xel-20200930


Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former)
e prime			e prime inc.
NSP-Minnesota			Northern States Power Company, a Minnesota corporation
NSP-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
Xcel Energy			Xcel Energy Inc. and its subsidiaries


Federal and State Regulatory Agencies
CPUC			Colorado Public Utilities Commission
D.C. Circuit			United States Court of Appeals for the District of Columbia Circuit
DOC			Department of Commerce
EPA			United States Environmental Protection Agency
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
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
AFUDC			Allowance for funds used during construction
AGIS			Advanced Grid Intelligence and Security
ALJ			Administrative Law Judge
ASC			FASB Accounting Standards Codification
C&I			Commercial and Industrial
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
COVID-19			Novel coronavirus
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
NOL			Net operating loss


O&M			Operating and maintenance
OATT			Open Access Transmission Tariff
PPA			Power purchase agreement
PTC			Production tax credit
ROE			Return on equity
ROFR			Right-of-first refusal
RTO			Regional Transmission Organization
SMMPA			Southern Minnesota Municipal Power Agency
SPP			Southwest Power Pool, Inc.
THI			Temperature-humidity index
TOs			Transmission owners
VaR			Value at Risk
VIE			Variable interest entity


Measurements
MW			Megawatts


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 2020 EPS guidance, 2021 EPS guidance, long-term EPS and dividend growth rate objectives, future sales, future bad debt expense, future operating performance, estimated base capital expenditures and financing plans, projected capital additions and forecasted annual revenue requirements with respect to rider filings, and expectations regarding regulatory proceedings, 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 filings with the SEC (including Xcel Energy’s Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2019, and subsequent 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 regulation and subsidiaries’ ability 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; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; seasonal weather patterns; changes in environmental laws and regulations; climate change and other weather; natural disaster and resource depletion, including compliance with any accompanying legislative and regulatory changes; and costs of potential regulatory penalties.


	Three Months Ended Sept. 30				Nine Months Ended Sept. 30
	2020		2019		2020		2019
Operating revenues
Electric	$	2,941	$	2,771	$	7,430	$	7,345
Natural gas	219		222		1,082		1,324
Other	22		20		67		62
Total operating revenues	3,182		3,013		8,579		8,731

Operating expenses
Electric fuel and purchased power	981		952		2,611		2,679
Cost of natural gas sold and transported	54		55		425		646
Cost of sales — other	11		9		28		28
Operating and maintenance expenses	579		580		1,708		1,764
Conservation and demand side management expenses	73		75		215		212
Depreciation and amortization	513		447		1,449		1,319
Taxes (other than income taxes)	158		137		453		429
Total operating expenses	2,369		2,255		6,889		7,077

Operating income	813		758		1,690		1,654

Other income (expense), net	1		8		(6)		14
Equity earnings of unconsolidated subsidiaries	12		10		29		29
Allowance for funds used during construction — equity	30		15		91		55

Interest charges and financing costs
Interest charges — includes other financing costs of $7, $6, $21 and $19, respectively	221		199		628		578
Allowance for funds used during construction — debt	(11)		(7)		(33)		(27)
Total interest charges and financing costs	210		192		595		551

Income before income taxes	646		599		1,209		1,201
Income tax expense	43		72		24		121
Net income	$	603	$	527	$	1,185	$	1,080

Weighted average common shares outstanding:
Basic	526		519		526		517
Diluted	528		521		527		518

Earnings per average common share:
Basic	$	1.15	$	1.02	$	2.25	$	2.09
Diluted	1.14		1.01		2.25		2.08

See Notes to Consolidated Financial Statements


	Nine Months Ended Sept. 30
	2020		2019
Operating activities
Net income	$	1,185	$	1,080
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	1,459		1,332
Nuclear fuel amortization	94		89
Deferred income taxes	45		130
Allowance for equity funds used during construction	(91)		(55)
Equity earnings of unconsolidated subsidiaries	(29)		(29)
Dividends from unconsolidated subsidiaries	32		30
Provision for bad debts	39		30
Share-based compensation expense	60		47
Changes in operating assets and liabilities:
Accounts receivable	(108)		9
Accrued unbilled revenues	124		132
Inventories	(37)		(60)
Other current assets	(68)		3
Accounts payable	(97)		(56)
Net regulatory assets and liabilities	(139)		(6)
Other current liabilities	(54)		(100)
Pension and other employee benefit obligations	(138)		(138)
Other, net	(103)		119
Net cash provided by operating activities	2,174		2,557

Investing activities
Capital/construction expenditures	(3,681)		(3,018)
Sale of MEC	684		—
Purchase of investment securities	(1,275)		(472)
Proceeds from the sale of investment securities	1,260		462
Other, net	(9)		(101)
Net cash used in investing activities	(3,021)		(3,129)

Financing activities
Proceeds from short-term borrowings, net	(95)		(105)
Proceeds from issuances of long-term debt	2,940		1,937
Repayments of long-term debt, including reacquisition premiums	(701)		(399)
Proceeds from issuance of common stock	5		457
Dividends paid	(638)		(587)
Other, net	(27)		(14)
Net cash provided by financing activities	1,484		1,289

Net change in cash and cash equivalents	637		717
Cash and cash equivalents at beginning of period	248		147
Cash and cash equivalents at end of period	$	885	$	864

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(582)	$	(544)
Cash (paid) received for income taxes, net	(17)		53

Supplemental disclosure of non-cash investing and financing transactions:
Accrued property, plant and equipment additions	$	933	$	420
Inventory transfers to property, plant and equipment	250		64
Operating lease right-of-use assets	361		1,718
Allowance for equity funds used during construction	91		55
Issuance of common stock for equity awards	51		46


See Notes to Consolidated Financial Statements


	Sept. 30, 2020		Dec. 31, 2019
Assets
Current assets
Cash and cash equivalents	$	885	$	248
Accounts receivable, net	899		837
Accrued unbilled revenues	586		713
Inventories	512		544
Regulatory assets	576		488
Derivative instruments	69		55
Prepaid taxes	78		43
Prepayments and other	232		185
Total current assets	3,837		3,113

Property, plant and equipment, net	42,227		39,483

Other assets
Nuclear decommissioning fund and other investments	2,813		2,731
Regulatory assets	2,918		2,935
Derivative instruments	31		22
Operating lease right-of-use assets	1,534		1,672
Other	348		492
Total other assets	7,644		7,852
Total assets	$	53,708	$	50,448

Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	401	$	702
Short-term debt	500		595
Accounts payable	1,602		1,294
Regulatory liabilities	302		407
Taxes accrued	504		466
Accrued interest	186		192
Dividends payable	226		212
Derivative instruments	48		38
Operating lease liabilities	208		194
Other	416		468
Total current liabilities	4,393		4,568

Deferred credits and other liabilities
Deferred income taxes	4,696		4,509
Deferred investment tax credits	46		49
Regulatory liabilities	5,311		5,077
Asset retirement obligations	2,942		2,701
Derivative instruments	158		175
Customer advances	201		203
Pension and employee benefit obligations	651		785
Operating lease liabilities	1,395		1,549
Other	178		186
Total deferred credits and other liabilities	15,578		15,234

Commitments and contingencies
Capitalization
Long-term debt	19,960		17,407
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 525,452,824 and 524,539,000 shares outstanding at Sept. 30, 2020 and Dec. 31, 2019, respectively	1,314		1,311
Additional paid in capital	6,694		6,656
Retained earnings	5,912		5,413
Accumulated other comprehensive loss	(143)		(141)
Total common stockholders’ equity	13,777		13,239
Total liabilities and equity	$	53,708	$	50,448

See Notes to Consolidated Financial Statements


	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, 2020 and 2019
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

Balance at June 30, 2020	525,205	$	1,313	$	6,679	$	5,538	$	(145)	$	13,385
Net income						603				603
Other comprehensive income								2		2
Dividends declared on common stock ($0.43 per share)						(226)				(226)
Issuances of common stock	302	1		9						10
Repurchase of common stock	(54)	—		(4)						(4)
Share-based compensation				10		(3)				7
Balance at Sept. 30, 2020	525,453	$	1,314	$	6,694	$	5,912	$	(143)	$	13,777

	Common Stock Issued					Retained Earnings		Accumulated Other Comprehensive Loss		Total Common Stockholders' Equity
	Shares	Par Value		Additional Paid In Capital
Nine Months Ended Sept. 30, 2020 and 2019
Balance at Dec. 31, 2018	514,037	$	1,285	$	6,168	$	4,893	$	(124)	$	12,222
Net income						1,080				1,080
Other comprehensive loss								(18)		(18)
Dividends declared on common stock ($1.215 per share)						(633)				(633)
Issuances of common stock	10,353	26		458						484
Repurchases of common stock	(6)	—		—						—
Share-based compensation				10		(4)				6
Balance at Sept. 30, 2019	524,384	$	1,311	$	6,636	$	5,336	$	(142)	$	13,141

Balance at Dec. 31, 2019	524,539	$	1,311	$	6,656	$	5,413	$	(141)	$	13,239
Net income						1,185				1,185
Other comprehensive loss								(2)		(2)
Dividends declared on common stock ($1.29 per share)						(679)				(679)
Issuances of common stock	968	3		30						33
Repurchase of common stock	(54)	—		(4)						(4)
Share-based compensation				12		(5)				7
Adoption of ASC Topic 326						(2)				(2)
Balance at Sept. 30, 2020	525,453	$	1,314	$	6,694	$	5,912	$	(143)	$	13,777

See Notes to Consolidated Financial Statements

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, 2020 and Dec. 31, 2019; the results of Xcel Energy’s operations, including the components of net income and comprehensive income, and changes in stockholders’ equity for the three and nine months ended Sept. 30, 2020 and 2019; and Xcel Energy’s cash flows for the nine months ended Sept. 30, 2020 and 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, 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, 2019 balance sheet information has been derived from the audited 2019 consolidated financial statements included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 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, 2019, filed with the SEC on Feb. 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, 2019 appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.


2. Accounting Pronouncements

Recently Adopted

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.

Xcel Energy implemented the guidance using a modified-retrospective approach, recognizing a cumulative effect charge of $2 million (after tax) to retained earnings on Jan. 1, 2020. Other than first-time recognition of an allowance for bad debts on accrued unbilled revenues, the Jan. 1, 2020, adoption of ASC Topic 326 did not have a significant impact on Xcel Energy’s consolidated financial statements.


