UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended Sept. 30, 2019 or

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

001-3034	41-0448030
(Commission File Number)	(I.R.S. Employer Identification No.)

(Registrant, State of Incorporation or Organization, Address of Principal Executive Officers and Telephone Number)

Xcel Energy Inc.

Minnesota

414 Nicollet Mall

Minneapolis Minnesota 55401

612 330-5500

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

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

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

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

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

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

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

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

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

Class	Oct. 17, 2019
Common Stock, $2.50 par value	524,388,096 shares

TABLE OF CONTENTS

PART I	FINANCIAL INFORMATION
Item 1 —	Financial Statements (unaudited)	5
	CONSOLIDATED STATEMENTS OF INCOME	5
	CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME	6
	CONSOLIDATED STATEMENTS OF CASH FLOWS	7
	CONSOLIDATED BALANCE SHEETS	8
	CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY	9
	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS	11
Item 2 —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25
Item 3 —	Quantitative and Qualitative Disclosures about Market Risk	37
Item 4 —	Controls and Procedures	37
PART II	OTHER INFORMATION
Item 1 —	Legal Proceedings	37
Item 1A —	Risk Factors	37
Item 2 —	Unregistered Sales of Equity Securities and Use of Proceeds	37
Item 6 —	Exhibits	38
SIGNATURES		39
	Certifications Pursuant to Section 302
	Certifications Pursuant to Section 906

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

2

ABBREVIATIONS AND INDUSTRY TERMS

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

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

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

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

EPS	Earnings per share
ETR	Effective tax rate
FASB	Financial Accounting Standards Board
FTR	Financial transmission right
GAAP	Generally accepted accounting principles
GE	General Electric
IPP	Independent power producing entity
MDL	Multi district litigation
MEC	Mankato Energy Center
MGP	Manufactured gas plant
MISO	Midcontinent Independent System Operator, Inc.
NAV	Net asset value
NOI	Notice of inquiry
NOL	Net operating loss
O&M	Operating and maintenance
OATT	Open Access Transmission Tariff
PPA	Power purchase agreement
PTC	Production tax credit
ROE	Return on equity
ROFR	Right-of-first refusal
ROU	Right-of-use
RTO	Regional Transmission Organization
SMMPA	Southern Minnesota Municipal Power Agency
SPP	Southwest Power Pool, Inc.
TCJA	2017 federal tax reform enacted as Public Law No: 115-97, commonly referred to as the Tax Cuts and Jobs Act
TOs	Transmission owners

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

3

Forward-Looking Statements

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

4

PART I — FINANCIAL INFORMATION

Item 1 — FINANCIAL STATEMENTS

XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) (amounts in millions, except per share data)
	Three Months Ended Sept. 30						Nine Months Ended Sept. 30
	2019			2018			2019			2018
Operating revenues
Electric	$	2,771		$	2,802		$	7,345		$	7,419
Natural gas	222			227			1,324			1,181
Other	20			19			62			57
Total operating revenues	3,013			3,048			8,731			8,657
Operating expenses
Electric fuel and purchased power	952			1,040			2,679			2,907
Cost of natural gas sold and transported	55			58			646			537
Cost of sales — other	9			9			28			26
Operating and maintenance expenses	580			593			1,764			1,729
Conservation and demand side management expenses	75			77			212			216
Depreciation and amortization	447			440			1,319			1,199
Taxes (other than income taxes)	137			135			429			417
Total operating expenses	2,255			2,352			7,077			7,031
Operating income	758			696			1,654			1,626
Other income (expense)	8			(7		)	14			(8		)
Equity earnings of unconsolidated subsidiaries	10			9			29			25
Allowance for funds used during construction — equity	15			30			55			79
Interest charges and financing costs
Interest charges — includes other financing costs of $6, $6, $19 and $18, respectively	199			177			578			523
Allowance for funds used during construction — debt	(7		)	(13		)	(27		)	(35		)
Total interest charges and financing costs	192			164			551			488
Income before income taxes	599			564			1,201			1,234
Income taxes	72			73			121			187
Net income	$	527		$	491		$	1,080		$	1,047
Weighted average common shares outstanding:
Basic	$	519		$	510		$	517		$	510
Diluted	521			511			518			510
Earnings per average common share:
Basic	$	1.02		$	0.96		$	2.09		$	2.05
Diluted	1.01			0.96			2.08			2.05
See Notes to Consolidated Financial Statements

5

XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (amounts in millions)
	Three Months Ended Sept. 30						Nine Months Ended Sept. 30
	2019			2018			2019			2018
Net income	$	527		$	491		$	1,080		$	1,047
Other comprehensive income
Pension and retiree medical benefits:
Net pension and retiree medical gains arising during the period, net of tax of $0, $(1), $1 and $(1), respectively	—			(2		)	2			(2		)
Amortization of losses included in net periodic benefit cost, net of tax of $0, $1, $1 and $2, respectively	1			4			3			6
	1			2			5			4
Derivative instruments:
Net fair value decrease, net of tax of $(3), $0, $(8) and $0, respectively	(9		)	—			(25		)	—
Reclassification of losses to net income, net of tax of $0, $0, $1 and $1, respectively	1			1			2			2
	(8		)	1			(23		)	2
Other comprehensive (loss) income	(7		)	3			(18		)	6
Comprehensive income	$	520		$	494		$	1,062		$	1,053
See Notes to Consolidated Financial Statements

6

XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) (amounts in millions)
	Nine Months Ended Sept. 30
	2019			2018
Operating activities
Net income	$	1,080		$	1,047
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	1,332			1,213
Nuclear fuel amortization	89			92
Deferred income taxes	130			184
Allowance for equity funds used during construction	(55		)	(79		)
Equity earnings of unconsolidated subsidiaries	(29		)	(25		)
Dividends from unconsolidated subsidiaries	30			27
Share-based compensation expense	47			25
Changes in operating assets and liabilities:
Accounts receivable	39			(48		)
Accrued unbilled revenues	132			114
Inventories	(60		)	37
Other current assets	3			52
Accounts payable	(56		)	37
Net regulatory assets and liabilities	(6		)	164
Other current liabilities	(100		)	(158		)
Pension and other employee benefit obligations	(138		)	(134		)
Other, net	119			(55		)
Net cash provided by operating activities	2,557			2,493
Investing activities
Utility capital/construction expenditures	(3,018		)	(2,681		)
Purchases of investment securities	(472		)	(494		)
Proceeds from the sale of investment securities	462			479
Other, net	(101		)	(10		)
Net cash used in investing activities	(3,129		)	(2,706		)
Financing activities
Repayments from short-term borrowings, net	(105		)	(376		)
Proceeds from issuances of long-term debt	1,937			1,381
Repayments of long-term debt, including reacquisition premiums	(399		)	(301		)
Proceeds from issuance of common stock	457			203
Dividends paid	(587		)	(544		)
Other, net	(14		)	(20		)
Net cash provided by financing activities	1,289			343
Net change in cash and cash equivalents	717			130
Cash and cash equivalents at beginning of period	147			83
Cash and cash equivalents at end of period	$	864		$	213
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(544	)	$	(491	)
Cash received (paid) for income taxes, net	53			(4		)
Supplemental disclosure of non-cash investing and financing transactions:
Accrued property, plant and equipment additions	$	420		$	340
Inventory transfers to property, plant and equipment	64			74
Operating lease right-of-use assets	1,718			—
Allowance for equity funds used during construction	55			79
Issuance of common stock for equity awards	46			52
See Notes to Consolidated Financial Statements

