☒ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
001-3034 | ||
(Commission File Number) |
Xcel Energy Inc. | ||||||||
(Exact name of registrant as specified in its charter) | ||||||||
Minnesota | 41-0448030 | |||||||||||||
(State or Other Jurisdiction of Incorporation or Organization) | (IRS Employer Identification No.) | |||||||||||||
414 Nicollet Mall | Minneapolis | Minnesota | 55401 | |||||||||||
(Address of Principal Executive Offices) | (Zip Code) |
612 | 330-5500 | ||||
(Registrant’s Telephone Number, Including Area Code) |
Title of each class | Trading Symbol | Name of each exchange on which registered | ||||||||||||
Common Stock, $2.50 par value | XEL | Nasdaq Stock Market LLC |
PART I | ||||||||
Item 1 — | ||||||||
Item 1A — | ||||||||
Item 1B — | ||||||||
Item 2 — | ||||||||
Item 3 — | ||||||||
Item 4 — | ||||||||
PART | ||||||||
Item 5 — | ||||||||
Item 6 — | ||||||||
Item 7 — | ||||||||
Item 7A — | ||||||||
Item 8 — | ||||||||
Item 9 — | ||||||||
Item 9A — | ||||||||
Item 9B — | ||||||||
PART III | ||||||||
Item 10 — | ||||||||
Item 11 — | ||||||||
Item 12 — | ||||||||
Item 13 — | ||||||||
Item 14 — | ||||||||
PART IV | ||||||||
Item 15 — | ||||||||
Item 16 — | ||||||||
ITEM 1 — BUSINESS |
Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former) | |||||
Capital Services | Capital Services, LLC | ||||
Eloigne | Eloigne Company | ||||
e prime | e prime inc. | ||||
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 | ||||
Operating companies | NSP-Minnesota, NSP-Wisconsin, PSCo and SPS | ||||
PSCo | Public Service Company of Colorado | ||||
SPS | Southwestern Public Service Co. | ||||
Utility subsidiaries | NSP-Minnesota, NSP-Wisconsin, PSCo and SPS | ||||
WGI | WestGas InterState, Inc. | ||||
WYCO | WYCO Development, LLC | ||||
Xcel Energy | Xcel Energy Inc. and its subsidiaries |
Federal and State Regulatory Agencies | |||||
CPUC | Colorado Public Utilities Commission | ||||
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 | ||||
Fifth Circuit | United States Court of Appeals for the Fifth Circuit | ||||
IRS | Internal Revenue Service | ||||
Minnesota District Court | U.S. District Court for the District of Minnesota | ||||
MPSC | Michigan Public Service Commission | ||||
MPUC | Minnesota Public Utilities Commission | ||||
NDPSC | North Dakota Public Service Commission | ||||
NERC | North American Electric Reliability Corporation | ||||
NMPRC | New Mexico Public Regulation Commission | ||||
NRC | Nuclear Regulatory Commission | ||||
Pipeline and Hazardous Materials Safety Administration | |||||
PSCW | Public Service Commission of Wisconsin | ||||
PUCT | Public Utility Commission of Texas | ||||
SDPUC | South Dakota Public Utilities Commission | ||||
SEC | Securities and Exchange Commission | ||||
TCEQ | Texas Commission on Environmental Quality |
Electric, Purchased Gas and Resource Adjustment Clauses | |||||
Colorado Energy Plan Adjustment | |||||
CIP | Conservation improvement program | ||||
DCRF | Distribution cost recovery factor | ||||
DSM | Demand side management | ||||
DSMCA | |||||
ECA | Retail electric commodity adjustment | ||||
EECRF | Energy efficiency cost recovery factor | ||||
Environmental improvement rider | |||||
FCA | Fuel clause adjustment | ||||
FPPCAC | Fuel and purchased power cost adjustment clause | ||||
GCA | Gas cost adjustment | ||||
GUIC | Gas utility infrastructure cost rider | ||||
PCCA | Purchased capacity cost adjustment |
Power cost recovery factor | |||||
PGA | Purchased gas adjustment | ||||
PSIA | Pipeline system integrity adjustment | ||||
RDF | Renewable development fund | ||||
RER | Renewable energy rider | ||||
RES | Renewable energy standard | ||||
RESA | |||||
SCA | Steam cost adjustment | ||||
SEP | State energy policy rider | ||||
TCA | Transmission cost adjustment | ||||
TCR | Transmission cost recovery adjustment | ||||
TCRF | Transmission cost recovery factor | ||||
WCA | Wind cost adjustment |
Other | |||||
ADIT | Accumulated deferred income taxes | ||||
AFUDC | Allowance for funds used during construction | ||||
ALLETE, Inc. | |||||
ARO | Asset retirement obligation | ||||
ASC | FASB Accounting Standards Codification | ||||
ASU | FASB Accounting Standards Update | ||||
BART | Best available retrofit technology | ||||
Boulder | City of Boulder, CO | ||||
C&I | Commercial and Industrial | ||||
Compound annual growth rate | |||||
CACJA | Clean Air Clean Jobs Act | ||||
Alliance of electric cooperatives, municipals and investor-owned utilities in the upper Midwest involved in a joint transmission line planning and construction effort | |||||
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 | ||||
CDD | Cooling degree-days | ||||
CEO | Chief executive officer | ||||
CFO | Chief financial officer | ||||
Colorado Interstate Gas Company, LLC | |||||
CWA | Clean Water Act | ||||
CWIP | Construction work in progress | ||||
DECON | Decommissioning method where radioactive contamination is removed and safely disposed of at a requisite facility or decontaminated to a permitted | ||||
Dividend Reinvestment Program | |||||
EEI | Edison Electric Institute | ||||
ELG | Effluent limitations guidelines | ||||
EMANI | European Mutual Association for Nuclear Insurance | ||||
EPS | Earnings per share | ||||
Effective tax rate | |||||
FASB | Financial Accounting Standards Board | ||||
FTR | Financial transmission right | ||||
GAAP | Generally accepted accounting principles | ||||
GE | General Electric | ||||
GHG | Greenhouse gas | ||||
HDD | Heating degree-days | ||||
IM | Integrated market | ||||
INPO | Institute of Nuclear Power Operations |
Independent power producing entity | |||||
IRP | Integrated Resource Plan | ||||
ITC | Investment Tax Credit | ||||
JOA | Joint operating agreement | ||||
LSP Transmission | LSP Transmission Holdings, LLC | ||||
MDL | Multi-district litigation | ||||
MEC | Mankato Energy Center | ||||
MGP | Manufactured gas plant | ||||
MISO | Midcontinent Independent System Operator, Inc. | ||||
Moody’s | Moody’s Investor Services | ||||
NAAQS | National Ambient Air Quality Standard | ||||
Native load | Demand of retail and wholesale customers that a utility has an obligation to serve under statute or contract | ||||
NAV | Net asset value | ||||
NEIL | Nuclear Electric Insurance Ltd. | ||||
Net operating loss | |||||
O&M | Operating and maintenance | ||||
OATT | Open Access Transmission Tariff | ||||
PI | Prairie Island nuclear generating plant | ||||
Post-65 | Post-Medicare | ||||
PPA | Purchased power agreement | ||||
Pre-65 | Pre-Medicare | ||||
PTC | Production tax credit | ||||
REC | Renewable energy credit | ||||
ROE | Return on equity | ||||
ROFR | Right-of-first-refusal | ||||
ROU | Right-of-use | ||||
RPS | Renewable portfolio standards | ||||
RTO | Regional Transmission Organization | ||||
Standard & Poor’s Global Ratings | |||||
SERP | Supplemental executive retirement plan | ||||
SMMPA | Southern Minnesota Municipal Power Agency | ||||
SO2 | Sulfur dioxide | ||||
SPP | Southwest Power Pool, Inc. | ||||
TCEH | Texas Competitive Energy Holdings | ||||
TCJA | 2017 federal tax reform enacted as Public Law No: 115-97, commonly referred to as the Tax Cuts and Jobs Act | ||||
THI | Temperature-humidity index | ||||
TOs | Transmission owners | ||||
Total shareholder return | |||||
VaR | Value at Risk | ||||
VIE | Variable interest entity | ||||
WOTUS | Waters of the U.S. |
Measurements | |||||
Bcf | Billion cubic feet | ||||
KV | Kilovolts | ||||
KWh | Kilowatt hours | ||||
MMBtu | Million British thermal units | ||||
MW | Megawatts | ||||
MWh | Megawatt hours |
Where to Find More Information |
Forward-Looking Statements |
Overview |
Utility Subsidiaries’ Service Territory | |||||||||||
Electric customers | 3.7 million | ||||||||||
Natural gas customers | 2.1 million | ||||||||||
Total assets | $ | ||||||||||
Electric generating capacity | |||||||||||
Natural gas storage capacity | 53.4 Bcf | ||||||||||
Electric transmission lines (conductor miles) | |||||||||||
Electric distribution lines (conductor miles) | |||||||||||
Natural gas transmission lines | |||||||||||
Natural gas distribution lines | |||||||||||
Vision, Mission and Values |
Employees Covered by Collective Bargaining Agreements | Total Full-Time Employees | |||||||
NSP-Minnesota | 2,033 | 3,144 | ||||||
NSP-Wisconsin | 394 | 540 | ||||||
PSCo | 1,882 | 2,378 | ||||||
SPS | 769 | 1,141 | ||||||
XES | — | 4,164 | ||||||
Total | 5,078 | 11,367 |
Female | Ethnically Diverse | |||||||
Board of Directors | 20% | 20% | ||||||
CEO direct reports | 38% | 13% | ||||||
Management | 22% | 10% | ||||||
Employees | 23% | 16% | ||||||
New hires | 33% | 22% | ||||||
Interns (hired throughout 2020) | 33% | 28% |
NSP-Minnesota | |||||||||||||||||
Electric customers | 1.5 million | 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 | 0.6 million | ||||||||||||||||
Consolidated earnings contribution | 35% to 45% | ||||||||||||||||
Total assets | $ | ||||||||||||||||
Rate Base (estimated) | $ | ||||||||||||||||
ROE (net income / average stockholder's equity) | |||||||||||||||||
Electric generating capacity | |||||||||||||||||
Gas storage capacity | 17.1 Bcf | ||||||||||||||||
Electric transmission lines (conductor miles) | |||||||||||||||||
Electric distribution lines (conductor miles) | |||||||||||||||||
Natural gas transmission lines | |||||||||||||||||
Natural gas distribution lines | |||||||||||||||||
NSP-Wisconsin | |||||||||||||||||
Electric customers | 0.3 million | NSP-Wisconsin conducts business in Wisconsin and Michigan and generates, transmits, distributes and sells electricity. NSP-Minnesota and NSP-Wisconsin electric operations are managed on the NSP System. NSP-Wisconsin also purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas. | |||||||||||||||
Natural gas customers | 0.1 million | ||||||||||||||||
Consolidated earnings contribution | 5% to 10% | ||||||||||||||||
Total assets | $ | ||||||||||||||||
Rate Base (estimated) | $ | ||||||||||||||||
ROE (net income / average stockholder's equity) | |||||||||||||||||
Electric generating capacity | 548 MW | ||||||||||||||||
Gas storage capacity | 3.8 Bcf | ||||||||||||||||
Electric transmission lines (conductor miles) | |||||||||||||||||
Electric distribution lines (conductor miles) | |||||||||||||||||
Natural gas transmission lines | 3 miles | ||||||||||||||||
Natural gas distribution lines | |||||||||||||||||
PSCo | |||||||||||||||||
Electric customers | 1.5 million | PSCo conducts business in Colorado and generates, purchases, transmits, distributes and sells electricity. PSCo also purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas. | |||||||||||||||
Natural gas customers | 1.4 million | ||||||||||||||||
Consolidated earnings contribution | 35% to 45% | ||||||||||||||||
Total assets | $ | ||||||||||||||||
Rate Base (estimated) | $ | ||||||||||||||||
ROE (net income / average stockholder's equity) | |||||||||||||||||
Electric generating capacity | |||||||||||||||||
Gas storage capacity | 32.5 Bcf | ||||||||||||||||
Electric transmission lines (conductor miles) | |||||||||||||||||
Electric distribution lines (conductor miles) | |||||||||||||||||
Natural gas transmission lines | |||||||||||||||||
Natural gas distribution lines | |||||||||||||||||
SPS | |||||||||||||||||
Electric customers | 0.4 million | SPS conducts business in Texas and New Mexico and generates, purchases, transmits, distributes and sells electricity. | |||||||||||||||
Consolidated earnings contribution | 15% to 20% | ||||||||||||||||
Total assets | $ | ||||||||||||||||
Rate | $ | ||||||||||||||||
ROE (net income / average stockholder's equity) | |||||||||||||||||
Electric generating capacity | |||||||||||||||||
Electric transmission lines (conductor miles) | |||||||||||||||||
Electric distribution lines (conductor miles) | |||||||||||||||||
Operations Overview |
Electric Operations |
2020 | 2019 | |||||||||||||
KWh sales per retail customer | 23,910 | 24,712 | ||||||||||||
Revenue per retail customer | $ | 2,199 | $ | 2,244 | ||||||||||
Residential revenue per KWh | 12.12 | ¢ | 11.97 | ¢ | ||||||||||
Large C&I revenue per KWh | 5.78 | ¢ | 5.96 | ¢ | ||||||||||
Small C&I revenue per KWh | 9.56 | ¢ | 9.43 | ¢ | ||||||||||
Total retail revenue per KWh | 9.20 | ¢ | 9.08 | ¢ |
2019 | 2018 | |||||||
KWh sales per retail customer | 24,712 | 25,263 | ||||||
Revenue per retail customer | $2,244 | $ | 2,257 | |||||
Residential revenue per KWh | 11.97 | ¢ | 11.78 | ¢ | ||||
Large C&I revenue per KWh | 5.96 | ¢ | 5.91 | ¢ | ||||
Small C&I revenue per KWh | 9.43 | ¢ | 9.21 | ¢ | ||||
Total retail revenue per KWh | 9.08 | ¢ | 8.93 | ¢ |
* Includes biomass and hydroelectric. |
2020 | 2019 | |||||||||||||||||||||||||
Utility Subsidiary | Wind Farms | Capacity (a) | Wind Farms | Capacity (b) | ||||||||||||||||||||||
NSP System | 11 | 1,540 MW | 7 | 1,079 MW | ||||||||||||||||||||||
PSCo | 2 | 1,059 MW | 1 | 582 MW | ||||||||||||||||||||||
SPS | 2 | 967 MW | 1 | 460 MW | ||||||||||||||||||||||
Total | 15 | 3,566 MW | 9 | 2,121 MW |
2019 | 2018 | |||||||
Utility Subsidiary | Wind Farms | Capacity | Wind Farms | Capacity | ||||
NSP System | 7 | 1,090 MW | 5 | 840 MW | ||||
PSCo | 1 | 600 MW | 1 | 600 MW | ||||
SPS | 1 | 478 MW | — | — |
Utility Subsidiary | 2019 | 2018 | Utility Subsidiary | 2020 | 2019 | |||||||||||||||||||||||||||||
PPAs | Range | PPAs | Range | PPAs | Range | PPAs | Range | |||||||||||||||||||||||||||
NSP System | 131 | 0.7 MW — 205.5 MW | 132 | 0.7 MW - 205.5 MW | NSP System | 129 | 1 MW — 206 MW | 131 | 1 MW — 206 MW | |||||||||||||||||||||||||
PSCo | 20 | 2.0 MW — 300.5 MW | 19 | 2.0 MW - 300.5 MW | PSCo | 17 | 23 MW — 301 MW | 20 | 2 MW — 301 MW | |||||||||||||||||||||||||
SPS | 18 | 0.7 MW — 250.0 MW | 18 | 0.7 MW - 250.0 MW | SPS | 18 | 1 MW — 250MW | 18 | 1 MW — 250 MW |
Utility Subsidiary | 2019 | 2018 | Utility Subsidiary | 2020 | 2019 | |||||||||||||
NSP System | 2,780 MW | 2,550 MW | NSP System | 3,348 MW | 2,767 MW | |||||||||||||
PSCo | 3,165 MW | 3,160 MW | PSCo | 4,085 MW | 3,145 MW | |||||||||||||
SPS | 2,045 MW | 1,565 MW | SPS | 2,535 MW | 2,027 MW |
Utility Subsidiary | 2020 | 2019 | ||||||||||||
NSP System | $ | 23 | $ | 35 | ||||||||||
PSCo | 35 | 47 | ||||||||||||
SPS | 17 | — |
Utility Subsidiary (a) | 2019 | 2018 | ||||||
NSP System | $ | 35 | $ | 37 | ||||
PSCo | 47 | — |
Utility Subsidiary | 2019 | 2018 | Utility Subsidiary | 2020 | 2019 | |||||||||||||||||
NSP System | $ | 41 | $ | 44 | NSP System | $ | 38 | $ | 41 | |||||||||||||
PSCo | 41 | 43 | PSCo | 40 | 41 | |||||||||||||||||
SPS | 25 | 26 | SPS | 26 | 25 |
Project | Utility Subsidiary | Capacity | ||||||||||||||
Blazing Star 1 | NSP-Minnesota | 200 MW | ||||||||||||||
Crowned Ridge 2 | NSP-Minnesota | |||||||||||||||
Community Wind North | NSP-Minnesota | 26 MW | ||||||||||||||
NSP-Minnesota | 43 MW | |||||||||||||||
Cheyenne Ridge | PSCo | 477 MW | ||||||||||||||
Sagamore | SPS | 507 MW | ||||||||||||||
Various PPAs | Various | ~ |
Utility Subsidiary | Capacity | Estimated Completion | ||||||||||||||||||
2021 | ||||||||||||||||||||
2021 | ||||||||||||||||||||
2021 | ||||||||||||||||||||
2022 | ||||||||||||||||||||
2024 | ||||||||||||||||||||
2024 | ||||||||||||||||||||
Grand Meadow | NSP-Minnesota | 100 MW | 2023 | |||||||||||||||||
Mower | NSP-Minnesota | 99 MW | 2021 | |||||||||||||||||
Various PPAs | Various | ~450 MW | 2021 |
Type | Utility Subsidiary | Capacity | ||||||||||||
Distributed Generation | NSP System | 899 MW | ||||||||||||
Utility-Scale | NSP System | 268 MW | ||||||||||||
Distributed Generation | PSCo | 643 MW | ||||||||||||
Utility-Scale | PSCo | 306 MW | ||||||||||||
Distributed Generation | SPS | 11 MW | ||||||||||||
Utility-Scale | SPS | 190 MW | ||||||||||||
Total | 2,317 MW |
Utility Subsidiary | 2020 | 2019 | ||||||||||||
NSP System | $ | 90 | $ | 81 | ||||||||||
PSCo | 89 | 89 | ||||||||||||
SPS | 59 | 56 |
Utility Subsidiary | Nuclear | |||||||||||||
NSP System | Cost | Percent | ||||||||||||
2020 | $ | 0.80 | 51 | % | ||||||||||
2019 | 0.81 | 45 |
Utility Subsidiary | Nuclear | ||||||
NSP System | Cost | Percent | |||||
2019 | $ | 0.81 | 45 | % | |||
2018 | 0.80 | 45 |
Approved | ||||||||||||||||||||
Year | Utility Subsidiary | Plant Unit | Capacity | |||||||||||||||||
2022 | PSCo | Comanche 1 | 325 MW | |||||||||||||||||
2023 | NSP-Minnesota | Sherco 2 | 682 MW | |||||||||||||||||
Harrington(a) | ||||||||||||||||||||
2025 | PSCo | |||||||||||||||||||
Craig 1 | 42 MW(b) | |||||||||||||||||||
2026 | NSP-Minnesota | Sherco 1 | 680 MW | |||||||||||||||||
2028 | PSCo | Craig 2 | 40 MW(b) |
Proposed | ||||||||||||||||||||
Year | Utility Subsidiary | Plant Unit | Capacity | |||||||||||||||||
98 MW(a) | ||||||||||||||||||||
Hayden 1 | 135 MW(b) | |||||||||||||||||||
2028 | NSP-Minnesota | A.S. King | 511 MW | |||||||||||||||||
2030 | NSP-Minnesota | Sherco 3 | 517 MW(c) | |||||||||||||||||
2032 | SPS | Tolk 1 | 532 MW | |||||||||||||||||
2032 | SPS | Tolk 2 | 535 MW |
Coal (a) | ||||||||||||||
Utility Subsidiary | Cost | Percent | ||||||||||||
NSP System | ||||||||||||||
2020 | $ | 1.97 | 31 | % | ||||||||||
2019 | 2.02 | 36 | ||||||||||||
PSCo | ||||||||||||||
2020 | 1.41 | 51 | ||||||||||||
2019 | 1.45 | 55 | ||||||||||||
SPS | ||||||||||||||
2020 | 2.28 | 40 | ||||||||||||
2019 | 2.19 | 45 |
Coal (a) | |||||||
Utility Subsidiary | Cost | Percent | |||||
NSP System | |||||||
2019 | $ | 2.02 | 36 | % | |||
2018 | 2.13 | 42 | |||||
PSCo | |||||||
2019 | 1.45 | 55 | |||||
2018 | 1.45 | 62 | |||||
SPS | |||||||
2019 | 2.19 | 45 | |||||
2018 | 2.04 | 56 |
Natural Gas | ||||||||||||||
Utility Subsidiary | Cost | Percent | ||||||||||||
NSP System | ||||||||||||||
2020 | $ | 2.67 | 17 | % | ||||||||||
2019 | 3.09 | 19 | ||||||||||||
PSCo | ||||||||||||||
2020 | 3.01 | 49 | ||||||||||||
2019 | 3.27 | 45 | ||||||||||||
SPS | ||||||||||||||
2020 | 1.43 | 60 | ||||||||||||
2019 | 1.14 | 55 |
Natural Gas | |||||||
Utility Subsidiary | Cost | Percent | |||||
NSP System | |||||||
2019 | $ | 3.09 | 19 | % | |||
2018 | 3.87 | 13 | |||||
PSCo | |||||||
2019 | 3.27 | 45 | |||||
2018 | 3.74 | 38 | |||||
SPS | |||||||
2019 | 1.14 | 55 | |||||
2018 | 2.24 | 44 |
System Peak Demand (in MW) | ||||||||||||||||||||||||||
2020 | 2019 | |||||||||||||||||||||||||
NSP System | 8,571 | July 8 | 8,774 | July 19 | ||||||||||||||||||||||
PSCo | 6,899 | Aug. 17 | 7,111 | July 19 | ||||||||||||||||||||||
SPS | 4,195 | July 14 | 4,261 | Aug. 5 |
System Peak Demand (in MW) | ||||||||||
Utility Subsidiary | 2019 | 2018 | ||||||||
NSP System | 8,774 | July 19 | 8,927 | June 29 | ||||||
PSCo | 7,111 | July 19 | 6,718 | July 10 | ||||||
SPS | 4,261 | Aug. 5 | 4,648 | July 19 |
Project | Utility Subsidiary | Miles | Size | |||||||||||||||||
Maple River-Red River | NSP-Minnesota | 115 KV | ||||||||||||||||||
69 KV | ||||||||||||||||||||
SPS | ||||||||||||||||||||
SPS | 345 KV | |||||||||||||||||||
Mustang-Seminole | SPS | 20 | 115 KV | |||||||||||||||||
Loving South-Phantom | SPS | 21 | 115 KV |
Project | Utility Subsidiary | Miles | Size | Completion Date | Project | Utility Subsidiary | Miles | Size | Completion Date | ||||||||||||||||||||||||||
Hibbing Taconite Relocation | Hibbing Taconite Relocation | NSP-Minnesota | 3 | 500 KV | 2021 | ||||||||||||||||||||||||||||||
Huntley-Wilmarth | NSP-Minnesota | 50 | 345 KV | 2021 | Huntley-Wilmarth | NSP-Minnesota | 50 | 345 KV | 2021 | ||||||||||||||||||||||||||
Helena Scott County | Helena Scott County | NSP-Minnesota | 16 | 345 KV | 2021 | ||||||||||||||||||||||||||||||
Baytown to Long Lake | Baytown to Long Lake | NSP-Minnesota | 9 | 115 KV | 2022 | ||||||||||||||||||||||||||||||
Centerville to Lincoln County | Centerville to Lincoln County | NSP-Minnesota | 14 | 69 KV | 2021 | ||||||||||||||||||||||||||||||
Turtle Lake Almena | Turtle Lake Almena | NSP-Wisconsin | 4 | 69 KV | 2021 | ||||||||||||||||||||||||||||||
Bayfield Second Circuit | NSP-Wisconsin | 19 | 35 KV | 2022 | Bayfield Second Circuit | NSP-Wisconsin | 19 | 35 KV | 2022 | ||||||||||||||||||||||||||
Cheyenne Ridge | PSCo | 65 | 345 KV | 2020 | |||||||||||||||||||||||||||||||
TUCO-Yoakum-Hobbs | SPS | 106 | 345 KV | 2020 | |||||||||||||||||||||||||||||||
Eddy-Kiowa | SPS | 34 | 345 KV | 2020 | |||||||||||||||||||||||||||||||
Roadrunner-China Draw | Roadrunner-China Draw | SPS | 41 | 345 KV | 2021 |
Natural Gas Operations |
2019 | 2018 | |||||||
MMBtu sales per retail customer | 129.31 | 120.51 | ||||||
Revenue per retail customer | $ | 851.94 | $ | 785.86 | ||||
Residential revenue per MMBtu | 7.14 | 7.01 | ||||||
C&I revenue per MMBtu | 5.73 | 5.76 | ||||||
Transportation and other revenue per MMBtu | 0.57 | 0.80 |
2020 | 2019 | |||||||||||||
MMBtu sales per retail customer | 118.13 | 129.31 | ||||||||||||
Revenue per retail customer | $ | 720.42 | $ | 851.94 | ||||||||||
Residential revenue per MMBtu | 6.64 | 7.14 | ||||||||||||
C&I revenue per MMBtu | 5.22 | 5.73 | ||||||||||||
Transportation and other revenue per MMBtu | 0.67 | 0.57 |
2020 | 2019 | |||||||||||||||||||||||||
Utility Subsidiary | MMBtu | Date | MMBtu | Date | ||||||||||||||||||||||
NSP-Minnesota | 871,921 | Jan. 16 | 897,615 | Feb. 25 | ||||||||||||||||||||||
NSP-Wisconsin | 150,320 | Dec. 24 | 166,009 | Jan. 30 | ||||||||||||||||||||||
PSCo | 1,931,888 | Feb. 4 | 2,139,420 | March 3 |
2019 | 2018 | |||||||||
Utility Subsidiary | MMBtu | Date | MMBtu | Date | ||||||
NSP-Minnesota | 897,615 | (a) | Feb. 25 | 786,751 | Jan. 12 | |||||
NSP-Wisconsin | 166,009 | (a) | Jan. 30 | 159,700 | Jan. 5 | |||||
PSCo | 2,139,420 | (a) | March 3 | 1,903,878 | Feb. 20 |
Utility Subsidiary | 2019 | 2018 | Utility Subsidiary | 2020 | 2019 | |||||||||||||||||
NSP-Minnesota | $ | 3.71 | $ | 4.03 | NSP-Minnesota | $ | 3.32 | $ | 3.71 | |||||||||||||
NSP-Wisconsin | 3.49 | 3.84 | NSP-Wisconsin | 3.08 | 3.49 | |||||||||||||||||
PSCo | 2.95 | 3.20 | PSCo | 2.52 | 2.95 |
General |
Public Utility Regulation |
Environmental |
•$400 million in 2020. •$345 million in 2019. • |
Capital Spending and Financing |
Employees Covered by CBAs | Total Employees | |||||
NSP-Minnesota | 2,036 | 3,203 | ||||
NSP-Wisconsin | 392 | 538 | ||||
PSCo | 1,884 | 2,369 | ||||
SPS | 779 | 1,158 | ||||
XES | — | 4,005 | ||||
Total | 5,091 | 11,273 |
Information about our Executive Officers (a) | ||||||||||||||||||||
Name | Age (b) | Current and Recent Positions | Time in Position | |||||||||||||||||
Ben Fowke | Chairman of the Board | August 2011 — Present | ||||||||||||||||||
Chief Executive Officer, NSP-Minnesota, NSP-Wisconsin, PSCo, and SPS | January 2015 — Present | |||||||||||||||||||
Robert C. Frenzel | 50 | |||||||||||||||||||
March | ||||||||||||||||||||
Executive Vice President, Chief Financial Officer, Xcel Energy Inc. | May 2016 — | |||||||||||||||||||
Senior Vice President and Chief Financial Officer, Luminant, a subsidiary of Energy Future Holdings Corp. | February 2012 — April 2016 | |||||||||||||||||||
Brett C. Carter | 54 | Executive Vice President and Chief Customer and Innovation Officer, Xcel Energy Inc. | May 2018 — Present | |||||||||||||||||
Senior Vice President and Shared Services Executive, Bank of America, an institutional investment bank and financial services company | October 2015 — May 2018 | |||||||||||||||||||
Christopher B. Clark | 54 | President and Director, NSP-Minnesota | January 2015 — Present | |||||||||||||||||
Darla Figoli | 58 | Executive Vice President, Human Resources & Employee Services, Chief Human Resources Officer, Xcel Energy Inc. | June 2020 — Present | |||||||||||||||||
Senior Vice President, Human Resources & Employee Services, Chief Human Resources Officer, Xcel Energy Inc. | May 2018 — June 2020 | |||||||||||||||||||
Senior Vice President, Human Resources and Employee Services, Xcel Energy Inc. | May 2015 — May 2018 | |||||||||||||||||||
David T. Hudson | President and Director, SPS | January 2015 — Present | ||||||||||||||||||
Alice Jackson | President and Director, PSCo | May 2018 — Present | ||||||||||||||||||
Area Vice President, Strategic Revenue Initiatives, Xcel Energy Services Inc. | November 2016 — May 2018 | |||||||||||||||||||
Regional Vice President, Rates and Regulatory Affairs, PSCo | November 2013 — November 2016 | |||||||||||||||||||
Executive Vice President, | ||||||||||||||||||||
Senior Vice President, Chief Nuclear Officer, Xcel Energy Services | February 2013 — | |||||||||||||||||||
Senior Vice President, | March 2020 — Present | |||||||||||||||||||
Vice President, Policy and Federal Affairs, Xcel Energy Services Inc. | January 2015 — | |||||||||||||||||||
