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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)

☒ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2023
or

☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to
Commission File Number: 001-3034

Xcel Energy Inc.
(Exact Name of Registrant as Specified in its Charter)

Minnesota |  |  |  | 41-0448030
(State or Other Jurisdiction of Incorporation or Organization) |  |  |  | (I.R.S. Employer Identification No.)
414 Nicollet Mall | Minneapolis | Minnesota |  |  |  | 55401
(Address of Principal Executive Offices) |  |  |  | (Zip Code)

(612) | 330-5500
(Registrant’s Telephone Number, Including Area Code)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class |  | Trading Symbol(s) |  | Name of each exchange on which registered
Common Stock, $2.50 par value |  | XEL |  | Nasdaq Stock Market LLC

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ☒ Yes ☐ No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). ☒ Yes ☐ No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer | ☒ |  | Accelerated filer | ☐ |
Non-accelerated filer | ☐ |  | Smaller reporting company | ☐ |
|  |  | Emerging growth company | ☐ |

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ☐ Yes ☒ No
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

Class |  | Outstanding at April 24, 2023
Common Stock, $2.50 par value |  | 550,356,331 shares

TABLE OF CONTENTS

PART I | FINANCIAL INFORMATION |
Item 1 — | Financial Statements (unaudited) | 5
| Consolidated Statements of Income | 5
| Consolidated Statements of Comprehensive Income | 6
| Consolidated Statements of Cash Flows | 7
| Consolidated Balance Sheets | 8
| Consolidated Statements of Common Stockholders’ Equity | 9
| Notes to Consolidated Financial Statements | 10
Item 2 — | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 20
Item 3 — | Quantitative and Qualitative Disclosures A bout Market Risk | 30
Item 4 — | Controls and Procedures | 30
PART II | OTHER INFORMATION |
Item 1 — | Legal Proceedings | 30
Item 1A — | Risk Factors | 30
Item 2 — | Unregistered Sales of Equity Securities and Use of Proceeds | 31
Item 6 — | Exhibits | 31
SIGNATURES | 32

This Form 10-Q is filed by Xcel Energy Inc. Additional information is available in various filings with the SEC. This report should be read in its entirety.
2

Definitions of Abbreviations

Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former)
e prime | e prime inc.
NSP-Minnesota | Northern States Power Company, a Minnesota corporation
NSP System | The electric production and transmission system of NSP-Minnesota and NSP-Wisconsin operated on an integrated basis and managed by NSP-Minnesota
NSP-Wisconsin | Northern States Power Company, a Wisconsin corporation
PSCo | Public Service Company of Colorado
SPS | Southwestern Public Service Company
Utility subsidiaries | NSP-Minnesota, NSP-Wisconsin, PSCo and SPS
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
EPA | United States Environmental Protection Agency
FERC | Federal Energy Regulatory Commission
LES-FEA | Louisiana Energy Services & Federal Executive Agencies
MPUC | Minnesota Public Utilities Commission
NMPRC | New Mexico Public Regulation Commission
NRC | Nuclear Regulatory Commission
OAG | Minnesota Office of Attorney General
PSCW | Public Service Commission of Wisconsin
PUCT | Public Utility Commission of Texas
SEC | Securities and Exchange Commission

Electric, Purchased Gas and Resource Adjustment Clauses
ECA | Retail electric commodity adjustment
GCA | Gas cost adjustment

Other
AFUDC | Allowance for funds used during construction
AG | New Mexico Attorney General
ALJ | Administrative Law Judge
ATM | At-the-market
C&I | Commercial and Industrial
CCR | Coal combustion residuals
CCR Rule | Final rule (40 CFR 257.50 - 257.107) published by EPA regulating the management, storage and disposal of CCRs as a nonhazardous waste
CDD | Cooling degree-days
CEO | Chief executive officer

CERCLA | Comprehensive Environmental Response, Compensation, and Liability Act
CFO | Chief financial officer
CORE | CORE Electric Cooperative
CSPV | Crystalline Silicon Photovoltaic
DRIP | Dividend Reinvestment and Stock Purchase Program
EPS | Earnings per share
ETR | Effective tax rate
FTR | Financial transmission right
FTY | Future test year
GAAP | United States generally accepted accounting principles
GE | General Electric Company
HDD | Heating degree-days
IPP | Independent power producing entity
IRA | Inflation Reduction Act
LDC | Local distribution company
LLC | Limited liability company
LP&L | Lubbock Power and Light
MGP | Manufactured gas plant
MISO | Midcontinent Independent System Operator, Inc.
NAV | Net asset value
NMLCG | New Mexico Large Customer Group
NOPR | Notice of Proposed Rulemaking
NOx | Nitrogen Oxides
O&M | Operating and maintenance
OATT | Open Access Transmission Tariff
OPL | Occidental Permian Ltd.
PFAS | Per- and Polyfluroroalkyl Substances
PIM | Performance Incentive Mechanism
PPA | Power purchase agreement
PTC | Production tax credit
RFP | Request for proposal
ROE | Return on equity
RTO | Regional Transmission Organization
SMMPA | Southern Minnesota Municipal Power Agency
SPP | Southwest Power Pool, Inc.
TCA | Transmission cost adjustment
THI | Temperature-humidity index
TOs | Transmission owners
VaR | Value at Risk

Measurements
MW | Megawatts

3

Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed herein are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements, including those relating to 2023 EPS guidance, long-term EPS and dividend growth rate objectives, future sales, future expenses, future tax rates, future operating performance, estimated base capital expenditures and financing plans, projected capital additions and forecasted annual revenue requirements with respect to rider filings, expected rate increases to customers, expectations and intentions regarding regulatory proceedings, and expected impact on our results of operations, financial condition and cash flows of resettlement calculations and credit losses relating to certain energy transactions, as well as assumptions and other statements are intended to be identified in this document by the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” “will,” “would” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we expressly disclaim any obligation to update any forward-looking information. The following factors, in addition to those discussed elsewhere in Xcel Energy’s Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2022 and subsequent filings with the SEC, could cause actual results to differ materially from management expectations as suggested by such forward-looking information: operational safety, including our nuclear generation facilities and other utility operations; successful long-term operational planning; commodity risks associated with energy markets and production; rising energy prices and fuel costs; qualified employee work force and third-party contractor factors; violations of our Codes of Conduct; our ability to recover costs and our subsidiaries’ ability to recover costs from customers; changes in regulation; reductions in our credit ratings and the cost of maintaining certain contractual relationships; general economic conditions, including recessionary conditions, inflation rates, monetary fluctuations, supply chain constraints and their impact on capital expenditures and/or the ability of Xcel Energy Inc. and its subsidiaries to obtain financing on favorable terms; availability or cost of capital; our customers’ and counterparties’ ability to pay their debts to us; assumptions and costs relating to funding our employee benefit plans and health care benefits; our subsidiaries’ ability to make dividend payments; tax laws; uncertainty regarding epidemics, the duration and magnitude of business restrictions including shutdowns (domestically and globally), the potential impact on the workforce, including shortages of employees or third-party contractors due to quarantine policies, vaccination requirements or government restrictions, impacts on the transportation of goods and the generalized impact on the economy; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; seasonal weather patterns; changes in environmental laws and regulations; climate change and other weather events; natural disaster and resource depletion, including compliance with any accompanying legislative and regulatory changes; costs of potential regulatory penalties; regulatory changes and/or limitations related to the use of natural gas as an energy source; challenging labor market conditions and our ability to attract and retain a qualified workforce; and our ability to execute on our strategies or achieve expectations related to environmental, social and governance matters including as a result of evolving legal, regulatory and other standards, processes, and assumptions, the pace of scientific and technological developments, increased costs, the availability of requisite financing, and changes in carbon markets.
4

Table of Contents
PART I — FINANCIAL INFORMATION

ITEM 1 — FINANCIAL STATEMENTS

XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
(amounts in millions, except per share data)

|  |  | Three Months Ended March 31
|  |  |  |  | 2023 |  | 2022
Operating revenues |  |  |  |  |  |  |
Electric |  |  |  |  | $ | 2,763 |  |  | $ | 2,633 |
Natural gas |  |  |  |  | 1,288 |  |  | 1,090 |
Other |  |  |  |  | 29 |  |  | 28 |
Total operating revenues |  |  |  |  | 4,080 |  |  | 3,751 |
Operating expenses |  |  |  |  |  |  |
Electric fuel and purchased power |  |  |  |  | 1,117 |  |  | 1,094 |
Cost of natural gas sold and transported |  |  |  |  | 844 |  |  | 710 |
Cost of sales — other |  |  |  |  | 12 |  |  | 10 |
Operating and maintenance expenses |  |  |  |  | 650 |  |  | 602 |
Conservation and demand side management expenses |  |  |  |  | 76 |  |  | 92 |
Depreciation and amortization |  |  |  |  | 624 |  |  | 562 |
Taxes (other than income taxes) |  |  |  |  | 184 |  |  | 171 |
Total operating expenses |  |  |  |  | 3,507 |  |  | 3,241 |
Operating income |  |  |  |  | 573 |  |  | 510 |
Other income, net |  |  |  |  | 5 |  |  | 1 |
Earnings from equity method investments |  |  |  |  | 11 |  |  | 15 |
Allowance for funds used during construction — equity |  |  |  |  | 19 |  |  | 13 |
Interest charges and financing costs |  |  |  |  |  |  |
Interest charges — includes other financing costs of $8 |  |  |  |  | 253 |  |  | 214 |
Allowance for funds used during construction — debt |  |  |  |  | (10) |  |  | (5) |
Total interest charges and financing costs |  |  |  |  | 243 |  |  | 209 |
Income before income taxes |  |  |  |  | 365 |  |  | 330 |
Income tax benefit |  |  |  |  | (53) |  |  | (50) |
Net income |  |  |  |  | $ | 418 |  |  | $ | 380 |
Weighted average common shares outstanding: |  |  |  |  |  |  |
Basic |  |  |  |  | 551 |  |  | 545 |
Diluted |  |  |  |  | 551 |  |  | 545 |
Earnings per average common share: |  |  |  |  |  |  |
Basic |  |  |  |  | $ | 0.76 |  |  | $ | 0.70 |
Diluted |  |  |  |  | 0.76 |  |  | 0.70 |
See Notes to Consolidated Financial Statements

5

Table of Contents
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
(amounts in millions)

|  |  | Three Months Ended March 31
|  |  |  |  | 2023 |  | 2022
Net income |  |  |  |  | $ | 418 |  |  | $ | 380 |
Other comprehensive income |  |  |  |  |  |  |
Pension and retiree medical benefits: |  |  |  |  |  |  |
Reclassifications of loss to net income, net of tax of $— and $1, respectively |  |  |  |  | — |  |  | 1 |
Derivative instruments: |  |  |  |  |  |  |
Net fair value (decrease) increase, net of tax of $(2) and $1, respectively |  |  |  |  | (5) |  |  | 5 |
Reclassification of losses to net income, net of tax of $— and $1, respectively |  |  |  |  | 1 |  |  | 1 |
Total other comprehensive (loss) income |  |  |  |  | (4) |  |  | 7 |
Total comprehensive income |  |  |  |  | $ | 414 |  |  | $ | 387 |
See Notes to Consolidated Financial Statements

6

Table of Contents
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(amounts in millions)

| Three Months Ended March 31
| 2023 |  | 2022
Operating activities |  |  |
Net income | $ | 418 |  |  | $ | 380 |
Adjustments to reconcile net income to cash provided by operating activities: |  |  |
Depreciation and amortization | 631 |  |  | 567 |
Nuclear fuel amortization | 29 |  |  | 30 |
Deferred income taxes | (73) |  |  | (55) |
Allowance for equity funds used during construction | (19) |  |  | (13) |
Earnings from equity method investments | (11) |  |  | (15) |
Dividends from equity method investments | 9 |  |  | 10 |
Provision for bad debts | 23 |  |  | 17 |
Share-based compensation expense | 9 |  |  | 4 |
Changes in operating assets and liabilities: |  |  |
Accounts receivable | 50 |  |  | (191) |
Accrued unbilled revenues | 329 |  |  | 146 |
Inventories | 189 |  |  | 107 |
Other current assets | 8 |  |  | (10) |
Accounts payable | (359) |  |  | (34) |
Net regulatory assets and liabilities | 345 |  |  | 215 |
Other current liabilities | 63 |  |  | 51 |
Pension and other employee benefit obligations | (45) |  |  | (31) |
Other, net | (59) |  |  | (38) |
Net cash provided by operating activities | 1,537 |  |  | 1,140 |
Investing activities |  |  |
Capital/construction expenditures | (1,265) |  |  | (942) |
Purchase of investment securities | (236) |  |  | (156) |
Proceeds from the sale of investment securities | 228 |  |  | 147 |
Other, net | (11) |  |  | (1) |
Net cash used in investing activities | (1,284) |  |  | (952) |
Financing activities |  |  |
Proceeds from (repayments of) short-term borrowings, net | 266 |  |  | (9) |
Repayments of long-term debt, including reacquisition premiums | (250) |  |  | — |
Proceeds from issuance of common stock | 6 |  |  | 1 |
Dividends paid | (259) |  |  | (240) |
Other, net | (13) |  |  | (16) |
Net cash used in financing activities | (250) |  |  | (264) |
Net change in cash, cash equivalents and restricted cash | 3 |  |  | (76) |
Cash, cash equivalents and restricted cash at beginning of period | 111 |  |  | 166 |
Cash, cash equivalents and restricted cash at end of period | $ | 114 |  |  | $ | 90 |
Supplemental disclosure of cash flow information: |  |  |
Cash paid for interest (net of amounts capitalized) | $ | (209) |  |  | $ | (202) |
Cash paid for income taxes, net | (1) |  |  | — |
Supplemental disclosure of non-cash investing and financing transactions: |  |  |
Accrued property, plant and equipment additions | $ | 449 |  |  | $ | 288 |
Inventory transfers to property, plant and equipment | 34 |  |  | 20 |
Operating lease right-of-use assets | 47 |  |  | 8 |
Allowance for equity funds used during construction | 19 |  |  | 13 |
Issuance of common stock for reinvested dividends and/or equity awards | 21 |  |  | 11 |
See Notes to Consolidated Financial Statements

7

Table of Contents
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(amounts in millions, except share and per share data)

| March 31, 2023 |  | Dec. 31, 2022
Assets |  |  |
Current assets |  |  |
Cash and cash equivalents | $ | 114 |  |  | $ | 111 |
Accounts receivable, net | 1,300 |  |  | 1,373 |
Accrued unbilled revenues | 777 |  |  | 1,105 |
Inventories | 580 |  |  | 803 |
Regulatory assets | 983 |  |  | 1,059 |
Derivative instruments | 97 |  |  | 279 |
Prepaid taxes | 43 |  |  | 54 |
Prepayments and other | 359 |  |  | 360 |
Total current assets | 4,253 |  |  | 5,144 |
Property, plant and equipment, net | 48,896 |  |  | 48,253 |
Other assets |  |  |
Nuclear decommissioning fund and other investments | 3,373 |  |  | 3,234 |
Regulatory assets | 2,657 |  |  | 2,871 |
Derivative instruments | 97 |  |  | 93 |
Operating lease right-of-use assets | 1,194 |  |  | 1,204 |
Other | 475 |  |  | 389 |
Total other assets | 7,796 |  |  | 7,791 |
Total assets | $ | 60,945 |  |  | $ | 61,188 |
Liabilities and Equity |  |  |
Current liabilities |  |  |
Current portion of long-term debt | $ | 901 |  |  | $ | 1,151 |
Short-term debt | 1,079 |  |  | 813 |
Accounts payable | 1,338 |  |  | 1,804 |
Regulatory liabilities | 358 |  |  | 418 |
Taxes accrued | 682 |  |  | 569 |
Accrued interest | 242 |  |  | 217 |
Dividends payable | 286 |  |  | 268 |
Derivative instruments | 62 |  |  | 76 |
Operating lease liabilities | 224 |  |  | 217 |
Other | 489 |  |  | 545 |
Total current liabilities | 5,661 |  |  | 6,078 |
Deferred credits and other liabilities |  |  |
Deferred income taxes | 4,729 |  |  | 4,756 |
Deferred investment tax credits | 47 |  |  | 48 |
Regulatory liabilities | 5,640 |  |  | 5,569 |
Asset retirement obligations | 3,423 |  |  | 3,380 |
Derivative instruments | 116 |  |  | 113 |
Customer advances | 180 |  |  | 181 |
Pension and employee benefit obligations | 345 |  |  | 390 |
Operating lease liabilities | 1,020 |  |  | 1,038 |
Other | 148 |  |  | 147 |
Total deferred credits and other liabilities | 15,648 |  |  | 15,622 |
Commitments and contingencies |  |  |
Capitalization |  |  |
Long-term debt | 22,818 |  |  | 22,813 |
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 550,222,192 and 549,578,018 shares outstanding at March 31, 2023 and December 31, 2022, respectively | 1,376 |  |  | 1,374 |
Additional paid in capital | 8,169 |  |  | 8,155 |
Retained earnings | 7,370 |  |  | 7,239 |
Accumulated other comprehensive loss | (97) |  |  | (93) |
Total common stockholders’ equity | 16,818 |  |  | 16,675 |
Total liabilities and equity | $ | 60,945 |  |  | $ | 61,188 |
See Notes to Consolidated Financial Statements

