Edgar Filing: XCEL ENERGY INC

Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)



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

For the fiscal year ended December 31, 2018



¨	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.
(a Minnesota corporation)
414 Nicollet Mall
Minneapolis, MN 55401
612-330-5500

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



Title of each class		Name of each exchange on which registered
Common Stock, $2.50 par value per share		Nasdaq Stock Market LLC
Securities registered pursuant to section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. x Yes ¨ No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. ¨ Yes x No

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. x Yes ¨ No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 and 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). x Yes ¨ No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulations S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. x 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 Act). ¨ Yes x No

As of June 29, 2018, the aggregate market value of the voting common stock held by non-affiliates of the Registrants was $23,246,479,826 and there were 508,898,420 shares of common stock outstanding.

As of Feb. 14, 2019, there were 514,211,368 shares of common stock outstanding, $2.50 par value.

DOCUMENTS INCORPORATED BY REFERENCE

The Registrant’s Definitive Proxy Statement for its 2019 Annual Meeting of Shareholders is incorporated by reference into Part III of this Form 10-K.

TABLE OF CONTENTS



PART I
Item 1 —	Business	3
	ABBREVIATIONS AND INDUSTRY TERMS	3
	COMPANY OVERVIEW	5
	ELECTRIC UTILITY OPERATIONS	8
	Electric Operating Statistics	8
	NSP-Minnesota	11
	NSP-Wisconsin	12
	PSCo	13
	SPS	14
	NATURAL GAS UTILITY OPERATIONS	15
	Natural Gas Operating Statistics	15
	NSP-Minnesota	16
	NSP-Wisconsin	16
	PSCo	16
	SPS	16
	GENERAL	16
	ENVIRONMENTAL MATTERS	17
	CAPITAL SPENDING AND FINANCING	17
	EMPLOYEES	17
	EXECUTIVE OFFICERS	18
Item 1A —	Risk Factors	19
Item 1B —	Unresolved Staff Comments	23
Item 2 —	Properties	24
Item 3 —	Legal Proceedings	25
Item 4 —	Mine Safety Disclosures	25

PART II
Item 5 —	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	25
Item 6 —	Selected Financial Data	26
Item 7 —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
Item 7A —	Quantitative and Qualitative Disclosures About Market Risk	43
Item 8 —	Financial Statements and Supplementary Data	43
Item 9 —	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	78
Item 9A —	Controls and Procedures	78
Item 9B —	Other Information	78

PART III
Item 10 —	Directors, Executive Officers and Corporate Governance	78
Item 11 —	Executive Compensation	78
Item 12 —	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	78
Item 13 —	Certain Relationships and Related Transactions, and Director Independence	78
Item 14 —	Principal Accountant Fees and Services	78

PART IV
Item 15 —	Exhibits, Financial Statement Schedules	79
Item 16 —	Form 10-K Summary	85

SIGNATURES		86

Table of Contents

PART I

Item 1 — Business

ABBREVIATIONS AND INDUSTRY TERMS



Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former)
Capital Services	Capital Services, LLC
Eloigne	Eloigne Company
e prime	e prime inc.
NCE	New Century Energies, Inc.
NSP-Minnesota	Northern States Power Company, a Minnesota corporation
NSP System	The electric production and transmission system of NSP-Minnesota and NSP-Wisconsin operated on an integrated basis and managed by NSP-Minnesota
NSP-Wisconsin	Northern States Power Company, a Wisconsin corporation
Operating companies	NSP-Minnesota, NSP-Wisconsin, PSCo and SPS
PSCo	Public Service Company of Colorado
SPS	Southwestern Public Service Co.
Utility subsidiaries	NSP-Minnesota, NSP-Wisconsin, PSCo and SPS
WGI	WestGas InterState, Inc.
WYCO	WYCO Development, LLC
Xcel Energy	Xcel Energy Inc. and its subsidiaries



Federal and State Regulatory Agencies
CPUC	Colorado Public Utilities Commission
D.C. Circuit	United States Court of Appeals for the District of Columbia Circuit
DOC	Minnesota Department of Commerce
DOE	United States Department of Energy
DOJ	Department of Justice
DOT	United States Department of Transportation
EPA	United States Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
Fifth Circuit	United States Court of Appeals for the Fifth Circuit
IRS	Internal Revenue Service
Minnesota District Court	U.S. District Court for the District of Minnesota
MPSC	Michigan Public Service Commission
MPUC	Minnesota Public Utilities Commission
NDPSC	North Dakota Public Service Commission
NERC	North American Electric Reliability Corporation
Ninth Circuit	U.S. Court of Appeals for the Ninth Circuit
NMPRC	New Mexico Public Regulation Commission
NRC	Nuclear Regulatory Commission
OAG	Minnesota Office of the Attorney General
PHMSA	Pipeline and Hazardous Materials Safety Administration
PSCW	Public Service Commission of Wisconsin
PUCT	Public Utility Commission of Texas
SDPUC	South Dakota Public Utilities Commission
SEC	Securities and Exchange Commission
TCEQ	Texas Commission on Environmental Quality



Electric, Purchased Gas and Resource Adjustment Clauses
CIP	Conservation improvement program
DCRF	Distribution cost recovery factor
DSM	Demand side management
DSMCA	Demand side management cost adjustment
ECA	Retail electric commodity adjustment



EE	Energy efficiency
EECRF	Energy efficiency cost recovery factor
EIR	Environmental improvement rider
FCA	Fuel clause adjustment
FPPCAC	Fuel and purchased power cost adjustment clause
GCA	Gas cost adjustment
GUIC	Gas utility infrastructure cost rider
PCCA	Purchased capacity cost adjustment
PCRF	Power cost recovery factor
PGA	Purchased gas adjustment
PSIA	Pipeline system integrity adjustment
RDF	Renewable development fund
RER	Renewable energy rider
RES	Renewable energy standard
RESA	Renewable energy standard adjustment
SCA	Steam cost adjustment
SEP	State energy policy rider
TCA	Transmission cost adjustment
TCR	Transmission cost recovery adjustment
TCRF	Transmission cost recovery factor
WCA	Windsource^® cost adjustment



Other
AFUDC	Allowance for funds used during construction
ALJ	Administrative law judge
APBO	Accumulated postretirement benefit obligation
ARAM	Average rate assumption method
ARO	Asset retirement obligation
ASC	FASB Accounting Standards Codification
ASU	FASB Accounting Standards Update
ATM	At-the-market
ATRR	Annual transmission revenue requirement
BART	Best available retrofit technology
Boulder	City of Boulder, CO
C&I	Commercial and Industrial
CAPM	Capital Asset Pricing Model
CACJA	Clean Air Clean Jobs Act
CAISO	California Independent System Operator
CapX2020	Alliance of electric cooperatives, municipals and investor-owned utilities in the upper Midwest involved in a joint transmission line planning and construction effort
CBA	Collective-bargaining agreement
CCR	Coal combustion residuals
CCR Rule	Final rule (40 CFR 257.50 - 257.107) published by the EPA regulating the management, storage and disposal of CCRs as a nonhazardous waste
CDD	Cooling degree-days
CEP	Colorado Energy Plan
CIG	Colorado Interstate Gas Company, LLC
CO₂	Carbon dioxide
Corps	U.S. Army Corps of Engineers
CPCN	Certificate of public convenience and necessity
CPP	Clean Power Plan
CWA	Clean Water Act

Table of Contents



CWIP	Construction work in progress
DCF	Discounted Cash Flows
DECON	Decommissioning method where radioactive contamination is removed and safely disposed at a requisite facility, or decontaminated to a permitted level.
DRC	Development Recovery Company
DRIP	Dividend Reinvestment Program
EEI	Edison Electric Institute
ELG	Effluent limitations guidelines
EMANI	European Mutual Association for Nuclear Insurance
EPS	Earnings per share
EPU	Extended power uprate
ERP	Electric resource plan
ETR	Effective tax rate
FASB	Financial Accounting Standards Board
FTR	Financial transmission right
GAAP	Generally accepted accounting principles
GE	General Electric
GHG	Greenhouse gas
HDD	Heating degree-days
HTY	Historic test year
IM	Integrated market
IPP	Independent power producing entity
IRC	Internal Revenue Code
IRP	Integrated Resource Plan
ISFSI	Independent Spent Fuel Storage Installation
ITC	Investment Tax Credit
JOA	Joint operating agreement
LCM	Life cycle management
LLW	Low-level radioactive waste
LSP Transmission	LSP Transmission Holdings, LLC
Mankato 1	Mankato Energy Center, LLC
Mankato 2	Mankato Energy Center II, LLC
MDL	Multi-district litigation
MGP	Manufactured gas plant
MISO	Midcontinent Independent System Operator, Inc.
Moody’s	Moody’s Investor Services
NAAQS	National Ambient Air Quality Standard
Native load	Demand of retail and wholesale customers that a utility has an obligation to serve under statute or contract
NAV	Net asset value
NEIL	Nuclear Electric Insurance Ltd.
NETO	New England Transmission Owners
NOL	Net operating loss
NOX	Nitrogen oxide
O&M	Operating and maintenance
OATT	Open Access Transmission Tariff
OCC	Office of Consumer Counsel
Opinion 531	Methodology for calculating base ROE adopted by the FERC in June 2014
Paris Agreement	Establishes a framework for GHG mitigation actions by all countries (“nationally determined contributions”)
PI	Prairie Island nuclear generating plant
PJM	PJM Interconnection, LLC



PM	Particulate matter
Post-65	Post-Medicare
PPA	Purchased power agreement
Pre-65	Pre-Medicare
PRP	Potentially responsible party
PTC	Production tax credit
QF	Qualifying facilities
R&E	Research and experimentation
REC	Renewable energy credit
RFP	Request for proposal
ROE	Return on equity
ROFR	Right-of-first-refusal
RPS	Renewable portfolio standards
RTO	Regional Transmission Organization
Standard & Poor’s	Standard & Poor’s Ratings Services
SAB	Staff Accounting Bulletin
SAB 118	Income Tax Accounting Implications of the Tax Cuts and Jobs Act
SERP	Supplemental executive retirement plan
SMMPA	Southern Minnesota Municipal Power Agency
SO2	Sulfur dioxide
SPP	Southwest Power Pool, Inc.
SSL	Statistically significant increase over established groundwater standards
TCEH	Texas Competitive Energy Holdings
TCJA	2017 federal tax reform enacted as Public Law No: 115-97, commonly referred to as the Tax Cuts and Jobs Act
THI	Temperature-humidity index
TOs	Transmission owners
TransCo	Transmission-only subsidiary
TSR	Total shareholder return
VaR	Value at Risk
VIE	Variable interest entity
WOTUS	Waters of the U.S.



Measurements
Bcf	Billion cubic feet
KV	Kilovolts
KWh	Kilowatt hours
MMBtu	Million British thermal units
MW	Megawatts
MWh	Megawatt hours

Table of Contents

Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed herein are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements, including the 2019 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 Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2018 (including the items described under Factors Affecting Results of Operations; and the other risk factors listed from time to time by Xcel Energy Inc. in reports filed with the SEC, including “Risk Factors” in Item 1A of this Annual Report on Form 10-K hereto), 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.

Where To Find More Information

Xcel Energy’s website address is www.xcelenergy.com. Xcel Energy makes available, free of charge through its website, its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after the reports are electronically filed with or furnished to the SEC. The SEC maintains an internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically at http://www.sec.gov.

COMPANY OVERVIEW

Xcel Energy Inc. and its subsidiaries (“Xcel Energy” or the “Company”) is a major U.S. regulated electric and natural gas delivery company which serves customers in eight mid-western and western states, including portions of Colorado, Michigan, Minnesota, New Mexico, North Dakota, South Dakota, Texas and Wisconsin. The Company provides a comprehensive portfolio of energy-related products and services to approximately 3.6 million electric customers and 2.0 million natural gas customers through four operating companies (e.g., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS).