3. Selected Balance Sheet Data


(Millions of Dollars)	Sept. 30, 2020		Dec. 31, 2019
Accounts receivable, net
Accounts receivable	$	965	$	892
Less allowance for bad debts	(66)		(55)
Accounts receivable, net	$	899	$	837


(Millions of Dollars)	Sept. 30, 2020		Dec. 31, 2019
Inventories
Materials and supplies	$	275	$	270
Fuel	157		191
Natural gas	80		83
Total inventories	$	512	$	544


(Millions of Dollars)	Sept. 30, 2020		Dec. 31, 2019
Property, plant and equipment, net
Electric plant	$	46,531	$	44,355
Natural gas plant	6,899		6,560
Common and other property	2,401		2,341
Plant to be retired (a)	287		259
Construction work in progress	3,265		2,329
Total property, plant and equipment	59,383		55,844
Less accumulated depreciation	(17,456)		(16,735)
Nuclear fuel	2,930		2,909
Less accumulated amortization	(2,630)		(2,535)
Property, plant and equipment, net	$	42,227	$	39,483

(a)The CPUC has approved early retirement of PSCo’s Comanche Units 1 and 2 in approximately 2022 and 2025, respectively, and PSCo’s Craig 1 in approximately 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.

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


(Amounts in Millions, Except Interest Rates)	Three Months Ended Sept. 30, 2020			Year Ended Dec. 31, 2019
Borrowing limit	$	3,600		$	3,600
Amount outstanding at period end	500			595
Average amount outstanding	1,195			1,115
Maximum amount outstanding	1,438			1,780
Weighted average interest rate, computed on a daily basis	0.81		%	2.72		%
Weighted average interest rate at period end	0.66			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 both Sept. 30, 2020 and Dec. 31, 2019, there were $20 million 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.

As of Sept. 30, 2020, Xcel Energy Inc. and its utility subsidiaries had the following committed revolving credit facilities available:


(Millions of Dollars)	Credit Facility (a)		Drawn (b)		Available
Xcel Energy Inc.	$	1,250	$	—	$	1,250
PSCo	700		8		692
NSP-Minnesota	500		10		490
SPS	500		2		498
NSP-Wisconsin	150		—		150
Total	$	3,100	$	20	$	3,080

(a)Expires in June 2024.

(b)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 two 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.

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 no direct advances on the credit facilities outstanding as of Sept. 30, 2020 and Dec. 31, 2019.

Term Loan Agreements — 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. 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 percent. Interest is at a rate equal to either the Eurodollar rate, plus 50.0 basis points, or an alternate base rate.

In September 2020, Xcel Energy Inc. repaid an incremental $700 million 364-Day Term Loan Agreement that was entered into in March 2020.

As of Sept. 30, 2020, 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 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, 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	$	46	$	29

Long-Term Borrowings

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

•Xcel Energy Inc. issued $600 million of 3.40% senior unsecured notes due June 1, 2030;

•PSCo issued $375 million of 2.70% first mortgage bonds due Jan. 15, 2051 and $375 million of 1.90% first mortgage bonds due Jan. 15, 2031;

•SPS issued $350 million of 3.15% first mortgage bonds due May 1, 2050;

•NSP-Wisconsin issued $100 million of 3.05% first mortgage bonds due May 1, 2051;

•NSP-Minnesota issued $700 million of 2.60% first mortgage bonds due June 1, 2051; and

•Xcel Energy Inc. issued $500 million of 0.50% senior unsecured notes due Oct. 15, 2023.

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

At Sept. 30, 2020, the forward agreements could have been settled with physical delivery of 11.8 million common shares to the banking counterparty in exchange for cash of $722 million. The forward instruments could also have been settled at Sept. 30, 2020, with delivery of approximately $92 million of cash or approximately 1.3 million shares of common stock to the counterparty, if Xcel Energy unilaterally elected net cash or net share settlement, respectively.

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

Xcel Energy may settle the agreements at any time up to the maturity date of Dec. 31, 2020. Depending on settlement timing, cash proceeds are expected to be approximately $720 million.

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

Other Equity — Xcel Energy Inc. issued $30 million and $29 million of equity through the DRIP during the nine months ended Sept. 30, 2020 and 2019, respectively. The program allows shareholders to elect dividend reinvestment in Xcel Energy Inc. common stock through a non-cash transaction.


5. Revenues

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


	Three Months Ended Sept. 30, 2020
(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	962	$	124	$	11	$	1,097
C&I	1,340		56		5		1,401
Other	34		—		2		36
Total retail	2,336		180		18		2,534
Wholesale	227		—		—		227
Transmission	157		—		—		157
Other	17		28		—		45
Total revenue from contracts with customers	2,737		208		18		2,963
Alternative revenue and other	204		11		4		219
Total revenues	$	2,941	$	219	$	22	$	3,182


	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


	Nine Months Ended Sept. 30, 2020
(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	2,356	$	647	$	32	$	3,035
C&I	3,481		308		20		3,809
Other	94		—		4		98
Total retail	5,931		955		56		6,942
Wholesale	553		—		—		553
Transmission	442		—		—		442
Other	55		86		—		141
Total revenue from contracts with customers	6,981		1,041		56		8,078
Alternative revenue and other	449		41		11		501
Total revenues	$	7,430	$	1,082	$	67	$	8,579


	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


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, 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
	2020		2019		2020		2019
Federal statutory rate	21.0	%	21.0	%	21.0	%	21.0	%
State tax (net of federal tax effect)	5.0		5.0		5.1		5.0
Decreases:
Wind PTCs	(8.0)		(6.1)		(13.2)		(8.1)
Plant regulatory differences (a)	(7.2)		(5.6)		(7.4)		(5.5)
NOL carryback	(1.9)		—		(1.0)		—
Other tax credits and NOL allowances (net)	(1.0)		(1.7)		(1.2)		(1.8)
Other (net)	(1.2)		(0.6)		(1.3)		(0.5)
Effective income tax rate	6.7	%	12.0	%	2.0	%	10.1	%

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

Federal Tax Loss Carryback Claims — In 2020, Xcel Energy identified certain expenses related to tax years 2009-2011 that qualify for an extended carryback claim. As a result, a tax benefit of approximately $13 million was recognized in 2020.

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


Tax Years						Expiration
2014 — 2016						July 2021

Additionally, the statute of limitations related to the federal tax loss carryback claim referenced above has been extended. 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 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. In April 2020, Xcel Energy and Office of Appeals reached an agreement and no material adjustments were required.

In 2018, the IRS began an audit of tax years 2014 - 2016. In July 2020, Xcel Energy and the IRS reached an agreement and the related benefit was recognized.

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, 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						2011
Wisconsin						2014

•In 2018, Wisconsin began an audit of tax years 2014 - 2016. As of Sept. 30, 2020, no material adjustments have been proposed.

•In July 2020, Minnesota began a review of the 2015-2018 Research and Experimentation Credits. As of Sept. 30, 2020, no material adjustments have been proposed.

•No other state income tax audits were in progress as of Sept. 30, 2020.

Unrecognized Benefits — The 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, 2020		Dec. 31, 2019
Unrecognized tax benefit — Permanent tax positions	$	36	$	35
Unrecognized tax benefit — Temporary tax positions	5		9
Total unrecognized tax benefit	$	41	$	44

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


(Millions of Dollars)	Sept. 30, 2020		Dec. 31, 2019
NOL and tax credit carryforwards	$	(28)	$	(40)

Net deferred tax liability associated with the unrecognized tax benefit amounts and related NOLs and tax credit carryforwards were $23 million at Sept. 30, 2020 and $29 million at Dec. 31, 2019.

As the IRS audit resumes and state audits progress, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $19 million in the next 12 months.

Payables for interest related to unrecognized tax benefits were not material and no amounts were accrued for penalties related to unrecognized tax benefits as of Sept. 30, 2020 or Dec. 31, 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.

Common Stock Equivalents — Xcel Energy Inc. has common stock equivalents related to forward equity agreements and time-based equity compensation awards.

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

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 1.6 million and 1.0 million for the three and nine months ended Sept. 30, 2020, respectively, and 1.8 million and 1.6 million for the three and nine months ended Sept. 30, 2019, 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 and requires disclosures about assets and liabilities measured at fair value. A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance.

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

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

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

Specific valuation methods include:

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

Investments in equity securities and other funds — Equity securities are valued using quoted prices in active markets. The fair values for commingled funds are measured using NAVs. The investments in commingled funds may be redeemed for NAV with proper notice. Private equity commingled fund investments require approval of the fund for any unscheduled redemption, and such redemptions may be approved or denied by the fund at its sole discretion. Unscheduled distributions from real estate commingled funds investments may be redeemed with proper notice, however, withdrawals may be delayed or discounted as a result of fund illiquidity.

Investments in debt securities — Fair values for debt securities are determined by a third party pricing service using recent trades and observable spreads from benchmark interest rates for similar securities.

Interest rate derivatives — Fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.

Commodity derivatives — Methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations and are generally assigned a Level 2 classification. When contractual settlements relate to inactive delivery locations or extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable forecasts of forward prices and volatilities on a valuation is evaluated and may result in Level 3 classification.

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

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

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

Non-trading monthly FTR settlements are included in fuel and purchased energy cost recovery mechanisms as applicable in each jurisdiction and therefore changes in the fair value of the yet to be settled portions of most FTRs are deferred as a regulatory asset or liability. Given this regulatory treatment and the limited magnitude of FTRs relative to the electric utility operations of NSP-Minnesota and SPS, the numerous unobservable quantitative inputs pertinent to the value of FTRs are insignificant to the consolidated financial 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 $770 million and $706 million as of Sept. 30, 2020 and Dec. 31, 2019, respectively, and unrealized losses were $13 million and $6 million as of Sept. 30, 2020 and Dec. 31, 2019, respectively.

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


	Sept. 30, 2020
			Fair Value
(Millions of Dollars)	Cost		Level 1		Level 2		Level 3		NAV		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	22	$	22	$	—	$	—	$	—	$	22
Commingled funds	773		—		—		—		956		956
Debt securities	519		—		546		13		—		559
Equity securities	450		983		1				—		984
Total	$	1,764	$	1,005	$	547	$	13	$	956	$	2,521

(a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $160 million of equity investments in unconsolidated subsidiaries and $132 million of rabbi trust assets and miscellaneous investments.


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

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

For the three and nine months ended Sept. 30, 2020 and 2019, there were immaterial Level 3 nuclear decommissioning fund investments or transfer of amounts between levels.

Contractual maturity dates of debt securities in the nuclear decommissioning fund as of Sept. 30, 2020:


	Final Contractual Maturity
(Millions of Dollars)	Due in 1 year or Less		Due in 1 to 5 Years		Due in 5 to 10 Years		Due after 10 years		Total
Debt securities	$	1	$	109	$	208	$	241	$	559

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, 2020
			Fair Value
(Millions of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Rabbi Trusts (a)
Cash equivalents	$	17	$	17	$	—	$	—	$	17
Mutual funds	58		65		—		—		65
Total	$	75	$	82	$	—	$	—	$	82


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

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

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 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, with changes in fair value prior to settlement recorded as other comprehensive income.

