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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
☒
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2019 or
☐
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
001-03280
(Commission File Number)
Public Service Company of Colorado
(Exact name of registrant as specified in its charter)
 
Colorado
 
84-0296600
(State or Other Jurisdiction of Incorporation or Organization)
 
(I.R.S. Employer Identification No.)
 
 
 
 
 
1800 Larimer, Suite 1100
Denver
Colorado
 
80202
(Address of Principal Executive Offices)
 
(Zip Code)
303
571-7511
(Registrant’s Telephone Number, Including Area Code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
 
Trading Symbol
 
Name of each exchange on which registered
N/A
 
N/A
 
N/A
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. ☒ 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 ☒ 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.
☒ Yes ☐ No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). ☒ Yes ☐ No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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 ☒ Non-accelerated filer ☐ Smaller reporting company ☐ Emerging growth company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). ☐ Yes ☒ No
As of Feb. 21, 2020, 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.
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 2020 Annual Meeting of Shareholders which definitive Proxy Statement is expected to be filed with the SEC on or about April 6, 2020. 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).
 

1

TABLE OF CONTENTS
PART I
 
 
Item 1 —
 
 
 
 
 
 
 
 
 
Item 1A —
Item 1B —
Item 2 —
Item 3 —
Item 4 —
 
 
 
PART II
 
 
Item 5 —
Item 6 —
Item 7 —
Item 7A —
Item 8 —
Item 9 —
Item 9A —
Item 9B —
 
 
 
PART III
 
 
Item 10 —
Item 11 —
Item 12 —
Item 13 —
Item 14 —
 
 
 
PART IV
 
 
Item 15 —
Item 16 —
 
 
 
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.


2
Table of Contents

PART I
ITEM 1 — BUSINESS
Definitions of Abbreviations
Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former)
e prime
e prime inc.
NSP-Minnesota
Northern States Power Company, a Minnesota corporation
NSP-Wisconsin
Northern States Power Company, a Wisconsin corporation
PSCo
Public Service Company of Colorado
SPS
Southwestern Public Service 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
CPUC
Colorado Public Utilities Commission
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
FCA
Fuel clause 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
Other
ADIT
Accumulated deferred income taxes
AFUDC
Allowance for funds used during construction
ARO
Asset retirement obligation
ASC
FASB Accounting Standards Codification
ASU
FASB Accounting Standards Update
Boulder
City of Boulder, CO
C&I
Commercial and Industrial
CACJA
Clean Air Clean Jobs Act
CCR
Coal combustion residuals
CCR Rule
Final rule (40 CFR 257.50 - 257.107) published by the EPA regulating the management, storage and disposal of CCRs as a nonhazardous waste
CEO
Chief executive officer
CFO
Chief financial officer
CEP
Colorado Energy Plan
CIG
Colorado Interstate Gas Company, LLC
CPCN
Certificate of public convenience and necessity
CWA
Clean Water Act
CWIP
Construction work in progress
DRC
Development Recovery Company
ELG
Effluent limitations guidelines
ETR
Effective tax rate
FASB
Financial Accounting Standards Board
 
GAAP
Generally accepted accounting principles
GHG
Greenhouse gas
IPP
Independent power producing entity
ITC
Investment tax credit
MDL
Multi-district litigation
MGP
Manufactured gas plant
Moody’s
Moody’s Investor Services
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
O&M
Operating and maintenance
Post-65
Post-Medicare
PPA
Purchased power agreement
Pre-65
Pre-Medicare
PTC
Production tax credit
REC
Renewable energy credit
ROE
Return on equity
ROU
Right-of-use
RTO
Regional Transmission Organization
SERP
Supplemental executive retirement plan
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

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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, 2019 (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: operational safety; successful long-term operational planning; commodity risks associated with energy markets and production; rising energy prices and fuel costs; qualified employee work force and third-party contractor factors; ability to recover costs, changes in regulation and subsidiaries’ ability to recover costs from customers; reductions in our credit ratings and the cost of maintaining certain contractual relationships; general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of 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; our subsidiaries’ ability to make dividend payments; tax laws; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; seasonal weather patterns; changes in environmental laws and regulations; climate change and other weather; natural disaster and resource depletion, including compliance with any accompanying legislative and regulatory changes; and costs of potential regulatory penalties.
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.
Overview
Electric customers
1.5 million
 
pscostatea10.jpg
 
PSCo was incorporated in 1924 under the laws of Colorado. PSCo conducts business in Colorado and generates, purchases, transmits, distributes and sells electricity in addition to purchasing, transporting, distributing and selling natural gas to retail customers and transporting customer-owned natural gas.
Natural gas customers
1.4 million
 
 
Total assets
$19.0 billion
 
 
Rate Base
$12.4 billion
 
 
ROE
8.69%
 
 
Electric generating capacity
5,666 MW
 
 
Gas storage capacity
32.5 Bcf
 
 
Electric transmission lines (conductor miles)
24,008 miles
 
 
Electric distribution lines (conductor miles)
78,023 miles
 
 
Natural gas transmission lines
2,057 miles
 
 
Natural gas distribution lines
22,633 miles
 
 
 
Electric Operations
PSCo had electric sales volume of 37,337 (millions of KWh), 1,507,841 customers and electric revenues of $3,033.0 (millions of dollars) for 2019.
 
chart-01adde45a48f3072795.jpgchart-84468d483299eb59076.jpgchart-22956286268cf711c38.jpg
 

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Sales/Revenue Statistics
 
 
2019
 
2018
KWH sales per retail customer
 
19,335

 
19,660

Revenue per retail customer
 
$1,812

 
$1,797

Residential revenue per KWh
 

11.09
¢
 

10.86
¢
Large C&I revenue per KWh
 

6.43
¢
 

6.20
¢
Small C&I revenue per KWh
 

9.38
¢
 

9.18
¢
Total retail revenue per KWh
 

9.37
¢
 

9.14
¢
Owned and Purchased Energy Generation — 2019
chart-3f0b0ec54bb449c3011.jpg
Electric Energy Sources
Total electric generation by source (including energy market purchases) for the year ended Dec. 31, 2019:
 
chart-f3da4e71f5ead742680.jpg
*Distributed generation from the Solar*Rewards® program is not included (approximately 512.8 million KWh for 2019).
 
Renewable Energy Sources
PSCo’s renewable energy portfolio includes wind, hydroelectric and solar power from both owned generating facilities and PPAs. Renewable percentages will vary year over year based on system additions, weather, system demand and transmission constraints.
See Item 2 — Properties for further information.
Renewable energy as a percentage of total energy for 2019:
chart-be2baf42059f09717a0.jpg
(a) 
Includes biomass and hydroelectric.
 
Wind Energy Sources
Owned — Owned and operated wind farms with corresponding capacity:
2019
 
2018
Wind Farms
 
Capacity
 
Wind Farms
 
Capacity
1
 
600 MW
 
1
 
600 MW
PPAs — Number of PPAs with range:
2019
 
2018
PPAs
 
Range
 
PPAs
 
Range
20
 
2.0 MW - 300.5 MW
 
19
 
2.0 MW - 300.5 MW
Capacity — Wind capacity:
2019
 
2018
3,165 MW
 
 3,160 MW
Average Cost (Owned) — Average cost per MWh of wind energy from owned generation:
2019
 
2018 (a)
$47
 
—
(a) 
The table reflects the owned wind site that was in commercial operation for the full calendar year. The Rush Creek wind farm was put into service in December 2018.
Average Cost (PPAs) — Average cost per MWh of wind energy under existing PPAs:
2019
 
2018
$41
 
$43
Wind Energy Development
PSCo currently has approximately 500 MW of owned wind under development or construction and approximately 450 MW of planned PPAs with an estimated completion date of 2021 or earlier:
Project
 
Capacity
 
Estimated Completion
Cheyenne Ridge
 
500 MW
 
2020
Various PPAs
 
~450 MW
 
2020-2021
Solar Energy Sources
Solar energy PPAs:
Type
 
Capacity
Distributed Generation
 
557 MW
Utility-Scale
 
305 MW
Fossil Fuel Energy Sources
PSCo’s fossil fuel energy portfolio includes coal and natural gas power from both owned generating facilities and PPAs.
See Item 2 — Properties for further information.
Coal Energy Sources
PSCo has four coal plants with approximately 2,000 MW of total 2019 net summer dependable capacity.

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The following are PSCo’s approved coal plant retirements. In addition, PSCo plans to continue to evaluate its coal fleet for other potential early coal plant retirements as part of state resource plans or other regulatory proceedings.
Approved (2019 to 2025)
Year
 
Plant
 
Capacity
2022
 
Comanche 1
 
325 MW
2025
 
Comanche 2
 
335 MW
2025
 
Craig 1
 
42 MW
Coal Fuel Cost
Delivered cost per MMBtu of coal consumed for owned electric generation and the percentage of total fuel requirements:
 
 
Coal
 
 
Cost
 
Percent
2019
 
$
1.45

 
55
%
2018
 
1.45

 
62

Natural Gas Energy Sources
PSCo has six natural gas plants with approximately 2,900 MW of total 2019 net summer dependable capacity. See item 2 - Properties for further detail.
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.
 
Natural Gas Cost
Delivered cost per MMBtu of natural gas consumed for owned electric generation and the percentage of total fuel requirements:
 
 
Natural Gas
 
 
Cost
 
Percent
2019
 
3.27

 
45
2018
 
3.74

 
38
Capacity and Demand
Uninterrupted system peak demand and occurrence date:
System Peak Demand (in MW)
2019
 
2018
7,111

 
July 19
 
6,718

 
July 10
Transmission
Transmission lines deliver electricity over long distances from power sources to transmission substations closer to homes and businesses. A strong transmission system ensures continued reliable and affordable service, ability to meet state and regional energy policy goals, and support a diverse generation mix, including renewable energy. PSCo owns more than 24,000 conductor miles of transmission lines across its service territory.
During 2019, PSCo completed the following transmission projects:
Project
 
Miles
 
Size
Pawnee-Daniels Park
 
125

 
345 KV
Thornton Substation
 
2

 
115 KV
Upcoming transmission projects:
Project
 
Miles
 
Size
Cheyenne Ridge
 
65

 
345 KV
Natural Gas Operations
Natural gas operations consist of purchase, transportation and distribution of natural gas to end use residential, C&I and transport customers. PSCo had natural gas deliveries of 334,698 (thousands of MMBtu), 1,425,895 customers and natural gas revenues of $1,160.9 (millions of dollars) for 2019.
 
chart-a08c2217be379d6d2a5.jpgchart-dfb81bcb11f85c6ae09.jpgchart-8a36ad4bc9ebab3e992.jpg
 
Sales/Revenue Statistics
 
 
2019
 
2018
MMBtu sales per retail customer
 
109.80

 
98.35

Revenue per retail customer
 
$
748.34

 
$
638.03

Residential revenue per MMBtu
 
7.02

 
6.67

C&I revenue per MMBtu
 
6.33

 
6.04

Transportation and other revenue per MMBtu
 
0.56

 
0.77

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

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Maximum daily output (firm and interruptible) and occurrence date:
2019
 
2018
MMBtu
 
Date
 
MMBtu
 
Date
2,139,420

(a) 
March 3
 
1,903,878

 
Feb. 20
(a) 
Increase in maximum MMBtu output due to colder winter temperatures in 2019.
Natural Gas Supply and Costs
PSCo actively seeks natural gas supply, transportation and storage alternatives to yield a diversified portfolio, which provides increased flexibility, decreased interruption and financial risk and economical rates. In addition, PSCo conducts natural gas price hedging activities approved by its state commissions.
Average delivered cost per MMBtu of natural gas for regulated retail distribution:
2019
 
2018
2.95

 
3.20

PSCo has natural gas supply transportation and storage agreements that include obligations for purchase and/or delivery of specified volumes or to make payments in lieu of delivery.
See Item 2 - Properties for further information.
General
Seasonality
Demand for electric power and natural gas is affected by seasonal differences in the weather. In general, peak sales of electricity occur in the summer months and peak sales of natural gas occur in the winter months. As a result, the overall operating results may fluctuate substantially on a seasonal basis. Additionally, PSCo’s operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer.
Competition
PSCo is subject to public policies that promote competition and development of energy markets. PSCo’s industrial and large commercial customers have the ability to generate their own electricity. In addition, customers may have the option of substituting other fuels or relocating their facilities to a lower cost region.
Customers have the opportunity to supply their own power with distributed generation including solar generation and in most jurisdictions can currently avoid paying for most of the fixed production, transmission and distribution costs incurred to serve them.
Several states, including Colorado, have incentives for the development of rooftop solar, community solar gardens and other distributed energy resources. Distributed generating resources are potential competitors to PSCo’s electric service business with these incentives and federal tax subsidies.
The FERC has continued to promote competitive wholesale markets through open access transmission and other means. PSCo’s wholesale customers can purchase their output from generation resources of competing suppliers or non-contracted quantities and use the transmission systems of Xcel Energy Inc.’s utility subsidiaries on a comparable basis to serve their native load.
 
FERC Order No. 1000 established 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 has franchise agreements with cities subject to periodic renewal; however, a city could seek alternative means to access electric power or gas, such as municipalization.
While facing these challenges, PSCo believes its rates and services are competitive with alternatives currently available.
Public Utility Regulation
See Item 7 for discussion of public utility regulation.
Environmental
Environmental Regulation
Our facilities are regulated by federal and state environmental agencies that have jurisdiction over air emissions, water quality, wastewater discharges, solid wastes and hazardous substances. Various company activities require registrations, permits, licenses, inspections and approvals from these agencies. PSCo has received necessary authorizations for the construction and continued operation of its generation, transmission and distribution systems. Our facilities have been designed and constructed to operate in compliance with applicable environmental standards and related monitoring and reporting requirements. However, it is not possible to determine when or to what extent additional facilities or modifications of existing or planned facilities will be required as a result of changes to environmental regulations, interpretations or enforcement policies or what effect future laws or regulations may have.
We may be required to incur expenditures in the future for remediation of MGP and other sites if it is determined that prior compliance efforts are not sufficient.
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 non-attainment area as it develops plans to meet ozone standards. Gas plants which operate in PSCo’s non-attainment area may be required to improve or add controls, implement further work practices and/or enhanced emissions monitoring as part of future Colorado state plans.
There are significant present and future environmental regulations to encourage use of clean energy technologies and regulate emissions of GHGs. PSCo has undertaken numerous initiatives to meet current requirements and prepare for potential future regulations, reduce GHG emissions and respond to state renewable and energy efficiency goals. If future environmental regulations do not take into consideration investments already made or if additional initiatives or emission reductions are required, substantial costs may be incurred.
In July 2019, the EPA adopted the Affordable Clean Energy rule, which requires states to develop plans for GHG reductions from coal-fired power plants. The state plans, due to the EPA in July 2022, will evaluate and potentially require heat rate improvements at existing coal-fired plants. It is not yet known how these state plans will affect PSCo’s existing coal plants, but they could require substantial additional investment, even in plants slated for retirement. PSCo believes, based on prior state commission practice, the cost of these initiatives or replacement generation would be recoverable through rates.

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PSCo seeks to address climate change and potential climate change regulation through efforts to reduce its GHG emissions in a balanced, cost-effective manner.
Employees
As of Dec. 31, 2019, PSCo had 2,369 full-time employees and no part-time employees, of which 1,884 were covered under collective-bargaining agreements.
ITEM 1A — RISK FACTORS
Xcel Energy, which includes PSCo, is subject to a variety of risks, many of which are beyond our control. Risks that may adversely affect the business, financial condition, results of operations or cash flows are described below. These risks should be carefully considered together with the other information set forth in this report and future reports that Xcel Energy files with the SEC.
Oversight of Risk and Related Processes
The Board of Directors is responsible for the oversight of material risk and maintaining an effective risk monitoring process. Management and the Board of Directors’ committees have responsibility for overseeing the identification and mitigation of key risks.
At a threshold level, PSCo maintains a robust compliance program and promotes a culture of compliance, beginning with the tone at the top. The risk mitigation process includes adherence to our code of conduct and compliance policies, operation of formal risk management structures and overall business management. PSCo further mitigates inherent risks through formal risk committees and corporate functions such as internal audit, and internal controls over financial reporting and legal.
Management identifies and analyzes risks to determine materiality and other attributes such as timing, probability and controllability. Identification and risk analysis occurs formally through risk assessment conducted by senior management, the financial disclosure process, hazard risk procedures, internal audit and compliance with financial and operational controls. Management also identifies and analyzes risk through the business planning process, development of goals and establishment of key performance indicators, including identification of barriers to implementing our strategy. The business planning process also identifies likelihood and mitigating factors to prevent the assumption of inappropriate risk to meet goals.
Management communicates regularly with the Board of Directors and its sole stockholder regarding risk. Senior management presents and communicates a periodic risk assessment to the Board of Directors, providing information on the risks that management believes are material, including financial impact, timing, likelihood and mitigating factors. The Board of Directors regularly reviews management’s key risk assessments, which includes areas of existing and future macroeconomic, financial, operational, policy, environmental and security risks.
The oversight, management and mitigation of risk is an integral and continuous part of the Board of Directors’ governance of PSCo. Processes are in place to ensure appropriate risk oversight, as well as identification and consideration of new risks.
 
