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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.


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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.