As of Sept. 30, 2020, accumulated other comprehensive loss related to settled interest rate derivatives included $6 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, 2020. Xcel Energy had no unsettled interest rate derivatives.

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. The classification as a regulatory asset or liability, if applicable, is based on approved regulatory recovery mechanisms.

As of Sept. 30, 2020, Xcel Energy had no commodity contracts designated as cash flow hedges.

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

Gross notional amounts of commodity forwards, options and FTRs:


(Amounts in Millions) (a)(b)	Sept. 30, 2020	Dec. 31, 2019
Megawatt hours of electricity	107	95
Million British thermal units of natural gas	177	110

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

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

Consideration of Credit Risk and Concentrations — Xcel Energy continuously monitors the creditworthiness of counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement, and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Impact of credit risk was immaterial to the fair value of unsettled commodity derivatives presented 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, 2020, six of Xcel Energy’s 10 most significant counterparties for these activities, comprising $147 million, or 57%, of this credit exposure, had investment grade credit ratings from S&P Global Ratings, Moody’s Investor Services or Fitch Ratings. Three of the 10 most significant counterparties, comprising $38 million, or 15%, 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. One of these significant counterparties, comprising $9 million or 4% of this credit exposure, had credit quality less than investment grade, based on internal analysis. Eight 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:
(Millions of Dollars)	Accumulated Other Comprehensive Loss		Regulatory (Assets) and Liabilities
Three Months Ended Sept. 30, 2020
Other derivative instruments
Electric commodity	$	—	$	(3)
Natural gas commodity	—		2
Total	$	—	$	(1)

Nine Months Ended Sept. 30, 2020
Derivatives designated as cash flow hedges
Interest rate	$	(13)	$	—
Total	$	(13)	$	—
Other derivative instruments
Electric commodity	$	—	$	(3)
Natural gas commodity	—		(1)
Total	$	—	$	(4)

Three Months Ended Sept. 30, 2019
Derivatives designated as cash flow hedges
Interest rate	$	(12)	$	—
Total	$	(12)	$	—
Other derivative instruments

Natural gas commodity	$	—	$	(3)
Total	$	—	$	(3)

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


	Pre-Tax (Gains) Losses Reclassified into Income During the Period from:						Pre-Tax Gains (Losses) Recognized During the Period in Income
(Millions of Dollars)	Accumulated Other Comprehensive Loss			Regulatory Assets and (Liabilities)
Three Months Ended Sept. 30, 2020
Derivatives designated as cash flow hedges
Interest rate	$	1	(a)	$	—		$	—
Total	$	1		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	2	(b)
Electric commodity	—			(3)		(c)	—
Total	$	—		$	(3)		$	2

Nine Months Ended Sept. 30, 2020
Derivatives designated as cash flow hedges
Interest rate	$	5	(a)	$	—		$	—
Total	$	5		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	(1)	(b)
Electric commodity	—			(6)		(c)	—
Natural gas commodity	—			5		(d)	(6)		(d)
Total	$	—		$	(1)		$	(7)

Three Months Ended Sept. 30, 2019
Derivatives designated as cash flow hedges
Interest rate	$	1	(a)	$	—		$	—
Total	$	1		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	1	(b)
Electric commodity	—			(1)		(c)	—
Total	$	—		$	(1)		$	1

Nine Months Ended Sept. 30, 2019
Derivatives designated as cash flow hedges
Interest rate	$	3	(a)	$	—		$	—
Total	$	3		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	5	(b)

Natural gas commodity	—			(1)		(d)	(4)		(d)
Total	$	—		$	(1)		$	1

(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, 2020 and 2019 included no 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. Remaining settlement losses for both the three and nine months ended Sept. 30, 2020 and 2019 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.

Changes in Level 3 commodity derivatives:


	Three Months Ended Sept. 30
(Millions of Dollars)	2020		2019
Balance at July 1	$	34	$	28
Purchases	—		5
Settlements	(17)		(21)
Net transactions recorded during the period:
(Losses) gains recognized in earnings (a)	(25)		1
Net gains recognized as regulatory assets and liabilities	2		2
Balance at Sept. 30	$	(6)	$	15

	Nine Months Ended Sept. 30
(Millions of Dollars)	2020		2019
Balance at Jan. 1	$	4	$	29
Purchases	49		42
Settlements	(59)		(48)
Net transactions recorded during the period:
Losses recognized in earnings (a)	(11)		(9)
Net gains recognized as regulatory assets and liabilities	11		1
Balance at Sept. 30	$	(6)	$	15

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

Xcel Energy recognizes transfers between levels as of the beginning of each period. There were no transfers of amounts between levels for derivative instruments for the three and nine months ended Sept. 30, 2020 and 2019.

Fair Value of Long-Term Debt

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


	Sept. 30, 2020				Dec. 31, 2019
(Millions of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	20,361	$	24,396	$	18,109	$	20,227

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, 2020 and Dec. 31, 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
	2020		2019		2020		2019
(Millions of Dollars)	Pension Benefits				Postretirement Health Care Benefits
Service cost	$	24	$	22	$	—	$	—
Interest cost (a)	31		36		5		6
Expected return on plan assets (a)	(52)		(51)		(5)		(5)
Amortization of prior service credit (a)	(1)		(1)		(2)		(3)
Amortization of net loss (a)	25		22		1		1
Net periodic benefit cost (credit)	27		28		(1)		(1)
Effects of regulation	4		—		1		—
Net benefit cost (credit) recognized for financial reporting	$	31	$	28	$	—	$	(1)


	Nine Months Ended Sept. 30
	2020		2019		2020		2019
(Millions of Dollars)	Pension Benefits				Postretirement Health Care Benefits
Service cost	$	72	$	64	$	1	$	1
Interest cost (a)	94		108		14		17
Expected return on plan assets (a)	(156)		(152)		(15)		(16)
Amortization of prior service credit (a)	(3)		(3)		(6)		(8)
Amortization of net loss (a)	74		66		3		4
Net periodic benefit cost (credit)	81		83		(3)		(2)
Effects of regulation	7		2		2		1
Net benefit cost (credit) recognized for financial reporting	$	88	$	85	$	(1)	$	(1)

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

In January 2020, contributions of $150 million were made across four of Xcel Energy’s pension plans. Xcel Energy does not expect additional pension contributions during 2020.


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, 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 Inc. 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 Inc., between 2003 and 2009 alleging fraud and anticompetitive activities in conspiring to restrain the trade of natural gas and manipulate natural gas prices. Cases were all consolidated in the U.S. District Court in Nevada. Two cases remain active which include an MDL matter consisting of a Colorado purported class (Breckenridge) and a Wisconsin purported class (Arandell Corp.).

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

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

Rate Matters and Other

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

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

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

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

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

On April 28, 2020, the Minnesota Supreme Court denied the insurers’ petition for further review, ending the litigation. In accordance with a prior MPUC order, NSP-Minnesota made a compliance filing on Aug. 24, 2020 detailing all costs that resulted from the outage and all insurance recoveries received by NSP-Minnesota in connection with the outage. The MPUC has indicated it intends to review the prudence of the Company’s actions and costs in connection with the outage now that the ligation is complete. The MPUC has not specified what process it will use to complete that review.

Westmoreland Arbitration — In November 2014, insurers for Westmoreland Coal Company filed an arbitration demand against NSP-Minnesota, SMMPA and Western Fuels Association, seeking recovery of alleged business losses due to a turbine failure at Sherco Unit 3. The Westmoreland insurers claim NSP-Minnesota’s invocation of the force majeure clause of the applicable coal supply agreement to stop the supply of coal was improper because the incident was allegedly caused by NSP-Minnesota’s failure to conform to industry maintenance standards. Westmoreland’s insurers quantified their losses as approximately $36 million.

All parties tolled the arbitration pending resolution of a separate lawsuit brought by NSP-Minnesota, SMMPA, and their insurers against various GE entities based on the inspection and maintenance advice GE provided for Sherco Unit 3. In July 2020, the litigation has been resolved and notice of resolution was served, triggering the arbitration to resume. NSP-Minnesota denies the claims asserted by the Westmoreland insurers, believes it properly stopped the supply of coal based upon the force majeure provision in the coal supply agreement and intends to defend the matter. It is uncertain when a final resolution will occur, but it is unlikely an arbitration hearing will take place before 2021. At this early stage of the proceeding, before any discovery has been conducted, a reasonable estimate of damages or range of damages cannot be determined.

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

The first complaint argued for a reduction in the base ROE in MISO transmission formula rates from 12.38% to 9.15%, and removal of ROE adders (including those for RTO membership). The second complaint sought to reduce base ROE from 12.38% to 8.67%. In September 2016, the FERC issued an order granting a 10.32% base ROE (10.82% with the RTO adder) effective for the first complaint period of Nov. 12, 2013 to Feb. 11, 2015 and subsequent to the date of the order. The D.C. Circuit subsequently vacated and remanded FERC Opinion No. 531, which had established the ROE methodology on which the September 2016 FERC order was based.

In November 2019, the FERC issued Opinion No. 569 adopting a new ROE methodology and settling the MISO base ROE at 9.88% (10.38% with the RTO adder), effective Sept. 28, 2016 and for the refund period in the first complaint. The second complaint was also dismissed. In December 2019, MISO TOs filed a request for rehearing. Customers also filed requests for rehearing, claiming among other points, that the FERC erred by dismissing the second complaint without refunds.

The FERC accepted the requests for rehearing in January 2020.

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.

In May 2020, the FERC issued Opinion No. 569-A, which granted rehearing in part to Opinion 569 and further refined the FERC’s ROE methodology, most significantly to incorporate the risk premium model (in addition to the discounted cash flow and capital asset pricing models), resulting in a new base ROE of 10.02%, effective Sept. 28, 2016 and for the refund period in the first complaint. The FERC also affirmed its decision in Opinion 569 to dismiss the second complaint.

The May 2020 FERC opinion remains subject to pending requests for rehearing, as well as the pending judicial review, NSP-Minnesota has recognized a liability for its best estimate of final refunds to customers.

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 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. Any refunds received by SPS are expected to be given back to SPS customers through future rates.

In October 2017, SPS filed a separate related complaint against SPP asserting that SPP has assessed upgrade charges to SPS in violation of the SPP OATT. In March 2018, the FERC issued an order denying the SPS complaint in its entirety, and finding SPP’s calculations to be consistent with the SPS Tariff. SPS filed a request for rehearing in April 2018. The FERC issued a tolling order granting a rehearing for further consideration in May 2018. If SPS’ complaint results in additional charges or refunds, SPS will seek to recover or refund the amounts through future SPS customer rates.

