UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
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x☒ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2016
2019or
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¨☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Commission File Number: 001-3280Public Service Company of Colorado
(Exact name of registrant as specified in its charter) |
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| 001-03280 |
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| Public Service Company of Colorado |
| (Exact name of registrant as specified in its charter) |
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| Colorado | | 84-0296600 |
(State or other jurisdictionOther Jurisdiction of incorporationIncorporation or organization)Organization) | | (I.R.S. Employer Identification No.) |
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| 1800 Larimer, Suite 1100 | Denver | Colorado | | 80202 |
(Address of principal executive offices)Principal Executive Offices) | | (Zip Code) |
Registrant’s telephone number, including area code: (303) 571-7511 |
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| 303 | 571-7511 |
| (Registrant’s Telephone Number, Including Area Code) |
Securities registered pursuant to Section 12(b) of the Act:None |
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| Title of each class | | Trading Symbol | | Name of each exchange on which registered |
| N/A | | N/A | | N/A |
Securities registered pursuant to section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. x☒Yes¨☐ No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. ¨☐ Yes x☒No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.x Yes ¨ No
☒Yes☐ No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 andof Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). x☒Yes¨☐ No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulations S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer”, “accelerated filer”, and “smaller reporting company”, and “emerging growth company” in Rule 12b-2 of the Exchange Act.☐ Large accelerated filer ☐ Accelerated filer ☒Non-accelerated filer☐ Smaller reporting company ☐ Emerging growth company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.☐ |
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Large accelerated filer ¨
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Non-accelerated filer x
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(Do not check if smaller reporting company) | | |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ¨☐ Yes x☒ No
As of Feb. 24, 201721, 2020, 100 shares of common stock, par value $0.01 per share, were outstanding, all of which were held by Xcel Energy Inc., a Minnesota corporation.
DOCUMENTS INCORPORATED BY REFERENCE
The information required by Item 14 of Form 10-K is set forth under the heading “Independent Registered Public Accounting Firm – Audit and Non-Audit Fees” in Xcel Energy Inc.’s definitive Proxy Statement for the 20172020 Annual Meeting of StockholdersShareholders which definitive Proxy Statement is expected to be filed with the SEC on or about April 4, 2017.6, 2020. Such information set forth under such heading is incorporated herein by this reference hereto.
Public Service Company of Colorado meets the conditions set forth in General Instructions I(1)(a) and (b) of Form 10-K and is therefore filing this form with reduced disclosure format permitted by General Instruction I(2).
TABLE OF CONTENTS
Index
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| PART I | | |
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| Item 1A — | | |
| Item 1B — | |
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| Item 2 — | | |
| Item 3 — | | |
| Item 4 — | | |
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| PART II | | |
Item 5 — | | |
Item 6 — | | |
Item 7 — | | |
Item 7A — | | |
Item 8 — | | |
Item 9 — | | |
Item 9A — | | |
Item 9B — | | |
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| PART III | | |
Item 10 — | | |
Item 11 — | | |
Item 12 — | | |
Item 13 — | | |
Item 14 — | | |
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| PART IV | | |
Item 15 — | | |
| Item 16 — | | |
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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.
PART I
Item l — Business
DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMSDefinitions of Abbreviations
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| Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former) |
NCEe prime | New Century Energies, Inc.e prime inc. |
| NSP-Minnesota | Northern States Power Company, a Minnesota corporation |
| NSP-Wisconsin | Northern States Power Company, a Wisconsin corporation |
| PSCo | Public Service Company of Colorado |
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 |
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| 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 |
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| Electric, Purchased Gas and Resource Adjustment Clauses |
| DSM | Demand side management |
| DSMCA | Demand side management cost adjustment |
| ECA | Retail electric commodity adjustment |
ERPFCA | Electric resource planFuel clause adjustment |
| GCA | Gas cost adjustment |
| PCCA | Purchased capacity cost adjustment |
| PSIA | Pipeline system integrity adjustment |
QSP | Quality of service plan |
RES | Renewable energy standard |
| RESA | Renewable energy standard adjustment |
| SCA | Steam cost adjustment |
| TCA | Transmission cost adjustment |
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Other Terms and Abbreviations |
| ADIT | Accumulated deferred income taxes |
| 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 |
| Boulder | City of Boulder, CO |
| C&I | Commercial and Industrial |
CAA | Clean Air Act |
| CACJA | Clean Air Clean Jobs Act |
CO2
CCR | Carbon dioxideCoal combustion residuals |
| CCR Rule | Final rule (40 CFR 257.50 - 257.107) published by the EPA regulating the management, storage and disposal of CCRs as a nonhazardous waste |
| CEO | Chief executive officer |
| CFO | Chief financial officer |
| CEP | Colorado Energy Plan |
| CIG | Colorado Interstate Gas Company, LLC |
| CPCN | Certificate of public convenience and necessity |
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CPPCWA | Clean Power PlanWater Act |
| CWIP | Construction work in progress |
ERCOTDRC | Electric Reliability Council of TexasDevelopment Recovery Company |
| ELG | Effluent limitations guidelines |
| ETR | Effective tax rate |
| FASB | Financial Accounting Standards Board |
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| GAAP | Generally accepted accounting principles |
| GHG | Greenhouse gas |
| IPP | Independent power producing entity |
| ITC | Investment tax credit |
JOAMDL | Joint operating agreementMulti-district litigation |
| MGP | Manufactured gas plant |
MISO | Midcontinent Independent Transmission System Operator, Inc. |
| Moody’s | Moody��sMoody’s Investor Services |
| Native load | Customer demand of retail and wholesale customers whereby a utility has an obligation to serve under statute or long-term contract. |
| NAV | Net asset value |
| NOL | Net operating loss |
NOx | Nitrogen oxide |
| O&M | Operating and maintenance |
OCIPost-65 | Other comprehensive income |
PCB | Polychlorinated biphenyl |
PJM | PJM Interconnection, LLC |
PM | Particulate matterPost-Medicare |
| PPA | Purchased power agreement |
PRPPre-65 | Potentially responsible partyPre-Medicare |
| PTC | Production tax credit |
PV | Photovoltaic |
R&E | Research and experimentation |
| REC | Renewable energy credit |
| ROE | Return on equity |
RPSROU | Renewable portfolio standardsRight-of-use |
SIPRTO | State implementation planRegional Transmission Organization |
SO2
SERP | Sulfur dioxideSupplemental executive retirement plan |
| SPP | Southwest Power Pool, Inc. |
| Standard & Poor’s | Standard & Poor’s Ratings Services |
| TCJA | 2017 federal tax reform enacted as Public Law No: 115-97, commonly referred to as the Tax Cuts and Jobs Act |
| VaR | Value at Risk |
| VIE | Variable interest entity |
| WOTUS | Waters of the U.S. |
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| Measurements |
| Bcf | Billion cubic feet |
| KV | Kilovolts |
| KWh | Kilowatt hours |
| MMBtu | Million British thermal units |
| MW | Megawatts |
| MWh | Megawatt hours |
GWh |
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| Forward-Looking Statements |
Except for the historical statements contained in this report, the matters discussed herein are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements, assumptions and other statements are intended to be identified in this document by the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” “will,” “would” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we expressly disclaim any obligation to update any forward-looking information. The following factors, in addition to those discussed elsewhere in this Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2019 (including risk factors listed from time to time by PSCo in reports filed with the SEC, including “Risk Factors” in Item 1A of this Annual Report on Form 10-K hereto), could cause actual results to differ materially from management expectations as suggested by such forward-looking information: operational safety; successful long-term operational planning; commodity risks associated with energy markets and production; rising energy prices and fuel costs; qualified employee work force and third-party contractor factors; ability to recover costs, changes in regulation and subsidiaries’ ability to recover costs from customers; reductions in our credit ratings and the cost of maintaining certain contractual relationships; general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of PSCo and its subsidiaries to obtain financing on favorable terms; availability or cost of capital; our customers’ and counterparties’ ability to pay their debts to us; assumptions and costs relating to funding our employee benefit plans and health care benefits; our subsidiaries’ ability to make dividend payments; tax laws; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; seasonal weather patterns; changes in environmental laws and regulations; climate change and other weather; natural disaster and resource depletion, including compliance with any accompanying legislative and regulatory changes; and costs of potential regulatory penalties.
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| Where to Find More Information |
PSCo is a wholly owned subsidiary of Xcel Energy Inc., and Xcel Energy’s website address is www.xcelenergy.com. Xcel Energy makes available, free of charge through its website, its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after the reports are electronically filed with or furnished to the SEC. The SEC maintains an internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically at http://www.sec.gov.
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| Gigawatt hours | | | | |
| Electric customers | 1.5 million | | | | PSCo was incorporated in 1924 under the laws of Colorado. PSCo conducts business in Colorado and generates, purchases, transmits, distributes and sells electricity in addition to purchasing, transporting, distributing and selling natural gas to retail customers and transporting customer-owned natural gas. |
| Natural gas customers | 1.4 million | | |
| Total assets | $19.0 billion | | |
| Rate Base | $12.4 billion | | |
| ROE | 8.69% | | |
| Electric generating capacity | 5,666 MW | | |
| Gas storage capacity | 32.5 Bcf | | |
| Electric transmission lines (conductor miles) | 24,008 miles | | |
| Electric distribution lines (conductor miles) | 78,023 miles | | |
| Natural gas transmission lines | 2,057 miles | | |
| Natural gas distribution lines | 22,633 miles | | | |
PSCo had electric sales volume of 37,337 (millions of KWh), 1,507,841 customers and electric revenues of $3,033.0 (millions of dollars) for 2019.
COMPANY OVERVIEWSales/Revenue Statistics
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| | | 2019 | | 2018 |
| KWH sales per retail customer | | 19,335 |
| | 19,660 |
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| Revenue per retail customer | | $1,812 |
| | $1,797 |
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| Residential revenue per KWh | |
| 11.09 | ¢ | |
| 10.86 | ¢ |
| Large C&I revenue per KWh | |
| 6.43 | ¢ | |
| 6.20 | ¢ |
| Small C&I revenue per KWh | |
| 9.38 | ¢ | |
| 9.18 | ¢ |
| Total retail revenue per KWh | |
| 9.37 | ¢ | |
| 9.14 | ¢ |
Owned and Purchased Energy Generation — 2019
Electric Energy Sources
Total electric generation by source (including energy market purchases) for the year ended Dec. 31, 2019:
*Distributed generation from the Solar*Rewards® program is not included (approximately 512.8 million KWh for 2019). Renewable Energy Sources
PSCo’s renewable energy portfolio includes wind, hydroelectric and solar power from both owned generating facilities and PPAs. Renewable percentages will vary year over year based on system additions, weather, system demand and transmission constraints.
See Item 2 — Properties for further information.
Renewable energy as a percentage of total energy for 2019:
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(a) | Includes biomass and hydroelectric. |
Wind Energy Sources
Owned — Owned and operated wind farms with corresponding capacity:
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| 2019 | | 2018 |
| Wind Farms | | Capacity | | Wind Farms | | Capacity |
| 1 | | 600 MW | | 1 | | 600 MW |
PPAs — Number of PPAs with range: |
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| 2019 | | 2018 |
| PPAs | | Range | | PPAs | | Range |
| 20 | | 2.0 MW - 300.5 MW | | 19 | | 2.0 MW - 300.5 MW |
Capacity — Wind capacity:
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| 2019 | | 2018 |
| 3,165 MW | | 3,160 MW |
Average Cost (Owned) — Average cost per MWh of wind energy from owned generation:
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(a) | The table reflects the owned wind site that was in commercial operation for the full calendar year. The Rush Creek wind farm was put into service in December 2018. |
Average Cost (PPAs) — Average cost per MWh of wind energy under existing PPAs:
Wind Energy Development
PSCo was incorporated in 1924currently has approximately 500 MW of owned wind under the lawsdevelopment or construction and approximately 450 MW of Colorado. PSCo is a utility engaged primarily in the generation, purchase, transmission, distribution and saleplanned PPAs with an estimated completion date of electricity in Colorado. The wholesale customers served by PSCo comprised approximately 14 percent of its total KWh sold in 2016. 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 1.4 million customers2021 or earlier:
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| Project | | Capacity | | Estimated Completion |
| Cheyenne Ridge | | 500 MW | | 2020 |
| Various PPAs | | ~450 MW | | 2020-2021 |
Solar Energy Sources
Solar energy PPAs:
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| Type | | Capacity |
| Distributed Generation | | 557 MW |
| Utility-Scale | | 305 MW |
Fossil Fuel Energy Sources
PSCo’s fossil fuel energy portfolio includes coal and natural gas utility service to approximately 1.4 million customers. All of PSCo’s retail electric operating revenues were derivedpower from operations in Colorado during 2016. 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 the following industries: fabricated metal products, communicationsboth owned generating facilities 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.PPAs.
See Item 2 — Properties for further information.
Coal Energy Sources
PSCo owns the following direct subsidiaries: 1480 Welton, Inc. and United Water Company, bothhas four coal plants with approximately 2,000 MW 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,total 2019 net income and related financial information.summer dependable capacity.
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 with respect to its wholesale electric operations, accounting practices, hydroelectric licensing, wholesale sales for resale, the 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 authorized to make wholesale electric sales at market-based prices to customers outside its 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 marginsThe following are shared with retail customers through the ECA. The ECA is revised quarterly.PSCo’s approved coal plant retirements. In addition, PSCo plans to continue to evaluate its coal fleet for other potential early coal plant retirements as part of state resource plans or other regulatory proceedings.
PCCA — Recovers purchased capacity payments.
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| Approved (2019 to 2025) |
| Year | | Plant | | Capacity |
| 2022 | | Comanche 1 | | 325 MW |
| 2025 | | Comanche 2 | | 335 MW |
| 2025 | | Craig 1 | | 42 MW |
Coal Fuel Cost
SCA — Recovers the difference between PSCo’s actualDelivered cost per MMBtu of fuelcoal consumed for owned electric generation and the amountpercentage of these costs recovered under its base steam service rates. The SCA rate is revised on a quarterly basis.total fuel requirements:
DSMCA — Recovers DSM, interruptible service option credit costs and performance initiatives for achieving various energy savings goals.
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| | | Coal |
| | | Cost | | Percent |
| 2019 | | $ | 1.45 |
| | 55 | % |
| 2018 | | 1.45 |
| | 62 |
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RESA — Recovers the incremental costs of compliance with the RES with a maximum of two percent of the customer’s total bill.
WindNatural Gas Energy Service — Premium service for customers who choose to pay an additional charge for renewable resources.
TCA — Recovers costs associated with transmission investment outside of rate cases.
CACJA — Recovers costs associated with implementing its compliance plan under the CACJA.
Sources
PSCo recovers fuelhas six natural gas plants with approximately 2,900 MW of total 2019 net summer dependable capacity. See item 2 - Properties for further detail.
Natural gas supplies, transportation and purchased energy costs from its wholesale electric customersstorage services for power plants are procured to provide an adequate supply of fuel. Remaining requirements are procured through a liquid spot market. Generally, natural gas supply contracts have variable pricing that is tied to natural gas indices. Natural gas supply and transportation agreements include obligations for the purchase and/or delivery of specified volumes or payments in lieu of delivery.
Natural Gas Cost
Delivered cost per MMBtu of natural gas consumed for owned electric generation and the percentage of total fuel cost adjustment clause approved by the FERC. PSCo’s wholesale customers have agreed to 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.requirements:
QSP Requirements— The CPUC established an electric QSP that provides for bill credits to customers if PSCo does not achieve certain performance targets relating to electric reliability and customer service. PSCo monitors and records, as necessary, an estimated customer refund obligation under the QSP. The CPUC extended the terms of the current QSP through 2018. |
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| | | Natural Gas |
| | | Cost | | Percent |
| 2019 | | 3.27 |
| | 45 |
| 2018 | | 3.74 |
| | 38 |
CapacityRenewable Energy Sources
PSCo’s renewable energy portfolio includes wind, hydroelectric and Demandsolar power from both owned generating facilities and PPAs. Renewable percentages will vary year over year based on system additions, weather, system demand and transmission constraints.
See Item 2 — Properties for further information.
Uninterrupted system peak demandRenewable energy as a percentage of total energy for PSCo’s electric utility for each of the last three years2019:
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(a) | Includes biomass and hydroelectric. |
Wind Energy Sources
Owned — Owned and the forecast for 2017, assuming normal weather conditions, is as follows:operated wind farms with corresponding capacity:
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| | System Peak Demand (in MW) |
| | 2014 | | 2015 | | 2016 | | 2017 Forecast |
| PSCo | 6,152 |
| | 6,284 |
| | 6,585 |
| | 6,439 |
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| 2019 | | 2018 |
| Wind Farms | | Capacity | | Wind Farms | | Capacity |
| 1 | | 600 MW | | 1 | | 600 MW |
PPAs — Number of PPAs with range: |
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| 2019 | | 2018 |
| PPAs | | Range | | PPAs | | Range |
| 20 | | 2.0 MW - 300.5 MW | | 19 | | 2.0 MW - 300.5 MW |
Capacity — Wind capacity:
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| 2019 | | 2018 |
| 3,165 MW | | 3,160 MW |
Average Cost (Owned) — Average cost per MWh of wind energy from owned generation:
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(a) | The table reflects the owned wind site that was in commercial operation for the full calendar year. The Rush Creek wind farm was put into service in December 2018. |
Average Cost (PPAs) — Average cost per MWh of wind energy under existing PPAs:
Wind Energy Development
PSCo currently has approximately 500 MW of owned wind under development or construction and approximately 450 MW of planned PPAs with an estimated completion date of 2021 or earlier:
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| Project | | Capacity | | Estimated Completion |
| Cheyenne Ridge | | 500 MW | | 2020 |
| Various PPAs | | ~450 MW | | 2020-2021 |
Solar Energy Sources
Solar energy PPAs:
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| Type | | Capacity |
| Distributed Generation | | 557 MW |
| Utility-Scale | | 305 MW |
Fossil Fuel Energy Sources
PSCo’s fossil fuel energy portfolio includes coal and natural gas power from both owned generating facilities and PPAs.
See Item 2 — Properties for further information.
Coal Energy Sources
PSCo has four coal plants with approximately 2,000 MW of total 2019 net summer dependable capacity.
The peak demand forfollowing are PSCo’s system typically occurs in the summer. The 2016 system peak demand for PSCo occurred on Aug. 3, 2016. The 2016 system peak demand was higher due to Comanche Unit 3 not running at full capacity, which increased PSCo’s system load for the backup power provided by PSCo to the joint owners. 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 independent power producers. Long-term purchased power contracts typically require a periodic capacity charge and an energy charge for energy actually purchased. PSCo also 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—approved coal plant retirements. In addition, PSCo plans to usingcontinue to evaluate 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, PSCo filed an applicationcoal fleet for a CPCN to build, own and operate a 600 MW wind generation facility at Rush Creek for a cost of approximately $1 billion, including transmission investment.
In 2016, the CPUC approved a settlement between PSCo and various parties and granted a CPCN, which allows PSCo to commence the project on a timely basis and capture the full PTC benefit for customers.
Key terms of the settlement are listed below:
The Rush Creek project satisfies the reasonable cost standard and is in the public interest;
The project should be placed in service by Oct. 31, 2018;
The useful life of the project should be set at 25 years;
A hard cost-cap on the $1.096 billion investment (which includes the capital investment and AFUDC);
A capital cost sharing mechanism for every $10 million below the cost-cap, with 82.5 percent retained by customers and 17.5 percent retained by PSCo on a net present value basis over the life of the project;
Amounts retained by PSCo under the capital cost sharing mechanismother potential early coal plant retirements as well as overall facility revenue requirements may each be reduced for lower than projected long term generating output (i.e., higher degradation);
The Pawnee-Daniels transmission line (estimated project cost of $178 million) should be accelerated and operations are expected to begin by October 2019; and
PSCo committed to develop a rate for third-party access to available capacity in the Rush Creek transmission line to be filed at the FERC.
Colorado 2016 ERP — In May 2016, PSCo filed its 2016 ERP which identified approximately 600 MW of additional resource needs by the summer of 2023; the level of resource need is driven by load growth, retiring generation facilities, expiring purchased power contracts and the impacts of customer-facing programs. In its initial filing, PSCo proposed a competitive acquisition process in which all generation resources, except coal-fired generation, could compete. PSCo has expressed an interest in owning incremental generation through self-build proposals, purchase of existing assets some of which are currently subject to PPAs or through build-own-transfer projects. In February 2017, the CPUC held hearings regarding PSCo’s proposal and an initial decision is anticipated by March 2017. The actual range of need to be filled in the competitive acquisition process will be determined once a final decision is received from the CPUC and prior to the beginning of the competitive acquisition phase of the ERP process.
Brush to Castle Pines 345 KV Transmission Line — In 2015, the CPUC granted a CPCN to construct a new 345 KV transmission line originating from Pawnee generating station, near Brush, CO to the Daniels Park substation, near Castle Pines, CO to be placed in service by May 2022. The estimated project cost is $178.3 million. The CPUC granted the parties’ requests for consolidation with the Rush Creek project and approved for construction to begin in the first half of 2017.
PSCo Global Settlement Agreement — In August 2016, PSCo and various intervenors entered into a global settlement agreement regarding three pending filings with the CPUC, including the Phase II electric rate case (which is related to the rate design portion of the 2015 Electric rate case), the Renewable*Connect® proposal and the 2017 Renewable Energy Plan. Key terms of the agreement include that participating customers in the proposed Renewable*Connect program would pay ordinary tariff electric rates in addition to a voluntary tariff solar charge, and receive bill credits related to avoided cost savings for a new 50 MW solar resource. It was also agreed that PSCo’s 2017 Renewable Energy Plan would include 2017 to 2019 acquisition of a total of 225 MW of renewable energy from sources including rooftop solar, solar gardens and recycled energy.
In December 2016, the CPUC approved the global settlement agreement. In January 2017, PSCo began implementing the terms of the settlement.
Joint Dispatch Agreement (JDA) — In February 2016, the FERC approved a JDA between PSCo, Black Hills/Colorado Electric Utility Company, LP and Platte River Power Authority. Through the JDA, energy is dispatched to economically serve the combined electric customer loads of the three systems. In circumstances where PSCo is the lowest cost producer, it will sell its excess generation to other JDA counterparties. The agreement results in a reduction in total energy costs for the parties, of which approximately $1.4 million would be allocated to PSCo’s customers. As part of the agreement, PSCo will earn a management fee to administer the JDA. In January 2017, the CPUC approved the JDA.state resource plans or other regulatory proceedings.
Advanced Grid Intelligence and Security —In August 2016, PSCo filed a request with the CPUC to approve a CPCN for implementation of its advanced grid initiative. The project incorporates installing advanced meters, implementing a combination of hardware and software applications to allow the distribution system to operate at a lower voltage (integrated volt-var optimization) and installing necessary communications infrastructure to implement this hardware. These major projects are expected to improve customer experience, enhance grid reliability and enable the implementation of new and innovative programs and rate structures. The estimated capital investment for the project is approximately $500 million. PSCo anticipates a CPUC decision by mid-2017. If approval is received, the project is expected to be completed by 2021. |
| | | | |
| Approved (2019 to 2025) |
| Year | | Plant | | Capacity |
| 2022 | | Comanche 1 | | 325 MW |
| 2025 | | Comanche 2 | | 335 MW |
| 2025 | | Craig 1 | | 42 MW |
Coal Fuel Cost
Decoupling Filing — In July 2016, PSCo filed a request with the CPUC to approve a partial decoupling mechanism for a five-year period, effective Jan. 1, 2017. The proposed decoupling adjustment would allow PSCo to adjust annual revenues based on changes in weather normalized average use per customer for the residential and small C&I classes. The proposed decoupling mechanism is symmetric and may result in potential refunds to customers if there were an increase in average use per customer. PSCo did not request that revenue be adjusted as a result of weather related sales fluctuations.
In January 2017, the CPUC Staff (Staff) and various intervenors, including the Office of Consumer Counsel (OCC), filed direct testimony.
The Staff recommended a portion of PSCo’s request be approved and suggested the CPUC should lower PSCo’s ROE by 30 basis points to account for lower risk associated with annual revenues, if the full proposal were approved;
The OCC opposed PSCo’s decoupling request; and
Other intervening parties generally supported PSCo’s proposal, but recommended various modifications, such as the use of actual sales data instead of weather-normalized sales.
A CPUC decision is expected in April 2017.
Boulder, Colo. Municipalization — In 2011, a ballot measure was passed which authorized the formation and operation of a municipal utility and the issuance of enterprise revenue bonds. In 2014, the City of Boulder (Boulder) City Council passed an ordinance to establish an electric utility. PSCo challenged the formation of this utility as premature because costs and system separation plans were not final, but the case was dismissed. PSCo appealed this decision and in September 2016, the Colorado Court of Appeals preserved PSCo’s ability to challenge the utility while vacating the lower court’s decision.
In 2013, the CPUC ruled that Boulder may not be the retail service provider to any PSCo customers located outside Boulder city limits unless Boulder can establish that PSCo is unwilling or unable to serve those customers. The CPUC also ruled that it has jurisdiction over the transfer of any facilities to Boulder that currently serve any customers located outside Boulder city limits and will determine separation matters. The CPUC has declared that Boulder must receive CPUC transfer approval prior to any eminent domain actions. Boulder appealed this ruling to the Boulder District Court. In January 2015, the Boulder District Court affirmed the CPUC decision. The Boulder District Court also dismissed a condemnation action that Boulder had filed. The CPUC must complete the separation plan proceeding before Boulder may refile a condemnation proceeding.
In July 2015, Boulder filed an application with the CPUC requesting approval of its proposed separation plan. In August 2015, PSCo filed a motion to dismiss Boulder’s separation proposal, arguing Boulder’s request was not permissible under Colorado law. In December 2015, the CPUC granted the motion to dismiss the application in part, holding that Boulder had no right to acquire PSCo facilities used exclusively to serve customers located outside Boulder city limits. Other portions of Boulder’s application were not dismissed, but were stayed until Boulder supplemented its application. Boulder filed its amended application in September 2016.
In February 2017, PSCo and other intervenors filed answer testimony which addressed several legal issues posed by the CPUC. Overall, PSCo believes that Boulder’s plan is not consistent with and cannot be effectively administered under Colorado law and that from a reliability perspective it is an inappropriate way to separate the two distribution systems and poses significant risks to PSCo and its remaining customers. The remaining key dates in the procedural schedule are as follows:
Rebuttal testimony — March 30, 2017;
Hearings — April 26 through May 5, 2017;
Statements of position — May 17, 2017; and
Final decision — June 15, 2017.
Depreciation and Amortization Proceeding — In April 2016, PSCo filed for approval of depreciation rates and amortization schedules for its electric and common plant. In January 2017, the CPUC approved a comprehensive settlement agreement. The new depreciation and amortization rates are expected to be implemented in conjunction with PSCo’s next rate case or through a separate proceeding in 2018, with an expected annual increase of approximately $33 million.
RES Compliance Plan — Colorado law mandates that at least 20 percent of PSCo’s energy sales are supplied by renewable energy through 2019, with the percentage increasing to 30 percent by 2020 and includes a distributed generation standard. PSCo was in compliance with the RES as of Dec. 31, 2016.
Fuel Supply and Costs
The following table shows the deliveredDelivered cost per MMBtu of each significant category of fuelcoal consumed for owned electric generation and the percentage of total fuel requirements represented by each category of fuel and the total weighted average cost of all fuels.requirements:
|
| | | | | | | | | | | | | | | | | | |
| | | Coal | | Natural Gas | | Weighted Average Owned Fuel Cost |
| PSCo Generating Plants | | Cost | | Percent | | Cost | | Percent | |
| 2016 | | $ | 1.75 |
| | 72 | % | | $ | 3.79 |
| | 28 | % | | $ | 2.33 |
|
| 2015 | | 1.75 |
| | 75 |
| | 3.89 |
| | 25 |
| | 2.29 |
|
| 2014 | | 1.82 |
| | 75 |
| | 5.32 |
| | 25 |
| | 2.68 |
|
|
| | | | | | | |
| | | Coal |
| | | Cost | | Percent |
| 2019 | | $ | 1.45 |
| | 55 | % |
| 2018 | | 1.45 |
| | 62 |
|
See Items 1A and 7 for further discussion of fuel supply and costs.
FuelNatural Gas Energy Sources
Coal— PSCo normally maintains approximately 41 days of coal inventory. Coal supply inventories at Dec. 31, 2016 and 2015 were approximately 36 and 49 days of usage, respectively. At Dec. 31, 2016, stockpile reductions in preparation for unit retirements at the Cherokee and Valmont stations in 2017 resulted in coal inventories being slightly below optimal levels. PSCo’s generation stations use low-sulfur western coal purchased primarily under contracts with suppliers operating in Colorado and Wyoming. During 2016 and 2015, PSCo’s coal requirements for existing plants were approximately 9.9 million tons and 10.5 million tons, respectively. The estimated coal requirements for 2017 are approximately 10.0 million tons. The increase is primarily due to higher expected natural gas prices in 2017.
PSCo has contracted for coal supply to provide 84 percent of its estimated coal requirements in 2017, and a declining percentage of requirements in subsequent years. PSCo’s general coal purchasing objective is to contract for approximately 80 percent of requirements for the first year, 50 percent of requirements in year two, and 25 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 2017 and 2018. 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 interruptiblesix natural gas supply and standby oil in combustion turbines and certain boilers. plants with approximately 2,900 MW of total 2019 net summer dependable capacity. See item 2 - Properties for further detail.
Natural gas supplies, transportation and storage services for 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 forecastedRemaining 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, the balance ofGenerally, natural gas supply contracts have variable pricing featuresthat is 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 naturalNatural 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, 2016, PSCo’s commitments related to
Natural Gas Cost
Delivered cost per MMBtu of natural gas supply contracts, which expire in various years from 2017 through 2023, were approximately $654 millionconsumed for owned electric generation and commitments related to gas transportation and storage contracts, which expire in various years from 2017 through 2060, were approximately $573 million.the percentage of total fuel requirements:
At Dec. 31, 2015, PSCo’s commitments related to gas supply contracts were approximately $750 million and commitments related to gas transportation and storage contracts were approximately $684 million.
PSCo has limited on-site fuel oil storage facilities and primarily relies on the spot market for incremental supplies.
|
| | | | | |
| | | Natural Gas |
| | | Cost | | Percent |
| 2019 | | 3.27 |
| | 45 |
| 2018 | | 3.74 |
| | 38 |
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, 2016, PSCo was in compliance with mandated RPS, which requires generation from renewable resources of 20.0 percent of electric retail sales.Renewable percentages will vary year over year based on system additions, weather, system demand and transmission constraints.
See Item 2 — Properties for further information.
Renewable energy comprised 28.3 percent and 22.0 percentas a percentage of PSCo’s total energy for 20162019:
| |
(a) | Includes biomass and hydroelectric. |
Wind Energy Sources
Owned — Owned and 2015, respectively;operated wind farms with corresponding capacity:
|
| | | | | | |
| 2019 | | 2018 |
| Wind Farms | | Capacity | | Wind Farms | | Capacity |
| 1 | | 600 MW | | 1 | | 600 MW |
PPAs — Number of PPAs with range: |
| | | | | | |
| 2019 | | 2018 |
| PPAs | | Range | | PPAs | | Range |
| 20 | | 2.0 MW - 300.5 MW | | 19 | | 2.0 MW - 300.5 MW |
Capacity — Wind energy comprised 23.7 percent and 19.4 percentcapacity:
|
| | |
| 2019 | | 2018 |
| 3,165 MW | | 3,160 MW |
Average Cost (Owned) — Average cost per MWh of the total energy for 2016 and 2015, respectively; and
Hydroelectric, biomass and solar power comprised approximately 4.6 percent and 2.6 percent of the total energy for 2016 and 2015.
PSCo also offers customer-focused renewable energy initiatives. Windsource® allows customers to purchase a portion or all of their electricity from renewable sources. In 2016, the number of customers utilizing Windsource increased to approximately 46,000 from 45,000 in 2015.
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 32,500 PV systems with approximately 276 MW of aggregate capacity and over 29,500 PV systems with approximately 258 MW of aggregate capacity have been installed in Colorado under this program as of Dec. 31, 2016 and 2015, respectively. Additionally, 25 community solar gardens with 18.1 MW of capacity and 24 gardens with 16.6 MW of capacity have been completed in Colorado as of Dec. 31, 2016 and 2015, respectively.
Wind— PSCo acquires the majority of its wind energy from PPAs with wind farm owners, primarily located in Colorado. Currently, PSCo has 19 of these agreements in place, with facilities ranging in size from two MW to over 300 MW.owned generation:
PSCo had approximately 2,560 MW of wind energy on its system at the end of 2016 and 2015. In addition to receiving purchased wind energy under these agreements, PSCo also typically receives wind RECs which are used to meet state renewable resource requirements. | |
(a) | The table reflects the owned wind site that was in commercial operation for the full calendar year. The Rush Creek wind farm was put into service in December 2018. |
The averageAverage Cost (PPAs) — Average cost per MWh of wind energy under these contracts was approximately $42 in 2016 and 2015. 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, contracts executed in 2016 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 beginning in 2017.existing PPAs:
Wholesale and Commodity Marketing Operations
Wind Energy Development
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 FERCcurrently 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.
Status of FERC Commissioners — The FERC is comprised of five commissioners appointed by the President and subject to confirmation by the Senate. There are today only two sitting commissioners. It is uncertain when the President will appoint new commissioners to the open seats or when those appointments may be confirmed. Without three sitting commissioners, the FERC will not have a quorum to act on contested matters. The lack of a quorum could affect the timing of FERC decisions on proposed rules or pending, newly submitted and future filings involving, among other things, contested electric rate matters and CPCNs for construction of interstate natural gas pipeline facilities.
NERC Critical Infrastructure Protection Requirements — The FERC has approved Version 5 of NERC’s critical infrastructure protection standards, which added additional requirements to strengthen grid security controls. PSCo applied the requirements to high and medium impact assets by the July 1, 2016 deadline. Requirements must be applied to low impact assets through a staggered implementation beginning April 1, 2017 through September 2018. PSCo is currently in the process of implementing initiatives to meet the compliance deadline. The additional cost for compliance is anticipated to be recoverable through rates.
NERC Physical Security Requirements — In 2014, the FERC approved NERC’s proposed critical infrastructure protection standard related to physical security for bulk electric system facilities. The new standard became enforceable in October 2015 with staggered milestone deliverable dates through 2016. PSCo has developed physical security plans in accordance with the requirements of the standard. The additional cost for compliance is anticipated to be recoverable through rates.
Formula Rate Treatment of Accumulated Deferred Income Taxes (ADIT) — In 2015, PSCo filed changes to its transmission
formula rate and production formula rate to comply with IRS guidance regarding how ADIT must be reflected in formula rates using
future test years and a true-up. The filings were intended to ensure that PSCo is in compliance with IRS rules and may continue to use
accelerated tax depreciation. PSCo requested a Jan. 1, 2016 effective date.
In April 2016, the FERC accepted PSCo’s ADIT formula rate changes, effective Jan. 1, 2016, subject to a compliance filing. In August 2016, the FERC approved PSCo’s compliance filing. PSCo believes its wholesale formula rates are in compliance with the IRS ADIT rules.
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 QF 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 800approximately 500 MW of solar generationowned wind under development or construction and 700approximately 450 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. FERC action is pending.planned PPAs with an estimated completion date of 2021 or earlier:
Electric Operating Statistics
Electric Sales Statistics |
| | | | | | | | | | | | |
| | Year Ended Dec. 31 | |
| | 2016 | | 2015 | | 2014 | |
| Electric sales (Millions of KWh) | | | | | | |
| Residential | 9,272 |
| | 9,112 |
| | 9,009 |
| |
| Large commercial and industrial | 6,371 |
| | 6,596 |
| | 6,712 |
| |
| Small commercial and industrial | 12,890 |
| | 12,750 |
| | 12,709 |
| |
| Public authorities and other | 268 |
| | 242 |
| | 241 |
| |
| Total retail | 28,801 |
| | 28,700 |
| | 28,671 |
| |
| Sales for resale | 4,672 |
| | 3,581 |
| | 3,664 |
| |
| Total energy sold | 33,473 |
| | 32,281 |
| | 32,335 |
| |
| | | | | | | |
| Number of customers at end of period | | | | | | |
| Residential | 1,235,378 |
| | 1,218,662 |
| | 1,202,621 |
| |
| Large commercial and industrial | 337 |
| | 337 |
| | 334 |
| |
| Small commercial and industrial | 159,299 |
| | 158,086 |
| | 156,809 |
| |
| Public authorities and other | 54,048 |
| | 53,944 |
| | 53,824 |
| |
| Total retail | 1,449,062 |
| | 1,431,029 |
| | 1,413,588 |
| |
| Wholesale | 34 |
| | 26 |
| | 23 |
| |
| Total customers | 1,449,096 |
| | 1,431,055 |
| | 1,413,611 |
| |
| | | | | | | |
| Electric revenues (Thousands of Dollars) | | | | | | |
| Residential | $ | 1,063,526 |
| | $ | 1,060,626 |
| | $ | 1,081,092 |
| |
| Large commercial and industrial | 414,797 |
| | 433,061 |
| | 462,449 |
| |
| Small commercial and industrial | 1,204,881 |
| | 1,220,064 |
| | 1,267,023 |
| |
| Public authorities and other | 54,070 |
| | 52,783 |
| | 54,555 |
| |
| Total retail | 2,737,274 |
| | 2,766,534 |
| | 2,865,119 |
| |
| Wholesale | 152,375 |
| | 180,716 |
| | 211,241 |
| |
| Other electric revenues | 159,703 |
| | 168,007 |
| | 49,577 |
| |
| Total electric revenues | $ | 3,049,352 |
| | $ | 3,115,257 |
| | $ | 3,125,937 |
| |
| | | | | | | |
| KWh sales per retail customer | 19,876 |
| | 20,055 |
| | 20,282 |
| |
| Revenue per retail customer | $ | 1,889 |
| | $ | 1,933 |
| | $ | 2,027 |
| |
| Residential revenue per KWh | 11.47 |
| ¢ | 11.64 |
| ¢ | 12.00 |
| ¢ |
| Large commercial and industrial revenue per KWh | 6.51 |
| | 6.57 |
| | 6.89 |
| |
| Small commercial and industrial revenue per KWh | 9.35 |
| | 9.57 |
| | 9.97 |
| |
| Total retail revenue per KWh | 9.50 |
| | 9.64 |
| | 9.99 |
| |
| Wholesale revenue per KWh | 3.26 |
| | 5.05 |
| | 5.77 |
| |
|
| | | | | | | | | | | | | | | | | |
| | Year Ended Dec. 31 |
| | 2016 | | 2015 | | 2014 |
| | Millions of KWh | | Percent of Generation | | Millions of KWh | | Percent of Generation | | Millions of KWh | | Percent of Generation |
| Coal | 15,895 |
| | 47 | % | | 18,601 |
| | 54 | % | | 18,274 |
| | 53 | % |
| Natural Gas | 8,632 |
| | 25 |
| | 7,948 |
| | 23 |
| | 8,601 |
| | 25 |
|
Wind (a) | 8,106 |
| | 24 |
| | 6,699 |
| | 19 |
| | 6,472 |
| | 19 |
|
| Hydroelectric | 1,179 |
| | 3 |
| | 662 |
| | 2 |
| | 617 |
| | 2 |
|
Other (b) | 393 |
| | 1 |
| | 705 |
| | 2 |
| | 294 |
| | 1 |
|
| Total | 34,205 |
| | 100 | % | | 34,615 |
| | 100 | % | | 34,258 |
| | 100 | % |
| |
|
| |
|
| | | | | | | | |
| Owned generation | 22,753 |
| | 67 | % | | 22,981 |
| | 66 | % | | 23,023 |
| | 67 | % |
| Purchased generation | 11,452 |
| | 33 |
| | 11,634 |
| | 34 |
| | 11,235 |
| | 33 |
|
| Total | 34,205 |
| | 100 | % | | 34,615 |
| | 100 | % | | 34,258 |
| | 100 | % |
|
| | | | |
(a)
Project | 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. | Capacity | | Estimated Completion |
| Cheyenne Ridge | | 500 MW | | 2020 |
| Various PPAs | | ~450 MW | | 2020-2021 |
Solar Energy Sources
Solar energy PPAs:
|
| | |
(b)
Type | | Capacity |
Distributed generation from the Solar*Rewards program is not included, and was approximately 396, 245 and 197 million net KWh for 2016, 2015, and 2014, respectively.Generation | | 557 MW |
| Utility-Scale | | 305 MW |
Fossil Fuel Energy Sources
PSCo’s fossil fuel energy portfolio includes coal and natural gas power from both owned generating facilities and PPAs.
See Item 2 — Properties for further information.
Coal Energy Sources
PSCo has four coal plants with approximately 2,000 MW of total 2019 net summer dependable capacity.
