Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

See Item 15-1 for an index of financial statements included herein.

See Note 15 to the consolidated financial statements for further information.

Management Report on Internal Control Over Financial Reporting

The management of Xcel Energy Inc. is responsible for establishing and maintaining adequate internal control over financial reporting. Xcel Energy Inc.’s internal control system was designed to provide reasonable assurance to Xcel Energy Inc.’s management and board of directors regarding the preparation and fair presentation of published financial statements.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

Xcel Energy Inc. management assessed the effectiveness of Xcel Energy Inc.’s internal control over financial reporting as of Dec. 31, 2019. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework (2013). Based on our assessment, we believe that, as of Dec. 31, 2019, Xcel Energy Inc.’s internal control over financial reporting is effective at the reasonable assurance level based on those criteria.

Xcel Energy Inc.’s independent registered public accounting firm has issued an audit report on Xcel Energy Inc.’s internal control over financial reporting. Its report appears herein.

/s/ BEN FOWKE			/s/ ROBERT C. FRENZEL
Ben Fowke			Robert C. Frenzel
Chairman, President, Chief Executive Officer and Director			Executive Vice President, Chief Financial Officer
Feb. 21, 2020			Feb. 21, 2020

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the stockholders and the Board of Directors of Xcel Energy Inc.

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheets of Xcel Energy Inc. and subsidiaries (the "Company") as of December 31, 2019 and 2018, the related consolidated statements of income, comprehensive income, stockholders' equity, and cash flows, for each of the three years in the period ended December 31, 2019, and the related notes and the schedules listed in the Index at Item 15 (collectively referred to as the "financial statements"). We also have audited the Company’s internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.

Basis for Opinions

The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management Report on Internal Controls over Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the financial statements included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Regulatory Assets and Liabilities - Impact of Rate Regulation on the Financial Statements - Refer to Notes 4 and 12 to the consolidated financial statements

Critical Audit Matter Description

The Company is subject to rate regulation by state utility regulatory agencies, which have jurisdiction with respect to the rates of electric and natural gas distribution companies in Minnesota, North Dakota, South Dakota, Wisconsin, Michigan, Colorado, New Mexico, and Texas. The Company is also subject to the jurisdiction of the Federal Energy Regulatory Commission for its wholesale electric operations, hydroelectric generation licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with North American Electric Reliability Corporation standards, asset transactions and mergers and natural gas transactions in interstate commerce, (collectively with state utility regulatory agencies, the “Commissions”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation affects multiple financial statement line items and disclosures, including property, plant and equipment, regulatory assets and liabilities, operating revenues and expenses, and income taxes.

The Company is subject to regulatory rate setting processes. Rates are determined and approved in regulatory proceedings based on an analysis of the Company’s costs to provide utility service and a return on, and recovery of, the Company’s investment in assets required to deliver services to customers. Accounting for the Company’s regulated operations provides that rate-regulated entities report assets and liabilities consistent with the recovery of those incurred costs in rates, if it is probable that such rates will be charged and collected. The Commissions’ regulation of rates is premised on the full recovery of incurred costs and a reasonable rate of return on invested capital. Decisions by the Commissions in the future will impact the accounting for regulated operations, including decisions about the amount of allowable costs and return on invested capital included in rates and any refunds that may be required. In the rate setting process, the Company’s rates result in the recording of regulatory assets and liabilities based on the probability of future cash flows. Regulatory assets generally represent incurred or accrued costs that have been deferred because future recovery from customers is probable. Regulatory liabilities generally represent amounts that are expected to be refunded to customers in future rates or amounts collected in current rates for future costs.

We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of part of the cost of recently completed plant, and 3) a refund due to customers. Given that management’s accounting judgements are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:

•

We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the recognition of regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.

•	We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.

•

We read relevant regulatory orders issued by the Commissions for the Company, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedence of the Commissions’ treatment of similar costs under similar circumstances. We also evaluated regulatory filings for any evidence that intervenors are challenging full recovery of the cost of any capital projects. If the full recovery of project costs is being challenged by intervenors, we evaluated management’s assessment of the probability of a disallowance. We evaluated the external information and compared to the Company’s recorded regulatory assets and liabilities for completeness.

•	We obtained management’s analysis and correspondence from counsel, as appropriate, regarding regulatory assets or liabilities not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.

/s/ DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
February 21, 2020
We have served as the Company’s auditor since 2002.

XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (amounts in millions, except per share data)
		Year Ended Dec. 31
		2019				2018				2017
Operating revenues
Electric		$	9,575			$	9,719			$	9,676
Natural gas		1,868				1,739				1,650
Other		86				79				78
Total operating revenues		11,529				11,537				11,404
Operating expenses
Electric fuel and purchased power		3,510				3,854				3,757
Cost of natural gas sold and transported		918				843				823
Cost of sales — other		40				35				34
Operating and maintenance expenses		2,338				2,352				2,270
Conservation and demand side management program expenses		285				290				273
Depreciation and amortization		1,765				1,642				1,479
Taxes (other than income taxes)		569				556				545
Total operating expenses		9,425				9,572				9,181
Operating income		2,104				1,965				2,223
Other income (expense), net		16				(14		)		(10		)
Equity earnings of unconsolidated subsidiaries		39				35				30
Allowance for funds used during construction — equity		77				108				75
Interest charges and financing costs
Interest charges — includes other financing costs of $26, $25 and $24, respectively		773				700				663
Allowance for funds used during construction — debt		(37		)		(48		)		(35		)
Total interest charges and financing costs		736				652				628
Income before income taxes		1,500				1,442				1,690
Income taxes		128				181				542
Net income		$	1,372			$	1,261			$	1,148
Weighted average common shares outstanding:
Basic		519				511				509
Diluted		520				511				509
Earnings per average common share:
Basic		$	2.64			$	2.47			$	2.26
Diluted		2.64				2.47				2.25
See Notes to Consolidated Financial Statements

XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (amounts in millions)
		Year Ended Dec. 31
		2019				2018				2017
Net income		$	1,372			$	1,261			$	1,148
Other comprehensive (loss) income
Defined pension and other postretirement benefits:
Net pension and retiree medical loss arising during the period, net of tax of $0, $(2) and $(2), respectively		—				(6		)		(3		)
Reclassification of loss to net income, net of tax of $1, $3 and $5, respectively		3				9				7
Derivative instruments:
Net fair value decrease, net of tax of $(8), $(2) and $0, respectively		(23		)		(5		)		—
Reclassification of loss to net income, net of tax of $1, $1 and $2, respectively		3				3				3
Total other comprehensive (loss) income		(17		)		1				7
Total comprehensive income		$	1,355			$	1,262			$	1,155
See Notes to Consolidated Financial Statements

XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (amounts in millions)
	Year Ended Dec. 31
	2019				2018				2017
Operating activities
Net income	$	1,372			$	1,261			$	1,148
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	1,785				1,659				1,495
Nuclear fuel amortization	119				122				114
Deferred income taxes	143				218				640
Allowance for equity funds used during construction	(77		)		(108		)		(75		)
Equity earnings of unconsolidated subsidiaries	(39		)		(35		)		(30		)
Dividends from unconsolidated subsidiaries	40				37				41
Provision for bad debts	42				42				39
Share-based compensation expense	58				45				57
Net realized and unrealized hedging and derivative transactions	45				22				2
Changes in operating assets and liabilities:
Accounts receivable	(20		)		(105		)		(60		)
Accrued unbilled revenues	42				9				(34		)
Inventories	(84		)		(65		)		(3		)
Other current assets	25				18				9
Accounts payable	(12		)		90				43
Net regulatory assets and liabilities	(66		)		223				(16		)
Other current liabilities	(15		)		(61		)		(38		)
Pension and other employee benefit obligations	(135		)		(179		)		(133		)
Other, net	40				(71		)		(73		)
Net cash provided by operating activities	3,263				3,122				3,126
Investing activities
Utility capital/construction expenditures	(4,225		)		(3,957		)		(3,244		)
Purchases of investment securities	(995		)		(853		)		(1,697		)
Proceeds from the sale of investment securities	975				833				1,669
Other, net	(98		)		(9		)		(24		)
Net cash used in investing activities	(4,343		)		(3,986		)		(3,296		)
Financing activities
(Repayments of) proceeds from short-term borrowings, net	(443		)		225				422
Proceeds from issuance of long-term debt	2,920				1,675				1,518
Repayments of long-term debt, including reacquisition premiums	(949		)		(452		)		(1,030		)
Proceeds from issuance of common stock	458				230				—
Dividends paid	(791		)		(730		)		(721		)
Other, net	(14		)		(20		)		(21		)
Net cash provided by financing activities	1,181				928				168
Net change in cash, cash equivalents and restricted cash	101				64				(2		)
Cash, cash equivalents and restricted cash at beginning of period	147				83				85
Cash, cash equivalents and restricted cash at end of period	$	248			$	147			$	83
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(698	)		$	(633	)		$	(616	)
Cash received for income taxes, net	53				27				44
Supplemental disclosure of non-cash investing and financing transactions:
Accrued property, plant and equipment additions	$	421			$	388			$	464
Inventory and other asset transfers to property, plant and equipment	88				129				63
Operating lease right-of-use assets	1,843				—				—
Allowance for equity funds used during construction	77				108				75
Issuance of common stock for reinvested dividends and equity awards	63				67				31
See Notes to Consolidated Financial Statements

XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (amounts in millions, except share and per share)
		Dec. 31
		2019				2018
Assets
Current assets
Cash and cash equivalents		$	248			$	147
Accounts receivable, net		837				860
Accrued unbilled revenues		713				755
Inventories		544				548
Regulatory assets		488				464
Derivative instruments		55				87
Prepaid taxes		43				79
Prepayments and other		185				154
Total current assets		3,113				3,094
Property, plant and equipment, net		39,483				36,944
Other assets
Nuclear decommissioning fund and other investments		2,731				2,317
Regulatory assets		2,935				3,326
Derivative instruments		22				34
Operating lease right-of-use assets		1,672				—
Other		492				272
Total other assets		7,852				5,949
Total assets		$	50,448			$	45,987
Liabilities and Equity
Current liabilities
Current portion of long-term debt		$	702			$	406
Short-term debt		595				1,038
Accounts payable		1,294				1,237
Regulatory liabilities		407				436
Taxes accrued		466				450
Accrued interest		192				174
Dividends payable		212				195
Derivative instruments		38				61
Other		662				463
Total current liabilities		4,568				4,460
Deferred credits and other liabilities
Deferred income taxes		4,509				4,165
Deferred investment tax credits		49				54
Regulatory liabilities		5,077				5,187
Asset retirement obligations		2,701				2,568
Derivative instruments		175				129
Customer advances		203				199
Pension and employee benefit obligations		785				994
Operating lease liabilities		1,549				—
Other		186				206
Total deferred credits and other liabilities		15,234				13,502
Commitments and contingencies
Capitalization
Long-term debt		17,407				15,803
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 524,539,000 and 514,036,787 shares outstanding at Dec. 31, 2019 and 2018, respectively		1,311				1,285
Additional paid in capital		6,656				6,168
Retained earnings		5,413				4,893
Accumulated other comprehensive loss		(141		)		(124		)
Total common stockholders’ equity		13,239				12,222
Total liabilities and equity		$	50,448			$	45,987
See Notes to Consolidated Financial Statements

XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY (amounts in millions, shares in thousands)
	Common Stock Issued															Accumulated Other Comprehensive Loss				Total Common Stockholders’ Equity
	Shares			Par Value				Additional Paid In Capital				Retained Earnings
Balance at Dec. 31, 2016	507,223			$	1,268			$	5,881			$	3,982			$	(110	)		$	11,021
Net income												1,148								1,148
Other comprehensive loss																7				7
Dividends declared on common stock ($1.44 per share)												(736		)						(736		)
Issuances of common stock	611			1				4												5
Repurchases of common stock	(71	)		—				(3		)										(3		)
Share-based compensation								16				(3		)						13
Adoption of ASU No. 2018-02												22				(22		)		—
Balance at Dec. 31, 2017	507,763			$	1,269			$	5,898			$	4,413			$	(125	)		$	11,455
Net income												1,261								1,261
Other comprehensive income																1				1
Dividends declared on common stock ($1.52 per share)												(780		)						(780		)
Issuances of common stock	6,296			16				254												270
Repurchases of common stock	(22	)		—				(1		)										(1		)
Share-based compensation								17				(1		)						16
Balance at Dec. 31, 2018	514,037			$	1,285			$	6,168			$	4,893			$	(124	)		$	12,222
Net income												1,372								1,372
Other comprehensive income																(17		)		(17		)
Dividends declared on common stock ($1.62 per share)												(846		)						(846		)
Issuances of common stock	10,508			26				468												494
Repurchases of common stock	(6	)		—				—												—
Share-based compensation								20				(6		)						14
Balance at Dec. 31, 2019	524,539			$	1,311			$	6,656			$	5,413			$	(141	)		$	13,239
See Notes to Consolidated Financial Statements

XCEL ENERGY INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements

1. Summary of Significant Accounting Policies

General — Xcel Energy Inc.’s utility subsidiaries are engaged in the regulated generation, purchase, transmission, distribution and sale of electricity and in the regulated purchase, transportation, distribution and sale of natural gas.

Xcel Energy’s regulated operations include the activities of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS. These utility subsidiaries serve electric and natural gas customers in portions of Colorado, Michigan, Minnesota, New Mexico, North Dakota, South Dakota, Texas and Wisconsin. Also included in regulated operations are WGI, an interstate natural gas pipeline company, and WYCO, a joint venture with CIG to develop and lease natural gas pipeline, storage and compression facilities.

Xcel Energy Inc.’s nonregulated subsidiaries include Eloigne, Capital Services and the newly formed MEC Holdings LLC. Eloigne invests in rental housing projects that qualify for low-income housing tax credits. Capital Services procures equipment for construction of renewable generation facilities at other subsidiaries. Xcel Energy Inc. owns the following additional direct subsidiaries, some of which are intermediate holding companies with additional subsidiaries: Xcel Energy Wholesale Group Inc., Xcel Energy Markets Holdings Inc., Xcel Energy Ventures Inc., Xcel Energy Retail Holdings Inc., Xcel Energy Communications Group, Inc., Xcel Energy International Inc., Xcel Energy Transmission Holding Company, LLC, Nicollet Holdings Company, LLC, Nicollet Project Holdings LLC, Xcel Energy Venture Holdings Inc. and Xcel Energy Services Inc. Xcel Energy Inc. and its subsidiaries collectively are referred to as Xcel Energy.

Xcel Energy’s consolidated financial statements include its wholly-owned subsidiaries and VIEs for which it is the primary beneficiary. All intercompany transactions and balances are eliminated, unless a different treatment is appropriate for rate regulated transactions.

Xcel Energy uses the equity method of accounting for its investment in WYCO. Xcel Energy’s equity earnings in WYCO are included on the consolidated statements of income as equity earnings of unconsolidated subsidiaries.

Xcel Energy has investments in certain plants and transmission facilities jointly owned with nonaffiliated utilities. Xcel Energy’s proportionate share of jointly owned facilities is recorded as property, plant and equipment on the consolidated balance sheets, and Xcel Energy’s proportionate share of the operating costs associated with these facilities is included in its consolidated statements of income.

Xcel Energy’s consolidated financial statements are presented in accordance with GAAP. All of the utility subsidiaries’ underlying accounting records also conform to the FERC uniform system of accounts. Certain amounts in the 2018 and 2017 consolidated financial statements or notes have been reclassified to conform to the 2019 presentation for comparative purposes; however, such reclassifications did not affect net income, total assets, liabilities, equity or cash flows.

Xcel Energy has evaluated events occurring after Dec. 31, 2019 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation.

Use of Estimates — Xcel Energy uses estimates based on the best information available in recording transactions and balances resulting from business operations.

Estimates are used on items such as plant depreciable lives or potential disallowances, AROs, certain regulatory assets and liabilities, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs. Recorded estimates are revised when better information becomes available or actual amounts can be determined. Revisions can affect operating results.

Regulatory Accounting — Xcel Energy Inc.’s regulated utility subsidiaries account for income and expense items in accordance with accounting guidance for regulated operations. Under this guidance:

•	Certain costs, which would otherwise be charged to expense or other comprehensive income, are deferred as regulatory assets based on the expected ability to recover the costs in future rates; and

•	Certain credits, which would otherwise be reflected as income or other comprehensive income, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred.

Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process.

If changes in the regulatory environment occur, the utility subsidiaries may no longer be eligible to apply this accounting treatment and may be required to eliminate regulatory assets and liabilities from their balance sheets. Such changes could have a material effect on Xcel Energy’s results of operations, financial condition and cash flows.

See Note 4 for further information.

Income Taxes — Xcel Energy accounts for income taxes using the asset and liability method, which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. Xcel Energy defers income taxes for all temporary differences between pretax financial and taxable income and between the book and tax bases of assets and liabilities. Xcel Energy uses rates that are scheduled to be in effect when the temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the period that includes the enactment date.

The effects of tax rate changes that are attributable to the utility subsidiaries are generally subject to a normalization method of accounting. Therefore, the revaluation of most of the utility subsidiaries’ net deferred taxes upon a tax rate reduction results in the establishment of a net regulatory liability, which will be refundable to utility customers over the remaining life of the related assets. A tax rate increase would result in the establishment of a similar regulatory asset.

Reversal of certain temporary differences are accounted for as current income tax expense due to the effects of past regulatory practices when deferred taxes were not required to be recorded due to the use of flow through accounting for ratemaking purposes. Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize it over the book depreciable lives of the related property. The requirement to defer and amortize tax credits only applies to federal ITCs related to public utility property. Utility rate regulation also has resulted in the recognition of regulatory assets and liabilities related to income taxes. Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized.

Xcel Energy follows the applicable accounting guidance to measure and disclose uncertain tax positions that it has taken or expects to take in its income tax returns. Xcel Energy recognizes a tax position in its consolidated financial statements when it is more likely than not that the position will be sustained upon examination based on the technical merits of the position. Recognition of changes in uncertain tax positions are reflected as a component of income tax expense.

