UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K (Mark One) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2017 or TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission File Number: 001-3280 Public Service Company of Colorado (Exact name of registrant as specified in its charter) Colorado (State or other jurisdiction of incorporation or organization) 84-0296600 (I.R.S. Employer Identification No.) 1800 Larimer, Suite 1100, Denver, Colorado 80202 (Address of principal executive offices) Registrant’s telephone number, including area code: (303) 571-7511 Securities registered pursuant to Section 12(b) of the Act: None Securities registered pursuant to section 12(g) of the Act: None Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes No No Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes No Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 and Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes No Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulations S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. 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 Non-accelerated filer (Do not check if smaller reporting company) Accelerated filer Smaller reporting company Emerging growth company If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes No As of Feb. 23, 2018, 100 shares of common stock, par value $0.01 per share, were outstanding, all of which were held by Xcel Energy Inc., a Minnesota corporation. DOCUMENTS INCORPORATED BY REFERENCE The information required by Item 14 of Form 10-K is set forth under the heading “Independent Registered Public Accounting Firm – Audit and Non-Audit Fees” in Xcel Energy Inc.’s definitive Proxy Statement for the 2018 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about April 3, 2018. Such information set forth under such heading is incorporated herein by this reference hereto. Public Service Company of Colorado meets the conditions set forth in General Instructions I(1)(a) and (b) of Form 10-K and is therefore filing this form with reduced disclosure format permitted by General Instruction I(2). TABLE OF CONTENTS Index PART I Item 1 — Business DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS COMPANY OVERVIEW ELECTRIC UTILITY OPERATIONS Public Utility Regulation Capacity and Demand Energy Sources and Related Transmission Initiatives Fuel Supply and Costs Fuel Sources Renewable Energy Sources Wholesale Commodity Marketing Operations Summary of Recent Regulatory Developments Electric Operating Statistics NATURAL GAS UTILITY OPERATIONS Overview Public Utility Regulation Capability and Demand Natural Gas Supply and Costs Natural Gas Operating Statistics GENERAL ENVIRONMENTAL MATTERS EMPLOYEES Item 1A — Risk Factors Item 1B — Unresolved Staff Comments Item 2 — Properties Item 3 — Legal Proceedings Item 4 — Mine Safety Disclosures 3 3 5 5 5 6 6 8 8 9 9 9 10 11 11 11 12 12 13 13 14 14 14 23 24 25 25 PART II Item 5 — Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities Item 6 — Selected Financial Data Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations Item 7A — Quantitative and Qualitative Disclosures About Market Risk Item 8 — Financial Statements and Supplementary Data Item 9 — Changes in and Disagreements with Accountants on Accounting and Financial Disclosure Item 9A — Controls and Procedures Item 9B — Other Information 25 25 25 28 30 80 80 80 PART III Item 10 — Directors, Executive Officers and Corporate Governance Item 11 — Executive Compensation Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters Item 13 — Certain Relationships and Related Transactions, and Director Independence Item 14 — Principal Accountant Fees and Services 80 80 81 81 81 PART IV Item 15 — Exhibits, Financial Statement Schedules Item 16 — Form 10-K Summary SIGNATURES 82 85 86 This Form 10-K is filed by PSCo. PSCo is a wholly owned subsidiary of Xcel Energy Inc. Additional information on Xcel Energy is available in various filings with the SEC. This report should be read in its entirety. 2 Table of Contents PART I Item l — Business DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former) NCE New Century Energies, Inc. NSP-Minnesota Northern States Power Company, a Minnesota corporation NSP-Wisconsin Northern States Power Company, a Wisconsin corporation PSCo Public Service Company of Colorado PSRI P.S.R. Investments, Inc. SPS Southwestern Public Service Company Utility subsidiaries NSP-Minnesota, NSP-Wisconsin, PSCo and SPS WYCO WYCO Development, LLC Xcel Energy Xcel Energy Inc. and subsidiaries Federal and State Regulatory Agencies CFTC Commodity Futures Trading Commission CPUC Colorado Public Utilities Commission D.C. Circuit United States Court of Appeals for the District of Columbia Circuit DOT United States Department of Transportation EPA United States Environmental Protection Agency FERC Federal Energy Regulatory Commission IRS Internal Revenue Service NERC North American Electric Reliability Corporation PHMSA Pipeline and Hazardous Materials Safety Administration SEC Securities and Exchange Commission Electric, Purchased Gas and Resource Adjustment Clauses DSM Demand side management DSMCA Demand side management cost adjustment ECA Retail electric commodity adjustment GCA Gas cost adjustment PCCA Purchased capacity cost adjustment PSIA Pipeline system integrity adjustment RESA Renewable energy standard adjustment SCA Steam cost adjustment TCA Transmission cost adjustment WCA Windsource® cost adjustment Other Terms and Abbreviations AFUDC Allowance for funds used during construction ALJ Administrative law judge APBO Accumulated postretirement benefit obligation ARO Asset retirement obligation ASC FASB Accounting Standards Codification ASU FASB Accounting Standards Update C&I Commercial and Industrial CAISO California Independent System Operator CAA Clean Air Act CACJA Clean Air Clean Jobs Act CO2 Carbon dioxide 3 Table of Contents CPCN CPP CWIP ERCOT ETR FASB GAAP GHG IRC ITC JOA MGP MISO Moody’s MWTG Native load NAV NOL NOx O&M OCI PJM PM PPA PRP PSIA PTC PV R&E REC ROE RPS SIP SO2 SPP Standard & Poor’s TCJA Measurements KV KWh MMBtu MW MWh GWh Certificate of public convenience and necessity Clean Power Plan Construction work in progress Electric Reliability Council of Texas Effective tax rate Financial Accounting Standards Board Generally accepted accounting principles Greenhouse gas Internal Revenue Code Investment tax credit Joint operating agreement Manufactured gas plant Midcontinent Independent Transmission System Operator, Inc. Moody’s Investor Services Mountain West Transmission Group Customer demand of retail and wholesale customers whereby a utility has an obligation to serve under statute or long-term contract. Net asset value Net operating loss Nitrogen oxide Operating and maintenance Other comprehensive income PJM Interconnection, LLC Particulate matter Purchased power agreement Potentially responsible party Pipeline system integrity adjustment Production tax credit Photovoltaic Research and experimentation Renewable energy credit Return on equity Renewable portfolio standards State implementation plan Sulfur dioxide Southwest Power Pool, Inc. Standard & Poor’s Ratings Services 2017 federal tax reform enacted as Public Law No: 115-97, commonly referred to as the Tax Cuts and Jobs Act Kilovolts Kilowatt hours Million British thermal units Megawatts Megawatt hours Gigawatt hours 4 Table of Contents COMPANY OVERVIEW PSCo was incorporated in 1924 under the laws of Colorado. PSCo is a utility engaged primarily in the generation, purchase, transmission, distribution and sale of electricity in Colorado. PSCo also purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas. PSCo provides electric utility service to approximately 1.5 million customers and natural gas utility service to approximately 1.4 million customers. All of PSCo’s retail electric operating revenues were derived from operations in Colorado. Although PSCo’s large C&I electric retail customers are comprised of many diversified industries, a significant portion of PSCo’s large C&I electric sales include: fabricated metal products, communications and health services. For small C&I customers, significant electric retail sales include the following industries: real estate and dining establishments. Generally, PSCo’s earnings contribute approximately 35 percent to 45 percent of Xcel Energy’s consolidated net income. The wholesale customers served by PSCo comprised approximately 14 percent of its total KWh sold in 2017. PSCo owns the following direct subsidiaries: 1480 Welton, Inc. and United Water Company, both of which own certain real estate interests; and Green and Clear Lakes Company, which owns water rights and certain real estate interests. PSCo also holds a controlling interest in several other relatively small ditch and water companies. PSCo conducts its utility business in the following reportable segments: regulated electric utility, regulated natural gas utility and all other. See Note 15 to the consolidated financial statements for further discussion relating to comparative segment revenues, net income and related financial information. ELECTRIC UTILITY OPERATIONS Public Utility Regulation Summary of Regulatory Agencies and Areas of Jurisdiction — PSCo is regulated by the CPUC with respect to its facilities, rates, accounts, services and issuance of securities. PSCo is regulated by the FERC for its wholesale electric operations, accounting practices, hydroelectric licensing, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with the NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce. PSCo is not presently a member of an RTO and does not operate within an RTO energy market. PSCo is authorized by the FERC to make wholesale electric sales at market-based prices to customers outside PSCo’s balancing authority area. Fuel, Purchased Energy and Conservation Cost-Recovery Mechanisms — PSCo has several retail adjustment clauses that recover fuel, purchased energy and other resource costs: • • • • • • • • ECA — Recovers fuel and purchased energy costs. Short-term sales margins are shared with retail customers through the ECA. The ECA is revised quarterly. PCCA — Recovers purchased capacity payments. SCA — Recovers the difference between PSCo’s actual cost of fuel and the amount of these costs recovered under its base steam service rates. The SCA rate is revised on a quarterly basis. DSMCA — Recovers DSM, interruptible service costs and performance initiatives for achieving energy savings goals. RESA — Recovers the incremental costs of compliance with the RES with a maximum of two percent of the customer’s bill. WCA — Premium service for customers who choose to pay for renewable resources. TCA — Recovers costs associated with transmission investment outside of rate cases. CACJA — Recovers costs associated with the CACJA. PSCo recovers fuel and purchased energy costs from its wholesale electric customers through a fuel cost adjustment clause approved by the FERC. PSCo’s wholesale customers pay the full cost of certain renewable energy purchase and generation costs through a fuel clause and in exchange receive RECs associated with those resources. The wholesale customers pay their jurisdictional allocation of production costs through a fully forecasted formula rate with true-up. 5 Table of Contents Capacity and Demand Uninterrupted system peak demand for PSCo’s electric utility for each of the last three years and the forecast for 2018, assuming normal weather conditions, is as follows: 2017 PSCo 6,671 System Peak Demand (in MW) 2016 2015 6,585 6,284 2018 Forecast 6,462 The peak demand for PSCo’s system typically occurs in the summer. The 2017 system peak demand for PSCo occurred on July 19, 2017. The 2017 system peak demand was higher than 2016 due to warmer July summer weather. The forecast of system peak assumes normal weather conditions. Energy Sources and Related Transmission Initiatives PSCo expects to meet its system capacity requirements through existing electric generating stations, power purchases, new generation facilities, DSM options and phased expansion of existing generation at select power plants. Purchased Power — PSCo has contracts to purchase power from other utilities and IPPs. Long-term purchased power contracts for dispatchable resources typically require a periodic capacity charge and an energy charge for energy actually purchased. PSCo also contracts to purchase power for both wind and solar resources. In addition, PSCo makes short-term purchases to meet system load and energy requirements, to replace generation from company-owned units under maintenance or during outages, to meet operating reserve obligations, or to obtain energy at a lower cost. Purchased Transmission Services — In addition to using its own transmission system, PSCo has contracts with regional transmission service providers to deliver energy to PSCo’s customers. Rush Creek Wind Ownership Proposal — In 2016, the CPUC granted PSCo a CPCN to build, own 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. PTC components for safe harboring the facility have been fabricated and construction began in April 2017. Investment costs will be recovered through the RESA and ECA riders until PSCo’s next rate case following Rush Creek’s in-service date. The wind generation facility is anticipated to be in service in October 2018. Colorado Energy Plan (CEP) — In 2016, PSCo filed its 2016 Electric Resource Plan (ERP) which included the estimated need for additional generation resources through spring of 2024. In 2017, PSCo filed an updated capacity need with the CPUC of 450 MW in 2023. In August 2017, PSCo and various other stakeholders filed a stipulation agreement proposing the CEP, an alternative plan that increases the amount of new resources sought under the ERP. The CEP would increase PSCo’s potential capacity need up to 1,110 MW due to the proposed retirement of two coal units. The major components include: • • • • • • Early retirement of 660 MWs of coal-fired generation at Comanche Units 1 (2022) and 2 (2025); Accelerated depreciation for the early retirement of the two Comanche units and establishment of a regulatory asset to collect the incremental depreciation expense and related costs; A RFP for up to 1,000 MW of wind, 700 MW of solar and 700 MW of natural gas and/or storage; Utility ownership targets of 50 percent renewable generation resources and 75 percent of natural gas-fired, storage, or renewable with storage generation resources; Reduction of the RESA rider, from two percent to one percent effective beginning 2021 or 2022; and Construction of a new transmission switching station to further the development of renewable generating resources. 6 Table of Contents Hearings were held in February 2018 with two parties opposing both the coal retirements and utility ownership. Fifteen parties in the proceeding support the CEP. The CPUC is expected to rule on the stipulation agreement in March 2018. PSCo is currently evaluating bids from a RFP and anticipates filing its recommended portfolios in April 2018. A CPUC decision on the recommended portfolio is anticipated in the summer of 2018. Boulder, Colorado Municipalization — In 2011, in the City of Boulder, Colorado (Boulder), voters passed a ballot measure authorizing the formation of an electric municipal utility, subject to certain conditions. Since that time, there have been various legal proceedings in multiple venues with jurisdiction over Boulder’s plan. In 2014, the Boulder City Council passed an ordinance to establish an electric utility. PSCo challenged the formation of this utility as premature and the Colorado Court of Appeals ruled in PSCo’s favor, vacating a lower court decision. Subsequently, the Colorado Supreme Court granted Boulder’s petition to review the Court of Appeals decision and oral arguments were held on Feb. 14, 2018. A ruling on the petition is anticipated in 2018. In 2015, the Boulder District Court (District Court) affirmed a prior CPUC decision that Boulder cannot serve customers outside its city limits; these customers were included in Boulder’s plan at the time. The District Court also ruled the CPUC has jurisdiction over the transfer of any facilities to Boulder and in determining how the systems are separated. Further, the District Court found that the CPUC must give approval before Boulder files any condemnation proceeding. Boulder does not have authorization to initiate a condemnation proceeding at this time. Boulder has filed multiple separation applications, the most recent one being in May 2017, which was challenged by PSCo and other intervenors. In September 2017, the CPUC issued a written decision, agreeing with several key aspects of PSCo’s position, stating PSCo is not required to undertake many of Boulder’s proposals, such as acting as a financier and contractor for Boulder. Additionally, the CPUC approved the designation of some electrical distribution assets for transfer, subject to Boulder completing 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 assets desired to be transferred; and Filing an agreement to address payments from Boulder to PSCo for costs of Boulder’s municipalization efforts. Boulder has requested that the CPUC grant an extension through March 13, 2018 to complete such filings. Once those filings have been submitted, additional hearings may be held. In November 2017, Boulder voters passed certain measures regarding Boulder’s pursuit of municipalization, including an extension and increase of the Utility Occupational Tax for funding Boulder’s exploration of municipalization. MWTG — PSCo, along with nine other electric service providers from the Rocky Mountain region, have been considering creating and operating a joint transmission tariff to increase wholesale market efficiency and improve regional transmission planning. In September 2017, the MWTG determined that membership in the SPP RTO could provide opportunities to reduce customer costs, and maximize resource and electric grid utilization. In October 2017, the MWTG commenced negotiations with SPP through the SPP public stakeholder process. SPP’s Board of Directors and organizational groups have begun to address the MWTG’s proposed terms for integration into the SPP RTO. Should the MWTG decide to move forward, SPP would make filings with the FERC and PSCo would make filings with the CPUC and the FERC, in the later part of 2018. If approved, MWTG operations within the SPP RTO would not be expected to begin until late 2019 at the earliest. PSCo recently engaged a consultant to conduct an analysis of the benefits associated with membership in the SPP RTO. The analysis assumed gas price forecasts that are lower than gas price forecasts used by the other MWTG utilities in their analysis of the benefits associated with membership in the SPP RTO. PSCo is in the process of evaluating that analysis. 7 Table of Contents Fuel Supply and Costs The following table shows the delivered cost per MMBtu of each significant category of fuel consumed for owned electric generation, the percentage of total fuel requirements represented by each category of fuel and the total weighted average cost of all fuels. Coal PSCo Generating Plants 2017 2016 2015 Cost $ 1.56 1.75 1.75 Natural Gas Percent 70% $ 72 75 Cost 3.82 3.79 3.89 Percent Weighted Average Owned Fuel Cost 30% $ 28 25 2.25 2.33 2.29 See Items 1A and 7 for further discussion of fuel supply and costs. Fuel Sources Coal — PSCo normally maintains approximately 35 - 50 days of coal inventory. Coal supply inventories at Dec. 31, 2017 and 2016 were approximately 48 and 36 days of usage, respectively. PSCo has contracted for coal supply to provide 75 percent of its 9.1 million tons of estimated coal requirements in 2018, and a declining percentage of requirements in subsequent years. PSCo’s general coal purchasing objective is to contract for approximately 75 percent of requirements for the first year, 40 percent of requirements in year two, and 20 percent of requirements in year three. Remaining requirements will be filled through the procurement process or over-the-counter transactions. PSCo has coal transportation contracts that provide for delivery of 100 percent its coal requirements in 2018 and 2019. Coal delivery may be subject to interruptions or reductions due to operation of the mines, transportation problems, weather and availability of equipment. Natural gas — PSCo uses both firm and interruptible natural gas supply in combustion turbines and certain boilers. Natural gas supplies for PSCo’s power plants are procured under contracts to provide an adequate supply of fuel. However, as natural gas primarily serves intermediate and peak demand, any remaining forecasted requirements are able to be procured through a liquid spot market. The majority of natural gas supply under contract is covered by a long-term agreement with Anadarko Energy Services Company and the balance of natural gas supply contracts have variable pricing features tied to changes in various natural gas indices. PSCo hedges a portion of that risk through financial instruments. See Note 10 to the consolidated financial statements for further discussion. Most transportation contract pricing is based on FERC approved transportation tariff rates. Certain natural gas supply and transportation agreements include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery. • • At Dec. 31, 2017, PSCo’s commitments related to gas supply contracts, which expire between 2021 through 2023, were approximately $545 million and commitments related to gas transportation and storage contracts, which expire between 2018 through 2040, were approximately $620 million. At Dec. 31, 2016, PSCo’s commitments related to gas supply contracts were approximately $654 million and commitments related to gas transportation and storage contracts were approximately $573 million. PSCo has limited on-site fuel oil storage facilities and primarily relies on the spot market for incremental supplies. 8 Table of Contents Renewable Energy Sources PSCo’s renewable energy portfolio includes wind, hydroelectric, biomass and solar power from both owned generating facilities and PPAs. As of Dec. 31, 2017, PSCo was in compliance with mandated RPS, which requires generation from renewable resources of 20.0 percent of electric retail sales. Renewable energy as a percentage of PSCo’ total energy: 2017 Renewable Wind Hydroelectric, biomass and solar 2016 27.7% 23.7 3.9 28.3% 23.7 4.6 PSCo also offers customer-focused renewable energy initiatives. Windsource allows customers to purchase electricity from renewable sources. The number of customers utilizing Windsource increased to approximately 50,000 in 2017 from 46,000 in 2016. Additionally, to encourage the growth of solar energy on the system, customers are offered incentives to install solar panels on their homes and businesses under the Solar*Rewards® program. Over 34,900 PV systems with approximately 310 MW of aggregate capacity have been installed in Colorado as of Dec. 31, 2017 and over 32,500 PV systems with approximately 276 MW of aggregate capacity were installed as of Dec. 31, 2016. Additionally, 33 community solar gardens with 33.5 MW of capacity have been completed in Colorado as of Dec. 31, 2017. Wind — PSCo acquires the majority of its wind energy from PPAs. Currently, PSCo has 18 of these agreements in place, with facilities ranging in size from two MW to over 300 MW. • • PSCo had approximately 2,560 MW of wind energy on its system at the end of 2017 and 2016. In addition to receiving purchased wind energy under these agreements, PSCo typically receives wind RECs which are used to meet state renewable resource requirements. The average cost per MWh of wind energy under these contracts was approximately $42 in 2017 and 2016. The cost per MWh of wind energy varies by contract and may be influenced by a number of factors including regulation, state-specific renewable resource requirements, and the year of contract execution. Generally, previously executed contracts continued to benefit from improvements in wind technology, excess capacity among manufacturers, and motivation to commence new construction prior to the anticipated expiration of the federal PTCs. In December 2015, the federal PTCs were extended through 2019 with a phase down on sites that began construction in 2017. Wholesale and Commodity Marketing Operations PSCo conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy related products. PSCo uses physical and financial instruments to minimize commodity price and credit risk and hedge sales and purchases. PSCo also engages in trading activity unrelated to hedging and sharing of any margins is determined through state regulatory proceedings as well as the operation of the FERC approved JOA. See Item 7 for further discussion. Summary of Recent Federal Regulatory Developments The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, hydro facility licensing, natural gas transportation, asset transactions and mergers, accounting practices and certain other activities of PSCo, including enforcement of NERC mandatory electric reliability standards. State and local agencies have jurisdiction over many of PSCo’s activities, including regulation of retail rates and environmental matters. In addition to the matters discussed below, see Note 11 to the accompanying consolidated financial statements for a discussion of other regulatory matters. Xcel Energy, which includes PSCo, attempts to mitigate the risk of regulatory penalties through formal training on prohibited practices and a compliance function that reviews interaction with the markets under FERC and CFTC jurisdictions. Public campaigns are conducted to raise awareness of the public safety issues of interacting with our electric systems. While programs to comply with regulatory requirements are in place, there is no guarantee the compliance programs or other measures will be sufficient to ensure against violations. 9 Table of Contents Public Utility Regulatory Policies Act (PURPA) Enforcement Complaint against CPUC — In December 2016, Sustainable Power Group, LLC (sPower) petitioned the FERC to initiate an enforcement action in federal court against the CPUC under PURPA. The petition asserts that a December 2016 CPUC ruling, which indicated that a qualifying facility must be a successful bidder in a PSCo resource acquisition bidding process, violated PURPA and FERC rules. In January 2017, PSCo filed a motion to intervene and protest, arguing that the FERC should decline the petition. The CPUC filed a similar pleading. sPower has proposed to construct 800 MW of solar generation and 700 MW of wind generation in Colorado and seeks to require PSCo to contract for these resources under PURPA. If sPower were to prevail, PSCo’s ability to select generation resources through competitive bidding would be negatively affected. However, due to a lack of quorum at the FERC, the FERC did not act on that petition within the sixty days contemplated by PURPA. Subsequently sPower filed a complaint for declaratory and injunctive relief in the United States District Court for the District of Colorado (District Court) requesting that the court find the bidding requirement in the CPUC qualifying facility rules to be unlawful. PSCo intervened in that proceeding and the CPUC filed a motion to dismiss. In June 2017, the United States Magistrate Judge issued a recommendation to the District Court that sPower’s complaint be dismissed because sPower failed to establish that it faced a substantial risk of harm. In October 2017, the District Court denied the CPUC’s motion to dismiss and instead allowed sPower to file an amended complaint. The case effectively started over and PSCo intervened. The CPUC filed a motion to dismiss the amended complaint which is currently pending before the District Court. The timing of a resolution in this case is unclear. Electric Operating Statistics Electric Sales Statistics 2017 Electric sales (Millions of KWh) Residential Large commercial and industrial Small commercial and industrial Public authorities and other Total retail Sales for resale Total energy sold KWh sales per retail customer Revenue per retail customer Residential revenue per KWh Large commercial and industrial revenue per KWh Small commercial and industrial revenue per KWh Total retail revenue per KWh Wholesale revenue per KWh 9,272 6,371 12,890 268 28,801 4,672 33,473 9,112 6,596 12,750 242 28,700 3,581 32,281 1,252,376 340 160,406 54,110 1,467,232 43 1,467,275 1,235,378 337 159,299 54,048 1,449,062 34 1,449,096 1,218,662 337 158,086 53,944 1,431,029 26 1,431,055 $ 1,033,324 421,068 1,227,886 52,834 2,735,112 167,971 100,725 $ 3,003,808 $ 1,063,526 414,797 1,204,881 54,070 2,737,274 152,375 159,703 $ 3,049,352 $ 1,060,626 433,061 1,220,064 52,783 2,766,534 180,716 168,007 $ 3,115,257 $ 10 2015 9,107 6,449 12,796 274 28,626 4,851 33,477 Number of customers at end of period Residential Large commercial and industrial Small commercial and industrial Public authorities and other Total retail Wholesale Total customers Electric revenues (Thousands of Dollars) Residential Large commercial and industrial Small commercial and industrial Public authorities and other Total retail Wholesale Other electric revenues Total electric revenues Year Ended Dec. 31 2016 19,510 1,864 $ 11.35 ¢ 6.53 9.60 9.55 3.46 19,876 1,889 $ 11.47 ¢ 6.51 9.35 9.50 3.26 20,055 1,933 11.64 ¢ 6.57 9.57 9.64 5.05 Table of Contents Energy Source Statistics Year Ended Dec. 31 2017 Millions of KWh 2016 Percent of Generation Millions of KWh 2015 Percent of Generation Millions of KWh Percent of Generation Coal Natural Gas Wind (a) Hydroelectric Other (b) Total 14,609 9,195 7,804 624 670 32,902 44% 28 24 2 2 100% 15,895 8,632 8,106 1,179 393 34,205 47% 25 24 3 1 100% 18,601 7,948 6,699 662 705 34,615 54% 23 19 2 2 100% Owned generation Purchased generation Total 23,053 9,849 32,902 70% 30 100% 22,753 11,452 34,205 67% 33 100% 22,981 11,634 34,615 66% 34 100% (a) (b) This category includes wind energy de-bundled from RECs and also includes Windsource RECs. PSCo uses RECs to meet or exceed state resource requirements and may sell surplus RECs. Distributed generation from the Solar*Rewards program is not included, and was approximately 393, 396 and 245 million net KWh for 2017, 2016, and 2015, respectively. NATURAL GAS UTILITY OPERATIONS Overview PSCo operates a natural gas local distribution company in Colorado. The most significant developments in the natural gas operations of PSCo are uncertainty regarding political and regulatory developments that impact hydraulic fracturing, safety requirements for natural gas pipelines and the continued trend of declining use per residential and small C&I customer, as a result of improved building construction technologies, higher appliance efficiencies, and conservation. From 2000 to 2017, average annual sales to the typical PSCo residential customer declined 17 percent, while sales to the typical small C&I customer declined 12 percent, each on a weather normalized basis. Although wholesale price increases do not directly affect earnings because of natural gas cost recovery mechanisms, high prices can encourage further efficiency efforts by customers. Pipeline Safety Act — The Pipeline Safety, Regulatory Certainty, and Job Creation Act (Pipeline Safety Act) requires additional verification of pipeline infrastructure records by pipeline owners and operators to confirm the maximum allowable operating pressure of lines located in high consequence areas or more-densely populated areas. In April 2016, the PHMSA released proposed rules that address this verification requirement along with a number of other significant changes to gas transmission regulations. These changes include requirements around use of automatic or remote-controlled shut-off valves, testing of certain previously untested transmission lines and expanding integrity management requirements. The Pipeline Safety Act also includes a maximum penalty for violating pipeline safety rules of $2 million per day for related violations. PHMSA is currently working through the rule with its Pipeline Advisory Committee. Current estimates are the rule will likely go into effect in late 2018 or early 2019. PSCo has been taking actions that were intended to comply with the Pipeline Safety Act and any related PHMSA regulations as they become effective. PSCo can generally recover costs to comply with the transmission and distribution integrity management programs through the PSIA rider. Public Utility Regulation Summary of Regulatory Agencies and Areas of Jurisdiction — PSCo is regulated by the CPUC with respect to its facilities, rates, accounts, services and issuance of securities. PSCo holds a FERC certificate that allows it to transport natural gas in interstate commerce without PSCo becoming subject to full FERC jurisdiction under the Federal Natural Gas Act. PSCo is subject to the DOT and the CPUC with regards to pipeline safety compliance. 