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, ~~2017~~2018



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

~~Commission File Number: 001-3280~~

~~Public Service Company of Colorado~~

~~(Exact name of registrant as specified in its charter)~~



~~Colorado~~001-03280		84-0296600
(~~State or other jurisdiction of incorporation or organization)~~Commission File Number)		(I.R.S. Employer Identification No.)

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

Public Service Company of Colorado

(a Colorado corporation)

1800 Larimer, Suite 1100

Denver, ~~Colorado~~CO 80202

~~(Address of principal executive offices)~~303-571-7511

~~Registrant’s telephone number, including area code:~~ ~~(303) 571-7511~~

Securities registered pursuant to Section 12(b) of the Act: None

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 ~~and posted on its corporate Web site, if any,~~ every Interactive Data File required to be submitted ~~and posted~~ 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 ~~and post~~ 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. x

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.



¨Large accelerated filer ¨ Accelerated filer x Non-accelerated filer ¨ Smaller Reporting Company ¨ Emerging growth company¨		~~Accelerated filer~~ ¨
~~Non-accelerated filer~~ x		~~Smaller reporting company~~ ¨
~~(Do not check if smaller reporting company)~~		~~Emerging growth company~~ ¨

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

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

As of Feb. ~~23, 2018~~22, 2019, 100 shares of common stock, par value $0.01 per share, were outstanding, all of which were held by Xcel Energy Inc., a Minnesota ~~corporation.~~corporation.

DOCUMENTS INCORPORATED BY REFERENCE

The information required by Item 14 of Form 10-K is set forth under the heading “Independent Registered Public Accounting Firm – Audit and Non-Audit Fees” in Xcel Energy Inc.’s definitive Proxy Statement for the ~~2018~~2019 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about April ~~3, 2018.~~1, 2019. Such information set forth under such heading is incorporated herein by this reference hereto.

Public Service Company of Colorado meets the conditions set forth in General Instructions I(1)(a) and (b) of Form 10-K and is therefore filing this form with reduced disclosure format permitted by General Instruction I(2).

TABLE OF CONTENTS

Index



PART I
Item 1 — Business	3
~~DEFINITION OF~~ ABBREVIATIONS AND INDUSTRY TERMS	3
FORWARD-LOOKING STATEMENTS	4
WHERE TO FIND MORE INFORMATION	4
COMPANY OVERVIEW	54
ELECTRIC UTILITY OPERATIONS	5
~~Public Utility Regulation~~Electric Operating Statistics	5
Energy Sources	6
Capacity and Demand	6
~~Energy Sources and Related Transmission Initiatives~~Public Utility Regulation	67
~~Fuel Supply~~Energy Sources and ~~Costs~~Transmission Service Providers	8
~~Fuel Sources~~	8
~~Renewable Energy Sources~~	97
Wholesale and Commodity Marketing Operations	9
~~Summary of Recent Regulatory Developments~~	9
~~Electric Operating Statistics~~	107
NATURAL GAS UTILITY OPERATIONS	118
~~Overview~~Natural Gas Operating Statistics	11
~~Public Utility Regulation~~	118
Capability and Demand	128
Natural Gas Supply and Costs	128
~~Natural Gas Operating Statistics~~Public Utility Regulation	138
GENERAL	139
ENVIRONMENTAL MATTERS	149
EMPLOYEES	149
Item 1A — Risk Factors	149
Item 1B — Unresolved Staff Comments	2314
Item 2 — Properties	2415
Item 3 — Legal Proceedings	2515
Item 4 — Mine Safety Disclosures	2515

PART II
Item 5 — Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	2515
Item 6 — Selected Financial Data	2515
Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations	2515
Item 7A — Quantitative and Qualitative Disclosures About Market Risk	2818
Item 8 — Financial Statements and Supplementary Data	3019
Item 9 — Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	8045
Item 9A — Controls and Procedures	8046
Item 9B — Other Information	8046

PART III
Item 10 — Directors, Executive Officers and Corporate Governance	8046
Item 11 — Executive Compensation	8046
Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	8146
Item 13 — Certain Relationships and Related Transactions, and Director Independence	8146
Item 14 — Principal Accountant Fees and Services	8146

PART IV
Item 15 — Exhibits, Financial Statement Schedules	8247
Item 16 — Form 10-K Summary	8549

SIGNATURES	8650

This Form 10-K is filed by PSCo. PSCo is a wholly owned subsidiary of Xcel Energy Inc. Additional information on Xcel Energy is available in various filings with the SEC. This report should be read in its entirety.

PART I

Item l — Business

~~DEFINITION OF~~ ABBREVIATIONS AND INDUSTRY TERMS



Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former)
~~NCE~~	~~New Century Energies, Inc.~~
NSP-Minnesota	Northern States Power Company, a Minnesota corporation
NSP-Wisconsin	Northern States Power Company, a Wisconsin corporation
PSCo	Public Service Company of Colorado
~~PSRI~~	~~P.S.R. Investments, Inc.~~
SPS	Southwestern Public Service Company
Utility subsidiaries	NSP-Minnesota, NSP-Wisconsin, PSCo and SPS
WYCO	WYCO Development, LLC
Xcel Energy	Xcel Energy Inc. and subsidiaries

Federal and State Regulatory Agencies
~~CFTC~~	~~Commodity Futures Trading Commission~~
CPUC	Colorado Public Utilities Commission
D.C. Circuit	United States Court of Appeals for the District of Columbia Circuit
DOT	United States Department of Transportation
EPA	United States Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
IRS	Internal Revenue Service
NERC	North American Electric Reliability Corporation
PHMSA	Pipeline and Hazardous Materials Safety Administration
SEC	Securities and Exchange Commission

Electric, Purchased Gas and Resource Adjustment Clauses
DSM	Demand side management
DSMCA	Demand side management cost adjustment
ECA	Retail electric commodity adjustment
GCA	Gas cost adjustment
PCCA	Purchased capacity cost adjustment
PSIA	Pipeline system integrity adjustment
RESA	Renewable energy standard adjustment
SCA	Steam cost adjustment
TCA	Transmission cost adjustment
WCA	Windsource^® cost adjustment

Other ~~Terms and Abbreviations~~
AFUDC	Allowance for funds used during construction
~~ALJ~~ARAM	~~Administrative law judge~~
~~APBO~~	~~Accumulated postretirement benefit obligation~~Average rate assumption method
ARO	Asset retirement obligation
~~ASC~~	~~FASB Accounting Standards Codification~~
ASU	FASB Accounting Standards Update
Boulder	City of Boulder, CO
C&I	Commercial and Industrial
~~CAISO~~	~~California Independent System Operator~~
~~CAA~~	~~Clean Air Act~~
CACJA	Clean Air Clean Jobs Act
CO₂ CCR	~~Carbon dioxide~~

Coal combustion residuals
CEP	Colorado Energy Plan
CIG	Colorado Interstate Gas Company, LLC
Corps	U.S. Army Corps of Engineers
CPCN	Certificate of public convenience and necessity
~~CPP~~CWA	Clean ~~Power Plan~~Water Act
CWIP	Construction work in progress
~~ERCOT~~DRC	~~Electric Reliability Council of Texas~~Development Recovery Company
ELG	Effluent limitations guidelines
ETR	Effective tax rate
FASB	Financial Accounting Standards Board



GAAP	Generally accepted accounting principles
GHG	Greenhouse gas
~~IRC~~IPP	~~Internal Revenue Code~~Independent power producing entity
ITC	Investment tax credit
~~JOA~~	~~Joint operating agreement~~
MGP	Manufactured gas plant
~~MISO~~	~~Midcontinent Independent Transmission System Operator, Inc.~~
Moody’s	Moody’s Investor Services
~~MWTG~~	~~Mountain West Transmission Group~~
Native load	Customer demand of retail and wholesale customers whereby a utility has an obligation to serve under statute or long-term contract.
NAV	Net asset value
NOL	Net operating loss
~~NOx~~	~~Nitrogen oxide~~
O&M	Operating and maintenance
~~OCI~~Post-65	~~Other comprehensive income~~
~~PJM~~	~~PJM Interconnection, LLC~~
PM	~~Particulate matter~~Post-Medicare
PPA	Purchased power agreement
~~PRP~~Pre-65	~~Potentially responsible party~~
~~PSIA~~	~~Pipeline system integrity adjustment~~ Pre-Medicare
PTC	Production tax credit
PV	Photovoltaic
~~R&E~~	~~Research and experimentation~~
REC	Renewable energy credit
ROE	Return on equity
~~RPS~~RTO	~~Renewable portfolio standards~~Regional Transmission Organization
~~SIP~~SERP	~~State implementation~~Supplemental executive retirement plan
SO₂	~~Sulfur dioxide~~
SPP	Southwest Power Pool, Inc.
Standard & Poor’s	Standard & Poor’s Ratings Services
TCJA	2017 federal tax reform enacted as Public Law No: 115-97, commonly referred to as the Tax Cuts and Jobs Act
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
~~GWh~~	~~Gigawatt hours~~

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, 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 risk factors listed from time to time by PSCo 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 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 PSCo 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; tax laws; operational safety; 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

PSCO is a wholly owned subsidiary of Xcel Energy Inc., and 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

PSCo was incorporated in 1924 under the laws of Colorado. PSCo ~~is a utility engaged primarily~~conducts business in ~~the generation, purchase, transmission, distribution~~Colorado and ~~sale of~~generates, purchases, transmits, distributes and sells electricity in ~~Colorado. PSCo also purchases, transports, distributes~~addition to purchasing, transporting, distributing and ~~sells~~selling natural gas to retail customers and ~~transports~~transporting customer-owned natural gas. PSCo provides electric utility service to approximately 1.5 million customers and natural gas utility service to approximately 1.4 million customers. All of PSCo’s retail electric operating revenues were derived from operations in Colorado. Although PSCo’s large C&I electric retail customers are comprised of many diversified industries, a significant portion of PSCo’s large C&I electric sales include: fabricated metal products, communications and health services. For small C&I customers, significant electric retail sales include the following industries: real estate and dining establishments. Generally, PSCo’s earnings contribute approximately 35 percent to 45 percent of Xcel Energy’s consolidated net income.




		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

~~The wholesale customers served by PSCo comprised approximately 14 percent of its total KWh sold in 2017.~~

PSCo owns the following direct subsidiaries: 1480 Welton, Inc. and United Water Company, both of which own certain real estate interests; and Green and Clear Lakes Company, which owns water rights and certain real estate interests. PSCo also holds a controlling interest in several other relatively small ditch and water companies.

PSCo conducts its utility business in the following reportable segments: regulated electric utility, regulated natural gas utility and all other. See Note 15 to the consolidated financial statements for further discussion relating to comparative segment revenues, net income and related financial information.

ELECTRIC UTILITY OPERATIONS

Electric Operating Statistics



	Year Ended Dec. 31
	2018			2017			2016
Electric sales (Millions of KWh)
Residential	9,438			9,107			9,272
Large C&I	6,566			6,449			6,371
Small C&I	12,973			12,796			12,890
Public authorities and other	270			274			268
Total retail	29,247			28,626			28,801
Sales for resale	7,403			4,851			4,672
Total energy sold	36,650			33,477			33,473

Number of customers at end of period
Residential	1,271,423			1,252,376			1,235,378
Large C&I	337			340			337
Small C&I	161,713			160,406			159,299
Public authorities and other	54,160			54,110			54,048
Total retail	1,487,633			1,467,232			1,449,062
Wholesale	52			43			34
Total customers	1,487,685			1,467,275			1,449,096

Electric revenues (Millions of Dollars)
Residential	$	1,025.1		$	1,033.3		$	1,063.5
Large C&I	406.8			421.1			414.8
Small C&I	1,191.2			1,227.9			1,204.9
Public authorities and other	50.5			52.8			54.1
Total retail	2,673.6			2,735.1			2,737.3
Wholesale	179.4			168.0			152.4
Other electric revenues	178.2			100.7			159.7
Total electric revenues	$	3,031.2		$	3,003.8		$	3,049.4

KWh sales per retail customer	19,660			19,510			19,876
Revenue per retail customer	$	1,797		$	1,864		$	1,889
Residential revenue per KWh		10.86	¢		11.35	¢		11.47	¢
Large C&I revenue per KWh	6.20			6.53			6.51
Small C&I revenue per KWh	9.18			9.60			9.35
Total retail revenue per KWh	9.14			9.55			9.50
Wholesale revenue per KWh	2.42			3.46			3.26

Energy Sources 2018

*Distributed generation from the Solar*Rewards^® program is not included (approximately 387 million KWh for 2018).

Energy Source Statistics

In 2018 and 2017, of PSCo’s total energy generation, 70% was owned and 30% was purchased.

Renewable Sources

PSCo’s renewable energy portfolio includes wind, hydroelectric, and solar power from both owned generating facilities and PPAs. As of Dec. 31, 2018, PSCo was in compliance with its applicable renewable portfolio standards. Renewable percentages will vary year over year based on local weather, system demand and transmission constraints.

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.

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				Natural Gas
	Cost		Percent		Cost		Percent
2018	$	1.45	62	%	$	3.74	38	%
2017	1.56		70		3.82		30

Weighted average cost per MMBtu of all fuels for owned electric generation was $2.33 in 2018 and $2.25 in 2017.

See Items 1A and 7 for further information.

Coal — Inventory maintained (in days):



Normal	Dec. 31, 2018 Actual	Dec. 31, 2017 Actual ^(a)
35 - 50	48	48


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

Coal requirements (in million tons) were 9.4 in 2018 and 10.0 in 2017. Coal supply as a percentage of requirements for 2019 is 8.4 million tons or 83% of contracted coal supply. The general coal purchasing objective is to contract for approximately 75% of year one requirements, 40% of year two requirements and 20% of year three requirements.

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



(Millions of Dollars)	Gas Supply^(a)		Gas Transportation and Storage ^(b)
2018	$	412	$	589
2017	545		620
Year of Expiration	2021 - 2023		2019 - 2040


^(a)	The 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 9 to the consolidated financial statements for further information.


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

Capacity and Demand

Uninterrupted system peak demand for PSCo’s electric utility for the last two years is as follows:



System Peak Demand (in MW)
2018		2017
6,718	July 10	6,671	July 19

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

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 ~~is authorized by the FERC~~does make certain sales to ~~make~~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.~~area as authorized by the FERC.

Fuel, Purchased Energy and Conservation Cost-Recovery

Mechanisms — ~~PSCo has several retail adjustment clauses that recover fuel, purchased energy and other resource costs:~~

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 ~~the amount of these~~ costs recovered under its ~~base~~ steam service rates. The SCA rate is revised ~~on a quarterly basis.~~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 ~~two percent~~2% of the customer’s bill.

WCA — ~~Premium service~~Recovers costs for customers who choose ~~to pay for~~ renewable resources.

TCA — Recovers costs ~~associated with~~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. ~~PSCo’s wholesale customers pay the full cost of certain renewable energy purchase and generation costs through a fuel clause and in exchange receive RECs associated with those resources.~~ The wholesale customers pay their jurisdictional allocation of production costs through a fully forecasted formula rate with true-up.

~~Capacity and Demand~~

~~Uninterrupted system peak demand for PSCo’s electric utility for each of the last three years and the forecast for 2018, assuming normal weather conditions, is as follows:~~

System Peak Demand (in MW)
2017 2016 2015 2018 Forecast
PSCo 6,671
6,585
6,284
6,462

The peak demand for PSCo’s system typically occurs in the summer. The 2017 system peak demand for PSCo occurred on July 19, 2017. The 2017 system peak demand was higher than 2016 due to warmer July summer weather. The forecast of system peak assumes normal weather conditions.

Energy Sources and ~~Related~~ Transmission ~~Initiatives~~

Service Providers

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

Purchased Power— — PSCo ~~has contracts to purchase~~purchases power from other utilities and IPPs. Long-term purchased power contracts for dispatchable resources typically require ~~a periodic~~ capacity charge and an energy ~~charge for energy actually purchased.~~charges. PSCo also contracts to purchase power for both wind and solar resources. ~~In addition,~~ PSCo makes short-term purchases to meet system load and energy requirements, to replace owned generation, ~~from company-owned units under maintenance or during outages, to~~ meet operating reserve obligations or to 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 ~~PSCo’s~~its customers.

~~Rush Creek~~ Wind ~~Ownership Proposal~~Development— In ~~2016, the CPUC granted~~2018, PSCo ~~a CPCN to build, own~~completed construction and ~~operate a~~placed in service its Rush Creek 600 MW wind ~~generation facility~~farm in Colorado at Rush Creek. The CPCN includes a hard cost-cap of $1.096 billion (including transmission costs) and a capital cost sharing mechanism between customers and PSCo of 82.5 percent to customers and 17.5 percent to PSCo for every $10 million the project comes in below the cost-cap.Colorado.

~~All major contracts required to complete the project have been executed. PTC components for safe harboring the facility have been fabricated and construction began in April 2017.~~

Investment costs will be recovered through the RESA and ECA riders until PSCo’s next rate case following Rush Creek’s in-service date. The wind generation facility is anticipated to be in service in October 2018.

~~Colorado Energy Plan (CEP)~~ CEP— In ~~2016, PSCo filed its 2016 Electric Resource Plan (ERP)~~September 2018, the CPUC approved PSCo’s preferred CEP portfolio, which included the ~~estimated need for additional generation resources through spring of 2024. In 2017, PSCo filed an updated capacity need with the CPUC of 450 MW in 2023.~~

In August 2017, PSCo and various other stakeholders filed a stipulation agreement proposing the CEP, an alternative plan that increases the amount of new resources sought under the ERP. The CEP would increase PSCo’s potential capacity need up to 1,110 MW due to the proposed retirement of two ~~coal units. The major components include:~~

~~Early retirement of 660 MWs of~~ coal-fired generation atunits, Comanche ~~Units~~Unit 1 ~~(2022)~~(in 2022) and Comanche Unit 2 ~~(2025);~~(in 2025), and the following additions:

~~Accelerated depreciation for the early retirement of the two Comanche units and establishment of a regulatory asset to collect the incremental depreciation expense and related costs;~~

~~A RFP for up to 1,000 MW of wind, 700 MW of solar and 700 MW of natural gas and/or storage;~~



	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

~~Utility ownership targets of 50 percent renewable generation resources and 75 percent of natural gas-fired, storage, or renewable with storage generation resources;~~

~~Reduction of the RESA rider, from two percent to one percent effective beginning 2021 or 2022; and~~

~~Construction of a new transmission switching station to further the development of renewable generating resources.~~

~~Hearings were held in February 2018 with two parties opposing both the coal retirements and utility ownership. Fifteen parties in the proceeding support the CEP. The CPUC~~PSCo’s investment is expected to ~~rule on~~be approximately $1 billion, including transmission to support the ~~stipulation agreement~~increase in ~~March 2018. PSCo is currently evaluating bids from a RFP~~renewable generation in the state. This investment includes the 500 MW Cheyenne Ridge Wind Farm and ~~anticipates filing its recommended portfolios~~the 345 KV generation tie line, as well as the Shortgrass Substation. CPCNs for these projects were filed in ~~April~~December 2018. A CPUC decision ~~on the recommended portfolio~~ is anticipated inby May 2019. CPCNs for the ~~summer of 2018.~~

natural gas facility are anticipated to be filed by mid-2019.

Boulder ~~Colorado~~ Municipalization — In 2011, ~~in the City of~~ Boulder ~~Colorado (Boulder), voters~~ passed a ballot measure authorizing the formation of an electric municipal utility, subject to certain conditions. ~~Since that time,~~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 ~~as premature~~ and the Colorado Court of Appeals ruled in PSCo’s favor, vacating a lower court decision. ~~Subsequently,~~In June 2018, the Colorado Supreme ~~Court granted~~court rejected Boulder’s ~~petition~~request to ~~review~~dismiss the ~~Court of Appeals decision~~case and ~~oral arguments were held on Feb. 14, 2018. A ruling on the petition is anticipated in 2018.~~

~~In 2015,~~remanded it to the Boulder District Court (District Court) affirmed a prior CPUC decision that Boulder cannot serve customers outside its city limits; these customers were included in Boulder’s plan at the time. The District Court also ruled the CPUC has jurisdiction over the transfer of any facilities to Boulder and in determining how the systems are separated. Further, the District Court found that the CPUC must give approval before Boulder files any condemnation proceeding. Boulder does not have authorization to initiate a condemnation proceeding at this time.Court.

Boulder has filed multiple separation applications with the ~~most recent one being in May 2017,~~CPUC, which ~~was~~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, stating PSCo is not required to undertake many of Boulder’s proposals, such as acting as a financier and contractor for Boulder. Additionally, the~~position. The CPUC has approved the designation of some electrical distribution assets for transfer, subject to Boulder completing certain ~~items, including:~~

~~Filing~~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 ~~agreement between Boulder and PSCo providing permanent rights for PSCo to place and access facilities in Boulder needed to continue to serve its customers;~~

~~Filing a complete and accurate revised list of distribution assets desired to be transferred; and~~

~~Filing an agreement to address payments from~~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 ~~for costs~~a Notice of ~~Boulder’s municipalization efforts.~~

Intent to acquire certain electric distribution assets.

Boulder ~~has requested that~~does not have authorization from the CPUC ~~grant an extension through March 13, 2018~~ to ~~complete such filings. Once those filings have been submitted, additional hearings may be held.~~

In November 2017, Boulder voters passed certain measures regarding Boulder’s pursuit of municipalization, including an extension and increase of the Utility Occupational Tax for funding Boulder’s exploration of municipalization.

~~MWTG —~~ ~~PSCo, along with nine other electric service providers from the Rocky Mountain region, have been considering creating and operating~~initiate a joint transmission tariff to increase wholesale market efficiency and improve regional transmission planning. In September 2017, the MWTG determined that membership in the SPP RTO could provide opportunities to reduce customer costs, and maximize resource and electric grid utilization. In October 2017, the MWTG commenced negotiations with SPP through the SPP public stakeholder process.

SPP’s Board of Directors and organizational groups have begun to address the MWTG’s proposed terms for integration into the SPP RTO. Should the MWTG decide to move forward, SPP would make filings with the FERC and PSCo would make filings with the CPUC and the FERC, in the later part of 2018. If approved, MWTG operations within the SPP RTO would not be expected to begin until late 2019condemnation proceeding at the earliest. PSCo recently engaged a consultant to conduct an analysis of the benefits associated with membership in the SPP RTO. The analysis assumed gas price forecasts that are lower than gas price forecasts used by the other MWTG utilities in their analysis of the benefits associated with membership in the SPP RTO. PSCo is in the process of evaluating that analysis.

~~Fuel Supply and Costs~~

The following table shows the delivered cost per MMBtu of each significant category of fuel consumed for owned electric generation, the percentage of total fuel requirements represented by each category of fuel and the total weighted average cost of all fuels.

Coal Natural Gas
Weighted
Average Owned Fuel Cost
PSCo Generating Plants Cost Percent Cost Percent
2017 $ 1.56
70 % $ 3.82
30 % $ 2.25
2016 1.75
72
3.79
28
2.33
2015 1.75
75
3.89
25
2.29

~~See Items 1A and 7 for further discussion of fuel supply and costs.~~

this time.

~~Fuel Sources~~

~~Coal~~— PSCo normally maintains approximately 35 - 50 days of coal inventory. Coal supply inventories at Dec. 31, 2017 and 2016 were approximately 48 and 36 days of usage, respectively. PSCo has contracted for coal supply to provide 75 percent of its 9.1 million tons of estimated coal requirements in 2018, and a declining percentage of requirements in subsequent years. PSCo’s general coal purchasing objective is to contract for approximately 75 percent of requirements for the first year, 40 percent of requirements in year two, and 20 percent of requirements in year three. Remaining requirements will be filled through the procurement process or over-the-counter transactions.

PSCo has coal transportation contracts that provide for delivery of 100 percent its coal requirements in 2018 and 2019. Coal delivery may be subject to interruptions or reductions due to operation of the mines, transportation problems, weather and availability of equipment.

~~Natural gas~~— PSCo uses both firm and interruptible natural gas supply in combustion turbines and certain boilers. Natural gas supplies for PSCo’s power plants are procured under contracts to provide an adequate supply of fuel. However, as natural gas primarily serves intermediate and peak demand, any remaining forecasted requirements are able to be procured through a liquid spot market. The 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 discussion.

Most transportation contract pricing is based on FERC approved transportation tariff rates. Certain natural gas supply and transportation agreements include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery.

At Dec. 31, 2017, PSCo’s commitments related to gas supply contracts, which expire between 2021 through 2023, were approximately $545 million and commitments related to gas transportation and storage contracts, which expire between 2018 through 2040, were approximately $620 million.

At Dec. 31, 2016, PSCo’s commitments related to gas supply contracts were approximately $654 million and commitments related to gas transportation and storage contracts were approximately $573 million.

~~PSCo has limited on-site fuel oil storage facilities and primarily relies on the spot market for incremental supplies.~~

~~Renewable Energy Sources~~

PSCo’s renewable energy portfolio includes wind, hydroelectric, biomass and solar power from both owned generating facilities and PPAs. As of Dec. 31, 2017, PSCo was in compliance with mandated RPS, which requires generation from renewable resources of 20.0 percent of electric retail sales.

~~Renewable energy as a percentage of PSCo’ total energy:~~

2017 2016
Renewable 27.7 % 28.3 %
Wind 23.7
23.7
Hydroelectric, biomass and solar 3.9
4.6

PSCo also offers customer-focused renewable energy initiatives. Windsource allows customers to purchase electricity from renewable sources. The number of customers utilizing Windsource increased to approximately 50,000 in 2017 from 46,000 in 2016.

~~Additionally, to encourage the growth of solar energy on the system, customers are offered incentives to install solar panels on their homes and businesses under the Solar*Rewards~~^® program. Over 34,900 PV systems with approximately 310 MW of aggregate capacity have been installed in Colorado as of Dec. 31, 2017 and over 32,500 PV systems with approximately 276 MW of aggregate capacity were installed as of Dec. 31, 2016. Additionally, 33 community solar gardens with 33.5 MW of capacity have been completed in Colorado as of Dec. 31, 2017.

~~Wind— PSCo acquires the majority of its wind energy from PPAs. Currently, PSCo has 18 of these agreements in place, with facilities ranging in size from two MW to over 300 MW.~~

PSCo had approximately 2,560 MW of wind energy on its system at the end of 2017 and 2016. In addition to receiving purchased wind energy under these agreements, PSCo typically receives wind RECs which are used to meet state renewable resource requirements.

The average cost per MWh of wind energy under these contracts was approximately $42 in 2017 and 2016. The cost per MWh of wind energy varies by contract and may be influenced by a number of factors including regulation, state-specific renewable resource requirements, and the year of contract execution. Generally, previously executed contracts continued to benefit from improvements in wind technology, excess capacity among manufacturers, and motivation to commence new construction prior to the anticipated expiration of the federal PTCs. In December 2015, the federal PTCs were extended through 2019 with a phase down on sites that began construction in 2017.

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. See Item 7 for further discussion.~~joint operating agreement.

~~Summary of Recent Federal Regulatory Developments~~

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, hydro facility licensing, natural gas transportation, asset transactions and mergers, accounting practices and certain other activities of PSCo, including enforcement of NERC mandatory electric reliability standards. State and local agencies have jurisdiction over many of PSCo’s activities, including regulation of retail rates and environmental matters. In addition to the matters discussed below, see Note 11 to the accompanying consolidated financial statements for a discussion of other regulatory matters.

Xcel Energy, which includes PSCo, attempts to mitigate the risk of regulatory penalties through formal training on prohibited practices and a compliance function that reviews interaction with the markets under FERC and CFTC jurisdictions. Public campaigns are conducted to raise awareness of the public safety issues of interacting with our electric systems. While programs to comply with regulatory requirements are in place, there is no guarantee the compliance programs or other measures will be sufficient to ensure against violations.

~~Public Utility Regulatory Policies Act (PURPA) Enforcement Complaint against CPUC~~ —In December 2016, Sustainable Power Group, LLC (sPower) petitioned the FERC to initiate an enforcement action in federal court against the CPUC under PURPA. The petition asserts that a December 2016 CPUC ruling, which indicated that a qualifying facility must be a successful bidder in a PSCo resource acquisition bidding process, violated PURPA and FERC rules. In January 2017, PSCo filed a motion to intervene and protest, arguing that the FERC should decline the petition. The CPUC filed a similar pleading. sPower has proposed to construct 800 MW of solar generation and 700 MW of wind generation in Colorado and seeks to require PSCo to contract for these resources under PURPA.

If sPower were to prevail, PSCo’s ability to select generation resources through competitive bidding would be negatively affected. However, due to a lack of quorum at the FERC, the FERC did not act on that petition within the sixty days contemplated by PURPA. Subsequently sPower filed a complaint for declaratory and injunctive relief in the United States District Court for the District of Colorado (District Court) requesting that the court find the bidding requirement in the CPUC qualifying facility rules to be unlawful. PSCo intervened in that proceeding and the CPUC filed a motion to dismiss. In June 2017, the United States Magistrate Judge issued a recommendation to the District Court that sPower’s complaint be dismissed because sPower failed to establish that it faced a substantial risk of harm. In October 2017, the District Court denied the CPUC’s motion to dismiss and instead allowed sPower to file an amended complaint. The case effectively started over and PSCo intervened. The CPUC filed a motion to dismiss the amended complaint which is currently pending before the District Court. The timing of a resolution in this case is unclear.

~~Electric Operating Statistics~~

~~Electric Sales Statistics~~

Year Ended Dec. 31
2017 2016 2015
Electric sales (Millions of KWh)
Residential 9,107
9,272
9,112

Large commercial and industrial 6,449
6,371
6,596

Small commercial and industrial 12,796
12,890
12,750

Public authorities and other 274
268
242

Total retail 28,626
28,801
28,700

Sales for resale 4,851
4,672
3,581

Total energy sold 33,477
33,473
32,281

Number of customers at end of period
Residential 1,252,376
1,235,378
1,218,662

Large commercial and industrial 340
337
337

Small commercial and industrial 160,406
159,299
158,086

Public authorities and other 54,110
54,048
53,944

Total retail 1,467,232
1,449,062
1,431,029

Wholesale 43
34
26

Total customers 1,467,275
1,449,096
1,431,055

Electric revenues (Thousands of Dollars)
Residential $ 1,033,324
$ 1,063,526
$ 1,060,626

Large commercial and industrial 421,068
414,797
433,061

Small commercial and industrial 1,227,886
1,204,881
1,220,064

Public authorities and other 52,834
54,070
52,783

Total retail 2,735,112
2,737,274
2,766,534

Wholesale 167,971
152,375
180,716

Other electric revenues 100,725
159,703
168,007

Total electric revenues $ 3,003,808
$ 3,049,352
$ 3,115,257

KWh sales per retail customer 19,510
19,876
20,055

Revenue per retail customer $ 1,864
$ 1,889
$ 1,933

Residential revenue per KWh 11.35
¢ 11.47
¢ 11.64
¢
Large commercial and industrial revenue per KWh 6.53
6.51
6.57

Small commercial and industrial revenue per KWh 9.60
9.35
9.57

Total retail revenue per KWh 9.55
9.50
9.64

Wholesale revenue per KWh 3.46
3.26
5.05

~~Energy Source Statistics~~

Year Ended Dec. 31
2017 2016 2015

Millions of
KWh

Percent of
Generation

Millions of
KWh

Percent of
Generation

Millions of
KWh

Percent of
Generation
Coal 14,609
44 % 15,895
47 % 18,601
54 %
Natural Gas 9,195
28
8,632
25
7,948
23
Wind ^(a)
7,804
24
8,106
24
6,699
19
Hydroelectric 624
2
1,179
3
662
2
Other ^(b)
670
2
393
1
705
2
Total 32,902
100 % 34,205
100 % 34,615
100 %

Owned generation 23,053
70 % 22,753
67 % 22,981
66 %
Purchased generation 9,849
30
11,452
33
11,634
34
Total 32,902
100 % 34,205
100 % 34,615
100 %


^(a)	~~This category includes wind energy de-bundled from RECs and also includes Windsource RECs. PSCo uses RECs to meet or exceed state resource requirements and may sell surplus RECs.~~


^(b)	~~Distributed generation from the Solar*Rewards program is not included, and was approximately 393, 396 and 245 million net KWh for 2017, 2016, and 2015, respectively.~~

NATURAL GAS UTILITY OPERATIONS

~~Overview~~Natural Gas Operating Statistics



	Year Ended Dec. 31
	2018		2017		2016
Natural gas deliveries (Thousands of MMBtu)
Residential	97,409		88,843		90,941
C&I	40,467		37,305		38,093
Total retail	137,876		126,148		129,034
Transportation and other	155,281		124,211		117,462
Total deliveries	293,157		250,359		246,496

Number of customers at end of period
Residential	1,300,826		1,284,644		1,269,338
C&I	101,036		100,802		100,718
Total retail	1,401,862		1,385,446		1,370,056
Transportation and other	7,891		7,649		7,261
Total customers	1,409,753		1,393,095		1,377,317

Natural gas revenues (Millions of Dollars)
Residential	$	649.9	$	652.9	$	611.8
C&I	244.5		247.6		228.1
Total retail	894.4		900.5		839.9
Transportation and other	120.2		94.7		117.8
Total natural gas revenues	$	1,014.6	$	995.2	$	957.7

MMBtu sales per retail customer	98.35		91.05		94.18
Revenue per retail customer	$	638	$	650	$	613
Residential revenue per MMBtu	6.67		7.35		6.73
C&I revenue per MMBtu	6.04		6.64		5.99
Transportation and other revenue per MMBtu	0.77		0.76		1.00

PSCo operates a natural gas local distribution company in Colorado. The most significant developments in the natural gas operations of PSCo are uncertainty regarding political and regulatory developments that impact hydraulic fracturing, safety requirements for natural gas pipelines and the continued trend of declining use per residential and small C&I customer, as a result of improved building construction technologies, higher appliance efficiencies, and conservation. From 2000 to 2017, average annual sales to the typical PSCo residential customer declined 17 percent, while sales to the typical small C&I customer declined 12 percent, each on a weather‑normalized basis. Although wholesale price increases do not directly affect earnings because of natural gas cost recovery mechanisms, high prices can encourage further efficiency efforts by customers.

~~Pipeline Safety Act~~ — The Pipeline Safety, Regulatory Certainty, and Job Creation Act (Pipeline Safety Act) requires additional 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. In April 2016, the PHMSA released proposed rules that address this verification requirement along with a number of other significant changes to gas transmission regulations. These changes include requirements around use of automatic or remote-controlled shut-off valves, testing of certain previously untested transmission lines and expanding integrity management requirements. The Pipeline Safety Act also includes a maximum penalty for violating pipeline safety rules of $2 million per day for related violations.

~~PHMSA is currently working through the rule with its Pipeline Advisory Committee. Current estimates are the rule will likely go into effect in late 2018 or early 2019.~~

PSCo has been taking actions that were intended to comply with the Pipeline Safety Act and any related PHMSA regulations as they become effective. PSCo can generally recover costs to comply with the transmission and distribution integrity management programs through the PSIA rider.

~~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 under the Federal Natural Gas Act. PSCo is subject to the DOT and the CPUC with regards to pipeline safety compliance.

~~Purchased Natural Gas and Conservation Cost-Recovery Mechanisms~~— ~~PSCo has retail adjustment clauses that recover purchased natural gas and other resource costs:~~

~~GCA~~ ~~— Recovers the actual costs of purchased natural gas and transportation to meet the requirements of its customers 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 associated with transmission and distribution pipeline integrity management programs and two projects to replace large transmission pipelines.~~

Capability and Demand

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

Maximum daily send-out (firm and interruptible) and occurrence date for ~~PSCo was 1,948,167 MMBtu, which occurred on Jan. 5, 2017 and 1,932,070 MMBtu, which occurred on Dec. 17, 2016.~~PSCo:

~~PSCo purchases natural~~



2018			2017
MMBtu		Date	MMBtu	Date
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. The natural gas~~prices, and is delivered under transportation agreements with interstate pipelines. These agreements provide for firm deliverable pipeline capacity of ~~approximately 1,818,151~~1,834,843 MMBtu per ~~day, which~~day. This amount includes ~~854,852~~871,418 MMBtu of natural gas held under third-party underground storage agreements. ~~In addition,~~

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

PSCo is required by CPUC regulations to file a natural gas purchase plan each year projecting and describing the quantities of natural gas supplies, upstream services and the costs of those supplies and services for the 12-month period of the following year. PSCo is also required to file a natural gas purchase report by October of each year reporting actual quantities and costs incurred for natural gas supplies and upstream services for the previous 12-month period.

Natural Gas Supply and Costs

PSCo actively seeks natural gas supply, transportation and storage alternatives to yield a diversified portfolio ~~that~~which provides increased flexibility, decreased interruption and financial risk and economical rates. In addition, PSCo conducts natural gas price hedging activities ~~that have been~~ approved by ~~the CPUC.~~their respective state commissions.

~~The following table summarizes the average~~Average delivered cost per MMBtu of natural gas ~~purchased~~ for ~~resale by PSCo’s~~ regulated retail ~~natural gas~~ distribution ~~business:~~

2017 $ 3.45
2016 3.27
2015 3.92

~~The cost of natural gas~~was $3.20 and $3.45 in 2018 and 2017, ~~increased due to higher wholesale commodity prices.~~

respectively.

PSCo has natural gas supply transportation and storage agreements that include obligations for the purchase and/or delivery of specified volumes ~~of natural gas~~ or to make payments in lieu of delivery. AtAs of Dec. 31, ~~2017,~~2018, PSCo was committed to approximately ~~$1.4~~$1.1 billion ~~in such~~of obligations under ~~these~~ contracts, which expire in various years from ~~2018 through~~2019 - 2029.

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.

~~PSCo purchases natural gas by optimizing a balance~~

Purchased Natural Gas and Conservation Cost-Recovery

Mechanisms —

GCA — Recovers the costs of ~~long-term and short-term natural gas purchases, firm transportation and natural gas storage contracts. During 2017, PSCo~~ purchased natural gas ~~from approximately 31 suppliers.~~

~~See Items 1A~~ and 7transportation to meet customer requirements and is revised quarterly to allow for ~~further discussion of~~changes in natural gas ~~supply~~rates.

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

~~Natural Gas Operating Statistics~~

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

Year Ended Dec. 31
2017 2016 2015
Natural gas deliveries (Thousands of MMBtu)
Residential 88,843
90,941
92,001
Commercial and industrial 37,305
38,093
38,405
Total retail 126,148
129,034
130,406
Transportation and other 124,211
117,462
108,860
Total deliveries 250,359
246,496
239,266

Number of customers at end of period
Residential 1,284,644
1,269,338
1,254,056
Commercial and industrial 100,802
100,718
100,389
Total retail 1,385,446
1,370,056
1,354,445
Transportation and other 7,649
7,261
6,936
Total customers 1,393,095
1,377,317
1,361,381

Natural gas revenues (Thousands of Dollars)
Residential $ 652,913
$ 611,804
$ 678,909
Commercial and industrial 247,582
228,103
257,287
Total retail 900,495
839,907
936,196
Transportation and other 94,719
117,814
70,470
Total natural gas revenues $ 995,214
$ 957,721
$ 1,006,666

MMBtu sales per retail customer 91.05
94.18
96.28
Revenue per retail customer $ 650
$ 613
$ 691
Residential revenue per MMBtu 7.35
6.73
7.38
Commercial and industrial revenue per MMBtu 6.64
5.99
6.70
Transportation and other revenue per MMBtu 0.76
1.00
0.65

GENERAL

Seasonality

~~The demand~~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, PSCo’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 ~~discussion.~~

information.

Competition

PSCo is a vertically integrated utility subject to traditional cost-of-service ~~regulation. However,~~regulation by state public utilities commissions. PSCo is subject to ~~different~~ public policies that promote competition and ~~the~~ development of energy markets. PSCo’s industrial and large commercial customers have the ability ~~to own or operate facilities~~ to generate their own electricity. In addition, customers may have the option of substituting other fuels ~~such as natural gas, steam~~ or ~~chilled water for heating, cooling and manufacturing purposes, or the option of~~ relocating their facilities to a lower cost region.

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

The FERC has continued to promote competitive wholesale markets through open access transmission and other means. As a result, PSCo and its wholesale customers can purchase the output from generation resources ~~from~~of competing wholesale suppliers and use the transmission systems of Xcel Energy Inc.’s utility subsidiaries on a comparable basis to serve their native load. State public utilities commissions, including the CPUC, have created resource planning programs that promote competition in the acquisition of electricity generation resources used to provide service to retail customers. In addition,

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.