Xcel Energy‘s vision is to be the preferred and trusted provider of the energy our customers need and we strive to provide our investors an attractive total return value proposition and customers with safe, clean and reliable energy services at a competitive price. This mission is enabled via three key strategic priorities:


•	Lead the clean energy transition;


•	Enhance the customer experience; and,


•	Keep the bills low.

Xcel Energy is an environmental leader and in 2018 was the first major utility in the nation to announce a vision to serve all customers with 100% zero-carbon emissions by 2050. The Company is also implementing the nation’s largest multi-state wind plan with 12 new, low-cost wind farms across seven states. By leading the clean energy transition, we have positioned ourselves to create economic development for the communities and customers we serve.

See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Management’s Strategic Priorities for further discussion.

* Holding company incorporated under the laws of Minnesota in 1909 and its executive offices are located at 414 Nicollet Mall, Minneapolis, MN 55401.

Table of Contents

NSP-Minnesota

NSP-Minnesota conducts business in Minnesota, North Dakota and South Dakota and has electric operations in all three states including the generation, purchase, transmission, distribution and sale of electricity as managed on the NSP System. NSP-Minnesota also purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas in Minnesota and North Dakota.




		NSP-Minnesota
		Electric customers	1.5 million
		Natural gas customers	0.5 million
		Consolidated earnings contribution	35% to 45%
		Total assets	$18.5 billion
		Electric generating capacity	7,530 MW
		Gas storage capacity	14.7 Bcf

NSP-Wisconsin

NSP-Wisconsin conducts business in Wisconsin and Michigan and generates, transmits, distributes and sells electricity as managed on the NSP System. NSP-Wisconsin also purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas.





		NSP-Wisconsin
		Electric customers	0.3 million
		Natural gas customers	0.1 million
		Consolidated earnings contribution	5% to 10%
		Total assets	$2.7 billion
		Electric generating capacity	563 MW
		Gas storage capacity	3.6 Bcf

Table of Contents

PSCo

PSCo conducts business in Colorado and generates, purchases, transmits, distributes and sells electricity in addition to purchasing, transporting, distributing and selling natural gas to retail customers and transporting customer-owned natural gas.




		PSCo
		Electric customers	1.5 million
		Natural gas customers	1.4 million
		Consolidated earnings contribution	35% to 45%
		Total assets	$17.3 billion
		Electric generating capacity	5,685 MW
		Gas storage capacity	27.1 Bcf

SPS

SPS conducts business in Texas and New Mexico and generates, purchases, transmits, distributes and sells electricity.





		SPS
		Electric customers	0.4 million
		Consolidated earnings contribution	15% to 20%
		Total assets	$6.7 billion
		Electric generating capacity	4,406 MW

Table of Contents

ELECTRIC UTILITY OPERATIONS

Electric Operating Statistics



	Year Ended Dec. 31
	2018			2017			2016
Electric sales (Millions of KWh)
Residential	25,518			24,216			24,726
Large C&I	28,686			27,951			27,664
Small C&I	36,308			35,493			35,830
Public authorities and other	1,071			1,055			1,103
Total retail	91,583			88,715			89,323
Sales for resale	24,199			18,349			18,694
Total energy sold	115,782			107,064			108,017

Number of customers at end of period
Residential	3,117,262			3,082,974			3,053,732
Large C&I	1,253			1,241			1,228
Small C&I	436,836			433,883			432,012
Public authorities and other	69,794			69,376			68,935
Total retail	3,625,145			3,587,474			3,555,907
Wholesale	70			58			52
Total customers	3,625,215			3,587,532			3,555,959

Electric revenues (Millions of Dollars)
Residential	$	3,006		$	2,975		$	2,966
Large C&I	1,696			1,779			1,707
Small C&I	3,343			3,463			3,328
Public authorities and other	136			143			140
Total retail	8,181			8,360			8,141
Wholesale	801			719			693
Other electric revenues	737			597			666
Total electric revenues	$	9,719		$	9,676		$	9,500

KWh sales per retail customer	25,263			24,729			25,120
Revenue per retail customer	$	2,257		$	2,330		$	2,289
Residential revenue per KWh		11.78	¢		12.29	¢		11.99	¢
Large C&I revenue per KWh	5.91			6.36			6.17
Small C&I revenue per KWh	9.21			9.76			9.29
Total retail revenue per KWh	8.93			9.42			9.11
Wholesale revenue per KWh	3.31			3.92			3.71

Table of Contents

Energy Sources 2018

*Distributed generation from the Solar*Rewards^® program is not included (approximately 432 million KWh for 2018).

Energy Source Statistics



	Xcel Energy		NSP System		PSCo		SPS
2018
Owned Generation	67	%	77	%	70	%	49	%
Purchased Generation	33		23		30		51
	100	%	100	%	100	%	100	%
2017
Owned Generation	66	%	75	%	70	%	47	%
Purchased Generation	34		25		30		53
	100	%	100	%	100	%	100	%

Renewable Sources

Xcel Energy’s renewable energy portfolio includes wind, hydroelectric, biomass and solar power from both owned generating facilities and PPAs. As of Dec. 31, 2018, each utility or system was in compliance with their applicable RPS. Renewable percentages will vary year over year based on local weather, system demand and transmission constraints.

NSP System

Renewable energy as a percentage of the NSP System’s total:



	2018		2017
Wind	16.4	%	18.3	%
Hydroelectric	5.8		6.3
Biomass and solar	4.8		4.2
Renewable	27.0	%	28.8	%

Wind — The NSP System has more than 130 PPAs ranging from under one MW to more than 200 MW. The NSP System owns and operates five wind farms with 840 MW, net, of capacity.


•	The NSP System had approximately 2,550 MW and 2,600 MW of wind energy on its system at the end of 2018 and 2017, respectively.


•	Average cost per MWh of wind energy under existing PPAs was approximately $44 for 2018 and 2017.


•	Average cost per MWh of wind energy from owned generation was approximately $37 and $42 for 2018 and 2017, respectively.

PSCo

Renewable energy as a percentage of PSCo’s total:



	2018		2017
Wind	23.8	%	23.7	%
Hydroelectric and solar	3.6		3.9
Renewable	27.4	%	27.6	%

Wind — PSCo has 19 PPAs ranging from two MW to over 300 MW. PSCo owns and operates the Rush Creek wind farm which has 600 MW, net, of capacity.


•	PSCo had approximately 3,160 MW and 2,560 MW of wind energy on its system at the end of 2018 and 2017, respectively.


•	Average cost per MWh of wind energy under these contracts was approximately $43 and $42 for 2018 and 2017, respectively.


•	Rush Creek became operational in December 2018. The 2019 average cost per MWh is expected to be $29.

SPS

Renewable energy as a percentage of SPS’ total:



	2018		2017
Wind	19.1	%	21.2	%
Solar	2.0		2.8
Renewable	21.1	%	24.0	%

Wind — SPS has 18 PPAs with facilities ranging from under one MW to 250 MW.


•	SPS had approximately 1,565 MW and 1,500 MW of wind energy on its system at the end of 2018 and 2017, respectively.


•	Average cost per MWh of wind energy under the IPP contracts and QF tariffs was approximately $26 and $27 for 2018 and 2017, respectively.


•	In 2018, SPS began construction on the Sagamore and Hale County wind farms. Refer to the SPS Wind Development section for further information.

Table of Contents

Non-Renewable Sources

Delivered cost per MMBtu of each significant category of fuel consumed for owned electric generation and the percentage of total fuel requirements represented by each category of fuel:



	Coal ^(a)				Nuclear				Natural Gas
	Cost		Percent		Cost		Percent		Cost		Percent
NSP System
2018	$	2.13	42	%	$	0.80	45	%	$	3.87	13	%
2017	2.08		45		0.78		45		4.10		10
PSCo
2018	1.45		62		—		—		3.74		38
2017	1.56		70		—		—		3.82		30
SPS
2018	2.04		56		—		—		2.24		44
2017	2.18		74		—		—		3.39		26


^(a)	Includes refuse-derived fuel and wood for the NSP System.

Weighted average cost per MMBtu of all fuels for owned electric generation:



	NSP System		PSCo		SPS
2018	$	1.78	$	2.33	$	2.13
2017	1.72		2.25		2.50

See Items 1A and 7 for further information.

Coal — Inventory maintained (in days):



	Normal	Dec. 31, 2018 Actual	Dec. 31, 2017 Actual ^(a)
NSP System	35 - 50	47	53
PSCo	35 - 50	48	48
SPS	35 - 50	44	52


^(a)	Milder weather, purchase commitments and low power and natural gas prices impacted coal inventory levels.

Coal requirements (in million tons):



	2018	2017
NSP System	7.8	8.0
PSCo	9.4	10.0
SPS	5.1	5.5

Coal supply as a percentage of requirements (in million tons) for 2019:



	Contracted Coal Supply		2019 Estimated Requirements
NSP System ^(a)	76%	^(b)	8.4
PSCo ^(a)	83		8.4
SPS ^(a)	64		4.1


^(a)	The general coal purchasing objective is to contract for approximately 75% of first year requirements, 40% of year two requirements and 20% of year three requirements.


^(b)	Increase in estimated million tons was due to lower delivered coal prices at Sherco in January 2019, combined with higher future forecasted gas prices for 2019 (higher burn forecast).

Contracted coal transportation as a percentage of requirements in 2019 and 2020:



	2019	2020
NSP System	100%	100%
PSCo	100	100
SPS	100	100

Natural Gas — Natural gas supplies, transportation and storage services for power plants are procured to provide an adequate supply of fuel. Remaining requirements are procured through a liquid spot market. Generally, natural gas supply contracts have variable pricing that is tied to natural gas indices. Natural gas supply and transportation agreements include obligations for the purchase and/or delivery of specified volumes or payments in lieu of delivery.

Contracts and commitments at Dec. 31:



	NSP System				PSCo				SPS
(Millions of Dollars)	Gas Supply		Gas Transportation and Storage ^(a)		Gas Supply ^(b)		Gas Transportation and Storage ^(a)		Gas Supply		Gas Transportation and Storage ^(a)
2018	$	—	$	406	$	412	$	589	$	20	$	152
2017	—		398		545		620		11		191
Year of Expiration	N/A		2020 - 2037		2021 - 2023		2019 - 2040		One year or less		2019 - 2033


^(a)	For incremental supplies, there are limited on-site fuel storage facilities, with a primary reliance on the spot market.


^(b)	Majority of natural gas supply under contract is covered by a long-term agreement with Anadarko Energy Services Company and the balance of natural gas supply contracts have variable pricing features tied to changes in various natural gas indices. PSCo hedges a portion of that risk through financial instruments. See Note 10 to the consolidated financial statements for further information.

Nuclear — NSP-Minnesota secures contracts for uranium concentrates, uranium conversion, uranium enrichment and fuel fabrication to operate its nuclear plants. The contract strategy involves a portfolio of spot purchases and medium and long-term contracts for uranium concentrates, conversion services and enrichment services with multiple producers and with a focus on diversification to minimize potential impacts caused by supply interruptions due to geographical and world political issues.


•	Current nuclear fuel supply contracts cover 100% of uranium concentrates requirements through 2021 and approximately 51% of the requirements for 2022 - 2033.


•	Current contracts for conversion services cover 100% of the requirements through 2021 and approximately 43% of the requirements for 2022 - 2033.


•	Current enrichment service contracts cover 100% of the requirements through 2025 and approximately 19% of the requirements for 2026 - 2033.

Fabrication services for Monticello and PI are 100% committed through 2030 and 2027, respectively.

NSP-Minnesota expects sufficient uranium concentrates, conversion services and enrichment services to be available for the requirements of its nuclear generating plants. Some exposure to market price volatility will remain due to index-based pricing structures contained in supply contracts.

See Item 7 for further information.

Table of Contents

Capacity and Demand

Uninterrupted system peak demand and date for the regulated utilities:



	System Peak Demand (in MW)
	2018		2017
NSP System ^(a)	8,927	June 29	8,546	July 17
PSCo ^(a)	6,718	July 10	6,671	July 19
SPS ^(a)	4,648	July 19	4,374	July 26


^(a)	Peak demand typically occurs in the summer. The increase in peak load from 2017 to 2018 is partly due to warmer weather in 2018.