Xcel Energy reports interest and penalties related to income taxes within the other income and interest charges in the consolidated statements of income.

Xcel Energy Inc. and its subsidiaries file consolidated federal income tax returns as well as consolidated or separate state income tax returns. Federal income taxes paid by Xcel Energy Inc. are allocated to its subsidiaries based on separate company computations. A similar allocation is made for state income taxes paid by Xcel Energy Inc. in connection with consolidated state filings. Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries.

See Note 7 for further information.

Property, Plant and Equipment and Depreciation in Regulated Operations — Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and AFUDC. The cost of plant retired is charged to accumulated depreciation and amortization. Amounts recovered in rates for future removal costs are recorded as regulatory liabilities. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance costs are charged to expense as incurred. Maintenance and replacement of items determined to be less than a unit of property are charged to operating expenses as incurred. Planned maintenance activities are charged to operating expense unless the cost represents the acquisition of an additional unit of property or the replacement of an existing unit of property.

Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable. A loss is recognized in the current period if it becomes probable that part of a cost of a plant under construction or recently completed plant will be disallowed for recovery from customers and a reasonable estimate of the disallowance can be made. For investments in property, plant and equipment that are abandoned and not expected to go into service, incurred costs and related deferred tax amounts are compared to the discounted estimated future rate recovery, and a loss is recognized, if necessary.

Xcel Energy records depreciation expense using the straight-line method over the plant’s useful life. Actuarial life studies are performed and submitted to the state and federal commissions for review. Upon acceptance by the various commissions, the resulting lives and net salvage rates are used to calculate depreciation. Depreciation expense, expressed as a percentage of average depreciable property, was approximately 3.3% for 2019, 3.1% for 2018 and 2017.

See Note 3 for further information.

AROs — Xcel Energy accounts for AROs under accounting guidance that requires a liability for the fair value of an ARO to be recognized in the period in which it is incurred if it can be reasonably estimated, with the offsetting associated asset retirement costs capitalized as a long-lived asset. The liability is generally increased over time by applying the effective interest method of accretion, and the capitalized costs are depreciated over the useful life of the long-lived asset. Changes resulting from revisions to the timing or amount of expected asset retirement cash flows are recognized as an increase or a decrease in the ARO. The utility subsidiaries also recover through rates certain future plant removal costs in addition to AROs.

The accumulated removal costs for these obligations are reflected in the consolidated balance sheets as a regulatory liability.

See Note 12 for further information.

Nuclear Decommissioning — Nuclear decommissioning studies that estimate NSP-Minnesota’s costs of decommissioning its nuclear power plants are performed at least every three years and submitted to the state commissions for approval.

For ratemaking purposes, NSP-Minnesota recovers regulator-approved decommissioning costs of its nuclear power plants over each facility’s expected service life, typically based on the triennial decommissioning studies. The studies consider estimated future costs of decommissioning and the market value of investments in trust funds and recommend annual funding amounts. Amounts collected in rates are deposited in the trust funds. For financial reporting purposes, NSP-Minnesota accounts for nuclear decommissioning as an ARO.

Restricted funds for the payment of future decommissioning expenditures for NSP-Minnesota’s nuclear facilities are included in nuclear decommissioning fund and other assets on the consolidated balance sheets.

See Note 10 and 12 for further information.

Benefit Plans and Other Postretirement Benefits — Xcel Energy maintains pension and postretirement benefit plans for eligible employees. Recognizing the cost of providing benefits and measuring the projected benefit obligation of these plans requires management to make various assumptions and estimates.

Certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are deferred as regulatory assets and liabilities, rather than recorded as other comprehensive income, based on regulatory recovery mechanisms.

See Note 11 for further information.

Environmental Costs — Environmental costs are recorded when it is probable Xcel Energy is liable for remediation costs and the liability can be reasonably estimated. Costs are deferred as a regulatory asset if it is probable that the costs will be recovered from customers in future rates. Otherwise, the costs are expensed. If an environmental expense is related to facilities currently in use, such as emission-control equipment, the cost is capitalized and depreciated over the life of the plant.

Estimated remediation costs are regularly adjusted as estimates are revised and remediation proceeds. If other participating potentially responsible parties exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for Xcel Energy’s expected share of the cost.

Future costs of restoring sites are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses. Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability.

See Note 12 for further information.

Revenue from Contracts with Customers — Performance obligations related to the sale of energy are satisfied as energy is delivered to customers. Xcel Energy recognizes revenue that corresponds to the price of the energy delivered to the customer. The measurement of energy sales to customers is generally based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and the corresponding unbilled revenue is recognized.

Xcel Energy does not recognize a separate financing component of its collections from customers as contract terms are short-term in nature. Xcel Energy presents its revenues net of any excise or sales taxes or fees. The utility subsidiaries recognize sales to customers on a gross basis in electric revenues and cost of sales. Revenues and charges for short term wholesale sales of excess energy transacted through RTOs are also recorded on a gross basis. Other RTO revenues and charges are recorded on a net basis in cost of sales.

See Note 6 for further information.

Cash and Cash Equivalents — Xcel Energy considers investments in instruments with a remaining maturity of three months or less at the time of purchase to be cash equivalents.

Accounts Receivable and Allowance for Bad Debts — Accounts receivable are stated at the actual billed amount net of an allowance for bad debts. Xcel Energy establishes an allowance for uncollectible receivables based on a policy that reflects its expected exposure to the credit risk of customers.

At both Dec. 31, 2019 and 2018, the allowance for bad debts was $55 million.

Inventory — Inventory is recorded at average cost and consisted of the following:

(Millions of Dollars)		Dec. 31, 2019				Dec. 31, 2018
Inventories
Materials and supplies		$	270			$	271
Fuel		191				170
Natural gas		83				107
Total inventories		$	544			$	548

Fair Value Measurements — Xcel Energy presents cash equivalents, interest rate derivatives, commodity derivatives and nuclear decommissioning fund assets at estimated fair values in its consolidated financial statements.

Cash equivalents are recorded at cost plus accrued interest; money market funds are measured using quoted NAVs. For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used to establish fair value. For commodity derivatives, the most observable inputs available are generally used to determine the fair value of each contract. In the absence of a quoted price, Xcel Energy may use quoted prices for similar contracts or internally prepared valuation models to determine fair value.

For the pension and postretirement plan assets and nuclear decommissioning fund, published trading data and pricing models, generally using the most observable inputs available, are utilized to estimate fair value for each security.

See Notes 10 and 11 for further information.

Derivative Instruments — Xcel Energy uses derivative instruments in connection with its interest rate, utility commodity price, vehicle fuel price and commodity trading activities, including forward contracts, futures, swaps and options. Any derivative instruments not qualifying for the normal purchases and normal sales exception are recorded on the consolidated balance sheets at fair value as derivative instruments. Classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship. Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability. Classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.

Gains or losses on commodity trading transactions are recorded as a component of electric operating revenues; hedging transactions for vehicle fuel costs are recorded as a component of capital projects and O&M costs; and interest rate hedging transactions are recorded as a component of interest expense.

Normal Purchases and Normal Sales — Xcel Energy enters into contracts for purchases and sales of commodities for use in its operations. At inception, contracts are evaluated to determine whether a derivative exists and/or whether an instrument may be exempted from derivative accounting if designated as a normal purchase or normal sale.

See Note 10 for further information.

Commodity Trading Operations — All applicable gains and losses related to commodity trading activities are shown on a net basis in electric operating revenues in the consolidated statements of income.

Commodity trading activities are not associated with energy produced from Xcel Energy’s generation assets or energy and capacity purchased to serve native load. Commodity trading contracts are recorded at fair market value and commodity trading results include the impact of all margin-sharing mechanisms.

See Note 10 for further information.

Other Utility Items

AFUDC — AFUDC represents the cost of capital used to finance utility construction activity. AFUDC is computed by applying a composite financing rate to qualified CWIP. The amount of AFUDC capitalized as a utility construction cost is credited to other nonoperating income (for equity capital) and interest charges (for debt capital). AFUDC amounts capitalized are included in Xcel Energy’s rate base for establishing utility rates.

Alternative Revenue — Certain rate rider mechanisms (including decoupling and CIP/DSM programs) qualify as alternative revenue programs. These mechanisms arise from costs imposed upon the utility by action of a regulator or legislative body related to an environmental, public safety or other mandate. When certain criteria are met, including expected collection within 24 months, revenue is recognized equal to the revenue requirement, which may include incentives and return on rate base items. Billing amounts are revised periodically for differences between total amount collected and revenue earned, which may increase or decrease the level of revenue collected from customers. Alternative revenues arising from these programs are presented on a gross basis and disclosed separately from revenue from contracts with customers.

See Note 6 for further information.

Conservation Programs — Costs incurred for DSM and CIP programs are deferred if it is probable future revenue will recover the incurred cost. Revenues recognized for incentive programs for the recovery of lost margins and/or conservation performance incentives are limited to amounts expected to be collected within 24 months from the year they are earned. Regulatory assets are recognized to reflect the amount of costs or earned incentives that have not yet been collected from customers.

Emission Allowances — Emission allowances are recorded at cost, including broker commission fees. The inventory accounting model is utilized for all emission allowances and sales of these allowances are included in electric revenues.

Nuclear Refueling Outage Costs — Xcel Energy uses a deferral and amortization method for nuclear refueling costs. This method amortizes costs over the period between refueling outages consistent with rate recovery.

RECs — Cost of RECs that are utilized for compliance is recorded as electric fuel and purchased power expense. In certain jurisdictions, Xcel Energy reduces recoverable fuel costs for the cost of RECs and records that cost as a regulatory asset when the amount is recoverable in future rates.

Sales of RECs are recorded in electric revenues on a gross basis. The cost of these RECs and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense.

Cost of RECs that are utilized to support commodity trading activities are recorded in a similar manner as the associated commodities and are shown on a net basis in electric operating revenues in the consolidated statements of income.

2. Accounting Pronouncements

Recently Issued

Credit Losses — In 2016, the FASB issued Financial Instruments - Credit Losses, Topic 326 (ASC Topic 326), which changes how entities account for losses on receivables and certain other assets. The guidance requires use of a current expected credit loss model, which may result in earlier recognition of credit losses than under previous accounting standards. ASC Topic 326 is effective for interim and annual periods beginning on or after Dec. 15, 2019 and will be applied using a modified-retrospective approach, with a cumulative-effect adjustment to retained earnings as of Jan. 1, 2020.

Xcel Energy expects the impact of adoption of the new standard to include first-time recognition of expected credit losses (i.e., bad debt expense) on unbilled revenues, with the initial allowance established at Jan. 1, 2020 charged to retained earnings. Recognition of this allowance and other impacts of adoption are expected to be immaterial to the consolidated financial statements.

Recently Adopted

Leases — In 2016, the FASB issued Leases, Topic 842 (ASC Topic 842), which provides new accounting and disclosure guidance for leasing activities, most significantly requiring that operating leases be recognized on the balance sheet. Xcel Energy adopted the guidance on Jan. 1, 2019 utilizing the package of transition practical expedients provided by the new standard, including carrying forward prior conclusions on whether agreements existing before the adoption date contain leases and whether existing leases are operating or finance leases; ASC Topic 842 refers to capital leases as finance leases.

Specifically, for land easement contracts, Xcel Energy has elected the practical expedient provided by ASU No. 2018-01 Leases: Land Easement Practical Expedient for Transition to Topic 842, and as a result, only those easement contracts entered on or after Jan. 1, 2019 will be evaluated to determine if lease treatment is appropriate.

Xcel Energy also utilized the transition practical expedient offered by ASU No. 2018-11 Leases: Targeted Improvements to implement the standard on a prospective basis. As a result, reporting periods in the consolidated financial statements beginning Jan. 1, 2019 reflect the implementation of ASC Topic 842, while prior periods continue to be reported in accordance with Leases, Topic 840 (ASC Topic 840). Other than first-time recognition of operating leases on its consolidated balance sheet, the implementation of ASC Topic 842 did not have a significant impact on Xcel Energy’s consolidated financial statements. Adoption resulted in recognition of approximately $1.7 billion of operating lease ROU assets and current/noncurrent operating lease liabilities.

See Note 12 for leasing disclosures.

3. Property, Plant and Equipment

Major classes of property, plant and equipment

(Millions of Dollars)		Dec. 31, 2019				Dec. 31, 2018
Property, plant and equipment
Electric plant		$	44,355			$	41,472
Natural gas plant		6,560				6,210
Common and other property		2,341				2,154
Plant to be retired (a)		259				322
CWIP		2,329				2,091
Total property, plant and equipment		55,844				52,249
Less accumulated depreciation		(16,735		)		(15,659		)
Nuclear fuel		2,909				2,771
Less accumulated amortization		(2,535		)		(2,417		)
Property, plant and equipment, net		$	39,483			$	36,944

(a)	In 2018, the CPUC approved early retirement of PSCo’s Comanche Units 1 and 2 in approximately 2022 and 2025, respectively. PSCo also expects Craig Unit 1 to be retired early in 2025. Amounts are presented net of accumulated depreciation.

Joint Ownership of Generation, Transmission and Gas Facilities

The utility subsidiaries’ jointly owned assets as of Dec. 31, 2019:

(Millions of Dollars)		Plant in Service				Accumulated Depreciation				CWIP				Percent Owned
NSP-Minnesota
Electric generation:
Sherco Unit 3		$	603			$	426			$	4			59	%
Sherco common facilities		145				103				2				80
Sherco substation		5				3				—				59
Electric transmission:
CapX2020		972				92				2				51
Grand Meadow		11				3				—				50
Total NSP-Minnesota		$	1,736			$	627			$	8

(Millions of Dollars)		Plant in Service				Accumulated Depreciation				CWIP				Percent Owned
NSP-Wisconsin
Electric transmission:
La Crosse, WI to Madison, WI		$	187			$	7			$	—			37	%
CapX2020		169				19				—				80
Total NSP-Wisconsin		$	356			$	26			$	—

(Millions of Dollars)		Plant in Service				Accumulated Depreciation				CWIP				Percent Owned
PSCo
Electric generation:
Hayden Unit 1		$	152			$	81			$	—			76	%
Hayden Unit 2		149				71				—				37
Hayden common facilities		41				22				—				53
Craig Units 1 and 2		81				41				—				10
Craig common facilities		39				22				—				7
Comanche Unit 3		887				149				1				67
Comanche common facilities		29				3				—				82
Electric transmission:
Transmission and other facilities		174				62				1				Various
Gas transmission:
Rifle, CO to Avon, CO		22				7				—				60
Gas transmission compressor		9				1				—				50
Total PSCo		$	1,583			$	459			$	2

Each company’s share of operating expenses and construction expenditures is included in the applicable utility accounts. Respective owners are responsible for providing their own financing.

4. Regulatory Assets and Liabilities

Regulatory assets and liabilities are created for amounts that regulators may allow to be collected or may require to be paid back to customers in future electric and natural gas rates. Xcel Energy would be required to recognize the write-off of regulatory assets and liabilities in net income or other comprehensive income if changes in the utility industry no longer allow for the application of regulatory accounting guidance under GAAP.

Components of regulatory assets:

(Millions of Dollars)		See Note(s)			Remaining Amortization Period		Dec. 31, 2019								Dec. 31, 2018
Regulatory Assets							Current				Noncurrent				Current				Noncurrent
Pension and retiree medical obligations		11			Various		$	85			$	1,328			$	87			$	1,500
Recoverable deferred taxes on AFUDC recorded in plant					Plant lives		—				271				—				264
Net AROs (a)		1, 12			Plant lives		—				269				—				452
Excess deferred taxes — TCJA		7			Various		39				239				—				296
Depreciation differences					One to twelve years		15				140				18				107
Environmental remediation costs		1, 12			Various		36				131				17				155
Benson biomass PPA termination and asset purchase					Ten years		9				73				10				86
Contract valuation adjustments (b)		1, 10			Term of related contract		20				62				17				77
Purchased power contract costs					Term of related contract		5				61				4				63
Laurentian biomass PPA termination					Five years		19				54				18				73
PI extended power uprate					Sixteen years		3				53				3				56
Losses on reacquired debt					Term of related debt		4				41				4				44
State commission adjustments					Plant lives		1				31				1				29
Property tax					Various		2				30				14				10
Conservation programs (c)		1			One to two years		27				26				42				28
Nuclear refueling outage costs		1			One to two years		43				17				37				14
Sales true-up and revenue decoupling					One to two years		54				16				38				7
Renewable resources and environmental initiatives					One to two years		72				10				39				9
Gas pipeline inspection and remediation costs					One to two years		26				8				28				3
Deferred purchased natural gas and electric energy costs					One to three years		6				6				57				13
Other					Various		22				69				30				40
Total regulatory assets							$	488			$	2,935			$	464			$	3,326

(a) Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments.

(b) Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.

(c) Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.

Components of regulatory liabilities:

(Millions of Dollars)		See Note(s)		Remaining Amortization Period		Dec. 31, 2019								Dec. 31, 2018
Regulatory Liabilities						Current				Noncurrent				Current				Noncurrent
Deferred income tax adjustments and TCJA refunds (a)		7		Various		$	75			$	3,523			$	157			$	3,715
Plant removal costs		1, 12		Plant lives		—				1,217				—				1,175
Effects of regulation on employee benefit costs (b)				Various		—				196				—				137
Renewable resources and environmental initiatives				Various		—				45				9				54
ITC deferrals (c)		1		Various		—				38				—				40
Deferred electric, natural gas and steam production costs				Less than one year		138				—				102				—
Contract valuation adjustments (d)		1, 10		Less than one year		19				—				26				—
Conservation programs (e)		1		Less than one year		37				—				36				—
DOE settlement				Less than one year		37				—				19				—
Other				Various		101				58				87				66
Total regulatory liabilities (f)						$	407			$	5,077			$	436			$	5,187

(a)	Includes the revaluation of recoverable/regulated plant ADIT and revaluation impact of non-plant ADIT due to the TCJA.