Risks Associated with Our Business
Operational Risks
Our natural gas and electric transmission and distribution operations involve numerous risks that may result in accidents and other operating risks and costs.
Our natural gas transmission and distribution activities include inherent hazards and operating risks, such as leaks, explosions, outages and mechanical problems. Our electric generation, transmission and distribution activities include inherent hazards and operating risks such as contact, fire and outages. These risks could result in loss of life, significant property damage, environmental pollution, impairment of our operations and substantial financial losses. We maintain insurance against most, but not all, of these risks and losses. The occurrence of these events, if not fully covered by insurance, could have a material effect on our financial condition, results of operations and cash flows.
Additionally, compliance with existing and potential new regulations related to the operation and maintenance of our natural gas infrastructure could result in significant costs. 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. We have programs in place to comply with the PHMSA regulations and systematically monitor and renew infrastructure over time; however, a significant incident or material finding of non-compliance could result in penalties and higher costs of operations.
Our natural gas and electric transmission and distribution operations are dependent upon complex information technology systems and network infrastructure, the failure of which could disrupt our normal business operations, which could have a material adverse effect on our ability to process transactions and provide services.
Our utility operations are subject to long-term planning and project 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. Our long-term resource plan is dependent on our ability to obtain required approvals, develop necessary technical expertise, allocate and coordinate sufficient resources and adhere to budgets and timelines.
In addition, the long-term nature of both our planning and our asset lives are subject to risk. The electric utility sector is undergoing a period of significant change. For example, increases in energy efficiency, wider adoption of lower cost renewable generation, distributed generation and shifts away from coal generation to decrease carbon 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, downward pressure on sales growth, as well as stranded costs if PSCo is not able to fully recover costs and investments.
Changing customer expectations and technologies are requiring significant investments in advanced grid infrastructure, which increases exposure to technology obsolescence.

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Evolving stakeholder preference for lower emission generation sources may pressure our investments in natural gas generation and delivery. The magnitude and timing of resource additions and changes in customer demand may not coincide while customer preference for resource generation may change, which introduces further uncertainty into long-term planning. Additionally, multiple states may not agree as to the appropriate resource mix which may lead to costs to comply with one jurisdiction that are not recoverable across all jurisdictions served by the same assets.
We are subject to longer-term availability of 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.
We are subject to commodity risks and other risks associated with energy markets and energy production.
In the event fuel costs increase, customer demand could decline and bad debt expense may rise, which may have a material impact on our results of operations. Despite existing fuel 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.
A significant disruption in supply could cause us to seek alternative supply services at potentially higher costs and supply shortages may not be fully resolved, which could cause disruptions in our ability to provide services to our customers. Failure to provide service due to disruptions may also result in fines, penalties or cost disallowances through the regulatory process. Also, significantly higher energy or fuel costs relative to sales commitments could negatively impact our cash flows and results of operations.
We also engage in wholesale sales and purchases of electric capacity, energy and energy-related products as well as natural gas. In many markets, emission allowances and/or RECs are also needed to comply with various statutes and commission rulings. As a result, we are subject to market supply and commodity price risk. Commodity price changes can affect the value of our commodity trading derivatives. We mark certain derivatives to estimated fair market value on a daily basis. Settlements can vary significantly from estimated fair values recorded and significant changes from the assumptions underlying our fair value estimates could cause earnings variability.
Failure to attract and retain a qualified workforce could have an adverse effect on operations.
Certain specialized knowledge is required of our technical employees for construction and operation of transmission, generation and distribution assets. Our business strategy is dependent on our ability to recruit, retain and motivate employees. Competition for skilled employees is high in the areas of business operations. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to new employees or future availability and cost of contract labor may adversely affect the ability to manage and operate our business. We have seen a tightening of supply for engineers and skilled laborers in certain markets and are implementing plans to retain these employees. Inability to attract and retain these employees could adversely impact our results of operations, financial condition or cash flows.
Our operations use third-party contractors in addition to employees to perform periodic and ongoing work.
We rely on third-party contractors to perform operations, maintenance and construction work. Our contractual arrangements with these contractors typically include performance standards, progress payments, insurance requirements and security for performance.
 
Poor vendor performance could impact ongoing operations, restoration operations, our reputation and could introduce financial risk or risks of fines.
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 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 of Directors makes determinations with respect to a number of significant corporate events, including the payment of our dividends.
We have historically paid quarterly dividends to Xcel Energy Inc. In 2019, 2018 and 2017 we paid $457.6 million, $375.3 million and $333.9 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 Note 5 to the consolidated financial statements for further information.
Financial Risks
Our profitability depends on 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.
There can also be no assurance that our regulatory commissions will judge all our costs to be prudent, which could result in disallowances, or that the regulatory process will always result in rates that will produce full recovery. Overall, management believes prudently incurred costs are recoverable given the existing regulatory framework. However, there may be changes in the regulatory environment that could impair our ability to recover costs historically collected from customers, or we could exceed caps on capital costs (e.g., wind projects) required by commissions and result in less than full recovery.
Changes in the long-term cost-effectiveness or to the operating conditions of our assets may result in early retirements of utility facilities. While regulation typically provides relief for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs.
In a continued low interest rate environment there has been increased downward pressure on allowed ROE. Conversely, higher than expected inflation or tariffs may increase costs of construction and operations. Also, rising fuel costs could increase the risk that we will not be able to fully recover our fuel costs from our customers.
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.

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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 disallowance of costs, significantly lower returns on equity, changes to equity ratios and impacts of tax policy 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 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. Capital markets are global and impacted by issues and events throughout the world. Any disruption in capital markets could have a material impact on our ability to fund our operations. Capital market disruption 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. 
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 may 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 System Operator, Inc. and the Electric Reliability Council of Texas, in which any credit losses are socialized to all market participants.
We have additional indirect credit exposure 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.
 
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 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, 2019, Xcel Energy Inc. and its utility subsidiaries had approximately $17.4 billion of long-term debt and $1.3 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, 2019, Xcel Energy had guarantees outstanding with a maximum stated amount of approximately $2.0 million and immaterial exposure. Xcel Energy also had additional guarantees of $60.4 million at Dec. 31, 2019 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.
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 numbers of retirements or employees leaving PSCo would trigger settlement accounting and could require PSCo to recognize incremental pension expense related to unrecognized plan losses in the year liabilities are paid. Changes in industry standards utilized in key assumptions (e.g., mortality tables) could have a significant impact on future liabilities and benefit costs.
Increasing costs associated with health care plans may adversely affect our results of operations.
Increasing levels of large individual health care claims and overall health care claims could have an adverse impact on our results of operations, financial condition or cash flows. Health care legislation could also significantly impact our benefit programs and costs.

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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. Tax depreciable lives and the value of various tax credits or the timeliness of their utilization may impact the economics or selection of resources. There could be timing delays before regulated rates provide for realization of tax changes in revenues. In addition, certain IRS tax policies such as tax 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, which correlates to customers/sales growth (decline). Economic conditions may be impacted by insufficient financial sector liquidity leading to potential increased unemployment, which may impact customers’ ability to pay their bills which could lead to additional bad debt expense.
Additionally, PSCo faces competitive factors, which could have an adverse impact on our financial condition, results of operations and cash flows. Further, worldwide economic activity impacts the demand for basic commodities necessary for utility infrastructure, which may inhibit our ability to acquire sufficient supplies. We operate in a capital intensive industry and federal trade policy could significantly impact the cost of materials we use. There may be delays before these additional material costs can be recovered in rates.
Operations could be impacted by war, terrorism or other 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.
We also face the risks of possible loss of business due to significant events such as severe storm, severe temperature extremes, wildfires (particularly in Colorado), widespread pandemic, 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).
The recent coronavirus outbreak in China is an example of how major catastrophic events throughout the world may disrupt our business. While we are a domestic company, the Company participates in a global supply chain, which includes materials and components that are sourced from China. A prolonged disruption could result in the delay of equipment and materials that may impact our ability to reliably serve our customers.
 
Disruption due to events such as those noted above 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.
PSCo participates in biennial grid security and emergency response exercises (GridEx). These efforts, led by the NERC, test and further develop the coordination, threat sharing and interaction between utilities and various government agencies relative to potential cyber and physical threats against the nation’s electric grid.
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 been the target of several attacks on operational systems and has seen 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 would likely receive state and federal regulatory scrutiny and 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. We are unable to quantify the potential impact of cyber security threats or subsequent related actions. Cyber security incidents and regulatory action could result in a material decrease in revenues and may cause significant additional costs (e.g., penalties, third-party claims, repairs, insurance or compliance) and potentially disrupt our supply and markets for natural gas, oil and other fuels.
We maintain security measures to protect our information technology and control systems, network infrastructure and other assets. However, these assets and the information they process may be vulnerable to cyber security incidents, including asset failure or unauthorized access to assets or information. A failure or breach of our technology systems or those of our third-party service providers could disrupt critical business functions and may negatively impact our business, our brand, and our reputation. The cyber security threat is dynamic and evolves continually, and our efforts to prioritize network protection may not be effective given the constant changes to threat vulnerability.

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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.
Public Policy Risks
We may be subject to legislative and regulatory responses to climate change, with which compliance could be difficult and costly.
Legislative and regulatory responses related to climate change and new interpretations of existing laws create financial risk as our facilities may be subject to additional regulation at either the state or federal level in the future. Such regulations could impose substantial costs on our system.
We may be subject to climate change lawsuits. An adverse outcome could require substantial capital expenditures and possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant and could affect results of operations, financial condition or cash flows if such costs are not recovered through regulated rates.
Although the United States has not adopted any international or federal GHG emission reduction targets, many states and localities may continue to pursue climate policies in the absence of federal mandates. The steps 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 being discussed, the lack of federal action does not adversely impact these state-endorsed actions and plans.
If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material effect on our results of operations, financial condition or cash flows.
Increased risks of regulatory penalties could negatively impact our business.
The Energy Act increased civil penalty authority for violation of FERC statutes, rules and orders. The FERC can impose penalties of up to $1.3 million per violation per day, particularly as it relates to energy trading activities for both electricity and natural gas. In addition, NERC electric reliability standards and critical infrastructure protection requirements are mandatory and subject to potential financial penalties. Also, the PHMSA, Occupational Safety and Health Administration and other federal agencies have the authority to assess penalties. In the event of serious incidents, these agencies have become more active in pursuing penalties. Some states additionally have the authority to impose substantial penalties. If a serious reliability, cyber or safety incident did occur, it could have a material effect on our results of operations, financial condition or cash flows.
 
Environmental Risks
We are subject to environmental laws and regulations, with which compliance could be difficult and costly.
We are subject to environmental laws and regulations that affect many aspects of our operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances. Laws and regulations require us to obtain permits, licenses, and approvals and to comply with a variety of environmental requirements.
Environmental laws and regulations can also require us to restrict or limit the output of facilities or the use of certain fuels, shift generation to lower-emitting facilities, install pollution control equipment, clean up spills and other contamination and correct environmental hazards. Environmental regulations may also lead to shutdown of existing facilities. Failure to meet requirements of environmental mandates may result in fines or penalties. We may be required to pay all or a portion of the cost to remediate (i.e., clean-up) sites where our past activities, or the activities of other parties, caused environmental contamination.
We are subject to mandates to provide customers with clean energy, renewable energy and energy conservation offerings. It could have a material effect on our results of operations, financial condition or cash flows if our regulators do not allow us to recover the cost of capital investment or the O&M costs incurred to comply with the requirements.
In addition, existing environmental laws or regulations may be revised, and new laws or regulations may be adopted. We may also incur additional unanticipated obligations or liabilities under existing environmental laws and regulations.
We are subject to physical and financial risks associated with climate change and other weather, natural disaster and resource depletion impacts.
Climate change can create physical and financial risk. Physical risks include changes in weather conditions and extreme weather events.
Our customers’ energy needs vary with weather. To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease. Increased energy use due to weather changes may require us to invest in generating assets, transmission and infrastructure. Decreased energy use due to weather changes may result in decreased revenues.
Climate change may impact a region’s economy, which could impact our sales and revenues. The price of energy has an impact on the economic health of our communities. The cost of additional regulatory requirements, such as regulation of GHG, could impact the availability of goods and prices charged by our suppliers which would normally be borne by consumers through higher prices for energy and purchased goods. To the extent financial markets view climate change and emissions of GHGs as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less than ideal terms and conditions.
Severe weather impacts our service territories, primarily when thunderstorms, flooding, tornadoes, wildfires and snow or ice storms occur. Extreme weather conditions in general require system backup and can contribute to increased system stress, including service interruptions. Extreme weather conditions creating high energy demand may raise electricity prices, increasing the cost of energy we provide to our customers.

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To the extent the frequency of extreme weather events increases, this could increase our cost of providing service. Periods of extreme temperatures could impact our ability to meet demand. Changes in precipitation resulting in droughts or water shortages could adversely affect our operations. Drought conditions also contribute to the increase in wildfire risk from our electric generation facilities. While we carry liability insurance, given an extreme event, if 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, cause early retirement of units and increase the price paid for energy. We may not recover all costs related to mitigating these physical and financial risks.
ITEM 1B — UNRESOLVED STAFF COMMENTS
None.
ITEM 2 — PROPERTIES
Virtually all of the utility plant property of PSCo is subject to the lien of its first mortgage bond indenture.
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, 8 Units
 
Hydro
 
Various
 
25

 
Wind:
 
 
 
 
 
 
 
Rush Creek, CO, 300 units
 
Wind
 
2018
 
582

(g) 
 
 
 
 
Total
 
5,666

 
(a) 
Summer 2019 net dependable capacity.
(b) 
In 2018, the CPUC approved early retirement of PSCo’s Comanche Units 1 and 2 in 2022 and 2025, respectively.
(c) 
Based on PSCo’s ownership interest of 67%.
(d) 
Craig Unit 1 is expected to be retired early in 2025.
(e) 
Based on PSCo’s ownership interest of 10%.
(f) 
Based on PSCo’s ownership interest of 76% of Unit 1 and 37% of Unit 2.
(g) 
Values disclosed are the maximum generation levels for these wind units. Capacity is attainable only when wind conditions are sufficiently available (on-demand net dependable capacity is zero).
 
Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2019:
Conductor Miles
 
345 KV
5,036

230 KV
12,108

138 KV
92

115 KV
5,055

Less than 115 KV
79,740

PSCo had 233 electric utility transmission and distribution substations at Dec. 31, 2019.
Natural gas utility mains at Dec. 31, 2019:
Miles
 
Transmission
2,057

Distribution
22,633

ITEM 3 — LEGAL PROCEEDINGS
PSCo is involved in various litigation matters in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for losses probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, would have a material effect on PSCo’s financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred.
See Note 10 to the consolidated financial statements, Item 1 and Item 7 for further information. 
ITEM 4 — MINE SAFETY DISCLOSURES
None.
PART II
ITEM 5 — MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
PSCo is a wholly owned subsidiary of Xcel Energy Inc. and there is no market for its common equity securities.
See Note 5 to the consolidated financial statements for further information.
The dividends declared during 2019 and 2018 were as follows:
(Millions of Dollars)
 
2019
 
2018
First quarter
 
$
98.8

 
$
95.3

Second quarter
 
104.9

 
100.3

Third quarter
 
97.3

 
103.5

Fourth quarter
 
176.6

 
91.6


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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)(a) and (b) of Form 10-K for wholly owned subsidiaries. It is replaced with management’s narrative analysis and the results of operations for the current year as set forth in general instructions I(2)(a) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).
Non-GAAP Financial Measures
The following discussion includes financial information prepared in accordance with GAAP, as well as certain non-GAAP financial measures such as electric margin, natural gas margin 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 to the Board of Directors, in determining performance-based compensation and communicating its earnings outlook to analysts and investors. Non-GAAP financial measures are intended to supplement investors’ understanding of our performance and should not be considered alternatives for financial measures presented in accordance with GAAP. These measures are discussed in more detail below and may not be comparable to other companies’ similarly titled non-GAAP financial measures.
Electric and Natural Gas Margins
Electric margin is presented as electric revenues less electric fuel and purchased power expenses. Natural gas margin is presented as natural gas revenues less the cost of natural gas sold and transported. Expenses incurred for electric fuel and purchased power and the cost of natural gas are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues.
Management believes electric and natural gas margins provide the most meaningful basis for evaluating our operations because they exclude the revenue impact of fluctuations in these expenses.
These margins can be reconciled to operating income, a GAAP measure, by including other operating revenues, cost of sales-other, O&M expenses, conservation and DSM expenses, depreciation and amortization and taxes (other than income taxes).
Earnings Adjusted for Certain Items (Ongoing Earnings)
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. For the years ended Dec. 31, 2019 and Dec. 31, 2018, there were no adjustments to GAAP earnings and therefore GAAP earnings equal ongoing earnings.
 
