Company Quick10K Filing
Quick10K
Public Service Co of Colorado
10-K 2018-12-31 Annual: 2018-12-31
10-Q 2018-09-30 Quarter: 2018-09-30
10-Q 2018-06-30 Quarter: 2018-06-30
10-Q 2018-03-31 Quarter: 2018-03-31
10-K 2017-12-31 Annual: 2017-12-31
10-Q 2017-09-30 Quarter: 2017-09-30
10-Q 2017-06-30 Quarter: 2017-06-30
10-Q 2017-03-31 Quarter: 2017-03-31
10-K 2016-12-31 Annual: 2016-12-31
10-Q 2016-09-30 Quarter: 2016-09-30
10-Q 2016-06-30 Quarter: 2016-06-30
10-Q 2016-03-31 Quarter: 2016-03-31
10-K 2015-12-31 Annual: 2015-12-31
10-Q 2015-09-30 Quarter: 2015-09-30
10-Q 2015-06-30 Quarter: 2015-06-30
10-Q 2015-03-31 Quarter: 2015-03-31
10-K 2014-12-31 Annual: 2014-12-31
10-Q 2014-09-30 Quarter: 2014-09-30
10-Q 2014-06-30 Quarter: 2014-06-30
10-Q 2014-03-31 Quarter: 2014-03-31
10-K 2013-12-31 Annual: 2013-12-31
8-K 2019-03-13 Other Events, Exhibits
8-K 2018-10-25 Earnings, Exhibits
8-K 2018-08-27 Other Events
8-K 2018-07-26 Earnings, Exhibits
8-K 2018-06-21 Other Events, Exhibits
8-K 2018-06-07 Other Events
8-K 2018-05-15 Other Events
8-K 2018-04-26 Earnings, Exhibits
8-K 2018-02-07 Earnings, Exhibits
HPT Hospitality Properties Trust 4,340
CCO Clear Channel Outdoor Holdings 1,950
UVSP Univest of Pennsylvania 740
URG UR-Energy 133
CPST Capstone Systems 67
EGI Entree Resources 62
QUMU Qumu 26
RSPI RespireRx Pharmaceuticals 0
ORM Owens Realty Mortgage 0
KSHB Kush Bottles 0
PSCO 2018-12-31
Part I
Item 1A - Risk Factors
Item 1B - Unresolved Staff Comments
Item 2 - Properties
Item 3 - Legal Proceedings
Item 4 - Mine Safety Disclosures
Part II
Item 5 - Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Item 6 - Selected Financial Data
Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 7A - Quantitative and Qualitative Disclosures About Market Risk
Item 8 - Financial Statements and Supplementary Data
Item 9 - Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A - Controls and Procedures
Item 9B - Other Information
Part III
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
Item 14 - Principal Accountant Fees and Services
Part IV
Item 15 - Exhibits, Financial Statement Schedules
Item 16 - Form 10-K Summary
EX-3.02 pscobylaws-amended0125191.htm
EX-23.01 pscoex2301q42018.htm
EX-31.01 pscoex3101q42018.htm
EX-31.02 pscoex3102q42018.htm
EX-32.01 pscoex3201q42018.htm

Public Service Co of Colorado Earnings 2018-12-31

PSCO 10K Annual Report

Balance SheetIncome StatementCash Flow

10-K 1 psco1231201810-k.htm 10-K Document

 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
x
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2018
or
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
001-03280
 
84-0296600
(Commission File Number)
 
(I.R.S. Employer Identification No.)

(Registrant, State of Incorporation or Organization, Address of Principal Executive Officers and Telephone Number)
Public Service Company of Colorado
(a Colorado corporation)
1800 Larimer, Suite 1100
Denver, CO 80202
303-571-7511

Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. x Yes ¨ No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. ¨ Yes x No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x Yes ¨ No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 and Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). x Yes ¨ No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulations S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company”, and “emerging growth company” in Rule 12b-2 of the Exchange Act. ¨ Large accelerated filer ¨ Accelerated filer x Non-accelerated filer ¨ Smaller Reporting Company ¨ Emerging growth company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). ¨ Yes x No
As of Feb. 22, 2019, 100 shares of common stock, par value $0.01 per share, were outstanding, all of which were held by Xcel Energy Inc., a Minnesota corporation.
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 2019 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about April 1, 2019. Such information set forth under such heading is incorporated herein by this reference hereto.
Public Service Company of Colorado meets the conditions set forth in General Instructions I(1)(a) and (b) of Form 10-K and is therefore filing this form with reduced disclosure format permitted by General Instruction I(2).


 

1


TABLE OF CONTENTS
Index
PART I
 
Item 1 — Business
Item 1A — Risk Factors
Item 2 — Properties
 
 
PART II
 
 
 
PART III
 
 
 
PART IV
 
Item 16 — Form 10-K Summary
 
 

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


PART I
Item lBusiness
ABBREVIATIONS AND INDUSTRY TERMS
Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former)
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
D.C. Circuit
United States Court of Appeals for the District of Columbia Circuit
DOT
United States Department of Transportation
EPA
United States Environmental Protection Agency
FERC
Federal Energy Regulatory Commission
IRS
Internal Revenue Service
NERC
North American Electric Reliability Corporation
PHMSA
Pipeline and Hazardous Materials Safety Administration
SEC
Securities and Exchange Commission
 
 
Electric, Purchased Gas and Resource Adjustment Clauses
DSM
Demand side management
DSMCA
Demand side management cost adjustment
ECA
Retail electric commodity adjustment
GCA
Gas cost adjustment
PCCA
Purchased capacity cost adjustment
PSIA
Pipeline system integrity adjustment
RESA
Renewable energy standard adjustment
SCA
Steam cost adjustment
TCA
Transmission cost adjustment
WCA
Windsource® cost adjustment
 
 
Other
AFUDC
Allowance for funds used during construction
ARAM
Average rate assumption method
ARO
Asset retirement obligation
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
CEP
Colorado Energy Plan
CIG
Colorado Interstate Gas Company, LLC
Corps
U.S. Army Corps of Engineers
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
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
PV
Photovoltaic
REC
Renewable energy credit
ROE
Return on equity
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

3


Forward-Looking Statements
Except for the historical statements contained in this report, the matters discussed herein are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements, assumptions and other statements are intended to be identified in this document by the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” “will,” “would” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we expressly disclaim any obligation to update any forward-looking information. The following factors, in addition to those discussed elsewhere in this Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2018 (including risk factors listed from time to time by PSCo in reports filed with the SEC, including “Risk Factors” in Item 1A of this Annual Report on Form 10-K hereto), could cause actual results to differ materially from management expectations as suggested by such forward-looking information: changes in environmental laws and regulations; climate change and other weather natural disaster and resource depletion, including compliance with any accompanying legislative and regulatory changes; ability to recover costs from customers; reductions in our credit ratings and the cost of maintaining certain contractual relationships; general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of PSCo and its subsidiaries to obtain financing on favorable terms; availability or cost of capital; our customers’ and counterparties’ ability to pay their debts to us; assumptions and costs relating to funding our employee benefit plans and health care benefits; tax laws; operational safety; successful long-term operational planning; commodity risks associated with energy markets and production; rising energy prices; costs of potential regulatory penalties; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; fuel costs; and employee work force and third party contractor factors.
Where To Find More Information
PSCO is a wholly owned subsidiary of Xcel Energy Inc., and Xcel Energy’s website address is www.xcelenergy.com. Xcel Energy makes available, free of charge through its website, its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after the reports are electronically filed with or furnished to the SEC. The SEC maintains an internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically at http://www.sec.gov.
COMPANY OVERVIEW
PSCo was incorporated in 1924 under the laws of Colorado. PSCo 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.
pscostate.jpg
 
 
 
 
PSCo
 
Electric customers
1.5 million
 
Natural gas customers
1.4 million
 
Consolidated earnings contribution
35% to 45%
 
Total assets
$17.3 billion
 
Electric generating capacity
5,685 MW
 
Gas storage capacity
27.1 Bcf
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


4


ELECTRIC UTILITY OPERATIONS
Electric Operating Statistics
 
Year Ended Dec. 31
 
2018
 
2017
 
2016
Electric sales (Millions of KWh)
 
 
 
 
 
Residential
9,438

 
9,107

 
9,272

Large C&I
6,566

 
6,449

 
6,371

Small C&I
12,973

 
12,796

 
12,890

Public authorities and other
270

 
274

 
268

Total retail
29,247

 
28,626

 
28,801

Sales for resale
7,403

 
4,851

 
4,672

Total energy sold
36,650

 
33,477

 
33,473

 
 
 
 
 
 
Number of customers at end of period
 
 
 
 
 
Residential
1,271,423

 
1,252,376

 
1,235,378

Large C&I
337

 
340

 
337

Small C&I
161,713

 
160,406

 
159,299

Public authorities and other
54,160

 
54,110

 
54,048

Total retail
1,487,633

 
1,467,232

 
1,449,062

Wholesale
52

 
43

 
34

Total customers
1,487,685

 
1,467,275

 
1,449,096

 
 
 
 
 
 
Electric revenues (Millions of Dollars)
 
 
 
 
 
Residential
$
1,025.1

 
$
1,033.3

 
$
1,063.5

Large C&I
406.8

 
421.1

 
414.8

Small C&I
1,191.2

 
1,227.9

 
1,204.9

Public authorities and other
50.5

 
52.8

 
54.1

Total retail
2,673.6

 
2,735.1

 
2,737.3

Wholesale
179.4

 
168.0

 
152.4

Other electric revenues
178.2

 
100.7

 
159.7

Total electric revenues
$
3,031.2

 
$
3,003.8

 
$
3,049.4

 
 
 
 
 
 
KWh sales per retail customer
19,660

 
19,510

 
19,876

Revenue per retail customer
$
1,797

 
$
1,864

 
$
1,889

Residential revenue per KWh

10.86
¢


11.35
¢


11.47
¢
Large C&I revenue per KWh
6.20

 
6.53

 
6.51

Small C&I revenue per KWh
9.18

 
9.60

 
9.35

Total retail revenue per KWh
9.14

 
9.55

 
9.50

Wholesale revenue per KWh
2.42

 
3.46

 
3.26



5


Energy Sources 2018
 
chart-6cda94edf70d4adeb30.jpg
*Distributed generation from the Solar*Rewards® program is not included (approximately 387 million KWh for 2018).
 