The following are PSCo’s approved coal plant retirements. In addition, PSCo plans to continue to evaluate its coal fleet for other potential early coal plant retirements as part of state resource plans or other regulatory proceedings.
|
| | | | |
| Approved (2019 to 2025) |
| Year | | Plant | | Capacity |
| 2022 | | Comanche 1 | | 325 MW |
| 2025 | | Comanche 2 | | 335 MW |
| 2025 | | Craig 1 | | 42 MW |
Coal Fuel Cost
Delivered cost per MMBtu of coal consumed for owned electric generation and the percentage of total fuel requirements:
|
| | | | | | | |
| | | Coal |
| | | Cost | | Percent |
| 2019 | | $ | 1.45 |
| | 55 | % |
| 2018 | | 1.45 |
| | 62 |
|
Natural Gas Energy Sources
PSCo has six natural gas plants with approximately 2,900 MW of total 2019 net summer dependable capacity. See item 2 - Properties for further detail.
Natural gas supplies, transportation and storage services for power plants are procured to provide an adequate supply of fuel. Remaining requirements are procured through a liquid spot market. Generally, natural gas supply contracts have variable pricing that is tied to natural gas indices. Natural gas supply and transportation agreements include obligations for the purchase and/or delivery of specified volumes or payments in lieu of delivery.
Natural Gas Cost
Delivered cost per MMBtu of natural gas consumed for owned electric generation and the percentage of total fuel requirements:
|
| | | | | |
| | | Natural Gas |
| | | Cost | | Percent |
| 2019 | | 3.27 |
| | 45 |
| 2018 | | 3.74 |
| | 38 |
NATURAL GAS UTILITY OPERATIONSCapacity and Demand
Uninterrupted system peak demand and occurrence date:
|
| | | | | | | | |
| System Peak Demand (in MW) |
| 2019 | | 2018 |
| 7,111 |
| | July 19 | | 6,718 |
| | July 10 |
OverviewTransmission
Transmission lines deliver electricity over long distances from power sources to transmission substations closer to homes and businesses. A strong transmission system ensures continued reliable and affordable service, ability to meet state and regional energy policy goals, and support a diverse generation mix, including renewable energy. PSCo owns more than 24,000 conductor miles of transmission lines across its service territory.
The most significant developments inDuring 2019, PSCo completed the naturalfollowing transmission projects:
|
| | | | | |
| Project | | Miles | | Size |
| Pawnee-Daniels Park | | 125 |
| | 345 KV |
| Thornton Substation | | 2 |
| | 115 KV |
Upcoming transmission projects:
|
| | | | | |
| Project | | Miles | | Size |
| Cheyenne Ridge | | 65 |
| | 345 KV |
Natural gas operations consist of PSCo are uncertainty regarding politicalpurchase, transportation 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 2016, average annual sales to the typical PSCo residential customer declined 16 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 becausedistribution of natural gas cost recovery mechanisms, high prices can encourage further efficiency efforts byto end use residential, C&I and transport customers. PSCo had natural gas deliveries of 334,698 (thousands of MMBtu), 1,425,895 customers and natural gas revenues of $1,160.9 (millions of dollars) for 2019.
The Pipeline and Hazardous Materials Safety AdministrationProtecting our Infrastructure of Pipelines and Enhancing Safety Act (PIPES) Act —The PIPES Act, signed into law in June 2016, requires the DOT PHMSA to issue regulations on the construction and operation of the nation’s underground gas storage fields. The act also grants PHMSA emergency order authority for pipeline operators, which would require operators to make immediate changes to assets or operations. The act also directs PHMSA to continue work on a variety of mandates from the 2012 Pipeline Safety, Regulatory Certainty, and Job Creation Act (Pipeline Safety Act), many of which have not been completed.Sales/Revenue Statistics
PHMSA issued interim final rules for underground storage operators in December 2016. PSCo operates three underground storage fields in Colorado and is developing a plan to meet the storage rules. PSCo does not expect these changes to have a material impact on costs or operating reliability. |
| | | | | | | | |
| | | 2019 | | 2018 |
| MMBtu sales per retail customer | | 109.80 |
| | 98.35 |
|
| Revenue per retail customer | | $ | 748.34 |
| | $ | 638.03 |
|
| Residential revenue per MMBtu | | 7.02 |
| | 6.67 |
|
| C&I revenue per MMBtu | | 6.33 |
| | 6.04 |
|
| Transportation and other revenue per MMBtu | | 0.56 |
| | 0.77 |
|
Pipeline Safety Act — The 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. The DOT PHMSA will require operators to re-confirm the maximum allowable operating pressure if records are inadequate. This process could cause temporary or permanent limitations on throughput for affected pipelines.
In addition, the Pipeline Safety Act requires PHMSA to issue reports and develop new regulations including: requiring use of automatic or remote-controlled shut-off valves; requiring testing of certain previously untested transmission lines; and expanding integrity management requirements. The Pipeline Safety Act also raises the maximum penalty for violating pipeline safety rules to $2 million per day for related violations. PSCo is taking actions that are intended to comply with the Pipeline Safety Act and any related PHMSA regulations as they become effective. PSCo cannot predict the ultimate impact the Pipeline Safety Act will have on its costs, operations or financial results. 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.
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. The rider has been extended through 2018.
QSP Requirements — The CPUC established a natural gas QSP that provides for bill credits to customers if PSCo does not achieve certain performance targets relating to natural gas leak repair time and customer service. The CPUC has extended the terms of the QSP through 2018.
Capability and Demand
Natural gas supply requirements are categorized as firm or interruptible (customers with an alternate energy supply). The maximum
Maximum daily send-outoutput (firm and interruptible) for PSCo was 1,932,070 MMBtu, which occurred on Dec. 17, 2016 and 1,633,493 MMBtu, which occurred on March 4, 2015.occurrence date:
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. |
| | | | | | | | |
| 2019 | | 2018 |
| MMBtu | | Date | | MMBtu | | Date |
| 2,139,420 |
| (a) | March 3 | | 1,903,878 |
| | Feb. 20 |
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.
| |
(a) | Increase in maximum MMBtu output due to colder winter temperatures in 2019. |
Natural Gas Supply and Costs
PSCo actively seeks natural gas supply, transportation and storage alternatives to yield a diversified portfolio, thatwhich 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.its state commissions.
The following table summarizes the averageAverage delivered cost per MMBtu of natural gas purchased for resale by PSCo’s regulated retail natural gas distribution business:distribution:
|
| | | |
| 2016 | $ | 3.27 |
|
| 2015 | 3.92 |
|
| 2014 | 4.91 |
|
The cost of natural gas in 2016 decreased due to lower 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, 2016, PSCo was committed to approximately $884 million in such obligations under these contracts, which expire in various years from 2017 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 2016, PSCo purchased natural gas from approximately 32 suppliers.
See Items 1A and 7Item 2 - Properties for further discussion of natural gas supply and costs.
information.
Natural Gas Operating Statistics
|
| | | | | | | | | | | |
| | Year Ended Dec. 31 |
| | 2016 | | 2015 | | 2014 |
| Natural gas deliveries (Thousands of MMBtu) | | | | | |
| Residential | 90,941 |
| | 92,001 |
| | 99,127 |
|
| Commercial and industrial | 38,093 |
| | 38,405 |
| | 40,438 |
|
| Total retail | 129,034 |
| | 130,406 |
| | 139,565 |
|
| Transportation and other | 117,462 |
| | 108,860 |
| | 108,006 |
|
| Total deliveries | 246,496 |
| | 239,266 |
| | 247,571 |
|
| | | | | | |
| Number of customers at end of period | | | | | |
| Residential | 1,269,338 |
| | 1,254,056 |
| | 1,240,674 |
|
| Commercial and industrial | 100,718 |
| | 100,389 |
| | 100,238 |
|
| Total retail | 1,370,056 |
| | 1,354,445 |
| | 1,340,912 |
|
| Transportation and other | 7,261 |
| | 6,936 |
| | 6,547 |
|
| Total customers | 1,377,317 |
| | 1,361,381 |
| | 1,347,459 |
|
| | | | | | |
| Natural gas revenues (Thousands of Dollars) | | | | | |
| Residential | $ | 611,804 |
| | $ | 678,909 |
| | $ | 824,633 |
|
| Commercial and industrial | 228,103 |
| | 257,287 |
| | 313,821 |
|
| Total retail | 839,907 |
| | 936,196 |
| | 1,138,454 |
|
| Transportation and other | 117,814 |
| | 70,470 |
| | 76,870 |
|
| Total natural gas revenues | $ | 957,721 |
| | $ | 1,006,666 |
| | $ | 1,215,324 |
|
| | | | | | |
| MMBtu sales per retail customer | 94.18 |
| | 96.28 |
| | 104.08 |
|
| Revenue per retail customer | $ | 613 |
| | $ | 691 |
| | $ | 849 |
|
| Residential revenue per MMBtu | 6.73 |
| | 7.38 |
| | 8.32 |
|
| Commercial and industrial revenue per MMBtu | 5.99 |
| | 6.70 |
| | 7.76 |
|
| Transportation and other revenue per MMBtu | 1.00 |
| | 0.65 |
| | 0.71 |
|
GENERAL
Seasonality
The demandDemand 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.
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 distributed generation including 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 promoteincentives for the development of rooftop solar, community solar gardens and other distributed energy resources through significant incentive policies; with these incentives and federal tax subsidies, distributedresources. Distributed generating resources are potential competitors to PSCo’s electric service business.
business with these incentives and federal tax subsidies.
The FERC has continued to promote competitive wholesale markets through open access transmission and other means. As a result, PSCo and itsPSCo’s wholesale customers can purchase their output from generation resources fromof competing wholesale suppliers or non-contracted quantities and use the transmission systems of Xcel Energy Inc.’s utility subsidiaries on a comparable basis to serve their native load. 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 No. 1000 seeks to establishestablished competition for construction and operation of certain new electric transmission facilities. State utilities commissions have also created resource planning programs that promote competition for electricity generation resources used to provide service to retail customers.
PSCo also has franchise agreements with certain cities subject to periodic renewal. Ifrenewal; however, 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 alternatives currently available alternatives.
available.
|
|
| Public Utility Regulation |
PSCo’sSee Item 7 for discussion of public utility regulation.
Environmental Regulation
Our facilities are regulated by federal and state environmental agencies. These agencies that have jurisdiction over air emissions, water quality, wastewater discharges, solid wastes and hazardous substances. Various company activities require registrations, permits, licenses, inspections and approvals from these agencies. PSCo has received all necessary authorizations for the construction and continued operation of its generation, transmission and distribution systems. PSCo’sOur facilities have been designed and constructed to operate in compliance with applicable environmental standards.standards and related monitoring and reporting requirements. However, it is not possible to determine when or to what extent additional facilities or modifications of existing or planned facilities will be required as a result of changes to environmental regulations, interpretations or enforcement policies or what effect future laws or regulations may have uponhave.
We may be required to incur expenditures in the future for remediation of MGP and other sites if it is determined that prior compliance efforts are not sufficient.
The Denver North Front Range Nonattainment Area does not meet either the 2008 or 2015 ozone National Ambient Air Quality Standard. Colorado will continue to consider further reductions available in the non-attainment area as it develops plans to meet ozone standards. Gas plants which operate in PSCo’s operations. See Notes 11 and 12non-attainment area may be required to the consolidated financial statements forimprove or add controls, implement further discussion.
work practices and/or enhanced emissions monitoring as part of future Colorado state plans.
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.GHGs. PSCo has undertaken a number ofnumerous 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 thetake into consideration investments we have already made to reduce GHG emissions, or if they require additional initiatives or emission reductions then their requirements wouldare required, substantial costs may be incurred.
In July 2019, the EPA adopted the Affordable Clean Energy rule, which requires states to develop plans for GHG reductions from coal-fired power plants. The state plans, due to the EPA in July 2022, will evaluate and potentially imposerequire heat rate improvements at existing coal-fired plants. It is not yet known how these state plans will affect PSCo’s existing coal plants, but they could require substantial additional substantial costs.investment, even in plants slated for retirement. PSCo believes, based on prior state commission practice, it would recover the cost of these initiatives or replacement generation would be recoverable through rates.
PSCo seeks to address climate change and potential climate change regulation through efforts to reduce its GHG emissions in a balanced, cost-effective manner.
As of Dec. 31, 2016,2019, PSCo had 2,5752,369 full-time employees and no part-time employees, of which 1,9841,884 were covered under collective-bargaining agreements. See Note 8 to the consolidated financial statements for further discussion.
Item 1A — Risk Factors
Xcel Energy, which includes PSCo, is subject to a variety of risks, many of which are beyond our control. Important risksRisks that may adversely affect the business, financial condition, and results of operations or cash flows 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 theThe Board of Directors is responsible for the oversight of material risk and our Board of Directors employsmaintaining an effective process for doing so.risk monitoring process. Management and eachthe Board of Directors’ committee hascommittees have responsibility for overseeing the identification and mitigation of key risks.
At a threshold level, PSCo maintains a robust compliance program and promotes a culture of compliance, beginning with the tone at the top. The risk mitigation process includes adherence to our code of conduct and compliance policies, operation of formal risk management structures and overall business management. PSCo further mitigates inherent risks through formal risk committees and corporate functions such as internal audit, and internal controls over financial reporting its assessments and activities to the full Board of Directors.
legal.
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 domesticIdentification and global economies and the environment when identifying, assessing, managing and mitigating risk. Identification andrisk analysis occurs formally through a key risk assessment process conducted by senior management, the financial disclosure process, the hazard risk management process andprocedures, internal auditingaudit and compliance with financial and operational controls. Management also identifies and analyzes risk through itsthe business planning process, and development of goals and establishment of key performance indicators, which include riskincluding identification to determineof barriers to implementing our strategy. The business planning process also identifies areas in which there is a potential for a business arealikelihood and mitigating factors to takeprevent the assumption of 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 strategy. Building on this culture of compliance, PSCo manages and 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.
goals.
Management communicates regularly with the Board of Directors and key stakeholdersits sole stockholder regarding risk. Senior management presents and communicates a periodic risk assessment of key risks to the Board of Directors. The presentation and the discussion of the key risks provides the Board of Directors, withproviding information on the risks that management believes are material, including the earningsfinancial impact, timing, likelihood and controllability. Management also provides information to the Board of Directors in presentations and communications over the course of the year.
mitigating factors. The Board of Directors approaches oversight, management and mitigation of risk as an integral and continuous part of its governance of PSCo. First, the Board of Directors regularly reviews management’s key risk assessment and analyzesassessments, which includes areas of existing and future risksmacroeconomic, financial, operational, policy, environmental and opportunities. In addition,security risks.
The oversight, management and mitigation of risk is an integral and continuous part of the Board of Directors assigns oversightDirectors’ governance of certain critical risks to each of its four standing committeesPSCo. Processes are in place to ensure these risks are well understood and given focused oversight by the appropriate committee. The Audit Committee is responsible for reviewing the adequacy of risk oversight, as well as identification and affirming that appropriate oversight occurs. New risks are considered and assigned as appropriate during the annual Boardconsideration of Directors’ and committee evaluation process, and committee charters and annual work plans are updated accordingly. Committees regularly report on their oversight activities and certain risk issues may be brought to the full Board of Directors for consideration where deemed appropriate to ensure broad Board of Directors’ understanding of the nature of the risk. Finally, the Board of Directors conducts an annual strategy session where PSCo’s future plans and initiatives are reviewed and confirmed.new risks.
Risks Associated with Our Business
EnvironmentalOperational Risks
We are subject to environmental lawsOur natural gas and regulations, with which compliance could be difficultelectric transmission and costly.
We are subject to environmental laws and regulationsdistribution operations involve numerous risks 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 and 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), licenses, permits, inspections and other approvals. 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. At Dec. 31, 2016, these sites included:
Sites of former MGPs operated by us, our predecessors or other entities; and
Third party sites, such as landfills, for which we are alleged to be a PRP that sent hazardous materials and wastes.
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, whichaccidents and other operating risks and costs.
Our natural gas transmission and distribution activities include inherent hazards and operating risks, such as leaks, explosions, outages and mechanical problems. Our electric generation, transmission and distribution activities include inherent hazards and operating risks such as contact, fire and outages. These risks could result in loss of life, significant property damage, environmental pollution, impairment of our operations and substantial financial losses. We maintain insurance against most, but not all, of these risks and losses. The occurrence of these events, if not fully covered by insurance, could have a material effect on our financial condition, results of operations. Ifoperations and cash flows.
Additionally, compliance with existing and potential new regulations related to the operation and maintenance of our regulators do not allow usnatural gas infrastructure could result in significant costs. The PHMSA is responsible for administering the DOT’s national regulatory program to recover all or a partassure the safe transportation of the costnatural gas, petroleum and other hazardous materials by pipelines. The PHMSA continues to develop regulations and other approaches to risk management to assure safety in design, construction, testing, operation, maintenance and emergency response of capital investment or the O&M costs incurrednatural gas pipeline infrastructure. We have programs in place to comply with the mandates, itPHMSA regulations and systematically monitor and renew infrastructure over time; however, a significant incident or material finding of non-compliance could result in penalties and higher costs of operations.
Our natural gas and electric transmission and distribution operations are dependent upon complex information technology systems and network infrastructure, the failure of which could disrupt our normal business operations, which could have a material adverse effect on our ability to process transactions and provide services.
Our utility operations are subject to long-term planning and project risks.
Most electric utility investments are planned to be used for decades. Transmission and generation investments typically have long lead times and are planned well in advance of when they are brought in-service subject to long-term resource plans. These plans are based on numerous assumptions such as: sales growth, customer usage, commodity prices, economic activity, costs, regulatory mechanisms, customer behavior, available technology and public policy. Our long-term resource plan is dependent on our ability to obtain required approvals, develop necessary technical expertise, allocate and coordinate sufficient resources and adhere to budgets and timelines.
In addition, the long-term nature of both our planning and our asset lives are subject to risk. The electric utility sector is undergoing a period of significant change. For example, increases in energy efficiency, wider adoption of lower cost renewable generation, distributed generation and shifts away from coal generation to decrease carbon emissions and increasing use of natural gas in electric generation driven by lower natural gas prices. Customer adoption of these technologies and increased energy efficiency could result in excess transmission and generation resources, downward pressure on sales growth, as well as stranded costs if PSCo is not able to fully recover costs and investments.
Changing customer expectations and technologies are requiring significant investments in advanced grid infrastructure, which increases exposure to technology obsolescence.
Evolving stakeholder preference for lower emission generation sources may pressure our investments in natural gas generation and delivery. The magnitude and timing of resource additions and changes in customer demand may not coincide while customer preference for resource generation may change, which introduces further uncertainty into long-term planning. Additionally, multiple states may not agree as to the appropriate resource mix which may lead to costs to comply with one jurisdiction that are not recoverable across all jurisdictions served by the same assets.
We are subject to longer-term availability of inputs such as coal, natural gas, uranium and water to cool our facilities. Lack of availability of these resources could jeopardize long-term operations of our facilities or make them uneconomic to operate.
We are subject to commodity risks and other risks associated with energy markets and energy production.
In the event fuel costs increase, customer demand could decline and bad debt expense may rise, which may have a material impact on our results of operations. Despite existing fuel recovery mechanisms, higher fuel costs could significantly impact our results of operations if costs are not recovered. Delays in the timing of the collection of fuel cost recoveries could impact our cash flows.
A significant disruption in supply could cause us to seek alternative supply services at potentially higher costs and supply shortages may not be fully resolved, which could cause disruptions in our ability to provide services to our customers. Failure to provide service due to disruptions may also result in fines, penalties or cost disallowances through the regulatory process. Also, significantly higher energy or fuel costs relative to sales commitments could negatively impact our cash flows and results of operations.
We also engage in wholesale sales and purchases of electric capacity, energy and energy-related products as well as natural gas. In many markets, emission allowances and/or RECs are also needed to comply with various statutes and commission rulings. As a result, we are subject to market supply and commodity price risk. Commodity price changes can affect the value of our commodity trading derivatives. We mark certain derivatives to estimated fair market value on a daily basis. Settlements can vary significantly from estimated fair values recorded and significant changes from the assumptions underlying our fair value estimates could cause earnings variability.
Failure to attract and retain a qualified workforce could have an adverse effect on operations.
Certain specialized knowledge is required of our technical employees for construction and operation of transmission, generation and distribution assets. Our business strategy is dependent on our ability to recruit, retain and motivate employees. Competition for skilled employees is high in the areas of business operations. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to new employees or future availability and cost of contract labor may adversely affect the ability to manage and operate our business. We have seen a tightening of supply for engineers and skilled laborers in certain markets and are implementing plans to retain these employees. Inability to attract and retain these employees could adversely impact our results of operations, financial positioncondition or cash flows.
Our operations use third-party contractors in addition to employees to perform periodic and ongoing work.
In addition, existing environmental lawsWe rely on third-party contractors to perform operations, maintenance and construction work. Our contractual arrangements with these contractors typically include performance standards, progress payments, insurance requirements and security for performance.
Poor vendor performance could impact ongoing operations, restoration operations, our reputation and could introduce financial risk or regulations may be revised, and new laws or regulations may be adopted or become applicable to us, including but not limited to, regulationrisks 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.
fines.
We are subjecta 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 physical and financial risks associated with climate change.be adverse to our interests.
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. ToAll of 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 outsidemembers of our service territoryBoard of Directors, as well as many of our executive officers, are officers of Xcel Energy Inc. Our Board of Directors makes determinations with respect to a number of significant corporate events, including the payment of our dividends.
We have historically paid quarterly dividends to Xcel Energy Inc. In 2019, 2018 and 2017 we paid $457.6 million, $375.3 million and $333.9 million of dividends to Xcel Energy Inc., respectively. If Xcel Energy Inc.’s cash requirements increase, our Board of Directors could 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 woulddecide to increase the cost of energydividends we providepay to our customers.
Severe weather impacts our service territories, primarily when thunderstorms, tornadoes 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,Xcel Energy Inc. to help support Xcel Energy Inc.’s cash needs. This could adversely affect our operations, principally our fossil generating units. A negative impact to water supplies due to long-term drought conditions could adversely impact our ability to provide electricity to customers, as well as increaseliquidity. The most restrictive dividend limitation for PSCo is imposed by its credit facility, which limits the price they pay for energy. We may not recover all costs related to mitigating these physical and financial risks.debt-to-total capitalization ratio.
Climate change may impact a region’s economic health, which could impact our revenues. Our financial performance is tiedSee Note 5 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 CO2 emissions under the CAA, 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 pricesconsolidated financial statements 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.further information.
FinancialOperational 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 profitability dependsnatural gas transmission and distribution activities include inherent hazards and operating risks, such as leaks, explosions, outages and mechanical problems. Our electric generation, transmission and distribution activities include inherent hazards and operating risks such as contact, fire and outages. These risks could result in partloss of life, significant property damage, environmental pollution, impairment of our operations and substantial financial losses. We maintain insurance against most, but not all, of these risks and losses. The occurrence of these events, if not fully covered by insurance, could have a material effect on our financial condition, results of operations and cash flows.
Additionally, compliance with existing and potential new regulations related to the operation and maintenance of our natural gas infrastructure could result in significant costs. The PHMSA is responsible for administering the DOT’s national regulatory program to assure the safe transportation of natural gas, petroleum and other hazardous materials by pipelines. The PHMSA continues to develop regulations and other approaches to risk management to assure safety in design, construction, testing, operation, maintenance and emergency response of natural gas pipeline infrastructure. We have programs in place to comply with the PHMSA regulations and systematically monitor and renew infrastructure over time; however, a significant incident or material finding of non-compliance could result in penalties and higher costs of operations.
Our natural gas and electric transmission and distribution operations are dependent upon complex information technology systems and network infrastructure, the failure of which could disrupt our normal business operations, which could have a material adverse effect on our ability to recover costs from our customersprocess transactions and there may be changes in circumstances or in the regulatory environment that impair our ability to recover costs from our customers.provide services.
WeOur utility operations are subject to comprehensive regulation by federallong-term planning and stateproject risks.
Most electric utility investments are planned to be used for decades. Transmission and generation investments typically have long lead times and are planned well in advance of when they are brought in-service subject to long-term resource plans. These plans are based on numerous assumptions such as: sales growth, customer usage, commodity prices, economic activity, costs, regulatory agencies. The CPUC regulates many aspects of our utility operations, including sitingmechanisms, customer behavior, available technology 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 operationspublic policy. Our long-term resource plan is dependent on our ability to recoverobtain required approvals, develop necessary technical expertise, allocate and coordinate sufficient resources and adhere to budgets and timelines.
In addition, the costslong-term nature of providing energyboth our planning 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. Weasset lives are subject to both futurerisk. The electric utility sector is undergoing a period of significant change. For example, increases in energy efficiency, wider adoption of lower cost renewable generation, distributed generation and historical test years depending upon the regulatory mechanisms approvedshifts away from coal generation to decrease carbon emissions and increasing use of natural gas 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 rateelectric generation driven by lower natural gas prices. Customer adoption 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, whichthese technologies and increased energy efficiency 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 retirementsexcess transmission and while regulation typically provides relief for these types of changes, theregeneration resources, downward pressure on sales growth, as well as stranded costs if PSCo is no assurance that regulators would allow full recovery of all remaining costs leaving all or a portion of these asset costs stranded. Rising fuel costs could increase the risk that we will not be able to fully recover costs and investments.
Changing customer expectations and technologies are requiring significant investments in advanced grid infrastructure, which increases exposure to technology obsolescence.
Evolving stakeholder preference for lower emission generation sources may pressure our fuel costs from our customers. Furthermore, there could beinvestments in natural gas generation and delivery. The magnitude and timing of resource additions and changes in the regulatory environment that would impair our ability to recover costs historically collected from our customers.
Management currently believes these prudently incurred costs are recoverable given the existing regulatory mechanisms in place. However, 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 effectcustomer demand may not coincide while customer preference for any given period of time, or that a rating will not be lowered or withdrawn entirely by a rating agency. In addition, our credit ratingsresource generation may change, which introduces further uncertainty into long-term planning. Additionally, multiple states may not agree as a result ofto the differing methodologies or change in the methodologies usedappropriate resource mix which may lead to costs to comply with one jurisdiction that are not recoverable across all jurisdictions served by the various rating agencies. Any downgrade could lead to higher borrowing costs. 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.
same assets.
We are subject to capital marketlonger-term availability of inputs such as coal, natural gas, uranium and interest rate risks.water to cool our facilities. Lack of availability of these resources could jeopardize long-term operations of our facilities or make them uneconomic to operate.
We are subject to commodity risks and other risks associated with energy markets and energy production.
Utility operations require significant capital investment. As a result, we frequently need to access capital markets. Any disruption in capital marketsIn the event fuel costs increase, customer demand could decline and bad debt expense may rise, which may have a material impact on our ability to fundresults of operations. Despite existing fuel recovery mechanisms, higher fuel costs could significantly impact our operations. Capital marketsresults of operations if costs are globalnot recovered. Delays in nature and are impacted by numerous issues and events throughout the world economy. Capital markettiming of the collection of fuel cost recoveries could impact our cash flows.
A significant disruption events and resulting broad financial market distressin supply could prevent us from issuing new securities or cause us to issue securitiesseek alternative supply services at potentially higher costs and supply shortages may not be fully resolved, which could cause disruptions in our ability to provide services to our customers. Failure to provide service due to disruptions may also result in fines, penalties or cost disallowances through the regulatory process. Also, significantly higher energy or fuel costs relative to sales commitments could negatively impact our cash flows and results of operations.
We also engage in wholesale sales and purchases of electric capacity, energy and energy-related products as well as natural gas. In many markets, emission allowances and/or RECs are also needed to comply with less than ideal termsvarious statutes and conditions, such as higher interest rates.commission rulings. As a result, we are subject to market supply and commodity price risk. Commodity price changes can affect the value of our commodity trading derivatives. We mark certain derivatives to estimated fair market value on a daily basis. Settlements can vary significantly from estimated fair values recorded and significant changes from the assumptions underlying our fair value estimates could cause earnings variability.
Higher interest rates on short-term borrowings with variable interest ratesFailure to attract and retain a qualified workforce could also have an adverse effect on operations.
Certain specialized knowledge is required of our operating results. Changes in interest rates may also impact the fair valuetechnical employees for construction and operation of the debt securities in the master pension trust, as well astransmission, generation and distribution assets. Our business strategy is dependent on our ability to earn a return on short-term investmentsrecruit, retain and motivate employees. Competition for skilled employees is high in the areas of excess cash.
We are subjectbusiness operations. Failure to credit risks.
Credit risk includes the risk that our customers will not pay their bills, which may lead to a reduction in liquidityhire and an increase in bad debt expense. Credit risk is comprised of numerous factorsadequately train replacement employees, including the pricetransfer of productssignificant internal historical knowledge and services provided,expertise to new employees or future availability and cost of contract labor may adversely affect the overall economyability to manage and local economiesoperate our business. We have seen a tightening of supply for engineers and skilled laborers 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 breach their obligations. Should the counterpartiescertain markets and are implementing plans to retain these arrangements failemployees. Inability to perform, we may be forced to enter into alternative arrangements. In that event, our financial resultsattract and retain these employees could be adversely affected and we could incur losses.
One alternative available to address counterparty credit risk is to transact on liquid commodity exchanges. The credit risk is then socialized through the exchange central clearinghouse function. While exchanges do remove counterparty credit risk, all participants are subject to margin requirements, which create an additional need for liquidity to post margin as exchange positions change value daily. The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) requires broad clearing of financial swap transactions through a central counterparty, which could lead to additional margin requirements that would impact our liquidity. However, we have taken advantage of an exception to mandatory clearing afforded to commercial end-users who are not classified as a major swap participant. The Board of Directors has authorized Xcel Energy and its subsidiaries to take advantage of this end-user exception.
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 SPP, PJM, 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 adverselyaffect our results of operations, financial positioncondition or liquidity.cash flows.
Our operations use third-party contractors in addition to employees to perform periodic and ongoing work.
We rely on third-party contractors to perform operations, maintenance and construction work. Our contractual arrangements with these contractors typically include performance standards, progress payments, insurance requirements and security for performance.
Poor vendor performance could impact ongoing operations, restoration operations, our reputation and could introduce financial risk or risks of fines.
We are a wholly owned subsidiary of Xcel Energy Inc. Xcel Energy Inc. can exercise substantial control over our dividend policy and business and operations and may exercise that control in a manner that may be perceived to be adverse to our interests.
All of the members of our Board of Directors, as well as many of our executive officers, are officers of Xcel Energy Inc. Our Board of Directors makes determinations with respect to a number of significant corporate events, including the payment of our dividends.
We have defined benefit pensionhistorically paid quarterly dividends to Xcel Energy Inc. In 2019, 2018 and postretirement plans that cover most2017 we paid $457.6 million, $375.3 million and $333.9 million of dividends to Xcel Energy Inc., respectively. If Xcel Energy Inc.’s cash requirements increase, our employees. Assumptions relatedBoard of Directors could decide to future costs, return on investments, interest rates and other actuarial assumptions, including mortality tables, have a significant impact on our funding requirements relatedincrease the dividends we pay 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 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 dueXcel Energy Inc. to high retirements or employees leaving PSCohelp support Xcel Energy Inc.’s cash needs. This 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.liquidity. The most restrictive dividend limitation for PSCo is imposed by its credit facility, which limits the debt-to-total capitalization ratio.
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.
Changes in federal tax law may significantly impact our business.
There are a number of provisions in federal tax law designed to incentivize capital investments which have benefited our customers by keeping rates lower than without such provisions. Examples of these include the use of accelerated and bonus depreciation for most of our capital investments, PTCs for wind energy, investment tax credits for solar energy and research and development tax credits and deductions. Changes to current federal tax law have the ability to benefit or adversely affect our earnings and our customer costs. Significant changes in corporate tax rates could result in the impairment of deferred tax assets that are established based on existing law. ChangesSee Note 5 to 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 realization of the changes.consolidated financial statements for further information.
Operational Risks
Our natural gas and electric transmission and distribution operations involve numerous risks that may result in accidents and other operating risks and costs.
Our natural gas transmission and distribution activities include inherent hazards and operating risks, such as leaks, explosions, outages and mechanical problems. Our electric generation, transmission and distribution activities include inherent hazards and operating risks such as contact, fire and outages. These risks could result in loss of life, significant property damage, environmental pollution, impairment of our operations and substantial financial losses. We maintain insurance against most, but not all, of these risks and losses. The occurrence of these events, if not fully covered by insurance, could have a material effect on our financial condition, results of operations and cash flows.
Additionally, compliance with existing and potential new regulations related to the operation and maintenance of our natural gas infrastructure could result in significant costs. The PHMSA is responsible for administering the DOT’s national regulatory program to assure the safe transportation of natural gas, petroleum and other hazardous materials by pipelines. The PHMSA continues to develop regulations and other approaches to risk management to assure safety in design, construction, testing, operation, maintenance and emergency response of natural gas pipeline infrastructure. We have programs in place to comply with the PHMSA regulations and systematically monitor and renew infrastructure over time; however, a significant incident or material finding of non-compliance could result in penalties and higher costs of operations.
Our natural gas and electric transmission and distribution operations are dependent upon complex information technology systems and network infrastructure, the failure of which could disrupt our normal business operations, which could have a material adverse effect on our ability to process transactions and provide services.
Our utility operations are subject to long-term planning and project risks.
Most electric utility investments are planned to be used for decades. Transmission and generation investments typically have long lead times and are planned well in advance of when they are brought in-service subject to long-term resource plans. These plans are based on numerous assumptions such as: sales growth, customer usage, commodity prices, economic activity, costs, regulatory mechanisms, customer behavior, available technology and public policy. Our long-term resource plan is dependent on our ability to obtain required approvals, develop necessary technical expertise, allocate and coordinate sufficient resources and adhere to budgets and timelines.
In addition, the long-term nature of both our planning and our asset lives are subject to risk. The electric utility sector is undergoing a period of significant change. For example, increases in energy efficiency, wider adoption of lower cost renewable generation, distributed generation and shifts away from coal generation to decrease carbon emissions and increasing use of natural gas in electric generation driven by lower natural gas prices. Customer adoption of these technologies and increased energy efficiency could result in excess transmission and generation resources, downward pressure on sales growth, as well as stranded costs if PSCo is not able to fully recover costs and investments.
Changing customer expectations and technologies are requiring significant investments in advanced grid infrastructure, which increases exposure to technology obsolescence.
Evolving stakeholder preference for lower emission generation sources may pressure our investments in natural gas generation and delivery. The magnitude and timing of resource additions and changes in customer demand may not coincide while customer preference for resource generation may change, which introduces further uncertainty into long-term planning. Additionally, multiple states may not agree as to the appropriate resource mix which may lead to costs to comply with one jurisdiction that are not recoverable across all jurisdictions served by the same assets.
We are subject to longer-term availability of inputs such as coal, natural gas, uranium and water to cool our facilities. Lack of availability of these resources could jeopardize long-term operations of our facilities or make them uneconomic to operate.
We are subject to commodity risks and other risks associated with energy markets and energy production.
In the event fuel costs increase, customer demand could decline and bad debt expense may rise, which may have a material impact on our results of operations. Despite existing fuel recovery mechanisms, higher fuel costs could significantly impact our results of operations if costs are not recovered. Delays in the timing of the collection of fuel cost recoveries could impact our cash flows.
A significant disruption in supply could cause us to seek alternative supply services at potentially higher costs and supply shortages may not be fully resolved, which could cause disruptions in our ability to provide services to our customers. Failure to provide service due to disruptions may also result in fines, penalties or cost disallowances through the regulatory process. Also, significantly higher energy or fuel costs relative to sales commitments could negatively impact our cash flows and results of operations.
We also engage in wholesale sales and purchases of electric capacity, energy and energy-related products as well as natural gas. In many markets, emission allowances and/or RECs are also needed to comply with various statutes and commission rulings. As a result, we are subject to market supply and commodity price risk. Commodity price changes can affect the value of our commodity trading derivatives. We mark certain derivatives to estimated fair market value on a daily basis (mark-to-market accounting). Actual settlementsbasis. Settlements can vary significantly from estimated fair values recorded and significant changes from the assumptions underlying our fair value estimates could cause significant earnings variability.
If we encounter market supply shortages or our suppliers are otherwise unableFailure to meet their contractual obligations, we may be unable to fulfill our contractual obligations to our customers at previously anticipated costs. Therefore,attract and retain 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 commitmentsqualified workforce could have a negative impactan adverse effect on operations.
Certain specialized knowledge is required of our cash flowstechnical employees for construction and potentially result in economic losses. Potential market supply shortages may not be fully resolved through alternative supply sourcesoperation of transmission, generation and may cause short-term disruptions indistribution assets. Our business strategy is dependent on our ability to provide electric and/recruit, retain and motivate employees. Competition for skilled employees is high in the areas of business operations. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to new employees or natural gas servicesfuture availability and cost of contract labor may adversely affect the ability to manage and operate our business. We have seen a tightening of supply for engineers and skilled laborers in certain markets and are implementing plans to retain these employees. Inability to attract and retain these employees could adversely impact our results of operations, financial condition or cash flows.
Our operations use third-party contractors in addition to employees to perform periodic and ongoing work.
We rely on third-party contractors to perform operations, maintenance and construction work. Our contractual arrangements with these contractors typically include performance standards, progress payments, insurance requirements and security for performance.
Poor vendor performance could impact ongoing operations, restoration operations, our reputation and could introduce financial risk or risks of fines.
We are a wholly owned subsidiary of Xcel Energy Inc. Xcel Energy Inc. can exercise substantial control over our dividend policy and business and operations and may exercise that control in a manner that may be perceived to be adverse to our customers.interests.
All of the members of our Board of Directors, as well as many of our executive officers, are officers of Xcel Energy Inc. Our Board of Directors makes determinations with respect to a number of significant corporate events, including the payment of our dividends.
We have historically paid quarterly dividends to Xcel Energy Inc. In 2019, 2018 and 2017 we paid $457.6 million, $375.3 million and $333.9 million of dividends to Xcel Energy Inc., respectively. If Xcel Energy Inc.’s cash requirements increase, our Board of Directors could decide to increase the dividends we pay to Xcel Energy Inc. to help support Xcel Energy Inc.’s cash needs. This could adversely affect our liquidity. The impact of these cost and reliability issuesmost restrictive dividend limitation for PSCo is imposed by its credit facility, which limits the debt-to-total capitalization ratio.
See Note 5 to the consolidated financial statements for further information.
Financial Risks
Our profitability depends on our 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.ability to recover costs from our customers and changes in regulation may impair our ability to recover costs from our customers.
Our utility operationsWe are subject to long-term planning risks.comprehensive regulation by federal and state utility regulatory agencies, including siting and construction of facilities, customer service and the rates that we can charge customers.
The profitability of our operations is dependent on our ability to recover the costs of providing energy and utility services and earn a return on our capital investment. Our rates are generally regulated and based on an analysis of our costs incurred in a test year. We are subject to both future and historical test years depending upon the regulatory jurisdiction. Thus, the rates we are allowed to charge may or may not match our costs at any given time. Rate regulation is premised on providing an opportunity to earn a reasonable rate of return on invested capital.
Most electric utility investments are long-lived and are plannedThere can also be no assurance that our regulatory commissions will judge all our costs 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, 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 efficiencyprudent, which 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 riskdisallowances, or that the magnitude and timing of resource additions and growthregulatory process will always result in customer demand may not coincide, andrates 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 during the planning period 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 utilitywill produce full recovery. Overall, management believes prudently incurred costs are recoveredrecoverable given the existing regulatory framework. However, there may be changes in the regulatory environment that could impair our ability to recover costs historically collected from customers, as they receive the benefit of service. PSCo is engaged in significantor we could exceed caps on capital costs (e.g., wind projects) required by commissions and ongoing infrastructure investment programs to accommodate distributed generation and maintain high system reliability. 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.
Changes in the long-term cost-effectiveness or to the operating conditions of our assets may result in early retirements of utility facilities. While regulation typically provides relief for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs. Both decreasing use per customer driven by appliance and lighting efficiency and the availability of cost-effective distributed generation puts
In a continued low interest rate environment there has been increased downward pressure on load growth. Thisallowed ROE. Conversely, higher than expected inflation or tariffs may increase costs of construction and operations. Also, rising fuel costs could increase the risk that we will not be able to fully recover our fuel costs from our customers.
Adverse regulatory rulings or the imposition of additional regulations could have an adverse impact on our results of operations and materially affect our ability to meet our financial obligations, including debt payments.
Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships.
We cannot be assured that our current ratings will remain in effect, or that a rating will not be lowered or withdrawn by a rating agency. Significant events including disallowance of costs, significantly lower returns on equity, changes to equity ratios and impacts of tax policy may impact our cash flows and credit metrics, potentially resulting in a change in our credit ratings. In addition, our credit ratings may change as a result of the differing methodologies or change in the methodologies used by the various rating agencies.
Any downgrade could lead to under recoveryhigher borrowing costs and could impact our ability to access capital markets. Also, we may enter into contracts that require posting of costs, excess resourcescollateral or settlement of applicable contracts if credit ratings fall below investment grade.
We are subject to meet customer demandcapital market and increasesinterest rate risks.