NSP-Minnesota

Public Utility Regulation

Summary of Regulatory Agencies and Areas of Jurisdiction — Retail rates, services and other aspects of NSP-Minnesota’s operations are regulated by the MPUC, NDPSC and SDPUC. The MPUC also has regulatory authority over security issuances, certain property transfers, mergers, dispositions of assets and transactions between NSP-Minnesota and its affiliates. In addition, the MPUC reviews and approves NSP-Minnesota’s IRPs for meeting future energy needs. In addition, MPUC certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV that will be located within the state. The NDPSC and SDPUC have regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in North Dakota and South Dakota, respectively.

NSP-Minnesota is subject to the jurisdiction of the FERC for its wholesale electric operations, hydroelectric licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transfers and mergers, and natural gas transactions in interstate commerce.

NSP-Minnesota is a transmission owning member of the MISO RTO and operates within the MISO RTO and MISO wholesale markets. NSP-Minnesota makes wholesale sales in other RTO markets at market-based rates. NSP-Minnesota and NSP-Wisconsin also make wholesale electric sales at market-based prices to customers outside of their balancing authority as jointly authorized by the FERC.

Fuel, Purchased Energy and Conservation Cost-Recovery

Mechanisms —


•	CIP rider — Recovers the costs of conservation and demand-side management programs.


•	EIR — Recovers the costs of environmental improvement projects.


•	RDF — Allocates money collected from retail customers to support the research and development of emerging renewable energy projects and technologies.


•	RES — Recovers the cost of renewable generation in Minnesota.


•	RER — Recovers the cost of renewable generation located in North Dakota.


•	SEP — Recovers costs related to various energy policies approved by the Minnesota legislature.


•	TCR — Recovers costs associated with investments in electric transmission and distribution grid modernization costs.


•	Infrastructure rider — Recovers costs for investments in generation and incremental property taxes in South Dakota.

NSP-Minnesota’s retail electric rates in Minnesota, North Dakota and South Dakota include a FCA for monthly billing adjustments to recover changes in prudently incurred costs of fuel related items and purchased energy. Capacity costs are recovered through base rates and are not recovered through the FCA. Costs associated with MISO are generally recovered through either the FCA or base rates.

In 2017, the MPUC voted to change the FCA process in Minnesota. Under the new process, each month utilities would collect amounts equal to the baseline cost of energy set at the start of the plan year (base would be reset annually). Monthly variations to the baseline costs would be tracked and netted over a 12-month period. Utilities would issue refunds above the baseline costs, and could seek recovery of any overage. Recently, the MPUC delayed implementation until January 2020.

Minnesota state law requires NSP-Minnesota to invest 2% of its state electric revenues and 0.5% of its state gas revenues in CIP. These costs are recovered through an annual cost-recovery mechanism for electric conservation and energy management program expenditures.

Energy Sources and Transmission Service Provider

NSP-Minnesota expects to use power plants, power purchases, CIP/DSM options, new generation facilities and expansion of power plants to meet its system capacity requirements.

Purchased Power — NSP-Minnesota has contracts to purchase power from other utilities and IPPs. Long-term purchased power contracts for dispatchable resources typically require a capacity charge and an energy charge. NSP-Minnesota makes short-term purchases to meet system requirements, replace company owned generation, meet operating reserve obligations or obtain energy at a lower cost.

Purchased Transmission Services — NSP-Minnesota and NSP-Wisconsin have contracts with MISO and other regional transmission service providers to deliver power and energy to their customers.

Wind Development — In 2017, the MPUC approved NSP-Minnesota’s proposal to add 1,550 MW of new wind generation including ownership of 1,150 MW of wind generation.

In April 2018, the MPUC approved NSP-Minnesota’s petition to build and own the Dakota Range, a 300 MW wind project in South Dakota. NSP-Minnesota’s capital investment for the Dakota Range is expected to be approximately $350 million and placed in service in 2021.

In December 2018, the NDPSC approved a settlement agreement for these wind development projects.

PPA Terminations and Amendments — In June 2018, NSP-Minnesota terminated the Benson and Laurentian PPAs, and purchased the Benson biomass facility. As a result, a $103 million regulatory asset was recognized for the costs of the Benson transaction. For Laurentian, a regulatory asset of $109 million was recognized for annual termination payments/obligations. Regulatory approvals provide for recovery of the Benson regulatory asset over 10 years and Laurentian termination payments as they occur (over six years). Termination of the PPAs is expected to save customers over $600 million throughout the next 10 years.

Table of Contents

Jurisdictional Cost Recovery Allocation — In December 2016, NSP-Minnesota filed a resource treatment framework with the NDPSC and MPUC. The filing proposed a framework to allow NSP-Minnesota’s operations in North Dakota and Minnesota to gradually become more independent of one another with respect to future generation resource selection while also identifying a path for cost sharing of current resources. NSP-Minnesota’s filing identified two options: a legal separation, creating a separate North Dakota operating company; or a pseudo-separation, which maintains the current corporate structure but directly assigns the costs and benefits of each resource to the jurisdiction that supports it. Docket remains under consideration by the NDPSC.

Minnesota State ROFR Statute Complaint — In September 2017, LSP Transmission filed a complaint in the Minnesota District Court against the Minnesota Attorney General, MPUC and DOC. The complaint was in response to MISO assigning NSP-Minnesota and ITC Midwest, LLC to jointly own a new 345 KV transmission line from near Mankato, Minnesota to Winnebago, Minnesota. The project was estimated by MISO to cost $108 million and was assigned to NSP-Minnesota and ITC Midwest as the incumbent utilities, consistent with a Minnesota state ROFR statute. The complaint challenged the constitutionality of the state ROFR statute and is seeking declaratory judgment that the statute violates the Commerce Clause of the U.S. Constitution and should not be enforced. The Minnesota state agencies and NSP-Minnesota filed motions to dismiss. In June 2018, the Minnesota District Court granted the defendants’ motions to dismiss with prejudice. LSP Transmission filed an appeal in July 2018. It is uncertain when a decision will be rendered.

Nuclear Power Operations and Waste Disposal

NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the PI plant. Nuclear power plant operations produce gaseous, liquid and solid radioactive wastes which are controlled by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. LLW consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment that have become contaminated through use in a plant.

NRC Regulation — The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs in customer rates and expects future compliance costs will continue to be recoverable.

LLW Disposal — LLW from NSP-Minnesota’s Monticello and PI nuclear plants is currently disposed at the Clive facility located in Utah and the Waste Control Specialists facility located in Texas. If off-site LLW disposal facilities become unavailable, NSP-Minnesota has storage capacity available on-site at PI and Monticello which would allow both plants to continue to operate until the end of their current licensed lives.

High-Level Radioactive Waste Disposal — The federal government has responsibility to permanently dispose domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility. The federal government has been evaluating a nuclear geologic repository at Yucca Mountain, Nevada for many years. Currently, there are no definitive plans for a permanent federal storage facility at Yucca Mountain or any other site.

Review of PI Costs — As part of NSP-Minnesota’s 2016 multi-year electric rate case and IRP, the MPUC ordered an investigation into NSP-Minnesota’s PI nuclear investments. The issue was resolved as part of the 2016 multi-year electric rate case settlement. In November 2018, the DOC issued a final report, in which no cost disallowances were recommended.

Nuclear Spent Fuel Storage — NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and PI nuclear generating plants. Authorized storage capacity is sufficient to allow NSP-Minnesota to operate until the end of the operating licenses in 2030 for Monticello, 2033 for PI Unit 1, and 2034 for PI Unit 2. Authorizations for additional spent fuel storage capacity may be required at each site to support either continued operation or decommissioning if the federal government does not commence storage operations.

In 2013, NSP-Minnesota’s Monticello nuclear generating plant loaded and placed five storage canisters (canisters #11-15) in the ISFSI and a sixth canister (canister #16) was loaded but remained in the plant pending resolution of weld inspection issues. Successful pressure and leak testing demonstrated the safety and integrity of all six canisters involved. NSP-Minnesota took several actions to assure compliance with the NRC’s regulations and Monticello’s storage license. The NRC has approved NSP-Minnesota’s compliance plan for all canisters.

NSP-Minnesota intends to seek recovery of these costs in a future regulatory proceeding. No public safety issues have been raised, or are believed to exist, in this matter.

See Note 12 to the consolidated financial statements for further information.

Wholesale and Commodity Marketing Operations

NSP-Minnesota conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy-related products. NSP-Minnesota uses physical and financial instruments to minimize commodity price and credit risk and hedge sales and purchases. NSP-Minnesota also engages in trading activity unrelated to hedging and sharing of any margins is determined through state regulatory proceedings as well as the operation of the FERC approved JOA. NSP-Minnesota does not serve any wholesale requirements customers at cost-based regulated rates.

NSP-Wisconsin

Public Utility Regulation

Summary of Regulatory Agencies and Areas of Jurisdiction — Retail rates, services and other aspects of NSP-Wisconsin’s operations are regulated by the PSCW and the MPSC. In addition, each of the state commissions certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built. NSP-Wisconsin is subject to the jurisdiction of the FERC for its wholesale electric operations, hydroelectric generation licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce. NSP-Wisconsin is a transmission owning member of the MISO RTO that operates within the MISO RTO and wholesale energy market. NSP-Wisconsin and NSP-Minnesota are jointly authorized by the FERC to make wholesale electric sales at market-based prices.

The PSCW has a biennial base rate filing requirement. By June of each odd numbered year, NSP-Wisconsin must submit a rate filing for the test year beginning the following January.

Table of Contents

Fuel and Purchased Energy Cost Recovery Mechanisms — NSP-Wisconsin does not have an automatic electric fuel adjustment clause. Instead, under Wisconsin rules, utilities submit a forward-looking annual fuel cost plan to the PSCW. Once the PSCW approves the fuel cost plan, utilities defer the amount of any fuel cost under-recovery or over-recovery in excess of a 2% annual tolerance band, for future rate recovery or refund. Approval of a fuel cost plan and any rate adjustment for refund or recovery of deferred costs is determined by the PSCW. Rate recovery of deferred fuel cost is subject to an earnings test based on the utility’s most recently authorized ROE. Fuel cost under-collections that exceed the 2% annual tolerance band may not be recovered if the utility earnings for that year exceed the authorized ROE.

NSP-Wisconsin’s electric fuel costs for 2018 were lower than authorized in rates and outside the 2% annual tolerance band, primarily due to greater than forecasted generation sales into the MISO market and lower purchased power costs coupled with moderate weather. Under the fuel cost recovery rules, NSP-Wisconsin retained approximately $3.6 million of fuel costs and deferred approximately $2.8 million. NSP-Wisconsin will file a reconciliation of 2018 fuel costs with the PSCW by March 31, 2019.

NSP-Wisconsin’s retail electric rate schedules for Michigan customers include power supply cost recovery factors, which are based on 12-month projections. After each 12-month period, a reconciliation is submitted whereby over-recoveries are refunded and any under-recoveries are collected from customers.

Wisconsin Energy Efficiency Program — The primary energy efficiency program is funded by the state’s utilities, but operated by independent contractors subject to oversight by the PSCW and utilities. NSP-Wisconsin recovers these costs from retail customers.

Transmission Initiatives

NSP-Wisconsin operates an integrated system with NSP-Minnesota. See NSP-Minnesota-Energy Sources and Transmission Service Provider.

NSP-Wisconsin / American Transmission Company, LLC - La Crosse to Madison, WI Transmission Line — In December 2018, construction was completed on the Badger Coulee 345 KV transmission line. The line extends from La Crosse, WI. to Madison, WI. NSP-Wisconsin’s half of the line is shared with Dairyland Power Cooperative, WPPI Energy and Southern Minnesota Municipal Power Agency-Wisconsin.

