0001123852nspm:RegulatedNaturalGasSegmentMemberus-gaap:IntersegmentEliminationMember2020-01-012020-12-31
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
| | | | | |
| ☒ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 20202021 or
| | | | | |
| ☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from _____ to _____
| | |
| 001-31387 |
| (Commission File Number) |
| | |
| Northern States Power Company |
Minnesota |
| (Exact name of registrant as specified in its charter) |
| | | | | | | | | | | | | | |
| Minnesota | | 41-1967505 |
(State or other jurisdictionOther Jurisdiction of incorporationIncorporation or organization)Organization) | | (I.R.S.IRS Employer Identification No.) |
| | | | |
| 414 Nicollet Mall | Minneapolis | Minnesota | | 55401 |
(Address of principal executive offices)Principal Executive Offices) | | (Zip Code) |
| | | | | |
| (612) | 330-5500 |
(Registrant’s telephone number, including area code)Telephone Number, Including Area Code) |
Securities registered pursuant to Section 12(b) of the Act:
| | | | | | | | | | | | | | |
| Title of each class | | Trading SymbolSymbol(s) | | Name of each exchange on which registered |
| N/A | | N/A | | N/A |
Securities registered pursuant to section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. ☒ Yes ☐ No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. ☐ Yes ☒ No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ☒ Yes ☐ No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). ☒ Yes ☐ No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company”, and “emerging growth company” in Rule 12b-2 of the Exchange Act. ☐ Large accelerated filer ☐ Accelerated filer ☒ Non-accelerated filer ☐ Smaller reporting company ☐ Emerging growth company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
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. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). ☐ Yes ☒ No
As of Feb. 17, 2021,23, 2022, 1,000,000 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 20212022 Annual Meeting of Shareholders which definitive Proxy Statement is expected to be filed with the SEC on or about April 6, 2021.5, 2022. Such information set forth under such heading is incorporated herein by this reference hereto.
Northern States Power Company meets the conditions set forth in General Instructions I(1)(a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format permitted by General Instruction I(2).
TABLE OF CONTENTS
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| PART I | | |
| Item 1 — | | |
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| Item 1A — | | |
| Item 1B — | | |
| Item 2 — | | |
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PartPART II | | |
| Item 5 — | | |
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| Item 7 — | | |
| Item 7A — | | |
| Item 8 — | | |
| Item 9 — | | |
| Item 9A — | | |
| Item 9B — | | |
| Item 9C — | | |
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PartPART III | | |
| Item 10 — | | |
| Item 11 — | | |
| Item 12 — | | |
| Item 13 — | | |
| Item 14 — | | |
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PartPART IV | | |
| Item 15 — | | |
| Item 16 — | | |
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This Form 10-K is filed by NSP-Minnesota. NSP-Minnesota 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
Definitions of Abbreviations
| | | | | |
| Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former) |
| NSP-Minnesota | Northern States Power Company, a Minnesota corporation |
| NSP System | The electric production and transmission system of NSP-Minnesota and NSP-Wisconsin operated on an integrated basis and managed by NSP-Minnesota |
| NSP-Wisconsin | Northern States Power Company, a Wisconsin corporation |
| PSCo | Public Service Company of Colorado |
| SPS | Southwestern Public Service Company |
| Utility subsidiaries | NSP-Minnesota, NSP-Wisconsin, PSCo and SPS |
| Xcel Energy | Xcel Energy Inc. and its subsidiaries |
| | | | | |
| Federal and State Regulatory Agencies |
D.C. Circuit | United States Court of Appeals for the District of Columbia Circuit |
| DOC | Minnesota Department of Commerce |
| DOE | United States Department of Energy |
| DOT | United States Department of Transportation |
| EPA | United States Environmental Protection Agency |
| FERC | Federal Energy Regulatory Commission |
| IRS | Internal Revenue Service |
Minnesota District Court | U.S. District Court for the District of Minnesota |
| MPUC | Minnesota Public Utilities Commission |
| NDPSC | North Dakota Public Service Commission |
| NERC | North American Electric Reliability Corporation |
| NRC | Nuclear Regulatory Commission |
| PHMSA | Pipeline and Hazardous Materials Safety Administration |
SDPUC | South Dakota Public Utilities Commission |
| SEC | Securities and Exchange Commission |
| | | | | |
| Electric, Purchased Gas and Resource Adjustment Clauses |
| CIP | Conservation improvement program |
| DSM | Demand side management |
EIR | Environmental improvement rider |
| FCA | Fuel clause adjustment |
| GUIC | Gas utility infrastructure cost rider |
PGA | Purchased gas adjustment |
RDF | Renewable development fund |
RER | Renewable energy rider |
| RES | Renewable energy standard |
SEP | State energy policy rider |
| TCR | Transmission cost recovery adjustment |
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| Other |
ADIT | Accumulated deferred income taxes |
| AFUDC | Allowance for funds used during construction |
ALLETEALJ | ALLETE, Inc.Administrative Law Judge |
| ARO | Asset retirement obligation |
| ASC | FASB Accounting Standards Codification |
ASU | FASB Accounting Standards Update |
| C&I | Commercial and Industrial |
| CapX2020 | Alliance of electric cooperatives, municipals and investor-owned utilities in the upper Midwest involved in a joint transmission line planning and construction effort |
| CCR | Coal combustion residuals |
| CCR Rule | Final rule (40 CFR 257.50 - 257.107) published by the EPA regulating the management, storage and disposal of CCRs as a nonhazardous waste |
| CEO | Chief executive officer |
| CFO | Chief financial officer |
| CON | Certificate of Need |
| COVID-19 | Novel coronavirus |
| | | | | |
COVID-19 | Novel coronavirus |
| CWA | Clean Water Act |
| CWIP | Construction work in progress |
| D.C. Circuit | United States Court of Appeals for the District of Columbia Circuit |
| ELG | Effluent limitations guidelines |
| EMANI | European Mutual Association for Nuclear Insurance |
| ETR | Effective tax rate |
| FASB | Financial Accounting Standards Board |
| FTR | Financial transmission right |
| GAAP | Generally accepted accounting principles |
| GE | General Electric |
| GHG | Greenhouse gas |
| INPO | Institute of Nuclear Power Operations |
| IPP | Independent power producing entity |
| ISO | Independent System Operators |
| ITC | Investment tax credit |
| MGP | Manufactured gas plant |
| MISO | Midcontinent Independent System Operator, Inc. |
| Moody’s | Moody’s Investor Services |
| Native load | Customer demand of retail and wholesale customers that a utility has an obligation to serve under statute or long-term contract |
| NAV | Net asset value |
| NEIL | Nuclear Electric Insurance Ltd. |
| NOL | Net operating loss |
| NOPR | Notice of proposed rulemaking |
| O&M | Operating and maintenance |
Paris AgreementOAG | Establishes a framework for GHG mitigation actions by all countries (“nationally determined contributions”)Minnesota Office of the Attorney General |
| PFAS | Per- and PolyFluoroAlkyl Substances |
| PI | Prairie Island nuclear generating plant |
| PPA | Purchased power agreement |
| PTC | Production tax credit |
| REC | Renewable energy credit |
| ROE | Return on equity |
ROFR | Right-of-first-refusal |
| ROU | Right-of-use |
| RTO | Regional Transmission Organization |
| S&P | Standard & Poor’s Global Ratings |
| SERP | Supplemental executive retirement plan |
SMMPA | Southern Minnesota Municipal Power Agency |
| TCJA | 2017 federal tax reform enacted as Public Law No: 115-97, commonly referred to as the Tax Cuts and Jobs Act |
| TO | Transmission owner |
| VaR | Value at Risk |
| VIE | Variable interest entity |
WOTUS | Waters of the U.S. |
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| Measurements |
| Bcf | Billion cubic feet |
| KV | Kilovolts |
| KWh | Kilowatt hours |
| MMBtu | Million British thermal units |
| MW | Megawatts |
| MWh | Megawatt hours |
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| Forward-Looking Statements |
Except for the historical statements contained in this report, the matters discussed herein are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements, including those relating to future sales, future bad debt expense,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 expectationsintentions regarding regulatory proceedings, and expected impact on our results of operations, financial condition and cash flows of resettlement calculations and credit losses relating to certain energy transactions, as well as assumptions and other statements are intended to be identified in this document by the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” “will,” “would” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we expressly disclaim any obligation to update any forward-looking information.
The following factors, in addition to those discussed elsewhere in this Annual Report on Form 10-K for the fiscal year ended Dec. 31, 20202021 (including risk factors listed from time to time by NSP-Minnesota in reports filed with the SEC, including “Risk Factors” in Item 1A of this Annual Report on Form 10-K hereto), could cause actual results to differ materially from management expectations as suggested by such forward-looking information: uncertainty around the impacts and duration of the COVID-19 pandemic;pandemic, including potential workforce impacts resulting from vaccination requirements, quarantine policies of government restrictions, and sales volatility; operational safety, including our nuclear generation facilities; successful long-term operational planning; commodity risks associated with energy markets and production; rising energy prices and fuel costs; qualified employee work force and third-party contractor factors; violations of our Code of Conduct; ability to recover costs; changes in regulation; reductions in our credit ratings and the cost of maintaining certain contractual relationships; general economic conditions, including inflation rates, monetary fluctuations, supply chain constraints and their impact on capital expenditures andand/or the ability of NSP-Minnesota and its subsidiaries to obtain financing on favorable terms; availability or cost of capital; our customers’ and counterparties’ ability to pay their debts to us; assumptions and costs relating to funding our employee benefit plans and health care benefits; tax laws; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; seasonal weather patterns; changes in environmental laws and regulations; climate change and other weather; natural disaster and resource depletion, including compliance with any accompanying legislative and regulatory changes; and costs of potential regulatory penalties.penalties; and regulatory changes and/or limitations related to the use of natural gas as an energy source.
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| Where to Find More Information |
NSP-Minnesota is a wholly owned subsidiary of Xcel Energy Inc., and Xcel Energy’s website address is www.xcelenergy.com. Xcel Energy makes available, free of charge through its website, its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after the reports are electronically filed with or furnished to the SEC. The SEC maintains an internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically at http://www.sec.gov. The information on Xcel Energy’s website is not a part of, or incorporated by reference in, this annual report on Form 10-K.
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| Electric customers | 1.5 million | | | | NSP-Minnesota was incorporated in 2000 under the laws of Minnesota. NSP-Minnesota conducts business in Minnesota, North Dakota and South Dakota and has electric operations in all three states including the generation, purchase, transmission, distribution and sale of electricity. NSP-Minnesota and NSP-Wisconsin electric operations are managed on the NSP System. NSP-Minnesota also purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas in Minnesota and North Dakota. |
| Natural gas customers | 0.60.5 million | | |
| Total assets | $21.122.8 billion | | |
| Rate Base (estimated) | $12.413.7 billion | | |
| ROE (net income / average stockholder's equity) | 9.20%8.45% | | |
| Electric generating capacity | 8,1378,628 MW | | |
| Gas storage capacity | 17.1 Bcf | | |
| Electric transmission lines (conductor miles) | 33,66034,155 miles | | |
| Electric distribution lines (conductor miles) | 80,50881,406 miles | | |
| Natural gas transmission lines | 8085 miles | | |
| Natural gas distribution lines | 10,62910,741 miles | | | |
Electric operations consist of energy supply, generation, transmission and distribution activities. NSP-Minnesota had electric sales volume of 33,73845,269 (millions of KWh), 1.5 million customers and electric revenues of $4,571$5,094 (millions of dollars) for 2020.2021.
Retail Sales/Revenue Statistics (a)
| | | 2020 | | 2019 | | 2021 | | 2020 |
| KWH sales per retail customer | KWH sales per retail customer | | 21,440 | | | 22,405 | | KWH sales per retail customer | | 21,644 | | | 21,440 | |
| Revenue per retail customer | Revenue per retail customer | | $ | 2,306 | | | $ | 2,368 | | Revenue per retail customer | | $ | 2,507 | | | $ | 2,306 | |
| Residential revenue per KWh | Residential revenue per KWh | | 13.36 | ¢ | | 13.22 | ¢ | Residential revenue per KWh | | 13.7 | ¢ | | 13.36 | ¢ |
| Large C&I revenue per KWh | Large C&I revenue per KWh | | 7.93 | ¢ | | 7.96 | ¢ | Large C&I revenue per KWh | | 8.96 | ¢ | | 7.93 | ¢ |
| Small C&I revenue per KWh | Small C&I revenue per KWh | | 10.24 | ¢ | | 10.15 | ¢ | Small C&I revenue per KWh | | 11.34 | ¢ | | 10.24 | ¢ |
| Total retail revenue per KWh | Total retail revenue per KWh | | 10.76 | ¢ | | 10.57 | ¢ | Total retail revenue per KWh | | 11.58 | ¢ | | 10.76 | ¢ |
(a) See Note 6 to the consolidated financial statements for further information.
Owned and Purchased Energy Generation — 20202021
Electric Energy Sources
Total electric energy generation by source (including energy market purchases) for the year ended Dec. 31, 2020:2021:
*Distributed generation from the Solar*Rewards® program is not included (approximately 4334 million KWh for 2020)2021). Carbon–Free Energy — NSP System
The NSP System’s carbon–free energy portfolio includes nuclear, wind, hydroelectric, biomass and solar power from both owned generating facilities and PPAs. Carbon–free percentages will vary year over year based on system additions, commodity costs, weather, system demand and transmission constraints.
See Item 2 — Properties for further information.
Carbon–free energy as a percentage of total energy for 2020:2021:
* Includes biomass and hydroelectric
Wind
Owned — Owned and operated wind farms with corresponding capacity:
| | | | | | | | | | | | | | | | | | | | |
| 2020 | | 2019 |
| Wind Farms | | Capacity (a) | | Wind Farms | | Capacity (b) |
| 11 | | 1,540 MW | | 7 | | 1,079 MW |
| | | | | | | | | | | | | | | | | | | | |
| 2021 | | 2020 |
| Wind Farms | | Capacity (a) | | Wind Farms | | Capacity (b) |
| 14 | | 2,031 MW | | 11 | | 1,540 MW |
(a)Summer 20202021 net dependable capacity.
(b)Summer 20192020 net dependable capacity.
PPAs — Number of PPAs with capacity range: | | | | | | | | | | | | | | | | | | | | |
| 2020 | | 2019 |
| PPAs | | Range | | PPAs | | Range |
| 129 | | 1 MW — 206 MW | | 131 | | 1 MW — 206 MW |
| | | | | | | | | | | | | | | | | | | | |
| 2021 | | 2020 |
| PPAs | | Range | | PPAs | | Range |
| 128 | | 1 MW — 206 MW | | 129 | | 1 MW — 206 MW |
Capacity — Wind capacity:
Capacity — Wind capacity:
Average Cost (Owned) — Average cost per MWh of wind energy from owned generation:
Average Cost (PPAs) — Average cost per MWh of wind energy under existing PPAs:
Wind Development
NSP-SystemThe NSP System placed approximately 460500 MW of owned wind and a 200approximately 255 MW PPAof PPAs into service during 2020:2021:
| | | | | | | | |
| Project | | Capacity (MW) |
Blazing Star 12 | | 200 MW (a)(b) |
Crowned Ridge 2Freeborn | | 192 MW200 (a)(b)
|
Community Wind NorthMower | | 26 MW(a)(b)
|
Jeffers | | 43 MW91 (a)(b)
|
| PPA | | 200 MW~255 (c)
|
(a)Summer 20202021 net dependable capacity.
(b)Values disclosed are the maximum generation levels for these wind units. Capacity is attainable only when wind conditions are sufficiently available (on-demand net dependable capacity is zero).
(c)Based on contracted capacity.
NSP-SystemThe NSP System currently has approximately 1,4501,050 MW of owned wind under development or construction.being repowered. In addition, the NSP-SystemNSP System expects to add approximately 450200 MW of planned PPAs.
| | | | | | | | | | | | | | |
Project | | | | | | | | | | | | | | | | Project | | Capacity (MW) | | Estimated Completion | | Northern Wind | | 100 | | 2022 | | Nobles | | 200 | | 2022 | | Dakota Range | | 300 | | 2022 (a) | | Grand Meadow | | 100 | | 2023 | | Border Winds | | 150 | | 2025 | | Pleasant Valley | | 200 | | 2025 | | Various PPAs | | ~200 | | 2022 |
(a) Placed in service in January 2022. | | Capacity | | Estimated Completion |
Dakota Range | | 300 MW | | 2021 |
Freeborn | | 200 MW | | 2021 |
Blazing Star 2 | | 200 MW | | 2021 |
Nobles | | 200 MW | | 2022 |
Pleasant Valley | | 200 MW | | 2024 |
Border Winds | | 150 MW | | 2024 |
Grand Meadow | | 100 MW | | 2023 |
Mower | | 99 MW | | 2021 |
Various PPAs | | ~450 MW | | 2021 |
Solar
Solar energy PPAs:PPA(s): | | | | | | | | |
| Type | | Capacity (MW) |
| Distributed Generation | | 899 MW994 |
| Utility-Scale | | 268 MW |
| Total | | 1,167 MW1,262 |
Average Cost (PPAs) — Average cost per MWh of solar energy under existing PPAs:
Solar Development
In June 2021, the PSCW approved NSP-Wisconsin’s request to purchase the 74 MW Western Mustang build-own-transfer solar facility for approximately $100 million. Also, as part of the Minnesota Recovery and Relief Recovery docket, NSP-Minnesota proposed to add 460 MW of solar facilities at the Sherco site with an incremental investment of approximately $575 million. An MPUC decision is expected by the third quarter of 2022.
Nuclear
The NSP System has two nuclear plants (owned by NSP-Minnesota) with approximately 1,700 MW of total 20202021 net summer dependable capacity. NSP-Minnesota secures contracts for uranium concentrates, uranium conversion, uranium enrichment and fuel fabrication to operate its nuclear plants. NSP-Minnesota uses varying contract lengths as well as multiple producers for uranium concentrates, conversion services and enrichment services to minimize potential impacts caused by supply interruptions due to geographical and world political issues.
Nuclear Fuel Cost
Delivered cost per MMBtu of nuclear fuel consumed for owned electric generation and the percentage of total fuel requirements:
| | | Nuclear | | Nuclear |
| | | Cost | | Percent | | | Cost | | Percent |
| 2021 | | 2021 | | $ | 0.77 | | | 46 | % |
| 2020 | 2020 | | $ | 0.80 | | | 51 | % | 2020 | | 0.80 | | | 51 | |
| 2019 | | 0.81 | | | 45 | | |
Other Carbon-Free Energy
NSP-System’sThe NSP System’s other carbon-free energy portfolio includes hydro from owned generating facilities.
See Item 2 — Properties for further information.
Fossil Fuel Energy — NSP System
The NSP System’s fossil fuel energy portfolio includes coal and natural gas power from both owned generating facilities and PPAs.
See Item 2 — Properties for further information.
Coal
The NSP System owns and operates coal units with approximately 2,400 MW of total 20202021 net summer dependable capacity.
Approved and proposed early coal plant retirements: | | | | | | | | | | | | | | |
Approved |
Year | | Plant Unit | | Capacity |
2023 | | Sherco 2 | | 682 MW |
2026 | | Sherco 1 | | 680 MW |
| | | | | | | | | | | | | | |
Proposed |
Year | | Plant Unit | | Capacity |
2028 | | A.S. King | | 511 MW |
2030 | | Sherco 3 | | 517 MW (a)
|
| | | | | | | | | | | | | | |
| Year | | Plant Unit | | Capacity (MW) |
| 2023 | | Sherco 2 | | 682 |
| 2026 | | Sherco 1 | | 680 |
| 2028 | | A.S. King | | 511 |
| 2030 | | Sherco 3 | | 517 (a) |
(a) Based on the NSP System’s ownership interest.
Coal Fuel Cost
Delivered cost per MMBtu of coal consumed for owned electric generation and the percentage of total fuel requirements:
| | | Coal (a) | | Coal (a) |
| | Cost | | Percent | | Cost | | Percent |
| | 2021 | | 2021 | | $ | 1.60 | | | 39 | % |
| 2020 | 2020 | | $ | 1.97 | | | 31 | % | 2020 | | 1.97 | | | 31 | |
| 2019 | | 2.02 | | | 36 | | |
(a) Includes refuse-derived fuel and wood.
Natural Gas
The NSP System has eight natural gas plants with approximately 2,800 MW of total 20202021 net summer dependable capacity.
Natural gas supplies, transportation and storage services for power plants are procured to provide an adequate supply of fuel. Remaining requirements are procured through a liquid spot market. Generally, natural gas supply contracts have variable pricing that is tied to natural gas indices. Natural gas supply and transportation agreements include obligations for the purchase and/or delivery of specified volumes or payments in lieu of delivery.
Natural Gas Cost
Delivered cost per MMBtu of natural gas consumed for owned electric generation and the percentage of total fuel requirements:
| | | Natural Gas | | Natural Gas |
| | Cost | | Percent | | Cost | | Percent |
2021 (a) | | 2021 (a) | | $ | 4.98 | | | 15 | % |
| 2020 | 2020 | | $ | 2.67 | | | 17 | % | 2020 | | 2.67 | | | 17 | |
| 2019 | | 3.09 | | | 19 | | |
(a)Reflective of Winter Storm Uri.
Capacity and Demand
Uninterrupted system peak demand and occurrence date:
| | | | | | | | | | | | | | | | | | | | |
| System Peak Demand (in MW) |
| 2020 | | 2019 |
| 8,571 | | | July 8 | | 8,774 | | | July 19 |
| | | | | | | | | | | | | | | | | | | | |
| System Peak Demand (MW) |
| 2021 | | 2020 |
| 8,837 | | | June 9 | | 8,571 | | | July 8 |
Transmission
Transmission lines deliver electricity over long distances from power sources to transmission substations closer to homes and businesses.customers. A strong transmission system ensures continued reliable and affordable service, ability to meet state and regional energy policy goals, and support for a diverse generation mix, including renewable energy. NSP-Minnesota owns more than 33,50034,000 conductor miles of transmission lines across its service territory.
During 2020, NSP-MinnesotaTransmission projects completed the following transmissionin 2021 include:
| | | | | | | | | | | | | | |
| Project | | Miles | | Size (KV) |
| Hibbing Taconite Relocation | | 3 | | | 500 | |
| Huntley - Wilmarth | | 50 | | | 345 | |
| Helena Scott County | | 16 | | | 345 | |
| Centerville to Lincoln County | | 14 | | | 69 | |
Notable upcoming projects:
| | | | | | | | | | | | | | |
Project | | Miles | | Size |
Maple River-Red River | | 4 | | | 115 KV |
Glenwood Douglas | | 20 | | | 69 KV |
| | | | | | | | | | | | | | | | | | | | |
| Project | | Miles | | Size (KV) | | Completion Date |
| Baytown to Long Lake | | 9 | | | 115 | | | 2022 |
| Bird Island - Atwater - Big Swan | | 68 | | | 69 | | | 2022 |
| Pipestone - Tracy | | 46 | | | 69 | | | 2022 |
| Line Rebuild - Central | | 24 | | | 69 | | | 2022 |
| West St. Cloud to Millwood Tap | | 24 | | | 69 | | | 2022 |
Upcoming transmission projects:
| | | | | | | | | | | | | | | | | | | | |
| Project | | Miles | | Size | | Completion Date |
| Hibbing Taconite Relocation | | 3 | | | 500 KV | | 2021 |
| Huntley-Wilmarth | | 50 | | | 345 KV | | 2021 |
| Helena Scott County | | 16 | | | 345 KV | | 2021 |
| Baytown to Long lake | | 9 | | | 115 KV | | 2022 |
| Centerville to Lincoln County | | 14 | | | 69 KV | | 2021 |
Distribution
Distribution lines allow electricity to travel at lower voltages from substations directly to homes and businesses.customers. NSP-Minnesota has a vast distribution network, owning and operating approximately 81,000 conductor miles of distribution lines across our service territory, both above ground and underground.territory. To continue providing reliable, affordable electric service and enable more flexibility for customers, we are working to digitize the distribution grid, while at the same time keeping it secure.
See Item 2 - Properties for further information.
Natural gas operations consist of purchase, transportation and distribution of natural gas to end-use residential, C&I and transport customers. NSP-Minnesota had natural gas deliveries of 98,711 94,802 (thousands of MMBtu), 0.60.5 million customers and natural gas revenues of $493 (millionsof $623 (millions of dollars) for 2020.2021.
Sales/Revenue Statistics (a)
| | | 2020 | | 2019 | | 2021 | | 2020 |
| MMBtu sales per retail customer | MMBtu sales per retail customer | | 159.30 | | | 176.96 | | MMBtu sales per retail customer | | 149 | | | 159 | |
| Revenue per retail customer | Revenue per retail customer | | $ | 901.93 | | | $ | 1,072.29 | | Revenue per retail customer | | $ | 1,121 | | | $ | 902 | |
| Residential revenue per MMBtu | Residential revenue per MMBtu | | 6.66 | | | 7.04 | | Residential revenue per MMBtu | | 8.56 | | | 6.66 | |
| C&I revenue per MMBtu | C&I revenue per MMBtu | | 4.69 | | | 5.12 | | C&I revenue per MMBtu | | 6.53 | | | 4.69 | |
| Transportation and other revenue per MMBtu | Transportation and other revenue per MMBtu | | 0.97 | | | 0.59 | | Transportation and other revenue per MMBtu | | 1.29 | | | 0.97 | |
(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:
| | | | | | | | | | | | | | | | | | | | |
| 2020 | | 2019 |
| MMBtu | | Date | | MMBtu | | Date |
| 871,921 | | | Jan. 16 | | 897,615 | | | Feb. 25 |
| | | | | | | | | | | | | | | | | | | | |
| 2021 | | 2020 |
| MMBtu | | Date (a) | | MMBtu | | Date |
| 899,133 | | | Feb. 11 | | 871,921 | | | Jan. 16 |
(a)Reflective of Winter Storm Uri.
Natural Gas Supply and Costs
NSP-Minnesota seeks natural gas supply, transportation and storage alternatives to yield a diversified portfolio, which increaseincreases flexibility decreaseand decreases interruption and financial risks and economical rates. In addition, NSP-Minnesota conducts natural gas price hedging activities approved by its states’ commissions.
Average delivered cost per MMBtu of natural gas for regulated retail distribution:
| | 2020 | | 2019 | |
2021 (a) | | 2021 (a) | | 2020 |
| $ | 3.32 | | | $ | 3.71 | | 7.48 | | | $ | 3.32 | |
(a)Reflective of Winter Storm Uri.
NSP-Minnesota 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, NSP-Minnesota’s operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer.
Competition
NSP-Minnesota is subject to public policies that promote competition and development of energy markets. NSP-Minnesota’s industrial and large commercial customers have the ability to generate their own electricity. In addition, customers may have the option of substituting other fuels or relocating their facilities to a lower cost region.
Customers have the opportunity to supply their own power with distributed generation including solar generation and in most jurisdictions can currently avoid paying for most of the fixed production, transmission and distribution costs incurred to serve them.
Minnesota has incentives for the development of rooftop solar, community solar gardens and other distributed energy resources. Distributed generating resources are potential competitors to NSP-Minnesota’s electric service business with these incentives and federal tax subsidies.
The FERC has continued to promote competitive wholesale markets through open access transmission and other means. NSP-Minnesota’s wholesale customers can purchase their output from generation resources of competing suppliers or non-contracted quantities and use the transmission system of NSP-Minnesota on a comparable basis to serve their native load.
FERC Order No. 1000 established competition for construction and operationownership of certain new electric transmission facilities. State utilities commissionsfacilities under Federal regulations. Some states have also createdstate laws that allow the incumbent a Right of First Refusal to own these transmission facilities.
FERC Order 2222 requires that RTO and ISO markets allow participation of aggregations of distributed energy resources. This order is expected to incentivize distributed energy resource planning programs that promote competition for electricity generation resources usedadoption, however implementation is expected to provide service to retail customers.vary by RTO/ISO and the near, medium, and long-term impacts of Order 2222 remain unclear.
NSP-Minnesota 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, NSP-Minnesota believes its rates and services are competitive with alternatives currently available.
Public Utility Regulation
See Item 7 for discussion of public utility regulation.
Environmental Regulation
Our facilities are regulated by federal and state agencies that have jurisdiction over air emissions, water quality, wastewater discharges, solid wastes and hazardous wastes or substances. Certain NSP-Minnesota activities require registrations, permits, licenses, inspections and approvals from these agencies. NSP-Minnesota has received necessary authorizations for the construction and continued operation of its generation, transmission and distribution systems. Our facilities strive to operate in compliance with applicable environmental standards and related monitoring and reporting requirements. However, it is not possible to determine when or to what extent additional facilities or modifications of 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 MGP and other sites if it is determined that prior compliance efforts are not sufficient.sites.
NSP-Minnesota must comply with emission levels that may require the purchase of emission allowances.
There are significant environmental regulations to encourage use of clean energy technologies and regulate emissions of GHGs. NSP-Minnesota 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.
In July 2019, the EPA adopted the Affordable Clean Energy rule, which requiredrequires states to develop plans by 2022 for GHG reductions from coal-fired power plants. In a Jan. 19,January 2021, decision, the U.S. Court of Appeals for the D.C. Circuit issued a decision vacating and remanding the Affordable Clean Energy rule. That decision if not successfully appealed or reconsidered, would allow the EPA to proceed with alternate regulation of coal-fired power plants, either revivingplants. However, the Clean Power Plan or proposing additional regulation. ItCourt of Appeals decision is too earlynow before the U.S. Supreme Court, where the Court is expected to predict an outcome, butrule on the nature and extent of the EPA’s GHG regulatory authority. If any new rules could require substantial additional investment, even in plants slated for retirement. NSP-Minnesota believes based on prior state commission practices,that the cost of these initiatives or replacement generation would be recoverable through rates.
rates based on prior state commission practices. NSP-Minnesota seeks to address climate change and potential climate change regulation through efforts to reduce its GHG emissions in a balanced, cost-effective manner.
Emerging Environmental Regulation
New regulations and legislation are being considered to regulate PFAS in drinking water, water discharges, commercial products, wastes, and other areas. PFAS are man-made chemicals found in many consumer products that can persist and accumulate in the environment. These chemicals have received heightened attention from environmental regulators. Increased regulation of PFAS and other emerging contaminants at the federal, state, and local level could have a potential adverse effect on our operations but at this time, it is uncertain what impact, if any, there will be on our operations, financial condition or cash flows. NSP-Minnesota will continue to monitor these regulatory developments and their potential impact on its operations.
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, 2020,2021, NSP-Minnesota had 3,1443,083 full-time employees and eightfive part-time employees, of which 2,0332,020 were covered under collective-bargaining agreements.
Xcel Energy, which includes NSP-Minnesota, is subject to a variety of risks, many of which are beyond our control. Risks that may adversely affect the business, financial condition, results of operations or cash flows are described below. Although the risks are organized by heading, and each risk is described separately, many of the risks are interrelated. These risks should be carefully considered together with the other information set forth in this report and future reports that Xcel Energy files with the SEC. You should not interpret the disclosure of any risk factor to imply that the risk has not already materialized. While we believe we have identified and discussed below the key risk factors affecting our business, there may be additional risks and uncertainties that are not presently known or that are not currently believed to be significant that may adversely affect our business, financial condition, results of operations or cash flows in the future.
Oversight of Risk and Related Processes
NSP-Minnesota’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.
At a threshold level, NSP-Minnesota 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. NSP-Minnesota 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 and security risks.
Overall,The oversight, management and mitigation of risk is an integral and continuous part of the Board of Directors’ governance of NSP-Minnesota. Processes are in place to ensure appropriate risk oversight, as well as identification and consideration of new risks.
Risks Associated with Our Business
Operational Risks
Our natural gas and electric generation/transmission and distribution operations involve numerous risks that may result in accidents and other operating risks and costs.
Our natural gas transmission and distribution activities include inherent hazards and operating risks, such as leaks, explosions, outages and mechanical problems. Our electric generation, transmission and distribution activities include inherent hazards and operating risks such as contact, fire and outages. These risks could result in loss of life, significant property damage, environmental pollution, impairment of our operations and substantial financial losses.losses to employees, third-party contractors, customers or the public. We maintain insurance against most, but not all, of these risks and losses. The occurrence of these events, if not fully covered by insurance, could have a material effect on our financial condition, results of operations and cash flows.flows as well as potential loss of reputation.
Other uncertainties and risks inherent in operating and maintaining NSP-Minnesota's facilities include, but are not limited to:
•Risks associated with facility start-up operations, such as whether the facility will achieve projected operating performance on schedule and otherwise as planned.
•Failures in the availability, acquisition or transportation of fuel or other necessary supplies.
•The impact of unusual or adverse weather conditions and natural disasters, including, but not limited to, tornadoes, icing events, floods and droughts.
•Performance below expected or contracted levels of output or efficiency (e.g., performance guarantees).
•Availability of replacement equipment.
•Availability of adequate water resources and ability to satisfy water intake and discharge requirements.
•Inability to identify, manage properly or mitigate equipment defects.
•Use of new or unproven technology.
•Risks associated with dependence on a specific type of fuel or fuel source, such as commodity price risk, availability of adequate fuel supply and transportation and lack of available alternative fuel sources.
•Increased competition due to, among other factors, new facilities, excess supply, shifting demand and regulatory changes.
Additionally, compliance with existing and potential new regulations related to the operation and maintenance of our natural gas infrastructure could result in significant costs. The PHMSA is responsible for administering the DOT’s national regulatory program to assure the safe transportation of natural gas, petroleum and other hazardous materials by pipelines. The PHMSA continues to develop regulations and other approaches to risk management to assure safety in design, construction, testing, operation, maintenance and emergency response of natural gas pipeline infrastructure. We have programs in place to comply with these regulations and systematically monitor and renew infrastructure over time, however, a significant incident or material finding of non-compliance could result in penalties and higher costs of operations.
Our natural gas and electric transmission and distribution operations are dependent upon complex information technology systems and network infrastructure, the failure of which could disrupt our normal business operations, which could have a material adverse effect on our ability to process transactions and provide services.
Our utility operations are subject to long-term planning and project risks.
Most electric utility investments are planned to be used for decades. Transmission and generation investments typically have long lead times and are planned well in advance of in-service dates and typically subject to long-term resource plans. These plans are based on numerous assumptions such as: sales growth, customer usage, commodity prices, economic activity, costs, regulatory mechanisms, customer behavior, available technology and public policy. Our long-term resource plan is dependent on our ability to obtain required approvals, develop necessary technical expertise, allocate and coordinate sufficient resources and adhere to budgets and timelines.
In addition, the long-term nature of both our planning and our asset lives are subject to risk. The electric utility sector is undergoing significant change (e.g,(e.g., increases in energy efficiency, wider adoption of distributed generation and shifts away from fossil fuel generation to renewable generation). Customer adoption of these technologies and increased energy efficiency could result in excess transmission and generation resources, downward pressure on sales growth, and potentially stranded costs if we are not able to fully recover costs and investments.
Changing customer expectations and technologies are requiring significant investments in advanced grid infrastructure, which increases exposure to technology obsolescence. Additionally, evolving stakeholder preference for lower emissions from generation sources and end-uses, like heating, may put pressure on our ability to recover capital investments in natural gas generation and delivery.
The magnitude and timing of resource additions and changes in customer demand may not coincide with evolving customer preference for generation resources and end-uses, which introduces further uncertainty into long-term planning. Efforts to electrify the transportation and building sectors to reduce GHG emissions may result in higher electric demand and lower natural gas demand over time. Additionally, multipleHigher electric demand may require us to adopt new technologies and make significant transmission and distribution investments including advanced grid infrastructure, which increases exposure to overall grid instability and technology obsolescence. Evolving stakeholder preference for lower emissions from generation sources and end-uses, like heating, may impact our resource mix and put pressure on our ability to recover capital investments in natural gas generation and delivery. Multiple states may not agree as to the appropriate resource mix, which may lead to costs to comply with one jurisdiction that are not recoverable across all jurisdictions served by the same assets.
We are subject to longer-term availability of inputs such as coal, natural gas, uranium and water to cool our facilities. Lack of availability of these resources could jeopardize long-term operations of our facilities or make them uneconomic to operate.
Our utilities are highly dependent on suppliers to deliver components in accordance with short and long-term project schedules.
Our products contain components that are globally sourced from suppliers who, in turn, source components from their suppliers. A shortage of key components in which an alternative supplier is not identified could significantly impact project plans. Such impacts could include timing of projects, including 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.
In the event fuel costs increase, customer demand could decline and bad debt expense may rise, which may have a material impact on our results of operations. Despite existing fuel recovery mechanisms, higher fuel costs could significantly impact our results of operations if costs are not recovered. Delays in the timing of the collection of fuel cost recoveries could impact our cash flows and liquidity.
A significant disruption in supply could cause us to seek alternative supply services at potentially higher costs and supply shortages may not be fully resolved, which could cause disruptions in our ability to provide services to our customers. Failure to provide service due to disruptions may also result in fines, penalties or cost disallowances through the regulatory process. Also, significantly higher energy or fuel costs relative to sales commitments could negatively impact 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.
Due to the inherent uncertainty involved in price movements and potential deviation from historical pricing, NSP-Minnesota 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, NSP-Minnesota cannot fully assure that its controls will be effective against all potential risks, including, without limitation, employee misconduct. If such controlsprograms and procedures are not effective, NSP-Minnesota’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.
SpecializedIn 2021, the competition for talent has become increasingly intense as a result of the ongoing “great resignation”, and we may experience increased employee turnover due to this tightening labor market. In addition, specialized knowledge is required of our technical employees for construction and operation of transmission, generation and distribution assets. Our business strategy is dependent on our abilityassets, which may pose additional difficulty for us as we work to recruit, retain and motivate employees. There is competition and a tightening market for skilled employees.employees in this climate. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to new employees or future availability and cost of contract labor may adversely affect the ability to manage and operate our business. Inability to attract and retain these employees could adversely impact our results of operations, financial condition or cash flows.
Our operations use third-party contractors in addition to employees to perform periodic and ongoing work.
We rely on third-party contractors to perform operations, maintenance and construction work. Our contractual arrangements with these contractors typically include performance standards, progress payments, insurance requirements and security for performance. Poor vendor performance or contractor unavailability could impact ongoing operations, restoration operations, 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.
TableWe are exposed to risk of Contentsemployee or third-party contractor fraud or other misconduct. All employees and members of the Board of Directors are subject to comply with our Code of Conduct and are required to participate in annual training. Additionally, suppliers are subject to comply with our supplier Code of Conduct. NSP-Minnesota 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 subject to the risks of nuclear generation.
NSP-Minnesota has two nuclear generation plants, PI and Monticello. Risks of nuclear generation include:
•Hazards associated with the use of radioactive material in energy production, including management, handling, storage and disposal.
•Limitations on insurance available to cover losses that may arise in connection with nuclear operations, as well as obligations to contribute to an insurance pool in the event of damages at a covered U.S. reactor.
•Technological and financial uncertainties related to the costs of decommissioning nuclear plants may cause our funding obligations to change.
The NRC has authority to impose licensing and safety-related requirements for the operation of nuclear generation facilities, including the ability to impose fines and/or shut down a unit until compliance is achieved. NRC safety requirements could necessitate substantial capital expenditures or an increase in operating expenses. In addition, the INPO reviews our nuclear operations. Compliance with the INPO’s recommendations could result in substantial capital expenditures or a substantial increase in operating expenses.
If a nuclear incident did occur, it could have a material impact on our results of operations, financial condition or cash flows. Furthermore, non-compliance or the occurrence of a serious incident at other nuclear facilities could result in increased industry regulation, which may increase our compliance costs.
We are a wholly owned subsidiary of Xcel Energy Inc. Xcel Energy Inc. can exercise substantial control over our dividend policy and business and operations and may exercise that control in a manner that may be perceived to be adverse to our interests.
All of the members of our Board of Directors, as well as many of our executive officers, are officers of Xcel Energy Inc. Our Board of Directors makes determinations with respect to a number of significant corporate events, including the payment of our dividends.