7

XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) (amounts in millions, except share and per share data)
	Sept. 30, 2019			Dec. 31, 2018
Assets
Current assets
Cash and cash equivalents	$	864		$	147
Accounts receivable, net	821			860
Accrued unbilled revenues	623			755
Inventories	544			548
Regulatory assets	455			464
Derivative instruments	61			87
Prepaid taxes	39			79
Prepayments and other	193			154
Total current assets	3,600			3,094
Property, plant and equipment, net	38,703			36,944
Other assets
Nuclear decommissioning fund and other investments	2,599			2,317
Regulatory assets	3,120			3,326
Derivative instruments	22			34
Operating lease right-of-use assets	1,718			—
Other	478			272
Total other assets	7,937			5,949
Total assets	$	50,240		$	45,987
Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	853		$	406
Short-term debt	933			1,038
Accounts payable	1,258			1,237
Regulatory liabilities	469			436
Taxes accrued	443			450
Accrued interest	166			174
Dividends payable	212			195
Derivative instruments	73			61
Other	614			463
Total current liabilities	5,021			4,460
Deferred credits and other liabilities
Deferred income taxes	4,427			4,165
Deferred investment tax credits	50			54
Regulatory liabilities	5,082			5,187
Asset retirement obligations	2,679			2,568
Derivative instruments	178			129
Customer advances	203			199
Pension and employee benefit obligations	856			994
Operating lease liabilities	1,598			—
Other	186			206
Total deferred credits and other liabilities	15,259			13,502
Commitments and contingencies
Capitalization
Long-term debt	16,819			15,803
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 524,384,030 and 514,036,787 shares outstanding at Sept. 30, 2019 and Dec. 31, 2018, respectively	1,311			1,285
Additional paid in capital	6,636			6,168
Retained earnings	5,336			4,893
Accumulated other comprehensive loss	(142		)	(124		)
Total common stockholders’ equity	13,141			12,222
Total liabilities and equity	$	50,240		$	45,987
See Notes to Consolidated Financial Statements

8

XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY (UNAUDITED) (amounts in millions, shares in thousands)
	Common Stock Issued					Retained Earnings			Accumulated Other Comprehensive Loss			Total Common Stockholders’ Equity
	Shares	Par Value		Additional Paid In Capital
Three Months Ended Sept. 30, 2019 and 2018
Balance at June 30, 2018	508,898	$	1,272	$	5,920	$	4,580		$	(122	)	$	11,650
Net income						491						491
Other comprehensive income									3			3
Dividends declared on common stock ($0.38 per share)						(195		)				(195		)
Issuances of common stock	4,401	11		197								208
Share-based compensation				8		—						8
Balance at Sept. 30, 2018	513,299	$	1,283	$	6,125	$	4,876		$	(119	)	$	12,165
Balance at June 30, 2019	514,865	$	1,287	$	6,190	$	5,024		$	(135	)	$	12,366
Net income						527						527
Other comprehensive loss									(7		)	(7		)
Dividends declared on common stock ($0.405 per share)						(214		)				(214		)
Issuances of common stock	9,519	24		438								462
Share-based compensation				8		(1		)				7
Balance at Sept. 30, 2019	524,384	$	1,311	$	6,636	$	5,336		$	(142	)	$	13,141
See Notes to Consolidated Financial Statements

9

XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY (UNAUDITED) (amounts in millions, shares in thousands)
	Common Stock Issued							Retained Earnings			Accumulated Other Comprehensive Loss			Total Common Stockholders’ Equity
	Shares		Par Value		Additional Paid In Capital
Nine Months Ended Sept. 30, 2019 and 2018
Balance at Dec. 31, 2017	507,763		$	1,269	$	5,898		$	4,413		$	(125	)	$	11,455
Net income								1,047						1,047
Other comprehensive income											6			6
Dividends declared on common stock ($1.14 per share)								(584		)				(584		)
Issuances of common stock	5,558		14		221									235
Repurchases of common stock	(22	)	—		(1		)							(1		)
Share-based compensation					7			—						7
Balance at Sept. 30, 2018	513,299		$	1,283	$	6,125		$	4,876		$	(119	)	$	12,165
Balance at Dec. 31, 2018	514,037		$	1,285	$	6,168		$	4,893		$	(124	)	$	12,222
Net income								1,080						1,080
Other comprehensive income											(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
See Notes to Consolidated Financial Statements

10

XCEL ENERGY INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements (UNAUDITED)

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

1. Summary of Significant Accounting Policies

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

2. Accounting Pronouncements

Recently Issued

Credit Losses — In 2016, the FASB issued Financial Instruments - Credit Losses, Topic 326 (ASC Topic 326), which changes how entities account for losses on receivables and certain other assets. The guidance requires use of a current expected credit loss model, which may result in earlier recognition of credit losses than under previous accounting standards. ASC Topic 326 is effective for interim and annual periods beginning on or after Dec. 15, 2019, and will be applied on a modified-retrospective approach through a cumulative-effect adjustment to retained earnings as of Jan. 1, 2020. Xcel Energy expects the impact of adoption of the new standard to include first-time recognition of expected credit losses (i.e., bad debt expense) on unbilled revenues, with the initial allowance established at Jan. 1, 2020 charged to retained earnings.

Recently Adopted

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

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

Xcel Energy also utilized the transition practical expedient offered by ASU No. 2018-11 Leases: Targeted Improvements to implement the standard on a prospective basis. As a result, reporting periods in the consolidated financial statements beginning Jan. 1, 2019 reflect the implementation of ASC Topic 842, while prior periods continue to be reported in accordance with Leases, Topic 840 (ASC Topic 840). Other than first-time recognition of operating leases on its consolidated balance sheet, the implementation of ASC Topic 842 did not have a significant impact on Xcel Energy’s consolidated financial statements. Adoption resulted in recognition of approximately $1.7 billion of operating lease ROU assets and current/noncurrent operating lease liabilities. See Note 10 to the consolidated financial statements for leasing disclosures.

3.     Selected Balance Sheet Data

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

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

(Millions of Dollars)	Sept. 30, 2019			Dec. 31, 2018
Property, plant and equipment, net
Electric plant	$	43,301		$	41,472
Natural gas plant	6,414			6,210
Common and other property	2,251			2,154
Plant to be retired (a)	276			322
CWIP	2,629			2,091
Total property, plant and equipment	54,871			52,249
Less accumulated depreciation	(16,549		)	(15,659		)
Nuclear fuel	2,887			2,771
Less accumulated amortization	(2,506		)	(2,417		)
Property, plant and equipment, net	$	38,703		$	36,944

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

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.

11

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

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

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

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

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

• Maturity extended from June 2021 to June 2024.

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

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

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

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.

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

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

^(a)  Expires in June 2024.

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

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the respective credit facilities. Xcel Energy Inc. and its subsidiaries had no direct advances on the credit facilities outstanding as of Sept. 30, 2019 and Dec. 31, 2018.

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

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

As of Sept. 30, 2019, 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.

As of Sept. 30, 2019, 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	$	20	$	55

Long-Term Borrowings

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

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

• Xcel Energy Inc. issued $130 million of 4.00% senior unsecured bonds due June 15, 2028.

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

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

• NSP-Minnesota issued $600 million of 2.90% first mortgage green bonds due March 1, 2050.

Forward Equity Agreements — In November 2018, Xcel Energy Inc. entered into forward sale agreements in connection with a completed $459 million public offering of 9.4 million shares of Xcel Energy common stock. The initial forward agreement was for 8.1 million shares with an additional agreement for 1.2 million shares that was exercised at the option of the banking counterparty. On Aug. 29, 2019, Xcel Energy settled the forward equity agreements by physically delivering 9.4 million shares of common equity for cash proceeds of $453 million.