11 Table of Contents Purchased Natural Gas and Conservation Cost-Recovery Mechanisms — PSCo has retail adjustment clauses that recover purchased natural gas and other resource costs: • • • GCA — Recovers the actual costs of purchased natural gas and transportation to meet the requirements of its customers and is revised quarterly to allow for changes in natural gas rates. DSMCA — Recovers costs of DSM and performance initiatives to achieve various energy savings goals. PSIA — Recovers costs associated with transmission and distribution pipeline integrity management programs and two projects to replace large transmission pipelines. Capability and Demand Natural gas supply requirements are categorized as firm or interruptible (customers with an alternate energy supply). The maximum daily send-out (firm and interruptible) for PSCo was 1,948,167 MMBtu, which occurred on Jan. 5, 2017 and 1,932,070 MMBtu, which occurred on Dec. 17, 2016. PSCo purchases natural gas from independent suppliers, generally based on market indices that reflect current prices. The natural gas is delivered under transportation agreements with interstate pipelines. These agreements provide for firm deliverable pipeline capacity of approximately 1,818,151 MMBtu per day, which includes 854,852 MMBtu of natural gas held under third-party underground storage agreements. In addition, PSCo operates three company-owned underground storage facilities, which provide approximately 43,500 MMBtu of natural gas supplies on a peak day. The balance of the quantities required to meet firm peak day sales obligations are primarily purchased at PSCo’s city gate meter stations. PSCo is required by CPUC regulations to file a natural gas purchase plan each year projecting and describing the quantities of natural gas supplies, upstream services and the costs of those supplies and services for the 12-month period of the following year. PSCo is also required to file a natural gas purchase report by October of each year reporting actual quantities and costs incurred for natural gas supplies and upstream services for the previous 12-month period. Natural Gas Supply and Costs PSCo actively seeks natural gas supply, transportation and storage alternatives to yield a diversified portfolio that provides increased flexibility, decreased interruption and financial risk and economical rates. In addition, PSCo conducts natural gas price hedging activities that have been approved by the CPUC. The following table summarizes the average delivered cost per MMBtu of natural gas purchased for resale by PSCo’s regulated retail natural gas distribution business: 2017 2016 2015 $ 3.45 3.27 3.92 The cost of natural gas in 2017 increased due to higher wholesale commodity prices. PSCo has natural gas supply, transportation and storage agreements that include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery. At Dec. 31, 2017, PSCo was committed to approximately $1.4 billion in such obligations under these contracts, which expire in various years from 2018 through 2029. PSCo purchases natural gas by optimizing a balance of long-term and short-term natural gas purchases, firm transportation and natural gas storage contracts. During 2017, PSCo purchased natural gas from approximately 31 suppliers. See Items 1A and 7 for further discussion of natural gas supply and costs. 12 Table of Contents Natural Gas Operating Statistics Year Ended Dec. 31 Natural gas deliveries (Thousands of MMBtu) Residential Commercial and industrial Total retail Transportation and other Total deliveries Number of customers at end of period Residential Commercial and industrial Total retail Transportation and other Total customers Natural gas revenues (Thousands of Dollars) Residential Commercial and industrial Total retail Transportation and other Total natural gas revenues $ $ MMBtu sales per retail customer Revenue per retail customer Residential revenue per MMBtu Commercial and industrial revenue per MMBtu Transportation and other revenue per MMBtu $ 2017 2016 2015 88,843 37,305 126,148 124,211 250,359 90,941 38,093 129,034 117,462 246,496 92,001 38,405 130,406 108,860 239,266 1,284,644 100,802 1,385,446 7,649 1,393,095 1,269,338 100,718 1,370,056 7,261 1,377,317 1,254,056 100,389 1,354,445 6,936 1,361,381 652,913 247,582 900,495 94,719 995,214 91.05 650 7.35 6.64 0.76 $ $ $ 611,804 228,103 839,907 117,814 957,721 94.18 613 6.73 5.99 1.00 $ 678,909 257,287 936,196 70,470 $ 1,006,666 $ 96.28 691 7.38 6.70 0.65 GENERAL Seasonality The demand for electric power and natural gas is affected by seasonal differences in the weather. In general, peak sales of electricity occur in the summer months, and peak sales of natural gas occur in the winter months. As a result, the overall operating results may fluctuate substantially on a seasonal basis. Additionally, PSCo’s operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. See Item 7 for further discussion. 13 Table of Contents Competition PSCo is a vertically integrated utility, subject to traditional cost-of-service regulation. However, PSCo is subject to different public policies that promote competition and the development of energy markets. PSCo’s industrial and large commercial customers have the ability to own or operate facilities to generate their own electricity. In addition, customers may have the option of substituting other fuels, such as natural gas, steam or chilled water for heating, cooling and manufacturing purposes, or the option of relocating their facilities to a lower cost region. Customers also have the opportunity to supply their own power with solar generation (typically rooftop solar or solar gardens) and in most jurisdictions can currently avoid paying for most of the fixed production, transmission and distribution costs incurred to serve them. Several states, including Colorado, have policies designed to promote the development of solar and other distributed energy resources through significant incentive policies; with these incentives and federal tax subsidies, distributed generating resources are potential competitors to PSCo’s electric service business. The FERC has continued to promote competitive wholesale markets through open access transmission and other means. As a result, PSCo and its wholesale customers can purchase generation resources from competing wholesale suppliers and use the transmission systems of Xcel Energy Inc.’s utility subsidiaries on a comparable basis to serve their native load. State public utilities commissions, including the CPUC, have created resource planning programs that promote competition in the acquisition of electricity generation resources used to provide service to retail customers. In addition, FERC Order 1000 seeks to establish competition for construction and operation of certain new electric transmission facilities. PSCo also has franchise agreements with certain cities subject to periodic renewal. If a city elected not to renew a franchise agreement, it could seek alternative means for its citizens to access electric power or gas, such as municipalization. While facing these challenges, PSCo believes its rates and services are competitive with currently available alternatives. ENVIRONMENTAL MATTERS PSCo’s facilities are regulated by federal and state environmental agencies. These agencies have jurisdiction over air emissions, water quality, wastewater discharges, solid wastes and hazardous substances. Various company activities require registrations, permits, licenses, inspections and approvals from these agencies. PSCo has received all necessary authorizations for the construction and continued operation of its generation, transmission and distribution systems. PSCo’s facilities have been designed and constructed to operate in compliance with applicable environmental standards. However, it is not possible to determine when or to what extent additional facilities or modifications of existing or planned facilities will be required as a result of changes to environmental regulations, interpretations or enforcement policies or what effect future laws or regulations may have upon PSCo’s operations. See Notes 11 and 12 to the consolidated financial statements for further discussion. There are significant present and future environmental regulations to encourage the use of clean energy technologies and regulate emissions of GHGs to address climate change. PSCo has undertaken a number of initiatives to meet current requirements and prepare for potential future regulations, reduce GHG emissions and respond to state renewable and energy efficiency goals. If these future environmental regulations do not provide credit for the investments we have already made to reduce GHG emissions, or if they require additional initiatives or emission reductions, then their requirements would potentially impose additional substantial costs. PSCo believes, based on prior state commission practice, it would recover the cost of these initiatives through rates. EMPLOYEES As of Dec. 31, 2017, PSCo had 2,400 full-time employees and two part-time employees, of which 1,835 were covered under collective-bargaining agreements. See Note 8 to the consolidated financial statements for further discussion. 14 Table of Contents Item 1A — Risk Factors Xcel Energy, which includes PSCo, is subject to a variety of risks, many of which are beyond our control. Important risks that may adversely affect the business, financial condition and results of operations are further described below. These risks should be carefully considered together with the other information set forth in this report and in future reports that Xcel Energy files with the SEC. Oversight of Risk and Related Processes A key accountability of the Board of Directors is the oversight of material risk, and our Board of Directors employs an effective process for doing so. Management and the Board of Directors have responsibility for overseeing the identification and mitigation of key risks. Management identifies and analyzes risks to determine materiality and other attributes such as timing, probability and controllability. Management broadly considers our business, the utility industry, the domestic and global economies and the environment when identifying, assessing, managing and mitigating risk. Identification and analysis occurs formally through a key risk assessment process conducted by senior management, the financial disclosure process, the hazard risk management process and internal auditing and compliance with financial and operational controls. Management also identifies and analyzes risk through its business planning process and development of goals and key performance indicators, which include risk identification to determine barriers to implementing our strategy. The business planning process also identifies areas in which there is a potential for a business area to take inappropriate risk to meet goals, and determines how to prevent inappropriate risk-taking. At a threshold level, PSCo has developed a robust compliance program and promotes a culture of compliance, including tone at the top, which mitigates risk. The process for risk mitigation includes adherence to our code of conduct and other compliance policies, operation of formal risk management structures and groups and overall business management to mitigate the risks inherent in the implementation of strategy. Building on this culture of compliance, management further mitigates risks through operation of formal risk management structures and groups, including management councils, risk committees and the services of internal corporate areas such as internal audit, the corporate controller and legal services. Management communicates regularly with the Board of Directors and key stakeholders regarding risk. Senior management presents a periodic assessment of key risks to the Board of Directors. The presentation and the discussion of the key risks provides the Board of Directors with information on the risks management believes are material, including the earnings impact, timing, likelihood and controllability. Management also provides information to the Board of Directors in presentations and communications over the course of the year. Overall, the Board of Directors approaches oversight, management and mitigation of risk as an integral and continuous part of its governance of PSCo. Processes are in place to ensure appropriate risk oversight, as well as identification and consideration of new risks. The Board of Directors regularly reviews management’s key risk assessment informed by these processes, and analyzes areas of existing and future risks and opportunities. Risks Associated with Our Business 15 Table of Contents Environmental Risks We are subject to environmental laws and regulations, with which compliance could be difficult and costly. We are subject to environmental laws and regulations that affect many aspects of our past, present and future operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances. These laws and regulations require us to obtain permits, licenses, and other approvals and to comply with a wide variety of environmental requirements including those for protected natural and cultural resources (such as wetlands, endangered species and other protected wildlife, and archaeological and historical resources). Environmental laws and regulations can also require us to restrict or limit the output of certain facilities or the use of certain fuels, shift generation to lower-emitting, but potentially more costly facilities, install pollution control equipment at our facilities, clean up spills and other contamination and correct environmental hazards. Environmental regulations may also lead to shutdown of existing facilities, either due to the difficulty in assuring compliance or that the costs of compliance makes operation of the units no longer economical. Both public officials and private individuals may seek to enforce the applicable environmental laws and regulations against us. We may be required to pay all or a portion of the cost to remediate (i.e., clean-up) sites where our past activities, or the activities of certain other parties, caused environmental contamination. We are also subject to mandates to provide customers with clean energy, renewable energy and energy conservation offerings. Failure to meet the requirements of these mandates may result in fines or penalties, which could have a material effect on our results of operations. If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates or other environmental requirements, it could have a material effect on our results of operations, financial position or cash flows. In addition, existing environmental laws or regulations may be revised, and new laws or regulations may be adopted or become applicable to us, including but not limited to, regulation of mercury, NOx, SO2, CO2 and other GHGs, particulates, cooling water intakes, water discharges and ash management. We may also incur additional unanticipated obligations or liabilities under existing environmental laws and regulations. We are subject to physical and financial risks associated with climate change and other weather, natural disaster and resource depletion impacts. Climate change can create physical and financial risk. Physical risks from climate change can include changes in weather conditions, changes in precipitation and extreme weather events. Our customers’ energy needs vary with weather conditions, primarily temperature and humidity. For residential customers, heating and cooling represent their largest energy use. To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease. Increased energy use due to weather changes may require us to invest in additional generating assets, transmission and other infrastructure to serve increased load. Decreased energy use due to weather changes may result in decreased revenues. Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system stress, including service interruptions. Weather conditions could also have an impact on our revenues. We buy and sell electricity depending upon system needs and market opportunities. Extreme weather conditions creating high energy demand may raise electricity prices, which would increase the cost of energy we provide to our customers. Severe weather impacts our service territories, primarily when thunderstorms and associated flooding, tornadoes, wildfires and snow or ice storms occur. To the extent the frequency of extreme weather events increases, this could increase our cost of providing service. Changes in precipitation resulting in droughts or water shortages, whether caused by climate change or otherwise, could adversely affect our operations, principally our fossil generating units. A negative impact to water supplies due to long-term drought or water depletion conditions could adversely impact our ability to provide electricity to customers, as well as increase the price they pay for energy. We may not recover all costs related to mitigating these physical and financial risks. Climate change may impact a region’s economic health, which could impact our revenues. Our financial performance is tied to the health of the regional economies we serve. The price of energy has an impact on the economic health of our communities. The cost of additional regulatory requirements, such as regulation of GHG or additional environmental regulation could impact the availability of goods and prices charged by our suppliers which would normally be borne by consumers through higher prices for energy and purchased goods. To the extent financial markets view climate change and emissions of GHGs as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less than ideal terms and conditions. 16 Table of Contents Financial Risks Our profitability depends in part on our ability to recover costs from our customers and there may be changes in circumstances or in the regulatory environment that impair our ability to recover costs from our customers. We are subject to comprehensive regulation by federal and state utility regulatory agencies. The CPUC regulates many aspects of our utility operations, including siting and construction of facilities, customer service and the rates that we can charge customers. The FERC has jurisdiction, among other things, over wholesale rates for electric transmission service, the sale of electric energy in interstate commerce and certain natural gas transactions in interstate commerce. The profitability of our operations is dependent on our ability to recover the costs of providing energy and utility services to our customers and earn a return on our capital investment. We provide service at rates approved by one or more regulatory commissions. These rates are generally regulated and based on an analysis of our costs incurred in a test year. We are subject to both future and historical test years depending upon the regulatory mechanisms approved in each jurisdiction. Thus, the rates we are allowed to charge may or may not match our costs at any given time. While rate regulation is premised on providing an opportunity to earn a reasonable rate of return on invested capital, in a continued low interest rate environment there has been pressure pushing down ROE. There can also be no assurance that the applicable regulatory commission will judge all of our costs to have been prudent, which could result in cost disallowances, or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of such costs. Changes in the long-term cost-effectiveness or changes to the operating conditions of our assets may result in early retirements and while regulation typically provides relief for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs leaving all or a portion of these asset costs stranded. Higher than expected inflation may increase costs of construction and operations. Rising fuel costs could increase the risk that we will not be able to fully recover our fuel costs from our customers. Furthermore, there could be changes in the regulatory environment that would impair our ability to recover costs historically collected from our customers, or these factors could cause us to exceed commitments made regarding cost caps and result in less than full recovery. Overall, management currently believes prudently incurred costs are generally recoverable given the existing regulatory mechanisms in place. Adverse regulatory rulings or the imposition of additional regulations could have an adverse impact on our results of operations and hence could materially and adversely affect our ability to meet our financial obligations, including debt payments. Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships. We cannot be assured that any of our current ratings will remain in effect for any given period of time, or that a rating will not be lowered or withdrawn entirely by a rating agency. Significant events including a major disallowance of costs, significantly lower returns on equity or equity ratios or impacts of tax policy changes, among others, may impact our cash flows and credit metrics, potentially resulting in a change in our credit ratings. In addition, our credit ratings may change as a result of the differing methodologies or change in the methodologies used by the various rating agencies. Any downgrade could lead to higher borrowing costs and could impact our ability to access capital markets. Also, we may enter into certain procurement and derivative contracts that require the posting of collateral or settlement of applicable contracts if credit ratings fall below investment grade. We are subject to capital market and interest rate risks. Utility operations require significant capital investment. As a result, we frequently need to access capital markets. Any disruption in capital markets could have a material impact on our ability to fund our operations. Capital markets are global in nature and are impacted by numerous issues and events throughout the world economy. Capital market disruption events and resulting broad financial market distress could prevent us from issuing short term commercial paper, issuing new securities or cause us to issue securities with less than ideal terms and conditions, such as higher interest rates. Higher interest rates on short-term borrowings with variable interest rates could also have an adverse effect on our operating results. Changes in interest rates may also impact the fair value of the debt securities in the master pension trust, as well as our ability to earn a return on short-term investments of excess cash. 17 Table of Contents We are subject to credit risks. Credit risk includes the risk that our customers will not pay their bills, which may lead to a reduction in liquidity and an increase in bad debt expense. Credit risk is comprised of numerous factors including the price of products and services provided, the overall economy and local economies in the geographic areas we serve, including local unemployment rates. Credit risk also includes the risk that various counterparties that owe us money or product will become insolvent and/or breach their obligations. Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected and we could incur losses. We may at times have direct credit exposure in our short-term wholesale and commodity trading activity to various financial institutions trading for their own accounts or issuing collateral support on behalf of other counterparties. We may also have some indirect credit exposure due to participation in organized markets, such as CAISO, SPP, MISO and ERCOT, in which any credit losses are socialized to all market participants. We do have additional indirect credit exposures to various domestic and foreign financial institutions in the form of letters of credit provided as security by power suppliers under various long-term physical purchased power contracts. If any of the credit ratings of the letter of credit issuers were to drop below the designated investment grade rating stipulated in the underlying long-term purchased power contracts, the supplier would need to replace that security with an acceptable substitute. If the security were not replaced, the party could be in technical default under the contract, which would enable us to exercise our contractual rights. Increasing costs associated with our defined benefit retirement plans and other employee benefits may adversely affect our results of operations, financial position or liquidity. We have defined benefit pension and postretirement plans that cover most of our employees. Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions, including mortality tables, have a significant impact on our funding requirements related to these plans. These estimates and assumptions may change based on economic conditions, actual stock and bond market performance, changes in interest rates and changes in governmental regulations. In addition, the Pension Protection Act of 2006 changed the minimum funding requirements for defined benefit pension plans with modifications that allowed additional flexibility in the timing of contributions. Therefore, our funding requirements and related contributions may change in the future. Also, the payout of a significant percentage of pension plan liabilities in a single year due to high retirements or employees leaving PSCo could trigger settlement accounting and could require PSCo to recognize material incremental pension expense related to unrecognized plan losses in the year these liabilities are paid. Increasing costs associated with health care plans may adversely affect our results of operations. Our self-insured costs of health care benefits for eligible employees have increased in recent years. Increasing levels of large individual health care claims and overall health care claims could have an adverse impact on our operating results, financial position, and liquidity. We believe that our employee benefit costs, including costs related to health care plans for our employees and former employees, will continue to rise. Changes in industry standards utilized by management in key assumptions (e.g., mortality tables) could have a significant impact on future liabilities and benefit costs. Legislation related to health care could also significantly change our benefit programs and costs. Federal tax law may significantly impact our business. PSCo collects through regulated rates its estimated federal, state and local tax payments. There are a number of provisions in federal tax law designed to incentivize capital investments which have benefited our customers by keeping our utility subsidiaries’ rates lower than rates calculated without such provisions. Examples include the use of accelerated depreciation for most of our capital investments, PTCs for wind energy, ITCs for solar energy and R&E tax credits and deductions. Changes to federal tax law may benefit or adversely affect our earnings and customer costs. Changes to tax depreciable lives and the value of various tax credits could change the economics of resources and our resource selections. While regulation allows us to incorporate changes in tax law into the rate-setting process, there could be timing delays before regulated rates provide for realization of the tax changes in revenues. In addition, certain IRS tax policies such as the requirement to utilize normalization may impact our ability to economically deliver certain types of resources relative to market prices. 18 Table of Contents Operational Risks Our natural gas and electric transmission and distribution operations involve numerous risks that may result in accidents and other operating risks and costs. Our natural gas transmission and distribution activities include a variety of inherent hazards and operating risks, such as leaks, explosions and mechanical problems, which could cause substantial financial losses. Our electric transmission and distribution activities also include inherent hazards and operating risks such as contact, fire and widespread outages which could cause substantial financial losses. In addition, these natural gas and electric risks could result in loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial losses to us. We maintain insurance against some, but not all, of these risks and losses. The occurrence of any of these events not fully covered by insurance could have a material effect on our financial position and results of operations. For our natural gas transmission or distribution lines located near populated areas, the level of potential damages resulting from these risks is greater. Additionally, for natural gas the operating or other costs that may be required in order to comply with potential new regulations, including the Pipeline Safety Act, could be significant. The Pipeline Safety Act requires verification of pipeline infrastructure records by pipeline owners and operators to confirm the maximum allowable operating pressure of lines located in high consequence areas or more-densely populated areas. We have programs in place to comply with the Pipeline Safety Act and for systematic infrastructure monitoring and renewal over time. A significant incident could increase regulatory scrutiny and result in penalties and higher costs of operations. Our utility operations are subject to long-term planning risks. Most electric utility investments are long-lived and are planned to be used for decades. Transmission and generation investments typically have long lead times, and therefore are planned well in advance of when they are brought in-service subject to long-term resource plans. These plans are based on numerous assumptions over the planning horizon such as: sales growth, customer usage, commodity prices, economic activity, costs, regulatory mechanisms, customer behavior, available technology and public policy. The electric utility sector is undergoing a period of significant change. For example, public policy has driven increases in appliance and lighting efficiency and energy efficient buildings, wider adoption and lower cost of renewable generation and distributed generation, including community solar gardens and customer-sited solar, shifts away from coal generation to decrease CO2 emissions and increasing use of natural gas in electric generation driven by lower natural gas prices. Over time, customer adoption of these technologies and increased energy efficiency could result in excess transmission and generation resources as well as stranded costs if PSCo is not able to fully recover the costs and investments. These changes also introduce additional uncertainty into long-term planning which gives rise to a risk that the magnitude and timing of resource additions and growth in customer demand may not coincide, and that the preference for the types of additions may change from planning to execution. In addition, we are also subject to longer-term availability of the natural resource inputs such as coal, natural gas, uranium and water to cool our facilities. Lack of availability of these resources could jeopardize long-term operations of our facilities or make them uneconomic to operate. The resource plans reviewed and approved by our state regulators assume continuation of the traditional utility cost of service model under which utility costs are recovered from customers as they receive the benefit of service. PSCo is engaged in significant and ongoing infrastructure investment programs to accommodate renewable distributed generation and maintain high system reliability. Changing customer expectations and changing technologies are requiring significant investments in advanced grid infrastructure. This also increases the exposure to potential outdating of technologies and the resultant risks. PSCo is also investing in renewable and natural gas-fired generation to reduce our CO2 emissions profile. The inability of coal mining companies to attract capital could disrupt longer-term supplies. Early plant retirements that may result from these changes could expose us to premature financial obligations, which could result in less than full recovery of all remaining costs. Both decreasing use per customer driven by appliance and lighting efficiency and the availability of cost-effective distributed generation puts downward pressure on load growth. This could lead to under recovery of costs, excess resources to meet customer demand and increases in electric rates. Finally, multiple states served by a single system may not agree as to the appropriate resource mix and the differing views may lead to costs incurred to comply with one jurisdiction that are not recoverable across all of the jurisdictions served by the same assets. 