We have historically paid quarterly dividends to Xcel Energy Inc. In 2021, 2020 2019 and 20182019 we paid $431 million, $408 million $467 million and $456$467 million of dividends to Xcel Energy Inc., respectively. If Xcel Energy Inc.’s cash requirements increase, our Board of Directors could decide to increase the dividends we pay to Xcel Energy Inc. to help support Xcel Energy Inc.’s cash needs. This could adversely affect our liquidity. The most restrictive dividend limitation for NSP-Minnesota is imposed by our state regulatory commissions. State regulatory commissions indirectly limit the amount of dividends NSP-Minnesota can pay to Xcel Energy Inc., by requiring a minimum equity-to-total capitalization ratio.
See Note 5 to the consolidated financial statements for further information.
Financial Risks
Our profitability depends on our ability to recover costs from our customers and changes in regulation may impair our ability to recover costs from our customers.
We are subject to comprehensive regulation by federal and state utility regulatory agencies, including siting and construction of facilities, customer service and the rates that we can charge customers.
The profitability of our operations is dependent on our ability to recover the costs of providing energy and utility services and earn a return on our capital investment. Our rates are generally regulated and based on an analysis of our costs incurred in a test year. We are subject to both future and historical test years depending upon the regulatory jurisdiction. Thus, the rates we are allowed to charge may or may not match our costs at any given time. Rate regulation is premised on providing an opportunity to earn a reasonable rate of return on invested capital.
There can also be no assurance that our regulatory commissions will judge all our costs to be prudent, which could result in disallowances, or that the regulatory process will always result in rates that will produce full recovery. Overall, management believes prudently incurred costs are recoverable given the existing regulatory framework. However, there may be changes in the regulatory environment that could impair our ability to recover costs historically collected from customers, or we could exceed caps on capital costs required by commissions and result in less than full recovery.
Changes in the long-term cost-effectiveness or to the operating conditions of our assets may result in early retirements of utility facilities. While regulation typically provides cost recovery relief for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs.
In a continued low interest rate environment there has been increased downward pressure on allowed ROE. Conversely, higherHigher than expected inflation or tariffs may increase costs of construction and operations. Also, rising fuel costs could increase the risk that we will not be able to fully recover our fuel costs from our customers.
Adverse regulatory rulings 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.
Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships.
We cannot be assured that our current credit ratings will remain in effect, or that a rating will not be lowered or withdrawn by a rating agency. Significant events including disallowance of costs, use of historic test years, elimination of riders or interim rates, increasing depreciation lives, lower returns on equity, changes to equity ratios and impacts of tax policy may impact our cash flows and credit metrics, potentially resulting in a change in our credit ratings. In addition, our credit ratings may change as a result of the differing methodologies or change in the methodologies used by the various rating agencies.
Any credit ratings downgrade could lead to higher borrowing costs andor lower proceeds from equity issuances. It could also impact our ability to access capital markets. Also, we may enter into contracts that require posting of collateral or settlement if credit ratings fall below investment grade.
We are subject to capital market and interest rate risks.
Utility operations require significant capital investment. As a result, we frequently need to access capital markets. Any disruption in capital markets could have a material impact on our ability to fund our operations. Capital market disruption and financial market distress could prevent us from issuing short-term commercial paper, issuing new securities or cause us to issue securities with unfavorable terms and conditions, such as higher interest rates.rates or lower proceeds from equity issuances. Higher interest rates on short-term borrowings with variable interest rates could also have an adverse effect on our operating results.
The performance of capital markets impacts the value of assets held in trusts to satisfy future obligations to decommission our nuclear plants and satisfy our defined benefit pension and postretirement benefit plan obligations. These assets are subject to market fluctuations and yield uncertain returns, which may fall below expected returns. A decline in the market value of these assets may increase funding requirements. Additionally, the fair value of the debt securities held in the nuclear decommissioning and/or pension trusts may be impacted by changes in interest rates.
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 economy and unemployment rates.
Credit risk also includes the risk that various 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., Southwest Power Pool, Inc., PJM Interconnection, LLC, MISO and Electric Reliability Council of Texas), in which any credit losses are socialized to all market participants.
We have additional indirect credit exposure to financial institutions from letters of credit provided as security by power suppliers under various purchased power contracts. If any of the credit ratings of the letter of credit issuers were to drop below investment grade, the supplier would need to replace that security with an acceptable substitute. If the security were not replaced, the party could be in default under the contract.
As we are a subsidiary of Xcel Energy Inc., we may be negatively affected by events impacting the credit or liquidity of Xcel Energy Inc. and its affiliates.
If either S&P or Moody’s were to downgrade Xcel Energy Inc.’s debt securities below investment grade, it would increase Xcel Energy Inc.’s cost of capital and restrict its access to the capital markets. This could limit Xcel Energy Inc.’s ability to contribute equity or make loans to us or may cause Xcel Energy Inc. to seek additional or accelerated funding from us in the form of dividends. If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.
As of Dec. 31, 2020,2021, Xcel Energy Inc. and its utility subsidiaries had approximately $19.6$21.8 billion of long-term debt and $1.0$1.6 billion of short-term debt and current maturities. Xcel Energy Inc. provides various guarantees and bond indemnities supporting some of its subsidiaries by guaranteeing the payment or performance by these subsidiaries for specified agreements or transactions.
Xcel Energy also has other contingent liabilities resulting from various tax disputes and other matters. Xcel Energy Inc.’s exposure under the guarantees is based upon the net liability of the relevant subsidiary under the specified agreements or transactions. The majority of Xcel Energy Inc.’s guarantees limit its exposure to a maximum amount that is stated in the guarantees.
As of Dec. 31, 2020,2021, Xcel Energy had guarantees outstanding with a $2$1 million maximum stated amount and immaterial exposure. Xcel Energy also had additional guarantees of $60$59 million at Dec. 31, 20202021 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 NSP-Minnesota could trigger settlement accounting and could require NSP-Minnesota 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.
NSP-Minnesota collects estimated federal, state and local tax payments through their regulated rates. Changes to federal tax law may benefit or adversely affect our earnings and customer costs. Tax depreciable lives and the valuevalue/availability of various tax credits or the timeliness of their utilization may impact the economics or selection of resources. If tax rates are increased, there could be timing delays before regulated rates provide for recovery of such tax increases in revenues. In addition, certain IRS tax policies such as tax normalization may impact our ability to economically deliver certain types of resources relative to market prices.
Macroeconomic Risks
Economic conditions impact our business.
Our operations are affected by local, national and worldwide economic conditions, which correlates to customers/sales growth (decline). Economic conditions may be impacted by insufficient financial sector liquidity leading to potential increased unemployment, which may impact customers’ ability to pay their bills which could lead to additional bad debt expense.
Additionally, NSP-Minnesota faces competitive factors, which could have an adverse impact on our financial condition, results of operations and cash flows. Further, worldwide economic activity impacts the demand for basic commodities necessary for utility infrastructure, which may inhibit our ability to acquire sufficient supplies. We operate in a capital intensive industry and federal trade policy could significantly impact the cost of materials we use. There may be delays before these additional material costs can be recovered in rates.
We face risks related to health epidemics and other outbreaks, which may have a material effect on our financial condition, results of operations and cash flows.
The global outbreak of COVID-19 is impactingcontinues to impact countries, communities, supply chains and markets. A high degree of uncertainty continues to exist regarding the pandemic,pandemic; the duration and magnitude of business restrictions re-shut downs,(domestically and globally); the potential shortages of employees and third-party contractors due to quarantine policies, vaccination requirements or government restrictions; re-shutdowns, if any, and the level and pace of economic recovery. While we
NSP-Minnesota has experienced and may continue to experience sales volatility and shifts between residential and C&I sales as a result of COVID-19. NSP-Minnesota has historically had a sales true-up mechanism for all electric customer classes which has ended in 2021. We are implementing contingency plans, there are no guarantees these plans will be sufficient to offsetrequesting implementation of a new sales true-up mechanism for 2022 - 2024. These mechanisms mitigate the impact of COVID-19.changes to sales levels as compared to a baseline.
Although the financial impact of the pandemic to the 2020on our financial results washas largely been mitigated, due to management’s actions, we cannot ultimately predict whether it will have a material impact on our future liquidity, financial condition or results of operations. Nor can we predict the impact of the virus on the health of our employees, our supply chain or our ability to recover higher costs associated with managing through the pandemic. The impact of COVID-19 may exacerbate other risks discussed herein, which could have a material effect on us. The situation is evolving and additional impacts may arise.
Operations could be impacted by war, terrorism, or other events.
Our generation plants, fuel storage facilities, transmission and distribution facilities and information and control systems may be targets of terrorist activities. Any disruption could impact operations or result in a decrease in revenues and additional costs to repair and insure our assets. These disruptions could have a material impact on our financial condition, results of operations or cash flows. The potential for terrorism has subjected our operations to increased risks and could have a material effect on our business. We have already incurred increased costs for security and capital expenditures in response to these risks. The insurance industry has also been affected by these events and the availability of insurance may decrease. In addition, insurance may have higher deductibles, higher premiums and more restrictive policy terms.
A disruption of the regional electric transmission grid, interstate natural gas pipeline infrastructure or other fuel sources, could negatively impact our business, brand and reputation. Because our facilities are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by the actions of a neighboring utility.
We also face the risks of possible loss of business due to significant events such as severe storms, severe temperature extremes, wildfires, widespread pandemic, generator or transmission facility outage, pipeline rupture, railroad disruption, operator error, sudden and significant increase or decrease in wind generation or a workforce disruption.
In addition, major catastrophic events throughout the world may disrupt our business. Xcel Energy 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 reliably serve our customers.
A major disruption could result in a significant decrease in revenues and additional costs to repair assets, which could have a material impact on our results of operations, financial condition or cash flows.
NSP-Minnesota participates in GridEx, which is the largest grid security and emergency response exercises (GridEx).exercise in North America. These efforts, led by the NERC, test and further develop the coordination, threat sharing, and interaction between utilities and various government agencies relative to potential cyber and physical threats against the nation’s electric grid.
A cyber incident or security breach could have a material effect on our business.
We operate in an industry that requires the continued operation of sophisticated information technology, control systems and network infrastructure. In addition, we use our systems and infrastructure to create, collect, use, disclose, store, dispose of and otherwise process sensitive information, including 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 cyber security incidents, including those caused by human error. Our industry has been the target of several attacks on operational systems and has seen an increased volume and sophistication of cyber security incidents from international activist organizations, Nation States and individuals. During the normal course of business, we have experienced and 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 operation. Cyber security incidents could harm our businesses by limiting our generating, transmitting and distributing capabilities, delaying our development and construction of new facilities or capital improvement projects to existing facilities, disrupting our customer operations or causing the release of customer information, all of which would likely receive state and federal regulatory scrutiny and could expose us to liability.
Our generation, transmission systems and natural gas pipelines are part of an interconnected system. Therefore, a disruption caused by the impact of a cyber security incident 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 and services may expose software or hardware to these risks and could result in a breach or significant costs of remediation. We are unable to quantify the potential impact of cyber security threats or subsequent related actions. Cyber security incidents and regulatory action could result in a material decrease in revenues and may cause significant additional costs (e.g., penalties, third-party claims, repairs, insurance or compliance) and potentially disrupt our supply and markets for natural gas, oil and other fuels.
We maintain security measures to protect our information technology and control systems, network infrastructure and other assets. However, these assets and the information they process may be vulnerable to cyber security incidents, including asset failure or unauthorized access to assets or information. A failure or breach of our technology systems or those of our third-party service providers could disrupt critical business functions and may negatively impact our business, our brand, and our reputation. The cyber security threat is dynamic and evolves continually, and our efforts to prioritize network protection may not be effective given the constant changes to threat vulnerability.
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
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. TheIn April 2021, ahead of the United Nations Climate Change Conference in Glasgow, the Biden Administration will establishcommitted the U.S. to a new nationally determined contribution for the United States. The Paris AgreementNationally Determined Contribution of 50-52% net GHG emissions reduction economy-wide from 2005 levels. This commitment and other agreements made in Glasgow could result in future additional GHG reductions in the United States. In addition, the Biden Administration has announced plans to implement new climate change programs, including potential regulation of GHG emissions targeting the utility industry.
The Biden Administration has also announced a one year suspension of new oil and natural gas drilling on federal lands to allow for a review of oil and gas leasing regulations. The form of these regulations is uncertain, but, depending on the requirements imposed in the short and long term, they could impose substantial costs on our oil and gas customers or result in substantial increases to the cost of fuel we use in our electricity and gas businesses.
Many states and localities continue to pursue their own climate policies. The steps NSP-Minnesota has taken to date to reduce GHG emissions, including energy efficiency measures, adding renewable generation or retiring or converting coal plants to natural gas, occurred under state-endorsed resource plans, renewable energy standards and other state policies.
We may be subject to climate change lawsuits. An adverse outcome could require substantial capital expenditures and possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant and could affect results of operations, financial condition or cash flows if such costs are not recovered through regulated rates.
If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material effect on our results of operations, financial condition or cash flows.
Increased risks of regulatory penalties could negatively impact our business.
The Energy Act increased civil penalty authority for violation of FERC statutes, rules and orders. The FERC can impose penalties of up to $1.3 million per violation per day, particularly as it relates to energy trading activities for both electricity and natural gas. In addition, NERC electric reliability standards and critical infrastructure protection requirements are mandatory and subject to potential financial penalties. Also, the PHMSA, Occupational Safety and Health Administration and other federal agencies have the authority to assess penalties.
In the event of serious incidents, these agencies may pursue penalties. In addition, certain states have the authority to impose substantial penalties. If a serious reliability, cyber or safety incident did occur, it could have a material effect on our results of operations, financial condition or cash flows.
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 Risks
We are subject to environmental laws and regulations, with which compliance could be difficult and costly.
We are subject to environmental laws and regulations that affect many aspects of our operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances. Laws and regulations require us to obtain permits, licenses, and approvals and to comply with a variety of environmental requirements.
Environmental laws and regulations can also require us to restrict or limit the output of facilities or the use of certain fuels, shift generation to lower-emitting facilities, install pollution control equipment, clean up spills and other contamination and correct environmental hazards. Failure to meet requirements of environmental mandates may result in fines or penalties. We may be required to pay all or a portion of the cost to remediate sites where our past activities, or the activities of other parties, caused environmental contamination.
Changes in environmental policies and regulations or regulatory decisions may result in early retirements of our generation facilities. While regulation typically provides relief for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs.
We are subject to mandates to provide customers with clean energy, renewable energy and energy conservation offerings. It could have a material effect on our results of operations, financial condition or cash flows if our regulators do not allow us to recover the cost of capital investment or O&M costs incurred to comply with the requirements.
In addition, existing environmental laws or regulations may be revised and new laws or regulations may be adopted. We may also incur additional unanticipated obligations or liabilities under existing environmental laws and regulations.
We are subject to physical and financial risks associated with climate change and other weather, natural disaster and resource depletion impacts.
Climate change can create physical and financial risk. Physical risks include changes in weather conditions and extreme weather events.
Our customers’ energy needs vary with weather. To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease. Increased energy use due to weather changes may require us to invest in generating assets, transmission and infrastructure. Decreased energy use due to weather changes may result in decreased revenues.
Climate change may impact the economy, which could impact our sales and revenues. The price of energy has an impact on the economic health of our communities. The cost of additional regulatory requirements, such as regulation of GHG, could impact the availability of goods and prices charged by our suppliers which would normally be borne by consumers through higher prices for energy and purchased goods. To the extent financial markets view climate change and emissions of GHGs as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less than ideal terms and conditions.
We have committed to a number of long-term climate change goals, which in part are dependent on future technologies not currently in existence. Given the long-term nature of these goals, there is an inherent uncertainty due to internal and external factors regarding our ability to achieve our stated climate change goals. To the extent climate change goals are not met, this could negatively impact our reputation and potentially result in financial risk.
Severe weather impacts our service territories, primarily when thunderstorms, flooding, tornadoes, wildfires and snow or ice storms 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. Periods of extreme temperatures could impact our ability to meet demand. Changes in precipitation resulting in droughts or water shortages could adversely affect our operations. Drought conditions also contribute to the increase in wildfire risk from our electric generation facilities.
While we carry liability insurance, given an extreme event, if NSP-Minnesota 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.
Virtually all of the utility plant property of NSP-Minnesota is subject to the lien of its first mortgage bond indenture.
| | Station, Location and Unit | | Fuel | | Installed | | MW (a) | | |
| Station, Location and Unit at Dec. 31, 2021 | | Station, Location and Unit at Dec. 31, 2021 | | Fuel | | Installed | | MW (a) | |
| Steam: | Steam: | | | | | | | | Steam: | | | | | | | |
A.S. King-Bayport, MN, 1 Unit (e)(f) | A.S. King-Bayport, MN, 1 Unit (e)(f) | | Coal | | 1968 | | 511 | | | A.S. King-Bayport, MN, 1 Unit (e)(f) | | Coal | | 1968 | | 511 | | |
Sherco-Becker, MN (f)(e) | Sherco-Becker, MN (f)(e) | | Sherco-Becker, MN (f)(e) | |
| Unit 1 | Unit 1 | | Coal | | 1976 | | 680 | | | Unit 1 | | Coal | | 1976 | | 680 | | |
| Unit 2 | Unit 2 | | Coal | | 1977 | | 682 | | | Unit 2 | | Coal | | 1977 | | 682 | | |
| Unit 3 | Unit 3 | | Coal | | 1987 | | 517 | | (b) | Unit 3 | | Coal | | 1987 | | 517 | | (b) |
| Monticello, MN, 1 Unit | Monticello, MN, 1 Unit | | Nuclear | | 1971 | | 617 | | | Monticello, MN, 1 Unit | | Nuclear | | 1971 | | 617 | | |
| PI-Welch, MN | PI-Welch, MN | | PI-Welch, MN | |
| Unit 1 | Unit 1 | | Nuclear | | 1973 | | 521 | | | Unit 1 | | Nuclear | | 1973 | | 521 | | |
| Unit 2 | Unit 2 | | Nuclear | | 1974 | | 519 | | | Unit 2 | | Nuclear | | 1974 | | 519 | | |
| Various locations, 4 Units | Various locations, 4 Units | | Wood/Refuse | | Various | | 36 | | (c) | Various locations, 4 Units | | Wood/Refuse | | Various | | 36 | | (c) |
| Combustion Turbine: | Combustion Turbine: | | Combustion Turbine: | |
| Angus Anson-Sioux Falls, SD, 3 Units | Angus Anson-Sioux Falls, SD, 3 Units | | Natural Gas | | 1994 - 2005 | | 327 | | | Angus Anson-Sioux Falls, SD, 3 Units | | Natural Gas | | 1994 - 2005 | | 327 | | |
| Black Dog-Burnsville, MN, 3 Units | Black Dog-Burnsville, MN, 3 Units | | Natural Gas | | 1987 - 2018 | | 494 | | | Black Dog-Burnsville, MN, 3 Units | | Natural Gas | | 1987 - 2018 | | 494 | | |
| Blue Lake-Shakopee, MN, 6 Units | Blue Lake-Shakopee, MN, 6 Units | | Natural Gas | | 1974 - 2005 | | 447 | | | Blue Lake-Shakopee, MN, 6 Units | | Natural Gas | | 1974 - 2005 | | 447 | | |
| High Bridge-St. Paul, MN, 3 Units | High Bridge-St. Paul, MN, 3 Units | | Natural Gas | | 2008 | | 530 | | | High Bridge-St. Paul, MN, 3 Units | | Natural Gas | | 2008 | | 530 | | |
| Inver Hills-Inver Grove Heights, MN, 6 Units | Inver Hills-Inver Grove Heights, MN, 6 Units | | Natural Gas | | 1972 | | 252 | | | Inver Hills-Inver Grove Heights, MN, 6 Units | | Natural Gas | | 1972 | | 252 | | |
| Riverside-Minneapolis, MN, 3 Units | Riverside-Minneapolis, MN, 3 Units | | Natural Gas | | 2009 | | 454 | | | Riverside-Minneapolis, MN, 3 Units | | Natural Gas | | 2009 | | 454 | | |
| Various locations, 7 Units | Various locations, 7 Units | | Natural Gas | | Various | | 10 | | | Various locations, 7 Units | | Natural Gas | | Various | | 10 | | |
| Wind: | Wind: | | Wind: | |
| Blazing Star 1-Lincoln County, MN, 100 Units | | Blazing Star 1-Lincoln County, MN, 100 Units | | Wind | | 2020 | | 200 | | (d) |
| Blazing Star 2-Lincoln County, MN, 100 Units | | Blazing Star 2-Lincoln County, MN, 100 Units | | Wind | | 2021 | | 200 | | (d) |
| Border-Rolette County, ND, 75 Units | Border-Rolette County, ND, 75 Units | | Wind | | 2015 | | 148 | | (d) | Border-Rolette County, ND, 75 Units | | Wind | | 2015 | | 148 | | (d) |
| Community Wind North-Lincoln County, MN, 12 Units | | Community Wind North-Lincoln County, MN, 12 Units | | Wind | | 2020 | | 26 | | (d) |
| Courtenay Wind-Stutsman County, ND, 100 Units | Courtenay Wind-Stutsman County, ND, 100 Units | | Wind | | 2016 | | 190 | | (d) | Courtenay Wind-Stutsman County, ND, 100 Units | | Wind | | 2016 | | 190 | | (d) |
| Crowned Ridge 2-Grant County, SD, 88 Units | | Crowned Ridge 2-Grant County, SD, 88 Units | | Wind | | 2020 | | 192 | | (d) |
| Foxtail-Dickey County, ND, 75 Units | Foxtail-Dickey County, ND, 75 Units | | Wind | | 2019 | | 150 | | (d) | Foxtail-Dickey County, ND, 75 Units | | Wind | | 2019 | | 150 | | (d) |
| Freeborn-Freeborn County, MN, 100 Units | | Freeborn-Freeborn County, MN, 100 Units | | Wind | | 2021 | | 200 | | (d) |
| Grand Meadow-Mower County, MN, 67 Units | Grand Meadow-Mower County, MN, 67 Units | | Wind | | 2008 | | 99 | | (d) | Grand Meadow-Mower County, MN, 67 Units | | Wind | | 2008 | | 99 | | (d) |
| Jeffers-Cottonwood County, MN, 20 Units | | Jeffers-Cottonwood County, MN, 20 Units | | Wind | | 2020 | | 43 | | (d) |
| Lake Benton-Pipestone County, MN, 44 Units | Lake Benton-Pipestone County, MN, 44 Units | | Wind | | 2019 | | 99 | | (d) | Lake Benton-Pipestone County, MN, 44 Units | | Wind | | 2019 | | 99 | | (d) |
| Mower-Mower County, MN, 43 Units | | Mower-Mower County, MN, 43 Units | | Wind | | 2021 | | 91 | | (d) |
| Nobles-Nobles County, MN, 134 Units | Nobles-Nobles County, MN, 134 Units | | Wind | | 2010 | | 197 | | (d) | Nobles-Nobles County, MN, 134 Units | | Wind | | 2010 | | 197 | | (d) |
| Pleasant Valley-Mower County, MN, 100 Units | Pleasant Valley-Mower County, MN, 100 Units | | Wind | | 2015 | | 196 | | (d) | Pleasant Valley-Mower County, MN, 100 Units | | Wind | | 2015 | | 196 | | (d) |
| Blazing Star 1-Lincoln County, MN, 100 Units | | Wind | | 2020 | | 200 | | (d) | |
| Crowned Ridge 2-Grant County, SD, 88 Units | | Wind | | 2020 | | 192 | | (d) | |
| Community Wind North-Lincoln County, MN, 12 Units | | Wind | | 2020 | | 26 | | (d) | |
| Jeffers-Cottonwood County, MN, 20 Units | | Wind | | 2020 | | 43 | | (d) | |
| | Total | | 8,137 | | | | Total | | 8,628 | | |
(a)Summer 20202021 net dependable capacity.
(b)Based on NSP-Minnesota’s ownership of 59%.
(c)Refuse-derived fuel is made from municipal solid waste.
(d)Values disclosed are the generation levels at the point-of-interconnection for these wind units. Capacity is attainable only when wind conditions are sufficiently available (on-demand net dependable capacity is zero).
(e)A.S. King is expected to be retired early in 2028.
(f)Sherco Unit 1, 2, and 3 are expected to be retired early in 2026, 2023 and 2030, respectively.
Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2020:2021:
| | | | | |
| Conductor Miles | |
| Transmission | |
| 500 KV | 2,9182,915 | |
| 345 KV | 13,15113,570 | |
| 230 KV | 2,3012,300 | |
| 161 KV | 674640 | |
| |
| 115 KV | 8,0608,086 | |
| Less than 115 KV | 6,5566,644 | |
| Total Transmission | 33,66034,155 | |
| |
| Distribution | |
| Less than 115 KV | 80,50881,406 | |
| |
| Total | 114,168115,561 | |
NSP-Minnesota had 352354 electric utility transmission and distribution substations at Dec. 31, 2020.2021.
Natural gas utility mains at Dec. 31, 2020:2021:
| | | | | |
| Miles | |
| Transmission | 8085 | |
| Distribution | 10,62910,741 | |
| | |
| ITEM 3 — LEGAL PROCEEDINGS |
NSP-Minnesota 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 NSP-Minnesota’s consolidated financial statements. Unless otherwise required by GAAP, legalLegal fees are generally expensed as incurred.
See Note 10 to the consolidated financial statements, Item 1 and Item 7 for further information.
| | |
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 |
NSP-Minnesota is a wholly owned subsidiary of Xcel Energy Inc. and there is no market for its common equity securities.
The dividends declared during 20202021 and 20192020 were as follows:
| | (Millions of Dollars) | (Millions of Dollars) | | 2020 | | 2019 | (Millions of Dollars) | | 2021 | | 2020 |
| First quarter | First quarter | | $ | 100 | | | $ | 95 | | First quarter | | $ | 109 | | | $ | 100 | |
| Second quarter | Second quarter | | 105 | | | 96 | | Second quarter | | 107 | | | 105 | |
| Third quarter | Third quarter | | 109 | | | 94 | | Third quarter | | 109 | | | 109 | |
| Fourth quarter | Fourth quarter | | 106 | | | 194 | | Fourth quarter | | 96 | | | 106 | |
| | |
ITEM 6 — SELECTED FINANCIAL DATA[RESERVED] |
Omitted per conditions set forth in general instructions I(1)(a) and (b) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).
| | |
| ITEM 7 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
Discussion of financial condition and liquidity for NSP-Minnesota is omitted per conditions set forth in general instructionsGeneral Instructions I(1)(a) and (b) of Form 10-K for wholly owned subsidiaries. It is replaced with management’s narrative analysis andof the results of operations for the current year as set forth in general instructionsGeneral Instruction I(2)(a) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).
Non-GAAP Financial Measures
The following discussion includes financial information prepared in accordance with GAAP, as well as certain non-GAAP financial measures such as electric margin, natural gas margin, and ongoing earnings. Generally, a non-GAAP financial measure is a measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are adjusted from measures calculated and presented in accordance with GAAP.
NSP-Minnesota’s management uses non-GAAP measures for financial planning and analysis, for reporting of results to the Board of Directors, in determining performance-based compensation and communicating its earnings outlook to analysts and investors. Non-GAAP financial measures are intended to supplement investors’ understanding of our performance and should not be considered alternatives for financial measures presented in accordance with GAAP. These measures are discussed in more detail below and may not be comparable to other companies’ similarly titled non-GAAP financial measures.
Electric and Natural Gas Margins
Electric margin is presented as electric revenues less electric fuel and purchased power expenses. Natural gas margin is presented as natural gas revenues less the cost of natural gas sold and transported. Expenses incurred for electric fuel and purchased power and the cost of natural gas are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues.
Management believes electric and natural gas margins provide the most meaningful basis for evaluating our operations because they exclude the revenue impact of fluctuations in these expenses. These margins can be reconciled to operating income, a GAAP measure, by including other operating revenues, cost of sales-other, O&M expenses, conservation and DSM expenses, depreciation and amortization and taxes (other than income taxes).
Earnings Adjusted for Certain Items (Ongoing Earnings)
Ongoing earnings reflect adjustments to GAAP earnings (net income) for certain items.
We use these non-GAAP financial measures to evaluate and provide details of NSP-Minnesota’s core earnings and underlying performance. We believe these measurements are useful to investors to evaluate the actual and projected financial performance and contribution of NSP-Minnesota. For the years ended Dec. 31, 20202021 and 2019,2020, there were no such adjustments to GAAP earnings and therefore GAAP earnings equal ongoing earnings.
20202021 Comparison with 20192020
NSP-Minnesota’s net income was approximately $606 million for 2021, compared with approximately $591 million for 2020, compared with approximately $543 million for 2019.2020. The increase in earnings was driven by higher electric margin (riders, wholesale transmission revenue and a sales true-up mechanism, whichprimarily reflects lower sales due to COVID-19) and lower O&M expenses, partiallycapital investment recovery offset by increasedadditional depreciation and lower natural gas margin.interest charges.
Electric Margin
Electric margin is presented as electric revenues less electric fuel and purchased power expenses. Expenses incurred for electric fuel and purchased power are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues.
Electric revenues and fuel and purchased power expenses are impacted by fluctuations in the price of natural gas, coal and uranium. However, these price fluctuations generally have minimal impact on marginearnings impact 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).income taxes.
Electric Revenues, Fuel and Margin:Purchased Power and Electric Margin
| | (Millions of Dollars) | (Millions of Dollars) | | 2020 | | 2019 | (Millions of Dollars) | | 2021 | | 2020 |
| Electric revenues | Electric revenues | | $ | 4,571 | | | $ | 4,506 | | Electric revenues | | $ | 5,094 | | | $ | 4,571 | |
| Electric fuel and purchased power | Electric fuel and purchased power | | (1,626) | | | (1,601) | | Electric fuel and purchased power | | (2,042) | | | (1,626) | |
| Electric margin | Electric margin | | $ | 2,945 | | | $ | 2,905 | | Electric margin | | $ | 3,052 | | | $ | 2,945 | |
Changes in Electric Margin:Margin
| | | | | | | | |
| (Millions of Dollars) | | 20202021 vs. 20192020 |
| Non-fuel riders | | $ | 68 | |
Wholesale transmission revenue (net) | | 21118 | |
Conservation incentiveprogram revenues (offset in expense) | | 924 | |
Estimated impactProprietary commodity trading, net of weather (net of decoupling/sales true-up)sharing(a)
| | 20 | |
| Interchange agreement billings with NSP-Wisconsin | | 118 | |
| PTCs flowed back to customers (offset by lower ETR) | | (60) | |
Purchased capacity costsWholesale transmission revenue (net) | | (15)(21) | |
| Other (net) | | 168 | |
| Total increase in electric margin | | $ | 40107 | |
(a)Includes $12 million of net gains recognized in the first quarter of 2021, driven by market changes associated with Winter Storm Uri. Additional amounts are primarily related to long-term physical generation contracts, which have increased in value as a result of higher energy prices.
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 on margin due to cost recovery mechanisms.
Natural gas revenues and margin:
| | | | | | | | | | | | | | |
| (Millions of Dollars) | | 2020 | | 2019 |
| Natural gas revenues | | $ | 493 | | | $ | 571 | |
| Cost of natural gas sold and transported | | (263) | | | (327) | |
| Natural gas margin | | $ | 230 | | | $ | 244 | |
Natural Gas Revenues, Cost of Natural Gas Sold and Transported and Natural Gas Margin
| | | | | | | | | | | | | | |
| (Millions of Dollars) | | 2021 | | 2020 |
| Natural gas revenues | | $ | 623 | | | $ | 493 | |
| Cost of natural gas sold and transported | | (385) | | | (263) | |
| Natural gas margin | | $ | 238 | | | $ | 230 | |
Changes in natural gas margin:Natural Gas Margin
| | | | | | | | |
| (Millions of Dollars) | | 20202021 vs. 20192020 |
| Infrastructure and integrity riders | | $ | 7 | |
| | |
| | |
| | |
| Estimated impact of weather | | $ | (12)(2) | |
Infrastructure and integrity ridersOther (net) | | (3) | |
Retail sales growth (excluding weather impact) | | 13 | |
Total decreaseincrease in natural gas margin | | $ | (14)8 | |
Non-Fuel Operating Expenses and Other Items
O&M Expenses— O&M expenses decreased $12 million, or 1.0%, for 2020, largely reflecting cost mitigation efforts to offset the impact from COVID-19 and lower interchange billings with NSP-Wisconsin. Cost mitigation efforts included allocation of workforce, material and supply management, and timing of maintenance activities. The decrease was partially offset by incremental bad debt expense related to the COVID-19 pandemic and a commitment to fund the Minnesota payment plan credit program as agreed to in the Minnesota electric rate case stay-out.
Depreciation and Amortization — Depreciation and amortization expense increased $34$101 million or 4.3%, for 2020.2021. The increase was primarily due to the Foxtail, Blazing Star I, Lake Benton, Crowned Ridge, Community Wind North and Jeffersdriven by several wind facilitiesfarms going into service, as well as normal system expansion.
Interest Charges — Interest charges increased $22 million year-to-date. The increase was largely due to higher debt levels to fund capital investments, partially offset by lower long-term and short-term interest rates.
Income Taxes — Income tax expense decreased $53benefit increased $42 million for 2020.2021. The decreaseincrease was primarily driven by an increase inincreased wind PTCs. Wind PTCs are credited to customers (recorded as a reduction to revenue) and do not have a material impact on net income.
Winter Storm Uri
In February 2021, the United States experienced Winter Storm Uri. Extreme cold temperatures impacted certain operational assets as well as the availability of renewable generation. The ETR was (1.0)%cold weather also affected the country’s supply and demand for 2020 compared with 8.0%natural gas. These factors contributed to extremely high market prices for 2019, largely duenatural gas and electricity. As a result of the extremely high market prices, NSP-Minnesota incurred net natural gas, fuel and purchased energy costs of approximately $230 million (largely deferred as regulatory assets).
Regulatory Overview —NSP-Minnesota has natural gas, fuel and purchased energy mechanisms in each jurisdiction for recovering incurred costs. However, NSP-Minnesota has deferred February 2021 cost increases for future recovery and sought recovery of the cost increases over a period of up to 63 months to mitigate the adjustments above.impact to customer bills. Additionally, we did not request recovery of financing costs in order to further limit the impact to our customers.
Proceedings initiated:
| | | | | |
| Jurisdiction | Regulatory Status |
| Minnesota | NSP-Minnesota filed with the MPUC seeking recovery of $215 million in incremental costs from natural gas customers. In August 2021, the MPUC allowed recovery of $179 million of costs deemed to be extraordinary beginning in September 2021 over 27 months (no financing charge) and $36 million of ordinary costs over 12 months through the monthly Purchased Gas Adjustment. The $179 million in extraordinary cost recovery is subject to refund pending the outcome of a contested case before an ALJ.
In December 2021, the MPUC approved extending recovery of Winter Storm Uri costs for the residential class (approximately $97 million) from a 27-month recovery period to a 63-month recovery period. New residential Winter Storm Uri rates were effective Jan. 1, 2022.
In December 2021, direct testimony was received from intervenors. The DOC recommended a $127 million disallowance based on allegations including peaking plant usage, load forecasting, natural gas supply/storage and related purchases. Alternatively, the DOC recommended a $42 million disallowance if NSP-Minnesota proves it prudently managed its peaking plants. The OAG recommended a disallowance of $179 million based on allegations that NSP-Minnesota could have fully hedged its exposure to spot market prices. Alternatively, the OAG recommended a $25 million disallowance based on allegations related to specific hedges allegedly available in the market during February 2021. The CUB recommended a $69 million disallowance based on allegations related to the unavailability of NSP-Minnesota’s peaking plants, inaccuracy of load forecasting and inadequate curtailment of interruptible customers.
Xcel Energy strongly disagrees with the recommendations of the DOC, OAG and CUB and believes that it acted prudently and according to MPUC approved procedures for the best interest of its customers and stakeholders. NSP-Minnesota intends to file rebuttal testimony in January 2022. A hearing before the ALJs assigned to the matter is scheduled for Feb. 17-23, 2022. An MPUC decision is expected in the summer of 2022.
See Rate Matters and Other within Note 10 to the consolidated financial statements for further information. |
| South Dakota | Winter Storm Uri had no impact on South Dakota electric costs as NSP-Minnesota was a net seller in the electric market. |
| North Dakota | In June, the NDPSC approved recovery of $32 million in natural gas costs over 15 months (starting July 2021) with no financing charge. |
| | |
| Public Utility Regulation |
The FERC and various state and local regulatory commissions regulate NSP-Minnesota. NSP-Minnesota 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 Minnesota, North Dakota and South Dakota.
Rates are designed to recover plant investment, operating costs and an allowed return on investment. Our utility subsidiaries requestNSP-Minnesota requests changes in utility rates for utility services through filings with governing commissions.commission filings. Changes in operating costs can affect NSP-Minnesota’s financial results, depending on the timing of rate case filingscases and implementation of final rates. Other factors affecting rate filings are new investments, sales, conservation and DSM efforts, and the cost of capital.
In addition, the regulatory commissions authorize the ROE, capital structure and depreciation rates in rate proceedings. Decisions by these regulators can significantly impact NSP-Minnesota’s results of operations.
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 |
| MPUC | | Retail rates, services, security issuances, property transfers, mergers, disposition of assets, affiliate transactions, and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV in Minnesota. Reviews and approves natural gas supply plans. Pipeline safety compliance. |
| NDPSC | | Retail rates, services and other aspects of electric and natural gas operations. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in North Dakota. Pipeline safety compliance. |
SDPUCSouth Dakota Public Utilities Commission | | Retail rates, services and other aspects of electric operations. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in South Dakota. Pipeline safety compliance. |
| FERC | | Wholesale electric operations, hydroelectric licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transfers and mergers, and natural gas transactions in interstate commerce. |
| MISO | | NSP-Minnesota is a transmission owning member of the MISO RTO and operates within the MISO RTO and wholesale markets. NSP-Minnesota makes wholesale sales in other RTO markets at market-based rates. NSP-Minnesota and NSP-Wisconsin also make wholesale electric sales at market-based prices to customers outside of their balancing authority as jointly authorized by the FERC. |
| DOT | | Pipeline safety compliance. |
| Minnesota Office of Pipeline Safety | | Pipeline safety compliance. |
Recovery Mechanisms
| | | | | | | | |
| Mechanism | | Additional Information |
CIP Rider (a) | | Recovers costs of conservation and DSM programs in Minnesota. |
EIREnvironmental Improvement Rider | | Recovers costs of environmental improvement projects in Minnesota. |
RDFRenewable Development Fund | | Allocates money collected from customers to support research and development of emerging renewable energy projects and technologies in Minnesota. |
| RES | | Recovers cost of renewable generation in Minnesota. |
RERRenewable Energy Rider | | Recovers cost of renewable generation in North Dakota. |
SEPState Energy Policy Rider | | Recovers costs related to various energy policies approved by the Minnesota legislature. |
| TCR | | Recovers costs for investments in electric transmission and distribution grid modernization. |
| Infrastructure Rider | | Recovers costs for investments in generation and incremental property taxes in South Dakota. |
FCA (b) | | Minnesota, North Dakota and South Dakota include a FCA for monthly billing adjustments to recover changes in prudently incurred costs of fuel related items and purchased energy. Capacity costs are recovered through base rates and are not recovered through the FCA. MISO costs are generally recovered through either the FCA or base rates. |
PGAPurchased Gas Adjustment | | Provides for prospective monthly rate adjustments for costs of purchased natural gas, transportation and storage service. Includes a true-up process for difference between projected and actual costs. |
| GUIC Rider | | Recovers costs for transmission and distribution pipeline integrity management programs, including:including funding for pipeline assessments, deferred costs for sewer separation and pipeline integrity management programs in Minnesota. |
| Sales True-up | | In February 2021,2022, NSP-Minnesota filed the 20202021 sales true-up compliance report, resulting in a total surcharge of $119$59 million. An MPUC ruling is anticipated in the second quarter of 2021. The 20212022. In their current rate case, NSP-Minnesota has proposed a sales true-up mechanism extended under the 2020 stay-out petition, willfor 2022 and beyond that would operate similarly to the currently approved2021 sales true-up and apply to all customer classes.true-up. Under the stay-out petition, 2021 NSP-Minnesota jurisdictional earnings will bewas capped at a 9.06% ROE. Any excess earnings willare required to be refunded to customers. |
(a)Minnesota state law requires NSP-Minnesota to spend 2% of its state electric revenues and 0.5% of its state natural gas revenues on CIP. These costs are recovered through an annual cost-recovery mechanism.