Utility operations require significant capital investment. As a result, we frequently need to access capital markets. Capital markets are global and impacted by issues and events throughout the world. Any disruption in electric rates.
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 insurancecapital markets could have a material impact on our ability to fund our operations. Capital market disruption and financial market distress could prevent us from issuing short-term commercial paper, issuing new securities or cause us to issue securities with unfavorable terms and conditions, such as higher interest rates. Higher interest rates on short-term borrowings with variable interest rates could also have an adverse effect on our financial positionoperating results.
We are subject to credit risks.
Credit risk includes the risk that our customers will not pay their bills, which may lead to a reduction in liquidity and resultsan increase in bad debt expense. Credit risk is comprised of operations. For our natural gas transmissionnumerous 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 distribution lines located near populated areas,product will become insolvent and may breach their obligations. Should the level of potential damages resulting from these risks is greater.
Additionally, for natural gas the operating or other costs thatcounterparties fail to perform, we may be required in orderforced to comply with potential new regulations, including the Pipeline Safety Act,enter into alternative arrangements. In that event, our financial results could be significant. The Pipeline Safety Act requires verificationadversely affected and incur losses.
We may at times have direct credit exposure in our short-term wholesale and commodity trading activity to financial institutions trading for their own accounts or issuing collateral support on behalf of pipeline infrastructure records by pipeline ownersother counterparties. We may also have some indirect credit exposure due to participation in organized markets, such as the California Independent System Operator, SPP, PJM Interconnection, LLC, Midcontinent Independent System Operator, Inc. and operatorsthe Electric Reliability Council of Texas, in which any credit losses are socialized to confirm the maximum allowable operating pressure of lines located in high consequence areas or more-densely populated areas. all market participants.
We have programsadditional indirect credit exposure to financial institutions in placethe form of letters of credit provided as security by power suppliers under various purchased power contracts. If any of the credit ratings of the letter of credit issuers were to complydrop below investment grade, the supplier would need to replace that security with an acceptable substitute. If the Pipeline Safety Act and for systematic infrastructure monitoring and renewal over time. A significant incidentsecurity were not replaced, the party could increase regulatory scrutiny and resultbe in penalties and higher costs of operations.default under the contract.
As we are a subsidiary of Xcel Energy Inc., we may be negatively affected by events impacting the credit or liquidity of Xcel Energy Inc. and its affiliates.
If 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, 2016,2019, Xcel Energy Inc. and its utility subsidiaries had approximately $14.2$17.4 billion of long-term debt and $0.6$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, 2016,2019, Xcel Energy had guarantees outstanding with a maximum stated amount of approximately $18.8$2.0 million and exposure of $0.1 million.immaterial exposure. Xcel Energy also had additional guarantees of $43.0$60.4 million at Dec. 31, 20162019 for performance and payment of surety bonds for the benefit of itself and its subsidiaries, with total exposure that cannot be estimated at this time. If Xcel Energy Inc. were to become obligated to make payments under these guarantees and bond indemnities or become obligated to fund other contingent liabilities, it could limit Xcel Energy Inc.’s ability to contribute equity or make loans to us or may cause Xcel Energy Inc. to seek additional or accelerated funding from us in the form of dividends. If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.
Increasing costs of our defined benefit retirement plans and employee benefits may adversely affect our results of operations, financial condition or cash flows.
We arehave defined benefit pension and postretirement plans that cover most of our employees. Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a wholly owned subsidiarysignificant impact on our funding requirements related to these plans. Estimates and assumptions may change. In addition, the Pension Protection Act changed the minimum funding requirements for defined benefit pension plans. Therefore, our funding requirements and related contributions may change in the future. Also, the payout of Xcel Energy Inc. Xcel Energy Inc. can exercise substantial control over our dividend policy and business and operations and may exercise that controla significant percentage of pension plan liabilities in a manner thatsingle year due to high numbers of retirements or employees leaving PSCo would trigger settlement accounting and could require PSCo to recognize incremental pension expense related to unrecognized plan losses in the year liabilities are paid. Changes in industry standards utilized in key assumptions (e.g., mortality tables) could have a significant impact on future liabilities and benefit costs.
Increasing costs associated with health care plans may be perceived to beadversely affect our results of operations.
Increasing levels of large individual health care claims and overall health care claims could have an adverse toimpact on our interests.results of operations, financial condition or cash flows. Health care legislation could also significantly impact our benefit programs and costs.
AllFederal tax law may significantly impact our business.
PSCo collects through regulated rates estimated federal, state and local tax payments. Changes to federal tax law may benefit or adversely affect our earnings and customer costs. Tax depreciable lives and the value of various tax credits or the timeliness of their utilization may impact the economics or selection of resources. There could be timing delays before regulated rates provide for realization of tax changes in revenues. In addition, certain IRS tax policies such as tax normalization may impact our ability to economically deliver certain types of resources relative to market prices.
Macroeconomic Risks
Economic conditions impact our business.
Our operations are affected by local, national and worldwide economic conditions, which correlates to customers/sales growth (decline). Economic conditions may be impacted by insufficient financial sector liquidity leading to potential increased unemployment, which may impact customers’ ability to pay their bills which could lead to additional bad debt expense.
Additionally, PSCo faces competitive factors, which could have an adverse impact on our financial condition, results of operations and cash flows. Further, worldwide economic activity impacts the demand for basic commodities necessary for utility infrastructure, which may inhibit our ability to acquire sufficient supplies. We operate in a capital intensive industry and federal trade policy could significantly impact the cost of materials we use. There may be delays before these additional material costs can be recovered in rates.
Operations could be impacted by war, terrorism or other events.
Our generation plants, fuel storage facilities, transmission and distribution facilities and information and control systems may be targets of terrorist activities. Any disruption could impact operations or result in a decrease in revenues and additional costs to repair and insure our assets. These disruptions could have a material impact on our financial condition, results of operations or cash flows. The potential for terrorism has subjected our operations to increased risks and could have a material effect on our business. We have already incurred increased costs for security and capital expenditures in response to these risks. The insurance industry has also been affected by these events and the availability of insurance may decrease. In addition, insurance may have higher deductibles, higher premiums and more restrictive policy terms.
A disruption of the membersregional electric transmission grid, interstate natural gas pipeline infrastructure or other fuel sources, could negatively impact our business, our brand and reputation. Because our facilities are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by the actions of a neighboring utility.
We also face the risks of possible loss of business due to significant events such as severe storm, severe temperature extremes, wildfires (particularly in Colorado), widespread pandemic, generator or transmission facility outage, pipeline rupture, railroad disruption, operator error, sudden and significant increase or decrease in wind generation or a disruption of work force within our Boardoperating systems (or on a neighboring system).
The recent coronavirus outbreak in China is an example of Directors,how major catastrophic events throughout the world may disrupt our business. While we are a domestic company, the Company participates in a global supply chain, which includes materials and components that are sourced from China. A prolonged disruption could result in the delay of equipment and materials that may impact our ability to reliably serve our customers.
Disruption due to events such as those noted above could result in a significant decrease in revenues and significant additional costs to repair assets, which could have a material impact on our results of operations, financial condition or cash flows.
PSCo participates in biennial grid security and emergency response exercises (GridEx). These efforts, led by the NERC, test and further develop the coordination, threat sharing and interaction between utilities and various government agencies relative to potential cyber and physical threats against the nation’s electric grid.
A cyber incident or security breach could have a material effect on our business.
We operate in an industry that requires the continued operation of sophisticated information technology, control systems and network infrastructure. In addition, we use our systems and infrastructure to create, collect, use, disclose, store, dispose of and otherwise process sensitive information, including company data, customer energy usage data, and personal information regarding customers, employees and their dependents, contractors and other individuals.
Our generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets, as well as manyinformation processed in our systems (e.g., information regarding our customers, employees, operations, infrastructure and assets) could be affected by cyber security incidents, including those caused by human error. Our industry has been the target of several attacks on operational systems and has seen an increased volume and sophistication of cyber security incidents from international activist organizations, Nation States and individuals. Cyber security incidents could harm our businesses by limiting our generating, transmitting and distributing capabilities, delaying our development and construction of new facilities or capital improvement projects to existing facilities, disrupting our customer operations or causing the release of customer information, all of which would likely receive state and federal regulatory scrutiny and could expose us to liability.
Our generation, transmission systems and natural gas pipelines are part of an interconnected system. Therefore, a disruption caused by the impact of a cyber security incident of the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources of our executive officers,third-party service providers’ operations, could also negatively impact our business.
Our supply chain for procurement of digital equipment may expose software or hardware to these risks and could result in a breach or significant costs of remediation. We are officersunable to quantify the potential impact of Xcel Energy Inc. Our Board makes determinations with respectcyber security threats or subsequent related actions. Cyber security incidents and regulatory action could result in a material decrease in revenues and may causesignificant additional costs (e.g., penalties, third-party claims, repairs, insurance or compliance) and potentially disrupt our supply and markets for natural gas, oil and other fuels.
We maintain security measures to a number of significant corporate events,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 paymentasset failure or unauthorized access to assets or information. A failure or breach of our dividends.technology systems or those of our third-party service providers could disrupt critical business functions and may negatively impact our business, our brand, and our reputation. The cyber security threat is dynamic and evolves continually, and our efforts to prioritize network protection may not be effective given the constant changes to threat vulnerability.
WeOur operating results may fluctuate on a seasonal and quarterly basis and can be adversely affected by milder weather.
Our electric and natural gas utility businesses are seasonal and weather patterns can have a material impact on our operating performance. Demand for electricity is often greater in the summer and winter months associated with cooling and heating. Because natural gas is heavily used for residential and commercial heating, the demand depends heavily upon weather patterns. A significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our operations have historically paid quarterly dividends to Xcel Energy Inc. In 2016, 2015generated less revenues and 2014 we paid $336.6 million, $330.8 millionincome when weather conditions are milder in the winter and $433.8 millioncooler in the summer. Unusually mild winters and summers could have an adverse effect on our financial condition, results of dividends to Xcel Energy Inc., respectively. If Xcel Energy Inc.’soperations or 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.flows.
Public Policy Risks
We may be subject to legislative and regulatory responses to climate change, and emissions, 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.
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 expendituressignificant and could affect results of operations, financial condition or cash flows and financial condition if such costs are not recovered through regulated rates.
The EPAAlthough the United States has proposed the CPP, which would regulate GHGs from power plants by mandating state plans to achieve state-specificnot adopted any international or federal GHG emission reduction goals. The legality of the CPP has been challenged in the courts,targets, many states and the Supreme Court stayed the rule while those challenges proceed. If the rule is ultimately implemented, uncertainties remain regarding implementation plans, including available opportunities to reduce costs, availability of emission trading, how states will allocate the reduction burden among utilities, what actions are creditable and the indirect impact of carbon regulation on natural gas and coal prices.
Some states have indicated a desire tolocalities may continue to pursue climate policies even in the absence of federal mandates. All of theThe steps that PSCo has taken to date to reduce GHG emissions, including energy efficiency measures, adding renewable generation or retiring or converting coal plants to natural gas, occurred under state-endorsed resource plans, renewable energy standards and other state policies. While those actions likely would have put PSCo in a good position to meet federal or international standards underbeing discussed, the CPP or the Paris Agreement, repeallack of these policies wouldfederal action does not adversely impact thosethese 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.
We are also subject to a significant number of proposed and potential rules that will impact our coal-fired and other generation facilities. These include rules associated with emissions of SO2 and NOx, mercury, regional haze, ozone and PM, water intakes, water discharges and ash management. The costs of investment to comply with these rules could be substantial and in some cases would lead to early retirement of coal units. We may not be able to timely recover all costs related to complying with regulatory requirements imposed on us.
operations, financial condition or cash flows.
Increased risks of regulatory penalties could negatively impact our business.
The Energy Act increased civil penalty authority for violation of FERC statutes, rules and orders. The FERC can now impose penalties of up to $1.2$1.3 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,penalties. Also, the NERC or the FERC for violations. Additionally, the PHMSA, the Occupational Safety and Health Administration and other federal agencies also have penalty authority.the authority to assess penalties. In the event of serious incidents, these agencies have become more active in pursuing penalties. Some states additionally have the authority to impose substantial penalties in the event of non-compliance.penalties. If a serious reliability, cyber or safety incident did occur, it could have a material effect on our results of operations, financial condition or financial results.cash flows.
Environmental Risks
We attemptare subject to mitigate the risk of regulatory penalties through formal training on such prohibited practicesenvironmental laws and aregulations, with which compliance function that reviews our interaction with the markets under FERCcould be difficult and CFTC jurisdictions. costly.
We are subject to environmental laws and regulations that affect many aspects of our operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances. Laws and regulations require us to obtain permits, licenses, and approvals and to comply with a variety of environmental requirements.
Environmental laws and regulations can also managing natural gas risk on our system by removing typesrequire us to restrict or limit the output of pipe (e.g. cast iron) with known problem tendenciesfacilities or the use of certain fuels, shift generation to lower-emitting facilities, install pollution control equipment, clean up spills and by testing transmission pipelinesother contamination and correct environmental hazards. Environmental regulations may also lead to shutdown of existing facilities. Failure to meet requirements of environmental mandates may result in high consequence areas. However, there is no guarantee our compliance programs willfines or penalties. We may be sufficientrequired to ensure against violations.
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 numberpay all or a portion 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 to remediate (i.e., clean-up) sites where our past activities, or the activities of capitalother parties, caused environmental contamination.
We are subject to mandates to provide customers with clean energy, renewable energy and our ability to raise capital, which is discussed in the capital market risk 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. Additionally, the cost of those commodities may be higher than expected.
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 systems may be targets of terrorist activities. Any such disruption could 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 andenergy conservation offerings. It could have a material effect on our business. We have alreadyresults of operations, financial condition or cash flows if our regulators do not allow us to recover the cost of capital investment or the O&M costs incurred 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 theyrequirements.
In addition, existing environmental laws or regulations may be revised, and new laws or regulations may be adopted. We may also incur additional unanticipated obligations or liabilities under existing environmental laws and regulations.
We are implementedsubject to physical and clarified.financial risks associated with climate change and other weather, natural disaster and resource depletion impacts.
Climate change can create physical and financial risk. Physical risks include changes in weather conditions and extreme weather events.
The insurance industry has also beenOur customers’ energy needs vary with weather. To the extent weather conditions are affected by these eventsclimate change, customers’ energy use could increase or decrease. Increased energy use due to weather changes may require us to invest in generating assets, transmission and infrastructure. Decreased energy use due to weather changes may result in decreased revenues.
Climate change may impact a region’s economy, which could impact our sales and revenues. The price of energy has an impact on the economic health of our communities. The cost of additional regulatory requirements, such as regulation of GHG,could impact the availability of insurancegoods and prices charged by our suppliers which would normally be borne by consumers through higher prices for energy and purchased goods. To the extent financial markets view climate change and emissions of GHGs as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less than ideal terms and conditions.
Severe weather impacts our service territories, primarily when thunderstorms, flooding, tornadoes, wildfires and snow or ice storms occur. Extreme weather conditions in general require system backup and can contribute to increased system stress, including service interruptions. Extreme weather conditions creating high energy demand may decrease. In addition,raise electricity prices, increasing the insurancecost of energy we are ableprovide to obtain may have higher deductibles, higher premiums and more restrictive policy terms.our customers.
A disruptionTo the extent the frequency of the regional electric transmission grid, interstate natural gas pipeline infrastructure or other fuel sources,extreme weather events increases, this could negativelyincrease our cost of providing service. Periods of extreme temperatures could impact our business. Becauseability to meet demand. Changes in precipitation resulting in droughts or water shortages could adversely affect our operations. Drought conditions also contribute to the increase in wildfire risk from our electric generation 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 (severe storm, severe temperature extremes, wildfires, solar storms, generator or transmission facility outage, breakdown or failure of equipment, pipeline rupture, railroad disruption, 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 systems and network infrastructure. In addition, we use our systems and infrastructure to create, collect, use, disclose, store, dispose of and otherwise process sensitive information, including company data, customer energy usage data, and personal information regarding customers, employees and their dependents, contractors and other individuals.
Our generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets, as well as the information processed in our systems (e.g., 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. 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 causesignificant 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 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.
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.facilities. While we have fuel clause recovery mechanisms, higher fuel costscarry liability insurance, given an extreme event, if PSCo was found to be liable for wildfire damages, amounts that potentially exceed our coverage could significantlynegatively 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 ourfinancial condition or cash flows. Drought or water depletion could adversely impact our ability to provide electricity to customers, cause early retirement of units and increase the price paid for energy. We 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 quartersnot recover all costs related to the heating season. Accordingly, our operations have historically generated less revenuesmitigating these physical 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. Poor vendor performance could impact on going operations, restoration operations, our reputation and could introduce financial risk or risks of fines for PSCo.
risks.
Item 1B — Unresolved Staff Comments |
|
| ITEM 1B — UNRESOLVED STAFF COMMENTS |
None.
Item 2 — Properties
Virtually all of the utility plant property of PSCo is subject to the lien of its first mortgage bond indenture.
|
| | | | | | | | |
| Electric Utility Generating Stations: | | | | | | | |
Station, Location and Unit | | Fuel | | Installed | | Summer 2016 Net Dependable Capability (MW) | |
| Steam: | | | | | | | |
| Cherokee-Denver, Colo., 1 Unit | | Coal | | 1968 | | 352 |
| (a) |
| Comanche-Pueblo, Colo. | | | | | | | |
| Unit 1 | | Coal | | 1973 | | 325 |
| |
| Unit 2 | | Coal | | 1975 | | 335 |
| |
| Unit 3 | | Coal | | 2010 | | 500 |
| (b) |
| Craig-Craig, Colo., 2 Units | | Coal | | 1979-1980 | | 83 |
| (c) |
| Hayden-Hayden, Colo., 2 Units | | Coal | | 1965-1976 | | 233 |
| (d) |
| Pawnee-Brush, Colo., 1 Unit | | Coal | | 1981 | | 505 |
| |
| Valmont-Boulder, Colo., 1 Unit | | Coal | | 1964 | | 184 |
| (e) |
| Combustion Turbine: | | | | | | | |
| Blue Spruce-Aurora, Colo., 2 Units | | Natural Gas | | 2003 | | 264 |
| |
| Cherokee-Denver, Colo., 3 Units | | Natural Gas | | 2015 | | 576 |
| |
| Fort St. Vrain-Platteville, Colo., 6 Units | | Natural Gas | | 1972-2009 | | 968 |
| |
| Rocky Mountain-Keenesburg, Colo., 3 Units | | Natural Gas | | 2004 | | 580 |
| |
| Various locations, 6 Units | | Natural Gas | | Various | | 171 |
| |
| Hydro: | | | | | | | |
| Cabin Creek-Georgetown, Colo. | | | | | | | |
| Pumped Storage, 2 Units | | Hydro | | 1967 | | 210 |
| |
| Various locations, 9 Units | | Hydro | | Various | | 26 |
| |
| | | | | Total | | 5,312 |
| |
|
| | | | | | | | |
| Station, Location and Unit | | Fuel | | Installed | | MW (a) | |
| Steam: | | | | | | | |
Comanche-Pueblo, CO (b) | | | | | | | |
| Unit 1 | | Coal | | 1973 | | 325 |
| |
| Unit 2 | | Coal | | 1975 | | 335 |
| |
| Unit 3 | | Coal | | 2010 | | 500 |
| (c) |
Craig-Craig, CO, 2 Units (d) | | Coal | | 1979 - 1980 | | 82 |
| (e) |
| Hayden-Hayden, CO, 2 Units | | Coal | | 1965 - 1976 | | 233 |
| (f) |
| Pawnee-Brush, CO, 1 Unit | | Coal | | 1981 | | 505 |
| |
| Cherokee-Denver, CO, 1 Unit | | Natural Gas | | 1968 | | 310 |
| |
| Combustion Turbine: | | | | | | | |
| Blue Spruce-Aurora, CO, 2 Units | | Natural Gas | | 2003 | | 264 |
| |
| Cherokee-Denver, CO, 3 Units | | Natural Gas | | 2015 | | 576 |
| |
| Fort St. Vrain-Platteville, CO, 6 Units | | Natural Gas | | 1972 - 2009 | | 968 |
| |
| Rocky Mountain-Keenesburg, CO, 3 Units | | Natural Gas | | 2004 | | 580 |
| |
| Various locations, 6 Units | | Natural Gas | | Various | | 171 |
| |
| Hydro: | | | | | | | |
| Cabin Creek-Georgetown, CO | | | | | | | |
| Pumped Storage, 2 Units | | Hydro | | 1967 | | 210 |
| |
| Various locations, 8 Units | | Hydro | | Various | | 25 |
| |
| Wind: | | | | | | | |
| Rush Creek, CO, 300 units | | Wind | | 2018 | | 582 |
| (g) |
| | | | | Total | | 5,666 |
| |
| |
(a) | Cherokee Unit 4 will be fuel switched from coal to natural gas by Dec. 31, 2017.Summer 2019 net dependable capacity. |
| |
(b) | In 2018, the CPUC approved early retirement of PSCo’s Comanche Units 1 and 2 in 2022 and 2025, respectively. |
| |
(c) | Based on PSCo’s ownership interest of 67 percent of Unit 3.67%. |
| |
(c)(d)
| Craig Unit 1 is expected to be retired early in 2025. |
| |
(e) | Based on PSCo’s ownership interest of 10 percent. Craig Unit 1 is expected to be early retired in approximately 2025.10%. |
| |
(d)(f)
| Based on PSCo’s ownership interest of 76 percent76% of Unit 1 and 37 percent37% of Unit 2. |
| |
(e)(g)
| Valmont Unit 5 will be retired by Dec. 31, 2017.Values disclosed are the maximum generation levels for these wind units. Capacity is attainable only when wind conditions are sufficiently available (on-demand net dependable capacity is zero). |
Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2016:2019:
|
| | |
| Conductor Miles | |
| 345 KV | 2,6305,036 |
|
| 230 KV | 12,89012,108 |
|
| 138 KV | 92 |
|
| 115 KV | 4,9295,055 |
|
| Less than 115 KV | 76,35579,740 |
|
PSCo had 230233 electric utility transmission and distribution substations at Dec. 31, 2016.
2019.
Natural gas utility mains at Dec. 31, 2016:2019:
|
| | |
| Miles | |
| Transmission | 2,2812,057 |
|
| Distribution | 22,26222,633 |
|
Item 3 — Legal Proceedings
|
|
| 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
For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, would have a material effect on PSCo’s financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred.
See Note 1210 to the consolidated financial statements, for further discussion of legal claims and environmental proceedings. See Item 1 and Note 11 to the consolidated financial statementsItem 7 for a discussion of proceedings involving utility rates and other regulatory matters.
further information.
Item 4 — Mine Safety Disclosures |
|
| 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 |
|
| 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 45 to the consolidated financial statements for further discussion of PSCo’s dividend policy.
information.
The dividends declared during 20162019 and 20152018 were as follows:
|
| | | | | | | | |
| (Millions of Dollars) | | 2019 | | 2018 |
| First quarter | | $ | 98.8 |
| | $ | 95.3 |
|
| Second quarter | | 104.9 |
| | 100.3 |
|
| Third quarter | | 97.3 |
| | 103.5 |
|
| Fourth quarter | | 176.6 |
| | 91.6 |
|
|
| | | | | | | | |
| (Thousands of Dollars) | | 2016 | | 2015 |
| First quarter | | $ | 83,914 |
| | $ | 80,650 |
|
| Second quarter | | 86,509 |
| | 82,872 |
|
| Third quarter | | 82,785 |
| | 83,672 |
|
| Fourth quarter | | 74,208 |
| | 83,373 |
|
|
|
| ITEM 6 — SELECTED FINANCIAL DATA |
Item 6 — Selected Financial Data
This is omitted per conditions set forth in general instructions I (1)(a) and (b) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).
Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations
|
|
| 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) I(1)(a) and (b) of Form 10-K for wholly owned subsidiaries. It is replaced with management’s narrative analysis ofand the results of operations for the current year as set forth in general instructions I (2) I(2)(a) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).
Non-GAAP Financial Review
Measures
The following discussion includes financial information prepared in accordance with GAAP, as well as certain non-GAAP financial measures such as electric margin, natural gas margin and ongoing earnings. Generally, a non-GAAP financial measure is a measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are adjusted from measures calculated and presented in accordance with GAAP. PSCo’s management uses non-GAAP measures for financial planning and analysis, by management focuses on those factors that had a material effect on PSCo’s financial condition,for reporting of results of operations and cash flows during the periods presented, or are expected to have a material impact in the future. It should be read in conjunction with the accompanying consolidated financial statements and related notes to the consolidatedBoard of Directors, in determining performance-based compensation and communicating its earnings outlook to analysts and investors. Non-GAAP financial statements.
Forward-Looking Statements
Except for the historical statements contained in this report, the matters discussed herein are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statementsmeasures are intended to supplement investors’ understanding of our performance and should not be identifiedconsidered alternatives for financial measures presented in this document byaccordance with GAAP. These measures are discussed in more detail below and may not be comparable to other companies’ similarly titled non-GAAP financial measures.
Electric and Natural Gas Margins
Electric margin is presented as electric revenues less electric fuel and purchased power expenses. Natural gas margin is presented as natural gas revenues less the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should”cost of natural gas sold and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made,transported. Expenses incurred for electric fuel 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, 2016 (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 expenditurespurchased power and the abilitycost of PSCo and its subsidiaries to obtain financing on favorable terms; business conditionsnatural gas are generally recovered through various regulatory recovery mechanisms. As a result, changes in the energy industry, including the risk of a slow downthese expenses are generally offset 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 theoperating revenues.
Management believes electric and natural gas markets; costs andmargins provide the most meaningful basis for evaluating our operations because they exclude the revenue impact of fluctuations in these expenses.
These margins can be reconciled to operating income, a GAAP measure, by including other effects of legal and administrative proceedings, settlements, investigations and claims; financial or regulatory accounting policies imposed by regulatory bodies; outcomes of regulatory proceedings; availability ofoperating revenues, cost of capital;sales-other, O&M expenses, conservation and employee work force factors.DSM expenses, depreciation and amortization and taxes (other than income taxes).
Earnings Adjusted for Certain Items (Ongoing Earnings)
Ongoing earnings reflect adjustments to GAAP earnings (net income) for certain items.
Management uses these non-GAAP financial measures to evaluate and provide details of PSCo’s core earnings and underlying performance. Management believes these measurements are useful to investors to evaluate the actual and projected financial performance and contribution of PSCo. For the years ended Dec. 31, 2019 and Dec. 31, 2018, there were no adjustments to GAAP earnings and therefore GAAP earnings equal ongoing earnings.
Management’s Discussion and Analysis of Financial Condition and Results of OperationsResults of Operations
2019 Comparison to 2018
PSCo’s net income was approximately $463.5$577.8 million for 2016,2019, compared with approximately $466.8$551.7 million for 2015.2018. The positive impact ofincrease was driven by higher electric and natural gas margins (primarily dueattributable to a rate increase), sales growthcapital riders and a lower estimated electric earnings test refund, were more thanincome taxes, partially offset by increasedlower AFUDC driven by the Rush Creek wind project that was placed in service in 2018 and higher depreciation, interest and interest charges.
O&M.
Electric Revenues and Margin
Electric revenues and fuel and purchased power expenses are largely impacted by the fluctuationfluctuations in the price of natural gas and coal used in the generation of electricity, but as a result of the design of fuel recovery mechanisms to recover current expenses,electricity. However, these price fluctuations have littleminimal impact on electric margin. The following table details themargin due to fuel recovery mechanisms that recover fuel expenses. In addition, electric revenuescustomers receive a credit for PTCs generated in a particular period.
Electric Revenues and margin:Margin:
| | | (Millions of Dollars) | | 2016 | | 2015 | | 2019 | | 2018 |
| Electric revenues | | $ | 3,049 |
| | $ | 3,115 |
| | $ | 3,033.0 |
| | $ | 3,031.2 |
|
| Electric fuel and purchased power | | (1,196 | ) | | (1,247 | ) | | (1,083.0 | ) | | (1,157.2 | ) |
| Electric margin | | $ | 1,853 |
| | $ | 1,868 |
| | $ | 1,950.0 |
| | $ | 1,874.0 |
|
The following tables summarize the components of the changesChanges in electric revenues and electric margin for the year ended Dec. 31:
Electric RevenuesMargin:
|
| | | | |
| (Millions of Dollars) | | 2016 vs. 2015 |
| Fuel and purchased power cost recovery | | $ | (40 | ) |
| DSM program revenues, offset by expenses | | (14 | ) |
| Firm wholesale | | (12 | ) |
| Trading, including REC sales | | (9 | ) |
| Non-fuel riders | | (5 | ) |
| Retail sales growth, excluding weather impact | | 15 |
|
| Earnings test refunds | | 6 |
|
| Other, net | | (7 | ) |
| Total decrease in electric revenues | | $ | (66 | ) |
Electric Margin
|
| | | | |
| (Millions of Dollars) | | 2016 vs. 2015 |
| DSM program revenues, offset by expenses | | $ | (14 | ) |
| Firm wholesale | | (12 | ) |
| Non-fuel riders | | (5 | ) |
| Retail sales growth, excluding weather impact | | 15 |
|
| Earnings test refunds | | 6 |
|
| Other, net | | (5 | ) |
| Total decrease in electric margin | | $ | (15 | ) |
|
| | | | |
| (Millions of Dollars) | | 2019 vs. 2018 |
| Non-fuel riders | | $ | 65.6 |
|
| Finance leases (offset in interest expense and amortization) | | 21.9 |
|
| Conservation incentive | | 6.1 |
|
| Firm wholesale (includes formula rate true-ups) | | 6.0 |
|
| Conservation and DSM riders (offset in expense) | | (5.2 | ) |
| Wholesale transmission revenue (net of expense) | | (4.8 | ) |
| Other (net) | | 11.9 |
|
| Total increase in electric margin before TCJA impact | | $ | 101.5 |
|
| TCJA impact (offset in income tax and amortization) | | (25.5 | ) |
| Total increase in electric margin | | $ | 76.0 |
|
Natural Gas Revenues and Margin
Total natural gas expense tends to varyvaries with changing sales requirements and the cost of natural gas purchases.gas. However, due to the design of purchased natural gas cost recovery mechanisms to recover current expenses for sales to retail customers, fluctuations in the cost of natural gas have little effectminimal impact on natural gas margin. The following table details natural gas revenues and margin:
|
| | | | | | | | |
| (Millions of Dollars) | | 2016 | | 2015 |
| Natural gas revenues | | $ | 958 |
| | $ | 1,007 |
|
| Cost of natural gas sold and transported | | (425 | ) | | (502 | ) |
| Natural gas margin | | $ | 533 |
| | $ | 505 |
|
The following tables summarize the components of the changes in natural gas revenues and natural gas margin for the year ended Dec. 31:
due to cost recovery mechanisms.
Natural Gas Revenues and Margin:
|
| | | | |
| (Millions of Dollars) | | 2016 vs. 2015 |
| Purchased natural gas adjustment clause recovery | | $ | (78 | ) |
| Infrastructure and integrity riders, partially offset in O&M expenses | | (9 | ) |
| Retail rate increase | | 32 |
|
| DSM program revenues, offset by expenses | | 2 |
|
| Other, net | | 4 |
|
| Total decrease in natural gas revenues | | $ | (49 | ) |
|
| | | | | | | | |
| (Millions of Dollars) | | 2019 | | 2018 |
| Natural gas revenues | | $ | 1,160.9 |
| | $ | 1,014.6 |
|
| Cost of natural gas sold and transported | | (526.0 | ) | | (428.4 | ) |
| Natural gas margin | | $ | 634.9 |
| | $ | 586.2 |
|
Changes in Natural Gas Margin:
|
| | | | |
| (Millions of Dollars) | | 2019 vs. 2018 |
| Infrastructure and integrity riders | | $ | 15.9 |
|
| Estimated impact of weather | | 10.9 |
|
| Transport sales | | 7.2 |
|
| Retail sales growth (excluding weather impact) | | 5.7 |
|
| Finance leases (offset in interest expense and amortization) | | 3.1 |
|
| Other (net) | | 5.9 |
|
| Total increase in natural gas margin | | $ | 48.7 |
|
Natural Gas Margin
|
| | | | |
| (Millions of Dollars) | | 2016 vs. 2015 |
| Retail rate increase | | $ | 32 |
|
| DSM program revenues, offset by expenses | | 2 |
|
| Infrastructure and integrity riders, partially offset in O&M expenses | | (9 | ) |
| Other, net | | 3 |
|
| Total increase in natural gas margin | | $ | 28 |
|
Non-Fuel Operating Expenses and Other Items
O&M Expenses— O&M expenses increased $22.4 million, or 2.8%, for 2019, primarily driven by distribution and gas operations. Distribution costs were higher due to storms and labor incurred primarily in the first six months of the year. Gas operation expenses increased due to increased damage prevention locates driven by construction demands and increased pipeline maintenance costs.
DSM Program Expenses— DSM program expenses decreased $10.5$6.2 million, or 8.2 percent,4.4%, for 2016 compared with 2015. The decrease was2019, primarily attributabledue to lower electric recovery rates. Lowerprior period over-recovery. DSM program expenses are generally offset by lower revenues.recovered concurrently through riders and base rates. Timing of recovery may vary from when costs are incurred.
Taxes (Other than Income Taxes)— Taxes (other than income taxes) increased $4.6 million, or 2.3%, for 2019, primarily due to higher property taxes.
Depreciation and Amortization— Depreciation and amortization expenseincreased $41.3 million, or 7.4%, for 2019, primarily driven by the Rush Creek wind farm going into service, natural gas and distribution/transmission replacements and software solutions. These increases were partially offset by higher levels of accelerated amortization of the prepaid pension asset in 2018 and new common and gas depreciation rates.
AFUDC, Equity and Debt— AFUDC decreased by $45.7 million for 2019, primarily due to the Rush Creek wind farm being placed in-service in 2018 and other capital investments.
Interest Charges —Interest charges increased by approximately $31.9$27.5 million, or 7.7 percent,13.2%, for 20162019, primarily due to higher debt levels to fund capital investments, changes in short-term interest rates and implementation of the lease accounting standard (offset in electric margin).
Income Taxes — Income taxes decreased $34.1 million for 2019, primarily driven by wind PTCs, partially offset by reduced AFUDC equity and reduced utility nonplant excess deferred tax amortization. Wind PTCs are credited to customers (recorded as a reduction to revenue) and do not have a material impact on net income. The ETR was 12.1% for 2019 compared with 2015.17.1% for 2018. The increase is primarily attributable to capital investments.
AFUDC— AFUDC increased by $5.6 million for 2016 compared with 2015. The increaselower ETR was primarily due to the expansionitems referenced above.
2018 Comparison with 2017
A discussion of transmission facilitieschanges in PSCo’s results of operations and otherliquidity and capital expenditures.
Interest Charges —Interest charges increasedresources from the year ended Dec. 31, 2017 to Dec. 31, 2018 can be found in Part II, “Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our Annual Report on Form 10-K for the fiscal year 2018, which was filed with the SEC on Feb. 22, 2019. However, such discussion is not incorporated by $4.2 million, or 2.4 percent, for 2016 compared with 2015. The increase is primarily due to higher long-term debt levels to fund capital investments.
Income Taxes — Income tax expense decreased $4.5 million for 2016 compared with 2015. The decrease in income tax expense was primarily due to lower pretax earnings in 2016reference into, and increased plant-related adjustments (e.g., AFUDC-equity) in 2016. The ETR was 37.1 percent for 2016 compared with 37.4 percent for 2015. The lower ETR in 2016 was primarily due to the adjustments referenced above.
does not constitute a part of, this Annual Report on Form 10-K.
|
|
| Public Utility Regulation |
The FERC has jurisdiction over rates for electric transmission service in interstate commerce and Qualitative Disclosures About Market Riskelectricity sold at wholesale, hydro facility licensing, natural gas transportation, asset transactions and mergers, accounting practices and certain other activities of PSCo, including enforcement of North American Electric Reliability Corporation mandatory electric reliability standards. State and local agencies have jurisdiction over many of PSCo’s activities, including regulation of retail rates and environmental matters.
Xcel Energy, which includes PSCo, attempts to mitigate the risk of regulatory penalties through formal training on prohibited practices and a compliance function that reviews interaction with the markets under FERC and Commodity Futures Trading Commission jurisdictions.
Public campaigns are conducted to raise awareness of public safety issues of interacting with our electric systems.
While programs to comply with regulatory requirements are in place, there is no guarantee compliance programs or other measures will be sufficient to ensure against violations. Decisions by these regulators can significantly impact PSCo’s results of operations.
See Rate Matters within Note 10 to the consolidated financial statements for further information.
Summary of Regulatory Agencies / RTO and Areas of Jurisdiction |
| | |
| Regulatory Body / RTO | | Additional Information on Regulatory Authority |
| CPUC | | Retail rates, accounts, services, issuance of securities and other aspects of electric and natural gas operations. Pipeline safety compliance. |
| FERC | | Wholesale electric operations, accounting practices, hydroelectric licensing, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with the NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce. Wholesale electric sales at cost-based prices to customers inside PSCo’s balancing authority area and at market-based prices to customers outside PSCo’s balancing authority area. PSCo holds a FERC certificate that allows it to transport natural gas in interstate commerce without PSCo becoming subject to full FERC jurisdiction. |
| RTO | | PSCo is not presently a member of an RTO and does not operate within an RTO energy market. However, PSCo does make certain sales to other RTO’s, including SPP and participates in a joint dispatch agreement with neighboring utilities. |
| DOT | | Pipeline safety compliance. |
Recovery Mechanisms |
| | |
| Mechanism | | Additional Information |
| ECA | | Recovers fuel and purchased energy costs. Short-term sales margins are shared with customers through the ECA. The ECA is revised quarterly. |
| PCCA | | Recovers purchased capacity payments. |
| SCA | | Recovers difference between actual fuel costs and costs recovered under steam service rates. The SCA rate is revised quarterly. |
| DSMCA | | Recovers DSM, interruptible service costs and performance initiatives for achieving energy savings goals. |
| RESA | | Recovers the incremental costs of compliance with the RES with a maximum of 2% of the customer’s bill. |
| WCA | | Recovers costs for customers who choose renewable resources. |
| TCA | | Recovers costs for transmission investment outside of rate cases. |
| CACJA | | Recovers costs associated with the CACJA. |
| FCA | | PSCo recovers fuel and purchased energy costs from wholesale electric customers through a fuel cost adjustment clause approved by the FERC. Wholesale customers pay production costs through a forecasted formula rate subject to true-up. |
| GCA | | Recovers costs of purchased natural gas and transportation and is revised quarterly to allow for changes in natural gas rates. |
| PSIA | | Recovers costs for transmission and distribution pipeline integrity management programs. |
Pending and Recently Concluded Regulatory Proceedings |
| | | | | | | | | | |
| Mechanism | | Utility Service | | Amount Requested (in millions) | | Filing Date | | Approval | | Additional Information |
| CPUC |
| Rate Case | | Steam | | $7 | | January 2019 | | Received | | In September 2019, the CPUC approved PSCo’s Settlement Agreement with CPUC Staff and the City of Denver. The settlement reflects an ROE of 9.67% for AFUDC purposes, an equity ratio of 56.04% and utilization of tax reform benefits. The first stepped increase went into effect Oct. 1, 2019, with full rates effective Oct. 1, 2020. |
| Rate Case Appeal | | Natural Gas | | N/A | | April 2019 | | Pending | | In April 2019, PSCo filed an appeal seeking judicial review of the CPUC’s prior ruling regarding PSCo’s last natural gas rate case (approved in December 2018). Appeal requests review of the following: denial of a return on the prepaid pension and retiree medical assets; the use of a capital structure that is not based on the actual historical test year level; and the use of an average rate base methodology rather than a year-end rate base methodology. Timeline on a final ruling is unknown. |
| DSM Incentive | | Electric & Natural Gas | | $12 | | April 2019 | | Received | | PSCo earned an electric and natural gas DSM incentive of $9 million and $3 million, respectively, for achieving its 2018 savings goals. |
Electric Rate Case — In October 2019, PSCo filed rebuttal testimony with the CPUC requesting a net rate increase of $108.4 million. This is based on a $353.3 million increase offset by $244.9 million of previously authorized costs currently recovered through various rider mechanisms. The request was based on a ROE of 10.20%, an equity ratio of 55.61% and a current test year, which includes certain forecasted plant additions through December 2019.
In December 2019, the CPUC held deliberations and on Feb. 11, 2020 issued a written decision approving a current test year ended Aug. 31, 2019, a 9.3% ROE, an equity ratio of 55.61%, implementation of decoupling in 2020 and other items. This resulted in an estimated $34.6 million net base rate revenue increase.
|
| | | | |
| Revenue Request (Millions of Dollars) | | 2020 |
| Company filed rebuttal | | $ | 353.3 |
|
| ROE | | (55.3 | ) |
| Impact of change in test year | | (17.1 | ) |
| Property tax expense | | 14.7 |
|
| Rate base adjustments | | (11.4 | ) |
| Capital structure | | (4.7 | ) |
| Total proposed revenue change | | 279.5 |
|
| Estimated impact of previously authorized costs (existing riders) | | 244.9 |
|
| Net revenue change | | $ | 34.6 |
|
Final rates are expected to be implemented in February 2020. PSCo currently intends to file an application for rehearing/reconsideration in the first quarter of 2020.
