~~0000072903 us-gaap:AccumulatedDefinedBenefitPlansAdjustmentMember 2019-07-01 2019-09-30~~

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



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

For the quarterly period ended ~~Sept. 30, 2019~~March 31, 2020 or



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



~~001-3034~~Xcel Energy Inc.
(Exact name of registrant as specified in its charter)
		~~41-0448030~~
~~(Commission File Number)~~		~~(I.R.S. Employer Identification No.)~~



414 Nicollet Mall



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

N/A

(Former Name, Former Address and Former Fiscal Year, if Changed Since Last Report)

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



Title of each class	Trading Symbol	Name of each exchange on which registered
Common Stock, $2.50 par value	XEL	~~NASDAQ~~Nasdaq Stock Market LLC

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ☒ Yes ☐ No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). ☒ Yes ☐ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.



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

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ☐ Yes ☒ No

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.



Class		~~Oct. 17, 2019~~April 30, 2020
Common Stock, $2.50 par value		~~524,388,096~~525,170,820 shares

~~Table of Contents~~

TABLE OF CONTENTS



PART I	FINANCIAL INFORMATION
Item 1 —	Financial Statements (unaudited)	56
	~~CONSOLIDATED STATEMENTS OF INCOME~~	5
	~~CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME~~Consolidated Statements of Income	6
	~~CONSOLIDATED STATEMENTS OF CASH FLOWS~~Consolidated Statements of Comprehensive Income	7
	~~CONSOLIDATED BALANCE SHEETS~~Consolidated Statements of Cash Flows	8
	~~CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY~~Consolidated Balance Sheets	9
	~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~Consolidated Statements of Common Stockholders’ Equity	10
	Notes to Consolidated Financial Statements	11
Item 2 —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2521
Item 3 —	Quantitative and Qualitative Disclosures about Market Risk	3732
Item 4 —	Controls and Procedures	3732

PART II	OTHER INFORMATION
Item 1 —	Legal Proceedings	3732
Item 1A —	Risk Factors	3733
Item 2 —	Unregistered Sales of Equity Securities and Use of Proceeds	3733
Item 6 —	Exhibits	3833

SIGNATURES		3934

	Certifications Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
	Certifications Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

This Form 10-Q is filed by Xcel Energy Inc. Additional information is available on various filings with the Securities and Exchange Commission (SEC).

~~Table of Contents~~

~~ABBREVIATIONS AND INDUSTRY TERMS~~Definitions of Abbreviations



Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former)
NSP-Minnesota	Northern States Power Company, a Minnesota corporation
NSP System	The electric production and transmission system of NSP-Minnesota and NSP-Wisconsin operated on an integrated basis and managed by NSP-Minnesota
NSP-Wisconsin	Northern States Power Company, a Wisconsin corporation
PSCo	Public Service Company of Colorado
SPS	Southwestern Public Service Co.
Utility subsidiaries	NSP-Minnesota, NSP-Wisconsin, PSCo and SPS
WGI	West Gas Interstate
~~WYCO~~	~~WYCO Development, LLC~~
Xcel Energy	Xcel Energy Inc. and its subsidiaries



Federal and State Regulatory Agencies
~~CEC~~	~~Colorado Energy Consumers~~
CPUC	Colorado Public Utilities Commission
D.C. Circuit	United States Court of Appeals for the District of Columbia Circuit
DOC	Department of Commerce
DOE	Department of Energy
EPA	United States Environmental Protection Agency
~~FEA~~	~~Federal Executive Agencies~~
FERC	Federal Energy Regulatory Commission
IRS	Internal Revenue Service
MPUC	Minnesota Public Utilities Commission
NMPRC	New Mexico Public Regulation Commission
NRC	Nuclear Regulatory Commission
OAG	Minnesota Office of the Attorney General
~~OCC~~	~~Office of Consumer Counsel~~
PSCW	Public Service Commission of Wisconsin
PUCT	Public Utility Commission of Texas
SEC	Securities and Exchange Commission



Electric, Purchased Gas and Resource Adjustment Clauses
DSM	Demand side management
FCA	Fuel clause adjustment
~~FPPCAC~~	~~Fuel and Purchased Power Cost Adjustment Clause~~
GUIC	Gas utility infrastructure cost rider
RES	Renewable energy standard
TCR	Transmission cost recovery adjustment



Other
~~ACE~~	~~Affordable Clean Energy~~
AFUDC	Allowance for funds used during construction
ASC	FASB Accounting Standards Codification
~~ASU~~AXM	~~FASB Accounting Standards Update~~Alliance of Xcel Municipalities
C&I	Commercial and Industrial
~~CAPM~~	~~Capital Asset Pricing Model~~
CC	Combined cycle
CCR	Coal combustion residual
CCR Rule	Final rule (40 CFR 257.50 - 257.107) published by the EPA regulating the management, storage and disposal of CCRs as a nonhazardous waste
CDD	Cooling degree-days
CEO	Chief executive officer
CFO	Chief financial officer
~~CIG~~COVID-19	~~Colorado Interstate Gas Company, LLC~~Novel coronavirus
CT	Combustion turbine
CWIP	Construction work in progress
~~DCF~~	~~Discounted Cash Flows~~
DR	Demand response
~~DRC~~	~~Development Recovery Company~~
DRIP	Dividend Reinvestment and Stock Purchase Program



EPS	Earnings per share
ETR	Effective tax rate
FASB	Financial Accounting Standards Board
FTR	Financial transmission right
GAAP	Generally accepted accounting principles
GE	General Electric
HDD	Heating degree-days
IPP	Independent power producing entity



LLC	Limited liability company
MDL	Multi district litigation
MEC	Mankato Energy Center
MGP	Manufactured gas plant
MISO	Midcontinent Independent System Operator, Inc.
NAV	Net asset value
NOI	Notice of inquiry
NOL	Net operating loss
O&M	Operating and maintenance
OATT	Open Access Transmission Tariff
OPUC	Office of Public Utility Counsel
PPA	Power purchase agreement
PTC	Production tax credit
ROE	Return on equity
ROFR	Right-of-first refusal
ROU	Right-of-use
RTO	Regional Transmission Organization
SMMPA	Southern Minnesota Municipal Power Agency
SPP	Southwest Power Pool, Inc.
~~TCJA~~THI	~~2017 federal tax reform enacted as Public Law No: 115-97, commonly referred to as the Tax Cuts and Jobs Act~~Temperature-humidity index
TIEC	Texas Industrial Energy Consumers
TOs	Transmission owners
VIE	Variable interest entity



Measurements
KV	Kilovolts
MMBtu	Million British thermal Units
MW	Megawatts
MWh	Megawatt hours

~~Table of Contents~~

Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed herein are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements, including the ~~2019~~2020 EPS guidance, long-term EPS and dividend growth rate objectives, future sales, future bad debt expense, and future operating performance, as well as assumptions and other statements are intended to be identified in this document by the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” “will,” “would” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we expressly disclaim any obligation to update any forward-looking information. The following factors, in addition to those discussed elsewhere in this Quarterly Report on Form 10-Q and in other securities filings (including Xcel Energy’s Annual Report on Form 10-K for the fiscal year ended Dec. 31, ~~2018,~~2019, and subsequent securities filings), could cause actual results to differ materially from management expectations as suggested by such forward-looking information: uncertainty around the impacts and duration of the COVID-19 pandemic; operational safety, including our nuclear generation facilities; successful long-term operational planning; commodity risks associated with energy markets and production; rising energy prices and fuel costs; qualified employee work force and third-party contractor factors; ability to recover costs, changes in ~~environmental laws~~regulation and ~~regulations; climate change and other weather, natural disaster and resource depletion, including compliance with any accompanying legislative and regulatory changes;~~subsidiaries’ ability ~~of subsidiaries~~ to recover costs from customers; reductions in our credit ratings and the cost of maintaining certain contractual relationships; general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of Xcel Energy Inc. and its subsidiaries to obtain financing on favorable terms; availability or cost of capital; our customers’ and counterparties’ ability to pay their debts to us; assumptions and costs relating to funding our employee benefit plans and health care benefits; our subsidiaries’ ability to make dividend payments; tax laws; operational safety, including our nuclear generation facilities; successful long-term operational planning; commodity risks associated with energy markets and production; rising energy prices; costs of potential regulatory penalties; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; ~~fuel costs;~~seasonal weather patterns; changes in environmental laws and ~~employee work force~~regulations; climate change and ~~third party contractor factors.~~other weather; natural disaster and resource depletion, including compliance with any accompanying legislative and regulatory changes; and costs of potential regulatory penalties.

Table of Contents

PART I — FINANCIAL INFORMATION

~~Item~~

ITEM 1 — FINANCIAL STATEMENTS

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

Three Months Ended Sept. 30 Nine Months Ended Sept. 30
2019 2018 2019 2018
Operating revenues
Electric $ 2,771
$ 2,802
$ 7,345
$ 7,419
Natural gas 222
227
1,324
1,181
Other 20
19
62
57
Total operating revenues 3,013
3,048
8,731
8,657

Operating expenses
Electric fuel and purchased power 952
1,040
2,679
2,907
Cost of natural gas sold and transported 55
58
646
537
Cost of sales — other 9
9
28
26
Operating and maintenance expenses 580
593
1,764
1,729
Conservation and demand side management expenses 75
77
212
216
Depreciation and amortization 447
440
1,319
1,199
Taxes (other than income taxes) 137
135
429
417
Total operating expenses 2,255
2,352
7,077
7,031

Operating income 758
696
1,654
1,626

Other income (expense) 8
(7 ) 14
(8 )
Equity earnings of unconsolidated subsidiaries 10
9
29
25
Allowance for funds used during construction — equity 15
30
55
79

Interest charges and financing costs
Interest charges — includes other financing costs of $6, $6, $19 and $18, respectively 199
177
578
523
Allowance for funds used during construction — debt (7 ) (13 ) (27 ) (35 )
Total interest charges and financing costs 192
164
551
488

Income before income taxes 599
564
1,201
1,234
Income taxes 72
73
121
187
Net income $ 527
$ 491
$ 1,080
$ 1,047

Weighted average common shares outstanding:
Basic $ 519
$ 510
$ 517
$ 510
Diluted 521
511
518
510

Earnings per average common share:
Basic $ 1.02
$ 0.96
$ 2.09
$ 2.05
Diluted 1.01
0.96
2.08
2.05

See Notes to Consolidated Financial Statements

~~Table of Contents~~

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

Three Months Ended Sept. 30 Nine Months Ended Sept. 30
2019 2018 2019 2018
Net income $ 527
$ 491
$ 1,080
$ 1,047

Other comprehensive income

Pension and retiree medical benefits:
Net pension and retiree medical gains arising during the period, net of tax of $0, $(1), $1 and $(1), respectively —
(2 ) 2
(2 )
Amortization of losses included in net periodic benefit cost, net of tax of $0, $1, $1 and $2, respectively 1
4
3
6
1
2
5
4

Derivative instruments:
Net fair value decrease, net of tax of $(3), $0, $(8) and $0, respectively (9 ) —
(25 ) —
Reclassification of losses to net income, net of tax of $0, $0, $1 and $1, respectively 1
1
2
2
(8 ) 1
(23 ) 2

Other comprehensive (loss) income (7 ) 3
(18 ) 6
Comprehensive income $ 520
$ 494
$ 1,062
$ 1,053

See Notes to Consolidated Financial Statements

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

	Three Months Ended March 31
	2020			2019
Operating revenues
Electric	$	2,203		$	2,325
Natural gas	583			794
Other	25			22
Total operating revenues	2,811			3,141

Operating expenses
Electric fuel and purchased power	797			914
Cost of natural gas sold and transported	285			479
Cost of sales — other	9			10
Operating and maintenance expenses	579			597
Conservation and demand side management expenses	74			72
Depreciation and amortization	463			433
Taxes (other than income taxes)	149			150
Total operating expenses	2,356			2,655

Operating income	455			486

Other (expense) income, net	(11		)	4
Equity earnings of unconsolidated subsidiaries	11			9
Allowance for funds used during construction — equity	23			20

Interest charges and financing costs
Interest charges — includes other financing costs of $7 and $6, respectively	199			189
Allowance for funds used during construction — debt	(10		)	(10		)
Total interest charges and financing costs	189			179

Income before income taxes	289			340
Income tax (benefit) expense	(6		)	25
Net income	$	295		$	315

Weighted average common shares outstanding:
Basic	526			515
Diluted	527			516

Earnings per average common share:
Basic	$	0.56		$	0.61
Diluted	0.56			0.61

See Notes to Consolidated Financial Statements

Table of Contents

XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(amounts in millions)
Nine Months Ended Sept. 30
2019 2018
Operating activities
Net income $ 1,080
$ 1,047
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization 1,332
1,213
Nuclear fuel amortization 89
92
Deferred income taxes 130
184
Allowance for equity funds used during construction (55 ) (79 )
Equity earnings of unconsolidated subsidiaries (29 ) (25 )
Dividends from unconsolidated subsidiaries 30
27
Share-based compensation expense 47
25
Changes in operating assets and liabilities:
Accounts receivable 39
(48 )
Accrued unbilled revenues 132
114
Inventories (60 ) 37
Other current assets 3
52
Accounts payable (56 ) 37
Net regulatory assets and liabilities (6 ) 164
Other current liabilities (100 ) (158 )
Pension and other employee benefit obligations (138 ) (134 )
Other, net 119
(55 )
Net cash provided by operating activities 2,557
2,493

Investing activities
Utility capital/construction expenditures (3,018 ) (2,681 )
Purchases of investment securities (472 ) (494 )
Proceeds from the sale of investment securities 462
479
Other, net (101 ) (10 )
Net cash used in investing activities (3,129 ) (2,706 )

Financing activities
Repayments from short-term borrowings, net (105 ) (376 )
Proceeds from issuances of long-term debt 1,937
1,381
Repayments of long-term debt, including reacquisition premiums (399 ) (301 )
Proceeds from issuance of common stock 457
203
Dividends paid (587 ) (544 )
Other, net (14 ) (20 )
Net cash provided by financing activities 1,289
343

Net change in cash and cash equivalents 717
130
Cash and cash equivalents at beginning of period 147
83
Cash and cash equivalents at end of period $ 864
$ 213

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized) $ (544 ) $ (491 )
Cash received (paid) for income taxes, net 53
(4 )

Supplemental disclosure of non-cash investing and financing transactions:
Accrued property, plant and equipment additions $ 420
$ 340
Inventory transfers to property, plant and equipment 64
74
Operating lease right-of-use assets 1,718
—
Allowance for equity funds used during construction 55
79
Issuance of common stock for equity awards 46
52

See Notes to Consolidated Financial Statements

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

	Three Months Ended March 31
	2020			2019
Net income	$	295		$	315
Other comprehensive loss
Pension and retiree medical benefits:
Net pension and retiree medical gains arising during the period, net of tax of $0 and $1, respectively	—			2
Reclassifications of loss to net income, net of tax of $0	1			1
Derivative instruments:
Net fair value decrease, net of tax of $(3) and $(2), respectively	(10		)	(7		)
Reclassification of losses to net income, net of tax of $0	2			1

Total other comprehensive loss	(7		)	(3		)
Total comprehensive income	$	288		$	312

See Notes to Consolidated Financial Statements

Table of Contents

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

Sept. 30, 2019 Dec. 31, 2018
Assets
Current assets
Cash and cash equivalents $ 864
$ 147
Accounts receivable, net 821
860
Accrued unbilled revenues 623
755
Inventories 544
548
Regulatory assets 455
464
Derivative instruments 61
87
Prepaid taxes 39
79
Prepayments and other 193
154
Total current assets 3,600
3,094

Property, plant and equipment, net 38,703
36,944

Other assets
Nuclear decommissioning fund and other investments 2,599
2,317
Regulatory assets 3,120
3,326
Derivative instruments 22
34
Operating lease right-of-use assets 1,718
—
Other 478
272
Total other assets 7,937
5,949
Total assets $ 50,240
$ 45,987

Liabilities and Equity
Current liabilities
Current portion of long-term debt $ 853
$ 406
Short-term debt 933
1,038
Accounts payable 1,258
1,237
Regulatory liabilities 469
436
Taxes accrued 443
450
Accrued interest 166
174
Dividends payable 212
195
Derivative instruments 73
61
Other 614
463
Total current liabilities 5,021
4,460

Deferred credits and other liabilities
Deferred income taxes 4,427
4,165
Deferred investment tax credits 50
54
Regulatory liabilities 5,082
5,187
Asset retirement obligations 2,679
2,568
Derivative instruments 178
129
Customer advances 203
199
Pension and employee benefit obligations 856
994
Operating lease liabilities 1,598
—
Other 186
206
Total deferred credits and other liabilities 15,259
13,502

Commitments and contingencies

Capitalization
Long-term debt 16,819
15,803
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 524,384,030
and 514,036,787 shares outstanding at Sept. 30, 2019 and Dec. 31, 2018, respectively
1,311
1,285
Additional paid in capital 6,636
6,168
Retained earnings 5,336
4,893
Accumulated other comprehensive loss (142 ) (124 )
Total common stockholders’ equity 13,141
12,222
Total liabilities and equity $ 50,240
$ 45,987

See Notes to Consolidated Financial Statements

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

	Three Months Ended March 31
	2020			2019
Operating activities
Net income	$	295		$	315
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	466			438
Nuclear fuel amortization	33			31
Deferred income taxes	34			26
Allowance for equity funds used during construction	(23		)	(20		)
Equity earnings of unconsolidated subsidiaries	(11		)	(9		)
Dividends from unconsolidated subsidiaries	11			10
Share-based compensation expense	26			19
Changes in operating assets and liabilities:
Accounts receivable	7			(114		)
Accrued unbilled revenues	149			92
Inventories	33			84
Other current assets	(31		)	(33		)
Accounts payable	(201		)	4
Net regulatory assets and liabilities	101			153
Other current liabilities	(77		)	(36		)
Pension and other employee benefit obligations	(157		)	(145		)
Other, net	14			(22		)
Net cash provided by operating activities	669			793

Investing activities
Capital/construction expenditures	(1,607		)	(844		)
Purchases of investment securities	(835		)	(305		)
Proceeds from the sale of investment securities	830			300
Other, net	6			(3		)
Net cash used in investing activities	(1,606		)	(852		)

Financing activities
Proceeds from short-term borrowings, net	1,170			214
Proceeds from issuances of long-term debt	—			392
Repayments of long-term debt, including reacquisition premiums	—			(400		)
Dividends paid	(204		)	(187		)
Other, net	(33		)	(13		)
Net cash provided by financing activities	933			6

Net change in cash, cash equivalents and restricted cash	(4		)	(53		)
Cash, cash equivalents and restricted cash at beginning of period	248			147
Cash, cash equivalents and restricted cash at end of period	$	244		$	94

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(207	)	$	(190	)
Cash received (paid) for income taxes, net	—			—

Supplemental disclosure of non-cash investing and financing transactions:
Accrued property, plant and equipment additions	$	284		$	238
Inventory transfers to property, plant and equipment	33			18
Operating lease right-of-use assets	—			1,659
Allowance for equity funds used during construction	23			20
Issuance of common stock for equity awards	18			17

See Notes to Consolidated Financial Statements

Table of Contents

XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY (UNAUDITED)
(amounts in millions, shares in thousands)

Common Stock Issued Retained Earnings Accumulated
Other
Comprehensive
Loss Total
Common
Stockholders’
Equity
Shares Par Value Additional Paid In Capital
Three Months Ended Sept. 30, 2019 and 2018
Balance at June 30, 2018 508,898
$ 1,272
$ 5,920
$ 4,580
$ (122 ) $ 11,650
Net income

491

491
Other comprehensive income

3
3
Dividends declared on common stock ($0.38 per share)

(195 )

(195 )
Issuances of common stock 4,401
11
197

208
Share-based compensation

8
—

8
Balance at Sept. 30, 2018 513,299
$ 1,283
$ 6,125
$ 4,876
$ (119 ) $ 12,165

Balance at June 30, 2019 514,865
$ 1,287
$ 6,190
$ 5,024
$ (135 ) $ 12,366
Net income

527

527
Other comprehensive loss

(7 ) (7 )
Dividends declared on common stock ($0.405 per share)

(214 )

(214 )
Issuances of common stock 9,519
24
438

462
Share-based compensation

8
(1 )

7
Balance at Sept. 30, 2019 524,384
$ 1,311
$ 6,636
$ 5,336
$ (142 ) $ 13,141

See Notes to Consolidated Financial Statements

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

	March 31, 2020			Dec. 31, 2019
Assets
Current assets
Cash and cash equivalents	$	244		$	248
Accounts receivable, net	839			837
Accrued unbilled revenues	561			713
Inventories	488			544
Regulatory assets	508			488
Derivative instruments	45			55
Prepaid taxes	68			43
Prepayments and other	230			185
Total current assets	2,983			3,113

Property, plant and equipment, net	40,776			39,483

Other assets
Nuclear decommissioning fund and other investments	2,429			2,731
Regulatory assets	3,130			2,935
Derivative instruments	39			22
Operating lease right-of-use assets	1,260			1,672
Other	516			492
Total other assets	7,374			7,852
Total assets	$	51,133		$	50,448

Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	1,102		$	702
Short-term debt	1,765			595
Accounts payable	996			1,294
Regulatory liabilities	456			407
Taxes accrued	553			466
Accrued interest	167			192
Dividends payable	226			212
Derivative instruments	52			38
Operating lease liabilities	143			194
Other	379			468
Total current liabilities	5,839			4,568

Deferred credits and other liabilities
Deferred income taxes	4,492			4,509
Deferred investment tax credits	48			49
Regulatory liabilities	5,342			5,077
Asset retirement obligations	2,734			2,701
Derivative instruments	183			175
Customer advances	202			203
Pension and employee benefit obligations	622			785
Operating lease liabilities	1,163			1,549
Other	196			186
Total deferred credits and other liabilities	14,982			15,234

Commitments and contingencies
Capitalization
Long-term debt	17,010			17,407
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 525,033,594 and 524,539,000 shares outstanding at March 31, 2020 and Dec. 31, 2019, respectively	1,313			1,311
Additional paid in capital	6,659			6,656
Retained earnings	5,478			5,413
Accumulated other comprehensive loss	(148		)	(141		)
Total common stockholders’ equity	13,302			13,239
Total liabilities and equity	$	51,133		$	50,448

See Notes to Consolidated Financial Statements

Table of Contents

XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY (UNAUDITED) (amounts in millions, shares in thousands)	XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY (UNAUDITED) (amounts in millions, shares in thousands)																		XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY (UNAUDITED) (amounts in millions, shares in thousands)

	Common Stock Issued							Retained Earnings				Accumulated Other Comprehensive Loss				Total Common Stockholders’ Equity			Common Stock Issued							Retained Earnings			Accumulated Other Comprehensive Loss			Total Common Stockholders’ Equity
	Shares		Par Value		Additional Paid In Capital						Shares								Par Value			Additional Paid In Capital
Nine Months Ended Sept. 30, 2019 and 2018
Balance at Dec. 31, 2017	507,763		$	1,269	$	5,898		$	4,413				$	(125	)		$	11,455
Three Months Ended March 31, 2020 and 2019
Balance at Dec. 31, 2018																			514,037		$	1,285	$	6,168		$	4,893		$	(124	)	$	12,222
Net income								1,047								1,047										315						315
Other comprehensive income												6				6
Dividends declared on common stock ($1.14 per share)								(584		)						(584		)
Other comprehensive loss																													(3		)	(3		)
Dividends declared on common stock ($0.41 per share)																										(210		)				(210		)
Issuances of common stock	5,558		14		221											235			637		2		10									12
Repurchases of common stock	(22	)	—		(1		)									(1		)	(6	)	—		—									—
Share-based compensation					7			—								7							(5		)	(2		)				(7		)
Balance at Sept. 30, 2018	513,299		$	1,283	$	6,125		$	4,876			$	(119	)		$	12,165
Balance at March 31, 2019																			514,668		$	1,287	$	6,173		$	4,996		$	(127	)	$	12,329

Balance at Dec. 31, 2018	514,037		$	1,285	$	6,168		$	4,893			$	(124	)		$	12,222
Balance at Dec. 31, 2019																			524,539		$	1,311	$	6,656		$	5,413		$	(141	)	$	13,239
Net income								1,080								1,080										295						295
Other comprehensive income												(18		)		(18		)
Dividends declared on common stock ($1.215 per share)								(633		)						(633		)
Other comprehensive loss																													(7		)	(7		)
Dividends declared on common stock ($0.43 per share)																										(227		)				(227		)
Issuances of common stock	10,353		26		458											484			495		2		10									12
Repurchases of common stock	(6	)	—		—											—
Share-based compensation					10			(4		)						6							(7		)	(1		)				(8		)
Balance at Sept. 30, 2019	524,384		$	1,311	$	6,636		$	5,336			$	(142	)		$	13,141
Adoption of ASC Topic 326																										(2		)				(2		)
Balance at March 31, 2020																			525,034		$	1,313	$	6,659		$	5,478		$	(148	)	$	13,302

See Notes to Consolidated Financial Statements

Table of Contents

XCEL ENERGY INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements (UNAUDITED)

In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly, in accordance with U.S. GAAP, the financial position of Xcel Energy Inc. and its subsidiaries as of ~~Sept. 30, 2019~~March 31, 2020 and Dec. 31, ~~2018;~~2019; the results of its operations, including the components of net income and comprehensive income, and changes in stockholders’ equity for the three ~~and nine~~ months ended ~~Sept. 30, 2019~~March 31, 2020 and ~~2018;~~2019; and its cash flows for the ~~nine~~three months ended ~~Sept. 30, 2019~~March 31, 2020 and ~~2018.~~2019. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after ~~Sept. 30, 2019~~March 31, 2020, up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation. The Dec. 31, ~~2018~~2019, balance sheet information has been derived from the audited ~~2018~~2019 consolidated financial statements included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, ~~2018.~~2019. Notes to the consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP on an annual basis have been condensed or omitted pursuant to such rules and regulations. For further information, refer to the consolidated financial statements and notes thereto, included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, ~~2018,~~2019, filed with the SEC on Feb. ~~22, 2019.~~21, 2020. Due to the seasonality of Xcel Energy’s electric and natural gas sales, interim results are not necessarily an appropriate base from which to project annual results.