(b)	Includes regulatory amortization and certain 2018 TCJA benefits approved by the CPUC to offset the PSCo prepaid pension asset.

(c)	Includes impact of lower federal tax rate due to the TCJA.

(d)	Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.

(e)	Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.

(f)	Revenue subject to refund of $28 million and $29 million for 2019 and 2018, respectively, is included in other current liabilities.

At Dec. 31, 2019 and 2018, Xcel Energy’s regulatory assets not earning a return primarily included the unfunded portion of pension and retiree medical obligations, net AROs and Laurentian biomass PPA termination costs/obligations. In addition, regulatory assets included $544 million and $512 million at Dec. 31, 2019 and 2018, respectively, of past expenditures not earning a return. Amounts primarily related to funded pension obligations, sales true-up and revenue decoupling, purchased natural gas and electric energy costs, various renewable resources and certain environmental initiatives.

5. Borrowings and Other Financing Instruments

Short-Term Borrowings

Short-Term Debt — Xcel Energy meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under their credit facilities and term loan agreements.

Commercial paper and term loan borrowings outstanding:

(Millions of Dollars, Except Interest Rates)		Three Months Ended Dec. 31, 2019				Year Ended Dec. 31
		2019				2018				2017
Borrowing limit		$	3,600			$	3,600			$	3,250			$	3,250
Amount outstanding at period end		595				595				1,038				814
Average amount outstanding		663				1,115				788				644
Maximum amount outstanding		945				1,780				1,349				1,247
Weighted average interest rate, computed on a daily basis		2.40		%		2.72		%		2.34		%		1.35		%
Weighted average interest rate at end of period		2.34				2.34				2.97				1.90

Term Loan Agreement — In December 2019, Xcel Energy Inc. entered into a $500 million 364-Day Term Loan Agreement to pay down borrowings and terminate the expiring $500 million term loan made to Xcel Energy under the 364-Day Term Loan Agreement dated as of Dec. 4, 2018. The loan is unsecured and matures Dec. 1, 2020. Xcel Energy has an option to request an extension through Nov. 30, 2021. Term loan includes one financial covenant, requiring Xcel Energy’s consolidated funded debt to total capitalization ratio to be less than or equal to 65 percent. Interest is at a rate equal to either the Eurodollar rate, plus 50.0 basis points, or an alternate base rate.

Term loan borrowings as of Dec. 31, 2019:

(Millions of Dollars)		Limit				Amount Used				Available
Xcel Energy Inc.		$	500			$	500			$	—

Bilateral Credit Agreement — In March 2019, NSP-Minnesota entered into a one-year uncommitted bilateral credit agreement. The agreement is limited in use to support letters of credit.

As of Dec. 31, 2019, outstanding letters of credit under the Bilateral Credit Agreement were as follows:

(Millions of Dollars)		Limit				Amount Used				Available
NSP-Minnesota		$	75			$	22			$	53

Letters of Credit — Xcel Energy uses letters of credit, typically with terms of one year, to provide financial guarantees for certain operating obligations. As of Dec. 31, 2019 and 2018, there were $20 million and $49 million of letters of credit outstanding under the credit facilities. Amounts approximate their fair value.

Credit Facilities — In order to use commercial paper programs to fulfill short-term funding needs, Xcel Energy Inc. and its utility subsidiaries must have revolving credit facilities in place at least equal to the amount of their respective commercial paper borrowing limits and cannot issue commercial paper in an aggregate amount exceeding available capacity under these credit facilities. The lines of credit provide short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.

Amended Credit Agreements — In June 2019, Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS entered into amended five-year credit agreements with a syndicate of banks. The total borrowing limit under the amended credit agreements was increased to $3.1 billion, with the following changes:

•	Maturity extended from June 2021 to June 2024;

•	Borrowing limit for Xcel Energy was increased from $1.0 billion to $1.25 billion;

•	Borrowing limit for SPS was increased from $400 million to $500 million; and

•	Added swingline subfacility for Xcel Energy up to $75 million

Features of the credit facilities:

		Debt-to-Total Capitalization Ratio**(a)**						Amount Facility May Be Increased (millions)				Additional Periods for Which a One-Year Extension May Be Requested (b)
		2019			2018
Xcel Energy Inc. (c)		58	%		58	%		$	200			2
NSP-Wisconsin		48			48			N/A				1
NSP-Minnesota		48			48			100				2
SPS		46			46			50				2
PSCo		44			46			100				2

(a)	Each credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65%.

(b)	All extension requests are subject to majority bank group approval.

(c)	The Xcel Energy Inc. credit facility has a cross-default provision that Xcel Energy Inc. will be in default on its borrowings under the facility if it or any of its subsidiaries (except NSP-Wisconsin as long as its total assets do not comprise more than 15% of Xcel Energy’s consolidated total assets) default on indebtedness in an aggregate principal amount exceeding $75 million.

If Xcel Energy Inc. or its utility subsidiaries do not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender. As of Dec. 31, 2019, Xcel Energy Inc. and its subsidiaries were in compliance with all financial covenants.

Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available as of Dec. 31, 2019:

(Millions of Dollars)		Credit Facility (a)				Drawn (b)				Available
Xcel Energy Inc.		$	1,250			$	—			$	1,250
PSCo		700				9				691
NSP-Minnesota		500				2				498
SPS		500				40				460
NSP-Wisconsin		150				65				85
Total		$	3,100			$	116			$	2,984

(a)	These credit facilities mature in June 2024.

(b)	Includes outstanding commercial paper and letters of credit.

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facilities. Xcel Energy Inc. and its subsidiaries had no direct advances on facilities outstanding as of Dec. 31, 2019 and 2018.

Long-Term Borrowings and Other Financing Instruments

Generally, all property of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS are subject to the liens of their first mortgage indentures. Debt premiums, discounts and expenses are amortized over the life of the related debt. The premiums, discounts and expenses for refinanced debt are deferred and amortized over the life of the new issuance.

Long term debt obligations for Xcel Energy Inc. and its utility subsidiaries as of Dec. 31 (Millions of Dollars):

Xcel Energy Inc.
Financing Instrument		Interest Rate			Maturity Date		2019				2018
Unsecured senior notes (d)		4.70	%		May 15, 2020		$	—			$	550
Unsecured senior notes		2.40			March 15, 2021		400				400
Unsecured senior notes		2.60			March 15, 2022		300				300
Unsecured senior notes		3.30			June 1, 2025		250				250
Unsecured senior notes		3.30			June 1, 2025		350				350
Unsecured senior notes		3.35			Dec. 1, 2026		500				500
Unsecured senior notes (a)		4.00			June 15, 2028		130				—
Unsecured senior notes (b)		4.00			June 15, 2028		500				500
Unsecured senior notes (a)		2.60			Dec. 1, 2029		500				—
Unsecured senior notes		6.50			July 1, 2036		300				300
Unsecured senior notes		4.80			Sept. 15, 2041		250				250
Unsecured senior notes (a)		3.50			Dec. 1, 2049		500				—
Elimination of PSCo capital lease obligation with affiliates (c)							—				(60		)
Unamortized discount							(5		)		(5		)
Unamortized debt issuance cost							(28		)		(21		)
Current maturities (capital lease obligation) (c)							—				2
Total long-term debt							$	3,947			$	3,316

(a)	2019 financing.

(b)	2018 financing.

(c)	Xcel Energy adopted ASC 842 on Jan. 1, 2019, which refers to capital leases as finance leases. Under ASC 842, the present value of future finance lease payments is included in other current liabilities and other noncurrent liabilities rather than debt.

(d)	Note was redeemed on Dec. 23, 2019.

NSP-Minnesota
Financing Instrument		Interest Rate			Maturity Date		2019				2018
First mortgage bonds		2.20	%		Aug. 15, 2020		$	300			$	300
First mortgage bonds		2.15			Aug. 15, 2022		300				300
First mortgage bonds		2.60			May 15, 2023		400				400
First mortgage bonds		7.13			July 1, 2025		250				250
First mortgage bonds		6.50			March 1, 2028		150				150
First mortgage bonds		5.25			July 15, 2035		250				250
First mortgage bonds		6.25			June 1, 2036		400				400
First mortgage bonds		6.20			July 1, 2037		350				350
First mortgage bonds		5.35			Nov. 1, 2039		300				300
First mortgage bonds		4.85			Aug. 15, 2040		250				250
First mortgage bonds		3.40			Aug. 15, 2042		500				500
First mortgage bonds		4.13			May 15, 2044		300				300
First mortgage bonds		4.00			Aug. 15, 2045		300				300
First mortgage bonds		3.60			May 15, 2046		350				350
First mortgage bonds		3.60			Sept. 15, 2047		600				600
First mortgage bonds (a)		2.90			March 1, 2050		600				—
Unamortized discount							(31		)		(21		)
Unamortized debt issuance cost							(48		)		(42		)
Current maturities							(300		)		—
Total long-term debt							$	5,221			$	4,937

(a)	2019 financing.

NSP-Wisconsin
Financing Instrument		Interest Rate			Maturity Date		2019				2018
City of La Crosse resource recovery bond		6.00	%		Nov 1, 2021		$	19			$	19
First mortgage bonds		3.30			June 15, 2024		100				100
First mortgage bonds		3.30			June 15, 2024		100				100
First mortgage bonds		6.38			Sept. 1, 2038		200				200
First mortgage bonds		3.70			Oct. 1, 2042		100				100
First mortgage bonds		3.75			Dec. 1, 2047		100				100
First mortgage bonds (a)		4.20			Sept. 1, 2048		200				200
Unamortized discount							(3		)		(3		)
Unamortized debt issuance cost							(8		)		(9		)
Total long-term debt							$	808			$	807

(a)	2018 financing.

PSCo
Financing Instrument		Interest Rate			Maturity Date		2019				2018
First mortgage bonds (d)		5.13	%		June 1, 2019		$	—			$	400
First mortgage bonds		3.20			Nov. 15, 2020		400				400
First mortgage bonds		2.25			Sept. 15, 2022		300				300
First mortgage bonds		2.50			March 15, 2023		250				250
First mortgage bonds		2.90			May 15, 2025		250				250
First mortgage bonds (b)		3.70			June 15, 2028		350				350
First mortgage bonds		6.25			Sept. 1, 2037		350				350
First mortgage bonds		6.50			Aug. 1, 2038		300				300
First mortgage bonds		4.75			Aug. 15, 2041		250				250
First mortgage bonds		3.60			Sept. 15, 2042		500				500
First mortgage bonds		3.95			March 15, 2043		250				250
First mortgage bonds		4.30			March 15, 2044		300				300
First mortgage bonds		3.55			June 15, 2046		250				250
First mortgage bonds		3.80			June 15, 2047		400				400
First mortgage bonds (b)		4.10			June 15, 2048		350				350
First mortgage bonds (a)		4.05			Sept. 15, 2049		400				—
First mortgage bonds (a)		3.20			March 1, 2050		550				—
Capital lease obligations (c)		11.20 - 14.30			2025 - 2060		—				145
Unamortized discount							(24		)		(14		)
Unamortized debt issuance cost							(41		)		(33		)
Current maturities							(400		)		(406		)
Total long-term debt							$	4,985			$	4,592

(a)	2019 financing.

(b)	2018 financing.

(c)	PSCo adopted ASC 842 on Jan. 1, 2019, which refers to capital leases as finance leases. Under ASC 842, the present value of future finance lease payments is included in other current liabilities and other noncurrent liabilities rather than debt.

(d)	Bond was redeemed on March 29, 2019.

SPS
Financing Instrument		Interest Rate			Maturity Date		2019				2018
First mortgage bonds		3.30	%		June 15, 2024		$	150			$	150
First mortgage bonds		3.30			June 15, 2024		200				200
Unsecured senior notes		6.00			Oct. 1, 2033		100				100
Unsecured senior notes		6.00			Oct. 1, 2036		250				250
First mortgage bonds		4.50			Aug. 15, 2041		200				200
First mortgage bonds		4.50			Aug. 15, 2041		100				100
First mortgage bonds		4.50			Aug. 15, 2041		100				100
First mortgage bonds		3.40			Aug. 15, 2046		300				300
First mortgage bonds		3.70			Aug. 15, 2047		450				450
First mortgage bonds (b)		4.40			Nov. 15, 2048		300				300
First mortgage bonds (a)		3.75			June 15, 2049		300				—
Unamortized discount							(7		)		(4		)
Unamortized debt issuance cost							(23		)		(20		)
Total long-term debt							$	2,420			$	2,126

(a)	2019 financing.

(b)	2018 financing.

Other Subsidiaries
Financing Instrument		Interest Rate		Maturity Date		2019				2018
Various Eloigne affordable housing project notes		0.00% - 6.90%		2020 — 2052		$	28			$	26
Current maturities						(2		)		(1		)
Total long-term debt						$	26			$	25

Maturities of long-term debt:

(Millions of Dollars)
2020		$	702
2021		421
2022		900
2023		650
2024		552

Deferred Financing Costs — Deferred financing costs of approximately $148 million and $126 million, net of amortization, are presented as a deduction from the carrying amount of long-term debt as of Dec. 31, 2019 and 2018, respectively.

Forward Equity Agreements — In November 2018, Xcel Energy Inc. entered into forward equity agreements in connection with a completed $459 million public offering of 9.4 million shares of Xcel Energy common stock. In August 2019, Xcel Energy settled the forward equity agreements by physically delivering 9.4 million shares of common equity for cash proceeds of $453 million.

In November 2019, Xcel Energy Inc. entered into forward equity agreements in connection with a completed $743 million public offering of 11.8 million shares of Xcel Energy common stock. The initial forward agreement was for 10.3 million shares with an additional agreement for 1.5 million shares exercised at the option of the banking counterparty.

At Dec. 31, 2019, the forward agreements could have been settled with physical delivery of 11.8 million common shares to the banking counterparty in exchange for cash of $739 million. The forward instruments could also have been settled at Dec. 31, 2019 with delivery of approximately $6 million of cash or approximately 0.1 million shares of common stock to the counterparty, if Xcel Energy unilaterally elected net cash or net share settlement, respectively.

The forward price used to determine amounts due at settlement is calculated based on the November 2019 public offering price for Xcel Energy’s common stock of $62.69, increased for the overnight bank funding rate, less a spread of 0.75% and less expected dividends on Xcel Energy’s common stock during the period the instruments are outstanding.

Xcel Energy may settle the agreements at any time up to the maturity date of Dec. 31, 2020. Depending on settlement timing, cash proceeds are expected to be approximately $730 million to $740 million.

Forward equity instruments were recognized within stockholders’ equity at fair value at execution of the agreements and will not be subsequently adjusted until settlement.

Other Equity — Xcel Energy issued $39 million of equity annually through the DRIP program during the years ended Dec. 31, 2019 and 2018, respectively. Program allows stockholders to elect dividend reinvestment in Xcel Energy common stock through a non-cash transaction. See Note 8 for equity items related to share based compensation.

Capital Stock — Preferred stock authorized/outstanding:

		Preferred Stock Authorized (Shares)			Par Value of Preferred Stock				Preferred Stock Outstanding (Shares) 2019 and 2018
Xcel Energy Inc.		7,000,000			$	100			—
PSCo		10,000,000			0.01				—
SPS		10,000,000			1.00				—

Xcel Energy Inc. had the following common stock authorized/outstanding:

Common Stock Authorized (Shares)			Par Value of Common Stock				Common Stock Outstanding (Shares) as of Dec. 31, 2019			Common Stock Outstanding (Shares) as of Dec. 31, 2018
1,000,000,000			$	2.50			524,539,000			514,036,787

Dividend and Other Capital-Related Restrictions — Xcel Energy depends on its subsidiaries to pay dividends. Xcel Energy Inc.’s utility subsidiaries’ dividends are subject to the FERC’s jurisdiction, which prohibits the payment of dividends out of capital accounts. Dividends are solely to be paid from retained earnings. Certain covenants also require Xcel Energy Inc. to be current on interest payments prior to dividend disbursements.

State regulatory commissions impose dividend limitations for NSP-Minnesota, NSP-Wisconsin and SPS, which are more restrictive than those imposed by the FERC. Requirements and actuals as of Dec. 31, 2019:

		Equity to Total Capitalization Ratio Required Range						Equity to Total Capitalization Ratio Actual
		Low			High			2019
NSP-Minnesota		47.1	%		57.5	%		52.3	%
NSP-Wisconsin		51.5			N/A			51.8
SPS (a)		45.0			55.0			54.4

(a)	Excludes short-term debt.

(Amounts in Millions)		Unrestricted Retained Earnings				Total Capitalization				Limit on Total Capitalization
NSP-Minnesota		$	1,147			$	11,634			$	12,700
NSP-Wisconsin (a)		12				1,827				N/A
SPS (b)		535				5,304				N/A

(a)	Cannot pay annual dividends in excess of approximately $55 million if its average equity-to-total capitalization ratio falls below the commission authorized level.

(b)	May not pay a dividend that would cause a loss of its investment grade bond rating.

Issuance of securities by Xcel Energy Inc. generally is not subject to regulatory approval. However, utility financings and intra-system financings are subject to the jurisdiction of state regulatory commissions and/or the FERC. Xcel Energy may seek additional authorization as necessary.

Amounts authorized to issue as of Dec. 31, 2019:

(Millions of Dollars)		Long-Term Debt				Short-Term Debt
NSP-Minnesota		52.93% of total capitalization			(a)	$	1,905		(a)
NSP-Wisconsin		$	—		(b)	150
SPS		—			(c)	600
PSCo		150				800

(a)	NSP-Minnesota has authorization to issue long-term securities provided the equity-to-total capitalization remains within the required range, and to issue short-term debt provided it does not exceed 15% of total capitalization.

(b)	NSP-Wisconsin filed for additional long-term debt authorization in December 2019.

(c)	SPS filed for additional long-term debt authorization in February 2020.