(b)The MPUC changed the FCA process in Minnesota (effective in 2020). Each month, utilities collect amounts equal to baseline cost of energy set at the start of the plan year (base would be reset annually). Monthly variations to baseline costs are tracked and netted over a 12-month period. Utilities issue refunds above the baseline costs and can seek recovery of any overage.
Pending and Recently Concluded Regulatory Proceedings
| | | | | | | | | | | | | | | | | | | | |
Proceeding2022 Minnesota Natural Gas Rate Case—In November 2021, NSP-Minnesota filed a request with the MPUC for an annual natural gas rate increase of $36 million, or 6.6%. The filing is based on a 2022 forecast test year and includes a requested ROE of 10.5%, rate base of $934 million and an equity ratio of 52.50%.In December 2021, the MPUC approved the requested interim rates of $25 million, subject to refund, beginning on Jan. 1, 2022. The next steps in the procedural schedule are expected to be as follows: •Intervenor testimony: Aug. 30, 2022 •Rebuttal testimony: Oct. 4, 2022 •Public hearing: Nov. 1-4, 2022 •ALJ Report: Feb. 6, 2023 •MPUC Order: April 26, 2023
| | Amount
(in millions) | | Filing
Date | | Approval |
2020 North Dakota Electric Rate Case | | $22 | | November 2020 | | Pending |
2020 TCR Electric Rider | | 82 | | November 2019 | | Pending |
2020 GUIC Natural Gas Rider | | 21 | | November 2019 | | Pending |
2021 GUIC Natural Gas Rider | | 27 | | October 2020 | | Pending |
2020 RES Electric Rider | | 102 | | November 2019 | | Pending |
2021 RES Electric Rider | | 189 | | November 2020 | | Pending |
Additional Information:
20202022 Minnesota Electric Rate Case and Stay-Out Alternative —In November 2020, In October 2021, NSP-Minnesota filed ana three-year electric rate case seeking a $597 million revenue increase over three years with the MPUC. The rate case is based on a requested ROE of 10.2%, a 52.50% equity ratio and forward test years.
The request is detailed as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| (Amounts in Millions, Except Percentages) | | 2022 | | 2023 | | 2024 | | Total |
| Rate request | | $ | 396 | | | $ | 150 | | | $ | 131 | | | $ | 677 | |
| Increase percentage | | 12.2 | % | | 4.8 | % | | 4.2 | % | | 21.2 | % |
| Rate base | | $ | 10,931 | | | $ | 11,446 | | | $ | 11,918 | | | N/A |
In addition, NSP-Minnesota requested interim rates, subject to refund, of $288 million to be implemented in January 2022 and an incremental $135 million to be implemented in January 2023. In December 2021, the MPUC approved rates of $247 million to begin on Jan. 1, 2022. The adjusted level reflects exigent circumstances from the COVID-19 pandemic.
The next steps in the procedural schedule are expected to be as follows:
•Intervenor testimony: Oct. 3, 2022
•Rebuttal testimony: Nov. 8, 2022
•Public hearing: Dec. 13-16, 2022
•ALJ Report: March 31, 2023
•MPUC Order: June 30, 2023
2021 North Dakota Natural Gas Rate Case — In September 2021, NSP-Minnesota filed a request with the NDPSC for a natural gas rate increase of $7 million, or 10.49%. The filing is based on a requested ROE of 10.5%, an equity ratio of 52.54%, a 2022 forecast test year and a 52.5% equity ratio. NSP-Minnesota also filed a stay-out alternativerate base of approximately $140 million. Interim rates of $7 million, subject to refund, were implemented on Nov. 1, 2021. An NDPSC decision is expected in which it would withdraw its rate case filing.early fall 2022.
In December 2020,The next steps in the MPUC verbally approved the stay-out alternative petition, which includes the extension of the sales, capital and property tax true-up mechanisms and delays any increaseprocedural schedule are expected to the Nuclear Decommissioning Trust annual accrual until Jan.be as follows:
•Intervenor testimony: March 1, 2022.2022
Additionally, NSP-Minnesota agreed to not seek recovery of incremental COVID-19 related expenses, including bad debt expense, and committed to fund $18 million in a Residential Payment Plan Credit Program or other similar customer relief programs, as directed by the MPUC. NSP-Minnesota also agreed to an earnings test in which all earnings above an ROE of 9.06% in 2021 would be refunded to customers.•Rebuttal testimony: April 1, 2022
•Hearings: June 1-3, 2022
2020 North Dakota Electric Rate Case — In November 2020, NSP-Minnesota filed a requestrate case with the NDPSC for an overall increase in annual retail electric revenues of approximately $22 million, or anseeking a rate increase of 10.8%. The rate filing is$19 million based on a 2021 forecast test year, a requested ROE of 10.2%, an equity ratio of 52.50%52.5% and an electric rate base of approximately $677 million. Interim rates, subject to refund, of approximately $16 million were implemented on
In August 2021, the NDPSC approved a settlement between NSP-Minnesota and various parties, which includes the following, effective Jan. 5, 2021.
2020 TCR Electric Rider — In November 2019, NSP-Minnesota filed the TCR Rider based on an ROE of 9.06%. An MPUC decision is pending.
2020 GUIC Natural Gas Rider — In November 2019, NSP-Minnesota filed the GUIC Rider based on an ROE of 9.04%. An MPUC decision is pending.
2021 GUIC Natural Gas Rider — In October 2020, NSP-Minnesota filed the GUIC Rider based on an ROE of 9.04%. An MPUC decision is pending.
2020 RES Electric Rider — In November 2019, NSP-Minnesota filed the RES Rider. The requested amount includes a true-up for the 2019 rider of $38 million and the 2020 requested amount of $64 million. The filing included an ROE of 9.06%. An MPUC decision is pending.
2021 RES Electric Rider — In November 2020, NSP-Minnesota filed the RES Rider. The requested amount includes a true-up for the 2019 and 2020 rider of $96 million and the 2021 requested amount of $93 million. The filing included an ROE of 9.06%. An MPUC decision is pending.
Minnesota Resource Plan —In July 2019, NSP-Minnesota filed its Minnesota resource plan, which runs through 2034. The plan would result in an 80% carbon reduction by 2030 (from 2005) and puts NSP-Minnesota on a path to achieving its vision of being 100% carbon-free by 2050.
The updated preferred resource plan reflects the following:1, 2021:
•RetirementBase revenue increase of all coal generation by 2030 with reduced operations at some units prior to retirement, including early retirement of the A.S. King coal plant (511 MW) in 2028 and the Sherco 3 coal plant (517 MW) in 2030.$7 million.
•Extending the lifeROE of the Monticello nuclear plant from 2030 to 2040.
•Continuing to run the PI through current end of life (2033 and 2034)9.5%.
•ConstructionEquity ratio of the Sherco combined cycle natural gas plant.
•The addition of 3,500 MW of solar.
•The addition of 2,250 MW of wind.
•2,600 MW of firm peaking (combustion turbine, pumped hydro, battery storage, demand response, etc.)52.5%.
•Achieving 780 GWh in energy efficiency savings annually through 2034.Deferral of advanced grid intelligence and security initiative capital and O&M expenses.
•Adding 400 MWAn earnings cap mechanism, which would return to customers 100% of incremental demand response by 2023, and a totalearnings equal to or in excess of 1,500 MW of demand response by 2034.9.75% ROE, effective until the next rate case.
Initial comments were submitted Feb. 11, 2021 and reply comments are due April 12, 2021. The MPUC is anticipated to make a final decision during 2021.
Minnesota Relief and Recovery — In 2020, the MPUC opened a docket and invited utilities in the state to submit potential projects that would create jobs and help jump start the economy to offset the impacts of COVID-19.
NSP-Minnesota’s proposal includedThe status of the following:various proposals is listed below:
•RepowerIn January 2021, the MPUC approved NSP-Minnesota’s request for the repowering of 651 MW of owned wind projects (capital investment of $750 million) as well as certain wind projects under PPAs.
•Acquire 120 MW repowered wind farm and buy-out of the remaining PPA from ALLETE for $210 million.
•Add solar facilities of 460 MW with an incremental investment of $550 million.
•Accelerate certain grid investment.
•Provide $150 million of incremental electric vehicle rebates.
In December 2020, the MPUC verbally approved the repowering of owned wind projects and 20 MW of wind projects under PPAs. These projects are estimated to save customers approximately $160 million over the next 25 years.
•In April 2021, NSP-Minnesota proposed to add 460 MW of solar facilities at the Sherco site with an incremental investment of approximately $575 million. An MPUC decision is expected by the third quarter of 2022.
•In June 2021, the MPUC approved NSP-Minnesota’s proposal to acquire a repowered wind farm from ALLETE, Inc.
•The MPUC is expectedalso considering NSP-Minnesota’s revised proposal to addressprovide $40 million of incremental electric vehicle rebates.
Minnesota Resource Plan—In July 2019, NSP-Minnesota filed its Minnesota resource plan, which runs through 2034.
On Feb. 8, 2022, the MPUC approved the following:
•10-year extension for the Monticello nuclear facility.
•Retirement of the A.S. King plant in 2028 and Sherco 3 in 2030.
•NSP-Minnesota ownership of Sherco and A.S. King gen-tie lines plus additional renewable resources on the lines up to its current interconnection rights (2,000 MW for Sherco and 600 MW for A.S. King).
•The need for 2,150 MW of new wind and 2,500 MW of new solar facilities, ALLETE PPA wind repowering acquisitionby 2032, as well as additional renewable generation of 1,100 MW beyond 2032.
•Recognition of the need for 800 MW of additional firm dispatchable resources between 2027 and 2029. The dispatchable generation will need to be approved through a CON process.
The next Minnesota resource plan is due on Feb. 1, 2024.
2022 RES Electric Rider — In November 2021, NSP-Minnesota filed the RES Rider. The requested amount of $264 million includes a true-up (2020 and 2021 riders) of $154 million and the electric vehicle proposal2022 requested amount of $110 million. The filing included a ROE of 9.06%. An MPUC decision is pending.
2021 RES Electric Rider — In November 2020, NSP-Minnesota filed the RES Rider. The requested amount of $189 million includes a true-up (2019 and 2020 riders) of $96 million and the 2021 requested amount of $93 million. The filing included a ROE of 9.06%. An MPUC decision is pending.
2022 GUIC Natural Gas Rider — In October 2021, NSP-Minnesota filed the GUIC Rider for an amount of $27 million based on a ROE of 9.04%. An MPUC decision is pending.
2021 GUIC Natural Gas Rider — In October 2020, NSP-Minnesota filed the GUIC Rider for an amount of $27 million based on a ROE of 9.04%. An MPUC decision is pending.
2022 TCR Electric Rider — In November 2021, NSP-Minnesota filed the TCR Rider for an amount of $105 million based on a ROE of 9.06%. An MPUC decision is pending.
2020 TCR Electric Rider — In November 2019, NSP-Minnesota filed the TCR Rider for an amount of $82 million based on a ROE of 9.06%, which was approved by the MPUC in December 2021.
FERC NOPR on ROE Incentive Adders — In April 2021, the second halfFERC issued a NOPR proposing to limit collection of 2021.ROE incentive adders for RTO membership to the first three years after an entity begins participation in an RTO. If adopted as a final rule, NSP-Minnesota would prospectively discontinue charging their current 50 basis point ROE incentive adders. Amounts related to a discontinuance of the adder would ultimately be offset by an increase in retail rates, subject to future rate cases.
Purchased Power Arrangements and Transmission Service Provider
NSP-Minnesota expects to use power plants, power purchases, CIP/DSM options, new generation facilities and expansion of power plants to meet its system capacity requirements.
Purchased Power — NSP-Minnesota has contracts to purchase power from other utilities and IPPs. Long-term purchased power contracts for dispatchable resources typically require a capacity and an energy charge.
NSP-Minnesota makes short-term purchases to meet system requirements, replace company owned generation, meet operating reserve obligations or obtain energy at a lower cost.
Purchased Transmission Services — NSP-Minnesota and NSP-Wisconsin have contracts with MISO and other regional transmission service providers to deliver power and energy to their customers.
Minnesota State ROFR Statute Complaint — In September 2017, LSP Transmission filed a complaint in the Minnesota District Court against the Minnesota Attorney General, MPUC and DOC. The complaint was in response to MISO assigning NSP-Minnesota and ITC Midwest, LLC to jointly own a new 345 KV transmission line from Mankato to Winnebago, Minnesota. The project is estimated to cost approximately $120 million and projected to be in-service by the end of 2021. It was assigned to NSP-Minnesota and ITC Midwest as the incumbent utilities, consistent with a Minnesota state ROFR statute.
The complaint challenged the constitutionality of the statute and is seeking declaratory judgment that the statute violates the Commerce Clause of the U.S. Constitution and should not be enforced. In June 2018, the Minnesota District Court granted Minnesota state agencies and NSP-Minnesota’s motions to dismiss with prejudice. In February 2020, the Eighth Circuit Court of Appeals upheld the Minnesota District Court decision to dismiss. In June 2020, the Eighth Circuit denied LSP Transmission’s petition for rehearing. In November 2020, LSP Transmission petitioned the U.S. Supreme Court to review its appeal. NSP-Minnesota filed a brief in opposition to this petition on Jan. 25, 2021.
Nuclear Power Operations
Nuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.
NRC Regulation — The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.
Low-Level Waste Disposal — Low level waste disposal from Monticello and PI is disposed at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site at PI and Monticello which would allow both plants to continue to operate until the end of their current licensed lives if off-site low-level waste disposal facilities become unavailable.
High-Level Radioactive Waste Disposal — The federal government has responsibility to permanently dispose domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility. Currently, there are no definitive plans for a permanent federal storage facility site.
Nuclear Spent Fuel Storage — NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and PI nuclear generating plants. Authorized storage capacity is sufficient to allow NSP-Minnesota to operate until the end of the operating licenses in 2030 for Monticello, 2033 for PI Unit 1, and 2034 for PI Unit 2. Authorizations for additional spent fuel storage capacity may be required at each site to support either continued operation or decommissioning if the federal government does not commence storage operations.
Monticello CON — In September 2021, NSP-Minnesota filed an application for a CON for additional spent fuel storage (existing Independent spent fuel storage installation) at the Monticello Nuclear Power Generating Plant. The CON requests sufficient additional spent fuel storage at the existing Independent spent fuel storage installation to allow continued operation of the Monticello Plant until 2040. The filing passed completeness review and has been referred to an ALJ. A decision is expected in late 2023.
Wholesale and Commodity Marketing Operations
NSP-Minnesota conducts wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy-related products. NSP-Minnesota uses physical and financial instruments to minimize commodity price and credit risk and to hedge sales and purchases.
NSP-Minnesota also engages in trading activity unrelated to hedging. Sharing of any margins is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement. NSP-Minnesota does not serve any wholesale requirements customers at cost-based regulated rates.
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ITEM 7A — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
Derivatives, Risk Management and Market Risk
NSP-Minnesota 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 of a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk.
See Note 8 to the consolidated financial statements for further information.
NSP-Minnesota is exposed to the impact of adverse changes in price for energy and energy related products, which is partially mitigated by the use of commodity derivatives. In addition to ongoing monitoring and maintaining credit policies intended to minimize overall credit risk, management takes steps to mitigate changes in credit and concentration risks associated with its derivatives and other contracts, including parental guarantees and requests of collateral. While NSP-Minnesota expects that the counterparties will perform under the contracts underlying its derivatives, the contracts expose NSP-Minnesota to certain credit and non-performance risk.
Distress in the financial markets may impact counterparty risk, the fair value of the securities in the nuclear decommissioning fund and pension fund and NSP-Minnesota’s ability to earn a return on short-term investments.
Commodity Price Risk — NSP-Minnesota is exposed to commodity price risk in its electric and natural gas operations. Commodity price risk is managed by entering into long- and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products and fuels used in generation and distribution activities. Commodity price risk is also managed through the use of financial derivative instruments. NSP-Minnesota’s risk management policy allows it to manage commodity price risk within each rate-regulated operation per commission approved hedge plans.
Wholesale and Commodity Trading Risk — NSP-Minnesota 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. NSP-Minnesota’s risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee.
Fair value of net commodity trading contracts as of Dec. 31, 2020:2021:
| | | Futures/ Forwards Maturity | | Futures/ Forwards Maturity |
| (Millions of Dollars) | (Millions of Dollars) | |
Less Than 1 Year | |
1 to 3 Years | |
4 to 5 Years | |
Greater Than 5 Years | | Total
Fair Value | (Millions of Dollars) | |
Less Than 1 Year | |
1 to 3 Years | |
4 to 5 Years | |
Greater Than 5 Years | | Total
Fair Value |
NSP-Minnesota (a) | NSP-Minnesota (a) | | $ | (2) | | | $ | 1 | | | $ | 2 | | | $ | 2 | | | $ | 3 | | NSP-Minnesota (a) | | $ | (4) | | | $ | (7) | | | $ | — | | | $ | (1) | | | $ | (12) | |
NSP-Minnesota (b) | NSP-Minnesota (b) | | (3) | | | 3 | | | (7) | | | (6) | | | (13) | | NSP-Minnesota (b) | | (1) | | | 3 | | | (9) | | | (8) | | | (15) | |
| | $ | (5) | | | $ | 4 | | | $ | (5) | | | $ | (4) | | | $ | (10) | | | $ | (5) | | | $ | (4) | | | $ | (9) | | | $ | (9) | | | $ | (27) | |
| | | Options Maturity | | Options Maturity |
| (Millions of Dollars) | (Millions of Dollars) | |
Less Than 1 Year | |
1 to 3 Years | |
4 to 5 Years | |
Greater Than 5 Years | | Total
Fair Value | (Millions of Dollars) | |
Less Than 1 Year | |
1 to 3 Years | |
4 to 5 Years | |
Greater Than 5 Years | | Total
Fair Value |
NSP-Minnesota (b) | NSP-Minnesota (b) | | $ | 1 | | | $ | — | | | $ | — | | | $ | 1 | | | $ | 2 | | NSP-Minnesota (b) | | $ | 1 | | | $ | — | | | $ | — | | | $ | 8 | | | $ | 9 | |
(a)Prices actively quoted or based on actively quoted prices.
(b)Prices based on models and other valuation methods.
Changes in the fair value of commodity trading contracts before the impacts of margin-sharing for the years ended Dec. 31:
| | (Millions of Dollars) | (Millions of Dollars) | | 2020 | | 2019 | (Millions of Dollars) | | 2021 | | 2020 |
| Fair value of commodity trading net contracts outstanding at Jan. 1 | Fair value of commodity trading net contracts outstanding at Jan. 1 | | $ | (2) | | | $ | 16 | | Fair value of commodity trading net contracts outstanding at Jan. 1 | | $ | (8) | | | $ | (2) | |
| Contracts realized or settled during the period | Contracts realized or settled during the period | | (11) | | | (11) | | Contracts realized or settled during the period | | (58) | | | (11) | |
| Commodity trading contract additions and changes during the period | Commodity trading contract additions and changes during the period | | 5 | | | (7) | | Commodity trading contract additions and changes during the period | | 48 | | | 5 | |
| Fair value of commodity trading net contracts outstanding at Dec. 31 | Fair value of commodity trading net contracts outstanding at Dec. 31 | | $ | (8) | | | $ | (2) | | Fair value of commodity trading net contracts outstanding at Dec. 31 | | $ | (18) | | | $ | (8) | |
At Dec. 31, 2020,2021, a 10% increase in market prices for commodity trading contracts through the forward curve would increase pretax income from continuing operations by approximately $6$3 million, whereas a 10% decrease would decrease pretax income from continuing operations by approximately $6$3 million. At Dec. 31, 2019,2020, a 10% increase in market prices for commodity trading contracts would increase pretax income from continuing operations by approximately $6 million, whereas a 10% decrease would decrease pretax income from continuing operations by approximately $6 million. Market price movements can exceed 10% under abnormal circumstances.
NSP-Minnesota’s commodity trading operations measure the outstanding risk exposure to price changes on contracts and obligations that have been entered into, but not closed, using an industry standard methodology known as VaR. VaR expresses the potential change in fair value on the outstanding contracts and obligations over a particular period of time under normal market conditions.
The VaRs for the NSP-Minnesota and PSCo commodity trading operations, excluding both non-derivative transactions and derivative transactions designated as normal purchase, normal sales, calculated on a consolidated basis using a Monte Carlo simulation with a 95% confidence level and a one-day holding period, were as follows:
| | (Millions of Dollars) | (Millions of Dollars) | | Year Ended Dec. 31 | | VaR Limit | | Average | | High | | Low | (Millions of Dollars) | | Year Ended Dec. 31 | | VaR Limit | | Average | | High | | Low |
| 2021 | | 2021 | | $ | 1 | | | $ | 3 | | | $ | 2 | | | $ | 52 | | | $ | 1 | |
| 2020 | 2020 | | $ | 1 | | | $ | 3 | | | $ | 1 | | | $ | 2 | | | $ | 1 | | 2020 | | 1 | | | 3 | | | 1 | | | 2 | | | 1 | |
| 2019 | | < 1 | | 3 | | | 1 | | | 1 | | | < 1 | |
A short-term increase in VaR occurred during the week of Feb. 12, 2021 through Feb. 18, 2021. On Feb. 17, 2021, the portfolio VaR reached a high of $52 million. This increase in VaR was driven by the unprecedented market conditions during Winter Storm Uri. Prior to this widespread weather event, VaR was $1 million and returned to $1 million by Feb. 19, 2021.
Nuclear Fuel Supply — NSP-Minnesota has contracted for approximately 11%78% of its 20212022 enriched nuclear material requirements from sources that could be impacted by sanctions against entities doing business with Iran. Those sanctions may impact the supply of enriched nuclear material supplied from Russia. Long-term, through 2030, NSP-Minnesota is scheduled to take delivery of approximately 28%30% of its average enriched nuclear material requirements from these sources. NSP-Minnesota is able to manage nuclear fuel supply with alternate potential sources. NSP-Minnesota periodically assesses if further actions are required to assure a secure supply of enriched nuclear material.
Interest Rate Risk — NSP-Minnesota is subject to interest rate risk. NSP-Minnesota’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.
A 100-basis-point change in the benchmark rate on NSP-Minnesota’s variable rate debt would impact pretax interest expense annually by an immaterial amount in 20202021 and 2019,2020, respectively.
NSP-Minnesota maintains a nuclear decommissioning fund, as required by the NRC. The nuclear decommissioning fund is subject to interest rate risk and equity price risk. The fund is invested in a diversified portfolio of cash equivalents, debt securities, equity securities and other investments. These investments may be used only for the purpose of decommissioning NSP-Minnesota’s nuclear generating plants. Realized and unrealized gains on the decommissioning fund investments are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs. Fluctuations in equity prices or interest rates affecting the nuclear decommissioning fund do not have a direct impact on earnings due to the application of regulatory accounting.
Changes in discount rates and expected return on plan assets impact the value of pension and postretirement plan assets and/or benefit costs.
See Note 8 to the consolidated financial statements for further information.
Credit Risk — NSP-Minnesota is also exposed to credit risk. Credit risk relates to the risk of loss resulting from counterparties’ nonperformance on their contractual obligations. NSP-Minnesota maintains credit policies intended to minimize overall credit risk and actively monitor these policies to reflect changes and scope of operations.
At Dec. 31, 2021, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $28 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $18 million. At Dec. 31, 2020, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $9 million, while a decrease in prices of 10% would have resulted in an increase in credit exposure of $1 million. At Dec. 31, 2019, a 10% increase in commodity prices would have resulted in an increase in credit exposure
NSP-Minnesota conducts credit reviews for all counterparties and employs credit risk controls, such as letters of credit, parental guarantees, master netting agreements and termination provisions. Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. Distress in the financial markets could increase NSP-Minnesota’s credit risk.
Fair Value Measurements
NSP-Minnesota uses derivative contracts such as futures, forwards, interest rate swaps, options and FTRs to manage commodity price and interest rate risk. Derivative contracts, with the exception of those designated as normal purchase-normal sale contracts, are reported at fair value.
NSP-Minnesota’s investments held in the nuclear decommissioning fund, rabbi trusts, pension and other postretirement funds are also subject to fair value accounting.
Commodity Derivatives — NSP-Minnesota continuously monitors the creditworthiness of the counterparties to its commodity derivative contracts and assesses each counterparty’s ability to perform on the transactions. The impact of discounting commodity derivative assets for counterparty credit risk was not material to the fair value of commodity derivative assets at Dec. 31, 2020.2021.
Adjustments to fair value for credit risk of commodity trading instruments are recorded in electric revenues. Credit risk adjustments for other commodity derivative instruments are recorded as other comprehensive income or deferred as regulatory assets and liabilities. Classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. The impact of discounting commodity derivative liabilities for credit risk was immaterial at Dec. 31, 2020.2021.
See Notes 8 and 9 to the consolidated financial statements for further information.
Natural Gas Fuel and Electricity Purchases
In February 2021, the United States experienced winter storm Uri and extreme cold temperatures in the central United States. This severe weather event increased the demand for natural gas used in our electric and natural gas businesses. Certain operational assets were impacted by extreme cold temperatures and safety protocols and the cold further impacted the availability of renewable generation across the region (which typically acts as a hedge against commodity prices) contributing to extremely high market prices for natural gas and electricity. As a result, electric and natural gas fuel costs increased approximately $300 million. These amounts are preliminary estimates through Feb. 16, 2021 and are subject to final settlement.
NSP-Minnesota has fuel recovery mechanisms in all of its states to recover the increased cost of natural gas and electricity. However, given the impact of these higher costs to our customers during a pandemic, we expect our regulators to undertake a heightened review and we intend to work with our commissions to recover these costs over time to help mitigate the impacts on customer bills. NSP-Minnesota is taking action to increase planned debt issuances to ensure adequate liquidity for the timing difference between fuel payments and revenue collection from customers and to address any potential need to post collateral.
| | |
ITEM 8 — FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
See Item 15-1 for an index of financial statements included herein.
See Note 14 to the consolidated financial statements for further information.
Management Report on Internal Control Over Financial Reporting
The management of NSP-Minnesota is responsible for establishing and maintaining adequate internal control over financial reporting. NSP-Minnesota’s internal control system was designed to provide reasonable assurance to Xcel Energy Inc.’s and NSP-Minnesota’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.
NSP-Minnesota management assessed the effectiveness of NSP-Minnesota’s internal control over financial reporting as of Dec. 31, 2020.2021. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework (2013). Based on our assessment, we believe that, as of Dec. 31, 2020,2021, NSP-Minnesota’s internal control over financial reporting is effective at the reasonable assurance level based on those criteria.
| | | | | | | | | | | |
/s/ BEN FOWKEROBERT C. FRENZEL | | /s/ BRIAN J. VAN ABEL | |
Ben FowkeRobert C. Frenzel | | Brian J. Van Abel | |
| Chairman, Chief Executive Officer and Director | | Executive Vice President, Chief Financial Officer and Director | |
Feb. 17, 202123, 2022 | | Feb. 17, 202123, 2022 | |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholder and the Board of Directors of Northern States Power Company, a Minnesota corporation
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Northern States Power Company, a Minnesota corporation and subsidiaries (the "Company") as of December 31, 20202021 and 2019,2020, 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, 2020,2021, 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, 20202021 and 2019,2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020,2021, 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 distribution companies in Minnesota, North Dakota and South Dakota, and natural gas distribution companies in Minnesota and North Dakota. The Company is also subject to the jurisdiction of the Federal Energy Regulatory Commission for its wholesale electric operations, hydroelectric generation licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with North American Electric Reliability Corporation standards, asset transactions and mergers and natural gas transactions in interstate commerce, (collectively with state utility regulatory agencies, the “Commissions”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation affects multiple financial statement line items and disclosures, including property, plant and equipment, regulatory assets and liabilities, operating revenues and expenses, and income taxes.
The Company is subject to regulatory rate setting processes. Rates are determined and approved in regulatory proceedings based on an analysis of the Company’s costs to provide utility service and a return on, and recovery of, the Company’s investment in assets required to deliver services to customers. Accounting for the Company’s regulated operations provides that rate-regulated entities report assets and liabilities consistent with the recovery of those incurred costs in rates, if it is probable that such rates will be charged and collected. The Commissions’ regulation of rates is premised on the full recovery of incurred costs and a reasonable rate of return on invested capital. Decisions by the Commissions in the future will impact the accounting for regulated operations, including decisions about the amount of allowable costs and return on invested capital included in rates and any refunds that may be required. In the rate setting process, the Company’s rates result in the recording of regulatory assets and liabilities based on the probability of future cash flows. Regulatory assets generally represent incurred or accrued costs that have been deferred because future recovery from customers is probable. Regulatory liabilities generally represent amounts that are expected to be refunded to customers in future rates or amounts collected in current rates for future costs.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of part of the cost of recently completed plant, and 3) a refund due to customers. Given that management’s accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:
•We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the recognition of regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
•We read relevant regulatory orders issued by the Commissions for the Company, regulatory statutes, interpretations, procedural schedules and memorandums, filings made by intervenors, experts’ testimony and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions’ treatment of similar costs under similar circumstances. We also evaluated regulatory filings for any evidence that intervenors are challenging full recovery of the cost of any capital projects. If the full recovery of project costs is being challenged by intervenors, we evaluated management’s assessment of the probability of a disallowance. We evaluated the external information and compared to the Company’s recorded regulatory assets and liabilities for completeness.
•We obtained management’s analysis and correspondence from counsel, as appropriate, regarding regulatory assets or liabilities not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.