Results of Operations
2019 Comparison to 2018
PSCo’s net income was $577.8 million for 2019, compared with $551.7 million for 2018. The increase was driven by higher electric and natural gas margins attributable to capital riders and lower income taxes, partially offset by lower AFUDC driven by the Rush Creek wind project that was placed in service in 2018 and higher depreciation, interest and O&M.
Electric 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. In addition, electric customers receive a credit for PTCs generated in a particular period.
Electric Revenues and Margin:
(Millions of Dollars)
 
2019
 
2018
Electric revenues
 
$
3,033.0

 
$
3,031.2

Electric fuel and purchased power
 
(1,083.0
)
 
(1,157.2
)
Electric margin
 
$
1,950.0

 
$
1,874.0

Changes in Electric Margin:
(Millions of Dollars)
 
2019 vs. 2018
Non-fuel riders
 
$
65.6

Finance leases (offset in interest expense and amortization)
 
21.9

Conservation incentive
 
6.1

Firm wholesale (includes formula rate true-ups)
 
6.0

Conservation and DSM riders (offset in expense)
 
(5.2
)
Wholesale transmission revenue (net of expense)
 
(4.8
)
Other (net)
 
11.9

Total increase in electric margin before TCJA impact
 
$
101.5

TCJA impact (offset in income tax and amortization)
 
(25.5
)
Total increase in electric margin
 
$
76.0

Natural Gas Margin
Total natural gas expense varies with changing sales requirements and the cost of natural gas. However, fluctuations in the cost of natural gas have minimal impact on natural gas margin due to cost recovery mechanisms.
Natural Gas Revenues and Margin:
(Millions of Dollars)
 
2019
 
2018
Natural gas revenues
 
$
1,160.9

 
$
1,014.6

Cost of natural gas sold and transported
 
(526.0
)
 
(428.4
)
Natural gas margin
 
$
634.9

 
$
586.2

Changes in Natural Gas Margin:
(Millions of Dollars)
 
2019 vs. 2018
Infrastructure and integrity riders
 
$
15.9

Estimated impact of weather
 
10.9

Transport sales
 
7.2

Retail sales growth (excluding weather impact)
 
5.7

Finance leases (offset in interest expense and amortization)
 
3.1

Other (net)
 
5.9

Total increase in natural gas margin
 
$
48.7


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Non-Fuel Operating Expenses and Other Items
O&M Expenses — O&M expenses increased $22.4 million, or 2.8%, for 2019, primarily driven by distribution and gas operations. Distribution costs were higher due to storms and labor incurred primarily in the first six months of the year. Gas operation expenses increased due to increased damage prevention locates driven by construction demands and increased pipeline maintenance costs.
DSM Program Expenses — DSM program expenses decreased $6.2 million, or 4.4%, for 2019, primarily due to prior period over-recovery. DSM expenses are generally recovered concurrently through riders and base rates. Timing of recovery may vary from when costs are incurred.
Taxes (Other than Income Taxes) — Taxes (other than income taxes) increased $4.6 million, or 2.3%, for 2019, primarily due to higher property taxes.
Depreciation and Amortization — Depreciation and amortization increased $41.3 million, or 7.4%, for 2019, primarily driven by the Rush Creek wind farm going into service, natural gas and distribution/transmission replacements and software solutions. These increases were partially offset by higher levels of accelerated amortization of the prepaid pension asset in 2018 and new common and gas depreciation rates.
AFUDC, Equity and Debt — AFUDC decreased by $45.7 million for 2019, primarily due to the Rush Creek wind farm being placed in-service in 2018 and other capital investments.
Interest Charges — Interest charges increased by $27.5 million, or 13.2%, for 2019, primarily due to higher debt levels to fund capital investments, changes in short-term interest rates and implementation of the lease accounting standard (offset in electric margin).
Income Taxes — Income taxes decreased $34.1 million for 2019, primarily driven by wind PTCs, partially offset by reduced AFUDC equity and reduced utility nonplant excess deferred tax amortization. Wind PTCs are credited to customers (recorded as a reduction to revenue) and do not have a material impact on net income. The ETR was 12.1% for 2019 compared with 17.1% for 2018. The lower ETR was primarily due to the items referenced above.
2018 Comparison with 2017
A discussion of changes in PSCo’s results of operations and liquidity and capital resources from the year ended Dec. 31, 2017 to Dec. 31, 2018 can be found in Part II, “Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our Annual Report on Form 10-K for the fiscal year 2018, which was filed with the SEC on Feb. 22, 2019. However, such discussion is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K.
Public Utility 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 North American Electric Reliability Corporation 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 public safety issues of interacting with our electric systems.
While programs to comply with regulatory requirements are in place, there is no guarantee compliance programs or other measures will be sufficient to ensure against violations. Decisions by these regulators can significantly impact PSCo’s results of operations.
See Rate Matters within Note 10 to the consolidated financial statements for further information.
Summary of Regulatory Agencies / RTO and Areas of Jurisdiction
Regulatory Body / RTO
 
Additional Information on Regulatory Authority
CPUC
 
Retail rates, accounts, services, issuance of securities and other aspects of electric and natural gas operations.
Pipeline safety compliance.
FERC
 
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.
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.
PSCo holds a FERC certificate that allows it to transport natural gas in interstate commerce without PSCo becoming subject to full FERC jurisdiction.
RTO
 
PSCo is not presently a member of an RTO and does not operate within an RTO energy market. However, PSCo does make certain sales to other RTO’s, including SPP and participates in a joint dispatch agreement with neighboring utilities.
DOT
 
Pipeline safety compliance.
Recovery Mechanisms
Mechanism
 
Additional Information
ECA
 
Recovers fuel and purchased energy costs. Short-term sales margins are shared with customers through the ECA. The ECA is revised quarterly.
PCCA
 
Recovers purchased capacity payments.
SCA
 
Recovers difference between actual fuel costs and costs recovered under steam service rates. The SCA rate is revised quarterly.
DSMCA
 
Recovers DSM, interruptible service costs and performance initiatives for achieving energy savings goals.
RESA
 
Recovers the incremental costs of compliance with the RES with a maximum of 2% of the customer’s bill.
WCA
 
Recovers costs for customers who choose renewable resources.
TCA
 
Recovers costs for transmission investment outside of rate cases.
CACJA
 
Recovers costs associated with the CACJA.
FCA
 
PSCo recovers fuel and purchased energy costs from wholesale electric customers through a fuel cost adjustment clause approved by the FERC. Wholesale customers pay production costs through a forecasted formula rate subject to true-up.
GCA
 
Recovers costs of purchased natural gas and transportation and is revised quarterly to allow for changes in natural gas rates.
PSIA
 
Recovers costs for transmission and distribution pipeline integrity management programs.

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Pending and Recently Concluded Regulatory Proceedings
Mechanism
 
Utility Service
 
Amount Requested
(in millions)
 
Filing
Date
 
Approval
 
Additional Information
CPUC
Rate Case
 
Steam
 
$7
 
January 2019
 
Received
 
In September 2019, the CPUC approved PSCo’s Settlement Agreement with CPUC Staff and the City of Denver. The settlement reflects an ROE of 9.67% for AFUDC purposes, an equity ratio of 56.04% and utilization of tax reform benefits. The first stepped increase went into effect Oct. 1, 2019, with full rates effective Oct. 1, 2020.
Rate Case Appeal
 
Natural Gas
 
N/A
 
April
2019
 
Pending
 
In April 2019, PSCo filed an appeal seeking judicial review of the CPUC’s prior ruling regarding PSCo’s last natural gas rate case (approved in December 2018). Appeal requests review of the following: denial of a return on the prepaid pension and retiree medical assets; the use of a capital structure that is not based on the actual historical test year level; and the use of an average rate base methodology rather than a year-end rate base methodology. Timeline on a final ruling is unknown.
DSM Incentive
 
Electric & Natural Gas
 
$12
 
April
2019
 
Received
 
PSCo earned an electric and natural gas DSM incentive of $9 million and $3 million, respectively, for achieving its 2018 savings goals.
Electric Rate Case — In October 2019, PSCo filed rebuttal testimony with the CPUC requesting a net rate increase of $108.4 million. This is based on a $353.3 million increase offset by $244.9 million of previously authorized costs currently recovered through various rider mechanisms. The request was based on a ROE of 10.20%, an equity ratio of 55.61% and a current test year, which includes certain forecasted plant additions through December 2019.
In December 2019, the CPUC held deliberations and on Feb. 11, 2020 issued a written decision approving a current test year ended Aug. 31, 2019, a 9.3% ROE, an equity ratio of 55.61%, implementation of decoupling in 2020 and other items. This resulted in an estimated $34.6 million net base rate revenue increase.
Revenue Request (Millions of Dollars)
 
2020
Company filed rebuttal
 
$
353.3

ROE
 
(55.3
)
Impact of change in test year
 
(17.1
)
Property tax expense
 
14.7

Rate base adjustments
 
(11.4
)
Capital structure
 
(4.7
)
     Total proposed revenue change
 
279.5

Estimated impact of previously authorized costs (existing riders)
 
244.9

Net revenue change
 
$
34.6

Final rates are expected to be implemented in February 2020. PSCo currently intends to file an application for rehearing/reconsideration in the first quarter of 2020.
Gas Rate Case — On Feb. 5, 2020, PSCo filed a request with the CPUC seeking a net increase to retail gas rates of $126.8 million, reflecting a $144.5 million increase in base rate revenue, which is partially offset by $17.7 million previously authorized through the PSIA rider mechanism. The request is based on a test year that incorporates actual capital and expenses as of Sept. 30, 2019, adjusted for known and measurable differences for the 12-month period ended Sept. 30, 2020, a 9.95% ROE and an equity ratio of 55.81%. Proposed effective date is Nov. 1, 2020.
 
Revenue Request (Millions of Dollars)
 
2020
Capital additions (through Sept. 30, 2019)
 
$
62.1

Forecasted capital additions (through Sept. 30, 2020)
 
33.0

Sales growth (includes amounts forecasted through Sept. 30, 2020)
 
(29.1
)
Operations and maintenance, amortization and other expenses
 
28.8

Property tax expense
 
18.9

Cost of capital
 
7.9

Updated depreciation rates
 
5.2

Net increase to revenue
 
126.8

Previously authorized costs:
 
 
Transfer PSIA rider costs to base rates
 
17.7

Total base request
 
$
144.5

 
 
 
Expected year-end rate base
 
$
2,236.4

The request reflects $1.3 billion of capital additions since the 2016 test year used to set current rates. Capital investments are made to maintain the safety and reliability of the natural gas system, along with investments to connect new customers and perform mandated infrastructure relocation work.
Timing of a CPUC ruling is expected in the second half of 2020.
Resource Plan
CEP — In September 2018, the CPUC approved PSCo’s CEP portfolio, which included the retirement of two coal-fired generation units, Comanche Unit 1 (in 2022) and Comanche Unit 2 (in 2025), and the following additions:
 
Total Capacity
 
PSCo's Ownership
Wind generation
1,100 MW
 
500 MW

Solar generation
700 MW
 
—

Battery storage
275 MW
 
—

Natural gas generation
380 MW
 
380 MW

PSCo’s investment is expected to be approximately $1 billion, including transmission to support the increase in renewable generation.
CPCNs were granted by the CPUC for the Shortgrass Substation in February 2019, and for the 500 MW Cheyenne Ridge wind farm and 345 KV generation tie line in April 2019.
A CPCN for the acquisitions of the Valmont and Manchief natural gas generation facilities was filed in July 2019, and a settlement on those acquisitions was reached with CPUC Staff and the Colorado Office of Consumer Counsel in January 2020, pending a CPUC decision expected in approximately the second quarter of 2020.

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A CPCN for voltage control facilities was also filed with the CPUC in December 2019, with another expected to follow in approximately the first quarter of 2020 for network transmission upgrades required for the CEP portfolio.
Purchased Power and Transmission Service Providers
PSCo expects to meet its system capacity requirements through electric generating stations, power purchases, new generation facilities, DSM options and expansion of generation plants.
Purchased Power — PSCo purchases power from other utilities and IPPs. Long-term purchased power contracts for dispatchable resources typically require capacity and energy charges. It also contracts to purchase power for both wind and solar resources. PSCo makes short-term purchases to meet system load and energy requirements, replace owned generation, meet operating reserve obligations, or obtain energy at a lower cost.
Purchased Transmission Services — In addition to using its own transmission system, PSCo has contracts with regional transmission service providers to deliver energy to its customers.
Boulder Municipalization
In 2011, Boulder passed a ballot measure authorizing the formation of an electric municipal utility, subject to certain conditions. Subsequently, there have been various legal proceedings in multiple venues with jurisdiction over Boulder’s plan. In 2014, the Boulder City Council passed an ordinance to establish an electric utility. PSCo challenged the formation of this utility and the Colorado Court of Appeals ruled in PSCo’s favor, vacating a lower court decision. In June 2018, the Colorado Supreme Court rejected Boulder’s request to dismiss the case and remanded it to the Boulder District Court. The case was then settled in June 2019 after Boulder agreed to repeal the ordinance establishing the utility.
Boulder has filed multiple separation applications with the CPUC, which have been challenged by PSCo and other intervenors. In September 2017, the CPUC issued a written decision, agreeing with several key aspects of PSCo’s position. The CPUC has approved the designation of some electrical distribution assets for transfer, subject to Boulder completing certain filings. In the fourth quarter of 2018, the Boulder City Council also adopted an Ordinance authorizing Boulder to begin negotiations for the acquisition of certain property or to otherwise condemn that property after Feb. 1, 2019. In the first quarter of 2019, Boulder sent PSCo a notice of intent to acquire certain electric distribution assets. In the third quarter of 2019, Boulder filed its condemnation litigation, which was later dismissed by the Boulder District Court in September 2019 on the grounds that Boulder had not completed the pre-requisite CPUC process and filings. Boulder is currently appealing this order. In October 2019, the CPUC approved the subsequent filings regarding asset transfers outside of substations, reaffirmed its 2017 decision on assets outside of substations and closed the CPUC proceeding. In December 2019, Boulder filed a new condemnation action despite its ongoing appeal of the last condemnation case. PSCo subsequently filed a motion to dismiss or stay the new condemnation action. In February 2020, Boulder filed an application under section 210 of the Federal Power Act asking FERC to order PSCo to interconnect its facilities with a future Boulder municipal utility under Boulder’s preferred terms and conditions.
 
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. Sharing of any margin is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement.
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 8 to the consolidated financial statements for further 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, 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 non-performance risk.
Distress in the financial markets may impact counterparty risk, the fair value of the securities in the pension fund and PSCo’s ability to earn a return on short-term 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 and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products and fuels used in generation and distribution activities. Commodity price risk is also managed through the use of financial derivative instruments. 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.
Fair value of net commodity trading contracts as of Dec. 31, 2019:
 
Futures / Forwards Maturity
(Millions of Dollars)
 
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 (a)
 
$
(4.5
)
 
$
(21.8
)
 
$
(30.7
)
 
$
—

 
$
(57.0
)
(a) 
Prices based on models and other valuation methods.

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Changes in the fair value of commodity trading contracts before the impacts of margin-sharing for the years ended Dec. 31:
(Millions of Dollars)
 
2019
 
2018
Fair value of commodity trading net contract assets outstanding at Jan. 1
 
$
1.3

 
$
0.5

Contracts realized or settled during the period
 
(10.9
)
 
(7.8
)
Commodity trading contract additions and changes during the period
 
(47.4
)
 
8.6

Fair value of commodity trading net contract assets outstanding at Dec. 31
 
$
(57.0
)
 
$
1.3

At Dec. 31, 2019, a 10% increase in market prices for commodity trading contracts would increase pretax income by approximately $3.3 million, whereas a 10% decrease would decrease pretax income by approximately $3.3 million. 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.
PSCo’s wholesale and commodity trading operations measure the outstanding risk exposure to price changes on transactions, contracts and obligations using 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. 
VaRs for the NSP-Minnesota and PSCo commodity trading operations, calculated on a consolidated basis using a Monte Carlo simulation with a 95% confidence level and a one-day holding period, were as follows:
(Millions of Dollars)
 
Year Ended
Dec. 31
 
VaR Limit
 
Average
 
High
 
Low
2019
 
$
0.4

 
$
3.0

 
$
0.6

 
$
0.8

 
$
0.3

2018
 
4.8

 
6.0

 
0.6

 
5.6

 
0.1

Interest Rate Risk — PSCo is subject to interest 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.
A 100 basis point change in the benchmark rate on PSCo’s variable rate debt would impact annual pretax interest expense by approximately $0.4 million in 2019 and $3.1 million in 2018.
See Note 8 to the consolidated financial statements for 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, 2019, a 10% increase in commodity prices would have resulted in a decrease in credit exposure of $3.1 million, while a decrease in prices of 10% would have resulted in an increase in credit exposure of $7.2 million. 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.
PSCo conducts credit reviews for all counterparties and employs credit risk controls, such as letters of credit, parental guarantees, master netting agreements and termination provisions. Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. Distress in the financial markets could increase PSCo’s credit risk.
Fair Value Measurements
PSCo uses derivative contracts such as futures, forwards, interest rate swaps and 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 accounting.
See Notes 8 and 9 to the consolidated financial statements for further 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. Given 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, 2019. 
Adjustments to fair value for credit risk of commodity trading instruments are recorded in electric revenues. Credit risk adjustments for other commodity derivative instruments are 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 at Dec. 31, 2019.
ITEM 8 — FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
See Item 15-1 for an index of financial statements included herein.
See Note 14 to the consolidated financial statements for further information.