Executive Vice President, General Counsel, Xcel Energy Inc. | June 2020 — Present | |||||||||||||||||||
Vice President and Deputy General Counsel, Xcel Energy Services Inc. | October 2019 — June 2020 | |||||||||||||||||||
Managing Attorney, Xcel Energy Services Inc. | July 2018 — October 2019 | |||||||||||||||||||
Rotational Position, Xcel Energy Services Inc. | January 2018 — July 2018 | |||||||||||||||||||
Lead Assistant General Counsel, Xcel Energy Services Inc. | July 2015 — January 2018 | |||||||||||||||||||
Jeffrey S. Savage | 49 | Senior Vice President, Controller, Xcel Energy Inc. | January 2015 — Present |
Mark E. Stoering |
60 | President and Director, NSP-Wisconsin | January 2015 — Present | |||||||||||||||
39 | Executive Vice President, Chief Financial Officer, | March 2020 — Present |
Senior Vice President, Finance and Corporate Development, Xcel Energy Services Inc. | September 2018 — March 2020 | |||||||||||||||||||
Vice President, Treasurer, Xcel Energy Services Inc. | July 2015 — September 2018 |
ITEM 1A — RISK FACTORS |
ITEM 1B — UNRESOLVED STAFF COMMENTS |
ITEM 2 — PROPERTIES |
NSP-Minnesota Station, Location and Unit | Fuel | Installed | MW (a) | ||||||||||||||||||||
Steam: | |||||||||||||||||||||||
A.S. King-Bayport, MN, 1 Unit (f) | Coal | 1968 | 511 | ||||||||||||||||||||
Sherco-Becker, MN (e) | |||||||||||||||||||||||
Unit 1 | Coal | 1976 | 680 | ||||||||||||||||||||
Unit 2 | Coal | 1977 | 682 | ||||||||||||||||||||
Unit 3 | Coal | 1987 | 517 | (b) | |||||||||||||||||||
Monticello, MN, 1 Unit | Nuclear | 1971 | 617 | ||||||||||||||||||||
PI-Welch, MN | |||||||||||||||||||||||
Unit 1 | Nuclear | 1973 | 521 | ||||||||||||||||||||
Unit 2 | Nuclear | 1974 | 519 | ||||||||||||||||||||
Various locations, 4 Units | Wood/Refuse | Various | 36 | (c) | |||||||||||||||||||
Combustion Turbine: | |||||||||||||||||||||||
Angus Anson-Sioux Falls, SD, 3 Units | Natural Gas | 1994 - 2005 | 327 | ||||||||||||||||||||
Black Dog-Burnsville, MN, 3 Units | Natural Gas | 1987 - 2018 | 494 | ||||||||||||||||||||
Blue Lake-Shakopee, MN, 6 Units | Natural Gas | 1974 - 2005 | 447 | ||||||||||||||||||||
High Bridge-St. Paul, MN, 3 Units | Natural Gas | 2008 | 530 | ||||||||||||||||||||
Inver Hills-Inver Grove Heights, MN, 6 Units | Natural Gas | 1972 | 252 | ||||||||||||||||||||
Riverside-Minneapolis, MN, 3 Units | Natural Gas | 2009 | 454 | ||||||||||||||||||||
Various locations, 7 Units | Natural Gas | Various | 10 | ||||||||||||||||||||
Wind: | |||||||||||||||||||||||
Border-Rolette County, ND, 75 Units | Wind | 2015 | 148 | (d) | |||||||||||||||||||
Courtenay Wind-Stutsman County, ND, 100 Units | Wind | 2016 | 190 | (d) | |||||||||||||||||||
Foxtail-Dickey County, ND, 75 Units | Wind | 2019 | 150 | (d) | |||||||||||||||||||
Grand Meadow-Mower County, MN, 67 Units | Wind | 2008 | 99 | (d) | |||||||||||||||||||
Lake Benton-Pipestone County, MN, 44 Units | Wind | 2019 | 99 | (d) | |||||||||||||||||||
Nobles-Nobles County, MN, 134 Units | Wind | 2010 | 197 | (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 |
NSP-Minnesota Station, Location and Unit | Fuel | Installed | MW (a) | |||||
Steam: | ||||||||
A.S. King-Bayport, MN, 1 Unit | Coal | 1968 | 511 | |||||
Sherco-Becker, MN | ||||||||
Unit 1 | Coal | 1976 | 680 | |||||
Unit 2 | Coal | 1977 | 682 | |||||
Unit 3 | Coal | 1987 | 517 | (b) | ||||
Monticello, MN, 1 Unit | Nuclear | 1971 | 617 | |||||
PI-Welch, MN | ||||||||
Unit 1 | Nuclear | 1973 | 521 | |||||
Unit 2 | Nuclear | 1974 | 519 | |||||
Various locations, 4 Units | Wood/Refuse | Various | 36 | (c) | ||||
Combustion Turbine: | ||||||||
Angus Anson-Sioux Falls, SD, 3 Units | Natural Gas | 1994 - 2005 | 327 | |||||
Black Dog-Burnsville, MN, 3 Units | Natural Gas | 1987 - 2018 | 494 | |||||
Blue Lake-Shakopee, MN, 6 Units | Natural Gas | 1974 - 2005 | 453 | |||||
High Bridge-St. Paul, MN, 3 Units | Natural Gas | 2008 | 530 | |||||
Inver Hills-Inver Grove Heights, MN, 6 Units | Natural Gas | 1972 | 282 | |||||
Riverside-Minneapolis, MN, 3 Units | Natural Gas | 2009 | 454 | |||||
Various locations, 7 Units | Natural Gas | Various | 10 | |||||
Wind: | ||||||||
Border-Rolette County, ND, 75 Units | Wind | 2015 | 148 | (d) | ||||
Courtenay Wind-Stutsman County, ND, 100 Units | Wind | 2016 | 190 | (d) | ||||
Foxtail-Dickey County, ND, 75 Units | Wind | 2019 | 150 | (d) | ||||
Grand Meadow-Mower County, MN, 67 Units | Wind | 2008 | 99 | (d) | ||||
Lake Benton-Pipestone County, MN, 44 Units | Wind | 2019 | 99 | (d) | ||||
Nobles-Nobles County, MN, 134 Units | Wind | 2010 | 197 | (d) | ||||
Pleasant Valley-Mower County, MN, 100 Units | Wind | 2015 | 196 | (d) | ||||
Total | 7,712 |
NSP-Wisconsin Station, Location and Unit | Fuel | Installed | MW (a) | |||||
Steam: | ||||||||
Bay Front-Ashland, WI, 2 Units | Coal/Wood/Natural Gas | 1948 - 1956 | 41 | |||||
French Island-La Crosse, WI, 2 Units | Wood/Refuse | 1940 - 1948 | 16 | (b) | ||||
Combustion Turbine: | ||||||||
French Island-La Crosse, WI, 2 Units | Oil | 1974 | 122 | |||||
Wheaton-Eau Claire, WI, 5 Units | Natural Gas/Oil | 1973 | 234 | |||||
Hydro: | ||||||||
Various locations, 63 Units | Hydro | Various | 135 | |||||
Total | 548 |
PSCo Station, Location and Unit | Fuel | Installed | MW (a) | |||||
Steam: | ||||||||
Comanche-Pueblo, CO (b) | ||||||||
Unit 1 | Coal | 1973 | 325 | |||||
Unit 2 | Coal | 1975 | 335 | |||||
Unit 3 | Coal | 2010 | 500 | (c) | ||||
Craig-Craig, CO, 2 Units (d) | Coal | 1979 - 1980 | 82 | (e) | ||||
Hayden-Hayden, CO, 2 Units | Coal | 1965 - 1976 | 233 | (f) | ||||
Pawnee-Brush, CO, 1 Unit | Coal | 1981 | 505 | |||||
Cherokee-Denver, CO, 1 Unit | Natural Gas | 1968 | 310 | |||||
Combustion Turbine: | ||||||||
Blue Spruce-Aurora, CO, 2 Units | Natural Gas | 2003 | 264 | |||||
Cherokee-Denver, CO, 3 Units | Natural Gas | 2015 | 576 | |||||
Fort St. Vrain-Platteville, CO, 6 Units | Natural Gas | 1972 - 2009 | 968 | |||||
Rocky Mountain-Keenesburg, CO, 3 Units | Natural Gas | 2004 | 580 | |||||
Various locations, 6 Units | Natural Gas | Various | 171 | |||||
Hydro: | ||||||||
Cabin Creek-Georgetown, CO | ||||||||
Pumped Storage, 2 Units | Hydro | 1967 | 210 | |||||
Various locations, 8 Units | Hydro | Various | 25 | |||||
Wind: | ||||||||
Rush Creek, CO, 300 units | Wind | 2018 | 582 | (g) | ||||
Total | 5,666 |
NSP-Wisconsin Station, Location and Unit | Fuel | Installed | MW (a) | ||||||||||||||||||||
Steam: | |||||||||||||||||||||||
Bay Front-Ashland, WI, 2 Units | Wood/Natural Gas | 1948 - 1956 | 41 | ||||||||||||||||||||
French Island-La Crosse, WI, 2 Units | Wood/Refuse | 1940 - 1948 | 16 | (b) | |||||||||||||||||||
Combustion Turbine: | |||||||||||||||||||||||
French Island-La Crosse, WI, 2 Units | Oil | 1974 | 122 | ||||||||||||||||||||
Wheaton-Eau Claire, WI, 5 Units | Natural Gas/Oil | 1973 | 234 | ||||||||||||||||||||
Hydro: | |||||||||||||||||||||||
Various locations, 63 Units | Hydro | Various | 135 | ||||||||||||||||||||
Total | 548 |
SPS Station, Location and Unit | Fuel | Installed | MW (a) | |||||
Steam: | ||||||||
Cunningham-Hobbs, NM, 2 Units | Natural Gas | 1957 - 1965 | 189 | |||||
Harrington-Amarillo, TX, 3 Units | Coal | 1976 - 1980 | 1,018 | |||||
Jones-Lubbock, TX, 2 Units | Natural Gas | 1971 - 1974 | 486 | |||||
Maddox-Hobbs, NM, 1 Unit | Natural Gas | 1967 | 112 | |||||
Nichols-Amarillo, TX, 3 Units | Natural Gas | 1960 - 1968 | 457 | |||||
Plant X-Earth, TX, 4 Units | Natural Gas | 1952 - 1964 | 411 | |||||
Tolk-Muleshoe, TX, 2 Units | Coal | 1982 - 1985 | 1,067 | |||||
Combustion Turbine: | ||||||||
Cunningham-Hobbs, NM, 2 Units | Natural Gas | 1997 | 209 | |||||
Jones-Lubbock, TX, 2 Units | Natural Gas | 2011 - 2013 | 334 | |||||
Maddox-Hobbs, NM, 1 Unit | Natural Gas | 1963 - 1976 | 61 | |||||
Wind: | ||||||||
Hale-Plainview, TX, 239 Units | Wind | 2019 | 460 | (b) | ||||
Total | 4,804 |
PSCo Station, Location and Unit | Fuel | Installed | MW (a) | ||||||||||||||||||||
Steam: | |||||||||||||||||||||||
Comanche-Pueblo, CO (b) | |||||||||||||||||||||||
Unit 1 | Coal | 1973 | 325 | ||||||||||||||||||||
Unit 2 | Coal | 1975 | 335 | ||||||||||||||||||||
Unit 3 | Coal | 2010 | 500 | (c) | |||||||||||||||||||
Craig-Craig, CO, 2 Units (d) | Coal | 1979 - 1980 | 82 | (e) | |||||||||||||||||||
Hayden-Hayden, CO, 2 Units (h) | Coal | 1965 - 1976 | 233 | (f) | |||||||||||||||||||
Pawnee-Brush, CO, 1 Unit | Coal | 1981 | 505 | ||||||||||||||||||||
Cherokee-Denver, CO, 1 Unit | Natural Gas | 1968 | 310 | ||||||||||||||||||||
Combustion Turbine: | |||||||||||||||||||||||
Blue Spruce-Aurora, CO, 2 Units | Natural Gas | 2003 | 264 | ||||||||||||||||||||
Cherokee-Denver, CO, 3 Units | Natural Gas | 2015 | 576 | ||||||||||||||||||||
Fort St. Vrain-Platteville, CO, 6 Units | Natural Gas | 1972 - 2009 | 968 | ||||||||||||||||||||
Rocky Mountain-Keenesburg, CO, 3 Units | Natural Gas | 2004 | 580 | ||||||||||||||||||||
Various locations, 8 Units | Natural Gas | Various | 251 | ||||||||||||||||||||
Hydro: | |||||||||||||||||||||||
Cabin Creek-Georgetown, CO | |||||||||||||||||||||||
Pumped Storage, 2 Units | Hydro | 1967 | 210 | ||||||||||||||||||||
Various locations, 8 Units | Hydro | Various | 25 | ||||||||||||||||||||
Wind: | |||||||||||||||||||||||
Rush Creek, CO, 300 units | Wind | 2018 | 582 | (g) | |||||||||||||||||||
Cheyenne Ridge, CO, 229 units | Wind | 2020 | 477 | (g) | |||||||||||||||||||
Total | 6,223 |
(a) Summer 2020 net dependable capacity. (b) Harrington is expected to be converted to natural gas by the end of 2024. (c) 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) (d) Tolk Unit 1 and 2 are expected to be retired in 2032. |
Conductor Miles | NSP-Minnesota | NSP-Wisconsin | PSCo | SPS | Conductor Miles | NSP-Minnesota | NSP-Wisconsin | PSCo | SPS | |||||||||||||||||||||||||||||
Transmission | Transmission | |||||||||||||||||||||||||||||||||||||
500 KV | 2,917 | — | — | — | 500 KV | 2,918 | — | — | — | |||||||||||||||||||||||||||||
345 KV | 13,133 | 3,337 | 5,036 | 9,566 | 345 KV | 13,151 | 3,337 | 5,389 | 11,019 | |||||||||||||||||||||||||||||
230 KV | 2,203 | — | 12,108 | 9,784 | 230 KV | 2,301 | — | 12,131 | 9,795 | |||||||||||||||||||||||||||||
161 KV | 673 | 1,821 | — | — | 161 KV | 674 | 1,823 | — | — | |||||||||||||||||||||||||||||
138 KV | — | — | 92 | — | 138 KV | — | — | 92 | — | |||||||||||||||||||||||||||||
115 KV | 8,045 | 1,815 | 5,055 | 14,662 | 115 KV | 8,060 | 1,822 | 5,092 | 14,830 | |||||||||||||||||||||||||||||
Less than 115 KV | 86,743 | 32,816 | 79,740 | 26,216 | Less than 115 KV | 6,556 | 5,306 | 1,682 | 4,375 | |||||||||||||||||||||||||||||
Total Transmission | Total Transmission | 33,660 | 12,288 | 24,386 | 40,019 | |||||||||||||||||||||||||||||||||
Distribution | Distribution | |||||||||||||||||||||||||||||||||||||
Less than 115 KV | Less than 115 KV | 80,508 | 27,611 | 78,483 | 21,984 | |||||||||||||||||||||||||||||||||
Total | Total | 114,168 | 39,899 | 102,869 | 62,003 |
NSP-Minnesota | NSP-Wisconsin | PSCo | SPS | |||||||||||||||||||||||
Quantity | 352 | 204 | 236 | 457 |
NSP-Minnesota | NSP-Wisconsin | PSCo | SPS | |||||||||
Quantity | 346 | 204 | 233 | 452 |
Miles | NSP-Minnesota | NSP-Wisconsin | PSCo | SPS | WGI | |||||||||||||||||||||||||||
Transmission | 80 | 3 | 2,058 | 20 | 11 | |||||||||||||||||||||||||||
Distribution | 10,629 | 2,492 | 22,815 | — | — |
Miles | NSP-Minnesota | NSP-Wisconsin | PSCo | SPS | WGI | ||||||||||
Transmission | 86 | 3 | 2,057 | 20 | 11 | ||||||||||
Distribution | 10,518 | 2,473 | 22,633 | — | — |
ITEM 3 — LEGAL PROCEEDINGS |
ITEM 4 — MINE SAFETY DISCLOSURES |
ITEM 5 — MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES. |
* $100 invested on Dec. 31, 2015 in stock or index — including reinvestment of dividends. Fiscal years ended Dec. 31. |
ITEM 6 — SELECTED FINANCIAL DATA |
(Millions of Dollars, Millions of Shares, Except Per Share Data) | 2020 | 2019 | 2018 | 2017 | 2016 | |||||||||||||||||||||||||||
Operating revenues | $ | 11,526 | $ | 11,529 | $ | 11,537 | $ | 11,404 | $ | 11,107 | ||||||||||||||||||||||
Operating expenses (a) | 9,410 | 9,425 | 9,572 | 9,181 | 8,867 | |||||||||||||||||||||||||||
Net income | 1,473 | 1,372 | 1,261 | 1,148 | 1,123 | |||||||||||||||||||||||||||
Earnings available to common shareholders | 1,473 | 1,372 | 1,261 | 1,148 | 1,123 | |||||||||||||||||||||||||||
Diluted earnings per common share | 2.79 | 2.64 | 2.47 | 2.25 | 2.21 | |||||||||||||||||||||||||||
Financial information | ||||||||||||||||||||||||||||||||
Dividends declared per common share | 1.72 | 1.62 | 1.52 | 1.44 | 1.36 | |||||||||||||||||||||||||||
Total assets | 53,957 | 50,448 | 45,987 | 43,030 | 41,155 | |||||||||||||||||||||||||||
Long-term debt (b) | 19,645 | 17,407 | 15,803 | 14,520 | 14,195 |
(Millions of Dollars, Millions of Shares, Except Per Share Data) | 2019 | 2018 | 2017 | 2016 | 2015 | |||||||||||||||
Operating revenues | $ | 11,529 | $ | 11,537 | $ | 11,404 | $ | 11,107 | $ | 11,024 | ||||||||||
Operating expenses (a) | 9,425 | 9,572 | 9,181 | 8,867 | 9,024 | |||||||||||||||
Net income | 1,372 | 1,261 | 1,148 | 1,123 | 984 | |||||||||||||||
Earnings available to common shareholders | 1,372 | 1,261 | 1,148 | 1,123 | 984 | |||||||||||||||
Diluted earnings per common share | 2.64 | 2.47 | 2.25 | 2.21 | 1.94 | |||||||||||||||
Financial information | ||||||||||||||||||||
Dividends declared per common share | 1.62 | 1.52 | 1.44 | 1.36 | 1.28 | |||||||||||||||
Total assets (b) (c) | 50,448 | 45,987 | 43,030 | 41,155 | 38,821 | |||||||||||||||
Long-term debt (c) (d) | 17,407 | 15,803 | 14,520 | 14,195 | 12,399 |
ITEM 7 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
Results of Operations |
2020 | 2019 | |||||||||||||
Diluted Earnings (Loss) Per Share | GAAP and Ongoing Diluted EPS | GAAP and Ongoing Diluted EPS | ||||||||||||
NSP-Minnesota | $ | 1.12 | $ | 1.04 | ||||||||||
PSCo | 1.11 | 1.11 | ||||||||||||
SPS | 0.56 | 0.51 | ||||||||||||
NSP-Wisconsin | 0.20 | 0.15 | ||||||||||||
Equity earnings of unconsolidated subsidiaries | 0.05 | 0.05 | ||||||||||||
Regulated utility (a) | 3.04 | 2.86 | ||||||||||||
Xcel Energy Inc. and Other | (0.25) | (0.22) | ||||||||||||
Total (a) | $ | 2.79 | $ | 2.64 |
2019 | 2018 | |||||||
Diluted Earnings (Loss) Per Share | GAAP and Ongoing Diluted EPS | GAAP and Ongoing Diluted EPS | ||||||
PSCo | $ | 1.11 | $ | 1.08 | ||||
NSP-Minnesota | 1.04 | 0.96 | ||||||
SPS | 0.51 | 0.42 | ||||||
NSP-Wisconsin | 0.15 | 0.19 | ||||||
Equity earnings of unconsolidated subsidiaries (a) | 0.05 | 0.04 | ||||||
Regulated utility (b) | 2.86 | 2.69 | ||||||
Xcel Energy Inc. and other | (0.22 | ) | (0.22 | ) | ||||
Total (b) | $ | 2.64 | $ | 2.47 |
2019 vs. 2018 | ||||
Diluted Earnings (Loss) Per Share | Dec. 31 | |||
GAAP and ongoing diluted EPS - 2018 | $ | 2.47 | ||
Components of change — 2019 vs. 2018 | ||||
Higher electric margins | 0.29 | |||
Lower ETR (a) | 0.15 | |||
Higher natural gas margins | 0.08 | |||
Lower O&M | 0.02 | |||
Higher depreciation and amortization | (0.18 | ) | ||
Higher interest | (0.11 | ) | ||
Lower AFUDC | (0.08 | ) | ||
GAAP and ongoing diluted EPS — 2019 | $ | 2.64 |
2020 vs. 2019 | ||||||||
Diluted Earnings (Loss) Per Share | Dec. 31 | |||||||
GAAP and ongoing diluted EPS - 2019 | $ | 2.64 | ||||||
Components of change — 2020 vs. 2019 | ||||||||
Higher electric margins (a) | 0.32 | |||||||
Lower ETR (b) | 0.22 | |||||||
Higher AFUDC | 0.08 | |||||||
Changes in O&M | 0.02 | |||||||
Higher depreciation and | (0.26) | |||||||
Higher interest | (0.10) | |||||||
Higher taxes (other than income taxes) | (0.06) | |||||||
Changes in | (0.01) | |||||||
Other (net) | (0.06) | |||||||
GAAP and ongoing diluted EPS — 2020 | $ | 2.79 |
Diluted Earnings (Loss) Per Share | Twelve Months Ended Dec. 31 | |||||||
Electric margin (excluding reductions in sales and demand) | $ | 0.41 | ||||||
Reductions in sales and demand | (0.09) | |||||||
Higher electric margins | $ | 0.32 |
2019 | 2018 | 2020 | 2019 | |||||||||||||||||
ROE | GAAP and Ongoing ROE | GAAP and Ongoing ROE | ROE | GAAP and Ongoing ROE | GAAP and Ongoing ROE | |||||||||||||||
NSP-Minnesota | NSP-Minnesota | 9.20 | % | 9.31 | % | |||||||||||||||
PSCo | 8.69 | % | 9.10 | % | PSCo | 8.06 | 8.69 | |||||||||||||
NSP-Minnesota | 9.31 | 8.91 | ||||||||||||||||||
SPS | 9.71 | 9.14 | SPS | 9.54 | 9.71 | |||||||||||||||
NSP-Wisconsin | 8.27 | 10.77 | NSP-Wisconsin | 10.52 | 8.27 | |||||||||||||||
Operating Companies | 9.06 | 9.14 | Operating Companies | 8.87 | 9.06 | |||||||||||||||
Xcel Energy | 10.78 | 10.65 | Xcel Energy | 10.59 | 10.78 |
2019 vs. Normal | 2018 vs. Normal | 2019 vs. 2018 | 2020 vs. Normal | 2019 vs. Normal | 2020 vs. 2019 | ||||||||||||||||||||
HDD | 10.4 | % | 2.2 | % | 6.8 | % | HDD | (3.1) | % | 10.4 | % | (12.0) | % | ||||||||||||
CDD | 5.4 | 26.7 | (15.5 | ) | CDD | 22.2 | 5.4 | 24.8 | |||||||||||||||||
THI | (8.8 | ) | 37.3 | (33.2 | ) | THI | 6.3 | (8.8) | 18.2 |
2019 vs. Normal | 2018 vs. Normal | 2019 vs. 2018 | 2020 vs. Normal | 2019 vs. Normal | 2020 vs. 2019 | |||||||||||||||||||||||
Retail electric | $ | 0.040 | $ | 0.114 | $ | (0.074 | ) | Retail electric | $ | 0.090 | $ | 0.040 | $ | 0.050 | ||||||||||||||
Decoupling and sales true-up | Decoupling and sales true-up | (0.041) | — | (0.041) | ||||||||||||||||||||||||
Total (excluding decoupling) | Total (excluding decoupling) | $ | 0.049 | $ | 0.040 | $ | 0.009 | |||||||||||||||||||||
Firm natural gas | 0.027 | 0.007 | 0.020 | Firm natural gas | (0.011) | 0.027 | (0.038) | |||||||||||||||||||||
Total (excluding decoupling) | $ | 0.067 | $ | 0.121 | $ | (0.054 | ) | |||||||||||||||||||||
Decoupling — Minnesota electric | — | (0.051 | ) | 0.051 | ||||||||||||||||||||||||
Total (adjusted for recovery from decoupling) | $ | 0.067 | $ | 0.070 | $ | (0.003 | ) | Total (adjusted for recovery from decoupling) | $ | 0.038 | $ | 0.067 | $ | (0.029) |
2020 vs. 2019 | ||||||||||||||||||||||||||||||||
PSCo | NSP-Minnesota | SPS | NSP-Wisconsin | Xcel Energy | ||||||||||||||||||||||||||||
Actual (a) | ||||||||||||||||||||||||||||||||
Electric residential | 5.8 | % | 5.0 | % | 3.6 | % | 2.4 | % | 4.9 | % | ||||||||||||||||||||||
Electric C&I | (4.1) | (7.0) | (3.3) | (4.6) | (5.0) | |||||||||||||||||||||||||||
Total retail electric sales | (1.1) | (3.4) | (2.2) | (2.6) | (2.3) | |||||||||||||||||||||||||||
Firm natural gas sales | (6.8) | (8.3) | n/a | (6.4) | (7.2) |
2020 vs. 2019 | ||||||||||||||||||||||||||||||||
PSCo | NSP-Minnesota | SPS | NSP-Wisconsin | Xcel Energy | ||||||||||||||||||||||||||||
Weather-normalized (a) | ||||||||||||||||||||||||||||||||
Electric residential | 3.8 | % | 3.7 | % | 1.6 | % | 2.6 | % | 3.3 | % | ||||||||||||||||||||||
Electric C&I | (4.5) | (7.0) | (3.4) | (4.8) | (5.2) | |||||||||||||||||||||||||||
Total retail electric sales | (1.9) | (3.8) | (2.6) | (2.7) | (2.8) | |||||||||||||||||||||||||||
Firm natural gas sales | 0.5 | 1.9 | n/a | 5.1 | 1.3 |
2019 vs. 2018 | |||||||||||||||
PSCo | NSP-Minnesota | SPS | NSP-Wisconsin | Xcel Energy | |||||||||||
Actual | |||||||||||||||
Electric residential | 0.1 | % | (3.5 | )% | 0.3 | % | (1.8 | )% | (1.5 | )% | |||||
Electric C&I | (0.6 | ) | (4.0 | ) | 3.5 | (3.2 | ) | (1.1 | ) | ||||||
Total retail electric sales | (0.3 | ) | (3.9 | ) | 2.8 | (2.8 | ) | (1.2 | ) | ||||||
Firm natural gas sales | 12.9 | 3.6 | N/A | (2.0 | ) | 8.8 |
2020 vs. 2019 (Leap Year Adjusted) | ||||||||||||||||||||||||||||||||
PSCo | NSP-Minnesota | SPS | NSP-Wisconsin | Xcel Energy | ||||||||||||||||||||||||||||
Weather-normalized (a) | ||||||||||||||||||||||||||||||||
Electric residential | 3.6 | % | 3.4 | % | 1.3 | % | 2.3 | % | 3.1 | % | ||||||||||||||||||||||
Electric C&I | (4.8) | (7.3) | (3.7) | (5.0) | (5.4) | |||||||||||||||||||||||||||
Total retail electric sales | (2.2) | (4.1) | (2.9) | (2.9) | (3.1) | |||||||||||||||||||||||||||
Firm natural gas sales | 0.1 | 1.4 | n/a | 4.6 | 0.7 |
2019 vs. 2018 | |||||||||||||||
PSCo | NSP-Minnesota | SPS | NSP-Wisconsin | Xcel Energy | |||||||||||
Weather-normalized | |||||||||||||||
Electric residential | (0.1 | )% | 0.1 | % | 1.9 | % | 1.1 | % | 0.4 | % | |||||
Electric C&I | (0.6 | ) | (3.0 | ) | 3.8 | (2.6 | ) | (0.5 | ) | ||||||
Total retail electric sales | (0.3 | ) | (2.1 | ) | 3.4 | (1.6 | ) | (0.3 | ) | ||||||
Firm natural gas sales | 4.1 | 1.1 | N/A | (2.5 | ) | 2.7 |
(Millions of Dollars) | 2019 vs. 2018 | |||
Non-fuel riders (a) | $ | 107 | ||
Regulatory rate outcomes (Minnesota, New Mexico, North and South Dakota) | 95 | |||
Implementation of lease accounting standard (offset in interest expense and amortization) | 22 | |||
Purchased capacity costs | 22 | |||
Demand revenue | 20 | |||
Wholesale transmission revenue (net) | 11 | |||
Timing of tax reform regulatory decisions (offset in income tax and amortization) | (37 | ) | ||
Estimated impact of weather (net of Minnesota decoupling) | (25 | ) | ||
Firm wholesale generation | (20 | ) | ||
Sales declines (excluding weather impact) | (18 | ) | ||
Other (net) | 23 | |||
Total increase in electric margin | $ | 200 |
Unit 1 | Coal | 1976 | 680 | ||||||||||||||||||||
Unit 2 | Coal | 1977 | 682 | ||||||||||||||||||||
Unit 3 | Coal | 1987 | 517 | (b) | |||||||||||||||||||
Monticello, MN, 1 Unit | Nuclear | 1971 | 617 | ||||||||||||||||||||
PI-Welch, MN | |||||||||||||||||||||||
Unit 1 | Nuclear | 1973 | 521 | ||||||||||||||||||||
Unit 2 | Nuclear | 1974 | 519 | ||||||||||||||||||||
Various locations, 4 Units | Wood/Refuse | Various | 36 | (c) | |||||||||||||||||||
Combustion Turbine: | |||||||||||||||||||||||
Angus Anson-Sioux Falls, SD, 3 Units | Natural Gas | 1994 - 2005 | 327 | ||||||||||||||||||||
Black Dog-Burnsville, MN, 3 Units | Natural Gas | 1987 - 2018 | 494 | ||||||||||||||||||||
Blue Lake-Shakopee, MN, 6 Units | Natural Gas | 1974 - 2005 | 447 | ||||||||||||||||||||
High Bridge-St. Paul, MN, 3 Units | Natural Gas | 2008 | 530 | ||||||||||||||||||||
Inver Hills-Inver Grove Heights, MN, 6 Units | Natural Gas | 1972 | 252 | ||||||||||||||||||||
Riverside-Minneapolis, MN, 3 Units | Natural Gas | 2009 | 454 | ||||||||||||||||||||
Various locations, 7 Units | Natural Gas | Various | 10 | ||||||||||||||||||||
Wind: | |||||||||||||||||||||||
Border-Rolette County, ND, 75 Units | Wind | 2015 | 148 | (d) | |||||||||||||||||||
Courtenay Wind-Stutsman County, ND, 100 Units | Wind | 2016 | 190 | (d) | |||||||||||||||||||
Foxtail-Dickey County, ND, 75 Units | Wind | 2019 | 150 | (d) | |||||||||||||||||||
Grand Meadow-Mower County, MN, 67 Units | Wind | 2008 | 99 | (d) | |||||||||||||||||||
Lake Benton-Pipestone County, MN, 44 Units | Wind | 2019 | 99 | (d) | |||||||||||||||||||
Nobles-Nobles County, MN, 134 Units | Wind | 2010 | 197 | (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 | ||||||||||||||||||||||
NSP-Wisconsin Station, Location and Unit | Fuel | Installed | MW (a) | ||||||||||||||||||||
Steam: | |||||||||||||||||||||||
Bay Front-Ashland, WI, 2 Units | Wood/Natural Gas | 1948 - 1956 | 41 | ||||||||||||||||||||
French Island-La Crosse, WI, 2 Units | Wood/Refuse | 1940 - 1948 | 16 | (b) | |||||||||||||||||||
Combustion Turbine: | |||||||||||||||||||||||
French Island-La Crosse, WI, 2 Units | Oil | 1974 | 122 | ||||||||||||||||||||
Wheaton-Eau Claire, WI, 5 Units | Natural Gas/Oil | 1973 | 234 | ||||||||||||||||||||
Hydro: | |||||||||||||||||||||||
Various locations, 63 Units | Hydro | Various | 135 | ||||||||||||||||||||
Total | 548 |
PSCo Station, Location and Unit | Fuel | Installed | MW (a) | ||||||||||||||||||||
Steam: | |||||||||||||||||||||||
Comanche-Pueblo, CO (b) | |||||||||||||||||||||||
Unit 1 | Coal | 1973 | 325 | ||||||||||||||||||||
Unit 2 | Coal | 1975 | 335 | ||||||||||||||||||||
Unit 3 | Coal | 2010 | 500 | (c) | |||||||||||||||||||
Craig-Craig, CO, 2 Units (d) | Coal | 1979 - 1980 | 82 | (e) | |||||||||||||||||||
Hayden-Hayden, CO, 2 Units (h) | Coal | 1965 - 1976 | 233 | (f) | |||||||||||||||||||
Pawnee-Brush, CO, 1 Unit | Coal | 1981 | 505 | ||||||||||||||||||||
Cherokee-Denver, CO, 1 Unit | Natural Gas | 1968 | 310 | ||||||||||||||||||||
Combustion Turbine: | |||||||||||||||||||||||
Blue Spruce-Aurora, CO, 2 Units | Natural Gas | 2003 | 264 | ||||||||||||||||||||
Cherokee-Denver, CO, 3 Units | Natural Gas | 2015 | 576 | ||||||||||||||||||||
Fort St. Vrain-Platteville, CO, 6 Units | Natural Gas | 1972 - 2009 | 968 | ||||||||||||||||||||
Rocky Mountain-Keenesburg, CO, 3 Units | Natural Gas | 2004 | 580 | ||||||||||||||||||||
Various locations, 8 Units | Natural Gas | Various | 251 | ||||||||||||||||||||
Hydro: | |||||||||||||||||||||||
Cabin Creek-Georgetown, CO | |||||||||||||||||||||||