1.	Summary of Significant Accounting Policies

The significant accounting policies set forth in Note 1 to the consolidated financial statements in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, ~~2018,~~2019, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.



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 on a modified-retrospective approach through 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.

Recently Adopted

~~Leases~~Credit Losses —In 2016, the FASB issued ~~Leases~~Financial Instruments - Credit Losses, Topic 326 (ASC Topic 326), ~~Topic 842(ASC Topic 842)~~, which ~~provides new~~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 ~~and disclosure guidance for leasing activities, most significantly requiring that operating leases be recognized on the balance sheet.~~ standards.

Xcel Energy ~~adopted~~implemented the guidance ~~on Jan. 1, 2019 utilizing the package~~using a modified-retrospective approach, recognizing a cumulative effect charge 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$2 million (after tax) 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)~~.retained earnings. Other than first-time recognition of ~~operating leases~~an allowance for doubtful accounts on ~~its consolidated balance sheet,~~accrued unbilled revenues, the ~~implementation~~Jan. 1, 2020, adoption of ASC Topic ~~842~~326 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 10 to the consolidated financial statements for leasing disclosures.

3. Selected Balance Sheet Data


(Millions of Dollars)	Sept. 30, 2019			Dec. 31, 2018			March 31, 2020			Dec. 31, 2019
Accounts receivable, net
Accounts receivable	$	875		$	915		$	897		$	892
Less allowance for bad debts	(54		)	(55		)	(58		)	(55		)
Accounts receivable, net	$	821		$	860		$	839		$	837



(Millions of Dollars)	March 31, 2020		Dec. 31, 2019
Inventories
Materials and supplies	$	283	$	270
Fuel	170		191
Natural gas	35		83
Total inventories	$	488	$	544

(Millions of Dollars) Sept. 30, 2019 Dec. 31, 2018
Inventories
Materials and supplies $ 271
$ 271
Fuel 187
170
Natural gas 86
107
Total inventories $ 544
$ 548


(Millions of Dollars)	Sept. 30, 2019			Dec. 31, 2018			March 31, 2020			Dec. 31, 2019
Property, plant and equipment, net
Electric plant	$	43,301		$	41,472		$	44,544		$	44,355
Natural gas plant	6,414			6,210			6,653			6,560
Common and other property	2,251			2,154			2,991			2,341
Plant to be retired ^(a)	276			322			217			259
CWIP	2,629			2,091			2,756			2,329
Total property, plant and equipment	54,871			52,249			57,161			55,844
Less accumulated depreciation	(16,549		)	(15,659		)	(16,730		)	(16,735		)
Nuclear fuel	2,887			2,771			2,913			2,909
Less accumulated amortization	(2,506		)	(2,417		)	(2,568		)	(2,535		)
Property, plant and equipment, net	$	38,703		$	36,944		$	40,776		$	39,483


^(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.

4. Borrowings and Other Financing Instruments

Short-Term Borrowings

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

~~Table of Contents~~

Commercial paper and term loan borrowings outstanding for Xcel Energy were as follows:


(Amounts in Millions, Except Interest Rates)	Three Months Ended Sept. 30, 2019			Year Ended Dec. 31, 2018			Three Months Ended March 31, 2020			Year Ended Dec. 31, 2019
Borrowing limit	$	3,600		$	3,250		$	4,300		$	3,600
Amount outstanding at period end	933			1,038			1,765			595
Average amount outstanding	1,303			788			1,404			1,115
Maximum amount outstanding	1,780			1,349			2,080			1,780
Weighted average interest rate, computed on a daily basis	2.62		%	2.34		%	2.05		%	2.72		%
Weighted average interest rate at period end	2.54			2.97			1.96			2.34

Letters of Credit — Xcel Energy Inc. and its subsidiaries use letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. At ~~Sept. 30, 2019~~both March 31, 2020 and Dec. 31, ~~2018,~~2019, there were ~~$30~~$20 million ~~and $49 million, respectively,~~ of letters of credit outstanding under the credit facilities. The contract amounts of these letters of credit approximate their fair value and are subject to fees.

Revolving 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~~ Table of Contents—~~In June 2019,~~

As of March 31, 2020, 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~~its utility subsidiaries had the following ~~changes:~~committed revolving credit facilities available:

~~Maturity extended from June 2021 to June 2024.~~



(Millions of Dollars)	Credit Facility ^(a)		Outstanding ^(b)		Available
Xcel Energy Inc.	$	1,250	$	449	$	801
PSCo	700		8		692
NSP-Minnesota	500		10		490
SPS	500		42		458
NSP-Wisconsin	150		76		74
Total	$	3,100	$	585	$	2,515


• ^(a)	~~Borrowing limit for Xcel Energy was increased from $1.0 billion to $1.25 billion~~ Expires in June 2024.


•	~~Borrowing limit for SPS was increased from $400 million to $500 million~~^(b)


•	~~Added swingline subfacility for Xcel Energy up to $75 million~~ Includes outstanding commercial paper and letters of credit.

Xcel Energy Inc., NSP-Minnesota, PSCo, and SPS each have the right to request an extension of the revolving credit facility termination date for 2two additional one year periods. NSP-Wisconsin has the right to request an extension of the revolving credit facility termination date for an additional one year period. All extension requests are subject to majority bank group approval.

~~As of Sept. 30, 2019, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available:~~

(Millions of Dollars)
Credit Facility ^(a)

Outstanding ^(b)
Available
Xcel Energy Inc. $ 1,250
$ 365
$ 885
PSCo 700
9
691
NSP-Minnesota 500
19
481
SPS 500
2
498
NSP-Wisconsin 150
68
82
Total $ 3,100
$ 463
$ 2,637


^(a)	~~Expires 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 respective credit facilities. Xcel Energy Inc. and its subsidiaries had 0 direct advances on the credit facilities outstanding as of ~~Sept. 30, 2019~~March 31, 2020 and Dec. 31, ~~2018.~~2019.

Term Loan ~~Agreement~~Agreements — In ~~December 2018,~~March 2020, Xcel Energy Inc. ~~renewed its $500~~entered into a $700 million, ~~364 Day~~364-Day Term Loan Agreement. ~~No additional capacity remains as loans borrowed and repaid may not be redrawn.~~ The loan is unsecured and matures ~~Dec. 3, 2019.~~March 22, 2021. Xcel Energy has an option to request an extension through ~~Dec. 2, 2020.~~

March 21, 2022. The 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%.~~65 percent. Interest is at a rate equal to either ~~(i)~~ the Eurodollar rate, plus ~~50.0~~60.0 basis points, or ~~(ii)~~ an alternate base rate. ~~Xcel Energy is also required to pay a commitment fee equal to 10 basis points per annum on any unborrowed portion.~~

As of ~~Sept. 30, 2019,~~March 31, 2020, Xcel Energy Inc.’s term loan borrowings were as follows:


(Millions of Dollars)	Limit		Amount Used		Available		Limit		Amount Used		Available
Xcel Energy Inc.	$	500	$	500	$	—	$	1,200	$	1,200	$	—

Bilateral Credit Agreement

In March 2019, NSP-Minnesota entered into a ~~one-year~~one year uncommitted bilateral credit agreement. The credit agreement is limited in use to support letters of credit. In March 2020, NSP-Minnesota renewed its bilateral credit agreement for an additional one-year term.

As of ~~Sept. 30, 2019,~~March 31, 2020, NSP-Minnesota’s outstanding letters of credit under the Bilateral Credit Agreement were as follows:


(Millions of Dollars)	Limit		Amount Outstanding		Available		Limit		Amount Outstanding		Available
NSP-Minnesota	$	75	$	20	$	55	$	75	$	26	$	49

Long-Term Borrowings

During the ~~nine~~three months ended ~~Sept. 30, 2019,~~March 31, 2020, Xcel Energy Inc. and its utility subsidiaries ~~issued the following:~~

~~PSCo issued $400 million of 4.05% first mortgage bonds due Sept. 15, 2049.~~

did not issue any long-term debt. On April 1, 2020, Xcel Energy Inc. issued ~~$130 million of 4.00% senior unsecured bonds due June 15, 2028.~~

~~SPS issued $300 million of 3.75% first mortgage green bonds due June 15, 2049.~~

~~PSCo issued $550 million of 3.20% first mortgage green bonds due March 1, 2050.~~

~~NSP-Minnesota issued~~ $600 million of ~~2.90% first mortgage green bonds~~3.40% senior unsecured notes due ~~March~~June 1, ~~2050.~~2030.

Forward Equity Agreements — In November ~~2018,~~2019, Xcel Energy Inc. entered into forward sale agreements in connection with a completed ~~$459~~$743 million public offering of ~~9.4~~11.8 million shares of Xcel Energy common stock. The initial forward agreement was for ~~8.1~~10.3 million shares with an additional agreement for ~~1.2~~1.5 million shares that was exercised at the option of the banking counterparty. ~~On Aug. 29, 2019, Xcel Energy settled~~

At March 31, 2020, the forward ~~equity~~ agreements ~~by physically delivering 9.4~~could have been settled with physical delivery of 11.8 million common shares to the banking counterparty in exchange for cash of $734 million. The forward instruments could also have been settled at March 31, 2020, with delivery of approximately $19 million of cash or approximately 0.3 million shares of common ~~equity~~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 $720 million to $735 million.

Forward equity instruments were recognized within stockholders’ equity at fair value at execution of ~~$453 million.~~the agreements and will not be subsequently adjusted until settlement.

Other Equity — Xcel Energy Inc. issued ~~$28.9~~$10 million ~~and $38.5 million~~ of equity through the DRIP during both the ~~nine~~three months ended ~~Sept. 30, 2019,~~March 31, 2020 and ~~year ended Dec. 31, 2018, respectively.~~2019. The program allows shareholders to elect dividend reinvestment in Xcel Energy Inc. common stock through a non-cash transaction.

~~Table of Contents~~



5.	Revenues

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

Three Months Ended Sept. 30, 2019
(Millions of Dollars) Electric Natural Gas All Other Total
Major revenue types
Revenue from contracts with customers:
Residential $ 865
$ 124
$ 10
$ 999
C&I 1,383
58
6
1,447
Other 35
—
1
36
Total retail 2,283
182
17
2,482
Wholesale 205
—
—
205
Transmission 151
—
—
151
Other 13
24
—
37
Total revenue from contracts with customers 2,652
206
17
2,875
Alternative revenue and other 119
16
3
138
Total revenues $ 2,771
$ 222
$ 20
$ 3,013

Three Months Ended Sept. 30, 2018
(Millions of Dollars) Electric Natural Gas All Other Total
Major revenue types
Revenue from contracts with customers:
Residential $ 890
$ 116
$ 10
$ 1,016
C&I 1,408
58
5
1,471
Other 35
—
1
36
Total retail 2,333
174
16
2,523
Wholesale 207
—
—
207
Transmission 143
—
—
143
Other 17
25
—
42
Total revenue from contracts with customers 2,700
199
16
2,915
Alternative revenue and other 102
28
3
133
Total revenues $ 2,802
$ 227
$ 19
$ 3,048

Nine Months Ended Sept. 30, 2019
(Millions of Dollars) Electric Natural Gas All Other Total
Major revenue types
Revenue from contracts with customers:
Residential $ 2,216
$ 801
$ 29
$ 3,046
C&I 3,724
403
21
4,148
Other 98
—
3
101
Total retail 6,038
1,204
53
7,295
Wholesale 548
—
—
548
Transmission 409
—
—
409
Other 42
84
—
126
Total revenue from contracts with customers 7,037
1,288
53
8,378
Alternative revenue and other 308
36
9
353
Total revenues $ 7,345
$ 1,324
$ 62
$ 8,731


	Nine Months Ended Sept. 30, 2018									Three Months Ended March 31, 2020
(Millions of Dollars)	Electric		Natural Gas		All Other		Total			Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:									Revenue from contracts with customers:
Residential	$	2,255	$	663	$	28	$	2,946		$	676	$	355	$	11	$	1,042
C&I	3,726		347		17		4,090			1,066		180		9		1,255
Other	101		—		5		106			29		—		1		30
Total retail	6,082		1,010		50		7,142			1,771		535		21		2,327
Wholesale	589		—		—		589			166		—		—		166
Transmission	398		—		—		398			132		—		—		132
Other	80		76		—		156			17		32		—		49
Total revenue from contracts with customers	7,149		1,086		50		8,285			2,086		567		21		2,674
Alternative revenue and other	270		95		7		372			117		16		4		137
Total revenues	$	7,419	$	1,181	$	57	$	8,657		$	2,203	$	583	$	25	$	2,811

1312

Table of Contents



	Three Months Ended March 31, 2019
(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	727	$	495	$	9	$	1,231
C&I	1,140		255		9		1,404
Other	32		—		1		33
Total retail	1,899		750		19		2,668
Wholesale	189		—		—		189
Transmission	131		—		—		131
Other	18		34		—		52
Total revenue from contracts with customers	2,237		784		19		3,040
Alternative revenue and other	88		10		3		101
Total revenues	$	2,325	$	794	$	22	$	3,141

6. Income Taxes

Note 7 to the consolidated financial statements included in Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, ~~2018~~2019, represents, in all material respects, the current status of other income tax matters except to the extent noted below, and are incorporated herein by reference.

The following table reconciles the difference between the statutory rate and the ETR:


	Three Months Ended Sept. 30				Nine Months Ended Sept. 30				Three Months Ended March 31
	2019		2018		2019		2018		2020		2019
Federal statutory rate	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%
State tax (net of federal tax effect)	5.0		5.0		5.0		5.0		4.9		5.0
(Decreases) increases:
Decreases in tax from:
Wind PTCs	(6.1	)	(2.6	)	(8.1	)	(4.3	)	(17.2	)	(8.6	)
Plant regulatory differences ^(a)	(5.6	)	(9.4	)	(5.5	)	(5.2	)	(8.4	)	(5.7	)
Other tax credits and tax credit and NOL allowances (net)	(1.7	)	(1.9	)	(1.8	)	(1.5	)
Other tax credits, net NOL & tax credit allowances									(0.9	)	(2.7	)
Other (net)	(0.6	)	0.8		(0.5	)	0.2		(1.5	)	(1.6	)
Effective income tax rate	12.0	%	12.9	%	10.1	%	15.2	%	(2.1	)%	7.4	%

^(a)

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

Federal Audits — Statute of limitations applicable to Xcel Energy’s consolidated federal income tax returns expire as follows:



Tax ~~Year(s)~~Years		Expiration
2009 - 2013		~~June~~September 2020
2014 - 2016		~~September 2020~~June 2021

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 ~~Sept. 30, 2019,~~March 31, 2020, 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 ~~Sept. 30, 2019,~~March 31, 2020, 0 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 ~~Sept. 30, 2019,~~March 31, 2020, 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 ~~Sept. 30, 2019,~~March 31, 2020, 0 material adjustments have been proposed.

No other state income tax audits were in progress as of ~~Sept. 30, 2019.~~March 31, 2020.

Unrecognized 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 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)	Sept. 30, 2019		Dec. 31, 2018		March 31, 2020		Dec. 31, 2019
Unrecognized tax benefit — Permanent tax positions	$	33	$	28	$	36	$	35
Unrecognized tax benefit — Temporary tax positions	10		9		10		9
Total unrecognized tax benefit	$	43	$	37	$	46	$	44

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


(Millions of Dollars)	Sept. 30, 2019			Dec. 31, 2018			March 31, 2020			Dec. 31, 2019
NOL and tax credit carryforwards	$	(40	)	$	(35	)	$	(42	)	$	(40	)

Net deferred tax liability associated with the unrecognized tax benefit amounts and related NOLs and tax credits carryforwards were ~~$28~~$30 million at ~~Sept. 30, 2019~~March 31, 2020 and ~~$24~~$29 million at Dec. 31, ~~2018.~~2019.

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

Payables for interest related to unrecognized tax benefits were not material and no0 amounts were accrued for penalties related to unrecognized tax benefits as of ~~Sept. 30, 2019~~March 31, 2020 or Dec. 31, ~~2018.~~2019.

7. Earnings Per Share

Basic EPS was computed by dividing the earnings available to common shareholders by the weighted average number of common shares outstanding. Diluted EPS was computed by dividing the earnings available to common shareholders by the diluted weighted average number of common shares outstanding.

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

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Common Stock Equivalents — Xcel Energy Inc. has common stock equivalents related to forward equity agreements ~~(settled in August 2019)~~ and time-based equity compensation awards.

~~Table of Contents~~

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

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 ~~1.8~~0.8 million and ~~1.6~~1.2 million for the three ~~and nine~~ months ended ~~Sept. 30,~~March 31, 2020 and 2019, ~~respectively (0.4 million for both the three and nine months ended Sept. 30, 2018).~~respectively.



8.	Fair Value of Financial Assets and Liabilities

Fair Value Measurements

Accounting guidance for fair value measurements and disclosures provides a single definition of fair value ~~a hierarchical framework for measuring assets and liabilities~~ and requires ~~disclosure~~disclosures about assets and liabilities measured at fair value.

~~Level 1~~ — ~~Quoted prices are available in active markets~~ A hierarchical framework for ~~identical assets or liabilities as~~disclosing the observability of the ~~reporting date. The types of~~inputs utilized in measuring assets and liabilities ~~included in Level 1 are highly liquid and actively traded instruments with quoted prices.~~at fair value is established by this guidance.

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


•	Level 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 the following:~~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;~~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 ~~generally~~ utilize ~~observable~~ forward prices and volatilities, as well as ~~observable~~ pricing adjustments for specific delivery locations and are generally assigned a Level 2 classification. When contractual settlements relate to inactive delivery locations ~~for which pricing is relatively unobservable,~~ or extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable ~~inputs~~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 ~~important~~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 insignificant to the consolidated financial ~~statements of Xcel Energy.~~statements.

Non-Derivative Fair Value Measurements

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 $619 million and $450 million as of Sept. 30, 2019 and Dec. 31, 2018, respectively, and unrealized losses were $22 million and $45 million as of Sept. 30, 2019 and Dec. 31, 2018, respectively.

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Unrealized gains for the nuclear decommissioning fund were $454 million and $706 million as of March 31, 2020 and Dec. 31, 2019, respectively, and unrealized losses were $88 million and $6 million as of March 31, 2020 and Dec. 31, 2019, respectively.

Non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund:


	Sept. 30, 2019												March 31, 2020
			Fair Value												Fair Value
(Millions of Dollars)	Cost		Level 1		Level 2		Level 3		NAV		Total		Cost		Level 1		Level 2		Level 3		NAV		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	23	$	23	$	—	$	—	$	—	$	23	$	71	$	71	$	—	$	—	$	—	$	71
Commingled funds	815		—		—		—		997		997		756		—		—		—		843		843
Debt securities	489		—		484		12		—		496		514		—		488		13		—		501
Equity securities	393		800		1		—		—		801		435		726		1		—		—		727
Total	$	1,720	$	823	$	485	$	12	$	997	$	2,317	$	1,776	$	797	$	489	$	13	$	843	$	2,142


^(a)	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes ~~$151~~$158 million of equity investments in unconsolidated subsidiaries and ~~$132~~$129 million of rabbi trust assets and miscellaneous investments.


	Dec. 31, 2018												Dec. 31, 2019
			Fair Value												Fair Value
(Millions of Dollars)	Cost		Level 1		Level 2		Level 3		NAV		Total		Cost		Level 1		Level 2		Level 3		NAV		Total
Nuclear decommissioning fund ^(a)
Cash equivalents	$	24	$	24	$	—	$	—	$	—	$	24	$	33	$	33	$	—	$	—	$	—	$	33
Commingled funds	758		79		—		—		819		898		733		—		—		—		935		935
Debt securities	466		—		436		—		—		436		489		—		495		13		—		508
Equity securities	401		697		—		—		—		697		485		962		2		—		—		964
Total	$	1,649	$	800	$	436	$	—	$	819	$	2,055	$	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 ~~$141~~$155 million of equity investments in unconsolidated subsidiaries and ~~$121~~$136 million of rabbi trust assets and miscellaneous investments.