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Management Report on Internal Control 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.
PSCo management assessed the effectiveness of PSCo’s internal control over financial reporting as of Dec. 31, 2019. 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, 2019, 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, Chief Executive Officer and Director
 
Executive Vice President, Chief Financial Officer and Director
Feb. 21, 2020
 
Feb. 21, 2020

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Table of Contents


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholder and Board of Directors 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") as of December 31, 2019 and 2018, the related consolidated statements of income, comprehensive income, cash flows and common stockholder's equity, for each of the three years in the period ended December 31, 2019, 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, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, 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 21, 2020
 
We have served as the Company’s auditor since 2002.

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Table of Contents

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(amounts in millions)
 
 
Year Ended Dec. 31
 
 
2019
 
2018
 
2017
Operating revenues
 
 
 
 
 
 
Electric
 
$
3,033.0

 
$
3,031.2

 
$
3,003.8

Natural gas
 
1,160.9

 
1,014.6

 
995.2

Steam and other
 
43.3

 
40.4

 
43.5

Total operating revenues
 
4,237.2

 
4,086.2

 
4,042.5

 
 
 
 
 
 
 
Operating expenses
 
 
 
 
 
 
Electric fuel and purchased power
 
1,083.0

 
1,157.2

 
1,126.7

Cost of natural gas sold and transported
 
526.0

 
428.4

 
458.7

Cost of sales — steam and other
 
16.6

 
15.3

 
16.1

Operating and maintenance expenses
 
809.9

 
787.5

 
760.8

Demand side management expenses
 
136.0

 
142.2

 
125.0

Depreciation and amortization
 
602.4

 
561.1

 
471.5

Taxes (other than income taxes)
 
206.5

 
201.9

 
195.7

Total operating expenses
 
3,380.4

 
3,293.6

 
3,154.5

 
 
 
 
 
 
 
Operating income
 
856.8

 
792.6

 
888.0

 
 
 
 
 
 
 
Other income, net
 
3.1

 
2.1

 
7.8

Allowance for funds used during construction — equity
 
21.7

 
56.4

 
29.8

 
 
 
 
 
 
 
Interest charges and financing costs
 
 
 
 
 
 
Interest charges — includes other financing costs of $6.6, $6.5 and $6.3, respectively
 
235.4

 
207.9

 
190.7

Allowance for funds used during construction — debt
 
(11.2
)
 
(22.2
)
 
(11.4
)
Total interest charges and financing costs
 
224.2

 
185.7

 
179.3

 
 
 
 
 
 
 
Income before income taxes
 
657.4

 
665.4

 
746.3

Income taxes
 
79.6

 
113.7

 
252.2

  Net income
 
$
577.8

 
$
551.7

 
$
494.1


See Notes to Consolidated Financial Statements

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Table of Contents

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(amounts in millions)
 
 
Year Ended Dec. 31
 
 
2019
 
2018
 
2017
Net income
 
$
577.8

 
$
551.7

 
$
494.1

 
 
 
 
 
 
 
Other comprehensive (loss) income
 
 
 
 
 
 
 
 
 
 
 
 
 
Defined pension and other postretirement benefits:
 
 
 
 
 
 
Net pension and retiree medical gain arising during the period, net of tax of $0.1, $0 and $0, respectively
 
0.4

 
—

 
—

Reclassification of gain to net income, net of tax of $(0.9), $0 and $0, respectively
 
(2.7
)
 
—

 
—

Derivative instruments:
 
 
 
 
 
 
Reclassification of loss to net income, net of tax of $0.4, $0.4 and $0.6, respectively
 
1.2

 
1.2

 
1.0

 
 
 
 
 
 
 
Other comprehensive (loss) income
 
(1.1
)
 
1.2

 
1.0

Comprehensive income
 
$
576.7

 
$
552.9

 
$
495.1


See Notes to Consolidated Financial Statements


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Table of Contents

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(amounts in millions)
 
Year Ended Dec. 31
 
2019
 
2018
 
2017
Operating activities
 
 
 
 
 
Net income
$
577.8

 
$
551.7

 
$
494.1

Adjustments to reconcile net income to cash provided by operating activities:
 
 
 
 
 
Depreciation and amortization
607.0

 
566.1

 
475.6

Deferred income taxes
97.0

 
23.8

 
207.8

Allowance for equity funds used during construction
(21.7
)
 
(56.4
)
 
(29.8
)
Provision for bad debts
16.5

 
16.4

 
14.3

Net realized and unrealized hedging and derivative transactions
62.1

 
(6.2
)
 
2.4

Changes in operating assets and liabilities:
 
 
 
 
 
Accounts receivable
(21.5
)
 
(42.8
)
 
(2.2
)
Accrued unbilled revenues
19.6

 
(17.7
)
 
1.3

Inventories
(27.0
)
 
(20.1
)
 
(9.1
)
Prepayments and other
(29.0
)
 
12.8

 
0.2

Accounts payable
(44.0
)
 
68.7

 
20.4

Net regulatory assets and liabilities
34.9

 
(14.6
)
 
(22.6
)
Other current liabilities
(0.1
)
 
(12.9
)
 
71.8

Pension and other employee benefit obligations
(47.0
)
 
(44.2
)
 
(16.5
)
Other, net
3.3

 
(16.3
)
 
(5.9
)
Net cash provided by operating activities
1,227.9

 
1,008.3

 
1,201.8

 
 
 
 
 
 
Investing activities
 
 
 
 
 
Utility capital/construction expenditures
(1,690.7
)
 
(1,577.2
)
 
(1,445.9
)
Investments in utility money pool arrangement
(641.0
)
 
(634.0
)
 
(954.0
)
Repayments from utility money pool arrangement
641.0

 
654.0

 
934.0

Other, net
—

 
—

 
(0.7
)
Net cash used in investing activities
(1,690.7
)
 
(1,557.2
)
 
(1,466.6
)
 
 
 
 
 
 
Financing activities
 
 
 
 
 
(Repayments of) proceeds from short-term borrowings, net
(307.0
)
 
307.0

 
(129.0
)
Borrowings under utility money pool arrangement
100.0

 
780.0

 
40.0

Repayments under utility money pool arrangement
(61.0
)
 
(780.0
)
 
(40.0
)
Proceeds from issuance of long-term debt
928.2

 
691.1

 
393.8

Repayments of long-term debt
(400.0
)
 
(300.0
)
 
—

Capital contributions from parent
638.2

 
252.1

 
335.6

Dividends paid to parent
(457.6
)
 
(375.3
)
 
(333.9
)
   Other, net
—

 
(0.1
)
 
(0.1
)
Net cash provided by financing activities
440.8

 
574.8

 
266.4

 
 
 
 
 
 
Net change in cash, cash equivalents and restricted cash
(22.0
)
 
25.9

 
1.6

Cash, cash equivalents and restricted cash at beginning of period
33.4

 
7.5

 
5.9

Cash, cash equivalents and restricted cash at end of period
$
11.4

 
$
33.4

 
$
7.5

 
 
 
 
 
 
Supplemental disclosure of cash flow information:
 
 
 
 
 
Cash paid for interest (net of amounts capitalized)
$
(209.3
)
 
$
(187.2
)
 
$
(175.0
)
Cash paid for income taxes, net
(4.7
)
 
(115.8
)
 
(7.7
)
Supplemental disclosure of non-cash investing transactions:
 
 
 
 
 
Accrued property, plant and equipment additions
$
233.8

 
$
142.1

 
$
199.1

Inventory transfers to property, plant and equipment
32.4

 
37.2

 
26.6

Operating lease right-of-use assets
653.8

 
—

 
—

Allowance for equity funds used during construction
21.7

 
56.4

 
29.8

 
 
 
 
 
 
See Notes to Consolidated Financial Statements

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Table of Contents

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(amounts in millions, except share and per share)
 
 
Dec. 31
 
 
2019
 
2018
Assets
 
 
 
 
Current assets
 
 
 
 
Cash and cash equivalents
 
$
11.4

 
$
33.4

Accounts receivable, net
 
303.9

 
310.3

Accounts receivable from affiliates
 
52.7

 
80.8

Accrued unbilled revenues
 
293.9

 
313.5

Inventories
 
192.0

 
197.4

Regulatory assets
 
64.0

 
120.6

Derivative instruments
 
7.2

 
42.6

Prepayments and other
 
55.9

 
23.8

Total current assets
 
981.0

 
1,122.4

 
 
 
 
 
Property, plant and equipment, net
 
16,155.0

 
15,120.0

 
 
 
 
 
Other assets
 
 

 
 

Regulatory assets
 
1,038.1

 
1,010.7

Derivative instruments
 
—

 
1.2

Operating lease right-of-use assets
 
574.0

 
—

Other
 
259.4

 
37.2

Total other assets
 
1,871.5

 
1,049.1

Total assets
 
$
19,007.5

 
$
17,291.5

 
 
 
 
 
Liabilities and Equity
 
 

 
 

Current liabilities
 
 

 
 

Current portion of long-term debt
 
$
400.0

 
$
406.2

Borrowings under utility money pool arrangement
 
39.0

 
—

Short-term debt
 
—

 
307.0

Accounts payable
 
573.3

 
503.4

Accounts payable to affiliates
 
43.9

 
46.0

Regulatory liabilities
 
69.2

 
67.3

Taxes accrued
 
202.1

 
202.0

Accrued interest
 
53.4

 
43.2

Dividends payable to parent
 
111.5

 
91.5

Derivative instruments
 
8.7

 
34.6

Operating lease liabilities
 
85.8

 
—

Other
 
98.8

 
101.5

Total current liabilities
 
1,685.7

 
1,802.7

 
 
 
 
 
Deferred credits and other liabilities
 
 

 
 

Deferred income taxes
 
1,850.8

 
1,719.3

Deferred investment tax credits
 
22.8

 
25.3

Regulatory liabilities
 
2,036.8

 
2,021.5

Asset retirement obligations
 
324.0

 
338.7

Derivative instruments
 
52.5

 
0.6

Customer advances
 
173.6

 
168.1

Pension and employee benefit obligations
 
211.9

 
275.3

Operating lease liabilities
 
517.6

 
—

Other
 
150.9

 
50.4

Total deferred credits and other liabilities
 
5,340.9

 
4,599.2

 
 
 
 
 
Commitments and contingencies
 


 


Capitalization
 
 

 
 

Long-term debt
 
4,984.7

 
4,591.4

Common stock — 100 shares authorized at $0.01 par value; 100 shares
outstanding at Dec. 31, 2019 and 2018, respectively
 
—

 
—

Additional paid in capital
 
4,939.4

 
4,340.5

Retained earnings
 
2,083.4

 
1,983.2

Accumulated other comprehensive loss
 
(26.6
)
 
(25.5
)
Total common stockholder’s equity
 
6,996.2

 
6,298.2

Total liabilities and equity
 
$
19,007.5

 
$
17,291.5

 
See Notes to Consolidated Financial Statements



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Table of Contents

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
(amounts in millions, except share data)
 
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, 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

 
 
 
 
 
 
 
 
 
 
 
 
Net income
 
 
 
 
 
 
577.8

 
 
 
577.8

Other comprehensive income
 
 
 
 
 
 
 
 
(1.1
)
 
(1.1
)
Common dividends declared to parent
 
 
 
 
 
 
(477.6
)
 
 
 
(477.6
)
Contribution of capital by parent
 
 
 
 
598.9

 
 
 
 
 
598.9

Balance at Dec. 31, 2019
100

 
$
—

 
$
4,939.4

 
$
2,083.4

 
$
(26.6
)
 
$
6,996.2

 
 
 
 
 
 
 
 
 
 
 
 
See Notes to Consolidated Financial Statements



25
Table of Contents

Notes to Consolidated Financial Statements
1. Summary of Significant Accounting Policies
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 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. 
PSCo’s consolidated financial statements 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. Certain amounts in the 2018 and 2017 consolidated financial statements or notes have been reclassified to conform to the 2019 presentation for comparative purposes; however, such reclassifications did not affect net income, total assets, liabilities, equity or cash flows.
PSCo has evaluated events occurring after Dec. 31, 2019 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation.
Use of Estimates — PSCo uses estimates based on the best information available in recording transactions and balances resulting from business operations. Estimates are used on items such 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. Recorded estimates are revised when better information becomes available or actual amounts can be determined. Revisions can affect operating results.
Regulatory Accounting — PSCo accounts for 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 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 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 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 results of operations, financial condition and cash flows. 
See Note 4 for further information.
 
Income Taxes — PSCo accounts for income taxes using the asset and liability method, which requires recognition of 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 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.
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 regulatory assets and liabilities related to income taxes. 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.
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 expense.
PSCo reports interest and penalties related to income taxes within the other income and interest charges in the consolidated statements of income.
Xcel Energy Inc. and its subsidiaries, including PSCo, file consolidated federal income tax returns as well as 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 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 7 for further information.
Property, Plant and Equipment and Depreciation in Regulated Operations — 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 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.

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Table of Contents

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 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 2.9% in 2019, 2.6% in 2018 and 2.7% in 2017.
See Note 3 for further 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 consolidated balance sheets as a regulatory liability.
See Note 10 for further information.
Benefit Plans and Other Postretirement Benefits — PSCo maintains pension and postretirement benefit plans for eligible employees. Recognizing the cost of providing benefits and measuring the projected benefit obligation of these plans requires management to make various assumptions and estimates.
Certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are deferred as regulatory assets and liabilities, rather than recorded as other comprehensive income, based on regulatory recovery mechanisms.
See Note 9 for further 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 are regularly adjusted as estimates are revised and remediation proceeds. If other participating 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. 
 
Future costs of restoring sites are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses. Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability.
See Note 10 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 6 for further information.
Cash and Cash Equivalents — PSCo considers investments in instruments 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.
As of Dec. 31, 2019 and 2018, the allowance for bad debts was $21.0 million and $20.5 million, respectively.
Inventory — Inventory is recorded at average cost and consisted of the following:
(Millions of Dollars)
 
Dec. 31, 2019
 
Dec. 31, 2018
Inventories
 
 
 
 
Materials and supplies
 
$
62.6

 
$
61.9

Fuel
 
77.1

 
69.5

Natural gas
 
52.3

 
66.0

Total inventories
 
$
192.0

 
$
197.4


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 8 and 9 for further information.

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Table of Contents

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.
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. 
Normal Purchases and Normal Sales — PSCo enters into contracts for purchases and sales of commodities for 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 8 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 8 for further information.
Other Utility Items
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 rates.
Alternative Revenue — Certain rate rider mechanisms (including DSM programs) qualify as alternative revenue programs. These mechanisms arise from costs imposed upon the utility by action of a regulator or legislative body related to an environmental, public safety or other mandate. When certain criteria are met, including expected 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 total amount collected and revenue earned, which may increase or decrease the level of revenue collected from customers. Alternative revenues arising from these programs are presented on a gross basis and disclosed separately from revenue from contracts with customers.
See Note 6 for further information.
 
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, as well as approximately 23 DSM products, pilots and services for residential and low-income customers. Overall, the DSM portfolio provides rebates and/or incentives 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. 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 have not yet been collected from customers.
Emission Allowances — Emission allowances are recorded at cost, including broker commission fees. The inventory accounting model is utilized for all emission allowances and sales of these allowances are included in electric revenues.
RECs — Cost of RECs that are utilized for compliance is recorded as electric fuel and purchased power expense. PSCo records that 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. 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
Credit Losses — In 2016, the FASB issued Financial Instruments - Credit Losses, Topic 326 (ASC Topic 326), which changes how entities account for losses on receivables and certain other assets. The guidance requires use of a current expected credit loss model, which may result in earlier recognition of credit losses than under previous accounting standards. ASC Topic 326 is effective for interim and annual periods beginning on or after Dec. 15, 2019 and will be applied using a modified-retrospective approach, with a cumulative-effect adjustment to retained earnings as of Jan. 1, 2020. PSCo expects the impact of adoption of the new standard to include first-time recognition of expected credit losses (i.e., bad debt expense) on unbilled revenues, with the initial allowance established at Jan. 1, 2020 charged to retained earnings. Recognition of this allowance and other impacts of adoption are expected to be immaterial to the consolidated financial statements.
Recently Adopted
Leases — In 2016, the FASB issued Leases, Topic 842 (ASC Topic 842), which provides new accounting and disclosure guidance for leasing activities, most significantly requiring that operating leases be recognized on the balance sheet. PSCo adopted the guidance on Jan. 1, 2019 utilizing the package of transition practical expedients provided by the new standard, including carrying forward prior conclusions on whether agreements existing before the adoption date contain leases and whether existing leases are operating or finance leases; ASC Topic 842 refers to capital leases as finance leases.

