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As Of Filer Filing For·On·As Docs:Size 2/21/20 Xcel Energy Inc 10-K 12/31/19 149:36M |
Document/Exhibit Description Pages Size 1: 10-K Annual Report HTML 4.03M 2: EX-4.01 Instrument Defining the Rights of Security Holders HTML 51K 3: EX-10.32 Material Contract HTML 83K 4: EX-21.01 Subsidiaries List HTML 47K 5: EX-23.01 Consent of Experts or Counsel HTML 44K 6: EX-24.01 Power of Attorney HTML 77K 7: EX-31.01 Certification -- §302 - SOA'02 HTML 46K 8: EX-31.02 Certification -- §302 - SOA'02 HTML 46K 9: EX-32.01 Certification -- §906 - SOA'02 HTML 43K 84: R1 Cover Page HTML 100K 132: R2 Consolidated Statements of Income HTML 119K 114: R3 Consolidated Statements of Income (Parenthetical) HTML 41K 31: R4 Consolidated Statements of Comprehensive Income HTML 71K 83: R5 Consolidated Statements of Comprehensive Income - HTML 52K Parenthetical 131: R6 Consolidated Statements of Cash Flows HTML 161K 113: R7 Consolidated Balance Sheets HTML 176K 33: R8 Consolidated Balance Sheets (Parenthetical) HTML 46K 82: R9 Consolidated Statements of Common Stockholders' HTML 90K Equity 37: R10 Consolidated Statements of Common Stockholders' HTML 44K Equity Consolidated Statements of Common Stockholders' Equity - Parenthetical 53: R11 Summary of Significant Accounting Policies HTML 89K 136: R12 Accounting Pronouncements HTML 47K 85: R13 Property Plant and Equipment Property Plant and HTML 149K Equipment 38: R14 Regulatory Assets and Liabilities HTML 189K 54: R15 Borrowings and Other Financing Instruments HTML 448K Borrowings and Other Financing Instruments 137: R16 Revenues HTML 114K 86: R17 Income Taxes HTML 205K 36: R18 Share-Based Compensation HTML 133K 55: R19 Earnings Per Share HTML 44K 133: R20 Fair Value of Financial Assets and Liabilities HTML 604K 117: R21 Benefit Plans and Other Postretirement Benefits HTML 423K 28: R22 Commitments and Contingencies HTML 477K 80: R23 Other Comprehensive Income HTML 84K 134: R24 Segments and Related Information HTML 117K 118: R25 Summarized Quarterly Financial Data (Unaudited) HTML 86K 30: R26 Schedule I, Condensed Financial 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Borrowings and Other Financing Instruments Term HTML 56K Loan Agreement (Details) 49: R52 Borrowings and Other Financing Instruments HTML 51K Bilateral Credit Agreement (Details) 65: R53 Borrowings and Other Financing Instruments Letters HTML 46K of Credit (Details) 142: R54 Borrowings and Other Financing Instruments Credit HTML 103K Facilities (Details) 93: R55 Borrowings and Other Financing Instruments Amended HTML 51K Credit Agreements (Details) 50: R56 Borrowings and Other Financing Instruments HTML 284K Long-Term Borrowings and Other Financing Instruments (Details) 66: R57 Borrowings and Other Financing Instruments HTML 42K Deferred Financing Costs (Details) 143: R58 Borrowings and Other Financing Instruments Forward HTML 69K Equity Agreements (Details) 91: R59 Borrowings and Other Financing Instruments Other HTML 44K Equity (Details) 20: R60 Borrowings and Other Financing Instruments Capital HTML 64K Stock (Details) 68: R61 Borrowings and Other Financing Instruments HTML 81K Dividend and Other Capital-Related Restrictions (Details) 128: R62 Borrowings and Other Financing Instruments HTML 43K Borrowings Phantom (Details) 108: R63 Revenues (Details) HTML 103K 21: R64 Income Taxes (Details) HTML 204K 69: R65 Income Taxes Federal Audit (Details) HTML 42K 129: R66 Income Taxes Unrecognized Tax Benefit (Details) HTML 77K 109: R67 Income Taxes Other Income Tax Matters (Details) HTML 97K 18: R68 Income Taxes Income Tax Phantom (Details) HTML 41K 75: R69 Incentive Plans Including Share-Based Compensation HTML 89K (Details) 63: R70 Share-Based Compensation Restricted Stock HTML 44K (Details) 42: R71 Other Equity Awards (Details) HTML 94K 98: R72 Stock Equivalent Units (Details) HTML 73K 146: R73 TSR Liability Awards (Details) HTML 64K 62: R74 Share-Based Compensation Expense (Details) HTML 59K 41: R75 Share-Based Compensation Share-Based Compensation HTML 44K Phantom (Details) 97: R76 Common Stock Equivalent (Details) HTML 42K 145: R77 Nuclear Decommissioning Fund (Details) HTML 138K 56: R78 Fair Value of Financial Assets and Liabilities HTML 72K Rabbi Trusts (Details) 44: R79 Interest Rate Derivatives (Details) HTML 45K 64: R80 Fair Value of Financial Assets and Liabilities HTML 52K Commodity Derivatives (Details) 43: R81 Fair Value of Financial Assets and Liabilities HTML 53K Consideration of Credit Risk and Concentrations (Details) 99: R82 Qualifying Cash Flow Hedges (Details) HTML 100K 147: R83 Credit Related Contingent Features (Details) HTML 43K 60: R84 Recurring Fair Value Measurements (Details) HTML 208K 39: R85 Fair Value of Long-Term Debt (Details) HTML 45K 96: R86 Fair Value of Financial Assets and Liabilities HTML 51K Fair Value Phantom (Details) 144: R87 Pension and Postretirement Health Care Benefits HTML 93K (Details) 58: R88 Plan Assets (Details) HTML 98K 46: R89 Funded Status (Details) HTML 220K 19: R90 Benefit Plans and Other Postretirement Benefits HTML 44K Net Periodic Benefit Cost (Credit) (Details) 67: R91 Benefit Plans and Other Postretirement Benefits HTML 45K Cash Flows (Details) 127: R92 Benefit Plans and Other Postretirement Benefits, HTML 41K Defined Contribution Plans (Details) 107: R93 Benefit Plans and Other Postretirement Benefits, HTML 54K Postretirement Health Care Benefits (Details) 23: R94 Benefit Plans and Other Postretirement Benefits, HTML 99K Fair Value of Postretirement Benefit Plan Assets (Details) 71: R95 Benefit Plans and Other Postretirement Benefits, HTML 223K Postretirement Benefit Plan Benefit Obligations, Cash Flows and Benefit Costs (Details) 130: R96 Projected Benefit Payments (Details) HTML 89K 110: R97 Benefit Plans and Other Postretirement Benefits HTML 41K Plan Amendments (Details) 16: R98 Commitments and Contingencies Gas Trading HTML 42K Litigation (Details) 73: R99 Commitments and Contingencies Line Extension HTML 44K Disputes (Details) 72: R100 Commitments and Contingencies MEC Acquisition HTML 45K (Details) 15: R101 Commitments and Contingencies Sherco (Details) HTML 46K 111: R102 Commitments and Contingencies MISO ROE Complaints HTML 55K (Details) 125: R103 Commitments and Contingencies Texas Fuel HTML 44K Reconciliation (Details) 74: R104 Commitments and Contingencies SPP OATT Upgrade HTML 44K Costs (Details) 17: R105 Commitments and Contingencies MGP Sites (Details) HTML 52K 112: R106 Commitments and Contingencies Environmental HTML 79K Requirements - Water and Waste (Details) 126: R107 Commitments and Contingencies Environmental HTML 50K Requirements - Air (Details) 70: R108 Asset Retirement Obligations (Details) HTML 108K 22: R109 Commitments and Contingencies Removal Costs HTML 50K (Details) 47: R110 Nuclear Insurance (Details) HTML 64K 59: R111 Commitments and Contingencies Nuclear Fuel HTML 46K Disposal (Details) 149: R112 Regulatory Plant Decommissioning Recovery HTML 104K (Details) 95: R113 Commitments and Contingencies Nuclear Obligations HTML 50K Phantom (Details) 45: R114 Commitments and Contingencies Leases (Details) HTML 214K 57: 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Document |
i ☒ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
i ☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
i 001-3034 |
(Commission
File Number) |
Xcel Energy Inc. | ||
(Exact name of registrant as specified in its charter) | ||
i Minnesota | i 41-0448030 | |||
(State
or Other Jurisdiction of Incorporation or Organization) | (IRS Employer Identification No.) | |||
i 414 Nicollet Mall | i Minneapolis | i Minnesota | i 55401 | |
(Address
of Principal Executive Offices) | (Zip Code) |
i 612 | i 330-5500 |
(Registrant’s
Telephone Number, Including Area Code) |
Title of each class | Trading Symbol | Name of each exchange on which registered | ||
i Common
Stock, $2.50 par value | i XEL | i Nasdaq Stock Market LLC |
PART I | ||
Item
1 — | ||
Item
1A — | ||
Item 1B — | ||
Item 2 — | ||
Item
3 — | ||
Item 4 — | ||
PART
II | ||
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 |
OAG | Minnesota Office of the Attorney General |
PHMSA | 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 | |
CIP | Conservation improvement program |
DCRF | Distribution cost recovery factor |
DSM | Demand side management |
DSMCA | Demand side management cost adjustment |
ECA | Retail electric commodity adjustment |
EECRF | Energy
efficiency cost recovery factor |
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 |
PCRF | 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 | Renewable energy standard adjustment |
SCA | Steam cost adjustment |
SEP | State energy policy rider |
TCA | Transmission cost adjustment |
TCR | Transmission cost recovery adjustment |
TCRF | Transmission
cost recovery factor |
Other | |
ADIT | Accumulated deferred income taxes |
AFUDC | Allowance for funds used during construction |
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 |
CACJA | Clean Air Clean Jobs Act |
CAISO | California
Independent System Operator |
CapX2020 | Alliance of electric cooperatives, municipals and investor-owned utilities in the upper Midwest involved in a joint transmission line planning and construction effort |
CBA | Collective-bargaining agreement |
CCR | Coal combustion residuals |
CCR Rule | Final rule (40 CFR 257.50 - 257.107) published by the EPA regulating the management, storage and disposal of CCRs as a nonhazardous waste |
CDD | Cooling
degree-days |
CEO | Chief executive officer |
CFO | Chief financial officer |
CEP | Colorado Energy Plan |
CIG | Colorado Interstate Gas Company, LLC |
CPCN | Certificate of public convenience and necessity |
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 level. |
DRC | Development Recovery Company |
DRIP | Dividend Reinvestment Program |
EEI | Edison Electric
Institute |
ELG | Effluent limitations guidelines |
EMANI | European Mutual Association for Nuclear Insurance |
EPS | Earnings per share |
EPU | Extended power uprate |
ETR | 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 |
IPP | 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. |
NOI | Notice of Inquiry |
NOL | 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 | Standard & Poor’s Ratings Services |
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 |
TransCo | Transmission-only subsidiary |
TSR | 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 |
Forward-Looking Statements |
Where to Find More Information |
Overview |
Utility Subsidiaries’
Service Territory | |||
Electric customers | 3.7 million | ||
Natural
gas customers | 2.1 million | ||
Total assets | $50.4 billion | ||
Electric generating capacity | 18,730 MW | ||
Electric transmission lines (conductor miles) | 108,238 miles | ||
Electric distribution
lines (conductor miles) | 207,524 miles | ||
Natural gas transmission lines | 2,177 miles | ||
Natural gas distribution lines | 35,624 miles | ||
Natural gas storage capacity | 53.4 Bcf | ||
Vision,
Mission and Values |
Strategic Priorities |
• | Offering
energy efficiency programs; |
• | Retiring coal units and modernizing generating plants; and |
• | Advancing power grid capabilities. |
• | Near our Sherco plant, scheduled to close by 2030, we are partnering with local leadership and a major data center to locate a $600 million data center. Additionally, Xcel Energy actively worked to relocate a metal recycling plant near our plant; and |
• | We retained Evraz Steel in Colorado, a major Pueblo
employer, by partnering with the company and community to create an affordable solar solution to meet their needs. |
• | Xcel
Energy has offered domestic partner benefits since 1995; |
• | The Company’s CEO has signed the Action for Diversity & Inclusion Pledge, for the advancement of diversity and inclusion within the workplace, and Xcel Energy has an employee-led Diversity & Inclusion Council; |
• | We have been selected among the nation’s top corporations for lesbian, gay, bisexual, transgender, and queer equality by earning a perfect score on the Human Rights
Campaign’s 2019 Corporate Equality Index for the past 4 years; and |
• | Xcel Energy was named to the 2019 Military Times Best for Vets Employers rankings for the sixth straight year and currently employs more than 1,000 veterans, nearly 10% of our workforce. |
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 | $19.9 billion | ||||
Rate Base | $11.2 billion | ||||
ROE | 9.31% | ||||
Electric
generating capacity | 7,712 MW | ||||
Gas storage capacity | 17.1 Bcf | ||||
Electric transmission lines (conductor miles) | 33,528 miles | ||||
Electric distribution lines (conductor miles) | 80,186
miles | ||||
Natural gas transmission lines | 86 miles | ||||
Natural gas distribution lines | 10,518 miles | ||||
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 | $2.8 billion | ||||
Rate Base | $1.7 billion | ||||
ROE | 8.27% | ||||
Electric
generating capacity | 548 MW | ||||
Gas storage capacity | 3.8 Bcf | ||||
Electric transmission lines (conductor miles) | 12,285 miles | ||||
Electric distribution lines (conductor miles) | 27,504
miles | ||||
Natural gas transmission lines | 3 miles | ||||
Natural gas distribution lines | 2,473 miles | ||||
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 | $19.0 billion | ||||
Rate Base | $12.4 billion | ||||
ROE | 8.69% | ||||
Electric
generating capacity | 5,666 MW | ||||
Gas storage capacity | 32.5 Bcf | ||||
Electric transmission lines (conductor miles) | 24,008 miles | ||||
Electric distribution lines (conductor miles) | 78,023
miles | ||||
Natural gas transmission lines | 2,057miles | ||||
Natural gas distribution lines | 22,633 miles | ||||
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 | $7.9 billion | ||||
Rate
base | $4.9 billion | ||||
ROE | 9.71% | ||||
Electric generating capacity | 4,804 MW | ||||
Electric transmission lines | 38,418 miles | ||||
Electric
distribution lines | 21,810 miles | ||||
Operations
Overview |
Electric Operations |
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 | ˘ |
(a) | Includes biomass and hydroelectric |
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 | ||||||
PPAs | Range | PPAs | Range | |||||
NSP
System | 131 | 0.7 MW — 205.5 MW | 132 | 0.7 MW - 205.5 MW | ||||
PSCo | 20 | 2.0 MW — 300.5 MW | 19 | 2.0
MW - 300.5 MW | ||||
SPS | 18 | 0.7 MW — 250.0 MW | 18 | 0.7 MW - 250.0 MW |
Utility
Subsidiary | 2019 | 2018 | ||
NSP System | 2,780 MW | 2,550 MW | ||
PSCo | 3,165 MW | 3,160
MW | ||
SPS | 2,045 MW | 1,565 MW |
Utility Subsidiary (a) | 2019 | 2018 | ||||||
NSP
System | $ | 35 | $ | 37 | ||||
PSCo | 47 | — |
(a) | The
table reflects owned wind sites that were in commercial operation for the full calendar year. The Hale wind farm for SPS was put into service in June 2019 and the Rush Creek wind farm was put into service in December 2018. |
Utility Subsidiary | 2019 | 2018 | ||||||
NSP
System | $ | 41 | $ | 44 | ||||
PSCo | 41 | 43 | ||||||
SPS | 25 | 26 |
Project | Utility Subsidiary | Capacity | ||
Rush Creek | PSCo | 582
MW | ||
Hale | SPS | 460 MW | ||
Foxtail | NSP-Minnesota | 150 MW | ||
Lake Benton | NSP-Minnesota | 99
MW | ||
Various PPAs | Various | ~300 MW |
Project | Utility
Subsidiary | Capacity | Estimated Completion | |||
Freeborn | NSP-Minnesota | 200 MW | 2020 | |||
Blazing Star 1 | NSP-Minnesota | 200
MW | 2020 | |||
Blazing Star 2 | NSP-Minnesota | 200 MW | 2020 | |||
Crowned Ridge (a) | NSP-Minnesota | 200
MW | 2020 | |||
Jeffers (b) | NSP-Minnesota | 44 MW | 2020 | |||
Community Wind North(b) | NSP-Minnesota | 26
MW | 2020 | |||
Dakota Range | NSP-Minnesota | 300 MW | 2021 | |||
Cheyenne Ridge | PSCo | 500
MW | 2020 | |||
Sagamore | SPS | 522 MW | 2020 | |||
Various PPAs | Various | ~900
MW | 2020 - 2021 |
(a) | Build-own-transfer project. |
(b) | Repowering project. |
Type | Utility
Subsidiary | Capacity | ||
Distributed Generation | NSP System | 736 MW | ||
Utility-Scale | NSP System | 266 MW | ||
Distributed Generation | PSCo | 557
MW | ||
Utility-Scale | PSCo | 305 MW | ||
Distributed Generation | SPS | 10 MW | ||
Utility-Scale | SPS | 191
MW |
Utility Subsidiary | Nuclear | ||||||
NSP System | Cost | Percent | |||||
2019 | $ | 0.81 | 45 | % | |||
2018 | 0.80 | 45 |
Approved
(2019 to 2027) | ||||||
Year | Utility Subsidiary | Plant | Capacity | |||
2022 | PSCo | Comanche 1 | 325
MW | |||
2023 | NSP-Minnesota | Sherco 2 | 682 MW | |||
2025 | PSCo | Comanche 2 | 335
MW | |||
2025 | PSCo | Craig 1 | 42 MW | |||
2026 | NSP-Minnesota | Sherco 1 | 680
MW |
Proposed (2028 to 2030) | ||||||
Year | Utility Subsidiary | Plant | Capacity | |||
2028 | NSP-Minnesota | A.S
King | 511 MW | |||
2030 | NSP-Minnesota | Sherco 3 | 517 MW |
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 |
(a) | Includes
refuse-derived fuel and wood for the NSP System. |
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) | ||||||||||
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 | 5 | 115 KV | ||||
Nelson-Wabasha | NSP-Wisconsin | 2 | 69
KV | ||||
Pawnee-Daniels Park | PSCo | 125 | 345 KV | ||||
Thornton Substation | PSCo | 2 | 115
KV | ||||
TUCO-Yoakum-Hobbs | SPS | 64 | 345 KV | ||||
NEF-Cardinal | SPS | 15 | 115
KV | ||||
Potash Junction-Livingston Ridge | SPS | 15 | 115 KV | ||||
Mustang-Shell | SPS | 9 | 115
KV | ||||
North Loving-South Loving | SPS | 3 | 115 KV | ||||
Cunningham-Monument Tap | SPS | 7 | 115
KV |
Project | Utility Subsidiary | Miles | Size | Completion
Date | |||||
Huntley-Wilmarth | NSP-Minnesota | 50 | 345 KV | 2021 | |||||
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 |
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 |
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 |
(a) | Increase
in maximum MMBtu output due to colder winter temperatures in 2019. |
Utility Subsidiary | 2019 | 2018 | ||||||
NSP-Minnesota | $ | 3.71 | $ | 4.03 | ||||
NSP-Wisconsin | 3.49 | 3.84 | ||||||
PSCo | 2.95 | 3.20 |
General |
Public Utility Regulation |
Environmental |
• | $345 million in 2019; |
• | $335 million in 2018; and |
• | $315 million in 2017. |
• | $30 million in 2019; |
• | $50
million in 2018; and |
• | $60 million in 2017. |
Capital Spending and Financing |
Employees |
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 (c) | 61 | Chairman
of the Board, President and Chief Executive Officer and Director, Xcel Energy Inc. | August 2011 — Present | |||
Chief Executive Officer, NSP-Minnesota, NSP-Wisconsin, PSCo, and SPS | January 2015 — Present | |||||
Brett C. Carter | 53 | 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 | |||||
Senior
Vice President and Chief Operating Officer, Bank of America | March 2015 — October 2015 | |||||
Senior Vice President and Chief Distribution Officer, Duke Energy Co., an electric power company | February 2013 — March 2015 | |||||
Christopher B. Clark | 53 | President
and Director, NSP-Minnesota | January 2015 — Present | |||
David L. Eves (d) | 61 | Executive Vice President and Group President, Utilities, Xcel Energy Inc. | March 2018 — Present | |||
President
and Director, PSCo | January 2015 — February 2018 | |||||
Darla Figoli | 57 | Senior Vice President, Human Resources & Employee Services, Chief Human Resources Officer, Xcel Energy Inc. | May 2018 — Present | |||
Senior
Vice President, Human Resources and Employee Services, Xcel Energy Inc. | May 2015 — May 2018 | |||||
Vice President, Human Resources, Xcel Energy Inc. | February 2010 — May 2015 | |||||
49 | Executive
Vice President, Chief Financial Officer, Xcel Energy Inc. | May 2016 — Present | ||||
Senior Vice President and Chief Financial Officer, Luminant, a subsidiary of Energy Future Holdings Corp. (e) | February 2012 — April 2016 | |||||
David T. Hudson | 59 | President
and Director, SPS | January 2015 — Present | |||
Alice Jackson | 41 | 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 | |||||
Kent T. Larson (f) | 60 | Executive
Vice President and Group President Operations, Xcel Energy Inc. | January 2015 — Present | |||
Timothy O’Connor (g) | 60 | Senior Vice President, Chief Nuclear Officer, Xcel Energy Services Inc. | February 2013 — Present | |||
Judy M. Poferl (h) | 60 | Senior
Vice President, Corporate Secretary and Executive Services, Xcel Energy Inc. | January 2015 — Present | |||
48 | Senior Vice President, Controller, Xcel Energy Inc. | January 2015 — Present | ||||
Mark E. Stoering | 59 | President
and Director, NSP-Wisconsin | January 2015 — Present | |||
Scott M. Wilensky | 63 | Executive Vice President, General Counsel, Xcel Energy Inc. | January 2015 — Present |
(a) | No
family relationships exist between any of the executive officers or directors. |
(b) | Ages as of Dec. 31, 2019. |
(c) | Effective March 31, 2020, Mr. Fowke will cease to serve as President and Mr. Frenzel will become President and Chief Operating Officer of Xcel Energy Inc. At the same time, Brian J. Van Abel will become Executive Vice President, Chief Financial Officer of Xcel Energy
Inc. |
(d) | Effective May 1, 2020, Mr. Eves will be retiring from the Company after retiring from his executive officer positions effective March 30, 2020. |
(e) | 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. |
(f) | Effective May 31, 2020, Mr. Larson will be leaving the Company after ceasing to serve in his executive officer positions effective March 30, 2020. |
(g) | Effective
March 31, 2020, Mr. O’Connor will become Executive Vice President, Chief Generation Officer. |
(h) | Effective March 31, 2020, Ms. Poferl will be retiring from the Company. Frank Prager has been elected to serve with the title of Senior Vice President, Strategy and Planning and External Affairs effective March 1, 2020. |
ITEM
1A — RISK FACTORS |
• | 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; and |
• | Technological and financial uncertainties related to the costs of decommissioning nuclear plants may cause our funding obligations to change. |
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 | 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 |
(a) | Summer
2019 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 maximum generation
levels for these wind units. Capacity is attainable only when wind conditions are sufficiently available (on-demand net dependable capacity is zero). |
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 |
(a) | Summer
2019 net dependable capacity. |
(b) | Refuse-derived fuel is made from municipal solid waste. |
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 |
(a) | Summer
2019 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 is expected to be retired early in 2025. |
(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 maximum generation levels for these wind units. Capacity is attainable only when wind conditions are sufficiently available (on-demand net dependable capacity is zero). |
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 |
(a) | Summer
2019 net dependable capacity. |
(b) | Values disclosed are the maximum generation levels for these wind units. Capacity is attainable only when wind conditions are sufficiently available (on-demand net dependable capacity is zero). |
Conductor
Miles | NSP-Minnesota | NSP-Wisconsin | PSCo | SPS | ||||||||
500 KV | 2,917 | — | — | — | ||||||||
345