Pumped Storage, 2 Units | Hydro | 1967 | 210 | ||||||||||||||||||||
Various locations, 8 Units | Hydro | Various | 25 | ||||||||||||||||||||
Wind: | |||||||||||||||||||||||
Rush Creek, CO, 300 units | Wind | 2018 | 582 | (g) | |||||||||||||||||||
Cheyenne Ridge, CO, 229 units | Wind | 2020 | 477 | (g) | |||||||||||||||||||
Total | 6,223 |
SPS Station, Location and Unit | Fuel | Installed | MW (a) | ||||||||||||||||||||
Steam: | |||||||||||||||||||||||
Cunningham-Hobbs, NM, 2 Units | Natural Gas | 1957 - 1965 | 225 | ||||||||||||||||||||
Harrington-Amarillo, TX, 3 Units (b) | Coal | 1976 - 1980 | 1,018 | ||||||||||||||||||||
Jones-Lubbock, TX, 2 Units | Natural Gas | 1971 - 1974 | 486 | ||||||||||||||||||||
Maddox-Hobbs, NM, 1 Unit | Natural Gas | 1967 | 112 | ||||||||||||||||||||
Nichols-Amarillo, TX, 3 Units | Natural Gas | 1960 - 1968 | 457 | ||||||||||||||||||||
Plant X-Earth, TX, 4 Units | Natural Gas | 1952 - 1964 | 298 | ||||||||||||||||||||
Tolk-Muleshoe, TX, 2 Units (d) | Coal | 1982 - 1985 | 1,067 | ||||||||||||||||||||
Combustion Turbine: | |||||||||||||||||||||||
Cunningham-Hobbs, NM, 2 Units | Natural Gas | 1997 | 207 | ||||||||||||||||||||
Jones-Lubbock, TX, 2 Units | Natural Gas | 2011 - 2013 | 334 | ||||||||||||||||||||
Maddox-Hobbs, NM, 1 Unit | Natural Gas | 1963 - 1976 | 61 | ||||||||||||||||||||
Wind: | |||||||||||||||||||||||
Hale-Plainview, TX, 239 Units | Wind | 2019 | 460 | (c) | |||||||||||||||||||
Sagamore-Dora, NM, 240 Units | Wind | 2020 | 507 | (c) | |||||||||||||||||||
Total | 5,232 |
Conductor Miles | NSP-Minnesota | NSP-Wisconsin | PSCo | SPS | ||||||||||||||||||||||
Transmission | ||||||||||||||||||||||||||
500 KV | 2,918 | — | — | — | ||||||||||||||||||||||
345 KV | 13,151 | 3,337 | 5,389 | 11,019 | ||||||||||||||||||||||
230 KV | 2,301 | — | 12,131 | 9,795 | ||||||||||||||||||||||
161 KV | 674 | 1,823 | — | — | ||||||||||||||||||||||
138 KV | — | — | 92 | — | ||||||||||||||||||||||
115 KV | 8,060 | 1,822 | 5,092 | 14,830 | ||||||||||||||||||||||
Less than 115 KV | 6,556 | 5,306 | 1,682 | 4,375 | ||||||||||||||||||||||
Total Transmission | 33,660 | 12,288 | 24,386 | 40,019 | ||||||||||||||||||||||
Distribution | ||||||||||||||||||||||||||
Less than 115 KV | 80,508 | 27,611 | 78,483 | 21,984 | ||||||||||||||||||||||
Total | 114,168 | 39,899 | 102,869 | 62,003 |
NSP-Minnesota | NSP-Wisconsin | PSCo | SPS | |||||||||||||||||||||||
Quantity | 352 | 204 | 236 | 457 |
Miles | NSP-Minnesota | NSP-Wisconsin | PSCo | SPS | WGI | |||||||||||||||||||||||||||
Transmission | 80 | 3 | 2,058 | 20 | 11 | |||||||||||||||||||||||||||
Distribution | 10,629 | 2,492 | 22,815 | — | — |
ITEM 3 — LEGAL PROCEEDINGS |
ITEM 4 — MINE SAFETY DISCLOSURES |
ITEM 5 — MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES. |
(Millions of Dollars) | 2019 vs. 2018 | |||
Infrastructure and integrity riders | $ | 19 | ||
Estimated impact of weather | 14 | |||
Transport sales | 7 | |||
Retail sales growth | 7 | |||
Other (net) | 7 | |||
Total increase in natural gas margin | $ | 54 |
ITEM 6 — SELECTED FINANCIAL DATA |
(Millions of Dollars, Millions of Shares, Except Per Share Data) | 2020 | 2019 | 2018 | 2017 | 2016 | |||||||||||||||||||||||||||
Operating revenues | $ | 11,526 | $ | 11,529 | $ | 11,537 | $ | 11,404 | $ | 11,107 | ||||||||||||||||||||||
Operating expenses (a) | 9,410 | 9,425 | 9,572 | 9,181 | 8,867 | |||||||||||||||||||||||||||
Net income | 1,473 | 1,372 | 1,261 | 1,148 | 1,123 | |||||||||||||||||||||||||||
Earnings available to common shareholders | 1,473 | 1,372 | 1,261 | 1,148 | 1,123 | |||||||||||||||||||||||||||
Diluted earnings per common share | 2.79 | 2.64 | 2.47 | 2.25 | 2.21 | |||||||||||||||||||||||||||
Financial information | ||||||||||||||||||||||||||||||||
Dividends declared per common share | 1.72 | 1.62 | 1.52 | 1.44 | 1.36 | |||||||||||||||||||||||||||
Total assets | 53,957 | 50,448 | 45,987 | 43,030 | 41,155 | |||||||||||||||||||||||||||
Long-term debt (b) | 19,645 | 17,407 | 15,803 | 14,520 | 14,195 |
ITEM 7 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
Results of Operations |
2020 | 2019 | |||||||||||||
Diluted Earnings (Loss) Per Share | GAAP and Ongoing Diluted EPS | GAAP and Ongoing Diluted EPS | ||||||||||||
NSP-Minnesota | $ | 1.12 | $ | 1.04 | ||||||||||
PSCo | 1.11 | 1.11 | ||||||||||||
SPS | 0.56 | 0.51 | ||||||||||||
NSP-Wisconsin | 0.20 | 0.15 | ||||||||||||
Equity earnings of unconsolidated subsidiaries | 0.05 | 0.05 | ||||||||||||
Regulated utility (a) | 3.04 | 2.86 | ||||||||||||
Xcel Energy Inc. and Other | (0.25) | (0.22) | ||||||||||||
Total (a) | $ | 2.79 | $ | 2.64 |
2020 | 2019 | |||||||||||||
ROE | GAAP and Ongoing ROE | GAAP and Ongoing ROE | ||||||||||||
NSP-Minnesota | 9.20 | % | 9.31 | % | ||||||||||
PSCo | 8.06 | 8.69 | ||||||||||||
SPS | 9.54 | 9.71 | ||||||||||||
NSP-Wisconsin | 10.52 | 8.27 | ||||||||||||
Operating Companies | 8.87 | 9.06 | ||||||||||||
Xcel Energy | 10.59 | 10.78 |
2020 vs. Normal | 2019 vs. Normal | 2020 vs. 2019 | |||||||||||||||
HDD | (3.1) | % | 10.4 | % | (12.0) | % | |||||||||||
CDD | 22.2 | 5.4 | 24.8 | ||||||||||||||
THI | 6.3 | (8.8) | 18.2 |
2020 vs. Normal | 2019 vs. Normal | 2020 vs. 2019 | |||||||||||||||
Retail electric | $ | 0.090 | $ | 0.040 | $ | 0.050 | |||||||||||
Decoupling and sales true-up | (0.041) | — | (0.041) | ||||||||||||||
Total (excluding decoupling) | $ | 0.049 | $ | 0.040 | $ | 0.009 | |||||||||||
Firm natural gas | (0.011) | 0.027 | (0.038) | ||||||||||||||
Total (adjusted for recovery from decoupling) | $ | 0.038 | $ | 0.067 | $ | (0.029) |
2020 vs. 2019 | ||||||||||||||||||||||||||||||||
PSCo | NSP-Minnesota | SPS | NSP-Wisconsin | Xcel Energy | ||||||||||||||||||||||||||||
Actual (a) | ||||||||||||||||||||||||||||||||
Electric residential | 5.8 | % | 5.0 | % | 3.6 | % | 2.4 | % | 4.9 | % | ||||||||||||||||||||||
Electric C&I | (4.1) | (7.0) | (3.3) | (4.6) | (5.0) | |||||||||||||||||||||||||||
Total retail electric sales | (1.1) | (3.4) | (2.2) | (2.6) | (2.3) | |||||||||||||||||||||||||||
Firm natural gas sales | (6.8) | (8.3) | n/a | (6.4) | (7.2) |
2020 vs. 2019 | ||||||||||||||||||||||||||||||||
PSCo | NSP-Minnesota | SPS | NSP-Wisconsin | Xcel Energy | ||||||||||||||||||||||||||||
Weather-normalized (a) | ||||||||||||||||||||||||||||||||
Electric residential | 3.8 | % | 3.7 | % | 1.6 | % | 2.6 | % | 3.3 | % | ||||||||||||||||||||||
Electric C&I | (4.5) | (7.0) | (3.4) | (4.8) | (5.2) | |||||||||||||||||||||||||||
Total retail electric sales | (1.9) | (3.8) | (2.6) | (2.7) | (2.8) | |||||||||||||||||||||||||||
Firm natural gas sales | 0.5 | 1.9 | n/a | 5.1 | 1.3 |
2020 vs. 2019 (Leap Year Adjusted) | ||||||||||||||||||||||||||||||||
PSCo | NSP-Minnesota | SPS | NSP-Wisconsin | Xcel Energy | ||||||||||||||||||||||||||||
Weather-normalized (a) | ||||||||||||||||||||||||||||||||
Electric residential | 3.6 | % | 3.4 | % | 1.3 | % | 2.3 | % | 3.1 | % | ||||||||||||||||||||||
Electric C&I | (4.8) | (7.3) | (3.7) | (5.0) | (5.4) | |||||||||||||||||||||||||||
Total retail electric sales | (2.2) | (4.1) | (2.9) | (2.9) | (3.1) | |||||||||||||||||||||||||||
Firm natural gas sales | 0.1 | 1.4 | n/a | 4.6 | 0.7 |
Steam: | |||||||||||||||||||||||
A.S. King-Bayport, MN, 1 Unit (f) | Coal | 1968 | 511 | ||||||||||||||||||||
Sherco-Becker, MN (e) | |||||||||||||||||||||||
Unit 1 | Coal | 1976 | 680 | ||||||||||||||||||||
Unit 2 | Coal | 1977 | 682 | ||||||||||||||||||||
Unit 3 | Coal | 1987 | 517 | (b) | |||||||||||||||||||
Monticello, MN, 1 Unit | Nuclear | 1971 | 617 | ||||||||||||||||||||
PI-Welch, MN | |||||||||||||||||||||||
Unit 1 | Nuclear | 1973 | 521 | ||||||||||||||||||||
Unit 2 | Nuclear | 1974 | 519 | ||||||||||||||||||||
Various locations, 4 Units | Wood/Refuse | Various | 36 | (c) | |||||||||||||||||||
Combustion Turbine: | |||||||||||||||||||||||
Angus Anson-Sioux Falls, SD, 3 Units | Natural Gas | 1994 - 2005 | 327 | ||||||||||||||||||||
Black Dog-Burnsville, MN, 3 Units | Natural Gas | 1987 - 2018 | 494 | ||||||||||||||||||||
Blue Lake-Shakopee, MN, 6 Units | Natural Gas | 1974 - 2005 | 447 | ||||||||||||||||||||
High Bridge-St. Paul, MN, 3 Units | Natural Gas | 2008 | 530 | ||||||||||||||||||||
Inver Hills-Inver Grove Heights, MN, 6 Units | Natural Gas | 1972 | 252 | ||||||||||||||||||||
Riverside-Minneapolis, MN, 3 Units | Natural Gas | 2009 | 454 | ||||||||||||||||||||
Various locations, 7 Units | Natural Gas | Various | 10 | ||||||||||||||||||||
Wind: | |||||||||||||||||||||||
Border-Rolette County, ND, 75 Units | Wind | 2015 | 148 | (d) | |||||||||||||||||||
Courtenay Wind-Stutsman County, ND, 100 Units | Wind | 2016 | 190 | (d) | |||||||||||||||||||
Foxtail-Dickey County, ND, 75 Units | Wind | 2019 | 150 | (d) | |||||||||||||||||||
Grand Meadow-Mower County, MN, 67 Units | Wind | 2008 | 99 | (d) | |||||||||||||||||||
Lake Benton-Pipestone County, MN, 44 Units | Wind | 2019 | 99 | (d) | |||||||||||||||||||
Nobles-Nobles County, MN, 134 Units | Wind | 2010 | 197 | (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 | ||||||||||||||||||||||
NSP-Wisconsin | Fuel | Installed | MW (a)
(a)Summer 2020 net dependable capacity. (b)Refuse-derived fuel is made from municipal solid waste.
(a) Summer 2020 net dependable capacity. (b)In 2018, the CPUC approved early retirement of PSCo’s Comanche Units 1 and 2 in 2022 and 2025, respectively. (c) Based on PSCo’s ownership of 67%. (d) Craig Unit 1 and 2 are expected to be retired early in 2025 and 2028, respectively. (e) Based on PSCo’s ownership of 10%. (f) Based on PSCo’s ownership of 76% of Unit 1 and 37% of Unit 2. (g) Values disclosed are the generation levels at the point-of-interconnection. Capacity is attainable only when wind conditions are sufficiently available (on-demand net dependable capacity is zero). (h)Hayden Unit 1 and 2 are expected to be retired in 2028 and 2027, respectively.
(a) Summer 2020 net dependable capacity. (b) Harrington is expected to be converted to natural gas by the end of 2024. (c) 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) (d) Tolk Unit 1 and 2 are expected to be retired in 2032. Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2020:
Electric utility transmission and distribution substations at Dec. 31, 2020:
Natural gas utility mains at Dec. 31, 2020:
23
Xcel Energy 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 Xcel Energy’s financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred. See Note 12 to the consolidated financial statements, Item 1 and Item 7 for further information.
None. PART II
Stock Data Xcel Energy Inc.’s common stock is listed on the Nasdaq Global Select Market (Nasdaq). The trading symbol is XEL. The number of common stockholders of record as of Feb. 12, 2021 was approximately 52,689. The following compares our cumulative TSR on common stock with the cumulative TSR of the EEI Investor-Owned Electrics Index and the S&P 500 Composite Stock Price Index over the last five years. The EEI Investor-Owned Electrics Index (market capitalization-weighted) included 39 companies at year-end and is a broad measure of industry performance. Comparison of Five Year Cumulative Total Return* * $100 invested on Dec. 31, 2015 in stock or index — including reinvestment of dividends. Fiscal years ended Dec. 31. Purchases of Equity Securities by Issuer and Affiliated Purchasers For the quarter ended Dec. 31, 2020, no equity securities that are registered by Xcel Energy Inc. pursuant to Section 12 of the Securities Exchange Act of 1934 were purchased by or on behalf of us or any of our affiliated purchasers.
Selected financial data for Xcel Energy related to the five most recent years ended Dec. 31:
(a) As a result of adopting ASU No. 2017-07 (Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, Topic 715), $33 million and $26 million of pension costs were retrospectively reclassified from O&M expenses to other income, net on the consolidated statements of income for the years ended Dec. 31, 2017 and Dec. 31, 2016, respectively. (b) As a result of adopting Leases, Topic 842, finance lease obligations of $77 million are included in other noncurrent liabilities on the consolidated balance sheet at Dec. 31, 2019. These obligations were included in long-term debt prior to 2019. 24
Non-GAAP Financial Measures The following discussion includes financial information prepared in accordance with GAAP, as well as certain non-GAAP financial measures such as ongoing ROE, electric margin, natural gas margin, ongoing earnings and ongoing diluted EPS. 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. Xcel Energy’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. Ongoing ROE Ongoing ROE is calculated by dividing the net income or loss of Xcel Energy or each subsidiary, adjusted for certain nonrecurring items, by each entity’s average stockholder’s equity. We use these non-GAAP financial measures to evaluate and provide details of earnings results. 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 and Ongoing Diluted EPS) GAAP diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock (i.e., common stock equivalents) were settled. The weighted average number of potentially dilutive shares outstanding used to calculate Xcel Energy Inc.’s diluted EPS is calculated using the treasury stock method. Ongoing earnings reflect adjustments to GAAP earnings (net income) for certain items. Ongoing diluted EPS is calculated by dividing the net income or loss of each subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period. Ongoing diluted EPS for each subsidiary is calculated by dividing the net income or loss of such subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period. We use these non-GAAP financial measures to evaluate and provide details of Xcel Energy’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 our subsidiaries. For the years ended Dec. 31, 2020 and 2019, there were no such adjustments to GAAP earnings and therefore GAAP earnings equal ongoing earnings.
Diluted EPS for Xcel Energy at Dec. 31:
(a) Amounts may not add due to rounding. Xcel Energy’s management believes that ongoing earnings reflects management’s performance in operating Xcel Energy and provides a meaningful representation of the performance of Xcel Energy’s core business. In addition, Xcel Energy’s management uses ongoing earnings internally for financial planning and analysis, reporting results to the Board of Directors and when communicating its earnings outlook to analysts and investors. 2020 Comparison with 2019 Xcel Energy — GAAP and ongoing earnings increased $0.15 per share, primarily reflecting higher electric margin (largely due to regulatory outcomes which recover capital investment), higher AFUDC and lower O&M expenses, which offset increased depreciation, interest expense and declining sales primarily due to the impacts of COVID-19. NSP-Minnesota — Earnings increased $0.08 per share for 2020, reflecting higher electric margin (riders, wholesale transmission revenue and a sales true-up mechanism, which recovers lower sales due to COVID-19) and lower O&M expenses, partially offset by increased depreciation and lower natural gas margin. PSCo — Earnings were flat for 2020, reflecting higher electric margin (wholesale transmission revenue and regulatory outcomes offset lower sales due to COVID-19), increased AFUDC and higher natural gas margin, offset by additional depreciation and taxes (other than income taxes). SPS — Earnings increased $0.05 per share for 2020, reflecting higher electric margin (wholesale transmission revenue and regulatory outcomes offset lower sales due to COVID-19) and lower O&M expenses, partially offset by increased depreciation, interest expense and taxes (other than income taxes). NSP-Wisconsin — Earnings increased $0.05 per share for 2020, reflecting higher electric margin (regulatory outcomes offset lower sales due to COVID-19) and lower O&M expenses, partially offset by increased depreciation and lower natural gas margin. Xcel Energy Inc. and Other — Primarily includes financing costs at the holding company. 25 Changes in Diluted EPS Components significantly contributing to changes in EPS:
(a)Change in electric margin was negatively impacted by reductions in sales and demand due to COVID-19 and is detailed below. Sales decline excludes weather impact, net of decoupling/sales true-up and reduction in demand revenue is net of sales true-up.
(b) Includes PTCs and tax reform regulatory amounts, which are primarily offset in electric margin. ROE for Xcel Energy and its utility subsidiaries:
Statement of Income Analysis The following summarizes the items that affected the individual revenue and expense items reported in the consolidated statements of income. Estimated Impact of Temperature Changes on Regulated Earnings — Unusually hot summers or cold winters increase electric and natural gas sales, while mild weather reduces electric and natural gas sales. The estimated impact of weather on earnings is based on the number of customers, temperature variances, the amount of natural gas or electricity historically used per degree of temperature and excludes any incremental related operating expenses that could result due to storm activity or vegetation management requirements. As a result, weather deviations from normal levels can affect Xcel Energy’s financial performance to the extent there is not a decoupling or sales true-up mechanism in the state. Degree-day or THI data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day’s average temperature and humidity. HDD is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit. CDD is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65° Fahrenheit. Each degree of temperature above 65° Fahrenheit is counted as one CDD, and each degree of temperature below 65° Fahrenheit is counted as one HDD. In Xcel Energy’s more humid service territories, a THI is used in place of CDD, which adds a humidity factor to CDD. HDD, CDD and THI are most likely to impact the usage of Xcel Energy’s residential and commercial customers. Industrial customers are less sensitive to weather. Normal weather conditions are defined as either the 10, 20 or 30-year average of actual historical weather conditions. The historical period of time used in the calculation of normal weather differs by jurisdiction, based on regulatory practice. To calculate the impact of weather on demand, a demand factor is applied to the weather impact on sales. Extreme weather variations, windchill and cloud cover may not be reflected in weather-normalized estimates. Percentage (decrease) increase in normal and actual HDD, CDD and THI:
Weather — Estimated impact of temperature variations on EPS compared with normal weather conditions:
Sales — Sales growth (decline) for actual and weather-normalized sales:
26
(a) Higher residential sales and lower C&I sales were primarily attributable to COVID-19. The increase in residential sales was partially driven by more customers working from home. Weather-normalized and leap-year adjusted electric sales growth (decline) — year-to-date (excluding leap day) •PSCo — Residential sales rose based on an increased number of customers and higher use per customer. The decline in C&I sales was primarily due to COVID-19, particularly within the manufacturing and service industries, partially offset by an increase in the energy sector. •NSP-Minnesota — Residential sales rose based on an increased number of customers and higher use per customer. The decline in C&I sales was primarily due to COVID-19, particularly within the energy, manufacturing and services sectors. •SPS — Residential sales rose based on an increased number of customers and higher use per customer. The decline in C&I sales was primarily due to COVID-19, particularly within the energy and manufacturing sectors. •NSP-Wisconsin — Residential sales rose based on an increased number of customers and higher use per customer. The decline in C&I sales was primarily due to COVID-19, particularly within the energy and manufacturing sectors. Weather-normalized and leap-year adjusted natural gas sales growth (decline) — year-to-date (excluding leap day) •Higher natural gas sales reflect an increase in the number of customers combined with higher residential customer use, partially offset by lower C&I customer use. Electric Margin Electric revenues and fuel and purchased power expenses are impacted by fluctuations in the price of natural gas, coal and uranium. However, these fluctuations have minimal impact on margin due to fuel recovery mechanisms. In addition, electric customers receive a credit for PTCs generated, which reduce electric revenue and margin (offset by lower tax expense). Electric revenues and margin:
Changes in Electric Margin
(a) Includes approximately $70 million of revenue and margin due to the Texas rate case outcome, which is largely offset by recognition of previously deferred costs. (b) Sales excludes weather impact, net of decoupling/sales true-up, and demand revenue is net of sales true-up. Natural Gas Margin Natural gas expense varies with changing sales and cost of natural gas. However, fluctuations in the cost of natural gas has minimal impact on margin due to cost recovery mechanisms. Natural gas revenues and margin:
Changes in Natural Gas Margin
27 Non-Fuel Operating Expenses and Other Items O&M Expenses — O&M expenses decreased $14 million, or 0.6%, for 2020, largely reflecting management actions to reduce costs to offset the impact of lower sales from COVID-19. Significant changes are as follows:
•Distribution declined due to cost mitigation/continuous improvement efforts and timing of maintenance, partially offset by increased storm impacts. •Generation was lower from timing of maintenance and overhauls at power plants and cost mitigation/continuous improvement efforts, partially offset by an increase in maintenance expenses from wind expansion. •Transmission declined due to cost mitigation/continuous improvement initiatives. •Minnesota payment plan credit program represents a commitment to fund customer programs as agreed to in the NSP-Minnesota rate case stay-out. •Information technology costs increased due to higher spending on network and other infrastructure costs. •Employee benefits increased due primarily to postretirement costs and other long-term benefits, partially offset by lower deferred compensation expense. Depreciation and Amortization — Depreciation and amortization increased $183 million, or 10.4%, year-to-date. The increase was primarily driven by the Hale, Cheyenne Ridge, Foxtail, Blazing Star I, Lake Benton, Sagamore, Crowned Ridge, Community Wind North and Jeffers wind facilities going into service, as well as normal system expansion. In addition, new depreciation rates were implemented in Colorado, New Mexico and Texas in 2020, increasing expense. Taxes (Other than Income Taxes) — Taxes (other than income taxes) increased $43 million, or 7.6%, year-to-date. The increase was primarily due to higher property taxes in Colorado and Texas (net of deferred amounts). Other Income (Expense) — Other income (expense) decreased $22 million year-to-date. The decrease was largely due to the performance of rabbi trust investments, primarily offset in O&M expenses. AFUDC, Equity and Debt — AFUDC increased $43 million year-to-date. The increase was primarily due to various wind projects under construction. Interest Charges — Interest charges increased $67 million, or 8.7%, 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 taxes decreased $134 million for 2020. The decrease was primarily driven by an increase in wind PTCs and an increase in plant-related regulatory differences. Xcel Energy Inc. and Other Results Net income and diluted EPS contributions of Xcel Energy Inc. and its nonregulated businesses:
(a)MEC was sold in the third quarter of 2020. (b)Amounts include gains or losses associated with sales of properties held by Eloigne. Xcel Energy Inc.’s results include interest charges, which are incurred at Xcel Energy Inc. and are not directly assigned to individual subsidiaries. 2019 Comparison with 2018 A discussion of changes in Xcel Energy’s results of operations, cash flows and liquidity and capital resources from the year ended Dec. 31, 2018 to Dec. 31, 2019 can be found in Part II, “Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our Annual Report on Form 10-K for the fiscal year 2019, which was filed with the SEC on Feb. 21, 2020. However, such discussion is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K.