MEC Transactions — In January 2020, Xcel Energy, Inc. purchased MEC, a 760 MW natural gas combined cycle facility, for approximately $650 million from Southern Power Company.

In July 2020, Xcel Energy sold MEC to Southwest Generation for $684 million. The gain on sale of approximately $20 million, which was offset by charitable giving, including COVID-19 relief efforts, had no material impact on earnings in the third quarter of 2020.

SPS — Contract Termination — SPS and Lubbock Power & Light are parties to a 25-year, 170 MW partial requirements contract. Lubbock Power & Light has initiated discussions with SPS concerning the interpretation of contractual terms related to early termination and default. If the parties are unable to reach resolution, the contract calls for the matter to proceed to arbitration.

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 were completed in 2020. Groundwater treatment activities will continue for many years.

The cost estimate for remediation and restoration of the entire site is approximately $199 million. At Sept. 30, 2020 and Dec. 31, 2019, NSP-Wisconsin had a total liability of $20 million and $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 and application of a 3% carrying charge to the regulatory asset.

In addition to the Ashland Site, Xcel Energy is currently investigating, remediating or performing post-closure actions at 13 other MGP, landfill or other disposal sites across its service territories.

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

Environmental Requirements — Water and Waste

Coal Ash Regulation — Xcel Energy’s operations are subject to federal and state 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. Currently, Xcel Energy has nine regulated ash units in operation.

Xcel Energy is conducting groundwater sampling and, where appropriate, implementing assessment of corrective measures at certain CCR landfills and surface impoundments. Groundwater monitoring consistent with the CCR Rule continued in 2020. In NSP-Minnesota, no results above the groundwater protection standards in the rule were identified. In PSCo, statistically significant increases above background concentrations were detected at four locations. Subsequently, assessment monitoring samples were collected at these locations and, based on the results, PSCo is evaluating options for corrective action at two locations. At one location, monitoring results indicate potential offsite impacts to groundwater. Until PSCo completes its assessment, it is uncertain what impact, if any, there will be on the operations, financial condition or cash flows.

On Aug. 28, 2020, the EPA published its final rule to implement a cease receipt and initiate a closure date of April 11, 2021 for all CCR impoundments affected by an August 2018 D.C. Circuit ruling. The D.C. Circuit concluded that the EPA cannot allow utilities to continue to use unlined impoundments (including clay lined impoundments) for the storage or disposal of coal ash. This final rule requires NSP-Minnesota to expedite closure plans for one impoundment at an estimated cost of $4 million and the construction of a new impoundment at the cost of $9 million. NSP-Minnesota completed construction of this new impoundment, an ash pond, and placed it in service on Oct. 5, 2020. With the new ash pond in service, NSP-Minnesota is required to initiate closure activities for the existing ash pond. In accordance with the CCR rule, NSP-Minnesota has five years to complete closure activities, and the facility’s National Pollutant Discharge Elimination System permit will be initiated.

PSCo is pursuing options to provide alternative storage capacity consistent with the CCR Rule at one facility until the affected generating units are retired in 2025.

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

VIEs

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

The utility subsidiaries had approximately 4,062 MW and 3,986 MW of capacity under long-term PPAs at Sept. 30, 2020 and Dec. 31, 2019, respectively, with entities that have been determined to be VIEs. Xcel Energy concluded that these entities are not required to be consolidated in its consolidated financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance. The PPAs have expiration dates through 2041.

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 and the operations of MEC until July 2020.

Xcel Energy had equity investments in unconsolidated subsidiaries of $160 million and $155 million as of Sept. 30, 2020 and Dec. 31, 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:


	Three Months Ended Sept. 30
(Millions of Dollars)	2020		2019
Regulated Electric
Operating revenues from external customers	$	2,941	$	2,771
Intersegment revenue	1		—
Total revenues	$	2,942	$	2,771
Net income	632		550
Regulated Natural Gas
Operating revenues from external customers	$	219	$	222
Net income (loss)	—		(1)
All Other
Total operating revenue	$	22	$	20
Net loss	(29)		(22)
Consolidated Total
Total revenue	$	3,183	$	3,013
Reconciling eliminations	(1)		—
Total operating revenues	$	3,182	$	3,013
Net income	603		527


	Nine Months Ended Sept. 30
(Millions of Dollars)	2020		2019
Regulated Electric
Operating revenues from external customers	$	7,430	$	7,345
Intersegment revenue	1		1
Total revenues	$	7,431	$	7,346
Net income	1,148		1,032
Regulated Natural Gas
Operating revenues from external customers	$	1,082	$	1,324
Intersegment revenue	1		1
Total revenues	$	1,083	$	1,325
Net income	111		127
All Other
Total operating revenue	$	67	$	62
Net loss	(74)		(79)
Consolidated Total
Total revenue	$	8,581	$	8,733
Reconciling eliminations	(2)		(2)
Total operating revenues	$	8,579	$	8,731
Net income	1,185		1,080

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.

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, 2020 and 2019, 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.

All companies were negatively impacted by the pandemic starting in March 2020 and continuing into the third quarter. See COVID-19 section below for further information, including estimated impact on weather-adjusted electric sales.

Summarized diluted EPS for Xcel Energy:


	Three Months Ended Sept. 30				Nine Months Ended Sept. 30
Diluted Earnings (Loss) Per Share	2020		2019		2020		2019
NSP-Minnesota	$	0.46	$	0.40	$	0.89	$	0.81
PSCo	0.42		0.39		0.87		0.86
SPS	0.24		0.20		0.46		0.42
NSP-Wisconsin	0.08		0.06		0.16		0.12
Equity earnings of unconsolidated subsidiaries	0.01		0.01		0.04		0.04
Regulated utility (a)	1.21		1.06		2.42		2.24
Xcel Energy Inc. and Other	(0.07)		(0.05)		(0.17)		(0.16)
Total (a)	$	1.14	$	1.01	$	2.25	$	2.08

(a) Amounts may not add due to rounding.

Summary of Earnings

Xcel Energy — Xcel Energy’s earnings increased $0.13 per share for the third quarter of 2020 and $0.17 per share year-to-date. Earnings primarily reflect higher electric margin (largely due to capital investment recovery) and AFUDC, which offset increased depreciation and declining sales due to the impacts of COVID-19.

NSP-Minnesota — Earnings increased $0.06 per share for the third quarter of 2020 and $0.08 per share year-to-date. Year-to-date results reflect lower O&M expenses and higher electric margin (regulatory outcomes offset lower sales primarily due to COVID-19), partially offset by increased depreciation and lower natural gas margin.

PSCo — Earnings increased $0.03 per share for the third quarter of 2020 and $0.01 per share year-to date. The increase in year-to-date earnings was driven by higher electric margin (regulatory outcomes offset lower sales due to COVID-19), increased AFUDC and reduced O&M expenses, partially offset by higher depreciation, interest expense and taxes (other than income taxes).

SPS — Earnings increased $0.04 per share for the third quarter of 2020 and $0.04 per share year-to-date. Year-to-date results reflect higher electric margin (regulatory outcomes offset lower sales due to COVID-19) and lower O&M expenses, partially offset by increased depreciation, interest expense and taxes (other than income taxes).

NSP-Wisconsin — Earnings increased $0.02 per share for the third quarter of 2020 and $0.04 per share year-to-date. The increase in year-to-date earnings was driven by higher electric margin (2020 Wisconsin Fuel Settlement offset lower sales due to COVID-19) and AFUDC, as well as lower O&M expenses. These items were partially offset by increased depreciation and lower natural gas margin.

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

Changes in GAAP and Ongoing Diluted EPS

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


Diluted Earnings (Loss) Per Share	Three Months Ended Sept. 30		Nine Months Ended Sept. 30
GAAP and ongoing diluted EPS - 2019	$	1.01	$	2.08

Components of change - 2020 vs. 2019
Higher electric margin (a)	0.20		0.22
Lower ETR (b)	0.07		0.17
Lower O&M	—		0.08
Higher AFUDC	0.03		0.07
Higher depreciation and amortization	(0.09)		(0.19)
Higher interest charges	(0.03)		(0.07)
Lower natural gas margins	—		(0.03)
Lower other income (expense), net	(0.01)		(0.03)
Other (net)	(0.04)		(0.05)
GAAP and ongoing diluted EPS - 2020	$	1.14	$	2.25

(a) Period-over-period change in electric margin was negatively impacted by reductions in sales and demand due to COVID-19 as follows:


Diluted Earnings (Loss) Per Share	Three Months Ended Sept. 30		Nine Months Ended Sept. 30
Electric margin (excluding reductions in sales and demand)	$	0.21	$	0.30
Reductions in sales and demand (*)	(0.01)		(0.08)
Higher electric margins	$	0.20	$	0.22

(*) Sales decline excludes weather impact, net of decoupling/sales true-up and decrease in demand revenue is net of sales true-up.

(b) Includes PTCs and tax reform regulatory amounts, which are primarily offset in electric margin.

Statement of Income Analysis

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

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

Degree-day or THI data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day’s average temperature and humidity. HDD is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit. CDD is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65° Fahrenheit.

Each degree of temperature above 65° Fahrenheit is counted as one CDD, and each degree of temperature below 65° Fahrenheit is counted as one HDD. In Xcel Energy’s more humid service territories, a THI is used in place of CDD, which adds a humidity factor to CDD. HDD, CDD and THI are most likely to impact the usage of Xcel Energy’s residential and commercial customers. Industrial customers are less sensitive to weather.