Energy Source Statistics
In 2018 and 2017, of PSCo’s total energy generation, 70% was owned and 30% was purchased.
Renewable Sources
PSCo’s renewable energy portfolio includes wind, hydroelectric, and solar power from both owned generating facilities and PPAs. As of Dec. 31, 2018, PSCo was in compliance with its applicable renewable portfolio standards. Renewable percentages will vary year over year based on local weather, system demand and transmission constraints.
PSCo
Renewable energy as a percentage of PSCo’s total:
 
 
2018
 
2017
Wind
 
23.8
%
 
23.7
%
Hydroelectric and solar
 
3.6

 
3.9

Renewable
 
27.4
%
 
27.6
%
Wind — PSCo has 19 PPAs ranging from two MW to over 300 MW. PSCo owns and operates the Rush Creek wind farm which has 600 MW, net, of capacity.
PSCo had approximately 3,160 MW and 2,560 MW of wind energy on its system at the end of 2018 and 2017, respectively.
Average cost per MWh of wind energy under these contracts was approximately $43 and $42 for 2018 and 2017, respectively.
Rush Creek became operational in December 2018. The 2019 average cost per MWh is expected to be $29.
 
Non-Renewable Sources
Delivered cost per MMBtu of each significant category of fuel consumed for owned electric generation and the percentage of total fuel requirements represented by each category of fuel:
 
 
Coal
 
Natural Gas
 
 
Cost
 
Percent
 
Cost
 
Percent
2018
 
$
1.45

 
62
%
 
$
3.74

 
38
%
2017
 
1.56

 
70

 
3.82

 
30

Weighted average cost per MMBtu of all fuels for owned electric generation was $2.33 in 2018 and $2.25 in 2017.
See Items 1A and 7 for further information.
Coal — Inventory maintained (in days):
Normal
 
Dec. 31, 2018 Actual
 
Dec. 31, 2017 Actual (a)
35 - 50
 
48
 
48
(a) 
Milder weather, purchase commitments and low power and natural gas prices impacted coal inventory levels.
Coal requirements (in million tons) were 9.4 in 2018 and 10.0 in 2017. Coal supply as a percentage of requirements for 2019 is 8.4 million tons or 83% of contracted coal supply. The general coal purchasing objective is to contract for approximately 75% of year one requirements, 40% of year two requirements and 20% of year three requirements.
Contracted coal transportation as a percentage of requirements in 2019 and 2020 is 100%.
Natural Gas — Natural gas supplies, transportation and storage services for power plants are procured to provide an adequate supply of fuel. Remaining requirements are procured through a liquid spot market. Generally, natural gas supply contracts have variable pricing that is tied to natural gas indices. Natural gas supply and transportation agreements include obligations for the purchase and/or delivery of specified volumes or payments in lieu of delivery.
Contracts and commitments at Dec. 31:
(Millions of Dollars)
 
Gas
Supply (a)
 
Gas Transportation and Storage (b)
2018
 
$
412

 
$
589

2017
 
545

 
620

Year of Expiration
 
2021 - 2023

 
2019 - 2040

(a) 
The majority of natural gas supply under contract is covered by a long-term agreement with Anadarko Energy Services Company and the balance of natural gas supply contracts have variable pricing features tied to changes in various natural gas indices. PSCo hedges a portion of that risk through financial instruments. See Note 9 to the consolidated financial statements for further information.
(b) 
For incremental supplies, there are limited on-site fuel storage facilities, with a primary reliance on the spot market.
Capacity and Demand
Uninterrupted system peak demand for PSCo’s electric utility for the last two years is as follows:
System Peak Demand (in MW)
2018
 
2017
6,718

 
July 10
 
6,671

 
July 19
The peak demand typically occurs in the summer. The increase in peak load from 2017 to 2018 is partly due to warmer weather in 2018.

6


Public Utility Regulation
Summary of Regulatory Agencies and Areas of Jurisdiction — PSCo is regulated by the CPUC with respect to its facilities, rates, accounts, services and issuance of securities. PSCo is regulated by the FERC for its wholesale electric operations, accounting practices, hydroelectric licensing, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with the NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce. PSCo is not presently a member of an RTO and does not operate within an RTO energy market. However, PSCo does make certain sales to other RTO’s, including SPP. PSCo makes wholesale electric sales at cost-based prices to customers inside PSCo’s balancing authority area and at market-based prices to customers outside PSCo’s balancing authority area as authorized by the FERC.
Fuel, Purchased Energy and Conservation Cost-Recovery
Mechanisms
ECA — Recovers fuel and purchased energy costs. Short-term sales margins are shared with retail customers through the ECA. The ECA is revised quarterly.
PCCA — Recovers purchased capacity payments.
SCA — Recovers the difference between PSCo’s actual cost of fuel and costs recovered under its steam service rates. The SCA rate is revised quarterly.
DSMCA — Recovers DSM, interruptible service costs and performance initiatives for achieving energy savings goals.
RESA — Recovers the incremental costs of compliance with the RES with a maximum of 2% of the customer’s bill.
WCA — Recovers costs for customers who choose renewable resources.
TCA — Recovers costs for transmission investment outside of rate cases.
CACJA — Recovers costs associated with the CACJA.
PSCo recovers fuel and purchased energy costs from its wholesale electric customers through a fuel cost adjustment clause approved by the FERC. The wholesale customers pay their jurisdictional allocation of production costs through a fully forecasted formula rate with true-up.
Energy Sources and Transmission Service Providers
PSCo expects to meet its system capacity requirements through electric generating stations, power purchases, new generation facilities, DSM options and expansion of generation plants.
Purchased Power — PSCo purchases power from other utilities and IPPs. Long-term purchased power contracts for dispatchable resources typically require capacity charge and energy charges. PSCo also contracts to purchase power for both wind and solar resources. PSCo makes short-term purchases to meet system load and energy requirements, replace owned generation, meet operating reserve obligations or obtain energy at a lower cost.
Purchased Transmission Services — In addition to using its own transmission system, PSCo has contracts with regional transmission service providers to deliver energy to its customers.
Wind Development — In 2018, PSCo completed construction and placed in service its Rush Creek 600 MW wind farm in Colorado.
 
CEP — In September 2018, the CPUC approved PSCo’s preferred CEP portfolio, which included the retirement of two coal-fired generation units, Comanche Unit 1 (in 2022) and Comanche Unit 2 (in 2025), and the following additions:
 
Total Capacity
 
PSCo's Ownership
Wind generation
1,100 MW
 
500 MW

Solar generation
700 MW
 

Battery storage
275 MW
 

Natural gas generation
380 MW
 
380 MW

PSCo’s investment is expected to be approximately $1 billion, including transmission to support the increase in renewable generation in the state. This investment includes the 500 MW Cheyenne Ridge Wind Farm and the 345 KV generation tie line, as well as the Shortgrass Substation. CPCNs for these projects were filed in December 2018. A CPUC decision is anticipated by May 2019. CPCNs for the natural gas facility are anticipated to be filed by mid-2019.
Boulder Municipalization — In 2011, Boulder passed a ballot measure authorizing the formation of an electric municipal utility, subject to certain conditions. Subsequently, there have been various legal proceedings in multiple venues with jurisdiction over Boulder’s plan. In 2014, the Boulder City Council passed an ordinance to establish an electric utility. PSCo challenged the formation of this utility and the Colorado Court of Appeals ruled in PSCo’s favor, vacating a lower court decision. In June 2018, the Colorado Supreme court rejected Boulder’s request to dismiss the case and remanded it to the Boulder District Court.
Boulder has filed multiple separation applications with the CPUC, which have been challenged by PSCo and other intervenors. In September 2017, the CPUC issued a written decision, agreeing with several key aspects of PSCo’s position. The CPUC has approved the designation of some electrical distribution assets for transfer, subject to Boulder completing certain filings. Those filings were submitted in the fourth quarter of 2018. Subsequently, various parties requested the CPUC commence additional processes; the form of such processes is currently under consideration. In the fourth quarter of 2018, Boulder’s City Council also adopted an Ordinance authorizing Boulder to begin negotiations for the acquisition of certain property or to otherwise condemn that property after Feb. 1, 2019. In the first quarter of 2019, Boulder sent PSCo a Notice of Intent to acquire certain electric distribution assets.
Boulder does not have authorization from the CPUC to initiate a condemnation proceeding at this time.
Wholesale and Commodity Marketing Operations
PSCo conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy related products. PSCo uses physical and financial instruments to minimize commodity price and credit risk and hedge sales and purchases. PSCo also engages in trading activity unrelated to hedging and sharing of any margins is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement.