6. Revenues

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

		Year Ended Dec. 31, 2019
(Millions of Dollars)		Electric				Natural Gas				All Other				Total
Major revenue types
Revenue from contracts with customers:
Residential		$	2,877			$	1,127			$	41			$	4,045
C&I		4,844				567				29				5,440
Other		130				—				4				134
Total retail		7,851				1,694				74				9,619
Wholesale		737				—				—				737
Transmission		507				—				—				507
Other		49				120				—				169
Total revenue from contracts with customers		9,144				1,814				74				11,032
Alternative revenue and other		431				54				12				497
Total revenues		$	9,575			$	1,868			$	86			$	11,529

		Year Ended Dec. 31, 2018
(Millions of Dollars)		Electric				Natural Gas				All Other				Total
Major revenue types
Revenue from contracts with customers:
Residential		$	2,919			$	988			$	38			$	3,945
C&I		4,874				524				25				5,423
Other		134				—				6				140
Total retail		7,927				1,512				69				9,508
Wholesale		791				—				—				791
Transmission		523				—				—				523
Other		98				100				—				198
Total revenue from contracts with customers		9,339				1,612				69				11,020
Alternative revenue and other		380				127				10				517
Total revenues		$	9,719			$	1,739			$	79			$	11,537

7. Income Taxes

Federal Tax Reform — In 2017, the TCJA was signed into law. The key provisions impacting Xcel Energy, generally beginning in 2018, included:

•	Corporate federal tax rate reduction from 35% to 21%;

•	Normalization of resulting plant-related excess deferred taxes;

•	Elimination of the corporate alternative minimum tax;

•	Continued interest expense deductibility and discontinued bonus depreciation for regulated public utilities;

•	Limitations on certain executive compensation deductions;

•	Limitations on certain deductions for NOLs arising after Dec. 31, 2017 (limited to 80% of taxable income);

•	Repeal of the section 199 manufacturing deduction; and

•	Reduced deductions for meals and entertainment as well as state and local lobbying.

Reductions in deferred tax assets and liabilities due to a decrease in corporate federal tax rates typically result in a net tax benefit. However, the impacts are primarily recognized as regulatory liabilities refundable to utility customers as a result of IRS requirements and past regulatory treatment.

Estimated impacts of the new tax law in December 2017 included:

•	$2.7 billion ($3.8 billion grossed-up for tax) of reclassifications of plant-related excess deferred taxes to regulatory liabilities upon valuation at the new 21% federal rate. The regulatory liabilities will be amortized consistent with IRS normalization requirements, resulting in customer refunds over an estimated weighted average period of approximately 30 years;

•	$254 million and $174 million of reclassifications (grossed-up for tax) of excess deferred taxes for non-plant related deferred tax assets and liabilities, respectively, to regulatory assets and liabilities; and

•	$23 million of total estimated income tax expense related to the tax rate change on certain non-plant deferred taxes and all other 2017 income statement impacts of the federal tax reform.

Xcel Energy accounted for the state tax impacts of federal tax reform based on enacted state tax laws. Any future state tax law changes related to the TCJA will be accounted for in the periods state laws are enacted.

Federal Audit — Statute of limitations applicable to Xcel Energy’s consolidated federal income tax returns:

Tax Year(s)		Expiration
2009 - 2013		June 2020
2014 - 2016		September 2020

In 2015, the IRS commenced an examination of tax years 2012 and 2013. In 2017, the IRS concluded the audit of tax years 2012 and 2013 and proposed an adjustment that would impact Xcel Energy’s NOL and ETR. Xcel Energy filed a protest with the IRS. As of Dec. 31, 2019, the case has been forwarded to the Office of Appeals and Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of this issue; however, the outcome and timing of a resolution is unknown.

In 2018, the IRS began an audit of tax years 2014 - 2016. As of Dec. 31, 2019, no adjustments have been proposed.

State Audits — Xcel Energy files consolidated state tax returns based on income in its major operating jurisdictions and various other state income-based tax returns.

As of Dec. 31, 2019, Xcel Energy’s earliest open tax years (subject to examination by state taxing authorities in its major operating jurisdictions) were as follows:

State		Year
Colorado		2009
Minnesota		2009
Texas		2009
Wisconsin		2014

•	In 2018, Wisconsin began an audit of tax years 2014 - 2016. As of Dec. 31, 2019, no material adjustments have been proposed.

•	Xcel Energy had no other state income tax audits in progress for its major operating jurisdictions as of Dec. 31, 2019.

Unrecognized Tax Benefits — Unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual ETR. In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain, but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the ETR but would accelerate the payment to the taxing authority to an earlier period.

Unrecognized tax benefits - permanent vs. temporary:

(Millions of Dollars)		Dec. 31, 2019				Dec. 31, 2018
Unrecognized tax benefit — Permanent tax positions		$	35			$	28
Unrecognized tax benefit — Temporary tax positions		9				9
Total unrecognized tax benefit		$	44			$	37

Changes in unrecognized tax benefits:

(Millions of Dollars)		2019				2018				2017
Balance at Jan. 1		$	37			$	39			$	134
Additions based on tax positions related to the current year		10				9				6
Reductions based on tax positions related to the current year		(4		)		(4		)		(4		)
Additions for tax positions of prior years		1				2				15
Reductions for tax positions of prior years		—				(4		)		(105		)
Settlements with taxing authorities		—				(5		)		(7		)
Balance at Dec. 31		$	44			$	37			$	39

Unrecognized tax benefits were reduced by tax benefits associated with NOL and tax credit carryforwards:

(Millions of Dollars)		Dec. 31, 2019				Dec. 31, 2018
NOL and tax credit carryforwards		$	(40	)		$	(35	)

Net deferred tax liability associated with the unrecognized tax benefit amounts and related NOLs and tax credits carryforwards were $29 million and $24 million at Dec. 31, 2019 and Dec. 31, 2018, respectively.

As the IRS Appeals and federal and state audits progress and other state audits resume, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $28 million in the next 12 months.

Payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards.

No amounts were payable for interest related to unrecognized tax benefits as of Dec. 31, 2019, 2018 or 2017. No interest income related to unrecognized tax benefits was recorded in 2019 or 2018, and $3 million was recorded in 2017.

No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2019, 2018 or 2017.

Other Income Tax Matters — NOL amounts represent the tax loss that is carried forward and tax credits represent the deferred tax asset. NOL and tax credit carryforwards as of Dec. 31:

(Millions of Dollars)		2019				2018
Federal tax credit carryforwards		$	639			$	553
Valuation allowances for federal credit carryforwards		—				(5		)
State NOL carryforwards		937				1,104
Valuation allowances for state NOL carryforwards		(19		)		(50		)
State tax credit carryforwards, net of federal detriment (a)		89				89
Valuation allowances for state credit carryforwards, net of federal benefit (b)		(66		)		(69		)

(a)	State tax credit carryforwards are net of federal detriment of $24 million as of Dec. 31, 2019 and 2018.

(b)	Valuation allowances for state tax credit carryforwards were net of federal benefit of $17 million and $18 million as of Dec. 31, 2019 and 2018, respectively.

Federal carryforward periods expire between 2023 and 2039 and state carryforward periods expire between 2020 and 2036.

Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense.

Effective income tax rate for years ended Dec. 31:

	2019			2018 (a)			2017 (a)
Federal statutory rate	21.0	%		21.0	%		35.0	%
State income tax on pretax income, net of federal tax effect	4.9			5.0			4.1
Increases (decreases) in tax from:
Wind PTCs	(9.4	)		(5.2	)		(4.7	)
Plant regulatory differences (b)	(5.8	)		(6.2	)		(0.8	)
Other tax credits, net of NOL & tax credit allowances	(1.7	)		(1.7	)		(1.0	)
Change in unrecognized tax benefits	0.5			0.4			(0.6	)
Tax reform	—			—			1.4
Other, net	(1.0	)		(0.7	)		(1.3	)
Effective income tax rate	8.5	%		12.6	%		32.1	%

(a)	Prior periods have been reclassified to conform to current year presentation.

(b)	Regulatory differences for income tax primarily relate to the credit of excess deferred taxes to customers through the average rate assumption method. Income tax benefits associated with the credit of excess deferred credits are offset by corresponding revenue reductions and additional prepaid pension asset amortization.

Components of income tax expense for years ended Dec. 31:

(Millions of Dollars)		2019				2018				2017
Current federal tax (benefit) expense		$	(16	)		$	(34	)		$	1
Current state tax expense (benefit)		4				8				(11		)
Current change in unrecognized tax expense (benefit)		2				(6		)		(83		)
Deferred federal tax expense		55				122				460
Deferred state tax expense		83				85				107
Deferred change in unrecognized tax expense		5				11				73
Deferred ITCs		(5		)		(5		)		(5		)
Total income tax expense		$	128			$	181			$	542

Components of deferred income tax expense as of Dec. 31:

(Millions of Dollars)		2019				2018				2017
Deferred tax expense (benefit) excluding items below		$	344			$	320			$	(2,939	)
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities		(206		)		(102		)		3,583
Tax benefit (expense) allocated to other comprehensive income, net of adoption of ASU No. 2018-02, and other		5				—				(4		)
Deferred tax expense		$	143			$	218			$	640

Components of net deferred tax liability as of Dec. 31:

(Millions of Dollars)		2019				2018 (a)
Deferred tax liabilities:
Differences between book and tax bases of property		$	5,474			$	5,082
Operating lease assets		449				—
Regulatory assets		598				599
Pension expense		173				178
Other		70				60
Total deferred tax liabilities		$	6,764			$	5,919
Deferred tax assets:
Regulatory liabilities		$	847			$	879
Operating lease liabilities		449				—
Tax credit carryforward		727				642
NOL carryforward		38				51
NOL and tax credit valuation allowances		(67		)		(79		)
Other employee benefits		128				124
Deferred ITCs		14				16
Rate refund		26				60
Other		93				61
Total deferred tax assets		$	2,255			$	1,754
Net deferred tax liability		$	4,509			$	4,165

(a) Prior periods have been reclassified to conform to current year presentation.

8. Share-Based Compensation

Incentive Plans Including Share-Based Compensation — Xcel Energy has two incentive plans which include share-based payment elements. Plans and authorized equity shares for awards:

•	Omnibus Incentive Plan - 7.0 million shares; and

•	Executive Annual Incentive Award Plan - 1.2 million shares.

Restricted Stock — The Executive Annual Incentive Award Plan and Omnibus Incentive Plan allow certain employees to elect to receive shares of common or restricted stock. Restricted stock is treated as an equity award and vests and settles in equal annual installments over a three-year period. Restricted stock has a fair value equal to the market trading price of Xcel Energy stock at the grant date.

Shares of restricted stock granted at Dec. 31:

(Shares in Thousands)		2019				2018				2017
Granted shares		13				18				15
Grant date fair value		$	53.46			$	44.68			$	42.00

Changes in nonvested restricted stock:

(Shares in Thousands)		Shares			Weighted Average Grant Date Fair Value
Nonvested restricted stock at Jan. 1, 2019		36			$	44.29
Granted		13			53.46
Forfeited		—			—
Vested		(19	)		41.60
Dividend equivalents		1			57.09
Nonvested restricted stock at Dec. 31, 2019		31			50.15

Other Equity Awards — Xcel Energy‘s Board of Directors has granted equity awards under the Omnibus Incentive Plan, which includes various vesting conditions and performance goals. At the end of the restricted period, such grants will be awarded if vesting conditions and/or performance goals are met.

Certain employees are granted equity awards with a portion subject only to service conditions, and the other portion subject to performance conditions. A total of 0.3 million time-based equity shares subject only to service conditions were granted annually in 2019, 2018 and 2017, respectively.

The performance conditions for a portion of the awards granted from 2017 to 2019 are based on relative TSR and environmental goals. Equity awards with performance conditions will be settled or forfeited after three years, with payouts ranging from zero to 200 percent depending on achievement.

Equity award units granted to employees (excluding restricted stock):

(Units in Thousands)		2019				2018				2017
Granted units		483				500				503
Weighted average grant date fair value		$	49.67			$	47.60			$	41.02

Equity awards vested:

(Units in Thousands)		2019				2018				2017
Vested Units		464				475				467
Total Fair Value		$	29,432			$	23,393			$	22,459

Changes in the nonvested portion of equity award units:

(Units in Thousands)		Units			Weighted Average Grant Date Fair Value
Nonvested Units at Jan. 1, 2019		939			$	44.30
Granted		483			49.67
Forfeited		(116	)		50.19
Vested		(464	)		41.09
Dividend equivalents		38			45.22
Nonvested Units at Dec. 31, 2019		880			48.20

Stock Equivalent Units — Non-employee members of Xcel Energy‘s Board of Directors may elect to receive their annual equity grant as stock equivalent units in lieu of common stock. Each unit’s value is equal to one share of common stock. The annual equity grant is vested as of the date of each member’s election to the Board of Directors; there is no further service or other condition. Directors may also elect to receive their cash fees as stock equivalent units in lieu of cash. Stock equivalent units are payable as a distribution of common stock upon a director’s termination of service.

Stock equivalent units granted:

(Units in Thousands)		2019				2018				2017
Granted units		29				36				51
Weighted average grant date fair value		$	58.44			$	45.44			$	46.05

Changes in stock equivalent units:

(Units in Thousands)		Units			Weighted Average Grant Date Fair Value
Stock equivalent units at Jan. 1, 2019		688			$	30.93
Granted		29			58.44
Units distributed		(11	)		32.56
Dividend equivalents		19			57.28
Stock equivalent units at Dec. 31, 2019		725			32.72

TSR Liability Awards — Xcel Energy Inc.’s Board of Directors has granted TSR liability awards under the Omnibus Incentive Plan. This plan allows Xcel Energy to attach various performance goals to the awards granted. The liability awards have been historically dependent on relative TSR measured over a three-year period. Xcel Energy Inc.’s TSR is compared to a peer group of 20 other utility members. Potential payouts of the awards range from zero to 200%.

TSR liability awards granted:

(In Thousands)		2019			2018			2017
Awards granted		225			239			240

TSR liability awards settled:

(In Thousands)		2019				2018				2017
Awards settled		466				482				454
Settlement amount (cash, common stock and deferred amounts)		$	24,930			$	21,534			$	19,083

TSR liability awards of $21 million were settled in cash in 2019.

Share-Based Compensation Expense — Other than for restricted stock, vesting of employee equity awards is typically predicated on the achievement of a TSR or environmental measures target. Additionally, approximately 0.3 million of equity award units were granted annually in 2017 - 2019, with vesting subject only to service conditions of three years.

Generally, these instruments are considered to be equity awards as the award settlement determination (shares or cash) is made by Xcel Energy, not the participants. In addition, these awards have not been previously settled in cash and Xcel Energy plans to continue electing share settlement.

Grant date fair value of equity awards is expensed over the service period. TSR liability awards have been historically settled partially in cash, and do not qualify as equity awards, but rather are accounted for as liabilities. As liability awards, the fair value on which ratable expense is based, as employees vest in their rights to those awards, is remeasured each period based on the current stock price and performance achievement, and final expense is based on the market value of the shares on the date the award is settled.

Compensation costs related to share-based awards:

(Millions of Dollars)		2019				2018				2017
Compensation cost for share-based awards (a)		$	58			$	45			$	57
Tax benefit recognized in income		15				12				22

(a)	Compensation costs for share-based payment are included in O&M expense.

There was approximately $40 million in 2019 and $38 million in 2018 of total unrecognized compensation cost related to nonvested share-based compensation awards. Xcel Energy expects to recognize the unrecognized amount over a weighted average period of 1.6 years.

9. Earnings Per Share

Basic EPS was computed by dividing the earnings available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS was computed by dividing the earnings available to common shareholders by the diluted weighted average number of common shares outstanding during the period. Diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock (i.e., common stock equivalents) were settled. The weighted average number of potentially dilutive shares outstanding used to calculate diluted EPS is calculated using the treasury stock method.

Common Stock Equivalents — Xcel Energy Inc. has common stock equivalents related to forward equity agreements and certain equity awards in share-based compensation arrangements. Common stock equivalents include commitments to issue common stock related to time-based equity compensation awards.

Stock equivalent units granted to Xcel Energy’s Board of Directors are included in common shares outstanding upon grant date as there is no further service, performance or market condition associated with these. Restricted stock issued to employees under the Executive Annual Incentive Award Plan is included in common shares outstanding when granted.

Share-based compensation arrangements for which there is currently no dilutive impact to EPS include the following:

•	Equity awards subject to a performance condition; included in common shares outstanding when all necessary conditions for settlement have been satisfied by the end of the reporting period; and

•	Liability awards subject to a performance condition; any portions settled in shares are included in common shares outstanding upon settlement.

Diluted common shares outstanding included common stock equivalents of 1.3 million, 0.5 million and 0.6 million shares for 2019, 2018 and 2017.

10. Fair Value of Financial Assets and Liabilities

Fair Value Measurements

Accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires disclosures about assets and liabilities measured at fair value. A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance.

•	Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices;

•	Level 2 — Pricing inputs are other than quoted prices in active markets but are either directly or indirectly observable as of the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts or priced with models using highly observable inputs; and

•	Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those valued with models requiring significant management judgment or estimation.

Specific valuation methods include:

Cash equivalents — The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted NAV.

Investments in equity securities and other funds — Equity securities are valued using quoted prices in active markets. The fair values for commingled funds are measured using NAVs. The investments in commingled funds may be redeemed for NAV with proper notice. Private equity commingled fund investments require approval of the fund for any unscheduled redemption, and such redemptions may be approved or denied by the fund at its sole discretion. Unscheduled distributions from real estate commingled funds investments 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 contractual settlements relate to inactive delivery locations or extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable forecasts of forward prices and volatilities on a valuation is evaluated and may result in Level 3 classification.