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

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5. Revenues

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

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

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

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

	Nine Months Ended Sept. 30, 2018
(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	2,255	$	663	$	28	$	2,946
C&I	3,726		347		17		4,090
Other	101		—		5		106
Total retail	6,082		1,010		50		7,142
Wholesale	589		—		—		589
Transmission	398		—		—		398
Other	80		76		—		156
Total revenue from contracts with customers	7,149		1,086		50		8,285
Alternative revenue and other	270		95		7		372
Total revenues	$	7,419	$	1,181	$	57	$	8,657

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6.    Income Taxes

Note 7 to the consolidated financial statements included in Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2018 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
	2019		2018		2019		2018
Federal statutory rate	21.0	%	21.0	%	21.0	%	21.0	%
State tax (net of federal tax effect)	5.0		5.0		5.0		5.0
(Decreases) increases:
Wind PTCs	(6.1	)	(2.6	)	(8.1	)	(4.3	)
Plant regulatory differences (a)	(5.6	)	(9.4	)	(5.5	)	(5.2	)
Other tax credits and tax credit and NOL allowances (net)	(1.7	)	(1.9	)	(1.8	)	(1.5	)
Other (net)	(0.6	)	0.8		(0.5	)	0.2
Effective income tax rate	12.0	%	12.9	%	10.1	%	15.2	%

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

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

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

In 2015, the IRS commenced an examination of tax years 2012 and 2013. In 2017, the IRS concluded the audit of tax years 2012 and 2013 and proposed an adjustment that would impact Xcel Energy’s NOL and ETR. Xcel Energy filed a protest with the IRS. As of Sept. 30, 2019, the case has been forwarded to the Office of Appeals and Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of this issue; however, the outcome and timing of a resolution is unknown.

In 2018, the IRS began an audit of tax years 2014 - 2016. As of Sept. 30, 2019, no adjustments have been proposed.

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

As of Sept. 30, 2019, Xcel Energy’s earliest open tax years (subject to examination by state taxing authorities in its major operating jurisdictions) were as follows:

State	Year
Colorado	2009
Minnesota	2009
Texas	2009
Wisconsin	2014

• In 2018, Wisconsin began an audit of tax years 2014 - 2016. As of Sept. 30, 2019, no material adjustments have been proposed.

• No other state income tax audits were in progress as of Sept. 30, 2019.

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

Unrecognized tax benefits — permanent vs. temporary:

(Millions of Dollars)	Sept. 30, 2019		Dec. 31, 2018
Unrecognized tax benefit — Permanent tax positions	$	33	$	28
Unrecognized tax benefit — Temporary tax positions	10		9
Total unrecognized tax benefit	$	43	$	37

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

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

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

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

Payables for interest related to unrecognized tax benefits were not material and no amounts were accrued for penalties related to unrecognized tax benefits as of Sept. 30, 2019 or Dec. 31, 2018.

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 (settled in August 2019) and time-based equity compensation awards.

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

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

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

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

Diluted common shares outstanding included common stock equivalents of 1.8 million and 1.6 million for the three and nine months ended Sept. 30, 2019, respectively (0.4 million for both the three and nine months ended Sept. 30, 2018).

8. Fair Value of Financial Assets and Liabilities

Fair Value Measurements

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

Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are 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.

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

Specific valuation methods include the following:

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 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 generally utilize observable forward prices and volatilities, as well as observable pricing adjustments for specific delivery locations, and are generally assigned a Level 2 classification. When contractual settlements relate to delivery locations for which pricing is relatively unobservable, or extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable inputs on a valuation is evaluated and may result in Level 3 classification.

Electric commodity derivatives held by NSP-Minnesota and SPS include transmission congestion instruments, generally referred to as FTRs. FTRs purchased from a RTO are financial instruments that entitle or obligate the holder to monthly revenues or charges based on transmission congestion across a given transmission path. The value of an FTR is derived from, and designed to offset, the cost of transmission congestion. In addition to overall transmission load, congestion is also influenced by the operating schedules of power plants and the consumption of electricity pertinent to a given transmission path. Unplanned plant outages, scheduled plant maintenance, changes in the relative costs of fuels used in generation, weather and overall changes in demand for electricity can each impact the operating schedules of the power plants on the transmission grid and the value of an FTR.

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

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

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 investment targets by asset class for the qualified trust.

NSP-Minnesota recognizes the costs of funding the decommissioning over the lives of the nuclear plants, assuming rate recovery of all costs. Realized and unrealized gains on fund investments over the life of the fund are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs. Consequently, any realized and unrealized gains and losses on securities in the nuclear decommissioning fund are deferred as a component of the regulatory asset.

Unrealized gains for the nuclear decommissioning fund were $619 million and $450 million as of Sept. 30, 2019 and Dec. 31, 2018, respectively, and unrealized losses were $22 million and $45 million as of Sept. 30, 2019 and Dec. 31, 2018, respectively.

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

	Sept. 30, 2019
			Fair Value
(Millions of Dollars)	Cost		Level 1		Level 2		Level 3		NAV		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	23	$	23	$	—	$	—	$	—	$	23
Commingled funds	815		—		—		—		997		997
Debt securities	489		—		484		12		—		496
Equity securities	393		800		1		—		—		801
Total	$	1,720	$	823	$	485	$	12	$	997	$	2,317

 

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

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

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

For the three and nine months ended Sept. 30, 2019 and 2018, there were no transfers of amounts between levels.

Contractual maturity dates of debt securities in the nuclear decommissioning fund as of Sept. 30, 2019:

	Final Contractual Maturity
(Millions of Dollars)	Due in 1 Year or Less		Due in 1 to 5 Years		Due in 5 to 10 Years		Due after 10 Years		Total
Debt securities	$	1	$	126	$	226	$	143	$	496

Rabbi Trusts

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

Cost and fair value of assets held in rabbi trusts:

	Sept. 30, 2019
			Fair Value
(Millions of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Rabbi Trusts (a)
Cash equivalents	$	17	$	17	$	—	$	—	$	17
Mutual funds	55		61		—		—		61
Total	$	72	$	78	$	—	$	—	$	78

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

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

Derivative 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.

As of Sept. 30, 2019, accumulated other comprehensive loss related to interest rate derivatives included $5 million of net losses expected to be reclassified into earnings during the next 12 months as the hedged transactions impact earnings.

As of Sept. 30, 2019, Xcel Energy had unsettled interest rate swaps outstanding with a notional amount of $300 million. These interest rate derivatives were designated as cash flow hedges, and as such, changes in fair value are recorded to other comprehensive income.

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

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

Xcel Energy may enter into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers, but may not be designated as qualifying hedging transactions. Changes in the fair value of non-trading commodity derivative instruments are recorded as other comprehensive income or deferred as a regulatory asset or liability. The classification as a regulatory asset or liability is based on approved regulatory recovery mechanisms.

As of Sept. 30, 2019, Xcel Energy had no commodity contracts designated as cash flow hedges.

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

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Gross notional amounts of commodity forwards, options and FTRs:

(Amounts in Millions) (a)(b)	Sept. 30, 2019	Dec. 31, 2018
MWh of electricity	121	87
MMBtu of natural gas	130	92

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

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

Consideration of Credit Risk and Concentrations — Xcel Energy continuously monitors the creditworthiness of counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement, and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Impact of credit risk was immaterial to the fair value of unsettled commodity derivatives presented in the consolidated balance sheets. Xcel Energy’s utility subsidiaries’ most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to their wholesale, trading and non-trading commodity activities.