19 Table of Contents We are subject to commodity risks and other risks associated with energy markets and energy production. We engage in wholesale sales and purchases of electric capacity, energy and energy-related products as well as natural gas. In many markets in which we operate, emission allowances and/or renewable energy credits are also needed to comply with various statutes and commission rulings associated with energy transactions. As a result we are subject to market supply and commodity price risk. Commodity price changes can affect the value of our commodity trading derivatives. We mark certain derivatives to estimated fair market value on a daily basis (mark-to-market accounting). Actual settlements can vary significantly from estimated fair values recorded, and significant changes from the assumptions underlying our fair value estimates could cause earnings variability. If we encounter market supply shortages or our suppliers are otherwise unable to meet their contractual obligations, we may be unable to fulfill our contractual obligations to our customers at previously anticipated costs. Therefore, a significant disruption could cause us to seek alternative supply services at potentially higher costs or suffer increased liability for unfulfilled contractual obligations. Any significantly higher energy or fuel costs relative to corresponding sales commitments could have a negative impact on our cash flows and potentially result in economic losses. Potential market supply shortages may not be fully resolved through alternative supply sources and may cause short-term disruptions in our ability to provide electric and/or natural gas services to our customers. The impact of these cost and reliability issues depends on our operating conditions such as generation fuels mix, availability of water for cooling, availability of fuel transportation including rail shipments of coal, electric generation capacity, transmission, natural gas pipeline capacity, etc. Failure to provide service due to disruptions could also result in fines, penalties or cost disallowances through the regulatory process. As we are a subsidiary of Xcel Energy Inc., we may be negatively affected by events impacting the credit or liquidity of Xcel Energy Inc. and its affiliates. If Xcel Energy Inc. were to become obligated to make payments under various guarantees and bond indemnities or to fund its other contingent liabilities, or if either Standard & Poor’s or Moody’s were to downgrade Xcel Energy Inc.’s credit rating below investment grade, Xcel Energy Inc. may be required to provide credit enhancements in the form of cash collateral, letters of credit or other security to satisfy part or potentially all of these exposures. If either Standard & Poor’s or Moody’s were to downgrade Xcel Energy Inc.’s debt securities below investment grade, it would increase Xcel Energy Inc.’s cost of capital and restrict its access to the capital markets. This could limit Xcel Energy Inc.’s ability to contribute equity or make loans to us, or may cause Xcel Energy Inc. to seek additional or accelerated funding from us in the form of dividends. If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs. As of Dec. 31, 2017, Xcel Energy Inc. and its utility subsidiaries had approximately $14.5 billion of long-term debt and $1.3 billion of short-term debt and current maturities. Xcel Energy Inc. provides various guarantees and bond indemnities supporting some of its subsidiaries by guaranteeing the payment or performance by these subsidiaries for specified agreements or transactions. Xcel Energy also has other contingent liabilities resulting from various tax disputes and other matters. Xcel Energy Inc.’s exposure under the guarantees is based upon the net liability of the relevant subsidiary under the specified agreements or transactions. The majority of Xcel Energy Inc.’s guarantees limit its exposure to a maximum amount that is stated in the guarantees. As of Dec. 31, 2017, Xcel Energy had guarantees outstanding with a maximum stated amount of approximately $19 million and immaterial exposure. Xcel Energy also had additional guarantees of $53 million at Dec. 31, 2017 for performance and payment of surety bonds for the benefit of itself and its subsidiaries, with total exposure that cannot be estimated at this time. If Xcel Energy Inc. were to become obligated to make payments under these guarantees and bond indemnities or become obligated to fund other contingent liabilities, it could limit Xcel Energy Inc.’s ability to contribute equity or make loans to us, or may cause Xcel Energy Inc. to seek additional or accelerated funding from us in the form of dividends. If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs. 20 Table of Contents We are a wholly owned subsidiary of Xcel Energy Inc. Xcel Energy Inc. can exercise substantial control over our dividend policy and business and operations and may exercise that control in a manner that may be perceived to be adverse to our interests. All of the members of our Board of Directors, as well as many of our executive officers, are officers of Xcel Energy Inc. Our Board makes determinations with respect to a number of significant corporate events, including the payment of our dividends. We have historically paid quarterly dividends to Xcel Energy Inc. In 2017, 2016 and 2015 we paid $334 million, $337 million and $331 million of dividends to Xcel Energy Inc., respectively. If Xcel Energy Inc.’s cash requirements increase, our Board of Directors could decide to increase the dividends we pay to Xcel Energy Inc. to help support Xcel Energy Inc.’s cash needs. This could adversely affect our liquidity. The most restrictive dividend limitation for PSCo is imposed by its credit facility, which limits the debt-to-total capitalization ratio. See Item 5 for further discussion on dividend limitations. Public Policy Risks We may be subject to legislative and regulatory responses to climate change, with which compliance could be difficult and costly. Increased public awareness and concern regarding climate change may result in more state, regional and/or federal requirements to reduce or mitigate the effects of GHGs. Legislative and regulatory responses related to climate change and new interpretations of existing laws through climate change litigation create financial risk as our electric generating facilities may be subject to additional regulation at either the state or federal level in the future. Such regulations could impose substantial costs on our system. International agreements could have an impact to the extent they lead to future federal or state regulations. In 2015, the 21st Conference of the Parties to the United Nations Framework Convention on Climate Change reached consensus among 190 nations on an agreement (the Paris Agreement) that establishes a framework for GHG mitigation actions by all countries (“nationally determined contributions”), with a goal of holding the increase in global average temperature to below 2o Celsius above pre-industrial levels and an aspiration to limit the increase to 1.5o Celsius. If implemented, the Paris Agreement could result in future additional GHG reductions in the United States. On June 21, 2017, President Trump announced that the U.S. would withdraw from the Paris Agreement. Such a withdrawal, under terms of the Agreement, becomes effective in four years. Many state and local government entities, however, have indicated that they intend to pursue GHG mitigation with a goal of achieving the GHG reductions in the United States anticipated by the Paris Agreement. We have been, and in the future may be, subject to climate change lawsuits. An adverse outcome in any of these cases could require substantial capital expenditures and could possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant. Such payments or expenditures could affect results of operations, cash flows and financial condition if such costs are not recovered through regulated rates. Some states and localities have indicated a desire to continue to pursue climate policies even in the absence of federal mandates. All of the steps that PSCo has taken to date to reduce GHG emissions, including energy efficiency measures, adding renewable generation or retiring or converting coal plants to natural gas, occurred under state-endorsed resource plans, renewable energy standards and other state policies. While those actions likely would have put PSCo in a good position to meet federal standards under the CPP or the Paris Agreement, repeal of these policies would not impact those state-endorsed actions and plans. Whether under state or federal programs, an important factor is our ability to recover the costs incurred to comply with any regulatory requirements in a timely manner. If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material effect on our results of operations. Increased risks of regulatory penalties could negatively impact our business. The Energy Act increased civil penalty authority for violation of FERC statutes, rules and orders. The FERC can now impose penalties of up to $1.2 million per violation per day, particularly as it relates to energy trading activities for both electricity and natural gas. Under statute, the FERC can adjust penalties for inflation. In addition, NERC electric reliability standards and critical infrastructure protection requirements are mandatory and subject to potential financial penalties by regional entities, the NERC or the FERC for violations. Additionally, the PHMSA, the Occupational Safety and Health Administration and other federal agencies also have penalty authority. In the event of serious incidents, these agencies have become more active in pursuing penalties. Some states have the authority to impose substantial penalties in the event of non-compliance. If a serious reliability or safety incident did occur, it could have a material effect on our operations or financial results. 21 Table of Contents Macroeconomic Risks Economic conditions impact our business. Our operations are affected by local, national and worldwide economic conditions. Growth in our customer base is correlated with economic conditions. While the number of customers is growing, sales growth is relatively modest due to an increased focus on energy efficiency including federal standards for appliance and lighting efficiency and distributed generation, primarily solar PV. Instability in the financial markets also may affect the cost of capital and our ability to raise capital, which is discussed in the capital market risk factor section above. Economic conditions may be impacted by insufficient financial sector liquidity leading to potential increased unemployment, which may impact customers’ ability to pay timely, increase customer bankruptcies, and may lead to increased bad debt. Further, worldwide economic activity has an impact on the demand for basic commodities needed for utility infrastructure, such as steel, copper, aluminum, etc., which may impact our ability to acquire sufficient supplies. We operate in a capital intensive industry, and federal policy on trade could significantly impact the costs of the materials we use. We may be at risk for higher than anticipated inflation both with respect to our own workforce, as well as our materials and labor that we contract for with others. There may be delays before these higher costs can be recovered in rates. Our operations could be impacted by war, acts of terrorism, threats of terrorism or disruptions in normal operating conditions due to localized or regional events. Our generation plants, fuel storage facilities, transmission and distribution facilities and information and control systems may be targets of terrorist activities. Any such disruption could impact operations or result in a decrease in revenues and additional costs to repair and insure our assets. These disruptions could have a material impact on our financial condition and results of operations. The potential for terrorism has subjected our operations to increased risks and could have a material effect on our business. We have already incurred increased costs for security and capital expenditures in response to these risks. In addition, we may experience additional capital and operating costs to implement security for our plants, such as additional physical plant security and additional security personnel. We have also already incurred increased costs for compliance with NERC reliability standards associated with critical infrastructure protection. In addition, we may experience additional capital and operating costs to comply with the NERC critical infrastructure protection standards as they are implemented and clarified. The insurance industry has also been affected by these events and the availability of insurance may decrease. In addition, the insurance we are able to obtain may have higher deductibles, higher premiums and more restrictive policy terms. A disruption of the regional electric transmission grid, interstate natural gas pipeline infrastructure or other fuel sources, could negatively impact our business, as well as our brand and reputation. Because our generation, the transmission systems and local natural gas distribution companies are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by the actions of a neighboring utility or an event (such as severe storm, severe temperature extremes, wildfires, solar storms, generator or transmission facility outage, breakdown or failure of equipment, pipeline rupture, railroad disruption, operator error, sudden and significant increase or decrease in wind generation or any disruption of work force such as may be caused by flu or other epidemic) within our operating systems or on a neighboring system. Any such disruption could result in a significant decrease in revenues and significant additional costs to repair assets, which could have a material impact on our financial condition and results. The degree to which we are able to maintain day-to-day operations in response to unforeseen events will in part determine the financial impact of certain events on our financial condition and results. It is difficult to predict the magnitude of such events and associated impacts. A cyber incident or cyber security breach could have a material effect on our business. We operate in an industry that requires the continued operation of sophisticated information technology and control systems and network infrastructure. In addition, we use our systems and infrastructure to create, collect, use, disclose, store, dispose of and otherwise process sensitive information, including company data, customer energy usage data, and personal information regarding customers, employees and their dependents, contractors and other individuals. 22 Table of Contents Our generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets, as well as the information processed in our systems (such as information about our customers, employees, operations, infrastructure and assets) could be affected by cyber security incidents, including those caused by human error. Our industry has begun to see an increased volume and sophistication of cyber security incidents from international activist organizations, Nation States and individuals. Cyber security incidents could harm our businesses by limiting our generating, transmitting and distributing capabilities, delaying our development and construction of new facilities or capital improvement projects to existing facilities, disrupting our customer operations or exposing us to liability. Our generation, transmission systems and natural gas pipelines are part of an interconnected system. Therefore, a disruption caused by the impact of a cyber security incident of the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources of our third party service providers’ operations, could also negatively impact our business. Our supply chain for procurement of digital equipment may expose software or hardware to these risks and could result in a breach or significant costs of remediation. In addition, such an event would likely receive regulatory scrutiny at both the federal and state level. We are unable to quantify the potential impact of cyber security threats or subsequent related actions. These potential cyber security incidents and corresponding regulatory action could result in a material decrease in revenues and may cause significant additional costs (e.g., penalties, third party claims, repairs, insurance or compliance) and potentially disrupt our supply and markets for natural gas, oil and other fuels. We maintain security measures designed to protect our information technology and control systems, network infrastructure and other assets. However, these assets and the information they process may be vulnerable to cyber security incidents, including the resulting disability, or failures of assets or unauthorized access to assets or information. If our technology systems were to fail or be breached, or those of our third-party service providers, we may be unable to fulfill critical business functions, including effectively maintaining certain internal controls over financial reporting. We are unable to quantify the potential impact of cyber security incidents on our business, our brand, and our reputation. The cyber security threat is dynamic and evolves continually, and our efforts to prioritize network monitoring may not be effective given the constant changes to threat vulnerability. Rising energy prices could negatively impact our business. Although commodity prices are currently relatively low, if fuel costs increase, customer demand could decline and bad debt expense may rise, which could have a material impact on our results of operations. While we have fuel clause recovery mechanisms, higher fuel costs could significantly impact our results of operations if costs are not recovered. Delays in the timing of the collection of fuel cost recoveries as compared with expenditures for fuel purchases could have an impact on our cash flows. Low fuel costs could have a positive impact on sales, though low oil and natural gas prices could negatively impact oil and gas production activities and subsequently our sales volumes and revenue. We are unable to predict future prices or the ultimate impact of such prices on our results of operations or cash flows. Our operating results may fluctuate on a seasonal and quarterly basis and can be adversely affected by milder weather. Our electric and natural gas utility businesses are seasonal, and weather patterns can have a material impact on our operating performance. Demand for electricity is often greater in the summer and winter months associated with cooling and heating. Because natural gas is heavily used for residential and commercial heating, the demand depends heavily upon weather patterns throughout our service territory, and a significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. Unusually mild winters and summers could have an adverse effect on our financial condition, results of operations, or cash flows. Our operations use third party contractors in addition to employees to perform periodic and on-going work. We rely on third party contractors with specific qualifications to perform work both for ongoing operations and maintenance and for capital construction. We have contractual arrangements with these contractors which typically include performance standards, progress payments, insurance requirements and security for performance. Cyber security breaches seen in the news have at times exploited third party equipment or software in order to gain access. Poor vendor performance could impact on going operations, restoration operations, our reputation and could introduce financial risk or risks of fines. Item 1B — Unresolved Staff Comments None. 23 Table of Contents Item 2 — Properties Virtually all of the utility plant property of PSCo is subject to the lien of its first mortgage bond indenture. Electric Utility Generating Stations: Station, Location and Unit Steam: Comanche-Pueblo, Colo. Unit 1 Unit 2 Unit 3 Craig-Craig, Colo., 2 Units Hayden-Hayden, Colo., 2 Units Pawnee-Brush, Colo., 1 Unit Valmont-Boulder, Colo., 1 Unit Combustion Turbine: Blue Spruce-Aurora, Colo., 2 Units Cherokee-Denver, Colo., 1 Unit Cherokee-Denver, Colo., 3 Units Fort St. Vrain-Platteville, Colo., 6 Units Rocky Mountain-Keenesburg, Colo., 3 Units Various locations, 6 Units Hydro: Cabin Creek-Georgetown, Colo. Pumped Storage, 2 Units Various locations, 9 Units (a) (b) (c) (d) (e) Summer 2017 Net Dependable Capability (MW) Fuel Installed Coal Coal Coal Coal Coal Coal Coal 1973 1975 2010 1979-1980 1965-1976 1981 1964 325 335 500 83 233 505 — Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas 2003 1968 2015 1972-2009 2004 Various 264 310 576 968 580 171 Hydro Hydro 1967 Various Total 210 26 5,086 Based on PSCo’s ownership interest of 67 percent of Unit 3. Based on PSCo’s ownership interest of 10 percent. Craig Unit 1 is expected to be early retired in approximately 2025. Based on PSCo’s ownership interest of 76 percent of Unit 1 and 37 percent of Unit 2. Valmont Unit 5 was retired in the third quarter of 2017. Cherokee Unit 4 was fuel switched from coal to natural gas in the third quarter of 2017. Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2017: Conductor Miles 345 KV 230 KV 138 KV 115 KV Less than 115 KV 2,630 12,911 92 4,969 76,998 PSCo had 230 electric utility transmission and distribution substations at Dec. 31, 2017. Natural gas utility mains at Dec. 31, 2017: Miles Transmission Distribution 2,315 22,540 24 (a) (b) (c) (d) (e) Table of Contents Item 3 — Legal Proceedings PSCo is involved in various litigation matters that are being defended and handled in the ordinary course of business. The assessment 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 See Note 12 to the consolidated financial statements for further discussion of legal claims and environmental proceedings. See Item 1 and Note 11 to the consolidated financial statements for a discussion of proceedings involving utility rates and other regulatory matters. Item 4 — Mine Safety Disclosures None. PART II Item 5 — Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities PSCo is a wholly owned subsidiary of Xcel Energy Inc. and there is no market for its common equity securities. PSCo’s dividends are subject to the FERC’s jurisdiction under the Federal Power Act, which prohibits the payment of dividends out of capital accounts; payment of dividends is allowed out of retained earnings only. See Note 4 to the financial statements for further discussion of PSCo’s dividend policy. The dividends declared during 2017 and 2016 were as follows: (Thousands of Dollars) 2017 First quarter Second quarter Third quarter Fourth quarter $ 87,104 83,978 88,589 76,195 2016 $ 83,914 86,509 82,785 74,208 Item 6 — Selected Financial Data This is omitted per conditions set forth in general instructions I (1) (a) and (b) of Form 10-K for wholly owned subsidiaries (reduced disclosure format). 25 Table of Contents Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations Discussion of financial condition and liquidity for PSCo is omitted per conditions set forth in general instructions I (1) (a) and (b) of Form 10-K for wholly owned subsidiaries. It is replaced with management’s narrative analysis of the results of operations set forth in general instructions I (2) (a) of Form 10-K for wholly owned subsidiaries (reduced disclosure format). Financial Review The following discussion and analysis by management focuses on those factors that had a material effect on PSCo’s financial condition, 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 consolidated financial statements and related notes to the consolidated financial statements. Forward-Looking Statements Except for the historical statements contained in this report, the matters discussed herein are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements, including the TCJA’s impact to PSCo and its customers, as well as assumptions and other statements identified in this document by the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” “will,” “would” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we expressly disclaim any obligation to update any forward-looking information. The following factors, in addition to those discussed elsewhere in this Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2017 (including risk factors listed from time to time by PSCo in reports filed with the SEC, including “Risk Factors” in Item 1A of this Annual Report on Form 10-K and Exhibit 99.01 hereto), could cause actual results to differ materially from management expectations as suggested by such forward-looking information: general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability 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. Results of Operations PSCo’s net income was approximately $494 million for 2017, compared with approximately $463 million for 2016. The increase in earnings, driven by higher electric and natural gas margins, AFUDC primarily related to the Rush Creek wind project and a lower ETR, was partially offset by higher depreciation expense, interest charges and the impact of unfavorable weather. Electric Revenues and Margin Electric revenues and fuel and purchased power expenses are impacted by fluctuations in the price of natural gas and coal used in the generation of electricity. However, these price fluctuations have minimal impact on electric margin due to fuel recovery mechanisms that recover fuel expenses. The following table details the electric revenues and margin: (Millions of Dollars) 2017 Electric revenues Electric fuel and purchased power Electric margin $ $ 26 3,004 $ (1,127) 1,877 $ 2016 3,049 (1,196) 1,853 Table of Contents The following tables summarize the components of the changes in electric revenues and electric margin for the year ended Dec. 31: Electric Revenues (Millions of Dollars) 2017 vs. 2016 Fuel and purchased power cost recovery DSM program revenues (offset by expenses) Non-fuel riders Other, net Total decrease in electric revenues $ (58) 6 5 2 (45) $ Electric Margin (Millions of Dollars) 2017 vs. 2016 DSM program revenues (offset by expenses) Non-fuel riders Earnings test Fuel handling and procurement $ Trading Other, net Total increase in electric margin 6 5 3 3 3 4 24 $ Natural Gas Revenues and Margin Total natural gas expense varies with changing sales and the cost of natural gas. However, fluctuations in the cost of natural gas has minimal impact on natural gas margin due to natural gas cost recovery mechanisms. The following table details natural gas revenues and margin: (Millions of Dollars) 2017 Natural gas revenues Cost of natural gas sold and transported Natural gas margin $ $ 2016 995 $ (459) 536 $ 958 (425) 533 The following tables summarize the components of the changes in natural gas revenues and natural gas margin for the year ended Dec. 31: Natural Gas Revenues (Millions of Dollars) 2017 vs. 2016 Purchased natural gas adjustment clause recovery Infrastructure and integrity riders Estimated impact of weather Retail rate decrease Total increase in natural gas revenues $ $ 32 13 (4) (4) 37 Natural Gas Margin (Millions of Dollars) 2017 vs. 2016 Infrastructure and integrity riders Estimated impact of weather Retail rate decrease Other, net Total increase in natural gas margin $ $ 27 13 (4) (4) (2) 3 Table of Contents Non-Fuel Operating Expenses and Other Items DSM Program Expenses — DSM program expenses increased $7 million, or 5.8 percent, for 2017 compared with 2016. The increase was due to higher recovery rates. DSM expenses are generally recovered concurrently through riders and base rates. Timing of recovery may not correspond to the period in which costs were incurred. Depreciation and Amortization — Depreciation and amortization expense increased $28 million, or 6.3 percent, for 2017 compared with 2016. The increase was primarily attributable to capital investments as well as a new enterprise resource planning system. AFUDC, Equity and Debt — AFUDC increased by $16 million for 2017 compared with 2016. The increase was primarily due to higher CWIP, particularly the Rush Creek wind project. Interest Charges — Interest charges increased by $9 million, or 5.0 percent, for 2017 compared with 2016. The increase is primarily due to higher long-term debt levels to fund capital investments, partially offset by refinancings at lower interest rates. Income Taxes — Income tax expense decreased $22 million for 2017 compared with 2016. The decrease in income tax expense was primarily due to the estimated one-time, non-cash, income tax benefit recognized in the fourth quarter related to the TCJA (see Note 7) and increased permanent plant-related adjustments. The ETR was 33.8 percent for 2017 compared with 37.1 percent for 2016. The lower ETR in 2017 was primarily due to the adjustments referenced above. Item 7A — Quantitative and Qualitative Disclosures About Market Risk Derivatives, Risk Management and Market Risk PSCo is exposed to a variety of market risks in the normal course of business. Market risk is the potential loss that may occur as a result of adverse changes in the market or fair value of a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk. See Note 10 to the consolidated financial statements for further discussion of market risks associated with derivatives. PSCo is exposed to the impact of adverse changes in price for energy and energy-related products, which is partially mitigated by the use of commodity derivatives. In addition to ongoing monitoring and maintaining credit policies intended to minimize overall credit risk, when necessary, management takes steps to mitigate changes in credit and concentration risks associated with its derivatives and other contracts, including parental guarantees and requests of collateral. While PSCo expects that the counterparties will perform under the contracts underlying its derivatives, the contracts expose PSCo to some credit and nonperformance risk. Though no material non-performance risk currently exists with the counterparties to PSCo’s commodity derivative contracts, distress in the financial markets may in the future impact that risk to the extent it impacts those counterparties. Distress in the financial markets may also impact the fair value of the securities in the master pension trust, as well as PSCo’s ability to earn a return on shortterm investments of excess cash. Commodity Price Risk — PSCo is exposed to commodity price risk in its electric and natural gas operations. Commodity price risk is managed by entering into long- and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products and for various fuels used in generation and distribution activities. Commodity price risk is also managed through the use of financial derivative instruments. PSCo’s risk management policy allows it to manage commodity price risk within each rate-regulated operation per commission approved hedge plans. Wholesale and Commodity Trading Risk — PSCo conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. PSCo’s risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee, which is made up of management personnel not directly involved in the activities governed by the policy. 28 Table of Contents At Dec. 31, 2017, the fair values by source for net commodity trading contract assets were as follows: Futures / Forwards (Thousands of Dollars) Maturity Less Than 1 Year Source of Fair Value PSCo 1 $ 291 Maturity 1 to 3 Years $ 179 Maturity 4 to 5 Years $ — Maturity Greater Than 5 Years Total Futures/ Forwards Fair Value $ $ — 470 1 — Prices actively quoted or based on actively quoted prices. Changes in the fair value of commodity trading contracts before the impacts of margin-sharing mechanisms for the years ended Dec. 31 were as follows: (Thousands of Dollars) 2017 Fair value of commodity trading net contract assets outstanding at Jan. 1 Contracts realized or settled during the period Commodity trading contract additions and changes during the period Fair value of commodity trading net contract assets outstanding at Dec. 31 $ $ 2016 (188) $ (775) 1,433 470 $ 112 (654) 354 (188) At Dec. 31, 2017, a 10 percent increase in market prices for commodity trading contracts would increase pretax income by approximately $0.6 million, whereas a 10 percent decrease would decrease pretax income by approximately $0.6 million. At Dec. 31, 2016, a 10 percent increase in market prices for commodity trading contracts would decrease pretax income by approximately $0.9 million, whereas a 10 percent decrease would increase pretax income by approximately $0.9 million. PSCo’s wholesale and commodity trading operations measure the outstanding risk exposure to price changes on transactions, contracts and obligations that have been entered into, but not closed, including transactions that are not recorded at fair value, using an industry standard methodology known as Value at Risk (VaR). VaR expresses the potential change in fair value on the outstanding transactions, contracts and obligations over a particular period of time under normal market conditions. The VaRs for the NSPMinnesota and PSCo commodity trading operations, calculated on a consolidated basis using a Monte Carlo simulation with a 95 percent confidence level and a one-day holding period, were as follows: (Millions of Dollars) 2017 2016 Year Ended Dec. 31 $ 0.18 0.09 VaR Limit $ 3.00 3.00 Average $ 0.21 0.16 High $ 0.66 0.38 Low $ 0.04 0.05 Interest Rate Risk — PSCo is subject to the risk of fluctuating interest rates in the normal course of business. PSCo’s risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives such as swaps, caps, collars and put or call options. At Dec. 31, 2017, a 100-basis-point change in the benchmark rate on PSCo’s variable rate debt would have no impact on annual pretax interest expense, and at Dec. 31, 2016 a 100-basis-point change in the benchmark rate on PSCo’s variable rate debt would impact annual pretax interest expense by approximately $1.3 million. See Note 10 to the consolidated financial statements for a discussion of PSCo’s interest rate derivatives. 