PSCo ~~also~~ has franchise agreements with ~~certain~~ cities subject to periodic ~~renewal. If~~renewal; however, a city ~~elected not to renew a franchise agreement, it~~ could seek alternative means ~~for its citizens~~ to access electric power or gas, such as municipalization.

While facing these challenges, PSCo believes its rates and services are competitive with the alternatives currently ~~available alternatives.~~available.

ENVIRONMENTAL MATTERS

PSCo’s facilities are regulated by federal and state environmental ~~agencies. These~~ 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. PSCo has received all necessary authorizations for the construction and continued operation of its generation, transmission and distribution systems. PSCo’s facilities have been designed and constructed to operate in compliance with applicable environmental ~~standards.~~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 PSCo’s operations. ~~See Notes 11~~PSCo may be required to incur capital expenditures in the future to comply with requirements for remediation of MGP and 12other 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.

The Denver North Front Range Nonattainment Area does not meet either the 2008 or 2015 ozone National Ambient Air Quality Standard. Colorado will continue to consider further reductions available in the ~~consolidated financial statements for~~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 ~~discussion.~~

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 ~~the~~ use of clean energy technologies and regulate emissions of ~~GHGs to address climate change.~~GHGs. PSCo has undertaken ~~a number of~~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 ~~these~~ future environmental regulations do not provide credit for the investments ~~we have~~PSCo has already made ~~to reduce GHG emissions,~~ or if they require additional initiatives or emission reductions, ~~then their requirements~~substantial costs may be incurred.

The EPA, as an alternative to the Clean Power Plan, has proposed a new regulation that, if adopted, would ~~potentially impose additional substantial costs.~~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. PSCo believes, based on prior state commission practice, ~~it would recover~~ the cost of these initiatives or replacement generation would be recoverable through rates.

PSCo 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, PSCo began reporting GHG emissions under the EPA’s mandatory GHG Reporting Program.

EMPLOYEES

As of Dec. 31, ~~2017,~~2018, PSCo had ~~2,400~~2,426 full-time employees and ~~two~~no part-time employees, of which ~~1,835~~1,904 were covered under collective-bargaining agreements. ~~See Note 8 to the consolidated financial statements for further discussion.~~

Item 1A — Risk Factors

Xcel Energy, which includes PSCo, is subject to a variety of risks, many of which are beyond our control. ~~Important risks~~Risks that may adversely affect the business, financial condition, ~~and~~ results of operations or cash flows are ~~further~~ described below. These risks should be carefully considered together with the other information set forth in this report and in 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 the Board of Directors have responsibility for overseeing the identification and mitigation of key risks.

Management identifies and analyzes risks to determine materiality and other attributes such as timing, probability and controllability. ~~Management broadly considers our business, the utility industry, the domestic and global economies and the environment when identifying, assessing, managing and mitigating risk.~~ Identification and analysis occurs formally through a key risk assessment process ~~conducted~~ by senior management, the financial disclosure process, ~~the~~ hazard risk management ~~process~~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 our strategy. The business planning process also identifies areas in which there is a potential for a business area to ~~take~~assume inappropriate risk to meet goals, and determines how to prevent inappropriate risk-taking.

At a threshold level, PSCo has ~~developed~~ a robust compliance program and promotes a culture of compliance, including tone at the ~~top, which mitigates risk.~~top. The process for risk mitigation includes adherence to our code of conduct and ~~other~~ compliance policies, operation of formal risk management structures ~~and groups~~ and overall business management to mitigate the risks inherent in the implementation of strategy. Building on this culture of compliance, management further mitigates risks through ~~operation of~~ formal risk management structures, ~~and groups,~~ including management councils, risk committees and ~~the~~ services of ~~internal~~ corporate areas such as internal audit, ~~the~~ corporate controller and ~~legal services.~~

legal.

Management communicates regularly with the Board of Directors and key stakeholders regarding risk. Senior management presents and communicates a periodic risk assessment ~~of key risks~~ to the Board of Directors. The presentation and the discussion of the key risks ~~provides the Board of Directors with~~provide information on the risks management believes are material, including the earnings impact, timing, likelihood and controllability. ~~Management also provides information to~~Oversight of cybersecurity risks by the ~~Board~~Operations, Nuclear, Environmental and Safety Committee includes receiving independent outside assessments of ~~Directors in presentations~~cybersecurity maturity and ~~communications over the course~~assessment of ~~the year.~~

plans.

Overall, the Board of Directors approaches oversight, management and mitigation of risk as an integral and continuous part of its governance of PSCo. Processes are in place to ensure appropriate risk oversight, as well as identification and consideration of new risks. The Board of Directors regularly reviews management’s key risk assessment informed by these processes, and analyzes areas of existing and future risks and opportunities.

Risks Associated with Our Business

~~Environmental~~Operational Risks

~~We are subject to environmental laws~~Our natural gas and ~~regulations, with which compliance could be difficult~~electric transmission and ~~costly.~~

~~We are subject to environmental laws and regulations~~distribution operations involve numerous risks that affect many aspects of our past, present and future operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances. These laws and regulations require us to obtain permits, licenses, and other approvals and to comply with a wide variety of environmental requirements including those for protected natural and cultural resources (such as wetlands, endangered species and other protected wildlife, and archaeological and historical resources). Environmental laws and regulations can also require us to restrict or limit the output of certain facilities or the use of certain fuels, shift generation to lower-emitting, but potentially more costly facilities, install pollution control equipment at our facilities, clean up spills and other contamination and correct environmental hazards. Environmental regulations may also lead to shutdown of existing facilities, either due to the difficulty in assuring compliance or that the costs of compliance makes operation of the units no longer economical. Both public officials and private individuals may seek to enforce the applicable environmental laws and regulations against us. 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 certain other parties, caused environmental contamination.

~~We are also subject to mandates to provide customers with clean energy, renewable energy and energy conservation offerings. Failure to meet the requirements of these mandates~~ may result in ~~fines or penalties,~~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 ~~have a material effect on~~cause substantial financial losses. These natural gas and electric risks could result in loss of life, significant property damage, environmental pollution, impairment of our ~~results~~operations and substantial losses. We maintain insurance against some, but not all, of ~~operations. If our regulators do~~these risks and losses. The occurrence of these events, if 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 or other environmental requirements, it~~fully covered by insurance, could have a material effect on our results of operations, financial ~~position~~condition or 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 carbon dioxide 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 PSCo 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.

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.

In addition, existing environmental laws or regulations may be revised, and new laws or regulations may be adopted or become applicable to us, including but not limited to, regulation of mercury, NOx, SO₂~~, CO~~₂and other GHGs, particulates, cooling water intakes, water discharges and ash management. We may also incur additional unanticipated obligations or liabilities under existing environmental laws and regulations.

We are subject to ~~physical~~commodity risks and ~~financial~~other risks associated with ~~climate change~~energy markets and ~~other weather, natural disaster~~energy production.

If fuel costs increase, customer demand could decline and ~~resource depletion impacts.~~

~~Climate change can create physical and financial risk. Physical risks from climate change can include changes in weather conditions, changes in precipitation and extreme weather events.~~

Our customers’ energy needs vary with weather conditions, primarily temperature and humidity. For residential customers, heating and cooling represent their largest energy use. To the extent weather conditions are affected by climate change, customers’ energy usebad debt expense may rise, which could increase or decrease. Increased energy use due to weather changes may require us to invest in additional generating assets, transmission and other infrastructure to serve increased load. Decreased energy use due to weather changes may result in decreased revenues. Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system stress, including service interruptions. Weather conditions could also have ana material impact on our ~~revenues.~~ results of operations. While we have fuel clause recovery mechanisms, 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 ~~buy~~also engage in wholesale sales and ~~sell electricity depending upon system needs~~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 ~~opportunities. Extreme weather conditions creating high energy demand~~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.

As we are a subsidiary of Xcel Energy Inc., we may ~~raise electricity prices, which~~be negatively affected by events impacting the credit or liquidity of Xcel Energy Inc. and its affiliates.

If Xcel Energy Inc. were to become obligated to make payments under various guarantees and bond indemnities or to fund its other contingent liabilities, or if either Standard & Poor’s or Moody’s were to downgrade Xcel Energy Inc.’s credit rating below investment grade, Xcel Energy Inc. may be required to provide credit enhancements in the form of cash collateral, letters of credit or other security to satisfy part or potentially all of these exposures. If either Standard & Poor’s or Moody’s were to downgrade Xcel Energy Inc.’s debt securities below investment grade, it would increase ~~the~~Xcel Energy Inc.’s cost of ~~energy~~capital and restrict its access to the capital markets. This could limit Xcel Energy Inc.’s ability to contribute equity or make loans to us, or may cause Xcel Energy Inc. to seek additional or accelerated funding from us in the form of dividends. If such event were to occur, we ~~provide~~may need to seek alternative sources of funds to meet our cash needs.

As of Dec. 31, 2018, Xcel Energy Inc. and its utility subsidiaries had approximately $15.8 billion of long-term debt and $1.4 billion of short-term debt and current maturities. Xcel Energy Inc. provides various guarantees and bond indemnities supporting some of its subsidiaries by guaranteeing the payment or performance by these subsidiaries for specified agreements or transactions.

Xcel Energy also has other contingent liabilities resulting from various tax disputes and other matters. Xcel Energy Inc.’s exposure under the guarantees is based upon the net liability of the relevant subsidiary under the specified agreements or transactions. The majority of Xcel Energy Inc.’s guarantees limit its exposure to a maximum amount that is stated in the guarantees. As of Dec. 31, 2018, Xcel Energy had guarantees outstanding with a maximum stated amount of approximately $17.8 million and immaterial exposure. Xcel Energy also had additional guarantees of $51.1 million at Dec. 31, 2018 for performance and payment of surety bonds for the benefit of itself and its subsidiaries, with total exposure that cannot be estimated at this time. If Xcel Energy Inc. were to become obligated to make payments under these guarantees and bond indemnities or become obligated to fund other contingent liabilities, it could limit Xcel Energy Inc.’s ability to contribute equity or make loans to us, or may cause Xcel Energy Inc. to seek additional or accelerated funding from us in the form of dividends. If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.

We are a wholly owned subsidiary of Xcel Energy Inc. Xcel Energy Inc. can exercise substantial control over our dividend policy and business and operations and may exercise that control in a manner that may be perceived to be adverse to our ~~customers.~~interests.

All of the members of our Board of Directors, as well as many of our executive officers, are officers of Xcel Energy Inc. Our Board makes determinations with respect to a number of significant corporate events, including the payment of our dividends.

~~Severe weather impacts our service territories, primarily when thunderstorms~~We have historically paid quarterly dividends to Xcel Energy Inc. In 2018, 2017 and ~~associated flooding, tornadoes, wildfires~~2016 we paid $375.3 million, $333.9 million and ~~snow or ice storms occur. To the extent the frequency~~$336.6 million of ~~extreme weather events increases, this could~~dividends to Xcel Energy Inc., respectively. If Xcel Energy Inc.’s cash requirements increase, our ~~cost~~Board of ~~providing service. Changes in precipitation resulting in droughts or water shortages, whether caused by climate change or otherwise,~~Directors could decide to increase the dividends we pay to Xcel Energy Inc. to help support Xcel Energy Inc.’s cash needs. This could adversely affect our operations, principally our fossil generating units. A negative impact to water supplies due to long-term drought or water depletion conditions could adversely impact our ability to provide electricity to customers, as well as increaseliquidity. The most restrictive dividend limitation for PSCo is imposed by its credit facility, which limits the ~~price they pay for energy. We may not recover all costs related to mitigating these physical and financial risks.~~

~~Climate change may impact a region’s economic health, which could impact our revenues. Our financial performance is tied~~debt-to-total capitalization ratio. See Note 5 to the ~~health of the regional economies we serve. The price of energy has an impact on the economic health of our communities. The cost of additional regulatory requirements, such as regulation of GHGor additional environmental regulation could impact the availability of goods and prices charged by our suppliers which would normally be borne by consumers through higher prices~~consolidated financial statements 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.further information.

~~Financial~~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 ~~profitability depends in part on our ability to recover costs from our customers~~natural gas transmission and ~~there may be changes in circumstances or in the regulatory environment that impair our ability to recover costs from our customers.~~

~~We are subject to comprehensive regulation by federal~~distribution activities include inherent hazards and ~~state utility regulatory agencies. The CPUC regulates many aspects of our utility operations, including siting~~operating risks, such as leaks, explosions, outages and ~~construction of facilities, customer service and the rates that we can charge customers. The FERC has jurisdiction, among other things, over wholesale rates for~~mechanical problems. Our electric transmission ~~service, the sale of electric energy in interstate commerce~~ and ~~certain~~distribution activities also include inherent hazards and operating risks such as contact, fire and outages which could cause substantial financial losses. These natural gas ~~transactions~~and electric risks could result in ~~interstate commerce.~~

~~The profitability~~loss of life, significant property damage, environmental pollution, impairment of our operations ~~is dependent on our ability to recover the costs of providing energy~~ and ~~utility services to our customers and earn a return on our capital investment.~~substantial losses. We provide service at rates approved by one or more regulatory commissions. These rates are generally regulated and based on an analysis of our costs incurred in a test year. We are subject to both future and historical test years depending upon the regulatory mechanisms approved in each jurisdiction. Thus, the rates we are allowed to charge may or maymaintain insurance against some, but not match our costs at any given time. While 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 the applicable regulatory commission will judge all, of our costs to have been prudent, which could result in cost disallowances, or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of such costs. Changes in the long-term cost-effectiveness or changes to the operating conditions of our assets may result in early retirementsthese risks 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~~losses. The occurrence of these ~~asset costs stranded. Higher than expected inflation may increase costs of construction and operations. Rising fuel costs could increase the risk that we will~~events, if not ~~be able to~~ fully recover our fuel costs from our customers. Furthermore, there could be changes in the regulatory environment that would impair our ability to recover costs historically collected from our customers, or these factors could cause us to exceed commitments made regarding cost caps and result in less than full recovery. Overall, management currently believes prudently incurred costs are generally recoverable given the existing regulatory mechanisms in place.

~~Adverse regulatory rulings or the imposition of additional regulations~~covered by insurance, could have ~~an adverse impact~~a material effect on our results of operations, financial condition or 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 ~~hence~~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 ~~materially~~increase regulatory scrutiny and ~~adversely affect~~result in penalties and higher costs of operations.

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

Customer adoption of these technologies and increased energy efficiency could result in excess transmission and generation resources as well as stranded costs if PSCo 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 ~~ability~~facilities. Lack of availability of these resources could jeopardize long-term operations of our facilities or make them uneconomic to operate.

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 ~~our financial obligations, including debt payments.~~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.

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

We cannot be assured that any of our current ratings will remain in effect for any given period of time, or that a rating will not be lowered or withdrawn entirely by a rating agency. Significant events including a major disallowance of costs, significantly lower returns on equity or equity ratios or impacts of tax policy changes, among others, 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, we may enter into certain procurement and derivative 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~~commodity risks and ~~interest rate risks.~~other risks associated with energy markets and energy production.

~~Utility operations require significant capital investment. As a result, we frequently need to access capital markets. Any disruption in capital markets~~If fuel costs increase, customer demand could decline and bad debt expense may rise, which could have a material impact on our ~~ability to fund~~results of operations. While we have fuel clause recovery mechanisms, higher fuel costs could significantly impact our ~~operations. Capital markets~~results of operations if costs are ~~global~~not recovered. Delays in ~~nature~~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 ~~are impacted by numerous issues~~natural gas prices could negatively impact oil and ~~events throughout the world economy. Capital market~~gas production activities and subsequently our sales volumes and revenue.

A significant disruption ~~events and resulting broad financial market distress~~in supply could ~~prevent us from issuing short term commercial paper, issuing new securities or~~ cause us to ~~issue securities with less than ideal terms and conditions, such as~~seek alternative supply services at potentially higher ~~interest rates.~~

~~Higher interest rates on short-term borrowings with variable interest rates could also~~costs or suffer increased liability for unfulfilled contractual obligations. Significantly higher energy or fuel costs relative to sales commitments have ~~an adverse effect~~a negative impact on our ~~operating results. Changes~~cash flows and potentially result in ~~interest rates~~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 ~~impact~~result in fines, penalties or cost disallowances through the ~~fair value~~regulatory process.

We also engage in wholesale sales and purchases of ~~the debt securities in the master pension trust,~~electric capacity, energy and energy-related products as well as ~~our ability~~natural gas. In many markets, emission allowances and/or RECs are also needed to ~~earn~~comply with various statutes and commission rulings. As a ~~return on short-term investments of excess cash.~~

Weresult we are subject to ~~credit risks.~~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.

~~Credit risk includes the risk that our customers will not pay their bills, which may lead to~~As we are a ~~reduction in liquidity and an increase in bad debt expense. Credit risk is comprised~~subsidiary 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 to these arrangements fail to perform,Xcel Energy Inc., we may be ~~forced~~negatively affected by events impacting the credit or liquidity of Xcel Energy Inc. and its affiliates.

If Xcel Energy Inc. were to ~~enter into alternative arrangements. In that event, our financial results could~~become obligated to make payments under various guarantees and bond indemnities or to fund its other contingent liabilities, or if either Standard & Poor’s or Moody’s were to downgrade Xcel Energy Inc.’s credit rating below investment grade, Xcel Energy Inc. may be ~~adversely affected and we could incur losses.~~

~~We may at times have direct~~required to provide credit exposure in our short-term wholesale and commodity trading activity to various 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, MISO and ERCOT, in which any credit losses are socialized to all market participants.

~~We do have additional indirect credit exposures to various domestic and foreign financial institutions~~enhancements in the form of cash collateral, letters of credit ~~provided as~~or other security to satisfy part or potentially all of these exposures. If either Standard & Poor’s or Moody’s were to downgrade Xcel Energy Inc.’s debt securities below investment grade, it would increase Xcel Energy Inc.’s cost of capital and restrict its access to the capital markets. This could limit Xcel Energy Inc.’s ability to contribute equity or make loans to us, or may cause Xcel Energy Inc. to seek additional or accelerated funding from us in the form of dividends. If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.

As of Dec. 31, 2018, Xcel Energy Inc. and its utility subsidiaries had approximately $15.8 billion of long-term debt and $1.4 billion of short-term debt and current maturities. Xcel Energy Inc. provides various guarantees and bond indemnities supporting some of its subsidiaries by ~~power suppliers~~guaranteeing the payment or performance by these subsidiaries for specified agreements or transactions.

Xcel Energy also has other contingent liabilities resulting from various tax disputes and other matters. Xcel Energy Inc.’s exposure under ~~various long-term physical purchased power contracts. If any~~the guarantees is based upon the net liability of the ~~credit ratings~~relevant subsidiary under the specified agreements or transactions. The majority of Xcel Energy Inc.’s guarantees limit its exposure to a maximum amount that is stated in the guarantees. As of Dec. 31, 2018, Xcel Energy had guarantees outstanding with a maximum stated amount of approximately $17.8 million and immaterial exposure. Xcel Energy also had additional guarantees of $51.1 million at Dec. 31, 2018 for performance and payment of surety bonds for the benefit of itself and its subsidiaries, with total exposure that cannot be estimated at this time. If Xcel Energy Inc. were to become obligated to make payments under these guarantees and bond indemnities or become obligated to fund other contingent liabilities, it could limit Xcel Energy Inc.’s ability to contribute equity or make loans to us, or may cause Xcel Energy Inc. to seek additional or accelerated funding from us in the form of dividends. If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.

All of the ~~letter~~members of ~~credit issuers were~~our Board of Directors, as well as many of our executive officers, are officers of Xcel Energy Inc. Our Board makes determinations with respect to ~~drop below~~a number of significant corporate events, including the designated investment grade rating stipulated in the underlying long-term purchased power contracts, the supplier would need to replace that security with an acceptable substitute. If the security were not replaced, the party could be in technical default under the contract, which would enable us to exercisepayment of our ~~contractual rights.~~

~~Increasing costs associated with our defined benefit retirement plans and other employee benefits may adverselyaffect our results of operations, financial position or liquidity.~~

dividends.

We have ~~defined benefit pension~~historically paid quarterly dividends to Xcel Energy Inc. In 2018, 2017 and ~~postretirement plans that cover most~~2016 we paid $375.3 million, $333.9 million and $336.6 million of dividends to Xcel Energy Inc., respectively. If Xcel Energy Inc.’s cash requirements increase, our ~~employees. Assumptions related~~Board of Directors could decide to ~~future costs, return on investments, interest rates and other actuarial assumptions, including mortality tables, have a significant impact on our funding requirements related~~increase the dividends we pay to these plans. These estimates and assumptions may change based on economic conditions, actual stock and bond market performance, changes in interest rates and changes in governmental regulations. In addition, the Pension Protection Act of 2006 changed the minimum funding requirements for defined benefit pension plans with modifications that allowed additional flexibility in the timing of contributions. 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 dueXcel Energy Inc. to ~~high retirements or employees leaving PSCo~~help support Xcel Energy Inc.’s cash needs. This could ~~trigger settlement accounting and could require PSCo to recognize material incremental pension expense related to unrecognized plan losses in the year these 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~~liquidity. The most restrictive dividend limitation 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 operating results,~~PSCo is imposed by its credit facility, which limits the debt-to-total capitalization ratio. See Note 5 to the consolidated financial ~~position, and liquidity. We believe that our employee benefit costs, including costs related to health care plans~~statements for our employees and former employees, will continue to rise. Changes in industry standards utilized by management 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.further information.

~~Federal tax law may significantly impact our business.~~

PSCo collects through regulated rates its estimated federal, state and local tax payments. There are a number of provisions in federal tax law designed to incentivize capital investments which have benefited our customers by keeping our utility subsidiaries’ rates lower than rates calculated without such provisions. Examples include the use of accelerated depreciation for most of our capital investments, PTCs for wind energy, ITCs for solar energy and R&E tax credits and deductions. 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 could change the economics of resources and our resource selections. While regulation allows us to incorporate changes in tax law into the rate-setting process, 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.

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 ~~a variety of~~ inherent hazards and operating risks, such as leaks, explosions, outages and mechanical ~~problems, which could cause substantial financial losses.~~problems. Our electric transmission and distribution activities also include inherent hazards and operating risks such as contact, fire and ~~widespread~~ outages which could cause substantial financial losses. ~~In addition, these~~These natural gas and electric risks could result in loss of ~~human~~ life, significant property damage, ~~to property,~~ environmental pollution, impairment of our operations and substantial ~~losses to us.~~losses. We maintain insurance against some, but not all, of these risks and losses.

The occurrence of ~~any of~~ these events, if not fully covered by insurance, could have a material effect on our ~~financial position and~~ results of ~~operations. For our natural gas transmission~~operations, financial condition or ~~distribution lines located near populated areas, the level of potential damages resulting from these risks is greater.~~cash flows.

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

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

Most electric utility investments ~~are long-lived and~~ are planned to be used for decades. Transmission and generation investments typically have long lead times and ~~therefore~~ 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 ~~over the planning horizon~~ 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, ~~public policy has driven~~ increases in appliance, ~~and~~ lighting ~~efficiency~~ and energy ~~efficient buildings,~~efficiency, wider adoption and lower cost of renewable generation and distributed generation, ~~including community solar gardens and customer-sited solar,~~ shifts away from coal generation to decrease CO₂carbon dioxide emissions and increasing use of natural gas in electric generation driven by lower natural gas prices. ~~Over time, customer~~

Customer adoption of these technologies and increased energy efficiency could result in excess transmission and generation resources as well as stranded costs if PSCo 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 ~~also~~ 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.

The resource plans reviewed and approved by our state regulators assume continuation of the traditional utility cost of service model under which utility costs are recovered from customers as they receive the benefit of service. PSCo is engaged in significant and ongoing infrastructure investment programs to accommodate renewable distributed generation and maintain high system reliability. Changing customer expectations and ~~changing~~ technologies are requiring significant investments in advanced grid infrastructure. This ~~also~~ increases the exposure to potential outdating of technologies and ~~the~~ resultant risks. ~~PSCo is also investing in renewable and natural gas-fired generation to reduce our CO~~₂ ~~emissions profile.~~ The inability of coal mining companies to attract capital could disrupt longer-term supplies. ~~Early plant retirements that may result from these changes could expose us to premature financial obligations, which could result in less than full recovery of all remaining costs. Both decreasing~~Decreasing use per customer driven by appliance and lighting efficiency and the availability of cost-effective distributed generation ~~puts~~places downward pressure on ~~load~~sales growth. This ~~could~~may lead to under recovery of costs, excess resources to meet customer demand and increases in electric rates. Finally, multiple states ~~served by a single system~~ 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.

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, 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.

We also engage in wholesale sales and purchases of electric capacity, energy and energy-related products as well as natural gas. In many markets, ~~in which we operate,~~ emission allowances and/or ~~renewable energy credits~~RECs are also needed to comply with various statutes and commission ~~rulings associated with energy transactions.~~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 (mark-to-market accounting).~~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.

If we encounter market supply shortages or our suppliers are otherwise unable to meet their contractual obligations, we may be unable to fulfill our contractual obligations to our customers at previously anticipated costs. Therefore, a significant disruption could cause us to seek alternative supply services at potentially higher costs or suffer increased liability for unfulfilled contractual obligations. Any significantly higher energy or fuel costs relative to corresponding sales commitments could 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 may cause short-term disruptions in our ability to provide electric and/or natural gas services to our customers. The impact of these cost and reliability issues depends on our operating conditions such as generation fuels mix, availability of water for cooling, availability of fuel transportation including rail shipments of coal, electric generation capacity, transmission, natural gas pipeline capacity, etc. Failure to provide service due to disruptions could also result in fines, penalties or cost disallowances through the regulatory process.

As we are a subsidiary of Xcel Energy Inc., we may be negatively affected by events impacting the credit or liquidity of Xcel Energy Inc. and its affiliates.

If Xcel Energy Inc. were to become obligated to make payments under various guarantees and bond indemnities or to fund its other contingent liabilities, or if either Standard & Poor’s or Moody’s were to downgrade Xcel Energy Inc.’s credit rating below investment grade, Xcel Energy Inc. may be required to provide credit enhancements in the form of cash collateral, letters of credit or other security to satisfy part or potentially all of these exposures. If either Standard & Poor’s or Moody’s were to downgrade Xcel Energy Inc.’s debt securities below investment grade, it would increase Xcel Energy Inc.’s cost of capital and restrict its access to the capital markets. This could limit Xcel Energy Inc.’s ability to contribute equity or make loans to us, or may cause Xcel Energy Inc. to seek additional or accelerated funding from us in the form of dividends. If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.

As of Dec. 31, ~~2017,~~2018, Xcel Energy Inc. and its utility subsidiaries had approximately ~~$14.5~~$15.8 billion of long-term debt and ~~$1.3~~$1.4 billion of short-term debt and current maturities. Xcel Energy Inc. provides various guarantees and bond indemnities supporting some of its subsidiaries by guaranteeing the payment or performance by these subsidiaries for specified agreements or transactions.

Xcel Energy also has other contingent liabilities resulting from various tax disputes and other matters. Xcel Energy Inc.’s exposure under the guarantees is based upon the net liability of the relevant subsidiary under the specified agreements or transactions. The majority of Xcel Energy Inc.’s guarantees limit its exposure to a maximum amount that is stated in the guarantees. As of Dec. 31, ~~2017,~~2018, Xcel Energy had guarantees outstanding with a maximum stated amount of approximately ~~$19~~$17.8 million and immaterial exposure. Xcel Energy also had additional guarantees of ~~$53~~$51.1 million at Dec. 31, ~~2017~~2018 for performance and payment of surety bonds for the benefit of itself and its subsidiaries, with total exposure that cannot be estimated at this time. If Xcel Energy Inc. were to become obligated to make payments under these guarantees and bond indemnities or become obligated to fund other contingent liabilities, it could limit Xcel Energy Inc.’s ability to contribute equity or make loans to us, or may cause Xcel Energy Inc. to seek additional or accelerated funding from us in the form of dividends. If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.

We have historically paid quarterly dividends to Xcel Energy Inc. In 2018, 2017 ~~2016~~ and ~~2015~~2016 we paid ~~$334~~$375.3 million, ~~$337~~$333.9 million and ~~$331~~$336.6 million of dividends to Xcel Energy Inc., respectively. If Xcel Energy Inc.’s cash requirements increase, our Board of Directors could decide to increase the dividends we pay to Xcel Energy Inc. to help support Xcel Energy Inc.’s cash needs. This could adversely affect our liquidity. The most restrictive dividend limitation for PSCo is imposed by its credit facility, which limits the debt-to-total capitalization ratio. See ~~Item~~Note 5 to the consolidated financial statements for further ~~discussion~~information.

Financial Risks

Our profitability depends on ~~dividend limitations.~~our ability to recover costs from our customers and changes in regulation may impair our ability to recover costs from our 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 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 our costs incurred in a test year. We are subject to both future and historical test years depending upon the regulatory jurisdiction. Thus, the rates we are allowed to charge may or may not match our 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 commission will judge all of our costs to be prudent, which could result in disallowances, or that the regulatory process 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 we will not be able to fully recover our fuel costs from our customers. Furthermore, there could be changes in the regulatory environment that would impair our ability to recover costs historically collected from our customers, or these factors could cause us 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.

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 will remain in effect, or that a rating will not be lowered or withdrawn by a rating agency. Significant events including a 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, we 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 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 the California Independent System Operator, SPP, PJM Interconnection, LLC, Midcontinent Independent Transmission System Operator, Inc. and the ERCOT, 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 PSCo could trigger settlement accounting and could require PSCo 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 operating results, financial condition and 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.

Federal tax law may significantly impact our business.

PSCo collects 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.

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 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 causesignificant 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 ongoing operations, restoration operations, our reputation and could introduce financial risk or risks of fines.

Public Policy Risks

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

~~Increased public awareness and concern regarding climate change may result in more state, regional and/or federal requirements to reduce or mitigate the effects of GHGs.~~ Legislative and regulatory responses related to climate change and new interpretations of existing laws ~~through climate change litigation~~ create financial risk as our ~~electric generating~~ 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. ~~International agreements could have an impact to the extent they lead to future federal or state regulations.~~

~~In 2015, the 21~~^st Conference of the Parties to the United Nations Framework Convention on Climate Change reached consensus among 190 nations on an agreement (the Paris Agreement) that establishes a framework for GHG mitigation actions by all countries (“nationally determined contributions”), with a goal of holding the increase in global average temperature to below 2^o ~~Celsius above pre-industrial levels and an aspiration to limit the increase to 1.5~~^oCelsius. If implemented, the Paris Agreement could result in future additional GHG reductions in the United States. On June 21, 2017, President Trump announced that the U.S. would withdraw from the Paris Agreement. Such a withdrawal, under terms of the Agreement, becomes effective in four years. Many state and local government entities, however, have indicated that they intend to pursue GHG mitigation with a goal of achieving the GHG reductions in the United States anticipated by the Paris Agreement.

We ~~have been, and in the future~~ may be subject to climate change lawsuits. An adverse outcome ~~in any of these cases~~ 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 ~~and financial condition~~ if such costs are not recovered through regulated rates.

~~Some~~Although the United States has not adopted any international or federal GHG emission reduction targets, many states and localities ~~have indicated a desire to~~may continue to pursue climate policies ~~even~~ in the absence of federal mandates. All of the steps that PSCo 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 PSCo in a good position to meet federal or international standards ~~under~~being discussed, the ~~CPP or the Paris Agreement, repeal~~lack of ~~these policies would~~federal action does not adversely impact ~~those~~these state-endorsed actions and plans.

~~Whether under state or federal programs, an important factor is our ability to recover the costs incurred to comply with any regulatory requirements in a timely manner.~~ 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 financial condition, results of ~~operations.~~

operations 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 ~~now~~ impose penalties of up to ~~$1.2~~$1.3 million per violation per day, particularly as it relates to energy trading activities for both electricity and natural gas. ~~Under statute, the FERC can adjust penalties for inflation.~~ In addition, NERC electric reliability standards and critical infrastructure protection requirements are mandatory and subject to potential financial ~~penalties by regional entities, the NERC or the FERC for violations.~~penalties. Additionally, the PHMSA, ~~the~~ Occupational Safety and Health Administration and other federal agencies ~~also~~ 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 in the event of non-compliance.~~penalties. If a serious reliability or safety incident did occur, it could have a material effect on our ~~operations or financial results.~~

~~Macroeconomic Risks~~

~~Economic conditions impact our business.~~

Our operations are affected by local, national and worldwide economic conditions. Growth in our customer base is correlated with economic conditions. While the number of customers is growing, sales growth is relatively modest due to an increased focus on energy efficiency including federal standards for appliance and lighting efficiency and distributed generation, primarily solar PV. Instability in the financial markets also may affect the cost of capital and our ability to raise capital, which is discussed in the capital market risk factor section above.

Further, worldwide economic activity has an impact on the demand for basic commodities needed for utility infrastructure, such as steel, copper, aluminum, etc., 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 costs of the materials we use. We may be at risk for higher than anticipated inflation both with respect to our own workforce, as well as our materials and labor that we contract for with others. There may be delays before these higher costs can be recovered in rates.

~~Our operations could be impacted by war, acts of terrorism, threats of terrorism or disruptions in normal operating conditions due to localized or regional events.~~

Our generation plants, fuel storage facilities, transmission and distribution facilities and information and control systems may be targets of terrorist activities. Any such 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 and results of operations. 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. In addition, we may experience additional capital and operating costs to implement security for our plants, such as additional physical plant security and additional security personnel. We have also already incurred increased costs for compliance with NERC reliability standards associated with critical infrastructure protection. In addition, we may experience additional capital and operating costs to comply with the NERC critical infrastructure protection standards as they are implemented and clarified.

The insurance industry has also been affected by these events and the availability of insurance may decrease. In addition, the insurance we are able to obtain 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, as well as our brand and reputation. Because our generation, the transmission systems and local natural gas distribution companies 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 (such as severe storm, severe temperature extremes, wildfires, solar storms, generator or transmission facility outage, breakdown or failure of equipment, pipeline rupture, railroad disruption, operator error, sudden and significant increase or decrease in wind generation or any disruption of work force such as may be caused by flu or other epidemic) 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 financial condition and results.

~~The degree to which we are able to maintain day-to-day operations in response to unforeseen events will in part determine the financial impact of certain events on our financial condition and results.It is difficult to predict the magnitude of such events and associated impacts.~~

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

We operate in an industry that requires the continued operation of sophisticated information technology and 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 and other individuals.

Our generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets, as well as the information processed in our systems (such as information about 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 exposing 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 regulatory scrutiny at both the federal and state level. We are unable to quantify the potential impact of cyber security threats or subsequent related actions. These potential cyber security incidents and corresponding 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 designed 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 were to fail or be breached, or those of our third-party service providers, we may be unable to fulfill critical business functions, including effectively maintaining certain internal controls over financial reporting. 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.

~~Rising energy prices could negatively impact our business.~~

Although commodity prices are currently relatively low, 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, 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 as compared with expenditures for fuel purchases could have an impact on our cash flows. Low fuel costs could have a positive impact on sales, though low oil and natural gas prices could negatively impact oil and gas production activities and subsequently our sales volumes and revenue. We are unable to predict future prices or the ultimate impact of such prices on our results of operations or cash flows.

~~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 throughout our service territory, and 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.

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 ~~operations~~customers’ energy needs vary with weather. To the extent weather conditions are affected by climate change, customers’ energy use ~~third party contractors~~could increase or decrease. Increased energy use due to weather changes may require us to invest in ~~addition~~generating assets, transmission and infrastructure. Decreased energy use due to ~~employees~~weather changes may result in decreased revenues. Extreme weather conditions in general require system backup, costs, and can contribute to ~~perform periodic~~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 ~~on-going work.~~

We rely on third party contractors with specific qualifications to perform work both for ongoing operations and maintenance and for capital construction. We have contractual arrangements with these contractors which typically include performance standards, progress payments, insurance requirements and security for performance. Cyber security breaches seen insnow or ice storms occur. To the ~~news have at times exploited third party equipment or software in order to gain access. Poor vendor performance~~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 PSCo 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 ~~going operations, restoration operations,~~the economic health of our ~~reputation~~communities. The cost of additional regulatory requirements, such as regulation of GHG,could impact the availability of goods and ~~could introduce~~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 ~~risks of fines.~~

cause us to receive less than ideal terms and conditions.

Item 1B — Unresolved Staff Comments

None.

~~None.~~

Item 2 — Properties

Virtually all of the utility plant property of PSCo is subject to the lien of its first mortgage bond indenture.

Electric Utility Generating Stations:

Station, Location and Unit
Fuel Installed Summer 2017
Net Dependable
Capability (MW)
Steam:
Comanche-Pueblo, Colo.
Unit 1 Coal 1973 325

Unit 2 Coal 1975 335

Unit 3 Coal 2010 500
^(a)
Craig-Craig, Colo., 2 Units Coal 1979-1980 83
^(b)
Hayden-Hayden, Colo., 2 Units Coal 1965-1976 233
^(c)
Pawnee-Brush, Colo., 1 Unit Coal 1981 505

Valmont-Boulder, Colo., 1 Unit Coal 1964 —
^(d)
Combustion Turbine:
Blue Spruce-Aurora, Colo., 2 Units Natural Gas 2003 264

Cherokee-Denver, Colo., 1 Unit Natural Gas 1968 310
^(e)
Cherokee-Denver, Colo., 3 Units Natural Gas 2015 576

Fort St. Vrain-Platteville, Colo., 6 Units Natural Gas 1972-2009 968

Rocky Mountain-Keenesburg, Colo., 3 Units Natural Gas 2004 580

Various locations, 6 Units Natural Gas Various 171

Hydro:
Cabin Creek-Georgetown, Colo.
Pumped Storage, 2 Units Hydro 1967 210

Various locations, 9 Units Hydro Various 26

Total 5,086



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)	~~Based on PSCo’s ownership interest of 67 percent of Unit 3.~~Summer 2018 net dependable capacity.


^(b)	~~Based on~~In 2018, the CPUC approved early retirement of PSCo’s ~~ownership interest of 10 percent. Craig Unit~~Comanche Units 1 ~~is expected to be early retired~~and 2 in ~~approximately 2025.~~2022 and 2025, respectively.


^(c)	Based on PSCo’s ownership interest of ~~76 percent~~67% of Unit ~~1 and 37 percent of Unit 2.~~3.


^(d)	~~Valmont~~Craig Unit ~~5 was~~1 is expected to be retired early in ~~the third quarter of 2017.~~2025.


^(e)	~~Cherokee~~Based on PSCo’s ownership interest of 10%. Craig Unit ~~4 was fuel switched from coal~~1 is expected to ~~natural gas~~be retired early in ~~the third quarter of 2017.~~2025.


^(f)	Based on PSCo’s ownership interest of 76% 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).

Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, ~~2017:~~2018:



Conductor Miles
345 KV	~~2,630~~4,062
230 KV	~~12,911~~12,053
138 KV	9291
115 KV	~~4,969~~5,051
Less than 115 KV	~~76,998~~78,446

PSCo had ~~230~~232 electric utility transmission and distribution substations at Dec. 31, ~~2017.~~

2018.

Natural gas utility mains at Dec. 31, ~~2017:~~2018:



Miles
Transmission	~~2,315~~2,081
Distribution	~~22,540~~22,518

Item 3 — Legal Proceedings

PSCo is involved in various litigation matters that are being defended and handled in the ordinary course of business. ~~The assessment~~Assessment of whether a loss is probable or is a reasonable possibility, and whether ~~the~~a loss or a range of loss is estimable, often involves a series of complex judgments ~~about~~regarding future events. Management maintains accruals for ~~such~~ losses that are probable of being incurred and subject to reasonable estimation. Management ~~is sometimes~~may be unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to, when (1) ~~the~~ damages sought are indeterminate, (2) ~~the~~ proceedings are in the early stages or (3) ~~the~~ matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.

~~Additional Information~~

See ~~Note 12 to the consolidated financial statements for further discussion of legal claims and environmental proceedings. See Item 1 and~~ Note 11 to the consolidated financial statements, Item 1 and Item 7 for ~~a discussion of proceedings involving utility rates and other regulatory matters.~~

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

PSCo is a wholly owned subsidiary of Xcel Energy Inc. and there is no market for its common equity securities. ~~PSCo’s dividends are subject~~See Note 5 to the ~~FERC’s jurisdiction under the Federal Power Act, which prohibits the payment of dividends out of capital accounts; payment of dividends is allowed out of retained earnings only.~~

~~See Note 4 to the~~consolidated financial statements for further ~~discussion of PSCo’s dividend policy.~~

information.