Gas Rate Case — On Feb. 5, 2020, PSCo filed a request with the CPUC seeking a net increase to retail gas rates of $126.8 million, reflecting a $144.5 million increase in base rate revenue, which is partially offset by $17.7 million previously authorized through the PSIA rider mechanism. The request is based on a test year that incorporates actual capital and expenses as of Sept. 30, 2019, adjusted for known and measurable differences for the 12-month period ended Sept. 30, 2020, a 9.95% ROE and an equity ratio of 55.81%. Proposed effective date is Nov. 1, 2020.
|
| | | | |
| Revenue Request (Millions of Dollars) | | 2020 |
| Capital additions (through Sept. 30, 2019) | | $ | 62.1 |
|
| Forecasted capital additions (through Sept. 30, 2020) | | 33.0 |
|
| Sales growth (includes amounts forecasted through Sept. 30, 2020) | | (29.1 | ) |
| Operations and maintenance, amortization and other expenses | | 28.8 |
|
| Property tax expense | | 18.9 |
|
| Cost of capital | | 7.9 |
|
| Updated depreciation rates | | 5.2 |
|
| Net increase to revenue | | 126.8 |
|
| Previously authorized costs: | | |
| Transfer PSIA rider costs to base rates | | 17.7 |
|
| Total base request | | $ | 144.5 |
|
| | | |
| Expected year-end rate base | | $ | 2,236.4 |
|
The request reflects $1.3 billion of capital additions since the 2016 test year used to set current rates. Capital investments are made to maintain the safety and reliability of the natural gas system, along with investments to connect new customers and perform mandated infrastructure relocation work.
Timing of a CPUC ruling is expected in the second half of 2020.
Resource Plan
CEP — In September 2018, the CPUC approved PSCo’s CEP portfolio, which included the retirement of two coal-fired generation units, Comanche Unit 1 (in 2022) and Comanche Unit 2 (in 2025), and the following additions:
|
| | | | |
| Total Capacity | | PSCo's Ownership |
| Wind generation | 1,100 MW | | 500 MW |
|
| Solar generation | 700 MW | | — |
|
| Battery storage | 275 MW | | — |
|
| Natural gas generation | 380 MW | | 380 MW |
|
PSCo’s investment is expected to be approximately $1 billion, including transmission to support the increase in renewable generation.
CPCNs were granted by the CPUC for the Shortgrass Substation in February 2019, and for the 500 MW Cheyenne Ridge wind farm and 345 KV generation tie line in April 2019.
A CPCN for the acquisitions of the Valmont and Manchief natural gas generation facilities was filed in July 2019, and a settlement on those acquisitions was reached with CPUC Staff and the Colorado Office of Consumer Counsel in January 2020, pending a CPUC decision expected in approximately the second quarter of 2020.
A CPCN for voltage control facilities was also filed with the CPUC in December 2019, with another expected to follow in approximately the first quarter of 2020 for network transmission upgrades required for the CEP portfolio.
Purchased Power and Transmission Service Providers
PSCo expects to meet its system capacity requirements through electric generating stations, power purchases, new generation facilities, DSM options and expansion of generation plants.
Purchased Power — PSCo purchases power from other utilities and IPPs. Long-term purchased power contracts for dispatchable resources typically require capacity and energy charges. It also contracts to purchase power for both wind and solar resources. PSCo makes short-term purchases to meet system load and energy requirements, replace owned generation, meet operating reserve obligations, or obtain energy at a lower cost.
Purchased Transmission Services — In addition to using its own transmission system, PSCo has contracts with regional transmission service providers to deliver energy to its customers.
Boulder Municipalization
In 2011, Boulder passed a ballot measure authorizing the formation of an electric municipal utility, subject to certain conditions. Subsequently, there have been various legal proceedings in multiple venues with jurisdiction over Boulder’s plan. In 2014, the Boulder City Council passed an ordinance to establish an electric utility. PSCo challenged the formation of this utility and the Colorado Court of Appeals ruled in PSCo’s favor, vacating a lower court decision. In June 2018, the Colorado Supreme Court rejected Boulder’s request to dismiss the case and remanded it to the Boulder District Court. The case was then settled in June 2019 after Boulder agreed to repeal the ordinance establishing the utility.
Boulder has filed multiple separation applications with the CPUC, which have been challenged by PSCo and other intervenors. In September 2017, the CPUC issued a written decision, agreeing with several key aspects of PSCo’s position. The CPUC has approved the designation of some electrical distribution assets for transfer, subject to Boulder completing certain filings. In the fourth quarter of 2018, the Boulder City Council also adopted an Ordinance authorizing Boulder to begin negotiations for the acquisition of certain property or to otherwise condemn that property after Feb. 1, 2019. In the first quarter of 2019, Boulder sent PSCo a notice of intent to acquire certain electric distribution assets. In the third quarter of 2019, Boulder filed its condemnation litigation, which was later dismissed by the Boulder District Court in September 2019 on the grounds that Boulder had not completed the pre-requisite CPUC process and filings. Boulder is currently appealing this order. In October 2019, the CPUC approved the subsequent filings regarding asset transfers outside of substations, reaffirmed its 2017 decision on assets outside of substations and closed the CPUC proceeding. In December 2019, Boulder filed a new condemnation action despite its ongoing appeal of the last condemnation case. PSCo subsequently filed a motion to dismiss or stay the new condemnation action. In February 2020, Boulder filed an application under section 210 of the Federal Power Act asking FERC to order PSCo to interconnect its facilities with a future Boulder municipal utility under Boulder’s preferred terms and conditions.
Wholesale and Commodity Marketing Operations
PSCo conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy related products. PSCo uses physical and financial instruments to minimize commodity price and credit risk and hedge sales and purchases. PSCo also engages in trading activity unrelated to hedging. Sharing of any margin is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement.
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|
| 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 108 to the consolidated financial statements for further discussion of market risks associated with derivatives.information.
PSCo is exposed to the impact of adverse changes in price for energy and energy-related products, which is partially mitigated by the use of commodity derivatives. In addition to ongoing monitoring and maintaining credit policies intended to minimize overall credit risk, 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 nonperformancenon-performance 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 counterparty risk, the fair value of the securities in the master pension trust, as well asfund and PSCo’s ability to earn a return on short-term investments of excess cash.investments.
Commodity Price Risk — PSCo is exposed to commodity price risk in its electric and natural gas operations. Commodity price risk is managed by entering into long-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 to the extent such exposure exists.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 upcommittee.
Fair value of management personnel not directly involved in the activities governed by the policy.
At Dec. 31, 2016, the fair values by source for net commodity trading contract assets werecontracts as follows:of Dec. 31, 2019:
| | | | | Futures / Forwards | Futures / Forwards Maturity |
| (Thousands of Dollars) | | Source of Fair Value | | Maturity Less Than 1 Year | | Maturity 1 to 3 Years | | Maturity 4 to 5 Years | | Maturity Greater Than 5 Years | | Total Futures/ Forwards Fair Value | |
| (Millions of Dollars) | | | Maturity Less Than 1 Year | | Maturity 1 to 3 Years | | Maturity 4 to 5 Years | | Maturity Greater Than 5 Years | | Total Futures/ Forwards Fair Value |
PSCo | | 1 |
| | $ | (188 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | (188 | ) | | $ | (4.5 | ) | | $ | (21.8 | ) | | $ | (30.7 | ) | | $ | — |
| | $ | (57.0 | ) |
1 — Prices actively quoted or based on actively quoted prices. | |
(a) | Prices based on models and other valuation methods. |
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:31:
| | | (Thousands of Dollars) | | 2016 | | 2015 | |
| (Millions of Dollars) | | | 2019 | | 2018 |
| Fair value of commodity trading net contract assets outstanding at Jan. 1 | | $ | 112 |
| | $ | — |
| | $ | 1.3 |
| | $ | 0.5 |
|
| Contracts realized or settled during the period | | (654 | ) | | 14 |
| | (10.9 | ) | | (7.8 | ) |
| Commodity trading contract additions and changes during the period | | 354 |
| | 98 |
| | (47.4 | ) | | 8.6 |
|
| Fair value of commodity trading net contract assets outstanding at Dec. 31 | | $ | (188 | ) | | $ | 112 |
| | $ | (57.0 | ) | | $ | 1.3 |
|
At Dec. 31, 2016,2019, a 10 percent10% increase in market prices for commodity trading contracts would increase pretax income by approximately $3.3 million, whereas a 10% decrease would decrease pretax income by approximately $3.3 million. At Dec. 31, 2018, a 10% increase in market prices for commodity trading contracts would decrease pretax income by approximately $0.9$0.2 million, whereas a 10 percent10% decrease would increase pretax income by approximately $0.9$0.2 million. At Dec. 31, 2015, a 10 percent increase in market prices for commodity trading contracts would decrease pretax income by approximately $0.1 million, whereas a 10 percent decrease would increase pretax income by approximately $0.1 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. 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 NSP-Minnesota and PSCo commodity trading operations, calculated on a consolidated basis using a Monte Carlo simulation with a 95 percent95% confidence level and a one-day holding period, were as follows:
|
| | | | | | | | | | | | | | | | | | | | |
| (Millions of Dollars) | | Year Ended Dec. 31 | | VaR Limit | | Average | | High | | Low |
| 2016 | | $ | 0.09 |
| | $ | 3.00 |
| | $ | 0.16 |
| | $ | 0.38 |
| | $ | 0.05 |
|
| 2015 | | 0.10 |
| | 3.00 |
| | 0.28 |
| | 1.34 |
| | | 0.06 |
|
|
| | | | | | | | | | | | | | | | | | | | |
| (Millions of Dollars) | | Year Ended Dec. 31 | | VaR Limit | | Average | | High | | Low |
| 2019 | | $ | 0.4 |
| | $ | 3.0 |
| | $ | 0.6 |
| | $ | 0.8 |
| | $ | 0.3 |
|
| 2018 | | 4.8 |
| | 6.0 |
| | 0.6 |
| | 5.6 |
| | 0.1 |
|
Interest Rate Risk — PSCo is subject to the risk of fluctuating interest rates in the normal course of business.rate risk. PSCo’s risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives such as swaps, caps, collars and put or call options.
At Dec. 31, 2016, a 100-basis-pointA 100 basis point change in the benchmark rate on PSCo’s variable rate debt would impact annual pretax interest expense by approximately $1.3$0.4 million in 2019 and at Dec. 31, 2015 a 100-basis-point change$3.1 million in the benchmark rate on PSCo’s variable rate debt would impact annual pretax interest expense by approximately $0.1 million. 2018.
See Note 108 to the consolidated financial statements for a discussion of PSCo’s interest rate derivatives.further information.
Credit Risk — PSCo is also exposed to credit risk. Credit risk relates to the risk of loss resulting from counterparties’ nonperformance on their contractual obligations. PSCo maintains credit policies intended to minimize overall credit risk and actively monitors these policies to reflect changes and scope of operations.
At Dec. 31, 2016,2019, a 10 percent10% increase in commodity prices would have resulted in a decrease in credit exposure of $3.1 million, while a decrease in prices of 10% would have resulted in an increase in credit exposure of $7.2 million. At Dec. 31, 2018, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $14.3$11.5 million, while a decrease in prices of 10 percent10% would have resulted in a decrease in credit exposure of $2.2$7.6 million. At Dec. 31, 2015, a 10 percent increase in commodity prices would have resulted in an increase in credit exposure of $3.2 million, while a decrease in prices of 10 percent would have resulted in an increase in credit exposure of $0.2 million.
PSCo conducts standard credit reviews for all counterparties. PSCocounterparties and employs additional credit risk control mechanisms when appropriate,controls, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures.provisions. Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. Distress in the financial markets could increase PSCo’s credit risk.
Fair Value Measurements
PSCo follows accountinguses derivative contracts such as futures, forwards, interest rate swaps and disclosure guidance onoptions to manage commodity price and interest rate risk. Derivative contracts, with the exception of those designated as normal purchase-normal sale contracts, are reported at fair value. PSCo’s investments held in rabbi trusts, pension and other postretirement funds are also subject to fair value measurements that contains a hierarchy for inputs used in measuring fair valueaccounting.
See Notes 8 and requires disclosure of the observability of the inputs used in these measurements. See Note 109 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.information.
Commodity Derivatives — PSCo continuously monitors the creditworthiness of the counterparties to its commodity derivative contracts and assesses each counterparty’s ability to perform on the transactions set forth in the contracts.transactions. 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, 2016. PSCo also assesses the impact of its own2019.
Adjustments to fair value for credit risk when determining the fair value of commodity trading instruments are recorded in electric revenues. Credit risk adjustments for other commodity derivative instruments are recorded as other comprehensive income or deferred as regulatory assets and liabilities. Classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. The impact of discounting commodity derivative liabilities for credit risk was immaterial to the fair value of commodity derivative liabilities at Dec. 31, 2016.
Commodity derivative assets and liabilities assigned to Level 3 typically consist of forwards and options that are long-term in nature. Determining the fair value of certain commodity forwards and options can require management to make use of subjective price and volatility forecasts which 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, 2016.
2019.
Item 8 — Financial Statements and Supplementary Data |
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| ITEM 8 — FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
See Item 15-1 in Part IV for an index of financial statements included herein.
See Note 1714 to the consolidated financial statements for summarized quarterly financial data.further information.
Management Report on Internal ControlsControl 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 will initiate deployment of work management systems modules, including the conversion of existing work management systems, during 2017. PSCo does not believe this implementation has or will have 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, 2016.2019. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework (2013). Based on our assessment, we believe that, as of Dec. 31, 2016,2019, PSCo’s internal control over financial reporting is effective at the reasonable assurance level based on those criteria.
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| | |
| /s/ BEN FOWKE | | /s/ ROBERT C. FRENZEL |
| Ben Fowke | | Robert C. Frenzel |
Chairman, and Chief Executive Officer and Director | | Executive Vice President, Chief Financial Officer and Director |
Feb. 24, 201721, 2020 | | Feb. 24, 201721, 2020 |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholder and Board of Directors and Stockholder of
Public Service Company of Colorado
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets and statements of capitalization of Public Service Company of Colorado and subsidiaries (the “Company”"Company") as of December 31, 20162019 and 2015, and2018, the related consolidated statements of income, comprehensive income, cash flows and common stockholder’sstockholder's equity, for each of the three years in the period ended December 31, 2016. Our audits also included2019, and the financial statementrelated notes and the schedule listed in the Index at Item 15. 15 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements and financial statement schedule 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 Public Company Accounting Oversight Board (United States).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.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. OurAs part of our audits, included considerationwe are required to obtain an understanding of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, 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. An audit also includes
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 supportingregarding the amounts and disclosures in the financial statements, assessingstatements. 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 statement presentation.statements. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Public Service Company of Colorado and subsidiaries as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
|
| |
/s/ DELOITTE & TOUCHE LLP | |
| Minneapolis, Minnesota |
| February 21, 2020 |
| |
February 24, 2017 | We have served as the Company’s auditor since 2002. |
PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(amounts in thousands)millions)
| | | | Year Ended Dec. 31 | | Year Ended Dec. 31 |
| | 2016 | | 2015 | | 2014 | | 2019 | | 2018 | | 2017 |
| Operating revenues | | | | | | | | | | | |
| Electric | $ | 3,049,352 |
| | $ | 3,115,257 |
| | $ | 3,125,937 |
| | $ | 3,033.0 |
| | $ | 3,031.2 |
| | $ | 3,003.8 |
|
| Natural gas | 957,721 |
| | 1,006,666 |
| | 1,215,324 |
| | 1,160.9 |
| | 1,014.6 |
| | 995.2 |
|
| Steam and other | 40,723 |
| | 41,590 |
| | 41,888 |
| | 43.3 |
| | 40.4 |
| | 43.5 |
|
| Total operating revenues | 4,047,796 |
| | 4,163,513 |
| | 4,383,149 |
| | 4,237.2 |
| | 4,086.2 |
| | 4,042.5 |
|
| | | | | | | | | | | | |
| Operating expenses | | | | | | | | | | | |
| Electric fuel and purchased power | 1,196,417 |
| | 1,246,666 |
| | 1,405,498 |
| | 1,083.0 |
| | 1,157.2 |
| | 1,126.7 |
|
| Cost of natural gas sold and transported | 425,410 |
| | 501,824 |
| | 725,754 |
| | 526.0 |
| | 428.4 |
| | 458.7 |
|
| Cost of sales — steam and other | 15,872 |
| | 17,788 |
| | 16,831 |
| | 16.6 |
| | 15.3 |
| | 16.1 |
|
| Operating and maintenance expenses | 762,416 |
| | 761,901 |
| | 751,786 |
| | 809.9 |
| | 787.5 |
| | 760.8 |
|
| Demand side management program expenses | 118,175 |
| | 128,681 |
| | 139,780 |
| |
| Demand side management expenses | | | 136.0 |
| | 142.2 |
| | 125.0 |
|
| Depreciation and amortization | 443,555 |
| | 411,667 |
| | 379,202 |
| | 602.4 |
| | 561.1 |
| | 471.5 |
|
| Taxes (other than income taxes) | 196,330 |
| | 195,285 |
| | 161,928 |
| | 206.5 |
| | 201.9 |
| | 195.7 |
|
| Total operating expenses | 3,158,175 |
| | 3,263,812 |
| | 3,580,779 |
| | 3,380.4 |
| | 3,293.6 |
| | 3,154.5 |
|
| | | | | | | | | | | | |
| Operating income | 889,621 |
| | 899,701 |
| | 802,370 |
| | 856.8 |
| | 792.6 |
| | 888.0 |
|
| | | | | | | | | | | | |
| Other income, net | 3,817 |
| | 2,964 |
| | 4,265 |
| | 3.1 |
| | 2.1 |
| | 7.8 |
|
| Allowance for funds used during construction — equity | 18,557 |
| | 14,485 |
| | 46,784 |
| | 21.7 |
| | 56.4 |
| | 29.8 |
|
| | | | | | | | | | | | |
| Interest charges and financing costs | | | | | | | | | | | |
Interest charges — includes other financing costs of $6,289, $6,285 and $6,340, respectively | 181,631 |
| | 177,430 |
| | 171,881 |
| |
| Interest charges — includes other financing costs of $6.6, $6.5 and $6.3, respectively | | | 235.4 |
| | 207.9 |
| | 190.7 |
|
| Allowance for funds used during construction — debt | (7,045 | ) | | (5,522 | ) | | (17,241 | ) | | (11.2 | ) | | (22.2 | ) | | (11.4 | ) |
| Total interest charges and financing costs | 174,586 |
| | 171,908 |
| | 154,640 |
| | 224.2 |
| | 185.7 |
| | 179.3 |
|
| | | | | | | | | | | | |
| Income before income taxes | 737,409 |
| | 745,242 |
| | 698,779 |
| | 657.4 |
| | 665.4 |
| | 746.3 |
|
| Income taxes | 273,918 |
| | 278,440 |
| | 243,591 |
| | 79.6 |
| | 113.7 |
| | 252.2 |
|
| Net income | $ | 463,491 |
| | $ | 466,802 |
| | $ | 455,188 |
| | $ | 577.8 |
| | $ | 551.7 |
| | $ | 494.1 |
|
See Notes to Consolidated Financial Statements
PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(amounts in thousands)millions)
|
| | | | | | | | | | | | |
| | | Year Ended Dec. 31 |
| | | 2016 | | 2015 | | 2014 |
| Net income | | $ | 463,491 |
| | $ | 466,802 |
| | $ | 455,188 |
|
| | | | | | | |
| Other comprehensive income (loss) | | | | | | |
| | | | | | | |
| Pension and retiree medical benefits: | | | | | | |
| Net pension and retiree medical losses arising during the period, net of tax of $(138), $0, and $0 | | (223 | ) | | — |
| | — |
|
| Amortization of losses included in net periodic benefit cost, net of tax of $2, $0, and $0, respectively | | 3 |
| | — |
| | — |
|
| | | (220 | ) | | — |
| | — |
|
| | | | | | | |
| Derivative instruments: | | | | | | |
| Net fair value decrease, net of tax of $0, $(20), and $(43), respectively | | — |
| | (30 | ) | | (72 | ) |
| Reclassification of losses (gains) to net income, net of tax of $648, $39, and $(287), respectively | | 1,056 |
| | 72 |
| | (468 | ) |
| | | 1,056 |
| | 42 |
| | (540 | ) |
| | | | | | | |
| Other comprehensive income (loss) | | 836 |
| | 42 |
| | (540 | ) |
| Comprehensive income | | $ | 464,327 |
| | $ | 466,844 |
| | $ | 454,648 |
|
|
| | | | | | | | | | | | |
| | | Year Ended Dec. 31 |
| | | 2019 | | 2018 | | 2017 |
| Net income | | $ | 577.8 |
| | $ | 551.7 |
| | $ | 494.1 |
|
| | | | | | | |
| Other comprehensive (loss) income | | | | | | |
| | | | | | | |
| Defined pension and other postretirement benefits: | | | | | | |
| Net pension and retiree medical gain arising during the period, net of tax of $0.1, $0 and $0, respectively | | 0.4 |
| | — |
| | — |
|
| Reclassification of gain to net income, net of tax of $(0.9), $0 and $0, respectively | | (2.7 | ) | | — |
| | — |
|
| Derivative instruments: | | | | | | |
| Reclassification of loss to net income, net of tax of $0.4, $0.4 and $0.6, respectively | | 1.2 |
| | 1.2 |
| | 1.0 |
|
| | | | | | | |
| Other comprehensive (loss) income | | (1.1 | ) | | 1.2 |
| | 1.0 |
|
| Comprehensive income | | $ | 576.7 |
| | $ | 552.9 |
| | $ | 495.1 |
|
See Notes to Consolidated Financial Statements
PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(amounts in thousands)millions)
| | | | Year Ended Dec. 31 | Year Ended Dec. 31 |
| | 2016 | | 2015 | | 2014 | 2019 | | 2018 | | 2017 |
| Operating activities | | | | | | | | | | |
| Net income | $ | 463,491 |
| | $ | 466,802 |
| | $ | 455,188 |
| $ | 577.8 |
| | $ | 551.7 |
| | $ | 494.1 |
|
| Adjustments to reconcile net income to cash provided by operating activities: | | | | | | | | | | |
| Depreciation and amortization | 446,179 |
| | 416,427 |
| | 383,992 |
| 607.0 |
| | 566.1 |
| | 475.6 |
|
| Demand side management program amortization | 2,138 |
| | 3,509 |
| | 4,331 |
| |
| Deferred income taxes | 222,002 |
| | 277,896 |
| | 227,823 |
| 97.0 |
| | 23.8 |
| | 207.8 |
|
| Amortization of investment tax credits | (2,805 | ) | | (2,807 | ) | | (2,941 | ) | |
| Allowance for equity funds used during construction | (18,557 | ) | | (14,485 | ) | | (46,784 | ) | (21.7 | ) | | (56.4 | ) | | (29.8 | ) |
| Provision for bad debts | 14,121 |
| | 13,052 |
| | 17,005 |
| 16.5 |
| | 16.4 |
| | 14.3 |
|
| Net realized and unrealized hedging and derivative transactions | 1,325 |
| | 2,414 |
| | (2,578 | ) | 62.1 |
| | (6.2 | ) | | 2.4 |
|
| Other | (388 | ) | | 2,500 |
| | — |
| |
| Changes in operating assets and liabilities: | | | | | | | | | | |
| Accounts receivable | (14,227 | ) | | 8,872 |
| | (42,921 | ) | (21.5 | ) | | (42.8 | ) | | (2.2 | ) |
| Accrued unbilled revenues | (20,866 | ) | | 17,837 |
| | (23,132 | ) | 19.6 |
| | (17.7 | ) | | 1.3 |
|
| Inventories | 172 |
| | 33,417 |
| | (972 | ) | (27.0 | ) | | (20.1 | ) | | (9.1 | ) |
| Prepayments and other | 68,693 |
| | 10,483 |
| | (81,715 | ) | (29.0 | ) | | 12.8 |
| | 0.2 |
|
| Accounts payable | 38,439 |
| | (40,982 | ) | | (22,789 | ) | (44.0 | ) | | 68.7 |
| | 20.4 |
|
| Net regulatory assets and liabilities | 4,143 |
| | 78,055 |
| | 130,499 |
| 34.9 |
| | (14.6 | ) | | (22.6 | ) |
| Other current liabilities | 1,892 |
| | 19,654 |
| | 5,284 |
| (0.1 | ) | | (12.9 | ) | | 71.8 |
|
| Pension and other employee benefit obligations | (10,627 | ) | | (23,449 | ) | | (38,905 | ) | (47.0 | ) | | (44.2 | ) | | (16.5 | ) |
| Change in other noncurrent assets | (6,750 | ) | | 4,086 |
| | 5,537 |
| |
| Change in other noncurrent liabilities | (22,120 | ) | | (35,334 | ) | | (19,130 | ) | |
| Other, net | | 3.3 |
| | (16.3 | ) | | (5.9 | ) |
| Net cash provided by operating activities | 1,166,255 |
| | 1,237,947 |
| | 947,792 |
| 1,227.9 |
| | 1,008.3 |
| | 1,201.8 |
|
| | | | | | | | | | | |
| Investing activities | | | | | | | | | | |
| Utility capital/construction expenditures | (1,113,800 | ) | | (995,597 | ) | | (1,114,338 | ) | (1,690.7 | ) | | (1,577.2 | ) | | (1,445.9 | ) |
| Proceeds from insurance recoveries | 608 |
| | — |
| | — |
| |
| Allowance for equity funds used during construction | 18,557 |
| | 14,485 |
| | 46,784 |
| |
| Investments in utility money pool arrangement | (444,000 | ) | | (196,300 | ) | | (603,000 | ) | (641.0 | ) | | (634.0 | ) | | (954.0 | ) |
| Repayments from utility money pool arrangement | 444,000 |
| | 212,300 |
| | 659,000 |
| 641.0 |
| | 654.0 |
| | 934.0 |
|
| Other | (1,460 | ) | | — |
| | — |
| |
| Other, net | | — |
| | — |
| | (0.7 | ) |
| Net cash used in investing activities | (1,096,095 | ) | | (965,112 | ) | | (1,011,554 | ) | (1,690.7 | ) | | (1,557.2 | ) | | (1,466.6 | ) |
| | | | | | | | | | | |
| Financing activities | | | | | | | | | | |
| Proceeds from (repayments of) short-term borrowings, net | 115,000 |
| | (368,000 | ) | | 382,000 |
| |
| (Repayments of) proceeds from short-term borrowings, net | | (307.0 | ) | | 307.0 |
| | (129.0 | ) |
| Borrowings under utility money pool arrangement | 524,500 |
| | 165,000 |
| | 333,000 |
| 100.0 |
| | 780.0 |
| | 40.0 |
|
| Repayments under utility money pool arrangement | (524,500 | ) | | (165,000 | ) | | (333,000 | ) | (61.0 | ) | | (780.0 | ) | | (40.0 | ) |
| Proceeds from issuance of long-term debt | 244,507 |
| | 246,751 |
| | 295,598 |
| 928.2 |
| | 691.1 |
| | 393.8 |
|
| Repayments of long-term debt | (129,500 | ) | | — |
| | (275,000 | ) | (400.0 | ) | | (300.0 | ) | | — |
|
| Capital contributions from parent | 38,755 |
| | 175,210 |
| | 81,498 |
| 638.2 |
| | 252.1 |
| | 335.6 |
|
| Dividends paid to parent | (336,581 | ) | | (330,846 | ) | | (433,788 | ) | (457.6 | ) | | (375.3 | ) | | (333.9 | ) |
| Net cash (used in) provided by financing activities | (67,819 | ) | | (276,885 | ) | | 50,308 |
| |
| Other, net | | — |
| | (0.1 | ) | | (0.1 | ) |
| Net cash provided by financing activities | | 440.8 |
| | 574.8 |
| | 266.4 |
|
| | | | | | | | | | | |
| Net change in cash and cash equivalents | 2,341 |
| | (4,050 | ) | | (13,454 | ) | |
| Cash and cash equivalents at beginning of period | 3,585 |
| | 7,635 |
| | 21,089 |
| |
| Cash and cash equivalents at end of period | $ | 5,926 |
| | $ | 3,585 |
| | $ | 7,635 |
| |
| Net change in cash, cash equivalents and restricted cash | | (22.0 | ) | | 25.9 |
| | 1.6 |
|
| Cash, cash equivalents and restricted cash at beginning of period | | 33.4 |
| | 7.5 |
| | 5.9 |
|
| Cash, cash equivalents and restricted cash at end of period | | $ | 11.4 |
| | $ | 33.4 |
| | $ | 7.5 |
|
| | | | | | | | | | | |
| Supplemental disclosure of cash flow information: | | | | | | | | | | |
| Cash paid for interest (net of amounts capitalized) | $ | (171,714 | ) | | $ | (165,546 | ) | | $ | (150,011 | ) | $ | (209.3 | ) | | $ | (187.2 | ) | | $ | (175.0 | ) |
| Cash received (paid) for income taxes, net | 22,827 |
| | 13,822 |
| | (91,810 | ) | |
| Cash paid for income taxes, net | | (4.7 | ) | | (115.8 | ) | | (7.7 | ) |
| Supplemental disclosure of non-cash investing transactions: | | | | | | | | | | |
| Property, plant and equipment additions in accounts payable | $ | 68,870 |
| | $ | 106,912 |
| | $ | 139,616 |
| |
| Accrued property, plant and equipment additions | | $ | 233.8 |
| | $ | 142.1 |
| | $ | 199.1 |
|
| Inventory transfers to property, plant and equipment | | 32.4 |
| | 37.2 |
| | 26.6 |
|
| Operating lease right-of-use assets | | 653.8 |
| | — |
| | — |
|
| Allowance for equity funds used during construction | | 21.7 |
| | 56.4 |
| | 29.8 |
|
| | | | | | | |
See Notes to Consolidated Financial Statements
PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(amounts in thousands,millions, except share and per share data)share)
| | | | Dec. 31 | | Dec. 31 |
| | 2016 | | 2015 | | 2019 | | 2018 |
| Assets | | | | | | | |
| Current assets | | | | | | | |
| Cash and cash equivalents | $ | 5,926 |
| | $ | 3,585 |
| | $ | 11.4 |
| | $ | 33.4 |
|
| Accounts receivable, net | 304,900 |
| | 300,882 |
| | 303.9 |
| | 310.3 |
|
| Accounts receivable from affiliates | 9,421 |
| | 4,909 |
| | 52.7 |
| | 80.8 |
|
| Accrued unbilled revenues | 297,078 |
| | 276,212 |
| | 293.9 |
| | 313.5 |
|
| Inventories | 202,220 |
| | 205,562 |
| | 192.0 |
| | 197.4 |
|
| Regulatory assets | 103,783 |
| | 92,072 |
| | 64.0 |
| | 120.6 |
|
| Derivative instruments | 10,934 |
| | 1,945 |
| | 7.2 |
| | 42.6 |
|
| Prepaid taxes | 9,124 |
| | 81,162 |
| |
| Prepayments and other | 25,435 |
| | 22,698 |
| | 55.9 |
| | 23.8 |
|
| Total current assets | 968,821 |
| | 989,027 |
| | 981.0 |
| | 1,122.4 |
|
| | | | | | | | |
| Property, plant and equipment, net | 12,849,799 |
| | 12,172,211 |
| | 16,155.0 |
| | 15,120.0 |
|
| | | | | | | | |
| Other assets | |
| | |
| | |
| | |
|
| Regulatory assets | 958,429 |
| | 906,275 |
| | 1,038.1 |
| | 1,010.7 |
|
| Derivative instruments | 3,398 |
| | 3,478 |
| | — |
| | 1.2 |
|
| Operating lease right-of-use assets | | | 574.0 |
| | — |
|
| Other | 25,637 |
| | 18,224 |
| | 259.4 |
| | 37.2 |
|
| Total other assets | 987,464 |
| | 927,977 |
| | 1,871.5 |
| | 1,049.1 |
|
| Total assets | $ | 14,806,084 |
| | $ | 14,089,215 |
| | $ | 19,007.5 |
| | $ | 17,291.5 |
|
| | | | | | | | |
| Liabilities and Equity | |
| | |
| | |
| | |
|
| Current liabilities | |
| | |
| | |
| | |
|
| Current portion of long-term debt | $ | 5,270 |
| | $ | 8,103 |
| | $ | 400.0 |
| | $ | 406.2 |
|
| Borrowings under utility money pool arrangement | | | 39.0 |
| | — |
|
| Short-term debt | 129,000 |
| | 14,000 |
| | — |
| | 307.0 |
|
| Accounts payable | 376,186 |
| | 352,701 |
| | 573.3 |
| | 503.4 |
|
| Accounts payable to affiliates | 98,797 |
| | 76,643 |
| | 43.9 |
| | 46.0 |
|
| Regulatory liabilities | 101,110 |
| | 152,823 |
| | 69.2 |
| | 67.3 |
|
| Taxes accrued | 171,862 |
| | 166,660 |
| | 202.1 |
| | 202.0 |
|
| Accrued interest | 48,619 |
| | 49,698 |
| | 53.4 |
| | 43.2 |
|
| Dividends payable to parent | 74,208 |
| | 83,374 |
| | 111.5 |
| | 91.5 |
|
| Derivative instruments | 6,788 |
| | 8,881 |
| | 8.7 |
| | 34.6 |
|
| Operating lease liabilities | | | 85.8 |
| | — |
|
| Other | 73,022 |
| | 78,910 |
| | 98.8 |
| | 101.5 |
|
| Total current liabilities | 1,084,862 |
| | 991,793 |
| | 1,685.7 |
| | 1,802.7 |
|
| | | | | | | | |
| Deferred credits and other liabilities | |
| | |
| | |
| | |
|
| Deferred income taxes | 2,889,129 |
| | 2,658,198 |
| | 1,850.8 |
| | 1,719.3 |
|
| Deferred investment tax credits | 30,661 |
| | 33,466 |
| | 22.8 |
| | 25.3 |
|
| Regulatory liabilities | 512,933 |
| | 471,421 |
| | 2,036.8 |
| | 2,021.5 |
|
| Asset retirement obligations | 289,563 |
| | 240,508 |
| | 324.0 |
| | 338.7 |
|
| Derivative instruments | 7,828 |
| | 13,020 |
| | 52.5 |
| | 0.6 |
|
| Customer advances | 162,742 |
| | 198,526 |
| | 173.6 |
| | 168.1 |
|
| Pension and employee benefit obligations | 285,774 |
| | 200,774 |
| | 211.9 |
| | 275.3 |
|
| Operating lease liabilities | | | 517.6 |
| | — |
|
| Other | 62,201 |
| | 63,864 |
| | 150.9 |
| | 50.4 |
|
| Total deferred credits and other liabilities | 4,240,831 |
| | 3,879,777 |
| | 5,340.9 |
| | 4,599.2 |
|
| | | | | | | | |
| Commitments and contingencies |
|
| |
|
| |
|
| |
|
|
| Capitalization | |
| | |
| | |
| | |
|
| Long-term debt | 4,210,936 |
| | 4,097,493 |
| | 4,984.7 |
| | 4,591.4 |
|
Common stock — 100 shares authorized of $0.01 par value; 100 shares outstanding at Dec. 31, 2016 and 2015, respectively | — |
| | — |
| |
Common stock — 100 shares authorized at $0.01 par value; 100 shares outstanding at Dec. 31, 2019 and 2018, respectively | | | — |
| | — |
|
| Additional paid in capital | 3,633,216 |
| | 3,620,824 |
| | 4,939.4 |
| | 4,340.5 |
|
| Retained earnings | 1,659,239 |
| | 1,523,164 |
| | 2,083.4 |
| | 1,983.2 |
|
| Accumulated other comprehensive loss | (23,000 | ) | | (23,836 | ) | | (26.6 | ) | | (25.5 | ) |
| Total common stockholder’s equity | 5,269,455 |
| | 5,120,152 |
| | 6,996.2 |
| | 6,298.2 |
|
| Total liabilities and equity | $ | 14,806,084 |
| | $ | 14,089,215 |
| | $ | 19,007.5 |
| | $ | 17,291.5 |
|
| | | |
| See Notes to Consolidated Financial Statements | | See Notes to Consolidated Financial Statements |
See Notes to Consolidated Financial Statements
PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
(amounts in thousands,millions, except share and per share data)
| | | | Common Stock Issued | | | | Accumulated Other Comprehensive Income (Loss) | | Total Common Stockholder’s Equity | Common Stock | | | | Accumulated Other Comprehensive Income (Loss) | | Total Common Stockholder’s Equity |
| | Shares | | Par Value | | Additional Paid In Capital | | Retained Earnings | | Shares | | Par Value | | Additional Paid In Capital | | Retained Earnings | |
| Balance at Dec. 31, 2013 | 100 |
| | $ | — |
| | $ | 3,441,290 |
| | $ | 1,384,047 |
| | $ | (23,338 | ) | | $ | 4,801,999 |
| |
| Net income | | | | | | | 455,188 |
| | | | 455,188 |
| |
| Other comprehensive loss | | | | | | | | | (540 | ) | | (540 | ) | |
| Common dividends declared to parent | | | | | | | (452,306 | ) | | | | (452,306 | ) | |
| Contribution of capital by parent | | | | | 81,498 |
| | | | | | 81,498 |
| |
| Balance at Dec. 31, 2014 | 100 |
| | $ | — |
| | $ | 3,522,788 |
| | $ | 1,386,929 |
| | $ | (23,878 | ) | | $ | 4,885,839 |
| |
| | | | | | | | | | | | | |
| Balance at Dec. 31, 2016 | | 100 |
| | $ | — |
| | $ | 3,633.2 |
| | $ | 1,659.3 |
| | $ | (23.0 | ) | | $ | 5,269.5 |
|
| | | | | | | | | | | | | |
| Net income | | | | | | | 466,802 |
| | | | 466,802 |
| | | | | | | 494.1 |
| | | | 494.1 |
|
| Other comprehensive income | | | | | | | | | 42 |
| | 42 |
| | | | | | | | | 1.0 |
| | 1.0 |
|
| Common dividends declared to parent | | | | | | | (330,567 | ) | | | | (330,567 | ) | | | | | | | (335.9 | ) | | | | (335.9 | ) |
| Contribution of capital by parent | | | | | 98,036 |
| | | | | | 98,036 |
| | | | | 399.6 |
| | | | | | 399.6 |
|
| Balance at Dec. 31, 2015 | 100 |
| | $ | — |
| | $ | 3,620,824 |
| | $ | 1,523,164 |
| | $ | (23,836 | ) | | $ | 5,120,152 |
| |
| Adoption of ASU No. 2018-02 | | | | | | | | 4.7 |
| | (4.7 | ) | | — |
|
| Balance at Dec. 31, 2017 | | 100 |
| | $ | — |
| | $ | 4,032.8 |
| | $ | 1,822.2 |
| | $ | (26.7 | ) | | $ | 5,828.3 |
|
| | | | | | | | | | | | | |
| Net income | | | | | | | 463,491 |
| | | | 463,491 |
| | | | | | | 551.7 |
| | | | 551.7 |
|
| Other comprehensive income | | | | | | | | | 836 |
| | 836 |
| | | | | | | | | 1.2 |
| | 1.2 |
|
| Common dividends declared to parent | | | | | | | (327,416 | ) | | | | (327,416 | ) | | | | | | | (390.7 | ) | | | | (390.7 | ) |
| Contribution of capital by parent | | | | | 12,392 |
| | | | | | 12,392 |
| | | | | 307.7 |
| | | | | | 307.7 |
|
| Balance at Dec. 31, 2016 | 100 |
| | $ | — |
| | $ | 3,633,216 |
| | $ | 1,659,239 |
| | $ | (23,000 | ) | | $ | 5,269,455 |
| |
| Balance at Dec. 31, 2018 | | 100 |
| | $ | — |
| | $ | 4,340.5 |
| | $ | 1,983.2 |
| | $ | (25.5 | ) | | $ | 6,298.2 |
|
| | | | | | | | | | | | | |
| Net income | | | | | | | | 577.8 |
| | | | 577.8 |
|
| Other comprehensive income | | | | | | | | | | (1.1 | ) | | (1.1 | ) |
| Common dividends declared to parent | | | | | | | | (477.6 | ) | | | | (477.6 | ) |
| Contribution of capital by parent | | | | | | 598.9 |
| | | | | | 598.9 |
|
| Balance at Dec. 31, 2019 | | 100 |
| | $ | — |
| | $ | 4,939.4 |
| | $ | 2,083.4 |
| | $ | (26.6 | ) | | $ | 6,996.2 |
|
| | | | | | | | | | | | | |
| See Notes to Consolidated Financial Statements | | See Notes to Consolidated Financial Statements |
See Notes to Consolidated Financial Statements
PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CAPITALIZATION
(amounts in thousands, except share and per share data) |
| | | | | | | |
| | Dec. 31 |
| | 2016 | | 2015 |
| Long-Term Debt | | | |
| First Mortgage Bonds, Series due: | | | |
Sept. 1, 2017, 4.375% (a) | $ | — |
| | $ | 129,500 |
|
| Aug. 1, 2018, 5.8% | 300,000 |
| | 300,000 |
|
| June 1, 2019, 5.125% | 400,000 |
| | 400,000 |
|
| Nov. 15, 2020, 3.2% | 400,000 |
| | 400,000 |
|
| Sept. 15, 2022, 2.25% | 300,000 |
| | 300,000 |
|
| March 15, 2023, 2.5% | 250,000 |
| | 250,000 |
|
| May 15, 2025, 2.9% | 250,000 |
| | 250,000 |
|
| Sept. 1, 2037, 6.25% | 350,000 |
| | 350,000 |
|
| Aug. 1, 2038, 6.5% | 300,000 |
| | 300,000 |
|
| Aug. 15, 2041, 4.75% | 250,000 |
| | 250,000 |
|
| Sept. 15, 2042, 3.6% | 500,000 |
| | 500,000 |
|
| March 15, 2043, 3.95% | 250,000 |
| | 250,000 |
|
| March 15, 2044, 4.3% | 300,000 |
| | 300,000 |
|
| June 15, 2046, 3.55% | 250,000 |
| | — |
|
| Capital lease obligations, through 2060, 11.2% — 14.3% | 155,927 |
| | 164,031 |
|
| Unamortized discount | (12,922 | ) | | (11,340 | ) |
| Unamortized debt expense | (26,799 | ) | | (26,595 | ) |
| Total | 4,216,206 |
| | 4,105,596 |
|
| Less current maturities | 5,270 |
| | 8,103 |
|
| Total long-term debt | $ | 4,210,936 |
| | $ | 4,097,493 |
|
| Common Stockholder’s Equity | |
| | |
|
Common Stock — 100 shares authorized of $0.01 par value; 100 shares outstanding at Dec. 31, 2016 and 2015, respectively. | $ | — |
| | $ | — |
|
| Additional paid-in capital | 3,633,216 |
| | 3,620,824 |
|
| Retained earnings | 1,659,239 |
| | 1,523,164 |
|
| Accumulated other comprehensive loss | (23,000 | ) | | (23,836 | ) |
| Total common stockholder’s equity | $ | 5,269,455 |
| | $ | 5,120,152 |
|
| |
(a)
| Pollution control financing. |
See Notes to Consolidated Financial Statements
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
| |
| 1. | Summary of Significant Accounting Policies |
Business and System of AccountsGeneral— 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
PSCo’s consolidated financial statements are presented in accordance with GAAP. All of PSCo’s underlying accounting records also conform to the FERC uniform system of accounts or to systems required by various state regulatory commissions. Certain amounts in the 2018 and 2017 consolidated financial statements or notes have been reclassified to conform to the 2019 presentation for further discussion of jointly owned generation, transmission, and gas facilities and related ownership percentages.
comparative purposes; however, such reclassifications did not affect net income, total assets, liabilities, equity or cash flows.
