capacity.
(b)Based on PSCo’s ownership of 67%.
(c)Based on PSCo’s ownership of 10%.
(d)Based on PSCo’s ownership of 76% of Unit 1 and 37% of Unit 2.
(e)Net maximum capacity is attainable only when wind conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2023 the Company’s wind facilities had a weighted-average capacity factors of 43%.
Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2023:
| | | | | |
| Conductor Miles | |
| Transmission | |
| |
| 345 KV | 5,421 | |
| 230 KV | 12,244 | |
| |
| 138 KV | 92 | |
| 115 KV | 4,994 | |
| Less than 115 KV | 1,782 | |
| Total Transmission | 24,533 | |
| |
| Distribution | |
| Less than 115 KV | 80,176 | |
| |
| Total | 104,709 | |
PSCo had 235 electric utility transmission and distribution substations at Dec. 31, 2023.
Natural gas utility mains at Dec. 31, 2023:
| | | | | |
| Miles | |
| Transmission | 2,024 | |
| Distribution | 23,494 | |
| | |
| 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. Legal fees are generally expensed as incurred.
See Note 10 to the consolidated financial statements, Item 1 and Item 7 for further information.
| | |
| ITEM 4 — MINE SAFETY DISCLOSURES |
None.
PART II
| | |
| 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 2023 and 2022 were as follows:
| | | | | | | | | | | | | | |
| (Millions of Dollars) | | 2023 | | 2022 |
| First quarter | | $ | 183 | | | $ | 129 | |
| Second quarter | | 189 | | | 132 | |
| Third quarter | | 161 | | | 127 | |
| Fourth quarter | | 72 | | | 119 | |
| | |
| 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 CPUCresults 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 regardsGAAP, as well as certain non-GAAP financial measures such as ongoing earnings. Generally, a non-GAAP financial measure is a measure of a company’s financial performance, financial position or cash flows that is 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 pipeline safety compliance.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.
Earnings Adjusted for Certain Items (Ongoing Earnings)
Ongoing earnings reflect adjustments to GAAP earnings (net income) for certain items.
Purchased Natural GasWe use this non-GAAP financial measure to evaluate and Conservation Cost-Recovery Mechanismsprovide details of PSCo’s core earnings and underlying performance. For instance, to present ongoing earnings, we may adjust the related GAAP amounts for certain items that are non-recurring in nature. We believe this measurement is useful to investors to evaluate the actual and projected financial performance and contribution of our subsidiaries. This non-GAAP financial measure should not be considered as an alternative to measures calculated and reported in accordance with GAAP.
The following table provides a reconciliation of GAAP earnings (net income) to ongoing earnings:
| | | | | | | | | | | | | | |
| (Millions of Dollars) | | 2023 | | 2022 |
| GAAP net income | | $ | 695 | | | $ | 727 | |
| Loss on Comanche Unit 3 litigation | | 35 | | | — | |
| Workforce reduction expenses | | 20 | | | — | |
| Less: tax effect of adjustment | | (13) | | | — | |
| Ongoing earnings | | $ | 737 | | | $ | 727 | |
Comanche Unit 3 Litigation — In the third quarter of 2023, PSCo recognized a $34 million loss due to a jury verdict in Denver County District Court awarding CORE lost power damages and other costs. PSCo intends to file an appeal of this decision. Given the non-recurring nature of this specific item, it has retail adjustment clauses that recoverbeen excluded from ongoing earnings.
Workforce Reduction — In 2023, Xcel Energy implemented workforce actions to align resources and investments with our evolving business and customer needs, and streamline the organization for long-term success. Xcel Energy initiated a voluntary retirement program, under which approximately 400 eligible non-bargaining employees retired. Xcel Energy also eliminated approximately 150 non-bargaining employees through an involuntary severance program.
Total Xcel Energy workforce reduction expenses of $72 million were recorded in the fourth quarter of 2023, of which $20 million was attributable to PSCo. Given the non-recurring nature of this item, it has been excluded from ongoing earnings.
2023 Comparison to 2022
PSCo’s GAAP net income was $695 million for 2023, compared to $727 million for 2022. Ongoing net income was $737 million for 2023, compared to $727 million for 2022. Ongoing earnings primarily reflects higher recovery of infrastructure investment and lower O&M expenses, which were partially offset by increased depreciation, interest charges and unfavorable weather.
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 other resource costs: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 Purchased Power and Electric Margin
| | | | | | | | | | | | | | |
| (Millions of Dollars) | | 2023 | | 2022 |
| Electric revenues | | $ | 3,731 | | | $ | 3,795 | |
| Electric fuel and purchased power | | (1,364) | | | (1,485) | |
| Electric margin | | $ | 2,367 | | | $ | 2,310 | |
GCA — Recovers the actual costsChanges in Electric Margin
| | | | | | | | |
| (Millions of Dollars) | | 2023 vs. 2022 |
| Regulatory rate outcome | | $ | 56 | |
| Non-fuel riders | | 26 | |
| Wholesale transmission revenue (net) | | 6 | |
| Estimated impact of weather (net of decoupling) | | (23) | |
Sales and demand (a) | | (5) | |
| | |
| | |
| Other (net) | | (3) | |
| Total increase | | $ | 57 | |
(a)Sales excludes weather impact, net of purchasedpartial decoupling (mechanism expired in September).
Natural Gas Margin
Natural gas margin is presented as natural gas revenues less the cost of natural gas sold and transportationtransported. 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 generally have minimal earnings impact due to meetcost recovery mechanisms.
Natural Gas Revenues, Cost of Natural Gas Sold and Transported and Natural Gas Margin
| | | | | | | | | | | | | | |
| (Millions of Dollars) | | 2023 | | 2022 |
| Natural gas revenues | | $ | 1,734 | | | $ | 1,860 | |
| Cost of natural gas sold and transported | | (910) | | | (1,053) | |
| Natural gas margin | | $ | 824 | | | $ | 807 | |
Changes in Natural Gas Margin
| | | | | | | | |
| (Millions of Dollars) | | 2023 vs. 2022 |
| Regulatory rate outcomes | | 47 | |
| Estimated impact of weather | | $ | (12) | |
| | |
| | |
| | |
| | |
| Other (net) | | (18) | |
| Total increase | | $ | 17 | |
Non-Fuel Operating Expenses and Other Items
O&M Expenses — O&M expenses decreased $40 million in 2023. The decrease was primarily due to impact of management cost containment efforts, the requirementstiming of regulatory deferrals and the exit of our appliance repair services business, offset by the impact of inflationary pressures, including labor.
Depreciation and Amortization— Depreciation and amortization increased $76 million in 2023. The increase was primarily due to system expansion and new electric and natural gas depreciation rates.
Interest Charges — Interest expenses increased $41 million in 2023. The increase was largely due to increased long-term debt levels to fund capital investments and higher interest rates.
| | |
| 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. PSCo requests changes in utility rates through commission filings. Changes in operating costs can affect PSCo’s financial results, depending on the timing of rate cases 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 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 the SPP Western Energy Imbalance Service market, an energy imbalance market. |
| DOT | | Pipeline safety compliance. |
Recovery Mechanisms | | | | | | | | |
| Mechanism | | Additional Information |
| Colorado Energy Plan Adjustment | | Recovers the early retirement costs of Comanche Units 1 and 2 to a maximum of 1% of the customer’s bill. |
| Decoupling | | Mechanism to true-up revenue to a baseline amount for residential (excluding lighting and demand) and metered non-demand small C&I classes (pilot program ended Sept. 2023, with amortization of previously deferred amounts expected through 2026). |
| DSM Cost Adjustment | | Recovers electric and gas DSM, interruptible service costs and performance incentives for achieving energy savings goals. |
| ECA | | Recovers fuel and purchased energy costs. Short-term sales margins are shared with customers. The ECA is revised quarterly. |
| Fuel 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. |
| Purchased Capacity Cost Adjustment | | Recovers purchased capacity payments. |
| RES Adjustment | | Recovers the incremental costs of compliance with the RES with a maximum of 1% of the customer’s bill. |
| Steam Cost Adjustment | | Recovers fuel costs to operate the steam system. The Steam Cost Adjustment rate is revised quarterly. |
| Transmission Cost Adjustment | | Recovers costs between rate cases for transmission projects that result in a net increase in capacity or are part of an approved wildfire mitigation plan. |
| | |
| Transportation Electrification Plan | | Recovers costs associated with the investment in and adoption of transportation electrification infrastructure. |
| | |
Pending and Recently Concluded Regulatory Proceedings
Colorado Electric Rate Case — In 2022, PSCo filed a Colorado electric rate case seeking a revised net increase of $253 million. The total request reflected a $303 million increase, which includes $50 million of authorized costs previously recovered through various rider mechanisms. The request was based on a 10.25% ROE, an equity ratio of 55.7% and a 2023 forecast test year with a 2023 average rate base of $11.3 billion.
In September 2023, the CPUC approved a settlement between PSCo and various parties, which included the following terms:
•Retail revenue increase (excluding rider roll-ins) of $95 million (2.96%), based on a 2022 historic test year using year-end rate base with forward looking known and measurable adjustments.
•Weighted-average cost of capital of 6.95% (based on 55.69% equity ratio and 9.3% ROE).
•Termination of the revenue decoupling pilot.
•Continuation of previously authorized trackers and deferrals.
Rates became effective in September 2023.
Colorado Resource Plan— In August 2022, the CPUC approved a settlement for the Colorado Resource Plan, which provides for an expected carbon reduction and the retirement of PSCo’s remaining coal plant by the end of 2030.
In September 2023 (updated in October 2023), PSCo filed its recommended Preferred Portfolio of resources, which proposed a total of 7,521 MW of generation resources, including 4,716 owned MW and 2,805 purchased power MW. The filing also included several other alternative portfolios.
In December 2023, the CPUC approved an alternative portfolio of 5,835 MW. The decision provides an opportunity to assess timing and levels of incremental renewable resources in the Just Transition Plan filing expected to be submitted by June 1, 2024.
Approved portfolio includes the following resources:
| | | | | | | | | | | |
| Generation Resource (in MW) | Company Owned | PPAs | Total |
| Wind Resources | 1,325 | | 375 | | 1,700 | |
| Solar | 858 | | 760 | | 1,618 | |
| Storage | 500 | | 1,348 | | 1,848 | |
| Natural Gas | 450 | | 219 | | 669 | |
| Total | 3,133 | | 2,702 | | 5,835 | |
PSCo expects to invest approximately $4.8 billion in generation resources under the alternative portfolio for the benefit of its customers and achieving the state’s clean energy goals. The CPUC did not approve the May Valley to Longhorn Transmission Line, which was estimated at $250 million.
In December 2023, the CPUC approved two PIMs associated with the generation projects in the portfolio, including a two-way sharing measure related to capital construction costs and another related to ongoing levelized energy costs. These PIMs will be further defined in the written order and related proceedings throughout 2024.
In February 2024, PSCo filed an ARRR to seek approval for an updated portfolio, reflecting inclusion of certain back-up bids and clarifications of the application of PIMs.
Colorado Natural Gas Rate Case — In January 2024, PSCo filed a request with the CPUC seeking an increase to retail natural gas rates of $171 million, or an approximately 9.5% increase in the average residential customer bill. The request is based on a 2023 test year, a 10.25% ROE, an equity ratio of 55% and a $4.2 billion retail rate base which includes projected capital additions through Dec. 31, 2023.PSCo has requested a proposed effective date of Nov. 1, 2024.
PSCo has proposed to defer collection of the increased rates until Feb. 15, 2025 (following the expiration of the rider to recover Winter Storm Uri costs) to mitigate customer bill impacts, with revenues for the deferred period collected over a 12-month period beginning on that date.
The request supports fundamental infrastructure investments to serve customers, consistent with PSCo’s obligation to provide safe, reliable service while enabling PSCo to continue to be a leader of the clean energy transition in partnership with the CPUC to achieve clean heat goals.
| | | | | | |
| Revenue Request (millions of dollars) | | |
| Changes since 2022 rate case: | | |
Plant related investments(a) | | $ | 145 | |
| Operations and maintenance, amortization and other expenses | | 23 | |
| Property tax expense | | 10 | |
| Sales growth | | (7) | |
| | |
| | |
| | |
| Total base revenue request | | $ | 171 | |
| | |
| | |
(a)Includes approximately $32 million as a result of the increase in ROE from 9.2% to 10.25%.
ECA Fuel Recovery — In December 2022, PSCo filed to recover $123 million of under-recovered 2022 fuel costs over two quarters. 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 costs.
In 2023, PSCo submitted interim ECA filings to recover $70 million and $25 million, respectively, of the 2022 under-recovered costs.
In the third quarter, PSCo and CPUC Staff filed a settlement allowing for collection of the remaining amount, which after final adjustments was $37 million. In December 2023, the ALJ issued a recommended decision approving the settlement in full. Recovery of costs is revised quarterlyexpected to allowbegin in the second quarter of 2024.
Colorado Legislation — In May 2023, Colorado Senate Bill 23-291 passed and was signed into law. The bill includes a number of topics including natural gas and electric fuel incentive mechanisms, natural gas planning rules, regulatory filing requirements, and non-recovery of certain expenses (e.g., certain organizational or membership dues, tax penalties or fines).
In November 2023, the CPUC approved PSCo’s natural gas price risk management plan, establishing upper and lower limits for changes in naturalthe GCA rate. As a result costs above the upper limit are deferred for future recovery, with interest, and costs below the lower limit are deferred as a reserve against future cost increases.
The legislation also calls for the CPUC to adopt rules to establish fuel cost mechanisms to align the financial incentives of a utility with the interests of the utility’s customers by Jan. 1, 2025. The CPUC issued a request for initial comments on a potential mechanism under which gas rates.
utilities would share a percentage, subject to an annual cap, of cost changes in the GCA. A formal rulemaking is expected to commence in the first half of 2024.Purchased Power and Transmission Service Providers
DSMCAPSCo meets its system capacity and energy requirements through its fleet of owned and purchased electric generation resources and, when required, the use of demand-side management programs.
Purchased Power — Recovers costsPSCo purchases power from other utilities, energy marketers and independent power producers. Long-term purchased power contracts for dispatchable resources typically require capacity and energy charges. Much of DSMPSCo’s long-term purchased power is for wind, solar and performance initiativesstorage resources. PSCo makes short-term purchases to achieve variousmeet system load and energy savings goals.
requirements, replace generation out of service for maintenance, meet operating reserve obligations, or obtain energy at a lower cost.PSIAEnergy Markets — Recovers costs associatedPSCo joined the SPP Western Energy Imbalance Service Market in April 2023. This market is an incremental step in the participation in an organized wholesale market. Energy imbalance 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 and distribution pipeline integrity management programs and two projectsservice providers to replace large transmission pipelines.deliver energy to its customers.
Capability and Demand
Natural gas supply requirements are categorized as firm or interruptible (customers with an alternate energy supply). The maximum
Maximum daily send-outoutput (firm and interruptible) for PSCo was 1,948,167 MMBtu, which occurred on Jan. 5, 2017 and 1,932,070 MMBtu, which occurred on Dec. 17, 2016.occurrence date:
| | | | | | | | | | | | | | | | | | | | |
| 2023 | | 2022 |
| MMBtu | | Date | | MMBtu | | Date |
| 2,190,155 | | | Jan. 30 | | 2,243,552 | | | Dec. 22 |
PSCo purchases natural gas from independent suppliers, generally based on market indices that reflect current prices. The natural gas is delivered under transportation agreements with interstate pipelines. These agreements provide for firm deliverable pipeline capacity of approximately 1,818,151 MMBtu per day, which includes 854,852 MMBtu of natural gas held under third-party underground storage agreements. In addition, PSCo operates three company-owned underground storage facilities, which provide approximately 43,500 MMBtu of natural gas supplies on a peak day. The balance of the quantities required to meet firm peak day sales obligations are primarily purchased at PSCo’s city gate meter stations.
PSCo is required by CPUC regulations to file a natural gas purchase plan each year projecting and describing the quantities of natural gas supplies, upstream services and the costs of those supplies and services for the 12-month period of the following year. PSCo is also required to file a natural gas purchase report by October of each year reporting actual quantities and costs incurred for natural gas supplies and upstream services for the previous 12-month period.
Natural Gas Supply and Costs
Cost
PSCo actively seeks natural gas supply, transportation and storage alternatives to yield a diversified portfolio, that provides increasedwhich increases flexibility, decreaseddecreases interruption, and financial riskrisks and economical rates. In addition, PSCo conducts natural gas price hedging activities that have been approved by the CPUC.its state’s commissions.
The following table summarizes the averageAverage delivered cost per MMBtu of natural gas purchased for resale by PSCo’s regulated retail natural gas distribution business:distribution:
|
| | | |
| 2017 | $ | 3.45 |
|
| 2016 | 3.27 |
|
| 2015 | 3.92 |
|
The cost of natural gas in 2017 increased due to higher wholesale commodity prices.
PSCo has natural gas supply transportation and storage agreements that include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery. At Dec. 31, 2017, PSCo was committed to approximately $1.4 billion in such obligations under these contracts, which expire in various years from 2018 through 2029.
PSCo purchases natural gas by optimizing a balance of long-term and short-term natural gas purchases, firm transportation and natural gas storage contracts. During 2017, PSCo purchased natural gas from approximately 31 suppliers.
See Items 1A and 7 for further discussion of natural gas supply and costs.
Natural Gas Operating Statistics
|
| | | | | | | | | | | |
| | Year Ended Dec. 31 |
| | 2017 | | 2016 | | 2015 |
| Natural gas deliveries (Thousands of MMBtu) | | | | | |
| Residential | 88,843 |
| | 90,941 |
| | 92,001 |
|
| Commercial and industrial | 37,305 |
| | 38,093 |
| | 38,405 |
|
| Total retail | 126,148 |
| | 129,034 |
| | 130,406 |
|
| Transportation and other | 124,211 |
| | 117,462 |
| | 108,860 |
|
| Total deliveries | 250,359 |
| | 246,496 |
| | 239,266 |
|
| | | | | | |
| Number of customers at end of period | | | | | |
| Residential | 1,284,644 |
| | 1,269,338 |
| | 1,254,056 |
|
| Commercial and industrial | 100,802 |
| | 100,718 |
| | 100,389 |
|
| Total retail | 1,385,446 |
| | 1,370,056 |
| | 1,354,445 |
|
| Transportation and other | 7,649 |
| | 7,261 |
| | 6,936 |
|
| Total customers | 1,393,095 |
| | 1,377,317 |
| | 1,361,381 |
|
| | | | | | |
| Natural gas revenues (Thousands of Dollars) | | | | | |
| Residential | $ | 652,913 |
| | $ | 611,804 |
| | $ | 678,909 |
|
| Commercial and industrial | 247,582 |
| | 228,103 |
| | 257,287 |
|
| Total retail | 900,495 |
| | 839,907 |
| | 936,196 |
|
| Transportation and other | 94,719 |
| | 117,814 |
| | 70,470 |
|
| Total natural gas revenues | $ | 995,214 |
| | $ | 957,721 |
| | $ | 1,006,666 |
|
| | | | | | |
| MMBtu sales per retail customer | 91.05 |
| | 94.18 |
| | 96.28 |
|
| Revenue per retail customer | $ | 650 |
| | $ | 613 |
| | $ | 691 |
|
| Residential revenue per MMBtu | 7.35 |
| | 6.73 |
| | 7.38 |
|
| Commercial and industrial revenue per MMBtu | 6.64 |
| | 5.99 |
| | 6.70 |
|
| Transportation and other revenue per MMBtu | 0.76 |
| | 1.00 |
| | 0.65 |
|
GENERAL
Seasonality
The demandDemand 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 milderwarmer in the winter and cooler in the summer. See Item 7 for further discussion.
Decoupling mechanisms mitigate the impacts of weather in certain jurisdictions. PSCo’s electric decoupling mechanism expired in September.
Competition
PSCo is a vertically integrated utility, subject to traditional cost-of-service regulation. However, PSCo is subject to different public policies that promote competition and the development of energy markets. PSCo’s industrial and large commercial customers have the ability to own or operate facilities to generate their own electricity. In addition, customers may have the option of substituting other fuels such as natural gas, steam or chilled water for heating, cooling and manufacturing purposes, or the option of relocating their facilities to a lower cost region.
Customers also have the opportunity to supply their own power with distributed generation including solar generation (typically rooftop solar or solar gardens) and in most jurisdictions can currently avoid paying for most of the fixed production, transmission and distribution costs incurred to serve them. Several states, including
Colorado have policies designed to promotehas incentives for the development of rooftop solar, community solar gardens and other distributed energy resources through significant incentive policies; with these incentives and federal tax subsidies, distributedresources. Distributed generating resources are potential competitors to PSCo’s electric service business.
business with these incentives and federal tax subsidies.
The FERC has continued to promote competitive wholesale markets through open access transmission and other means. As a result, PSCo and itsPSCo’s wholesale customers can purchase energy from competing generation resources and transmission services from competing wholesale suppliers and use the transmission systems of Xcel Energy Inc.’s utility subsidiaries on a comparable basisother service providers to serve their native load. State public utilities commissions, including the CPUC, have created resource planning programs that promote competition in the acquisition of electricity generation resources used to provide service to retail customers. In addition,
FERC Order No. 1000 seeks to establishestablished competition for construction and operationownership of certain new electric transmission facilities under Federal regulations. Some states have state 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 adoption, however implementation is expected to vary by RTO/ISO and the near, medium, and long-term impacts of Order 2222 remain unclear.
PSCo also has franchise agreements with certain cities subject to periodic renewal. Ifrenewal; however, a city elected not to renew a franchise agreement, it could seek alternative means for its citizens 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 alternatives.available.
ENVIRONMENTAL MATTERSPublic Utility Regulation
See Item 7 for discussion of public utility regulation.
PSCo’sEnvironmental Regulation
Our facilities are regulated by federal and state environmental agencies. These agencies that have jurisdiction over air emissions, water quality, wastewater discharges, solid wastes and hazardous wastes or substances. Various companyCertain PSCo activities require registrations, permits, licenses, inspections and approvals from these agencies.
PSCo has received all necessary authorizations for the construction and continued operation of its generation, transmission and distribution systems. PSCo’sOur facilities have been designed and constructedstrive to operate in compliance with applicable environmental standards. 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 environmental regulations, interpretations or enforcement policies or what effect future laws or regulations may have upon PSCo’s operations. See Notes 11have. We may be required to incur expenditures in the future for remediation of historic and 12 to the consolidated financial statements for further discussion.
current operating sites and other waste treatment, storage and disposal sites.
There are significant present and future environmental regulations to encourage the use of clean energy technologies and regulate emissions of GHGs to address climate change.GHGs. PSCo has undertaken a number ofnumerous initiatives to meet current requirements and prepare for potential future regulations, reduce GHG emissions and respond to state renewable and energy efficiency goals. If these futureFuture environmental regulations domay result in substantial costs.
Emerging Environmental Regulation
Clean Air Act
Power Plant Greenhouse Gas Regulations— In May 2023, the EPA published proposed rules addressing control of CO2 emissions from the power sector. The rule proposed regulations for new natural gas generating units and emission guidelines for existing coal and certain natural gas generation. The proposed rules create subcategories of coal units based on planned retirement date and subcategories of natural gas combustion turbines and combined cycle units based on utilization. The CO2 control requirements vary by subcategory. Until final rules are issued, it is not provide credit forcertain what the investments we have already made to reduce GHG emissions, or if they require additionalimpact will be on PSCo. PSCo believes that the cost of these initiatives or emission reductions, then their requirementsreplacement generation would potentially impose additional substantial costs. PSCo believes,be recoverable through rates based on prior state commission practice,practices.
Coal Ash Regulation
In May 2023, the EPA published proposed rules to regulate legacy CCR surface impoundments at inactive facilities and previously exempt areas where CCR was placed directly on land at regulated CCR facilities under the CCR Rule for the first time. The proposed rule would subject these areas to the CCR Rule requirements, including groundwater monitoring, corrective action, closure, and post-closure care requirements, among other requirements, with several of the deadlines accelerated.
The EPA has committed to a May 2024 publication date for those new rules. It is also anticipated that the EPA may issue other CCR proposed rules in 2024 and 2025 that further expand the scope of the CCR Rule. Until final rules are issued, it would recoveris not certain what the impact will be on PSCo. PSCo. believes that the cost of these initiatives would be recoverable through rates.rates based on prior state commission practices.
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. EMPLOYEESIn September 2022, the EPA proposed to designate two types of PFAS as “hazardous substances” under the CERCLA. In March 2023, the EPA published a proposed rule that would establish enforceable drinking water standards for certain PFAS chemicals.
Final rules are expected in 2024. Costs are uncertain until a final rule is published.
The proposed rules could result in new obligations for investigation and cleanup. PSCo is monitoring changes to state laws addressing PFAS. The impact of these proposed regulations is uncertain.
Effluent Limitation Guidelines
In March 2023, the EPA released a proposed rule under the Clean Water Act, setting forth proposed Effluent Limitations Guidelines and Standards for steam generating coal plants. This proposed rule establishes more stringent wastewater discharge standards for bottom ash transport water, flue-gas desulfurization wastewater, and combustion residuals leachate from steam electric power plants, particularly coal-fired power plants. The impact of these proposed regulations is uncertain until a final rule is published.
Other
Our operations are subject to 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, 2017,2023, PSCo had 2,4002,352 full-time employees and twoten part-time employees, of which 1,8351,878 were covered under collective-bargaining agreements. See Note 8 to the consolidated financial statements for further discussion.
Item 1A — Risk Factors
Xcel Energy, which includes PSCo, is subject to a variety of risks, many of which are beyond our control. Important risksRisks that may adversely affect the business, financial condition, and results of operations or cash flows are further 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 in future reports that Xcel Energy files with the SEC.
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
A key accountability of thePSCo’s Board of Directors is responsible for the oversight of material risk and our Board of Directors employsmaintaining an effective process for doing so.risk monitoring process. Management and the Board of Directors have responsibility for overseeing the identification and mitigation of key risks.
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 Code of Conduct 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. Management broadly considers our business, the utility industry, the domesticIdentification and global economies and the environment when identifying, assessing, managing and mitigating risk. Identification andrisk analysis occurs formally through a key risk assessment process conducted by senior management, the financial disclosure process, the hazard risk management process andprocedures, internal auditingaudit and compliance with financial and operational controls. Management also identifies and analyzes risk through itsthe business planning process, and development of goals and establishment of key performance indicators, which include riskincluding identification to determineof barriers to implementing our strategy. The business planning process also identifies areas in which there is a potential for a business arealikelihood and mitigating factors to takeprevent the assumption of inappropriate risk to meet goals, and determines how to prevent inappropriate risk-taking.goals.
At a threshold level, PSCo has developed a robust compliance program and promotes a culture of compliance, including tone at the top, which mitigates risk. The process for risk mitigation includes adherence to our code of conduct and other compliance policies, operation of formal risk management structures and groups and overall business management to mitigate the risks inherent in the implementation of strategy. Building on this culture of compliance, management further mitigates risks through operation of formal risk management structures and groups, including management councils, risk committees and the services of internal corporate areas such as internal audit, the corporate controller and legal services.
Management communicates regularly with the Board of Directors and key stakeholdersits sole stockholder regarding risk. Senior management presents and communicates a periodic risk assessment of key risks to the Board of Directors. The presentation and the discussion of the key risks provides the Board of Directors, withproviding information on the risks that management believes are material, including the earningsfinancial impact, timing, likelihood and controllability. Management also provides information to themitigating factors. The Board of Directors in presentationsregularly reviews management’s key risk assessments, which includes areas of existing and communications over the course of the year.future macroeconomic, financial, operational, policy, environmental, safety and security risks.
Overall, the Board of Directors approachesThe oversight, management and mitigation of risk asis an integral and continuous part of itsthe Board of Directors’ governance of PSCo. Processes are in place to ensureconfirm appropriate risk oversight, as well as identification and consideration of new risks. The Board of Directors regularly reviews management’s key risk assessment informed by these processes, and analyzes areas of existing and future risks and opportunities.
Risks Associated with Our Business
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 past, present and future operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances. These laws and regulations require us to obtain permits, licenses, and other approvals and to comply with a wide variety of environmental requirements including those for protected natural and cultural resources (such as wetlands, endangered species and other protected wildlife, and archaeological and historical resources). Environmental laws and regulations can also require us to restrict or limit the output of certain facilities or the use of certain fuels, shift generation to lower-emitting, but potentially more costly facilities, install pollution control equipment at our facilities, clean up spills and other contamination and correct environmental hazards. Environmental regulations may also lead to shutdown of existing facilities, either due to the difficulty in assuring compliance or that the costs of compliance makes operation of the units no longer economical. Both public officials and private individuals may seek to enforce the applicable environmental laws and regulations against us. We may be required to pay all or a portion of the cost to remediate (i.e., clean-up) sites where our past activities, or the activities of certain other parties, caused environmental contamination.
We are also subject to mandates to provide customers with clean energy, renewable energy and energy conservation offerings. Failure to meet the requirements of these mandates may result in fines or penalties, which could have a material effect on our results of operations. 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 or other environmental requirements, it could have a material effect on our results of operations, financial position or cash flows.
In addition, existing environmental laws or regulations may be revised, and new laws or regulations may be adopted or become applicable to us, including but not limited to, regulation of mercury, NOx, SO2, CO2 and other GHGs, particulates, cooling water intakes, water discharges and ash management. 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 from climate change can include changes in weather conditions, changes in precipitation and extreme weather events.
Our customers’ energy needs vary with weather conditions, primarily temperature and humidity. For residential customers, heating and cooling represent their largest energy use. 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 additional generating assets, transmission and other infrastructure to serve increased load. Decreased energy use due to weather changes may result in decreased revenues. Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system stress, including service interruptions. Weather conditions could also have an impact on our revenues. We buy and sell electricity depending upon system needs and market opportunities. Extreme weather conditions creating high energy demand may raise electricity prices, which would increase the cost of energy we provide to our customers.
Severe weather impacts our service territories, primarily when thunderstorms and associated flooding, tornadoes, wildfires and snow or ice storms occur. To the extent the frequency of extreme weather events increases, this could increase our cost of providing service. Changes in precipitation resulting in droughts or water shortages, whether caused by climate change or otherwise, could adversely affect our operations, principally our fossil generating units. A negative impact to water supplies due to long-term drought or water depletion conditions could adversely impact our ability to provide electricity to customers, as well as increase the price they pay for energy. We may not recover all costs related to mitigating these physical and financial risks.
Climate change may impact a region’s economic health, which could impact our revenues. Our financial performance is tied to the health of the regional economies we serve. The price of energy has an impact on the economic health of our communities. The cost of additional regulatory requirements, such as regulation of GHGor additional environmental regulation 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.
Financial Risks
Our profitability depends in part on our ability to recover costs from our customers and there may be changes in circumstances or in the regulatory environment that impair our ability to recover costs from our customers.
We are subject to comprehensive regulation by federal and state utility regulatory agencies. The CPUC regulates many aspects of our utility operations, including siting and construction of facilities, customer service and the rates that we can charge customers. The FERC has jurisdiction, among other things, over wholesale rates for electric transmission service, the sale of electric energy in interstate commerce and certain natural gas transactions in interstate commerce.
The profitability of our operations is dependent on our ability to recover the costs of providing energy and utility services to our customers and earn a return on our capital investment. We provide service at rates approved by one or more regulatory commissions. These rates are generally regulated and 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 mechanisms approved in each jurisdiction. Thus, the rates we are allowed to charge may or may not match our costs at any given time. While rate regulation is premised on providing an opportunity to earn a reasonable rate of return on invested capital, in a continued low interest rate environment there has been pressure pushing down ROE. There can also be no assurance that the applicable regulatory commission will judge all of our costs to have been prudent, which could result in cost disallowances, or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of such costs. Changes in the long-term cost-effectiveness or changes to the operating conditions of our assets may result in early retirements and while regulation typically provides relief for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs leaving all or a portion of these asset costs stranded. Higher than expected inflation may increase costs of construction and operations. Rising fuel costs could increase the risk that we will not be able to fully recover our fuel costs from our customers. Furthermore, there could be changes in the regulatory environment that would impair our ability to recover costs historically collected from our customers, or these factors could cause us to exceed commitments made regarding cost caps and result in less than full recovery. Overall, management currently believes prudently incurred costs are generally recoverable given the existing regulatory mechanisms in place.
Adverse regulatory rulings or the imposition of additional regulations could have an adverse impact on our results of operations and hence could materially and adversely affect our ability to meet our financial obligations, including debt payments.
Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships.
We cannot be assured that any of our current ratings will remain in effect for any given period of time, or that a rating will not be lowered or withdrawn entirely by a rating agency. Significant events including a major disallowance of costs, significantly lower returns on equity or equity ratios or impacts of tax policy changes, among others, 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 downgrade could lead to higher borrowing costs and could impact our ability to access capital markets. Also, we may enter into certain procurement and derivative contracts that require the posting of collateral or settlement of applicable contracts 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 markets are global in nature and are impacted by numerous issues and events throughout the world economy. Capital market disruption events and resulting broad financial market distress could prevent us from issuing short term commercial paper, issuing new securities or cause us to issue securities with less than ideal terms and conditions, such as higher interest rates.
Higher interest rates on short-term borrowings with variable interest rates could also have an adverse effect on our operating results. Changes in interest rates may also impact the fair value of the debt securities in the master pension trust, as well as our ability to earn a return on short-term investments of excess cash.
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 liquidity and an increase in bad debt expense. Credit risk is comprised of numerous factors including the price of products and services provided, the overall economy and local economies in the geographic areas we serve, including local unemployment rates.
Credit risk also includes the risk that various counterparties that owe us money or product will become insolvent and/or breach their obligations. Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected and we could incur losses.
We may at times have direct credit exposure in our short-term wholesale and commodity trading activity to various 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, such as CAISO, SPP, MISO and ERCOT, in which any credit losses are socialized to all market participants.
We do have additional indirect credit exposures to various domestic and foreign financial institutions in the form of letters of credit provided as security by power suppliers under various long-term physical purchased power contracts. If any of the credit ratings of the letter of credit issuers were to drop below the designated investment grade rating stipulated in the underlying long-term purchased power contracts, the supplier would need to replace that security with an acceptable substitute. If the security were not replaced, the party could be in technical default under the contract, which would enable us to exercise our contractual rights.
Increasing costs associated with our defined benefit retirement plans and other employee benefits may adverselyaffect our results of operations, financial position or liquidity.
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, including mortality tables, have a significant impact on our funding requirements related to these plans. These estimates and assumptions may change based on economic conditions, actual stock and bond market performance, changes in interest rates and changes in governmental regulations. In addition, the Pension Protection Act of 2006 changed the minimum funding requirements for defined benefit pension plans with modifications that allowed additional flexibility in the timing of contributions. Therefore, our funding requirements and related contributions may change in the future. Also, the payout of a significant percentage of pension plan liabilities in a single year due to high retirements or employees leaving PSCo could trigger settlement accounting and could require PSCo to recognize material incremental pension expense related to unrecognized plan losses in the year these liabilities are paid.
Increasing costs associated with health care plans may adversely affect our results of operations.
Our self-insured costs of health care benefits for eligible employees have increased in recent years. Increasing levels of large individual health care claims and overall health care claims could have an adverse impact on our operating results, financial position, and liquidity. We believe that our employee benefit costs, including costs related to health care plans for our employees and former employees, will continue to rise. Changes in industry standards utilized by management in key assumptions (e.g., mortality tables) could have a significant impact on future liabilities and benefit costs. Legislation related to health care could also significantly change our benefit programs and costs.
Federal tax law may significantly impact our business.
PSCo collects through regulated rates its estimated federal, state and local tax payments. There are a number of provisions in federal tax law designed to incentivize capital investments which have benefited our customers by keeping our utility subsidiaries’ rates lower than rates calculated without such provisions. Examples include the use of accelerated depreciation for most of our capital investments, PTCs for wind energy, ITCs for solar energy and R&E tax credits and deductions. Changes to federal tax law may benefit or adversely affect our earnings and customer costs. Changes to tax depreciable lives and the value of various tax credits could change the economics of resources and our resource selections. While regulation allows us to incorporate changes in tax law into the rate-setting process, there could be timing delays before regulated rates provide for realization of the tax changes in revenues. In addition, certain IRS tax policies such as the requirement to utilize normalization may impact our ability to economically deliver certain types of resources relative to market prices.
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 a variety of inherent hazards and operating risks, such as leaks, explosions, outages and mechanical problems, which could cause substantial financial losses.problems. Our electric generation, transmission and distribution activities also include inherent hazards and operating risks such as contact, fire and widespread outages which could cause substantial financial losses. In addition, these natural gas and electricoutages. These risks could result in loss of human life, significant property damage, to property, environmental pollution, impairment of our operations and substantial financial losses to us.employees, third-party contractors, customers or the public. We maintain insurance against some,most, but not all, of these risks and losses.
The occurrence of any of these events, if not fully covered by insurance, could have a material effect on our financial position andcondition, results of operations. Foroperations and cash 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 supplies.
•Impact of adverse weather conditions and natural disasters, including, tornadoes, avalanches, icing events, floods, high winds and droughts.
•Performance below expected or contracted levels of output or 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 transmission or distribution lines located near populated areas,infrastructure could result in significant costs. The PHMSA is responsible for administering the levelDOT’s national regulatory program to assure the safe transportation of potential damages resulting from these risks is greater.
Additionally, for natural gas, the operating orpetroleum and other costs that may be requiredhazardous materials by pipelines. The PHMSA continues to develop regulations and other approaches to risk management to assure safety in order to comply with potential new regulations, including the Pipeline Safety Act, could be significant. The Pipeline Safety Act requires verificationdesign, construction, testing, operation, maintenance and emergency response of natural gas pipeline infrastructure records by pipeline owners and operators to confirm the maximum allowable operating pressure of lines located in high consequence areas or more-densely populated areas.infrastructure. We have programs in place to comply with the Pipeline Safety Actthese regulations and for systematicsystematically monitor and renew infrastructure monitoring and renewal over time. Atime; however, a significant incident or material finding of non-compliance could increase regulatory scrutiny and 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 long-lived and are planned to be used for decades. Transmission and generation investments typically have long lead times and therefore are planned well in advance of when they are brought in-service dates and typically subject to long-term resource plans. These plans are based on numerous assumptions over the planning horizon 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 a period of significant change. For example, public policy has drivenchange (e.g., increases in appliance and lightingenergy efficiency, and energy efficient buildings, wider adoption and lower cost of renewabledistributed generation and distributed generation, including community solar gardens and customer-sited solar, shifts away from coalfossil fuel generation to decrease CO2 emissions and increasing use of natural gas in electric generation driven by lower natural gas prices. Over time, customerrenewable generation). Customer adoption of these technologies and increased energy efficiency could result in excess transmission and generation resources, as well asdownward pressure on sales growth, and potentially stranded costs if PSCo iswe are not able to fully recover the costs and investments. These changes also introduce additional uncertainty into long-term planning which gives rise to a risk that the
The magnitude and timing of resource additions and growthchanges in customer demand may not coincide and that thewith evolving customer preference for generation resources and end-uses, which introduces further uncertainty into long-term planning. Efforts to electrify the types of additionstransportation and building sectors to reduce GHG emissions may changeresult in higher electric demand and lower natural gas demand over time. New data centers and crypto mining facilities could generate significant increase in demand. Higher 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 planninggeneration sources and end-uses, like heating, may impact our resource mix and put pressure on our ability to execution. In addition, werecover 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 also subject to longer-term availability ofnot recoverable across all jurisdictions served by the natural resourcesame assets.
We require inputs such as coal, natural gas uranium and water to cool our facilities.water. Lack of availability of these resources could jeopardize long-term operations of our facilities or make them uneconomic to operate.
The resourceOur 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. A shortage of key components in which an alternative supplier is not identified could significantly impact operations and project plans reviewedfor PSCo and approved by our state regulators assume continuationcustomers. Such impacts could include timing of the traditional utility cost of service model under which utility costs are recovered from customers as they receive the benefit of service. PSCo is engaged in significant and ongoing infrastructure investment programs to accommodate renewable distributed generation and maintain high system reliability. Changing customer expectations and changing technologies are requiring significant investments in advanced grid infrastructure. This also increases the exposure to potential outdating of technologiesprojects and the resultant risks. PSCo is also investing in renewablepotential for project cancellation. Failure to adhere to project budgets and natural gas-fired generation to reducetimelines could adversely impact our CO2 emissions profile. The inabilityresults of coal mining companies to attract capital could disrupt longer-term supplies. Early plant retirements that may result from these changes could expose us to prematureoperations, financial obligations, which could result in less than full recovery of all remaining costs. Both decreasing use per customer driven by appliance and lighting efficiency and the availability of cost-effective distributed generation puts downward pressure on load growth. This could lead to under recovery of costs, excess resources to meet customer demand and increases in electric rates. Finally, multiple states served by a single system may not agree as to the appropriate resource mix and the differing views may lead to costs incurred to comply with one jurisdiction that are not recoverable across all of the jurisdictions served by the same assets.
condition or cash flows.
We are subject to commodity risks and other risks associated with energy markets and energy production.
A significant increase in fuel costs could cause a decline in customer demand, adverse regulatory outcomes and an increase in bad debt expense 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 alternatives at potentially higher costs. Additionally, supply shortages may not be fully resolved, which negatively 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 negatively impacts 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, in which we operate, emission allowances and/or renewable energy creditsRECs are also needed to comply with various statutes and commission rulings associated with energy transactions.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 (mark-to-market accounting). Actual settlementsbasis. 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 passed through to customer bills could impact our ability to recover costs for other improvements and operations.