29 Table of Contents Credit Risk — PSCo is also exposed to credit risk. Credit risk relates to the risk of loss resulting from counterparties’ nonperformance on their contractual obligations. PSCo maintains credit policies intended to minimize overall credit risk and actively monitors these policies to reflect changes and scope of operations. At Dec. 31, 2017, a 10 percent increase in commodity prices would have resulted in an increase in credit exposure of $17.4 million, while a decrease in prices of 10 percent would have resulted in an increase in credit exposure of $5.5 million. At Dec. 31, 2016, a 10 percent increase in commodity prices would have resulted in an increase in credit exposure of $14.3 million, while a decrease in prices of 10 percent would have resulted in a decrease in credit exposure of $2.2 million. PSCo conducts standard credit reviews for all counterparties. PSCo employs additional 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. Distress in the financial markets could increase PSCo’s credit risk. Fair Value Measurements PSCo follows accounting and disclosure guidance on fair value measurements that contains a hierarchy for inputs used in measuring fair value and requires disclosure of the observability of the inputs used in these measurements. See Note 10 to the consolidated financial statements for further discussion of the fair value hierarchy and the amounts of assets and liabilities measured at fair value that have been assigned to Level 3. Commodity Derivatives — PSCo continuously monitors the creditworthiness of the counterparties to its commodity derivative contracts and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Given this assessment and the typically short duration of these contracts, the impact of discounting commodity derivative assets for counterparty credit risk was not material to the fair value of commodity derivative assets at Dec. 31, 2017. PSCo also assesses the impact of its own credit risk when determining the fair value of commodity derivative liabilities. The impact of discounting commodity derivative liabilities for credit risk was immaterial to the fair value of commodity derivative liabilities at Dec. 31, 2017. Commodity derivative assets and liabilities assigned to Level 3 typically consist of forward and option contracts that are long-term in nature or relate to inactive delivery locations. Determining the fair value of certain commodity forwards and options can require management to make use of subjective price and volatility forecasts for inactive delivery locations and for contracts that extend to periods beyond those readily observable on active exchanges or quoted by brokers. When less observable forward price and volatility forecasts are significant to determining the value of commodity forwards and options, these instruments are assigned to Level 3. There were immaterial Level 3 commodity derivative assets or liabilities at Dec. 31, 2017. Item 8 — Financial Statements and Supplementary Data See Item 15-1 in Part IV for an index of financial statements included herein. See Note 17 to the consolidated financial statements for summarized quarterly financial data. 30 Table of Contents Management Report on Internal Controls Over Financial Reporting The management of PSCo is responsible for establishing and maintaining adequate internal control over financial reporting. PSCo’s internal control system was designed to provide reasonable assurance to Xcel Energy Inc.’s and PSCo’s management and board of directors regarding the preparation and fair presentation of published financial statements. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. In 2016, PSCo implemented the general ledger modules of a new enterprise resource planning system. PSCo initiated and implemented additional work management systems modules in 2017. PSCo does not believe this implementation had an adverse effect on its internal control over financial reporting. PSCo management assessed the effectiveness of PSCo’s internal control over financial reporting as of Dec. 31, 2017. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework (2013). Based on our assessment, we believe that, as of Dec. 31, 2017, PSCo’s internal control over financial reporting is effective at the reasonable assurance level based on those criteria. /s/ BEN FOWKE Ben Fowke Chairman and Chief Executive Officer Feb. 23, 2018 /s/ ROBERT C. FRENZEL Robert C. Frenzel Executive Vice President, Chief Financial Officer Feb. 23, 2018 31 Table of Contents REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Stockholder of Public Service Company of Colorado Opinion on the Financial Statements We have audited the accompanying consolidated balance sheets of Public Service Company of Colorado and subsidiaries (the “Company”) as of December 31, 2017 and 2016, the related consolidated statements of income, comprehensive income, cash flows, and common stockholder’s equity, for each of the three years in the period ended December 31, 2017, and the related notes and the schedule listed in the Index at Item 15 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America. Basis for Opinion These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. /s/ DELOITTE & TOUCHE LLP Minneapolis, Minnesota February 23, 2018 We have served as the Company's auditor since 2002. 32 Table of Contents PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (amounts in thousands) 2017 Operating revenues Electric Natural gas Steam and other Total operating revenues $ Operating expenses Electric fuel and purchased power Cost of natural gas sold and transported Cost of sales — steam and other Operating and maintenance expenses Demand side management program expenses Depreciation and amortization Taxes (other than income taxes) Total operating expenses 3,003,808 995,214 43,487 4,042,509 Year Ended Dec. 31 2016 $ 3,049,352 957,721 40,723 4,047,796 2015 $ 3,115,257 1,006,666 41,590 4,163,513 1,126,660 458,717 16,146 762,817 125,029 471,515 195,695 3,156,579 1,196,417 425,410 15,872 762,416 118,175 443,555 196,330 3,158,175 1,246,666 501,824 17,788 761,901 128,681 411,667 195,285 3,263,812 885,930 889,621 899,701 Other income, net Allowance for funds used during construction — equity 9,852 29,803 3,817 18,557 2,964 14,485 Interest charges and financing costs Interest charges — includes other financing costs of $6,281, $6,289 and $6,285, respectively Allowance for funds used during construction — debt Total interest charges and financing costs 190,694 (11,407) 179,287 181,631 (7,045) 174,586 177,430 (5,522) 171,908 Income before income taxes Income taxes Net income 746,298 252,179 494,119 737,409 273,918 463,491 745,242 278,440 466,802 Operating income $ See Notes to Consolidated Financial Statements 33 $ $ Table of Contents PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (amounts in thousands) Year Ended Dec. 31 2016 2017 Net income $ 494,119 $ 463,491 2015 $ 466,802 Other comprehensive income (loss) Pension and retiree medical benefits: Net pension and retiree medical losses arising during the period, net of tax of $(3), $(138), and $0 Amortization of losses included in net periodic benefit cost, net of tax of $4, $2, and $0, respectively Derivative instruments: Net fair value decrease, net of tax of $0, $0, and $(20), respectively Reclassification of losses to net income, net of tax of $610, $648, and $39, respectively Other comprehensive income Comprehensive income 34 (223) — 5 — 3 (220) — — — 1,005 1,005 $ See Notes to Consolidated Financial Statements (5) 1,005 495,124 — 1,056 1,056 $ 836 464,327 (30) 72 42 $ 42 466,844 Table of Contents PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (amounts in thousands) Year Ended Dec. 31 2016 2017 Operating activities Net income Adjustments to reconcile net income to cash provided by operating activities: Depreciation and amortization Demand side management program amortization Deferred income taxes Amortization of investment tax credits Allowance for equity funds used during construction Provision for bad debts Net realized and unrealized hedging and derivative transactions Other Changes in operating assets and liabilities: Accounts receivable Accrued unbilled revenues Inventories Prepayments and other Accounts payable Net regulatory assets and liabilities Other current liabilities Pension and other employee benefit obligations Change in other noncurrent assets Change in other noncurrent liabilities Net cash provided by operating activities $ Investing activities Utility capital/construction expenditures Proceeds from insurance recoveries Allowance for equity funds used during construction Investments in utility money pool arrangement Repayments from utility money pool arrangement Other Net cash used in investing activities Financing activities (Repayments of) proceeds from short-term borrowings, net Borrowings under utility money pool arrangement Repayments under utility money pool arrangement Proceeds from issuance of long-term debt Repayments of long-term debt Capital contributions from parent Dividends paid to parent Other Net cash provided by (used in) financing activities Net change in cash and cash equivalents Cash and cash equivalents at beginning of period Cash and cash equivalents at end of period $ Supplemental disclosure of cash flow information: Cash paid for interest (net of amounts capitalized) Cash (paid) received for income taxes, net Supplemental disclosure of non-cash investing transactions: Property, plant and equipment additions in accounts payable $ $ See Notes to Consolidated Financial Statements 35 494,119 $ 463,491 2015 $ 466,802 475,592 672 207,817 (2,803) (29,803) 14,303 2,364 6 446,179 2,138 222,002 (2,805) (18,557) 14,121 1,325 (388) 416,427 3,509 277,896 (2,807) (14,485) 13,052 2,414 2,500 (2,229) 1,277 (9,099) 188 20,410 (22,548) 71,776 (16,515) (785) (2,982) 1,201,760 (14,227) (20,866) 172 68,693 38,439 4,143 1,892 (10,627) (6,750) (22,120) 1,166,255 8,872 17,837 33,417 10,483 (40,982) 78,055 19,654 (23,449) 4,086 (35,334) 1,237,947 (1,475,697) — 29,803 (954,000) 934,000 (657) (1,466,551) (1,113,800) 608 18,557 (444,000) 444,000 (1,460) (1,096,095) (995,597) — 14,485 (196,300) 212,300 — (965,112) (129,000) 40,000 (40,000) 393,791 — 335,576 (333,879) (110) 266,378 115,000 524,500 (524,500) 244,507 (129,500) 38,755 (336,581) — (67,819) (368,000) 165,000 (165,000) 246,751 — 175,210 (330,846) — (276,885) 1,587 5,926 7,513 $ (174,978) $ (7,717) 183,858 $ $ (4,050) 7,635 3,585 (171,714) $ 22,827 (165,546) 13,822 2,341 3,585 5,926 68,870 $ 106,912 Table of Contents PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (amounts in thousands, except share and per share data) Dec. 31 2017 Assets Current assets Cash and cash equivalents Accounts receivable, net Accounts receivable from affiliates Investments in utility money pool arrangement Accrued unbilled revenues Inventories Regulatory assets Derivative instruments Prepayments and other Total current assets $ 2016 7,513 294,403 14,719 20,000 295,801 214,489 77,337 3,197 35,720 963,179 $ 5,926 304,900 9,421 — 297,078 202,220 103,783 10,934 34,559 968,821 Property, plant and equipment, net 14,025,751 12,849,799 Other assets Regulatory assets Derivative instruments Other Total other assets Total assets 950,258 1,009 27,429 978,696 15,967,626 958,429 3,398 25,637 987,464 14,806,084 $ Liabilities and Equity Current liabilities Current portion of long-term debt Short-term debt Accounts payable Accounts payable to affiliates Regulatory liabilities Taxes accrued Accrued interest Dividends payable to parent Derivative instruments Other Total current liabilities $ Deferred credits and other liabilities Deferred income taxes Deferred investment tax credits Regulatory liabilities Asset retirement obligations Derivative instruments Customer advances Pension and employee benefit obligations Other Total deferred credits and other liabilities Commitments and contingencies Capitalization Long-term debt Common stock — 100 shares authorized of $0.01 par value; 100 shares outstanding at Dec. 31, 2017 and 2016, respectively Additional paid in capital Retained earnings Accumulated other comprehensive loss Total common stockholder’s equity Total liabilities and equity 305,577 — 492,829 58,749 66,126 222,517 48,552 76,195 7,348 92,333 1,370,226 $ $ 1,644,476 27,858 1,933,488 347,769 3,468 162,614 287,783 58,923 4,466,379 2,889,129 30,661 512,933 289,563 7,828 162,742 285,774 62,201 4,240,831 4,302,698 4,210,936 — $ See Notes to Consolidated Financial Statements 36 5,270 129,000 376,186 98,797 101,110 171,862 48,619 74,208 6,788 73,022 1,084,862 4,032,826 1,822,229 (26,732) 5,828,323 15,967,626 $ — 3,633,216 1,659,239 (23,000) 5,269,455 14,806,084 Table of Contents PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY (amounts in thousands, except share and per share data) Common Stock Issued Shares Balance at Dec. 31, 2014 Net income Other comprehensive income Common dividends declared to parent Contribution of capital by parent Balance at Dec. 31, 2015 Net income Other comprehensive income Common dividends declared to parent Contribution of capital by parent Balance at Dec. 31, 2016 Net income Other comprehensive income Common dividends declared to parent Contribution of capital by parent Adoption of ASU No. 2018-02 Balance at Dec. 31, 2017 100 Par Value $ — Additional Paid In Capital $ 3,522,788 Retained Earnings $1,386,929 466,802 Accumulated Other Comprehensive Income (Loss) $ (23,878) $ Total Common Stockholder’s Equity 42 (330,567) 100 $ — 98,036 $ 3,620,824 $1,523,164 463,491 $ (23,836) $ 836 (327,416) 100 $ — 12,392 $ 3,633,216 $1,659,239 494,119 $ (23,000) $ 1,005 (335,866) 399,610 100 $ — $ 4,032,826 4,737 $1,822,229 See Notes to Consolidated Financial Statements 37 $ (4,737) (26,732) $ 4,885,839 466,802 42 (330,567) 98,036 5,120,152 463,491 836 (327,416) 12,392 5,269,455 494,119 1,005 (335,866) 399,610 — 5,828,323 Table of Contents PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CAPITALIZATION (amounts in thousands, except share and per share data) Dec. 31 Long-Term Debt First Mortgage Bonds, Series due: Aug. 1, 2018, 5.8% June 1, 2019, 5.125% Nov. 15, 2020, 3.2% Sept. 15, 2022, 2.25% March 15, 2023, 2.5% May 15, 2025, 2.9% Sept. 1, 2037, 6.25% Aug. 1, 2038, 6.5% Aug. 15, 2041, 4.75% Sept. 15, 2042, 3.6% March 15, 2043, 3.95% March 15, 2044, 4.3% June 15, 2046, 3.55% June 15, 2047, 3.8% Capital lease obligations, through 2060, 11.2% — 14.3% Unamortized discount Unamortized debt expense Total Less current maturities Total long-term debt $ $ Common Stockholder’s Equity Common Stock — 100 shares authorized of $0.01 par value; 100 shares outstanding at Dec. 31, 2017 and 2016, respectively. Additional paid-in capital Retained earnings Accumulated other comprehensive loss Total common stockholder’s equity See Notes to Consolidated Financial Statements 38 $ $ 2017 2016 300,000 $ 400,000 400,000 300,000 250,000 250,000 350,000 300,000 250,000 500,000 250,000 300,000 250,000 400,000 150,658 (13,472) (28,911) 4,608,275 305,577 4,302,698 $ 300,000 400,000 400,000 300,000 250,000 250,000 350,000 300,000 250,000 500,000 250,000 300,000 250,000 — 155,927 (12,922) (26,799) 4,216,206 5,270 4,210,936 — $ 4,032,826 1,822,229 (26,732) 5,828,323 $ — 3,633,216 1,659,239 (23,000) 5,269,455 Table of Contents NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. Summary of Significant Accounting Policies Business and System of Accounts — PSCo is engaged in the regulated generation, purchase, transmission, distribution and sale of electricity and in the regulated purchase, transportation, distribution and sale of natural gas. PSCo’s consolidated financial statements and disclosures are presented in accordance with GAAP. All of PSCo’s underlying accounting records also conform to the FERC uniform system of accounts or to systems required by various state regulatory commissions, which are the same in all material respects. Principles of Consolidation — PSCo’s consolidated financial statements include its wholly-owned subsidiaries. In the consolidation process, all intercompany transactions and balances are eliminated. PSCo has investments in several plants and transmission facilities jointly owned with nonaffiliated utilities. PSCo’s proportionate share of jointly owned facilities is recorded as property, plant and equipment on the consolidated balance sheets, and PSCo’s proportionate share of the operating costs associated with these facilities is included in its consolidated statements of income. See Note 6 for further discussion of jointly owned generation, transmission and gas facilities, and related ownership percentages. PSCo evaluates its arrangements and contracts with other entities, including investments, PPAs and fuel contracts, to determine if the other party is a variable interest entity, if PSCo has a variable interest and if PSCo is the primary beneficiary. PSCo follows accounting guidance for variable interest entities which requires consideration of the activities that most significantly impact an entity’s financial performance and power to direct those activities, when determining whether PSCo is a variable interest entity’s primary beneficiary. See Note 12 for further discussion of variable interest entities. Use of Estimates — In recording transactions and balances resulting from business operations, PSCo uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives or potential disallowances, AROs, certain regulatory assets and liabilities, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs. The recorded estimates are revised when better information becomes available or when actual amounts can be determined. Those revisions can affect operating results. Regulatory Accounting — PSCo accounts for certain income and expense items in accordance with accounting guidance for regulated operations. Under this guidance: • • Certain costs, which would otherwise be charged to expense or OCI, are deferred as regulatory assets based on the expected ability to recover the costs in future rates; and Certain credits, which would otherwise be reflected as income or OCI, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred. Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process. If restructuring or other changes in the regulatory environment occur, PSCo may no longer be eligible to apply this accounting treatment and may be required to eliminate regulatory assets and liabilities from its balance sheet. Such changes could have a material effect on PSCo’s financial condition, results of operations and cash flows. See Note 13 for further discussion of regulatory assets and liabilities. Revenue Recognition — Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meter, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is recognized. PSCo presents its revenues net of any excise or other fiduciary-type taxes or fees. 39 Table of Contents PSCo has various rate-adjustment mechanisms in place that provide for the recovery of natural gas, electric fuel and purchased energy costs. These cost-adjustment tariffs may increase or decrease the level of revenue collected from customers and are revised periodically for differences between the total amount collected under the clauses and the costs incurred. When applicable, under governing regulatory commission rate orders, fuel cost over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as regulatory assets. Certain rate rider mechanisms qualify as alternative revenue programs under GAAP. These mechanisms arise from costs imposed upon the utility by action of a regulator or legislative body related to an environmental, public safety or other mandate. When certain criteria are met, revenue is recognized equal to the revenue requirement, including return on rate base items, for the qualified mechanisms. The mechanisms are revised periodically for differences between the total amount collected under the riders and the revenue recognized, which may increase or decrease the level of revenue collected from customers. Conservation Programs — PSCo has implemented programs to assist its retail customers in conserving energy and reducing peak demand on the electric and natural gas systems. These programs include approximately 20 unique DSM products, pilots and services for C&I customers, as well as approximately 23 DSM products, pilots and services for residential and low-income customers. Overall, the DSM portfolio provides rebates and/or incentives for nearly 1,000 unique measures. The costs incurred for DSM programs are deferred if it is probable future revenue will be provided to permit recovery of the incurred cost. Recorded revenues for incentive programs designed for recovery of DSM program costs and/or conservation performance incentives are limited to amounts expected to be collected within 24 months from the annual period in which they are earned. PSCo’s DSM program costs are recovered through a combination of base rate revenue and rider mechanisms. The revenue billed to customers recovers incurred costs for conservation programs and also incentive amounts that are designed to encourage PSCo’s achievement of energy conservation goals. PSCo recognizes regulatory assets to reflect the amount of costs or earned incentives that have not yet been collected from customers. Property, Plant and Equipment and Depreciation — Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and AFUDC. The cost of plant retired is charged to accumulated depreciation and amortization. Amounts recovered in rates for future removal costs are recorded as regulatory liabilities. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance costs are charged to expense as incurred. Maintenance and replacement of items determined to be less than a unit of property are charged to operating expenses as incurred. Planned major maintenance activities are charged to operating expense unless the cost represents the acquisition of an additional unit of property or the replacement of an existing unit of property. Property, plant and equipment also includes costs associated with property held for future use. The depreciable lives of certain plant assets are reviewed annually, and revised, if appropriate. Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable. A loss is recognized in the current period if it becomes probable that part of a cost of a plant under construction or recently completed plant will be disallowed for recovery from customers and a reasonable estimate of the disallowance can be made. For investments in property, plant and equipment that are abandoned and not expected to go into service, incurred costs and related deferred tax amounts are compared to the discounted estimated future rate recovery, and a loss is recognized, if necessary. PSCo records depreciation expense related to its plant using the straight-line method over the plant’s useful life. Actuarial life studies are performed and submitted to the state and federal commissions for review. Upon acceptance by the various commissions, the resulting lives and net salvage rates are used to calculate depreciation. Depreciation expense, expressed as a percentage of average depreciable property, was approximately 2.7, 2.6 and 2.7 percent for the years ended Dec. 31, 2017, 2016 and 2015, respectively. Leases — PSCo evaluates a variety of contracts for lease classification at inception, including PPAs and rental arrangements for office space, vehicles, and equipment. Contracts determined to contain a lease because of per unit pricing that is other than fixed or market price, terms regarding the use of a particular asset, and other factors are evaluated further to determine if the arrangement is a capital lease. See Note 12 for further discussion of leases. 40 Table of Contents AFUDC — AFUDC represents the cost of capital used to finance utility construction activity. AFUDC is computed by applying a composite financing rate to qualified CWIP. The amount of AFUDC capitalized as a utility construction cost is credited to other nonoperating income (for equity capital) and interest charges (for debt capital). AFUDC amounts capitalized are included in PSCo’s rate base for establishing utility service rates. Generally, AFUDC costs are recovered from customers as the related property is depreciated. However, in some cases, including certain generation and transmission projects, the CPUC has approved a more current recovery of the cost of capital associated with large capital projects, resulting in a lower recognition of AFUDC. In other cases, the CPUC has allowed an AFUDC calculation greater than the FERC-defined AFUDC rate, resulting in higher recognition of AFUDC. AROs — PSCo accounts for AROs under accounting guidance that requires a liability for the fair value of an ARO to be recognized in the period in which it is incurred if it can be reasonably estimated, with the offsetting associated asset retirement costs capitalized as a long-lived asset. The liability is generally increased over time by applying the effective interest method of accretion, and the capitalized costs are depreciated over the useful life of the long-lived asset. Changes resulting from revisions to the timing or amount of expected asset retirement cash flows are recognized as an increase or a decrease in the ARO. PSCo also recovers through rates certain future plant removal costs in addition to AROs. The accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability. See Note 12 for further discussion of AROs. Income Taxes — PSCo accounts for income taxes using the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. PSCo defers income taxes for all temporary differences between pretax financial and taxable income, and between the book and tax bases of assets and liabilities. PSCo uses the tax rates that are scheduled to be in effect when the temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the period that includes the enactment date. The effects of PSCo’s tax rate changes are generally subject to a normalization method of accounting. Therefore, the revaluation of most of its net deferred taxes upon a tax rate reduction results in the establishment of a net regulatory liability which will be refundable to utility customers over the remaining life of the related assets. A tax rate increase would result in the establishment of a similar regulatory asset. Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize it over the book depreciable lives of the related property. The requirement to defer and amortize tax credits only applies to federal ITCs related to public utility property. Utility rate regulation also has resulted in the recognition of certain regulatory assets and liabilities related to income taxes, which are summarized in Note 13. Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized. In making such a determination, all available evidence is considered, including scheduled reversals of deferred tax liabilities, projected future taxable income, tax planning strategies and recent financial operations. PSCo follows the applicable accounting guidance to measure and disclose uncertain tax positions that it has taken or expects to take in its income tax returns. PSCo recognizes a tax position in its consolidated financial statements when it is more likely than not that the position will be sustained upon examination based on the technical merits of the position. Recognition of changes in uncertain tax positions are reflected as a component of income tax. PSCo reports interest and penalties related to income taxes within the other income and interest charges sections in the consolidated statements of income. Xcel Energy Inc. and its subsidiaries, including PSCo, file consolidated federal income tax returns as well as combined or separate state income tax returns. Federal income taxes paid by Xcel Energy Inc. are allocated to Xcel Energy Inc.’s subsidiaries based on separate company computations of tax. A similar allocation is made for state income taxes paid by Xcel Energy Inc. in connection with combined state filings. Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries which are recorded directly in equity by the subsidiaries based on the relative positive tax liabilities of the subsidiaries. See Note 7 for further discussion of income taxes. 41 Table of Contents Types of and Accounting for Derivative Instruments — PSCo uses derivative instruments in connection with its interest rate, utility commodity price, vehicle fuel price and commodity trading activities, including forward contracts, futures, swaps and options. All derivative instruments not designated and qualifying for the normal purchases and normal sales exception, as defined by the accounting guidance for derivatives and hedging, are recorded on the consolidated balance sheets at fair value as derivative instruments. This includes certain instruments used to mitigate market risk for the utility operations and all instruments related to the commodity trading operations. The classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship. Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. Gains or losses on commodity trading transactions are recorded as a component of electric operating revenues; hedging transactions for vehicle fuel costs are recorded as a component of capital projects and O&M costs; and interest rate hedging transactions are recorded as a component of interest expense. PSCo is allowed to recover in electric or natural gas rates the costs of certain financial instruments purchased to reduce commodity cost volatility. For further information on derivatives entered to mitigate commodity price risk on behalf of electric and natural gas customer, see Note 10. Cash Flow Hedges — Certain qualifying hedging relationships are designated as a hedge of a forecasted transaction or future cash flow (cash flow hedge). Changes in the fair value of a derivative designated as a cash flow hedge, to the extent effective are included in OCI, or deferred as a regulatory asset or liability based on recovery mechanisms until earnings are affected by the hedged transaction. Normal Purchases and Normal Sales — PSCo enters into contracts for the purchase and sale of commodities for use in its business operations. Derivatives and hedging accounting guidance requires a company to evaluate these contracts to determine whether the contracts are derivatives. Certain contracts that meet the definition of a derivative may be exempted from derivative accounting if designated as normal purchases or normal sales. PSCo evaluates all of its contracts at inception to determine if they are derivatives and if they meet the normal purchases and normal sales designation requirements. None of the contracts entered into within the commodity trading operations qualify for a normal purchases and normal sales designation. See Note 10 for further discussion of PSCo’s risk management and derivative activities. Commodity Trading Operations — All applicable gains and losses related to commodity trading activities, whether or not settled physically, are shown on a net basis in electric operating revenues in the consolidated statements of income. Pursuant to the JOA approved by the FERC, some of the commodity trading margins from PSCo are apportioned to NSP-Minnesota and SPS. Commodity trading activities are not associated with energy produced from PSCo’s generation assets or energy and capacity purchased to serve native load. Commodity trading contracts are recorded at fair market value and commodity trading results include the impact of all margin-sharing mechanisms. See Note 10 for further discussion. Fair Value Measurements — PSCo presents cash equivalents, interest rate derivatives and commodity derivatives at estimated fair values in its consolidated financial statements. Cash equivalents are recorded at cost plus accrued interest; money market funds are measured using quoted NAVs. For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used as a primary input to establish fair value. For commodity derivatives, the most observable inputs available are generally used to determine the fair value of each contract. In the absence of a quoted price for an identical contract in an active market, PSCo may use quoted prices for similar contracts, or internally prepared valuation models to determine fair value. For the pension and postretirement plan assets published trading data and pricing models, generally using the most observable inputs available, are utilized to estimate fair value for each security. See Note 8 and 10 for further discussion. Cash and Cash Equivalents — PSCo considers investments in certain instruments, including commercial paper and money market funds, with a remaining maturity of three months or less at the time of purchase, to be cash equivalents. Accounts Receivable and Allowance for Bad Debts — Accounts receivable are stated at the actual billed amount net of an allowance for bad debts. PSCo establishes an allowance for uncollectible receivables based on a policy that reflects its expected exposure to the credit risk of customers. 42 Table of Contents Inventory — All inventory is recorded at average cost. RECs — RECs are marketable environmental instruments that represent proof that energy was generated from eligible renewable energy sources. RECs are awarded upon delivery of the associated energy and can be bought and sold. RECs are typically used as a form of measurement of compliance to RPS enacted by those states that are encouraging construction and consumption from renewable energy sources, but can also be sold separately from the energy produced. PSCo acquires RECs from the generation or purchase of renewable power. When RECs are purchased or acquired in the course of generation they are recorded as inventory at cost. The cost of RECs that are utilized for compliance purposes is recorded as electric fuel and purchased power expense. As a result of state regulatory orders, PSCo records that cost as a regulatory asset when the amount is recoverable in future rates. Sales of RECs that are purchased or acquired in the course of generation are recorded in electric utility operating revenues on a gross basis. The cost of these RECs, related transaction costs, and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense. Emission Allowances — Emission allowances, including the annual SO2 and NOx emission allowance entitlement received from the EPA, are recorded at cost plus associated broker commission fees. PSCo follows the inventory accounting model for all emission allowances. Sales of emission allowances are included in electric utility operating revenues and the operating activities section of the consolidated statements of cash flows. Environmental Costs — Environmental costs are recorded when it is probable PSCo is liable for remediation costs and the liability can be reasonably estimated. Costs are deferred as a regulatory asset if it is probable that the costs will be recovered from customers in future rates. Otherwise, the costs are expensed. If an environmental expense is related to facilities currently in use, such as emission-control equipment, the cost is capitalized and depreciated over the life of the plant. Estimated remediation costs, excluding inflationary increases, are recorded based on experience, an assessment of the current situation and the technology currently available for use in the remediation. The recorded costs are regularly adjusted as estimates are revised and remediation proceeds. If other participating PRPs exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for PSCo’s expected share of the cost. Any future costs of restoring sites where operation may extend indefinitely are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses, which may include final remediation costs. Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability. See Note 12 for further discussion of environmental costs. Benefit Plans and Other Postretirement Benefits — PSCo maintains pension and postretirement benefit plans for eligible employees. Recognizing the cost of providing benefits and measuring the projected benefit obligation of these plans under applicable accounting guidance requires management to make various assumptions and estimates. Based on regulatory recovery mechanisms, certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are recorded as regulatory assets and liabilities, rather than OCI. See Note 8 for further discussion of benefit plans and other postretirement benefits. 43 Table of Contents Guarantees — PSCo recognizes, upon issuance or modification of a guarantee, a liability for the fair market value of the obligation that has been assumed in issuing the guarantee. This liability includes consideration of specific triggering events and other conditions which may modify the ongoing obligation to perform under the guarantee. The obligation recognized is reduced over the term of the guarantee as PSCo is released from risk under the guarantee. Subsequent Events — Management has evaluated the impact of events occurring after Dec. 31, 2017 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation. 2. Accounting Pronouncements Recently Issued Revenue Recognition — In May 2014, the FASB issued Revenue from Contracts with Customers, Topic 606 (ASU No. 2014-09), which provides a new framework for the recognition of revenue. As the appropriate timing of recognition of revenue from contracts with customers in our regulated operations continues to generally be based on the delivery of electricity and natural gas, PSCo’s adoption will primarily result in increased disclosures regarding sources of revenues, including alternative revenue programs. The guidance is effective for interim and annual periods beginning after Dec. 15, 2017. PSCo is implementing the standard on a modified retrospective basis, which requires application to contracts with customers effective Jan. 1, 2018. Classification and Measurement of Financial Instruments — In January 2016, the FASB issued Recognition and Measurement of Financial Assets and Financial Liabilities, Subtopic 825-10 (ASU No. 2016-01), which eliminates the available-for-sale classification for marketable equity securities and also replaces the cost method of accounting for non-marketable equity securities with a model for recognizing impairments and observable price changes. Under the new standard, other than when the consolidation or equity method of accounting is utilized, changes in the fair value of equity securities are to be recognized in earnings. This guidance is effective for interim and annual reporting periods beginning after Dec. 15, 2017. The overall impacts of the Jan. 1, 2018 adoption will not be material. Leases — In February 2016, the FASB issued Leases, Topic 842 (ASU No. 2016-02), which, for lessees, requires balance sheet recognition of right-of-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 and proposed in Targeted Improvements, Topic 842 (Proposed ASU 2018-200). As such, agreements entered prior to Jan. 1, 2019 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, 2018 will generally qualify as leases under the new standard. 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. As a result of application of accounting principles for rate regulated entities, a similar amount of pension cost, including non-service components, will be recognized consistent with the historical ratemaking treatment and the impacts of adoption will be limited to changes in classification of non-service costs in the consolidated statement of income. This guidance is effective for interim and annual reporting periods beginning after Dec. 15, 2017. 44 Table of Contents Recently Adopted Accounting for the TCJA — In December 2017, the SEC staff issued Staff Accounting Bulletin No. 118 Income Tax Accounting Implications of the Tax Cuts and Jobs Act (SAB 118), to supplement the accounting requirements of ASC Topic 740 Income Taxes (ASC Topic 740) as it relates to assessing and recognizing the impacts of the TCJA in the period of enactment. SAB 118 allows an entity to recognize provisional amounts in its financial statements in circumstances in which the entity’s assessment is incomplete, but for which a reasonable estimate can be made. Provisional amounts recognized are subject to adjustment for up to one year from the enactment date. For further details, see Note 7 to the consolidated financial statements. Reporting Comprehensive Income — In February 2018, the FASB issued Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, Topic 220 (ASU No. 2018-02), which addresses the stranded amounts of accumulated OCI which may result from enactment of a new tax law. Though accumulated OCI is presented on a net-of-tax basis, ASC Topic 740 requires that the effects of new tax laws on items in accumulated OCI be recognized without a corresponding adjustment to accumulated OCI, and instead recorded to income tax expense. ASU No. 2018-02 permits stranded amounts of accumulated OCI specifically resulting from the TCJA to be removed from accumulated OCI and reclassified to retained earnings, if elected. PSCo adopted the guidance in the fourth quarter of 2017, and elected to recognize a $4.7 million increase to accumulated other comprehensive loss and retained earnings in the consolidated financial statements for the year ended Dec. 31, 2017, related to a revaluation of deferred income tax assets and liabilities for items in accumulated other comprehensive loss, at the TCJA federal tax rate. 3. Selected Balance Sheet Data (Thousands of Dollars) Dec. 31, 2017 Accounts receivable, net Accounts receivable Less allowance for bad debts $ $ (Thousands of Dollars) 314,009 $ (19,606) 294,403 $ Dec. 31, 2017 Inventories Materials and supplies Fuel Natural gas $ $ (Thousands of Dollars) 68,940 73,893 71,656 214,489 $ $ 324,512 (19,612) 304,900 Dec. 31, 2016 $ $ Dec. 31, 2017 Property, plant and equipment, net Electric plant Natural gas plant Common and other property Plant to be retired (a) Construction work in progress Total property, plant and equipment Less accumulated depreciation (a) Dec. 31, 2016 12,627,592 $ 4,102,075 1,022,333 10,949 1,014,338 18,777,287 (4,751,536) 14,025,751 $ 66,161 66,429 69,630 202,220 Dec. 31, 2016 12,304,436 3,710,772 919,955 31,839 484,340 17,451,342 (4,601,543) 12,849,799 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. 45 Table of Contents 4. Borrowings and Other Financing Instruments Short-Term Borrowings Money Pool — Xcel Energy Inc. and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings between the utility subsidiaries. Xcel Energy Inc. may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy Inc. PSCo had no money pool borrowings outstanding during the three months ended Dec. 31, 2017. Money pool borrowings for PSCo were as follows: Twelve Months Ended Dec. 31, 2017 (Amounts in Millions, Except Interest Rates) Borrowing limit Amount outstanding at period end Average amount outstanding Maximum amount outstanding Weighted average interest rate, computed on a daily basis Weighted average interest rate at period end $ Twelve Months Ended Dec. 31, 2016 250 $ — — 20 0.92% N/A Twelve Months Ended Dec. 31, 2015 250 $ — 21 141 0.73% N/A 250 — 1 34 0.41% N/A Commercial Paper — PSCo meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility. PSCo had no commercial paper borrowings outstanding during the three months ended Dec. 31, 2017. Commercial paper borrowings for PSCo were as follows: Twelve Months Ended Dec. 31, 2017 (Amounts in Millions, Except Interest Rates) Borrowing limit Amount outstanding at period end Average amount outstanding Maximum amount outstanding Weighted average interest rate, computed on a daily basis Weighted average interest rate at period end $ Twelve Months Ended Dec. 31, 2016 700 $ — 54 268 1.08% N/A Twelve Months Ended Dec. 31, 2015 700 $ 129 24 154 0.70% 0.95 700 14 95 449 0.51% 0.60 Letters of Credit — PSCo uses letters of credit, generally with terms of one-year, to provide financial guarantees for certain operating obligations. At both Dec. 31, 2017 and 2016, there were $3 million of letters of credit outstanding under the credit facility. The contract amounts of these letters of credit approximate their fair value and are subject to fees. Credit Facility — In order to use its commercial paper program to fulfill short-term funding needs, PSCo must have a revolving credit facility in place at least equal to the amount of its commercial paper borrowing limit and cannot issue commercial paper in an aggregate amount exceeding available capacity under this credit facility. The credit facility provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings. PSCo has the right to request an extension of the June 2021 termination date for two additional one-year periods. The extension requests are subject to majority bank group approval. 46 Table of Contents Other features of PSCo’s credit facility include: • • • • PSCo may increase its credit facility by up to $100 million. The credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65 percent. PSCo was in compliance as its debt-to-total capitalization ratio was 44 percent and 45 percent at Dec. 31, 2017 and 2016, respectively. If PSCo does not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender. The credit facility has a cross-default provision that provides PSCo will be in default on its borrowings under the facility if PSCo or any of its subsidiaries whose total assets exceed 15 percent of PSCo’s consolidated total assets, default on certain indebtedness in an aggregate principal amount exceeding $75 million. PSCo was in compliance with all financial covenants on its debt agreements as of Dec. 31, 2017 and 2016. At Dec. 31, 2017, PSCo had the following committed credit facility available (in millions): Credit Facility (a) $ (a) (b) 700 Drawn (b) $ Available 3 $ 697 This credit facility matures in June 2021. Includes 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 had no direct advances on the credit facility outstanding at Dec. 31, 2017 and 2016. Long-Term Borrowings Generally, all real and personal property of PSCo is subject to the liens of its first mortgage indenture. Debt premiums, discounts and expenses are amortized over the life of the related debt. The premiums, discounts and expenses associated with refinanced debt are deferred and amortized over the life of the related new issuance, in accordance with regulatory guidelines. In 2017, PSCo issued $400 million of 3.80 percent first mortgage bonds due June 15, 2047. In 2016, PSCo issued $250 million of 3.55 percent first mortgage bonds due June 15, 2046. During the next five years, PSCo has long-term debt maturities of $300 million, $400 million, $400 million and $300 million due in 2018, 2019, 2020 and 2022, respectively. Deferred Financing Costs — Deferred financing costs of approximately $29 million and $27 million, net of amortization, are presented as a deduction from the carrying amount of long-term debt at Dec. 31, 2017 and 2016, respectively. PSCo is amortizing these financing costs over the remaining maturity periods of the related debt. Dividend Restrictions — PSCo’s dividends are subject to the FERC’s jurisdiction, which prohibits the payment of dividends out of capital accounts; payment of dividends is allowed out of retained earnings only. 5. Preferred Stock PSCo has authorized the issuance of preferred stock. Preferred Shares Authorized 10,000,000 Preferred Shares Outstanding Par Value $ 0.01 None 47 Table of Contents 6. Joint Ownership of Generation, Transmission and Gas Facilities Following are the investments by PSCo in jointly owned generation, transmission and gas facilities and the related ownership percentages as of Dec. 31, 2017: Plant in Service (Thousands of Dollars) Electric Generation: Hayden Unit 1 Hayden Unit 2 Hayden Common Facilities Craig Units 1 and 2 Craig Common Facilities 1, 2 and 3 Comanche Unit 3 Comanche Common Facilities Electric Transmission: Transmission and other facilities, including substations Gas Transportation: Rifle, Colo. to Avon, Colo. Gas Transportation Compressor Total $ $ 150,441 148,694 39,321 80,650 38,902 889,630 24,421 Accumulated Depreciation $ 72,042 65,493 19,886 38,666 20,116 117,759 2,092 CWIP $ Ownership % 830 18 97 — — 476 2,809 176,873 67,637 638 21,532 8,417 1,578,881 7,579 616 411,886 — — 4,868 $ $ 76% 37 53 10 7 67 82 Various 60 50 PSCo has approximately 816 MW of jointly owned generating capacity. PSCo’s share of operating expenses and construction expenditures are included in the applicable utility accounts. Each of the respective owners is responsible for providing its own financing. 7. Income Taxes Federal Tax Reform — In December 2017, the TCJA was signed into law. While the legislation will require interpretations and regulations to be issued by the IRS, the key provisions impacting Xcel Energy (which includes PSCo), generally beginning in 2018, include: • • • • • • • • Corporate federal tax rate reduction from 35 percent to 21 percent; Normalization of resulting plant-related excess deferred taxes; Elimination of the corporate alternative minimum tax; Continued interest expense deductibility and discontinued bonus depreciation for regulated public utilities; Limitations on certain executive compensation deductions; Limitations on certain deductions for NOLs arising after Dec. 31, 2017 (limited to 80 percent of taxable income); Repeal of the section 199 manufacturing deduction; and Reduced deductions for meals and entertainment as well as state and local lobbying. Entities are required under ASC Topic 740 to recognize the accounting impacts of a tax law change, including the impacts of a change in tax rates on deferred tax assets and liabilities, in the period including the date of the tax law enactment. The SEC staff issued guidance in SAB 118 that supplements the accounting requirements of ASC Topic 740 if elements of the TCJA assessment are not complete, and provides for up to a one year period to finalize the required accounting. Xcel Energy has estimated the effects of the TCJA, which have been reflected in the Dec. 31, 2017 consolidated financial statements. Issuance of U.S. Treasury regulations interpreting the TCJA, other U.S. Treasury and IRS guidance or interpretations of the application of ASC Topic 740 may result in changes to these estimates. Overall for Xcel Energy, reductions in deferred tax assets and liabilities due to the reduction in corporate federal tax rates result in a net tax benefit. However, as a result of IRS requirements and past regulatory treatment of deferred taxes in the determination of regulated rates of the utility subsidiaries, including deferred taxes related to regulated plant and certain other deferred tax assets and liabilities, the impact was primarily recognized as a regulatory liability refundable to utility customers. 48 Table of Contents The fourth quarter 2017 estimated accounting impacts of the December 2017 enactment of the new tax law at PSCo included: • • • $1.1 billion ($1.5 billion grossed-up for tax) of reclassifications of plant-related excess deferred taxes to regulatory liabilities upon valuation at the new 21 percent federal rate. The regulatory liabilities will be amortized consistent with IRS normalization requirements, resulting in customer refunds over the average remaining life of the related property; $54 million and $50 million of reclassifications (grossed-up for tax) of excess deferred taxes for non-plant related deferred tax assets and liabilities, respectively, to regulatory assets and liabilities; $18 million of total estimated income tax benefit related to the federal tax reform implementation, and a $4 million reduction to net income related to the allocation of Xcel Energy Services Inc.’s tax rate change on its deferred taxes. Xcel Energy has accounted for the state tax impacts of federal tax reform based on currently enacted state tax laws. Any future state tax law changes related to the TCJA will be accounted for in the periods state laws are enacted. Consolidated Appropriations Act, 2016 — In December 2015, the Consolidated Appropriations Act, 2016 (Act) was signed into law. The Act provided for the following: • • • • • Immediate expensing, or “bonus depreciation,” of 50 percent for property placed in service in 2015, 2016, and 2017; PTCs at 100 percent of the applicable rate for wind energy projects that begin construction by the end of 2016; 80 percent of the credit rate for projects that begin construction in 2017; 60 percent of the credit rate for projects that begin construction in 2018; and 40 percent of the credit rate for projects that begin construction in 2019. The wind energy PTC was not extended for projects that begin construction after 2019; ITCs at 30 percent for commercial solar projects that begin construction by the end of 2019; 26 percent for projects that begin construction in 2020; 22 percent for projects that begin construction in 2021; and 10 percent for projects thereafter; R&E credit was permanently extended; and Delay of two years (until 2020) of the excise tax on certain employer-provided health insurance plans. The accounting related to the Act was recorded beginning in the fourth quarter of 2015 because a change in tax law is accounted for beginning in the period of enactment. Federal Audit — PSCO is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. The statutes of limitations applicable to Xcel Energy’s federal income tax returns expire as follows: Tax Year(s) 2009 - 2011 2012 - 2013 2014 2015 2016 Expiration June 2018 October 2018 September 2018 September 2019 September 2020 In 2012, the IRS commenced an examination of tax years 2010 and 2011, including the 2009 carryback claim. The IRS proposed an adjustment to the federal tax loss carryback claims that would have resulted in $14 million of income tax expense for the 2009 through 2011 claims, and the 2013 through 2015 claims. In the fourth quarter of 2015, the IRS forwarded the issue to the Office of Appeals (“Appeals”). In the third quarter of 2017, Xcel Energy and 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. As of Dec. 31, 2017, the case has been forwarded to the Joint Committee on Taxation. In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013. In the third quarter of 2017, the IRS concluded the audit of tax years 2012 and 2013 and proposed an adjustment that would impact Xcel Energy’s NOL and ETR. After evaluating the proposed adjustment, Xcel Energy filed a protest with the IRS. Xcel Energy anticipates the issue will be forwarded to Appeals. As of Dec. 31, 2017, Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of this issue; however, the outcome and timing of a resolution is uncertain. State Audits — PSCo is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Dec. 31, 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. 49 Table of Contents Unrecognized Tax 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) Dec. 31, 2017 Unrecognized tax benefit — Permanent tax positions Unrecognized tax benefit — Temporary tax positions Total unrecognized tax benefit $ 4.0 6.1 10.1 $ Dec. 31, 2016 $ 2.9 16.8 19.7 $ A reconciliation of the beginning and ending amount of unrecognized tax benefit is as follows: (Millions of Dollars) 2017 Balance at Jan. 1 Additions based on tax positions related to the current year Reductions based on tax positions related to the current year Additions for tax positions of prior years Reductions for tax positions of prior years Balance at Dec. 31 $ $ 2016 19.7 $ 1.9 (1.5) 4.4 (14.4) 10.1 $ 2015 17.4 $ 2.7 — 0.5 (0.9) 19.7 $ 11.9 4.5 (1.5) 2.5 — 17.4 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) Dec. 31, 2017 NOL and tax credit carryforwards Dec. 31, 2016 (4.0) $ $ (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 $2 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) 2017 Payable for interest related to unrecognized tax benefits at Jan. 1 Interest income (expense) related to unrecognized tax benefits Payable for interest related to unrecognized tax benefits at Dec. 31 $ $ 2016 (1.1) $ 0.8 (0.3) $ No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2017, 2016 or 2015. 50 2015 (0.4) $ (0.7) (1.1) $ (0.2) (0.2) (0.4) Table of Contents Other Income Tax Matters — NOL amounts represent the amount of the tax loss that is carried forward and tax credits represent the deferred tax asset. NOL and tax credit carryforwards as of Dec. 31 were as follows: (Millions of Dollars) 2017 Federal NOL carryforward Federal tax credit carryforwards State NOL carryforwards State tax credit carryforwards, net of federal detriment (a) Valuation allowances for state credit carryforwards, net of federal detriment (b) (a) (b) $ 2016 68 $ 30 679 17 (7) 260 25 684 13 (3) State tax credit carryforwards are net of federal detriment of $4 million and $7 million as of Dec. 31, 2017 and 2016, respectively. Valuation allowances for state tax credit carryforwards were net of federal benefit of $2 million and $2 million as of Dec. 31, 2017 and 2016, respectively. The federal carryforward periods expire between 2021 and 2037. The state carryforward periods expire between 2018 and 2033. Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. The following reconciles such differences for the years ending Dec. 31: 2017 Federal statutory rate State income tax on pretax income, net of federal tax effect Increases (decreases) in tax from: Tax reform Tax credits recognized, net of federal income tax expense Regulatory differences - effects of rate changes (a) Regulatory differences - other utility plant items Change in unrecognized tax benefits Other, net Effective income tax rate (a) (b) 2016 (b) 2015 (b) 35.0% 3.0% 35.0% 3.0% 35.0% 3.0% (2.4) (0.9) (0.1) (0.9) 0.2 (0.1) 33.8% — (0.7) (0.1) (0.5) — 0.4 37.1% — (0.7) (0.1) (0.3) 0.1 0.4 37.4% The amortization of excess deferred taxes. The prior periods included in this footnote have been reclassified to conform to current year presentation. The components of income tax expense for the years ending Dec. 31 were: (Thousands of Dollars) Current federal tax expense (benefit) Current state tax expense (benefit) Current change in unrecognized tax (benefit) expense Deferred federal tax expense Deferred state tax expense Deferred change in unrecognized tax expense (benefit) Deferred investment tax credits Total income tax expense $ $ 2017 2016 2015 40,386 $ 14,577 (7,798) 176,410 22,513 8,894 (2,803) 252,179 $ 45,287 $ 8,754 680 195,064 27,216 (278) (2,805) 273,918 $ (1,166) (727) 5,244 246,096 36,450 (4,650) (2,807) 278,440 2017 2016 2015 The components of deferred income tax expense for the years ending Dec. 31 were: (Thousands of Dollars) Deferred tax (benefit) expense excluding items below Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities Tax expense allocated to other comprehensive income, net of adoption of ASU No. 2018-02, and other Deferred tax expense 51 $ (1,244,653) $ 1,453,080 $ (610) 207,817 $ 230,931 $ (8,418) (511) 222,002 $ 285,144 (7,229) (19) 277,896 Table of Contents The components of the net deferred tax liability at Dec. 31 were as follows: 2017 2016 (a) $ 1,797,023 252,353 60,032 3,994 $ 2,113,402 $ 2,967,162 102,967 10,016 3,920 $ 3,084,065 $ $ (Thousands of Dollars) Deferred tax liabilities: Differences between book and tax bases of property Regulatory assets Pension expense Other Total deferred tax liabilities Deferred tax assets: Regulatory liabilities NOL carryforward Tax credit carryforward Deferred investment tax credits Other employee benefits Deferred fuel costs Rate refund Other Total deferred tax assets Net deferred tax liability 337,973 39,347 39,323 6,872 6,779 6,523 890 31,219 $ 468,926 $ 1,644,476 (a) The prior period included in this footnote has been reclassified to conform to current year presentation. 8. Benefit Plans and Other Postretirement Benefits (35,813) 115,328 34,658 11,653 15,274 10,070 7,221 36,545 $ 194,936 $ 2,889,129 Consistent with the process for rate recovery of pension and postretirement benefits for its employees, PSCo accounts for its participation in, and related costs of, pension and other postretirement benefit plans sponsored by Xcel Energy Inc. as multiple employer plans. PSCo is responsible for its share of cash contributions, plan costs and obligations and is entitled to its share of plan assets; accordingly, PSCo accounts for its pro rata share of these plans, including pension expense and contributions, resulting in accounting consistent with that of a single employer plan exclusively for PSCo employees. Xcel Energy, which includes PSCo, offers various benefit plans to its employees. Approximately 76 percent of employees that receive benefits are represented by several local labor unions under several collective-bargaining agreements. At Dec. 31, 2017, PSCo had 1,835 bargaining employees covered under a collective-bargaining agreement, which expired in May 2017. While collective bargaining is ongoing, the terms and conditions of the agreement are automatically extended. The plans invest in various instruments which are disclosed under the accounting guidance for fair value measurements which establishes a hierarchical framework for disclosing the observability of the inputs utilized in measuring fair value. The three levels in the hierarchy and examples of each level are as follows: Level 1 — Quoted prices are available in active markets for identical assets as of the reporting date. The types of assets included in Level 1 are highly liquid and actively traded instruments with quoted prices. Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reporting date. The types of assets included in Level 2 are typically either comparable to actively traded securities or contracts, or priced with models using highly observable inputs. Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets included in Level 3 are those with inputs requiring significant management judgment or estimation. Specific valuation methods include the following: Cash equivalents — The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted NAVs. 52 Table of Contents Insurance contracts — Insurance contract fair values take into consideration the value of the investments in separate accounts of the insurer, which are priced based on observable inputs. Investments in commingled funds, equity securities and other funds — Equity securities are valued using quoted prices in active markets. The fair values for commingled funds are measured using NAVs, which take into consideration the value of underlying fund investments, as well as the other accrued assets and liabilities of a fund, in order to determine a per share market value. The investments in commingled funds may be redeemed for NAV with proper notice. Proper notice varies by fund and can range from daily with a few days’ notice to annually with 90 days’ notice. Private equity investments require approval of the fund for any unscheduled redemption, and such redemptions may be approved or denied by the fund at its sole discretion. Depending on the fund, unscheduled distributions from real estate investments may require approval of the fund or may be redeemed with proper notice, which is typically quarterly with 45-90 days’ notice; however, withdrawals from real estate investments may be delayed or discounted as a result of fund illiquidity. Investments in debt securities — Fair values for debt securities are determined by a third party pricing service using recent trades and observable spreads from benchmark interest rates for similar securities. Derivative Instruments — Fair values for foreign currency derivatives are determined using pricing models based on the prevailing forward exchange rate of the underlying currencies. The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts. Pension Benefits Xcel Energy, which includes PSCo, has several noncontributory, defined benefit pension plans that cover almost all employees. Generally, benefits are based on a combination of years of service, the employee’s average pay and, in some cases, social security benefits. Xcel Energy Inc.’s and PSCo’s policy is to fully fund into an external trust the actuarially determined pension costs recognized for ratemaking and financial reporting purposes, subject to the limitations of applicable employee benefit and tax laws. In addition to the qualified pension plans, Xcel Energy maintains a supplemental executive retirement plan (SERP) and a nonqualified pension plan. The SERP is maintained for certain executives that were participants in the plan in 2008, when the SERP was closed to new participants. The nonqualified pension plan provides unfunded, nonqualified benefits for compensation that is in excess of the limits applicable to the qualified pension plans, with distributions attributable to PSCo funded by PSCo’s consolidated operating cash flows. The total obligations of the SERP and nonqualified plan as of Dec. 31, 2017 and 2016 were $37 million and $44 million, respectively, of which $3 million and $4 million were attributable to PSCo. In 2017 and 2016, Xcel Energy recognized net benefit cost for financial reporting for the SERP and nonqualified plans of $5 million and $8 million, respectively, of which $1 million in each year was attributable to PSCo. In 2016, Xcel Energy established rabbi trusts to provide partial funding for future distributions of the SERP and its deferred compensation plan. Rabbi trust funding of deferred compensation plan distributions attributable to PSCo will be supplemented by PSCo’s consolidated operating cash flows as determined necessary. The amount of rabbi trust funding attributable to PSCo is immaterial. Also in 2016, Xcel Energy amended the deferred compensation plan to provide eligible participants the ability to diversify deferred settlements of equity awards, other than time-based equity awards, into various fund options. Xcel Energy Inc. and PSCo base the investment-return assumption on expected long-term performance for each of the investment types included in the pension asset portfolio and consider the historical returns achieved by the asset portfolio over the past 20-year or longer period, as well as the long-term return levels projected and recommended by investment experts. Xcel Energy Inc. and PSCo continually review pension assumptions. The pension cost determination assumes a forecasted mix of investment types over the long term. • • • • Investment returns in 2017 were above the assumed level of 6.84 percent; Investment returns in 2016 were below the assumed level of 6.84 percent; Investment returns in 2015 were below the assumed level of 6.81 percent; and In 2018, PSCo’s expected investment-return assumption is 6.84 percent. The assets are invested in a portfolio according to Xcel Energy Inc.’s and PSCo’s return, liquidity and diversification objectives to provide funding for plan obligations and minimize contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the projected asset allocation given the long-term risk, return, and liquidity characteristics of each particular asset class. There were no significant concentrations of risk in any particular industry, index, or entity. Market volatility can impact even well-diversified portfolios and significantly affect the return levels achieved by pension assets in any year. 53 Table of Contents The following table presents the target pension asset allocations for PSCo at Dec. 31 for the upcoming year: 2017 Domestic and international equity securities Long-duration fixed income and interest rate swap securities Short-to-intermediate fixed income securities Alternative investments Cash Total 2016 34% 32 18 14 2 100% 36% 31 15 16 2 100% The ongoing investment strategy is based on plan-specific investment recommendations that seek to minimize potential investment and interest rate risk as a plan’s funded status increases over time. The investment recommendations result in a greater percentage of long-duration fixed income securities being allocated to specific plans having relatively higher funded status ratios and a greater percentage of growth assets being allocated to plans having relatively lower funded status ratios. The aggregate projected asset allocation presented in the table above for the master pension trust results from the plan-specific strategies. Pension Plan Assets The following tables present, for each of the fair value hierarchy levels, PSCo’s pension plan assets that are measured at fair value as of Dec. 31, 2017 and 2016: Dec. 31, 2017 (Thousands of Dollars) Cash equivalents Commingled funds: U.S. equity funds Non U.S. equity funds U.S. corporate bond funds Emerging market equity funds Emerging market debt funds Private equity investments Real estate Other commingled funds Debt securities: Government securities U.S. corporate bonds Non U.S. corporate bonds Equity securities: U.S. equities Other Total Level 1 $ $ Level 2 67,179 $ Investments Measured at NAV Level 3 — $ — $ — Total $ 67,179 169,624 30,277 137,086 — 24,825 — — 1,601 — — — — — — — — — — — — — — — — — 65,822 — 103,876 54,954 27,816 64,500 38,545 169,624 96,099 137,086 103,876 79,779 27,816 64,500 40,146 — — — 144,333 102,659 16,792 — — — — — — 144,333 102,659 16,792 — 1,414 265,198 — — — — 180 355,693 37,752 (9,885) 458,459 $ 54 $ $ $ 37,752 (8,291) 1,079,350 Table of Contents Dec. 31, 2016 (Thousands of Dollars) Cash equivalents Commingled funds: U.S. equity funds Non U.S. equity funds U.S. corporate bond funds Emerging market equity funds Emerging market debt funds Commodity funds Private equity investments Real estate Other commingled funds Debt securities: Government securities U.S. corporate bonds Non U.S. corporate bonds Mortgage-backed securities Asset-backed securities Equity securities: U.S. equities Other Total Level 1 $ $ Level 2 34,957 $ Investments Measured at NAV Level 3 — $ — $ — Total $ 34,957 165,621 64,710 96,995 — 25,866 — — — — — — — — — — — — — — — — — — — — — — — 57,487 — 64,784 27,837 7,497 31,828 61,048 74,696 165,621 122,197 96,995 64,784 53,703 7,497 31,828 61,048 74,696 — — — — — 168,014 86,081 13,828 2,179 1,032 — — — — — — — — — — 168,014 86,081 13,828 2,179 1,032 — (7,595) 263,539 $ — — — — — 325,177 27,348 — 415,497 $ $ $ 27,348 (7,595) 1,004,213 There were no assets transferred in or out of Level 3 for the years ended Dec. 31, 2017, 2016 or 2015. Benefit Obligations — A comparison of the actuarially computed pension benefit obligation and plan assets for PSCo is presented in the following table: (Thousands of Dollars) 2017 Accumulated Benefit Obligation at Dec. 31 Change in Projected Benefit Obligation: Obligation at Jan. 1 Service cost Interest cost Transfer to other plan Plan amendments Actuarial loss Benefit payments Obligation at Dec. 31 1,285,010 $ 1,251,822 $ 27,280 50,558 — (1,096) 83,531 (77,915) 1,334,180 $ $ (Thousands of Dollars) $ 2017 Change in Fair Value of Plan Assets: Fair value of plan assets at Jan. 1 Actual return on plan assets Employer contributions Transfer to other plan Benefit payments Fair value of plan assets at Dec. 31 $ $ (Thousands of Dollars) Funded Status of Plans at Dec. 31: Funded status (a) (a) 2016 $ $ Amounts are recognized in noncurrent liabilities on PSCo’s consolidated balance sheets. 