The FERC and various state and local regulatory commissions regulate Xcel Energy Inc.’s utility subsidiaries and WGI. Xcel Energy 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, South Dakota, Wisconsin, Michigan, Colorado, New Mexico, and Texas. Rates are designed to recover plant investment, operating costs and an allowed return on investment. Our utility subsidiaries request changes in rates for utility services through filings with governing commissions. Changes in operating costs can affect Xcel Energy’s financial results, depending on the timing of rate case filings 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 Xcel Energy’s results of operations. See Rate Matters within Note 12 to the consolidated financial statements for further information. 28 NSP-Minnesota Summary of Regulatory Agencies / RTO and Areas of Jurisdiction
Recovery Mechanisms
(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
29 Additional Information: 2020 Minnesota Electric Rate Case and Stay-Out Alternative — In November 2020, NSP-Minnesota filed an 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% and a 52.5% equity ratio. NSP-Minnesota also filed a stay-out alternative in which it would withdraw its rate case filing. In December 2020, 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 increase to the Nuclear Decommissioning Trust annual accrual until Jan. 1, 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. 2020 North Dakota Electric Rate Case — In November 2020, NSP-Minnesota filed a request with the NDPSC for an overall increase in annual retail electric revenues of approximately $22 million, or an increase of 10.8%. The rate filing is based on a 2021 forecast test year, a requested ROE of 10.2%, an equity ratio of 52.50% and an electric rate base of approximately $677 million. Interim rates, subject to refund, of approximately $16 million were implemented on 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: •Retirement 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. •Extending the life of the Monticello nuclear plant from 2030 to 2040. •Continuing to run the PI through current end of life (2033 and 2034). •Construction 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.). •Achieving 780 GWh in energy efficiency savings annually through 2034. •Adding 400 MW of incremental demand response by 2023, and a total of 1,500 MW of demand response by 2034. 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 included the following: •Repower 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. The MPUC is expected to address the solar facilities, ALLETE PPA wind repowering acquisition and the electric vehicle proposal in the second half of 2021. 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. 30 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. 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 JOA. NSP-Minnesota does not serve any wholesale requirements customers at cost-based regulated rates. NSP-Wisconsin Summary of Regulatory Agencies / RTO and Areas of Jurisdiction
Recovery Mechanisms
Pending and Recently Concluded Regulatory Proceedings 2021 Electric Fuel Cost Recovery —In December 2020, the PSCW approved the NSP-Wisconsin application to update its 2021 fuel cost and decrease retail electric rates for 2021 by approximately $12 million. Request to Participate in Utility Money Pool— In October 2020, the PSCW approved NSP-Wisconsin’s application to participate in the Money Pool. NSP-Wisconsin Solar Proposal — In October 2020, NSP-Wisconsin filed for a 74 MW solar facility build-own-transfer in Wisconsin for approximately $100 million. A PSCW decision is expected in the third quarter of 2021. Purchased Power and Transmission Services The NSP System expects to use power plants, power purchases, conservation and DSM options, new generation facilities and expansion of power plants to meet its system capacity requirements. Purchased Power — Through the Interchange Agreement, NSP-Wisconsin receives power purchased by NSP-Minnesota from other utilities and independent power producers. Long-term purchased power contracts for dispatchable resources typically require a capacity charge 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. Wholesale and Commodity Marketing Operations NSP-Wisconsin does not serve any wholesale requirements customers at cost-based regulated rates. PSCo Summary of Regulatory Agencies / RTO and Areas of Jurisdiction
Recovery Mechanisms
Additional Information: 2020 Natural Gas Rate Case — In October 2020, the CPUC approved a settlement resulting in a net increase of $77 million. This increase reflects a $94 million increase in base rate revenue, partially offset by $17 million of costs previously recovered through the Pipeline Integrity rider. Rates will be implemented on April 1, 2021 (retroactive to November 2020). 2019 Electric Rate Case — In 2019, PSCo filed a request with the CPUC seeking a net rate increase of approximately $108 million. In February 2020, the CPUC issued an initial decision for a net rate increase of $35 million. In July 2020, the CPUC’s final written decision on rehearing was received and resulted in an additional increase of approximately $12 million annually. In December 2020, the CPUC denied PSCo’s request of a $5 million surcharge for changes to the revenue increase from the effective date of rates, based on the CPUC’s decision on rehearing. PSCo has appealed this decision with the District Court of Denver County.
32 2019 Phase I Electric Rate Case Appeal — In August 2020, PSCo filed an appeal with the Denver District Court seeking a review of CPUC decisions on gain on sales and losses of assets, oil and gas royalty revenues and Board of Director’s equity compensation. PSCo plans to seek consolidation of this appeal with the appeal of the surcharge decision in this same proceeding. 2019 Natural Gas Rate Case Appeal — In April 2019, PSCo filed an appeal seeking judicial review of the CPUC’s prior ruling regarding PSCo’s natural gas rate case (filed in June 2017 and approved in December 2018). The appeal requested review of the following: denial of a return on the prepaid pension and retiree medical assets; the use of a capital structure not based on the actual historical test year; and use of an average rate base methodology rather than a year-end rate base methodology. In March 2020, The District Court of Denver County ruled in favor of allowing the prepaid pension assets to be included in rate base; but upheld the CPUC’s treatment of the retiree medical assets and capital structure methodology. In March 2021, PSCo expects to file a motion to implement the District Court’s decision on treatment of the prepaid pension asset for the applicable period of Jan. 1, 2018 through Oct. 31, 2020. Wildfire Protection Rider —In 2020, PSCo requested to establish a rider to recover incremental costs associated with system investments to reduce wildfire risk. The rider would be effective in June 2021 and continue through 2025. The Office of Consumer Counsel and CPUC Staff are supportive of the wildfire mitigation program as proposed, but oppose rider recovery and instead recommend deferral of certain costs with recovery in a future rate case. A CPUC decision is expected in the second quarter of 2021. Wildfire Protection capital investment is projected to be approximately $325 million. Forecasted annual revenue requirements from 2021 through 2025:
Transportation Electrification Plan — In January 2021, the CPUC approved PSCo's Transportation Electrification Plan, which authorizes rider recovery of new electric vehicle utility programs for the residential, commercial, multi-family and public charging sectors. The approval establishes utility-owned charging infrastructure and chargers and amortization of rebates for electric vehicles. The Transportation Electrification Plan approval authorizes approximately $110 million in spending with flexibility up to approximately $138 million over three years. Advanced Grid Rider In 2020, PSCo requested to establish a rider to recover incremental costs associated with the Advanced Grid Intelligence and Security initiative. The rider would be effective in May 2021 and continue through 2025. In October 2020, an ALJ issued The Recommended Decision granting the Office of Consumer Counsel motion to dismiss the Advanced Grid Rider. PSCo has chosen not to appeal the ALJ’s Recommended Decision. The PSCo portion of the Advanced Grid Intelligence and Security capital investment is projected to be approximately $850 million. Forecasted annual revenue requirements from 2021 through 2025 are as follows:
PSCo KEPCO Filing In September 2020, PSCo filed with the CPUC for approval to terminate a solar PPA with KEPCO Solar of Alamosa, Inc. and establish a regulatory asset to recover transaction costs of approximately $41 million. By terminating the PPA, customers would save approximately $38 million over an 11-year period. A CPUC decision is expected in the second quarter of 2021. Natural Gas LDC and Emission Reductions In October 2020, the CPUC opened a docket to investigate topics related to natural gas emissions in relation to statewide emission reduction goals. The first meeting was held in November 2020, in which subject matter experts discussed greenhouse emission reductions required from the natural gas industry in regard to the statewide goals. Resource Plan PSCo is expected to file its next Electric Resource Plan on March 31, 2021. The filing will propose the future of the remaining coal plants in Colorado and PSCo’s plan to achieve it’s 80% carbon emissions reduction target by 2030. A CPUC decision is expected in 2022. PSCo — Comanche Unit 3 PSCo is part owner and operator of Comanche Unit 3, a 750 MW, coal-fueled electric generating unit. In January 2020, the unit experienced a turbine failure causing the unit to be taken offline for repairs, which were completed in June 2020. During start-up the unit experienced a loss of turbine oil, which damaged the plant. Comanche Unit 3 recommenced operations in January 2021. Replacement and repair of damaged systems in excess of a $2 million deductible are expected to be recovered through insurance policies. PSCo obtained replacement power costs of approximately $16 million during the outage. In October 2020, the CPUC initiated a non-adjudicatory review of Comanche Unit 3’s performance. A report on performance is expected to be issued in March 2021. At this stage of the regulatory review, the resulting recommendations of the CPUC’s staff cannot be determined. Boulder Municipalization In 2011, Boulder passed a ballot measure authorizing the formation of an electric municipal utility. Subsequently, there have been various legal proceedings in multiple venues. In September 2020, the City Council voted to approve a settlement between PSCo and Boulder officials to end the city’s municipalization effort. The settlement resulted in a 20-year franchise arrangement (with multiple opt-out conditions), an energy partnership and an undergrounding agreement. It also established the municipalization process if Boulder exercised an opt-out. In December 2020, PSCo filed the franchise agreement with the CPUC and is currently awaiting a decision. Natural Gas Xcel Energy has 22 natural gas plants with approximately 7,900 MW of total 2020 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 percentage of total fuel requirements:
12 Capacity and Demand Uninterrupted system peak demand and occurrence date for the regulated utilities:
Transmission Transmission lines deliver electricity at higher voltage and over longer distances from power sources to transmission substations closer to homes and businesses. 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. Xcel Energy owns more than 20,000 miles of transmission lines, serving 22,000 MW of customer load. Transmission projects completed in 2020 include:
Notable upcoming projects:
Distribution Distribution lines allow electricity to travel at lower voltages from substations directly to homes and businesses. Xcel Energy has a vast distribution network, owning and operating approximately 210,000 conductor miles of distribution lines across our eight-state service territory, both above ground and underground. 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. Over the five year project, Xcel Energy plans to invest approximately $1.8 billion implementing new network infrastructure, smart meters, advanced software, equipment sensors and related data analytics capabilities. These investments will further improve reliability and reduce outage restoration times for our customers, while at the same time enabling new options and opportunities for increased efficiency savings. The new capabilities will also enable integration of battery storage and other distributed energy resources into the grid, including electric vehicles. 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 in NSP-Minnesota, NSP-Wisconsin and PSCo. Xcel Energy had natural gas deliveries of 444,340 (thousands of MMBtu), 2.1 million customers and natural gas revenues of $1,636 (millions of dollars) for 2020. 13 Sales/Revenue Statistics (a)
(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:
Natural Gas Supply and Cost Xcel Energy seeks natural gas supply, transportation and storage alternatives to yield a diversified portfolio, which increase flexibility, decrease interruption and financial risks and economic customer rates. In addition, the utility subsidiaries conduct natural gas price hedging activities approved by their states’ commissions. Average delivered cost per MMBtu of natural gas for regulated retail distribution:
NSP-Minnesota, NSP-Wisconsin and PSCo have 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.
General Economic Conditions Economic conditions may have a material impact on Xcel Energy’s operating results. Other events impact overall economic conditions and management cannot predict the impact of fluctuating energy prices, terrorist activity, war or the threat of war. We could experience a material impact to our results of operations, future growth or ability to raise capital resulting from a sustained general slowdown in economic growth or a significant increase in interest rates. 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, Xcel Energy’s operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. Competition Xcel Energy is subject to public policies that promote competition and development of energy markets. Xcel Energy’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. Several states have incentives for the development of rooftop solar, community solar gardens and other distributed energy resources. Distributed generating resources are potential competitors to Xcel Energy’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. Xcel Energy’s wholesale customers can purchase their output from generation resources of competing suppliers or non-contracted quantities and use the transmission systems of the utility subsidiaries on a comparable basis to serve their native load. FERC Order No. 1000 established competition for construction and operation of certain new electric transmission facilities. State utility commissions have also created resource planning programs that promote competition for electric generation resources used to provide service to retail customers. Xcel Energy Inc.’s utility subsidiaries have franchise agreements with cities subject to periodic renewal; however, a city could seek alternative means to access electric power or gas, such as municipalization. While each utility subsidiary faces these challenges, Xcel Energy believes their rates and services are competitive with alternatives currently available.
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 substances. Certain Xcel Energy activities require registrations, permits, licenses, inspections and approvals from these agencies. Xcel Energy has received necessary authorizations for the construction and continued operation of its generation, transmission and distribution systems. Our facilities 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. 14 Xcel Energy must comply with emission levels in Minnesota, Texas and Wisconsin that may require the purchase of emission allowances. The Denver North Front Range Non-attainment Area does not meet either the 2008 or 2015 ozone NAAQS. Colorado will continue to consider further reductions available in the non-attainment area as it develops plans to meet ozone standards. Gas plants which operate in PSCo’s non-attainment area may be required to improve or add controls, implement further work practices and/or enhanced emissions monitoring as part of future Colorado state plans. There are significant environmental regulations to encourage use of clean energy technologies and regulate emissions of GHGs. We have 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 required states to develop plans by 2022 for GHG reductions from coal-fired power plants. In a Jan. 19, 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 reviving the Clean Power Plan or proposing additional regulation. It is too early to predict an outcome, but new rules could require substantial additional investment, even in plants slated for retirement. Xcel Energy believes, based on prior state commission practices, the cost of these initiatives or replacement generation would be recoverable through rates. In October 2020, the TCEQ approved an agreement that ensures SPS will convert the Harrington plant from coal to natural gas by Jan. 1, 2025. This conversion is necessary to attain Federal Clean Air Act standards for emissions of SO2. Xcel Energy seeks to address climate change and potential climate change regulation through efforts to reduce its GHG emissions in a balanced, cost-effective manner. In 2020, Xcel Energy estimates that it reduced carbon emissions associated with electric generating resources, both owned and under PPAs, used to serve its customers by approximately 51% from 2005 levels. Environmental Costs Environmental costs include amounts for nuclear plant decommissioning and payments for storage of spent nuclear fuel, disposal of hazardous materials and waste, remediation of contaminated sites, monitoring of discharges to the environment and compliance with laws and permits with respect to emissions. Costs charged to operating expenses for nuclear decommissioning, spent nuclear fuel disposal, environmental monitoring and remediation and disposal of hazardous materials and waste were approximately: •$400 million in 2020. •$345 million in 2019. •$335 million in 2018. Average annual expense of approximately $465 million from 2021 – 2025 is estimated for similar costs. The precise timing and amount of environmental costs, including those for site remediation and disposal of hazardous materials, are unknown. Additionally, the extent to which environmental costs will be included in and recovered through rates may fluctuate. Capital expenditures for environmental improvements were approximately: •$30 million in 2020. •$30 million in 2019. •$50 million in 2018.
See Item 7 for discussion of capital expenditures and funding sources. 15
(a) No family relationships exist between any of the executive officers or directors. (b) Ages as of Feb. 17, 2021. (c) In April 2014, Energy Future Holdings Corp., the majority of its subsidiaries, including TCEH the parent company of Luminant, filed a voluntary bankruptcy petition under Chapter 11 of the United States Bankruptcy Code. TCEH emerged from Chapter 11 in October 2016.
Xcel Energy 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. These risks should be carefully considered together with the other information set forth in this report and future reports that we file with the SEC. Oversight of Risk and Related Processes The Board of Directors is responsible for the oversight of material risk and maintaining an effective risk monitoring process. Management and the Board of Directors’ committees have responsibility for overseeing the identification and mitigation of key risks and reporting its assessments and activities to the full Board of Directors. Xcel Energy 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. Xcel Energy 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 Xcel Energy’s 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 key stakeholders 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. 16 The oversight, management and mitigation of risk is an integral and continuous part of the Board of Directors’ governance of Xcel Energy. The Board of Directors assigns oversight of critical risks to each of its four committees to ensure these risks are well understood and given appropriate focus. The Audit Committee is responsible for reviewing the adequacy of the committee’s risk oversight and affirming appropriate aggregate oversight occurs. Committees regularly report on their oversight activities and certain risk issues may be brought to the full Board of Directors for consideration when deemed appropriate. New risks are considered and assigned as appropriate during the annual Board of Directors and committee evaluation process, resulting in updates to the committee charters and annual work plans. Additionally, the Board of Directors conducts an annual strategy session where Xcel Energy’s future plans and initiatives are reviewed. Risks Associated with Our Business Operational Risks Our natural gas and electric 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. 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. Other uncertainties and risks inherent in operating and maintaining Xcel Energy'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. Xcel Energy’s 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. 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, 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. 17 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 in most of our states, 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, Xcel Energy 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, Xcel Energy cannot fully assure that its controls will be effective against all potential risks, including, without limitation, employee misconduct. If such controls are not effective, Xcel Energy’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. Specialized knowledge is required of our technical employees for construction and operation of transmission, generation and distribution assets. Xcel Energy’s business strategy is dependent on our ability to recruit, retain and motivate employees. There is competition and a tightening market for skilled employees. 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 could impact ongoing operations, restoration operations, our reputation and could introduce financial risk or risks of fines. Our subsidiary, NSP-Minnesota, is 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 NSP-Minnesota’s 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 NSP-Minnesota’s compliance costs. Financial Risks Our profitability depends on the ability of our utility subsidiaries to recover their costs and changes in regulation may impair the ability of our utility subsidiaries to recover costs from their 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 utility operations is dependent on our ability to recover the costs of providing energy and utility services and earning a return on capital investment. Our rates are generally regulated and are based on an analysis of the utility’s costs incurred in a test year. The utility subsidiaries are subject to both future and historical test years depending upon the regulatory jurisdiction. Thus, the rates a utility is allowed to charge may or may not match its 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 the costs of our utility subsidiaries 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 the ability of our utility subsidiaries to recover costs historically collected from customers, or these subsidiaries could exceed caps on capital costs required by commissions and result in less than full recovery. 18 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, higher than expected inflation or tariffs may increase costs of construction and operations. Also, rising fuel costs could increase the risk that our utility subsidiaries will not be able to fully recover their fuel costs from their 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 and the payment of dividends on common stock. Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships. We cannot be assured that our current credit ratings or our subsidiaries’ 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, 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 and could impact our ability to access capital markets. Also, our utility subsidiaries 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. 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 NSP-Minnesota’s 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 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. Xcel Energy 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. California Independent System Operator, SPP, 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. 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, would trigger settlement accounting and could require Xcel Energy 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. We must rely on cash from our subsidiaries to make dividend payments. Investments in our subsidiaries are our primary assets. Substantially all of our operations are conducted by our subsidiaries. Consequently, our operating cash flow and ability to service our debt and pay dividends depends upon the operating cash flows of our subsidiaries and their payment of dividends. Our subsidiaries are separate legal entities that have no obligation to pay any amounts due pursuant to our obligations or to make any funds available for dividends on our common stock. In addition, each subsidiary’s ability to pay dividends depends on statutory and/or contractual restrictions which may include requirements to maintain minimum levels of equity ratios, working capital or assets. If the utility subsidiaries were to cease making dividend payments, our ability to pay dividends on our common stock or otherwise meet our financial obligations could be adversely affected. Our utility subsidiaries are regulated by state utility commissions, which possess broad powers to ensure that the needs of the utility customers are met. We may be negatively impacted by the actions of state commissions that limit the payment of dividends by our utility subsidiaries. 19 Federal tax law may significantly impact our business. Our utility subsidiaries collect estimated federal, state and local tax payments through their regulated rates. Changes to federal tax law may benefit or adversely affect our earnings and customer costs. Tax depreciable lives and the value 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. Xcel Energy’s 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. Our utility subsidiaries face 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 impacting countries, communities, supply chains and markets. A high degree of uncertainty continues to exist regarding the pandemic, the duration and magnitude of business restrictions, re-shut downs, if any, and the level and pace of economic recovery. While we are implementing contingency plans, there are no guarantees these plans will be sufficient to offset the impact of COVID-19. Although the impact of the pandemic to the 2020 results was largely 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 (particularly in Colorado), 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. Xcel Energy participates in grid security and emergency response exercises (GridEx). These efforts, led by the NERC, test and further develop the coordination, threat sharing and interaction between utilities and various government agencies relative to potential cyber and physical threats against the nation’s electric grid. A cyber incident or security breach could have a material effect on our business. We operate in an industry that requires the continued operation of sophisticated information technology, control systems and network infrastructure. In addition, we use our systems and infrastructure to create, collect, use, disclose, store, dispose of and otherwise process sensitive information, including company data, customer energy usage data, and personal information regarding customers, employees and their dependents, contractors, shareholders and other individuals. Xcel Energy’s 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. The utility industry has been the target of several attacks on operational systems and has seen an increased volume and sophistication of cyber security incidents from international activist organizations, Nation States and individuals. Cyber security incidents could harm our businesses by limiting our generating, transmitting and distributing capabilities, delaying our development and construction of new facilities or capital improvement projects to existing facilities, disrupting our customer operations or causing the release of customer information, all of which would likely receive state and federal regulatory scrutiny and could expose us to liability. 20 Xcel Energy’s 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 causesignificant additional costs (e.g., penalties, third-party claims, repairs, insurance or compliance) and potentially disrupt our supply and markets for natural gas, oil and other fuels. We maintain security measures to protect our information technology and control systems, network infrastructure and other assets. However, these assets and the information they process may be vulnerable to 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. The Biden Administration will establish a new nationally determined contribution for the United States. The Paris Agreement 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 Xcel Energy 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. 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. 21 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. 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 Xcel Energy 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. We may not recover all costs related to mitigating these physical and financial risks.
None.
Virtually all of the utility plant property of the operating companies is subject to the lien of their respective first mortgage bond indentures.
(a)Summer 2020 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. 22
(a)Summer 2020 net dependable capacity. (b)Refuse-derived fuel is made from municipal solid waste.
(a) Summer 2020 net dependable capacity. (b)In 2018, the CPUC approved early retirement of PSCo’s Comanche Units 1 and 2 in 2022 and 2025, respectively. (c) Based on PSCo’s ownership of 67%. (d) Craig Unit 1 and 2 are expected to be retired early in 2025 and 2028, respectively. (e) Based on PSCo’s ownership of 10%. (f) Based on PSCo’s ownership of 76% of Unit 1 and 37% of Unit 2. (g) Values disclosed are the generation levels at the point-of-interconnection. Capacity is attainable only when wind conditions are sufficiently available (on-demand net dependable capacity is zero). (h)Hayden Unit 1 and 2 are expected to be retired in 2028 and 2027, respectively.
(a) Summer 2020 net dependable capacity. (b) Harrington is expected to be converted to natural gas by the end of 2024. (c) 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) (d) Tolk Unit 1 and 2 are expected to be retired in 2032. Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2020:
Electric utility transmission and distribution substations at Dec. 31, 2020:
Natural gas utility mains at Dec. 31, 2020:
23
Xcel Energy 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 Xcel Energy’s financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred. See Note 12 to the consolidated financial statements, Item 1 and Item 7 for further information.
None. PART II
Stock Data Xcel Energy Inc.’s common stock is listed on the Nasdaq Global Select Market (Nasdaq). The trading symbol is XEL. The number of common stockholders of record as of Feb. 12, 2021 was approximately 52,689. The following compares our cumulative TSR on common stock with the cumulative TSR of the EEI Investor-Owned Electrics Index and the S&P 500 Composite Stock Price Index over the last five years. The EEI Investor-Owned Electrics Index (market capitalization-weighted) included 39 companies at year-end and is a broad measure of industry performance. Comparison of Five Year Cumulative Total Return* * $100 invested on Dec. 31, 2015 in stock or index — including reinvestment of dividends. Fiscal years ended Dec. 31. Purchases of Equity Securities by Issuer and Affiliated Purchasers For the quarter ended Dec. 31, 2020, no equity securities that are registered by Xcel Energy Inc. pursuant to Section 12 of the Securities Exchange Act of 1934 were purchased by or on behalf of us or any of our affiliated purchasers.
Selected financial data for Xcel Energy related to the five most recent years ended Dec. 31:
(a) As a result of adopting ASU No. 2017-07 (Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, Topic 715), $33 million and $26 million of pension costs were retrospectively reclassified from O&M expenses to other income, net on the consolidated statements of income for the years ended Dec. 31, 2017 and Dec. 31, 2016, respectively. (b) As a result of adopting Leases, Topic 842, finance lease obligations of $77 million are included in other noncurrent liabilities on the consolidated balance sheet at Dec. 31, 2019. These obligations were included in long-term debt prior to 2019. 24
Non-GAAP Financial Measures The following discussion includes financial information prepared in accordance with GAAP, as well as certain non-GAAP financial measures such as ongoing ROE, electric margin, natural gas margin, ongoing earnings and ongoing diluted EPS. 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. Xcel Energy’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. Ongoing ROE Ongoing ROE is calculated by dividing the net income or loss of Xcel Energy or each subsidiary, adjusted for certain nonrecurring items, by each entity’s average stockholder’s equity. We use these non-GAAP financial measures to evaluate and provide details of earnings results. 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 and Ongoing Diluted EPS) GAAP diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock (i.e., common stock equivalents) were settled. The weighted average number of potentially dilutive shares outstanding used to calculate Xcel Energy Inc.’s diluted EPS is calculated using the treasury stock method. Ongoing earnings reflect adjustments to GAAP earnings (net income) for certain items. Ongoing diluted EPS is calculated by dividing the net income or loss of each subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period. Ongoing diluted EPS for each subsidiary is calculated by dividing the net income or loss of such subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period. We use these non-GAAP financial measures to evaluate and provide details of Xcel Energy’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 our subsidiaries. For the years ended Dec. 31, 2020 and 2019, there were no such adjustments to GAAP earnings and therefore GAAP earnings equal ongoing earnings.