7


NATURAL GAS UTILITY OPERATIONS
Natural Gas Operating Statistics
 
Year Ended Dec. 31
 
2018
 
2017
 
2016
Natural gas deliveries (Thousands of MMBtu)
 
 
 
 
 
Residential
97,409

 
88,843

 
90,941

C&I
40,467

 
37,305

 
38,093

Total retail
137,876

 
126,148

 
129,034

Transportation and other
155,281

 
124,211

 
117,462

Total deliveries
293,157

 
250,359

 
246,496

 
 
 
 
 
 
Number of customers at end of period
 
 
 
 
 
Residential
1,300,826

 
1,284,644

 
1,269,338

C&I
101,036

 
100,802

 
100,718

Total retail
1,401,862

 
1,385,446

 
1,370,056

Transportation and other
7,891

 
7,649

 
7,261

Total customers
1,409,753

 
1,393,095

 
1,377,317

 
 
 
 
 
 
Natural gas revenues (Millions of Dollars)
 
 
 
 
 
Residential
$
649.9

 
$
652.9

 
$
611.8

C&I
244.5

 
247.6

 
228.1

Total retail
894.4

 
900.5

 
839.9

Transportation and other
120.2

 
94.7

 
117.8

Total natural gas revenues
$
1,014.6

 
$
995.2

 
$
957.7

 
 
 
 
 
 
MMBtu sales per retail customer
98.35

 
91.05

 
94.18

Revenue per retail customer
$
638

 
$
650

 
$
613

Residential revenue per MMBtu
6.67

 
7.35

 
6.73

C&I revenue per MMBtu
6.04

 
6.64

 
5.99

Transportation and other revenue per MMBtu
0.77

 
0.76

 
1.00

Capability and Demand
Natural gas supply requirements are categorized as firm or interruptible (customers with an alternate energy supply).
Maximum daily send-out (firm and interruptible) and occurrence date for PSCo:
2018
 
2017
MMBtu
 
Date
 
MMBtu
 
Date
1,903,878

(a) 
Feb. 20
 
1,948,167

 
Jan. 5
(a) 
Decrease in MMBtu output due to milder winter temperatures in 2018.
Natural gas is purchased from independent suppliers, generally based on market indices that reflect current prices, and is delivered under transportation agreements with interstate pipelines. These agreements provide for firm deliverable pipeline capacity of 1,834,843 MMBtu per day. This amount includes 871,418 MMBtu of natural gas held under third-party underground storage agreements.
PSCo also operates three company-owned underground storage facilities, which provide approximately 43,500 MMBtu of natural gas on peak days. The balance required to meet firm peak day sales obligations is primarily purchased at PSCo’s city gate meter stations.
 
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 their respective state commissions.
Average delivered cost per MMBtu of natural gas for regulated retail distribution was $3.20 and $3.45 in 2018 and 2017, respectively.
PSCo has natural gas supply transportation and storage agreements that include obligations for the purchase and/or delivery of specified volumes or to make payments in lieu of delivery. As of Dec. 31, 2018, PSCo was committed to approximately $1.1 billion of obligations under contracts, which expire in various years from 2019 - 2029.
Public Utility Regulation
Summary of Regulatory Agencies and Areas of Jurisdiction — PSCo is regulated by the CPUC with respect to its facilities, rates, accounts, services and issuance of securities. PSCo holds a FERC certificate that allows it to transport natural gas in interstate commerce without PSCo becoming subject to full FERC jurisdiction. PSCo is subject to the DOT and CPUC with regards to pipeline safety compliance.

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Purchased Natural Gas and Conservation Cost-Recovery
Mechanisms
GCA — Recovers the costs of purchased natural gas and transportation to meet customer requirements and is revised quarterly to allow for changes in natural gas rates.
DSMCA — Recovers costs of DSM and performance initiatives to achieve various energy savings goals.
PSIA — Recovers costs for transmission and distribution pipeline integrity management programs.
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.
See Item 7 for further information.
Competition
PSCo is a vertically integrated utility subject to traditional cost-of-service regulation by state public utilities commissions. 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, but not limited to, solar generation and in most jurisdictions can currently avoid paying for most of the fixed production, transmission and distribution costs incurred to serve them. Several states, including PSCo, have policies designed to promote the development of solar and other distributed energy resources through incentive policies. With these incentives and federal tax subsidies, distributed generating resources are potential competitors to PSCo’s electric service business.
The FERC has continued to promote competitive wholesale markets through open access transmission and other means. As a result, PSCo and its wholesale customers can purchase the output from generation resources of competing wholesale suppliers and use the transmission systems of Xcel Energy Inc.’s utility subsidiaries on a comparable basis to serve their native load.
FERC Order No. 1000 seeks to establish competition for construction and operation of certain new electric transmission facilities. State utilities commissions have also created resource planning programs that promote competition for electricity generation resources used to provide service to retail customers.
PSCo 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 the alternatives currently available.
 
ENVIRONMENTAL MATTERS
PSCo’s facilities are regulated by federal and state environmental agencies that have jurisdiction over air emissions, water quality, wastewater discharges, solid wastes and hazardous substances. Various company activities require registrations, permits, licenses, inspections and approvals from these agencies. PSCo has received all necessary authorizations for the construction and continued operation of its generation, transmission and distribution systems. PSCo’s facilities have been designed and constructed to operate in compliance with applicable environmental standards and related monitoring and reporting requirements. However, it is not possible to determine when or to what extent additional facilities or modifications of existing or planned facilities will be required as a result of changes to environmental regulations, interpretations or enforcement policies or what effect future laws or regulations may have upon PSCo’s operations. PSCo may be required to incur capital expenditures in the future to comply with requirements for remediation of MGP and other legacy sites. The scope and timing of these expenditures cannot be determined until more information is obtained regarding the need for remediation at legacy sites.
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 implement enhanced emissions monitoring as part of future Colorado state plans.
There are significant present and future environmental regulations to encourage use of clean energy technologies and regulate emissions of GHGs. 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 provide credit for the investments PSCo has already made or if they require additional initiatives or emission reductions, substantial costs may be incurred.
The EPA, as an alternative to the Clean Power Plan, has proposed a new regulation that, if adopted, would require implementation of heat rate improvement projects at our coal-fired power plants. It is not known what those costs might be until a final rule is adopted and state plans are developed to implement a final regulation. PSCo believes, based on prior state commission practice, the cost of these initiatives or replacement generation would be recoverable through rates.
PSCo is committed to addressing climate change and potential climate change regulation through efforts to reduce its GHG emissions in a balanced, cost-effective manner. Starting in 2011, PSCo began reporting GHG emissions under the EPA’s mandatory GHG Reporting Program.
EMPLOYEES
As of Dec. 31, 2018, PSCo had 2,426 full-time employees and no part-time employees, of which 1,904 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.

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Oversight of Risk and Related Processes
A key accountability of the Board of Directors is the oversight of material risk, and our Board of Directors employs an effective process for doing so. Management and the Board of Directors have responsibility for overseeing the identification and mitigation of key risks.
Management identifies and analyzes risks to determine materiality and other attributes such as timing, probability and controllability. Identification and analysis occurs formally through a key risk assessment process by senior management, the financial disclosure process, hazard risk management procedures and internal auditing and compliance with financial and operational controls. Management also identifies and analyzes risk through its business planning process and development of goals and key performance indicators, which include risk identification to determine barriers to implementing our strategy. The business planning process also identifies areas in which there is a potential for a business area to assume inappropriate risk to meet goals, and determines how to prevent inappropriate risk-taking.
At a threshold level, PSCo has a robust compliance program and promotes a culture of compliance, including tone at the top. The process for risk mitigation includes adherence to our code of conduct and compliance policies, operation of formal risk management structures and overall business management to mitigate the risks inherent in the implementation of strategy. Building on this culture of compliance, management further mitigates risks through formal risk management structures, including management councils, risk committees and services of corporate areas such as internal audit, corporate controller and legal.
Management communicates regularly with the Board of Directors and key stakeholders regarding risk. Senior management presents and communicates a periodic risk assessment to the Board of Directors. The presentation and the discussion of the key risks provide information on the risks management believes are material, including the earnings impact, timing, likelihood and controllability. Oversight of cybersecurity risks by the Operations, Nuclear, Environmental and Safety Committee includes receiving independent outside assessments of cybersecurity maturity and assessment of plans.
Overall, the Board of Directors approaches oversight, management and mitigation of risk as an integral and continuous part of its governance of PSCo. Processes are in place to ensure appropriate risk oversight, as well as identification and consideration of new risks. The Board of Directors regularly reviews management’s key risk assessment informed by these processes, and analyzes areas of existing and future risks and opportunities.
Risks Associated with Our Business
Operational Risks
Our natural gas and electric transmission and distribution operations involve numerous risks that may result in accidents and other operating risks and costs.
Our natural gas transmission and distribution activities include inherent hazards and operating risks, such as leaks, explosions, outages and mechanical problems. Our electric transmission and distribution activities also include inherent hazards and operating risks such as contact, fire and outages which could cause substantial financial losses. These natural gas and electric risks could result in loss of life, significant property damage, environmental pollution, impairment of our operations and substantial losses. We maintain insurance against some, but not all, of these risks and losses. The occurrence of these events, if not fully covered by insurance, could have a material effect on our results of operations, financial condition or cash flows.
 