55 1,004,213 $ 135,552 17,500 — (77,915) 1,079,350 $ 1,213,890 1,224,650 25,926 55,405 (9,149) 206 51,779 (96,995) 1,251,822 2016 1,036,681 56,762 16,829 (9,064) (96,995) 1,004,213 2017 2016 (254,830) $ (247,609) Table of Contents (Thousands of Dollars) 2017 Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: Net loss Prior service credit Total $ $ (Thousands of Dollars) 2016 543,707 $ (10,593) 533,114 $ 2017 Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates: Current regulatory assets Noncurrent regulatory assets Deferred income taxes Net-of-tax accumulated OCI Total Measurement date Significant Assumptions Used to Measure Benefit Obligations: Discount rate for year-end valuation Expected average long-term increase in compensation level Mortality table $ $ 27,662 505,171 69 212 533,114 554,999 (12,155) 542,844 2016 $ $ 26,853 515,708 108 175 542,844 Dec. 31, 2017 Dec. 31, 2016 2017 2016 3.63% 3.75 RP-2014 4.13% 3.75 RP-2014 Mortality — In 2014, the Society of Actuaries published a new mortality table (RP-2014) that increased the overall life expectancy of males and females. In 2014, PSCo adopted this mortality table, with modifications, based on its population and specific experience. During 2017, a new projection table was released (MP-2017). PSCo evaluated the updated projection table and concluded that the methodology currently in use and adopted in 2016 is consistent with the recently updated 2017 table and continues to be representative of PSCo’s population. Cash Flows — Cash funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other calculations prescribed by the funding requirements of income tax and other pension-related regulations. Required contributions were made in 2015 through 2018 to meet minimum funding requirements. Total voluntary and required pension funding contributions across all four of Xcel Energy’s pension plans were as follows: • • • • $150 million in January 2018, of which $22 million was attributable to PSCo; $162 million in 2017, of which $18 million was attributable to PSCo; $125 million in 2016, of which $17 million was attributable to PSCo; and $90 million in 2015, of which $20 million was attributable to PSCo. For future years, Xcel Energy and PSCo anticipate contributions will be made as necessary. Plan Amendments — Xcel Energy, which includes PSCo, amended the Xcel Energy Inc. Nonbargaining Pension Plan (South) in 2017 to reduce supplemental benefits for non-bargaining participants as well as to allow the transfer of a portion of non-qualified pension obligations into the qualified plans. In 2016, the annual credits contributed to the PSCo Bargaining Plan retirement spending account increased. 56 Table of Contents Benefit Costs — The components of PSCo’s net periodic pension cost were: (Thousands of Dollars) 2017 Service cost Interest cost Expected return on plan assets Amortization of prior service credit Amortization of net loss Net periodic pension cost (Costs) credits not recognized due to effects of regulation Net benefit cost recognized for financial reporting $ $ 27,280 $ 50,558 (68,535) (3,211) 28,355 34,447 (2,631) 31,816 $ 2017 Significant Assumptions Used to Measure Costs: Discount rate Expected average long-term increase in compensation level Expected average long-term rate of return on assets 4.13% 3.75 6.84 2016 25,926 $ 55,405 (70,769) (3,211) 26,771 34,122 3,364 37,486 $ 2016 4.66% 4.00 6.84 2015 28,260 50,857 (72,590) (3,136) 36,377 39,768 (1,464) 38,304 2015 4.11% 3.75 6.81 In addition to the benefit costs in the table above, for the pension plans sponsored by Xcel Energy Inc., costs are allocated to PSCo based on Xcel Energy Services Inc. employees’ labor costs. Amounts allocated to PSCo were $18 million, $9 million and $10 million in 2017, 2016 and 2015, respectively. Pension costs include an expected return impact for the current year that may differ from actual investment performance in the plan. The return assumption used for 2018 pension cost calculations is 6.84 percent. The cost calculation uses a market-related valuation of pension assets. Xcel Energy, including PSCo, uses a calculated value method to determine the market-related value of the plan assets. The market-related value begins with the fair market value of assets as of the beginning of the year. The market-related value is determined by adjusting the fair market value of assets to reflect the investment gains and losses (the difference between the actual investment return and the expected investment return on the market-related value) during each of the previous five years at the rate of 20 percent per year. As these differences between actual investment returns and the expected investment returns are incorporated into the market-related value, the differences are recognized over the expected average remaining years of service for active employees. Defined Contribution Plans Xcel Energy, which includes PSCo, maintains 401(k) and other defined contribution plans that cover substantially all employees. The expense to these plans for PSCo was approximately $10 million in 2017, 2016 and 2015. Postretirement Health Care Benefits Xcel Energy, which includes PSCo, has a contributory health and welfare benefit plan that provides health care and death benefits to certain retirees. Xcel Energy discontinued contributing toward health care benefits for PSCo nonbargaining employees retiring after June 30, 2003. Employees of NCE who retired in 2002 continue to receive employer-subsidized health care benefits. Nonbargaining employees of the former NCE who retired after 1998, bargaining employees of the former NCE who retired after 1999 and nonbargaining employees of NCE who retired after June 30, 2003, are eligible to participate in the Xcel Energy health care program with no employer subsidy. 57 Table of Contents Plan Assets — Certain state agencies that regulate Xcel Energy Inc.’s utility subsidiaries also have issued guidelines related to the funding of postretirement benefit costs. PSCo is required to fund postretirement benefit costs in irrevocable external trusts that are dedicated to the payment of these postretirement benefits. These assets are invested in a manner consistent with the investment strategy for the pension plan. The following table presents the target postretirement asset allocations for Xcel Energy Inc. and PSCo at Dec. 31 for the upcoming year: 2017 Domestic and international equity securities Short-to-intermediate fixed income securities Alternative investments Cash Total 2016 24% 60 9 7 100% 25% 57 13 5 100% Xcel Energy Inc. and PSCo base the investment-return assumptions for the postretirement health care fund assets on expected longterm performance for each of the investment types included in the asset portfolio. Assumptions and target allocations are determined at the master trust level. The investment mix at each of Xcel Energy Inc.’s utility subsidiaries may vary from the investment mix of the total asset portfolio. The assets are invested in a portfolio according to Xcel Energy Inc.’s and PSCo’s return, liquidity and diversification objectives to provide a source of funding for plan obligations and minimize contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the projected asset allocation given the long-term risk, return, correlation and liquidity characteristics of each particular asset class. There were no significant concentrations of risk in any particular industry, index, or entity. Market volatility can impact even well-diversified portfolios and significantly affect the return levels achieved by postretirement health care assets in any year. The following tables present, for each of the fair value hierarchy levels, PSCo’s proportionate allocation of the total postretirement benefit plan assets that are measured at fair value as of Dec. 31, 2017 and 2016: Dec. 31, 2017 (Thousands of Dollars) Cash equivalents Insurance contracts Commingled funds: U.S. equity funds U.S fixed income funds Emerging market debt funds Debt securities: Government securities U.S. corporate bonds Non U.S. corporate bonds Asset-backed securities Mortgage-backed securities Equity securities: Non U.S. equities Other Total Level 1 $ $ Level 2 25,724 — $ Investments Measured at NAV Level 3 — 43,524 $ — — $ — — Total $ 25,724 43,524 64,899 29,946 35,402 — — — — — — — — — 64,899 29,946 35,402 — — — — — 50,576 55,323 18,712 20,468 30,231 — — — — — — — — — — 50,576 55,323 18,712 20,468 30,231 30,671 — 186,642 — 948 219,782 — — — — — — 30,671 948 406,424 58 $ $ $ $ Table of Contents Dec. 31, 2016 (Thousands of Dollars) Cash equivalents Insurance contracts Commingled funds: U.S. equity funds U.S fixed income funds Emerging market debt funds Other commingled funds Debt securities: Government securities U.S. corporate bonds Non U.S. corporate bonds Asset-backed securities Mortgage-backed securities Equity securities: Non U.S. equities Other Total Level 1 $ $ Level 2 18,288 — $ Investments Measured at NAV Level 3 — 42,046 $ — — $ — — Total $ 18,288 42,046 48,462 24,132 27,089 — — — — — — — — — — — — 48,922 48,462 24,132 27,089 48,922 — — — — — 33,600 55,473 15,384 16,845 25,563 — — — — — — — — — — 33,600 55,473 15,384 16,845 25,563 36,462 — 154,433 — 1,289 190,200 — — — — — 48,922 36,462 1,289 393,555 $ $ $ $ There were no assets transferred in or out of Level 3 for the years ended Dec. 31, 2017, 2016 or 2015. Benefit Obligations — A comparison of the actuarially computed benefit obligation and plan assets for PSCo is presented in the following table: (Thousands of Dollars) 2017 Change in Projected Benefit Obligation: Obligation at Jan. 1 Service cost Interest cost Medicare subsidy reimbursements Plan participants’ contributions Actuarial loss Benefit payments Obligation at Dec. 31 $ $ (Thousands of Dollars) 421,823 $ 767 16,765 993 5,971 18,314 (35,386) 429,247 $ 2017 Change in Fair Value of Plan Assets: Fair value of plan assets at Jan. 1 Actual return on plan assets Plan participants’ contributions Employer contributions Benefit payments Fair value of plan assets at Dec. 31 $ $ (Thousands of Dollars) 393,555 $ 36,975 5,971 5,309 (35,386) 406,424 $ 2017 2016 403,574 768 18,070 1,901 5,376 27,355 (35,221) 421,823 2016 399,442 18,590 5,376 5,368 (35,221) 393,555 2016 Funded Status at Dec. 31: Funded status (a) (a) $ Amounts are recognized in noncurrent liabilities on PSCo’s consolidated balance sheets as of Dec. 31, 2017 and 2016, respectively. 59 (22,823) $ (28,268) Table of Contents (Thousands of Dollars) 2017 Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: Net loss Prior service credit Total $ 2016 77,760 $ (21,448) 56,312 $ $ (Thousands of Dollars) 78,359 (27,695) 50,664 2017 2016 Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates: Noncurrent regulatory assets $ Measurement date Dec. 31, 2017 Dec. 31, 2016 2017 2016 3.62% RP 2014 7.00% 5.50% 4.13% RP 2014 5.50% 5.50% 56,312 Significant Assumptions Used to Measure Benefit Obligations: Discount rate for year-end valuation Mortality table Health care costs trend rate — initial: Pre-65 Health care costs trend rate — initial: Post-65 $ 50,664 Beginning with the Dec. 31 2017 measurement, Xcel Energy Inc. and PSCo separated its initial medical trend assumption for preMedicare (Pre-65) and post-Medicare (Post-65) claims costs of 7.0 percent and 5.5 percent, respectively, in order to reflect different short-term expectations based on recent experience differences. The ultimate trend assumption remained at 4.5 percent for both Pre-65 and Post-65 claims costs as similar long-term trend rates are expected for both populations. The period until the ultimate rate is reached is five years. Xcel Energy Inc. and PSCo base the medical trend assumption on the long-term cost inflation expected in the health care market, considering the levels projected and recommended by industry experts, as well as recent actual medical cost increases experienced by the retiree medical plan. A one-percent change in the assumed health care cost trend rate would have the following effects on PSCo: One-Percentage Point (Thousands of Dollars) Increase APBO Service and interest components $ 41,665 1,837 Decrease $ (35,254) (1,555) Cash Flows — The postretirement health care plans have no funding requirements under income tax and other retirement-related regulations other than fulfilling benefit payment obligations, when claims are presented and approved under the plans. Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities. Xcel Energy, which includes PSCo, contributed $20 million, $18 million and $18 million during 2017, 2016 and 2015, respectively, of which $5 million, $5 million and $6 million were attributable to PSCo. Xcel Energy expects to contribute approximately $12 million during 2018, of which amounts attributable to PSCo will be zero. Plan Amendments — In 2017 and 2016 there were no plan amendments made which affected the projected benefit obligation. Benefit Costs — The components of PSCo’s net periodic postretirement benefit costs were: (Thousands of Dollars) 2017 Service cost Interest cost Expected return on plan assets Amortization of prior service credit Amortization of net loss Net periodic postretirement benefit credit $ $ 60 767 $ 16,765 (21,905) (6,247) 3,843 (6,777) $ 2016 768 $ 18,070 (22,299) (6,247) 1,931 (7,777) $ 2015 928 17,498 (23,803) (6,247) 2,475 (9,149) Table of Contents 2017 Significant Assumptions Used to Measure Costs: Discount rate Expected average long-term rate of return on assets 2016 4.13% 5.80 2015 4.65% 5.80 4.08% 5.80 In addition to the benefit costs in the table above, for the postretirement health care plans sponsored by Xcel Energy Inc., costs are allocated to PSCo based on Xcel Energy Services Inc. employees’ labor costs. Projected Benefit Payments The following table lists PSCo’s projected benefit payments for the pension and postretirement benefit plans: (Thousands of Dollars) 2018 2019 2020 2021 2022 2023-2027 9. Projected Pension Benefit Payments Gross Projected Postretirement Health Care Benefit Payments Expected Medicare Part D Subsidies Net Projected Postretirement Health Care Benefit Payments $ $ $ $ 83,036 81,698 81,413 82,021 83,261 411,798 32,186 32,454 32,767 32,737 32,998 152,926 2,074 2,192 2,296 2,404 2,501 13,789 30,112 30,262 30,471 30,333 30,497 139,137 Other Income, Net Other income, net for the years ended Dec. 31 consisted of the following: (Thousands of Dollars) 2017 Interest income Other nonoperating income Insurance policy expense Other nonoperating expense Other income, net $ $ 3,809 $ 6,383 (340) — 9,852 $ 2016 2015 1,860 $ 2,241 (281) (3) 3,817 $ 753 2,408 (197) — 2,964 10. Fair Value of Financial Assets and Liabilities Fair Value Measurements The accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires certain disclosures about assets and liabilities measured at fair value. A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance. The three levels in the hierarchy are as follows: Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices. Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, or priced with models using highly observable inputs. Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those valued with models requiring significant management judgment or estimation. 61 Table of Contents Specific valuation methods include the following: Cash equivalents — The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted NAV. Interest rate derivatives — The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts. Commodity derivatives — The methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2 classification. When contractual settlements relate to inactive delivery locations or extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable forecasts of forward prices and volatilities on a valuation is evaluated, and may result in Level 3 classification. Derivative Instruments Fair Value Measurements PSCo enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to manage risk in connection with changes in interest rates, utility commodity prices and vehicle fuel prices. Interest Rate Derivatives — PSCo enters into various instruments that effectively fix the interest payments on certain floating rate debt obligations or effectively fix the yield or price on a specified benchmark interest rate for an anticipated debt issuance for a specific period. These derivative instruments are generally designated as cash flow hedges for accounting purposes. At Dec. 31, 2017, accumulated other comprehensive losses related to interest rate derivatives included $1.2 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for unsettled hedges, as applicable. Wholesale and Commodity Trading Risk — PSCo conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. PSCo’s risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee, which is made up of management personnel not directly involved in the activities governed by this policy. Commodity Derivatives — PSCo enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric and natural gas operations, as well as for trading purposes. This could include the purchase or sale of energy or energy-related products, natural gas to generate electric energy, natural gas for resale, and vehicle fuel. PSCo enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but may not be designated as qualifying hedging transactions. Changes in the fair value of non-trading commodity derivative instruments are recorded in OCI or deferred as a regulatory asset or liability. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. PSCo recorded no amounts to income related to the ineffectiveness of cash flow hedges for the year ended Dec. 31, 2017 and immaterial amounts for the year ended Dec. 31, 2016. Additionally, PSCo enters into commodity derivative instruments for trading purposes not directly related to commodity price risks associated with serving its electric and natural gas customers. Changes in the fair value of these commodity derivatives are recorded in electric operating revenues, net of amounts credited to customers under margin-sharing mechanisms. The following table details the gross notional amounts of commodity forwards and options at Dec. 31: (Amounts in Thousands) (a)(b) 2017 MWh of electricity MMBtu of natural gas (a) (b) 22,260 13,410 Amounts are not reflective of net positions in the underlying commodities. Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise. 62 2016 6,283 42,203 Table of Contents Consideration of Credit Risk and Concentrations — PSCo continuously monitors the creditworthiness of the counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement, and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Given this assessment, as well as an assessment of the impact of PSCo’s own credit risk when determining the fair value of derivative liabilities, the impact of credit risk was immaterial to the fair value of unsettled commodity derivatives presented in the consolidated balance sheets. PSCo employs additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures. Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. PSCo’s most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to its wholesale, trading and non-trading commodity activities. At Dec. 31, 2017, five of PSCo’s 10 most significant counterparties for these activities, comprising $7.0 million or 16 percent of this credit exposure, had investment grade credit ratings from S&P’s, Moody’s or Fitch Ratings. Four of the 10 most significant counterparties, comprising $16.5 million or 37 percent of this credit exposure at Dec. 31, 2017 were not rated by these external agencies, but based on PSCo’s internal analysis, had credit quality consistent with investment grade. Another of these significant counterparties, comprising $7.4 million or 17 percent of this credit exposure, had credit quality less than investment grade, based on ratings from external analysis. Six of these significant counterparties are municipal or cooperative electric entities, or other utilities. Financial Impact of Qualifying Cash Flow Hedges — The impact of qualifying interest rate and vehicle fuel cash flow hedges on PSCo’s accumulated other comprehensive loss, included in the consolidated statements of common stockholder’s equity and in the consolidated statements of comprehensive income, is detailed in the following table: (Thousands of Dollars) 2017 2016 2015 $ (22,780) $ (23,836) $ (23,878) — — (30) 1,005 1,056 72 $ (21,775) $ (22,780) $ (23,836) Accumulated other comprehensive loss related to cash flow hedges at Jan. 1 After-tax net unrealized losses related to derivatives accounted for as hedges After-tax net realized losses on derivative transactions reclassified into earnings Accumulated other comprehensive loss related to cash flow hedges at Dec. 31 The following tables detail the impact of derivative activity during the years ended Dec. 31, 2017, 2016 and 2015, on accumulated other comprehensive loss, regulatory assets and liabilities, and income: Year Ended Dec. 31, 2017 Pre-Tax Fair Value Losses Recognized During the Period in: Accumulated Other Comprehensive Loss (Thousands of Dollars) Derivatives designated as cash flow hedges Interest rate Total Other derivative instruments Commodity trading Natural gas commodity Total Accumulated Other Comprehensive Loss Regulatory (Assets) and Liabilities $ $ — — $ $ $ — — — $ $ Pre-Tax Losses Reclassified into Income During the Period from: $ — — — (10,921) (10,921) 63 $ $ 1,615 1,615 $ — — — $ Pre-Tax Gains (Losses) Recognized During the Period in Income Regulatory Assets and (Liabilities) (a) $ $ — — $ — 1,933 1,933 $ $ $ (d) $ $ — — 386 (4,170) (3,784) (c) (d) Table of Contents Year Ended Dec. 31, 2016 Pre-Tax Fair Value Gains Recognized During the Period in: Accumulated Other Comprehensive Loss (Thousands of Dollars) Derivatives designated as cash flow hedges Interest rate Vehicle fuel and other commodity Total Other derivative instruments Commodity trading Natural gas commodity Total $ — $ — — $ $ — — — Pre-Tax Losses Reclassified into Income During the Period from: Accumulated Other Comprehensive Loss Regulatory (Assets) and Liabilities $ — $ — — $ — 2,051 2,051 $ $ 1,618 (a) (b) $ 86 1,704 $ $ Pre-Tax Losses Recognized During the Period in Income Regulatory Assets and (Liabilities) — — — $ — $ — $ — — $ — — $ — 10,292 10,292 $ (d) $ $ (257) (5,832) (6,089) (c) (d) Year Ended Dec. 31, 2015 Pre-Tax Fair Value Losses Recognized During the Period in: Accumulated Other Comprehensive Loss (Thousands of Dollars) Derivatives designated as cash flow hedges Interest rate Vehicle fuel and other commodity Total Other derivative instruments Commodity trading Natural gas commodity Total (a) (b) (c) (d) $ — $ (50) (50) $ $ — — — Pre-Tax Losses Reclassified into Income During the Period from: Accumulated Other Comprehensive Loss Regulatory (Assets) and Liabilities $ — $ — — $ $ — (10,635) (10,635) $ 54 (a) (b) $ 57 111 $ $ — — — Pre-Tax Gains (Losses) Recognized During the Period in Income Regulatory Assets and (Liabilities) $ — $ — $ — — $ — — $ $ — 10,158 10,158 (d) $ $ 364 (7,620) (7,256) (c) (d) Amounts are recorded to interest charges. Amounts are recorded to O&M expenses. 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. Certain derivatives are utilized to mitigate natural gas price risk for electric generation and are recorded to electric fuel and purchased power, subject to costrecovery mechanisms and reclassified to a regulatory asset as appropriate. Amounts for the year ended Dec. 31, 2017 included $0.4 million of settlement gains and amounts for the years ended Dec. 31, 2016 and 2015 included $0.2 million and $1.1 million, respectively, of settlement losses on derivatives entered to mitigate natural gas price risk for electric generation, recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. The remaining settlement losses for the years ended Dec. 31, 2017, 2016 and 2015 relate to natural gas operations and are recorded to cost of natural gas sold and transported. These losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset, as appropriate. PSCo had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2017, 2016 and 2015. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods. 64 Table of Contents Credit Related Contingent Features — Contract provisions for derivative instruments that PSCo enters into, including those accounted for as normal purchase-normal sale contracts and therefore not reflected on the consolidated balance sheets, may require the posting of collateral or settlement of the contracts for various reasons, including if PSCo’s credit ratings are downgraded below its investment grade credit rating by any of the major credit rating agencies or for cross-default contractual provisions that could result in the settlement of such contracts if there was a failure under other financing arrangements related to payment terms or other covenants. At Dec. 31, 2017 and 2016, there were no derivative instruments in a material liability position with such underlying contract provisions. Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that PSCo’s ability to fulfill its contractual obligations is reasonably expected to be impaired. PSCo had no collateral posted related to adequate assurance clauses in derivative contracts as of Dec. 31, 2017 and 2016. Recurring Fair Value Measurements — The following table presents, for each of the fair value hierarchy levels, PSCo’s derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2017: Dec. 31, 2017 Fair Value (Thousands of Dollars) Current derivative assets Other derivative instruments: Commodity trading Natural gas commodity Total current derivative assets PPAs (a) Current derivative instruments Noncurrent derivative assets Other derivative instruments: Commodity trading Total noncurrent derivative assets PPAs (a) Noncurrent derivative instruments Current derivative liabilities Other derivative instruments: Commodity trading Natural gas commodity Total current derivative liabilities PPAs (a) Current derivative instruments Noncurrent derivative liabilities Other derivative instruments: Commodity trading Total noncurrent derivative liabilities PPAs (a) Noncurrent derivative instruments (a) (b) Level 1 $ $ 528 — 528 Level 2 $ 4,488 18 $ 4,506 Fair Value Total Level 3 $ $ 12 — 12 $ $ 5,028 18 5,046 Counterparty Netting (b) $ $ Total (3,554) $ (10) (3,564) $ $ $ — — $ 1,541 $ 1,541 $ $ — — $ $ 1,541 1,541 $ $ (563) $ (563) $ $ $ $ $ 446 — 446 — — $ 4,285 1,016 $ 5,301 $ 1,362 $ 1,362 $ $ $ $ 6 — 6 — — $ $ $ $ 4,737 1,016 5,753 1,362 1,362 $ $ $ $ (3,431) $ (10) (3,441) 1,474 8 1,482 1,715 3,197 978 978 31 1,009 $ 1,306 1,006 2,312 5,036 7,348 (563) $ (563) $ $ 799 799 2,669 3,468 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. PSCo nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2017. At Dec. 31, 2017, derivative assets and liabilities include no obligations to return or reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. 65 Table of Contents The following table presents, for each of the fair value hierarchy levels, PSCo’s derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2016: Dec. 31, 2016 Fair Value (Thousands of Dollars) Current derivative assets Other derivative instruments: Commodity trading Natural gas commodity Total current derivative assets PPAs (a) Current derivative instruments Noncurrent derivative assets Other derivative instruments: Commodity trading Total noncurrent derivative assets PPAs (a) Noncurrent derivative instruments Current derivative liabilities Other derivative instruments: Commodity trading Total current derivative liabilities PPAs (a) Current derivative instruments Noncurrent derivative liabilities PPAs (a) Noncurrent derivative instruments (a) (b) Level 1 Level 2 $ 1,124 — $ 1,124 $ 5,453 7,778 $ 13,231 Fair Value Total Level 3 $ $ — — — $ $ 6,577 7,778 14,355 Counterparty Netting (b) $ $ Total (5,137) $ — (5,137) $ $ $ — — $ 1,652 $ 1,652 $ $ — — $ $ 1,652 1,652 $ $ — — $ $ $ 1,386 $ 1,386 $ 5,357 $ 5,357 $ $ 22 22 $ $ 6,765 6,765 $ $ (5,137) $ (5,137) 1,440 7,778 9,218 1,716 10,934 1,652 1,652 1,746 3,398 $ 1,628 1,628 5,160 6,788 $ $ 7,828 7,828 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. PSCo nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2016. At Dec. 31, 2016, derivative assets and liabilities include no obligations to return cash collateral of or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. There were immaterial gains recognized in earnings for the year ended Dec. 31, 2017 and immaterial losses recognized in earnings for the year ended Dec. 31, 2016 for level 3 commodity trading derivatives. There were no changes in Level 3 recurring fair value measurements for the year ended Dec. 31, 2015. PSCo recognizes transfers between levels as of the beginning of each period. There were no transfers of amounts between levels for derivative instruments for the years ended Dec. 31, 2017, 2016 and 2015. Fair Value of Long-Term Debt As of Dec. 31, 2017 and 2016, other financial instruments for which the carrying amount did not equal fair value were as follows: 2017 (Thousands of Dollars) Long-term debt, including current portion Carrying Amount $ 4,608,275 2016 Fair Value Carrying Amount Fair Value $ 5,024,840 $ 4,216,206 $ 4,491,570 The fair value of PSCo’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. The fair value estimates are based on information available to management as of Dec. 31, 2017 and 2016, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2. 