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

Percentage increase (decrease) in normal and actual HDD, CDD and THI:


	Three Months Ended Sept. 30						Nine Months Ended Sept. 30
	2020 vs. Normal		2019 vs. Normal		2020 vs. 2019		2020 vs. Normal		2019 vs. Normal		2020 vs. 2019
HDD	48.4	%	(64.0)	%	251.2	%	(2.8)	%	10.7	%	(11.2)	%
CDD	20.7		27.4		1.3		21.2		6.4		21.3
THI	4.6		(2.6)		8.3		7.0		(8.2)		18.3

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


	Three Months Ended Sept. 30						Nine Months Ended Sept. 30
	2020 vs. Normal		2019 vs. Normal		2020 vs. 2019		2020 vs. Normal		2019 vs. Normal		2020 vs. 2019
Retail electric	$	0.079	$	0.040	$	0.039	$	0.096	$	0.035	$	0.061
Decoupling and sales true-up	(0.035)		—		(0.035)		(0.044)		0.001		(0.045)
Electric total	$	0.044	$	0.040	$	0.004	$	0.052	$	0.036	$	0.016
Firm natural gas	—		(0.001)		0.001		(0.005)		0.021		(0.026)
Total	$	0.044	$	0.039	$	0.005	$	0.047	$	0.057	$	(0.010)

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


	Three Months Ended Sept. 30
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Actual (a)
Electric residential	8.7	%	11.8	%	4.4	%	6.6	%	9.1	%
Electric C&I	(4.5)		(5.2)		(5.5)		(4.1)		(5.0)
Total retail electric sales	(0.1)		0.1		(3.5)		(1.2)		(0.9)
Firm natural gas sales	1.1		2.1		N/A		11.2		2.0


	Three Months Ended Sept. 30
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Weather-Normalized (a)
Electric residential	3.8	%	4.3	%	2.2	%	2.0	%	3.7	%
Electric C&I	(4.2)		(5.3)		(5.0)		(4.6)		(4.8)
Total retail electric sales	(1.6)		(2.3)		(3.5)		(2.7)		(2.4)
Firm natural gas sales	(4.8)		(1.8)		N/A		6.6		(3.3)


	Nine Months Ended Sept. 30
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Actual (a)
Electric residential	6.9	%	5.6	%	5.0	%	2.9	%	5.8	%
Electric C&I	(4.2)		(7.3)		(3.4)		(5.6)		(5.2)
Total retail electric sales	(0.7)		(3.4)		(2.0)		(3.2)		(2.2)
Firm natural gas sales	(7.3)		(9.3)		N/A		(9.9)		(8.1)


	Nine Months Ended Sept. 30
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Weather-Normalized (a)
Electric residential	3.5	%	3.3	%	2.0	%	2.7	%	3.2	%
Electric C&I	(4.7)		(7.5)		(3.5)		(5.8)		(5.5)
Total retail electric sales	(2.1)		(4.2)		(2.6)		(3.4)		(3.1)
Firm natural gas sales	(1.7)		2.2		N/A		3.6		(0.2)


	Nine Months Ended Sept. 30 (Leap Year Adjusted)
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Weather-Normalized (a)
Electric residential	3.2	%	3.0	%	1.6	%	2.3	%	2.8	%
Electric C&I	(5.1)		(7.8)		(3.9)		(6.2)		(5.8)
Total retail electric sales	(2.5)		(4.6)		(3.0)		(3.8)		(3.5)
Firm natural gas sales	(2.5)		1.4		N/A		2.8		(1.0)

(a) Higher residential sales and lower C&I sales were primarily attributable to COVID-19.

Weather-normalized and leap-year adjusted electric sales growth (decline) — year-to-date (excluding leap day)

•PSCo — Residential sales rose based on higher use per customer from increased working from home and an increased number of customers. The decline in C&I sales was primarily due to the economic contraction from COVID-19, particularly noted within the manufacturing and service industries.

•NSP-Minnesota — Residential sales growth reflects higher use per customer from increased working from home and an increase in customers. Decrease in C&I sales were driven by the energy, manufacturing and services sectors, primarily related to COVID-19.

•SPS — Residential sales increased due to customer growth and higher use per customer from increased working from home. The decline in C&I sales was driven by shutdowns of the economy from COVID-19, primarily within the energy and manufacturing sectors.

•NSP-Wisconsin — Residential sales growth was attributable to higher use per customer from increased working from home and customer additions. The decline in C&I sales was largely related to COVID-19, specifically decreased sales to the manufacturing sector.

Weather-normalized and leap-year adjusted natural gas sales growth (decline) — year-to-date (excluding leap day)

•Natural gas sales reflect primarily lower C&I customer use due to the economic contraction from COVID-19, partially offset by an increase in number of residential and C&I customers.

Electric Margin

Electric revenues and fuel and purchased power expenses are impacted by fluctuations in the price of natural gas, coal and uranium. However, these 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, which reduced electric revenue and margin.

Electric revenues and margin:


	Three Months Ended Sept. 30				Nine Months Ended Sept. 30
(Millions of Dollars)	2020		2019		2020		2019
Electric revenues	$	2,941	$	2,771	$	7,430	$	7,345
Electric fuel and purchased power	(981)		(952)		(2,611)		(2,679)
Electric margin	$	1,960	$	1,819	$	4,819	$	4,666

Changes in electric margin:


(Millions of Dollars)	Three Months Ended Sept. 30, 2020 vs. 2019		Nine Months Ended Sept. 30, 2020 vs. 2019
Regulatory rate outcomes (Colorado, Wisconsin, Texas and New Mexico) (a)	$	123	$	158
Non-fuel riders	19		43
Wholesale transmission revenue (net)	10		35
MEC purchased capacity costs (b)	4		35
Estimated impact of weather (net of decoupling/sales true-up)	4		12
PTCs flowed back to customers (offset by lower ETR)	(28)		(81)
Sales and demand (c)	(9)		(56)

Other (net)	18		7
Total increase in electric margin	$	141	$	153

(a) Includes approximately $70 million of revenue and margin due to the Texas rate case outcome, which is largely offset by recognition of previously deferred costs, see Public Utility Regulation below for additional information.

(b) Prior to the MEC acquisition (first quarter of 2020), all purchased power costs were recorded as a component of electric fuel and purchased power. During Xcel Energy’s ownership of MEC, all non-fuel related costs including depreciation, O&M and interest expenses were recorded within separate statement of income line items in our consolidated financial results. MEC was sold in the third quarter of 2020.

(c) Sales increase (decline) excludes weather impact, net of decoupling/sales true-up, and decrease in demand revenue is net of sales true-up.

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
(Millions of Dollars)	2020		2019		2020		2019
Natural gas revenues	$	219	$	222	$	1,082	$	1,324
Cost of natural gas sold and transported	(54)		(55)		(425)		(646)
Natural gas margin	$	165	$	167	$	657	$	678

Changes in natural gas margin:


(Millions of Dollars)	Three Months Ended Sept. 30, 2020 vs. 2019		Nine Months Ended Sept. 30, 2020 vs. 2019
Estimated impact of weather	$	1	$	(18)
Retail sales decline	(1)		(2)

Regulatory rate outcomes (Wisconsin)	—		(2)
Transport sales	1		(1)
Infrastructure and integrity riders	1		6

Other (net)	(4)		(4)
Total decrease in natural gas margin	$	(2)	$	(21)

Non-Fuel Operating Expenses and Other Items

O&M Expenses — O&M expenses decreased $1 million, or 0.2%, for the third quarter and $56 million, or 3.2%, year-to-date, largely reflecting management actions to reduce costs to offset the impact of lower sales from COVID-19. Significant changes are summarized as follows:


(Millions of Dollars)	Three Months Ended Sept. 30, 2020 vs. 2019		Nine Months Ended Sept. 30, 2020 vs. 2019
Distribution	$	(10)	$	(40)
Transmission	(4)		(10)

Generation	(3)		(8)
Texas rate case deferral	13		5
Other (net)	3		(3)
Total decrease in O&M expenses	$	(1)	$	(56)

•Distribution declined due to cost mitigation/continuous improvement efforts and the timing of maintenance activities;

•Transmission declined due to cost mitigation/continuous improvement initiatives.

•Generation was lower from timing of maintenance and overhauls at power plants and cost mitigation/continuous improvement efforts, which were partially offset by an increase in wind related O&M expenses from our renewable expansion.

•Texas rate case deferral amounts were due to recognition of previously deferred amounts related with the Texas Electric Rate Case.

•Included within Other (net) are amounts associated with the sale of MEC. During the third quarter of 2020, Xcel Energy recognized a net gain of approximately $20 million on the sale, which was offset by charitable giving, including COVID-19 relief efforts.

Depreciation and Amortization — Depreciation and amortization increased $66 million, or 14.8%, for the third quarter and $130 million, or 9.9%, year-to-date. Increase was primarily driven by Hale, Lake Benton, Foxtail, Blazing Star I and Cheyenne Ridge wind facilities going into service, as well as normal system expansion. In addition, new depreciation rates were implemented in Colorado, New Mexico and Texas as part of regulatory outcomes in 2020.

Other Income (Expense) — Other income (expense) decreased $7 million for the third quarter and $20 million year-to-date. The decrease was substantially due to the performance of rabbi trust investments primarily in the first half of 2020, which was offset in O&M expenses.

AFUDC, Equity and Debt — AFUDC increased $19 million for the third quarter and $42 million year-to-date. Increase was primarily due to various wind projects under construction.

Interest Charges — Interest charges increased $22 million, or 11.1%, for the third quarter and $50 million, or 8.7% year-to-date. The increase was largely due to higher debt levels to fund capital investments, partially offset by lower long-term and short-term interest rates.

Income Taxes — Income taxes decreased $29 million for the third quarter. The decrease was primarily driven by an increase in wind PTCs, an increase in plant regulatory differences and a carryback tax benefit, partially offset by higher pretax 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 6.7% for the third quarter of 2020 compared with 12.0% for 2019.

Income taxes decreased $97 million year-to-date. The decrease was primarily driven by an increase in wind PTCs and an increase in plant-related regulatory differences. Wind PTCs are credited to customers and do not have a material impact on net income. The ETR was 2.0% for the first nine months ending Sept. 30, 2020 compared with 10.1% for 2019.


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.

Except to the extent noted below, the circumstances set forth in Public Utility Regulation included in Item 7 of Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2019 and in Item 2 of Xcel Energy’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2020 and Fo rm 10-Q for the quarterly period ended June 30, 2020 appropriately represent, in all material respects, the current status of public utility regulation and are incorporated by reference.

NSP-Minnesota

Pending and Recently Concluded Regulatory Proceedings

Proceeding

Amount
(in millions)

Filing
Date

Approval

2020 Electric Rate Case

TBD

November 2020

Pending Filing

2020 TCR Electric Rider

$82

November 2019

Pending

2020 GUIC Electric Rider

$21

November 2019

Pending

2020 RES Electric Rider

$102

November 2019

Pending

Additional Information:

2020 Electric Rate Case — NSP-Minnesota plans to file an electric rate case in November 2020, including a stay-out alternative.

TCR Electric Rider — In November 2019, NSP-Minnesota filed the TCR Rider. The filing included an ROE of 9.06%. Timing of an MPUC ruling is uncertain.

GUIC Electric Rider — In November 2019, NSP-Minnesota filed the GUIC Rider with the MPUC. The filing included an ROE of 9.04%. Timing of an MPUC ruling is uncertain.

RES Electric Rider — In November 2019, NSP-Minnesota filed the 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.

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.

In June 2020, NSP-Minnesota filed a supplement to its resource plan, including new modeling scenarios required by the MPUC. The updated preferred resource plan reflects the following:

•Retirement of all coal generation by 2030 with reduced operations at some units prior to retirement, including early retirement of the King coal plant (511 MW) in 2028 and the Sherco 3 coal plant (517 MW) in 2030;

•Extending the life of the Monticello nuclear plant from 2030 to 2040;

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

•Construction of the Sherco combined cycle natural gas plant;

•The addition of 3,500 MW of solar;

•The addition of 2,250 MW of wind;

•2,600 MW of firm peaking (combustion turbine, pumped hydro, battery storage, demand response, etc.);

•Achieving 780 GWh in energy efficiency savings annually through 2034; and

•Adding 400 MW of incremental demand response by 2023, and a total of 1,500 MW of demand response by 2034.