For the three ~~and nine~~ months ended ~~Sept. 30,~~March 31, 2020 and 2019, ~~and 2018,~~ there were ~~0 transfers~~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 ~~Sept. 30, 2019:~~March 31, 2020:


	Final Contractual Maturity										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		Due in 1 Year or Less		Due in 1 to 5 Years		Due in 5 to 10 Years		Due after 10 Years		Total
Debt securities	$	1	$	126	$	226	$	143	$	496	$	11	$	81	$	205	$	204	$	501

Rabbi Trusts

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

Cost and fair value of assets held in rabbi trusts:

Sept. 30, 2019
Fair Value
(Millions of Dollars) Cost Level 1 Level 2 Level 3 Total
Rabbi Trusts ^(a)

Cash equivalents $ 17
$ 17
$ —
$ —
$ 17
Mutual funds 55
61
—
—
61
Total $ 72
$ 78
$ —
$ —
$ 78



	March 31, 2020
			Fair Value
(Millions of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Rabbi Trusts ^(a)
Cash equivalents	$	17	$	17	$	—	$	—	$	17
Mutual funds	57		56		—		—		56
Total	$	74	$	73	$	—	$	—	$	73


	Dec. 31, 2018										Dec. 31, 2019
			Fair Value										Fair Value
(Millions of Dollars)	Cost		Level 1		Level 2		Level 3		Total		Cost		Level 1		Level 2		Level 3		Total
Rabbi Trusts ^(a)
Cash equivalents	$	16	$	16	$	—	$	—	$	16	$	17	$	17	$	—	$	—	$	17
Mutual funds	52		51		—		—		51		57		65		—		—		65
Total	$	68	$	67	$	—	$	—	$	67	$	74	$	82	$	—	$	—	$	82

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

Derivative Instruments Fair Value Measurements

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

Interest Rate Derivatives — Xcel Energy enters into various instruments that effectively fix the 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 ~~Sept. 30, 2019,~~March 31, 2020, Xcel Energy had $13 million of settlement payables related to interest rate swaps, which were paid in April 2020. These interest rate derivatives were designated as hedges and changes in fair value were recorded as other comprehensive income.

As of March 31, 2020, accumulated other comprehensive loss 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 Sept. 30, 2019, Xcel Energy had unsettled interest rate swaps outstanding with a notional amount of $300 million. These interest rate derivatives were designated as cash flow 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.

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 as other comprehensive income or deferred as a regulatory asset or liability. The classification as a regulatory asset or liability is based on approved regulatory recovery mechanisms.

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As of ~~Sept. 30, 2019,~~March 31, 2020, Xcel Energy had 0 commodity contracts designated as cash flow hedges.

Xcel Energy ~~also~~ 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.

~~Table of Contents~~

Gross notional amounts of commodity forwards, options and FTRs:


(Amounts in Millions) ^(a)(b)	Sept. 30, 2019	Dec. 31, 2018	March 31, 2020	Dec. 31, 2019
MWh of electricity	121	87	79	95
MMBtu of natural gas	130	92	149	110


^(a)	Not reflective of net positions in the underlying commodities.


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

Consideration of Credit Risk and Concentrations — 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 ~~Sept. 30, 2019,~~March 31, 2020, 6 of Xcel Energy’s 10 most significant counterparties for these activities, comprising ~~$156~~$154 million, or ~~53%~~56%, of this credit exposure, had investment grade credit ratings from S&P Global Ratings, Moody’s Investor Services or Fitch Ratings. NaN of the 10 most significant counterparties, comprising ~~$24~~$35 million, or 8%13%, 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. NaN of these significant counterparties, comprising $8$12 million or 3%4% of this credit exposure, had credit quality less than investment grade, based on ~~external~~internal analysis. NaN of these significant counterparties are municipal or cooperative electric entities, RTOs or other utilities.

Impact of derivative activity:


	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:						Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:
(Millions of Dollars)	Accumulated Other Comprehensive Loss			Regulatory (Assets) and Liabilities			Accumulated Other Comprehensive Loss			Regulatory (Assets) and Liabilities
Three Months Ended Sept. 30, 2019
Three Months Ended March 31, 2020
Derivatives designated as cash flow hedges
Interest rate	$	(12	)	$	—		$	(13	)	$	—
Total	$	(12	)	$	—		(13		)	—
Other derivative instruments
Natural gas commodity	$	—		$	(3	)
Total	$	—		$	(3	)

Nine Months Ended Sept. 30, 2019
Three Months Ended March 31, 2019
Derivatives designated as cash flow hedges
Interest rate	$	(33	)	$	—		(9		)	—
Total	$	(33	)	$	—		(9		)	—
Other derivative instruments
Electric commodity	$	—		$	4		—			12
Natural gas commodity	—			(5		)	—			4
Total	$	—		$	(1	)	$	—		$	16

Three Months Ended Sept. 30, 2018
Other derivative instruments
Electric commodity	$	—		$	(2	)
Natural gas commodity	—			(2		)
Total	$	—		$	(4	)

Nine Months Ended Sept. 30, 2018
Other derivative instruments
Electric commodity	$	—		$	6
Natural gas commodity	—			(1		)
Total	$	—		$	5

~~Table of Contents~~


	Pre-Tax (Gains) Losses Reclassified into Income During the Period from:							Pre-Tax Gains (Losses) Recognized During the Period in Income				Pre-Tax (Gains) Losses Reclassified into Income During the Period from:							Pre-Tax Gains (Losses) Recognized During the Period in Income
(Millions of Dollars)	Accumulated Other Comprehensive Loss			Regulatory Assets and (Liabilities)								Accumulated Other Comprehensive Loss			Regulatory Assets and (Liabilities)
Three Months Ended Sept. 30, 2019
Three Months Ended March 31, 2020
Derivatives designated as cash flow hedges
Interest rate	$	1	^(a)	$	—			$	—			$	2	^(a)	$	—			$	—
Total	$	1		$	—			$	—			2			—				—
Other derivative instruments
Commodity trading	$	—		$	—			$	1		^(b)	—			—				1			^(b)
Electric commodity	—			(1		)	^(c)	—				—			(4		)	^(c)	—
Natural gas commodity												—			5			^(d)	(6		)	^(d)
Total	$	—		$	(1	)		$	1			—			1				(5		)

Nine Months Ended Sept. 30, 2019
Three Months Ended March 31, 2019
Derivatives designated as cash flow hedges
Interest rate	$	3	^(a)	$	—			$	—			1		^(a)	—				—
Total	$	3		$	—			$	—			1			—				—
Other derivative instruments
Commodity trading	$	—		$	—			$	5		^(b)	—			—				1			^(b)
Electric commodity												—			1			^(c)	—
Natural gas commodity	—			(1		)	^(d)	(4		)	^(d)	—			(1		)	^(d)	(3		)	^(d)
Total	$	—		$	(1	)		$	1			$	—		$	—			$	(2	)

Three Months Ended Sept. 30, 2018
Derivatives designated as cash flow hedges
Interest rate	$	1	^(a)	$	—			$	—
Total	$	1		$	—			$	—
Other derivative instruments
Commodity trading	$	—		$	—			$	5		^(b)
Total	$	—		$	—			$	5

Nine Months Ended Sept. 30, 2018
Derivatives designated as cash flow hedges
Interest rate	$	3	^(a)	$	—			$	—
Total	$	3		$	—			$	—
Other derivative instruments
Commodity trading	$	—		$	—			$	14		^(b)
Natural gas commodity	—			2			^(d)	(2		)	^(d)
Total	$	—		$	2			$	12


^(a)	Recorded to interest charges.


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


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

^(d)

Amounts for both the three ~~and nine~~ months ended ~~Sept. 30,~~March 31, 2020 and 2019 included 0 settlement gains or 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. ~~Amounts for the three and nine months ended Sept. 30, 2018 included 0 such settlement gains or losses and $1 million of such settlement losses, respectively.~~ Remaining settlement losses for the three ~~and nine~~ months ended ~~Sept. 30,~~March 31, 2020 and 2019 ~~and 2018~~ related to natural gas operations and were recorded to cost of natural gas sold and transported. These gains and losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset or liability, as appropriate.

Xcel Energy had 0 derivative instruments designated as fair value hedges during the three ~~and nine~~ months ended ~~Sept. 30, 2019~~March 31, 2020 and ~~2018.~~2019.

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 ~~Sept. 30, 2019~~March 31, 2020 and Dec. 31, ~~2018,~~2019, there were 0$11 million and $7 million derivative instruments in a liability position with such underlying contract provisions, ~~with 0 offsetting positions or posted collateral.~~

respectively. Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. 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 0 collateral posted related to adequate assurance clauses in derivative contracts as of ~~Sept. 30, 2019~~March 31, 2020 and Dec. 31, ~~2018~~2019.

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Recurring Fair Value Measurements — Derivative assets and liabilities measured at fair value on a recurring basis:


	Sept. 30, 2019															Dec. 31, 2018																			March 31, 2020																						Dec. 31, 2019
	Fair Value						Fair Value Total			Netting ^(a)			Total			Fair Value								Fair Value Total			Netting ^(a)				Total				Fair Value												Fair Value Total		Netting ^(a)				Total				Fair Value												Fair Value Total				Netting ^(a)				Total
(Millions of Dollars)	Level 1		Level 2		Level 3				Level 1				Total		Level 2			Level 3					Level 1				Netting ^(a)			Level 2					Level 3							Level 1				Level 2			Netting ^(a)			Level 3																	Fair Value Total				Netting ^(a)				Total
Current derivative assets							Fair Value Total
Other derivative instruments:										Netting ^(a)
Commodity trading	$	3	$	42	$	13	$	58		$	(34	)	$	24		$	4		$	92	$	2		Fair Value Total	$	98		$	(44	)	Total		$	54			$	8			$	63			$	16	Fair Value Total		$	87			Total		$	(63	)		$	24			$	3			$	51			$	24			$	78			$	(52	)	$	26
Electric commodity	—		—		28		28			(1		)	27			—			—		25			25			—				25				—				—				18				18		—				18				—				—				21				21				(1		)		20
Natural gas commodity	—		7		—		7			—			7			—			4		—			4			—				4				—				—				—				—		—				—				—				6				—				6				—				6
Total current derivative assets	$	3	$	49	$	41	$	93		$	(35	)	58			$	4		$	96	$	27		$	127		$	(44	)		83				$	8			$	63			$	34			$	105	$	(63	)		42				$	3			$	57			$	45			$	105			$	(53	)		52
PPAs ^(b)													3																		4																						3																								3
Current derivative instruments													$	61																	$	87																					$	45																							$	55
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	$	5	$	39	$	5	$	49		$	(41	)	$	8		$	—		$	27	$	5		$	32		$	(14	)		$	18			$	10			$	38			$	22			$	70	$	(45	)		$	25			$	9			$	38			$	7			$	54			$	(45	)		$	9
Electric commodity																																			—				—				2				2		—				2				—				—				—				—				—				—
Total noncurrent derivative assets	$	5	$	39	$	5	$	49		$	(41	)	8			$	—		$	27	$	5		$	32		$	(14	)		18				$	10			$	38			$	24			$	72	$	(45	)		27				$	9			$	38			$	7			$	54			$	(45	)		9
PPAs ^(b)													14																		16																						12																								13
Noncurrent derivative instruments													$	22																	$	34																					$	39																							$	22


	Sept. 30, 2019															Dec. 31, 2018																			March 31, 2020																						Dec. 31, 2019
	Fair Value						Fair Value Total			Netting ^(a)			Total			Fair Value								Fair Value Total			Netting ^(a)				Total				Fair Value												Fair Value Total		Netting ^(a)				Total				Fair Value												Fair Value Total				Netting ^(a)				Total
(Millions of Dollars)	Level 1		Level 2		Level 3				Level 1				Total		Level 2			Level 3					Level 1				Netting ^(a)			Level 2					Level 3							Level 1				Level 2			Netting ^(a)			Level 3																	Fair Value Total				Netting ^(a)				Total
Current derivative liabilities							Fair Value Total
Derivatives designated as cash flow hedges:										Netting ^(a)
Interest rate	$	—	$	40	$	—	$	40		$	—		$	40		$	—		$	7	$	—		Fair Value Total	$	7		$	—		Total		$	7			$	—			$	13			$	—	Fair Value Total		$	13			Total		$	—			$	13			$	—			$	—			$	—			$	—			$	—	$	—
Other derivative instruments:
Commodity trading	3		42		11		56			(46		)	10			4			88		2			94			(60		)		34				$	8			$	62			$	14			$	84	$	(63	)		$	21			$	4			$	59			$	15			$	78			$	(63	)		$	15
Electric commodity	—		—		1		1			(1		)	—			—			—		—			—			—				—				—				—				—				—		—				—				—				—				1				1				(1		)		—
Natural gas commodity	—		6		—		6			—			6			—			—		—			—			—				—				—				—				—				—		—				—				—				5				—				5				—				5
Total current derivative liabilities	$	3	$	88	$	12	$	103		$	(47	)	56			$	4		$	95	$	2		$	101		$	(60	)		41				$	8			$	75			$	14			$	97	$	(63	)		34				$	4			$	64			$	16			$	84			$	(64	)		20
PPAs ^(b)													17																		20																						18																								18
Current derivative instruments													$	73																	$	61																					$	52																							$	38
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	2	$	88	$	19	$	109		$	(10	)	$	99		$	—		$	18	$	1		$	19		$	17			$	36			$	3			$	89			$	39			$	131	$	(19	)		$	112			$	2			$	79			$	32			$	113			$	(13	)		$	100
Total noncurrent derivative liabilities	$	2	$	88	$	19	$	109		$	(10	)	99			$	—		$	18	$	1		$	19		$	17			36				$	3			$	89			$	39			$	131	$	(19	)		112				$	2			$	79			$	32			$	113			$	(13	)		100
PPAs ^(b)													79																		93																						71																								75
Noncurrent derivative instruments													$	178																	$	129																					$	183																							$	175

^(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 at ~~Sept. 30, 2019~~March 31, 2020 and Dec. 31, ~~2018.~~2019. At both ~~Sept. 30, 2019~~March 31, 2020 and Dec. 31, ~~2018,~~2019, derivative assets and liabilities include $32 million of obligations to return cash ~~collateral. At Sept. 30, 2019~~collateral and ~~Dec. 31, 2018, derivative assets and liabilities include~~ rights to reclaim cash collateral of ~~$12~~$6 million and ~~$15~~$11 million, respectively. Counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.


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

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Changes in Level 3 commodity derivatives:


	Three Months Ended Sept. 30
(Millions of Dollars)	2019			2018
Balance at July 1	$	28		$	64
Purchases	5			3
Settlements	(21		)	(19		)
Net transactions recorded during the period:
Gains recognized in earnings ^(a)	1			—
Net gains recognized as regulatory assets and liabilities	2			—
Balance at Sept. 30	$	15		$	48

	Nine Months Ended Sept. 30						Three Months Ended March 31
(Millions of Dollars)	2019			2018			2020			2019
Balance at Jan. 1	$	29		$	35		$	4		$	29
Purchases	42			49			12			4
Settlements	(48		)	(51		)	(18		)	(11		)
Net transactions recorded during the period:
Losses recognized in earnings ^(a)	(9		)	—
Net gains recognized as regulatory assets and liabilities	1			15
Balance at Sept. 30	$	15		$	48
Gains (losses) recognized in earnings ^(a)							6			(18		)
Net gains (losses) recognized as regulatory assets and liabilities							1			(11		)
Balance at March 31							$	5		$	(7	)


^(a)	~~These amounts~~Amounts relate to commodity derivatives held at the end of the period.

Xcel Energy recognizes transfers between ~~fair value hierarchy~~ levels as of the beginning of each period. There were 0 transfers of amounts between levels for derivative instruments for the three ~~and nine~~ months ended ~~Sept. 30, 2019~~March 31, 2020 and ~~2018.~~2019.

Fair Value of Long-Term Debt

Other financial instruments ~~for~~ which the carrying amount did not equal fair value:


	Sept. 30, 2019				Dec. 31, 2018				March 31, 2020				Dec. 31, 2019
(Millions of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	17,672	$	20,064	$	16,209	$	16,755	$	18,112	$	19,864	$	18,109	$	20,227

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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 ~~Sept. 30, 2019~~March 31, 2020 and Dec. 31, ~~2018,~~2019, and given the observability of the inputs, fair values presented for long-term debt were assigned as Level 2.

9. Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost (Credit)


	Three Months Ended Sept. 30												Three Months Ended March 31
	2019			2018			2019			2018			2020			2019			2020			2019
(Millions of Dollars)	Pension Benefits						Postretirement Health Care Benefits						Pension Benefits						Postretirement Health Care Benefits
Service cost	$	22		$	24		$	—		$	1		$	24		$	22		$	—		$	—
Interest cost ^(a)	36			33			6			5			31			36			5			6
Expected return on plan assets ^(a)	(51		)	(52		)	(5		)	(6		)	(52		)	(51		)	(5		)	(5		)
Amortization of prior service credit ^(a)	(1		)	(1		)	(3		)	(3		)	(1		)	(1		)	(2		)	(3		)
Amortization of net loss ^(a)	22			27			1			2			25			22			1			1
Settlement charge ^(b)	—			59			—			—
Net periodic benefit cost (credit)	28			90			(1		)	(1		)	27			28			(1		)	(1		)
Credits (costs) not recognized due to the effects of regulation	—			(50		)	—			1
Credits not recognized due to effects of regulation													2			1			1			—
Net benefit cost (credit) recognized for financial reporting	$	28		$	40		$	(1	)	$	—		$	29		$	29		$	—		$	(1	)

Nine Months Ended Sept. 30
2019 2018 2019 2018
(Millions of Dollars) Pension Benefits Postretirement Health
Care Benefits
Service cost $ 64
$ 71
$ 1
$ 1
Interest cost ^(a)
108
100
17
16
Expected return on plan assets ^(a)
(152 ) (157 ) (16 ) (19 )
Amortization of prior service credit ^(a)
(3 ) (3 ) (8 ) (8 )
Amortization of net loss ^(a)
66
83
4
6
Settlement charge ^(b)
—
59
—
—
Net periodic benefit cost (credit) 83
153
(2 ) (4 )
Credits (costs) not recognized due to the effects of regulation 2
(51 ) 1
1
Net benefit cost (credit) recognized for financial reporting $ 85
$ 102
$ (1 ) $ (3 )


^(a)	Components of net periodic cost other than the service cost component are included in the line item “other ~~expense,~~(expense) income, net” in the consolidated statement of income or capitalized on the consolidated balance sheet as a regulatory asset.

^(b)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 the third quarter of 2018 as a result of lump-sum distributions during the 2018 plan year, Xcel Energy recorded a total pension settlement charge of $59 million, the majority of which was not recognized due to the effects of regulation. A total of $6 million of that amount was recorded in other expense in the third quarter of 2018.

In January ~~2019,~~2020, contributions of $150 million were made across 4 of Xcel Energy’s pension plans. ~~In July 2019, Xcel Energy made a $4 million contribution to the Xcel Energy Inc. Non-Bargaining Pension Plan (South).~~ Xcel Energy does not expect additional pension contributions during ~~2019.~~2020.

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10. Commitments and Contingencies

The following include commitments, contingencies and unresolved contingencies that are material to Xcel Energy’s financial position.

Legal

Xcel Energy is involved in various litigation matters in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for losses probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories.

In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, would have a material effect on Xcel Energy’s financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred.

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 seeking monetary damages were commenced against e prime and its affiliates, including Xcel Energy, between 2003 and 2009 alleging fraud and anticompetitive activities in conspiring to restrain the trade of natural gas and manipulate natural gas prices. Cases were all consolidated in the U.S. District Court in Nevada.

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

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

Arandell Corp. — In February 2019, the case was remanded back to the U.S. District Court in Wisconsin. Plaintiffs are seeking class certification. It is uncertain when the court will rule on this issue.

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 50 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 DRC. PSCo filed a motion to dismiss this claim, which was granted in May 2018. DRC subsequently filed an appeal to the Colorado Court of Appeals. It is uncertain when a decision will be rendered.

PSCo has concluded that a loss is remote with respect to both of these matters as the service agreements were developed to implement CPUC approved tariffs and PSCo has complied with the tariff provisions. If a loss were sustained, PSCo believes it would be allowed to recover costs through traditional regulatory mechanisms. Amount or range in dispute is presently unknown and 0 accrual has been recorded for this matter.

Rate Matters

MEC Transactions — 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, 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 existing PPAs with NSP-Minnesota. A newly formed non-regulated subsidiary of Xcel Energy completed the transaction to purchase MEC in January 2020.

In April 2020, Xcel Energy reached agreement to sell MEC to Southwest Generation for $680 million, subject to working capital adjustments. Proceeds from the sale will primarily be used to reduce Xcel Energy’s overall financing needs. The transaction is not anticipated to have a material impact on long-term earnings per share and is expected to close in the third quarter of 2020.

The sale will result in a gain, which Xcel Energy plans to use to fund its corporate giving efforts, including support related to COVID-19 recovery.

NSP-Minnesota — Sherco — In NSP-Minnesota’s 2013 fuel reconciliation filing, the MPUC made recovery of replacement power costs associated with athe 2011 ~~turbine malfunction~~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 ~~has~~ 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, ~~the~~ 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. The lower court’s decision was affirmed on appeal. In March 2020, NSP-Minnesota’s insurers filed a petition seeking additional review by the Minnesota Supreme Court, which remains pending.

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

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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 ~~October 2018,~~November 2019, the FERC issued an ~~ROE~~ order that addressed the D.C. Circuit’s actions. Under a new proposed 2 step ROE approach, the FERC indicated an intention to dismiss an ROE complaint if the existing ROE falls within the range of just and reasonable ROEs based on equal weighting of the DCF, CAPM, and Expected Earnings models. The FERC proposed that if necessary, it would then setadopting a new ROE ~~by averaging~~methodology and settling the ~~results of these models plus a Risk Premium model.~~

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 ~~subsequently made preliminary determinations in~~also dismissed the second complaint. In December 2019, MISO TOs filed a ~~November 2018 order~~request for rehearing. Customers also filed requests for rehearing claiming, among other points, that the ~~MISO TO’s base ROE~~FERC erred by dismissing the second complaint without refunds.

FERC accepted the requests for rehearing in ~~effect for~~January 2020, however, it is uncertain when the ~~first complaint period (12.38%) was outside~~FERC will act on the ~~range of reasonableness, and should be reduced. The FERC indicated its preliminary analysis using the new ROE approach resulted in a base ROE of 10.28% for the first complaint period, compared~~requests or any other pending matters related to the ~~previously ordered base ROE of 10.32%~~2019 NOIs.

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NSP-Minnesota has recognized a ~~current refund~~ liability ~~consistent with~~for its best estimate of final refunds to customers.

In March 2020, the FERC issued a Notice of Proposed Rulemaking regarding changes to its policies for transmission incentives, including a proposal to increase the RTO participation adder from 50 to 100 basis points and to make the adder available regardless of whether a utility’s ongoing participation in the RTO is voluntary or required by legislation or a regulator. It is uncertain if or when this change will be adopted and implemented as a final ~~ROE, pending further FERC action as early as the fourth quarter of 2019.~~order.

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

In July 2018, SPS’ appeal to the D.C. Circuit over the FERC rulings granting SPP the right to recover these previously unbilled charges was remanded to the FERC. In February 2019, the FERC reversed its 2016 decision and ordered SPP to refund the 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. In February 2020, FERC issued an order rejecting all rehearing requests and providing certain clarifications. In March 2020, SPP and Oklahoma Gas & Electric separately filed petitions for review of FERC’s orders at the D.C. Circuit. SPS has intervened in both appeals in support of FERC. The timing of ~~a FERC response to the rehearing requests~~an appeals decision 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 that SPP has assessed upgrade charges to SPS in violation of the SPP OATT. The FERC granted a rehearing for further consideration in May 2018. The 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

MGP, Landfill and Disposal Sites

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

The current cost estimate for remediation and restoration of the entire site is approximately ~~$194~~$199 million. At ~~Sept. 30, 2019~~March 31, 2020 and Dec. 31, ~~2018, NSP-Wisconsin~~2019, NSP‑Wisconsin had a total liability of $22 million and ~~$27~~$23 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 ~~2012,~~its final December 2019 order approving 2020 and 2021 natural gas base rates, the PSCW ~~agreed to allow NSP-Wisconsin to pre-collect certain~~authorized continued amortization of costs ~~to amortize costs over 10 years~~ and ~~to apply~~application of a 3% carrying ~~cost~~charge to the ~~unamortized~~ regulatory asset.