| | |
| /s/ DELOITTE & TOUCHE LLP |
| Minneapolis, Minnesota |
February 17, 202123, 2022 |
|
| We have served as the Company’s auditor since 2002. |
NSP-MINNESOTA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(amounts in millions)
| | | Year Ended Dec. 31 | | Year Ended Dec. 31 |
| | 2020 | | 2019 | | 2018 | | 2021 | | 2020 | | 2019 |
| Operating revenues | Operating revenues | | | | | | Operating revenues | | | | | |
| Electric, non-affiliates | Electric, non-affiliates | $ | 4,131 | | | $ | 4,049 | | | $ | 4,034 | | Electric, non-affiliates | $ | 4,593 | | | $ | 4,131 | | | $ | 4,049 | |
| Electric, affiliates | Electric, affiliates | 440 | | | 457 | | | 474 | | Electric, affiliates | 501 | | | 440 | | | 457 | |
| Natural gas | Natural gas | 493 | | | 571 | | | 583 | | Natural gas | 623 | | | 493 | | | 571 | |
| Other | Other | 37 | | | 35 | | | 31 | | Other | 39 | | | 37 | | | 35 | |
| Total operating revenues | Total operating revenues | 5,101 | | | 5,112 | | | 5,122 | | Total operating revenues | 5,756 | | | 5,101 | | | 5,112 | |
| | Operating expenses | Operating expenses | | Operating expenses | |
| Electric fuel and purchased power | Electric fuel and purchased power | 1,626 | | | 1,601 | | | 1,701 | | Electric fuel and purchased power | 2,042 | | | 1,626 | | | 1,601 | |
| Cost of natural gas sold and transported | Cost of natural gas sold and transported | 263 | | | 327 | | | 345 | | Cost of natural gas sold and transported | 385 | | | 263 | | | 327 | |
| Cost of sales — other | Cost of sales — other | 22 | | | 23 | | | 20 | | Cost of sales — other | 23 | | | 22 | | | 23 | |
| Operating and maintenance expenses | Operating and maintenance expenses | 1,191 | | | 1,203 | | | 1,223 | | Operating and maintenance expenses | 1,190 | | | 1,191 | | | 1,203 | |
| Conservation program expenses | Conservation program expenses | 119 | | | 120 | | | 118 | | Conservation program expenses | 144 | | | 119 | | | 120 | |
| Depreciation and amortization | Depreciation and amortization | 825 | | | 791 | | | 742 | | Depreciation and amortization | 926 | | | 825 | | | 791 | |
| Taxes (other than income taxes) | Taxes (other than income taxes) | 259 | | | 260 | | | 257 | | Taxes (other than income taxes) | 264 | | | 259 | | | 260 | |
| Total operating expenses | Total operating expenses | 4,305 | | | 4,325 | | | 4,406 | | Total operating expenses | 4,974 | | | 4,305 | | | 4,325 | |
| | Operating income | Operating income | 796 | | | 787 | | | 716 | | Operating income | 782 | | | 796 | | | 787 | |
| | Other income (expense), net | Other income (expense), net | 2 | | | (1) | | | (7) | | Other income (expense), net | 4 | | | 2 | | | (1) | |
| Allowance for funds used during construction — equity | Allowance for funds used during construction — equity | 25 | | | 25 | | | 24 | | Allowance for funds used during construction — equity | 30 | | | 25 | | | 25 | |
| | Interest charges and financing costs | Interest charges and financing costs | | Interest charges and financing costs | |
| Interest charges — includes other financing costs of $8, $7 and $7, respectively | 249 | | | 233 | | | 227 | | |
| Interest charges — includes other financing costs of $8, $8 and $7, respectively | | Interest charges — includes other financing costs of $8, $8 and $7, respectively | 271 | | | 249 | | | 233 | |
| Allowance for funds used during construction — debt | Allowance for funds used during construction — debt | (11) | | | (12) | | | (13) | | Allowance for funds used during construction — debt | (13) | | | (11) | | | (12) | |
| Total interest charges and financing costs | Total interest charges and financing costs | 238 | | | 221 | | | 214 | | Total interest charges and financing costs | 258 | | | 238 | | | 221 | |
| | Income before income taxes | Income before income taxes | 585 | | | 590 | | | 519 | | Income before income taxes | 558 | | | 585 | | | 590 | |
| Income tax (benefit) expense | Income tax (benefit) expense | (6) | | | 47 | | | 27 | | Income tax (benefit) expense | (48) | | | (6) | | | 47 | |
| Net income | Net income | $ | 591 | | | $ | 543 | | | $ | 492 | | Net income | $ | 606 | | | $ | 591 | | | $ | 543 | |
| | See Notes to Consolidated Financial Statements | See Notes to Consolidated Financial Statements | See Notes to Consolidated Financial Statements |
NSP-MINNESOTA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(amounts in millions)
| | | Year Ended Dec. 31 | | Year Ended Dec. 31 |
| | 2020 | | 2019 | | 2018 | | 2021 | | 2020 | | 2019 |
| Net income | Net income | $ | 591 | | | $ | 543 | | | $ | 492 | | Net income | $ | 606 | | | $ | 591 | | | $ | 543 | |
| | Other comprehensive income | Other comprehensive income | | Other comprehensive income | |
| | | Derivative instruments: | Derivative instruments: | | Derivative instruments: | |
| | Reclassification of losses to net income, net of tax of $0 | 1 | | | 0 | | | 1 | | |
| Reclassification of losses to net income, net of tax of $— | | Reclassification of losses to net income, net of tax of $— | 2 | | | 1 | | | — | |
| | | Total other comprehensive income | Total other comprehensive income | 1 | | | 0 | | | 1 | | Total other comprehensive income | 2 | | | 1 | | | — | |
| Total comprehensive income | Total comprehensive income | $ | 592 | | | $ | 543 | | | $ | 493 | | Total comprehensive income | $ | 608 | | | $ | 592 | | | $ | 543 | |
| | See Notes to Consolidated Financial Statements | See Notes to Consolidated Financial Statements | See Notes to Consolidated Financial Statements |
NSP-MINNESOTA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(amounts in millions)
| | | Year Ended Dec. 31 | | Year Ended Dec. 31 |
| | 2020 | | 2019 | | 2018 | | 2021 | | 2020 | | 2019 |
| Operating activities | Operating activities | | | | | | Operating activities | | | | | |
| Net income | Net income | $ | 591 | | | $ | 543 | | | $ | 492 | | Net income | $ | 606 | | | $ | 591 | | | $ | 543 | |
| Adjustments to reconcile net income to cash provided by operating activities: | Adjustments to reconcile net income to cash provided by operating activities: | | Adjustments to reconcile net income to cash provided by operating activities: | |
| Depreciation and amortization | Depreciation and amortization | 831 | | | 798 | | | 748 | | Depreciation and amortization | 932 | | | 831 | | | 798 | |
| Nuclear fuel amortization | Nuclear fuel amortization | 123 | | | 119 | | | 122 | | Nuclear fuel amortization | 114 | | | 123 | | | 119 | |
| Deferred income taxes | Deferred income taxes | (67) | | | (39) | | | 41 | | Deferred income taxes | (36) | | | (67) | | | (39) | |
| Allowance for equity funds used during construction | Allowance for equity funds used during construction | (25) | | | (25) | | | (24) | | Allowance for equity funds used during construction | (30) | | | (25) | | | (25) | |
| Provision for bad debts | Provision for bad debts | 24 | | | 13 | | | 16 | | Provision for bad debts | 24 | | | 24 | | | 13 | |
| Net realized and unrealized hedging and derivative transactions | (4) | | | 19 | | | 27 | | |
| Changes in operating assets and liabilities: | Changes in operating assets and liabilities: | | Changes in operating assets and liabilities: | |
| Accounts receivable | Accounts receivable | (55) | | | 15 | | | (43) | | Accounts receivable | (89) | | | (55) | | | 15 | |
| Accrued unbilled revenues | Accrued unbilled revenues | 1 | | | 20 | | | 7 | | Accrued unbilled revenues | (71) | | | 1 | | | 20 | |
| Inventories | Inventories | (14) | | | (29) | | | (21) | | Inventories | (22) | | | (14) | | | (29) | |
| Other current assets | Other current assets | (9) | | | (3) | | | 95 | | Other current assets | 3 | | | (9) | | | (3) | |
| Accounts payable | Accounts payable | (1) | | | (13) | | | 11 | | Accounts payable | 69 | | | (1) | | | (13) | |
| Net regulatory assets and liabilities | Net regulatory assets and liabilities | (87) | | | (140) | | | 182 | | Net regulatory assets and liabilities | (282) | | | (87) | | | (140) | |
| Other current liabilities | Other current liabilities | (58) | | | (12) | | | (64) | | Other current liabilities | (5) | | | (58) | | | (12) | |
| Pension and other employee benefit obligations | Pension and other employee benefit obligations | (54) | | | (49) | | | (76) | | Pension and other employee benefit obligations | (41) | | | (54) | | | (49) | |
| Other, net | Other, net | (4) | | | (48) | | | (31) | | Other, net | (50) | | | (8) | | | (29) | |
| Net cash provided by operating activities | Net cash provided by operating activities | 1,192 | | | 1,169 | | | 1,482 | | Net cash provided by operating activities | 1,122 | | | 1,192 | | | 1,169 | |
| | Investing activities | Investing activities | | Investing activities | |
| Capital/construction expenditures | Capital/construction expenditures | (1,901) | | | (1,417) | | | (1,150) | | Capital/construction expenditures | (1,866) | | | (1,901) | | | (1,417) | |
| Purchase of investment securities | Purchase of investment securities | (1,398) | | | (995) | | | (853) | | Purchase of investment securities | (757) | | | (1,398) | | | (995) | |
| Proceeds from the sale of investment securities | Proceeds from the sale of investment securities | 1,378 | | | 975 | | | 833 | | Proceeds from the sale of investment securities | 743 | | | 1,378 | | | 975 | |
| Investments in utility money pool arrangement | Investments in utility money pool arrangement | (718) | | | (219) | | | (805) | | Investments in utility money pool arrangement | (821) | | | (718) | | | (219) | |
| Repayments from utility money pool arrangement | Repayments from utility money pool arrangement | 718 | | | 219 | | | 805 | | Repayments from utility money pool arrangement | 730 | | | 718 | | | 219 | |
| Other, net | Other, net | 1 | | | (3) | | | (4) | | Other, net | 1 | | | 1 | | | (3) | |
| Net cash used in investing activities | Net cash used in investing activities | (1,920) | | | (1,440) | | | (1,174) | | Net cash used in investing activities | (1,970) | | | (1,920) | | | (1,440) | |
| | Financing activities | Financing activities | | Financing activities | |
| Proceeds from (repayments of) short-term borrowings, net | 149 | | | (120) | | | 130 | | |
| (Repayments of) proceeds from short-term borrowings, net | | (Repayments of) proceeds from short-term borrowings, net | (179) | | | 149 | | | (120) | |
| Borrowings under utility money pool arrangement | Borrowings under utility money pool arrangement | 136 | | | 696 | | | 479 | | Borrowings under utility money pool arrangement | 434 | | | 136 | | | 696 | |
| Repayments under utility money pool arrangement | Repayments under utility money pool arrangement | (136) | | | (696) | | | (564) | | Repayments under utility money pool arrangement | (434) | | | (136) | | | (696) | |
| Proceeds from issuance of long-term debt | Proceeds from issuance of long-term debt | 677 | | | 580 | | | 0 | | Proceeds from issuance of long-term debt | 836 | | | 677 | | | 580 | |
| Repayment of long-term debt | Repayment of long-term debt | (300) | | | 0 | | | 0 | | Repayment of long-term debt | — | | | (300) | | | — | |
| Capital contributions from parent | Capital contributions from parent | 527 | | | 354 | | | 109 | | Capital contributions from parent | 649 | | | 527 | | | 354 | |
| Dividends paid to parent | Dividends paid to parent | (408) | | | (467) | | | (456) | | Dividends paid to parent | (431) | | | (408) | | | (467) | |
| Other, net | Other, net | 3 | | | 0 | | | 0 | | Other, net | — | | | 3 | | | — | |
| Net cash provided by (used in) financing activities | 648 | | | 347 | | | (302) | | |
| Net cash provided by financing activities | | Net cash provided by financing activities | 875 | | | 648 | | | 347 | |
| | Net change in cash and cash equivalents | (80) | | | 76 | | | 6 | | |
| Cash and cash equivalents at beginning of period | 126 | | | 50 | | | 44 | | |
| Cash and cash equivalents at end of period | $ | 46 | | | $ | 126 | | | $ | 50 | | |
| Net change in cash, cash equivalents and restricted cash | | Net change in cash, cash equivalents and restricted cash | 27 | | | (80) | | | 76 | |
| Cash, cash equivalents and restricted cash at beginning of period | | Cash, cash equivalents and restricted cash at beginning of period | 46 | | | 126 | | | 50 | |
| Cash, cash equivalents and restricted cash at end of period | | Cash, cash equivalents and restricted cash at end of period | $ | 73 | | | $ | 46 | | | $ | 126 | |
| | Supplemental disclosure of cash flow information: | Supplemental disclosure of cash flow information: | | Supplemental disclosure of cash flow information: | |
| Cash paid for interest (net of amounts capitalized) | Cash paid for interest (net of amounts capitalized) | $ | (230) | | | $ | (209) | | | $ | (207) | | Cash paid for interest (net of amounts capitalized) | $ | (245) | | | $ | (230) | | | $ | (209) | |
| Cash (paid) received for income taxes, net | (53) | | | (105) | | | 89 | | |
| Cash received (paid) for income taxes, net | | Cash received (paid) for income taxes, net | 11 | | | (53) | | | (105) | |
| | 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 | $ | 74 | | | $ | 95 | | | $ | 93 | | Accrued property, plant and equipment additions | $ | 242 | | | $ | 74 | | | $ | 95 | |
| Inventory transfers to property, plant and equipment | Inventory transfers to property, plant and equipment | 24 | | | 24 | | | 61 | | Inventory transfers to property, plant and equipment | 8 | | | 24 | | | 24 | |
| Operating lease right-of-use assets | Operating lease right-of-use assets | 2 | | | 629 | | | 0 | | Operating lease right-of-use assets | 4 | | | 2 | | | 629 | |
| Allowance for equity funds used during construction | Allowance for equity funds used during construction | 25 | | | 25 | | | 24 | | Allowance for equity funds used during construction | 30 | | | 25 | | | 25 | |
| | See Notes to Consolidated Financial Statements | See Notes to Consolidated Financial Statements | See Notes to Consolidated Financial Statements |
NSP-MINNESOTA AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(amounts in millions, except share and per share data)
| | | Dec. 31 | | Dec. 31 |
| | 2020 | | 2019 | | 2021 | | 2020 |
| Assets | Assets | | | | Assets | | | |
| Current assets | Current assets | | Current assets | |
| Cash and cash equivalents | Cash and cash equivalents | $ | 46 | | | $ | 126 | | Cash and cash equivalents | $ | 73 | | | $ | 46 | |
| Accounts receivable, net | Accounts receivable, net | 392 | | | 360 | | Accounts receivable, net | 429 | | | 392 | |
| Accounts receivable from affiliates | Accounts receivable from affiliates | 32 | | | 44 | | Accounts receivable from affiliates | 29 | | | 32 | |
| Investments in money pool arrangements | | Investments in money pool arrangements | 91 | | | — | |
| Accrued unbilled revenues | Accrued unbilled revenues | 248 | | | 251 | | Accrued unbilled revenues | 319 | | | 248 | |
| Inventories | Inventories | 295 | | | 305 | | Inventories | 309 | | | 295 | |
| Regulatory assets | Regulatory assets | 411 | | | 320 | | Regulatory assets | 527 | | | 411 | |
| Derivative instruments | Derivative instruments | 17 | | | 32 | | Derivative instruments | 53 | | | 17 | |
| Prepayments and other | Prepayments and other | 50 | | | 31 | | Prepayments and other | 46 | | | 50 | |
| Total current assets | Total current assets | 1,491 | | | 1,469 | | Total current assets | 1,876 | | | 1,491 | |
| | Property, plant and equipment, net | Property, plant and equipment, net | 15,308 | | | 14,244 | | Property, plant and equipment, net | 16,430 | | | 15,308 | |
| | Other assets | Other assets | | Other assets | |
| Nuclear decommissioning fund and other investments | Nuclear decommissioning fund and other investments | 2,830 | | | 2,495 | | Nuclear decommissioning fund and other investments | 3,308 | | | 2,830 | |
| Regulatory assets | Regulatory assets | 924 | | | 1,125 | | Regulatory assets | 718 | | | 924 | |
| Derivative instruments | Derivative instruments | 5 | | | 9 | | Derivative instruments | 33 | | | 5 | |
| Operating lease right-of-use assets | Operating lease right-of-use assets | 488 | | | 564 | | Operating lease right-of-use assets | 408 | | | 488 | |
| Other | Other | 14 | | | 10 | | Other | 36 | | | 14 | |
| Total other assets | Total other assets | 4,261 | | | 4,203 | | Total other assets | 4,503 | | | 4,261 | |
| Total assets | Total assets | $ | 21,060 | | | $ | 19,916 | | Total assets | $ | 22,809 | | | $ | 21,060 | |
| | Liabilities and Equity | Liabilities and Equity | | Liabilities and Equity | |
| Current liabilities | Current liabilities | | Current liabilities | |
| Current portion of long-term debt | Current portion of long-term debt | $ | 0 | | | $ | 300 | | Current portion of long-term debt | $ | 300 | | | $ | — | |
| Short-term debt | Short-term debt | 179 | | | 30 | | Short-term debt | — | | | 179 | |
| Accounts payable | Accounts payable | 438 | | | 388 | | Accounts payable | 522 | | | 438 | |
| Accounts payable to affiliates | Accounts payable to affiliates | 66 | | | 76 | | Accounts payable to affiliates | 63 | | | 66 | |
| Regulatory liabilities | Regulatory liabilities | 123 | | | 141 | | Regulatory liabilities | 117 | | | 123 | |
| Taxes accrued | Taxes accrued | 263 | | | 232 | | Taxes accrued | 260 | | | 263 | |
| Accrued interest | Accrued interest | 72 | | | 72 | | Accrued interest | 78 | | | 72 | |
| Dividends payable to parent | Dividends payable to parent | 106 | | | 94 | | Dividends payable to parent | 96 | | | 106 | |
| Derivative instruments | Derivative instruments | 22 | | | 25 | | Derivative instruments | 35 | | | 22 | |
| Operating lease liabilities | Operating lease liabilities | 85 | | | 80 | | Operating lease liabilities | 90 | | | 85 | |
| Other | Other | 154 | | | 202 | | Other | 166 | | | 154 | |
| Total current liabilities | Total current liabilities | 1,508 | | | 1,640 | | Total current liabilities | 1,727 | | | 1,508 | |
| | Deferred credits and other liabilities | Deferred credits and other liabilities | | Deferred credits and other liabilities | |
| Deferred income taxes | Deferred income taxes | 1,840 | | | 1,779 | | Deferred income taxes | 1,949 | | | 1,840 | |
| Deferred investment tax credits | Deferred investment tax credits | 18 | | | 20 | | Deferred investment tax credits | 17 | | | 18 | |
| Regulatory liabilities | Regulatory liabilities | 1,896 | | | 1,937 | | Regulatory liabilities | 1,927 | | | 1,896 | |
| Asset retirement obligations | Asset retirement obligations | 2,350 | | | 2,280 | | Asset retirement obligations | 2,585 | | | 2,350 | |
| Derivative instruments | Derivative instruments | 71 | | | 110 | | Derivative instruments | 71 | | | 71 | |
| Pension and employee benefit obligations | Pension and employee benefit obligations | 192 | | | 236 | | Pension and employee benefit obligations | 112 | | | 192 | |
| Operating lease liabilities | Operating lease liabilities | 443 | | | 526 | | Operating lease liabilities | 353 | | | 443 | |
| Other | Other | 69 | | | 86 | | Other | 48 | | | 69 | |
| Total deferred credits and other liabilities | Total deferred credits and other liabilities | 6,879 | | | 6,974 | | Total deferred credits and other liabilities | 7,062 | | | 6,879 | |
| | Commitments and contingencies | Commitments and contingencies | 0 | | 0 | Commitments and contingencies | 0 | | 0 |
| Capitalization | Capitalization | | Capitalization | |
| Long-term debt | Long-term debt | 5,904 | | | 5,221 | | Long-term debt | 6,447 | | | 5,904 | |
Common stock — 5,000,000 shares authorized of $0.01 par value; 1,000,000 shares outstanding at Dec. 31, 2020 and Dec. 31, 2019, respectively | 0 | | | 0 | | |
Common stock — 5,000,000 shares authorized of $0.01 par value; 1,000,000 shares outstanding at Dec. 31, 2021 and Dec. 31, 2020, respectively | | Common stock — 5,000,000 shares authorized of $0.01 par value; 1,000,000 shares outstanding at Dec. 31, 2021 and Dec. 31, 2020, respectively | — | | | — | |
| Additional paid in capital | Additional paid in capital | 4,585 | | | 4,068 | | Additional paid in capital | 5,202 | | | 4,585 | |
| Retained earnings | Retained earnings | 2,206 | | | 2,036 | | Retained earnings | 2,391 | | | 2,206 | |
| Accumulated other comprehensive loss | Accumulated other comprehensive loss | (22) | | | (23) | | Accumulated other comprehensive loss | (20) | | | (22) | |
| Total common stockholder's equity | Total common stockholder's equity | 6,769 | | | 6,081 | | Total common stockholder's equity | 7,573 | | | 6,769 | |
| Total liabilities and equity | Total liabilities and equity | $ | 21,060 | | | $ | 19,916 | | Total liabilities and equity | $ | 22,809 | | | $ | 21,060 | |
| | See Notes to Consolidated Financial Statements | See Notes to Consolidated Financial Statements | See Notes to Consolidated Financial Statements |
NSP-MINNESOTA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
(amounts in millions, except share data)
| | | Common Stock | | Accumulated Other
Comprehensive
Income (Loss) | | Total Common
Stockholder’s
Equity | | Common Stock | | Accumulated Other
Comprehensive
Income (Loss) | | Total Common
Stockholder’s
Equity |
| | Shares | | Par Value | | Additional Paid In Capital | | Retained Earnings | | | Shares | | Par Value | | Additional Paid In Capital | | Retained Earnings | |
| | Balance at Dec. 31, 2017 | 1,000,000 | | | $ | 0 | | | $ | 3,580 | | | $ | 1,920 | | | $ | (24) | | | $ | 5,476 | | |
| | Net income | | 492 | | | 492 | | |
| Other comprehensive income | | 1 | | | 1 | | |
| Dividends declared to parent | | (440) | | | (440) | | |
| Contribution of capital by parent | | 44 | | | 44 | | |
| Balance at Dec. 31, 2018 | Balance at Dec. 31, 2018 | 1,000,000 | | | $ | 0 | | | $ | 3,624 | | | $ | 1,972 | | | $ | (23) | | | $ | 5,573 | | Balance at Dec. 31, 2018 | 1,000,000 | | | $ | — | | | $ | 3,624 | | | $ | 1,972 | | | $ | (23) | | | $ | 5,573 | |
| | Net income | Net income | | 543 | | | 543 | | Net income | | 543 | | | 543 | |
| | Dividends declared to parent | Dividends declared to parent | | (479) | | | (479) | | Dividends declared to parent | | (479) | | | (479) | |
| Contribution of capital by parent | Contribution of capital by parent | | 444 | | | 444 | | Contribution of capital by parent | | 444 | | | 444 | |
| Balance at Dec. 31, 2019 | Balance at Dec. 31, 2019 | 1,000,000 | | | $ | 0 | | | $ | 4,068 | | | $ | 2,036 | | | $ | (23) | | | $ | 6,081 | | Balance at Dec. 31, 2019 | 1,000,000 | | | $ | — | | | $ | 4,068 | | | $ | 2,036 | | | $ | (23) | | | $ | 6,081 | |
| | Net income | Net income | | 591 | | | 591 | | Net income | | 591 | | | 591 | |
| Other comprehensive income | Other comprehensive income | | 1 | | | 1 | | Other comprehensive income | | 1 | | | 1 | |
| Dividends declared to parent | Dividends declared to parent | | (420) | | | (420) | | Dividends declared to parent | | (420) | | | (420) | |
| Contribution of capital by parent | Contribution of capital by parent | | 517 | | | 517 | | Contribution of capital by parent | | 517 | | | 517 | |
| Adoption of ASC Topic 326 | Adoption of ASC Topic 326 | | (1) | | | (1) | | Adoption of ASC Topic 326 | | (1) | | | (1) | |
| Balance at Dec. 31, 2020 | Balance at Dec. 31, 2020 | 1,000,000 | | | $ | 0 | | | $ | 4,585 | | | $ | 2,206 | | | $ | (22) | | | $ | 6,769 | | Balance at Dec. 31, 2020 | 1,000,000 | | | $ | — | | | $ | 4,585 | | | $ | 2,206 | | | $ | (22) | | | $ | 6,769 | |
| | Net income | | Net income | | 606 | | | 606 | |
| Other comprehensive income | | Other comprehensive income | | 2 | | | 2 | |
| Dividends declared to parent | | Dividends declared to parent | | (421) | | | (421) | |
| Contribution of capital by parent | | Contribution of capital by parent | | 617 | | | 617 | |
| | Balance at Dec. 31, 2021 | | Balance at Dec. 31, 2021 | 1,000,000 | | | $ | — | | | $ | 5,202 | | | $ | 2,391 | | | $ | (20) | | | $ | 7,573 | |
| | See Notes to Consolidated Financial Statements | See Notes to Consolidated Financial Statements | See Notes to Consolidated Financial Statements |
NORTHERN STATES POWER COMPANY - MINNESOTA
Notes to Consolidated Financial Statements
| | |
| 1. Summary of Significant Accounting Policies |
General — NSP-Minnesota 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.
NSP-Minnesota’s consolidated financial statements include its wholly-owned subsidiaries. In the consolidation process, all intercompany transactions and balances are eliminated. NSP-Minnesota has investments in certain plants and transmission facilities jointly owned with nonaffiliated utilities.
NSP-Minnesota’s proportionate share of jointly owned facilities is recorded as property, plant and equipment on the consolidated balance sheets and NSP-Minnesota’s proportionate share of the operating costs associated with these facilities is included in its consolidated statements of income.
NSP-Minnesota’s consolidated financial statements are presented in accordance with GAAP. All of NSP-Minnesota’s underlying accounting records also conform to the FERC uniform system of accounts or to systems required by various state regulatory commissions. Certain amounts in the consolidated financial statements or notes have been reclassified for comparative purposes; however, such reclassifications did not affect net income, total assets, liabilities, equity or cash flows.
NSP-Minnesota has evaluated events occurring after Dec. 31, 20202021 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation.
Use of Estimates — NSP-Minnesota uses estimates based on the best information available in recording transactions and balances resulting from business operations. Estimates are used onfor items such as plant depreciable lives or potential disallowances, AROs, certain regulatory assets and liabilities, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs. Recorded estimates are revised when better information becomes available or actual amounts can be determined. Revisions can affect operating results.
Regulatory Accounting — NSP-Minnesota accounts for income and expense items in accordance with accounting guidance for regulated operations. Under this guidance:
•Certain costs, which would otherwise be charged to expense or other comprehensive income, are deferred as regulatory assets based on the expected ability to recover the costs in future rates.
•Certain credits, which would otherwise be reflected as income or other comprehensive income, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred.
Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process. If changes in the regulatory environment occur, NSP-Minnesota may no longer be eligible to apply this accounting treatment and may be required to eliminate regulatory assets and liabilities from its balance sheet. Such changes could have a material effect on NSP-Minnesota’s results of operations, financial condition and cash flows.
See Note 4 for further information.
Income Taxes — NSP-Minnesota 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 financial statements. NSP-Minnesota defers income taxes for all temporary differences between pretax financial and taxable income and between the book and tax bases of assets and liabilities. NSP-Minnesota uses rates that are scheduled to be in effect when the temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the period that includes the enactment date.
The effects of NSP-Minnesota’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 would be refundable to utility customers over the remaining life of the related assets. NSP-Minnesota anticipates that a tax rate increase would result in the establishment of a regulatory asset, subject to regulatory approval.an evaluation of whether future recovery is expected.
Reversal of certain temporary differences are accounted for as current income tax expense due to the effects of past regulatory practices, when deferred taxes were not required to be recorded due to the use of flow through accounting for ratemaking purposes. Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize it over the book depreciable lives of the related property. The requirement to defer and amortize tax credits only applies to federal ITCs related to public utility property. Utility rate regulation also has resulted in the recognition of regulatory assets and liabilities related to income taxes. 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.
NSP-Minnesota 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. NSP-Minnesota 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 expense.
NSP-Minnesota reports interest and penalties related to income taxes within other (expense) income or interest charges in the consolidated statements of income.
Xcel Energy Inc. and its subsidiaries, including NSP-Minnesota, file consolidated federal income tax returns as well as consolidated or separate state income tax returns. Federal income taxes paid by Xcel Energy Inc. are allocated to its subsidiaries based on separate company computations. A similar allocation is made for state income taxes paid by Xcel Energy Inc. in connection with consolidated state filings. Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries.
See Note 7 for further information.
Property, Plant and Equipment and Depreciation in Regulated Operations — Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and AFUDC. The cost of plant retired is charged to accumulated depreciation and amortization. Amounts recovered in rates for future removal costs are recorded as regulatory liabilities. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance costs are charged to expense as incurred.
Maintenance and replacement of items determined to be less than a unit of property are charged to operating expenses as incurred. Planned maintenance activities are charged to operating expense unless the cost represents the acquisition of an additional unit of property or the replacement of an existing unit of property.
Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable. A loss is recognized in the current period if it becomes probable that part of a cost of a plant under construction or recently completed plant will be disallowed for recovery from customers and a reasonable estimate of the disallowance can be made.
For investments in property, plant and equipment that are abandoned and not expected to go into service, incurred costs and related deferred tax amounts are compared to the discounted estimated future rate recovery, and a loss is recognized, if necessary.
NSP-Minnesota records depreciation expense 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 recovered in rates as authorized by the appropriate regulatory entities. The amount of removal costs areis based on current factors used in existing depreciation rates. 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 3.7% for 2021, 3.7% for 2020 and 3.7% for 2019 and 3.6% for 2018.2019.
See Note 3 for further information.
AROs — NSP-Minnesota accounts for AROs under accounting guidance that requires a liability for the fair value of an ARO to be recognized in the period in which it 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, and the capitalized costs are depreciated over the useful life of the long-lived asset. Changes resulting from revisions to the timing or amount of expected asset retirement cash flows are recognized as an increase or a decrease in the ARO.
See Note 10 for further information.
Nuclear Decommissioning — Nuclear decommissioning studies that estimate NSP-Minnesota’s costs of decommissioning its nuclear power plants are performed at least every three3 years and submitted to the state commissions for approval.
NSP-Minnesota recovers regulator-approved decommissioning costs of its nuclear power plants over each facility’s expected service life, typically based on the triennial decommissioning studies. The studies consider estimated future costs of decommissioning and the market value of investments in trust funds and recommend annual funding amounts. Amounts collected in rates are deposited in the trust funds. For financial reporting purposes, NSP-Minnesota accounts for nuclear decommissioning as an ARO.
Restricted funds for the payment of future decommissioning expenditures for NSP-Minnesota’s nuclear facilities are included in nuclear decommissioning fund and other assets on the consolidated balance sheets.
See Notes 8 and 10 for further information.
Benefit Plans and Other Postretirement Benefits — NSP-Minnesota 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 NSP-Minnesota 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 anFor certain environmental expense iscosts related to facilities currently in use, such as for emission-control equipment, the cost is capitalized and depreciated over the life of the plant.
Estimated remediation costs are regularly adjusted as estimates are revised and remediation proceeds. If other participating potentially responsible parties exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for NSP-Minnesota’s expected share of the cost.
Future costs of restoring sites are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses. Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability.
See Note 10 for further information.
Revenue from Contracts with Customers — Performance obligations related to the sale of energy are satisfied as energy is delivered to customers. NSP-Minnesota 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.
NSP-Minnesota does not recognize a separate financing component of its collections from customers as contract terms are short-term in nature. NSP-Minnesota presents its revenues net of any excise or sales taxes or fees.
NSP-Minnesota recognizes physical sales to customers (native load and wholesale) on a gross basis in electric revenues and cost of sales. Revenues and charges for short-term physical wholesale sales of excess energy transacted through RTOs are also recorded on a gross basis. Other revenues and charges settled/facilitated through an RTO are recorded on a net basis in cost of sales.
NSP-Minnesota has various rate-adjustment mechanisms that provide for the recovery of natural gas, electric fuel and purchased energy costs. 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, 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.
See Note 6 for further information.
Cash and Cash Equivalents — NSP-Minnesota considers investments in instruments with a remaining maturity of three3 months or less at the time of purchase to be cash equivalents.
Accounts Receivable and Allowance for Bad Debts — Accounts receivable are stated at the actual billed amount net of an allowance for bad debts. NSP-Minnesota 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, 20202021 and 2019,2020, the allowance for bad debts waswas $45 million and $33 million, and $23 million, respectively.
Inventory — Inventory is recorded at average cost and consisted of the following: | | (Millions of Dollars) | (Millions of Dollars) | | Dec. 31, 2020 | | Dec. 31, 2019 | (Millions of Dollars) | | Dec. 31, 2021 | | Dec. 31, 2020 |
| Inventories | Inventories | | | | | Inventories | | | | |
| Materials and supplies | Materials and supplies | | $ | 178 | | | $ | 176 | | Materials and supplies | | $ | 181 | | | $ | 178 | |
| Fuel | Fuel | | 90 | | | 103 | | Fuel | | 81 | | | 90 | |
| Natural gas | Natural gas | | 27 | | | 26 | | Natural gas | | 47 | | | 27 | |
| Total inventories | Total inventories | | $ | 295 | | | $ | 305 | | Total inventories | | $ | 309 | | | $ | 295 | |
Fair Value Measurements — NSP-Minnesota presents cash equivalents, interest rate derivatives, commodity derivatives and nuclear decommissioning fund assets at estimated fair values in its consolidated financial statements. Cash equivalents are recorded at cost plus accrued interest; money market funds are measured using quoted NAVs.
For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used to 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, NSP-Minnesota may use quoted prices for similar contracts or internally prepared valuation models 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 estimate fair value for each security.
See Notes 8 and 9 for further information.
Derivative Instruments — NSP-Minnesota uses derivative instruments in connection with its interest rate, utility commodity price and commodity trading activities, including forward contracts, futures, swaps and options. Any derivative instruments not qualifying for the normal purchases and normal sales exception are recorded on the consolidated balance sheets at fair value as derivative instruments. Classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship.
Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability. Classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.
Gains or losses on commodity trading transactions are recorded as a component of electric operating revenues and interest rate hedging transactions are recorded as a component of interest expense.
Normal Purchases and Normal Sales — NSP-Minnesota enters into contracts for purchases and sales of commodities for use in its operations. At inception, contracts are evaluated to determine whether a derivative exists and/or whether an instrument may be exempted from derivative accounting if designated as a normal purchase or normal sale.
See Note 8 for further information.
Commodity Trading Operations — All applicable gains and losses related to commodity trading activities are shown on a net basis in electric operating revenues in the consolidated statements of income.
Commodity trading activities are not associated with energy produced from NSP-Minnesota’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. AFUDC 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 NSP-Minnesota’s rate base for establishing utility rates.
Alternative Revenue — Certain rate rider mechanisms (including decouplingdecoupling/sales true up and CIP/DSM programs) qualify as alternative revenue programs. These mechanisms arise from costs imposed upon the utility by action of a regulator or legislative body related to an environmental, public safety or other mandate.mandate or from other instances where the 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 recognized equal to the revenue requirement, which may include incentives and return on rate base items.
Billing amounts are revised periodically for differences between total amount collected and revenue earned, which may increase or decrease the level of revenue collected from customers. Alternative revenues arising from these programs are presented on a gross basis and disclosed separately from revenue from contracts with customers.
See Note 6 for further information.
Conservation Programs — Costs incurred for DSM and CIP programs are deferred if it is probable future revenue will recover the incurred cost. Revenues recognized for incentive programs for the recovery of lost margins and/or conservation performance incentives are limited to amounts expected to be collected within 24 months from the year they are earned. Regulatory assets are recognized to reflect the amount of costs or earned incentives that have not yet been collected from customers.
Emission Allowances — Emission allowances are recorded at cost, including broker commission fees. The inventory accounting model is utilized for all emission allowances and sales of these allowances are included in electric revenues.
Nuclear Refueling Outage Costs — NSP-Minnesota uses a deferral and amortization method for nuclear refueling costs. This method amortizes costs over the period between refueling outages consistent with rate recovery.
RECs — Cost of RECs that are utilized for compliance is recorded as electric fuel and purchased power expense. Sales of RECs are recorded in electric revenues on a gross basis. The cost of these RECs and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense.
Cost of RECs that are utilized to support commodity trading activities are recorded in a similar manner as the associated commodities and are shown on a net basis in electric operating revenues in the consolidated statements of income.
| | |
| 2. Accounting Pronouncements |
Recently Adopted
Credit Losses — In 2016, the FASB issued Financial Instruments - Credit Losses, Topic 326 (ASC Topic 326), which changes how entities account for losses on receivables and certain other assets. The guidance requires use of a current expected credit loss model, which may result in earlier recognition of credit losses than under previous accounting standards.
NSP-Minnesota implemented the guidance using a modified-retrospective approach, recognizing a cumulative effect charge of $1 million (after tax) to retained earnings on Jan. 1, 2020. Other than first-time recognition of an allowance for bad debts on accrued unbilled revenues, the Jan. 1, 2020 adoption of ASC Topic 326 did not have a significant impact on NSP-Minnesota’s consolidated financial statements.
| | |
| 3. Property, Plant and Equipment |
Major classes of property, plant and equipment
| | (Millions of Dollars) | (Millions of Dollars) | | Dec. 31, 2020 | | Dec. 31, 2019 | (Millions of Dollars) | | Dec. 31, 2021 | | Dec. 31, 2020 |
| Property, plant and equipment, net | Property, plant and equipment, net | | | | | Property, plant and equipment, net | | | | |
| Electric plant | Electric plant | | $ | 18,948 | | | $ | 18,519 | | Electric plant | | $ | 19,154 | | | $ | 18,948 | |
| Natural gas plant | Natural gas plant | | 1,707 | | | 1,563 | | Natural gas plant | | 1,864 | | | 1,707 | |
| Common and other property | Common and other property | | 955 | | | 887 | | Common and other property | | 1,007 | | | 955 | |
Plant to be retired (a) | Plant to be retired (a) | | 136 | | | 0 | | Plant to be retired (a) | | 719 | | | 136 | |
| CWIP | CWIP | | 1,150 | | | 846 | | CWIP | | 984 | | | 1,150 | |
| Total property, plant and equipment | Total property, plant and equipment | | 22,896 | | | 21,815 | | Total property, plant and equipment | | 23,728 | | | 22,896 | |
| Less accumulated depreciation | Less accumulated depreciation | | (7,898) | | | (7,945) | | Less accumulated depreciation | | (7,606) | | | (7,898) | |
| Nuclear fuel | Nuclear fuel | | 2,970 | | | 2,910 | | Nuclear fuel | | 3,081 | | | 2,970 | |
| Less accumulated amortization | Less accumulated amortization | | (2,660) | | | (2,536) | | Less accumulated amortization | | (2,773) | | | (2,660) | |
| Property, plant and equipment, net | Property, plant and equipment, net | | $ | 15,308 | | | $ | 14,244 | | Property, plant and equipment, net | | $ | 16,430 | | | $ | 15,308 | |
(a)Includes regulator-approved retirements of Sherco Units 1, 2 and 2.3 and A.S. King.
Joint Ownership of Generation and Transmission Facilities
Jointly owned assets as of Dec. 31, 2020:2021:
| | (Millions of Dollars, Except Percent Owned) | (Millions of Dollars, Except Percent Owned) | | Plant in Service | | Accumulated Depreciation | | CWIP | | Percent Owned | (Millions of Dollars, Except Percent Owned) | | Plant in Service | | Accumulated Depreciation | | | Percent Owned |
| Electric generation: | Electric generation: | | | | | | | | | Electric generation: | | | | | | | |
| Sherco Unit 3 | Sherco Unit 3 | | $ | 601 | | | $ | 435 | | | $ | 2 | | | 59 | % | Sherco Unit 3 | | $ | 620 | | | $ | 451 | | | | 59 | % |
| Sherco common facilities | Sherco common facilities | | 149 | | | 108 | | | 5 | | | 80 | | Sherco common facilities | | 178 | | | 108 | | | | 80 | |
| Sherco substation | Sherco substation | | 5 | | | 3 | | | 0 | | | 59 | | Sherco substation | | 5 | | | 4 | | | | 59 | |
| Electric transmission: | Electric transmission: | | Electric transmission: | | | |
| Grand Meadow | Grand Meadow | | 11 | | | 3 | | | 0 | | | 50 | | Grand Meadow | | 11 | | | 3 | | | | 50 | |
| Huntley Wilmarth | | Huntley Wilmarth | | 48 | | | 1 | | | | 50 | |
| CapX2020 | CapX2020 | | 954 | | | 108 | | | 33 | | | 51 | | CapX2020 | | 952 | | | 127 | | | | 51 | |
| Total | | $ | 1,720 | | | $ | 657 | | | $ | 40 | | | |
Total (a) | | Total (a) | | $ | 1,814 | | | $ | 694 | | | | |
(a)Projects additionally include $7 million in CWIP.
NSP-Minnesota’s share of operating expenses and construction expenditures is included in the applicable utility accounts. Respective owners are responsible for providing their own financing.
| | |
| 4. Regulatory Assets and Liabilities |
Regulatory assets and liabilities are created for amounts that regulators may allow to be collected or may require to be paid back to customers in future electric and natural gas rates. NSP-Minnesota would be required to recognize the write-off of regulatory assets and liabilities in net income or other comprehensive income if changes in the utility industry no longer allow for the application of regulatory accounting guidance under GAAP.
Components of regulatory assets:
| | (Millions of Dollars) | (Millions of Dollars) | | See Note(s) | | Remaining Amortization Period | | Dec. 31, 2020 | | Dec. 31, 2019 | (Millions of Dollars) | | See Note(s) | | Remaining Amortization Period | | Dec. 31, 2021 | | Dec. 31, 2020 |
| Regulatory Assets | Regulatory Assets | | | | | | Current | | Noncurrent | | Current | | Noncurrent | Regulatory Assets | | | | | | Current | | Noncurrent | | Current | | Noncurrent |
| Pension and retiree medical obligations | Pension and retiree medical obligations | | 9 | | | Various | | $ | 26 | | | $ | 364 | | | $ | 28 | | | $ | 378 | | Pension and retiree medical obligations | | 9 | | | Various | | $ | 24 | | | $ | 301 | | | $ | 26 | | | $ | 364 | |
| Deferred natural gas and electric energy/fuel costs | | Deferred natural gas and electric energy/fuel costs | | One to five years | | 138 | | | 190 | | | 8 | | | 18 | |
| Recoverable deferred taxes on AFUDC | | Recoverable deferred taxes on AFUDC | | Plant lives | | — | | | 114 | | | — | | | 113 | |
| Excess deferred taxes — TCJA | Excess deferred taxes — TCJA | | 7 | | Various | | 10 | | | 122 | | | 10 | | | 132 | | Excess deferred taxes — TCJA | | 7 | | Various | | 10 | | | 113 | | | 10 | | | 122 | |
| Recoverable deferred taxes on AFUDC | | | Plant lives | | 0 | | | 113 | | | 0 | | | 115 | | |
| Sales true-up and revenue decoupling | | Sales true-up and revenue decoupling | | One to two years | | 33 | | | 56 | | | 101 | | | 28 | |
| Benson biomass PPA termination and asset purchase | Benson biomass PPA termination and asset purchase | | Nine years | | 10 | | | 65 | | | 9 | | | 73 | | Benson biomass PPA termination and asset purchase | | Eight years | | 10 | | | 55 | | | 10 | | | 65 | |
| PI extended power uprate | PI extended power uprate | | 14 years | | 3 | | | 49 | | | 3 | | | 53 | | PI extended power uprate | | 13 years | | 4 | | | 46 | | | 3 | | | 49 | |
Contract valuation adjustments (a) | Contract valuation adjustments (a) | | 1, 8 | | Term of related contract | | 16 | | | 48 | | | 16 | | | 62 | | Contract valuation adjustments (a) | | 1, 8 | | Term of related contract | | 18 | | | 34 | | | 16 | | | 48 | |
| Purchased power contracts costs | | Purchased power contracts costs | | Term of related contract | | 6 | | | 27 | | | 4 | | | 32 | |
Conservation programs (b) | | Conservation programs (b) | | 1 | | One to two years | | 7 | | | 22 | | | 14 | | | 23 | |
| Laurentian biomass PPA termination | Laurentian biomass PPA termination | | Three years | | 18 | | | 36 | | | 19 | | | 54 | | Laurentian biomass PPA termination | | Two years | | 18 | | | 18 | | | 18 | | | 36 | |
| Purchased power contracts costs | | Term of related contract | | 4 | | | 32 | | | 3 | | | 36 | | |
| Sales true-up and revenue decoupling | | One to two years | | 101 | | | 28 | | | 54 | | | 16 | | |
Conservation programs (b) | | 1 | | One to two years | | 14 | | | 23 | | | 18 | | | 13 | | |
| Deferred purchased natural gas and electricity energy costs | | One to two years | | 8 | | | 18 | | | 6 | | | 6 | | |
| Nuclear refueling outage costs | | Nuclear refueling outage costs | | 1 | | One to two years | | 37 | | | 16 | | | 28 | | | 10 | |
| Losses on reacquired debt | Losses on reacquired debt | | Term of related debt | | 1 | | | 12 | | | 2 | | | 14 | | Losses on reacquired debt | | Term of related debt | | 1 | | | 11 | | | 1 | | | 12 | |
| Nuclear refueling outage costs | | 1 | | One to two years | | 28 | | | 10 | | | 43 | | | 17 | | |
| Environmental remediation costs | Environmental remediation costs | | 1, 10 | | Pending future rate cases | | 1 | | | 9 | | | 1 | | | 12 | | Environmental remediation costs | | 1, 10 | | Pending future rate cases | | — | | | 5 | | | 1 | | | 9 | |
| Renewable resources and environmental initiatives | | Renewable resources and environmental initiatives | | One to two years | | 170 | | | 3 | | | 129 | | | 1 | |
| State commission adjustments | State commission adjustments | | Plant lives | | 0 | | | 3 | | | 0 | | | 3 | | State commission adjustments | | Plant lives | | — | | | 3 | | | — | | | 3 | |
| Renewable resources and environmental initiatives | | One to two years | | 129 | | | 1 | | | 72 | | | 1 | | |
| Gas pipeline inspection and remediation costs | Gas pipeline inspection and remediation costs | | One to two years | | 26 | | | 0 | | | 26 | | | 0 | | Gas pipeline inspection and remediation costs | | One to two years | | 33 | | | — | | | 26 | | | — | |
Net AROs (c) | Net AROs (c) | | 1, 10 | | Various | | 0 | | | (32) | | | 0 | | | 118 | | Net AROs (c) | | 1, 10 | | Various | | — | | | (316) | | | — | | | (32) | |
| Other | Other | | Various | | 16 | | | 23 | | | 10 | | | 22 | | Other | | Various | | 18 | | | 20 | | | 16 | | | 23 | |
| Total regulatory assets | Total regulatory assets | | | $ | 411 | | | $ | 924 | | | $ | 320 | | | $ | 1,125 | | Total regulatory assets | | $ | 527 | | | $ | 718 | | | $ | 411 | | | $ | 924 | |
(a)Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.
(b)Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.
(c)Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments.
Components of regulatory liabilities:
| | (Millions of Dollars) | (Millions of Dollars) | | See Note(s) | | Remaining Amortization Period | | Dec. 31, 2020 | | Dec. 31, 2019 | (Millions of Dollars) | | See Note(s) | | Remaining Amortization Period | | Dec. 31, 2021 | | Dec. 31, 2020 |
| Regulatory Liabilities | Regulatory Liabilities | | | | | | Current | | Noncurrent | | Current | | Noncurrent | Regulatory Liabilities | | | | | | Current | | Noncurrent | | Current | | Noncurrent |
Deferred income tax adjustments and TCJA refunds (a) | Deferred income tax adjustments and TCJA refunds (a) | | 7 | | Various | | $ | 9 | | | $ | 1,326 | | | $ | 13 | | | $ | 1,389 | | Deferred income tax adjustments and TCJA refunds (a) | | 7 | | Various | | $ | 9 | | | $ | 1,256 | | | $ | 9 | | | $ | 1,326 | |
| Plant removal costs | Plant removal costs | | 1, 10 | | Various | | 0 | | | 544 | | | 0 | | | 520 | | Plant removal costs | | 1, 10 | | Various | | — | | | 613 | | | — | | | 544 | |
| Renewable resources and environmental initiatives | | Renewable resources and environmental initiatives | | Various | | 1 | | | 10 | | | 5 | | | — | |
| ITC deferrals | ITC deferrals | | 1 | | Various | | 0 | | | 8 | | | 0 | | | 8 | | ITC deferrals | | 1 | | Various | | — | | | 7 | | | — | | | 8 | |
Contract valuation adjustments (b) | Contract valuation adjustments (b) | | 1, 8 | | Less than one year | | 12 | | | 0 | | | 8 | | | 0 | | Contract valuation adjustments (b) | | 1, 8 | | Less than one year | | 29 | | | — | | | 12 | | | — | |
| DOE Settlement | DOE Settlement | | Less than one year | | 11 | | | 0 | | | 27 | | | 0 | | DOE Settlement | | Less than one year | | 14 | | | — | | | 11 | | | — | |
| Deferred electric energy costs | | Less than one year | | 8 | | | 0 | | | 24 | | | 0 | | |
| Renewable resources and environmental initiatives | | Less than one year | | 5 | | | 0 | | | 0 | | | 0 | | |
| Deferred natural gas and electric energy/fuel costs | | Deferred natural gas and electric energy/fuel costs | | Less than one year | | 14 | | | — | | | 8 | | | — | |
| Other | Other | | Various | | 78 | | | 18 | | | 69 | | | 20 | | Other | | Various | | 50 | | | 41 | | | 78 | | | 18 | |
Total regulatory liabilities (c) | Total regulatory liabilities (c) | | | $ | 123 | | | $ | 1,896 | | | $ | 141 | | | $ | 1,937 | | Total regulatory liabilities (c) | | $ | 117 | | | $ | 1,927 | | | $ | 123 | | | $ | 1,896 | |
(a)Includes the revaluation of recoverable/regulated plant ADITaccumulated deferred income taxes and revaluation impact of non-plant ADITaccumulated deferred income taxes due to the TCJA.
