UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.  20549
FORM 10-Q
(Mark One)
x☒QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended Sept. 30, 20172022
or
¨☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ____________ to ___________

Commission File Number: 001-3280
Public Service Company of Colorado
(Exact name of registrant as specified in its charter)
001-03280
Public Service Company of Colorado
(Exact Name of Registrant as Specified in its Charter)
Colorado84-0296600
(State or Other Jurisdiction of Incorporation or Organization)(I.R.S. Employer Identification No.)
1800 Larimer Street, Suite 1100DenverCO80202
(Address of Principal Executive Offices)(Zip Code)
Colorado(303)84-0296600571-7511
(State or other jurisdiction of incorporation or organization)(I.R.S. Employer Identification No.)
1800 Larimer, Suite 1100
Denver, Colorado80202
(Address of principal executive offices)(ZipRegistrant’s Telephone Number, Including Area Code)
(303) 571-7511
(Registrant’s telephone number, including area code)Securities registered pursuant to Section 12(b) of the Act:

Title of each classTrading Symbol(s)Name of each exchange on which registered
N/AN/AN/A

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x☒ Yes ¨☐ No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 andof Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). x☒ Yes ¨☐ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company.  See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer☐Accelerated filer☐
Non-accelerated filer☒Smaller reporting company☐
Large accelerated filer ¨
Accelerated filer ¨
Non-accelerated filer x
Smaller reporting company ¨
(Do not check if smaller reporting company)
Emerging growth company¨
☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨☐

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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
ClassOutstanding at Oct. 27, 20172022
Common Stock, $0.01 par value100 shares

Public Service Company of Colorado meets the conditions set forth in General Instruction H (1) Instructions H(1)(a) and (b) of Form 10-Q and is therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H (2)H(2) to such Form 10-Q.




TABLE OF CONTENTS

PART I — FINANCIAL INFORMATION
Item l1 —
34

4
5
6
7
8
9
Item 2 —
2416

Item 4 —
2920

PART II — OTHER INFORMATION
Item 1 —
3020

Item 1A —
3020

Item 6 —
3020

3121

Certifications Pursuant to Section 3021
Certifications Pursuant to Section 9061
Statement Pursuant to Private Litigation1

This Form 10-Q is filed by Public Service Company of Colorado,PSCo, a Colorado corporation (PSCo).corporation. PSCo is a wholly owned subsidiary of Xcel Energy Inc. Xcel Energy Inc. wholly owns the following subsidiaries: Northern States Power Company, a Minnesota corporation (NSP-Minnesota); Northern States Power Company, a Wisconsin corporation (NSP-Wisconsin); PSCo; and Southwestern Public Service Company, a New Mexico corporation (SPS). NSP-Minnesota, NSP-Wisconsin, PSCo and SPS are also referred to collectively as utility subsidiaries. Additional information on Xcel Energy Inc. and its subsidiaries (collectively, Xcel Energy) is available onin various filings with the SEC. This report should be read in its entirety.


Definitions of Abbreviations
Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former)
e primee prime inc.
NSP-MinnesotaNorthern States Power Company, a Minnesota corporation
NSP-WisconsinNorthern States Power Company, a Wisconsin corporation
PSCoPublic Service Company of Colorado
SPSSouthwestern Public Service Company
Utility subsidiariesNSP-Minnesota, NSP-Wisconsin, PSCo and SPS
Xcel EnergyXcel Energy Inc. and its subsidiaries
Federal and State Regulatory Agencies
CPUCColorado Public Utilities Commission
D.C. CircuitUnited States Court of Appeals for the District of Columbia Circuit
EPAUnited States Environmental Protection Agency
FERCFederal Energy Regulatory Commission
SECSecurities and Exchange Commission
Other
ACEAffordable Clean Energy
AMTAlternative minimum tax
C&ICommercial and Industrial
CCRCoal combustion residuals
CCR RuleFinal rule (40 CFR 257.50 - 257.107) published by the EPA regulating the management, storage and disposal of CCRs as a nonhazardous waste
CEOChief executive officer
CERCLAComprehensive Environmental Response, Compensation, and Liability Act
CFOChief financial officer
CORECORE Electric Cooperative
CPCNCertificate of Public Convenience and Necessity
CSPVCrystalline Silicon Photovoltaic
ETREffective Tax Rate
GAAPUnited States generally accepted accounting principles
GCAGas cost adjustment
IPPIndependent power producing entity
IRAInflation Reduction Act
ITCInvestment tax credit
MGPManufactured gas plant
NOPRNotice of proposed rulemaking
O&MOperating and maintenance
PFASPer- and PolyFluoroAlkyl Substances
PIMPerformance incentive mechanism
PPAPower purchase agreement
PTCProduction tax credit
ROEReturn on equity
UCAColorado Office of the Utility Consumer Advocate
WACCWeighted average cost of capital
Measurements
MWMegawatts




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 Exchange Commission (SEC).assumptions. Such forward-looking statements, including those relating to future sales, future expenses, future tax rates, future operating performance, estimated base capital expenditures and financing plans, projected capital additions and forecasted annual revenue requirements with respect to rider filings, expected rate increases to customers, expectations and intentions regarding regulatory proceedings, and expected impact on our results of operations, financial condition and cash flows of resettlement calculations and credit losses relating to certain energy transactions, as well as assumptions and other statements are intended to be identified in this document by the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” “will,” “would” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made and we expressly disclaim any obligation to update any forward-looking information. The following factors, in addition to those discussed in PSCo’s Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2021 and subsequent filings with the SEC, could cause actual results to differ materially from management expectations as suggested by such forward-looking information: uncertainty around the impacts and duration of the COVID-19 pandemic, including potential workforce impacts resulting from vaccination requirements, quarantine policies or government restrictions, and sales volatility; operational safety; successful long-term operational planning; commodity risks associated with energy markets and production; rising energy prices and fuel costs; qualified employee work force and third-party contractor factors; violations of our Codes of Conduct; ability to recover costs; changes in regulation; reductions in our credit ratings and the cost of maintaining certain contractual relationships; general economic conditions, including recessionary conditions, inflation rates, monetary fluctuations, supply chain constraints and their impact on capital expenditures and/or the ability of PSCo 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; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; seasonal weather patterns; changes in environmental laws and regulations; climate change and other weather; natural disaster and resource depletion, including compliance with any accompanying legislative and regulatory changes and costs of potential regulatory penalties; regulatory changes and/or limitations related to the use of natural gas as an energy source; and our ability to execute on our strategies or achieve expectations related to environmental, social and governance matters, including as a result of evolving legal, regulatory and other standards, processes, and assumptions, the pace of scientific and technological developments, increased costs, the availability of requisite financing, and changes in carbon markets.


Table of Contents
PART I — FINANCIAL INFORMATION

ItemITEM 1 — FINANCIAL STATEMENTS

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
(amounts in thousands)millions)
Three Months Ended Sept. 30 Nine Months Ended Sept. 30 Three Months Ended Sept. 30Nine Months Ended Sept. 30
2017 2016 2017 2016 2022202120222021
Operating revenues       Operating revenues  
Electric$877,604
 $897,516
 $2,318,912
 $2,337,547
Electric$1,137 $1,048 $2,849 $2,608 
Natural gas142,389
 152,763
 691,302
 659,738
Natural gas235 177 1,087 930 
Steam and other10,300
 8,898
 31,529
 29,585
OtherOther11 12 39 34 
Total operating revenues1,030,293
 1,059,177
 3,041,743
 3,026,870
Total operating revenues1,383 1,237 3,975 3,572 
       
Operating expenses 
  
    Operating expenses  
Electric fuel and purchased power288,997
 318,624
 857,346
 890,509
Electric fuel and purchased power399 403 1,075 1,002 
Cost of natural gas sold and transported37,243
 42,379
 303,903
 270,182
Cost of natural gas sold and transported98 43 549 381 
Cost of sales — steam and other4,098
 3,664
 11,991
 10,874
Operating and maintenance expenses173,905
 191,011
 547,413
 570,343
Cost of sales — otherCost of sales — other4 5 13 11 
O&M expensesO&M expenses220 210 650 622 
Demand side management expenses34,520
 31,015
 92,552
 88,094
Demand side management expenses32 34 97 98 
Depreciation and amortization118,289
 111,803
 350,796
 330,593
Depreciation and amortization219 189 627 557 
Taxes (other than income taxes)47,213
 45,076
 146,481
 146,851
Taxes (other than income taxes)70 62 205 192 
Total operating expenses704,265
 743,572
 2,310,482
 2,307,446
Total operating expenses1,042 946 3,216 2,863 
       
Operating income326,028
 315,605
 731,261
 719,424
Operating income341 291 759 709 
       
Other income, net1,536
 544
 7,085
 1,837
Other (expense) income, netOther (expense) income, net(4)— (4)3 
Allowance for funds used during construction — equity8,642
 5,343
 19,591
 13,714
Allowance for funds used during construction — equity8 7 22 19 
       
Interest charges and financing costs 
  
    Interest charges and financing costs
Interest charges — includes other financing costs of $1,605, $1,271, $4,669 and
$4,735, respectively
49,097
 46,664
 141,403
 138,982
Interest charges — includes other financing costs of $2, $2, $6 and $6, respectivelyInterest charges — includes other financing costs of $2, $2, $6 and $6, respectively70 62 199 183 
Allowance for funds used during construction — debt(3,266) (1,995) (7,610) (5,222)Allowance for funds used during construction — debt(3)(3)(8)(6)
Total interest charges and financing costs45,831
 44,669
 133,793
 133,760
Total interest charges and financing costs67 59 191 177 
       
Income before income taxes290,375
 276,823
 624,144
 601,215
Income before income taxes278 239 586 554 
Income taxes104,298
 103,216
 225,934
 224,390
Income tax expenseIncome tax expense31 24 31 38 
Net income$186,077
 $173,607
 $398,210
 $376,825
Net income$247 $215 $555 $516 
See Notes to Consolidated Financial Statements

4
Table of Contents
PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
(amounts in thousands)millions)
  Three Months Ended Sept. 30 Nine Months Ended Sept. 30
  2017 2016 2017 2016
Net income $186,077
 $173,607
 $398,210
 $376,825
         
Other comprehensive income (loss)      
  
         
Pension and retiree medical benefits:        
Amortization of losses (gains) included in net periodic benefit cost,
   net of tax of $1, $0, $3 and $(134), respectively
 1
 —
 3
 (217)
         
Derivative instruments:      
  
Net fair value increase, net of tax of $0, $(1), $0, and $1, respectively
 —
 (1) —
 1
Reclassification of losses to net income, net of tax of $150, $162, $455, and $486, respectively 257
 266
 753
 792
         
Other comprehensive income 258
 265
 756
 576
Comprehensive income $186,335
 $173,872
 $398,966
 $377,401

 Three Months Ended Sept. 30Nine Months Ended Sept. 30
 2022202120222021
Net income$247 $215 $555 $516 
Other comprehensive income
Derivative instruments:
Reclassification of loss to net income, net of tax of $—, $—, $— and $— respectively1 — 1 1 
Total other comprehensive income1 — 1 1 
Total comprehensive income$248 $215 $556 $517 
See Notes to Consolidated Financial Statements



5
Table of Contents
PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(amounts in thousands)millions)
Nine Months Ended Sept. 30 Nine Months Ended Sept. 30
2017 2016 20222021
Operating activities   Operating activities  
Net income$398,210
 $376,825
Net income$555 $516 
Adjustments to reconcile net income to cash provided by operating activities: 
  
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization353,653
 332,383
Depreciation and amortization631 560 
Demand side management program amortization672
 1,802
Deferred income taxes223,121
 202,599
Deferred income taxes16 38 
Amortization of investment tax credits(2,102) (2,104)
Allowance for equity funds used during construction(19,591) (13,714)Allowance for equity funds used during construction(22)(19)
Provision for bad debtsProvision for bad debts22 28 
Net realized and unrealized hedging and derivative transactions907
 (1,801)Net realized and unrealized hedging and derivative transactions(12)(60)
Other(11) (388)
Changes in operating assets and liabilities: 
  
Changes in operating assets and liabilities:
Accounts receivable4,431
 27,080
Accounts receivable(77)(38)
Accrued unbilled revenues74,918
 70,498
Accrued unbilled revenues38 49 
Inventories(250) (11,712)Inventories(130)(58)
Prepayments and other11,717
 52,526
Other current assetsOther current assets(10)2 
Accounts payable(53,706) (20,164)Accounts payable97 25 
Net regulatory assets and liabilities(28,594) (31,152)Net regulatory assets and liabilities(43)(544)
Other current liabilities(40,789) (59,596)Other current liabilities(58)(49)
Pension and other employee benefit obligations(16,691) (13,080)Pension and other employee benefit obligations(14)(53)
Change in other noncurrent assets(1,149) (1,422)
Change in other noncurrent liabilities(1,916) (15,433)
Other, netOther, net(62)18 
Net cash provided by operating activities902,830
 893,147
Net cash provided by operating activities931 415 
   
Investing activities 
  
Investing activities
Utility capital/construction expenditures(995,680) (802,051)Utility capital/construction expenditures(1,384)(1,098)
Proceeds from insurance recoveries—
 608
Allowance for equity funds used during construction19,591
 13,714
Investments in utility money pool arrangement(659,000) (437,000)Investments in utility money pool arrangement(45)(273)
Repayments from utility money pool arrangement609,000
 437,000
Repayments from utility money pool arrangement45 243 
Other, net(657) (1,460)
Net cash used in investing activities(1,026,746) (789,189)Net cash used in investing activities(1,384)(1,128)
   
Financing activities 
  
Financing activities
Repayments of short-term borrowings, net(129,000) (14,000)Repayments of short-term borrowings, net(147)(136)
Borrowings under utility money pool arrangement40,000
 357,000
Borrowings under utility money pool arrangement1,042 514 
Repayments under utility money pool arrangement(40,000) (306,000)Repayments under utility money pool arrangement(877)(571)
Proceeds from issuance of long-term debt393,795
 244,527
Proceeds from issuance of long-term debt686 738 
Repayments of long-term debt—
 (129,500)Repayments of long-term debt(300)— 
Capital contributions from parent158,080
 1,571
Capital contributions from parent399 567 
Dividends paid to parent(245,291) (253,796)Dividends paid to parent(365)(340)
Other(110) —
Net cash provided by (used in) financing activities177,474
 (100,198)
   
Net change in cash and cash equivalents53,558
 3,760
Cash and cash equivalents at beginning of period5,926
 3,585
Cash and cash equivalents at end of period$59,484
 $7,345
Net cash provided by financing activitiesNet cash provided by financing activities438 772 
Net change in cash, cash equivalents and restricted cashNet change in cash, cash equivalents and restricted cash(15)59 
Cash, cash equivalents and restricted cash at beginning of periodCash, cash equivalents and restricted cash at beginning of period25 28 
Cash, cash equivalents and restricted cash at end of periodCash, cash equivalents and restricted cash at end of period$10 $87 
   
Supplemental disclosure of cash flow information: 
  
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)$(145,461) $(149,786)Cash paid for interest (net of amounts capitalized)$(195)$(195)
Cash (paid) received for income taxes, net(7,752) 32,388
Supplemental disclosure of non-cash investing transactions: 
  