Rice Yards (Denver ) MGP ~~Landfill or Disposal Sites~~Site — — 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 to the Rice Yards and Ashland Sites, Xcel Energy is currently investigating, remediating or ~~remediating 12~~performing post-closure actions at 11 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 ~~the~~ costs incurred.

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Environmental Requirements — Water and Waste

Coal Ash Regulation — Xcel Energy’s operations are subject to federal and state ~~laws~~regulations that impose requirements for handling, storage, treatment and disposal of solid waste.

Under the CCR Rule, utilities are required to complete groundwater sampling around their CCR landfills and surface impoundments. ~~By the end of 2019, only~~Currently, Xcel Energy has 9 ~~of Xcel Energy’s~~ regulated ash units ~~are expected to be~~ in operation.

Xcel Energy is conducting groundwater sampling and, where appropriate, ~~initiating the~~implementing assessment of corrective measures at certain CCR landfills and surface impoundments. In 2019, groundwater monitoring consistent with the CCR Rule was conducted. In NSP-Minnesota, 0 results above the groundwater protection standards in the rule were identified. In PSCo, statistically significant increases above background concentrations were detected at 4 locations. Subsequently, assessment monitoring samples were collected, and PSCo is evaluating ~~whether~~options for corrective action ~~is required~~ at ~~any CCR landfills or surface impoundments.~~

2 locations. Until ~~Xcel Energy~~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 1 impoundment at an estimated cost of $4 million and the construction of a new impoundment at the cost of $8 million. In 2019, NSP-Minnesota 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 under the D.C. Circuit ruling may require PSCo to expedite the closure of 1 coal ash impoundment that was not previously required to close. PSCo is pursuing options through comment on the proposed rules or some other means to allow continued operation of this impoundment until the generating units are retired in 2025, at which time the impoundment would be closed.

Closure costs for existing impoundments are included in the calculation of the asset retirement obligation liability.

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 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) Sept. 30, 2019
PPAs $ 1,642
Other 201
Gross operating lease ROU assets 1,843
Accumulated amortization (125 )
Net operating lease ROU assets $ 1,718

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.

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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) Sept. 30, 2019
Gas storage facilities $ 201
Gas pipeline 21
Gross finance lease ROU assets 222
Accumulated amortization (81 )
Net finance lease ROU assets $ 141

~~Components of lease expense:~~

(Millions of Dollars) Three Months Ended Sept. 30, 2019 Nine Months Ended Sept. 30, 2019
Operating leases
PPA capacity payments $ 58
$ 163
Other operating leases ^(a)
9
26
Total operating lease expense ^(b)
$ 67
$ 189

Finance leases
Amortization of ROU assets $ 1
$ 5
Interest expense on lease liability 5
14
Total finance lease expense $ 6
$ 19


^(a)	~~Includes short-term lease expense of $1 million for the three months ended Sept. 30, 2019 and $4 million for the nine months ended Sept. 30, 2019.~~


^(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.

Xcel Energy has requested regulatory approval to purchase the MEC in the fourth quarter of 2019. Xcel Energy currently receives energy and capacity from MEC under PPAs expiring in 2026 and 2039. Pending the purchase by Xcel Energy, operating lease liabilities at ~~Sept. 30,~~Dec. 31, 2019 ~~currently~~ include a present value of ~~$415~~remaining lease payments of approximately $400 million for the MEC ~~PPA capacity payments.~~

~~Future commitments under~~PPAs. At March 31, 2020, NSP-Minnesota operating lease liabilities and ~~finance leases as~~related ROU assets are eliminated from Xcel Energy’s consolidated balance sheet following the completed January 2020 purchase of ~~Sept. 30, 2019:~~MEC by Xcel Energy.

(Millions of Dollars)
PPA ^{(a) (b)}
Operating
Leases

Other Operating
Leases

Total
Operating
Leases

Finance
Leases ^(c)
2019 $ 59
$ 6
$ 65
$ 3
2020 236
26
262
14
2021 238
29
267
14
2022 225
28
253
12
2023 214
25
239
12
Thereafter 959
136
1,095
219
Total minimum obligation 1,931
250
2,181
274
Interest component of obligation (337 ) (54 ) (391 ) (192 )
Present value of minimum obligation $ 1,594
$ 196
1,790
82
Less current portion (192 ) (4 )
Noncurrent operating and finance lease liabilities $ 1,598
$ 78

Weighted-average remaining lease term in years 9.5
37.2


^(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.~~

~~Future 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.~~

~~Variable Interest Entities~~VIEs

Under certain PPAs, NSP-Minnesota, PSCo and SPS purchase power from IPPs ~~and~~for which the utility subsidiaries are required to reimburse ~~the IPPs for natural gas or~~ fuel costs, or to participate in tolling arrangements under which the utility subsidiaries procure the natural gas required to produce the energy that they purchase. These specific PPAs create a variable interest in the ~~associated~~ IPP.

~~Xcel Energy~~The utility subsidiaries had approximately ~~3,986~~3,266 MW and ~~3,770~~3,986 MW of capacity under ~~long-term~~long‑term PPAs ~~as of Sept. 30, 2019~~at March 31, 2020 and Dec. 31, ~~2018,~~2019, respectively, with entities that have been determined to be ~~variable interest entities.~~VIEs. Xcel Energy ~~has~~ 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. ~~These agreements~~Agreements have ~~various~~ expiration dates through 2041.

~~Table of Contents~~

Other

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 ~~Sept. 30, 2019~~March 31, 2020 and Dec. 31, ~~2018,~~2019, Xcel Energy Inc. and its subsidiaries had 0 assets held as collateral related to their guarantees, bond indemnities and indemnification agreements.

Guarantees and bond indemnities issued and outstanding for Xcel Energy were $60 million and $62 million ~~and $69 million~~ at ~~Sept. 30, 2019~~March 31, 2020 and Dec. 31, ~~2018,~~2019, respectively.

Other Indemnification Agreements — Xcel Energy Inc. and its subsidiaries provide indemnifications through various contracts. These are primarily indemnifications against adverse litigation outcomes in connection with underwriting agreements, as well as breaches of representations and warranties, including corporate existence, transaction authorization and income tax matters with respect to assets sold. Xcel Energy Inc.’s and its subsidiaries’ obligations under these agreements may be limited in terms of duration and amount. Maximum future payments under these indemnifications cannot be reasonably estimated as the dollar amounts are often not explicitly stated.

11. Other Comprehensive Loss

Changes in accumulated other comprehensive loss, net of tax, for the three ~~and nine~~ months ended ~~Sept. 30, 2019~~March 31, 2020 and ~~2018:~~2019:

Three Months Ended Sept. 30, 2019 Three Months Ended Sept. 30, 2018
(Millions of Dollars)
Gains and Losses
on Cash Flow Hedges

Defined Benefit Pension and
Postretirement Items
Total
Gains and Losses
on Cash Flow Hedges

Defined Benefit Pension and
Postretirement Items
Total
Accumulated other comprehensive loss at July 1 $ (75 ) $ (60 ) $ (135 ) $ (57 ) $ (65 ) $ (122 )
Other comprehensive (loss) before reclassifications (net of taxes of $(3), $0, $0 and $(1), respectively) (9 ) —
(9 ) —
(2 ) (2 )
Losses reclassified from net accumulated other comprehensive loss:

Interest rate derivatives (net of taxes of $0) ^(a)
1
—
1
1
—
1
Amortization of net actuarial loss (net of taxes of $0, $0, $0 and $1, respectively) ^(b)
—
1
1
—
4
4
Net current period other comprehensive income (8 ) 1
(7 ) 1
2
3
Accumulated other comprehensive loss at Sept. 30 $ (83 ) $ (59 ) $ (142 ) $ (56 ) $ (63 ) $ (119 )

Nine Months Ended Sept. 30, 2019 Nine Months Ended Sept. 30, 2018
(Millions of Dollars)
Gains and Losses
on Cash Flow Hedges

Defined Benefit Pension and
Postretirement Items
Total
Gains and Losses
on Cash Flow Hedges

Defined Benefit Pension and
Postretirement Items
Total
Accumulated other comprehensive loss at Jan. 1 $ (60 ) $ (64 ) $ (124 ) $ (58 ) $ (67 ) $ (125 )
Other comprehensive (loss) gain before reclassifications (net of taxes of $(9), $1, $0 and $(1), respectively) (25 ) 2
(23 ) —
(2 ) (2 )
Losses reclassified from net accumulated other comprehensive loss:

Interest rate derivatives (net of taxes of $1, $0, $1 and $0, respectively) ^(a)
2
—
2
2
—
2
Amortization of net actuarial loss (net of taxes of $0, $1, $0 and $2, respectively) ^(b)
—
3
3
—
6
6
Net current period other comprehensive income (23 ) 5
(18 ) 2
4
6
Accumulated other comprehensive loss at Sept. 30 $ (83 ) $ (59 ) $ (142 ) $ (56 ) $ (63 ) $ (119 )



	Three Months Ended March 31, 2020
(Millions of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit Pension and Postretirement Items			Total
Accumulated other comprehensive loss at Jan. 1	$	(80	)	$	(61	)	$	(141	)
Other comprehensive loss before reclassifications (net of taxes of $(3) and $0, respectively)	(10		)	—			(10		)
Losses reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (net of taxes of $0) ^(a)	2			—			2
Amortization of net actuarial loss (net of taxes of $0) ^(b)	—			1			1
Net current period other comprehensive (loss) income	(8		)	1			(7		)
Accumulated other comprehensive loss at March 31	$	(88	)	$	(60	)	$	(148	)


^(a)	Included in interest charges.


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

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	Three Months Ended March 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) gain before reclassifications (net of taxes of $(2) and $1, respectively)	(7		)	2			(5		)
Losses reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (net of taxes of $0) ^(a)	1			—			1
Amortization of net actuarial loss (net of taxes of $0) ^(b)	—			1			1
Net current period other comprehensive (loss) income	(6		)	3			(3		)
Accumulated other comprehensive loss at March 31	$	(66	)	$	(61	)	$	(127	)


^(a)	Included in interest charges.


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

~~12. Segment Information~~

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 are each separately and regularly reviewed by Xcel Energy’s chief operating decision maker.



12. Segment Information

Xcel Energy evaluates performance by each utility subsidiary based on profit or loss generated from the product or service ~~provided.~~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.~~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.

~~Table of Contents~~


•	~~All Other~~ - Operating segments with revenues below the necessary quantitative thresholds are included in this category. Those 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 ~~$151~~$158 million and ~~$141~~$155 million as of ~~Sept. 30, 2019~~March 31, 2020 and Dec. 31, ~~2018,~~2019, 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 for the three ~~and nine~~ months ended ~~Sept. 30:~~March 31:

Three Months Ended Sept. 30
(Millions of Dollars) 2019 2018
Regulated Electric
Operating revenues from external customers $ 2,771
$ 2,802
Net income 550
514
Regulated Natural Gas
Operating revenues from external customers $ 222
$ 227
Net (loss) income (1 ) 9
All Other
Total operating revenue $ 20
$ 19
Net loss (22 ) (32 )

Consolidated Total
Total revenue $ 3,013
$ 3,048
Net income 527
491


	Nine Months Ended Sept. 30
(Millions of Dollars)	2019			2018			2020			2019
Regulated Electric
Operating revenues from external customers	$	7,345		$	7,419		$	2,203		$	2,325
Intersegment revenue	1			1
Total revenues	$	7,346		$	7,420
Net income	1,032			997			227			234
Regulated Natural Gas
Operating revenues from external customers	$	1,324		$	1,181		$	583		$	794
Intersegment revenue	1			1			—			1
Total revenues	$	1,325		$	1,182		$	583		$	795
Net income	127			130			91			105
All Other
Total operating revenue	$	62		$	57		$	25		$	22
Net loss	(79		)	(80		)	(23		)	(24		)

Consolidated Total
Total revenue	$	8,733		$	8,659		$	2,811		$	3,142
Reconciling eliminations	(2		)	(2		)	—			(1		)
Consolidated total revenue	$	8,731		$	8,657		$	2,811		$	3,141
Net income	1,080			1,047			295			315

~~Item~~



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

The following discussion and analysis by management focuses on those factors that had a material effect on Xcel Energy’s financial condition, results of operations and cash flows during the periods presented, or are expected to have a material impact in the future. It should be read in conjunction with the accompanying unaudited consolidated financial statements and the related notes to consolidated financial statements.

Due to the seasonality of Xcel Energy’s operating results, quarterly financial results are not an appropriate base from which to project annual results. The demand for electric power and natural gas is affected by seasonal differences in the weather. In general, peak sales of electricity occur in the summer months, and peak sales of natural gas occur in the winter months. As a result, the overall operating results may fluctuate substantially on a seasonal basis. Additionally, Xcel Energy’s operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer.

Non-GAAP Financial Measures

The following discussion includes financial information prepared in accordance with GAAP, as well as certain non-GAAP financial measures such as electric margin, natural gas margin, ongoing earnings and ongoing diluted EPS. Generally, a non-GAAP financial measure is a measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are adjusted from measures calculated and presented in accordance with GAAP. Xcel Energy’s management uses non-GAAP measures for financial planning and analysis, for reporting of results to the Board of Directors, in determining performance-based compensation, and communicating its earnings outlook to analysts and investors. Non-GAAP financial measures are intended to supplement investors’ understanding of our performance and should not be considered alternatives for financial measures presented in accordance with GAAP. These measures are discussed in more detail below and may not be comparable to other companies’ similarly titled non-GAAP financial measures.

2521

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Electric and Natural Gas Margins

Electric margin is presented as electric revenues less electric fuel and purchased power expenses. Natural gas margin is presented as natural gas revenues less the cost of natural gas sold and transported. Expenses incurred for electric fuel and purchased power and the cost of natural gas are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues.

Management believes electric and natural gas margins provide the most meaningful basis for evaluating our operations because they exclude the revenue impact of fluctuations in these expenses. These margins can be reconciled to operating income, a GAAP measure, by including other operating revenues, cost of sales — other, O&M expenses, conservation and DSM expenses, depreciation and amortization and taxes (other than income taxes).

Earnings Adjusted for Certain Items (Ongoing Earnings and Ongoing Diluted EPS)

GAAP diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock (i.e., common stock equivalents) were settled. The weighted average number of potentially dilutive shares outstanding used to calculate Xcel Energy Inc.’s diluted EPS is calculated using the treasury stock method. Ongoing earnings reflect adjustments to GAAP earnings (net income) for certain items.

Ongoing diluted EPS is calculated by dividing the net income or loss of each subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period. Ongoing diluted EPS for each subsidiary is calculated by dividing the net income or loss of such subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period.

We use these non-GAAP financial measures to evaluate and provide details of Xcel Energy’s core earnings and underlying performance. We believe these measurements are useful to investors to evaluate the actual and projected financial performance and contribution of our subsidiaries.

For the three ~~and nine~~ months ended ~~Sept. 30,~~March 31, 2020 and 2019, ~~and 2018,~~ there were no such adjustments to GAAP earnings and therefore GAAP earnings equal ongoing earnings for these periods.

Results of Operations

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

GAAP and ongoing diluted EPS for Xcel Energy:


	Three Months Ended Sept. 30						Nine Months Ended Sept. 30						Three Months Ended March 31
Diluted Earnings (Loss) Per Share	2019			2018			2019			2018			2020			2019
PSCo	$	0.39		$	0.41		$	0.86		$	0.91		$	0.24		$	0.27
NSP-Minnesota	0.40			0.39			0.81			0.79			0.20			0.22
SPS	0.20			0.16			0.42			0.34			0.08			0.10
NSP-Wisconsin	0.06			0.06			0.12			0.15			0.06			0.05
Equity earnings of unconsolidated subsidiaries	0.01			0.01			0.04			0.03			0.01			0.01
Regulated utility ^(a)	1.06			1.03			2.24			2.22			0.60			0.65
Xcel Energy Inc. and Other	(0.05		)	(0.07		)	(0.16		)	(0.17		)	(0.04		)	(0.04		)
Total ^(a)	$	1.01		$	0.96		$	2.08		$	2.05		$	0.56		$	0.61


^(a)	Amounts may not add due to rounding.

Summary of Earnings

Xcel Energy — Xcel Energy’s earnings ~~increased~~decreased $0.05 per share for the ~~third~~first quarter of ~~2019 and~~2020. Earnings reflect the negative impact of weather. The impact of COVID-19 did not significantly impact first quarter 2020 results, but could have a material impact on our financial results going forward. See COVID-19 section below for further discussion.

PSCo — Earnings decreased $0.03 per share ~~year-to-date.~~ ~~Earnings reflect higher electric~~for the first quarter of 2020, reflecting lower natural gas margins primarily due to ~~non-fuel riders~~unfavorable weather, higher depreciation and ~~regulatory rate outcomes and lower~~ O&M, ~~expenses,~~ partially offset by ~~lower AFUDC, increased depreciation~~higher electric margin and ~~interest expenses.~~AFUDC.

~~PSCo~~NSP-Minnesota — Earnings decreased $0.02 per share for the ~~third~~first quarter of ~~2019~~2020, driven by reduced natural gas margins primarily due to unfavorable weather as well as lower electric margin, which reflects the unfavorable weather experienced in North and ~~$0.05~~South Dakota. NSP-Minnesota also recognized increased interest and higher depreciation, partially offset by lower O&M and income taxes.

SPS — Earnings decreased $0.02 per share ~~year-to-date. The decrease in year-to-date earnings was driven by higher depreciation, O&M, interest expense and~~for the first quarter of 2020, reflecting lower ~~allowance for funds used during construction (AFUDC), which offsets higher natural gas and~~ electric ~~margin. Changes in~~margin primarily due to a 2019 NMPRC revised order eliminating a $10 million retroactive refund of tax reform benefits. SPS also recognized additional depreciation and less AFUDC, ~~are primarily driven~~partially offset by ~~the Rush Creek wind project that was placed in service in 2018.~~lower income taxes.

~~NSP-Minnesota~~NSP-Wisconsin — Earnings increased $0.01 per share for the ~~third~~first quarter of ~~2019~~2020, driven by reduced O&M and ~~$0.02 per share year-to-date. Year-to-date results reflect~~ higher electric margin, ~~driven by regulatory rate outcomes,~~ partially offset by ~~the negative impact of weather, unfavorable sales and increased depreciation.~~

~~SPS~~ — Earnings increased $0.04 for the third quarter of 2019 and $0.08 per share year-to-date. Year-to-date results reflect higher electric margin attributable to regulatory rate outcomes and sales growth despite unfavorable weather. Higher electric margin and AFUDC associated with the Hale wind project were partially offset by increased depreciation, O&M and interest expenses.

~~NSP-Wisconsin~~ ~~— Earnings were flat for the third quarter of 2019 and decreased $0.03 per share year-to-date. Year-to-date results reflect unfavorable weather, higher~~additional depreciation and lower ~~AFUDC.~~natural gas margin.

Xcel Energy Inc. and Other — ~~Xcel Energy Inc. and Other primarily~~Primarily includes financing costs at the holding company.

Changes in GAAP and Ongoing Diluted EPS

Components significantly contributing to changes in ~~2019~~2020 EPS compared with the same period in ~~2018:~~2019:

Diluted Earnings (Loss) Per Share Three Months Ended Sept. 30 Nine Months Ended Sept. 30
GAAP and ongoing diluted EPS — 2018 $ 0.96
$ 2.05

Components of change — 2019 vs. 2018
Higher electric margins 0.08
0.22
Lower ETR ^(a)
0.03
0.12
Higher natural gas margin —
0.05
Higher depreciation and amortization (0.01 ) (0.17 )
Higher interest charges (0.03 ) (0.08 )
Lower AFUDC (0.04 ) (0.06 )
Changes in O&M 0.02
(0.05 )
GAAP and ongoing diluted EPS — 2019 $ 1.01
$ 2.08



Diluted Earnings (Loss) Per Share	Three Months Ended March 31
GAAP and ongoing diluted EPS — 2019	$	0.61

Components of change — 2020 vs. 2019
Higher depreciation and amortization	(0.04		)
Lower electric and natural gas margins	(0.03		)
Higher interest	(0.01		)
Lower ETR ^(a)	0.03
Lower O&M	0.03
Lower other (expense) income, net ^(b)	(0.02		)
Other (net)	(0.01		)
GAAP and ongoing diluted EPS — 2020	$	0.56


^(a)	Includes PTCs and timing of tax reform regulatory decisions, which are primarily offset in electric margin.

~~Table of Contents~~


^(b)	Decrease is primarily due to the performance of rabbi trust investments associated with deferred compensation, which is offset in O&M.

Statement of Income Analysis

The following summarizes the items that affected the individual revenue and expense items reported in the consolidated statements of income.

Estimated Impact of Temperature Changes on Regulated Earnings ~~— Unusually~~—Unusually hot summers or cold winters increase electric and natural gas sales, while mild weather reduces electric and natural gas sales. The estimated impact of weather on earnings is based on the number of customers, temperature variances, ~~and~~ the amount of natural gas or electricity historically used per degree of ~~temperature. Weather~~temperature and excludes any incremental related operating expenses that could result due to storm activity or vegetation management requirements. As a result, weather deviations from normal levels can affect Xcel Energy’s financial performance.

Table of Contents

Degree-day or ~~Temperature-Humidity Index (THI)~~THI data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day’s average temperature and humidity. ~~Heating degree-days (HDD)~~HDD is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit. ~~Cooling degree-days (CDD)~~CDD is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65° Fahrenheit. Each degree of temperature above 65° Fahrenheit is counted as one CDD, and each degree of temperature below 65° Fahrenheit is counted as one HDD. In Xcel Energy’s more humid service territories, a THI is used in place of CDD, which adds a humidity factor to CDD. HDD, CDD and THI are most likely to impact the usage of Xcel Energy’s residential and commercial customers. Industrial customers are less sensitive to weather.

Normal weather conditions are defined as either the ~~20-year~~10, 20 or 30-year average of actual historical weather conditions. The historical period of time used in the calculation of normal weather differs by jurisdiction, based on regulatory practice. To calculate the impact of weather on demand, a demand factor is applied to the weather impact on sales. Extreme weather variations, windchill and cloud cover may not be reflected in weather-normalized estimates.