PSCo evaluates its arrangementshas evaluated events occurring after Dec. 31, 2019 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and contracts with other entities, including but not limited to, 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 activitiesdisclosures resulting from 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.evaluation.
Use of Estimates— In recording transactions and balances resulting from business operations, PSCo uses estimates based on the best information available.available in recording transactions and balances resulting from business operations. Estimates are used foron items 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 recordedRecorded estimates are revised when better information becomes available or when actual amounts can be determined. Those revisionsRevisions 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,other comprehensive income, are deferred as regulatory assets based on the expected ability to recover the costs in future rates; and
Certain credits, which would otherwise be reflected as income or OCI,other comprehensive income, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred.
Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process.
If 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, financial condition and cash flows.
See Note 134 for further discussioninformation.
Income Taxes — PSCo accounts for income taxes using the asset and liability method, which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. PSCo defers income taxes for all temporary differences between pretax financial and taxable income and between the book and tax bases of assets and liabilities. PSCo uses rates that are scheduled to be in effect when the temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the period that includes the enactment date.
The effects of PSCo’s tax rate changes are generally subject to a normalization method of accounting. Therefore, the revaluation of most of its net deferred taxes upon a tax rate reduction results in the establishment of a net regulatory liability, which will be refundable to utility customers over the remaining life of the related assets. A tax rate increase would result in the establishment of a similar regulatory asset.
Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize it over the book depreciable lives of the related property. The requirement to defer and amortize tax credits only applies to federal ITCs related to public utility property. Utility rate regulation also has resulted in the recognition of regulatory assets and liabilities.
Revenue Recognition— Revenuesliabilities related to the sale of energyincome taxes. Deferred tax assets are generally recorded when servicereduced by a valuation allowance if it is renderedmore likely than not that some portion or energy is delivered to customers. However, the determinationall of the energy salesdeferred tax asset will not be realized.
PSCo follows the applicable accounting guidance to individual customersmeasure 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 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 datetechnical merits of the last meter readingposition. Recognition of changes in uncertain tax positions are estimated and the corresponding unbilled revenue is recognized. PSCo presents its revenues netreflected as a component of any excise or other fiduciary-type taxes or fees.
income tax expense.
PSCo has various rate-adjustment mechanisms in place that provide for the recovery of natural gas, electric fuelreports interest 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 bodypenalties related to an environmental, public safety, orincome taxes within the other mandate. When certain criteria are met, revenue is recognized equal toincome and interest charges in the revenue requirement,consolidated statements of income.
Xcel Energy Inc. and its subsidiaries, 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,file consolidated federal income tax returns as well as approximately 23 DSM products, pilots and servicesconsolidated or separate state income tax returns. Federal income taxes paid by Xcel Energy Inc. are allocated to its subsidiaries based on separate company computations. A similar allocation is made for residential and low-income customers. Overall, the DSM portfolio provides rebates and/or incentivesstate income taxes paid by Xcel Energy Inc. in connection with consolidated state filings. Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries.
See Note 7 for nearly 1,000 unique measures.further information.
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 in Regulated Operations —Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and AFUDC. The cost of plant retired is charged to accumulated depreciation and amortization. Amounts recovered in rates for future removal costs are recorded as regulatory liabilities. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance costs are charged to expense as incurred. Maintenance and replacement of items determined to be less than a unit of property are charged to operating expenses as incurred. Planned 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 2.6, 2.72.9% in 2019, 2.6% in 2018 and 2.7 percent for the years ended Dec. 31, 2016, 2015 and 2014, respectively.2.7% in 2017.
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 123 for further discussion of leases.information.
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 consolidated 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 income in the period that includes the enactment date.
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.
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.
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.
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 discussioninformation.
Benefit Plans and Other Postretirement Benefits — PSCo maintains pension and postretirement benefit plans for eligible employees. Recognizing the cost of PSCo’s riskproviding benefits and measuring the projected benefit obligation of these plans requires management to make various assumptions and derivative activities.estimates.
Commodity Trading Operations— All applicableCertain unrecognized actuarial gains and losses related to commodity trading activities, whetherand unrecognized prior service costs or not settled physically,credits are showndeferred as regulatory assets and liabilities, rather than recorded as other comprehensive income, based on a net basis in electric operating revenues in the consolidated statements of income.regulatory recovery mechanisms.
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 109 for further discussion.information.
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. See Note 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.
Inventory— All inventory is recorded at average cost.
RECs — RECs aremarketable 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 PRPspotentially responsible parties exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for PSCo’s expected share of the cost. Any future
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.expenses. Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability.
See Note 10 for further information.
Revenue from Contracts with Customers — Performance obligations related to the sale of energy are satisfied as energy is delivered to customers. PSCo recognizes revenue that corresponds to the price of the energy delivered to the customer. The measurement of energy sales to customers is generally based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and the corresponding unbilled revenue is recognized.
PSCo does not recognize a separate financing component of its collections from customers as contract terms are short-term in nature. PSCo presents its revenues net of any excise or sales taxes or fees.
See Note 126 for further discussion of environmental costs.information.
Benefit PlansCash and Other Postretirement BenefitsCash Equivalents — PSCo maintainsconsiders investments in instruments with a remaining maturity of three months or less at the time of purchase to be cash equivalents.
Accounts Receivable and Allowance for Bad Debts — Accounts receivable are stated at the actual billed amount net of an allowance for bad debts. PSCo establishes an allowance for uncollectible receivables based on a policy that reflects its expected exposure to the credit risk of customers.
As of Dec. 31, 2019 and 2018, the allowance for bad debts was $21.0 million and $20.5 million, respectively.
Inventory — Inventory is recorded at average cost and consisted of the following: |
| | | | | | | | |
| (Millions of Dollars) | | Dec. 31, 2019 | | Dec. 31, 2018 |
| Inventories | | | | |
| Materials and supplies | | $ | 62.6 |
| | $ | 61.9 |
|
| Fuel | | 77.1 |
| | 69.5 |
|
| Natural gas | | 52.3 |
| | 66.0 |
|
| Total inventories | | $ | 192.0 |
| | $ | 197.4 |
|
Fair Value Measurements— PSCo presents cash equivalents, interest rate derivatives and commodity derivatives at estimated fair values in its consolidated financial statements. Cash equivalents are recorded at cost plus accrued interest; money market funds are measured using quoted NAVs. For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used to establish fair value. For commodity derivatives, the most observable inputs available are generally used to determine the fair value of each contract. In the absence of a quoted price, PSCo may use quoted prices for similar contracts or internally prepared valuation models to determine fair value.
For the pension and postretirement benefit plansplan assets, published trading data and pricing models, generally using the most observable inputs available, are utilized to estimate fair value for eligible employees. Recognizing the cost of providing benefitseach security.
See Notes 8 and measuring the projected benefit obligation of these plans under applicable accounting guidance requires management to make various assumptions and estimates.9 for further information.
BasedDerivative Instruments — PSCo uses derivative instruments in connection with its interest rate, utility commodity price, vehicle fuel price and commodity trading activities, including forward contracts, futures, swaps and options. Any derivative instruments not qualifying for the normal purchases and normal sales exception are recorded on the consolidated balance sheets at fair value as derivative instruments. Classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship. Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability. Classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms, certain unrecognized actuarial gains andmechanisms.
Gains or losses and unrecognized prior service costs or creditson commodity trading transactions are recorded as regulatory assetsa component of electric operating revenues; hedging transactions for vehicle fuel costs are recorded as a component of capital projects and liabilities, rather than OCI.O&M costs; and interest rate hedging transactions are recorded as a component of interest expense.
Normal Purchases and Normal Sales — PSCo enters into contracts for purchases and sales of commodities for use in its operations. At inception, contracts are evaluated to determine whether a derivative exists and/or whether an instrument may be exempted from derivative accounting if designated as a normal purchase or normal sale.
See Note 8 for further discussion of benefit plansinformation.
Commodity Trading Operations — All applicable gains and other postretirement benefits.
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.
Reclassifications— Due to adoption of new accounting pronouncements, certain previously reported amounts have been reclassified to conform to the current year presentation. See Note 2 for further discussion of recently adopted accounting pronouncements.
Subsequent Events — Management has evaluated the impact of events occurring after Dec. 31, 2016 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. PSCo expects its adoption will result in increased disclosures regarding revenue, cash flows and obligationslosses related to arrangements with customers, as well as separate presentation of alternative revenue programscommodity trading activities are shown on a net basis in electric operating revenues in the consolidated statements of income.
Commodity trading activities are not associated with energy produced from PSCo’s generation assets or energy and capacity purchased to serve native load. Commodity trading contracts are recorded at fair market value and commodity trading results include the impact of all margin-sharing mechanisms.
See Note 8 for further information.
Other Utility Items
AFUDC— AFUDC represents the cost of capital used to finance utility construction activity. AFUDC is computed by applying a composite financing rate to qualified CWIP. The amount of AFUDC capitalized as a utility construction cost is credited to other nonoperating income (for equity capital) and interest charges (for debt capital). AFUDC amounts capitalized are included in PSCo’s rate base for establishing utility rates.
Alternative Revenue — Certain rate rider mechanisms (including DSM programs) qualify as alternative revenue programs. These mechanisms arise from costs imposed upon the utility by action of a regulator or legislative body related to an environmental, public safety or other mandate. When certain criteria are met, including expected collection within 24 months, revenue is recognized equal to the revenue requirement, which may include incentives and return on rate base items. Billing amounts are revised periodically for differences between total amount collected and revenue earned, which may increase or decrease the level of revenue collected from customers. Alternative revenues arising from these programs are presented on a gross basis and disclosed separately from revenue from contracts with customers.
See Note 6 for further information.
Conservation Programs — PSCo has implemented programs to assist its retail customers in conserving energy and reducing peak demand on the electric and natural gas systems. These programs include approximately 20 unique DSM products, pilots and services for C&I customers, as well as approximately 23 DSM products, pilots and services for residential and low-income customers. Overall, the DSM portfolio provides rebates and/or incentives for nearly 1,000 unique measures.
The costs incurred for DSM programs are deferred if it is probable future revenue will be provided to permit recovery of the incurred cost. Revenues recognized for incentive programs designed for recovery of DSM program costs and/or conservation performance incentives are limited to amounts expected to be collected within 24 months from the annual period in which they are earned.
PSCo’s DSM program costs are recovered through a combination of base rate revenue and rider mechanisms. Regulatory assets are recognized to reflect the amount of costs or earned incentives that have not yet fully determined the impactsbeen collected from customers.
Emission Allowances — Emission allowances are recorded at cost, including broker commission fees. The inventory accounting model is utilized for all emission allowances and sales of adoptionthese allowances are included in electric revenues.
RECs — Cost of RECs that are utilized for several aspects of the standard, including a determination of whether receipts of non-refundable contributions in aid of construction should be recognized as revenues or may continue to becompliance is recorded as reductions to property, plantelectric fuel and equipment. Also, itpurchased power expense. PSCo records that cost as a regulatory asset when the amount is yet to be determined whether and how much an evaluationrecoverable in future rates.
Sales of the collectability of regulatedRECs are recorded in electric and gas revenues will impact the amounts of revenue recognized upon delivery. PSCo currently expects to implement the standard on a modified retrospective basis, which requires applicationgross basis. Cost of these RECs and amounts credited to contracts with customers effective Jan. 1, 2018, with the cumulative impact on contracts not yet completed as of Dec. 31, 2017 recognized as an adjustment to the opening balance of retained earnings.under margin-sharing mechanisms are recorded in electric fuel and purchased power expense.
Classification and Measurement of Financial Instruments |
|
| 2. Accounting Pronouncements |
Recently Issued
Credit Losses— In January 2016, the FASB issued RecognitionFinancial Instruments - Credit Losses, Topic 326 (ASC Topic 326), which changes how entities account for losses on receivables and Measurementcertain other assets. The guidance requires use of Financial Assets and Financial Liabilities, Subtopic 825-10 (ASU No. 2016-01),a current expected credit loss model, which among other changesmay result in earlier recognition of credit losses than under previous accounting and disclosure requirements, replaces the cost method of accounting for non-marketable equity securities with a model for recognizing impairments and observable price changes, and also eliminates the available-for-sale classification for marketable equity securities. Under the new guidance, other than when the consolidation or equity method of accountingstandards. ASC Topic 326 is utilized, changes in the fair value of equity securities are to be recognized in earnings. This guidance will be effective for interim and annual reporting periods beginning on or after Dec. 15, 2017.2019 and will be applied using a modified-retrospective approach, with a cumulative-effect adjustment to retained earnings as of Jan. 1, 2020. PSCo is currently evaluatingexpects the impact of adopting ASU No. 2016-01adoption of the new standard to include first-time recognition of expected credit losses (i.e., bad debt expense) on itsunbilled revenues, with the initial allowance established at Jan. 1, 2020 charged to retained earnings. Recognition of this allowance and other impacts of adoption are expected to be immaterial to the consolidated financial statements.
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 all leases. Additionally, for leases that qualify as finance leases, the guidance requires expense recognition consisting of amortization of the right-of-use asset as well as interest on the related lease liability using the effective interest method. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2018, and early adoption is permitted. PSCo is currently evaluating the impact of adopting ASU No. 2016-02 on its consolidated financial statements.
Recently Adopted
ConsolidationLeases —In February 2015,2016, the FASB issued Amendments to the Consolidation Analysis, Leases, Topic 810 (ASU No. 2015-02)842(ASC Topic 842), which reducesprovides new accounting and disclosure guidance for leasing activities, most significantly requiring that operating leases be recognized on the number of consolidation models and amends certain consolidation principles related to variable interest entities.balance sheet. PSCo implementedadopted the guidance on Jan. 1, 2016,2019 utilizing the package of transition practical expedients provided by the new standard, including carrying forward prior conclusions on whether agreements existing before the adoption date contain leases and whether existing leases are operating or finance leases; ASC Topic 842 refers to capital leases as finance leases.
Specifically for land easement contracts, PSCo has elected the practical expedient provided by ASU No. 2018-01 Leases: Land Easement Practical Expedient for Transition to Topic 842, and as a result, only those easement contracts entered on or after Jan. 1, 2019 will be evaluated to determine if lease treatment is appropriate.
PSCo also utilized the transition practical expedient offered by ASU No. 2018-11 Leases: Targeted Improvements to implement the standard on a prospective basis. As a result, reporting periods in the consolidated financial statements beginning Jan. 1, 2019 reflect the implementation of ASC Topic 842, while prior periods continue to be reported in accordance with Leases, Topic 840 (ASC Topic 840). Other than first-time recognition of operating leases on its consolidated balance sheet, the implementation of ASC Topic 842 did not have a significant impact on itsPSCo’s consolidated financial statements.
Presentation Adoption resulted in recognition of Debt Issuance Costs— In April 2015, the FASB issued Simplifying the Presentationapproximately $0.7 billion of Debt Issuance Costs, Subtopic 835-30 (ASU No. 2015-03), which requires the presentation of debt issuance costs on the balance sheet as a deduction from the carrying amount of the related debt, instead of presentation as an asset. PSCo implemented the new guidance as required on Jan. 1, 2016, and as a result, $26.6 million of such deferred costs were retrospectively reclassified from other non-current assets to long-term debt on the consolidated balance sheet as of Dec. 31, 2015.
Fair Value Measurement— In May 2015, the FASB issued Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent), Topic 820 (ASU No. 2015-07), which eliminates the requirement to categorize fair value measurements using a NAV methodology in the fair value hierarchy. PSCo implemented the guidance on Jan. 1, 2016, and the implementation did not have a material impact on its consolidated financial statements. For related disclosures, see Note 8 to the consolidated financial statements.
Presentation of Deferred Taxes — In November 2015, the FASB issued Balance Sheet Classification of Deferred Taxes, Topic 740 (ASU No. 2015-17), which eliminates the requirement to present deferred taxoperating lease ROU assets and liabilities as current and current/noncurrent on the consolidated balance sheet based on the classification of the related asset or liability, and instead requires classification of all deferred tax assets and liabilities as noncurrent. PSCo early adopted the new guidance in the fourth quarter of 2016 and as a result $62.7 million of current deferred income taxes were retrospectively reclassified to long-term deferred income tax liabilities on the consolidated balance sheet as of Dec. 31, 2015.operating lease liabilities.
Stock Compensation — In March 2016, the FASB issued Improvements to Employee Share-Based Payment Accounting, Topic 718 (ASU No. 2016-09), which simplifies accounting and financial statement presentationSee Note 10 for share-based payment transactions. The guidance requires that the difference between the tax deduction available upon settlement of share-based equity awards and the tax benefit accumulated over the vesting period be recognized as an adjustment to income tax expense. PSCo adopted the guidance in 2016, and the implementation did not have a material impact on its consolidated financial statements.
leasing disclosures.
|
|
| 3. | Selected Balance Sheet Data Plant, Property and Equipment |
|
| | | | | | | | |
| (Thousands of Dollars) | | Dec. 31, 2016 | | Dec. 31, 2015 |
| Accounts receivable, net | | | | |
| Accounts receivable | | $ | 324,512 |
| | $ | 321,004 |
|
| Less allowance for bad debts | | (19,612 | ) | | (20,122 | ) |
| | | $ | 304,900 |
| | $ | 300,882 |
|
|
| | | | | | | | |
| (Millions of Dollars) | | Dec. 31, 2019 | | Dec. 31, 2018 |
| Property, plant and equipment, net | | | | |
| Electric plant | | $ | 14,361.9 |
| | $ | 13,604.5 |
|
| Natural gas plant | | 4,631.4 |
| | 4,387.6 |
|
| Common and other property | | 1,113.5 |
| | 1,023.7 |
|
Plant to be retired (a) | | 259.9 |
| | 321.9 |
|
| CWIP | | 912.7 |
| | 573.3 |
|
| Total property, plant and equipment | | 21,279.4 |
| | 19,911.0 |
|
| Less accumulated depreciation | | (5,124.4 | ) | | (4,791.0 | ) |
| Property, plant and equipment, net | | $ | 16,155.0 |
| | $ | 15,120.0 |
|
|
| | | | | | | | |
| (Thousands of Dollars) | | Dec. 31, 2016 | | Dec. 31, 2015 |
| Inventories | | | | |
| Materials and supplies | | $ | 66,161 |
| | $ | 58,128 |
|
| Fuel | | 66,429 |
| | 78,586 |
|
| Natural gas | | 69,630 |
| | 68,848 |
|
| | | $ | 202,220 |
| | $ | 205,562 |
|
|
| | | | | | | | |
| (Thousands of Dollars) | | Dec. 31, 2016 | | Dec. 31, 2015 |
| Property, plant and equipment, net | | | | |
| Electric plant | | $ | 12,304,436 |
| | $ | 11,856,126 |
|
| Natural gas plant | | 3,710,772 |
| | 3,420,249 |
|
| Common and other property | | 919,955 |
| | 862,840 |
|
Plant to be retired (a) | | 31,839 |
| | 38,249 |
|
| Construction work in progress | | 484,340 |
| | 408,963 |
|
| Total property, plant and equipment | | 17,451,342 |
| | 16,586,427 |
|
| Less accumulated depreciation | | (4,601,543 | ) | | (4,414,216 | ) |
| | | $ | 12,849,799 |
| | $ | 12,172,211 |
|
| |
(a) | In 2017, PSCo expects to2018, the CPUC approved early retire Valmont Unit 5retirement of PSCo’s Comanche Units 1 and convert Cherokee Unit 4 from a coal-fueled generating facility to natural gas.2 in approximately 2022 and 2025, respectively. PSCo also expects Craig Unit 1 to be retired early retired by approximatelyin 2025. Amounts are presented net of accumulated depreciation. |
Joint Ownership of Generation, Transmission and Gas Facilities
Jointly owned assets as of Dec. 31, 2019:
|
| | | | | | | | | | | | | | | |
| (Millions of Dollars) | | Plant in Service | | Accumulated
Depreciation | | CWIP | | Percent Owned |
| Electric generation: | | | | | | | | |
| Hayden Unit 1 | | $ | 152.5 |
| | $ | 80.9 |
| | $ | 0.2 |
| | 76 | % |
| Hayden Unit 2 | | 149.0 |
| | 70.8 |
| | 0.2 |
| | 37 |
|
| Hayden common facilities | | 41.4 |
| | 22.0 |
| | — |
| | 53 |
|
| Craig Units 1 and 2 | | 80.9 |
| | 41.4 |
| | 0.3 |
| | 10 |
|
| Craig common facilities | | 39.1 |
| | 21.7 |
| | 0.1 |
| | 7 |
|
| Comanche Unit 3 | | 886.7 |
| | 148.6 |
| | 0.6 |
| | 67 |
|
| Comanche common facilities | | 28.9 |
| | 3.0 |
| | 0.1 |
| | 82 |
|
| Electric transmission: | | | | | | | | |
| Transmission and other facilities | | 173.7 |
| | 61.7 |
| | 0.9 |
| | Various |
|
| Gas transmission: | | | | | | | | |
| Rifle, CO to Avon, CO | | 22.2 |
| | 7.4 |
| | — |
| | 60 |
|
| Gas transmission compressor | | 8.5 |
| | 1.0 |
| | — |
| | 50 |
|
| Total | | $ | 1,582.9 |
| | $ | 458.5 |
| | $ | 2.4 |
| | |
PSCo’s share of operating expenses and construction expenditures is included in the applicable utility accounts. Respective owners are responsible for providing their own financing.
|
|
| 4. Regulatory Assets and Liabilities |
Regulatory assets and liabilities are created for amounts that regulators may allow to be collected or may require to be paid back to customers in future electric and natural gas rates. PSCo would be required to recognize the write-off of regulatory assets and liabilities in net income or other comprehensive income if changes in the utility industry no longer allow for the application of regulatory accounting guidance under GAAP.
Components of regulatory assets: |
| | | | | | | | | | | | | | | | | | | | | |
| (Millions of Dollars) | | See Note(s) | | Remaining Amortization Period | | Dec. 31, 2019 | | Dec. 31, 2018 |
| Regulatory Assets | | | | | | Current | | Noncurrent | | Current | | Noncurrent |
| Pension and retiree medical obligations | | 9 |
| | Various | | $ | 22.7 |
| | $ | 493.6 |
| | $ | 26.1 |
| | $ | 559.0 |
|
| Depreciation differences | | | | One to twelve years | | 14.6 |
| | 139.6 |
| | 17.5 |
| | 107.0 |
|
Net AROs (a) | | 1, 10 |
| | Plant lives | | — |
| | 119.0 |
| | — |
| | 98.9 |
|
Recoverable deferred taxes on AFUDC recorded in plant | | | | Plant lives | | — |
| | 104.7 |
| | — |
| | 101.9 |
|
| Excess deferred taxes — TCJA | | 7 |
| | Various | | 3.2 |
| | 55.3 |
| | — |
| | 62.0 |
|
| Property tax | | | | Various | | 1.4 |
| | 30.4 |
| | 5.6 |
| | 9.8 |
|
| Purchased power contract costs | | | | Term of related contract | | 2.1 |
| | 24.3 |
| | 1.7 |
| | 26.3 |
|
Conservation programs (b) | | 1 |
| | One to two years | | 8.4 |
| | 11.0 |
| | 7.3 |
| | 6.5 |
|
| Gas pipeline inspection costs | | | | One to two years | | — |
| | 7.9 |
| | 0.7 |
| | 3.1 |
|
| Losses on reacquired debt | | | | Term of related debt | | 1.1 |
| | 4.2 |
| | 1.2 |
| | 3.7 |
|
Contract valuation adjustments (c) | | 1, 8 |
| | Term of related contract | | 3.4 |
| | — |
| | 2.6 |
| | — |
|
| Recoverable purchased natural gas and electric energy costs | | | | Less than one year | | — |
| | — |
| | 51.2 |
| | — |
|
| Other | | | | Various | | 7.1 |
| | 48.1 |
| | 6.7 |
| | 32.5 |
|
| Total regulatory assets | | | | | | $ | 64.0 |
| | $ | 1,038.1 |
| | $ | 120.6 |
| | $ | 1,010.7 |
|
| |
4.(a) | Includes amounts recorded for future recovery of AROs. |
| |
(b) | Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. |
| |
(c) | Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases. |
Components of regulatory liabilities:
|
| | | | | | | | | | | | | | | | | | | | |
| (Millions of Dollars) | | See Note(s) | | Remaining Amortization Period | | Dec. 31, 2019 | | Dec. 31, 2018 |
| Regulatory Liabilities | | | | | | Current | | Noncurrent | | Current | | Noncurrent |
Deferred income tax adjustments and TCJA refunds (a) | | 7 | | Various | | $ | 4.8 |
| | $ | 1,403.2 |
| | $ | 0.8 |
| | $ | 1,441.6 |
|
| Plant removal costs | | 1, 10 | | Plant lives | | — |
| | 350.8 |
| | — |
| | 344.4 |
|
Effects of regulation on employee benefit costs (b) | | | | Various | | — |
| | 183.2 |
| | — |
| | 126.9 |
|
| Renewable resources and environmental initiatives | | | | Various | | — |
| | 44.9 |
| | — |
| | 54.0 |
|
ITC deferrals (c) | | 1 | | Various | | — |
| | 26.1 |
| | — |
| | 27.5 |
|
| Deferred electric, natural gas and steam production costs | | | | Less than one year | | 7.7 |
| | — |
| | 7.2 |
| | — |
|
Conservation programs (d) | | 1 | | Less than one year | | 30.2 |
| | — |
| | 29.8 |
| | — |
|
| Other | | | | Various | | 26.5 |
| | 28.6 |
| | 29.5 |
| | 27.1 |
|
Total regulatory liabilities (e) | | | | | | $ | 69.2 |
| | $ | 2,036.8 |
| | $ | 67.3 |
| | $ | 2,021.5 |
|
| |
(a) | Includes the revaluation of recoverable/regulated plant ADIT and revaluation impact of non-plant ADIT due to the TCJA. |
| |
(b) | Includes regulatory amortization and certain 2018 TCJA benefits approved by the CPUC to offset the prepaid pension asset. |
| |
(c) | Includes impact of lower federal tax rate due to the TCJA. |
| |
(d) | Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. |
| |
(e) | Revenue subject to refund of $16.2 million for 2018 was included in other current liabilities and none for 2019. |
At Dec. 31, 2019 and 2018, PSCo’s regulatory assets not earning a return primarily included the unfunded portion of pension and retiree medical obligations and net AROs. In addition, PSCo’s regulatory assets included $160.0 million and $188.7 million at Dec. 31, 2019 and 2018, respectively, of past expenditures not earning a return. Amounts primarily related to funded pension obligations, property taxes, various renewable resources and certain environmental initiatives.
|
|
| 5. Borrowings and Other Financing Instruments |
Short-Term Borrowings
PSCo meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility and the money pool.
Money Pool — Xcel Energy Inc. and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings between the utility subsidiaries. Xcel Energy Inc. may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy Inc.
Money pool borrowings for PSCo were as follows:
|
| | | | | | | | | | | | | | | | |
| (Millions of Dollars, Except Interest Rates) | | Three Months Ended Dec. 31, 2019 | | Year Ended Dec. 31 |
| | | 2019 | | 2018 | | 2017 |
| Borrowing limit | | $ | 250 |
| | $ | 250 |
| | $ | 250 |
| | $ | 250 |
|
| Amount outstanding at period end | | 39 |
| | 39 |
| | — |
| | — |
|
| Average amount outstanding | | — |
| | 7 |
| | 25 |
| | — |
|
| Maximum amount outstanding | | 39 |
| | 50 |
| | 156 |
| | 20 |
|
| Weighted average interest rate, computed on a daily basis | | 1.63 | % | | 2.29 | % | | 1.93 | % | | 0.92 | % |
| Weighted average interest rate at end of period | | 1.63 |
| | 1.63 |
| | N/A |
| | N/A |
|
|
| | | | |
| (Amounts in Millions, Except Interest Rates) | | Three Months Ended Dec. 31, 2016 |
| Borrowing limit | | $ | 250 |
|
| Amount outstanding at period end | | — |
|
| Average amount outstanding | | 56 |
|
| Maximum amount outstanding | | 141 |
|
| Weighted average interest rate, computed on a daily basis | | 0.78 | % |
| Weighted average interest rate at period end | | N/A |
|
|
| | | | | | | | | | | | |
| (Amounts in Millions, Except Interest Rates) | | Twelve Months Ended Dec. 31, 2016 | | Twelve Months Ended Dec. 31, 2015 | | Twelve Months Ended Dec. 31, 2014 |
| Borrowing limit | | $ | 250 |
| | $ | 250 |
| | $ | 250 |
|
| Amount outstanding at period end | | — |
| | — |
| | — |
|
| Average amount outstanding | | 21 |
| | 1 |
| | 4 |
|
| Maximum amount outstanding | | 141 |
| | 34 |
| | 97 |
|
| Weighted average interest rate, computed on a daily basis | | 0.73 | % | | 0.41 | % | | 0.25 | % |
| Weighted average interest rate at period end | | N/A |
| | N/A |
| | N/A |
|
Commercial Paper — PSCo meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility. Commercial paper borrowings for PSCo were as follows:
|
| | | | | | | | | | | | | | | | |
| (Millions of Dollars, Except Interest Rates) | | Three Months Ended Dec. 31, 2019 | | Year Ended Dec. 31 |
| | | 2019 | | 2018 | | 2017 |
| Borrowing limit | | $ | 700 |
| | $ | 700 |
| | $ | 700 |
| | $ | 700 |
|
| Amount outstanding at period end | | — |
| | — |
| | 307 |
| | — |
|
| Average amount outstanding | | — |
| | 154 |
| | 55 |
| | 54 |
|
| Maximum amount outstanding | | — |
| | 432 |
| | 309 |
| | 268 |
|
| Weighted average interest rate, computed on a daily basis | | N/A |
| | 2.67 | % | | 2.28 | % | | 1.08 | % |
| Weighted average interest rate at end of period | | N/A |
| | N/A |
| | 2.95 |
| | N/A |
|
|
| | | | |
| (Amounts in Millions, Except Interest Rates) | | Three Months Ended Dec. 31, 2016 |
| Borrowing limit | | $ | 700 |
|
| Amount outstanding at period end | | 129 |
|
| Average amount outstanding | | 33 |
|
| Maximum amount outstanding | | 151 |
|
| Weighted average interest rate, computed on a daily basis | | 0.78 | % |
| Weighted average interest rate at period end | | 0.95 |
|
|
| | | | | | | | | | | | |
| (Amounts in Millions, Except Interest Rates) | | Twelve Months Ended Dec. 31, 2016 | | Twelve Months Ended Dec. 31, 2015 | | Twelve Months Ended Dec. 31, 2014 |
| Borrowing limit | | $ | 700 |
| | $ | 700 |
| | $ | 700 |
|
| Amount outstanding at period end | | 129 |
| | 14 |
| | 382 |
|
| Average amount outstanding | | 24 |
| | 95 |
| | 167 |
|
| Maximum amount outstanding | | 154 |
| | 449 |
| | 393 |
|
| Weighted average interest rate, computed on a daily basis | | 0.70 | % | | 0.51 | % | | 0.31 | % |
| Weighted average interest rate at period end | | 0.95 |
| | 0.60 |
| | 0.65 |
|
Letters of Credit— PSCo uses letters of credit, generallytypically with terms of one-year,one year, to provide financial guarantees for certain operating obligations. AtAs of Dec. 31, 20162019 and 2015,2018, there were $3$9 million and $4$10 million of letters of credit outstanding, respectively under the credit facility. The contract amounts of these letters of credit approximate their fair value and are subject to fees.
Credit Facility — In order to use its commercial paper program to fulfill short-term funding needs, PSCo must have a revolving credit facility in place at least equal to the amount of its commercial paper borrowing limit and cannot issue commercial paper in an aggregate amount exceeding available capacity under this credit facility. The credit facility provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.
Amended Credit Agreement— In June 2016,2019, PSCo entered into an amended five-year credit agreement with a syndicate of banks. The total borrowing limit under the amended credit agreement remained at $700 million. The amended credit agreement hasagreements have substantially the same terms and conditions as the prior credit agreementagreements with the following exceptions:
Theexception of the maturity, which was extended from October 2019June 2021 to June 2021.2024.
The Eurodollar borrowing margin on this line of credit was reduced to a range of 75 to 150 basis points per year, from a range of 87.5 to 175 basis points per year, based upon applicable long-term credit ratings.
The commitment fees, calculated on the unused portion of the line of credit, were reduced to a range of 6 to 22.5 basis points per year, from a range of 7.5 to 27.5 basis points per year, also based on applicable long-term credit ratings.
PSCo has the right to request an extension of the termination date for two additional one-year periods. The extension requests are subject to majority bank group approval.
Other featuresFeatures of PSCo’s credit facility include:facility:
|
| | | | | | | | | | |
Debt-to-Total Capitalization Ratio(a) | | Amount Facility May Be Increased (millions) | | Additional Periods for Which a One-Year Extension May Be Requested (b) |
| 2019 | | 2018 | | | | |
| 44 | % | | 46 | % | | $ | 100 |
| | 2 |
| |
(a) | The PSCo financial covenant requires that the debt-to-total capitalization ratio be less than or equal to 65%. |
| |
(b) | All extension requests are subject to majority bank group approval. |
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 45 percent at both Dec. 31, 2016 and 2015. 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.million.
If PSCo does not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender. As of Dec. 31, 2019, PSCo was in compliance with all financial covenants on its debt agreements as of Dec. 31, 2016 and 2015.covenants.
At Dec. 31, 2016, PSCoPSCO had the following committed credit facilityfacilities available (in millions)as of Dec. 31, 2019 (millions):
|
| | | | | | | | | | |
Credit Facility (a) | | Drawn (b) | | Available |
| $ | 700 |
| | $ | 9 |
| | $ | 691 |
|
|
| | | | | | | | | | |
Credit Facility (a) | | Drawn (b) | | Available |
| $ | 700 |
| | $ | 132 |
| | $ | 568 |
|
| |
(a) | This credit facility matures in June 2021.2024. |
| |
(b) | Includes letters of credit and outstanding commercial paper and letters of credit.paper. |
All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. PSCo had no0 direct advances on the credit facility outstanding at Dec. 31, 20162019 and 2015.
2018.
Long-Term Borrowings
and Other Financing Instruments
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 withfor refinanced debt are deferred and amortized over the life of the related new issuance, in accordance with regulatory guidelines.issuance.
Long-term debt obligations for PSCo as of Dec. 31 (millions of dollars):
In 2016, PSCo issued $250 million |
| | | | | | | | | | | | | |
| Financing Instrument | | Interest Rate | | Maturity Date | | 2019 | | 2018 |
First mortgage bonds (d) | | 5.13 | % | | June 1, 2019 | | $ | — |
| | $ | 400 |
|
| First mortgage bonds | | 3.20 |
| | Nov. 15, 2020 | | 400 |
| | 400 |
|
| First mortgage bonds | | 2.25 |
| | Sept. 15, 2022 | | 300 |
| | 300 |
|
| First mortgage bonds | | 2.50 |
| | March 15, 2023 | | 250 |
| | 250 |
|
| First mortgage bonds | | 2.90 |
| | May 15, 2025 | | 250 |
| | 250 |
|
First mortgage bonds (b) | | 3.70 |
| | June 15, 2028 | | 350 |
| | 350 |
|
| First mortgage bonds | | 6.25 |
| | Sept. 1, 2037 | | 350 |
| | 350 |
|
| First mortgage bonds | | 6.50 |
| | Aug. 1, 2038 | | 300 |
| | 300 |
|
| First mortgage bonds | | 4.75 |
| | Aug. 15, 2041 | | 250 |
| | 250 |
|
| First mortgage bonds | | 3.60 |
| | Sept. 15, 2042 | | 500 |
| | 500 |
|
| First mortgage bonds | | 3.95 |
| | March 15, 2043 | | 250 |
| | 250 |
|
| First mortgage bonds | | 4.30 |
| | March 15, 2044 | | 300 |
| | 300 |
|
| First mortgage bonds | | 3.55 |
| | June 15, 2046 | | 250 |
| | 250 |
|
| First mortgage bonds | | 3.80 |
| | June 15, 2047 | | 400 |
| | 400 |
|
First mortgage bonds (b) | | 4.10 |
| | June 15, 2048 | | 350 |
| | 350 |
|
First mortgage bonds (a) | | 4.05 |
| | Sept. 15, 2049 | | 400 |
| | — |
|
First mortgage bonds (a) | | 3.20 |
| | March 1, 2050 | | 550 |
| | — |
|
Capital lease obligations (c) | | 11.20 - 14.30 |
| | 2025-2060 | | — |
| | 145 |
|
| Unamortized discount | | | | | | (24 | ) | | (14 | ) |
| Unamortized debt issuance cost | | | | | | (41 | ) | | (33 | ) |
| Current maturities | | | | | | (400 | ) | | (406 | ) |
| Total long-term debt | | | | | | $ | 4,985 |
| | $ | 4,592 |
|
| |
(c) | PSCo adopted ASC 842 on Jan. 1, 2019, which refers to capital leases as finance leases. Under ASC 842, the present value of future finance lease payments is included in other current liabilities and other noncurrent liabilities rather than debt. |
| |
(d) | Bond was redeemed on March 29, 2019. |
Maturities of 3.55 percent first mortgage bonds due June 15, 2046. In 2015, PSCo issued $250 million of 2.9 percent first mortgage bonds due May 15, 2025.long-term debt:
|
| | | | |
| (Millions of Dollars) | | |
| 2020 | | $ | 400 |
|
| 2021 | | — |
|
| 2022 | | 300 |
|
| 2023 | | 250 |
|
| 2024 | | — |
|
During the next five years, PSCo has long-term debt maturities of $300 million, $400 million and $400 million due in 2018, 2019 and 2020, respectively.
Deferred Financing Costs— Deferred financing costs of approximately $26.8$41 million and $26.6$33 million, net of amortization, are presented as a deduction from the carrying amount of long-term debt atas of Dec. 31, 20162019 and 2015,2018, respectively. PSCo is amortizing these financing costs over the remaining maturity periods of the related debt.