As of Sept. 30, 2019, six of Xcel Energy’s 10 most significant counterparties for these activities, comprising $156 million or 53% 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 $24 million or 8% 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 $8 million or 3% of this credit exposure, had credit quality less than investment grade, based on external analysis. Eight of these significant counterparties are municipal or cooperative electric entities 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, 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	)
Three Months Ended Sept. 30, 2018
Other derivative instruments
Electric commodity	$	—		$	(2	)
Natural gas commodity	—			(2		)
Total	$	—		$	(4	)
Nine Months Ended Sept. 30, 2018
Other derivative instruments
Electric commodity	$	—		$	6
Natural gas commodity	—			(1		)
Total	$	—		$	5

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	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, 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
Three Months Ended Sept. 30, 2018
Derivatives designated as cash flow hedges
Interest rate	$	1	(a)	$	—			$	—
Total	$	1		$	—			$	—
Other derivative instruments
Commodity trading	$	—		$	—			$	5		(b)
Total	$	—		$	—			$	5
Nine Months Ended Sept. 30, 2018
Derivatives designated as cash flow hedges
Interest rate	$	3	(a)	$	—			$	—
Total	$	3		$	—			$	—
Other derivative instruments
Commodity trading	$	—		$	—			$	14		(b)
Natural gas commodity	—			2			(d)	(2		)	(d)
Total	$	—		$	2			$	12

^(a)  Recorded to interest charges.

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

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

^(d)  Amounts for both the three and nine months ended Sept. 30, 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. Amounts for the three and nine months ended Sept. 30, 2018 included no such settlement gains or losses and $1 million of such settlement losses, respectively. Remaining settlement losses for the three and nine months ended Sept. 30, 2019 and 2018 related to natural gas operations and were recorded to cost of natural gas sold and transported. These gains and losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset or liability, as appropriate.

Xcel Energy had no derivative instruments designated as fair value hedges during the three and nine months ended Sept. 30, 2019 and 2018.

Credit Related Contingent Features — Contract provisions for derivative instruments that the utility subsidiaries enter, including those accounted for as normal purchase-normal sale contracts and therefore not reflected on the consolidated balance sheets, may require the posting of collateral or settlement of the contracts for various reasons, including if the applicable utility subsidiary’s credit ratings are downgraded below its investment grade credit rating by any of the major credit rating agencies, or for cross default contractual provisions if there was a failure under other financing arrangements related to payment terms or other covenants. As of Sept. 30, 2019 and Dec. 31, 2018, there were no derivative instruments in a liability position with such underlying contract provisions, with no offsetting positions or posted collateral.

Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. Provisions allow counterparties to seek performance assurance, including cash collateral, in the event that a given utility subsidiary’s ability to fulfill its contractual obligations is reasonably expected to be impaired. Xcel Energy had no collateral posted related to adequate assurance clauses in derivative contracts as of Sept. 30, 2019 and Dec. 31, 2018.

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

	Sept. 30, 2019													Dec. 31, 2018
	Fair Value						Fair Value Total		Netting (a)			Total		Fair Value						Fair Value Total		Netting (a)			Total
(Millions of Dollars)	Level 1		Level 2		Level 3									Level 1		Level 2		Level 3
Current derivative assets
Other derivative instruments:
Commodity trading	$	3	$	42	$	13	$	58	$	(34	)	$	24	$	4	$	92	$	2	$	98	$	(44	)	$	54
Electric commodity	—		—		28		28		(1		)	27		—		—		25		25		—			25
Natural gas commodity	—		7		—		7		—			7		—		4		—		4		—			4
Total current derivative assets	$	3	$	49	$	41	$	93	$	(35	)	58		$	4	$	96	$	27	$	127	$	(44	)	83
PPAs (b)												3													4
Current derivative instruments												$	61												$	87
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	$	5	$	39	$	5	$	49	$	(41	)	$	8	$	—	$	27	$	5	$	32	$	(14	)	$	18
Total noncurrent derivative assets	$	5	$	39	$	5	$	49	$	(41	)	8		$	—	$	27	$	5	$	32	$	(14	)	18
PPAs (b)												14													16
Noncurrent derivative instruments												$	22												$	34

	Sept. 30, 2019													Dec. 31, 2018
	Fair Value						Fair Value Total		Netting (a)			Total		Fair Value						Fair Value Total		Netting (a)			Total
(Millions of Dollars)	Level 1		Level 2		Level 3									Level 1		Level 2		Level 3
Current derivative liabilities
Derivatives designated as cash flow hedges:
Interest rate	$	—	$	40	$	—	$	40	$	—		$	40	$	—	$	7	$	—	$	7	$	—		$	7
Other derivative instruments:
Commodity trading	3		42		11		56		(46		)	10		4		88		2		94		(60		)	34
Electric commodity	—		—		1		1		(1		)	—		—		—		—		—		—			—
Natural gas commodity	—		6		—		6		—			6		—		—		—		—		—			—
Total current derivative liabilities	$	3	$	88	$	12	$	103	$	(47	)	56		$	4	$	95	$	2	$	101	$	(60	)	41
PPAs (b)												17													20
Current derivative instruments												$	73												$	61
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	2	$	88	$	19	$	109	$	(10	)	$	99	$	—	$	18	$	1	$	19	$	17		$	36
Total noncurrent derivative liabilities	$	2	$	88	$	19	$	109	$	(10	)	99		$	—	$	18	$	1	$	19	$	17		36
PPAs (b)												79													93
Noncurrent derivative instruments												$	178												$	129

^(a)  Xcel Energy nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Sept. 30, 2019 and Dec. 31, 2018. At both Sept. 30, 2019 and Dec. 31, 2018, derivative assets and liabilities include $32 million of obligations to return cash collateral. At Sept. 30, 2019 and Dec. 31, 2018, derivative assets and liabilities include rights to reclaim cash collateral of $12 million and $15 million, respectively. Counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

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

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Changes in Level 3 commodity derivatives:

	Three Months Ended Sept. 30
(Millions of Dollars)	2019			2018
Balance at July 1	$	28		$	64
Purchases	5			3
Settlements	(21		)	(19		)
Net transactions recorded during the period:
Gains recognized in earnings (a)	1			—
Net gains recognized as regulatory assets and liabilities	2			—
Balance at Sept. 30	$	15		$	48
	Nine Months Ended Sept. 30
(Millions of Dollars)	2019			2018
Balance at Jan. 1	$	29		$	35
Purchases	42			49
Settlements	(48		)	(51		)
Net transactions recorded during the period:
Losses recognized in earnings (a)	(9		)	—
Net gains recognized as regulatory assets and liabilities	1			15
Balance at Sept. 30	$	15		$	48

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

Xcel Energy recognizes transfers between fair value hierarchy levels as of the beginning of each period. There were no transfers of amounts between levels for derivative instruments for the three and nine months ended Sept. 30, 2019 and 2018.

Fair Value of Long-Term Debt

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

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

Fair value of Xcel Energy’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. Fair value estimates are based on information available to management as of Sept. 30, 2019 and Dec. 31, 2018, 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
	2019			2018			2019			2018
(Millions of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	22		$	24		$	—		$	1
Interest cost (a)	36			33			6			5
Expected return on plan assets (a)	(51		)	(52		)	(5		)	(6		)
Amortization of prior service credit (a)	(1		)	(1		)	(3		)	(3		)
Amortization of net loss (a)	22			27			1			2
Settlement charge (b)	—			59			—			—
Net periodic benefit cost (credit)	28			90			(1		)	(1		)
Credits (costs) not recognized due to the effects of regulation	—			(50		)	—			1
Net benefit cost (credit) recognized for financial reporting	$	28		$	40		$	(1	)	$	—

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

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

^(b) A settlement charge is required when the amount of all lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In the third quarter of 2018 as a result of lump-sum distributions during the 2018 plan year, Xcel Energy recorded a total pension settlement charge of $59 million, the majority of which was not recognized due to the effects of regulation. A total of $6 million of that amount was recorded in other expense in the third quarter of 2018.