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Table of Contents

Specifically for land easement contracts, PSCo has elected the practical expedient provided by ASU No. 2018-01 Leases: Land Easement Practical Expedient for Transition to Topic 842, and as a result, only those easement contracts entered on or after Jan. 1, 2019 will be evaluated to determine if lease treatment is appropriate.
PSCo also utilized the transition practical expedient offered by ASU No. 2018-11 Leases: Targeted Improvements to implement the standard on a prospective basis. As a result, reporting periods in the consolidated financial statements beginning Jan. 1, 2019 reflect the implementation of ASC Topic 842, while prior periods continue to be reported in accordance with Leases, Topic 840 (ASC Topic 840). Other than first-time recognition of operating leases on its consolidated balance sheet, the implementation of ASC Topic 842 did not have a significant impact on PSCo’s consolidated financial statements. Adoption resulted in recognition of approximately $0.7 billion of operating lease ROU assets and current/noncurrent operating lease liabilities.
See Note 10 for leasing disclosures.
3. Plant, Property and Equipment

Major classes of property, plant and equipment
(Millions of Dollars)
 
Dec. 31, 2019
 
Dec. 31, 2018
Property, plant and equipment, net
 
 
 
 
Electric plant
 
$
14,361.9

 
$
13,604.5

Natural gas plant
 
4,631.4

 
4,387.6

Common and other property
 
1,113.5

 
1,023.7

Plant to be retired (a)
 
259.9

 
321.9

CWIP
 
912.7

 
573.3

Total property, plant and equipment
 
21,279.4

 
19,911.0

Less accumulated depreciation
 
(5,124.4
)
 
(4,791.0
)
Property, plant and equipment, net
 
$
16,155.0

 
$
15,120.0


(a) 
In 2018, the CPUC approved early retirement of PSCo’s Comanche Units 1 and 2 in approximately 2022 and 2025, respectively. PSCo also expects Craig Unit 1 to be retired early in 2025. Amounts are presented net of accumulated depreciation.
 
Joint Ownership of Generation, Transmission and Gas Facilities
Jointly owned assets as of Dec. 31, 2019:
(Millions of Dollars)
 
Plant in
Service
 
Accumulated
Depreciation
 
CWIP
 
Percent Owned
Electric generation:
 
 
 
 
 
 
 
 
Hayden Unit 1
 
$
152.5

 
$
80.9

 
$
0.2

 
76
%
Hayden Unit 2
 
149.0

 
70.8

 
0.2

 
37

Hayden common facilities
 
41.4

 
22.0

 
—

 
53

Craig Units 1 and 2
 
80.9

 
41.4

 
0.3

 
10

Craig common facilities
 
39.1

 
21.7

 
0.1

 
7

Comanche Unit 3
 
886.7

 
148.6

 
0.6

 
67

Comanche common facilities
 
28.9

 
3.0

 
0.1

 
82

Electric transmission:
 
 
 
 
 
 
 
 
Transmission and other facilities
 
173.7

 
61.7

 
0.9

 
Various

Gas transmission:
 
 
 
 
 
 
 
 
Rifle, CO to Avon, CO
 
22.2

 
7.4

 
—

 
60

   Gas transmission compressor
 
8.5

 
1.0

 
—

 
50

Total
 
$
1,582.9

 
$
458.5

 
$
2.4

 
 

PSCo’s share of operating expenses and construction expenditures is 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, 2019
 
Dec. 31, 2018
Regulatory Assets
 
 
 
 
 
Current
 
Noncurrent
 
Current
 
Noncurrent
Pension and retiree medical obligations
 
9

 
Various
 
$
22.7

 
$
493.6

 
$
26.1

 
$
559.0

Depreciation differences
 
 
 
One to twelve years
 
14.6

 
139.6

 
17.5

 
107.0

Net AROs (a)
 
1, 10

 
Plant lives
 
—

 
119.0

 
—

 
98.9

Recoverable deferred taxes on AFUDC recorded in plant 
 
 
 
Plant lives
 
—

 
104.7

 
—

 
101.9

Excess deferred taxes — TCJA
 
7

 
Various
 
3.2

 
55.3

 
—

 
62.0

Property tax
 
 
 
Various
 
1.4

 
30.4

 
5.6

 
9.8

Purchased power contract costs
 
 
 
Term of related contract
 
2.1

 
24.3

 
1.7

 
26.3

Conservation programs (b)
 
1

 
One to two years
 
8.4

 
11.0

 
7.3

 
6.5

Gas pipeline inspection costs
 
 
 
One to two years
 
—

 
7.9

 
0.7

 
3.1

Losses on reacquired debt
 
 
 
Term of related debt
 
1.1

 
4.2

 
1.2

 
3.7

Contract valuation adjustments (c)
 
1, 8

 
Term of related contract
 
3.4

 
—

 
2.6

 
—

Recoverable purchased natural gas and electric energy costs
 
 
 
Less than one year
 
—

 
—

 
51.2

 
—

Other
 
 
 
Various
 
7.1

 
48.1

 
6.7

 
32.5

Total regulatory assets
 
 
 
 
 
$
64.0

 
$
1,038.1

 
$
120.6

 
$
1,010.7


(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.

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Table of Contents

Components of regulatory liabilities:
(Millions of Dollars)
 
See Note(s)
 
Remaining Amortization Period
 
Dec. 31, 2019
 
Dec. 31, 2018
Regulatory Liabilities
 
 
 
 
 
Current
 
Noncurrent
 
Current
 
Noncurrent
Deferred income tax adjustments and TCJA refunds (a)
 
7
 
Various
 
$
4.8

 
$
1,403.2

 
$
0.8

 
$
1,441.6

Plant removal costs
 
1, 10
 
Plant lives
 
—

 
350.8

 
—

 
344.4

Effects of regulation on employee benefit costs (b)
 
 
 
Various
 
—

 
183.2

 
—

 
126.9

Renewable resources and environmental initiatives
 
 
 
Various
 
—

 
44.9

 
—

 
54.0

ITC deferrals (c)
 
1
 
Various
 
—

 
26.1

 
—

 
27.5

Deferred electric, natural gas and steam production costs
 
 
 
Less than one year
 
7.7

 
—

 
7.2

 
—

Conservation programs (d)
 
1
 
Less than one year
 
30.2

 
—

 
29.8

 
—

Other
 
 
 
Various
 
26.5

 
28.6

 
29.5

 
27.1

Total regulatory liabilities (e)
 
 
 
 
 
$
69.2

 
$
2,036.8

 
$
67.3

 
$
2,021.5

(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 2018 TCJA benefits approved by the CPUC to offset the prepaid pension asset.
(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 for 2018 was included in other current liabilities and none for 2019.
At Dec. 31, 2019 and 2018, PSCo’s regulatory assets not earning a return primarily included the unfunded portion of pension and retiree medical obligations and net AROs. In addition, PSCo’s regulatory assets included $160.0 million and $188.7 million at Dec. 31, 2019 and 2018, respectively, of past expenditures not earning a return. Amounts primarily related to funded pension obligations, property taxes, various renewable resources and certain environmental initiatives.
5. Borrowings and Other Financing Instruments
Short-Term Borrowings
PSCo meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility and the money pool.
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.
Money pool borrowings for PSCo were as follows:
(Millions of Dollars, Except Interest Rates)
 
Three Months Ended Dec. 31, 2019
 
Year Ended Dec. 31
 
 
2019
 
2018
 
2017
Borrowing limit
 
$
250

 
$
250

 
$
250

 
$
250

Amount outstanding at period end
 
39

 
39

 
—

 
—

Average amount outstanding
 
—

 
7

 
25

 
—

Maximum amount outstanding
 
39

 
50

 
156

 
20

Weighted average interest rate, computed on a daily basis
 
1.63
%
 
2.29
%
 
1.93
%
 
0.92
%
Weighted average interest rate at end of period
 
1.63

 
1.63

 
N/A

 
N/A


Commercial Paper — Commercial paper borrowings for PSCo were as follows:
(Millions of Dollars, Except Interest Rates)
 
Three Months Ended Dec. 31, 2019
 
Year Ended Dec. 31
 
 
2019
 
2018
 
2017
Borrowing limit
 
$
700

 
$
700

 
$
700

 
$
700

Amount outstanding at period end
 
—

 
—

 
307

 
—

Average amount outstanding
 
—

 
154

 
55

 
54

Maximum amount outstanding
 
—

 
432

 
309

 
268

Weighted average interest rate, computed on a daily basis
 
N/A

 
2.67
%
 
2.28
%
 
1.08
%
Weighted average interest rate at end of period
 
N/A

 
N/A

 
2.95

 
N/A


 
Letters of Credit — PSCo uses letters of credit, typically with terms of one year, to provide financial guarantees for certain operating obligations. As of Dec. 31, 2019 and 2018, there were $9 million and $10 million letters of credit outstanding, respectively under the credit facility. The contract amounts of these letters of credit approximate their fair value and are subject to fees.
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.
Amended Credit Agreement — In June 2019, PSCo entered into an amended five-year credit agreement with a syndicate of banks. The amended credit agreements have substantially the same terms and conditions as the prior credit agreements with the exception of the maturity, which was extended from June 2021 to June 2024.
Features of PSCo’s credit facility:
Debt-to-Total Capitalization Ratio(a)
 
Amount Facility May Be Increased (millions)
 
Additional Periods for Which a One-Year Extension May Be Requested (b)
2019
 
2018
 
 
 
 
44
%
 
46
%
 
$
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 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 indebtedness in an aggregate principal amount exceeding $75 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, 2019, PSCo was in compliance with all financial covenants.

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PSCO had the following committed credit facilities available as of Dec. 31, 2019 (millions):
Credit Facility (a)
 
Drawn (b)
 
Available
$
700

 
$
9

 
$
691


(a) 
This credit facility matures in June 2024.
(b) 
Includes letters of 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 facility outstanding at Dec. 31, 2019 and 2018.
Long-Term Borrowings and Other Financing Instruments
Generally, 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 for refinanced debt are deferred and amortized over the life of the new issuance.
Long-term debt obligations for PSCo as of Dec. 31 (millions of dollars):
Financing Instrument
 
Interest Rate
 
Maturity Date
 
2019
 
2018
First mortgage bonds (d)
 
5.13
%
 
June 1, 2019
 
$
—

 
$
400

First mortgage bonds
 
3.20

 
Nov. 15, 2020
 
400

 
400

First mortgage bonds
 
2.25

 
Sept. 15, 2022
 
300

 
300

First mortgage bonds
 
2.50

 
March 15, 2023
 
250

 
250

First mortgage bonds
 
2.90

 
May 15, 2025
 
250

 
250

First mortgage bonds (b)
 
3.70

 
June 15, 2028
 
350

 
350

First mortgage bonds
 
6.25

 
Sept. 1, 2037
 
350

 
350

First mortgage bonds
 
6.50

 
Aug. 1, 2038
 
300

 
300

First mortgage bonds
 
4.75

 
Aug. 15, 2041
 
250

 
250

First mortgage bonds
 
3.60

 
Sept. 15, 2042
 
500

 
500

First mortgage bonds
 
3.95

 
March 15, 2043
 
250

 
250

First mortgage bonds
 
4.30

 
March 15, 2044
 
300

 
300

First mortgage bonds
 
3.55

 
June 15, 2046
 
250

 
250

First mortgage bonds
 
3.80

 
June 15, 2047
 
400

 
400

First mortgage bonds (b)
 
4.10

 
June 15, 2048
 
350

 
350

First mortgage bonds (a)
 
4.05

 
Sept. 15, 2049
 
400

 
—

First mortgage bonds (a)
 
3.20

 
March 1, 2050
 
550

 
—

Capital lease obligations (c)
 
11.20 - 14.30

 
2025-2060
 
—

 
145

Unamortized discount
 
 
 
 
 
(24
)
 
(14
)
Unamortized debt issuance cost
 
 
 
 
 
(41
)
 
(33
)
Current maturities
 
 
 
 
 
(400
)
 
(406
)
Total long-term debt
 
 
 
 
 
$
4,985

 
$
4,592


(a) 
2019 financing.
(b) 
2018 financing.
(c) 
PSCo adopted ASC 842 on Jan. 1, 2019, which refers to capital leases as finance leases. Under ASC 842, the present value of future finance lease payments is included in other current liabilities and other noncurrent liabilities rather than debt.
(d) 
Bond was redeemed on March 29, 2019.
 
Maturities of long-term debt:
(Millions of Dollars)
 
 
2020
 
$
400

2021
 
—

2022
 
300

2023
 
250

2024
 
—


Deferred Financing Costs — Deferred financing costs of approximately $41 million and $33 million, net of amortization, are presented as a deduction from the carrying amount of long-term debt as of Dec. 31, 2019 and 2018, respectively. PSCo is amortizing these financing costs over the remaining maturity periods of the related debt.
Capital Stock — PSCo has authorized the issuance of preferred stock.
Preferred
Shares
Authorized
 
Par Value
 
Preferred
Shares
Outstanding
10,000,000

 
$
0.01

 
—


Dividend Restrictions — PSCo’s dividends are subject to the FERC’s jurisdiction, which prohibits the payment of dividends out of capital accounts. Dividends are solely to be paid from retained earnings.
6. Revenues
Revenue is classified by the type of goods/services rendered and market/customer type. PSCo’s operating revenues consisted of the following:
 
 
Year Ended Dec. 31, 2019
(Millions of Dollars)
 
Electric
 
Natural Gas
 
All Other
 
Total
Major revenue types
 
 
 
 
 
 
 
 
Revenue from contracts with customers:
 
 
 
 
 
 
 
 
Residential
 
$
1,005.5

 
$
750.1

 
$
11.2

 
$
1,766.8

C&I
 
1,579.5

 
281.2

 
27.7

 
1,888.4

Other
 
50.0

 
—

 
—

 
50.0

Total retail
 
2,635.0

 
1,031.3

 
38.9

 
3,705.2

Wholesale
 
166.5

 
—

 
—

 
166.5

Transmission
 
51.7

 
—

 
—

 
51.7

Other
 
31.8

 
107.3

 
—

 
139.1

Total revenue from contracts with customers
 
2,885.0

 
1,138.6

 
38.9

 
4,062.5

Alternative revenue and other
 
148.0

 
22.3

 
4.4

 
174.7

Total revenues
 
$
3,033.0

 
$
1,160.9

 
$
43.3

 
$
4,237.2


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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


7. Income Taxes

Federal Tax Reform — In 2017, the TCJA was signed into law. The key provisions impacting Xcel Energy (which includes PSCo), generally beginning in 2018, included:
•
Corporate federal tax rate reduction from 35% to 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% of taxable income);
•
Repeal of the section 199 manufacturing deduction; and
•
Reduced deductions for meals and entertainment as well as state and local lobbying.
Xcel Energy estimated the effects of the TCJA, which have been reflected in the consolidated financial statements.
Reductions in deferred tax assets and liabilities due to 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.
Estimated impacts of the new tax law for 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% 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 accounted for the state tax impacts of federal tax reform based on 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.
Federal Audit — PSCo is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. Statute of limitations applicable to Xcel Energy’s consolidated federal income tax returns expire as follows:
Tax Year(s)
 
Expiration
2009 - 2013
 
June 2020
2014 - 2016
 
September 2020

In 2015, the IRS commenced an examination of tax years 2012 and 2013. In 2017, the IRS concluded the audit of tax years 2012 and 2013 and proposed an adjustment that would impact Xcel Energy’s NOL and ETR. Xcel Energy filed a protest with the IRS. As of Dec. 31, 2019, the case has been forwarded to the Office of Appeals and Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of this issue; however, the outcome and timing of a resolution is unknown.
In the fourth quarter of 2018, the IRS began an audit of tax years 2014 - 2016. As of Dec. 31, 2019 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, 2019, 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 — 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 to the taxing authority to an earlier period.
Unrecognized tax benefits - permanent vs temporary:
(Millions of Dollars)
 
Dec. 31, 2019
 
Dec. 31, 2018
Unrecognized tax benefit — Permanent tax positions
 
$
7.4

 
$
5.4

Unrecognized tax benefit — Temporary tax positions
 
4.6

 
4.9

Total unrecognized tax benefit
 
$
12.0

 
$
10.3


Changes in unrecognized tax benefits:
(Millions of Dollars)
 
2019
 
2018
 
2017
Balance at Jan. 1
 
$
10.3

 
$
10.1

 
$
19.7

Additions based on tax positions related to the current year
 
1.4

 
1.1

 
1.9

Reductions based on tax positions related to the current year
 
(0.2
)
 
(0.3
)
 
(1.5
)
Additions for tax positions of prior years
 
0.5

 
0.4

 
4.4

Reductions for tax positions of prior years
 
—

 
(0.1
)
 
(14.4
)
Settlements with taxing authorities
 
—

 
(0.9
)
 
—

Balance at Dec. 31
 
$
12.0

 
$
10.3

 
$
10.1


Unrecognized tax benefits were reduced by tax benefits associated with NOL and tax credit carryforwards:
(Millions of Dollars)
 
Dec. 31, 2019
 
Dec. 31, 2018
NOL and tax credit carryforwards
 
$
(8.3
)
 
$
(5.6
)

Net deferred tax liability associated with the unrecognized tax benefit amounts and related NOLs and tax credits carryforwards were $5.0 million and $2.0 million for Dec. 31, 2019 and Dec. 31, 2018, respectively.