Additionally, for natural gas costs that may be required in order to comply with potential new regulations, including the Pipeline Safety Act, could be significant.
The Pipeline Safety Act requires verification of pipeline infrastructure records by pipeline owners and operators to confirm the maximum allowable operating pressure of lines located in high consequence areas or more-densely populated areas. We have programs in place to comply with the Pipeline Safety Act and for systematic infrastructure monitoring and renewal over time. A significant incident could increase regulatory scrutiny and result in penalties and higher costs of operations.
The PHMSA is responsible for administering the DOT’s national regulatory program to assure the safe transportation of natural gas, petroleum and other hazardous materials by pipelines. The PHMSA continues to develop regulations and other approaches to risk management to assure safety in design, construction, testing, operation, maintenance, and emergency response of natural gas pipeline infrastructure.
Our utility operations are subject to long-term planning risks.
Most electric utility investments are planned to be used for decades. Transmission and generation investments typically have long lead times and are planned well in advance of when they are brought in-service subject to long-term resource plans. These plans are based on numerous assumptions such as: sales growth, customer usage, commodity prices, economic activity, costs, regulatory mechanisms, customer behavior, available technology and public policy.
The electric utility sector is undergoing a period of significant change. For example, increases in appliance, lighting and energy efficiency, wider adoption and lower cost of renewable generation and distributed generation, shifts away from coal generation to decrease carbon dioxide emissions and increasing use of natural gas in electric generation driven by lower natural gas prices.
Customer adoption of these technologies and increased energy efficiency could result in excess transmission and generation resources as well as stranded costs if PSCo is not able to fully recover the costs and investments. These changes also introduce additional uncertainty into long-term planning which gives rise to a risk that the magnitude and timing of resource additions and growth in customer demand may not coincide, and that the preference for the types of additions may change from planning to execution. In addition, we are subject to longer-term availability of the natural resource inputs such as coal, natural gas, uranium and water to cool our facilities. Lack of availability of these resources could jeopardize long-term operations of our facilities or make them uneconomic to operate.
Changing customer expectations and technologies are requiring significant investments in advanced grid infrastructure. This increases the exposure to potential outdating of technologies and resultant risks. The inability of coal mining companies to attract capital could disrupt longer-term supplies. Decreasing use per customer driven by appliance and lighting efficiency and the availability of cost-effective distributed generation places downward pressure on sales growth. This may lead to under recovery of costs, excess resources to meet customer demand and increases in electric rates. Finally, multiple states may not agree as to the appropriate resource mix and the differing views may lead to costs incurred to comply with one jurisdiction that are not recoverable across all of the jurisdictions served by the same assets.

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We are subject to commodity risks and other risks associated with energy markets and energy production.
If fuel costs increase, customer demand could decline and bad debt expense may rise, which could have a material impact on our results of operations. While we have fuel clause recovery mechanisms, higher fuel costs could significantly impact our results of operations if costs are not recovered. Delays in the timing of the collection of fuel cost recoveries could impact our cash flows. Low fuel costs have a positive impact on sales, however low oil and natural gas prices could negatively impact oil and gas production activities and subsequently our sales volumes and revenue.
A significant disruption in supply could cause us to seek alternative supply services at potentially higher costs or suffer increased liability for unfulfilled contractual obligations. Significantly higher energy or fuel costs relative to sales commitments have a negative impact on our cash flows and potentially result in economic losses. Potential market supply shortages may not be fully resolved through alternative supply sources and could cause disruptions in our ability to provide electric and/or natural gas services to our customers. Failure to provide service due to disruptions may also result in fines, penalties or cost disallowances through the regulatory process.
We also engage in wholesale sales and purchases of electric capacity, energy and energy-related products as well as natural gas. In many markets, emission allowances and/or RECs are also needed to comply with various statutes and commission rulings. As a result we are subject to market supply and commodity price risk. Commodity price changes can affect the value of our commodity trading derivatives. We mark certain derivatives to estimated fair market value on a daily basis. Actual settlements can vary significantly from estimated fair values recorded and significant changes from the assumptions underlying our fair value estimates could cause earnings variability.
As we are a subsidiary of Xcel Energy Inc., we may be negatively affected by events impacting the credit or liquidity of Xcel Energy Inc. and its affiliates.
If Xcel Energy Inc. were to become obligated to make payments under various guarantees and bond indemnities or to fund its other contingent liabilities, or if either Standard & Poor’s or Moody’s were to downgrade Xcel Energy Inc.’s credit rating below investment grade, Xcel Energy Inc. may be required to provide credit enhancements in the form of cash collateral, letters of credit or other security to satisfy part or potentially all of these exposures. If either Standard & Poor’s or Moody’s were to downgrade Xcel Energy Inc.’s debt securities below investment grade, it would increase Xcel Energy Inc.’s cost of capital and restrict its access to the capital markets. This could limit Xcel Energy Inc.’s ability to contribute equity or make loans to us, or may cause Xcel Energy Inc. to seek additional or accelerated funding from us in the form of dividends. If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.
As of Dec. 31, 2018, Xcel Energy Inc. and its utility subsidiaries had approximately $15.8 billion of long-term debt and $1.4 billion of short-term debt and current maturities. Xcel Energy Inc. provides various guarantees and bond indemnities supporting some of its subsidiaries by guaranteeing the payment or performance by these subsidiaries for specified agreements or transactions.
 
Xcel Energy also has other contingent liabilities resulting from various tax disputes and other matters. Xcel Energy Inc.’s exposure under the guarantees is based upon the net liability of the relevant subsidiary under the specified agreements or transactions. The majority of Xcel Energy Inc.’s guarantees limit its exposure to a maximum amount that is stated in the guarantees. As of Dec. 31, 2018, Xcel Energy had guarantees outstanding with a maximum stated amount of approximately $17.8 million and immaterial exposure. Xcel Energy also had additional guarantees of $51.1 million at Dec. 31, 2018 for performance and payment of surety bonds for the benefit of itself and its subsidiaries, with total exposure that cannot be estimated at this time. If Xcel Energy Inc. were to become obligated to make payments under these guarantees and bond indemnities or become obligated to fund other contingent liabilities, it could limit Xcel Energy Inc.’s ability to contribute equity or make loans to us, or may cause Xcel Energy Inc. to seek additional or accelerated funding from us in the form of dividends. If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.
We are a wholly owned subsidiary of Xcel Energy Inc. Xcel Energy Inc. can exercise substantial control over our dividend policy and business and operations and may exercise that control in a manner that may be perceived to be adverse to our interests.
All of the members of our Board of Directors, as well as many of our executive officers, are officers of Xcel Energy Inc. Our Board makes determinations with respect to a number of significant corporate events, including the payment of our dividends.
We have historically paid quarterly dividends to Xcel Energy Inc. In 2018, 2017 and 2016 we paid $375.3 million, $333.9 million and $336.6 million of dividends to Xcel Energy Inc., respectively. If Xcel Energy Inc.’s cash requirements increase, our 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. In a continued low interest rate environment there has been pressure pushing down ROE. There can also be no assurance that our regulatory commission will judge all of our costs to be prudent, which could result in disallowances, or that the regulatory process always result in rates that will produce full recovery.

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Changes in the long-term cost-effectiveness or changes to the operating conditions of our assets may result in early retirements of utility facilities and while regulation typically provides relief for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs leaving all or a portion of these asset costs stranded. Higher than expected inflation or tariffs may increase costs of construction and operations. Rising fuel costs could increase the risk that we will not be able to fully recover our fuel costs from our customers. Furthermore, there could be changes in the regulatory environment that would impair our ability to recover costs historically collected from our customers, or these factors could cause us to exceed commitments made regarding cost caps and result in less than full recovery. Overall, management currently believes prudently incurred costs are recoverable given the existing regulatory mechanisms in place.
Adverse regulatory rulings or the imposition of additional regulations could have an adverse impact on our results of operations and materially affect our ability to meet our financial obligations, including debt payments.
Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships.
We cannot be assured that our current ratings will remain in effect, or that a rating will not be lowered or withdrawn by a rating agency. Significant events including a disallowance of costs, significantly lower returns on equity or equity ratios or impacts of tax policy changes may impact our cash flows and credit metrics, potentially resulting in a change in our credit ratings. In addition, our credit ratings may change as a result of the differing methodologies or change in the methodologies used by the various rating agencies.
Any downgrade could lead to higher borrowing costs and could impact our ability to access capital markets. Also, we may enter into contracts that require the posting of collateral or settlement of applicable contracts if credit ratings fall below investment grade.
We are subject to capital market and interest rate risks.
Utility operations require significant capital investment. As a result, we frequently need to access capital markets. Any disruption in capital markets could have a material impact on our ability to fund our operations. Capital markets are global and impacted by issues and events throughout the world. Capital market disruption events and financial market distress could prevent us from issuing short-term commercial paper, issuing new securities or cause us to issue securities with unfavorable terms and conditions, such as higher interest rates.
Higher interest rates on short-term borrowings with variable interest rates could also have an adverse effect on our operating results. Changes in interest rates may also impact the fair value of the debt securities in the pension funds, as well as our ability to earn a return on short-term investments of excess cash.
We are subject to credit risks.
Credit risk includes the risk that our customers will not pay their bills, which may lead to a reduction in liquidity and an increase in bad debt expense. Credit risk is comprised of numerous factors including the price of products and services provided, the overall economy and local economies in the geographic areas we serve, including local unemployment rates.
Credit risk also includes the risk that various counterparties that owe us money or product will become insolvent and/or breach their obligations. Should the counterparties fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected and incur losses.
 