8

Table of Contents
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY (UNAUDITED)
(amounts in millions, except per share data; shares in actual amounts)

| Common Stock Issued |  | Retained Earnings |  | Accumulated Other Comprehensive Loss |  | Total Common Stockholders' Equity
| Shares |  | Par Value |  | Additional Paid In Capital |  |  |
Three Months Ended March 31, 2023 and 2022 |  |  |  |  |  |  |  |  |  |  |
Balance at Dec. 31, 2021 | 544,025,269 |  |  | $ | 1,360 |  |  | $ | 7,803 |  |  | $ | 6,572 |  |  | $ | (123) |  |  | $ | 15,612 |
Net income |  |  |  |  |  |  | 380 |  |  |  |  | 380 |
Other comprehensive loss |  |  |  |  |  |  |  |  | 7 |  |  | 7 |
Dividends declared on common stock ($0.4875 per share) |  |  |  |  |  |  | (265) |  |  |  |  | (265) |
Issuances of common stock | 505,718 |  |  | 1 |  |  | 11 |  |  |  |  |  |  | 12 |
Share-based compensation |  |  |  |  | (13) |  |  | (1) |  |  |  |  | (14) |
Balance at March 31, 2022 | 544,530,987 |  |  | $ | 1,361 |  |  | $ | 7,801 |  |  | $ | 6,686 |  |  | $ | (116) |  |  | $ | 15,732 |
Balance at Dec. 31, 2022 | 549,578,018 |  |  | $ | 1,374 |  |  | $ | 8,155 |  |  | $ | 7,239 |  |  | $ | (93) |  |  | $ | 16,675 |
Net income |  |  |  |  |  |  | 418 |  |  |  |  | 418 |
Other comprehensive income |  |  |  |  |  |  |  |  | (4) |  |  | (4) |
Dividends declared on common stock ($0.52 per share) |  |  |  |  |  |  | (286) |  |  |  |  | (286) |
Issuances of common stock | 644,174 |  |  | 2 |  |  | 16 |  |  |  |  |  |  | 18 |
Share-based compensation |  |  |  |  | (2) |  |  | (1) |  |  |  |  | (3) |
Balance at March 31, 2023 | 550,222,192 |  |  | $ | 1,376 |  |  | $ | 8,169 |  |  | $ | 7,370 |  |  | $ | (97) |  |  | $ | 16,818 |
See Notes to Consolidated Financial Statements

9

Table of Contents
XCEL ENERGY INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements (UNAUDITED)
In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly, in accordance with GAAP, the financial position of Xcel Energy as of March 31, 2023 and Dec. 31, 2022; the results of Xcel Energy’s operations, including the components of net income, comprehensive income, and changes in stockholders’ equity for the three months ended March 31, 2023 and 2022; and Xcel Energy’s cash flows for the three months ended March 31, 2023 and 2022.
All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after March 31, 2023, up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation. The Dec. 31, 2022 balance sheet information has been derived from the audited 2022 consolidated financial statements included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2022.
Notes to the consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP on an annual basis have been condensed or omitted pursuant to such rules and regulations. For further information, refer to the consolidated financial statements and notes thereto included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2022, filed with the SEC on Feb. 23, 2023.
Due to the seasonality of Xcel Energy’s electric and natural gas sales, interim results are not necessarily an appropriate base from which to project annual results.

1. Summary of Significant Accounting Policies

The significant accounting policies set forth in Note 1 to the consolidated financial statements in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2022 appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

2. Accounting Pronouncements

As of March 31, 2023, there was no material impact from the recent adoption of new accounting pronouncements, nor expected material impact from recently issued accounting pronouncements yet to be adopted, on Xcel Energy’s consolidated financial statements.

3. Selected Balance Sheet Data

(Millions of Dollars) |  | March 31, 2023 |  | Dec. 31, 2022
Accounts receivable, net |  |  |  |
Accounts receivable |  | $ | 1,426 |  |  | $ | 1,495 |
Less allowance for bad debts |  | (126) |  |  | (122) |
Accounts receivable, net |  | $ | 1,300 |  |  | $ | 1,373 |

(Millions of Dollars) |  | March 31, 2023 |  | Dec. 31, 2022
Inventories |  |  |  |
Materials and supplies |  | $ | 340 |  |  | $ | 330 |
Fuel |  | 169 |  |  | 201 |
Natural gas |  | 71 |  |  | 272 |
Total inventories |  | $ | 580 |  |  | $ | 803 |

(Millions of Dollars) |  | March 31, 2023 |  | Dec. 31, 2022
Property, plant and equipment, net |  |  |  |
Electric plant |  | $ | 50,227 |  |  | $ | 49,639 |
Natural gas plant |  | 8,612 |  |  | 8,514 |
Common and other property |  | 3,001 |  |  | 2,970 |
Plant to be retired (a) |  | 2,180 |  |  | 2,217 |
Construction work in progress |  | 2,224 |  |  | 2,124 |
Total property, plant and equipment |  | 66,244 |  |  | 65,464 |
Less accumulated depreciation |  | (17,694) |  |  | (17,502) |
Nuclear fuel |  | 3,266 |  |  | 3,183 |
Less accumulated amortization |  | (2,920) |  |  | (2,892) |
Property, plant and equipment, net |  | $ | 48,896 |  |  | $ | 48,253 |

(a)Amounts include Sherco Units 1, 2 and 3 and A.S. King for NSP-Minnesota; Comanche Units 2 and 3, Craig Units 1 and 2, Hayden Units 1 and 2 and coal generation assets at Pawnee pending facility gas conversion for PSCo; and Tolk and coal generation assets at Harrington pending facility gas conversion for SPS. Amounts are presented net of accumulated depreciation.

4. Borrowings and Other Financing Instruments

Short-Term Borrowings
Short-Term Debt — Xcel Energy Inc. and its utility subsidiaries meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under their credit facilities and term loan agreements.
Commercial paper and term loan borrowings outstanding for Xcel Energy:

(Amounts in Millions, Except Interest Rates) |  | Three Months Ended March 31, 2023 |  | Year Ended Dec. 31, 2022
Borrowing limit |  | $ | 3,550 |  |  | $ | 3,550 |
Amount outstanding at period end |  | 1,079 |  |  | 813 |
Average amount outstanding |  | 928 |  |  | 552 |
Maximum amount outstanding |  | 1,241 |  |  | 1,357 |
Weighted average interest rate, computed on a daily basis |  | 4.85 | % |  | 1.47 | %
Weighted average interest rate at period end |  | 5.23 |  |  | 4.66 |

Letters of Credit — Xcel Energy Inc. and its utility subsidiaries use letters of credit, generally with terms of one year, to provide financial guarantees for certain obligations. There were $43 million of letters of credit outstanding under the credit facilities at both March 31, 2023 and Dec. 31, 2022. Amounts approximate their fair value and are subject to fees.
Revolving Credit Facilities — In order to issue commercial paper, Xcel Energy Inc. and its utility subsidiaries must have revolving credit facilities equal or greater than the commercial paper borrowing limits and cannot issue commercial paper exceeding available credit facility capacity. The lines of credit provide short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.
As of March 31, 2023, Xcel Energy Inc. and its utility subsidiaries had the following committed revolving credit facilities available:

(Millions of Dollars) |  | Credit Facility (a) |  | Drawn (b) |  | Available
Xcel Energy Inc. |  | $ | 1,500 |  |  | $ | 510 |  |  | $ | 990 |
PSCo |  | 700 |  |  | 385 |  |  | 315 |
NSP-Minnesota |  | 700 |  |  | 135 |  |  | 565 |
SPS |  | 500 |  |  | 80 |  |  | 420 |
NSP-Wisconsin |  | 150 |  |  | 12 |  |  | 138 |
Total |  | $ | 3,550 |  |  | $ | 1,122 |  |  | $ | 2,428 |

(a)Expires in September 2027.
(b)Includes outstanding commercial paper and letters of credit.
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Xcel Energy Inc., NSP-Minnesota, PSCo, and SPS each have the right to request an extension of the credit facility termination date for two additional one-year periods. NSP-Wisconsin has the right to request an extension of the credit facility termination date for an additional one-year period. All extension requests are subject to majority bank group approval.
All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity of the credit facility. Xcel Energy Inc. and its utility subsidiaries had no direct advances on the credit facilities outstanding as of March 31, 2023 and Dec. 31, 2022.
Bilateral Credit Agreement
In April 2023, NSP-Minnesota’s uncommitted bilateral credit agreement was renewed for an additional one-year term. The credit agreement is limited in use to support letters of credit.
As of March 31, 2023, NSP-Minnesota had $53 million of outstanding letters of credit under the $75 million bilateral credit agreement.
Long-Term Borrowings and Other Financing Instruments
On April 3, 2023, PSCo issued $850 million of 5.25% first mortgage bonds due April 1, 2053.
On April 21, 2023, NSP-Wisconsin priced a private placement of $125 million of 5.30% first mortgage bonds due June 15, 2053. The closing of the sale of the bonds is subject to execution of a bond purchase agreement and customary closing conditions and is expected to occur in June 2023.
ATM Equity Offering — In November 2021, Xcel Energy Inc. filed a prospectus supplement under which it may sell up to $800 million of its common stock through an ATM program. In 2021, 5.33 million shares were issued (approximately $350 million). In 2022, 4.30 million shares of common stock were issued (approximately $300 million). As of March 31, 2023, approximately $150 million remained available for sale under the ATM program.
Other Equity — Xcel Energy Inc. issued $15 million and $10 million of equity through the DRIP during the three months ended March 31, 2023 and 2022, respectively. The program allows shareholders to reinvest their dividends directly in Xcel Energy Inc. common stock.

5. Revenues

Revenue is classified by the type of goods/services rendered and market/customer type. Xcel Energy’s operating revenues consisted of the following:

|  | Three Months Ended March 31, 2023
(Millions of Dollars) |  | Electric |  | Natural Gas |  | All Other |  | Total
Major revenue types |  |  |  |  |  |  |  |
Revenue from contracts with customers:
Residential |  | $ | 875 |  |  | $ | 789 |  |  | $ | 13 |  |  | $ | 1,677 |
C&I |  | 1,352 |  |  | 423 |  |  | 12 |  |  | 1,787 |
Other |  | 36 |  |  | — |  |  | 1 |  |  | 37 |
Total retail |  | 2,263 |  |  | 1,212 |  |  | 26 |  |  | 3,501 |
Wholesale |  | 224 |  |  | — |  |  | — |  |  | 224 |
Transmission |  | 163 |  |  | — |  |  | — |  |  | 163 |
Other |  | 9 |  |  | 48 |  |  | — |  |  | 57 |
Total revenue from contracts with customers |  | 2,659 |  |  | 1,260 |  |  | 26 |  |  | 3,945 |
Alternative revenue and other |  | 104 |  |  | 28 |  |  | 3 |  |  | 135 |
Total revenues |  | $ | 2,763 |  |  | $ | 1,288 |  |  | $ | 29 |  |  | $ | 4,080 |

|  | Three Months Ended March 31, 2022
(Millions of Dollars) |  | Electric |  | Natural Gas |  | All Other |  | Total
Major revenue types |  |  |  |  |  |  |  |
Revenue from contracts with customers:
Residential |  | $ | 817 |  |  | $ | 663 |  |  | $ | 9 |  |  | $ | 1,489 |
C&I |  | 1,235 |  |  | 356 |  |  | 2 |  |  | 1,593 |
Other |  | 32 |  |  | — |  |  | 14 |  |  | 46 |
Total retail |  | 2,084 |  |  | 1,019 |  |  | 25 |  |  | 3,128 |
Wholesale |  | 259 |  |  | — |  |  | — |  |  | 259 |
Transmission |  | 152 |  |  | — |  |  | — |  |  | 152 |
Other |  | 23 |  |  | 45 |  |  | — |  |  | 68 |
Total revenue from contracts with customers |  | 2,518 |  |  | 1,064 |  |  | 25 |  |  | 3,607 |
Alternative revenue and other |  | 115 |  |  | 26 |  |  | 3 |  |  | 144 |
Total revenues |  | $ | 2,633 |  |  | $ | 1,090 |  |  | $ | 28 |  |  | $ | 3,751 |

6. Income Taxes

Reconciliation between the statutory rate and ETR:

|  |  |  | Three Months Ended March 31
|  |  |  |  |  | 2023 |  | 2022
Federal statutory rate |  |  |  |  |  | 21.0 | % |  | 21.0 | %
State tax (net of federal tax effect) |  |  |  |  |  | 4.8 |  |  | 4.9 |
Decreases: |  |  |  |  |  |  |  |
Wind PTCs (a) |  |  |  |  |  | (33.1) |  |  | (34.4) |
Plant regulatory differences (b) |  |  |  |  |  | (5.5) |  |  | (4.8) |
Other tax credits, net operating loss & tax credits allowances |  |  |  |  |  | (1.6) |  |  | (1.5) |
Other (net) |  |  |  |  |  | (0.1) |  |  | (0.4) |
Effective income tax rate |  |  |  |  |  | (14.5) | % |  | (15.2) | %

(a)Wind PTCs are credited to customers (reduction to revenue) and do not materially impact net income.
(b)Regulatory differences for income tax primarily relate to the credit of excess deferred taxes to customers through the average rate assumption method. Income tax benefits associated with the credit of excess deferred taxes are offset by corresponding revenue reductions.

7. Earnings Per Share

Basic EPS was computed by dividing the earnings available to common shareholders by the average weighted number of common shares outstanding. Diluted EPS was computed by dividing the earnings available to common shareholders by the diluted weighted average number of common shares outstanding.
Diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock (i.e., common stock equivalents) were settled. The weighted average number of potentially dilutive shares outstanding used to calculate diluted EPS is calculated using the treasury stock method.
Common Stock Equivalents — Xcel Energy Inc. has common stock equivalents related to time-based equity compensation awards.
Stock equivalent units granted to Xcel Energy Inc.’s Board of Directors are included in common shares outstanding upon grant date as there is no further service, performance or market condition associated with these awards. Restricted stock issued to employees is included in common shares outstanding when granted.
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Share-based compensation arrangements for which there is currently no dilutive impact to EPS include the following:
•Equity awards subject to a performance condition; included in common shares outstanding when all necessary conditions have been satisfied by the end of the reporting period.
•Liability awards subject to a performance condition; any portions settled in shares are included in common shares outstanding upon settlement.
Common shares outstanding used in the basic and diluted EPS computation:

|  |  |  | Three Months Ended March 31
(Shares in Millions) |  |  |  |  |  | 2023 |  | 2022
Basic |  |  |  |  |  | 551 |  | 545
Diluted (a) |  |  |  |  |  | 551 |  |  | 545 |

(a)Diluted common shares outstanding included common stock equivalents of 0.2 million for the three months ended March 31, 2023 and 2022, respectively.