(b)Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.
(c)Revenue subject forto refund of $15 million and $17 million for 2021 and $24 million for 2020, and 2019, respectively, is included in other current liabilities.
At Dec. 31, 20202021 and 2019,2020, NSP-Minnesota’s regulatory assets not earning a return primarily included the unfunded portion of pension and retiree medical obligations and net AROs. In addition, regulatory assets included $399$691 million and $235$399 million at Dec. 31, 20202021 and 2019,2020, respectively, of past expenditures not earning a return. Amounts are related to funded pension obligations, sales true-up and revenue decoupling, purchased natural gas and electric energy costs (including those related to Winter Storm Uri), various renewable resources and certain environmental initiatives.
| | |
| 5. Borrowings and Other Financing Instruments |
Short-Term Borrowings
NSP-Minnesota meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility and the money pool.
Money Pool — Xcel Energy Inc. and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings between the utility subsidiaries. Xcel Energy Inc. may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy Inc.
Money pool borrowings for NSP-Minnesota were as follows:borrowings:
| | (Millions of Dollars, Except Interest Rates) | (Millions of Dollars, Except Interest Rates) | | Three Months Ended Dec. 31, 2020 | | Year Ended Dec. 31 | (Millions of Dollars, Except Interest Rates) | | Three Months Ended Dec. 31, 2021 | | Year Ended Dec. 31 |
| 2020 | | 2019 | | 2018 | | 2021 | | 2020 | | 2019 |
| Borrowing limit | Borrowing limit | | $ | 250 | | | $ | 250 | | | $ | 250 | | | $ | 250 | | Borrowing limit | | $ | 250 | | | $ | 250 | | | $ | 250 | | | $ | 250 | |
| Amount outstanding at period end | Amount outstanding at period end | | 0 | | | 0 | | | 0 | | | 0 | | Amount outstanding at period end | | — | | | — | | | — | | | — | |
| Average amount outstanding | Average amount outstanding | | 0 | | | 3 | | | 32 | | | 17 | | Average amount outstanding | | — | | | 6 | | | 3 | | | 32 | |
| Maximum amount outstanding | Maximum amount outstanding | | 18 | | | 116 | | | 250 | | | 143 | | Maximum amount outstanding | | — | | | 236 | | | 116 | | | 250 | |
| Weighted average interest rate, computed on a daily basis | Weighted average interest rate, computed on a daily basis | | 0.08 | % | | 1.53 | % | | 2.05 | % | | 1.96 | % | Weighted average interest rate, computed on a daily basis | | N/A | | 0.07 | % | | 1.53 | % | | 2.05 | % |
| Weighted average interest rate at period end | Weighted average interest rate at period end | | N/A | | N/A | | N/A | | N/A | Weighted average interest rate at period end | | N/A | | N/A | | N/A | | N/A |
Commercial Paper — Commercial paper outstanding for NSP-Minnesota was as follows:outstanding:
| | (Millions of Dollars, Except Interest Rates) | (Millions of Dollars, Except Interest Rates) | | Three Months Ended Dec. 31, 2020 | | Year Ended Dec. 31 | (Millions of Dollars, Except Interest Rates) | | Three Months Ended Dec. 31, 2021 | | Year Ended Dec. 31 |
| 2020 | | 2019 | | 2018 | | 2021 | | 2020 | | 2019 |
| Borrowing limit | Borrowing limit | | $ | 500 | | | $ | 500 | | | $ | 500 | | | $ | 500 | | Borrowing limit | | $ | 500 | | | $ | 500 | | | $ | 500 | | | $ | 500 | |
| Amount outstanding at period end | Amount outstanding at period end | | 179 | | | 179 | | | 30 | | | 150 | | Amount outstanding at period end | | — | | | — | | | 179 | | | 30 | |
| Average amount outstanding | Average amount outstanding | | 13 | | | 10 | | | 71 | | | 38 | | Average amount outstanding | | — | | | 26 | | | 10 | | | 71 | |
| Maximum amount outstanding | Maximum amount outstanding | | 179 | | | 179 | | | 317 | | | 198 | | Maximum amount outstanding | | 13 | | | 317 | | | 179 | | | 317 | |
| Weighted average interest rate, computed on a daily basis | Weighted average interest rate, computed on a daily basis | | 0.17 | % | | 1.25 | % | | 2.59 | % | | 2.08 | % | Weighted average interest rate, computed on a daily basis | | 0.15 | % | | 0.18 | % | | 1.25 | % | | 2.59 | % |
| Weighted average interest rate at end of period | Weighted average interest rate at end of period | | 0.18 | | | 0.18 | | | 2.05 | | | 2.97 | | Weighted average interest rate at end of period | | N/A | | N/A | | 0.18 | | | 2.05 | |
Letters of Credit — NSP-Minnesota uses letters of credit, typically with terms of one year, to provide financial guarantees for certain operating obligations. At both Dec. 31, 20202021 and 2019,2020, there were $109 million and $10 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 commercial paper programs to fulfill short-term funding needs, NSP-Minnesota must have revolving credit facilities in place at least equal to the amount of their respective commercial paper borrowing limits and cannot issue commercial paper in an aggregate amount exceeding available capacity under these credit facilities. The lines of credit provide short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.
Amended Credit Agreement— In June 2019, NSP-Minnesota entered into an amended five-year credit agreement with a syndicate of banks. The amended credit agreement has substantially the same terms and conditions as the prior credit agreement with the exception of the maturity, which is June 2024.
Features of NSP-Minnesota’s credit facility:
| Debt-to-Total Capitalization Ratio (a) | Debt-to-Total Capitalization Ratio (a) | | Amount Facility May Be Increased (millions) | | Additional Periods for Which a One-Year Extension May Be Requested (b) | Debt-to-Total Capitalization Ratio (a) | | Amount Facility May Be Increased (millions of dollars) | | Additional Periods for Which a One-Year Extension May Be Requested (b) |
| 2020 | | 2019 | | | | | |
| 2021 | | 2021 | | 2020 | | | | |
| 47 | 47 | % | | 48 | % | | $ | 100 | | | 2 | | 47 | % | | 47 | % | | $ | 100 | | | 2 | |
(a) The credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65%.
(b) All extension requests are subject to majority bank group approval.
The credit facility has a cross-default provision that NSP-Minnesota would be in default on its borrowings under the facility if it or any of its subsidiaries whose total assets exceed 15% of NSP-Minnesota’s consolidated total assets, default on indebtedness in an aggregate principal amount exceeding $75 million.
If NSP-Minnesota does not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender. As of Dec. 31, 2020,2021, NSP-Minnesota was in compliance with all financial covenants on its debt agreements.
NSP-Minnesota had the following committed credit facility available as of Dec. 31, 20202021 (in millions)millions of dollars):
| Credit Facility (a) | Credit Facility (a) | | Drawn (b) | | Available | Credit Facility (a) | | Drawn (b) | | Available |
| $ | 500 | | | $ | 189 | | | $ | 311 | | 500 | | | $ | 9 | | | $ | 491 | |
(a)This credit facility matures in June 2024.
(b)Includes outstanding commercial paper and letters of credit.
All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. NSP-Minnesota had 0no direct advances on the facility outstanding at Dec. 31, 20202021 and 2019.2020.
Bilateral Credit Agreement
—In March 2019, NSP-Minnesota entered into a one-yearApril 2021, NSP-Minnesota’s uncommitted bilateral credit agreement.agreement was renewed for an additional one-year term. The credit agreement is limited in use to support letters of credit. In March 2020, NSP-Minnesota renewed its bilateral credit agreement for an additional one-year term.
As of Dec. 31, 2020, NSP-Minnesota’s2021, NSP-Minnesota had $45 million outstanding letters of credit under the $75 million Bilateral Credit Agreement were as follows (in millions):
| | | | | | | | | | | | | | |
| Limit | | Amount Outstanding | | Available |
| $ | 75 | | | $ | 49 | | | $ | 26 | |
Long-Term Borrowings and Other Financing Instruments
Generally, all property of NSP-Minnesota is subject to the lien of its first mortgage indenture. Debt premiums, discounts and expenses are amortized over the life of the related debt. The premiums, discounts and expenses for refinanced debt are deferred and amortized over the life of the new issuance.
Long term debt obligations for NSP-Minnesota as of Dec. 31 (millions(in millions of dollars):
| | Financing Instrument | Financing Instrument | | Interest Rate | | Maturity Date | | 2020 | | 2019 | Financing Instrument | | Interest Rate | | Maturity Date | | 2021 | | 2020 |
| First mortgage bonds | First mortgage bonds | | 2.20 | % | | Aug. 15, 2020 | | $ | 0 | | | $ | 300 | | First mortgage bonds | | 2.15 | % | | Aug. 15, 2022 | | $ | 300 | | | $ | 300 | |
| First mortgage bonds | First mortgage bonds | | 2.15 | | | Aug. 15, 2022 | | 300 | | | 300 | | First mortgage bonds | | 2.60 | | | May 15, 2023 | | 400 | | | 400 | |
| First mortgage bonds | First mortgage bonds | | 2.60 | | | May 15, 2023 | | 400 | | | 400 | | First mortgage bonds | | 7.125 | | | July 1, 2025 | | 250 | | | 250 | |
| First mortgage bonds | First mortgage bonds | | 7.13 | | | July 1, 2025 | | 250 | | | 250 | | First mortgage bonds | | 6.50 | | | March 1, 2028 | | 150 | | | 150 | |
| First mortgage bonds | | 6.50 | | | March 1, 2028 | | 150 | | | 150 | | |
First mortgage bonds (a) | | First mortgage bonds (a) | | 2.25 | | | April 1, 2031 | | 425 | | | — | |
| First mortgage bonds | First mortgage bonds | | 5.25 | | | July 15, 2035 | | 250 | | | 250 | | First mortgage bonds | | 5.25 | | | July 15, 2035 | | 250 | | | 250 | |
| First mortgage bonds | First mortgage bonds | | 6.25 | | | June 1, 2036 | | 400 | | | 400 | | First mortgage bonds | | 6.25 | | | June 1, 2036 | | 400 | | | 400 | |
| First mortgage bonds | First mortgage bonds | | 6.20 | | | July 1, 2037 | | 350 | | | 350 | | First mortgage bonds | | 6.20 | | | July 1, 2037 | | 350 | | | 350 | |
| First mortgage bonds | First mortgage bonds | | 5.35 | | | Nov. 1, 2039 | | 300 | | | 300 | | First mortgage bonds | | 5.35 | | | Nov. 1, 2039 | | 300 | | | 300 | |
| First mortgage bonds | First mortgage bonds | | 4.85 | | | Aug. 15, 2040 | | 250 | | | 250 | | First mortgage bonds | | 4.85 | | | Aug. 15, 2040 | | 250 | | | 250 | |
| First mortgage bonds | First mortgage bonds | | 3.40 | | | Aug. 15, 2042 | | 500 | | | 500 | | First mortgage bonds | | 3.40 | | | Aug. 15, 2042 | | 500 | | | 500 | |
| First mortgage bonds | First mortgage bonds | | 4.13 | | | May 15, 2044 | | 300 | | | 300 | | First mortgage bonds | | 4.125 | | | May 15, 2044 | | 300 | | | 300 | |
| First mortgage bonds | First mortgage bonds | | 4.00 | | | Aug. 15, 2045 | | 300 | | | 300 | | First mortgage bonds | | 4.00 | | | Aug. 15, 2045 | | 300 | | | 300 | |
| First mortgage bonds | First mortgage bonds | | 3.60 | | | May 15, 2046 | | 350 | | | 350 | | First mortgage bonds | | 3.60 | | | May 15, 2046 | | 350 | | | 350 | |
| First mortgage bonds | First mortgage bonds | | 3.60 | | | Sept. 15, 2047 | | 600 | | | 600 | | First mortgage bonds | | 3.60 | | | Sept. 15, 2047 | | 600 | | | 600 | |
First mortgage bonds (b) | First mortgage bonds (b) | | 2.90 | | | March 1, 2050 | | 600 | | | 600 | | First mortgage bonds (b) | | 2.90 | | | March 1, 2050 | | 600 | | | 600 | |
First mortgage bonds (a)(b) | First mortgage bonds (a)(b) | | 2.60 | | | June 1, 2051 | | 700 | | | 0 | | First mortgage bonds (a)(b) | | 2.60 | | | June 1, 2051 | | 700 | | | 700 | |
First mortgage bonds (a) | | First mortgage bonds (a) | | 3.20 | | | April 1, 2052 | | 425 | | | — | |
| Other long-term debt | | Other long-term debt | | 3 | | | — | |
| Unamortized discount | Unamortized discount | | (42) | | | (31) | | Unamortized discount | | (44) | | | (42) | |
| Unamortized debt issuance cost | Unamortized debt issuance cost | | (54) | | | (48) | | Unamortized debt issuance cost | | (62) | | | (54) | |
| Current maturities | Current maturities | | 0 | | | (300) | | Current maturities | | (300) | | | — | |
| Total long-term debt | Total long-term debt | | $ | 5,904 | | | $ | 5,221 | | Total long-term debt | | $ | 6,447 | | | $ | 5,904 | |
(a)20202021 financing.
(b)20192020 financing.
Maturities of long-term debt are as follows:
| | (Millions of Dollars) | (Millions of Dollars) | | (Millions of Dollars) | |
| 2021 | | $ | 0 | | |
| 2022 | 2022 | | 300 | | 2022 | | $ | 300 | |
| 2023 | 2023 | | 400 | | 2023 | | 400 | |
| 2024 | 2024 | | 0 | | 2024 | | — | |
| 2025 | 2025 | | 250 | | 2025 | | 250 | |
| 2026 | | 2026 | | — | |
Deferred Financing Costs — Deferred financing costs of approximately $5462 million and $48$54 million, net of amortization, are presented as a deduction from the carrying amount of long-term debt at Dec. 31, 20202021 and 2019,2020, respectively.
Dividend Restrictions — NSP-Minnesota’s dividends are subject to the FERC’s jurisdiction, which prohibits the payment of dividends out of capital accounts. Dividend payments are solely to be paid from retained earnings.
NSP-Minnesota’s state regulatory commissions additionally impose dividend limitations, which are more restrictive than those imposed by the FERC.
Requirements and actuals as of Dec. 31, 2020:2021:
| Equity to Total
Capitalization Ratio
Required Range | Equity to Total
Capitalization Ratio
Required Range | | Equity to Total Capitalization Ratio Actual | Equity to Total
Capitalization Ratio
Required Range | | Equity to Total Capitalization Ratio Actual |
| Low | Low | | High | | 2020 | Low | | High | | 2021 |
| 47.1 | % | | 57.5 | % | | 52.7 | % | |
| 47.2 | | 47.2 | % | | 57.6 | % | | 52.9 | % |
| | Unrestricted Retained Earnings | Unrestricted Retained Earnings | | Total Capitalization | | Limit on Total Capitalization | Unrestricted Retained Earnings | | Total Capitalization | | Limit on Total Capitalization |
| $ | 1 | billion | | $ | 13 | billion | | $ | 13 | billion | 1,558 | million | | $ | 14,321 | million | | $ | 15,332 | million |
Revenue is classified by the type of goods/services rendered and market/customer type. NSP-Minnesota’s operating revenues consisted of the following:
| | | Year Ended Dec. 31, 2020 | | Year Ended Dec. 31, 2021 |
| (Millions of Dollars) | (Millions of Dollars) | | Electric | | Natural Gas | | All Other | | Total | (Millions of Dollars) | | Electric | | Natural Gas | | All Other | | Total |
| Major revenue types | Major revenue types | Major revenue types |
| Revenue from contracts with customers: | Revenue from contracts with customers: | Revenue from contracts with customers: |
| Residential | Residential | | $ | 1,375 | | | $ | 261 | | | $ | 31 | | | $ | 1,667 | | Residential | | $ | 1,374 | | | $ | 315 | | | $ | 33 | | | $ | 1,722 | |
| C&I | C&I | | 1,935 | | | 189 | | | 0 | | | 2,124 | | C&I | | 2,107 | | | 246 | | | — | | | 2,353 | |
| Other | Other | | 33 | | | 0 | | | 6 | | | 39 | | Other | | 33 | | | — | | | 6 | | | 39 | |
| Total retail | Total retail | | 3,343 | | | 450 | | | 37 | | | 3,830 | | Total retail | | 3,514 | | | 561 | | | 39 | | | 4,114 | |
| Wholesale | Wholesale | | 202 | | | 0 | | | 0 | | | 202 | | Wholesale | | 442 | | | — | | | — | | | 442 | |
| Transmission | Transmission | | 238 | | | 0 | | | 0 | | | 238 | | Transmission | | 242 | | | — | | | — | | | 242 | |
| Interchange | Interchange | | 440 | | | 0 | | | 0 | | | 440 | | Interchange | | 501 | | | — | | | — | | | 501 | |
| Other | Other | | 15 | | | 7 | | | 0 | | | 22 | | Other | | 7 | | | 14 | | | — | | | 21 | |
| Total revenue from contracts with customers | Total revenue from contracts with customers | | 4,238 | | | 457 | | | 37 | | | 4,732 | | Total revenue from contracts with customers | | 4,706 | | | 575 | | | 39 | | | 5,320 | |
| Alternative revenue and other | Alternative revenue and other | | 333 | | | 36 | | | 0 | | | 369 | | Alternative revenue and other | | 388 | | | 48 | | | — | | | 436 | |
| Total revenues | Total revenues | | $ | 4,571 | | | $ | 493 | | | $ | 37 | | | $ | 5,101 | | Total revenues | | $ | 5,094 | | | $ | 623 | | | $ | 39 | | | $ | 5,756 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended Dec. 31, 2020 |
| (Millions of Dollars) | | Electric | | Natural Gas | | All Other | | Total |
| Major revenue types | | | | | | | | |
| Revenue from contracts with customers: |
| Residential | | $ | 1,375 | | | $ | 261 | | | $ | 31 | | | $ | 1,667 | |
| C&I | | 1,935 | | | 189 | | | — | | | 2,124 | |
| Other | | 33 | | | — | | | 6 | | | 39 | |
| Total retail | | 3,343 | | | 450 | | | 37 | | | 3,830 | |
| Wholesale | | 202 | | | — | | | — | | | 202 | |
| Transmission | | 238 | | | — | | | — | | | 238 | |
| Interchange | | 440 | | | — | | | — | | | 440 | |
| Other | | 15 | | | 7 | | | — | | | 22 | |
| Total revenue from contracts with customers | | 4,238 | | | 457 | | | 37 | | | 4,732 | |
| Alternative revenue and other | | 333 | | | 36 | | | — | | | 369 | |
| Total revenues | | $ | 4,571 | | | $ | 493 | | | $ | 37 | | | $ | 5,101 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended Dec. 31, 2019 |
| (Millions of Dollars) | | Electric | | Natural Gas | | All Other | | Total |
| Major revenue types | | | | | | | | |
| Revenue from contracts with customers: |
| Residential | | $ | 1,280 | | | $ | 303 | | | $ | 30 | | | $ | 1,613 | |
| C&I | | 2,054 | | | 229 | | | 0 | | | 2,283 | |
| Other | | 33 | | | 0 | | | 5 | | | 38 | |
| Total retail | | 3,367 | | | 532 | | | 35 | | | 3,934 | |
| Wholesale | | 210 | | | 0 | | | 0 | | | 210 | |
| Transmission | | 216 | | | 0 | | | 0 | | | 216 | |
| Interchange | | 459 | | | 0 | | | 0 | | | 459 | |
| Other | | 12 | | | 9 | | | 0 | | | 21 | |
| Total revenue from contracts with customers | | 4,264 | | | 541 | | | 35 | | | 4,840 | |
| Alternative revenue and other | | 242 | | | 30 | | | 0 | | | 272 | |
| Total revenues | | $ | 4,506 | | | $ | 571 | | | $ | 35 | | | $ | 5,112 | |
| | | Year Ended Dec. 31, 2018 | | Year Ended Dec. 31, 2019 |
| (Millions of Dollars) | (Millions of Dollars) | | Electric | | Natural Gas | | All Other | | Total | (Millions of Dollars) | | Electric | | Natural Gas | | All Other | | Total |
| Major revenue types | Major revenue types | | | | | | | | | Major revenue types | | | | | | | | |
| Revenue from contracts with customers: | Revenue from contracts with customers: | Revenue from contracts with customers: |
| Residential | Residential | | $ | 1,308 | | | $ | 309 | | | $ | 27 | | | $ | 1,644 | | Residential | | $ | 1,280 | | | $ | 303 | | | $ | 30 | | | $ | 1,613 | |
| C&I | C&I | | 2,052 | | | 239 | | | 1 | | | 2,292 | | C&I | | 2,054 | | | 229 | | | — | | | 2,283 | |
| Other | Other | | 37 | | | 0 | | | 3 | | | 40 | | Other | | 33 | | | — | | | 5 | | | 38 | |
| Total retail | Total retail | | 3,397 | | | 548 | | | 31 | | | 3,976 | | Total retail | | 3,367 | | | 532 | | | 35 | | | 3,934 | |
| Wholesale | Wholesale | | 189 | | | 0 | | | 0 | | | 189 | | Wholesale | | 210 | | | — | | | — | | | 210 | |
| Transmission | Transmission | | 238 | | | 0 | | | 0 | | | 238 | | Transmission | | 216 | | | — | | | — | | | 216 | |
| Interchange | Interchange | | 474 | | | 0 | | | 0 | | | 474 | | Interchange | | 459 | | | — | | | — | | | 459 | |
| Other | Other | | 28 | | | 12 | | | 0 | | | 40 | | Other | | 12 | | | 9 | | | — | | | 21 | |
| Total revenue from contracts with customers | Total revenue from contracts with customers | | 4,326 | | | 560 | | | 31 | | | 4,917 | | Total revenue from contracts with customers | | 4,264 | | | 541 | | | 35 | | | 4,840 | |
| Alternative revenue and other | Alternative revenue and other | | 182 | | | 23 | | | 0 | | | 205 | | Alternative revenue and other | | 242 | | | 30 | | | — | | | 272 | |
| Total revenues | Total revenues | | $ | 4,508 | | | $ | 583 | | | $ | 31 | | | $ | 5,122 | | Total revenues | | $ | 4,506 | | | $ | 571 | | | $ | 35 | | | $ | 5,112 | |
Federal Tax Loss Carryback Claims — In 2020, Xcel Energy identified certain expenses related to tax years 2009 - 2011 that qualify for an extended carryback claim. As a result, a tax benefit of approximately $13 million was recognized in 2020.
Federal Audit — NSP-Minnesota is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. Statute of limitations applicable to Xcel Energy’s consolidated federal income tax returns expire as follows:
| | | | | | | | |
| Tax Year(s) | | Expiration |
| 2014 - 2016 | | July 2021December 2022 |
| 2018 | | September 2022 |
Additionally, the statute of limitations related to the federal tax credit carryforwards will remain open until those credits are utilized in subsequent returns. Further, the statute of limitations related to the additional federal tax loss carryback claim referenced abovefiled in 2020 has been extended. Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of this issue; however, the outcome and timing of a resolution is unknown.
In 2017, the IRS concluded the audit of tax years 2012 and 2013 and proposed an adjustment that would impact Xcel Energy’s NOL and ETR. Xcel Energy filed a protest with the IRS. In April 2020, Xcel Energy and Appeals reached an agreement and 0 material adjustments were required.
In 2018, the IRS began an audit of tax years 2014 - 2016. In July 2020, Xcel Energy and the IRS reached an agreement and the related benefit was recognized.
State Audits — NSP-Minnesota is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Dec. 31, 2020,2021, NSP-Minnesota’s earliest open tax year subject to examination by state taxing authorities under applicable statutes of limitations is 2009.2014. In July 2020, Minnesota began a reviewan audit of thetax years 2015 - 2018 Research and Experimentation Credits.2018. As of Dec. 31, 2020,2021, 0 material adjustments have been proposed.
Unrecognized Tax Benefits — Unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual ETR. In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain, but for which there is uncertainty about the timing of such deductibility.timing. A change in the periodtiming of deductibility would not affect the ETR but would accelerate the payment to the taxing authority to an earlier period.authority.
Unrecognized tax benefits - permanent vs temporary: | | (Millions of Dollars) | (Millions of Dollars) | | Dec. 31, 2020 | | Dec. 31, 2019 | (Millions of Dollars) | | Dec. 31, 2021 | | Dec. 31, 2020 |
| Unrecognized tax benefit — Permanent tax positions | Unrecognized tax benefit — Permanent tax positions | | $ | 21 | | | $ | 15 | | Unrecognized tax benefit — Permanent tax positions | | $ | 23 | | | $ | 21 | |
| Unrecognized tax benefit — Temporary tax positions | Unrecognized tax benefit — Temporary tax positions | | 3 | | | 5 | | Unrecognized tax benefit — Temporary tax positions | | 3 | | | 3 | |
| Total unrecognized tax benefit | Total unrecognized tax benefit | | $ | 24 | | | $ | 20 | | Total unrecognized tax benefit | | $ | 26 | | | $ | 24 | |
Changes in unrecognized tax benefits:
| | (Millions of Dollars) | (Millions of Dollars) | | 2020 | | 2019 | | 2018 | (Millions of Dollars) | | 2021 | | 2020 | | 2019 |
| Balance at Jan. 1 | Balance at Jan. 1 | | $ | 20 | | | $ | 17 | | | $ | 18 | | Balance at Jan. 1 | | $ | 24 | | | $ | 20 | | | $ | 17 | |
| Additions based on tax positions related to the current year | Additions based on tax positions related to the current year | | 2 | | | 3 | | | 2 | | Additions based on tax positions related to the current year | | 2 | | | 2 | | | 3 | |
| Reductions based on tax positions related to the current year | Reductions based on tax positions related to the current year | | 0 | | | (1) | | | 0 | | Reductions based on tax positions related to the current year | | — | | | — | | | (1) | |
| Additions for tax positions of prior years | Additions for tax positions of prior years | | 16 | | | 1 | | | 0 | | Additions for tax positions of prior years | | — | | | 16 | | | 1 | |
| Reductions for tax positions of prior years | Reductions for tax positions of prior years | | (14) | | | 0 | | | (1) | | Reductions for tax positions of prior years | | — | | | (14) | | | — | |
| Settlements with taxing authorities | | 0 | | | 0 | | | (2) | | |
| Balance at Dec. 31 | Balance at Dec. 31 | | $ | 24 | | | $ | 20 | | | $ | 17 | | Balance at Dec. 31 | | $ | 26 | | | $ | 24 | | | $ | 20 | |
Unrecognized tax benefits were reduced by tax benefits associated with NOL and tax credit carryforwards: | | | | | | | | | | | | | | |
| (Millions of Dollars) | | Dec. 31, 2020 | | Dec. 31, 2019 |
| NOL and tax credit carryforwards | | $ | (11) | | | $ | (16) | |
Net deferred tax liability associated with the unrecognized tax benefit amounts and related NOLs and tax credits carryforwards were $8 million and $11 million at Dec. 31, 2020 and Dec. 31, 2019, respectively. | | | | | | | | | | | | | | |
| (Millions of Dollars) | | Dec. 31, 2021 | | Dec. 31, 2020 |
| NOL and tax credit carryforwards | | $ | (13) | | | $ | (11) | |
As the IRS progresses its review of the tax loss carryback claims and as state audits resume and state review progresses,progress, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $15$14 million in the next 12 months.
Payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards.
Interest payable related to unrecognized tax benefits:
| | (Millions of Dollars) | (Millions of Dollars) | | 2020 | | 2019 | | 2018 | (Millions of Dollars) | | 2021 | | 2020 | | 2019 |
| Payable for interest related to unrecognized tax benefits at Jan. 1 | Payable for interest related to unrecognized tax benefits at Jan. 1 | | $ | (2) | | | $ | (1) | | | $ | (1) | | Payable for interest related to unrecognized tax benefits at Jan. 1 | | $ | (2) | | | $ | (2) | | | $ | (1) | |
| Interest expense related to unrecognized tax benefits | Interest expense related to unrecognized tax benefits | | 0 | | | (1) | | | 0 | | Interest expense related to unrecognized tax benefits | | — | | | — | | | (1) | |
| Payable for interest related to unrecognized tax benefits at Dec. 31 | Payable for interest related to unrecognized tax benefits at Dec. 31 | | $ | (2) | | | $ | (2) | | | $ | (1) | | Payable for interest related to unrecognized tax benefits at Dec. 31 | | $ | (2) | | | $ | (2) | | | $ | (2) | |
NaN amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2021, 2020 2019 or 2018.2019.
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) | (Millions of Dollars) | | 2020 | | 2019 | (Millions of Dollars) | | 2021 | | 2020 |
| Federal NOL carryforward | | Federal NOL carryforward | | $ | 77 | | | $ | — | |
| Federal tax credit carryforwards | Federal tax credit carryforwards | | $ | 543 | | | $ | 449 | | Federal tax credit carryforwards | | 704 | | | 543 | |
| State NOL carryforwards | State NOL carryforwards | | 151 | | | 133 | | State NOL carryforwards | | 344 | | | 151 | |
| Valuation allowances for state NOL carryforwards | Valuation allowances for state NOL carryforwards | | (1) | | | (1) | | Valuation allowances for state NOL carryforwards | | (1) | | | (1) | |
State tax credit carryforwards, net of federal detriment (a) | State tax credit carryforwards, net of federal detriment (a) | | 71 | | | 78 | | State tax credit carryforwards, net of federal detriment (a) | | 78 | | | 71 | |
Valuation allowances for state credit carryforwards, net of federal benefit (b) | Valuation allowances for state credit carryforwards, net of federal benefit (b) | | (59) | | | (66) | | Valuation allowances for state credit carryforwards, net of federal benefit (b) | | (64) | | | (59) | |
(a)State tax credit carryforwards are net of federal detriment of $19$21 million and $21$19 million as of Dec. 31, 20202021 and 2019,2020, respectively.
(b)Valuation allowances for state tax credit carryforwards were net of federal benefit of $16$17 million and $18$16 million as of Dec. 31, 20202021 and 2019,2020, respectively.
Federal carryforward periods expire between 2031 and 20402041 and state carryforward periods expire between 2021 and 2035.starting 2022.
Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense.
Effective income tax rate for years ended Dec. 31:
| | | 2020 | | 2019 | | 2018 | | 2021 | | 2020 | | 2019 |
| Federal statutory rate | Federal statutory rate | | 21.0 | % | | 21.0 | % | | 21.0 | % | Federal statutory rate | | 21.0 | % | | 21.0 | % | | 21.0 | % |
| State income tax on pretax income, net of federal tax effect | State income tax on pretax income, net of federal tax effect | | 7.0 | | | 7.1 | | | 7.1 | | State income tax on pretax income, net of federal tax effect | | 7.0 | | | 7.0 | | | 7.1 | |
| Increases (decreases) in tax from: | Increases (decreases) in tax from: | | Increases (decreases) in tax from: | |
| Wind PTCs | Wind PTCs | | (19.3) | | | (11.8) | | | (13.6) | | Wind PTCs | | (27.8) | | | (19.3) | | | (11.8) | |
Plant regulatory differences (a) | Plant regulatory differences (a) | | (7.2) | | | (7.4) | | | (8.8) | | Plant regulatory differences (a) | | (8.1) | | | (7.2) | | | (7.4) | |
| NOL Carryback | | (2.1) | | | 0 | | | 0 | | |
| Other tax credits, net NOL & tax credit allowances | Other tax credits, net NOL & tax credit allowances | | (1.2) | | | (1.5) | | | (1.1) | | Other tax credits, net NOL & tax credit allowances | | (1.4) | | | (1.2) | | | (1.5) | |
| Change in unrecognized tax benefits | Change in unrecognized tax benefits | | 1.0 | | | 0.5 | | | 0.1 | | Change in unrecognized tax benefits | | 0.5 | | | 1.0 | | | 0.5 | |
| NOL Carryback | | NOL Carryback | | — | | | (2.1) | | | — | |
| Other, net | Other, net | | (0.2) | | | 0.1 | | | 0.5 | | Other, net | | 0.2 | | | (0.2) | | | 0.1 | |
| Effective income tax rate | Effective income tax rate | | (1.0) | % | | 8.0 | % | | 5.2 | % | Effective income tax rate | | (8.6) | % | | (1.0) | % | | 8.0 | % |
(a)Regulatory differences for income tax primarily relate to the credit of excess deferred taxes to customers through the average rate assumption method. Income tax benefits associated with the credit of excess deferred credits are offset by corresponding revenue reductions.
Components of income tax expense for years ended Dec. 31:
| | (Millions of Dollars) | (Millions of Dollars) | | 2020 | | 2019 | | 2018 | (Millions of Dollars) | | 2021 | | 2020 | | 2019 |
| Current federal tax expense (benefit) | | $ | 41 | | | $ | 80 | | | $ | (17) | | |
| Current state tax expense | | 12 | | | 8 | | | 5 | | |
| Current federal tax (benefit) expense | | Current federal tax (benefit) expense | | $ | (10) | | | $ | 41 | | | $ | 80 | |
| Current state tax (benefit) expense | | Current state tax (benefit) expense | | (1) | | | 12 | | | 8 | |
| Current change in unrecognized tax expense (benefit) | Current change in unrecognized tax expense (benefit) | | 9 | | | (1) | | | (1) | | Current change in unrecognized tax expense (benefit) | | 1 | | | 9 | | | (1) | |
| Deferred federal tax benefit | Deferred federal tax benefit | | (102) | | | (86) | | | (3) | | Deferred federal tax benefit | | (87) | | | (102) | | | (86) | |
| Deferred state tax expense | Deferred state tax expense | | 38 | | | 43 | | | 42 | | Deferred state tax expense | | 49 | | | 38 | | | 43 | |
| Deferred change in unrecognized tax (benefit) expense | | (3) | | | 4 | | | 2 | | |
| Deferred change in unrecognized tax expense (benefit) | | Deferred change in unrecognized tax expense (benefit) | | 2 | | | (3) | | | 4 | |
| Deferred ITCs | Deferred ITCs | | (1) | | | (1) | | | (1) | | Deferred ITCs | | (2) | | | (1) | | | (1) | |
| Total income tax (benefit) expense | Total income tax (benefit) expense | | $ | (6) | | | $ | 47 | | | $ | 27 | | Total income tax (benefit) expense | | $ | (48) | | | $ | (6) | | | $ | 47 | |
Components of deferred income tax expense as of Dec. 31:
| | (Millions of Dollars) | (Millions of Dollars) | | 2020 | | 2019 | | 2018 | (Millions of Dollars) | | 2021 | | 2020 | | 2019 |
| Deferred tax expense excluding items below | Deferred tax expense excluding items below | | $ | 61 | | | $ | 97 | | | 70 | | Deferred tax expense excluding items below | | $ | 109 | | | $ | 61 | | | 97 | |
| Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities | Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities | | (127) | | | (135) | | | (28) | | Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities | | (145) | | | (127) | | | (135) | |
| Tax expense allocated to other comprehensive income, adoption of ASC Topic 326, adoption of ASU No. 2018-02 and other | | (1) | | | (1) | | | (1) | | |
| Deferred tax (benefit) expense | | $ | (67) | | | $ | (39) | | | $ | 41 | | |
| Tax expense allocated to other comprehensive income, adoption of ASC Topic 326, and other | | Tax expense allocated to other comprehensive income, adoption of ASC Topic 326, and other | | — | | | (1) | | | (1) | |
| Deferred tax benefit | | Deferred tax benefit | | $ | (36) | | | $ | (67) | | | $ | (39) | |
Components of the net deferred tax liability as of Dec. 31:
| | (Millions of Dollars) | (Millions of Dollars) | | 2020 | | 2019 (a) | (Millions of Dollars) | | 2021 | | 2020 (a) |
| Deferred tax liabilities: | Deferred tax liabilities: | | | | | Deferred tax liabilities: | | | | |
| Differences between book and tax bases of property | Differences between book and tax bases of property | | $ | 2,482 | | | $ | 2,361 | | Differences between book and tax bases of property | | $ | 2,679 | | | $ | 2,482 | |
| Regulatory assets | Regulatory assets | | 270 | | | 255 | | Regulatory assets | | 260 | | | 270 | |
| Operating lease assets | Operating lease assets | | 147 | | | 170 | | Operating lease assets | | 123 | | | 147 | |
| Deferred fuel costs | | Deferred fuel costs | | 92 | | | 7 | |
| Pension expense | Pension expense | | 72 | | | 68 | | Pension expense | | 73 | | | 72 | |
| Other | Other | | 14 | | | 10 | | Other | | 13 | | | 7 | |
| Total deferred tax liabilities | Total deferred tax liabilities | | $ | 2,985 | | | $ | 2,864 | | Total deferred tax liabilities | | $ | 3,240 | | | $ | 2,985 | |
| | Deferred tax assets: | Deferred tax assets: | | Deferred tax assets: | |
| Tax credit carryforward | Tax credit carryforward | | $ | 614 | | | $ | 527 | | Tax credit carryforward | | $ | 782 | | | $ | 614 | |
| Regulatory Liabilities | Regulatory Liabilities | | 349 | | | 362 | | Regulatory Liabilities | | 325 | | | 349 | |
| Operating lease liabilities | Operating lease liabilities | | 147 | | | 170 | | Operating lease liabilities | | 123 | | | 147 | |
| NOL and tax credit valuation allowances | NOL and tax credit valuation allowances | | (59) | | | (66) | | NOL and tax credit valuation allowances | | (64) | | | (59) | |
| Other employee benefits | Other employee benefits | | 38 | | | 38 | | Other employee benefits | | 32 | | | 38 | |
| NOL carryforward | NOL carryforward | | 12 | | | 10 | | NOL carryforward | | 43 | | | 12 | |
| Rate refund | | 7 | | | 11 | | |
| Deferred ITCs | Deferred ITCs | | 5 | | | 6 | | Deferred ITCs | | 5 | | | 5 | |
| Other | Other | | 32 | | | 27 | | Other | | 45 | | | 39 | |
| Total deferred tax assets | Total deferred tax assets | | $ | 1,145 | | | $ | 1,085 | | Total deferred tax assets | | $ | 1,291 | | | $ | 1,145 | |
| Net deferred tax liability | Net deferred tax liability | | $ | 1,840 | | | $ | 1,779 | | Net deferred tax liability | | $ | 1,949 | | | $ | 1,840 | |
(a)Prior periods have been reclassified to conform to current year presentation.
| | |
| 8. Fair Value of Financial Assets and Liabilities |
Fair Value Measurements
Accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires disclosures about assets and liabilities measured at fair value. A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance.
•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 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 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 are those valued with models requiring significant management judgment or estimation.
Cash equivalents — The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted NAV.
Investments in 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. The investments in commingled funds may be redeemed for NAV with proper notice. Private equity commingled fund 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.
Unscheduled distributions from real estate commingled funds’ investments may be redeemed with proper notice, however, 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.
Interest rate derivatives — The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.
Commodity derivatives — The methods 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 settlements 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 volatilities on a valuation is evaluated and may result in Level 3 classification.
Electric commodity derivatives held by NSP-Minnesota include transmission congestion instruments, generally referred to as FTRs. FTRs purchased from aan RTO are financial instruments that entitle or obligate the holder to monthly revenues or charges based on transmission congestion across a given transmission path. The value of an FTR is derived from, and designed to offset, the cost of transmission congestion.