KV | 13,133 | 3,337 | 5,036 | 9,566 | ||||||||
230 KV | 2,203 | — | 12,108 | 9,784 | ||||||||
161
KV | 673 | 1,821 | — | — | ||||||||
138 KV | — | — | 92 | — | ||||||||
115
KV | 8,045 | 1,815 | 5,055 | 14,662 | ||||||||
Less than 115 KV | 86,743 | 32,816 | 79,740 | 26,216 |
NSP-Minnesota | NSP-Wisconsin | PSCo | SPS | |||||||||
Quantity | 346 | 204 | 233 | 452 |
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, 2014 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) | 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 |
(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 ASU No. 2015-17 (Balance Sheet Classification of Deferred Taxes, Topic 740), $140 million of current deferred income taxes
was retrospectively reclassified to long-term deferred income tax liabilities on the consolidated balance sheet as of Dec. 31, 2015. |
(c) | As a result of adopting ASU No. 2015-03 (Simplifying the Presentation of Debt Issuance Costs, Subtopic 835-30), $92 million of deferred debt issuance costs was retrospectively reclassified from other noncurrent assets to long-term debt on the consolidated balance sheet as of Dec. 31, 2015. |
(d) | 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. |
ITEM 7 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
Results of Operations |
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 |
(a) | Includes
income taxes. |
(b) | Amounts may not add due to rounding. |
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 |
(a) | Includes
PTCs and timing of tax reform regulatory decisions, which are primarily offset in electric margin. |
2019 | 2018 | |||||
ROE
| GAAP and Ongoing ROE | GAAP and Ongoing ROE | ||||
PSCo | 8.69 | % | 9.10 | % | ||
NSP-Minnesota | 9.31 | 8.91 | ||||
SPS | 9.71 | 9.14 | ||||
NSP-Wisconsin | 8.27 | 10.77 | ||||
Operating
Companies | 9.06 | 9.14 | ||||
Xcel Energy | 10.78 | 10.65 |
2019
vs. Normal | 2018 vs. Normal | 2019 vs. 2018 | ||||||
HDD | 10.4 | % | 2.2 | % | 6.8 | % | ||
CDD | 5.4 | 26.7 | (15.5 | ) | ||||
THI | (8.8 | ) | 37.3 | (33.2 | ) |
2019 vs. Normal | 2018 vs. Normal | 2019 vs. 2018 | |||||||||
Retail
electric | $ | 0.040 | $ | 0.114 | $ | (0.074 | ) | ||||
Firm natural gas | 0.027 | 0.007 | 0.020 | ||||||||
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 | ) |
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 |
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 |
• | PSCo — Residential sales declined due to lower use per customer, partially offset by an increased number of customers. The decline in C&I was mainly due to lower use per customer, primarily led by customers in the food products and service industries, partially offset by growth in the metal mining and fabricated metal and industries. The decrease in customer use was partially offset by an increase in the number of C&I customers; |
• | NSP-Minnesota —
Flat residential sales reflect lower use per customer offset by customer additions. The decline in C&I sales was a result of customer growth being offset by lower use per customer, and certain customers moving to co-generation. Decreased sales to C&I customers were driven by the energy and manufacturing sectors; |
• | SPS — Residential sales grew largely due to an increase in customers and higher use per customer. C&I sales grew based on higher use per small C&I customer and an overall increase in the number of C&I customers. In addition, the increase in C&I sales was driven by the oil and natural gas industry in the Southeastern New Mexico, Permian Basin area; and |
• | NSP-Wisconsin
— Residential sales growth was primarily attributable to customer additions and more use per customer. The decline in C&I sales was largely due to lower use per customer and decreased sales to the frac sand mining, food and manufacturing sectors, which was partially offset by customer additions. |
• | Overall natural gas sales reflect an increase in the number of customers combined with higher customer use, particularly C&I at PSCo. This was partially offset by a decline in C&I sales at NSP-Wisconsin, driven by the frac sand mining industry. |
(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 |
(a) | Includes
approximately $60 million of additional PTC benefit (grossed-up for tax) as compared to 2018, which are credited to customers through various regulatory mechanisms. |
(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 |
(Millions of Dollars) | 2019 vs. 2018 | |||
Plant generation | $ | (20 | ) | |
Nuclear
plant operations and amortization | (8 | ) | ||
Transmission | (7 | ) | ||
Distribution | 16 | |||
Other (net) | 5 | |||
Total
decrease in O&M expenses | $ | (14 | ) |
• | Plant generation, transmission and distribution costs were lower due to timing of maintenance activities; |
• | Nuclear plant operations and amortization were lower largely reflecting improved operating efficiencies and
reduced refueling outage costs; and |
• | Distribution expenses in 2019 were higher than 2018 due to storms, labor and overtime incurred primarily in the first six months of 2019. |
Contribution
(Millions of Dollars) | ||||||||
2019 | 2018 | |||||||
Xcel Energy Inc. financing costs | $ | (128 | ) | $ | (110 | ) | ||
Eloigne
(a) | 1 | — | ||||||
Xcel Energy Inc. taxes and other results | 12 | (5 | ) | |||||
Total
Xcel Energy Inc. and other costs | $ | (115 | ) | $ | (115 | ) |
Contribution
(Diluted Earnings (Loss) Per Share) | ||||||||
2019 | 2018 | |||||||
Xcel Energy Inc. financing costs | $ | (0.21 | ) | $ | (0.21 | ) | ||
Eloigne
(a) | — | — | ||||||
Xcel Energy Inc. taxes and other results | (0.01 | ) | (0.01 | ) | ||||
Total
Xcel Energy Inc. and other costs | $ | (0.22 | ) | $ | (0.22 | ) |
(a) | Amounts include gains or losses associated with sales of properties held by Eloigne. |
Public Utility Regulation |
Regulatory
Body / RTO | Additional Information | |
MPUC (a) | Retail rates, services, security issuances, property transfers, mergers, disposition of assets, affiliate transactions, and other aspects of electric and natural gas operations. Reviews and approves IRPs for meeting future energy needs. Certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV in Minnesota. Reviews and approves natural gas supply plans. Pipeline
safety compliance. | |
NDPSC (a) | Retail rates, services and other aspects of electric and natural gas operations. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in North Dakota. Pipeline safety compliance. | |
SDPUC | Retail rates, services and other aspects of electric operations. Regulatory authority
over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in South Dakota. Pipeline safety compliance. | |
FERC | Wholesale electric operations, hydroelectric licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transfers and mergers, and natural gas transactions in interstate commerce. | |
MISO | NSP-Minnesota is a transmission owning member of the MISO
RTO and operates within the MISO RTO and wholesale markets. NSP-Minnesota makes wholesale sales in other RTO markets at market-based rates. NSP-Minnesota and NSP-Wisconsin also make wholesale electric sales at market-based prices to customers outside of their balancing authority as jointly authorized by the FERC. | |
DOT | Pipeline safety compliance. | |
Minnesota Office of Pipeline Safety | Pipeline safety compliance. |
(a) | Jurisdictional
Cost Recovery Allocation — In December 2016, NSP-Minnesota filed a resource treatment framework with the NDPSC and MPUC to allow NSP-Minnesota’s operations in North Dakota and Minnesota to gradually become more independent of one another. The filing identified two options: a legal separation, creating a separate North Dakota operating company; or a pseudo-separation, which maintains the current corporate structure but directly assigns costs and benefits of each resource to the jurisdiction that supports it. Docket remains under consideration by the NDPSC. |
Mechanism | Additional
Information | |
CIP Rider (a) | Recovers costs of conservation and DSM programs. | |
EIR | Recovers costs of environmental improvement projects. | |
RDF | Allocates money collected from customers to support research and development of emerging renewable energy projects and technologies. | |
RES | Recovers
cost of renewable generation in Minnesota. | |
RER | Recovers the cost of renewable generation in North Dakota. | |
SEP | Recovers costs related to various energy policies approved by the Minnesota legislature. | |
TCR | Recovers costs for investments in electric transmission and distribution grid modernization. | |
Infrastructure
Rider | Recovers costs for investments in generation and incremental property taxes in South Dakota. | |
FCA (b) | Minnesota, North Dakota and South Dakota include a FCA for monthly billing adjustments to recover changes in prudently incurred costs of fuel related items and purchased energy. Capacity costs are recovered through base rates and are not recovered through the FCA. MISO costs are generally recovered through either the FCA or base rates. | |
PGA | Provides
for prospective monthly rate adjustments for costs of purchased natural gas, transportation and storage service. Includes a true-up process for difference between projected and actuals costs. | |
GUIC Rider | Recovers costs for transmission and distribution pipeline integrity management programs, including: funding for pipeline assessments, deferred costs for sewer separation and pipeline integrity management programs. |
(a) | Minnesota state law requires NSP-Minnesota to invest 2% of its state electric revenues and
0.5% of its state gas revenues in CIP. These costs are recovered through an annual cost-recovery mechanism. |
(b) | In 2017, the MPUC changed the FCA process in Minnesota, which will implemented in 2020. Under the new process, each month utilities would collect amounts equal to the baseline cost of energy set at the start of the plan year (base would be reset annually). Monthly variations to the baseline costs would be tracked and netted over a 12-month period. Utilities would issue refunds above the baseline costs and could seek recovery of any overage. |
Mechanism | Utility Service | Amount Requested (in millions) | Filing Date | Approval | Additional
Information | |||||
MPUC | ||||||||||
2018 TCR | Electric | $98 | November 2017 | Received | In November 2019, the MPUC issued an order setting an ROE of 9.06% and recovery of 2017-2018 expenses related
to advanced grid investments. | |||||
2020 TCR | Electric | $82 | November 2019 | Pending | In November 2019, NSP-Minnesota filed the 2020 TCR Rider. The filing included an ROE of 9.06%. Timing of an MPUC ruling is uncertain. | |||||
2019
GUIC | Natural Gas | $29 | November 2018 | Pending | In November 2018, NSP-Minnesota filed the 2019 GUIC Rider with the MPUC. The filing included an ROE of 10.25%. Timing of an MPUC ruling is uncertain. | |||||
2020 GUIC | Natural
Gas | $21 | November 2019 | Pending | In November 2019, NSP-Minnesota filed the 2020 GUIC Rider with the MPUC. The filing included an ROE of 9.04%. Timing of an MPUC ruling is uncertain. | |||||
2018 RES | Electric | $23 | November
2017 | Received | In November 2019, the MPUC approved an order setting an ROE of 9.06%. | |||||
2020 RES | Electric | $102 | November 2019 | Pending | In
November 2019, NSP-Minnesota filed the 2020 RES Rider with the MPUC. 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%. Timing of an MPUC ruling is uncertain. |
• | Extends the life of the Monticello nuclear plant from 2030 to 2040; |
• | Continues to run PI through current end of life (2033 and 2034); |
• | Includes
the MEC acquisition and construction of the Sherco combined cycle natural gas plant; |
• | Includes the early retirement of the King coal plant (511 MW) in 2028 and the Sherco 3 coal plant (517 MW) in 2030; |
• | Adds approximately 1,700 MW of firm peaking (combustion turbine, pumped hydro, battery storage, demand response, etc.); |
• | Adds
approximately 1,200 MW of wind replacement; and |
• | Adds approximately 4,000 MW of solar. |
Regulatory Body / RTO | Additional Information | |
PSCW | Retail rates, services and other aspects of electric and natural gas operations. Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built. The PSCW has a biennial base rate
filing requirement. By June of each odd numbered year, NSP-Wisconsin must submit a rate filing for the test year beginning the following January. Pipeline safety compliance. | |
MPSC | Retail rates, services and other aspects of electric and natural gas operations. Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built. Pipeline safety compliance. | |
FERC | Wholesale electric operations,
hydroelectric generation licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce. | |
MISO | NSP-Wisconsin is a transmission owning member of the MISO RTO that operates within the MISO RTO and wholesale energy market. NSP-Wisconsin and NSP-Minnesota are jointly authorized by the FERC to make wholesale electric sales at market-based prices. | |
DOT | Pipeline safety compliance. |
Mechanism | Additional Information | |
Annual Fuel Cost Plan (a) | NSP-Wisconsin does not have an automatic electric fuel adjustment clause. Under Wisconsin rules, utilities submit a forward-looking annual fuel cost plan to the PSCW. Once the PSCW approves the plan, utilities defer the amount of any fuel cost under-recovery or over-recovery in excess of a 2% annual tolerance band,
for future rate recovery or refund. Approval of a fuel cost plan and any rate adjustment for refund or recovery of deferred costs is determined by the PSCW. Rate recovery of deferred fuel cost is subject to an earnings test based on the most recently authorized ROE. Under-collections that exceed the 2% annual tolerance band may not be recovered if the utility earnings for that year exceed the authorized ROE. | |
Power Supply Cost Recovery Factors | NSP-Wisconsin’s retail electric rate schedules for Michigan customers include power supply cost recovery factors, based on 12-month projections. After each 12-month period, a reconciliation is submitted whereby over-recoveries are refunded and any under-recoveries are collected from customers. | |
Wisconsin
Energy Efficiency Program | The primary energy efficiency program is funded by the utilities, but operated by independent contractors subject to oversight by the PSCW and utilities. NSP-Wisconsin recovers these costs from customers. | |
PGA | NSP-Wisconsin has a retail PGA cost-recovery mechanism for Wisconsin to recover the actual cost of natural gas and transportation and storage services. | |
Natural Gas Cost-Recovery Factor (MI) | NSP-Wisconsin’s natural
gas rates for Michigan customers include a natural gas cost-recovery factor, based on 12-month projections and trued-up to actual amounts on an annual basis. |
(a) | NSP-Wisconsin’s electric fuel costs were lower than authorized in rates and outside the 2% annual tolerance band in 2019. Under the fuel cost recovery rules, NSP-Wisconsin retained the $3.3 million of over-recovered fuel costs (amounts within annual tolerance band) and deferred $9.7 million (amounts in excess of annual tolerance band) as a regulatory liability. NSP-Wisconsin plans to file a reconciliation of 2019 fuel costs with the PSCW by March 2020. |
Mechanism | Utility Service | Amount Requested (in millions) | Filing Date | Approval | Additional
Information | |||||
PSCW | ||||||||||
Rate Case | Electric & Natural Gas | N/A | May 2019 | Received | In May 2019, NSP-Wisconsin filed an application with the PSCW seeking no change to base electric
rates through Dec. 31, 2021; and a $3.2 million (4.6%) decrease to base natural gas rates, effective Jan. 1, 2020, and no additional changes to base natural gas rates through Dec. 31, 2021. The settlement is based on an ROE of 10.0% and an equity ratio of 52.5%. In September 2019, the PSCW issued an interim order approving the settlement agreement as filed with one minor modification, to remove the deferral of pension settlement accounting costs for 2021. A final order was received in December 2019. |
Regulatory Body / RTO | Additional Information | |
CPUC | Retail
rates, accounts, services, issuance of securities and other aspects of electric and natural gas operations. Pipeline safety compliance. | |
FERC | Wholesale electric operations, accounting practices, hydroelectric licensing, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with the NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce. Wholesale electric sales at cost-based prices to customers inside PSCo’s balancing authority area and at market-based prices to customers outside PSCo’s balancing authority area. PSCo holds a FERC certificate
that allows it to transport natural gas in interstate commerce without PSCo becoming subject to full FERC jurisdiction. | |
RTO | PSCo is not presently a member of an RTO and does not operate within an RTO energy market. However, PSCo does make certain sales to other RTO’s, including SPP and participates in a joint dispatch agreement with neighboring utilities. | |
DOT | Pipeline safety compliance. |
Mechanism | Additional
Information | |
ECA | Recovers fuel and purchased energy costs. Short-term sales margins are shared with customers through the ECA. The ECA is revised quarterly. | |
PCCA | Recovers purchased capacity payments. | |
SCA | Recovers difference between actual fuel costs and costs recovered under steam service rates. The SCA rate is revised quarterly. | |
DSMCA | Recovers
DSM, interruptible service costs and performance initiatives for achieving energy savings goals. | |
RESA | Recovers the incremental costs of compliance with the RES with a maximum of 2% of the customer’s bill. | |
WCA | Recovers costs for customers who choose renewable resources. | |
TCA | Recovers costs for transmission investment outside of rate cases. | |
CACJA | Recovers
costs associated with the CACJA. | |
FCA | PSCo recovers fuel and purchased energy costs from wholesale electric customers through a fuel cost adjustment clause approved by the FERC. Wholesale customers pay production costs through a forecasted formula rate subject to true-up. | |
GCA | Recovers costs of purchased natural gas and transportation and is revised quarterly to allow for changes in natural gas rates. | |
PSIA | Recovers
costs for transmission and distribution pipeline integrity management programs. |
Mechanism | Utility Service | Amount Requested (in millions) | Filing
Date | Approval | Additional Information | |||||
CPUC | ||||||||||
Rate Case | Steam | $7 | January 2019 | Received | In
September 2019, the CPUC approved PSCo’s Settlement Agreement with CPUC Staff and the City of Denver. The settlement reflects an ROE of 9.67% for AFUDC purposes, an equity ratio of 56.04% and utilization of tax reform benefits. The first stepped increase went into effect Oct. 1, 2019, with full rates effective Oct. 1, 2020. | |||||
Rate Case Appeal | Natural Gas | N/A | April 2019 | Pending | In
April 2019, PSCo filed an appeal seeking judicial review of the CPUC’s prior ruling regarding PSCo’s last natural gas rate case (approved in December 2018). Appeal requests review of the following: denial of a return on the prepaid pension and retiree medical assets; the use of a capital structure that is not based on the actual historical test year level; and the use of an average rate base methodology rather than a year-end rate base methodology. Timeline on a final ruling is unknown. | |||||
DSM Incentive | Electric & Natural Gas | $12 | April
2019 | Received | PSCo earned an electric and natural gas DSM incentive of $9 million and $3 million, respectively, for achieving its 2018 savings goals. |
Revenue Request (Millions of Dollars) | 2020 | |||
Company
filed rebuttal | $ | 353 | ||
ROE | (55 | ) | ||
Impact of change in test year | (17 | ) | ||
Property tax expense | 15 | |||
Rate
base adjustments | (11 | ) | ||
Capital structure | (5 | ) | ||
Total proposed revenue change | 280 | |||
Estimated impact of previously authorized costs (existing
riders) | 245 | |||
Net revenue change | $ | 35 |
Revenue Request (Millions of Dollars) | 2020 | |||
Capital additions (through Sept. 30, 2019) | $ | 62 | ||
Forecasted
capital additions (through Sept. 30, 2020) | 33 | |||
Sales growth (includes amounts forecasted through Sept. 30, 2020) | (29 | ) | ||
Operations and maintenance, amortization and other expenses | 29 | |||
Property
tax expense | 19 | |||
Cost of capital | 8 | |||
Updated depreciation rates | 5 | |||
Net increase to revenue | 127 | |||
Previously
authorized costs: | ||||
Transfer PSIA rider costs to base rates | 18 | |||
Total base request | $ | 145 | ||
Expected
year-end rate base | $ | 2,236 |
Total Capacity | PSCo's Ownership | |||
Wind generation | 1,100 MW | 500
MW | ||
Solar generation | 700 MW | — | ||
Battery storage | 275 MW | — | ||
Natural gas generation | 380 MW | 380
MW |
Regulatory Body / RTO | Additional Information | |
PUCT | Retail electric operations, rates, services, construction of transmission or generation and other aspects of SPS’ electric operations. The municipalities in which SPS operates in Texas have original jurisdiction over rates in those communities. The municipalities’ rate setting decisions
are subject to PUCT review. | |
NMPRC | Retail electric operations, retail rates and services and the construction of transmission or generation. | |
FERC | Wholesale electric operations, accounting practices, wholesale sales for resale, the transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers, and natural gas transactions in interstate commerce. | |
SPP RTO and SPP IM Wholesale Market | SPS
is a transmission-owning member of the SPP RTO and operates within the SPP RTO and SPP IM wholesale market. SPS is authorized to make wholesale electric sales at market-based prices. |
Mechanism | Additional Information | |
DCRF | Recovers distribution costs not included in rates in Texas. | |
EECRF | Recovers
costs for energy efficiency programs in Texas. | |
Energy Efficiency Rider | Recovers costs for energy efficiency programs in New Mexico. | |
FPPCAC | Adjusts monthly to recover actual fuel and purchased power costs in New Mexico. In October 2019, SPS filed an application to the NMPRC to approve SPS’ continued use of its FPPCAC and for reconciliation of fuel costs for the period Sept. 1, 2015, through June 30, 2019, which will determine
whether all fuel costs incurred are eligible for recovery. No procedural schedule has yet been established for this matter. | |
PCRF | Allows recovery of purchased power costs not included in Texas rates. | |
RPS | Recovers deferred costs for renewable energy programs in New Mexico. | |
TCRF | Recovers certain transmission infrastructure improvement costs and changes in wholesale transmission
charges not included in Texas base rates. | |
Fixed Fuel and Purchased Recovery Factor | Provides for the over- or under-recovery of energy expenses. Regulations require refunding or surcharging over- or under- recovery amounts, including interest, when they exceed 4% of the utility’s annual fuel and purchased energy costs on a rolling 12-month basis, if this condition is expected to continue. | |