8. Fair Value of Financial Assets and Liabilities

Fair Value Measurements
Accounting guidance for fair value measurements and disclosures provides a hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value.
•Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are actively traded instruments with observable actual trading prices.
•Level 2 — Pricing inputs are other than actual trading prices in active markets but are either directly or indirectly observable as of the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts or priced with models using highly observable inputs.
•Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 include those valued with models requiring significant judgment or estimation.
Specific valuation methods include:
Investments in equity securities and other funds — Equity securities are valued using quoted prices in active markets. The fair values for commingled funds are measured using NAVs. The investments in commingled funds may be redeemed for NAV with proper notice. Private equity commingled funds require approval of the fund for any unscheduled redemption, and such redemptions may be approved or denied by the fund at its sole discretion. Unscheduled distributions from real estate commingled funds may be redeemed with proper notice, however, withdrawals may be delayed or discounted as a result of fund illiquidity.
Investments in debt securities — Fair values for debt securities are determined by a third party pricing service using recent trades and observable spreads from benchmark interest rates for similar securities.
Interest rate derivatives — Fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.
Commodity Derivatives — Methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2 classification. When contracts relate to inactive delivery locations or extend to periods beyond those readily observable on active exchanges, the significance of the use of less observable inputs on a valuation is evaluated and may result in Level 3 classification.
Electric commodity derivatives held by NSP-Minnesota and SPS include transmission congestion instruments, generally referred to as FTRs. FTRs purchased from an RTO are financial instruments that entitle or obligate the holder to monthly revenues or charges based on transmission congestion across a given transmission path.
The values of these instruments are derived from, and designed to offset, the costs of transmission congestion. In addition to overall transmission load, congestion is also influenced by the operating schedules of power plants and the consumption of electricity pertinent to a given transmission path. Unplanned plant outages, scheduled plant maintenance, changes in the relative costs of fuels used in generation, weather and overall changes in demand for electricity can each impact the operating schedules of the power plants on the transmission grid and the value of these instruments.
FTRs are recognized at fair value and adjusted each period prior to settlement. Given the limited observability of certain variables underlying the reported auction values of FTRs, these fair value measurements have been assigned a Level 3 classification.
Net congestion costs, including the impact of FTR settlements, are shared through fuel and purchased energy cost recovery mechanisms. As such, the fair value of the unsettled instruments (i.e., derivative asset or liability) is offset/deferred as a regulatory asset or liability.
Non-Derivative Fair Value Measurements
Nuclear Decommissioning Fund
The NRC requires NSP-Minnesota to maintain a portfolio of investments to fund the costs of decommissioning its nuclear generating plants. Assets of the nuclear decommissioning fund are legally restricted for the purpose of decommissioning these facilities. The fund contains cash equivalents, debt securities, equity securities and other investments. NSP-Minnesota uses the MPUC approved asset allocation for the investment targets by asset class for the qualified trust.
NSP-Minnesota recognizes the costs of funding the decommissioning over the lives of the nuclear plants, assuming rate recovery of all costs. Realized and unrealized gains on fund investments over the life of the fund are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs. Consequently, any realized and unrealized gains and losses on securities in the nuclear decommissioning fund are deferred as a component of the regulatory asset.
Unrealized gains for the nuclear decommissioning fund were $1 billion as of March 31, 2023 and Dec. 31, 2022, and unrealized losses were $61 million and $90 million as of March 31, 2023 and Dec. 31, 2022, respectively.
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Non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund:

|  | March 31, 2023
|  |  |  | Fair Value
(Millions of Dollars) |  | Cost |  | Level 1 |  | Level 2 |  | Level 3 |  | NAV |  | Total
Nuclear decommissioning fund (a)
Cash equivalents |  | $ | 44 |  |  | $ | 44 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 44 |
Commingled funds |  | 743 |  |  | — |  |  | — |  |  | — |  |  | 1,076 |  |  | 1,076 |
Debt securities |  | 751 |  |  | — |  |  | 707 |  |  | 7 |  |  | — |  |  | 714 |
Equity securities |  | 507 |  |  | 1,172 |  |  | 2 |  |  | — |  |  | — |  |  | 1,174 |
Total |  | $ | 2,045 |  |  | $ | 1,216 |  |  | $ | 709 |  |  | $ | 7 |  |  | $ | 1,076 |  |  | $ | 3,008 |

(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $228 million of equity method investments and $137 million of rabbi trust assets and other miscellaneous investments.

|  | Dec. 31, 2022
|  |  |  | Fair Value
(Millions of Dollars) |  | Cost |  | Level 1 |  | Level 2 |  | Level 3 |  | NAV |  | Total
Nuclear decommissioning fund (a)
Cash equivalents |  | $ | 29 |  |  | $ | 29 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 29 |
Commingled funds |  | 803 |  |  | — |  |  | — |  |  | — |  |  | 1,178 |  |  | 1,178 |
Debt securities |  | 738 |  |  | — |  |  | 669 |  |  | 6 |  |  | — |  |  | 675 |
Equity securities |  | 406 |  |  | 999 |  |  | 1 |  |  | — |  |  | — |  |  | 1,000 |
Total |  | $ | 1,976 |  |  | $ | 1,028 |  |  | $ | 670 |  |  | $ | 6 |  |  | $ | 1,178 |  |  | $ | 2,882 |

(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $219 million of equity investments in unconsolidated subsidiaries and $133 million of rabbi trust assets and other miscellaneous investments.
For the three months ended March 31, 2023 and 2022, there were immaterial Level 3 nuclear decommissioning fund investments or transfer of amounts between levels.
Contractual maturity dates of debt securities in the nuclear decommissioning fund as of March 31, 2023:

|  | 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 |  | $ | 1 |  |  | $ | 220 |  |  | $ | 254 |  |  | $ | 239 |  |  | $ | 714 |

Rabbi Trusts
Xcel Energy has established rabbi trusts to provide partial funding for future distributions of a deferred compensation plan. The fair value of assets held in the rabbi trusts were $82 million and $80 million at March 31, 2023 and Dec. 31, 2022, respectively, comprised of cash equivalents and mutual funds (level 1 valuation methods). Amounts are reported in nuclear decommissioning fund and other investments on the consolidated balance sheet.
Derivative Activities and Fair Value Measurements
Xcel Energy enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to manage risk in connection with changes in interest rates, and utility commodity prices.
Interest Rate Derivatives — Xcel Energy enters into contracts that effectively fix the interest rate on a specified principal amount of a hypothetical future debt issuance. These financial swaps net settle based on changes in a specified benchmark interest rate, acting as a hedge of changes in market interest rates that will impact specified anticipated debt issuances. These derivative instruments are designated as cash flow hedges for accounting purposes, with changes in fair value prior to occurrence of the hedged transactions recorded as other comprehensive income.
As of March 31, 2023, accumulated other comprehensive loss related to interest rate derivatives included $2 million of net losses expected to be reclassified into earnings during the next 12 months as the hedged transactions impact earnings. As of March 31, 2023, Xcel Energy had unsettled interest swaps outstanding with a notional amount of $495 million.
See Note 11 for the financial impact of qualifying interest rate cash flow hedges on Xcel Energy’s accumulated other comprehensive loss included in the consolidated statements of common stockholder’s equity and in the consolidated statements of comprehensive income.
Wholesale and Commodity Trading — Xcel Energy Inc.’s utility subsidiaries conduct various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. Xcel Energy is allowed to conduct these activities within guidelines and limitations as approved by its risk management committee, comprised of management personnel not directly involved in the activities governed by this policy.
Results of derivative instrument transactions entered into for trading purposes are presented in the consolidated statements of income as electric revenues, net of any sharing with customers. These activities are not intended to mitigate commodity price risk associated with regulated electric and natural gas operations. Sharing of these margins is determined through state regulatory proceedings as well as the operation of the FERC-approved joint operating agreement.
Commodity Derivatives — Xcel Energy enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric and natural gas operations. This could include the purchase or sale of energy or energy-related products, natural gas to generate electric energy, natural gas for resale and FTRs.
The most significant derivative positions outstanding at March 31, 2023 and Dec. 31, 2022 for this purpose relate to FTR instruments administered by MISO and SPP. These instruments are intended to offset the impacts of transmission system congestion.
When Xcel Energy enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers, the instruments are not typically designated as qualifying hedging transactions. The classification of unrealized losses or gains on these instruments as a regulatory asset or liability, if applicable, is based on approved regulatory recovery mechanisms.
As of March 31, 2023, Xcel Energy had no commodity contracts designated as cash flow hedges.
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Gross notional amounts of commodity forwards, options and FTRs:

(Amounts in Millions) (a)(b) |  | March 31, 2023 |  | Dec. 31, 2022
Megawatt hours of electricity |  | 41 |  |  | 61 |
Million British thermal units of natural gas |  | 117 |  |  | 131 |

(a)Not reflective of net positions in the underlying commodities.
(b)Notional amounts for options included on a gross basis but weighted for the probability of exercise.
Consideration of Credit Risk and Concentrations — Xcel Energy continuously monitors the creditworthiness of counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Impact of credit risk was immaterial to the fair value of unsettled commodity derivatives presented on the consolidated balance sheets.
Xcel Energy’s utility subsidiaries’ most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to their wholesale, trading and non-trading commodity activities.
As of March 31, 2023, four of Xcel Energy’s ten most significant counterparties for these activities, comprising $60 million, or 32%, of this credit exposure, had investment grade credit ratings from S&P Global Ratings, Moody’s Investor Services or Fitch Ratings.
Three of the ten most significant counterparties, comprising $54 million, or 28%, of this credit exposure, were not rated by these external ratings agencies, but based on Xcel Energy’s internal analysis, had credit quality consistent with investment grade.
Three of these significant counterparties, comprising $77 million, or 40%, of this credit exposure, had credit quality less than investment grade, based on internal analysis. Six of these significant counterparties are municipal or cooperative electric entities, RTOs or other utilities.
Credit Related Contingent Features — Contract provisions for derivative instruments that the utility subsidiaries enter, including those accounted for as normal purchase and normal sale contracts and therefore not reflected on the consolidated balance sheets, may require the posting of collateral or settlement of the contracts for various reasons, including if the applicable utility subsidiary’s credit ratings are downgraded below its investment grade credit rating by any of the major credit rating agencies.
As of March 31, 2023 and Dec. 31, 2022, there were $8 million and $4 million, respectively, of derivative liabilities with such underlying contract provisions, respectively.
Certain contracts also contain cross default provisions that may require the posting of collateral or settlement of the contracts if there was a failure under other financing arrangements related to payment terms or other covenants.
As of March 31, 2023 and Dec. 31, 2022, there were approximately $84 million and $76 million of derivative liabilities with such underlying contract provisions, respectively.
Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that a given utility subsidiary’s ability to fulfill its contractual obligations is reasonably expected to be impaired.
Xcel Energy had no collateral posted related to adequate assurance clauses in derivative contracts as of March 31, 2023 and Dec. 31, 2022.
Recurring Derivative Fair Value Measurements
Impact of derivative activity:

|  | Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:
(Millions of Dollars) |  | Accumulated Other Comprehensive Loss |  | Regulatory Assets and Liabilities
Three Months Ended March 31, 2023 |  |  |  |
Derivatives designated as cash flow hedges: |  |
Interest rate |  | $ | (7) |  |  | $ | — |
Total |  | $ | (7) |  |  | $ | — |
Other derivative instruments: |  |  |  |
Electric commodity |  | $ | — |  |  | $ | (92) |
Natural gas commodity |  | — |  |  | 3 |
Total |  | $ | — |  |  | $ | (89) |
Three Months Ended March 31, 2022 |  |  |  |
Derivatives designated as cash flow hedges: |  |
Interest rate |  | $ | 6 |  |  | $ | — |
Total |  | $ | 6 |  |  | $ | — |
Other derivative instruments: |  |  |  |
Electric commodity |  | $ | — |  |  | $ | 1 |
Natural gas commodity |  | — |  |  | 4 |
Total |  | $ | — |  |  | $ | 5 |

|  | 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 |
Three Months Ended March 31, 2023 |  |  |  |  |
Derivatives designated as cash flow hedges:
Interest rate |  | $ | 1 |  | (a) | $ | — |  |  | $ | — |  |
Total |  | $ | 1 |  |  | $ | — |  |  | $ | — |  |
Other derivative instruments: |  |  |  |  |
Commodity trading |  | $ | — |  |  | $ | — |  |  | $ | (1) |  | (b)
Electric commodity |  | — |  |  | 82 |  | (c) | — |  |
Natural gas commodity |  | — |  |  | 9 |  | (d) | (19) |  | (d)(e)
Total |  | $ | — |  |  | $ | 91 |  |  | $ | (20) |  |
Three Months Ended March 31, 2022 |  |  |  |  |
Derivatives designated as cash flow hedges:
Interest rate |  | $ | 2 |  | (a) | $ | — |  |  | $ | — |  |
Total |  | $ | 2 |  |  | $ | — |  |  | $ | — |  |
Other derivative instruments:
Commodity trading |  | $ | — |  |  | $ | — |  |  | $ | 2 |  | (b)
Electric commodity |  | — |  |  | (13) |  | (c) | — |  |
Natural gas commodity |  | — |  |  | 3 |  | (d) | (17) |  | (d)(e)
Total |  | $ | — |  |  | $ | (10) |  |  | $ | (15) |  |

(a)Recorded to interest charges.
(b)Recorded to electric revenues. Presented amounts do not reflect non-derivative transactions or margin sharing with customers.
(c)Recorded to 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. FTR settlements are shared with customers and do not have a material impact on net income. Presented amounts reflect changes in fair value between auction and settlement dates, but exclude the original auction fair value.
(d)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.
(e)Relates primarily to option premium amortization.
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Xcel Energy had no derivative instruments designated as fair value hedges during the three months ended March 31, 2023 and 2022.
Derivative assets and liabilities measured at fair value on a recurring basis were as follows:

|  | March 31, 2023 |  | Dec. 31, 2022
|  | Fair Value |  | Fair Value Total |  | Netting (a) |  | Total |  | Fair Value |  | Fair Value Total |  | Netting (a) |  | Total
(Millions of Dollars) |  | Level 1 |  | Level 2 |  | Level 3 |  |  |  |  | Level 1 |  | Level 2 |  | Level 3 |  |  |
Current derivative assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Other derivative instruments: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity trading |  | $ | 11 |  |  | $ | 152 |  |  | $ | 21 |  |  | $ | 184 |  |  | $ | (124) |  |  | $ | 60 |  |  | $ | 32 |  |  | $ | 259 |  |  | $ | 33 |  |  | $ | 324 |  |  | $ | (242) |  |  | $ | 82 |
Electric commodity |  | — |  |  | — |  |  | 34 |  |  | 34 |  |  | — |  |  | 34 |  |  | — |  |  | — |  |  | 177 |  |  | 177 |  |  | (2) |  |  | 175 |
Natural gas commodity |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 19 |  |  | — |  |  | 19 |  |  | — |  |  | 19 |
Total current derivative assets |  | $ | 11 |  |  | $ | 152 |  |  | $ | 55 |  |  | $ | 218 |  |  | $ | (124) |  |  | 94 |  |  | $ | 32 |  |  | $ | 278 |  |  | $ | 210 |  |  | $ | 520 |  |  | $ | (244) |  |  | 276 |
PPAs (b) |  |  |  |  |  |  |  |  |  |  |  | 3 |  |  |  |  |  |  |  |  |  |  |  |  | 3 |
Current derivative instruments |  |  |  |  |  |  |  |  |  |  |  | $ | 97 |  |  |  |  |  |  |  |  |  |  |  |  | $ | 279 |
Noncurrent derivative assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Other derivative instruments: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity trading |  | $ | 24 |  |  | $ | 62 |  |  | $ | 78 |  |  | $ | 164 |  |  | $ | (69) |  |  | $ | 95 |  |  | $ | 34 |  |  | $ | 71 |  |  | $ | 74 |  |  | $ | 179 |  |  | $ | (89) |  |  | $ | 90 |
Total noncurrent derivative assets |  | $ | 24 |  |  | $ | 62 |  |  | $ | 78 |  |  | $ | 164 |  |  | $ | (69) |  |  | 95 |  |  | $ | 34 |  |  | $ | 71 |  |  | $ | 74 |  |  | $ | 179 |  |  | $ | (89) |  |  | 90 |
PPAs (b) |  |  |  |  |  |  |  |  |  |  |  | 2 |  |  |  |  |  |  |  |  |  |  |  |  | 3 |
Noncurrent derivative instruments |  |  |  |  |  |  |  |  |  |  |  | $ | 97 |  |  |  |  |  |  |  |  |  |  |  |  | $ | 93 |