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Table of Contents

As the IRS Appeals and federal audit progress and state audits resume, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $8.7 million in the next 12 months.
Payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards.
Interest payable related to unrecognized tax benefits:
(Millions of Dollars)
 
2019
 
2018
 
2017
Payable for interest related to unrecognized tax benefits at Jan. 1
 
$
(0.7
)
 
$
(0.3
)
 
$
(1.1
)
Interest (expense) income related to unrecognized tax benefits
 
(0.4
)
 
(0.4
)
 
0.8

Payable for interest related to unrecognized tax benefits at Dec. 31
 
$
(1.1
)
 
$
(0.7
)
 
$
(0.3
)

No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2019, 2018 or 2017.
Other Income Tax Matters — NOL amounts represent 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)
 
2019
 
2018
Federal tax credit carryforwards
 
$
83.2

 
$
35.0

State NOL carryforwards
 
388.1

 
484.7

State tax credit carryforwards, net of federal detriment (a)
 
17.6

 
16.9

Valuation allowances for state credit carryforwards, net of federal benefit (b)
 
(8.0
)
 
(8.9
)

(a) 
State tax credit carryforwards are net of federal detriment of $4.7 million and $4.5 million as of Dec. 31, 2019 and 2018, respectively.
(b) 
Valuation allowances for state tax credit carryforwards were net of federal benefit of $2.1 million and $2.4 million as of Dec. 31, 2019 and 2018, respectively.
Federal carryforward periods expire between 2023 and 2039 and state carryforward periods expire between 2020 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.
Effective income tax rate for years ended Dec. 31:
 
 
2019
 
2018 (a)
 
2017 (a)
Federal statutory rate
 
21.0
 %
 
21.0
 %
 
35.0
 %
State income tax on pretax income, net of federal tax effect
 
3.6
 %
 
3.7
 %
 
3.0
 %
Increases (decreases) in tax from:
 


 


 


Wind PTCs
 
(7.5
)
 
(0.6
)
 
—

Plant regulatory differences (b)
 
(3.3
)
 
(4.5
)
 
(1.0
)
Other tax credits, net of NOL & tax credit allowances
 
(1.3
)
 
(0.6
)
 
(0.9
)
Amortization of excess nonplant deferred taxes
 
(0.2
)
 
(1.4
)
 
—

Change in unrecognized tax benefits
 
0.3

 
0.1

 
0.2

Tax reform
 
—

 
—

 
(2.4
)
Other, net
 
(0.5
)
 
(0.6
)
 
(0.1
)
Effective income tax rate
 
12.1
 %
 
17.1
 %
 
33.8
 %

(a) Prior periods have been reclassified to conform to current year presentation.
(b) Regulatory differences for income tax primarily relate to the credit of excess deferred taxes to customers through the average rate assumption method. Income tax benefits associated with the credit of excess deferred credits are offset by corresponding revenue reductions and additional prepaid pension asset amortization.
 
Components of income tax expense for the years ended Dec. 31:
(Millions of Dollars)
 
2019
 
2018
 
2017
Current federal tax (benefit) expense
 
$
(8.9
)
 
$
79.5

 
$
40.4

Current state tax (benefit) expense
 
(5.0
)
 
14.2

 
14.6

Current change in unrecognized tax benefit
 
(1.0
)
 
(1.3
)
 
(7.8
)
Deferred federal tax expense
 
60.9

 
4.9

 
176.4

Deferred state tax expense
 
33.1

 
16.6

 
22.5

Deferred change in unrecognized tax expense
 
3.0

 
2.3

 
8.9

Deferred ITCs
 
(2.5
)
 
(2.5
)
 
(2.8
)
Total income tax expense
 
$
79.6

 
$
113.7

 
$
252.2

Components of deferred income tax expense as of Dec. 31:
(Millions of Dollars)
 
2019
 
2018
 
2017
Deferred tax expense (benefit) excluding items below
 
$
131.5

 
$
74.8

 
$
(1,244.7
)
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities
 
(34.9
)
 
(50.6
)
 
1,453.1

Tax benefit (expense) allocated to other comprehensive income, net of adoption of ASU No. 2018-02, and other
 
0.4

 
(0.4
)
 
(0.6
)
Deferred tax expense
 
$
97.0

 
$
23.8

 
$
207.8


Components of the net deferred tax liability as of Dec. 31:
(Millions of Dollars)
 
2019
 
2018 (a)
Deferred tax liabilities:
 
 
 
 
Differences between book and tax bases of property
 
$
2,039.1

 
$
1,860.1

Regulatory assets
 
253.1

 
251.1

Operating lease assets
 
147.9

 
—

Pension expense and other employee benefits
 
21.5

 
31.1

Other
 
8.3

 
1.7

Total deferred tax liabilities
 
$
2,469.9

 
$
2,144.0

 
 
 
 
 
Deferred tax assets:
 
 

 
 

Regulatory liabilities
 
$
327.2

 
$
336.3

Operating lease liabilities
 
147.9

 
—

Tax credit carryforward
 
100.8

 
51.9

NOL carryforward
 
14.3

 
18.2

Rate refund
 
6.1

 
9.3

Deferred ITCs
 
5.6

 
6.3

Tax credit valuation allowances
 
(8.0
)
 
(8.9
)
Other
 
25.2

 
11.6

Total deferred tax assets
 
$
619.1

 
$
424.7

Net deferred tax liability
 
$
1,850.8

 
$
1,719.3


(a) Prior periods have been reclassified to conform to current year presentation.

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8. 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 disclosures about assets and liabilities measured at fair value. A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance. 
•
Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices.
•
Level 2 — Pricing inputs are other than quoted prices in active markets but are either directly or indirectly observable as of the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts or priced with models using highly observable inputs.
•
Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those valued with models requiring significant management judgment or estimation.
Specific valuation methods include:
Cash equivalents — The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted NAV.
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.
As of Dec. 31, 2019, 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 is allowed to conduct these activities within guidelines and limitations as approved by its risk management committee, comprised of management personnel not directly involved in activities governed by this policy.
Commodity Derivatives — 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 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. No amounts related to the ineffectiveness of cash flow hedges were recorded for the years ended Dec. 31, 2019 and 2018.
As of Dec. 31, 2019, 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.
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.
Gross notional amounts of commodity forwards and options at Dec. 31:
(Amounts in Millions) (a)(b)
 
2019
 
2018
MWh of electricity
 
9.3

 
24.4

MMBtu of natural gas
 
32.2

 
48.4

(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. The impact of credit risk was immaterial to the fair value of unsettled commodity derivatives presented in the consolidated balance sheets.
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, 2019, five of PSCo’s 10 most significant counterparties for these activities, comprising $110.1 million or 78% of this credit exposure, had investment grade credit ratings from Standard & Poor’s, Moody’s or Fitch Ratings. Five of the 10 most significant counterparties, comprising $15.7 million or 11% of this credit exposure, were not rated by these external agencies, but based on PSCo’s internal analysis, had credit quality consistent with investment grade. Eight of these significant counterparties are municipal or cooperative electric entities, ISOs or other utilities.

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Table of Contents

Qualifying Cash Flow Hedges — 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:
(Millions of Dollars)
 
2019
 
2018
 
2017
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1
 
$
(25.3
)
 
$
(26.5
)
 
$
(22.8
)
After-tax net realized losses on derivative transactions reclassified into earnings
 
1.2

 
1.2

 
1.0

Adoption of ASU No. 2018-02 (a)
 
—

 
—

 
(4.7
)
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31
 
$
(24.1
)
 
$
(25.3
)
 
$
(26.5
)

(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.
Impact of derivative activity:
 
 
Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:
(Millions of Dollars)
 
Accumulated Other
Comprehensive Loss
 
Regulatory (Assets) and Liabilities
Year to date Dec. 31, 2019
 
 
 
 
Other derivative instruments
 
 
 
 
Natural gas commodity
 
$
—

 
$
(5.3
)
Total
 
$
—

 
$
(5.3
)
 
 
 
 
 
Year to date Dec. 31, 2018
 
 
 
 
Other derivative instruments
 
 
 
 
Natural gas commodity
 
$
—

 
$
8.0

Total
 
$
—

 
$
8.0

 
 
 
 
 
Year to date Dec. 31, 2017
 
 
 
 
Other derivative instruments
 
 
 
 
Natural gas commodity
 
$
—

 
$
(10.9
)
Total
 
$
—

 
$
(10.9
)

 
 
 
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 to date Dec. 31, 2019
 
 
 
 
 
 
 
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
 
—

 
0.6

(d) 
(3.9
)
(d) 
Total
 
$
—

 
$
0.6

 
$
(0.8
)
 
 
 
 
 
 
 
 
 
Year to date 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 to date 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
)
 
(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) 
Amounts for the year ended Dec. 31, 2019, 2018 and 2017 included no settlement gains or losses, $1.2 million of settlement losses and $0.4 million of settlement gains, 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. Remaining settlement losses for the years ended Dec. 31, 2019, 2018 and 2017 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, 2019, 2018 and 2017. 

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Table of Contents

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 if there was a failure under other financing arrangements related to payment terms or other covenants.
 
At Dec. 31, 2019 and 2018, there were no derivative instruments in a 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, 2019 and 2018.
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, 2019 and 2018:
 
 
Dec. 31, 2019
 
Dec. 31, 2018
 
 
Fair Value
 
 
 
 
 
 
 
Fair Value
 
 
 
 
 
 
(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
 
$
1.9

 
$
11.1

 
$
0.9

 
$
13.9

 
$
(10.1
)
 
$
3.8

 
$
2.3

 
$
65.0

 
$
0.1

 
$
67.4

 
$
(28.2
)
 
$
39.2

Natural gas commodity
 
—

 
3.4

 
—

 
3.4

 
—

 
3.4

 
—

 
3.4

 
—

 
3.4

 
—

 
3.4

Total current derivative assets
 
$
1.9

 
$
14.5

 
$
0.9

 
$
17.3

 
$
(10.1
)
 
7.2

 
$
2.3

 
$
68.4

 
$
0.1

 
$
70.8

 
$
(28.2
)
 
42.6

Current derivative instruments
 
 
 
 
 
 
 
 
 
 
 
$
7.2

 
 
 
 
 
 
 
 
 
 
 
$
42.6

Noncurrent derivative assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other derivative instruments:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity trading
 
$
0.4

 
$
8.1

 
$
1.1

 
$
9.6

 
$
(9.6
)
 
$
—

 
$
—

 
$
1.6

 
$
—

 
$
1.6

 
$
(0.4
)
 
$
1.2

Total noncurrent derivative assets
 
$
0.4

 
$
8.1

 
$
1.1

 
$
9.6

 
$
(9.6
)
 
—

 
$
—

 
$
1.6

 
$
—

 
$
1.6

 
$
(0.4
)
 
1.2

Noncurrent derivative instruments
 
 
 
 
 
 
 
 
 
 
 
$
—

 
 
 
 
 
 
 
 
 
 
 
$
1.2

Current derivative liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other derivative instruments:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity trading
 
$
1.7

 
$
16.7

 
$
—

 
$
18.4

 
$
(13.1
)
 
$
5.3

 
$
2.4

 
$
64.2

 
$
—

 
$
66.6

 
$
(34.7
)
 
$
31.9

Natural gas commodity
 
—

 
3.4

 
—

 
3.4

 
—

 
3.4

 
—

 
—

 
—

 
—

 
—

 
—

Total current derivative liabilities
 
$
1.7

 
$
20.1

 
$
—

 
$
21.8

 
$
(13.1
)
 
8.7

 
$
2.4

 
$
64.2

 
$
—

 
$
66.6

 
$
(34.7
)
 
31.9

PPAs (b)
 
 
 
 
 
 
 
 
 
 
 
—

 
 
 
 
 
 
 
 
 
 
 
2.7

Current derivative instruments
 
 
 
 
 
 
 
 
 
 
 
$
8.7

 
 
 
 
 
 
 
 
 
 
 
$
34.6

Noncurrent derivative liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other derivative instruments:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity trading
 
$
0.4

 
$
47.0

 
$
14.7

 
$
62.1

 
$
(9.6
)
 
$
52.5

 
$
—

 
$
1.1

 
$
—

 
$
1.1

 
$
(0.5
)
 
$
0.6

Total noncurrent derivative liabilities
 
$
0.4

 
$
47.0

 
$
14.7

 
$
62.1

 
$
(9.6
)
 
52.5

 
$
—

 
$
1.1

 
$
—

 
$
1.1

 
$
(0.5
)
 
0.6

Noncurrent derivative instruments
 
 
 
 
 
 
 
 
 
 
 
$
52.5

 
 
 
 
 
 
 
 
 
 
 
$
0.6

(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, 2019 and 2018. At both Dec. 31, 2019 and 2018, derivative assets and liabilities include no obligations to return cash collateral. At Dec. 31, 2019 and 2018, derivative assets and liabilities include the rights to reclaim cash collateral of $3.0 million and $6.5 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 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.
There were $10.9 million of losses, $0.1 million of gains and immaterial gains recognized in earnings for the years ended Dec. 31, 2019, 2018 and 2017, respectively, for Level 3 commodity trading derivatives.
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, 2019, 2018 and 2017.
Fair Value of Long-Term Debt
As of Dec. 31, other financial instruments for which the carrying amount did not equal fair value:
 
 
2019
 
2018
(Millions of Dollars)
 
Carrying
Amount
 
Fair Value
 
Carrying
Amount
 
Fair Value
Long-term debt, including current portion
 
$
5,384.7

 
$
6,039.3

 
$
4,997.6

 
$
5,123.2


 
Fair value of PSCo’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. Fair value estimates are based on information available to management as of Dec. 31, 2019 and 2018, and given the observability of the inputs, fair values presented for long-term debt were assigned as Level 2.

36
Table of Contents

9. Benefit Plans and Other Postretirement Benefits

Pension and Postretirement Health Care 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 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 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, 2019 and 2018 were $39 million and $33 million, respectively, of which $3 million was attributable to PSCo in both years. Xcel Energy recognized net benefit cost for financial reporting for the SERP and nonqualified plans of $4 million in 2019 and 2018, respectively, of which $1 million was attributable to PSCo.
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.
•
Investment returns in 2019 were above the assumed level of 6.84%;
•
Investment returns in 2018 were below the assumed level of 6.84%;
•
Investment returns in 2017 were above the assumed level of 6.84%; and
•
In 2020, 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 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 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.
Plan Assets
For each of the fair value hierarchy levels, PSCo’s pension plan assets measured at fair value:
 
 
Dec. 31, 2019 (a)
 
Dec. 31, 2018 (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
 
$
45.6

 
$
—

 
$
—

 
$
—

 
$
45.6

 
$
53.0

 
$
—

 
$
—

 
$
—

 
$
53.0

Commingled funds
 
497.0

 
—

 
—

 
355.3

 
852.3

 
316.2

 
—

 
—

 
326.1

 
642.3

Debt securities
 
—

 
241.2

 
1.5

 
—

 
242.7

 
—

 
242.3

 
—

 
—

 
242.3

Equity securities
 
29.7

 
—

 
—

 
—

 
29.7

 
35.2

 
—

 
—

 
—

 
35.2

Other
 
(41.3
)
 
1.7

 
—

 
(6.9
)
 
(46.5
)
 
0.6

 
2.0

 
—

 
(9.9
)
 
(7.3
)
Total
 
$
531.0

 
$
242.9

 
$
1.5

 
$
348.4

 
$
1,123.8

 
$
405.0

 
$
244.3

 
$
—

 
$
316.2

 
$
965.5


(a) 
See Note 8 for further information on fair value measurement inputs and methods.
For each of the fair value hierarchy levels, PSCo’s proportionate allocation of the total postretirement benefit plan assets that were measured at fair value:
 
 
Dec. 31, 2019 (a)
 
Dec. 31, 2018 (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
 
$
20.3

 
$
—

 
$
—

 
$
—

 
$
20.3

 
$
17.0

 
$
—

 
$
—

 
$
—

 
$
17.0

Insurance contracts
 
—

 
45.4

 
—

 
—

 
45.4

 
—

 
40.2

 
—

 
—

 
40.2

Commingled funds
 
61.9

 
—

 
—

 
68.0

 
129.9

 
118.7

 
—

 
—

 
35.8

 
154.5

Debt securities
 
—

 
203.4

 
1.0

 
—

 
204.4

 
—

 
159.7

 
—

 
—

 
159.7

Equity securities
 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Other
 
—

 
0.5

 
—

 
—

 
0.5

 
—

 
0.7

 
—

 
—

 
0.7

Total
 
$
82.2

 
$
249.3

 
$
1.0

 
$
68.0

 
$
400.5

 
$
135.7

 
$
200.6

 
$
—

 
$
35.8

 
$
372.1

(a) 
See Note 8 for further information on fair value measurement inputs and methods.
Immaterial assets were transferred in or out of Level 3 for 2019. No assets were transferred in or out of Level 3 for 2018.