If we encounter market supply shortages or our suppliers are otherwiseDue to the uncertainty involved in price movements and potential deviation from historical pricing, PSCo is unable to meet their contractual obligations,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. If such programs 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.
The competition for talent has become increasingly prevalent, and we have experienced increased employee turnover due to the condition of the labor market and decisions related to strategic workforce planning. In addition, specialized knowledge and skills are required for many of our positions, which may be unablepose additional difficulty for us as we work to fulfillrecruit, retain and motivate employees in this climate.
Failure to hire, adequately train replacement employees, transfer knowledge/expertise or future availability and cost of contract labor may adversely affect the ability to manage and operate our contractual obligationsbusiness. Inability to attract and retain these employees could adversely impact our customers at previously anticipated costs. Therefore, a significant disruptionresults of operations, financial condition or cash flows.
Our businesses have collective bargaining agreements with labor unions. Failure to renew or renegotiate these contracts could cause uslead to seek alternative supply services at potentially higher costslabor disruptions, including strikes or suffer increased liability for unfulfilled contractual obligations. Any significantly higher energyboycotts. Such disruptions or fuel costs relative to corresponding sales commitmentsany negotiated wage or benefit increases could have a negativematerial adverse impact to our results of operations, financial condition or cash flows.
National unionization efforts could affect our business, as an increase in unionized workers could challenge our operational efficiency and increase costs.
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 compliance with our Code of Conduct and are required to participate in annual training. Additionally, suppliers are subject to compliance 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. 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 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 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 for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs.
Higher 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 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.
Our credit ratings are subject to change and our credit ratings may 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 economic losses. Potential market supply shortages may not be fully resolved through alternative supply sources and may cause short-term disruptions inthe methodologies used by the various rating agencies.
Any credit ratings downgrade could lead to higher borrowing costs or lower proceeds from equity issuances. It could also impact our ability to provide electric and/access capital markets. Also, we may enter into contracts that require posting of collateral or natural gas servicessettlement 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 customers. The impact of these costability to fund our operations. Capital market disruption and reliability issues dependsfinancial market distress could prevent us from issuing commercial paper, issuing new securities or cause us to issue securities with unfavorable terms and conditions, such as higher interest 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 conditions such as generation fuels mix, availabilityresults.
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 cash flow and liquidity and an increase in bad debt expense. Credit risk is comprised of waternumerous 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 cooling, availabilitytheir own accounts or issuing collateral support on behalf of fuel transportation including rail shipments of coal, electric generation capacity, transmission, natural gas pipeline capacity, etc. Failure to provide serviceother counterparties. We may also have some indirect credit exposure due to disruptionsparticipation in organized markets, (e.g., SPP, Midcontinent Independent System Operator, Inc. 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 also resultbe in fines, penalties or cost disallowances throughdefault under the regulatory process.
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 Xcel Energy Inc. were to become obligated to make payments under various guarantees and bond indemnities or to fund its other contingent liabilities, or if either Standard & Poor’sS&P or Moody’s were to downgrade Xcel Energy Inc.’s credit rating below investment grade, Xcel Energy Inc. may be required to provide credit enhancements in the form of cash collateral, letters of credit or other security to satisfy part or potentially all of these exposures. If either Standard & Poor’s or Moody’sInvestor Services 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, 2017,2023, Xcel Energy Inc. and its utility subsidiaries had approximately $14.5$24.9 billion of long-term debt and $1.3 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, 2017,2023, Xcel Energy had the following guarantees outstandingoutstanding:
•$951 million for performance and payment of Capital Services, LLC contracts for wind and solar generating equipment, with a maximum stated amount of approximately $19 million and immaterial exposure. Xcel Energy also had additional guarantees
•$100 million for performance on tax credit sale agreements of $53its subsidiaries, with immaterial exposure.
•$75 million at Dec. 31, 2017 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.
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 wholly owned subsidiarysignificant impact on future obligations and benefit costs.
Increasing costs associated with health care plans may adversely affect our results of Xcel Energy Inc. Xcel Energy Inc. can exercise substantial control overoperations.
Increasing levels of large individual health care claims and overall health care claims could have an adverse impact on our dividend policyresults of operations, financial condition or cash flows. Health care legislation could also significantly impact our benefit programs and businesscosts.
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 value/availability of various tax credits or the timeliness of their utilization may impact the economics or selection of resources. 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 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.
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 exercise that controlinhibit our ability to acquire sufficient supplies. We operate in a mannercapital 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.
The oil and gas industry represents our largest commercial and industrial customer base. Oil and natural gas prices are sensitive to market risk factors which may impact demand.
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.
Health epidemics impact countries, communities, supply chains and markets. Uncertainty continues to exist regarding epidemics; the duration and magnitude of business restrictions 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 generalized impact on the economy.
We cannot ultimately predict whether an epidemic will have a material impact on our future liquidity, financial condition or results of operations. Nor can we predict the impact on the health of our employees, our supply chain or our ability to recover higher costs associated with managing 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 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, 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. While 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 be perceivedimpact our ability to beconnect, restore and reliably serve our customers.
A major disruption could result in a significant decrease in revenues, 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.
A cybersecurity 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 our interests.create, collect, use, disclose, store, dispose of and otherwise process sensitive information, including Company data, customer energy usage data, and personal information regarding customers, employees and their dependents, contractors and other individuals.
All of the members of our Board of Directors,Our generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets, as well as manyinformation processed in our systems (e.g., information regarding our customers, employees, operations, infrastructure and assets) could be affected by cybersecurity incidents, including those caused by human error.
The utility industry has been the target of several attacks on operational systems and has seen an increased volume and sophistication of cybersecurity incidents from international activist organizations, other 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.
Cybersecurity incidents could harm our businesses by limiting our generation, transmission and distribution 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 cybersecurity incident on the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources of our executive officers,third-party service providers’ operations, could also negatively impact our business.
Generative Artificial Intelligence, such as large language models like ChatGPT, present a range of challenges and potential risks as we consider impacts to the business. These challenges involve navigating the complexities of creating and deploying AI models that generate content autonomously. Data privacy, legal concerns, and security issues are officersall risks as this technology continues to be adopted.
Our Board makes determinations with respectsupply 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 cybersecurity threats or subsequent related actions. Cybersecurity incidents and regulatory action could result in a material decrease in revenues and may causesignificant 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 cybersecurity 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 cybersecurity 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 corporate events, includingamount of natural gas revenues are recognized in the payment offirst and fourth quarters related to the heating season. Accordingly, our dividends.
Weoperations have historically paid quarterly dividends to Xcel Energy Inc. In 2017, 2016generated less revenues and 2015 we paid $334 million, $337 millionincome when weather conditions are milder in the winter and $331 millioncooler in the summer. Unusually mild winters and summers could have an adverse effect on our financial condition, results of dividends to Xcel Energy Inc., respectively. If Xcel Energy Inc.’soperations or 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 Item 5 for further discussion on dividend limitations.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, cybersecurity 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.
Increased public awareness and concern regarding climate change may result in more state, regional and/or federal requirements to reduce or mitigate the effects of GHGs. Legislative and regulatory responses related to climate change and new interpretations of existing laws through climate change litigationmay create financial risk as our electric generating facilities may be subject to additional regulation at either the state or federal level in the future. Such regulations could impose substantial costs on our system. International agreements could have an impact to the extent theyadditionally lead to future federal or state regulations.
In 2015, the 21st Conference of the Parties to 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, (“nationally determined contributions”), with a goal of holding the increase in global average temperature to below 2o2º Celsius above pre-industrial levels and an aspiration to limit the increase to 1.5o 1.5º Celsius. If implemented, the Paris Agreement
International commitments and agreements could result in future additional GHG reductions in the United States. On June 21, 2017, President Trump announced thatIn addition, in 2023 the U.S. would withdrawEPA intends to publish draft regulations for GHG emissions from the Paris Agreement. Such a withdrawal, under terms ofpower sector consistent with the Agreement, becomes effective in four years. Many state and local government entities, however, have indicated that they intend to pursue GHG mitigation with a goal of achieving the GHG reductions in the United States anticipated by the Paris Agreement.agency’s Clean Air Act authorities.
We have been, and in the future may be, subject to climate change lawsuits. An adverse outcome in any of these cases could require substantial capital expenditures and could possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant. Such payments or expenditures could affect results of operations, cash flows and financial condition if such costs are not recovered through regulated rates.
SomeMany states and localities have indicated a desire to continue to pursue their own climate policies even in the absence of federal mandates. All of thepolicies. The steps that PSCoXcel 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. While those actions likely would have put PSCo in a good position
We may be subject to meet federal standards under the CPPclimate change lawsuits. An adverse outcome could require substantial capital expenditures and possibly require payment of substantial penalties or the Paris Agreement, repealdamages. Defense costs associated with such litigation can also be significant and could affect results of these policies wouldoperations, financial condition or cash flows if such costs are not impact those state-endorsed actions and plans.recovered through regulated rates.
Whether under state or federal programs, an important factor is our ability to recover the costs incurred to comply with any regulatory requirements in a timely manner. 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.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 now impose penalties of up to $1.2 million per violation per day, particularly as it relates to energy trading activities for both electricity and natural gas. Under statute, the FERC can adjust penalties for inflation. In addition, NERC electric reliability standards and critical infrastructure protection requirementsWe are mandatory and subject to potential financial penalties by regional entities,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 NERCgeneration, 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 FERC for violations. Additionally, the PHMSA, the Occupational Safety and Health Administrationuse of certain fuels, shift generation to lower-emitting facilities, install pollution control equipment, clean up spills and other federal agencies also have penalty authority. Incontamination 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 eventcost to remediate sites where our past activities, or the activities of serious incidents,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 agencies have become more active in pursuing penalties. Some states have the authoritytypes of changes, there is no assurance that regulators would allow full recovery of all remaining costs.
We are subject to impose substantial penalties in the event of non-compliance. If a serious reliability or safety incident did occur, itmandates 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 financial results.
Macroeconomic Risks
Economic conditions impactcash flows if our business.
Our operations are affected by local, national and worldwide economic conditions. Growth in our customer base is correlated with economic conditions. While the number of customers is growing, sales growth is relatively modest dueregulators do not allow us to an increased focus on energy efficiency including federal standards for appliance and lighting efficiency and distributed generation, primarily solar PV. Instability in the financial markets also may affectrecover the cost of capital and our abilityinvestment or O&M costs incurred to raise capital, which is discussed incomply with the capital market risk factor section above.requirements.
Economic conditionsIn addition, existing environmental laws or regulations may be impactedrevised, 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 insufficient financial sector liquidity leadingclimate change, customers’ energy use could increase or decrease. Increased energy use due to potential increased unemployment, whichweather 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 customers’ ability to pay timely, increase customer bankruptcies,the economy, which could impact our sales and may lead to increased bad debt.
Further, worldwide economic activityrevenues. The price of energy has an impact on the demand for basic commodities needed for utility infrastructure,economic health of our communities. The cost of additional regulatory requirements, such as steel, copper, aluminum, etc.,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 and result in more frequent service interruptions. Periods of extreme temperatures could also impact our ability to acquiremeet demand.
More frequent and severe drought conditions, extreme swings in amount and timing of precipitation, changes in vegetation, unseasonably warm temperatures, very low humidity, stronger winds and other factors have increased the duration of the wildfire season and the potential impact of an event. Also, the expansion of the wildland urban interface increases the wildfire risk to surrounding communities and PSCo's electric and natural gas infrastructure.
Other potential risks associated with wildfires and other climate events include the inability to secure sufficient supplies. We operate in a capital intensive industry, and federal policy on trade could significantly impact theinsurance coverage, or increased costs of insurance, regulatory recovery risk, and the materials we use. We may be at riskpotential for higher than anticipated inflation both with respect to our own workforce, as well as our materialsa credit downgrade and labor that we contract for with others. There may be delays before these higher costs can be recovered in rates.
Our operations could be impacted by war, acts of terrorism, threats of terrorism or disruptions in normal operating conditions due to localized or regional events.
Our generation plants, fuel storage facilities, transmission and distribution facilities and information and control systems may be targets of terrorist activities. Any such disruption could impact operations or result in a decrease in revenues andsubsequent additional costs to repair and insureaccess 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 assets. These disruptions could have a material impact on our financial condition and results of operations. 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. In addition, we may experience additional capital and operating costs to implement security for our plants, such as additional physical plant security and additional security personnel. We have also already incurred increased costs for compliance with NERC reliability standards associated with critical infrastructure protection. In addition, we may experience additional capital and operating costs to comply with the NERC critical infrastructure protection standards as they are implemented and clarified.
The insurance industry has also been affected by these events and the availability of insurance may decrease. In addition, the insurance we are able to obtain 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,coverage could negatively impact our business, as well asresults of operations, financial condition or cash flows. Drought or water depletion could adversely impact our brandability to provide electricity to customers, cause early retirement of power plants and reputation. Because our generation,increase the transmission systems and local natural gas distribution companies 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 or an event (such as severe storm, severe temperature extremes, wildfires, solar storms, generator or transmission facility outage, breakdown or failure of equipment, pipeline rupture, railroad disruption, operator error, sudden and significant increase or decrease in wind generation or any disruption of work force such ascost for energy. Adverse events may be caused by flu or other epidemic) within our operating systems or on a neighboring system. Any such disruption could result in increased insurance costs and/or decreased insurance availability. We may not recover all costs related to mitigating these physical and financial risks.
| | |
| ITEM 1B — UNRESOLVED STAFF COMMENTS |
None.
PSCo is a significant decreasewholly owned subsidiary of Xcel Energy. As such, its cybersecurity processes are maintained by Xcel Energy management and governed by its Board of Directors.
As described in revenues and significant additional costs to repair assets, which could have a material impact on our financial condition and results.
The degree to which we are able to maintain day-to-day operations in response to unforeseen events will in part determine the financial impact of certain events on our financial condition and results.It is difficult to predict the magnitude of such events and associated impacts.
A cyber incident or cyber security breach could have a material effect on our business.
We operateItem 1A – Risk Factors, Xcel Energy operates in an industry that requires the continued operation of sophisticated information technology, and control systems and network infrastructure. In addition, we useinfrastructure, as such, our systemsbusiness is subject to the risk of interruption by cybersecurity incidents that range from attacks common to most industries, such as phishing and denial-of-service, to attacks from more sophisticated adversaries, including nation state actors, that target the critical infrastructure used in the operation of our business.
Xcel Energy has a security risk program in place to create, collect, use, disclose, store, disposeidentify, assess, manage and report material risks from cybersecurity incidents. As a utility provider, Xcel Energy complies with reliability standards imposed by NERC, including critical infrastructure protection standards related to both cybersecurity and physical security. These standards imposed by NERC, in alignment with the NIST Cybersecurity Framework, are the basis for which Xcel Energy has designed the cybersecurity control framework within its security risk program.
Annually, as part of Xcel Energy’s enterprise risk program, an integrated cybersecurity risk identification and otherwise process sensitive information,assessment is completed across Xcel Energy’s business, including company 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 the information processed in our systems (such as information about our customers, employees, operations, infrastructure and assets)(including systems hosted by third parties) that could be affected by cybercybersecurity incidents. This analysis includes the impact, likelihood, timeframe and controllability of cybersecurity risks and is presented to the Board of Directors. Management monitors and reviews the results of this analysis, integrating them into the enterprise risk assessment processes and implements appropriate mitigating actions as needed.
Xcel Energy’s cybersecurity policies, standards, practices and readiness are regularly assessed by third-party consultants. These partners are engaged to perform independent penetration testing and other security related services to assist in the prevention, detection, monitoring, mitigation and remediation of cybersecurity incidents and risks. The results of these assessments are communicated to management and the Board of Directors by the Chief Security Officer.
Xcel Energy employs a comprehensive risk based approach to assess the magnitude and significance of a vendor’s risk to Xcel Energy. Certain third-party service providers are subject to vendor security risk assessments at the time of integration, contract execution/renewal, and upon detection of any increase in risk profile. Xcel Energy uses a variety of inputs in such risk assessments, including information supplied by providers and third parties (including information analysis centers that share daily threat intelligence and improve organizational agility associated with management of cybersecurity risks). In addition, Xcel Energy requires certain third-party service providers to meet appropriate security requirements, controls and responsibilities. Xcel Energy deploys periodic monitoring activities to assess compliance with our cybersecurity control framework and investigates security incidents including those caused by human error. Our industry has begun to see an increased volume and sophistication of cyber security incidents from international activist organizations, Nation States and individuals. 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 exposing 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 of 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 may expose software or hardware to these risks and could result in a breach or significant costs of remediation. In addition, such an event would likely receive regulatory scrutiny at both the federal and state level. We are unable to quantify the potential impact of cyber security threats or subsequent related actions. These potential cyber security incidents and corresponding regulatory action could result in a material decrease in revenues and may causesignificant 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 designed 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 the resulting disability, or failures of assets or unauthorized access to assets or information. If our technology systems were to fail or be breached, or those ofthat have impacted our third-party service providers we may be unableas appropriate.
Management has assigned responsibility for the security risk program to fulfillthe Chief Security Officer who has extensive experience in critical business functions,infrastructure protection, including effectively maintaining certain internal controls over financial reporting. Wemultiple years of experience with the Department of Defense. The Chief Security Officer is informed about and monitors prevention, detection, mitigation and remediation efforts through a team of security professionals, many of whom are unableCertified Information Systems Security Professionals, Certified Information Security Managers or have received other cybersecurity certifications. The team has extensive experience selecting, deploying and operating cybersecurity technologies, initiatives and processes that aid in preventing, remediating and mitigating known and unknown cybersecurity threats.
The Chief Security Officer or members of management brief the Board on routine and regular cybersecurity risk and threat updates, typically on a quarterly basis. In the event of a significant threat or incident, management and the Chief Security Officer leverage Xcel Energy’s incident response processes to quantifyassess impacts and resolve incidents. When a significant cybersecurity incident occurs, management communicates with the potential impactBoard of cyberDirectors and relevant committees.
The Board of Directors oversees the risks associated with cybersecurity and the physical security incidents onof our business, our brand,assets, with information security matters being discussed at each regular board meeting as well as at the ONES and our reputation. The cyber security threatAudit Committee meetings throughout the year.
While the ONES Committee has primary committee responsibility for cybersecurity due to the operational issues involved, the Board of Directors has determined that the topic is dynamicof sufficient importance to warrant this comprehensive oversight approach. Augmenting such oversight efforts, the Board conducts drills to practice its response in a possible emergency situation to ensure it is well prepared and evolves continually, and our effortspositioned to prioritize network monitoring may not be effective given the constant changes to threat vulnerability.perform in a possible crisis.
Rising energy prices could negatively impact ourCybersecurity risks are a part of Xcel Energy’s normal course of business.
Although commodity prices are currently relatively low, if fuel costs increase, customer demand could decline and bad debt expense may rise, which could have To date, no cybersecurity incident or attack has had a material impact on our business or results of operations. While weAs of Feb. 21, 2024 there have fuel clause 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 as compared with expenditures for fuel purchases could have an impact on our cash flows. Low fuel costs could have a positive impact on sales, though low oil and natural gas prices could negatively impact oil and gas production activities and subsequently our sales volumes and revenue. We are unablebeen no material cybersecurity incidents to predict future prices or the ultimate impact of such prices on our results of operations or cash flows.report.
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 throughout our service territory, and 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.
Our operations use third party contractors in addition to employees to perform periodic and on-going work.
We rely on third party contractors with specific qualifications to perform work both for ongoing operations and maintenance and for capital construction. We have contractual arrangements with these contractors which typically include performance standards, progress payments, insurance requirements and security for performance. Cyber security breaches seen in the news have at times exploited third party equipment or software in order to gain access. Poor vendor performance could impact on going operations, restoration operations, our reputation and could introduce financial risk or risks of fines.
Item 1B — Unresolved Staff Comments
None.
Item 2 — Properties
Virtually all of the utility plant property of PSCo is subject to the lien of its first mortgage bond indenture.
| | | | | | | | | | | | | | | | | | | | | | | |
| Station, Location and Unit at Dec. 31, 2023 | | Fuel | | Installed | | MW (a) | |
| Steam: | | | | | | | |
| Comanche-Pueblo, CO | | | | | | | |
| Unit 2 | | Coal | | 1975 | | 330 | | |
| Unit 3 | | Coal | | 2010 | | 500 | | (b) |
| Craig-Craig, CO, 2 Units | | Coal | | 1979 - 1980 | | 82 | | (c) |
| Hayden-Hayden, CO, 2 Units | | Coal | | 1965 - 1976 | | 233 | | (d) |
| Pawnee-Brush, CO, 1 Unit | | Coal | | 1981 | | 505 | | |
| Cherokee-Denver, CO, 1 Unit | | Natural Gas | | 1968 | | 310 | | |
| Combustion Turbine: | | | | | | | |
| Blue Spruce-Aurora, CO, 2 Units | | Natural Gas | | 2003 | | 264 | | |
| Cherokee-Denver, CO, 3 Units | | Natural Gas | | 2015 | | 576 | | |
| Fort St. Vrain-Platteville, CO, 6 Units | | Natural Gas | | 1972 - 2009 | | 1,022 | | |
| Manchief, CO, 2 Units . | | Natural Gas | | 2000 | | 250 | | |
| Rocky Mountain-Keenesburg, CO, 3 Units | | Natural Gas | | 2004 | | 592 | | |
| Various locations, 8 Units | | Natural Gas | | Various | | 247 | | |
| Hydro: | | | | | | | |
| Cabin Creek-Georgetown, CO | | | | | | | |
| Pumped Storage, 2 Units | | Hydro | | 1967 | | 210 | | |
| Various locations, 6 Units | | Hydro | | Various | | 23 | | |
| Wind: | | | | | | | |
| Rush Creek, CO, 300 units | | Wind | | 2018 | | 582 | | (e) |
| Cheyenne Ridge, CO, 229 units | | Wind | | 2020 | | 477 | | (e) |
| | | | Total | | 6,203 | | |
(a)Summer 2023 net dependable capacity. Wind is presented as net maximum capacity.
(b)Based on PSCo’s ownership of 67%.
(c)Based on PSCo’s ownership of 10%.
(d)Based on PSCo’s ownership of 76% of Unit 1 and 37% of Unit 2.
(e)Net maximum capacity is attainable only when wind conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2023 the Company’s wind facilities had a weighted-average capacity factors of 43%.
|
| | | | | | | | |
| Electric Utility Generating Stations: | | | | | | | |
Station, Location and Unit
| | Fuel | | Installed | | Summer 2017
Net Dependable
Capability (MW) | |
| Steam: | | | | | | | |
| Comanche-Pueblo, Colo. | | | | | | | |
| Unit 1 | | Coal | | 1973 | | 325 |
| |
| Unit 2 | | Coal | | 1975 | | 335 |
| |
| Unit 3 | | Coal | | 2010 | | 500 |
| (a) |
| Craig-Craig, Colo., 2 Units | | Coal | | 1979-1980 | | 83 |
| (b) |
| Hayden-Hayden, Colo., 2 Units | | Coal | | 1965-1976 | | 233 |
| (c) |
| Pawnee-Brush, Colo., 1 Unit | | Coal | | 1981 | | 505 |
| |
| Valmont-Boulder, Colo., 1 Unit | | Coal | | 1964 | | — |
| (d) |
| Combustion Turbine: | | | | | | | |
| Blue Spruce-Aurora, Colo., 2 Units | | Natural Gas | | 2003 | | 264 |
| |
| Cherokee-Denver, Colo., 1 Unit | | Natural Gas | | 1968 | | 310 |
| (e) |
| Cherokee-Denver, Colo., 3 Units | | Natural Gas | | 2015 | | 576 |
| |
| Fort St. Vrain-Platteville, Colo., 6 Units | | Natural Gas | | 1972-2009 | | 968 |
| |
| Rocky Mountain-Keenesburg, Colo., 3 Units | | Natural Gas | | 2004 | | 580 |
| |
| Various locations, 6 Units | | Natural Gas | | Various | | 171 |
| |
| Hydro: | | | | | | | |
| Cabin Creek-Georgetown, Colo. | | | | | | | |
| Pumped Storage, 2 Units | | Hydro | | 1967 | | 210 |
| |
| Various locations, 9 Units | | Hydro | | Various | | 26 |
| |
| | | | | Total | | 5,086 |
| |
| |
(a)
| Based on PSCo’s ownership interest of 67 percent of Unit 3. |
| |
(b)
| Based on PSCo’s ownership interest of 10 percent. Craig Unit 1 is expected to be early retired in approximately 2025. |
| |
(c)
| Based on PSCo’s ownership interest of 76 percent of Unit 1 and 37 percent of Unit 2. |
| |
(d)
| Valmont Unit 5 was retired in the third quarter of 2017. |
| |
(e)
| Cherokee Unit 4 was fuel switched from coal to natural gas in the third quarter of 2017. |
Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2017:
| | | | | |
| Conductor Miles | | |
Conductor MilesTransmission | |
| |
| 345 KV | 2,6305,421 | |
| 230 KV | 12,91112,244 | |
| |
| 138 KV | 92 | |
| 115 KV | 4,9694,994 | |
| Less than 115 KV | 76,9981,782 | |
| Total Transmission | 24,533 | |
| |
| Distribution | |
| Less than 115 KV | 80,176 | |
| |
| Total | 104,709 | |
PSCo PSCo had 230 electric utility235 electric utility transmission and distribution substations at Dec. 31, 2017.
2023.
Natural gas utility mains at Dec. 31, 2017:
| | | | | |
| Miles | | |
MilesTransmission | 2,024 | |
TransmissionDistribution | 2,31523,494 | |
Distribution | 22,540 |
|
Item 3 — Legal Proceedings
| | |
| ITEM 3 — LEGAL PROCEEDINGS |
PSCo is involved in various litigation matters that are being defended and handled 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 such losses that are 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.
Additional Information
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. Legal fees are generally expensed as incurred.
See Note 1210 to the consolidated financial statements, for further discussion of legal claims and environmental proceedings. See Item 1 and Note 11 to the consolidated financial statementsItem 7 for a discussion of proceedings involving utility rates and other regulatory matters.further information.
Item 4 — Mine Safety Disclosures
| | |
| ITEM 4 — MINE SAFETY DISCLOSURES |
None.
PART II
Item 5 — Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
| | |
| 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. PSCo’s dividends are subject to the FERC’s jurisdiction under the Federal Power Act, which prohibits the payment of dividends out of capital accounts; payment of dividends is allowed out of retained earnings only.
See Note 45 to the consolidated financial statements for further discussion of PSCo’s dividend policy.information.
The dividends declared during 20172023 and 20162022 were as follows:
| | | | | | | | | | | | | | |
| (Millions of Dollars) | | 2023 | | 2022 |
| First quarter | | $ | 183 | | | $ | 129 | |
| Second quarter | | 189 | | | 132 | |
| Third quarter | | 161 | | | 127 | |
| Fourth quarter | | 72 | | | 119 | |
|
| | | | | | | | |
| (Thousands of Dollars) | | 2017 | | 2016 |
| First quarter | | $ | 87,104 |
| | $ | 83,914 |
|
| Second quarter | | 83,978 |
| | 86,509 |
|
| Third quarter | | 88,589 |
| | 82,785 |
|
| Fourth quarter | | 76,195 |
| | 74,208 |
|
Item 6 — Selected Financial Data
This is omitted per conditions set forth in general instructions I (1) (a) and (b) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).
Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations
| | |
| 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) I(1)(a) and (b) of Form 10-K for wholly owned subsidiaries. It is replaced with management’s narrative analysis ofand the results of operations for the current year as set forth in general instructions I (2) I(2)(a) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).
Non-GAAP Financial Review
Measures
The following discussion and analysis by management focuses on those factors that had a material effect on PSCo’sincludes financial condition, results of operations and cash flows during the periods presented, or are expected to have a material impactinformation prepared in the future. It should be read in conjunctionaccordance with the accompanying consolidated financial statements and related notes to the consolidated financial statements.
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 the TCJA’s impact to PSCo and its customers,GAAP, as well as assumptionscertain non-GAAP financial measures such as ongoing earnings. Generally, a non-GAAP financial measure is a measure of a company’s financial performance, financial position or cash flows that is 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.
Earnings Adjusted for Certain Items (Ongoing Earnings)
Ongoing earnings reflect adjustments to GAAP earnings (net income) for certain items.
We use this non-GAAP financial measure to evaluate and provide details of PSCo’s core earnings and underlying performance. For instance, to present ongoing earnings, we may adjust the related GAAP amounts for certain items that are non-recurring in nature. We believe this measurement is useful to investors to evaluate the actual and projected financial performance and contribution of our subsidiaries. This non-GAAP financial measure should not be considered as an alternative to measures calculated and reported in accordance with GAAP.
The following table provides a reconciliation of GAAP earnings (net income) to ongoing earnings:
| | | | | | | | | | | | | | |
| (Millions of Dollars) | | 2023 | | 2022 |
| GAAP net income | | $ | 695 | | | $ | 727 | |
| Loss on Comanche Unit 3 litigation | | 35 | | | — | |
| Workforce reduction expenses | | 20 | | | — | |
| Less: tax effect of adjustment | | (13) | | | — | |
| Ongoing earnings | | $ | 737 | | | $ | 727 | |
Comanche Unit 3 Litigation — In the third quarter of 2023, PSCo recognized a $34 million loss due to a jury verdict in Denver County District Court awarding CORE lost power damages and other statements 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 obligationcosts. PSCo intends 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, 2017 (including risk factors listed from time to time by PSCo in reports filed with the SEC, including “Risk Factors” in Item 1Afile an appeal of this Annual Report on Form 10-Kdecision. Given the non-recurring nature of this specific item, it has been excluded from ongoing earnings.
Workforce Reduction — In 2023, Xcel Energy implemented workforce actions to align resources and Exhibit 99.01 hereto), could cause actual results to differ materially from management expectations as suggested by such forward-looking information: general economic conditions, including inflation rates, monetary fluctuationsinvestments with our evolving business and their impact on capital expenditurescustomer needs, and streamline the abilityorganization for long-term success. Xcel Energy initiated a voluntary retirement program, under which approximately 400 eligible non-bargaining employees retired. Xcel Energy also eliminated approximately 150 non-bargaining employees through an involuntary severance program.
Total Xcel Energy workforce reduction expenses of PSCo and its subsidiaries to obtain financing on favorable terms; business conditions$72 million were recorded in the energy industry, includingfourth quarter of 2023, of which $20 million was attributable to PSCo. Given the risknon-recurring nature of a slow down in the U.S. economy or delay in growth, recovery, trade, fiscal, taxation and environmental policies in areas where PSCothis item, it has a financial interest; customer business conditions; actions of credit rating agencies; competitive factors, including the extent and timing of the entry of additional competition in the markets served by PSCo and its subsidiaries; unusual weather; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates, or have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degreebeen excluded from ongoing earnings.
2023 Comparison to which competition enters the electric and natural gas markets; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; financial or regulatory accounting policies imposed by regulatory bodies; outcomes of regulatory proceedings; availability or cost of capital; and employee work force factors.
Results of Operations
2022
PSCo’s GAAP net income was approximately $494$695 million for 2017,2023, compared with approximately $463to $727 million for 2016. The increase in2022. Ongoing net income was $737 million for 2023, compared to $727 million for 2022. Ongoing earnings driven byprimarily reflects higher electricrecovery of infrastructure investment and natural gas margins, AFUDC primarily related to the Rush Creek wind project and a lower ETR, wasO&M expenses, which were partially offset by higherincreased depreciation, expense, interest charges and the impact of unfavorable weather.
Electric Margin
Electric Revenuesmargin is presented as electric revenues less electric fuel and Margin
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 used in the generation of electricity.coal. However, these price fluctuations have minimal impact on electric margin due to fuel recovery mechanisms that recover fuel expenses. The following table details themechanisms. In addition, electric revenuescustomers receive a credit for PTCs generated, which reduce electric revenue and margin:
|
| | | | | | | | |
| (Millions of Dollars) | | 2017 | | 2016 |
| Electric revenues | | $ | 3,004 |
| | $ | 3,049 |
|
| Electric fuel and purchased power | | (1,127 | ) | | (1,196 | ) |
| Electric margin | | $ | 1,877 |
| | $ | 1,853 |
|
The following tables summarize the components of the changes in electric revenues and electric margin for the year ended Dec. 31:
(offset by lower tax expense).
Electric Revenues,
|
| | | | |
| (Millions of Dollars) | | 2017 vs. 2016 |
| Fuel and purchased power cost recovery | | $ | (58 | ) |
| DSM program revenues (offset by expenses) | | 6 |
|
| Non-fuel riders | | 5 |
|
| Other, net | | 2 |
|
| Total decrease in electric revenues | | $ | (45 | ) |
Fuel and Purchased Power and Electric Margin
| | | | | | | | | | | | | | |
| (Millions of Dollars) | | 2023 | | 2022 |
| Electric revenues | | $ | 3,731 | | | $ | 3,795 | |
| Electric fuel and purchased power | | (1,364) | | | (1,485) | |
| Electric margin | | $ | 2,367 | | | $ | 2,310 | |
|
| | | | |
| (Millions of Dollars) | | 2017 vs. 2016 |
| DSM program revenues (offset by expenses) | | $ | 6 |
|
| Non-fuel riders | | 5 |
|
| Earnings test | | 3 |
|
| Fuel handling and procurement | | 3 |
|
| Trading | | 3 |
|
| Other, net | | 4 |
|
| Total increase in electric margin | | $ | 24 |
|
Changes in Electric Margin
| | | | | | | | |
| (Millions of Dollars) | | 2023 vs. 2022 |
| Regulatory rate outcome | | $ | 56 | |
| Non-fuel riders | | 26 | |
| Wholesale transmission revenue (net) | | 6 | |
| Estimated impact of weather (net of decoupling) | | (23) | |
Sales and demand (a) | | (5) | |
| | |
| | |
| Other (net) | | (3) | |
| Total increase | | $ | 57 | |
(a)Sales excludes weather impact, net of partial decoupling (mechanism expired in September).
Natural Gas RevenuesMargin
Natural gas margin is presented as natural gas revenues less the cost of natural gas sold and Margintransported. 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.
Total naturalNatural 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 natural gas margin due to natural gas cost recovery mechanisms. The following table details natural gas revenues and margin:
|
| | | | | | | | |
| (Millions of Dollars) | | 2017 | | 2016 |
| Natural gas revenues | | $ | 995 |
| | $ | 958 |
|
| Cost of natural gas sold and transported | | (459 | ) | | (425 | ) |
| Natural gas margin | | $ | 536 |
| | $ | 533 |
|
The following tables summarize the components of the changes in natural gas revenues and natural gas margin for the year ended Dec. 31:
Natural Gas Revenues,
|
| | | | |
| (Millions of Dollars) | | 2017 vs. 2016 |
| Purchased natural gas adjustment clause recovery | | $ | 32 |
|
| Infrastructure and integrity riders | | 13 |
|
| Estimated impact of weather | | (4 | ) |
| Retail rate decrease | | (4 | ) |
| Total increase in natural gas revenues | | $ | 37 |
|
Cost of Natural Gas Sold and Transported and Natural Gas Margin
| | | | | | | | | | | | | | |
| (Millions of Dollars) | | 2023 | | 2022 |
| Natural gas revenues | | $ | 1,734 | | | $ | 1,860 | |
| Cost of natural gas sold and transported | | (910) | | | (1,053) | |
| Natural gas margin | | $ | 824 | | | $ | 807 | |
|
| | | | |
| (Millions of Dollars) | | 2017 vs. 2016 |
| Infrastructure and integrity riders | | $ | 13 |
|
| Estimated impact of weather | | (4 | ) |
| Retail rate decrease | | (4 | ) |
| Other, net | | (2 | ) |
| Total increase in natural gas margin | | $ | 3 |
|
| | | | | | | | |
| (Millions of Dollars) | | 2023 vs. 2022 |
| Regulatory rate outcomes | | 47 | |
| Estimated impact of weather | | $ | (12) | |
| | |
| | |
| | |
| | |
| Other (net) | | (18) | |
| Total increase | | $ | 17 | |
Non-Fuel Operating Expenses and Other Items
DSM ProgramO&M Expenses— DSM programO&M expenses increased $7decreased $40 million or 5.8 percent, for 2017 compared with 2016.in 2023. The increasedecrease was primarily due to higher recovery rates. DSM expenses are generally recovered concurrently through ridersimpact of management cost containment efforts, the timing of regulatory deferrals and base rates. Timingthe exit of recovery may not correspond toour appliance repair services business, offset by the period in which costs were incurred.impact of inflationary pressures, including labor.
Depreciation and Amortization— Depreciation and amortization expense increased $28$76 million or 6.3 percent, for 2017 compared with 2016. The increase was primarily attributable to capital investments as well as a new enterprise resource planning system.
AFUDC, Equity and Debt— AFUDC increased by $16 million for 2017 compared with 2016.in 2023. The increase was primarily due to higher CWIP, particularly the Rush Creek wind project.system expansion and new electric and natural gas depreciation rates.
Interest Charges —Interest chargesexpenses increased by $9$41 million or 5.0 percent, for 2017 compared with 2016.in 2023. The increase is primarilywas largely due to higherincreased long-term debt levels to fund capital investments partially offsetand higher interest rates.
| | |
| Public Utility Regulation |
The FERC and state and local regulatory commissions regulate PSCo. PSCo is subject to rate regulation by refinancings at lower interest rates.
Income Taxes — Income tax expense decreased $22 million for 2017 comparedstate utility regulatory agencies, which have jurisdiction with 2016. The decrease in income tax expense was primarily duerespect to the estimated one-time, non-cash, income tax benefit recognizedrates of electric and natural gas distribution companies in Colorado.
Rates are designed to recover plant investment, operating costs and an allowed return on investment. PSCo requests changes in utility rates through commission filings. Changes in operating costs can affect PSCo’s financial results, depending on the timing of rate cases 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 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 the SPP Western Energy Imbalance Service market, an energy imbalance market. |
| DOT | | Pipeline safety compliance. |
Recovery Mechanisms | | | | | | | | |
| Mechanism | | Additional Information |
| Colorado Energy Plan Adjustment | | Recovers the early retirement costs of Comanche Units 1 and 2 to a maximum of 1% of the customer’s bill. |
| Decoupling | | Mechanism to true-up revenue to a baseline amount for residential (excluding lighting and demand) and metered non-demand small C&I classes (pilot program ended Sept. 2023, with amortization of previously deferred amounts expected through 2026). |
| DSM Cost Adjustment | | Recovers electric and gas DSM, interruptible service costs and performance incentives for achieving energy savings goals. |
| ECA | | Recovers fuel and purchased energy costs. Short-term sales margins are shared with customers. The ECA is revised quarterly. |
| Fuel 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. |
| Purchased Capacity Cost Adjustment | | Recovers purchased capacity payments. |
| RES Adjustment | | Recovers the incremental costs of compliance with the RES with a maximum of 1% of the customer’s bill. |
| Steam Cost Adjustment | | Recovers fuel costs to operate the steam system. The Steam Cost Adjustment rate is revised quarterly. |
| Transmission Cost Adjustment | | Recovers costs between rate cases for transmission projects that result in a net increase in capacity or are part of an approved wildfire mitigation plan. |
| | |
| Transportation Electrification Plan | | Recovers costs associated with the investment in and adoption of transportation electrification infrastructure. |
| | |
Pending and Recently Concluded Regulatory Proceedings
Colorado Electric Rate Case — In 2022, PSCo filed a Colorado electric rate case seeking a revised net increase of $253 million. The total request reflected a $303 million increase, which includes $50 million of authorized costs previously recovered through various rider mechanisms. The request was based on a 10.25% ROE, an equity ratio of 55.7% and a 2023 forecast test year with a 2023 average rate base of $11.3 billion.
In September 2023, the CPUC approved a settlement between PSCo and various parties, which included the following terms:
•Retail revenue increase (excluding rider roll-ins) of $95 million (2.96%), based on a 2022 historic test year using year-end rate base with forward looking known and measurable adjustments.
•Weighted-average cost of capital of 6.95% (based on 55.69% equity ratio and 9.3% ROE).
•Termination of the revenue decoupling pilot.
•Continuation of previously authorized trackers and deferrals.
Rates became effective in September 2023.
Colorado Resource Plan— In August 2022, the CPUC approved a settlement for the Colorado Resource Plan, which provides for an expected carbon reduction and the retirement of PSCo’s remaining coal plant by the end of 2030.
In September 2023 (updated in October 2023), PSCo filed its recommended Preferred Portfolio of resources, which proposed a total of 7,521 MW of generation resources, including 4,716 owned MW and 2,805 purchased power MW. The filing also included several other alternative portfolios.
In December 2023, the CPUC approved an alternative portfolio of 5,835 MW. The decision provides an opportunity to assess timing and levels of incremental renewable resources in the fourthJust Transition Plan filing expected to be submitted by June 1, 2024.
Approved portfolio includes the following resources:
| | | | | | | | | | | |
| Generation Resource (in MW) | Company Owned | PPAs | Total |
| Wind Resources | 1,325 | | 375 | | 1,700 | |
| Solar | 858 | | 760 | | 1,618 | |
| Storage | 500 | | 1,348 | | 1,848 | |
| Natural Gas | 450 | | 219 | | 669 | |
| Total | 3,133 | | 2,702 | | 5,835 | |
PSCo expects to invest approximately $4.8 billion in generation resources under the alternative portfolio for the benefit of its customers and achieving the state’s clean energy goals. The CPUC did not approve the May Valley to Longhorn Transmission Line, which was estimated at $250 million.
In December 2023, the CPUC approved two PIMs associated with the generation projects in the portfolio, including a two-way sharing measure related to capital construction costs and another related to ongoing levelized energy costs. These PIMs will be further defined in the written order and related proceedings throughout 2024.