|  | March 31, 2023 |  | Dec. 31, 2022
|  | Fair Value |  | Fair Value Total |  | Netting (a) |  | Total |  | Fair Value |  | Fair Value Total |  | Netting (a) |  | Total
(Millions of Dollars) |  | Level 1 |  | Level 2 |  | Level 3 |  |  |  |  | Level 1 |  | Level 2 |  | Level 3 |  |  |
Current derivative liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Derivatives designated as cash flow hedges: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Interest rate |  | $ | — |  |  | $ | 6 |  |  | $ | — |  |  | $ | 6 |  |  | $ | — |  |  | $ | 6 |  |  | $ | — |  |  | $ | 1 |  |  | $ | — |  |  | $ | 1 |  |  | $ | — |  |  | $ | 1 |
Other derivative instruments: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity trading |  | $ | 9 |  |  | $ | 180 |  |  | $ | 4 |  |  | $ | 193 |  |  | $ | (153) |  |  | $ | 40 |  |  | $ | 29 |  |  | $ | 297 |  |  | $ | 6 |  |  | $ | 332 |  |  | $ | (287) |  |  | $ | 45 |
Electric commodity |  | — |  |  | — |  |  | 1 |  |  | 1 |  |  | (1) |  |  | — |  |  | — |  |  | — |  |  | 2 |  |  | 2 |  |  | (2) |  |  | — |
Natural gas commodity |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 13 |  |  | — |  |  | 13 |  |  | — |  |  | 13 |
Total current derivative liabilities |  | $ | 9 |  |  | $ | 186 |  |  | $ | 5 |  |  | $ | 200 |  |  | $ | (154) |  |  | 46 |  |  | $ | 29 |  |  | $ | 311 |  |  | $ | 8 |  |  | $ | 348 |  |  | $ | (289) |  |  | 59 |
PPAs (b) |  |  |  |  |  |  |  |  |  |  |  | 16 |  |  |  |  |  |  |  |  |  |  |  |  | 17 |
Current derivative instruments |  |  |  |  |  |  |  |  |  |  |  | $ | 62 |  |  |  |  |  |  |  |  |  |  |  |  | $ | 76 |
Noncurrent derivative liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Other derivative instruments: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity trading |  | $ | 30 |  |  | $ | 77 |  |  | $ | 50 |  |  | $ | 157 |  |  | $ | (69) |  |  | $ | 88 |  |  | $ | 43 |  |  | $ | 97 |  |  | $ | 41 |  |  | $ | 181 |  |  | $ | (98) |  |  | $ | 83 |
Total noncurrent derivative liabilities |  | $ | 30 |  |  | $ | 77 |  |  | $ | 50 |  |  | $ | 157 |  |  | $ | (69) |  |  | 88 |  |  | $ | 43 |  |  | $ | 97 |  |  | $ | 41 |  |  | $ | 181 |  |  | $ | (98) |  |  | 83 |
PPAs (b) |  |  |  |  |  |  |  |  |  |  |  | 28 |  |  |  |  |  |  |  |  |  |  |  |  | 30 |
Noncurrent derivative instruments |  |  |  |  |  |  |  |  |  |  |  | $ | 116 |  |  |  |  |  |  |  |  |  |  |  |  | $ | 113 |

(a)Xcel Energy nets derivative instruments and related collateral on its consolidated balance sheets when supported by a legally enforceable master netting agreement. At March 31, 2023 and Dec. 31, 2022, derivative assets and liabilities include no obligations to return cash collateral. At March 31, 2023 and Dec. 31, 2022, derivative assets and liabilities include rights to reclaim cash collateral of $29 million and $53 million, respectively. Counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.
(b)Xcel Energy currently applies the normal purchase exception to qualifying PPAs. Balance relates to specific contracts that were previously recognized at fair value prior to applying the normal purchase exception, and are being amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.
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Changes in Level 3 commodity derivatives:

|  | Three Months Ended March 31
(Millions of Dollars) |  | 2023 |  | 2022
Balance at Jan. 1 |  | $ | 235 |  |  | $ | 19 |
Purchases (a) |  | 6 |  |  | 5 |
Settlements (a) |  | (29) |  |  | (50) |
Net transactions recorded during the period: |  |  |  |
(Losses) gains recognized in earnings (b) |  | (13) |  |  | 42 |
Net (losses) gains recognized as regulatory assets and liabilities (a) |  | (121) |  |  | 24 |
Balance at March 31 |  | $ | 78 |  |  | $ | 40 |

(a)Relates primarily to NSP-Minnesota and SPS FTR instruments administered by MISO and SPP.
(b)Relates to commodity trading and is subject to substantial offsetting losses and gains on derivative instruments categorized as levels 1 and 2 in the income statement. See above tables for the income statement impact of derivative activity, including commodity trading gains and losses.
Fair Value of Long-Term Debt
As of March 31, 2023, other financial instruments for which the carrying amount did not equal fair value:

|  | March 31, 2023 |  | Dec. 31, 2022
(Millions of Dollars) |  | Carrying Amount |  | Fair Value |  | Carrying Amount |  | Fair Value
Long-term debt, including current portion |  | $ | 23,719 |  |  | $ | 21,167 |  |  | $ | 23,964 |  |  | $ | 20,897 |

Fair value of Xcel Energy’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. Fair value estimates are based on information available to management as of March 31, 2023 and Dec. 31, 2022, and given the observability of the inputs, fair values presented for long-term debt were assigned as Level 2.

9. Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost

|  | Three Months Ended March 31
|  | 2023 |  | 2022 |  | 2023 |  | 2022
(Millions of Dollars) |  | Pension Benefits |  | Postretirement Health Care Benefits
Service cost |  | $ | 18 |  |  | $ | 24 |  |  | $ | — |  |  | $ | — |
Interest cost (a) |  | 40 |  |  | 27 |  |  | 5 |  |  | 4 |
Expected return on plan assets (a) |  | (52) |  |  | (52) |  |  | (4) |  |  | (4) |
Amortization of prior service credit (a) |  | — |  |  | — |  |  | — |  |  | (2) |
Amortization of net loss (a) |  | 5 |  |  | 19 |  |  | 1 |  |  | 1 |
Settlement charge (b) |  | — |  |  | (1) |  |  | — |  |  | — |
Net periodic benefit cost (credit) |  | 11 |  |  | 17 |  |  | 2 |  |  | (1) |
Effects of regulation |  | 5 |  |  | 5 |  |  | — |  |  | 1 |
Net benefit cost recognized for financial reporting |  | $ | 16 |  |  | $ | 22 |  |  | $ | 2 |  |  | $ | — |

(a)The components of net periodic cost other than the service cost component are included in the line item “Other income, net” in the consolidated statements of income or capitalized on the consolidated balance sheets as a regulatory asset.
(b)In the first quarter of 2022, Xcel Energy recognized $1 million in settlement charge true-ups related to the fourth quarter of 2021.
In January 2023, contributions totaling $50 million were made across Xcel Energy’s pension plans. Xcel Energy does not expect additional pension contributions during 2023.

10. Commitments and Contingencies

Legal
Xcel Energy is involved in various litigation matters in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for losses probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories.
In such cases, there is considerable uncertainty regarding the timing or ultimate resolution, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, would have a material effect on Xcel Energy’s consolidated financial statements. Legal fees are generally expensed as incurred.
Gas Trading Litigation — e prime is a wholly owned subsidiary of Xcel Energy. e prime was in the business of natural gas trading and marketing but has not engaged in natural gas trading or marketing activities since 2003. Multiple lawsuits involving multiple plaintiffs seeking monetary damages were commenced against e prime and its affiliates, including Xcel Energy, between 2003 and 2009 alleging fraud and anticompetitive activities in conspiring to restrain the trade of natural gas and manipulate natural gas prices. Cases were all consolidated in the U.S. District Court in Nevada.
One case remains active which includes a multi-district litigation matter consisting of a Wisconsin purported class (Arandell Corp.). The Court issued a ruling in June 2022 granting plaintiffs’ class certification. In April 2023, the Seventh Circuit Court of Appeals heard the defendants’ appeal challenging whether the district court properly assessed class certification. A decision relating to class certification is expected later this year. Xcel Energy considers the reasonably possible loss associated with this litigation to be immaterial.
Comanche Unit 3 Litigation — In 2021, CORE filed a lawsuit in Denver County District Court, alleging PSCo breached ownership agreement terms by failing to operate Comanche Unit 3 in accordance with prudent utility practices. In January 2022, the Court granted PSCo’s motion to dismiss CORE’s claims for unjust enrichment, declaratory judgment and damages for replacement power costs. In April 2022, CORE filed a supplement to include the January 2022 outage and damages related to this event. Also in 2022, CORE sent notice of withdrawal from the ownership agreement based on the same alleged breaches. In February 2023, CORE disclosed its expert witness, who estimated damages incurred of $270 million. Also in February 2023, the court granted PSCo’s motion precluding CORE from seeking damages related to its withdrawal as part of the lawsuit. PSCo continues to believe CORE's claims are without merit and disputes CORE’s right to withdraw.
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Rate Matters and Other
Xcel Energy’s operating subsidiaries are involved in various regulatory proceedings arising in the ordinary course of business. Until resolution, typically in the form of a rate order, uncertainties may exist regarding the ultimate rate treatment for certain activities and transactions. Amounts have been recognized for probable and reasonably estimable losses that may result. Unless otherwise disclosed, any reasonably possible range of loss in excess of any recognized amount is not expected to have a material effect on the consolidated financial statements.
Sherco — In 2018, NSP-Minnesota and SMMPA (Co-owner of Sherco Unit 3) reached a settlement with GE related to a 2011 incident, which damaged the turbine at Sherco Unit 3 and resulted in an extended outage for repair. NSP-Minnesota notified the MPUC of its proposal to refund settlement proceeds to customers through the fuel clause adjustment.
In March 2019, the MPUC approved NSP-Minnesota’s settlement refund proposal. Additionally, the MPUC decided to withhold any decision as to NSP-Minnesota’s prudence in connection with the incident at Sherco Unit 3 until after conclusion of an appeal pending between GE and NSP-Minnesota’s insurers. In February 2020, the Minnesota Court of Appeals affirmed the district court’s judgment in favor of GE. In March 2020, NSP-Minnesota’s insurers filed a petition seeking additional review by the Minnesota Supreme Court. In April 2020, the Minnesota Supreme Court denied the insurers’ petition for further review, ending the litigation.
In January 2021, the OAG and DOC recommended that NSP-Minnesota refund approximately $17 million of replacement power costs previously recovered through the fuel clause adjustment. NSP-Minnesota subsequently filed its response, asserting that it acted prudently in connection with the Sherco Unit 3 outage, the MPUC has previously disallowed $22 million of related costs and no additional refund or disallowance is appropriate.
In July 2022, the MPUC referred the matter to the Office of Administrative Hearings to conduct a contested case on the prudence of the replacement power costs incurred by NSP-Minnesota. A final decision by the MPUC is expected in mid-2024. A loss related to this matter is deemed remote.
MISO ROE Complaints — In November 2013 and February 2015, customer groups filed two ROE complaints against MISO TOs, which includes NSP-Minnesota and NSP-Wisconsin. The first complaint requested a reduction in base ROE transmission formula rates from 12.38% to 9.15% for the time period of Nov. 12, 2013 to Feb. 11, 2015, and removal of ROE adders (including those for RTO membership). The second complaint requested, for a subsequent time period, a base ROE reduction from 12.38% to 8.67%.
The FERC subsequently issued various related orders (including Opinion Nos. 569, 569A and 569B) related to ROE methodology/calculations and timing. NSP-Minnesota has processed refunds to customers for applicable complaint periods based on the ROE in the most recent applicable opinions.
The MISO TOs and various other parties have filed petitions for review of the FERC’s most recent applicable opinions at the D.C. Circuit. In August 2022, the D.C. Circuit ruled that FERC had not adequately supported its conclusions, vacated FERC’s related orders, and remanded the issue back to FERC for further proceedings, which remain pending. Additional exposure, if any related to this matter is expected to be immaterial.
SPP OATT Upgrade Costs — Costs of transmission upgrades may be recovered from other SPP customers whose transmission service depends on capacity enabled by the upgrade under the SPP OATT. SPP had not been charging its customers for these upgrades, even though the SPP OATT had allowed SPP to do so since 2008. In 2016, the FERC granted SPP’s request to recover these previously unbilled charges and SPP subsequently billed SPS approximately $13 million.
In 2018, SPS’ appeal to the D.C. Circuit over the FERC rulings granting SPP the right to recover previously unbilled charges was remanded to the FERC. In 2019, the FERC reversed its 2016 decision and ordered SPP to refund charges retroactively collected from its transmission customers, including SPS, related to periods before September 2015. In 2020, SPP and Oklahoma Gas & Electric separately filed petitions for review of the FERC’s orders at the D.C. Circuit. In 2021, the D.C. Circuit issued a decision denying these appeals and upholding the FERC’s orders. Refunds received by SPS are expected to be given back to SPS customers through future rates.
In 2017, SPS filed a separate related complaint asserting SPP assessed upgrade charges to SPS in violation of the SPP OATT. In 2018, the FERC issued an order denying the SPS complaint. SPS filed a request for rehearing in 2018. The FERC subsequently issued a tolling order granting a rehearing for further consideration. If SPS’ complaint results in additional charges or refunds, SPS will seek to recover or refund the amount through future SPS customer rates. In 2020, SPS filed a petition for review of the FERC’s 2018 orders at the D.C. Circuit. In February 2022, FERC issued an order rejecting SPS’ request for hearing. SPS has appealed that order. That appeal has been combined with SPS’ prior appeal.
Environmental
MGP, Landfill and Disposal Sites
Xcel Energy is investigating, remediating or performing post-closure actions at nine MGP, landfill or other disposal sites across its service territories, excluding sites that are being addressed under current coal ash regulations.
Xcel Energy has recognized its best estimate of costs/liabilities from final resolution of these issues, however, the outcome and timing are unknown. In addition, there may be insurance recovery and/or recovery from other potentially responsible parties, offsetting a portion of costs incurred.
Environmental Requirements — Water and Waste
Coal Ash Regulation — Xcel Energy’s operations are subject to federal and state regulations that impose requirements for handling, storage, treatment and disposal of solid waste. Under the CCR Rule, utilities are required to complete groundwater sampling around their applicable landfills and surface impoundments as well as perform corrective actions where offsite groundwater has been impacted.
As of March 31, 2023, Xcel Energy had eight regulated ash units in operation.
PSCo has executed an agreement with a third party that will excavate and process ash for beneficial use (at two sites) at a cost of approximately $45 million. An estimated liability has been recorded and amounts are expected to be fully recoverable through regulatory mechanisms.
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Investigation and feasibility studies for additional corrective action related to offsite groundwater are ongoing (at three Colorado sites). While the results are uncertain, additional costs are estimated to be at least $30 million. A liability has been recorded for the portion of these actions that are estimable/probable, and are expected to be fully recoverable through regulatory mechanisms.
Federal Clean Water Act Section 316(b) — The Federal Clean Water Act requires the EPA to regulate cooling water intake structures to assure they reflect the best technology available for minimizing impingement and entrainment of aquatic species.
Estimated capital expenditures of approximately $45 million may be required to comply with the requirements. Xcel Energy anticipates these costs will be recoverable through regulatory mechanisms.
Monticello Tritium — Monticello regularly monitors onsite tritium levels (a weak radioactive isotope that is a byproduct of plant operations) from releases in groundwater monitoring wells onsite. In late 2022, Xcel Energy detected a release of tritium to groundwater and reported the event to the NRC and the State of Minnesota. Xcel Energy has completed repairs, replaced the source of the release and is extracting the impacted groundwater. Xcel Energy anticipates costs to extract and contain the impacted groundwater from this release to be immaterial. The water is fully contained on-site and has not been detected in any drinking water. The release does not represent a risk to human health or the environment.
Environmental Requirements — Air
Regional Haze Rules — In 2016, the EPA adopted a final rule establishing a federal implementation plan for reasonable further progress under the regional haze program for the state of Texas. The rule imposes SO 2 emission limitations which would require the installation of dry scrubbers on Tolk Units 1 and 2; compliance would have been required by February 2021. SPS appealed the EPA’s decision and obtained a stay of the final rule.
In 2017, the EPA adopted a final BART rule for Texas. Under that rule, Harrington Units 1, 2, and 3 and Tolk Units 1 and 2 participate in intrastate SO 2 budget and trading program. The rule also implemented participation in a federal ozone season NOx budget and trading program, named the Cross State Air Pollution Rule. The EPA is reconsidering this rule and a proposal for reconsideration is anticipated in the second quarter of 2023.
Leases
Xcel Energy evaluates contracts that may contain leases, including PPAs and arrangements for the use of office space and other facilities, vehicles and equipment. A contract contains a lease if it conveys the exclusive right to control the use of a specific asset.
Components of lease expense:

|  | Three Months Ended March 31
(Millions of Dollars) |  | 2023 |  | 2022
Operating leases |  |  |  |
PPA capacity payments |  | $ | 60 |  |  | $ | 63 |
Other operating leases (a) |  | 12 |  |  | 13 |
Total operating lease expense (b) |  | $ | 72 |  |  | $ | 76 |
Finance leases |  |  |  |
Amortization of ROU assets |  | $ | 1 |  |  | $ | 1 |
Interest expense on lease liability |  | 4 |  |  | 4 |
Total finance lease expense |  | $ | 5 |  |  | $ | 5 |