Diluted EPS for Xcel Energy at Dec. 31:
(a) Amounts may not add due to rounding. Xcel Energy’s management believes that ongoing earnings reflects management’s performance in operating Xcel Energy and provides a meaningful representation of the performance of Xcel Energy’s core business. In addition, Xcel Energy’s management uses ongoing earnings internally for financial planning and analysis, reporting results to the Board of Directors and when communicating its earnings outlook to analysts and investors. 2020 Comparison with 2019 Xcel Energy — GAAP and ongoing earnings increased $0.15 per share, primarily reflecting higher electric margin (largely due to regulatory outcomes which recover capital investment), higher AFUDC and lower O&M expenses, which offset increased depreciation, interest expense and declining sales primarily due to the impacts of COVID-19. NSP-Minnesota — Earnings increased $0.08 per share for 2020, reflecting higher electric margin (riders, wholesale transmission revenue and a sales true-up mechanism, which recovers lower sales due to COVID-19) and lower O&M expenses, partially offset by increased depreciation and lower natural gas margin. PSCo — Earnings were flat for 2020, reflecting higher electric margin (wholesale transmission revenue and regulatory outcomes offset lower sales due to COVID-19), increased AFUDC and higher natural gas margin, offset by additional depreciation and taxes (other than income taxes). SPS — Earnings increased $0.05 per share for 2020, reflecting higher electric margin (wholesale transmission revenue and regulatory outcomes offset lower sales due to COVID-19) and lower O&M expenses, partially offset by increased depreciation, interest expense and taxes (other than income taxes). NSP-Wisconsin — Earnings increased $0.05 per share for 2020, reflecting higher electric margin (regulatory outcomes offset lower sales due to COVID-19) and lower O&M expenses, partially offset by increased depreciation and lower natural gas margin. Xcel Energy Inc. and Other — Primarily includes financing costs at the holding company. 25 Changes in Diluted EPS Components significantly contributing to changes in EPS:
(a)Change in electric margin was negatively impacted by reductions in sales and demand due to COVID-19 and is detailed below. Sales decline excludes weather impact, net of decoupling/sales true-up and reduction in demand revenue is net of sales true-up.
(b) Includes PTCs and tax reform regulatory amounts, which are primarily offset in electric margin. ROE for Xcel Energy and its utility subsidiaries:
Statement of Income Analysis The following summarizes the items that affected the individual revenue and expense items reported in the consolidated statements of income. Estimated Impact of Temperature Changes on Regulated Earnings — Unusually hot summers or cold winters increase electric and natural gas sales, while mild weather reduces electric and natural gas sales. The estimated impact of weather on earnings is based on the number of customers, temperature variances, the amount of natural gas or electricity historically used per degree of temperature and excludes any incremental related operating expenses that could result due to storm activity or vegetation management requirements. As a result, weather deviations from normal levels can affect Xcel Energy’s financial performance to the extent there is not a decoupling or sales true-up mechanism in the state. Degree-day or THI data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day’s average temperature and humidity. HDD is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit. CDD is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65° Fahrenheit. Each degree of temperature above 65° Fahrenheit is counted as one CDD, and each degree of temperature below 65° Fahrenheit is counted as one HDD. In Xcel Energy’s more humid service territories, a THI is used in place of CDD, which adds a humidity factor to CDD. HDD, CDD and THI are most likely to impact the usage of Xcel Energy’s residential and commercial customers. Industrial customers are less sensitive to weather. Normal weather conditions are defined as either the 10, 20 or 30-year average of actual historical weather conditions. The historical period of time used in the calculation of normal weather differs by jurisdiction, based on regulatory practice. To calculate the impact of weather on demand, a demand factor is applied to the weather impact on sales. Extreme weather variations, windchill and cloud cover may not be reflected in weather-normalized estimates. Percentage (decrease) increase in normal and actual HDD, CDD and THI:
Weather — Estimated impact of temperature variations on EPS compared with normal weather conditions:
Sales — Sales growth (decline) for actual and weather-normalized sales:
26
(a) Higher residential sales and lower C&I sales were primarily attributable to COVID-19. The increase in residential sales was partially driven by more customers working from home. Weather-normalized and leap-year adjusted electric sales growth (decline) — year-to-date (excluding leap day) •PSCo — Residential sales rose based on an increased number of customers and higher use per customer. The decline in C&I sales was primarily due to COVID-19, particularly within the manufacturing and service industries, partially offset by an increase in the energy sector. •NSP-Minnesota — Residential sales rose based on an increased number of customers and higher use per customer. The decline in C&I sales was primarily due to COVID-19, particularly within the energy, manufacturing and services sectors. •SPS — Residential sales rose based on an increased number of customers and higher use per customer. The decline in C&I sales was primarily due to COVID-19, particularly within the energy and manufacturing sectors. •NSP-Wisconsin — Residential sales rose based on an increased number of customers and higher use per customer. The decline in C&I sales was primarily due to COVID-19, particularly within the energy and manufacturing sectors. Weather-normalized and leap-year adjusted natural gas sales growth (decline) — year-to-date (excluding leap day) •Higher natural gas sales reflect an increase in the number of customers combined with higher residential customer use, partially offset by lower C&I customer use. Electric Margin Electric revenues and fuel and purchased power expenses are impacted by fluctuations in the price of natural gas, coal and uranium. However, these fluctuations have minimal impact on margin due to fuel recovery mechanisms. In addition, electric customers receive a credit for PTCs generated, which reduce electric revenue and margin (offset by lower tax expense). Electric revenues and margin:
Changes in Electric Margin
(a) Includes approximately $70 million of revenue and margin due to the Texas rate case outcome, which is largely offset by recognition of previously deferred costs. (b) Sales excludes weather impact, net of decoupling/sales true-up, and demand revenue is net of sales true-up. Natural Gas Margin Natural gas expense varies with changing sales and cost of natural gas. However, fluctuations in the cost of natural gas has minimal impact on margin due to cost recovery mechanisms. Natural gas revenues and margin:
Changes in Natural Gas Margin
27 Non-Fuel Operating Expenses and Other Items O&M Expenses — O&M expenses decreased $14 million, or 0.6%, for 2020, largely reflecting management actions to reduce costs to offset the impact of lower sales from COVID-19. Significant changes are as follows:
•Distribution declined due to cost mitigation/continuous improvement efforts and timing of maintenance, partially offset by increased storm impacts. •Generation was lower from timing of maintenance and overhauls at power plants and cost mitigation/continuous improvement efforts, partially offset by an increase in maintenance expenses from wind expansion. •Transmission declined due to cost mitigation/continuous improvement initiatives. •Minnesota payment plan credit program represents a commitment to fund customer programs as agreed to in the NSP-Minnesota rate case stay-out. •Information technology costs increased due to higher spending on network and other infrastructure costs. •Employee benefits increased due primarily to postretirement costs and other long-term benefits, partially offset by lower deferred compensation expense. Depreciation and Amortization — Depreciation and amortization increased $183 million, or 10.4%, year-to-date. The increase was primarily driven by the Hale, Cheyenne Ridge, Foxtail, Blazing Star I, Lake Benton, Sagamore, Crowned Ridge, Community Wind North and Jeffers wind facilities going into service, as well as normal system expansion. In addition, new depreciation rates were implemented in Colorado, New Mexico and Texas in 2020, increasing expense. Taxes (Other than Income Taxes) — Taxes (other than income taxes) increased $43 million, or 7.6%, year-to-date. The increase was primarily due to higher property taxes in Colorado and Texas (net of deferred amounts). Other Income (Expense) — Other income (expense) decreased $22 million year-to-date. The decrease was largely due to the performance of rabbi trust investments, primarily offset in O&M expenses. AFUDC, Equity and Debt — AFUDC increased $43 million year-to-date. The increase was primarily due to various wind projects under construction. Interest Charges — Interest charges increased $67 million, or 8.7%, 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 taxes decreased $134 million for 2020. The decrease was primarily driven by an increase in wind PTCs and an increase in plant-related regulatory differences. Xcel Energy Inc. and Other Results Net income and diluted EPS contributions of Xcel Energy Inc. and its nonregulated businesses:
(a)MEC was sold in the third quarter of 2020. (b)Amounts include gains or losses associated with sales of properties held by Eloigne. Xcel Energy Inc.’s results include interest charges, which are incurred at Xcel Energy Inc. and are not directly assigned to individual subsidiaries. 2019 Comparison with 2018 A discussion of changes in Xcel Energy’s results of operations, cash flows and liquidity and capital resources from the year ended Dec. 31, 2018 to Dec. 31, 2019 can be found in Part II, “Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our Annual Report on Form 10-K for the fiscal year 2019, which was filed with the SEC on Feb. 21, 2020. However, such discussion is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K.
The FERC and various state and local regulatory commissions regulate Xcel Energy Inc.’s utility subsidiaries and WGI. Xcel Energy 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, South Dakota, Wisconsin, Michigan, Colorado, New Mexico, and Texas. Rates are designed to recover plant investment, operating costs and an allowed return on investment. Our utility subsidiaries request changes in rates for utility services through filings with governing commissions. Changes in operating costs can affect Xcel Energy’s financial results, depending on the timing of rate case filings 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 Xcel Energy’s results of operations. See Rate Matters within Note 12 to the consolidated financial statements for further information. 28 NSP-Minnesota Summary of Regulatory Agencies / RTO and Areas of Jurisdiction
Recovery Mechanisms
(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
29 Additional Information: 2020 Minnesota Electric Rate Case and Stay-Out Alternative — In November 2020, NSP-Minnesota filed an 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% and a 52.5% equity ratio. NSP-Minnesota also filed a stay-out alternative in which it would withdraw its rate case filing. In December 2020, 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 increase to the Nuclear Decommissioning Trust annual accrual until Jan. 1, 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. 2020 North Dakota Electric Rate Case — In November 2020, NSP-Minnesota filed a request with the NDPSC for an overall increase in annual retail electric revenues of approximately $22 million, or an increase of 10.8%. The rate filing is based on a 2021 forecast test year, a requested ROE of 10.2%, an equity ratio of 52.50% and an electric rate base of approximately $677 million. Interim rates, subject to refund, of approximately $16 million were implemented on 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: •Retirement 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. •Extending the life of the Monticello nuclear plant from 2030 to 2040. •Continuing to run the PI through current end of life (2033 and 2034). •Construction 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.). •Achieving 780 GWh in energy efficiency savings annually through 2034. •Adding 400 MW of incremental demand response by 2023, and a total of 1,500 MW of demand response by 2034. 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 included the following: •Repower 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. The MPUC is expected to address the solar facilities, ALLETE PPA wind repowering acquisition and the electric vehicle proposal in the second half of 2021. Purchased Power Arrangements and Transmission Service Purchased Power — NSP-Minnesota makes short-term purchases to meet system Purchased Transmission Services — 30 Minnesota State ROFR Statute Complaint — In The complaint challenged the 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 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 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 Wholesale and Commodity Marketing Operations NSP-Minnesota also engages in trading activity unrelated to hedging. Sharing of any Summary of Regulatory Agencies / RTO and Areas of Jurisdiction
Recovery Mechanisms
Pending and Recently Concluded Regulatory Proceedings 2021 Electric Fuel Cost Recovery —In Request to Participate in Utility Money Pool— In
NSP-Wisconsin Solar Proposal — In October 2020, NSP-Wisconsin filed for a 74 MW solar facility build-own-transfer in Wisconsin for approximately $100 million. A PSCW decision is expected Purchased Power Purchased Power — Purchased Transmission Services — Wholesale and Commodity Marketing Operations NSP-Wisconsin does not serve any wholesale requirements customers at cost-based regulated rates. PSCo Summary of Regulatory Agencies / RTO and Areas of Jurisdiction
Recovery Mechanisms
Pending and Recently Concluded Regulatory Proceedings
Additional Information: 2020 Natural Gas Rate Case — In October 2020, the CPUC approved a settlement resulting in a net increase of $77 million. This increase reflects a $94 million increase in base rate revenue, partially offset by $17 million of costs previously recovered through the Pipeline Integrity rider. Rates will be implemented on April 1, 2021 (retroactive to November 2020). 2019 Electric Rate Case — In 2019, PSCo filed a request with the CPUC seeking a net rate increase of approximately $108 million. In February 2020, the CPUC issued an initial decision for a net rate increase of $35 million. In July 2020, the CPUC’s final written decision on rehearing was received and resulted in an additional increase of approximately $12 million annually. In December 2020, the CPUC denied PSCo’s request of a $5 million surcharge for changes to the revenue increase from the effective date of rates, based on the CPUC’s decision on rehearing. PSCo has appealed this decision with the District Court of Denver County. 32 2019 Phase I Electric Rate Case Appeal — In August 2020, PSCo filed an appeal with the Denver District Court seeking a review of CPUC decisions on gain on sales and losses of assets, oil and gas royalty revenues and Board of Director’s equity compensation. PSCo plans to seek consolidation of this appeal with the appeal of the surcharge decision in this same proceeding. 2019 Natural Gas Rate Case Appeal — In April 2019, PSCo filed an appeal seeking judicial review of the CPUC’s prior ruling regarding PSCo’s natural gas rate case (filed in June 2017 and approved in December 2018). The appeal requested review of the following: denial of a return on the prepaid pension and retiree medical assets; the use of a capital structure not based on the actual historical test year; and use of an average rate base methodology rather than a year-end rate base methodology. In March 2020, The District Court of Denver County ruled in favor of allowing the prepaid pension assets to be included in rate base; but upheld the CPUC’s treatment of the retiree medical assets and capital structure methodology. In March 2021, PSCo expects to file a motion to implement the District Court’s decision on treatment of the prepaid pension asset for the applicable period of Jan. 1, 2018 through Oct. 31, 2020. Wildfire Protection Rider —In 2020, PSCo requested to establish a rider to recover incremental costs associated with system investments to reduce wildfire risk. The rider would be effective in June 2021 and continue through 2025. The Office of Consumer Counsel and CPUC Staff are supportive of the wildfire mitigation program as proposed, but oppose rider recovery and instead recommend deferral of certain costs with recovery in a future rate case. A CPUC decision is expected in the second quarter of 2021. Wildfire Protection capital investment is projected to be approximately $325 million. Forecasted annual revenue requirements from 2021 through 2025:
Transportation Electrification Plan — In January 2021, the CPUC approved PSCo's Transportation Electrification Plan, which authorizes rider recovery of new electric vehicle utility programs for the residential, commercial, multi-family and public charging sectors. The approval establishes utility-owned charging infrastructure and chargers and amortization of rebates for electric vehicles. The Transportation Electrification Plan approval authorizes approximately $110 million in spending with flexibility up to approximately $138 million over three years. Advanced Grid Rider In 2020, PSCo requested to establish a rider to recover incremental costs associated with the Advanced Grid Intelligence and Security initiative. The rider would be effective in May 2021 and continue through 2025. In October 2020, an ALJ issued The Recommended Decision granting the Office of Consumer Counsel motion to dismiss the Advanced Grid Rider. PSCo has chosen not to appeal the ALJ’s Recommended Decision. The PSCo portion of the Advanced Grid Intelligence and Security capital investment is projected to be approximately $850 million. Forecasted annual revenue requirements from 2021 through 2025 are as follows:
PSCo KEPCO Filing In September 2020, PSCo filed with the CPUC for approval to terminate a solar PPA with KEPCO Solar of Alamosa, Inc. and establish a regulatory asset to recover transaction costs of approximately $41 million. By terminating the PPA, customers would save approximately $38 million over an 11-year period. A CPUC decision is expected in the second quarter of 2021. Natural Gas LDC and Emission Reductions In October 2020, the CPUC opened a docket to investigate topics related to natural gas emissions in relation to statewide emission reduction goals. The first meeting was held in November 2020, in which subject matter experts discussed greenhouse emission reductions required from the natural gas industry in regard to the statewide goals. Resource Plan PSCo is expected to file its next Electric Resource Plan on March 31, 2021. The filing will propose the future of the remaining coal plants in Colorado and PSCo’s plan to achieve it’s 80% carbon emissions reduction target by 2030. A CPUC decision is expected in 2022. PSCo — Comanche Unit 3 PSCo is part owner and operator of Comanche Unit 3, a 750 MW, coal-fueled electric generating unit. In January 2020, the unit experienced a turbine failure causing the unit to be taken offline for repairs, which were completed in June 2020. During start-up the unit experienced a loss of turbine oil, which damaged the plant. Comanche Unit 3 recommenced operations in January 2021. Replacement and repair of damaged systems in excess of a $2 million deductible are expected to be recovered through insurance policies. PSCo obtained replacement power costs of approximately $16 million during the outage. In October 2020, the CPUC initiated a non-adjudicatory review of Comanche Unit 3’s performance. A report on performance is expected to be issued in March 2021. At this stage of the regulatory review, the resulting recommendations of the CPUC’s staff cannot be determined. Boulder Municipalization In 2011, Boulder passed a ballot measure authorizing the formation of an electric municipal utility. Subsequently, there have been various legal proceedings in multiple venues. In September 2020, the City Council voted to approve a settlement between PSCo and Boulder officials to end the city’s municipalization effort. The settlement resulted in a 20-year franchise arrangement (with multiple opt-out conditions), an energy partnership and an undergrounding agreement. It also established the municipalization process if Boulder exercised an opt-out. In December 2020, PSCo filed the franchise agreement with the CPUC and is currently awaiting a decision. Natural Gas Xcel Energy has 22 natural gas plants with approximately 7,900 MW of total 2020 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 percentage of total fuel requirements:
12 Capacity and Demand Uninterrupted system peak demand and occurrence date for the regulated utilities:
Transmission Transmission lines deliver electricity at higher voltage and over longer distances from power sources to transmission substations closer to homes and businesses. 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. Xcel Energy owns more than 20,000 miles of transmission lines, serving 22,000 MW of customer load. Transmission projects completed in 2020 include:
Notable upcoming projects:
Distribution Distribution lines allow electricity to travel at lower voltages from substations directly to homes and businesses. Xcel Energy has a vast distribution network, owning and operating approximately 210,000 conductor miles of distribution lines across our eight-state service territory, both above ground and underground. 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. Over the five year project, Xcel Energy plans to invest approximately $1.8 billion implementing new network infrastructure, smart meters, advanced software, equipment sensors and related data analytics capabilities. These investments will further improve reliability and reduce outage restoration times for our customers, while at the same time enabling new options and opportunities for increased efficiency savings. The new capabilities will also enable integration of battery storage and other distributed energy resources into the grid, including electric vehicles. 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 in NSP-Minnesota, NSP-Wisconsin and PSCo. Xcel Energy had natural gas deliveries of 444,340 (thousands of MMBtu), 2.1 million customers and natural gas revenues of $1,636 (millions of dollars) for 2020. 13 Sales/Revenue Statistics (a)
(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:
Natural Gas Supply and Cost Xcel Energy seeks natural gas supply, transportation and storage alternatives to yield a diversified portfolio, which increase flexibility, decrease interruption and financial risks and economic customer rates. In addition, the utility subsidiaries conduct natural gas price hedging activities approved by their states’ commissions. Average delivered cost per MMBtu of natural gas for regulated retail distribution:
NSP-Minnesota, NSP-Wisconsin and PSCo have 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.
General Economic Conditions Economic conditions may have a material impact on Xcel Energy’s operating results. Other events impact overall economic conditions and management cannot predict the impact of fluctuating energy prices, terrorist activity, war or the threat of war. We could experience a material impact to our results of operations, future growth or ability to raise capital resulting from a sustained general slowdown in economic growth or a significant increase in interest rates. 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, Xcel Energy’s operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. Competition Xcel Energy is subject to public policies that promote competition and development of energy markets. Xcel Energy’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. Several states have incentives for the development of rooftop solar, community solar gardens and other distributed energy resources. Distributed generating resources are potential competitors to Xcel Energy’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. Xcel Energy’s wholesale customers can purchase their output from generation resources of competing suppliers or non-contracted quantities and use the transmission systems of the utility subsidiaries on a comparable basis to serve their native load. FERC Order No. 1000 established competition for construction and operation of certain new electric transmission facilities. State utility commissions have also created resource planning programs that promote competition for electric generation resources used to provide service to retail customers. Xcel Energy Inc.’s utility subsidiaries have franchise agreements with cities subject to periodic renewal; however, a city could seek alternative means to access electric power or gas, such as municipalization. While each utility subsidiary faces these challenges, Xcel Energy believes their rates and services are competitive with alternatives currently available.
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 substances. Certain Xcel Energy activities require registrations, permits, licenses, inspections and approvals from these agencies. Xcel Energy has received necessary authorizations for the construction and continued operation of its generation, transmission and distribution systems. Our facilities 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. 14 Xcel Energy must comply with emission levels in Minnesota, Texas and Wisconsin that may require the purchase of emission allowances. The Denver North Front Range Non-attainment Area does not meet either the 2008 or 2015 ozone NAAQS. Colorado will continue to consider further reductions available in the non-attainment area as it develops plans to meet ozone standards. Gas plants which operate in PSCo’s non-attainment area may be required to improve or add controls, implement further work practices and/or enhanced emissions monitoring as part of future Colorado state plans. There are significant environmental regulations to encourage use of clean energy technologies and regulate emissions of GHGs. We have 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 required states to develop plans by 2022 for GHG reductions from coal-fired power plants. In a Jan. 19, 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 reviving the Clean Power Plan or proposing additional regulation. It is too early to predict an outcome, but new rules could require substantial additional investment, even in plants slated for retirement. Xcel Energy believes, based on prior state commission practices, the cost of these initiatives or replacement generation would be recoverable through rates. In October 2020, the TCEQ approved an agreement that ensures SPS will convert the Harrington plant from coal to natural gas by Jan. 1, 2025. This conversion is necessary to attain Federal Clean Air Act standards for emissions of SO2. Xcel Energy seeks to address climate change and potential climate change regulation through efforts to reduce its GHG emissions in a balanced, cost-effective manner. In 2020, Xcel Energy estimates that it reduced carbon emissions associated with electric generating resources, both owned and under PPAs, used to serve its customers by approximately 51% from 2005 levels. Environmental Costs Environmental costs include amounts for nuclear plant decommissioning and payments for storage of spent nuclear fuel, disposal of hazardous materials and waste, remediation of contaminated sites, monitoring of discharges to the environment and compliance with laws and permits with respect to emissions. Costs charged to operating expenses for nuclear decommissioning, spent nuclear fuel disposal, environmental monitoring and remediation and disposal of hazardous materials and waste were approximately: •$400 million in 2020. •$345 million in 2019. •$335 million in 2018. Average annual expense of approximately $465 million from 2021 – 2025 is estimated for similar costs. The precise timing and amount of environmental costs, including those for site remediation and disposal of hazardous materials, are unknown. Additionally, the extent to which environmental costs will be included in and recovered through rates may fluctuate. Capital expenditures for environmental improvements were approximately: •$30 million in 2020. •$30 million in 2019. •$50 million in 2018.
See Item 7 for discussion of capital expenditures and funding sources. 15
(a) No family relationships exist between any of the executive officers or directors. (b) Ages as of Feb. 17, 2021. (c) In April 2014, Energy Future Holdings Corp., the majority of its subsidiaries, including TCEH the parent company of Luminant, filed a voluntary bankruptcy petition under Chapter 11 of the United States Bankruptcy Code. TCEH emerged from Chapter 11 in October 2016.
Xcel Energy 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. These risks should be carefully considered together with the other information set forth in this report and future reports that we file with the SEC. Oversight of Risk and Related Processes The Board of Directors is responsible for the oversight of material risk and maintaining an effective risk monitoring process. Management and the Board of Directors’ committees have responsibility for overseeing the identification and mitigation of key risks and reporting its assessments and activities to the full Board of Directors. Xcel Energy 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. Xcel Energy 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 Xcel Energy’s 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 key stakeholders 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. 16 The oversight, management and mitigation of risk is an integral and continuous part of the Board of Directors’ governance of Xcel Energy. The Board of Directors assigns oversight of critical risks to each of its four committees to ensure these risks are well understood and given appropriate focus. The Audit Committee is responsible for reviewing the adequacy of the committee’s risk oversight and affirming appropriate aggregate oversight occurs. Committees regularly report on their oversight activities and certain risk issues may be brought to the full Board of Directors for consideration when deemed appropriate. New risks are considered and assigned as appropriate during the annual Board of Directors and committee evaluation process, resulting in updates to the committee charters and annual work plans. Additionally, the Board of Directors conducts an annual strategy session where Xcel Energy’s future plans and initiatives are reviewed. Risks Associated with Our Business Operational Risks Our natural gas and electric 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. 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. Other uncertainties and risks inherent in operating and maintaining Xcel Energy'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. Xcel Energy’s 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. 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, 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. 17 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 in most of our states, 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, Xcel Energy 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, Xcel Energy cannot fully assure that its controls will be effective against all potential risks, including, without limitation, employee misconduct. If such controls are not effective, Xcel Energy’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. Specialized knowledge is required of our technical employees for construction and operation of transmission, generation and distribution assets. Xcel Energy’s business strategy is dependent on our ability to recruit, retain and motivate employees. There is competition and a tightening market for skilled employees. 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 could impact ongoing operations, restoration operations, our reputation and could introduce financial risk or risks of fines. Our subsidiary, NSP-Minnesota, is 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 NSP-Minnesota’s 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 NSP-Minnesota’s compliance costs. Financial Risks Our profitability depends on the ability of our utility subsidiaries to recover their costs and changes in regulation may impair the ability of our utility subsidiaries to recover costs from their 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 utility operations is dependent on our ability to recover the costs of providing energy and utility services and earning a return on capital investment. Our rates are generally regulated and are based on an analysis of the utility’s costs incurred in a test year. The utility subsidiaries are subject to both future and historical test years depending upon the regulatory jurisdiction. Thus, the rates a utility is allowed to charge may or may not match its 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 the costs of our utility subsidiaries 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 the ability of our utility subsidiaries to recover costs historically collected from customers, or these subsidiaries could exceed caps on capital costs required by commissions and result in less than full recovery. 18 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, higher than expected inflation or tariffs may increase costs of construction and operations. Also, rising fuel costs could increase the risk that our utility subsidiaries will not be able to fully recover their fuel costs from their 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 and the payment of dividends on common stock. Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships. We cannot be assured that our current credit ratings or our subsidiaries’ 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, 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 and could impact our ability to access capital markets. Also, our utility subsidiaries 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. 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 NSP-Minnesota’s 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 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. Xcel Energy 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. California Independent System Operator, SPP, 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. 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, would trigger settlement accounting and could require Xcel Energy 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. We must rely on cash from our subsidiaries to make dividend payments. Investments in our subsidiaries are our primary assets. Substantially all of our operations are conducted by our subsidiaries. Consequently, our operating cash flow and ability to service our debt and pay dividends depends upon the operating cash flows of our subsidiaries and their payment of dividends. Our subsidiaries are separate legal entities that have no obligation to pay any amounts due pursuant to our obligations or to make any funds available for dividends on our common stock. In addition, each subsidiary’s ability to pay dividends depends on statutory and/or contractual restrictions which may include requirements to maintain minimum levels of equity ratios, working capital or assets. If the utility subsidiaries were to cease making dividend payments, our ability to pay dividends on our common stock or otherwise meet our financial obligations could be adversely affected. Our utility subsidiaries are regulated by state utility commissions, which possess broad powers to ensure that the needs of the utility customers are met. We may be negatively impacted by the actions of state commissions that limit the payment of dividends by our utility subsidiaries. 19 Federal tax law may significantly impact our business. Our utility subsidiaries collect estimated federal, state and local tax payments through their regulated rates. Changes to federal tax law may benefit or adversely affect our earnings and customer costs. Tax depreciable lives and the value 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. Xcel Energy’s 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. Our utility subsidiaries face 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 impacting countries, communities, supply chains and markets. A high degree of uncertainty continues to exist regarding the pandemic, the duration and magnitude of business restrictions, re-shut downs, if any, and the level and pace of economic recovery. While we are implementing contingency plans, there are no guarantees these plans will be sufficient to offset the impact of COVID-19. Although the impact of the pandemic to the 2020 results was largely 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 (particularly in Colorado), 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. Xcel Energy participates in grid security and emergency response exercises (GridEx). These efforts, led by the NERC, test and further develop the coordination, threat sharing and interaction between utilities and various government agencies relative to potential cyber and physical threats against the nation’s electric grid. A cyber incident or security breach could have a material effect on our business. We operate in an industry that requires the continued operation of sophisticated information technology, control systems and network infrastructure. In addition, we use our systems and infrastructure to create, collect, use, disclose, store, dispose of and otherwise process sensitive information, including company data, customer energy usage data, and personal information regarding customers, employees and their dependents, contractors, shareholders and other individuals. Xcel Energy’s 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. The utility industry has been the target of several attacks on operational systems and has seen an increased volume and sophistication of cyber security incidents from international activist organizations, Nation States and individuals. Cyber security incidents could harm our businesses by limiting our generating, transmitting and distributing capabilities, delaying our development and construction of new facilities or capital improvement projects to existing facilities, disrupting our customer operations or causing the release of customer information, all of which would likely receive state and federal regulatory scrutiny and could expose us to liability. 20 Xcel Energy’s 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 causesignificant additional costs (e.g., penalties, third-party claims, repairs, insurance or compliance) and potentially disrupt our supply and markets for natural gas, oil and other fuels. We maintain security measures to protect our information technology and control systems, network infrastructure and other assets. However, these assets and the information they process may be vulnerable to 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. The Biden Administration will establish a new nationally determined contribution for the United States. The Paris Agreement 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 Xcel Energy 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. 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. 21 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. 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 Xcel Energy 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. We may not recover all costs related to mitigating these physical and financial risks.