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

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10.    Commitments and Contingencies

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

Legal

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

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

Gas Trading Litigation — e prime is a wholly owned subsidiary of Xcel Energy. e prime was in the business of natural gas trading and marketing but has not engaged in natural gas trading or marketing activities since 2003.  Multiple lawsuits seeking monetary damages were commenced against e prime and its affiliates, including Xcel Energy, between 2003 and 2009 alleging fraud and anticompetitive activities in conspiring to restrain the trade of natural gas and manipulate natural gas prices. Cases were all consolidated in the U.S. District Court in Nevada.

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

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

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

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

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

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

PSCo has concluded that a loss is remote with respect to both of these matters as the service agreements were developed to implement CPUC approved tariffs and PSCo has complied with the tariff provisions. If a loss were sustained, PSCo believes it would be allowed to recover costs through traditional regulatory mechanisms. Amount or range in dispute is presently unknown and no accrual has been recorded for this matter.

Rate Matters

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

In 2018, NSP-Minnesota and SMMPA reached a settlement with GE. NSP-Minnesota has notified the MPUC of its proposal to refund the GE settlement proceeds back to customers through the FCA.

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

In January 2019, the DOC recommended that NSP-Minnesota refund $20 million of previously recovered purchased power costs to its customers, based on the jury’s apportionment of fault. NSP-Minnesota filed reply comments arguing that the DOC recommendations are without merit and that it acted prudently in operating the plant and its settlement with GE was reasonable.

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

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

The FERC subsequently made preliminary determinations in a November 2018 order that the MISO TO’s base ROE in effect for the first complaint period (12.38%) was outside the range of reasonableness, and should be reduced. The FERC indicated its preliminary analysis using the new ROE approach resulted in a base ROE of 10.28% for the first complaint period, compared to the previously ordered base ROE of 10.32%.

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NSP-Minnesota has recognized a current refund liability consistent with its best estimate of the final ROE, pending further FERC action as early as the fourth quarter of 2019.

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

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

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

Environmental

MGP 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 and restoration activities are anticipated to be completed in 2019 and groundwater treatment activities will continue for many years.

The current cost estimate for remediation and restoration of the entire site is approximately $194 million. At Sept. 30, 2019 and Dec. 31, 2018, NSP-Wisconsin had a total liability of $22 million and $27 million, respectively, for the entire site.

NSP-Wisconsin has deferred the unrecovered portion of the estimated Site remediation and restoration costs as a regulatory asset. The PSCW has authorized NSP-Wisconsin rate recovery for all remediation and restoration costs incurred at the Site. In 2012, the PSCW agreed to allow NSP-Wisconsin to pre-collect certain costs, to amortize costs over 10 years and to apply a 3% carrying cost to the unamortized regulatory asset.

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

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

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

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

Environmental Requirements — Water and Waste

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

Under the CCR Rule, utilities are required to complete groundwater sampling around their CCR landfills and surface impoundments. By the end of 2019, only nine of Xcel Energy’s regulated ash units are expected to be in operation. Xcel Energy is conducting groundwater sampling and, where appropriate, initiating the assessment of corrective measures and evaluating whether corrective action is required at any CCR landfills or surface impoundments.

Until Xcel Energy completes its assessment, it is uncertain what impact, if any, there will be on the operations, financial condition or cash flows.

Leases

Xcel Energy evaluates contracts that may contain leases, including PPAs and arrangements for the use of office space and other facilities, vehicles and equipment. Under ASC Topic 842, adopted by Xcel Energy on Jan. 1, 2019, a contract contains a lease if it conveys the exclusive right to control the use of a specific asset. A contract determined to contain a lease is evaluated further to determine if the arrangement is a finance lease.

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

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

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

Operating lease ROU assets:

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

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

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

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

Finance lease ROU assets:

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

Components of lease expense:

(Millions of Dollars)	Three Months Ended Sept. 30, 2019		Nine Months Ended Sept. 30, 2019
Operating leases
PPA capacity payments	$	58	$	163
Other operating leases (a)	9		26
Total operating lease expense (b)	$	67	$	189
Finance leases
Amortization of ROU assets	$	1	$	5
Interest expense on lease liability	5		14
Total finance lease expense	$	6	$	19

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

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

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

Future commitments under operating and finance leases as of Sept. 30, 2019:

(Millions of Dollars)	PPA (a) (b) Operating Leases			Other Operating Leases			Total Operating Leases			Finance  Leases (c)
2019	$	59		$	6		$	65		$	3
2020	236			26			262			14
2021	238			29			267			14
2022	225			28			253			12
2023	214			25			239			12
Thereafter	959			136			1,095			219
Total minimum obligation	1,931			250			2,181			274
Interest component of obligation	(337		)	(54		)	(391		)	(192		)
Present value of minimum obligation	$	1,594		$	196		1,790			82
Less current portion							(192		)	(4		)
Noncurrent operating and finance lease liabilities							$	1,598		$	78
Weighted-average remaining lease term in years							9.5			37.2

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

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

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

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

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

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

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

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

Variable Interest Entities

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

Xcel Energy utility subsidiaries had approximately 3,986 MW and 3,770 MW of capacity under long-term PPAs as of Sept. 30, 2019 and Dec. 31, 2018, respectively, with entities that have been determined to be variable interest entities. Xcel Energy has concluded that these entities are not required to be consolidated in its financial statements because it does not have the power to direct the activities that significantly impact the entities’ economic performance. These agreements have various expiration dates through 2041.

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Other

Guarantees and Bond Indemnifications — Xcel Energy Inc. and its subsidiaries provide guarantees and bond indemnities which guarantee payment or performance. Xcel Energy Inc.’s exposure is based upon the net liability under the specified agreements or transactions. Most of the guarantees and bond indemnities issued by Xcel Energy Inc. and its subsidiaries have a stated maximum amount. As of Sept. 30, 2019 and Dec. 31, 2018, Xcel Energy Inc. and its subsidiaries had no assets held as collateral related to their guarantees, bond indemnities and indemnification agreements.

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

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

11.    Other Comprehensive Loss

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

	Three Months Ended Sept. 30, 2019									Three Months Ended Sept. 30, 2018
(Millions of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit Pension and Postretirement Items			Total			Gains and Losses on Cash Flow Hedges			Defined Benefit Pension and Postretirement Items			Total
Accumulated other comprehensive loss at July 1	$	(75	)	$	(60	)	$	(135	)	$	(57	)	$	(65	)	$	(122	)
Other comprehensive (loss) before reclassifications (net of taxes of $(3), $0, $0 and $(1), respectively)	(9		)	—			(9		)	—			(2		)	(2		)
Losses reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (net of taxes of $0) (a)	1			—			1			1			—			1
Amortization of net actuarial loss (net of taxes of $0, $0, $0 and $1, respectively) (b)	—			1			1			—			4			4
Net current period other comprehensive income	(8		)	1			(7		)	1			2			3
Accumulated other comprehensive loss at Sept. 30	$	(83	)	$	(59	)	$	(142	)	$	(56	)	$	(63	)	$	(119	)

	Nine Months Ended Sept. 30, 2019									Nine Months Ended Sept. 30, 2018
(Millions of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit Pension and Postretirement Items			Total			Gains and Losses on Cash Flow Hedges			Defined Benefit Pension and Postretirement Items			Total
Accumulated other comprehensive loss at Jan. 1	$	(60	)	$	(64	)	$	(124	)	$	(58	)	$	(67	)	$	(125	)
Other comprehensive (loss) gain before reclassifications (net of taxes of $(9), $1, $0 and $(1), respectively)	(25		)	2			(23		)	—			(2		)	(2		)
Losses reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (net of taxes of $1, $0, $1 and $0, respectively) (a)	2			—			2			2			—			2
Amortization of net actuarial loss (net of taxes of $0, $1, $0 and $2, respectively) (b)	—			3			3			—			6			6
Net current period other comprehensive income	(23		)	5			(18		)	2			4			6
Accumulated other comprehensive loss at Sept. 30	$	(83	)	$	(59	)	$	(142	)	$	(56	)	$	(63	)	$	(119	)

^(a)  Included in interest charges.