(a)Includes short-term lease expense of $2 million and $1 million for 2023 and 2022, respectively.
(b)PPA capacity payments are included in electric fuel and purchased power on the consolidated statements of income. Expense for other operating leases is included in O&M expense and electric fuel and purchased power.
Commitments under operating and finance leases as of March 31, 2023:

(Millions of Dollars) |  | PPA Operating Leases |  | Other Operating Leases |  | Total Operating Leases |  | Finance Leases (a)
Total minimum obligation |  | $ | 1,223 |  |  | $ | 257 |  |  | $ | 1,480 |  |  | $ | 225 |
Interest component of obligation |  | (160) |  |  | (76) |  |  | (236) |  |  | (160) |
Present value of minimum obligation |  | $ | 1,063 |  |  | 181 |  |  | 1,244 |  |  | 65 |
Less current portion |  |  |  |  |  | (224) |  |  | (2) |
Noncurrent operating and finance lease liabilities |  |  |  |  |  | $ | 1,020 |  |  | $ | 63 |

(a)Excludes certain amounts related to Xcel Energy’s 50% ownership interest in WYCO.
Variable Interest Entities
Under certain PPAs, NSP-Minnesota, PSCo and SPS purchase power from IPPs for which the utility subsidiaries are required to reimburse fuel costs, or to participate in tolling arrangements under which the utility subsidiaries procure the natural gas required to produce the energy that they purchase. These specific PPAs create a variable interest in the IPP.
In addition, certain solar PPAs provide an option to purchase emission allowances or sharing provisions related to production credits generated by the solar facility under contract. These specific PPAs create a variable interest in the IPP.
Xcel Energy concluded that these entities are not required to be consolidated in its financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance.
The utility subsidiaries had approxi ma tely 4,053 MW an d 3,961 MW of capacity under long-term PPAs at March 31, 2023 and Dec. 31, 2022, respectively, with entities that have been determined to be variable interest entities. The PPAs have expiration dates through 2041.
Other
Guarantees and Bond Indemnifications — Xcel Energy provides guarantees and bond indemnities, which guarantee payment or performance. Xcel Energy Inc.’s exposure is based upon the net liability under the agreements. Most of the guarantees and bond indemnities issued by Xcel Energy have a stated maximum amount.
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As of March 31, 2023 and Dec. 31, 2022, Xcel Energy had no assets held as collateral related to their guarantees, bond indemnities and indemnification agreements. Guarantees and bond indemnities issued and outstanding for Xcel Energy were approximately $62 million at both March 31, 2023 and Dec. 31, 2022.
Other Indemnification Agreements — Xcel Energy provides indemnifications through various contracts. These are primarily indemnifications against adverse litigation outcomes in connection with underwriting agreements, as well as breaches of representations and warranties, including corporate existence, transaction authorization and income tax matters with respect to assets sold.
Xcel Energy’s obligations under these agreements may be limited in duration and amount. Maximum future payments under these indemnifications cannot be reasonably estimated.

11. Other Comprehensive Loss

Changes in accumulated other comprehensive loss, net of tax :

|  | Three Months Ended March 31, 2023 |  | Three Months Ended March 31, 2022
(Millions of Dollars) |  | Gains and Losses on Cash Flow Hedges |  | Defined Benefit Pension and Postretirement Items |  | Total |  | Gains and Losses on Cash Flow Hedges |  | Defined Benefit Pension and Postretirement Items |  | Total
Accumulated other comprehensive loss at Jan. 1 |  | $ | (54) |  |  | $ | (39) |  |  | $ | (93) |  |  | $ | (75) |  |  | $ | (48) |  |  | $ | (123) |
Other comprehensive (loss) gain before reclassifications |  | (5) |  |  | — |  |  | (5) |  |  | 5 |  |  | — |  |  | 5 |
Losses reclassified from net accumulated other comprehensive loss: |  |  |  |  |  |  |  |  |  |  |  |
Interest rate derivatives (a) |  | 1 |  |  | — |  |  | 1 |  |  | 1 |  |  | — |  |  | 1 |
Amortization of net actuarial loss (b) |  | — |  |  | — |  |  | — |  |  | — |  |  | 1 |  |  | 1 |
Net current period other comprehensive (loss) income |  | (4) |  |  | — |  |  | (4) |  |  | 6 |  |  | 1 |  |  | 7 |
Accumulated other comprehensive loss at March 31 |  | $ | (58) |  |  | $ | (39) |  |  | $ | (97) |  |  | $ | (69) |  |  | $ | (47) |  |  | $ | (116) |

(a)Included in interest charges.
(b)Included in the computation of net periodic pension and postretirement benefit costs.

12. Segment Information

Xcel Energy evaluates performance by each utility subsidiary based on profit or loss generated from the product or service provided including the regulated electric utility operating results of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS, as well as the regulated natural gas utility operating results of NSP-Minnesota, NSP-Wisconsin and PSCo.
These segments are managed separately because the revenue streams are dependent upon regulated rate recovery, which is separately determined for each segment.
Xcel Energy has the following reportable segments:
•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.
•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.
Xcel Energy also presents All Other, which includes operating segments with revenues below the necessary quantitative thresholds. Those operating segments primarily include steam revenue, appliance repair services, non-utility real estate activities, revenues associated with processing solid waste into refuse-derived fuel and investments in rental housing projects that qualify for low-income housing tax credits.
Xcel Energy had equity method investments of $228 million and $219 million as of March 31, 2023 and Dec. 31, 2022, respectively, included in the natural gas utility and all other segments.
Asset and capital expenditure information is not provided for Xcel Energy’s reportable segments. As an integrated electric and natural gas utility, Xcel Energy operates significant assets that are not dedicated to a specific business segment. Reporting assets and capital expenditures by business segment would require arbitrary and potentially misleading allocations, which may not necessarily reflect the assets that would be required for the operation of the business segments on a stand-alone basis.
Certain costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation allocators across each segment. In addition, a general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising.
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Xcel Energy’s segment information:

|  | Three Months Ended March 31
(Millions of Dollars) |  | 2023 |  | 2022
Regulated Electric |  |  |  |
Total revenues |  | $ | 2,763 |  |  | $ | 2,633 |
Net income |  | 296 |  |  | 278 |
Regulated Natural Gas |  |  |  |
Operating revenues |  | $ | 1,288 |  |  | $ | 1,090 |
Intersegment revenue |  | 1 |  |  | — |
Total revenues |  | $ | 1,289 |  |  | $ | 1,090 |
Net income |  | 159 |  |  | 130 |
All Other |  |  |  |
Total revenues |  | $ | 29 |  |  | $ | 28 |
Net loss |  | (37) |  |  | (28) |
Consolidated Total |  |  |  |
Total revenues |  | $ | 4,081 |  |  | $ | 3,751 |
Reconciling eliminations |  | (1) |  |  | — |
Total operating revenues |  | $ | 4,080 |  |  | $ | 3,751 |
Net income |  | 418 |  |  | 380 |

ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis by management focuses on those factors that had a material effect on Xcel Energy’s financial condition, results of operations and cash flows during the periods presented or are expected to have a material impact in the future. It should be read in conjunction with the accompanying unaudited consolidated financial statements and the related notes to consolidated financial statements. Due to the seasonality of Xcel Energy’s operating results, quarterly financial results are not an appropriate base from which to project annual results.
The demand for electric power and natural gas is affected by seasonal differences in the weather. In general, peak sales of electricity occur in the summer months, and peak sales of natural gas occur in the winter months. As a result, the overall operating results may fluctuate substantially on a seasonal basis. Additionally, Xcel Energy’s operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer.
Non-GAAP Financial Measures
The following discussion includes financial information prepared in accordance with GAAP, as well as certain non-GAAP financial measures such as ongoing earnings and ongoing diluted EPS. Generally, a non-GAAP financial measure is a measure of a company’s financial performance, financial position or cash flows that adjusts measures calculated and presented in accordance with GAAP. Xcel Energy’s management uses non-GAAP measures for financial planning and analysis, for reporting of results to the Board of Directors, in determining performance-based compensation, and communicating its earnings outlook to analysts and investors. Non-GAAP financial measures are intended to supplement investors’ understanding of our performance and should not be considered alternatives for financial measures presented in accordance with GAAP. These measures are discussed in more detail below and may not be comparable to other companies’ similarly titled non-GAAP financial measures.
Earnings Adjusted for Certain Items (Ongoing Earnings and Ongoing Diluted EPS)
GAAP diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock (i.e., common stock equivalents) were settled. The weighted average number of potentially dilutive shares outstanding used to calculate Xcel Energy Inc.’s diluted EPS is calculated using the treasury stock method.
Ongoing earnings reflect adjustments to GAAP earnings (net income) for certain items. Ongoing diluted EPS for Xcel Energy is calculated by dividing net income or loss, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period. Ongoing diluted EPS for each subsidiary is calculated by dividing the net income or loss for such subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period.
We use these non-GAAP financial measures to evaluate and provide details of Xcel Energy’s core earnings and underlying performance. We believe these measurements are useful to investors to evaluate the actual and projected financial performance and contribution of our subsidiaries. For the three months ended March 31, 2023 and 2022, there were no such adjustments to GAAP earnings and therefore GAAP earnings equal ongoing earnings for these periods.

Results of Operations

The only common equity securities that are publicly traded are common shares of Xcel Energy Inc. Diluted earnings and EPS of each subsidiary discussed below do not represent a direct legal interest in the assets and liabilities allocated to such subsidiary but rather represent a direct interest in our assets and liabilities as a whole.
Summarized diluted EPS for Xcel Energy:

|  |  |  | Three Months Ended March 31
Diluted Earnings (Loss) Per Share |  |  |  |  |  | 2023 |  | 2022
PSCo |  |  |  |  |  | $ | 0.39 |  |  | $ | 0.32 |
NSP-Minnesota |  |  |  |  |  | 0.25 |  |  | 0.23 |
SPS |  |  |  |  |  | 0.10 |  |  | 0.10 |
NSP-Wisconsin |  |  |  |  |  | 0.08 |  |  | 0.09 |
Earnings from equity method investments — WYCO |  |  |  |  |  | 0.01 |  |  | 0.01 |
Regulated utility (a) |  |  |  |  |  | 0.83 |  |  | 0.75 |
Xcel Energy Inc. and Other |  |  |  |  |  | (0.07) |  |  | (0.05) |
Total (a) |  |  |  |  |  | $ | 0.76 |  |  | $ | 0.70 |

(a) Amounts may not add due to rounding.
Summary of Earnings
Xcel Energy — Xcel Energy’s first quarter diluted earnings were $0.76 per share in 2023 compared with $0.70 per share in 2022. The increase was driven by recovery of electric and natural gas infrastructure investment, partially offset by higher depreciation, O&M expenses and interest charges. Fluctuations in electric and natural gas revenues associated with changes in fuel and purchased power and/or natural gas sold and transported generally do not significantly impact earnings (changes in costs are offset by the related variation in revenues).
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PSCo — Earnings increased $0.07 per share for the first quarter of 2023. The higher earnings primarily reflect the timing of recovery of electric and natural gas infrastructure investment and the impact of colder than normal weather, partially offset by increased depreciation, O&M expenses and interest charges. Incremental investment recovery was implemented for electric operations in April 2022 and natural gas operations in November 2022, resulting in higher revenues in the first quarter of 2023 compared to 2022. The year-over-year impact of these higher revenues is not expected to continue throughout the rest of the year. Earnings are not a result of higher natural gas prices as PSCo does not profit on fuel or power costs purchased for its customers.
NSP-Minnesota — Earnings increased $0.02 per share for the first quarter of 2023. The increase is primarily due to recovery of electric infrastructure investment, partially offset by increased O&M expenses and depreciation.
SPS — Earnings were flat for the first quarter of 2023. Recovery of electric infrastructure investment and strong sales growth were offset by higher depreciation and O&M expenses.
NSP-Wisconsin — Earnings decreased $0.01 per share for the first quarter of 2023. Recovery of electric and natural gas infrastructure investment were more than offset by impacts of warmer winter weather, higher depreciation and O&M expenses.
Xcel Energy Inc. and Other — Primarily includes financing costs at the holding company and earnings from Energy Impact Partners funds equity method investments. Earnings decreased $0.02 per share for the first quarter, largely attributable to higher interest charges.
Changes in GAAP and Ongoing Diluted EPS
Components significantly contributing to changes in 2023 EPS compared to 2022:

Diluted Earnings (Loss) Per Share |  |  |  | Three Months Ended March 31
GAAP and ongoing diluted EPS — 2022 |  |  |  | $ | 0.70 |
Components of change - 2023 vs. 2022 |  |  |  |
Higher electric revenues, net of electric fuel and purchased power |  |  |  | 0.15 |
Higher natural gas revenues, net of cost of natural gas sold and transported |  |  |  | 0.09 |
Lower effective tax rate (ETR) (a) |  |  |  | 0.02 |
Higher depreciation and amortization |  |  |  | (0.08) |
Higher O&M expenses |  |  |  | (0.06) |
Higher interest charges |  |  |  | (0.05) |
Higher taxes (other than income taxes) |  |  |  | (0.02) |
Other, net |  |  |  | 0.01 |
GAAP and ongoing diluted EPS — 2023 |  |  |  | $ | 0.76 |

(a)Includes PTCs and plant regulatory amounts, which are primarily offset as a reduction to electric revenues.
Statement of Income Analysis
The following summarizes the items that affected the individual revenue and expense items reported in the consolidated statements of income.
Estimated Impact of Temperature Changes on Regulated Earnings —Unusually hot summers or cold winters increase electric and natural gas sales, while mild weather reduces electric and natural gas sales. The estimated impact of weather on earnings is based on the number of customers, temperature variances, the amount of natural gas or electricity historically used per degree of temperature and excludes any incremental related operating expenses that could result due to storm activity or vegetation management requirements.
As a result, weather deviations from normal levels can affect Xcel Energy’s financial performance. However, decoupling mechanisms in Colorado and proposed decoupling mechanisms in Minnesota predominately mitigate the positive and adverse impacts of weather for the electric utility in those jurisdictions.
Degree-day or THI data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day’s average temperature and humidity. HDD is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit. CDD is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65° Fahrenheit.
Each degree of temperature above 65° Fahrenheit is counted as one CDD, and each degree of temperature below 65° Fahrenheit is counted as one HDD. In Xcel Energy’s more humid service territories, a THI is used in place of CDD, which adds a humidity factor to CDD. HDD, CDD and THI are most likely to impact the usage of Xcel Energy’s residential and commercial customers. Industrial customers are less sensitive to weather. Typically, sales are not impacted in the first or fourth quarter due to THI or CDD.
Normal weather conditions are defined as either the 10, 20 or 30 year average of actual historical weather conditions. The historical period of time used in the calculation of normal weather differs by jurisdiction, based on regulatory practice. To calculate the impact of weather on demand, a demand factor is applied to the weather impact on sales. Extreme weather variations, windchill and cloud cover may not be reflected in weather-normalized estimates.
Percentage increase (decrease) in normal and actual HDD:

|  |  | Three Months Ended March 31
|  |  |  |  |  |  | 2023 vs. Normal |  | 2022 vs. Normal |  | 2023 vs. 2022
HDD |  |  |  |  |  |  | 1.4 | % |  | 9.7 | % |  | (7.3) | %

Weather — Estimated impact of temperature variations on EPS compared with normal weather conditions:

|  |  | Three Months Ended March 31
|  |  |  |  |  |  | 2023 vs. Normal |  | 2022 vs. Normal |  | 2023 vs. 2022
Retail electric |  |  |  |  |  |  | $ | 0.002 |  |  | $ | 0.020 |  |  | $ | (0.018) |
Decoupling |  |  |  |  |  |  | (0.006) |  |  | (0.010) |  |  | 0.004 |
Electric total |  |  |  |  |  |  | $ | (0.004) |  |  | $ | 0.010 |  |  | $ | (0.014) |
Firm natural gas |  |  |  |  |  |  | 0.029 |  |  | 0.016 |  |  | 0.013 |
Total |  |  |  |  |  |  | $ | 0.025 |  |  | $ | 0.026 |  |  | $ | (0.001) |