None.
Virtually all of the utility plant property of the operating companies is subject to the lien of their respective first mortgage bond indentures.
(a)Summer 2020 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. 22
(a)Summer 2020 net dependable capacity. (b)Refuse-derived fuel is made from municipal solid waste.
(a) Summer 2020 net dependable capacity. (b)In 2018, the CPUC approved early retirement of PSCo’s Comanche Units 1 and 2 in 2022 and 2025, respectively. (c) Based on PSCo’s ownership of 67%. (d) Craig Unit 1 and 2 are expected to be retired early in 2025 and 2028, respectively. (e) Based on PSCo’s ownership of 10%. (f) Based on PSCo’s ownership of 76% of Unit 1 and 37% of Unit 2. (g) Values disclosed are the generation levels at the point-of-interconnection. Capacity is attainable only when wind conditions are sufficiently available (on-demand net dependable capacity is zero). (h)Hayden Unit 1 and 2 are expected to be retired in 2028 and 2027, respectively.
(a) Summer 2020 net dependable capacity. (b) Harrington is expected to be converted to natural gas by the end of 2024. (c) 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) (d) Tolk Unit 1 and 2 are expected to be retired in 2032. Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2020:
Electric utility transmission and distribution substations at Dec. 31, 2020:
Natural gas utility mains at Dec. 31, 2020:
23
Xcel Energy 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 Xcel Energy’s financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred. See Note 12 to the consolidated financial statements, Item 1 and Item 7 for further information.
None. PART II
Stock Data Xcel Energy Inc.’s common stock is listed on the Nasdaq Global Select Market (Nasdaq). The trading symbol is XEL. The number of common stockholders of record as of Feb. 12, 2021 was approximately 52,689. The following compares our cumulative TSR on common stock with the cumulative TSR of the EEI Investor-Owned Electrics Index and the S&P 500 Composite Stock Price Index over the last five years. The EEI Investor-Owned Electrics Index (market capitalization-weighted) included 39 companies at year-end and is a broad measure of industry performance. Comparison of Five Year Cumulative Total Return* * $100 invested on Dec. 31, 2015 in stock or index — including reinvestment of dividends. Fiscal years ended Dec. 31. Purchases of Equity Securities by Issuer and Affiliated Purchasers For the quarter ended Dec. 31, 2020, no equity securities that are registered by Xcel Energy Inc. pursuant to Section 12 of the Securities Exchange Act of 1934 were purchased by or on behalf of us or any of our affiliated purchasers.
Selected financial data for Xcel Energy related to the five most recent years ended Dec. 31:
(a) As a result of adopting ASU No. 2017-07 (Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, Topic 715), $33 million and $26 million of pension costs were retrospectively reclassified from O&M expenses to other income, net on the consolidated statements of income for the years ended Dec. 31, 2017 and Dec. 31, 2016, respectively. (b) As a result of adopting Leases, Topic 842, finance lease obligations of $77 million are included in other noncurrent liabilities on the consolidated balance sheet at Dec. 31, 2019. These obligations were included in long-term debt prior to 2019. 24
Non-GAAP Financial Measures The following discussion includes financial information prepared in accordance with GAAP, as well as certain non-GAAP financial measures such as ongoing ROE, electric margin, natural gas margin, ongoing earnings and ongoing diluted EPS. 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. Xcel Energy’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. Ongoing ROE Ongoing ROE is calculated by dividing the net income or loss of Xcel Energy or each subsidiary, adjusted for certain nonrecurring items, by each entity’s average stockholder’s equity. We use these non-GAAP financial measures to evaluate and provide details of earnings results. 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 and Ongoing Diluted EPS) GAAP diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock (i.e., common stock equivalents) were settled. The weighted average number of potentially dilutive shares outstanding used to calculate Xcel Energy Inc.’s diluted EPS is calculated using the treasury stock method. Ongoing earnings reflect adjustments to GAAP earnings (net income) for certain items. Ongoing diluted EPS is calculated by dividing the net income or loss of each subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period. Ongoing diluted EPS for each subsidiary is calculated by dividing the net income or loss of such subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period. We use these non-GAAP financial measures to evaluate and provide details of Xcel Energy’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 our subsidiaries. For the years ended Dec. 31, 2020 and 2019, there were no such adjustments to GAAP earnings and therefore GAAP earnings equal ongoing earnings.
Diluted EPS for Xcel Energy at Dec. 31:
(a) Amounts may not add due to rounding. Xcel Energy’s management believes that ongoing earnings reflects management’s performance in operating Xcel Energy and provides a meaningful representation of the performance of Xcel Energy’s core business. In addition, Xcel Energy’s management uses ongoing earnings internally for financial planning and analysis, reporting results to the Board of Directors and when communicating its earnings outlook to analysts and investors. 2020 Comparison with 2019 Xcel Energy — GAAP and ongoing earnings increased $0.15 per share, primarily reflecting higher electric margin (largely due to regulatory outcomes which recover capital investment), higher AFUDC and lower O&M expenses, which offset increased depreciation, interest expense and declining sales primarily due to the impacts of COVID-19. NSP-Minnesota — Earnings increased $0.08 per share for 2020, reflecting higher electric margin (riders, wholesale transmission revenue and a sales true-up mechanism, which recovers lower sales due to COVID-19) and lower O&M expenses, partially offset by increased depreciation and lower natural gas margin. PSCo — Earnings were flat for 2020, reflecting higher electric margin (wholesale transmission revenue and regulatory outcomes offset lower sales due to COVID-19), increased AFUDC and higher natural gas margin, offset by additional depreciation and taxes (other than income taxes). SPS — Earnings increased $0.05 per share for 2020, reflecting higher electric margin (wholesale transmission revenue and regulatory outcomes offset lower sales due to COVID-19) and lower O&M expenses, partially offset by increased depreciation, interest expense and taxes (other than income taxes). NSP-Wisconsin — Earnings increased $0.05 per share for 2020, reflecting higher electric margin (regulatory outcomes offset lower sales due to COVID-19) and lower O&M expenses, partially offset by increased depreciation and lower natural gas margin. Xcel Energy Inc. and Other — Primarily includes financing costs at the holding company. 25 Changes in Diluted EPS Components significantly contributing to changes in EPS:
(a)Change in electric margin was negatively impacted by reductions in sales and demand due to COVID-19 and is detailed below. Sales decline excludes weather impact, net of decoupling/sales true-up and reduction in demand revenue is net of sales true-up.
(b) Includes PTCs and tax reform regulatory amounts, which are primarily offset in electric margin. ROE for Xcel Energy and its utility subsidiaries:
Statement of Income Analysis The following summarizes the items that affected the individual revenue and expense items reported in the consolidated statements of income. Estimated Impact of Temperature Changes on Regulated Earnings — Unusually hot summers or cold winters increase electric and natural gas sales, while mild weather reduces electric and natural gas sales. The estimated impact of weather on earnings is based on the number of customers, temperature variances, the amount of natural gas or electricity historically used per degree of temperature and excludes any incremental related operating expenses that could result due to storm activity or vegetation management requirements. As a result, weather deviations from normal levels can affect Xcel Energy’s financial performance to the extent there is not a decoupling or sales true-up mechanism in the state. Degree-day or THI data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day’s average temperature and humidity. HDD is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit. CDD is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65° Fahrenheit. Each degree of temperature above 65° Fahrenheit is counted as one CDD, and each degree of temperature below 65° Fahrenheit is counted as one HDD. In Xcel Energy’s more humid service territories, a THI is used in place of CDD, which adds a humidity factor to CDD. HDD, CDD and THI are most likely to impact the usage of Xcel Energy’s residential and commercial customers. Industrial customers are less sensitive to weather. Normal weather conditions are defined as either the 10, 20 or 30-year average of actual historical weather conditions. The historical period of time used in the calculation of normal weather differs by jurisdiction, based on regulatory practice. To calculate the impact of weather on demand, a demand factor is applied to the weather impact on sales. Extreme weather variations, windchill and cloud cover may not be reflected in weather-normalized estimates. Percentage (decrease) increase in normal and actual HDD, CDD and THI:
Weather — Estimated impact of temperature variations on EPS compared with normal weather conditions:
Sales — Sales growth (decline) for actual and weather-normalized sales:
26
(a) Higher residential sales and lower C&I sales were primarily attributable to COVID-19. The increase in residential sales was partially driven by more customers working from home. Weather-normalized and leap-year adjusted electric sales growth (decline) — year-to-date (excluding leap day) •PSCo — Residential sales rose based on an increased number of customers and higher use per customer. The decline in C&I sales was primarily due to COVID-19, particularly within the manufacturing and service industries, partially offset by an increase in the energy sector. •NSP-Minnesota — Residential sales rose based on an increased number of customers and higher use per customer. The decline in C&I sales was primarily due to COVID-19, particularly within the energy, manufacturing and services sectors. •SPS — Residential sales rose based on an increased number of customers and higher use per customer. The decline in C&I sales was primarily due to COVID-19, particularly within the energy and manufacturing sectors. •NSP-Wisconsin — Residential sales rose based on an increased number of customers and higher use per customer. The decline in C&I sales was primarily due to COVID-19, particularly within the energy and manufacturing sectors. Weather-normalized and leap-year adjusted natural gas sales growth (decline) — year-to-date (excluding leap day) •Higher natural gas sales reflect an increase in the number of customers combined with higher residential customer use, partially offset by lower C&I customer use. Electric Margin Electric revenues and fuel and purchased power expenses are impacted by fluctuations in the price of natural gas, coal and uranium. However, these fluctuations have minimal impact on margin due to fuel recovery mechanisms. In addition, electric customers receive a credit for PTCs generated, which reduce electric revenue and margin (offset by lower tax expense). Electric revenues and margin:
Changes in Electric Margin
(a) Includes approximately $70 million of revenue and margin due to the Texas rate case outcome, which is largely offset by recognition of previously deferred costs. (b) Sales excludes weather impact, net of decoupling/sales true-up, and demand revenue is net of sales true-up. Natural Gas Margin Natural gas expense varies with changing sales and cost of natural gas. However, fluctuations in the cost of natural gas has minimal impact on margin due to cost recovery mechanisms. Natural gas revenues and margin:
Changes in Natural Gas Margin
27 Non-Fuel Operating Expenses and Other Items O&M Expenses — O&M expenses decreased $14 million, or 0.6%, for 2020, largely reflecting management actions to reduce costs to offset the impact of lower sales from COVID-19. Significant changes are as follows:
•Distribution declined due to cost mitigation/continuous improvement efforts and timing of maintenance, partially offset by increased storm impacts. •Generation was lower from timing of maintenance and overhauls at power plants and cost mitigation/continuous improvement efforts, partially offset by an increase in maintenance expenses from wind expansion. •Transmission declined due to cost mitigation/continuous improvement initiatives. •Minnesota payment plan credit program represents a commitment to fund customer programs as agreed to in the NSP-Minnesota rate case stay-out. •Information technology costs increased due to higher spending on network and other infrastructure costs. •Employee benefits increased due primarily to postretirement costs and other long-term benefits, partially offset by lower deferred compensation expense. Depreciation and Amortization — Depreciation and amortization increased $183 million, or 10.4%, year-to-date. The increase was primarily driven by the Hale, Cheyenne Ridge, Foxtail, Blazing Star I, Lake Benton, Sagamore, Crowned Ridge, Community Wind North and Jeffers wind facilities going into service, as well as normal system expansion. In addition, new depreciation rates were implemented in Colorado, New Mexico and Texas in 2020, increasing expense. Taxes (Other than Income Taxes) — Taxes (other than income taxes) increased $43 million, or 7.6%, year-to-date. The increase was primarily due to higher property taxes in Colorado and Texas (net of deferred amounts). Other Income (Expense) — Other income (expense) decreased $22 million year-to-date. The decrease was largely due to the performance of rabbi trust investments, primarily offset in O&M expenses. AFUDC, Equity and Debt — AFUDC increased $43 million year-to-date. The increase was primarily due to various wind projects under construction. Interest Charges — Interest charges increased $67 million, or 8.7%, 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 taxes decreased $134 million for 2020. The decrease was primarily driven by an increase in wind PTCs and an increase in plant-related regulatory differences. Xcel Energy Inc. and Other Results Net income and diluted EPS contributions of Xcel Energy Inc. and its nonregulated businesses:
(a)MEC was sold in the third quarter of 2020. (b)Amounts include gains or losses associated with sales of properties held by Eloigne. Xcel Energy Inc.’s results include interest charges, which are incurred at Xcel Energy Inc. and are not directly assigned to individual subsidiaries. 2019 Comparison with 2018 A discussion of changes in Xcel Energy’s results of operations, cash flows and liquidity and capital resources from the year ended Dec. 31, 2018 to Dec. 31, 2019 can be found in Part II, “Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our Annual Report on Form 10-K for the fiscal year 2019, which was filed with the SEC on Feb. 21, 2020. However, such discussion is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K.
The FERC and various state and local regulatory commissions regulate Xcel Energy Inc.’s utility subsidiaries and WGI. Xcel Energy 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, South Dakota, Wisconsin, Michigan, Colorado, New Mexico, and Texas. Rates are designed to recover plant investment, operating costs and an allowed return on investment. Our utility subsidiaries request changes in rates for utility services through filings with governing commissions. Changes in operating costs can affect Xcel Energy’s financial results, depending on the timing of rate case filings 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 Xcel Energy’s results of operations. See Rate Matters within Note 12 to the consolidated financial statements for further information. 28 NSP-Minnesota Summary of Regulatory Agencies / RTO and Areas of Jurisdiction
Recovery Mechanisms
(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
29 Additional Information: 2020 Minnesota Electric Rate Case and Stay-Out Alternative — In November 2020, NSP-Minnesota filed an 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% and a 52.5% equity ratio. NSP-Minnesota also filed a stay-out alternative in which it would withdraw its rate case filing. In December 2020, 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 increase to the Nuclear Decommissioning Trust annual accrual until Jan. 1, 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. 2020 North Dakota Electric Rate Case — In November 2020, NSP-Minnesota filed a request with the NDPSC for an overall increase in annual retail electric revenues of approximately $22 million, or an increase of 10.8%. The rate filing is based on a 2021 forecast test year, a requested ROE of 10.2%, an equity ratio of 52.50% and an electric rate base of approximately $677 million. Interim rates, subject to refund, of approximately $16 million were implemented on 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: •Retirement 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. •Extending the life of the Monticello nuclear plant from 2030 to 2040. •Continuing to run the PI through current end of life (2033 and 2034). •Construction 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.). •Achieving 780 GWh in energy efficiency savings annually through 2034. •Adding 400 MW of incremental demand response by 2023, and a total of 1,500 MW of demand response by 2034. 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 included the following: •Repower 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. The MPUC is expected to address the solar facilities, ALLETE PPA wind repowering acquisition and the electric vehicle proposal in the second half of 2021. 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. 30 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. 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 JOA. NSP-Minnesota does not serve any wholesale requirements customers at cost-based regulated rates. NSP-Wisconsin Summary of Regulatory Agencies / RTO and Areas of Jurisdiction
Recovery Mechanisms
31 Pending and Recently Concluded Regulatory Proceedings 2021 Electric Fuel Cost Recovery —In December 2020, the PSCW approved the NSP-Wisconsin application to update its 2021 fuel cost and decrease retail electric rates for 2021 by approximately $12 million. Request to Participate in Utility Money Pool— In October 2020, the PSCW approved NSP-Wisconsin’s application to participate in the Money Pool. NSP-Wisconsin Solar Proposal — In October 2020, NSP-Wisconsin filed for a 74 MW solar facility build-own-transfer in Wisconsin for approximately $100 million. A PSCW decision is expected in the third quarter of 2021. Purchased Power and Transmission Services The NSP System expects to use power plants, power purchases, conservation and DSM options, new generation facilities and expansion of power plants to meet its system capacity requirements. Purchased Power — Through the Interchange Agreement, NSP-Wisconsin receives power purchased by NSP-Minnesota from other utilities and independent power producers. Long-term purchased power contracts for dispatchable resources typically require a capacity charge 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. Wholesale and Commodity Marketing Operations NSP-Wisconsin does not serve any wholesale requirements customers at cost-based regulated rates. PSCo Summary of Regulatory Agencies / RTO and Areas of Jurisdiction
Recovery Mechanisms
Pending and Recently Concluded Regulatory Proceedings
Additional Information: 2020 Natural Gas Rate Case — In October 2020, the CPUC approved a settlement resulting in a net increase of $77 million. This increase reflects a $94 million increase in base rate revenue, partially offset by $17 million of costs previously recovered through the Pipeline Integrity rider. Rates will be implemented on April 1, 2021 (retroactive to November 2020). 2019 Electric Rate Case — In 2019, PSCo filed a request with the CPUC seeking a net rate increase of approximately $108 million. In February 2020, the CPUC issued an initial decision for a net rate increase of $35 million. In July 2020, the CPUC’s final written decision on rehearing was received and resulted in an additional increase of approximately $12 million annually. In December 2020, the CPUC denied PSCo’s request of a $5 million surcharge for changes to the revenue increase from the effective date of rates, based on the CPUC’s decision on rehearing. PSCo has appealed this decision with the District Court of Denver County. 32 2019 Phase I Electric Rate Case Appeal — In August 2020, PSCo filed an appeal with the Denver District Court seeking a review of CPUC decisions on gain on sales and losses of assets, oil and gas royalty revenues and Board of Director’s equity compensation. PSCo plans to seek consolidation of this appeal with the appeal of the surcharge decision in this same proceeding. 2019 Natural Gas Rate Case Appeal — In April 2019, PSCo filed an appeal seeking judicial review of the CPUC’s prior ruling regarding PSCo’s natural gas rate case (filed in June 2017 and approved in December 2018). The appeal requested review of the following: denial of a return on the prepaid pension and retiree medical assets; the use of a capital structure not based on the actual historical test year; and use of an average rate base methodology rather than a year-end rate base methodology. In March 2020, The District Court of Denver County ruled in favor of allowing the prepaid pension assets to be included in rate base; but upheld the CPUC’s treatment of the retiree medical assets and capital structure methodology. In March 2021, PSCo expects to file a motion to implement the District Court’s decision on treatment of the prepaid pension asset for the applicable period of Jan. 1, 2018 through Oct. 31, 2020. Wildfire Protection Rider —In 2020, PSCo requested to establish a rider to recover incremental costs associated with system investments to reduce wildfire risk. The rider would be effective in June 2021 and continue through 2025. The Office of Consumer Counsel and CPUC Staff are supportive of the wildfire mitigation program as proposed, but oppose rider recovery and instead recommend deferral of certain costs with recovery in a future rate case. A CPUC decision is expected in the second quarter of 2021. Wildfire Protection capital investment is projected to be approximately $325 million. Forecasted annual revenue requirements from 2021 through 2025:
Transportation Electrification Plan — In January 2021, the CPUC approved PSCo's Transportation Electrification Plan, which authorizes rider recovery of new electric vehicle utility programs for the residential, commercial, multi-family and public charging sectors. The approval establishes utility-owned charging infrastructure and chargers and amortization of rebates for electric vehicles. The Transportation Electrification Plan approval authorizes approximately $110 million in spending with flexibility up to approximately $138 million over three years. Advanced Grid Rider In 2020, PSCo requested to establish a rider to recover incremental costs associated with the Advanced Grid Intelligence and Security initiative. The rider would be effective in May 2021 and continue through 2025. In October 2020, an ALJ issued The Recommended Decision granting the Office of Consumer Counsel motion to dismiss the Advanced Grid Rider. PSCo has chosen not to appeal the ALJ’s Recommended Decision. The PSCo portion of the Advanced Grid Intelligence and Security capital investment is projected to be approximately $850 million. Forecasted annual revenue requirements from 2021 through 2025 are as follows:
PSCo KEPCO Filing In September 2020, PSCo filed with the CPUC for approval to terminate a solar PPA with KEPCO Solar of Alamosa, Inc. and establish a regulatory asset to recover transaction costs of approximately $41 million. By terminating the PPA, customers would save approximately $38 million over an 11-year period. A CPUC decision is expected in the second quarter of 2021. Natural Gas LDC and Emission Reductions In October 2020, the CPUC opened a docket to investigate topics related to natural gas emissions in relation to statewide emission reduction goals. The first meeting was held in November 2020, in which subject matter experts discussed greenhouse emission reductions required from the natural gas industry in regard to the statewide goals. Resource Plan PSCo is expected to file its next Electric Resource Plan on March 31, 2021. The filing will propose the future of the remaining coal plants in Colorado and PSCo’s plan to achieve it’s 80% carbon emissions reduction target by 2030. A CPUC decision is expected in 2022. PSCo — Comanche Unit 3 PSCo is part owner and operator of Comanche Unit 3, a 750 MW, coal-fueled electric generating unit. In January 2020, the unit experienced a turbine failure causing the unit to be taken offline for repairs, which were completed in June 2020. During start-up the unit experienced a loss of turbine oil, which damaged the plant. Comanche Unit 3 recommenced operations in January 2021. Replacement and repair of damaged systems in excess of a $2 million deductible are expected to be recovered through insurance policies. PSCo obtained replacement power costs of approximately $16 million during the outage. In October 2020, the CPUC initiated a non-adjudicatory review of Comanche Unit 3’s performance. A report on performance is expected to be issued in March 2021. At this stage of the regulatory review, the resulting recommendations of the CPUC’s staff cannot be determined. Boulder Municipalization In 2011, Boulder passed a ballot measure authorizing the formation of an electric municipal utility. Subsequently, there have been various legal proceedings in multiple venues. In September 2020, the City Council voted to approve a settlement between PSCo and Boulder officials to end the city’s municipalization effort. The settlement resulted in a 20-year franchise arrangement (with multiple opt-out conditions), an energy partnership and an undergrounding agreement. It also established the municipalization process if Boulder exercised an opt-out. In December 2020, PSCo filed the franchise agreement with the CPUC and is currently awaiting a decision. Purchased Power and Transmission Service Providers PSCo expects to meet its system capacity requirements through electric generating stations, power purchases, new generation facilities, DSM options and expansion of generation plants. Purchased Power — PSCo purchases power from other utilities and IPPs. Long-term purchased power contracts for dispatchable resources typically require capacity and energy charges. It also contracts to purchase power for both wind and solar resources. PSCo makes short-term purchases to meet system load and energy requirements, replace owned generation, meet operating reserve obligations, or obtain energy at a lower cost. 33 Energy Markets — PSCo is working towards joining the Western Energy Imbalance Market in 2022. This market was developed by the California ISO and allows PSCo access to a real-time energy market. The Western Energy Imbalance Market allows participants to buy and sell power close to the time electricity is consumed and gives system operators real-time visibility across neighboring grids. The result improves balancing supply and demand at a lower cost. Purchased Transmission Services — In addition to using its own transmission system, PSCo has contracts with regional transmission service providers to deliver energy to its customers. Wholesale and Commodity Marketing Operations PSCo conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy related products. PSCo uses physical and financial instruments to minimize commodity price and credit risk and hedge sales and purchases. PSCo also engages in trading activity unrelated to hedging. Sharing of any margin is determined through state regulatory proceedings as well as the operation of the FERC approved JOA. SPS Summary of Regulatory Agencies / RTO and Areas of Jurisdiction
Recovery Mechanisms
Pending and Recently Concluded Regulatory Proceedings
Additional Information: 2019 New Mexico Electric Rate Case — In May 2020, the NMPRC approved a settlement between SPS and intervening parties, which reflects the following terms: a base rate increase of $31 million, an ROE of 9.45% and an equity ratio of 54.77%. New rates and tariffs were effective in May 2020. 2019 Texas Electric Rate Case — In August 2020, the PUCT approved a settlement between SPS and intervening parties, which reflects the following terms: a rate increase of $88 million; ROE of 9.45% and equity ratio of 54.62% for AFUDC purposes. In December 2020, SPS filed to surcharge the final under-recovered amount, estimated to be approximately $72 million, offset by the recognition of previously deferred costs. 2021 New Mexico Electric Rate Case — On Jan. 4, 2021, SPS filed an electric rate case with the NMPRC seeking an increase in base rates of approximately $88 million. SPS' net rate increase to New Mexico customers is expected to be approximately $48 million, or 10%, as a result of offsetting fuel cost reductions and PTCs attributable to wind energy provided by the Sagamore wind project. PTCs are being credited to customers through the fuel clause. The request is based on a historic test year ended Sept. 30, 2020, including expected capital additions through Feb. 28, 2021, a ROE of 10.35%, an equity ratio of 54.72% and retail rate base of approximately $1.9 billion (total company rate base of approximately $6.0 billion). Additionally, the request includes the effect of approximately 400 MW of reduced peak load in 2021 from a wholesale transmission customer and changes to depreciation rates to reflect a reduction to the service lives of SPS’ Tolk power plant (from 2037 to 2032) and the coal handling assets at the Harrington facility (to 2024). The NMPRC suspended new rates for nine months beyond the 30-day notice period, consistent with historic practice. The next steps in the procedural schedule are expected to be as follows: •Staff and intervenor testimony — May 17, 2021. •Rebuttal testimony — June 9, 2021. •Deadline to file stipulation — June 23, 2021. •Public hearing or hearing on stipulation — July 26 - Aug. 6, 2021. •End of nine month suspension — Nov. 3, 2021. A NMPRC decision and implementation of final rates is anticipated in the fourth quarter of 2021. 2021 Texas Rate Case— On Feb. 8, 2021, SPSfiled an electric rate case with the PUCT and its 81 municipalities with original rate jurisdiction seeking an increase in base rates of approximately $143 million. SPS' net rate increase to Texas customers is expected to be approximately $74 million, or 9.2%, as a result of offsetting $69 million in fuel cost reductions and PTCs from the Sagamore wind project. 34 The request is primarily driven by additional capital investment in new and upgraded electric facilities and equipment since SPS’ previous rate case in 2019, including the 522 MW Sagamore wind project. The request is based on an ROE of 10.35%, an equity ratio of 54.60% (based on actual capital structure), a Texas retail rate base of approximately $3.3 billion and a historic test year based on the 12-month period ended Dec. 31, 2020 (with the final three months based on estimates). In March 2021, SPS will file to update estimates to actuals through Dec. 31, 2020. Additionally, the request includes the effect of approximately 400 MW from a wholesale transmission customer and changes to depreciation rates to reflect a reduction to the service lives of SPS’ Tolk power plant (from 2037 to 2032) and the coal handling assets of the Harrington facility (to 2024). Summary of SPS’ request:
SPS is requesting the PUCT set current rates as temporary on March 15, 2021. Once final rates are approved, a surcharge will be requested from March 15, 2021 through the effective date of new base rates. A PUCT decision is expected in the first quarter of 2022. Texas State ROFR Litigation — In May 2019, the Governor signed a ROFR bill into law, which grants incumbent utilities a ROFR to build transmission infrastructure when it directly interconnects to the utility’s existing facility. In June 2019, a complaint was filed in the United States District Court for the Western District of Texas claiming the new ROFR law to be unconstitutional. In February 2020, the federal court complaint was dismissed by the district court. In March 2020, the district court ruling was appealed to the Fifth Circuit. A decision is pending. New Mexico FPPCAC Continuation — In December 2020, the Hearing Examiner recommended the NMPRC approve SPS’ request for the continued use of the FPPCAC and the reconciliation of its fuel costs for the reporting period (September 2015 through June 2019). Additionally, the Hearing Examiner recommended the NMPRC deny the proposed Annual Deferred Fuel Balance True-Up. The proposed true-up is designed to maintain the Deferred Fuel and Purchased Power balance within a bandwidth of plus or minus 5% of annual New Mexico fuel and purchased power costs. A decision is pending. Resource Plan — SPS is required to file an IRP in New Mexico every three years and will file its next IRP in July 2021. Purchased Power Arrangements and Transmission Service Providers SPS expects to use electric generating stations, power purchases, DSM and new generation options to meet its system capacity requirements. Purchased Power — SPS purchases power from other utilities and IPPs. Long-term purchased power contracts typically require periodic capacity and energy charges. SPS also makes short-term purchases to meet system load and energy requirements to replace owned generation, meet operating reserve obligations or obtain energy at a lower cost. Purchased Transmission Services — SPS has contractual arrangements with SPP and regional transmission service providers to deliver power and energy to its native load customers. Natural Gas SPS does not provide retail natural gas service, but purchases and transports natural gas for its generation facilities and operates natural gas pipeline facilities connecting the generation facilities to interstate natural gas pipelines. SPS is subject to the jurisdiction of the FERC with respect to natural gas transactions in interstate commerce and the PHMSA and PUCT for pipeline safety compliance. SPS conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy related products. SPS uses physical and financial instruments to minimize commodity price and credit risk and to hedge sales and purchases.