In February 2024, PSCo filed an ARRR to seek approval for an updated portfolio, reflecting inclusion of certain back-up bids and clarifications of the application of PIMs.
Colorado Natural Gas Rate Case — In January 2024, PSCo filed a request with the CPUC seeking an increase to retail natural gas rates of $171 million, or an approximately 9.5% increase in the average residential customer bill. The request is based on a 2023 test year, a 10.25% ROE, an equity ratio of 55% and a $4.2 billion retail rate base which includes projected capital additions through Dec. 31, 2023.PSCo has requested a proposed effective date of Nov. 1, 2024.
PSCo has proposed to defer collection of the increased rates until Feb. 15, 2025 (following the expiration of the rider to recover Winter Storm Uri costs) to mitigate customer bill impacts, with revenues for the deferred period collected over a 12-month period beginning on that date.
The request supports fundamental infrastructure investments to serve customers, consistent with PSCo’s obligation to provide safe, reliable service while enabling PSCo to continue to be a leader of the clean energy transition in partnership with the CPUC to achieve clean heat goals.
| | | | | | |
| Revenue Request (millions of dollars) | | |
| Changes since 2022 rate case: | | |
Plant related investments(a) | | $ | 145 | |
| Operations and maintenance, amortization and other expenses | | 23 | |
| Property tax expense | | 10 | |
| Sales growth | | (7) | |
| | |
| | |
| | |
| Total base revenue request | | $ | 171 | |
| | |
| | |
(a)Includes approximately $32 million as a result of the increase in ROE from 9.2% to 10.25%.
ECA Fuel Recovery — In December 2022, PSCo filed to recover $123 million of under-recovered 2022 fuel costs over two quarters. 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 costs.
In 2023, PSCo submitted interim ECA filings to recover $70 million and $25 million, respectively, of the 2022 under-recovered costs.
In the third quarter, PSCo and CPUC Staff filed a settlement allowing for collection of the remaining amount, which after final adjustments was $37 million. In December 2023, the ALJ issued a recommended decision approving the settlement in full. Recovery of costs is expected to begin in the second quarter of 2024.
Colorado Legislation — In May 2023, Colorado Senate Bill 23-291 passed and was signed into law. The bill includes a number of topics including natural gas and electric fuel incentive mechanisms, natural gas planning rules, regulatory filing requirements, and non-recovery of certain expenses (e.g., certain organizational or membership dues, tax penalties or fines).
In November 2023, the CPUC approved PSCo’s natural gas price risk management plan, establishing upper and lower limits for changes in the GCA rate. As a result costs above the upper limit are deferred for future recovery, with interest, and costs below the lower limit are deferred as a reserve against future cost increases.
The legislation also calls for the CPUC to adopt rules to establish fuel cost mechanisms to align the financial incentives of a utility with the interests of the utility’s customers by Jan. 1, 2025. The CPUC issued a request for initial comments on a potential mechanism under which gas utilities would share a percentage, subject to an annual cap, of cost changes in the GCA. A formal rulemaking is expected to commence in the first half of 2024.
Purchased Power and Transmission Service Providers
PSCo meets its system capacity and energy requirements through its fleet of owned and purchased electric generation resources and, when required, the use of demand-side management programs.
Purchased Power — PSCo purchases power from other utilities, energy marketers and independent power producers. Long-term purchased power contracts for dispatchable resources typically require capacity and energy charges. Much of PSCo’s long-term purchased power is for wind, solar and storage resources. PSCo makes short-term purchases to meet system load and energy requirements, replace generation out of service for maintenance, meet operating reserve obligations, or obtain energy at a lower cost.
Energy Markets — PSCo joined the SPP Western Energy Imbalance Service Market in April 2023. This market is an incremental step in the participation in an organized wholesale market. Energy imbalance 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 risk and hedge sales and purchases. PSCo also engages in trading activity unrelated to 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 the TCJA (see Note 7)scarcity of certain raw materials and increased permanent plant-related adjustments. The ETR was 33.8 percentinterruptions in production and shipping. Inflationary pressures, labor shortages, and the impact of geopolitical events have further exacerbated these disruptions. 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.
Additionally, certain products, components, and equipment, particularly in renewables categories, originate in countries that could face tariffs, fines, or restrictions from government or other regulatory bodies and present a cost and supply risk until there is sufficient capacity and supply base with adequate capacity to meet US needs.
Electric Meters and Transformers
Supply chain issues associated with semiconductors delayed the availability of AMI meters, which led to a reduced number of meters deployed in 2022. PSCo saw significant improvement in meter availability in 2023 and we expect normal conditions in 2024 and going forward. PSCo expects to complete AMI meter deployment in 2025.
Additionally, the availability of certain transformers is an industry-wide issue that has significantly impacted and in some cases resulted in delays to projects and new customer connections. Proposed governmental actions related to transformer efficiency standards may compound these delays in the future. PSCo continues to seek alternative suppliers and prioritize work plans to mitigate the impacts of supply constraints.
Solar Resources
In August 2023, the U.S. Department of Commerce completed its anti-circumvention investigation. It concluded that CSPV solar panels and cells imported from Malaysia, Vietnam, Thailand, and Cambodia would be subject to incremental tariffs ranging from 50% to 250%. These countries account for 2017 comparedmore than 80% of CSPV panel imports.
An interim stay on tariffs remains in effect until June 2024. Many significant solar projects have resumed with 37.1 percent for 2016. The lower ETRmodified costs and projected in-service dates, including certain PPAs in 2017 was primarilyPSCo. Further policy action, a change in the interim stay of tariffs, or other restrictions on solar imports (e.g., due to implementation of the adjustments referenced above.Uyghur Forced Labor Protection Act) or disruptions in solar imports from key suppliers could impact project timelines and costs.
Item 7A — Quantitative and Qualitative Disclosures About Market Risk
| | |
| 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 10 to the consolidated financial statements for further discussion of market risks associated with derivatives.
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, when necessary, 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 some credit and nonperformancenon-performance risk.
Though no material non-performance risk currently exists with the counterparties to PSCo’s commodity derivative contracts, distress in the financial markets may in the future impact that risk to the extent it impacts those counterparties. Distress in the financial markets may also impact counterparty risk and the fair value of the securities in the master pension trust, as well as PSCo’s ability to earn a return on short-term investments of excess cash.fund.
Commodity Price Risk — PSCo is We are exposed to commodity price risk in itsour electric and natural gas operations. Commodity price risk is managed by entering into long-long and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products and for various 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, which is made upcommittee.
Fair value of management personnel not directly involved in the activities governed by the policy.
At Dec. 31, 2017, the fair values by source for net commodity trading contract assets werecontracts as follows:of Dec. 31, 2023:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Futures / Forwards Maturity |
| (Millions of Dollars) | |
Less Than
1 Year | |
1 to 3
Years | |
4 to 5
Years | |
Greater Than
5 Years | | Total
Fair Value |
PSCo (a) | | $ | — | | | $ | 1 | | | $ | 2 | | | $ | — | | | $ | 3 | |
PSCo (b) | | (10) | | | 6 | | | 2 | | | — | | | (2) | |
| | $ | (10) | | | $ | 7 | | | $ | 4 | | | $ | — | | | $ | 1 | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | Futures / Forwards |
| (Thousands of Dollars) | | Source of Fair Value | | Maturity Less Than 1 Year | | Maturity 1 to 3 Years | | Maturity 4 to 5 Years | | Maturity Greater Than 5 Years | | Total Futures/ Forwards Fair Value |
| PSCo | | 1 |
| | $ | 291 |
| | $ | 179 |
| | $ | — |
| | $ | — |
| | $ | 470 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Options Maturity |
| (Millions of Dollars) | |
Less Than
1 Year | |
1 to 3
Years | |
4 to 5
Years | |
Greater Than
5 Years | | Total
Fair Value |
| | | | | | | | | | |
PSCo (b) | | $ | 4 | | | $ | — | | | $ | — | | | $ | — | | | $ | 4 | |
| | | | | | | | | | |
1 — (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 mechanisms for the years ended Dec. 31 were as follows:31:
| | | | | | | | | | | | | | |
| (Millions of Dollars) | | 2023 | | 2022 |
| Fair value of commodity trading net contracts outstanding at Jan. 1 | | $ | — | | | $ | (15) | |
| Contracts realized or settled during the period | | (12) | | | (8) | |
| Commodity trading contract additions and changes during the period | | 17 | | | 23 | |
| Fair value of commodity trading net contracts outstanding at Dec.31 | | $ | 5 | | | $ | — | |
|
| | | | | | | | |
| (Thousands of Dollars) | | 2017 | | 2016 |
| Fair value of commodity trading net contract assets outstanding at Jan. 1 | | $ | (188 | ) | | $ | 112 |
|
| Contracts realized or settled during the period | | (775 | ) | | (654 | ) |
| Commodity trading contract additions and changes during the period | | 1,433 |
| | 354 |
|
| Fair value of commodity trading net contract assets outstanding at Dec. 31 | | $ | 470 |
| | $ | (188 | ) |
At Dec. 31, 2017, a 10 percentA 10% increase and 10% decrease in forward market prices for PSCo’s commodity trading contracts would increasehave likewise increased and decreased pretax income from continuing operations, by approximately $0.6$3 million whereas a 10 percent decrease would decrease pretax income by approximately $0.6 million. Atat Dec. 31, 2016, a 10 percent increase in market prices for commodity trading contracts would decrease pretax income by approximately $0.92023 and $7 million whereas a 10 percent decrease would increase pretax income by approximately $0.9 million.at Dec. 31, 2022. Market price movements can exceed 10% under abnormal circumstances.
PSCo’s wholesale andXcel Energy’s commodity trading operations measure the outstanding risk exposure to price changes on transactions, contracts and obligations that have been entered into, but not closed, including transactions that are not recorded at fair value, using an industry standard methodology known as Value at Risk (VaR).VaR. VaR expresses the potential change in fair value onof the outstanding transactions, 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 purchases and normal sales, calculated on a consolidated basis using a Monte Carlo simulation with a 95 percent95% confidence level and a one-day holding period, were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (Millions of Dollars) | | Year Ended Dec. 31 | | | | Average | | High | | Low |
| 2023 | | $ | — | | | | | $ | — | | | $ | 1 | | | $ | — | | |
| 2022 | | $ | 2 | | | | | $ | 1 | | | $ | 5 | | | $ | — | | |
|
| | | | | | | | | | | | | | | | | | | | |
| (Millions of Dollars) | | Year Ended Dec. 31 | | VaR Limit | | Average | | High | | Low |
| 2017 | | $ | 0.18 |
| | $ | 3.00 |
| | $ | 0.21 |
| | $ | 0.66 |
| | $ | 0.04 |
|
| 2016 | | 0.09 |
| | 3.00 |
| | 0.16 |
| | 0.38 |
| | | 0.05 |
|
Interest Rate Risk — PSCo is subject to the risk of fluctuating interest rates in the normal course of business.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.
At Dec. 31, 2017, a 100-basis-point change in the benchmark rate on PSCo’s variable rate debt would have no impact on annual pretax interest expense, and at Dec. 31, 2016 a 100-basis-pointA 100 basis point change in the benchmark rate on PSCo’s variable rate debt would impact annual pretax interest expense annually by approximately $1.3 million. See Note 10$4 million and $3 million in 2023 and 2022, respectively.
The 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 the consolidated financial statements for a discussion of PSCo’soptimize potential investment risk and minimize interest rate derivatives.risk associated with changes in the 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 monitors these policies to reflect changes and scope of operations.
At Dec. 31, 2017,2023, a 10 percent10% increase in commodity prices would have resulted in an increase in credit exposure of $17.4$2 million, while a decrease in prices of 10 percent10% would have resulted in an increasea decrease in credit exposure of $5.5$2 million. At Dec. 31, 2016,2022, a 10 percent10% increase in commodity prices would have resulted in an increase in credit exposure of $14.3$13 million, while a decrease in prices of 10 percent10% would have resulted in a decrease in credit exposure of $2.2$6 million.
PSCo conducts standard credit reviews for all counterparties. PSCowholesale, trading and non-trading commodity counterparties and employs additional credit risk control mechanisms when appropriate,controls, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures.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 follows accountingDerivative contracts, with the exception of those designated as normal purchases and disclosure guidance onnormal sales, are reported at fair value. PSCo’s investments held in pension and other postretirement funds are also subject to fair value measurements that contains a hierarchy for inputs used in measuring fair valueaccounting. See Notes 8 and requires disclosure of the observability of the inputs used in these measurements. See Note 109 to the consolidated financial statements for further discussion of the fair value hierarchy and the amounts of assets and liabilities measured at fair value that have been assigned to Level 3.information.
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 set forth in the contracts. Given this assessment and the typically short duration of these contracts, 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, 2017. PSCo also assesses the impact of its own credit risk when determining the fair value of commodity derivative liabilities. The impact of discounting commodity derivative liabilities for credit risk was immaterial to the fair value of commodity derivative liabilities at Dec. 31, 2017.
Commodity derivative assets and liabilities assigned to Level 3 typically consist of forward and option contracts that are long-term in nature or relate to inactive delivery locations. Determining the fair value of certain commodity forwards and options can require management to make use of subjective price and volatility forecasts for inactive delivery locations and for contracts that extend to periods beyond those readily observable on active exchanges or quoted by brokers. When less observable forward price and volatility forecasts are significant to determining the value of commodity forwards and options, these instruments are assigned to Level 3. There were immaterial Level 3 commodity derivative assets or liabilities at Dec. 31, 2017.
Item 8 — Financial Statements and Supplementary Data
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| ITEM 8 — FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
See Item 15-1 in Part IV for an index of financial statements included herein.
See Note 1714 to the consolidated financial statements for summarized quarterly financial data.further information.
Management Report on Internal ControlsControl 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.
In 2016, PSCo implemented the general ledger modules of a new enterprise resource planning system. PSCo initiated and implemented additional work management systems modules in 2017. PSCo does not believe this implementation had an adverse effect on its internal control over financial reporting.
PSCo management assessed the effectiveness of PSCo’s internal control over financial reporting as of Dec. 31, 2017.2023. 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, 2017,2023, PSCo’s internal control over financial reporting is effective at the reasonable assurance level based on those criteria.
| | | | | | | | |
| | |
/s/ BEN FOWKE | | /s/ ROBERT C. FRENZEL | | /s/ BRIAN J. VAN ABEL |
Ben Fowke | | Robert C. Frenzel | | Brian J. Van Abel |
Chairman, and Chief Executive Officer and Director | | Executive Vice President, Chief Financial Officer and Director |
Feb. 23, 201821, 2024 | | Feb. 23, 201821, 2024 |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholder and the Board of Directors and Stockholder 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”"Company") as of December 31, 20172023 and 2016,2022, the related consolidated statements of income, comprehensive income, common stockholder's equity, and cash flows and common stockholder’s equity, for each of the three years in the period ended December 31, 2017,2023, 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, 20172023 and 2016,2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017,2023, 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 recovery in future rates of incurred costs and refunds 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 filings, legal decisions and recommendations being evaluated by the Commissions, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates. We evaluated historic orders for precedents of the Commissions’ treatment of similar costs under similar circumstances. We compared the regulatory orders, filings and other publicly available information 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 23, 201821, 2024 |
|
| We have served as the Company’s auditor since 2002. |
We have served as the Company's auditor since 2002.
PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(amounts in thousands)millions)
| | | | Year Ended Dec. 31 |
| | 2017 | | 2016 | | 2015 |
| | Year Ended Dec. 31 | | | | Year Ended Dec. 31 |
| | 2023 | | | | 2023 | | 2022 | | 2021 |
| Operating revenues | | | | | |
| Electric | $ | 3,003,808 |
| | $ | 3,049,352 |
| | $ | 3,115,257 |
|
| Electric | |
| Electric | |
| Natural gas | 995,214 |
| | 957,721 |
| | 1,006,666 |
|
| Steam and other | 43,487 |
| | 40,723 |
| | 41,590 |
|
| Other | |
| Total operating revenues | 4,042,509 |
| | 4,047,796 |
| | 4,163,513 |
|
| | | | | | |
| Operating expenses | | | | | |
| Operating expenses | |
| Operating expenses | |
| Electric fuel and purchased power | |
| Electric fuel and purchased power | |
| Electric fuel and purchased power | 1,126,660 |
| | 1,196,417 |
| | 1,246,666 |
|
| Cost of natural gas sold and transported | 458,717 |
| | 425,410 |
| | 501,824 |
|
| Cost of sales — steam and other | 16,146 |
| | 15,872 |
| | 17,788 |
|
| Operating and maintenance expenses | 762,817 |
| | 762,416 |
| | 761,901 |
|
| Demand side management program expenses | 125,029 |
| | 118,175 |
| | 128,681 |
|
| Demand side management expenses | |
| Depreciation and amortization | 471,515 |
| | 443,555 |
| | 411,667 |
|
| Taxes (other than income taxes) | 195,695 |
| | 196,330 |
| | 195,285 |
|
| Loss on Comanche Unit 3 litigation | |
| Workforce reduction expenses | |
| Total operating expenses | 3,156,579 |
| | 3,158,175 |
| | 3,263,812 |
|
| | | | | | |
| Operating income | 885,930 |
| | 889,621 |
| | 899,701 |
|
| Operating income | |
| Operating income | |
| | | | | | |
| Other income, net | 9,852 |
| | 3,817 |
| | 2,964 |
|
| Other income (expense), net | |
| Other income (expense), net | |
| Other income (expense), net | |
| Allowance for funds used during construction — equity | 29,803 |
| | 18,557 |
| | 14,485 |
|
| | | | | | |
| Interest charges and financing costs | | | | | |
Interest charges — includes other financing costs of $6,281, $6,289 and $6,285, respectively | 190,694 |
| | 181,631 |
| | 177,430 |
|
| Interest charges and financing costs | |
| Interest charges and financing costs | |
| Interest charges — includes other financing costs of $8, $8 and $8, respectively | |
| Interest charges — includes other financing costs of $8, $8 and $8, respectively | |
| Interest charges — includes other financing costs of $8, $8 and $8, respectively | |
| Allowance for funds used during construction — debt | (11,407 | ) | | (7,045 | ) | | (5,522 | ) |
| Total interest charges and financing costs | 179,287 |
| | 174,586 |
| | 171,908 |
|
| | | | | | |
| Income before income taxes | 746,298 |
| | 737,409 |
| �� | 745,242 |
|
| Income taxes | 252,179 |
| | 273,918 |
| | 278,440 |
|
| Income before income taxes | |
| Income before income taxes | |
| Income tax expense | |
| Net income | $ | 494,119 |
| | $ | 463,491 |
| | $ | 466,802 |
|
See Notes to Consolidated Financial Statements
PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(amounts in thousands)millions)
|
| | | | | | | | | | | | |
| | | Year Ended Dec. 31 |
| | | 2017 | | 2016 | | 2015 |
| Net income | | $ | 494,119 |
| | $ | 463,491 |
| | $ | 466,802 |
|
| | | | | | | |
| Other comprehensive income (loss) | | | | | | |
| | | | | | | |
| Pension and retiree medical benefits: | | | | | | |
| Net pension and retiree medical losses arising during the period, net of tax of $(3), $(138), and $0 | | (5 | ) | | (223 | ) | | — |
|
| Amortization of losses included in net periodic benefit cost, net of tax of $4, $2, and $0, respectively | | 5 |
| | 3 |
| | — |
|
| | | — |
| | (220 | ) | | — |
|
| | | | | | | |
| Derivative instruments: | | | | | | |
| Net fair value decrease, net of tax of $0, $0, and $(20), respectively | | — |
| | — |
| | (30 | ) |
| Reclassification of losses to net income, net of tax of $610, $648, and $39, respectively | | 1,005 |
| | 1,056 |
| | 72 |
|
| | | 1,005 |
| | 1,056 |
| | 42 |
|
| | | | | | | |
| Other comprehensive income | | 1,005 |
| | 836 |
| | 42 |
|
| Comprehensive income | | $ | 495,124 |
| | $ | 464,327 |
| | $ | 466,844 |
|
| | | | | | | | | | | | | | | | | | | | |
| | Year Ended Dec. 31 |
| | 2023 | | 2022 | | 2021 |
| Net income | | $ | 695 | | | $ | 727 | | | $ | 660 | |
| Other comprehensive income | | | | | | |
| Pension and retiree medical benefits: | | | | | | |
| Net pension and retiree medical gain (loss) arising during the period, net of tax | | — | | | (1) | | | — | |
| Reclassification of loss to net income, net of tax | | 1 | | | — | | | — | |
| Derivative instruments: | | | | | | |
| Reclassification of loss to net income, net of tax | | 1 | | | 1 | | | 2 | |
| | | | | | |
| Total other comprehensive income | | 2 | | | — | | | 2 | |
| Total comprehensive income | | $ | 697 | | | $ | 727 | | | $ | 662 | |
See Notes to Consolidated Financial Statements
PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(amounts in thousands)millions)
| | | | Year Ended Dec. 31 |
| | 2017 | | 2016 | | 2015 |
| Year Ended Dec. 31 | | | Year Ended Dec. 31 |
| 2023 | | | 2023 | | 2022 | | 2021 |
| Operating activities | | | | | |
| Net income | |
| Net income | |
| Net income | $ | 494,119 |
| | $ | 463,491 |
| | $ | 466,802 |
|
| Adjustments to reconcile net income to cash provided by operating activities: | | | | | |
| Depreciation and amortization | 475,592 |
| | 446,179 |
| | 416,427 |
|
| Demand side management program amortization | 672 |
| | 2,138 |
| | 3,509 |
|
| Depreciation and amortization | |
| Depreciation and amortization | |
| Deferred income taxes | 207,817 |
| | 222,002 |
| | 277,896 |
|
| Amortization of investment tax credits | (2,803 | ) | | (2,805 | ) | | (2,807 | ) |
| | Allowance for equity funds used during construction | |
| Allowance for equity funds used during construction | |
| Allowance for equity funds used during construction | (29,803 | ) | | (18,557 | ) | | (14,485 | ) |
| Provision for bad debts | 14,303 |
| | 14,121 |
| | 13,052 |
|
| Net realized and unrealized hedging and derivative transactions | 2,364 |
| | 1,325 |
| | 2,414 |
|
| Other | 6 |
| | (388 | ) | | 2,500 |
|
| | Changes in operating assets and liabilities: | | | | | |
| Changes in operating assets and liabilities: | |
| Changes in operating assets and liabilities: | |
| Accounts receivable | |
| Accounts receivable | |
| Accounts receivable | (2,229 | ) | | (14,227 | ) | | 8,872 |
|
| Accrued unbilled revenues | 1,277 |
| | (20,866 | ) | | 17,837 |
|
| Inventories | (9,099 | ) | | 172 |
| | 33,417 |
|
| Prepayments and other | 188 |
| | 68,693 |
| | 10,483 |
|
| Other current assets | |
| Accounts payable | 20,410 |
| | 38,439 |
| | (40,982 | ) |
| Net regulatory assets and liabilities | (22,548 | ) | | 4,143 |
| | 78,055 |
|
| Other current liabilities | 71,776 |
| | 1,892 |
| | 19,654 |
|
| Pension and other employee benefit obligations | (16,515 | ) | | (10,627 | ) | | (23,449 | ) |
| Change in other noncurrent assets | (785 | ) | | (6,750 | ) | | 4,086 |
|
| Change in other noncurrent liabilities | (2,982 | ) | | (22,120 | ) | | (35,334 | ) |
| Other, net | |
| Net cash provided by operating activities | 1,201,760 |
| | 1,166,255 |
| | 1,237,947 |
|
| | | | | | |
| Investing activities | | | | | |
| Investing activities | |
| Investing activities | |
| Utility capital/construction expenditures | (1,475,697 | ) | | (1,113,800 | ) | | (995,597 | ) |
| Proceeds from insurance recoveries | — |
| | 608 |
| | — |
|
| Allowance for equity funds used during construction | 29,803 |
| | 18,557 |
| | 14,485 |
|
| Utility capital/construction expenditures | |
| Utility capital/construction expenditures | |
| Investments in utility money pool arrangement | (954,000 | ) | | (444,000 | ) | | (196,300 | ) |
| Repayments from utility money pool arrangement | 934,000 |
| | 444,000 |
| | 212,300 |
|
| Other | (657 | ) | | (1,460 | ) | | — |
|
| | Net cash used in investing activities | |
| Net cash used in investing activities | |
| Net cash used in investing activities | (1,466,551 | ) | | (1,096,095 | ) | | (965,112 | ) |
| | | | | | |
| Financing activities | | | | | |
| (Repayments of) proceeds from short-term borrowings, net | (129,000 | ) | | 115,000 |
| | (368,000 | ) |
| Financing activities | |
| Financing activities | |
| Proceeds from short-term borrowings, net | |
| Proceeds from short-term borrowings, net | |
| Proceeds from short-term borrowings, net | |
| Borrowings under utility money pool arrangement | 40,000 |
| | 524,500 |
| | 165,000 |
|
| Repayments under utility money pool arrangement | (40,000 | ) | | (524,500 | ) | | (165,000 | ) |
| Proceeds from issuance of long-term debt | 393,791 |
| | 244,507 |
| | 246,751 |
|
| Repayments of long-term debt | — |
| | (129,500 | ) | | — |
|
| Capital contributions from parent | 335,576 |
| | 38,755 |
| | 175,210 |
|
| Dividends paid to parent | (333,879 | ) | | (336,581 | ) | | (330,846 | ) |
| Other | (110 | ) | | — |
| | — |
|
| Net cash provided by (used in) financing activities | 266,378 |
| | (67,819 | ) | | (276,885 | ) |
| | Net cash provided by financing activities | |
| Net cash provided by financing activities | |
| Net cash provided by financing activities | |
| | | | | | |
| Net change in cash and cash equivalents | 1,587 |
| | 2,341 |
| | (4,050 | ) |
| Cash and cash equivalents at beginning of period | 5,926 |
| | 3,585 |
| | 7,635 |
|
| Cash and cash equivalents at end of period | $ | 7,513 |
| | $ | 5,926 |
| | $ | 3,585 |
|
| Net change in cash and cash equivalents | |
| Net change in cash and cash equivalents | |
| Cash, cash equivalents and restricted cash at beginning of period | |
| Cash, cash equivalents and restricted cash at end of period | |
| | | | | | |
| 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) | $ | (174,978 | ) | | $ | (171,714 | ) | | $ | (165,546 | ) |
| Cash (paid) received for income taxes, net | (7,717 | ) | | 22,827 |
| | 13,822 |
|
| Supplemental disclosure of non-cash investing transactions: | | | | | |
| Property, plant and equipment additions in accounts payable | $ | 183,858 |
| | $ | 68,870 |
| | $ | 106,912 |
|
| Cash paid for interest (net of amounts capitalized) | |
| Cash paid for interest (net of amounts capitalized) | |
| Cash paid for income taxes, net | |
| | 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 | |
| Accrued property, plant and equipment additions | |
| Inventory transfers to property, plant and equipment | |
| Operating lease right-of-use assets | |
| Allowance for equity funds used during construction | |
See Notes to Consolidated Financial Statements
PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(amounts in thousands,millions, except share and per share data)share)
| | | | | | | | | | | | | | |
| | Dec. 31 |
| | | 2023 | | 2022 |
| Assets | | | | |
| Current assets | | | | |
| Cash and cash equivalents | | $ | 13 | | | $ | 10 | |
| Accounts receivable, net | | 492 | | | 562 | |
| Accounts receivable from affiliates | | 28 | | | 11 | |
| Accrued unbilled revenues | | 361 | | | 519 | |
| Inventories | | 258 | | | 319 | |
| Regulatory assets | | 304 | | | 411 | |
| Derivative instruments | | 11 | | | 65 | |
| Prepayments and other | | 95 | | | 103 | |
| Total current assets | | 1,562 | | | 2,000 | |
| | | | |
| Property, plant and equipment, net | | 21,035 | | | 19,652 | |
| | | | |
| Other assets | | | | |
| Regulatory assets | | 1,267 | | | 1,277 | |
| Derivative instruments | | 15 | | | 22 | |
| Operating lease right-of-use assets | | 366 | | | 437 | |
| Other | | 383 | | | 231 | |
| Total other assets | | 2,031 | | | 1,967 | |
| Total assets | | $ | 24,628 | | | $ | 23,619 | |
| | | | |
| Liabilities and Equity | | | | |
| Current liabilities | | | | |
| Current portion of long-term debt | | $ | — | | | $ | 250 | |
| Borrowings under utility money pool arrangement | | 51 | | | — | |
| Short-term debt | | 320 | | | 294 | |
| Accounts payable | | 704 | | | 764 | |
| Accounts payable to affiliates | | 83 | | | 75 | |
| Regulatory liabilities | | 70 | | | 59 | |
| Taxes accrued | | 261 | | | 242 | |
| Accrued interest | | 68 | | | 59 | |
| Dividends payable to parent | | 72 | | | 120 | |
| Derivative instruments | | 17 | | | 30 | |
| Operating lease liabilities | | 102 | | | 80 | |
| Other | | 177 | | | 115 | |
| Total current liabilities | | 1,925 | | | 2,088 | |
| | | | |
| Deferred credits and other liabilities | | | | |
| Deferred income taxes | | 1,894 | | | 1,983 | |
| | | | |
| Regulatory liabilities | | 2,562 | | | 2,489 | |
| Asset retirement obligations | | 383 | | | 476 | |
| Derivative instruments | | — | | | 9 | |
| Customer advances | | 124 | | | 144 | |
| Pension and employee benefit obligations | | 40 | | | 13 | |
| Operating lease liabilities | | 290 | | | 379 | |
| Other | | 218 | | | 198 | |
| Total deferred credits and other liabilities | | 5,511 | | | 5,691 | |
| | | | |
| Commitments and contingencies | | | | |
| Capitalization | | | | |
| Long-term debt | | 7,450 | | | 6,610 | |
| Common stock — 100 shares authorized of $0.01 par value; 100 shares outstanding at Dec. 31, 2023 and Dec. 31, 2022, respectively | | — | | | — | |
| Additional paid in capital | | 7,412 | | | 6,992 | |
| Retained earnings | | 2,350 | | | 2,260 | |
| Accumulated other comprehensive loss | | (20) | | | (22) | |
| Total common stockholder's equity | | 9,742 | | | 9,230 | |
| Total liabilities and stockholder's equity | | $ | 24,628 | | | $ | 23,619 | |
| See Notes to Consolidated Financial Statements |
|
| | | | | | | |
| | Dec. 31 |
| | 2017 | | 2016 |
| Assets | | | |
| Current assets | | | |
| Cash and cash equivalents | $ | 7,513 |
| | $ | 5,926 |
|
| Accounts receivable, net | 294,403 |
| | 304,900 |
|
| Accounts receivable from affiliates | 14,719 |
| | 9,421 |
|
| Investments in utility money pool arrangement | 20,000 |
| | — |
|
| Accrued unbilled revenues | 295,801 |
| | 297,078 |
|
| Inventories | 214,489 |
| | 202,220 |
|
| Regulatory assets | 77,337 |
| | 103,783 |
|
| Derivative instruments | 3,197 |
| | 10,934 |
|
| Prepayments and other | 35,720 |
| | 34,559 |
|
| Total current assets | 963,179 |
| | 968,821 |
|
| | | | |
| Property, plant and equipment, net | 14,025,751 |
| | 12,849,799 |
|
| | | | |
| Other assets | |
| | |
|
| Regulatory assets | 950,258 |
| | 958,429 |
|
| Derivative instruments | 1,009 |
| | 3,398 |
|
| Other | 27,429 |
| | 25,637 |
|
| Total other assets | 978,696 |
| | 987,464 |
|
| Total assets | $ | 15,967,626 |
| | $ | 14,806,084 |
|
| | | | |
| Liabilities and Equity | |
| | |
|
| Current liabilities | |
| | |
|
| Current portion of long-term debt | $ | 305,577 |
| | $ | 5,270 |
|
| Short-term debt | — |
| | 129,000 |
|
| Accounts payable | 492,829 |
| | 376,186 |
|
| Accounts payable to affiliates | 58,749 |
| | 98,797 |
|
| Regulatory liabilities | 66,126 |
| | 101,110 |
|
| Taxes accrued | 222,517 |
| | 171,862 |
|
| Accrued interest | 48,552 |
| | 48,619 |
|
| Dividends payable to parent | 76,195 |
| | 74,208 |
|
| Derivative instruments | 7,348 |
| | 6,788 |
|
| Other | 92,333 |
| | 73,022 |
|
| Total current liabilities | 1,370,226 |
| | 1,084,862 |
|
| | | | |
| Deferred credits and other liabilities | |
| | |
|
| Deferred income taxes | 1,644,476 |
| | 2,889,129 |
|
| Deferred investment tax credits | 27,858 |
| | 30,661 |
|
| Regulatory liabilities | 1,933,488 |
| | 512,933 |
|
| Asset retirement obligations | 347,769 |
| | 289,563 |
|
| Derivative instruments | 3,468 |
| | 7,828 |
|
| Customer advances | 162,614 |
| | 162,742 |
|
| Pension and employee benefit obligations | 287,783 |
| | 285,774 |
|
| Other | 58,923 |
| | 62,201 |
|
| Total deferred credits and other liabilities | 4,466,379 |
| | 4,240,831 |
|
| | | | |
| Commitments and contingencies |
|
| |
|
|
| Capitalization | |
| | |
|
| Long-term debt | 4,302,698 |
| | 4,210,936 |
|
Common stock — 100 shares authorized of $0.01 par value; 100 shares outstanding at Dec. 31, 2017 and 2016, respectively | — |
| | — |
|
| Additional paid in capital | 4,032,826 |
| | 3,633,216 |
|
| Retained earnings | 1,822,229 |
| | 1,659,239 |
|
| Accumulated other comprehensive loss | (26,732 | ) | | (23,000 | ) |
| Total common stockholder’s equity | 5,828,323 |
| | 5,269,455 |
|
| Total liabilities and equity | $ | 15,967,626 |
| | $ | 14,806,084 |
|
See Notes to Consolidated Financial Statements
PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
(amounts in thousands,millions, except share and per 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, 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 | |
| | | | | | | | | | | |
| Net income | | | | | | | 695 | | | | | 695 | |
| Other comprehensive income | | | | | | | | | 2 | | | 2 | |
| Common dividends declared to parent | | | | | | | (605) | | | | | (605) | |
| Contribution of capital by parent | | | | | 420 | | | | | | | 420 | |
| | | | | | | | | | | |
| Balance at Dec. 31, 2023 | 100 | | | $ | — | | | $ | 7,412 | | | $ | 2,350 | | | $ | (20) | | | $ | 9,742 | |
| | | | | | | | | | | |
| See Notes to Consolidated Financial Statements |
|
| | | | | | | | | | | | | | | | | | | | | | |
| | Common Stock Issued | | | | Accumulated Other Comprehensive Income (Loss) | | Total Common Stockholder’s Equity |
| | Shares | | Par Value | | Additional Paid In Capital | | Retained Earnings | | |
| Balance at Dec. 31, 2014 | 100 |
| | $ | — |
| | $ | 3,522,788 |
| | $ | 1,386,929 |
| | $ | (23,878 | ) | | $ | 4,885,839 |
|
| Net income | | | | | | | 466,802 |
| | | | 466,802 |
|
| Other comprehensive income | | | | | | | | | 42 |
| | 42 |
|
| Common dividends declared to parent | | | | | | | (330,567 | ) | | | | (330,567 | ) |
| Contribution of capital by parent | | | | | 98,036 |
| | | | | | 98,036 |
|
| Balance at Dec. 31, 2015 | 100 |
| | $ | — |
| | $ | 3,620,824 |
| | $ | 1,523,164 |
| | $ | (23,836 | ) | | $ | 5,120,152 |
|
| Net income | | | | | | | 463,491 |
| | | | 463,491 |
|
| Other comprehensive income | | | | | | | | | 836 |
| | 836 |
|
| Common dividends declared to parent | | | | | | | (327,416 | ) | | | | (327,416 | ) |
| Contribution of capital by parent | | | | | 12,392 |
| | | | | | 12,392 |
|
| Balance at Dec. 31, 2016 | 100 |
| | $ | — |
| | $ | 3,633,216 |
| | $ | 1,659,239 |
| | $ | (23,000 | ) | | $ | 5,269,455 |
|
| Net income | | | | | | | 494,119 |
| | | | 494,119 |
|
| Other comprehensive income | | | | | | | | | 1,005 |
| | 1,005 |
|
| Common dividends declared to parent | | | | | | | (335,866 | ) | | | | (335,866 | ) |
| Contribution of capital by parent | | | | | 399,610 |
| | | | | | 399,610 |
|
| Adoption of ASU No. 2018-02 | | | | | | | 4,737 |
| | (4,737 | ) | | — |
|
| Balance at Dec. 31, 2017 | 100 |
| | $ | — |
| | $ | 4,032,826 |
| | $ | 1,822,229 |
| | $ | (26,732 | ) | | $ | 5,828,323 |
|
PUBLIC SERVICE COMPANY of COLORADO
See Notes to Consolidated Financial Statements
PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CAPITALIZATION
(amounts in thousands, except share and per share data)
|
| | | | | | | |
| | Dec. 31 |
| | 2017 | | 2016 |
| Long-Term Debt | | | |
| First Mortgage Bonds, Series due: | | | |
| Aug. 1, 2018, 5.8% | $ | 300,000 |
| | $ | 300,000 |
|
| June 1, 2019, 5.125% | 400,000 |
| | 400,000 |
|
| Nov. 15, 2020, 3.2% | 400,000 |
| | 400,000 |
|
| Sept. 15, 2022, 2.25% | 300,000 |
| | 300,000 |
|
| March 15, 2023, 2.5% | 250,000 |
| | 250,000 |
|
| May 15, 2025, 2.9% | 250,000 |
| | 250,000 |
|
| Sept. 1, 2037, 6.25% | 350,000 |
| | 350,000 |
|
| Aug. 1, 2038, 6.5% | 300,000 |
| | 300,000 |
|
| Aug. 15, 2041, 4.75% | 250,000 |
| | 250,000 |
|
| Sept. 15, 2042, 3.6% | 500,000 |
| | 500,000 |
|
| March 15, 2043, 3.95% | 250,000 |
| | 250,000 |
|
| March 15, 2044, 4.3% | 300,000 |
| | 300,000 |
|
| June 15, 2046, 3.55% | 250,000 |
| | 250,000 |
|
| June 15, 2047, 3.8% | 400,000 |
| | — |
|
| Capital lease obligations, through 2060, 11.2% — 14.3% | 150,658 |
| | 155,927 |
|
| Unamortized discount | (13,472 | ) | | (12,922 | ) |
| Unamortized debt expense | (28,911 | ) | | (26,799 | ) |
| Total | 4,608,275 |
| | 4,216,206 |
|
| Less current maturities | 305,577 |
| | 5,270 |
|
| Total long-term debt | $ | 4,302,698 |
| | $ | 4,210,936 |
|
| | | | |
| Common Stockholder’s Equity | |
| | |
|
Common Stock — 100 shares authorized of $0.01 par value; 100 shares outstanding at Dec. 31, 2017 and 2016, respectively. | $ | — |
| | $ | — |
|
| Additional paid-in capital | 4,032,826 |
| | 3,633,216 |
|
| Retained earnings | 1,822,229 |
| | 1,659,239 |
|
| Accumulated other comprehensive loss | (26,732 | ) | | (23,000 | ) |
| Total common stockholder’s equity | $ | 5,828,323 |
| | $ | 5,269,455 |
|
See Notes to Consolidated Financial Statements
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
| | |
| 1. | Summary of Significant Accounting Policies |
Business and System of AccountsGeneral— 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 and disclosures 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 various state regulatory commissions, which are the same in all material respects.
Principles of Consolidation— 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. See Note 6
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 its state regulatory commission. Certain amounts in the consolidated financial statements or notes have been reclassified for further discussion of jointly owned generation, transmission and gas facilities, and related ownership percentages.
comparative purposes; however, such reclassifications did not affect net income, total assets, liabilities, equity or cash flows.
PSCo evaluates its arrangementshas evaluated events occurring after Dec. 31, 2023 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and contracts with other entities, including investments, PPAs and fuel contracts, to determine if the other party is a variable interest entity, if PSCo has a variable interest and if PSCo is the primary beneficiary. PSCo follows accounting guidance for variable interest entities which requires consideration of the activitiesdisclosures resulting from that most significantly impact an entity’s financial performance and power to direct those activities, when determining whether PSCo is a variable interest entity’s primary beneficiary. See Note 12 for further discussion of variable interest entities.evaluation.
Use of Estimates— In recording transactions and balances resulting from business operations, PSCo uses estimates based on the best information available. available to record transactions and balances resulting from business operations.
Estimates are used for items such items 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. The recordedRecorded estimates are revised when better information becomes available or when actual amounts can be determined. Those revisionsRevisions can affect operating results.
Regulatory Accounting— PSCo accounts for certain 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 OCI,other comprehensive income, are deferred as regulatory assets based on the expected ability to recover the costs in future rates; andrates.
•Certain credits, which would otherwise be reflected as income or OCI,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 available information. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process.
If restructuring or other 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 financial condition, results of operations, financial condition and cash flows.
See Note 134 for further discussioninformation.
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. Income taxes are deferred for all temporary differences between pretax financial and taxable income and between the book and tax bases of assets and liabilities utilizing 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.
Utility rate regulation has resulted in the recognition of regulatory assets and liabilities.
Revenue Recognition— Revenuesliabilities related to the saleincome taxes. The effects of energyPSCo’s tax rate changes are generally subject to a normalization method of accounting. Therefore, the revaluation of most of its net deferred taxes upon a tax rate reduction results in the establishment of a net regulatory liability, 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.