Sales — Sales growth (decline) for actual and weather-normalized sales in 2023 compared to 2022:

|  | Three Months Ended March 31
|  | PSCo |  | NSP-Minnesota |  | SPS |  | NSP-Wisconsin |  | Xcel Energy
Actual |  |  |  |  |  |  |  |  |  |
Electric residential |  | 0.6 | % |  | (4.2) | % |  | (2.7) | % |  | (6.4) | % |  | (2.4) | %
Electric C&I |  | (1.2) |  |  | (1.8) |  |  | 7.3 |  |  | — |  |  | 1.0 |
Total retail electric sales |  | (0.6) |  |  | (2.6) |  |  | 5.3 |  |  | (2.0) |  |  | — |
Firm natural gas sales |  | 5.8 |  |  | (10.1) |  |  | N/A |  | (14.3) |  |  | (1.1) |

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|  | Three Months Ended March 31
|  | PSCo |  | NSP-Minnesota |  | SPS |  | NSP-Wisconsin |  | Xcel Energy
Weather-Normalized
Electric residential |  | (0.9) | % |  | (1.2) | % |  | 3.1 | % |  | (0.9) | % |  | (0.4) | %
Electric C&I |  | (1.4) |  |  | (1.3) |  |  | 7.2 |  |  | 0.6 |  |  | 1.1 |
Total retail electric sales |  | (1.3) |  |  | (1.3) |  |  | 6.3 |  |  | 0.2 |  |  | 0.6 |
Firm natural gas sales |  | (0.1) |  |  | (1.4) |  |  | N/A |  | (2.1) |  |  | (0.7) |

Weather-normalized electric sales growth (decline) — year-to-date
•PSCo — Residential sales declined due to decreased use per customer, partially offset by a 1.3% increase in customers. The C&I sales decline was attributable to decreased use per customer, primarily due to a two-month outage at a large manufacturing sector customer.
•NSP-Minnesota — Residential sales declined due to decreased use per customer, partially offset by a 1.0% increase in customers. The C&I sales decline was attributable to lower use per customer, primarily driven by declines in the educational, transportation and warehousing and retail trade sectors.
•SPS — Residential sales growth was primarily attributable to increased use per customer, in addition to a 0.8% increase in customers. C&I sales increased due to higher use per customer, primarily driven by the energy sector.
•NSP-Wisconsin — Residential sales declined due to decreased use per customer, primarily offset by a 0.7% increase in customers. C&I sales growth was primarily associated with customer growth, experienced primarily in the transportation and professional services sectors.
Weather-normalized natural gas sales growth (decline) — year-to-date
•Natural gas sales reflect a lower use per residential customer in all jurisdictions, partially offset by an increase in C&I use per customer in PSCo. In addition, residential and C&I customer growth was 1.2% and 0.7%, respectively.
Electric Margin
Electric margin is presented as electric revenues less electric fuel and purchased power expenses. Expenses incurred for electric fuel and purchased power are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues.
Electric revenues and fuel and purchased power expenses are impacted by fluctuations in the price of natural gas, coal and uranium. However, these price fluctuations generally have minimal earnings impact due to fuel recovery mechanisms. In addition, electric customers receive a credit for PTCs generated, which reduce electric revenue and income taxes.
Electric revenues, fuel and purchased power and margin:

|  |  |  | Three Months Ended March 31
(Millions of Dollars) |  |  |  |  |  | 2023 |  | 2022
Electric revenues |  |  |  |  |  | $ | 2,763 |  |  | $ | 2,633 |
Electric fuel and purchased power |  |  |  |  |  | (1,117) |  |  | (1,094) |
Electric margin |  |  |  |  |  | $ | 1,646 |  |  | $ | 1,539 |

(Millions of Dollars) |  |  |  | Three Months Ended March 31, 2023 vs. 2022
Regulatory rate outcomes (Minnesota, Colorado, Texas, New Mexico, South Dakota and Wisconsin) |  |  |  | $ | 88 |
Sales and demand (a) |  |  |  | 18 |
Wholesale transmission (net) |  |  |  | 17 |
Non-fuel riders |  |  |  | 15 |
Conservation and demand side management (offset in expense) |  |  |  | (17) |
PTCs flowed back to customers (offset by a lower ETR) |  |  |  | (12) |
Estimated impact of weather, net of decoupling |  |  |  | (10) |
Other (net) |  |  |  | 8 |
Total increase |  |  |  | $ | 107 |

(a)Sales excludes weather impact, net of decoupling in Colorado and proposed decoupling in Minnesota.
Natural Gas Margin
Natural gas margin is presented as natural gas revenues less the cost of natural gas sold and transported. Expenses incurred for the cost of natural gas sold are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues.
Natural gas expense varies with changing sales and the cost of natural gas. However, fluctuations in the cost of natural gas generally have minimal earnings impact due to cost recovery mechanisms.
Natural gas revenues, cost of natural gas sold and transported and margin:

|  |  |  | Three Months Ended March 31
(Millions of Dollars) |  |  |  |  |  | 2023 |  | 2022
Natural gas revenues |  |  |  |  |  | $ | 1,288 |  |  | $ | 1,090 |
Cost of natural gas sold and transported |  |  |  |  |  | (844) |  |  | (710) |
Natural gas margin |  |  |  |  |  | $ | 444 |  |  | $ | 380 |

(Millions of Dollars) |  |  |  | Three Months Ended March 31, 2023 vs. 2022
Regulatory rate outcomes (Colorado and Wisconsin) |  |  |  | $ | 47 |
Estimated impact of weather |  |  |  | 9 |
Infrastructure and integrity riders |  |  |  | 4 |
Other (net) |  |  |  | 4 |
Total increase |  |  |  | $ | 64 |

Non-Fuel Operating Expenses and Other Items
O&M Expenses — O&M expenses increased $48 million for the first quarter. Increase was primarily due to timing of recovery mechanisms, generation outages and emergent work; higher bad debt expenses; the impact of inflationary pressures, including labor increases, and investments in electric vehicle programs and other customer products.

Depreciation and Amortization — Depreciation and amortization increased $62 million for the first quarter, primarily driven by system expansion and the implementation of new depreciation rates in Colorado and Minnesota.
Interest Charges — Interest charges increased $39 million for the first quarter, largely due to higher interest rates and increased long-term debt levels to fund capital investments.
22

Public Utility Regulation and Other

The FERC and various state and local regulatory commissions regulate Xcel Energy Inc.’s utility subsidiaries and West Gas Interstate. Xcel Energy is subject to rate regulation by state utility regulatory agencies, which have jurisdiction with respect to the rates of electric and natural gas distribution companies in Minnesota, North Dakota, South Dakota, Wisconsin, Michigan, Colorado, New Mexico and Texas.
Rates are designed to recover plant investment, operating costs and an allowed return on investment. Our utility subsidiaries request changes in utility rates through commission filings. Changes in operating costs can affect Xcel Energy’s financial results, depending on the timing of rate cases and implementation of final rates. Other factors affecting rate filings are new investments, sales, conservation and demand side management efforts, and the cost of capital.
In addition, the regulatory commissions authorize the ROE, capital structure and depreciation rates in rate proceedings. Decisions by these regulators can significantly impact Xcel Energy’s results of operations.
Except to the extent noted below, the circumstances set forth in Public Utility Regulation included in Item 7 of Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2022 appropriately represent, in all material respects, the current status of public utility regulation and are incorporated herein by reference.
NSP-Minnesota
Pending and Recently Concluded Regulatory Proceedings
2022 Minnesota Electric Rate Case — In October 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC. The rate case is based on a requested ROE of 10.2%, a 52.5% equity ratio and forward test years.
In December 2021, the MPUC approved interim rates, subject to refund, of $247 million, effective Jan. 1, 2022. In November 2022, NSP-Minnesota revised its rate request to $498 million over three years.
On March 31, 2023, the ALJ’s report was issued. NSP-Minnesota estimates that the ALJ recommendation would result in a rate increase of approximately $386 million over three years from 2022-2024, based on a ROE of 9.87% and an equity ratio of 52.5%. In addition, it also reflects rate reductions associated with certain wind and nuclear generation life extensions and MISO capacity revenues and related tracker, as proposed in NSP-Minnesota’s revised rate request. A MPUC order is expected by June 30, 2023.
Proposed ALJ modifications to NSP-Minnesota’s request were as follows:

(Millions of Dollars) |  | 2022 |  | 2023 |  | 2024
NSP-Minnesota’s revised revenue request |  | $ | 234 |  |  | $ | 328 |  |  | $ | 498 |
ALJ recommended adjustments: |  |  |  |  |  |
PTC forecast |  | (28) |  |  | (2) |  |  | (1) |
Impact of ROE change |  | (27) |  |  | (29) |  |  | (30) |
O&M expenses |  | (15) |  |  | (17) |  |  | (18) |
Property tax |  | — |  |  | (11) |  |  | (23) |
Sherco 3 and A.S. King remaining life |  | — |  |  | — |  |  | (35) |
Other, net |  | 3 |  |  | (9) |  |  | (5) |
Total adjustments |  | (67) |  |  | (68) |  |  | (112) |
Total proposed revenue change |  | $ | 167 |  |  | $ | 260 |  |  | $ | 386 |

2022 Minnesota Natural Gas Rate Case — In November 2021, NSP-Minnesota filed a request with the MPUC for an annual natural gas rate increase of $36 million, or 6.6%. The filing is based on a 2022 forecast test year and includes a requested ROE of 10.5%, an equity ratio of 52.5% and a rate base of $934 million. In December 2021, the MPUC approved an interim rate increase of $25 million, subject to refund, effective Jan. 1, 2022.
In March 2023, the MPUC approved a settlement between NSP-Minnesota and various parties, which includes the following key terms:
•Base rate revenue increase of $21 million, with a true up to weather normalized actual sales for 2022.
•Revenue decoupling mechanism.
•Symmetrical property tax true-up.
•ROE of 9.57%.
•Equity ratio of 52.5%.
2022 South Dakota Electric Rate Case — In June 2022, NSP-Minnesota filed a South Dakota electric rate case (first since 2014) seeking a revenue increase of approximately $44 million. The filing was based on a 2021 historic test year adjusted for certain known and measurable changes for 2022 and 2023, a requested ROE of 10.75%, rate base of approximately $947 million and an equity ratio of 53%. A commission decision is expected later this year.
Wind Repowering — In January 2021, the MPUC approved NSP-Minnesota’s request for the repowering of 651 MW of owned wind projects. Two of the four repowering projects, where construction has not yet begun (in-service dates in 2025), now expect costs in excess of the original approval. While the capital costs have increased, the passage of the IRA and other changes result in a levelized cost of energy that is approximately 30% lower than the original approval.
In March 2023, the MPUC approved the revised projects.
2022 Upper Midwest RFP — In August 2022, NSP-Minnesota launched a RFP for 900 MW of solar or solar-plus-storage hybrid resources to come online by the end of 2025, including up to 300 MW of capacity to reuse the Sherco Unit 2 interconnection rights when the coal facility retires at the end of 2023.
NSP-Minnesota completed its bid evaluation process in December 2022 and will file for approval of selected projects in the second quarter of 2023.
2022 Minnesota Electric Vehicle Proposal — In August 2022, NSP-Minnesota filed a request with the MPUC for approval of approximately $320 million of capital investments (2022 through 2026) to support a public charging network, electric school bus pilot, and other expansions and modifications to its residential and commercial electric vehicle programs.
In February 2023, other parties to the contested proceeding filed their direct testimony ranging in levels of support/opposition to the proposals. In March 2023, the ALJ granted NSP-Minnesota’s request for a 60-day stay in the case so that the parties could pursue potential settlement. An evidentiary hearing has not been scheduled but is expected in June 2023. A MPUC decision is expected in late 2023.
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Nuclear Power Operations
NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the Prairie Island plant. See Note 12 to the consolidated financial statements of Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2022 for further information. The circumstances set forth in Nuclear Power Operations included in Item 7 of Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2022, appropriately represent, in all material respects, the current status of nuclear power operations, and are incorporated by reference.
NSP-Wisconsin
Upcoming Regulatory Proceedings
Wisconsin Rate Case — On April 28, 2023, NSP-Wisconsin expects to file a base rate filing with the PSCW seeking an electric increase of $40 million (an overall rate increase of 4.8%) and a natural gas increase of $9 million (an overall rate increase of 5.3%). The rate request is based on a 2024 forward-looking test year with a requested ROE of 10.25% and a 52.5% equity ratio. A final decision by the PSCW is expected late fourth quarter 2023.
PSCo
Pending and Recently Concluded Regulatory Proceedings
Colorado Electric Rate Case — In November 2022, PSCo filed an electric rate case seeking a net increase of $262 million, or 8.2%. The total request reflects a $312 million increase, which includes $50 million of authorized costs currently recovered through various rider mechanisms. The request is based on a 10.25% ROE, an equity ratio of 55.7% and a 2023 forecast test year with a 2023 year-end rate base of $11.3 billion. PSCo requested rates effective in September 2023.
Next steps in the procedural schedule are expected to be as follows:
•Answer testimony May 3, 2023.
•Rebuttal testimony: May 31, 2023.
•Settlement deadline: June 14, 2023.
•Hearing: July 6-21, 2023.
•Statement of position: Aug. 10, 2023.
A CPUC decision is expected in the third quarter of 2023.
Colorado Resource Plan — In August 2022, the CPUC approved an updated settlement, which will result in the further acceleration of the retirement of the Comanche Unit 3 coal plant, an expected carbon reduction of at least 85% and an 80% renewable mix by 2030. The CPUC deferred a decision on the method of cost recovery for the retiring coal units to a separate docket, which will consider accelerated depreciation, creation of regulatory assets and securitization. In April 2023, PSCo filed a coal cost recovery settlement with the CPUC that includes regulatory asset recovery of the remaining plant balances at retirement and a potential bundled securitization of the remaining coal plant book values including Comanche Unit 3 in 2031.
In December 2022, PSCo commenced the RFP process for generation resources with bids due in March 2023. After reviewing the bids received, PSCo will file a report with the CPUC with recommended resource acquisitions and a CPUC decision on the resources to be acquired is expected in November 2023.
Decoupling Filing — PSCo has a decoupling program, effective April 1, 2020 through Dec. 31, 2023. The program applies to Residential and metered small C&I customers who do not pay a demand charge. The program includes a refund and surcharge cap not to exceed 3% of forecasted base rate revenue for a specified period.
In October 2021, a settlement was reached on Winter Storm Uri costs and also addressed certain components of the 2020 decoupling refunds.
In April 2022, PSCo made its annual filing on this matter. In December 2022, the ALJ approved a settlement between PSCo, CPUC Staff and the UCA. In the first quarter of 2023, PSCo filed a petition for CPUC declaratory judgment to address the treatment of any expired balance under the 3% soft cap provisions. A decision is pending.
As of March 31, 2023, PSCo has recognized a refund for Residential customers and a surcharge for small C&I customers based on 2020, 2021, 2022 and the first quarter of 2023 results.
Transmission Cost Adjustment — In December 2022, the CPUC suspended PSCo’s request for 2023 TCA rate changes. The CPUC Staff protested the TCA on the grounds that only projects resulting in new transmission should be included and no repair or replacement of existing infrastructure should be included. The CPUC consolidated the matter with the pending electric rate case for assessment.
ECA Fuel Recovery — In December 2022, PSCo filed its first quarter 2023 ECA Advice Letter, which sought to recover $123 million of under-recovered 2022 fuel costs over two quarters (instead of one quarter, as more typical). In December 2022, the CPUC found that the $123 million should be removed from the proposed ECA rates, and required PSCo to file a separate application to recover these costs.
In February 2023, PSCo submitted an interim ECA filing which included $70 million of the 2022 under-recovered costs and collections commenced on March 1, 2023. The remaining $53 million of under-recovered costs consists of $25 million of ordinary fuel and purchased energy costs and $28 million costs attributable to coal curtailments resulting from rail transportation labor shortages. PSCo expects to make filings in the second quarter regarding the prudence of costs associated with coal curtailments, and to request that recovery of the remaining $25 million of ordinary fuel and purchased energy costs commence in the third quarter.
GCA NOPR — In June 2021, the CPUC issued a NOPR addressing the recovery of costs through the GCA. The CPUC has proposed a 2-step process aimed at 1) considering near term process changes to the GCA and 2) a longer-term process to evaluate potential performance incentive structures. In step 1, consensus proposed rule amendments to update the process and filing requirements for GCA and related filings have been submitted to the CPUC for consideration. PSCo worked with other utilities and stakeholders regarding consensus proposed rule amendments for step 2, including a provision that each LDC bring forward its own PIM in a future filing. In December 2022, the CPUC approved the consensus proposal. PSCo expects to file its proposed PIM in the second quarter of 2023.
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In February 2023, the Governor of Colorado issued an open letter to the CPUC, utilities and other stakeholders directing agencies to take additional steps to address energy costs. It is likely this request will result in the opening of additional dockets to further explore the GCA and other related mechanisms. Additionally, the Colorado Legislature formed a Joint Select Committee to investigate the source of rising utility rates and explore potential actions to prevent future price instability. Legislation has been introduced by members of the Joint Select Committee on a number of topics including natural gas and electric fuel incentive mechanisms, natural gas planning rules, regulatory filing requirements, and non-recovery of certain expenses (e.g., certain organizational or membership dues, tax penalties or fines).
Natural Gas Planning — In the first quarter of 2023, final rules were issued to implement recent state legislation requiring natural gas utilities to develop clean heat plans to meet state greenhouse gas emission reduction targets, as well as updated demand-side management criteria. Additionally, the rules included new comprehensive natural gas infrastructure planning requirements and Certificate of Public Convenience and Necessity application procedures, changes in natural gas line extension policy, and details on emission accounting related to clean heat plans.
Real-Time Energy Imbalance Market — In April 2023, PSCo joined the SPP Western Energy Imbalance Service market which balances generation and load regionally and in real time for participants in the Western Interconnection. PSCo’s participation in the SPP Western Energy Imbalance Service market replaces its joint dispatch agreement while extending the geographic area for which energy sales are made.
SPS
Pending and Recently Concluded Regulatory Proceedings
SPS — 2022 New Mexico Electric Rate Case — In November 2022, SPS filed an electric rate case with the NMPRC seeking a revenue increase of $78 million, or 10%. The request is based on a FTY ending June 30, 2024, a ROE of 10.75%, an equity ratio of 54.7% and rate base of $2.4 billion. Additionally, the request reflects further acceleration of the Tolk coal plant depreciation life from 2032 to 2028. In March 2023, the NMPRC issued an Order extending the suspension period by one month. Additionally, SPS filed a supplemental filing, which decreased the requested increase to $76 million.
On April 21, 2023, the following parties filed testimony: NMPRC Staff, OPL, AG, NMLCG, LES-FEA and Walmart, with all except Walmart providing a proposed revenue change.