The dividends declared during ~~2017~~2018 and ~~2016~~2017 were as follows:


(Thousands of Dollars)	2017		2016
(Millions of Dollars)					2018		2017
First quarter	$	87,104	$	83,914	$	95.4	$	87.1
Second quarter	83,978		86,509		100.3		84.0
Third quarter	88,589		82,785		103.5		88.6
Fourth quarter	76,195		74,208		91.5		76.2

Item 6 — Selected Financial Data

This is omitted per conditions set forth in general instructions I (1)(a) and (b) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).

Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations

Discussion of financial condition and liquidity for PSCo is omitted per conditions set forth in general instructions ~~I (1)~~ I(1)(a) and (b) of Form 10-K for wholly owned subsidiaries. It is replaced with management’s narrative analysis ofand the results of operations for the current year as set forth in general instructions ~~I (2)~~ I(2)(a) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).

Non-GAAP Financial ~~Review~~

Measures

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

~~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 TCJA’s impact to PSCo and its customers,GAAP, as well as ~~assumptions~~certain non-GAAP financial measures such as electric margin, natural gas margin and ongoing earnings. Generally, a non-GAAP financial measure is a measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are adjusted from measures calculated and presented in accordance with GAAP. PSCo’s management uses non-GAAP measures for financial planning and analysis, for reporting of results, in determining performance-based compensation and communicating its earnings outlook to analysts and investors. Non-GAAP financial measures are intended to supplement investors’ understanding of our performance and should not be considered alternatives for financial measures presented in accordance with GAAP. These measures are discussed in more detail below and may not be comparable to other ~~statements identified in this document by~~companies’ similarly titled non-GAAP financial measures.

Electric and Natural Gas Margins

Electric margin is presented as electric revenues less electric fuel and purchased power expenses. Natural gas margin is presented as natural gas revenues less the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” “will,” “would”cost of natural gas sold and ~~similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made,~~transported. Expenses incurred for electric fuel 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, 2017 (including risk factors listed from time to time by PSCo in reports filed with the SEC, including “Risk Factors” in Item 1A of this Annual Report on Form 10-K and Exhibit 99.01 hereto), could cause actual results to differ materially from management expectations as suggested by such forward-looking information: general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditurespurchased power and the ~~ability~~cost of ~~PSCo and its subsidiaries to obtain financing on favorable terms; business conditions~~natural gas are generally recovered through various regulatory recovery mechanisms. As a result, changes in ~~the energy industry, including the risk of a slow down~~these expenses are generally offset in the U.S. economy or delay in growth, recovery, trade, fiscal, taxation and environmental policies in areas where PSCo has a financial interest; customer business conditions; actions of credit rating agencies; competitive factors, including the extent and timing of the entry of additional competition in the markets served by PSCo and its subsidiaries; unusual weather; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates, or have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters theoperating revenues.

Management believes electric and natural gas ~~markets; costs and~~margins provide the most meaningful basis for evaluating our operations because they exclude the revenue impact of fluctuations in these expenses. These margins can be reconciled to operating income, a GAAP measure, by including other effects of legal and administrative proceedings, settlements, investigations and claims; financial or regulatory accounting policies imposed by regulatory bodies; outcomes of regulatory proceedings; availability oroperating revenues, cost of ~~capital;~~sales-other, O&M expenses, conservation and ~~employee work force factors.~~DSM expenses, depreciation and amortization and taxes (other than income taxes).

Earnings Adjusted for Certain Items (Ongoing Earnings)

Ongoing earnings reflect adjustments to GAAP earnings (net income) for certain items.

Management uses these non-GAAP financial measures to evaluate and provide details of PSCo’s core earnings and underlying performance. Management believes these measurements are useful to investors to evaluate the actual and projected financial performance and contribution of PSCo.

Results of Operations

PSCo’s net income was approximately ~~$494~~$551.7 million for ~~2017,~~2018, compared with approximately ~~$463~~$494.1 million for ~~2016.~~2017. The increase ~~in earnings,~~was driven by higher ~~electric and~~ natural gas margins largely due to a natural gas rate increase, higher electric margins (before the impact of the TCJA) reflecting favorable weather and sales growth, and additional AFUDC ~~primarily related to~~associated with the Rush Creek wind ~~project and a lower ETR, was~~project. These items were partially offset by higher O&M expenses, interest charges, depreciation expense ~~interest charges~~ and ~~the impact of unfavorable weather.~~property taxes.

Electric ~~Revenues and~~ Margin

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

Electric revenues and ~~margin:~~margin before and after the impact of TCJA:

(Millions of Dollars) 2017 2016
Electric revenues $ 3,004
$ 3,049
Electric fuel and purchased power (1,127 ) (1,196 )
Electric margin $ 1,877
$ 1,853

~~The following tables summarize the components of the changes in electric revenues and electric margin for the year ended Dec. 31:~~

~~Electric Revenues~~

(Millions of Dollars) 2017 vs. 2016
Fuel and purchased power cost recovery $ (58 )
DSM program revenues (offset by expenses) 6
Non-fuel riders 5
Other, net 2
Total decrease in electric revenues $ (45 )



(Millions of Dollars)	2018			2017
Electric revenues before TCJA impact	$	3,095.4		$	3,003.8
Electric fuel and purchased power	(1,157.2		)	(1,126.7		)
Electric margin before TCJA impact	$	1,938.2		$	1,877.1
TCJA impact (offset as a reduction in income tax)	(64.2		)	—
Electric margin	$	1,874.0		$	1,877.1

Electric Margin


(Millions of Dollars)	2017 vs. 2016		2018 vs. 2017
Retail sales growth (excluding weather impact)			$	16.4
DSM program revenues (offset by expenses)	$	6	14.1
Non-fuel riders	5		12.9
Earnings test	3
Fuel handling and procurement	3
Trading	3
Estimated impact of weather			12.8
Other, net	4		4.9
Total increase in electric margin	$	24
Total increase in electric margin before TCJA impact			$	61.1
TCJA impact (offset as a reduction in income tax)			(64.2		)
Total decrease in electric margin			$	(3.1	)

Natural Gas ~~Revenues and~~ Margin

Total natural gas expense varies with changing sales and the cost of natural gas. However, fluctuations in the cost of natural gas ~~has~~have minimal impact on natural gas margin due to natural gas cost recovery mechanisms. ~~The following table details natural~~

Natural gas revenues and ~~margin:~~margin before and after the impact of the TCJA:

(Millions of Dollars) 2017 2016
Natural gas revenues $ 995
$ 958
Cost of natural gas sold and transported (459 ) (425 )
Natural gas margin $ 536
$ 533

~~The following tables summarize the components of the changes in natural gas revenues and natural gas margin for the year ended Dec. 31:~~

~~Natural Gas Revenues~~

(Millions of Dollars) 2017 vs. 2016
Purchased natural gas adjustment clause recovery $ 32
Infrastructure and integrity riders 13
Estimated impact of weather (4 )
Retail rate decrease (4 )
Total increase in natural gas revenues $ 37



(Millions of Dollars)	2018			2017
Natural gas revenues before TCJA impact	$	1,044.8		$	995.2
Cost of natural gas sold and transported	(428.4		)	(458.7		)
Natural gas margin before TCJA impact	$	616.4		$	536.5
TCJA impact (offset as a reduction in income tax)	(30.2		)	—
Natural gas margin	$	586.2		$	536.5

Natural Gas Margin



(Millions of Dollars)	2018 vs. 2017
Retail rate increase	$	50.1
Infrastructure and integrity riders	14.9
Estimated impact of weather	8.0
Retail sales growth (excluding weather impact)	2.8
DSM program revenues (offset by expenses)	2.6
Other, net	1.5
Total increase in natural gas margin before TCJA impact	$	79.9
TCJA impact (offset as a reduction in income tax)	(30.2		)
Total increase in natural gas margin	$	49.7

(Millions of Dollars) 2017 vs. 2016
Infrastructure and integrity riders $ 13
Estimated impact of weather (4 )
Retail rate decrease (4 )
Other, net (2 )
Total increase in natural gas margin $ 3

Non-Fuel Operating Expenses and Other Items

O&M Expenses— O&M expenses increased $26.7 million, or 3.5%, for 2018. Significant changes are summarized below:



(Millions of Dollars)	2018 vs. 2017
Distribution costs	$	13.0
Natural gas systems damage prevention	7.2
Business systems and contract labor	6.7
Plant generation costs	(1.4		)
Other, net	1.2
Total increase in O&M expenses	$	26.7

Distribution costs reflect higher maintenance expenses, including vegetation management; and

Business systems and contract labor costs increased due to growing network and storage needs, cybersecurity, initiatives to support our customer strategy, and initiatives to improve business processes.

DSM Program Expenses — DSM program expenses increased $7$17.2 million, or ~~5.8 percent,~~13.8%, for ~~2017 compared with 2016.~~2018. The increase was due to ~~higher recovery rates.~~increases in conservation programs to help customers reduce energy use. DSM expenses are generally recovered concurrently through riders and base rates. Timing of recovery may ~~not correspond~~vary from when costs are incurred.

Taxes (Other than Income Taxes)— Taxes (other than income taxes) increased $6.2 million, or 3.2%, for 2018 compared with 2017. The increase was primarily due to ~~the period in which costs were incurred.~~higher property taxes.

Depreciation and Amortization — Depreciation and amortization ~~expense~~ increased ~~$28~~$89.6 million, or ~~6.3 percent,~~19.0%, for ~~2017~~2018 compared with ~~2016.~~2017. The increase was primarily ~~attributable to~~driven by capital investments ~~as well as~~and additional amortization of a ~~new enterprise resource planning system.~~prepaid pension asset related to TCJA settlements, which were offset by lower income taxes (approximately $75 million).

AFUDC, Equity and Debt — AFUDC increased by ~~$16~~$37.4 million for ~~2017~~2018 compared with ~~2016.~~2017. The increase was primarily due to ~~higher CWIP, particularly~~ the Rush Creek wind ~~project.~~project and other capital investments.

Interest Charges — Interest charges increased by $9$17.2 million, or ~~5.0 percent,~~9.0%, for ~~2017~~2018 compared with ~~2016.~~2017. The increase iswas primarily due to higher ~~long-term~~ debt levels to fund capital investments, partially offset by ~~refinancings~~refinancing at lower interest rates.

Income Taxes — Income tax expense decreased ~~$22~~$138.5 million for ~~2017 compared with 2016.~~2018. The decrease ~~in income tax expense~~ was primarily due to a lower federal tax rate due to the ~~estimated~~TCJA and lower pretax earnings, an increase in plant-related regulatory difference related to ARAM (net of deferrals), 2018 non-plant excess accumulated deferred income tax amortization, 2018 wind PTCs; partially offset by a one-time, non-cash, income tax ~~benefit recognized in the fourth quarter~~expense related to the ~~TCJA (see Note 7) and increased permanent plant-related adjustments.~~impacts of tax reform in 2017. The ETR was ~~33.8 percent~~17.1% for ~~2017~~2018 compared with ~~37.1 percent~~33.8% for ~~2016.~~2017. The lower ETR in ~~2017~~2018 was ~~primarily~~largely due to the adjustments ~~referenced~~ above.

Regulation

FERC and State Regulation — The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, hydro facility licensing, natural gas transportation, asset transactions and mergers, accounting practices and certain other activities of PSCo, including enforcement of NERC mandatory electric reliability standards. State and local agencies have jurisdiction over many of PSCo’s activities, including regulation of retail rates and environmental matters.

Xcel Energy, which includes PSCo, attempts to mitigate the risk of regulatory penalties through formal training on prohibited practices and a compliance function that reviews interaction with the markets under FERC and Commodity Futures Trading Commission jurisdictions. Public campaigns are conducted to raise awareness of the public safety issues of interacting with our electric systems. While programs to comply with regulatory requirements are in place, there is no guarantee the compliance programs or other measures will be sufficient to ensure against violations. Decisions by these regulators can significantly impact PSCo’s results of operations.

Tax Reform — Regulatory Proceedings

In December 2017, the TCJA was signed into law, enacting significant changes to the Internal Revenue Code, including a reduction of the corporate income tax rate from 35% to 21% and a resulting reduction in deferred tax assets and liabilities. As a result of IRS requirements and past regulatory treatment of income taxes in the determination of regulated rates, the impacts of TCJA are primarily recognized as a regulatory liability. Treatment of these tax benefits, (e.g., degree to which benefits will be used to refund currently effective rates and/or used to mitigate other costs and potential future rate increases) is subject to regulatory approval. Concluded and ongoing regulatory TCJA proceedings:



Utility Service	Approval Date	Additional Information
Natural Gas	December 2018	In February 2018, the administrative law judge recommended approval of a TCJA settlement agreement, which included a $20 million reduction to PSCo’s provisional rates effective March 1, 2018. In September 2018, PSCo revised its 2018 TCJA benefit estimate to $24 million and requested an equity ratio of 56% to offset the negative impact of the TCJA on credit metrics. In December 2018, the CPUC approved an equity ratio of 54.6% and utilized the remainder of the TCJA benefit to reduce an existing prepaid pension asset. The CPUC also ordered 2018 excess non-plant ADIT benefits of $11.1 million be utilized to accelerate amortization of the prepaid pension asset.
Electric	June 2018 October 2018	In 2018, the CPUC approved a TCJA settlement agreement that included a customer refund of $42 million in 2018, with the remainder of the $59 million of TCJA benefits to be used to accelerate the amortization of an existing prepaid pension asset. For 2019, the expected customer refund is estimated to be $67 million, and amortization of the prepaid pension asset is estimated to be $34 million. Impacts of the TCJA for 2020 and future years are expected to be addressed in a future electric rate case.

Pending and Recently Concluded Regulatory Proceedings



Mechanism	Utility Service	Amount Requested (in millions)	Filing Date	Approval	Additional Information
PSCo (CPUC)
Multi-Year Rate Case	Natural Gas	$139	June 2017	Received	Proposed annual revenue request of $139 million over three years, $63 million for 2018. Requested an ROE of 10.0% and an equity ratio of 55.25%. In August 2018, CPUC approved an increase of $46 million (prior to TCJA impacts). The interim decision included application of a 2016 historic test year, a 13-month average rate base, an ROE of 9.35%, an equity ratio of 54.6% and provided no return on the prepaid pension asset. In December 2018, CPUC issued the final ruling which upheld the interim decision and finalized the TCJA impacts. In October 2018, the CPUC approved a settlement to extend the PSIA rider through 2021.
DSM Incentive	Electric & Natural Gas	$11	April 2018	Received	PSCo earned an electric and natural gas DSM incentive of $9 million and $2 million, respectively, for achieving its 2017 savings goals.

Item 7A — Quantitative and Qualitative Disclosures About Market Risk

Derivatives, Risk Management and Market Risk

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

See Note 109 to the consolidated financial statements for further ~~discussion of market risks associated with derivatives.~~

information.

PSCo is exposed to the impact of adverse changes in price for energy and energy-related products, which is partially mitigated by the use of commodity derivatives. In addition to ongoing monitoring and maintaining credit policies intended to minimize overall credit risk, ~~when necessary,~~ management takes steps to mitigate changes in credit and concentration risks associated with its derivatives and other contracts, including parental guarantees and requests of collateral. While PSCo expects that the counterparties will perform under the contracts underlying its derivatives, the contracts expose PSCo to some credit and ~~nonperformance~~non-performance risk.

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

investments.

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

Wholesale and Commodity Trading Risk — PSCo conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. PSCo’s risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management ~~committee, which is made up of management personnel not directly involved in the activities governed by the policy.~~committee.

At Dec. 31, ~~2017, the~~2018, fair values by source for net commodity trading contract assets were as follows:


	Futures / Forwards											Futures / Forwards
(Thousands of Dollars)	Source of Fair Value	Maturity Less Than 1 Year		Maturity 1 to 3 Years		Maturity 4 to 5 Years		Maturity Greater Than 5 Years		Total Futures/ Forwards Fair Value
(Millions of Dollars)												Source of Fair Value	Maturity Less Than 1 Year		Maturity 1 to 3 Years		Maturity 4 to 5 Years		Maturity Greater Than 5 Years		Total Futures/ Forwards Fair Value
PSCo	1	$	291	$	179	$	—	$	—	$	470	2	$	0.8	$	0.5	$	—	$	—	$	1.3

12 — Prices ~~actively quoted or~~ based on ~~actively quoted prices.~~

models and other valuation methods.

Changes in the fair value of commodity trading contracts before the impacts of margin-sharing ~~mechanisms~~ for the years ended Dec. 31 were as follows:


(Thousands of Dollars)	2017			2016
(Millions of Dollars)							2018			2017
Fair value of commodity trading net contract assets outstanding at Jan. 1	$	(188	)	$	112		$	0.5		$	(0.2	)
Contracts realized or settled during the period	(775		)	(654		)	(7.8		)	(0.8		)
Commodity trading contract additions and changes during the period	1,433			354			8.6			1.5
Fair value of commodity trading net contract assets outstanding at Dec. 31	$	470		$	(188	)	$	1.3		$	0.5

At Dec. 31, 2018, a 10% increase in market prices for commodity trading contracts would decrease pretax income by approximately $0.2 million, whereas a 10% decrease would increase pretax income by approximately $0.2 million. At Dec. 31, 2017, a ~~10 percent~~10% increase in market prices for commodity trading contracts would increase pretax income by approximately $0.6 million, whereas a ~~10 percent~~10% decrease would decrease pretax income by approximately $0.6 million. At Dec. 31, 2016, a 10 percent increase in market prices for commodity trading contracts would decrease pretax income by approximately $0.9 million, whereas a 10 percent decrease would increase pretax income by approximately $0.9 million.

PSCo’s wholesale and commodity trading operations measure the outstanding risk exposure to price changes on transactions, contracts and obligations ~~that have been entered into, but not closed, including transactions that are not recorded at fair value,~~ using ~~an industry standard methodology known as Value at Risk (VaR).~~VaR. VaR expresses the potential change in fair value on the outstanding transactions, contracts and obligations over a particular period of time under normal market conditions. ~~The~~

VaRs for the NSP-Minnesota and PSCo commodity trading operations, calculated on a consolidated basis using a Monte Carlo simulation with a ~~95 percent~~95% confidence level and a one-day holding period, were as follows:


(Millions of Dollars)	Year Ended Dec. 31		VaR Limit		Average		High		Low		Year Ended Dec. 31		VaR Limit		Average		High		Low
2018											$	4.83	$	6.00	$	0.62	$	5.63	$	0.06
2017	$	0.18	$	3.00	$	0.21	$	0.66	$	0.04	0.18		3.00		0.21		0.66		0.04
2016	0.09		3.00		0.16		0.38			0.05

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

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

~~At Dec. 31, 2017, a 100-basis-point change in the benchmark rate on PSCo’s variable rate debt would have no impact on annual pretax interest expense, and at Dec. 31, 2016 a 100-basis-point~~A 100 basis point change in the benchmark rate on PSCo’s variable rate debt would impact annual pretax interest expense by approximately ~~$1.3 million.~~ $3.1 million in 2018 and no impact in 2017.

See Note 109 to the consolidated financial statements for ~~a discussion of PSCo’s interest rate derivatives.~~

further information.

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

At Dec. 31, 2018, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $11.5 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $7.6 million. At Dec. 31, 2017, a ~~10 percent~~10% increase in commodity prices would have resulted in an increase in credit exposure of $17.4 million, while a decrease in prices of ~~10 percent~~10% would have resulted in an increase in credit exposure of $5.5 million. At Dec. 31, 2016, a 10 percent increase in commodity prices would have resulted in an increase in credit exposure of $14.3 million, while a decrease in prices of 10 percent would have resulted in a decrease in credit exposure of $2.2 million.

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

Fair Value Measurements

PSCo ~~follows accounting~~uses derivative contracts such as futures, forwards, interest rate swaps and ~~disclosure guidance on~~options to manage commodity price and interest rate risk. Derivative contracts, with the exception of those designated as normal purchase-normal sale contracts, are reported at fair value. PSCo’s investments held in rabbi trusts, pension and other postretirement funds are also subject to fair value ~~measurements that contains a hierarchy for inputs used in measuring fair value~~accounting.

See Notes 9 and ~~requires disclosure of the observability of the inputs used in these measurements. See Note~~ 10 to the consolidated financial statements for further ~~discussion of the fair value hierarchy and the amounts of assets and liabilities measured at fair value that have been assigned to Level 3.~~

information.

Commodity Derivatives — PSCo continuously monitors the creditworthiness of the counterparties to its commodity derivative contracts and assesses each counterparty’s ability to perform on the ~~transactions set forth in the contracts.~~transactions. Given ~~this assessment and~~ the typically short duration of these contracts, the impact of discounting commodity derivative assets for counterparty credit risk was not material to the fair value of commodity derivative assets at Dec. 31, ~~2017. PSCo also assesses the impact of its own~~2018.

Adjustments to fair value for credit risk ~~when determining the fair value~~ of commodity trading instruments are recorded in electric revenues. Credit risk adjustments for other commodity derivative instruments are recorded as other comprehensive income or deferred as regulatory assets and liabilities. Classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. The impact of discounting commodity derivative liabilities for credit risk was immaterial ~~to the fair value of commodity derivative liabilities~~ at Dec. 31, ~~2017.~~

Commodity derivative assets and liabilities assigned to Level 3 typically consist of forward and option contracts that are long-term in nature or relate to inactive delivery locations. Determining the fair value of certain commodity forwards and options can require management to make use of subjective price and volatility forecasts for inactive delivery locations and for contracts that extend to periods beyond those readily observable on active exchanges or quoted by brokers. When less observable forward price and volatility forecasts are significant to determining the value of commodity forwards and options, these instruments are assigned to Level 3. There were immaterial Level 3 commodity derivative assets or liabilities at Dec. 31, 2017.

2018.

Item 8 — Financial Statements and Supplementary Data

See Item 15-1 ~~in Part IV~~ for an index of financial statements included herein.

See Note 1715 to the consolidated financial statements for ~~summarized quarterly financial data.~~further information.

Management Report on Internal Controls Over Financial Reporting

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

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

In 2016, PSCo implemented the general ledger modules of a new enterprise resource planning system. PSCo initiated and implemented additional work management systems modules in 2017. PSCo does not believe this implementation had an adverse effect on its internal control over financial reporting.

PSCo management assessed the effectiveness of PSCo’s internal control over financial reporting as of Dec. 31, ~~2017.~~2018. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework (2013). Based on our assessment, we believe that, as of Dec. 31, ~~2017,~~2018, PSCo’s internal control over financial reporting is effective at the reasonable assurance level based on those criteria.



/s/ BEN FOWKE		/s/ ROBERT C. FRENZEL
Ben Fowke		Robert C. Frenzel
Chairman and Chief Executive Officer		Executive Vice President, Chief Financial Officer
Feb. ~~23, 2018~~22, 2019		Feb. ~~23, 2018~~22, 2019

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholder of

Public Service Company of Colorado

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Public Service Company of Colorado and subsidiaries (the ~~“Company”~~"Company") as of December 31, ~~2017~~2018 and ~~2016,~~2017, the related consolidated statements of income, comprehensive income, cash flows and, common ~~stockholder’s~~stockholder's equity for each of the three years in the period ended December 31, ~~2017,~~2018, and the related notes and the schedule listed in the Index at Item 15 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, ~~2017~~2018 and ~~2016,~~2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, ~~2017,~~2018, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.



/s/ DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
February 22, 2019

~~February 23, 2018~~	We have served as the Company’s auditor since 2002.

~~We have served as the Company's auditor since 2002.~~

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(amounts in ~~thousands)~~millions)


	Year Ended Dec. 31										Year Ended Dec. 31
	2017			2016				2015			2018			2017			2016
Operating revenues
Electric	$	3,003,808		$	3,049,352			$	3,115,257		$	3,031.2		$	3,003.8		$	3,049.4
Natural gas	995,214			957,721				1,006,666			1,014.6			995.2			957.7
Steam and other	43,487			40,723				41,590			40.4			43.5			40.7
Total operating revenues	4,042,509			4,047,796				4,163,513			4,086.2			4,042.5			4,047.8

Operating expenses
Electric fuel and purchased power	1,126,660			1,196,417				1,246,666			1,157.2			1,126.7			1,196.4
Cost of natural gas sold and transported	458,717			425,410				501,824			428.4			458.7			425.4
Cost of sales — steam and other	16,146			15,872				17,788			15.3			16.1			15.9
Operating and maintenance expenses	762,817			762,416				761,901			787.5			760.8			759.7
Demand side management program expenses	125,029			118,175				128,681			142.2			125.0			118.2
Depreciation and amortization	471,515			443,555				411,667			561.1			471.5			443.6
Taxes (other than income taxes)	195,695			196,330				195,285			201.9			195.7			196.3
Total operating expenses	3,156,579			3,158,175				3,263,812			3,293.6			3,154.5			3,155.5

Operating income	885,930			889,621				899,701			792.6			888.0			892.3

Other income, net	9,852			3,817				2,964			2.1			7.8			1.1
Allowance for funds used during construction — equity	29,803			18,557				14,485			56.4			29.8			18.6

Interest charges and financing costs
Interest charges — includes other financing costs of $6,281, $6,289 and $6,285, respectively	190,694			181,631				177,430
Interest charges — includes other financing costs of $6.5, $6.3 and $6.3, respectively											207.9			190.7			181.6
Allowance for funds used during construction — debt	(11,407		)	(7,045		)		(5,522		)	(22.2		)	(11.4		)	(7.0		)
Total interest charges and financing costs	179,287			174,586				171,908			185.7			179.3			174.6

Income before income taxes	746,298			737,409			��	745,242			665.4			746.3			737.4
Income taxes	252,179			273,918				278,440			113.7			252.2			273.9
Net income	$	494,119		$	463,491			$	466,802		$	551.7		$	494.1		$	463.5

See Notes to Consolidated Financial Statements

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(amounts in ~~thousands)~~millions)


	Year Ended Dec. 31									Year Ended Dec. 31
	2017			2016			2015			2018		2017		2016
Net income	$	494,119		$	463,491		$	466,802		$	551.7	$	494.1	$	463.5

Other comprehensive income (loss)

Pension and retiree medical benefits:
Net pension and retiree medical losses arising during the period, net of tax of $(3), $(138), and $0	(5		)	(223		)	—
Amortization of losses included in net periodic benefit cost, net of tax of $4, $2, and $0, respectively	5			3			—
Net pension and retiree medical losses arising during the period, net of tax of $0, $0, and ($0.1), respectively										—		—		(0.2		)
	—			(220		)	—			—		—		(0.2		)

Derivative instruments:
Net fair value decrease, net of tax of $0, $0, and $(20), respectively	—			—			(30		)
Reclassification of losses to net income, net of tax of $610, $648, and $39, respectively	1,005			1,056			72
Reclassification of losses to net income, net of tax of $0.4, $0.6, and $0.7, respectively										1.2		1.0		1.0
	1,005			1,056			42			1.2		1.0		1.0

Other comprehensive income	1,005			836			42			1.2		1.0		0.8
Comprehensive income	$	495,124		$	464,327		$	466,844		$	552.9	$	495.1	$	464.3

See Notes to Consolidated Financial Statements

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(amounts in ~~thousands)~~millions)


	Year Ended Dec. 31									Year Ended Dec. 31
	2017			2016			2015			2018			2017			2016
Operating activities
Net income	$	494,119		$	463,491		$	466,802		$	551.7		$	494.1		$	463.5
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	475,592			446,179			416,427			566.1			475.6			446.2
Demand side management program amortization	672			2,138			3,509
Deferred income taxes	207,817			222,002			277,896			23.8			207.8			222.0
Amortization of investment tax credits	(2,803		)	(2,805		)	(2,807		)
Allowance for equity funds used during construction	(29,803		)	(18,557		)	(14,485		)	(56.4		)	(29.8		)	(18.6		)
Provision for bad debts	14,303			14,121			13,052			16.4			14.3			14.1
Net realized and unrealized hedging and derivative transactions	2,364			1,325			2,414			(6.2		)	2.4			1.3
Other	6			(388		)	2,500
Changes in operating assets and liabilities:
Accounts receivable	(2,229		)	(14,227		)	8,872			(42.8		)	(2.2		)	(14.2		)
Accrued unbilled revenues	1,277			(20,866		)	17,837			(17.7		)	1.3			(20.9		)
Inventories	(9,099		)	172			33,417			(20.1		)	(9.1		)	0.2
Prepayments and other	188			68,693			10,483			12.8			0.2			68.7
Accounts payable	20,410			38,439			(40,982		)	68.7			20.4			38.4
Net regulatory assets and liabilities	(22,548		)	4,143			78,055			(14.6		)	(22.6		)	4.2
Other current liabilities	71,776			1,892			19,654			(12.9		)	71.8			1.9
Pension and other employee benefit obligations	(16,515		)	(10,627		)	(23,449		)	(44.2		)	(16.5		)	(10.6		)
Change in other noncurrent assets	(785		)	(6,750		)	4,086
Change in other noncurrent liabilities	(2,982		)	(22,120		)	(35,334		)
Other, net										(16.3		)	(5.9		)	(29.9		)
Net cash provided by operating activities	1,201,760			1,166,255			1,237,947			1,008.3			1,201.8			1,166.3

Investing activities
Utility capital/construction expenditures	(1,475,697		)	(1,113,800		)	(995,597		)	(1,577.2		)	(1,445.9		)	(1,095.2		)
Proceeds from insurance recoveries	—			608			—			—			—			0.6
Allowance for equity funds used during construction	29,803			18,557			14,485
Investments in utility money pool arrangement	(954,000		)	(444,000		)	(196,300		)	(634.0		)	(954.0		)	(444.0		)
Repayments from utility money pool arrangement	934,000			444,000			212,300			654.0			934.0			444.0
Other	(657		)	(1,460		)	—
Other, net										—			(0.7		)	(1.5		)
Net cash used in investing activities	(1,466,551		)	(1,096,095		)	(965,112		)	(1,557.2		)	(1,466.6		)	(1,096.1		)

Financing activities
(Repayments of) proceeds from short-term borrowings, net	(129,000		)	115,000			(368,000		)
Proceeds from (repayments of) short-term borrowings, net										307.0			(129.0		)	115.0
Borrowings under utility money pool arrangement	40,000			524,500			165,000			780.0			40.0			524.5
Repayments under utility money pool arrangement	(40,000		)	(524,500		)	(165,000		)	(780.0		)	(40.0		)	(524.5		)
Proceeds from issuance of long-term debt	393,791			244,507			246,751			691.1			393.8			244.5
Repayments of long-term debt	—			(129,500		)	—			(300.0		)	—			(129.5		)
Capital contributions from parent	335,576			38,755			175,210			252.1			335.6			38.8
Dividends paid to parent	(333,879		)	(336,581		)	(330,846		)	(375.3		)	(333.9		)	(336.6		)
Other	(110		)	—			—
Other, net										(0.1		)	(0.1		)	—
Net cash provided by (used in) financing activities	266,378			(67,819		)	(276,885		)	574.8			266.4			(67.8		)

Net change in cash and cash equivalents	1,587			2,341			(4,050		)	25.9			1.6			2.4
Cash and cash equivalents at beginning of period	5,926			3,585			7,635			7.5			5.9			3.5
Cash and cash equivalents at end of period	$	7,513		$	5,926		$	3,585		$	33.4		$	7.5		$	5.9

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(174,978	)	$	(171,714	)	$	(165,546	)	$	(187.2	)	$	(175.0	)	$	(171.7	)
Cash (paid) received for income taxes, net	(7,717		)	22,827			13,822			(115.8		)	(7.7		)	22.8
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	183,858		$	68,870		$	106,912
Accrued property, plant and equipment additions										$	142.1		$	199.1		$	81.1
Inventory transfers to property, plant and equipment										37.2			26.6			40.8
Allowance for equity funds used during construction										56.4			29.8			18.6

See Notes to Consolidated Financial Statements

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(amounts in ~~thousands,~~millions, except share and per ~~share data)~~share)


	Dec. 31						Dec. 31
	2017			2016			2018			2017
Assets
Current assets
Cash and cash equivalents	$	7,513		$	5,926		$	33.4		$	7.5
Accounts receivable, net	294,403			304,900			310.3			294.4
Accounts receivable from affiliates	14,719			9,421			80.8			14.7
Investments in utility money pool arrangement	20,000			—			—			20.0
Accrued unbilled revenues	295,801			297,078			313.5			295.8
Inventories	214,489			202,220			197.4			214.5
Regulatory assets	77,337			103,783			120.6			77.3
Derivative instruments	3,197			10,934			42.6			3.2
Prepayments and other	35,720			34,559			23.8			35.7
Total current assets	963,179			968,821			1,122.4			963.1

Property, plant and equipment, net	14,025,751			12,849,799			15,120.0			14,025.8

Other assets
Regulatory assets	950,258			958,429			1,010.7			950.3
Derivative instruments	1,009			3,398			1.2			1.0
Other	27,429			25,637			37.2			27.4
Total other assets	978,696			987,464			1,049.1			978.7
Total assets	$	15,967,626		$	14,806,084		$	17,291.5		$	15,967.6

Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	305,577		$	5,270		$	406.2		$	305.6
Short-term debt	—			129,000			307.0			—
Accounts payable	492,829			376,186			503.4			492.9
Accounts payable to affiliates	58,749			98,797			46.0			58.7
Regulatory liabilities	66,126			101,110			67.3			66.1
Taxes accrued	222,517			171,862			202.0			222.5
Accrued interest	48,552			48,619			43.2			48.6
Dividends payable to parent	76,195			74,208			91.5			76.2
Derivative instruments	7,348			6,788			34.6			7.3
Other	92,333			73,022			101.5			92.3
Total current liabilities	1,370,226			1,084,862			1,802.7			1,370.2

Deferred credits and other liabilities
Deferred income taxes	1,644,476			2,889,129			1,719.3			1,644.5
Deferred investment tax credits	27,858			30,661			25.3			27.8
Regulatory liabilities	1,933,488			512,933			2,021.5			1,933.5
Asset retirement obligations	347,769			289,563			338.7			347.8
Derivative instruments	3,468			7,828			0.6			3.5
Customer advances	162,614			162,742			168.1			162.6
Pension and employee benefit obligations	287,783			285,774			275.3			287.8
Other	58,923			62,201			50.4			58.9
Total deferred credits and other liabilities	4,466,379			4,240,831			4,599.2			4,466.4

Commitments and contingencies
Capitalization
Long-term debt	4,302,698			4,210,936			4,591.4			4,302.7
Common stock — 100 shares authorized of $0.01 par value; 100 shares outstanding at Dec. 31, 2017 and 2016, respectively	—			—
Common stock — 100 shares authorized of $0.01 par value; 100 shares outstanding at Dec. 31, 2018 and 2017, respectively							—			—
Additional paid in capital	4,032,826			3,633,216			4,340.5			4,032.8
Retained earnings	1,822,229			1,659,239			1,983.2			1,822.2
Accumulated other comprehensive loss	(26,732		)	(23,000		)	(25.5		)	(26.7		)
Total common stockholder’s equity	5,828,323			5,269,455			6,298.2			5,828.3
Total liabilities and equity	$	15,967,626		$	14,806,084		$	17,291.5		$	15,967.6

See Notes to Consolidated Financial Statements

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY

(amounts in ~~thousands,~~millions, except ~~share and per~~ share data)

Common Stock Issued
Accumulated
Other
Comprehensive
Income (Loss)

Total
Common
Stockholder’s
Equity
Shares Par Value
Additional
Paid In
Capital

Retained
Earnings

Balance at Dec. 31, 2014 100
$ —
$ 3,522,788
$ 1,386,929
$ (23,878 ) $ 4,885,839
Net income 466,802
466,802
Other comprehensive income 42
42
Common dividends declared to parent (330,567 ) (330,567 )
Contribution of capital by parent 98,036
98,036
Balance at Dec. 31, 2015 100
$ —
$ 3,620,824
$ 1,523,164
$ (23,836 ) $ 5,120,152
Net income 463,491
463,491
Other comprehensive income 836
836
Common dividends declared to parent (327,416 ) (327,416 )
Contribution of capital by parent 12,392
12,392
Balance at Dec. 31, 2016 100
$ —
$ 3,633,216
$ 1,659,239
$ (23,000 ) $ 5,269,455
Net income 494,119
494,119
Other comprehensive income 1,005
1,005
Common dividends declared to parent (335,866 ) (335,866 )
Contribution of capital by parent 399,610
399,610
Adoption of ASU No. 2018-02 4,737
(4,737 ) —
Balance at Dec. 31, 2017 100
$ —
$ 4,032,826
$ 1,822,229
$ (26,732 ) $ 5,828,323

~~See Notes to Consolidated Financial Statements~~

~~PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES~~

~~CONSOLIDATED STATEMENTS OF CAPITALIZATION~~

~~(amounts in thousands, except share and per share data)~~

Dec. 31
2017 2016
Long-Term Debt
First Mortgage Bonds, Series due:
Aug. 1, 2018, 5.8% $ 300,000
$ 300,000
June 1, 2019, 5.125% 400,000
400,000
Nov. 15, 2020, 3.2% 400,000
400,000
Sept. 15, 2022, 2.25% 300,000
300,000
March 15, 2023, 2.5% 250,000
250,000
May 15, 2025, 2.9% 250,000
250,000
Sept. 1, 2037, 6.25% 350,000
350,000
Aug. 1, 2038, 6.5% 300,000
300,000
Aug. 15, 2041, 4.75% 250,000
250,000
Sept. 15, 2042, 3.6% 500,000
500,000
March 15, 2043, 3.95% 250,000
250,000
March 15, 2044, 4.3% 300,000
300,000
June 15, 2046, 3.55% 250,000
250,000
June 15, 2047, 3.8% 400,000
—
Capital lease obligations, through 2060, 11.2% — 14.3% 150,658
155,927
Unamortized discount (13,472 ) (12,922 )
Unamortized debt expense (28,911 ) (26,799 )
Total 4,608,275
4,216,206
Less current maturities 305,577
5,270
Total long-term debt $ 4,302,698
$ 4,210,936

Common Stockholder’s Equity

Common Stock — 100 shares authorized of $0.01 par value; 100 shares
outstanding at Dec. 31, 2017 and 2016, respectively.
$ —
$ —
Additional paid-in capital 4,032,826
3,633,216
Retained earnings 1,822,229
1,659,239
Accumulated other comprehensive loss (26,732 ) (23,000 )
Total common stockholder’s equity $ 5,828,323
$ 5,269,455



	Common Stock								Accumulated Other Comprehensive Income (Loss)			Total Common Stockholder’s Equity
	Shares	Par Value		Additional Paid In Capital		Retained Earnings

Balance at Dec. 31, 2015	100	$	—	$	3,620.8	$	1,523.2		$	(23.8	)	$	5,120.2

Net income						463.5						463.5
Other comprehensive income									0.8			0.8
Common dividends declared to parent						(327.4		)				(327.4		)
Contribution of capital by parent				12.4								12.4
Balance at Dec. 31, 2016	100	$	—	$	3,633.2	$	1,659.3		$	(23.0	)	$	5,269.5

Net income						494.1						494.1
Other comprehensive income									1.0			1.0
Common dividends declared to parent						(335.9		)				(335.9		)
Contribution of capital by parent				399.6								399.6
Adoption of ASU No. 2018-02						4.7			(4.7		)	—
Balance at Dec. 31, 2017	100	$	—	$	4,032.8	$	1,822.2		$	(26.7	)	$	5,828.3

Net income						551.7						551.7
Other comprehensive income									1.2			1.2
Common dividends declared to parent						(390.7		)				(390.7		)
Contribution of capital by parent				307.7								307.7
Balance at Dec. 31, 2018	100	$	—	$	4,340.5	$	1,983.2		$	(25.5	)	$	6,298.2

See Notes to Consolidated Financial Statements

~~See Notes to Consolidated Financial Statements~~

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1.	Summary of Significant Accounting Policies

~~Business and System of Accounts~~General — PSCo is engaged in the regulated generation, purchase, transmission, distribution and sale of electricity and in the regulated purchase, transportation, distribution and sale of natural gas. PSCo’s consolidated financial statements and disclosures are presented in accordance with GAAP. All of PSCo’s underlying accounting records also conform to the FERC uniform system of accounts or to systems required by various state regulatory commissions, which are the same in all material respects.