37
Table of Contents

Funded Status — Comparisons of the actuarially computed benefit obligation, changes in plan assets and funded status of the pension and postretirement health care plans for Xcel Energy are as follows:
 
 
Pension Benefits
 
Postretirement Benefits
(Millions of Dollars)
 
2019
 
2018
 
2019
 
2018
Change in Benefit Obligation:
 
 
 
 
 
 
 
 
Obligation at Jan. 1
 
$
1,229.3

 
$
1,334.2

 
$
376.5

 
$
429.2

Service cost
 
25.6

 
29.0

 
0.5

 
0.7

Interest cost
 
51.6

 
47.3

 
15.6

 
15.0

Plan amendments
 
—

 
—

 
—

 
—

Actuarial loss (gain)
 
108.2

 
(96.5
)
 
12.7

 
(40.6
)
Plan participants’ contributions
 
—

 
—

 
6.6

 
6.5

Medicare subsidy reimbursements
 
—

 
—

 
1.6

 
0.9

Benefit payments
 
(84.9
)
 
(84.7
)
 
(33.5
)
 
(35.2
)
Obligation at Dec. 31
 
$
1,329.8

 
$
1,229.3

 
$
380.0

 
$
376.5

Change in Fair Value of Plan Assets:
 
 
 
 
 
 
 
 
Fair value of plan assets at Jan. 1
 
$
965.5

 
$
1,079.4

 
$
372.1

 
$
406.4

Actual return on plan assets
 
197.4

 
(50.9
)
 
51.0

 
(11.1
)
Employer contributions
 
45.8

 
21.7

 
4.3

 
5.5

Plan participants’ contributions
 
—

 
—

 
6.6

 
6.5

Benefit payments
 
(84.9
)
 
(84.7
)
 
(33.5
)
 
(35.2
)
Fair value of plan assets at Dec. 31
 
$
1,123.8

 
$
965.5

 
$
400.5

 
$
372.1

Funded status of plans at Dec. 31
 
$
(206.0
)
 
$
(263.8
)
 
$
20.5

 
$
(4.4
)
Amounts recognized in the Consolidated Balance Sheet at Dec. 31:
 
 
 
 
 
 
 
 
Noncurrent liabilities
 
(206.0
)
 
(263.8
)
 
20.5

 
(4.4
)
Net amounts recognized
 
$
(206.0
)
 
$
(263.8
)
 
$
20.5

 
$
(4.4
)
Significant Assumptions Used to Measure Benefit Obligations:
 
 
 
 
 
 
 
 
Discount rate for year-end valuation
 
3.49
%
 
4.31
%
 
3.47
%
 
4.32
%
Expected average long-term increase in compensation level
 
3.75

 
3.75

 
N/A

 
N/A

Mortality table
 
Pri-2012

 
RP-2014

 
Pri-2012

 
RP-2014

Health care costs trend rate — initial: Pre-65
 
N/A

 
N/A

 
6.00
%
 
6.50
%
Health care costs trend rate — initial: Post-65
 
N/A

 
N/A

 
5.10
%
 
5.30
%
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

 
3

 
4


Accumulated benefit obligation for the pension plan was $1,267.2 million and $1,183.3 million as of Dec. 31, 2019 and 2018, respectively.
Net Periodic Benefit Cost (Credit) — Net periodic benefit cost (credit) other than the service cost component is included in other income in the consolidated statement of income.
Components of net periodic benefit cost (credit) and the amounts recognized in other comprehensive income and regulatory assets and liabilities:
 
 
Pension Benefits
 
Postretirement Benefits
(Millions of Dollars)
 
2019
 
2018
 
2017
 
2019
 
2018
 
2017
Service cost
 
$
25.6

 
$
29.0

 
$
27.3

 
$
0.5

 
$
0.7

 
$
0.7

Interest cost
 
51.6

 
47.3

 
50.6

 
15.6

 
15.0

 
16.8

Expected return on plan assets
 
(68.5
)
 
(68.5
)
 
(68.5
)
 
(18.9
)
 
(22.7
)
 
(21.9
)
Amortization of prior service credit
 
(3.4
)
 
(3.4
)
 
(3.2
)
 
(5.4
)
 
(6.2
)
 
(6.2
)
Amortization of net loss
 
25.4

 
31.2

 
28.3

 
2.9

 
4.0

 
3.8

Settlement charge (a)
 
3.2

 
4.5

 
—

 
—

 
—

 
—

Net periodic pension cost (credit)
 
33.9

 
40.1

 
34.5

 
(5.3
)
 
(9.2
)
 
(6.8
)
Costs (credits) not recognized due to effects of regulation
 
3.5

 
(3.9
)
 
(2.7
)
 
1.2

 
1.8

 
—

Net benefit cost (credit) recognized for financial reporting
 
$
37.4

 
$
36.2

 
$
31.8

 
$
(4.1
)
 
$
(7.4
)
 
$
(6.8
)
Significant Assumptions Used to Measure Costs:
 
 
 
 
 
 
 
 
 
 
 
 
Discount rate
 
4.31
%
 
3.63
%
 
4.13
%
 
4.32
%
 
3.62
%
 
4.13
%
Expected average long-term increase in compensation level
 
3.75

 
3.75

 
3.75

 
N/A

 
N/A

 
N/A

Expected average long-term rate of return on assets
 
6.84

 
6.84

 
6.84

 
4.50

 
5.30

 
5.80

(a) 
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 2019 and 2018, as a result of lump-sum distributions during the 2019 and 2018 plan years, PSCo recorded a total pension settlement charge of $3.2 million and $4.5 million in 2019 and 2018. A total of $0.1 million and $0.2 million of that amount was recorded in the income statement in 2019 and 2018, respectively.

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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 2020 pension cost calculations is 6.84%.
 
 
Pension Benefits
 
Postretirement Benefits
(Millions of Dollars)
 
2019
 
2018
 
2019
 
2018
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
 
 
 
 
 
 
 
 
Net loss
 
$
481.5

 
$
530.8

 
$
44.6

 
$
66.9

Prior service credit
 
(3.8
)
 
(7.2
)
 
(9.9
)
 
(15.3
)
Total
 
$
477.7

 
$
523.6

 
$
34.7

 
$
51.6

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
 
$
22.3

 
$
25.8

 

 
$
—

Noncurrent regulatory assets
 
452.1

 
497.5

 
34.7

 
51.6

Deferred income taxes
 
0.8

 
0.1

 
—

 
—

Net-of-tax accumulated other comprehensive income
 
2.5

 
0.2

 
—

 
—

Total
 
$
477.7

 
$
523.6

 
$
34.7

 
$
51.6

Measurement date
 
Dec. 31, 2019
 
Dec. 31, 2018
 
Dec. 31, 2019
 
Dec. 31, 2018

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 2017 - 2020 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 2020, of which $50 million was attributable to PSCo;
•
$154 million in 2019, of which $46 million was attributable to PSCo;
•
$150 million in 2018, of which $22 million was attributable to PSCo; and
•
$162 million in 2017, of which $18 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 $10 million during 2020, of which amounts attributable to PSCo will be zero.
Xcel Energy, which includes PSCo, contributed:
•
$15 million during 2019, of which $4 million was attributable to PSCo;
•
$11 million during 2018, of which $5 million was attributable to PSCo; and
•
$20 million during 2017, of which $5 million was attributable to PSCo.
 
Targeted asset allocations:
 
 
Pension Benefits
 
Postretirement Benefits
 
 
2019
 
2018
 
2019
 
2018
Domestic and international equity securities
 
37
%
 
35
%
 
15
%
 
18
%
Long-duration fixed income securities
 
30

 
32

 
—

 
—

Short-to-intermediate fixed income securities
 
14

 
16

 
72

 
70

Alternative investments
 
17

 
15

 
9

 
8

Cash
 
2

 
2

 
4

 
4

Total
 
100
%
 
100
%
 
100
%
 
100
%

Plan Amendments — The Xcel Energy Pension Plan and Xcel Energy Inc. Nonbargaining Pension Plan (South), which includes PSCo, were amended 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 2018, the PSCo postretirement plan was amended to add the 5% cash balance formula.
In 2019, 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
2020
 
$
82.0

 
$
30.5

 
$
1.9

 
$
28.6

2021
 
81.9

 
30.3

 
2.0

 
28.3

2022
 
82.3

 
29.8

 
2.1

 
27.7

2023
 
82.7

 
29.4

 
2.2

 
27.2

2024
 
82.4

 
28.8

 
2.2

 
26.6

2025-2029
 
402.9

 
129.9

 
12.1

 
117.8



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Table of Contents

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 2019 and 2018, respectively, and $10 million in 2017.
10. Commitments and Contingencies

Legal
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 complex judgments about future events. Management maintains accruals for losses that are probable of being incurred and subject to reasonable estimation.
Management may be unable to estimate an amount or range of a reasonably possible loss in certain situations, including 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 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.
Gas Trading Litigation — e prime is a wholly owned subsidiary of Xcel Energy Inc. e prime was in the business of natural gas trading and marketing but has not engaged in natural gas trading or marketing activities since 2003. Multiple lawsuits involving multiple plaintiffs seeking monetary damages were commenced against e prime and its affiliates, including Xcel Energy, between 2003 and 2009 alleging fraud and anticompetitive activities in conspiring to restrain the trade of natural gas and manipulate natural gas prices. Cases were all consolidated in the U.S. District Court in Nevada.
Two cases remain active which include an MDL matter consisting of a Colorado purported class (Breckenridge) and a Wisconsin purported class (Arandell Corp.).
Breckenridge/Colorado — In February 2019, the MDL panel remanded Breckenridge back to the U.S. District Court in Colorado.
Arandell Corp. — In February 2019, the case was remanded back to the U.S. District Court in Wisconsin.
Xcel Energy has concluded that a loss is remote for both remaining lawsuits.
Line Extension Disputes — In December 2015, the DRC filed a lawsuit seeking monetary damages in the Denver District Court, stating PSCo failed to award proper allowances and refunds for line extensions to new developments pursuant to the terms of electric and gas service agreements. The dispute involves claims by over fifty developers. In February 2018, the Colorado Supreme Court denied DRC’s petition to appeal the Denver District Court’s dismissal of the lawsuit, effectively terminating this litigation. However, in January 2018, DRC filed a new lawsuit in Boulder County District Court, asserting a single claim that PSCo was required to file its line extension agreements with the CPUC but failed to do so.
 
This claim is similar to the arguments previously raised by the DRC. PSCo filed a motion to dismiss this claim, which was granted in May 2018. The DRC subsequently filed an appeal to the Colorado Court of Appeals. In November 2019, the Colorado Court of Appeals issued an opinion affirming dismissal of the lawsuit based upon lack of subject matter jurisdiction. The Colorado Court of Appeals did not address the second issue based upon issue preclusion. Finally, the Colorado Court of Appeals remanded the case to the Boulder District Court to consider PSCo’s request for an award of costs, which it concluded does not include attorneys’ fees. The DRC did not file a petition for a Writ of Certiorari to the Colorado Supreme Court by the Dec. 26, 2019 deadline effectively terminating this litigation.
Environmental
New and changing federal and state environmental mandates can create financial liabilities for PSCo, which are normally recovered through the regulated rate process.
Site Remediation — Various federal and state environmental laws impose liability where hazardous substances or other regulated materials have been released to the environment. PSCo may sometimes pay all or a portion of the 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 cooperating with the City of Denver on an environmental investigation of the Rice Yards Site in Denver, Colorado, which had various historic industrial uses by multiple parties, including railroad, maintenance shop, scrap metal yard, and MGP operations.
The area is being redeveloped into residential and commercial mixed uses, and PSCo is in discussions with the current property owner regarding legal claims related to the Rice Yards Site.
In addition, PSCo is currently investigating or remediating two other MGP, landfill or other disposal sites across its service territories.
PSCo has recognized its best estimate of costs/liabilities that will result from final resolution of these issues, however, the outcome and timing is unknown. In addition, there may be insurance recovery and/or recovery from other potentially responsible parties, offsetting a portion of costs incurred.
Environmental Requirements — Water and Waste
Coal Ash Regulation — PSCo’s operations are subject to federal and state laws that impose requirements for handling, storage, treatment and disposal of solid waste. Under the CCR Rule, utilities are required to complete groundwater sampling around their CCR landfills and surface impoundments. Currently, PSCo has six regulated ash units in operation.
PSCo is conducting groundwater sampling and, where appropriate, initiating the assessment of corrective measures and evaluating whether corrective action is required at any CCR landfills or surface impoundments. In 2019, groundwater monitoring consistent with the CCR Rule was conducted. Statistically significant increase above background concentration was detected at four locations. Subsequently, assessment monitoring samples were collected, and PSCo is evaluating the results to determine whether corrective action is required. Until PSCo completes its assessment, it is uncertain what impact, if any, there will be on the operations, financial condition or cash flows.

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In August 2018, the United States Court of Appeals for the District of Columbia Circuit ruled that the EPA cannot allow utilities to continue to use unlined impoundments (including clay lined impoundments) for the storage or disposal of coal ash. In November 2019, the EPA proposed rules in response to this decision that, if finalized in their current form, may require PSCo to expedite closure of one coal ash impoundment.
Closure costs for existing impoundments are included in the calculation of the ARO liability.
See Note 10 for further information.
Federal CWA WOTUS Rule — In 2015, the EPA and U.S. Army Corps of Engineers published a final rule that significantly broadened the scope of waters under the CWA that are subject to federal jurisdiction, referred to as “WOTUS”. In 2019, the EPA repealed the 2015 rule and published a draft replacement rule. Until a final rule is issued, PSCo cannot estimate potential impacts, but anticipates 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 revise certain 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 estimates the likely cost for complying with impingement and entrainment requirements is immaterial. PSCo anticipates these costs will be fully recoverable through regulatory mechanisms.
Environmental Requirements — Air
Regional Haze Rules — The regional haze program requires sulfur dioxide, nitrogen oxide and particulate matter emission controls at power plants to reduce visibility impairment in national parks and wilderness areas. The program includes reasonable further progress. The requirements of the first regional haze plans developed by Colorado have been approved and implemented.
 
AROs — AROs have been recorded for PSCo’s assets.
PSCo’s AROs were as follows:
 
 
2019
(Millions 
of Dollars)
 
Jan. 1,
2019
 
Accretion
 
Cash Flow
Revisions
(a)
 
Dec. 31,
2019
(b)
Electric
 
 
 
 
 
 
 
 
Steam, hydro and other production
 
$
102.2

 
$
4.9

 
$
(7.3
)
 
$
99.8

Wind
 
14.5

 
0.8

 
1.1

 
16.4

Distribution
 
13.4

 
0.6

 
—

 
14.0

Miscellaneous
 
3.2

 
—

 
(3.2
)
 
—

Natural gas
 
 
 
 
 
 
 
 
Transmission and distribution
 
200.9

 
8.9

 
(19.4
)
 
190.4

Miscellaneous
 
4.0

 
0.1

 
(1.2
)
 
2.9

Common
 
 
 
 
 
 
 
 
Miscellaneous
 
0.5

 
—

 
—

 
0.5

Total liability
 
$
338.7

 
$
15.3

 
$
(30.0
)
 
$
324.0

(a) 
In 2019, AROs were revised for changes in timing and estimates of 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 decreased inflation rates. Changes in steam, hydro, and other production AROs primarily related to the cost estimates to remediate ponds at production facilities. 
(b) 
There were no ARO amounts incurred or settled in 2019.
 
 
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) 
Amounts incurred related to the Rush Creek wind farm, which was placed in service in 2018.
(b) 
Amounts settled related to closure of certain ash containment facilities.
(c) 
In 2018, AROs were revised for changes in timing and estimates of 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.
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, 2019. Therefore, an ARO has not been recorded for these facilities.

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Removal Costs — PSCo records a regulatory liability for the plant removal costs that are recovered currently in rates. 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, 2019 and 2018 were $350.8 million and $344.4 million, respectively.
Leases
PSCo evaluates contracts that may contain leases, including PPAs and arrangements for the use of office space and other facilities, vehicles and equipment. Under ASC Topic 842, adopted by PSCo on Jan. 1, 2019, a contract contains a lease if it conveys the exclusive right to control the use of a specific asset. A contract determined to contain a lease is evaluated further to determine if the arrangement is a finance lease.
ROU assets represent PSCo's rights to use leased assets. Starting in 2019, the present value of future operating lease payments is recognized in current and noncurrent operating lease liabilities. These amounts, adjusted for any prepayments or incentives, are recognized as operating lease ROU assets.
Most of PSCo’s leases do not contain a readily determinable discount rate. Therefore, the present value of future lease payments is generally calculated using the estimated incremental borrowing rate (weighted-average of 4.1%). PSCo has elected to utilize the practical expedient under which non-lease components, such as asset maintenance costs included in payments, are not deducted from minimum lease payments for the purposes of lease accounting and disclosure.
Leases with an initial term of 12 months or less are classified as short-term leases and are not recognized on the consolidated balance sheet.
Operating lease ROU assets:
(Millions of Dollars)
 
Dec. 31, 2019
PPAs
 
$
585.1

Other
 
68.7

Gross operating lease ROU assets
 
653.8

Accumulated amortization
 
(79.8
)
Net operating lease ROU assets
 
$
574.0


In 2019, ROU assets for finance leases are included in other noncurrent assets, and the present value of future finance lease payments is included in other current liabilities and other noncurrent liabilities. Prior to 2019, finance leases were included in property, plant and equipment, the current portion of long-term debt and long-term debt.
PSCo’s most significant finance lease activities are related to WYCO, a joint venture with CIG, to develop and lease natural gas pipeline, storage and compression facilities. Xcel Energy Inc. has a 50% ownership interest in WYCO. WYCO leases its facilities to CIG, and CIG operates the facilities, providing natural gas storage and transportation services to PSCo under separate service agreements.
PSCo accounts for its Totem natural gas storage service and Front Range pipeline arrangements with CIG and WYCO, respectively, as finance leases.
 