Property, plant and equipment additions in accounts payable$133,933
 $84,417
Cash paid for income taxes, netCash paid for income taxes, net(70)(14)
Supplemental disclosure of non-cash investing and financing transactions:Supplemental disclosure of non-cash investing and financing transactions:
Accrued property, plant and equipment additionsAccrued property, plant and equipment additions$144 $170 
Inventory transfers to property, plant and equipmentInventory transfers to property, plant and equipment15 11 
Operating lease right-of-use assetsOperating lease right-of-use assets16 4 
Allowance for equity funds used during constructionAllowance for equity funds used during construction22 19 
See Notes to Consolidated Financial Statements

6
Table of Contents
PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(amounts in thousands,millions, except share and per share data)
Sept. 30, 2017 Dec. 31, 2016 Sept. 30, 2022Dec. 31, 2021
Assets   Assets  
Current assets   Current assets  
Cash and cash equivalents$59,484
 $5,926
Cash and cash equivalents$10 $25 
Accounts receivable, net299,367
 304,900
Accounts receivable, net430 374 
Accounts receivable from affiliates13,386
 9,421
Accounts receivable from affiliates— 13 
Investments in utility money pool arrangement50,000
 —
Accrued unbilled revenues222,160
 297,078
Accrued unbilled revenues312 350 
Inventories205,640
 202,220
Inventories359 245 
Regulatory assets81,021
 103,783
Regulatory assets504 353 
Derivative instruments3,681
 10,934
Derivative instruments48 39 
Prepayments and other24,193
 34,559
Prepayments and other124 104 
Total current assets958,932
 968,821
Total current assets1,787 1,503 
   
Property, plant and equipment, net13,550,488
 12,849,799
Property, plant and equipment, net19,309 18,444 
   
Other assets 
  
Other assets
Regulatory assets972,876
 958,429
Regulatory assets1,257 1,293 
Derivative instruments861
 3,398
Derivative instruments12 27 
Operating lease right-of-use assetsOperating lease right-of-use assets358 409 
Other27,636
 25,637
Other270 246 
Total other assets1,001,373
 987,464
Total other assets1,897 1,975 
Total assets$15,510,793
 $14,806,084
Total assets$22,993 $21,922 
   
Liabilities and Equity 
  
Liabilities and Equity
Current liabilities 
  
Current liabilities
Current portion of long-term debt$305,437
 $5,270
Current portion of long-term debt$250 $300 
Borrowings under utility money pool arrangementBorrowings under utility money pool arrangement165 — 
Short-term debt—
 129,000
Short-term debt— 147 
Accounts payable399,402
 376,186
Accounts payable611 531 
Accounts payable to affiliates32,179
 98,797
Accounts payable to affiliates87 69 
Regulatory liabilities61,224
 101,110
Regulatory liabilities68 95 
Taxes accrued138,924
 171,862
Taxes accrued186 252 
Accrued interest33,430
 48,619
Accrued interest48 58 
Dividends payable to parent88,588
 74,208
Dividends payable to parent127 104 
Derivative instruments6,049
 6,788
Derivative instruments37 30 
Operating lease liabilitiesOperating lease liabilities79 84 
Other79,265
 73,022
Other119 109 
Total current liabilities1,144,498
 1,084,862
Total current liabilities1,777 1,779 
   
Deferred credits and other liabilities 
  
Deferred credits and other liabilities
Deferred income taxes3,122,909
 2,889,129
Deferred income taxes2,010 1,960 
Deferred investment tax credits28,559
 30,661
Regulatory liabilities493,674
 512,933
Regulatory liabilities2,484 2,397 
Asset retirement obligations298,740
 289,563
Asset retirement obligations448 422 
Derivative instruments4,255
 7,828
Derivative instruments7 29 
Customer advances159,012
 162,742
Customer advances150 160 
Pension and employee benefit obligations269,156
 285,774
Pension and employee benefit obligations4 23 
Operating lease liabilitiesOperating lease liabilities302 351 
Other59,909
 62,201
Other204 190 
Total deferred credits and other liabilities4,436,214
 4,240,831
Total deferred credits and other liabilities5,609 5,532 
   
Commitments and contingencies

 

Commitments and contingencies
Capitalization 
  
Capitalization
Long-term debt4,303,229
 4,210,936
Long-term debt6,608 6,167 
Common stock — 100 shares authorized at $0.01 par value; 100 shares
outstanding at Sept. 30, 2017 and Dec. 31, 2016, respectively
—
 —
Common stock — 100 shares authorized of $0.01 par value; 100 shares outstanding at Sept. 30, 2022 and Dec. 31, 2021, respectivelyCommon stock — 100 shares authorized of $0.01 par value; 100 shares outstanding at Sept. 30, 2022 and Dec. 31, 2021, respectively— — 
Additional paid in capital3,851,318
 3,633,216
Additional paid in capital6,813 6,426 
Retained earnings1,797,778
 1,659,239
Retained earnings2,207 2,040 
Accumulated other comprehensive loss(22,244) (23,000)Accumulated other comprehensive loss(21)(22)
Total common stockholder’s equity5,626,852
 5,269,455
Total common stockholder's equityTotal common stockholder's equity8,999 8,444 
Total liabilities and equity$15,510,793
 $14,806,084
Total liabilities and equity$22,993 $21,922 
See Notes to Consolidated Financial Statements

7
Table of Contents
PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY (UNAUDITED)
(amounts in millions, except share data)
Common Stock IssuedRetained EarningsAccumulated Other Comprehensive Loss Total Common Stockholder's Equity
SharesPar ValueAdditional Paid
In Capital
Three Months Ended Sept. 30, 2022 and 2021
Balance at June 30, 2021100 $— $6,210 $1,912 $(23)$8,099 
Net income215 215 
Dividends declared to parent(127)(127)
Contribution of capital by parent123 123 
Balance at Sept. 30, 2021100 $— $6,333 $2,000 $(23)$8,310 
Balance at June 30, 2022100 $— $6,623 $2,087 $(22)$8,688 
Net income247 247 
Other comprehensive income1 1 
Dividends declared to parent(127)(127)
Contribution of capital by parent190 190 
Balance at Sept. 30, 2022100 $— $6,813 $2,207 $(21)$8,999 
Common Stock IssuedRetained EarningsAccumulated Other Comprehensive LossTotal Common Stockholder's Equity
SharesPar ValueAdditional Paid
In Capital
Nine Months Ended Sept. 30, 2022 and 2021
Balance at Dec. 31, 2020100 $— $5,770 $1,846 $(24)$7,592 
Net income516 516 
Other comprehensive income1 1 
Dividends declared to parent(362)(362)
Contribution of capital by parent563 563 
Balance at Sept. 30, 2021100 $— $6,333 $2,000 $(23)$8,310 
Balance at Dec. 31, 2021100 $— $6,426 $2,040 $(22)$8,444 
Net income555 555 
Other comprehensive income1 1 
Dividends declared to parent(388)(388)
Contribution of capital by parent387 387 
Balance at Sept. 30, 2022100 $— $6,813 $2,207 $(21)$8,999 
See Notes to Consolidated Financial Statements



8
Table of Contents
PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
Notes to Consolidated Financial Statements (UNAUDITED)

In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly, in accordance with accounting principles generally accepted in the United States of America (GAAP),GAAP, the financial position of PSCo and its subsidiaries as of Sept. 30, 20172022 and Dec. 31, 2016;2021; the results of itsPSCo’s operations, including the components of net income, and comprehensive income and changes in stockholder’s equity for the three and nine months ended Sept. 30, 20172022 and 2016;2021; and itsPSCo’s cash flows for the nine months ended Sept. 30, 20172022 and 2016. 2021.
All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after Sept. 30, 20172022, up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation. The Dec. 31, 20162021 balance sheet information has been derived from the audited 20162021 consolidated financial statements included in the PSCo Annual Report on Form 10-K for the year ended Dec. 31, 2016. These notes2021.
Notes to the consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP on an annual basis have been condensed or omitted pursuant to such rules and regulations. For further information, refer to the consolidated financial statements and notes thereto included in the PSCo Annual Report on Form 10-K for the year ended Dec. 31, 2016,2021, filed with the SEC on Feb. 24, 2017.23, 2022. Due to the seasonality of PSCo’s electric and natural gas sales, interim results are not necessarily an appropriate base from which to project annual results.

1.Summary of Significant Accounting Policies

The significant accounting policies set forth in Note 1 to the consolidated financial statements in the PSCo Annual Report on Form 10-K for the year ended Dec. 31, 2016,2021 appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

2.Accounting Pronouncements

Recently Issued

Revenue Recognition— In May 2014,As of Sept. 30, 2022, there was no material impact from the Financial Accounting Standards Board (FASB)recent adoption of new accounting pronouncements, nor expected material impact from recently issued Revenue from Contracts with Customers, Topic 606 (Accounting Standards Update (ASU) No. 2014-09), which provides a new framework for the recognition of revenue. PSCo expects its adoption will primarily result in increased disclosures regarding revenue related to arrangements with customers, as well as separate presentation of alternative revenue programs. PSCo currently expects to implement the standard on a modified retrospective basis, which requires application to contracts with customers effective Jan. 1, 2018, with the cumulative impact on contracts notaccounting pronouncements yet completed as of Dec. 31, 2017 recognized as an adjustment to the opening balance of retained earnings.

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

Leases —In February 2016, the FASB issued Leases, Topic 842 (ASU No. 2016-02), which for lessees requires balance sheet recognition of right-of-use assets and lease liabilities for most leases. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2018. PSCo has not yet fully determined the impacts of implementation. However, adoption is expected to occur on Jan. 1, 2019 utilizing the practical expedients provided by the standard. As such, agreements entered prior to Jan. 1, 2017 that are currently considered leases are expected to be recognized on the consolidated balance sheet, including contracts for use of office space, equipment and natural gas storage assets, as well as certain purchased power agreements (PPAs) for natural gas-fueled generating facilities. PSCo expects that similar agreements entered after Dec. 31, 2016 will generally qualify as leases under the new standard, but has not yet completed its evaluation of certain other contracts, including arrangements for the secondary use of assets, such as land easements.



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

3.Selected Balance Sheet Data
(Millions of Dollars)Sept. 30, 2022Dec. 31, 2021
Accounts receivable, net
Accounts receivable$478 $414 
Less allowance for bad debts(48)(40)
Accounts receivable, net$430 $374 
(Millions of Dollars)Sept. 30, 2022Dec. 31, 2021
Inventories
Materials and supplies$77 $70 
Fuel85 71 
Natural gas197 104 
Total inventories$359 $245 

(Thousands of Dollars) Sept. 30, 2017 Dec. 31, 2016
Accounts receivable, net    
Accounts receivable $319,051
 $324,512
Less allowance for bad debts (19,684) (19,612)
  $299,367
 $304,900
(Millions of Dollars)Sept. 30, 2022Dec. 31, 2021
Property, plant and equipment, net
Electric plant$15,468 $16,543 
Natural gas plant5,760 5,471 
Common and other property1,341 1,224 
Plant to be retired (a)
1,326 182 
Construction work in progress956 681 
Total property, plant and equipment24,851 24,101 
Less accumulated depreciation(5,542)(5,657)
Property, plant and equipment, net$19,309 $18,444 
(Thousands of Dollars) Sept. 30, 2017 Dec. 31, 2016
Inventories    
Materials and supplies $69,051
 $66,161
Fuel 56,247
 66,429
Natural gas 80,342
 69,630
  $205,640
 $202,220
(a)Amounts as of Dec. 31, 2021 include Comanche Unit 1 and 2 and Craig Units 1 and 2. Following the June 2022 approval of PSCo’s revised resource plan settlement, amounts as of Sept. 30, 2022 include the addition of Comanche Unit 3, Hayden Units 1 and 2 and coal generation assets at Pawnee pending facility gas conversion. Amounts are reported net of accumulated depreciation.
(Thousands of Dollars) Sept. 30, 2017 Dec. 31, 2016
Property, plant and equipment, net    
Electric plant $12,542,171
 $12,304,436
Natural gas plant 3,904,223
 3,710,772
Common and other property 943,117
 919,955
Plant to be retired (a)
 11,412
 31,839
Construction work in progress 874,399
 484,340
Total property, plant and equipment 18,275,322
 17,451,342
Less accumulated depreciation (4,724,834) (4,601,543)
  $13,550,488
 $12,849,799

(a)
In the third quarter of 2017, PSCo early retired Valmont Unit 5 and converted Cherokee Unit 4 from a coal-fueled generating facility to natural gas. PSCo also expects Craig Unit 1 to be early retired in approximately 2025. Amounts are presented net of accumulated depreciation.

4.Income Taxes

Except to the extent noted below, Note 7 to the consolidated financial statements included in PSCo’s Annual Report on Form 10-K for the year ended Dec. 31, 2016 appropriately represents, in all material respects, the current status of other income tax matters, and are incorporated herein by reference.

Federal Audits— PSCo is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. The statute of limitations applicable to Xcel Energy’s 2009 through 2011 and 2012 through 2013 federal income tax returns, following extensions, expires in June 2018 and October 2018, respectively.

In 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011, including a 2009 carryback claim. The IRS proposed an adjustment to the federal tax loss carryback claims that would result in $14 million of income tax expense for the 2009 through 2011 claims, and the 2013 through 2015 claims. In the fourth quarter of 2015, the IRS forwarded the issue to the Office of Appeals (Appeals). In the third quarter of 2017, Xcel Energy and Appeals reached an agreement and the benefit related to the agreed upon portions was recognized. PSCo did not accrue any income tax benefit related to this adjustment.


In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013. In the third quarter of 2017, the IRS concluded the audit of tax years 2012 and 2013 and proposed an adjustment that would impact Xcel Energy’s net operating loss (NOL) and effective tax rate (ETR). After evaluating the proposed adjustment Xcel Energy filed a protest with the IRS. Xcel Energy anticipates the issue will be forwarded to Appeals. As of Sept. 30, 2017, Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of this issue; however, the outcome and timing of a resolution is unknown.

State Audits — PSCo is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Sept. 30, 2017, PSCo’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009. There are currently no state income tax audits in progress.

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

A reconciliation of the amount of unrecognized tax benefit is as follows:
(Millions of Dollars) Sept. 30, 2017 Dec. 31, 2016
Unrecognized tax benefit — Permanent tax positions $3.7
 $2.9
Unrecognized tax benefit — Temporary tax positions 6.2
 16.8
Total unrecognized tax benefit $9.9
 $19.7

The unrecognized tax benefit amounts were reduced by the tax benefits associated with NOL and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows:
(Millions of Dollars) Sept. 30, 2017 Dec. 31, 2016
NOL and tax credit carryforwards $(3.9) $(5.8)

It is reasonably possible that PSCo’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS Appeals progresses and the IRS and state audits resume. As the IRS Appeals progresses, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $3 million.

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

(Millions of Dollars) Sept. 30, 2017 Dec. 31, 2016
Payable for interest related to unrecognized tax benefits at beginning of period $(1.1) $(0.4)
Interest income (expense) related to unrecognized tax benefits recorded during the period 0.9
 (0.7)
Payable for interest related to unrecognized tax benefits at end of period $(0.2) $(1.1)

No amounts were accrued for penalties related to unrecognized tax benefits as of Sept. 30, 2017 or Dec. 31, 2016.