There was no impact on sales for the first quarter of 2020 due to THI or CDD. Percentage ~~increase (decrease)~~change in normal and actual ~~HDD, CDD and THI:~~HDD:

Three Months Ended Sept. 30 Nine Months Ended Sept. 30
2019 vs.
Normal 2018 vs.
Normal 2019 vs.
2018 2019 vs.
Normal 2018 vs.
Normal 2019 vs.
2018
HDD (64.0 )% (18.2 )% (57.0 )% 10.7 % (0.3 )% 9.4 %
CDD 27.4
14.8
20.9
6.4
27.1
(14.9 )
THI (2.6 ) 18.2
(17.0 ) (8.2 ) 38.4
(33.2 )



	Three Months Ended March 31
	2020 vs. Normal		2019 vs. Normal		2020 vs. 2019
HDD	(5.5	)%	10.5	%	(14.1	)%

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

Three Months Ended Sept. 30 Nine Months Ended Sept. 30
2019 vs.
Normal 2018 vs.
Normal 2019 vs.
2018 2019 vs.
Normal 2018 vs.
Normal 2019 vs.
2018
Retail electric $ 0.040
$ 0.043
$ (0.003 ) $ 0.035
$ 0.110
$ (0.075 )
Firm natural gas (0.001 ) —
(0.001 ) 0.021
0.003
0.018
Total (excluding decoupling) $ 0.039
$ 0.043
$ (0.004 ) $ 0.056
$ 0.113
$ (0.057 )
Decoupling — Minnesota
—
(0.018 ) 0.018
0.001
(0.050 ) 0.051
Total (adjusted for decoupling) $ 0.039
$ 0.025
$ 0.014
$ 0.057
$ 0.063
$ (0.006 )



	Three Months Ended March 31
	2020 vs. Normal			2019 vs. Normal			2020 vs. 2019
Retail electric	$	(0.011	)	$	0.018		$	(0.029	)
MN decoupling and sales true-up	0.006			(0.005		)	0.011
Electric total	$	(0.005	)	$	0.013		$	(0.018	)
Firm natural gas	(0.007		)	0.017			(0.024		)
Total	$	(0.012	)	$	0.030		$	(0.042	)

Sales Growth (Decline) — Sales growth (decline) for actual and weather-normalized sales in ~~2019~~2020 compared to the same period in ~~2018:~~2019:


	Three Months Ended Sept. 30										Three Months Ended March 31
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy		PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Actual
Electric residential	1.7	%	(6.2	)%	5.9	%	(1.8	)%	(1.2	)%	(0.9	)%	(4.8	)%	(1.4	)%	(6.3	)%	(3.0	)%
Electric C&I	(1.6	)	(6.1	)	4.6		(3.6	)	(1.9	)	0.2		(3.9	)	3.3		(0.4	)	(0.6	)
Total retail electric sales	(0.5	)	(6.1	)	4.7		(3.1	)	(1.7	)	(0.2	)	(4.2	)	2.3		(2.2	)	(1.3	)
Firm natural gas sales	4.2		1.7		N/A		(10.6	)	2.5		(6.6	)	(13.4	)	N/A		(14.4	)	(9.3	)



	Three Months Ended March 31
	PSCo ^(a)		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Weather-normalized
Electric residential	1.0	%	0.2	%	0.6	%	1.6	%	0.7	%
Electric C&I	0.6		(3.2	)	3.4		0.4		(0.1	)
Total retail electric sales	0.7		(2.2	)	2.8		0.8		0.1
Firm natural gas sales	0.8		2.6		N/A		3.3		1.5

Three Months Ended Sept. 30
PSCo NSP-Minnesota SPS NSP-Wisconsin Xcel Energy
Weather-normalized
Electric residential (1.1 )% (1.0 )% (1.4 )% 1.5 % (0.9 )%
Electric C&I (2.8 ) (4.4 ) 3.6
(2.8 ) (1.8 )
Total retail electric sales (2.2 ) (3.4 ) 2.4
(1.7 ) (1.6 )
Firm natural gas sales 6.8
4.0
N/A
(7.9 ) 5.1



	Three Months Ended March 31 (Leap Year Adjusted)
	PSCo ^(a)		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Weather-normalized
Electric residential	(0.1	)%	(0.9	)%	(0.5	)%	0.5	%	(0.4	)%
Electric C&I	(0.5	)	(4.3	)	2.3		(0.7	)	(1.2	)
Total retail electric sales	(0.4	)	(3.3	)	1.7		(0.3	)	(1.0	)
Firm natural gas sales	(0.4	)	1.4		N/A		2.1		0.4


^(a)	CPUC approved a historical 10-year weather normalization approach for retail electric, effective March 1, 2020, which did not materially impact the weather-normalized calculation.

Nine Months Ended Sept. 30
PSCo NSP-Minnesota SPS NSP-Wisconsin Xcel Energy
Actual
Electric residential (0.4 )% (4.8 )% (0.4 )% (2.4 )% (2.4 )%
Electric C&I (0.9 ) (4.6 ) 3.9
(2.8 ) (1.2 )
Total retail electric sales (0.7 ) (4.6 ) 2.9
(2.7 ) (1.6 )
Firm natural gas sales 15.6
5.3
N/A
(1.7 ) 10.9

Nine Months Ended Sept. 30
PSCo NSP-Minnesota SPS NSP-Wisconsin Xcel Energy
Weather-normalized
Electric residential (0.2 )% — % 1.2 % 1.1 % 0.2 %
Electric C&I (0.8 ) (3.2 ) 4.2
(2.0 ) (0.5 )
Total retail electric sales (0.5 ) (2.3 ) 3.5
(1.2 ) (0.3 )
Firm natural gas sales 4.9
1.3
N/A
(4.1 ) 3.2

~~Year-to-date weather-normalized~~Weather-normalized and Leap-Year Adjusted Electric Sales Growth (Decline)

All companies were negatively impacted by COVID-19 in March 2020. In addition, the following items impacted sales in each of the companies:

PSCo — Residential sales ~~were lower~~declined slightly due to ~~a decrease in~~lower use per customer, ~~usage,~~ partially offset by ~~customer additions. Commercial and industrial (C&I)~~an increase in customers. The decline in C&I was mainly due to lower ~~usage in~~use per customer, primarily led by the food products and service industries, partially offset by growth in ~~metal fabrication and mining industries.~~the energy industry.

NSP-Minnesota — ~~Decline~~Residential sales declined reflecting lower use per customer, partially offset by customer additions. The decline in C&I sales was ~~due to expected discrete~~a result of lower use by certain customers in the energy, manufacturing ~~customer declines due to newly installed co-generation, which was~~and services sectors, partially offset by ~~an increase in customers.~~customer growth.

~~Table of Contents~~

SPS — Residential sales ~~growth was~~decreased slightly primarily due to ~~customer additions, partially offset by~~ lower use per customer. ~~Higher~~ C&I sales ~~was primarily driven by increase~~grew based on higher sales to large customers in the oil and natural gas industry in the Permian Basin.

NSP-Wisconsin — Residential sales growth was primarily attributable to customer additions, ~~and increased usage. Decline~~partially offset by less use per customer. The decline in C&I sales was largely due to lower use per customer, partially offset by customer additions and decreased sales to the ~~mining,~~ manufacturing sector, which was partially offset by an increase in the energy sector.

Weather-normalized and ~~food industries.~~

~~Year-to-date weather-normalized~~Leap-Year Adjusted Natural Gas Sales Growth (Decline)

Natural gas sales reflect an increase in the number of customers combined with ~~higher~~lower customer ~~use.~~use and the negative impacts of COVID-19 in March 2020.

Electric Margin

Electric revenues and fuel and purchased power expenses are impacted by fluctuations in the price of natural gas, coal and uranium used in the generation of electricity. However, these price fluctuations have minimal impact on electric margin due to fuel recovery mechanisms that recover fuel expenses.

In addition, electric customers receive a credit for PTCs generated in a particular period.

Electric revenues and margin:



	Three Months Ended March 31
(Millions of Dollars)	2020			2019
Electric revenues	$	2,203		$	2,325
Electric fuel and purchased power	(797		)	(914		)
Electric margin	$	1,406		$	1,411

Three Months Ended Sept. 30 Nine Months Ended Sept. 30
(Millions of Dollars) 2019 2018 2019 2018
Electric revenues $ 2,771
$ 2,802
$ 7,345
$ 7,419
Electric fuel and purchased power (952 ) (1,040 ) (2,679 ) (2,907 )
Electric margin $ 1,819
$ 1,762
$ 4,666
$ 4,512

Table of Contents

Changes in electric margin:

(Millions of Dollars) Three Months Ended Sept. 30,
2019 vs. 2018 Nine Months Ended Sept. 30,
2019 vs. 2018
Non-fuel riders ^(a)
$ 25
$ 81
Regulatory rate outcomes (Minnesota, New Mexico, North and South Dakota) 32
79
Wholesale transmission revenue (net) 11
22
Purchased capacity costs 6
21
Implementation of lease accounting standard (offset in interest expense and amortization) 5
16
Demand revenue (1 ) 12
Estimated impact of weather (net of Minnesota decoupling) 6
(26 )
Timing of tax reform regulatory decisions (offset in income tax and amortization) (3 ) (22 )
Sales declines (excluding weather impact and net of sales true-up) (16 ) (17 )
Firm wholesale generation (9 ) (14 )
Other (net)
1
2
Total increase in electric margin $ 57
$ 154



(Millions of Dollars)	Three Months Ended March 31, 2020 vs. 2019
PTCs flowed back to customers (offset by a lower ETR)	$	(23	)
Estimated impact of weather (net of decoupling/sales true-up)	(13		)
New Mexico tax reform related regulatory settlement (2019)	(10		)
Regulatory rate outcomes (Colorado and Wisconsin)	13
Non-fuel riders	13
Wholesale transmission revenue (net)	5
Sales growth (excluding weather impact, net of decoupling/sales true-up	4
Other (net)	6
Total decrease in electric margin	$	(5	)


^(a)	Includes approximately $17 million and $50 million, respectively, of additional PTC benefit (grossed-up for tax) as compared to the same periods in 2018, which are credited to customers through various regulatory mechanisms.

Natural Gas Margin

Natural gas expense varies with changing sales and the cost of natural gas. However, fluctuations in the cost of natural gas has minimal impact on natural gas margin due to cost recovery mechanisms.

Natural gas revenues and margin:


	Three Months Ended Sept. 30						Nine Months Ended Sept. 30						Three Months Ended March 31
(Millions of Dollars)	2019			2018			2019			2018			2020			2019
Natural gas revenues	$	222		$	227		$	1,324		$	1,181		$	583		$	794
Cost of natural gas sold and transported	(55		)	(58		)	(646		)	(537		)	(285		)	(479		)
Natural gas margin	$	167		$	169		$	678		$	644		$	298		$	315

Changes in natural gas margin:


(Millions of Dollars)	Three Months Ended Sept. 30, 2019 vs. 2018			Nine Months Ended Sept. 30, 2019 vs. 2018			Three Months Ended March 31, 2020 vs. 2019
Estimated impact of weather	$	—		$	12		$	(17	)
Transport sales							(2		)
Regulatory rate outcomes (Wisconsin)							(1		)
Retail sales growth							2
Infrastructure and integrity riders	4			11			1
Retail sales growth	1			5
Retail rate increase (Colorado, partially offset in amortization)	(8		)	4
Transport sales	1			4
Conservation revenue (offset in expenses)	—			(3		)	1
Other (net)	—			1			(1		)
Total (decrease) increase in natural gas margin	$	(2	)	$	34
Total decrease in natural gas margin							$	(17	)

Non-Fuel Operating Expenses and Other Items

O&M Expenses — O&M expenses decreased ~~$13~~$18 million, or ~~2.2%~~3.0%, for the ~~third~~first quarter of ~~2019 and increased $35 million, or 2.0%, year-to-date.~~2020. Significant changes are summarized ~~below:~~as follows:



(Millions of Dollars)	Three Months Ended March 31, 2020 vs. 2019
Employee benefits	$	(15	)
Distribution	(10		)
Generation	(2		)
Strategic initiatives	7
Other (net)	2
Total decrease in O&M expenses	$	(18	)

(Millions of Dollars) Three Months Ended Sept. 30,
2019 vs. 2018 Nine Months Ended Sept. 30,
2019 vs. 2018
Distribution $ —
$ 23
Business systems (6 ) 5
Plant generation —
3
Natural gas operations (3 ) 1
Nuclear plant operations and amortization (4 ) (4 )
Other (net) —
7
Total (decrease) increase in O&M expenses $ (13 ) $ 35

Employee benefits were lower primarily due to change in deferred compensation related liability, offset in Other (Expense) Income;

Distribution expenses ~~for the nine month comparison~~declined due to storms, labor and overtime;

Generation expenses were lower from timing of maintenance and overhauls at power plants, partially offset by an increase in wind related amounts; and

Strategic initiatives expenses were higher due to ~~storms and labor charges incurred during the first half of the year;~~

~~Business Systems costs were higher for the nine month comparison, primarily due to~~ increased spending on customer experience transformation program ~~expenses;~~

~~Natural gas operation~~ expenses ~~for the nine month comparison increased due to pipeline maintenance; and~~

~~Nuclear plant operations~~ and ~~amortization are lower largely reflecting savings initiatives and reduced refueling outage costs.~~advanced grid infrastructure.

Depreciation and Amortization — Depreciation and amortization increased $7$30 million, or ~~1.6%~~6.9%, for the ~~third~~first quarter of ~~2019 and $120 million, or 10.0%, year-to-date.~~2020. Increase was primarily driven by the ~~Rush Creek~~Hale, Lake Benton, and ~~Hale~~Foxtail wind ~~farms~~facilities going into service, as well as ~~other capital investments, which was partially offset~~normal system expansion. In addition, depreciation rates were increased in February 2020 as part of the Colorado electric rate case.

Other (Expense) Income — Other (Expense) Income decreased by ~~accelerated amortization of PSCo’s prepaid pension asset in the third quarter of 2018.~~

~~Table of Contents~~

~~Taxes (Other than Income Taxes)~~ ~~— Taxes (other than income taxes) increased $2~~$15 million ~~or 1.5%, for the third quarter of 2019 and $12 million, or 2.9%, year-to-date. Increase was~~ primarily due to ~~higher property taxes~~the performance of rabbi trust investments, which is offset in ~~Colorado and Minnesota (net of deferred amounts).~~O&M expense.

AFUDC, Equity and Debt — AFUDC ~~decreased $21~~increased $3 million for the ~~third~~first quarter of ~~2019 and $32 million year-to-date. Decrease~~2020. Increase was primarily due to ~~the Rush Creek~~an increase in AFUDC recorded on various wind ~~project being placed in-service in 2018, partially offset by the Hale wind project, which went into service in June 2019, and other capital investments.~~projects currently under construction.

Interest Charges — Interest charges increased ~~$22~~$10 million, or ~~12.4%~~5.3%, for the ~~third~~first quarter of ~~2019 and $55 million, or 10.5%, year-to-date.~~2020. Increase was primarily due to higher debt levels to fund capital investments, ~~changes in~~partially offset by lower long-term and short-term interest ~~rates and implementation of lease accounting standard (offset in electric margin).~~rates.

Income Taxes — Income taxes decreased $1$31 million for the ~~third quarter of 2019. Higher pre-tax earnings were offset~~three months ended March 31, 2020. The decrease was primarily driven by an increase in wind PTCs, lower pretax earnings in 2020 and ~~tax benefit adjustments attributable to the tax return filed for 2018.~~an increase in plant regulatory differences. Wind PTCs are credited to customers (recorded as a reduction to revenue) and do not have a material impact on net income. These were partially offset by a decrease in other tax credits. The ETR was ~~12.0%~~(2.1%) for the ~~third~~first quarter of ~~2019~~2020 compared with ~~12.9%~~7.4% for the same period in ~~2018, largely due to the adjustments above.~~2019.

Income taxes decreased $66 million for the first nine months of 2019, primarily driven by additional wind PTCs and lower pre-tax earnings. Wind PTCs are credited to customers (recorded as a reduction to revenue) and do not have a material impact on net income. The ETR was 10.1% for the first nine months of 2019 compared with 15.2% for the same period in 2018, largely due to the adjustments above.

~~Regulation~~

~~FERC and State Regulation~~—

Public Utility Regulation

The FERC and various state and local regulatory commissions regulate Xcel Energy Inc.’s utility subsidiaries and WGI. The electric and natural gas rates charged to customers of Xcel Energy Inc.’s utility subsidiaries and WGI are approved by the FERC or the regulatory commissions in the states in which they operate.

The rates are designed to recover plant investment, operating costs and an allowed return on investment. Xcel Energy Inc.’s utility subsidiaries request changes in rates for utility services through filings with governing commissions.

Changes in operating costs can affect Xcel Energy’s financial results, depending on the timing of rate case filings and implementation of final rates. Other factors affecting rate filings are new investments, sales, conservation and DSM efforts, and the cost of capital. In addition, the regulatory commissions authorize the ROE, capital structure and depreciation rates in rate proceedings. Decisions by these regulators can significantly impact Xcel Energy’s results of operations.

~~Recently Filed Regulatory Proceedings~~

~~NSP-Wisconsin~~ —~~Rate Case Settlement~~ —~~In May 2019, NSP-Wisconsin filed an application with the PSCW seeking approval of a rate case settlement with various intervenors for 2020-2021.~~

For NSP-Wisconsin’s electric utility, the settlement agreement results in no change to base electric rates through Dec. 31, 2021. For the natural gas utility, there would be a $3 million (4.6%) decrease to base rates, effective Jan. 1, 2020, and no additional changes to base rates through Dec. 31, 2021.

~~Key elements of the settlement include:~~

~~Electric:~~

~~Allowed ROE of 10.0%;~~

~~Allowed equity ratio of 52.5%;~~

~~Retain expected fuel cost savings from new wind farms for the NSP System;~~

~~Allow deferral of pension settlement costs, if any, for 2019-2021;~~

~~Utilize a portion of tax reform benefits to offset revenue deficiency;~~

~~Allow deferral of certain large customer non-fuel cost of service impacts and bad debt expense in 2019-2021; and~~

~~Apply an earnings sharing mechanism for 2020 and 2021. The mechanism would return to customers 50% of earnings between 10.25% and 10.75% ROE and 100% of earnings equal to or in excess of 10.75% ROE.~~

~~Natural Gas:~~

~~Utilize tax reform benefits of $22 million to offset a portion of the regulatory asset for remediation of the MGP site in Ashland, WI.~~

~~In September 2019, the PSCW issued an interim order approving the settlement agreement as filed with one minor modification, to remove the deferral of pension settlement accounting costs for 2021.~~

~~PSCo~~ — ~~Colorado 2019 Electric Rate Case~~ — In May 2019, PSCo filed a request with the CPUC seeking a net rate increase of approximately $158 million, or 5.7%. The filing also requests the transfer of $249 million of rider revenue to base rates, which will not impact overall customer bills as the revenue is currently being recovered through various riders. The request is based on a ROE of 10.35%, an equity ratio of 56.46%, a rate base of approximately $8.2 billion, a historic test year ended Dec. 31, 2018 (adjusted for 2019 capital investment) and incorporates the full impact of tax reform.

In October 2019, PSCo filed rebuttal testimony and revised its request seeking a net increase to retail electric base rate revenue of $108 million, reflecting a $353 million increase offset by $245 million of previously authorized costs (currently recovered through various rider mechanisms). The rebuttal includes certain forecasted plant additions through June 2019 based on a 13-month average rate base convention, a ROE of 10.20%, an equity ratio of 55.61% (based on a 13-month average equity ending Aug. 31, 2019) and inclusion of short-term debt in the capital structure and CWIP in rate base.

~~The procedural schedule is as follows:~~

~~Settlement deadline — Oct. 30, 2019~~

~~Evidentiary hearing — Nov. 4-13, 2019~~

~~A CPUC decision is anticipated in December 2019 with implementation of final rates on Jan. 1, 2020.~~

~~In September 2019, the CPUC Staff, FEA, OCC and CEC filed comprehensive answer testimony. Several other parties filed additional testimony.~~

~~Table of Contents~~

Recommendations and the estimated impact on PSCo’s filed electric rate request as calculated by the filing parties, but with our estimate of the impact of their recommendations on riders are as follows:

(Millions of Dollars) Filed base revenue request
Less: Previously authorized costs (existing riders) ^(b)

Filed net change to revenue ^(c)
PSCo $ 408
$ 249
$ 158
CPUC Staff ^(a)
235
227
8
FEA 246
239
7
OCC ^(a)
207
216
(9 )
CEC ^(a)
187
213
(26 )


^(a)	~~Staff, OCC and CEC have incorporated corrections to the filed case of ($4) million identified by PSCo.~~


^(b)	~~Amounts derived from intervenors’ positions attributable to previously authorized costs (existing riders), impacted by proposed differences in weighted average cost of capital.~~


^(c)	~~Amounts may not add due to rounding.~~

~~Recommended positions on PSCo’s filed electric rate request are as follows:~~

Position Staff FEA OCC CEC
ROE 9.00 % 9.20 % 8.80 % 8.90 %
Equity 55.57 % 56.11 % 54.60 % 54.27 %
Test Year 2019 Current
^(a)
2018 Historic
^(b)
2018 Historic
^(c)
2018 Historic
^(d)


^(a)	~~Incorporated 13-month average of proposed forecasted plant additions and rejected adjustments for wildfire mitigation improvements.~~


^(b)	Incorporated year-end rate base and rejected proposed forecasted plant additions. Except for the transmission portion, the FEA supported portions of wildfire mitigation improvements and included 2019 distribution capital and O&M in its cost of service amount.


^(c)	~~Incorporated proposed 13-month average rate base while rejecting the proposed forecasted plant additions including amounts requested for AGIS and wildfire mitigation improvements.~~


^(d)	~~Rejected proposed forecasted plant additions and the majority of the adjustment for wildfire mitigation improvements.~~

~~SPS~~ — ~~Texas 2019 Electric Rate Case~~— In August 2019, SPS filed an electric rate case with the PUCT seeking an increase in retail electric base rates of approximately $141 million. The filing requests an ROE of 10.35%, a 54.65% equity ratio, a rate base of approximately $2.6 billion and is built on a 12 month period that ended June 30, 2019. In September 2019, SPS filed an update to the electric rate case and revised its requested increase to approximately $136 million.

~~The following table summarizes SPS’ base rate increase request:~~

Revenue Request (Millions of Dollars)
Hale Wind Farm $ 62
Capital investments 47
Depreciation rate change (including Tolk) 34
Cost of capital 10
Expiring purchased power contracts (28 )
Other, net 11
New revenue request $ 136

~~The procedural schedule is as follows:~~

~~Intervenor testimony — Feb. 10, 2020~~

~~Staff testimony — Feb. 18, 2020~~

~~Rebuttal testimony — March 11, 2020~~

~~Public hearing begins — March 30, 2020~~

~~Final order deadline — Sept. 7, 2020~~

~~The final rates established at the end of the rate case are expected to be made effective relating back to Sept. 12, 2019. SPS expects a decision from the PUCT in the second quarter of 2020.~~

~~SPS~~ — ~~New Mexico 2019 Electric Rate Case~~ — In July 2019, SPS filed an electric rate case with the NMPRC seeking an increase in retail electric base rates of approximately $51 million. The rate request is based on a ROE of 10.35%, a 54.77% equity ratio, a rate base of approximately $1.3 billion and a historic test year with rate base additions through Aug. 31, 2019. SPS anticipates final rates will go into effect in the second or third quarter of 2020.

SPS' proposed increase in base rates would be partially mitigated by savings to New Mexico customers achieved through fuel cost reductions and PTCs attributable to wind energy provided by the Hale Wind Farm. SPS’ $51 million requested increase in base rates would be offset by approximately $25 million of savings resulting in a net revenue increase of approximately $26 million, or 5.7%.