(Millions of Dollars) |  | NMPRC Staff |  | OPL |  | AG |  | NMLCG |  | LES-FEA
SPS direct testimony |  | $ | 76 |  |  | $ | 76 |  |  | $ | 76 |  |  | $ | 76 |  |  | $ | 76 |
Recommended base rate adjustments:
Test year present revenues and allocators |  | (1) |  |  | 2 |  |  | (1) |  |  | 1 |  |  | (47) |
ROE (a) |  | (24) |  |  | (29) |  |  | (37) |  |  | (29) |  |  | (21) |
Capital structure |  | — |  |  | (22) |  |  | — |  |  | (22) |  |  | — |
Adjustment to FTY plant additions/rate base items |  | — |  |  | (4) |  |  | (10) |  |  | (5) |  |  | — |
Tolk Generating Station depreciation expense |  | — |  |  | (7) |  |  | — |  |  | (7) |  |  | (11) |
Other, net |  | (14) |  |  | (1) |  |  | (19) |  |  | (13) |  |  | — |
Total adjustments |  | (39) |  |  | (61) |  |  | (67) |  |  | (75) |  |  | (79) |
Total proposed revenue change |  | $ | 37 |  |  | $ | 15 |  |  | $ | 9 |  |  | $ | 1 |  |  | $ | (3) |

(a)AG recommends a reduction of $37 million reflecting its combined recommendation for ROE and capital structure.

Recommended Position |  | NMPRC Staff |  | OPL |  | AG |  | NMLCG |  | LES-FEA |  | Walmart
ROE |  | 9.35 | % |  | 8.70 | % |  | 9.00 | % |  | 8.70 | % |  | 9.40 | % |  | 9.61 | %
Equity Ratio |  | 54.70 |  |  | 45.00 |  |  | 50.57 |  |  | 45.00 |  |  | 54.70 |  |  | N/A

The next steps in the revised procedural schedule are as follows:
•Rebuttal testimony: May 10, 2023.
•Stipulation: May 17, 2023.
•Hearing: June 20, 2023.
•End of rate suspension: Oct. 19, 2023.
2023 Texas Electric Rate Case — In February 2023, SPS filed an electric rate case with the Public Utility Commission of Texas (PUCT) seeking an increase in base rate revenue of $149 million (13%). In March 2023, SPS updated the filing based on a historical test year period ended Dec. 31, 2022, which increased the rate revenue request to $158 million (14% impact to customer bills). The request is based on a ROE of 10.65%, an equity ratio of 54.6% and retail rate base of $3.6 billion. Additionally, the request reflects further acceleration of the Tolk coal plant depreciation life from 2034 to 2028. SPS is requesting a surcharge from July 13, 2023 through the effective date of new base rates.
Next steps in the procedural schedule are as follows:
•Intervenor direct testimony: August 4, 2023.
•Staff direct testimony: August 11, 2023.
•Rebuttal testimony: August 25, 2023.
•Hearings: Sept. 12-21, 2023.
•Proposed findings: Oct. 25, 2023.
A PUCT decision is expected in the first quarter of 2024.
SPS and LP&L Contract Termination — SPS and LP&L have a 25-year, 170 MW partial requirements contract. In May 2021, SPS and LP&L finalized a settlement which would terminate the contract upon LP&L’s move from the SPP to the Electric Reliability Council of Texas (expected in 2023). The settlement agreement requires LP&L to pay SPS $78 million (to the benefit of SPS’ remaining customers). LP&L would remain obligated to pay for SPP transmission charges associated with LP&L’s load in SPP. The agreement has received PUCT approval and is pending FERC approval.
2022 All-Source RFP — In 2022, SPS issued an RFP, which seeks up to 947 MW of new or existing capacity resources to provide replacement capacity for retiring units and meet SPS’ growing capacity needs through 2027. SPS has received bids and is currently reviewing the proposals. SPS will file for the approval of successful proposals in the third quarter of 2023.
Texas Fuel Reconciliation — In 2021, SPS filed to recover $88 million of Winter Storm Uri costs over 24 months, as part of the Texas fuel surcharge filing, with total under-recovered costs of $121 million. In April 2022, interim rates designed to recover $121 million over 30 months were approved, subject to PUCT approval through the triennial Fuel Reconciliation proceeding.
In November 2022, the ALJs found that costs were prudently incurred and recommended no disallowances. In March 2023, the PUCT issued a Final Order which fully adopted the recommended decision with no disallowances of costs.
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Other
Supply Chain
Xcel Energy’s ability to meet customer energy requirements, respond to storm-related disruptions and execute our capital expenditure program are dependent on maintaining an efficient supply chain. Manufacturing processes have experienced disruptions related to scarcity of certain raw materials and interruptions in production and shipping. These disruptions have been further exacerbated by inflationary pressures, labor shortages and the impact of international conflicts/issues. Xcel Energy continues to monitor the situation as it remains fluid and seeks to mitigate the impacts by securing alternative suppliers, modifying design standards, and adjusting the timing of work.
Electric Meters and Transformers
Supply chain issues associated with semi-conductors have delayed the availability of advanced infrastructure meters, which led to a reduced number of meters deployed in 2022. While we have seen improvements in the 2023 deployment plan, the supply chain challenges persist. Full 2023 impacts and mitigation plans are currently being evaluated.
Additionally, the availability of certain transformers is an industry-wide issue that has significantly impacted and in some cases may result in delays in projects and new customer connections. Proposed governmental actions related to transformer efficiency standards may compound these delays in the future. Xcel Energy continues to seek alternative suppliers and prioritize work plans to mitigate impacts of supply constraints.
Solar Resources
In April 2022, the U.S. Department of Commerce initiated an anti-circumvention investigation that would subject CSPV solar panels and cells imported from Malaysia, Vietnam, Thailand, and Cambodia with potential incremental tariffs ranging from 50% to 250%. These countries account for more than 80% of CSPV panel imports.
An interim stay on tariffs has been issued and many significant solar projects have resumed with modified costs and projected in-service dates, including the Sherco Solar facility in Minnesota and certain PPAs in PSCo. Further policy action, a change in the interim stay of tariffs, or other restrictions on solar imports (i.e., as a result of implementation of the Uyghur Forced Labor Protection Act) could impact project timelines and costs.
Marshall Wildfire
In December 2021, a wildfire ignited in Boulder County, Colorado (the “Marshall Fire”), which burned over 6,000 acres and destroyed or damaged over 1,000 structures. Boulder County authorities are currently investigating the fire and have not yet determined a cause. There were no downed power lines in the ignition area, and nothing PSCo has seen to this point indicates that our equipment or operations caused the fire.
In Colorado, the standard of review governing liability differs from the “inverse condemnation” or strict liability standard utilized in California. In Colorado, courts look to whether electric power companies have operated their system with a heightened duty of care consistent with the practical conduct of its business, and liability does not extend to occurrences that cannot be reasonably anticipated. In addition, PSCo has been operating under a commission approved wildfire mitigation plan and carries wildfire liability insurance.
In March 2022, a class action suit was filed in Boulder County pertaining to the Marshall Fire. In the remote event Xcel Energy Inc. or PSCo was found liable related to this litigation and were required to pay damages, such amounts could exceed our insurance coverage and have a material adverse effect on our financial condition, results of operations or cash flows. In December 2022, the District Court judge denied our Motion to Dismiss. An evidentiary hearing regarding our request to dismiss Xcel Energy, Inc. from the suit is scheduled for May 2023.
MISO Capacity Credits — The NSP System offered 1,500 MW of excess capacity into the MISO planning resource auction for June 2022 through May 2023. Due to a projected overall capacity shortfall in the MISO region, the 1,500 MWs offered cleared the auction at maximum pricing and is expected to generate revenues of approximately $90 million in 2022 and approximately $60 million in 2023. During the three months ended March 31, 2023, the NSP System received approximately $40 million of capacity credits. These amounts will primarily be used to mitigate customer rate increases or returned through earnings sharing or other mechanisms.

Environmental

Clean Air Act
NOx Allowance Allocations — In March 2023, after disapproving state implementation plans, the EPA released a prepublication version of the final regulations under the "Good Neighbor" provisions of the Clean Air Act. The final rule applies to generation facilities in Minnesota, Texas and Wisconsin, as well as other states outside of our service territory. The rule establishes an allowance trading program for NOx that will impact Xcel Energy fossil fuel-fired electric generating facilities in the states within our service territory. Applicable facilities will have to secure additional allowances, install NOx controls and/or develop a strategy of operations that utilizes the existing allowance allocations. Guidelines are also established for allowance banking and emission limit backstops.
While the financial impacts of the final rule are uncertain and dependent on market forces and anticipated generation, Xcel Energy anticipates the annual costs could be significant, but would be recoverable through regulatory mechanisms.
SPS and NSP-Minnesota have joined other impacted companies in litigation challenging the EPA’ disapproval of Texas and Minnesota state implementation plans.
GHG Emissions Limits — It is anticipated the EPA will propose rules to limit GHG emissions from new fossil fuel-fired electric generating units and natural gas-fired stationary combustion units under Clean Air Act Section 111(b) as well as emission guidelines under Clean Air Act Section 111(d) to limit GHG emissions from existing fossil fuel-fired electric generating units in 2023.
If any new rules require additional investment, Xcel Energy believes that the cost of these initiatives or replacement generation would be recoverable through rates based on prior state commission practices.
Coal Ash Regulation
In February 2023, the EPA entered into a Consent Decree committing the agency to either issue new proposed rules by May 5, 2023, to regulate inactive CCR landfills under the CCR Rule for the first time or to determine no such rules are necessary by that date.
If proposed rules are issued, the EPA has committed to a May 2024 effective date for those new rules. It is also anticipated that the EPA may issue other CCR proposed rules in 2023 that further expand the scope of
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the CCR Rule. Until proposed rules are issued, it is not certain what the impact will be on Xcel Energy.
Emerging Contaminants of Concern
PFAS are man-made chemicals that are widely used in consumer products and can persist and bio-accumulate in the environment. Xcel Energy does not manufacture PFAS but because PFAS are so ubiquitous in products and the environment, it may impact our operations.
In September 2022, the EPA proposed to designate two types of PFAS as “hazardous substances” under the CERCLA.
In March 2023, the EPA published a proposed rule that would establish enforceable drinking water standards for certain PFAS chemicals.
The proposed rules could result in new obligations for investigation and cleanup. Xcel Energy is monitoring changes to state laws addressing PFAS. The impact of these proposed regulations is uncertain.
Effluent Limitation Guidelines
In March 2023, the EPA released a proposed rule under the Clean Water Act, setting forth proposed Effluent Limitations Guidelines and Standards for steam generating coal plants. This proposed rule establishes more stringent wastewater discharge standards for bottom ash transport water, flue-gas desulfurization wastewater, and combustion residuals leachate from steam electric power plants, particularly coal-fired power plants. Comments to the proposed regulations are due May 30, 2023. The impact of these proposed regulations is uncertain.

Derivatives, Risk Management and Market Risk

We are exposed to a variety of market risks in the normal course of business. Market risk is the potential loss that may occur as a result of adverse changes in the market or fair value for a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk.
Xcel Energy is exposed to the impact of adverse changes in price for energy and energy-related products, which is partially mitigated by the use of commodity derivatives. In addition to ongoing monitoring and maintaining credit policies intended to minimize overall credit risk, management takes steps to mitigate changes in credit and concentration risks associated with its derivatives and other contracts, including parental guarantees and requests of collateral. While we expect that the counterparties will perform on the contracts underlying our derivatives, the contracts expose us to credit and non-performance risk.
Distress in the financial markets may impact counterparty risk and the fair value of the securities in the nuclear decommissioning fund and pension fund.
Commodity Price Risk — We are exposed to commodity price risk in our electric and natural gas operations. Commodity price risk is managed by entering into long and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products and fuels used in generation and distribution activities.
Commodity price risk is also managed through the use of financial derivative instruments. Our risk management policy allows us to manage commodity price risk within each rate-regulated operation per commission approved hedge plans.
Wholesale and Commodity Trading Risk — Xcel Energy conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. Our risk management policy allows management to conduct these activities within guidelines and limitations as approved by our risk management committee.
Fair value of net commodity trading contracts as of March 31, 2023:

|  | Futures / Forwards Maturity
(Millions of Dollars) |  | Less Than 1 Year |  | 1 to 3 Years |  | 4 to 5 Years |  | Greater Than 5 Years |  | Total Fair Value
NSP-Minnesota (a) |  | $ | (2) |  |  | $ | (3) |  |  | $ | (6) |  |  | $ | (1) |  |  | $ | (12) |
NSP- Minnesota (b) |  | (2) |  |  | (7) |  |  | (2) |  |  | (2) |  |  | (13) |
PSCo (a) |  | 4 |  |  | 1 |  |  | 3 |  |  | — |  |  | 8 |
PSCo (b) |  | (42) |  |  | 3 |  |  | 2 |  |  | — |  |  | (37) |
|  | $ | (42) |  |  | $ | (6) |  |  | $ | (3) |  |  | $ | (3) |  |  | $ | (54) |

|  | 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 (b) |  | $ | — |  |  | $ | — |  |  | $ | 3 |  |  | $ | 15 |  |  | $ | 18 |
PSCo (b) |  | 33 |  |  | 1 |  |  | — |  |  | — |  |  | 34 |
|  | $ | 33 |  |  | $ | 1 |  |  | $ | 3 |  |  | $ | 15 |  |  | $ | 52 |

(a) Prices actively quoted or based on actively quoted prices.
(b) Prices based on models and other valuation methods.
Changes in the fair value of commodity trading contracts before the impacts of margin-sharing for the three months ended March 31:

(Millions of Dollars) |  | 2023 |  | 2022
Fair value of commodity trading net contracts outstanding at Jan. 1 |  | $ | (33) |  |  | $ | (33) |
Contracts realized or settled during the period |  | 3 |  |  | 3 |
Commodity trading contract additions and changes during the period |  | 28 |  |  | 9 |
Fair value of commodity trading net contracts outstanding at March 31 |  | $ | (2) |  |  | $ | (21) |

A 10% increase and 10% decrease in forward market prices for Xcel Energy’s commodity trading contracts would have likewise increased and decreased pretax income from continuing operations, by an immaterial amount and approximately $4 million at March 31, 2023, and approximately $14 million and $17 million at March 31, 2022. Market price movements can exceed 10% under abnormal circumstances.
The utility subsidiaries’ commodity trading operations measure the outstanding risk exposure to price changes on contracts and obligations using an industry standard methodology known as VaR. VaR expresses the potential change in fair value of the outstanding contracts and obligations over a particular period of time under normal market conditions.
The VaRs for the NSP-Minnesota and PSCo commodity trading operations, excluding both non-derivative transactions and derivative transactions designated as normal purchases and normal sales, calculated on a consolidated basis using a Monte Carlo simulation with a 95% confidence level and a one-day holding period, were as follows:

(Millions of Dollars) |  | Three Months Ended March 31 |  | Average |  | High |  | Low
2023 |  | $ | 0.6 |  |  | $ | 0.7 |  |  | $ | 1.1 |  |  | $ | 0.4 |
2022 |  | 1.1 |  |  | 1.0 |  |  | 1.3 |  |  | 0.7 |

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Nuclear Fuel Supply — NSP-Minnesota has contracted for its 2023, 2024 and 2025 enriched nuclear material requirements, which are in various stages of processing in Canada, Europe and the United States. NSP-Minnesota is scheduled to take delivery of approximately 26% of its average enriched nuclear material requirements from Russia through 2030. Given the evolving situation in Ukraine and its global impacts, we have entered into additional new contracts that cover potential supply interruptions of nuclear material from Russia.
Interest Rate Risk — Xcel Energy is subject to interest rate risk. Our risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives.
A 100-basis point change in the benchmark rate on Xcel Energy’s variable rate debt would impact pretax interest expense annually by approximately $11 million and $12 million in March 31, 2023 and 2022, respectively.
NSP-Minnesota maintains a nuclear decommissioning fund, as required by the NRC. The nuclear decommissioning fund is subject to interest rate and equity price risk. The fund is invested in a diversified portfolio of debt securities, equity securities and other investments. These investments may be used only for the purpose of decommissioning NSP-Minnesota’s nuclear generating plants.
Fluctuations in equity prices or interest rates affecting the nuclear decommissioning fund do not have a direct impact on earnings due to the application of regulatory accounting. Realized and unrealized gains on the decommissioning fund investments are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs.
The value of pension and postretirement plan assets and benefit costs are impacted by changes in discount rates and expected return on plan assets. Xcel Energy’s ongoing pension and postretirement investment strategy is based on plan-specific investment recommendations that seek to optimize potential investment risk and minimize interest rate risk associated with changes in the obligations as a plan’s funded status increases over time. The impacts of fluctuations in interest rates on pension and postretirement costs are mitigated by pension cost calculation methodologies and regulatory mechanisms that minimize the earnings impacts of such changes.
Credit Risk — Xcel Energy is also exposed to credit risk. Credit risk relates to the risk of loss resulting from counterparties’ nonperformance on their contractual obligations. Xcel Energy maintains credit policies intended to minimize overall credit risk and actively monitors these policies to reflect changes and scope of operations.
At March 31, 2023, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $37 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $36 million. At March 31, 2022, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $39 million, while a decrease in prices of 10% would have resulted in an decrease in credit exposure of $28 million.
Xcel Energy conducts credit reviews for all wholesale, trading and non-trading commodity counterparties and employs credit risk controls, such as letters of credit, parental guarantees, master netting agreements and termination provisions.
Credit exposure is monitored, and when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. Distress in the financial markets could increase our credit risk.

FAIR VALUE MEASUREMENTS

Derivative contracts, with the exception of those designated as normal purchases and normal sales, are reported at fair value. Xcel Energy’s investments held in the nuclear decommissioning fund, rabbi trusts, pension and other postretirement funds are also subject to fair value accounting. See Notes 8 and 9 to the consolidated financial statements for further information.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows
Operating Cash Flows

(Millions of Dollars) |  | Three Months Ended March 31
Cash provided by operating activities — 2022 |  | $ | 1,140 |
Components of change — 2023 vs. 2022 |  |
Higher net income |  | 38 |
Non-cash transactions |  | 53 |
Changes in working capital |  | 211 |
Changes in net regulatory and other assets and liabilities |  | 95 |
Cash provided by operating activities — 2023 |  | $ | 1,537 |

Net cash provided by operating activities increased $397 million for the three months ended March 31, 2023 compared with the prior year. The increase was primarily due to the impact of decreasing natural gas prices on customer receivables and accounts payable, as well as continued collections of deferred net natural gas, fuel and purchased energy costs incurred during Winter Storm Uri.
Investing Cash Flows

(Millions of Dollars) |  | Three Months Ended March 31
Cash used in investing activities — 2022 |  | $ | (952) |
Components of change — 2023 vs. 2022 |  |
Increased capital expenditures |  | (323) |
Other investing activities |  | (9) |
Cash used in investing activities — 2023 |  | $ | (1,284) |

Net cash used in investing activities increased $332 million for the three months ended March 31, 2023 compared with the prior year. The increase in capital expenditures was largely due to continued system expansion.
Financing Cash Flows

(Millions of Dollars) |  | Three Months Ended March 31
Cash used in financing activities — 2022 |  | $ | (264) |
Components of change — 2023 vs. 2022 |  |
Higher net short-term debt proceeds |  | 275 |
Lower net long-term debt repayments |  | (250) |
Higher proceeds from issuance of common stock |  | 5 |
Other financing activities |  | (16) |
Cash used in financing activities — 2023 |  | $ | (250) |

Net cash used by financing activities decreased $14 million for the three months ended March 31, 2023 compared with the prior year. The decrease was largely related to the amount/timing of debt issuances and repayments.
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Capital Requirements
Xcel Energy expects to meet future financing requirements by periodically issuing short-term debt, long-term debt, common stock, hybrid and other securities to maintain desired capitalization ratios.
Pension Fund — Xcel Energy’s pension assets are invested in a diversified portfolio of domestic and international equity securities, short-term to long-duration fixed income securities, and alternative investments, including private equity, real estate and hedge funds.
•In January 2023, contributions of $50 million were made across four of Xcel Energy’s pension plans.
•In 2022, contributions of $50 million were made across four of Xcel Energy’s pension plans.
•For future years, contributions will be made as deemed appropriate based on evaluation of various factors including the funded status of the plans, minimum funding requirements, interest rates and expected investment returns.
Capital Sources
Short-Term Funding Sources — Xcel Energy uses a number of sources to fulfill short-term funding needs, including operating cash flow, notes payable, commercial paper and bank lines of credit. The amount and timing of short-term funding needs depend on financing needs for construction expenditures, working capital and dividend payments.
Short-Term Investments — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS maintain cash operating and short-term investment accounts.
Revolving Credit Facilities — Xcel Energy Inc., NSP-Minnesota, PSCo and SPS each have the right to request an extension of their revolving credit facility termination date for two additional one-year periods beyond the September 2027 termination date. NSP-Wisconsin has the right to request an extension of the revolving credit facility termination date for an additional one-year period. All extension requests are subject to majority bank group approval.
As of April 24, 2023, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet liquidity needs:

(Millions of Dollars) |  | Credit Facility (a) |  | Drawn (b) |  | Available |  | Cash |  | Liquidity
Xcel Energy Inc. |  | $ | 1,500 |  |  | $ | 367 |  |  | $ | 1,133 |  |  | $ | 1 |  |  | $ | 1,134 |
PSCo |  | 700 |  |  | 27 |  |  | 673 |  |  | 155 |  |  | 828 |
NSP-Minnesota |  | 700 |  |  | 92 |  |  | 608 |  |  | 4 |  |  | 612 |
SPS |  | 500 |  |  | 55 |  |  | 445 |  |  | 2 |  |  | 447 |
NSP-Wisconsin |  | 150 |  |  | 30 |  |  | 120 |  |  | 1 |  |  | 121 |
Total |  | $ | 3,550 |  |  | $ | 571 |  |  | $ | 2,979 |  |  | $ | 163 |  |  | $ | 3,142 |

(a)Credit facilities expire in September 2027.
(b)Includes outstanding commercial paper and letters of credit.
Short-Term Debt — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each have individual commercial paper programs. The authorized levels for these commercial paper programs are:
•$1.5 billion for Xcel Energy Inc.
•$700 million for PSCo.
•$700 million for NSP-Minnesota.
•$500 million for SPS.
•$150 million for NSP-Wisconsin.
Money Pool — Xcel Energy received FERC approval to establish a utility money pool arrangement with the utility subsidiaries, subject to receipt of required state regulatory approvals. The utility money pool allows for short-term investments in and borrowings between the utility subsidiaries.
Xcel Energy may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy. The money pool balances are eliminated in consolidation. NSP-Minnesota, NSP-Wisconsin, PSCo and SPS participate in the money pool pursuant to approval from their respective state regulatory commissions.
2023 Planned Financing Activity — During 2023, Xcel Energy plans to issue approximately $85 million of equity through the DRIP and benefit programs. Xcel Energy and its utility subsidiaries issued or plan to issue the following long-term debt:

Issuer |  | Security |  | Amount |  | Status |  | Tenor |  | Coupon
PSCo |  | First Mortgage Bonds |  | $ | 850 | million |  | Completed (a) |  | 30 Year |  | 5.25%
NSP-Wisconsin |  | First Mortgage Bonds |  | 125 | million |  | Second Quarter (b) |  | 30 Year |  | 5.30
NSP-Minnesota |  | First Mortgage Bonds |  | 800 | million |  | Second Quarter |  | N/A |  | N/A
Xcel Energy |  | Unsecured Senior Notes |  | 500 | million |  | Third Quarter |  | N/A |  | N/A
SPS |  | First Mortgage Bonds |  | 100 | million |  | Third Quarter |  | N/A |  | N/A

(a)Bond was issued on April 3, 2023.
(b)NSP-Wisconsin priced a 30-year first mortgage bond on April 21, 2023 and will close on the proceeds in June 2023.
Financing plans are subject to change, depending on legislative initiatives (e.g., federal tax law changes), capital expenditures, the development of a tax credit transferability market, regulatory outcomes, internal cash generation, market conditions and other factors.
Off-Balance-Sheet Arrangements
Xcel Energy does not have any off-balance-sheet arrangements, other than those currently disclosed, that have or are reasonably likely to have a current or future effect on financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.
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Earnings Guidance and Long-Term EPS and Dividend Growth Rate Objectives
Xcel Energy 2023 Earnings Guidance — Xcel Energy’s 2023 GAAP and ongoing earnings guidance is a range of $3.30 to $3.40 per share.(a)
•Constructive outcomes in all rate case and regulatory proceedings.
•Normal weather patterns for the remainder of the year.
•Weather-normalized retail electric sales are projected to increase ~1%.
•Weather-normalized retail firm natural gas sales are projected to be relatively flat.
•Capital rider revenue is projected to increase $70 million to $80 million (net of PTCs). The change from the previous estimate is largely due to a change in the projected levels of PTCs, which are offset in the ETR and largely earnings neutral.
•O&M expenses are projected to decline ~2%.
•Depreciation expense is projected to increase approximately $130 million to $140 million.
•Property taxes are projected to increase approximately $30 million to $40 million.
•Interest expense (net of AFUDC - debt) is projected to increase $100 million to $110 million.
•AFUDC - equity is projected to increase $0 million to $10 million.
•ETR is projected to be ~(7%) to (9%). The change from the previous estimate is largely due to a change in the projected levels of PTCs, which are offset in the capital riders and fuel mechanisms and are largely earnings neutral.
(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.
Long-Term EPS and Dividend Growth Rate Objectives — Xcel Energy expects to deliver an attractive total return to our shareholders through a combination of earnings growth and dividend yield, based on the following long-term objectives:
• Deliver long-term annual EPS growth of 5% to 7% based off of a 2022 base of $3.15 per share, which represents the mid-point of the original 2022 guidance range of $3.10 to $3.20 per share.
• Deliver annual dividend increases of 5% to 7%.
• Target a dividend payout ratio of 60% to 70%.
• Maintain senior secured debt credit ratings in the A range.
• Maintain senior secured debt credit ratings in the A range.

ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

There have been no material changes to the market risk disclosure included in our Annual Report on Form 10-K for the year ended Dec. 31, 2022 under “Derivatives, Risk Management and Market Risk.”

ITEM 4 — CONTROLS AND PROCEDURES

Disclosure Controls and Procedures
Xcel Energy maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the CEO and CFO, allowing timely decisions regarding required disclosure.
As of March 31, 2023, based on an evaluation carried out under the supervision and with the participation of Xcel Energy’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and procedures, the CEO and CFO have concluded that Xcel Energy’s disclosure controls and procedures were effective.
Internal Control Over Financial Reporting
No changes in Xcel Energy’s internal control over financial reporting occurred during the most recent fiscal quarter that materially affected, or are reasonably likely to materially affect, Xcel Energy’s internal control over financial reporting.
PART II — OTHER INFORMATION

ITEM 1 — LEGAL PROCEEDINGS

Xcel Energy is involved in various litigation matters in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for losses probable of being incurred and subject to reasonable estimation.
Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.
For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, would have a material effect on Xcel Energy’s consolidated financial statements. Legal fees are generally expensed as incurred.
See Note 10 to the consolidated financial statements and Part I Item 2 for further information.

ITEM 1A — RISK FACTORS

Xcel Energy’s risk factors are documented in Item 1A of Part I of its Annual Report on Form 10-K for the year ended Dec. 31, 2022, which is incorporated herein by reference. There have been no material changes from the risk factors previously disclosed in the Form 10-K.
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ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Purchases of Equity Securities by the Issuer and Affiliated Purchaser:
The following table provides information about our purchases of equity securities that are registered by Xcel Energy Inc. pursuant to Section 12 of the Exchange Act for the quarter ended March 31, 2023:

|  | Issuer Purchases of Equity Securities
Period |  | Total Number of Shares Purchased |  | Average Price Paid per Share |  | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs |  | Maximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs
Jan. 1, 2023 - Jan. 31, 2023 |  | — |  |  | $ | — |  |  | — |  |  | — |
Feb. 1, 2023 - Feb. 28, 2023 |  | — |  |  | — |  |  | — |  |  | — |
March 1, 2023 - March 31, 2023 (a) |  | 795 |  |  | 64.57 |  |  | — |  |  | — |
|  | 795 |  |  |  |  | — |  |  | — |

(a)Xcel Energy Inc. or one of its agents periodically purchases common shares in open-market transactions in order to satisfy obligations under the Stock Equivalent Plan for Non-Employee Directors.

ITEM 6 — EXHIBITS

* Indicates incorporation by reference

Exhibit Number | Description | Report or Registration Statement | Exhibit Reference
3.01* | Amended and Restated Articles of Incorporation of Xcel Energy Inc., dated May 17, 2012 | Xcel Energy Inc. Form 8-K dated May 16, 2012 | 3.01
3.02* | Bylaws of Xcel Energy Inc. as Amended on April 3, 2020 | Xcel Energy Inc Form 8-K dated April 3, 2020 | 3.01
4.01* | Supplemental Indenture No. 34 dated as of March 1, 2023, between PSCo and U.S. Bank Trust Company, National Association, as successor Trustee, creating $850 million aggregate principal amount of 5.25% First Mortgage Bonds, Series No. 40 due April 1, 2053 | PSCo Form 8-K dated April 3, 2023 | 4.01
31.01 | Principal Executive Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |  |
31.02 | Principal Financial Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |  |
32.01 | Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |  |
101.INS | Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. |  |
101.SCH | Inline XBRL Schema |  |
101.CAL | Inline XBRL Calculation |  |
101.DEF | Inline XBRL Definition |  |
101.LAB | Inline XBRL Label |  |
101.PRE | Inline XBRL Presentation |  |
104 | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) |  |

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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

|  | XCEL ENERGY INC.
4/27/2023 | By: | /s/ BRIAN J. VAN ABEL
|  | Brian J. Van Abel
|  | Executive Vice President, Chief Financial Officer
|  | (Principal Accounting Officer and Principal Financial Officer)

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