Wholesale Fuel and Purchased Energy Cost Adjustment | SPS recovers fuel and purchased energy costs from its wholesale customers through a monthly wholesale fuel and purchased energy cost
adjustment clause accepted by the FERC. Wholesale customers also pay the jurisdictional allocation of production costs. |
Mechanism | Utility Service | Amount Requested (in millions) | Filing
Date | Approval | Additional Information | |||||
SPS (NMPRC) | ||||||||||
Rate Case | Electric | $51 | July 2019 | Pending | In
July 2019, SPS filed an electric rate case with the NMPRC seeking an increase in retail electric base rates of approximately $51 million. The rate request is based on an ROE of 10.35%, an equity ratio of 54.77%, a rate base of approximately $1.3 billion and a historic test year with rate base additions through Aug. 31, 2019. In December 2019, SPS revised its base rate increase request to approximately $47 million, based on an ROE of 10.10% and updated information. The request also included an increase of $14.6 million for accelerated depreciation including the early retirement of the Tolk Coal Plant in 2032. On Jan. 13, 2020, SPS and various parties filed an uncontested comprehensive stipulation. The stipulation includes a base rate revenue increase of $31 million, based on an ROE of 9.45% and an equity ratio of 54.77%. The
stipulation also includes an acceleration of depreciation on the Tolk Coal Plant to reflect early retirement in 2037, which results in a total increase in depreciation expense of $8 million. The Signatories will not oppose the full application of depreciation rates associated with the 2032 retirement date in SPS’ next base rate case. SPS anticipates final rates will go into effect in the second or third quarter of 2020. |
(Millions
of Dollars) | Staff | AXM | OPUC | TIEC | DOE | |||||||||||||||
SPS Direct Testimony | $ | 137 | $ | 137 | $ | 137 | $ | 137 | $ | 137 | ||||||||||
Recommended
base rate adjustments: | ||||||||||||||||||||
ROE | (22 | ) | (24 | ) | (15 | ) | (21 | ) | (24 | ) | ||||||||||
Capital
structure | (7 | ) | (10 | ) | — | (7 | ) | (3 | ) | |||||||||||
Tolk/Harrington
O&M disallowance | — | (7 | ) | — | — | — | ||||||||||||||
Distribution
and Transmission Capital Disallowances (a) | (7 | ) | — | — | — | — | ||||||||||||||
Depreciation
expense | (8 | ) | (15 | ) | (8 | ) | (20 | ) | — | |||||||||||
Excess
ADIT unprotected plant | — | — | (7 | ) | — | — | ||||||||||||||
Income
Tax Expense Differences | (12 | ) | — | — | — | — | ||||||||||||||
Other,
net | (6 | ) | (6 | ) | (1 | ) | (1 | ) | — | |||||||||||
Total
Adjustments | (62 | ) | (62 | ) | (31 | ) | (49 | ) | (27 | ) | ||||||||||
Total
proposed revenue change | $ | 75 | $ | 75 | $ | 106 | $ | 88 | $ | 110 |
Recommended
Position | Staff | AXM | OPUC (b) | TIEC | DOE | ||||||||||
ROE | 9.1 | % | 9.0 | % | — | % | 9.2 | % | 9.0 | % | |||||
Equity
Ratio | 51.00 | % | 50.00 | % | — | % | 51.00 | % | 53.00 | % |
(a) | Staff
recommends exclusion of approximately $134 million in transmission, distribution, and general plant in service in this rate case resulting in an approximate $7 million decrease to the revenue requirement. |
(b) | OPUC did not provide a recommendation for an ROE or equity ratio. For illustrative purposes an ROE of 9.5% was used. |
• | Rebuttal testimony — March
11, 2020; and |
• | Public hearing begins — March 30, 2020 |
• | New and revised environmental regulations; |
• | Impacts of variability due to participation in the SPP; |
• | Customer expectations; |
• | Technological
advances; |
• | Groundwater aquifer depletion at SPS’s Tolk Station; |
• | Aging generation fleet; |
• | Load growth and gas price variability; |
• | Changes
to tax credits and incentives; and |
• | Changes to renewable portfolio standard acquisitions. |
Critical
Accounting Policies and Estimates |
Pension
Costs | ||||||||
(Millions of Dollars) | +1% | -1% | ||||||
Rate of return | $ | (16 | ) | $ | 18 | |||
Discount
rate (a) | (5 | ) | 9 |
(a) | These costs include the effects of regulation. |
Accumulated Postretirement Benefit Obligation | Service and Interest Components | |||||||
(Millions of Dollars) | +1% | -1% | +1% | -1% | ||||
Health
care cost trend | $51 | $(43) | $2 | $(2) |
• | $150 million in January 2020; |
• | $154
million in 2019; |
• | $150 million in 2018; and |
• | $162 million in 2017. |
• | 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 liability; |
• | In 2018, the PSCW approved NSP-Wisconsin’s request for deferred accounting treatment of the 2018 pension settlement accounting expense; |
• | 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 jurisdictions; |
• | PSCo and SPS recognize pension expense in all regulatory jurisdictions based on expense consistent with accounting guidance. The Texas and Colorado electric retail jurisdictions and the Colorado gas retail jurisdiction, each record the difference between annual recognized pension expense and the annual amount of pension expense approved in their last respective general rate case as a deferral to a regulatory asset; and |
• | 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. |
Derivatives, Risk Management and Market Risk |
Futures
/ Forwards Maturity | ||||||||||||||||||||
(Millions of Dollars) | Less Than 1 Year | 1 to 3 Years | 4 to 5 Years | Greater Than 5 Years | Total Fair
Value | |||||||||||||||
NSP-Minnesota (a) | $ | (1 | ) | $ | 2 | $ | 2 | $ | 3 | $ | 6 | |||||||||
NSP-Minnesota
(b) | 2 | (3 | ) | (2 | ) | (10 | ) | (13 | ) | |||||||||||
PSCo
(b) | (4 | ) | (22 | ) | (31 | ) | — | (57 | ) | |||||||||||
$ | (3 | ) | $ | (23 | ) | $ | (31 | ) | $ | (7 | ) | $ | (64 | ) |
(a) | Prices
actively quoted or based on actively quoted prices. |
(b) | Prices based on models and other valuation methods. |
Options
Maturity | ||||||||||||||||||||
(Millions of Dollars) | Less Than 1 Year | 1 to 3 Years | 4 to 5 Years | Greater Than 5 Years | Total Fair Value | |||||||||||||||
NSP-Minnesota
(a) | $ | 4 | $ | 1 | $ | — | $ | — | $ | 5 |
(a) | Prices
based on models and other valuation methods. |
(Millions of Dollars) | 2019 | 2018 | ||||||
Fair
value of commodity trading net contract assets outstanding at Jan. 1 | $ | 17 | $ | 16 | ||||
Contracts realized or settled during the period | (22 | ) | (10 | ) | ||||
Commodity
trading contract additions and changes during the period | (54 | ) | 11 | |||||
Fair value of commodity trading net contract assets outstanding at Dec. 31 | $ | (59 | ) | $ | 17 |
(Millions
of Dollars) | Year Ended Dec. 31 | VaR Limit | Average | High | Low | |||||||||||||||
2019 | $ | 0.4 | $ | 3.0 | $ | 0.6 | $ | 0.8 | $ | 0.3 | ||||||||||
2018 | 4.8 | 6.0 | 0.6 | 5.6 | 0.1 |
Liquidity
and Capital Resources |
(Millions of Dollars) | 2019 | 2018 | 2017 | |||||||||
Net
cash provided by operating activities | $ | 3,263 | $ | 3,122 | $ | 3,126 |
(Millions of Dollars) | 2019 | 2018 | 2017 | |||||||||
Net
cash used in investing activities | $ | (4,343 | ) | $ | (3,986 | ) | $ | (3,296 | ) |
(Millions of Dollars) | 2019 | 2018 | 2017 | |||||||||
Net
cash provided by financing activities | $ | 1,181 | $ | 928 | $ | 168 |
Payments
Due by Period | ||||||||||||||||||||
(Millions of Dollars) | Total | Less than 1 Year | 1 to 3 Years | 3 to 5 Years | After 5 Years | |||||||||||||||
Long-term debt, principal
and interest payments | $ | 31,433 | $ | 1,422 | $ | 2,702 | $ | 2,514 | $ | 24,795 | ||||||||||
Finance
lease obligations | 271 | 14 | 26 | 24 | 207 | |||||||||||||||
Operating
leases obligations (a) | 2,116 | 262 | 520 | 469 | 865 | |||||||||||||||
Unconditional
purchase obligations (b) | 5,831 | 1,302 | 1,940 | 1,178 | 1,411 | |||||||||||||||
Other
long-term obligations, including current portion | 680 | 64 | 89 | 59 | 468 | |||||||||||||||
Other
short-term obligations | 442 | 442 | — | — | — | |||||||||||||||
Short-term
debt | 595 | 595 | — | — | — | |||||||||||||||
Total
contractual cash obligations | $ | 41,368 | $ | 4,101 | $ | 5,277 | $ | 4,244 | $ | 27,746 |
(a) | Included
in operating lease obligations are $236 million, $463 million, $422 million and $750 million, for the less than 1 year, 1 - 3 years, 3 - 5 years and after 5 years categories, respectively, pertaining to PPAs that were accounted for as operating leases. |
(b) | Xcel Energy Inc. and its subsidiaries have contracts providing for the purchase and delivery of a
significant portion of its fuel (nuclear, natural gas and coal) requirements. Additionally, the utility subsidiaries of Xcel Energy Inc. have entered into non-lease purchase power agreements. Certain contractual purchase obligations are adjusted on indices. Effects of price changes are mitigated through cost of energy adjustment mechanisms. |
Capital
Forecast | ||||||||||||||||||||||||
(Millions of Dollars) | 2020 | 2021 | 2022 | 2023 | 2024 | 2020 -
2024 Total | ||||||||||||||||||
By Subsidiary | ||||||||||||||||||||||||
NSP-Minnesota | $ | 2,025 | $ | 1,580 | $ | 1,670 | $ | 1,800 | $ | 1,845 | $ | 8,920 | ||||||||||||
PSCo | 1,415 | 1,445 | 1,720 | 1,565 | 1,530 | 7,675 | ||||||||||||||||||
SPS | 1,025 | 530 | 700 | 750 | 800 | 3,805 | ||||||||||||||||||
NSP-Wisconsin | 250 | 320 | 345 | 350 | 425 | 1,690 | ||||||||||||||||||
Other
(a) | (85 | ) | (65 | ) | 10 | 10 | 10 | (120 | ) | |||||||||||||||
Total
capital expenditures | $ | 4,630 | $ | 3,810 | $ | 4,445 | $ | 4,475 | $ | 4,610 | $ | 21,970 |
(a) | Other
category includes intercompany transfers for safe harbor wind turbines. The $650M non-regulated acquisition of MEC in 2020 is not included above. |
Capital
Forecast | ||||||||||||||||||||||||
(Millions of Dollars) | 2020 | 2021 | 2022 | 2023 | 2024 | 2020 - 2024
Total | ||||||||||||||||||
By Function | ||||||||||||||||||||||||
Renewables | $ | 1,760 | $ | 315 | $ | — | $ | — | $ | — | $ | 2,075 | ||||||||||||
Electric
generation | 480 | 595 | 580 | 780 | 1,000 | 3,435 | ||||||||||||||||||
Electric
transmission | 625 | 835 | 1,295 | 1,270 | 1,260 | 5,285 | ||||||||||||||||||
Electric
distribution | 885 | 1,140 | 1,415 | 1,470 | 1,350 | 6,260 | ||||||||||||||||||
Natural
gas | 520 | 450 | 600 | 560 | 640 | 2,770 | ||||||||||||||||||
Other | 360 | 475 | 555 | 395 | 360 | 2,145 | ||||||||||||||||||
Total
capital expenditures | $ | 4,630 | $ | 3,810 | $ | 4,445 | $ | 4,475 | $ | 4,610 | $ | 21,970 |
(Millions of Dollars) | ||||
Funding
Capital Expenditures | ||||
Cash from operations (a) | $ | 13,905 | ||
New debt (b) | 6,665 | |||
Equity
through the DRIP and benefit program | 400 | |||
Equity through the at-the-market program | 250 | |||
Equity through forward equity agreements (c) | 750 | |||
Base
capital expenditures 2020 - 2024 | $ | 21,970 | ||
Maturing Debt | $ | 3,245 |
• | Projected cash generation; |
• | Projected capital investment; |
• | A reasonable rate of return on shareholder investment; and |
• | The
impact on Xcel Energy’s capital structure and credit ratings. |
(Millions of Dollars) | ||||||||
Fair value of pension assets | $ | 3,184 | $ | 2,742 | ||||
Projected pension obligation (a) | 3,701 | 3,477 | ||||||
Funded
status | $ | (517 | ) | $ | (735 | ) |
(a) |
Pension Assumptions | 2019 | 2018 | ||||
Discount rate | 3.49 | % | 4.31 | % | ||
Expected
long-term rate of return | 6.87 | 6.87 |
• | $1.25 billion for Xcel Energy Inc.; |
• | $700
million for PSCo; |
• | $500 million for NSP-Minnesota; |
• | $500 million for SPS; and |
• | $150 million for NSP-Wisconsin. |
(Amounts in Millions, Except Interest Rates) | Three Months Ended Dec. 31, 2019 | |||
Borrowing limit | $ | 3,600 | ||
Amount
outstanding at period end | 595 | |||
Average amount outstanding | 663 | |||
Maximum amount outstanding | 945 | |||
Weighted average interest rate, computed
on a daily basis | 2.40 | % | ||
Weighted average interest rate at end of period | 2.34 |
(Amounts
in Millions, Except Interest Rates) | Year Ended Dec. 31, 2019 | Year Ended Dec. 31, 2018 | Year Ended Dec. 31, 2017 | |||||||||
Borrowing limit | $ | 3,600 | $ | 3,250 | $ | 3,250 | ||||||
Amount
outstanding at period end | 595 | 1,038 | 814 | |||||||||
Average amount outstanding | 1,115 | 788 | 644 | |||||||||
Maximum
amount outstanding | 1,780 | 1,349 | 1,247 | |||||||||
Weighted average interest rate, computed on a daily basis | 2.72 | % | 2.34 | % | 1.35 | % | ||||||
Weighted
average interest rate at end of period | 2.34 | 2.97 | 1.90 |
(Millions of Dollars) | Facility | Drawn (a) | Available | Cash | Liquidity | |||||||||||||||
Xcel
Energy Inc. | $ | 1,250 | $ | 759 | $ | 491 | $ | — | $ | 491 | ||||||||||
PSCo | 700 | 49 | 651 | 1 | 652 | |||||||||||||||
NSP-Minnesota | 500 | 10 | 490 | 1 | 491 | |||||||||||||||
SPS | 500 | 123 | 377 | 1 | 378 | |||||||||||||||
NSP-Wisconsin | 150 | 62 | 88 | — | 88 | |||||||||||||||
Total | $ | 3,100 | $ | 1,003 | $ | 2,097 | $ | 3 | $ | 2,100 |
(a) | Includes
outstanding commercial paper, term loan borrowings and letters of credit. |
• | Xcel
Energy Inc. — approximately $700 million of senior unsecured bonds and approximately $75 to $80 million of equity through the DRIP and benefit programs; |
• | NSP-Minnesota — approximately $550 million of first mortgage bonds; |
• | NSP-Wisconsin — approximately $100 million of first mortgage bonds |
• | PSCo
— approximately $750 million of first mortgage bonds; and |
• | SPS — approximately $300 million of first mortgage bonds. |
• | Constructive
outcomes in all rate case and regulatory proceedings. |
• | Normal weather patterns. |
• | Weather-normalized retail electric sales are projected to increase ~1%, including impact of leap year. |
• | Weather-normalized retail firm natural gas sales are projected to increase ~1%, including impact of leap year. |
• | Capital
rider revenue is projected to increase $45 million to $55 million (net of PTCs). PTCs are credited to customers, through capital riders and reductions to electric margin. |
• | O&M expenses are projected to increase approximately 1% to 2%. |
• | Depreciation expense is projected to increase approximately $160 million to $170 million. |
• | Property
taxes are projected to increase approximately $35 million to $45 million. |
• | Interest expense (net of AFUDC — debt) is projected to increase $50 million to $60 million. |
• | AFUDC — equity is projected to increase approximately $10 million to $20 million. |
• | The
ETR is projected to be approximately 0%. The ETR reflects benefits of PTCs which are credited to customers through electric margin and will not impact net income. |
(a) | Ongoing earnings is calculated using net income and adjusting for certain nonrecurring or infrequent items that are, in management’s view, not reflective of ongoing operations. Ongoing earnings could differ from those prepared in accordance with GAAP for unplanned and/or unknown adjustments. Xcel Energy is unable to forecast if any of these items will occur or provide a quantitative reconciliation of the guidance for ongoing EPS to corresponding GAAP EPS. |
ITEM 7A — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
ITEM
8 — FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
/s/ BEN FOWKE | ||||
Chairman, President, Chief Executive Officer and Director | Executive Vice President, Chief Financial Officer | |||
• | 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 precedence of the Commissions’ treatment of similar costs under similar circumstances. We also evaluated regulatory filings for any evidence
that intervenors are challenging full recovery of the cost of any capital projects. If the full recovery of project costs is being challenged by intervenors, we evaluated management’s assessment of the probability of a disallowance. We evaluated the external information and compared to the Company’s recorded regulatory assets and liabilities for completeness. |
• | We obtained management’s analysis and correspondence from counsel, as appropriate, regarding regulatory assets or liabilities not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or a future reduction in rates. |
Minneapolis, Minnesota |
We have served as the Company’s auditor since 2002. |
XCEL
ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (amounts in millions, except per share data) | ||||||||||||
Year Ended Dec. 31 | ||||||||||||
2019 | 2018 | 2017 | ||||||||||
Operating
revenues | ||||||||||||
Electric | $ | i 9,575 | $ | i 9,719 | $ | i 9,676 | ||||||
Natural
gas | i 1,868 | i 1,739 | i 1,650 | |||||||||
Other | i 86 | i 79 | i 78 | |||||||||
Total
operating revenues | i 11,529 | i 11,537 | i 11,404 | |||||||||
Operating
expenses | ||||||||||||
Electric fuel and purchased power | i 3,510 | i 3,854 | i 3,757 | |||||||||
Cost
of natural gas sold and transported | i 918 | i 843 | i 823 | |||||||||
Cost
of sales — other | i 40 | i 35 | i 34 | |||||||||
Operating
and maintenance expenses | i 2,338 | i 2,352 | i 2,270 | |||||||||
Conservation
and demand side management program expenses | i 285 | i 290 | i 273 | |||||||||
Depreciation
and amortization | i 1,765 | i 1,642 | i 1,479 | |||||||||
Taxes
(other than income taxes) | i 569 | i 556 | i 545 | |||||||||
Total
operating expenses | i 9,425 | i 9,572 | i 9,181 | |||||||||
Operating
income | i 2,104 | i 1,965 | i 2,223 | |||||||||
Other
income (expense), net | i 16 | ( i 14 | ) | ( i 10 | ) | |||||||
Equity
earnings of unconsolidated subsidiaries | i 39 | i 35 | i 30 | |||||||||
Allowance
for funds used during construction — equity | i 77 | i 108 | i 75 | |||||||||
Interest
charges and financing costs | ||||||||||||
Interest charges — includes other financing costs of $26, $25 and $24, respectively | i 773 | i 700 | i 663 | |||||||||
Allowance
for funds used during construction — debt | ( i 37 | ) | ( i 48 | ) | ( i 35 | ) | ||||||
Total
interest charges and financing costs | i 736 | i 652 | i 628 | |||||||||
Income
before income taxes | i 1,500 | i 1,442 | i 1,690 | |||||||||
Income
taxes | i 128 | i 181 | i 542 | |||||||||
Net
income | $ | i 1,372 | $ | i 1,261 | $ | i 1,148 | ||||||
Weighted
average common shares outstanding: | ||||||||||||
Basic | i 519 | i 511 | i 509 | |||||||||
Diluted | i 520 | i 511 | i 509 | |||||||||
Earnings
per average common share: | ||||||||||||
Basic | $ | i 2.64 | $ | i 2.47 | $ | i 2.26 | ||||||
Diluted | i 2.64 | i 2.47 | i 2.25 | |||||||||
See
Notes to Consolidated Financial Statements |
XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (amounts in millions) | ||||||||||||
Year
Ended Dec. 31 | ||||||||||||
2019 | 2018 | 2017 | ||||||||||
Net
income | $ | i 1,372 | $ | i 1,261 | $ | i 1,148 | ||||||
Other
comprehensive (loss) income | ||||||||||||
Defined pension and other postretirement benefits: | ||||||||||||
Net
pension and retiree medical loss arising during the period, net of tax of $0, $(2) and $(2), respectively | i — | ( i 6 | ) | ( i 3 | ) | |||||||
Reclassification
of loss to net income, net of tax of $1, $3 and $5, respectively | i 3 | i 9 | i 7 | |||||||||
Derivative
instruments: | ||||||||||||
Net fair value decrease, net of tax of $(8), $(2) and $0, respectively | ( i 23 | ) | ( i 5 | ) | i — | |||||||
Reclassification
of loss to net income, net of tax of $1, $1 and $2, respectively | i 3 | i 3 | i 3 | |||||||||
Total
other comprehensive (loss) income | ( i 17 | ) | i 1 | i 7 | ||||||||
Total
comprehensive income | $ | i 1,355 | $ | i 1,262 | $ | i 1,155 | ||||||
See
Notes to Consolidated Financial Statements |
XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (amounts in millions) | |||||||||||
Year
Ended Dec. 31 | |||||||||||
2019 | 2018 | 2017 | |||||||||
Operating activities | |||||||||||
Net
income | $ | i 1,372 | $ | i 1,261 | $ | i 1,148 | |||||
Adjustments
to reconcile net income to cash provided by operating activities: | |||||||||||
Depreciation and amortization | i 1,785 | i 1,659 | i 1,495 | ||||||||
Nuclear
fuel amortization | i 119 | i 122 | i 114 | ||||||||
Deferred
income taxes | i 143 | i 218 | i 640 | ||||||||
Allowance
for equity funds used during construction | ( i 77 | ) | ( i 108 | ) | ( i 75 | ) | |||||
Equity
earnings of unconsolidated subsidiaries | ( i 39 | ) | ( i 35 | ) | ( i 30 | ) | |||||
Dividends
from unconsolidated subsidiaries | i 40 | i 37 | i 41 | ||||||||
Provision
for bad debts | i 42 | i 42 | i 39 | ||||||||
Share-based
compensation expense | i 58 | i 45 | i 57 | ||||||||
Net
realized and unrealized hedging and derivative transactions | i 45 | i 22 | i 2 | ||||||||
Changes
in operating assets and liabilities: | |||||||||||
Accounts receivable | ( i 20 | ) | ( i 105 | ) | ( i 60 | ) | |||||
Accrued
unbilled revenues | i 42 | i 9 | ( i 34 | ) | |||||||
Inventories | ( i 84 | ) | ( i 65 | ) | ( i 3 | ) | |||||
Other
current assets | i 25 | i 18 | i 9 | ||||||||
Accounts
payable | ( i 12 | ) | i 90 | i 43 | |||||||
Net
regulatory assets and liabilities | ( i 66 | ) | i 223 | ( i 16 | ) | ||||||
Other
current liabilities | ( i 15 | ) | ( i 61 | ) | ( i 38 | ) | |||||
Pension
and other employee benefit obligations | ( i 135 | ) | ( i 179 | ) | ( i 133 | ) | |||||
Other,
net | i 40 | ( i 71 | ) | ( i 73 | ) | ||||||
Net
cash provided by operating activities | i 3,263 | i 3,122 | i 3,126 | ||||||||
Investing
activities | |||||||||||
Utility capital/construction expenditures | ( i 4,225 | ) | ( i 3,957 | ) | ( i 3,244 | ) | |||||
Purchases
of investment securities | ( i 995 | ) | ( i 853 | ) | ( i 1,697 | ) | |||||
Proceeds
from the sale of investment securities | i 975 | i 833 | i 1,669 | ||||||||
Other,
net | ( i 98 | ) | ( i 9 | ) | ( i 24 | ) | |||||
Net
cash used in investing activities | ( i 4,343 | ) | ( i 3,986 | ) | ( i 3,296 | ) | |||||
Financing
activities | |||||||||||
(Repayments of) proceeds from short-term borrowings, net | ( i 443 | ) | i 225 | i 422 | |||||||
Proceeds
from issuance of long-term debt | i 2,920 | i 1,675 | i 1,518 | ||||||||
Repayments
of long-term debt, including reacquisition premiums | ( i 949 | ) | ( i 452 | ) | ( i 1,030 | ) | |||||
Proceeds
from issuance of common stock | i 458 | i 230 | i — | ||||||||
Dividends
paid | ( i 791 | ) | ( i 730 | ) | ( i 721 | ) | |||||
Other,
net | ( i 14 | ) | ( i 20 | ) | ( i 21 | ) | |||||
Net
cash provided by financing activities | i 1,181 | i 928 | i 168 | ||||||||
Net
change in cash, cash equivalents and restricted cash | i 101 | i 64 | ( i 2 | ) | |||||||
Cash,
cash equivalents and restricted cash at beginning of period | i 147 | i 83 | i 85 | ||||||||
Cash,
cash equivalents and restricted cash at end of period | $ | i 248 | $ | i 147 | $ | i 83 | |||||
Supplemental
disclosure of cash flow information: | |||||||||||
Cash paid for interest (net of amounts capitalized) | $ | ( i 698 | ) | $ | ( i 633 | ) | $ | ( i 616 | ) | ||
Cash
received for income taxes, net | i 53 | i 27 | i 44 | ||||||||
Supplemental
disclosure of non-cash investing and financing transactions: | |||||||||||
Accrued property, plant and equipment additions | $ | i 421 | $ | i 388 | $ | i 464 | |||||
Inventory
and other asset transfers to property, plant and equipment | i 88 | i 129 | i 63 | ||||||||
Operating
lease right-of-use assets | i 1,843 | i — | i — | ||||||||
Allowance
for equity funds used during construction | i 77 | i 108 | i 75 | ||||||||
Issuance
of common stock for reinvested dividends and equity awards | i 63 | i 67 | i 31 | ||||||||
See
Notes to Consolidated Financial Statements |
XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (amounts in millions, except share and per share) | ||||||||
Dec.