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

12.    Segment Information

Regulated electric utility operating results of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS, as well as the regulated natural gas utility operating results of NSP-Minnesota, NSP-Wisconsin and PSCo are each separately and regularly reviewed by Xcel Energy’s chief operating decision maker. Xcel Energy evaluates performance by each utility subsidiary based on profit or loss generated from the product or service provided.

These segments are managed separately because the revenue streams are dependent upon regulated rate recovery, which is separately determined for each segment.

Xcel Energy has the following reportable segments:

• Regulated Electric - The regulated electric utility segment generates, transmits and distributes electricity in Minnesota, Wisconsin, Michigan, North Dakota, South Dakota, Colorado, Texas and New Mexico. In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States. The regulated electric utility segment also includes wholesale commodity and trading operations.

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

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• All Other - Operating segments with revenues below the necessary quantitative thresholds are included in this category. Those segments primarily include steam revenue, appliance repair services, non-utility real estate activities, revenues associated with processing solid waste into refuse-derived fuel and investments in rental housing projects that qualify for low-income housing tax credits.

Xcel Energy had equity investments in unconsolidated subsidiaries of $151 million and $141 million as of Sept. 30, 2019 and Dec. 31, 2018, respectively, included in the natural gas utility and all other segments.

Asset and capital expenditure information is not provided for Xcel Energy’s reportable segments. As an integrated electric and natural gas utility, Xcel Energy operates significant assets that are not dedicated to a specific business segment. Reporting assets and capital expenditures by business segment would require arbitrary and potentially misleading allocations which may not necessarily reflect the assets that would be required for the operation of the business segments on a stand-alone basis.

Certain costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation allocators across each segment. In addition, a general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising.

Xcel Energy’s segment information for the three and nine months ended Sept. 30:

	Three Months Ended Sept. 30
(Millions of Dollars)	2019			2018
Regulated Electric
Operating revenues from external customers	$	2,771		$	2,802
Net income	550			514
Regulated Natural Gas
Operating revenues from external customers	$	222		$	227
Net (loss) income	(1		)	9
All Other
Total operating revenue	$	20		$	19
Net loss	(22		)	(32		)
Consolidated Total
Total revenue	$	3,013		$	3,048
Net income	527			491

	Nine Months Ended Sept. 30
(Millions of Dollars)	2019			2018
Regulated Electric
Operating revenues from external customers	$	7,345		$	7,419
Intersegment revenue	1			1
Total revenues	$	7,346		$	7,420
Net income	1,032			997
Regulated Natural Gas
Operating revenues from external customers	$	1,324		$	1,181
Intersegment revenue	1			1
Total revenues	$	1,325		$	1,182
Net income	127			130
All Other
Total operating revenue	$	62		$	57
Net loss	(79		)	(80		)
Consolidated Total
Total revenue	$	8,733		$	8,659
Reconciling eliminations	(2		)	(2		)
Consolidated total revenue	$	8,731		$	8,657
Net income	1,080			1,047

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.

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Electric and Natural Gas Margins

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

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

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

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

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

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

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

Results of Operations

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

GAAP and ongoing diluted EPS for Xcel Energy:

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

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

Summary of Earnings

Xcel Energy — Xcel Energy’s earnings increased $0.05 per share for the third quarter of 2019 and $0.03 per share year-to-date. Earnings reflect higher electric margins primarily due to non-fuel riders and regulatory rate outcomes and lower O&M expenses, partially offset by lower AFUDC, increased depreciation and interest expenses.

PSCo — Earnings decreased $0.02 per share for the third quarter of 2019 and $0.05 per share year-to-date. The decrease in year-to-date earnings was driven by higher depreciation, O&M, interest expense and lower allowance for funds used during construction (AFUDC), which offsets higher natural gas and electric margin. Changes in depreciation and AFUDC are primarily driven by the Rush Creek wind project that was placed in service in 2018.

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

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

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

Xcel Energy Inc. and Other — 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 2019 EPS compared with the same period in 2018:

Diluted Earnings (Loss) Per Share	Three Months Ended Sept. 30			Nine Months Ended Sept. 30
GAAP and ongoing diluted EPS — 2018	$	0.96		$	2.05
Components of change — 2019 vs. 2018
Higher electric margins	0.08			0.22
Lower ETR (a)	0.03			0.12
Higher natural gas margin	—			0.05
Higher depreciation and amortization	(0.01		)	(0.17		)
Higher interest charges	(0.03		)	(0.08		)
Lower AFUDC	(0.04		)	(0.06		)
Changes in O&M	0.02			(0.05		)
GAAP and ongoing diluted EPS — 2019	$	1.01		$	2.08

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

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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 and the amount of natural gas or electricity historically used per degree of temperature. Weather deviations from normal levels can affect Xcel Energy’s financial performance.

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

Normal weather conditions are defined as either the 20-year 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
	2019 vs. Normal		2018 vs. Normal		2019 vs. 2018		2019 vs. Normal		2018 vs. Normal		2019 vs. 2018
HDD	(64.0	)%	(18.2	)%	(57.0	)%	10.7	%	(0.3	)%	9.4	%
CDD	27.4		14.8		20.9		6.4		27.1		(14.9	)
THI	(2.6	)	18.2		(17.0	)	(8.2	)	38.4		(33.2	)

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

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

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

	Three Months Ended Sept. 30
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Actual
Electric residential	1.7	%	(6.2	)%	5.9	%	(1.8	)%	(1.2	)%
Electric C&I	(1.6	)	(6.1	)	4.6		(3.6	)	(1.9	)
Total retail electric sales	(0.5	)	(6.1	)	4.7		(3.1	)	(1.7	)
Firm natural gas sales	4.2		1.7		N/A		(10.6	)	2.5

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

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

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

Year-to-date weather-normalized Electric Sales Growth (Decline)

• PSCo — Residential sales were lower due to a decrease in customer usage, partially offset by customer additions. Commercial and industrial (C&I) decline was due to lower usage in food and service industries, partially offset by growth in metal fabrication and mining industries.

• NSP-Minnesota — Decline in C&I sales was due to expected discrete energy manufacturing customer declines due to newly installed co-generation, which was partially offset by an increase in customers.

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• SPS — Residential sales growth was due to customer additions, partially offset by lower use per customer. Higher C&I sales was primarily driven by increase in the oil and natural gas industry in the Permian Basin.

• NSP-Wisconsin — Residential sales growth was attributable to customer additions and increased usage. Decline in C&I sales was due to lower use per customer and decreased sales to the mining, manufacturing and food industries.

Year-to-date weather-normalized Natural Gas Sales Growth

• Natural gas sales reflect an increase in the number of customers combined with higher customer use.

Electric Margin

Electric revenues and fuel and purchased power expenses are impacted by fluctuations in the price of natural gas, coal and uranium used in the generation of electricity. However, these price fluctuations have minimal impact on electric margin due to fuel recovery mechanisms that recover fuel expenses. In addition, electric customers receive a credit for PTCs generated in a particular period.