~~Principles of Consolidation~~— PSCo’s consolidated financial statements include its wholly-owned subsidiaries. In the consolidation process, all intercompany transactions and balances are eliminated. PSCo has investments in several plants and transmission facilities jointly owned with nonaffiliated utilities. PSCo’s proportionate share of jointly owned facilities is recorded as property, plant and equipment on the consolidated balance sheets, and PSCo’s proportionate share of the operating costs associated with these facilities is included in its consolidated statements of income. See Note 63 for further ~~discussion~~information.

PSCo’s consolidated financial statements and disclosures are presented in accordance with GAAP. All of ~~jointly owned generation, transmission and gas facilities, and related ownership percentages.~~

PSCo’s underlying accounting records also conform to the FERC uniform system of accounts or to systems required by various state regulatory commissions.

PSCo ~~evaluates its arrangements~~has evaluated the impact of events occurring after Dec. 31, 2018 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and contracts with other entities, including investments, PPAs and fuel contracts, to determine if the other party is a variable interest entity, if PSCo has a variable interest and if PSCo is the primary beneficiary. PSCo follows accounting guidance for variable interest entities which requires consideration of the activitiesdisclosures resulting from that most significantly impact an entity’s financial performance and power to direct those activities, when determining whether PSCo is a variable interest entity’s primary beneficiary. See Note 12 for further discussion of variable interest entities.

evaluation.

Use of Estimates — ~~In recording transactions and balances resulting from business operations,~~ PSCo uses estimates based on the best information ~~available.~~available in recording transactions and balances resulting from business operations. Estimates are used ~~for~~on items such ~~items~~ as plant depreciable lives or potential disallowances, AROs, certain regulatory assets and liabilities, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs. ~~The recorded~~Recorded estimates are revised when better information becomes available or when actual amounts can be determined. Those revisions can affect operating results.

Regulatory Accounting — PSCo accounts for ~~certain~~ income and expense items in accordance with accounting guidance for regulated operations. Under this guidance:

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

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

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

If ~~restructuring or other~~ changes in the regulatory environment occur, PSCo may no longer be eligible to apply this accounting treatment, and may be required to eliminate regulatory assets and liabilities from its balance sheet. Such changes could have a material effect on PSCo’s ~~financial condition,~~ results of operations, ~~and~~financial condition or cash flows.

See Note 134 for further ~~discussion~~information.

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

Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize it over the book depreciable lives of the related property. The requirement to defer and amortize tax credits only applies to federal ITCs related to public utility property. Utility rate regulation also has resulted in the recognition of certain regulatory assets and ~~liabilities.~~

~~Revenue Recognition— Revenues~~liabilities related to ~~the sale of energy~~income taxes.

Deferred tax assets are ~~generally recorded when service~~reduced by a valuation allowance if it is ~~rendered~~more likely than not that some portion or ~~energy is delivered to customers. However, the determination~~all of the ~~energy sales~~deferred tax asset will not be realized.

PSCo follows the applicable accounting guidance to ~~individual customers~~measure and disclose uncertain tax positions that it has taken or expects to take in its income tax returns. PSCo recognizes a tax position in its consolidated financial statements when it is more likely than not that the position will be sustained upon examination based on the ~~reading of their meter, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date~~technical merits of the ~~last meter reading~~position.

Recognition of changes in uncertain tax positions are ~~estimated and the corresponding unbilled revenue is recognized. PSCo presents its revenues net~~reflected as a component of ~~any excise or other fiduciary-type taxes or fees.~~

income tax.

PSCo ~~has various rate-adjustment mechanisms in place that provide for the recovery of natural gas, electric fuel~~reports interest and purchased energy costs. These cost-adjustment tariffs may increase or decrease the level of revenue collected from customers and are revised periodically for differences between the total amount collected under the clauses and the costs incurred. When applicable, under governing regulatory commission rate orders, fuel cost over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as regulatory assets.

~~Certain rate rider mechanisms qualify as alternative revenue programs under GAAP. These mechanisms arise from costs imposed upon the utility by action of a regulator or legislative body~~penalties related to ~~an environmental, public safety or~~income taxes within the other ~~mandate. When certain criteria are met, revenue is recognized equal to~~income and interest charges in the ~~revenue requirement,~~consolidated statements of income.

Xcel Energy Inc. and its subsidiaries, including return on rate base items, for the qualified mechanisms. The mechanisms are revised periodically for differences between the total amount collected under the riders and the revenue recognized, which may increase or decrease the level of revenue collected from customers.

~~Conservation Programs~~ — PSCo, has implemented programs to assist its retail customers in conserving energy and reducing peak demand on the electric and natural gas systems. These programs include approximately 20 unique DSM products, pilots and services for C&I customers,file consolidated federal income tax returns as well as ~~approximately 23 DSM products, pilots and services~~consolidated or separate state income tax returns. Federal income taxes paid by Xcel Energy Inc. are allocated to its subsidiaries based on separate company computations. A similar allocation is made for ~~residential and low-income customers. Overall, the DSM portfolio provides rebates and/or incentives~~state income taxes paid by Xcel Energy Inc. in connection with consolidated state filings. Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries.

See Note 8 for ~~nearly 1,000 unique measures.~~

The costs incurred for DSM programs are deferred if it is probable future revenue will be provided to permit recovery of the incurred cost. Recorded revenues for incentive programs designed for recovery of DSM program costs and/or conservation performance incentives are limited to amounts expected to be collected within 24 months from the annual period in which they are earned.

PSCo’s DSM program costs are recovered through a combination of base rate revenue and rider mechanisms. The revenue billed to customers recovers incurred costs for conservation programs and also incentive amounts that are designed to encourage PSCo’s achievement of energy conservation goals. PSCo recognizes regulatory assets to reflect the amount of costs or earned incentives that have not yet been collected from customers.

further information.

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

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

PSCo records depreciation expense ~~related to its plant~~ using the straight-line method over the plant’s useful life. Actuarial life studies are performed and submitted to the state and federal commissions for review. Upon acceptance by the various commissions, the resulting lives and net salvage rates are used to calculate depreciation. Depreciation expense, expressed as a percentage of average depreciable property, was approximately ~~2.7, 2.6~~2.6% in 2018, 2.7% in 2017 and ~~2.7 percent for the years ended Dec. 31, 2017, 2016 and 2015, respectively.~~2.6% in 2016.

~~Leases~~ — PSCo evaluates a variety of contracts for lease classification at inception, including PPAs and rental arrangements for office space, vehicles, and equipment. Contracts determined to contain a lease because of per unit pricing that is other than fixed or market price, terms regarding the use of a particular asset, and other factors are evaluated further to determine if the arrangement is a capital lease. See Note 123 for further ~~discussion of leases.~~

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

Generally, AFUDC costs are recovered from customers as the related property is depreciated. However, in some cases, including certain generation and transmission projects, the CPUC has approved a more current recovery of the cost of capital associated with large capital projects, resulting in a lower recognition of AFUDC. In other cases, the CPUC has allowed an AFUDC calculation greater than the FERC-defined AFUDC rate, resulting in higher recognition of AFUDC.

information.

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

See Note 1211 for further ~~discussion of AROs.~~

information.

~~Income Taxes~~Benefit Plans and Other Postretirement Benefits— PSCo ~~accounts~~maintains pension and postretirement benefit plans for ~~income taxes using~~eligible employees. Recognizing the ~~asset~~cost of providing benefits and ~~liability method, which~~measuring the projected benefit obligation of these plans requires ~~the recognition of deferred tax assets~~management to make various assumptions and ~~liabilities for the expected future tax consequences of events that have been included in the financial statements. PSCo defers income taxes for all temporary differences between pretax financial~~estimates.

Certain unrecognized actuarial gains and ~~taxable income,~~losses and between the book and tax bases of assets and liabilities. PSCo uses the tax rates that are scheduled to be in effect when the temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the period that includes the enactment date.

The effects of PSCo’s tax rate changes are generally subject to a normalization method of accounting. Therefore, the revaluation of most of its net deferred taxes upon a tax rate reduction results in the establishment of a net regulatory liability which will be refundable to utility customers over the remaining life of the related assets. A tax rate increase would result in the establishment of a similar regulatory asset. Taxunrecognized prior service costs or credits are recorded when earned unless there is a requirement to defer the benefit and amortize it over the book depreciable lives of the related property. The requirement to defer and amortize tax credits only applies to federal ITCs related to public utility property. Utility rate regulation also has resulted in the recognition of certaindeferred as regulatory assets and liabilities, ~~related to~~rather than recorded as other comprehensive income, ~~taxes, which are summarized in Note 13.~~

Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized. In making such a determination, all available evidence is considered, including scheduled reversals of deferred tax liabilities, projected future taxable income, tax planning strategies and recent financial operations.

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

~~PSCo reports interest and penalties related to income taxes within the other income and interest charges sections in the consolidated statements of income.~~

Xcel Energy Inc. and its subsidiaries, including PSCo, file consolidated federal income tax returns as well as combined or separate state income tax returns. Federal income taxes paid by Xcel Energy Inc. are allocated to Xcel Energy Inc.’s subsidiaries based on separate company computations of tax. A similar allocation is made for state income taxes paid by Xcel Energy Inc. in connection with combined state filings. Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries which are recorded directly in equity by the subsidiaries based on the relative positive tax liabilities of the subsidiaries.

~~See Note 7 for further discussion of income taxes.~~

~~Types of and Accounting for Derivative Instruments~~— PSCo uses derivative instruments in connection with its interest rate, utility commodity price, vehicle fuel price and commodity trading activities, including forward contracts, futures, swaps and options. All derivative instruments not designated and qualifying for the normal purchases and normal sales exception, as defined by the accounting guidance for derivatives and hedging, are recorded on the consolidated balance sheets at fair value as derivative instruments. This includes certain instruments used to mitigate market risk for the utility operations and all instruments related to the commodity trading operations. The classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship. Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.

Gains or losses on commodity trading transactions are recorded as a component of electric operating revenues; hedging transactions for vehicle fuel costs are recorded as a component of capital projects and O&M costs; and interest rate hedging transactions are recorded as a component of interest expense. PSCo is allowed to recover in electric or natural gas rates the costs of certain financial instruments purchased to reduce commodity cost volatility. For further information on derivatives entered to mitigate commodity price risk on behalf of electric and natural gas customer, see Note 10.

~~Cash Flow Hedges~~ — Certain qualifying hedging relationships are designated as a hedge of a forecasted transaction or future cash flow (cash flow hedge). Changes in the fair value of a derivative designated as a cash flow hedge, to the extent effective are included in OCI, or deferred as a regulatory asset or liability based on recovery mechanisms until earnings are affected by the hedged transaction.

~~Normal Purchases and Normal Sales~~ — PSCo enters into contracts for the purchase and sale of commodities for use in its business operations. Derivatives and hedging accounting guidance requires a company to evaluate these contracts to determine whether the contracts are derivatives. Certain contracts that meet the definition of a derivative may be exempted from derivative accounting if designated as normal purchases or normal sales.

PSCo evaluates all of its contracts at inception to determine if they are derivatives and if they meet the normal purchases and normal sales designation requirements. None of the contracts entered into within the commodity trading operations qualify for a normal purchases and normal sales designation.

See Note 10 for further ~~discussion of PSCo’s risk management and derivative activities.~~

~~Commodity Trading Operations~~— All applicable gains and losses related to commodity trading activities, whether or not settled physically, are shown on a net basis in electric operating revenues in the consolidated statements of income.

Pursuant to the JOA approved by the FERC, some of the commodity trading margins from PSCo are apportioned to NSP-Minnesota and SPS. Commodity trading activities are not associated with energy produced from PSCo’s generation assets or energy and capacity purchased to serve native load. Commodity trading contracts are recorded at fair market value and commodity trading results include the impact of all margin-sharing mechanisms. See Note 10 for further discussion.

~~Fair Value Measurements~~— PSCo presents cash equivalents, interest rate derivatives and commodity derivatives at estimated fair values in its consolidated financial statements. Cash equivalents are recorded at cost plus accrued interest; money market funds are measured using quoted NAVs. For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used as a primary input to establish fair value. For commodity derivatives, the most observable inputs available are generally used to determine the fair value of each contract. In the absence of a quoted price for an identical contract in an active market, PSCo may use quoted prices for similar contracts, or internally prepared valuation models to determine fair value. For the pension and postretirement plan assets published trading data and pricing models, generally using the most observable inputs available, are utilized to estimate fair value for each security. See Note 8 and 10 for further discussion.

~~Cash and Cash Equivalents~~— PSCo considers investments in certain instruments, including commercial paper and money market funds, with a remaining maturity of three months or less at the time of purchase, to be cash equivalents.

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

~~Inventory— All inventory is recorded at average cost.~~

~~RECs —~~ ~~RECs are~~marketable environmental instruments that represent proof that energy was generated from eligible renewable energy sources. RECs are awarded upon delivery of the associated energy and can be bought and sold. RECs are typically used as a form of measurement of compliance to RPS enacted by those states that are encouraging construction and consumption from renewable energy sources, but can also be sold separately from the energy produced. PSCo acquires RECs from the generation or purchase of renewable power.

When RECs are purchased or acquired in the course of generation they are recorded as inventory at cost. The cost of RECs that are utilized for compliance purposes is recorded as electric fuel and purchased power expense. As a result of state regulatory orders, PSCo records that cost as a regulatory asset when the amount is recoverable in future rates.

Sales of RECs that are purchased or acquired in the course of generation are recorded in electric utility operating revenues on a gross basis. The cost of these RECs, related transaction costs, and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense.

~~Emission Allowances —~~ ~~Emission allowances, including the annual SO~~₂ and NOx emission allowance entitlement received from the EPA, are recorded at cost plus associated broker commission fees. PSCo follows the inventory accounting model for all emission allowances. Sales of emission allowances are included in electric utility operating revenues and the operating activities section of the consolidated statements of cash flows.

information.

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

Estimated remediation ~~costs, excluding inflationary increases, are recorded based on experience, an assessment of the current situation and the technology currently available for use in the remediation. The recorded~~ costs are regularly adjusted as estimates are revised and remediation proceeds. If other participating ~~PRPs~~potentially responsible parties exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for PSCo’s expected share of the cost.

~~Any future~~Future costs of restoring sites ~~where operation may extend indefinitely~~ are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal ~~expenses, which may include final remediation costs.~~expenses. Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability.

See Note 11 for further information.

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

PSCo does not recognize a separate financing component of its collections from customers as contract terms are short-term in nature. PSCo presents its revenues net of any excise or sales taxes or fees.

See Note 126 for further ~~discussion~~information.

Cash and Cash Equivalents— PSCo considers investments in instruments with a remaining maturity of ~~environmental costs.~~three months or less at the time of purchase, to be cash equivalents.

Accounts Receivable and Allowance for Bad Debts — Accounts receivable are stated at the actual billed amount net of an allowance for bad debts. PSCo establishes an allowance for uncollectible receivables based on a policy that reflects its expected exposure to the credit risk of customers. As of Dec. 31, 2018 and 2017, the allowance for bad debts was $20.5 million and $19.6 million, respectively.

Inventory— Inventory is recorded at average cost. As of Dec. 31, 2018, materials and supplies, fuel and natural gas inventory were $61.9 million, $69.5 million and $66.0 million, respectively. As of Dec. 31, 2017, materials and supplies, fuel and natural gas inventory were $68.9 million, $73.9 million and $71.7 million, respectively.

Fair Value Measurements— PSCo presents cash equivalents, interest rate derivatives and commodity derivatives at estimated fair values in its consolidated financial statements. Cash equivalents are recorded at cost plus accrued interest; money market funds are measured using quoted NAVs. For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used to establish fair value. For commodity derivatives, the most observable inputs available are generally used to determine the fair value of each contract. In the absence of a quoted price, PSCo may use quoted prices for similar contracts or internally prepared valuation models to determine fair value.

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

See Notes 9 and 10 for further information.

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

~~Benefit Plans~~Normal Purchases and ~~Other Postretirement Benefits~~Normal Sales — PSCo ~~maintains pension~~enters into contracts for the purchases and ~~postretirement benefit plans~~sales of commodities for ~~eligible employees. Recognizing~~use in its operations. At inception, contracts are evaluated to determine whether a derivative exists and/or whether an instrument may be exempted from derivative accounting if designated as a normal purchase or normal sale.

See Note 9 for further information.

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

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

See Note 9 for further information.

Other Utility Items

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

Alternative Revenue — Certain rate rider mechanisms (including DSM programs) qualify as alternative revenue programs under GAAP. These mechanisms arise from costs imposed upon the ~~projected benefit obligation~~utility by action of a regulator or legislative body related to an environmental, public safety or other mandate. When certain criteria are met, such as collection within 24 months, revenue is recognized equal to the revenue requirement, which may include incentives and return on rate base items. Billing amounts are revised periodically for differences between the total amount collected and revenue earned, which may increase or decrease the level of revenue collected from customers. Alternative revenues arising from these ~~plans under applicable accounting guidance requires management to make various assumptions~~programs are presented on a gross basis and ~~estimates.~~disclosed separately from revenue from contracts with customers in the period earned.

Based on regulatory recovery mechanisms, certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are recorded as regulatory assets and liabilities, rather than OCI.

See Note 86 for further ~~discussion of benefit plans and other postretirement benefits.~~

information.

~~Guarantees~~Conservation Programs — PSCo ~~recognizes, upon issuance~~ has implemented programs to assist its retail customers in conserving energy and reducing peak demand on the electric and natural gas systems. These programs include approximately 20 unique DSM products, pilots and services for C&I customers, as well as approximately 23 DSM products, pilots and services for residential and low-income customers. Overall, the DSM portfolio provides rebates and/or ~~modification of a guarantee, a liability~~incentives for ~~the fair market value~~nearly 1,000 unique measures.

The costs incurred for DSM programs are deferred if it is probable future revenue will be provided to permit recovery of the ~~obligation~~incurred cost. Revenues recognized for incentive programs designed for recovery of DSM program costs and/or conservation performance incentives are limited to amounts expected to be collected within 24 months from the annual period in which they are earned.

PSCo’s DSM program costs are recovered through a combination of base rate revenue and rider mechanisms. Regulatory assets are recognized to reflect the amount of costs or earned incentives that ~~has~~have not yet been ~~assumed in issuing the guarantee. This liability includes consideration of specific triggering events and other conditions which may modify the ongoing obligation to perform under the guarantee.~~collected from customers.

~~The obligation recognized is reduced over the term of the guarantee as PSCo is released from risk under the guarantee.~~

~~Subsequent Events~~Emission Allowances — ~~Management has evaluated the impact of events occurring after Dec. 31, 2017 up to the date of issuance~~ Emission allowances are recorded at cost plus broker commission fees. The inventory accounting model is utilized for all emission allowances and sales of these ~~consolidated financial statements. These statements contain all necessary adjustments~~allowances are included in electric revenues.

RECs — Cost of RECs that are utilized for compliance purposes is recorded as electric fuel and ~~disclosures resulting from~~purchased power expense. PSCo records that ~~evaluation.~~cost as a regulatory asset when the amount is recoverable in future rates.

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


2.	Accounting Pronouncements

Recently Issued

~~Revenue Recognition~~—Leases ~~In May 2014, the FASB issued~~— ~~Revenue from Contracts with Customers, Topic 606 (ASU No. 2014-09)~~, which provides a new framework for the recognition of revenue. As the appropriate timing of recognition of revenue from contracts with customers in our regulated operations continues to generally be based on the delivery of electricity and natural gas, PSCo’s adoption will primarily result in increased disclosures regarding sources of revenues, including alternative revenue programs. The guidance is effective for interim and annual periods beginning after Dec. 15, 2017. PSCo is implementing the standard on a modified retrospective basis, which requires application to contracts with customers effective Jan. 1, 2018.

~~Classification and Measurement of Financial Instruments —~~In ~~January 2016, the FASB issued~~ ~~Recognition and Measurement of Financial Assets and Financial Liabilities, Subtopic 825-10 (ASU No. 2016-01),~~ which eliminates the available-for-sale classification for marketable equity securities and also replaces the cost method of accounting for non-marketable equity securities with a model for recognizing impairments and observable price changes. Under the new standard, other than when the consolidation or equity method of accounting is utilized, changes in the fair value of equity securities are to be recognized in earnings. This guidance is effective for interim and annual reporting periods beginning after Dec. 15, 2017. The overall impacts of the Jan. 1, 2018 adoption will not be material.

~~Leases —~~ ~~In February~~ 2016, the FASB issued Leases, Topic 842 (ASU No. 2016-02), which ~~for lessees,~~ requires balance sheet recognition of right-of-useassets and lease liabilities for most leases. Adoptionwill occur on Jan. 1, 2019 utilizing the package of transition practical expedients provided by the new standard, including carrying forward prior conclusions of whether agreements existing before the adoption date contain leases, and whether existing leases are operating or capital/finance leases. PSCo expects to utilize other expedients offered by the new standard and Leases, Topic 842 (ASU No. 2018-11), including elections to not recognize short term leases on the consolidated balance sheet for certain classes of assets and to implement the standard on a prospective basis. PSCo’s implementation of the new guidance is substantially complete, and is expected to result in the recognition of right-of-use assets and lease liabilities in the first quarter of 2019 for ~~most leases. This guidance will be effective~~operating leases for ~~interim~~the use of real estate, equipment and ~~annual reporting periods beginning after Dec. 15, 2018. PSCo has~~ certain natural gas generating facilities operated under PPAs. The implementation isnot ~~yet fully determined the impacts of implementation. However, adoption is~~ expected to ~~occur~~have a significant impact on ~~Jan. 1, 2019 utilizing the practical expedients provided by the standard and proposed in~~ PSCo’s consolidated~~Targeted Improvements, Topic 842~~ ~~(Proposed ASU 2018-200). As such, agreements entered prior to Jan. 1, 2019 that are currently considered~~financial statements, other than first-time recognition of these operating leases ~~are expected to be recognized~~ on the consolidated balance sheet, including contracts for use of office space, equipment and natural gas storage assets, as well as certain purchased power agreements (PPAs) for natural gas-fueled generating facilities. PSCo expects that similar agreements entered after Dec. 31, 2018 will generally qualify as leases under the new standard.sheet.

~~Presentation of Net Periodic Benefit Cost —~~I~~n March 2017, the FASB issued~~ ~~Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, Topic 715 (ASU No. 2017-07)~~, which establishes that only the service cost element of pension cost may be presented as a component of operating income in the income statement. Also under the guidance, only the service cost component of pension cost is eligible for capitalization. As a result of application of accounting principles for rate regulated entities, a similar amount of pension cost, including non-service components, will be recognized consistent with the historical ratemaking treatment and the impacts of adoption will be limited to changes in classification of non-service costs in the consolidated statement of income. This guidance is effective for interim and annual reporting periods beginning after Dec. 15, 2017.

Recently Adopted

~~Accounting for the TCJA~~—Revenue Recognition — In ~~December 2017, the SEC staff issued Staff Accounting Bulletin No. 118~~ ~~Income Tax Accounting Implications of the Tax Cuts and Jobs Act~~ ~~(SAB 118), to supplement the accounting requirements of ASC Topic 740~~ ~~Income Taxes~~ (ASC Topic 740) as it relates to assessing and recognizing the impacts of the TCJA in the period of enactment. SAB 118 allows an entity to recognize provisional amounts in its financial statements in circumstances in which the entity’s assessment is incomplete, but for which a reasonable estimate can be made. Provisional amounts recognized are subject to adjustment for up to one year from the enactment date. For further details, see Note 7 to the consolidated financial statements.

~~Reporting Comprehensive Income —~~ ~~In February 2018,~~2014, the FASB issued ~~Reclassification of Certain Tax Effects~~Revenue from ~~Accumulated Other Comprehensive Income,~~Contracts with Customers, Topic ~~220~~606 (ASU No. ~~2018-02)~~2014-09), which ~~addresses the stranded amounts of accumulated OCI which may result from enactment of~~provides a new ~~tax law. Though accumulated OCI is presented~~framework for the recognition of revenue. PSCo implemented the guidance on a ~~net-of-tax~~modified retrospective basis ~~ASC~~on Jan. 1, 2018. Results for reporting periods beginning after Dec. 31, 2017 are presented in accordance with Topic ~~740 requires~~606, while prior period results have not been adjusted and continue to be reported in accordance with prior accounting guidance. The implementation did not have a material impact on PSCo’s consolidated financial statements, other than increased disclosures regarding revenues related to contracts with customers.

Classification and Measurement of Financial Instruments — In 2016, the FASB issued Recognition and Measurement of Financial Assets and Financial Liabilities, Subtopic 825-10 (ASU No. 2016-01), which eliminated the available-for-sale classification for marketable equity securities and also replaced the cost method of accounting for non-marketable equity securities with a model for recognizing impairments and observable price changes. PSCo implemented the guidance on Jan. 1, 2018 and the adoption impacts were not material.

Presentation of Net Periodic Benefit Cost — In 2017, the FASB issued Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, Topic 715 (ASU No. 2017-07), which establishes that only the ~~effects~~service cost portion of ~~new tax laws on items in accumulated OCI~~pension cost may be presented as a component of operating income. In addition, only the service cost portion of pension cost is eligible for capitalization. As a result of regulatory accounting treatment, a similar amount of pension cost, including non-service components, will be recognized ~~without a corresponding adjustment~~consistent with historical ratemaking and the impacts of adoption are limited to ~~accumulated OCI, and instead recorded to income tax expense. ASU No. 2018-02 permits stranded amounts~~changes in classification of accumulated OCI specifically resulting from the TCJA to be removed from accumulated OCI and reclassified to retained earnings, if elected. PSCo adopted the guidance in the fourth quarter of 2017, and elected to recognize a $4.7 million increase to accumulated other comprehensive loss and retained earningsnon-service costs in the consolidated ~~financial statements~~statement of income.

PSCo implemented the new guidance on Jan. 1, 2018. As a result, $2.1 million and $2.7 million of pension costs were retrospectively reclassified from O&M expenses to other income, net on the consolidated income statement for 2017 and 2016, respectively. PSCo used benefit cost amounts disclosed for prior periods as the ~~year ended Dec. 31, 2017, related to a revaluation of deferred income tax assets and liabilities~~basis for ~~items in accumulated other comprehensive loss, at the TCJA federal tax rate.~~

retrospective application.


3.	~~Selected Balance Sheet Data~~Plant, Property and Equipment

(Thousands of Dollars) Dec. 31, 2017 Dec. 31, 2016
Accounts receivable, net
Accounts receivable $ 314,009
$ 324,512
Less allowance for bad debts (19,606 ) (19,612 )
$ 294,403
$ 304,900
Major classes of property, plant and equipment:

(Thousands of Dollars) Dec. 31, 2017 Dec. 31, 2016
Inventories
Materials and supplies $ 68,940
$ 66,161
Fuel 73,893
66,429
Natural gas 71,656
69,630
$ 214,489
$ 202,220


(Thousands of Dollars)	Dec. 31, 2017			Dec. 31, 2016
Property, plant and equipment, net
(Millions of Dollars)							Dec. 31, 2018			Dec. 31, 2017
Property, plant and equipment
Electric plant	$	12,627,592		$	12,304,436		$	13,604.5		$	12,627.6
Natural gas plant	4,102,075			3,710,772			4,387.6			4,102.1
Common and other property	1,022,333			919,955			1,023.7			1,022.3
Plant to be retired ^(a)	10,949			31,839			321.9			11.0
Construction work in progress	1,014,338			484,340
CWIP							573.3			1,014.3
Total property, plant and equipment	18,777,287			17,451,342			19,911.0			18,777.3
Less accumulated depreciation	(4,751,536		)	(4,601,543		)	(4,791.0		)	(4,751.5		)
	$	14,025,751		$	12,849,799		$	15,120.0		$	14,025.8

^(a)

In 2018, the ~~third quarter~~CPUC approved early retirement of ~~2017, PSCo early retired Valmont Unit 5~~PSCo’s Comanche Units 1 and ~~converted Cherokee Unit 4 from a coal-fueled generating facility to natural gas.~~2 in approximately 2022 and 2025, respectively. PSCo also expects Craig Unit 1 to be retired early ~~retired~~ in ~~approximately~~ 2025. Amounts are presented net of accumulated depreciation.

Joint Ownership of Generation, Transmission and Gas Facilities

Jointly owned assets as of Dec. 31, 2018:



(Millions of Dollars)	Plant in Service		Accumulated Depreciation		CWIP		Percent Owned
Electric Generation:
Hayden Unit 1	$	152.8	$	76.5	$	—	76	%
Hayden Unit 2	148.9		68.0		—		37
Hayden Common Facilities	40.8		20.9		—		53
Craig Units 1 and 2	81.0		40.0		—		10
Craig Common Facilities	39.1		20.9		—		7
Comanche Unit 3	886.3		130.7		—		67
Comanche Common Facilities	27.9		2.5		0.1		82
Electric Transmission:
Transmission and other facilities	182.8		63.2		0.7		Various
Gas Transportation:
Rifle, CO to Avon, CO	21.5		7.2		0.1		60
Gas Tran Compressor	8.4		0.9		—		50
Total	$	1,589.5	$	430.8	$	0.9

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


4.	Regulatory Assets and Liabilities

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

Components of regulatory assets:



(Millions of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2018				Dec. 31, 2017
Regulatory Assets			Current		Noncurrent		Current		Noncurrent
Pension and retiree medical obligations	10	Various	$	26.1	$	559.0	$	28.0	$	565.3
Depreciation differences		One to thirteen years	17.5		107.0		19.8		69.4
Recoverable deferred taxes on AFUDC recorded in plant		Plant lives	—		101.9		—		87.0
Net AROs^(a)	1, 11	Plant lives	—		98.9		—		80.5
Excess deferred taxes - TCJA	8	Various	—		62.0		—		53.9
Purchased power contract costs		Term of related contract	1.7		26.3		1.3		28.0
Property tax		Various	5.6		9.8		—		16.1
Conservation programs ^(b)	1	One to two years	7.3		6.5		7.0		5.5
Losses on reacquired debt		Term of related debt	1.2		3.7		1.2		4.9
Gas pipeline inspection costs		One to two years	0.7		3.1		1.8		7.8
Contract valuation adjustments ^(c)	1, 9	Term of related contract	2.6		—		6.0		2.6
Recoverable purchased natural gas and electric energy costs		Less than one year	51.2		—		7.6		—
Other		Various	6.7		32.5		4.6		29.3
Total regulatory assets			$	120.6	$	1,010.7	$	77.3	$	950.3


^(a)	Includes amounts recorded for future recovery of AROs.


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


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

Components of regulatory liabilities:



(Millions of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2018				Dec. 31, 2017
Regulatory Liabilities			Current		Noncurrent		Current		Noncurrent
Deferred income tax adjustments and TCJA refunds ^(a)	8	Various	$	0.8	$	1,441.6	$	—	$	1,469.3
Plant removal costs	1, 11	Plant lives	—		344.4		—		346.2
Effects of regulation on employee benefit costs ^(b)		Various	—		126.9		—		35.7
Renewable resources and environmental initiatives		Various	—		54.0		—		56.2
ITC deferrals ^(c)	1	Various	—		27.5		—		9.1
Deferred electric, natural gas and steam production costs		Less than one year	7.2		—		29.0		—
Conservation programs ^(d)	1	Less than one year	29.8		—		21.2		—
Other		Various	29.5		27.1		15.9		17.0
Total regulatory liabilities ^(e)			$	67.3	$	2,021.5	$	66.1	$	1,933.5


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


^(b)	Includes regulatory amortization and certain TCJA benefits approved by the CPUC to offset the prepaid pension asset at Dec. 31, 2018.


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


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


^(e)	Revenue subject to refund of $16.2 million and $0.0 million for 2018 and 2017, respectively, is included in other current liabilities.

At Dec. 31, 2018 and 2017, approximately $50 million and $44 million, respectively, of PSCo’s regulatory assets represented past expenditures not earning a return. Amounts primarily related to property taxes, renewable resources and environmental initiatives.


5.	Borrowings and Other Financing Instruments

Short-Term Borrowings

Money Pool — Xcel Energy Inc. and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings between the utility subsidiaries. Xcel Energy Inc. may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy Inc. ~~PSCo had no money pool borrowings outstanding during the three months ended Dec. 31, 2017.~~ Money pool borrowings for PSCo were as follows:


										Three Months Ended Dec. 31, 2018				Year Ended Dec. 31
(Amounts in Millions, Except Interest Rates)	Twelve Months Ended Dec. 31, 2017			Twelve Months Ended Dec. 31, 2016			Twelve Months Ended Dec. 31, 2015						2018				2017				2016
Borrowing limit	$	250		$	250		$	250			$	250			$	250			$	250			$	250
Amount outstanding at period end	—			—			—			—				—				—				—
Average amount outstanding	—			21			1			26				25				—				21
Maximum amount outstanding	20			141			34			96				156				20				141
Weighted average interest rate, computed on a daily basis	0.92		%	0.73		%	0.41		%	2.27		%		1.93		%		0.92		%		0.73		%
Weighted average interest rate at period end	N/A			N/A			N/A
Weighted average interest rate at end of period										N/A				N/A				N/A				N/A

Commercial Paper — PSCo meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility. ~~PSCo had no commercial paper borrowings outstanding during the three months ended Dec. 31, 2017.~~

Commercial paper borrowings for PSCo were as follows:


										Three Months Ended Dec. 31, 2018				Year Ended Dec. 31
(Amounts in Millions, Except Interest Rates)	Twelve Months Ended Dec. 31, 2017			Twelve Months Ended Dec. 31, 2016			Twelve Months Ended Dec. 31, 2015						2018				2017				2016
Borrowing limit	$	700		$	700		$	700			$	700			$	700			$	700			$	700
Amount outstanding at period end	—			129			14			307				307				—				129
Average amount outstanding	54			24			95			87				55				54				24
Maximum amount outstanding	268			154			449			309				309				268				154
Weighted average interest rate, computed on a daily basis	1.08		%	0.70		%	0.51		%	2.64		%		2.28		%		1.08		%		0.70		%
Weighted average interest rate at period end	N/A			0.95			0.60
Weighted average interest rate at end of period										2.95				2.95				N/A				0.95

Letters of Credit— PSCo uses letters of credit, ~~generally~~typically with terms of one-year, to provide financial guarantees for certain operating obligations. ~~At both~~As of Dec. 31, ~~2017~~2018 and ~~2016,~~2017, there were $10 million and $3 million of letters of credit outstanding, respectively under the credit facility. ~~The contract amounts of these letters of credit~~Amounts approximate their fair ~~value and are subject to fees.~~value.

Credit Facility — ~~In order to use its commercial paper program to fulfill short-term funding needs,~~ PSCo must have a revolving credit facility in place at least equal to the amount of its commercial paper borrowing limit and cannot issue commercial paper in an aggregate amount exceeding available capacity under this credit facility. The credit facility provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.

~~PSCo has the right to request an extension of the June 2021 termination date for two additional one-year periods. The extension requests are subject to majority bank group approval.~~

~~Other features~~Features of PSCo’s credit ~~facility include:~~facility:

~~PSCo may increase its credit facility by up to $100 million.~~



Debt-to-Total Capitalization Ratio^(a)				Amount Facility May Be Increased (millions)		Additional Periods For Which a One-Year Extension May Be Requested ^(b)
2018		2017
46	%	44	%	$	100	2


^(a)	The PSCo financial covenant requires that the debt-to-total capitalization ratio be less than or equal to 65%.


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

The credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65 percent. PSCo was in compliance as its debt-to-total capitalization ratio was 44 percent and 45 percent at Dec. 31, 2017 and 2016, respectively. If PSCo does not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender.

The credit facility has a cross-default provision that provides PSCo will be in default on its borrowings under the facility if PSCo or any of its subsidiaries whose total assets exceed 15 percent of PSCo’s consolidated total assets, default on ~~certain~~ indebtedness in an aggregate principal amount exceeding $75 ~~million.~~million.

If PSCo does not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender. As of Dec. 31, 2018, PSCo was in compliance with all financial ~~covenants on its debt agreements as of Dec. 31, 2017 and 2016.~~covenants.

~~At Dec. 31, 2017, PSCo~~PSCO had the following committed credit ~~facility~~facilities available ~~(in millions)~~as of Dec. 31, 2018 (millions):


Credit Facility ^(a)	Credit Facility ^(a)	Drawn ^(b)		Available		Credit Facility ^(a)	Drawn ^(b)		Available
$	700	$	3	$	697	700	$	317	$	383


^(a)	This credit facility matures in June 2021.


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

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. PSCo had no direct advances on the ~~credit~~ facility outstanding at Dec. 31, ~~2017~~2018 and ~~2016.~~

2017.

Long-Term Borrowings

Generally, ~~all real and personal~~ property of PSCo is subject to the liens of its first mortgage indenture. Debt premiums, discounts and expenses are amortized over the life of the related debt. The premiums, discounts and expenses ~~associated with~~for refinanced debt are deferred and amortized over the life of the ~~related~~ new ~~issuance, in accordance with regulatory guidelines.~~issuance.

Long-term debt obligations for PSCo as of Dec. 31:



(Millions of Dollars)	Maturity Range	Interest Rate Range 2018	Interest Rate Range 2017	2018			2017
Capital lease obligations	2025-2060	11.20% - 14.30%	11.20% - 14.30%	$	145		$	151
Mortgage bonds	2019-2048	2.25% - 6.50%	2.25% - 6.50%	4,900			4,500
Unamortized discount				(14		)	(13		)
Unamortized debt issuance cost				(33		)	(29		)
Current maturities				(406		)	(306		)
Total				$	4,592		$	4,303

Maturities of long-term debt:



(Millions of Dollars)
2019	$	400
2020	400
2021	—
2022	300
2023	250

2018 financings:



Amount	Financing Instrument	Interest Rate		Maturity Date
$350 million	First mortgage bonds	3.70	%	June 15, 2028
350 million	First mortgage bonds	4.10		June 15, 2048

2017 ~~PSCo issued $400 million of 3.80 percent first mortgage bonds due June 15, 2047. In 2016, PSCo issued $250 million of 3.55 percent first mortgage bonds due June 15, 2046.~~financings:

~~During the next five years, PSCo has long-term debt maturities of $300 million, $400 million, $400 million and $300 million due in 2018, 2019, 2020 and 2022, respectively.~~



Amount	Financing Instrument	Interest Rate		Maturity Date
$400 million	First mortgage bonds	3.80	%	June 15, 2047

Deferred Financing Costs — Deferred financing costs of approximately ~~$29~~$33 million and ~~$27~~$29 million, net of amortization, are presented as a deduction from the carrying amount of long-term debt atas of Dec. 31, ~~2017~~2018 and ~~2016,~~2017, respectively. PSCo is amortizing these financing costs over the remaining maturity periods of the related debt.

Dividend Restrictions — PSCo’s dividends are subject to the FERC’s jurisdiction, which prohibits the payment of dividends out of capital ~~accounts; payment~~accounts. Dividends are solely to be paid from retained earnings.


6.	Revenues

Revenue is classified by the type of ~~dividends is allowed out~~goods/services rendered and market/customer type. PSCo’s operating revenues (subsequent to adoption of ~~retained earnings only.~~the revised revenue guidance) consists of the following:



	Year Ended Dec. 31, 2018
(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	991.2	$	606.5	$	10.7	$	1,608.4
C&I	1,560.6		223.5		25.3		1,809.4
Other	47.6		—		0.1		47.7
Total retail	2,599.4		830.0		36.1		3,465.5
Wholesale	174.6		—		—		174.6
Transmission	54.2		—		—		54.2
Other	54.9		84.0		—		138.9
Total revenue from contracts with customers	2,883.1		914.0		36.1		3,833.2
Alternative revenue and other	148.1		100.6		4.3		253.0
Total revenues	$	3,031.2	$	1,014.6	$	40.4	$	4,086.2


5.7.	Preferred Stock

PSCo has authorized the issuance of preferred stock.

Preferred
Shares
Authorized Par Value Preferred
Shares
Outstanding
10,000,000
$ 0.01
None


6.	~~Joint Ownership of Generation, Transmission and Gas Facilities~~

~~Following are the investments by PSCo in jointly owned generation, transmission and gas facilities and the related ownership percentages as of Dec. 31, 2017:~~

(Thousands of Dollars)
Plant in
Service
Accumulated
Depreciation CWIP Ownership %
Electric Generation:
Hayden Unit 1 $ 150,441
$ 72,042
$ 830
76 %
Hayden Unit 2 148,694
65,493
18
37
Hayden Common Facilities 39,321
19,886
97
53
Craig Units 1 and 2 80,650
38,666
—
10
Craig Common Facilities 1, 2 and 3 38,902
20,116
—
7
Comanche Unit 3 889,630
117,759
476
67
Comanche Common Facilities 24,421
2,092
2,809
82
Electric Transmission:
Transmission and other facilities, including substations 176,873
67,637
638
Various
Gas Transportation:
Rifle, Colo. to Avon, Colo. 21,532
7,579
—
60
Gas Transportation Compressor 8,417
616
—
50
Total $ 1,578,881
$ 411,886
$ 4,868

PSCo has approximately 816 MW of jointly owned generating capacity. PSCo’s share of operating expenses and construction expenditures are included in the applicable utility accounts. Each of the respective owners is responsible for providing its own financing.