Initial comments are due Jan. 15, 2021 and reply comments are due March 15, 2021. The MPUC is anticipated to make a final decision during 2021.

Minnesota Relief and Recovery — In 2020, the MPUC opened a docket and invited utilities in the state to submit potential projects that would create jobs and help jump start the economy to offset the impacts of COVID-19. NSP-Minnesota’s filing included the following components:

•In September 2020, NSP-Minnesota proposed to accelerate approximately $865 million of grid investment and sought approval for approximately $150 million of incremental electric vehicle rebates;

•In September 2020, NSP-Minnesota proposed to repower 651 MW of owned wind projects with a capital investment of approximately $750 million. In addition, developers proposed repowering 67 MW of wind projects under power purchase agreements (PPAs). NSP-Minnesota estimates over $160 million in customers savings over the life of the projects. NSP-Minnesota has requested a decision from the MPUC by year-end.

•In the first quarter of 2021, NSP-Minnesota plans to propose solar facilities of approximately 460MW with an incremental investment of approximately $650 million. NSP-Minnesota anticipates a MPUC decision in the second or third quarter of 2021.

Minnesota State ROFR Statute Complaint — In September 2017, LSP Transmission filed a complaint in the Minnesota District Court against the Minnesota Attorney General, MPUC and DOC. The complaint was in response to MISO assigning NSP-Minnesota and ITC Midwest, LLC to jointly own a new 345 kilovolt transmission line from Mankato to Winnebago, Minnesota. The project is estimated to cost $140 million and projected to be in-service by the end of 2021. It was assigned to NSP-Minnesota and ITC Midwest as the incumbent utilities, consistent with a Minnesota state ROFR statute.

The complaint challenged the constitutionality of the statute and is seeking declaratory judgment that the statute violates the Commerce Clause of the U.S. Constitution and should not be enforced. In June 2018, the Minnesota District Court granted Minnesota state agencies and NSP-Minnesota’s motions to dismiss with prejudice. LSP Transmission filed an appeal in July 2018. In February 2020, the Eighth Circuit Court of Appeals upheld the Minnesota District Court decision to dismiss. In June 2020, the Eighth Circuit denied LSP Transmission’s petition for rehearing. LSP Transmission has until Nov. 5, 2020 to seek further review of this appeal with the U.S. Supreme Court.

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, 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, 2019, appropriately represent, in all material respects, the current status of nuclear power operations, and are incorporated by reference.

NSP-Wisconsin

2019 Electric Fuel Cost Recovery — NSP-Wisconsin’s electric fuel costs for 2019 were lower than authorized in rates and outside the 2% annual tolerance band. Under the fuel cost recovery rules, NSP-Wisconsin may retain approximately $3 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 August 2020, the PSCW approved NSP-Wisconsin’s request to refund over-collections of approximately $10 million to customers.

2021 Electric Fuel Cost Recovery — In June 2020, NSP-Wisconsin filed an application with the PSCW to update its 2021 fuel costs and return biomass fuel savings, which would decrease retail electric rates for 2021 by approximately $12 million. NSP-Wisconsin expects a PSCW decision on the application in the fourth quarter of 2020.

NSP-Wisconsin Solar Proposal — In October 2020, NSP-Wisconsin filed for a 74 MW solar facility build-own-transfer in Wisconsin for approximately $100 million. A PSCW decision is expected in the third quarter of 2021.

PSCo

Pending and Recently Concluded Regulatory Proceedings

Proceeding

Amount
(in millions)

Filing
Date

Approval

2020 Natural Gas Rate Case

$127

February 2020

Received

2019 Electric Rate Case

$158

May 2019

Received

2019 Natural Gas Rate Case Appeal

N/A

April 2019

Pending

Wildfire Protection Rider

$325

July 2020

Pending

Advanced Grid Rider

$850

July 2020

Pending

Additional Information:

2020 Natural Gas Rate Case — In October 2020, the CPUC accepted a recommended decision by the ALJ to approve a comprehensive settlement without modification between PSCo, the CPUC Staff and various intervenors. The rate outcome results in a net increase to retail gas rates of $77 million, reflecting a $94 million increase in base rate revenue, partially offset by $17 million of costs previously authorized through the Pipeline Integrity rider. Rates will be implemented on April 1, 2021 and will be retroactively effective back to November 2020. The settlement is based on:

•A ROE of 9.20%;

•An equity ratio of 55.62%; and

•A historic test year as of Sept. 30, 2019, utilizing a year-end rate base, and incorporating a known and measurable adjustment for the Tungsten to Black Hawk pipeline.

2019 Electric Rate Case — 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, implementation of decoupling in 2020 and other items.

In May 2020, the CPUC deliberated on PSCo’s request for rehearing and revised its prior decision on the test year calculation, return on prepaid pension and medical assets, a disallowance of a capital investment for the Comanche Unit 3 superheater and Board compensation. In July 2020, the CPUC’s written decision was received. As a result, electric rates will increase approximately $12 million. In October 2020, the CPUC initiated a non-adjudicatory review of Comanche Unit 3’s performance to be handled by the CPUC Staff, consistent with what was signaled during the 2019 Electric Rate Case rehearing. A report is expected to be issued in the first half of 2021.

2019 Natural Gas Rate Case Appeal — In April 2019, PSCo filed an appeal seeking judicial review of the CPUC’s prior ruling regarding PSCo’s 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.

PSCo 2020 Rider Filings

In July 2020, PSCo filed rider requests with the CPUC instead of filing a comprehensive electric rate case in 2020.

Wildfire Protection Rider — Seeks to establish a rider to recover incremental costs associated with system investments to reduce wildfire risk. In August 2020, the CPUC referred it to an ALJ.

Procedural schedule:

•Answer testimony Nov. 20, 2020;

•Rebuttal testimony Dec. 18, 2020;

•Settlement by Jan. 8, 2021;

•Hearing Jan. 14, 2021 - Jan. 15, 2021; and

•Statutory deadline March 24, 2021.

The rider is expected to be effective in June 2021 and continue through 2025. Wildfire Protection capital investment is projected to be approximately $325 million. Forecasted annual revenue requirements from 2021 through 2025 are as follows:


(Millions of Dollars)	2021		2022		2023		2024		2025
Forecasted annual revenue requirement	$	17	$	24	$	29	$	32	$	34

Advanced Grid Rider — Seeks to establish a rider to recover incremental costs associated with the AGIS initiative. In August 2020, the CPUC referred the matter to an ALJ. In September 2020, the Office of Consumer Counsel filed a motion to dismiss the Advanced Grid Rider.

Procedural schedule:

•Answer testimony Dec. 9, 2020;

•Rebuttal Jan. 8, 2021;

•Settlement by Jan. 20, 2021;

•Hearing Jan. 25, 2021 - Jan 28, 2021; and

•Statutory deadline April 24, 2021.

The rider is expected to be effective in May 2021 and continue through 2025. The PSCo portion of the AGIS capital investment is projected to be approximately $850 million. Forecasted annual revenue requirements from 2021 through 2025 are as follows:


(Millions of Dollars)	2021		2022		2023		2024		2025
Forecasted annual revenue requirement	$	53	$	69	$	83	$	89	$	99

PSCo KEPCO Filing — In September 2020, PSCo filed with the CPUC for approval to terminate a solar PPA with KEPCO Solar of Alamosa, Inc. and establish a regulatory asset to recover transaction costs of approximately $41 million. By terminating the PPA, customers would save approximately $38 million over an 11-year period. A CPUC decision is expected in the second quarter of 2021.

PSCo — Comanche Unit 3

PSCo is part owner of Comanche Unit 3, a 750 MW, coal-fueled electric generating unit. PSCo is the operating agent under the joint ownership agreement. In June 2020, the unit experienced loss of turbine oil during start-up which damaged the plant. It is currently anticipated that Comanche Unit 3 will recommence operations in the fourth quarter of 2020. Replacement and repair of damaged systems in excess of a $2 million deductible are expected to be recovered through insurance policies. PSCo has obtained replacement power for a portion of the unit’s output through PPAs. In October 2020, the CPUC initiated a non-adjudicatory review of Comanche Unit 3’s performance to be handled by the CPUC Staff, consistent with what was signaled during the 2019 Electric Rate Case rehearing. A report is expected to be issued in the first half of 2021.

Boulder Municipalization

In 2011, Boulder passed a ballot measure authorizing the formation of an electric municipal utility, subject to certain conditions. Subsequently, there have been various legal proceedings in multiple venues.

In September 2020, the City Council voted to approve a settlement between PSCo and Boulder officials to end the city’s municipalization effort. The settlement would result in a 20-year franchise arrangement (with multiple opt-out conditions), an energy partnership and an undergrounding agreement. It also established the municipalization process if Boulder exercised an opt-out. The citizens of Boulder will vote on Nov. 3, 2020, whether to approve or deny the franchise agreement.

PSCo — Natural Gas LDC and Emission Reductions — In October 2020, the CPUC opened a docket to investigate topics related to natural gas emissions in relation to statewide emission reduction goals.

The first meeting will be scheduled in the fourth quarter of 2020, in which subject matter experts will discuss greenhouse emission reductions required from the natural gas industry in regard to the statewide goals.

SPS

Pending and Recently Concluded Regulatory Proceedings

Proceeding

Amount
(in millions)

Filing
Date

Approval

2019 Texas Electric Rate Case

$88

August 2019

Received

2020 New Mexico Electric Rate Case

TBD

January 2021

Pending Filing

2020 Texas Electric Rate Case

TBD

February 2021

Pending Filing

Additional Information:

2019 Texas Electric Rate Case — In August 2020, the PUCT approved a settlement between SPS and intervening parties, which reflects the following terms, retroactive to Sept. 12, 2019:

•An electric rate increase of $88 million;

•ROE of 9.45% and equity ratio of 54.62% for AFUDC purposes;

•Acceleration of the depreciation life of the Tolk coal plant; and

•Ring-fencing measures, similar to other Texas utilities.

SPS expects to submit a filing in the fourth quarter of 2020 to surcharge the final under-recovered amount, which is estimated to be approximately $70 million, offset by the recognition of previously deferred costs. The impact of the retroactive amounts (related to period prior to Sept. 1, 2020) is as follows:


(Millions of Dollars)	Nine Months Ended Sept. 30, 2020
Revenue surcharge accrual	$	70
Depreciation and amortization	(37)
O&M expense	(15)
Interest expense	(11)
Taxes other than income taxes	(7)

2020 Electric Rate Cases — In the first quarter of 2021, SPS intends to file electric rate cases for both the Texas and New Mexico jurisdictions due to the settlement reached for the Hale and Sagamore wind farms.