Tax credits are recorded when serviceearned unless there is rendereda requirement to defer the benefit and amortize over the book depreciable lives of 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 otherwise eligible to be recognized when earned, PSCo considers the impact of rate regulation to determine if these credits and related adjustments should be deferred as regulatory assets or energyliabilities.
Deferred tax assets are reduced by a valuation allowance if it is delivered to customers. However, the determinationmore likely than not that some portion or all of the energydeferred tax asset will not be realized. This evaluation includes consideration of whether tax credits are expected to be sold at a discount and impact the realization of amounts presented as deferred tax assets. Transferable tax credits are accounted for under ASC 740 Income Taxes, and valuation allowances and any adjustments for discounts incurred on sales transactions are recorded to individual customersdeferred tax expense, typically recovered in regulatory mechanisms.
PSCo measures and discloses uncertain tax positions that it has taken or expects to take in its income tax returns. A tax position is recognized in the consolidated financial statements when it is more likely than not that the position will be sustained upon examination based on the reading of their meter, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the datetechnical merits of the last meter readingposition. Recognition of changes in uncertain tax positions are estimatedreflected as a component of income tax expense.
Interest and the corresponding unbilled revenue is recognized. PSCo presents its revenues net of any excise or other fiduciary-type taxes or fees.
PSCo has various rate-adjustment mechanisms in place that provide for the recovery of natural gas, electric fuel and purchased energy costs. These cost-adjustment tariffs may increase or decrease the level of revenue collected from customers and are revised periodically for differences between the total amount collected under the clauses and the costs incurred. When applicable, under governing regulatory commission rate orders, fuel cost over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as regulatory assets.
Certain rate rider mechanisms qualify as alternative revenue programs under GAAP. These mechanisms arise from costs imposed upon the utility by action of a regulator or legislative bodypenalties related to an environmental, public safetyincome taxes are reported within Other income (expense), net or other mandate. When certain criteria are met, revenue is recognized equal tointerest charges in the revenue requirement,consolidated statements of income.
Xcel Energy Inc. and its subsidiaries, including return on rate base items, for the qualified mechanisms. The mechanisms are revised periodically for differences between the total amount collected under the riders and the revenue recognized, which may increase or decrease the level of revenue collected from customers.
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,file consolidated federal income tax returns as well as approximately 23 DSM products, pilots and servicesconsolidated 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 residential and low-income customers. Overall, the DSM portfolio provides rebates and/or incentivesstate 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 nearly 1,000 unique measures.further information.
The costs incurred for DSM programs are deferred if it is probable future revenue will be provided to permit recovery of the incurred cost. Recorded revenues 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 period in which they are earned.
PSCo’s DSM program costs are recovered through a combination of base rate revenue and rider mechanisms. The revenue billed to customers recovers incurred costs for conservation programs and also incentive amounts that are designed to encourage PSCo’s achievement of energy conservation goals. PSCo recognizes regulatory assets to reflect the amount of costs or earned incentives that have not yet been collected from customers.
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 expensesexpense as incurred. Planned major 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 also includes costs associated with property held for future use. The depreciable lives of certain plant assets are reviewed annually, and revised, if appropriate.
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 related to its plantis 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 applicable regulator. Accumulated removal costs are reflected in the consolidated balance sheet as a regulatory liability. Depreciation expense, expressed as a percentage of average depreciable property, was approximately 2.7, 2.63.6% in 2023, 3.4% in 2022 and 2.7 percent3.2% in 2021.
See Note 3 for further information.
AROs — PSCo records AROs as a liability in the period incurred (if fair value can be reasonably estimated), with the offsetting/associated 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 timing or amounts 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 amount 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. For certain environmental costs 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 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.
Estimated future expenditures to restore 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.
A separate financing component of collections from customers is not recognized as contract terms are short-term in nature. Revenues are net of any excise or sales taxes or fees.
PSCo recognizes physical sales to customers (native load and wholesale) on a gross basis in electric revenues and cost of sales. PSCo participates in SPP WEIS. Revenues for short-term physical wholesale sales of excess energy transacted through the imbalance market are recorded on a gross basis. Other revenues and charges settled/facilitated through SPP WEIS are recorded on a net basis in cost of sales.
See Note 6 for further information.
Cash and Cash Equivalents — PSCo considers investments in instruments with a remaining maturity of 3 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, 2023 and 2022, the allowance for bad debts was $56 million and $54 million, respectively.
Inventory — Inventory is recorded at the lower of average cost or net realizable value and consisted of the following:
| | | | | | | | | | | | | | |
| (Millions of Dollars) | | Dec. 31, 2023 | | Dec. 31, 2022 |
| Inventories | | | | |
| Materials and supplies | | $ | 91 | | | $ | 80 | |
| Fuel | | 83 | | | 68 | |
| Natural gas | | 84 | | | 171 | |
| Total inventories | | $ | 258 | | | $ | 319 | |
Fair Value Measurements— PSCo presents cash equivalents, interest rate derivatives and commodity derivatives at estimated fair values in its consolidated financial statements.
For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used to estimate 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, 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 determine 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 rates and utility commodity prices, including forward contracts, futures, swaps and options. Derivatives not qualifying for the years ended Dec. 31, 2017, 2016normal purchases and 2015, respectively.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.
LeasesGains or losses on commodity trading transactions are recorded as a component of electric operating revenues.
Normal Purchases and Normal Sales — PSCo evaluates a variety ofenters into contracts for lease classification atpurchases and sales of commodities for use in its operations. At inception, including PPAs and rental arrangements for office space, vehicles, and equipment. Contracts determinedcontracts are evaluated to determine whether they contain a lease because of per unit pricing that is other than fixedderivative, and if so, whether they may be exempted from derivative accounting if designated as normal purchases or market price, terms regarding the use of a particular asset, and other factors are evaluated further to determine if the arrangement is a capital lease. normal sales.
See Note 128 for further discussioninformation.
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 leases.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
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 service rates.base.
Generally, AFUDC costs are recoveredAlternative Revenue — Certain rate rider mechanisms (including decoupling and DSM programs) qualify as alternative revenue programs. These mechanisms arise from customers as the related property is depreciated. However, in some cases, including certain generation and transmission projects, the CPUC has approved a more current recovery of the cost of capital associated with large capital projects, resulting in a lower recognition of AFUDC. In other cases, the CPUC has allowed an AFUDC calculation greater than the FERC-defined AFUDC rate, resulting in higher recognition of AFUDC.
AROs— PSCo accounts for AROs under accounting guidance that requires a liability for the fair value of an ARO to be recognized in the periodinstances in which itthe regulator authorizes a future surcharge in response to past activities or completed events. When certain criteria are met, including expected collection within 24 months, revenue is incurred if it can be reasonably estimated, with the 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,recognized, which may include incentives and the capitalized costsreturn on rate base items.
Billing amounts are depreciated over the useful life of the long-lived asset. Changes resulting from revisions to the timing orrevised periodically for differences between total amount of expected asset retirement cash flows are recognized as ancollected 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 decrease in the ARO. PSCo also recovers through rates certain future plant removal costs in addition to AROs. The accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability. See Note 12 for further discussion of AROs.
Income Taxes— PSCo accounts for income taxes using the assetgross basis and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. PSCo defers income taxes for all temporary differences between pretax financial and taxable income, and between the book and tax bases of assets and liabilities. PSCo uses the tax 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 are generally subject to a normalization method of accounting. Therefore, the revaluation of most of its net deferred taxes upon a tax rate reduction results in the establishment of a net regulatory liability which will be refundable to utility customers over the remaining life of the related assets. A tax rate increase would result in the establishment of a similar regulatory asset. 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 tax credits only applies to federal ITCs related to public utility property. Utility rate regulation also has resulted in the recognition of certain regulatory assets and liabilities related to income taxes, which are summarized in Note 13.
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. In making such a determination, all available evidence is considered, including scheduled reversals of deferred tax liabilities, projected future taxable income, tax planning strategies and recent financial operations.
PSCo follows the applicable accounting guidance to measure and disclose uncertain tax positions that it has taken or expects to take in its income tax returns. PSCo recognizes a tax position in its 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.
PSCo reports interest and penalties related to income taxes within the other income and interest charges sections in the consolidated statements of income.
Xcel Energy Inc. and its subsidiaries, including PSCo, file consolidated federal income tax returns as well as combined or separate state income tax returns. Federal income taxes paid by Xcel Energy Inc. are allocated to Xcel Energy Inc.’s subsidiaries based on separate company computations of tax. A similar allocation is made for state income taxes paid by Xcel Energy Inc. in connectiondisclosed separately from revenue from contracts with combined state filings. Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries which are recorded directly in equity by the subsidiaries based on the relative positive tax liabilities of the subsidiaries.
customers.
See Note 76 for further discussion of income taxes.information.
Types ofConservation Programs — PSCo has implemented programs to assist its retail customers in conserving energy and Accounting for Derivative Instruments— PSCo uses derivative instruments in connection with its interest rate, utility commodity price, vehicle fuel price and commodity trading activities, including forward contracts, futures, swaps and options. All derivative instruments not designated and qualifying for the normal purchases and normal sales exception, as defined by the accounting guidance for derivatives and hedging, are recordedreducing peak demand on the consolidated balance sheets at fair value as derivative instruments. This includes certain instruments used to mitigate market risk for the utility operations and all instruments related to the commodity trading operations. The 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. The 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; hedging transactions for vehicle fuel costs are recorded as a component of capital projects and O&M costs; and interest rate hedging transactions are recorded as a component of interest expense. PSCo is allowed to recover in electric or natural gas rates the costs of certain financial instruments purchased to reduce commodity cost volatility. For further information on derivatives entered to mitigate commodity price risk on behalf of electric and natural gas customer, see Note 10.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.
Cash Flow Hedges — Certain qualifying hedging relationshipsThe costs incurred for DSM programs are designated as a hedgedeferred if it is probable future revenue will be provided to permit recovery of a forecasted transaction the incurred cost. Revenues recognized for incentive programs designed for recovery of DSM program costs and/or future cash flow (cash flow hedge). Changesconservation performance incentives are limited to amounts expected to be collected within 24 months from the year in the fair value of a derivative designated as a cash flow hedge, to the extent effective are included in OCI, or deferred as a regulatory asset or liability based on recovery mechanisms until earnings are affected by the hedged transaction.
Normal Purchases and Normal Sales — PSCo enters into contracts for the purchase and sale of commodities for use in its business operations. Derivatives and hedging accounting guidance requires a company to evaluate these contracts to determine whether the contracts are derivatives. Certain contracts that meet the definition of a derivative may be exempted from derivative accounting if designated as normal purchases or normal sales.
PSCo evaluates all of its contracts at inception to determine ifwhich they are derivativesearned.
PSCo’s DSM program costs are recovered through a combination of base rate revenue and if they meetrider mechanisms. Regulatory assets are recognized to reflect the normal purchases and normal sales designation requirements. Noneamount of the contracts entered into within the commodity trading operations qualify for a normal purchases and normal sales designation.costs or earned incentives that have not yet been collected from customers.
See Note 10 for further discussion of PSCo’s risk management and derivative activities.
Commodity Trading OperationsEmissions Allowances— All applicable gains and losses related to commodity trading activities, whether or not settled physically, are shown on a net basis in electric operating revenues in the consolidated statements of income.
Pursuant to the JOA approved by the FERC, some of the commodity trading margins from PSCo are apportioned to NSP-Minnesota and SPS. 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 10 for further discussion.
Fair Value Measurements— PSCo presents cash equivalents, interest rate derivatives and commodity derivatives at estimated fair values in its consolidated financial statements. Cash equivalents Emissions allowances are recorded at cost, plus accrued interest; money market fundsincluding broker commission fees. The inventory accounting model is utilized for all emissions allowances and any sales of these allowances are measured using quoted NAVs. For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used as a primary input to establish 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 for an identical contractincluded in an active market, PSCo may use quoted prices for similar contracts, or internally prepared valuation models to determine fair value. For the pension and postretirement plan assets published trading data and pricing models, generally using the most observable inputs available, are utilized to estimate fair value for each security. See Note 8 and 10 for further discussion.electric revenues.
Cash and Cash EquivalentsRECs— PSCo considers investments in certain instruments, including commercial paper and money market funds, with a remaining maturity of three 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.
Inventory— All inventory is recorded at average cost.
RECs — RECs aremarketable environmental instruments that represent proof that energy was generated from eligible renewable energy sources. RECs are awarded upon delivery of the associated energy and can be bought and sold. RECs are typically used as a form of measurement of compliance to RPS enacted by those states that are encouraging construction and consumption from renewable energy sources, but can also be sold separately from the energy produced. PSCo acquires RECs from the generation or purchase of renewable power.
When RECs are purchased or acquired in the course of generation they are recorded as inventory at cost. The cost Cost of RECs that are utilized for compliance purposes is recorded as electric fuel and purchased power expense. As a result of state regulatory orders, 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 that are purchased or acquired in the course of generation are recorded in electric utility operating revenues on a gross basis. The costCost of these RECs related transaction costs, and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense.
Emission Allowances — Emission allowances, including the annual SO2 and NOx emission allowance entitlement received from the EPA, are recorded at cost plus associated broker commission fees. PSCo follows the inventory accounting model for all emission allowances. Sales of emission allowances are included in electric utility operating revenues and the operating activities section of the consolidated statements of cash flows.
Environmental Costs— Environmental costs are recorded when it is probable PSCo is liable for remediation costs and the liability 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 an environmental expense is related to facilities currently in use, such as emission-control equipment, the cost is capitalized and depreciated over the life of the plant.
Estimated remediation costs, excluding inflationary increases, are recorded based on experience, an assessment of the current situation and the technology currently available for use in the remediation. The recorded costs are regularly adjusted as estimates are revised and remediation proceeds. If other participating PRPs exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for PSCo’s expected share of the cost.
Any future costs of restoring sites where operation may extend indefinitely are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses, which may include final remediation costs. Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability.
See Note 12 for further discussion of environmental costs.
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 under applicable accounting guidance requires management to make various assumptions and estimates.
Based on regulatory recovery mechanisms, certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are recorded as regulatory assets and liabilities, rather than OCI.
See Note 8 for further discussion of benefit plans and other postretirement benefits.
Guarantees — PSCo recognizes, upon issuance or modification of a guarantee, a liability for the fair market value of the obligation that has been assumed in issuing the guarantee. This liability includes consideration of specific triggering events and other conditions which may modify the ongoing obligation to perform under the guarantee.
The obligation recognized is reduced over the term of the guarantee as PSCo is released from risk under the guarantee.
Subsequent Events — Management has evaluated the impact of events occurring after Dec. 31, 2017 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation.
| | |
2. | Accounting Pronouncements |
Recently Issued
Revenue RecognitionSegment Reporting —In May 2014,November 2023, the FASB issued Revenue from Contracts with Customers, Topic 606 (ASU No. 2014-09)ASU 2023-07 – Segment Reporting (Topic 280) – Improvements to Reportable Segment Disclosures, which provides a new frameworkextends the existing requirements for annual disclosures to quarterly periods, and requires that both annual and quarterly disclosures present segment expenses using line items consistent with information regularly provided to the recognition of revenue. As the appropriate timing of recognition of revenue from contracts with customers in our regulated operations continues to generally be based on the delivery of electricity and natural gas, PSCo’s adoption will primarily result in increased disclosures regarding sources of revenues, including alternative revenue programs.chief operating decision maker. The guidanceASU is effective for interim and annual periods beginning after Dec. 15, 2017. PSCo is implementing the standard on a modified retrospective basis, which requires application to contracts with customers effective Jan. 1, 2018.
Classification2023 and Measurement of Financial Instruments — In January 2016, the FASB issued Recognition and Measurement of Financial Assets and Financial Liabilities, Subtopic 825-10 (ASU No. 2016-01), which eliminates the available-for-sale classification for marketable equity securities and also replaces the cost method of accounting for non-marketable equity securities with a model for recognizing impairments and observable price changes. Under the new standard, other than when the consolidation or equity method of accounting is utilized, changes in the fair value of equity securities are to be recognized in earnings. This guidance is effective for interim and annual reportingquarterly periods beginning after Dec. 15, 2017. The overall impacts2024, and PSCo does not expect implementation of the Jan. 1, 2018 adoption will not be material.new disclosure guidance to have a material impact to its consolidated financial statements.
Leases Income Taxes —In February 2016,December 2023, the FASB issued Leases, Topic 842 (ASU No. 2016-02)ASU 2023-09 –Income Taxes (Topic 740) – Improvements to Income Tax Disclosures, which, for lessees, requires balance sheet recognitionwith new disclosure requirements including presentation of right-of-use assetsprescribed line items in the effective tax rate reconciliation and lease liabilities for most leases. This guidance will bedisclosures regarding state and local tax payments. The ASU is effective for interim and annual reporting periods beginning after Dec. 15, 2018.2024, and PSCo hasdoes not yet fully determinedexpect implementation of the impactsnew disclosure guidance to have a material impact to its consolidated financial statements.
| | |
| 3. Property, Plant and Equipment |
Major classes of implementation. However, adoptionproperty, plant and equipment
| | | | | | | | | | | | | | |
| (Millions of Dollars) | | Dec. 31, 2023 | | Dec. 31, 2022 |
| Property, plant and equipment, net | | | | |
| Electric plant | | $ | 16,698 | | | $ | 15,771 | |
| Natural gas plant | | 6,321 | | | 5,949 | |
| Common and other property | | 1,472 | | | 1,415 | |
Plant to be retired (a) | | 1,203 | | | 1,305 | |
| CWIP | | 1,310 | | | 877 | |
| Total property, plant and equipment | | 27,004 | | | 25,317 | |
| Less accumulated depreciation | | (5,969) | | | (5,665) | |
| Property, plant and equipment, net | | $ | 21,035 | | | $ | 19,652 | |
(a)Amounts include Comanche Units 2 and 3, Craig Units 1 and 2, Hayden Units 1 and 2 and coal generation assets at Pawnee pending facility gas conversion. Amounts are presented net of accumulated depreciation.
Joint Ownership of Generation, Transmission and Gas Facilities
Jointly owned assets as of Dec. 31, 2023:
| | | | | | | | | | | | | | | | | | | | | | |
| (Millions of Dollars, Except Percent Owned) | | Plant in Service | | Accumulated Depreciation | | | | Percent Owned |
| Electric generation: | | | | | | | | |
| Hayden Unit 1 | | $ | 157 | | | $ | 108 | | | | | 76 | % |
| Hayden Unit 2 | | 151 | | | 87 | | | | | 37 | |
| Hayden common facilities | | 44 | | | 31 | | | | | 53 | |
| Craig Units 1 and 2 | | 82 | | | 55 | | | | | 10 | |
| Craig common facilities | | 39 | | | 25 | | | | | 7 | |
| Comanche Unit 3 | | 916 | | | 191 | | | | | 67 | |
| Comanche common facilities | | 29 | | | 4 | | | | | 77 | |
| Electric transmission: | | | | | | | | |
| Transmission and other facilities | | 189 | | | 75 | | | | | Various |
| Gas transmission: | | | | | | | | |
| Rifle, CO to Avon, CO | | 28 | | | 9 | | | | | 60 | |
| Gas transmission compressor | | 8 | | | 2 | | | | | 50 | |
Total (a) | | $ | 1,643 | | | $ | 587 | | | | | |
(a)Projects additionally include $18 million in CWIP.
PSCo’s share of operating expenses and construction expenditures is expected to occur on Jan. 1, 2019 utilizingincluded in the practical expedients provided by the standardapplicable utility accounts. Respective owners are responsible for providing their own financing.
| | |
| 4. Regulatory Assets and Liabilities |
Regulatory assets and proposed in Targeted Improvements, Topic 842 (Proposed ASU 2018-200). As such, agreements entered prior to Jan. 1, 2019liabilities are created for amounts that are currently considered leases are expectedregulators may allow to be recognized on the consolidated balance sheet, including contracts for use of office space, equipmentcollected or may require to be paid back to customers in future electric and natural gas storagerates. 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) | | See Note(s) | | Remaining Amortization Period | | Dec. 31, 2023 | | Dec. 31, 2022 |
| Regulatory Assets | | | | | | Current | | Noncurrent | | Current | | Noncurrent |
| Pension and retiree medical obligations | | 9 | | Various | | $ | 2 | | | $ | 396 | | | $ | 3�� | | | $ | 367 | |
Net AROs (a) | | 1, 10 | | Various | | — | | | 236 | | | — | | | 212 | |
| Depreciation differences | | | | One to 10 years | | 16 | | | 184 | | | 16 | | | 187 | |
| Recoverable deferred taxes on AFUDC | | | | Plant lives | | — | | | 135 | | | — | | | 119 | |
| Excess deferred taxes — TCJA | | 7 | | Various | | — | | | 55 | | | 2 | | | 54 | |
| Environmental remediation costs | | | | Various | | — | | | 44 | | | 6 | | | 26 | |
Conservation programs (b) | | 1 | | One to two years | | 12 | | | 33 | | | 8 | | | 16 | |
| Revenue decoupling | | | | Various | | — | | | 31 | | | — | | | — | |
| Gas pipeline inspection costs | | | | One to two years | | 3 | | | 25 | | | — | | | 13 | |
| Deferred natural gas, electric, steam energy/fuel costs | | | | One to three years | | 221 | | | 22 | | | 312 | | | 200 | |
| Purchased power contract costs | | | | Term of related contract | | 4 | | | 20 | | | 3 | | | 16 | |
| Grid modernization costs | | | | Two years | | 15 | | | 14 | | | 14 | | | 22 | |
| Property tax | | | | Various | | 3 | | | 7 | | | 8 | | | 2 | |
| Other | | | | Various | | 28 | | | 65 | | | 39 | | | 43 | |
| Total regulatory assets | | | | | | $ | 304 | | | $ | 1,267 | | | $ | 411 | | | $ | 1,277 | |
(a)Includes amounts recorded for future recovery of AROs.
(b)Includes costs for conservation programs, as well as incentives allowed in certain purchased power agreements (PPAs) for natural gas-fueled generating facilities. PSCo expects that similar agreements entered afterjurisdictions.
Components of regulatory liabilities:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (Millions of Dollars) | | See Note(s) | | Remaining Amortization Period | | Dec. 31, 2023 | | Dec. 31, 2022 |
| Regulatory Liabilities | | | | | | Current | | Noncurrent | | Current | | Noncurrent |
Deferred income tax adjustments and TCJA refunds (a) | | 7 | | Various | | $ | 2 | | | $ | 1,260 | | | $ | 2 | | | $ | 1,298 | |
| Plant removal costs | | 1, 10 | | Various | | — | | | 769 | | | — | | | 705 | |
Effects of regulation on employee benefit costs (b) | | | | Various | | — | | | 234 | | | — | | | 227 | |
| Renewable resources and environmental initiatives | | | | Various | | — | | | 152 | | | — | | | 141 | |
| Revenue decoupling | | | | Various | | — | | | 63 | | | — | | | 55 | |
| ITC deferrals | | 1 | | Various | | 1 | | | 44 | | | 1 | | | 41 | |
| Deferred natural gas, electric, steam energy/fuel costs | | | | Less than one year | | 34 | | | — | | | 3 | | | — | |
| Conservation programs | | 1 | | Less than one year | | 9 | | | — | | | 19 | | | — | |
| Formula rates | | | | One to two years | | 8 | | | — | | | 16 | | | — | |
| Other | | | | Various | | 16 | | | 40 | | | 18 | | | 22 | |
| Total regulatory liabilities | | | | | | $ | 70 | | | $ | 2,562 | | | $ | 59 | | | $ | 2,489 | |
(a)Includes the revaluation of recoverable/regulated plant accumulated deferred income taxes and revaluation impact of non-plant accumulated deferred income taxes due to the TCJA.
(b)Includes regulatory amortization and certain 2018 TCJA benefits approved by the CPUC to offset the prepaid pension asset.
PSCo’s regulatory assets not earning a return include past expenditures of $416 million and $538 million at Dec. 31, 2018 will generally qualify as leases under2023 and 2022, respectively, which predominately relate to purchased natural gas and electric energy costs (including certain costs related to Winter Storm Uri), sales true-up and revenue decoupling and various renewable resources/environmental initiatives. Additionally, the new standard.
Presentation of Net Periodic Benefit Cost —In March 2017, the FASB issued Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, Topic 715 (ASU No. 2017-07), which establishes that only the service cost elementunfunded portion of pension cost may be presented as a component of operating income in the income statement. Also under the guidance, only the service cost component of pension cost is eligible for capitalization. As a result of application of accounting principles for rate regulated entities, a similar amount of pension cost, including non-service components, will be recognized consistent with the historical ratemaking treatment and the impacts of adoption will be limited to changes in classification of non-service costs in the consolidated statement of income. This guidance is effective for interimretiree medical obligations and annual reporting periods beginning after Dec. 15, 2017.
Recently Adopted
Accounting for the TCJA— In December 2017, the SEC staff issued Staff Accounting Bulletin No. 118 Income Tax Accounting Implications of the Tax Cuts and Jobs Act (SAB 118), to supplement the accounting requirements of ASC Topic 740 Income Taxes (ASC Topic 740) as it relates to assessing and recognizing the impacts of the TCJA in the period of enactment. SAB 118 allows an entity to recognize provisional amounts in its financial statements in circumstances in which the entity’s assessment is incomplete, butnet AROs (i.e. deferrals for which cash has not been disbursed) do not earn a reasonable estimate can be made. Provisional amounts recognized are subject to adjustment for up to one year from the enactment date. For further details, see Note 7 to the consolidated financial statements.return.
Reporting Comprehensive Income — In February 2018, the FASB issued Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, Topic 220 (ASU No. 2018-02), which addresses the stranded amounts of accumulated OCI which may result from enactment of a new tax law. Though accumulated OCI is presented on a net-of-tax basis, ASC Topic 740 requires that the effects of new tax laws on items in accumulated OCI be recognized without a corresponding adjustment to accumulated OCI, and instead recorded to income tax expense. ASU No. 2018-02 permits stranded amounts of accumulated OCI specifically resulting from the TCJA to be removed from accumulated OCI and reclassified to retained earnings, if elected. PSCo adopted the guidance in the fourth quarter of 2017, and elected to recognize a $4.7 million increase to accumulated other comprehensive loss and retained earnings in the consolidated financial statements for the year ended Dec. 31, 2017, related to a revaluation of deferred income tax assets and liabilities for items in accumulated other comprehensive loss, at the TCJA federal tax rate.
| | |
3. | Selected Balance Sheet Data |
|
| | | | | | | | |
| (Thousands of Dollars) | | Dec. 31, 2017 | | Dec. 31, 2016 |
| Accounts receivable, net | | | | |
| Accounts receivable | | $ | 314,009 |
| | $ | 324,512 |
|
| Less allowance for bad debts | | (19,606 | ) | | (19,612 | ) |
| | | $ | 294,403 |
| | $ | 304,900 |
|
|
| | | | | | | | |
| (Thousands of Dollars) | | Dec. 31, 2017 | | Dec. 31, 2016 |
| Inventories | | | | |
| Materials and supplies | | $ | 68,940 |
| | $ | 66,161 |
|
| Fuel | | 73,893 |
| | 66,429 |
|
| Natural gas | | 71,656 |
| | 69,630 |
|
| | | $ | 214,489 |
| | $ | 202,220 |
|
|
| | | | | | | | |
| (Thousands of Dollars) | | Dec. 31, 2017 | | Dec. 31, 2016 |
| Property, plant and equipment, net | | | | |
| Electric plant | | $ | 12,627,592 |
| | $ | 12,304,436 |
|
| Natural gas plant | | 4,102,075 |
| | 3,710,772 |
|
| Common and other property | | 1,022,333 |
| | 919,955 |
|
Plant to be retired (a) | | 10,949 |
| | 31,839 |
|
| Construction work in progress | | 1,014,338 |
| | 484,340 |
|
| Total property, plant and equipment | | 18,777,287 |
| | 17,451,342 |
|
| Less accumulated depreciation | | (4,751,536 | ) | | (4,601,543 | ) |
| | | $ | 14,025,751 |
| | $ | 12,849,799 |
|
| |
(a)
| In the third quarter of 2017, PSCo early retired Valmont Unit 5 and converted Cherokee Unit 4 from a coal-fueled generating facility to natural gas. PSCo also expects Craig Unit 1 to be early retired in approximately 2025. Amounts are presented net of accumulated depreciation. |
| |
4. | 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. PSCo had no money pool borrowings outstanding during the three months ended Dec. 31, 2017.
Money pool borrowings for PSCo were as follows:borrowings:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| (Millions of Dollars, Except Interest Rates) | | Three Months Ended Dec. 31, 2023 | | Year Ended Dec. 31 |
| | 2023 | | 2022 | | 2021 |
| Borrowing limit | | $ | 250 | | | $ | 250 | | | $ | 250 | | | $ | 250 | |
| Amount outstanding at period end | | 51 | | | 51 | | | — | | | — | |
| Average amount outstanding | | 64 | | | 23 | | | 29 | | | 12 | |
| Maximum amount outstanding | | 250 | | | 250 | | | 250 | | | 243 | |
| Weighted average interest rate, computed on a daily basis | | 5.33 | % | | 5.31 | % | | 1.66 | % | | 0.07 | % |
| Weighted average interest rate at end of period | | 5.34 | | | 5.34 | | | N/A | | N/A |
|
| | | | | | | | | | | | |
| (Amounts in Millions, Except Interest Rates) | | Twelve Months Ended Dec. 31, 2017 | | Twelve Months Ended Dec. 31, 2016 | | Twelve Months Ended Dec. 31, 2015 |
| Borrowing limit | | $ | 250 |
| | $ | 250 |
| | $ | 250 |
|
| Amount outstanding at period end | | — |
| | — |
| | — |
|
| Average amount outstanding | | — |
| | 21 |
| | 1 |
|
| Maximum amount outstanding | | 20 |
| | 141 |
| | 34 |
|
| Weighted average interest rate, computed on a daily basis | | 0.92 | % | | 0.73 | % | | 0.41 | % |
| Weighted average interest rate at period end | | N/A |
| | N/A |
| | N/A |
|
Commercial Paper — PSCo meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility. PSCo had no commercial paper borrowings outstanding during the three months ended Dec. 31, 2017. Commercial paper borrowings for PSCo were as follows:borrowings:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| (Millions of Dollars, Except Interest Rates) | | Three Months Ended Dec. 31, 2023 | | Year Ended Dec. 31 |
| | 2023 | | 2022 | | 2021 |
| Borrowing limit | | $ | 700 | | | $ | 700 | | | $ | 700 | | | $ | 700 | |
| Amount outstanding at period end | | 320 | | | 320 | | | 294 | | | 147 | |
| Average amount outstanding | | 189 | | | 124 | | | 71 | | | 26 | |
| Maximum amount outstanding | | 369 | | | 454 | | | 328 | | | 322 | |
| Weighted average interest rate, computed on a daily basis | | 5.53 | % | | 5.17 | % | | 2.56 | % | | 0.19 | % |
| Weighted average interest rate at end of period | | 5.56 | | | 5.56 | | | 4.73 | | | 0.22 | |
|
| | | | | | | | | | | | |
| (Amounts in Millions, Except Interest Rates) | | Twelve Months Ended Dec. 31, 2017 | | Twelve Months Ended Dec. 31, 2016 | | Twelve Months Ended Dec. 31, 2015 |
| Borrowing limit | | $ | 700 |
| | $ | 700 |
| | $ | 700 |
|
| Amount outstanding at period end | | — |
| | 129 |
| | 14 |
|
| Average amount outstanding | | 54 |
| | 24 |
| | 95 |
|
| Maximum amount outstanding | | 268 |
| | 154 |
| | 449 |
|
| Weighted average interest rate, computed on a daily basis | | 1.08 | % | | 0.70 | % | | 0.51 | % |
| Weighted average interest rate at period end | | N/A |
| | 0.95 |
| | 0.60 |
|
Letters of Credit— PSCo uses letters of credit, generallytypically with terms of one-year,one year, to provide financial guarantees for certain operating obligations. At both Dec. 31, 20172023 and 2016,2022, there were $3$29 million and $27 million of letters of credit outstanding under the credit facility.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.
PSCo has the right to request an extension of the June 2021 termination date for two additional one-year periods. The extension requests are subject to majority bank group approval.
Other featuresFeatures of PSCo’s credit facility include:facility:
| | | | | | | | | | | | | | | | | | | | |
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) |
| 2023 | | 2022 | | | | |
| 44.8 | % | | 44.0 | % | | $ | 100 | | | 2 |
PSCo may increase its credit facility by up to $100 million.
(a)The credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65 percent.65%.
(b)All extension requests are subject to majority bank group approval.
The credit facility has a cross-default provision that provides PSCo waswould be in compliance asdefault on its debt-to-total capitalization ratio was 44 percent and 45 percent at Dec. 31, 2017 and 2016, respectively. 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.
The credit facility has a cross-default provision that provides PSCo will be in default on its borrowings under the facility if PSCo or any As of its subsidiaries whose total assets exceed 15 percent of PSCo’s consolidated total assets, default on certain indebtedness in an aggregate principal amount exceeding $75 million.
Dec. 31, 2023, PSCo was in compliance with all financial covenants on its debt agreements ascovenants.
At Dec. 31, 2017, PSCo had the following committed credit facility available as of Dec. 31, 2023 (in millions)millions of dollars):
| | | | | | | | | | | | | | |
Credit Facility (a) | | Drawn (b) | | Available |
| $ | 700 | | | $ | 349 | | | $ | 351 | |
|
| | | | | | | | | | |
Credit Facility (a) | | Drawn (b) | | Available |
| $ | 700 |
| | $ | 3 |
| | $ | 697 |
|
| |
(a)
| This credit facility matures in June 2021. |
| |
(b)
| Includes letters of credit. |
(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 hadnodirect advances on the credit facility outstanding at Dec. 31, 20172023 and 2016.
2022.
Long-Term Borrowings
and Other Financing Instruments
Generally, all real and personalthe 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 associated withfor refinanced debt are deferred and amortized over the life of the related new issuance, in accordance with regulatory guidelines.issuance.
Long-term debt obligations for PSCo as of Dec. 31 (in millions of dollars):
In 2017, PSCo issued $400 million | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Financing Instrument | | Interest Rate | | Maturity Date | | 2023 | | 2022 |
| First mortgage bonds | | 2.50 | % | | March 15, 2023 | | $ | — | | | $ | 250 | |
| First mortgage bonds | | 2.90 | | | May 15, 2025 | | 250 | | | 250 | |
| First mortgage bonds | | 3.70 | | | June 15, 2028 | | 350 | | | 350 | |
| First mortgage bonds | | 1.90 | | | Jan. 15, 2031 | | 375 | | | 375 | |
| First mortgage bonds | | 1.875 | | | June 15, 2031 | | 750 | | | 750 | |
First mortgage bonds (a) | | 4.10 | | | June 1, 2032 | | 300 | | | 300 | |
| First mortgage bonds | | 6.25 | | | Sept. 1, 2037 | | 350 | | | 350 | |
| First mortgage bonds | | 6.50 | | | Aug. 1, 2038 | | 300 | | | 300 | |
| First mortgage bonds | | 4.75 | | | Aug. 15, 2041 | | 250 | | | 250 | |
| First mortgage bonds | | 3.60 | | | Sept. 15, 2042 | | 500 | | | 500 | |
| First mortgage bonds | | 3.95 | | | March 15, 2043 | | 250 | | | 250 | |
| First mortgage bonds | | 4.30 | | | March 15, 2044 | | 300 | | | 300 | |
| First mortgage bonds | | 3.55 | | | June 15, 2046 | | 250 | | | 250 | |
| First mortgage bonds | | 3.80 | | | June 15, 2047 | | 400 | | | 400 | |
| First mortgage bonds | | 4.10 | | | June 15, 2048 | | 350 | | | 350 | |
| First mortgage bonds | | 4.05 | | | Sept. 15, 2049 | | 400 | | | 400 | |
| First mortgage bonds | | 3.20 | | | March 1, 2050 | | 550 | | | 550 | |
| First mortgage bonds | | 2.70 | | | Jan. 15, 2051 | | 375 | | | 375 | |
First mortgage bonds (a) | | 4.50 | | | June 1, 2052 | | 400 | | | 400 | |
First mortgage bonds (b) | | 5.25 | | | April 1, 2053 | | 850 | | | — | |
| Unamortized discount | | | | | | (41) | | | (37) | |
| Unamortized debt issuance cost | | | | | | (59) | | | (53) | |
| Current maturities | | | | | | — | | | (250) | |
| Total long-term debt | | | | | | $ | 7,450 | | | $ | 6,610 | |
(a)2022 financing.
(b)2023 financing.
Maturities of 3.80 percent first mortgage bonds due June 15, 2047. In 2016, PSCo issued $250 million of 3.55 percent first mortgage bonds due June 15, 2046.long-term debt:
| | | | | | | | |
| (Millions of Dollars) | | |
| 2024 | | $ | — | |
| 2025 | | 250 | |
| 2026 | | — | |
| 2027 | | — | |
| 2028 | | 350 | |
During the next five years, PSCo has long-term debt maturities of $300 million, $400 million, $400 million and $300 million due in 2018, 2019, 2020 and 2022, respectively.
Deferred Financing Costs— Deferred financing costs of approximately $29$59 million and $27$53 million, net of amortization, are presented as a deduction from the carrying amount of long-term debt atas of Dec. 31, 20172023 and 2016,2022, respectively.
Capital Stock — PSCo is amortizing these financing costs overhas authorized the remaining maturity periodsissuance of the related debt.preferred stock.
| | | | | | | | | | | | | | |
| Preferred Stock Authorized (Shares) | | Par Value of Preferred Stock | | Preferred Stock Outstanding (Shares) 2023 and 2022 |
| 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; payment of dividends is allowed out ofaccounts. Dividends are solely to be paid from retained earnings only.earnings.
PSCo has authorized the issuance of preferred stock.
|
| | | | | | | | |
Preferred
Shares
Authorized | | Par Value | | Preferred
Shares
Outstanding |
| 10,000,000 |
| | $ | 0.01 |
| | None |
|
| |
| 6. | Joint Ownership of Generation, Transmission and Gas Facilities Revenues |
Following areRevenue is classified by the investments by PSCo in jointly owned generation, transmissiontype of goods/services rendered and gas facilities and the related ownership percentages as of Dec. 31, 2017:
|
| | | | | | | | | | | | | | | |
| (Thousands of Dollars) | | Plant in Service | | Accumulated
Depreciation | | CWIP | | Ownership % |
| Electric Generation: | | | | | | | | |
| Hayden Unit 1 | | $ | 150,441 |
| | $ | 72,042 |
| | $ | 830 |
| | 76 | % |
| Hayden Unit 2 | | 148,694 |
| | 65,493 |
| | 18 |
| | 37 |
|
| Hayden Common Facilities | | 39,321 |
| | 19,886 |
| | 97 |
| | 53 |
|
| Craig Units 1 and 2 | | 80,650 |
| | 38,666 |
| | — |
| | 10 |
|
| Craig Common Facilities 1, 2 and 3 | | 38,902 |
| | 20,116 |
| | — |
| | 7 |
|
| Comanche Unit 3 | | 889,630 |
| | 117,759 |
| | 476 |
| | 67 |
|
| Comanche Common Facilities | | 24,421 |
| | 2,092 |
| | 2,809 |
| | 82 |
|
| Electric Transmission: | | | | | | | | |
| Transmission and other facilities, including substations | | 176,873 |
| | 67,637 |
| | 638 |
| | Various |
|
| Gas Transportation: | | | | | | | | |
| Rifle, Colo. to Avon, Colo. | | 21,532 |
| | 7,579 |
| | — |
| | 60 |
|
| Gas Transportation Compressor | | 8,417 |
| | 616 |
| | — |
| | 50 |
|
| Total | | $ | 1,578,881 |
| | $ | 411,886 |
| | $ | 4,868 |
| | |
PSCo has approximately 816 MW of jointly owned generating capacity.market/customer type. PSCo’s share of operating expenses and construction expenditures are included in the applicable utility accounts. Eachrevenues consisted of the respective owners is responsible for providing its own financing.following:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended Dec. 31, 2023 |
| (Millions of Dollars) | | Electric | | Natural Gas | | All Other | | Total |
| Major revenue types | | | | | | | | |
| Revenue from contracts with customers: |
| Residential | | $ | 1,295 | | | $ | 1,109 | | | $ | 19 | | | $ | 2,423 | |
| C&I | | 1,816 | | | 459 | | | 30 | | | 2,305 | |
| Other | | 52 | | | — | | | 5 | | | 57 | |
| Total retail | | 3,163 | | | 1,568 | | | 54 | | | 4,785 | |
| Wholesale | | 237 | | | — | | | — | | | 237 | |
| Transmission | | 90 | | | — | | | — | | | 90 | |
| Other | | 61 | | | 132 | | | — | | | 193 | |
| Total revenue from contracts with customers | | 3,551 | | | 1,700 | | | 54 | | | 5,305 | |
| Alternative revenue and other | | 180 | | | 34 | | | — | | | 214 | |
| Total revenues | | $ | 3,731 | | | $ | 1,734 | | | $ | 54 | | | $ | 5,519 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended Dec. 31, 2022 |
| (Millions of Dollars) | | Electric | | Natural Gas | | All Other | | Total |
| Major revenue types | | | | | | | | |
| Revenue from contracts with customers: |
| Residential | | $ | 1,341 | | | $ | 1,203 | | | $ | 15 | | | $ | 2,559 | |
| C&I | | 1,843 | | | 479 | | | 32 | | | 2,354 | |
| Other | | 52 | | | — | | | — | | | 52 | |
| Total retail | | 3,236 | | | 1,682 | | | 47 | | | 4,965 | |
| Wholesale | | 286 | | | — | | | — | | | 286 | |
| Transmission | | 88 | | | — | | | — | | | 88 | |
| Other | | 53 | | | 151 | | | — | | | 204 | |
| Total revenue from contracts with customers | | 3,663 | | | 1,833 | | | 47 | | | 5,543 | |
| Alternative revenue and other | | 132 | | | 27 | | | 6 | | | 165 | |
| Total revenues | | $ | 3,795 | | | $ | 1,860 | | | $ | 53 | | | $ | 5,708 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended Dec. 31, 2021 |
| (Millions of Dollars) | | Electric | | Natural Gas | | All Other | | Total |
| Major revenue types | | | | | | | | |
| Revenue from contracts with customers: |
| Residential | | $ | 1,174 | | | $ | 816 | | | $ | 12 | | | $ | 2,002 | |
| C&I | | 1,660 | | | 308 | | | 30 | | | 1,998 | |
| Other | | 49 | | | — | | | — | | | 49 | |
| Total retail | | 2,883 | | | 1,124 | | | 42 | | | 4,049 | |
| Wholesale | | 228 | | | — | | | — | | | 228 | |
| Transmission | | 75 | | | — | | | — | | | 75 | |
| Other | | 44 | | | 159 | | | — | | | 203 | |
| Total revenue from contracts with customers | | 3,230 | | | 1,283 | | | 42 | | | 4,555 | |
| Alternative revenue and other | | 183 | | | 72 | | | 5 | | | 260 | |
| Total revenues | | $ | 3,413 | | | $ | 1,355 | | | $ | 47 | | | $ | 4,815 | |
Federal Tax Reform— In December 2017, the TCJA was signed into law. While the legislation will require interpretations and regulations to be issued by the IRS, the key provisions impacting Xcel Energy (which includes PSCo), generally beginning in 2018, include:
Corporate federal tax rate reduction from 35 percent to 21 percent;
Normalization of resulting plant-related excess deferred taxes;
Elimination of the corporate alternative minimum tax;
Continued interest expense deductibility and discontinued bonus depreciation for regulated public utilities;
Limitations on certain executive compensation deductions;
Limitations on certain deductions for NOLs arising after Dec. 31, 2017 (limited to 80 percent of taxable income);
Repeal of the section 199 manufacturing deduction; and
Reduced deductions for meals and entertainment as well as state and local lobbying.