Wholesale and Commodity Marketing Operations

NSP-Wisconsin does not serve any wholesale requirements customers at cost-based regulated rates.

PSCo

Public Utility Regulation

Summary of Regulatory Agencies and Areas of Jurisdiction — PSCo is regulated by the CPUC with respect to its facilities, rates, accounts, services and issuance of securities. PSCo is regulated by the FERC for its wholesale electric operations, accounting practices, hydroelectric licensing, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with the NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce. PSCo is not presently a member of an RTO and does not operate within an RTO energy market. However, PSCo does make certain sales to other RTO’s, including SPP. PSCo makes wholesale electric sales at cost-based prices to customers inside PSCo’s balancing authority area and at market-based prices to customers outside PSCo’s balancing authority area as authorized by the FERC.

Fuel, Purchased Energy and Conservation Cost-Recovery

Mechanisms


•	ECA — Recovers fuel and purchased energy costs. Short-term sales margins are shared with retail customers through the ECA. The ECA is revised quarterly.


•	PCCA — Recovers purchased capacity payments.


•	SCA — Recovers the difference between PSCo’s actual cost of fuel and costs recovered under its steam service rates. The SCA rate is revised quarterly.


•	DSMCA — Recovers DSM, interruptible service costs and performance initiatives for achieving energy savings goals.


•	RESA — Recovers the incremental costs of compliance with the RES with a maximum of 2% of the customer’s bill.


•	WCA — Recovers costs for customers who choose renewable resources.


•	TCA — Recovers costs for transmission investment outside of rate cases.


•	CACJA — Recovers costs associated with the CACJA.

PSCo recovers fuel and purchased energy costs from its wholesale electric customers through a fuel cost adjustment clause approved by the FERC. Wholesale customers pay their jurisdictional allocation of production costs through a fully forecasted formula rate with true-up.

Energy Sources and Transmission Service Providers

PSCo expects to meet its system capacity requirements through electric generating stations, power purchases, new generation facilities, DSM options and expansion of generation plants.

Purchased Power — PSCo purchases power from other utilities and IPPs. Long-term purchased power contracts for dispatchable resources typically require capacity and energy charges. It also contracts to purchase power for both wind and solar resources. PSCo makes short-term purchases to meet system load and energy requirements, replace owned generation, meet operating reserve obligations, or obtain energy at a lower cost.

Purchased Transmission Services — In addition to using its own transmission system, PSCo has contracts with regional transmission service providers to deliver energy to its customers.

Wind Development — In 2018, PSCo completed construction and placed in service its Rush Creek 600 MW wind farm in Colorado.

CEP — In September 2018, the CPUC approved PSCo’s preferred CEP portfolio, which included the retirement of two coal-fired generation units, Comanche Unit 1 (in 2022) and Comanche Unit 2 (in 2025), and the following additions:



	Total Capacity	PSCo's Ownership
Wind generation	1,100 MW	500 MW
Solar generation	700 MW	—
Battery storage	275 MW	—
Natural gas generation	380 MW	380 MW

PSCo’s investment is expected to be approximately $1 billion, including transmission to support the increase in renewable generation. This investment includes the 500 MW Cheyenne Ridge wind farm and 345 KV generation tie line, as well as the Shortgrass Substation. CPCNs for these projects were filed in December 2018. A CPUC decision is anticipated by May 2019. CPCNs for the natural gas generation facility are anticipated to be filed by mid-2019.

Table of Contents

Boulder Municipalization — In 2011, Boulder passed a ballot measure authorizing the formation of an electric municipal utility, subject to certain conditions. Subsequently, there have been various legal proceedings in multiple venues with jurisdiction over Boulder’s plan. In 2014, the Boulder City Council passed an ordinance to establish an electric utility. PSCo challenged the formation of this utility and the Colorado Court of Appeals ruled in PSCo’s favor, vacating a lower court decision. In June 2018, the Colorado Supreme court rejected Boulder’s request to dismiss the case and remanded it to the Boulder District Court.

Boulder has filed multiple separation applications with the CPUC, which have been challenged by PSCo and other intervenors. In September 2017, the CPUC issued a written decision, agreeing with several key aspects of PSCo’s position. The CPUC has approved the designation of some electrical distribution assets for transfer, subject to Boulder completing certain filings. Those filings were submitted in the fourth quarter of 2018. Subsequently, various parties requested the CPUC commence additional processes; the form of such processes is currently under consideration. In the fourth quarter of 2018, Boulder’s City Council also adopted an Ordinance authorizing Boulder to begin negotiations for the acquisition of certain property or to otherwise condemn that property after Feb. 1, 2019. In the first quarter of 2019, Boulder sent PSCo a Notice of Intent to acquire certain electric distribution assets.

Boulder does not have authorization from the CPUC to initiate a condemnation proceeding at this time.

Wholesale and Commodity Marketing Operations

PSCo conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy related products. PSCo uses physical and financial instruments to minimize commodity price and credit risk and hedge sales and purchases. PSCo also engages in trading activity unrelated to hedging and sharing of any margins is determined through state regulatory proceedings as well as the operation of the FERC approved JOA.

SPS

Public Utility Regulation

Summary of Regulatory Agencies and Areas of Jurisdiction — The PUCT and NMPRC regulate SPS’ retail electric operations and have jurisdiction over its retail rates and services and the construction of transmission or generation in their respective states. The municipalities in which SPS operates in Texas have original jurisdiction over SPS’ rates in those communities. The municipalities’ rate setting decisions are subject to PUCT review.

SPS is regulated by the FERC for its wholesale electric operations, accounting practices, wholesale sales for resale, the transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers, and natural gas transactions in interstate commerce. SPS is a transmission-owning member of the SPP RTO and operates within the SPP RTO and SPP IM wholesale market. SPS is authorized to make wholesale electric sales at market-based prices.

Fuel, Purchased Energy and Conservation Cost-Recovery

Mechanisms —


•	DCRF — Recovers distribution costs not included in rates in Texas.


•	EECRF — Recovers costs for energy efficiency programs in Texas.


•	EE rider — Recovers costs for energy efficiency programs in New Mexico.


•	FPPCAC — Adjusts monthly to recover the actual fuel and purchased power costs in New Mexico.


•	PCRF — Allows recovery of purchased power costs not included in rates in Texas.


•	RPS — Recovers deferred costs for renewable energy programs in New Mexico.


•	TCRF — Recovers certain transmission infrastructure improvement costs and changes in wholesale transmission charges not included in base rates in Texas.

The fixed fuel and purchased energy recovery factor provides for the over- or under-recovery of energy expenses. Regulations require refunding or surcharging over- or under- recovery amounts, including interest, when they exceed 4% of the utility’s annual fuel and purchased energy costs on a rolling 12-month basis, if this condition is expected to continue.

SPS recovers fuel and purchased energy costs from its wholesale customers through a monthly wholesale fuel and purchased energy cost adjustment clause accepted by the FERC. Wholesale customers also pay the jurisdictional allocation of production costs.

Energy Sources and Transmission Service Providers

SPS expects to use electric generating stations, power purchases, DSM and new generation options to meet its system capacity requirements. In addition, it has evaluated water supply issues at the Tolk facility, concluding additional resource investment will be required to operate the plant through its existing life. The Ogallala aquifer has depleted more rapidly than expected. SPS installed a horizontal water well that may help delay the need for a more substantial investment solution. As a result of this issue and future environmental rules facing the plant, it sought a decrease to the remaining life of the facility in the 2017 Texas and New Mexico rate case proceedings.

Purchased Power — SPS purchases power from other utilities and IPPs. Long-term purchased power contracts typically require periodic capacity and energy charges. SPS also makes short-term purchases to meet system load and energy requirements to replace owned generation, meet operating reserve obligations or obtain energy at a lower cost.

Purchased Transmission Services — SPS has contractual arrangements with SPP and regional transmission service providers to deliver power and energy to its native load customers.

Wind Development — In 2018, the NMPRC and PUCT approved SPS’ proposal to add 1,230 MW of new wind generation, including 1,000 MW ownership.

In March 2018, the NMPRC approved SPS’ petition to build and own Sagamore, a 522 MW wind project in New Mexico which is expected to be placed into service in 2020. In May 2018, the PUCT approved SPS’ petition to build and own Hale County, a 478 MW wind project in Texas which is expected to be placed into service in 2019. Both projects qualify for 100% of PTCs. SPS’ capital investment for these wind projects is expected to be approximately $1.6 billion.

Texas State ROFR Request for Declaratory Order — In 2017, SPS and SPP filed a joint petition with the PUCT for a declaratory order regarding SPS’ ROFR. SPS contended that Texas law grants an incumbent electric utility the ROFR to construct new transmission facilities located in the utility’s service area. The PUCT subsequently issued an order finding that SPS does not possess an exclusive right to construct and operate transmission facilities. In January 2018, SPS and two other parties filed appeals in the Texas State District Court. In September 2018, the District Court affirmed the PUCT’s ROFR order. SPS has filed an additional appeal.

Table of Contents

NATURAL GAS UTILITY OPERATIONS

Natural Gas Operating Statistics



	Year Ended Dec. 31
	2018		2017		2016
Natural gas deliveries (Thousands of MMBtu)
Residential	149,036		134,189		132,853
C&I	96,447		87,271		84,082
Total retail	245,483		221,460		216,935
Transportation and other	173,092		142,497		133,498
Total deliveries	418,575		363,957		350,433

Number of customers at end of period
Residential	1,878,576		1,856,221		1,835,507
C&I	158,424		157,798		157,286
Total retail	2,037,000		2,014,019		1,992,793
Transportation and other	7,951		7,705		7,316
Total customers	2,044,951		2,021,724		2,000,109

Natural gas revenues (Millions of Dollars)
Residential	$	1,045	$	1,006	$	930
C&I	556		524		469
Total retail	1,601		1,530		1,399
Transportation and other	138		120		132
Total natural gas revenues	$	1,739	$	1,650	$	1,531

MMBtu sales per retail customer	120.51		109.96		108.86
Revenue per retail customer	$	786	$	760	$	702
Residential revenue per MMBtu	7.01		7.50		7.00
C&I revenue per MMBtu	5.76		6.00		5.58
Transportation and other revenue per MMBtu	0.80		0.84		0.99

Capability and Demand

Natural gas supply requirements are categorized as firm or interruptible (customers with an alternate energy supply).

Maximum daily send-out (firm and interruptible) and occurrence date:



	2018			2017
Utility Subsidiary	MMBtu		Date	MMBtu	Date
NSP-Minnesota	786,751	^(a)	Jan. 12	893,062	Dec. 26
NSP-Wisconsin	159,700		Jan. 5	160,170	Dec. 26
PSCo	1,903,878	^(a)	Feb. 20	1,948,167	Jan. 5


^(a)	Decrease in MMBtu output due to milder winter temperatures in 2018.

Natural gas is purchased from independent suppliers, generally based on market indices that reflect current prices, and is delivered under transportation agreements with interstate pipelines.

Contracted firm deliverable pipeline capacity as of Dec. 31:



Utility Subsidiary	MMBtu Per Day
NSP-Minnesota	645,171
NSP-Wisconsin	140,195
PSCo	1,834,843	^(a)


^(a)	Includes 871,418 MMBtu of natural gas under third-party underground storage agreements.

The utility subsidiaries contract with providers of underground natural gas storage services. Agreements provided storage of winter natural gas and peak day firm requirements for 2018 as follows:



Utility Subsidiary	Percent of Winter Requirements	Peak Day Firm Requirements
NSP-Minnesota	24%	29%
NSP-Wisconsin	30	33

PSCo also operates three company-owned underground storage facilities, which provide approximately 43,500 MMBtu of natural gas on peak days. The balance required to meet firm peak day sales obligations is primarily purchased at PSCo’s city gate meter stations.

Table of Contents

Natural Gas Supply and Costs

Xcel Energy actively seeks natural gas supply, transportation and storage alternatives to yield a diversified portfolio which provides increased flexibility, decreased interruption and financial risk and economical rates. In addition, the utility subsidiaries conduct natural gas price hedging activities approved by their respective state commissions.