Texas State ROFR Litigation — In May 2019, the Governor signed into law a ROFR Bill, which grants incumbent utilities a ROFR to build transmission infrastructure when it directly interconnects to the utility’s existing facility. In June 2019, a complaint was filed in the United States District Court for the Western District of Texas claiming the new ROFR law to be unconstitutional. In February 2020, the federal court complaint was dismissed by the district court. In March 2020, the district court ruling was appealed to the United States Court of Appeals for the Fifth Circuit. The parties are awaiting a decision.

Texas Fuel 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.

In August 2020, the PUCT approved SPS’ request to refund approximately $39 million to customers for over-collected fuel and purchased power costs.

New Mexico FPPCAC Continuation — In October 2019, SPS filed an application to the NMPRC to approve SPS’ continued use of its FPPCAC and for reconciliation of fuel costs for the period Sept. 1, 2015, through June 30, 2019, which will determine whether all fuel costs incurred are eligible for recovery. SPS also proposed that it annually review its average New Mexico Deferred Fuel and Purchased Power balance and requests the NMPRC approve an Annual Deferred Fuel Balance True-Up. The proposed true-up is designed to maintain the Deferred Fuel and Purchased Power balance within a bandwidth of plus or minus 5% of annual New Mexico fuel and purchased power costs. A decision is pending.

Environmental

Environmental Regulation

In July 2019, the EPA adopted the Affordable Clean Energy rule, which requires states to develop plans for greenhouse gas reductions from coal-fired power plants. The state plans, due to the EPA in July 2022, will evaluate and potentially require heat rate improvements at existing coal-fired plants. It is not yet known how these state plans will affect our existing coal plants, but they could require substantial additional investment, even in plants slated for retirement. Xcel Energy believes, based on prior state commission practice, the cost of these initiatives or replacement generation would be recoverable through rates.

On Oct. 21, 2020, the Texas Commission on Environmental Quality approved the Harrington Station Power Plant agreement, which ensures SPS will cease coal-fired operations and convert the plant to natural gas by Jan. 1, 2025. This conversion is necessary to attain Federal Clean Air Act standards for emissions of sulfur dioxide.


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, management takes steps to mitigate changes in credit and concentration risks associated with its derivatives and other contracts, including parental guarantees and requests of collateral. While we expect that the counterparties will perform under the contracts underlying its derivatives, the contracts expose us to some credit and non-performance risk.

Distress in the financial markets may impact counterparty risk, the fair value of the securities in the nuclear decommissioning fund and pension fund and Xcel Energy’s ability to earn a return on short-term investments.

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

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

Fair value of net commodity trading contracts as of Sept. 30, 2020:


	Futures / Forwards Maturity
(Millions of Dollars)	Less Than 1 Year		1 to 3 Years		4 to 5 Years		Greater Than 5 Years		Total Fair Value
NSP-Minnesota (a)	$	(4)	$	(1)	$	2	$	3	$	—
NSP- Minnesota (b)	2		(1)		(2)		(6)		(7)
PSCo (a)	—		1		—		—		1
PSCo (b)	(14)		(31)		(19)		—		(64)
	$	(16)	$	(32)	$	(19)	$	(3)	$	(70)


	Options Maturity
(Millions of Dollars)	Less Than 1 Year		1 to 3 Years		4 to 5 Years		Greater Than 5 Years		Total Fair Value
NSP-Minnesota (b)	$	1	$	—	$	—	$	1	$	2
PSCo (b)	5		4		1		—		10
	$	6	$	4	$	1	$	1	$	12

(a) Prices actively quoted or based on actively quoted prices.

(b) Prices based on models and other valuation methods.

Changes in the fair value of commodity trading contracts before the impacts of margin-sharing for the nine months ended Sept. 30:


(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	(9)		(13)
Commodity trading contract additions and changes during the period	10		(61)
Fair value of commodity trading net contract (liabilities) assets outstanding at Sept. 30	$	(58)	$	(57)

At Sept. 30, 2020, a 10% increase in market prices for commodity trading contracts through the forward curve would increase pre-tax income from continuing operations by approximately $14 million, whereas a 10% decrease would decrease pre-tax income from continuing operations by approximately $14 million. Market price movements can exceed 10% under abnormal circumstances. 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.

The utility subsidiaries’ commodity trading operations measure the outstanding risk exposure to price changes on contracts and obligations that have been entered into, but not closed, using an industry standard methodology known as VaR. VaR expresses the potential change in fair value on the outstanding contracts and obligations over a particular period of time under normal market conditions.

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
2020	$	1.2	$	3.0	$	1.0	$	1.3	$	0.8
2019	0.5		3.0		1.0		1.3		0.5

Nuclear Fuel Supply — NSP-Minnesota has contracted for approximately 55% 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 2030, NSP-Minnesota is scheduled to take delivery of approximately 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.

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

At Sept. 30, 2020 and 2019, 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 $6 million and $9 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 maintains a nuclear decommissioning fund, as required by the NRC. The nuclear decommissioning fund is subject to interest rate risk and equity price risk. The fund is invested in a diversified portfolio of cash equivalents, debt securities, equity securities, and other investments. These investments may be used only for purpose of decommissioning NSP-Minnesota’s nuclear generating plants.

Realized and unrealized gains on the decommissioning fund investments are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs. Fluctuations in equity prices or interest rates affecting the nuclear decommissioning fund do not have a direct impact on earnings due to the application of regulatory accounting.

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

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

At Sept. 30, 2020, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $29 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $3 million. At Sept. 30, 2019, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $30 million, while a decrease in prices of 10% would have resulted in an increase in credit exposure of $12 million.

Xcel Energy conducts credit reviews for all counterparties and employs credit risk control, such as letters of credit, parental guarantees, master netting agreements and termination provisions. Credit exposure is monitored and when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. Distress in the financial markets could increase our credit risk.


FAIR VALUE MEASUREMENTS

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

The Company’s investments held in the nuclear decommissioning fund, rabbi trusts, pension and other postretirement funds are also subject to fair value 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 monitors the creditworthiness of the counterparties to its commodity derivative contracts and assesses each counterparty’s ability to perform on the transactions. The impact of discounting commodity derivative assets for counterparty credit risk was not material to the fair value of commodity derivative assets at Sept. 30, 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. The impact of discounting commodity derivative liabilities for credit risk was immaterial at Sept. 30, 2020.


LIQUIDITY AND CAPITAL RESOURCES

Cash Flows


	Nine Months Ended Sept. 30
(Millions of Dollars)	2020		2019
Cash provided by operating activities	$	2,174	$	2,557

Net cash provided by operating activities decreased $383 million for the nine months ended Sept. 30, 2020 compared with the prior year. Decrease (excluding amounts related to non-cash operating activities (e.g., depreciation and amortization and deferred tax expenses)) was primarily due to changes in accounts receivable and timing of recovery of regulatory assets, partially offset by reduced O&M expenditures.


	Nine Months Ended Sept. 30
(Millions of Dollars)	2020		2019
Cash used in investing activities	$	(3,021)	$	(3,129)

Net cash used in investing activities decreased $108 million for the nine months ended Sept. 30, 2020 compared with the prior year. Increased levels of capital expenditures (primarily for wind projects) were offset by the sale of MEC in the third quarter.


	Nine Months Ended Sept. 30
(Millions of Dollars)	2020		2019
Cash provided by financing activities	$	1,484	$	1,289

Net cash provided by financing activities increased $195 million for the nine months ended Sept. 30, 2020 compared with the prior year. Increase was primarily attributable to proceeds from issuances of long-term debt, partially offset by higher repayments of long-term debt and a decrease in common stock issuances (related to the settlement of a forward equity agreement in August 2019).

Capital Requirements

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

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

•In January 2020, contributions of $150 million were made across four of Xcel Energy’s pension plans;

•In 2019, contributions of $154 million were made across four of Xcel Energy’s pension plans; and

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

Capital Sources

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

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

Revolving Credit Facilities — Xcel Energy Inc., NSP-Minnesota, PSCo and SPS each have the right to request an extension of 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. 26, 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
Xcel Energy Inc.	$	1,250	$	—	$	1,250	$	269	$	1,519
PSCo	700		8		692		2		694
NSP-Minnesota	500		10		490		202		692
SPS	500		16		484		1		485
NSP-Wisconsin	150		10		140		—		140
Total	$	3,100	$	44	$	3,056	$	474	$	3,530

(a)Credit facilities expire in June 2024.

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

Bilateral Credit Agreement

As of Sept. 30, 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	$	46	$	29

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, which was repaid in full in September 2020.

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


(Amounts in Millions, Except Interest Rates)	Three Months Ended Sept. 30, 2020			Year Ended Dec. 31, 2019
Borrowing limit	$	3,600		$	3,600
Amount outstanding at period end	500			595
Average amount outstanding	1,195			1,115
Maximum amount outstanding	1,438			1,780
Weighted average interest rate, computed on a daily basis	0.81		%	2.72		%
Weighted average interest rate at period end	0.66			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. In October 2020, the PSCW approved NSP-Wisconsin’s application to participate in the Money Pool.

Capital Expenditures — Base capital expenditures and incremental capital forecast for Xcel Energy for 2021 through 2025 are as follows:


	Base Capital Forecast (Millions of Dollars)
By Regulated Utility	2021		2022		2023		2024		2025		2021 - 2025 Total
PSCo	$	1,700	$	1,835	$	1,750	$	1,695	$	1,655	$	8,635
NSP-Minnesota	1,630		1,605		1,635		1,645		1,890		8,405
SPS	505		710		770		735		675		3,395
NSP-Wisconsin	360		430		395		515		470		2,170
Other (a)	(20)		(15)		10		10		10		(5)
Total base capital expenditures	$	4,175	$	4,565	$	4,560	$	4,600	$	4,700	$	22,600


	Base Capital Forecast (Millions of Dollars)
By Function	2021		2022		2023		2024		2025		2021 - 2025 Total
Electric distribution	$	1,205	$	1,440	$	1,550	$	1,505	$	1,475	$	7,175
Electric transmission	870		1,285		1,285		1,270		1,290		6,000
Electric generation	630		575		560		750		975		3,490
Natural gas	615		615		665		670		625		3,190
Other	545		575		485		405		335		2,345
Renewables	310		75		15		—		—		400
Total base capital expenditures	$	4,175	$	4,565	$	4,560	$	4,600	$	4,700	$	22,600

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


	Incremental Capital Forecast (Millions of Dollars) (a)
NSP-Minnesota Proposal	2021		2022		2023		2024		2025		2021 - 2025 Total
Wind repowering	$	150	$	180	$	150	$	270	$	—	$	750
Solar	40		150		460		—		—		650
Total incremental capital	$	190	$	330	$	610	$	270	$	—	$	1,400

(a) Reflects proposed capital investment filed under the Minnesota Relief and Recovery plan, which is pending a MPUC decision. The incremental capital investment is not included in the base capital forecast.