Electric commodity derivatives held by NSP-Minnesota and SPS include transmission congestion instruments, generally referred to as FTRs. FTRs purchased from a RTO are financial instruments that entitle or obligate the holder to monthly revenues or charges based on transmission congestion across a given transmission path.

The value of an FTR is derived from, and designed to offset, the cost of transmission congestion. In addition to overall transmission load, congestion is also influenced by the operating schedules of power plants and the consumption of electricity pertinent to a given transmission path. Unplanned plant outages, scheduled plant maintenance, changes in the relative costs of fuels used in generation, weather and overall changes in demand for electricity can each impact the operating schedules of the power plants on the transmission grid and the value of an FTR.

If forecasted costs of electric transmission congestion increase or decrease for a given FTR path, the value of that particular FTR instrument will likewise increase or decrease. Given the limited observability of certain inputs to the value of FTRs between auction processes, including expected plant operating schedules and retail and wholesale demand, fair value measurements for FTRs have been assigned a Level 3.

Non-trading monthly FTR settlements are included in fuel and purchased energy cost recovery mechanisms as applicable in each jurisdiction, and therefore changes in the fair value of the yet to be settled portions of most FTRs are deferred as a regulatory asset or liability. Given this regulatory treatment and the limited magnitude of FTRs relative to the electric utility operations of NSP-Minnesota and SPS, the numerous unobservable quantitative inputs pertinent to the value of FTRs are immaterial to the consolidated financial statements.

Non-Derivative Fair Value Measurements

Nuclear Decommissioning Fund

The NRC requires NSP-Minnesota to maintain a portfolio of investments to fund the costs of decommissioning its nuclear generating plants. Assets of the nuclear decommissioning fund are legally restricted for the purpose of decommissioning these facilities. The fund contains cash equivalents, debt securities, equity securities and other investments. NSP-Minnesota uses the MPUC approved asset allocation for the escrow and investment targets by asset class for both the escrow and 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 $706 million and $450 million as of Dec. 31, 2019 and 2018, respectively, and unrealized losses were $6 million and $45 million as of Dec. 31, 2019 and 2018, respectively.

Non-derivative instruments with recurring fair value measurements:

		Dec. 31, 2019
						Fair Value
(Millions of Dollars)		Cost				Level 1				Level 2				Level 3				NAV				Total
Nuclear decommissioning fund (a)
Cash equivalents		$	33			$	33			$	—			$	—			$	—			$	33
Commingled funds		733				—				—				—				935				935
Debt securities		489				—				495				13				—				508
Equity securities		485				962				2				—				—				964
Total		$	1,740			$	995			$	497			$	13			$	935			$	2,440

(a)	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $155 million of equity investments in unconsolidated subsidiaries and $136 million of rabbi trust assets and miscellaneous investments.

		Dec. 31, 2018
						Fair Value
(Millions of Dollars)		Cost				Level 1				Level 2				Level 3				NAV				Total
Nuclear decommissioning fund (a)
Cash equivalents		$	24			$	24			$	—			$	—			$	—			$	24
Commingled funds		758				79				—				—				819				898
Debt securities		466				—				436				—				—				436
Equity securities		401				697				—				—				—				697
Total		$	1,649			$	800			$	436			$	—			$	819			$	2,055

(a)	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $141 million of equity investments in unconsolidated subsidiaries and $121 million of rabbi trust assets and miscellaneous investments.

For the years ended Dec. 31, 2019 and 2018, there were immaterial Level 3 nuclear decommissioning fund investments or transfer of amounts between levels.

Contractual maturity dates of debt securities in the nuclear decommissioning fund as of Dec. 31, 2019:

		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		$	(7	)		$	111			$	246			$	158			$	508

Rabbi Trusts

Xcel Energy has established rabbi trusts to provide partial funding for future distributions of its SERP and deferred compensation plan.

Cost and fair value of assets held in rabbi trusts:

		Dec. 31, 2019
						Fair Value
(Millions of Dollars)		Cost				Level 1				Level 2				Level 3				Total
Rabbi Trusts (a)
Cash equivalents		$	17			$	17			$	—			$	—			$	17
Mutual funds		57				65				—				—				65
Total		$	74			$	82			$	—			$	—			$	82

(a)	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet.

		Dec. 31, 2018
						Fair Value
(Millions of Dollars)		Cost				Level 1				Level 2				Level 3				Total
Rabbi Trusts (a)
Cash equivalents		$	16			$	16			$	—			$	—			$	16
Mutual funds		52				51				—				—				51
Total		$	68			$	67			$	—			$	—			$	67

(a)	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet.

Derivative Fair Value Measurements

Xcel Energy enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to manage risk in connection with changes in interest rates, utility commodity prices and vehicle fuel prices.

Interest Rate Derivatives — Xcel Energy enters into various instruments that effectively fix the interest payments on certain floating rate debt obligations or effectively fix the yield or price on a specified benchmark interest rate for an anticipated debt issuance for a specific period. These derivative instruments are generally designated as cash flow hedges for accounting purposes.

As of Dec. 31, 2019, accumulated other comprehensive losses related to interest rate derivatives included $5 million of net losses expected to be reclassified into earnings during the next 12 months as the hedged transactions impact earnings.

As of Dec. 31, 2019, Xcel Energy had no unsettled interest rate swaps outstanding. These interest rate derivatives were designated as hedges, and as such, changes in fair value are recorded to other comprehensive income.

Wholesale and Commodity Trading Risk — Xcel Energy Inc.’s utility subsidiaries conduct various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. Xcel Energy is allowed to conduct these activities within guidelines and limitations as approved by its risk management committee, comprised of management personnel not directly involved in activities governed by this policy.

Commodity Derivatives — Xcel Energy enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric and natural gas operations, as well as for trading purposes. This could include the purchase or sale of energy or energy-related products, natural gas to generate electric energy, natural gas for resale, FTRs, vehicle fuel and weather derivatives.

As of Dec. 31, 2019, Xcel Energy had no commodity derivative contracts designated as cash flow hedges. Xcel Energy may enter into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but may not be designated as qualifying hedging transactions. Changes in the fair value of non-trading commodity derivative instruments are recorded in other comprehensive income or deferred as a regulatory asset or liability. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. Immaterial amounts to income related to the ineffectiveness of cash flow hedges were recorded for the years ended Dec. 31, 2019 and 2018.

As of Dec. 31, 2019, there were no net gains related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses or related amounts expected to be reclassified into earnings during the next 12 months.

Xcel Energy enters into commodity derivative instruments for trading purposes not directly related to commodity price risks associated with serving its electric and natural gas customers. Changes in the fair value of these commodity derivatives are recorded in electric operating revenues, net of amounts credited to customers under margin-sharing mechanisms.

Gross notional amount of commodity forwards, options and FTRs at Dec. 31:

(Millions of Dollars) (a) (b)		2019			2018
MWh of electricity		95			87
MMBtu of natural gas		110			92

(a)	Amounts are not reflective of net positions in the underlying commodities.

(b)	Notional amounts for options are included on a gross basis but weighted for the probability of exercise.

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 in 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 Dec. 31, 2019, six of Xcel Energy’s 10 most significant counterparties for these activities, comprising $154 million or 60% of this credit exposure, had investment grade credit ratings from Standard & Poor’s, Moody’s Investor Services or Fitch Ratings. Four of the 10 most significant counterparties, comprising $37 million or 14% of this credit exposure, were not rated by these external agencies, but based on Xcel Energy’s internal analysis, had credit quality consistent with investment grade. Nine of these significant counterparties are municipal or cooperative electric entities, RTOs or other utilities.

Qualifying Cash Flow Hedges — Financial impact of qualifying interest rate and vehicle fuel cash flow hedges on Xcel Energy’s accumulated other comprehensive loss, included in the consolidated statements of common stockholders’ equity and in the consolidated statements of comprehensive income:

(Millions of Dollars)		2019				2018				2017
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1		$	(60	)		$	(58	)		$	(51	)
After-tax net unrealized losses related to derivatives accounted for as hedges		(23		)		(5		)		—
After-tax net realized losses on derivative transactions reclassified into earnings		3				3				3
Adoption of ASU. 2018-02 (a)		—				—				(10		)
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31		$	(80	)		$	(60	)		$	(58	)

(a)	In 2017, Xcel Energy implemented ASU No 2018-02 related to TCJA, which resulted in reclassification of certain credit balances within net accumulated other comprehensive loss to retained earnings.

Impact of derivative activity:

		Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:
(Millions of Dollars)		Accumulated Other Comprehensive Loss				Regulatory (Assets) and Liabilities
Year Ended Dec. 31, 2019
Derivatives designated as cash flow hedges
Interest rate		$	(30	)		$	—
Total		(30		)		—
Other derivative instruments
Electric commodity		—				8
Natural gas commodity		—				(9		)
Total		—				(1		)
Year Ended Dec. 31, 2018
Interest rate		(7		)		—
Total		(7		)		—
Other derivative instruments
Electric commodity		—				1
Natural gas commodity		—				10
Total		—				11
Year Ended Dec. 31, 2017
Other derivative instruments
Electric commodity		—				10
Natural gas commodity		—				(13		)
Total		$	—			$	(3	)

	Pre-Tax (Gains) Losses Reclassified into Income During the Period from:								Pre-Tax Gains (Losses) Recognized During the Period in Income
(Millions of Dollars)	Accumulated Other Comprehensive Loss				Regulatory Assets and (Liabilities)
Year Ended Dec. 31, 2019
Derivatives designated as cash flow hedges
Interest rate	$	4		(a)	$	—			$	—
Total	4				—				—
Other derivative instruments
Commodity trading	—				—				2			(b)
Electric commodity	—				(5		)	(c)	—
Natural gas commodity	—				2			(d)	(7		)	(d)
Total	—				(3		)		(5		)
Year Ended Dec. 31, 2018
Derivatives designated as cash flow hedges
Interest rate	4			(a)	—				—
Total	4				—				—
Other derivative instruments
Commodity trading	—				—				14			(b)
Electric commodity	—				(1		)	(c)	—
Natural gas commodity	—				(6		)	(d)	(4		)	(d)
Total	—				(7		)		10
Year Ended Dec. 31, 2017
Derivatives designated as cash flow hedges
Interest rate	5			(a)	—				—
Total	5				—				—
Other derivative instruments
Commodity trading	—				—				10			(b)
Electric commodity	—				(15		)	(c)	—
Natural gas commodity	—				3			(d)	(6		)	(d)
Total	$	—			$	(12	)		$	4

(a)	Amounts recorded to interest charges.

(b)	Amounts recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate.

(c)	Amounts recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms and reclassified out of income as regulatory assets or liabilities, as appropriate.

(d)

Amounts for the year ended Dec. 31, 2019 included no settlement losses on derivatives entered to mitigate natural gas price risk for electric generation recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. Such losses and gains for the years ended Dec. 31, 2018 and 2017 were $1 million and immaterial, respectively. Remaining settlement losses for the years ended Dec. 31, 2019, 2018 and 2017 related to natural gas operations and were recorded to cost of natural gas sold and transported. These losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset, as appropriate.

Xcel Energy had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2019, 2018 and 2017.

Credit Related Contingent Features — Contract provisions for derivative instruments that the utility subsidiaries enter, including those accounted for as normal purchase-normal sale contracts and therefore not reflected on the consolidated balance sheets, may require the posting of collateral or settlement of the contracts for various reasons, including if the applicable utility subsidiary’s credit ratings are downgraded below its investment grade credit rating by any of the major credit rating agencies, or for cross default contractual provisions if there was a failure under other financing arrangements related to payment terms or other covenants. As of Dec. 31, 2019 and 2018, the amounts for derivative instruments in a liability position with such underlying contract provisions were $7 million and none, 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 Dec. 31, 2019 and 2018.

Recurring Fair Value Measurements — Xcel Energy’s derivative assets and liabilities measured at fair value on a recurring basis:

		Dec. 31, 2019																								Dec. 31, 2018
		Fair Value												Fair Value Total				Netting (a)								Fair Value												Fair Value Total				Netting (a)
(Millions of Dollars)		Level 1				Level 2				Level 3						Total				Level 1				Level 2				Level 3						Total
Current derivative assets
Commodity trading		$	3			$	51			$	24			$	78			$	(52	)		$	26			$	4			$	92			$	2			$	98			$	(44	)		$	54
Electric commodity		—				—				21				21				(1		)		20				—				—				25				25				—				25
Natural gas commodity		—				6				—				6				—				6				—				4				—				4				—				4
Total current derivative assets		$	3			$	57			$	45			$	105			$	(53	)		52				$	4			$	96			$	27			$	127			$	(44	)		83
PPAs (b)																						3																								4
Current derivative instruments																						$	55																							$	87
Noncurrent derivative assets
Other derivative instruments:
Commodity trading		$	9			$	38			$	7			$	54			$	(45	)		$	9			$	—			$	27			$	5			$	32			$	(14	)		$	18
Total noncurrent derivative assets		$	9			$	38			$	7			$	54			$	(45	)		9				$	—			$	27			$	5			$	32			$	(14	)		18
PPAs (b)																						13																								16
Noncurrent derivative instruments																						$	22																							$	34

		Dec. 31, 2019																								Dec. 31, 2018
		Fair Value												Fair Value Total				Netting (a)								Fair Value												Fair Value Total				Netting (a)
(Millions of Dollars)		Level 1				Level 2				Level 3						Total				Level 1				Level 2				Level 3						Total
Current derivative liabilities
Derivatives designated as cash flow hedges:
Interest rate		$	—			$	—			$	—			$	—			$	—			$	—			$	—			$	7			$	—			$	7			$	—			$	7
Other derivative instruments:
Commodity trading		4				59				15				78				(63		)		15				4				88				2				94				(60		)		34
Electric commodity		—				—				1				1				(1		)		—				—				—				—				—				—				—
Natural gas commodity		—				5				—				5				—				5				—				—				—				—				—				—
Total current derivative liabilities		$	4			$	64			$	16			$	84			$	(64	)		20				$	4			$	95			$	2			$	101			$	(60	)		41
PPAs (b)																						18																								20
Current derivative instruments																						$	38																							$	61
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading		$	2			$	79			$	32			$	113			$	(13	)		$	100			$	—			$	18			$	1			$	19			$	17			$	36
Total noncurrent derivative liabilities		$	2			$	79			$	32			$	113			$	(13	)		100				$	—			$	18			$	1			$	19			$	17			36
PPAs (b)																						75																								93
Noncurrent derivative instruments																						$	175																							$	129

(a)

Xcel Energy nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement and all derivative instruments and related collateral amounts were subject to master netting agreements as of Dec. 31, 2019 and 2018. At both Dec. 31, 2019 and 2018, derivative assets and liabilities included $32 million of obligations to return cash collateral. At Dec. 31, 2019 and 2018, derivative assets and liabilities included rights to reclaim cash collateral of $11 million and $15 million, respectively. Counterparty netting excludes settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

(b)	During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

Changes in Level 3 commodity derivatives:

		Year Ended Dec. 31
(Millions of Dollars)		2019				2018				2017
Balance at Jan. 1		$	29			$	35			$	17
Purchases		44				59				82
Settlements		(64		)		(59		)		(97		)
Net transactions recorded during the period:
(Losses) gains recognized in earnings (a)		(8		)		(1		)		5
Net gains (losses) recognized as regulatory assets and liabilities		3				(5		)		28
Balance at Dec. 31		$	4			$	29			$	35

(a)	Amounts relate to commodity derivatives held at the end of the period.

Xcel Energy recognizes transfers between levels as of the beginning of each period. There were no transfers of amounts between levels for derivative instruments for 2017 - 2019.

Fair Value of Long-Term Debt

As of Dec. 31, other financial instruments for which the carrying amount did not equal fair value:

		2019								2018
(Millions of Dollars)		Carrying Amount				Fair Value				Carrying Amount				Fair Value
Long-term debt, including current portion		$	18,109			$	20,227			$	16,209			$	16,755

Fair value of Xcel Energy’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. Fair value estimates are based on information available to management as of Dec. 31, 2019 and 2018, and given the observability of the inputs, fair values presented for long-term debt were assigned as Level 2.

11. Benefit Plans and Other Postretirement Benefits

Pension and Postretirement Health Care Benefits

Xcel Energy has several noncontributory, defined benefit pension plans that cover almost all employees. Generally, benefits are based on a combination of years of service and average pay. Xcel Energy’s policy is to fully fund into an external trust the actuarially determined pension costs subject to the limitations of applicable employee benefit and tax laws.

In addition to the qualified pension plans, Xcel Energy maintains a SERP and a nonqualified pension plan. The SERP is maintained for certain executives that were participants in the plan in 2008, when the SERP was closed to new participants.

The nonqualified pension plan provides benefits for compensation that is in excess of the limits applicable to the qualified pension plans, with distributions funded by Xcel Energy’s consolidated operating cash flows.

Obligations of the SERP and nonqualified plan as of Dec. 31, 2019 and 2018 were $39 million and $33 million, respectively. Xcel Energy recognized net benefit cost for the SERP and nonqualified plans of $4 million in 2019 and in 2018.

Xcel Energy bases the investment-return assumption on expected long-term performance for each of the asset classes in its pension and postretirement health care portfolios. For pension assets, Xcel Energy considers the historical returns achieved by its asset portfolio over the past 20 years or longer period, as well as long-term projected return levels.

Pension cost determination assumes a forecasted mix of investment types over the long-term.

•	Investment returns in 2019 were above the assumed level of 6.87%;

•	Investment returns in 2018 were below the assumed level of 6.87%;

•	Investment returns in 2017 were above the assumed level of 6.87%; and

•	In 2020, expected investment-return assumption is 6.87%.

Pension plan and postretirement benefit assets are invested in a portfolio according to Xcel Energy’s return, liquidity and diversification objectives to provide a source of funding for plan obligations and minimize contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the asset allocation given the long-term risk, return, correlation and liquidity characteristics of each particular asset class. There were no significant concentrations of risk in any industry, index, or entity. Market volatility can impact even well-diversified portfolios and significantly affect the return levels achieved by the assets in any year.