Average delivered cost per MMBtu of natural gas for regulated retail distribution:



	NSP-Minnesota		NSP-Wisconsin		PSCo
2018	$	4.03	$	3.84	$	3.20
2017	3.89		3.88		3.45

NSP-Minnesota, NSP-Wisconsin and PSCo have natural gas supply transportation and storage agreements that include obligations for purchase and/or delivery of specified volumes or to make payments in lieu of delivery. As of Dec. 31, 2018, the utility subsidiaries had the following contractual obligations:


•	NSP-Minnesota — $437 million (expire 2019 - 2033);


•	NSP-Wisconsin — $89 million (expire 2019 - 2029); and,


•	PSCo — $1.1 billion (expire 2019 - 2029).

NSP-Minnesota

Public Utility Regulation

Summary of Regulatory Agencies and Areas of Jurisdiction — Retail rates, services and other aspects of NSP-Minnesota’s retail natural gas operations are regulated by the MPUC and NDPSC. The MPUC has regulatory authority over security issuances, certain property transfers, mergers with other utilities and transactions between NSP-Minnesota and its affiliates. The MPUC reviews and approves NSP-Minnesota’s natural gas supply plans for meeting future energy needs. NSP-Minnesota is subject to the jurisdiction of the FERC with respect to certain natural gas transactions in interstate commerce. NSP-Minnesota is also subject to the DOT, Minnesota Office of Pipeline Safety, NDPSC and SDPUC for pipeline safety compliance.

Purchased Gas and Conservation Cost-Recovery Mechanisms — NSP-Minnesota’s retail natural gas rates for Minnesota and North Dakota include a PGA clause that provides for prospective monthly rate adjustments to reflect the forecasted cost of purchased natural gas, transportation and storage service. The annual difference between the natural gas cost revenues collected through PGA rates and the actual natural gas costs is collected or refunded over the subsequent 12-month period.

NSP-Minnesota also recovers costs associated with transmission and distribution pipeline integrity management programs through its GUIC rider. Costs recoverable under the GUIC rider include funding for pipeline assessments as well as deferred costs from NSP-Minnesota’s existing sewer separation and pipeline integrity management programs.

NSP-Wisconsin

Public Utility Regulation

Summary of Regulatory Agencies and Areas of Jurisdiction — NSP-Wisconsin is regulated by the PSCW and MPSC. The PSCW has a biennial base-rate filing requirement. By June of each odd-numbered year, NSP-Wisconsin must submit a rate filing for the test year period beginning the following January.

NSP-Wisconsin is subject to the jurisdiction of the FERC with respect to natural gas transactions in interstate commerce. NSP-Wisconsin is subject to the DOT, PSCW and MPSC for pipeline safety compliance.

Natural Gas Cost-Recovery Mechanisms — NSP-Wisconsin has a retail PGA cost-recovery mechanism for Wisconsin to recover the actual cost of natural gas and transportation and storage services.

NSP-Wisconsin’s natural gas rates for Michigan customers include a natural gas cost-recovery factor, which is based on 12-month projections and trued-up to actual amounts on an annual basis.

PSCo

Public Utility Regulation

Summary of Regulatory Agencies and Areas of Jurisdiction — PSCo is regulated by the CPUC with respect to its facilities, rates, accounts, services and issuance of securities. PSCo holds a FERC certificate that allows it to transport natural gas in interstate commerce without PSCo becoming subject to full FERC jurisdiction. PSCo is subject to the DOT and CPUC with regards to pipeline safety compliance.

Purchased Natural Gas and Conservation Cost-Recovery Mechanisms


•	GCA — Recovers the costs of purchased natural gas and transportation to meet customer requirements and is revised quarterly to allow for changes in natural gas rates.


•	DSMCA — Recovers costs of DSM and performance initiatives to achieve various energy savings goals.


•	PSIA — Recovers costs for transmission and distribution pipeline integrity management programs.

SPS

Natural Gas Facilities Used for Electric Generation

SPS does not provide retail natural gas service, but purchases and transports natural gas for its generation facilities and operates natural gas pipeline facilities connecting the generation facilities to interstate natural gas pipelines. SPS is subject to the jurisdiction of the FERC with respect to natural gas transactions in interstate commerce and the PHMSA and PUCT for pipeline safety compliance.

GENERAL

Seasonality

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.

See Item 7 for further information.

Competition

Xcel Energy is a vertically integrated utility subject to traditional cost-of-service regulation by state public utilities commissions. Xcel Energy is subject to public policies that promote competition and development of energy markets. Xcel Energy’s industrial and large commercial customers have the ability to generate their own electricity. In addition, customers may have the option of substituting other fuels or relocating their facilities to a lower cost region.

Table of Contents

Customers have the opportunity to supply their own power with distributed generation including, but not limited to, solar generation and in most jurisdictions can currently avoid paying for most of the fixed production, transmission and distribution costs incurred to serve them. Several states have policies designed to promote the development of solar and other distributed energy resources through incentive policies. With these incentives and federal tax subsidies, distributed generating resources are potential competitors to Xcel Energy’s electric service business.

The FERC has continued to promote competitive wholesale markets through open access transmission and other means. As a result, Xcel Energy Inc.’s utility subsidiaries and their wholesale customers can purchase the output from generation resources of competing wholesale suppliers and use the transmission systems of the utility subsidiaries on a comparable basis to serve their native load.

FERC Order No. 1000 seeks to establish competition for construction and operation of certain new electric transmission facilities. State utilities commissions have also created resource planning programs that promote competition for electricity generation resources used to provide service to retail customers.

Xcel Energy Inc.’s utility subsidiaries have franchise agreements with cities subject to periodic renewal, however, a city could seek alternative means to access electric power or gas, such as municipalization.

While each of Xcel Energy Inc.’s utility subsidiaries faces these challenges, Xcel Energy believes their rates and services are competitive with the alternatives currently available.

ENVIRONMENTAL MATTERS

Xcel Energy’s facilities are regulated by federal and state environmental agencies that have jurisdiction over air emissions, water quality, wastewater discharges, solid wastes and hazardous substances. Various company activities require registrations, permits, licenses, inspections and approvals from these agencies. Xcel Energy has received all necessary authorizations for the construction and continued operation of its generation, transmission and distribution systems. Xcel Energy’s facilities have been designed and constructed to operate in compliance with applicable environmental standards and related monitoring and reporting requirements. However, it is not possible to determine when or to what extent additional facilities or modifications of existing or planned facilities will be required as a result of changes to environmental regulations, interpretations or enforcement policies or what effect future laws or regulations may have upon Xcel Energy’s operations. Xcel Energy will likely be required to incur capital expenditures in the future to comply with requirements for remediation of MGP and other legacy sites. The scope and timing of these expenditures cannot be determined until more information is obtained regarding the need for remediation at legacy sites.

In Minnesota, Texas and Wisconsin, Xcel Energy must comply with emission budgets that require the purchase of emission allowances from other utilities. The Denver North Front Range Nonattainment Area does not meet either the 2008 or 2015 ozone NAAQS. Colorado will continue to consider further reductions available in the non-attainment area as it develops plans to meet ozone standards. Gas plants which operate in PSCo’s non-attainment area may be required to improve or add controls, implement further work practices and/or implement enhanced emissions monitoring as part of future Colorado state plans.

There are significant present and future environmental regulations to encourage use of clean energy technologies and regulate emissions of GHGs. Xcel Energy has undertaken numerous initiatives to meet current requirements and prepare for potential future regulations, reduce GHG emissions and respond to state renewable and energy efficiency goals. If future environmental regulations do not provide credit for the investments Xcel Energy has already made or if they require additional initiatives or emission reductions, substantial costs may be incurred. The EPA, as an alternative to the CPP, has proposed a new regulation that, if adopted, would require implementation of heat rate improvement projects at our coal-fired power plants. It is not known what those costs might be until a final rule is adopted and state plans are developed to implement a final regulation. Xcel Energy believes, based on prior state commission practice, the cost of these initiatives or replacement generation would be recoverable through rates.

Xcel Energy is committed to addressing climate change and potential climate change regulation through efforts to reduce its GHG emissions in a balanced, cost-effective manner. Starting in 2011, Xcel Energy began reporting GHG emissions under the EPA’s mandatory GHG Reporting Program.

Xcel Energy estimates that in 2018, it reduced the CO₂ emissions associated with the electric generating resources used to serve its customers by approximately 40% from 2005 levels. This reduction accounts for emissions from electric generating plants owned by Xcel Energy as well as purchased power.

Xcel Energy primarily relied on strategies that resulted in:


•	Development of renewable energy facilities;


•	Retirement and replacement of existing generating plants; and,


•	Customer energy efficiency programs.

CAPITAL SPENDING AND FINANCING

See Item 7 for a discussion of expected capital expenditures and funding sources.

EMPLOYEES

As of Dec. 31, 2018, Xcel Energy had 11,043 full-time employees and 49 part-time employees, of which 5,129 were covered under CBAs.



	Employees Covered by CBAs	Total Employees
NSP-Minnesota	2,064	3,278
NSP-Wisconsin	386	540
PSCo	1,904	2,426
SPS	775	1,151
XES	—	3,697
Total	5,129	11,092

Table of Contents



EXECUTIVE OFFICERS ^(a)
Name	Age ^(b)	Current and Recent Positions Held	Time in Position
Ben Fowke	60	Chairman of the Board, President and Chief Executive Officer and Director, Xcel Energy Inc.	August 2011 - Present
		Chief Executive Officer, NSP-Minnesota, NSP-Wisconsin, PSCo, and SPS	January 2015 - Present
Brett C. Carter	52	Executive Vice President and Chief Customer and Innovation Officer, Xcel Energy Inc.	May 2018 - Present
		Senior Vice President and Shared Services Executive, Bank of America	October 2015 - May 2018
		Senior Vice President and Chief Operating Officer, Bank of America	March 2015 - October 2015
		Senior Vice President and Chief Distribution Officer, Duke Energy Co.	February 2013 - March 2015
Christopher B. Clark	52	President and Director, NSP-Minnesota	January 2015 - Present
		Regional Vice President, Rates and Regulatory Affairs, NSP-Minnesota	October 2012 - December 2014
David L. Eves	60	Executive Vice President and Group President, Utilities, Xcel Energy Inc.	March 2018 - Present
		President and Director, PSCo	January 2015 - February 2018
		President, Director and Chief Executive Officer, PSCo	December 2009 - December 2014
Darla Figoli	56	Senior Vice President, Human Resources & Employee Services, Chief Human Resources Officer, Xcel Energy Inc.	May 2018 - Present
		Senior Vice President, Human Resources and Employee Services, Xcel Energy Inc.	May 2015 - May 2018
		Vice President, Human Resources, Xcel Energy Inc.	February 2010 - May 2015
Robert C. Frenzel	48	Executive Vice President, Chief Financial Officer, Xcel Energy Inc.	May 2016 - Present
		Senior Vice President and Chief Financial Officer, Luminant, a subsidiary of Energy Future Holdings Corp. ^(c)	February 2012 - April 2016
David T. Hudson	58	President and Director, SPS	January 2015 - Present
		President, Director and Chief Executive Officer, SPS	January 2014 - December 2014
Alice Jackson	40	President and Director, PSCo	May 2018 - Present
		Area Vice President, Strategic Revenue Initiatives, Xcel Energy Services Inc.	November 2016 - May 2018
		Regional Vice President, Rates and Regulatory Affairs, PSCo	October 2011 - November 2016
Kent T. Larson	59	Executive Vice President and Group President Operations, Xcel Energy Inc.	January 2015 - Present
		Senior Vice President, Group President Operations, Xcel Energy Services Inc.	August 2014 - December 2014
		Senior Vice President Operations, Xcel Energy Services Inc.	September 2011 - August 2014
Timothy O’Connor	59	Senior Vice President, Chief Nuclear Officer, Xcel Energy Services Inc.	February 2013 - Present
Judy M. Poferl	59	Senior Vice President, Corporate Secretary and Executive Services, Xcel Energy Inc.	January 2015 - Present
		Vice President, Corporate Secretary, Xcel Energy Inc.	May 2013 - December 2014
Jeffrey S. Savage	47	Senior Vice President, Controller, Xcel Energy Inc.	January 2015 - Present
		Vice President, Controller, Xcel Energy Inc.	September 2011 - December 2014
Mark E. Stoering	58	President and Director, NSP-Wisconsin	January 2015 - Present
		President, Director and Chief Executive Officer, NSP-Wisconsin	January 2012 - December 2014
Scott M. Wilensky	62	Executive Vice President, General Counsel, Xcel Energy Inc.	January 2015 - Present
		Senior Vice President, General Counsel, Xcel Energy Inc.	September 2011 - December 2014

^(a)No family relationships exist between any of the executive officers or directors.