Preferred Shares Authorized	Par Value		Preferred Shares Outstanding
10,000,000	$	0.01	—


7.8.	Income Taxes

Federal Tax Reform — In ~~December~~ 2017, the TCJA was signed into law. ~~While the legislation will require interpretations and regulations to be issued by the IRS, the~~The key provisions impacting Xcel Energy (which includes PSCo), generally beginning in 2018, include:

Corporate federal tax rate reduction from ~~35 percent~~35% to ~~21 percent;~~21%;

Normalization of resulting plant-related excess deferred taxes;

Elimination of the corporate alternative minimum tax;

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

Limitations on certain executive compensation deductions;

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

Repeal of the section 199 manufacturing deduction; and

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

Entities are required under ASC Topic 740 to recognize the accounting impacts of a tax law change, including the impacts of a change in tax rates on deferred tax assets and liabilities, in the period including the date of the tax law enactment. The SEC staff issued guidance in SAB 118 that supplements the accounting requirements of ASC Topic 740 if elements of the TCJA assessment are not complete, and provides for up to a one year period to finalize the required accounting. Xcel Energy ~~has~~ estimated the effects of the TCJA, which have been reflected in the ~~Dec. 31, 2017~~ consolidated financial statements. ~~Issuance of U.S. Treasury regulations interpreting the TCJA, other U.S. Treasury and IRS guidance or interpretations of the application of ASC Topic 740 may result in changes to these estimates.~~

~~Overall for Xcel Energy, reductions~~Reductions in deferred tax assets and liabilities due to ~~the reduction~~a decrease in corporate federal tax rates typically result in a net tax benefit. However, the impacts are primarily recognized as regulatory liabilities refundable to utility customers as a result of IRS requirements and past regulatory treatment of deferred taxes in the determination of regulated rates of the utility subsidiaries, including deferred taxes related to regulated plant and certain other deferred tax assets and liabilities, the impact was primarily recognized as a regulatory liability refundable to utility customers.treatment.

~~The fourth quarter 2017 estimated accounting~~Estimated impacts ~~of the December 2017 enactment~~ of the new tax law atfor PSCo in December 2017 included:

$1.1 billion ($1.5 billion grossed-up for tax) of reclassifications of plant-related excess deferred taxes to regulatory liabilities upon valuation at the new ~~21 percent~~21% federal rate. The regulatory liabilities will be amortized consistent with IRS normalization requirements, resulting in customer refunds over the average remaining life of the related property;

$54 million and $50 million of reclassifications (grossed-up for tax) of excess deferred taxes for non-plant related deferred tax assets and liabilities, respectively, to regulatory assets and liabilities; and

$18 million of total estimated income tax benefit related to the federal tax reform implementation, and a $4 million reduction to net income related to the allocation of Xcel Energy Services Inc.’s tax rate change on its deferred taxes.

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

~~Consolidated Appropriations Act, 2016~~ ~~— In December 2015, the Consolidated Appropriations Act, 2016 (Act) was signed into law. The Act provided for the following:~~

~~Immediate expensing, or “bonus depreciation,” of 50 percent for property placed in service in 2015, 2016, and 2017;~~

PTCs at 100 percent of the applicable rate for wind energy projects that begin construction by the end of 2016; 80 percent of the credit rate for projects that begin construction in 2017; 60 percent of the credit rate for projects that begin construction in 2018; and 40 percent of the credit rate for projects that begin construction in 2019. The wind energy PTC was not extended for projects that begin construction after 2019;

ITCs at 30 percent for commercial solar projects that begin construction by the end of 2019; 26 percent for projects that begin construction in 2020; 22 percent for projects that begin construction in 2021; and 10 percent for projects thereafter;

~~R&E credit was permanently extended; and~~

~~Delay of two years (until 2020) of the excise tax on certain employer-provided health insurance plans.~~

~~The accounting related to the Act was recorded beginning in the fourth quarter of 2015 because a change in tax law is accounted for beginning in the period of enactment.~~

Federal Audit — ~~PSCO~~PSCo is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. ~~The statutes~~Statute of limitations applicable to Xcel Energy’s consolidated federal income tax returns expire as follows:



Tax Year(s)		Expiration
2009 - ~~2011~~		~~June 2018~~
~~2012 - 2013~~2014		October ~~2018~~
~~2014~~		~~September 2018~~2019
2015		September 2019
2016		September 2020
2017		September 2021

In 2012, the IRS commenced an examination of tax years 2010 and 2011, including the 2009 carryback claim. The IRS proposed an adjustment to the federal tax loss carryback claims that would have resulted in $14 million of income tax expense for the 2009 through 2011 claims, and the 2013 through 2015 claims. In ~~the fourth quarter of 2015, the IRS forwarded the issue to the Office of Appeals (“Appeals”). In the third quarter of~~ 2017, Xcel Energy and the Office of Appeals reached an agreement and the benefit related to the agreed upon portions was recognized. PSCo did not accrue any income tax benefit related to this adjustment. AsIn the second quarter of ~~Dec. 31, 2017, the case has been forwarded to~~2018, the Joint Committee on ~~Taxation.~~

Taxation completed its review and took no exception to the agreement. As a result, the remaining unrecognized tax benefit was released and recorded as a payable to the IRS.

In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013. In the third quarter of 2017, the IRS concluded the audit of tax years 2012 and 2013 and proposed an adjustment that would impact Xcel Energy’s NOL and ETR. ~~After evaluating the proposed adjustment,~~ Xcel Energy filed a protest with the IRS. ~~Xcel Energy anticipates the issue will be forwarded to Appeals.~~ As of Dec. 31, ~~2017,~~2018, the case has been forwarded to the Office of Appeals and Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of this issue; however, the outcome and timing of a resolution is ~~uncertain.~~unknown.

In the fourth quarter of 2018, the IRS began an audit of tax years 2014 - 2016, however no adjustments have been proposed.

State Audits — PSCo is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Dec. 31, ~~2017,~~2018, PSCo’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009. There are currently no state income tax audits in progress.

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

~~A reconciliation of the amount of unrecognized~~

Unrecognized tax ~~benefit is as follows:~~benefits - permanent vs temporary:


(Millions of Dollars)	Dec. 31, 2017		Dec. 31, 2016		Dec. 31, 2018		Dec. 31, 2017
Unrecognized tax benefit — Permanent tax positions	$	4.0	$	2.9	$	5.4	$	4.0
Unrecognized tax benefit — Temporary tax positions	6.1		16.8		4.9		6.1
Total unrecognized tax benefit	$	10.1	$	19.7	$	10.3	$	10.1

~~A reconciliation of the beginning and ending amount of~~Changes in unrecognized tax ~~benefit is as follows:~~benefits:


(Millions of Dollars)	2017			2016			2015			2018			2017			2016
Balance at Jan. 1	$	19.7		$	17.4		$	11.9		$	10.1		$	19.7		$	17.4
Additions based on tax positions related to the current year	1.9			2.7			4.5			1.1			1.9			2.7
Reductions based on tax positions related to the current year	(1.5		)	—			(1.5		)	(0.3		)	(1.5		)	—
Additions for tax positions of prior years	4.4			0.5			2.5			0.4			4.4			0.5
Reductions for tax positions of prior years	(14.4		)	(0.9		)	—			(0.1		)	(14.4		)	(0.9		)
Settlements with taxing authorities										(0.9		)	—			—
Balance at Dec. 31	$	10.1		$	19.7		$	17.4		$	10.3		$	10.1		$	19.7

~~The unrecognized~~Unrecognized tax ~~benefit amounts~~benefits were reduced by ~~the~~ tax benefits associated with NOL and tax credit ~~carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows:~~carryforwards:


(Millions of Dollars)	Dec. 31, 2017			Dec. 31, 2016			Dec. 31, 2018			Dec. 31, 2017
NOL and tax credit carryforwards	$	(4.0	)	$	(5.8	)	$	(5.6	)	$	(4.0	)

~~It is reasonably possible that PSCo’s amount of~~Net deferred tax liability associated with the unrecognized tax ~~benefits could significantly change in the next 12 months as the IRS Appeals progresses~~benefit amounts and ~~the IRS~~related NOLs and ~~state audits resume.~~ tax credits carryforwards were $2.0 million and $(0.3) million for Dec. 31, 2018 and Dec. 31, 2017, respectively.

As the IRS Appeals ~~progresses,~~and federal audit progress and state audits resume, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately ~~$2 million.~~$8.7 million in the next 12 months.

~~The payable~~Payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. ~~A reconciliation of the beginning and ending amount of the~~

Interest payable ~~for interest~~ related to unrecognized tax ~~benefits are as follows:~~benefits:


(Millions of Dollars)	2017			2016			2015			2018			2017			2016
Payable for interest related to unrecognized tax benefits at Jan. 1	$	(1.1	)	$	(0.4	)	$	(0.2	)	$	(0.3	)	$	(1.1	)	$	(0.4	)
Interest income (expense) related to unrecognized tax benefits	0.8			(0.7		)	(0.2		)
Interest (expense) income related to unrecognized tax benefits										(0.4		)	0.8			(0.7		)
Payable for interest related to unrecognized tax benefits at Dec. 31	$	(0.3	)	$	(1.1	)	$	(0.4	)	$	(0.7	)	$	(0.3	)	$	(1.1	)

No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2018, 2017 ~~2016~~ or ~~2015.~~

2016.

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


(Millions of Dollars)	2017			2016			2018			2017
Federal NOL carryforward	$	68		$	260		$	—		$	67.6
Federal tax credit carryforwards	30			25			35.0			29.8
State NOL carryforwards	679			684			484.7			679.2
State tax credit carryforwards, net of federal detriment ^(a)	17			13			16.9			16.8
Valuation allowances for state credit carryforwards, net of federal detriment ^(b)	(7		)	(3		)
Valuation allowances for state credit carryforwards, net of federal benefit ^(b)							(8.9		)	(7.3		)


^(a)	State tax credit carryforwards are net of federal detriment of ~~$4 million and $7~~$4.5 million as of Dec. 31, ~~2017~~2018 and ~~2016, respectively.~~2017.


^(b)	Valuation allowances for state tax credit carryforwards were net of federal benefit of $2$2.4 million and $2$1.9 million as of Dec. 31, ~~2017~~2018 and ~~2016,~~2017, respectively.

~~The federal~~

Federal carryforward periods expire between 2021 and ~~2037. The~~2038 and state carryforward periods expire between ~~2018~~2019 and 2033.

Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. ~~The following reconciles such differences~~

Effective income tax rate for ~~the~~ years ~~ending~~ended Dec. 31:


	2017		2016 ^(b)		2015 ^(b)		2018		2017 ^(a)		2016 ^(a)
Federal statutory rate	35.0	%	35.0	%	35.0	%	21.0	%	35.0	%	35.0	%
State income tax on pretax income, net of federal tax effect	3.0	%	3.0	%	3.0	%	3.7	%	3.0	%	3.0	%
Increases (decreases) in tax from:
Regulatory differences - ARAM ^(b)							(3.0	)	(0.1	)	(0.1	)
Regulatory differences - other utility plant items							(1.7	)	(0.9	)	(0.5	)
Amortization of excess nonplant deferred taxes							(1.4	)	—		—
Tax credits recognized, net of federal income tax expense							(0.9	)	(0.9	)	(0.7	)
Wind PTCs recognized							(0.6	)	—		—
Regulatory differences - Deferral of ARAM ^(c)							0.2		—		—
Change in unrecognized tax benefits							0.1		0.2		—
Tax reform	(2.4	)	—		—		—		(2.4	)	—
Tax credits recognized, net of federal income tax expense	(0.9	)	(0.7	)	(0.7	)
Regulatory differences - effects of rate changes ^(a)	(0.1	)	(0.1	)	(0.1	)
Regulatory differences - other utility plant items	(0.9	)	(0.5	)	(0.3	)
Change in unrecognized tax benefits	0.2		—		0.1
Other, net	(0.1	)	0.4		0.4		(0.3	)	(0.1	)	0.4
Effective income tax rate	33.8	%	37.1	%	37.4	%	17.1	%	33.8	%	37.1	%


^(a)	~~The amortization of excess deferred taxes.~~Prior periods have been reclassified to conform to current year presentation.


^(b)	~~The prior periods included~~ARAM is a method to flow back excess deferred taxes to customers.

^(c)

ARAM has been deferred when regulatory treatment has not been established. As Xcel Energy received direction from its regulatory commissions regarding the return of excess deferred taxes to customers, the ARAM deferral was reversed. This resulted in ~~this footnote have been reclassified~~a reduction to ~~conform~~tax expense with a corresponding reduction to ~~current year presentation.~~revenue.

~~The components~~Components of income tax expense for the years ~~ending~~ended Dec. ~~31 were:~~31:


(Thousands of Dollars)	2017			2016			2015
Current federal tax expense (benefit)	$	40,386		$	45,287		$	(1,166	)
Current state tax expense (benefit)	14,577			8,754			(727		)
(Millions of Dollars)										2018			2017			2016
Current federal tax expense										$	79.5		$	40.4		$	45.3
Current state tax expense										14.2			14.6			8.7
Current change in unrecognized tax (benefit) expense	(7,798		)	680			5,244			(1.3		)	(7.8		)	0.7
Deferred federal tax expense	176,410			195,064			246,096			4.9			176.4			195.1
Deferred state tax expense	22,513			27,216			36,450			16.6			22.5			27.2
Deferred change in unrecognized tax expense (benefit)	8,894			(278		)	(4,650		)	2.3			8.9			(0.3		)
Deferred investment tax credits	(2,803		)	(2,805		)	(2,807		)
Deferred ITCs										(2.5		)	(2.8		)	(2.8		)
Total income tax expense	$	252,179		$	273,918		$	278,440		$	113.7		$	252.2		$	273.9

~~The components~~Components of deferred income tax expense ~~for the years ending~~as of Dec. ~~31 were:~~31:



(Millions of Dollars)	2018			2017			2016
Deferred tax expense (benefit) excluding items below	$	74.8		$	(1,244.7	)	$	230.9
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	(50.6		)	1,453.1			(8.4		)
Tax expense allocated to other comprehensive income, net of adoption of ASU No. 2018-02, and other	(0.4		)	(0.6		)	(0.5		)
Deferred tax expense	$	23.8		$	207.8		$	222.0

(Thousands of Dollars) 2017 2016 2015
Deferred tax (benefit) expense excluding items below $ (1,244,653 ) $ 230,931
$ 285,144
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities 1,453,080
(8,418 ) (7,229 )
Tax expense allocated to other comprehensive income, net of adoption of ASU No. 2018-02, and other (610 ) (511 ) (19 )
Deferred tax expense $ 207,817
$ 222,002
$ 277,896

~~The components~~

Components of the net deferred tax liability atas of Dec. ~~31 were as follows:~~31:

(Thousands of Dollars) 2017
2016 ^(a)
Deferred tax liabilities:
Differences between book and tax bases of property $ 1,797,023
$ 2,967,162
Regulatory assets 252,353
102,967
Pension expense 60,032
10,016
Other 3,994
3,920
Total deferred tax liabilities $ 2,113,402
$ 3,084,065
Deferred tax assets:

Regulatory liabilities $ 337,973
$ (35,813 )
NOL carryforward 39,347
115,328
Tax credit carryforward 39,323
34,658
Deferred investment tax credits 6,872
11,653
Other employee benefits 6,779
15,274
Deferred fuel costs 6,523
10,070
Rate refund 890
7,221
Other 31,219
36,545
Total deferred tax assets $ 468,926
$ 194,936
Net deferred tax liability $ 1,644,476
$ 2,889,129


^(a)	~~The prior period included in this footnote has been reclassified to conform to current year presentation.~~


8.	~~Benefit Plans and Other Postretirement Benefits~~

Consistent with the process for rate recovery of pension and postretirement benefits for its employees, PSCo accounts for its participation in, and related costs of, pension and other postretirement benefit plans sponsored by Xcel Energy Inc. as multiple employer plans. PSCo is responsible for its share of cash contributions, plan costs and obligations and is entitled to its share of plan assets; accordingly, PSCo accounts for its pro rata share of these plans, including pension expense and contributions, resulting in accounting consistent with that of a single employer plan exclusively for PSCo employees.

Xcel Energy, which includes PSCo, offers various benefit plans to its employees. Approximately 76 percent of employees that receive benefits are represented by several local labor unions under several collective-bargaining agreements. At Dec. 31, 2017, PSCo had 1,835 bargaining employees covered under a collective-bargaining agreement, which expired in May 2017. While collective bargaining is ongoing, the terms and conditions of the agreement are automatically extended.

The plans invest in various instruments which are disclosed under the accounting guidance for fair value measurements which establishes a hierarchical framework for disclosing the observability of the inputs utilized in measuring fair value. The three levels in the hierarchy and examples of each level are as follows:

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

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

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

~~Specific valuation methods include the following:~~

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

~~Insurance contracts~~ ~~— Insurance contract fair values take into consideration the value of the investments in separate accounts of the insurer, which are priced based on observable inputs.~~

~~Investments in commingled funds, equity securities and other funds~~ — Equity securities are valued using quoted prices in active markets. The fair values for commingled funds are measured using NAVs, which take into consideration the value of underlying fund investments, as well as the other accrued assets and liabilities of a fund, in order to determine a per share market value. The investments in commingled funds may be redeemed for NAV with proper notice. Proper notice varies by fund and can range from daily with a few days’ notice to annually with 90 days’ notice. Private equity investments require approval of the fund for any unscheduled redemption, and such redemptions may be approved or denied by the fund at its sole discretion. Depending on the fund, unscheduled distributions from real estate investments may require approval of the fund or may be redeemed with proper notice, which is typically quarterly with 45-90 days’ notice; however, withdrawals from real estate investments may be delayed or discounted as a result of fund illiquidity.

~~Investments in debt securities~~ ~~— Fair values for debt securities are determined by a third party pricing service using recent trades and observable spreads from benchmark interest rates for similar securities.~~ ~~Derivative Instruments~~ —Fair values for foreign currency derivatives are determined using pricing models based on the prevailing forward exchange rate of the underlying currencies. The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.

~~Pension Benefits~~

Xcel Energy, which includes PSCo, has several noncontributory, defined benefit pension plans that cover almost all employees. Generally, benefits are based on a combination of years of service, the employee’s average pay and, in some cases, social security benefits. Xcel Energy Inc.’s and PSCo’s policy is to fully fund into an external trust the actuarially determined pension costs recognized for ratemaking and financial reporting purposes, subject to the limitations of applicable employee benefit and tax laws.

In addition to the qualified pension plans, Xcel Energy maintains a supplemental executive retirement plan (SERP) and a nonqualified pension plan. The SERP is maintained for certain executives that were participants in the plan in 2008, when the SERP was closed to new participants. The nonqualified pension plan provides unfunded, nonqualified benefits for compensation that is in excess of the limits applicable to the qualified pension plans, with distributions attributable to PSCo funded by PSCo’s consolidated operating cash flows. The total obligations of the SERP and nonqualified plan as of Dec. 31, 2017 and 2016 were $37 million and $44 million, respectively, of which $3 million and $4 million were attributable to PSCo. In 2017 and 2016, Xcel Energy recognized net benefit cost for financial reporting for the SERP and nonqualified plans of $5 million and $8 million, respectively, of which $1 million in each year was attributable to PSCo.

In 2016, Xcel Energy established rabbi trusts to provide partial funding for future distributions of the SERP and its deferred compensation plan. Rabbi trust funding of deferred compensation plan distributions attributable to PSCo will be supplemented by PSCo’s consolidated operating cash flows as determined necessary. The amount of rabbi trust funding attributable to PSCo is immaterial. Also in 2016, Xcel Energy amended the deferred compensation plan to provide eligible participants the ability to diversify deferred settlements of equity awards, other than time-based equity awards, into various fund options.

Xcel Energy Inc. and PSCo base the investment-return assumption on expected long-term performance for each of the investment types included in the pension asset portfolio and consider the historical returns achieved by the asset portfolio over the past 20-year or longer period, as well as the long-term return levels projected and recommended by investment experts. Xcel Energy Inc. and PSCo continually review pension assumptions. The pension cost determination assumes a forecasted mix of investment types over the long term.

~~Investment returns in 2017 were above the assumed level of 6.84 percent;~~

~~Investment returns in 2016 were below the assumed level of 6.84 percent;~~

~~Investment returns in 2015 were below the assumed level of 6.81 percent; and~~

~~In 2018, PSCo’s expected investment-return assumption is 6.84 percent.~~

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

~~The following table presents the target pension asset allocations for PSCo at Dec. 31 for the upcoming year:~~

2017 2016
Domestic and international equity securities 34 % 36 %
Long-duration fixed income and interest rate swap securities 32
31
Short-to-intermediate fixed income securities 18
15
Alternative investments 14
16
Cash 2
2
Total 100 % 100 %

The ongoing investment strategy is based on plan-specific investment recommendations that seek to minimize potential investment and interest rate risk as a plan’s funded status increases over time. The investment recommendations result in a greater percentage of long-duration fixed income securities being allocated to specific plans having relatively higher funded status ratios and a greater percentage of growth assets being allocated to plans having relatively lower funded status ratios. The aggregate projected asset allocation presented in the table above for the master pension trust results from the plan-specific strategies.

~~Pension Plan Assets~~

~~The following tables present, for each of the fair value hierarchy levels, PSCo’s pension plan assets that are measured at fair value as of Dec. 31, 2017 and 2016:~~

Dec. 31, 2017
(Thousands of Dollars) Level 1 Level 2 Level 3 Investments Measured at NAV Total
Cash equivalents $ 67,179
$ —
$ —
$ —
$ 67,179
Commingled funds:
U.S. equity funds 169,624
—
—
—
169,624
Non U.S. equity funds 30,277
—
—
65,822
96,099
U.S. corporate bond funds 137,086
—
—
—
137,086
Emerging market equity funds —
—
—
103,876
103,876
Emerging market debt funds 24,825
—
—
54,954
79,779
Private equity investments —
—
—
27,816
27,816
Real estate —
—
—
64,500
64,500
Other commingled funds 1,601
—
—
38,545
40,146
Debt securities:
Government securities —
144,333
—
—
144,333
U.S. corporate bonds —
102,659
—
—
102,659
Non U.S. corporate bonds —
16,792
—
—
16,792
Equity securities:
U.S. equities 37,752
—
—
—
37,752
Other (9,885 ) 1,414
—
180
(8,291 )
Total $ 458,459
$ 265,198
$ —
$ 355,693
$ 1,079,350

Dec. 31, 2016
(Thousands of Dollars) Level 1 Level 2 Level 3 Investments Measured at NAV Total
Cash equivalents $ 34,957
$ —
$ —
$ —
$ 34,957
Commingled funds:
U.S. equity funds 165,621
—
—
—
165,621
Non U.S. equity funds 64,710
—
—
57,487
122,197
U.S. corporate bond funds 96,995
—
—
—
96,995
Emerging market equity funds —
—
—
64,784
64,784
Emerging market debt funds 25,866
—
—
27,837
53,703
Commodity funds —
—
—
7,497
7,497
Private equity investments —
—
—
31,828
31,828
Real estate —
—
—
61,048
61,048
Other commingled funds —
—
—
74,696
74,696
Debt securities:
Government securities —
168,014
—
—
168,014
U.S. corporate bonds —
86,081
—
—
86,081
Non U.S. corporate bonds —
13,828
—
—
13,828
Mortgage-backed securities —
2,179
—
—
2,179
Asset-backed securities —
1,032
—
—
1,032
Equity securities:
U.S. equities 27,348
—
—
—
27,348
Other —
(7,595 ) —
—
(7,595 )
Total $ 415,497
$ 263,539
$ —
$ 325,177
$ 1,004,213

~~There were no assets transferred in or out of Level 3 for the years ended Dec. 31, 2017, 2016 or 2015.~~

~~Benefit Obligations~~ ~~— A comparison of the actuarially computed pension benefit obligation and plan assets for PSCo is presented in the following table:~~

(Thousands of Dollars) 2017 2016
Accumulated Benefit Obligation at Dec. 31 $ 1,285,010
$ 1,213,890

Change in Projected Benefit Obligation:
Obligation at Jan. 1 $ 1,251,822
$ 1,224,650
Service cost 27,280
25,926
Interest cost 50,558
55,405
Transfer to other plan —
(9,149 )
Plan amendments (1,096 ) 206
Actuarial loss 83,531
51,779
Benefit payments (77,915 ) (96,995 )
Obligation at Dec. 31 $ 1,334,180
$ 1,251,822

(Thousands of Dollars) 2017 2016
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1 $ 1,004,213
$ 1,036,681
Actual return on plan assets 135,552
56,762
Employer contributions 17,500
16,829
Transfer to other plan —
(9,064 )
Benefit payments (77,915 ) (96,995 )
Fair value of plan assets at Dec. 31 $ 1,079,350
$ 1,004,213

(Thousands of Dollars) 2017 2016
Funded Status of Plans at Dec. 31:
Funded status ^(a)
$ (254,830 ) $ (247,609 )


^(a)	~~Amounts are recognized in noncurrent liabilities on PSCo’s consolidated balance sheets.~~

(Thousands of Dollars) 2017 2016
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss $ 543,707
$ 554,999
Prior service credit (10,593 ) (12,155 )
Total $ 533,114
$ 542,844

(Thousands of Dollars) 2017 2016
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Current regulatory assets $ 27,662
$ 26,853
Noncurrent regulatory assets 505,171
515,708
Deferred income taxes 69
108
Net-of-tax accumulated OCI 212
175
Total $ 533,114
$ 542,844



~~Measurement date~~	~~Dec. 31, 2017~~	~~Dec. 31, 2016~~

2017 2016
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation 3.63 % 4.13 %
Expected average long-term increase in compensation level 3.75
3.75
Mortality table RP-2014
RP-2014

~~Mortality —~~ In 2014, the Society of Actuaries published a new mortality table (RP-2014) that increased the overall life expectancy of males and females. In 2014, PSCo adopted this mortality table, with modifications, based on its population and specific experience. During 2017, a new projection table was released (MP-2017). PSCo evaluated the updated projection table and concluded that the methodology currently in use and adopted in 2016 is consistent with the recently updated 2017 table and continues to be representative of PSCo’s population.

~~Cash Flows —~~ Cash funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other calculations prescribed by the funding requirements of income tax and other pension-related regulations. Required contributions were made in 2015 through 2018 to meet minimum funding requirements.

~~Total voluntary and required pension funding contributions across all four of Xcel Energy’s pension plans were as follows:~~

~~$150 million in January 2018, of which $22 million was attributable to PSCo;~~

~~$162 million in 2017, of which $18 million was attributable to PSCo;~~

~~$125 million in 2016, of which $17 million was attributable to PSCo; and~~

~~$90 million in 2015, of which $20 million was attributable to PSCo.~~

~~For future years, Xcel Energy and PSCo anticipate contributions will be made as necessary.~~

~~Plan Amendments —~~ Xcel Energy, which includes PSCo, amended the Xcel Energy Inc. Nonbargaining Pension Plan (South) in 2017 to reduce supplemental benefits for non-bargaining participants as well as to allow the transfer of a portion of non-qualified pension obligations into the qualified plans. In 2016, the annual credits contributed to the PSCo Bargaining Plan retirement spending account increased.

~~Benefit Costs~~ —~~The components of PSCo’s net periodic pension cost were:~~

(Thousands of Dollars) 2017 2016 2015
Service cost $ 27,280
$ 25,926
$ 28,260
Interest cost 50,558
55,405
50,857
Expected return on plan assets (68,535 ) (70,769 ) (72,590 )
Amortization of prior service credit (3,211 ) (3,211 ) (3,136 )
Amortization of net loss 28,355
26,771
36,377
Net periodic pension cost 34,447
34,122
39,768
(Costs) credits not recognized due to effects of regulation (2,631 ) 3,364
(1,464 )
Net benefit cost recognized for financial reporting $ 31,816
$ 37,486
$ 38,304

2017 2016 2015
Significant Assumptions Used to Measure Costs:
Discount rate 4.13 % 4.66 % 4.11 %
Expected average long-term increase in compensation level 3.75
4.00
3.75
Expected average long-term rate of return on assets 6.84
6.84
6.81

In addition to the benefit costs in the table above, for the pension plans sponsored by Xcel Energy Inc., costs are allocated to PSCo based on Xcel Energy Services Inc. employees’ labor costs. Amounts allocated to PSCo were $18 million, $9 million and $10 million in 2017, 2016 and 2015, respectively. Pension costs include an expected return impact for the current year that may differ from actual investment performance in the plan. The return assumption used for 2018 pension cost calculations is 6.84 percent. The cost calculation uses a market-related valuation of pension assets. Xcel Energy, including PSCo, uses a calculated value method to determine the market-related value of the plan assets. The market-related value begins with the fair market value of assets as of the beginning of the year. The market-related value is determined by adjusting the fair market value of assets to reflect the investment gains and losses (the difference between the actual investment return and the expected investment return on the market-related value) during each of the previous five years at the rate of 20 percent per year. As these differences between actual investment returns and the expected investment returns are incorporated into the market-related value, the differences are recognized over the expected average remaining years of service for active employees.

~~Defined Contribution Plans~~

Xcel Energy, which includes PSCo, maintains 401(k) and other defined contribution plans that cover substantially all employees. The expense to these plans for PSCo was approximately $10 million in 2017, 2016 and 2015.

~~Postretirement Health Care Benefits~~

Xcel Energy, which includes PSCo, has a contributory health and welfare benefit plan that provides health care and death benefits to certain retirees. Xcel Energy discontinued contributing toward health care benefits for PSCo nonbargaining employees retiring after June 30, 2003. Employees of NCE who retired in 2002 continue to receive employer-subsidized health care benefits. Nonbargaining employees of the former NCE who retired after 1998, bargaining employees of the former NCE who retired after 1999 and nonbargaining employees of NCE who retired after June 30, 2003, are eligible to participate in the Xcel Energy health care program with no employer subsidy.

~~Plan Assets —~~ Certain state agencies that regulate Xcel Energy Inc.’s utility subsidiaries also have issued guidelines related to the funding of postretirement benefit costs. PSCo is required to fund postretirement benefit costs in irrevocable external trusts that are dedicated to the payment of these postretirement benefits. These assets are invested in a manner consistent with the investment strategy for the pension plan.

~~The following table presents the target postretirement asset allocations for Xcel Energy Inc. and PSCo at Dec. 31 for the upcoming year:~~

2017 2016
Domestic and international equity securities 24 % 25 %
Short-to-intermediate fixed income securities 60
57
Alternative investments 9
13
Cash 7
5
Total 100 % 100 %

Xcel Energy Inc. and PSCo base the investment-return assumptions for the postretirement health care fund assets on expected long-term performance for each of the investment types included in the asset portfolio. Assumptions and target allocations are determined at the master trust level. The investment mix at each of Xcel Energy Inc.’s utility subsidiaries may vary from the investment mix of the total asset portfolio. The assets are invested in a portfolio according to Xcel Energy Inc.’s and PSCo’s return, liquidity and diversification objectives to provide a source of funding for plan obligations and minimize contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the projected asset allocation given the long-term risk, return, correlation and liquidity characteristics of each particular asset class. There were no significant concentrations of risk in any particular industry, index, or entity. Market volatility can impact even well-diversified portfolios and significantly affect the return levels achieved by postretirement health care assets in any year.

The following tables present, for each of the fair value hierarchy levels, PSCo’s proportionate allocation of the total postretirement benefit plan assets that are measured at fair value as of Dec. 31, 2017 and 2016:

Dec. 31, 2017
(Thousands of Dollars) Level 1 Level 2 Level 3 Investments Measured at NAV Total
Cash equivalents $ 25,724
$ —
$ —
$ —
$ 25,724
Insurance contracts —
43,524
—
—
43,524
Commingled funds:
U.S. equity funds 64,899
—
—
—
64,899
U.S fixed income funds 29,946
—
—
—
29,946
Emerging market debt funds 35,402
—
—
—
35,402
Debt securities:
Government securities —
50,576
—
—
50,576
U.S. corporate bonds —
55,323
—
—
55,323
Non U.S. corporate bonds —
18,712
—
—
18,712
Asset-backed securities —
20,468
—
—
20,468
Mortgage-backed securities —
30,231
—
—
30,231
Equity securities:
Non U.S. equities 30,671
—
—
—
30,671
Other —
948
—
—
948
Total $ 186,642
$ 219,782
$ —
$ —
$ 406,424

Dec. 31, 2016
(Thousands of Dollars) Level 1 Level 2 Level 3
Investments Measured at NAV

Total
Cash equivalents $ 18,288
$ —
$ —
$ —
$ 18,288
Insurance contracts —
42,046
—
—
42,046
Commingled funds:
U.S. equity funds 48,462
—
—
—
48,462
U.S fixed income funds 24,132
—
—
—
24,132
Emerging market debt funds 27,089
—
—
—
27,089
Other commingled funds —
—
—
48,922
48,922
Debt securities:
Government securities —
33,600
—
—
33,600
U.S. corporate bonds —
55,473
—
—
55,473
Non U.S. corporate bonds —
15,384
—
—
15,384
Asset-backed securities —
16,845
—
—
16,845
Mortgage-backed securities —
25,563
—
—
25,563
Equity securities:
Non U.S. equities 36,462
—
—
—
36,462
Other —
1,289
—
—
1,289
Total $ 154,433
$ 190,200
$ —
$ 48,922
$ 393,555

~~There were no assets transferred in or out of Level 3 for the years ended Dec. 31, 2017, 2016 or 2015.~~

~~Benefit Obligations~~ ~~— A comparison of the actuarially computed benefit obligation and plan assets for PSCo is presented in the following table:~~

(Thousands of Dollars) 2017 2016
Change in Projected Benefit Obligation:
Obligation at Jan. 1 $ 421,823
$ 403,574
Service cost 767
768
Interest cost 16,765
18,070
Medicare subsidy reimbursements 993
1,901
Plan participants’ contributions 5,971
5,376
Actuarial loss 18,314
27,355
Benefit payments (35,386 ) (35,221 )
Obligation at Dec. 31 $ 429,247
$ 421,823

(Thousands of Dollars) 2017 2016
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1 $ 393,555
$ 399,442
Actual return on plan assets 36,975
18,590
Plan participants’ contributions 5,971
5,376
Employer contributions 5,309
5,368
Benefit payments (35,386 ) (35,221 )
Fair value of plan assets at Dec. 31 $ 406,424
$ 393,555

(Thousands of Dollars) 2017 2016
Funded Status at Dec. 31:
Funded status ^(a)
$ (22,823 ) $ (28,268 )


^(a)	~~Amounts are recognized in noncurrent liabilities on PSCo’s consolidated balance sheets as of Dec. 31, 2017 and 2016, respectively.~~

(Thousands of Dollars) 2017 2016
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss $ 77,760
$ 78,359
Prior service credit (21,448 ) (27,695 )
Total $ 56,312
$ 50,664

(Thousands of Dollars) 2017 2016
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Noncurrent regulatory assets $ 56,312
$ 50,664



~~Measurement date~~	~~Dec. 31, 2017~~	~~Dec. 31, 2016~~

2017 2016
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation 3.62 % 4.13 %
Mortality table RP 2014
RP 2014
Health care costs trend rate — initial: Pre-65 7.00 % 5.50 %
Health care costs trend rate — initial: Post-65 5.50 % 5.50 %

Beginning with the Dec. 31 2017 measurement, Xcel Energy Inc. and PSCo separated its initial medical trend assumption for pre-Medicare (Pre-65) and post-Medicare (Post-65) claims costs of 7.0 percent and 5.5 percent, respectively, in order to reflect different short-term expectations based on recent experience differences. The ultimate trend assumption remained at 4.5 percent for both Pre-65 and Post-65 claims costs as similar long-term trend rates are expected for both populations. The period until the ultimate rate is reached is five years. Xcel Energy Inc. and PSCo base the medical trend assumption on the long-term cost inflation expected in the health care market, considering the levels projected and recommended by industry experts, as well as recent actual medical cost increases experienced by the retiree medical plan.

~~A one-percent change in the assumed health care cost trend rate would have the following effects on PSCo:~~

One-Percentage Point
(Thousands of Dollars) Increase Decrease
APBO $ 41,665
$ (35,254 )
Service and interest components 1,837
(1,555 )

~~Cash Flows —~~ The postretirement health care plans have no funding requirements under income tax and other retirement-related regulations other than fulfilling benefit payment obligations, when claims are presented and approved under the plans. Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities. Xcel Energy, which includes PSCo, contributed $20 million, $18 million and $18 million during 2017, 2016 and 2015, respectively, of which $5 million, $5 million and $6 million were attributable to PSCo. Xcel Energy expects to contribute approximately $12 million during 2018, of which amounts attributable to PSCo will be zero.

~~Plan Amendments —~~ ~~In 2017 and 2016 there were no plan amendments made which affected the projected benefit obligation.~~

~~Benefit Costs~~ ~~— The components of PSCo’s net periodic postretirement benefit costs were:~~

(Thousands of Dollars) 2017 2016 2015
Service cost $ 767
$ 768
$ 928
Interest cost 16,765
18,070
17,498
Expected return on plan assets (21,905 ) (22,299 ) (23,803 )
Amortization of prior service credit (6,247 ) (6,247 ) (6,247 )
Amortization of net loss 3,843
1,931
2,475
Net periodic postretirement benefit credit $ (6,777 ) $ (7,777 ) $ (9,149 )

2017 2016 2015
Significant Assumptions Used to Measure Costs:
Discount rate 4.13 % 4.65 % 4.08 %
Expected average long-term rate of return on assets 5.80
5.80
5.80

In addition to the benefit costs in the table above, for the postretirement health care plans sponsored by Xcel Energy Inc., costs are allocated to PSCo based on Xcel Energy Services Inc. employees’ labor costs.

~~Projected Benefit Payments~~

~~The following table lists PSCo’s projected benefit payments for the pension and postretirement benefit plans:~~

(Thousands of Dollars) Projected Pension
Benefit Payments Gross Projected
Postretirement
Health Care
Benefit Payments Expected Medicare
Part D Subsidies Net Projected
Postretirement
Health Care
Benefit Payments
2018 $ 83,036
$ 32,186
$ 2,074
$ 30,112
2019 81,698
32,454
2,192
30,262
2020 81,413
32,767
2,296
30,471
2021 82,021
32,737
2,404
30,333
2022 83,261
32,998
2,501
30,497
2023-2027 411,798
152,926
13,789
139,137



(Millions of Dollars)	2018			2017
Deferred tax liabilities:
Differences between book and tax bases of property	$	1,860.1		$	1,790.1
Regulatory assets	251.1			252.4
Pension expense	33.9			60.0
Other	13.1			3.7
Total deferred tax liabilities	$	2,158.2		$	2,106.2

Deferred tax assets:
Regulatory liabilities	$	336.3		$	338.0
NOL carryforward	18.2			39.3
Tax credit carryforward	51.9			39.3
Tax credit valuation allowances	(8.9		)	—
Deferred ITCs	6.3			6.9
Other employee benefits	2.8			6.8
Rate refund	9.3			0.9
Other	23.0			30.5
Total deferred tax assets	$	438.9		$	461.7
Net deferred tax liability	$	1,719.3		$	1,644.5


9.	~~Other Income, Net~~

~~Other income, net for the years ended Dec. 31 consisted of the following:~~

(Thousands of Dollars) 2017 2016 2015
Interest income $ 3,809
$ 1,860
$ 753
Other nonoperating income 6,383
2,241
2,408
Insurance policy expense (340 ) (281 ) (197 )
Other nonoperating expense —
(3 ) —
Other income, net $ 9,852
$ 3,817
$ 2,964


~~10.~~	Fair Value of Financial Assets and Liabilities

Fair Value Measurements

The accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires ~~certain~~ disclosures about assets and liabilities measured at fair value. A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance. ~~The three levels in the hierarchy are as follows:~~

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

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

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

Specific valuation methods ~~include the following:~~

include:

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

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

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

Derivative Instruments Fair Value Measurements

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

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

AtAs of Dec. 31, ~~2017,~~2018, accumulated other comprehensive losses related to interest rate derivatives included $1.2 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for unsettled hedges, as applicable.