~~The following table summarizes SPS’ base rate increase request:~~

Revenue Request (Millions of Dollars)
Hale Wind Farm $ 28
Other plant investment 22
Wholesale sales reduction 17
Allocator changes due to load growth 15
Depreciation rate change (including Tolk) 15
Base rate sales growth (41 )
Other, net (5 )
New revenue request $ 51

~~The procedural schedule is as follows:~~

~~Filing of stipulation, if any — Nov. 15, 2019~~

~~Staff and intervenor testimony or testimony in support of a stipulation — Nov. 22, 2019~~

~~Testimony in opposition to a stipulation, if any — Dec. 6, 2019~~

~~Rebuttal testimony — Dec. 20, 2019~~

~~Public hearing begins — Jan. 7, 2020~~

~~End of 9-month suspension — April 30, 2020~~

~~Table of Contents~~

~~Other Pending and Recently Concluded Regulatory Proceedings~~



~~Mechanism~~	~~Utility Service~~	~~Amount Requested (in millions)~~	~~Filing~~ ~~Date~~	~~Approval~~	~~Additional Information~~
~~NSP-Minnesota (MPUC)~~
~~TCR~~	~~Electric~~	~~$98~~	~~November~~ ~~2017~~	~~Pending~~	~~In May 2019, the MPUC issued a verbal order setting an ROE of 9.06% and recovery of 2017-2018 expenses related to advanced grid investments. A final order is expected in the fourth quarter of 2019.~~
~~2018 GUIC~~	~~Natural Gas~~	~~$23~~	~~November 2017~~	~~Received~~	~~In May 2019, the MPUC issued a verbal order setting an ROE of 9.04%. A final order was received in August 2019.~~
~~2019 GUIC~~	~~Natural Gas~~	~~$29~~	~~November 2018~~	~~Pending~~	~~Proposed ROE of 10.25%. Timing of the MPUC decision is uncertain.~~
~~RES~~	~~Electric~~	~~$23~~	~~November 2017~~	~~Pending~~	~~In May 2019, the MPUC issued a verbal order setting an ROE of 9.06%. A final order is expected in the fourth quarter of 2019.~~
~~PSCo (CPUC)~~
~~Rate Case~~	~~Steam~~	$7	~~May~~ ~~2019~~	~~Received~~	In May 2019, PSCo filed an unopposed Settlement Agreement with CPUC Staff and the City of Denver. The settlement reflects a ROE of 9.67% for AFUDC purposes, an equity ratio of 56.04% and utilization of tax reform benefits. The CPUC approved the Settlement Agreement without modification on Sept. 5, 2019. The first stepped increase went into effect Oct. 1, 2019, with full rates effective Oct. 1, 2020.
~~Rate Case Appeal~~	~~Natural Gas~~	~~N/A~~	~~April~~ ~~2019~~	~~Pending~~	In April 2019, PSCo filed an appeal seeking judicial review of the CPUC’s prior ruling regarding PSCo’s last natural gas rate case (approved in December 2018). Appeal requests review of the following: denial of a return on the prepaid pension and retiree medical assets; the use of a capital structure that is not based on the actual historical test year level; and the use of an average rate base methodology rather than a year-end rate base methodology. The District Court of Denver County has adopted a briefing schedule that will conclude in October 2019. Timeline on a final ruling is unknown.

~~NSP-Minnesota~~ — ~~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 for approximately $650 million.

On Sept. 27, 2019, the Minnesota Public Utilities Commission (MPUC) voted to deny NSP-Minnesota's request to purchase MEC. The MPUC determined there was too much uncertainty regarding estimated customer benefits associated with the transaction without being able to fully review NSP-Minnesota's Resource Plan (filed July 2019).

Xcel Energy plans to acquire MEC as a non-regulated investment and step into the terms of the existing PPAs with NSP-Minnesota. Xcel Energy provided Southern Power Company formal contractual notice of transferring the purchase agreement to a newly formed non-regulated subsidiary and submitted acquisition and affiliated interest filings to the Federal Energy Regulatory Commission (FERC) and MPUC, respectively. Approval is anticipated by the end of 2019.

~~NSP-Minnesota~~ — ~~Minnesota Resource Plan~~ —In July 2019, NSP-Minnesota filed its Minnesota resource plan, which runs through 2034. The plan would result in an 80% carbon reduction by 2030 and puts NSP on a path to achieving its vision of being 100% carbon-free by 2050. The preferred plan includes the following:

~~Extends the life of the Monticello nuclear plant from 2030 to 2040;~~

~~Continues to run the Prairie Island nuclear plant through current end of life (2033 and 2034);~~

~~Includes the MEC acquisition and construction of the Sherco CC natural gas plant;~~

~~Includes the early retirement of the King coal plant (511 MW) in 2028 and the Sherco 3 coal plant (517 MW) in 2030;~~

~~Adds approximately 1,700 MW of firm peaking (CT, pumped hydro, battery storage, DR, etc.);~~

~~Adds approximately 1,200 MW of wind replacement; and~~

~~Adds approximately 4,000 MW of solar.~~

Intervening parties will provide recommendations and comments on the resource plan. Following the MPUC’s denial of its request to purchase MEC, NSP-Minnesota will provide updates to remove its ownership of MEC from the preferred plan. The MPUC is anticipated to make a final decision on the resource plan in late 2020 or the first half of 2021.

~~NSP-Minnesota~~ —~~Jeffers Wind and CommunityWind North Repowering Acquisition~~— In December 2018, NSP-Minnesota filed a request with the MPUC seeking approval to acquire the Jeffers and Community Wind North wind facilities in western Minnesota from Longroad Energy. The wind farms, currently contracted under PPAs with NSP-Minnesota, will have approximately 70 MW of capacity after being repowered. The repowering and acquisition are expected to be complete by December 2020 and qualify for the 100% PTC benefit. The $135 million asset acquisition is projected to provide customer savings of approximately $7 million over the life of the facilities, compared to the amended PPAs. The FERC approved the acquisition in July 2019.

The DOC filed initial comments in support of NSP-Minnesota continuing to contract for the assets under the amended PPAs, but not the acquisition. In reply comments, NSP-Minnesota indicated it would be willing to acquire the wind facilities as a non-regulated investment and step into the terms of the PPAs, similar to MEC. In October, Xcel Energy filed with FERC requesting contingent approval for a non-regulated subsidiary to acquire the facilities, depending on the MPUC decision. The MPUC decision is expected in the fourth quarter of 2019.

~~NSP-Minnesota~~ — ~~Mower Wind Facility~~ —On Aug. 30, 2019, NSP-Minnesota filed a petition with the MPUC to acquire the Mower wind facility from affiliates of NextEra Energy, Inc. for an undisclosed amount. The Mower facility is located in southeastern Minnesota and is currently contracted under a PPA with NSP-Minnesota through 2026. Mower will be repowered and continue to have approximately 99 MW of capacity. The acquisition would occur after repowering which is expected to be complete in 2020 and qualify for 100% of the PTC. NSP-Minnesota will need approval from both the MPUC and FERC to complete the transaction. Timing of approval is uncertain.

~~Table of Contents~~

~~NSP-Minnesota~~ — ~~Crowned Ridge Wind Project~~ —In 2017, the MPUC approved the NSP-Minnesota proposed wind portfolio that included 1,150 MW of wind ownership and 400 MW of PPAs. Included in that proposal were two Crowned Ridge projects: a 300 MW build-owner transfer (BOT) wind farm and a 300 MW PPA, both with affiliates of NextEra. In August 2019, NextEra withdrew their MISO queue position for a portion of the projects that were still awaiting transmission access due to increased estimates of MISO transmission upgrade and interconnection costs. As a result, NextEra has reduced both the BOT and PPA Crown Ridge projects from 300 MW to 200 MW. The projects are targeting a commercial operation date in the fourth quarter of 2020.

~~Public Utility Regulation~~

Except to the extent noted below, ~~and in Regulation above,~~ the circumstances set forth in Public Utility Regulation included in Item 17 of Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, ~~2018 and in Item 2 of Xcel Energy Inc.’s Quarterly Report on Form 10-Q for the quarterly periods ending March 31, 2019 and June 30,~~ 2019 appropriately represent, in all material respects, the current status of public utility regulation and are incorporated by reference.

Table of Contents

NSP-Minnesota

Pending and Recently Concluded Regulatory Proceedings



Mechanism	Utility Service	Amount Requested (in millions)	Filing Date	Approval	Additional Information
MPUC
2020 TCR	Electric	$82	November 2019	Pending	In November 2019, NSP-Minnesota filed the 2020 TCR Rider. The filing included an ROE of 9.06%. Timing of an MPUC ruling is uncertain.
2019 GUIC	Natural Gas	$29	November 2018	Received	In November 2018, NSP-Minnesota filed the 2019 GUIC Rider with the MPUC. The filing included an ROE of 10.25%. In January 2020, the MPUC approved an order setting an ROE of 9.04%.
2020 GUIC	Natural Gas	$21	November 2019	Pending	In November 2019, NSP-Minnesota filed the 2020 GUIC Rider with the MPUC. The filing included an ROE of 9.04%. Timing of an MPUC ruling is uncertain.
2020 RES	Electric	$102	November 2019	Pending	In November 2019, NSP-Minnesota filed the 2020 RES Rider with the MPUC. The requested amount includes a true-up for the 2019 rider of $38 million and the 2020 requested amount of $64 million. The filing included an ROE of 9.06%. Timing of an MPUC ruling is uncertain.
2020 Rate Case Stay Out Petition	Electric	N/A	November 2019	Received	In November 2019, NSP-Minnesota filed a three-year electric rate case with the MPUC, which included a stay-out petition. In December 2019, the MPUC verbally approved the stay-out petition including extension of the sales, capital and property tax true-up mechanisms and the delay of any increase to the Nuclear Decommissioning Trust annual accrual until Jan. 1, 2021. A written order of approval was received in March 2020.

NSP-Minnesota — Minnesota Resource Plan —In July 2019, NSP-Minnesota filed its Minnesota resource plan, which runs through 2034. The plan would result in an 80% carbon reduction by 2030 (from 2005) and puts NSP-Minnesota on a path to achieving its vision of being 100% carbon-free by 2050.

The preferred plan includes the following:

Extends the life of the Monticello nuclear plant from 2030 to 2040;

Continues to run the Prairie Island nuclear plant through current end of life (2033 and 2034);

Includes the MEC acquisition and construction of the Sherco CC natural gas plant;

Includes the early retirement of the King coal plant (511 MW) in 2028 and the Sherco 3 coal plant (517 MW) in 2030;

Adds approximately 1,700 MW of firm peaking (CT, pumped hydro, battery storage, DR, etc.);

Adds approximately 1,200 MW of wind replacement; and

Adds approximately 4,000 MW of solar.

Intervening parties will provide recommendations and comments on the resource plan. NSP-Minnesota will provide updates to remove its ownership of MEC from the preferred plan. The MPUC required NSP-Minnesota to update its filing to address issues related to its decision on MEC, including certain new modeling scenarios. An updated filing will be made on June 30, 2020. The MPUC is anticipated to make a final decision on the resource plan in the first half of 2021.

NSP-Minnesota — Mower Wind Facility —In August 2019, NSP-Minnesota filed a petition with the MPUC to acquire the Mower wind facility from affiliates of NextEra Energy, Inc. for an undisclosed amount. The Mower facility is located in southeastern Minnesota and is currently contracted under a PPA with NSP-Minnesota through 2026. Mower is expected to continue to have approximately 99 MW of capacity following a planned repowering. The acquisition would occur after repowering, which is expected to be completed in 2020 and qualify for the full PTC. NSP-Minnesota will need approval from both the MPUC and FERC to complete the transaction. NSP-Minnesota filed reply comments addressing the DOC’s concerns with the transaction in February 2020. The DOC filed supplemental comments in April 2020. Timing of MPUC and FERC decisions are uncertain.

Minnesota State ROFR Statute Complaint — In September 2017, LSP Transmission filed a complaint in the Minnesota District Court against the Minnesota Attorney General, MPUC and DOC. The complaint was in response to MISO assigning NSP-Minnesota and ITC Midwest, LLC ~~joint ownership of~~to jointly own a new ~~Mankato-Winnebago~~ 345 KV transmission line ~~(estimated~~from Mankato to Winnebago, Minnesota. The project was estimated to cost $108 million and projected to be in-service by the end of ~~$108 million),~~2021. It was assigned to NSP-Minnesota and ITC Midwest as the incumbent utilities, consistent with a Minnesota state ROFR statute.

The complaint challenged the constitutionality of the ~~state ROFR~~ statute and is seeking declaratory judgment that the statute violates the Commerce Clause of the U.S. Constitution and should not be enforced.

The Minnesota state agencies and NSP-Minnesota filed motions to dismiss. In June 2018, the Minnesota District Court granted the defendants’ motions to dismiss with prejudice. LSP Transmission filed an appeal in July 2018. In September 2019, the estimate was updated to approximately $140 million, due to various changes in build plans. In October 2019, oral arguments were held with the Eighth Circuit Court of Appeals. In February 2020, the Eighth Circuit of Appeals upheld the Minnesota District Court decision to dismiss. It is ~~uncertain when a decision will be rendered.~~unknown whether LSP Transmission intends to appeal this decision.

Nuclear Power Operations

NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the Prairie Island plant. See Note 12 to the consolidated financial statements of Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, ~~2018,~~2019, for further information. The circumstances set forth in Nuclear Power Operations and Waste Disposal included in Item 1 of Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, ~~2018,~~2019, appropriately represent, in all material respects, the current status of nuclear power operations, and are incorporated by reference.

NSP-Wisconsin

~~2018~~2019 Electric Fuel Cost Recovery — NSP-Wisconsin’s electric fuel costs for ~~2018~~2019 were lower than authorized in rates and outside the 2% annual tolerance band, primarily due to increased sales to other utilities compared to the forecast used to set authorized rates. Under the fuel cost recovery rules, NSP-Wisconsin may retain approximately $4$3.4 million of fuel costs and defer the amount of over-recovery in excess of the 2% annual tolerance band for future refund to customers. In March ~~2019,~~2020, NSP-Wisconsin filed with the PSCW ~~to provide a refund~~indicating an over-refund of approximately ~~$4 million to customers~~$9.7 million. The PSCW will determine how the liability will be addressed with an order expected later in 2020.

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PSCo

Pending and ~~proposed for it to be issued in September 2019. In August 2019, the Commission issued their order to refund the $4 million.~~Recently Concluded Regulatory Proceedings



Mechanism	Utility Service	Amount Requested (in millions)	Filing Date	Approval	Additional Information
CPUC
Rate Case	Natural Gas	$127	February 2020	Pending	In February 2020, PSCo filed a rate case with the CPUC seeking a net increase to retail gas rates of $126.8 million, reflecting a $144.5 million increase in base rate revenue, partially offset by $17.7 million of costs previously authorized through the Pipeline Integrity rider. The request is based on a 9.95% ROE, an equity ratio of 55.81% and a historic test year as of Sept. 30, 2019, adjusted for known and measurable differences for the 12-month period ended Sept. 30, 2020. The procedural schedule is as follows: • Answer testimony - May 13, 2020; • Rebuttal testimony - June 8, 2020; • Evidentiary hearing - July 7-17, 2020; • Statement of position - July 31, 2020; and • CPUC decision is expected in the second half of 2020 and rates are anticipated to be effective in November 2020.
Rate Case	Electric	$158	May 2019	Pending	In 2019, PSCo filed a request with the CPUC seeking a net rate increase of $108.4 million, based on a requested ROE of 10.2% and an equity ratio of 55.6%. In February 2020, the CPUC issued a written decision, resulting in an estimated $34.9 million net base rate revenue increase. The CPUC decision included a 9.3% ROE, an equity ratio of 55.61%, based on a current test year ended Aug. 31, 2019 and the implementation of decoupling in 2020 and other items. Final rates were implemented on Feb. 25, 2020. PSCo filed an application for rehearing/reconsideration, which is expected to be heard by the CPUC in the second quarter of 2020.
Rate Case Appeal	Natural Gas	N/A	April 2019	Pending	In April 2019, PSCo filed an appeal seeking judicial review of the CPUC’s prior ruling regarding PSCo’s last natural gas rate case (approved in December 2018). The appeal requested review of the following: denial of a return on the prepaid pension and retiree medical assets; the use of a capital structure not based on the actual historical test year; and use of an average rate base methodology rather than a year-end rate base methodology. In March 2020, The District Court of Denver County ruled in favor of allowing the prepaid pension assets to be included in rate base; but it upheld the CPUC treatment of the retiree medical assets and capital structure methodology. The CPUC did not appeal the decision allowing inclusion of the prepaid pension assets in rate base.

SPS

Pending and Recently Concluded Regulatory Proceedings



Mechanism	Utility Service	Amount Requested (in millions)	Filing Date	Approval	Additional Information
NMPRC
Rate Case	Electric	$51	July 2019	Pending	In July 2019, SPS filed an electric rate case with the NMPRC seeking an increase in retail electric base rates of approximately $51 million. The rate request is based on an ROE of 10.35%, an equity ratio of 54.77%, a rate base of approximately $1.3 billion and a historic test year with rate base additions through Aug. 31, 2019. In December 2019, SPS revised its base rate increase request to approximately $47 million, based on an ROE of 10.10% and updated information. The request also included an increase of $14.6 million for accelerated depreciation including the early retirement of the Tolk coal plant in 2032. In January 2020, SPS and various parties filed an uncontested comprehensive stipulation. The stipulation includes a base rate revenue increase of $31 million, an ROE of 9.45% and an equity ratio of 54.77%. The stipulation also includes an acceleration of depreciation on the Tolk coal plant to reflect early retirement in 2037, which results in a total increase in depreciation expense of $8 million. The parties to the stipulation agreed not to oppose the full application of depreciation rates associated with the 2032 retirement date in SPS’ next base rate case. A NMPRC decision is expected later in the year. SPS anticipates final rates will go into effect in the second or third quarter of 2020.

~~Wind Development~~Texas 2019 Electric Rate Case — In ~~2018,~~August 2019, SPS filed an electric rate case with the ~~NMPRC~~PUCT seeking an increase in retail electric base rates of approximately $141 million. The filing requests an ROE of 10.35%, a 54.65% equity ratio, a rate base of approximately $2.6 billion and is built on a 12 month period that ended June 30, 2019. In September 2019, SPS filed an update to the electric rate case and revised its requested increase to approximately $137 million.

On Feb. 10, 2020, the AXM, TIEC, OPUC and DOE filed testimony along with several other parties. On Feb. 18, 2020, the PUCT ~~approved~~Staff filed testimony that included certain adjustments and various ring-fencing measures.

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Proposed modifications to SPS’ ~~proposal~~request:



(Millions of Dollars)	Staff			AXM			OPUC			TIEC			DOE
SPS Direct Testimony	$	137		$	137		$	137		$	137		$	137

Recommended base rate adjustments:
ROE	(22		)	(24		)	(15		)	(21		)	(24		)
Capital structure	(7		)	(10		)	—			(7		)	(3		)
Tolk/Harrington O&M disallowance	—			(7		)	—			—			—
Distribution and Transmission Capital Disallowances ^(a)	(7		)	—			—			—			—
Depreciation expense	(8		)	(15		)	(8		)	(20		)	—
Excess ADIT unprotected plant	—			—			(7		)	—			—
Income Tax Expense Differences	(12		)	—			—			—			—
Other, net	(6		)	(6		)	(1		)	(1		)	—
Total Adjustments	(62		)	(62		)	(31		)	(49		)	(27		)
Total proposed revenue change	$	75		$	75		$	106		$	88		$	110



Recommended Position	Staff		AXM		OPUC ^(b)		TIEC		DOE
ROE	9.1	%	9.0	%	—	%	9.2	%	9.0	%
Equity Ratio	51.00	%	50.00	%	—	%	51.00	%	53.00	%


^(a)	Staff recommends exclusion of approximately $134 million in transmission, distribution, and general plant in service in this rate case resulting in an approximate $7 million decrease to the revenue requirement.


^(b)	OPUC did not provide a recommendation for an ROE or equity ratio. For illustrative purposes an ROE of 9.5% was used.

In March 2020, SPS filed an update to ~~add 1,230 MW~~the electric rate case and revised its requested increase to approximately $130 million, based on a requested ROE of ~~new wind generation, including construction~~10.1%, a 54.65% equity ratio, rate base of approximately $2.6 billion and ~~ownership of~~historic test year ended June 30, 2019.



Revenue Request (Millions of Dollars)
Hale Wind Farm	$	61
Capital investments	47
Depreciation rate change (including Tolk)	34
Cost of capital	8
Expiring purchased power contracts	(28		)
Other, net	8
New revenue request	$	130

In May 2020, SPS and the ~~478 MW Hale~~intervening parties announced they have reached a constructive, unopposed settlement agreement in principle. We are working with intervening parties to document and ~~522 MW Sagamore wind farms. The Hale wind farm was placed into commercial operation~~file the settlement, which we expect to occur in ~~June 2019. Sagamore is~~the second quarter.

Final rates are expected to ~~go into service~~be retroactively applied as of Sept. 12, 2019. A decision from the PUCT is anticipated in ~~2020 and cost approximately $900 million.~~the third quarter of 2020.

Texas State ~~(ROFR)~~ROFR Litigation — In May 2019, the Governor signed into law Senate Bill 1938, which grants incumbent utilities a ROFR to build transmission infrastructure when it directly interconnects to the utility’s existing facility. In June 2019, a complaint was filed in the United States District Court for the Western District of Texas claiming the new ROFR law to be unconstitutional. The Texas Attorney General has made a motion to dismiss the federal court complaint. In February 2020, the federal court complaint was dismissed. In March 2020, the ruling was appealed.

Texas Fuel ~~Reconciliation~~ Refund— Fuel and purchased power costs are recoverable in Texas through a fixed fuel factor, which is part of SPS’ rates. The PUCT rule requires refunding or surcharging of under and over-recovered amounts, including interest, when they exceed 4% of the utility’s annual fuel costs on a rolling 12-month basis, as allowed by the PUCT, if this condition is expected to continue.

Under the fuel cost recovery rules, SPS’ 2019 total fuel and purchased power costs were over-collected by approximately $39 million, including interest. In ~~December 2018,~~February 2020, SPS filed an application with the PUCT ~~for reconciliation~~requesting to provide a net refund of ~~fuel costs for the period Jan. 1, 2016, through June 30, 2018,~~$39 million to ~~determine whether all fuel costs incurred~~customers to be issued beginning May 2020. In April 2020, interim rates were ~~eligible for recovery. On Oct. 17, 2019, the assigned Administrative Law Judges (ALJs) issued~~granted by a Proposal for Decision recommending the PUCT disallow approximately $3 million of costs related to the reconciliation period, based on the ALJs’ determination that entering into two specific solar PPAs was imprudent. The related solar facilities are located in New MexicoTexas administrative law judge. This case is pending final review and ~~were previously approved~~approval by the NMPRC as reasonable, necessary and economic. SPS plans to file exceptions regarding the proposed disallowance and assert, among other points, that the ALJs erred in failing to account for the capacity value of the solar projects.

~~New Mexico Fuel Continuation~~ —In October 2019, SPS filed an application to the NMPRC to approve SPS’s continued use of its FPPCAC and for reconciliation of fuel costs for the period Sept. 1, 2015, through June 30, 2019, which will determine whether all fuel costs incurred are eligible for recovery. No procedural schedule has yet been established for this matter.PUCT.



Environmental

Environmental ~~Matters~~Regulation

In ~~June~~July 2019, the EPA ~~issued~~adopted the ~~final ACE~~Affordable Clean Energy rule, which requires states to ~~replace~~develop plans for greenhouse gas reductions from coal-fired power plants. The state plans, due to the ~~Obama-era Clean Power Plan. The final ACE rule may~~EPA in July 2022, will evaluate and potentially require ~~implementation of~~ heat rate ~~improvement projects~~improvements at ~~some of our~~existing coal-fired ~~power~~ plants. It is not yet known ~~what the costs associated with the final rule might be until~~how these state plans ~~are developed to implement the final regulation.~~will affect our existing coal plants, but they could require substantial additional investment, even in plants slated for retirement. Xcel Energy believes, ~~the costs would be recoverable through rates~~ based on prior state commission ~~practice.~~practice, the cost of these initiatives or replacement generation would be recoverable through rates.

~~Derivatives, Risk Management and Market Risk~~

~~Xcel Energy Inc. and its subsidiaries~~

Derivatives, Risk Management and Market Risk

We are exposed to a variety of market risks in the normal course of business. Market risk is the potential loss that may occur as a result of adverse changes in the market or fair value of a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk.