Entities are required under ASC Topic 740 to recognize the accounting impacts of a tax law change, including the impacts of a change in tax rates on deferred tax assets and liabilities, in the period including the date of the tax law enactment. The SEC staff issued guidance in SAB 118 that supplements the accounting requirements of ASC Topic 740 if elements of the TCJA assessment are not complete, and provides for up to a one year period to finalize the required accounting. Xcel Energy has estimated the effects of the TCJA, which have been reflected in the Dec. 31, 2017 consolidated financial statements. Issuance of U.S. Treasury regulations interpreting the TCJA, other U.S. Treasury and IRS guidance or interpretations of the application of ASC Topic 740 may result in changes to these estimates.
Overall for Xcel Energy, reductions in deferred tax assets and liabilities due to the reduction in corporate federal tax rates result in a net tax benefit. However, as a result of IRS requirements and past regulatory treatment of deferred taxes in the determination of regulated rates of the utility subsidiaries, including deferred taxes related to regulated plant and certain other deferred tax assets and liabilities, the impact was primarily recognized as a regulatory liability refundable to utility customers.
The fourth quarter 2017 estimated accounting impacts of the December 2017 enactment of the new tax law at PSCo included:
$1.1 billion ($1.5 billion grossed-up for tax) of reclassifications of plant-related excess deferred taxes to regulatory liabilities upon valuation at the new 21 percent federal rate. The regulatory liabilities will be amortized consistent with IRS normalization requirements, resulting in customer refunds over the average remaining life of the related property;
$54 million and $50 million of reclassifications (grossed-up for tax) of excess deferred taxes for non-plant related deferred tax assets and liabilities, respectively, to regulatory assets and liabilities;
$18 million of total estimated income tax benefit related to the federal tax reform implementation, and a $4 million reduction to net income related to the allocation of Xcel Energy Services Inc.’s tax rate change on its deferred taxes.
Xcel Energy has accounted for the state tax impacts of federal tax reform based on currently enacted state tax laws. Any future state tax law changes related to the TCJA will be accounted for in the periods state laws are enacted.
Consolidated Appropriations Act, 2016 — In December 2015, the Consolidated Appropriations Act, 2016 (Act) was signed into law. The Act provided for the following:
Immediate expensing, or “bonus depreciation,” of 50 percent for property placed in service in 2015, 2016, and 2017;
PTCs at 100 percent of the applicable rate for wind energy projects that begin construction by the end of 2016; 80 percent of the credit rate for projects that begin construction in 2017; 60 percent of the credit rate for projects that begin construction in 2018; and 40 percent of the credit rate for projects that begin construction in 2019. The wind energy PTC was not extended for projects that begin construction after 2019;
ITCs at 30 percent for commercial solar projects that begin construction by the end of 2019; 26 percent for projects that begin construction in 2020; 22 percent for projects that begin construction in 2021; and 10 percent for projects thereafter;
R&E credit was permanently extended; and
Delay of two years (until 2020) of the excise tax on certain employer-provided health insurance plans.
The accounting related to the Act was recorded beginning in the fourth quarter of 2015 because a change in tax law is accounted for beginning in the period of enactment.
Federal Audit — PSCO is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. The statutes of limitations applicable to Xcel Energy’s federal income tax returns expire as follows:
|
| | |
Tax Year(s) | | Expiration |
2009 - 2011 | | June 2018 |
2012 - 2013 | | October 2018 |
2014 | | September 2018 |
2015 | | September 2019 |
2016 | | September 2020 |
In 2012, the IRS commenced an examination of tax years 2010 and 2011, including the 2009 carryback claim. The IRS proposed an adjustment to the federal tax loss carryback claims that would have resulted in $14 million of income tax expense for the 2009 through 2011 claims, and the 2013 through 2015 claims. In the fourth quarter of 2015, the IRS forwarded the issue to the Office of Appeals (“Appeals”). In the third quarter of 2017, Xcel Energy and Appeals reached an agreement and the benefit related to the agreed upon portions was recognized. PSCo did not accrue any income tax benefit related to this adjustment. As of Dec. 31, 2017, the case has been forwarded to the Joint Committee on Taxation.
In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013. In the third quarter of 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. After evaluating the proposed adjustment, Xcel Energy filed a protest with the IRS. Xcel Energy anticipates the issue will be forwarded to Appeals. As of Dec. 31, 2017, 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 uncertain.
State Audits — PSCo is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Dec. 31, 2017, PSCo’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009. There are currently no state income tax audits in progress.
Unrecognized Tax Benefits— The 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. A change in the period of deductibility would not affect the ETR but would accelerate the payment of cash to the taxing authority to an earlier period.
A reconciliation of the amount of unrecognized tax benefit is as follows:
|
| | | | | | | | |
| (Millions of Dollars) | | Dec. 31, 2017 | | Dec. 31, 2016 |
| Unrecognized tax benefit — Permanent tax positions | | $ | 4.0 |
| | $ | 2.9 |
|
| Unrecognized tax benefit — Temporary tax positions | | 6.1 |
| | 16.8 |
|
| Total unrecognized tax benefit | | $ | 10.1 |
| | $ | 19.7 |
|
A reconciliation of the beginning and ending amount of unrecognized tax benefit is as follows:
|
| | | | | | | | | | | | |
| (Millions of Dollars) | | 2017 | | 2016 | | 2015 |
| Balance at Jan. 1 | | $ | 19.7 |
| | $ | 17.4 |
| | $ | 11.9 |
|
| Additions based on tax positions related to the current year | | 1.9 |
| | 2.7 |
| | 4.5 |
|
| Reductions based on tax positions related to the current year | | (1.5 | ) | | — |
| | (1.5 | ) |
| Additions for tax positions of prior years | | 4.4 |
| | 0.5 |
| | 2.5 |
|
| Reductions for tax positions of prior years | | (14.4 | ) | | (0.9 | ) | | — |
|
| Balance at Dec. 31 | | $ | 10.1 |
| | $ | 19.7 |
| | $ | 17.4 |
|
The unrecognized tax benefit amounts were reduced by the tax benefits associated with NOL and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows:
|
| | | | | | | | |
| (Millions of Dollars) | | Dec. 31, 2017 | | Dec. 31, 2016 |
| NOL and tax credit carryforwards | | $ | (4.0 | ) | | $ | (5.8 | ) |
It is reasonably possible that PSCo’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS Appeals progresses and the IRS and state audits resume. As the IRS Appeals progresses, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $2 million.
The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. A reconciliation of the beginning and ending amount of the payable for interest related to unrecognized tax benefits are as follows: |
| | | | | | | | | | | | |
| (Millions of Dollars) | | 2017 | | 2016 | | 2015 |
| Payable for interest related to unrecognized tax benefits at Jan. 1 | | $ | (1.1 | ) | | $ | (0.4 | ) | | $ | (0.2 | ) |
| Interest income (expense) related to unrecognized tax benefits | | 0.8 |
| | (0.7 | ) | | (0.2 | ) |
| Payable for interest related to unrecognized tax benefits at Dec. 31 | | $ | (0.3 | ) | | $ | (1.1 | ) | | $ | (0.4 | ) |
No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2017, 2016 or 2015.
Other Income Tax Matters — NOL amounts represent the amount of 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) | | 2017 | | 2016 |
| Federal NOL carryforward | | $ | 68 |
| | $ | 260 |
|
| Federal tax credit carryforwards | | 30 |
| | 25 |
|
| State NOL carryforwards | | 679 |
| | 684 |
|
State tax credit carryforwards, net of federal detriment (a) | | 17 |
| | 13 |
|
Valuation allowances for state credit carryforwards, net of federal detriment (b) | | (7 | ) | | (3 | ) |
| |
(a)
| State tax credit carryforwards are net of federal detriment of $4 million and $7 million as of Dec. 31, 2017 and 2016, respectively. |
| |
(b)
| Valuation allowances for state tax credit carryforwards were net of federal benefit of $2 million and $2 million as of Dec. 31, 2017 and 2016, respectively. |
The federal carryforward periods expire between 2021 and 2037. The state carryforward periods expire between 2018 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. The following reconciles such
Effective income tax rate for years ended Dec. 31: | | | | | | | | | | | | | | | | | | | | |
| | 2023 | | 2022 | | 2021 |
| Federal statutory rate | | 21.0 | % | | 21.0 | % | | 21.0 | % |
| State income tax on pretax income, net of federal tax effect | | 3.5 | | | 3.5 | | | 3.6 | |
| Increases (decreases) in tax from: | | | | | | |
Wind PTCs (a) | | (14.5) | | | (14.3) | | | (14.3) | |
Plant regulatory differences (b) | | (5.5) | | | (4.5) | | | (4.6) | |
| Other tax credits, net NOL & tax credit allowances | | (1.1) | | | (1.1) | | | (1.0) | |
| Other, net | | 0.6 | | | 0.2 | | | 0.1 | |
| Effective income tax rate | | 4.0 | % | | 4.8 | % | | 4.8 | % |
(a)Wind PTCs net of estimated transfer discount are credited to customers (reduction to revenue) and do not materially impact net income.
(b)Plant regulatory differences forprimarily relate to the years ending Dec. 31:credit of excess deferred taxes to customers through the average rate assumption method. Income tax benefits associated with the credit are offset by corresponding revenue reductions.
|
| | | | | | | | | |
| | | 2017 | | 2016 (b) | | 2015 (b) |
| Federal statutory rate | | 35.0 | % | | 35.0 | % | | 35.0 | % |
| State income tax on pretax income, net of federal tax effect | | 3.0 | % | | 3.0 | % | | 3.0 | % |
| Increases (decreases) in tax from: | |
|
| |
|
| |
|
|
| Tax reform | | (2.4 | ) | | — |
| | — |
|
| Tax credits recognized, net of federal income tax expense | | (0.9 | ) | | (0.7 | ) | | (0.7 | ) |
Regulatory differences - effects of rate changes (a) | | (0.1 | ) | | (0.1 | ) | | (0.1 | ) |
| Regulatory differences - other utility plant items | | (0.9 | ) | | (0.5 | ) | | (0.3 | ) |
| Change in unrecognized tax benefits | | 0.2 |
| | — |
| | 0.1 |
|
| Other, net | | (0.1 | ) | | 0.4 |
| | 0.4 |
|
| Effective income tax rate | | 33.8 | % | | 37.1 | % | | 37.4 | % |
| |
(a)
| The amortization of excess deferred taxes. |
| |
(b)
| The prior periods included in this footnote have been reclassified to conform to current year presentation. |
The componentsComponents of income tax expense for the years endingended Dec. 31 were:31:
| | | | | | | | | | | | | | | | | | | | |
| (Millions of Dollars) | | 2023 | | 2022 | | 2021 |
| Current federal tax expense | | $ | 182 | | | $ | 39 | | | $ | 16 | |
| Current state tax expense | | 28 | | | 11 | | | — | |
| Current change in unrecognized tax benefit | | — | | | — | | | (1) | |
| Deferred federal tax benefit | | (181) | | | (32) | | | (13) | |
| Deferred state tax expense | | 2 | | | 21 | | | 31 | |
| Deferred change in unrecognized tax expense | | 1 | | | 1 | | | 3 | |
| Deferred ITCs | | (3) | | | (3) | | | (3) | |
| Total income tax expense | | $ | 29 | | | $ | 37 | | | $ | 33 | |
|
| | | | | | | | | | | | |
| (Thousands of Dollars) | | 2017 | | 2016 | | 2015 |
| Current federal tax expense (benefit) | | $ | 40,386 |
| | $ | 45,287 |
| | $ | (1,166 | ) |
| Current state tax expense (benefit) | | 14,577 |
| | 8,754 |
| | (727 | ) |
| Current change in unrecognized tax (benefit) expense | | (7,798 | ) | | 680 |
| | 5,244 |
|
| Deferred federal tax expense | | 176,410 |
| | 195,064 |
| | 246,096 |
|
| Deferred state tax expense | | 22,513 |
| | 27,216 |
| | 36,450 |
|
| Deferred change in unrecognized tax expense (benefit) | | 8,894 |
| | (278 | ) | | (4,650 | ) |
| Deferred investment tax credits | | (2,803 | ) | | (2,805 | ) | | (2,807 | ) |
| Total income tax expense | | $ | 252,179 |
| | $ | 273,918 |
| | $ | 278,440 |
|
The componentsComponents of deferred income tax expense as of Dec. 31:
| | | | | | | | | | | | | | | | | | | | |
| (Millions of Dollars) | | 2023 | | 2022 | | 2021 |
| Deferred tax (benefit) expense excluding items below | | $ | (89) | | | $ | 23 | | | $ | 63 | |
| Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities | | (48) | | | (32) | | | (42) | |
Adjustments to deferred income taxes for wind production tax credit cash transfers (a) | | (40) | | | — | | | — | |
| Tax expense allocated to other comprehensive income and other | | (1) | | | (1) | | | — | |
| Deferred tax (benefit) expense | | $ | (178) | | | $ | (10) | | | $ | 21 | |
(a)Proceeds from tax credit transfers are included in cash received (paid) for income taxes in the years ending Dec. 31 were:consolidated statement of cash flows.
|
| | | | | | | | | | | | |
| (Thousands of Dollars) | | 2017 | | 2016 | | 2015 |
| Deferred tax (benefit) expense excluding items below | | $ | (1,244,653 | ) | | $ | 230,931 |
| | $ | 285,144 |
|
| Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities | | 1,453,080 |
| | (8,418 | ) | | (7,229 | ) |
| Tax expense allocated to other comprehensive income, net of adoption of ASU No. 2018-02, and other | | (610 | ) | | (511 | ) | | (19 | ) |
| Deferred tax expense | | $ | 207,817 |
| | $ | 222,002 |
| | $ | 277,896 |
|
The componentsComponents of the net deferred tax liability atas of Dec. 31:
| | | | | | | | | | | | | | |
| (Millions of Dollars) | | 2023 | | 2022 (a) |
| Deferred tax liabilities: | | | | |
| Differences between book and tax bases of property | | $ | 2,326 | | | $ | 2,315 | |
| Regulatory assets | | 289 | | | 243 | |
| Operating lease assets | | 95 | | | 112 | |
| Deferred fuel costs | | 51 | | | 125 | |
| Pension expense and other employee benefits | | 22 | | | 27 | |
| Other | | 8 | | | 11 | |
| Total deferred tax liabilities | | $ | 2,791 | | | $ | 2,833 | |
| | | | |
| Deferred tax assets: | | | | |
| Tax credit carryforward | | $ | 457 | | | $ | 385 | |
| Regulatory liabilities | | 291 | | | 292 | |
| Operating lease liabilities | | 95 | | | 112 | |
| Bad debts | | 14 | | | 14 | |
| Deferred ITCs | | 10 | | | 7 | |
| Tax credit carryforward valuation allowances | | (6) | | | (6) | |
| Rate refund | | 4 | | | 21 | |
| NOL carryforward | | — | | | 9 | |
| Other | | 32 | | | 16 | |
| Total deferred tax assets | | $ | 897 | | | $ | 850 | |
| Net deferred tax liability | | $ | 1,894 | | | $ | 1,983 | |
(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) | | 2023 | | 2022 |
| Federal NOL carryforward | | $ | — | | | $ | 5 | |
| Federal tax credit carryforwards | | 444 | | | 368 | |
| Valuation allowances for federal credit carryforwards | | (3) | | | — | |
| State NOL carryforwards | | — | | | 223 | |
State tax credit carryforwards, net of federal detriment (a) | | 13 | | | 16 | |
Valuation allowances for state credit carryforwards, net of federal benefit (b) | | (3) | | | (6) | |
|
| | | | | | | | |
| (Thousands of Dollars) | | 2017 | | 2016 (a) |
| Deferred tax liabilities: | | | | |
| Differences between book and tax bases of property | | $ | 1,797,023 |
| | $ | 2,967,162 |
|
| Regulatory assets | | 252,353 |
| | 102,967 |
|
| Pension expense | | 60,032 |
| | 10,016 |
|
| Other | | 3,994 |
| | 3,920 |
|
| Total deferred tax liabilities | | $ | 2,113,402 |
| | $ | 3,084,065 |
|
| Deferred tax assets: | | |
| | |
|
| Regulatory liabilities | | $ | 337,973 |
| | $ | (35,813 | ) |
| NOL carryforward | | 39,347 |
| | 115,328 |
|
| Tax credit carryforward | | 39,323 |
| | 34,658 |
|
| Deferred investment tax credits | | 6,872 |
| | 11,653 |
|
| Other employee benefits | | 6,779 |
| | 15,274 |
|
| Deferred fuel costs | | 6,523 |
| | 10,070 |
|
| Rate refund | | 890 |
| | 7,221 |
|
| Other | | 31,219 |
| | 36,545 |
|
| Total deferred tax assets | | $ | 468,926 |
| | $ | 194,936 |
|
| Net deferred tax liability | | $ | 1,644,476 |
| | $ | 2,889,129 |
|
| |
(a)
| The prior period included in this footnote has been reclassified to conform to current year presentation. |
| |
8. | Benefit Plans and Other Postretirement Benefits |
Consistent with the process for rate recovery(a)State tax credit carryforwards are net of pension and postretirement benefits for its employees, PSCo accounts for its participation in, and related costsfederal detriment of pension and other postretirement benefit plans sponsored by Xcel Energy Inc. as multiple employer plans. PSCo is responsible for its share of cash contributions, plan costs and obligations and is entitled to its share of plan assets; accordingly, PSCo accounts for its pro rata share of these plans, including pension expense and contributions, resulting in accounting consistent with that of a single employer plan exclusively for PSCo employees.
Xcel Energy, which includes PSCo, offers various benefit plans to its employees. Approximately 76 percent of employees that receive benefits are represented by several local labor unions under several collective-bargaining agreements. At Dec. 31, 2017, PSCo had 1,835 bargaining employees covered under a collective-bargaining agreement, which expired in May 2017. While collective bargaining is ongoing, the terms and conditions of the agreement are automatically extended.
The plans invest in various instruments which are disclosed under the accounting guidance for fair value measurements which establishes a hierarchical framework for disclosing the observability of the inputs utilized in measuring fair value. The three levels in the hierarchy and examples of each level are as follows:
Level 1 — Quoted prices are available in active markets for identical assets as of the reporting date. The types of assets included in Level 1 are highly liquid and actively traded instruments with quoted prices.
Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reporting date. The types of assets 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 included in Level 3 are those with inputs requiring significant management judgment or estimation.
Specific valuation methods include the following:
Cash equivalents —The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted NAVs.
Insurance contracts — Insurance contract fair values take into consideration the value of the investments in separate accounts of the insurer, which are priced based on observable inputs.
Investments in commingled funds, equity securities and other funds — Equity securities are valued using quoted prices in active markets. The fair values for commingled funds are measured using NAVs, which take into consideration the value of underlying fund investments, as well as the other accrued assets and liabilities of a fund, in order to determine a per share market value. The investments in commingled funds may be redeemed for NAV with proper notice. Proper notice varies by fund and can range from daily with a few days’ notice to annually with 90 days’ notice. Private equity investments require approval of the fund for any unscheduled redemption, and such redemptions may be approved or denied by the fund at its sole discretion. Depending on the fund, unscheduled distributions from real estate investments may require approval of the fund or may be redeemed with proper notice, which is typically quarterly with 45-90 days’ notice; however, withdrawals from real estate investments may be delayed or discounted as a result of fund illiquidity.
Investments in debt securities — Fair values for debt securities are determined by a third party pricing service using recent trades and observable spreads from benchmark interest rates for similar securities. Derivative Instruments —Fair values for foreign currency derivatives are determined using pricing models based on the prevailing forward exchange rate of the underlying currencies. The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.
Pension Benefits
Xcel Energy, which includes PSCo, has several noncontributory, defined benefit pension plans that cover almost all employees. Generally, benefits are based on a combination of years of service, the employee’s average pay and, in some cases, social security benefits. Xcel Energy Inc.’s and PSCo’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 supplemental executive retirement plan (SERP) and a nonqualified pension plan. The SERP is maintained for certain executives that were participants in the plan in 2008, when the SERP was closed to new participants. The nonqualified pension plan provides unfunded, nonqualified benefits for compensation that is in excess of the limits applicable to the qualified pension plans, with distributions attributable to PSCo funded by PSCo’s consolidated operating cash flows. The total obligations of the SERP and nonqualified plan as of Dec. 31, 2017 and 2016 were $37 million and $44 million, respectively, of which $3 million and $4 million were attributable to PSCo. In 2017 and 2016, Xcel Energy recognized net benefit cost for financial reporting for the SERP and nonqualified plans of $5 million and $8 million, respectively, of which $1 million in each year was attributable to PSCo.
In 2016, Xcel Energy established rabbi trusts to provide partial funding for future distributions of the SERP and its deferred compensation plan. Rabbi trust funding of deferred compensation plan distributions attributable to PSCo will be supplemented by PSCo’s consolidated operating cash flows as determined necessary. The amount of rabbi trust funding attributable to PSCo is immaterial. Also in 2016, Xcel Energy amended the deferred compensation plan to provide eligible participants the ability to diversify deferred settlements of equity awards, other than time-based equity awards, into various fund options.
Xcel Energy Inc. and PSCo base the investment-return assumption on expected long-term performance for each of the investment types included in the pension asset portfolio and consider the historical returns achieved by the asset portfolio over the past 20-year or longer period, as well as the long-term return levels projected and recommended by investment experts. Xcel Energy Inc. and PSCo continually review pension assumptions. The pension cost determination assumes a forecasted mix of investment types over the long term.
Investment returns in 2017 were above the assumed level of 6.84 percent;
Investment returns in 2016 were below the assumed level of 6.84 percent;
Investment returns in 2015 were below the assumed level of 6.81 percent; and
In 2018, PSCo’s expected investment-return assumption is 6.84 percent.
The assets are invested in a portfolio according to Xcel Energy Inc.’s and PSCo’s return, liquidity and diversification objectives to provide funding for plan obligations and minimize contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the projected asset allocation given the long-term risk, return, and liquidity characteristics of each particular asset class. There were no significant concentrations of risk in any particular industry, index, or entity. Market volatility can impact even well-diversified portfolios and significantly affect the return levels achieved by pension assets in any year.
The following table presents the target pension asset allocations for PSCo at Dec. 31 for the upcoming year:
|
| | | | | | |
| | | 2017 | | 2016 |
| Domestic and international equity securities | | 34 | % | | 36 | % |
| Long-duration fixed income and interest rate swap securities | | 32 |
| | 31 |
|
| Short-to-intermediate fixed income securities | | 18 |
| | 15 |
|
| Alternative investments | | 14 |
| | 16 |
|
| Cash | | 2 |
| | 2 |
|
| Total | | 100 | % | | 100 | % |
The 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 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. The aggregate projected asset allocation presented in the table above for the master pension trust results from the plan-specific strategies.
Pension Plan Assets
The following tables present, for each of the fair value hierarchy levels, PSCo’s pension plan assets that are measured at fair value as of Dec. 31, 20172023 and 2016:2022, respectively.
|
| | | | | | | | | | | | | | | | | | | | |
| | | Dec. 31, 2017 |
| (Thousands of Dollars) | | Level 1 | | Level 2 | | Level 3 | | Investments Measured at NAV | | Total |
| Cash equivalents | | $ | 67,179 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 67,179 |
|
| Commingled funds: | | | | | | | | | | |
| U.S. equity funds | | 169,624 |
| | — |
| | — |
| | — |
| | 169,624 |
|
| Non U.S. equity funds | | 30,277 |
| | — |
| | — |
| | 65,822 |
| | 96,099 |
|
| U.S. corporate bond funds | | 137,086 |
| | — |
| | — |
| | — |
| | 137,086 |
|
| Emerging market equity funds | | — |
| | — |
| | — |
| | 103,876 |
| | 103,876 |
|
| Emerging market debt funds | | 24,825 |
| | — |
| | — |
| | 54,954 |
| | 79,779 |
|
| Private equity investments | | — |
| | — |
| | — |
| | 27,816 |
| | 27,816 |
|
| Real estate | | — |
| | — |
| | — |
| | 64,500 |
| | 64,500 |
|
| Other commingled funds | | 1,601 |
| | — |
| | — |
| | 38,545 |
| | 40,146 |
|
| Debt securities: | | | | | | | | | | |
| Government securities | | — |
| | 144,333 |
| | — |
| | — |
| | 144,333 |
|
| U.S. corporate bonds | | — |
| | 102,659 |
| | — |
| | — |
| | 102,659 |
|
| Non U.S. corporate bonds | | — |
| | 16,792 |
| | — |
| | — |
| | 16,792 |
|
| Equity securities: | | | | | | | | | | |
| U.S. equities | | 37,752 |
| | — |
| | — |
| | — |
| | 37,752 |
|
| Other | | (9,885 | ) | | 1,414 |
| | — |
| | 180 |
| | (8,291 | ) |
| Total | | $ | 458,459 |
| | $ | 265,198 |
| | $ | — |
| | $ | 355,693 |
| | $ | 1,079,350 |
|
|
| | | | | | | | | | | | | | | | | | | | |
| | | Dec. 31, 2016 |
| (Thousands of Dollars) | | Level 1 | | Level 2 | | Level 3 | | Investments Measured at NAV | | Total |
| Cash equivalents | | $ | 34,957 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 34,957 |
|
| Commingled funds: | | | | | | | | | | |
| U.S. equity funds | | 165,621 |
| | — |
| | — |
| | — |
| | 165,621 |
|
| Non U.S. equity funds | | 64,710 |
| | — |
| | — |
| | 57,487 |
| | 122,197 |
|
| U.S. corporate bond funds | | 96,995 |
| | — |
| | — |
| | — |
| | 96,995 |
|
| Emerging market equity funds | | — |
| | — |
| | — |
| | 64,784 |
| | 64,784 |
|
| Emerging market debt funds | | 25,866 |
| | — |
| | — |
| | 27,837 |
| | 53,703 |
|
| Commodity funds | | — |
| | — |
| | — |
| | 7,497 |
| | 7,497 |
|
| Private equity investments | | — |
| | — |
| | — |
| | 31,828 |
| | 31,828 |
|
| Real estate | | — |
| | — |
| | — |
| | 61,048 |
| | 61,048 |
|
| Other commingled funds | | — |
| | — |
| | — |
| | 74,696 |
| | 74,696 |
|
| Debt securities: | | | | | | | | | | |
| Government securities | | — |
| | 168,014 |
| | — |
| | — |
| | 168,014 |
|
| U.S. corporate bonds | | — |
| | 86,081 |
| | — |
| | — |
| | 86,081 |
|
| Non U.S. corporate bonds | | — |
| | 13,828 |
| | — |
| | — |
| | 13,828 |
|
| Mortgage-backed securities | | — |
| | 2,179 |
| | — |
| | — |
| | 2,179 |
|
| Asset-backed securities | | — |
| | 1,032 |
| | — |
| | — |
| | 1,032 |
|
| Equity securities: | | | | | | | | | | |
| U.S. equities | | 27,348 |
| | — |
| | — |
| | — |
| | 27,348 |
|
| Other | | — |
| | (7,595 | ) | | — |
| | — |
| | (7,595 | ) |
| Total | | $ | 415,497 |
| | $ | 263,539 |
| | $ | — |
| | $ | 325,177 |
| | $ | 1,004,213 |
|
There(b)Valuation allowances for state tax credit carryforwards were no assets transferred in or outnet of Level 3 for the years ended Dec. 31, 2017, 2016 or 2015.
Benefit Obligations — A comparisonfederal benefit of the actuarially computed pension benefit obligation and plan assets for PSCo is presented in the following table:
|
| | | | | | | | |
| (Thousands of Dollars) | | 2017 | | 2016 |
| Accumulated Benefit Obligation at Dec. 31 | | $ | 1,285,010 |
| | $ | 1,213,890 |
|
| | | | | |
| Change in Projected Benefit Obligation: | | | | |
| Obligation at Jan. 1 | | $ | 1,251,822 |
| | $ | 1,224,650 |
|
| Service cost | | 27,280 |
| | 25,926 |
|
| Interest cost | | 50,558 |
| | 55,405 |
|
| Transfer to other plan | | — |
| | (9,149 | ) |
| Plan amendments | | (1,096 | ) | | 206 |
|
| Actuarial loss | | 83,531 |
| | 51,779 |
|
| Benefit payments | | (77,915 | ) | | (96,995 | ) |
| Obligation at Dec. 31 | | $ | 1,334,180 |
| | $ | 1,251,822 |
|
|
| | | | | | | | |
| (Thousands of Dollars) | | 2017 | | 2016 |
| Change in Fair Value of Plan Assets: | | | | |
| Fair value of plan assets at Jan. 1 | | $ | 1,004,213 |
| | $ | 1,036,681 |
|
| Actual return on plan assets | | 135,552 |
| | 56,762 |
|
| Employer contributions | | 17,500 |
| | 16,829 |
|
| Transfer to other plan | | — |
| | (9,064 | ) |
| Benefit payments | | (77,915 | ) | | (96,995 | ) |
| Fair value of plan assets at Dec. 31 | | $ | 1,079,350 |
| | $ | 1,004,213 |
|
|
| | | | | | | | |
| (Thousands of Dollars) | | 2017 | | 2016 |
| Funded Status of Plans at Dec. 31: | | | | |
Funded status (a) | | $ | (254,830 | ) | | $ | (247,609 | ) |
| |
(a)
| Amounts are recognized in noncurrent liabilities on PSCo’s consolidated balance sheets. |
|
| | | | | | | | |
| (Thousands of Dollars) | | 2017 | | 2016 |
| Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: | | | | |
| Net loss | | $ | 543,707 |
| | $ | 554,999 |
|
| Prior service credit | | (10,593 | ) | | (12,155 | ) |
| Total | | $ | 533,114 |
| | $ | 542,844 |
|
|
| | | | | | | | |
| (Thousands of Dollars) | | 2017 | | 2016 |
| 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 | | $ | 27,662 |
| | $ | 26,853 |
|
| Noncurrent regulatory assets | | 505,171 |
| | 515,708 |
|
| Deferred income taxes | | 69 |
| | 108 |
|
| Net-of-tax accumulated OCI | | 212 |
| | 175 |
|
| Total | | $ | 533,114 |
| | $ | 542,844 |
|
|
| | | | |
Measurement date | | Dec. 31, 2017 | | Dec. 31, 2016 |
|
| | | | | | |
| | | 2017 | | 2016 |
| Significant Assumptions Used to Measure Benefit Obligations: | | | | |
| Discount rate for year-end valuation | | 3.63 | % | | 4.13 | % |
| Expected average long-term increase in compensation level | | 3.75 |
| | 3.75 |
|
| Mortality table | | RP-2014 |
| | RP-2014 |
|
Mortality — In 2014, the Society of Actuaries published a new mortality table (RP-2014) that increased the overall life expectancy of males and females. In 2014, PSCo adopted this mortality table, with modifications, based on its population and specific experience. During 2017, a new projection table was released (MP-2017). PSCo evaluated the updated projection table and concluded that the methodology currently in use and adopted in 2016 is consistent with the recently updated 2017 table and continues to be representative of PSCo’s population.
Cash Flows — Cash funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other calculations prescribed by the funding requirements of income tax and other pension-related regulations. Required contributions were made in 2015 through 2018 to meet minimum funding requirements.
Total voluntary and required pension funding contributions across all four of Xcel Energy’s pension plans were as follows:
$150 million in January 2018, of which $22 million was attributable to PSCo;
$162 million in 2017, of which $18 million was attributable to PSCo;
$125 million in 2016, of which $17 million was attributable to PSCo; and
$90 million in 2015, of which $20 million was attributable to PSCo.
For future years, Xcel Energy and PSCo anticipate contributions will be made as necessary.
Plan Amendments — Xcel Energy, which includes PSCo, amended the Xcel Energy Inc. Nonbargaining Pension Plan (South) in 2017 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. In 2016, the annual credits contributed to the PSCo Bargaining Plan retirement spending account increased.
Benefit Costs —The components of PSCo’s net periodic pension cost were:
|
| | | | | | | | | | | | |
| (Thousands of Dollars) | | 2017 | | 2016 | | 2015 |
| Service cost | | $ | 27,280 |
| | $ | 25,926 |
| | $ | 28,260 |
|
| Interest cost | | 50,558 |
| | 55,405 |
| | 50,857 |
|
| Expected return on plan assets | | (68,535 | ) | | (70,769 | ) | | (72,590 | ) |
| Amortization of prior service credit | | (3,211 | ) | | (3,211 | ) | | (3,136 | ) |
| Amortization of net loss | | 28,355 |
| | 26,771 |
| | 36,377 |
|
| Net periodic pension cost | | 34,447 |
| | 34,122 |
| | 39,768 |
|
| (Costs) credits not recognized due to effects of regulation | | (2,631 | ) | | 3,364 |
| | (1,464 | ) |
| Net benefit cost recognized for financial reporting | | $ | 31,816 |
| | $ | 37,486 |
| | $ | 38,304 |
|
|
| | | | | | | | | |
| | | 2017 | | 2016 | | 2015 |
| Significant Assumptions Used to Measure Costs: | | | | | | |
| Discount rate | | 4.13 | % | | 4.66 | % | | 4.11 | % |
| Expected average long-term increase in compensation level | | 3.75 |
| | 4.00 |
| | 3.75 |
|
| Expected average long-term rate of return on assets | | 6.84 |
| | 6.84 |
| | 6.81 |
|
In addition to the benefit costs in the table above, for the pension plans sponsored by Xcel Energy Inc., costs are allocated to PSCo based on Xcel Energy Services Inc. employees’ labor costs. Amounts allocated to PSCo were $18 million, $9$1 million and $10$2 million in 2017, 2016 and 2015, respectively. Pension costs include an expected return impact for the current year that may differ from actual investment performance in the plan. The return assumption used for 2018 pension cost calculations is 6.84 percent. The cost calculation uses a market-related valuation of pension assets. Xcel Energy, including PSCo, uses a calculated value method to determine the market-related value of the plan assets. The market-related value begins with the fair market value of assets as of the beginning of the year. The market-related value is determined by adjusting the fair market value of assets to reflect the investment gains and losses (the difference between the actual investment return and the expected investment return on the market-related value) during each of the previous five years at the rate of 20 percent per year. As these differences between actual investment returns and the expected investment returns are incorporated into the market-related value, the differences are recognized over the expected average remaining years of service for active employees.
Defined Contribution Plans
Xcel Energy, which includes PSCo, maintains 401(k) and other defined contribution plans that cover substantially all employees. The expense to these plans for PSCo was approximately $10 million in 2017, 2016 and 2015.
Postretirement Health Care Benefits
Xcel Energy, which includes PSCo, has a contributory health and welfare benefit plan that provides health care and death benefits to certain retirees. Xcel Energy discontinued contributing toward health care benefits for PSCo nonbargaining employees retiring after June 30, 2003. Employees of NCE who retired in 2002 continue to receive employer-subsidized health care benefits. Nonbargaining employees of the former NCE who retired after 1998, bargaining employees of the former NCE who retired after 1999 and nonbargaining employees of NCE who retired after June 30, 2003, are eligible to participate in the Xcel Energy health care program with no employer subsidy.
Plan Assets — Certain state agencies that regulate Xcel Energy Inc.’s utility subsidiaries also have issued guidelines related 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.
The following table presents the target postretirement asset allocations for Xcel Energy Inc. and PSCo at Dec. 31 for the upcoming year:
|
| | | | | | |
| | | 2017 | | 2016 |
| Domestic and international equity securities | | 24 | % | | 25 | % |
| Short-to-intermediate fixed income securities | | 60 |
| | 57 |
|
| Alternative investments | | 9 |
| | 13 |
|
| Cash | | 7 |
| | 5 |
|
| Total | | 100 | % | | 100 | % |
Xcel Energy Inc. and PSCo base the investment-return assumptions for the postretirement health care fund assets on expected long-term performance for each of the investment types included in the asset portfolio. Assumptions and target allocations are determined at the master trust level. The investment mix at each of Xcel Energy Inc.’s utility subsidiaries may vary from the investment mix of the total asset portfolio. The assets are invested in a portfolio according to Xcel Energy Inc.’s and PSCo’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 projected 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 particular industry, index, or entity. Market volatility can impact even well-diversified portfolios and significantly affect the return levels achieved by postretirement health care assets in any year.
The following tables present, for each of the fair value hierarchy levels, PSCo’s proportionate allocation of the total postretirement benefit plan assets that are measured at fair value as of Dec. 31, 20172023 and 2016:2022, respectively.
Federal carryforward periods expire between 2038 and 2043 and state carryforward periods expire between 2024 and 2036.
|
| | | | | | | | | | | | | | | | | | | | |
| | | Dec. 31, 2017 |
| (Thousands of Dollars) | | Level 1 | | Level 2 | | Level 3 | | Investments Measured at NAV | | Total |
| Cash equivalents | | $ | 25,724 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 25,724 |
|
| Insurance contracts | | — |
| | 43,524 |
| | — |
| | — |
| | 43,524 |
|
| Commingled funds: | | | | | | | | | | |
| U.S. equity funds | | 64,899 |
| | — |
| | — |
| | — |
| | 64,899 |
|
| U.S fixed income funds | | 29,946 |
| | — |
| | — |
| | — |
| | 29,946 |
|
| Emerging market debt funds | | 35,402 |
| | — |
| | — |
| | — |
| | 35,402 |
|
| Debt securities: | | | | | | | | | | |
| Government securities | | — |
| | 50,576 |
| | — |
| | — |
| | 50,576 |
|
| U.S. corporate bonds | | — |
| | 55,323 |
| | — |
| | — |
| | 55,323 |
|
| Non U.S. corporate bonds | | — |
| | 18,712 |
| | — |
| | — |
| | 18,712 |
|
| Asset-backed securities | | — |
| | 20,468 |
| | — |
| | — |
| | 20,468 |
|
| Mortgage-backed securities | | — |
| | 30,231 |
| | — |
| | — |
| | 30,231 |
|
| Equity securities: | | | | | | | | | | |
| Non U.S. equities | | 30,671 |
| | — |
| | — |
| | — |
| | 30,671 |
|
| Other | | — |
| | 948 |
| | — |
| | — |
| | 948 |
|
| Total | | $ | 186,642 |
| | $ | 219,782 |
| | $ | — |
| | $ | — |
| | $ | 406,424 |
|
Unrecognized Tax Benefits
Federal Audit — PSCo is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. The statute of limitations applicable to Xcel Energy’s consolidated federal tax returns expire as follows: | | | | | | | | |
| Tax Year(s) | | Expiration |
| 2014 - 2016 | | March 2025 |
| 2020 | | September 2024 |
|
| | | | | | | | | | | | | | | | | | | | |
| | | Dec. 31, 2016 |
| (Thousands of Dollars) | | Level 1 | | Level 2 | | Level 3 | | Investments Measured at NAV
| | Total |
| Cash equivalents | | $ | 18,288 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 18,288 |
|
| Insurance contracts | | — |
| | 42,046 |
| | — |
| | — |
| | 42,046 |
|
| Commingled funds: | | | | | | | | | | |
| U.S. equity funds | | 48,462 |
| | — |
| | — |
| | — |
| | 48,462 |
|
| U.S fixed income funds | | 24,132 |
| | — |
| | — |
| | — |
| | 24,132 |
|
| Emerging market debt funds | | 27,089 |
| | — |
| | — |
| | — |
| | 27,089 |
|
| Other commingled funds | | — |
| | — |
| | — |
| | 48,922 |
| | 48,922 |
|
| Debt securities: | | | | | | | | | | |
| Government securities | | — |
| | 33,600 |
| | — |
| | — |
| | 33,600 |
|
| U.S. corporate bonds | | — |
| | 55,473 |
| | — |
| | — |
| | 55,473 |
|
| Non U.S. corporate bonds | | — |
| | 15,384 |
| | — |
| | — |
| | 15,384 |
|
| Asset-backed securities | | — |
| | 16,845 |
| | — |
| | — |
| | 16,845 |
|
| Mortgage-backed securities | | — |
| | 25,563 |
| | — |
| | — |
| | 25,563 |
|
| Equity securities: | | | | | | | | | | |
| Non U.S. equities | | 36,462 |
| | — |
| | — |
| | — |
| | 36,462 |
|
| Other | | — |
| | 1,289 |
| | — |
| | — |
| | 1,289 |
|
| Total | | $ | 154,433 |
| | $ | 190,200 |
| | $ | — |
| | $ | 48,922 |
| | $ | 393,555 |
|
There were no assets transferredAdditionally, the statute of limitations related to certain federal tax credit carryforwards will remain open until those credits are utilized in or outsubsequent returns. Further, the statute of Level 3 forlimitations related to the years endedadditional federal tax loss carryback claim filed in 2020 has been extended. As of Dec. 31, 2017, 2016 or 2015.2023 the IRS issued its Revenue Agent’s Report related to the federal tax loss carryback claim. The Company materially agrees with the report and re-recognized the related benefit in Dec. 2023.