5.Rate Matters

Except to the extent noted below, the circumstances set forth in Note 11 to the consolidated financial statements included in PSCo’s Annual Report on Form 10-K for the year ended Dec. 31, 2016 and in Note 5 to PSCo’s Quarterly Report on Form 10-Q for the quarterly periods ended March 31, 2017 and June 30, 2017, appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.


Pending Regulatory Proceedings — Colorado Public Utilities Commission (CPUC)

Colorado 2017 Multi-Year Electric Rate Case — In October 2017, PSCo filed a multi-year request with the CPUC seeking to increase electric rates approximately $245 million over four years. The request, summarized below, is based on forecast test years (FTY) ending Dec. 31, a 10.0 percent return on equity (ROE) and an equity ratio of 55.25 percent.
Revenue Request (Millions of Dollars) 2018 2019 2020 2021 Total
Revenue request $74.6
 $74.9
 $59.7
 $35.7
 $244.9
Clean Air Clean Jobs Act (CACJA) revenue conversion to base rates (a)
 90.4
 —
 —
 —
 90.4
Transmission Cost Adjustment (TCA) revenue conversion to base rates (a)
 42.7
 —
 —
 —
 42.7
  Total (b)
 $207.7
 $74.9
 $59.7
 $35.7
 $378.0
           
Expected year-end rate base (billions of dollars) (b)
 $6.8
 $7.1
 $7.3
 $7.4
  
(a)
The roll-in of each of the TCA and CACJA rider revenues into base rates will not have an impact on total customer bills or total revenue as these costs are already being recovered through a rider. Transmission investments for 2019 through 2021 will be recovered through the TCA rider.

(b)
This base rate request does not include the impacts associated with the renewable energy standard adjustment and retail electric commodity adjustment for the Rush Creek wind investments or any impacts of the proposed Colorado Energy Plan.

Final rates are expected to be effective in June 2018. PSCo also proposed a stay-out provision and earnings test through 2021.

Colorado 2017 Multi-Year Natural Gas Rate Case — In June 2017, PSCo filed a multi-year request with the CPUC seeking to increase retail natural gas rates approximately $139 million over three years. The request, detailed below, is based on FTYs, a 10.0 percent ROE and an equity ratio of 55.25 percent.
Revenue Request (Millions of Dollars) 2018 2019 2020 Total
Revenue request $63.2
 $32.9
 $42.9
 $139.0
Pipeline System Integrity Adjustment (PSIA) revenue conversion to base rates (a)
 —
 93.9
 —
 93.9
Total $63.2
 $126.8
 $42.9
 $232.9
         
Expected year-end rate base (billions of dollars) (b)
 $1.5
 $2.3
 $2.4
  
(a)
The roll-in of PSIA rider revenue into base rates will not have an impact on customer bills or total revenue as these costs are already being recovered through the rider. PSCo plans to request new PSIA rates for 2018 in November 2017. The recovery of incremental PSIA related investments in 2019 and 2020 are included in the base rate request.

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

In October 2017, several parties filed answer testimony. The CPUC Staff (Staff) and the Office of Consumer Counsel (OCC), recommended a single 2016 historic test year (HTY), based on an average 13-month rate base, and opposed a multi-year plan (MYP). The Staff and OCC recommended an equity capital structure of 48.73 percent and 51.2 percent, respectively. Both the Staff and the OCC recommended the existing PSIA rider expire with the 2018 rates rolled into base rates beginning Jan. 1, 2019. Planned investments in 2019 and 2020 would be recoverable through base rates, subject to a future rate case.

The following represents adjustments to PSCo’s filed request made by Staff and OCC for 2018:
(Millions of Dollars) Staff OCC
Filed 2018 new revenue request $63.2
 $63.2
Impact of the change in test year 4.4
 4.4
PSCo’s filed 2016 HTY $67.6
 $67.6
     
Recommended adjustments:    
ROE (9.0 percent) (13.5) (13.5)
Capital structure and cost of debt (10.2) (7.5)
Change in amortization period (5.4) —
Prepaid pension and retiree medical assets (5.2) —
Change from 2016 year end to average rate base (4.8) (4.8)
Other, net (5.0) (5.5)
Total adjustments $(44.1) $(31.3)
     
Total recommended rate increase $23.5
 $36.3

The next steps in the procedural schedule are as follows:

Rebuttal testimony — Nov. 3, 2017;
Intervenor sur-rebuttal testimony — Nov. 15, 2017;
Hearings — Dec. 11 - 15 and 18 - 19, 2017; and
Statements of position — Jan. 19, 2018.

Interim rates, subject to refund, are expected to be effective Jan. 1, 2018. A final decision by the CPUC is anticipated in March 2018.

Annual Electric Earnings Test — PSCo must share with customers earnings that exceed the authorized ROE of 9.83 percent for 2015 through 2017, as part of an annual earnings test. The current estimate of the 2017 earnings test, based on annual forecasted information, did not result in the recognition of a liability as of Sept. 30, 2017.

6.Commitments and Contingencies

Except to the extent noted below and in Note 5 above, the circumstances set forth in Notes 11 and 12 to the consolidated financial statements included in PSCo’s Annual Report on Form 10-K for the year ended Dec. 31, 2016 and in Notes 5 and 6 to the
consolidated financial statements included in PSCo’s Quarterly Report on Form 10-Q for the quarterly periods ended March
31, 2017 and June 30, 2017, appropriately represent, in all material respects, the current status of commitments and contingent liabilities and are incorporated herein by reference. The following include commitments, contingencies and unresolved contingencies that are material to PSCo’s financial position.

PPAs

Under certain PPAs, PSCo purchases power from independent power producing entities that own natural gas fueled power plants for which PSCo is required to reimburse natural gas fuel costs, or to participate in tolling arrangements under which PSCo procures the natural gas required to produce the energy that it purchases. These specific PPAs create a variable interest in the associated independent power producing entity.

PSCo had approximately 1,571 megawatts (MW) of capacity under long-term PPAs as of Sept. 30, 2017 and Dec. 31, 2016, with entities that have been determined to be variable interest entities. PSCo has concluded that these entities are not required to be consolidated in its consolidated financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance. These agreements have expiration dates through 2032.


Environmental Contingencies

Manufactured Gas Plant (MGP) Sites — PSCo is currently involved in investigating and/or remediating MGP sites. PSCo has identified three sites where former MGP disposal activities have or may have resulted in site contamination and are under current investigation and/or remediation. At some or all of these sites, there may be parties that have responsibility for some portion of any remediation. PSCo anticipates that the majority of the investigation or remediation at these sites will continue through at least 2018. PSCo had accrued $3.3 million and $1.7 million and for these sites as of Sept. 30, 2017 and Dec. 31, 2016, respectively. There may be insurance recovery and/or recovery from other potentially responsible parties to offset any costs incurred. PSCo anticipates that any significant amounts incurred will be recovered from customers.

Environmental Requirements

Water and Waste
Federal Clean Water Act (CWA) Waters of the United States Rule —In 2015, the EPA and the U.S. Army Corps of Engineers (Corps) published a final rule that significantly expanded the types of water bodies regulated under the CWA and broadened the scope of waters subject to federal jurisdiction. In October 2015, the U.S. Court of Appeals for the Sixth Circuit issued a nationwide stay of the final rule and subsequently ruled that it, rather than the federal district courts, had jurisdiction over challenges to the rule.  In January 2017, the U.S. Supreme Court agreed to resolve the dispute as to which court should hear challenges to the rule. A ruling is expected in the first quarter of 2018.

In February 2017, President Trump issued an executive order requiring the EPA and the Corps to review and revise the final rule. On June 27, 2017, the agencies issued a proposed rule that rescinds the 2015 final rule and reinstates the prior 1986 definition of “Water of the U.S.” The agencies are also undertaking a rulemaking to develop a new definition of “Waters of the U.S.”

Federal CWA Effluent Limitations Guidelines (ELG) —In 2015, the EPA issued a final ELG rule for power plants that use coal, natural gas, oil or nuclear materials as fuel and discharge treated effluent to surface waters as well as utility-owned landfills that receive coal combustion residuals. In September 2017, the EPA delayed the compliance date for flue gas desulfurization wastewater and bottom ash transport water until November 2020 while the agency conducts a rulemaking process to potentially revise the effluent limitations and pretreatment standards for these waste streams.

Air
Greenhouse Gas (GHG) Emission Standard for Existing Sources (Clean Power Plan or CPP) — In 2015, the EPA issued its final rule for existing power plants.  Among other things, the rule requires that state plans include enforceable measures to ensure emissions from existing power plants achieve the EPA’s state-specific interim (2022-2029) and final (2030 and thereafter) emission performance targets. 

The CPP was challenged by multiple parties in the D.C. Circuit Court.  In February 2016, the U.S. Supreme Court issued an order staying the final CPP rule. In September 2016, the D.C. Circuit Court heard oral arguments in the consolidated challenges to the CPP. The stay will remain in effect until the D.C. Circuit Court reaches its decision and the U.S. Supreme Court either declines to review the lower court’s decision or reaches a decision of its own.

In March 2017, President Trump signed an executive order requiring the EPA Administrator to review the CPP rule and if appropriate, publish proposed rules suspending, revising or rescinding it. Accordingly, the EPA has requested that the D.C. Circuit Court hold the litigation in abeyance until the EPA completes its work under the executive order. The D.C. Circuit granted the EPA’s request and is holding the litigation in abeyance while considering briefs by the parties on whether the court should remand the challenges to the EPA rather than holding them in abeyance, determining whether and how the court continues or ends the stay that currently applies to the CPP.

In October 2017, the EPA published a proposed rule to repeal the CPP, based on an analysis that the CPP exceeds the EPA’s statutory authority under the Clean Air Act (CAA). The EPA will take public comment on the proposal for 60 days. The EPA stated it has not yet determined whether it will promulgate a new rule to regulate GHG emissions from existing electric generating units.


Revisions to the National Ambient Air Quality Standard (NAAQS) for Ozone — In 2015, the EPA revised the NAAQS for ozone by lowering the eight-hour standard from 75 parts per billion (ppb) to 70 ppb. The Denver Metropolitan Area is currently not meeting the prior ozone standard and will therefore not meet the new, more stringent standard, however PSCo’s scheduled retirement of coal fired plants in Denver that began in 2011 and was completed in August 2017, should help in any plan to mitigate non-attainment. In August 2017, the EPA withdrew its prior decision delaying designations of nonattainment areas under the 2015 ozone NAAQS to October 2018. The CAA requires areas to be designated within two years after a revision to the NAAQS but allows a one year extension if the EPA has insufficient information on which to base a decision. The EPA is now re-assessing to what extent it has sufficient information to make designations in October 2017 and whether in some cases an extension is still necessary.

Legal Contingencies

PSCo is involved in various litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on PSCo’s financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred.

Employment, Tort and Commercial Litigation

Line Extension Disputes — In December 2015, Development Recovery Company (DRC) filed a lawsuit in Denver State Court, stating PSCo failed to award proper allowances and refunds for line extensions to new developments pursuant to the terms of electric and gas service agreements entered into by PSCo and various developers. The dispute involves claims by over fifty developers. In May 2016, the district court granted PSCo’s motion to dismiss the lawsuit, concluding that jurisdiction over this dispute resides with the CPUC. In June 2016, DRC appealed the district court’s dismissal of the lawsuit, and the Colorado Court of Appeals affirmed the lower court decision in favor of PSCo. In July 2017, DRC filed a petition to appeal the decision with the Colorado Supreme Court. It is uncertain whether the Colorado Supreme Court will grant the petition. DRC also brought a proceeding before the CPUC as assignee on behalf of two developers, Ryland Homes and Richmond Homes of Colorado.  In March 2016, the administrative law judge (ALJ) issued an order rejecting DRC’s claims for additional allowances and refunds.  In June 2016, the ALJ’s determination was approved by the CPUC.  DRC did not file a request for reconsideration before the CPUC contesting the decision, but filed an appeal in the Denver District Court in August 2016.  In July 2017, a stipulation to dismiss this lawsuit with prejudice was filed on behalf of all parties and granted by the Denver District Court.
PSCo has concluded that a loss is remote with respect to this matter as the service agreements were developed to implement CPUC approved tariffs and PSCo has complied with the tariff provisions. Also, if a loss were sustained, PSCo believes it would be allowed to recover these costs through traditional regulatory mechanisms. The amount or range in dispute is presently unknown and no accrual has been recorded for this matter.

7.Borrowings and Other Financing Instruments

Short-Term Borrowings

PSCo meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility and the money pool.
Money Pool — Xcel Energy Inc. and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings between the utility subsidiaries. Xcel Energy Inc. may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy Inc.
Money pool borrowings for PSCo were as follows:PSCo:
(Amounts in Millions, Except Interest Rates)Three Months Ended Sept. 30, 2022Year Ended Dec. 31, 2021
Borrowing limit$250 $250 
Amount outstanding at period end165 — 
Average amount outstanding49 12 
Maximum amount outstanding197 243 
Weighted average interest rate, computed on a daily basis2.06 %0.07 %
Weighted average interest rate at period end2.33 N/A
(Amounts in Millions, Except Interest Rates) Three Months Ended Sept. 30, 2017 Year Ended Dec. 31, 2016
Borrowing limit $250
 $250
Amount outstanding at period end —
 —
Average amount outstanding —
 21
Maximum amount outstanding —
 141
Weighted average interest rate, computed on a daily basis N/A
 0.73%
Weighted average interest rate at period end N/A
 N/A

Commercial Paper — PSCo meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility and the money pool. Commercial paper outstanding for PSCo was as follows:PSCo:
(Amounts in Millions, Except Interest Rates)Three Months Ended Sept. 30, 2022Year Ended Dec. 31, 2021
Borrowing limit$700 $700 
Amount outstanding at period end— 147 
Average amount outstanding14 26 
Maximum amount outstanding170 322 
Weighted average interest rate, computed on a daily basis2.07 %0.19 %
Weighted average interest rate at period endN/A0.22 
(Amounts in Millions, Except Interest Rates) Three Months Ended Sept. 30, 2017 Year Ended Dec. 31, 2016
Borrowing limit $700
 $700
Amount outstanding at period end —
 129
Average amount outstanding —
 24
Maximum amount outstanding —
 154
Weighted average interest rate, computed on a daily basis N/A
 0.70%
Weighted average interest rate at period end N/A
 0.95

Letters of Credit— PSCo uses letters of credit, generally with terms of one year, to provide financial guaranteesguarantees for certain operating obligations. At Sept. 30, 20172022 and Dec. 31, 2016,2021, there were $4$26 million and $3$8 million respectively of letters of credit outstanding under the credit facility. The contract amounts of these letters of creditfacility, respectively. Amounts approximate their fairfair value and are subject to fees.

9
Table of Contents
Revolving Credit Facility — In order to useissue its commercial paper, program to fulfill short-term funding needs, PSCo must have a revolving credit facility in place at least equal to the amount of its commercial paper borrowing limit and cannot issue commercial paper in an aggregate amount exceeding available capacity under this credit facility. The credit facility provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.

In September 2022, PSCo entered into an amended five-year credit agreement with a syndicate of banks, with substantially the same terms and conditions as the prior credit agreements. The maturity was extended from June 2024 to September 2027.
PSCo has the right to request an extension of the revolving credit facility termination date for two additional one-year periods. All extension requests are subject to majority bank group approval.
At Sept. 30, 2017,2022, PSCo had the following committed revolving credit facility available (in millions of dollars):
Credit Facility (a)
Drawn (b)
Available
$700 $26 $674 
Credit Facility (a)
 
Drawn (b)
 Available
$700
 $4
 $696
(a)    Expires in September 2027.