Preparation of the consolidated financial statements requires the application of accounting rules and guidance, as well as the use of estimates. Application of these policies involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges and anticipated recovery of costs. These judgments could materially impact the consolidated financial statements, based on varying assumptions. In addition, the financial and operating environment also may have a significant effect on the operation of the business and results reported. Accounting policies and estimates that are most significant to Xcel Energy’s results of operations, financial condition or cash flows, and require management’s most difficult, subjective or complex judgments are outlined below. Each of these has a higher likelihood of resulting in materially different reported amounts under different conditions or using different assumptions. Each critical accounting policy has been reviewed and discussed with the Audit Committee of Xcel Energy Inc.’s Board of Directors on a quarterly basis. Regulatory Accounting Xcel Energy is subject to the accounting for Regulated Operations, which 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. Our rates are derived through the ratemaking process, which results 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. In other businesses or industries, regulatory assets and regulatory liabilities would generally be charged to net income or other comprehensive income. 35 Each reporting period we assess the probability of future recoveries and obligations associated with regulatory assets and liabilities. Factors such as the current regulatory environment, recently issued rate orders and historical precedents are considered. Decisions made by regulatory agencies can directly impact the amount and timing of cost recovery as well as the rate of return on invested capital, and may materially impact our results of operations, financial condition or cash flows. As of Dec. 31, See Note 4 to the consolidated financial statements for further information. Income Tax Accruals Judgment, uncertainty and estimates are a significant aspect of the income tax accrual process that accounts for the effects of current and deferred income taxes. Uncertainty associated with the application of tax statutes and regulations and outcomes of tax audits and appeals require that judgment and estimates be made in the accrual process and in the calculation of the ETR. Changes in tax laws and rates may affect recorded deferred tax assets and liabilities and our future ETR. ETR calculations are revised every quarter based on best available year-end tax assumptions, adjusted in the following year after returns are filed. In accordance with the interim period reporting guidance, income tax expense for the first three quarters in a year is based on the forecasted annual ETR. The forecasted ETR reflects a number of estimates, including forecasted annual income, permanent tax adjustments and tax credits. Valuation allowances are applied to deferred tax assets if it is more likely than not that at least a portion may not be realized based on an evaluation of expected future taxable income. Accounting for income taxes also requires that only tax benefits that meet the more likely than not recognition threshold can be recognized or continue to be recognized. We may adjust our unrecognized tax benefits and interest accruals as disputes with the IRS and state tax authorities are resolved, and as new developments occur. These adjustments may increase or decrease earnings. See Note 7 to the consolidated financial statements for further information. Employee Benefits We sponsor several noncontributory, defined benefit pension plans and other postretirement benefit plans that cover almost all employees and certain retirees. Projected benefit costs are based on historical information and actuarial calculations that include key assumptions (annual return level on pension and postretirement health care investment assets, discount rates, mortality rates and health care cost trend rates, etc.). In addition, the pension cost calculation uses a methodology to reduce the volatility of investment performance over time. Pension assumptions are continually reviewed. At Dec. 31, Xcel Energy’s pension investment strategy is based on plan-specific investments that seek to minimize investment and interest rate risk as a plan’s funded status increases over time. This strategy results in a greater percentage of interest rate sensitive securities being allocated to plans with a higher funded status and a greater percentage of growth assets being allocated to plans having a lower funded status ratios. Xcel Energy set the discount rates used to value the pension obligations at The effective yield on this cash flow matched bond portfolio determines the discount rate for the individual plans. The bond matching study is validated for reasonableness against the Merrill Lynch Corporate 15+ Bond Index. In addition, Xcel Energy reviews general actuarial survey data to assess the reasonableness of the discount rate selected. If Xcel Energy were to use alternative assumptions, a 1% change would result in the following impact on
Mortality rates are developed from actual and projected plan experience for pension plan and postretirement benefits. Xcel Energy’s actuary conducts an experience study periodically As of Dec. 31,
36 The pension cost calculation uses a market-related valuation of pension assets. Xcel Energy uses a calculated value method to determine the market-related value of the plan assets. The market-related value is determined by adjusting the fair market value of assets at the beginning of the year to reflect the investment gains and losses (the difference between the actual investment return and the expected investment return on the market-related value) during each of the previous five years at the rate of 20% per year. As differences between actual and expected investment returns are incorporated into the market-related value, amounts are recognized in pension cost over the expected average remaining years of service for active employees (approximately Xcel Energy currently projects the pension costs recognized for financial reporting purposes will be Pension funding contributions across all four of Xcel Energy’s pension plans, both voluntary and required, for •$125 million in January 2021. •$150 million in •$154 million in •$150 million in Future amounts may change based on actual market performance, changes in interest rates and any changes in governmental regulations. Therefore, additional contributions could be required in the future. Xcel Energy contributed $11 million, $15 million and $11 million during 2020, 2019 and •NSP-Minnesota recognizes pension expense in all regulatory jurisdictions using the aggregate normal cost actuarial method. Differences between aggregate normal cost and expense as calculated by pension accounting standards are deferred as a regulatory •In 2018, the PSCW approved NSP-Wisconsin’s request for deferred accounting treatment of the 2018 pension settlement accounting •Regulatory Commissions in Colorado, Texas, New Mexico and FERC jurisdictions allow the recovery of other postretirement benefit costs only to the extent that recognized expense is matched by cash contributions to an irrevocable trust. Xcel Energy has consistently funded at a level to allow full recovery of costs in these •PSCo and SPS recognize pension expense in all regulatory jurisdictions based on •In 2018, PSCo was required to create a regulatory liability to adjust postretirement health care costs to zero in order to match the amounts collected in rates in the Colorado Gas retail jurisdiction. In 2020, this requirement was extended to the Colorado Electric retail jurisdiction. See Note 11 to the consolidated financial statements for further information. Nuclear Decommissioning Xcel Energy recognizes liabilities for the expected cost of retiring tangible long-lived assets for which a legal obligation exists. These AROs are recognized at fair value as incurred and are capitalized as part of the cost of the related long-lived assets. In the absence of quoted market prices, Xcel Energy estimates the fair value of its AROs using present value techniques, in which it makes assumptions including estimates of the amounts and timing of future cash flows associated with retirement activities, credit-adjusted risk free rates and cost escalation rates. When A significant portion of Xcel Energy’s AROs relates to the future decommissioning of NSP-Minnesota’s nuclear facilities. The nuclear decommissioning obligation is funded by the external decommissioning trust fund. Difference between regulatory funding (including depreciation expense less returns from the external trust fund) and expense recognized is deferred as a regulatory asset. The amounts recorded for AROs related to future nuclear decommissioning were $2.0 billion in 2020 and $2.1 billion in NSP-Minnesota obtains periodic independent cost studies in order to estimate the cost and timing of planned nuclear decommissioning activities. Estimates of future cash flows are highly uncertain and may vary significantly from actual results. NSP-Minnesota is required to file a nuclear decommissioning filing every three years. The filing covers all expenses for the decommissioning of the nuclear plants, including decontamination and removal of radioactive material. The In December 2020, The following assumptions have a significant effect on the estimated nuclear obligation: Timing — Decommissioning cost estimates are impacted by each facility’s retirement date and timing of the actual decommissioning activities. Estimated retirement dates coincide with the expiration of each unit’s operating license with the NRC (i.e., 2030 for Monticello and 2033 and 2034 for PI’s Unit 1 and 2, respectively). The estimated timing of the decommissioning activities is based upon the DECON method (required by the MPUC), which assumes prompt removal and dismantlement. Technology and Regulation — There is limited experience with actual decommissioning of large nuclear facilities. Changes in technology, experience and regulations could cause cost estimates to change significantly. 37 Escalation Rates — Escalation rates represent projected cost increases due to general inflation and increases in the cost of decommissioning activities. NSP-Minnesota Discount Rates — Changes in timing or estimated cash flows that result in upward revisions to the ARO are calculated using the then-current credit-adjusted risk-free interest rate. The credit-adjusted risk-free rate in effect when the change occurs is used to discount the revised estimate of the incremental expected cash flows of the retirement activity. If the change in timing or estimated expected cash flows results in a downward revision of the ARO, the undiscounted revised estimate of expected cash flows is discounted using the credit-adjusted risk-free rate in effect at the date of initial measurement and recognition of the original ARO. Discount rates ranging from approximately Significant uncertainties exist in estimating future costs including the method to be utilized, ultimate costs to decommission and planned method of disposing spent fuel. If different cost estimates, life assumptions or cost escalation rates were utilized, the AROs could change materially. However, changes in estimates have minimal impact on results of operations as NSP-Minnesota expects to continue to recover all costs in future rates. See Note 12 to the consolidated financial statements for further information.
We are 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. Xcel Energy is Distress in the financial markets may impact counterparty risk, the fair value of the securities in the nuclear decommissioning fund and pension fund and Xcel Energy’s ability to earn a return on short-term investments. Commodity Price Risk — We are exposed to commodity price risk in Wholesale and Commodity Trading Risk — Xcel Energy 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. Our 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,
Changes in the fair value of commodity trading contracts before the impacts of margin-sharing for the years ended Dec. 31:
At Dec. 31, 2020, a 10% increase in market prices for commodity trading contracts through the forward curve would increase pretax income from continuing operations by approximately $13 million, whereas a 10% decrease would decrease pretax income from continuing operations by approximately $13 million. At Dec. 31, 2019, a 10% increase in market prices for commodity trading contracts would increase pretax income from continuing operations by approximately $10 million, whereas a 10% decrease would decrease pretax income from continuing operations by approximately $10 million. The utility subsidiaries’ 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. 38 The VaRs for the NSP-Minnesota and PSCo commodity trading operations, excluding both non-derivative transactions and derivative transactions designated as normal purchase and normal sales, calculated on a consolidated basis using a Monte Carlo simulation with a 95% confidence level and a one-day holding period, were as follows:
Nuclear Fuel Supply — NSP-Minnesota has Interest Rate Risk — Xcel Energy is subject to interest rate risk. Our 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 Xcel Energy’s variable rate debt would impact 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. Credit Risk — Xcel Energy is also exposed to credit risk. Credit risk relates to the risk of loss resulting from counterparties’ nonperformance on their contractual obligations. At Dec. 31, 2020, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $11 million, while a decrease in prices of 10% would have resulted in an immaterial increase in credit exposure. At Dec. 31, 2019, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $19 million, while a decrease in prices of 10% would have resulted in an increase in credit exposure of $14 Xcel Energy 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 our credit risk. Fair Value Measurements Xcel Energy 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 Xcel Energy’s investments held in the nuclear decommissioning fund, rabbi trusts, pension and other postretirement funds are also subject to fair value accounting. Commodity Derivatives — Xcel Energy 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, 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, See Notes 10 and 11 to the consolidated financial statements for further information.
Cash Flows Operating Cash Flows
(b) Working capital includes accounts receivable, accrued unbilled revenues, inventories, accounts payable, other current assets and other current liabilities. Net cash provided by operating activities decreased by
39 Investing Cash Flows
Net cash used in investing activities increased by Financing Cash Flows
Net cash provided by financing activities increased by Capital Requirements Xcel Energy expects to meet future financing requirements by periodically issuing short-term debt, long-term debt, common stock, hybrid and other securities to maintain desired capitalization ratios. Contractual Obligations and Other Commitments — Xcel Energy has contractual obligations and other commitments that will need to be funded in the future. Contractual obligations and other commercial commitments as of Dec. 31,
Capital Expenditures —
40
Xcel Energy’s capital expenditure Financing Capital Expenditures through Current estimated financing plans for
(a) Net of dividends and pension funding. (b) Reflects a combination of short and long-term debt; net of refinancing. Common Stock Dividends — Future dividend levels will be dependent on Xcel Energy’s results of operations, financial condition, cash flows, reinvestment opportunities and other factors, and will be evaluated by the Xcel Energy Inc. Board of Directors. In February Xcel Energy’s dividend policy balances the following: •Projected cash •Projected capital •A reasonable rate of return on shareholder •The impact on Xcel Energy’s capital structure and credit ratings. In addition, there are certain statutory limitations that could affect dividend levels. Federal law places limits on the ability of public utilities within a holding company See Note 5 to the consolidated financial statements for further information. Pension Fund — Xcel Energy’s pension assets are invested in a diversified portfolio of domestic and international equity securities, short-term to long-duration fixed income securities and alternative investments, including private equity, real estate and hedge funds. Funded status and pension assumptions:
Capital Sources Short-Term Funding Sources — Xcel Energy Short-Term Investments — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS maintain cash 41 Short-Term Debt — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each have individual commercial paper programs. Authorized levels for these commercial paper programs are: •$1.25 billion for Xcel Energy Inc. •$700 million for •$500 million for •$500 million for •$150 million for NSP-Wisconsin. In addition, in December 2020, Xcel Energy Inc. Xcel Energy’s outstanding short-term debt:
Credit Facility Agreements — Xcel Energy Inc., NSP-Minnesota, PSCo and SPS each have the right to request an extension of the revolving credit facility for two additional one-year periods beyond the June 2024 termination date. NSP-Wisconsin has the right to request an extension of the revolving credit facility As of Feb.
Registration Statements — Xcel Energy Inc.’s Articles of Incorporation authorize the issuance of one billion shares of $2.50 par value common stock. As of Dec. 31, 2020 and 2019, Xcel Energy Inc. and its utility subsidiaries have registration statements on file with the SEC pursuant to which they may sell securities from time to time. These registration statements, which are uncapped, permit Xcel Energy Inc. and its utility subsidiaries to issue debt and other securities in the future at amounts, prices and with terms to be determined at the time of future offerings, and in the case of our utility subsidiaries, subject to commission approval. Planned Financing Activity — Xcel Energy’s •Xcel Energy Inc. — approximately •PSCo — approximately $750 million of first mortgage •SPS — approximately •NSP-Minnesota — approximately $850 million of first mortgage bonds. •NSP-Wisconsin — approximately $125 million of first mortgage bonds. Forward Equity Agreements — In November 2018, Xcel Energy Inc. entered into forward equity agreements in connection with a completed $459 million public offering of 9.4 million shares of Xcel Energy common stock. In August 2019, In November 2019, Xcel Energy Inc. entered into forward equity agreements for a $743 million public offering of 11.8 million shares of Xcel Energy common stock. In November 2020, Xcel Energy settled the forward equity agreements by delivering 11.8 million shares of common equity for cash proceeds of $721 million. Long-Term Borrowings and Other Financing Instruments — See Note 5 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 $1.2 billion (PSCo - $650 million, NSP-Minnesota - $300 million, SPS - $200 million and NSP-Wisconsin - $45 million). These amounts are preliminary estimates through Feb. 16, 2021 and are subject to final settlement. Xcel Energy 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. Xcel Energy 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. 42 Earnings Guidance Key •Constructive outcomes in all rate case and regulatory proceedings. •Modest impacts from COVID-19. •Normal weather •Weather-normalized retail electric sales are projected to increase ~1% •Weather-normalized retail firm natural gas sales are projected to •Capital rider revenue is projected to increase •O&M expenses are projected to •Depreciation expense is projected to increase approximately •Property taxes are projected to increase approximately •Interest expense (net of AFUDC - debt) is projected to increase $0 million to $10 million. •AFUDC - equity is projected to decline approximately $45 million to $55 million.
Off-Balance Sheet Arrangements Xcel Energy does not have any off-balance-sheet arrangements, other than those currently disclosed, that have or are reasonably likely to have a current or future effect on financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.
Although the COVID-19 pandemic has led to numerous challenges, Xcel Energy believes its risk management program, including business continuity and disaster recovery planning, will continue to allow us to proactively manage and successfully navigate challenges, risks and uncertainties. There is continued uncertainty regarding COVID-19, the duration and magnitude of business restrictions, re-shut downs and the level and pace of economic recovery. Also, while we may implement contingency plans, there are no guarantees these plans will be sufficient to offset the impact of the pandemic, which could have a material impact on our results of operations, financial condition or cash flow. An overview of certain risk considerations or areas which have or could significantly impact us, is as follows. Sales — Xcel Energy has experienced and may continue to experience higher residential sales and lower C&I sales as a result of COVID-19. Xcel Energy has decoupling and sales true-up mechanisms in Minnesota (all electric classes) and Colorado (residential and non-demand small C&I electric classes), which mitigate the impact of changes to sales levels as compared to a baseline. Bad Debt — Bad debt expense could significantly increase due to pandemic related economic impacts, customer hardship, federal or state legislation and regulatory orders. However, several of our commissions have approved the deferral of incremental COVID-19 related expense, including bad debt expense. Xcel Energy has received orders in Colorado, Wisconsin, Texas, New Mexico, North Dakota, South Dakota and Michigan, allowing regulatory deferral of incremental COVID-19 costs as a regulatory asset subject to future determination of amount and timing of recovery. As part of NSP-Minnesota’s stay-out alternative, NSP-Minnesota agreed to not seek recovery of incremental COVID-19 related costs. The majority of wholesale customers are subject to formula transmission and production rates, which true-up rates to actual costs to serve. Supply Chain and Capital Expenditures — Xcel Energy’s ability to meet customer energy requirements, respond to storm-related disruptions and execute our capital expenditure program are dependent on maintaining an efficient supply chain. During 2020, Xcel Energy did not experience supply chain, contractor or employee disruptions with the exception of delays in certain wind projects. Liquidity — Xcel Energy took steps to enhance its liquidity in 2020 and believes it has more than adequate liquidity. Xcel Energy will take steps to enhance liquidity in 2021 if needed.
See Item 7, incorporated by reference.
See Item 15-1 for an index of financial statements included herein. See Note 15 to the consolidated financial statements for further information. Management Report on Internal Control Over Financial Reporting The management of Xcel Energy Inc. is responsible for establishing and maintaining adequate internal control over financial reporting. Xcel Energy Inc.’s internal control system was designed to provide reasonable assurance to Xcel Energy Inc.’s management and 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. Xcel Energy Inc. management assessed the effectiveness of Xcel Energy Inc.’s internal control over financial reporting as of Dec. 31, Xcel Energy Inc.’s independent registered public accounting firm has issued an audit report on Xcel Energy Inc.’s internal control over financial reporting. Its report appears herein.
44 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the stockholders and the Board of Directors of Xcel Energy Inc. Opinions on the Financial Statements and Internal Control over Financial Reporting We have audited the accompanying consolidated balance sheets of Xcel Energy Inc. and subsidiaries (the "Company") as of December 31, In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, Basis for Opinions The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management Report on Internal Controls over Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion on the Company’s internal control over financial reporting 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 audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures to 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. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions. Definition and Limitations of Internal Control over Financial Reporting A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 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. 45 Regulatory Assets and Liabilities - Impact of Rate Regulation on the Financial Statements Critical Audit Matter Description The Company is subject to rate regulation by state utility regulatory agencies, which have jurisdiction with respect to the rates of electric and natural gas distribution companies in Minnesota, North Dakota, South Dakota, Wisconsin, Michigan, Colorado, New Mexico, and Texas. 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 judgements 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 memorandums, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on •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.
XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (amounts in millions, except per share data)
47
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (amounts in millions)
48
CONSOLIDATED STATEMENTS OF CASH FLOWS (amounts in millions)
49
(amounts in millions, except share and per share)
50
(amounts in millions, shares in thousands)
51
XCEL ENERGY INC. AND SUBSIDIARIES Notes to Consolidated Financial Statements
General — Xcel Energy Inc.’s utility subsidiaries are engaged in the regulated generation, purchase, transmission, distribution and sale of electricity and in the regulated purchase, transportation, distribution and sale of natural gas. Xcel Energy’s regulated operations include the activities of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS. These utility subsidiaries serve electric and natural gas customers in portions of Colorado, Michigan, Minnesota, New Mexico, North Dakota, South Dakota, Texas and Wisconsin. Also included in regulated operations are WGI, an interstate natural gas pipeline company, and WYCO, a joint venture with CIG to develop and lease natural gas pipeline, storage and compression facilities. Xcel Energy Inc.’s nonregulated subsidiaries include Eloigne, Capital Services and Xcel Energy’s consolidated financial statements include its wholly-owned subsidiaries and VIEs for which it is the primary beneficiary. All intercompany transactions and balances are eliminated, unless a different treatment is appropriate for rate regulated transactions. Xcel Energy uses the equity method of accounting for its investment in WYCO. Xcel Energy’s equity earnings in WYCO are included on the consolidated statements of income as equity earnings of unconsolidated subsidiaries. Xcel Energy has investments in certain plants and transmission facilities jointly owned with nonaffiliated utilities. Xcel Energy’s proportionate share of jointly owned facilities is recorded as property, plant and equipment on the consolidated balance sheets, and Xcel Energy’s proportionate share of the operating costs associated with these facilities is included in its consolidated statements of income. Xcel Energy’s consolidated financial statements are presented in accordance with GAAP. All of the utility subsidiaries’ underlying accounting records also conform to the FERC uniform system of accounts. Certain amounts in the Xcel Energy has evaluated events occurring after Dec. 31, Use of Estimates — Xcel Energy uses estimates based on the best information available in recording transactions and balances resulting from business operations. Estimates are used on 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 — Xcel Energy Inc.’s regulated utility subsidiaries account 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 •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, the utility subsidiaries may no longer be eligible to apply this accounting treatment and may be required to eliminate regulatory assets and liabilities from their balance sheets. Such changes could have a material effect on Xcel Energy’s results of operations, financial condition and cash flows. See Note 4 for further information. Income Taxes — Xcel Energy 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. Xcel Energy defers income taxes for all temporary differences between pretax financial and taxable income and between the book and tax bases of assets and liabilities. Xcel Energy 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 tax rate changes that are attributable to the utility subsidiaries are generally subject to a normalization method of accounting. Therefore, the revaluation of most of the utility subsidiaries’ net deferred taxes upon a tax rate reduction results in the establishment of a net regulatory liability, which 52 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. Xcel Energy 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. Xcel Energy 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. Xcel Energy reports interest and penalties related to income taxes within Xcel Energy Inc. and its subsidiaries 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. Xcel Energy records depreciation expense using the straight-line method over the plant’s 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 of Xcel Energy’s utility subsidiaries are recovered in rates as authorized by the appropriate regulatory entities. The amount of removal costs are 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 3.4% for 2020, 3.3% for 2019 and 3.1% for See Note 3 for further information. AROs — Xcel Energy 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 12 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 three years and submitted to the state commissions for approval. 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 Benefit Plans and Other Postretirement Benefits — Xcel Energy 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 11 for further information. 53 Environmental Costs — Environmental costs are recorded when it is probable Xcel Energy is liable for remediation costs and the liability can be reasonably estimated. Costs are deferred as a regulatory asset if it is probable that the costs will be recovered from customers in future rates. Otherwise, the costs are expensed. If an environmental expense is related to facilities currently in use, such as emission-control equipment, the cost is capitalized and depreciated over the life of the plant. Estimated remediation costs 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 Xcel Energy’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 12 for further information. Revenue from Contracts with Customers — Performance obligations related to the sale of energy are satisfied as energy is delivered to customers. Xcel Energy 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 Xcel Energy does not recognize a separate financing component of its collections from customers as contract terms are short-term in nature. Xcel Energy presents its revenues net of any excise or sales taxes or fees. The utility subsidiaries recognize physical sales to customers (native load and wholesale) on a gross basis in electric revenues and cost of sales. Revenues and charges for See Note 6 for further information. Cash and Cash Equivalents — Xcel Energy considers investments in instruments with a remaining maturity of three months or less at the time of purchase to be cash equivalents. Accounts Receivable and Allowance for Bad Debts — Accounts receivable are stated at the actual billed amount net of an allowance for bad debts. Xcel Energy establishes an allowance for uncollectible receivables based on a policy that reflects its expected exposure to the credit risk of customers. Inventory — Inventory is recorded at average cost and consisted of the following:
Fair Value Measurements — Xcel Energy 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, Xcel Energy 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 10 and 11 for further information. Derivative Instruments — Xcel Energy uses derivative instruments in connection with its interest rate, utility commodity price Gains or losses on commodity trading transactions are recorded as a component of electric operating Normal Purchases and Normal Sales — Xcel Energy 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 10 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 Xcel Energy’s generation assets or energy and capacity purchased to serve native load. Commodity trading contracts are recorded at fair market value and commodity trading results include the impact of all margin-sharing mechanisms. See Note 10 for further 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 Xcel Energy’s rate base for establishing utility rates. 54 Alternative Revenue — Certain rate rider mechanisms (including decoupling 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. 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 — Xcel Energy 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. In certain jurisdictions, Xcel Energy reduces recoverable fuel costs for the cost of RECs and records that cost as a regulatory asset when the amount is recoverable in future rates. 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.
Recently Credit Losses — In 2016, the FASB issued Financial Instruments - Credit Losses, Topic Xcel Energy implemented the guidance using a modified-retrospective approach,
Major classes of property, plant and equipment
Joint Ownership of Generation, Transmission and Gas Facilities The utility subsidiaries’ jointly owned assets as of Dec. 31,
Each company’s share of operating expenses and construction expenditures is included in the applicable utility accounts. Respective owners are responsible for providing their own financing.
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. Xcel Energy 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:
(a) Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments. (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) Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. Components of regulatory liabilities:
At Dec. 31,
Short-Term Borrowings Short-Term Debt — Xcel Energy meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under their credit facilities and term loan agreements. Commercial paper and term loan borrowings outstanding:
Term Loan
Bilateral Credit Agreement — In March 2019, NSP-Minnesota entered into a one-year uncommitted bilateral credit agreement. The 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,
Letters of Credit — Xcel Energy uses letters of credit, typically with terms of one year, to provide financial guarantees for certain operating obligations. As of Dec. 31, Credit Facilities — In order to use commercial paper programs to fulfill short-term funding needs, Xcel Energy Inc. and its utility subsidiaries 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. Features of the credit facilities:
If Xcel Energy Inc. or its utility subsidiaries do 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, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available as of Dec. 31,
All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facilities. Xcel Energy Inc. and its utility subsidiaries had 0 direct advances on facilities outstanding as of Dec. 31, Long-Term Borrowings and Other Financing Instruments Generally, all property of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS are subject to the liens of their first mortgage indentures. 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. 57
(a)2020 financing. (b)2019 financing. (c)Note was redeemed on Dec. 1, 2020.
(a)2020 financing. (b)2019 financing.
(a)2020 financing.
(a)2020 financing. (b)2019 financing.
(b)2019 financing.
Maturities of long-term debt:
Deferred Financing Costs — Deferred financing costs of approximately Forward Equity Agreements — In November 2018, Xcel Energy Inc. entered into forward equity agreements In November 2019, Xcel Energy Inc. entered into forward equity agreements Other Equity — Xcel Energy Capital Stock — Preferred stock authorized/outstanding:
Xcel Energy Inc. had the following common stock authorized/outstanding:
Dividend and Other Capital-Related Restrictions — Xcel Energy depends on its utility subsidiaries to pay dividends. Xcel Energy Inc.’s utility subsidiaries’ dividends are subject to the FERC’s jurisdiction, which prohibits the payment of dividends out of capital accounts. Dividends are solely to be paid from retained earnings. Certain covenants also require Xcel Energy Inc. to be current on interest payments prior to dividend disbursements. State regulatory commissions impose dividend limitations for NSP-Minnesota, NSP-Wisconsin and SPS, which are more restrictive than those imposed by the FERC. Requirements and actuals as of Dec. 31,
Issuance of securities by Xcel Energy Inc. Amounts authorized to issue as of Dec. 31,
(a) NSP-Minnesota has authorization to issue long-term securities provided the equity-to-total capitalization remains within the required range, and to issue short-term debt provided it does not exceed 15% of total capitalization. (b) SPS filed for additional long-term debt authorization in December 2020. 59
Revenue is classified by the type of goods/services rendered and market/customer type. Xcel Energy’s operating revenues consisted of the following:
Federal Federal Audit — Statute of limitations applicable to Xcel Energy’s consolidated federal income tax returns:
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 file 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. State Audits — Xcel Energy files consolidated state tax returns based on income in its major operating jurisdictions and various other state income-based tax returns. As of Dec. 31,
•In 2018, Wisconsin began an audit of tax years 2014 - 2016. As of Dec. 31, •In July 2020, Minnesota began a review of the 2015 - 2018 Research and Experimentation Credits. As of Dec. 31, 2020, 0 material adjustments have been proposed. •Xcel Energy had 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. A change in the period of deductibility would not affect the ETR but would accelerate the payment to the taxing authority to an earlier period. Unrecognized tax benefits - permanent vs. temporary:
60 Changes in unrecognized tax benefits:
Unrecognized tax benefits were reduced by tax benefits associated with NOL and tax credit carryforwards:
Net deferred tax liability associated with the unrecognized tax benefit amounts and related NOLs and tax credits carryforwards were As the IRS Payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards.