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

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

PSCo enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but may not be designated as qualifying hedging transactions. Changes in the fair value of non-trading commodity derivative instruments are recorded in ~~OCI~~other comprehensive income or deferred as a regulatory asset or liability. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. ~~PSCo recorded no~~No amounts ~~to income~~ related to the ineffectiveness of cash flow hedges were recorded for the ~~year~~years ended Dec. 31, ~~2017~~2018 and ~~immaterial amounts for the year ended~~2017.

As of Dec. 31, ~~2016.~~2018, there were no net gains related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses or related amounts expected to be reclassified into earnings during the next 12 months.

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

~~The following table details the gross~~

Gross notional amounts of commodity forwards and options at Dec. 31:


(Amounts in Thousands) ^(a)(b)	2017	2016
(Amounts in Millions) ^(a)(b)			2018	2017
MWh of electricity	22,260	6,283	24.4	22.3
MMBtu of natural gas	13,410	42,203	48.4	13.4


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


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

Consideration of Credit Risk and Concentrations — PSCo continuously monitors the creditworthiness of the counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement, and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. ~~Given this assessment, as well as an assessment of the impact of PSCo’s own credit risk when determining the fair value of derivative liabilities, the~~The impact of credit risk was immaterial to the fair value of unsettled commodity derivatives presented in the consolidated balance sheets.

PSCo employs additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures. Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided.

PSCo’s most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to its wholesale, trading and non-trading commodity activities. At Dec. 31, ~~2017, five~~2018, seven of PSCo’s 10 most significant counterparties for these activities, comprising ~~$7.0~~$63.8 million or ~~16 percent~~63% of this credit exposure, had investment grade credit ratings from ~~S&P’s,~~Standard & Poor’s, Moody’s or Fitch Ratings. ~~Four~~Three of the 10 most significant counterparties, comprising ~~$16.5~~$14.4 million or ~~37 percent~~14% of this credit exposure, ~~at Dec. 31, 2017~~ were not rated by these external agencies, but based on PSCo’s internal analysis, had credit quality consistent with investment grade. ~~Another of these significant counterparties, comprising $7.4 million or 17 percent of this credit exposure, had credit quality less than investment grade, based on ratings from external analysis. Six~~Eight of these significant counterparties are municipal or cooperative electric entities, or other utilities.

~~Financial Impact of~~ Qualifying Cash Flow Hedges — ~~The~~Financial impact of qualifying interest rate and vehicle fuel cash flow hedges on PSCo’s accumulated other comprehensive loss, included in the consolidated statements of common stockholder’s equity and in the consolidated statements of comprehensive ~~income, is detailed in the following table:~~income:


(Thousands of Dollars)	2017			2016			2015
(Millions of Dollars)										2018			2017			2016
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$	(22,780	)	$	(23,836	)	$	(23,878	)	$	(26.5	)	$	(22.8	)	$	(23.8	)
After-tax net unrealized losses related to derivatives accounted for as hedges	—			—			(30		)
After-tax net realized losses on derivative transactions reclassified into earnings	1,005			1,056			72			1.2			1.0			1.0
Adoption of ASU. 2018-02 ^(a)										—			(4.7		)	—
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31	$	(21,775	)	$	(22,780	)	$	(23,836	)	$	(25.3	)	$	(26.5	)	$	(22.8	)


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

~~The following tables detail the impact~~Impact of derivative ~~activity during the years ended Dec. 31, 2017, 2016 and 2015, on accumulated other comprehensive loss, regulatory assets and liabilities, and income:~~activity:



	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:
(Millions of Dollars)	Accumulated Other Comprehensive Loss		Regulatory(Assets) and Liabilities
Year Ended Dec. 31, 2018
Other derivative instruments
Natural gas commodity	$	—	$	8.0
Total	$	—	$	8.0

Year Ended Dec. 31, 2017
Other derivative instruments
Natural gas commodity	$	—	$	(10.9	)
Total	$	—	$	(10.9	)

Year Ended Dec. 31, 2016
Other derivative instruments
Natural gas commodity	—		2.1
Total	$	—	$	2.1

Year Ended Dec. 31, 2017
Pre-Tax Fair Value
Losses Recognized
During the Period in: Pre-Tax Losses
Reclassified into Income
During the Period from:
(Thousands of Dollars)
Accumulated
Other
Comprehensive
Loss

Regulatory
(Assets) and
Liabilities

Accumulated
Other
Comprehensive
Loss

Regulatory
Assets and
(Liabilities)
Pre-Tax Gains (Losses) Recognized
During the Period
in Income
Derivatives designated as cash flow hedges
Interest rate $ —
$ —
$ 1,615
^(a)
$ —
$ —

Total $ —
$ —
$ 1,615
$ —
$ —

Other derivative instruments
Commodity trading $ —
$ —
$ —
$ —
$ 386
^(c)
Natural gas commodity —
(10,921 ) —
1,933
^(d)
(4,170 )
^(d)
Total $ —
$ (10,921 ) $ —
$ 1,933
$ (3,784 )



	Pre-Tax (Gains) Losses Reclassified into Income During the Period from:
(Millions of Dollars)	Accumulated Other Comprehensive Loss			Regulatory Assets and (Liabilities)				Pre-Tax Gains (Losses) Recognized During the Period in Income
Year Ended Dec. 31, 2018
Derivatives designated as cash flow hedges
Interest rate	$	1.6	^(a)	$	—			$	—
Total	$	1.6		$	—			$	—
Other derivative instruments
Commodity trading	$	—		$	—			$	3.1		^(c)
Natural gas commodity	—			(4.1		)	^(d)	(2.9		)	^(d)
Total	$	—		$	(4.1	)		$	0.2

Year Ended Dec. 31, 2017
Derivatives designated as cash flow hedges
Interest rate	$	1.6	^(a)	$	—			$	—
Total	$	1.6		$	—			$	—
Other derivative instruments
Commodity trading	$	—		$	—			$	0.4		^(c)
Natural gas commodity	—			1.9			^(d)	(4.2		)	^(d)
Total	$	—		$	1.9			$	(3.8	)

Year Ended Dec. 31, 2016
Derivatives designated as cash flow hedges
Interest rate	$	1.6	^(a)	$	—			$	—
Vehicle fuel and other commodity	0.1		^(b)	—				—
Total	$	1.7		$	—			$	—
Other derivative instruments
Commodity trading	$	—		$	—			$	(0.3	)	^(c)
Natural gas commodity	—			10.3			^(d)	(5.8		)	^(d)
Total	$	—		$	10.3			$	(6.1	)

Year Ended Dec. 31, 2016
Pre-Tax Fair Value
Gains Recognized
During the Period in: Pre-Tax Losses
Reclassified into Income
During the Period from:
(Thousands of Dollars)
Accumulated
Other
Comprehensive
Loss

Regulatory
(Assets) and
Liabilities

Accumulated
Other
Comprehensive
Loss

Regulatory
Assets and
(Liabilities)

Pre-Tax Losses
Recognized
During the Period
in Income

Derivatives designated as cash flow hedges
Interest rate $ —
$ —
$ 1,618
^(a)
$ —
$ —

Vehicle fuel and other commodity —
—
86
^(b)
—
—

Total $ —
$ —
$ 1,704
$ —
$ —

Other derivative instruments
Commodity trading $ —
$ —
$ —
$ —
$ (257 )
^(c)
Natural gas commodity —
2,051
—
10,292
^(d)
(5,832 )
^(d)
Total $ —
$ 2,051
$ —
$ 10,292
$ (6,089 )

Year Ended Dec. 31, 2015
Pre-Tax Fair Value
Losses Recognized
During the Period in: Pre-Tax Losses
Reclassified into Income
During the Period from:
(Thousands of Dollars)
Accumulated
Other
Comprehensive
Loss

Regulatory
(Assets) and
Liabilities

Accumulated
Other
Comprehensive
Loss

Regulatory
Assets and
(Liabilities)
Pre-Tax Gains (Losses) Recognized
During the Period
in Income
Derivatives designated as cash flow hedges
Interest rate $ —
$ —
$ 54
^(a)
$ —
$ —

Vehicle fuel and other commodity (50 ) —
57
^(b)
—
—

Total $ (50 ) $ —
$ 111
$ —
$ —

Other derivative instruments
Commodity trading $ —
$ —
$ —
$ —
$ 364
^(c)
Natural gas commodity —
(10,635 ) —
10,158
^(d)
(7,620 )
^(d)
Total $ —
$ (10,635 ) $ —
$ 10,158
$ (7,256 )


^(a)	Amounts are recorded to interest charges.


^(b)	Amounts are recorded to O&M expenses.


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

^(d)

Certain derivatives are utilized to mitigate natural gas price risk for electric generation and are recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset as appropriate. Amounts for the year ended Dec. 31, 2018, 2017 and 2016 included $1.2 million of settlement losses, $0.4 million of settlement gains and ~~amounts for the years ended Dec. 31, 2016 and 2015 included~~ $0.2 million ~~and $1.1 million, respectively,~~ of settlement losses, respectively, on derivatives entered to mitigate natural gas price risk for electric generation recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset or liability, as appropriate. ~~The remaining~~Remaining settlement losses for the years ended Dec. 31, 2018, 2017 ~~2016~~ and ~~2015~~2016 relate to natural gas operations and are recorded to cost of natural gas sold and transported. These losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset or liability, as appropriate.

PSCo had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2018, 2017 ~~2016~~ and ~~2015. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.~~2016.

Credit Related Contingent Features —Contract provisions for derivative instruments that PSCo enters into, including those accounted for as normal purchase-normal sale contracts and therefore not reflected on the consolidated balance sheets, may require the posting of collateral or settlement of the contracts for various reasons, including if PSCo’s credit ratings are downgraded below its investment grade credit rating by any of the major credit rating agencies, or for cross-default contractual provisions ~~that could result in the settlement of such contracts~~ if there was a failure under other financing arrangements related to payment terms or other covenants.

At Dec. 31, ~~2017~~2018 and ~~2016,~~2017, there were no derivative instruments in a ~~material~~ liability position with such underlying contract provisions.

Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that PSCo’s ability to fulfill its contractual obligations is reasonably expected to be impaired. PSCo had no collateral posted related to adequate assurance clauses in derivative contracts as of Dec. 31, ~~2017~~2018 and ~~2016.~~2017.

Recurring Fair Value Measurements —The following table presents, for each of the fair value hierarchy levels, PSCo’s derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2018 and 2017:


	Dec. 31, 2017													Dec. 31, 2018													Dec. 31, 2017
	Fair Value													Fair Value													Fair Value
(Thousands of Dollars)	Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting ^(b)			Total
(Millions of Dollars)														Level 1		Level 2		Level 3		Fair Value Total		Netting ^(a)			Total		Level 1		Level 2		Level 3		Fair Value Total		Netting ^(a)			Total
Current derivative assets
Other derivative instruments:
Commodity trading	$	528	$	4,488	$	12	$	5,028	$	(3,554	)	$	1,474	$	2.3	$	65.0	$	0.1	$	67.4	$	(28.2	)	$	39.2	$	0.5	$	4.5	$	—	$	5.0	$	(3.5	)	$	1.5
Natural gas commodity	—		18		—		18		(10		)	8		—		3.4		—		3.4		—			3.4		—		—		—		—		—			—
Total current derivative assets	$	528	$	4,506	$	12	$	5,046	$	(3,564	)	1,482		$	2.3	$	68.4	$	0.1	$	70.8	$	(28.2	)	42.6		$	0.5	$	4.5	$	—	$	5.0	$	(3.5	)	1.5
PPAs ^(a)												1,715
PPAs ^(b)																									—													1.7
Current derivative instruments												$	3,197												$	42.6												$	3.2
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	$	—	$	1,541	$	—	$	1,541	$	(563	)	$	978	$	—	$	1.6	$	—	$	1.6	$	(0.4	)	$	1.2	$	—	$	1.5	$	—	$	1.5	$	(0.5	)	$	1.0
Total noncurrent derivative assets	$	—	$	1,541	$	—	$	1,541	$	(563	)	978		$	—	$	1.6	$	—	$	1.6	$	(0.4	)	1.2		$	—	$	1.5	$	—	$	1.5	$	(0.5	)	1.0
PPAs ^(a)												31
PPAs ^(b)																									—													—
Noncurrent derivative instruments												$	1,009												$	1.2												$	1.0
Current derivative liabilities
Other derivative instruments:
Commodity trading	$	446	$	4,285	$	6	$	4,737	$	(3,431	)	$	1,306	$	2.4	$	64.2	$	—	$	66.6	$	(34.7	)	$	31.9	$	0.4	$	4.3	$	—	$	4.7	$	(3.4	)	$	1.3
Natural gas commodity	—		1,016		—		1,016		(10		)	1,006		—		—		—		—		—			—		—		1.0		—		1.0		—			1.0
Total current derivative liabilities	$	446	$	5,301	$	6	$	5,753	$	(3,441	)	2,312		$	2.4	$	64.2	$	—	$	66.6	$	(34.7	)	31.9		$	0.4	$	5.3	$	—	$	5.7	$	(3.4	)	2.3
PPAs ^(a)												5,036
PPAs ^(b)																									2.7													5.0
Current derivative instruments												$	7,348												$	34.6												$	7.3
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	—	$	1,362	$	—	$	1,362	$	(563	)	$	799	$	—	$	1.1	$	—	$	1.1	$	(0.5	)	$	0.6	$	—	$	1.4	$	—	$	1.4	$	(0.6	)	$	0.8
Total noncurrent derivative liabilities	$	—	$	1,362	$	—	$	1,362	$	(563	)	799		$	—	$	1.1	$	—	$	1.1	$	(0.5	)	0.6		$	—	$	1.4	$	—	$	1.4	$	(0.6	)	0.8
PPAs ^(a)												$	2,669
PPAs ^(b)																									—													2.7
Noncurrent derivative instruments												$	3,468												$	0.6												$	3.5

^(a)

PSCo nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2018 and 2017. At both Dec. 31, 2018 and 2017, derivative assets and liabilities include no obligations to return cash collateral. At Dec. 31, 2018 and 2017, derivative assets and liabilities include the rights to reclaim cash collateral of $6.5 million and $0 million, respectively. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.


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

^(b)

PSCo nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2017. At Dec. 31, 2017, derivative assets and liabilities include no obligations to return or reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

~~The following table presents, for each of the fair value hierarchy levels, PSCo’s derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2016:~~

Dec. 31, 2016
Fair Value
(Thousands of Dollars) Level 1 Level 2 Level 3
Fair Value
Total

Counterparty
Netting ^(b)
Total
Current derivative assets
Other derivative instruments:
Commodity trading $ 1,124
$ 5,453
$ —
$ 6,577
$ (5,137 ) $ 1,440
Natural gas commodity —
7,778
—
7,778
—
7,778
Total current derivative assets $ 1,124
$ 13,231
$ —
$ 14,355
$ (5,137 ) 9,218
PPAs ^(a)
1,716
Current derivative instruments $ 10,934
Noncurrent derivative assets ��
Other derivative instruments:
Commodity trading $ —
$ 1,652
$ —
$ 1,652
$ —
$ 1,652
Total noncurrent derivative assets $ —
$ 1,652
$ —
$ 1,652
$ —
1,652
PPAs ^(a)
1,746
Noncurrent derivative instruments $ 3,398
Current derivative liabilities
Other derivative instruments:
Commodity trading $ 1,386
$ 5,357
$ 22
$ 6,765
$ (5,137 ) $ 1,628
Total current derivative liabilities $ 1,386
$ 5,357
$ 22
$ 6,765
$ (5,137 ) 1,628
PPAs ^(a)
5,160
Current derivative instruments $ 6,788
Noncurrent derivative liabilities
PPAs ^(a)
$ 7,828
Noncurrent derivative instruments $ 7,828


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

^(b)

PSCo nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2016. At Dec. 31, 2016, derivative assets and liabilities include no obligations to return cash collateral of or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

There were $0.1 million of gains, immaterial gains ~~recognized in earnings for the year ended Dec. 31, 2017~~ and immaterial losses recognized in earnings for the ~~year~~years ended Dec. 31, 2018, 2017 and 2016, respectively, for ~~level~~Level 3 commodity trading derivatives. ~~There were no changes in Level 3 recurring fair value measurements for the year ended Dec. 31, 2015.~~

PSCo recognizes transfers between levels as of the beginning of each period. There were no transfers of amounts between levels for derivative instruments for the years ended Dec. 31, 2018, 2017 ~~2016~~ and ~~2015.~~2016.

Fair Value of Long-Term Debt

As of Dec. 31, ~~2017 and 2016,~~ other financial instruments for which the carrying amount did not equal fair ~~value were as follows:~~value:


	2017				2016				2018				2017
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
(Millions of Dollars)									Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	4,608,275	$	5,024,840	$	4,216,206	$	4,491,570	$	4,997.6	$	5,123.2	$	4,608.3	$	5,024.8

~~The fair~~Fair value of PSCo’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. ~~The fair~~Fair value estimates are based on information available to management as of Dec. 31, ~~2017~~2018 and ~~2016,~~2017, and given the observability of the inputs, ~~to these estimates, the~~ fair values presented for long-term debt ~~have been~~were assigned aas Level 2.


~~11.~~10.	~~Rate Matters~~Benefit Plans and Other Postretirement Benefits

Pension and Postretirement Health Care Benefits

~~Tax Reform~~ — ~~Regulatory Proceedings~~Xcel Energy, which includes PSCo, has several noncontributory, defined benefit pension plans that cover almost all employees. Generally, benefits are based on a combination of years of service, the employee’s average pay and, in some cases, social security benefits. Xcel Energy Inc.’s and PSCo’s policy is to fully fund into an external trust the actuarially determined pension costs recognized for ratemaking and financial reporting purposes, subject to the limitations of applicable employee benefit and tax laws.

In addition to the qualified pension plans, Xcel Energy maintains a SERP and a nonqualified pension plan. The ~~specific impacts~~SERP is maintained for certain executives that were participants in the plan in 2008, when the SERP was closed to new participants. The nonqualified pension plan provides benefits for compensation that is in excess of the ~~TCJA on retail customer rates are subject~~limits applicable to ~~regulatory approval.~~the qualified pension plans, with distributions attributable to PSCo ~~is in the process of quantifying the rate impacts~~funded by PSCo’s consolidated operating cash flows. The total obligations of the ~~TCJA~~SERP and ~~are being addressed in several regulatory proceedings focused on retail base rate impacts, which include the following:~~

~~Colorado Statewide TCJA Proceeding— On Jan.~~nonqualified plan as of Dec. 31, 2018 and 2017 were $33 million and $37 million, respectively, of which $3 million and $3 million were attributable to PSCo. Xcel Energy recognized net benefit cost for financial reporting for the ~~CPUC opened a statewide TCJA proceeding~~SERP and ~~ordered deferred accounting~~nonqualified plans of $4 million in 2018 and $5 million in 2017, of which $1 million in each year was attributable to PSCo.

In 2016, Xcel Energy established rabbi trusts to provide partial funding for all investor-owned utilities. On Feb. 21, 2017, PSCo filed a response with the CPUC related to the deferred accounting order and statewide TCJA proceeding, addressing the estimated impacts along with other considerations given PSCo’s pending natural gas and electric rate cases.

~~Colorado 2017 Multi-Year Natural Gas Rate Case— On Feb. 14, 2018, the ALJ approved PSCo and CPUC Staff’s non-unanimous settlement agreement which addresses the impacts~~future distributions of the ~~TCJA in 2018. This settlement agreement includes~~SERP and its deferred compensation plan. Rabbi trust funding of deferred compensation plan distributions attributable to PSCo will be supplemented by PSCo’s consolidated operating cash flows.

Xcel Energy has a ~~$20 million reduction~~contributory health and welfare benefit plan that provides health care and death benefits to ~~provisional rates effective March 1, 2018, with future true-ups to be determined later in 2018 once a full analysis~~certain Xcel Energy retirees.

Xcel Energy discontinued subsidizing health care benefits for nonbargaining employees of the comprehensive impacts of tax reform is performed, including any outcomes associated with statewide proceeding. The final true-up would provide customers the full net benefit of the TCJA effective Jan. 1, 2018.

~~Colorado 2017 Multi-Year Electric Rate Case— On Feb. 16, 2018, the CPUC denied the proposed settlement agreement between~~former NCE, which includes PSCo and several intervenors, in favor of the state TCJA proceeding. In the second quarter of 2018, PSCo plans to file a revised rate request that will include the impacts of the TCJA. Provisional rates, subject to refund with interest, are expected to be effectiveemployees, who retired after June 1, 2018. The appropriate test year and the final approved revenue requirement will be determined in the pending rate case, discussed below. PSCo expects to defer the TCJA net benefits for the first five months of 2018, prior to provisional rates.30, 2003.

~~The CPUC is expected to rule on the regulatory treatment of the TCJA, the natural gas rate case and the electric rate case later in 2018.~~

~~Pending Regulatory Proceedings — CPUC~~

Xcel Energy Inc. and PSCo base the investment-return assumption on expected long-term performance for each of the asset classes in their pension and postretirement health care portfolios. For pension assets, Xcel Energy Inc. and PSCo consider the historical returns achieved by the asset portfolio over the past 20-years or longer period, as well as the long-term return levels projected and recommended by investment experts. Xcel Energy Inc. and PSCo continually review pension assumptions.

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

~~Colorado~~Investment returns in 2018 were below the assumed level of 6.84%;

Investment returns in 2017 ~~Multi-Year Electric Rate Case~~ — were above the assumed level of 6.84%;

Investment returns in 2016 were below the assumed level of 6.84%; and

In ~~October 2017,~~2019, PSCo’s expected investment-return assumption is 6.84%.

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

State agencies also have issued guidelines to the funding of postretirement benefit costs. PSCo ~~filed~~is required to fund postretirement benefit costs in irrevocable external trusts that are dedicated to the payment of these postretirement benefits. These assets are invested in a ~~multi-year request~~manner consistent with the ~~CPUC seeking to increase electric rates approximately $245 million over four years.~~ investment strategy for the pension plan.

The ~~request, summarized below,~~ongoing investment strategy is based on ~~FTY ending Dec. 31,~~plan-specific investment recommendations that seek to minimize potential investment and interest rate risk as a ~~10.0 percent ROE~~plan’s funded status increases over time. The investment recommendations result in a greater percentage of long-duration fixed income securities being allocated to specific plans having relatively higher funded status ratios and ~~an equity ratio~~a greater percentage of ~~55.25 percent.~~growth assets being allocated to plans having relatively lower funded status ratios.

Plan Assets

The following presents, for each of the fair value hierarchy levels, PSCo’s pension plan assets measured at fair value:

Revenue Request (Millions of Dollars) 2018 2019 2020 2021 Total
Revenue request $ 74
$ 75
$ 60
$ 36
$ 245
CACJA revenue conversion to base rates ^(a)
90
—
—
—
90
TCA revenue conversion to base rates ^(a)
43
—
—
—
43
Total ^(b)
$ 207
$ 75
$ 60
$ 36
$ 378

Expected year-end rate base (billions of dollars) ^(b)
$ 6.8
$ 7.1
$ 7.3
$ 7.4



	Dec. 31, 2018 ^(a)												Dec. 31, 2017 ^(a)
(Millions of Dollars)	Level 1		Level 2		Level 3		Measured at NAV			Total			Level 1			Level 2		Level 3		Measured at NAV		Total
Cash equivalents	$	53.0	$	—	$	—	$	—		$	53.0		$	67.2		$	—	$	—	$	—	$	67.2
Commingled funds	316.2		—		—		326.1			642.3			363.4			—		—		355.5		718.9
Debt securities	—		242.3		—		—			242.3			—			263.8		—		—		263.8
Equity securities	35.2		—		—		—			35.2			37.8			—		—		—		37.8
Other	0.6		2.0		—		(9.9		)	(7.3		)	(9.9		)	1.4		—		0.2		(8.3		)
Total	$	405.0	$	244.3	$	—	$	316.2		$	965.5		$	458.5		$	265.2	$	—	$	355.7	$	1,079.4


^(a)	~~The roll-in of the TCA~~See Note 9 for further information on fair value measurement inputs and CACJA rider revenues into base rates will not have an impact on customer bills or revenue as these costs are already being recovered through a rider. Transmission investments for 2019-2021 will be recovered through the TCA rider.


^(b)	~~This base rate request does not include the impacts of the RESA and ECA for the Rush Creek wind investments or the proposed CEP.~~methods.

~~Key dates in the procedural schedule are as follows:~~

~~Supplemental direct testimony — April 16, 2018;~~

~~Answer testimony — May 31, 2018;~~

~~Rebuttal and cross-answer testimony — July 10, 2018;~~

~~Hearings — Aug. 21 - 31, 2018; and~~

~~Statement of position — Sept. 28, 2018.~~

Interim rates, subject to refund and interest, are to be effective on June 1, 2018. PSCo also proposed a stay-out provision and earnings test through 2021. On Jan. 31, 2018, the CPUC ordered deferred accountingThe following presents, for ~~the impacts of TCJA and opened a statewide TCJA proceeding, as discussed above. In the second quarter of 2018, PSCo plans to file a revised rate request that will include the impacts~~each of the ~~TCJA. The CPUC is expected to rule on the regulatory treatment~~fair value hierarchy levels, PSCo’s proportionate allocation of the ~~TCJA and the electric rate case later in 2018.~~

~~Colorado 2017 Multi-Year Natural Gas Rate Case~~ — In June 2017, PSCo filed a multi-year request with the CPUC seeking to increase retail natural gas rates approximately $139 million over three years. The request, detailed below, is based on FTYs, a 10.0 percent ROE and an equity ratio of 55.25 percent.total postretirement benefit plan assets that were measured at fair value:

Revenue Request (Millions of Dollars) 2018 2019 2020 Total
Revenue request $ 63
$ 33
$ 43
$ 139
PSIA revenue conversion to base rates ^(a)
—
94
—
94
Total $ 63
$ 127
$ 43
$ 233

Expected year-end rate base (billions of dollars) ^(b)
$ 1.5
$ 2.3
$ 2.4


^(a)	The roll-in of PSIA rider revenue into base rates will not have an impact on customer bills or revenue as these costs are already being recovered through the rider. The recovery of incremental PSIA related investments in 2019 and 2020 are included in the base rate request.


^(b)	~~The additional rate base in 2019 predominantly reflects the roll-in of capital associated with the PSIA rider.~~

In October 2017, several parties filed answer testimony. The CPUC Staff (Staff) and the OCC, recommended a single 2016 HTY, based on an average 13-month rate base, and opposed a multi-year request. The Staff and OCC recommended an equity capital structure of 48.73 percent and 51.2 percent, respectively. Both the Staff and the OCC recommended the existing PSIA rider expire with the 2018 rates rolled into base rates beginning Jan. 1, 2019. Planned investments in 2019 and 2020 would be recoverable through base rates, subject to a future rate case. The final positions of the Staff and OCC provide for a recommended 2018 rate increase of approximately $30 million and $39 million, respectively.

In December 2017, hearings before an ALJ were held and the evidentiary record for the case was closed. Provisional rates, subject to refund, were implemented on Jan. 1, 2018. As discussed above, PSCo and the CPUC Staff filed a non-unanimous settlement agreement to address the impacts of the TCJA on rates to be effective in 2018, which was approved by the ALJ. On Jan. 31, 2018, the CPUC ordered deferred accounting for the impacts of TCJA and opened a statewide TCJA proceeding, as discussed above. The CPUC is expected to rule on the regulatory treatment of the TCJA and the natural gas rate case later in 2018.

~~Annual Electric Earnings Test~~ — PSCo must share with customers earnings that exceed the authorized ROE of 9.83 percent for 2015 through 2017, as part of an annual earnings test. PSCo estimates the 2017 earnings test will not result in a customer refund obligation. PSCo will file its 2017 earnings test with the CPUC in April 2018. The final sharing obligation, if any, will be based on the CPUC approved tariff and could vary from the current estimate.

~~Electric, Purchased Gas and Resource Adjustment Clauses~~

~~DSM and the DSMCA riders~~ — Energy efficiency and DSM costs are recovered through a combination of the DSMCA riders and base rates. DSMCA riders are adjusted biannually to capture program costs, performance incentives, and any over- or under-recoveries are trued-up in the following year. Performance incentives are awarded in the year following plan achievements. PSCo is able to earn $5 million upon reaching its annual savings goal along with an incentive on five percent of net economic benefits up to a maximum annual incentive of $30 million. In 2017, PSCo earned an electric and natural gas DSM incentive of $11 million and $3 million, respectively, for achieving its 2016 electric and natural gas savings goals. For 2018, the electric energy savings goal is 400 GWh with a spending limit of $84 million.


~~12.~~	~~Commitments and Contingencies~~

~~Commitments~~

~~Capital Commitments —~~ ~~PSCo has made commitments in connection with a portion of its projected capital expenditures. PSCo’s capital commitments primarily relate to the following major projects:~~

~~Advanced Grid Intelligence and Security Initiative~~ — PSCo is pursuing projects to update and advance its electric distribution grid to increase reliability and security standards, meet customer expectations, offer additional customer choice and control over energy usage and implement new rate structures.

~~Rush Creek Wind Farm~~ — ~~PSCo has gained approval to build, own and operate a 600 MW wind generation facility and proposed transmission line in Colorado.~~

~~Gas Transmission Integrity Management Programs~~ — PSCo is proactively identifying and addressing the safety and reliability of natural gas transmission pipelines. The pipeline integrity efforts include primarily pipeline assessment and maintenance projects.

~~Electric Distribution Integrity Management Programs~~ — ~~PSCo is assessing aging infrastructure for distribution assets and replacing worn components to increase system performance.~~

~~Fuel Contracts~~— PSCo has entered into various long-term commitments for the purchase and delivery of a significant portion of its current coal and natural gas requirements. These contracts expire in various years between 2018 and 2060. PSCo is required to pay additional amounts depending on actual quantities shipped under these agreements.

~~The estimated minimum purchases for PSCo under these contracts as of Dec. 31, 2017, are as follows:~~

(Millions of Dollars) Coal Natural gas supply Natural gas
storage and
transportation
2018 $ 160
$ 344
$ 114
2019 97
286
112
2020 69
275
111
2021 37
278
109
2022 38
126
109
Thereafter 184
57
605
Total $ 585
$ 1,366
$ 1,160

Additional expenditures for fuel and natural gas storage and transportation will be required to meet expected future electric generation and natural gas needs. PSCo’s risk of loss, in the form of increased costs from market price changes in fuel, is mitigated through the use of natural gas and energy cost-rate adjustment mechanisms, which provide for pass-through of most fuel, storage and transportation costs to customers.

~~PPAs~~— PSCo has entered into PPAs with other utilities and energy suppliers with expiration dates through 2034 for purchased power to meet system load and energy requirements and meet operating reserve obligations. In general, these agreements provide for energy payments, based on actual energy delivered and capacity payments. Certain PPAs accounted for as executory contracts also contain minimum energy purchase commitments. Capacity and energy payments are typically contingent on the independent power producing entity meeting contract obligations, including plant availability requirements. Contractual payments are adjusted based on market indices. The effects of price adjustments on our financial results are mitigated through purchased energy cost recovery mechanisms.

Included in electric fuel and purchased power expenses for PPAs, accounted for as executory contracts, were payments for capacity of $25 million, $44 million and $70 million in 2017, 2016 and 2015, respectively. At Dec. 31, 2017, the estimated future payments for capacity that PSCo is obligated to purchase pursuant to these executory contracts, subject to availability, are as follows:

(Millions of Dollars) Capacity
2018 $ 22
2019 12
2020 4
2021 4
2022 4
Thereafter 14
Total $ 60

~~Additional energy payments under these PPAs and PPAs accounted for as operating leases will be required to meet expected future electric demand.~~

~~Leases~~— PSCo leases a variety of equipment and facilities. Three of these leases are accounted for as capital leases. The assets and liabilities at the inception of a capital lease are recorded at the lower of fair market value or the present value of future lease payments and are amortized over the term of the contract.

WYCO is a joint venture between Xcel Energy Inc. and Colorado Interstate Gas Company, LLC (CIG) to develop and lease natural gas pipeline, storage, and compression facilities. Xcel Energy Inc. has a 50 percent ownership interest in WYCO, and PSCo has no direct ownership interest. WYCO generally leases its facilities to CIG, and CIG operates the facilities, providing natural gas storage services to PSCo under separate service agreements.

PSCo accounts for its Totem natural gas storage service arrangement with CIG as a capital lease. As a result, PSCo had $124 million and $127 million of capital lease obligations as of Dec. 31, 2017 and 2016, respectively.

PSCo records amortization for its capital leases as cost of natural gas sold and transported on the consolidated statements of income. Total amortization expenses under capital lease assets were approximately $5 million, $8 million, and $8 million for 2017, 2016 and 2015, respectively. Following is a summary of property held under capital leases:

(Millions of Dollars) Dec. 31, 2017 Dec. 31, 2016
Gas storage facilities $ 200.5
$ 200.5
Gas pipeline 20.7
20.7
Property held under capital leases 221.2
221.2
Accumulated depreciation (70.6 ) (65.3 )
Total property held under capital leases, net $ 150.6
$ 155.9

The remainder of the leases, primarily for office space, railcars, generating facilities, vehicles, aircraft and power-operated equipment, are accounted for as operating leases. Total expenses under operating lease obligations were approximately $109 million, $118 million and $130 million for 2017, 2016 and 2015, respectively. These expenses include capacity payments for PPAs accounted for as operating leases of $96 million, $102 million and $114 million in 2017, 2016 and 2015, respectively, recorded to electric fuel and purchased power expenses.

Included in the future commitments under operating leases are estimated future capacity payments under PPAs that have been accounted for as operating leases in accordance with the applicable accounting guidance. Future commitments under operating and capital leases are:

(Millions of Dollars)
Operating
Leases

PPA ^{(a) (b)}
Operating
Leases

Total
Operating
Leases

Capital
Leases
2018 $ 10
$ 96
$ 106
$ 25
2019 10
97
107
25
2020 10
98
108
25
2021 9
99
108
24
2022 8
87
95
21
Thereafter 34
394
428
442
Total minimum obligation 562
Interest component of obligation (411 )
Present value of minimum obligation $ 151



	Dec. 31, 2018 ^(a)										Dec. 31, 2017 ^(a)
(Millions of Dollars)	Level 1		Level 2		Level 3		Measured at NAV		Total		Level 1		Level 2		Level 3		Measured at NAV		Total
Cash equivalents	$	17.0	$	—	$	—	$	—	$	17.0	$	25.7	$	—	$	—	$	—	$	25.7
Insurance contracts	—		40.2		—		—		40.2		—		43.5		—		—		43.5
Commingled funds	118.7		—		—		35.8		154.5		130.2		—		—		—		130.2
Debt securities	—		159.7		—		—		159.7		—		175.4		—		—		175.4
Equity securities	—		—		—		—		—		30.7		—		—		—		30.7
Other	—		0.7		—		—		0.7		—		0.9		—		—		0.9
Total	$	135.7	$	200.6	$	—	$	35.8	$	372.1	$	186.6	$	219.8	$	—	$	—	$	406.4


^(a)	~~Amounts do not include PPAs accounted~~See Note 9 for ~~as executory contracts.~~


^(b)	~~PPA operating leases contractually expire through 2034.~~further information on fair value measurement inputs and methods.

No assets were transferred in or out of Level 3 for 2018 or 2017.

~~Variable Interest Entities~~Funded Status— ~~The accounting guidance~~ Comparisons of the actuarially computed benefit obligation, changes in plan assets and funded status of the pension and postretirement health care plans for ~~consolidation~~Xcel Energy are as follows:



	Pension Benefits						Postretirement Benefits
(Millions of Dollars)	2018			2017			2018			2017
Change in Benefit Obligation:
Obligation at Jan. 1	$	1,334.2		$	1,251.8		$	429.2		$	421.8
Service cost	29.0			27.3			0.7			0.7
Interest cost	47.3			50.6			15.0			16.8
Plan amendments	—			(1.1		)	—			—
Actuarial loss	(96.5		)	83.5			(40.6		)	18.3
Plan participants’ contributions	—			—			6.5			6.0
Medicare subsidy reimbursements	—			—			0.9			1.0
Benefit payments	(84.7		)	(77.9		)	(35.2		)	(35.4		)
Obligation at Dec. 31	$	1,229.3		$	1,334.2		$	376.5		$	429.2
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	1,079.4		$	1,004.2		$	406.4		$	393.5
Actual return on plan assets	(50.9		)	135.6			(11.1		)	37.0
Employer contributions	21.7			17.5			5.5			5.3
Plan participants’ contributions	—			—			6.5			6.0
Benefit payments	(84.7		)	(77.9		)	(35.2		)	(35.4		)
Fair value of plan assets at Dec. 31	$	965.5		$	1,079.4		$	372.1		$	406.4
Funded status of plans at Dec. 31	$	(263.8	)	$	(254.8	)	$	(4.4	)	$	(22.8	)
Amounts recognized in the Consolidated Balance Sheet at Dec. 31:
Noncurrent liabilities	(263.8		)	(254.8		)	(4.4		)	(22.8		)
Net amounts recognized	$	(263.8	)	$	(254.8	)	$	(4.4	)	$	(22.8	)
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	4.31		%	3.63		%	4.32		%	3.62		%
Expected average long-term increase in compensation level	3.75			3.75			N/A			N/A
Mortality table	RP-2014			RP-2014			RP-2014			RP-2014
Health care costs trend rate — initial: Pre-65	N/A			N/A			6.50		%	7.00		%
Health care costs trend rate — initial: Post-65	N/A			N/A			5.30		%	5.50		%
Ultimate trend assumption — initial: Pre-65	N/A			N/A			4.50		%	4.50		%
Ultimate trend assumption — initial: Post-65	N/A			N/A			4.50		%	4.50		%
Years until ultimate trend is reached	N/A			N/A			4			5

Accumulated benefit obligation for the pension plan was $1,183.3 million and $1,285.0 million as of ~~variable interest entities requires enterprises to consider the activities that most significantly impact an entity’s financial performance,~~Dec. 31, 2018 and ~~power to direct those activities, when determining whether an enterprise is a variable interest entity’s primary beneficiary.~~2017, respectively.

~~PPAs~~Net Periodic Benefit Cost (Credit) — ~~Under certain PPAs, PSCo purchases power from independent power producing entities for which PSCo~~Net periodic benefit cost (credit) other than the service cost component is ~~required to reimburse natural gas fuel costs, or to participate~~included in ~~tolling arrangements under which PSCo procures the natural gas required to produce the energy that it purchases. These specific PPAs create a variable interest~~other income in the ~~independent power producing entity.~~consolidated statement of income.

~~PSCo has determined that certain independent power producing entities are variable interest entities. PSCo is not subject to risk~~Components of ~~loss from the operations of these entities, and no significant financial support has been, or is required to be provided other than contractual payments for energy and capacity set forth in the PPAs.~~

PSCo has evaluated each of these variable interest entities for possible consolidation, including review of qualitative factors such as the length and terms of the contract, control over O&M, control over dispatch of electricity, historical and estimated future fuel and electricity prices, and financing activities. PSCo has concluded that these entities are not required to be consolidated in its consolidated financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance. PSCo had approximately 1,571 MW of capacity under long-term PPAs at both Dec. 31, 2017 and 2016 with entities that have been determined to be variable interest entities. These agreements have expiration dates through the year 2032.

~~Environmental Contingencies~~

PSCo has been or is currently involved with the cleanup of contamination from certain hazardous substances at several sites. In many situations, PSCo believes it will recover some portion of these costs through insurance claims. Additionally, where applicable, PSCo is pursuing, or intends to pursue, recovery from other PRPs and through the regulated rate process. New and changing federal and state environmental mandates can also create added financial liabilities for PSCo, which are normally recovered through the regulated rate process. To the extent any costs are not recovered through the options listed above, PSCo would be required to recognize an expense.

~~Site Remediation~~— Various federal and state environmental laws impose liability, without regard to the legality of the original conduct, where hazardous substances or other regulated materials have been released to the environment. PSCo may sometimes pay all or a portion of thenet periodic benefit cost to remediate sites where past activities of PSCo or other parties have caused environmental contamination. Environmental contingencies could arise from various situations, including sites of former MGPs operated by PSCo, its predecessors, or other entities; and third-party sites, such as landfills, for which PSCo is alleged to be a PRP that sent wastes to that site.