We may at times have direct credit exposure in our short-term wholesale and commodity trading activity to financial institutions trading for their own accounts or issuing collateral support on behalf of other counterparties. We may also have some indirect credit exposure due to participation in organized markets, such as the California Independent System Operator, SPP, PJM Interconnection, LLC, Midcontinent Independent Transmission System Operator, Inc. and the ERCOT, in which any credit losses are socialized to all market participants.
We have additional indirect credit exposures to financial institutions in the form of letters of credit provided as security by power suppliers under various purchased power contracts. If any of the credit ratings of the letter of credit issuers were to drop below investment grade, the supplier would need to replace that security with an acceptable substitute. If the security were not replaced, the party could be in default under the contract.
Increasing costs of our defined benefit retirement plans and employee benefits may adversely affect our results of operations, financial condition or cash flows.
We have defined benefit pension and postretirement plans that cover most of our employees. Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements related to these plans. Estimates and assumptions may change. In addition, the Pension Protection Act changed the minimum funding requirements for defined benefit pension plans. Therefore, our funding requirements and related contributions may change in the future. Also, the payout of a significant percentage of pension plan liabilities in a single year due to high retirements or employees leaving PSCo could trigger settlement accounting and could require PSCo to recognize incremental pension expense related to unrecognized plan losses in the year liabilities are paid.
Increasing costs associated with health care plans may adversely affect our results of operations.
Our self-insured costs of health care benefits for eligible employees have increased in recent years. Increasing levels of large individual health care claims and overall health care claims could have an adverse impact on our operating results, financial condition and cash flows. Changes in industry standards utilized in key assumptions (e.g., mortality tables) could have a significant impact on future liabilities and benefit costs. Legislation related to health care could also significantly change our benefit programs and costs.
Federal tax law may significantly impact our business.
PSCo collects through regulated rates estimated federal, state and local tax payments. Changes to federal tax law may benefit or adversely affect our earnings and customer costs. Changes to tax depreciable lives and the value of various tax credits may change the economics of resources and our resource selections. There could be timing delays before regulated rates provide for realization of the tax changes in revenues. In addition, certain IRS tax policies such as the requirement to utilize normalization may impact our ability to economically deliver certain types of resources relative to market prices.
Macroeconomic Risks
Economic conditions impact our business.
Our operations are affected by local, national and worldwide economic conditions. Growth in customers and sales are correlated with economic conditions.

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Economic conditions may be impacted by insufficient financial sector liquidity leading to potential increased unemployment, which may impact customers’ ability to pay timely, increase customer bankruptcies, and may lead to additional bad debt expense.
Further, worldwide economic activity impacts the demand for basic commodities necessary for utility infrastructure, which may impact our ability to acquire sufficient supplies. We operate in a capital intensive industry and federal policy on trade could significantly impact the cost of materials we use. We could be at risk for higher costs for materials and our workforce. There may be delays before these additional costs can be recovered in rates.
Our operations could be impacted by war, acts of terrorism, and threats of terrorism or disruptions due to events.
Our generation plants, fuel storage facilities, transmission and distribution facilities and information and control systems may be targets of terrorist activities. Any disruption could impact operations or result in a decrease in revenues and additional costs to repair and insure our assets. These disruptions could have a material impact on our financial condition, results of operations or cash flows. The potential for terrorism has subjected our operations to increased risks and could have a material effect on our business. We have already incurred increased costs for security and capital expenditures in response to these risks.
The insurance industry has also been affected by these events and the availability of insurance may decrease. In addition, insurance may have higher deductibles, higher premiums and more restrictive policy terms.
A disruption of the regional electric transmission grid, interstate natural gas pipeline infrastructure or other fuel sources, could negatively impact our business, our brand and reputation. Because our facilities are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by the actions of a neighboring utility or an event (e.g., severe storm, severe temperature extremes, wildfires, generator or transmission facility outage, pipeline rupture, railroad disruption, operator error, sudden and significant increase or decrease in wind generation or a disruption of work force) within our operating systems or on a neighboring system. Any such disruption could result in a significant decrease in revenues and significant additional costs to repair assets, which could have a material impact on our results of operations, financial condition or cash flows.
A cyber incident or security breach could have a material effect on our business.
We operate in an industry that requires the continued operation of sophisticated information technology, control systems and network infrastructure. In addition, we use our systems and infrastructure to create, collect, use, disclose, store, dispose of and otherwise process sensitive information, including company data, customer energy usage data, and personal information regarding customers, employees and their dependents, contractors and other individuals.
Our generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets, as well as information processed in our systems (e.g., information regarding our customers, employees, operations, infrastructure and assets) could be affected by cyber security incidents, including those caused by human error.
 
Our industry has begun to see an increased volume and sophistication of cyber security incidents from international activist organizations, Nation States and individuals. Cyber security incidents could harm our businesses by limiting our generating, transmitting and distributing capabilities, delaying our development and construction of new facilities or capital improvement projects to existing facilities, disrupting our customer operations or causing the release of customer information, all of which could expose us to liability.
Our generation, transmission systems and natural gas pipelines are part of an interconnected system. Therefore, a disruption caused by the impact of a cyber security incident of the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources of our third party service providers’ operations, could also negatively impact our business. 
Our supply chain for procurement of digital equipment may expose software or hardware to these risks and could result in a breach or significant costs of remediation. In addition, such an event would likely receive federal and state regulatory scrutiny. We are unable to quantify the potential impact of cyber security threats or subsequent related actions. These potential cyber security incidents and regulatory action could result in a material decrease in revenues and may cause significant additional costs (e.g., penalties, third party claims, repairs, insurance or compliance) and potentially disrupt our supply and markets for natural gas, oil and other fuels.
We maintain security measures to protect our information technology and control systems, network infrastructure and other assets. However, these assets and the information they process may be vulnerable to cyber security incidents, including the resulting disability, or failures of assets or unauthorized access to assets or information. If our technology systems or those of our third-party service providers were to fail or be breached, we may be unable to fulfill critical business functions. We are unable to quantify the potential impact of cyber security incidents on our business, our brand, and our reputation. The cyber security threat is dynamic and evolves continually, and our efforts to prioritize network monitoring may not be effective given the constant changes to threat vulnerability.
Our operating results may fluctuate on a seasonal and quarterly basis and can be adversely affected by milder weather.
Our electric and natural gas utility businesses are seasonal, and weather patterns can have a material impact on our operating performance. Demand for electricity is often greater in the summer and winter months associated with cooling and heating. Because natural gas is heavily used for residential and commercial heating, the demand depends heavily upon weather patterns. A significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. Unusually mild winters and summers could have an adverse effect on our financial condition, results of operations or cash flows.
Our operations use third party contractors in addition to employees to perform periodic and on-going work.
We rely on third party contractors to perform work for operations, maintenance and construction. We have contractual arrangements with these contractors which typically include performance standards, progress payments, insurance requirements and security for performance.
Cyber security breaches have at times exploited third party equipment or software in order to gain access. Poor vendor performance could impact ongoing operations, restoration operations, our reputation and could introduce financial risk or risks of fines.

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Public Policy Risks
We may be subject to legislative and regulatory responses to climate change, with which compliance could be difficult and costly.
Legislative and regulatory responses related to climate change and new interpretations of existing laws create financial risk as our facilities may be subject to additional regulation at either the state or federal level in the future. Such regulations could impose substantial costs on our system.
We may be subject to climate change lawsuits. An adverse outcome could require substantial capital expenditures and could possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant. Such payments or expenditures could affect results of operations, financial condition or cash flows if such costs are not recovered through regulated rates.
Although the United States has not adopted any international or federal GHG emission reduction targets, many states and localities may continue to pursue climate policies in the absence of federal mandates. All of the steps that 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 financial condition, results of operations or cash flows.
Increased risks of regulatory penalties could negatively impact our business.
The Energy Act increased civil penalty authority for violation of FERC statutes, rules and orders. The FERC can impose penalties of up to $1.3 million per violation per day, particularly as it relates to energy trading activities for both electricity and natural gas. In addition, NERC electric reliability standards and critical infrastructure protection requirements are mandatory and subject to potential financial penalties. Additionally, the PHMSA, Occupational Safety and Health Administration and other federal agencies have penalty authority. In the event of serious incidents, these agencies have become more active in pursuing penalties. Some states have the authority to impose substantial penalties. If a serious reliability or safety incident did occur, it could have a material effect on our financial condition, results of operations or cash flows.
Environmental Risks
We are subject to environmental laws and regulations, with which compliance could be difficult and costly.
We are subject to environmental laws and regulations that affect many aspects of our operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances. Laws and regulations require us to obtain permits, licenses, and approvals and to comply with a variety of environmental requirements.
Environmental laws and regulations can also require us to restrict or limit the output of facilities or the use of certain fuels, shift generation to lower-emitting, install pollution control equipment, clean up spills and other contamination and correct environmental hazards. Environmental regulations may also lead to shutdown of existing facilities.
 