Benefit ObligationsState Audits — A comparisonPSCo is a member of the actuarially computed benefit obligation and plan assets for PSCo is presented in the following table:
|
| | | | | | | | |
| (Thousands of Dollars) | | 2017 | | 2016 |
| Change in Projected Benefit Obligation: | | | | |
| Obligation at Jan. 1 | | $ | 421,823 |
| | $ | 403,574 |
|
| Service cost | | 767 |
| | 768 |
|
| Interest cost | | 16,765 |
| | 18,070 |
|
| Medicare subsidy reimbursements | | 993 |
| | 1,901 |
|
| Plan participants’ contributions | | 5,971 |
| | 5,376 |
|
| Actuarial loss | | 18,314 |
| | 27,355 |
|
| Benefit payments | | (35,386 | ) | | (35,221 | ) |
| Obligation at Dec. 31 | | $ | 429,247 |
| | $ | 421,823 |
|
|
| | | | | | | | |
| (Thousands of Dollars) | | 2017 | | 2016 |
| Change in Fair Value of Plan Assets: | | | | |
| Fair value of plan assets at Jan. 1 | | $ | 393,555 |
| | $ | 399,442 |
|
| Actual return on plan assets | | 36,975 |
| | 18,590 |
|
| Plan participants’ contributions | | 5,971 |
| | 5,376 |
|
| Employer contributions | | 5,309 |
| | 5,368 |
|
| Benefit payments | | (35,386 | ) | | (35,221 | ) |
| Fair value of plan assets at Dec. 31 | | $ | 406,424 |
| | $ | 393,555 |
|
|
| | | | | | | | |
| (Thousands of Dollars) | | 2017 | | 2016 |
| Funded Status at Dec. 31: | | | | |
Funded status (a) | | $ | (22,823 | ) | | $ | (28,268 | ) |
| |
(a)
| Amounts are recognized in noncurrent liabilities on PSCo’s consolidated balance sheets as of Dec. 31, 2017 and 2016, respectively. |
|
| | | | | | | | |
| (Thousands of Dollars) | | 2017 | | 2016 |
| Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: | | | | |
| Net loss | | $ | 77,760 |
| | $ | 78,359 |
|
| Prior service credit | | (21,448 | ) | | (27,695 | ) |
| Total | | $ | 56,312 |
| | $ | 50,664 |
|
|
| | | | | | | | |
| (Thousands of Dollars) | | 2017 | | 2016 |
| Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates: | | | | |
| Noncurrent regulatory assets | | $ | 56,312 |
| | $ | 50,664 |
|
Xcel Energy affiliated group that files consolidated state income tax returns. As of Dec. 31, 2023, PSCo’s earliest open tax years that are subject to examination by state taxing authorities under applicable statutes of limitations are as follows: | | | | | | | | | | | | | | |
| State | | Tax Year(s) | | Expiration |
| Colorado | | 2014-2016 | | | March 2026 |
Measurement dateColorado | | 2019 | | Dec. 31, 2017 | Dec. 31, 2016October 2024 |
There are currently no state income tax audits in progress. |
| | | | | | |
| | | 2017 | | 2016 |
| Significant Assumptions Used to Measure Benefit Obligations: | | | | |
| Discount rate for year-end valuation | | 3.62 | % | | 4.13 | % |
| Mortality table | | RP 2014 |
| | RP 2014 |
|
| Health care costs trend rate — initial: Pre-65 | | 7.00 | % | | 5.50 | % |
| Health care costs trend rate — initial: Post-65 | | 5.50 | % | | 5.50 | % |
Beginning withUnrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the Dec. 31 2017 measurement, Xcel Energy Inc. and PSCo separated its initial medical trend assumptionETR. In addition, the unrecognized tax benefit balance includes temporary tax positions for pre-Medicare (Pre-65) and post-Medicare (Post-65) claims costs of 7.0 percent and 5.5 percent, respectively, in order to reflect different short-term expectations based on recent experience differences. The ultimate trend assumption remained at 4.5 percentwhich deductibility is highly certain, but for both Pre-65 and Post-65 claims costs as similar long-term trend rates are expected for both populations. The period untilwhich there is uncertainty about the ultimate rate is reached is five years. Xcel Energy Inc. and PSCo base the medical trend assumption on the long-term cost inflation expected in the health care market, considering the levels projected and recommended by industry experts, as well as recent actual medical cost increases experienced by the retiree medical plan.
timing. A one-percent change in the assumed health care cost trend ratetiming of deductibility would havenot affect the following effects on PSCo:ETR but would accelerate the payment to the taxing authority.
Unrecognized tax benefits - permanent vs temporary:
| | | | | | | | | | | | | | |
| (Millions of Dollars) | | Dec. 31, 2023 | | Dec. 31, 2022 |
| Unrecognized tax benefit — Permanent tax positions | | $ | 12 | | | $ | 11 | |
| Unrecognized tax benefit — Temporary tax positions | | — | | | 2 | |
| Total unrecognized tax benefit | | $ | 12 | | | $ | 13 | |
Changes in unrecognized tax benefits:
| | | | | | | | | | | | | | | | | | | | |
| (Millions of Dollars) | | 2023 | | 2022 | | 2021 |
| Balance at Jan. 1 | | $ | 13 | | | $ | 11 | | | $ | 9 | |
| Additions based on tax positions related to the current year | | 2 | | | 2 | | | 2 | |
| Reductions for tax positions of prior years | | (3) | | | — | | | — | |
| Balance at Dec. 31 | | $ | 12 | | | $ | 13 | | | $ | 11 | |
Unrecognized tax benefits were reduced by tax benefits associated with NOL and tax credit carryforwards:
| | | | | | | | | | | | | | |
| (Millions of Dollars) | | Dec. 31, 2023 | | Dec. 31, 2022 |
| NOL and tax credit carryforwards | | $ | (11) | | | $ | (12) | |
As IRS and state audits resume, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $4 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. Payables for interest related to unrecognized tax benefits at Dec. 31, 2023, 2022 and 2021 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2023, 2022 or 2021.
|
| | | | | | | | |
| | | One-Percentage Point |
| (Thousands of Dollars) | | Increase | | Decrease |
| APBO | | $ | 41,665 |
| | $ | (35,254 | ) |
| Service and interest components | | 1,837 |
| | (1,555 | ) |
Cash Flows — The postretirement health care plans have no funding requirements under income tax and other retirement-related regulations other than fulfilling benefit payment obligations, when claims are presented and approved under the plans. Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities. Xcel Energy, which includes PSCo, contributed $20 million, $18 million and $18 million during 2017, 2016 and 2015, respectively, of which $5 million, $5 million and $6 million were attributable to PSCo. Xcel Energy expects to contribute approximately $12 million during 2018, of which amounts attributable to PSCo will be zero.
Plan Amendments — In 2017 and 2016 there were no plan amendments made which affected the projected benefit obligation.
Benefit Costs — The components of PSCo’s net periodic postretirement benefit costs were:
|
| | | | | | | | | | | | |
| (Thousands of Dollars) | | 2017 | | 2016 | | 2015 |
| Service cost | | $ | 767 |
| | $ | 768 |
| | $ | 928 |
|
| Interest cost | | 16,765 |
| | 18,070 |
| | 17,498 |
|
| Expected return on plan assets | | (21,905 | ) | | (22,299 | ) | | (23,803 | ) |
| Amortization of prior service credit | | (6,247 | ) | | (6,247 | ) | | (6,247 | ) |
| Amortization of net loss | | 3,843 |
| | 1,931 |
| | 2,475 |
|
| Net periodic postretirement benefit credit | | $ | (6,777 | ) | | $ | (7,777 | ) | | $ | (9,149 | ) |
|
| | | | | | | | | |
| | | 2017 | | 2016 | | 2015 |
| Significant Assumptions Used to Measure Costs: | | | | | | |
| Discount rate | | 4.13 | % | | 4.65 | % | | 4.08 | % |
| Expected average long-term rate of return on assets | | 5.80 |
| | 5.80 |
| | 5.80 |
|
In addition to the benefit costs in the table above, for the postretirement health care plans sponsored by Xcel Energy Inc., costs are allocated to PSCo based on Xcel Energy Services Inc. employees’ labor costs.
Projected Benefit Payments
The following table lists PSCo’s projected benefit payments for the pension and postretirement benefit plans:
|
| | | | | | | | | | | | | | | | |
| (Thousands 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 |
| 2018 | | $ | 83,036 |
| | $ | 32,186 |
| | $ | 2,074 |
| | $ | 30,112 |
|
| 2019 | | 81,698 |
| | 32,454 |
| | 2,192 |
| | 30,262 |
|
| 2020 | | 81,413 |
| | 32,767 |
| | 2,296 |
| | 30,471 |
|
| 2021 | | 82,021 |
| | 32,737 |
| | 2,404 |
| | 30,333 |
|
| 2022 | | 83,261 |
| | 32,998 |
| | 2,501 |
| | 30,497 |
|
| 2023-2027 | | 411,798 |
| | 152,926 |
| | 13,789 |
| | 139,137 |
|
Other income, net for the years ended Dec. 31 consisted of the following:
|
| | | | | | | | | | | | |
| (Thousands of Dollars) | | 2017 | | 2016 | | 2015 |
| Interest income | | $ | 3,809 |
| | $ | 1,860 |
| | $ | 753 |
|
| Other nonoperating income | | 6,383 |
| | 2,241 |
| | 2,408 |
|
| Insurance policy expense | | (340 | ) | | (281 | ) | | (197 | ) |
| Other nonoperating expense | | — |
| | (3 | ) | | — |
|
| Other income, net | | $ | 9,852 |
| | $ | 3,817 |
| | $ | 2,964 |
|
| |
10. | 8. Fair Value of Financial Assets and Liabilities |
Fair Value Measurements
The accountingAccounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires certain 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. The three levels in the hierarchy are as follows: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 the following:include:
Cash equivalents— The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted NAV.
Interest rate derivatives— The fair Fair 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 interest paymentsrate on certain floating ratea specified principal amount of a hypothetical future debt obligations or effectively fix the yield or priceissuance. 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.purposes, with changes in fair value prior to occurrence of the hedged transactions recorded as other comprehensive income.
AtAs of Dec. 31, 2017,2023, accumulated other comprehensive lossesloss related to interest rate derivatives included $1.2$1 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged transactions impact earnings. As of Dec. 31, 2023, PSCo had no unsettled interest rate transactions impact earnings, including forecasted amounts for unsettled hedges, as applicable.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’s risk management policy allows managementPSCo is allowed to conduct these activities within guidelines and limitations as approved by its risk management committee, which is made upcomprised 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. Changes in the fair valueThe classification of non-trading commodity derivativeunrealized losses or gains on these instruments are recorded in OCI or deferred as a regulatory asset or liability. The classification as a regulatory asset or liability, if applicable, is based on commission approved regulatory recovery mechanisms.
As of Dec. 31, 2023, PSCo recordedhad no amounts to income related to the ineffectiveness ofcommodity contracts designated as cash flow hedges for the year ended Dec. 31, 2017 and immaterial amounts for the year ended Dec. 31, 2016.hedges.
Additionally, 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.
The following table details the grossGross notional amounts of commodity forwards and options:
| | | | | | | | | | | | | | |
(Amounts in Millions) (a)(b) | | Dec. 31, 2023 | | Dec. 31, 2022 |
| MWh of electricity | | 2 | | | 8 | |
| MMBtu of natural gas | | 20 | | | 43 | |
(a)Not reflective of net positions in the underlying commodities.
(b)Notional amounts for options at Dec. 31:included on a gross basis, but weighted for the probability of exercise.
|
| | | | | | |
(Amounts in Thousands) (a)(b) | | 2017 | | 2016 |
| MWh of electricity | | 22,260 |
| | 6,283 |
|
| MMBtu of natural gas | | 13,410 |
| | 42,203 |
|
| |
(a)
| Amounts are not reflective of net positions in the underlying commodities. |
| |
(b)
| Notional amounts for options are 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. Given this assessment, as well as an assessment of the impact of PSCo’s own credit risk when determining the fair value of derivative liabilities, the impactImpact of credit risk was immaterial to the fair value of unsettled commodity derivatives presented inon the consolidated balance sheets.
PSCo employs additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures. Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided.
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, 2017, five2023, four of PSCo’s 10ten most significant counterparties for these activities, comprising $7.0$30 million or 16 percent36% of this credit exposure, had investment grade credit ratings from S&P’s,&P Global Ratings, Moody’s Investor Services or Fitch Ratings. Four
Six of the 10ten most significant counterparties, comprising $16.5$40 million or 37 percent48% of this credit exposure, at Dec. 31, 2017 were not rated by these external ratings agencies, but based on PSCo’s internal analysis, had credit quality consistent with investment grade. Another
None of these significant counterparties comprising $7.4 million or 17 percent of this credit exposure, had credit quality less than investment grade, based on ratings from externalinternal analysis. Six
Eight of these significant counterparties are municipal, or cooperative electric entities, RTOs or other utilities.
Financial Impact of Qualifying Cash Flow Hedges — The 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, is detailed in the following table:
|
| | | | | | | | | | | | |
| (Thousands of Dollars) | | 2017 | | 2016 | | 2015 |
| Accumulated other comprehensive loss related to cash flow hedges at Jan. 1 | | $ | (22,780 | ) | | $ | (23,836 | ) | | $ | (23,878 | ) |
| After-tax net unrealized losses related to derivatives accounted for as hedges | | — |
| | — |
| | (30 | ) |
| After-tax net realized losses on derivative transactions reclassified into earnings | | 1,005 |
| | 1,056 |
| | 72 |
|
| Accumulated other comprehensive loss related to cash flow hedges at Dec. 31 | | $ | (21,775 | ) | | $ | (22,780 | ) | | $ | (23,836 | ) |
The following tables detail the impact of derivative activity during the years ended Dec. 31, 2017, 2016 and 2015, on accumulated other comprehensive loss, regulatory assets and liabilities, and income:
|
| | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended Dec. 31, 2017 | |
| | | Pre-Tax Fair Value
Losses Recognized
During the Period in: | | Pre-Tax Losses
Reclassified into Income
During the Period from: | | | |
| (Thousands of Dollars) | | Accumulated
Other
Comprehensive Loss | | Regulatory
(Assets) and Liabilities | | Accumulated
Other
Comprehensive Loss | | Regulatory
Assets and (Liabilities) | | Pre-Tax Gains (Losses) Recognized
During the Period
in Income | |
| Derivatives designated as cash flow hedges | | | | | | | | | | | |
| Interest rate | | $ | — |
| | $ | — |
| | $ | 1,615 |
| (a) | $ | — |
| | $ | — |
| |
| Total | | $ | — |
| | $ | — |
| | $ | 1,615 |
| | $ | — |
| | $ | — |
| |
| Other derivative instruments | | | | | | | | | | | |
| Commodity trading | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 386 |
| (c) |
| Natural gas commodity | | — |
| | (10,921 | ) | | — |
| | 1,933 |
| (d) | (4,170 | ) | (d) |
| Total | | $ | — |
| | $ | (10,921 | ) | | $ | — |
| | $ | 1,933 |
| | $ | (3,784 | ) | |
|
| | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended Dec. 31, 2016 | |
| | | Pre-Tax Fair Value
Gains Recognized
During the Period in: | | Pre-Tax Losses
Reclassified into Income
During the Period from: | | | |
| (Thousands of Dollars) | | Accumulated Other Comprehensive Loss | | Regulatory (Assets) and Liabilities | | Accumulated Other Comprehensive Loss | | Regulatory Assets and (Liabilities) | | Pre-Tax Losses
Recognized
During the Period
in Income | |
| Derivatives designated as cash flow hedges | | | | | | | | | | | |
| Interest rate | | $ | — |
| | $ | — |
| | $ | 1,618 |
| (a) | $ | — |
| | $ | — |
| |
| Vehicle fuel and other commodity | | — |
| | — |
| | 86 |
| (b) | — |
| | — |
| |
| Total | | $ | — |
| | $ | — |
| | $ | 1,704 |
| | $ | — |
| | $ | — |
| |
| Other derivative instruments | | | | | | | | | | | |
| Commodity trading | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | (257 | ) | (c) |
| Natural gas commodity | | — |
| | 2,051 |
| | — |
| | 10,292 |
| (d) | (5,832 | ) | (d) |
| Total | | $ | — |
| | $ | 2,051 |
| | $ | — |
| | $ | 10,292 |
| | $ | (6,089 | ) | |
|
| | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended Dec. 31, 2015 | |
| | | Pre-Tax Fair Value
Losses Recognized
During the Period in: | | Pre-Tax Losses
Reclassified into Income
During the Period from: | | | |
| (Thousands of Dollars) | | Accumulated
Other
Comprehensive Loss | | Regulatory
(Assets) and Liabilities | | Accumulated
Other
Comprehensive Loss | | Regulatory
Assets and (Liabilities) | | Pre-Tax Gains (Losses) Recognized
During the Period
in Income | |
| Derivatives designated as cash flow hedges | | | | | | | | | | | |
| Interest rate | | $ | — |
| | $ | — |
| | $ | 54 |
| (a) | $ | — |
| | $ | — |
| |
| Vehicle fuel and other commodity | | (50 | ) | | — |
| | 57 |
| (b) | — |
| | — |
| |
| Total | | $ | (50 | ) | | $ | — |
| | $ | 111 |
| | $ | — |
| | $ | — |
| |
| Other derivative instruments | | | | | | | | | | | |
| Commodity trading | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 364 |
| (c) |
| Natural gas commodity | | — |
| | (10,635 | ) | | — |
| | 10,158 |
| (d) | (7,620 | ) | (d) |
| Total | | $ | — |
| | $ | (10,635 | ) | | $ | — |
| | $ | 10,158 |
| | $ | (7,256 | ) | |
| |
(a)
| Amounts are recorded to interest charges. |
| |
(b)
| Amounts are recorded to O&M expenses. |
| |
(c)
| Amounts are 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. |
| |
(d)
| Certain derivatives are utilized to mitigate natural gas price risk for electric generation and are recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset as appropriate. Amounts for the year ended Dec. 31, 2017 included $0.4 million of settlement gains and amounts for the years ended Dec. 31, 2016 and 2015 included $0.2 million and $1.1 million, respectively, 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, as appropriate. The remaining settlement losses for the years ended Dec. 31, 2017, 2016 and 2015 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, as appropriate. |
PSCo had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2017, 2016 and 2015. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.
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 or for cross-default contractualagencies. As of Dec. 31, 2023 and 2022, there were no derivative liabilities position with such underlying contract provisions.
Also, certain contracts may contain cross default provisions that could result inmay require the posting of collateral or settlement of suchthe contracts if there was a failure under other financing arrangements related to payment terms or other covenants. AtAs of Dec. 31, 2017 and 2016,2023 there were noapproximately $8 million of derivative instruments in a material liability position with such underlying contract provisions.
As of Dec. 31, 2022, there were no derivative liabilities in a liability 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 no collateral posted related to adequate assurance clauses in derivative contracts as of Dec. 31, 20172023 and 2016.2022.
Recurring Derivative Fair Value Measurements—The following table presents, for each
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, 2023 | | | | |
| Other derivative instruments | | | | |
| Natural gas commodity | | $ | — | | | $ | (13) | |
| Total | | $ | — | | | $ | (13) | |
| | | | |
| 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) | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | Pre-Tax (Gains) Losses Reclassified into Income During the Period from: | | Pre-Tax Gains (Losses) Recognized During the Period in Income | |
| (Millions of Dollars) | | Accumulated Other Comprehensive Loss | | Regulatory Assets and (Liabilities) | | |
| Year Ended Dec. 31, 2023 | | | | | |
| Derivatives designated as cash flow hedges | | | |
| Interest rate | | $ | 1 | | (a) | $ | — | | | $ | — | | |
| Total | | $ | 1 | | | $ | — | | | $ | — | | |
| Other derivative instruments | | | |
| Commodity trading | | $ | — | | | $ | — | | | $ | (5) | | (b) |
| Natural gas commodity | | — | | | 15 | | (c) | (16) | | (c)(d) |
| Total | | $ | — | | | $ | 15 | | | $ | (21) | | |
| 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) | | |
(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 hierarchy levels, PSCo’s derivativehedges during the years ended Dec. 31, 2023, 2022 and 2021.
Derivative assets and liabilities measured at fair value on a recurring basis atwere as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Dec. 31, 2023 | | Dec. 31, 2022 |
| | Fair Value | | Fair Value Total | | Netting (a) | | Total | | Fair Value | | Fair Value Total | | Netting (a) | | Total |
| (Millions of Dollars) | | Level 1 | | Level 2 | | Level 3 | | | | | Level 1 | | Level 2 | | Level 3 | | | |
| Current derivative assets | | | | | | | | | | | | | | | | | | | | | | | | |
| Other derivative instruments: | | | | | | | | | | | | | | | | | | | | | | | | |
| Commodity trading | | $ | 1 | | | $ | 19 | | | $ | — | | | $ | 20 | | | $ | (17) | | | $ | 3 | | | $ | 16 | | | $ | 220 | | | $ | 1 | | | $ | 237 | | | $ | (184) | | | $ | 53 | |
| Natural gas commodity | | — | | | 8 | | | — | | | 8 | | | — | | | 8 | | | — | | | 12 | | | — | | | 12 | | | — | | | 12 | |
| Total current derivative assets | | $ | 1 | | | $ | 27 | | | $ | — | | | $ | 28 | | | $ | (17) | | | $ | 11 | | | $ | 16 | | | $ | 232 | | | $ | 1 | | | $ | 249 | | | $ | (184) | | | $ | 65 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| Noncurrent derivative assets | | | | | | | | | | | | | | | | | | | | | | | | |
| Other derivative instruments: | | | | | | | | | | | | | | | | | | | | | | | | |
| Commodity trading | | $ | 6 | | | $ | 9 | | | $ | — | | | $ | 15 | | | $ | — | | | $ | 15 | | | $ | 12 | | | $ | 32 | | | $ | 9 | | | $ | 53 | | | $ | (31) | | | $ | 22 | |
| Total noncurrent derivative assets | | $ | 6 | | | $ | 9 | | | $ | — | | | $ | 15 | | | $ | — | | | $ | 15 | | | $ | 12 | | | $ | 32 | | | $ | 9 | | | $ | 53 | | | $ | (31) | | | $ | 22 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| Current derivative liabilities | | | | | | | | | | | | | | | | | | | | | | | | |
| Other derivative instruments: | | | | | | | | | | | | | | | | | | | | | | | | |
| Commodity trading | | $ | 1 | | | $ | 25 | | | $ | — | | | $ | 26 | | | $ | (17) | | | $ | 9 | | | $ | 5 | | | $ | 237 | | | $ | 1 | | | $ | 243 | | | $ | (223) | | | $ | 20 | |
| Natural gas commodity | | — | | | 8 | | | — | | | 8 | | | — | | | 8 | | | — | | | 10 | | | — | | | 10 | | | — | | | 10 | |
| Total current derivative liabilities | | $ | 1 | | | $ | 33 | | | $ | — | | | $ | 34 | | | $ | (17) | | | $ | 17 | | | $ | 5 | | | $ | 247 | | | $ | 1 | | | $ | 253 | | | $ | (223) | | | $ | 30 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| Noncurrent derivative liabilities | | | | | | | | | | | | | | | | | | | | | | | | |
| Other derivative instruments: | | | | | | | | | | | | | | | | | | | | | | | | |
| Commodity trading | | $ | 2 | | | $ | 1 | | | $ | — | | | $ | 3 | | | $ | (3) | | | $ | — | | | $ | 7 | | | $ | 40 | | | $ | — | | | $ | 47 | | | $ | (38) | | | $ | 9 | |
| Total noncurrent derivative liabilities | | $ | 2 | | | $ | 1 | | | $ | — | | | $ | 3 | | | $ | (3) | | | $ | — | | | $ | 7 | | | $ | 40 | | | $ | — | | | $ | 47 | | | $ | (38) | | | $ | 9 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | |
(a)PSCo nets derivative instruments and related collateral on its consolidated balance sheets when supported by a legally enforceable master netting agreement. At Dec. 31, 2017:
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Dec. 31, 2017 |
| | | Fair Value | | | | | | |
| (Thousands of Dollars) | | Level 1 | | Level 2 | | Level 3 | | Fair Value Total | | Counterparty Netting (b) | | Total |
| Current derivative assets | | | | | | | | | | | | |
| Other derivative instruments: | | | | | | | | | | | | |
| Commodity trading | | $ | 528 |
| | $ | 4,488 |
| | $ | 12 |
| | $ | 5,028 |
| | $ | (3,554 | ) | | $ | 1,474 |
|
| Natural gas commodity | | — |
| | 18 |
| | — |
| | 18 |
| | (10 | ) | | 8 |
|
| Total current derivative assets | | $ | 528 |
| | $ | 4,506 |
| | $ | 12 |
| | $ | 5,046 |
| | $ | (3,564 | ) | | 1,482 |
|
PPAs (a) | | | | | | | | | | | | 1,715 |
|
| Current derivative instruments | | | | | | | | | | | | $ | 3,197 |
|
| Noncurrent derivative assets | | | | | | | | | | | | |
| Other derivative instruments: | | | | | | | | | | | | |
| Commodity trading | | $ | — |
| | $ | 1,541 |
| | $ | — |
| | $ | 1,541 |
| | $ | (563 | ) | | $ | 978 |
|
| Total noncurrent derivative assets | | $ | — |
| | $ | 1,541 |
| | $ | — |
| | $ | 1,541 |
| | $ | (563 | ) | | 978 |
|
PPAs (a) | | | | | | | | | | | | 31 |
|
| Noncurrent derivative instruments | | | | | | | | | | | | $ | 1,009 |
|
| Current derivative liabilities | | | | | | | | | | | | |
| Other derivative instruments: | | | | | | | | | | | | |
| Commodity trading | | $ | 446 |
| | $ | 4,285 |
| | $ | 6 |
| | $ | 4,737 |
| | $ | (3,431 | ) | | $ | 1,306 |
|
| Natural gas commodity | | — |
| | 1,016 |
| | — |
| | 1,016 |
| | (10 | ) | | 1,006 |
|
| Total current derivative liabilities | | $ | 446 |
| | $ | 5,301 |
| | $ | 6 |
| | $ | 5,753 |
| | $ | (3,441 | ) | | 2,312 |
|
PPAs (a) | | | | | | | | | | | | 5,036 |
|
| Current derivative instruments | | | | | | | | | | | | $ | 7,348 |
|
| Noncurrent derivative liabilities | | | | | | | | | | | | |
| Other derivative instruments: | | | | | | | | | | | | |
| Commodity trading | | $ | — |
| | $ | 1,362 |
| | $ | — |
| | $ | 1,362 |
| | $ | (563 | ) | | $ | 799 |
|
| Total noncurrent derivative liabilities | | $ | — |
| | $ | 1,362 |
| | $ | — |
| | $ | 1,362 |
| | $ | (563 | ) | | 799 |
|
PPAs (a) | | | | | | | | | | | | $ | 2,669 |
|
| Noncurrent derivative instruments | | | | | | | | | | | | $ | 3,468 |
|
| |
(a)
| During 2006, PSCo qualified these contracts under the normal purchase exception. Based onthis qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.
|
| |
(b)
| PSCo nets derivative instruments and related collateral in its consolidated balance sheet 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, 2017. At Dec. 31, 2017, derivative assets and liabilities include no obligations to return or reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. |
The following table presents, for each of the fair value hierarchy levels, PSCo’s2023 and 2022, derivative assets and liabilities measured at fair value on a recurring basis atinclude no obligations to return cash collateral. At Dec. 31, 2016:2023 and 2022, derivative assets and liabilities include rights to reclaim cash collateral of $4 million and $46 million, respectively. Counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Dec. 31, 2016 |
| | | Fair Value | | | | | | |
| (Thousands of Dollars) | | Level 1 | | Level 2 | | Level 3 | | Fair Value Total | | Counterparty Netting (b) | | Total |
| Current derivative assets | | | | | | | | | | | | |
| Other derivative instruments: | | | | | | | | | | | | |
| Commodity trading | | $ | 1,124 |
| | $ | 5,453 |
| | $ | — |
| | $ | 6,577 |
| | $ | (5,137 | ) | | $ | 1,440 |
|
| Natural gas commodity | | — |
| | 7,778 |
| | — |
| | 7,778 |
| | — |
| | 7,778 |
|
| Total current derivative assets | | $ | 1,124 |
| | $ | 13,231 |
| | $ | — |
| | $ | 14,355 |
| | $ | (5,137 | ) | | 9,218 |
|
PPAs (a) | | | | | | | | | | | | 1,716 |
|
| Current derivative instruments | | | | | | | | | | | | $ | 10,934 |
|
| Noncurrent derivative assets | | | | | | | | | | | �� | |
| Other derivative instruments: | | | | | | | | | | | | |
| Commodity trading | | $ | — |
| | $ | 1,652 |
| | $ | — |
| | $ | 1,652 |
| | $ | — |
| | $ | 1,652 |
|
| Total noncurrent derivative assets | | $ | — |
| | $ | 1,652 |
| | $ | — |
| | $ | 1,652 |
| | $ | — |
| | 1,652 |
|
PPAs (a) | | | | | | | | | | | | 1,746 |
|
| Noncurrent derivative instruments | | | | | | | | | | | | $ | 3,398 |
|
| Current derivative liabilities | | | | | | | | | | | | |
| Other derivative instruments: | | | | | | | | | | | | |
| Commodity trading | | $ | 1,386 |
| | $ | 5,357 |
| | $ | 22 |
| | $ | 6,765 |
| | $ | (5,137 | ) | | $ | 1,628 |
|
| Total current derivative liabilities | | $ | 1,386 |
| | $ | 5,357 |
| | $ | 22 |
| | $ | 6,765 |
| | $ | (5,137 | ) | | 1,628 |
|
PPAs (a) | | | | | | | | | | | | 5,160 |
|
| Current derivative instruments | | | | | | | | | | | | $ | 6,788 |
|
| Noncurrent derivative liabilities | | | | | | | | | | | | |
PPAs (a) | | | | | | | | | | | | $ | 7,828 |
|
| Noncurrent derivative instruments | | | | | | | | | | | | $ | 7,828 |
|
39
| |
(a)
| During 2006, PSCo qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. |
| |
(b)
| PSCo nets derivative instruments and related collateral in its consolidated balance sheet 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, 2016. At Dec. 31, 2016, derivative assets and liabilities include no obligations to return cash collateral of or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.
|
There were immaterial gains recognized in earnings for the year ended Dec. 31, 2017 and immaterial losses recognized in earnings for the year ended Dec. 31, 2016 for level 3 commodity trading derivatives. There were no changesChanges in Level 3 recurring fair value measurementscommodity derivatives:
| | | | | | | | | | | | | | | | | | | | |
| | Year Ended Dec. 31 |
| (Millions of Dollars) | | 2023 | | 2022 | | 2021 |
| Balance at Jan. 1 | | $ | 9 | | | $ | (63) | | | $ | (44) | |
| | | | | | |
Settlements (a) | | — | | | 12 | | | 4 | |
| Net transactions recorded during the period: | | | | | | |
(Losses) gains recognized in earnings (a) | | (9) | | | 60 | | | (23) | |
| | | | | | |
| Balance at Dec. 31 | | $ | — | | | $ | 9 | | | $ | (63) | |
(a)Relates to commodity trading and is subject to substantial offsetting losses and gains on derivative instruments categorized as levels 1 and 2 in the income statement. See above tables for the year ended Dec. 31, 2015.
PSCo recognizes transfers between levels asincome statement impact of the beginning of each period. There were no transfers of amounts between levels for derivative instruments for the years ended Dec. 31, 2017, 2016activity, including commodity trading gains and 2015.losses.
Fair Value of Long-Term Debt
As of Dec. 31, 2017 and 2016, other financial instruments for which the carrying amount did not equal fair value were as follows:value:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2023 | | 2022 |
| (Millions of Dollars) | | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value |
| Long-term debt, including current portion | | $ | 7,450 | | | $ | 6,580 | | | $ | 6,860 | | | $ | 5,881 | |
|
| | | | | | | | | | | | | | | | |
| | | 2017 | | 2016 |
| (Thousands of Dollars) | | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value |
| Long-term debt, including current portion | | $ | 4,608,275 |
| | $ | 5,024,840 |
| | $ | 4,216,206 |
| | $ | 4,491,570 |
|
The fairFair value of PSCo’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. The fairFair value estimates are based on information available to management as of Dec. 31, 20172023 and 2016,2022, and given the observability of the inputs, to these estimates, the fair values presented for long-term debt have beenwere assigned aas Level 2.
| | |
11. | Rate Matters9. Benefit Plans and Other Postretirement Benefits |
Tax Reform — Regulatory ProceedingsPension and Postretirement Health Care Benefits
The specific impacts ofXcel 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 TCJA on retail customer rates are subject to regulatory approval. PSCo is in the process of quantifying the rate impacts of the TCJA and are being addressed in several regulatory proceedings focused on retail base rate impacts,Cash Balance formula, which include the following:
Colorado Statewide TCJA Proceeding— On Jan. 31, 2018, the CPUC opened a statewide TCJA proceeding and ordered deferred accounting for all investor-owned utilities. On Feb. 21, 2017, PSCo filed a response with the CPUC related to the deferred accounting order and statewide TCJA proceeding, addressing the estimated impacts along with other considerations given PSCo’s pending natural gas and electric rate cases.
Colorado 2017 Multi-Year Natural Gas Rate Case— On Feb. 14, 2018, the ALJ approved PSCo and CPUC Staff’s non-unanimous settlement agreement which addresses the impacts of the TCJA in 2018. This settlement agreement includes a $20 million reduction to provisional rates effective March 1, 2018, with future true-ups to be determined later in 2018 once a full analysis of the comprehensive impacts of tax reform is performed, including any outcomes associated with statewide proceeding. The final true-up would provide customers the full net benefit of the TCJA effective Jan. 1, 2018.
Colorado 2017 Multi-Year Electric Rate Case— On Feb. 16, 2018, the CPUC denied the proposed settlement agreement between PSCo and several intervenors, in favor of the state TCJA proceeding. In the second quarter of 2018, PSCo plans to file a revised rate request that will include the impacts of the TCJA. Provisional rates, subject to refund with interest, are expected to be effective June 1, 2018. The appropriate test year and the final approved revenue requirement will be determined in the pending rate case, discussed below. PSCo expects to defer the TCJA net benefits for the first five months of 2018, prior to provisional rates.
The CPUC is expected to rule on the regulatory treatment of the TCJA, the natural gas rate case and the electric rate case later in 2018.
Pending Regulatory Proceedings — CPUC
Colorado 2017 Multi-Year Electric Rate Case — In October 2017, PSCo filed a multi-year request with the CPUC seeking to increase electric rates approximately $245 million over four years. The request, summarized below, is based on FTY endingpay credits using a percentage of annual eligible pay and annual interest credits.
The average annual interest crediting rates for these plans was 5.03, 5.14 and 2.26 percent in 2023, 2022, and 2021, 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, a 10.0 percent ROE2023 and an equity ratio2022 were $12 million and $11 million, respectively, of 55.25 percent.
|
| | | | | | | | | | | | | | | | | | | | |
| Revenue Request (Millions of Dollars) | | 2018 | | 2019 | | 2020 | | 2021 | | Total |
| Revenue request | | $ | 74 |
| | $ | 75 |
| | $ | 60 |
| | $ | 36 |
| | $ | 245 |
|
CACJA revenue conversion to base rates (a) | | 90 |
| | — |
| | — |
| | — |
| | 90 |
|
TCA revenue conversion to base rates (a) | | 43 |
| | — |
| | — |
| | — |
| | 43 |
|
Total (b) | | $ | 207 |
| | $ | 75 |
| | $ | 60 |
| | $ | 36 |
| | $ | 378 |
|
| | | | | | | | | | | |
Expected year-end rate base (billions of dollars) (b) | | $ | 6.8 |
| | $ | 7.1 |
| | $ | 7.3 |
| | $ | 7.4 |
| | |
| |
(a)
| The roll-in of the TCA and CACJA rider revenues into base rates will not have an impact on customer bills or revenue as these costs are already being recovered through a rider. Transmission investments for 2019-2021 will be recovered through the TCA rider. |
| |
(b)
| This base rate request does not include the impacts of the RESA and ECA for the Rush Creek wind investments or the proposed CEP. |
Key dateswhich $2 million and $1 million was attributable to PSCo in the procedural schedule are as follows:
Supplemental direct testimony — April 16, 2018;
Answer testimony — May 31, 2018;
Rebuttal2023 and cross-answer testimony — July 10, 2018;
Hearings — Aug. 21 - 31, 2018; and
Statement of position — Sept. 28, 2018.
Interim rates, subject to refund and interest, are to be effective on June 1, 2018. PSCo also proposed a stay-out provision and earnings test through 2021. On Jan. 31, 2018, the CPUC ordered deferred accounting2022, respectively. Xcel Energy recognized net benefit cost for financial reporting for the impactsSERP and nonqualified plans of TCJA$2 million in 2023 and opened$17 million in 2022, respectively, of which immaterial amounts were attributable to PSCo.
Xcel Energy’s postretirement health care benefit plan is a statewide TCJA proceeding, as discussed above. In the second quartercontinuation of 2018, PSCo plans to filecertain welfare benefit programs for current employees. A full time employee’s date of hire or a revised rate request that will include the impactsretiree’s date of retirement determine eligibility for each of the TCJA. The CPUC isprograms.
Xcel Energy’s investment-return assumption considers the expected to rule on the regulatory treatmentlong-term performance for each of the TCJAasset classes in its pension and postretirement health care portfolio. Xcel Energy considers the electric rate case laterhistorical returns achieved by its asset portfolios over long time periods, as well as the long-term projected return levels from 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 2018.2023 were above the assumed level of 6.53%.
•Investment returns in 2022 were below the assumed level of 6.39%.
Colorado 2017 Multi-Year Natural Gas Rate Case — •Investment returns in 2021 were above the assumed level of 6.38%.
•In June 2017, PSCo filed2024, PSCo’s expected investment-return assumption is 6.53%.
Pension plan and postretirement benefit assets are invested in a multi-year requestportfolio 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. These assets are invested in a manner consistent with the CPUC seeking to increase retail natural gas rates approximately $139 million over three years. The request, detailed below,investment strategy for the pension plan.
Xcel Energy’s ongoing investment strategy is based on FTYs,plan-specific investment recommendations that seek to minimize potential investment and interest rate risk as a 10.0 percent ROEplan’s funded status increases over time.
The investment recommendations consider many factors and an equity ratio of 55.25 percent.
|
| | | | | | | | | | | | | | | | |
| Revenue Request (Millions of Dollars) | | 2018 | | 2019 | | 2020 | | Total |
| Revenue request | | $ | 63 |
| | $ | 33 |
| | $ | 43 |
| | $ | 139 |
|
PSIA revenue conversion to base rates (a) | | — |
| | 94 |
| | — |
| | 94 |
|
| Total | | $ | 63 |
| | $ | 127 |
| | $ | 43 |
| | $ | 233 |
|
| | | | | | | | | |
Expected year-end rate base (billions of dollars) (b) | | $ | 1.5 |
| | $ | 2.3 |
| | $ | 2.4 |
| | |
| |
(a)
| The roll-in of PSIA rider revenue into base rates will not have an impact on customer bills or revenue as these costs are already being recovered through the rider. The recovery of incremental PSIA related investments in 2019 and 2020 are included in the base rate request. |
| |
(b)
| The additional rate base in 2019 predominantly reflects the roll-in of capital associated with the PSIA rider. |
In October 2017, several parties filed answer testimony. The CPUC Staff (Staff) and the OCC, recommended a single 2016 HTY, based on an average 13-month rate base, and opposed a multi-year request. The Staff and OCC recommended an equity capital structure of 48.73 percent and 51.2 percent, respectively. Both the Staff and the OCC recommended the existing PSIA rider expire with the 2018 rates rolled into base rates beginning Jan. 1, 2019. Planned investments in 2019 and 2020 would be recoverable through base rates, subject to a future rate case. The final positions of the Staff and OCC provide for a recommended 2018 rate increase of approximately $30 million and $39 million, respectively.