Capital Stock — PSCo has authorized the issuance of preferred stock.
|
| | | | | | | | |
Preferred
Shares
Authorized | | Par Value | | Preferred
Shares
Outstanding |
| 10,000,000 |
| | $ | 0.01 |
| | — |
|
Dividend Restrictions —PSCo’s dividends are subject to the FERC’s jurisdiction, which prohibits the payment of dividends out of capital accounts; payment of dividends is allowed out ofaccounts. Dividends are solely to be paid from retained earnings only.
earnings.
PSCo has authorized the issuance of preferred stock.
|
| | | | | | | | |
Preferred
Shares
Authorized | | Par Value | | Preferred
Shares
Outstanding |
| 10,000,000 |
| | $ | 0.01 |
| | None |
|
|
|
| 6. | Joint Ownership of Generation, Transmission and Gas Facilities Revenues |
Following areRevenue is classified by the investments by PSCo in jointly owned generation, transmissiontype of goods/services rendered and gas facilities andmarket/customer type. PSCo’s operating revenues consisted of the related ownership percentages as of Dec. 31, 2016:following:
|
| | | | | | | | | | | | | | | | |
| | | Year Ended Dec. 31, 2019 |
| (Millions of Dollars) | | Electric | | Natural Gas | | All Other | | Total |
| Major revenue types | | | | | | | | |
| Revenue from contracts with customers: | | | | | | | | |
| Residential | | $ | 1,005.5 |
| | $ | 750.1 |
| | $ | 11.2 |
| | $ | 1,766.8 |
|
| C&I | | 1,579.5 |
| | 281.2 |
| | 27.7 |
| | 1,888.4 |
|
| Other | | 50.0 |
| | — |
| | — |
| | 50.0 |
|
| Total retail | | 2,635.0 |
| | 1,031.3 |
| | 38.9 |
| | 3,705.2 |
|
| Wholesale | | 166.5 |
| | — |
| | — |
| | 166.5 |
|
| Transmission | | 51.7 |
| | — |
| | — |
| | 51.7 |
|
| Other | | 31.8 |
| | 107.3 |
| | — |
| | 139.1 |
|
| Total revenue from contracts with customers | | 2,885.0 |
| | 1,138.6 |
| | 38.9 |
| | 4,062.5 |
|
| Alternative revenue and other | | 148.0 |
| | 22.3 |
| | 4.4 |
| | 174.7 |
|
| Total revenues | | $ | 3,033.0 |
| | $ | 1,160.9 |
| | $ | 43.3 |
| | $ | 4,237.2 |
|
|
| | | | | | | | | | | | | | | |
| (Thousands of Dollars) | | Plant in Service | | Accumulated
Depreciation | | CWIP | | Ownership % |
| Electric Generation: | | | | | | | | |
| Hayden Unit 1 | | $ | 149,221 |
| | $ | 67,415 |
| | $ | 97 |
| | 76 | % |
| Hayden Unit 2 | | 148,795 |
| | 64,024 |
| | 64 |
| | 37 |
|
| Hayden Common Facilities | | 38,230 |
| | 18,951 |
| | 282 |
| | 53 |
|
| Craig Units 1 and 2 | | 60,318 |
| | 37,570 |
| | 15,730 |
| | 10 |
|
| Craig Common Facilities 1, 2 and 3 | | 37,925 |
| | 19,312 |
| | 183 |
| | 7 |
|
| Comanche Unit 3 | | 892,978 |
| | 112,254 |
| | 6 |
| | 67 |
|
| Comanche Common Facilities | | 24,694 |
| | 1,821 |
| | 636 |
| | 82 |
|
| Electric Transmission: | | | | | | | | |
| Transmission and other facilities, including substations | | 166,840 |
| | 65,619 |
| | 4,313 |
| | Various |
|
| Gas Transportation: | | | | | | | | |
| Rifle, Colo. to Avon, Colo. | | 23,406 |
| | 7,679 |
| | — |
| | 60 |
|
| Gas Transportation Compressor | | 8,397 |
| | 368 |
| | — |
| | 50 |
|
| Total | | $ | 1,550,804 |
| | $ | 395,013 |
| | $ | 21,311 |
| | |
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. |
| | | | | | | | | | | | | | | | |
| | | Year Ended Dec. 31, 2018 |
| (Millions of Dollars) | | Electric | | Natural Gas | | All Other | | Total |
| Major revenue types | | | | | | | | |
| Revenue from contracts with customers: | | | | | | | | |
| Residential | | $ | 991.2 |
| | $ | 606.5 |
| | $ | 10.7 |
| | $ | 1,608.4 |
|
| C&I | | 1,560.6 |
| | 223.5 |
| | 25.3 |
| | 1,809.4 |
|
| Other | | 47.6 |
| | — |
| | 0.1 |
| | 47.7 |
|
| Total retail | | 2,599.4 |
| | 830.0 |
| | 36.1 |
| | 3,465.5 |
|
| Wholesale | | 174.6 |
| | — |
| | — |
| | 174.6 |
|
| Transmission | | 54.2 |
| | — |
| | — |
| | 54.2 |
|
| Other | | 54.9 |
| | 84.0 |
| | — |
| | 138.9 |
|
| Total revenue from contracts with customers | | 2,883.1 |
| | 914.0 |
| | 36.1 |
| | 3,833.2 |
|
| Alternative revenue and other | | 148.1 |
| | 100.6 |
| | 4.3 |
| | 253.0 |
|
| Total revenues | | $ | 3,031.2 |
| | $ | 1,014.6 |
| | $ | 40.4 |
| | $ | 4,086.2 |
|
Consolidated Appropriations Act, 2016Federal Tax Reform —In December 2015,2017, the Consolidated Appropriations Act, 2016 (Act)TCJA was signed into law. The Act provideskey provisions impacting Xcel Energy (which includes PSCo), generally beginning in 2018, included:
Corporate federal tax rate reduction from 35% to 21%;
Normalization of resulting plant-related excess deferred taxes;
Elimination of the corporate alternative minimum tax;
Continued interest expense deductibility and discontinued bonus depreciation for regulated public utilities;
Limitations on certain executive compensation deductions;
Limitations on certain deductions for NOLs arising after Dec. 31, 2017 (limited to 80% of taxable income);
Repeal of the following:section 199 manufacturing deduction; and
Reduced deductions for meals and entertainment as well as state and local lobbying.
Immediate expensing, or “bonus depreciation,”Xcel Energy estimated the effects of 50 percentthe TCJA, which have been reflected in the consolidated financial statements.
Reductions in deferred tax assets and liabilities due to a decrease in corporate federal tax rates typically result in a net tax benefit. However, the impacts are primarily recognized as regulatory liabilities refundable to utility customers as a result of IRS requirements and past regulatory treatment.
Estimated impacts of the new tax law for property placedPSCo in service in 2015, 2016, and 2017; 40 percentDecember 2017 included:
$1.1 billion ($1.5 billion grossed-up for property placed in service in 2018; and 30 percent for property placed in service in 2019. Additionally, some longer production period property placed in service in 2020tax) of reclassifications of plant-related excess deferred taxes to regulatory liabilities upon valuation at the new 21% federal rate. The regulatory liabilities will be eligible for bonus depreciation;
PTCs at 100 percentamortized consistent with IRS normalization requirements, resulting in customer refunds over the average remaining life of the credit rate ($0.023 per KWh)related property;
$54 million and $50 million of reclassifications (grossed-up for wind energy projects that begin construction by the endtax) of 2016; 80 percentexcess deferred taxes for non-plant related deferred tax assets and liabilities, respectively, to regulatory assets and liabilities; and
$18 million 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 excisetotal estimated income tax on certain employer-provided health insurance plans.
The accountingbenefit related to the Act was recorded beginning in the fourth quarter of 2015 becausefederal tax reform implementation, and a change in tax law is accounted for beginning in the period of enactment.
Tax Increase Prevention Act of 2014— In 2014, the Tax Increase Prevention Act (TIPA) was signed into law. The TIPA provides for the following:
The R&E credit was extended for 2014;
PTCs were extended for projects that began construction before the end of 2014 with certain projects qualifying into future years; and
50 percent bonus depreciation was extended one year through 2014. Additionally, some longer production period property placed in service in 2015 is also eligible for 50 percent bonus depreciation.
The accounting$4 million reduction to net income related to the TIPA was recorded beginning inallocation of Xcel Energy Services Inc.’s tax rate change on its deferred taxes.
Xcel Energy accounted for the fourth quarterstate tax impacts of 2014 because a change infederal tax reform based on enacted state tax laws. Any future state tax law ischanges related to the TCJA will be accounted for in the period of enactment.periods state laws are enacted.
Federal Audit— PSCo is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. Statute of limitations applicable to Xcel Energy’s consolidated federal income tax returns expire as follows: |
| | |
| Tax Year(s) | | Expiration |
| 2009 - 2013 | | June 2020 |
| 2014 - 2016 | | September 2020 |
In 2012,2015, the IRS commenced an examination of tax years 20102012 and 2011, including2013. In 2017, the IRS concluded the audit of tax years 2012 and 2013 and proposed an adjustment that would impact Xcel Energy’s NOL and ETR. Xcel Energy filed a 2009 carryback claim.protest with the IRS. As of Dec. 31, 2016,2019, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $14 million of income tax expense for the 2009 through 2011 claims, and the 2013 through 2015 claims. In the fourth quarter of 2015, the IRScase has been forwarded the issue to the Office of Appeals (Appeals). In 2016 the IRS audit team and Xcel Energy presented their cases to Appeals; however, the outcome and timing of a resolution is uncertain. The statute of limitations applicable to Xcel Energy’s 2009 through 2011 federal income tax returns, following extensions, expires in December 2017. Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of the IRS’ proposed adjustment of the carryback claims. PSCo is not expected to accrue any income tax expense related to this adjustment.
In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013. As of Dec. 31, 2016, the IRS had not proposed any material adjustments to tax years 2012 and 2013. Subsequent to year-end, the IRS proposed an adjustment to tax years 2012 through 2013 that may impact Xcel Energy’s NOL and tax credit carryforwards and ETR. However, Xcel Energy is continuing to evaluate the IRS’ proposal andissue; however, the outcome and timing of a resolution is uncertain.unknown.
In the fourth quarter of 2018, the IRS began an audit of tax years 2014 - 2016. As of Dec. 31, 2019 0 adjustments have been proposed.
State Audits — PSCo is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Dec. 31, 2016,2019, PSCo’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009. There are currently no state income tax audits in progress.
Unrecognized Tax Benefits— The unrecognized 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.
Unrecognized tax benefits - permanent vs temporary:
A reconciliation of the amount of |
| | | | | | | | |
| (Millions of Dollars) | | Dec. 31, 2019 | | Dec. 31, 2018 |
| Unrecognized tax benefit — Permanent tax positions | | $ | 7.4 |
| | $ | 5.4 |
|
| Unrecognized tax benefit — Temporary tax positions | | 4.6 |
| | 4.9 |
|
| Total unrecognized tax benefit | | $ | 12.0 |
| | $ | 10.3 |
|
Changes in unrecognized tax benefit is as follows:benefits:
|
| | | | | | | | | | | | |
| (Millions of Dollars) | | 2019 | | 2018 | | 2017 |
| Balance at Jan. 1 | | $ | 10.3 |
| | $ | 10.1 |
| | $ | 19.7 |
|
| Additions based on tax positions related to the current year | | 1.4 |
| | 1.1 |
| | 1.9 |
|
| Reductions based on tax positions related to the current year | | (0.2 | ) | | (0.3 | ) | | (1.5 | ) |
| Additions for tax positions of prior years | | 0.5 |
| | 0.4 |
| | 4.4 |
|
| Reductions for tax positions of prior years | | — |
| | (0.1 | ) | | (14.4 | ) |
| Settlements with taxing authorities | | — |
| | (0.9 | ) | | — |
|
| Balance at Dec. 31 | | $ | 12.0 |
| | $ | 10.3 |
| | $ | 10.1 |
|
|
| | | | | | | | |
| (Millions of Dollars) | | Dec. 31, 2016 | | Dec. 31, 2015 |
| Unrecognized tax benefit — Permanent tax positions | | $ | 2.9 |
| | $ | 2.4 |
|
| Unrecognized tax benefit — Temporary tax positions | | 16.8 |
| | 15.0 |
|
| Total unrecognized tax benefit | | $ | 19.7 |
| | $ | 17.4 |
|
A reconciliation of the beginning and ending amount of unrecognizedUnrecognized tax benefit is as follows:
|
| | | | | | | | | | | | |
| (Millions of Dollars) | | 2016 | | 2015 | | 2014 |
| Balance at Jan. 1 | | $ | 17.4 |
| | $ | 11.9 |
| | $ | 8.4 |
|
| Additions based on tax positions related to the current year | | 2.7 |
| | 4.5 |
| | 3.7 |
|
| Reductions based on tax positions related to the current year | | — |
| | (1.5 | ) | | (0.7 | ) |
| Additions for tax positions of prior years | | 0.5 |
| | 2.5 |
| | 2.8 |
|
| Reductions for tax positions of prior years | | (0.9 | ) | | — |
| | (1.2 | ) |
| Settlements with taxing authorities | | — |
| | — |
| | (1.1 | ) |
| Balance at Dec. 31 | | $ | 19.7 |
| | $ | 17.4 |
| | $ | 11.9 |
|
The unrecognized tax benefit amountsbenefits were reduced by the tax benefits associated with NOL and tax credit carryforwards. The amounts ofcarryforwards:
|
| | | | | | | | |
| (Millions of Dollars) | | Dec. 31, 2019 | | Dec. 31, 2018 |
| NOL and tax credit carryforwards | | $ | (8.3 | ) | | $ | (5.6 | ) |
Net deferred tax benefitsliability associated with NOLthe unrecognized tax benefit amounts and related NOLs and tax creditcredits carryforwards are as follows:
were $5.0 million and $2.0 million for Dec. 31, 2019 and Dec. 31, 2018, respectively.
|
| | | | | | | | |
| (Millions of Dollars) | | Dec. 31, 2016 | | Dec. 31, 2015 |
| NOL and tax credit carryforwards | | $ | (5.8 | ) | | $ | (4.3 | ) |
It is reasonably possible that PSCo’s amount of unrecognized tax benefits could significantly change in the next 12 months asAs the IRS Appeals and federal audit progress and state audits resume. As the IRS Appeals and audit progress,resume, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $11 million.$8.7 million in the next 12 months.
The payablePayable 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
Interest payable
for interest related to unrecognized tax
benefits are as follows:benefits: | | | (Millions of Dollars) | | 2016 | | 2015 | | 2014 | | 2019 | | 2018 | | 2017 |
| Payable for interest related to unrecognized tax benefits at Jan. 1 | | $ | (0.4 | ) | | $ | (0.2 | ) | | $ | (0.1 | ) | | $ | (0.7 | ) | | $ | (0.3 | ) | | $ | (1.1 | ) |
| Interest expense related to unrecognized tax benefits | | (0.7 | ) | | (0.2 | ) | | (0.1 | ) | |
| Interest (expense) income related to unrecognized tax benefits | | | (0.4 | ) | | (0.4 | ) | | 0.8 |
|
| Payable for interest related to unrecognized tax benefits at Dec. 31 | | $ | (1.1 | ) | | $ | (0.4 | ) | | $ | (0.2 | ) | | $ | (1.1 | ) | | $ | (0.7 | ) | | $ | (0.3 | ) |
No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2016, 20152019, 2018 or 2014.2017.
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) | | 2019 | | 2018 |
| Federal tax credit carryforwards | | $ | 83.2 |
| | $ | 35.0 |
|
| State NOL carryforwards | | 388.1 |
| | 484.7 |
|
State tax credit carryforwards, net of federal detriment (a) | | 17.6 |
| | 16.9 |
|
Valuation allowances for state credit carryforwards, net of federal benefit (b) | | (8.0 | ) | | (8.9 | ) |
|
| | | | | | | | |
| (Millions of Dollars) | | 2016 | | 2015 |
| Federal NOL carryforward | | $ | 260 |
| | $ | 328 |
|
| Federal tax credit carryforwards | | 25 |
| | 24 |
|
| State NOL carryforwards | | 684 |
| | 684 |
|
State tax credit carryforwards, net of federal detriment (a) | | 13 |
| | 13 |
|
Valuation allowances for state credit carryforwards, net of federal detriment (b) | | (3 | ) | | (1 | ) |
| |
(a) | State tax credit carryforwards are net of federal detriment of $7$4.7 million and $7$4.5 million as of Dec. 31, 20162019 and 2015,2018, respectively. |
| |
(b) | Valuation allowances for state tax credit carryforwards were net of federal benefit of $2$2.1 million and $1$2.4 million as of Dec. 31, 20162019 and 2015,2018, respectively. |
The federalFederal carryforward periods expire between 20212023 and 2036. The2039 and state carryforward periods expire between 20172020 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
Effective income tax rate for years ended Dec. 31: |
| | | | | | | | | |
| | | 2019 | | 2018 (a) | | 2017 (a) |
| Federal statutory rate | | 21.0 | % | | 21.0 | % | | 35.0 | % |
| State income tax on pretax income, net of federal tax effect | | 3.6 | % | | 3.7 | % | | 3.0 | % |
| Increases (decreases) in tax from: | |
|
| |
|
| |
|
|
| Wind PTCs | | (7.5 | ) | | (0.6 | ) | | — |
|
Plant regulatory differences (b) | | (3.3 | ) | | (4.5 | ) | | (1.0 | ) |
| Other tax credits, net of NOL & tax credit allowances | | (1.3 | ) | | (0.6 | ) | | (0.9 | ) |
| Amortization of excess nonplant deferred taxes | | (0.2 | ) | | (1.4 | ) | | — |
|
| Change in unrecognized tax benefits | | 0.3 |
| | 0.1 |
| | 0.2 |
|
| Tax reform | | — |
| | — |
| | (2.4 | ) |
| Other, net | | (0.5 | ) | | (0.6 | ) | | (0.1 | ) |
| Effective income tax rate | | 12.1 | % | | 17.1 | % | | 33.8 | % |
(a)Prior periods have been reclassified to conform to current year presentation.
(b) Regulatory differences for income tax primarily relate to the years ending Dec. 31:credit of excess deferred taxes to customers through the average rate assumption method. Income tax benefits associated with the credit of excess deferred credits are offset by corresponding revenue reductions and additional prepaid pension asset amortization.
|
| | | | | | | | | |
| | | 2016 | | 2015 | | 2014 |
| Federal statutory rate | | 35.0 | % | | 35.0 | % | | 35.0 | % |
| Increases (decreases) in tax from: | | | | | | |
| State income taxes, net of federal income tax benefit | | 3.2 |
| | 3.2 |
| | 2.8 |
|
| Tax credits recognized, net of federal income tax expense | | (0.7 | ) | | (0.7 | ) | | (0.8 | ) |
| Regulatory differences — utility plant items | | (0.5 | ) | | (0.3 | ) | | (2.1 | ) |
| Change in unrecognized tax benefits (expense) | | — |
| | 0.1 |
| | (0.1 | ) |
| Other, net | | 0.1 |
| | 0.1 |
| | 0.1 |
|
| Effective income tax rate | | 37.1 | % | | 37.4 | % | | 34.9 | % |
The componentsComponents of income tax expense for the years endingended Dec. 31 were:31:
|
| | | | | | | | | | | | |
| (Thousands of Dollars) | | 2016 | | 2015 | | 2014 |
| Current federal tax expense (benefit) | | $ | 45,287 |
| | $ | (1,166 | ) | | $ | 9,550 |
|
| Current state tax expense (benefit) | | 8,754 |
| | (727 | ) | | 2,611 |
|
| Current change in unrecognized tax expense | | 680 |
| | 5,244 |
| | 6,548 |
|
| Deferred federal tax expense | | 195,064 |
| | 246,096 |
| | 208,781 |
|
| Deferred state tax expense | | 27,216 |
| | 36,450 |
| | 26,196 |
|
| Deferred change in unrecognized tax benefit | | (278 | ) | | (4,650 | ) | | (7,154 | ) |
| Deferred investment tax credits | | (2,805 | ) | | (2,807 | ) | | (2,941 | ) |
| Total income tax expense | | $ | 273,918 |
| | $ | 278,440 |
| | $ | 243,591 |
|
|
| | | | | | | | | | | | |
| (Millions of Dollars) | | 2019 | | 2018 | | 2017 |
| Current federal tax (benefit) expense | | $ | (8.9 | ) | | $ | 79.5 |
| | $ | 40.4 |
|
| Current state tax (benefit) expense | | (5.0 | ) | | 14.2 |
| | 14.6 |
|
| Current change in unrecognized tax benefit | | (1.0 | ) | | (1.3 | ) | | (7.8 | ) |
| Deferred federal tax expense | | 60.9 |
| | 4.9 |
| | 176.4 |
|
| Deferred state tax expense | | 33.1 |
| | 16.6 |
| | 22.5 |
|
| Deferred change in unrecognized tax expense | | 3.0 |
| | 2.3 |
| | 8.9 |
|
| Deferred ITCs | | (2.5 | ) | | (2.5 | ) | | (2.8 | ) |
| Total income tax expense | | $ | 79.6 |
| | $ | 113.7 |
| | $ | 252.2 |
|
The componentsComponents of deferred income tax expense for the years endingas of Dec. 31 were:31:
|
| | | | | | | | | | | | |
| (Millions of Dollars) | | 2019 | | 2018 | | 2017 |
| Deferred tax expense (benefit) excluding items below | | $ | 131.5 |
| | $ | 74.8 |
| | $ | (1,244.7 | ) |
| Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities | | (34.9 | ) | | (50.6 | ) | | 1,453.1 |
|
| Tax benefit (expense) allocated to other comprehensive income, net of adoption of ASU No. 2018-02, and other | | 0.4 |
| | (0.4 | ) | | (0.6 | ) |
| Deferred tax expense | | $ | 97.0 |
| | $ | 23.8 |
| | $ | 207.8 |
|
|
| | | | | | | | | | | | |
| (Thousands of Dollars) | | 2016 | | 2015 | | 2014 |
| Deferred tax expense excluding items below | | $ | 230,931 |
| | $ | 285,144 |
| | $ | 254,142 |
|
| Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities | | (8,418 | ) | | (7,229 | ) | | (26,649 | ) |
| Tax (expense) benefit allocated to other comprehensive income and other | | (511 | ) | | (19 | ) | | 330 |
|
| Deferred tax expense | | $ | 222,002 |
| | $ | 277,896 |
| | $ | 227,823 |
|
The componentsComponents of the net deferred tax liability atas of Dec. 31 were as follows:31:
|
| | | | | | | | |
| (Millions of Dollars) | | 2019 | | 2018 (a) |
| Deferred tax liabilities: | | | | |
| Differences between book and tax bases of property | | $ | 2,039.1 |
| | $ | 1,860.1 |
|
| Regulatory assets | | 253.1 |
| | 251.1 |
|
| Operating lease assets | | 147.9 |
| | — |
|
| Pension expense and other employee benefits | | 21.5 |
| | 31.1 |
|
| Other | | 8.3 |
| | 1.7 |
|
| Total deferred tax liabilities | | $ | 2,469.9 |
| | $ | 2,144.0 |
|
| | | | | |
| Deferred tax assets: | | |
| | |
|
| Regulatory liabilities | | $ | 327.2 |
| | $ | 336.3 |
|
| Operating lease liabilities | | 147.9 |
| | — |
|
| Tax credit carryforward | | 100.8 |
| | 51.9 |
|
| NOL carryforward | | 14.3 |
| | 18.2 |
|
| Rate refund | | 6.1 |
| | 9.3 |
|
| Deferred ITCs | | 5.6 |
| | 6.3 |
|
| Tax credit valuation allowances | | (8.0 | ) | | (8.9 | ) |
| Other | | 25.2 |
| | 11.6 |
|
| Total deferred tax assets | | $ | 619.1 |
| | $ | 424.7 |
|
| Net deferred tax liability | | $ | 1,850.8 |
| | $ | 1,719.3 |
|
(a) Prior periods have been reclassified to conform to current year presentation.
|
| | | | | | | | |
| (Thousands of Dollars) | | 2016 | | 2015 |
| Deferred tax liabilities: | | | | |
| Differences between book and tax bases of property | | $ | 2,967,162 |
| | $ | 2,772,043 |
|
| Employee benefits | | 87,693 |
| | 105,049 |
|
| Other | | 69,931 |
| | 82,732 |
|
| Total deferred tax liabilities | | $ | 3,124,786 |
| | $ | 2,959,824 |
|
| Deferred tax assets: | | | | |
| NOL carryforward | | $ | 115,328 |
| | $ | 147,763 |
|
| Tax credit carryforward | | 34,658 |
| | 35,240 |
|
| Regulatory liabilities | | 19,635 |
| | 17,201 |
|
| Deferred investment tax credits | | 11,653 |
| | 12,718 |
|
| Deferred fuel costs | | 10,070 |
| | 29,694 |
|
| Rate refund | | 7,221 |
| | 23,352 |
|
| Other | | 37,092 |
| | 35,658 |
|
| Total deferred tax assets | | $ | 235,657 |
| | $ | 301,626 |
|
| Net deferred tax liability | | $ | 2,889,129 |
| | $ | 2,658,198 |
|
|
|
| 8. | Benefit Plans Fair Value of Financial Assets and Other Postretirement BenefitsLiabilities |
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 77 percent of employees that receive benefits are represented by several local labor unions under several collective-bargaining agreements. At Dec. 31, 2016, PSCo had 1,984 bargaining employees covered under a collective-bargaining agreement, which expires in May 2017.
Fair Value Measurements
The plans invest in various instruments which are disclosed under the accounting guidance for fair value measurements which establishesand disclosures provides a single definition of fair value and requires disclosures about assets and liabilities measured at fair value. A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value. The three levels in the hierarchy and examples of each level are as follows:value is established by this guidance.
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.
| |
| • | Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices. |
| |
| • | Level 2 — Pricing inputs are other than quoted prices in active markets but are either directly or indirectly observable as of the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts or priced with models using highly observable inputs. |
| |
| • | Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those valued with models requiring significant management judgment or estimation. |
Specific valuation methods include the following:include:
Cash equivalents—The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted NAVs.NAV.
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 exchangeInterest rate of the underlying currencies.derivatives— The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.
Commodity derivatives— The methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2 classification. When contractual settlements relate to inactive delivery locations or extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable forecasts of forward prices and volatilities on a valuation is evaluated and may result in Level 3 classification.
Derivative Instruments Fair Value Measurements
PSCo enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to manage risk in connection with changes in interest rates, utility commodity prices and vehicle fuel prices.
Interest Rate Derivatives — PSCo enters into various instruments that effectively fix the interest payments on certain floating rate debt obligations or effectively fix the yield or price on a specified benchmark interest rate for an anticipated debt issuance for a specific period. These derivative instruments are generally designated as cash flow hedges for accounting purposes.
As of Dec. 31, 2019, accumulated other comprehensive losses related to interest rate derivatives included $1.2 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for unsettled hedges, as applicable.
Wholesale and Commodity Trading Risk — PSCo conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. PSCo is allowed to conduct these activities within guidelines and limitations as approved by its risk management committee, comprised of management personnel not directly involved in activities governed by this policy.
Commodity Derivatives — PSCo enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric and natural gas operations, as well as for trading purposes. This could include the purchase or sale of energy or energy-related products, natural gas to generate electric energy, natural gas for resale, and vehicle fuel.
PSCo enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but may not be designated as qualifying hedging transactions. Changes in the fair value of non-trading commodity derivative instruments are recorded in other comprehensive income or deferred as a regulatory asset or liability. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. NaN amounts related to the ineffectiveness of cash flow hedges were recorded for the years ended Dec. 31, 2019 and 2018.
As of Dec. 31, 2019, there were 0 net gains related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses or related amounts expected to be reclassified into earnings during the next 12 months.
PSCo enters into commodity derivative instruments for trading purposes not directly related to commodity price risks associated with serving its electric and natural gas customers. Changes in the fair value of these commodity derivatives are recorded in electric operating revenues, net of amounts credited to customers under margin-sharing mechanisms.
Gross notional amounts of commodity forwards and options at Dec. 31:
|
| | | | | | |
(Amounts in Millions) (a)(b) | | 2019 | | 2018 |
| MWh of electricity | | 9.3 |
| | 24.4 |
|
| MMBtu of natural gas | | 32.2 |
| | 48.4 |
|
| |
(a) | Amounts are not reflective of net positions in the underlying commodities. |
| |
(b) | Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise. |
Consideration of Credit Risk and Concentrations — PSCo continuously monitors the creditworthiness of the counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. The impact of credit risk was immaterial to the fair value of unsettled commodity derivatives presented in the consolidated balance sheets.
PSCo’s most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to its wholesale, trading and non-trading commodity activities. At Dec. 31, 2019, 5 of PSCo’s 10 most significant counterparties for these activities, comprising $110.1 million or 78% of this credit exposure, had investment grade credit ratings from Standard & Poor’s, Moody’s or Fitch Ratings. NaN of the 10 most significant counterparties, comprising $15.7 million or 11% of this credit exposure, were not rated by these external agencies, but based on PSCo’s internal analysis, had credit quality consistent with investment grade. NaN of these significant counterparties are municipal or cooperative electric entities, ISOs or other utilities.
Pension BenefitsQualifying Cash Flow Hedges — Financial impact of qualifying interest rate and vehicle fuel cash flow hedges on PSCo’s accumulated other comprehensive loss, included in the consolidated statements of common stockholder’s equity and in the consolidated statements of comprehensive income:
|
| | | | | | | | | | | | |
| (Millions of Dollars) | | 2019 | | 2018 | | 2017 |
| Accumulated other comprehensive loss related to cash flow hedges at Jan. 1 | | $ | (25.3 | ) | | $ | (26.5 | ) | | $ | (22.8 | ) |
| After-tax net realized losses on derivative transactions reclassified into earnings | | 1.2 |
| | 1.2 |
| | 1.0 |
|
Adoption of ASU No. 2018-02 (a) | | — |
| | — |
| | (4.7 | ) |
| Accumulated other comprehensive loss related to cash flow hedges at Dec. 31 | | $ | (24.1 | ) | | $ | (25.3 | ) | | $ | (26.5 | ) |
| |
(a) | In 2017, PSCo implemented ASU No. 2018-02 related to TCJA, which resulted in reclassification of certain credit balances within net accumulated other comprehensive loss to retained earnings. |
Impact of derivative activity:
|
| | | | | | | | |
| | | Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: |
| (Millions of Dollars) | | Accumulated Other
Comprehensive Loss | | Regulatory (Assets) and Liabilities |
| Year to date Dec. 31, 2019 | | | | |
| Other derivative instruments | | | | |
| Natural gas commodity | | $ | — |
| | $ | (5.3 | ) |
| Total | | $ | — |
| | $ | (5.3 | ) |
| | | | | |
| Year to date Dec. 31, 2018 | | | | |
| Other derivative instruments | | | | |
| Natural gas commodity | | $ | — |
| | $ | 8.0 |
|
| Total | | $ | — |
| | $ | 8.0 |
|
| | | | | |
| Year to date Dec. 31, 2017 | | | | |
| Other derivative instruments | | | | |
| Natural gas commodity | | $ | — |
| | $ | (10.9 | ) |
| Total | | $ | — |
| | $ | (10.9 | ) |
|
| | | | | | | | | | | | | |
| | | Pre-Tax (Gains) Losses
Reclassified into Income
During the Period from: | | | |
| (Millions of Dollars) | | Accumulated
Other
Comprehensive Loss | | Regulatory
Assets and (Liabilities) | | Pre-Tax Gains (Losses) Recognized
During the Period
in Income | |
| Year to date Dec. 31, 2019 | | | | | | | |
| Derivatives designated as cash flow hedges | | | | | | | |
| Interest rate | | $ | 1.6 |
| (a) | $ | — |
| | $ | — |
| |
| Total | | $ | 1.6 |
| | $ | — |
| | $ | — |
| |
| Other derivative instruments | | . |
| | | | | |
| Commodity trading | | $ | — |
| | $ | — |
| | $ | 3.1 |
| (c) |
| Natural gas commodity | | — |
| | 0.6 |
| (d) | (3.9 | ) | (d) |
| Total | | $ | — |
| | $ | 0.6 |
| | $ | (0.8 | ) | |
| | | | | | | | |
| Year to date Dec. 31, 2018 | | | | | | | |
| Derivatives designated as cash flow hedges | | | | | | | |
| Interest rate | | $ | 1.6 |
| (a) | $ | — |
| | $ | — |
| |
| Total | | $ | 1.6 |
| | $ | — |
| | $ | — |
| |
| Other derivative instruments | | | | | | | |
| Commodity trading | | $ | — |
| | $ | — |
| | $ | 3.1 |
| (c) |
| Natural gas commodity | | — |
| | (4.1 | ) | (d) | (2.9 | ) | (d) |
| Total | | $ | — |
| | $ | (4.1 | ) | | $ | 0.2 |
| |
| | | | | | | | |
| Year to date Dec. 31, 2017 | | | | | | | |
| Derivatives designated as cash flow hedges | | | | | | | |
| Interest rate | | $ | 1.6 |
| (a) | $ | — |
| | $ | — |
| |
| Total | | $ | 1.6 |
| | $ | — |
| | $ | — |
| |
| Other derivative instruments | | | | | | | |
| Commodity trading | | $ | — |
| | $ | — |
| | $ | 0.4 |
| (c) |
| Natural gas commodity | | — |
| | 1.9 |
| (d) | (4.2 | ) | (d) |
| Total | | $ | — |
| | $ | 1.9 |
| | $ | (3.8 | ) | |
| |
(a) | Amounts are recorded to interest charges. |
| |
(b) | Amounts are recorded to O&M expenses. |
| |
(c) | Amounts are recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate. |
| |
(d) | Amounts for the year ended Dec. 31, 2019, 2018 and 2017 included 0 settlement gains or losses, $1.2 million of settlement losses and $0.4 million of settlement gains, respectively, on derivatives entered to mitigate natural gas price risk for electric generation recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset or liability, as appropriate. Remaining settlement losses for the years ended Dec. 31, 2019, 2018 and 2017 relate to natural gas operations and are recorded to cost of natural gas sold and transported. These losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset or liability, as appropriate. |
PSCo had 0 derivative instruments designated as fair value hedges during the years ended Dec. 31, 2019, 2018 and 2017.
Credit Related Contingent Features— Contract provisions for derivative instruments that PSCo enters into, including those accounted for as normal purchase-normal sale contracts and therefore not reflected on the consolidated balance sheets, may require the posting of collateral or settlement of the contracts for various reasons, including if PSCo’s credit ratings are downgraded below its investment grade credit rating by any of the major credit rating agencies, or for cross-default contractual provisions if there was a failure under other financing arrangements related to payment terms or other covenants.
At Dec. 31, 2019 and 2018, there were 0 derivative instruments in a liability position with such underlying contract provisions.
Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that PSCo’s ability to fulfill its contractual obligations is reasonably expected to be impaired. PSCo had 0 collateral posted related to adequate assurance clauses in derivative contracts as of Dec. 31, 2019 and 2018.
Recurring Fair Value Measurements— The following table presents, for each of the fair value hierarchy levels, PSCo’s derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2019 and 2018: |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Dec. 31, 2019 | | Dec. 31, 2018 |
| | | Fair Value | | | | | | | | Fair Value | | | | | | |
| (Millions of Dollars) | | Level 1 | | Level 2 | | Level 3 | | Fair Value Total | | Netting (a) | | Total | | Level 1 | | Level 2 | | Level 3 | | Fair Value Total | | Netting (a) | | Total |
| Current derivative assets | | | | | | | | | | | | | | | | | | | | | | | | |
| Other derivative instruments: | | | | | | | | | | | | | | | | | | | | | | | | |
| Commodity trading | | $ | 1.9 |
| | $ | 11.1 |
| | $ | 0.9 |
| | $ | 13.9 |
| | $ | (10.1 | ) | | $ | 3.8 |
| | $ | 2.3 |
| | $ | 65.0 |
| | $ | 0.1 |
| | $ | 67.4 |
| | $ | (28.2 | ) | | $ | 39.2 |
|
| Natural gas commodity | | — |
| | 3.4 |
| | — |
| | 3.4 |
| | — |
| | 3.4 |
| | — |
| | 3.4 |
| | — |
| | 3.4 |
| | — |
| | 3.4 |
|
| Total current derivative assets | | $ | 1.9 |
| | $ | 14.5 |
| | $ | 0.9 |
| | $ | 17.3 |
| | $ | (10.1 | ) | | 7.2 |
| | $ | 2.3 |
| | $ | 68.4 |
| | $ | 0.1 |
| | $ | 70.8 |
| | $ | (28.2 | ) | | 42.6 |
|
| Current derivative instruments | | | | | | | | | | | | $ | 7.2 |
| | | | | | | | | | | | $ | 42.6 |
|
| Noncurrent derivative assets | | | | | | | | | | | | | | | | | | | | | | | | |
| Other derivative instruments: | | | | | | | | | | | | | | | | | | | | | | | | |
| Commodity trading | | $ | 0.4 |
| | $ | 8.1 |
| | $ | 1.1 |
| | $ | 9.6 |
| | $ | (9.6 | ) | | $ | — |
| | $ | — |
| | $ | 1.6 |
| | $ | — |
| | $ | 1.6 |
| | $ | (0.4 | ) | | $ | 1.2 |
|
| Total noncurrent derivative assets | | $ | 0.4 |
| | $ | 8.1 |
| | $ | 1.1 |
| | $ | 9.6 |
| | $ | (9.6 | ) | | — |
| | $ | — |
| | $ | 1.6 |
| | $ | — |
| | $ | 1.6 |
| | $ | (0.4 | ) | | 1.2 |
|
| Noncurrent derivative instruments | | | | | | | | | | | | $ | — |
| | | | | | | | | | | | $ | 1.2 |
|
| Current derivative liabilities | | | | | | | | | | | | | | | | | | | | | | | | |
| Other derivative instruments: | | | | | | | | | | | | | | | | | | | | | | | | |
| Commodity trading | | $ | 1.7 |
| | $ | 16.7 |
| | $ | — |
| | $ | 18.4 |
| | $ | (13.1 | ) | | $ | 5.3 |
| | $ | 2.4 |
| | $ | 64.2 |
| | $ | — |
| | $ | 66.6 |
| | $ | (34.7 | ) | | $ | 31.9 |
|
| Natural gas commodity | | — |
| | 3.4 |
| | — |
| | 3.4 |
| | — |
| | 3.4 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Total current derivative liabilities | | $ | 1.7 |
| | $ | 20.1 |
| | $ | — |
| | $ | 21.8 |
| | $ | (13.1 | ) | | 8.7 |
| | $ | 2.4 |
| | $ | 64.2 |
| | $ | — |
| | $ | 66.6 |
| | $ | (34.7 | ) | | 31.9 |
|
PPAs (b) | | | | | | | | | | | | — |
| | | | | | | | | | | | 2.7 |
|
| Current derivative instruments | | | | | | | | | | | | $ | 8.7 |
| | | | | | | | | | | | $ | 34.6 |
|
| Noncurrent derivative liabilities | | | | | | | | | | | | | | | | | | | | | | | | |
| Other derivative instruments: | | | | | | | | | | | | | | | | | | | | | | | | |
| Commodity trading | | $ | 0.4 |
| | $ | 47.0 |
| | $ | 14.7 |
| | $ | 62.1 |
| | $ | (9.6 | ) | | $ | 52.5 |
| | $ | — |
| | $ | 1.1 |
| | $ | — |
| | $ | 1.1 |
| | $ | (0.5 | ) | | $ | 0.6 |
|
| Total noncurrent derivative liabilities | | $ | 0.4 |
| | $ | 47.0 |
| | $ | 14.7 |
| | $ | 62.1 |
| | $ | (9.6 | ) | | 52.5 |
| | $ | — |
| | $ | 1.1 |
| | $ | — |
| | $ | 1.1 |
| | $ | (0.5 | ) | | 0.6 |
|
| Noncurrent derivative instruments | | | | | | | | | | | | $ | 52.5 |
| | | | | | | | | | | | $ | 0.6 |
|
| |
(a) | PSCo nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2019 and 2018. At both Dec. 31, 2019 and 2018, derivative assets and liabilities include 0 obligations to return cash collateral. At Dec. 31, 2019 and 2018, derivative assets and liabilities include the rights to reclaim cash collateral of $3.0 million and $6.5 million, respectively. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. |
| |
(b) | During 2006, PSCo qualified these contracts under the normal purchase exception. Based onthis qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. |
There were $10.9 million of losses, $0.1 million of gains and immaterial gains recognized in earnings for the years ended Dec. 31, 2019, 2018 and 2017, respectively, for Level 3 commodity trading derivatives.
PSCo recognizes transfers between levels as of the beginning of each period. There were 0 transfers of amounts between levels for derivative instruments for the years ended Dec. 31, 2019, 2018 and 2017.