(a)    This credit facility expires in June 2021.
(b)Includes outstanding commercial paper and letters of credit.

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. PSCo hadno direct advances on the credit facility outstanding at Sept. 30, 20172022 and Dec. 31, 2016.2021.

Long-Term Borrowings

In June 2017,During the nine months ended Sept. 30, 2022, PSCo issued $400$300 million of 3.80 percent4.10% first mortgage bonds due June 15, 2047.1, 2032 and $400 million of 4.50% first mortgage bonds due June 1, 2052.

8.5. Revenues
Revenue is classified by the type of goods/services rendered and market/customer type. PSCo’s operating revenues consisted of the following:
Three Months Ended Sept. 30, 2022
(Millions of Dollars)ElectricNatural GasAll OtherTotal
Major revenue types
Revenue from contracts with customers:
Residential$431 $136 $4 $571 
C&I556 64 7 627 
Other13 — — 13 
Total retail1,000 200 11 1,211 
Wholesale63 — — 63 
Transmission25 — — 25 
Other15 30 — 45 
Total revenue from contracts with customers1,103 230 11 1,344 
Alternative revenue and other34 5 — 39 
Total revenues$1,137 $235 $11 $1,383 

Three Months Ended Sept. 30, 2021
(Millions of Dollars)ElectricNatural GasAll OtherTotal
Major revenue types
Revenue from contracts with customers:
Residential$386 $97 $3 $486 
C&I510 38 7 555 
Other12 — — 12 
Total retail908 135 10 1,053 
Wholesale60 — — 60 
Transmission23 — — 23 
Other15 38 — 53 
Total revenue from contracts with customers1,006 173 10 1,189 
Alternative revenue and other42 4 2 48 
Total revenues$1,048 $177 $12 $1,237 
Nine Months Ended Sept. 30, 2022
(Millions of Dollars)ElectricNatural GasAll OtherTotal
Major revenue types
Revenue from contracts with customers:
Residential$1,025 $686 $11 $1,722 
C&I1,383 279 16 1,678 
Other38 — — 38 
Total retail2,446 965 27 3,438 
Wholesale200 — — 200 
Transmission65 — — 65 
Other39 106 — 145 
Total revenue from contracts with customers2,750 1,071 27 3,848 
Alternative revenue and other99 16 12 127 
Total revenues$2,849 $1,087 $39 $3,975 
Nine Months Ended Sept. 30, 2021
(Millions of Dollars)ElectricNatural GasAll OtherTotal
Major revenue types
Revenue from contracts with customers:
Residential$904 $540 $9 $1,453 
C&I1,262 203 22 1,487 
Other37 — — 37 
Total retail2,203 743 31 2,977 
Wholesale195 — — 195 
Transmission59 — — 59 
Other37 122 — 159 
Total revenue from contracts with customers2,494 865 31 3,390 
Alternative revenue and other114 65 3 182 
Total revenues$2,608 $930 $34 $3,572 



10
Table of Contents
6. Income Taxes
Reconciliation between the statutory rate and ETR:
Nine Months Ended Sept. 30
20222021
Federal statutory rate21.0 %21.0 %
State tax (net of federal tax effect)3.6 3.6 
Increases (decreases):
Wind PTCs (a)
(14.2)(12.9)
Plant regulatory differences (b)
(4.4)(4.1)
Other tax credits, net operating loss & tax credit allowances(1.1)(0.7)
Other (net)0.4 — 
Effective income tax rate5.3 %6.9 %
(a)Wind PTCs are credited to customers (reduction to revenue) and do not materially impact net income.
(b)Regulatory differences for income tax primarily relate to the credit of excess deferred taxes to customers through the average rate assumption method. Income tax benefits associated with the credit of excess deferred taxes are offset by corresponding revenue reductions.
7. Fair Value of Financial Assets and Liabilities

Fair Value Measurements

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

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

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

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


Specific valuation methods include the following:include:

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

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

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

Derivative Instruments Fair Value Measurements

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

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

purposes, with changes in fair value prior to settlement recorded as other comprehensive income.
At Sept. 30, 2017,2022, accumulated other comprehensive lossesloss related to interest rate derivatives included $1.0$1 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged transactions impact earnings. As of Sept. 30, 2022, PSCo had no unsettled interest rate transactions impact earnings, including forecasted amounts for unsettled hedges, as applicable.derivatives.

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 relatedgas-related instruments, including derivatives. PSCo’s risk management policy allows managementPSCo is allowed to conduct these activities within guidelines and limitations as approved by its risk management committee, which is made upcomprised of management personnel not directly involved in the activities governed by this policy. Sharing of any margins is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement.

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

PSCo entersmay enter into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but may not be designated as qualifying hedging transactions. Changes in the fair valueThe classification of non-trading commodity derivativegains or losses for these instruments are recorded in other comprehensive income or deferred as a regulatory asset or liability. The classification as a regulatory asset or liability, if applicable, is based on commission approved regulatory recovery mechanisms.
As of Sept. 30, 2022, PSCo recorded immaterial amounts to income related to the ineffectiveness ofhad no commodity contracts designated as cash flow hedges for the three and nine months ended Sept. 30, 2017 and 2016.hedges.

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

The following table details the grossGross notional amounts of commodity forwards and options:
(Amounts in Millions) (a)(b)
Sept. 30, 2022Dec. 31, 2021
Megawatt hours of electricity10 15 
Million British thermal units of natural gas52 71 
(a)Amounts are not reflective of net positions in the underlying commodities.
(b)Notional amounts for options at Sept. 30, 2017 and Dec. 31, 2016:are included on a gross basis, but are weighted for the probability of exercise.
11
Table of Contents
(Amounts in Thousands) (a)(b)
 Sept. 30, 2017 Dec. 31, 2016
Megawatt hours of electricity 13,967
 6,283
Million British thermal units of natural gas 14,807
 42,203

(a)
Amounts are not reflective of net positions in the underlying commodities.
(b)
Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise.


The following tables detail the impact of derivative activity during the three months ended Sept. 30, 2017 and 2016, on accumulated other comprehensive loss, regulatory assets and liabilities, and income:
  Three Months Ended Sept. 30, 2017 
  
Pre-Tax Fair Value
Losses Recognized
During the Period in:
 
Pre-Tax Losses
Reclassified into Income
During the Period from:
   
(Thousands of Dollars) 
Accumulated
Other
Comprehensive
Loss
 
Regulatory
(Assets) and
Liabilities
 
Accumulated
Other
Comprehensive
Loss
 
Regulatory
Assets and
(Liabilities)
 
Pre-Tax Losses
Recognized
During the Period
in Income
 
Derivatives designated as cash flow hedges           
Interest rate $—
 $—
 $407
(a) 
$—
 $—
 
Total $—
 $—
 $407
 $—
 $—
 
Other derivative instruments           
Commodity trading $—
 $—
 $—
 $—
 $(211)
(c) 
Natural gas commodity —
 (1,635) —
 —
 —
 
Total $—
 $(1,635) $—
 $—
 $(211) 
            
  Nine Months Ended Sept. 30, 2017 
  
Pre-Tax Fair Value
Losses Recognized
During the Period in:
 
Pre-Tax Losses
Reclassified into Income
During the Period from:
 
Pre-Tax Losses
Recognized
During the Period
in Income
 
(Thousands of Dollars) 
Accumulated
Other
Comprehensive
Loss
 
Regulatory
(Assets) and
Liabilities
 
Accumulated
Other
Comprehensive
Loss
 
Regulatory
Assets and
(Liabilities)
  
Derivatives designated as cash flow hedges           
Interest rate $—
 $—
 $1,208
(a) 
$—
 $—
 
Total $—
 $—
 $1,208
 $—
 $—
 
Other derivative instruments  
         
Commodity trading $—
 $—
 $—
 $—
 $(23)
(c) 
Natural gas commodity —
 (8,643) —
 282
(d) 
(2,990)
(d) 
Total $—
 $(8,643) $—
 $282
 $(3,013) 
            
            
  Three Months Ended Sept. 30, 2016 
  
Pre-Tax Fair Value
Losses Recognized
During the Period in:
 
Pre-Tax Losses
Reclassified into Income
During the Period from:
   
(Thousands of Dollars) 
Accumulated
Other
Comprehensive
Loss
 
Regulatory
(Assets) and
Liabilities
 
Accumulated
Other
Comprehensive
Loss
 
Regulatory
Assets and
(Liabilities)
 
Pre-Tax Gains
Recognized
During the Period
in Income
 
Derivatives designated as cash flow hedges           
Interest rate $—
 $—
 $407
(a) 
$—
 $—
 
Vehicle fuel and other commodity (2) —
 21
(b) 
—
 —
 
Total $(2) $—
 $428
 $—
 $—
 
Other derivative instruments           
Commodity trading $—
 $—
 $—
 $—
 $(28)
(c) 
Natural gas commodity —
 (4,848) —
 —

(6)
(d) 
Total $—
 $(4,848) $—
 $—
 $(34) 

            
  Nine Months Ended Sept. 30, 2016 
  
Pre-Tax Fair Value
Gains (Losses) Recognized
During the Period in:
 
Pre-Tax Losses
Reclassified into Income
During the Period from:
   
(Thousands of Dollars) 
Accumulated
Other
Comprehensive
Loss
 
Regulatory
(Assets) and
Liabilities
 
Accumulated
Other
Comprehensive
Loss
 
Regulatory
Assets and
(Liabilities)
 
Pre-Tax Gains (Losses)
Recognized
During the Period
in Income
 
Derivatives designated as cash flow hedges           
Interest rate $—
 $—
 $1,211
(a) 
$—
 $—
 
Vehicle fuel and other commodity 2
 —
 67
(b) 
—
 —
 
Total $2
 $—
 $1,278
 $—
 $—
 
Other derivative instruments           
Commodity trading $—
 $—
 $—
 $—
 $200
(c) 
Natural gas commodity —
 (1,172) —
 7,736
(d) 
(3,242)
(d) 
Total $—
 $(1,172) $—
 $7,736
 $(3,042) 

(a)
Recorded to interest charges.
(b)
Recorded to operating and maintenance (O&M) expenses.
(c)
Amounts are recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue as appropriate.
(d)
Certain derivatives are utilized to mitigate natural gas price risk for electric generation and are recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. Amounts for the three and nine months ended Sept. 30, 2017 included no settlement gains or losses and $0.9 million of settlement gains, respectively. Amounts for the three and nine months ended Sept. 30, 2016 included no settlement gains or losses. The remaining derivative settlement gains and losses for the nine months ended Sept. 30, 2017 and 2016 relate to natural gas operations and are recorded to cost of natural gas sold and transported. These gains and losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset or liability, as appropriate.

PSCo had no derivative instruments designated as fair value hedges during the three and nine months ended Sept. 30, 2017 and 2016. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.

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

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

PSCo’s most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to its wholesale, trading and non-trading commodity activities.
At Sept. 30, 2017, five2022, four of PSCo’s 10ten most significant counterparties for these activities, comprising $4.5$53 million, or 10 percent45%, of this credit exposure, had investment grade credit ratings from Standard & Poor’s,S&P Global Ratings, Moody’s Investor Services or Fitch Ratings. Four of the 10ten most significant counterparties, comprising $17.3$26 million, or 39 percent22%, of this credit exposure, were not rated by these external ratings agencies, but based on PSCo’s internal analysis, had credit quality consistent with investment grade. The one remainingTwo of these significant counterparty,counterparties, comprising $8.1$16 million, or 18 percent13%, of this credit exposure, had credit quality less than investment grade, based on ratings from externalinternal analysis. NineSix of these significant counterparties are independent system operators, municipal or cooperative electric entities, Regional Transmission Organizations or other utilities.

Impact of Derivative Activity —

Changes in the fair value of natural gas commodity derivatives resulted in net losses of $4 million and $2 million for the three and nine months ended Sept. 30, 2022, respectively, which were recognized as regulatory assets and liabilities. Changes in the fair value of natural gas commodity derivatives resulted in net gains of $37 million and $36 million for the three and nine months ended Sept. 30, 2021, respectively. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.
Pre-Tax (Gains) Losses Reclassified into Income During the Period from:Pre-Tax Gains (Losses) Recognized During the Period in Income
(Millions of Dollars)Accumulated Other Comprehensive LossRegulatory Assets and (Liabilities)
Three Months Ended Sept. 30, 2022
Derivatives designated as cash flow hedges
Interest rate$1 (a)$— $— 
Total$1 $— $— 
Other derivative instruments
Commodity trading$— $— $2 (b)
Total$— $— $2 
Nine Months Ended Sept. 30, 2022
Derivatives designated as cash flow hedges
Interest rate$1 (a)$— $— 
Total$1 $— $— 
Other derivative instruments
Commodity trading$— $— $3 (b)
Natural gas commodity— 2 (c)(11)(c)(d)
Total$— $2 $(8)
Three Months Ended Sept. 30, 2021
Other derivative instruments
Commodity trading$— $— $11 (b)
Total$— $— $11 
Nine Months Ended Sept. 30, 2021
Derivatives designated as cash flow hedges
Interest rate$1 (a)$— $— 
Total$1 $— $— 
Other derivative instruments
Commodity trading$— $— $25 (b)
Natural gas commodity— 6 (c)(6)(c)(d)
Total$— $6 $19 
(a)    Recorded to interest charges.
(b)    Recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue as appropriate.
(c)    Recorded to cost of natural gas sold and transported. These losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset, as appropriate.
(d)    Relates primarily to option premium amortization.
PSCo had no derivative instruments designated as fair value hedges during the three and nine months ended Sept. 30, 2022 and 2021.
Credit Related Contingent Features—Contract provisions for derivative instruments that PSCo enters into, including those accounted for as normal purchase-normal sale contracts and therefore not reflected on the consolidated balance sheet,sheets, may require the posting of collateral or settlement of the contracts for various reasons, including if PSCo’s credit ratings are downgraded below its investment grade credit rating by any of the major credit rating agencies or for cross-default contractualagencies.
At Sept. 30, 2022 and Dec. 31, 2021, there were no derivative liabilities with such underlying contract provisions. Certain contracts also contain cross default provisions that could result inmay require the posting of collateral or settlement of suchthe contracts if there was a failure under the other financing arrangements related to payment terms or other covenants. AtAs of Sept. 30, 20172022 and Dec. 31, 2016,2021, there were noapproximately $2 million and $16 million, respectively, of derivative instruments in a material liability positionliabilities with such underlying contract provisions.

12
Table of Contents
Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that PSCo’s ability to fulfill its contractual obligations is reasonably expected to be impaired. PSCo had no collateral posted related to adequate assurance clauses in derivative contracts as of Sept. 30, 20172022 and Dec. 31, 2016.2021.