^(b)Ages as of Dec. 31, 2018.


^(c)	In April 2014, Energy Future Holdings Corp., the majority of its subsidiaries, including TCEH the parent company of Luminant, filed a voluntary bankruptcy petition. TCEH emerged from Chapter 11 in October 2016.

Table of Contents

Item 1A — Risk Factors

Xcel Energy is subject to a variety of risks, many of which are beyond our control. Risks that may adversely affect the business, financial condition, results of operations or cash flows are described below. These risks should be carefully considered together with the other information set forth in this report and future reports that Xcel Energy files with the SEC.

Oversight of Risk and Related Processes

A key accountability of the Board of Directors is the oversight of material risk, and our Board of Directors employs an effective process for doing so. Management and each Board of Directors’ committee have responsibility for overseeing the identification and mitigation of key risks and reporting its assessments and activities to the full Board of Directors.

Management identifies and analyzes risks to determine materiality and other attributes such as timing, probability and controllability. Identification and analysis occurs formally through a key risk assessment conducted by senior management, the financial disclosure process, hazard risk management procedures and internal auditing and compliance with financial and operational controls. Management also identifies and analyzes risk through its business planning process and development of goals and key performance indicators, which include risk identification to determine barriers to implementing Xcel Energy’s strategy. The business planning process also identifies areas in which there is a potential for a business area to assume inappropriate risk to meet goals and determines how to prevent inappropriate risk-taking.

Xcel Energy has a robust compliance program and promotes a culture of compliance, including tone at the top. The process for risk mitigation includes adherence to our code of conduct and compliance policies, operation of formal risk management structures and overall business management to mitigate the risks inherent in the implementation of strategy. Xcel Energy manages and further mitigates risks through formal risk management structures, including management councils, risk committees and services of corporate areas such as internal audit, corporate controller and legal.

Management communicates regularly with the Board of Directors and key stakeholders regarding risk. Senior management presents and communicates a periodic risk assessment to the Board of Directors which provides information on the risks management believes are material, including the earnings impact, timing, likelihood and controllability.

The Board of Directors approaches oversight, management and mitigation of risk as an integral and continuous part of its governance of Xcel Energy. The Board of Directors regularly reviews management’s key risk assessment and analyzes areas of existing and future risks and opportunities. In addition, the Board of Directors assigns oversight of critical risks to its four committees to ensure these risks are well understood and given appropriate focus. The Audit Committee is responsible for reviewing the adequacy of risk oversight and affirming that appropriate oversight occurs. Oversight of cybersecurity risks by the Operations, Nuclear, Environmental and Safety Committee includes receiving independent outside assessments of cybersecurity maturity and assessment of plans.

New risks are considered and assigned as appropriate during the annual Board of Directors’ and committee evaluation process. Committee charters and annual work plans are updated accordingly. Committees regularly report on their oversight activities and certain risk issues may be brought to the full Board of Directors for consideration when deemed appropriate. Finally, the Board of Directors conducts an annual strategy session where Xcel Energy’s future plans and initiatives are reviewed.

Risks Associated with Our Business

Operational Risks

Our natural gas and electric transmission and distribution operations involve numerous risks that may result in accidents and other operating risks and costs.

Our natural gas transmission and distribution activities include inherent hazards and operating risks, such as leaks, explosions, outages and mechanical problems. Our electric transmission and distribution activities also include inherent hazards and operating risks such as contact, fire and outages which could cause substantial financial losses. These natural gas and electric risks could result in loss of life, significant property damage, environmental pollution, impairment of our operations and substantial losses. We maintain insurance against some, but not all, of these risks and losses. The occurrence of these events, if not fully covered by insurance, could have a material effect on our financial condition, results of operations and cash flows.

Additionally, for natural gas costs that may be required in order to comply with potential new regulations, including the Pipeline Safety Act, could be significant.

The Pipeline Safety Act requires verification of pipeline infrastructure records by pipeline owners and operators to confirm the maximum allowable operating pressure of lines located in high consequence areas or more-densely populated areas. We have programs in place to comply with the Pipeline Safety Act and for systematic infrastructure monitoring and renewal over time. A significant incident could increase regulatory scrutiny and result in penalties and higher costs of operations.

The PHMSA is responsible for administering the DOT’s national regulatory program to assure the safe transportation of natural gas, petroleum and other hazardous materials by pipelines. The PHMSA continues to develop regulations and other approaches to risk management to assure safety in design, construction, testing, operation, maintenance and emergency response of natural gas pipeline infrastructure.

Our utility operations are subject to long-term planning risks.

Most electric utility investments are planned to be used for decades. Transmission and generation investments typically have long lead times and are planned well in advance of when they are brought in-service subject to long-term resource plans. These plans are based on numerous assumptions such as: sales growth, customer usage, commodity prices, economic activity, costs, regulatory mechanisms, customer behavior, available technology and public policy.

The electric utility sector is undergoing a period of significant change. For example, increases in appliance, lighting and energy efficiency, wider adoption and lower cost of renewable generation and distributed generation, shifts away from coal generation to decrease CO₂ emissions and increasing use of natural gas in electric generation driven by lower natural gas prices. Customer adoption of these technologies and increased energy efficiency could result in excess transmission and generation resources as well as stranded costs if Xcel Energy is not able to fully recover the costs and investments. These changes also introduce additional uncertainty into long-term planning which gives rise to a risk that the magnitude and timing of resource additions and growth in customer demand may not coincide and that the preference for the types of additions may change from planning to execution. In addition, we are subject to longer-term availability of the natural resource inputs such as coal, natural gas, uranium and water to cool our facilities. Lack of availability of these resources could jeopardize long-term operations of our facilities or make them uneconomic to operate.

Table of Contents

Changing customer expectations and technologies are requiring significant investments in advanced grid infrastructure. This increases the exposure to potential outdating of technologies and resultant risks. The inability of coal mining companies to attract capital could disrupt longer-term supplies. Decreasing use per customer driven by appliance and lighting efficiency and the availability of cost-effective distributed generation places downward pressure on sales growth. This may lead to under recovery of costs, excess resources to meet customer demand and increases in electric rates. Finally, multiple states may not agree as to the appropriate resource mix and the differing views may lead to costs incurred to comply with one jurisdiction that are not recoverable across all of the jurisdictions served by the same assets.

Our subsidiary, NSP-Minnesota, is subject to the risks of nuclear generation.

NSP-Minnesota’s two nuclear stations, PI and Monticello, subject it to the risks of nuclear generation, which include:


•	Risks associated with use of radioactive material in the production of energy, the management, handling, storage and disposal of radioactive materials;


•	Limitations on insurance available to cover losses that might arise in connection with nuclear operations, as well as obligations to contribute to an insurance pool in the event of damages at a covered U.S. reactor; and,


•	Uncertainties with the technological and financial aspects of decommissioning nuclear plants. For example, assumptions regarding decommissioning costs may change based on economic conditions and changes in the expected life of the asset may cause our funding obligations to change.

The NRC has authority to impose licensing and safety-related requirements for the operation of nuclear generation facilities. The NRC has the authority to impose fines and/or shut down a unit until compliance is achieved. Revised NRC safety requirements could necessitate substantial capital expenditures or an increase in operating expenses. In addition, the Institute for Nuclear Power Operations reviews NSP-Minnesota’s nuclear operations and nuclear generation facilities. Compliance with the Institute for Nuclear Power Operations’ recommendations could result in substantial capital expenditures or a substantial increase in operating expenses.

If an incident did occur, it could have a material effect on our results of operations, financial condition or cash flows. Furthermore, the non-compliance or the occurrence of a serious incident at other nuclear facilities could result in increased regulation of the industry, which may increase NSP-Minnesota’s compliance costs.

NSP-Wisconsin’s production and transmission system is operated on an integrated basis with NSP-Minnesota. NSP-Wisconsin may be subject to risks associated with NSP-Minnesota’s nuclear generation.

We are subject to commodity risks and other risks associated with energy markets and energy production.

If fuel costs increase, customer demand could decline and bad debt expense may rise, which could have a material impact on our results of operations. While we have fuel clause recovery mechanisms in most of our states, higher fuel costs could significantly impact our results of operations if costs are not recovered. Delays in the timing of the collection of fuel cost recoveries could impact our cash flows. Low fuel costs have a positive impact on sales, however low oil and natural gas prices could negatively impact oil and gas production activities and subsequently our sales volumes and revenue.

A significant disruption in supply could cause us to seek alternative supply services at potentially higher costs or suffer increased liability for unfulfilled contractual obligations. Significantly higher energy or fuel costs relative to sales commitments have a negative impact on our cash flows and potentially result in economic losses. Potential market supply shortages may not be fully resolved through alternative supply sources and could cause disruptions in our ability to provide electric and/or natural gas services to our customers. Failure to provide service due to disruptions may also result in fines, penalties or cost disallowances through the regulatory process.

We also engage in wholesale sales and purchases of electric capacity, energy and energy-related products as well as natural gas. In many markets, emission allowances and/or RECs are also needed to comply with various statutes and commission rulings. As a result we are subject to market supply and commodity price risk. Commodity price changes can affect the value of our commodity trading derivatives. We mark certain derivatives to estimated fair market value on a daily basis. Actual settlements can vary significantly from estimated fair values recorded and significant changes from the assumptions underlying our fair value estimates could cause earnings variability.

Financial Risks

Our profitability depends on the ability of our utility subsidiaries to recover their costs and changes in regulation may impair the ability of our utility subsidiaries to recover costs from their customers.

We are subject to comprehensive regulation by federal and state utility regulatory agencies, including siting and construction of facilities, customer service and the rates that we can charge customers.

The profitability of our utility operations is dependent on our ability to recover the costs of providing energy and utility services and earn a return on our capital investment. Our rates are generally regulated and based on an analysis of the utility’s costs incurred in a test year. Our utility subsidiaries are subject to both future and historical test years depending upon the regulatory jurisdiction. Thus, the rates a utility is allowed to charge may or may not match its costs at any given time. Rate regulation is premised on providing an opportunity to earn a reasonable rate of return on invested capital. In a continued low interest rate environment there has been pressure pushing down ROE. There can also be no assurance that our regulatory commissions will judge all the costs of our utility subsidiaries to be prudent, which could result in disallowances, or that the regulatory process will always result in rates that will produce full recovery. Changes in the long-term cost-effectiveness or changes to the operating conditions of our assets may result in early retirements of utility facilities and while regulation typically provides relief for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs leaving all or a portion of these asset costs stranded. Higher than expected inflation or tariffs may increase costs of construction and operations. Rising fuel costs could increase the risk that our utility subsidiaries will not be able to fully recover their fuel costs from their customers. Furthermore, there could be changes in the regulatory environment that would impair the ability of our utility subsidiaries to recover costs historically collected from their customers, or these factors could cause the operating utilities to exceed commitments made regarding cost caps and result in less than full recovery. Overall, management currently believes prudently incurred costs are recoverable given the existing regulatory mechanisms in place.