31 | ||||||||
2019 | 2018 | |||||||
Assets | ||||||||
Current assets | ||||||||
Cash
and cash equivalents | $ | i 248 | $ | i 147 | ||||
Accounts
receivable, net | i 837 | i 860 | ||||||
Accrued
unbilled revenues | i 713 | i 755 | ||||||
Inventories | i 544 | i 548 | ||||||
Regulatory
assets | i 488 | i 464 | ||||||
Derivative
instruments | i 55 | i 87 | ||||||
Prepaid
taxes | i 43 | i 79 | ||||||
Prepayments
and other | i 185 | i 154 | ||||||
Total
current assets | i 3,113 | i 3,094 | ||||||
Property,
plant and equipment, net | i 39,483 | i 36,944 | ||||||
Other
assets | ||||||||
Nuclear decommissioning fund and other investments | i 2,731 | i 2,317 | ||||||
Regulatory
assets | i 2,935 | i 3,326 | ||||||
Derivative
instruments | i 22 | i 34 | ||||||
Operating
lease right-of-use assets | i 1,672 | i — | ||||||
Other | i 492 | i 272 | ||||||
Total
other assets | i 7,852 | i 5,949 | ||||||
Total
assets | $ | i 50,448 | $ | i 45,987 | ||||
Liabilities
and Equity | ||||||||
Current liabilities | ||||||||
Current portion of long-term debt | $ | i 702 | $ | i 406 | ||||
Short-term
debt | i 595 | i 1,038 | ||||||
Accounts
payable | i 1,294 | i 1,237 | ||||||
Regulatory
liabilities | i 407 | i 436 | ||||||
Taxes
accrued | i 466 | i 450 | ||||||
Accrued
interest | i 192 | i 174 | ||||||
Dividends
payable | i 212 | i 195 | ||||||
Derivative
instruments | i 38 | i 61 | ||||||
Other | i 662 | i 463 | ||||||
Total
current liabilities | i 4,568 | i 4,460 | ||||||
Deferred
credits and other liabilities | ||||||||
Deferred income taxes | i 4,509 | i 4,165 | ||||||
Deferred
investment tax credits | i 49 | i 54 | ||||||
Regulatory
liabilities | i 5,077 | i 5,187 | ||||||
Asset
retirement obligations | i 2,701 | i 2,568 | ||||||
Derivative
instruments | i 175 | i 129 | ||||||
Customer
advances | i 203 | i 199 | ||||||
Pension
and employee benefit obligations | i 785 | i 994 | ||||||
Operating
lease liabilities | i 1,549 | i — | ||||||
Other | i 186 | i 206 | ||||||
Total
deferred credits and other liabilities | i 15,234 | i 13,502 | ||||||
Commitments
and contingencies | i | i | ||||||
Capitalization | ||||||||
Long-term
debt | i 17,407 | i 15,803 | ||||||
Common
stock — 1,000,000,000 shares authorized of $2.50 par value; 524,539,000 and 514,036,787 shares outstanding at Dec. 31, 2019 and 2018, respectively | i 1,311 | i 1,285 | ||||||
Additional
paid in capital | i 6,656 | i 6,168 | ||||||
Retained
earnings | i 5,413 | i 4,893 | ||||||
Accumulated
other comprehensive loss | ( i 141 | ) | ( i 124 | ) | ||||
Total
common stockholders’ equity | i 13,239 | i 12,222 | ||||||
Total
liabilities and equity | $ | i 50,448 | $ | i 45,987 | ||||
See
Notes to Consolidated Financial Statements |
XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY (amounts in millions, shares in thousands) | ||||||||||||||||||||||
Common Stock Issued | Accumulated
Other Comprehensive Loss | Total Common Stockholders’ Equity | ||||||||||||||||||||
Shares | Par Value | Additional Paid In Capital | Retained Earnings | |||||||||||||||||||
Balance
at Dec. 31, 2016 | i 507,223 | $ | i 1,268 | $ | i 5,881 | $ | i 3,982 | $ | ( i 110 | ) | $ | i 11,021 | ||||||||||
Net
income | i 1,148 | i 1,148 | ||||||||||||||||||||
Other
comprehensive loss | i 7 | i 7 | ||||||||||||||||||||
Dividends
declared on common stock ($1.44 per share) | ( i 736 | ) | ( i 736 | ) | ||||||||||||||||||
Issuances
of common stock | i 611 | i 1 | i 4 | i 5 | ||||||||||||||||||
Repurchases
of common stock | ( i 71 | ) | i — | ( i 3 | ) | ( i 3 | ) | |||||||||||||||
Share-based
compensation | i 16 | ( i 3 | ) | i 13 | ||||||||||||||||||
Adoption
of ASU No. 2018-02 | i 22 | ( i 22 | ) | i — | ||||||||||||||||||
Balance
at Dec. 31, 2017 | i 507,763 | $ | i 1,269 | $ | i 5,898 | $ | i 4,413 | $ | ( i 125 | ) | $ | i 11,455 | ||||||||||
Net
income | i 1,261 | i 1,261 | ||||||||||||||||||||
Other
comprehensive income | i 1 | i 1 | ||||||||||||||||||||
Dividends
declared on common stock ($1.52 per share) | ( i 780 | ) | ( i 780 | ) | ||||||||||||||||||
Issuances
of common stock | i 6,296 | i 16 | i 254 | i 270 | ||||||||||||||||||
Repurchases
of common stock | ( i 22 | ) | i — | ( i 1 | ) | ( i 1 | ) | |||||||||||||||
Share-based
compensation | i 17 | ( i 1 | ) | i 16 | ||||||||||||||||||
Balance
at Dec. 31, 2018 | i 514,037 | $ | i 1,285 | $ | i 6,168 | $ | i 4,893 | $ | ( i 124 | ) | $ | i 12,222 | ||||||||||
Net
income | i 1,372 | i 1,372 | ||||||||||||||||||||
Other
comprehensive income | ( i 17 | ) | ( i 17 | ) | ||||||||||||||||||
Dividends
declared on common stock ($1.62 per share) | ( i 846 | ) | ( i 846 | ) | ||||||||||||||||||
Issuances
of common stock | i 10,508 | i 26 | i 468 | i 494 | ||||||||||||||||||
Repurchases
of common stock | ( i 6 | ) | i — | i — | i — | |||||||||||||||||
Share-based
compensation | i 20 | ( i 6 | ) | i 14 | ||||||||||||||||||
Balance
at Dec. 31, 2019 | i 524,539 | $ | i 1,311 | $ | i 6,656 | $ | i 5,413 | $ | ( i 141 | ) | $ | i 13,239 | ||||||||||
See
Notes to Consolidated Financial Statements |
1. Summary of Significant Accounting Policies |
• | Certain costs, which would otherwise be charged to expense or other comprehensive income, are deferred as regulatory assets based on the expected ability to recover the costs in future rates; and |
• | 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. |
(Millions
of Dollars) | ||||||||
Inventories | ||||||||
Materials and supplies | $ | i 270 | $ | i 271 | ||||
Fuel | i 191 | i 170 | ||||||
Natural
gas | i 83 | i 107 | ||||||
Total
inventories | $ | i 544 | $ | i 548 |
2. Accounting Pronouncements |
3. Property, Plant and Equipment |
(Millions of Dollars) | ||||||||
Property, plant and equipment | ||||||||
Electric
plant | $ | i 44,355 | $ | i 41,472 | ||||
Natural
gas plant | i 6,560 | i 6,210 | ||||||
Common
and other property | i 2,341 | i 2,154 | ||||||
Plant
to be retired (a) | i 259 | i 322 | ||||||
CWIP | i 2,329 | i 2,091 | ||||||
Total
property, plant and equipment | i 55,844 | i 52,249 | ||||||
Less
accumulated depreciation | ( i 16,735 | ) | ( i 15,659 | ) | ||||
Nuclear
fuel | i 2,909 | i 2,771 | ||||||
Less
accumulated amortization | ( i 2,535 | ) | ( i 2,417 | ) | ||||
Property,
plant and equipment, net | $ | i 39,483 | $ | i 36,944 |
(a) | In
2018, the CPUC approved early retirement of PSCo’s Comanche Units 1 and 2 in approximately 2022 and 2025, respectively. PSCo also expects Craig Unit 1 to be retired early in 2025. Amounts are presented net of accumulated depreciation. |
(Millions of Dollars) | Plant
in Service | Accumulated Depreciation | CWIP | Percent Owned | |||||||||||
NSP-Minnesota | |||||||||||||||
Electric
generation: | |||||||||||||||
Sherco Unit 3 | $ | i 603 | $ | i 426 | $ | i 4 | i 59 | % | |||||||
Sherco
common facilities | i 145 | i 103 | i 2 | i 80 | |||||||||||
Sherco
substation | i 5 | i 3 | i — | i 59 | |||||||||||
Electric
transmission: | |||||||||||||||
CapX2020 | i 972 | i 92 | i 2 | i 51 | |||||||||||
Grand
Meadow | i 11 | i 3 | i — | i 50 | |||||||||||
Total
NSP-Minnesota | $ | i 1,736 | $ | i 627 | $ | i 8 |
(Millions of Dollars) | Plant
in Service | Accumulated Depreciation | CWIP | Percent Owned | |||||||||||
NSP-Wisconsin | |||||||||||||||
Electric
transmission: | |||||||||||||||
La Crosse, WI to Madison, WI | $ | i 187 | $ | i 7 | $ | i — | i 37 | % | |||||||
CapX2020 | i 169 | i 19 | i — | i 80 | |||||||||||
Total
NSP-Wisconsin | $ | i 356 | $ | i 26 | $ | i — |
(Millions of Dollars) | Plant
in Service | Accumulated Depreciation | CWIP | Percent Owned | |||||||||||
PSCo | |||||||||||||||
Electric
generation: | |||||||||||||||
Hayden Unit 1 | $ | i 152 | $ | i 81 | $ | i — | i 76 | % | |||||||
Hayden
Unit 2 | i 149 | i 71 | i — | i 37 | |||||||||||
Hayden
common facilities | i 41 | i 22 | i — | i 53 | |||||||||||
Craig
Units 1 and 2 | i 81 | i 41 | i — | i 10 | |||||||||||
Craig
common facilities | i 39 | i 22 | i — | i 7 | |||||||||||
Comanche
Unit 3 | i 887 | i 149 | i 1 | i 67 | |||||||||||
Comanche
common facilities | i 29 | i 3 | i — | i 82 | |||||||||||
Electric
transmission: | |||||||||||||||
Transmission and other facilities | i 174 | i 62 | i 1 | Various | |||||||||||
Gas
transmission: | |||||||||||||||
Rifle, CO to Avon, CO | i 22 | i 7 | i — | i 60 | |||||||||||
Gas
transmission compressor | i 9 | i 1 | i — | i 50 | |||||||||||
Total
PSCo | $ | i 1,583 | $ | i 459 | $ | i 2 |
4. Regulatory Assets and Liabilities |
(Millions of Dollars) | See
Note(s) | Remaining Amortization Period | |||||||||||||||||||
Regulatory Assets | Current | Noncurrent | Current | Noncurrent | |||||||||||||||||
Pension
and retiree medical obligations | 11 | Various | $ | i 85 | $ | i 1,328 | $ | i 87 | $ | i 1,500 | |||||||||||
Recoverable
deferred taxes on AFUDC recorded in plant | Plant lives | i — | i 271 | i — | i 264 | ||||||||||||||||
Net
AROs (a) | 1, 12 | Plant lives | i — | i 269 | i — | i 452 | |||||||||||||||
Excess
deferred taxes — TCJA | 7 | Various | i 39 | i 239 | i — | i 296 | |||||||||||||||
Depreciation
differences | One to twelve years | i 15 | i 140 | i 18 | i 107 | ||||||||||||||||
Environmental
remediation costs | 1, 12 | Various | i 36 | i 131 | i 17 | i 155 | |||||||||||||||
Benson
biomass PPA termination and asset purchase | Ten years | i 9 | i 73 | i 10 | i 86 | ||||||||||||||||
Contract
valuation adjustments (b) | 1, 10 | Term of related contract | i 20 | i 62 | i 17 | i 77 | |||||||||||||||
Purchased
power contract costs | Term of related contract | i 5 | i 61 | i 4 | i 63 | ||||||||||||||||
Laurentian
biomass PPA termination | Five years | i 19 | i 54 | i 18 | i 73 | ||||||||||||||||
PI
extended power uprate | Sixteen years | i 3 | i 53 | i 3 | i 56 | ||||||||||||||||
Losses
on reacquired debt | Term of related debt | i 4 | i 41 | i 4 | i 44 | ||||||||||||||||
State
commission adjustments | Plant lives | i 1 | i 31 | i 1 | i 29 | ||||||||||||||||
Property
tax | Various | i 2 | i 30 | i 14 | i 10 | ||||||||||||||||
Conservation
programs (c) | 1 | One to two years | i 27 | i 26 | i 42 | i 28 | |||||||||||||||
Nuclear
refueling outage costs | 1 | One to two years | i 43 | i 17 | i 37 | i 14 | |||||||||||||||
Sales
true-up and revenue decoupling | One to two years | i 54 | i 16 | i 38 | i 7 | ||||||||||||||||
Renewable
resources and environmental initiatives | One to two years | i 72 | i 10 | i 39 | i 9 | ||||||||||||||||
Gas
pipeline inspection and remediation costs | One to two years | i 26 | i 8 | i 28 | i 3 | ||||||||||||||||
Deferred
purchased natural gas and electric energy costs | One to three years | i 6 | i 6 | i 57 | i 13 | ||||||||||||||||
Other | Various | i 22 | i 69 | i 30 | i 40 | ||||||||||||||||
Total
regulatory assets | $ | i 488 | $ | i 2,935 | $ | i 464 | $ | i 3,326 |
(Millions of Dollars) | See Note(s) | Remaining Amortization Period | ||||||||||||||||||
Regulatory Liabilities | Current | Noncurrent | Current | Noncurrent | ||||||||||||||||
Deferred
income tax adjustments and TCJA refunds (a) | 7 | Various | $ | i 75 | $ | i 3,523 | $ | i 157 | $ | i 3,715 | ||||||||||
Plant
removal costs | 1, 12 | Plant lives | i — | i 1,217 | i — | i 1,175 | ||||||||||||||
Effects
of regulation on employee benefit costs (b) | Various | i — | i 196 | i — | i 137 | |||||||||||||||
Renewable
resources and environmental initiatives | Various | i — | i 45 | i 9 | i 54 | |||||||||||||||
ITC
deferrals (c) | 1 | Various | i — | i 38 | i — | i 40 | ||||||||||||||
Deferred
electric, natural gas and steam production costs | Less than one year | i 138 | i — | i 102 | i — | |||||||||||||||
Contract
valuation adjustments (d) | 1, 10 | Less than one year | i 19 | i — | i 26 | i — | ||||||||||||||
Conservation
programs (e) | 1 | Less than one year | i 37 | i — | i 36 | i — | ||||||||||||||
DOE
settlement | Less than one year | i 37 | i — | i 19 | i — | |||||||||||||||
Other | Various | i 101 | i 58 | i 87 | i 66 | |||||||||||||||
Total
regulatory liabilities (f) | $ | i 407 | $ | i 5,077 | $ | i 436 | $ | i 5,187 |
(a) | Includes
the revaluation of recoverable/regulated plant ADIT and revaluation impact of non-plant ADIT due to the TCJA. |
(b) | Includes regulatory amortization and certain 2018 TCJA benefits approved by the CPUC to offset the PSCo prepaid pension asset. |
(c) | Includes impact of lower federal tax rate due to the TCJA. |
(d) | Includes
the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases. |
(e) | Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. |
(f) | Revenue subject to refund of $ i 28
million and $ i 29 million for 2019 and 2018, respectively, is included in other current liabilities. |
5. Borrowings
and Other Financing Instruments |
(Millions
of Dollars, Except Interest Rates) | Three Months Ended Dec. 31, 2019 | Year Ended Dec. 31 | ||||||||||||||
2019 | 2018 | 2017 | ||||||||||||||
Borrowing
limit | $ | i 3,600 | $ | i 3,600 | $ | i 3,250 | $ | i 3,250 | ||||||||
Amount
outstanding at period end | i 595 | i 595 | i 1,038 | i 814 | ||||||||||||
Average
amount outstanding | i 663 | i 1,115 | i 788 | i 644 | ||||||||||||
Maximum
amount outstanding | i 945 | i 1,780 | i 1,349 | i 1,247 | ||||||||||||
Weighted
average interest rate, computed on a daily basis | i 2.40 | % | i 2.72 | % | i 2.34 | % | i 1.35 | % | ||||||||
Weighted
average interest rate at end of period | i 2.34 | i 2.34 | i 2.97 | i 1.90 |
(Millions of Dollars) | Limit | Amount Used | Available | |||||||||
Xcel
Energy Inc. | $ | i 500 | $ | i 500 | $ | i — |
(Millions of Dollars) | Limit | Amount
Used | Available | |||||||||
NSP-Minnesota | $ | i 75 | $ | i 22 | $ | i 53 |
• | Maturity extended from June 2021 to June 2024; |
• | Borrowing limit for Xcel Energy was increased from $ i 1.0
billion to $ i 1.25 billion; |
• | Borrowing limit for SPS was increased from $ i 400
million to $ i 500 million; and |
• | Added swingline subfacility for Xcel Energy up to $ i 75
million |
Debt-to-Total
Capitalization Ratio(a) | Amount Facility May Be Increased (millions) | Additional Periods for Which a One-Year Extension May Be Requested (b) | |||||||||||
2019 | 2018 | ||||||||||||
Xcel
Energy Inc. (c) | i 58 | % | i 58 | % | $ | i 200 | i 2 | ||||||
NSP-Wisconsin | i 48 | i 48 | N/A | i 1 | |||||||||
NSP-Minnesota | i 48 | i 48 | i 100 | i 2 | |||||||||
SPS | i 46 | i 46 | i 50 | i 2 | |||||||||
PSCo | i 44 | i 46 | i 100 | i 2 |
(a) | Each
credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to i 65%. |
(b) | All
extension requests are subject to majority bank group approval. |
(c) | The Xcel Energy Inc. credit facility has a cross-default provision that Xcel Energy Inc. will be in default on its borrowings under the facility if it or any of its subsidiaries (except NSP-Wisconsin as long as its total assets do not comprise more than i 15%
of Xcel Energy’s consolidated total assets) default on indebtedness in an aggregate principal amount exceeding $ i 75 million. |
(Millions of Dollars) | Credit Facility (a) | Drawn
(b) | Available | |||||||||
Xcel Energy Inc. | $ | i 1,250 | $ | i — | $ | i 1,250 | ||||||
PSCo | i 700 | i 9 | i 691 | |||||||||
NSP-Minnesota | i 500 | i 2 | i 498 | |||||||||
SPS | i 500 | i 40 | i 460 | |||||||||
NSP-Wisconsin | i 150 | i 65 | i 85 | |||||||||
Total | $ | i 3,100 | $ | i 116 | $ | i 2,984 |
(a) | These
credit facilities mature in June 2024. |
(b) | Includes outstanding commercial paper and letters of credit. |
Xcel Energy Inc. | |||||||||||||
Financing Instrument | Interest Rate | Maturity
Date | 2019 | 2018 | |||||||||
Unsecured senior notes (d) | i 4.70 | % | $ | i — | $ | i 550 | |||||||
Unsecured
senior notes | i 2.40 | i 400 | i 400 | ||||||||||
Unsecured
senior notes | i 2.60 | i 300 | i 300 | ||||||||||
Unsecured
senior notes | i 3.30 | i 250 | i 250 | ||||||||||
Unsecured
senior notes | i 3.30 | i 350 | i 350 | ||||||||||
Unsecured
senior notes | i 3.35 | i 500 | i 500 | ||||||||||
Unsecured
senior notes (a) | i 4.00 | i 130 | i — | ||||||||||
Unsecured
senior notes (b) | i 4.00 | i 500 | i 500 | ||||||||||
Unsecured
senior notes (a) | i 2.60 | i 500 | i — | ||||||||||
Unsecured
senior notes | i 6.50 | i 300 | i 300 | ||||||||||
Unsecured
senior notes | i 4.80 | Sept. 15, 2041 | i 250 | i 250 | |||||||||
Unsecured
senior notes (a) | i 3.50 | Dec.
1, 2049 | i 500 | i — | |||||||||
Elimination
of PSCo capital lease obligation with affiliates (c) | i — | ( i 60 | ) | ||||||||||
Unamortized
discount | ( i 5 | ) | ( i 5 | ) | |||||||||
Unamortized
debt issuance cost | ( i 28 | ) | ( i 21 | ) | |||||||||
Current
maturities (capital lease obligation) (c) | i — | i 2 | |||||||||||
Total
long-term debt | $ | i 3,947 | $ | i 3,316 |
(a) | 2019
financing. |
(b) | 2018 financing. |
(c) | Xcel Energy adopted ASC 842 on Jan. 1, 2019, which refers to capital leases as finance leases. Under ASC 842, the present value of future finance lease payments is included in other current liabilities and other noncurrent liabilities rather than debt. |
(d) | Note
was redeemed on Dec. 23, 2019. |
NSP-Minnesota | |||||||||||||
Financing Instrument | Interest Rate | Maturity Date | 2019 | 2018 | |||||||||
First
mortgage bonds | i 2.20 | % | $ | i 300 | $ | i 300 | |||||||
First
mortgage bonds | i 2.15 | i 300 | i 300 | ||||||||||
First
mortgage bonds | i 2.60 | i 400 | i 400 | ||||||||||
First
mortgage bonds | i 7.13 | i 250 | i 250 | ||||||||||
First
mortgage bonds | i 6.50 | i 150 | i 150 | ||||||||||
First
mortgage bonds | i 5.25 | i 250 | i 250 | ||||||||||
First
mortgage bonds | i 6.25 | i 400 | i 400 | ||||||||||
First
mortgage bonds | i 6.20 | i 350 | i 350 | ||||||||||
First
mortgage bonds | i 5.35 | Nov. 1, 2039 | i 300 | i 300 | |||||||||
First
mortgage bonds | i 4.85 | Aug. 15, 2040 | i 250 | i 250 | |||||||||
First
mortgage bonds | i 3.40 | Aug. 15, 2042 | i 500 | i 500 | |||||||||
First
mortgage bonds | i 4.13 | May 15, 2044 | i 300 | i 300 | |||||||||
First
mortgage bonds | i 4.00 | Aug. 15, 2045 | i 300 | i 300 | |||||||||
First
mortgage bonds | i 3.60 | May 15, 2046 | i 350 | i 350 | |||||||||
First
mortgage bonds | i 3.60 | Sept. 15, 2047 | i 600 | i 600 | |||||||||
First
mortgage bonds (a) | i 2.90 | March 1, 2050 | i 600 | i — | |||||||||
Unamortized
discount | ( i 31 | ) | ( i 21 | ) | |||||||||
Unamortized
debt issuance cost | ( i 48 | ) | ( i 42 | ) | |||||||||
Current
maturities | ( i 300 | ) | i — | ||||||||||
Total
long-term debt | $ | i 5,221 | $ | i 4,937 |
(a) | 2019
financing. |
NSP-Wisconsin | |||||||||||||
Financing Instrument | Interest Rate | Maturity
Date | 2019 | 2018 | |||||||||
City of La Crosse resource recovery bond | i 6.00 | % | Nov
1, 2021 | $ | i 19 | $ | i 19 | ||||||
First
mortgage bonds | i 3.30 | i 100 | i 100 | ||||||||||
First
mortgage bonds | i 3.30 | i 100 | i 100 | ||||||||||
First
mortgage bonds | i 6.38 | Sept. 1, 2038 | i 200 | i 200 | |||||||||
First
mortgage bonds | i 3.70 | Oct. 1, 2042 | i 100 | i 100 | |||||||||
First
mortgage bonds | i 3.75 | Dec. 1, 2047 | i 100 | i 100 | |||||||||
First
mortgage bonds (a) | i 4.20 | Sept.