See Note 8 to the consolidated financial statements for further discussion of market risks associated with derivatives.

Xcel Energy is exposed to the impact of adverse changes in price for energy and energy-related products, which is partially mitigated by the use of commodity derivatives. In addition to ongoing monitoring and maintaining credit policies intended to minimize overall credit risk, ~~when necessary,~~ management takes steps to mitigate changes in credit and concentration risks associated with its derivatives and other contracts, including parental guarantees and requests of collateral.

While ~~Xcel Energy expects~~we expect that the counterparties will perform under the contracts underlying its derivatives, the contracts expose ~~Xcel Energy~~us to some credit and non-performance risk.

~~Table of Contents~~

Though no material non-performance risk currently exists with the counterparties to Xcel Energy’s commodity derivative contracts, distress in the financial markets may in the future impact that risk to the extent it impacts those counterparties. Distress in the financial markets may ~~also~~ impact counterparty risk, the fair value of the securities in the nuclear decommissioning fund and ~~master~~ pension ~~trust, as well as~~fund and Xcel Energy’s ability to earn a return on short-term ~~investments of excess cash.~~investments.

Commodity Price Risk — ~~Xcel Energy Inc.’s utility subsidiaries~~We are exposed to commodity price risk in ~~their~~our electric and natural gas operations. Commodity price risk is managed by entering into long- and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products and ~~for various~~ fuels used in generation and distribution activities. Commodity price risk is also managed through the use of financial derivative instruments. ~~Xcel Energy’s~~Our risk management policy allows it to manage commodity price risk within each rate-regulated operation ~~to the extent such exposure exists.~~per commission approved hedge plans.

Wholesale and Commodity Trading Risk — Xcel Energy ~~Inc.’s utility subsidiaries conduct~~conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. ~~Xcel Energy’s~~Our risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management ~~committee, which is made up~~committee.

Table of ~~management personnel not directly involved in the activities governed by this policy.~~Contents

~~At Sept. 30, 2019, the fair values by source for~~

Fair value of net commodity trading ~~contract assets were~~contracts as ~~follows:~~of March 31, 2020:


	Futures / Forwards																Futures / Forwards Maturity
(Millions of Dollars)	Source of Fair Value	Maturity Less Than 1 Year			Maturity 1 to 3 Years			Maturity 4 to 5 Years			Maturity Greater Than 5 Years			Total Futures/ Forwards Fair Value				Less Than 1 Year			1 to 3 Years			4 to 5 Years			Greater Than 5 Years			Total Fair Value
NSP-Minnesota(a)	1	$	(1	)	$	1		$	1		$	1		$	2			$	(1	)	$	1		$	3		$	4		$	7
NSP-Minnesota(b)	2	5			(4		)	1			(7		)	(5		)		4			(2		)	(3		)	(10		)	(11		)
PSCo(a)	2	(5		)	(21		)	(29		)	(4		)	(59		)		1			—			—			—			1
PSCo ^(b)																		(5		)	(25		)	(28		)	—			(58		)
		$	(1	)	$	(24	)	$	(27	)	$	(10	)	$	(62	)		$	(1	)	$	(26	)	$	(28	)	$	(6	)	$	(61	)


	Options											Options Maturity
(Millions of Dollars)	Source of Fair Value	Maturity Less Than 1 Year		Maturity 1 to 3 Years		Maturity 4 to 5 Years		Maturity Greater Than 5 Years		Total Futures/ Forwards Fair Value			Less Than 1 Year		1 to 3 Years		4 to 5 Years		Greater Than 5 Years		Total Fair Value
NSP-Minnesota(b)	2	$	3	$	2	$	—	$	—	$	5		$	3	$	—	$	—	$	—	$	3
		$	3	$	2	$	—	$	—	$	5		$	3	$	—	$	—	$	—	$	3

~~1 —~~ ^(a)Prices actively quoted or based on actively quoted prices.

~~2 —~~^(b) Prices based on models and other valuation methods.

Changes in the fair value of commodity trading contracts before the impacts of margin-sharing ~~mechanisms~~ for the ~~nine~~three months ended ~~Sept. 30, were as follows:~~March 31:

(Millions of Dollars) 2019 2018
Fair value of commodity trading net contract assets outstanding at Jan. 1 $ 17
$ 16
Contracts realized or settled during the period (13 ) (8 )
Commodity trading contract additions and changes during the period (61 ) 10
Fair value of commodity trading net contract assets outstanding at Sept. 30 $ (57 ) $ 18



(Millions of Dollars)	2020			2019
Fair value of commodity trading net contract (liabilities) assets outstanding at Jan. 1	$	(59	)	$	17
Contracts realized or settled during the period	—			(4		)
Commodity trading contract additions and changes during the period	1			1
Fair value of commodity trading net contract (liabilities) assets outstanding at March 31	$	(58	)	$	14

At March 31, 2020, a 10% increase in market prices for commodity trading contracts would increase pre-tax income from continuing operations by approximately $9 million, whereas a 10% decrease would decrease pre-tax income from continuing operations by approximately $9 million. At March 31, 2019, a 10% increase in market prices for commodity trading contracts would increase pre-tax income from continuing operations by approximately $8 million, whereas a 10% decrease would decrease pre-tax income from continuing operations by approximately $8 million.

~~Xcel Energy Inc.’s~~The utility subsidiaries’ commodity trading operations ~~which exclude any transactions designated as normal purchases and normal sales,~~ measure the outstanding risk exposure to price changes on contracts and obligations that have been entered into, but not closed, using an industry standard methodology known as Value at Risk (VaR). VaR expresses the potential change in fair value on the outstanding contracts and obligations over a particular period of time under normal market conditions.

The VaRs for the NSP-Minnesota and PSCo commodity trading operations, excluding both non-derivative transactions and derivative transactions designated as normal purchase, normal sales, calculated on a consolidated basis using a Monte Carlo simulation with a 95% confidence level and a one-day holding period, were as follows:


(Millions of Dollars)	Three Months Ended Sept. 30		VaR Limit		Average		High		Low		Three Months Ended March 31		VaR Limit		Average		High		Low
2020											$	0.8	$	3.0	$	0.5	$	1.0	$	0.3
2019	$	0.52	$	3.00	$	0.97	$	1.30	$	0.52	1.1		3.0		1.9		4.4		1.0
2018	0.19		3.00		0.20		0.50		0.08

In November 2018, management temporarily increased the VaR limit to accommodate a 10-year transaction. NSP-Minnesota ~~has been~~ systematically hedging the transaction and the consolidated VaR returned below $3 million in early January 2019.

At Sept. 30, 2019, a 10% increase or decrease in market prices for commodity trading contracts would increase or decrease pre-tax income from continuing operations by an immaterial amount. At Sept. 30, 2018, a 10% increase in market prices for commodity trading contracts would increase pre-tax income from continuing operations by approximately $1 million, whereas a 10% decrease would decrease pre-tax income from continuing operations by approximately $1 million.

Nuclear Fuel Supply — NSP-Minnesota has ~~received all enriched nuclear material for 2019 and has~~ contracted for approximately ~~50%~~51% of its 2020 enriched nuclear material requirements from sources that could be impacted by sanctions against entities doing business with Iran. Those sanctions may impact the supply of enriched nuclear material supplied from Russia. Long-term, through ~~2024,~~2030, NSP-Minnesota is scheduled to take delivery of approximately ~~34%~~30% of its average enriched nuclear material requirements from these sources. Alternate potential sources provide the flexibility to manage NSP-Minnesota’s nuclear fuel supply. NSP-Minnesota periodically assesses if further actions are required to assure a secure supply of enriched nuclear material.

~~Disruptions in third party nuclear fuel supply contracts due to bankruptcies or change of contract assignments have not materially impacted NSP‑Minnesota’s operational or financial performance.~~

Interest Rate Risk — Xcel Energy is subject to ~~the risk of fluctuating~~ interest ~~rates in the normal course of business. Xcel Energy’s~~rate risk. Our risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives such as swaps, caps, collars and put or call options.

At ~~Sept. 30,~~March 31, 2020 and 2019, ~~and 2018,~~ a 100-basis-point change in the benchmark rate on Xcel Energy’s variable rate debt would impact pre-tax interest expense annually by approximately $9$21 million and $5$13 million, respectively.

See Note 8 to the consolidated financial statements for a discussion of Xcel Energy Inc. and its subsidiaries’ interest rate derivatives.

NSP-Minnesota ~~also~~ maintains a nuclear decommissioning fund, as required by the NRC. The nuclear decommissioning fund is subject to interest rate risk and equity price risk. ~~At Sept. 30, 2019, the~~The fund ~~was~~is invested in a diversified portfolio of cash equivalents, debt securities, equity securities, and other investments.

~~Table of Contents~~

These investments may be used only for ~~activities related to~~purpose of decommissioning NSP‑Minnesota’s nuclear ~~decommissioning. Given the purpose and legal restrictions on the use of nuclear decommissioning fund assets, any realized~~generating plants.

Realized and unrealized gains ~~and losses~~ on ~~securities in~~ the ~~nuclear~~ decommissioning fund ~~including any other-than-temporary impairments,~~investments are deferred as ~~a component~~an offset of ~~the~~NSP-Minnesota’s regulatory asset for nuclear ~~decommissioning. Since the accounting for nuclear~~ decommissioning ~~recognizes that costs are recovered through rates, fluctuations~~costs. Fluctuations in equity prices or interest rates affecting the nuclear decommissioning fund do not have a direct impact on ~~earnings.~~earnings due to the application of regulatory accounting.

Changes in discount rates and expected return on plan assets impact the value of pension and postretirement plan assets and/or benefit costs.

Credit Risk — Xcel Energy ~~Inc. and its subsidiaries are~~is also exposed to credit risk. Credit risk relates to the risk of loss resulting from counterparties’ nonperformance on their contractual obligations. ~~Xcel Energy Inc. and its subsidiaries maintain~~The Company maintains credit policies intended to minimize overall credit risk and actively monitor these policies to reflect changes and scope of operations.

At ~~Sept. 30,~~March 31, 2020, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $21 million, while a decrease in prices of 10% would have resulted in an immaterial decrease in credit exposure. At March 31, 2019, a 10% increase in commodity prices would have resulted in an increase in credit exposure of ~~$30~~$29 million, while a decrease in prices of 10% would have resulted in an increase in credit exposure of $12 million. At Sept. 30, 2018, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $33 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $8$7 million.

Xcel Energy ~~Inc. and its subsidiaries conduct standard~~conducts credit reviews for all ~~counterparties. Xcel Energy~~counterparties and employs ~~additional~~ credit risk control, ~~mechanisms when appropriate,~~ such as letters of credit, parental guarantees, ~~standardized~~ master netting agreements and termination ~~provisions that allow for offsetting of positive and negative exposures.~~provisions. Credit exposure is monitored and when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. Distress in the financial markets could increase ~~Xcel Energy’s~~our credit risk.

~~Fair Value Measurements~~

FAIR VALUE MEASUREMENTS

Xcel Energy ~~follows accounting~~uses derivative contracts such as futures, forwards, interest rate swaps, options and ~~disclosure guidance on~~FTRs to manage commodity price and interest rate risk. Derivative contracts, with the exception of those designated as normal purchase-normal sale contracts, are reported at fair value.

Table of Contents

The Company’s investments held in the nuclear decommissioning fund, rabbi trusts, pension and other postretirement funds are also subject to fair value ~~measurements that contains a hierarchy for inputs used in measuring fair value and requires disclosure of the observability of the inputs used in these measurements.~~ accounting.

See Note 8 to the consolidated financial statements for further discussion of the fair value hierarchy and the amounts of assets and liabilities measured at fair value that have been assigned to Level 3.

Commodity Derivatives — Xcel Energy ~~continuously~~ monitors the creditworthiness of the counterparties to its commodity derivative contracts and assesses each counterparty’s ability to perform on the ~~transactions set forth in the contracts. Given this assessment and the typically short duration of these contracts, the~~transactions. The impact of discounting commodity derivative assets for counterparty credit risk was not material to the fair value of commodity derivative assets at ~~Sept. 30, 2019.~~ March 31, 2020.

Adjustments to fair value for credit risk of commodity trading instruments are recorded in electric revenues. Credit risk adjustments for other commodity derivative instruments are deferred as other comprehensive income or deferred as regulatory assets and liabilities. Classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. ~~Xcel Energy also assesses the impact of its own credit risk when determining the fair value of commodity derivative liabilities.~~ The impact of discounting commodity derivative liabilities for credit risk was immaterial ~~to the fair value of commodity derivative liabilities~~ at ~~Sept. 30, 2019.~~March 31, 2020.

~~Liquidity and Capital Resources~~

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows


	Nine Months Ended Sept. 30				Three Months Ended March 31
(Millions of Dollars)	2019		2018		2020		2019
Cash provided by operating activities	$	2,557	$	2,493	$	669	$	793

Net cash provided by operating activities ~~increased $64~~decreased $124 million for the ~~nine~~three months ended ~~Sept. 30, 2019~~March 31, 2020 compared with the prior year. ~~Increase~~Decrease was primarily due to ~~additional~~lower net income ~~partially offset by increased refunds associated with TCJA.~~(excluding amounts related to non-cash operating activities (e.g., depreciation and amortization and deferred tax expenses)) and lower accounts payable due to a decrease in the cost of fuel.


	Nine Months Ended Sept. 30						Three Months Ended March 31
(Millions of Dollars)	2019			2018			2020			2019
Cash used in investing activities	$	(3,129	)	$	(2,706	)	$	(1,606	)	$	(852	)

Net cash used in investing activities increased ~~$423~~$754 million for the ~~nine~~three months ended ~~Sept. 30, 2019~~March 31, 2020 compared with the prior year. Increase was ~~primarily attributable to~~driven by capital expansion (primarily for wind projects)~~, partially offset by Rush Creek being placed~~ as well as the purchase of MEC in ~~service in 2018.~~January 2020.


	Nine Months Ended Sept. 30				Three Months Ended March 31
(Millions of Dollars)	2019		2018		2020		2019
Cash provided by financing activities	$	1,289	$	343	$	933	$	6

Net cash provided by financing activities increased ~~$946~~$927 million for the ~~nine~~three months ended ~~Sept. 30, 2019~~March 31, 2020 compared with the prior year. Increase was primarily attributable to higher proceeds from issuances of ~~long-term debt, common stock issuances (primarily due to the forward equity agreement settling in August 2019) and~~ short-term ~~borrowings, partially offset by higher repayments of long-term debt and dividends paid.~~borrowings.

Capital Requirements

Xcel Energy expects to meet future financing requirements by periodically issuing short-term debt, long-term debt, common stock, hybrid and other securities to maintain desired capitalization ratios.

Pension Fund — Xcel Energy’s pension assets are invested in a diversified portfolio of domestic and international equity securities, short-term to long-duration fixed income securities, and alternative investments, including private equity, real estate and hedge funds.

In ~~July 2019, Xcel Energy made a $4 million contribution to the Xcel Energy Inc. Non-Bargaining Pension Plan (South).~~

In January ~~2019,~~2020, contributions of $150 million were made across four of Xcel Energy’s pension plans.

In ~~2018,~~2019, contributions of ~~$150~~$154 million were made across four of Xcel Energy’s pension plans.

For future years, contributions will be made as deemed appropriate based on evaluation of various factors including the funded status of the plans, minimum funding requirements, interest rates and expected investment returns.

~~Table of Contents~~

Capital Sources

Short-Term Funding Sources — Xcel Energy uses a number of sources to fulfill short-term funding needs, including operating cash flow, notes payable, commercial paper and bank lines of credit. The amount and timing of short-term funding needs depend on financing needs for construction expenditures, working capital and dividend payments.

Short-Term Investments — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS maintain cash operating and short-term investment accounts.

Revolving Credit Facilities — Xcel Energy Inc., NSP-Minnesota, PSCo and SPS each have the right to request an extension of the revolving credit facility for two additional one-year periods beyond the June 2024 termination date. NSP-Wisconsin has the right to request an extension of the revolving credit facility termination date for an additional one-year period. All extension requests are subject to majority bank group approval.

As of ~~Oct. 21, 2019,~~May 4, 2020, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet liquidity needs:


(Millions of Dollars)	Credit Facility ^(a)		Drawn ^(b)		Available		Cash		Liquidity		Credit Facility ^(a)		Drawn ^(b)		Available		Cash		Liquidity
Xcel Energy Inc.	$	1,250	$	379	$	871	$	1	$	872	$	1,250	$	107	$	1,143	$	311	$	1,454
PSCo	700		9		691		256		947		700		117		583		1		584
NSP-Minnesota	500		19		481		181		662		500		10		490		52		542
SPS	500		2		498		110		608		500		126		374		1		375
NSP-Wisconsin	150		66		84		1		85		150		55		95		1		96
Total	$	3,100	$	475	$	2,625	$	549	$	3,174	$	3,100	$	415	$	2,685	$	366	$	3,051


^(a)	Credit facilities expire in June 2024.


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

~~Term Loan Agreement~~ —~~In December 2018, Xcel Energy Inc. renewed its $500 million, 364-Day Term Loan Agreement. No additional capacity remains as loans borrowed and repaid may not be redrawn.~~

~~As of Sept. 30, 2019, Xcel Energy Inc.’s term loan borrowings were as follows:~~

(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~~one-year uncommitted bilateral credit agreement. The credit agreement is limited in use to support letters of credit. In March 2020, NSP-Minnesota renewed its bilateral credit agreement for an additional one-year term.

As of ~~Sept. 30, 2019,~~March 31, 2020, NSP-Minnesota’s outstanding letters of credit under the Bilateral Credit Agreement were as follows:



(Millions of Dollars)	Limit		Amount Outstanding		Available
NSP-Minnesota	$	75	$	26	$	49

(Millions of Dollars) Limit Amount Outstanding Available
NSP-Minnesota $ 75
$ 20
$ 55

~~Commercial Paper~~Table of Contents

Short-Term Debt — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each have individual commercial paper programs. The authorized levels for these commercial paper programs are:

$1.25 billion for Xcel Energy Inc.;

$700 million for PSCo;

$500 million for NSP-Minnesota;

$500 million for SPS; and

$150 million for NSP-Wisconsin.

In addition, in December 2019, Xcel Energy Inc. entered into a $500 million 364-Day Term Loan Agreement that matures Dec. 1, 2020. Xcel Energy has an option to request an extension through Nov. 30, 2021. In March 2020, Xcel Energy Inc. entered into a $700 million 364-Day Term Loan Agreement that matures March 22, 2021. Xcel Energy has an option to request an extension through March 21, 2022.

Short-term debt outstanding for Xcel Energy was as follows:


(Amounts in Millions, Except Interest Rates)	Three Months Ended Sept. 30, 2019			Year Ended Dec. 31, 2018			Three Months Ended March 31, 2020			Year Ended Dec. 31, 2019
Borrowing limit	$	3,600		$	3,250		$	4,300		$	3,600
Amount outstanding at period end	933			1,038			1,765			595
Average amount outstanding	1,303			788			1,404			1,115
Maximum amount outstanding	1,780			1,349			2,080			1,780
Weighted average interest rate, computed on a daily basis	2.62		%	2.34		%	2.05		%	2.72		%
Weighted average interest rate at period end	2.54			2.97			1.96			2.34

Money Pool — Xcel Energy received FERC approval to establish a utility money pool arrangement with the utility subsidiaries, subject to receipt of required state regulatory approvals. The utility money pool allows for short-term investments in and borrowings between the utility subsidiaries. Xcel Energy Inc. may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy Inc. The money pool balances are eliminated in consolidation.

NSP-Minnesota, PSCo and SPS participate in the money pool pursuant to approval from their respective state regulatory commissions. NSP-Wisconsin does not participate in the money pool.

~~Capital Expenditures~~ — ~~The estimated base capital expenditures for Xcel Energy for 2020 through 2024 are shown in the table below:~~

Base Capital Forecast
By Subsidiary (Millions of Dollars) 2020 2021 2022 2023 2024
2020 - 2024
Total
NSP-Minnesota $ 2,025
$ 1,580
$ 1,670
$ 1,800
$ 1,845
$ 8,920
PSCo 1,415
1,445
1,720
1,565
1,530
7,675
SPS 1,025
530
700
750
800
3,805
NSP-Wisconsin 250
320
345
350
425
1,690
Other ^(a)
(85 ) (65 ) 10
10
10
(120 )
Total capital expenditures $ 4,630
$ 3,810
$ 4,445
$ 4,475
$ 4,610
$ 21,970

Base Capital Forecast
By Function
(Millions of Dollars)
2020 2021 2022 2023 2024
2020 - 2024
Total
Electric distribution $ 885
$ 1,140
$ 1,415
$ 1,470
$ 1,350
$ 6,260
Electric transmission 625
835
1,295
1,270
1,260
5,285
Electric generation 480
595
580
780
1,000
3,435
Natural gas 520
450
600
560
640
2,770
Other 360
475
555
395
360
2,145
Renewables 1,760
315
—
—
—
2,075
Total capital expenditures $ 4,630
$ 3,810
$ 4,445
$ 4,475
$ 4,610
$ 21,970

^(a)~~Other category includes intercompany transfers for safe harbor wind turbines.~~

~~Table of Contents~~

Xcel Energy’s capital expenditure forecast is subject to continuing review and modification. Actual capital expenditures may vary from estimates due to changes in electric and natural gas projected load growth, safety and reliability needs, regulatory decisions, legislative initiatives, reserve requirements, availability of purchased power, alternative plans for meeting long-term energy needs, environmental regulation, and merger, acquisition and divestiture opportunities.

~~Financing for Capital Expenditures through 2024~~ — Xcel Energy issues debt and equity securities to refinance retiring maturities, reduce short-term debt, fund capital programs, infuse equity in subsidiaries, fund asset acquisitions and for other general corporate purposes. The current estimated financing plans of Xcel Energy for 2020 through 2024 are shown in the table below.

(Millions of Dollars)
Funding Capital Expenditures
Cash from Operations^(a)
$ 13,905
New Debt^(b)
6,665
Equity through the Dividend Reinvestment Program (DRIP) and Benefit Program 400
Other equity 1,000
Base Capital Expenditures 2020-2024 $ 21,970

Maturing Debt $ 3,245

^(a)~~Net of dividends and pension funding.~~

^(b)~~Reflects a combination of short and long-term debt; net of refinancing.~~

~~2019 Debt~~2020 Planned Financing Activity — During ~~2019,~~2020, Xcel Energy plans to issue approximately $75 to $80 million of equity through the DRIP and benefit programs. In addition, Xcel Energy Inc. and its utility subsidiaries issued or anticipate issuing the following debt securities:

Issuer

Security

Amount

Status

Tenor

Coupon

Security

Amount

Status

Tenor

Coupon

Xcel Energy Inc.

Senior Unsecured Notes

600

million

Completed

10 Year

3.4

NSP-Minnesota

First Mortgage Bonds

700

million

Pending

N/A

NSP-Wisconsin

First Mortgage Bonds

100

million

Pending

N/A

PSCo

First Mortgage Bonds

400

million

Completed

30 Year

4.05

First Mortgage Bonds

750

million

Pending

N/A

Xcel Energy Inc.

Senior Unsecured Bonds

130

million

Completed

9 Year

4.00

SPS

First Mortgage Green Bonds

300

million

Completed

30 Year

3.75

First Mortgage Bonds

350

million

Pending

N/A

PSCo

First Mortgage Green Bonds

550

million

Completed

30 Year

3.20

NSP-Minnesota

First Mortgage Green Bonds

600

million

Completed

30 Year

2.90

Xcel Energy Inc.