In addition to overall transmission load, congestion is also influenced by the operating schedules of power plants and the consumption of electricity pertinent to a given transmission path. Unplanned plant outages, scheduled plant maintenance, changes in the relative costs of fuels used in generation, weather and overall changes in demand for electricity can each impact the operating schedules of the power plants on the transmission grid and the value of an FTR.
If forecasted costs of electric transmission congestion increase or decrease for a given FTR path, the value of that particular FTR instrument will likewise increase or decrease. Given the limited observability of certain inputs to the value of FTRs between auction processes, including expected plant operating schedules and retail and wholesale demand, fair value measurements for FTRs have been assigned a Level 3.
Non-trading monthly FTR settlements are included in fuel and purchased energy cost recovery mechanisms and therefore changes in the fair value of the yet to be settled portions of most FTRs are deferred as a regulatory asset or liability. Given this regulatory treatment and the limited magnitude of NSP-Minnesota’s FTRs relative to its electric utility operations, the numerous unobservable quantitative inputs pertinent to the value of FTRs are immaterial to the consolidated financial statements of NSP-Minnesota.
Non-Derivative Fair Value Measurements
Nuclear Decommissioning Fund — The NRC requires NSP-Minnesota to maintain a portfolio of investments to fund the costs of decommissioning its nuclear generating plants. Assets of the nuclear decommissioning fund are legally restricted for the purpose of decommissioning these facilities. The fund contains cash equivalents, debt securities, equity securities and other investments. NSP-Minnesota uses the MPUC approved asset allocation for the investment targets by asset class for the qualified trust.
NSP-Minnesota recognizes the costs of funding the decommissioning over the lives of the nuclear plants, assuming rate recovery of all costs. Realized and unrealized gains on fund investments over the life of the fund are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs. Consequently, any realized and unrealized gains and losses on securities in the nuclear decommissioning fund are deferred as a component of the regulatory asset.
Unrealized gains for the nuclear decommissioning fund were $981 million$1.3 billion and $706$981 million as of Dec. 31, 20202021 and 2019,2020, respectively, and unrealized losses were $5$7 million and $6$5 million as of Dec. 31, 20202021 and 2019,2020, respectively.
Non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund:
| | | Dec. 31, 2020 | | Dec. 31, 2021 |
| | | Fair Value | | | Fair Value |
| (Millions of Dollars) | (Millions of Dollars) | | Cost | | Level 1 | | Level 2 | | Level 3 | | NAV | | Total | (Millions of Dollars) | | Cost | | Level 1 | | Level 2 | | Level 3 | | NAV | | Total |
Nuclear decommissioning fund (a) | Nuclear decommissioning fund (a) | | | | | | | | | Nuclear decommissioning fund (a) | | | | | | | | |
| Cash equivalents | Cash equivalents | | $ | 40 | | | $ | 40 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 40 | | Cash equivalents | | $ | 64 | | | $ | 64 | | | $ | — | | | $ | — | | | $ | — | | | $ | 64 | |
| Commingled funds | Commingled funds | | 787 | | | 0 | | | 0 | | | 0 | | | 1,041 | | | 1,041 | | Commingled funds | | 856 | | | — | | | — | | | — | | | 1,294 | | | 1,294 | |
| Debt securities | Debt securities | | 528 | | | 0 | | | 572 | | | 13 | | | 0 | | | 585 | | Debt securities | | 631 | | | — | | | 666 | | | 9 | | | — | | | 675 | |
| Equity securities | Equity securities | | 446 | | | 1,109 | | | 2 | | | 0 | | | 0 | | | 1,111 | | Equity securities | | 411 | | | 1,222 | | | 1 | | | — | | | — | | | 1,223 | |
| Total | Total | | $ | 1,801 | | | $ | 1,149 | | | $ | 574 | | | $ | 13 | | | $ | 1,041 | | | $ | 2,777 | | Total | | $ | 1,962 | | | $ | 1,286 | | | $ | 667 | | | $ | 9 | | | $ | 1,294 | | | $ | 3,256 | |
(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $52 million of rabbi trust assets and miscellaneous investments.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Dec. 31, 2020 |
| | | | Fair Value |
| (Millions of Dollars) | | Cost | | Level 1 | | Level 2 | | Level 3 | | NAV | | Total |
Nuclear decommissioning fund (a) | | | | | | | | |
| Cash equivalents | | $ | 40 | | | $ | 40 | | | $ | — | | | $ | — | | | $ | — | | | $ | 40 | |
| Commingled funds | | 787 | | | — | | | — | | | — | | | 1,041 | | | 1,041 | |
| Debt securities | | 528 | | | — | | | 572 | | | 13 | | | — | | | 585 | |
| Equity securities | | 446 | | | 1,109 | | | 2 | | | — | | | — | | | 1,111 | |
| Total | | $ | 1,801 | | | $ | 1,149 | | | $ | 574 | | | $ | 13 | | | $ | 1,041 | | | $ | 2,777 | |
(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $53 million of rabbi trust assets and miscellaneous investments.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Dec. 31, 2019 |
| | | | Fair Value |
| (Millions of Dollars) | | Cost | | Level 1 | | Level 2 | | Level 3 | | NAV | | Total |
Nuclear decommissioning fund (a) | | | | | | | | |
| Cash equivalents | | $ | 33 | | | $ | 33 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 33 | |
| Commingled funds | | 733 | | | 0 | | | 0 | | | 0 | | | 935 | | | 935 | |
| Debt securities | | 489 | | | 0 | | | 495 | | | 13 | | | 0 | | | 508 | |
| Equity securities | | 485 | | | 962 | | | 2 | | | 0 | | | 0 | | | 964 | |
| Total | | $ | 1,740 | | | $ | 995 | | | $ | 497 | | | $ | 13 | | | $ | 935 | | | $ | 2,440 | |
(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $55 million of rabbi trust assets and miscellaneous investments.
For the years ended Dec. 31, 20202021 and 2019,2020, there were immaterial Level 3 nuclear decommissioning fund investments or transfer of amounts between levels.
Contractual maturity dates of debt securities in the nuclear decommissioning fund as of Dec. 31, 2020:2021:
| | | Final Contractual Maturity | | Final Contractual Maturity |
| (Millions of Dollars) | (Millions of Dollars) | | Due in 1 year or Less | | Due in 1 to 5 Years | | Due in 5 to 10 Years | | Due after 10 Years | | Total | (Millions of Dollars) | | Due in 1 year or Less | | Due in 1 to 5 Years | | Due in 5 to 10 Years | | Due after 10 Years | | Total |
| Debt securities | Debt securities | | $ | 1 | | | $ | 116 | | | $ | 211 | | | $ | 257 | | | $ | 585 | | Debt securities | | $ | 4 | | | $ | 149 | | | $ | 208 | | | $ | 314 | | | $ | 675 | |
Rabbi Trusts
NSP-Minnesota has established a rabbi trust to provide partial funding for future deferred compensation plan distributions.
Cost and fair value of assets held in rabbi trusts:
| | | Dec. 31, 2020 | | Dec. 31, 2021 |
| | | Fair Value | | | Fair Value |
| (Millions of Dollars) | (Millions of Dollars) | | Cost | | Level 1 | | Level 2 | | Level 3 | | Total | (Millions of Dollars) | | Cost | | Level 1 | | Level 2 | | Level 3 | | Total |
Rabbi Trusts (a) | Rabbi Trusts (a) | | | | | | | | | | | Rabbi Trusts (a) | | | | | | | | | | |
| Cash equivalents | | $ | 1 | | | $ | 1 | | | $ | 0 | | | $ | 0 | | | $ | 1 | | |
| | Mutual funds | Mutual funds | | 14 | | | 16 | | | 0 | | | 0 | | | 16 | | Mutual funds | | $ | 10 | | | $ | 13 | | | $ | — | | | $ | — | | | $ | 13 | |
| Total | Total | | $ | 15 | | | $ | 17 | | | $ | 0 | | | $ | 0 | | | $ | 17 | | Total | | $ | 10 | | | $ | 13 | | | $ | — | | | $ | — | | | $ | 13 | |
(a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet.
| | | Dec. 31, 2019 | | Dec. 31, 2020 |
| | | Fair Value | | | Fair Value |
| (Millions of Dollars) | (Millions of Dollars) | | Cost | | Level 1 | | Level 2 | | Level 3 | | Total | (Millions of Dollars) | | Cost | | Level 1 | | Level 2 | | Level 3 | | Total |
Rabbi Trusts (a) | Rabbi Trusts (a) | | | | | | | | | | | Rabbi Trusts (a) | | | | | | | | | | |
| Cash equivalents | Cash equivalents | | $ | 1 | | | $ | 1 | | | $ | 0 | | | $ | 0 | | | $ | 1 | | Cash equivalents | | $ | 1 | | | $ | 1 | | | $ | — | | | $ | — | | | $ | 1 | |
| Mutual funds | Mutual funds | | 11 | | | 13 | | | 0 | | | 0 | | | 13 | | Mutual funds | | 14 | | | 16 | | | — | | | — | | | 16 | |
| Total | Total | | $ | 12 | | | $ | 14 | | | $ | 0 | | | $ | 0 | | | $ | 14 | | Total | | $ | 15 | | | $ | 17 | | | $ | — | | | $ | — | | | $ | 17 | |
(a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet.
Derivative Instruments Fair Value Measurements
NSP-Minnesota 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, utility commodity prices and vehicle fuel prices.
Interest Rate Derivatives — NSP-Minnesota enters into various instruments that effectively fix the yield or price on a specified benchmark interest rate for an anticipated debt issuance for a specific period. These derivative instruments are generally designated as cash flow hedges for accounting purposes, with changes in fair value prior to settlement recorded as other comprehensive income.
AtAs of Dec. 31, 2020,2021, accumulated other comprehensive loss related to settled interest rate derivatives included $1 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings. As of Dec. 31, 2021, NSP-Minnesota had no unsettled interest rate derivatives.
Wholesale and Commodity Trading Risk — NSP-Minnesota 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. NSP-Minnesota is allowed to conduct these activities within guidelines and limitations as approved by its risk management committee, comprised of management personnel not directly involved in activities governed by this policy.
Commodity Derivatives — NSP-Minnesota 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. This could include the purchase or sale of energy or energy-related products, natural gas to generate electric energy, natural gas for resale, FTRs, vehicle fuel, and weather derivatives.
As of Dec. 31, 2020,2021, NSP-Minnesota had 0no commodity contracts designated as cash flow hedges. NSP-Minnesota may enter into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers, but may not be designated as qualifying hedging transactions. The classification of unrealized losses or gains on these instruments as a regulatory asset or liability, if applicable, is based on approved regulatory recovery mechanisms.
NSP-Minnesota enters into commodity derivative instruments for trading purposes not directly related to commodity price risks associated with serving its electric and natural gas customers. Changes in the fair value of these commodity derivatives are recorded in electric operating revenues, net of amounts credited to customers under margin-sharing mechanisms.
Gross notional amounts of commodity forwards, options and FTRs:
| (Amounts in Millions) (a) (b) | | Dec. 31, 2020 | | Dec. 31, 2019 | |
(Amounts in Millions) (a)(b) | | (Amounts in Millions) (a)(b) | | Dec. 31, 2021 | | Dec. 31, 2020 |
| MWh of electricity | MWh of electricity | | 65 | | | 79 | | MWh of electricity | | 57 | | | 65 | |
| MMBtu of natural gas | MMBtu of natural gas | | 83 | | | 78 | | MMBtu of natural gas | | 85 | | | 83 | |
(a)Not reflective of net positions in the underlying commodities.
(b)Notional amounts for options included on a gross basis, but are weighted for the probability of exercise.
Consideration of Credit Risk and Concentrations — NSP-Minnesota continuously monitors the creditworthiness of 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. Impact of credit risk was immaterial to the fair value of unsettled commodity derivatives presented on the consolidated balance sheets. NSP-Minnesota’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.
As of Dec. 31, 2020, 62021, 8 of NSP-Minnesota’s 10 most significant counterparties for these activities, comprising $31$33 million or 59%63% of this credit exposure, had investment grade credit ratings from S&P, Moody’s or Fitch Ratings. NaN of the 10 most significant counterparties, comprising $13$17 million or 25%34% of this credit exposure, werewas not rated by these external agencies, but based on NSP-Minnesota’s internal analysis, had credit quality consistent with investment grade. NaN of these significant counterparties, comprising an immaterial amount or less than 1% of this credit exposure, had credit quality less than investment grade, based on internal analysis. NaN of these significant counterparties are municipal or cooperative electric entities, RTOs or other utilities.
Qualifying Cash Flow Hedges — Financial impact of qualifying interest rate and vehicle fuel cash flow hedges on NSP-Minnesota’s accumulated other comprehensive loss, included in the consolidated statements of common stockholder’s equity and in the consolidated statements of comprehensive income:
| | (Millions of Dollars) | (Millions of Dollars) | | 2020 | | 2019 | | 2018 | (Millions of Dollars) | | 2021 | | 2020 | | 2019 |
| Accumulated other comprehensive loss related to cash flow hedges at Jan. 1 | Accumulated other comprehensive loss related to cash flow hedges at Jan. 1 | | $ | (20) | | | $ | (20) | | | $ | (21) | | Accumulated other comprehensive loss related to cash flow hedges at Jan. 1 | | $ | (19) | | | $ | (20) | | | $ | (20) | |
| | After-tax net realized losses on derivative transactions reclassified into earnings | After-tax net realized losses on derivative transactions reclassified into earnings | | 1 | | | 0 | | | 1 | | After-tax net realized losses on derivative transactions reclassified into earnings | | 2 | | | 1 | | | — | |
| Accumulated other comprehensive loss related to cash flow hedges at Dec. 31 | Accumulated other comprehensive loss related to cash flow hedges at Dec. 31 | | $ | (19) | | | $ | (20) | | | $ | (20) | | Accumulated other comprehensive loss related to cash flow hedges at Dec. 31 | | $ | (17) | | | $ | (19) | | | $ | (20) | |
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, 2021 | | | | |
| Other derivative instruments | | | | |
| Electric commodity | | $ | — | | | $ | 3 | |
| Natural gas commodity | | — | | | (3) | |
| Total | | $ | — | | | $ | — | |
| | | | |
| Year Ended Dec. 31, 2020 | | | | |
| Other derivative instruments | | | | |
| Electric commodity | | $ | — | | | $ | 2 | |
| Natural gas commodity | | — | | | (2) | |
| Total | | $ | — | | | $ | — | |
| | | | |
| Year Ended Dec. 31, 2019 | | | | |
| Other derivative instruments | | | | |
| Electric commodity | | $ | — | | | $ | 2 | |
| Natural gas commodity | | — | | | (3) | |
| 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, 2021 | | | |
| Derivatives designated as cash flow hedges | | | |
| Interest rate | | $ | 2 | | (a) | $ | — | | | $ | — | | |
| Total | | $ | 2 | | | $ | — | | | $ | — | | |
| Other derivative instruments | | | |
| Commodity trading | | $ | — | | | $ | — | | | $ | 51 | | (b) |
| Electric commodity | | — | | | (3) | | (c) | — | | |
| Natural gas commodity | | — | | | 1 | | (d) | (6) | | (d) |
| Total | | $ | — | | | $ | (2) | | | $ | 45 | | |
Impact of derivative activity: | | | | | | | | | | | | | | | | | | | | | | | |
| | 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, 2020 | | | |
| Derivatives designated as cash flow hedges | | | |
| Interest rate | | $ | 1 | | (a) | $ | — | | | $ | — | | |
| Total | | $ | 1 | | | $ | — | | | $ | — | | |
| Other derivative instruments | | | |
| Commodity trading | | $ | — | | | $ | — | | | $ | (5) | | (b) |
| Electric commodity | | — | | | (3) | | (c) | — | | |
| Natural gas commodity | | — | | | 2 | | (d) | (4) | | (d) |
| Total | | $ | — | | | $ | (1) | | | $ | (9) | | |
| | | | | | | | | | | | | | |
| | Pre-Tax Fair Value
Gains (Losses) Recognized
During the Period in: |
| (Millions of Dollars) | | Accumulated Other Comprehensive Loss | | Regulatory (Assets) and Liabilities |
| Year Ended Dec. 31, 2020 | | | | |
| Other derivative instruments | | | | |
| Electric commodity | | $ | 0 | | | $ | 2 | |
| Natural gas commodity | | 0 | | | (2) | |
| Total | | $ | 0 | | | $ | 0 | |
| | | | |
| Year Ended Dec. 31, 2019 | | | | |
| Other derivative instruments | | | | |
| Electric commodity | | $ | 0 | | | $ | 2 | |
| Natural gas commodity | | 0 | | | (3) | |
| Total | | $ | 0 | | | $ | (1) | |
| | | | |
| Year Ended Dec. 31, 2018 | | | | |
| Other derivative instruments | | | | |
| Electric commodity | | $ | 0 | | | $ | (6) | |
| Natural gas commodity | | 0 | | | 2 | |
| Total | | $ | 0 | | | $ | (4) | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | 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, 2020 | | | |
| Derivatives designated as cash flow hedges | | | |
| Interest rate | | $ | 1 | | (a) | $ | 0 | | | $ | 0 | | |
| Total | | $ | 1 | | | $ | 0 | | | $ | 0 | | |
| Other derivative instruments | | | |
| Commodity trading | | $ | 0 | | | $ | 0 | | | $ | (5) | | (b) |
| Electric commodity | | 0 | | | (3) | | (c) | 0 | | |
| Natural gas commodity | | 0 | | | 2 | | (d) | (4) | | (d) |
| Total | | $ | 0 | | | $ | (1) | | | $ | (9) | | |
(a)Recorded to interest charges.
(b)Recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate.
(c)Recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate.
(d)Amounts are recorded to cost of natural gas sold and transported. These derivative settlement gains and losses are shared with natural gas customers through purchased natural gas cost-recovery mechanisms, and reclassified out of income as regulatory assets and liabilities, as appropriate.
| | | Pre-Tax (Gains) Losses
Reclassified into Income
During the Period from: | | Pre-Tax Gains (Losses)
Recognized
During the Period in Income | | | Pre-Tax (Gains) Losses
Reclassified into Income
During the Period from: | | Pre-Tax Gains (Losses)
Recognized
During the Period in Income | |
| (Millions of Dollars) | (Millions of Dollars) | | Accumulated Other Comprehensive Loss | | Regulatory
Assets and (Liabilities) | | (Millions of Dollars) | | Accumulated Other Comprehensive Loss | | Regulatory
Assets and (Liabilities) | |
| Year Ended Dec. 31, 2019 | Year Ended Dec. 31, 2019 | | | | Year Ended Dec. 31, 2019 | | | |
| | | Other derivative instruments | Other derivative instruments | | Other derivative instruments | |
| Commodity trading | | $ | 0 | | | $ | 0 | | | $ | 0 | |
| |
| | Electric commodity | Electric commodity | | 0 | | | 1 | | (a) | 0 | | | Electric commodity | | $ | — | | | $ | 1 | | (c) | $ | — | | |
| Natural gas commodity | Natural gas commodity | | 0 | | | 1 | | (b) | (3) | | (b) | Natural gas commodity | | — | | | 1 | | (d) | (3) | | (d) |
| Total | Total | | $ | 0 | | | $ | 2 | | | $ | (3) | | | Total | | $ | — | | | $ | 2 | | | $ | (3) | | |
(a)Recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms and reclassified out of income as regulatory assets or liabilities, as appropriate.
(b)Amounts are recorded to cost of natural gas sold and transported. These derivative settlement gains and losses are shared with natural gas customers through purchased natural gas cost-recovery mechanisms and reclassified out of income as regulatory assets and liabilities, as appropriate.
| | | | | | | | | | | | | | | | | | | | | | | |
| | 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, 2018 | | | |
| Derivatives designated as cash flow hedges | | | |
| Interest rate | | $ | 1 | | (a) | $ | 0 | | | $ | 0 | | |
| Total | | $ | 1 | | | $ | 0 | | | $ | 0 | | |
| Other derivative instruments | | | |
| Commodity trading | | $ | 0 | | | $ | 0 | | | $ | 11 | | (b) |
| Electric commodity | | 0 | | | 3 | | (c) | 0 | | |
| Natural gas commodity | | 0 | | | (2) | | (d) | (1) | | (d) |
| Total | | $ | 0 | | | $ | 1 | | | $ | 10 | | |
(a)Recorded to interest charges.
(b)Recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate.
(c)Recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms and reclassified out of income as regulatory assets or liabilities, as appropriate.
(d)Amounts are recorded to cost of natural gas sold and transported. These derivative settlement gains and losses are shared with natural gas customers through purchased natural gas cost-recovery mechanisms and reclassified out of income as regulatory assets and liabilities, as appropriate.
NSP-Minnesota had 0no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2021, 2020 2019 and 2018.
2019.
Credit Related Contingent Features — Contract provisions for derivative instruments that NSP-Minnesota enters into, including those accounted for as normal purchase-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 NSP-Minnesota’s credit ratings are downgraded below its investment grade credit rating by any of the major credit rating agencies. As of Dec. 31, 20202021 and 2019,2020, there were $4$3 million and $7$4 million derivative instruments in a liability position with such underlying contract provisions, respectively.
Certain contracts also contain cross default provisions that may require the posting of collateral or settlement of the contracts if there was a failure under the other financing arrangements related to payment terms or other covenants. As of Dec. 31, 2021 and 2020, there were approximately $48 million and $14 million of derivative instruments in a liability position with such underlying contract provisions.provisions, respectively.
Provisions allow counterparties to seek performance assurance, including cash collateral, in the event that NSP-Minnesota’s ability to fulfill its contractual obligations is reasonably expected to be impaired. NSP-Minnesota had 0no collateral posted related to adequate assurance clauses in derivative contracts as of Dec. 31, 20202021 and 2019.2020.
Recurring Fair Value Measurements — NSP-Minnesota’s derivative assets and liabilities measured at fair value on a recurring basis were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Dec. 31, 2020 | | Dec. 31, 2019 |
| | 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 | | | $ | 26 | | | $ | 0 | | | $ | 27 | | | $ | (25) | | | $ | 2 | | | $ | 2 | | | $ | 40 | | | $ | 23 | | | $ | 65 | | | $ | (42) | | | $ | 23 | |
| Electric commodity | | 0 | | | 0 | | | 13 | | | 13 | | | (1) | | | 12 | | | 0 | | | 0 | | | 9 | | | 9 | | | (1) | | | 8 | |
| Natural gas commodity | | 0 | | | 3 | | | 0 | | | 3 | | | 0 | | | 3 | | | 0 | | | 1 | | | 0 | | | 1 | | | 0 | | | 1 | |
| Total current derivative assets | | $ | 1 | | | $ | 29 | | | $ | 13 | | | $ | 43 | | | $ | (26) | | | 17 | | | $ | 2 | | | $ | 41 | | | $ | 32 | | | $ | 75 | | | $ | (43) | | | 32 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| Noncurrent derivative assets | | | | | | | | | | | | | | | | | | | | | | | | |
| Other derivative instruments: | | | | | | | | | | | | | | | | | | | | | | | | |
| Commodity trading | | $ | 7 | | | $ | 39 | | | $ | 0 | | | $ | 46 | | | $ | (41) | | | $ | 5 | | | $ | 9 | | | $ | 29 | | | $ | 6 | | | $ | 44 | | | $ | (35) | | | $ | 9 | |
| Total noncurrent derivative assets | | $ | 7 | | | $ | 39 | | | $ | 0 | | | $ | 46 | | | $ | (41) | | | 5 | | | $ | 9 | | | $ | 29 | | | $ | 6 | | | $ | 44 | | | $ | (35) | | | 9 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Dec. 31, 2020 | | Dec. 31, 2019 |
| | 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 liabilities | | | | | | | | | | | | | | | | | | | | | | | | |
| Other derivative instruments: | | | | | | | | | | | | | | | | | | | | | | | | |
| Commodity trading | | $ | 3 | | | $ | 18 | | | $ | 10 | | | $ | 31 | | | $ | (25) | | | $ | 6 | | | $ | 2 | | | $ | 42 | | | $ | 15 | | | $ | 59 | | | $ | (50) | | | $ | 9 | |
| Electric commodity | | 0 | | | 0 | | | 1 | | | 1 | | | (1) | | | 0 | | | 0 | | | 0 | | | 1 | | | 1 | | | (1) | | | 0 | |
| Natural gas commodity | | 0 | | | 2 | | | 0 | | | 2 | | | 0 | | | 2 | | | 0 | | | 2 | | | 0 | | | 2 | | | 0 | | | 2 | |
| Total current derivative liabilities | | $ | 3 | | | $ | 20 | | | $ | 11 | | | $ | 34 | | | $ | (26) | | | 8 | | | $ | 2 | | | $ | 44 | | | $ | 16 | | | $ | 62 | | | $ | (51) | | | 11 | |
PPAs (b) | | | | | | | | | | | | 14 | | | | | | | | | | | | | 14 | |
| Current derivative instruments | | | | | | | | | | | | $ | 22 | | | | | | | | | | | | | $ | 25 | |
| Noncurrent derivative liabilities | | | | | | | | | | | | | | | | | | | | | | | | |
| Other derivative instruments: | | | | | | | | | | | | | | | | | | | | | | | | |
| Commodity trading | | $ | 2 | | | $ | 35 | | | $ | 13 | | | $ | 50 | | | $ | (27) | | | $ | 23 | | | $ | 2 | | | $ | 32 | | | $ | 17 | | | $ | 51 | | | $ | (3) | | | $ | 48 | |
| Total noncurrent derivative liabilities | | $ | 2 | | | $ | 35 | | | $ | 13 | | | $ | 50 | | | $ | (27) | | | 23 | | | $ | 2 | | | $ | 32 | | | $ | 17 | | | $ | 51 | | | $ | (3) | | | 48 | |
PPAs (b) | | | | | | | | | | | | 48 | | | | | | | | | | | | | 62 | |
| Noncurrent derivative instruments | | | | | | | | | | | | $ | 71 | | | | | | | | | | | | | $ | 110 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Dec. 31, 2021 | | Dec. 31, 2020 |
| | 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 | | $ | 9 | | | $ | 40 | | | $ | 22 | | | $ | 71 | | | $ | (53) | | | $ | 18 | | | $ | 1 | | | $ | 26 | | | $ | — | | | $ | 27 | | | $ | (25) | | | $ | 2 | |
| Electric commodity | | — | | | — | | | 30 | | | 30 | | | (1) | | | 29 | | | — | | | — | | | 13 | | | 13 | | | (1) | | | 12 | |
| Natural gas commodity | | — | | | 6 | | | — | | | 6 | | | — | | | 6 | | | — | | | 3 | | | — | | | 3 | | | — | | | 3 | |
| Total current derivative assets | | $ | 9 | | | $ | 46 | | | $ | 52 | | | $ | 107 | | | $ | (54) | | | $ | 53 | | | $ | 1 | | | $ | 29 | | | $ | 13 | | | $ | 43 | | | $ | (26) | | | $ | 17 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| Noncurrent derivative assets | | | | | | | | | | | | | | | | | | | | | | | | |
| Other derivative instruments: | | | | | | | | | | | | | | | | | | | | | | | | |
| Commodity trading | | $ | 6 | | | $ | 34 | | | $ | 35 | | | $ | 75 | | | $ | (42) | | | $ | 33 | | | $ | 7 | | | $ | 39 | | | $ | — | | | $ | 46 | | | $ | (41) | | | $ | 5 | |
| Total noncurrent derivative assets | | $ | 6 | | | $ | 34 | | | $ | 35 | | | $ | 75 | | | $ | (42) | | | $ | 33 | | | $ | 7 | | | $ | 39 | | | $ | — | | | $ | 46 | | | $ | (41) | | | $ | 5 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Dec. 31, 2021 | | Dec. 31, 2020 |
| | 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 liabilities | | | | | | | | | | | | | | | | | | | | | | | | |
| Other derivative instruments: | | | | | | | | | | | | | | | | | | | | | | | | |
| Commodity trading | | $ | 13 | | | $ | 58 | | | $ | 4 | | | $ | 75 | | | $ | (58) | | | $ | 17 | | | $ | 3 | | | $ | 18 | | | $ | 10 | | | $ | 31 | | | $ | (25) | | | $ | 6 | |
| Electric commodity | | — | | | — | | | 1 | | | 1 | | | (1) | | | — | | | — | | | — | | | 1 | | | 1 | | | (1) | | | — | |
| Natural gas commodity | | — | | | 4 | | | — | | | 4 | | | — | | | 4 | | | — | | | 2 | | | — | | | 2 | | | — | | | 2 | |
| Total current derivative liabilities | | $ | 13 | | | $ | 62 | | | $ | 5 | | | $ | 80 | | | $ | (59) | | | 21 | | | $ | 3 | | | $ | 20 | | | $ | 11 | | | $ | 34 | | | $ | (26) | | | 8 | |
PPAs (b) | | | | | | | | | | | | 14 | | | | | | | | | | | | | 14 | |
| Current derivative instruments | | | | | | | | | | | | $ | 35 | | | | | | | | | | | | | $ | 22 | |
| Noncurrent derivative liabilities | | | | | | | | | | | | | | | | | | | | | | | | |
| Other derivative instruments: | | | | | | | | | | | | | | | | | | | | | | | | |
| Commodity trading | | $ | 15 | | | $ | 48 | | | $ | 26 | | | $ | 89 | | | $ | (53) | | | $ | 36 | | | $ | 2 | | | $ | 35 | | | $ | 13 | | | $ | 50 | | | $ | (27) | | | $ | 23 | |
| Total noncurrent derivative liabilities | | $ | 15 | | | $ | 48 | | | $ | 26 | | | $ | 89 | | | $ | (53) | | | 36 | | | $ | 2 | | | $ | 35 | | | $ | 13 | | | $ | 50 | | | $ | (27) | | | 23 | |
PPAs (b) | | | | | | | | | | | | 35 | | | | | | | | | | | | | 48 | |
| Noncurrent derivative instruments | | | | | | | | | | | | $ | 71 | | | | | | | | | | | | | $ | 71 | |
(a)NSP-Minnesota nets derivative instruments and related collateral on its consolidated balance sheets 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, 20202021 and 2019.2020. At both Dec. 31, 20202021 derivative assets and 2019,liabilities include 0 obligations to return cash collateral. At Dec. 31, 2020 derivative assets and liabilities include $15 million and $32 million of obligations to return cash collateral, respectively.collateral. At Dec. 31, 20202021 and 2019,2020, derivative assets and liabilities include the rights to reclaim cash collateral of $1$16 million and $8$1 million, respectively. The counterparty netting excludes settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.
(b)During 2006, Xcel Energy 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.
Changes in Level 3 commodity derivatives for the years ended Dec. 31, 2021, 2020 2019 and 2018:2019:
| | | Year Ended Dec. 31 | | Year Ended Dec. 31 |
| (Millions of Dollars) | (Millions of Dollars) | | 2020 | | 2019 | | 2018 | (Millions of Dollars) | | 2021 | | 2020 | | 2019 |
| Balance at Jan. 1 | Balance at Jan. 1 | | $ | 5 | | | $ | 14 | | | $ | 23 | | Balance at Jan. 1 | | $ | (11) | | | $ | 5 | | | $ | 14 | |
| Purchases | Purchases | | 28 | | | 17 | | | 26 | | Purchases | | 54 | | | 28 | | | 17 | |
| Settlements | Settlements | | (49) | | | (28) | | | (17) | | Settlements | | (82) | | | (49) | | | (28) | |
| Net transactions recorded during the period: | Net transactions recorded during the period: | | Net transactions recorded during the period: | |
(Losses) gains recognized in earnings (a) | | (8) | | | 3 | | | (2) | | |
Gains (losses) recognized in earnings (a) | | Gains (losses) recognized in earnings (a) | | 72 | | | (8) | | | 3 | |
| Net gains (losses) recognized as regulatory assets and liabilities | Net gains (losses) recognized as regulatory assets and liabilities | | 13 | | | (1) | | | (16) | | Net gains (losses) recognized as regulatory assets and liabilities | | 23 | | | 13 | | | (1) | |
| Balance at Dec. 31 | Balance at Dec. 31 | | $ | (11) | | | $ | 5 | | | $ | 14 | | Balance at Dec. 31 | | $ | 56 | | | $ | (11) | | | $ | 5 | |
(a)Level 3 losses and gains recognized in earnings are subject to offsetting gains and losses of derivative instruments categorized as levels 1 and 2 in the income statement.
NSP-Minnesota recognizes transfers between levels as of the beginning of each period. There were 0no transfers of amounts between levels for derivative instruments for the years ended Dec. 31, 2021, 2020 2019 and 2018.2019.
Fair Value of Long-Term Debt
As of Dec. 31, other financial instruments for which the carrying amount did not equal fair value:
| | | 2020 | | 2019 | | 2021 | | 2020 |
| (Millions of Dollars) | (Millions of Dollars) | | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value | (Millions of Dollars) | | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value |
| Long-term debt, including current portion | Long-term debt, including current portion | | $ | 5,904 | | | $ | 7,391 | | | $ | 5,521 | | | $ | 6,297 | | Long-term debt, including current portion | | $ | 6,747 | | | $ | 7,761 | | | $ | 5,904 | | | $ | 7,391 | |
Fair value of NSP-Minnesota’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. Fair value estimates are based on information available to management as of Dec. 31, 20202021 and 2019,2020, and given the observability of the inputs, fair values presented for long-term debt were assigned as Level 2.
| | |
| 9. Benefit Plans and Other Postretirement Benefits |
Pension and Postretirement Health Care Benefits
Xcel Energy, which includes NSP-Minnesota, has several noncontributory, qualified, defined benefit pension plans that cover almost all employees. All newly hired or rehired employees participate under the Cash Balance formula, which is based on pay credits using a percentage of annual eligible pay and annual interest credits. The average annual interest crediting rates for these plans was 1.96, 1.78 2.74 and 3.572.74 percent in 2021, 2020, 2019, and 2018,2019, respectively. Some employees may participate under legacy formulas such as the traditional final average pay or pension equity. Xcel Energy’s and NSP-Minnesota’s policy is to fully fund into an external trust the actuarially determined pension costs 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, 20202021 and 20192020 were $43 million and $39$43 million, respectively, of which $3 million and $4 million was attributable to NSP-Minnesota in both years.2021 and 2020, respectively. In 20202021 and 2019,2020, Xcel Energy recognized net benefit cost for the SERP and nonqualified plans of $6$4 million and $4$6 million, respectively, of which $1 million was attributable to NSP-Minnesota in both years.2020 and the cost for 2021 was immaterial.
Xcel Energy, which includes NSP-Minnesota, bases the investment-return assumption onconsiders the expected long-term performance for each of the asset classes in its pension and postretirement health care portfolios. For pension assets,portfolio. Xcel Energy considers the historical returns achieved by its asset portfolioportfolios over the past 20 years or longer period,long time periods, as well as the long-term projected return levels. Xcel Energy and NSP-Minnesota continually review their pension assumptions.
Pension cost determination assumes a forecasted mix of investment types over the long-term.
•Investment returns in 2021 were above the assumed level of 6.60%.
•Investment returns in 2020 were above the assumed level of 7.10%.
•Investment returns in 2019 were above the assumed level of 7.10%.
•Investment returns in 2018 were below the assumed level of 7.10%.
•In 2021,2022, NSP-Minnesota’s expected investment-return assumption is 6.60%.
Pension plan and postretirement benefit assets are invested in a portfolio according to Xcel Energy’s return, liquidity and diversification objectives to provide a source of funding for plan obligations and minimize contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the asset allocation given the long-term risk, return, correlation and liquidity characteristics of each particular asset class. There were no significant concentrations of risk in any industry, index, or entity. Market volatility can impact even well-diversified portfolios and significantly affect the return levels achieved by the assets in any year.
Xcel Energy’s ongoing investment strategy is based on plan-specific investment recommendations that seek to minimize potential investment and interest rate risk as a plan’s funded status increases over time. The investment recommendations result in a greater percentage of long-duration fixed income securities being allocated to specific plans having relatively higher funded status ratios and a greater percentage of growth assets being allocated to plans having relatively lower funded status ratios.
Plan Assets
For each of the fair value hierarchy levels, NSP-Minnesota’s pension plan assets measured at fair value:
| | | Dec. 31, 2020 (a) | | Dec. 31, 2019 (a) | | Dec. 31, 2021 (a) | | Dec. 31, 2020 (a) |
| (Millions of Dollars) | (Millions of Dollars) | | Level 1 | | Level 2 | | Level 3 | | Measured at NAV | | Total | | Level 1 | | Level 2 | | Level 3 | | Measured at NAV | | Total | (Millions of Dollars) | | Level 1 | | Level 2 | | Level 3 | | Measured at NAV | | Total | | Level 1 | | Level 2 | | Level 3 | | Measured at NAV | | Total |
| Cash equivalents | Cash equivalents | | $ | 52 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 52 | | | $ | 41 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 41 | | Cash equivalents | | $ | 31 | | | $ | — | | | $ | — | | | $ | — | | | $ | 31 | | | $ | 52 | | | $ | — | | | $ | — | | | $ | — | | | $ | 52 | |
| Commingled funds | Commingled funds | | 369 | | | 0 | | | 0 | | | 284 | | | 653 | | | 360 | | | 0 | | | 0 | | | 270 | | | 630 | | Commingled funds | | 304 | | | — | | | — | | | 274 | | | 578 | | | 369 | | | — | | | — | | | 284 | | | 653 | |
| Debt securities | Debt securities | | 0 | | | 167 | | | 1 | | | 0 | | | 168 | | | 0 | | | 156 | | | 1 | | | 0 | | | 157 | | Debt securities | | — | | | 219 | | | 1 | | | — | | | 220 | | | — | | | 167 | | | 1 | | | — | | | 168 | |
| Equity securities | Equity securities | | 20 | | | 0 | | | 0 | | | 0 | | | 20 | | | 23 | | | 0 | | | 0 | | | 0 | | | 23 | | Equity securities | | 16 | | | — | | | — | | | — | | | 16 | | | 20 | | | — | | | — | | | — | | | 20 | |
| Other | Other | | 3 | | | 1 | | | 0 | | | 0 | | | 4 | | | (32) | | | 1 | | | 0 | | | (5) | | | (36) | | Other | | — | | | 1 | | | — | | | 7 | | | 8 | | | 3 | | | 1 | | | — | | | — | | | 4 | |
| Total | Total | | $ | 444 | | | $ | 168 | | | $ | 1 | | | $ | 284 | | | $ | 897 | | | $ | 392 | | | $ | 157 | | | $ | 1 | | | $ | 265 | | | $ | 815 | | Total | | $ | 351 | | | $ | 220 | | | $ | 1 | | | $ | 281 | | | $ | 853 | | | $ | 444 | | | $ | 168 | | | $ | 1 | | | $ | 284 | | | $ | 897 | |
(a)See Note 8 for further information on fair value measurement inputs and methods.
For each of the fair value hierarchy levels, NSP-Minnesota’s postretirement benefit plan assets that were measured at fair value:
| | | Dec. 31, 2020 (a) | | Dec. 31, 2019 (a) | | Dec. 31, 2021 (a) | | Dec. 31, 2020 (a) |
| (Millions of Dollars) | (Millions of Dollars) | | Level 1 | | Level 2 | | Level 3 | | Measured at NAV | | Total | | Level 1 | | Level 2 | | Level 3 | | Measured at NAV | | Total | (Millions of Dollars) | | Level 1 | | Level 2 | | Level 3 | | Measured at NAV | | Total | | Level 1 | | Level 2 | | Level 3 | | Measured at NAV | | Total |
| | Commingled funds | Commingled funds | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 1 | | | $ | 1 | | Commingled funds | | $ | — | | | $ | — | | | $ | — | | | $ | 1 | | | $ | 1 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| Debt securities | Debt securities | | 0 | | | 2 | | | 0 | | | 0 | | | 2 | | | 0 | | | 2 | | | 0 | | | 0 | | | 2 | | Debt securities | | — | | | 2 | | | — | | | — | | | 2 | | | — | | | 2 | | | — | | | — | | | 2 | |
| | Total | Total | | $ | 0 | | | $ | 2 | | | $ | 0 | | | $ | 0 | | | $ | 2 | | | $ | 0 | | | $ | 2 | | | $ | 0 | | | $ | 1 | | | $ | 3 | | Total | | $ | — | | | $ | 2 | | | $ | — | | | $ | 1 | | | $ | 3 | | | $ | — | | | $ | 2 | | | $ | — | | | $ | — | | | $ | 2 | |
(a)See Note 8 for further information on fair value measurement inputs and methods.