In December 2017, hearings before an ALJ were held and the evidentiary record for the case was closed. Provisional rates, subject to refund, were implemented on Jan. 1, 2018. As discussed above, PSCo and the CPUC Staff filed a non-unanimous settlement agreement to address the impacts of the TCJA on rates to be effective in 2018, which was approved by the ALJ. On Jan. 31, 2018, the CPUC ordered deferred accounting for the impacts of TCJA and opened a statewide TCJA proceeding, as discussed above. The CPUC is expected to rule on the regulatory treatment of the TCJA and the natural gas rate case later in 2018.
Annual Electric Earnings Test — PSCo must share with customers earnings that exceed the authorized ROE of 9.83 percent for 2015 through 2017, as part of an annual earnings test. PSCo estimates the 2017 earnings test will notgenerally result in a customer refundgreater 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, 2023 (a) | | Dec. 31, 2022 (a) |
| (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 | | $ | 94 | | | $ | — | | | $ | — | | | $ | — | | | $ | 94 | | | $ | 52 | | | $ | — | | | $ | — | | | $ | — | | | $ | 52 | |
| Commingled funds | | 177 | | | — | | | — | | | 464 | | | 641 | | | 355 | | | — | | | — | | | 317 | | | 672 | |
| Debt securities | | — | | | 287 | | | 1 | | | — | | | 288 | | | — | | | 286 | | | 1 | | | — | | | 287 | |
| Equity securities | | 12 | | | — | | | — | | | — | | | 12 | | | 17 | | | — | | | — | | | — | | | 17 | |
| Other | | — | | | 2 | | | — | | | — | | | 2 | | | — | | | 3 | | | — | | | — | | | 3 | |
| Total | | $ | 283 | | | $ | 289 | | | $ | 1 | | | $ | 464 | | | $ | 1,037 | | | $ | 424 | | | $ | 289 | | | $ | 1 | | | $ | 317 | | | $ | 1,031 | |
(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, 2023 (a) | | Dec. 31, 2022 (a) |
| (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 | | $ | 29 | | | $ | — | | | $ | — | | | $ | — | | | $ | 29 | | | $ | 28 | | | $ | — | | | $ | — | | | $ | — | | | $ | 28 | |
| Insurance contracts | | — | | | 35 | | | — | | | — | | | 35 | | | — | | | 36 | | | — | | | — | | | 36 | |
| Commingled funds | | 20 | | | — | | | — | | | 63 | | | 83 | | | 47 | | | — | | | — | | | 56 | | | 103 | |
| Debt securities | | — | | | 165 | | | 1 | | | — | | | 166 | | | — | | | 153 | | | 1 | | | — | | | 154 | |
| Other | | — | | | 1 | | | — | | | — | | | 1 | | | — | | | (1) | | | — | | | — | | | (1) | |
| Total | | $ | 49 | | | $ | 201 | | | $ | 1 | | | $ | 63 | | | $ | 314 | | | $ | 75 | | | $ | 188 | | | $ | 1 | | | $ | 56 | | | $ | 320 | |
(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 2023 and 2022.
Funded Status — 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 |
| (Millions of Dollars) | | 2023 | | 2022 | | 2023 | | 2022 |
| Change in Benefit Obligation: | | | | | | | | |
| Obligation at Jan. 1 | | $ | 1,032 | | | $ | 1,363 | | | $ | 296 | | | $ | 369 | |
| Service cost | | 19 | | | 29 | | | 1 | | | 1 | |
| Interest cost | | 58 | | | 41 | | | 16 | | | 10 | |
| | | | | | | | |
| Actuarial (gain) loss | | 45 | | | (317) | | | 18 | | | (55) | |
| Plan participants’ contributions | | — | | | — | | | 7 | | | 7 | |
| Medicare subsidy reimbursements | | — | | | — | | | — | | | 1 | |
| Benefit payments | | (83) | | | (84) | | | (42) | | | (37) | |
| Obligation at Dec. 31 | | $ | 1,071 | | | $ | 1,032 | | | $ | 296 | | | $ | 296 | |
| Change in Fair Value of Plan Assets: | | | | | | | | |
| Fair value of plan assets at Jan. 1 | | $ | 1,031 | | | $ | 1,351 | | | $ | 320 | | | $ | 393 | |
| Actual return on plan assets | | 89 | | | (276) | | | 26 | | | (46) | |
| Employer contributions | | — | | | 40 | | | 3 | | | 3 | |
| Plan participants’ contributions | | — | | | — | | | 7 | | | 7 | |
| Benefit payments | | (83) | | | (84) | | | (42) | | | (37) | |
| Fair value of plan assets at Dec. 31 | | $ | 1,037 | | | $ | 1,031 | | | $ | 314 | | | $ | 320 | |
| Funded status of plans at Dec. 31 | | $ | (34) | | | $ | (1) | | | $ | 18 | | | $ | 24 | |
| Amounts recognized in the Consolidated Balance Sheet at Dec. 31: | | | | | | | | |
| Noncurrent assets | | — | | | 8 | | | 18 | | | 24 | |
| Noncurrent liabilities | | (34) | | | (9) | | | — | | | — | |
| Net amounts recognized | | $ | (34) | | | $ | (1) | | | $ | 18 | | | $ | 24 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | Postretirement Benefits |
| Significant Assumptions Used to Measure Benefit Obligations: | | 2023 | | 2022 | | 2023 | | 2022 |
| Discount rate for year-end valuation | | 5.49 | % | | 5.80 | % | | 5.54 | % | | 5.80 | % |
| Expected average long-term increase in compensation level | | 4.25 | % | | 4.25 | % | | 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 | % | | 6.50 | % |
| Health care costs trend rate — initial: Post-65 | | N/A | | N/A | | 5.50 | % | | 5.50 | % |
| 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 | | 6 | | 7 |
Accumulated benefit obligation for the pension plan was $1,010 million and $992 million as of Dec. 31, 2023 and 2022, respectively.
Net Periodic Benefit Cost (Credit) —Net periodic benefit cost (credit), other than the service cost component, is included in other income (expense) 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 |
| (Millions of Dollars) | | 2023 | | 2022 | | 2021 | | 2023 | | 2022 | | 2021 |
| Service cost | | $ | 19 | | | $ | 29 | | | $ | 32 | | | $ | 1 | | | $ | 1 | | | $ | 1 | |
| Interest cost | | 58 | | | 41 | | | 39 | | | 16 | | | 10 | | | 11 | |
| Expected return on plan assets | | (76) | | | (78) | | | (73) | | | (15) | | | (15) | | | (16) | |
| Amortization of prior service credit | | — | | | — | | | — | | | — | | | (2) | | | (4) | |
| Amortization of net loss | | 1 | | | 23 | | | 32 | | | 1 | | | 1 | | | 3 | |
Settlement charge (a) | | — | | | 3 | | | — | | | — | | | — | | | — | |
| Net periodic pension cost (credit) | | 2 | | | 18 | | | 30 | | | 3 | | | (5) | | | (5) | |
| Effects of regulation | | 9 | | | 4 | | | — | | | — | | | 3 | | | 2 | |
| Net benefit cost (credit) recognized for financial reporting | | $ | 11 | | | $ | 22 | | | $ | 30 | | | $ | 3 | | | $ | (2) | | | $ | (3) | |
| Significant Assumptions Used to Measure Costs: | | | | | | | | | | | | |
| Discount rate | | 5.80 | % | | 3.08 | % | | 2.71 | % | | 5.80 | % | | 3.09 | % | | 2.65 | % |
| Expected average long-term increase in compensation level | | 4.25 | | | 3.75 | | | 3.75 | | | N/A | | N/A | | N/A |
| Expected average long-term rate of return on assets | | 6.53 | | | 6.39 | | | 6.38 | | | 5.00 | | | 4.10 | | | 4.10 | |
(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 2022, as a result of lump-sum distributions during the plan year, PSCo recorded a total pension settlement charge of $3 million. An immaterial amount was recorded in the income statement in 2022. There were no settlement charges recorded to the qualified pension plans in 2023 or 2021.
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| | Pension Benefits | | Postretirement Benefits |
| (Millions of Dollars) | | 2023 | | 2022 | | 2023 | | 2022 |
| Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: | | | | | | | | |
| Net loss | | $ | 355 | | | $ | 325 | | | $ | 59 | | | $ | 53 | |
| Prior service credit | | (1) | | | (1) | | | — | | | — | |
| Total | | $ | 354 | | | $ | 324 | | | $ | 59 | | | $ | 53 | |
| 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 | | $ | 3 | | | $ | 3 | | | $ | 1 | | | $ | — | |
| Noncurrent regulatory assets | | 351 | | | 320 | | | 58 | | | 53 | |
| | | | | | | | |
| Net-of-tax accumulated other comprehensive income | | | | 1 | | | | | — | |
| Total | | $ | 354 | | | $ | 324 | | | $ | 59 | | | $ | 53 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Measurement date | | Dec. 31, 2023 | | Dec. 31, 2022 | | Dec. 31, 2023 | | Dec. 31, 2022 |
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 2021 - 2024 to meet minimum funding requirements. Total voluntary and required pension funding contributions across all four of Xcel Energy’s pension plans were as follows:
•$100 million in January 2024, of which $7 million was attributable to PSCo.
•$50 million in 2023, of which zero was attributable to PSCo.
•$50 million in 2022, of which $40 million was attributable to PSCo.
•$131 million in 2021, of which $46 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:
•$11 million expected in 2024, of which $2 million is attributable to PSCo.
•$11 million during 2023, of which $3 million was attributable to PSCo.
•$13 million during 2022, of which $3 million was attributable to PSCo.
•$15 million during 2021, of which $3 million was attributable to PSCo.
Targeted asset allocations:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | Postretirement Benefits |
| | 2023 | | 2022 | | 2023 | | 2022 |
| Long-duration fixed income securities | | 38 | % | | 38 | % | | — | % | | — | % |
| Domestic and international equity securities | | 31 | | | 33 | | | 9 | | | 16 | |
| Alternative investments | | 20 | | | 18 | | | 13 | | | 12 | |
| Short-to-intermediate fixed income securities | | 9 | | | 9 | | | 77 | | | 71 | |
| Cash | | 2 | | | 2 | | | 1 | | | 1 | |
| 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 2023, Xcel Energy amended the Xcel Energy Pension Plan and Xcel Energy Inc. Nonbargaining Pension Plan (South) to reduce supplemental social security benefits for all active participants on and after Jan. 1, 2024.
There was no significant plan amendments made in 2022 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) | | Projected
Pension Benefit
Payments | | Gross Projected
Postretirement
Health Care
Benefit Payments | | Expected
Medicare Part D
Subsidies | | Net Projected
Postretirement
Health Care
Benefit Payments |
| 2024 | | $ | 89 | | | $ | 31 | | | $ | 2 | | | $ | 29 | |
| 2025 | | 80 | | | 30 | | | 2 | | | 28 | |
| 2026 | | 80 | | | 29 | | | 2 | | | 27 | |
| 2027 | | 80 | | | 28 | | | 2 | | | 26 | |
| 2028 | | 79 | | | 27 | | | 2 | | | 25 | |
| 2029-2033 | | 384 | | | 123 | | | 12 | | | 111 | |
Voluntary Retirement Program
Incremental to amounts presented above for postretirement benefits, Xcel Energy, which includes PSCo, will file its 2017 earnings test withrecognized new postemployment costs and obligations in the CPUC in April 2018. The final sharing obligation, if any, will be based on the CPUC approved tariff and could vary from the current estimate.fourth quarter of 2023 for employees accepted to a voluntary retirement program.
Electric, Purchased Gas and Resource Adjustment Clauses
DSMUtilizing employee information and the DSMCA riders — Energy efficiencyfollowing inputs, the estimated PSCo obligations for the program of $2 million for health plan subsidies and DSM costs are recovered through a combination of the DSMCA riders and base rates. DSMCA riders are adjusted biannually to capture program costs, performance incentives, and any over- or under-recoveries are trued-upan immaterial amount for other medical benefits, each commencing in 2024, were recognized in the following year. Performance incentivesfourth quarter of 2023. These unfunded obligations are awardedpresented in other current liabilities and noncurrent pension and employee benefit obligations in the year following plan achievements. PSCo is able to earn $5 million upon reaching its annual savings goal along with an incentive on five percentconsolidated balance sheet as of net economic benefits up to a maximum annual incentive of $30 million. In 2017, PSCo earned an electric and natural gas DSM incentive of $11 million and $3 million, respectively, for achieving its 2016 electric and natural gas savings goals. For 2018, the electric energy savings goal is 400 GWh with a spending limit of $84 million.Dec. 31, 2023.
| | | | | | | | |
| Significant Assumptions to Measure Benefit Obligations: | | 2023 |
12.Discount rate for year-end valuation | | 5.50 | % |
| Mortality table | | PRI-2012 |
| Health care costs trend rate and ultimate trend assumption | | 7.00 | % |
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 $13 million in 2023, and $12 million in 2022 and 2021.
| | |
| 10. Commitments and Contingencies |
Commitments
Capital Commitments — PSCo has made commitments in connection with a portion of its projected capital expenditures. PSCo’s capital commitments primarily relate to the following major projects:
Advanced Grid Intelligence and Security Initiative — PSCo is pursuing projects to update and advance its electric distribution grid to increase reliability and security standards, meet customer expectations, offer additional customer choice and control over energy usage and implement new rate structures.
Rush Creek Wind Farm — PSCo has gained approval to build, own and operate a 600 MW wind generation facility and proposed transmission line in Colorado.
Gas Transmission Integrity Management Programs — PSCo is proactively identifying and addressing the safety and reliability of natural gas transmission pipelines. The pipeline integrity efforts include primarily pipeline assessment and maintenance projects.
Electric Distribution Integrity Management Programs — PSCo is assessing aging infrastructure for distribution assets and replacing worn components to increase system performance.
Fuel Contracts— PSCo has entered into various long-term commitments for the purchase and delivery of a significant portion of its current coal and natural gas requirements. These contracts expire in various years between 2018 and 2060. PSCo is required to pay additional amounts depending on actual quantities shipped under these agreements.
The estimated minimum purchases for PSCo under these contracts as of Dec. 31, 2017, are as follows:
|
| | | | | | | | | | | | |
| (Millions of Dollars) | | Coal | | Natural gas supply | | Natural gas
storage and
transportation |
| 2018 | | $ | 160 |
| | $ | 344 |
| | $ | 114 |
|
| 2019 | | 97 |
| | 286 |
| | 112 |
|
| 2020 | | 69 |
| | 275 |
| | 111 |
|
| 2021 | | 37 |
| | 278 |
| | 109 |
|
| 2022 | | 38 |
| | 126 |
| | 109 |
|
| Thereafter | | 184 |
| | 57 |
| | 605 |
|
| Total | | $ | 585 |
| | $ | 1,366 |
| | $ | 1,160 |
|
Additional expenditures for fuel and natural gas storage and transportation will be required to meet expected future electric generation and natural gas needs. PSCo’s risk of loss, in the form of increased costs from market price changes in fuel, is mitigated through the use of natural gas and energy cost-rate adjustment mechanisms, which provide for pass-through of most fuel, storage and transportation costs to customers.
PPAs— PSCo has entered into PPAs with other utilities and energy suppliers with expiration dates through 2034 for purchased power to meet system load and energy requirements and meet operating reserve obligations. In general, these agreements provide for energy payments, based on actual energy delivered and capacity payments. Certain PPAs accounted for as executory contracts also contain minimum energy purchase commitments. Capacity and energy payments are typically contingent on the independent power producing entity meeting contract obligations, including plant availability requirements. Contractual payments are adjusted based on market indices. The effects of price adjustments on our financial results are mitigated through purchased energy cost recovery mechanisms.
Included in electric fuel and purchased power expenses for PPAs, accounted for as executory contracts, were payments for capacity of $25 million, $44 million and $70 million in 2017, 2016 and 2015, respectively. At Dec. 31, 2017, the estimated future payments for capacity that PSCo is obligated to purchase pursuant to these executory contracts, subject to availability, are as follows:
|
| | | | |
| (Millions of Dollars) | | Capacity |
| 2018 | | $ | 22 |
|
| 2019 | | 12 |
|
| 2020 | | 4 |
|
| 2021 | | 4 |
|
| 2022 | | 4 |
|
| Thereafter | | 14 |
|
| Total | | $ | 60 |
|
Additional energy payments under these PPAs and PPAs accounted for as operating leases will be required to meet expected future electric demand.
Leases— PSCo leases a variety of equipment and facilities. Three of these leases are accounted for as capital leases. The assets and liabilities at the inception of a capital lease are recorded at the lower of fair market value or the present value of future lease payments and are amortized over the term of the contract.
WYCO is a joint venture between Xcel Energy Inc. and Colorado Interstate Gas Company, LLC (CIG) to develop and lease natural gas pipeline, storage, and compression facilities. Xcel Energy Inc. has a 50 percent ownership interest in WYCO, and PSCo has no direct ownership interest. WYCO generally leases its facilities to CIG, and CIG operates the facilities, providing natural gas storage services to PSCo under separate service agreements.
PSCo accounts for its Totem natural gas storage service arrangement with CIG as a capital lease. As a result, PSCo had $124 million and $127 million of capital lease obligations as of Dec. 31, 2017 and 2016, respectively.
PSCo records amortization for its capital leases as cost of natural gas sold and transported on the consolidated statements of income. Total amortization expenses under capital lease assets were approximately $5 million, $8 million, and $8 million for 2017, 2016 and 2015, respectively. Following is a summary of property held under capital leases:
|
| | | | | | | | |
| (Millions of Dollars) | | Dec. 31, 2017 | | Dec. 31, 2016 |
| Gas storage facilities | | $ | 200.5 |
| | $ | 200.5 |
|
| Gas pipeline | | 20.7 |
| | 20.7 |
|
| Property held under capital leases | | 221.2 |
| | 221.2 |
|
| Accumulated depreciation | | (70.6 | ) | | (65.3 | ) |
| Total property held under capital leases, net | | $ | 150.6 |
| | $ | 155.9 |
|
The remainder of the leases, primarily for office space, railcars, generating facilities, vehicles, aircraft and power-operated equipment, are accounted for as operating leases. Total expenses under operating lease obligations were approximately $109 million, $118 million and $130 million for 2017, 2016 and 2015, respectively. These expenses include capacity payments for PPAs accounted for as operating leases of $96 million, $102 million and $114 million in 2017, 2016 and 2015, respectively, recorded to electric fuel and purchased power expenses.
Included in the future commitments under operating leases are estimated future capacity payments under PPAs that have been accounted for as operating leases in accordance with the applicable accounting guidance. Future commitments under operating and capital leases are:
|
| | | | | | | | | | | | | | | | |
| (Millions of Dollars) | | Operating Leases | | PPA (a) (b) Operating Leases | | Total Operating Leases | | Capital Leases |
| 2018 | | $ | 10 |
| | $ | 96 |
| | $ | 106 |
| | $ | 25 |
|
| 2019 | | 10 |
| | 97 |
| | 107 |
| | 25 |
|
| 2020 | | 10 |
| | 98 |
| | 108 |
| | 25 |
|
| 2021 | | 9 |
| | 99 |
| | 108 |
| | 24 |
|
| 2022 | | 8 |
| | 87 |
| | 95 |
| | 21 |
|
| Thereafter | | 34 |
| | 394 |
| | 428 |
| | 442 |
|
| Total minimum obligation | | | | | | | | 562 |
|
| Interest component of obligation | | | | | | | | (411 | ) |
| Present value of minimum obligation | | | | | | | | $ | 151 |
|
| |
(a)
| Amounts do not include PPAs accounted for as executory contracts. |
| |
(b)
| PPA operating leases contractually expire through 2034. |
Variable Interest Entities— The accounting guidance for consolidation of variable interest entities requires enterprises to consider the activities that most significantly impact an entity’s financial performance, and power to direct those activities, when determining whether an enterprise is a variable interest entity’s primary beneficiary.
PPAs — Under certain PPAs, PSCo purchases power from independent power producing entities for which PSCo is required to reimburse natural gas fuel costs, or to participate in tolling arrangements under which PSCo procures the natural gas required to produce the energy that it purchases. These specific PPAs create a variable interest in the independent power producing entity.
PSCo has determined that certain independent power producing entities are variable interest entities. PSCo is not subject to risk of loss from the operations of these entities, and no significant financial support has been, or is required to be provided other than contractual payments for energy and capacity set forth in the PPAs.
PSCo has evaluated each of these variable interest entities 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 has 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 1,571 MW of capacity under long-term PPAs at both Dec. 31, 2017 and 2016 with entities that have been determined to be variable interest entities. These agreements have expiration dates through the year 2032.
Environmental Contingencies
PSCo has been or is currently involved with the cleanup of contamination from certain hazardous substances at several sites. In many situations, PSCo believes it will recover some portion of these costs through insurance claims. Additionally, where applicable, PSCo is pursuing, or intends to pursue, recovery from other PRPs and through the regulated rate process. New and changing federal and state environmental mandates can also create added financial liabilities for PSCo, which are normally recovered through the regulated rate process. To the extent any costs are not recovered through the options listed above, PSCo would be required to recognize an expense.
Site Remediation— Various federal and state environmental laws impose liability, without regard to the legality of the original conduct, 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 or other parties have caused environmental contamination. Environmental contingencies could arise from various situations, including sites of former MGPs operated by PSCo, its predecessors, or other entities; and third-party sites, such as landfills, for which PSCo is alleged to be a PRP that sent wastes to that site.
Other MGP, Landfill or Disposal Sites— PSCo is currently involved in investigating and/or remediating several MGP, landfill or other disposal sites. PSCo has identified three sites where contamination is present and where investigation and/or remediation activities are currently underway. Other parties may have responsibility for some portion of the investigation and/or remediation activities that are underway. PSCo anticipates that these investigation or remediation activities will continue through at least 2018. PSCo had accrued an immaterial amount and $2 million for all of these sites as of Dec. 31, 2017 and 2016, respectively. There may be insurance recovery and/or recovery from other PRPs that will offset any costs incurred. PSCo anticipates that any amounts spent will be fully recovered from customers.
Environmental Requirements
Water and Waste
Asbestos Removal — Some of PSCo’s facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that contain it are demolished or removed. PSCo has recorded an estimate for final removal of the asbestos as an ARO. It may be necessary to remove some asbestos to perform maintenance or make improvements to other equipment. The cost of removing asbestos as part of other work is not expected to be material and is recorded as incurred as operating expenses for maintenance projects, capital expenditures for construction projects or removal costs for demolition projects.
Coal Ash Regulation— PSCo’s operations are subject to federal and state laws that impose requirements for handling, storage, treatment and disposal of solid waste. In 2015, the EPA published a final rule regulating the management, storage, and disposal of coal combustion residuals (CCRs) as a nonhazardous waste (CCR Rule). Industry and environmental non-governmental organizations sought judicial review of the final CCR Rule, but a final decision has not been issued in that litigation. The EPA announced in late 2017 its intent to revise the CCR Rule. It is anticipated that the EPA will publish the revised rule in the first quarter of 2018.
Under the CCR Rule, utilities were required to complete groundwater sampling around their CCR landfills and surface impoundments and to analyze the results by early 2018 to determine if there were any statistically significant increases (SSIs) above background levels of certain constituents in the groundwater. PSCo has identified SSIs at several sites. Going forward, PSCo will either conduct additional groundwater sampling to determine whether another source besides plant operations is impacting groundwater and/or to determine if corrective action is needed. Several PSCo sites where SSIs were identified were already undergoing cessation of coal operations and closure of the on-site coal units and therefore no further corrective action is expected at those sites.
Until a final decision is reached in the litigation, the EPA publishes its revised rule, and PSCo completes additional groundwater sampling, it is uncertain what impact, if any, there will be on the operations, financial position or cash flows of PSCo. PSCo believes that any associated costs would be recoverable through regulatory mechanisms.
Federal CWA Waters of the United States Rule —In 2015, the EPA and the U.S. Army Corps of Engineers (Corps) published a final rule that significantly expanded the types of water bodies regulated under the CWA and broadened the scope of waters subject to federal jurisdiction. In October 2015, the U.S. Court of Appeals for the Sixth Circuit issued a nationwide stay of the final rule and subsequently ruled that it, rather than the federal district courts, had jurisdiction over challenges to the rule. In January 2017, the U.S. Supreme Court agreed to resolve the dispute as to which court should hear challenges to the rule. A ruling is expected in 2018.
In February 2017, President Trump issued an executive order requiring the EPA and the Corps to review and revise the final rule. On June 27, 2017, the agencies issued a proposed rule that rescinds the final rule and reinstates the prior definition of “Water of the U.S.” The agencies are also undertaking a rulemaking to develop a new definition of “Waters of the U.S.”
Federal CWA Effluent Limitations Guidelines (ELG) — In 2015, the EPA issued a final ELG rule for power plants that use coal, natural gas, oil or nuclear materials as fuel and discharge treated effluent to surface waters as well as utility-owned landfills that receive coal combustion residuals. In 2017, the EPA delayed the compliance date for flue gas desulfurization wastewater and bottom ash transport until November 2020 while the agency conducts a rulemaking process to potentially revise the effluent limitations and pretreatment standards for these waste streams.
Federal CWA Section 316(b) — The federal CWA requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available for minimizing adverse environmental impacts to aquatic species. The EPA published the final 316(b) rule in 2014. The rule prescribes technology for protecting fish that get stuck on plant intake screens (known as impingement) and describes a process for site-specific determinations by each state for sites that must protect the small aquatic organisms that pass through the intake screens into the plant cooling systems (known as entrainment). PSCo does not anticipate the cost of compliance will have a material impact on its results of operations, financial position or cash flows.
Air
GHG Emission Standard for Existing Sources (CPP) — In 2015, the EPA issued its final CPP rule for existing power plants. Among other things, the CPP requires that state plans include enforceable measures to ensure emissions from existing power plants achieve the EPA’s state-specific interim and final emission performance targets.
The CPP was challenged by multiple parties in the D.C. Circuit Court. In February 2016, the U.S. Supreme Court issued an order staying the final CPP rule. The stay will remain in effect until the D.C. Circuit Court reaches its decision and the U.S. Supreme Court either declines to review the lower court’s decision or reaches a decision of its own.
In March 2017, President Trump signed an executive order requiring the EPA Administrator to review the CPP rule and if appropriate publish proposed rules suspending, revising or rescinding it. Accordingly, the EPA requested that the D.C. Circuit Court hold the litigation in abeyance until the EPA completes its work under the executive order. The D.C. Circuit granted the EPA’s request and is holding the litigation in abeyance, while considering briefs by the parties on whether the court should remand the challenges to the EPA rather than holding them in abeyance, determining whether and how the court continues or ends the stay that currently applies to the CPP.
In October 2017, the EPA published a proposed rule to repeal the CPP, based on an analysis that the CPP exceeds the EPA’s statutory authority under the CAA. In the proposal, the EPA stated it has not yet determined whether it will promulgate a new rule to regulate GHG emissions from existing EGUs. In December 2017, the EPA issued an Advanced Notice of Proposed Rulemaking to take and consider comments on whether to issue a future rule and what such a rule should include.
Implementation of the NAAQS for SO2 — The EPA adopted a more stringent NAAQS for SO2 in 2010, and evaluated areas in in three phases. In December 2017, the EPA adopted a final rule that completed its initial designations of areas attaining or not attaining the standard. The EPA’s final actions designate all areas near PSCo’s generating plants as meeting the SO2 NAAQS with one exception. In June 2016, the EPA issued final designations which found the area near the Pawnee plant is “unclassifiable.” Since the 2016 “unclassifiable” designation, the Colorado Department of Public Health and Environment has prepared and submitted air dispersion modeling to the EPA demonstrating that the area near the Pawnee plant meets the SO2 NAAQS. The EPA has not yet completed its evaluation of the Pawnee plant.
Revisions to the NAAQS for Ozone— In 2015, the EPA revised the NAAQS for ozone by lowering the eight-hour standard from 75 parts per billion (ppb) to 70 ppb. In November 2017, the EPA published final designations of areas that meet the 2015 ozone standard. Xcel Energy meets the 2015 ozone standard in all areas where its generating units operate, except for the Denver Metropolitan Area. PSCo’s scheduled retirement of coal fired plants in Denver that began in 2011 and was completed in August 2017, should help in any plan to mitigate non-attainment. The EPA has not yet taken final action on the designation, but notified the State of Colorado in December 2017 that it intends to designate the parts of the Denver Metropolitan Area that currently do not attain the 2008 ozone standards as also not attaining the more stringent 2015 ozone standard.
Asset Retirement Obligations
Recorded AROs — AROs have been recorded for property related to the following: electric production (steam, wind, other and hydro), electric distribution and transmission, natural gas production, natural gas transmission and distribution, natural gas storage, thermal and common general property. The electric production obligations include asbestos, processed water and ash-containment facilities, radiation sources, storage tanks and control panels. The asbestos recognition associated with electric production includes certain specific plants. The AROs recorded for PSCo steam and other production relate to processed water and ash-containment facilities such as ash ponds, evaporation ponds and solid waste landfills. PSCo has also recorded AROs for the retirement and removal of assets at certain wind production facilities for which the land is leased and removal is required by contract.
PSCo recognized AROs for the retirement costs of natural gas mains and lines and for the retirement of above ground gas gathering equipment, impoundments at gas extraction sites and wells related to gas storage facilities. In addition, an ARO was recognized for the removal of electric transmission and distribution equipment, which consists of obligations associated with polychlorinated biphenyl, mineral oil, lithium batteries, mercury and street lighting lamps. The common general ARO includes obligations related to storage tanks.
A reconciliation of PSCo’s AROs for the years ended Dec. 31, 2017 and 2016 is as follows: |
| | | | | | | | | | | | | | | | | | | | |
| (Thousands of Dollars) | | Beginning Balance Jan. 1, 2017 | | Liabilities
Settled (a) | | Accretion | | Cash Flow Revisions (b) | | Ending Balance Dec. 31, 2017 (c) |
| Electric plant | | | | | | | | | | |
| Steam and other production ash containment | | $ | 72,600 |
| | $ | (12,068 | ) | | $ | 3,159 |
| | $ | 9,573 |
| | $ | 73,264 |
|
| Steam, hydro, and other production asbestos | | 40,450 |
| | (12,047 | ) | | 1,917 |
| | (458 | ) | | 29,862 |
|
| Electric distribution | | 7,669 |
| | — |
| | 274 |
| | — |
| | 7,943 |
|
| Wind production | | 2,072 |
| | — |
| | 20 |
| | — |
| | 2,092 |
|
| Other | | 1,520 |
| | (204 | ) | | 66 |
| | — |
| | 1,382 |
|
| Natural gas plant | | | | | | | | | | |
| Gas transmission and distribution | | 160,719 |
| | — |
| | 6,649 |
| | 61,503 |
| | 228,871 |
|
| Other | | 4,080 |
| | (354 | ) | | 159 |
| | — |
| | 3,885 |
|
| Common and other property | | | | | | | | | | |
| Common miscellaneous | | 453 |
| | — |
| | 17 |
| | — |
| | 470 |
|
| Total liability | | $ | 289,563 |
| | $ | (24,673 | ) | | $ | 12,261 |
| | $ | 70,618 |
| | $ | 347,769 |
|
| |
(a)
| The liabilities settled relate to asbestos abatement projects, the closure of certain ash containment facilities, and removal and proper disposal of storage tanks and other above ground equipment. |
| |
(b)
| In 2017, AROs were revised for changes in estimated cash flows and the timing of those cash flows. Changes in the gas transmission and distribution AROs were mainly related to increased labor costs. |
| |
(c)
| There were no ARO liabilities recognized during the year ended Dec. 31, 2017. |
|
| | | | | | | | | | | | | | | | | | | | |
| (Thousands of Dollars) | | Beginning Balance Jan. 1, 2016 | | Liabilities
Recognized | | Accretion | | Cash Flow Revisions (a) | | Ending Balance Dec. 31, 2016 (b) |
| Electric plant | | | | | | | | | | |
| Steam, hydro, and other production asbestos | | $ | 38,676 |
| | $ | — |
| | $ | 1,877 |
| | $ | (103 | ) | | $ | 40,450 |
|
| Steam and other production ash containment | | 70,767 |
| | — |
| | 3,078 |
| | (1,245 | ) | | 72,600 |
|
| Wind production | | 1,992 |
| | — |
| | 19 |
| | 61 |
| | 2,072 |
|
| Electric distribution | | 1,130 |
| | — |
| | 45 |
| | 6,494 |
| | 7,669 |
|
| Other | | 1,054 |
| | 214 |
| | 46 |
| | 206 |
| | 1,520 |
|
| Natural gas plant | | | | | | | | | | |
| Gas transmission and distribution | | 122,168 |
| | — |
| | 5,009 |
| | 33,542 |
| | 160,719 |
|
| Other | | 3,925 |
| | — |
| | 155 |
| | — |
| | 4,080 |
|
| Common and other property | | | | | | | | | | |
| Common miscellaneous | | 796 |
| | — |
| | 28 |
| | (371 | ) | | 453 |
|
| Total liability | | $ | 240,508 |
| | $ | 214 |
| | $ | 10,257 |
| | $ | 38,584 |
| | $ | 289,563 |
|
| |
(a)
| In 2016, AROs were revised for changes in estimated cash flows and the timing of those cash flows. Changes in the gas transmission and distribution AROs were mainly related to increased miles of gas mains. |
| |
(b)
| There were no ARO liabilities settled during the year ended Dec. 31, 2016. |
Indeterminate AROs— Outside of the known and 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 amount of asbestos or cost of removal could be determined as of Dec. 31, 2017. Therefore, an ARO has not been recorded for these facilities.
Removal Costs — PSCo records a regulatory liability for the plant removal costs of generation, transmission and distribution facilities that are recovered currently in rates. Generally, the accrual of future non-ARO removal obligations is not required. However, long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for such costs in historical depreciation rates. These removal costs have accumulated over a number of years based on varying rates as authorized by the appropriate regulatory entities. Given the long time periods over which the amounts were accrued and the changing of rates over time, PSCo has estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates. Removal costs as of Dec. 31, 2017 and 2016 were $346 million and $367 million, respectively.
Legal Contingencies
PSCo is involved in various litigation matters that are being defended and handled 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 such losses that are 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, arising from such current proceedings would have a material effect on PSCo’s consolidated financial statements. Unless otherwise required by GAAP, legalLegal fees are generally expensed as incurred.
Employment, Tort and CommercialComanche Unit 3 Litigation
Line Extension Disputes — In December 2015, Development Recovery Company (DRC)2021, CORE filed a lawsuit in the Denver County District Court, statingalleging PSCo failedbreached ownership agreement terms by failing to award proper allowances and refunds for line extensionsoperate Comanche Unit 3 in accordance with prudent utility practices. In April 2022, CORE filed a supplement to new developments pursuantinclude damages related to a 2022 outage. Also in 2022, CORE sent notice of withdrawal from the terms of electric and gas service agreements entered into by PSCo and various developers. The dispute involves claims by over fifty developers. ownership agreement based on the same alleged breaches.
In May 2016,February 2023, the Denver District Courtcourt granted PSCo’s motion precluding CORE from seeking damages related to dismiss the lawsuit, concluding that jurisdiction over this dispute resides with the CPUC. In June 2016, DRC appealed the Denver District Court’s dismissalits withdrawal as part of the lawsuit,lawsuit. In October 2023, the jury ruled that CORE may not withdraw as a joint owner of the facility but awarded CORE lost power damages of $26 million. PSCo recognized a $34 million loss for the verdict in the third quarter of 2023, including estimated interest and other costs. PSCo intends to file an appeal of this decision.
Marshall Wildfire Litigation — 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. On June 8, 2023, the Boulder County Sheriff’s Office released its Marshall Fire Investigative Summary and Review and its supporting documents (the “Sheriff’s Report”). According to an October 2022 statement from the Colorado CourtInsurance Commissioner, the Marshall Fire is estimated to have caused more than $2 billion in property losses.
According to the Sheriff’s Report, on Dec. 30, 2021, a fire ignited on a residential property in Boulder, Colorado, located in PSCo’s service territory, for reasons unrelated to PSCo’s power lines. According to the Sheriff’s Report, approximately one hour and 20 minutes after the first ignition, a second fire ignited just south of Appeals affirmed the lower court decisionMarshall Mesa Trailhead in favorunincorporated Boulder County, Colorado, also located in PSCo’s service territory. According to the Sheriff’s Report, the second ignition started approximately 80 to 110 feet away from PSCo’s power lines in the area.
The Sheriff’s Report states that the most probable cause of PSCo.the second ignition was hot particles discharged from PSCo’s power lines after one of the power lines detached from its insulator in strong winds, and further states that it cannot be ruled out that the second ignition was caused by an underground coal fire. According to the Sheriff’s Report, no design, installation or maintenance defects or deficiencies were identified on PSCo’s electrical circuit in the area of the second ignition. PSCo disputes that its power lines caused the second ignition.
PSCo is aware of 302 complaints, most of which have also named Xcel Energy Inc. and Xcel Energy Services, Inc. as additional defendants, relating to the Marshall Fire. The complaints are on behalf of at least 4,047 plaintiffs, and one complaint is filed on behalf of a putative class of first responders who allegedly were exposed to the threat of serious bodily injury, or smoke, soot and ash from the Marshall Fire. The complaints generally allege that PSCo’s equipment ignited the Marshall Fire and assert various causes of action under Colorado law, including negligence, premises liability, trespass, nuisance, wrongful death, willful and wanton conduct, negligent infliction of emotional distress, loss of consortium and inverse condemnation. In July 2017, DRC filed a petitionaddition to appealseeking compensatory damages, certain of the decision with the Colorado Supreme Court. In February 2018, the Colorado Supreme Court denied DRC’s petition effectively terminating this litigation.
complaints also seek exemplary damages.
In January 2018, DRC filed a new lawsuit inSeptember 2023, the Boulder County District Court assertingJudge consolidated eight lawsuits that were pending at that time into a single action for pretrial purposes and has subsequently consolidated additional lawsuits that have been filed. At the case management conference in February 2024, a trial date was set for September 2025.
Colorado courts do not apply strict liability in determining an electric utility company’s liability for fire-related damages. For inverse condemnation claims, Colorado courts assess whether a defendant acted with intent to take a plaintiff’s property or intentionally took an action which has the natural consequence of taking the property. For negligence claims, 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.
Colorado law does not impose joint and several liability in tort actions. Instead, under Colorado law, a defendant is liable for the degree or percentage of the negligence or fault attributable to that defendant, except where the defendant conspired with another defendant. A jury’s verdict in a Colorado civil case must be unanimous. Under Colorado law, in a civil action other than a medical malpractice action, the total award for noneconomic loss is capped at $0.6 million per defendant for claims that accrued at the time of the Marshall Fire unless the court finds justification to exceed that amount by clear and convincing evidence, in which case the maximum doubles.
Colorado law caps punitive or exemplary damages to an amount equal to the amount of the actual damages awarded to the injured party, except the court may increase any award of punitive damages to a sum up to three times the amount of actual damages if the conduct that is the subject of the claim thathas continued during the pendency of the case or the defendant has acted in a willful and wanton manner during the action which further aggravated plaintiff’s damages.
In the event Xcel Energy Inc. or PSCo was found liable related to this litigation and were required to file its line extension agreementspay damages, such amounts could exceed our insurance coverage of approximately $500 million and have a material adverse effect on our financial condition, results of operations or cash flows. However, due to uncertainty as to the cause of the fire and the extent and magnitude of potential damages, Xcel Energy Inc. and PSCo are unable to estimate the amount or range of possible losses in connection with the CPUC but failedMarshall Fire.
Rate Matters
PSCo is involved in various regulatory proceedings arising in the ordinary course of business. Until resolution, typically in the form of a 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 do so. This claim is substantially similarhave a material effect on the 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 arguments previously raised by DRC. Datesenvironment. 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 this proceedingwhich PSCo is alleged to have notsent wastes to that site.
MGP, Landfill and Disposal Sites
PSCo is currently investigating, remediating or performing post-closure actions at two historical MGP, landfill or other disposal sites across its service territory, excluding sites that are being addressed under current coal ash regulations (see below).
PSCo has recognized approximately $6 million of costs/liabilities from final resolution of these issues; however, the outcome and timing are 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 applicable landfills and surface impoundments as well as perform corrective actions where offsite groundwater has been scheduled.impacted.
If certain impacts to groundwater are detected, utilities are required to perform additional groundwater investigations and/or perform corrective actions beginning with an Assessment of Corrective Measures. Investigation and/or corrective action related to groundwater impacts are currently underway at four PSCo sites under the federal CCR program at a current estimated cost of at least $40 million. A liability has been recorded and is expected to be fully recoverable through regulatory mechanisms.
PSCo has concludedexecuted an agreement with a third party that will excavate and process ash for beneficial use (at two sites) at a loss is remote with respect to bothcost of these matters as the service agreements were developed to implement CPUC approved tariffs and PSCo has complied with the tariff provisions. Also, if a loss were sustained, PSCo believes it would be allowed to recover these costs through traditional regulatory mechanisms. The amount or range in dispute is presently unknown and no accrualapproximately $45 million. An estimated liability has been recorded and amounts are expected to be fully recoverable through regulatory mechanisms.
AROs — AROs have been recorded for this matter.
Other Contingencies
See Note 11 for further discussion.
| |
13. | Regulatory Assets and Liabilities |
PSCo’s assets.