Senior Unsecured Bonds

billion

Pending

TBD

Financing plans are subject to change, depending on capital expenditures, internal cash generation, market conditions and other factors.

~~2020 Planned Debt Financing~~ ~~— During 2020, Xcel Energy Inc. and its utility subsidiaries anticipate issuing the following:~~

~~Xcel Energy Inc. - approximately $700 million of senior unsecured bonds;~~

~~NSP-Minnesota - approximately $550 million of first mortgage bonds;~~

~~NSP-Wisconsin - approximately $100 million of first mortgage bonds;~~

~~PSCo - approximately $750 million of first mortgage bonds; and~~

~~SPS - approximately $300 million of first mortgage bonds.~~

Forward Equity Agreements — In ~~2018, Xcel Energy entered into a forward equity agreement. On Aug. 29,~~November 2019 Xcel Energy ~~settled the~~Inc. entered into forward equity ~~agreement by delivering 9.4~~agreements in connection with a completed $743 million public offering of 11.8 million shares ~~in exchange for $453 million.~~of common stock.

Off-Balance-Sheet Arrangements

Xcel Energy does not have any off-balance-sheet arrangements, other than those currently disclosed, that have or are reasonably likely to have a current or future effect on financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.

Earnings Guidance and Long-Term EPS and Dividend Growth Rate Objectives

Xcel Energy ~~2019~~2020 Earnings Guidance — Xcel Energy ~~narrows its 2019~~reaffirms 2020 EPS earnings guidance of $2.73 to ~~$2.60 to $2.65~~$2.83 per share ~~from $2.55 to $2.65 per~~

~~share.~~^{(a) (b)}, which assumes the implementation of contingency plans will be sufficient to offset the negative impacts of COVID-19 under the base case scenario. However, these contingency plans would not be sufficient to offset the negative impacts of COVID-19 under the severe scenario, which would likely result in earnings below the guidance range.

Key assumptions as compared with ~~2018~~2019 levels unless noted:

Constructive outcomes in all rate case and regulatory proceedings.

Normal weather patterns for the remainder of the year.

Weather-normalized retail electric sales are projected to ~~be relatively consistent.~~decline ~4%, under the base case scenario.

Weather-normalized retail firm natural gas sales are projected to ~~be within a range of 2.0% to 3.0%.~~

~~Capital rider revenue is projected to increase $115 million to $125 million (net of PTCs). PTCs are credited to customers, through capital riders and reductions to electric margin.~~

~~Purchase capacity costs are expected to~~ decline ~~$25 million to $30 million.~~

~~O&M expenses are projected to decrease approximately 1.0% to 2.0%.~~

Depreciation expense is projected to increase approximately $135 million to $145 million. Depreciation expense includes $34 million for the amortization of a prepaid pension asset at PSCo, which is tax reform related and will not impact earnings.

~~Property taxes are projected to increase approximately $10 million to $20 million.~~

~~Interest expense (net of AFUDC - debt) is projected to increase $80 million to $90 million.~~

~~AFUDC - equity is projected to decrease approximately $20 million to $30 million.~~


•	~~The ETR is projected to be approximately 8~~% ~~to 10~~%~~. The ETR reflects benefits of PTCs which are credited to customers through electric margin and will not impact net income.~~

~~Table of Contents~~

~~Xcel Energy 2020 Earnings Guidance~~ ~~— Xcel Energy’s 2020 GAAP and ongoing earnings guidance is a range of $2.73 to $2.83 per share.~~^(a)

~~Key assumptions as compared with projected 2019 levels unless noted:~~

~~Constructive outcomes in all rate case and regulatory proceedings.~~

~~Normal weather patterns.~~

~~Weather-normalized retail electric sales are projected to increase~~ ~1%, ~~including impact of leap year.~~

~~Weather-normalized retail firm natural gas sales are projected to increase ~1%, including impact of leap year.~~under the base case scenario.

Capital rider revenue is projected to increase $45 million to $55 million (net of PTCs). PTCs are credited to customers, through capital riders and reductions to electric margin.

O&M expenses are projected to ~~increase~~decline approximately ~~2%.~~4% to 5% under the base case scenario.

Depreciation expense is projected to increase approximately ~~$180~~$160 million to ~~$190 million, which includes $30 million of nuclear decommission which is expected to be recovered from customers in rate filings.~~$170 million.

Property taxes are projected to increase approximately ~~$25~~$35 million to ~~$35~~$45 million.

Interest expense (net of AFUDC - debt) is projected to increase ~~$50~~$60 million to ~~$60~~$70 million.

AFUDC - equity is projected to increase approximately ~~$20~~$25 million to ~~$30~~$35 million.


•	The ETR is projected to be approximately 0%. The ETR reflects benefits of PTCs which are credited to customers through electric margin and will not have a material impact on net income.

^(a)

Ongoing earnings is calculated using net income and adjusting for certain nonrecurring or infrequent items that are, in management’s view, not reflective of ongoing operations. Ongoing earnings could differ from those prepared in accordance with GAAP for unplanned and/or unknown adjustments. Xcel Energy is unable to forecast if any of these items will occur or provide a quantitative reconciliation of the guidance for ongoing EPS to corresponding GAAP EPS.


^(b)	The global outbreak of COVID-19 is currently impacting countries, communities, supply chains and markets. The ultimate severity of this event is uncertain and could have a material impact on our liquidity, financial condition, or results of operations.

Long-Term EPS and Dividend Growth Rate Objectives — Xcel Energy expects to deliver an attractive total return to our shareholders through a combination of earnings growth and dividend yield, based on the following long-term objectives:

Deliver long-term annual EPS growth of 5% to 7% based off of a 2019 base of $2.60 per share, which represents the mid-point of the original 2019 guidance range of $2.55 to $2.65 per share;

Deliver annual dividend increases of 5% to 7%;

Target a dividend payout ratio of 60% to 70%; and

Maintain senior secured debt credit ratings in the A range.

~~Item 3~~Table of Contents

COVID-19

The global outbreak of the COVID-19 pandemic has adversely impacted economic conditions worldwide. Efforts to control the spread of COVID-19 have led to shutdowns or curtailments of various industries, disrupting supply chains and markets. Beginning in mid-March, wide-spread government mandates (e.g., shelter-in-place) or other initiatives impacted our service territories. COVID-19 did not significantly impact first quarter 2020 results, but could have a material impact on our financial results in the future.

An overview of certain risk considerations or areas which have or could significantly impact us, is as follows:

Sales— In the first quarter of 2020, Xcel Energy experienced a decline in weather and leap year adjusted sales. The decline in sales was primarily due to pandemic related mandates implemented in March 2020 involving the temporary closure of non-essential businesses and state directives for individuals to stay-at-home. We experienced a substantive decline in April sales and expect that our future sales will be impacted due to stay-at-home and closure provisions in place and the impact of COVID-19 on the economy and its ultimate recovery.

Xcel Energy has decoupling and sales true-up mechanisms in Minnesota (all electric classes) and Colorado (residential and non-demand SC&I electric classes), which mitigate the impact of changes to sales levels as compared to a base line.

The following scenarios outline the potential impact of the pandemic on electric and natural gas sales and EPS, based on various assumptions of the duration of the stay-at-home provisions and economic recovery:


•	Mild Scenario (severe impact through May with a V-shaped economic recovery), resulting in the following change in electric sales for 2020: an increase of approximately 1% in residential; a decline of approximately 4% in C&I; and a decline in total retail electric sales of approximately 2%. This sales decline would reduce EPS by approximately $0.11.

•

Base Case Scenario (severe impact through the second quarter with slower U-shaped recovery with lingering effects throughout 2020), resulting in the following change in electric sales for 2020: an increase of approximately 1% in residential; a decline of approximately 6% in C&I; and a decline in total retail electric sales of approximately 4%. This sales decline would reduce EPS by approximately $0.17.


•	Severe Scenario (severe impact through the third quarter followed by protracted challenged L-shaped recovery), resulting in the following change in electric sales for 2020: an increase of approximately 1% in residential; a decline of approximately 12% in C&I; and a decline in total retail electric sales of approximately 8%. This sales decline would reduce EPS by approximately $0.37.

The mild, base case and severe scenarios include a decrease in natural gas sales of 0%, 1% and 2%, respectively.

Potential impacts due to other items could have negative EPS impact of $0.02 to $0.05, assuming constructive regulatory treatment.

Bad Debt— In March 2020, Xcel Energy announced it would not disconnect residential customers’ electric or natural gas service during the virus outbreak. Certain states have issued additional limitations on charging late fees and extended protection to other customer classes. Bad debt expense could significantly increase due to regulatory orders, pandemic related economic impacts and customers hardship. However, several of our commissions are allowing the deferral of incremental COVID-19 related expense, including bad debt expense as discussed further under Regulatory.

Regulatory— Xcel Energy has received orders in Wisconsin, Texas and Michigan, allowing regulatory deferral of incremental COVID-19 costs as a regulatory asset subject to future determination of amount and timing of recovery. Costs include, but are not limited to, suspension of disconnections, waived late fees and other costs and/or foregone revenues. In addition, the Company has filed requests in Colorado, Minnesota, North Dakota, New Mexico and South Dakota to record a regulatory asset and defer all incremental expenses related to the pandemic.

We will continue to monitor these costs and assess whether the actions of the regulator provide the evidence necessary to defer amounts as regulatory assets. Xcel Energy serves the majority of its wholesale customers under formula transmission and production rates which true-up rates to actual costs to serve.

Contingency Plan— We are implementing contingency plans to reduce costs to offset the negative impact of COVID-19. Actions include reductions of employee expenses, consulting, variable compensation, delays of certain work activities, attrition and implementation of a hiring freeze. Based on these actions, our base case assumption is that 2020 O&M expenses will decline 4% to 5% compared with 2019. The ultimate level of O&M expenses will be dependent on actual sales levels.

In addition, we have received orders allowing the deferral of incremental pandemic related expenses in Texas, Wisconsin and Michigan. We are seeking regulatory authority to defer incremental expense in Minnesota, Colorado and other states.

We believe we can deliver earnings within our 2020 guidance range based on implementing contingency plans to offset the impact of the pandemic on sales and expense levels under the base case scenario. However, our contingency plans may not be able to offset the negative impact of COVID-19 under a severe scenario.

Supply Chain and Capital Expenditures— Xcel Energy’s ability to meet customer energy requirements, respond to storm-related disruptions and maintain our capital expenditure program are dependent on maintaining an efficient supply chain. During the first quarter of 2020, Xcel Energy did not experience any material supply chain, contractor or employee disruptions that prevented us from performing maintenance or construction activity. As a result, we have not significantly adjusted our 2020 capital expenditure plan.

However, the situation is fluid and in April we were informed of supply chain disruptions, which will likely result in delays in the completion of two of our wind farms into 2021. We are working through these challenges to try to complete the projects this year, however, we believe these wind farms would meet the IRS continuous efforts criteria and qualify for 100% PTC benefit even if completed in 2021.

Pension— The funded status of the Xcel Energy pension plans was approximately 90% in January 2020. The funded status of the pension plan is estimated to be in the low 80% range, based on market conditions as of early May 2020.

Our disciplined pension plan management practices include maintaining a well-diversified growth portfolio across a diverse set of asset classes and an allocation to interest rate hedging instruments. Xcel Energy does not expect any material changes to its pension funding requirement at this time. In addition, Xcel Energy has pension trackers in Colorado and Texas, which allow us to defer amounts that are above or below a baseline.

Table of Contents

Liquidity — Xcel Energy has taken steps to enhance its liquidity and believes it has more than adequate liquidity.

As a result of these actions, Xcel Energy currently has $3.1 billion of available liquidity. In addition, there are other items that will enhance liquidity.

Xcel Energy has an outstanding forward equity agreement in connection with a $743 million public offering of 11.8 million shares. These shares have not been issued and we expect to settle this equity forward later in 2020.

The MEC sale will result in approximately $650 million of additional funds, after our previously-announced planned corporate giving, that can be used for general corporate purposes and enhanced liquidity.

Xcel Energy continues to have access to the capital markets on favorable terms.

Customer Service & Reliability — Xcel Energy remains committed to continuing to safely deliver reliable services to our customers as families and communities face the COVID-19 pandemic. We have exercised our business continuity plans to safely serve our customers, protect our employees and ensure critical positions remain staffed.

Key actions include:

Executing work-from-home practices for employees who can do their work remotely;

Enhancing cleaning practices within our facilities;

Providing proper personal protective equipment and following CDC and state guidelines;

Conducting employee temperature checks;

Changing work practices to promote social distancing;

Splitting crews and staggering work times;

Limiting employee entry into customer homes to emergency situations only; and

Reminding customers of increased risks of scam activity.

~~QUANTITATIVE AND~~Employees ~~QUALITATIVE DISCLOSURES ABOUT MARKET RISK~~— The health and safety of our workforce is one of our core values, and we have taken several actions that reflect that during this pandemic:

~~See Management’s Discussion~~Continued pay for employees who have been quarantined;

Expanded medical plan coverage for employees and ~~Analysis~~ their families to include 100% of COVID-19 medical costs;

Offered up to an additional 80 hours of paid time off to employees for pandemic related illness;

Expanded eligibility for our paid time off donation program to employees who have or are caring for a family member who has been diagnosed with the virus;

Offered new anxiety and stress management tools, in addition to our existing Employee Assistance Program; and

Provided resources and educational materials to support employees adjusting to distance learning with their children.

Communities— Xcel Energy is committed to the communities in which we operate. Early actions include the following:

Plan to donate approximately $20 million in corporate giving, including COVID-19 relief in 2020. Along with the Xcel Energy Foundation, we have already donated approximately $1.5 million to support pandemic relief efforts across our eight-state footprint and implemented a virtual volunteering program;

Donated over 300,000 masks to hospitals in the communities we serve; and launched a special $300,000 COVID-19 two-to-one matching campaign, which provides a match for employee donations to impacted non-profit organizations, in addition to our standard employee matching gift programs; and

Submitted a proposal to reduce our approved 2020 Fuel Forecast by $25 million to provide immediate relief to our Minnesota customers during the pandemic and resulting economic downturn, which will be implemented across the three summer months equally.

ITEM 3 — QUANTITATIVE ANDQUALITATIVE DISCLOSURES ABOUT MARKET RISK

There have been no material changes from Derivatives, Risk Management and Market Risk ~~under Item 2.~~from our 2019 Form 10-K.

~~Item~~

ITEM 4 — CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Xcel Energy maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the CEO and CFO, allowing timely decisions regarding required disclosure.

As of ~~Sept. 30, 2019,~~March 31, 2020, based on an evaluation carried out under the supervision and with the participation of Xcel Energy’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that Xcel Energy’s disclosure controls and procedures were effective.

Internal Control Over Financial Reporting

No changes in Xcel Energy’s internal control over financial reporting occurred during the most recent fiscal quarter that materially affected, or are reasonably likely to materially affect, Xcel Energy’s internal control over financial reporting.

Part II — OTHER INFORMATION

~~Item 1~~ — ~~Legal Proceedings~~

ITEM 1 — LEGAL PROCEEDINGS

See Note 10 to the consolidated financial statements and Part I Item 2 for further information.

~~Item~~

Table of Contents

ITEM 1A — RISK FACTORS

There have been no material changes from the risk factors disclosed in the 2019Form 10-K except as follows:

We face risks related to health epidemics and other outbreaks, which may have a material effect on our financial condition, results of operations and cash flows.

The global outbreak of COVID-19 is currently impacting countries, communities, supply chains and markets. COVID-19 has not had a material impact on our first quarter results; however, we did experience a substantive drop in our sales in April. The severity of the outbreak is uncertain and we cannot ultimately predict whether it will have a material impact on our liquidity, financial condition, or results of operations. Nor can we predict the impact of the virus on the health of our employees, our supply chain or our ability to recover higher costs associated with managing through the pandemic.

Xcel ~~Energy Inc.’s~~Energy’s risk factors are documented in Item 1A of Part I of its Annual Report on Form 10-K for the year ended Dec. 31, ~~2018,~~2019, which is incorporated herein by ~~reference. There~~reference, as well as other information set forth in this report, which could have ~~been no~~a material ~~changes from the risk factors previously disclosed in the~~ ~~Form 10-K~~.impact on our financial condition, results of operations and cash flows.

~~Item~~

ITEM 2— — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

~~For the quarter ended Sept. 30, 2019, no~~The following table provides information about our purchases of equity securities that are registered by Xcel Energy Inc., pursuant to Section 12 of the ~~Securities~~ Exchange Act ~~of 1934, were purchased by or on behalf of us or any of our affiliated purchasers.~~

for the quarter ended March 31, 2020:



	Issuer Purchases of Equity Securities
Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs
Jan. 1, 2020 - Jan. 31, 2020	—	$	—	—	—
Feb. 1, 2020 - Feb. 29, 2020	—	—		—	—
March 1, 2020 - March 31, 2020 ^(a)	6,394	62.32		—	—
Total	6,394			—	—


^(a)	Xcel Energy Inc. withholds stock to satisfy tax withholding obligations on vesting of awards of restricted stock under the Xcel Energy Executive Annual Incentive Award Plan.

~~Table of Contents~~

~~Item 6~~—~~EXHIBITS~~

ITEM 6 — EXHIBITS

* Indicates incorporation by reference

+ Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors



Exhibit Number	Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference
3.01*	Amended and Restated Articles of Incorporation of Xcel Energy Inc.	Xcel Energy Inc. Form 8-K dated May 16, 2012	001-03034	3.01
3.02*	Bylaws of Xcel Energy Inc. as Amended on April 3, 2020	Xcel Energy Inc Form 8-K dated April 3, 2020	001-03034	3.01
4.01*	Supplemental Indenture No. 13, dated as of April 1, 2020 between Xcel Energy Inc. and Wells Fargo Bank, National Association as Trustee	Xcel Energy Inc. Form 8-K dated ~~Feb. 17, 2016~~April 1, 2020	001-03034	~~3.01~~
4.01*	Supplemental Trust Indenture dated as of September 1, 2019 between Northern States Power Company and The Bank of New York Mellon Trust Company, N.A., as successor Trustee, creating 2.90% First Mortgage Bonds, Series due March 1, 2050.	~~NSP-Minnesota Form 8-K dated Sept. 10, 2019~~	~~001-31387~~	4.01
4.0210.01	~~Supplemental Indenture~~364-Day Term Loan Agreement dated as of ~~August 1, 2019, between Public Service Company of Colorado~~March 23, 2020 among Xcel Energy Inc. as Borrower, the several lenders from time to time parties thereto, and U.S. Bank National Association, as ~~successor Trustee, creating 3.20% First Mortgage Bonds, Series No. 34 due March 1, 2050.~~Administrative Agent	~~PSCo~~Xcel Energy Inc. Form 8-K dated ~~August 13, 2019~~March 23, 2020	~~001-3280~~001-03034	~~4.01~~10.01
10.02+	Eighth Amendment to the Xcel Energy Senior Executive Severance and Change-In-Control Policy
31.01	Principal Executive Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02	Principal Financial Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS	XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH	XBRL Schema
101.CAL	XBRL Calculation
101.DEF	XBRL Definition
101.LAB	XBRL Label
101.PRE	XBRL Presentation
104	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

3833

Table of Contents

SIGNATURES

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



		XCEL ENERGY INC.

~~Oct. 25, 2019~~May 7, 2020	By:	/s/ JEFFREY S. SAVAGE
		Jeffrey S. Savage
		Senior Vice President, Controller
		(Principal Accounting Officer)

		/s/ ~~ROBERT C. FRENZEL~~BRIAN J. VAN ABEL
		~~Robert C. Frenzel~~Brian J. Van Abel
		Executive Vice President, Chief Financial Officer
		(Principal Financial Officer)

3934



(Millions of Dollars)	Sept. 30, 2019
PPAs	$	1,642
Other	201
Gross operating lease ROU assets	1,843
Accumulated amortization	(125		)
Net operating lease ROU assets	$	1,718



(Millions of Dollars)	Sept. 30, 2019
Gas storage facilities	$	201
Gas pipeline	21
Gross finance lease ROU assets	222
Accumulated amortization	(81		)
Net finance lease ROU assets	$	141



(Millions of Dollars)	PPA ^{(a) (b)} Operating Leases			Other Operating Leases			Total Operating Leases			Finance Leases ^(c)
2019	$	59		$	6		$	65		$	3
2020	236			26			262			14
2021	238			29			267			14
2022	225			28			253			12
2023	214			25			239			12
Thereafter	959			136			1,095			219
Total minimum obligation	1,931			250			2,181			274
Interest component of obligation	(337		)	(54		)	(391		)	(192		)
Present value of minimum obligation	$	1,594		$	196		1,790			82
Less current portion							(192		)	(4		)
Noncurrent operating and finance lease liabilities							$	1,598		$	78

Weighted-average remaining lease term in years							9.5			37.2



(Millions of Dollars)	Filed base revenue request		Less: Previously authorized costs (existing riders) ^(b)		Filed net change to revenue ^(c)
PSCo	$	408	$	249	$	158
CPUC Staff ^(a)	235		227		8
FEA	246		239		7
OCC ^(a)	207		216		(9		)
CEC ^(a)	187		213		(26		)



Position	Staff			FEA			OCC			CEC
ROE	9.00	%		9.20	%		8.80	%		8.90	%
Equity	55.57	%		56.11	%		54.60	%		54.27	%
Test Year	2019 Current		^(a)	2018 Historic		^(b)	2018 Historic		^(c)	2018 Historic		^(d)



Revenue Request (Millions of Dollars)
Hale Wind Farm	$	28
Other plant investment	22
Wholesale sales reduction	17
Allocator changes due to load growth	15
Depreciation rate change (including Tolk)	15
Base rate sales growth	(41		)
Other, net	(5		)
New revenue request	$	51



	Base Capital Forecast
By Subsidiary (Millions of Dollars)	2020			2021			2022		2023		2024		2020 - 2024 Total
NSP-Minnesota	$	2,025		$	1,580		$	1,670	$	1,800	$	1,845	$	8,920
PSCo	1,415			1,445			1,720		1,565		1,530		7,675
SPS	1,025			530			700		750		800		3,805
NSP-Wisconsin	250			320			345		350		425		1,690
Other ^(a)	(85		)	(65		)	10		10		10		(120		)
Total capital expenditures	$	4,630		$	3,810		$	4,445	$	4,475	$	4,610	$	21,970



	Base Capital Forecast
By Function (Millions of Dollars)	2020		2021		2022		2023		2024		2020 - 2024 Total
Electric distribution	$	885	$	1,140	$	1,415	$	1,470	$	1,350	$	6,260
Electric transmission	625		835		1,295		1,270		1,260		5,285
Electric generation	480		595		580		780		1,000		3,435
Natural gas	520		450		600		560		640		2,770
Other	360		475		555		395		360		2,145
Renewables	1,760		315		—		—		—		2,075
Total capital expenditures	$	4,630	$	3,810	$	4,445	$	4,475	$	4,610	$	21,970



(Millions of Dollars)
Funding Capital Expenditures
Cash from Operations^(a)	$	13,905
New Debt^(b)	6,665
Equity through the Dividend Reinvestment Program (DRIP) and Benefit Program	400
Other equity	1,000
Base Capital Expenditures 2020-2024	$	21,970

Maturing Debt	$	3,245

(~~Registrant,~~ State or Other Jurisdiction of Incorporation or ~~Organization, Address of Principal Executive Officers and Telephone~~Organization)

(Commission File Number)

(IRS Employer Identification No.)

~~Xcel Energy Inc.~~

~~Minnesota~~