NoNaN assets were transferred in or out of Level 3 for 2020. Immaterial assets were transferred in2021 or out2020.
Funded Status — Benefit obligations for both pension and postretirement plans increaseddecreased from Dec. 31, 20192020 to Dec. 31, 2020,2021, due primarily to decreasesbenefit
payments and increases in discount rates used in actuarial valuations. Comparisons of the actuarially computed benefit obligation, changes in plan assets and funded status of the pension and postretirement health care plans for NSP-Minnesota are as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | Postretirement Benefits |
| (Millions of Dollars) | | 2021 | | 2020 | | 2021 | | 2020 |
| Change in Benefit Obligation: | | | | | | | | |
| Obligation at Jan. 1 | | $ | 989 | | | $ | 942 | | | $ | 73 | | | $ | 76 | |
| Service cost | | 30 | | | 27 | | | — | | | — | |
| Interest cost | | 25 | | | 31 | | | 2 | | | 2 | |
| Plan amendments | | 1 | | | — | | | — | | | — | |
| Actuarial (gain) loss | | (28) | | | 84 | | | (5) | | | 2 | |
| | | | | | | | |
| Benefit payments | | (140) | | | (95) | | | (6) | | | (7) | |
| Obligation at Dec. 31 | | $ | 877 | | | $ | 989 | | | $ | 64 | | | $ | 73 | |
| Change in Fair Value of Plan Assets: | | | | | | | | |
| Fair value of plan assets at Jan. 1 | | $ | 897 | | | $ | 815 | | | $ | 2 | | | $ | 3 | |
| Actual return on plan assets | | 62 | | | 133 | | | — | | | — | |
| Employer contributions | | 34 | | | 44 | | | 7 | | | 6 | |
| | | | | | | | |
| Benefit payments | | (140) | | | (95) | | | (6) | | | (7) | |
| Fair value of plan assets at Dec. 31 | | $ | 853 | | | $ | 897 | | | $ | 3 | | | $ | 2 | |
| Funded status of plans at Dec. 31 | | $ | (24) | | | $ | (92) | | | $ | (61) | | | $ | (71) | |
| Amounts recognized in the Consolidated Balance Sheet at Dec. 31: | | | | | | | | |
| Current liabilities | | $ | — | | | $ | — | | | $ | (3) | | | $ | (5) | |
| Noncurrent liabilities | | (24) | | | (92) | | | (58) | | | (66) | |
| Net amounts recognized | | $ | (24) | | | $ | (92) | | | $ | (61) | | | $ | (71) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | Postretirement Benefits |
| (Millions of Dollars) | | 2020 | | 2019 | | 2020 | | 2019 |
| Change in Benefit Obligation: | | | | | | | | |
| Obligation at Jan. 1 | | $ | 942 | | | $ | 907 | | | $ | 76 | | | $ | 76 | |
| Service cost | | 27 | | | 25 | | | 0 | | | 0 | |
| Interest cost | | 31 | | | 37 | | | 2 | | | 3 | |
| Plan amendments | | 0 | | | 1 | | | 0 | | | 0 | |
| Actuarial loss | | 84 | | | 62 | | | 2 | | | 4 | |
| | | | | | | | |
| Benefit payments | | (95) | | | (90) | | | (7) | | | (7) | |
| Obligation at Dec. 31 | | $ | 989 | | | $ | 942 | | | $ | 73 | | | $ | 76 | |
| Change in Fair Value of Plan Assets: | | | | | | | | |
| Fair value of plan assets at Jan. 1 | | $ | 815 | | | $ | 711 | | | $ | 3 | | | $ | 2 | |
| Actual return on plan assets | | 133 | | | 147 | | | 0 | | | 0 | |
| Employer contributions | | 44 | | | 47 | | | 6 | | | 8 | |
| | | | | | | | |
| Benefit payments | | (95) | | | (90) | | | (7) | | | (7) | |
| Fair value of plan assets at Dec. 31 | | $ | 897 | | | $ | 815 | | | $ | 2 | | | $ | 3 | |
| Funded status of plans at Dec. 31 | | $ | (92) | | | $ | (127) | | | $ | (71) | | | $ | (73) | |
| Amounts recognized in the Consolidated Balance Sheet at Dec. 31: | | | | | | | | |
| Current liabilities | | $ | 0 | | | $ | 0 | | | $ | (5) | | | $ | (4) | |
| Noncurrent liabilities | | (92) | | | (127) | | | (66) | | | (69) | |
| Net amounts recognized | | $ | (92) | | | $ | (127) | | | $ | (71) | | | $ | (73) | |
| | | Pension Benefits | | Postretirement Benefits | | Pension Benefits | | Postretirement Benefits |
| Significant Assumptions Used to Measure Benefit Obligations: | Significant Assumptions Used to Measure Benefit Obligations: | | 2020 | | 2019 | | 2020 | | 2019 | Significant Assumptions Used to Measure Benefit Obligations: | | 2021 | | 2020 | | 2021 | | 2020 |
| Discount rate for year-end valuation | Discount rate for year-end valuation | | 2.71 | % | | 3.49 | % | | 2.65 | % | | 3.47 | % | Discount rate for year-end valuation | | 3.08 | % | | 2.71 | % | | 3.09 | % | | 2.65 | % |
| Expected average long-term increase in compensation level | Expected average long-term increase in compensation level | | 3.75 | % | | 3.75 | % | | N/A | | N/A | Expected average long-term increase in compensation level | | 3.75 | % | | 3.75 | % | | N/A | | N/A |
| Mortality table | Mortality table | | Pri-2012 | | Pri-2012 | | Pri-2012 | | Pri-2012 | Mortality table | | Pri-2012 | | Pri-2012 | | Pri-2012 | | Pri-2012 |
| Health care costs trend rate — initial: Pre-65 | Health care costs trend rate — initial: Pre-65 | | N/A | | N/A | | 5.50 | % | | 6.00 | % | Health care costs trend rate — initial: Pre-65 | | N/A | | N/A | | 5.30 | % | | 5.50 | % |
| Health care costs trend rate — initial: Post-65 | Health care costs trend rate — initial: Post-65 | | N/A | | N/A | | 5.00 | % | | 5.10 | % | Health care costs trend rate — initial: Post-65 | | N/A | | N/A | | 4.90 | % | | 5.00 | % |
| Ultimate trend assumption — initial: Pre-65 | Ultimate trend assumption — initial: Pre-65 | | N/A | | N/A | | 4.50 | % | | 4.50 | % | Ultimate trend assumption — initial: Pre-65 | | N/A | | N/A | | 4.50 | % | | 4.50 | % |
| Ultimate trend assumption — initial: Post-65 | Ultimate trend assumption — initial: Post-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 | Years until ultimate trend is reached | | N/A | | N/A | | 5 | | 3 | Years until ultimate trend is reached | | N/A | | N/A | | 4 | | 5 |
The accumulated benefit obligation for the pension plan was $912$811 million and $872$912 million as of Dec. 31, 2021 and 2020, and 2019, 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 consolidated statements of income.
Components of net periodic benefit cost (credit) and amounts recognized in other comprehensive income and regulatory assets and liabilities:
| | | Pension Benefits | | Postretirement Benefits | | Pension Benefits | | Postretirement Benefits |
| (Millions of Dollars) | (Millions of Dollars) | | 2020 | | 2019 | | 2018 | | 2020 | | 2019 | | 2018 | (Millions of Dollars) | | 2021 | | 2020 | | 2019 | | 2021 | | 2020 | | 2019 |
| Service cost | Service cost | | $ | 27 | | | $ | 25 | | | $ | 28 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | Service cost | | $ | 30 | | | $ | 27 | | | $ | 25 | | | $ | — | | | $ | — | | | $ | — | |
| Interest cost | Interest cost | | 31 | | | 37 | | | 35 | | | 2 | | | 3 | | | 3 | | Interest cost | | 25 | | | 31 | | | 37 | | | 2 | | | 2 | | | 3 | |
| Expected return on plan assets | Expected return on plan assets | | (55) | | | (54) | | | (58) | | | 0 | | | 0 | | | 0 | | Expected return on plan assets | | (52) | | | (55) | | | (54) | | | — | | | — | | | — | |
| Amortization of prior service cost | Amortization of prior service cost | | 0 | | | 0 | | | 0 | | | (3) | | | (3) | | | (3) | | Amortization of prior service cost | | — | | | — | | | — | | | (3) | | | (3) | | | (3) | |
| Amortization of net loss | Amortization of net loss | | 33 | | | 30 | | | 38 | | | 1 | | | 2 | | | 2 | | Amortization of net loss | | 34 | | | 33 | | | 30 | | | 2 | | | 1 | | | 2 | |
Settlement charge (a) | Settlement charge (a) | | 0 | | | 0 | | | 49 | | | 0 | | | 0 | | | 0 | | Settlement charge (a) | | 35 | | | — | | | — | | | — | | | — | | | — | |
| Net periodic pension cost | Net periodic pension cost | | 36 | | | 38 | | | 92 | | | 0 | | | 2 | | | 2 | | Net periodic pension cost | | 72 | | | 36 | | | 38 | | | 1 | | | — | | | 2 | |
| Effects of regulation | Effects of regulation | | (4) | | | (5) | | | (66) | | | 0 | | | 0 | | | 0 | | Effects of regulation | | (44) | | | (4) | | | (5) | | | — | | | — | | | — | |
| Net benefit cost recognized for financial reporting | Net benefit cost recognized for financial reporting | | $ | 32 | | | $ | 33 | | | $ | 26 | | | $ | 0 | | | $ | 2 | | | $ | 2 | | Net benefit cost recognized for financial reporting | | $ | 28 | | | $ | 32 | | | $ | 33 | | | $ | 1 | | | $ | — | | | $ | 2 | |
| Significant Assumptions Used to Measure Costs: | Significant Assumptions Used to Measure Costs: | | | | | | | | | | | | | Significant Assumptions Used to Measure Costs: | | | | | | | | | | | | |
| Discount rate | Discount rate | | 3.49 | % | | 4.31 | % | | 3.63 | % | | 3.47 | % | | 4.32 | % | | 3.62 | % | Discount rate | | 2.71 | % | | 3.49 | % | | 4.31 | % | | 2.65 | % | | 3.47 | % | | 4.32 | % |
| Expected average long-term increase in compensation level | Expected average long-term increase in compensation level | | 3.75 | | | 3.75 | | | 3.75 | | | 0 | | | 0 | | | 0 | | Expected average long-term increase in compensation level | | 3.75 | | | 3.75 | | | 3.75 | | | — | | | — | | | — | |
| Expected average long-term rate of return on assets | Expected average long-term rate of return on assets | | 7.10 | | | 7.10 | | | 7.10 | | | 4.50 | | | 4.50 | | | 5.30 | | Expected average long-term rate of return on assets | | 6.60 | | | 7.10 | | | 7.10 | | | 4.10 | | | 4.50 | | | 4.50 | |
(a)A settlement charge is required when the amount of 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 2018,2021, as a result of lump-sum distributions during the 20182021 plan year, NSP-Minnesota recorded a total pension settlement charge of $49$35 million in 2018,2021, which was not recognized due to the effects of regulation. There were no0 settlement charges recorded to the qualified pension plans in 2020 and 2019.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | Postretirement Benefits |
| (Millions of Dollars) | | 2020 | | 2019 | | 2020 | | 2019 |
| Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: | | | | | | | | |
| Net loss | | $ | 414 | | | $ | 440 | | | $ | 37 | | | $ | 37 | |
| Prior service credit | | 0 | | | 0 | | | (6) | | | (9) | |
| Total | | $ | 414 | | | $ | 440 | | | $ | 31 | | | $ | 28 | |
| 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 | | $ | 29 | | | $ | 29 | | | $ | 0 | | | $ | 0 | |
| Noncurrent regulatory assets | | 385 | | | 411 | | | 29 | | | 26 | |
| Deferred income taxes | | 0 | | | 0 | | | 1 | | | 1 | |
| Net-of-tax accumulated other comprehensive income | | 0 | | | 0 | | | 1 | | | 1 | |
| Total | | $ | 414 | | | $ | 440 | | | $ | 31 | | | $ | 28 | |
| | | | | | | | |
| Measurement date | | Dec 31, 2020 | | Dec 31, 2019 | | Dec 31, 2020 | | Dec 31, 2019 |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | Postretirement Benefits |
| (Millions of Dollars) | | 2021 | | 2020 | | 2021 | | 2020 |
| Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: | | | | | | | | |
| Net loss | | $ | 307 | | | $ | 414 | | | $ | 31 | | | $ | 37 | |
| Prior service credit | | — | | | — | | | (4) | | | (6) | |
| Total | | $ | 307 | | | $ | 414 | | | $ | 27 | | | $ | 31 | |
| 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 | | $ | 25 | | | $ | 29 | | | $ | — | | | $ | — | |
| Noncurrent regulatory assets | | 282 | | | 385 | | | 25 | | | 29 | |
| Deferred income taxes | | — | | | — | | | 1 | | | 1 | |
| Net-of-tax accumulated other comprehensive income | | — | | | — | | | 1 | | | 1 | |
| Total | | $ | 307 | | | $ | 414 | | | $ | 27 | | | $ | 31 | |
| | | | | | | | |
| Measurement date | | Dec 31, 2021 | | Dec 31, 2020 | | Dec 31, 2021 | | Dec 31, 2020 |
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 20182019 —- 20212022 to meet minimum funding requirements.
Total voluntary and required pension funding contributions across all 4 of Xcel Energy’s pension plans were as follows:
•$12550 million in January 2022, of which $5 million is attributable to NSP-Minnesota.
•$131 million in 2021, of which $33$34 million iswas attributable to NSP-Minnesota.
•$150 million in 2020, of which $44 million was attributable to NSP-Minnesota.
•$154 million in 2019, of which $47 million was attributable to NSP-Minnesota.
•$150 million in 2018, of which $63 million was attributable to NSP-Minnesota.
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:
•$109 million in 2022, of which $6 million is attributable to NSP-Minnesota.
•$15 million in 2021, of which $7$8 million, iswas attributable to NSP-Minnesota.
•$11 million in 2020, of which $6 million was attributable to NSP-Minnesota.
•$15 million in 2019, of which $8 million was attributable to NSP-Minnesota.
Target asset allocations:
| | | Pension Benefits | | Postretirement Benefits | | Pension Benefits | | Postretirement Benefits |
| | 2020 | | 2019 | | 2020 | | 2019 | | 2021 | | 2020 | | 2021 | | 2020 |
| Domestic and international equity securities | Domestic and international equity securities | | 35 | % | | 37 | % | | 15 | % | | 15 | % | Domestic and international equity securities | | 33 | % | | 35 | % | | 15 | % | | 15 | % |
| Long-duration fixed income and interest rate swap securities | Long-duration fixed income and interest rate swap securities | | 35 | | | 30 | | | 0 | | | 0 | | Long-duration fixed income and interest rate swap securities | | 37 | | | 35 | | | — | | | — | |
| Short-to-intermediate fixed income securities | Short-to-intermediate fixed income securities | | 13 | | | 14 | | | 72 | | | 72 | | Short-to-intermediate fixed income securities | | 11 | | | 13 | | | 71 | | | 72 | |
| Alternative investments | Alternative investments | | 15 | | | 17 | | | 9 | | | 9 | | Alternative investments | | 17 | | | 15 | | | 8 | | | 9 | |
| Cash | Cash | | 2 | | | 2 | | | 4 | | | 4 | | Cash | | 2 | | | 2 | | | 6 | | | 4 | |
| Total | Total | | 100 | % | | 100 | % | | 100 | % | | 100 | % | Total | | 100 | % | | 100 | % | | 100 | % | | 100 | % |
The asset allocations above reflect target allocations approved in the calendar year to take effect in the subsequent year
Plan Amendments — In 2019, the Pension Protection Act measurement concept was extended beyond 2019 for NSP bargaining terminations and retirements to Dec. 31, 2022.
In 2020, and 2018, there were no0 significant plan amendments made which affected the postretirement 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
NSP-Minnesota’s projected benefit payments:
| | (Millions of Dollars) | (Millions of Dollars) | | Projected
Pension Benefit
Payments | | Gross Projected
Postretirement
Health Care
Benefit Payments | | Expected
Medicare Part D
Subsidies | | Net Projected
Postretirement
Health Care
Benefit Payments | (Millions of Dollars) | | Projected
Pension Benefit
Payments | | Gross Projected
Postretirement
Health Care
Benefit Payments | | Expected
Medicare Part D
Subsidies | | Net Projected
Postretirement
Health Care
Benefit Payments |
| 2021 | | $ | 104 | | | $ | 7 | | | $ | 0 | | | $ | 7 | | |
| 2022 | 2022 | | 92 | | | 6 | | | 0 | | | 6 | | 2022 | | $ | 118 | | | $ | 6 | | | $ | — | | | $ | 6 | |
| 2023 | 2023 | | 86 | | | 6 | | | 0 | | | 6 | | 2023 | | 72 | | | 6 | | | — | | | 6 | |
| 2024 | 2024 | | 79 | | | 5 | | | 0 | | | 5 | | 2024 | | 68 | | | 5 | | | — | | | 5 | |
| 2025 | 2025 | | 75 | | | 5 | | | 0 | | | 5 | | 2025 | | 67 | | | 5 | | | — | | | 5 | |
| 2026-2030 | | 320 | | | 21 | | | 0 | | | 21 | | |
| 2026 | | 2026 | | 64 | | | 5 | | | — | | | 5 | |
| 2027-2031 | | 2027-2031 | | 292 | | | 18 | | | — | | | 18 | |
Defined Contribution Plans
Xcel Energy, which includes NSP-Minnesota, maintains 401(k) and other defined contribution plans that cover most employees. The expense to these plans for NSP-Minnesota was approximately $12 million in 2021, 2020 2019 and 2018.2019.
Multiemployer Plans
NSP-Minnesota contributes to several union multiemployer pension and other postretirement benefit plans, none of which are individually significant. These plans provide pension and postretirement health care benefits to certain union employees who may perform services for multiple employers and do not participate in the NSP-Minnesota sponsored pension and postretirement health care plans. Contributing to these types of plans creates risk that differs from providing benefits under NSP-Minnesota sponsored plans, in that if another participating employer ceases to contribute to a multiemployer plan, additional unfunded obligations may need to be funded over time by remaining participating employers.
| | |
| 10. Commitments and Contingencies |
Legal
NSP-Minnesota 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 NSP-Minnesota’s consolidated financial statements. Unless otherwise required by GAAP, legalLegal fees are generally expensed as incurred.
Rate Matters and Other
NSP-Minnesota 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 have a material effect on the consolidated financial statements.
Minnesota Winter Storm Uri Costs — In its Minnesota jurisdiction, NSP-Minnesota is participating in a contested case regarding the prudency of incremental natural gas costs incurred during Winter Storm Uri. Other parties to the case have recommended significant cost disallowances, and while ultimate resolution of the matter is uncertain, it is reasonably possible that the MPUC could disallow certain deferred costs, resulting in earnings losses. The OAG recommended the MPUC deny recovery of up to $179 million, the largest recommendation among the intervenor positions.
NSP-Minnesota strongly disagrees with the recommendations of the DOC, OAG and CUB, and believes that it acted prudently and according to MPUC approved procedures for the best interest of its customers and stakeholders. NSP-Minnesota filed rebuttal testimony in January 2022 detailing its position that the disallowances recommended by other parties lack any merit in the prudency review given the pertinent facts regarding NSP-Minnesota’s actions before, during and after the storm event. An MPUC decision is expected in the summer of 2022.
Sherco — In 2018, NSP-Minnesota and SMMPASouthern Minnesota Municipal Power Agency (Co-owner of Sherco Unit 3) reached a settlement with GE related to a 2011 incident, which damaged the turbine at Sherco Unit 3 and resulted in an extended outage for repair. NSP-Minnesota notified the MPUC of its proposal to refund settlement proceeds to customers through the FCA.
In March 2019, the MPUC approved NSP-Minnesota’s settlement refund proposal. Additionally, the MPUC decided to withhold any decision as to NSP-Minnesota’s prudence in connection with the incident at Sherco Unit 3 until after conclusion of an appeal pending between GE and NSP-Minnesota’s insurers. In February 2020, the Minnesota Court of Appeals affirmed the district court’s judgment in favor of GE. In March 2020, NSP-Minnesota’s insurers filed a petition seeking additional review by the Minnesota Supreme Court.
In April 2020, the Minnesota Supreme Court denied the insurers’ petition for further review, ending the litigation. In accordance with a prior MPUC order, NSP-Minnesota made a compliance filing in August 2020 detailing all costs that resulted from the outage and all insurance recoveries received by NSP-Minnesota in connection with the outage.
In January 2021, the Minnesota Office of the Attorney GeneralOAG and DOC filed comments recommendingrecommended that NSP-Minnesota refund approximately $17 million of replacement power costs previously recovered through the FCA. On Jan. 27, 2021, NSP-Minnesota subsequently filed its response, asserting that it acted prudently in connection with the Sherco Unit 3 outage, the MPUC has previously disallowed $22 million of related costs and no additional refund or disallowance is appropriate. A final decision by the MPUC is pending. A loss related to this matter is deemed remote.
Westmoreland Arbitration — In November 2014, insurers forof the Westmoreland Coal Company filed an arbitration demand against NSP-Minnesota, SMMPASouthern Minnesota Municipal Power Agency and Western Fuels Association, seeking recovery of alleged $36 million of business losses due to a turbine failure at Sherco Unit 3. The Westmoreland insurers claim NSP-Minnesota’s invocation of the force majeure clause to stop the supply of coal was improper because the incident was allegedly caused by NSP-Minnesota’s failure to conform to industry maintenance standards. Westmoreland’s insurers quantified their losses as approximately $36 million.
Arbitration was delayed pending resolution of a separate lawsuit brought by NSP-Minnesota, SMMPA, and their insurers against various GE entities based on the inspection and maintenance advice GE provided for Sherco Unit 3. In July 2020, following the conclusion of the appeal that fully resolved the GE litigation, Westmoreland’s insurers served notice, which triggered the arbitration to resume.
NSP-Minnesota denies the claims asserted by the Westmoreland insurers and believes it properly stopped the supply of coal based upon the force majeure provision. It is uncertain when aprovision. A final resolution will occur, but it is unlikely an arbitration hearing will take place beforehas been scheduled for October 2022. The parties are also required to participate in mediation, which has been scheduled for the fourthfirst quarter 2021.of 2022. At this stage of the proceeding, before any discovery has been conducted/completed, a reasonable estimate of damages or range of damages cannot be determined.
MISO ROE Complaints — In November 2013 and February 2015, customer groups filed two ROE complaints against MISO TOs, which includes NSP-Minnesota and NSP-Wisconsin. The first complaint requested a reduction in base ROE transmission formula rates from 12.38% to 9.15% for the time period of Nov. 12, 2013 to Feb. 11, 2015, and removal of ROE adders (including those for RTO membership). The second complaint requested, for a subsequent time period, a base ROE reduction from 12.38% to 8.67%.
In September 2016, the FERC issued an order (Opinion No. 551) granting a 10.32% base ROE effective for the first complaint period of Nov. 12, 2013 to Feb. 11, 2015 and subsequent to the date of the order. The D.C Circuit subsequently vacated and remanded the FERC Opinion.
Opinion No. 551.In November 2019, the FERC issued an order (Opinion No. 569), which set the MISO base ROE at 9.88%, effective Sept. 28, 2016 and for the first complaint period. The FERC also dismissed the second complaint. In December 2019, MISO TOs filed a request for rehearing regarding the new ROE methodology announced in Opinion No. 569. Customers also filed requests for rehearing claiming, among other points, that the FERC erred by dismissing the second complaint without refunds.
In May 2020, the FERC issued an order (Opinion No. 569-A) which granted rehearing in part to Opinion 569 and further refined the FERC’s ROE methodology, most significantly to incorporate the risk premium model (in addition to the discounted cash flow and capital asset pricing models), resulting in a new base ROE of 10.02%, effective Sept. 28, 2016 and for the first complaint period. The FERC also affirmed its decision in Opinion No. 569 to dismiss the second complaint.
In June 2020, various parties filed requests for rehearing of Opinion 569-A with the FERC. In November 2020, the FERC issued an order (Opinion No. 569-B) in response to the rehearing requests. The FERC corrected certain inputs to its ROE calculation model, did not change the ROE effective Sept. 28, 2016, and for the first MISO complaint period and upheld its decision to deny refunds for the second complaint period. EachNSP-Minnesota has recognized a liability for its best estimate of final refunds to customers. Each 10 basis point reduction in the allowed base ROE for the first complaint andperiod, second complaint period and subsequent period relative to amounts accrued would reduce Xcel Energy’s net income by $1 million, $1 million and $2 million, respectively.
The MISO TOs and $1 million, respectively.
Variousvarious parties have filed petitions for review of Opinion Nos. 569, 569-A and 569-B at the D.C. Circuit. These appeals remain pending.Oral arguments were held in late 2021 and a decision is expected by the end of the third quarter of 2022.
Environmental
New and changing federal and state environmental mandates can create financial liabilities for NSP-Minnesota, which are normally recovered through the regulated rate process.
Site Remediation
Various federal and state environmental laws impose liability where hazardous substances or other regulated materials have been released to the environment. NSP-Minnesota may sometimes pay all or a portion of the cost to remediate sites where past activities of NSP-Minnesota’s predecessors or other parties have caused environmental contamination. Environmental contingencies could arise from various situations, including sites of former MGPs; and third-party sites, such as landfills, for which NSP-Minnesota is alleged to have sent wastes to that site.
Historical MGP, Landfill and Disposal Sites
NSP-Minnesota is currently investigating, remediating or performing post closure actions at 7 historical MGP, landfill or other disposal sites across its service territories. territories, excluding sites that are being addressed under current coal ash regulations (see below).
NSP-Minnesota has recognized its best estimate of costs/liabilities that will result from final resolution of these issues,issues; however, the outcome and timing isare unknown. In addition, there may be insurance recovery and/or recovery from other potentially responsible parties, offsetting a portion of costs incurred.
Environmental Requirements — Water and Waste
Coal Ash Regulation — NSP-Minnesota’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 CCR landfills and surface impoundments. Currently, NSP-Minnesota has 3 regulated ash units in operation.
NSP-Minnesota is conducting groundwater sampling and monitoring and implementing assessment of corrective measures at certain CCR landfills and surface impoundments. NaN results above the groundwater protection standards in the rule were identified. Until NSP-Minnesota completes its assessment, it is uncertain what impact, if any, there will be on the operations, financial condition or cash flows.
In August 2020, the EPA published its final rule to implement a cease receipt and initiate a closure date ofby April 2021 for all CCR impoundments affected by the August 2018 D.C. Circuit ruling. The D.C. Circuit concluded that the EPA cannot allow utilities to continue to use unlined impoundments (including clay lined impoundments) for the storage or disposal of coal ash. This final rule required NSP-Minnesota to expedite closure plans for 1 impoundment.
In October 2020, NSP-Minnesota completed construction ofand placed in service a new impoundment to replace the clay lined impoundment at a cost of $9 million.impoundment. With the new ash pond in service, NSP-Minnesota has initiated closure activities for the existing ash pond at an estimated cost of $4 million. NSP-Minnesota has five years to complete closure activities.
Closure costs for existing impoundments are included in the calculation of the ARO.
Federal CWA WOTUSWaters of the U.S. Rule — In April 2020, the EPA and U.S. Army Corps of Engineers (“Agencies”) replaced the 2015 WOTUS rule and narrowedNSP-Minnesota is monitoring ongoing changes to the definition of WOTUS (“2020 WOTUS Rule”). The newWaters of the U.S. under the CWA. Regardless of which definition simplifiesis applicable in the process whether waters are subject to CWA jurisdiction and streamlines the permitting process.states in which we operate, NSP-Minnesota does not anticipate that compliance costs will be material.
Federal CWA ELG — In 2015, the EPA issued a final ELG rule for power plants that discharge treated effluent to surface waters as well as utility-owned landfills that receive CCRs. In October 2020, the EPA published a final rule revising the regulations.
The retirement of units affected by the final ELG rule is subject to regulatory approval.The exact total cost of ELG compliance is therefore uncertain but NSP-Minnesotadoes not anticipate that compliance costs will be material.
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 impingement and entrainment of aquatic species. NSP-Minnesota estimates the likely future cost for complying with impingement and entrainment requirements is approximately $37$36 million, to be incurred between 20212022 and 2028. NSP-Minnesota believes 6 plants could be required to make improvements to reduce impingement and entrainment. The exact total cost of the impingement and entrainment improvements is uncertain, but could be up to $189$188 million. NSP-Minnesota anticipates these costs will be fully recoverable through regulatory mechanisms.
Environmental Requirements — Air
Regional Haze Rules — The regional haze program requires sulfur dioxide, nitrogen oxide and particulate matter emission controls at power plants to reduce visibility impairment in national parks and wilderness areas. The program includes best available retrofit technology and reasonable further progress. The regional haze first planning period requirements were approved by the EPA and implemented by 2014.
All states are now subject to a second round of regional haze planning/rulemaking, focusing on additional reductions to meet reasonable progress requirements. Any additional impacts to NSP-Minnesota facilities are expected to be minimal.
AROs — AROs have been recorded for NSP-Minnesota’s assets. For nuclear assets, the ARO is associated with the decommissioning of NSP-Minnesota nuclear generating plants.
Aggregate fair value of NSP-Minnesota’s legally restricted assets, for funding future nuclear decommissioning, was $3.3 billion and $2.8 billion for 2021 and $2.4 billion for 2020, and 2019, respectively.
NSP-Minnesota’s AROs were as follows:
| | | 2020 | | 2021 |
(Millions
of Dollars) | (Millions
of Dollars) | | Jan. 1, 2020 | | Amounts Incurred (a) | | Amounts Settled (b) | | Accretion | | Cash Flow Revisions (c) | | Dec. 31, 2020 | (Millions
of Dollars) | | Jan. 1, 2021 | | Amounts Incurred (a) | | | Accretion | | Cash Flow Revisions (b) | | Dec. 31, 2021 (c) |
| Electric | Electric | | | | | | | | | | | | | Electric | | | | | | | | | | | |
| Nuclear | Nuclear | | $ | 2,068 | | | $ | 0 | | | $ | 0 | | | $ | 105 | | | $ | (216) | | | $ | 1,957 | | Nuclear | | $ | 1,957 | | | $ | — | | | | $ | 99 | | | $ | — | | | $ | 2,056 | |
| Wind | Wind | | 113 | | | 90 | | | 0 | | | 7 | | | 60 | | | 270 | | Wind | | 270 | | | 101 | | | | 13 | | | — | | | 384 | |
| Steam and other production | Steam and other production | | 47 | | | 0 | | | (3) | | | 2 | | | 21 | | | 67 | | Steam and other production | | 67 | | | 6 | | | | 2 | | | (2) | | | 73 | |
| Distribution | Distribution | | 15 | | | 0 | | | 0 | | | 1 | | | 0 | | | 16 | | Distribution | | 16 | | | — | | | | — | | | — | | | 16 | |
| Natural gas | Natural gas | | Natural gas | | | |
| Transmission and distribution | Transmission and distribution | | 36 | | | 0 | | | 0 | | | 2 | | | 1 | | | 39 | | Transmission and distribution | | 39 | | | — | | | | 2 | | | 14 | | | 55 | |
| Common | Common | | Common | | | |
| Miscellaneous | Miscellaneous | | 1 | | | 0 | | | 0 | | | 0 | | | 0 | | | 1 | | Miscellaneous | | 1 | | | — | | | | — | | | — | | | 1 | |
| Total liability | Total liability | | $ | 2,280 | | | $ | 90 | | | $ | (3) | | | $ | 117 | | | $ | (134) | | | $ | 2,350 | | Total liability | | $ | 2,350 | | | $ | 107 | | | | $ | 116 | | | $ | 12 | | | $ | 2,585 | |
(a)Amounts incurred relate to the wind farms placed in service in 2021 (Blazing Star 2, Mower and Freeborn) and removal of a utility scale battery asset.
(b)In 2021, AROs were revised for changes in timing and estimates of cash flows. Changes in gas transmission and distribution AROs were primarily related to changes in labor rates coupled with increased gas line mileage and number of services.
(c)There were no ARO amounts settled in 2021.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2020 |
(Millions
of Dollars) | | Jan. 1, 2020 | | Amounts Incurred (a) | | Amounts Settled (b) | | Accretion | | Cash Flow Revisions (c) | | Dec. 31, 2020 |
| Electric | | | | | | | | | | | | |
| Nuclear | | $ | 2,068 | | | $ | — | | | $ | — | | | $ | 105 | | | $ | (216) | | | $ | 1,957 | |
| Wind | | 113 | | | 90 | | | — | | | 7 | | | 60 | | | 270 | |
| Steam and other production | | 47 | | | — | | | (3) | | | 2 | | | 21 | | | 67 | |
| Distribution | | 15 | | | — | | | — | | | 1 | | | — | | | 16 | |
| Miscellaneous | | — | | | — | | | — | | | — | | | — | | | — | |
| Natural gas | | | | | | | | | | | | |
| Transmission and distribution | | 36 | | | — | | | — | | | 2 | | | 1 | | | 39 | |
| Common | | | | | | | | | | | | |
| Miscellaneous | | 1 | | | — | | | — | | | — | | | — | | | 1 | |
| Total liability | | $ | 2,280 | | | $ | 90 | | | $ | (3) | | | $ | 117 | | | $ | (134) | | | $ | 2,350 | |
(a)Amounts incurred relate to the wind farms placed in service in 2020 (Blazing Star 1, Crowned Ridge, Jeffers and Community Wind North).
(b)Amounts settled related to closure of certain ash containment facilities.
(c)In 2020, AROs were revised for changes in timing and estimates of cash flows. Revisions in the nuclear AROs were driven by reductions in spent fuel cooling time requirements in the nuclear triennial filing coupled with decreasing interest rates. Changes in wind AROs were driven by new dismantling studies. Revisions in steam and other production AROs primarily related to changes in cost estimates for remediation of ash containment facilities.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2019 |
(Millions
of Dollars) | | Jan. 1, 2019 | | Amounts Incurred (a) | | Amounts Settled (b) | | Accretion | | Cash Flow Revisions (c) | | Dec. 31, 2019 |
| Electric | | | | | | | | | | | | |
| Nuclear | | $ | 1,968 | | | $ | 0 | | | $ | 0 | | | $ | 100 | | | $ | 0 | | | $ | 2,068 | |
| Wind | | 105 | | | 10 | | | 0 | | | 5 | | | (7) | | | 113 | |
| Steam and other production | | 49 | | | 0 | | | (3) | | | 2 | | | (1) | | | 47 | |
| Distribution | | 14 | | | 0 | | | 0 | | | 1 | | | 0 | | | 15 | |
| Miscellaneous | | 2 | | | 0 | | | 0 | | | 0 | | | (2) | | | 0 | |
| Natural gas | | | | | | | | | | | | |
| Transmission and distribution | | 38 | | | 0 | | | 0 | | | 2 | | | (4) | | | 36 | |
| Common | | | | | | | | | | | | |
| Miscellaneous | | 1 | | | 0 | | | 0 | | | 0 | | | 0 | | | 1 | |
| Total liability | | $ | 2,177 | | | $ | 10 | | | $ | (3) | | | $ | 110 | | | $ | (14) | | | $ | 2,280 | |
(a)Amounts incurred relate to the wind farms placed in service in 2019 (Lake Benton and Foxtail).
(b)Amounts settled related to closure of certain ash containment facilities.
(c)In 2019, AROs were revised for changes in timing and estimates of cash flows. Changes in wind AROs were driven by new dismantling studies. Changes in gas transmission and distribution AROs were primarily related to increased gas line mileage and number of services, which were more than offset by decreased inflation rates. Changes in steam and other production AROs primarily related to the cost estimates to remediate ponds at production facilities.
Indeterminate AROs — Outside of the recorded asbestos AROs, other plants or buildings may contain asbestos due to the age of many of NSP-Minnesota’s facilities, but no confirmation or measurement of the cost of removal could be determined as of Dec. 31, 2020.2021. Therefore, an ARO has not been recorded for these facilities.
Nuclear Related
Nuclear Insurance — NSP-Minnesota’s public liability for claims from any nuclear incident is limited to $13.8$13.5 billion under the Price-Anderson amendment to the Atomic Energy Act. NSP-Minnesota has secured $450 million of coverage for its public liability exposure with a pool of insurance companies. The remaining $13.3$13.0 billion of exposure is funded by the Secondary Financial Protection Program available from assessments by the federal government.
NSP-Minnesota is subject to assessments of up to $138 million per reactor-incident for each of its 3 reactors, for public liability arising from a nuclear incident at any licensed nuclear facility in the United States. The maximum funding requirement is $21 million per reactor-incident during any one year. Maximum assessments are subject to inflation adjustments.
NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs from NEIL and EMANI. The coverage limits are $2.8 billion for each of NSP-Minnesota’s 2 nuclear plant sites. NEIL also provides business interruption insurance coverage up to $350 million, including the cost of replacement power during prolonged accidental outages of nuclear generating units. Premiums are expensed over the policy term.
All companies insured with NEIL are subject to retroactive premium adjustments if losses exceed accumulated reserve funds. Capital has been accumulated in the reserve funds of NEIL and EMANI to the extent that NSP-Minnesota would have no exposure for retroactive premium assessments in case of a single incident under the business interruption and the property damage insurance coverage. NSP-Minnesota could be subject to annual maximum assessments of $11 million for business interruption insurance and $34$33 million for property damage insurance if losses exceed accumulated reserve funds.
Nuclear Fuel Disposal — NSP-Minnesota is responsible for temporarily storing spent nuclear fuel from its nuclear plants. The DOE is responsible for permanently storing spent fuel from U.S. nuclear plants, but no such facility is yet available.
NSP-Minnesota owns temporary on-site storage facilities for spent fuel at its Monticello and PI nuclear plants, which consist of storage pools and dry cask facilities. The Monticello dry-cask storage facility currently stores all 30 of the authorized canisters. The PI dry-cask storage facility currently stores 47 of the 64 authorized casks. Monticello’s future spent fuel will continue to be placed in its spent fuel pool. The decommissioning plan addresses the disposition of spent fuel at the end of the licensed life. A CON for additional storage at the Monticello site has been filed with the MPUC, to support possible life extension. NSP-Minnesota expects a decision by year-end 2023.
Regulatory Plant Decommissioning Recovery — Decommissioning activities for NSP-Minnesota’s nuclear facilities are planned to begin at the end of each unit’s operating license and be completed by 2095.2091. NSP-Minnesota’s current operating licenses allow continued use of its Monticello nuclear plant until 2030 and its PI nuclear plant until 2033 for Unit 1 and 2034 for Unit 2.
Future decommissioning costs of nuclear facilities are estimated through triennial periodic studies that assess the costs and timing of planned nuclear decommissioning activities for each unit.
Obligations for decommissioning are expected to be funded 100% by the external decommissioning trust fund. The cost study assumes the external decommissioning fund will earn an after-tax return between 5.23% and 6.30%. Realized and unrealized gains on fund investments are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs. Decommissioning costs are quantified in 2014 dollars. Escalation rates are 4.36% for plant removal activities and 3.36% for fuel management and site restoration activities.