State agencies also have issued guidelines to the funding of postretirement benefit costs. SPS is required to fund postretirement benefit costs for Texas and New Mexico amounts collected in rates. PSCo is required to fund postretirement benefit costs in irrevocable external trusts that are dedicated to the payment of these postretirement benefits. These assets are invested in a manner consistent with the investment strategy for the pension plan.

Xcel Energy’s ongoing investment strategy is based on plan-specific investment recommendations that seek to minimize potential investment and interest rate risk as a plan’s funded status increases over time. The investment recommendations result in a greater percentage of long-duration fixed income securities being allocated to specific plans having relatively higher funded status ratios and a greater percentage of growth assets being allocated to plans having relatively lower funded status ratios.

Plan Assets

For each of the fair value hierarchy levels, Xcel Energy’s pension plan assets measured at fair value:

		Dec. 31, 2019 (a)																				Dec. 31, 2018 (a)
(Millions of Dollars)		Level 1				Level 2				Level 3				Measured at NAV				Total				Level 1				Level 2				Level 3				Measured at NAV				Total
Cash equivalents		$	145			$	—			$	—			$	—			$	145			$	137			$	—			$	—			$	—			$	137
Commingled funds		1,408				—				—				1,031				2,439				914				—				—				987				1,901
Debt securities		—				645				4				—				649				—				621				—				—				621
Equity securities		86				—				—				—				86				106				—				—				—				106
Other		(120		)		5				—				(20		)		(135		)		2				5				—				(30		)		(23		)
Total		$	1,519			$	650			$	4			$	1,011			$	3,184			$	1,159			$	626			$	—			$	957			$	2,742

(a)	See Note 10 for further information regarding fair value measurement inputs and methods.

For each of the fair value hierarchy levels, Xcel Energy’s postretirement benefit plan assets that were measured at fair value:

		Dec. 31, 2019 (a)																				Dec. 31, 2018 (a)
(Millions of Dollars)		Level 1				Level 2				Level 3				Measured at NAV				Total				Level 1				Level 2				Level 3				Measured at NAV				Total
Cash equivalents		$	23			$	—			$	—			$	—			$	23			$	19			$	—			$	—			$	—			$	19
Insurance contracts		—				51				—				—				51				—				45				—				—				45
Commingled funds		69				—				—				76				145				133				—				—				40				173
Debt securities		—				228				1				—				229				—				179				—				—				179
Other		—				1				—				—				1				—				1				—				—				1
Total		$	92			$	280			$	1			$	76			$	449			$	152			$	225			$	—			$	40			$	417

(a)	See Note 10 for further information on fair value measurement inputs and methods.

Immaterial assets were transferred in or out of Level 3 for 2019. No assets were transferred in or out of Level 3 for 2018.

Funded Status — Comparisons of the actuarially computed benefit obligation, changes in plan assets and funded status of the pension and postretirement health care plans for Xcel Energy are as follows:

		Pension Benefits								Postretirement Benefits
(Millions of Dollars)		2019				2018				2019				2018
Change in Benefit Obligation:
Obligation at Jan. 1		$	3,477			$	3,828			$	542			$	621
Service cost		86				94				2				2
Interest cost		145				133				22				22
Plan amendments		1				—				—				—
Actuarial loss (gain)		273				(224		)		19				(62		)
Plan participants’ contributions		—				—				8				8
Medicare subsidy reimbursements		—				—				1				1
Benefit payments (a)		(281		)		(354		)		(47		)		(50		)
Obligation at Dec. 31		$	3,701			$	3,477			$	547			$	542
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1		$	2,742			$	3,088			$	417			$	461
Actual return on plan assets		568				(142		)		56				(13		)
Employer contributions		155				150				15				11
Plan participants’ contributions		—				—				8				8
Benefit payments		(281		)		(354		)		(47		)		(50		)
Fair value of plan assets at Dec. 31		$	3,184			$	2,742			$	449			$	417
Funded status of plans at Dec. 31		$	(517	)		$	(735	)		$	(98	)		$	(125	)
Amounts recognized in the Consolidated Balance Sheet at Dec. 31:
Noncurrent assets		$	—			$	—			$	21			$	—
Current liabilities		—				—				(6		)		(7		)
Noncurrent liabilities		(517		)		(735		)		(113		)		(118		)
Net amounts recognized		$	(517	)		$	(735	)		$	(98	)		$	(125	)

(a)	Includes approximately $20 million in 2019 and $198 million in 2018 of lump-sum benefit payments used in the determination of a settlement charge.

		Pension Benefits						Postretirement Benefits
(Millions of Dollars)		2019			2018			2019			2018
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation		3.49	%		4.31	%		3.47	%		4.32	%
Expected average long-term increase in compensation level		3.75			3.75			N/A			N/A
Mortality table		PRI-2012			RP-2014			PRI-2012			RP-2014
Health care costs trend rate — initial: Pre-65		N/A			N/A			6.00	%		6.50	%
Health care costs trend rate — initial: Post-65		N/A			N/A			5.10	%		5.30	%
Ultimate trend assumption — initial: Pre-65		N/A			N/A			4.50	%		4.50	%
Ultimate trend assumption — initial: Post-65		N/A			N/A			4.50	%		4.50	%
Years until ultimate trend is reached		N/A			N/A			3			4

Accumulated benefit obligation for the pension plan was $3,465 million and $3,275 million as of Dec. 31, 2019 and 2018, respectively.

Net Periodic Benefit Cost (Credit) — Net periodic benefit cost (credit), other than the service cost component, is included in other income in the consolidated statements of income.

Components of net periodic benefit cost (credit) and amounts recognized in other comprehensive income and regulatory assets and liabilities:

		Pension Benefits												Postretirement Benefits
(Millions of Dollars)		2019				2018				2017				2019				2018				2017
Service cost		$	86			$	94			$	94			$	2			$	2			$	2
Interest cost		145				133				147				22				22				24
Expected return on plan assets		(203		)		(209		)		(209		)		(21		)		(26		)		(25		)
Amortization of prior service credit		(5		)		(5		)		(2		)		(10		)		(11		)		(11		)
Amortization of net loss		87				111				107				5				8				7
Settlement charge (a)		6				91				81				—				—				—
Net periodic pension cost (credit)		116				215				218				(2		)		(5		)		(3		)
Costs not recognized due to effects of regulation		(1		)		(75		)		(79		)		1				2				—
Net benefit cost (credit) recognized for financial reporting		$	115			$	140			$	139			$	(1	)		$	(3	)		$	(3	)
Significant Assumptions Used to Measure Costs:
Discount rate		4.31		%		3.63		%		4.13		%		4.32		%		3.62		%		4.13		%
Expected average long-term increase in compensation level		3.75				3.75				3.75				—				—				—
Expected average long-term rate of return on assets		6.87				6.87				6.87				4.50				5.30				5.80

(a)

A settlement charge is required when the amount of all lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In 2019 and 2018, as a result of lump-sum distributions during the 2019 and 2018 plan years, Xcel Energy recorded a total pension settlement charge of $6 million in 2019 and $91 million in 2018, the majority of which was not recognized due to the effects of regulation. A total of $1 million and $11 million was recorded in the consolidated statements of income in 2019 and 2018, respectively.

		Pension Benefits								Postretirement Benefits
(Millions of Dollars)		2019				2018				2019				2018
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss		$	1,447			$	1,633			$	95			$	116
Prior service credit		(15		)		(20		)		(23		)		(33		)
Total		$	1,432			$	1,613			$	72			$	83
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Current regulatory assets		$	78			$	94			$	—			$	—
Noncurrent regulatory assets		1,285				1,446				80				89
Current regulatory liabilities		—				—				(1		)		(1		)
Noncurrent regulatory liabilities		—				—				(12		)		(10		)
Deferred income taxes		18				19				1				1
Net-of-tax accumulated other comprehensive income		51				54				4				4
Total		$	1,432			$	1,613			$	72			$	83

Measurement date		Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2019		Dec. 31, 2018

Cash Flows — Funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other calculations prescribed by the requirements of income tax and other pension-related regulations. Required contributions were made in 2017 — 2020 to meet minimum funding requirements.

Voluntary and required pension funding contributions:

•	$150 million in January 2020;

•	$154 million in 2019;

•	$150 million in 2018; and

•	$162 million in 2017.

The postretirement health care plans have no funding requirements other than fulfilling benefit payment obligations, when claims are presented and approved. Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities.

Voluntary postretirement funding contributions:

•	$10 million during 2020;

•	$15 million during 2019;

•	$11 million during 2018; and

•	$20 million during 2017.

Targeted asset allocations:

		Pension Benefits						Postretirement Benefits
		2019			2018			2019			2018
Domestic and international equity securities		37	%		36	%		15	%		18	%
Long-duration fixed income securities		30			30			—			—
Short-to-intermediate fixed income securities		14			17			72			70
Alternative investments		17			15			9			8
Cash		2			2			4			4
Total		100	%		100	%		100	%		100	%

Plan Amendments — The Xcel Energy Pension Plan and Xcel Energy Inc. Nonbargaining Pension Plan (South) were amended in 2017 to reduce supplemental benefits for non-bargaining participants as well as to allow the transfer of a portion of non-qualified pension obligations into the qualified plans.

In 2018, the PSCo postretirement plan was amended to add the 5% cash balance formula.

In 2019, the Pension Protection Act measurement concept was extended beyond 2019 for NSP bargaining terminations and retirements to Dec. 31, 2022.

There were no plan amendments made in 2019 which affected the postretirement benefit obligation.

Projected Benefit Payments

Xcel Energy’s projected benefit payments:

(Millions of Dollars)		Projected Pension Benefit Payments				Gross Projected Postretirement Health Care Benefit Payments				Expected Medicare Part D Subsidies				Net Projected Postretirement Health Care Benefit Payments
2020		$	278			$	44			$	2			$	42
2021		263				43				2				41
2022		262				42				2				40
2023		260				41				2				39
2024		255				40				2				38
2025-2029		1,205				181				13				168

Defined Contribution Plans

Xcel Energy maintains 401(k) and other defined contribution plans that cover most employees. Total expense to these plans was approximately $39 million in 2019, $38 million in 2018 and $37 million in 2017.

Multiemployer Plans

NSP-Minnesota and NSP-Wisconsin each contribute to several union multiemployer pension and other postretirement benefit plans, none of which are individually significant. These plans provide pension and postretirement health care benefits to certain union employees who may perform services for multiple employers and do not participate in the NSP-Minnesota and NSP-Wisconsin sponsored pension and postretirement health care plans.

Contributing to these types of plans creates risk that differs from providing benefits under NSP-Minnesota and NSP-Wisconsin sponsored plans, in that if another participating employer ceases to contribute to a multiemployer plan, additional unfunded obligations may need to be funded over time by remaining participating employers.

12. Commitments and Contingencies

Legal

Xcel Energy is involved in various litigation matters that are being defended and handled in the ordinary course of business. Assessing whether a loss is probable or a reasonable possibility, and whether the loss or a range of loss is estimable, often involves complex judgments regarding future events. Management maintains accruals for losses that are probable of being incurred and subject to reasonable estimation.

Management may be unable to estimate an amount or range of a reasonably possible loss in certain situations, including 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 the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Xcel Energy’s financial statements. Unless otherwise required by GAAP, legal fees are 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.

Two cases remain active which include an MDL matter consisting of a Colorado purported class (Breckenridge) and a Wisconsin purported class (Arandell Corp.).

Breckenridge/Colorado — In February 2019, the MDL panel remanded Breckenridge back to the U.S. District Court in Colorado.

Arandell Corp. — In February 2019, the case was remanded back to the U.S. District Court in Wisconsin.

Xcel Energy has concluded that a loss is remote for both remaining lawsuits.

Line Extension Disputes — In December 2015, the DRC filed a lawsuit seeking monetary damages in the Denver District Court, stating PSCo failed to award proper allowances and refunds for line extensions to new developments pursuant to the terms of electric and gas service agreements. The dispute involves claims by over fifty developers. In February 2018, the Colorado Supreme Court denied DRC’s petition to appeal the Denver District Court’s dismissal of the lawsuit, effectively terminating this litigation. However, in January 2018, DRC filed a new lawsuit in Boulder County District Court, asserting a single claim that PSCo was required to file its line extension agreements with the CPUC but failed to do so.

This claim is similar to the arguments previously raised by the DRC. PSCo filed a motion to dismiss this claim, which was granted in May 2018. The DRC subsequently filed an appeal to the Colorado Court of Appeals. In November 2019, the Colorado Court of Appeals issued an opinion affirming dismissal of the lawsuit based upon lack of subject matter jurisdiction. The Colorado Court of Appeals did not address the second issue based upon issue preclusion. Finally, the Colorado Court of Appeals remanded the case to the Boulder District Court to consider PSCo’s request for an award of costs, which it concluded does not include attorneys’ fees. The DRC did not file a petition for a Writ of Certiorari to the Colorado Supreme Court by the Dec. 26, 2019 deadline, effectively terminating this litigation.

Rate Matters

MEC Acquisition — In November 2018, NSP-Minnesota reached an agreement with Southern Power Company (a subsidiary of Southern Company) to purchase MEC, a 760 MW natural gas combined cycle facility, with capacity and energy historically sold to NSP-Minnesota under PPAs expiring in 2026 and 2039, for approximately $650 million.

In September 2019, the MPUC denied NSP-Minnesota's request to purchase MEC as a rate base asset. In January 2020, the MPUC approved Xcel Energy’s plan to acquire MEC as a non-regulated investment and step into the terms of the existing PPAs with NSP-Minnesota. A newly formed non-regulated subsidiary of Xcel Energy completed the transaction to purchase MEC on Jan. 17, 2020.

Sherco — In NSP-Minnesota’s 2013 fuel reconciliation filing, the MPUC made recovery of replacement power costs associated with the 2011 incident at its Sherco Unit 3 plant provisional and subject to further review following conclusion of litigation commenced by NSP-Minnesota, SMMPA (Co-owner of Sherco Unit 3) and insurance companies against GE.

In 2018, NSP-Minnesota and SMMPA reached a settlement with GE. NSP-Minnesota notified the MPUC of its proposal to refund the GE settlement proceeds back to customers through the FCA. The insurance providers continued their litigation against GE and the case went to trial.

In 2018, GE prevailed in the lawsuit with the insurance companies, however, the jury found comparable fault, finding that GE was 52% and NSP-Minnesota was 48% at fault. At that point in the litigation, NSP-Minnesota was no longer involved in the case and was not present to make arguments about its role in the event. The specific issue leading to the fault apportionment was also not before the jury and not relevant to the outcome of the trial.

In January 2019, the DOC recommended that NSP-Minnesota refund $20 million of previously recovered purchased power costs to its customers, based on the jury’s apportionment of fault. The OAG recommended the MPUC withhold any decision until the underlying litigation by the insurance providers (currently under appeal) is concluded. The DOC subsequently filed comments agreeing with the OAG’s recommendation to withhold a decision pending the outcome of any appeals. NSP-Minnesota filed reply comments arguing that the DOC recommendations are without merit and that it acted prudently in operating the plant and its settlement with GE was reasonable.

In March 2019, MPUC approved NSP-Minnesota’s proposal to refund the GE settlement proceeds back to customers through the FCA. It also decided to withhold any decision as to NSP-Minnesota’s prudence in connection with the incident at Sherco Unit 3 until after conclusion of the pending litigation between GE and NSP-Minnesota’s insurers.

MISO ROE Complaints — In November 2013 and February 2015, customers filed complaints against MISO TOs including NSP-Minnesota and NSP-Wisconsin.

The first complaint argued for a reduction in the base ROE in MISO transmission formula rates from 12.38% to 9.15%, and removal of ROE adders (including those for RTO membership). The second complaint sought to reduce base ROE from 12.38% to 8.67%.

In September 2016, the FERC issued an order granting a 10.32% base ROE (10.82% with the RTO adder) effective for the first complaint period of Nov. 12, 2013 to Feb. 11, 2015 and subsequent to the date of the order. The D.C. Circuit subsequently vacated and remanded FERC Opinion No. 531, which had established the ROE methodology on which the September 2016 FERC order was based.

On March 21, 2019, FERC announced a NOI seeking public comments on whether, and if so how, to revise ROE policies in light of the D.C. Circuit Court decision. FERC also initiated a NOI on whether to revise its policies on incentives for electric transmission investments, including the RTO membership incentive. In November 2019, the FERC issued an order adopting a new ROE methodology and settling the MISO base ROE at 9.88% (10.38% with the RTO adder), effective Sept. 28, 2016 and for the Nov. 12, 2013 to Feb. 11, 2015 refund period. The FERC also dismissed the second complaint.

In December 2019, MISO TOs filed a request for rehearing. Customers also filed requests for rehearing claiming, among other points, that the FERC erred by dismissing the second complaint without refunds. Xcel Energy has recognized a liability for its best estimate of final refunds to customers. It is uncertain when the FERC will act on the requests for rehearing or any other pending matters related to the 2019 NOIs.

Texas Fuel Reconciliation — In December 2018, SPS filed an application with the PUCT for reconciliation of fuel costs for the period Jan. 1, 2016, through June 30, 2018, to determine whether all fuel costs incurred were eligible for recovery. In December 2019, the PUCT issued an order disallowing recovery of costs for Texas customers related to two specific solar PPAs. These PPAs were previously approved by the NMPRC as reasonable, necessary and economic. SPS recorded a total disallowance of approximately $6 million in December 2019.

SPP OATT Upgrade Costs — Under the SPP OATT, costs of transmission upgrades may be recovered from other SPP customers whose transmission service depends on capacity enabled by the upgrade. SPP had not been charging its customers for these upgrades, even though the SPP OATT had allowed SPP to do so since 2008. In 2016, the FERC granted SPP’s request to recover previously unbilled charges and SPP subsequently billed SPS approximately $13 million.