Failure to meet requirements of environmental mandates may result in fines or penalties. We may be required to pay all or a portion of the cost to remediate (i.e., clean-up) sites where our past activities, or the activities of other parties, caused environmental contamination.
We are subject to mandates to provide customers with clean energy, renewable energy and energy conservation offerings. It could have a material effect on our results of operations, financial condition or cash flows. If our regulators do not allow us to recover the cost of capital investment or the O&M costs incurred to comply with the requirements.
In addition, existing environmental laws or regulations may be revised, and new laws or regulations may be adopted. We may also incur additional unanticipated obligations or liabilities under existing environmental laws and regulations.
We are subject to physical and financial risks associated with climate change and other weather, natural disaster and resource depletion impacts.
Climate change can create physical and financial risk. Physical risks include changes in weather conditions and extreme weather events.
Our customers’ energy needs vary with weather. To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease. Increased energy use due to weather changes may require us to invest in generating assets, transmission and infrastructure. Decreased energy use due to weather changes may result in decreased revenues. Extreme weather conditions in general require system backup, costs, and can contribute to increased system stress, including service interruptions. Extreme weather conditions creating high energy demand may raise electricity prices, increasing the cost of energy we provide to our customers.
Severe weather impacts our service territories, primarily when thunderstorms, flooding, tornadoes, wildfires and snow or ice storms occur. To the extent the frequency of extreme weather events increases, this could increase our cost of providing service. Periods of extreme temperatures could impact our ability to meet demand. Changes in precipitation resulting in droughts or water shortages could adversely affect our operations. Drought conditions also contribute to the increase in wildfire risk from our electric generation facilities. While we carry liability insurance, given an extreme event, if PSCo was found to be liable for wildfire damages, amounts that potentially exceed our coverage could negatively impact our results of operations, financial condition or cash flows. Drought or water depletion could adversely impact our ability to provide electricity to customers and increase the price paid for energy. We may not recover all costs related to mitigating these physical and financial risks.
Climate change may impact a region’s economy, which could impact our sales and revenues. The price of energy has an impact on the economic health of our communities. The cost of additional regulatory requirements, such as regulation of GHG, could impact the availability of goods and prices charged by our suppliers which would normally be borne by consumers through higher prices for energy and purchased goods. To the extent financial markets view climate change and emissions of GHGs as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less than ideal terms and conditions.
Item 1B — Unresolved Staff Comments
None.

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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, 9 Units
 
Hydro
 
Various
 
26

 
Wind:
 
 
 
 
 
 
 
Rush Creek, CO, 300 units
 
Wind
 
2018
 
600

(g) 
 
 
 
 
Total
 
5,685

 
(a) 
Summer 2018 net dependable capacity.
(b) 
In 2018, the CPUC approved early retirement of PSCo’s Comanche Units 1 and 2 in 2022 and 2025, respectively.
(c) 
Based on PSCo’s ownership interest of 67% of Unit 3.
(d) 
Craig Unit 1 is expected to be retired early in 2025.
(e) 
Based on PSCo’s ownership interest of 10%. Craig Unit 1 is expected to be retired early in 2025.
(f) 
Based on PSCo’s ownership interest of 76% of Unit 1 and 37% of Unit 2.
(g) 
Generation capability is based on the maximum output level of wind units, including the Rush Creek Wind Project. Capacity is attainable only when wind conditions are sufficiently available (on-demand net dependable capacity is zero).
Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2018:
Conductor Miles
 
345 KV
4,062

230 KV
12,053

138 KV
91

115 KV
5,051

Less than 115 KV
78,446

PSCo had 232 electric utility transmission and distribution substations at Dec. 31, 2018.
Natural gas utility mains at Dec. 31, 2018:
Miles
 
Transmission
2,081

Distribution
22,518

 
Item 3 — Legal Proceedings
PSCo is involved in various litigation matters that are being defended and handled in the ordinary course of business. Assessment of whether a loss is probable or is a reasonable possibility, and whether a loss or a range of loss is estimable, often involves a series of complex judgments regarding future events. Management maintains accruals for losses that are probable of being incurred and subject to reasonable estimation. Management may be unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to, when (1) damages sought are indeterminate, (2) proceedings are in the early stages or (3) matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.
See Note 11 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 2018 and 2017 were as follows:
(Millions of Dollars)
 
2018
 
2017
First quarter
 
$
95.4

 
$
87.1

Second quarter
 
100.3

 
84.0

Third quarter
 
103.5

 
88.6

Fourth quarter
 
91.5

 
76.2

Item 6 — Selected Financial Data
This is omitted per conditions set forth in general instructions I (1)(a) and (b) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).
Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations
Discussion of financial condition and liquidity for PSCo is omitted per conditions set forth in general instructions I(1)(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).

15


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, 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.
Results of Operations
PSCo’s net income was approximately $551.7 million for 2018, compared with approximately $494.1 million for 2017. The increase was driven by higher natural gas margins largely due to a natural gas rate increase, higher electric margins (before the impact of the TCJA) reflecting favorable weather and sales growth, and additional AFUDC associated with the Rush Creek wind project. These items were partially offset by higher O&M expenses, interest charges, depreciation expense and property taxes.
 
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.
Electric revenues and margin before and after the impact of TCJA:
(Millions of Dollars)
 
2018
 
2017
Electric revenues before TCJA impact
 
$
3,095.4

 
$
3,003.8

Electric fuel and purchased power
 
(1,157.2
)
 
(1,126.7
)
Electric margin before TCJA impact
 
$
1,938.2

 
$
1,877.1

TCJA impact (offset as a reduction in income tax)
 
(64.2
)
 

Electric margin
 
$
1,874.0

 
$
1,877.1

Electric Margin
(Millions of Dollars)
 
2018 vs. 2017
Retail sales growth (excluding weather impact)
 
$
16.4

DSM program revenues (offset by expenses)
 
14.1

Non-fuel riders
 
12.9

Estimated impact of weather
 
12.8

Other, net
 
4.9

Total increase in electric margin before TCJA impact
 
$
61.1

TCJA impact (offset as a reduction in income tax)
 
(64.2
)
Total decrease in electric margin
 
$
(3.1
)
Natural Gas Margin
Total natural gas expense varies with changing sales and the cost of natural gas. However, fluctuations in the cost of natural gas have minimal impact on natural gas margin due to natural gas cost recovery mechanisms.
Natural gas revenues and margin before and after the impact of the TCJA:
(Millions of Dollars)
 
2018
 
2017
Natural gas revenues before TCJA impact
 
$
1,044.8

 
$
995.2

Cost of natural gas sold and transported
 
(428.4
)
 
(458.7
)
Natural gas margin before TCJA impact
 
$
616.4

 
$
536.5

TCJA impact (offset as a reduction in income tax)
 
(30.2
)
 

Natural gas margin
 
$
586.2

 
$
536.5

Natural Gas Margin
(Millions of Dollars)
 
2018 vs. 2017
Retail rate increase
 
$
50.1

Infrastructure and integrity riders
 
14.9

Estimated impact of weather
 
8.0

Retail sales growth (excluding weather impact)
 
2.8

DSM program revenues (offset by expenses)
 
2.6

Other, net
 
1.5

Total increase in natural gas margin before TCJA impact
 
$
79.9

TCJA impact (offset as a reduction in income tax)
 
(30.2
)
Total increase in natural gas margin
 
$
49.7


16


Non-Fuel Operating Expenses and Other Items
O&M Expenses O&M expenses increased $26.7 million, or 3.5%, for 2018. Significant changes are summarized below:
(Millions of Dollars)
 
2018 vs. 2017
Distribution costs
 
$
13.0

Natural gas systems damage prevention
 
7.2

Business systems and contract labor
 
6.7

Plant generation costs
 
(1.4
)
Other, net
 
1.2

  Total increase in O&M expenses
 
$
26.7

Distribution costs reflect higher maintenance expenses, including vegetation management; and
Business systems and contract labor costs increased due to growing network and storage needs, cybersecurity, initiatives to support our customer strategy, and initiatives to improve business processes.
DSM Program Expenses DSM program expenses increased $17.2 million, or 13.8%, for 2018. The increase was due to increases in conservation programs to help customers reduce energy use. DSM expenses are generally recovered concurrently through riders and base rates. Timing of recovery may vary from when costs are incurred.
 
Taxes (Other than Income Taxes) Taxes (other than income taxes) increased $6.2 million, or 3.2%, for 2018 compared with 2017. The increase was primarily due to higher property taxes.
Depreciation and Amortization Depreciation and amortization increased $89.6 million, or 19.0%, for 2018 compared with 2017. The increase was primarily driven by capital investments and additional amortization of a prepaid pension asset related to TCJA settlements, which were offset by lower income taxes (approximately $75 million).
AFUDC, Equity and Debt — AFUDC increased by $37.4 million for 2018 compared with 2017. The increase was primarily due to the Rush Creek wind project and other capital investments.
Interest Charges Interest charges increased by $17.2 million, or 9.0%, for 2018 compared with 2017. The increase was primarily due to higher debt levels to fund capital investments, partially offset by refinancing at lower interest rates.
Income Taxes Income tax expense decreased $138.5 million for 2018. The decrease was primarily due to a lower federal tax rate due to the TCJA and lower pretax earnings, an increase in plant-related regulatory difference related to ARAM (net of deferrals), 2018 non-plant excess accumulated deferred income tax amortization, 2018 wind PTCs; partially offset by a one-time, non-cash, income tax expense related to the impacts of tax reform in 2017. The ETR was 17.1% for 2018 compared with 33.8% for 2017. The lower ETR in 2018 was largely due to the adjustments above.