1, 2048 | i 200 | i 200 | |||||||||
Unamortized
discount | ( i 3 | ) | ( i 3 | ) | |||||||||
Unamortized
debt issuance cost | ( i 8 | ) | ( i 9 | ) | |||||||||
Total
long-term debt | $ | i 808 | $ | i 807 |
(a) | 2018
financing. |
PSCo | |||||||||||||
Financing Instrument | Interest Rate | Maturity Date | 2019 | 2018 | |||||||||
First
mortgage bonds (d) | i 5.13 | % | $ | i — | $ | i 400 | |||||||
First
mortgage bonds | i 3.20 | i 400 | i 400 | ||||||||||
First
mortgage bonds | i 2.25 | i 300 | i 300 | ||||||||||
First
mortgage bonds | i 2.50 | i 250 | i 250 | ||||||||||
First
mortgage bonds | i 2.90 | i 250 | i 250 | ||||||||||
First
mortgage bonds (b) | i 3.70 | i 350 | i 350 | ||||||||||
First
mortgage bonds | i 6.25 | i 350 | i 350 | ||||||||||
First
mortgage bonds | i 6.50 | Aug. 1, 2038 | i 300 | i 300 | |||||||||
First
mortgage bonds | i 4.75 | Aug. 15, 2041 | i 250 | i 250 | |||||||||
First
mortgage bonds | i 3.60 | Sept. 15, 2042 | i 500 | i 500 | |||||||||
First
mortgage bonds | i 3.95 | March 15, 2043 | i 250 | i 250 | |||||||||
First
mortgage bonds | i 4.30 | March 15, 2044 | i 300 | i 300 | |||||||||
First
mortgage bonds | i 3.55 | June 15, 2046 | i 250 | i 250 | |||||||||
First
mortgage bonds | i 3.80 | June 15, 2047 | i 400 | i 400 | |||||||||
First
mortgage bonds (b) | i 4.10 | June 15, 2048 | i 350 | i 350 | |||||||||
First
mortgage bonds (a) | i 4.05 | Sept. 15, 2049 | i 400 | i — | |||||||||
First
mortgage bonds (a) | i 3.20 | March 1, 2050 | i 550 | i — | |||||||||
Capital
lease obligations (c) | 11.20 - 14.30 | 2025 - 2060 | i — | i 145 | |||||||||
Unamortized
discount | ( i 24 | ) | ( i 14 | ) | |||||||||
Unamortized
debt issuance cost | ( i 41 | ) | ( i 33 | ) | |||||||||
Current
maturities | ( i 400 | ) | ( i 406 | ) | |||||||||
Total
long-term debt | $ | i 4,985 | $ | i 4,592 |
(a) | 2019
financing. |
(b) | 2018 financing. |
(c) | PSCo adopted ASC 842 on Jan. 1, 2019, which refers to capital leases as finance leases. Under ASC 842, the present value of future finance lease payments is included in other current liabilities and other noncurrent liabilities rather than debt. |
(d) | Bond
was redeemed on March 29, 2019. |
SPS | |||||||||||||
Financing Instrument | Interest
Rate | Maturity Date | 2019 | 2018 | |||||||||
First mortgage bonds | i 3.30 | % | $ | i 150 | $ | i 150 | |||||||
First
mortgage bonds | i 3.30 | i 200 | i 200 | ||||||||||
Unsecured
senior notes | i 6.00 | i 100 | i 100 | ||||||||||
Unsecured
senior notes | i 6.00 | i 250 | i 250 | ||||||||||
First
mortgage bonds | i 4.50 | Aug. 15, 2041 | i 200 | i 200 | |||||||||
First
mortgage bonds | i 4.50 | Aug. 15, 2041 | i 100 | i 100 | |||||||||
First
mortgage bonds | i 4.50 | Aug. 15, 2041 | i 100 | i 100 | |||||||||
First
mortgage bonds | i 3.40 | Aug. 15, 2046 | i 300 | i 300 | |||||||||
First
mortgage bonds | i 3.70 | Aug. 15, 2047 | i 450 | i 450 | |||||||||
First
mortgage bonds (b) | i 4.40 | Nov. 15, 2048 | i 300 | i 300 | |||||||||
First
mortgage bonds (a) | i 3.75 | June 15, 2049 | i 300 | i — | |||||||||
Unamortized
discount | ( i 7 | ) | ( i 4 | ) | |||||||||
Unamortized
debt issuance cost | ( i 23 | ) | ( i 20 | ) | |||||||||
Total
long-term debt | $ | i 2,420 | $ | i 2,126 |
(a) | 2019
financing. |
(b) | 2018 financing. |
Other Subsidiaries | ||||||||||||
Financing Instrument | Interest
Rate | Maturity Date | 2019 | 2018 | ||||||||
Various Eloigne affordable housing project notes | 0.00% - 6.90% | 2020 — 2052 | $ | i 28 | $ | i 26 | ||||||
Current
maturities | ( i 2 | ) | ( i 1 | ) | ||||||||
Total
long-term debt | $ | i 26 | $ | i 25 |
(Millions of Dollars) | ||||
2020 | $ | i 702 | ||
2021 | i 421 | |||
2022 | i 900 | |||
2023 | i 650 | |||
2024 | i 552 |
Preferred
Stock Authorized (Shares) | Par Value of Preferred Stock | Preferred Stock Outstanding (Shares) 2019 and 2018 | ||||||||
Xcel Energy Inc. | i 7,000,000 | $ | i 100 | i — | ||||||
PSCo | i 10,000,000 | i 0.01 | i — | |||||||
SPS | i 10,000,000 | i 1.00 | i — |
Common Stock Authorized (Shares) | Par Value of Common Stock | Common Stock Outstanding (Shares) as of Dec. 31, 2019 | Common
Stock Outstanding (Shares) as of Dec. 31, 2018 | ||||||||
i 1,000,000,000 | $ | i 2.50 | i 524,539,000 | i 514,036,787 |
Equity to Total Capitalization Ratio Required Range | Equity to Total Capitalization Ratio Actual | ||||||||
Low | High | 2019 | |||||||
NSP-Minnesota | i 47.1 | % | i 57.5 | % | i 52.3 | % | |||
NSP-Wisconsin | i 51.5 | N/A | i 51.8 | ||||||
SPS
(a) | i 45.0 | i 55.0 | i 54.4 |
(a) | Excludes
short-term debt. |
(Amounts in Millions) | Unrestricted Retained Earnings | Total Capitalization | Limit on Total
Capitalization | |||||||||
NSP-Minnesota | $ | i 1,147 | $ | i 11,634 | $ | i 12,700 | ||||||
NSP-Wisconsin
(a) | i 12 | i 1,827 | N/A | |||||||||
SPS (b) | i 535 | i 5,304 | N/A |
(a) | Cannot
pay annual dividends in excess of approximately $ i 55 million if its average equity-to-total capitalization ratio falls below the commission authorized level. |
(b) | May
not pay a dividend that would cause a loss of its investment grade bond rating. |
(Millions of Dollars) | Long-Term Debt | Short-Term Debt | |||||||
NSP-Minnesota | 52.93%
of total capitalization | (a) | $ | i 1,905 | (a) | ||||
NSP-Wisconsin | $ | i — | (b) | i 150 | |||||
SPS | i — | (c) | i 600 | ||||||
PSCo | i 150 | i 800 |
(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 i 15% of total capitalization. |
(b) | NSP-Wisconsin
filed for additional long-term debt authorization in December 2019. |
(c) | SPS filed for additional long-term debt authorization in February 2020. |
6. Revenues |
Year
Ended Dec. 31, 2019 | ||||||||||||||||
(Millions of Dollars) | Electric | Natural Gas | All Other | Total | ||||||||||||
Major revenue types | ||||||||||||||||
Revenue
from contracts with customers: | ||||||||||||||||
Residential | $ | i 2,877 | $ | i 1,127 | $ | i 41 | $ | i 4,045 | ||||||||
C&I | i 4,844 | i 567 | i 29 | i 5,440 | ||||||||||||
Other | i 130 | i — | i 4 | i 134 | ||||||||||||
Total
retail | i 7,851 | i 1,694 | i 74 | i 9,619 | ||||||||||||
Wholesale | i 737 | i — | i — | i 737 | ||||||||||||
Transmission | i 507 | i — | i — | i 507 | ||||||||||||
Other | i 49 | i 120 | i — | i 169 | ||||||||||||
Total
revenue from contracts with customers | i 9,144 | i 1,814 | i 74 | i 11,032 | ||||||||||||
Alternative
revenue and other | i 431 | i 54 | i 12 | i 497 | ||||||||||||
Total
revenues | $ | i 9,575 | $ | i 1,868 | $ | i 86 | $ | i 11,529 |
Year
Ended Dec. 31, 2018 | ||||||||||||||||
(Millions of Dollars) | Electric | Natural Gas | All Other | Total | ||||||||||||
Major revenue types | ||||||||||||||||
Revenue
from contracts with customers: | ||||||||||||||||
Residential | $ | i 2,919 | $ | i 988 | $ | i 38 | $ | i 3,945 | ||||||||
C&I | i 4,874 | i 524 | i 25 | i 5,423 | ||||||||||||
Other | i 134 | i — | i 6 | i 140 | ||||||||||||
Total
retail | i 7,927 | i 1,512 | i 69 | i 9,508 | ||||||||||||
Wholesale | i 791 | i — | i — | i 791 | ||||||||||||
Transmission | i 523 | i — | i — | i 523 | ||||||||||||
Other | i 98 | i 100 | i — | i 198 | ||||||||||||
Total
revenue from contracts with customers | i 9,339 | i 1,612 | i 69 | i 11,020 | ||||||||||||
Alternative
revenue and other | i 380 | i 127 | i 10 | i 517 | ||||||||||||
Total
revenues | $ | i 9,719 | $ | i 1,739 | $ | i 79 | $ | i 11,537 |
7. Income
Taxes |
• | Corporate federal tax rate reduction from i 35%
to i 21%; |
• | Normalization of resulting plant-related excess deferred taxes; |
• | Elimination
of the corporate alternative minimum tax; |
• | Continued interest expense deductibility and discontinued bonus depreciation for regulated public utilities; |
• | Limitations on certain executive compensation deductions; |
• | Limitations on certain deductions for NOLs arising after Dec.
31, 2017 (limited to i 80% of taxable income); |
• | Repeal of the section 199 manufacturing deduction; and |
• | Reduced
deductions for meals and entertainment as well as state and local lobbying. |
• | $ i 2.7
billion ($ i 3.8 billion grossed-up for tax) of reclassifications of plant-related excess deferred taxes to regulatory liabilities upon valuation at the new i 21%
federal rate. The regulatory liabilities will be amortized consistent with IRS normalization requirements, resulting in customer refunds over an estimated weighted average period of approximately i 30 years; |
• | $ i 254
million and $ i 174 million of reclassifications (grossed-up for tax) of excess deferred taxes for non-plant related deferred tax assets and liabilities, respectively, to regulatory assets and liabilities; and |
• | $ i 23
million of total estimated income tax expense related to the tax rate change on certain non-plant deferred taxes and all other 2017 income statement impacts of the federal tax reform. |
Tax Year(s) | Expiration | |
2009 - 2013 | June 2020 | |
2014 - 2016 | September 2020 |
State | Year | |
Colorado | 2009 | |
Minnesota | 2009 | |
Texas | 2009 | |
Wisconsin | 2014 |
• | In
2018, Wisconsin began an audit of tax years 2014 - 2016. As of Dec. 31, 2019, no material adjustments have been proposed. |
• | Xcel Energy had no other state income tax audits in progress for its major operating jurisdictions as of Dec. 31, 2019. |
(Millions
of Dollars) | ||||||||
Unrecognized tax benefit — Permanent tax positions | $ | i 35 | $ | i 28 | ||||
Unrecognized
tax benefit — Temporary tax positions | i 9 | i 9 | ||||||
Total
unrecognized tax benefit | $ | i 44 | $ | i 37 |
(Millions of Dollars) | 2019 | 2018 | 2017 | |||||||||
Balance
at Jan. 1 | $ | i 37 | $ | i 39 | $ | i 134 | ||||||
Additions
based on tax positions related to the current year | i 10 | i 9 | i 6 | |||||||||
Reductions
based on tax positions related to the current year | ( i 4 | ) | ( i 4 | ) | ( i 4 | ) | ||||||
Additions
for tax positions of prior years | i 1 | i 2 | i 15 | |||||||||
Reductions
for tax positions of prior years | i — | ( i 4 | ) | ( i 105 | ) | |||||||
Settlements
with taxing authorities | i — | ( i 5 | ) | ( i 7 | ) | |||||||
Balance
at Dec. 31 | $ | i 44 | $ | i 37 | $ | i 39 |
(Millions of Dollars) | ||||||||
NOL and tax credit carryforwards | $ | ( i 40 | ) | $ | ( i 35 | ) |
(Millions of Dollars) | 2019 | 2018 | ||||||
Federal tax credit carryforwards | $ | i 639 | $ | i 553 | ||||
Valuation
allowances for federal credit carryforwards | i — | ( i 5 | ) | |||||
State
NOL carryforwards | i 937 | i 1,104 | ||||||
Valuation
allowances for state NOL carryforwards | ( i 19 | ) | ( i 50 | ) | ||||
State
tax credit carryforwards, net of federal detriment (a) | i 89 | i 89 | ||||||
Valuation
allowances for state credit carryforwards, net of federal benefit (b) | ( i 66 | ) | ( i 69 | ) |
(a) | State
tax credit carryforwards are net of federal detriment of $ i 24 million as of Dec. 31, 2019 and 2018. |
(b) | Valuation allowances for state tax credit carryforwards
were net of federal benefit of $ i 17 million and $ i 18 million
as of Dec. 31, 2019 and 2018, respectively. |
2019 | 2018 (a) | 2017 (a) | ||||||
Federal statutory rate | i 21.0 | % | i 21.0 | % | i 35.0 | % | ||
State
income tax on pretax income, net of federal tax effect | i 4.9 | i 5.0 | i 4.1 | |||||
Increases
(decreases) in tax from: | ||||||||
Wind PTCs | ( i 9.4 | ) | ( i 5.2 | ) | ( i 4.7 | ) | ||
Plant
regulatory differences (b) | ( i 5.8 | ) | ( i 6.2 | ) | ( i 0.8 | ) | ||
Other
tax credits, net of NOL & tax credit allowances | ( i 1.7 | ) | ( i 1.7 | ) | ( i 1.0 | ) | ||
Change
in unrecognized tax benefits | i 0.5 | i 0.4 | ( i 0.6 | ) | ||||
Tax
reform | i — | i — | i 1.4 | |||||
Other,
net | ( i 1.0 | ) | ( i 0.7 | ) | ( i 1.3 | ) | ||
Effective
income tax rate | i 8.5 | % | i 12.6 | % | i 32.1 | % |
(a) | Prior
periods have been reclassified to conform to current year presentation. |
(b) | Regulatory differences for income tax primarily relate to the credit of excess deferred taxes to customers through the average rate assumption method. Income tax benefits associated with the credit of excess deferred credits are offset by corresponding revenue reductions and additional prepaid pension asset amortization. |
(Millions of Dollars) | 2019 | 2018 | 2017 | |||||||||
Current
federal tax (benefit) expense | $ | ( i 16 | ) | $ | ( i 34 | ) | $ | i 1 | ||||
Current
state tax expense (benefit) | i 4 | i 8 | ( i 11 | ) | ||||||||
Current
change in unrecognized tax expense (benefit) | i 2 | ( i 6 | ) | ( i 83 | ) | |||||||
Deferred
federal tax expense | i 55 | i 122 | i 460 | |||||||||
Deferred
state tax expense | i 83 | i 85 | i 107 | |||||||||
Deferred
change in unrecognized tax expense | i 5 | i 11 | i 73 | |||||||||
Deferred
ITCs | ( i 5 | ) | ( i 5 | ) | ( i 5 | ) | ||||||
Total
income tax expense | $ | i 128 | $ | i 181 | $ | i 542 |
(Millions of Dollars) | 2019 | 2018 | 2017 | |||||||||
Deferred
tax expense (benefit) excluding items below | $ | i 344 | $ | i 320 | $ | ( i 2,939 | ) | |||||
Amortization
and adjustments to deferred income taxes on income tax regulatory assets and liabilities | ( i 206 | ) | ( i 102 | ) | i 3,583 | |||||||
Tax
benefit (expense) allocated to other comprehensive income, net of adoption of ASU No. 2018-02, and other | i 5 | i — | ( i 4 | ) | ||||||||
Deferred
tax expense | $ | i 143 | $ | i 218 | $ | i 640 |
(Millions of Dollars) | 2019 | 2018 (a) | ||||||
Deferred tax liabilities: | ||||||||
Differences
between book and tax bases of property | $ | i 5,474 | $ | i 5,082 | ||||
Operating
lease assets | i 449 | i — | ||||||
Regulatory
assets | i 598 | i 599 | ||||||
Pension
expense | i 173 | i 178 | ||||||
Other | i 70 | i 60 | ||||||
Total
deferred tax liabilities | $ | i 6,764 | $ | i 5,919 | ||||
Deferred
tax assets: | ||||||||
Regulatory liabilities | $ | i 847 | $ | i 879 | ||||
Operating
lease liabilities | i 449 | i — | ||||||
Tax
credit carryforward | i 727 | i 642 | ||||||
NOL
carryforward | i 38 | i 51 | ||||||
NOL
and tax credit valuation allowances | ( i 67 | ) | ( i 79 | ) | ||||
Other
employee benefits | i 128 | i 124 | ||||||
Deferred
ITCs | i 14 | i 16 | ||||||
Rate
refund | i 26 | i 60 | ||||||
Other | i 93 | i 61 | ||||||
Total
deferred tax assets | $ | i 2,255 | $ | i 1,754 | ||||
Net
deferred tax liability | $ | i 4,509 | $ | i 4,165 |
8. Share-Based Compensation |
• | Omnibus Incentive Plan - i 7.0
million shares; and |
• | Executive Annual Incentive Award Plan - i 1.2
million shares. |
(Shares in Thousands) | 2019 | 2018 | 2017 | |||||||||
Granted
shares | i 13 | i 18 | i 15 | |||||||||
Grant
date fair value | $ | i 53.46 | $ | i 44.68 | $ | i 42.00 |
(Shares in Thousands) | Shares | Weighted Average Grant Date Fair Value | |||||
Nonvested restricted stock at Jan. 1, 2019 | i 36 | $ | i 44.29 | ||||
Granted | i 13 | i 53.46 | |||||
Forfeited | i — | i — | |||||
Vested | ( i 19 | ) | i 41.60 | ||||
Dividend
equivalents | i 1 | i 57.09 | |||||
Nonvested
restricted stock at Dec. 31, 2019 | i 31 | i 50.15 |
(Units in Thousands) | 2019 | 2018 | 2017 | |||||||||
Granted
units | i 483 | i 500 | i 503 | |||||||||
Weighted
average grant date fair value | $ | i 49.67 | $ | i 47.60 | $ | i 41.02 |
(Units in Thousands) | 2019 | 2018 | 2017 | |||||||||
Vested
Units | i 464 | i 475 | i 467 | |||||||||
Total
Fair Value | $ | i 29,432 | $ | i 23,393 | $ | i 22,459 |
(Units in Thousands) | Units | Weighted Average Grant Date Fair Value | |||||
Nonvested Units at Jan. 1, 2019 | i 939 | $ | i 44.30 | ||||
Granted | i 483 | i 49.67 | |||||
Forfeited | ( i 116 | ) | i 50.19 | ||||
Vested | ( i 464 | ) | i 41.09 | ||||
Dividend
equivalents | i 38 | i 45.22 | |||||
Nonvested
Units at Dec. 31, 2019 | i 880 | i 48.20 |
(Units in Thousands) | 2019 | 2018 | 2017 | |||||||||
Granted
units | i 29 | i 36 | i 51 | |||||||||
Weighted
average grant date fair value | $ | i 58.44 | $ | i 45.44 | $ | i 46.05 |
(Units in Thousands) | Units | Weighted Average Grant Date Fair Value | |||||
Stock equivalent units at Jan. 1, 2019 | i 688 | $ | i 30.93 | ||||
Granted | i 29 | i 58.44 | |||||
Units
distributed | ( i 11 | ) | i 32.56 | ||||
Dividend
equivalents | i 19 | i 57.28 | |||||
Stock
equivalent units at Dec. 31, 2019 | i 725 | i 32.72 |
(In
Thousands) | 2019 | 2018 | 2017 | ||||||
Awards granted | i 225 | i 239 | i 240 |
(In Thousands) | 2019 | 2018 | 2017 | |||||||||
Awards
settled | i 466 | i 482 | i 454 | |||||||||
Settlement
amount (cash, common stock and deferred amounts) | $ | i 24,930 | $ | i 21,534 | $ | i 19,083 |
(Millions
of Dollars) | 2019 | 2018 | 2017 | |||||||||
Compensation cost for share-based awards (a) | $ | i 58 | $ | i 45 | $ | i 57 | ||||||
Tax
benefit recognized in income | i 15 | i 12 | i 22 |
(a) | Compensation
costs for share-based payment are included in O&M expense. |
9. Earnings
Per Share |
• | 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 period; and |
• | Liability awards subject to a performance condition; any portions settled in shares are included in common shares outstanding upon settlement. |
10. Fair Value of Financial Assets and Liabilities |
• | Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices; |
• | Level
2 — Pricing inputs are other than quoted prices in active markets but are either directly or indirectly observable as of the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts or priced with models using highly observable inputs; and |
• | Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those valued with models requiring significant management judgment or estimation. |
Fair Value | ||||||||||||||||||||||||
(Millions of Dollars) | Cost | Level 1 | Level 2 | Level
3 | NAV | Total | ||||||||||||||||||
Nuclear decommissioning fund (a) | ||||||||||||||||||||||||
Cash
equivalents | $ | i 33 | $ | i 33 | $ | i — | $ | i — | $ | i — | $ | i 33 | ||||||||||||
Commingled
funds | i 733 | i — | i — | i — | i 935 | i 935 | ||||||||||||||||||
Debt
securities | i 489 | i — | i 495 | i 13 | i — | i 508 | ||||||||||||||||||
Equity
securities | i 485 | i 962 | i 2 | i — | i — | i 964 | ||||||||||||||||||
Total
| $ | i 1,740 | $ | i 995 | $ | i 497 | $ | i 13 | $ | i 935 | $ | i 2,440 |
(a) | Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $ i 155 million of equity investments in unconsolidated subsidiaries and $ i 136
million of rabbi trust assets and miscellaneous investments. |
Fair Value | ||||||||||||||||||||||||
(Millions of Dollars) | Cost | Level 1 | Level 2 | Level
3 | NAV | Total | ||||||||||||||||||
Nuclear decommissioning fund (a) | ||||||||||||||||||||||||
Cash
equivalents | $ | i 24 | $ | i 24 | $ | i — | $ | i — | $ | i — | $ | i 24 | ||||||||||||
Commingled
funds | i 758 | i 79 | i — | i — | i 819 | i 898 | ||||||||||||||||||
Debt
securities | i 466 | i — | i 436 | i — | i — | i 436 | ||||||||||||||||||
Equity
securities | i 401 | i 697 | i — | i — | i — | i 697 | ||||||||||||||||||
Total
| $ | i 1,649 | $ | i 800 | $ | i 436 | $ | i — | $ | i 819 | $ | i 2,055 |
(a) | Reported
in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $ i 141 million of equity investments in unconsolidated subsidiaries and $ i 121
million of rabbi trust assets and miscellaneous investments. |
Final Contractual Maturity | ||||||||||||||||||||
(Millions
of Dollars) | Due in 1 Year or Less | Due in 1 to 5 Years | Due in 5 to 10 Years | Due after 10 Years | Total | |||||||||||||||
Debt
securities | $ | ( i 7 | ) | $ | i 111 | $ | i 246 | $ | i 158 | $ | i 508 |
Fair Value | ||||||||||||||||||||
(Millions of Dollars) | Cost | Level 1 | Level 2 | Level
3 | Total | |||||||||||||||
Rabbi Trusts (a) | ||||||||||||||||||||
Cash
equivalents | $ | i 17 | $ | i 17 | $ | i — | $ | i — | $ | i 17 | ||||||||||
Mutual
funds | i 57 | i 65 | i — | i — | i 65 | |||||||||||||||
Total | $ | i 74 | $ | i 82 | $ | i — | $ | i — | $ | i 82 |
(a) | Reported
in nuclear decommissioning fund and other investments on the consolidated balance sheet. |
Fair Value | ||||||||||||||||||||
(Millions of Dollars) | Cost | Level 1 | Level 2 | Level
3 | Total | |||||||||||||||
Rabbi Trusts (a) | ||||||||||||||||||||
Cash
equivalents | $ | i 16 | $ | i 16 | $ | i — | $ | i — | $ | i 16 | ||||||||||
Mutual
funds | i 52 | i 51 | i — | i — | i 51 | |||||||||||||||
Total | $ | i 68 | $ | i 67 | $ | i — | $ | i — | $ | i 67 |
(a) | Reported