In July 2018, SPS’ appeal to the D.C. Circuit over the FERC rulings granting SPP the right to recover previously unbilled charges was remanded to the FERC. In February 2019, the FERC reversed its 2016 decision and ordered SPP to refund charges retroactively collected from its transmission customers, including SPS, related to periods before September 2015. In April 2019, several parties, including SPP, filed requests for a rehearing. Timing of a FERC response to rehearing requests is uncertain. Any refunds received by SPS are expected to be given back to SPS customers through future rates.

In October 2017, SPS filed a separate complaint against SPP asserting SPP assessed upgrade charges to SPS in violation of the SPP OATT. The FERC granted a rehearing for further consideration in May 2018. Timing of FERC action on the SPS rehearing is uncertain. If SPS’ complaint results in additional charges or refunds, SPS will seek to recover or refund the amounts through future SPS customer rates.

Environmental

New and changing federal and state environmental mandates can create financial liabilities for Xcel Energy, which are normally recovered through the regulated rate process.

Site Remediation — Various federal and state environmental laws impose liability where hazardous substances or other regulated materials have been released to the environment. Xcel Energy Inc.’s subsidiaries may sometimes pay all or a portion of the cost to remediate sites where past activities of their predecessors or other parties have caused environmental contamination. Environmental contingencies could arise from various situations, including sites of former MGPs; and third-party sites, such as landfills, for which one or more of Xcel Energy Inc.’s subsidiaries are alleged to have sent wastes to that site.

MGP Sites

Ashland MGP Site — NSP-Wisconsin was named a responsible party for contamination at the Ashland/Northern States Power Lakefront Superfund Site (the Site) in Ashland, Wisconsin. Remediation was completed in 2019 and restoration activities are anticipated to be completed in 2020. Groundwater treatment activities will continue for many years.

The current cost estimate for remediation and restoration of the entire site is approximately $199 million. At Dec. 31, 2019 and 2018, NSP-Wisconsin had a total liability of $23 million and $27 million, respectively, for the entire site.

NSP-Wisconsin has deferred the unrecovered portion of the estimated Site remediation and restoration costs as a regulatory asset. The PSCW has authorized NSP-Wisconsin rate recovery for all remediation and restoration costs incurred at the Site. In its final December 2019 order approving 2020 and 2021 natural gas base rates, the PSCW authorized continued amortization of costs and application of a 3% carrying charge to the regulatory asset.

MGP, Landfill or Disposal Sites — PSCo is cooperating with the City of Denver on an environmental investigation of the Rice Yards Site in Denver, Colorado, which had various historic industrial uses by multiple parties, including railroad, maintenance shop, scrap metal yard, and MGP operations.

The area is being redeveloped into residential and commercial mixed uses, and PSCo is in discussions with the current property owner regarding legal claims related to the Rice Yards Site.

In addition, Xcel Energy is currently investigating or remediating 12 other MGP, landfill or other disposal sites across its service territories.

Xcel Energy has recognized its best estimate of costs/liabilities that will result from final resolution of these issues, however, the outcome and timing is unknown. In addition, there may be insurance recovery and/or recovery from other potentially responsible parties, offsetting a portion of costs incurred.

Environmental Requirements — Water and Waste

Coal Ash Regulation — Xcel Energy’s operations are subject to federal and state laws that impose requirements for handling, storage, treatment and disposal of solid waste. Under the CCR Rule, utilities are required to complete groundwater sampling around their CCR landfills and surface impoundments. Currently, Xcel Energy has nine regulated ash units in operation.

Xcel Energy is conducting groundwater sampling and, where appropriate, initiating the assessment of corrective measures and evaluating whether corrective action is required at any CCR landfills or surface impoundments. In 2019, groundwater monitoring consistent with the CCR Rule was conducted. In NSP-Minnesota, no results above the groundwater protection standards in the rule were identified. In PSCo, statistically significant increase above background concentration was detected at four locations. Subsequently, assessment monitoring samples were collected, and PSCo is evaluating the results to determine whether corrective action is required. Until PSCo completes its assessment, it is uncertain what impact, if any, there will be on the operations, financial condition or cash flows.

In August 2018, the D.C. Circuit ruled that the EPA cannot allow utilities to continue to use unlined impoundments (including clay lined impoundments) for the storage or disposal of coal ash. In November 2019, the EPA proposed rules in response to this decision.

If finalized in their current form, these rules would require NSP-Minnesota to expedite closure plans for one impoundment at an estimated cost of $2 million and the construction of a new impoundment at the cost of $9 million.

In 2019, Xcel Energy initiated the construction of this new impoundment, an ash pond, expected to be in service in 2020. Upon placing the new ash pond in service, the existing ash pond will be taken out of service, and closure activities as prescribed by the CCR Rule and the facility’s National Pollutant Discharge Elimination System permit will be initiated. In addition, the rules proposed by the EPA may require PSCo to expedite the closure of one coal ash impoundment.

Closure costs for existing impoundments are included in the calculation of the ARO liability. See Note 12 for further information.

Federal CWA WOTUS Rule — In 2015, the EPA and U.S. Army Corps of Engineers published a final rule that significantly broadened the scope of waters under the CWA that are subject to federal jurisdiction, referred to as “WOTUS”. In 2019, the EPA repealed the 2015 rule and published a draft replacement rule. Until a final rule is issued, Xcel Energy cannot estimate potential impacts, but anticipates costs will be recoverable through regulatory mechanisms.

Federal CWA ELG — In 2015, the EPA issued a final ELG rule for power plants that discharge treated effluent to surface waters as well as utility-owned landfills that receive CCRs. In 2017, the EPA delayed the compliance date for flue gas desulfurization wastewater and bottom ash transport until November 2020. After 2020, Xcel Energy estimates that ELG compliance will cost approximately $12 million to complete. The EPA, however, is conducting a rulemaking process to revise certain effluent limitations and pretreatment standards, which may impact compliance costs. Xcel Energy anticipates these costs will be fully recoverable through regulatory mechanisms.

Federal CWA Section 316(b) — The federal CWA requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available for minimizing impingement and entrainment of aquatic species. Xcel Energy estimates the likely cost for complying with impingement and entrainment requirements is approximately $40 million, to be incurred between 2020 and 2028. Xcel Energy believes six NSP-Minnesota plants and two NSP-Wisconsin plants could be required by state regulators to make improvements to reduce impingement and entrainment. The exact total cost of the impingement and entrainment improvements is uncertain but could be up to approximately $198 million. Xcel Energy anticipates these costs will be fully recoverable through regulatory mechanisms.

Environmental Requirements — Air

Regional Haze Rules — The regional haze program requires SO2, nitrogen oxide and particulate matter emission controls at power plants to reduce visibility impairment in national parks and wilderness areas. The program includes BART and reasonable further progress. The requirements of the first regional haze plans developed by Minnesota and Colorado have been approved and implemented. Texas’ first regional haze plan has undergone federal review as described below.

BART Determination for Texas: The EPA has issued a revised final rule adopting a BART alternative Texas only SO2 trading program that applies to all Harrington and Tolk units. Under the trading program, SPS expects the allowance allocations to be sufficient for SO2 emissions. The anticipated costs of compliance are not expected to have a material impact; and SPS believes that compliance costs would be recoverable through regulatory mechanisms.

Several parties have challenged whether the final rule issued by the EPA should be considered to have met the requirements imposed in a Consent Decree entered by the United States District Court for the District of Columbia that established deadlines for the EPA to take final action on state regional haze plan submissions. The court has required status reports from the parties while the EPA works on the reconsideration rulemaking.

In December 2017, the National Parks Conservation Association, Sierra Club, and Environmental Defense Fund appealed the EPA’s 2017 final BART rule to the Fifth Circuit and filed a petition for administrative reconsideration. In January 2018, the court granted SPS’ motion to intervene in the Fifth Circuit litigation in support of the EPA’s final rule. The court has held the litigation in abeyance while the EPA decided whether to reconsider the rule. In August 2018, the EPA started a reconsideration rulemaking, which was supplemented by an additional agency notice in November 2019. It is not known when the EPA will make a final decision on this proposal.

Reasonable Progress Rule: In 2016, the EPA adopted a final rule establishing a federal implementation plan for reasonable further progress under the regional haze program for the state of Texas. The rule imposes SO2 emission limitations that would require the installation of dry scrubbers on Tolk Units 1 and 2, with compliance required by February 2021. Investment costs associated with dry scrubbers could be $600 million. SPS appealed the EPA’s decision and obtained a stay of the final rule.

In March 2017, the Fifth Circuit remanded the rule to the EPA for reconsideration, leaving the stay in effect. In a future rulemaking, the EPA will address whether SO2 emission reductions beyond those required in the BART alternative rule are needed at Tolk under the “reasonable progress” requirements. The EPA has not announced a schedule for acting on the remanded rule.

Implementation of the NAAQS for SO**2 — The EPA has designated all areas near SPS’ generating plants as attaining the SO2 NAAQS with an exception. The EPA issued final designations, which found the area near the SPS Harrington plant as “unclassifiable.” The area near the Harrington plant is to be monitored for three years and a final designation is expected to be made by December 2020.

If the area near the Harrington plant is designated nonattainment in 2020, the TCEQ will need to develop an implementation plan, designed to achieve the NAAQS by 2025. The TCEQ could require additional SO2 controls at Harrington as part of such a plan. Xcel Energy cannot evaluate the impacts until the final designation is made and any required state plans are developed.

Xcel Energy believes that should SO2 control systems be required for a plant, compliance costs or the costs of alternative cost-effective generation will be recoverable through regulatory mechanisms and therefore does not expect a material impact on results of operations, financial condition or cash flows.

AROs — AROs have been recorded for Xcel Energy’s assets. For nuclear assets, the ARO is associated with the decommissioning of NSP-Minnesota nuclear generating plants.

Aggregate fair value of NSP-Minnesota’s legally restricted assets, for funding future nuclear decommissioning, was $2.4 billion and $2.1 billion for 2019 and 2018, respectively.

Xcel Energy’s AROs were as follows:

(Millions of Dollars)		Jan. 1, 2019				Amounts Incurred (a)				Amounts Settled (b)				Accretion				Cash Flow Revisions (c)				Dec. 31, 2019
Electric
Nuclear		$	1,968			$	—			$	—			$	100			$	—			$	2,068
Steam, hydro and other production		177				—				(5		)		8				22				202
Wind		119				26				—				7				(6		)		146
Distribution		42				—				—				2				—				44
Miscellaneous		7				—				—				—				(7		)		—
Natural gas
Transmission and distribution		249				—				—				11				(24		)		236
Miscellaneous		4				—				—				—				(1		)		3
Common
Miscellaneous		1				—				—				—				—				1
Non-utility
Miscellaneous		1				—				—				—				—				1
Total liability		$	2,568			$	26			$	(5	)		$	128			$	(16	)		$	2,701

(a)	Amounts incurred related to the wind farms placed in service in 2019 for NSP-Minnesota (Lake Benton and Foxtail) and SPS (Hale).

(b)	Amounts settled related to asbestos abatement projects and closure of certain ash containment facilities.

(c)

In 2019, AROs were revised for changes in timing and estimates of cash flows. Changes in gas transmission and distribution AROs were primarily related to increased gas line mileage and number of services, which were more than offset by decreased inflation rates. Changes in steam, hydro and other production AROs primarily related to the cost estimates to remediate ponds at production facilities. Changes in wind AROs were driven by new dismantling studies.

(Millions of Dollars)		Jan. 1, 2018				Amounts Incurred (a)				Amounts Settled (b)				Accretion				Cash Flow Revisions (c)				Dec. 31, 2018
Electric
Nuclear		$	1,874			$	—			$	—			$	94			$	—			$	1,968
Steam, hydro and other production		192				—				(14		)		8				(9		)		177
Wind		96				12				—				4				7				119
Distribution		21				—				—				1				20				42
Miscellaneous		5				—				—				—				2				7
Natural gas
Transmission and distribution		282				—				—				13				(46		)		249
Miscellaneous		4				—				—				—				—				4
Common
Miscellaneous		1				—				—				—				—				1
Non-utility
Miscellaneous		—				1				—				—				—				1
Total liability		$	2,475			$	13			$	(14	)		$	120			$	(26	)		$	2,568

(a)	Amounts incurred related to the PSCo Rush Creek wind farm and Nicollet Projects community solar gardens, which were placed in service in 2018.

(b)	Amounts settled related to asbestos abatement projects and closure of certain ash containment facilities.

(c)	In 2018, AROs were revised for changes in timing and estimates of cash flows. Changes in gas transmission and distribution AROs were primarily related to increased gas line mileage and number of services, which were more than offset by increased discount rates. Changes in electric distribution AROs primarily related to increased labor costs.

Indeterminate AROs — Other plants or buildings may contain asbestos due to the age of many of Xcel Energy’s facilities, but no confirmation or measurement of the cost of removal could be determined as of Dec. 31, 2019. Therefore, an ARO was not recorded for these facilities.

Removal Costs — Xcel Energy records a regulatory liability for the plant removal costs of its utility subsidiaries that are recovered currently in rates. Removal costs have accumulated based on varying rates as authorized by the appropriate regulatory entities. The utility subsidiaries have estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates.

Accumulated balances by entity at Dec. 31:

(Millions of Dollars)		2019				2018
NSP-Minnesota		$	520			$	485
PSCo		351				344
SPS		175				188
NSP-Wisconsin		171				158
Total Xcel Energy		$	1,217			$	1,175

Nuclear Related

Nuclear Insurance — NSP-Minnesota’s public liability for claims from any nuclear incident is limited to $13.9 billion under the Price-Anderson amendment to the Atomic Energy Act. NSP-Minnesota has secured $450 million of coverage for its public liability exposure with a pool of insurance companies. The remaining $13.5 billion of exposure is funded by the Secondary Financial Protection Program, available from assessments by the federal government.

NSP-Minnesota is subject to assessments of up to $138 million per reactor-incident for each of its three licensed reactors, for public liability arising from a nuclear incident at any licensed nuclear facility in the United States. The maximum funding requirement is $21 million per reactor-incident during any one year. Maximum assessments are subject to inflation adjustments by the NRC and state premium taxes. The NRC’s last adjustment was effective November 2018.

NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs from NEIL and EMANI. The coverage limits are $2.7 billion for each of NSP-Minnesota’s two nuclear plant sites. NEIL also provides business interruption insurance coverage up to $350 million, including the cost of replacement power during prolonged accidental outages of nuclear generating units. Premiums are expensed over the policy term.

All companies insured with NEIL are subject to retroactive premium adjustments if losses exceed accumulated reserve funds. Capital has been accumulated in the reserve funds of NEIL and EMANI to the extent that NSP-Minnesota would have no exposure for retroactive premium assessments in case of a single incident under the business interruption and the property damage insurance coverage.

NSP-Minnesota could be subject to annual maximum assessments of approximately $12 million for business interruption insurance and $35 million for property damage insurance if losses exceed accumulated reserve funds.

Nuclear Fuel Disposal — NSP-Minnesota is responsible for temporarily storing spent nuclear fuel from its nuclear plants. The DOE is responsible for permanently storing spent fuel from U.S. nuclear plants, but no such facility is yet available.

NSP-Minnesota owns temporary on-site storage facilities for spent fuel at its Monticello and PI nuclear plants, which consist of storage pools and dry cask facilities. The Monticello dry-cask storage facility currently stores all 30 of the authorized canisters. The PI dry-cask storage facility currently stores 44 of the 64 authorized casks. Monticello’s future spent fuel will continue to be placed in its spent fuel pool. The decommissioning plan addresses the disposition of spent fuel at the end of the licensed life.

Regulatory Plant Decommissioning Recovery — Decommissioning activities for NSP-Minnesota’s nuclear facilities are planned to begin at the end of each unit’s operating license and be completed by 2091. NSP-Minnesota’s current operating licenses allow continued use of its Monticello nuclear plant until 2030 and its PI nuclear plant until 2033 for Unit 1 and 2034 for Unit 2.

Future decommissioning costs of nuclear facilities are estimated through triennial periodic studies that assess the costs and timing of planned nuclear decommissioning activities for each unit.

Obligations for decommissioning are expected to be funded 100% by the external decommissioning trust fund. The cost study assumes the external decommissioning fund will earn an after-tax return between 5.23% and 6.30%. Realized and unrealized gains on fund investments are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs. Decommissioning costs are quantified in 2014 dollars. Escalation rates are 4.36% for plant removal activities and 3.36% for fuel management and site restoration activities.

NSP-Minnesota had $2.4 billion of assets held in external decommissioning trusts at Dec. 31, 2019. The following table summarizes the funded status of NSP-Minnesota’s decommissioning obligation. Xcel Energy believes future decommissioning costs will continue to be recovered in customer rates. The following amounts were prepared on a regulatory basis and not directly recorded in the financial statements as an ARO.

		Regulatory Basis
(Millions of Dollars)		2019				2018
Estimated decommissioning cost obligation from most recently approved study (in 2014 dollars)		$	3,012			$	3,012
Effect of escalating costs		688				539
Estimated decommissioning cost obligation (in current dollars)		3,700				3,551
Effect of escalating costs to payment date		7,505				7,654
Estimated future decommissioning costs (undiscounted)		11,205				11,205
Effect of discounting obligation (using average risk-free interest rate of 2.39% and 3.33% for 2019 and 2018, respectively)		(5,562		)		(6,911		)
Discounted decommissioning cost obligation		$	5,643			$	4,294
Assets held in external decommissioning trust		$	2,440			$	2,055
Underfunding of external decommissioning fund compared to the discounted decommissioning obligation		3,203				2,239

Calculations and data used by the regulator in approving NSP-Minnesota’s rates are useful in assessing future cash flows. Regulatory basis information is a means to reconcile amounts previously provided to the MPUC and utilized for regulatory purposes to amounts used for financial reporting.