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 initiatives and merger, acquisition and divestiture opportunities.

Financing for Capital Expenditures through 2025 — 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. Current estimated financing plans of Xcel Energy for 2021 through 2025:


(Millions of Dollars)
Funding Capital Expenditures
Cash from Operations (a)	$	14,680
New Debt (b)	7,260
Equity through the DRIP and Benefit Program	410
Other Equity	250
Base Capital Expenditures 2021-2025	$	22,600

Maturing Debt	$	4,120

(a) Net of dividends and pension funding

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

The incremental renewable capital proposed in the Minnesota Relief and Recovery plan would be financed with approximately 50% debt and 50% equity, if approved by the MPUC.

2020 Financing Activity — During 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 the following:

Issuer

Security

Amount

Status

Tenor

Coupon

Xcel Energy Inc.

Senior Unsecured Notes

600

million

Completed

10 Year

3.40

NSP-Minnesota

First Mortgage Bonds

700

million

Completed

31 Year

2.60

NSP-Wisconsin

First Mortgage Bonds

100

million

Completed

31 Year

3.05

PSCo

First Mortgage Bonds

375

million

Completed

31 Year

2.70

PSCo

First Mortgage Bonds

375

million

Completed

11 Year

1.90

SPS

First Mortgage Bonds

350

million

Completed

30 Year

3.15

Xcel Energy Inc.

Senior Unsecured Notes

500

million

Completed

3 Year

0.50

2021 Planned Debt Financing — During 2021, Xcel Energy Inc. and its utility subsidiaries anticipate issuing the following:

•NSP-Minnesota — approximately $400 million of first mortgage bonds;

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

•PSCo — approximately $400 million of first mortgage bonds; and

•SPS — approximately $150 million of first mortgage bonds.

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

Forward Equity Agreements — In November 2019 Xcel Energy Inc. entered into forward equity agreements in connection with a completed $743 million public offering of 11.8 million shares of common stock, which is expected to be settled in shares later in 2020.

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 2020 Earnings Guidance — Xcel Energy narrows 2020 GAAP and ongoing earnings guidance to $2.75 to $2.81 from $2.73 to $2.83 per share (a)(b), which assumes the implementation of contingency plans will be sufficient to offset the negative impacts of COVID-19.

Key assumptions as compared with 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 decline ~3%.

•Weather-normalized retail firm natural gas sales are projected to be relatively flat.

•Capital rider revenue is projected to increase $40 million to $45 million (net of PTCs). PTCs are credited to customers, through capital riders and reductions to electric margin.

•O&M expenses are projected to decline approximately 1% to 2%.

•Depreciation expense is projected to increase approximately $180 million to $190 million.

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

•Interest expense (net of AFUDC - debt) is projected to increase $60 million to $65 million.

•AFUDC - equity is projected to increase approximately $35 million to $45 million.

•ETR is projected to be ~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.

Xcel Energy 2021 Earnings Guidance — Xcel Energy’s 2021 GAAP and ongoing earnings guidance is a range of $2.90 to $3.00 per share.(a)(b)

Key assumptions as compared with 2020 levels unless noted:

•Constructive outcomes in all rate case and regulatory proceedings.

•Modest impacts from COVID-19.

•Normal weather patterns for the year.

•Weather-normalized retail electric sales are projected to increase ~1%.

•Weather-normalized retail firm natural gas sales are projected to be relatively flat.

•Capital rider revenue is projected to increase $125 million to $135 million (net of PTCs). PTCs are credited to customers, through capital riders and reductions to electric margin.

•O&M expenses are projected to increase approximately 1%.

•Depreciation expense is projected to increase approximately $210 million to $220 million.

•Property taxes are projected to increase approximately $45 million to $55 million.

•Interest expense (net of AFUDC - debt) is projected to increase $0 million to $10 million.

•AFUDC - equity is projected to decline approximately $45 million to $55 million.

•ETR is projected to be ~(9%). 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 2020 base of $2.78 per share, which represents the mid-point of the original 2020 guidance range of $2.73 to $2.83 per share.

• Deliver annual dividend increases of 5% to 7%.

• Target a dividend payout ratio of 60% to 70%.

• Maintain senior secured debt credit ratings in the A range.


COVID-19

Although COVID-19 represents an unprecedented event that has led to numerous challenges, Xcel Energy believes its risk management program, including business continuity and disaster recovery planning, will allow us to continue to proactively manage and successfully navigate the challenges, risks and uncertainties associated with the pandemic. In addition, we have implemented O&M contingency plans to reduce costs and seek regulatory deferral mechanisms to offset the negative impact of the pandemic on sales, bad debt and other aspects of our business.

There is continued uncertainty regarding COVID-19, the duration and magnitude of business restrictions, re-shut downs and the level and pace of economic recovery. Also, while we are implementing contingency plans, there are no guarantees these plans will be sufficient to offset the impact of the pandemic, which could have a material impact on our results of operations, financial condition or cash flow.

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

Sales — In the first nine months of 2020, Xcel Energy experienced a decline in weather and leap year adjusted sales due to the impacts of COVID-19.

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

In April 2020, Xcel Energy estimated the following potential impact of the pandemic on electric and natural gas sales and EPS:

•Weather-adjusted electric retail sales were projected to decline ~4% for 2020 (based on an increase of ~1% in residential sales and a decline of 6% in C&I sales).

•Weather-adjusted firm natural gas sales were projected to decline ~1%.

•Projected sales decline were estimated to reduce EPS by approximately $0.17.

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

However, our year-to-date weather and leap-year adjusted electric sales declined 3.5%, which was better than anticipated. As a result, we now expect weather and leap-year adjusted electric sales to decline by approximately 3% for the full-year of 2020. In comparison, our original 2020 earnings guidance assumed sales growth of approximately 1%.

Bad Debt — In March 2020, Xcel Energy announced it would not disconnect residential customers’ electric or natural gas service during the virus outbreak. In addition, certain states have issued 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 customer hardship. However, several of our commissions have approved the deferral of incremental COVID-19 related expense, including bad debt expense as discussed below.

Regulatory — Xcel Energy has received orders in Minnesota, Colorado, Wisconsin, Texas, New Mexico, South Dakota and Michigan, allowing regulatory deferral of incremental COVID-19 costs as a regulatory asset subject to future determination of amount and timing of recovery. Xcel Energy has also filed requests in North Dakota to record a regulatory asset and defer all incremental expenses related to the pandemic.

The majority of wholesale customers are subject to formula transmission and production rates, which true-up rates to actual costs to serve.

Xcel Energy deferred approximately $6 million of related expenses as of Sept. 30, 2020. 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.

Contingency Plan — Xcel Energy has implemented contingency plans to reduce costs to offset the negative impact of COVID-19. Based on these actions and our year-to-date sales, we now expect 2020 O&M expenses will decline 1% to 2% compared with 2019.

Supply Chain and Capital Expenditures — Xcel Energy’s ability to meet customer energy requirements, respond to storm-related disruptions and execute our capital expenditure program are dependent on maintaining an efficient supply chain. During the first nine months of 2020, Xcel Energy did not experience supply chain, contractor or employee disruptions that prevented us from performing certain maintenance or construction activity with the exception of delays in certain wind projects. However, we have not significantly adjusted our 2020 capital expenditure plan.

Pension — The funded status of the Xcel Energy pension plans was approximately 90% in January 2020. The funded status of the pension plan is currently estimated to be approximately 85%.

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 above or below a baseline.

Liquidity — Xcel Energy has taken steps to enhance its liquidity and believes it has more than adequate liquidity. We have completed our debt issuance plans for 2020. As a result of these actions, Xcel Energy had approximately $3.5 billion of available liquidity as of Oct. 26, 2020.

Furthermore, 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, which will further enhance liquidity. Finally, Xcel Energy continues to have access to the capital markets on favorable terms.


ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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


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, 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

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

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


ITEM 1A — RISK FACTORS

There have been no material changes from the risk factors disclosed in our Form 10-K for the year ended Dec. 31, 2019 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. A high degree of uncertainty continues to exist regarding COVID-19, the duration and magnitude of business restrictions, re-shut downs, if any, and the level and pace of economic recovery. While we are implementing contingency plans, there are no guarantees these plans will be sufficient to offset the impact of COVID-19.

Although we do not expect the impact of COVID-19 to be material to the 2020 results, we cannot ultimately predict whether it will have a material impact on our future liquidity, financial condition, or results of operations. Nor can we predict the impact of the virus on the health of our employees, our supply chain or our ability to recover higher costs associated with managing through the pandemic.

Xcel Energy’s risk factors are documented in Item 1A of Part I of its Annual Report on Form 10-K for the year ended Dec. 31, 2019, which is incorporated herein by reference, as well as other information set forth in this report, which could have a material impact on our financial condition, results of operations and cash flows.


Class						Outstanding at Oct. 19, 2020
Common Stock, $2.50 par value						525,457,773 shares


PART I	FINANCIAL INFORMATION
Item 1 —	Financial Statements (unaudited)	4
	Consolidated Statements of Income	4
	Consolidated Statements of Comprehensive Income	5
	Consolidated Statements of Cash Flows	6
	Consolidated Balance Sheets	7
	Consolidated Statements of Common Stockholders’ Equity	8
	Notes to Consolidated Financial Statements	9
Item 2 —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
Item 3 —	Quantitative and Qualitative Disclosures about Market Risk	34
Item 4 —	Controls and Procedures	34

PART II	OTHER INFORMATION
Item 1 —	Legal Proceedings	34
Item 1A —	Risk Factors	34
Item 2 —	Unregistered Sales of Equity Securities and Use of Proceeds	35
Item 6 —	Exhibits	35

SIGNATURES		36

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


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


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


Xcel Energy Inc.
(Exact name of registrant as specified in its charter)


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)


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


	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
July 1 - July 31, 2020	—	$	—	—	—
Aug. 1, 2020 - Aug. 31, 2020	—	—		—	—
Sept. 1, 2020 - Sept. 30, 2020 (a)	54,475	70.49		—	—
	54,475			—	—


		XCEL ENERGY INC.

Oct. 29, 2020	By:	/s/ JEFFREY S. SAVAGE
		Jeffrey S. Savage
		Senior Vice President, Controller
		(Principal Accounting Officer)

		/s/ BRIAN J. VAN ABEL
		Brian J. Van Abel
		Executive Vice President, Chief Financial Officer
		(Principal Financial Officer)