~~Other MGP, Landfill or Disposal Sites~~— PSCo is currently involved in investigating and/or remediating several MGP, landfill or other disposal sites. PSCo has identified three sites where contamination is present and where investigation and/or remediation activities are currently underway. Other parties may have responsibility for some portion of the investigation and/or remediation activities that are underway. PSCo anticipates that these investigation or remediation activities will continue through at least 2018. PSCo had accrued an immaterial amount and $2 million for all of these sites as of Dec. 31, 2017 and 2016, respectively. There may be insurance recovery and/or recovery from other PRPs that will offset any costs incurred. PSCo anticipates that any amounts spent will be fully recovered from customers.

~~Environmental Requirements~~

~~Water and Waste~~

~~Asbestos Removal —~~ Some of PSCo’s facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that contain it are demolished or removed. PSCo has recorded an estimate for final removal of the asbestos as an ARO. It may be necessary to remove some asbestos to perform maintenance or make improvements to other equipment. The cost of removing asbestos as part of other work is not expected to be material and is recorded as incurred as operating expenses for maintenance projects, capital expenditures for construction projects or removal costs for demolition projects.

~~Coal Ash Regulation~~— PSCo’s operations are subject to federal and state laws that impose requirements for handling, storage, treatment and disposal of solid waste. In 2015, the EPA published a final rule regulating the management, storage, and disposal of coal combustion residuals (CCRs) as a nonhazardous waste (CCR Rule). Industry and environmental non-governmental organizations sought judicial review of the final CCR Rule, but a final decision has not been issued in that litigation. The EPA announced in late 2017 its intent to revise the CCR Rule. It is anticipated that the EPA will publish the revised rule in the first quarter of 2018.

Under the CCR Rule, utilities were required to complete groundwater sampling around their CCR landfills and surface impoundments and to analyze the results by early 2018 to determine if there were any statistically significant increases (SSIs) above background levels of certain constituents in the groundwater. PSCo has identified SSIs at several sites. Going forward, PSCo will either conduct additional groundwater sampling to determine whether another source besides plant operations is impacting groundwater and/or to determine if corrective action is needed. Several PSCo sites where SSIs were identified were already undergoing cessation of coal operations and closure of the on-site coal units and therefore no further corrective action is expected at those sites.

Until a final decision is reached in the litigation, the EPA publishes its revised rule, and PSCo completes additional groundwater sampling, it is uncertain what impact, if any, there will be on the operations, financial position or cash flows of PSCo. PSCo believes that any associated costs would be recoverable through regulatory mechanisms.

~~Federal CWA Waters of the United States Rule~~ —~~In 2015, the EPA~~(credit) and the ~~U.S. Army Corps of Engineers (Corps) published a final rule that significantly expanded the types of water bodies regulated under the CWA~~amounts recognized in other comprehensive income and ~~broadened the scope of waters subject to federal jurisdiction. In October 2015, the U.S. Court of Appeals for the Sixth Circuit issued a nationwide stay of the final rule~~regulatory assets and subsequently ruled that it, rather than the federal district courts, had jurisdiction over challenges to the rule. In January 2017, the U.S. Supreme Court agreed to resolve the dispute as to which court should hear challenges to the rule. A ruling is expected in 2018.liabilities:

In February 2017, President Trump issued an executive order requiring the EPA and the Corps to review and revise the final rule. On June 27, 2017, the agencies issued a proposed rule that rescinds the final rule and reinstates the prior definition of “Water of the U.S.” The agencies are also undertaking a rulemaking to develop a new definition of “Waters of the U.S.”

~~Federal CWA Effluent Limitations Guidelines (ELG)~~ — In 2015, the EPA issued a final ELG rule for power plants that use coal, natural gas, oil or nuclear materials as fuel and discharge treated effluent to surface waters as well as utility-owned landfills that receive coal combustion residuals. In 2017, the EPA delayed the compliance date for flue gas desulfurization wastewater and bottom ash transport until November 2020 while the agency conducts a rulemaking process to potentially revise the effluent limitations and pretreatment standards for these waste streams.

~~Federal CWA Section 316(b)~~ — The federal CWA requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available for minimizing adverse environmental impacts to aquatic species. The EPA published the final 316(b) rule in 2014. The rule prescribes technology for protecting fish that get stuck on plant intake screens (known as impingement) and describes a process for site-specific determinations by each state for sites that must protect the small aquatic organisms that pass through the intake screens into the plant cooling systems (known as entrainment). PSCo does not anticipate the cost of compliance will have a material impact on its results of operations, financial position or cash flows.

~~Air~~

~~GHG Emission Standard for Existing Sources (CPP)~~ — In 2015, the EPA issued its final CPP rule for existing power plants. Among other things, the CPP requires that state plans include enforceable measures to ensure emissions from existing power plants achieve the EPA’s state-specific interim and final emission performance targets.

The CPP was challenged by multiple parties in the D.C. Circuit Court. In February 2016, the U.S. Supreme Court issued an order staying the final CPP rule. The stay will remain in effect until the D.C. Circuit Court reaches its decision and the U.S. Supreme Court either declines to review the lower court’s decision or reaches a decision of its own.

In March 2017, President Trump signed an executive order requiring the EPA Administrator to review the CPP rule and if appropriate publish proposed rules suspending, revising or rescinding it. Accordingly, the EPA requested that the D.C. Circuit Court hold the litigation in abeyance until the EPA completes its work under the executive order. The D.C. Circuit granted the EPA’s request and is holding the litigation in abeyance, while considering briefs by the parties on whether the court should remand the challenges to the EPA rather than holding them in abeyance, determining whether and how the court continues or ends the stay that currently applies to the CPP.

In October 2017, the EPA published a proposed rule to repeal the CPP, based on an analysis that the CPP exceeds the EPA’s statutory authority under the CAA. In the proposal, the EPA stated it has not yet determined whether it will promulgate a new rule to regulate GHG emissions from existing EGUs. In December 2017, the EPA issued an Advanced Notice of Proposed Rulemaking to take and consider comments on whether to issue a future rule and what such a rule should include.

~~Implementation of the NAAQS for SO~~₂ ~~— The EPA adopted a more stringent NAAQS for SO~~₂ in 2010, and evaluated areas in in three phases. In December 2017, the EPA adopted a final rule that completed its initial designations of areas attaining or not attaining the standard. The EPA’s final actions designate all areas near PSCo’s generating plants as meeting the SO₂ NAAQS with one exception. In June 2016, the EPA issued final designations which found the area near the Pawnee plant is “unclassifiable.” Since the 2016 “unclassifiable” designation, the Colorado Department of Public Health and Environment has prepared and submitted air dispersion modeling to the EPA demonstrating that the area near the Pawnee plant meets the SO₂ ~~NAAQS. The EPA has not yet completed its evaluation of the Pawnee plant.~~

~~Revisions to the NAAQS for Ozone~~— In 2015, the EPA revised the NAAQS for ozone by lowering the eight-hour standard from 75 parts per billion (ppb) to 70 ppb. In November 2017, the EPA published final designations of areas that meet the 2015 ozone standard. Xcel Energy meets the 2015 ozone standard in all areas where its generating units operate, except for the Denver Metropolitan Area. PSCo’s scheduled retirement of coal fired plants in Denver that began in 2011 and was completed in August 2017, should help in any plan to mitigate non-attainment. The EPA has not yet taken final action on the designation, but notified the State of Colorado in December 2017 that it intends to designate the parts of the Denver Metropolitan Area that currently do not attain the 2008 ozone standards as also not attaining the more stringent 2015 ozone standard.

~~Asset Retirement Obligations~~

~~Recorded AROs —~~ AROs have been recorded for property related to the following: electric production (steam, wind, other and hydro), electric distribution and transmission, natural gas production, natural gas transmission and distribution, natural gas storage, thermal and common general property. The electric production obligations include asbestos, processed water and ash-containment facilities, radiation sources, storage tanks and control panels. The asbestos recognition associated with electric production includes certain specific plants. The AROs recorded for PSCo steam and other production relate to processed water and ash-containment facilities such as ash ponds, evaporation ponds and solid waste landfills. PSCo has also recorded AROs for the retirement and removal of assets at certain wind production facilities for which the land is leased and removal is required by contract.

PSCo recognized AROs for the retirement costs of natural gas mains and lines and for the retirement of above ground gas gathering equipment, impoundments at gas extraction sites and wells related to gas storage facilities. In addition, an ARO was recognized for the removal of electric transmission and distribution equipment, which consists of obligations associated with polychlorinated biphenyl, mineral oil, lithium batteries, mercury and street lighting lamps. The common general ARO includes obligations related to storage tanks.

~~A reconciliation of PSCo’s AROs for the years ended Dec. 31, 2017 and 2016 is as follows:~~

(Thousands of Dollars)
Beginning Balance
Jan. 1, 2017

Liabilities
Settled ^(a)
Accretion
Cash Flow
Revisions ^(b)

Ending Balance
Dec. 31, 2017 ^(c)
Electric plant
Steam and other production ash containment $ 72,600
$ (12,068 ) $ 3,159
$ 9,573
$ 73,264
Steam, hydro, and other production asbestos 40,450
(12,047 ) 1,917
(458 ) 29,862
Electric distribution 7,669
—
274
—
7,943
Wind production 2,072
—
20
—
2,092
Other 1,520
(204 ) 66
—
1,382
Natural gas plant
Gas transmission and distribution 160,719
—
6,649
61,503
228,871
Other 4,080
(354 ) 159
—
3,885
Common and other property
Common miscellaneous 453
—
17
—
470
Total liability $ 289,563
$ (24,673 ) $ 12,261
$ 70,618
$ 347,769



	Pension Benefits									Postretirement Benefits
(Millions of Dollars)	2018			2017			2016			2018			2017			2016
Service cost	$	29.0		$	27.3		$	25.9		$	0.7		$	0.7		$	0.8
Interest cost	47.3			50.6			55.4			15.0			16.8			18.1
Expected return on plan assets	(68.5		)	(68.5		)	(70.8		)	(22.7		)	(21.9		)	(22.3		)
Amortization of prior service credit	(3.4		)	(3.2		)	(3.2		)	(6.2		)	(6.2		)	(6.3		)
Amortization of net loss	31.2			28.3			26.8			4.0			3.8			1.9
Settlement charge ^(a)	4.5			—			—			—			—			—
Net periodic pension cost (credit)	40.1			34.5			34.1			(9.2		)	(6.8		)	(7.8		)
Costs (credits) not recognized due to effects of regulation	(3.9		)	(2.7		)	3.4			1.8			—			—
Net benefit cost (credit) recognized for financial reporting	$	36.2		$	31.8		$	37.5		$	(7.4	)	$	(6.8	)	$	(7.8	)
Significant Assumptions Used to Measure Costs:
Discount rate	3.63		%	4.13		%	4.66		%	3.62		%	4.13		%	4.65		%
Expected average long-term increase in compensation level	3.75			3.75			4.00			N/A			N/A			N/A
Expected average long-term rate of return on assets	6.84			6.84			6.84			5.80			5.80			5.80

^(a)

~~The liabilities settled relate~~A settlement charge is required when the amount of all lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In 2018, as a result of lump-sum distributions during the 2018 plan years, PSCo recorded a total pension settlement charge of $4.5 million in 2018, the majority of which was not recognized due to ~~asbestos abatement projects,~~ the ~~closure~~effects of ~~certain ash containment facilities, and removal and proper disposal of storage tanks and other above ground equipment.~~regulation.

Pension costs include an expected return impact for the current year that may differ from actual investment performance in the plan. Return assumption used for 2019 pension cost calculations is 6.84%.



	Pension Benefits						Postretirement Benefits
(Millions of Dollars)	2018			2017			2018			2017
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	530.8		$	543.7		$	66.9		$	77.8
Prior service credit	(7.2		)	(10.6		)	(15.3		)	(21.5		)
Total	$	523.6		$	533.1		$	51.6		$	56.3
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Current regulatory assets	$	25.8		$	27.7					$	—
Noncurrent regulatory assets	497.5			505.1			51.6			56.3
Deferred income taxes	0.1			0.1			—			—
Net-of-tax accumulated other comprehensive income	0.2			0.2			—			—
Total	$	523.6		$	533.1		$	51.6		$	56.3



^(b) Measurement date	~~In 2017, AROs were revised for changes in estimated cash flows and the timing of those cash flows. Changes in the gas transmission and distribution AROs were mainly related to increased labor costs.~~


^(c)	~~There were no ARO liabilities recognized during the year ended~~ Dec. 31, ~~2017.~~2018		Dec. 31, 2017		Dec. 31, 2018		Dec. 31, 2017

Cash Flows — Cash funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other calculations prescribed by the funding requirements of income tax and other pension-related regulations. Required contributions were made in 2016 - 2019 to meet minimum funding requirements. Total voluntary and required pension funding contributions across all four of Xcel Energy’s pension plans were as follows:

$150 million in January 2019, of which $43 million was attributable to PSCo;

$150 million in 2018, of which $22 million was attributable to PSCo;

$162 million in 2017, of which $18 million was attributable to PSCo; and

$125 million in 2016, of which $17 million was attributable to PSCo.

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

Xcel Energy expects to contribute approximately $11 million during 2019, of which amounts attributable to PSCo will be zero.

Xcel Energy, which includes PSCo, contributed:

$11 million during 2018, of which $5 million was attributable to PSCo;

$20 million during 2017, of which $5 million was attributable to PSCo; and

$18 million during 2016, of which $5 million was attributable to PSCo.

Targeted asset allocations:

(Thousands of Dollars)
Beginning
Balance
Jan. 1, 2016
Liabilities
Recognized Accretion
Cash Flow
Revisions ^(a)

Ending
Balance
Dec. 31, 2016 ^(b)
Electric plant
Steam, hydro, and other production asbestos $ 38,676
$ —
$ 1,877
$ (103 ) $ 40,450
Steam and other production ash containment 70,767
—
3,078
(1,245 ) 72,600
Wind production 1,992
—
19
61
2,072
Electric distribution 1,130
—
45
6,494
7,669
Other 1,054
214
46
206
1,520
Natural gas plant
Gas transmission and distribution 122,168
—
5,009
33,542
160,719
Other 3,925
—
155
—
4,080
Common and other property
Common miscellaneous 796
—
28
(371 ) 453
Total liability $ 240,508
$ 214
$ 10,257
$ 38,584
$ 289,563



	Pension Benefits				Postretirement Benefits
	2018		2017		2018		2017
Domestic and international equity securities	35	%	34	%	18	%	24	%
Long-duration fixed income securities	32		32		—		—
Short-to-intermediate fixed income securities	16		18		70		60
Alternative investments	15		14		8		9
Cash	2		2		4		7
Total	100	%	100	%	100	%	100	%

Plan Amendments — Xcel Energy, which includes PSCo, amended the Xcel Energy Inc. Nonbargaining Pension Plan (South) in 2017 to reduce supplemental benefits for non-bargaining participants as well as to allow the transfer of a portion of non-qualified pension obligations into the qualified plans. In 2016, the annual credits contributed to the PSCo Bargaining Plan retirement spending account increased.

In 2018 and 2017, there were no plan amendments made which affected the projected benefit obligation.

Projected Benefit Payments

PSCo’s projected benefit payments:



(Millions of Dollars)	Projected Pension Benefit Payments		Gross Projected Postretirement Health Care Benefit Payments		Expected Medicare Part D Subsidies		Net Projected Postretirement Health Care Benefit Payments
2019	$	81.2	$	31.6	$	2.0	$	29.6
2020	80.9		31.7		2.1		29.6
2021	82.4		31.6		2.2		29.4
2022	82.8		31.5		2.3		29.2
2023	83.4		31.0		2.4		28.6
2024-2028	410.2		141.5		13.0		128.5

Defined Contribution Plans

Xcel Energy, which includes PSCo, maintains 401(k) and other defined contribution plans that cover most employees. Total expense to these plans for PSCo was approximately $11 million in 2018 and $10 million in 2017 and 2016.


^(a) 11.	~~In 2016, AROs were revised for changes in estimated cash flows~~Commitments and ~~the timing of those cash flows. Changes in the gas transmission and distribution AROs were mainly related to increased miles of gas mains.~~


^(b)	~~There were no ARO liabilities settled during the year ended Dec. 31, 2016.~~Contingencies

~~Indeterminate AROs~~— Outside of the known and recorded asbestos AROs, other plants or buildings may contain asbestos due to the age of many of PSCo’s facilities, but no confirmation or measurement of the amount of asbestos or cost of removal could be determined as of Dec. 31, 2017. Therefore, an ARO has not been recorded for these facilities.

~~Removal Costs —~~ PSCo records a regulatory liability for the plant removal costs of generation, transmission and distribution facilities that are recovered currently in rates. Generally, the accrual of future non-ARO removal obligations is not required. However, long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for such costs in historical depreciation rates. These removal costs have accumulated over a number of years based on varying rates as authorized by the appropriate regulatory entities. Given the long time periods over which the amounts were accrued and the changing of rates over time, PSCo has estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates. Removal costs as of Dec. 31, 2017 and 2016 were $346 million and $367 million, respectively.

Legal ~~Contingencies~~

PSCo is involved in various litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves ~~a series of~~ complex judgments about future events. Management maintains accruals for ~~such~~ losses that are probable of being incurred and subject to reasonable estimation.

Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including ~~but not limited to~~ when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on PSCo’s financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred.

~~Employment, Tort and Commercial Litigation~~

Line Extension Disputes — In December 2015, ~~Development Recovery Company (DRC)~~the DRC filed a lawsuit seeking monetary damages in the Denver District Court, stating PSCo failed to award proper allowances and refunds for line extensions to new developments pursuant to the terms of electric and gas service ~~agreements entered into by PSCo and various developers.~~agreements. The dispute involves claims by over fifty developers. In May 2016, the Denver District Court granted PSCo’s motion to dismiss the lawsuit, concluding that jurisdiction over this dispute resides with the CPUC. In June 2016, DRC appealed the Denver District Court’s dismissal of the lawsuit, and the Colorado Court of Appeals affirmed the lower court decision in favor of PSCo. In July 2017, DRC filed a petition to appeal the decision with the Colorado Supreme Court. In February 2018, the Colorado Supreme Court denied DRC’s petition to appeal the Denver District Court’s dismissal of the lawsuit, effectively terminating this litigation.

In However, in January 2018, DRC filed a new lawsuit in Boulder County District Court, asserting a single claim that PSCo was required to file its line extension agreements with the CPUC but failed to do so.

This claim is substantially similar to the arguments previously raised by DRC. ~~Dates for~~PSCo filed a motion to dismiss this ~~proceeding have not been scheduled.~~

claim, which was granted in May 2018. DRC subsequently filed an appeal to the Colorado Court of Appeals with its opening brief in January 2019 and PSCo filed its answer brief in February 2019. It is uncertain when a decision will be rendered.

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

~~Other Contingencies~~

~~See Note 11 for further discussion.~~


~~13.~~	~~Regulatory Assets and Liabilities~~

Environmental

~~PSCo’s consolidated~~New and changing federal and state environmental mandates can create financial ~~statements~~liabilities for PSCo, which are ~~prepared in accordance with~~normally recovered through the ~~applicable accounting guidance, as discussed in Note 1. Under this guidance, regulatory assets~~regulated rate process.

Site Remediation— Various federal and ~~liabilities are created for amounts that regulators~~state environmental laws impose liability where hazardous substances or other regulated materials have been released to the environment.

PSCo may ~~allow to be collected,~~sometimes pay all or ~~may require to be paid back to customers in future electric and natural gas rates. Any~~a portion of the ~~business~~cost to remediate sites where past activities of PSCo’s predecessors or other parties have caused environmental contamination. Environmental contingencies could arise from various situations, including sites of former MGPs; and third-party sites, such as landfills, for which PSCo is alleged to have sent wastes to that site.

MGP, Landfill or Disposal Sites— PSCo is ~~not rate regulated cannot establish regulatory assets~~currently investigating or remediating three MGP, landfill or other disposal sites across its service territories, and ~~liabilities. If changes in the utility industry or the business~~these activities will continue through at least 2019. PSCo accrued $0.6 million as of ~~PSCo no longer allow for the application~~Dec. 31, 2018 and an immaterial amount as of ~~regulatory accounting guidance under GAAP, PSCo would be required to recognize the write-off of regulatory assets and liabilities in net income or OCI.~~

~~The components of regulatory assets shown on the consolidated balance sheets of PSCo at~~ Dec. 31, 2017 for these sites. There may be insurance recovery and/or recovery from other potentially responsible parties, offsetting some portion of costs incurred.

Environmental Requirements — Water and ~~2016 are:~~Waste

Coal Ash Regulation— PSCo’s operations are subject to federal and state laws that impose requirements for handling, storage, treatment and disposal of solid waste. In 2015, the EPA published the CCR Rule. Litigation was brought challenging the rule in the D.C. Circuit.

Under the CCR Rule, utilities are required to complete groundwater sampling around their CCR landfills and surface impoundments. PSCo has identified at least two sites where statistically significant increases over established groundwater standards exist in the groundwater near landfills and/or impoundments. PSCo has completed removal of CCR from these impoundments and plans to close these landfills. By the end of 2019, only six of PSCo’s regulated ash units are expected to be in operation. PSCo is conducting additional groundwater sampling and will evaluate whether corrective action is required at any CCR landfills or surface impoundments.

Until PSCo completes its assessment, it is uncertain what impact, if any, there will be on the operations, financial condition or cash flows. In August 2018, the D.C. Circuit ruled that the EPA cannot allow utilities to continue to use unlined impoundments (including clay lined impoundments) for the storage or disposal of coal ash. Litigation is ongoing regarding the deadline for closing or retrofitting these impoundments.

Federal CWA WOTUS Rule —In 2015, the EPA and Corps published a final rule that significantly broadened the scope of waters under the CWA that are subject to federal jurisdiction, referred to as “WOTUS”. The Rule has been subject to significant litigation and is currently stayed in a portion of the country. PSCo cannot estimate potential impacts until the legal and administrative processes are finalized, but expects costs will be recoverable through regulatory mechanisms.

Federal CWA ELG — In 2015, the EPA issued a final ELG rule for power plants that discharge treated effluent to surface waters as well as utility-owned landfills that receive CCRs. In 2017, the EPA delayed the compliance date for flue gas desulfurization wastewater and bottom ash transport until November 2020. After 2020, PSCo estimates that ELG compliance will cost approximately $1.5 million to complete. The EPA, however, is conducting a rulemaking process to potentially revise the effluent limitations and pretreatment standards, which may impact compliance costs. PSCo anticipates these costs will be fully recoverable through regulatory mechanisms.

Federal CWA Section 316(b) — The federal CWA requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available for minimizing impingement and entrainment of aquatic species. PSCo anticipates these costs will be fully recoverable through regulatory mechanisms.

AROs — AROs have been recorded for PSCo’s assets.

PSCo’s AROs were as follows:

(Thousands of Dollars) See Note(s) Remaining
Amortization Period Dec. 31, 2017 Dec. 31, 2016
Regulatory Assets Current Noncurrent Current Noncurrent
Pension and retiree medical obligations ^(a)
8
Various $ 28,010
$ 565,241
$ 27,270
$ 568,258
Recoverable deferred taxes on AFUDC recorded in plant^(b)
1
Plant lives —
86,966
—
151,022
Net AROs^(c)
1, 12
Plant lives —
80,476
—
78,050
Depreciation differences 1
One to fourteen years 19,835
69,428
15,363
90,426
Excess deferred taxes - TCJA 7
Various —
53,937
—
—
Purchased power contract costs 12
Term of related contract 1,261
28,009
1,035
29,029
Property tax Pending rate cases —
16,047
9,393
1,653
Gas pipeline inspection costs 12
One to two years 1,791
7,743
—
4,405
Conservation programs ^(d)
1, 11
One to two years 6,942
5,528
9,262
6,986
Losses on reacquired debt 4
Term of related debt 1,203
4,916
1,203
6,120
Contract valuation adjustments ^(e)
10
Term of related contract 6,022
2,638
3,444
6,082
Other Various 12,273
29,329
36,813
16,398
Total regulatory assets $ 77,337
$ 950,258
$ 103,783
$ 958,429



	Dec. 31, 2018
(Millions of Dollars)	Jan. 1, 2018		Amounts Incurred (a)		Amounts Settled (b)			Accretion		Cash Flow Revisions (c)			Dec. 31, 2018
Electric
Steam, hydro, and other production	$	103.2	$	—	$	(7.1	)	$	4.7	$	1.4		$	102.2
Wind	2.1		12.3		—			0.1		—			14.5
Distribution	7.9		—		—			0.3		5.2			13.4
Miscellaneous	1.4		—		(0.1		)	0.1		1.8			3.2
Natural gas
Transmission and distribution	228.9		—		—			9.3		(37.3		)	200.9
Miscellaneous	3.9		—		—			0.1		—			4.0
Common
Miscellaneous	0.4		—		—			0.1		—			0.5
Total liability	$	347.8	$	12.3	$	(7.2	)	$	14.7	$	(28.9	)	$	338.7


^(a)	~~Includes $3.4 million and $4.2 million of regulatory assets~~Amounts incurred related to the ~~nonqualified pension plan, of~~Rush Creek wind farm, which ~~$0.3 million and $0.4 million is included~~was placed in ~~the current asset at Dec. 31, 2017 and 2016, respectively.~~service in 2018.


^(b)	~~Includes a write-down~~Amounts settled related to closure of ~~$75.9 million as a result of the revaluation of deferred tax gross up at the new federal tax rate at Dec. 31, 2017.~~certain ash containment facilities.

^(c)

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


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


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

~~The components of regulatory liabilities shown on the consolidated balance sheets of PSCo at Dec. 31, 2017 and 2016 are:~~

(Thousands of Dollars) See Note(s) Remaining
Amortization Period Dec. 31, 2017 Dec. 31, 2016
Regulatory Liabilities Current Noncurrent Current Noncurrent
Excess deferred taxes - TCJA ^(a)
7
Various $ —
$ 1,445,079
$ —
$ —
Plant removal costs 1, 12
Plant lives —
346,174
—
367,440
Renewable resources and environmental initiatives 11, 12
Various —
56,153
3,600
67,728
Investment tax credit deferrals 1, 7
Various —
17,088
—
18,797
Deferred income tax adjustment 1
Various —
16,301
—
16,260
Deferred electric, natural gas and steam production costs 1
Less than one year 29,078
—
35,123
—
Conservation programs ^(b)
1, 11
Less than one year 21,168
—
24,077
—
Other Various 15,880
52,693
38,310
42,708
Total regulatory liabilities ^(c)
$ 66,126
$ 1,933,488
$ 101,110
$ 512,933



	Dec. 31, 2017
(Millions of Dollars)	Jan. 1, 2017		Amounts Settled (a)			Accretion		Cash Flow Revisions (b)		Dec. 31, 2017 (c)
Electric
Steam, hydro, and other production	$	113.1	$	(24.1	)	$	5.1	$	9.1	$	103.2
Wind	2.1		—			—		—		2.1
Distribution	7.7		—			0.2		—		7.9
Miscellaneous	1.5		(0.2		)	0.1		—		1.4
Natural gas
Transmission and distribution	160.7		—			6.7		61.5		228.9
Miscellaneous	4.1		(0.4		)	0.2		—		3.9
Common
Miscellaneous	0.4		—			—		—		0.4
Total liability	$	289.6	$	(24.7	)	$	12.3	$	70.6	$	347.8


^(a)	~~Primarily relates~~Amounts settled related to ~~the revaluation~~asbestos abatement projects, closure of ~~recoverable/regulated plant ADIT~~certain ash containment facilities, and ~~$49.6 million revaluation impact~~removal and proper disposal of ~~non-plant ADIT at Dec. 31, 2017.~~storage tanks and other above ground equipment.


^(b)	~~Includes costs~~In 2017, AROs were revised for ~~conservation programs, as well as incentives allowed~~changes in ~~certain jurisdictions.~~timing and estimates of cash flows. Changes in gas transmission and distribution AROs were primarily related to increased labor costs.


^(c)	~~Revenue subject to refund of $0 million and $2.4 million for 2017 and 2016, respectively, is included~~There were no ARO amounts incurred in ~~other current liabilities.~~2017.

Indeterminate AROs— Outside of the recorded asbestos AROs, other plants or buildings may contain asbestos due to the age of many of PSCo’s facilities, but no confirmation or measurement of the cost of removal could be determined as of Dec. 31, 2018. Therefore, an ARO has not been recorded for these facilities.

Removal Costs — PSCo records a regulatory liability for the plant removal costs that are recovered currently in rates. These removal costs have accumulated based on varying rates as authorized by the appropriate regulatory entities. PSCo has estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates. Removal costs as of Dec. 31, 2018 and 2017 were $344 million and $346 million, respectively.

Leases— PSCo has three leases accounted for as capital leases. The assets and liabilities of a capital lease are recorded at the lower of fair market value of the leased asset or the present value of future lease payments and are amortized over the term of the contract.

WYCO is a joint venture between Xcel Energy Inc. and CIG to develop and lease natural gas pipeline, storage and compression facilities. Xcel Energy Inc. has a 50% ownership interest in WYCO, and PSCo has no direct ownership interest. WYCO leases its facilities to CIG, and CIG operates the facilities, providing natural gas storage and transportation services to PSCo under separate service agreements.

PSCo accounts for its Totem natural gas storage service arrangement with CIG as a capital lease. As a result, PSCo had $120.0 million and $123.8 million of capital lease obligations as of Dec. 31, 2018 and 2017, respectively.

PSCo records amortization for its capital lease assets as electric fuel and purchased power and cost of natural gas sold and transported on the consolidated statements of income. Total amortization expense under capital lease assets was approximately $5.6 million, $5.3 million and $8.1 million for 2018, 2017 and 2016, ~~approximately $44 million~~respectively.

Property held under capital leases:



(Millions of Dollars)	Dec. 31, 2018			Dec. 31, 2017
Gas storage facilities	$	200.5		$	200.5
Gas pipeline	20.7			20.7
Property held under capital leases	221.2			221.2
Accumulated depreciation	(76.2		)	(70.6		)
Total property held under capital leases, net	$	145.0		$	150.6

Remaining leases, primarily for office space, railcars, generating facilities, vehicles, aircraft and ~~$28 million of PSCo’s regulatory assets represented past expenditures not currently earning a return, respectively. This amount primarily includes certain expenditures associated with property taxes~~power-operated equipment, are accounted for as operating leases.

Total expenses (including capacity payments) under operating lease obligations for PSCo and ~~renewable resources~~the corresponding capacity payments for PPAs accounted for as operating leases for the year ended Dec. 31:



(Millions of Dollars)	2018		2017		2016
Total expense	$	110.6	$	108.6	$	118.2
Capacity payments	96.6		96.1		102.4

Included in the future commitments under operating leases are estimated future capacity payments under PPAs that have been accounted for as operating leases.

Future commitments under operating and ~~environmental initiatives.~~capital leases:



(Millions of Dollars)	Operating Leases		PPA ^{(a) (b)} Operating Leases		Total Operating Leases		Capital Leases
2019	$	10.8	$	95.5	$	106.3	$	24.9
2020	10.7		95.9		106.6		24.8
2021	9.5		96.4		105.9		23.6
2022	8.4		82.6		91.0		20.5
2023	8.1		70.0		78.1		20.3
Thereafter	53.4		288.6		342.0		420.4
Total minimum obligation							534.5
Interest component of obligation							(389.5		)
Present value of minimum obligation							$	145.0


~~14.~~ ^(a)	Amounts do not include PPAs accounted for as executory contracts.


^(b)	PPA operating leases contractually expire through 2034.

Non-Lease PPAs— PSCo has entered into PPAs with other utilities and energy suppliers with expiration dates through 2034 for purchased power to meet system load and energy requirements and meet operating reserve obligations. In general, these agreements provide for energy payments, based on actual energy delivered and capacity payments. Certain PPAs accounted for as executory contracts contain minimum energy purchase commitments.

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

Included in electric fuel and purchased power expenses for PPAs accounted for as executory contracts were payments for capacity of $20.9 million, $25.2 million and $44.0 million in 2018, 2017 and 2016, respectively.

At Dec. 31, 2018, the estimated future payments for capacity that PSCo is obligated to purchase pursuant to these executory contracts, subject to availability, were as follows:



(Millions of Dollars)	Capacity
2019	$	12.3
2020	3.3
2021	3.2
2022	3.2
2023	3.2
Thereafter	9.8
Total	$	35.0

Fuel Contracts — PSCo has entered into various long-term commitments for the purchase and delivery of a significant portion of its coal and natural gas requirements. These contracts expire between 2019 and 2060. PSCo is required to pay additional amounts depending on actual quantities shipped under these agreements.

Estimated minimum purchases under these contracts as of Dec. 31, 2018:



(Millions of Dollars)	Coal		Natural gas supply		Natural gas storage and transportation
2019	$	133.1	$	342.6	$	116.7
2020	86.4		261.6		115.1
2021	55.6		251.8		113.0
2022	32.5		113.0		113.1
2023	24.8		59.9		65.5
Thereafter	104.3		—		544.0
Total	$	436.7	$	1,028.9	$	1,067.4

VIEs— Under certain PPAs, PSCo purchases power from IPPs for which PSCo is required to reimburse fuel costs, or to participate in tolling arrangements under which PSCo procures the natural gas required to produce the energy that it purchases. PSCo has determined that certain IPPs are VIEs. PSCo is not subject to risk of loss from the operations of these entities, and no significant financial support is required other than contractual payments for energy and capacity.

PSCo evaluated each of these VIEs for possible consolidation, including review of qualitative factors such as the length and terms of the contract, control over O&M, control over dispatch of electricity, historical and estimated future fuel and electricity prices, and financing activities. PSCo concluded that these entities are not required to be consolidated in its consolidated financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance. PSCo had approximately 1,571 MW of capacity under long-term PPAs at both Dec. 31, 2018 and 2017 with entities that have been determined to be VIEs. These agreements have expiration dates through 2032.


12.	Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. ~~31, 2017 and 2016 were as follows:~~31:

Year Ended Dec. 31, 2017
(Thousands of Dollars) Gains and Losses on Cash Flow Hedges Defined Benefit and Postretirement Items Total
Accumulated other comprehensive loss at Jan. 1 $ (22,780 ) $ (220 ) $ (23,000 )
Other comprehensive loss before reclassifications —
(5 ) (5 )
Losses reclassified from net accumulated other comprehensive loss 1,005
5
1,010
Net current period other comprehensive income 1,005
—
1,005

Adoption of ASU No. 2018-02 ^(a)
(4,690 ) (47 ) (4,737 )
Accumulated other comprehensive loss at Dec. 31 $ (26,465 ) $ (267 ) $ (26,732 )



	2018
(Millions of Dollars)	Gains and Losses on Cash Flow Hedges				Defined Benefit and Postretirement Items			Total
Accumulated other comprehensive loss at Jan. 1	$	(26.5	)		$	(0.2	)	$	(26.7	)
Losses reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (net of taxes of $0.4 and $0, respectively)	1.2			^(a)	—			1.2
Net current period other comprehensive income	1.2				—			1.2
Accumulated other comprehensive loss at Dec. 31	$	(25.3	)		$	(0.2	)	$	(25.5	)



	2017
(Millions of Dollars)	Gains and Losses on Cash Flow Hedges				Defined Benefit and Postretirement Items			Total
Accumulated other comprehensive loss at Jan. 1	$	(22.8	)		$	(0.2	)	$	(23.0	)
Losses reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (net of taxes of $0.6 and $0, respectively)	1.0			^(a)	—			1.0
Net current period other comprehensive income	1.0				—			1.0
Adoption of ASU No. 2018-02 ^(b)	(4.7		)		—			(4.7		)
Accumulated other comprehensive loss at Dec. 31	$	(26.5	)		$	(0.2	)	$	(26.7	)


^(a)	Included in interest charges.


^(b)	In 2017, PSCo implemented ASU No. 2018-02 related to the TCJA, which resulted in reclassification of certain credit balances within net accumulated other comprehensive loss to retained earnings. ~~For further information, see Note 2.~~

Year Ended Dec. 31, 2016
(Thousands of Dollars) Gains and Losses on Cash Flow Hedges Defined Benefit and Postretirement Items Total
Accumulated other comprehensive loss at Jan. 1 $ (23,836 ) $ —
$ (23,836 )
Other comprehensive loss before reclassifications —
(223 ) (223 )
Losses reclassified from net accumulated other comprehensive loss 1,056
3
1,059
Net current period other comprehensive income (loss) 1,056
(220 ) 836
Accumulated other comprehensive loss at Dec. 31 $ (22,780 ) $ (220 ) $ (23,000 )

~~Reclassifications from accumulated other comprehensive loss for the years ended Dec. 31, 2017 and 2016 were as follows:~~

Amounts Reclassified from Accumulated
Other Comprehensive Loss
(Thousands of Dollars) Year Ended Dec. 31, 2017 Year Ended Dec. 31, 2016
Losses (gains) on cash flow hedges:
Interest rate derivatives $ 1,615
^(a)
$ 1,618
^(a)
Vehicle fuel derivatives —
^(b)
86
^(b)
Total, pre-tax 1,615
1,704

Tax benefit (610 ) (648 )
Total, net of tax 1,005
1,056

Defined benefit pension and postretirement losses (gains):
Amortization of net losses 9
^(c)
5
^(c)
Total, pre-tax 9
5

Tax benefit (4 ) (2 )
Total, net of tax 5
3

Total amounts reclassified, net of tax $ 1,010
$ 1,059


^(a)	~~Included in interest charges.~~


^(b)	~~Included in O&M expenses.~~


^(c)	~~Included in the computation of net periodic pension and postretirement benefit costs. See Note 8 for details regarding these benefit plans.~~


~~15.~~13.	Segments and Related Information

Operating results from the regulated electric utility and regulated natural gas utility are each separately and regularly reviewed by PSCo’s chief operating decision maker. PSCo evaluates performance based on profit or loss generated from the product or service provided. These segments are managed separately because the revenue streams are dependent upon regulated rate recovery, which is separately determined for each segment.

PSCo has the following reportable segments: regulated electric utility, regulated natural gas utility and all other.

~~PSCo’s~~Regulated Electric - The regulated electric utility segment generates electricity which is transmitted and distributed in Colorado. ~~In addition, this~~This segment includes sales for resale and provides wholesale transmission service to various entities in the United States. Regulated electric utility also includes PSCo’s wholesale commodity and trading operations.

~~PSCo’s~~

Regulated Natural Gas - The regulated natural gas utility segment transports, stores and distributes natural gas in portions of Colorado.

All Other - Revenues from operating segments not included above are below the necessary quantitative thresholds ~~and~~ are ~~therefore~~ included in the all other category. Those primarily include steam revenue, appliance repair services and nonutility real estate activities.

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

To report income from operations for regulated electric and regulated natural gas utility segments, the majority of costs are directly assigned to each segment. However, some costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation allocators. A general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising.