Regulation
FERC and State Regulation The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, hydro facility licensing, natural gas transportation, asset transactions and mergers, accounting practices and certain other activities of PSCo, including enforcement of NERC mandatory electric reliability standards. State and local agencies have jurisdiction over many of PSCo’s activities, including regulation of retail rates and environmental matters. 
Xcel Energy, which includes PSCo, attempts to mitigate the risk of regulatory penalties through formal training on prohibited practices and a compliance function that reviews interaction with the markets under FERC and Commodity Futures Trading Commission jurisdictions. Public campaigns are conducted to raise awareness of the public safety issues of interacting with our electric systems. While programs to comply with regulatory requirements are in place, there is no guarantee the compliance programs or other measures will be sufficient to ensure against violations. Decisions by these regulators can significantly impact PSCo’s results of operations.
Tax Reform Regulatory Proceedings
 

In December 2017, the TCJA was signed into law, enacting significant changes to the Internal Revenue Code, including a reduction of the corporate income tax rate from 35% to 21% and a resulting reduction in deferred tax assets and liabilities. As a result of IRS requirements and past regulatory treatment of income taxes in the determination of regulated rates, the impacts of TCJA are primarily recognized as a regulatory liability. Treatment of these tax benefits, (e.g., degree to which benefits will be used to refund currently effective rates and/or used to mitigate other costs and potential future rate increases) is subject to regulatory approval. Concluded and ongoing regulatory TCJA proceedings:
Utility Service
 
Approval Date
 
Additional Information
Natural Gas
 
December 2018
 
In February 2018, the administrative law judge recommended approval of a TCJA settlement agreement, which included a $20 million reduction to PSCo’s provisional rates effective March 1, 2018. In September 2018, PSCo revised its 2018 TCJA benefit estimate to $24 million and requested an equity ratio of 56% to offset the negative impact of the TCJA on credit metrics. In December 2018, the CPUC approved an equity ratio of 54.6% and utilized the remainder of the TCJA benefit to reduce an existing prepaid pension asset. The CPUC also ordered 2018 excess non-plant ADIT benefits of $11.1 million be utilized to accelerate amortization of the prepaid pension asset.
Electric
 
June 2018
October 2018
 
In 2018, the CPUC approved a TCJA settlement agreement that included a customer refund of $42 million in 2018, with the remainder of the $59 million of TCJA benefits to be used to accelerate the amortization of an existing prepaid pension asset. For 2019, the expected customer refund is estimated to be $67 million, and amortization of the prepaid pension asset is estimated to be $34 million. Impacts of the TCJA for 2020 and future years are expected to be addressed in a future electric rate case.

17


Pending and Recently Concluded Regulatory Proceedings
Mechanism
 
Utility Service
 
Amount Requested
(in millions)
 
Filing
Date
 
Approval
 
Additional Information
PSCo (CPUC)
Multi-Year Rate Case
 
Natural Gas
 
$139
 
June
2017
 
Received
 
Proposed annual revenue request of $139 million over three years, $63 million for 2018. Requested an ROE of 10.0% and an equity ratio of 55.25%. In August 2018, CPUC approved an increase of $46 million (prior to TCJA impacts). The interim decision included application of a 2016 historic test year, a 13-month average rate base, an ROE of 9.35%, an equity ratio of 54.6% and provided no return on the prepaid pension asset. In December 2018, CPUC issued the final ruling which upheld the interim decision and finalized the TCJA impacts.
In October 2018, the CPUC approved a settlement to extend the PSIA rider through 2021.
DSM Incentive
 
Electric & Natural Gas
 
$11
 
April 2018
 
Received
 
PSCo earned an electric and natural gas DSM incentive of $9 million and $2 million, respectively, for achieving its 2017 savings goals.
Item 7A — Quantitative and Qualitative Disclosures About Market Risk
Derivatives, Risk Management and Market Risk
PSCo is exposed to a variety of market risks in the normal course of business. Market risk is the potential loss that may occur as a result of adverse changes in the market or fair value of a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk.
See Note 9 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.
 
At Dec. 31, 2018, fair values by source for net commodity trading contract assets were as follows:
 
 
Futures / Forwards
(Millions 
of Dollars)
 
Source of
Fair Value
 
Maturity
Less Than
1 Year
 
Maturity
1 to 3
Years
 
Maturity
4 to 5
Years
 
Maturity
Greater Than
5 Years
 
Total Futures/
Forwards
Fair Value
PSCo
 
2

 
$
0.8

 
$
0.5

 
$

 
$

 
$
1.3

2 — Prices based on models and other valuation methods.
Changes in the fair value of commodity trading contracts before the impacts of margin-sharing for the years ended Dec. 31 were as follows:
(Millions of Dollars)
 
2018
 
2017
Fair value of commodity trading net contract assets outstanding at Jan. 1
 
$
0.5

 
$
(0.2
)
Contracts realized or settled during the period
 
(7.8
)
 
(0.8
)
Commodity trading contract additions and changes during the period
 
8.6

 
1.5

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

 
$
0.5

At Dec. 31, 2018, a 10% increase in market prices for commodity trading contracts would decrease pretax income by approximately $0.2 million, whereas a 10% decrease would increase pretax income by approximately $0.2 million. At Dec. 31, 2017, a 10% increase in market prices for commodity trading contracts would increase pretax income by approximately $0.6 million, whereas a 10% decrease would decrease pretax income by approximately $0.6 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
2018
 
$
4.83

 
$
6.00

 
$
0.62

 
$
5.63

 
$
0.06

2017
 
0.18

 
3.00

 
0.21

 
0.66

 
0.04

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

18


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 $3.1 million in 2018 and no impact in 2017.
See Note 9 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, 2018, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $11.5 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $7.6 million. At Dec. 31, 2017, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $17.4 million, while a decrease in prices of 10% would have resulted in an increase in credit exposure of $5.5 million.
PSCo conducts credit reviews for all counterparties and employ 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 9 and 10 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, 2018. 
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, 2018.
Item 8 — Financial Statements and Supplementary Data
See Item 15-1 for an index of financial statements included herein.
See Note 15 to the consolidated financial statements for further information.

19


Management Report on Internal Controls Over Financial Reporting
The management of PSCo is responsible for establishing and maintaining adequate internal control over financial reporting. PSCo’s internal control system was designed to provide reasonable assurance to Xcel Energy Inc.’s and PSCo’s management and board of directors regarding the preparation and fair presentation of published financial statements.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
PSCo management assessed the effectiveness of PSCo’s internal control over financial reporting as of Dec. 31, 2018. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework (2013). Based on our assessment, we believe that, as of Dec. 31, 2018, PSCo’s internal control over financial reporting is effective at the reasonable assurance level based on those criteria.
/s/ BEN FOWKE
 
/s/ ROBERT C. FRENZEL
Ben Fowke
 
Robert C. Frenzel
Chairman and Chief Executive Officer
 
Executive Vice President, Chief Financial Officer
Feb. 22, 2019
 
Feb. 22, 2019

20



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholder of
Public Service Company of Colorado
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Public Service Company of Colorado and subsidiaries (the "Company") as of December 31, 2018 and 2017, 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, 2018, and the related notes and the schedule listed in the Index at Item 15 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
February 22, 2019
 
We have served as the Company’s auditor since 2002.



21


PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(amounts in millions)
 
 
Year Ended Dec. 31
 
 
2018
 
2017
 
2016
Operating revenues
 
 
 
 
 
 
Electric
 
$
3,031.2

 
$
3,003.8

 
$
3,049.4

Natural gas
 
1,014.6

 
995.2

 
957.7

Steam and other
 
40.4

 
43.5

 
40.7

Total operating revenues
 
4,086.2

 
4,042.5

 
4,047.8

 
 
 
 
 
 
 
Operating expenses
 
 
 
 
 
 
Electric fuel and purchased power
 
1,157.2

 
1,126.7

 
1,196.4

Cost of natural gas sold and transported
 
428.4

 
458.7

 
425.4

Cost of sales — steam and other
 
15.3

 
16.1

 
15.9

Operating and maintenance expenses
 
787.5

 
760.8

 
759.7

Demand side management program expenses
 
142.2

 
125.0

 
118.2

Depreciation and amortization
 
561.1

 
471.5

 
443.6

Taxes (other than income taxes)
 
201.9

 
195.7

 
196.3

Total operating expenses
 
3,293.6

 
3,154.5

 
3,155.5

 
 
 
 
 
 
 
Operating income
 
792.6

 
888.0

 
892.3

 
 
 
 
 
 
 
Other income, net
 
2.1

 
7.8

 
1.1

Allowance for funds used during construction — equity
 
56.4

 
29.8

 
18.6

 
 
 
 
 
 
 
Interest charges and financing costs
 
 
 
 
 
 
Interest charges — includes other financing costs of
$6.5, $6.3 and $6.3, respectively
 
207.9

 
190.7

 
181.6

Allowance for funds used during construction — debt
 
(22.2
)
 
(11.4
)
 
(7.0
)
Total interest charges and financing costs
 
185.7

 
179.3

 
174.6

 
 
 
 
 
 
 
Income before income taxes
 
665.4

 
746.3

 
737.4

Income taxes
 
113.7

 
252.2

 
273.9

Net income
 
$
551.7

 
$
494.1

 
$
463.5


See Notes to Consolidated Financial Statements

22


PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(amounts in millions)
 
 
Year Ended Dec. 31
 
 
2018
 
2017
 
2016
Net income
 
$
551.7

 
$
494.1

 
$
463.5

 
 
 
 
 
 
 
Other comprehensive income (loss)
 
 
 
 
 
 
 
 
 
 
 
 
 
Pension and retiree medical benefits:
 
 
 
 
 