in nuclear decommissioning fund and other investments on the consolidated balance sheet. |
(Millions
of Dollars) (a) (b) | 2019 | 2018 | ||||
MWh of electricity | i 95 | i 87 | ||||
MMBtu
of natural gas | i 110 | i 92 |
(a) | Amounts
are not reflective of net positions in the underlying commodities. |
(b) | Notional amounts for options are included on a gross basis but weighted for the probability of exercise. |
(Millions of Dollars) | 2019 | 2018 | 2017 | |||||||||
Accumulated
other comprehensive loss related to cash flow hedges at Jan. 1 | $ | ( i 60 | ) | $ | ( i 58 | ) | $ | ( i 51 | ) | |||
After-tax
net unrealized losses related to derivatives accounted for as hedges | ( i 23 | ) | ( i 5 | ) | i — | |||||||
After-tax
net realized losses on derivative transactions reclassified into earnings | i 3 | i 3 | i 3 | |||||||||
Adoption
of ASU. 2018-02 (a) | i — | i — | ( i 10 | ) | ||||||||
Accumulated
other comprehensive loss related to cash flow hedges at Dec. 31 | $ | ( i 80 | ) | $ | ( i 60 | ) | $ | ( i 58 | ) |
(a) | In
2017, Xcel Energy implemented ASU No 2018-02 related to TCJA, which resulted in reclassification of certain credit balances within net accumulated other comprehensive loss to retained earnings. |
Pre-Tax
Fair Value Gains (Losses) Recognized During the Period in: | ||||||||
(Millions of Dollars) | Accumulated Other Comprehensive Loss | Regulatory (Assets) and Liabilities | ||||||
Year Ended Dec. 31, 2019 | ||||||||
Derivatives
designated as cash flow hedges | ||||||||
Interest rate | $ | ( i 30 | ) | $ | i — | |||
Total | ( i 30 | ) | i — | |||||
Other
derivative instruments | ||||||||
Electric commodity | i — | i 8 | ||||||
Natural
gas commodity | i — | ( i 9 | ) | |||||
Total | i — | ( i 1 | ) | |||||
Year
Ended Dec. 31, 2018 | ||||||||
Interest rate | ( i 7 | ) | i — | |||||
Total | ( i 7 | ) | i — | |||||
Other
derivative instruments | ||||||||
Electric commodity | i — | i 1 | ||||||
Natural
gas commodity | i — | i 10 | ||||||
Total | i — | i 11 | ||||||
Year
Ended Dec. 31, 2017 | ||||||||
Other derivative instruments | ||||||||
Electric commodity | i — | i 10 | ||||||
Natural
gas commodity | i — | ( i 13 | ) | |||||
Total | $ | i — | $ | ( i 3 | ) |
Pre-Tax
(Gains) Losses Reclassified into Income During the Period from: | Pre-Tax Gains (Losses) Recognized During the Period in Income | |||||||||||
(Millions of Dollars) | Accumulated Other Comprehensive Loss | Regulatory Assets and (Liabilities) | ||||||||||
Year
Ended Dec. 31, 2019 | ||||||||||||
Derivatives designated as cash flow hedges | ||||||||||||
Interest
rate | $ | i 4 | (a) | $ | i — | $ | i — | |||||
Total | i 4 | i — | i — | |||||||||
Other
derivative instruments | ||||||||||||
Commodity trading | i — | i — | i 2 | (b) | ||||||||
Electric
commodity | i — | ( i 5 | ) | (c) | i — | |||||||
Natural
gas commodity | i — | i 2 | (d) | ( i 7 | ) | (d) | ||||||
Total | i — | ( i 3 | ) | ( i 5 | ) | |||||||
Year
Ended Dec. 31, 2018 | ||||||||||||
Derivatives designated as cash flow hedges | ||||||||||||
Interest
rate | i 4 | (a) | i — | i — | ||||||||
Total | i 4 | i — | i — | |||||||||
Other
derivative instruments | ||||||||||||
Commodity trading | i — | i — | i 14 | (b) | ||||||||
Electric
commodity | i — | ( i 1 | ) | (c) | i — | |||||||
Natural
gas commodity | i — | ( i 6 | ) | (d) | ( i 4 | ) | (d) | |||||
Total | i — | ( i 7 | ) | i 10 | ||||||||
Year
Ended Dec. 31, 2017 | ||||||||||||
Derivatives designated as cash flow hedges | ||||||||||||
Interest
rate | i 5 | (a) | i — | i — | ||||||||
Total | i 5 | i — | i — | |||||||||
Other
derivative instruments | ||||||||||||
Commodity trading | i — | i — | i 10 | (b) | ||||||||
Electric
commodity | i — | ( i 15 | ) | (c) | i — | |||||||
Natural
gas commodity | i — | i 3 | (d) | ( i 6 | ) | (d) | ||||||
Total | $ | i — | $ | ( i 12 | ) | $ | i 4 |
(a) | Amounts
recorded to interest charges. |
(b) | Amounts recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate. |
(c) | Amounts recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms and reclassified out of income
as regulatory assets or liabilities, as appropriate. |
(d) | Amounts for the year ended Dec. 31, 2019 included i no
settlement losses on derivatives entered to mitigate natural gas price risk for electric generation recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. Such losses and gains for the years ended Dec. 31, 2018 and 2017 were $ i 1
million and immaterial, respectively. Remaining settlement losses for the years ended Dec. 31, 2019, 2018 and 2017 related to natural gas operations and were recorded to cost of natural gas sold and transported. These losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset, as appropriate. |
Fair Value | Fair Value Total | Netting (a) | Fair
Value | Fair Value Total | Netting (a) | |||||||||||||||||||||||||||||||||||||||||||
(Millions of Dollars) | Level 1 | Level 2 | Level
3 | Total | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||||||||||||||
Current
derivative assets | ||||||||||||||||||||||||||||||||||||||||||||||||
Commodity
trading | $ | i 3 | $ | i 51 | $ | i 24 | $ | i 78 | $ | ( i 52 | ) | $ | i 26 | $ | i 4 | $ | i 92 | $ | i 2 | $ | i 98 | $ | ( i 44 | ) | $ | i 54 | ||||||||||||||||||||||
Electric
commodity | i — | i — | i 21 | i 21 | ( i 1 | ) | i 20 | i — | i — | i 25 | i 25 | i — | i 25 | |||||||||||||||||||||||||||||||||||
Natural
gas commodity | i — | i 6 | i — | i 6 | i — | i 6 | i — | i 4 | i — | i 4 | i — | i 4 | ||||||||||||||||||||||||||||||||||||
Total
current derivative assets | $ | i 3 | $ | i 57 | $ | i 45 | $ | i 105 | $ | ( i 53 | ) | i 52 | $ | i 4 | $ | i 96 | $ | i 27 | $ | i 127 | $ | ( i 44 | ) | i 83 | ||||||||||||||||||||||||
PPAs
(b) | i 3 | i 4 | ||||||||||||||||||||||||||||||||||||||||||||||
Current
derivative instruments | $ | i 55 | $ | i 87 | ||||||||||||||||||||||||||||||||||||||||||||
Noncurrent
derivative assets | ||||||||||||||||||||||||||||||||||||||||||||||||
Other
derivative instruments: | ||||||||||||||||||||||||||||||||||||||||||||||||
Commodity
trading | $ | i 9 | $ | i 38 | $ | i 7 | $ | i 54 | $ | ( i 45 | ) | $ | i 9 | $ | i — | $ | i 27 | $ | i 5 | $ | i 32 | $ | ( i 14 | ) | $ | i 18 | ||||||||||||||||||||||
Total
noncurrent derivative assets | $ | i 9 | $ | i 38 | $ | i 7 | $ | i 54 | $ | ( i 45 | ) | i 9 | $ | i — | $ | i 27 | $ | i 5 | $ | i 32 | $ | ( i 14 | ) | i 18 | ||||||||||||||||||||||||
PPAs
(b) | i 13 | i 16 | ||||||||||||||||||||||||||||||||||||||||||||||
Noncurrent
derivative instruments | $ | i 22 | $ | i 34 |
Fair Value | Fair Value Total | Netting (a) | Fair
Value | Fair Value Total | Netting (a) | |||||||||||||||||||||||||||||||||||||||||||
(Millions of Dollars) | Level 1 | Level 2 | Level
3 | Total | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||||||||||||||
Current
derivative liabilities | ||||||||||||||||||||||||||||||||||||||||||||||||
Derivatives
designated as cash flow hedges: | ||||||||||||||||||||||||||||||||||||||||||||||||
Interest
rate | $ | i — | $ | i — | $ | i — | $ | i — | $ | i — | $ | i — | $ | i — | $ | i 7 | $ | i — | $ | i 7 | $ | i — | $ | i 7 | ||||||||||||||||||||||||
Other
derivative instruments: | ||||||||||||||||||||||||||||||||||||||||||||||||
Commodity
trading | i 4 | i 59 | i 15 | i 78 | ( i 63 | ) | i 15 | i 4 | i 88 | i 2 | i 94 | ( i 60 | ) | i 34 | ||||||||||||||||||||||||||||||||||
Electric
commodity | i — | i — | i 1 | i 1 | ( i 1 | ) | i — | i — | i — | i — | i — | i — | i — | |||||||||||||||||||||||||||||||||||
Natural
gas commodity | i — | i 5 | i — | i 5 | i — | i 5 | i — | i — | i — | i — | i — | i — | ||||||||||||||||||||||||||||||||||||
Total
current derivative liabilities | $ | i 4 | $ | i 64 | $ | i 16 | $ | i 84 | $ | ( i 64 | ) | i 20 | $ | i 4 | $ | i 95 | $ | i 2 | $ | i 101 | $ | ( i 60 | ) | i 41 | ||||||||||||||||||||||||
PPAs
(b) | i 18 | i 20 | ||||||||||||||||||||||||||||||||||||||||||||||
Current
derivative instruments | $ | i 38 | $ | i 61 | ||||||||||||||||||||||||||||||||||||||||||||
Noncurrent
derivative liabilities | ||||||||||||||||||||||||||||||||||||||||||||||||
Other
derivative instruments: | ||||||||||||||||||||||||||||||||||||||||||||||||
Commodity
trading | $ | i 2 | $ | i 79 | $ | i 32 | $ | i 113 | $ | ( i 13 | ) | $ | i 100 | $ | i — | $ | i 18 | $ | i 1 | $ | i 19 | $ | i 17 | $ | i 36 | |||||||||||||||||||||||
Total
noncurrent derivative liabilities | $ | i 2 | $ | i 79 | $ | i 32 | $ | i 113 | $ | ( i 13 | ) | i 100 | $ | i — | $ | i 18 | $ | i 1 | $ | i 19 | $ | i 17 | i 36 | |||||||||||||||||||||||||
PPAs
(b) | i 75 | i 93 | ||||||||||||||||||||||||||||||||||||||||||||||
Noncurrent
derivative instruments | $ | i 175 | $ | i 129 |
(a) | Xcel
Energy nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement and all derivative instruments and related collateral amounts were subject to master netting agreements as of Dec. 31, 2019 and 2018. At both Dec. 31, 2019 and 2018, derivative assets and liabilities included $ i 32
million of obligations to return cash collateral. At Dec. 31, 2019 and 2018, derivative assets and liabilities included rights to reclaim cash collateral of $ i 11 million and $ i 15
million, respectively. Counterparty netting excludes settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. |
(b) | During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining
contract lives along with the offsetting regulatory assets and liabilities. |
Year
Ended Dec. 31 | ||||||||||||
(Millions of Dollars) | 2019 | 2018 | 2017 | |||||||||
Balance at Jan. 1 | $ | i 29 | $ | i 35 | $ | i 17 | ||||||
Purchases | i 44 | i 59 | i 82 | |||||||||
Settlements | ( i 64 | ) | ( i 59 | ) | ( i 97 | ) | ||||||
Net
transactions recorded during the period: | ||||||||||||
(Losses) gains recognized in earnings (a) | ( i 8 | ) | ( i 1 | ) | i 5 | |||||||
Net
gains (losses) recognized as regulatory assets and liabilities | i 3 | ( i 5 | ) | i 28 | ||||||||
Balance
at Dec. 31 | $ | i 4 | $ | i 29 | $ | i 35 |
(a) | Amounts
relate to commodity derivatives held at the end of the period. |
2019 | 2018 | |||||||||||||||
(Millions
of Dollars) | Carrying Amount | Fair Value | Carrying Amount | Fair Value | ||||||||||||
Long-term debt, including current portion | $ | i 18,109 | $ | i 20,227 | $ | i 16,209 | $ | i 16,755 |
11. Benefit Plans and Other Postretirement Benefits |
• | Investment returns in 2019 were above the assumed level of i 6.87%;
|
• | Investment returns in 2018 were below the assumed level of i 6.87%; |
• | Investment
returns in 2017 were above the assumed level of i 6.87%; and |
• | In 2020, expected investment-return
assumption is i 6.87%. |
Dec.
31, 2019 (a) | Dec. 31, 2018 (a) | |||||||||||||||||||||||||||||||||||||||
(Millions of Dollars) | Level 1 | Level 2 | Level 3 | Measured
at NAV | Total | Level 1 | Level 2 | Level 3 | Measured at NAV | Total | ||||||||||||||||||||||||||||||
Cash
equivalents | $ | i 145 | $ | i — | $ | i — | $ | i — | $ | i 145 | $ | i 137 | $ | i — | $ | i — | $ | i — | $ | i 137 | ||||||||||||||||||||
Commingled
funds | i 1,408 | i — | i — | i 1,031 | i 2,439 | i 914 | i — | i — | i 987 | i 1,901 | ||||||||||||||||||||||||||||||
Debt
securities | i — | i 645 | i 4 | i — | i 649 | i — | i 621 | i — | i — | i 621 | ||||||||||||||||||||||||||||||
Equity
securities | i 86 | i — | i — | i — | i 86 | i 106 | i — | i — | i — | i 106 | ||||||||||||||||||||||||||||||
Other | ( i 120 | ) | i 5 | i — | ( i 20 | ) | ( i 135 | ) | i 2 | i 5 | i — | ( i 30 | ) | ( i 23 | ) | |||||||||||||||||||||||||
Total | $ | i 1,519 | $ | i 650 | $ | i 4 | $ | i 1,011 | $ | i 3,184 | $ | i 1,159 | $ | i 626 | $ | i — | $ | i 957 | $ | i 2,742 |
(a) | See
Note 10 for further information regarding fair value measurement inputs and methods. |
Dec.
31, 2019 (a) | Dec. 31, 2018 (a) | |||||||||||||||||||||||||||||||||||||||
(Millions of Dollars) | Level 1 | Level 2 | Level 3 | Measured
at NAV | Total | Level 1 | Level 2 | Level 3 | Measured at NAV | Total | ||||||||||||||||||||||||||||||
Cash
equivalents | $ | i 23 | $ | i — | $ | i — | $ | i — | $ | i 23 | $ | i 19 | $ | i — | $ | i — | $ | i — | $ | i 19 | ||||||||||||||||||||
Insurance
contracts | i — | i 51 | i — | i — | i 51 | i — | i 45 | i — | i — | i 45 | ||||||||||||||||||||||||||||||
Commingled
funds | i 69 | i — | i — | i 76 | i 145 | i 133 | i — | i — | i 40 | i 173 | ||||||||||||||||||||||||||||||
Debt
securities | i — | i 228 | i 1 | i — | i 229 | i — | i 179 | i — | i — | i 179 | ||||||||||||||||||||||||||||||
Other | i — | i 1 | i — | i — | i 1 | i — | i 1 | i — | i — | i 1 | ||||||||||||||||||||||||||||||
Total | $ | i 92 | $ | i 280 | $ | i 1 | $ | i 76 | $ | i 449 | $ | i 152 | $ | i 225 | $ | i — | $ | i 40 | $ | i 417 |
(a) | See
Note 10 for further information on fair value measurement inputs and methods. |
Pension Benefits | Postretirement Benefits | |||||||||||||||
(Millions of Dollars) | 2019 | 2018 | 2019 | 2018 | ||||||||||||
Change
in Benefit Obligation: | ||||||||||||||||
Obligation at Jan. 1 | $ | i 3,477 | $ | i 3,828 | $ | i 542 | $ | i 621 | ||||||||
Service
cost | i 86 | i 94 | i 2 | i 2 | ||||||||||||
Interest
cost | i 145 | i 133 | i 22 | i 22 | ||||||||||||
Plan
amendments | i 1 | i — | i — | i — | ||||||||||||
Actuarial
loss (gain) | i 273 | ( i 224 | ) | i 19 | ( i 62 | ) | ||||||||||
Plan
participants’ contributions | i — | i — | i 8 | i 8 | ||||||||||||
Medicare
subsidy reimbursements | i — | i — | i 1 | i 1 | ||||||||||||
Benefit
payments (a) | ( i 281 | ) | ( i 354 | ) | ( i 47 | ) | ( i 50 | ) | ||||||||
Obligation
at Dec. 31 | $ | i 3,701 | $ | i 3,477 | $ | i 547 | $ | i 542 | ||||||||
Change
in Fair Value of Plan Assets: | ||||||||||||||||
Fair value of plan assets at Jan. 1 | $ | i 2,742 | $ | i 3,088 | $ | i 417 | $ | i 461 | ||||||||
Actual
return on plan assets | i 568 | ( i 142 | ) | i 56 | ( i 13 | ) | ||||||||||
Employer
contributions | i 155 | i 150 | i 15 | i 11 | ||||||||||||
Plan
participants’ contributions | i — | i — | i 8 | i 8 | ||||||||||||
Benefit
payments | ( i 281 | ) | ( i 354 | ) | ( i 47 | ) | ( i 50 | ) | ||||||||
Fair
value of plan assets at Dec. 31 | $ | i 3,184 | $ | i 2,742 | $ | i 449 | $ | i 417 | ||||||||
Funded
status of plans at Dec. 31 | $ | ( i 517 | ) | $ | ( i 735 | ) | $ | ( i 98 | ) | $ | ( i 125 | ) | ||||
Amounts
recognized in the Consolidated Balance Sheet at Dec. 31: | ||||||||||||||||
Noncurrent assets | $ | — | $ | — | $ | i 21 | $ | — | ||||||||
Current
liabilities | i — | i — | ( i 6 | ) | ( i 7 | ) | ||||||||||
Noncurrent
liabilities | ( i 517 | ) | ( i 735 | ) | ( i 113 | ) | ( i 118 | ) | ||||||||
Net
amounts recognized | $ | ( i 517 | ) | $ | ( i 735 | ) | $ | ( i 98 | ) | $ | ( i 125 | ) |
(a) | Includes
approximately $ i 20 million in 2019 and $ i 198 million in
2018 of lump-sum benefit payments used in the determination of a settlement charge. |
Pension Benefits | Postretirement Benefits | |||||||||||
(Millions of Dollars) | 2019 | 2018 | 2019 | 2018 | ||||||||
Significant
Assumptions Used to Measure Benefit Obligations: | ||||||||||||
Discount rate for year-end valuation | i 3.49 | % | i 4.31 | % | i 3.47 | % | i 4.32 | % | ||||
Expected
average long-term increase in compensation level | i 3.75 | i 3.75 | N/A | N/A | ||||||||
Mortality
table | PRI-2012 | RP-2014 | PRI-2012 | RP-2014 | ||||||||
Health care costs trend rate — initial:
Pre-65 | N/A | N/A | i 6.00 | % | i 6.50 | % | ||||||
Health
care costs trend rate — initial: Post-65 | N/A | N/A | i 5.10 | % | i 5.30 | % | ||||||
Ultimate
trend assumption — initial: Pre-65 | N/A | N/A | i 4.50 | % | i 4.50 | % | ||||||
Ultimate
trend assumption — initial: Post-65 | N/A | N/A | i 4.50 | % | i 4.50 | % | ||||||
Years
until ultimate trend is reached | N/A | N/A | i 3 | i 4 |
Pension
Benefits | Postretirement Benefits | |||||||||||||||||||||||
(Millions of Dollars) | 2019 | 2018 | 2017 | 2019 | 2018 | 2017 | ||||||||||||||||||
Service
cost | $ | i 86 | $ | i 94 | $ | i 94 | $ | i 2 | $ | i 2 | $ | i 2 | ||||||||||||
Interest
cost | i 145 | i 133 | i 147 | i 22 | i 22 | i 24 | ||||||||||||||||||
Expected
return on plan assets | ( i 203 | ) | ( i 209 | ) | ( i 209 | ) | ( i 21 | ) | ( i 26 | ) | ( i 25 | ) | ||||||||||||
Amortization
of prior service credit | ( i 5 | ) | ( i 5 | ) | ( i 2 | ) | ( i 10 | ) | ( i 11 | ) | ( i 11 | ) | ||||||||||||
Amortization
of net loss | i 87 | i 111 | i 107 | i 5 | i 8 | i 7 | ||||||||||||||||||
Settlement
charge (a) | i 6 | i 91 | i 81 | i — | i — | i — | ||||||||||||||||||
Net
periodic pension cost (credit) | i 116 | i 215 | i 218 | ( i 2 | ) | ( i 5 | ) | ( i 3 | ) | |||||||||||||||
Costs
not recognized due to effects of regulation | ( i 1 | ) | ( i 75 | ) | ( i 79 | ) | i 1 | i 2 | i — | |||||||||||||||
Net
benefit cost (credit) recognized for financial reporting | $ | i 115 | $ | i 140 | $ | i 139 | $ | ( i 1 | ) | $ | ( i 3 | ) | $ | ( i 3 | ) | |||||||||
Significant
Assumptions Used to Measure Costs: | ||||||||||||||||||||||||
Discount rate | i 4.31 | % | i 3.63 | % | i 4.13 | % | i 4.32 | % | i 3.62 | % | i 4.13 | % | ||||||||||||
Expected
average long-term increase in compensation level | i 3.75 | i 3.75 | i 3.75 | i — | i — | i — | ||||||||||||||||||
Expected
average long-term rate of return on assets | i 6.87 | i 6.87 | i 6.87 | i 4.50 | i 5.30 | i 5.80 |
(a) | A
settlement charge is required when the amount of all lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In 2019 and 2018, as a result of lump-sum distributions during the 2019 and 2018 plan years, Xcel Energy recorded a total pension settlement charge of $ i 6 million in 2019 and $ i 91
million in 2018, the majority of which was not recognized due to the effects of regulation. A total of $ i 1 million and $ i 11
million was recorded in the consolidated statements of income in 2019 and 2018, respectively. |
Pension
Benefits | Postretirement Benefits | |||||||||||||||
(Millions of Dollars) | 2019 | 2018 | 2019 | 2018 | ||||||||||||
Amounts Not Yet Recognized as Components of Net Periodic Benefit
Cost: | ||||||||||||||||
Net loss | $ | i 1,447 | $ | i 1,633 | $ | i 95 | $ | i 116 | ||||||||
Prior
service credit | ( i 15 | ) | ( i 20 | ) | ( i 23 | ) | ( i 33 | ) | ||||||||
Total | $ | i 1,432 | $ | i 1,613 | $ | i 72 | $ | i 83 | ||||||||
Amounts
Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates: | ||||||||||||||||
Current regulatory assets | $ | i 78 | $ | i 94 | $ | i — | $ | i — | ||||||||
Noncurrent
regulatory assets | i 1,285 | i 1,446 | i 80 | i 89 | ||||||||||||
Current
regulatory liabilities | i — | i — | ( i 1 | ) | ( i 1 | ) | ||||||||||
Noncurrent
regulatory liabilities | i — | i — | ( i 12 | ) | ( i 10 | ) | ||||||||||
Deferred
income taxes | i 18 | i 19 | i 1 | i 1 | ||||||||||||
Net-of-tax
accumulated other comprehensive income | i 51 | i 54 | i 4 | i 4 | ||||||||||||
Total | $ | i 1,432 | $ | i 1,613 | $ | i 72 | $ | i 83 |
Measurement
date |
• | $ i 150
million in January 2020; |
• | $ i 154 million in 2019; |
• | $ i 150
million in 2018; and |
• | $ i 162 million in 2017. |
• | $ i 10
million during 2020; |
• | $ i 15 million during 2019; |
• | $ i 11
million during 2018; and |
• | $ i 20 million during 2017 i . |
Pension Benefits | Postretirement Benefits | |||||||||||
2019 | 2018 | 2019 | 2018 | |||||||||
Domestic
and international equity securities | i 37 | % | i 36 | % | i 15 | % | i 18 | % | ||||
Long-duration
fixed income securities | i 30 | i 30 | i — | i — | ||||||||
Short-to-intermediate
fixed income securities | i 14 | i 17 | i 72 | i 70 | ||||||||
Alternative
investments | i 17 | i 15 | i 9 | i 8 | ||||||||
Cash | i 2 | i 2 | i 4 | i 4 | ||||||||
Total | i 100 | % | i 100 | % | i 100 | % | i 100 | % |
(Millions of Dollars) | Projected
Pension Benefit Payments | Gross Projected Postretirement Health Care Benefit Payments | Expected Medicare Part D Subsidies | Net Projected Postretirement Health Care Benefit Payments | ||||||||||||
2020 | $ | i 278 | $ | i 44 | $ | i 2 | $ | i 42 | ||||||||
2021 | i 263 | i 43 | i 2 | i 41 | ||||||||||||
2022 | i 262 | i 42 | i 2 | i 40 | ||||||||||||
2023 | i 260 | i 41 | i 2 | i 39 | ||||||||||||
2024 | i 255 | i 40 | i 2 | i 38 | ||||||||||||
2025-2029 | i 1,205 | i 181 | i 13 | i 168 |