Reconciliation of the discounted decommissioning cost obligation - regulated basis to the ARO recorded in accordance with GAAP:

(Millions of Dollars)		2019				2018
Discounted decommissioning cost obligation - regulated basis		$	5,643			$	4,294
Differences in discount rate and market risk premium		(2,295		)		(1,447		)
O&M costs not included for GAAP		(1,280		)		(879		)
Nuclear production decommissioning ARO - GAAP		$	2,068			$	1,968

Decommissioning expenses recognized as a result of regulation:

(Millions of Dollars)		2019				2018				2017
Annual decommissioning recorded as depreciation expense: (a) (b)		$	20			$	20			$	20

(a)	Decommissioning expense does not include depreciation of the capitalized nuclear asset retirement costs.

(b)	Decommissioning expenses in 2019, 2018 and 2017 include Minnesota’s retail jurisdiction annual funding requirement of approximately $14 million.

The 2014 nuclear decommissioning filing, approved in 2015, was used for regulatory presentation in 2019, 2018 and 2017. The 2017 filing, effective Jan. 1, 2019, has been approved by the MPUC. In December 2019, the MPUC verbally approved for NSP-Minnesota to delay any increase to the annual funding requirement until 2021.

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. Under ASC Topic 842, adopted by Xcel Energy on Jan. 1, 2019, a contract contains a lease if it conveys the exclusive right to control the use of a specific asset. A contract determined to contain a lease is evaluated further to determine if the arrangement is a finance lease.

ROU assets represent Xcel Energy's rights to use leased assets. Starting in 2019, the present value of future operating lease payments are recognized in other current liabilities and noncurrent operating lease liabilities. These amounts, adjusted for any prepayments or incentives, are recognized as operating lease ROU assets.

Most of Xcel Energy’s leases do not contain a readily determinable discount rate. Therefore, the present value of future lease payments is generally calculated using the applicable Xcel Energy subsidiary’s estimated incremental borrowing rate (weighted-average of 4.1%). Xcel Energy has elected the practical expedient under which non-lease components, such as asset maintenance costs included in payments, are not deducted from minimum lease payments for the purposes of lease accounting and disclosure.

Leases with an initial term of 12 months or less are classified as short-term leases and are not recognized on the consolidated balance sheet.

Operating lease ROU assets:

(Millions of Dollars)		Dec. 31, 2019
PPAs		$	1,642
Other		201
Gross operating lease ROU assets		1,843
Accumulated amortization		(171		)
Net operating lease ROU assets		$	1,672

In 2019, ROU assets for finance leases are included in other noncurrent assets, and the present value of future finance lease payments is included in other current liabilities and other noncurrent liabilities. Prior to 2019, finance leases were included in property, plant and equipment, the current portion of long-term debt and long-term debt.

Xcel Energy’s most significant finance lease activities are related to WYCO, a joint venture with CIG, to develop and lease natural gas pipeline, storage and compression facilities. Xcel Energy Inc. has a 50% ownership interest in WYCO. WYCO leases its facilities to CIG, and CIG operates the facilities, providing natural gas storage and transportation services to PSCo under separate service agreements.

PSCo accounts for its Totem natural gas storage service and Front Range pipeline arrangements with CIG and WYCO, respectively, as finance leases. Xcel Energy Inc. eliminates 50% of the finance lease obligation related to WYCO in the consolidated balance sheet along with an equal amount of Xcel Energy Inc.’s equity investment in WYCO.

Finance lease ROU assets:

(Millions of Dollars)		Dec. 31, 2019				Dec. 31, 2018
Gas storage facilities		$	201			$	201
Gas pipeline		21				21
Gross finance lease ROU assets		222				222
Accumulated amortization		(83		)		(77		)
Net finance lease ROU assets		$	139			$	145

Components of lease expense:

(Millions of Dollars)		2019				2018				2017
Operating leases
PPA capacity payments		$	221			$	210			$	210
Other operating leases (a)		34				38				36
Total operating lease expense (b)		$	255			$	248			$	246
Finance leases
Amortization of ROU assets		$	6			$	6			$	5
Interest expense on lease liability		19				19				20
Total finance lease expense		$	25			$	25			$	25

(a)	Includes short-term lease expense of $5 million for 2019, 2018 and 2017.

(b)	PPA capacity payments are included in electric fuel and purchased power on the consolidated statements of income. Expense for other operating leases is included in O&M expense and electric fuel and purchased power.

Commitments under operating and finance leases as of Dec. 31, 2019:

(Millions of Dollars)		PPA (a) (b) Operating Leases				Other Operating Leases				Total Operating Leases				Finance Leases (c)
2020		$	236			$	26			$	262			$	14
2021		238				29				267				14
2022		225				28				253				12
2023		214				25				239				12
2024		208				22				230				12
Thereafter		750				115				865				207
Total minimum obligation		1,871				245				2,116				271
Interest component of obligation		(321		)		(52		)		(373		)		(190		)
Present value of minimum obligation		$	1,550			193				1,743				81
Less current portion										(194		)		(4		)
Noncurrent operating and finance lease liabilities										$	1,549			$	77
Weighted-average remaining lease term in years										9.3				37.0

(a)	Amounts do not include PPAs accounted for as executory contracts and/or contingent payments, such as energy payments on renewable PPAs.

(b)	PPA operating leases contractually expire at various dates through 2033.

(c)	Excludes certain amounts related to Xcel Energy’s 50% ownership interest in WYCO.

Operating lease liabilities at Dec. 31, 2019 include a present value of approximately $400 million for MEC PPA capacity payments. In 2020, these operating lease liabilities and related ROU assets will be eliminated from Xcel Energy’s consolidated balance sheet following the completed January 2020 purchase of MEC by a newly formed non-regulated subsidiary of Xcel Energy.

Commitments under operating and finance leases as of Dec. 31, 2018:

(Millions of Dollars)		PPA (a) (b) Operating Leases				Other Operating Leases				Total Operating Leases				Finance Leases (c)
2019		$	207			$	32			$	239			$	14
2020		208				26				234				14
2021		210				25				235				14
2022		197				24				221				12
2023		186				22				208				12
Thereafter		883				154				1,037				220
Total minimum obligation														286
Interest component of obligation														(201		)
Present value of minimum obligation														$	85

(a)	Amounts do not include PPAs accounted for as executory contracts and/or contingent payments, such as energy payments on renewable PPAs.

(b)	PPA operating leases contractually expire at various dates through 2033.

(c)	Excludes certain amounts related to Xcel Energy’s 50% ownership interest in WYCO.

PPAs and Fuel Contracts

Non-Lease PPAs — NSP Minnesota, PSCo and SPS have entered into PPAs with other utilities and energy suppliers with various expiration dates through 2034 for purchased power to meet system load and energy requirements, operating reserve obligations and as part of wholesale and commodity trading activities. In general, these agreements provide for energy payments, based on actual energy delivered and capacity payments. Certain PPAs accounted for as executory contracts contain minimum energy purchase commitments, and total energy payments on those contracts were $102 million, $105 million and $100 million in 2019, 2018 and 2017, respectively.

Included in electric fuel and purchased power expenses for PPAs accounted for as executory contracts were payments for capacity of $86 million, $131 million and $168 million in 2019, 2018 and 2017, respectively.

Capacity and energy payments are contingent on the IPPs meeting contract obligations, including plant availability requirements. Certain contractual payments are adjusted based on market indices. The effects of price adjustments on financial results are mitigated through purchased energy cost recovery mechanisms.

At Dec. 31, 2019, the estimated future payments for capacity and energy that the utility subsidiaries of Xcel Energy are obligated to purchase pursuant to these executory contracts, subject to availability, were as follows:

(Millions of Dollars)		Capacity				Energy (a)
2020		$	70			$	110
2021		78				157
2022		77				173
2023		79				177
2024		74				182
Thereafter		56				146
Total		$	434			$	945

(a)	Excludes contingent energy payments for renewable energy PPAs.

Fuel Contracts — Xcel Energy has entered into various long-term commitments for the purchase and delivery of a significant portion of its coal, nuclear fuel and natural gas requirements. These contracts expire between 2020 and 2060. Xcel Energy is required to pay additional amounts depending on actual quantities shipped under these agreements.

Estimated minimum purchases under these contracts as of Dec. 31, 2019:

(Millions of Dollars)		Coal				Nuclear fuel				Natural gas supply				Natural gas supply and transportation
2020		$	430			$	54			$	343			$	295
2021		222				103				254				283
2022		135				85				104				269
2023		58				103				53				198
2024		24				74				3				153
Thereafter		74				275				—				860
Total		$	943			$	694			$	757			$	2,058

VIEs

PPAs — Under certain PPAs, NSP-Minnesota, PSCo and SPS purchase power from IPPs for which the utility subsidiaries are required to reimburse fuel costs, or to participate in tolling arrangements under which the utility subsidiaries procure the natural gas required to produce the energy that they purchase. Xcel Energy has determined that certain IPPs are VIEs. Xcel Energy is not subject to risk of loss from the operations of these entities, and no significant financial support is required other than contractual payments for energy and capacity.

In addition, certain solar PPAs provide an option to purchase emission allowances or sharing provisions related to production credits generated by the solar facility under contract. These specific PPAs create a variable interest in the IPP.

Xcel Energy evaluated each of these VIEs for possible consolidation, including review of qualitative factors such as the length and terms of the contract, control over O&M, control over dispatch of electricity, historical and estimated future fuel and electricity prices, and financing activities. Xcel Energy concluded that these entities are not required to be consolidated in its consolidated financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance.

The utility subsidiaries had approximately 3,986 MW and 3,770 MW of capacity under long-term PPAs at Dec. 31, 2019 and 2018, respectively, with entities that have been determined to be VIEs. Agreements have expiration dates through 2041.

Fuel Contracts — SPS purchases all of its coal requirements for its Harrington and Tolk plants from TUCO Inc. under contracts that will expire in December 2022. TUCO arranges for the purchase, receiving, transporting, unloading, handling, crushing, weighing and delivery of coal to meet SPS’ requirements. TUCO is responsible for negotiating and administering contracts with coal suppliers, transporters and handlers.

SPS has not provided any significant financial support to TUCO, other than contractual payments for delivered coal. However, the fuel contracts create a variable interest in TUCO due to SPS’ reimbursement of fuel procurement costs.

SPS has determined that TUCO is a VIE, however it has concluded that SPS is not the primary beneficiary of TUCO because it does not have the power to direct the activities that most significantly impact TUCO’s economic performance.

Low-Income Housing Limited Partnerships — Eloigne and NSP-Wisconsin have entered into limited partnerships for the construction and operation of affordable rental housing developments which qualify for low-income housing tax credits. Xcel Energy Inc. has determined Eloigne and NSP-Wisconsin’s low-income housing partnerships to be VIEs primarily due to contractual arrangements within each limited partnership that establish sharing of ongoing voting control and profits and losses that does not align with the partners’ proportional equity ownership.

Eloigne and NSP-Wisconsin have the power to direct the activities that most significantly impact these entities’ economic performance. Therefore, Xcel Energy Inc. consolidates these limited partnerships in its consolidated financial statements. Xcel Energy’s risk of loss for these partnerships is limited to its capital contributions, adjusted for any distributions and its share of undistributed profits and losses; no significant additional financial support has been, or is required to be, provided to the limited partnerships by Eloigne or NSP-Wisconsin.

Amounts reflected in Xcel Energy’s consolidated balance sheets for the Eloigne and NSP-Wisconsin low-income housing limited partnerships:

(Millions of Dollars)		Dec. 31, 2019				Dec. 31, 2018
Current assets		$	7			$	5
Property, plant and equipment, net		41				42
Other noncurrent assets		1				1
Total assets		$	49			$	48
Current liabilities		$	8			$	7
Mortgages and other long-term debt payable		26				26
Other noncurrent liabilities		—				—
Total liabilities		$	34			$	33

Other

Technology Agreements — Xcel Energy has a contract that extends through December 2022 with IBM for information technology services. The contract is cancelable at Xcel Energy’s option, although Xcel Energy would be obligated to pay 50% of the contract value for early termination. Xcel Energy capitalized or expensed $46 million, $81 million and $98 million associated with the IBM contract in 2019, 2018 and 2017, respectively.

Xcel Energy’s contract with Accenture for information technology services extends through December 2020. The contract is cancelable at Xcel Energy’s option, although there are financial penalties for early termination. Xcel Energy capitalized or expensed $52 million, $46 million and $16 million associated with the Accenture contract in 2019, 2018 and 2017, respectively.

During 2019, Xcel Energy executed a contract with Cognizant for information technology services which extends through 2022. The contract is cancelable at Xcel Energy’s option, although there are financial penalties for early termination. Xcel Energy capitalized or expensed $3 million associated with the Cognizant contract in 2019.

Committed minimum payments under these obligations:

(Millions of Dollars)		IBM Agreement				Accenture Agreement				Cognizant Agreement
2020		$	15			$	11			$	9
2021		15				—				7
2022		6				—				3
2023		—				—				—
2024		—				—				—
Thereafter		—				—				—

Guarantees and Bond Indemnifications — Xcel Energy Inc. and its subsidiaries provide guarantees and bond indemnities, which guarantee payment or performance. Xcel Energy Inc.’s exposure is based upon the net liability under the specified agreements or transactions. Most of the guarantees and bond indemnities issued by Xcel Energy Inc. and its subsidiaries have a stated maximum amount. As of Dec. 31, 2019 and 2018, Xcel Energy Inc. and its subsidiaries 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 $62 million and $69 million as of Dec. 31, 2019 and 2018.

13. Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31:

		2019
(Millions of Dollars)		Gains and Losses on Cash Flow Hedges				Defined Benefit Pension and Postretirement Items				Total
Accumulated other comprehensive loss at Jan. 1		$	(60	)		$	(64	)		$	(124	)
Other comprehensive loss before reclassifications (net of taxes of $(8) and $0, respectively)		(23		)		—				(23		)
Losses reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (net of taxes of $1 and $0, respectively)		3			(a)	—				3
Amortization of net actuarial loss (net of taxes of $0 and $1, respectively)		—				3			(b)	3
Net current period other comprehensive (loss) income		(20		)		3				(17		)
Accumulated other comprehensive loss at Dec. 31		$	(80	)		$	(61	)		$	(141	)

(a)	Included in interest charges.

(b)	Included in the computation of net periodic pension and postretirement benefit costs. See Note 11 for further information.

		2018
(Millions of Dollars)		Gains and Losses on Cash Flow Hedges				Defined Benefit Pension and Postretirement Items				Total
Accumulated other comprehensive loss at Jan. 1		$	(58	)		$	(67	)		$	(125	)
Other comprehensive loss before reclassifications (net of taxes of $(2) and $(2), respectively)		(5		)		(6		)		(11		)
Losses reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (net of taxes of $1 and $0, respectively)		3			(a)	—				3
Amortization of net actuarial loss (net of taxes of $0 and $3, respectively)		—				9			(b)	9
Net current period other comprehensive (loss) income		(2		)		3				1
Accumulated other comprehensive loss at Dec. 31		$	(60	)		$	(64	)		$	(124	)

(a)	Included in interest charges.

(b)	Included in the computation of net periodic pension and postretirement benefit costs. See Note 11 for further information.

14. Segments and Related Information

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; and

•	Regulated Natural Gas - The regulated natural gas utility segment transports, stores and distributes natural gas primarily in portions of Minnesota, Wisconsin, North Dakota, Michigan and Colorado.

Xcel Energy presents 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 investments in unconsolidated subsidiaries of $155 million and $141 million as of Dec. 31, 2019 and 2018, 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.

Xcel Energy’s segment information:

(Millions of Dollars)		2019				2018				2017
Regulated Electric
Operating revenues from external customers		$	9,575			$	9,719			$	9,676
Intersegment revenue		1				1				2
Total revenues		$	9,576			$	9,720			$	9,678
Depreciation and amortization		1,535				1,421				1,298
Interest charges and financing costs		500				449				449
Income tax expense		125				187				528
Net income		1,288				1,177				1,066
Regulated Natural Gas
Operating revenues from external customers		$	1,868			$	1,739			$	1,650
Intersegment revenue		2				2				1
Total revenues		$	1,870			$	1,741			$	1,651
Depreciation and amortization		219				212				174
Interest charges and financing costs		69				61				57
Income tax expense		48				28				23
Net income		195				187				182
Other
Total operating revenue		$	86			$	79			$	78
Depreciation and amortization		11				9				7
Interest charges and financing costs		167				142				122
Income tax (benefit)		(45		)		(34		)		(9		)
Net (loss)		(111		)		(103		)		(100		)
Consolidated Total
Total revenue		$	11,532			$	11,540			$	11,407
Reconciling eliminations		(3		)		(3		)		(3		)
Consolidated total revenue		$	11,529			$	11,537			$	11,404
Depreciation and amortization		1,765				1,642				1,479
Interest charges and financing costs		736				652				628
Income tax expense		128				181				542
Net income		1,372				1,261				1,148

15. Summarized Quarterly Financial Data (Unaudited)

		Quarter Ended
(Amounts in millions, except per share data)		March 31, 2019				June 30, 2019				Sept. 30, 2019				Dec. 31, 2019
Operating revenues		$	3,141			$	2,577			$	3,013			$	2,798
Operating income		486				410				758				450
Net income		315				238				527				292
EPS total — basic		$	0.61			$	0.46			$	1.02			$	0.56
EPS total — diluted		0.61				0.46				1.01				0.56
Cash dividends declared per common share		0.405				0.405				0.405				0.405

		Quarter Ended
(Amounts in millions, except per share data)		March 31, 2018				June 30, 2018				Sept. 30, 2018				Dec. 31, 2018
Operating revenues		$	2,951			$	2,658			$	3,048			$	2,880
Operating income (a)		480				450				696				339
Net income		291				265				491				214
EPS total — basic		$	0.57			$	0.52			$	0.96			$	0.42
EPS total — diluted		0.57				0.52				0.96				0.42
Cash dividends declared per common share		0.380				0.380				0.380				0.380

(a)	In 2018, Xcel Energy implemented ASU No. 2017-07 related to net periodic benefit cost, which resulted in retrospective reclassification of pension costs from O&M expense to other income.