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:
Federal carryforward periods expire between 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:
Components of income tax expense for years ended Dec. 31:
Components of deferred income tax expense as of Dec. 31:
61 Components of net deferred tax liability as of Dec. 31:
Incentive Restated 2015 Omnibus Incentive Plan Restricted Stock — The Shares of restricted stock granted at Dec. 31:
Changes in nonvested restricted stock:
Other Equity Awards — Xcel Energy‘s Board of Directors has granted equity awards under the Amended and Restated 2015 Omnibus Incentive Plan, which includes various vesting conditions and performance goals. At the end of the restricted period, such grants will be awarded if vesting conditions and/or performance goals are met. Certain employees are granted equity awards with a portion subject only to service conditions, and the other portion subject to performance conditions. A total of 0.2 million, 0.3 million, and 0.3 million time-based equity shares subject only to service conditions were granted annually in 2020, 2019 and 2018, The performance conditions for a portion of the awards granted from Equity award units granted to employees (excluding restricted stock):
Equity awards vested:
Changes in the nonvested portion of equity award units:
Stock Equivalent Units — Non-employee members of Xcel Energy‘s Board of Directors may elect to receive their annual equity grant as stock equivalent units in lieu of common stock. Each unit’s value is equal to 1 share of common stock. The annual equity grant is vested as of the date of each member’s election to the Board of Directors; there is no further service or other condition. Directors may also elect to receive their cash fees as stock equivalent units in lieu of cash. Stock equivalent units are payable as a distribution of common stock upon a director’s termination of service. Stock equivalent units granted:
Changes in stock equivalent units:
TSR Liability Awards — Xcel Energy Inc.’s Board of Directors has granted TSR liability awards under the Amended and Restated 2015 Omnibus Incentive Plan. This plan allows Xcel Energy to attach various performance goals to the awards granted. The liability awards have been historically dependent on relative TSR measured over a 62 TSR liability awards granted:
TSR liability awards settled:
TSR liability awards of Share-Based Compensation Expense — Other than for restricted stock, vesting of employee equity awards is typically predicated on the achievement of a TSR or environmental measures target. Additionally, approximately 0.2 million, 0.3 million, and 0.3 million of equity award units were granted Generally, these instruments are considered to be equity awards as the award settlement determination (shares or cash) is made by Xcel Energy, not the participants. In addition, these awards have not been previously settled in cash and Xcel Energy plans to continue electing share settlement. Grant date fair value of equity awards is expensed over the service period. TSR liability awards have been historically settled partially in cash, and do not qualify as equity awards, but rather are accounted for as liabilities. As liability awards, the fair value on which ratable expense is based, as employees vest in their rights to those awards, is remeasured each period based on the current stock price and performance achievement, and final expense is based on the market value of the shares on the date the award is settled. Compensation costs related to share-based awards:
There was approximately $51 million in 2020 and $40 million in 2019
Basic EPS was computed by dividing the earnings available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS was computed by dividing the earnings available to common shareholders by the diluted weighted average number of common shares outstanding during the period. Diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock (i.e., common stock equivalents) were settled. The weighted average number of potentially dilutive shares outstanding used to calculate diluted EPS is calculated using the treasury stock method. Common Stock Equivalents — Xcel Energy Inc. has common stock equivalents related to forward equity agreements and certain equity awards in share-based compensation arrangements. Common stock equivalents include commitments to issue common stock related to time-based equity compensation awards. Stock equivalent units granted to Xcel Energy’s Board of Directors are included in common shares outstanding upon grant date as there is no further service, performance or market condition associated with these. Restricted stock issued to employees under the Executive Annual Incentive Award Plan is included in common shares outstanding when granted. Share-based compensation arrangements for which there is currently no dilutive impact to EPS include the following: •Equity awards subject to a performance condition; included in common shares outstanding when all necessary conditions for settlement have been satisfied by the end of the reporting •Liability awards subject to a performance condition; any portions settled in shares are included in common shares outstanding upon settlement. Diluted common shares outstanding included common stock equivalents of 1.1 million, 1.3 million
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.
Specific valuation methods include: Cash equivalents — The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted 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 63 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 — Fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts. Commodity derivatives — 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 and SPS include transmission congestion instruments, generally referred to as FTRs. FTRs purchased from a 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 as applicable in each jurisdiction, 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 FTRs relative to the electric utility operations of NSP-Minnesota and SPS, the numerous unobservable quantitative inputs pertinent to the value of FTRs are immaterial to the consolidated financial statements. 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 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 Non-derivative instruments with recurring fair value measurements:
For the years ended Dec. 31, Contractual maturity dates of debt securities in the nuclear decommissioning fund as of Dec. 31,
64 Rabbi Trusts Xcel Energy has established rabbi trusts to provide partial funding for future distributions of its SERP and deferred compensation plan. Cost and fair value of assets held in rabbi trusts:
Derivative Instruments Fair Value Measurements Xcel Energy 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 — Xcel Energy enters into various instruments that effectively fix the As of Dec. 31, As of Dec. 31, Wholesale and Commodity Trading Risk — Xcel Energy Inc.’s utility subsidiaries conduct 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. Xcel Energy 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 — Xcel Energy 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. Xcel Energy 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. As of Dec. 31, Xcel Energy 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
Consideration of Credit Risk and Concentrations — Xcel Energy 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 Xcel Energy’s utility subsidiaries’ most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to their wholesale, trading and non-trading commodity activities. As of Dec. 31, Qualifying Cash Flow Hedges — Financial impact of qualifying interest rate
65 Impact of derivative activity:
(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.
Xcel Energy had 0 derivative instruments designated as fair value hedges during the years ended Dec. 31, 2020, 2019 66 Credit Related Contingent Features — Contract provisions for derivative instruments that the utility subsidiaries enter, including those accounted for as normal Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. Recurring Fair Value Measurements —
(a)Xcel Energy 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 as of Dec. 31, 2020 and 2019. At Dec. 31, 2020 and 2019, derivative assets and liabilities include $15 million and $32 million of obligations to return cash collateral, respectively. At Dec. 31, 2020 and 2019, derivative assets and liabilities include rights to reclaim cash collateral of $6 million and $11 million, respectively. Counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. (b)During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, contracts are no longer adjusted to fair value and the previous carrying value of these contracts is being amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.
67 Changes in Level 3 commodity derivatives:
Xcel Energy recognizes transfers between levels as of the beginning of each period. There were 0 transfers of amounts between levels for derivative instruments for Fair Value of Long-Term Debt As of Dec. 31, other financial instruments for which the carrying amount did not equal fair value:
Fair value of Xcel Energy’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,
Pension and Postretirement Health Care Benefits Xcel Energy has several noncontributory, qualified, defined benefit pension plans that cover almost all employees. In addition to the qualified pension plans, Xcel Energy maintains a SERP and a nonqualified pension plan. The SERP is maintained for certain executives 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, 2020 and 2019 Xcel Energy bases the investment-return assumption on expected long-term performance for each of the asset classes in its pension and postretirement health care portfolios. For pension assets, Xcel Energy considers the historical returns achieved by its asset portfolio over the past 20 years or longer period, as well as long-term projected return levels. Pension cost determination assumes a forecasted mix of investment types over the long-term. •Investment returns in 2020 were above the assumed level of 6.87%. •Investment returns in 2019 were above the assumed level of 6.87% •Investment returns in 2018 were below the assumed level of 6.87% •In Pension plan and postretirement benefit assets are invested in a portfolio according to Xcel Energy’s return, liquidity and diversification objectives to provide a source of funding for plan obligations and minimize contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the asset allocation given the long-term risk, return, correlation and liquidity characteristics of each particular asset class. There were no significant concentrations of risk in any industry, index, or entity. Market volatility can impact even well-diversified portfolios and significantly affect the return levels achieved by the assets in any year. State agencies also have issued guidelines to the funding of postretirement benefit costs. SPS is required to fund postretirement benefit costs for Texas and New Mexico amounts collected in rates. PSCo is required to fund postretirement benefit costs in irrevocable external trusts that are dedicated to the payment of these postretirement benefits. These assets are invested in a manner consistent with the investment strategy for the pension plan. Xcel Energy’s ongoing investment strategy is based on plan-specific investment recommendations that seek to minimize potential investment and interest rate risk as a plan’s funded status increases over time. The investment recommendations 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. 68 Plan Assets For each of the fair value hierarchy levels, Xcel Energy’s pension plan assets measured at fair value:
For each of the fair value hierarchy levels, Xcel Energy’s postretirement benefit plan assets that were measured at fair value:
No assets were transferred in or out of Level 3 for 2020. Immaterial assets were transferred in or out of Level 3 for 2019. Funded Status — Benefit obligations for both pension and postretirement plans increased from Dec. 31, 2019 to Dec. 31, 2020, due primarily to decreases 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 Xcel Energy are as follows:
(a)Includes approximately $0 million in 2020 and $20 million in 2019 of lump-sum benefit payments used in the determination of a settlement charge. 69
Accumulated benefit obligation for the pension plan was Net Periodic Benefit Cost (Credit) — Net periodic benefit cost (credit), other than the service cost component, is included in other income 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:
70 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 Voluntary and required pension funding contributions: •$125 million in January 2021. •$150 million in •$154 million in •$150 million in 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. Voluntary postretirement funding contributions: •$11 million during 2020. •$15 million during •$11 million during Targeted asset allocations:
Plan Amendments — In 2018, the PSCo postretirement plan was amended to add the 5% cash balance formula. In 2019, the Pension Protection Act measurement concept was extended beyond 2019 for NSP bargaining terminations and retirements to Dec. 31, 2022. There were no significant plan amendments made in Projected Benefit Payments Xcel Energy’s projected benefit payments:
Defined Contribution Plans Xcel Energy maintains 401(k) and other defined contribution plans that cover most employees. Total expense to these plans was approximately $42 million in 2020, $39 million in 2019 and $38 million in Multiemployer Plans NSP-Minnesota and NSP-Wisconsin each contribute 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 and NSP-Wisconsin sponsored pension and postretirement health care plans. Contributing to these types of plans creates risk that differs from providing benefits under NSP-Minnesota and NSP-Wisconsin 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.
Legal Xcel Energy is involved in various litigation matters Management 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, Gas Trading Litigation — e prime is a wholly owned subsidiary of Xcel Energy. e prime was in the business of natural gas trading and marketing but has not engaged in natural gas trading or marketing activities since 2003. Multiple lawsuits involving multiple plaintiffs seeking monetary damages were commenced against e prime and its affiliates, including Xcel Energy, between 2003 and 2009 alleging fraud and anticompetitive activities in conspiring to restrain the trade of natural gas and manipulate natural gas prices. Cases were all consolidated in the U.S. District Court in Nevada. NaN cases remain active which include an MDL matter consisting of a Colorado purported class (Breckenridge) and a Wisconsin purported class (Arandell Corp.). Breckenridge/Colorado — In February 2019, the MDL panel remanded Breckenridge back to the U.S. District Court in Arandell Corp. — In February 2019, the case was remanded back to the U.S. District Court in Wisconsin. Xcel Energy has concluded that a loss is remote for 71 Rate Matters and Other MEC Acquisition and Disposition — In In Sherco — In In March 2019, the MPUC approved NSP-Minnesota’s 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 General and DOC filed comments recommending that NSP-Minnesota refund approximately $17 million of replacement power costs previously recovered through the FCA. On Jan. 27, 2021, NSP-Minnesota 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 for Westmoreland Coal Company filed an arbitration demand against NSP-Minnesota, SMMPA and Western Fuels Association, seeking recovery of alleged 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 a final resolution will occur, but it is unlikely an arbitration hearing will take place before the fourth quarter 2021. 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, The first complaint In September 2016, the FERC issued an order (Opinion No. 551) granting a 10.32% base ROE Opinion.In December 2019, MISO TOs filed a request for In May 2020, the FERC In June 2020, various parties filed requests for rehearing Various parties have filed petitions for review of SPP OATT Upgrade Costs — Under the SPP OATT, costs of transmission upgrades may be recovered from other SPP customers whose transmission service depends on capacity enabled by the upgrade. SPP had not been charging its customers for these upgrades, even though the SPP OATT had allowed SPP to do so since 2008. In 2016, the FERC granted SPP’s request to recover these previously unbilled charges and SPP subsequently billed SPS approximately $13 million. In July 2018, SPS’ appeal to the D.C. Circuit over the FERC rulings granting SPP the right to recover previously unbilled charges was remanded to the FERC. In February 2019, the FERC reversed its 2016 decision and ordered SPP to refund charges retroactively collected from its transmission customers, including SPS, related to periods before September 2015. In 72 In October 2017, SPS filed a separate related complaint Wind Operating Commitments — PUCT and NMPRC orders related to the Hale and Sagamore wind projects included certain operating and savings minimums. In general, annual generation must exceed a net capacity factor of 48%. If annual generation is below the guaranteed level, SPS would be obligated to refund an amount equal to foregone PTCs and fuel savings. Additionally, retail customer savings must exceed project costs included in base rates over the first ten years of operations. SPS would be required to refund excess costs, if any, after ten years of operations. As of Dec. 31, 2020, SPS does not expect refunds to be probable under either of these commitments. Contract Termination —SPS and Lubbock Power & Light are parties to a 25-year, 170 MW partial requirements contract. In October 2020, Lubbock Power & Light initiated discussions concerning the interpretation of contractual terms related to early termination and default. If the parties are unable to reach resolution, the contract calls for the matter to proceed to arbitration. The amount of any damages depends on multiple factors and is currently unknown. Environmental New and changing federal and state environmental mandates can create financial liabilities for Xcel Energy, 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. Xcel Energy Inc.’s subsidiaries may sometimes pay all or a portion of the cost to remediate sites where past activities of their 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 one or more of Xcel Energy Inc.’s subsidiaries are alleged to have sent wastes to that site. MGP, Landfill and Disposal Sites Ashland MGP Site — NSP-Wisconsin was named a responsible party for contamination at the Ashland/Northern States Power Lakefront Superfund Site (the Site) in Ashland, Wisconsin. Remediation was completed in 2019 and restoration activities The NSP-Wisconsin has deferred the unrecovered portion of the estimated Site remediation and restoration costs as a regulatory asset. The PSCW has authorized NSP-Wisconsin rate recovery for all remediation and restoration costs incurred at the Xcel Energy has recognized its best estimate of costs/liabilities that will result from final resolution of these issues, however, the outcome and timing is 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 — Xcel Energy’s operations are subject to federal and state Xcel Energy is conducting groundwater sampling and In August 2020, the EPA published its final rule to implement a cease receipt and initiate a closure date of April 2021 for all CCR impoundments affected by the August 2018 In October 2020, NSP-Minnesota completed construction and PSCo is pursuing options to build an alternative bottom ash collection system that will be Closure costs for existing impoundments are included in the calculation of the 73 Federal CWA WOTUS Rule — In 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 The retirement of units affected by the final ELG rule is subject to regulatory approval.The exact total cost of ELG compliance 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. Xcel Energy estimates the likely cost for complying with impingement and entrainment requirements is approximately Environmental Requirements — Air Regional Haze Rules — The regional haze program requires SO2, nitrogen oxide and particulate matter emission controls at power plants to reduce visibility impairment in national parks and wilderness areas. The program includes BART and reasonable further progress. The 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 Xcel Energy facilities are expected to be minimal. BART Determination for Texas: The EPA has issued a revised final rule adopting a BART alternative Texas only SO2 trading program that applies to all Harrington and Tolk units. Under the trading program, SPS expects the allowance allocations to be sufficient for SO2 emissions. The anticipated costs of compliance are not expected to have a material impact; and SPS believes that compliance costs would be recoverable through regulatory mechanisms. Several parties have challenged whether the final rule issued by the EPA should be considered to have met the requirements imposed in a Consent Decree entered by the United States District Court for the District of Columbia that established deadlines for the EPA to take final action on state regional haze plan submissions. The court has required status reports from the parties while the EPA works on the reconsideration rulemaking. In December 2017, the National Parks Conservation Association, Sierra Club, and Environmental Defense Fund appealed the EPA’s 2017 final BART rule to the Fifth Circuit and filed a petition for administrative reconsideration. The 2020 EPA Action has been challenged. All pending actions could be consolidated, and may proceed in the Fifth Circuit or the D.C. Circuit, where a parallel challenge has been filed. The timing of final decisions is Reasonable Progress Rule: In 2016, the EPA adopted a final rule establishing a federal implementation plan for reasonable further progress under the regional haze program for the state of Texas. The rule imposes SO2 emission limitations that would require the installation of dry scrubbers on Tolk Units 1 and 2, with compliance required by February 2021. Investment costs associated with dry scrubbers could be $600 million. SPS appealed the EPA’s decision and obtained a stay of the final rule. In March 2017, the Fifth Circuit remanded the rule to the EPA for reconsideration, leaving the stay in effect. In a future rulemaking, the EPA will address whether SO2 emission reductions beyond those required in the BART alternative rule are needed at Tolk under the “reasonable progress” requirements. Implementation of the NAAQS for SO2 — The EPA has designated all areas near SPS’ generating plants as attaining the SO2 NAAQS with an exception. The EPA issued final designations, which found the area near the SPS Harrington plant as “unclassifiable.” The area near the Harrington plant To address this issue, SPS negotiated an order with the TCEQ providing for Xcel Energy believes AROs — AROs have been recorded for Xcel Energy’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 $2.8 billion and $2.4 billion for 2020 and 74 Xcel Energy’s AROs were as follows:
(a)Amounts incurred related to the wind farms placed in service in 2020 for NSP-Minnesota (Blazing Star 1, Crowned Ridge 2, Jeffers and Community Wind North), PSCo (Cheyenne Ridge) and SPS (Sagamore). (b)Amounts settled primarily related to closure of certain ash containment facilities, removal of wind facilities and asbestos abatement projects. (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, hydro and other production AROs were primarily related to changes in cost estimates for remediation of ash containment facilities.
(a)Amounts incurred related to the wind farms placed in service in 2019 for NSP-Minnesota (Lake Benton and Foxtail) and SPS (Hale). (b)Amounts settled related to asbestos abatement projects and closure of certain ash containment facilities. (c)In 2019, AROs were revised for changes in timing and estimates of cash flows. Revisions 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, hydro and other production AROs primarily related to changes in cost estimates to remediate ponds at production facilities. Revisions in wind AROs were driven by new dismantling studies.
Indeterminate AROs — Other plants or buildings may contain asbestos due to the age of many of Xcel Energy’s facilities, but no confirmation or measurement of the cost of removal could be determined as of Dec. 31,
Nuclear Related Nuclear Insurance — NSP-Minnesota’s public liability for claims from any nuclear incident is limited to NSP-Minnesota is subject to assessments of up to $138 million per reactor-incident for each of its 3 NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs from NEIL and EMANI. The coverage limits are 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 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 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 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. 75 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
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:
Decommissioning expenses recognized as a result of regulation:
The 2014 nuclear decommissioning filing, approved in 2015, was used for regulatory presentation in 2020, 2019 Leases Xcel Energy evaluates contracts that may contain leases, including PPAs and arrangements for the use of office space and other facilities, vehicles and equipment. ROU assets represent Xcel Energy's rights to use leased assets. Most of Xcel Energy’s leases do not contain a readily determinable discount rate. Therefore, the present value of future lease payments is generally calculated using the applicable Xcel Energy subsidiary’s estimated incremental borrowing rate (weighted-average of 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:
Xcel Energy’s most significant finance lease activities are related to WYCO, a joint venture with CIG, to develop and lease natural gas pipeline, storage and compression facilities. Xcel Energy Inc. has a 50% ownership interest in WYCO. WYCO leases its facilities to CIG, and CIG operates the facilities, providing natural gas storage and transportation services to PSCo under separate service agreements. PSCo accounts for its Totem natural gas storage service and Front Range pipeline arrangements with CIG and WYCO, respectively, as finance leases. Xcel Energy Inc. eliminates 50% of the finance lease obligation related to WYCO in the consolidated balance sheet along with an equal amount of Xcel Energy Inc.’s equity investment in WYCO. Finance lease ROU assets:
76 Components of lease expense:
Commitments under operating and finance leases as of Dec. 31,
PPAs and Fuel Contracts Non-Lease PPAs — NSP Minnesota, PSCo and SPS have entered into PPAs with other utilities and energy suppliers with various expiration dates through Included in electric fuel and purchased power expenses for PPAs accounted for as executory contracts were payments for capacity of $75 million, $86 million and $131 million in 2020, 2019 and 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,
Fuel Contracts — Xcel Energy 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 between Estimated minimum purchases under these contracts as of Dec. 31,
VIEs PPAs — Under certain PPAs, NSP-Minnesota, PSCo and SPS purchase power from IPPs for which the utility subsidiaries are required to reimburse fuel costs, or to participate in tolling arrangements under which the utility subsidiaries procure the natural gas required to produce the energy that they purchase. Xcel Energy has determined that certain IPPs are VIEs. Xcel Energy 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. In addition, certain solar PPAs provide an option to purchase emission allowances or sharing provisions related to production credits generated by the solar facility under contract. These specific PPAs create a variable interest in the IPP. Xcel Energy 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. Xcel Energy 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. The utility subsidiaries had approximately 77 Fuel Contracts — SPS purchases all of its coal requirements for its Harrington and Tolk plants from TUCO Inc. under contracts that will expire in December 2022. TUCO arranges for the purchase, receiving, transporting, unloading, handling, crushing, weighing and delivery of coal to meet SPS’ requirements. TUCO is responsible for negotiating and administering contracts with coal suppliers, transporters and handlers. SPS has not provided any significant financial support to TUCO, other than contractual payments for delivered coal. However, the fuel contracts create a variable interest in TUCO due to SPS’ reimbursement of fuel procurement costs. SPS has determined that TUCO is a VIE, however it has concluded that SPS is not the primary beneficiary of TUCO because it does not have the power to direct the activities that most significantly impact TUCO’s economic performance. Low-Income Housing Limited Partnerships — Eloigne and NSP-Wisconsin have entered into limited partnerships for the construction and operation of affordable rental housing developments which qualify for low-income housing tax credits. Xcel Energy Inc. has determined Eloigne and NSP-Wisconsin’s low-income housing partnerships to be VIEs primarily due to contractual arrangements within each limited partnership that establish sharing of ongoing voting control and profits and losses that does not align with the partners’ proportional equity ownership. Eloigne and NSP-Wisconsin have the power to direct the activities that most significantly impact these entities’ economic performance. Therefore, Xcel Energy Inc. consolidates these limited partnerships in its consolidated financial statements. Xcel Energy’s risk of loss for these partnerships is limited to its capital contributions, adjusted for any distributions and its share of undistributed profits and losses; no significant additional financial support has been, or is required to be, provided to the limited partnerships by Eloigne or NSP-Wisconsin. Amounts reflected in Xcel Energy’s consolidated balance sheets for the Eloigne and NSP-Wisconsin low-income housing limited partnerships:
Other Technology Agreements — Xcel Energy has Committed minimum payments under these
Guarantees and Bond Indemnifications — Xcel Energy Inc. and its subsidiaries provide guarantees and bond indemnities, which guarantee payment or performance. Xcel Energy Inc.’s exposure is based upon the net liability under the specified agreements or transactions. Most of the guarantees and bond indemnities issued by Xcel Energy Inc. and its subsidiaries have a stated maximum amount. As of Dec. 31, Guarantees and bond indemnities issued and outstanding for Xcel Energy were $62 million Other Indemnification Agreements — Xcel Energy Inc. and its subsidiaries provide indemnifications through various contracts. These are primarily indemnifications against adverse litigation outcomes in connection with underwriting agreements, as well as breaches of representations and warranties, including corporate existence, transaction authorization and income tax matters with respect to assets sold. Xcel Energy Inc.’s and its subsidiaries’ obligations under these agreements may be limited in terms of duration and amount. Maximum future payments under these indemnifications cannot be reasonably estimated as the dollar amounts are often not explicitly stated.
Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31:
(b)Included in the computation of net periodic pension and postretirement benefit costs. See Note 11 for further information. 78
(a)Included in interest charges. (b)Included in the computation of net periodic pension and postretirement benefit costs. See Note 11 for further information.
Xcel Energy evaluates performance by each utility subsidiary based on profit or loss generated from the product or service provided, including the regulated electric utility operating results of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS, as well as the regulated natural gas utility operating results of NSP-Minnesota, NSP-Wisconsin and PSCo. These segments are managed separately because the revenue streams are dependent upon regulated rate recovery, which is separately determined for each segment. Xcel Energy has the following reportable segments:
Xcel Energy 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, revenues associated with processing solid waste into refuse-derived fuel, Xcel Energy had equity investments in unconsolidated subsidiaries of Asset and capital expenditure information is not provided for Xcel Energy’s reportable segments. As an integrated electric and natural gas utility, Xcel Energy 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. Xcel Energy’s segment information:
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None.
Disclosure Controls and Procedures Xcel Energy 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, Internal Control Over Financial Reporting No changes in Xcel Energy’s internal control over financial reporting occurred during the most recent fiscal quarter that materially affected, or are reasonably likely to materially affect, Xcel Energy’s internal control over financial reporting. Xcel Energy maintains internal control over financial reporting to provide reasonable assurance regarding the reliability of the financial reporting. Xcel Energy 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,
None.
Information required under this Item with respect to Directors and Corporate Governance is set forth in Xcel Energy Inc.’s Proxy Statement for its
Information required under this Item is set forth in Xcel Energy Inc.’s Proxy Statement for its
Information required under this Item is contained in Xcel Energy Inc.’s Proxy Statement for its
Information required under this Item is contained in Xcel Energy Inc.’s Proxy Statement for its
Information required under this Item is contained in Xcel Energy Inc.’s 80 PART IV
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SCHEDULE I XCEL ENERGY INC.
(amounts in millions, except per share data)
(amounts in millions)
XCEL ENERGY INC. CONDENSED BALANCE SHEETS (amounts in millions)
Notes to Condensed Financial Statements Incorporated by reference are Xcel Energy’s consolidated statements of common stockholders’ equity and other comprehensive income in Part II, Item 8. Basis of Presentation — The condensed financial information of Xcel Energy Inc. is presented to comply with Rule 12-04 of Regulation S-X. Xcel Energy Inc.’s investments in subsidiaries are presented under the equity method of accounting. Under this method, the assets and liabilities of subsidiaries are not consolidated. The investments in net assets of the subsidiaries are recorded in the balance sheets. The income from operations of the subsidiaries is reported on a net basis as equity in income of subsidiaries. As a holding company with no business operations, Xcel Energy Inc.’s assets consist primarily of investments in its utility subsidiaries. Xcel Energy Inc.’s material cash inflows are only from dividends and other payments received from its utility subsidiaries and the proceeds raised from the sale of debt and equity securities. The ability of its utility subsidiaries to make dividend and other payments is subject to the availability of funds after taking into account their respective funding requirements, the terms of their respective indebtedness, the regulations of the FERC under the Federal Power Act, and applicable state laws. Management does not expect maintaining these requirements to have an impact on Xcel Energy Inc.’s ability to pay dividends at the current level in the foreseeable future. Each of its utility subsidiaries, however, is legally distinct and has no obligation, contingent or otherwise, to make funds available to Xcel Energy Inc. 85 Guarantees and Indemnifications Xcel Energy Inc. provides guarantees and bond indemnities under specified agreements or transactions, which guarantee payment or performance. Xcel Energy Inc.’s exposure is based upon the net liability of the relevant subsidiary under the specified agreements or transactions. Most of the guarantees and bond indemnities issued by Xcel Energy Inc. limit the exposure to a maximum stated amount. As of Dec. 31, Guarantees and bond indemnities issued and outstanding as of Dec. 31,
Indemnification Agreements Xcel Energy Inc. provides indemnifications through contracts entered into in the normal course of business. Indemnifications are primarily against adverse litigation outcomes in connection with underwriting agreements, breaches of representations and warranties, including corporate existence, transaction authorization and certain income tax matters. Obligations under these agreements may be limited in terms of duration or amount. Maximum future payments under these indemnifications cannot be reasonably estimated as the dollar amounts are often not explicitly stated. Related Party Transactions — Xcel Energy Inc. presents related party receivables net of payables. Accounts receivable
Dividends — Cash dividends paid to Xcel Energy Inc. by its subsidiaries were $2,527 million, $2,987 million Money Pool — FERC approval was received to establish a utility money pool arrangement with the utility subsidiaries, subject to receipt of required state regulatory approvals. The utility money pool 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 lending for Xcel Energy Inc.:
See notes to the consolidated financial statements in Part II, Item 8. SCHEDULE II Xcel Energy Inc. and Subsidiaries Valuation and Qualifying Accounts Years Ended Dec. 31
(b)Deductions related primarily to bad debt write-offs. (c)Primarily the reduction of valuation allowances for North Dakota ITC, net of federal income tax benefit, that is offset to a regulatory liability forecasted to be used prior to expiration along with valuation allowances that expired. (d)Primarily reductions to valuation allowances due to additional NOLs and tax credits forecasted to be used prior to expiration.
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.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities on the date indicated above.
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