12. Commitments and Contingencies |
(Millions of Dollars) | Amounts Incurred (a) | Amounts Settled (b) | Accretion | Cash Flow Revisions (c) | ||||||||||||||||||||
Electric | ||||||||||||||||||||||||
Nuclear | $ | i 1,968 | $ | i — | $ | i — | $ | i 100 | $ | i — | $ | i 2,068 | ||||||||||||
Steam,
hydro and other production | i 177 | i — | ( i 5 | ) | i 8 | i 22 | i 202 | |||||||||||||||||
Wind | i 119 | i 26 | i — | i 7 | ( i 6 | ) | i 146 | |||||||||||||||||
Distribution | i 42 | i — | i — | i 2 | i — | i 44 | ||||||||||||||||||
Miscellaneous | i 7 | i — | i — | i — | ( i 7 | ) | i — | |||||||||||||||||
Natural
gas | ||||||||||||||||||||||||
Transmission and distribution | i 249 | i — | i — | i 11 | ( i 24 | ) | i 236 | |||||||||||||||||
Miscellaneous | i 4 | i — | i — | i — | ( i 1 | ) | i 3 | |||||||||||||||||
Common | ||||||||||||||||||||||||
Miscellaneous | i 1 | i — | i — | i — | i — | i 1 | ||||||||||||||||||
Non-utility | ||||||||||||||||||||||||
Miscellaneous | i 1 | i — | i — | i — | i — | i 1 | ||||||||||||||||||
Total
liability | $ | i 2,568 | $ | i 26 | $ | ( i 5 | ) | $ | i 128 | $ | ( i 16 | ) | $ | i 2,701 |
(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. Changes in gas transmission and distribution AROs were primarily related to increased gas line mileage and number of services, which were more than offset by decreased
inflation rates. Changes in steam, hydro and other production AROs primarily related to the cost estimates to remediate ponds at production facilities. Changes in wind AROs were driven by new dismantling studies. |
(Millions of Dollars) | Amounts Incurred (a) | Amounts Settled (b) | Accretion | Cash Flow Revisions (c) | ||||||||||||||||||||
Electric | ||||||||||||||||||||||||
Nuclear | $ | i 1,874 | $ | i — | $ | i — | $ | i 94 | $ | i — | $ | i 1,968 | ||||||||||||
Steam,
hydro and other production | i 192 | i — | ( i 14 | ) | i 8 | ( i 9 | ) | i 177 | ||||||||||||||||
Wind | i 96 | i 12 | i — | i 4 | i 7 | i 119 | ||||||||||||||||||
Distribution | i 21 | i — | i — | i 1 | i 20 | i 42 | ||||||||||||||||||
Miscellaneous | i 5 | i — | i — | i — | i 2 | i 7 | ||||||||||||||||||
Natural
gas | ||||||||||||||||||||||||
Transmission and distribution | i 282 | i — | i — | i 13 | ( i 46 | ) | i 249 | |||||||||||||||||
Miscellaneous | i 4 | i — | i — | i — | i — | i 4 | ||||||||||||||||||
Common | ||||||||||||||||||||||||
Miscellaneous | i 1 | i — | i — | i — | i — | i 1 | ||||||||||||||||||
Non-utility | ||||||||||||||||||||||||
Miscellaneous | i — | i 1 | i — | i — | i — | i 1 | ||||||||||||||||||
Total
liability | $ | i 2,475 | $ | i 13 | $ | ( i 14 | ) | $ | i 120 | $ | ( i 26 | ) | $ | i 2,568 |
(a) | Amounts
incurred related to the PSCo Rush Creek wind farm and Nicollet Projects community solar gardens, which were placed in service in 2018. |
(b) | Amounts settled related to asbestos abatement projects and closure of certain ash containment facilities. |
(c) | In 2018, AROs were revised for changes in timing and estimates of cash
flows. Changes in gas transmission and distribution AROs were primarily related to increased gas line mileage and number of services, which were more than offset by increased discount rates. Changes in electric distribution AROs primarily related to increased labor costs. |
(Millions of Dollars) | 2019 | 2018 | ||||||
NSP-Minnesota | $ | i 520 | $ | i 485 | ||||
PSCo | i 351 | i 344 | ||||||
SPS | i 175 | i 188 | ||||||
NSP-Wisconsin | i 171 | i 158 | ||||||
Total
Xcel Energy | $ | i 1,217 | $ | i 1,175 |
Regulatory
Basis | ||||||||
(Millions of Dollars) | 2019 | 2018 | ||||||
Estimated decommissioning cost obligation from most recently approved study (in 2014 dollars) | $ | i 3,012 | $ | i 3,012 | ||||
Effect
of escalating costs | i 688 | i 539 | ||||||
Estimated
decommissioning cost obligation (in current dollars) | i 3,700 | i 3,551 | ||||||
Effect
of escalating costs to payment date | i 7,505 | i 7,654 | ||||||
Estimated
future decommissioning costs (undiscounted) | i 11,205 | i 11,205 | ||||||
Effect
of discounting obligation (using average risk-free interest rate of 2.39% and 3.33% for 2019 and 2018, respectively) | ( i 5,562 | ) | ( i 6,911 | ) | ||||
Discounted
decommissioning cost obligation | $ | i 5,643 | $ | i 4,294 | ||||
Assets
held in external decommissioning trust | $ | i 2,440 | $ | i 2,055 | ||||
Underfunding
of external decommissioning fund compared to the discounted decommissioning obligation | i 3,203 | i 2,239 |
(Millions of Dollars) | 2019 | 2018 | ||||||
Discounted
decommissioning cost obligation - regulated basis | $ | i 5,643 | $ | i 4,294 | ||||
Differences
in discount rate and market risk premium | ( i 2,295 | ) | ( i 1,447 | ) | ||||
O&M
costs not included for GAAP | ( i 1,280 | ) | ( i 879 | ) | ||||
Nuclear
production decommissioning ARO - GAAP | $ | i 2,068 | $ | i 1,968 |
(Millions of Dollars) | 2019 | 2018 | 2017 | |||||||||
Annual
decommissioning recorded as depreciation expense: (a) (b) | $ | i 20 | $ | i 20 | $ | i 20 |
(a) | Decommissioning
expense does not include depreciation of the capitalized nuclear asset retirement costs. |
(b) | Decommissioning expenses in 2019, 2018 and 2017 include Minnesota’s retail jurisdiction annual funding requirement of approximately $ i 14
million. |
(Millions of Dollars) | ||||
PPAs | $ | i 1,642 | ||
Other | i 201 | |||
Gross
operating lease ROU assets | i 1,843 | |||
Accumulated amortization | ( i 171 | ) | ||
Net
operating lease ROU assets | $ | i 1,672 |
(Millions of Dollars) | ||||||||
Gas storage facilities | $ | i 201 | $ | i 201 | ||||
Gas
pipeline | i 21 | i 21 | ||||||
Gross
finance lease ROU assets | i 222 | i 222 | ||||||
Accumulated
amortization | ( i 83 | ) | ( i 77 | ) | ||||
Net
finance lease ROU assets | $ | i 139 | $ | i 145 |
(Millions of Dollars) | 2019 | 2018 | 2017 | |||||||||
Operating
leases | ||||||||||||
PPA capacity payments | $ | i 221 | $ | i 210 | $ | i 210 | ||||||
Other
operating leases (a) | i 34 | i 38 | i 36 | |||||||||
Total
operating lease expense (b) | $ | i 255 | $ | i 248 | $ | i 246 | ||||||
Finance
leases | ||||||||||||
Amortization of ROU assets | $ | i 6 | $ | i 6 | $ | i 5 | ||||||
Interest
expense on lease liability | i 19 | i 19 | i 20 | |||||||||
Total
finance lease expense | $ | i 25 | $ | i 25 | $ | i 25 |
(a) | Includes
short-term lease expense of $ i 5 million for 2019, 2018 and 2017. |
(b) | PPA capacity payments are included in electric fuel and purchased power on the consolidated statements of income.
Expense for other operating leases is included in O&M expense and electric fuel and purchased power. |
(Millions of Dollars) | PPA (a)
(b) Operating Leases | Other Operating Leases | Total Operating Leases | Finance Leases (c) | ||||||||||||
2020 | $ | i 236 | $ | i 26 | $ | i 262 | $ | i 14 | ||||||||
2021 | i 238 | i 29 | i 267 | i 14 | ||||||||||||
2022 | i 225 | i 28 | i 253 | i 12 | ||||||||||||
2023 | i 214 | i 25 | i 239 | i 12 | ||||||||||||
2024 | i 208 | i 22 | i 230 | i 12 | ||||||||||||
Thereafter | i 750 | i 115 | i 865 | i 207 | ||||||||||||
Total
minimum obligation | i 1,871 | i 245 | i 2,116 | i 271 | ||||||||||||
Interest
component of obligation | ( i 321 | ) | ( i 52 | ) | ( i 373 | ) | ( i 190 | ) | ||||||||
Present
value of minimum obligation | $ | i 1,550 | i 193 | i 1,743 | i 81 | |||||||||||
Less
current portion | ( i 194 | ) | ( i 4 | ) | ||||||||||||
Noncurrent
operating and finance lease liabilities | $ | i 1,549 | $ | i 77 | ||||||||||||
Weighted-average
remaining lease term in years | i 9.3 | i 37.0 |
(a) | Amounts
do not include PPAs accounted for as executory contracts and/or contingent payments, such as energy payments on renewable PPAs. |
(b) | PPA operating leases contractually expire at various dates through 2033. |
(c) | Excludes certain amounts related to Xcel Energy’s i 50%
ownership interest in WYCO. |
(Millions of Dollars) | PPA
(a) (b) Operating Leases | Other Operating Leases | Total Operating Leases | Finance Leases (c) | ||||||||||||
2019 | $ | i 207 | $ | i 32 | $ | i 239 | $ | i 14 | ||||||||
2020 | i 208 | i 26 | i 234 | i 14 | ||||||||||||
2021 | i 210 | i 25 | i 235 | i 14 | ||||||||||||
2022 | i 197 | i 24 | i 221 | i 12 | ||||||||||||
2023 | i 186 | i 22 | i 208 | i 12 | ||||||||||||
Thereafter | i 883 | i 154 | i 1,037 | i 220 | ||||||||||||
Total
minimum obligation | i 286 | |||||||||||||||
Interest
component of obligation | ( i 201 | ) | ||||||||||||||
Present
value of minimum obligation | $ | i 85 |
(a) | Amounts
do not include PPAs accounted for as executory contracts and/or contingent payments, such as energy payments on renewable PPAs. |
(b) | PPA operating leases contractually expire at various dates through 2033. |
(c) | Excludes certain amounts related
to Xcel Energy’s i 50% ownership interest in WYCO. |
(Millions of Dollars) | Capacity | Energy (a) | ||||||
2020 | $ | i 70 | $ | i 110 | ||||
2021 | i 78 | i 157 | ||||||
2022 | i 77 | i 173 | ||||||
2023 | i 79 | i 177 | ||||||
2024 | i 74 | i 182 | ||||||
Thereafter | i 56 | i 146 | ||||||
Total | $ | i 434 | $ | i 945 |
(a) | Excludes
contingent energy payments for renewable energy PPAs. |
(Millions of Dollars) | Coal | Nuclear
fuel | Natural gas supply | Natural gas supply and transportation | ||||||||||||
2020 | $ | i 430 | $ | i 54 | $ | i 343 | $ | i 295 | ||||||||
2021 | i 222 | i 103 | i 254 | i 283 | ||||||||||||
2022 | i 135 | i 85 | i 104 | i 269 | ||||||||||||
2023 | i 58 | i 103 | i 53 | i 198 | ||||||||||||
2024 | i 24 | i 74 | i 3 | i 153 | ||||||||||||
Thereafter | i 74 | i 275 | i — | i 860 | ||||||||||||
Total | $ | i 943 | $ | i 694 | $ | i 757 | $ | i 2,058 |
(Millions of Dollars) | ||||||||
Current assets | $ | i 7 | $ | i 5 | ||||
Property,
plant and equipment, net | i 41 | i 42 | ||||||
Other
noncurrent assets | i 1 | i 1 | ||||||
Total
assets | $ | i 49 | $ | i 48 | ||||
Current
liabilities | $ | i 8 | $ | i 7 | ||||
Mortgages
and other long-term debt payable | i 26 | i 26 | ||||||
Other
noncurrent liabilities | i — | i — | ||||||
Total
liabilities | $ | i 34 | $ | i 33 |
(Millions of Dollars) | IBM
Agreement | Accenture Agreement | Cognizant Agreement | |||||||||
2020 | $ | i 15 | $ | i 11 | $ | i 9 | ||||||
2021 | i 15 | i — | i 7 | |||||||||
2022 | i 6 | i — | i 3 | |||||||||
2023 | i — | i — | i — | |||||||||
2024 | i — | i — | i — | |||||||||
Thereafter | i — | i — | i — |
13. Other
Comprehensive Income |
2019 | ||||||||||||
(Millions of Dollars) | Gains and Losses on Cash Flow Hedges | Defined
Benefit Pension and Postretirement Items | Total | |||||||||
Accumulated other comprehensive loss at Jan. 1 | $ | ( i 60 | ) | $ | ( i 64 | ) | $ | ( i 124 | ) | |||
Other
comprehensive loss before reclassifications (net of taxes of $(8) and $0, respectively) | ( i 23 | ) | i — | ( i 23 | ) | |||||||
Losses
reclassified from net accumulated other comprehensive loss: | ||||||||||||
Interest rate derivatives (net of taxes of $1 and $0, respectively) | i 3 | (a) | i — | i 3 | ||||||||
Amortization
of net actuarial loss (net of taxes of $0 and $1, respectively) | i — | i 3 | (b) | i 3 | ||||||||
Net
current period other comprehensive (loss) income | ( i 20 | ) | i 3 | ( i 17 | ) | |||||||
Accumulated
other comprehensive loss at Dec. 31 | $ | ( i 80 | ) | $ | ( i 61 | ) | $ | ( i 141 | ) |
(a) | Included
in interest charges. |
(b) | Included in the computation of net periodic pension and postretirement benefit costs. See Note 11 for further information. |
2018 | ||||||||||||
(Millions
of Dollars) | Gains and Losses on Cash Flow Hedges | Defined Benefit Pension and Postretirement Items | Total | |||||||||
Accumulated other comprehensive loss at Jan. 1 | $ | ( i 58 | ) | $ | ( i 67 | ) | $ | ( i 125 | ) | |||
Other
comprehensive loss before reclassifications (net of taxes of $(2) and $(2), respectively) | ( i 5 | ) | ( i 6 | ) | ( i 11 | ) | ||||||
Losses
reclassified from net accumulated other comprehensive loss: | ||||||||||||
Interest rate derivatives (net of taxes of $1 and $0, respectively) | i 3 | (a) | i — | i 3 | ||||||||
Amortization
of net actuarial loss (net of taxes of $0 and $3, respectively) | i — | i 9 | (b) | i 9 | ||||||||
Net
current period other comprehensive (loss) income | ( i 2 | ) | i 3 | i 1 | ||||||||
Accumulated
other comprehensive loss at Dec. 31 | $ | ( i 60 | ) | $ | ( i 64 | ) | $ | ( i 124 | ) |
(a) | Included
in interest charges. |
(b) | Included in the computation of net periodic pension and postretirement benefit costs. See Note 11 for further information. |
14. Segments
and Related Information |
• | Regulated Electric - The regulated electric utility segment generates, transmits and distributes electricity in Minnesota, Wisconsin, Michigan, North Dakota, South Dakota, Colorado, Texas and New Mexico. In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States. The regulated electric utility segment also includes wholesale commodity and trading operations; and |
• | Regulated
Natural Gas - The regulated natural gas utility segment transports, stores and distributes natural gas primarily in portions of Minnesota, Wisconsin, North Dakota, Michigan and Colorado. |
(Millions of Dollars) | 2019 | 2018 | 2017 | |||||||||
Regulated
Electric | ||||||||||||
Operating revenues from external customers | $ | i 9,575 | $ | i 9,719 | $ | i 9,676 | ||||||
Intersegment
revenue | i 1 | i 1 | i 2 | |||||||||
Total
revenues | $ | i 9,576 | $ | i 9,720 | $ | i 9,678 | ||||||
Depreciation
and amortization | i 1,535 | i 1,421 | i 1,298 | |||||||||
Interest
charges and financing costs | i 500 | i 449 | i 449 | |||||||||
Income
tax expense | i 125 | i 187 | i 528 | |||||||||
Net
income | i 1,288 | i 1,177 | i 1,066 | |||||||||
Regulated
Natural Gas | ||||||||||||
Operating revenues from external customers | $ | i 1,868 | $ | i 1,739 | $ | i 1,650 | ||||||
Intersegment
revenue | i 2 | i 2 | i 1 | |||||||||
Total
revenues | $ | i 1,870 | $ | i 1,741 | $ | i 1,651 | ||||||
Depreciation
and amortization | i 219 | i 212 | i 174 | |||||||||
Interest
charges and financing costs | i 69 | i 61 | i 57 | |||||||||
Income
tax expense | i 48 | i 28 | i 23 | |||||||||
Net
income | i 195 | i 187 | i 182 | |||||||||
Other | ||||||||||||
Total
operating revenue | $ | i 86 | $ | i 79 | $ | i 78 | ||||||
Depreciation
and amortization | i 11 | i 9 | i 7 | |||||||||
Interest
charges and financing costs | i 167 | i 142 | i 122 | |||||||||
Income
tax (benefit) | ( i 45 | ) | ( i 34 | ) | ( i 9 | ) | ||||||
Net
(loss) | ( i 111 | ) | ( i 103 | ) | ( i 100 | ) | ||||||
Consolidated
Total | ||||||||||||
Total revenue | $ | i 11,532 | $ | i 11,540 | $ | i 11,407 | ||||||
Reconciling
eliminations | ( i 3 | ) | ( i 3 | ) | ( i 3 | ) | ||||||
Consolidated
total revenue | $ | i 11,529 | $ | i 11,537 | $ | i 11,404 | ||||||
Depreciation
and amortization | i 1,765 | i 1,642 | i 1,479 | |||||||||
Interest
charges and financing costs | i 736 | i 652 | i 628 | |||||||||
Income
tax expense | i 128 | i 181 | i 542 | |||||||||
Net
income | i 1,372 | i 1,261 | i 1,148 |
15. Summarized
Quarterly Financial Data (Unaudited) |
Quarter
Ended | ||||||||||||||||
(Amounts in millions, except per share data) | ||||||||||||||||
Operating
revenues | $ | i 3,141 | $ | i 2,577 | $ | i 3,013 | $ | i 2,798 | ||||||||
Operating
income | i 486 | i 410 | i 758 | i 450 | ||||||||||||
Net
income | i 315 | i 238 | i 527 | i 292 | ||||||||||||
EPS
total — basic | $ | i 0.61 | $ | i 0.46 | $ | i 1.02 | $ | i 0.56 | ||||||||
EPS
total — diluted | i 0.61 | i 0.46 | i 1.01 | i 0.56 | ||||||||||||
Cash
dividends declared per common share | i 0.405 | i 0.405 | i 0.405 | i 0.405 |
Quarter
Ended | ||||||||||||||||
(Amounts in millions, except per share data) | ||||||||||||||||
Operating
revenues | $ | i 2,951 | $ | i 2,658 | $ | i 3,048 | $ | i 2,880 | ||||||||
Operating
income (a) | i 480 | i 450 | i 696 | i 339 | ||||||||||||
Net
income | i 291 | i 265 | i 491 | i 214 | ||||||||||||
EPS
total — basic | $ | i 0.57 | $ | i 0.52 | $ | i 0.96 | $ | i 0.42 | ||||||||
EPS
total — diluted | i 0.57 | i 0.52 | i 0.96 | i 0.42 | ||||||||||||
Cash
dividends declared per common share | i 0.380 | i 0.380 | i 0.380 | i 0.380 |
(a) | In
2018, Xcel Energy implemented ASU No. 2017-07 related to net periodic benefit cost, which resulted in retrospective reclassification of pension costs from O&M expense to other income. |
ITEM 9 — CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
ITEM
9A — CONTROLS AND PROCEDURES |
ITEM 9B
— OTHER INFORMATION |
ITEM 10 — DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE |
ITEM 11 — EXECUTIVE COMPENSATION |
ITEM 12
— SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS |
ITEM 13 — CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE |
ITEM 14 — PRINCIPAL ACCOUNTANT FEES AND SERVICES |
ITEM 15 — EXHIBITS, FINANCIAL STATEMENT SCHEDULES |
1 | Consolidated Financial Statements | |||
Management Report on Internal Controls Over
Financial Reporting — For the year ended Dec. 31, 2019. | ||||
Report of Independent Registered Public Accounting Firm — Financial Statements | ||||
Report of Independent Registered Public Accounting Firm — Internal Controls Over Financial Reporting | ||||
Consolidated Statements of Income — For the three years ended Dec. 31, 2019, 2018, and 2017. | ||||
Consolidated
Statements of Comprehensive Income — For the three years ended Dec. 31, 2019, 2018, and 2017. | ||||
Consolidated Statements of Cash Flows — For the three years ended Dec. 31, 2019, 2018, and 2017. | ||||
Consolidated Balance Sheets — As of Dec. 31, 2019 and 2018. | ||||
Consolidated
Statements of Common Stockholders’ Equity — For the three years ended Dec. 31, 2019, 2018, and 2017. | ||||
2 | Schedule I — Condensed Financial Information of Registrant. | |||
Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2019, 2018 and 2017. | ||||
3 | Exhibits | |||
* | Indicates
incorporation by reference | |||
+ | Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors | |||
Xcel Energy Inc. | ||||
Exhibit Number | Description | Report or Registration Statement | SEC File or Registration Number | Exhibit Reference |
3.01* | Xcel Energy Inc Form 8-K dated May 16, 2012 | 3.01 | ||
3.02* | Xcel
Energy Inc Form 8-K dated Feb. 17, 2016 | 3.01 | ||
4.02* | Xcel Energy Inc. Form 8-K dated Dec. 14, 2000 | 4.01 | ||
4.03* | Xcel Energy Inc. Form 8-K dated June 6, 2006 | 4.01 | ||
4.04* | Xcel Energy Inc. Form 8-K dated Jan. 16, 2008 | 4.01 | ||
4.05* | Xcel Energy Inc. Form 8-K dated Jan. 16, 2008 | 4.03 | ||
Xcel
Energy Inc. Form 8-K dated May 10, 2010 | 4.01 | |||
4.07* | Xcel Energy Inc. Form
8-K dated Sept. 12, 2011 | 4.01 | ||
4.08* | Xcel Energy Inc.
Form 8-K dated June 1, 2015 | 4.01 | ||
4.09* | Xcel Energy
Inc. Form 8-K dated March 8, 2016 | 4.02 | ||
4.10* | Xcel
Energy Inc. Form 8-K dated Dec. 1, 2016 | 4.01 | ||
4.11* | Xcel
Energy Inc. Form 8-K dated June 25, 2018 | 4.01 | ||
4.12* | Xcel Energy Inc. Form 8-K dated Nov. 7, 2019 | 4.01 | ||
Xcel
Energy Inc. Form 10-K for the year ended Dec. 31, 2008 | 10.02 | |||
10.02*+ | Xcel Energy Inc. Form 10-K for the year
ended Dec. 31, 2008 | 10.05 | ||
10.03*+ | Xcel Energy Inc. Form 10-K for the year ended Dec.
31, 2008 | 10.08 | ||
10.04*+ | Xcel Energy Inc. Form U5B dated Nov. 16, 2000 | H-1 | ||
10.05*+ | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008 | 10.17 | ||
10.06*+ | Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2009 | 10.06 |
10.07*+ | Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2009 | 10.08 | ||
10.08*+ | Xcel Energy Inc. Definitive Proxy Statement dated April 6, 2010 | Appendix A | ||
10.09*+ | Xcel Energy Inc. Definitive Proxy Statement dated April 5, 2011 | Appendix A | ||
10.10*+ | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008 | 10.07 | ||
10.11*+ | Xcel
Energy Inc. Form 10-K for the year ended Dec. 31, 2011 | 10.17 | ||
10.12*+ | Xcel Energy Inc. Form 10-K for the year ended Dec.
31, 2011 | 10.18 | ||
10.13*+ | Xcel Energy Inc. Form 10-Q for the quarter ended March 31, 2013 | 10.01 | ||
10.14*+ | Xcel Energy Inc. Form 10-Q for the quarter ended March 31, 2013 | 10.02 | ||
10.15*+ | Xcel
Energy Inc. Form 10-K for the year ended Dec. 31, 2013 | 10.22 | ||
10.16*+ | Xcel Energy Inc.