Fair Value of Long-Term Debt
As of Dec. 31, other financial instruments for which the carrying amount did not equal fair value:
|
| | | | | | | | | | | | | | | | |
| | | 2019 | | 2018 |
| (Millions of Dollars) | | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value |
| Long-term debt, including current portion | | $ | 5,384.7 |
| | $ | 6,039.3 |
| | $ | 4,997.6 |
| | $ | 5,123.2 |
|
Fair value of PSCo’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. Fair value estimates are based on information available to management as of Dec. 31, 2019 and 2018, and given the observability of the inputs, fair values presented for long-term debt were assigned as Level 2.
|
|
| 9. Benefit Plans and Other Postretirement Benefits |
Pension and Postretirement Health Care Benefits
Xcel Energy, which includes PSCo, has several noncontributory, defined benefit pension plans that cover almost all employees. Generally, benefits are based on a combination of years of service, the employee’s average pay and, in some cases, social security benefits. Xcel Energy Inc.’s and PSCo’s policy is to fully fund into an external trust the actuarially determined pension costs recognized for ratemaking and financial reporting purposes, subject to the limitations of applicable employee benefit and tax laws.
In addition to the qualified pension plans, Xcel Energy maintains a supplemental executive retirement plan (SERP)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, 20162019 and 20152018 were $43.5$39 million and $41.8$33 million, respectively, of which $3.8$3 million and $3.6 million werewas attributable to PSCo. In 2016 and 2015,PSCo in both years. Xcel Energy recognized net benefit cost for financial reporting for the SERP and nonqualified plans of $7.9$4 million in 2019 and $9.5 million,2018, respectively, of which $0.6$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 includedasset classes in thetheir pension asset portfolio and postretirement health care portfolios. For pension assets, Xcel Energy Inc. and PSCo consider the historical returns achieved by the asset portfolio over the past 20-year20-years or longer period, as well as the long-term return levels projected and recommended by investment experts. Xcel Energy Inc. and PSCo continually review pension assumptions. The pension
Pension cost determination assumes a forecasted mix of investment types over the long term.
Investment returns in 2019 were above the assumed level of 6.84%;
Investment returns in 20162018 were below the assumed level of 6.84 percent;6.84%;
Investment returns in 2015 were below the assumed level of 6.81 percent;
Investment returns in 20142017 were above the assumed level of 6.81 percent;6.84%; and
In 2017,2020, PSCo’s expected investment-return assumption is 6.62 percent.6.84%.
ThePension plan and postretirement benefit assets are invested in a portfolio according to Xcel Energy Inc.’s and PSCo’s return, liquidity and diversification objectives to provide a source of funding for plan obligations and minimize the necessity of contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the projectedasset allocation of assets to selected asset classes, 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 pensionthe assets in any year.
The following table presentsState agencies also have issued guidelines to the target pension asset allocations forfunding of postretirement benefit costs. PSCo at Dec. 31is 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 upcoming year:
|
| | | | | | |
| | | 2016 | | 2015 |
| Domestic and international equity securities | | 36 | % | | 36 | % |
| Long-duration fixed income and interest rate swap securities | | 31 |
| | 32 |
|
| Short-to-intermediate fixed income securities | | 15 |
| | 12 |
|
| Alternative investments | | 16 |
| | 18 |
|
| Cash | | 2 |
| | 2 |
|
| Total | | 100 | % | | 100 | % |
pension plan.
The ongoing investment strategy is based on plan-specific investment recommendations that seek to minimize potential investment and interest rate risk as a plan’s funded status increases over time. The investment recommendations result in a greater percentage of long-duration fixed income securities being allocated to specific plans having relatively higher funded status ratios and a greater percentage of growth assets being allocated to plans having relatively lower funded status ratios. 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, forFor each of the fair value hierarchy levels, PSCo’s pension plan assets that are measured at fair value as of Dec. 31, 2016 and 2015:value:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Dec. 31, 2019 (a) | | Dec. 31, 2018 (a) |
| (Millions of Dollars) | | Level 1 | | Level 2 | | Level 3 | | Measured at NAV | | Total | | Level 1 | | Level 2 | | Level 3 | | Measured at NAV | | Total |
| Cash equivalents | | $ | 45.6 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 45.6 |
| | $ | 53.0 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 53.0 |
|
| Commingled funds | | 497.0 |
| | — |
| | — |
| | 355.3 |
| | 852.3 |
| | 316.2 |
| | — |
| | — |
| | 326.1 |
| | 642.3 |
|
| Debt securities | | — |
| | 241.2 |
| | 1.5 |
| | — |
| | 242.7 |
| | — |
| | 242.3 |
| | — |
| | — |
| | 242.3 |
|
| Equity securities | | 29.7 |
| | — |
| | — |
| | — |
| | 29.7 |
| | 35.2 |
| | — |
| | — |
| | — |
| | 35.2 |
|
| Other | | (41.3 | ) | | 1.7 |
| | — |
| | (6.9 | ) | | (46.5 | ) | | 0.6 |
| | 2.0 |
| | — |
| | (9.9 | ) | | (7.3 | ) |
| Total | | $ | 531.0 |
| | $ | 242.9 |
| | $ | 1.5 |
| | $ | 348.4 |
| | $ | 1,123.8 |
| | $ | 405.0 |
| | $ | 244.3 |
| | $ | — |
| | $ | 316.2 |
| | $ | 965.5 |
|
|
| | | | | | | | | | | | | | | | | | | | |
| | | Dec. 31, 2016 |
| (Thousands of Dollars) | | Level 1 | | Level 2 | | Level 3 | | Investments Measured at NAV (a) | | Total |
| Cash equivalents | | $ | 34,957 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 34,957 |
|
| Commingled funds: | | | | | | | | | | |
| U.S. equity funds | | — |
| | — |
| | — |
| | 165,621 |
| | 165,621 |
|
| Non U.S. equity funds | | — |
| | — |
| | — |
| | 122,197 |
| | 122,197 |
|
| U.S. corporate bond funds | | — |
| | — |
| | — |
| | 96,995 |
| | 96,995 |
|
| Emerging market equity funds | | — |
| | — |
| | — |
| | 64,784 |
| | 64,784 |
|
| Emerging market debt funds | | — |
| | — |
| | — |
| | 53,703 |
| | 53,703 |
|
| Commodity funds | | — |
| | — |
| | — |
| | 7,497 |
| | 7,497 |
|
| Private equity investments | | — |
| | — |
| | — |
| | 31,828 |
| | 31,828 |
|
| Real estate | | — |
| | — |
| | — |
| | 61,048 |
| | 61,048 |
|
| Other commingled funds | | — |
| | — |
| | — |
| | 74,696 |
| | 74,696 |
|
| Debt securities: | | | | | | | | | | |
| Government securities | | — |
| | 168,014 |
| | — |
| | — |
| | 168,014 |
|
| U.S. corporate bonds | | — |
| | 86,081 |
| | — |
| | — |
| | 86,081 |
|
| Non U.S. corporate bonds | | — |
| | 13,828 |
| | — |
| | — |
| | 13,828 |
|
| Mortgage-backed securities | | — |
| | 2,179 |
| | — |
| | — |
| | 2,179 |
|
| Asset-backed securities | | — |
| | 1,032 |
| | — |
| | — |
| | 1,032 |
|
| Equity securities: | | | | | | | | | | |
| U.S. equities | | 27,348 |
| | — |
| | — |
| | — |
| | 27,348 |
|
| Other | | — |
| | (7,595 | ) | | — |
| | — |
| | (7,595 | ) |
| Total | | $ | 62,305 |
| | $ | 263,539 |
| | $ | — |
| | $ | 678,369 |
| | $ | 1,004,213 |
|
| |
(a) | Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 28 for further information on the adoption of ASU No. 2015-07.fair value measurement inputs and methods. |
For each of the fair value hierarchy levels, PSCo’s proportionate allocation of the total postretirement benefit plan assets that were measured at fair value:
|
| | | | | | | | | | | | | | | | | | | | |
| | | Dec. 31, 2015 |
| (Thousands of Dollars) | | Level 1 | | Level 2 | | Level 3 | | Investments Measured at NAV (a) | | Total |
| Cash equivalents | | $ | 81,954 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 81,954 |
|
| Derivatives | | — |
| | 1,204 |
| | — |
| | — |
| | 1,204 |
|
| Commingled funds: | | | | | | | | | | |
| U.S. equity funds | | — |
| | — |
| | — |
| | 125,011 |
| | 125,011 |
|
| Non U.S. equity funds | | — |
| | — |
| | — |
| | 119,394 |
| | 119,394 |
|
| U.S. corporate bond funds | | — |
| | — |
| | — |
| | 82,827 |
| | 82,827 |
|
| Emerging market equity funds | | — |
| | — |
| | — |
| | 56,525 |
| | 56,525 |
|
| Emerging market debt funds | | — |
| | — |
| | — |
| | 54,362 |
| | 54,362 |
|
| Commodity funds | | — |
| | — |
| | — |
| | 14,169 |
| | 14,169 |
|
| Private equity investments | | — |
| | — |
| | — |
| | 34,353 |
| | 34,353 |
|
| Real estate | | — |
| | — |
| | — |
| | 67,075 |
| | 67,075 |
|
| Other commingled funds | | — |
| | — |
| | — |
| | 72,327 |
| | 72,327 |
|
| Debt securities: | | | | | | | | | | |
| Government securities | | — |
| | 214,341 |
| | — |
| | — |
| | 214,341 |
|
| U.S. corporate bonds | | — |
| | 74,787 |
| | — |
| | — |
| | 74,787 |
|
| Non U.S. corporate bonds | | — |
| | 12,127 |
| | — |
| | — |
| | 12,127 |
|
| Asset-backed securities | | — |
| | 881 |
| | — |
| | — |
| | 881 |
|
| Equity securities: | | | | | | | | | | |
| U.S. equities | | 28,797 |
| | — |
| | — |
| | — |
| | 28,797 |
|
| Other | | — |
| | (3,453 | ) | | — |
| | — |
| | (3,453 | ) |
| Total | | $ | 110,751 |
| | $ | 299,887 |
| | $ | — |
| | $ | 626,043 |
| | $ | 1,036,681 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Dec. 31, 2019 (a) | | Dec. 31, 2018 (a) |
| (Millions of Dollars) | | Level 1 | | Level 2 | | Level 3 | | Measured at NAV | | Total | | Level 1 | | Level 2 | | Level 3 | | Measured at NAV | | Total |
| Cash equivalents | | $ | 20.3 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 20.3 |
| | $ | 17.0 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 17.0 |
|
| Insurance contracts | | — |
| | 45.4 |
| | — |
| | — |
| | 45.4 |
| | — |
| | 40.2 |
| | — |
| | — |
| | 40.2 |
|
| Commingled funds | | 61.9 |
| | — |
| | — |
| | 68.0 |
| | 129.9 |
| | 118.7 |
| | — |
| | — |
| | 35.8 |
| | 154.5 |
|
| Debt securities | | — |
| | 203.4 |
| | 1.0 |
| | — |
| | 204.4 |
| | — |
| | 159.7 |
| | — |
| | — |
| | 159.7 |
|
| Equity securities | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Other | | — |
| | 0.5 |
| | — |
| | — |
| | 0.5 |
| | — |
| | 0.7 |
| | — |
| | — |
| | 0.7 |
|
| Total | | $ | 82.2 |
| | $ | 249.3 |
| | $ | 1.0 |
| | $ | 68.0 |
| | $ | 400.5 |
| | $ | 135.7 |
| | $ | 200.6 |
| | $ | — |
| | $ | 35.8 |
| | $ | 372.1 |
|
| |
(a) | Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 28 for further information on the adoption of ASU No. 2015-07.fair value measurement inputs and methods. |
ThereImmaterial assets were no assets transferred in or out of Level 3 for the years ended Dec. 31, 2016, 20152019. No assets were transferred in or 2014.out of Level 3 for 2018.
Benefit ObligationsFunded Status — A comparisonComparisons of the actuarially computed pension benefit obligation, andchanges in plan assets and funded status of the pension and postretirement health care plans for PSCoXcel Energy are as follows:
|
| | | | | | | | | | | | | | | | |
| | | Pension Benefits | | Postretirement Benefits |
| (Millions of Dollars) | | 2019 | | 2018 | | 2019 | | 2018 |
| Change in Benefit Obligation: | | | | | | | | |
| Obligation at Jan. 1 | | $ | 1,229.3 |
| | $ | 1,334.2 |
| | $ | 376.5 |
| | $ | 429.2 |
|
| Service cost | | 25.6 |
| | 29.0 |
| | 0.5 |
| | 0.7 |
|
| Interest cost | | 51.6 |
| | 47.3 |
| | 15.6 |
| | 15.0 |
|
| Plan amendments | | — |
| | — |
| | — |
| | — |
|
| Actuarial loss (gain) | | 108.2 |
| | (96.5 | ) | | 12.7 |
| | (40.6 | ) |
| Plan participants’ contributions | | — |
| | — |
| | 6.6 |
| | 6.5 |
|
| Medicare subsidy reimbursements | | — |
| | — |
| | 1.6 |
| | 0.9 |
|
| Benefit payments | | (84.9 | ) | | (84.7 | ) | | (33.5 | ) | | (35.2 | ) |
| Obligation at Dec. 31 | | $ | 1,329.8 |
| | $ | 1,229.3 |
| | $ | 380.0 |
| | $ | 376.5 |
|
| Change in Fair Value of Plan Assets: | | | | | | | | |
| Fair value of plan assets at Jan. 1 | | $ | 965.5 |
| | $ | 1,079.4 |
| | $ | 372.1 |
| | $ | 406.4 |
|
| Actual return on plan assets | | 197.4 |
| | (50.9 | ) | | 51.0 |
| | (11.1 | ) |
| Employer contributions | | 45.8 |
| | 21.7 |
| | 4.3 |
| | 5.5 |
|
| Plan participants’ contributions | | — |
| | — |
| | 6.6 |
| | 6.5 |
|
| Benefit payments | | (84.9 | ) | | (84.7 | ) | | (33.5 | ) | | (35.2 | ) |
| Fair value of plan assets at Dec. 31 | | $ | 1,123.8 |
| | $ | 965.5 |
| | $ | 400.5 |
| | $ | 372.1 |
|
| Funded status of plans at Dec. 31 | | $ | (206.0 | ) | | $ | (263.8 | ) | | $ | 20.5 |
| | $ | (4.4 | ) |
| Amounts recognized in the Consolidated Balance Sheet at Dec. 31: | | | | | | | | |
| Noncurrent liabilities | | (206.0 | ) | | (263.8 | ) | | 20.5 |
| | (4.4 | ) |
| Net amounts recognized | | $ | (206.0 | ) | | $ | (263.8 | ) | | $ | 20.5 |
| | $ | (4.4 | ) |
| Significant Assumptions Used to Measure Benefit Obligations: | | | | | | | | |
| Discount rate for year-end valuation | | 3.49 | % | | 4.31 | % | | 3.47 | % | | 4.32 | % |
| Expected average long-term increase in compensation level | | 3.75 |
| | 3.75 |
| | N/A |
| | N/A |
|
| Mortality table | | Pri-2012 |
| | RP-2014 |
| | Pri-2012 |
| | RP-2014 |
|
Health care costs trend rate — initial: Pre-65 | | N/A |
| | N/A |
| | 6.00 | % | | 6.50 | % |
Health care costs trend rate — initial: Post-65 | | N/A |
| | N/A |
| | 5.10 | % | | 5.30 | % |
Ultimate trend assumption — initial: Pre-65 | | N/A |
| | N/A |
| | 4.50 | % | | 4.50 | % |
Ultimate trend assumption — initial: Post-65 | | N/A |
| | N/A |
| | 4.50 | % | | 4.50 | % |
| Years until ultimate trend is reached | | N/A |
| | N/A |
| | 3 |
| | 4 |
|
Accumulated benefit obligation for the pension plan was $1,267.2 million and $1,183.3 million as of Dec. 31, 2019 and 2018, respectively.
Net Periodic Benefit Cost (Credit) — Net periodic benefit cost (credit) other than the service cost component is presentedincluded in other income in the following table:consolidated statement of income.
Components of net periodic benefit cost (credit) and the amounts recognized in other comprehensive income and regulatory assets and liabilities:
|
| | | | | | | | |
| (Thousands of Dollars) | | 2016 | | 2015 |
| Accumulated Benefit Obligation at Dec. 31 | | $ | 1,213,890 |
| | $ | 1,192,798 |
|
| | | | | |
| Change in Projected Benefit Obligation: | | | | |
| Obligation at Jan. 1 | | $ | 1,224,650 |
| | $ | 1,277,957 |
|
| Service cost | | 25,926 |
| | 28,260 |
|
| Interest cost | | 55,405 |
| | 50,857 |
|
| Transfer to other plan | | (9,149 | ) | | (2,938 | ) |
| Plan amendments | | 206 |
| | — |
|
| Actuarial loss (gain) | | 51,779 |
| | (54,737 | ) |
| Benefit payments | | (96,995 | ) | | (74,749 | ) |
| Obligation at Dec. 31 | | $ | 1,251,822 |
| | $ | 1,224,650 |
|
|
| | | | | | | | |
| (Thousands of Dollars) | | 2016 | | 2015 |
| Change in Fair Value of Plan Assets: | | | | |
| Fair value of plan assets at Jan. 1 | | $ | 1,036,681 |
| | $ | 1,103,865 |
|
| Actual return (loss) on plan assets | | 56,762 |
| | (9,122 | ) |
| Employer contributions | | 16,829 |
| | 20,056 |
|
| Transfer to other plan | | (9,064 | ) | | (3,369 | ) |
| Benefit payments | | (96,995 | ) | | (74,749 | ) |
| Fair value of plan assets at Dec. 31 | | $ | 1,004,213 |
| | $ | 1,036,681 |
|
|
| | | | | | | | |
| (Thousands of Dollars) | | 2016 | | 2015 |
| Funded Status of Plans at Dec. 31: | | | | |
Funded status (a) | | $ | (247,609 | ) | | $ | (187,969 | ) |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Pension Benefits | | Postretirement Benefits |
| (Millions of Dollars) | | 2019 | | 2018 | | 2017 | | 2019 | | 2018 | | 2017 |
| Service cost | | $ | 25.6 |
| | $ | 29.0 |
| | $ | 27.3 |
| | $ | 0.5 |
| | $ | 0.7 |
| | $ | 0.7 |
|
| Interest cost | | 51.6 |
| | 47.3 |
| | 50.6 |
| | 15.6 |
| | 15.0 |
| | 16.8 |
|
| Expected return on plan assets | | (68.5 | ) | | (68.5 | ) | | (68.5 | ) | | (18.9 | ) | | (22.7 | ) | | (21.9 | ) |
| Amortization of prior service credit | | (3.4 | ) | | (3.4 | ) | | (3.2 | ) | | (5.4 | ) | | (6.2 | ) | | (6.2 | ) |
| Amortization of net loss | | 25.4 |
| | 31.2 |
| | 28.3 |
| | 2.9 |
| | 4.0 |
| | 3.8 |
|
Settlement charge (a) | | 3.2 |
| | 4.5 |
| | — |
| | — |
| | — |
| | — |
|
| Net periodic pension cost (credit) | | 33.9 |
| | 40.1 |
| | 34.5 |
| | (5.3 | ) | | (9.2 | ) | | (6.8 | ) |
| Costs (credits) not recognized due to effects of regulation | | 3.5 |
| | (3.9 | ) | | (2.7 | ) | | 1.2 |
| | 1.8 |
| | — |
|
| Net benefit cost (credit) recognized for financial reporting | | $ | 37.4 |
| | $ | 36.2 |
| | $ | 31.8 |
| | $ | (4.1 | ) | | $ | (7.4 | ) | | $ | (6.8 | ) |
| Significant Assumptions Used to Measure Costs: | | | | | | | | | | | | |
| Discount rate | | 4.31 | % | | 3.63 | % | | 4.13 | % | | 4.32 | % | | 3.62 | % | | 4.13 | % |
| Expected average long-term increase in compensation level | | 3.75 |
| | 3.75 |
| | 3.75 |
| | N/A |
| | N/A |
| | N/A |
|
| Expected average long-term rate of return on assets | | 6.84 |
| | 6.84 |
| | 6.84 |
| | 4.50 |
| | 5.30 |
| | 5.80 |
|
| |
(a) | Amounts are recognizedA settlement charge is required when the amount of all lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In 2019 and 2018, as a result of lump-sum distributions during the 2019 and 2018 plan years, PSCo recorded a total pension settlement charge of $3.2 million and $4.5 million in noncurrent liabilities on PSCo’s consolidated balance sheets.2019 and 2018. A total of $0.1 million and $0.2 million of that amount was recorded in the income statement in 2019 and 2018, respectively. |
|
| | | | | | | | |
| (Thousands of Dollars) | | 2016 | | 2015 |
| Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: | | | | |
| Net loss | | $ | 554,999 |
| | $ | 521,703 |
|
| Prior service credit | | (12,155 | ) | | (15,572 | ) |
| Total | | $ | 542,844 |
| | $ | 506,131 |
|
| | | (Thousands of Dollars) | | 2016 | | 2015 | |
| | | | Pension Benefits | | Postretirement Benefits |
| (Millions of Dollars) | | | 2019 | | 2018 | | 2019 | | 2018 |
| Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: | | | | | | | | | |
| Net loss | | | $ | 481.5 |
| | $ | 530.8 |
| | $ | 44.6 |
| | $ | 66.9 |
|
| Prior service credit | | | (3.8 | ) | | (7.2 | ) | | (9.9 | ) | | (15.3 | ) |
| Total | | | $ | 477.7 |
| | $ | 523.6 |
| | $ | 34.7 |
| | $ | 51.6 |
|
| Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates: | | | | | | | | | | | | |
| Current regulatory assets | | $ | 515,708 |
| | $ | 28,852 |
| | $ | 22.3 |
| | $ | 25.8 |
| |
| | $ | — |
|
| Noncurrent regulatory assets | | 26,853 |
| | 477,279 |
| | 452.1 |
| | 497.5 |
| | 34.7 |
| | 51.6 |
|
| Deferred income taxes | | 108 |
| | — |
| | 0.8 |
| | 0.1 |
| | — |
| | — |
|
| Net-of-tax accumulated OCI | | 175 |
| | — |
| |
| Net-of-tax accumulated other comprehensive income | | | 2.5 |
| | 0.2 |
| | — |
| | — |
|
| Total | | $ | 542,844 |
| | $ | 506,131 |
| | $ | 477.7 |
| | $ | 523.6 |
| | $ | 34.7 |
| | $ | 51.6 |
|
|
| | | | | | | | |
| Measurement date | | Dec. 31, 20162019 | | Dec. 31, 20152018 | | Dec. 31, 2019 | | Dec. 31, 2018 |
|
| | | | | | |
| | | 2016 | | 2015 |
| Significant Assumptions Used to Measure Benefit Obligations: | | | | |
| Discount rate for year-end valuation | | 4.13 | % | | 4.66 | % |
| Expected average long-term increase in compensation level | | 3.75 |
| | 4.00 |
|
| Mortality table | | RP-2014 |
| | RP-2014 |
|
Mortality — In 2014, the Society of Actuaries published a new mortality table (RP-2014) and projection scale (MP-2014) that increased the overall life expectancy of males and females. On Dec. 31, 2014 PSCo adopted the RP-2014 table, with modifications, based on its population and specific experience and a modified MP-2014 projection scale. During 2016, a new projection table was released (MP-2016). In 2016, PSCo adopted a modified version of the MP-2016 table and will continue to utilize the RP-2014 base table, modified for company experience.
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 2014 through 2017 - 2020 to meet minimum funding requirements.
Total voluntary and required pension funding contributions across all four4 of Xcel Energy’s pension plans were as follows:
$150.0150 million in January 2017,2020, of which $16.8$50 million was attributable to PSCo;
$125.2154 million in 2016,2019, of which $16.8$46 million was attributable to PSCo;
$90.1150 million in 2015,2018, of which $20.1$22 million was attributable to PSCo; and
$130.6162 million in 2014,2017, of which $35.2$18 million was attributable to PSCo.
The postretirement health care plans have no funding requirements other than fulfilling benefit payment obligations, when claims are presented and approved. Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities.
For future years, Xcel Energy andexpects to contribute approximately $10 million during 2020, of which amounts attributable to PSCo anticipate contributions will be made0.
Xcel Energy, which includes PSCo, contributed:
$15 million during 2019, of which $4 million was attributable to PSCo;
$11 million during 2018, of which $5 million was attributable to PSCo; and
$20 million during 2017, of which $5 million was attributable to PSCo.
Targeted asset allocations:
|
| | | | | | | | | | | | |
| | | Pension Benefits | | Postretirement Benefits |
| | | 2019 | | 2018 | | 2019 | | 2018 |
| Domestic and international equity securities | | 37 | % | | 35 | % | | 15 | % | | 18 | % |
| Long-duration fixed income securities | | 30 |
| | 32 |
| | — |
| | — |
|
| Short-to-intermediate fixed income securities | | 14 |
| | 16 |
| | 72 |
| | 70 |
|
| Alternative investments | | 17 |
| | 15 |
| | 9 |
| | 8 |
|
| Cash | | 2 |
| | 2 |
| | 4 |
| | 4 |
|
| Total | | 100 | % | | 100 | % | | 100 | % | | 100 | % |
Plan Amendments — The Xcel Energy Pension Plan and Xcel Energy Inc. Nonbargaining Pension Plan (South), which includes PSCo, were amended in 2017 to reduce supplemental benefits for non-bargaining participants as necessary.well as to allow the transfer of a portion of non-qualified pension obligations into the qualified plans.
Plan Amendments — The 2016 increase in the projected benefit obligation resulted from an increase in the annual credits contributed toIn 2018, the PSCo Bargaining Plan retirement spending account. postretirement plan was amended to add the 5% cash balance formula.
In 2015,2019, there were no plan amendments made which affected the projected benefit obligation.
Projected Benefit Payments
Benefit Costs —The components of PSCo’s net periodic pension cost were:projected benefit payments:
|
| | | | | | | | | | | | | | | | |
| (Millions of Dollars) | | Projected Pension
Benefit Payments | | Gross Projected
Postretirement
Health Care
Benefit Payments | | Expected Medicare
Part D Subsidies | | Net Projected
Postretirement
Health Care
Benefit Payments |
| 2020 | | $ | 82.0 |
| | $ | 30.5 |
| | $ | 1.9 |
| | $ | 28.6 |
|
| 2021 | | 81.9 |
| | 30.3 |
| | 2.0 |
| | 28.3 |
|
| 2022 | | 82.3 |
| | 29.8 |
| | 2.1 |
| | 27.7 |
|
| 2023 | | 82.7 |
| | 29.4 |
| | 2.2 |
| | 27.2 |
|
| 2024 | | 82.4 |
| | 28.8 |
| | 2.2 |
| | 26.6 |
|
| 2025-2029 | | 402.9 |
| | 129.9 |
| | 12.1 |
| | 117.8 |
|
|
| | | | | | | | | | | | |
| (Thousands of Dollars) | | 2016 | | 2015 | | 2014 |
| Service cost | | $ | 25,926 |
| | $ | 28,260 |
| | $ | 23,939 |
|
| Interest cost | | 55,405 |
| | 50,857 |
| | 53,277 |
|
| Expected return on plan assets | | (70,769 | ) | | (72,590 | ) | | (70,709 | ) |
| Amortization of prior service credit | | (3,211 | ) | | (3,136 | ) | | (3,092 | ) |
| Amortization of net loss | | 26,771 |
| | 36,377 |
| | 33,892 |
|
| Net periodic pension cost | | 34,122 |
| | 39,768 |
| | 37,307 |
|
| Credits (costs) not recognized due to effects of regulation | | 3,364 |
| | (1,464 | ) | | — |
|
| Net benefit cost recognized for financial reporting | | $ | 37,486 |
| | $ | 38,304 |
| | $ | 37,307 |
|
|
| | | | | | | | | |
| | | 2016 | | 2015 | | 2014 |
| Significant Assumptions Used to Measure Costs: | | | | | | |
| Discount rate | | 4.66 | % | | 4.11 | % | | 4.75 | % |
| Expected average long-term increase in compensation level | | 4.00 |
| | 3.75 |
| | 3.75 |
|
| Expected average long-term rate of return on assets | | 6.84 |
| | 6.81 |
| | 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 $9.4 million, $9.9 million and $9.4 million in 2016, 2015 and 2014, 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 2017 pension cost calculations is 6.62 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 PlansDerivative Instruments Fair Value Measurements
PSCo enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to manage risk in connection with changes in interest rates, utility commodity prices and vehicle fuel prices.
Interest Rate Derivatives — PSCo enters into various instruments that effectively fix the interest payments on certain floating rate debt obligations or effectively fix the yield or price on a specified benchmark interest rate for an anticipated debt issuance for a specific period. These derivative instruments are generally designated as cash flow hedges for accounting purposes.
As of Dec. 31, 2019, accumulated other comprehensive losses related to interest rate derivatives included $1.2 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for unsettled hedges, as applicable.
Wholesale and Commodity Trading Risk — PSCo conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. PSCo is allowed to conduct these activities within guidelines and limitations as approved by its risk management committee, comprised of management personnel not directly involved in activities governed by this policy.
Commodity Derivatives — PSCo enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric and natural gas operations, as well as for trading purposes. This could include the purchase or sale of energy or energy-related products, natural gas to generate electric energy, natural gas for resale, and vehicle fuel.
PSCo enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but may not be designated as qualifying hedging transactions. Changes in the fair value of non-trading commodity derivative instruments are recorded in other comprehensive income or deferred as a regulatory asset or liability. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. NaN amounts related to the ineffectiveness of cash flow hedges were recorded for the years ended Dec. 31, 2019 and 2018.
As of Dec. 31, 2019, there were 0 net gains related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses or related amounts expected to be reclassified into earnings during the next 12 months.
PSCo enters into commodity derivative instruments for trading purposes not directly related to commodity price risks associated with serving its electric and natural gas customers. Changes in the fair value of these commodity derivatives are recorded in electric operating revenues, net of amounts credited to customers under margin-sharing mechanisms.
Gross notional amounts of commodity forwards and options at Dec. 31:
|
| | | | | | |
(Amounts in Millions) (a)(b) | | 2019 | | 2018 |
| MWh of electricity | | 9.3 |
| | 24.4 |
|
| MMBtu of natural gas | | 32.2 |
| | 48.4 |
|
| |
(a) | Amounts are not reflective of net positions in the underlying commodities. |
| |
(b) | Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise. |
Consideration of Credit Risk and Concentrations — PSCo continuously monitors the creditworthiness of the counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. The impact of credit risk was immaterial to the fair value of unsettled commodity derivatives presented in the consolidated balance sheets.
PSCo’s most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to its wholesale, trading and non-trading commodity activities. At Dec. 31, 2019, 5 of PSCo’s 10 most significant counterparties for these activities, comprising $110.1 million or 78% of this credit exposure, had investment grade credit ratings from Standard & Poor’s, Moody’s or Fitch Ratings. NaN of the 10 most significant counterparties, comprising $15.7 million or 11% of this credit exposure, were not rated by these external agencies, but based on PSCo’s internal analysis, had credit quality consistent with investment grade. NaN of these significant counterparties are municipal or cooperative electric entities, ISOs or other utilities.
Xcel Energy, which includes Qualifying Cash Flow Hedges — Financial impact of qualifying interest rate and vehicle fuel cash flow hedges on PSCo’s accumulated other comprehensive loss, included in the consolidated statements of common stockholder’s equity and in the consolidated statements of comprehensive income:
|
| | | | | | | | | | | | |
| (Millions of Dollars) | | 2019 | | 2018 | | 2017 |
| Accumulated other comprehensive loss related to cash flow hedges at Jan. 1 | | $ | (25.3 | ) | | $ | (26.5 | ) | | $ | (22.8 | ) |
| After-tax net realized losses on derivative transactions reclassified into earnings | | 1.2 |
| | 1.2 |
| | 1.0 |
|
Adoption of ASU No. 2018-02 (a) | | — |
| | — |
| | (4.7 | ) |
| Accumulated other comprehensive loss related to cash flow hedges at Dec. 31 | | $ | (24.1 | ) | | $ | (25.3 | ) | | $ | (26.5 | ) |
| |
(a) | In 2017, PSCo implemented ASU No. 2018-02 related to TCJA, which resulted in reclassification of certain credit balances within net accumulated other comprehensive loss to retained earnings. |
Impact of derivative activity:
|
| | | | | | | | |
| | | Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: |
| (Millions of Dollars) | | Accumulated Other
Comprehensive Loss | | Regulatory (Assets) and Liabilities |
| Year to date Dec. 31, 2019 | | | | |
| Other derivative instruments | | | | |
| Natural gas commodity | | $ | — |
| | $ | (5.3 | ) |
| Total | | $ | — |
| | $ | (5.3 | ) |
| | | | | |
| Year to date Dec. 31, 2018 | | | | |
| Other derivative instruments | | | | |
| Natural gas commodity | | $ | — |
| | $ | 8.0 |
|
| Total | | $ | — |
| | $ | 8.0 |
|
| | | | | |
| Year to date Dec. 31, 2017 | | | | |
| Other derivative instruments | | | | |
| Natural gas commodity | | $ | — |
| | $ | (10.9 | ) |
| Total | | $ | — |
| | $ | (10.9 | ) |
|
| | | | | | | | | | | | | |
| | | Pre-Tax (Gains) Losses
Reclassified into Income
During the Period from: | | | |
| (Millions of Dollars) | | Accumulated
Other
Comprehensive Loss | | Regulatory
Assets and (Liabilities) | | Pre-Tax Gains (Losses) Recognized
During the Period
in Income | |
| Year to date Dec. 31, 2019 | | | | | | | |
| Derivatives designated as cash flow hedges | | | | | | | |
| Interest rate | | $ | 1.6 |
| (a) | $ | — |
| | $ | — |
| |
| Total | | $ | 1.6 |
| | $ | — |
| | $ | — |
| |
| Other derivative instruments | | . |
| | | | | |
| Commodity trading | | $ | — |
| | $ | — |
| | $ | 3.1 |
| (c) |
| Natural gas commodity | | — |
| | 0.6 |
| (d) | (3.9 | ) | (d) |
| Total | | $ | — |
| | $ | 0.6 |
| | $ | (0.8 | ) | |
| | | | | | | | |
| Year to date Dec. 31, 2018 | | | | | | | |
| Derivatives designated as cash flow hedges | | | | | | | |
| Interest rate | | $ | 1.6 |
| (a) | $ | — |
| | $ | — |
| |
| Total | | $ | 1.6 |
| | $ | — |
| | $ | — |
| |
| Other derivative instruments | | | | | | | |
| Commodity trading | | $ | — |
| | $ | — |
| | $ | 3.1 |
| (c) |
| Natural gas commodity | | — |
| | (4.1 | ) | (d) | (2.9 | ) | (d) |
| Total | | $ | — |
| | $ | (4.1 | ) | | $ | 0.2 |
| |
| | | | | | | | |
| Year to date Dec. 31, 2017 | | | | | | | |
| Derivatives designated as cash flow hedges | | | | | | | |
| Interest rate | | $ | 1.6 |
| (a) | $ | — |
| | $ | — |
| |
| Total | | $ | 1.6 |
| | $ | — |
| | $ | — |
| |
| Other derivative instruments | | | | | | | |
| Commodity trading | | $ | — |
| | $ | — |
| | $ | 0.4 |
| (c) |
| Natural gas commodity | | — |
| | 1.9 |
| (d) | (4.2 | ) | (d) |
| Total | | $ | — |
| | $ | 1.9 |
| | $ | (3.8 | ) | |
| |
(a) | Amounts are recorded to interest charges. |
| |
(b) | Amounts are recorded to O&M expenses. |
| |
(c) | Amounts are recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate. |
| |
(d) | Amounts for the year ended Dec. 31, 2019, 2018 and 2017 included 0 settlement gains or losses, $1.2 million of settlement losses and $0.4 million of settlement gains, respectively, on derivatives entered to mitigate natural gas price risk for electric generation recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset or liability, as appropriate. Remaining settlement losses for the years ended Dec. 31, 2019, 2018 and 2017 relate to natural gas operations and are recorded to cost of natural gas sold and transported. These losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset or liability, as appropriate. |
PSCo maintains 401(k)had 0 derivative instruments designated as fair value hedges during the years ended Dec. 31, 2019, 2018 and other defined contribution plans that cover substantially all employees. The expense to these plans for PSCo was approximately $9.9 million in 2016, $9.5 million in 2015 and $9.1 million in 2014.2017.
Credit Related Contingent Features— Contract provisions for derivative instruments that PSCo enters into, including those accounted for as normal purchase-normal sale contracts and therefore not reflected on the consolidated balance sheets, may require the posting of collateral or settlement of the contracts for various reasons, including if PSCo’s credit ratings are downgraded below its investment grade credit rating by any of the major credit rating agencies, or for cross-default contractual provisions if there was a failure under other financing arrangements related to payment terms or other covenants.
At Dec. 31, 2019 and 2018, there were 0 derivative instruments in a liability position with such underlying contract provisions.
Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that PSCo’s ability to fulfill its contractual obligations is reasonably expected to be impaired. PSCo had 0 collateral posted related to adequate assurance clauses in derivative contracts as of Dec. 31, 2019 and 2018.
Recurring Fair Value Measurements— The following table presents, for each of the fair value hierarchy levels, PSCo’s derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2019 and 2018: |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Dec. 31, 2019 | | Dec. 31, 2018 |
| | | Fair Value | | | | | | | | Fair Value | | | | | | |
| (Millions of Dollars) | | Level 1 | | Level 2 | | Level 3 | | Fair Value Total | | Netting (a) | | Total | | Level 1 | | Level 2 | | Level 3 | | Fair Value Total | | Netting (a) | | Total |
| Current derivative assets | | | | | | | | | | | | | | | | | | | | | | | | |
| Other derivative instruments: | | | | | | | | | | | | | | | | | | | | | | | | |
| Commodity trading | | $ | 1.9 |
| | $ | 11.1 |
| | $ | 0.9 |
| | $ | 13.9 |
| | $ | (10.1 | ) | | $ | 3.8 |
| | $ | 2.3 |
| | $ | 65.0 |
| | $ | 0.1 |
| | $ | 67.4 |
| | $ | (28.2 | ) | | $ | 39.2 |
|
| Natural gas commodity | | — |
| | 3.4 |
| | — |
| | 3.4 |
| | — |
| | 3.4 |
| | — |
| | 3.4 |
| | — |
| | 3.4 |
| | — |
| | 3.4 |
|
| Total current derivative assets | | $ | 1.9 |
| | $ | 14.5 |
| | $ | 0.9 |
| | $ | 17.3 |
| | $ | (10.1 | ) | | 7.2 |
| | $ | 2.3 |
| | $ | 68.4 |
| | $ | 0.1 |
| | $ | 70.8 |
| | $ | (28.2 | ) | | 42.6 |
|
| Current derivative instruments | | | | | | | | | | | | $ | 7.2 |
| | | | | | | | | | | | $ | 42.6 |
|
| Noncurrent derivative assets | | | | | | | | | | | | | | | | | | | | | | | | |
| Other derivative instruments: | | | | | | | | | | | | | | | | | | | | | | | | |
| Commodity trading | | $ | 0.4 |
| | $ | 8.1 |
| | $ | 1.1 |
| | $ | 9.6 |
| | $ | (9.6 | ) | | $ | — |
| | $ | — |
| | $ | 1.6 |
| | $ | — |
| | $ | 1.6 |
| | $ | (0.4 | ) | | $ | 1.2 |
|
| Total noncurrent derivative assets | | $ | 0.4 |
| | $ | 8.1 |
| | $ | 1.1 |
| | $ | 9.6 |
| | $ | (9.6 | ) | | — |
| | $ | — |
| | $ | 1.6 |
| | $ | — |
| | $ | 1.6 |
| | $ | (0.4 | ) | | 1.2 |
|
| Noncurrent derivative instruments | | | | | | | | | | | | $ | — |
| | | | | | | | | | | | $ | 1.2 |
|
| Current derivative liabilities | | | | | | | | | | | | | | | | | | | | | | | | |
| Other derivative instruments: | | | | | | | | | | | | | | | | | | | | | | | | |
| Commodity trading | | $ | 1.7 |
| | $ | 16.7 |
| | $ | — |
| | $ | 18.4 |
| | $ | (13.1 | ) | | $ | 5.3 |
| | $ | 2.4 |
| | $ | 64.2 |
| | $ | — |
| | $ | 66.6 |
| | $ | (34.7 | ) | | $ | 31.9 |
|
| Natural gas commodity | | — |
| | 3.4 |
| | — |
| | 3.4 |
| | — |
| | 3.4 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Total current derivative liabilities | | $ | 1.7 |
| | $ | 20.1 |
| | $ | — |
| | $ | 21.8 |
| | $ | (13.1 | ) | | 8.7 |
| | $ | 2.4 |
| | $ | 64.2 |
| | $ | — |
| | $ | 66.6 |
| | $ | (34.7 | ) | | 31.9 |
|
PPAs (b) | | | | | | | | | | | | — |
| | | | | | | | | | | | 2.7 |
|
| Current derivative instruments | | | | | | | | | | | | $ | 8.7 |
| | | | | | | | | | | | $ | 34.6 |
|
| Noncurrent derivative liabilities | | | | | | | | | | | | | | | | | | | | | | | | |
| Other derivative instruments: | | | | | | | | | | | | | | | | | | | | | | | | |
| Commodity trading | | $ | 0.4 |
| | $ | 47.0 |
| | $ | 14.7 |
| | $ | 62.1 |
| | $ | (9.6 | ) | | $ | 52.5 |
| | $ | — |
| | $ | 1.1 |
| | $ | — |
| | $ | 1.1 |
| | $ | (0.5 | ) | | $ | 0.6 |
|
| Total noncurrent derivative liabilities | | $ | 0.4 |
| | $ | 47.0 |
| | $ | 14.7 |
| | $ | 62.1 |
| | $ | (9.6 | ) | | 52.5 |
| | $ | — |
| | $ | 1.1 |
| | $ | — |
| | $ | 1.1 |
| | $ | (0.5 | ) | | 0.6 |
|
| Noncurrent derivative instruments | | | | | | | | | | | | $ | 52.5 |
| | | | | | | | | | | | $ | 0.6 |
|
| |
(a) | PSCo nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2019 and 2018. At both Dec. 31, 2019 and 2018, derivative assets and liabilities include 0 obligations to return cash collateral. At Dec. 31, 2019 and 2018, derivative assets and liabilities include the rights to reclaim cash collateral of $3.0 million and $6.5 million, respectively. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. |
| |
(b) | During 2006, PSCo qualified these contracts under the normal purchase exception. Based onthis qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. |
There were $10.9 million of losses, $0.1 million of gains and immaterial gains recognized in earnings for the years ended Dec. 31, 2019, 2018 and 2017, respectively, for Level 3 commodity trading derivatives.