Recurring Fair Value Measurements—The following table presents, for each of the fair value hierarchy levels, PSCo’s derivative assets and liabilities measured at fair value on a recurring basis atwere as follows:
Sept. 30, 2022Dec. 31, 2021
Fair ValueFair Value Total
Netting (a)
TotalFair ValueFair Value Total
Netting (a)
Total
(Millions of Dollars)Level 1Level 2Level 3Level 1Level 2Level 3
Current derivative assets
Other derivative instruments:
Commodity trading$28 $116 $— $144 $(114)$30 $12 $97 $— $109 $(81)$28 
Natural gas commodity— 18 — 18 — 18 — 11 — 11 — 11 
Total current derivative assets$28 $134 $— $162 $(114)$48 $12 $108 $— $120 $(81)$39 
Noncurrent derivative assets
Other derivative instruments:
Commodity trading$20 $22 $16 $58 $(46)$12 $10 $28 $54 $92 $(65)$27 
Total noncurrent derivative assets$20 $22 $16 $58 $(46)$12 $10 $28 $54 $92 $(65)$27 
Sept. 30, 2022Dec. 31, 2021
Fair ValueFair Value Total
Netting (a)
TotalFair ValueFair Value Total
Netting (a)
Total
(Millions of Dollars)Level 1Level 2Level 3Level 1Level 2Level 3
Current derivative liabilities
Other derivative instruments:
Commodity trading$12 $123 $14 $149 $(120)$29 $6 $90 $16 $112 $(85)$27 
Natural gas commodity— 8 — 8 — 8 — 3 — 3 — 3 
Total current derivative liabilities$12 $131 $14 $157 $(120)$37 $6 $93 $16 $115 $(85)$30 
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading$9 $25 $26 $60 $(53)$7 $3 $— $101 $104 $(75)$29 
Total noncurrent derivative assets$9 $25 $26 $60 $(53)$7 $3 $— $101 $104 $(75)$29 
(a)PSCo nets derivative instruments and related collateral on its consolidated balance sheets when supported by a legally enforceable master netting agreement. At both Sept. 30, 2017:
  Sept. 30, 2017
  Fair Value 
Fair Value
Total
 
Counterparty
Netting (b)
  
(Thousands of Dollars) Level 1 Level 2 Level 3   Total
Current derivative assets            
Other derivative instruments:            
Commodity trading $116
 $3,238
 $5
 $3,359
 $(2,652) $707
Natural gas commodity —
 1,394
 —
 1,394
 (135) 1,259
Total current derivative assets $116
 $4,632
 $5
 $4,753
 $(2,787) 1,966
PPAs (a)
           1,715
Current derivative instruments           $3,681
Noncurrent derivative assets            
Other derivative instruments:            
Commodity trading $—
 $511
 $—
 $511
 $(109) $402
Total noncurrent derivative assets $—
 $511
 $—
 $511
 $(109) 402
PPAs (a)
           459
Noncurrent derivative instruments           $861
Current derivative liabilities            
Other derivative instruments:            
Commodity trading $144
 $3,104
 $3
 $3,251
 $(3,188) $63
Natural gas commodity —
 962
 —
 962
 (135) 827
Total current derivative liabilities $144
 $4,066
 $3
 $4,213
 $(3,323) 890
PPAs (a)
           5,159
Current derivative instruments           $6,049
Noncurrent derivative liabilities            
Other derivative instruments:            
Commodity trading $—
 $406
 $—
 $406
 $(109) $297
Total noncurrent derivative liabilities $—
 $406
 $—
 $406
 $(109) 297
PPAs (a)
           3,958
Noncurrent derivative instruments           $4,255

(a)
During 2006, PSCo qualified these contracts under the normal purchase exception. Based onthis qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.
(b)
PSCo nets2022 and Dec. 31, 2021, derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Sept. 30, 2017. At Sept. 30, 2017, derivative assets and liabilities include no obligations to return cash collateral and rights to reclaim cash collateral of $0.5 million. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.


The following table presents, for each of the fair value hierarchy levels, PSCo’s assets and liabilities measured at fair value on a recurring basis atinclude no obligations to return cash collateral. At Sept. 30, 2022 and Dec. 31, 2016:2021, derivative assets and liabilities include rights to reclaim cash collateral of $13 million and $14 million, respectively. Counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.
Changes in Level 3 commodity derivatives:
  Dec. 31, 2016
  Fair Value 
Fair Value
Total
 
Counterparty
Netting (b)
  
(Thousands of Dollars) Level 1 Level 2 Level 3   Total
Current derivative assets            
Other derivative instruments:            
Commodity trading $1,124
 $5,453
 $—
 $6,577
 $(5,137) $1,440
Natural gas commodity —
 7,778
 —
 7,778
 —
 7,778
Total current derivative assets $1,124
 $13,231
 $—
 $14,355
 $(5,137) 9,218
PPAs (a)
           1,716
Current derivative instruments           $10,934
Noncurrent derivative assets            
Other derivative instruments:    
    
  
  
Natural gas commodity $—
 $1,652
 $—
 $1,652
 $—
 $1,652
Total noncurrent derivative assets $—
 $1,652
 $—
 $1,652
 $—
 1,652
PPAs (a)
           1,746
Noncurrent derivative instruments           $3,398
Current derivative liabilities            
Other derivative instruments:            
Commodity trading $1,386
 $5,357
 $22
 $6,765
 $(5,137) $1,628
Total current derivative liabilities $1,386
 $5,357
 $22
 $6,765
 $(5,137) 1,628
PPAs (a)
           5,160
Current derivative instruments           $6,788
Noncurrent derivative liabilities            
PPAs (a)
           $7,828
Noncurrent derivative instruments           $7,828
Three Months Ended Sept. 30
(Millions of Dollars)20222021
Balance at July 1$(30)$(61)
Settlements5 4 
Net transactions recorded during the period:
Gains (losses) recognized in earnings (a)
1 (11)
Balance at Sept. 30$(24)$(68)
Nine Months Ended Sept. 30
(Millions of Dollars)20222021
Balance at Jan. 1$(63)$(44)
Settlements9 3 
Net transactions recorded during the period:
Gains (losses) recognized in earnings (a)
30 (27)
Balance at Sept. 30$(24)$(68)

(a)
During 2006, PSCo qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.
(b)
PSCo nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2016. At Dec. 31, 2016, derivative assets and liabilities include no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

There were immaterial(a)Level 3 net gains and losses recognized in earnings for Level 3 commodity trading derivativesare subject to offsetting net losses of derivative instruments categorized as levels 1 and 2 in the three and nine months ended Sept. 30, 2017 and 2016.

income statement.
PSCo recognizes transfers between levels as of the beginning of each period. There were no transfers of amounts between levels for derivative instruments for the three and nine months ended Sept. 30, 20172022 and 2016.2021.

Fair Value of Long-Term Debt

As of Sept. 30, 2017 and Dec. 31, 2016, otherOther financial instruments for which the carrying amount did not equal fair value were as follows:value:
Sept. 30, 2022Dec. 31, 2021
(Millions of Dollars)Carrying AmountFair ValueCarrying AmountFair Value
Long-term debt, including current portion$6,858 $5,785 $6,467 $7,291 
  Sept. 30, 2017 Dec. 31, 2016
(Thousands of Dollars) 
Carrying
Amount
 Fair Value 
Carrying
Amount
 Fair Value
Long-term debt, including current portion $4,608,666
 $4,958,850
 $4,216,206
 $4,491,570

The fairFair value of PSCo’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. The fairFair value estimates are based on information available to management as of Sept. 30, 20172022 and Dec. 31, 2016,2021 and given the observability of the inputs, to these estimates, the fair values presented for long-term debt have beenwere assigned aas Level 2.


13
Table of Contents
8. Benefit Plans and Other Postretirement Benefits
Components of Net Periodic Benefit Cost (Credit)
 Three Months Ended Sept. 30
 2022202120222021
(Millions of Dollars)Pension BenefitsPostretirement Health
Care Benefits
Service cost$7 $8 $1 $— 
Interest cost (a)
10 9 2 2 
Expected return on plan assets (a)
(19)(18)(4)(4)
Amortization of prior service credit (a)
— — (1)(1)
Amortization of net loss (a)
6 9 — 1 
Settlement charge (b)
2 — — — 
Net periodic benefit cost (credit)6 8 (2)(2)
Effects of regulation(2)(2)1 1 
Net benefit cost (credit) recognized for financial reporting$4 $6 $(1)$(1)
Nine Months Ended Sept. 30
2022202120222021
(Millions of Dollars)Pension BenefitsPostretirement Health
Care Benefits
Service cost$22 $24 $1 $— 
Interest cost (a)
31 29 8 8 
Expected return on plan assets (a)
(58)(54)(12)(12)
Amortization of prior service credit (a)
— — (2)(3)
Amortization of net loss (a)
17 24 1 3 
Settlement charge (b)
2 — — — 
Net periodic benefit cost (credit)14 23 (4)(4)
Effects of regulation3 — 2 2 
Net benefit cost (credit) recognized for financial reporting$17 $23 $(2)$(2)
(a)The components of net periodic cost other than the service cost component are included in the line item “Other income, net” in the consolidated statements of income or capitalized on the consolidated balance sheets as a regulatory asset.
(b)A settlement charge is required when the amount of all lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In the third quarter of 2022 as a result of lump-sum distributions during the 2022 plan year, PSCO recorded a pension settlement charge of $2 million, the majority of which was not recognized due to the effects of regulation.
In January 2022, contributions of $50 million were made across four of Xcel Energy’s pension plans, of which $40 million was attributable to PSCo. Xcel Energy does not expect additional pension contributions during 2022.
9.Other Income, Net Commitments and Contingencies

Other income, net consistedThe following includes commitments, contingencies and unresolved contingencies that are material to PSCo’s financial position.
Legal
PSCo is involved in various litigation matters in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the following:loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for losses probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories.
In such cases, there is considerable uncertainty regarding the timing or ultimate resolution, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, would have a material effect on PSCo’s consolidated financial statements. Legal fees are generally expensed as incurred.
Comanche Unit 3 Litigation —In September 2021, CORE filed a lawsuit in Denver County District Court. CORE alleges PSCo breached ownership agreement terms by failing to operate Comanche Unit 3 in accordance with prudent utility practices. In January 2022, the Court granted PSCo’s motion and dismissed CORE’s claims for unjust enrichment, declaratory judgment and damages for replacement power costs. In February 2022, CORE disclosed that it is claiming in excess of $125 million in total damages.
In April 2022, CORE filed a supplement to include the January 2022 outage. It claims additional undisclosed damages arising from this event. PSCo continues to believe CORE’s claims are without merit.
Rate Matters
PSCo is involved in various regulatory proceedings arising in the ordinary course of business. Until resolution, typically in the form of a rate order, uncertainties may exist regarding the ultimate rate treatment for certain activities and transactions. Amounts have been recognized for probable and reasonably estimable losses that may result. Unless otherwise disclosed, any reasonably possible range of loss in excess of any recognized amount is not expected to have a material effect on the financial statements.
Environmental
MGP, Landfill and Disposal Sites
PSCo is investigating, remediating or performing post-closure actions at two MGP, landfill or other disposal sites across its service territory.
PSCo has recognized its best estimate of costs/liabilities from final resolution of these issues, however, the outcome and timing are unknown. In addition, there may be insurance recovery and/or recovery from other potentially responsible parties, offsetting a portion of costs incurred.
Environmental Requirements — Water and Waste
Coal Ash Regulation— PSCo’s operations are subject to federal and state regulations that impose requirements for handling, storage, treatment and disposal of solid waste. Under the CCR Rule, utilities are required to complete groundwater sampling around their applicable landfills and surface impoundments as well as perform corrective actions where offsite groundwater has been impacted.
As of Sept. 30, 2022, PSCo has five regulated ash units in operation with two sites being evaluated for corrective actions.
PSCo is currently exploring an agreement with a third party that would excavate and process ash for beneficial use (at two sites) at a cost of approximately $43 million. An estimated liability has been recorded for this amount. PSCo anticipates these costs will be fully recoverable through regulatory mechanisms.
Investigation and feasibility studies for additional corrective action related to offsite groundwater are ongoing (at two sites). While the results are uncertain, additional costs are estimated to be up to $35 million. An estimated liability has been recorded for the portion of these actions that are estimable, and are expected to be fully recoverable through regulatory mechanisms.
 Three Months Ended Sept. 30 Nine Months Ended Sept. 30
(Thousands of Dollars)2017 2016 2017 2016
Interest income$1,422
 $162
 $2,406
 $451
Other nonoperating income193
 511
 4,940
 1,594
Insurance policy expense(79) (129) (261) (205)
Other nonoperating expense—
 —
 —
 (3)
Other income, net$1,536
 $544
 $7,085
 $1,837
14

Table of Contents
Leases
PSCo evaluates contracts that may contain leases, including PPAs and arrangements for the use of office space and other facilities, vehicles and equipment. A contract contains a lease if it conveys the exclusive right to control the use of a specific asset.
Components of lease expense:
Three Months Ended Sept. 30
(Millions of Dollars)20222021
Operating leases
PPA capacity payments$22 $26 
Other operating leases (a)
3 2 
Total operating lease expense (b)
$25 $28 
Finance leases
Amortization of ROU assets$1 $2 
Interest expense on lease liability4 4 
Total finance lease expense$5 $6 
(a)Includes immaterial short-term lease expense for 2022 and 2021.
(b)PPA capacity payments are included in electric fuel and purchased power on the consolidated statements of income. Expense for other operating leases is included in O&M expense and electric fuel and purchased power.
Nine Months Ended Sept. 30
(Millions of Dollars)20222021
Operating leases
PPA capacity payments$70 $77 
Other operating leases (a)
13 9 
Total operating lease expense (b)
$83 $86 
Finance leases
Amortization of ROU assets$3 $6 
Interest expense on lease liability12 12 
Total finance lease expense$15 $18 
(a)Includes short-term lease expense of $1 million for 2022 and 2021, respectively.
(b)PPA capacity payments are included in electric fuel and purchased power on the consolidated statements of income. Expense for other operating leases is included in O&M expense and electric fuel and purchased power.
Commitments under operating and finance leases as of Sept. 30, 2022:
(Millions of Dollars)PPA Operating LeasesOther Operating LeaseTotal Operating LeasesFinance Leases
Total minimum obligation$388 $44 $432 $454 
Interest component of obligation(46)(5)(51)(332)
Present value of minimum obligation$342 $39 381 122 
Less current portion(79)(5)
Noncurrent operating and finance lease liabilities$302 $117 
Variable Interest Entities
Under certain PPAs, PSCo purchases power from IPPs for which PSCo is required to reimburse fuel costs, or to participate in tolling arrangements under which PSCo procures the natural gas required to produce the energy that they purchase. These specific PPAs create a variable interest in the IPP.
PSCo had approximately 1,442 MW and 1518 MW of capacity under long-term PPAs at Sept. 30, 2022 and Dec. 31, 2021 with entities that have been determined to be variable interest entities. PSCo concluded that these entities are not required to be consolidated in its financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance. The PPAs have expiration dates through 2032.
10. Other Comprehensive Income
Changes in accumulated other comprehensive loss, net of tax, for the three and nine months ended Sept. 30, 2022 and 2021:
Three Months Ended Sept. 30, 2022Three Months Ended Sept. 30, 2021
(Millions of Dollars)Gains and Losses on Cash Flow HedgesDefined Benefit Pension and Postretirement ItemsTotalGains and Losses on Cash Flow HedgesDefined Benefit Pension and Postretirement ItemsTotal
Accumulated other comprehensive loss at July 1$(21)$(1)$(22)$(22)$(1)$(23)
Losses reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (a)
1 — 1 — — — 
Net current period other comprehensive income1 — 1 — — — 
Accumulated other comprehensive loss at Sept. 30$(20)$(1)$(21)$(22)$(1)$(23)
Nine Months Ended Sept. 30, 2022Nine Months Ended Sept. 30, 2021
(Millions of Dollars)Gains and Losses on Cash Flow HedgesDefined Benefit Pension and Postretirement ItemsTotalGains and Losses on Cash Flow HedgesDefined Benefit Pension and Postretirement ItemsTotal
Accumulated other comprehensive loss at Jan. 1$(21)$(1)$(22)$(23)$(1)$(24)
Losses reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (a)
1 — 1 1 — 1 
Net current period other comprehensive income1 — 1 1 — 1 
Accumulated other comprehensive loss at Sept. 30$(20)$(1)$(21)$(22)$(1)$(23)
(a) Included in interest charges.
15
Table of Contents
11. Segment Information

Operating results from the regulated electric utility and regulated natural gas utility are each separately and regularly reviewed by PSCo’s chief operating decision maker. PSCo evaluates performance based on profit or loss generated from the product or service provided. These segments are managed separately because the revenue streams are dependent upon regulated rate recovery, which is separately determined for each segment.