Finance lease ROU assets:
(Millions of Dollars)
 
Dec. 31, 2019
 
Dec. 31, 2018
Gas storage facilities
 
$
200.5

 
$
200.5

Gas pipeline
 
20.7

 
20.7

Gross finance lease ROU assets
 
221.2

 
221.2

Accumulated amortization
 
(82.4
)
 
(76.2
)
Net finance lease ROU assets
 
$
138.8

 
$
145.0


Components of lease expense:
(Millions of Dollars)
 
2019
 
2018
 
2017
Operating leases
 
 
 
 
 
 
PPA capacity payments
 
$
98.0

 
$
96.6

 
$
96.1

Other operating leases (a)
 
14.4

 
14.0

 
12.5

Total operating lease expense (b)
 
$
112.4

 
$
110.6

 
$
108.6

Finance leases
 
 
 
 
 
 
Amortization of ROU assets
 
$
6.2

 
$
5.6

 
$
5.3

Interest expense on lease liability
 
18.7

 
19.5

 
20.3

Total finance lease expense
 
$
24.9

 
$
25.1

 
$
25.6

(a) 
Includes short-term lease expense of $1.3 million, $1.5 million and $1.0 million for 2019, 2018 and 2017, respectively.
(b) 
PPA capacity payments are included in electric fuel and purchased power on the consolidated statements of income. Expense for other operating leases is included in O&M expense and electric fuel and purchased power.
Commitments under operating and finance leases as of Dec. 31, 2019:
(Millions of Dollars)
 
PPA (a) (b)
Operating
Leases
 
Other Operating
Leases
 
Total
Operating
Leases
 
Finance Leases
2020
 
$
95.9

 
$
13.2

 
$
109.1

 
$
24.8

2021
 
96.4

 
12.6

 
109.0

 
23.6

2022
 
82.6

 
11.6

 
94.2

 
20.5

2023
 
70.0

 
10.9

 
80.9

 
20.3

2024
 
62.6

 
11.0

 
73.6

 
20.1

Thereafter
 
226.0

 
18.1

 
244.1

 
399.7

Total minimum obligation
 
633.5

 
77.4

 
710.9

 
509.0

Interest component of obligation
 
(95.0
)
 
(12.5
)
 
(107.5
)
 
(370.2
)
Present value of minimum obligation
 
$
538.5

 
$
64.9

 
603.4

 
138.8

Less current portion
 
 
 
 
 
(85.8
)
 
(6.9
)
Noncurrent operating and finance lease liabilities
 
 
 
 
 
$
517.6

 
$
131.9

 
 
 
 
 
 
 
 
 
Weighted-average remaining lease term in years
 
 
 
 
 
7.9

 
38.7

(a) 
Amounts do not include PPAs accounted for as executory contracts and/or contingent payments, such as energy payments on renewable PPAs.
(b) 
PPA operating leases contractually expire at various dates through 2032.

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Table of Contents

Commitments under operating and finance leases as of Dec. 31, 2018:
(Millions of Dollars)
 
PPA (a) (b)
Operating
Leases
 
Other Operating
Leases
 
Total
Operating
Leases
 
Finance Leases
2019
 
$
95.5

 
$
10.8

 
$
106.3

 
$
24.9

2020
 
95.9

 
10.7

 
106.6

 
24.8

2021
 
96.4

 
9.5

 
105.9

 
23.6

2022
 
82.6

 
8.4

 
91.0

 
20.5

2023
 
70.0

 
8.1

 
78.1

 
20.3

Thereafter
 
288.6

 
53.4

 
342.0

 
420.4

Total minimum obligation
 
 
 
 
 
 
 
534.5

Interest component of obligation
 
 
 
 
 
 
 
(389.5
)
Present value of minimum obligation
 
 
 
 
 
$
145.0

(a) 
Amounts do not include PPAs accounted for as executory contracts and/or contingent payments, such as energy payments on renewable PPAs.
(b) 
PPA operating leases contractually expire at various dates through 2032.
PPAs and Fuel Contracts
Non-Lease PPAs — PSCo has entered into PPAs with other utilities and energy suppliers with various expiration dates through 2034 for purchased power to meet system load and energy requirements and 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.
Included in electric fuel and purchased power expenses for PPAs accounted for as executory contracts were payments for capacity of $12.0 million, $20.9 million and $25.2 million in 2019, 2018 and 2017, respectively.
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 financial results are mitigated through purchased energy cost recovery mechanisms.
At Dec. 31, 2019, 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
2020
 
$
3.2

2021
 
3.2

2022
 
3.2

2023
 
3.2

2024
 
3.2

Thereafter
 
10.4

Total
 
$
26.4


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 2020 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, 2019:
(Millions of Dollars)
 
Coal
 
Natural gas supply
 
Natural gas storage and
transportation
2020
 
$
155.7

 
$
287.3

 
$
116.0

2021
 
66.6

 
252.7

 
113.3

2022
 
44.1

 
102.5

 
113.4

2023
 
22.4

 
52.6

 
65.7

2024
 
22.9

 
2.9

 
35.0

Thereafter
 
71.3

 
—

 
537.7

Total
 
$
383.0

 
$
698.0

 
$
981.1


 
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 1,442 MW and 1,571 MW of capacity under long-term PPAs at Dec. 31, 2019 and 2018, respectively, with entities that have been determined to be VIEs. These agreements have expiration dates through 2032.
11. Other Comprehensive Income
Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31:
 
 
2019
(Millions of Dollars)
 
Gains and Losses on Cash Flow Hedges
 
Defined Benefit and Postretirement Items
 
Total
Accumulated other comprehensive loss at Jan. 1
 
$
(25.3
)
 
$
(0.2
)
 
$
(25.5
)
Other comprehensive loss before reclassifications (net of taxes of $0 and $0.1, respectively)
 
—

 
0.4

 
0.4

Losses (gains) reclassified from net accumulated other comprehensive loss:
 
 
 
 
 
 
Interest rate derivatives (net of taxes of $0.4 and $0, respectively)
 
1.2

(a) 
—

 
1.2

Amortization of net actuarial gains (net of taxes of $0 and $(0.9), respectively)
 
—

 
(2.7
)
(b) 
(2.7
)
Net current period other comprehensive income (loss)
 
1.2

 
(2.3
)
 
(1.1
)
Accumulated other comprehensive loss at Dec. 31
 
$
(24.1
)
 
$
(2.5
)
 
$
(26.6
)
(a) 
Included in interest charges.
(b) 
Included in the computation of net periodic pension and postretirement benefit costs. See Note 9 for further information.

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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
)

(a) 
Included in interest charges.
12. Segments and Related Information
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.
•
Regulated Electric - The regulated electric utility segment generates electricity which is transmitted and distributed in Colorado. 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.
•
Regulated Natural Gas - The regulated natural gas utility segment transports, stores and distributes natural gas in portions of Colorado.
PSCo presents Other, which includes operating segments, with revenues below the necessary quantitative thresholds. Those operating segments primarily includes 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.
 
PSCo’s segment information:
(Millions of Dollars)
 
2019
 
2018
 
2017
Regulated Electric
 
 
 
 
 
 
Operating revenues (a)
 
$
3,033.0

 
$
3,031.2

 
$
3,003.8

Intersegment revenues
 
0.4

 
0.3

 
0.3

Total operating revenue
 
$
3,033.4

 
$
3,031.5

 
$
3,004.1

Depreciation and amortization
 
454.9

 
415.6

 
353.6

Interest charges and financing costs
 
173.7

 
142.3

 
138.6

Income tax expense
 
45.0

 
103.0

 
243.6

Net income
 
464.9

 
428.6

 
370.6

Regulated Natural Gas
 
 
 
 
 
 
Operating revenues (a)
 
$
1,160.9

 
$
1,014.6

 
$
995.2

Intersegment revenues
 
0.4

 
0.6

 
0.4

Total operating revenue
 
$
1,161.3

 
$
1,015.2

 
$
995.6

Depreciation and amortization
 
141.4

 
140.6

 
113.2

Interest charges and financing costs
 
49.7

 
42.9

 
40.2

Income tax expense
 
32.6

 
13.1

 
18.4

Net income
 
119.4

 
121.4

 
107.8

All Other
 
 
 
 
 
 
Operating revenues (a)
 
$
43.3

 
$
40.4

 
$
43.5

Depreciation and amortization
 
6.1

 
4.9

 
4.7

Interest charges and financing costs
 
0.8

 
0.5

 
0.5

Income tax (benefit)
 
2.0

 
(2.4
)
 
(9.8
)
Net (loss) income
 
(6.5
)
 
1.7

 
15.7

 
 
 
 
 
 
 
Consolidated Total
 
 
 
 
 
 
Operating revenues (a)
 
$
4,238.0

 
$
4,087.1

 
$
4,043.2

Intersegment revenues
 
(0.8
)
 
(0.9
)
 
(0.7
)
Total operating revenue
 
$
4,237.2

 
$
4,086.2

 
$
4,042.5

Depreciation and amortization
 
602.4

 
561.1

 
471.5

Interest charges and financing costs
 
224.2

 
185.7

 
179.3

Income tax expense
 
79.6

 
113.7

 
252.2

Net income
 
577.8

 
551.7

 
494.1


(a) 
Operating revenues include $4.5 million, $4.4 million and $5.9 million of intercompany revenue for the years ended Dec. 31, 2019, 2018 and 2017, respectively. See Note 13 for further information.
13. 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 5 for further information.

44
Table of Contents

Significant affiliate transactions among the companies and related parties for the years ended Dec. 31:
(Millions of Dollars)
 
2019
 
2018
 
2017
Operating revenues:
 
 
 
 
 
 
Electric
 
$
—

 
$
—

 
$
1.4

Other
 
4.5

 
4.4

 
4.5

Operating expenses:
 
 
 
 
 
 
Other operating expenses — paid to Xcel Energy Services Inc.
 
531.9

 
518.7

 
485.1

Interest expense
 
0.4

 
—

 
—

Interest income
 
0.2

 
—

 
—


Accounts receivable and payable with affiliates at Dec. 31:
 
 
2019
 
2018
(Millions of Dollars)
 
Accounts
Receivable
 
Accounts
Payable
 
Accounts
Receivable
 
Accounts
Payable
NSP-Minnesota
 
$
18.8

 
$
—

 
$
17.9

 
$
—

NSP-Wisconsin
 
—

 
0.2

 
—

 
0.2

SPS
 
0.4

 
—

 
0.7

 
—

Other subsidiaries of Xcel Energy Inc.
 
33.5

 
43.7

 
62.2

 
45.8

 
 
$
52.7

 
$
43.9

 
$
80.8

 
$
46.0


14. Summarized Quarterly Financial Data (Unaudited)
 
 
Quarter Ended
(Millions of Dollars)
 
March 31, 2019
 
June 30, 2019
 
Sept. 30, 2019
 
Dec. 31, 2019
Operating revenues
 
$
1,223.0

 
$
910.0

 
$
1,044.3

 
$
1,059.9

Operating income
 
209.9

 
162.7

 
284.3

 
199.9

Net income
 
138.8

 
101.5

 
204.5

 
133.0

 
 
Quarter Ended
(Millions of Dollars)
 
March 31, 2018
 
June 30, 2018
 
Sept. 30, 2018
 
Dec. 31, 2018
Operating revenues
 
$
1,073.3

 
$
911.9

 
$
1,060.7

 
$
1,040.3

Operating income (a)
 
206.9

 
189.3

 
276.9

 
119.5

Net income
 
133.7

 
122.3

 
207.1

 
88.6


(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.
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 CEO and CFO, allowing timely decisions regarding required disclosure. 
 
As of Dec. 31, 2019, based on an evaluation carried out under the supervision and with the participation of PSCo’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and procedures, the CEO and CFO have concluded that PSCo’s disclosure controls and procedures were effective.
Internal Control Over Financial Reporting
No changes in PSCo’s internal control over financial reporting occurred during the most recent fiscal quarter that materially affected, or are 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, 2019 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, as approved by the SEC and as indicated in PSCo’s Management Report on Internal Controls over Financial Reporting, which is contained in Item 8 herein.
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 definitive Proxy Statement for its 2020 Annual Meeting of Shareholders, which is incorporated by reference.

45
Table of Contents

ITEM 14 — PRINCIPAL ACCOUNTANT FEES AND SERVICES
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 2020 Annual Meeting of Shareholders which definitive Proxy Statement is expected to be filed with the SEC on or about April 6, 2020. Such information set forth under such heading is incorporated herein by this reference hereto.
PART IV
ITEM 15 — EXHIBITS, FINANCIAL STATEMENT SCHEDULES
1
Consolidated Financial Statements:
 
Management Report on Internal Controls Over Financial Reporting — For the year ended Dec. 31, 2019.
 
Report of Independent Registered Public Accounting Firm — Financial Statements
 
Consolidated Statements of Income — For the three years ended Dec. 31, 2019, 2018 and 2017.
 
Consolidated Statements of Comprehensive Income — For the three years ended Dec. 31, 2019, 2018 and 2017.
 
Consolidated Statements of Cash Flows — For the three years ended Dec. 31, 2019, 2018 and 2017.
 
Consolidated Balance Sheets — As of Dec. 31, 2019 and 2018.
 
Consolidated Statements of Common Stockholder’s Equity — For the three years ended Dec. 31, 2019, 2018 and 2017.
 
 
2
Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2019, 2018 and 2017.
 
 
3
Exhibits
* 
Indicates incorporation by reference
+
Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors
Exhibit Number
Description
Report or Registration Statement
SEC File or Registration Number
Exhibit Reference
PSCo Form 10-Q for the quarter ended Sept. 30, 2017
001-03280

3.01
PSCo Form 10-K for the year ended Dec. 31, 2018
001-03280
3.02
Xcel Energy Inc. Form S-3 dated April 18, 2018
001-03034
4(d)(3)
PSCo Form 8-K dated Aug. 8, 2007
001-03280
4.01
PSCo Form 8-K dated Aug. 6, 2008
001-03280
4.01
PSCo Form 8-K dated May 28, 2009
001-03280
4.01
PSCo Form 8-K dated Nov. 8, 2010
001-03280
4.01
PSCo Form 8-K dated Aug. 9, 2011
001-03280
4.01
PSCo Form 8-K dated Sept. 11, 2012
001-03280
4.01
PSCo Form 8-K dated March 26, 2013
001-03280
4.01
PSCo Form 8-K dated March 10, 2014
001-03280
4.01
PSCo Form 8-K dated May 12, 2015
001-03280
4.01
PSCo Form 8-K dated June 13, 2016
001-03280
4.01
PSCo Form 8-K dated June 19, 2017
001-03280
4.01
PSCo Form 8-K dated June 21, 2018
001-03280
4.01

46
Table of Contents

PSCo Form 8-K dated March 13, 2019
001-03280
4.01
PSCo Form 8-K dated August 13, 2019
001-03280
4.01
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008
001-03034
10.02
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008
001-03034
10.05
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008
001-03034
10.08
Xcel Energy Inc. Form U5B dated Nov. 16, 2000
001-03034
H-1
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008
001-03034
10.17
Xcel Energy Inc. Form 8-K dated Dec. 3, 2004
001-03034
99.02
Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2009
001-03034
10.06
Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2009
001-03034
10.08
Xcel Energy Inc. Definitive Proxy Statement dated April 6, 2010
001-03034
Appendix A
Xcel Energy Inc. Definitive Proxy Statement dated April 5, 2011
001-03034
Appendix A
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008
001-03034
10.07
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2011
001-03034
10.17
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2011
001-03034
10.18
Xcel Energy Inc. Form 10-Q for the quarter ended March 31, 2013
001-03034
10.01
Xcel Energy Inc. Form 10-Q for the quarter ended March 31, 2013
001-03034
10.02
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2013
001-03034
10.22
Xcel Energy Inc. Form 8-K dated May 20, 2015
001-03034
10.02
Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2016
001-03034
10.01
Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2016
001-03034
10.01
Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2017
001-03034
10.01
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2017
001-03034
10.30
Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2018
001-03034
10.01
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018
001-03034
10.34
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018
001-03034
10.35
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018
001-03034
10.36
Xcel Energy Inc. Form 8-K dated June 7, 2019
001-03034
99.03
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2019
001-03034
10.33
101.INS
XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH
XBRL Schema
101.CAL
XBRL Calculation

47
Table of Contents

101.DEF
XBRL Definition
101.LAB
XBRL Label
101.PRE
XBRL Presentation
104
Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

SCHEDULE II
Public Service Co. of Colorado and Subsidiaries Valuation and Qualifying Accounts Years Ended Dec. 31
 
 
Allowance for bad debts
(Millions of Dollars)
 
2019
 
2018
 
2017
Balance at Jan. 1
 
$
20.5

 
$
19.6

 
$
19.6

Additions charged to costs and expenses
 
16.5

 
16.4

 
14.3

Additions charged to other accounts (a)
 
5.8

 
4.7

 
4.0

Deductions from reserves (b)
 
(21.8
)
 
(20.2
)
 
(18.3
)
Balance at Dec. 31
 
$
21.0

 
$
20.5

 
$
19.6

(a) 
Recovery of amounts previously written off.
(b) 
Deductions related primarily to bad debt write-offs.
Item 16 — Form 10-K Summary
None.


48
Table of Contents

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. 21, 2020

/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/ ALICE K. JACKSON
Ben Fowke
 
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/ DAVID L. EVES
 
 
David L. Eves
 
 
Executive Vice President, Group President, Utilities 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.


49