Electric revenues and margin:

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

Changes in electric margin:

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

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

Natural Gas Margin

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

Natural gas revenues and margin:

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

Changes in natural gas margin:

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

Non-Fuel Operating Expenses and Other Items

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

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

• Distribution expenses for the nine month comparison were higher due to storms and labor charges incurred during the first half of the year;

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

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

• Nuclear plant operations and amortization are lower largely reflecting savings initiatives and reduced refueling outage costs.

Depreciation and Amortization — Depreciation and amortization increased $7 million, or 1.6%, for the third quarter of 2019 and $120 million, or 10.0%, year-to-date. Increase was primarily driven by the Rush Creek and Hale wind farms going into service, as well as other capital investments, which was partially offset by accelerated amortization of PSCo’s prepaid pension asset in the third quarter of 2018.

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Taxes (Other than Income Taxes) — Taxes (other than income taxes) increased $2 million, or 1.5%, for the third quarter of 2019 and $12 million, or 2.9%, year-to-date. Increase was primarily due to higher property taxes in Colorado and Minnesota (net of deferred amounts).

AFUDC, Equity and Debt — AFUDC decreased $21 million for the third quarter of 2019 and $32 million year-to-date. Decrease was primarily due to the Rush Creek wind project being placed in-service in 2018, partially offset by the Hale wind project, which went into service in June 2019, and other capital investments.

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

Income Taxes — Income taxes decreased $1 million for the third quarter of 2019. Higher pre-tax earnings were offset by an increase in wind PTCs and tax benefit adjustments attributable to the tax return filed for 2018. 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 12.0% for the third quarter of 2019 compared with 12.9% for the same period in 2018, largely due to the adjustments above.

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

Regulation

FERC and State Regulation — The FERC and various state and local regulatory commissions regulate Xcel Energy Inc.’s utility subsidiaries and WGI. The electric and natural gas rates charged to customers of Xcel Energy Inc.’s utility subsidiaries and WGI are approved by the FERC or the regulatory commissions in the states in which they operate. The rates are designed to recover plant investment, operating costs and an allowed return on investment. Xcel Energy Inc.’s utility subsidiaries request changes in rates for utility services through filings with governing commissions.

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

Recently Filed Regulatory Proceedings

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

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

Key elements of the settlement include:

Electric:

• Allowed ROE of 10.0%;

• Allowed equity ratio of 52.5%;

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

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

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

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

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

Natural Gas:

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

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

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

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

The procedural schedule is as follows:

• Settlement deadline — Oct. 30, 2019

• Evidentiary hearing — Nov. 4-13, 2019

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

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

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

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

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

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

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

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

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

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

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

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

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

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

The following table summarizes SPS’ base rate increase request:

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

The procedural schedule is as follows:

• Intervenor testimony — Feb. 10, 2020

• Staff testimony — Feb. 18, 2020

• Rebuttal testimony — March 11, 2020

• Public hearing begins — March 30, 2020

• Final order deadline — Sept. 7, 2020

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

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

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

The following table summarizes SPS’ base rate increase request:

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

The procedural schedule is as follows:

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

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

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

• Rebuttal testimony — Dec. 20, 2019

• Public hearing begins — Jan. 7, 2020

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

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Other Pending and Recently Concluded Regulatory Proceedings

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

NSP-Minnesota — MEC Acquisition — In November 2018, NSP-Minnesota reached an agreement with Southern Power Company (a subsidiary of Southern Company) to purchase MEC, a 760 MW natural gas combined cycle facility for approximately $650 million.

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

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

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

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

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

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

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

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

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

• Adds approximately 4,000 MW of solar.

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

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

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

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

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

Public Utility Regulation

Except to the extent noted below and in Regulation above, the circumstances set forth in Public Utility Regulation included in Item 1 of Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2018 and in Item 2 of Xcel Energy Inc.’s Quarterly Report on Form 10-Q for the quarterly periods ending March 31, 2019 and June 30, 2019, appropriately represent, in all material respects, the current status of public utility regulation and are incorporated by reference.

NSP-Minnesota

Minnesota State ROFR Statute Complaint — In September 2017, LSP Transmission filed a complaint in the Minnesota District Court against the Minnesota Attorney General, MPUC and DOC. The complaint was in response to MISO assigning NSP-Minnesota and ITC Midwest, LLC joint ownership of a new Mankato-Winnebago 345 KV transmission line (estimated cost of $108 million), consistent with a Minnesota state ROFR statute. The complaint challenged the constitutionality of the state ROFR statute and is seeking declaratory judgment that the statute violates the Commerce Clause of the U.S. Constitution and should not be enforced.

The Minnesota state agencies and NSP-Minnesota filed motions to dismiss. In June 2018, the Minnesota District Court granted the defendants’ motions to dismiss with prejudice. LSP Transmission filed an appeal in July 2018. It is uncertain when a decision will be rendered.

Nuclear Power Operations

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

NSP-Wisconsin

2018 Electric Fuel Cost Recovery — NSP-Wisconsin’s electric fuel costs for 2018 were lower than authorized in rates and outside the 2% annual tolerance band, primarily due to increased sales to other utilities compared to the forecast used to set authorized rates. Under the fuel cost recovery rules, NSP-Wisconsin may retain approximately $4 million of fuel costs and defer the amount of over-recovery in excess of the 2% annual tolerance band for future refund to customers. In March 2019, NSP-Wisconsin filed with the PSCW to provide a refund of approximately $4 million to customers and proposed for it to be issued in September 2019. In August 2019, the Commission issued their order to refund the $4 million.

SPS

Wind Development — In 2018, the NMPRC and PUCT approved SPS’ proposal to add 1,230 MW of new wind generation, including construction and ownership of the 478 MW Hale and 522 MW Sagamore wind farms. The Hale wind farm was placed into commercial operation in June 2019. Sagamore is expected to go into service in 2020 and cost approximately $900 million.

Texas State (ROFR) Litigation — In May 2019, the Governor signed into law Senate Bill 1938, which grants incumbent utilities a ROFR to build transmission infrastructure when it directly interconnects to the utility’s existing facility. In June 2019, a complaint was filed in the United States District Court for the Western District of Texas claiming the new ROFR law to be unconstitutional.

Texas Fuel Reconciliation — In December 2018, SPS filed an application with the PUCT for reconciliation of fuel costs for the period Jan. 1, 2016, through June 30, 2018, to determine whether all fuel costs incurred were eligible for recovery. On Oct. 17, 2019, the assigned Administrative Law Judges (ALJs) issued a Proposal for Decision recommending the PUCT disallow approximately $3 million of costs related to the reconciliation period, based on the ALJs’ determination that entering into two specific solar PPAs was imprudent. The related solar facilities are located in New Mexico and were previously approved by the NMPRC as reasonable, necessary and economic. SPS plans to file exceptions regarding the proposed disallowance and assert, among other points, that the ALJs erred in failing to account for the capacity value of the solar projects.

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

Environmental Matters

In June 2019, the EPA issued the final ACE rule to replace the Obama-era Clean Power Plan. The final ACE rule may require implementation of heat rate improvement projects at some of our coal-fired power plants. It is not known what the costs associated with the final rule might be until state plans are developed to implement the final regulation. Xcel Energy believes the costs would be recoverable through rates based on prior state commission practice.

Derivatives, Risk Management and Market Risk

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

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

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

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

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

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

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’s risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee, which is made up of management personnel not directly involved in the activities governed by this policy.

At Sept. 30, 2019, the fair values by source for net commodity trading contract assets were as follows:

	Futures / Forwards
(Millions of Dollars)	Source of Fair Value	Maturity Less Than 1 Year			Maturity 1 to 3 Years			Maturity 4 to 5 Years			Maturity Greater Than 5 Years			Total Futures/ Forwards Fair Value
NSP-Minnesota	1	$	(1	)	$	1		$	1		$	1		$	2
NSP-Minnesota	2	5			(4		)	1			(7		)	(5		)
PSCo	2	(5		)	(21		)	(29		)	(4		)	(59		)
		$	(1	)	$	(24	)	$	(27	)	$	(10	)	$	(62	)

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

1 — Prices actively quoted or based on actively quoted prices.