PSCo has the following reportable segments: regulated electric utility, regulated natural gas utility and all other.

PSCo’s•Regulated Electric— The regulated electric utility segment generates transmitselectricity which is transmitted and distributes electricity primarilydistributed in portions of Colorado. In addition, thisThis segment includes sales for resale and provides wholesale transmission service to various entities in the United States. RegulatedThe regulated electric utility segment also includes PSCo’s wholesale commodity and trading operations.
PSCo’s•Regulated Natural Gas — The regulated natural gas utility segment transports, stores and distributes natural gas primarily in portions of Colorado.
Revenues fromPSCo also presents All Other, which includes operating segments not included above arewith revenues below the necessary quantitative thresholds and are therefore included in the all other category.thresholds. Those operating segments primarily include steam revenue, appliance repair services and nonutilitynon-utility real estate activities.

Asset and capital expenditure information is not provided for PSCo’s reportable segments because, as an integrated electric and natural gas utility, PSCo operates significant assets that are not dedicated to a specific business segment and reporting assets and capital expenditures by business segment would require arbitrary and potentially misleading allocations, which may not necessarily reflect the assets that would be required for the operation of the business segments on a stand-alone basis.

To report income from operations for regulated electric and regulated natural gas utility segments, the majority of costs are directly assigned to each segment. However, someCertain costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation allocators. Aallocators across each segment. In addition, a general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising.
PSCo’s segment information:
(Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total
Three Months Ended Sept. 30, 2017          
Operating revenues (a)(b)
 $877,604
 $142,389
 $10,300
 $—
 $1,030,293
Intersegment revenues 47
 222
 —
 (269) —
Total revenues $877,651
 $142,611
 $10,300
 $(269) $1,030,293
Net income $178,648
 $5,815
 $1,614
 $—
 $186,077
Three Months Ended Sept. 30
(Millions of Dollars)20222021
Regulated Electric
Total revenues$1,137 $1,048 
Net income243 212 
Regulated Natural Gas
Total revenues$235 $177 
Net income4 8 
All Other
Total revenues (a)
$11 $12 
Net loss— (5)
Consolidated Total
Total revenues (a)
$1,383 $1,237 
Net income247 215 

(Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total
Three Months Ended Sept. 30, 2016          
Operating revenues (a)(b)
 $897,516
 $152,763
 $8,898
 $—
 $1,059,177
Intersegment revenues 54
 6
 —
 (60) —
Total revenues $897,570
 $152,769
 $8,898
 $(60) $1,059,177
Net income (loss) $168,328
 $4,918
 $361
 $—
 $173,607
(a)    OperatingTotal revenues include $0 and $2 million of affiliate electric revenue for the three months ended Sept. 30, 2017 and 2016.
(b)    Operating revenues include $1 million of other affiliate revenue for the three months ended Sept. 30, 20172022 and 2016.2021.
Nine Months Ended Sept. 30
(Millions of Dollars)20222021
Regulated Electric
Operating revenues — external$2,849 $2,608 
Intersegment revenue— 1 
Total revenues2,849 2,609 
Net income455 400 
Regulated Natural Gas
Total revenues$1,087 $930 
Net income99 121 
All Other
Total revenues (a)
$39 $34 
Net income (loss)1 (5)
Consolidated Total
Total revenues (a)
$3,975 $3,573 
Reconciling eliminations— (1)
Total operating revenues$3,975 $3,572 
Net income555 516 
(Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total
Nine Months Ended Sept. 30, 2017          
Operating revenues (a)(b)
 $2,318,912
 $691,302
 $31,529
 $—
 $3,041,743
Intersegment revenues 206
 318
 —
 (524) —
Total revenues $2,319,118
 $691,620
 $31,529
 $(524) $3,041,743
Net income $342,195
 $53,133
 $2,882
 $—
 $398,210
(Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total
Nine Months Ended Sept. 30, 2016          
Operating revenues (a)(b)
 $2,337,547
 $659,738
 $29,585
 $—
 $3,026,870
Intersegment revenues 196
 84
 —
 (280) —
Total revenues $2,337,743
 $659,822
 $29,585
 $(280) $3,026,870
Net income $320,192
 $53,883
 $2,750
 $—
 $376,825
(a)    OperatingTotal revenues include $1$4 million and $7 million of affiliate electric revenue for the nine months ended Sept. 30, 2017 and 2016, respectively.
(b)    Operating revenues include $3 million of other affiliate revenue for the nine months ended Sept. 30, 20172022 and 2016.2021.

11.Benefit Plans and Other Postretirement BenefitsITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Components of Net Periodic Benefit Cost (Credit)
         
  Three Months Ended Sept. 30
  2017 2016 2017 2016
(Thousands of Dollars) Pension Benefits 
Postretirement Health
Care Benefits
Service cost $6,820
 $6,487
 $192
 $192
Interest cost 12,639
 13,852
 4,191
 4,518
Expected return on plan assets (17,134) (17,692) (5,476) (5,575)
Amortization of prior service credit (803) (801) (1,562) (1,562)
Amortization of net loss 7,089
 6,692
 961
 483
Net periodic benefit cost (credit) 8,611
 8,538
 (1,694) (1,944)
Credits not recognized due to the effects of regulation 736
 682
 —
 —
Net benefit cost (credit) recognized for financial reporting $9,347
 $9,220
 $(1,694) $(1,944)

         
  Nine Months Ended Sept. 30
  2017 2016 2017 2016
(Thousands of Dollars) Pension Benefits Postretirement Health
Care Benefits
Service cost $20,460
 $19,445
 $576
 $576
Interest cost 37,919
 41,554
 12,573
 13,554
Expected return on plan assets (51,402) (53,076) (16,428) (16,725)
Amortization of prior service credit (2,409) (2,408) (4,686) (4,686)
Amortization of net loss 21,267
 20,078
 2,883
 1,449
Net periodic benefit cost (credit) 25,835
 25,593
 (5,082) (5,832)
Credits not recognized due to the effects of regulation 1,898
 1,947
 —
 —
Net benefit cost (credit) recognized for financial reporting $27,733
 $27,540
 $(5,082) $(5,832)

In January 2017, contributions of $150.0 million were made across four of Xcel Energy’s pension plans, of which $16.8 million was attributable to PSCo. Xcel Energy does not expect additional pension contributions during 2017.

12.Other Comprehensive Income (Loss)

Changes in accumulated other comprehensive loss, net of tax, for the three and nine months ended Sept. 30, 2017 and 2016 were as follows:
  Three Months Ended Sept. 30, 2017
(Thousands of Dollars) Gains and Losses on Cash Flow Hedges Defined Benefit and Postretirement Items Total
Accumulated other comprehensive loss at July 1 $(22,284) $(218) $(22,502)
Losses reclassified from net accumulated other comprehensive loss 257
 1
 258
Net current period other comprehensive income 257
 1
 258
Accumulated other comprehensive loss at Sept. 30 $(22,027) $(217) $(22,244)
  Three Months Ended Sept. 30, 2016
(Thousands of Dollars) Gains and Losses on Cash Flow Hedges Defined Benefit and Postretirement Items Total
Accumulated other comprehensive loss at July 1 $(23,308) $(217) $(23,525)
Other comprehensive loss before reclassifications (1) —
 (1)
Losses reclassified from net accumulated other comprehensive loss 266
 —
 266
Net current period other comprehensive income 265
 —
 265
Accumulated other comprehensive loss at Sept. 30 $(23,043) $(217) $(23,260)
  Nine Months Ended Sept. 30, 2017
(Thousands of Dollars) Gains and Losses on Cash Flow Hedges Defined Benefit and Postretirement Items Total
Accumulated other comprehensive loss at Jan. 1 $(22,780) $(220) $(23,000)
Losses reclassified from net accumulated other comprehensive loss 753
 3
 756
Net current period other comprehensive income 753
 3
 756
Accumulated other comprehensive loss at Sept. 30 $(22,027) $(217) $(22,244)

  Nine Months Ended Sept. 30, 2016
(Thousands of Dollars) Gains and Losses on Cash Flow Hedges Defined Benefit and Postretirement Items Total
Accumulated other comprehensive loss at Jan. 1 $(23,836) $—
 $(23,836)
Other comprehensive income (loss) before reclassifications 1
 (219) (218)
Losses reclassified from net accumulated other comprehensive loss 792
 2
 794
Net current period other comprehensive loss 793
 (217) 576
Accumulated other comprehensive loss at Sept. 30 $(23,043) $(217) $(23,260)

Reclassifications from accumulated other comprehensive loss for the three and nine months ended Sept. 30, 2017 and 2016 were as follows:
      
  Amounts Reclassified from Accumulated Other
Comprehensive Loss		 
(Thousands of Dollars) Three Months Ended Sept. 30, 2017 Three Months Ended Sept. 30, 2016 
Losses on cash flow hedges:  
   
Interest rate derivatives $407
(a) 
$407
(a) 
Vehicle fuel derivatives —
(b) 
21
(b) 
Total, pre-tax $407
 $428
 
Tax benefit (150) (162) 
Total, net of tax $257
 $266
 
Defined benefit pension and postretirement losses:     
Amortization of net loss $2
(c) 
$—
(c) 
Total, pre-tax 2
 —
 
Tax benefit (1) —
 
Total, net of tax 1
 —
 
Total amounts reclassified, net of tax $258
 $266
 
  
Amounts Reclassified from Accumulated
Other Comprehensive Loss
 
(Thousands of Dollars) Nine Months Ended Sept. 30, 2017 Nine Months Ended Sept. 30, 2016 
Losses on cash flow hedges:     
Interest rate derivatives $1,208
(a) 
$1,211
(a) 
Vehicle fuel derivatives —
(b) 
67
(b) 
Total, pre-tax 1,208
 1,278
 
Tax benefit (455) (486) 
Total, net of tax $753
 $792
 
Defined benefit pension and postretirement losses:     
Amortization of net loss $6
(c) 
$—
(c) 
Total, pre-tax 6
 —
 
Tax benefit (3) —
 
Total, net of tax 3
 —
 
Total amounts reclassified, net of tax $756
 $792
 
(a)
Included in interest charges.
(b)
Included in O&M expenses.
(c)
Included in the computation of net periodic pension and postretirement benefit costs. See Note 11 for details regarding these benefit plans.


Item 2 — 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 H (1) General Instructions H(1)(a) and (b) of Form 10-Q for wholly owned subsidiaries. It is replaced with management’s narrative analysis of the results of operations set forth in general instructions H (2) General Instruction H(2)(a) of Form 10-Q for wholly owned subsidiaries (reduced disclosure format).

Non-GAAP Financial Review

Measures
The following discussion includes financial information prepared in accordance with GAAP, as well as certain non-GAAP financial measures such as 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, by management focuses on those factors that had a material effect on PSCo’s financial condition,for reporting of results of operations and cash flows during the periods presented, or are expected to have a material impact in the future. It should be read in conjunction with the accompanying unaudited consolidated financial statements and related notes to the consolidatedBoard of Directors, in determining performance-based compensation and communicating its earnings outlook to analysts and investors. Non-GAAP financial statements. Due to the seasonality of PSCo’s electric and natural gas sales, such interim results are not necessarily an appropriate base from which to project annual results.

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 statementsmeasures are intended to supplement investors’ understanding of our performance and should not be identifiedconsidered 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.
Earnings Adjusted for Certain Items (Ongoing Earnings)
Ongoing earnings reflect adjustments to GAAP earnings (net income) for certain items.
We use this document bynon-GAAP financial measure to evaluate and provide details of PSCo’s core earnings and underlying performance. We believe this measurement is useful to investors to evaluate the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should”actual and similar expressions. Actual results may vary materially. Forward-looking statements speak only asprojected financial performance and contribution of PSCo. For the date they are made,three and we expressly disclaim any obligationnine months ended Sept. 30, 2022 and 2021, there were no such adjustments to update any forward-looking information. The following factors, in addition to those discussed elsewhere in this Quarterly Report on Form 10-QGAAP earnings and in other securities filings (including PSCo’s Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2016 and subsequent securities filings), could cause actual results to differ materially from management expectations as suggested by such forward-looking information: general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the abilitytherefore GAAP earnings equal ongoing earnings.
16
Table of PSCo and its subsidiaries to obtain financing on favorable terms; business conditions in the energy industry; including the risk of a slow down in the U.S. economy or delay in growth, recovery, trade, fiscal, taxation and environmental policies in areas where PSCo has a financial interest; customer business conditions; actions of credit rating agencies; competitive factors including the extent and timing of the entry of additional competition in the markets served by PSCo and its subsidiaries; unusual weather; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric and natural gas markets; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; financial or regulatory accounting policies imposed by regulatory bodies; outcomes of regulatory proceedings; availability or cost of capital; and employee work force factors.Contents

Results of Operations
Results of Operations

PSCo’s net income was approximately $398.2$555 million for 2017 year-to-date,the nine months ended Sept. 30, 2022, compared with approximately $376.8to $516 million for the same period of 2016.prior year. The increase is driven by higher electric margin, lower O&M expenses and lower ETR, which werereflects regulatory rate outcomes, partially offset by increased depreciation expense.

and O&M expenses.
Electric RevenuesMargin
Electric margin is presented as electric revenues less electric fuel and Margin

purchased power expenses. Expenses incurred for electric fuel and purchased power are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues.
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.coal. However, these price fluctuations have minimal impact on electric margin due to fuel recovery mechanisms that recovermechanisms. In addition, electric customers receive a credit for PTCs generated, which reduce electric revenue and margin (offset by lower tax expense).
Electric revenues, fuel expenses. The following table details theand purchased power and electric revenuesmargin and margin:
  Nine Months Ended Sept. 30
(Millions of Dollars) 2017 2016
Electric revenues $2,319
 $2,338
Electric fuel and purchased power (857) (891)
Electric margin $1,462
 $1,447


The following tables summarize the componentsexplanation of the changes are listed as follows:
Nine Months Ended Sept. 30
(Millions of Dollars)20222021
Electric revenues$2,849 $2,608 
Electric fuel and purchased power(1,075)(1,002)
Electric margin$1,774 $1,606 
(Millions of Dollars)Nine Months Ended Sept. 30, 2022 vs. 2021
Regulatory rate outcomes$110 
Sales and demand (a)
39 
Non-fuel riders18 
Proprietary commodity trading, net of sharing (b)
(13)
Other, net14 
Total increase$168 
(a)Sales excludes weather impact, net of decoupling.
(b)Includes $11 million of trading margin recognized in electric revenues and electric margin for the nine months ended Sept. 30:

Electric Revenues
(Millions of Dollars) 2017 vs. 2016
Fuel and purchased power cost recovery $(33)
Non-fuel riders 5
Trading 4
Earnings test 2
Other, net 3
Total decrease in electric revenues $(19)

Electric Margin
(Millions of Dollars) 2017 vs. 2016
Non-fuel riders $5
Trading 3
Earnings test 2
Other, net 5
Total increase in electric margin $15

first quarter of 2021, driven by market changes associated with Winter Storm Uri.
Natural Gas Revenues and Margin

TotalNatural gas margin is presented as natural gas expense varies with changing sales and the cost of natural gas. However, fluctuations inrevenues less the cost of natural gas has minimal impact onsold and transported. Expenses incurred for the cost of natural gas margin due tosold are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues.
Natural gas revenues, cost of natural gas cost recovery mechanisms. The following table details natural gas revenuessold and margin:
  Nine Months Ended Sept. 30
(Millions of Dollars) 2017 2016
Natural gas revenues $691
 $660
Cost of natural gas sold and transported (304) (270)
Natural gas margin $387
 $390

The following tables summarize the components of the changes in natural gas revenuestransported and natural gas margin forand explanation of the nine months ended Sept. 30:changes are listed as follows:

Nine Months Ended Sept. 30
(Millions of Dollars)20222021
Natural gas revenues$1,087 $930 
Cost of natural gas sold and transported(549)(381)
Natural gas margin$538 $549 
Natural Gas Revenues
(Millions of Dollars)Nine Months Ended Sept. 30, 2022 vs. 2021
Infrastructure and integrity riders$2 
Regulatory rate outcomes (a)
(10)
Winter Storm Uri disallowance(4)
Other, net1 
Total decrease$(11)
(Millions of Dollars) 2017 vs. 2016
Purchased natural gas adjustment clause recovery $33
Infrastructure and integrity rider 9
Retail rate decrease (5)
Estimated impact of weather (4)
Other, net (2)
Total increase in natural gas revenues $31


Natural Gas Margin
(Millions of Dollars) 2017 vs. 2016
Retail rate decrease $(5)
Estimated impact of weather (4)
Infrastructure and integrity rider 9
Other, net (3)
Total decrease in natural gas margin $(3)

(a)Impact is due to a favorable regulatory rate outcome recognized in the second quarter of 2021.
Non-Fuel Operating Expenses and Other Items

O&M Expenses— O&M expenses decreased $22.9costs increased $28 million or 4.0 percent, for 2017 year-to-date. The decrease primarily reflects the timing of planned maintenance and overhauls at various generation facilities, the timing of transmission line maintenance and the impact of costs associated with storm damage in 2016, as summarized in the table below:
(Millions of Dollars) 2017 vs. 2016
Plant generation costs $(13.1)
Electric distribution costs (8.0)
Transmission costs (3.1)
Employee benefits expense 3.2
Other, net (1.9)
  Total decrease in O&M expenses $(22.9)

DSM Program Expenses — Demand side management (DSM) program expenses increased $4.5 million, or 5.1 percent, for 2017 year-to-date. The increase wasis due to additional investments in technology and customer programs, higher recovery rates. DSM expenses are generally recovered concurrently through ridersregulatory fees, increased costs for vegetation management and base rates. Timing of recovery may not correspond to the periodinflation, offset by a reduction in which costs were incurred.employee benefit costs.

Depreciation and Amortization— Depreciation and amortization expense increased $20.2$70 million or 6.1 percent, for 2017 year-to-date. The increase was primarily attributable to electric and natural gas investments as well as a new enterprise resource planning system.

AFUDC, Equity and Debt— Allowance for funds used during construction (AFUDC) increased $8.3 million for 2017 year-to-date. The increase was primarily due to normal system expansion and new electric and natural gas depreciation rates.
Interest Charges — Interest charges increased $16 million year-to-date, largely due to higher interest rates and increased long-term debt levels to fund capital investments.
Income Taxes — Income tax expense decreased $7 million year-to-date. The decrease was primarily driven by an increase in wind construction work in progress, particularly Rush Creek.

Income Taxes — Income tax expense increased $1.5 million for 2017 year-to-date. The increase in income tax expense was primarilyPTCs due to higher pretax earnings,greater production. Wind PTCs are credited to customers (recorded as a reduction to revenue) and do not have a material impact on net income. These were partially offset by increased permanent plant-related adjustments (e.g., AFUDC-equity); a tax benefit for adjustments attributablehigher pretax earnings.
See Note 6 to the 2016 tax return filed in the third quarter;consolidated financial statements.
Public Utility Regulation and Other
The FERC and a tax expense for state tax credit valuation allowances in 2016. The ETR was 36.2 percent for 2017 year-to-date, comparedand local regulatory commissions regulate PSCo. PSCo is subject to rate regulation by state utility regulatory agencies, which have jurisdiction with 37.3 percent for the same period of 2016. The lower ETR in 2017 was primarily duerespect to the adjustments referenced above.rates of electric and natural gas distribution companies in Colorado.

Rates are designed to recover plant investment, operating costs and an allowed return on investment. PSCo requests changes in utility rates through commission filings. Changes in operating costs can affect PSCo’s financial results, depending on the timing of rate cases and implementation of final rates. Other factors affecting rate filings are new investments, sales, conservation and demand side management efforts, and the cost of capital.
In addition, the regulatory commissions authorize the ROE, capital structure and depreciation rates in rate proceedings. Decisions by these regulators can significantly impact PSCo’s results of operations.
Public Utility Regulation

Except to the extent noted below, the circumstances set forth in Public Utility Regulation included in Item 17 of PSCo’s Annual Report on Form 10-K for the year ended Dec. 31, 2016 and Public Utility Regulation included in Item 2 of PSCo’s Quarterly Report on Form
10-Q for the quarterly periods ended March 31, 2017 and June 30, 2017,2021, appropriately represent, in all material respects, the current status of public utility regulation and are incorporated herein by reference.

17
Table of Contents
Rush Creek Wind Ownership Proposal
Pending and Recently Concluded Regulatory Proceedings
Colorado Natural Gas Rate Case —In January 2022, PSCo filed a request with the CPUC seeking a net increase to retail natural gas rates of $107 million. The total change to base rates is $215 million, which reflects the transfer of $108 million previously recovered from customers through the pipeline system integrity adjustment rider. The request is based on a 10.25% ROE, an equity ratio of 55.66% and a 2022 current test year with a projected rate base of $3.6 billion. PSCo has requested a proposed effective date of Nov. 1, 2022.
Additionally, PSCo’s request includes step revenue increases of $40 million (effective Nov. 1, 2023) and $41 million (effective Nov. 1, 2024) related to continued capital investment.
In October 2022, the CPUC issued a written decision approving a rate increase net of rider roll-ins of $64 million. The decision reflects a stated WACC of 6.7%, a historic test year with a year-end rate base and $16 million of incremental depreciation expense. PSCo has the option to determine its ROE within a range of 9.2% to 9.5% and its equity ratio within a range of 52% to 55%, as long as it results in a WACC of 6.7%. PSCo anticipates using a ROE of 9.2% and an equity ratio of 53.8%. The CPUC denied the 2023-2024 step increases.
Power Pathway Settlement— In June 2022, the CPUC issued a final written order issuing the CPCN for the Pathway Project. Key decisions include:
•The CPUC approved PSCo’s cost estimate of $1.7 billion and recovery through the transmission rider.
•The CPUC modified the PIMs proposed in the settlement agreement, which focused on cost controls, to add a separate mechanism to further incentivize timely delivery of the Pathway Project segments. The CPUC also increased the magnitude of the PIMs.
•The CPUC granted conditional approval for the 345 kilovolt May Valley-Longhorn line extension, pending the level of renewables being added in that region through PSCo’s resource plan. The initial cost estimate for the extension is approximately $250 million.
Resource Plan Settlement— In 2016,August 2022, the CPUC grantedissued a written approval of a revised settlement, which will result in the further acceleration of the retirement of the Comanche Unit 3 coal plant, an expected carbon reduction of at least 85% and an 80% renewable mix by 2030. The CPUC deferred a decision on the method of cost recovery for the retiring coal units to a separate docket, which will consider accelerated depreciation, creation of regulatory assets and securitization. PSCo expects to commence the request for proposal process for generation resources and file a Certificaterecovery method docket in the fourth quarter of Public Convenience2022.
Key settlement terms include:
•Early retirement of Hayden: Unit 2 in 2027 (was 2036); and Necessity (CPCN)Unit 1 in 2028 (was 2030).
•Conversion of the Pawnee coal plant to build, ownnatural gas by no later than Jan. 1, 2026.
•Early retirement of Comanche Unit 3 by Jan. 1, 2031 (was 2070) with reduced operations beginning in 2025.
•Addition of ~2,400 MW of wind.
•Addition of ~1,600 MW of universal-scale solar.
•Addition of 400 MW of storage.
•Addition of 1,300 MW of flexible, dispatchable generation.
•Addition of ~1,200 MW of distributed solar resources through our renewable energy programs.
Partial Settlement — In October 2021, PSCo filed a comprehensive settlement with the CPUC Staff and operate a 600 MW wind generation facility in Colorado at Rush Creek. The CPCN includes a hard cost-cap of $1.096 billion (including transmission costs) and a capital cost sharing mechanism between customers and PSCo of 82.5 percent to customers and 17.5 percent to PSCo for every $10 million the project comes in below the cost-cap.

All major contracts required to complete the project have been executed including the Vestas turbine supply and balance of plant agreements. Vestas production tax credit (PTC) components for safe harboring the facility have been fabricated and are currently being stored at Vestas facilities in Colorado. Construction of roads, collection systems, and foundations began in April 2017.


Colorado Energy Plan (CEP) —Office, which proposed to address four outstanding regulatory items, including recovery of fuel costs related to Winter Storm Uri, disputed revenue associated with the 2020 electric decoupling pilot program year, replacement power costs associated with an extended outage at Comanche Unit 3 during 2020 and deferred customer bad debt balances associated with COVID-19. In May 2016, PSCo filed its 2016 Electric Resource Plan which included the estimated need for additional generation resources through 2024. In April 2017,July 2022, the CPUC approved the modeling assumptions that will be usedsettlement, with an $8 million disallowance relating to the Winter Storm Uri fuel costs.
Decoupling Filing— PSCo has a decoupling program, effective April 1, 2020 through Dec. 31, 2023. The program applies to Residential and metered small C&I customers who do not pay a demand charge. The program includes a refund and surcharge cap not to exceed 3% of forecasted base rate revenue for a specified period.
In October 2021, a settlement was reached on Winter Storm Uri costs and also addressed certain components of decoupling. See Partial Settlement disclosure above.
As of Sept. 30, 2022, PSCo has recognized a refund for Residential customers and a surcharge for small C&I customers based on 2020, 2021 and the first, second and third quarters of 2022 results.
In April 2022, PSCo made its annual filing. In May 2022, the UCA filed a protest raising issues relating to the Winter Storm Uri settlement and the soft cap components of the decoupling program. On May 25, 2022 the CPUC found merit in UCA’s protest, suspended PSCo’s advice letter and referred the matter to the ALJ. A hearing is expected to take place in the Request for Proposal (RFP) process.fourth quarter of 2022 and an ALJ recommendation is expected in the first quarter of 2023.
2019 Electric Rate Case Appeal — In August 2017,2020, PSCo filed an updated capacity needappeal with the Denver District Court seeking a review of CPUC decisions on gains and losses on sales of 450 MW.

assets, and other items. In August 2017,January 2022, the court issued its decision that the CPUC’s approach to gains and losses on certain sales of assets was legally erroneous and confiscatory to PSCo along with various other stakeholders, filed a stipulation agreement proposingand set aside and remanded the CEP. The major components include:

Early retirement of 660 MW of coal-fired generation at Comanche Units 1 (2022) and 2 (2025);
An RFP which could result in the addition of up to 1,000 MW of wind, 700 MW solar and 700 MW of natural gas and/or storage;
Utility ownership targets of 50 percent renewable generation resources and 75 percent of natural gas-fired, storage, or renewable with storage generation resources;
Accelerated depreciationissue for the early retirement of the two Comanche units and establishment of a regulatory asset to collect the incremental depreciation expense and related costs;
Reduction of the Renewable Energy Standard Adjustment rider, from two percent to one percent, subject to regulatory proceedings, effective beginning 2021 or 2022; and
Construction of a new transmission switching station to further the development of renewable generating resources.

consideration. In August 2017, PSCo issued an All-Source RFP. Bids are due on Nov. 28, 2017. PSCo anticipates filing its’ recommended portfolios in April 2018. The CPUC is expected to rule on the stipulation agreement in March 2018. A CPUC decision on the recommended portfolio is anticipated in the summer of 2018.

Approval of the CEP could increase the total capital investment up to $1.5 billion.