~~The accounting policies of the segments are the same as those described in Note 1.~~

PSCo’s segment information:

(Thousands of Dollars) Regulated
Electric Regulated
Natural Gas All Other Reconciling
Eliminations Consolidated
Total
2017
Operating revenues ^(a)
$ 3,003,808
$ 995,214
$ 43,487
$ —
$ 4,042,509
Intersegment revenues 288
344
—
(632 ) —
Total revenues $ 3,004,096
$ 995,558
$ 43,487
$ (632 ) $ 4,042,509

Depreciation and amortization $ 353,560
$ 113,253
$ 4,702
$ —
$ 471,515
Interest charges and financing costs 138,565
40,214
508
—
179,287
Income tax expense (benefit) 243,604
18,398
(9,823 ) —
252,179
Net income 370,636
107,822
15,661
—
494,119

(Thousands of Dollars)
Regulated
Electric

Regulated
Natural Gas
All Other
Reconciling
Eliminations

Consolidated
Total
2016
Operating revenues ^(a)
$ 3,049,352
$ 957,721
$ 40,723
$ —
$ 4,047,796
Intersegment revenues 275
110
—
(385 ) —
Total revenues $ 3,049,627
$ 957,831
$ 40,723
$ (385 ) $ 4,047,796

Depreciation and amortization $ 337,583
$ 101,663
$ 4,309
$ —
$ 443,555
Interest charges and financing costs 136,274
37,881
431
—
174,586
Income tax expense (benefit) 228,825
45,960
(867 ) —
273,918
Net income 383,973
75,426
4,092
—
463,491


(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
2015
(Millions of Dollars)													2018			2017			2016
Regulated Electric
Operating revenues ^(a)	$	3,115,257	$	1,006,666	$	41,590		$	—		$	4,163,513	$	3,031.2		$	3,003.8		$	3,049.4
Intersegment revenues	301		67		—			(368		)	—		0.3			0.3			0.3
Total revenues	$	3,115,558	$	1,006,733	$	41,590		$	(368	)	$	4,163,513

Total operating revenue													$	3,031.5		$	3,004.1		$	3,049.7
Depreciation and amortization	$	311,122	$	96,384	$	4,161		$	—		$	411,667	415.6			353.6			337.6
Interest charges and financing costs	136,397		34,935		576			—			171,908		142.3			138.6			136.3
Income tax expense (benefit)	234,873		44,192		(625		)	—			278,440
Income tax expense													103.0			243.6			228.8
Net income	391,257		74,267		1,278			—			466,802		428.6			370.6			384.0
Regulated Natural Gas
Operating revenues^(a)													$	1,014.6		$	995.2		$	957.7
Intersegment revenues													0.6			0.4			0.1
Total operating revenue													$	1,015.2		$	995.6		$	957.8
Depreciation and amortization													140.6			113.2			101.7
Interest charges and financing costs													42.9			40.2			37.9
Income tax expense													13.1			18.4			46.0
Net income													121.4			107.8			75.4
All Other
Operating revenues^(a)													$	40.4		$	43.5		$	40.7
Depreciation and amortization													4.9			4.7			4.3
Interest charges and financing costs													0.5			0.5			0.4
Income tax (benefit)													(2.4		)	(9.8		)	(0.9		)
Net income													1.7			15.7			4.1

Consolidated Total
Operating revenues^(a)													$	4,087.1		$	4,043.2		$	4,048.2
Intersegment revenues													(0.9		)	(0.7		)	(0.4		)
Total operating revenue													$	4,086.2		$	4,042.5		$	4,047.8
Depreciation and amortization													561.1			471.5			443.6
Interest charges and financing costs													185.7			179.3			174.6
Income tax expense													113.7			252.2			273.9
Net income													551.7			494.1			463.5


^(a)	Operating revenues include $6$4.4 million, ~~$13~~$5.9 million and ~~$13~~$13.3 million of intercompany revenue for the years ended Dec. 31, 2018, 2017 ~~2016~~ and ~~2015,~~2016, respectively. See Note 1614 for further ~~discussion of related party transactions by reportable segment.~~information.


~~16.~~14.	Related Party Transactions

Xcel Energy Services Inc. provides management, administrative and other services for the subsidiaries of Xcel Energy Inc., including PSCo. The services are provided and billed to each subsidiary in accordance with service agreements executed by each subsidiary. PSCo uses services provided by Xcel Energy Services Inc. whenever possible. Costs are charged directly to the subsidiary and are allocated if they cannot be directly assigned.

Xcel Energy Inc., NSP-Minnesota, PSCo and SPS have established a utility money pool arrangement. See Note 45 for further ~~discussion.~~information.

~~The table below contains significant~~

Significant affiliate transactions among the companies and related parties for the years ended Dec. 31:


(Thousands of Dollars)	2017		2016		2015
(Millions of Dollars)							2018		2017		2016
Operating revenues:
Electric	$	1,436	$	8,809	$	8,632	$	—	$	1.4	$	8.8
Other	4,492		4,525		4,441		4.4		4.5		4.5
Operating expenses:
Purchased power	2		56		—
Other operating expenses — paid to Xcel Energy Services Inc.	485,066		446,086		414,620		518.7		485.1		446.1
Interest expense	—		149		211		—		—		0.1
Interest income	—		—		45

Accounts receivable and payable with affiliates at Dec. ~~31 were:~~31:


	2017				2016				2018				2017
(Thousands of Dollars)	Accounts Receivable		Accounts Payable		Accounts Receivable		Accounts Payable
(Millions of Dollars)									Accounts Receivable		Accounts Payable		Accounts Receivable		Accounts Payable
NSP-Minnesota	$	7,738	$	—	$	7,669	$	—	$	17.9	$	—	$	7.7	$	—
NSP-Wisconsin	61		—		974		—		—		0.2		—		—
SPS	279		—		745		—		0.7		—		0.3		—
Other subsidiaries of Xcel Energy Inc.	6,641		58,748		33		98,797		62.2		45.8		6.7		58.7
	$	14,719	$	58,748	$	9,421	$	98,797	$	80.8	$	46.0	$	14.7	$	58.7


~~17.~~15.	Summarized Quarterly Financial Data (Unaudited)


	Quarter Ended								Quarter Ended
(Thousands of Dollars)	March 31, 2017		June 30, 2017		Sept. 30, 2017		Dec. 31, 2017
(Millions of Dollars)									March 31, 2018		June 30, 2018		Sept. 30, 2018		Dec. 31, 2018
Operating revenues	$	1,080,534	$	930,916	$	1,030,293	$	1,000,766	$	1,073.3	$	911.9	$	1,060.7	$	1,040.3
Operating income	212,422		192,811		326,028		154,669		206.9		189.3		276.9		119.5
Net income	111,546		100,587		186,077		95,909		133.7		122.3		207.1		88.6


	Quarter Ended								Quarter Ended
(Thousands of Dollars)	March 31, 2016		June 30, 2016		Sept. 30, 2016		Dec. 31, 2016
(Millions of Dollars)									March 31, 2017		June 30, 2017		Sept. 30, 2017		Dec. 31, 2017
Operating revenues	$	1,057,841	$	909,852	$	1,059,177	$	1,020,926	$	1,080.5	$	930.9	$	1,030.3	$	1,000.8
Operating income(a)	223,190		180,629		315,605		170,197		212.9		193.3		326.5		155.3
Net income	115,874		87,344		173,607		86,666		111.5		100.6		186.1		95.9


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

Item 9 — Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

~~None.~~

Item 9A — Controls and Procedures

Disclosure Controls and Procedures

PSCo maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer ~~(CEO)~~ and chief financial officer, ~~(CFO),~~ allowing timely decisions regarding required disclosure. As of Dec. 31, ~~2017,~~2018, based on an evaluation carried out under the supervision and with the participation of PSCo’s management, including the ~~CEO~~chief executive officer and ~~CFO,~~chief financial officer, of the effectiveness of its disclosure controls and the procedures, the ~~CEO~~chief executive officer and ~~CFO~~chief financial officer have concluded that PSCo’s disclosure controls and procedures were effective.

Internal Control Over Financial Reporting

No change in PSCo’s internal control over financial reporting has occurred during the most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, PSCo’s internal control over financial reporting. PSCo maintains internal control over financial reporting to provide reasonable assurance regarding the reliability of the financial reporting. PSCo has evaluated and documented its controls in process activities, general computer activities, and on an entity-wide level. During the year and in preparation for issuing its report for the year ended Dec. 31, ~~2017~~2018 on internal controls under section 404 of the Sarbanes-Oxley Act of 2002, PSCo conducted testing and monitoring of its internal control over financial reporting. Based on the control evaluation, testing and remediation performed, PSCo did not identify any material control weaknesses, as defined under the standards and rules issued by the Public Company Accounting Oversight Board and as approved by the SEC and as indicated in Management Report on Internal Controls herein.

In 2016, PSCo implemented the general ledger modules of a new enterprise resource planning system to improve certain financial and related transaction processes. PSCo implemented additional work management systems modules in 2017. PSCo updated its internal control over financial reporting, as necessary, to accommodate modifications to its business processes and accounting systems. PSCo does not believe that this implementation had an adverse effect on its internal control over financial reporting.

This annual report does not include an attestation report of PSCo’s independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by PSCo’s independent registered public accounting firm pursuant to the rules of the SEC that permit PSCo to provide only management’s report in this annual report.

Item 9B — Other Information

None.

PART III

Items 10, 11, 12 and 13 of Part III of Form 10-K have been omitted from this report for PSCo in accordance with conditions set forth in general instructions I (1) (a) and (b) of Form 10-K for wholly-owned subsidiaries.

Item 10 — Directors, Executive Officers and Corporate Governance

Item 11 — Executive Compensation

Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Item 13 — Certain Relationships and Related Transactions, and Director Independence

Information required under this Item is contained in Xcel Energy Inc.’s ~~Proxy~~Proxy. Statement for its ~~2018~~2019 Annual Meeting of Shareholders, which is incorporated by reference.

Item 14 — Principal Accountant Fees and Services

~~The information~~Information required by Item 14 of From 10-K is set forth under the heading “Independent Registered Public Accounting Firm - Audit and Non-Audit Fees” in Xcel Energy Inc.’s definitive Proxy Statement for the ~~2018~~2019 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about April ~~3, 2018.~~1, 2019. Such information set forth under such heading is incorporated herein by this reference hereto.

PART IV

Item 15—Exhibits, Financial Statement Schedules



1.1	Consolidated Financial Statements:

	Management Report on Internal Controls Over Financial Reporting — For the year ended Dec. 31, ~~2017.~~2018.
	Report of Independent Registered Public Accounting Firm — Financial Statements
	Consolidated Statements of Income — For the three years ended Dec. 31, 2018, 2017, ~~2016,~~ and ~~2015.~~2016.
	Consolidated Statements of Comprehensive Income — For the three years ended Dec. 31, 2018, 2017, ~~2016,~~ and ~~2015.~~2016.
	Consolidated Statements of Cash Flows — For the three years ended Dec. 31, 2018, 2017, ~~2016,~~ and ~~2015.~~2016.
	Consolidated Balance Sheets — As of Dec. 31, ~~2017~~2018 and ~~2016.~~2017.
	Consolidated Statements of Common Stockholder’s Equity — For the three years ended Dec. 31, ~~2017, 2016 and 2015.~~
	~~Consolidated Statements of Capitalization — As of Dec. 31,~~2018, 2017 and 2016.

2.2	Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2018, 2017, ~~2016,~~ and ~~2015.~~2016.
3.	~~Exhibits~~


3	Exhibits
*	Indicates incorporation by reference
+	Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors
^t	Certain portions of this agreement have been omitted pursuant to a request for confidential treatment and have been filed separately with the SEC.



Exhibit Number	Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference
3.01*	Amended and Restated Articles of Incorporation dated July 15, 1998 ~~(Exhibit 3.01 to~~	PSCo Form 10-Q for the quarter ended Sept. 30, 2017 ~~(file no. 001-03280)).~~	001-03280	3.01
3.02*	By-Laws of PSCo as Amended and Restated on ~~Sept. 26, 2013 (Exhibit 3.02 to Form 10-Q/A for the quarter ended Sept. 30, 2013 (file no. 001-03280)).~~Jan. 25, 2019
4.01*	Indenture, dated as of Oct. 1, 1993 between PSCo and Morgan Guaranty Trust Company of New York, as ~~trustee,~~Trustee, providing for the issuance of First Collateral Trust Bonds ~~(Exhibit 4.34 to Form 10-K of~~	Xcel Energy ~~(file no. 001-03034) for the year ended Dec. 31, 2017).~~


Inc. Form S-3 dated April 18, 2018	001-03034	4(d)(3)
4.02*	Indenture dated July 1, 1999, between PSCo and The Bank of New York, providing for the issuance of Senior Debt Securities and First Supplemental Indenture dated July ~~15,~~14, 1999 between PSCo and ~~The~~the Bank of New York ~~(Exhibits 4.1 and 4.2 to~~	PSCo Form 8-K ~~(file no. 001-03280)~~ dated July 13, ~~1999).~~1999	001-03280	4.1 4.2
4.03*	Supplemental Indenture, dated Aug. 1, 2007 between PSCo and U.S. Bank Trust National Association, as successor Trustee ~~(Exhibit 4.01 to~~	PSCo Form 8-K ~~(file no. 001-03280)~~ dated Aug. ~~18, 2007).~~8, 2007	001-03280	4.01
4.04*	Supplemental Indenture dated as of Aug. 1, 2008 between PSCo and U.S. Bank Trust National Association, as successor Trustee, creating $300 million principal amount of ~~5.80 percent~~5.80% First Mortgage Bonds, Series No. 18 due 2018 and $300 million principal amount of ~~6.50 percent~~6.50% First Mortgage Bonds, Series No. 19 due 2038 ~~(Exhibit 4.01 of~~	PSCo Form 8-K ~~of PSCo~~ dated Aug. 6, 2008 ~~(file no. 001-03280)).~~	001-03280	4.01
4.05*	Supplemental Indenture dated as of May 1, 2009 between PSCo and U.S. Bank Trust National Association, as successor Trustee, creating $400 million principal amount of ~~5.125 percent~~5.125% First Mortgage Bonds, Series No. 20 due 2019 ~~(Exhibit 4.01 of~~	PSCo Form 8-K ~~of PSCo~~ dated May 28, 2009 ~~(file no. 001-03280)).~~	001-03280	4.01
4.06*	Supplemental Indenture dated as of Nov. 1, 2010 between PSCo and U.S. Bank National Association, as successor Trustee, creating $400 million principal amount of ~~3.200 percent~~3.20% First Mortgage Bonds, Series No. 21 due 2020 ~~(Exhibit 4.01 of~~	PSCo Form 8-K ~~of PSCo~~ dated Nov. ~~18,~~8, 2010 ~~(file no. 001-03280)).~~	001-03280	4.01
4.07*	Supplemental Indenture dated as of Aug. 1, 2011 between PSCo and U.S. Bank National Association, as successor Trustee, creating $250 million principal amount of ~~4.75 percent~~4.75% First Mortgage Bonds, Series No. 22 due 2041 ~~(Exhibit 4.01 to~~	PSCo Form 8-K ~~of PSCo~~ dated Aug. 9, 2011 ~~(file no. 001-03280)).~~	001-03280	4.01
4.08*	Supplemental Indenture dated as of Sept. 1, 2012 between PSCo and U.S. Bank National Association, as successor Trustee, creating $300 million principal amount of ~~2.25 percent~~2.25% First Mortgage Bonds, Series No. 23 due 2022 and $500 million principal amount of ~~3.60 percent~~3.60% First Mortgage Bonds, Series No. 24 due 2042 ~~(Exhibit 4.01 to~~	PSCo Form 8-K dated Sept. 11, 2012 ~~(file no. 001-03280)).~~	001-03280	4.01
4.09*	Supplemental Indenture dated as of March 1, 2013 between PSCo and U.S. Bank National Association, as successor Trustee, creating $250 million principal amount of ~~2.50 percent~~2.50% First Mortgage Bonds, Series No. 25 due 2023 and $250 million principal amount of ~~3.95 percent~~3.95% First Mortgage Bonds, Series No. 26 due 2043 ~~(Exhibit 4.01 to~~	PSCo Form 8-K ~~of PSCo~~ dated March 26, 2013 ~~(file no. 001-03280)).~~


	001-03280	4.01
4.10*	Supplemental Indenture dated as of March 1, 2014 between PSCo and U.S. Bank National Association, as successor Trustee, creating $300 million principal amount of ~~4.30 percent~~4.30% First Mortgage Bonds, Series No. 27 due ~~2044. (Exhibit 4.01 to~~2044	PSCo Form 8-K ~~of PSCo~~ dated March 10, 2014 ~~(file no. 001-03280)).~~	001-03280	4.01
4.11*	Supplemental Indenture dated as of May 1, 2015 between PSCo and U.S. Bank National Association, as successor Trustee, creating $250 million principal amount of ~~2.90 percent~~2.90% First Mortgage Bonds, Series No. 28 due ~~2025. (Exhibit 4.01 to~~2025	PSCo Form 8-K ~~of PSCo~~ dated May 12, 2015 ~~(file no. 001-03280)).~~	001-03280	4.01
4.12*	Supplemental Indenture dated as of June 1, 2016 between PSCo and U.S. Bank National Association, as successor Trustee, creating $250 million principal amount of ~~3.55 percent~~3.55% First Mortgage Bonds, Series No. 29 due ~~2046. (Exhibit 4.01 to~~2046	PSCo Form 8-K ~~of PSCo~~ dated June 13, 2016 ~~(file no. 001-03280)).~~	001-03280	4.01
4.13*	Supplemental Indenture No. 27 dated as of June 1, 2017 between PSCo and U.S. Bank National Association, as successor Trustee, creating $400 million principal amount of ~~3.80 percent~~3.80% First Mortgage Bonds, Series No. 30 due ~~2047. (Exhibit 4.01 to~~2047	PSCo Form 8-K ~~of PSCo~~ dated June 19, 2017 ~~(file no. 001-03280)).~~	001-03280	4.01
4.14*	Supplemental Indenture dated as of June 1, 2018 between PSCo and U.S. Bank National Association, as successor Trustee, creating $350 million principal amount of 3.70% First Mortgage Bonds, Series No. 31 due 2028, and $350 million principal amount of 4.10% First Mortgage Bonds, Series No. 32 due 2048	PSCo Form 8-K dated June 21, 2018	001-03280	4.01
10.01*+	Xcel Energy Inc. Nonqualified Pension Plan (2009 Restatement) ~~(Exhibit 10.02 to~~	Xcel Energy Inc. Form 10-K ~~of Xcel Energy (file no. 001-03034)~~ for the year ended Dec. 31, ~~2008).~~2008	001-03034	10.02



10.02*+	Xcel Energy Senior Executive Severance and Change-in-Control Policy (2009 ~~Amendment and~~ Restatement) ~~(Exhibit 10.05 to~~	Xcel Energy Inc. Form 10-K ~~of Xcel Energy (file no. 001-03034)~~ for the year ended Dec. 31, ~~2008).~~2008	001-03034	10.05
10.03*+	Xcel Energy Inc. Non-Employee ~~Directors’~~Directors Deferred Compensation Plan as amended and restated on Jan. 1, 2009 ~~(Exhibit 10.08 to~~	Xcel Energy Inc. Form 10-K ~~of Xcel Energy (file no. 001-03034)~~ for the year ended Dec. 31, ~~2008).~~2008	001-03034	10.08
10.04*+	Form of Services Agreement between Xcel Energy Services Inc. and utility companies ~~(Exhibit H-1 to~~	Xcel Energy Inc. Form U5B ~~(file no. 001-03034)~~ dated Nov. 16, ~~2000).~~2000	001-03034	H-1
10.05*+	Xcel Energy Inc. Supplemental Executive Retirement Plan as amended and restated Jan. 1, 2009 ~~(Exhibit 10.17 to~~	Xcel Energy Inc. Form 10-K ~~of Xcel Energy (file no. 001-03034)~~ for the year ended Dec. 31, ~~2008).~~2008	001-03034	10.17
10.06*	Proposed Settlement Agreement, excerpts, as filed with the CPUC ~~(Exhibit 99.02 to~~	Xcel Energy Inc. Form 8-K ~~of Xcel Energy (file no. 001-03034)~~ dated Dec. 3, ~~2004).~~2004	001-03034	99.02
10.07*+	First Amendment to Exhibit 10.02 dated Aug. 26, 2009 ~~to the~~	Xcel Energy ~~Senior Executive Severance and Change-in-Control Policy (Exhibit 10.06 to~~Inc. Form 10-Q ~~of Xcel Energy (file no. 001-03034)~~ for the quarter ended Sept. 30, ~~2009).~~2009	001-03034	10.06
10.08*+	Xcel Energy Inc. Executive Annual Incentive Award Plan Form of Restricted Stock Agreement ~~(Exhibit 10.08 to~~	Xcel Energy Inc. Form 10-Q ~~of Xcel Energy (file no. 001-03034)~~ for the quarter ended Sept. 30, ~~2009).~~2009	001-03034	10.08
10.09*+	Xcel Energy Inc. Executive Annual Incentive ~~Award~~ Plan (as amended and restated effective Feb. 17, 2010) ~~(incorporated by reference to Appendix A to Schedule 14A,~~	Xcel Energy Inc. Definitive Proxy Statement ~~to Xcel Energy (file no. 001-03034)~~ dated April 6, ~~2010).~~2010	001-03034	Schedule 14A
10.10*+	Xcel Energy Inc. 2005 Long-Term Incentive Plan (as amended and restated effective Feb. 17, 2010) ~~(incorporated by reference to Appendix B to Schedule 14A,~~	Xcel Energy Inc. Definitive Proxy Statement ~~to Xcel Energy (file no. 001-03034)~~ dated April 6, ~~2010).~~2010	001-03034	Schedule 14A
10.11*+	Stock Equivalent Plan for Non-Employee Directors of Xcel Energy Inc. as amended and restated effective Feb. 23, 2011 ~~(Appendix A to the~~	Xcel Energy Inc. Definitive Proxy Statement ~~(file no. 001-03034) filed Apr.~~dated April 5, ~~2011).~~2011	001-03034	Schedule 14A
10.12*+	Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009 Restatement) ~~(Exhibit 10.07 to~~	Xcel Energy Inc. Form 10-K ~~of Xcel Energy (file no. 001-03034)~~ for the year ended Dec. 31, ~~2008).~~2008	001-03034	10.07
10.13*+	First Amendment to Exhibit 10.12 effective Nov. 29, 2011 ~~to the~~	Xcel Energy Inc. ~~Nonqualified Deferred Compensation Plan (2009 Restatement) (Exhibit 10.17 to~~ Form 10-K ~~of Xcel Energy (file no. 001-03034)~~ for the year ended Dec. 31, ~~2011).~~2011	001-03034	10.17
10.14*+	Second Amendment to Exhibit 10.02 dated Oct. 26, 2011 ~~to the~~	Xcel Energy ~~Senior Executive Severance and Change-in-Control Policy (Exhibit 10.18 to~~Inc. Form 10-K ~~of Xcel Energy (file no. 001-03034)~~ for the year ended Dec. 31, ~~2011).~~2011	001-03034	10.18
10.15*+	First Amendment to Exhibit 10.09 dated Feb. 20, 2013 ~~to the~~	Xcel Energy Inc. ~~Executive Annual Incentive Award Plan (as amended and restated effective Feb. 17, 2010) (Exhibit 10.01 to~~ Form 10-Q ~~of Xcel Energy (file no. 001-03034)~~ for the quarter ended March 31, ~~2013).~~2013	001-03034	10.01
10.16*+	Fourth Amendment to Exhibit 10.02 dated Feb. 20, 2013 ~~to the~~	Xcel Energy ~~Senior Executive Severance and Change-in-Control Policy (Exhibit 10.02 to~~Inc. Form 10-Q ~~of Xcel Energy (file no. 001-03034)~~ for the quarter ended March 31, ~~2013).~~2013	001-03034	10.02
10.17*+	First Amendment to Exhibit 10.10 dated May 21, 2013 ~~to the~~	Xcel Energy Inc. ~~2005 Long-Term Incentive Plan (as amended and restated effective Feb. 17, 2010) (Exhibit 10.21 to~~ Form 10-K ~~of Xcel Energy (file no. 001-03034)~~ for the year ended Dec. 31, ~~2013).~~2013	001-03034	10.21
10.18*+	Second Amendment to Exhibit 10.12 dated May 21, 2013 ~~to the~~	Xcel Energy Inc. ~~Nonqualified Deferred Compensation Plan (2009 Restatement) (Exhibit 10.22 to~~ Form 10-K ~~of Xcel Energy (file no. 001-03034)~~ for the year ended Dec. 31, ~~2013).~~2013	001-03034	10.22
10.19*+	Xcel Energy Inc. 2005 Long-Term Incentive Plan Form of Long-Term Incentive Award Agreement ~~(Exhibit 10.23 to~~	Xcel Energy Inc. Form 10-K ~~of Xcel Energy (file no. 001-03034)~~ for the year ended Dec. 31, ~~2013).~~


2013	001-03034	10.23
10.20*+	Xcel Energy Inc. 2015 Omnibus Incentive Plan ~~(incorporated by reference to Appendix B to Schedule 14A,~~	Xcel Energy Inc. Definitive Proxy Statement ~~to Xcel Energy Inc. (file no. 001-03034)~~ dated April 6, ~~2015).~~2015	001-03034	Schedule 14A
10.21*+	Stock Equivalent Program for Non-Employee Directors of Xcel Energy Inc. ~~(As First Effective May 20, 2015)~~ under the Xcel Energy Inc. 2015 Omnibus Incentive ~~Plan. (Exhibit 10.02 to~~Plan	Xcel Energy Inc. Form 8-K ~~of Xcel Energy,~~ dated May ~~26,~~20, 2015 ~~(file no. 001-03034).~~	001-03034	10.02
10.22*+	Form of Xcel Energy Inc. 2015 Omnibus Incentive Plan Award Agreement and Award Terms and Conditions ~~(Restricted Stock Units and Performance Share Units)~~ under the Xcel Energy Inc. 2015 Omnibus Incentive ~~Plan. (Exhibit 10.03 to~~Plan	Xcel Energy Inc. Form 8-K ~~of Xcel Energy,~~ dated May ~~26,~~20, 2015 ~~(file no. 001-03034).~~	001-03034	10.03
10.23*+	Xcel Energy Inc. 2015 Omnibus Incentive Plan Form of Award ~~Agreement. (Exhibit 10.28 to~~Agreement	Xcel Energy Inc. Form 10-K ~~of Xcel Energy (file no. 001-03034)~~ for the year ended Dec. 31, ~~2015).~~2015	001-03034	10.28
10.24*+	Xcel Energy Inc. Executive Annual Incentive Award Sub-plan pursuant to the Xcel Energy Inc. 2015 Omnibus Incentive ~~Plan. (Exhibit 10.29 to~~Plan	Xcel Energy Inc. Form 10-K ~~of Xcel Energy (file no. 001-03034)~~ for the year ended Dec. 31, ~~2015).~~2015	001-03034	10.29
10.25*+	Fifth Amendment Exhibit 10.02 dated May 3, 2016 ~~to the~~	Xcel Energy ~~Senior Executive Severance and Change-in-Control Policy (Exhibit 10.01 to~~Inc. Form 10-Q ~~of Xcel Energy (file no. 001-03034)~~ for the quarter ended June 30, ~~2016).~~2016	001-03034	10.01
10.26*	Second Amended and Restated Credit Agreement, dated as of June 20, 2016 among PSCo, as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A. and Barclays Bank Plc, as Syndication Agents, and Wells Fargo Bank, National Association and ~~The~~the Bank of Tokyo-Mitsubishi UFJ, Ltd., as Documentation ~~Agents. (Exhibit 99.03 to~~Agents	Xcel Energy Inc. Form 8-K ~~of Xcel Energy~~ dated June 20, 2016 ~~(file no. 001-03034)).~~	001-03034	99.03
10.27*+	Third Amendment to Exhibit 10.12 dated Sept. 30, 2016 ~~to the~~	Xcel Energy Inc. ~~Nonqualified Deferred Compensation Plan (2009 Restatement) (Exhibit 10.01 to~~ Form 10-Q ~~of Xcel Energy (file no. 001-03034)~~ for the quarter ended Sept. 30, ~~2016).~~2016	001-03034	10.01
10.28*+	Form of Xcel Energy, Inc. 2015 Omnibus Incentive Plan Award Agreement and Award Terms and Conditions ~~(Restricted Stock Units and Performance Share Units)~~ under the Xcel Energy ~~Inc.~~inc. 2015 Omnibus Incentive ~~Plan. (Exhibit 10.27 to~~Plan	Xcel Energy Inc. Form 10-K ~~of Xcel Energy (file no. 001-03034)~~ for the year ended Dec. 31, ~~2016).~~2016	001-03034	10.27
10.29*+	Fourth Amendment to ~~the~~ Exhibit 10.12 dated Oct. 23, 2017	Xcel Energy Inc. ~~Nonqualified Deferred Compensation Plan (2009 Restatement) (Exhibit 10.1 to~~ Form 10-Q ~~of Xcel Energy~~ for the quarter ended Sept. 30, 2017 ~~(file no. 001-03034)).~~	001-03034	10.1
10.30*+	Sixth Amendment to Exhibit 10.02 dated Feb. 22, 2018 to	Xcel Energy ~~Senior Executive Severance and Change-in-Control Policy (Exhibit 10.30 to~~Inc. Form 10-K ~~of Xcel Energy (file no. 001-03034)~~ for the year ended Dec. 31, ~~2017.~~2017	001-03034	10.30
10.31*+	Seventh Amendment to Exhibit 10.02 dated May 7, 2018	Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2018	001-03034	10.01
10.32*+	Xcel Energy Inc. Amended and Restated 2015 Omnibus Incentive Plan	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018	001-03034	10.34
10.33*+	Form of Xcel Energy Inc. 2015 Omnibus Incentive Plan Award Agreement Terms and Conditions under the Xcel Energy Inc. Amended and Restated 2015 Omnibus Incentive Plan	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018	001-03034	10.35
10.34*+	Stock Program for Non-Employee Directors of Xcel Energy Inc. as Amended and Restated on Dec. 12, 2017 under the 2015 Omnibus Incentive Plan	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018	001-03034	10.36



~~12.01~~	~~Statement of Computation of Ratio of Earnings to Fixed Charges.~~
23.01	Consent of Independent Registered Public Accounting Firm.
31.01	Principal Executive Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02	Principal Financial Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
~~99.01~~	~~Statement pursuant to Private Securities Litigation Reform Act of 1995.~~
101	The following materials from PSCo’s Annual Report on Form 10-K for the year ended Dec. 31, ~~2017~~2018 are formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statements of Income, (ii) the Consolidated Statements of Comprehensive Income, (iii) the Consolidated Statements of Cash Flows, (iv) the Consolidated Balance Sheets, (v) the Consolidated Statements of Stockholder’s Equity, (vi) ~~the Consolidated Statements of Capitalization, (vii)~~ Notes to Consolidated Financial Statements, ~~(viii)~~(vii) document and entity information, and ~~(ix)~~(viii) Schedule II.

SCHEDULE II

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

VALUATION AND QUALIFYING ACCOUNTS

YEARS ENDED DEC. 31, 2018, 2017 ~~2016~~ AND ~~2015~~2016

~~(amounts in thousands)~~

Additions

Balance at
Jan. 1
Charged to Costs and Expenses
Charged to Other Accounts^(a)

Deductions from
Reserves^(b)

Balance at
Dec. 31
Allowance for bad debts:
2017 $ 19,612
$ 14,303
$ 3,968
$ 18,277
$ 19,606
2016 20,122
14,121
4,447
19,078
19,612
2015 23,122
13,052
5,175
21,227
20,122



	Allowance for bad debts
(Millions of Dollars)	2018			2017			2016
Balance at Jan. 1	$	19.6		$	19.6		$	20.1
Additions Charged to Costs and Expenses	16.4			14.3			14.1
Additions Charged to Other Accounts ^(a)	4.7			4.0			4.5
Deductions from Reserves ^(b)	(20.2		)	(18.3		)	(19.1		)
Balance at Dec. 31	$	20.5		$	19.6		$	19.6


^(a)	Recovery of amounts previously written off.


^(b)	Deductions relate primarily to bad debt write-offs.

Item 16 — Form 10-K Summary

None.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this annual report to be signed on its behalf by the undersigned thereunto duly authorized.



		PUBLIC SERVICE COMPANY OF COLORADO

Feb. ~~23, 2018~~22, 2019		/s/ ROBERT C. FRENZEL
		Robert C. Frenzel
		Executive Vice President, Chief Financial Officer and Director
		(Principal Financial Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities on the date indicated above.



/s/ BEN FOWKE		/s/ ~~DAVID L. EVES~~ALICE K. JACKSON
Ben Fowke		~~David L. Eves~~Alice K. Jackson
Chairman, Chief Executive Officer and Director		President and Director
(Principal Executive Officer)

/s/ ROBERT C. FRENZEL		/s/ JEFFREY S. SAVAGE
Robert C. Frenzel		Jeffrey S. Savage
Executive Vice President, Chief Financial Officer and Director		Senior Vice President, Controller
(Principal Financial Officer)		(Principal Accounting Officer)

/s/ ~~MARVIN E. MCDANIEL, JR.~~DAVID L. EVES
~~Marvin E. McDaniel, Jr.~~David L. Eves
Executive Vice President and Director

SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(D) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT

PSCo has not sent, and does not expect to send, an annual report or proxy statement to its security holder.

8650



	Coal				Natural Gas				Weighted Average Owned Fuel Cost
PSCo Generating Plants	Cost		Percent		Cost		Percent		Weighted Average Owned Fuel Cost
2017	$	1.56	70	%	$	3.82	30	%	$	2.25
2016	1.75		72		3.79		28		2.33
2015	1.75		75		3.89		25		2.29



Electric Utility Generating Stations:
Station, Location and Unit	Fuel	Installed	Summer 2017 Net Dependable Capability (MW)
Steam:
Comanche-Pueblo, Colo.
Unit 1	Coal	1973	325
Unit 2	Coal	1975	335
Unit 3	Coal	2010	500	^(a)
Craig-Craig, Colo., 2 Units	Coal	1979-1980	83	^(b)
Hayden-Hayden, Colo., 2 Units	Coal	1965-1976	233	^(c)
Pawnee-Brush, Colo., 1 Unit	Coal	1981	505
Valmont-Boulder, Colo., 1 Unit	Coal	1964	—	^(d)
Combustion Turbine:
Blue Spruce-Aurora, Colo., 2 Units	Natural Gas	2003	264
Cherokee-Denver, Colo., 1 Unit	Natural Gas	1968	310	^(e)
Cherokee-Denver, Colo., 3 Units	Natural Gas	2015	576
Fort St. Vrain-Platteville, Colo., 6 Units	Natural Gas	1972-2009	968
Rocky Mountain-Keenesburg, Colo., 3 Units	Natural Gas	2004	580
Various locations, 6 Units	Natural Gas	Various	171
Hydro:
Cabin Creek-Georgetown, Colo.
Pumped Storage, 2 Units	Hydro	1967	210
Various locations, 9 Units	Hydro	Various	26
		Total	5,086



(Millions of Dollars)	2017 vs. 2016
Fuel and purchased power cost recovery	$	(58	)
DSM program revenues (offset by expenses)	6
Non-fuel riders	5
Other, net	2
Total decrease in electric revenues	$	(45	)



(Millions of Dollars)	2017 vs. 2016
Purchased natural gas adjustment clause recovery	$	32
Infrastructure and integrity riders	13
Estimated impact of weather	(4		)
Retail rate decrease	(4		)
Total increase in natural gas revenues	$	37



	Common Stock Issued								Accumulated Other Comprehensive Income (Loss)			Total Common Stockholder’s Equity
	Shares	Par Value		Additional Paid In Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Common Stockholder’s Equity
Balance at Dec. 31, 2014	100	$	—	$	3,522,788	$	1,386,929		$	(23,878	)	$	4,885,839
Net income						466,802						466,802
Other comprehensive income									42			42
Common dividends declared to parent						(330,567		)				(330,567		)
Contribution of capital by parent				98,036								98,036
Balance at Dec. 31, 2015	100	$	—	$	3,620,824	$	1,523,164		$	(23,836	)	$	5,120,152
Net income						463,491						463,491
Other comprehensive income									836			836
Common dividends declared to parent						(327,416		)				(327,416		)
Contribution of capital by parent				12,392								12,392
Balance at Dec. 31, 2016	100	$	—	$	3,633,216	$	1,659,239		$	(23,000	)	$	5,269,455
Net income						494,119						494,119
Other comprehensive income									1,005			1,005
Common dividends declared to parent						(335,866		)				(335,866		)
Contribution of capital by parent				399,610								399,610
Adoption of ASU No. 2018-02						4,737			(4,737		)	—
Balance at Dec. 31, 2017	100	$	—	$	4,032,826	$	1,822,229		$	(26,732	)	$	5,828,323



	One-Percentage Point
(Thousands of Dollars)	Increase		Decrease
APBO	$	41,665	$	(35,254	)
Service and interest components	1,837		(1,555		)



	Year Ended Dec. 31, 2017
	Pre-Tax Fair Value Losses Recognized During the Period in:					Pre-Tax Losses Reclassified into Income During the Period from:
(Thousands of Dollars)	Accumulated Other Comprehensive Loss		Regulatory (Assets) and Liabilities			Accumulated Other Comprehensive Loss			Regulatory Assets and (Liabilities)			Pre-Tax Gains (Losses) Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	—	$	—		$	1,615	^(a)	$	—		$	—
Total	$	—	$	—		$	1,615		$	—		$	—
Other derivative instruments
Commodity trading	$	—	$	—		$	—		$	—		$	386		^(c)
Natural gas commodity	—		(10,921		)	—			1,933		^(d)	(4,170		)	^(d)
Total	$	—	$	(10,921	)	$	—		$	1,933		$	(3,784	)



	Year Ended Dec. 31, 2016
	Pre-Tax Fair Value Gains Recognized During the Period in:				Pre-Tax Losses Reclassified into Income During the Period from:
(Thousands of Dollars)	Accumulated Other Comprehensive Loss		Regulatory (Assets) and Liabilities		Accumulated Other Comprehensive Loss			Regulatory Assets and (Liabilities)			Pre-Tax Losses Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	—	$	—	$	1,618	^(a)	$	—		$	—
Vehicle fuel and other commodity	—		—		86		^(b)	—			—
Total	$	—	$	—	$	1,704		$	—		$	—
Other derivative instruments
Commodity trading	$	—	$	—	$	—		$	—		$	(257	)	^(c)
Natural gas commodity	—		2,051		—			10,292		^(d)	(5,832		)	^(d)
Total	$	—	$	2,051	$	—		$	10,292		$	(6,089	)



	Year Ended Dec. 31, 2015
	Pre-Tax Fair Value Losses Recognized During the Period in:						Pre-Tax Losses Reclassified into Income During the Period from:
(Thousands of Dollars)	Accumulated Other Comprehensive Loss			Regulatory (Assets) and Liabilities			Accumulated Other Comprehensive Loss			Regulatory Assets and (Liabilities)			Pre-Tax Gains (Losses) Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	—		$	—		$	54	^(a)	$	—		$	—
Vehicle fuel and other commodity	(50		)	—			57		^(b)	—			—
Total	$	(50	)	$	—		$	111		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	—		$	—		$	364		^(c)
Natural gas commodity	—			(10,635		)	—			10,158		^(d)	(7,620		)	^(d)
Total	$	—		$	(10,635	)	$	—		$	10,158		$	(7,256	)



Revenue Request (Millions of Dollars)	2018		2019		2020		2021		Total
Revenue request	$	74	$	75	$	60	$	36	$	245
CACJA revenue conversion to base rates ^(a)	90		—		—		—		90
TCA revenue conversion to base rates ^(a)	43		—		—		—		43
Total ^(b)	$	207	$	75	$	60	$	36	$	378

Expected year-end rate base (billions of dollars) ^(b)	$	6.8	$	7.1	$	7.3	$	7.4



(Thousands of Dollars)	Beginning Balance Jan. 1, 2017		Liabilities Settled ^(a)			Accretion		Cash Flow Revisions ^(b)			Ending Balance Dec. 31, 2017 ^(c)
Electric plant
Steam and other production ash containment	$	72,600	$	(12,068	)	$	3,159	$	9,573		$	73,264
Steam, hydro, and other production asbestos	40,450		(12,047		)	1,917		(458		)	29,862
Electric distribution	7,669		—			274		—			7,943
Wind production	2,072		—			20		—			2,092
Other	1,520		(204		)	66		—			1,382
Natural gas plant
Gas transmission and distribution	160,719		—			6,649		61,503			228,871
Other	4,080		(354		)	159		—			3,885
Common and other property
Common miscellaneous	453		—			17		—			470
Total liability	$	289,563	$	(24,673	)	$	12,261	$	70,618		$	347,769



(Thousands of Dollars)	Beginning Balance Jan. 1, 2016		Liabilities Recognized		Accretion		Cash Flow Revisions ^(a)			Ending Balance Dec. 31, 2016 ^(b)
Electric plant
Steam, hydro, and other production asbestos	$	38,676	$	—	$	1,877	$	(103	)	$	40,450
Steam and other production ash containment	70,767		—		3,078		(1,245		)	72,600
Wind production	1,992		—		19		61			2,072
Electric distribution	1,130		—		45		6,494			7,669
Other	1,054		214		46		206			1,520
Natural gas plant
Gas transmission and distribution	122,168		—		5,009		33,542			160,719
Other	3,925		—		155		—			4,080
Common and other property
Common miscellaneous	796		—		28		(371		)	453
Total liability	$	240,508	$	214	$	10,257	$	38,584		$	289,563



			Additions
	Balance at Jan. 1		Charged to Costs and Expenses		Charged to Other Accounts^(a)		Deductions from Reserves^(b)		Balance at Dec. 31
Allowance for bad debts:
2017	$	19,612	$	14,303	$	3,968	$	18,277	$	19,606
2016	20,122		14,121		4,447		19,078		19,612
2015	23,122		13,052		5,175		21,227		20,122