NSP-Minnesota had $2.8$3.3 billion of assets held in external decommissioning trusts at Dec. 31, 2020.2021. The following table summarizes the funded status of NSP-Minnesota’s decommissioning obligation. Xcel Energy believes future decommissioning costs will continue to be recovered in customer rates. The following amounts were prepared on a regulatory basis and not directly recorded in the financial statements as an ARO.
| | | Regulatory Basis | | Regulatory Basis |
| (Millions of Dollars) | (Millions of Dollars) | | 2020 | | 2019 | (Millions of Dollars) | | 2021 | | 2020 |
Estimated decommissioning cost obligation from most recently
approved study (in 2014 dollars) | Estimated decommissioning cost obligation from most recently
approved study (in 2014 dollars) | | $ | 3,012 | | | $ | 3,012 | | Estimated decommissioning cost obligation from most recently
approved study (in 2014 dollars) | | $ | 3,012 | | | $ | 3,012 | |
| Effect of escalating costs | Effect of escalating costs | | 844 | | | 688 | | Effect of escalating costs | | 1,006 | | | 844 | |
| Estimated decommissioning cost obligation (in current dollars) | Estimated decommissioning cost obligation (in current dollars) | | 3,856 | | | 3,700 | | Estimated decommissioning cost obligation (in current dollars) | | 4,018 | | | 3,856 | |
| Effect of escalating costs to payment date | Effect of escalating costs to payment date | | 7,349 | | | 7,505 | | Effect of escalating costs to payment date | | 7,187 | | | 7,349 | |
| Estimated future decommissioning costs (undiscounted) | Estimated future decommissioning costs (undiscounted) | | 11,205 | | | 11,205 | | Estimated future decommissioning costs (undiscounted) | | 11,205 | | | 11,205 | |
Effect of discounting obligation (using average risk-free interest rate of 1.64% and 2.39% for 2020 and 2019, respectively) | | (4,181) | | | (5,562) | | |
Effect of discounting obligation (using average risk-free interest rate of 1.96% and 1.64% for 2021 and 2020, respectively) | | Effect of discounting obligation (using average risk-free interest rate of 1.96% and 1.64% for 2021 and 2020, respectively) | | (4,651) | | | (4,181) | |
| Discounted decommissioning cost obligation | Discounted decommissioning cost obligation | | $ | 7,024 | | | $ | 5,643 | | Discounted decommissioning cost obligation | | $ | 6,554 | | | $ | 7,024 | |
| Assets held in external decommissioning trust | Assets held in external decommissioning trust | | $ | 2,777 | | | $ | 2,440 | | Assets held in external decommissioning trust | | $ | 3,256 | | | $ | 2,777 | |
Underfunding of external decommissioning fund compared to
the discounted decommissioning obligation | Underfunding of external decommissioning fund compared to
the discounted decommissioning obligation | | 4,247 | | | 3,203 | | Underfunding of external decommissioning fund compared to
the discounted decommissioning obligation | | 3,298 | | | 4,247 | |
Calculations and data used by the regulator in approving NSP-Minnesota’s rates are useful in assessing future cash flows. Regulatory basis information is a means to reconcile amounts previously provided to the MPUC and utilized for regulatory purposes to amounts used for financial reporting.
Reconciliation of the discounted decommissioning cost obligation - regulated basis to the ARO recorded in accordance with GAAP:
| | (Millions of Dollars) | (Millions of Dollars) | | 2020 | | 2019 | (Millions of Dollars) | | 2021 | | 2020 |
| Discounted decommissioning cost obligation - regulated basis | Discounted decommissioning cost obligation - regulated basis | | $ | 7,024 | | | $ | 5,643 | | Discounted decommissioning cost obligation - regulated basis | | $ | 6,554 | | | $ | 7,024 | |
| Differences in discount rate and market risk premium | Differences in discount rate and market risk premium | | (2,628) | | | (2,295) | | Differences in discount rate and market risk premium | | (2,209) | | | (2,628) | |
| O&M costs not included for GAAP | O&M costs not included for GAAP | | (1,734) | | | (1,280) | | O&M costs not included for GAAP | | (1,584) | | | (1,734) | |
| ARO differences between 2020 and 2014 cost studies | ARO differences between 2020 and 2014 cost studies | | (705) | | | 0 | | ARO differences between 2020 and 2014 cost studies | | (705) | | | (705) | |
| Nuclear production decommissioning ARO - GAAP | Nuclear production decommissioning ARO - GAAP | | $ | 1,957 | | | $ | 2,068 | | Nuclear production decommissioning ARO - GAAP | | $ | 2,056 | | | $ | 1,957 | |
Decommissioning expenses recognized as a result of regulation: | | (Millions of Dollars) | (Millions of Dollars) | | 2020 | | 2019 | | 2018 | (Millions of Dollars) | | 2021 | | 2020 | | 2019 |
Annual decommissioning recorded as depreciation expense: (a) (b) | Annual decommissioning recorded as depreciation expense: (a) (b) | | $ | 20 | | | $ | 20 | | | $ | 20 | | Annual decommissioning recorded as depreciation expense: (a) (b) | | $ | 22 | | | $ | 20 | | | $ | 20 | |
(a)Decommissioning expense does not include depreciation of the capitalized nuclear asset retirement costs.
(b)Decommissioning expenses in 2021, 2020 2019 and 20182019 include Minnesota’s retail jurisdiction annual funding requirement of approximately $14 million.
The 2014 nuclear decommissioning filing, approved in 2015, was used for regulatory presentation in 2020, 2019 and 2018. Although there was a nuclear triennial filing in 2017, the MPUC continued to approve the 2014 triennial filing as the regulatory basis in 2020, 2019 and 2018. In December 2020, the MPUC verbally approved NSP-Minnesota to continue using the 2014 filing as the basis for 2021.
The 2017 nuclear decommissioning filing, effective Jan. 1, 2019, has been approved by the MPUC. In March 2020, the MPUC approved for NSP-Minnesota to delay any increase to the annual funding requirement until 2021. In December 2020, the MPUC verbally approved for NSP-Minnesota to delay any increase to the annual funding requirement until 2022. Also, as of December 2020, NSP-Minnesota submitted a Petition for approval of the 2022 - 2024 Nuclear Decommissioning Study and Assumptions. Contemplated but not proposed in this filing, was the 10-year extension of the license to operate the Monticello Plant, moving the planned retirement date from 2030 to 2040. The 2019 Preferred Integrated Resource Plan Supplement does include a 10-year extension of the license.On Feb. 8, 2022, the MPUC ruled on and approved the 10-year extension for the Monticello nuclear facility.
Leases
NSP-Minnesota evaluates contracts that may contain leases, including PPAs and arrangements for the use of office space and other facilities, vehicles and equipment. A contract contains a lease if it conveys the exclusive right to control the use of a specific asset. A contract determined to contain a lease is evaluated further to determine if the arrangement is a finance lease.
ROU assets represent NSP-Minnesota's rights to use leased assets. The present value of future operating lease payments areis 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 NSP-Minnesota’s leases do not contain a readily determinable discount rate. Therefore, the present value of future lease payments is generally calculated using the estimated incremental borrowing rate (weighted-average(weighted average of 3.8%).
NSP-Minnesota has elected to utilize the practical expedient under which non-lease components, such as asset maintenance costs included in payments, are not deducted from minimum lease payments for the purposes of lease accounting and disclosure.
Leases with an initial term of 12 months or less are classified as short-term leases and are not recognized on the consolidated balance sheet.
Operating lease ROU assets:
| | (Millions of Dollars) | (Millions of Dollars) | | Dec. 31, 2020 | | Dec. 31, 2019 | (Millions of Dollars) | | Dec. 31, 2021 | | Dec. 31, 2020 |
| PPAs | PPAs | | $ | 558 | | | $ | 556 | | PPAs | | $ | 556 | | | $ | 558 | |
| Other | Other | | 74 | | | 72 | | Other | | 74 | | | 74 | |
| Gross operating lease ROU assets | Gross operating lease ROU assets | | 632 | | | 628 | | Gross operating lease ROU assets | | 630 | | | 632 | |
| Accumulated amortization | Accumulated amortization | | (144) | | | (64) | | Accumulated amortization | | (222) | | | (144) | |
| Net operating lease ROU assets | Net operating lease ROU assets | | $ | 488 | | | $ | 564 | | Net operating lease ROU assets | | $ | 408 | | | $ | 488 | |
Components of lease expense:
| | (Millions of Dollars) | (Millions of Dollars) | | 2020 | | 2019 | | 2018 | (Millions of Dollars) | | 2021 | | 2020 | | 2019 |
| Operating leases | Operating leases | | | | | | | Operating leases | | | | | | |
| PPA capacity payments | PPA capacity payments | | $ | 89 | | | $ | 76 | | | $ | 63 | | PPA capacity payments | | $ | 96 | | | $ | 89 | | | $ | 76 | |
Other operating leases (a) | Other operating leases (a) | | 8 | | | 9 | | | 14 | | Other operating leases (a) | | 8 | | | 8 | | | 9 | |
Total operating lease expense (b) | Total operating lease expense (b) | | $ | 97 | | | $ | 85 | | | $ | 77 | | Total operating lease expense (b) | | $ | 104 | | | $ | 97 | | | $ | 85 | |
(a)Includes short-term lease expense ofof $2 million, $2 million and $1 million for 2021, 2020 and $2 million for 2020, 2019, and 2018, respectively.
(b)PPA capacity payments are included in electric fuel and purchased power on the consolidated statements of income. Expense for other operating leases is included in O&M expense and electric fuel and purchased power.
Commitments under operating leases as of Dec. 31, 2020:2021:
| | (Millions of Dollars) | (Millions of Dollars) | | PPA (a) (b) Operating Leases | | Other Operating Leases | | Total
Operating Leases | (Millions of Dollars) | | PPA (a) (b) Operating Leases | | Other Operating Leases | | Total
Operating Leases |
| 2021 | | $ | 95 | | | $ | 8 | | | $ | 103 | | |
| 2022 | 2022 | | 96 | | | 12 | | | 108 | | 2022 | | $ | 96 | | | $ | 9 | | | $ | 105 | |
| 2023 | 2023 | | 98 | | | 8 | | | 106 | | 2023 | | 98 | | | 12 | | | 110 | |
| 2024 | 2024 | | 100 | | | 7 | | | 107 | | 2024 | | 100 | | | 7 | | | 107 | |
| 2025 | 2025 | | 80 | | | 7 | | | 87 | | 2025 | | 80 | | | 7 | | | 87 | |
| 2026 | | 2026 | | 40 | | | 7 | | | 47 | |
| Thereafter | Thereafter | | 40 | | | 39 | | | 79 | | Thereafter | | — | | | 31 | | | 31 | |
| Total minimum obligation | Total minimum obligation | | 509 | | | 81 | | | 590 | | Total minimum obligation | | 414 | | | 73 | | | 487 | |
| Interest component of obligation | Interest component of obligation | | (48) | | | (14) | | | (62) | | Interest component of obligation | | (32) | | | (12) | | | (44) | |
| Present value of minimum obligation | Present value of minimum obligation | | $ | 461 | | | $ | 67 | | | 528 | | Present value of minimum obligation | | $ | 382 | | | $ | 61 | | | 443 | |
| Less current portion | Less current portion | | (85) | | Less current portion | | (90) | |
| Noncurrent operating lease liabilities | Noncurrent operating lease liabilities | | $ | 443 | | Noncurrent operating lease liabilities | | $ | 353 | |
| | Weighted-average remaining lease term in years | Weighted-average remaining lease term in years | | 5.8 | Weighted-average remaining lease term in years | | 8.5 |
(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 2026.2039.
PPAs and Fuel Contracts
Non-Lease PPAs — NSP-Minnesota has entered into PPAs with other utilities and energy suppliers with various expiration dates through 2033 for purchased power to meet system load and energy requirements, operating reserve obligations and as part of wholesale and commodity trading activities. In general, these agreements provide for energy payments, based on actual energy delivered and capacity payments. Certain PPAs, accounted for as executory contracts with various expiration dates through 2033, contain minimum energy purchase commitments, and totalcommitments. Total energy payments on those contracts were $149 million, $112 million and $102 million in 2021, 2020 and $105 million in 2020, 2019, and 2018, respectively.
Included in electric fuel and purchased power expenses for PPAs accounted for as executory contracts were payments for capacity of $55 million, $52 million and $54 million in 2021, 2020 and $53 million in 2020, 2019, and 2018, respectively.
Capacity and energy payments are contingent on the IPPs meeting contract obligations, including plant availability requirements. Certain contractual payments are adjusted based on market indices. The effects of price adjustments on financial results are mitigated through purchased energy cost recovery mechanisms.
At Dec. 31, 2020,2021, the estimated future payments for capacity and energy that NSP-Minnesota is obligated to purchase pursuant to these executory contracts, subject to availability, were as follows:
| | (Millions of Dollars) | (Millions of Dollars) | | Capacity | | Energy (a) | (Millions of Dollars) | | Capacity | | Energy (a) |
| 2021 | | $ | 56 | | | $ | 156 | | |
| 2022 | 2022 | | 60 | | | 172 | | 2022 | | $ | 60 | | | $ | 165 | |
| 2023 | 2023 | | 61 | | | 176 | | 2023 | | 61 | | | 169 | |
| 2024 | 2024 | | 63 | | | 181 | | 2024 | | 63 | | | 174 | |
| 2025 | 2025 | | 26 | | | 60 | | 2025 | | 26 | | | 53 | |
| 2026 | | 2026 | | 9 | | | 10 | |
| Thereafter | Thereafter | | 19 | | | 85 | | Thereafter | | 10 | | | 38 | |
Total (b) | Total (b) | | $ | 285 | | | $ | 830 | | Total (b) | | $ | 229 | | | $ | 609 | |
(a)Excludes contingent energy payments for renewable energy PPAs.
(b)Includes amounts allocated to NSP-Wisconsin through intercompany charges.
Fuel Contracts — NSP-Minnesota has entered into various long-term commitments for the purchase and delivery of a significant portion of its coal, nuclear fuel and natural gas requirements. These contracts expire in various years between 20212022 and 2037. NSP-Minnesota is required to pay additional amounts depending on actual quantities shipped under these agreements.
Estimated minimum purchases for these contracts as of Dec. 31, 2020:2021: | | (Millions of Dollars) | (Millions of Dollars) | | Coal | | Nuclear fuel | | Natural gas
supply | | Natural gas
storage and
transportation | (Millions of Dollars) | | Coal | | Nuclear fuel | | Natural gas
supply | | Natural gas
storage and
transportation |
| 2021 | | $ | 79 | | | $ | 101 | | | $ | 58 | | | $ | 124 | | |
| 2022 | 2022 | | 69 | | | 87 | | | 1 | | | 120 | | 2022 | | $ | 219 | | | $ | 89 | | | $ | 95 | | | $ | 128 | |
| 2023 | 2023 | | 35 | | | 103 | | | 1 | | | 109 | | 2023 | | 79 | | | 109 | | | — | | | 114 | |
| 2024 | 2024 | | 1 | | | 83 | | | 0 | | | 103 | | 2024 | | 48 | | | 82 | | | — | | | 108 | |
| 2025 | 2025 | | 1 | | | 121 | | | 0 | | | 93 | | 2025 | | 1 | | | 119 | | | — | | | 98 | |
| 2026 | | 2026 | | 1 | | | 29 | | | — | | | 97 | |
| Thereafter | Thereafter | | 2 | | | 274 | | | 0 | | | 200 | | Thereafter | | 1 | | | 309 | | | — | | | 107 | |
Total (a) | Total (a) | | $ | 187 | | | $ | 769 | | | $ | 60 | | | $ | 749 | | Total (a) | | $ | 349 | | | $ | 737 | | | $ | 95 | | | $ | 652 | |
(a)Includes amounts allocated to NSP-Wisconsin through intercompany charges.
VIEs
Under certain PPAs, NSP-Minnesota purchases power from IPPs for which NSP-Minnesota is required to reimburse fuel costs, or to participate in tolling arrangements under which NSP-Minnesota procures the natural gas required to produce the energy that it purchases. NSP-Minnesota has determined that certain IPPs are VIEs. NSP-Minnesota 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. NSP-Minnesota 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.
NSP-Minnesota 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. NSP-Minnesota had approximately 1,347 MW of capacity under long-term PPAs at both Dec. 31, 20202021 and 20192020 with entities that have been determined to be VIEs. These agreements have expiration dates through 2039.
| | |
| 11. Other Comprehensive Income |
Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31: | | | 2020 | | 2021 |
| (Millions of Dollars) | (Millions of Dollars) | | Gains and Losses on Cash Flow Hedges | | Defined Benefit Pension and Postretirement Items | | Total | (Millions of Dollars) | | Gains and Losses on Cash Flow Hedges | | Defined Benefit Pension and Postretirement Items | | Total |
| Accumulated other comprehensive loss at Jan. 1 | Accumulated other comprehensive loss at Jan. 1 | | $ | (20) | | | $ | (3) | | | $ | (23) | | Accumulated other comprehensive loss at Jan. 1 | | $ | (19) | | | $ | (3) | | | $ | (22) | |
| | Losses reclassified from net accumulated other comprehensive loss: | Losses reclassified from net accumulated other comprehensive loss: | | Losses reclassified from net accumulated other comprehensive loss: | |
| Interest rate derivatives, net of tax of $0 | | 1 | | (a) | 0 | | | 1 | | |
| Interest rate derivatives, net of tax of $— | | Interest rate derivatives, net of tax of $— | | 2 | | (a) | — | | | 2 | |
| | Net current period other comprehensive income | Net current period other comprehensive income | | 1 | | | 0 | | | 1 | | Net current period other comprehensive income | | 2 | | | — | | | 2 | |
| Accumulated other comprehensive loss at Dec. 31 | Accumulated other comprehensive loss at Dec. 31 | | $ | (19) | | | $ | (3) | | | $ | (22) | | Accumulated other comprehensive loss at Dec. 31 | | $ | (17) | | | $ | (3) | | | $ | (20) | |
(a)Included in interest charges.
| | | | | | | | | | | | | | | | | | | | |
| | 2020 |
| (Millions of Dollars) | | Gains and Losses on Cash Flow Hedges | | Defined Benefit Pension and Postretirement Items | | Total |
| Accumulated other comprehensive loss at Jan. 1 | | $ | (20) | | | $ | (3) | | | $ | (23) | |
| | | | | | |
| Losses reclassified from net accumulated other comprehensive loss: | | | | | | |
| Interest rate derivatives, net of tax of $— | | 1 | | (a) | — | | | 1 | |
| | | | | | |
| Net current period other comprehensive income | | 1 | | | — | | | 1 | |
| Accumulated other comprehensive loss at Dec. 31 | | $ | (19) | | | $ | (3) | | | $ | (22) | |
(a)Included in interest charges.
| | | | | | | | | | | | | | | | | | | | |
| | 2019 |
| (Millions of Dollars) | | Losses on Cash Flow Hedges | | Defined Benefit Pension and Postretirement Items | | Total |
| Accumulated other comprehensive loss at Jan. 1 | | $ | (20) | | | $ | (3) | | | $ | (23) | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| Accumulated other comprehensive loss at Dec. 31 | | $ | (20) | | | $ | (3) | | | $ | (23) | |
NSP-Minnesota 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.
NSP-Minnesota has the following reportable segments:
•Regulated Electric — The regulated electric utility segment generates, electricity which is transmittedtransmits and distributeddistributes electricity in Minnesota, North Dakota and South Dakota. In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States. The regulated electric utility segment also includes NSP-Minnesota’s wholesale commodity and trading operations.
•Regulated Natural Gas — The regulated natural gas utility segment transports, stores and distributes natural gas primarily in portions of Minnesota and North Dakota.
NSP-Minnesota also presents All Other, which includes operating segments with revenues below the necessary quantitative thresholds. Those operating segments primarily include steam revenue, appliance repair services, non-utility real estate activities and revenues associated with processing solid waste into refuse-derived fuel.
Asset and capital expenditure information is not provided for NSP-Minnesota’s reportable segments. As an integrated electric and natural gas utility, NSP-Minnesota operates significant assets that are not dedicated to a specific business segment. 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.
Certain costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation allocators 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.
NSP-Minnesota’s segment information is as follows:information:
| | (Millions of Dollars) | (Millions of Dollars) | | 2020 | | 2019 | | 2018 | (Millions of Dollars) | | 2021 | | 2020 | | 2019 |
| Regulated Electric | Regulated Electric | | | | | | | Regulated Electric | | | | | | |
Operating revenues - external (a) | | $ | 4,571 | | | $ | 4,506 | | | $ | 4,508 | | |
Operating revenues — external (a) | | Operating revenues — external (a) | | $ | 5,094 | | | $ | 4,571 | | | $ | 4,506 | |
| Intersegment revenue | Intersegment revenue | | 1 | | | 1 | | | 1 | | Intersegment revenue | | 1 | | | 1 | | | 1 | |
| Total revenues | Total revenues | | $ | 4,572 | | | $ | 4,507 | | | $ | 4,509 | | Total revenues | | $ | 5,095 | | | $ | 4,572 | | | $ | 4,507 | |
| Depreciation and amortization | Depreciation and amortization | | 773 | | | 742 | | | 698 | | Depreciation and amortization | | 869 | | | 773 | | | 742 | |
| Interest charges and financing costs | Interest charges and financing costs | | 221 | | | 205 | | | 199 | | Interest charges and financing costs | | 240 | | | 221 | | | 205 | |
| Income tax (benefit) expense | Income tax (benefit) expense | | (14) | | | 36 | | | 16 | | Income tax (benefit) expense | | (53) | | | (14) | | | 36 | |
| Net income | Net income | | 553 | | | 491 | | | 450 | | Net income | | 566 | | | 553 | | | 491 | |
| Regulated Natural Gas | Regulated Natural Gas | | Regulated Natural Gas | |
| Operating revenues - external | | $ | 493 | | | $ | 571 | | | $ | 583 | | |
Operating revenues — external (b) | | Operating revenues — external (b) | | $ | 623 | | | $ | 493 | | | $ | 571 | |
| Intersegment revenue | Intersegment revenue | | 0 | | | 1 | | | 0 | | Intersegment revenue | | 1 | | | — | | | 1 | |
| Total revenues | Total revenues | | $ | 493 | | | $ | 572 | | | $ | 583 | | Total revenues | | $ | 624 | | | $ | 493 | | | $ | 572 | |
| Depreciation and amortization | Depreciation and amortization | | 51 | | | 49 | | | 43 | | Depreciation and amortization | | 56 | | | 51 | | | 49 | |
| Interest charges and financing costs | Interest charges and financing costs | | 17 | | | 16 | | | 15 | | Interest charges and financing costs | | 18 | | | 17 | | | 16 | |
| Income tax expense | Income tax expense | | 7 | | | 12 | | | 10 | | Income tax expense | | 6 | | | 7 | | | 12 | |
| Net income | Net income | | 30 | | | 40 | | | 34 | | Net income | | 29 | | | 30 | | | 40 | |
| All Other | All Other | | All Other | |
| Total revenues | Total revenues | | $ | 37 | | | $ | 35 | | | $ | 31 | | Total revenues | | $ | 39 | | | $ | 37 | | | $ | 35 | |
| Depreciation and amortization | Depreciation and amortization | | 1 | | | 0 | | | 1 | | Depreciation and amortization | | 1 | | | 1 | | | — | |
| | Income tax expense (benefit) | | 1 | | | (1) | | | 1 | | |
| Income tax (benefit) expense | | Income tax (benefit) expense | | (1) | | | 1 | | | (1) | |
| Net income | Net income | | 8 | | | 12 | | | 8 | | Net income | | 11 | | | 8 | | | 12 | |
| | Consolidated Total | Consolidated Total | | Consolidated Total | |
Total revenues (a)(b) | Total revenues (a)(b) | | $ | 5,102 | | | $ | 5,114 | | | $ | 5,123 | | Total revenues (a)(b) | | $ | 5,758 | | | $ | 5,102 | | | $ | 5,114 | |
| Reconciling eliminations | Reconciling eliminations | | (1) | | | (2) | | | (1) | | Reconciling eliminations | | (2) | | | (1) | | | (2) | |
| Total operating revenues | Total operating revenues | | $ | 5,101 | | | $ | 5,112 | | | $ | 5,122 | | Total operating revenues | | $ | 5,756 | | | $ | 5,101 | | | $ | 5,112 | |
| Depreciation and amortization | Depreciation and amortization | | 825 | | | 791 | | | 742 | | Depreciation and amortization | | 926 | | | 825 | | | 791 | |
| Interest charges and financing costs | Interest charges and financing costs | | 238 | | | 221 | | | 214 | | Interest charges and financing costs | | 258 | | | 238 | | | 221 | |
| Income tax (benefit) expense | Income tax (benefit) expense | | (6) | | | 47 | | | 27 | | Income tax (benefit) expense | | (48) | | | (6) | | | 47 | |
| Net income | Net income | | 591 | | | 543 | | | 492 | | Net income | | 606 | | | 591 | | | 543 | |
(a) Operating revenues include $501 million, $440 million and $457 million and $474 million of intercompanyaffiliate electric revenue for the years ended Dec. 31, 2021, 2020 and 2019, respectively. See Note 13 for further information.
(b) Operating revenues include $1 million of affiliate gas revenue for the years ended Dec. 31, 2021, 2020 and 2018,2019, respectively. See Note 13 for further information.
| | |
| 13. Related Party Transactions |
Xcel Energy Services Inc. provides management, administrative and other services for the subsidiaries of Xcel Energy Inc., including NSP-Minnesota. The services are provided and billed to each subsidiary in accordance with service agreements executed by each subsidiary. NSP-Minnesota uses the services provided by Xcel Energy Services Inc. whenever possible. Costs are charged directly to the subsidiary and are allocated if they cannot be directly assigned.
Xcel Energy, Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS have established a utility money pool arrangement.
See Note 5 for further information.
The electric production and transmission costs of the entire NSP System are shared by NSP-Minnesota and NSP-Wisconsin. The Interchange Agreement provides for the sharing of all costs of generation and transmission facilities of the system, including capital costs.
Significant affiliate transactions among the companies and related parties including billings under the Interchange Agreement for the years ended Dec. 31:
| | (Millions of Dollars) | (Millions of Dollars) | | 2020 | | 2019 | | 2018 | (Millions of Dollars) | | 2021 | | 2020 | | 2019 |
| Operating revenues: | Operating revenues: | | | | | | | Operating revenues: | | | | | | |
| Electric | Electric | | $ | 440 | | | $ | 457 | | | $ | 474 | | Electric | | $ | 501 | | | $ | 440 | | | $ | 457 | |
| Gas | Gas | | 1 | | | 1 | | | 0 | | Gas | | 1 | | | 1 | | | 1 | |
| Operating expenses: | Operating expenses: | | Operating expenses: | |
| Purchased power | Purchased power | | 59 | | | 61 | | | 61 | | Purchased power | | 67 | | | 59 | | | 61 | |
| Transmission expense | Transmission expense | | 109 | | | 116 | | | 97 | | Transmission expense | | 121 | | | 109 | | | 116 | |
| Other operating expenses — paid to Xcel Energy Services Inc. | Other operating expenses — paid to Xcel Energy Services Inc. | | 584 | | | 533 | | | 535 | | Other operating expenses — paid to Xcel Energy Services Inc. | | 615 | | | 584 | | | 533 | |
| Interest expense | Interest expense | | 0 | | | 1 | | | 0 | | Interest expense | | — | | | — | | | 1 | |
Accounts receivable and payable with affiliates at Dec. 31 were:31:
| | | 2020 | | 2019 | | 2021 | | 2020 |
| (Millions of Dollars) | (Millions of Dollars) | | Accounts Receivable | | Accounts Payable | | Accounts Receivable | | Accounts Payable | (Millions of Dollars) | | Accounts Receivable | | Accounts Payable | | Accounts Receivable | | Accounts Payable |
| NSP-Wisconsin | NSP-Wisconsin | | $ | 6 | | | $ | 0 | | | $ | 8 | | | $ | 0 | | NSP-Wisconsin | | $ | 13 | | | $ | — | | | $ | 6 | | | $ | — | |
| PSCo | PSCo | | 1 | | | 0 | | | 0 | | | 19 | | PSCo | | 16 | | | — | | | 1 | | | — | |
| SPS | SPS | | 0 | | | 3 | | | 0 | | | 4 | | SPS | | — | | | 2 | | | — | | | 3 | |
| Other subsidiaries of Xcel Energy Inc. | Other subsidiaries of Xcel Energy Inc. | | 25 | | | 63 | | | 36 | | | 53 | | Other subsidiaries of Xcel Energy Inc. | | — | | | 61 | | | 25 | | | 63 | |
| | $ | 32 | | | $ | 66 | | | $ | 44 | | | $ | 76 | | | $ | 29 | | | $ | 63 | | | $ | 32 | | | $ | 66 | |
| | |
14. Summarized Quarterly Financial Data (Unaudited) |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Quarter Ended |
| (Millions of Dollars) | | March 31, 2020 | | June 30, 2020 | | Sept. 30, 2020 | | Dec. 31, 2020 |
| Operating revenues | | $ | 1,250 | | | $ | 1,180 | | | $ | 1,388 | | | $ | 1,283 | |
| Operating income | | 157 | | | 158 | | | 314 | | | 167 | |
| Net income | | 107 | | | 117 | | | 246 | | | 121 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Quarter Ended |
| (Millions of Dollars) | | March 31, 2019 | | June 30, 2019 | | Sept. 30, 2019 | | Dec. 31, 2019 |
| Operating revenues | | $ | 1,350 | | | $ | 1,185 | | | $ | 1,345 | | | $ | 1,232 | |
| Operating income | | 167 | | | 147 | | | 291 | | | 182 | |
| Net income | | 113 | | | 96 | | | 209 | | | 125 | |
| | |
ITEM 9 — CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
None.
| | |
ITEM 9A — CONTROLS AND PROCEDURES |
Disclosure Controls and Procedures
NSP-Minnesota maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms.
In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the CEO and CFO, allowing timely decisions regarding required disclosure. As of Dec. 31, 20202021, based on an evaluation carried out under the supervision and with the participation of NSP-Minnesota’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and procedures, the CEO and CFO have concluded that NSP-Minnesota’s disclosure controls and procedures were effective.
Internal Control Over Financial Reporting
No changes in NSP-Minnesota’s internal control over financial reporting occurred during the most recent fiscal quarter ended Dec. 31, 2021 that materially affected, or are reasonably likely to materially affect, NSP-Minnesota’s internal control over financial reporting. NSP-Minnesota maintains internal control over financial reporting to provide reasonable assurance regarding the reliability of the financial reporting. NSP-Minnesota 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, 20202021 on internal controls under section 404 of the Sarbanes-Oxley Act of 2002, NSP-Minnesota conducted testing and monitoring of its internal control over financial reporting. Based on the control evaluation, testing and remediation performed, NSP-Minnesota did not identify any material control weaknesses, as defined under the standards and rules issued by the Public Company Accounting Oversight Board, as approved by the SEC and as indicated in NSP-Minnesota’s Management Report on Internal Controls over Financial Reporting, which is contained in Item 8 herein.
This annual report does not include an attestation report of NSP-Minnesota’s independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by NSP-Minnesota’s independent registered public accounting firm pursuant to the rules of the SEC that permit NSP-Minnesota to provide only management’s report in this annual report.
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ITEM 9B — OTHER INFORMATION |
None.
| | |
| ITEM 9C — DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS |
Not applicable.
PART III
Items 10, 11, 12 and 13 of Part III of Form 10-K have been omitted from this report for NSP-Minnesota in accordance with conditions set forth in general instructionsGeneral Instructions I(1)(a) and (b) of Form 10-K for wholly-owned subsidiaries.
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ITEM 10 — DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE |
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ITEM 11 — EXECUTIVE COMPENSATION |
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ITEM 12 — SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS |
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ITEM 13 — CERTAIN RELATIONSHIPRELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE |
Information required under this Item is contained in Xcel Energy Inc.’s definitive Proxy Statement for its 20212022 Annual Meeting of Shareholders, which is incorporated by reference.
| | |
ITEM 14 — PRINCIPAL ACCOUNTANT FEES AND SERVICES |
The informationInformation required under this Item (aggregate fees billed to us by Item 14 of Form 10-Kour principal accountant, Deloitte & Touche LLP (PCAOB ID No. 34)) is set forth under the heading “Independent Registered Public Accounting Firm - Audit and Non-Audit Fees”contained in Xcel Energy Inc.’s Proxy Statement for the 2021its 2022 Annual Meeting of Shareholders, which is expected to be filed with the SEC on or about April 6, 2021. Such information set forth under such heading is incorporated herein by this reference hereto.reference.
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ITEM 15 — EXHIBIT AND FINANCIAL STATEMENT SCHEDULES |
| | | | | |
| 1 | Consolidated Financial Statements: |
| |
| Management Report on Internal Controls Over Financial Reporting — For the year ended Dec. 31, 2020.2021. |
| Report of Independent Registered Public Accounting Firm — Financial Statements |
| Consolidated Statements of Income — For each of the three years ended Dec. 31, 2021, 2020 2019 and 2018.2019. |
| Consolidated Statements of Comprehensive Income — For each of the three years ended Dec. 31, 2021, 2020 2019 and 2018.2019. |
| Consolidated Statements of Cash Flows — For each of the three years ended Dec. 31, 2021, 2020 2019 and 2018.2019. |
| Consolidated Balance Sheets — As of Dec. 31, 20202021 and 2019.2020. |
| Consolidated Statements of Common Stockholder’s Equity — For each of the three years ended Dec. 31, 2021, 2020 2019 and 2018.2019. |
| |
| 2 | Schedule II — Valuation and Qualifying Accounts and Reserves for each of the years ended Dec. 31, 2021, 2020 2019 and 2018.2019. |
| |
| 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 |
| | NSP-Minnesota Form 10-12G dated Oct. 5, 2000 | 3.01 |
| | NSP-Minnesota Form 10-K for the year ended Dec. 31, 2018 | 3.02 |
| | Xcel Energy Inc. Form S-3 dated April 18, 2018 | 4(b)(3) |
| | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2017 | 4.11 |
| | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2017 | 4.12 |
| | NSP-Minnesota Form 10-12G dated Oct. 5, 2000 | 4.51 |
| | Xcel Energy Inc. Form S-3 dated April 18, 2018 | 4(b)(7) |
| | NSP-Minnesota Form 10-12G dated Oct. 5, 2000 | 4.63 |
| | NSP-Minnesota Form 8-K dated July 14, 2005 | 4.01 |
| | NSP-Minnesota Form 8-K dated May 18, 2006 | 4.01 |
| | NSP-Minnesota Form 8-K dated June 19, 2007 | 4.01 |
| | NSP-Minnesota Form 8-K dated Nov. 16, 2009 | 4.01 |
| | NSP-Minnesota Form 8-K dated Aug. 4, 2010 | 4.01 |
| | NSP-Minnesota Form 8-K dated Aug. 13, 2012 | 4.01 |
| | NSP-Minnesota Form 8-K dated May 20, 2013 | 4.01 |
| | NSP-Minnesota Form 8-K dated May 13, 2014 | 4.01 |
| | NSP-Minnesota Form 8-K dated Aug. 11, 2015 | 4.01 |
| | NSP-Minnesota Form 8-K dated May 31, 2016 | 4.01 |
| | NSP-Minnesota Form 8-K dated Sept. 13, 2017 | 4.01 |
| | NSP-Minnesota Form 8-K dated Sept. 10, 2019 | 4.01 |
| | | | | | | | | | | |
| | NSP-Minnesota 8-K dated June 15, 2020 | 4.01 |
| | NSP-Minnesota 8-K dated March 30, 2021 | 4.01 |
| | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008 | 10.02 |
| | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008 | 10.05 |
| | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2011 | 10.18 |
| | Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2016 | 10.01 |
| | Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2018 | 10.01 |
| | Xcel Energy Inc. Form 10-Q for the quarter ended March 31, 2020 | 10.02 |
| | Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2020 | 10.01 |
| | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008 | 10.17 |
| | Xcel Energy Inc. Definitive Proxy Statement dated April 6, 2010 | Appendix A |
| | Xcel Energy Inc. Form 10-Q for the quarter ended March 31, 2013 | 10.01 |
| | Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2009 | 10.08 |
| | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008 | 10.07 |
| | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2011 | 10.17 |
| | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2013 | 10.22 |
| | Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2016 | 10.01 |
| | Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2017 | 10.1 |
| | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018 | 10.34 |
| | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018 | 10.35 |
| | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2019 | 10.33 |
| | Xcel Energy Inc. Definitive Proxy Statement dated April 5, 2011 | Schedule 14A |
| | Xcel Energy Inc. Form 8-K dated May 20,26, 2015 | 10.02 |
| | Xcel Energy Inc. Form 10-K10-Q for the yearquarter ended Dec. 31, 2020September 30, 2021 | 10.2210.01 |
| | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018 | 10.36 |
| | Xcel Energy Inc. Form U5B dated Nov. 16, 2000 | H-1 |
| | NSP-Wisconsin Form S-4 dated Jan. 21, 2004 | 10.01 |
| Third Amended and Restated Credit Agreement, dated as of June 7, 2019 among NSP-Minnesota, 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, as Syndication Agents, Wells Fargo Bank, National Association, MUFG Bank, Ltd., and Citibank, N.A., as Documentation Agents | Xcel Energy Inc. Form 8-K dated June 7, 2019 | 99.02 |
| |
| |
| |
| |
| 101.INS | Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document |
| 101.SCH | Inline XBRL Schema |
| 101.CAL | Inline XBRL Calculation |
| 101.DEF | Inline XBRL Definition |
| 101.LAB | Inline XBRL Label |
| 101.PRE | Inline XBRL Presentation |
| 104 | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) |
SCHEDULE II
NSP-Minnesota and Subsidiaries Valuation and Qualifying Accounts Years Ended Dec. 31 | | | Allowance for bad debts | | Allowance for bad debts |
| (Millions of Dollars) | (Millions of Dollars) | | 2020 | | 2019 | | 2018 | (Millions of Dollars) | | 2021 | | 2020 | | 2019 |
| Balance at Jan. 1 | Balance at Jan. 1 | | $ | 23 | | | $ | 24 | | | $ | 21 | | Balance at Jan. 1 | | $ | 33 | | | $ | 23 | | | $ | 24 | |
| Additions charged to costs and expenses | Additions charged to costs and expenses | | 24 | | | 13 | | | 16 | | Additions charged to costs and expenses | | 24 | | | 24 | | | 13 | |
Additions charged to other accounts (a) | Additions charged to other accounts (a) | | 5 | | | 7 | | | 4 | | Additions charged to other accounts (a) | | 5 | | | 5 | | | 7 | |
Deductions from reserves (b) | Deductions from reserves (b) | | (19) | | | (21) | | | (17) | | Deductions from reserves (b) | | (17) | | | (19) | | | (21) | |
| Balance at Dec. 31 | Balance at Dec. 31 | | $ | 33 | | | $ | 23 | | | $ | 24 | | Balance at Dec. 31 | | $ | 45 | | | $ | 33 | | | $ | 23 | |
(a)Recovery of amounts previously written-off.
(b)Deductions related 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.
| | | | | | | | |
| | NORTHERN STATES POWER COMPANY (A MINNESOTA CORPORATION) |
| | |
Feb. 17, 202123, 2022 | | /s/ BRIAN J. VAN ABEL |
| | Brian J. Van Abel |
| | Executive Vice President, Chief Financial Officer and Director |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities on the date indicated above.
| | | | | | | | |
/s/ BEN FOWKEROBERT C. FRENZEL | | /s/ CHRISTOPHER B. CLARK |
Ben FowkeRobert C. Frenzel | | Christopher B. Clark |
| Chairman, Chief Executive Officer and Director | | President and Director |
| (Principal Executive Officer) | | |
| | |
| /s/ BRIAN J. VAN ABEL | | /s/ JEFFREY S. SAVAGE |
| Brian J. Van Abel | | Jeffrey S. Savage |
| Executive Vice President, Chief Financial Officer and Director | | Senior Vice President, Controller |
| (Principal Financial Officer) | | (Principal Accounting Officer) |
| | |
/s/ ROBERT C. FRENZEL | | |
Robert C. Frenzel | | |
Executive Vice President, Chief Operating Officer and Director | | |
SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(D) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT
NSP-Minnesota has not sent, and does not expect to send, an annual report or proxy statement to its security holder.