Adverse regulatory rulings or the imposition of additional regulations could have an adverse impact on our results of operations and materially affect our ability to meet our financial obligations, including debt payments and the payment of dividends on our common stock.

Table of Contents

Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships.

We cannot be assured that our current ratings or our subsidiaries’ ratings will remain in effect, or that a rating will not be lowered or withdrawn by a rating agency. Significant events including disallowance of costs, significantly lower returns on equity or equity ratios or impacts of tax policy changes may impact our cash flows and credit metrics, potentially resulting in a change in our credit ratings. In addition, our credit ratings may change as a result of the differing methodologies or change in the methodologies used by the various rating agencies.

Any downgrade could lead to higher borrowing costs and could impact our ability to access capital markets. Also, our utility subsidiaries may enter into contracts that require the posting of collateral or settlement of applicable contracts if credit ratings fall below investment grade.

We are subject to capital market and interest rate risks.

Utility operations require significant capital investment. As a result, we frequently need to access capital markets. Any disruption in capital markets could have a material impact on our ability to fund our operations. Capital markets are global and impacted by issues and events throughout the world. Capital market disruption events and financial market distress could prevent us from issuing short-term commercial paper, issuing new securities or cause us to issue securities with unfavorable terms and conditions, such as higher interest rates.

Higher interest rates on short-term borrowings with variable interest rates could also have an adverse effect on our operating results. Changes in interest rates may also impact the fair value of the debt securities in the nuclear decommissioning and/or pension funds, as well as our ability to earn a return on short-term investments of excess cash.

We are subject to credit risks.

Credit risk includes the risk that our customers will not pay their bills, which may lead to a reduction in liquidity and an increase in bad debt expense. Credit risk is comprised of numerous factors including the price of products and services provided, the overall economy and local economies in the geographic areas we serve, including local unemployment rates.

Credit risk also includes the risk that various counterparties that owe us money or product will become insolvent and/or breach their obligations. Should the counterparties fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected and incur losses.

We may at times have direct credit exposure in our short-term wholesale and commodity trading activity to financial institutions trading for their own accounts or issuing collateral support on behalf of other counterparties. We may also have some indirect credit exposure due to participation in organized markets, such as CAISO, SPP, PJM, MISO and Electric Reliability Council of Texas, in which any credit losses are socialized to all market participants.

We have additional indirect credit exposures to financial institutions in the form of letters of credit provided as security by power suppliers under various purchased power contracts. If any of the credit ratings of the letter of credit issuers were to drop below investment grade, the supplier would need to replace that security with an acceptable substitute. If the security were not replaced, the party could be in default under the contract.

Increasing costs of our defined benefit retirement plans and employee benefits may adversely affect our results of operations, financial condition or cash flows.

We have defined benefit pension and postretirement plans that cover most of our employees. Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements related to these plans. Estimates and assumptions may change. In addition, the Pension Protection Act changed the minimum funding requirements for defined benefit pension plans. Therefore, our funding requirements and related contributions may change in the future. Also, the payout of a significant percentage of pension plan liabilities in a single year due to high retirements or employees leaving could trigger settlement accounting and could require Xcel Energy to recognize incremental pension expense related to unrecognized plan losses in the year liabilities are paid.

Increasing costs associated with health care plans may adversely affect our results of operations.

Our self-insured costs of health care benefits for eligible employees have increased in recent years. Increasing levels of large individual health care claims and overall health care claims could have an adverse impact on our results of operations, financial condition or cash flows. Changes in industry standards utilized in key assumptions (e.g., mortality tables) could have a significant impact on future liabilities and benefit costs. Legislation related to health care could also significantly change our benefit programs and costs.

We must rely on cash from our subsidiaries to make dividend payments.

We are a holding company and investments in our subsidiaries are our primary assets. Substantially all of our operations are conducted by our subsidiaries. Consequently, our operating cash flow and ability to service our debt and pay dividends depends upon the operating cash flows of our subsidiaries and their payment of dividends. Our subsidiaries are separate legal entities that have no obligation to pay any amounts due pursuant to our obligations or to make any funds available for dividends on our common stock. In addition, each subsidiary’s ability to pay dividends depends on statutory and/or contractual restrictions which may include requirements to maintain minimum levels of equity ratios, working capital or assets. Also, our utility subsidiaries are regulated by state utility commissions, which possess broad powers to ensure that the needs of the utility customers are being met.

If our utility subsidiaries were to cease making dividend payments, our ability to pay dividends on our common stock or otherwise meet our financial obligations could be adversely affected.

Federal tax law may significantly impact our business.

Xcel Energy’s utility subsidiaries collect through regulated rates estimated federal, state and local tax payments. Changes to federal tax law may benefit or adversely affect our earnings and customer costs. Changes to tax depreciable lives and the value of various tax credits may change the economics of resources and our resource selections. There could be timing delays before regulated rates provide for realization of the tax changes in revenues. In addition, certain IRS tax policies such as the requirement to utilize normalization may impact our ability to economically deliver certain types of resources relative to market prices.

Table of Contents

Macroeconomic Risks

Economic conditions impact our business.

Our operations are affected by local, national and worldwide economic conditions. Growth in customers and sales are correlated with economic conditions.

Economic conditions may be impacted by insufficient financial sector liquidity leading to potential increased unemployment, which may impact customers’ ability to pay timely, increase customer bankruptcies, and may lead to additional bad debt expense.

Further, worldwide economic activity impacts the demand for basic commodities necessary for utility infrastructure, which may impact our ability to acquire sufficient supplies. We operate in a capital intensive industry and federal policy on trade could significantly impact the cost of materials we use. We could be at risk for higher costs for materials and our workforce. There may be delays before these additional costs can be recovered in rates.

Our operations could be impacted by war, acts of terrorism, and threats of terrorism or disruptions due to events.

Our generation plants, fuel storage facilities, transmission and distribution facilities and information and control systems may be targets of terrorist activities. Any disruption could impact operations or result in a decrease in revenues and additional costs to repair and insure our assets. These disruptions could have a material impact on our financial condition, results of operations or cash flows. The potential for terrorism has subjected our operations to increased risks and could have a material effect on our business. We have already incurred increased costs for security and capital expenditures in response to these risks.

The insurance industry has also been affected by these events and the availability of insurance may decrease. In addition, insurance may have higher deductibles, higher premiums and more restrictive policy terms.

A disruption of the regional electric transmission grid, interstate natural gas pipeline infrastructure or other fuel sources, could negatively impact our business, our brand and reputation. Because our facilities are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by the actions of a neighboring utility or an event (e.g., severe storm, severe temperature extremes, wildfires, generator or transmission facility outage, pipeline rupture, railroad disruption, operator error, sudden and significant increase or decrease in wind generation or a disruption of work force) within our operating systems or on a neighboring system. Any such disruption could result in a significant decrease in revenues and significant additional costs to repair assets, which could have a material impact on our results of operations, financial condition or cash flows.

A cyber incident or security breach could have a material effect on our business.

We operate in an industry that requires the continued operation of sophisticated information technology, control systems and network infrastructure. In addition, we use our systems and infrastructure to create, collect, use, disclose, store, dispose of and otherwise process sensitive information, including company data, customer energy usage data, and personal information regarding customers, employees and their dependents, contractors, shareholders and other individuals.

Our generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets, as well as information processed in our systems (e.g., information regarding our customers, employees, operations, infrastructure and assets) could be affected by cyber security incidents, including those caused by human error.

Our industry has begun to see an increased volume and sophistication of cyber security incidents from international activist organizations, Nation States and individuals. Cyber security incidents could harm our businesses by limiting our generating, transmitting and distributing capabilities, delaying our development and construction of new facilities or capital improvement projects to existing facilities, disrupting our customer operations or causing the release of customer information, all of which could expose us to liability.

Our generation, transmission systems and natural gas pipelines are part of an interconnected system. Therefore, a disruption caused by the impact of a cyber security incident of the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources of our third party service providers’ operations, could also negatively impact our business.

Our supply chain for procurement of digital equipment may expose software or hardware to these risks and could result in a breach or significant costs of remediation. In addition, such an event would likely receive federal and state regulatory scrutiny. We are unable to quantify the potential impact of cyber security threats or subsequent related actions. These potential cyber security incidents and regulatory action could result in a material decrease in revenues and may cause significant additional costs (e.g., penalties, third party claims, repairs, insurance or compliance) and potentially disrupt our supply and markets for natural gas, oil and other fuels.

We maintain security measures to protect our information technology and control systems, network infrastructure and other assets. However, these assets and the information they process may be vulnerable to cyber security incidents, including the resulting disability, or failures of assets or unauthorized access to assets or information. If our technology systems or those of our third-party service providers were to fail or be breached, we may be unable to fulfill critical business functions. We are unable to quantify the potential impact of cyber security incidents on our business, our brand, and our reputation. The cyber security threat is dynamic and evolves continually, and our efforts to prioritize network monitoring may not be effective given the constant changes to threat vulnerability.

Our operating results may fluctuate on a seasonal and quarterly basis and can be adversely affected by milder weather.

Our electric and natural gas utility businesses are seasonal and weather patterns can have a material impact on our operating performance. Demand for electricity is often greater in the summer and winter months associated with cooling and heating. Because natural gas is heavily used for residential and commercial heating, the demand depends heavily upon weather patterns. A significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. Unusually mild winters and summers could have an adverse effect on our financial condition, results of operations or cash flows.

Our operations use third party contractors in addition to employees to perform periodic and on-going work.

We rely on third party contractors to perform work for operations, maintenance and construction. We have contractual arrangements with these contractors which typically include performance standards, progress payments, insurance requirements and security for performance.

Cyber security breaches have at times exploited third party equipment or software in order to gain access. Poor vendor performance could impact on going operations, restoration operations, our reputation and could introduce financial risk or risks of fines.

Table of Contents

Public Policy Risks

We may be subject to legislative and regulatory responses to climate change, with which compliance could be difficult and costly.

Legislative and regulatory responses related to climate change and new interpretations of existing laws create financial risk as our facilities may be subject to additional regulation at either the state or federal level in the future. Such regulations could impose substantial costs on our system.

We may be subject to climate change lawsuits. An adverse outcome could require substantial capital expenditures and could possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant. Such payments or expenditures could affect results of operations, financial condition or cash flows if such costs are not recovered through regulated rates.

Although the United States has not adopted any international or federal GHG emission reduction targets, many states and localities may continue to pursue climate policies in the absence of federal mandates. All of the steps that Xcel Energy has taken to date to reduce GHG emissions, including energy efficiency measures, adding renewable generation or retiring or converting coal plants to natural gas, occurred under state-endorsed resource plans, renewable energy standards and other state policies. While those actions likely would have put Xcel Energy in a good position to meet federal or international standards being discussed, the lack of federal action does not adversely impact these state-endorsed actions and plans.

If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material effect on our results of operations, financial condition or cash flows.

Increased risks of regulatory penalties could negatively impact our business.

The Energy Act increased civil penalty authority for violation of FERC statutes, rules and orders. The FERC can impose penalties of up to $1.3 million per violation per day, particularly as it relates to energy trading activities for both electricity and natural gas. In addition, NERC electric reliability standards and critical infrastructure protection requirements are mandatory and subject to potential financial penalties. Additionally, the PHMSA, Occupational Safety and Health Administration and other federal agencies have penalty authority. In the event of serious incidents, these agencies have become more active in pursuing penalties. Some states have the authority to impose substantial penalties. If a serious reliability or safety incident did occur, it could have a material effect on our results of operations, financial condition or cash flows.

Environmental Risks

We are subject to environmental laws and regulations, with which compliance could be difficult and costly.

We are subject to environmental laws and regulations that affect many aspects of our operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances. Laws and regulations require us to obtain permits, licenses, and approvals and to comply with a variety of environmental requirements.

Environmental laws and regulations can also require us to restrict or limit the output of facilities or the use of certain fuels, shift generation to lower-emitting, install pollution control equipment, clean up spills and other contamination and correct environmental hazards. Environmental regulations may also lead to shutdown of existing facilities.