Advanced Grid Intelligence and Security — In July 2017,October 2022, the CPUC approved PSCo’s proposed methodology to allocate gains and losses.
GCA NOPR— In June 2021, the CPUC issued a NOPR addressing the recovery of costs through the GCA. The CPUC has reopened the GCA NOPR matter and proposed a 2 step process aimed at 1) considering near term process changes to the GCA used by various utilities and 2) a longer term process to evaluate potential performance incentive GCA structures to be filed by Nov. 1, 2022. In step 1, consensus proposed rule amendments to update the process and filing requirements for GCA and related filings have been submitted to the CPUC for consideration.
Natural Gas Planning NOPR — In October 2021, the CPUC issued a NOPR to implement recent state legislation requiring natural gas utilities to develop clean heat plans as a means to meet state greenhouse gas emission reduction targets, as well as updated demand-side management criteria. Additionally, the proposed rules included new comprehensive natural gas infrastructure planning requirements and related CPCN application procedures, changes in natural gas line extension policy, and details on emission accounting related to clean heat plans. The CPUC staff will provide proposed rules in the fourth quarter of 2022.
18
Table of Contents
Other
Supply Chain
PSCo’s ability to meet customer energy requirements, respond to storm-related disruptions and execute our capital expenditure program are dependent on maintaining an efficient supply chain. Manufacturing processes have experienced disruptions related to scarcity of certain raw materials and interruptions in production and shipping. For example, availability of certain types of transformers has been significantly impacted and in some cases may result in delays in new customer connections as we work to address the shortage. These disruptions have been further exacerbated by inflationary pressures, labor shortages and the impact of international conflicts/issues. PSCo continues to monitor the situation as it remains fluid and seeks to mitigate the impacts by securing alternative suppliers, modifying design standards, and adjusting the timing of work.
Advanced Metering Infrastructure Implementation
Supply chain issues associated with semi-conductors have delayed the availability of advanced infrastructure electric meters, which has led to a reduced number of meters deployed in 2022. Impacts to the 2023 deployment schedule are currently being evaluated.
Solar Resources
In April 2022, the U.S. Department of Commerce initiated an anti-circumvention investigation that would subject CSPV solar panels and cells imported from Malaysia, Vietnam, Thailand, and Cambodia with potential incremental tariffs ranging from 50% to 250%. These countries account for implementationmore than 80% of CSPV panel imports.
Since that time, an interim stay on tariffs has been issued and many significant solar projects have resumed with modified costs and projected in-service dates, including certain PPAs in PSCo which are pending regulatory approval.
Marshall Wildfire
In December 2021, a wildfire ignited in Boulder County, Colorado (the “Marshall Fire”), which burned over 6,000 acres and destroyed or damaged over 1,000 structures. Boulder County authorities are currently investigating the fire and have not yet determined a cause. There were no downed power lines in the ignition area, and nothing the Company has seen to this point indicates that our equipment or operations caused the fire.
In Colorado, the standard of review governing liability differs from the “inverse condemnation” or strict liability standard utilized in California. In Colorado, courts look to whether electric power companies have operated their system with a heightened duty of care consistent with the practical conduct of its advanced grid initiative. business, and liability does not extend to occurrences that cannot be reasonably anticipated. In addition, PSCo has been operating under a commission approved wildfire mitigation plan and carries wildfire liability insurance.
In March 2022, a class action suit was filed in Boulder County pertaining to the Marshall Fire. In the remote event PSCo was found liable related to this litigation and were required to pay damages, such amounts could exceed our insurance coverage and have a material adverse effect on our financial condition, results of operations or cash flows. In June 2022, Plaintiffs served the class action lawsuit. In July 2022, PSCo filed a Motion to Dismiss.
Comanche Unit 3 Outage
In late January 2022, PSCo experienced an outage at the Comanche Unit 3 coal plant.The project incorporates installing advanced meters, implementing hardwareplant returned to service in June 2022. PSCo will not seek recovery of the $10 million of incremental replacement power costs incurred during the outage, which reflects a true-up to final incurred costs in the third quarter of 2022.
Inflation Reduction Act — In August 2022, the IRA was signed into law.
Key provisions impacting PSCo include:
•Extends current PTC and software applicationsITC for renewable technologies (e.g., wind and solar).
•Restores full value of the PTC and ITC for qualifying facilities placed in-service after 2021.
•Creates a PTC for solar, clean hydrogen and nuclear.
•Establishes an ITC for energy storage, microgrids, interconnection facilities, etc.
•Allows companies to monetize or sell credits to unrelated parties.
PSCo anticipates the IRA will drive significant customer savings for both new and existing Company owned renewable projects, assuming appropriate regulatory mechanisms and development of a market for the sale of tax credits. The IRA is expected to allow PSCo to monetize tax credits more efficiently with the distribution systemincremental benefits passed through to operate at a lower voltage (integrated volt-var optimization) and installing communications infrastructure. These major projects are expected to improve customer experience, enhance grid reliability and enable the implementation of new and innovative programs and rate structures.

customers.
In June 2017,addition, the CPUC approvedIRA created a settlement, which delayednew corporate AMT. PSCo does not anticipate AMT having a material cash impact based on current estimates and our interpretation of AMT application.
Winter Storm Uri
In February 2021, the advanced meter deployment from 2017-2021United States experienced Winter Storm Uri. Extreme cold temperatures impacted certain operational assets as well as the availability of renewable generation. The cold weather also affected the country’s supply and demand for natural gas. These factors contributed to 2019-2024. The total capital cost of the project included in the CPCN is approximately $537 millionextremely high market prices for 2017-2024.natural gas and electricity. As a result of the settlement,extremely high market prices, PSCo incurred net natural gas, fuel and purchased energy costs of approximately $120$610 million of capital investment was(largely deferred to 2022-2024.as regulatory assets).

Decoupling Filing — In July 2016,May 2021, PSCo filed a request with the CPUC to approverecover $263 million in weather-related electric costs, $287 million in incremental natural gas costs and $4 million in incremental steam costs over 24 months with no financing charge.
In May 2022, an ALJ recommended full recovery of all costs with no cost disallowances. In July 2022, the CPUC approved a partial decoupling mechanism, which would adjust annual revenues based on changessettlement providing full recovery of fuel costs with the exception of an $8 million disallowance.
Environmental
CERCLA
PFAS are man-made chemicals that are widely used in weather normalized average use per customer for the residentialconsumer products and small commercial classes. 

In July 2017, the CPUC issued a decision which approved the following key decisions regarding decoupling:

Effective Jan. 1, 2018 through December 2023 (subject to establishing new ratescan persist and bio-accumulate in the next electric rate case);
Applicable to the residential class and small commercial class;
Based on total class revenues (subject to establishing the base period in the next electric rate case);
Based on actual sales; and
Subject to a soft cap of 3 percent on any annual adjustment.

In August 2017, the CPUC denied PSCo’s request for reconsideration of the order.

Boulder, Colo. Municipalization — In 2011, in the City of Boulder, Colo. (Boulder), voters passed a ballot measure authorizing the formation of a municipal utility, subject to certain conditions. In 2014, the Boulder City Council passed an ordinance to establish an electric utility.environment. PSCo challenged the formation of this utility. In 2016, the Colorado Court of Appeals preserved PSCo’s ability to do so. Subsequently, Boulder filed a Petition for Writ of Certiorari with the Colorado Supreme Court. In August 2017, the Colorado Supreme Court granted the petition to review the Colorado Court of Appeals decision.


In 2015, the Boulder District Court affirmed a prior CPUC decision that Boulder cannot serve customers outside its city limits. The District Court also ruled the CPUC has jurisdiction over the transfer of any facilities to Boulder and in determining how the systems are separated to preserve reliability, safety and effectiveness. Further, the Boulder District Court dismissed the condemnation action Boulder had filed, finding that the CPUC must give approval before Boulder files any future condemnation proceeding. Boulder does not have authorization to initiate a condemnation proceeding at this time.
Beginningmanufacture PFAS but because PFAS are so ubiquitous in 2015, Boulder filed multiple separation applications,products and the most recent one being in May 2017. In June 2017, PSCo and other intervenors filed alternatives to Boulder’s separation plan and opposed certain sharing; contracting and financing aspects of the plan. 

environment, it may impact our operations. In September 2017,2022, the CPUC issued a written decision, agreeing with several key aspectsEPA proposed to designate two types of PSCo’s position, stating PSCo is not required to:

Finance Boulder’s municipalization efforts;
Design or construct future Boulder electric distribution facilities;
Enter into joint use of pole arrangements with Boulder;PFAS as “hazardous substances” under the CERCLA, specifically perfluorooctanoic acid and
Use a third party to design perfluorooctanesulfonic acid. This proposed rule could result in new obligations for investigation and build facilities.

The CPUC provided conditional approval related to the transfer of some of the electrical distribution assets in Boulder, however subject to completion of certain items, including:

Filing an agreement between Boulder and PSCo providing permanent rights for PSCo to place and access facilities in Boulder needed to continue to serve its customers;
Filing a complete and accurate revised list of distribution assetscleanup wherever PFAS are found to be transferred; and
Filing an agreement to address numerous aspects of payments from Boulder to PSCo for costs of Boulder’s municipalization efforts.

present. The CPUC requested those filings be made by Dec. 13, 2017. The CPUC has established a process whereby once those filings are made, additional hearings may be held.

At the end of 2017, several Boulder measures expire absent voter approvals, including the Utility Occupational Tax (UOT) which funds Boulder’s municipalization efforts. In response, Boulder has placed the following measures on the November 2017 ballot:

An extension and increase of the UOT for funding Boulder’s exploration of municipalization;
Requiring final voter approval prior to Boulder issuing debt to acquire assets and fund the start up of a local electric utility; and
Extending Boulder city council’s authority to hold non-public, executive sessions to discuss legal strategy related to municipalization, but not to discuss certain settlement options with PSCo.

Mountain West Transmission Group (MWTG) — PSCo, along with six other transmission owners from the Rocky Mountain region, have been considering creating and operating a joint transmission tariff to increase wholesale market efficiency and improve regional transmission planning.  In September 2017, the MWTG determined that membership in the Southwest Power Pool, Inc. (SPP) Regional Transmission Organization (RTO) would provide opportunities to reduce customer costs, and maximize resource and electric grid utilization. If participation with SPP proceeds, the MWTG utilities expect an economic benefit. In October 2017, the MWTG commenced negotiations with SPP through the SPP public stakeholder process.

SPP’s organizational group will address respective findings, objectives and next steps related to MWTG’s consideration of SPP membership. Should the MWTG decide to move forward, SPP would make filings with the FERC and PSCo would make filings with the CPUC and the FERC, in mid-2018. If approved, MWTG operations within the SPP RTO would not be expected to begin until late 2019, at the earliest. 


Summary of Recent Federal Regulatory Developments

FERC

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, hydro facility licensing, natural gas transportation, asset transactions and mergers, accounting practices and certain other activities of PSCo, including enforcement of North American Electric Reliability Corporation mandatory electric reliability standards. State and local agencies have jurisdiction over many of PSCo’s activities, including regulation of retail rates and environmental matters. See additional discussion in the summary of recent federal regulatory developments and public utility regulation sections of the PSCo Annual Report on Form 10-K for the year ended Dec. 31, 2016 and Quarterly Report on Form 10-Q for the quarterly periods ended
March 31, 2017 and June 30, 2017. In addition to the matters discussed below, see Note 5 to the consolidated financial statements for a discussion of other regulatory matters.

North American Electric Reliability Corporation (NERC) Supply Chain Standards — In September 2017, NERC filed supply chain cyber security reliability standards with the FERC. These standards consider the FERC’s directives to address supply chain cyber security risk management for industrial control system hardware, software, computing and network services associated with electric grid operations. The proposed reliability standards focus on security objectives including software integrity and authenticity, vendor remote access protections, information system planning and vendor risk management. It is uncertain when the FERC will take action to approve or remandimpact the proposed reliability standards. If approved by the FERC, the proposed reliability standards will become effectiveregulation may have on the first calendar quarter thatelectric and gas utilities is 18 months after the effective datecurrently uncertain.
19
Table of the approval. PSCo is in the process of developing plans in accordance with the requirements of the standards. The additional cost for compliance is anticipated to be recoverable through wholesale and retail rates.Contents

ITEM 4 — CONTROLS AND PROCEDURES
Public Utility Regulatory Policies Act (PURPA) Enforcement Complaint Against CPUC —In December 2016, Sustainable Power Group, LLC (sPower) petitioned the FERC to initiate an enforcement action in federal court against the CPUC under PURPA. The petition asserts that a December 2016 CPUC ruling, which indicated that a qualifying facility must be a successful bidder in a PSCo resource acquisition bidding process, violated PURPA and FERC rules. In January 2017, PSCo filed a motion to intervene and protest, arguing that the FERC should decline the petition. The CPUC filed a similar pleading. sPower has proposed to construct 800 MW of solar generation and 700 MW of wind generation in Colorado and seeks to require PSCo to contract for these resources under PURPA. If sPower were to prevail, PSCo’s ability to select generation resources through competitive bidding would be negatively affected. However, due to a lack of quorum at the FERC, the FERC did not act on that petition within the sixty days contemplated by PURPA. Subsequently sPower filed a complaint for declaratory and injunctive relief in the United States District Court for the District of Colorado (District Court) requesting that the court find the bidding requirement in the CPUC qualifying facility rules to be unlawful. PSCo intervened in that proceeding and the CPUC filed a motion to dismiss. In June 2017, the United States Magistrate Judge (Magistrate) issued a recommendation to the District Court that sPower’s complaint be dismissed because sPower failed to establish that it faced a substantial risk of harm. In October 2017, the District Court denied the CPUC’s motion to dismiss and instead allowed sPower to file an amended complaint. The case effectively starts over and PSCo is expected to intervene in the proceeding again. The timing of a resolution in this case is unclear.

Item 4 — CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

PSCo maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms.
In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer (CEO)CEO and chief financial officer (CFO),CFO, allowing timely decisions regarding required disclosure.
As of Sept. 30, 2017,2022, based on an evaluation carried out under the supervision and with the participation of PSCo’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that PSCo’s disclosure controls and procedures were effective.


Internal Control Over Financial Reporting

In 2016, PSCo implemented the general ledger modules of a new enterprise resource planning system to improve certain financial and related transaction processes. PSCo initiated deployment of work management systems modules and is continuing to implement additional modules including the conversion of existing work management systems to this same system during 2017. In connection with this ongoing implementation, PSCo is updating its internal control over financial reporting, as necessary, to accommodate modifications to its business processes and accounting systems. PSCo does not believe that this implementation will have an adverse effect on its internal control over financial reporting.

No changes in PSCo’s internal control over financial reporting occurred during the most recent fiscal quarter that materially affected, or are reasonably likely to materially affect, PSCo’s internal control over financial reporting.


Part
PART II — OTHER INFORMATION

Item 1 — LEGAL PROCEEDINGS

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

Additional Information

For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, would have a material effect on PSCo’s consolidated financial statements. Legal fees are generally expensed as incurred.
See Note 69 to the consolidated financial statements for further discussion of legal claims and environmental proceedings. See Part I Item 2 and Note 5 to the consolidated financial statements for a discussion of proceedings involving utility rates and other regulatory matters.further information.

ITEM 1A — RISK FACTORS
Item 1A — RISK FACTORS

PSCo’s risk factors are documented in Item 1A of Part I of its Annual Report on Form 10-K for the year ended Dec. 31, 2016,2021, which is incorporated herein by reference. There have been no material changes from the risk factors previously disclosed in the Form 10-K.10-K.



Item 6 — EXHIBITS
*Indicates incorporation by reference
+Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors

ITEM 6— EXHIBITS
* Indicates incorporation by reference
Exhibit NumberDescriptionReport or Registration StatementExhibit Reference
3.02*
By-Laws of PSCo as Amended and Restated on Sept. 26, 2013 (Exhibit 3.02 to Form 10-Q/A10-Q for the quarter ended Sept. 30, 2013 (file no. 001-03280)).
2017		3.01
PSCo Form 10-K for the year ended Dec. 31, 20183.02
Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009 Restatement) (Exhibit 10.1 to Form 10-Q of Xcel Energy for the quarter ended Sept. 30, 2017 (file no. 001-03034)).8-K dated September 19, 202299.03
99.01
101.INS
Statement pursuant to Private Securities Litigation Reform Act of 1995.
Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101101.SCHThe following materials from PSCo’s Quarterly Report on Form 10-Q for the quarter ended Sept. 30, 2017 are formattedInline XBRL Schema
101.CALInline XBRL Calculation
101.DEFInline XBRL Definition
101.LABInline XBRL Label
101.PREInline XBRL Presentation
104Cover Page Interactive Data File (formatted as Inline XBRL and contained in XBRL (eXtensible Business Reporting Language):  (i) the Consolidated Statements of Income, (ii) the Consolidated Statements of Comprehensive Income (iii) the Consolidated Statements of Cash Flows, (iv) the Consolidated Balance Sheets, (v) Notes to Consolidated Financial Statements, and (vi) document and entity information.Exhibit 101)
20


Table of Contents
SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

Public Service Company of Colorado
10/27/2022By:Public Service Company of Colorado/s/ BRIAN J. VAN ABEL
Brian J. Van Abel
Oct. 27, 2017By:/s/ JEFFREY S. SAVAGE
Jeffrey S. Savage
Senior Vice President, Controller
(Principal Accounting Officer)
/s/ ROBERT C. FRENZEL
Robert C. Frenzel
Executive Vice President, Chief Financial Officer and Director
(Duly Authorized Officer and Principal Financial Officer)



31
21