Form 8-K dated May 20, 2015 | 10.02 | ||
10.17*+ | Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2016 | 10.01 | ||
10.18*+ | Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2016 | 10.01 | ||
10.19*+ | Xcel
Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2017 | 10.1 | ||
10.20*+ | Xcel Energy Inc. Form 10-K for the year ended Dec.
31, 2017 | 10.30 | ||
10.21*+ | Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2018 | 10.01 | ||
Xcel Energy Inc. Form 8-K dated Nov. 7, 2018 | 10.01 | |||
Xcel Energy Inc. Form 8-K dated Dec. 4, 2018 | 99.01 | |||
10.24*+ | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018 | 10.34 | ||
10.25*+ | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018 | 10.35 | ||
10.26*+ | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018 | 10.36 | ||
10.27*+ | Xcel Energy Inc. Form 10-Q for the quarter ended March 31, 2019 | 10.01 | ||
Xcel Energy Inc. Form 8-K dated June 7, 2019 | 99.01 | |||
Xcel Energy Inc. Form 8-K dated Oct. 30, 2019 | 10.01 | |||
Xcel Energy Inc. Form 8-K dated Oct. 30, 2019 | 10.02 | |||
Xcel Energy Inc. Form 8-K dated Dec. 3, 2019 | 10.01 | |||
NSP-Minnesota | ||||
4.13* | Xcel Energy Inc. Form S-3 dated April 18, 2018 | 4(b)(3) | ||
4.14* | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2017 | 4.11 | ||
4.15* | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2017 | 4.12 | ||
4.16* | NSP-Minnesota Form 10-12G dated Oct. 5, 2000 | 4.51 | ||
4.17* | Xcel Energy Inc. Form S-3 dated April 18, 2018 | 4(b)(7) |
4.18* | NSP-Minnesota Form 10-12G dated Oct. 5, 2000 | 4.63 | ||
4.19* | NSP-Minnesota Form 8-K dated July 14, 2005 | 4.01 | ||
4.20* | NSP-Minnesota Form 8-K dated May 18, 2006 | 4.01 | ||
4.21* | NSP-Minnesota Form 8-K dated June 19, 2007 | 4.01 | ||
4.22* | NSP-Minnesota Form 8-K dated Nov. 16, 2009 | 4.01 | ||
4.23* | NSP-Minnesota Form 8-K dated Aug. 4, 2010 | 4.01 | ||
4.24* | NSP-Minnesota Form 8-K dated Aug. 13, 2012 | 4.01 | ||
4.25* | NSP-Minnesota Form 8-K dated May 20, 2013 | 4.01 | ||
4.26* | NSP-Minnesota Form 8-K dated May 13, 2014 | 4.01 | ||
4.27* | NSP-Minnesota Form 8-K dated Aug. 11, 2015 | 4.01 | ||
4.28* | NSP-Minnesota Form 8-K dated May 31, 2016 | 4.01 | ||
4.29* | NSP-Minnesota Form 8-K dated Sept. 13, 2017 | 4.01 | ||
4.30* | NSP-Minnesota Form 8-K dated Sept. 10, 2019 | 4.01 | ||
NSP-Wisconsin Form S-4 dated Jan. 21, 2004 | 10.01 | |||
Xcel Energy Inc. Form 8-K dated June 7, 2019 | 99.02 | |||
NSP-Wisconsin | ||||
4.31* | Xcel Energy Inc. Form S-3 dated April 18, 2018 | 4(c)(3) | ||
4.32* | NSP-Wisconsin Form 8-K dated Sept. 25, 2000 | 4.01 | ||
4.33* | Xcel Energy Inc Form 10-Q for the quarter ended Sept. 30, 2003 | 4.05 | ||
4.34* | NSP-Wisconsin Form 8-K dated Sept. 3, 2008 | 4.01 | ||
4.35* | NSP-Wisconsin Form 8-K dated Oct. 10, 2012 | 4.01 | ||
4.36* | NSP-Wisconsin Form 8-K dated June 23, 2014 | 4.01 | ||
4.37* | NSP-Wisconsin Form 8-K dated Dec. 4, 2017 | 4.01 | ||
4.38* | NSP-Wisconsin to Form 8-K dated Sept. 12, 2018 | 4.01 | ||
NSP-Wisconsin Form S-4 dated Jan. 21, 2004 | 10.01 |
Xcel Energy Inc. Form 8-K dated June 7, 2019 | 99.05 | |||
PSCo | ||||
4.39* | Xcel Energy Inc. Form S-3 dated April 18, 2018 | 4(d)(3) | ||
4.40* | PSCo Form 8-K dated July 13, 1999 | 4.1 4.2 | ||
4.41* | PSCo Form 8-K dated Aug. 8, 2007 | 4.01 | ||
4.42* | PSCo Form 8-K dated Aug. 6, 2008 | 4.01 | ||
4.43* | PSCo Form 8-K dated May 28, 2009 | 4.01 | ||
4.44* | PSCo Form 8-K dated Nov. 8, 2010 | 4.01 | ||
4.45* | PSCo Form 8-K dated Aug. 9, 2011 | 4.01 | ||
4.46* | PSCo Form 8-K dated Sept. 11, 2012 | 4.01 | ||
4.47* | PSCo Form 8-K dated March 26, 2013 | 4.01 | ||
4.48* | PSCo Form 8-K dated March 10, 2014 | 4.01 | ||
4.49* | PSCo Form 8-K dated May 12, 2015 | 4.01 | ||
4.50* | PSCo Form 8-K dated June 13, 2016 | 4.01 | ||
4.51* | PSCo Form 8-K dated June 19, 2017 | 4.01 | ||
4.52* | PSCo Form 8-K dated June 21, 2018 | 4.01 | ||
4.53* | PSCo Form 8-K dated March 13, 2019 | 4.01 | ||
4.54* | PSCo Form 8-K dated August 13, 2019 | 4.01 | ||
Xcel Energy Inc. Form 8-K dated Dec. 3, 2004 | 99.02 | |||
Xcel Energy Inc. Form 8-K dated June 7, 2019 | 99.03 | |||
SPS | ||||
4.55* | SPS Form 8-K dated Feb. 25, 1999 | 99.2 | ||
4.56* | Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2003 | 4.04 | ||
4.57* | SPS Form 8-K dated Oct. 3, 2006 | 4.01 | ||
4.58* | SPS Form 8-K dated Aug. 10, 2011 | 4.01 | ||
4.59* | SPS Form 8-K dated Aug. 10, 2011 | 4.02 | ||
4.60* | SPS Form 8-K dated June 9, 2014 | 4.02 | ||
4.61* | SPS Form 8-K dated Aug. 12, 2016 | 4.02 | ||
4.62* | SPS Form 8-K dated Aug 9. 2017 | 4.02 | ||
4.63* | SPS Form 8-K dated Nov. 5, 2018 | 4.02 |
4.64* | SPS Form 8-K dated June 18, 2019 | 4.02 | ||
Xcel Energy Inc. Form 8-K dated June 7, 2019 | 99.04 | |||
Xcel
Energy Inc. | ||||
101.INS | XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document | |||
101.SCH | XBRL
Schema | |||
101.CAL | XBRL Calculation | |||
101.DEF | XBRL Definition | |||
101.LAB | XBRL Label | |||
101.PRE | XBRL Presentation | |||
104 | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) |
XCEL ENERGY INC. CONDENSED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME (amounts in millions, except per share data) | |||||||||||
Year
Ended Dec. 31 | |||||||||||
2019 | 2018 | 2017 | |||||||||
Income | |||||||||||
Equity earnings
of subsidiaries | $ | i 1,505 | $ | i 1,393 | $ | i 1,263 | |||||
Total
income | i 1,505 | i 1,393 | i 1,263 | ||||||||
Expenses
and other deductions | |||||||||||
Operating expenses | i 23 | i 24 | i 30 | ||||||||
Other
income | ( i 9 | ) | ( i 1 | ) | ( i 6 | ) | |||||
Interest
charges and financing costs | i 173 | i 149 | i 128 | ||||||||
Total
expenses and other deductions | i 187 | i 172 | i 152 | ||||||||
Income
before income taxes | i 1,318 | i 1,221 | i 1,111 | ||||||||
Income
tax benefit | ( i 54 | ) | ( i 40 | ) | ( i 37 | ) | |||||
Net
income | $ | i 1,372 | $ | i 1,261 | $ | i 1,148 | |||||
Other
Comprehensive Income | |||||||||||
Pension and retiree medical benefits, net of tax of $1, $1 and $3, respectively | $ | i 3 | $ | i 3 | $ | i 4 | |||||
Derivative
instruments, net of tax of $(7), $(1) and $2, respectively | ( i 20 | ) | ( i 2 | ) | i 3 | ||||||
Other
comprehensive income (loss) | ( i 17 | ) | i 1 | i 7 | |||||||
Comprehensive
income | $ | i 1,355 | $ | i 1,262 | $ | i 1,155 | |||||
Weighted
average common shares outstanding: | |||||||||||
Basic | i 519 | i 511 | i 509 | ||||||||
Diluted | i 520 | i 511 | i 509 | ||||||||
Earnings
per average common share: | |||||||||||
Basic | $ | i 2.64 | $ | i 2.47 | $ | i 2.26 | |||||
Diluted | i 2.64 | i 2.47 | i 2.25 | ||||||||
See
Notes to Condensed Financial Statements |
XCEL ENERGY INC. CONDENSED STATEMENTS OF CASH FLOWS (amounts in millions) | |||||||||||
Year
Ended Dec. 31 | |||||||||||
2019 | 2018 | 2017 | |||||||||
Operating activities | |||||||||||
Net
cash provided by operating activities | $ | i 1,389 | $ | i 1,210 | $ | i 1,208 | |||||
Investing
activities | |||||||||||
Capital contributions to subsidiaries | ( i 1,594 | ) | ( i 809 | ) | ( i 849 | ) | |||||
Investments
in the utility money pool | ( i 1,054 | ) | ( i 2,578 | ) | ( i 1,258 | ) | |||||
Return
of investments in the utility money pool | i 1,093 | i 2,493 | i 1,173 | ||||||||
Net
cash used in investing activities | ( i 1,555 | ) | ( i 894 | ) | ( i 934 | ) | |||||
Financing
activities | |||||||||||
Proceeds from (repayment of) short-term borrowings, net | i 12 | ( i 295 | ) | i 715 | |||||||
Proceeds
from issuance of long-term debt | i 1,120 | i 492 | i — | ||||||||
Repayment
of long-term debt | ( i 550 | ) | i — | ( i 250 | ) | ||||||
Proceeds
from issuance of common stock | i 458 | i 230 | i — | ||||||||
Repurchase
of common stock | i — | ( i 1 | ) | ( i 3 | ) | ||||||
Dividends
paid | ( i 791 | ) | ( i 730 | ) | ( i 721 | ) | |||||
Other | ( i 14 | ) | ( i 12 | ) | ( i 14 | ) | |||||
Net
cash (used in) provided by financing activities | i 235 | ( i 316 | ) | ( i 273 | ) | ||||||
Net
change in cash and cash equivalents | i 69 | i — | i 1 | ||||||||
Cash
and cash equivalents at beginning of period | i 1 | i 1 | i — | ||||||||
Cash
and cash equivalents at end of period | $ | i 70 | $ | i 1 | $ | i 1 | |||||
See
Notes to Condensed Financial Statements |
XCEL ENERGY INC. CONDENSED BALANCE SHEETS (amounts in millions) | |||||||
Dec. 31 | |||||||
2019 | 2018 | ||||||
Assets | |||||||
Cash
and cash equivalents | $ | i 70 | $ | i 1 | |||
Accounts
receivable from subsidiaries | i 370 | i 309 | |||||
Other
current assets | i 12 | i 1 | |||||
Total
current assets | i 452 | i 311 | |||||
Investment
in subsidiaries | i 17,443 | i 15,965 | |||||
Other
assets | i 60 | i 44 | |||||
Total
other assets | i 17,503 | i 16,009 | |||||
Total
assets | $ | i 17,955 | $ | i 16,320 | |||
Liabilities
and Equity | |||||||
Dividends payable | i 212 | i 195 | |||||
Short-term
debt | i 500 | i 488 | |||||
Other
current liabilities | i 33 | i 10 | |||||
Total
current liabilities | i 745 | i 693 | |||||
Other
liabilities | i 23 | i 32 | |||||
Total
other liabilities | i 23 | i 32 | |||||
Commitments
and contingencies | |||||||
Capitalization | |||||||
Long-term debt | i 3,948 | i 3,373 | |||||
Common
stockholders’ equity | i 13,239 | i 12,222 | |||||
Total
capitalization | i 17,187 | i 15,595 | |||||
Total
liabilities and equity | $ | i 17,955 | $ | i 16,320 | |||
See
Notes to Condensed Financial Statements |
(Millions
of Dollars) | Guarantor | Guarantee Amount | Current Exposure | Triggering Event | |||||||
Guarantee of loan for Hiawatha Collegiate High School (a) | Xcel
Energy Inc. | $ | i 1.0 | i — | (c) | ||||||
Guarantee
performance and payment of surety bonds for Xcel Energy Inc.’s utility subsidiaries (b) | Xcel Energy Inc. | i 60.4 | (e) | (d) |
(a) | The
term of this guarantee expires the earlier of 2024 or full repayment of the loan. |
(b) | The surety bonds primarily relate to workers compensation benefits and utility projects. The workers compensation bonds are renewed annually and the project based bonds expire in conjunction with the completion of the related projects. |
(c) | Nonperformance and/or nonpayment. |
(d) | Per
the indemnity agreement between Xcel Energy Inc. and the various surety companies, surety companies have the discretion to demand that collateral be posted. |
(e) | Due to the magnitude of projects associated with the surety bonds, the total current exposure of this indemnification cannot be determined. Xcel Energy Inc. believes the exposure to be significantly less than the total amount of the outstanding bonds. |
2019 | 2018 | |||||||||||||||
(Millions of Dollars) | Accounts
Receivable | Accounts Payable | Accounts Receivable | Accounts Payable | ||||||||||||
NSP-Minnesota | $ | i 60 | $ | i — | $ | i 117 | $ | i — | ||||||||
NSP-Wisconsin | i 17 | i — | i 3 | i — | ||||||||||||
PSCo | i 78 | i — | i 29 | i — | ||||||||||||
SPS | i 47 | i — | i 39 | i — | ||||||||||||
Xcel
Energy Services Inc. | i 112 | i — | i 96 | i — | ||||||||||||
Xcel
Energy Ventures Inc. | i 25 | i — | i 13 | i — | ||||||||||||
Other
subsidiaries of Xcel Energy Inc. | i 31 | i — | i 12 | i — | ||||||||||||
$ | i 370 | $ | i — | $ | i 309 | $ | i — |
(Amounts
in Millions, Except Interest Rates) | Three Months Ended Dec. 31, 2019 | |||
Loan outstanding at period end | $ | i 39 | ||
Average
loan outstanding | i 35 | |||
Maximum loan outstanding | i 125 | |||
Weighted
average interest rate, computed on a daily basis | i 1.67 | % | ||
Weighted average interest rate at end of period | i 1.63 | % | ||
Money
pool interest income | i 1.47 | % |
(Amounts
in Millions, Except Interest Rates) | Year Ended | Year Ended | Year Ended Dec. 31, 2017 | |||||||||
Loan outstanding at period end | $ | i 39 | $ | i — | $ | i 85 | ||||||
Average
loan outstanding | i 47 | i 71 | i 38 | |||||||||
Maximum
loan outstanding | i 250 | i 243 | i 226 | |||||||||
Weighted
average interest rate, computed on a daily basis | i 2.15 | % | i 1.95 | % | i 1.13 | % | ||||||
Weighted
average interest rate at end of period | i 1.63 | % | N/A | i 1.18 | ||||||||
Money
pool interest income | $ | i 1.0 | $ | i 1.4 | $ | i 0.4 |
Allowance
for bad debts | NOL and tax credit valuation allowances | ||||||||||||||||||||||||
(Millions of Dollars) | 2019 | 2018 | 2017 | 2019 | 2018 | 2017 | |||||||||||||||||||
Balance
at Jan. 1 | $ | i 55 | $ | i 52 | $ | i 51 | $ | i 79 | $ | i 77 | $ | i 58 | |||||||||||||
Additions
charged to costs and expenses | i 42 | i 42 | i 39 | i 9 | i 7 | i 9 | |||||||||||||||||||
Additions
charged to other accounts | i 16 | (a) | i 11 | (a) | i 10 | (a) | i — | i — | i 22 | (c) | |||||||||||||||
Deductions
from reserves | ( i 58 | ) | (b) | ( i 50 | ) | (b) | ( i 48 | ) | (b) | ( i 21 | ) | (e) | ( i 5 | ) | (e) | ( i 12 | ) | (d) | |||||||
Balance
at Dec. 31 | $ | i 55 | $ | i 55 | $ | i 52 | $ | i 67 | $ | i 79 | $ | i 77 |
(a) | Recovery
of amounts previously written off. |
(b) | Deductions related primarily to bad debt write-offs. |
(c) | Accrual of valuation allowances for North Dakota ITC, net of federal income tax benefit, that is offset to a regulatory liability and includes $ i 14
million expense related to the revaluation of federal benefit as a result of the TCJA. |
(d) | Primarily the reductions to valuation allowances for North Dakota ITC carryforwards, net of federal benefit, primarily due to a consolidated adjustment to the regulatory liability accrual referenced above; the change includes $ i 4
million of reduced expense related to the revaluation of federal benefit as a result of TCJA. |
(e) | Primarily the reductions to valuation allowances due to additional NOLs and tax credits now forecasted to be used prior to expiration. |
ITEM 16 —
FORM 10-K SUMMARY |
XCEL
ENERGY INC. | ||
By: | ||
Executive
Vice President, Chief Financial Officer | ||
(Principal Financial Officer) |
/s/ BEN
FOWKE | Chairman, President, Chief Executive Officer and Director | ||
(Principal Executive Officer) | |||
Executive Vice President, Chief Financial Officer | |||
(Principal Financial Officer) | |||
Senior Vice President, Controller | |||
(Principal Accounting Officer) | |||
* | Director | ||
Lynn
Casey | |||
* | Director | ||
Richard K. Davis | |||
* | Director | ||
Richard
T. O’Brien | |||
* | Director | ||
David K. Owens | |||
* | Director | ||
Christopher
J. Policinski | |||
* | Director | ||
James Prokopanko | |||
* | Director | ||
A.
Patricia Sampson | |||
* | Director | ||
James J. Sheppard | |||
* | Director | ||
David
A. Westerlund | |||
* | Director | ||
Kim Williams | |||
* | Director | ||
Timothy
V. Wolf | |||
* | Director | ||
Daniel Yohannes | |||
*By: | Attorney-in-Fact | ||
This ‘10-K’ Filing | Date | Other Filings | ||
---|---|---|---|---|
9/1/37 | ||||
7/1/37 | ||||
10/1/36 | ||||
7/1/36 | ||||
6/1/36 | ||||
7/15/35 | ||||
10/1/33 | ||||
12/1/29 | ||||
6/15/28 | ||||
3/1/28 | ||||
12/1/26 | ||||
7/1/25 | ||||
6/1/25 | ||||
5/15/25 | ||||
6/15/24 | ||||
5/15/23 | ||||
3/15/23 | ||||
12/31/22 | ||||
9/15/22 | ||||
8/15/22 | ||||
3/15/22 | ||||
12/31/21 | ||||
11/30/21 | ||||
3/15/21 | ||||
1/1/21 | ||||
12/31/20 | ||||
12/1/20 | ||||
11/15/20 | ||||
11/1/20 | ||||
10/1/20 | ||||
9/30/20 | ||||
8/15/20 | ||||
5/31/20 | ||||
5/15/20 | 8-K | |||
5/1/20 | ||||
4/6/20 | 8-K | |||
4/1/20 | 8-K | |||
3/31/20 | 10-Q, 3, 4 | |||
3/30/20 | 4, 424B2 | |||
3/11/20 | ||||
3/1/20 | ||||
Filed on: | 2/21/20 | 4 | ||
2/19/20 | 8-K | |||
2/18/20 | 4 | |||
2/13/20 | ||||
2/11/20 | ||||
2/10/20 | ||||
2/5/20 | 8-K | |||
1/17/20 | ||||
1/13/20 | ||||
1/1/20 | ||||
For Period end: | 12/31/19 | 11-K, 5 | ||
12/26/19 | ||||
12/23/19 | ||||
12/15/19 | ||||
12/3/19 | 8-K | |||
11/7/19 | 8-K | |||
10/30/19 | 424B5, 8-K | |||
10/1/19 | 4 | |||
9/30/19 | 10-Q, 8-K | |||
9/10/19 | 4 | |||
8/31/19 | ||||
8/13/19 | ||||
6/30/19 | 10-Q | |||
6/28/19 | 4 | |||
6/18/19 | ||||
6/7/19 | 4, 8-K | |||
6/1/19 | ||||
3/31/19 | 10-Q | |||
3/29/19 | 4 | |||
3/21/19 | ||||
3/13/19 | 4 | |||
2/22/19 | 10-K, 4 | |||
2/1/19 | ||||
1/1/19 | ||||
12/31/18 | 10-K, 11-K, 4, 5 | |||
12/4/18 | 4 | |||
11/7/18 | 424B5 | |||
11/5/18 | ||||
9/30/18 | 10-Q | |||
9/12/18 | 4 | |||
6/30/18 | 10-Q | |||
6/25/18 | 8-K | |||
6/21/18 | 424B2 | |||
4/18/18 | S-3ASR | |||
3/31/18 | 10-Q | |||
1/1/18 | ||||
12/31/17 | 10-K, 11-K | |||
12/4/17 | 4 | |||
9/30/17 | 10-Q | |||
9/13/17 | ||||
6/19/17 | ||||
12/31/16 | 10-K, 11-K | |||
12/1/16 | 8-K | |||
9/30/16 | 10-Q, 4 | |||
9/28/16 | 4 | |||
8/12/16 | 8-K | |||
6/30/16 | 10-Q, 4 | |||
6/13/16 | ||||
5/31/16 | ||||
3/8/16 | 8-K | |||
2/17/16 | 8-K | |||
1/1/16 | ||||
12/31/15 | 10-K, 11-K, 4 | |||
9/1/15 | ||||
8/11/15 | ||||
6/1/15 | 4, 8-K | |||
5/20/15 | 8-K, DEF 14A, S-8 | |||
5/12/15 | UPLOAD | |||
2/11/15 | SC 13G/A | |||
12/31/14 | 10-K, 11-K, ARS | |||
6/23/14 | 8-K | |||
6/9/14 | ||||
5/13/14 | ARS | |||
3/10/14 | ||||
12/31/13 | 10-K, 11-K, ARS | |||
11/12/13 | ||||
5/20/13 | ||||
3/31/13 | 10-Q | |||
3/26/13 | ||||
10/10/12 | ||||
9/11/12 | ||||
8/13/12 | ||||
5/16/12 | 4, 8-K, DEF 14A, PRE 14A | |||
12/31/11 | 10-K, 11-K, ARS | |||
9/12/11 | 8-K | |||
8/10/11 | ||||
8/9/11 | ||||
4/5/11 | 8-K, DEF 14A, DEFA14A | |||
11/8/10 | ||||
8/4/10 | 424B2, FWP | |||
5/10/10 | 424B5, 8-K, FWP | |||
4/6/10 | DEF 14A, DEFA14A | |||
11/16/09 | 3, CORRESP, UPLOAD | |||
9/30/09 | 10-Q, UPLOAD | |||
5/28/09 | 8-K | |||
12/31/08 | 10-K, 11-K, 4 | |||
9/3/08 | 8-K | |||
8/6/08 | 4 | |||
1/16/08 | 4, 8-K | |||
8/8/07 | 8-K | |||
6/19/07 | 8-K, S-4 | |||
10/3/06 | 4 | |||
6/6/06 | 424B5, 8-K, FWP | |||
5/18/06 | 3, 4 | |||
7/14/05 | 8-K | |||
12/3/04 | 8-K | |||
1/21/04 | 4, 4/A | |||
9/30/03 | 10-Q, 4, POS AMC, U-1/A, U-9C-3 | |||
12/14/00 | 8-K | |||
11/16/00 | 35-CERT, U5B | |||
10/5/00 | ||||
9/25/00 | ||||
7/13/99 | ||||
2/25/99 | ||||
List all Filings |