Failure to meet requirements of environmental mandates may result in fines or penalties. We may be required to pay all or a portion of the cost to remediate (i.e., clean-up) sites where our past activities, or the activities of other parties, caused environmental contamination.

We are subject to mandates to provide customers with clean energy, renewable energy and energy conservation offerings. It could have a material effect on our results of operations, financial condition or cash flows if our regulators do not allow us to recover the cost of capital investment or the O&M costs incurred to comply with the requirements.

In addition, existing environmental laws or regulations may be revised and new laws or regulations may be adopted. We may also incur additional unanticipated obligations or liabilities under existing environmental laws and regulations.

We are subject to physical and financial risks associated with climate change and other weather, natural disaster and resource depletion impacts.

Climate change can create physical and financial risk. Physical risks include changes in weather conditions and extreme weather events.

Our customers’ energy needs vary with weather. To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease. Increased energy use due to weather changes may require us to invest in generating assets, transmission and infrastructure. Decreased energy use due to weather changes may result in decreased revenues. Extreme weather conditions in general require system backup, costs, and can contribute to increased system stress, including service interruptions. Extreme weather conditions creating high energy demand may raise electricity prices, increasing the cost of energy we provide to our customers.

Severe weather impacts our service territories, primarily when thunderstorms, flooding, tornadoes, wildfires and snow or ice storms occur. To the extent the frequency of extreme weather events increases, this could increase our cost of providing service. Periods of extreme temperatures could impact our ability to meet demand. Changes in precipitation resulting in droughts or water shortages could adversely affect our operations. Drought conditions also contribute to the increase in wildfire risk from our electric generation facilities. While we carry liability insurance, given an extreme event, if Xcel Energy was found to be liable for wildfire damages, amounts that potentially exceed our coverage could negatively impact our results of operations, financial condition or cash flows. Drought or water depletion could adversely impact our ability to provide electricity to customers and increase the price paid for energy. We may not recover all costs related to mitigating these physical and financial risks.

Climate change may impact a region’s economy, which could impact our sales and revenues. The price of energy has an impact on the economic health of our communities. The cost of additional regulatory requirements, such as regulation of GHG, could impact the availability of goods and prices charged by our suppliers which would normally be borne by consumers through higher prices for energy and purchased goods. To the extent financial markets view climate change and emissions of GHGs as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less than ideal terms and conditions.

Item 1B — Unresolved Staff Comments

None.

Table of Contents

Item 2 — Properties

Virtually all of the utility plant property of NSP-Minnesota, NSP-Wisconsin, SPS and PSCo is subject to the lien of their first mortgage bond indentures.

Electric Generating Stations:



NSP-Minnesota Station, Location and Unit	Fuel	Installed	MW ^(a)
Steam:
A.S. King-Bayport, MN, 1 Unit	Coal	1968	511
Sherco-Becker, MN
Unit 1	Coal	1976	680
Unit 2	Coal	1977	682
Unit 3	Coal	1987	517	^(b)
Monticello, MN, 1 Unit	Nuclear	1971	617
PI-Welch, MN
Unit 1	Nuclear	1973	521
Unit 2	Nuclear	1974	519
Various locations, 4 Units	Wood/Refuse	Various	36	^(c)
Combustion Turbine:
Angus Anson-Sioux Falls, SD, 3 Units	Natural Gas	1994 - 2005	327
Black Dog-Burnsville, MN, 3 Units	Natural Gas	1987 - 2002	494	^(d)
Blue Lake-Shakopee, MN, 6 Units	Natural Gas	1974 - 2005	453
High Bridge-St. Paul, MN, 3 Units	Natural Gas	2008	530
Inver Hills-Inver Grove Heights, MN, 6 Units	Natural Gas	1972	282
Riverside-Minneapolis, MN, 3 Units	Natural Gas	2009	454
Various locations, 14 Units	Natural Gas	Various	67
Wind:
Border-Rolette County, ND, 75 Units	Wind	2015	148	^(e)
Courtenay Wind, ND, 100 Units	Wind	2016	195	^(e)
Grand Meadow-Mower County, MN, 67 Units	Wind	2008	101	^(e)
Nobles-Nobles County, MN., 134 Units	Wind	2010	200	^(e)
Pleasant Valley-Mower County, MN, 100 Units	Wind	2015	196	^(e)
		Total	7,530


^(a)	Summer 2018 net dependable capacity.


^(b)	Based on NSP-Minnesota’s ownership of 59%.


^(c)	Refuse-derived fuel is made from municipal solid waste.


^(d)	Black Dog Unit 6 was commissioned and placed into operation in the third quarter of 2018.


^(e)	Values disclosed are the maximum generation levels for these wind units. Capacity is attainable only when wind conditions are sufficiently available (on-demand net dependable capacity is zero).



NSP-Wisconsin Station, Location and Unit	Fuel	Installed	MW ^(a)
Steam:
Bay Front-Ashland, WI, 3 Units	Coal/Wood/Natural Gas	1948 - 1956	56
French Island-La Crosse, WI, 2 Units	Wood/Refuse	1940 - 1948	16	^(b)
Combustion Turbine:
French Island-La Crosse, WI, 2 Units	Oil	1974	122
Wheaton-Eau Claire, WI, 5 Units	Natural Gas/Oil	1973	234
Hydro:
Various locations, 63 Units	Hydro	Various	135
		Total	563


^(a)	Summer 2018 net dependable capacity.


^(b)	Refuse-derived fuel is made from municipal solid waste.



PSCo Station, Location and Unit	Fuel	Installed	MW ^(a)
Steam:
Comanche-Pueblo, CO ^(b)
Unit 1	Coal	1973	325
Unit 2	Coal	1975	335
Unit 3	Coal	2010	500	^(c)
Craig-Craig, CO, 2 Units ^(d)	Coal	1979 - 1980	82	^(e)
Hayden-Hayden, CO, 2 Units	Coal	1965 - 1976	233	^(f)
Pawnee-Brush, CO, 1 Unit	Coal	1981	505
Cherokee-Denver, CO, 1 Unit	Natural Gas	1968	310
Combustion Turbine:
Blue Spruce-Aurora, CO, 2 Units	Natural Gas	2003	264
Cherokee-Denver, CO, 3 Units	Natural Gas	2015	576
Fort St. Vrain-Platteville, CO, 6 Units	Natural Gas	1972 - 2009	968
Rocky Mountain-Keenesburg, CO, 3 Units	Natural Gas	2004	580
Various locations, 6 Units	Natural Gas	Various	171
Hydro:
Cabin Creek-Georgetown, CO
Pumped Storage, 2 Units	Hydro	1967	210
Various locations, 9 Units	Hydro	Various	26
Wind:
Rush Creek, CO, 300 units	Wind	2018	600	^(g)
		Total	5,685


^(a)	Summer 2018 net dependable capacity.


^(b)	In 2018, the CPUC approved early retirement of PSCo’s Comanche Units 1 and 2 in 2022 and 2025, respectively.


^(c)	Based on PSCo’s ownership of 67%.


^(d)	Craig Unit 1 is expected to be retired early in 2025.


^(e)	Based on PSCo’s ownership of 10%.


^(f)	Based on PSCo’s ownership of 75% of Unit 1 and 37% of Unit 2.


^(g)	Generation capability is based on the maximum output level of wind units, including the Rush Creek Wind Project. Capacity is attainable only when wind conditions are sufficiently available (on-demand net dependable capacity is zero).



SPS Station, Location and Unit	Fuel	Installed	MW ^(a)
Steam:
Cunningham-Hobbs, NM, 2 Units	Natural Gas	1957 - 1965	251
Harrington-Amarillo, TX, 3 Units	Coal	1976 - 1980	1,018
Jones-Lubbock, TX, 2 Units	Natural Gas	1971 - 1974	486
Maddox-Hobbs, NM, 1 Unit	Natural Gas	1967	112
Nichols-Amarillo, TX, 3 Units	Natural Gas	1960 - 1968	457
Plant X-Earth, TX, 4 Units	Natural Gas	1952 - 1964	411
Tolk-Muleshoe, TX, 2 Units	Coal	1982 - 1985	1,067
Combustion Turbine:
Cunningham-Hobbs, NM, 2 Units	Natural Gas	1998	209
Jones-Lubbock, TX, 2 Units	Natural Gas	2011 - 2013	334
Maddox-Hobbs, TX, 1 Unit	Natural Gas	1963 - 1976	61
		Total	4,406


^(a)	Summer 2018 net dependable capacity.

Table of Contents

Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2018:



Conductor Miles	NSP-Minnesota	NSP-Wisconsin	PSCo	SPS
500 KV	2,917	—	—	—
345 KV	13,560	3,415	4,062	9,028
230 KV	2,202	—	12,053	9,675
161 KV	615	1,823	—	—
138 KV	—	—	91	—
115 KV	7,372	1,817	5,051	14,493
Less than 115 KV	86,185	32,831	78,446	25,820

Electric utility transmission and distribution substations at Dec. 31, 2018:



	NSP-Minnesota	NSP-Wisconsin	PSCo	SPS
Quantity	348	203	232	459

Natural gas utility mains at Dec. 31, 2018:



Miles	NSP-Minnesota	NSP-Wisconsin	PSCo	SPS	WGI
Transmission	90	3	2,080	20	11
Distribution	10,437	2,466	22,518	—	—

Item 3 — Legal Proceedings

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

See Note 12 to the consolidated financial statements, Item 1 and Item 7 for further information.

Item 4 — Mine Safety Disclosures

None.

PART II

Item 5 — Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Stock Data

Xcel Energy Inc.’s common stock was listed on the New York Stock Exchange (NYSE) in 2017, but moved to the Nasdaq Global Select Market (Nasdaq) in 2018. The trading symbol is XEL. The number of common stockholders of record as of Dec. 31, 2018 was approximately 57,059.

See Item 7 for further information.

The following compares our cumulative TSR on common stock with the cumulative TSR of the EEI Investor-Owned Electrics Index and the Standard & Poor’s 500 Composite Stock Price Index over the last five years (assuming a $100 investment on Dec. 31, 2013, and the reinvestment of all dividends).

The EEI Investor-Owned Electrics Index (market capitalization-weighted) included 42 companies at year-end and is a broad measure of industry performance.

COMPARISON OF FIVE YEAR CUMULATIVE TOTAL RETURN*

Xcel Energy Inc., the EEI Investor-Owned Electrics and the Standard & Poor’s 500


*	$100 invested on Dec. 31, 2013 in stock or index — including reinvestment of dividends. Fiscal years ended Dec. 31.

Table of Contents

Securities Authorized for Issuance Under Equity Compensation Plans

Information required under Item 5 — Securities Authorized for Issuance Under Equity Compensation Plans is contained in Xcel Energy Inc.’s Proxy Statement for its 2018 Annual Meeting of Shareholders, which is incorporated by reference.

Purchases of Equity Securities by Issuer and Affiliated Purchasers

For the quarter ended Dec. 31, 2018, no equity securities that are registered by Xcel Energy Inc. pursuant to Section 12 of the Securities Exchange Act of 1934 were purchased by or on behalf of us or any of our affiliated purchasers.

Item 6 — Selected Financial Data

Selected financial data for Xcel Energy related to the five most recent years ended Dec. 31.



(Millions of Dollars, Millions of Shares, Except Per Share Data)	2018		2017		2016		2015		2014
Operating revenues	$	11,537	$	11,404	$	11,107	$	11,024	$	11,686
Operating expenses ^(a)	9,572		9,181		8,867		9,024		9,738
Net income	1,261		1,148		1,123		984		1,021
Earnings available to common shareholders	1,261		1,148		1,123		984		1,021
Diluted earnings per common share	2.47		2.25		2.21		1.94		2.03
Financial information
Dividends declared per common share	1.52		1.44		1.36		1.28		1.20
Total assets ^{(b) (c)}	45,987		43,030		41,155		38,821		36,958
Long-term debt ^(c) ^(d)	15,803		14,520		14,195		12,399