66 Table of Contents 11. Rate Matters Tax Reform — Regulatory Proceedings The specific impacts of the TCJA on retail customer rates are subject to regulatory approval. PSCo is in the process of quantifying the rate impacts of the TCJA and are being addressed in several regulatory proceedings focused on retail base rate impacts, which include the following: • Colorado Statewide TCJA Proceeding — On Jan. 31, 2018, the CPUC opened a statewide TCJA proceeding and ordered deferred accounting for all investor-owned utilities. On Feb. 21, 2017, PSCo filed a response with the CPUC related to the deferred accounting order and statewide TCJA proceeding, addressing the estimated impacts along with other considerations given PSCo’s pending natural gas and electric rate cases. • Colorado 2017 Multi-Year Natural Gas Rate Case — On Feb. 14, 2018, the ALJ approved PSCo and CPUC Staff’s nonunanimous settlement agreement which addresses the impacts of the TCJA in 2018. This settlement agreement includes a $20 million reduction to provisional rates effective March 1, 2018, with future true-ups to be determined later in 2018 once a full analysis of the comprehensive impacts of tax reform is performed, including any outcomes associated with statewide proceeding. The final true-up would provide customers the full net benefit of the TCJA effective Jan. 1, 2018. • Colorado 2017 Multi-Year Electric Rate Case — On Feb. 16, 2018, the CPUC denied the proposed settlement agreement between PSCo and several intervenors, in favor of the state TCJA proceeding. In the second quarter of 2018, PSCo plans to file a revised rate request that will include the impacts of the TCJA. Provisional rates, subject to refund with interest, are expected to be effective June 1, 2018. The appropriate test year and the final approved revenue requirement will be determined in the pending rate case, discussed below. PSCo expects to defer the TCJA net benefits for the first five months of 2018, prior to provisional rates. The CPUC is expected to rule on the regulatory treatment of the TCJA, the natural gas rate case and the electric rate case later in 2018. Pending Regulatory Proceedings — CPUC 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 FTY ending Dec. 31, a 10.0 percent ROE and an equity ratio of 55.25 percent. Revenue Request (Millions of Dollars) 2018 Revenue request CACJA revenue conversion to base rates (a) TCA revenue conversion to base rates (a) Total (b) $ Expected year-end rate base (billions of dollars) (b) 2019 $ $ 74 90 43 207 $ 6.8 2020 $ $ 75 — — 75 $ 7.1 2021 Total $ $ 60 — — 60 $ 36 — — 36 $ 7.3 $ 7.4 $ $ 245 90 43 378 (a) The roll-in of the TCA and CACJA rider revenues into base rates will not have an impact on customer bills or revenue as these costs are already being recovered through a rider. Transmission investments for 2019-2021 will be recovered through the TCA rider. (b) This base rate request does not include the impacts of the RESA and ECA for the Rush Creek wind investments or the proposed CEP. Key dates in the procedural schedule are as follows: • • • • • Supplemental direct testimony — April 16, 2018; Answer testimony — May 31, 2018; Rebuttal and cross-answer testimony — July 10, 2018; Hearings — Aug. 21 - 31, 2018; and Statement of position — Sept. 28, 2018. 67 Table of Contents Interim rates, subject to refund and interest, are to be effective on June 1, 2018. PSCo also proposed a stay-out provision and earnings test through 2021. On Jan. 31, 2018, the CPUC ordered deferred accounting for the impacts of TCJA and opened a statewide TCJA proceeding, as discussed above. In the second quarter of 2018, PSCo plans to file a revised rate request that will include the impacts of the TCJA. The CPUC is expected to rule on the regulatory treatment of the TCJA and the electric rate case later in 2018. Colorado 2017 Multi-Year Natural Gas Rate Case — In June 2017, PSCo filed a multi-year request with the CPUC seeking to increase retail natural gas rates approximately $139 million over three years. The request, detailed below, is based on FTYs, a 10.0 percent ROE and an equity ratio of 55.25 percent. Revenue Request (Millions of Dollars) 2018 Revenue request PSIA revenue conversion to base rates (a) Total $ Expected year-end rate base (billions of dollars) (b) 2019 $ $ 63 — 63 $ 1.5 2020 Total $ $ 33 94 127 $ 43 — 43 $ 2.3 $ 2.4 $ $ 139 94 233 (a) The roll-in of PSIA rider revenue into base rates will not have an impact on customer bills or revenue as these costs are already being recovered through the rider. The recovery of incremental PSIA related investments in 2019 and 2020 are included in the base rate request. (b) The additional rate base in 2019 predominantly reflects the roll-in of capital associated with the PSIA rider. In October 2017, several parties filed answer testimony. The CPUC Staff (Staff) and the OCC, recommended a single 2016 HTY, based on an average 13-month rate base, and opposed a multi-year request. The Staff and OCC recommended an equity capital structure of 48.73 percent and 51.2 percent, respectively. Both the Staff and the OCC recommended the existing PSIA rider expire with the 2018 rates rolled into base rates beginning Jan. 1, 2019. Planned investments in 2019 and 2020 would be recoverable through base rates, subject to a future rate case. The final positions of the Staff and OCC provide for a recommended 2018 rate increase of approximately $30 million and $39 million, respectively. In December 2017, hearings before an ALJ were held and the evidentiary record for the case was closed. Provisional rates, subject to refund, were implemented on Jan. 1, 2018. As discussed above, PSCo and the CPUC Staff filed a non-unanimous settlement agreement to address the impacts of the TCJA on rates to be effective in 2018, which was approved by the ALJ. On Jan. 31, 2018, the CPUC ordered deferred accounting for the impacts of TCJA and opened a statewide TCJA proceeding, as discussed above. The CPUC is expected to rule on the regulatory treatment of the TCJA and the natural gas rate case later in 2018. Annual Electric Earnings Test — PSCo must share with customers earnings that exceed the authorized ROE of 9.83 percent for 2015 through 2017, as part of an annual earnings test. PSCo estimates the 2017 earnings test will not result in a customer refund obligation. PSCo will file its 2017 earnings test with the CPUC in April 2018. The final sharing obligation, if any, will be based on the CPUC approved tariff and could vary from the current estimate. Electric, Purchased Gas and Resource Adjustment Clauses DSM and the DSMCA riders — Energy efficiency and DSM costs are recovered through a combination of the DSMCA riders and base rates. DSMCA riders are adjusted biannually to capture program costs, performance incentives, and any over- or underrecoveries are trued-up in the following year. Performance incentives are awarded in the year following plan achievements. PSCo is able to earn $5 million upon reaching its annual savings goal along with an incentive on five percent of net economic benefits up to a maximum annual incentive of $30 million. In 2017, PSCo earned an electric and natural gas DSM incentive of $11 million and $3 million, respectively, for achieving its 2016 electric and natural gas savings goals. For 2018, the electric energy savings goal is 400 GWh with a spending limit of $84 million. 12. Commitments and Contingencies Commitments Capital Commitments — PSCo has made commitments in connection with a portion of its projected capital expenditures. PSCo’s capital commitments primarily relate to the following major projects: 68 Table of Contents Advanced Grid Intelligence and Security Initiative — PSCo is pursuing projects to update and advance its electric distribution grid to increase reliability and security standards, meet customer expectations, offer additional customer choice and control over energy usage and implement new rate structures. Rush Creek Wind Farm — PSCo has gained approval to build, own and operate a 600 MW wind generation facility and proposed transmission line in Colorado. Gas Transmission Integrity Management Programs — PSCo is proactively identifying and addressing the safety and reliability of natural gas transmission pipelines. The pipeline integrity efforts include primarily pipeline assessment and maintenance projects. Electric Distribution Integrity Management Programs — PSCo is assessing aging infrastructure for distribution assets and replacing worn components to increase system performance. Fuel Contracts — PSCo has entered into various long-term commitments for the purchase and delivery of a significant portion of its current coal and natural gas requirements. These contracts expire in various years between 2018 and 2060. PSCo is required to pay additional amounts depending on actual quantities shipped under these agreements. The estimated minimum purchases for PSCo under these contracts as of Dec. 31, 2017, are as follows: (Millions of Dollars) Coal 2018 2019 2020 2021 2022 Thereafter Total $ $ Natural gas storage and transportation Natural gas supply 160 97 69 37 38 184 585 $ $ 344 286 275 278 126 57 1,366 $ $ 114 112 111 109 109 605 1,160 Additional expenditures for fuel and natural gas storage and transportation will be required to meet expected future electric generation and natural gas needs. PSCo’s risk of loss, in the form of increased costs from market price changes in fuel, is mitigated through the use of natural gas and energy cost-rate adjustment mechanisms, which provide for pass-through of most fuel, storage and transportation costs to customers. PPAs — PSCo has entered into PPAs with other utilities and energy suppliers with expiration dates through 2034 for purchased power to meet system load and energy requirements and meet operating reserve obligations. In general, these agreements provide for energy payments, based on actual energy delivered and capacity payments. Certain PPAs accounted for as executory contracts also contain minimum energy purchase commitments. Capacity and energy payments are typically contingent on the independent power producing entity meeting contract obligations, including plant availability requirements. Contractual payments are adjusted based on market indices. The effects of price adjustments on our financial results are mitigated through purchased energy cost recovery mechanisms. Included in electric fuel and purchased power expenses for PPAs, accounted for as executory contracts, were payments for capacity of $25 million, $44 million and $70 million in 2017, 2016 and 2015, respectively. At Dec. 31, 2017, the estimated future payments for capacity that PSCo is obligated to purchase pursuant to these executory contracts, subject to availability, are as follows: (Millions of Dollars) 2018 2019 2020 2021 2022 Thereafter Total Capacity $ 22 12 4 4 4 14 60 $ Additional energy payments under these PPAs and PPAs accounted for as operating leases will be required to meet expected future electric demand. 69 Table of Contents Leases — PSCo leases a variety of equipment and facilities. Three of these leases are accounted for as capital leases. The assets and liabilities at the inception of a capital lease are recorded at the lower of fair market value or the present value of future lease payments and are amortized over the term of the contract. WYCO is a joint venture between Xcel Energy Inc. and Colorado Interstate Gas Company, LLC (CIG) to develop and lease natural gas pipeline, storage, and compression facilities. Xcel Energy Inc. has a 50 percent ownership interest in WYCO, and PSCo has no direct ownership interest. WYCO generally leases its facilities to CIG, and CIG operates the facilities, providing natural gas storage services to PSCo under separate service agreements. PSCo accounts for its Totem natural gas storage service arrangement with CIG as a capital lease. As a result, PSCo had $124 million and $127 million of capital lease obligations as of Dec. 31, 2017 and 2016, respectively. PSCo records amortization for its capital leases as cost of natural gas sold and transported on the consolidated statements of income. Total amortization expenses under capital lease assets were approximately $5 million, $8 million, and $8 million for 2017, 2016 and 2015, respectively. Following is a summary of property held under capital leases: (Millions of Dollars) Dec. 31, 2017 Gas storage facilities Gas pipeline Property held under capital leases Accumulated depreciation Total property held under capital leases, net $ Dec. 31, 2016 200.5 $ 20.7 221.2 (70.6) 150.6 $ $ 200.5 20.7 221.2 (65.3) 155.9 The remainder of the leases, primarily for office space, railcars, generating facilities, vehicles, aircraft and power-operated equipment, are accounted for as operating leases. Total expenses under operating lease obligations were approximately $109 million, $118 million and $130 million for 2017, 2016 and 2015, respectively. These expenses include capacity payments for PPAs accounted for as operating leases of $96 million, $102 million and $114 million in 2017, 2016 and 2015, respectively, recorded to electric fuel and purchased power expenses. Included in the future commitments under operating leases are estimated future capacity payments under PPAs that have been accounted for as operating leases in accordance with the applicable accounting guidance. Future commitments under operating and capital leases are: (Millions of Dollars) 2018 2019 2020 2021 2022 Thereafter Total minimum obligation Interest component of obligation Present value of minimum obligation (a) (b) PPA (a) (b) Operating Leases Operating Leases $ 10 10 10 9 8 34 $ 96 97 98 99 87 394 Total Operating Leases $ 106 107 108 108 95 428 Capital Leases $ $ 25 25 25 24 21 442 562 (411) 151 Amounts do not include PPAs accounted for as executory contracts. PPA operating leases contractually expire through 2034. Variable Interest Entities — The accounting guidance for consolidation of variable interest entities requires enterprises to consider the activities that most significantly impact an entity’s financial performance, and power to direct those activities, when determining whether an enterprise is a variable interest entity’s primary beneficiary. 70 Table of Contents PPAs — Under certain PPAs, PSCo purchases power from independent power producing entities 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 independent power producing entity. PSCo has determined that certain independent power producing entities are variable interest entities. PSCo is not subject to risk of loss from the operations of these entities, and no significant financial support has been, or is required to be provided other than contractual payments for energy and capacity set forth in the PPAs. PSCo has evaluated each of these variable interest entities for possible consolidation, including review of qualitative factors such as the length and terms of the contract, control over O&M, control over dispatch of electricity, historical and estimated future fuel and electricity prices, and financing activities. PSCo has concluded that these entities are not required to be consolidated in its consolidated financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance. PSCo had approximately 1,571 MW of capacity under long-term PPAs at both Dec. 31, 2017 and 2016 with entities that have been determined to be variable interest entities. These agreements have expiration dates through the year 2032. Environmental Contingencies PSCo has been or is currently involved with the cleanup of contamination from certain hazardous substances at several sites. In many situations, PSCo believes it will recover some portion of these costs through insurance claims. Additionally, where applicable, PSCo is pursuing, or intends to pursue, recovery from other PRPs and through the regulated rate process. New and changing federal and state environmental mandates can also create added financial liabilities for PSCo, which are normally recovered through the regulated rate process. To the extent any costs are not recovered through the options listed above, PSCo would be required to recognize an expense. Site Remediation — Various federal and state environmental laws impose liability, without regard to the legality of the original conduct, where hazardous substances or other regulated materials have been released to the environment. PSCo may sometimes pay all or a portion of the cost to remediate sites where past activities of PSCo or other parties have caused environmental contamination. Environmental contingencies could arise from various situations, including sites of former MGPs operated by PSCo, its predecessors, or other entities; and third-party sites, such as landfills, for which PSCo is alleged to be a PRP that sent wastes to that site. Other MGP, Landfill or Disposal Sites — PSCo is currently involved in investigating and/or remediating several MGP, landfill or other disposal sites. PSCo has identified three sites where contamination is present and where investigation and/or remediation activities are currently underway. Other parties may have responsibility for some portion of the investigation and/or remediation activities that are underway. PSCo anticipates that these investigation or remediation activities will continue through at least 2018. PSCo had accrued an immaterial amount and $2 million for all of these sites as of Dec. 31, 2017 and 2016, respectively. There may be insurance recovery and/or recovery from other PRPs that will offset any costs incurred. PSCo anticipates that any amounts spent will be fully recovered from customers. Environmental Requirements Water and Waste Asbestos Removal — Some of PSCo’s facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that contain it are demolished or removed. PSCo has recorded an estimate for final removal of the asbestos as an ARO. It may be necessary to remove some asbestos to perform maintenance or make improvements to other equipment. The cost of removing asbestos as part of other work is not expected to be material and is recorded as incurred as operating expenses for maintenance projects, capital expenditures for construction projects or removal costs for demolition projects. 71 Table of Contents Coal Ash Regulation — PSCo’s operations are subject to federal and state laws that impose requirements for handling, storage, treatment and disposal of solid waste. In 2015, the EPA published a final rule regulating the management, storage, and disposal of coal combustion residuals (CCRs) as a nonhazardous waste (CCR Rule). Industry and environmental non-governmental organizations sought judicial review of the final CCR Rule, but a final decision has not been issued in that litigation. The EPA announced in late 2017 its intent to revise the CCR Rule. It is anticipated that the EPA will publish the revised rule in the first quarter of 2018. Under the CCR Rule, utilities were required to complete groundwater sampling around their CCR landfills and surface impoundments and to analyze the results by early 2018 to determine if there were any statistically significant increases (SSIs) above background levels of certain constituents in the groundwater. PSCo has identified SSIs at several sites. Going forward, PSCo will either conduct additional groundwater sampling to determine whether another source besides plant operations is impacting groundwater and/or to determine if corrective action is needed. Several PSCo sites where SSIs were identified were already undergoing cessation of coal operations and closure of the on-site coal units and therefore no further corrective action is expected at those sites. Until a final decision is reached in the litigation, the EPA publishes its revised rule, and PSCo completes additional groundwater sampling, it is uncertain what impact, if any, there will be on the operations, financial position or cash flows of PSCo. PSCo believes that any associated costs would be recoverable through regulatory mechanisms. Federal CWA Waters of the United States Rule — In 2015, the EPA 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 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 final rule and reinstates the prior definition of “Water of the U.S.” The agencies are also undertaking a rulemaking to develop a new definition of “Waters of the U.S.” Federal CWA Effluent Limitations Guidelines (ELG) — In 2015, the EPA issued a final ELG rule for power plants that use coal, natural gas, oil or nuclear materials as fuel and discharge treated effluent to surface waters as well as utility-owned landfills that receive coal combustion residuals. In 2017, the EPA delayed the compliance date for flue gas desulfurization wastewater and bottom ash transport until November 2020 while the agency conducts a rulemaking process to potentially revise the effluent limitations and pretreatment standards for these waste streams. Federal CWA Section 316(b) — The federal CWA requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available for minimizing adverse environmental impacts to aquatic species. The EPA published the final 316(b) rule in 2014. The rule prescribes technology for protecting fish that get stuck on plant intake screens (known as impingement) and describes a process for site-specific determinations by each state for sites that must protect the small aquatic organisms that pass through the intake screens into the plant cooling systems (known as entrainment). PSCo does not anticipate the cost of compliance will have a material impact on its results of operations, financial position or cash flows. Air GHG Emission Standard for Existing Sources (CPP) — In 2015, the EPA issued its final CPP rule for existing power plants. Among other things, the CPP requires that state plans include enforceable measures to ensure emissions from existing power plants achieve the EPA’s state-specific interim and final emission performance targets. 72 Table of Contents The CPP was challenged by multiple parties in the D.C. Circuit Court. In February 2016, the U.S. Supreme Court issued an order staying the final CPP rule. The stay will remain in effect until the D.C. Circuit Court reaches its decision and the U.S. Supreme Court either declines to review the lower court’s decision or reaches a decision of its own. In March 2017, President Trump signed an executive order requiring the EPA Administrator to review the CPP rule and if appropriate publish proposed rules suspending, revising or rescinding it. Accordingly, the EPA requested that the D.C. Circuit Court hold the litigation in abeyance until the EPA completes its work under the executive order. The D.C. Circuit granted the EPA’s request and is holding the litigation in abeyance, while considering briefs by the parties on whether the court should remand the challenges to the EPA rather than holding them in abeyance, determining whether and how the court continues or ends the stay that currently applies to the CPP. In October 2017, the EPA published a proposed rule to repeal the CPP, based on an analysis that the CPP exceeds the EPA’s statutory authority under the CAA. In the proposal, the EPA stated it has not yet determined whether it will promulgate a new rule to regulate GHG emissions from existing EGUs. In December 2017, the EPA issued an Advanced Notice of Proposed Rulemaking to take and consider comments on whether to issue a future rule and what such a rule should include. Implementation of the NAAQS for SO2 — The EPA adopted a more stringent NAAQS for SO2 in 2010, and evaluated areas in in three phases. In December 2017, the EPA adopted a final rule that completed its initial designations of areas attaining or not attaining the standard. The EPA’s final actions designate all areas near PSCo’s generating plants as meeting the SO2 NAAQS with one exception. In June 2016, the EPA issued final designations which found the area near the Pawnee plant is “unclassifiable.” Since the 2016 “unclassifiable” designation, the Colorado Department of Public Health and Environment has prepared and submitted air dispersion modeling to the EPA demonstrating that the area near the Pawnee plant meets the SO2 NAAQS. The EPA has not yet completed its evaluation of the Pawnee plant. Revisions to the NAAQS for Ozone — In 2015, the EPA revised the NAAQS for ozone by lowering the eight-hour standard from 75 parts per billion (ppb) to 70 ppb. In November 2017, the EPA published final designations of areas that meet the 2015 ozone standard. Xcel Energy meets the 2015 ozone standard in all areas where its generating units operate, except for the Denver Metropolitan Area. PSCo’s scheduled retirement of coal fired plants in Denver that began in 2011 and was completed in August 2017, should help in any plan to mitigate non-attainment. The EPA has not yet taken final action on the designation, but notified the State of Colorado in December 2017 that it intends to designate the parts of the Denver Metropolitan Area that currently do not attain the 2008 ozone standards as also not attaining the more stringent 2015 ozone standard. Asset Retirement Obligations Recorded AROs — AROs have been recorded for property related to the following: electric production (steam, wind, other and hydro), electric distribution and transmission, natural gas production, natural gas transmission and distribution, natural gas storage, thermal and common general property. The electric production obligations include asbestos, processed water and ash-containment facilities, radiation sources, storage tanks and control panels. The asbestos recognition associated with electric production includes certain specific plants. The AROs recorded for PSCo steam and other production relate to processed water and ash-containment facilities such as ash ponds, evaporation ponds and solid waste landfills. PSCo has also recorded AROs for the retirement and removal of assets at certain wind production facilities for which the land is leased and removal is required by contract. PSCo recognized AROs for the retirement costs of natural gas mains and lines and for the retirement of above ground gas gathering equipment, impoundments at gas extraction sites and wells related to gas storage facilities. In addition, an ARO was recognized for the removal of electric transmission and distribution equipment, which consists of obligations associated with polychlorinated biphenyl, mineral oil, lithium batteries, mercury and street lighting lamps. The common general ARO includes obligations related to storage tanks. 73 Table of Contents A reconciliation of PSCo’s AROs for the years ended Dec. 31, 2017 and 2016 is as follows: (Thousands of Dollars) Electric plant Steam and other production ash containment Steam, hydro, and other production asbestos Electric distribution Wind production Other Natural gas plant Gas transmission and distribution Other Common and other property Common miscellaneous Total liability (a) (b) (c) Beginning Balance Jan. 1, 2017 $ 40,450 7,669 2,072 1,520 (12,047) — — (204) 1,917 274 20 66 160,719 4,080 — (354) 6,649 159 — (24,673) $ 17 12,261 $ $ $ Ending Balance (c) Dec. 31, 2017 9,573 $ (458) — — — 29,862 7,943 2,092 1,382 61,503 — — 70,618 $ 73,264 228,871 3,885 $ 470 347,769 The liabilities settled relate to asbestos abatement projects, the closure of certain ash containment facilities, and removal and proper disposal of storage tanks and other above ground equipment. In 2017, AROs were revised for changes in estimated cash flows and the timing of those cash flows. Changes in the gas transmission and distribution AROs were mainly related to increased labor costs. There were no ARO liabilities recognized during the year ended Dec. 31, 2017. Electric plant Steam, hydro, and other production asbestos Steam and other production ash containment Wind production Electric distribution Other Natural gas plant Gas transmission and distribution Other Common and other property Common miscellaneous Total liability (b) 3,159 453 289,563 Beginning Balance Jan. 1, 2016 (Thousands of Dollars) (a) Cash Flow(b) Revisions Accretion (12,068) $ 72,600 $ Liabilities (a) Settled $ $ 38,676 Liabilities Recognized $ Cash Flow Revisions (a) Accretion — $ 1,877 $ (103) $ Ending Balance Dec. 31, 2016 (b) 40,450 70,767 1,992 1,130 1,054 — — — 214 3,078 19 45 46 (1,245) 61 6,494 206 72,600 2,072 7,669 1,520 122,168 3,925 — — 5,009 155 33,542 — 160,719 4,080 (371) 38,584 $ 453 289,563 796 240,508 — 214 $ $ 28 10,257 $ In 2016, AROs were revised for changes in estimated cash flows and the timing of those cash flows. Changes in the gas transmission and distribution AROs were mainly related to increased miles of gas mains. There were no ARO liabilities settled during the year ended Dec. 31, 2016. Indeterminate AROs — Outside of the known and recorded asbestos AROs, other plants or buildings may contain asbestos due to the age of many of PSCo’s facilities, but no confirmation or measurement of the amount of asbestos or cost of removal could be determined as of Dec. 31, 2017. Therefore, an ARO has not been recorded for these facilities. 74 Table of Contents Removal Costs — PSCo records a regulatory liability for the plant removal costs of generation, transmission and distribution facilities that are recovered currently in rates. Generally, the accrual of future non-ARO removal obligations is not required. However, longstanding ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for such costs in historical depreciation rates. These removal costs have accumulated over a number of years based on varying rates as authorized by the appropriate regulatory entities. Given the long time periods over which the amounts were accrued and the changing of rates over time, PSCo has estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates. Removal costs as of Dec. 31, 2017 and 2016 were $346 million and $367 million, respectively. Legal Contingencies PSCo is involved in various litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on PSCo’s financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred. Employment, Tort and Commercial Litigation Line Extension Disputes — In December 2015, Development Recovery Company (DRC) filed a lawsuit in the Denver District Court, stating PSCo failed to award proper allowances and refunds for line extensions to new developments pursuant to the terms of electric and gas service agreements entered into by PSCo and various developers. The dispute involves claims by over fifty developers. In May 2016, the Denver District Court granted PSCo’s motion to dismiss the lawsuit, concluding that jurisdiction over this dispute resides with the CPUC. In June 2016, DRC appealed the Denver District Court’s dismissal of the lawsuit, and the Colorado Court of Appeals affirmed the lower court decision in favor of PSCo. In July 2017, DRC filed a petition to appeal the decision with the Colorado Supreme Court. In February 2018, the Colorado Supreme Court denied DRC’s petition effectively terminating this litigation. In January 2018, DRC filed a new lawsuit in Boulder County District Court, asserting a single claim that PSCo was required to file its line extension agreements with the CPUC but failed to do so. This claim is substantially similar to the arguments previously raised by DRC. Dates for this proceeding have not been scheduled. PSCo has concluded that a loss is remote with respect to both of these matters as the service agreements were developed to implement CPUC approved tariffs and PSCo has complied with the tariff provisions. Also, if 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. Other Contingencies See Note 11 for further discussion. 13. Regulatory Assets and Liabilities PSCo’s consolidated financial statements are prepared in accordance with the applicable accounting guidance, as discussed in Note 1. Under this guidance, regulatory assets and liabilities are created for amounts that regulators may allow to be collected, or may require to be paid back to customers in future electric and natural gas rates. Any portion of the business that is not rate regulated cannot establish regulatory assets and liabilities. If changes in the utility industry or the business of PSCo no longer allow for the application of regulatory accounting guidance under GAAP, PSCo would be required to recognize the write-off of regulatory assets and liabilities in net income or OCI. 75 Table of Contents The components of regulatory assets shown on the consolidated balance sheets of PSCo at Dec. 31, 2017 and 2016 are: (Thousands of Dollars) See Note(s) Remaining Amortization Period Dec. 31, 2017 Regulatory Assets Pension and retiree medical obligations Recoverable deferred taxes on AFUDC recorded in plant (b) Net AROs (c) Depreciation differences Excess deferred taxes - TCJA Purchased power contract costs Property tax Gas pipeline inspection costs Conservation programs (d) Losses on reacquired debt Contract valuation adjustments (e) (a) 8 1 1, 12 1 7 12 12 1, 11 4 10 (b) (c) (d) (e) Noncurrent Current Noncurrent $ 28,010 $ 565,241 $ 27,270 $ 568,258 — — 19,835 — 1,261 — 1,791 6,942 1,203 6,022 86,966 80,476 69,428 53,937 28,009 16,047 7,743 5,528 4,916 2,638 — — 15,363 — 1,035 9,393 — 9,262 1,203 3,444 151,022 78,050 90,426 — 29,029 1,653 4,405 6,986 6,120 6,082 12,273 $ 77,337 29,329 $ 950,258 36,813 $ 103,783 16,398 $ 958,429 Plant lives Plant lives One to fourteen years Various Term of related contract Pending rate cases One to two years One to two years Term of related debt Term of related contract Various Other Total regulatory assets (a) Various Dec. 31, 2016 Current Includes $3.4 million and $4.2 million of regulatory assets related to the nonqualified pension plan, of which $0.3 million and $0.4 million is included in the current asset at Dec. 31, 2017 and 2016, respectively. Includes a write-down of $75.9 million as a result of the revaluation of deferred tax gross up at the new federal tax rate at Dec. 31, 2017. Includes amounts recorded for future recovery of AROs. Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases. The components of regulatory liabilities shown on the consolidated balance sheets of PSCo at Dec. 31, 2017 and 2016 are: (Thousands of Dollars) See Note(s) Remaining Amortization Period Dec. 31, 2017 Regulatory Liabilities Excess deferred taxes - TCJA (a) Plant removal costs Renewable resources and environmental initiatives Investment tax credit deferrals Deferred income tax adjustment Deferred electric, natural gas and steam production costs Conservation programs (b) Other Total regulatory liabilities (c) (a) (b) (c) Current 7 1, 12 Various Plant lives 11, 12 Various 1, 7 Various 1 Various 1 1, 11 Less than one year Less than one year Various $ Dec. 31, 2016 Noncurrent Current $ — — Noncurrent — — $1,445,079 346,174 $ — 367,440 — — — 56,153 17,088 16,301 3,600 — — 67,728 18,797 16,260 29,078 21,168 15,880 $ 66,126 — — 52,693 $1,933,488 35,123 24,077 38,310 $ 101,110 — — 42,708 $ 512,933 Primarily relates to the revaluation of recoverable/regulated plant ADIT and $49.6 million revaluation impact of non-plant ADIT at Dec. 31, 2017. Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. Revenue subject to refund of $0 million and $2.4 million for 2017 and 2016, respectively, is included in other current liabilities. At Dec. 31, 2017 and 2016, approximately $44 million and $28 million of PSCo’s regulatory assets represented past expenditures not currently earning a return, respectively. This amount primarily includes certain expenditures associated with property taxes and renewable resources and environmental initiatives. 76 Table of Contents 14. Other Comprehensive Income Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31, 2017 and 2016 were as follows: Year Ended Dec. 31, 2017 (Thousands of Dollars) Accumulated other comprehensive loss at Jan. 1 Other comprehensive loss before reclassifications Losses reclassified from net accumulated other comprehensive loss Net current period other comprehensive income Adoption of ASU No. 2018-02 (a) Accumulated other comprehensive loss at Dec. 31 (a) Defined Benefit and Postretirement Items Gains and Losses on Cash Flow Hedges $ $ Total (22,780) $ — 1,005 1,005 (220) $ (5) 5 — (23,000) (5) 1,010 1,005 (4,690) (26,465) $ (47) (267) $ (4,737) (26,732) In 2017, PSCo implemented ASU No. 2018-02 related to the TCJA, which resulted in reclassification of certain credit balances within net accumulated other comprehensive loss to retained earnings. For further information, see Note 2. Year Ended Dec. 31, 2016 Gains and Losses on Cash Flow Hedges (Thousands of Dollars) Accumulated other comprehensive loss at Jan. 1 Other comprehensive loss before reclassifications Losses reclassified from net accumulated other comprehensive loss Net current period other comprehensive income (loss) Accumulated other comprehensive loss at Dec. 31 $ $ Defined Benefit and Postretirement Items (23,836) $ — 1,056 1,056 (22,780) $ Total — $ (223) 3 (220) (220) $ (23,836) (223) 1,059 836 (23,000) Reclassifications from accumulated other comprehensive loss for the years ended Dec. 31, 2017 and 2016 were as follows: Amounts Reclassified from Accumulated Other Comprehensive Loss Year Ended Dec. 31, 2017 (Thousands of Dollars) Losses (gains) on cash flow hedges: Interest rate derivatives Vehicle fuel derivatives Total, pre-tax Tax benefit Total, net of tax Defined benefit pension and postretirement losses (gains): Amortization of net losses Total, pre-tax Tax benefit Total, net of tax Total amounts reclassified, net of tax (a) (b) (c) $ $ Year Ended Dec. 31, 2016 1,615 — 1,615 (610) 1,005 (a) 9 9 (4) 5 1,010 (c) (b) $ $ Included in interest charges. Included in O&M expenses. Included in the computation of net periodic pension and postretirement benefit costs. See Note 8 for details regarding these benefit plans. 77 1,618 86 1,704 (648) 1,056 (a) 5 5 (2) 3 1,059 (c) (b) Table of Contents 15. Segments and Related Information Operating results from the regulated electric utility and regulated natural gas utility are each separately and regularly reviewed by PSCo’s chief operating decision maker. PSCo evaluates performance based on profit or loss generated from the product or service provided. These segments are managed separately because the revenue streams are dependent upon regulated rate recovery, which is separately determined for each segment. PSCo has the following reportable segments: regulated electric utility, regulated natural gas utility and all other. • • • PSCo’s regulated electric utility segment generates electricity which is transmitted and distributed in Colorado. In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States. Regulated electric utility also includes PSCo’s wholesale commodity and trading operations. PSCo’s regulated natural gas utility segment transports, stores and distributes natural gas in portions of Colorado. Revenues from operating segments not included above are below the necessary quantitative thresholds and are therefore included in the all other category. Those primarily include steam revenue, appliance repair services and nonutility real estate activities. Asset and capital expenditure information is not provided for PSCo’s reportable segments because as an integrated electric and natural gas utility, PSCo operates significant assets that are not dedicated to a specific business segment, and reporting assets and capital expenditures by business segment would require arbitrary and potentially misleading allocations which may not necessarily reflect the assets that would be required for the operation of the business segments on a stand-alone basis. To report income from operations for regulated electric and regulated natural gas utility segments, the majority of costs are directly assigned to each segment. However, some costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation allocators. A general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising. The accounting policies of the segments are the same as those described in Note 1. Regulated Electric (Thousands of Dollars) 2017 Operating revenues (a) Intersegment revenues Total revenues Depreciation and amortization Interest charges and financing costs Income tax expense (benefit) Net income $ 3,003,808 288 $ 3,004,096 $ $ $ Depreciation and amortization Interest charges and financing costs Income tax expense (benefit) Net income 353,560 138,565 243,604 370,636 $ Regulated Electric (Thousands of Dollars) 2016 Operating revenues (a) Intersegment revenues Total revenues Regulated Natural Gas $ $ $ 337,583 136,274 228,825 383,973 78 995,214 344 995,558 $ 113,253 40,214 18,398 107,822 $ $ Regulated Natural Gas $ 3,049,352 275 $ 3,049,627 $ Reconciling Eliminations All Other 43,487 — 43,487 $ $ 4,702 $ 508 (9,823) 15,661 957,721 110 957,831 $ 101,663 37,881 45,960 75,426 $ $ 40,723 — 40,723 — $ 4,042,509 (632) — (632) $ 4,042,509 — — — — Reconciling Eliminations All Other $ $ 4,309 $ 431 (867) 4,092 Consolidated Total $ 471,515 179,287 252,179 494,119 Consolidated Total — $ 4,047,796 (385) — (385) $ 4,047,796 — — — — $ 443,555 174,586 273,918 463,491 Table of Contents Regulated Electric Regulated Natural Gas $ 3,115,257 301 $ 3,115,558 $ 1,006,666 67 $ 1,006,733 $ $ $ $ (Thousands of Dollars) 2015 Operating revenues (a) Intersegment revenues Total revenues Depreciation and amortization Interest charges and financing costs Income tax expense (benefit) Net income (a) 311,122 136,397 234,873 391,257 96,384 34,935 44,192 74,267 Reconciling Eliminations All Other 41,590 — 41,590 $ $ Consolidated Total — $ 4,163,513 (368) — (368) $ 4,163,513 $ 4,161 $ 576 (625) 1,278 — — — — $ 411,667 171,908 278,440 466,802 Operating revenues include $6 million, $13 million and $13 million of intercompany revenue for the years ended Dec. 31, 2017, 2016 and 2015, respectively. See Note 16 for further discussion of related party transactions by reportable segment. 16. Related Party Transactions Xcel Energy Services Inc. provides management, administrative and other services for the subsidiaries of Xcel Energy Inc., including PSCo. The services are provided and billed to each subsidiary in accordance with service agreements executed by each subsidiary. PSCo uses services provided by Xcel Energy Services Inc. whenever possible. Costs are charged directly to the subsidiary and are allocated if they cannot be directly assigned. Xcel Energy Inc., NSP-Minnesota, PSCo and SPS have established a utility money pool arrangement. See Note 4 for further discussion. The table below contains significant affiliate transactions among the companies and related parties for the years ended Dec. 31: (Thousands of Dollars) 2017 Operating revenues: Electric Other Operating expenses: Purchased power Other operating expenses — paid to Xcel Energy Services Inc. Interest expense Interest income $ 1,436 4,492 2016 $ 2015 8,809 4,525 2 485,066 — — $ 56 446,086 149 — 8,632 4,441 — 414,620 211 45 Accounts receivable and payable with affiliates at Dec. 31 were: 2017 Accounts Receivable (Thousands of Dollars) NSP-Minnesota NSP-Wisconsin SPS Other subsidiaries of Xcel Energy Inc. $ $ 2016 Accounts Payable 7,738 61 279 6,641 14,719 $ $ — — — 58,748 58,748 Accounts Receivable $ $ 7,669 974 745 33 9,421 Accounts Payable $ $ — — — 98,797 98,797 17. Summarized Quarterly Financial Data (Unaudited) Quarter Ended (Thousands of Dollars) March 31, 2017 Operating revenues Operating income Net income $ 1,080,534 212,422 111,546 79 June 30, 2017 $ 930,916 192,811 100,587 Sept. 30, 2017 Dec. 31, 2017 $ 1,030,293 326,028 186,077 $ 1,000,766 154,669 95,909 Table of Contents Quarter Ended (Thousands of Dollars) March 31, 2016 Operating revenues Operating income Net income $ 1,057,841 223,190 115,874 June 30, 2016 $ 909,852 180,629 87,344 Sept. 30, 2016 Dec. 31, 2016 $ 1,059,177 315,605 173,607 $ 1,020,926 170,197 86,666 Item 9 — Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None. Item 9A — Controls and Procedures Disclosure Controls and Procedures PSCo maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer (CEO) and chief financial officer (CFO), allowing timely decisions regarding required disclosure. As of Dec. 31, 2017, 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 No change in PSCo’s internal control over financial reporting has occurred during the most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, PSCo’s internal control over financial reporting. PSCo maintains internal control over financial reporting to provide reasonable assurance regarding the reliability of the financial reporting. PSCo has evaluated and documented its controls in process activities, general computer activities, and on an entity-wide level. During the year and in preparation for issuing its report for the year ended Dec. 31, 2017 on internal controls under section 404 of the Sarbanes-Oxley Act of 2002, PSCo conducted testing and monitoring of its internal control over financial reporting. Based on the control evaluation, testing and remediation performed, PSCo did not identify any material control weaknesses, as defined under the standards and rules issued by the Public Company Accounting Oversight Board and as approved by the SEC and as indicated in Management Report on Internal Controls herein. In 2016, PSCo implemented the general ledger modules of a new enterprise resource planning system to improve certain financial and related transaction processes. PSCo implemented additional work management systems modules in 2017. PSCo updated its internal control over financial reporting, as necessary, to accommodate modifications to its business processes and accounting systems. PSCo does not believe that this implementation had an adverse effect on its internal control over financial reporting. This annual report does not include an attestation report of PSCo’s independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by PSCo’s independent registered public accounting firm pursuant to the rules of the SEC that permit PSCo to provide only management’s report in this annual report. Item 9B — Other Information None. PART III Items 10, 11, 12 and 13 of Part III of Form 10-K have been omitted from this report for PSCo in accordance with conditions set forth in general instructions I (1) (a) and (b) of Form 10-K for wholly-owned subsidiaries. Item 10 — Directors, Executive Officers and Corporate Governance Item 11 — Executive Compensation 80 Table of Contents Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters Item 13 — Certain Relationships and Related Transactions, and Director Independence Information required under this Item is contained in Xcel Energy Inc.’s Proxy Statement for its 2018 Annual Meeting of Shareholders, which is incorporated by reference. Item 14 — Principal Accountant Fees and Services The information required by Item 14 of From 10-K is set forth under the heading “Independent Registered Public Accounting Firm Audit and Non-Audit Fees” in Xcel Energy Inc.’s definitive Proxy Statement for the 2018 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about April 3, 2018. Such information set forth under such heading is incorporated herein by this reference hereto. 81 Table of Contents PART IV Item 15 — Exhibits, Financial Statement Schedules 1. Consolidated Financial Statements: Management Report on Internal Controls Over Financial Reporting — For the year ended Dec. 31, 2017. Report of Independent Registered Public Accounting Firm — Financial Statements Consolidated Statements of Income — For the three years ended Dec. 31, 2017, 2016, and 2015. Consolidated Statements of Comprehensive Income — For the three years ended Dec. 31, 2017, 2016, and 2015. Consolidated Statements of Cash Flows — For the three years ended Dec. 31, 2017, 2016, and 2015. Consolidated Balance Sheets — As of Dec. 31, 2017 and 2016. Consolidated Statements of Common Stockholder’s Equity — For the three years ended Dec. 31, 2017, 2016 and 2015. Consolidated Statements of Capitalization — As of Dec. 31, 2017 and 2016. 2. 3. Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2017, 2016, and 2015. Exhibits * + Indicates incorporation by reference Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors Certain portions of this agreement have been omitted pursuant to a request for confidential treatment and have been filed separately with the SEC. t 3.01* 3.02* Amended and Restated Articles of Incorporation dated July 15, 1998 (Exhibit 3.01 to Form 10-Q for the quarter ended Sept. 30, 2017 (file no. 001-03280)). By-Laws of PSCo as Amended and Restated on Sept. 26, 2013 (Exhibit 3.02 to Form 10-Q/A for the quarter ended Sept. 30, 2013 (file no. 001-03280)). 4.01* Indenture, dated as of Oct. 1, 1993, between PSCo and Morgan Guaranty Trust Company of New York, as trustee, providing for the issuance of First Collateral Trust Bonds (Exhibit 4.34 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2017). 4.02* Indenture dated July 1, 1999, between PSCo and The Bank of New York, providing for the issuance of Senior Debt Securities and First Supplemental Indenture dated July 15, 1999, between PSCo and The Bank of New York (Exhibits 4.1 and 4.2 to Form 8-K (file no. 001-03280) dated July 13, 1999). Supplemental Indenture, dated Aug. 1, 2007, between PSCo and U.S. Bank Trust National Association, as successor Trustee (Exhibit 4.01 to PSCo Form 8-K (file no. 001-03280) dated Aug. 18, 2007). Supplemental Indenture dated as of Aug. 1, 2008, between PSCo and U.S. Bank Trust National Association, as successor Trustee, creating $300 million principal amount of 5.80 percent First Mortgage Bonds, Series No. 18 due 2018 and $300 million principal amount of 6.50 percent First Mortgage Bonds, Series No. 19 due 2038 (Exhibit 4.01 of Form 8-K of PSCo dated Aug. 6, 2008 (file no. 001-03280)). Supplemental Indenture dated as of May 1, 2009 between PSCo and U.S. Bank Trust National Association, as successor Trustee, creating $400 million principal amount of 5.125 percent First Mortgage Bonds, Series No. 20 due 2019 (Exhibit 4.01 of Form 8-K of PSCo dated May 28, 2009 (file no. 001-03280)). Supplemental Indenture dated as of Nov. 1, 2010 between PSCo and U.S. Bank National Association, as successor Trustee, creating $400 million principal amount of 3.200 percent First Mortgage Bonds, Series No. 21 due 2020 (Exhibit 4.01 of Form 8-K of PSCo dated Nov. 18, 2010 (file no. 001-03280)). Supplemental Indenture dated as of Aug. 1, 2011 between PSCo and U.S. Bank National Association, as successor Trustee, creating $250 million principal amount of 4.75 percent First Mortgage Bonds, Series No. 22 due 2041 (Exhibit 4.01 to Form 8-K of PSCo dated Aug. 9, 2011 (file no. 001-03280)). Supplemental Indenture dated as of Sept. 1, 2012 between PSCo and U.S. Bank National Association, as successor Trustee, creating $300 million principal amount of 2.25 percent First Mortgage Bonds, Series No. 23 due 2022 and $500 million principal amount of 3.60 percent First Mortgage Bonds, Series No. 24 due 2042 (Exhibit 4.01 to Form 8-K dated Sept. 11, 2012 (file no. 001-03280)). Supplemental Indenture dated as of March 1, 2013 between PSCo and U.S. Bank National Association, as successor Trustee, creating $250 million principal amount of 2.50 percent First Mortgage Bonds, Series No. 25 due 2023 and $250 million principal amount of 3.95 percent First Mortgage Bonds, Series No. 26 due 2043 (Exhibit 4.01 to Form 8-K of PSCo dated March 26, 2013 (file no. 001-03280)). 4.03* 4.04* 4.05* 4.06* 4.07* 4.08* 4.09* 82 Table of Contents 4.10* Supplemental Indenture dated as of March 1, 2014 between PSCo and U.S. Bank National Association, as successor Trustee, creating $300 million principal amount of 4.30 percent First Mortgage Bonds, Series No. 27 due 2044. (Exhibit 4.01 to Form 8-K of PSCo dated March 10, 2014 (file no. 001-03280)). 4.11* Supplemental Indenture dated as of May 1, 2015 between PSCo and U.S. Bank National Association, as successor Trustee, creating $250 million principal amount of 2.90 percent First Mortgage Bonds, Series No. 28 due 2025. (Exhibit 4.01 to Form 8-K of PSCo dated May 12, 2015 (file no. 001-03280)). Supplemental Indenture dated as of June 1, 2016 between PSCo and U.S. Bank National Association, as successor Trustee, creating $250 million principal amount of 3.55 percent First Mortgage Bonds, Series No. 29 due 2046. (Exhibit 4.01 to Form 8-K of PSCo dated June 13, 2016 (file no. 001-03280)). Supplemental Indenture No. 27 dated as of June 1, 2017 between PSCo and U.S. Bank National Association, as Trustee, creating $400 million principal amount of 3.80 percent First Mortgage Bonds, Series No. 30 due 2047. (Exhibit 4.01 to Form 8-K of PSCo dated June 19, 2017 (file no. 001-03280)). Xcel Energy Inc. Nonqualified Pension Plan (2009 Restatement) (Exhibit 10.02 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008). Xcel Energy Senior Executive Severance and Change-in-Control Policy (2009 Amendment and Restatement) (Exhibit 10.05 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008). Xcel Energy Inc. Non-Employee Directors’ Deferred Compensation Plan as amended and restated on Jan. 1, 2009 (Exhibit 10.08 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008). Form of Services Agreement between Xcel Energy Services Inc. and utility companies (Exhibit H-1 to Form U5B (file no. 001-03034) dated Nov. 16, 2000). Xcel Energy Inc. Supplemental Executive Retirement Plan as amended and restated Jan. 1, 2009 (Exhibit 10.17 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008). Proposed Settlement Agreement excerpts, as filed with the CPUC (Exhibit 99.02 to Form 8-K of Xcel Energy (file no. 001-03034) dated Dec. 3, 2004). Amendment dated Aug. 26, 2009 to the Xcel Energy Senior Executive Severance and Change-in-Control Policy (Exhibit 10.06 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009). Xcel Energy Inc. Executive Annual Incentive Award Plan Form of Restricted Stock Agreement (Exhibit 10.08 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009). Xcel Energy Inc. Executive Annual Incentive Award Plan (as amended and restated effective Feb. 17, 2010) (incorporated by reference to Appendix A to Schedule 14A, Definitive Proxy Statement to Xcel Energy (file no. 001-03034) dated April 6, 2010). Xcel Energy Inc. 2005 Long-Term Incentive Plan (as amended and restated effective Feb. 17, 2010) (incorporated by reference to Appendix B to Schedule 14A, Definitive Proxy Statement to Xcel Energy (file no. 001-03034) dated April 6, 2010). Stock Equivalent Plan for Non-Employee Directors of Xcel Energy Inc. as amended and restated effective Feb. 23, 2011 (Appendix A to the Xcel Energy Definitive Proxy Statement (file no. 001-03034) filed Apr. 5, 2011). Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009 Restatement) (Exhibit 10.07 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008). First Amendment effective Nov. 29, 2011 to the Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009 Restatement) (Exhibit 10.17 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2011). 4.12* 4.13* 10.01*+ 10.02*+ 10.03*+ 10.04*+ 10.05*+ 10.06* 10.07*+ 10.08*+ 10.09*+ 10.10*+ 10.11*+ 10.12*+ 10.13*+ 10.14*+ 10.15*+ 10.16*+ 10.17*+ 10.18*+ 10.19*+ Second Amendment dated Oct. 26, 2011 to the Xcel Energy Senior Executive Severance and Change-in-Control Policy (Exhibit 10.18 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2011). First Amendment dated Feb. 20, 2013 to the Xcel Energy Inc. Executive Annual Incentive Award Plan (as amended and restated effective Feb. 17, 2010) (Exhibit 10.01 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended March 31, 2013). Fourth Amendment dated Feb. 20, 2013 to the Xcel Energy Senior Executive Severance and Change-in-Control Policy (Exhibit 10.02 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended March 31, 2013). First Amendment dated May 21, 2013 to the Xcel Energy Inc. 2005 Long-Term Incentive Plan (as amended and restated effective Feb. 17, 2010) (Exhibit 10.21 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2013). Second Amendment dated May 21, 2013 to the Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009 Restatement) (Exhibit 10.22 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2013). Xcel Energy Inc. 2005 Long-Term Incentive Plan Form of Long-Term Incentive Award Agreement (Exhibit 10.23 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2013). 83 Table of Contents 10.20*+ 10.21*+ 10.22*+ 10.23*+ 10.24*+ 10.25*+ 10.26* 10.27*+ 10.28*+ 10.29*+ 10.30*+ 12.01 23.01 31.01 31.02 32.01 99.01 101 Xcel Energy Inc. 2015 Omnibus Incentive Plan (incorporated by reference to Appendix B to Schedule 14A, Definitive Proxy Statement to Xcel Energy Inc. (file no. 001-03034) dated April 6, 2015). Stock Equivalent Program for Non-Employee Directors of Xcel Energy Inc. (As First Effective May 20, 2015) under the Xcel Energy Inc. 2015 Omnibus Incentive Plan. (Exhibit 10.02 to Form 8-K of Xcel Energy, dated May 26, 2015 (file no. 001-03034). Form of Xcel Energy Inc. 2015 Omnibus Incentive Plan Award Agreement and Award Terms and Conditions (Restricted Stock Units and Performance Share Units) under the Xcel Energy Inc. 2015 Omnibus Incentive Plan. (Exhibit 10.03 to Form 8-K of Xcel Energy, dated May 26, 2015 (file no. 001-03034). Xcel Energy Inc. 2015 Omnibus Incentive Plan Form of Award Agreement. (Exhibit 10.28 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2015). Xcel Energy Inc. Executive Annual Incentive Award Sub-plan pursuant to the Xcel Energy Inc. 2015 Omnibus Incentive Plan. (Exhibit 10.29 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2015). Fifth Amendment dated May 3, 2016 to the Xcel Energy Senior Executive Severance and Change-in-Control Policy (Exhibit 10.01 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended June 30, 2016). Second Amended and Restated Credit Agreement, dated as of June 20, 2016 among PSCo, as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A. and Barclays Bank Plc, as Syndication Agents, and Wells Fargo Bank, National Association and The Bank of TokyoMitsubishi UFJ, Ltd., as Documentation Agents. (Exhibit 99.03 to Form 8-K of Xcel Energy dated June 20, 2016 (file no. 001-03034)). Third Amendment dated Sept. 30, 2016 to the Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009 Restatement) (Exhibit 10.01 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2016). Form of Xcel Energy Inc. 2015 Omnibus Incentive Plan Award Agreement and Award Terms and Conditions (Restricted Stock Units and Performance Share Units) under the Xcel Energy Inc. 2015 Omnibus Incentive Plan. (Exhibit 10.27 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2016). Fourth Amendment to the 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)). Sixth Amendment dated Feb. 22, 2018 to Xcel Energy Senior Executive Severance and Change-in-Control Policy (Exhibit 10.30 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2017. Statement of Computation of Ratio of Earnings to Fixed Charges. Consent of Independent Registered Public Accounting Firm. Principal Executive Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. Principal Financial Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. Statement pursuant to Private Securities Litigation Reform Act of 1995. The following materials from PSCo’s Annual Report on Form 10-K for the year ended Dec. 31, 2017 are formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statements of Income, (ii) the Consolidated Statements of Comprehensive Income, (iii) the Consolidated Statements of Cash Flows, (iv) the Consolidated Balance Sheets, (v) the Consolidated Statements of Stockholder’s Equity, (vi) the Consolidated Statements of Capitalization, (vii) Notes to Consolidated Financial Statements, (viii) document and entity information, and (ix) Schedule II. 84 Table of Contents SCHEDULE II PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES VALUATION AND QUALIFYING ACCOUNTS YEARS ENDED DEC. 31, 2017, 2016 AND 2015 (amounts in thousands) Additions Charged to Costs and Expenses Balance at Jan. 1 Allowance for bad debts: 2017 2016 2015 (a) (b) $ 19,612 20,122 23,122 Recovery of amounts previously written off. Deductions relate primarily to bad debt write-offs. Item 16 — Form 10-K Summary None. 85 $ 14,303 14,121 13,052 Charged to Other(a) Accounts $ 3,968 4,447 5,175 Deductions from (b) Reserves $ 18,277 19,078 21,227 Balance at Dec. 31 $ 19,606 19,612 20,122 Table of Contents SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this annual report to be signed on its behalf by the undersigned thereunto duly authorized. PUBLIC SERVICE COMPANY OF COLORADO Feb. 23, 2018 /s/ ROBERT C. FRENZEL Robert C. Frenzel Executive Vice President, Chief Financial Officer and Director (Principal Financial Officer) Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities on the date indicated above. /s/ BEN FOWKE Ben Fowke Chairman, Chief Executive Officer and Director (Principal Executive Officer) /s/ DAVID L. EVES David L. Eves President and Director /s/ ROBERT C. FRENZEL Robert C. Frenzel Executive Vice President, Chief Financial Officer and Director (Principal Financial Officer) /s/ JEFFREY S. SAVAGE Jeffrey S. Savage Senior Vice President, Controller (Principal Accounting Officer) /s/ MARVIN E. MCDANIEL, JR. Marvin E. McDaniel, Jr. Director SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(D) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT PSCo has not sent, and does not expect to send, an annual report or proxy statement to its security holder. 86 Exhibit 12.01 PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES STATEMENT OF COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES (amounts in thousands, except ratio) Year Ended Dec. 31 2017 Earnings, as defined: Pretax income Add: Fixed charges Total earnings, as defined Fixed charges, as defined: Interest charges Interest charges on life insurance policy borrowings Interest component of leases Total fixed charges, as defined Ratio of earnings to fixed charges $ $ $ $ 2016 746,298 241,434 987,732 $ 190,694 271 50,469 241,434 4.1 $ $ $ 2015 737,409 236,080 973,489 $ 181,631 203 54,246 236,080 4.1 $ $ $ 2014 745,242 235,530 980,772 $ 177,430 233 57,867 235,530 4.2 $ $ $ 2013 698,779 232,832 931,611 $ 171,881 214 60,737 232,832 4.0 $ $ $ 704,123 232,539 936,662 173,602 245 58,692 232,539 4.0 Exhibit 23.01 CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM We consent to the incorporation by reference in Registration Statement No. 333-203664-04 on Form S-3 of our report dated February 23, 2018, relating to the consolidated financial statements and financial statement schedule of Public Service Company of Colorado and subsidiaries appearing in this Annual Report on Form 10-K of Public Service Company of Colorado for the year ended December 31, 2017. /s/ DELOITTE & TOUCHE LLP Minneapolis, Minnesota February 23, 2018 Exhibit 31.01 CERTIFICATION I, Ben Fowke, certify that: 1. I have reviewed this report on Form 10-K of Public Service Company of Colorado; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: 5. a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. Date: Feb. 23, 2018 /s/ BEN FOWKE Ben Fowke Chairman, Chief Executive Officer and Director 1 Exhibit 31.02 CERTIFICATION I, Robert C. Frenzel, certify that: 1. I have reviewed this report on Form 10-K of Public Service Company of Colorado; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: 5. a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. Date: Feb. 23, 2018 /s/ ROBERT C. FRENZEL Robert C. Frenzel Executive Vice President, Chief Financial Officer and Director 2 Exhibit 32.01 OFFICER CERTIFICATION CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Annual Report of Public Service Company of Colorado (PSCo) on Form 10-K for the year ended Dec. 31, 2017, as filed with the SEC on the date hereof (Form 10-K), each of the undersigned officers of PSCo certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to such officer’s knowledge: (1) The Form 10-K fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of PSCo as of the dates and for the periods expressed in the Form 10-K. Date: Feb. 23, 2018 /s/ BEN FOWKE Ben Fowke Chairman, Chief Executive Officer and Director /s/ ROBERT C. FRENZEL Robert C. Frenzel Executive Vice President, Chief Financial Officer and Director The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Report or as a separate disclosure document. A signed original of this written statement required by Section 906, or other document authenticating, acknowledging or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to PSCo and will be retained by PSCo and furnished to the SEC or its staff upon request. 1 Exhibit 99.01 Public Service Company of Colorado Cautionary Factors The Private Securities Litigation Reform Act provides a “safe harbor” for forward-looking statements to encourage such disclosures without the threat of litigation, providing those statements are identified as forward-looking and are accompanied by meaningful, cautionary statements identifying important factors that could cause the actual results to differ materially from those projected in the statement. Forward-looking statements are made in written documents and oral presentations of PSCo. These statements are based on management’s beliefs as well as assumptions and information currently available to management. Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” and similar expressions. In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements, factors that could cause PSCo’s actual results to differ materially from those contemplated in any forward-looking statements include, among others, the following: • • • • • • • • • • • • • • • • • Economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures; The risk of a significant slowdown in growth or decline in the U.S. economy, the risk of delay in growth recovery in the U.S. economy or the risk of increased cost for insurance premiums, security and other items as a consequence of past or future terrorist attacks; Trade, monetary, fiscal, taxation and environmental policies of governments, agencies and similar organizations in geographic areas where PSCo has a financial interest; Customer business conditions, including demand for their products or services and supply of labor and materials used in creating their products and services; Financial or regulatory accounting principles or policies imposed by the FASB, the SEC, the Federal Energy Regulatory Commission and similar entities with regulatory oversight; Availability or cost of capital such as changes in: interest rates; market perceptions of the utility industry, PSCo, Xcel Energy Inc. or any of its other subsidiaries; or security ratings; Factors affecting utility and nonutility operations such as unusual weather conditions; catastrophic weather-related damage; unscheduled generation outages, maintenance or repairs; unanticipated changes to fossil fuel or natural gas supply costs or availability due to higher demand, shortages, transportation problems or other developments; environmental incidents; cyber incidents; or electric transmission or natural gas pipeline constraints; Employee workforce factors, including loss or retirement of key executives, collective-bargaining agreements with union employees, or work stoppages; Increased competition in the utility industry or additional competition in the markets served by PSCo, Xcel Energy Inc. or any of its other subsidiaries; State, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rate structures and affect the speed and degree to which competition enters the electric and natural gas markets; industry restructuring initiatives; transmission system operation and/or administration initiatives; recovery of investments made under traditional regulation; nature of competitors entering the industry; retail wheeling; a new pricing structure; and former customers entering the generation market; Environmental laws and regulations, including legislation and regulations relating to climate change, and the associated cost of compliance; Rate-setting policies or procedures of regulatory entities, including environmental externalities, which are values established by regulators assigning environmental costs to each method of electricity generation when evaluating generation resource options; Social attitudes regarding the utility and power industries; Cost and other effects of legal and administrative proceedings, settlements, investigations and claims; Technological developments that result in competitive disadvantages and create the potential for impairment of existing assets; Risks associated with implementations of new technologies; and Other business or investment considerations that may be disclosed from time to time in PSCo’s SEC filings, including “Risk Factors” in Item 1A of this Form 10-K, or in other publicly disseminated written documents. PSCo undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing review of factors should not be construed as exhaustive.