 
Net pension and retiree medical losses arising during the period, net of tax of $0, $0, and ($0.1), respectively
 

 

 
(0.2
)
 
 

 

 
(0.2
)
 
 
 
 
 
 
 
Derivative instruments:
 
 
 
 
 
 
Reclassification of losses to net income, net of tax of $0.4, $0.6, and $0.7, respectively
 
1.2

 
1.0

 
1.0

 
 
1.2

 
1.0

 
1.0

 
 
 
 
 
 
 
Other comprehensive income
 
1.2

 
1.0

 
0.8

Comprehensive income
 
$
552.9

 
$
495.1

 
$
464.3


See Notes to Consolidated Financial Statements


23


PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(amounts in millions)
 
Year Ended Dec. 31
 
2018
 
2017
 
2016
Operating activities
 
 
 
 
 
Net income
$
551.7

 
$
494.1

 
$
463.5

Adjustments to reconcile net income to cash provided by operating activities:
 
 
 
 
 
Depreciation and amortization
566.1

 
475.6

 
446.2

Deferred income taxes
23.8

 
207.8

 
222.0

Allowance for equity funds used during construction
(56.4
)
 
(29.8
)
 
(18.6
)
Provision for bad debts
16.4

 
14.3

 
14.1

Net realized and unrealized hedging and derivative transactions
(6.2
)
 
2.4

 
1.3

Changes in operating assets and liabilities:
 
 
 
 
 
Accounts receivable
(42.8
)
 
(2.2
)
 
(14.2
)
Accrued unbilled revenues
(17.7
)
 
1.3

 
(20.9
)
Inventories
(20.1
)
 
(9.1
)
 
0.2

Prepayments and other
12.8

 
0.2

 
68.7

Accounts payable
68.7

 
20.4

 
38.4

Net regulatory assets and liabilities
(14.6
)
 
(22.6
)
 
4.2

Other current liabilities
(12.9
)
 
71.8

 
1.9

Pension and other employee benefit obligations
(44.2
)
 
(16.5
)
 
(10.6
)
Other, net
(16.3
)
 
(5.9
)
 
(29.9
)
Net cash provided by operating activities
1,008.3

 
1,201.8

 
1,166.3

 
 
 
 
 
 
Investing activities
 
 
 
 
 
Utility capital/construction expenditures
(1,577.2
)
 
(1,445.9
)
 
(1,095.2
)
Proceeds from insurance recoveries

 

 
0.6

Investments in utility money pool arrangement
(634.0
)
 
(954.0
)
 
(444.0
)
Repayments from utility money pool arrangement
654.0

 
934.0

 
444.0

Other, net

 
(0.7
)
 
(1.5
)
Net cash used in investing activities
(1,557.2
)
 
(1,466.6
)
 
(1,096.1
)
 
 
 
 
 
 
Financing activities
 
 
 
 
 
Proceeds from (repayments of) short-term borrowings, net
307.0

 
(129.0
)
 
115.0

Borrowings under utility money pool arrangement
780.0

 
40.0

 
524.5

Repayments under utility money pool arrangement
(780.0
)
 
(40.0
)
 
(524.5
)
Proceeds from issuance of long-term debt
691.1

 
393.8

 
244.5

Repayments of long-term debt
(300.0
)
 

 
(129.5
)
Capital contributions from parent
252.1

 
335.6

 
38.8

Dividends paid to parent
(375.3
)
 
(333.9
)
 
(336.6
)
   Other, net
(0.1
)
 
(0.1
)
 

Net cash provided by (used in) financing activities
574.8

 
266.4

 
(67.8
)
 
 
 
 
 
 
Net change in cash and cash equivalents
25.9

 
1.6

 
2.4

Cash and cash equivalents at beginning of period
7.5

 
5.9

 
3.5

Cash and cash equivalents at end of period
$
33.4

 
$
7.5

 
$
5.9

 
 
 
 
 
 
Supplemental disclosure of cash flow information:
 
 
 
 
 
Cash paid for interest (net of amounts capitalized)
$
(187.2
)
 
$
(175.0
)
 
$
(171.7
)
Cash (paid) received for income taxes, net
(115.8
)
 
(7.7
)
 
22.8

Supplemental disclosure of non-cash investing transactions:
 
 
 
 
 
Accrued property, plant and equipment additions
$
142.1

 
$
199.1

 
$
81.1

Inventory transfers to property, plant and equipment
37.2

 
26.6

 
40.8

Allowance for equity funds used during construction
56.4

 
29.8

 
18.6

 
 
 
 
 
 
See Notes to Consolidated Financial Statements

24


PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(amounts in millions, except share and per share)
 
 
Dec. 31
 
 
2018
 
2017
Assets
 
 
 
 
Current assets
 
 
 
 
Cash and cash equivalents
 
$
33.4

 
$
7.5

Accounts receivable, net
 
310.3

 
294.4

Accounts receivable from affiliates
 
80.8

 
14.7

Investments in utility money pool arrangement
 

 
20.0

Accrued unbilled revenues
 
313.5

 
295.8

Inventories
 
197.4

 
214.5

Regulatory assets
 
120.6

 
77.3

Derivative instruments
 
42.6

 
3.2

Prepayments and other
 
23.8

 
35.7

Total current assets
 
1,122.4

 
963.1

 
 
 
 
 
Property, plant and equipment, net
 
15,120.0

 
14,025.8

 
 
 
 
 
Other assets
 
 

 
 

Regulatory assets
 
1,010.7

 
950.3

Derivative instruments
 
1.2

 
1.0

Other
 
37.2

 
27.4

Total other assets
 
1,049.1

 
978.7

Total assets
 
$
17,291.5

 
$
15,967.6

 
 
 
 
 
Liabilities and Equity
 
 

 
 

Current liabilities
 
 

 
 

Current portion of long-term debt
 
$
406.2

 
$
305.6

Short-term debt
 
307.0

 

Accounts payable
 
503.4

 
492.9

Accounts payable to affiliates
 
46.0

 
58.7

Regulatory liabilities
 
67.3

 
66.1

Taxes accrued
 
202.0

 
222.5

Accrued interest
 
43.2

 
48.6

Dividends payable to parent
 
91.5

 
76.2

Derivative instruments
 
34.6

 
7.3

Other
 
101.5

 
92.3

Total current liabilities
 
1,802.7

 
1,370.2

 
 
 
 
 
Deferred credits and other liabilities
 
 

 
 

Deferred income taxes
 
1,719.3

 
1,644.5

Deferred investment tax credits
 
25.3

 
27.8

Regulatory liabilities
 
2,021.5

 
1,933.5

Asset retirement obligations
 
338.7

 
347.8

Derivative instruments
 
0.6

 
3.5

Customer advances
 
168.1

 
162.6

Pension and employee benefit obligations
 
275.3

 
287.8

Other
 
50.4

 
58.9

Total deferred credits and other liabilities
 
4,599.2

 
4,466.4

 
 
 
 
 
Commitments and contingencies
 


 


Capitalization
 
 

 
 

Long-term debt
 
4,591.4

 
4,302.7

Common stock — 100 shares authorized of $0.01 par value; 100 shares
outstanding at Dec. 31, 2018 and 2017, respectively
 

 

Additional paid in capital
 
4,340.5

 
4,032.8

Retained earnings
 
1,983.2

 
1,822.2

Accumulated other comprehensive loss
 
(25.5
)
 
(26.7
)
Total common stockholder’s equity
 
6,298.2

 
5,828.3

Total liabilities and equity
 
$
17,291.5

 
$
15,967.6


See Notes to Consolidated Financial Statements

25


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, 2015
100

 
$

 
$
3,620.8

 
$
1,523.2

 
$
(23.8
)
 
$
5,120.2

 
 
 
 
 
 
 
 
 
 
 
 
Net income
 
 
 
 
 
 
463.5

 
 
 
463.5

Other comprehensive income
 
 
 
 
 
 
 
 
0.8

 
0.8

Common dividends declared to parent
 
 
 
 
 
 
(327.4
)
 
 
 
(327.4
)
Contribution of capital by parent
 
 
 
 
12.4

 
 
 
 
 
12.4

Balance at Dec. 31, 2016
100

 
$

 
$
3,633.2

 
$
1,659.3

 
$
(23.0
)
 
$
5,269.5

 
 
 
 
 
 
 
 
 
 
 
 
Net income
 
 
 
 
 
 
494.1

 
 
 
494.1

Other comprehensive income
 
 
 
 
 
 
 
 
1.0

 
1.0

Common dividends declared to parent
 
 
 
 
 
 
(335.9
)
 
 
 
(335.9
)
Contribution of capital by parent
 
 
 
 
399.6

 
 
 
 
 
399.6

Adoption of ASU No. 2018-02
 
 
 
 
 
 
4.7

 
(4.7
)
 

Balance at Dec. 31, 2017
100

 
$

 
$
4,032.8

 
$
1,822.2

 
$
(26.7
)
 
$
5,828.3

 
 
 
 
 
 
 
 
 
 
 
 
Net income
 
 
 
 
 
 
551.7

 
 
 
551.7

Other comprehensive income
 
 
 
 
 
 
 
 
1.2

 
1.2

Common dividends declared to parent
 
 
 
 
 
 
(390.7
)
 
 
 
(390.7
)
Contribution of capital by parent
 
 
 
 
307.7

 
 
 
 
 
307.7

Balance at Dec. 31, 2018
100

 
$

 
$
4,340.5

 
$
1,983.2

 
$
(25.5
)
 
$
6,298.2