PSCo’s consolidated financial statements are preparedAROs were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2023 |
(Millions
of Dollars) | | Jan. 1,
2023 | | | | | | Accretion | | Cash Flow Revisions (a) | | Dec. 31, 2023 |
| Electric | | | | | | | | | | | | |
| Steam, hydro and other production | | $ | 180 | | | | | | | $ | 8 | | | $ | — | | | $ | 188 | |
| Wind | | 44 | | | | | | | 2 | | | — | | | 46 | |
| Distribution | | 17 | | | | | | | — | | | — | | | 17 | |
| Natural gas | | | | | | | | | | | | |
| Transmission and distribution | | 235 | | | | | | | 11 | | | (114) | | | 132 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| Total liability | | $ | 476 | | | | | | | $ | 21 | | | $ | (114) | | | $ | 383 | |
(a)In 2023, AROs were revised for changes in accordancetiming and estimates of cash flows. Changes in gas transmission and distribution AROs were primarily the result of changes to inflation and discount rate assumptions as well as updated mileage of gas lines and number of services.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2022 |
(Millions
of Dollars) | | Jan. 1, 2022 | | | | | | Amounts Incurred (a) | | Accretion | | Cash Flow Revisions (b) | | Dec. 31, 2022 |
| Electric | | | | | | | | | | | | | | |
| Steam, hydro and other production | | $ | 152 | | | | | | | $ | 34 | | | $ | 6 | | | $ | (12) | | | $ | 180 | |
| Wind | | 42 | | | | | | | — | | | 2 | | | — | | | 44 | |
| Distribution | | 16 | | | | | | | — | | | 1 | | | — | | | 17 | |
| Natural gas | | | | | | | | | | | | | | |
| Transmission and distribution | | 212 | | | | | | | — | | | 10 | | | 13 | | | 235 | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| Total liability | | $ | 422 | | | | | | | $ | 34 | | | $ | 19 | | | $ | 1 | | | $ | 476 | |
(a)Amounts incurred related to steam production pond remediation costs.
(b)In 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 the applicable accounting guidance, as discussed in Note 1. Under this guidance, regulatory assetsincreased gas line mileage 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. Any portionnumber of services.
Indeterminate AROs— Outside of the businessrecorded 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, 2023. Therefore, an ARO has not been recorded for these facilities.
Leases
PSCo evaluates contracts that is not rate regulated cannot establish regulatory assetsmay contain leases, including PPAs and liabilities. If changes in the utility industry or the business of PSCo no longer allowarrangements for the applicationuse of regulatoryoffice 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 of 4.2%). For currently existing asset classes, 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 lease payments for the purposes of lease accounting guidance under GAAP, PSCo would be required to recognize the write-offand disclosure.
Leases with an initial term of regulatory assets12 months or less are classified as short-term leases and liabilities in net income or OCI.
The components of regulatory assets shownare not recognized on the consolidated balance sheetssheet.
Operating lease ROU assets:
| | | | | | | | | | | | | | |
| (Millions of Dollars) | | Dec. 31, 2023 | | Dec. 31, 2022 |
| PPAs | | $ | 623 | | | $ | 612 | |
| Other | | 112 | | | 80 | |
| Gross operating lease ROU assets | | 735 | | | 692 | |
| Accumulated amortization | | (369) | | | (255) | |
| Net operating lease ROU assets | | $ | 366 | | | $ | 437 | |
ROU assets for finance leases are included in other noncurrent assets, and the present value of PSCo at Dec. 31, 2017future finance lease payments is included in other current liabilities and 2016 are:other noncurrent liabilities.
|
| | | | | | | | | | | | | | | | | | | | | |
| (Thousands of Dollars) | | See Note(s) | | Remaining
Amortization Period | | Dec. 31, 2017 | | Dec. 31, 2016 |
| Regulatory Assets | | | | | | Current | | Noncurrent | | Current | | Noncurrent |
Pension and retiree medical obligations (a) | | 8 |
| | Various | | $ | 28,010 |
| | $ | 565,241 |
| | $ | 27,270 |
| | $ | 568,258 |
|
Recoverable deferred taxes on AFUDC recorded in plant (b) | | 1 |
| | Plant lives | | — |
| | 86,966 |
| | — |
| | 151,022 |
|
Net AROs (c) | | 1, 12 |
| | Plant lives | | — |
| | 80,476 |
| | — |
| | 78,050 |
|
| Depreciation differences | | 1 |
| | One to fourteen years | | 19,835 |
| | 69,428 |
| | 15,363 |
| | 90,426 |
|
| Excess deferred taxes - TCJA | | 7 |
| | Various | | — |
| | 53,937 |
| | — |
| | — |
|
| Purchased power contract costs | | 12 |
| | Term of related contract | | 1,261 |
| | 28,009 |
| | 1,035 |
| | 29,029 |
|
| Property tax | | | | Pending rate cases | | — |
| | 16,047 |
| | 9,393 |
| | 1,653 |
|
| Gas pipeline inspection costs | | 12 |
| | One to two years | | 1,791 |
| | 7,743 |
| | — |
| | 4,405 |
|
Conservation programs (d) | | 1, 11 |
| | One to two years | | 6,942 |
| | 5,528 |
| | 9,262 |
| | 6,986 |
|
| Losses on reacquired debt | | 4 |
| | Term of related debt | | 1,203 |
| | 4,916 |
| | 1,203 |
| | 6,120 |
|
Contract valuation adjustments (e) | | 10 |
| | Term of related contract | | 6,022 |
| | 2,638 |
| | 3,444 |
| | 6,082 |
|
| Other | | | | Various | | 12,273 |
| | 29,329 |
| | 36,813 |
| | 16,398 |
|
| Total regulatory assets | | | | | | $ | 77,337 |
| | $ | 950,258 |
| | $ | 103,783 |
| | $ | 958,429 |
|
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.
| |
(a)
| Includes $3.4 million and $4.2 million of regulatory assets related to the nonqualified pension plan, of which $0.3 million and $0.4 million is included in the current asset at Dec. 31, 2017 and 2016, respectively. |
| |
(b)
| Includes a write-down of $75.9 million as a result of the revaluation of deferred tax gross up at the new federal tax rate at Dec. 31, 2017. |
| |
(c)
| Includes amounts recorded for future recovery of AROs. |
| |
(d)
| Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. |
| |
(e)
| Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases. |
PSCo accounts for its Totem natural gas storage service and Front Range pipeline arrangements with CIG and WYCO, respectively, as finance leases.
The componentsFinance lease ROU assets:
| | | | | | | | | | | | | | |
| (Millions of Dollars) | | Dec. 31, 2023 | | Dec. 31, 2022 |
| Gas storage facilities | | $ | 160 | | | $ | 160 | |
| Gas pipeline | | 21 | | | 21 | |
| Gross finance lease ROU assets | | 181 | | | 181 | |
| Accumulated amortization | | (67) | | | (64) | |
| Net finance lease ROU assets | | $ | 114 | | | $ | 117 | |
Components of regulatory liabilities shownlease expense:
| | | | | | | | | | | | | | | | | | | | |
| (Millions of Dollars) | | 2023 | | 2022 | | 2021 |
| Operating leases | | | | | | |
| PPA capacity payments | | $ | 89 | | | $ | 91 | | | $ | 102 | |
Other operating leases (a) | | 19 | | | 20 | | | 16 | |
Total operating lease expense (b) | | $ | 108 | | | $ | 111 | | | $ | 118 | |
| Finance leases | | | | | | |
| Amortization of ROU assets | | $ | 3 | | | $ | 4 | | | $ | 7 | |
| Interest expense on lease liability | | 15 | | | 16 | | | 17 | |
| Total finance lease expense | | $ | 18 | | | $ | 20 | | | $ | 24 | |
(a)Includes immaterial short-term lease expense of for 2023, 2022 and 2021.
(b)PPA capacity payments are included in electric fuel and purchased power on the consolidated balance sheetsstatements of PSCo atincome. 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, 2017 and 2016 are:2023:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| (Millions of Dollars) | | PPA (a) (b) Operating Leases | | Other Operating Leases | | Total
Operating Leases | | Finance Leases |
| 2024 | | $ | 98 | | | $ | 19 | | | $ | 117 | | | $ | 18 | |
| 2025 | | 97 | | | 12 | | | 109 | | | 18 | |
| 2026 | | 74 | | | 8 | | | 82 | | | 18 | |
| 2027 | | 44 | | | 8 | | | 52 | | | 16 | |
| 2028 | | 20 | | | 8 | | | 28 | | | 15 | |
| Thereafter | | 39 | | | 6 | | | 45 | | | 333 | |
| Total minimum obligation | | 372 | | | 61 | | | 433 | | | 418 | |
| Interest component of obligation | | (35) | | | (6) | | | (41) | | | (304) | |
| Present value of minimum obligation | | $ | 337 | | | $ | 55 | | | 392 | | | 114 | |
| Less current portion | | | | | | (102) | | | (3) | |
| Noncurrent operating and finance lease liabilities | | | | | | $ | 290 | | | $ | 111 | |
| | | | | | | | |
| Weighted-average remaining lease term in years | | | | | | 4.6 | | 36.8 |
(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
|
| | | | | | | | | | | | | | | | | | | | | |
| (Thousands of Dollars) | | See Note(s) | | Remaining
Amortization Period | | Dec. 31, 2017 | | Dec. 31, 2016 |
| Regulatory Liabilities | | | | | | Current | | Noncurrent | | Current | | Noncurrent |
Excess deferred taxes - TCJA (a) | | 7 |
| | Various | | $ | — |
| | $ | 1,445,079 |
| | $ | — |
| | $ | — |
|
| Plant removal costs | | 1, 12 |
| | Plant lives | | — |
| | 346,174 |
| | — |
| | 367,440 |
|
| Renewable resources and environmental initiatives | | 11, 12 |
| | Various | | — |
| | 56,153 |
| | 3,600 |
| | 67,728 |
|
| Investment tax credit deferrals | | 1, 7 |
| | Various | | — |
| | 17,088 |
| | — |
| | 18,797 |
|
| Deferred income tax adjustment | | 1 |
| | Various | | — |
| | 16,301 |
| | — |
| | 16,260 |
|
| Deferred electric, natural gas and steam production costs | | 1 |
| | Less than one year | | 29,078 |
| | — |
| | 35,123 |
| | — |
|
Conservation programs (b) | | 1, 11 |
| | Less than one year | | 21,168 |
| | — |
| | 24,077 |
| | — |
|
| Other | | | | Various | | 15,880 |
| | 52,693 |
| | 38,310 |
| | 42,708 |
|
Total regulatory liabilities (c) | | | | | | $ | 66,126 |
| | $ | 1,933,488 |
| | $ | 101,110 |
| | $ | 512,933 |
|
Included in electric fuel and purchased power expenses for PPAs accounted for as executory contracts were payments for capacity of $3 million, $3 million and $2 million in 2023, 2022 and 2021, respectively.
| |
(a)
| Primarily relates to the revaluation of recoverable/regulated plant ADIT and $49.6 million revaluation impact of non-plant ADIT at Dec. 31, 2017. |
| |
(b)
| Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. |
| |
(c)
| Revenue subject to refund of $0 million and $2.4 million for 2017 and 2016, respectively, is included in other current liabilities. |
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, 20172023, 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) | | Capacity |
| 2024 | | $ | 3 | |
| 2025 | | 3 | |
| 2026 | | 3 | |
| 2027 | | 1 | |
| 2028 | | — | |
| Thereafter | | — | |
| Total | | $ | 10 | |
Fuel Contracts — PSCo has entered into various long-term commitments for the purchase and 2016,delivery of a significant portion of its coal and natural gas requirements. These contracts expire between 2024 and 2060. PSCo is required to pay additional amounts depending on actual quantities delivered under these agreements.
Estimated minimum purchases under these contracts as of Dec. 31, 2023:
| | | | | | | | | | | | | | | | | | | | |
| (Millions of Dollars) | | Coal | | Natural gas supply | | Natural gas storage and
transportation |
| 2024 | | $ | 143 | | | $ | 221 | | | $ | 108 | |
| 2025 | | 74 | | | 12 | | | 105 | |
| 2026 | | 39 | | | — | | | 105 | |
| 2027 | | 35 | | | — | | | 105 | |
| 2028 | | — | | | — | | | 62 | |
| Thereafter | | — | | | — | | | 382 | |
| Total | | $ | 291 | | | $ | 233 | | | $ | 867 | |
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, however 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 PSCo does not have the power to direct the activities that most significantly impact the entities’ economic performance. PSCo had approximately $44 million1,207 MW and $28 million1,442 MW of PSCo’s regulatory assets represented past expenditures not currently earning a return, respectively. This amount primarily includes certain expenditures associatedcapacity under long-term PPAs at Dec. 31, 2023 and 2022, respectively, with property taxes and renewable resources and environmental initiatives.entities that have been determined to be VIEs. These agreements have expiration dates through 2032.
| | |
14. | 11. Other Comprehensive Income |
Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31, 201731:
| | | | | | | | | | | | | | | | | | | | |
| | 2023 |
| (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 | | $ | (20) | | | $ | (2) | | | $ | (22) | |
| Other comprehensive loss before reclassifications | | — | | | — | | | — | |
| Losses reclassified from net accumulated other comprehensive loss: |
| Amortization of interest rate hedges | | 1 | | (a) | — | | | 1 | |
| Amortization of net actuarial loss | | — | | | 1 | | (b) | 1 | |
| Net current period other comprehensive income | | 1 | | | 1 | | | 2 | |
| Accumulated other comprehensive loss at Dec. 31 | | $ | (19) | | | $ | (1) | | | $ | (20) | |
(a)Included in interest charges.
(b)Included in the computation of net periodic pension and 2016 were as follows:postretirement benefit costs. See Note 9 for further information.
| | | | | | | | | | | | | | | | | | | | |
| | 2022 |
| (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 | | $ | (21) | | | $ | (1) | | | $ | (22) | |
| Other comprehensive loss before reclassifications | | — | | | (1) | | | (1) | |
| Losses reclassified from net accumulated other comprehensive loss: |
| Amortization of interest rate hedges | | 1 | | (a) | — | | | 1 | |
| | | | | | |
| Net current period other comprehensive income (loss) | | 1 | | | (1) | | | — | |
| Accumulated other comprehensive loss at Dec. 31 | | (20) | | | (2) | | | (22) | |
(a)Included in interest charges.
|
| | | | | | | | | | | | |
| | | Year Ended Dec. 31, 2017 |
| (Thousands of Dollars) | | Gains and Losses on Cash Flow Hedges | | Defined Benefit and Postretirement Items | | Total |
| Accumulated other comprehensive loss at Jan. 1 | | $ | (22,780 | ) | | $ | (220 | ) | | $ | (23,000 | ) |
| Other comprehensive loss before reclassifications | | — |
| | (5 | ) | | (5 | ) |
| Losses reclassified from net accumulated other comprehensive loss | | 1,005 |
| | 5 |
| | 1,010 |
|
| Net current period other comprehensive income | | 1,005 |
| | — |
| | 1,005 |
|
| | | | | | | |
Adoption of ASU No. 2018-02 (a) | | (4,690 | ) | | (47 | ) | | (4,737 | ) |
| Accumulated other comprehensive loss at Dec. 31 | | $ | (26,465 | ) | | $ | (267 | ) | | $ | (26,732 | ) |
| | |
(a)
| In 2017, PSCo implemented ASU No. 2018-02 related to the TCJA, which resulted in reclassification of certain credit balances within net accumulated other comprehensive loss to retained earnings. For further information, see Note 2. |
|
| | | | | | | | | | | | |
| | | Year Ended Dec. 31, 2016 |
| (Thousands of Dollars) | | Gains and Losses on Cash Flow Hedges | | Defined Benefit and Postretirement Items | | Total |
| Accumulated other comprehensive loss at Jan. 1 | | $ | (23,836 | ) | | $ | — |
| | $ | (23,836 | ) |
| Other comprehensive loss before reclassifications | | — |
| | (223 | ) | | (223 | ) |
| Losses reclassified from net accumulated other comprehensive loss | | 1,056 |
| | 3 |
| | 1,059 |
|
| Net current period other comprehensive income (loss) | | 1,056 |
| | (220 | ) | | 836 |
|
| Accumulated other comprehensive loss at Dec. 31 | | $ | (22,780 | ) | | $ | (220 | ) | | $ | (23,000 | ) |
Reclassifications from accumulated other comprehensive loss for the years ended Dec. 31, 2017 and 2016 were as follows:
|
| | | | | | | | | |
| | | Amounts Reclassified from Accumulated
Other Comprehensive Loss | |
| (Thousands of Dollars) | | Year Ended Dec. 31, 2017 | | Year Ended Dec. 31, 2016 | |
| Losses (gains) on cash flow hedges: | | | | | |
| Interest rate derivatives | | $ | 1,615 |
| (a) | $ | 1,618 |
| (a) |
| Vehicle fuel derivatives | | — |
| (b) | 86 |
| (b) |
| Total, pre-tax | | 1,615 |
| | 1,704 |
| |
| Tax benefit | | (610 | ) | | (648 | ) | |
| Total, net of tax | | 1,005 |
| | 1,056 |
| |
| Defined benefit pension and postretirement losses (gains): | | | | | |
| Amortization of net losses | | 9 |
| (c) | 5 |
| (c) |
| Total, pre-tax | | 9 |
| | 5 |
| |
| Tax benefit | | (4 | ) | | (2 | ) | |
| Total, net of tax | | 5 |
| | 3 |
| |
| Total amounts reclassified, net of tax | | $ | 1,010 |
| | $ | 1,059 |
| |
| |
(a)
| Included in interest charges. |
| |
(b)
| Included in O&M expenses. |
| |
(c)
| Included in the computation of net periodic pension and postretirement benefit costs. See Note 8 for details regarding these benefit plans. |
| |
15. | Segments and Related12. Segment Information |
Operating results from the regulated electric utility and regulated natural gas utility are each separately and regularly reviewed by PSCo’s chief operating decision maker. 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 utility, regulated natural gas utility and all other.
PSCo’s•Regulated Electric — The regulated electric utility segment generates, electricity which is transmittedpurchases, transmits, distributes and distributedsells electricity in Colorado. In addition, thisThis 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.
PSCo’s•Regulated Natural Gas — The regulated natural gas utility segment purchases, transports, stores, distributes and distributessells natural gas in portions of Colorado.
Revenues fromPSCo also presents All Other, which includes operating segments not included above arewith revenues below the necessary quantitative thresholds and are therefore included in the all other category.thresholds. Those operating segments primarily include steam revenue, appliance repair services and nonutilitynon-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.
The accounting policies of the segments are the same as those described in Note 1.
|
| | | | | | | | | | | | | | | | | | | | |
| (Thousands of Dollars) | | Regulated
Electric | | Regulated
Natural Gas | | All Other | | Reconciling
Eliminations | | Consolidated
Total |
| 2017 | | | | | | | | | | |
Operating revenues (a) | | $ | 3,003,808 |
| | $ | 995,214 |
| | $ | 43,487 |
| | $ | — |
| | $ | 4,042,509 |
|
| Intersegment revenues | | 288 |
| | 344 |
| | — |
| | (632 | ) | | — |
|
| Total revenues | | $ | 3,004,096 |
| | $ | 995,558 |
| | $ | 43,487 |
| | $ | (632 | ) | | $ | 4,042,509 |
|
| | | | | | | | | | | |
| Depreciation and amortization | | $ | 353,560 |
| | $ | 113,253 |
| | $ | 4,702 |
| | $ | — |
| | $ | 471,515 |
|
| Interest charges and financing costs | | 138,565 |
| | 40,214 |
| | 508 |
| | — |
| | 179,287 |
|
| Income tax expense (benefit) | | 243,604 |
| | 18,398 |
| | (9,823 | ) | | — |
| | 252,179 |
|
| Net income | | 370,636 |
| | 107,822 |
| | 15,661 |
| | — |
| | 494,119 |
|
PSCo’s segment information:
| | | | | | | | | | | | | | | | | | | | |
| (Millions of Dollars) | | 2023 | | 2022 | | 2021 |
| Regulated Electric | | | | | | |
| Operating revenues — external | | $ | 3,731 | | | $ | 3,795 | | | $ | 3,413 | |
| Intersegment revenue | | 1 | | | 1 | | | 1 | |
| Total revenues | | $ | 3,732 | | | $ | 3,796 | | | $ | 3,414 | |
| Depreciation and amortization | | 692 | | | 650 | | | 566 | |
| Interest charges and financing costs | | 224 | | | 200 | | | 179 | |
| Income tax benefit | | (2) | | | (11) | | | (16) | |
| Net income | | 529 | | | 550 | | | 495 | |
| Regulated Natural Gas | | | | | | |
| | | | | | |
| | | | | | |
| Total revenues | | $ | 1,734 | | | $ | 1,860 | | | $ | 1,355 | |
| Depreciation and amortization | | 224 | | | 190 | | | 171 | |
| Interest charges and financing costs | | 67 | | | 59 | | | 53 | |
| Income tax expense | | 37 | | | 49 | | | 45 | |
| Net income | | 149 | | | 180 | | | 168 | |
| All Other | | | | | | |
Total revenues (a) | | $ | 54 | | | $ | 53 | | | $ | 47 | |
| Depreciation and amortization | | 8 | | | 8 | | | 7 | |
| Interest charges and financing costs | | 1 | | | 1 | | | 2 | |
| Income tax (benefit) expense | | (6) | | | (1) | | | 4 | |
| Net (loss) income | | 17 | | | (3) | | | (3) | |
| | | | | | |
| Consolidated Total | | | | | | |
Total revenues (a) | | $ | 5,520 | | | $ | 5,709 | | | $ | 4,816 | |
| Reconciling eliminations | | (1) | | | (1) | | | (1) | |
| Total operating revenues | | $ | 5,519 | | | $ | 5,708 | | | $ | 4,815 | |
| Depreciation and amortization | | 924 | | | 848 | | | 744 | |
| Interest charges and financing costs | | 292 | | | 260 | | | 234 | |
| Income tax expense | | 29 | | | 37 | | | 33 | |
| Net income | | 695 | | | 727 | | | 660 | |
(a)Operating revenues include $5 million of other affiliate revenue for the years ended Dec. 31, 2023, 2022 and 2021, respectively. See Note 13 for further information.
|
| | | | | | | | | | | | | | | | | | | | |
| (Thousands of Dollars) | | Regulated Electric | | Regulated Natural Gas | | All Other | | Reconciling Eliminations | | Consolidated Total |
| 2016 | | | | | | | | | | |
Operating revenues (a) | | $ | 3,049,352 |
| | $ | 957,721 |
| | $ | 40,723 |
| | $ | — |
| | $ | 4,047,796 |
|
| Intersegment revenues | | 275 |
| | 110 |
| | — |
| | (385 | ) | | — |
|
| Total revenues | | $ | 3,049,627 |
| | $ | 957,831 |
| | $ | 40,723 |
| | $ | (385 | ) | | $ | 4,047,796 |
|
| | | | | | | | | | | |
| Depreciation and amortization | | $ | 337,583 |
| | $ | 101,663 |
| | $ | 4,309 |
| | $ | — |
| | $ | 443,555 |
|
| Interest charges and financing costs | | 136,274 |
| | 37,881 |
| | 431 |
| | — |
| | 174,586 |
|
| Income tax expense (benefit) | | 228,825 |
| | 45,960 |
| | (867 | ) | | — |
| | 273,918 |
|
| Net income | | 383,973 |
| | 75,426 |
| | 4,092 |
| | — |
| | 463,491 |
|
|
| | | | | | | | | | | | | | | | | | | | |
| (Thousands of Dollars) | | Regulated Electric | | Regulated Natural Gas | | All Other | | Reconciling Eliminations | | Consolidated Total |
| 2015 | | | | | | | | | | |
Operating revenues (a) | | $ | 3,115,257 |
| | $ | 1,006,666 |
| | $ | 41,590 |
| | $ | — |
| | $ | 4,163,513 |
|
| Intersegment revenues | | 301 |
| | 67 |
| | — |
| | (368 | ) | | — |
|
| Total revenues | | $ | 3,115,558 |
| | $ | 1,006,733 |
| | $ | 41,590 |
| | $ | (368 | ) | | $ | 4,163,513 |
|
| | | | | | | | | | | |
| Depreciation and amortization | | $ | 311,122 |
| | $ | 96,384 |
| | $ | 4,161 |
| | $ | — |
| | $ | 411,667 |
|
| Interest charges and financing costs | | 136,397 |
| | 34,935 |
| | 576 |
| | — |
| | 171,908 |
|
| Income tax expense (benefit) | | 234,873 |
| | 44,192 |
| | (625 | ) | | — |
| | 278,440 |
|
| Net income | | 391,257 |
| | 74,267 |
| | 1,278 |
| | — |
| | 466,802 |
|
| | |
(a)
| Operating revenues include $6 million, $13 million and $13 million of intercompany revenue for the years ended Dec. 31, 2017, 2016 and 2015, respectively. See Note 16 for further discussion of related party transactions by reportable segment. |
| |
16. | 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 45 for further discussion.information.
The table below contains significantSignificant affiliate transactions among the companies and related parties for the years ended Dec. 31:
| | | | | | | | | | | | | | | | | | | | |
| (Millions of Dollars) | | 2023 | | 2022 | | 2021 |
| Operating revenues: | | | | | | |
| | | | | | |
| Other | | $ | 5 | | | $ | 5 | | | $ | 5 | |
| Operating expenses: | | | | | | |
| Other operating expenses — paid to Xcel Energy Services Inc. | | 679 | | | 670 | | | 617 | |
| Interest expense | | 5 | | | 2 | | | — | |
| Interest income | | 2 | | | — | | | ��� | |
|
| | | | | | | | | | | | |
| (Thousands of Dollars) | | 2017 | | 2016 | | 2015 |
| Operating revenues: | | | | | | |
| Electric | | $ | 1,436 |
| | $ | 8,809 |
| | $ | 8,632 |
|
| Other | | 4,492 |
| | 4,525 |
| | 4,441 |
|
| Operating expenses: | | | | | | |
| Purchased power | | 2 |
| | 56 |
| | — |
|
| Other operating expenses — paid to Xcel Energy Services Inc. | | 485,066 |
| | 446,086 |
| | 414,620 |
|
| Interest expense | | — |
| | 149 |
| | 211 |
|
| Interest income | | — |
| | — |
| | 45 |
|
Accounts receivable and payable with affiliates at Dec. 31 were:31:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2023 | | 2022 |
| (Millions of Dollars) | | Accounts Receivable | | Accounts Payable | | Accounts Receivable | | Accounts Payable |
| NSP-Minnesota | | $ | — | | | $ | 5 | | | $ | 2 | | | $ | — | |
| NSP-Wisconsin | | — | | | 1 | | | — | | | 2 | |
| SPS | | — | | | 11 | | | — | | | 11 | |
| Other subsidiaries of Xcel Energy Inc. | | 28 | | | 66 | | | 9 | | | 62 | |
| | $ | 28 | | | $ | 83 | | | $ | 11 | | | $ | 75 | |
|
| | | | | | | | | | | | | | | | |
| | | 2017 | | 2016 |
| (Thousands of Dollars) | | Accounts
Receivable | | Accounts
Payable | | Accounts
Receivable | | Accounts
Payable |
| NSP-Minnesota | | $ | 7,738 |
| | $ | — |
| | $ | 7,669 |
| | $ | — |
|
| NSP-Wisconsin | | 61 |
| | — |
| | 974 |
| | — |
|
| SPS | | 279 |
| | — |
| | 745 |
| | — |
|
| Other subsidiaries of Xcel Energy Inc. | | 6,641 |
| | 58,748 |
| | 33 |
| | 98,797 |
|
| | | $ | 14,719 |
| | $ | 58,748 |
| | $ | 9,421 |
| | $ | 98,797 |
|
| | |
17. | Summarized Quarterly Financial Data (Unaudited)14. Workforce Reduction |
In 2023, Xcel Energy implemented workforce actions to align resources and investments with evolving business and customer needs, and streamline the organization for long-term success.
In September 2023, Xcel Energy announced a voluntary retirement program to a group of eligible non-bargaining employees, with an enhanced retirement package including certain health care and cash benefits for accepted employees. Approximately 400 employees retired under this program in December 2023.
In November 2023, Xcel Energy, Inc. also reduced its non-bargaining workforce by approximately 150 employees through an involuntary severance program.
In the fourth quarter of 2023, Xcel Energy recorded total expense of $72 million related to these workforce actions, of which $20 million was attributable to PSCo. Expenses relate to the estimated cost of future health plan subsidies and other medical benefits for the voluntary retirement program, as well as severance and other employee payouts and legal and other professional fees.
For further information on the estimated obligations for future health plan subsidies and other medical benefits, see Note 9 to the consolidated financial statements.
|
| | | | | | | | | | | | | | | | |
| | | Quarter Ended |
| (Thousands of Dollars) | | March 31, 2017 | | June 30, 2017 | | Sept. 30, 2017 | | Dec. 31, 2017 |
| Operating revenues | | $ | 1,080,534 |
| | $ | 930,916 |
| | $ | 1,030,293 |
| | $ | 1,000,766 |
|
| Operating income | | 212,422 |
| | 192,811 |
| | 326,028 |
| | 154,669 |
|
| Net income | | 111,546 |
| | 100,587 |
| | 186,077 |
| | 95,909 |
|
|
| | | | | | | | | | | | | | | | |
| | | Quarter Ended |
| (Thousands of Dollars) | | March 31, 2016 | | June 30, 2016 | | Sept. 30, 2016 | | Dec. 31, 2016 |
| Operating revenues | | $ | 1,057,841 |
| | $ | 909,852 |
| | $ | 1,059,177 |
| | $ | 1,020,926 |
|
| Operating income | | 223,190 |
| | 180,629 |
| | 315,605 |
| | 170,197 |
|
| Net income | | 115,874 |
| | 87,344 |
| | 173,607 |
| | 86,666 |
|
Item 9 — Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
| | |
| ITEM 9 — CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
None.
Item 9A — Controls and Procedures
| | |
| 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 chief executive officer (CEO)CEO and chief financial officer (CFO),CFO, allowing timely decisions regarding required disclosure.
As of Dec. 31, 2017,2023, 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 the procedures, the CEO and CFO have concluded that PSCo’s disclosure controls and procedures were effective.
Internal Control Over Financial Reporting
No changechanges in PSCo’s internal control over financial reporting has occurred during the most recent fiscal quarter ended Dec. 31, 2023 that has materially affected, or isare 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, 20172023 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, and as approved by the SEC and as indicated in PSCo’s Management Report on Internal Controls herein.
In 2016, PSCo implemented the general ledger modules of a new enterprise resource planning system to improve certain financial and related transaction processes. PSCo implemented additional work management systems modulesover Financial Reporting, which is contained in 2017. PSCo updated its internal control over financial reporting, as necessary, to accommodate modifications to its business processes and accounting systems. PSCo does not believe that this implementation had an adverse effect on its internal control over financial reporting.
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.
Item 9B — Other Information
| | |
| ITEM 9B — OTHER INFORMATION |
None.
| | |
| 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) I(1)(a) and (b) of Form 10-K for wholly-owned subsidiaries.
| | |
| ITEM 10 — DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE |
Item 10 — Directors, Executive Officers and Corporate Governance
| | |
| ITEM 11 — EXECUTIVE COMPENSATION |
Item 11 — Executive Compensation | | |
| ITEM 12 — SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS |
Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13 — Certain Relationships and Related Transactions, and Director Independence
| | |
| 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 20182024 Annual Meeting of Shareholders, which is incorporated by reference.
| | |
| ITEM 14 — PRINCIPAL ACCOUNTANT FEES AND SERVICES |
Information required under this Item 14 — Principal Accountant Fees and Services
The information required(aggregate fees billed to us by Item 14 of From 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 definitive Proxy Statement for the 2018its 2024 Annual Meeting of StockholdersShareholders, which definitive Proxy Statement is expected to be filed with the SEC on or about April 3, 2018. Such information set forth under such heading is incorporated herein by this reference hereto.reference.
PART IV
Item 15 — Exhibits, Financial Statement Schedules
| | |
ITEM 15—EXHIBIT AND FINANCIAL STATEMENT SCHEDULES |
| | | | | |
1.1 | Consolidated Financial Statements: |
| |
| Management Report on Internal Controls Over Financial Reporting —For the year ended Dec. 31, 2017.2023. |
| Report of Independent Registered Public Accounting Firm — Financial Statements |
| Consolidated Statements of Income — For each of the three years ended Dec. 31, 2017, 2016,2023, 2022, and 2015.2021. |
| Consolidated Statements of Comprehensive Income — For each of the three years ended Dec. 31, 2017, 2016,2023, 2022, and 2015.2021. |
| Consolidated Statements of Cash Flows — For each of the three years ended Dec. 31, 2017, 2016,2023, 2022, and 2015.2021. |
| Consolidated Balance Sheets — As of Dec. 31, 2017 and 2016.2023, 2022. |
| Consolidated Statements of Common Stockholder’s Equity — For each of the three years ended Dec. 31, 2017, 20162023, 2022, and 2015.2021. |
| | Consolidated Statements of Capitalization — As of Dec. 31, 2017 and 2016.
| |
2.2 | Schedule II — Valuation and Qualifying Accounts and Reserves for each of the years ended Dec. 31, 2017, 2016,2023, 2022, and 2015.2021. |
| 3. |
| 3 | Exhibits |
|
| * | |
* | Indicates incorporation by reference |
| + | Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors |
| | | | | | | | | | | |
| Exhibit Number | Description | Report or Registration Statement | Exhibit Reference |
t
| Certain portions of this agreement have been omitted pursuant to a request for confidential treatment and have been filed separately with the SEC. |
|
| |
| | PSCo Form 10-Q for the quarter ended Sept. 30, 2017 (file no. 001-03280)). | 3.01 |
| | PSCo Form 10-Q/A10-K for the quarteryear ended Sept. 30, 2013 (file no. 001-03280)).Dec. 31, 2018 | 3.02 |
| | Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2017).Inc. Form S-3 dated April 18, 2018 | 4(d)(3) |
|
| | | | | | | | | | |
| |
| | PSCo Form 8-K (file no. 001-03280) dated Aug. 18, 2007).8, 2007 | 4.01 |
| | PSCo Form 8-K of PSCo dated Aug. 6, 2008 (file no. 001-03280)). | 4.01 |
| |
| |
| | PSCo Form 8-K of PSCo dated Aug. 9, 2011 (file no. 001-03280)). | 4.01 |
| | PSCo Form 8-K dated Sept. 11, 2012 (file no. 001-03280)). | 4.01 |
| Supplemental Indenture No. 23, dated as of March 1, 2013, by and between PSCo and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as successor Trustee, creating $250 million aggregate principal amount of 2.50 percent2.50% First Mortgage Bonds, Series No. 25 due March 15, 2023 and $250 million aggregate principal amount of 3.95 percent3.95% First Mortgage Bonds, Series No. 26 due March 15, 2043 (Exhibit 4.01 to | PSCo Form 8-K of PSCo dated March 26, 2013 (file no. 001-03280)). |
|
| 4.01 |
| | PSCo Form 8-K of PSCo dated March 10, 2014 (file no. 001-03280)). | 4.01 |
| | PSCo Form 8-K of PSCo dated May 12, 2015 (file no. 001-03280)). | 4.01 |
| | PSCo Form 8-K of PSCo dated June 13, 2016 (file no. 001-03280)). | 4.01 |
| | PSCo Form 8-K of PSCo dated June 19, 2017 (file no. 001-03280)). | 4.01 |
| Supplemental Indenture No. 28, dated as of June 1, 2018, by and between PSCo and U.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 and U.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 |
| Supplemental Indenture No. 33, dated as of May 1, 2022, by and between PSCo and U.S. Bank Trust Company, National Association, as Trustee, creating $300 million aggregate principal amount of 4.10% First Mortgage Bonds, Series No. 38 due June 1, 2032 and $400 million aggregate principal amount of 4.50% First Mortgage Bonds, Series No. 39 due June 1, 2052 | PSCo Form 8-K dated May 17, 2022 | 99.03 |
| | PSCo Form 8-K dated April 3, 2023 | 4.01 |
| | Xcel Energy Inc. Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).2008 | 10.02 |
| | Xcel Energy Inc. Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).2008 | 10.05 |
| | Xcel Energy Inc. Non-Employee Directors’ Deferred Compensation Plan as amended and restated on Jan. 1, 2009 (Exhibit 10.08 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).2011 | 10.18 |
| | Xcel Energy Services Inc. and utility companies (Exhibit H-1 to Form U5B (file no. 001-03034) dated Nov. 16, 2000).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 of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).2008 | 10.17 |
| | | |
| | | |
| | | |
| | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008 | 10.07 |
| | Xcel Energy (file no. 001-03034) datedInc. Form 10-K for the year ended Dec. 3, 2004).31, 2011 | 10.17 |
| | Xcel Energy Senior Executive Severance and Change-in-Control Policy (Exhibit 10.06Inc. Form 10-K for the year ended Dec. 31, 2013 | 10.22 |
| | Xcel Energy (file no. 001-03034)Inc. Form 10-Q for the quarter ended Sept. 30, 2009).2016 | 10.01 |
| | | | | | | | | | | |
| | Xcel Energy Inc. Executive Annual Incentive Award Plan Form of Restricted Stock Agreement (Exhibit 10.08 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009).2017 | 10.1 |
| | Xcel Energy (file no. 001-03034) dated April 6, 2010).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, 2019 | 10.32 |
| | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2023 | 10.16 |
| | Xcel Energy Inc. Form 8-K dated Dec. 10, 2021 | 10.01 |
| | Xcel Energy (file no. 001-03034) dated April 6, 2010).Inc. Form 10-K for the year ended Dec. 31, 2023 | 10.18 |
| | Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2023 | 10.01 |
| | Xcel Energy Inc. Definitive Proxy Statement (file no. 001-03034) filed Apr.dated April 5, 2011).2011 | Appendix A |
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|
| |
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| | Xcel Energy Inc. 2015 Omnibus Incentive Plan. (Exhibit 10.03 to Form 8-K of Xcel Energy, dated May 26, 2015 (file no. 001-03034). |
| 2018 | 10.36 |
| | Xcel Energy Inc. Executive Annual Incentive Award Sub-plan pursuant to the Xcel Energy Inc. 2015 Omnibus Incentive Plan. (Exhibit 10.29 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2015).U5B dated Nov. 16, 2000 | H-1 |
| |
| SecondFourth Amended and Restated Credit Agreement, dated as of June 20, 2016September 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, and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Documentation Agents. (Exhibit 99.03 to Form 8-K of Xcel Energy dated June 20, 2016 (file no. 001-03034)).Agents |
| 19, 2022 | 99.03 |
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|
|
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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 |
101101.SCH | The following materials from PSCo’s Annual Report on Form 10-K for the year ended Dec. 31, 2017 are formattedInline 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 XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statements of Income, (ii) the Consolidated Statements of Comprehensive Income, (iii) the Consolidated Statements of Cash Flows, (iv) the Consolidated Balance Sheets, (v) the Consolidated Statements of Stockholder’s Equity, (vi) the Consolidated Statements of Capitalization, (vii) Notes to Consolidated Financial Statements, (viii) document and entity information, and (ix) Schedule II.Exhibit 101) |
SCHEDULE II
PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
YEARS ENDED DEC. 31, 2017, 2016 AND 2015
(amounts in thousands)
|
| | | | | | | | | | | | | | | | | | | |
| | | | Additions | | | | |
| | Balance at Jan. 1 | | Charged to Costs and Expenses | | Charged to Other Accounts(a) | | Deductions from Reserves(b) | | Balance at Dec. 31 |
| Allowance for bad debts: | | | | | | | | | |
| 2017 | $ | 19,612 |
| | $ | 14,303 |
| | $ | 3,968 |
| | $ | 18,277 |
| | $ | 19,606 |
|
| 2016 | 20,122 |
| | 14,121 |
| | 4,447 |
| | 19,078 |
| | 19,612 |
|
| 2015 | 23,122 |
| | 13,052 |
| | 5,175 |
| | 21,227 |
| | 20,122 |
|
| | | | | | | | | | | | | | | | | | | | |
| | Allowance for bad debts |
| (Millions of Dollars) | | 2023 | | 2022 | | 2021 |
| Balance at Jan. 1 | | $ | 54 | | | $ | 40 | | | $ | 29 | |
| Additions charged to costs and expenses | | 34 | | | 38 | | | 26 | |
Additions charged to other accounts (a) | | 5 | | | 18 | | | 4 | |
Deductions from reserves (b) | | (37) | | | (42) | | | (19) | |
| Balance at Dec. 31 | | $ | 56 | | | $ | 54 | | | $ | 40 | |
(a)Recovery of amounts previously written-off.
(b)Deductions related primarily to bad debt write-offs.
| | |
(a)
| Recovery of amounts previously written off.Item 16 — Form 10-K Summary |
| |
(b)
| Deductions relate primarily to bad debt write-offs. |
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.
| | | | | | | | |
| | |
| | PUBLIC SERVICE COMPANY OF COLORADO |
| | |
| Feb. 21, 2024 | | /s/ BRIAN J. VAN ABEL |
| Feb. 23, 2018 |
/s/ ROBERT C. FRENZELBrian J. Van Abel |
| | Robert C. Frenzel |
| | Executive Vice President, Chief Financial Officer and Director |
| | (Principal Financial Officer) |
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.
| | | | | | | | |
| /s/ ROBERT C. FRENZEL | | /s/ ROBERT S. KENNEY |
| Robert C. Frenzel | | Robert S. Kenney |
/s/ BEN FOWKE | | /s/ DAVID L. EVES |
Ben Fowke | | David L. Eves |
| Chairman, Chief Executive Officer and Director | | President and Director |
| (Principal Executive Officer) | | |
| | |
/s/ ROBERT C. FRENZELBRIAN J. VAN ABEL | | | /s/ JEFFREY S. SAVAGE
Robert C. FrenzelBrian 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)
| | |
| /s/ MARVIN E. MCDANIEL, JR. | |
| Marvin E. McDaniel, Jr. | |
| 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.