2 — Prices based on models and other valuation methods.

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

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

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

The VaRs for the NSP-Minnesota and PSCo commodity trading operations, 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
2019	$	0.52	$	3.00	$	0.97	$	1.30	$	0.52
2018	0.19		3.00		0.20		0.50		0.08

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

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

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

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

Interest Rate Risk — Xcel Energy is subject to the risk of fluctuating interest rates in the normal course of business. Xcel Energy’s 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, 2019 and 2018, a 100-basis-point change in the benchmark rate on Xcel Energy’s variable rate debt would impact pre-tax interest expense annually by approximately $9 million and $5 million, respectively. See Note 8 to the consolidated financial statements for a discussion of Xcel Energy Inc. and its subsidiaries’ interest rate derivatives.

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

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These investments may be used only for activities related to nuclear decommissioning. Given the purpose and legal restrictions on the use of nuclear decommissioning fund assets, any realized and unrealized gains and losses on securities in the nuclear decommissioning fund, including any other-than-temporary impairments, are deferred as a component of the regulatory asset for nuclear decommissioning. Since the accounting for nuclear decommissioning recognizes that costs are recovered through rates, fluctuations in equity prices or interest rates affecting the nuclear decommissioning fund do not have a direct impact on earnings.

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

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. At Sept. 30, 2018, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $33 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $8 million.

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

Fair Value Measurements

Xcel Energy follows accounting and disclosure guidance on fair value measurements that contains a hierarchy for inputs used in measuring fair value and requires disclosure of the observability of the inputs used in these measurements. See Note 8 to the consolidated financial statements for further discussion of the fair value hierarchy and the amounts of assets and liabilities measured at fair value that have been assigned to Level 3.

Commodity Derivatives — Xcel Energy continuously monitors the creditworthiness of the counterparties to its commodity derivative contracts and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Given this assessment and the typically short duration of these contracts, the impact of discounting commodity derivative assets for counterparty credit risk was not material to the fair value of commodity derivative assets at Sept. 30, 2019. 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 regulatory assets and liabilities. Classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. Xcel Energy also assesses the impact of its own credit risk when determining the fair value of commodity derivative liabilities. The impact of discounting commodity derivative liabilities for credit risk was immaterial to the fair value of commodity derivative liabilities at Sept. 30, 2019.

Liquidity and Capital Resources

Cash Flows

	Nine Months Ended Sept. 30
(Millions of Dollars)	2019		2018
Cash provided by operating activities	$	2,557	$	2,493

Net cash provided by operating activities increased $64 million for the nine months ended Sept. 30, 2019 compared with the prior year. Increase was primarily due to additional net income partially offset by increased refunds associated with TCJA.

	Nine Months Ended Sept. 30
(Millions of Dollars)	2019			2018
Cash used in investing activities	$	(3,129	)	$	(2,706	)

Net cash used in investing activities increased $423 million for the nine months ended Sept. 30, 2019 compared with the prior year. Increase was primarily attributable to capital expansion (primarily for wind projects), partially offset by Rush Creek being placed in service in 2018.

	Nine Months Ended Sept. 30
(Millions of Dollars)	2019		2018
Cash provided by financing activities	$	1,289	$	343

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

Capital Requirements

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

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

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

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

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

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

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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.

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

As of Oct. 21, 2019, 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	$	379	$	871	$	1	$	872
PSCo	700		9		691		256		947
NSP-Minnesota	500		19		481		181		662
SPS	500		2		498		110		608
NSP-Wisconsin	150		66		84		1		85
Total	$	3,100	$	475	$	2,625	$	549	$	3,174

^(a)  Credit facilities expire in June 2024.

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

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

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

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

Bilateral Credit Agreement

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

As of Sept. 30, 2019, 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	$	20	$	55

Commercial Paper — 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.

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

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

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

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

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

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

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

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

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

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

(Millions of Dollars)
Funding Capital Expenditures
Cash from Operations(a)	$	13,905
New Debt(b)	6,665
Equity through the Dividend Reinvestment Program (DRIP) and Benefit Program	400
Other equity	1,000
Base Capital Expenditures 2020-2024	$	21,970
Maturing Debt	$	3,245

^(a) Net of dividends and pension funding.

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

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

Issuer	Security	Amount			Status	Tenor	Coupon
PSCo	First Mortgage Bonds	$	400	million	Completed	30 Year	4.05	%
Xcel Energy Inc.	Senior Unsecured Bonds	130		million	Completed	9 Year	4.00
SPS	First Mortgage Green Bonds	300		million	Completed	30 Year	3.75
PSCo	First Mortgage Green Bonds	550		million	Completed	30 Year	3.20
NSP-Minnesota	First Mortgage Green Bonds	600		million	Completed	30 Year	2.90
Xcel Energy Inc.	Senior Unsecured Bonds	1		billion	Pending	TBD	TBD

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

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

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

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

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

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

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

Forward Equity Agreements — In 2018, Xcel Energy entered into a forward equity agreement. On Aug. 29, 2019, Xcel Energy settled the forward equity agreement by delivering 9.4 million shares in exchange for $453 million.

Off-Balance-Sheet Arrangements

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

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

Xcel Energy 2019 Earnings Guidance — Xcel Energy narrows its 2019 earnings guidance to $2.60 to $2.65 per share from $2.55 to $2.65 per

share.^(a) 

Key assumptions as compared with 2018 levels unless noted:

• Constructive outcomes in all rate case and regulatory proceedings.

• Normal weather patterns for the remainder of the year.

• Weather-normalized retail electric sales are projected to be relatively consistent.

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

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

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

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

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

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

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

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

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

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

Key assumptions as compared with projected 2019 levels unless noted:

• Constructive outcomes in all rate case and regulatory proceedings.

• Normal weather patterns.

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

• Weather-normalized retail firm natural gas sales are projected to increase ~1%, including impact of leap year.

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

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

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

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

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

• AFUDC - equity is projected to increase approximately $20 million to $30 million.

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

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

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% off of a 2019 base of $2.60 per share, which represents the mid-point of the original 2019 guidance range of $2.55 to $2.65 per share;

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

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

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

Item 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See Management’s Discussion and Analysis — Derivatives, Risk Management and Market Risk under Item 2.

Item 4 — CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Xcel Energy maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the CEO and CFO, allowing timely decisions regarding required disclosure. As of Sept. 30, 2019, 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

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

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

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

Item 1A — RISK FACTORS

Xcel Energy Inc.’s risk factors are documented in Item 1A of Part I of its Annual Report on Form 10-K for the year ended Dec. 31, 2018, which is incorporated herein by reference. There have been no material changes from the risk factors previously disclosed in the Form 10-K.

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

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

For the quarter ended Sept. 30, 2019, no equity securities registered by Xcel Energy Inc., pursuant to Section 12 of the Securities Exchange Act of 1934, were purchased by or on behalf of us or any of our affiliated purchasers.

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Item 6 — EXHIBITS

* Indicates incorporation by reference

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

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

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SIGNATURES

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

		XCEL ENERGY INC.
Oct. 25, 2019	By:	/s/ JEFFREY S. SAVAGE
		Jeffrey S. Savage
		Senior Vice President, Controller
		(Principal Accounting Officer)
		/s/ ROBERT C. FRENZEL
		Robert C. Frenzel
		Executive Vice President, Chief Financial Officer
		(Principal Financial Officer)

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