PSCo recognizes transfers between levels as of the beginning of each period. There were 0 transfers of amounts between levels for derivative instruments for the years ended Dec. 31, 2019, 2018 and 2017.
Fair Value of Long-Term Debt
As of Dec. 31, other financial instruments for which the carrying amount did not equal fair value:
|
| | | | | | | | | | | | | | | | |
| | | 2019 | | 2018 |
| (Millions of Dollars) | | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value |
| Long-term debt, including current portion | | $ | 5,384.7 |
| | $ | 6,039.3 |
| | $ | 4,997.6 |
| | $ | 5,123.2 |
|
Fair value of PSCo’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. Fair value estimates are based on information available to management as of Dec. 31, 2019 and 2018, and given the observability of the inputs, fair values presented for long-term debt were assigned as Level 2.
|
|
| 9. Benefit Plans and Other Postretirement Benefits |
Pension and Postretirement Health Care Benefits
Xcel Energy, which includes PSCo, has several noncontributory, defined benefit pension plans that cover almost all employees. Generally, benefits are based on a contributory healthcombination of years of service, the employee’s average pay 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 caresome cases, social security 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.
Plan Assets — Certain state agencies that regulate Xcel Energy Inc.’s utility subsidiariesand PSCo’s policy is to fully fund into an external trust the actuarially determined pension costs recognized for ratemaking and financial reporting purposes, subject to the limitations of applicable employee benefit and tax laws.
In addition to the qualified pension plans, Xcel Energy maintains a SERP and a nonqualified pension plan. The SERP is maintained for certain executives that were participants in the plan in 2008, when the SERP was closed to new participants. The nonqualified pension plan provides benefits for compensation that is in excess of the limits applicable to the qualified pension plans, with distributions attributable to PSCo funded by PSCo’s consolidated operating cash flows. The total obligations of the SERP and nonqualified plan as of Dec. 31, 2019 and 2018 were $39 million and $33 million, respectively, of which $3 million was attributable to PSCo in both years. Xcel Energy recognized net benefit cost for financial reporting for the SERP and nonqualified plans of $4 million in 2019 and 2018, respectively, of which $1 million was attributable to PSCo.
Xcel Energy Inc. and PSCo base the investment-return assumption on expected long-term performance for each of the asset classes in their pension and postretirement health care portfolios. For pension assets, Xcel Energy Inc. and PSCo consider the historical returns achieved by the asset portfolio over the past 20-years or longer period, as well as the long-term return levels projected and recommended by investment experts. Xcel Energy Inc. and PSCo continually review pension assumptions.
Pension cost determination assumes a forecasted mix of investment types over the long term.
Investment returns in 2019 were above the assumed level of 6.84%;
Investment returns in 2018 were below the assumed level of 6.84%;
Investment returns in 2017 were above the assumed level of 6.84%; and
In 2020, PSCo’s expected investment-return assumption is 6.84%.
Pension plan and postretirement benefit assets are invested in a portfolio according to Xcel Energy Inc.’s and PSCo’s return, liquidity and diversification objectives to provide a source of funding for plan obligations and minimize contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the asset allocation given the long-term risk, return, correlation and liquidity characteristics of each particular asset class. There were no significant concentrations of risk in any industry, index, or entity. Market volatility can impact even well-diversified portfolios and significantly affect the return levels achieved by the assets in any year.
State agencies also have issued guidelines 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.ongoing investment strategy is based on plan-specific investment recommendations that seek to minimize potential investment and PSCo at Dec. 31 for the upcoming year: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.
|
| | | | | | |
| | | 2016 | | 2015 |
| Domestic and international equity securities | | 25 | % | | 25 | % |
| Short-to-intermediate fixed income securities | | 57 |
| | 57 |
|
| Alternative investments | | 13 |
| | 13 |
|
| Cash | | 5 |
| | 5 |
|
| Total | | 100 | % | | 100 | % |
Xcel Energy Inc. and PSCo base the investment-return assumptions for the postretirement health care fund assets on expected long-term performance forFor each of the investment types included in the asset portfolio. Assumptions and target allocations are determinedfair value hierarchy levels, PSCo’s pension plan assets measured 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 the necessity of contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the projected allocation of assets to selected asset classes, 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.fair value:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Dec. 31, 2019 (a) | | Dec. 31, 2018 (a) |
| (Millions of Dollars) | | Level 1 | | Level 2 | | Level 3 | | Measured at NAV | | Total | | Level 1 | | Level 2 | | Level 3 | | Measured at NAV | | Total |
| Cash equivalents | | $ | 45.6 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 45.6 |
| | $ | 53.0 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 53.0 |
|
| Commingled funds | | 497.0 |
| | — |
| | — |
| | 355.3 |
| | 852.3 |
| | 316.2 |
| | — |
| | — |
| | 326.1 |
| | 642.3 |
|
| Debt securities | | — |
| | 241.2 |
| | 1.5 |
| | — |
| | 242.7 |
| | — |
| | 242.3 |
| | — |
| | — |
| | 242.3 |
|
| Equity securities | | 29.7 |
| | — |
| | — |
| | — |
| | 29.7 |
| | 35.2 |
| | — |
| | — |
| | — |
| | 35.2 |
|
| Other | | (41.3 | ) | | 1.7 |
| | — |
| | (6.9 | ) | | (46.5 | ) | | 0.6 |
| | 2.0 |
| | — |
| | (9.9 | ) | | (7.3 | ) |
| Total | | $ | 531.0 |
| | $ | 242.9 |
| | $ | 1.5 |
| | $ | 348.4 |
| | $ | 1,123.8 |
| | $ | 405.0 |
| | $ | 244.3 |
| | $ | — |
| | $ | 316.2 |
| | $ | 965.5 |
|
| |
(a) | See Note 8 for further information on fair value measurement inputs and methods. |
The following tables present, forFor each of the fair value hierarchy levels, PSCo’s proportionate allocation of the total postretirement benefit plan assets that arewere measured at fair value as of Dec. 31, 2016 and 2015:value:
|
| | | | | | | | | | | | | | | | | | | | |
| | | Dec. 31, 2016 |
| (Thousands of Dollars) | | Level 1 | | Level 2 | | Level 3 | | Investments Measured at NAV (a) | | Total |
| Cash equivalents | | $ | 18,288 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 18,288 |
|
| Insurance contracts | | — |
| | 42,046 |
| | — |
| | — |
| | 42,046 |
|
| Commingled funds: | | | | | | | | | | |
| U.S. equity funds | | — |
| | — |
| | — |
| | 48,462 |
| | 48,462 |
|
| U.S fixed income funds | | — |
| | — |
| | — |
| | 24,132 |
| | 24,132 |
|
| Emerging market debt funds | | — |
| | — |
| | — |
| | 27,089 |
| | 27,089 |
|
| Other commingled funds | | — |
| | — |
| | — |
| | 48,922 |
| | 48,922 |
|
| Debt securities: | | | | | | | | | | |
| Government securities | | — |
| | 33,600 |
| | — |
| | — |
| | 33,600 |
|
| U.S. corporate bonds | | — |
| | 55,473 |
| | — |
| | — |
| | 55,473 |
|
| Non U.S. corporate bonds | | — |
| | 15,384 |
| | — |
| | — |
| | 15,384 |
|
| Asset-backed securities | | — |
| | 16,845 |
| | — |
| | — |
| | 16,845 |
|
| Mortgage-backed securities | | — |
| | 25,563 |
| | — |
| | — |
| | 25,563 |
|
| Equity securities: | | | | | | | | | | |
| Non U.S. equities | | 36,462 |
| | — |
| | — |
| | — |
| | 36,462 |
|
| Other | | — |
| | 1,289 |
| | — |
| | — |
| | 1,289 |
|
| Total | | $ | 54,750 |
| | $ | 190,200 |
| | $ | — |
| | $ | 148,605 |
| | $ | 393,555 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Dec. 31, 2019 (a) | | Dec. 31, 2018 (a) |
| (Millions of Dollars) | | Level 1 | | Level 2 | | Level 3 | | Measured at NAV | | Total | | Level 1 | | Level 2 | | Level 3 | | Measured at NAV | | Total |
| Cash equivalents | | $ | 20.3 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 20.3 |
| | $ | 17.0 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 17.0 |
|
| Insurance contracts | | — |
| | 45.4 |
| | — |
| | — |
| | 45.4 |
| | — |
| | 40.2 |
| | — |
| | — |
| | 40.2 |
|
| Commingled funds | | 61.9 |
| | — |
| | — |
| | 68.0 |
| | 129.9 |
| | 118.7 |
| | — |
| | — |
| | 35.8 |
| | 154.5 |
|
| Debt securities | | — |
| | 203.4 |
| | 1.0 |
| | — |
| | 204.4 |
| | — |
| | 159.7 |
| | — |
| | — |
| | 159.7 |
|
| Equity securities | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Other | | — |
| | 0.5 |
| | — |
| | — |
| | 0.5 |
| | — |
| | 0.7 |
| | — |
| | — |
| | 0.7 |
|
| Total | | $ | 82.2 |
| | $ | 249.3 |
| | $ | 1.0 |
| | $ | 68.0 |
| | $ | 400.5 |
| | $ | 135.7 |
| | $ | 200.6 |
| | $ | — |
| | $ | 35.8 |
| | $ | 372.1 |
|
| |
(a) | Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 28 for further information on the adoption of ASU No. 2015-07.fair value measurement inputs and methods. |
|
| | | | | | | | | | | | | | | | | | | | |
| | | Dec. 31, 2015 |
| (Thousands of Dollars) | | Level 1 | | Level 2 | | Level 3 | | Investments Measured at NAV (a)
| | Total |
| Cash equivalents | | $ | 17,524 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 17,524 |
|
| Insurance contracts | | — |
| | 42,123 |
| | — |
| | — |
| | 42,123 |
|
| Commingled funds: | | | | | | | | | | |
| U.S. equity funds | | — |
| | — |
| | — |
| | 34,089 |
| | 34,089 |
|
| Non U.S. equity funds | | — |
| | — |
| | — |
| | 29,979 |
| | 29,979 |
|
| U.S fixed income funds | | — |
| | — |
| | — |
| | 21,638 |
| | 21,638 |
|
| Emerging market equity funds | | — |
| | — |
| | — |
| | 9,901 |
| | 9,901 |
|
| Emerging market debt funds | | — |
| | — |
| | — |
| | 31,827 |
| | 31,827 |
|
| Other commingled funds | | — |
| | — |
| | — |
| | 55,302 |
| | 55,302 |
|
| Debt securities: | | | | | | | | | | |
| Government securities | | — |
| | 35,016 |
| | — |
| | — |
| | 35,016 |
|
| U.S. corporate bonds | | — |
| | 53,433 |
| | — |
| | — |
| | 53,433 |
|
| Non U.S. corporate bonds | | — |
| | 11,598 |
| | — |
| | — |
| | 11,598 |
|
| Asset-backed securities | | — |
| | 25,602 |
| | — |
| | — |
| | 25,602 |
|
| Mortgage-backed securities | | — |
| | 31,778 |
| | — |
| | — |
| | 31,778 |
|
| Other | | — |
| | (368 | ) | | — |
| | — |
| | (368 | ) |
| Total | | $ | 17,524 |
| | $ | 199,182 |
| | $ | — |
| | $ | 182,736 |
| | $ | 399,442 |
|
| |
(a)
| Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU No. 2015-07. |
ThereImmaterial assets were no assets transferred in or out of Level 3 for the years ended Dec. 31, 2016, 20152019. No assets were transferred in or 2014.out of Level 3 for 2018.
Benefit ObligationsFunded Status — A comparisonComparisons of the actuarially computed benefit obligation, andchanges in plan assets and funded status of the pension and postretirement health care plans for PSCoXcel Energy are as follows:
|
| | | | | | | | | | | | | | | | |
| | | Pension Benefits | | Postretirement Benefits |
| (Millions of Dollars) | | 2019 | | 2018 | | 2019 | | 2018 |
| Change in Benefit Obligation: | | | | | | | | |
| Obligation at Jan. 1 | | $ | 1,229.3 |
| | $ | 1,334.2 |
| | $ | 376.5 |
| | $ | 429.2 |
|
| Service cost | | 25.6 |
| | 29.0 |
| | 0.5 |
| | 0.7 |
|
| Interest cost | | 51.6 |
| | 47.3 |
| | 15.6 |
| | 15.0 |
|
| Plan amendments | | — |
| | — |
| | — |
| | — |
|
| Actuarial loss (gain) | | 108.2 |
| | (96.5 | ) | | 12.7 |
| | (40.6 | ) |
| Plan participants’ contributions | | — |
| | — |
| | 6.6 |
| | 6.5 |
|
| Medicare subsidy reimbursements | | — |
| | — |
| | 1.6 |
| | 0.9 |
|
| Benefit payments | | (84.9 | ) | | (84.7 | ) | | (33.5 | ) | | (35.2 | ) |
| Obligation at Dec. 31 | | $ | 1,329.8 |
| | $ | 1,229.3 |
| | $ | 380.0 |
| | $ | 376.5 |
|
| Change in Fair Value of Plan Assets: | | | | | | | | |
| Fair value of plan assets at Jan. 1 | | $ | 965.5 |
| | $ | 1,079.4 |
| | $ | 372.1 |
| | $ | 406.4 |
|
| Actual return on plan assets | | 197.4 |
| | (50.9 | ) | | 51.0 |
| | (11.1 | ) |
| Employer contributions | | 45.8 |
| | 21.7 |
| | 4.3 |
| | 5.5 |
|
| Plan participants’ contributions | | — |
| | — |
| | 6.6 |
| | 6.5 |
|
| Benefit payments | | (84.9 | ) | | (84.7 | ) | | (33.5 | ) | | (35.2 | ) |
| Fair value of plan assets at Dec. 31 | | $ | 1,123.8 |
| | $ | 965.5 |
| | $ | 400.5 |
| | $ | 372.1 |
|
| Funded status of plans at Dec. 31 | | $ | (206.0 | ) | | $ | (263.8 | ) | | $ | 20.5 |
| | $ | (4.4 | ) |
| Amounts recognized in the Consolidated Balance Sheet at Dec. 31: | | | | | | | | |
| Noncurrent liabilities | | (206.0 | ) | | (263.8 | ) | | 20.5 |
| | (4.4 | ) |
| Net amounts recognized | | $ | (206.0 | ) | | $ | (263.8 | ) | | $ | 20.5 |
| | $ | (4.4 | ) |
| Significant Assumptions Used to Measure Benefit Obligations: | | | | | | | | |
| Discount rate for year-end valuation | | 3.49 | % | | 4.31 | % | | 3.47 | % | | 4.32 | % |
| Expected average long-term increase in compensation level | | 3.75 |
| | 3.75 |
| | N/A |
| | N/A |
|
| Mortality table | | Pri-2012 |
| | RP-2014 |
| | Pri-2012 |
| | RP-2014 |
|
Health care costs trend rate — initial: Pre-65 | | N/A |
| | N/A |
| | 6.00 | % | | 6.50 | % |
Health care costs trend rate — initial: Post-65 | | N/A |
| | N/A |
| | 5.10 | % | | 5.30 | % |
Ultimate trend assumption — initial: Pre-65 | | N/A |
| | N/A |
| | 4.50 | % | | 4.50 | % |
Ultimate trend assumption — initial: Post-65 | | N/A |
| | N/A |
| | 4.50 | % | | 4.50 | % |
| Years until ultimate trend is reached | | N/A |
| | N/A |
| | 3 |
| | 4 |
|
Accumulated benefit obligation for the pension plan was $1,267.2 million and $1,183.3 million as of Dec. 31, 2019 and 2018, respectively.
Net Periodic Benefit Cost (Credit) — Net periodic benefit cost (credit) other than the service cost component is presentedincluded in other income in the following table:consolidated statement of income.
Components of net periodic benefit cost (credit) and the amounts recognized in other comprehensive income and regulatory assets and liabilities:
|
| | | | | | | | |
| (Thousands of Dollars) | | 2016 | | 2015 |
| Change in Projected Benefit Obligation: | | | | |
| Obligation at Jan. 1 | | $ | 403,574 |
| | $ | 443,753 |
|
| Service cost | | 768 |
| | 928 |
|
| Interest cost | | 18,070 |
| | 17,498 |
|
| Medicare subsidy reimbursements | | 1,901 |
| | 1,712 |
|
| Plan participants’ contributions | | 5,376 |
| | 4,961 |
|
| Actuarial loss (gain) | | 27,355 |
| | (32,001 | ) |
| Benefit payments | | (35,221 | ) | | (33,277 | ) |
| Obligation at Dec. 31 | | $ | 421,823 |
| | $ | 403,574 |
|
|
| | | | | | | | |
| (Thousands of Dollars) | | 2016 | | 2015 |
| Change in Fair Value of Plan Assets: | | | | |
| Fair value of plan assets at Jan. 1 | | $ | 399,442 |
| | $ | 425,282 |
|
| Actual return (loss) on plan assets | | 18,590 |
| | (3,076 | ) |
| Plan participants’ contributions | | 5,376 |
| | 4,961 |
|
| Employer contributions | | 5,368 |
| | 5,552 |
|
| Benefit payments | | (35,221 | ) | | (33,277 | ) |
| Fair value of plan assets at Dec. 31 | | $ | 393,555 |
| | $ | 399,442 |
|
|
| | | | | | | | |
| (Thousands of Dollars) | | 2016 | | 2015 |
| Funded Status at Dec. 31: | | | | |
Funded status (a) | | $ | (28,268 | ) | | $ | (4,132 | ) |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Pension Benefits | | Postretirement Benefits |
| (Millions of Dollars) | | 2019 | | 2018 | | 2017 | | 2019 | | 2018 | | 2017 |
| Service cost | | $ | 25.6 |
| | $ | 29.0 |
| | $ | 27.3 |
| | $ | 0.5 |
| | $ | 0.7 |
| | $ | 0.7 |
|
| Interest cost | | 51.6 |
| | 47.3 |
| | 50.6 |
| | 15.6 |
| | 15.0 |
| | 16.8 |
|
| Expected return on plan assets | | (68.5 | ) | | (68.5 | ) | | (68.5 | ) | | (18.9 | ) | | (22.7 | ) | | (21.9 | ) |
| Amortization of prior service credit | | (3.4 | ) | | (3.4 | ) | | (3.2 | ) | | (5.4 | ) | | (6.2 | ) | | (6.2 | ) |
| Amortization of net loss | | 25.4 |
| | 31.2 |
| | 28.3 |
| | 2.9 |
| | 4.0 |
| | 3.8 |
|
Settlement charge (a) | | 3.2 |
| | 4.5 |
| | — |
| | — |
| | — |
| | — |
|
| Net periodic pension cost (credit) | | 33.9 |
| | 40.1 |
| | 34.5 |
| | (5.3 | ) | | (9.2 | ) | | (6.8 | ) |
| Costs (credits) not recognized due to effects of regulation | | 3.5 |
| | (3.9 | ) | | (2.7 | ) | | 1.2 |
| | 1.8 |
| | — |
|
| Net benefit cost (credit) recognized for financial reporting | | $ | 37.4 |
| | $ | 36.2 |
| | $ | 31.8 |
| | $ | (4.1 | ) | | $ | (7.4 | ) | | $ | (6.8 | ) |
| Significant Assumptions Used to Measure Costs: | | | | | | | | | | | | |
| Discount rate | | 4.31 | % | | 3.63 | % | | 4.13 | % | | 4.32 | % | | 3.62 | % | | 4.13 | % |
| Expected average long-term increase in compensation level | | 3.75 |
| | 3.75 |
| | 3.75 |
| | N/A |
| | N/A |
| | N/A |
|
| Expected average long-term rate of return on assets | | 6.84 |
| | 6.84 |
| | 6.84 |
| | 4.50 |
| | 5.30 |
| | 5.80 |
|
| |
(a) | Amounts are recognizedA settlement charge is required when the amount of all lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In 2019 and 2018, as a result of lump-sum distributions during the 2019 and 2018 plan years, PSCo recorded a total pension settlement charge of $3.2 million and $4.5 million in noncurrent liabilities on PSCo’s consolidated balance sheets.2019 and 2018. A total of $0.1 million and $0.2 million of that amount was recorded in the income statement in 2019 and 2018, respectively. |
|
| | | | | | | | |
| (Thousands of Dollars) | | 2016 | | 2015 |
| Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: | | | | |
| Net loss | | $ | 78,359 |
| | $ | 49,226 |
|
| Prior service credit | | (27,695 | ) | | (33,942 | ) |
| Total | | $ | 50,664 |
| | $ | 15,284 |
|
| | | (Thousands of Dollars) | | 2016 | | 2015 | |
| | | | Pension Benefits | | Postretirement Benefits |
| (Millions of Dollars) | | | 2019 | | 2018 | | 2019 | | 2018 |
| Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: | | | | | | | | | |
| Net loss | | | $ | 481.5 |
| | $ | 530.8 |
| | $ | 44.6 |
| | $ | 66.9 |
|
| Prior service credit | | | (3.8 | ) | | (7.2 | ) | | (9.9 | ) | | (15.3 | ) |
| Total | | | $ | 477.7 |
| | $ | 523.6 |
| | $ | 34.7 |
| | $ | 51.6 |
|
| Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates: | | | | | | | | | | | | |
| Current regulatory assets | | | $ | 22.3 |
| | $ | 25.8 |
| |
| | $ | — |
|
| Noncurrent regulatory assets | | $ | 50,664 |
| | $ | 15,284 |
| | 452.1 |
| | 497.5 |
| | 34.7 |
| | 51.6 |
|
| Deferred income taxes | | | 0.8 |
| | 0.1 |
| | — |
| | — |
|
| Net-of-tax accumulated other comprehensive income | | | 2.5 |
| | 0.2 |
| | — |
| | — |
|
| Total | | | $ | 477.7 |
| | $ | 523.6 |
| | $ | 34.7 |
| | $ | 51.6 |
|
|
| | | | | | | | |
| Measurement date | | Dec. 31, 20162019 | | Dec. 31, 20152018 | | Dec. 31, 2019 | | Dec. 31, 2018 |
|
| | | | | | |
| | | 2016 | | 2015 |
| Significant Assumptions Used to Measure Benefit Obligations: | | | | |
| Discount rate for year-end valuation | | 4.13 | % | | 4.65 | % |
| Mortality table | | RP 2014 |
| | RP 2014 |
|
| Health care costs trend rate — initial | | 5.50 | % | | 6.00 | % |
Effective Jan. 1, 2017, the initial medical trend rate was decreased from 6.0 percentCash Flows — Cash funding requirements can be impacted by changes to 5.5 percent. The ultimate trend assumption remained at 4.5 percent. The period until the ultimate rate is reached is two years. Xcel Energy Inc.actuarial assumptions, actual asset levels 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 experiencedother calculations prescribed by the retiree medical plan.funding requirements of income tax and other pension-related regulations. Required contributions were made in 2017 - 2020 to meet minimum funding requirements. Total voluntary and required pension funding contributions across all 4 of Xcel Energy’s pension plans were as follows:
$150 million in January 2020, of which $50 million was attributable to PSCo;
$154 million in 2019, of which $46 million was attributable to PSCo;
A one-percent change$150 million in the assumed health care cost trend rate would have the following effects on PSCo:2018, of which $22 million was attributable to PSCo; and
$162 million in 2017, of which $18 million was attributable to PSCo. |
| | | | | | | | |
| | | One-Percentage Point |
| (Thousands of Dollars) | | Increase | | Decrease |
| APBO | | $ | 40,100 |
| | $ | (34,155 | ) |
| Service and interest components | | 1,980 |
| | (1,677 | ) |
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.approved. Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities. Xcel Energy, which includes PSCo, contributed $17.9 million, $18.3 million and $17.1 million during 2016, 2015 and 2014, respectively, of which $5.4 million, $5.6 million and $5.5 million were attributable to PSCo.
Xcel Energy expects to contribute approximately $11.8$10 million during 2017,2020, of which amounts attributable to PSCo will be zero.0.
Xcel Energy, which includes PSCo, contributed:
$15 million during 2019, of which $4 million was attributable to PSCo;
$11 million during 2018, of which $5 million was attributable to PSCo; and
$20 million during 2017, of which $5 million was attributable to PSCo.
Targeted asset allocations:
|
| | | | | | | | | | | | |
| | | Pension Benefits | | Postretirement Benefits |
| | | 2019 | | 2018 | | 2019 | | 2018 |
| Domestic and international equity securities | | 37 | % | | 35 | % | | 15 | % | | 18 | % |
| Long-duration fixed income securities | | 30 |
| | 32 |
| | — |
| | — |
|
| Short-to-intermediate fixed income securities | | 14 |
| | 16 |
| | 72 |
| | 70 |
|
| Alternative investments | | 17 |
| | 15 |
| | 9 |
| | 8 |
|
| Cash | | 2 |
| | 2 |
| | 4 |
| | 4 |
|
| Total | | 100 | % | | 100 | % | | 100 | % | | 100 | % |
Plan Amendments — The Xcel Energy Pension Plan and Xcel Energy Inc. Nonbargaining Pension Plan (South), which includes PSCo, were amended in 2017 to reduce supplemental benefits for non-bargaining participants as well as to allow the transfer of a portion of non-qualified pension obligations into the qualified plans.
In 2016 and 20152018, the PSCo postretirement plan was amended to add the 5% cash balance formula.
In 2019, there were no plan amendments made which affected the projected benefit obligation.
Benefit Costs — The components of PSCo’s net periodic postretirement benefit costs were:
|
| | | | | | | | | | | | |
| (Thousands of Dollars) | | 2016 | | 2015 | | 2014 |
| Service cost | | $ | 768 |
| | $ | 928 |
| | $ | 1,915 |
|
| Interest cost | | 18,070 |
| | 17,498 |
| | 23,704 |
|
| Expected return on plan assets | | (22,299 | ) | | (23,803 | ) | | (30,214 | ) |
| Amortization of prior service credit | | (6,247 | ) | | (6,247 | ) | | (6,247 | ) |
| Amortization of net loss | | 1,931 |
| | 2,475 |
| | 6,434 |
|
| Net periodic postretirement benefit credit | | $ | (7,777 | ) | | $ | (9,149 | ) | | $ | (4,408 | ) |
|
| | | | | | | | | |
| | | 2016 | | 2015 | | 2014 |
| Significant Assumptions Used to Measure Costs: | | | | | | |
| Discount rate | | 4.65 | % | | 4.08 | % | | 4.82 | % |
| Expected average long-term rate of return on assets | | 5.80 |
| | 5.80 |
| | 7.18 |
|
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:payments:
|
| | | | | | | | | | | | | | | | |
| (Millions of Dollars) | | Projected Pension
Benefit Payments | | Gross Projected
Postretirement
Health Care
Benefit Payments | | Expected Medicare
Part D Subsidies | | Net Projected
Postretirement
Health Care
Benefit Payments |
| 2020 | | $ | 82.0 |
| | $ | 30.5 |
| | $ | 1.9 |
| | $ | 28.6 |
|
| 2021 | | 81.9 |
| | 30.3 |
| | 2.0 |
| | 28.3 |
|
| 2022 | | 82.3 |
| | 29.8 |
| | 2.1 |
| | 27.7 |
|
| 2023 | | 82.7 |
| | 29.4 |
| | 2.2 |
| | 27.2 |
|
| 2024 | | 82.4 |
| | 28.8 |
| | 2.2 |
| | 26.6 |
|
| 2025-2029 | | 402.9 |
| | 129.9 |
| | 12.1 |
| | 117.8 |
|
|
| | | | | | | | | | | | | | | | |
| (Thousands of Dollars) | | Projected Pension
Benefit Payments | | Gross Projected
Postretirement
Health Care
Benefit Payments | | Expected Medicare
Part D Subsidies | | Net Projected
Postretirement
Health Care
Benefit Payments |
| 2017 | | $ | 79,506 |
| | $ | 33,912 |
| | $ | 2,140 |
| | $ | 31,772 |
|
| 2018 | | 78,738 |
| | 33,652 |
| | 2,266 |
| | 31,386 |
|
| 2019 | | 80,914 |
| | 33,467 |
| | 2,383 |
| | 31,084 |
|
| 2020 | | 81,095 |
| | 33,991 |
| | 2,475 |
| | 31,516 |
|
| 2021 | | 82,084 |
| | 33,588 |
| | 2,574 |
| | 31,014 |
|
| 2022-2026 | | 417,876 |
| | 156,773 |
| | 14,246 |
| | 142,527 |
|
Other income, net for the years ended Dec. 31 consisted of the following:
|
| | | | | | | | | | | | |
| (Thousands of Dollars) | | 2016 | | 2015 | | 2014 |
| Interest income | | $ | 1,860 |
| | $ | 753 |
| | $ | 1,470 |
|
| Other nonoperating income | | 2,241 |
| | 2,408 |
| | 3,601 |
|
| Insurance policy expense | | (281 | ) | | (197 | ) | | (806 | ) |
| Other nonoperating expense | | (3 | ) | | — |
| | — |
|
| Other income, net | | $ | 3,817 |
| | $ | 2,964 |
| | $ | 4,265 |
|
| |
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.
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.
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. When contractual settlements extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable forecasts of long-term forward prices and 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.
AtAs of Dec. 31, 2016,2019, accumulated other comprehensive losses related to interest rate derivatives included $1.0$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 managementPSCo is allowed to conduct these activities within guidelines and limitations as approved by its risk management committee, which is made upcomprised of management personnel not directly involved in the activities governed by this policy.
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 aremay not be designated as qualifying hedging transactions. Changes in the fair value of non-trading commodity derivative instruments are recorded in OCIother comprehensive income or deferred as a regulatory asset or liability. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. PSCo recorded immaterialNaN amounts to income related to the ineffectiveness of cash flow hedges were recorded for the years ended Dec. 31, 20162019 and 2015.2018.
As of Dec. 31, 2019, there were 0 net gains related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses or related amounts expected to be reclassified into earnings during the next 12 months.
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 grossGross notional amounts of commodity forwards and options at Dec. 31:
| | (Amounts in Thousands) (a)(b) | | 2016 | | 2015 | |
(Amounts in Millions) (a)(b) | | | 2019 | | 2018 |
| MWh of electricity | | 6,283 |
| | 684 |
| | 9.3 |
| | 24.4 |
|
| MMBtu of natural gas | | 42,203 |
| | 12,515 |
| | 32.2 |
| | 48.4 |
|
| Gallons of vehicle fuel | | — |
| | 63 |
| |
| |
(a) | Amounts are not reflective of net positions in the underlying commodities. |
| |
(b) | Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise. |
Consideration of Credit Risk and Concentrations — PSCo continuously monitors the creditworthiness of the counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Given this assessment, as well as an assessment of theThe impact of PSCo’s own credit risk when determining the fair value of derivative liabilities, the impact of considering 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, 2016, six2019, 5 of PSCo’s 10 most significant counterparties for these activities, comprising $8.8$110.1 million or 15 percent78% of this credit exposure, had investment grade credit ratings from Standard & Poor’s, Moody’s or Fitch Ratings. FourNaN of the 10 most significant counterparties, comprising $21.1$15.7 million or 35 percent11% of this credit exposure, at Dec. 31, 2016, were not rated by these external agencies, but based on PSCo’s internal analysis, had credit quality consistent with investment grade. SevenNaN of these significant counterparties are municipal or cooperative electric entities, ISOs or other utilities.
Financial Impact of Qualifying Cash Flow Hedges — The Financial impact of qualifying interest rate and vehicle fuel cash flow hedges on PSCo’s accumulated other comprehensive loss, included in the consolidated statements of common stockholder’s equity and in the consolidated statements of comprehensive income, is detailed in the following table:income:
|
| | | | | | | | | | | | |
| (Millions of Dollars) | | 2019 | | 2018 | | 2017 |
| Accumulated other comprehensive loss related to cash flow hedges at Jan. 1 | | $ | (25.3 | ) | | $ | (26.5 | ) | | $ | (22.8 | ) |
| After-tax net realized losses on derivative transactions reclassified into earnings | | 1.2 |
| | 1.2 |
| | 1.0 |
|
Adoption of ASU No. 2018-02 (a) | | — |
| | — |
| | (4.7 | ) |
| Accumulated other comprehensive loss related to cash flow hedges at Dec. 31 | | $ | (24.1 | ) | | $ | (25.3 | ) | | $ | (26.5 | ) |
|
| | | | | | | | | | | | |
| (Thousands of Dollars) | | 2016 | | 2015 | | 2014 |
| Accumulated other comprehensive loss related to cash flow hedges at Jan. 1 | | $ | (23,836 | ) | | $ | (23,878 | ) | | $ | (23,338 | ) |
| After-tax net unrealized (losses) related to derivatives accounted for as hedges | | — |
| | (30 | ) | | (72 | ) |
| After-tax net realized losses (gains) on derivative transactions reclassified into earnings | | 1,056 |
| | 72 |
| | (468 | ) |
| Accumulated other comprehensive loss related to cash flow hedges at Dec. 31 | | $ | (22,780 | ) | | $ | (23,836 | ) | | $ | (23,878 | ) |
The following tables detail the impact of derivative activity during the years ended Dec. 31, 2016, 2015 and 2014, on accumulated other comprehensive loss, regulatory assets and liabilities, and income:
|
| | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended Dec. 31, 2016 | |
| | | Pre-Tax Fair Value
Gains Recognized
During the Period in: | | Pre-Tax Losses
Reclassified into Income
During the Period from: | | | |
| (Thousands of Dollars) | | Accumulated
Other
Comprehensive Loss | | Regulatory
(Assets) and Liabilities | | Accumulated
Other
Comprehensive Loss | | Regulatory
Assets and (Liabilities) | | Pre-Tax Losses Recognized
During the Period
in Income | |
| Derivatives designated as cash flow hedges | | | | | | | | | | | |
| Interest rate | | $ | — |
| | $ | — |
| | $ | 1,618 |
| (a) | $ | — |
| | $ | — |
| |
| Vehicle fuel and other commodity | | — |
| | — |
| | 86 |
| (b) | — |
| | — |
| |
| Total | | $ | — |
| | $ | — |
| | $ | 1,704 |
| | $ | — |
| | $ | — |
| |
| Other derivative instruments | | | | | | | | | | | |
| Commodity trading | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | (257 | ) | (c) |
| Natural gas commodity | | — |
| | 2,051 |
| | — |
| | 10,292 |
| (d) | (5,832 | ) | (d) |
| Total | | $ | — |
| | $ | 2,051 |
| | $ | — |
| | $ | 10,292 |
| | $ | (6,089 | ) | |
|
| | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended Dec. 31, 2015 | |
| | | Pre-Tax Fair Value
Losses Recognized
During the Period in: | | Pre-Tax Losses
Reclassified into Income
During the Period from: | | | |
| (Thousands of Dollars) | | Accumulated Other Comprehensive Loss | | Regulatory (Assets) and Liabilities | | Accumulated Other Comprehensive Loss | | Regulatory Assets and (Liabilities) | | Pre-Tax Gains (Losses)
Recognized
During the Period
in Income | |
| Derivatives designated as cash flow hedges | | | | | | | | | | | |
| Interest rate | | $ | — |
| | $ | — |
| | $ | 54 |
| (a) | $ | — |
| | $ | — |
| |
| Vehicle fuel and other commodity | | (50 | ) | | — |
| | 57 |
| (b) | — |
| | — |
| |
| Total | | $ | (50 | ) | | $ | — |
| | $ | 111 |
| | $ | — |
| | $ | — |
| |
| Other derivative instruments | | | | | | | | | | | |
| Commodity trading | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 364 |
| (c) |
| Natural gas commodity | | — |
| | (10,635 | ) | | — |
| | 10,158 |
| (d) | (7,620 | ) | (d) |
| Total | | $ | — |
| | $ | (10,635 | ) | | $ | — |
| | $ | 10,158 |
| | $ | (7,256 | ) | |
|
| | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended Dec. 31, 2014 | |
| | | Pre-Tax Fair Value
Gains (Losses) Recognized
During the Period in: | | Pre-Tax Gains
Reclassified into Income
During the Period from: | | | |
| (Thousands of Dollars) | | Accumulated
Other
Comprehensive Loss | | Regulatory
(Assets) and Liabilities | | Accumulated
Other
Comprehensive Loss | | Regulatory
Assets and (Liabilities) | | Pre-Tax Losses Recognized
During the Period
in Income | |
| Derivatives designated as cash flow hedges | | | | | | | | | | | |
| Interest rate | | $ | — |
| | $ | — |
| | $ | (730 | ) | (a) | $ | — |
| | $ | — |
| |
| Vehicle fuel and other commodity | | (115 | ) | | — |
| | (25 | ) | (b) | — |
| | — |
| |
| Total | | $ | (115 | ) | | $ | — |
| | $ | (755 | ) | | $ | — |
| | $ | — |
| |
| Other derivative instruments | | | | | | | | | | | |
| Natural gas commodity | | $ | — |
| | $ | 451 |
| | $ | — |
| | $ | (4,631 | ) | (d) | $ | (9,850 | ) | (d) |
| Total | | $ | — |
| | $ | 451 |
| | $ | — |
| | $ | (4,631 | ) | | $ | (9,850 | ) | |
| |
(a) | In 2017, PSCo implemented ASU No. 2018-02 related to TCJA, which resulted in reclassification of certain credit balances within net accumulated other comprehensive loss to retained earnings. |
Impact of derivative activity:
|
| | | | | | | | |
| | | Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: |
| (Millions of Dollars) | | Accumulated Other
Comprehensive Loss | | Regulatory (Assets) and Liabilities |
| Year to date Dec. 31, 2019 | | | | |
| Other derivative instruments | | | | |
| Natural gas commodity | | $ | — |
| | $ | (5.3 | ) |
| Total | | $ | — |
| | $ | (5.3 | ) |
| | | | | |
| Year to date Dec. 31, 2018 | | | | |
| Other derivative instruments | | | | |
| Natural gas commodity | | $ | — |
| | $ | 8.0 |
|
| Total | | $ | — |
| | $ | 8.0 |
|
| | | | | |
| Year to date Dec. 31, 2017 | | | | |
| Other derivative instruments | | | | |
| Natural gas commodity | | $ | — |
| | $ | (10.9 | ) |
| Total | | $ | — |
| | $ | (10.9 | ) |
|
| | | | | | | | | | | | | |
| | | Pre-Tax (Gains) Losses
Reclassified into Income
During the Period from: | | | |
| (Millions of Dollars) | | Accumulated
Other
Comprehensive Loss | | Regulatory
Assets and (Liabilities) | | Pre-Tax Gains (Losses) Recognized
During the Period
in Income | |
| Year to date Dec. 31, 2019 | | | | | | | |
| Derivatives designated as cash flow hedges | | | | | | | |
| Interest rate | | $ | 1.6 |
| (a) | $ | — |
| | $ | — |
| |
| Total | | $ | 1.6 |
| | $ | — |
| | $ | — |
| |
| Other derivative instruments | | . |
| | | | | |
| Commodity trading | | $ | — |
| | $ | — |
| | $ | 3.1 |
| (c) |
| Natural gas commodity | | — |
| | 0.6 |
| (d) | (3.9 | ) | (d) |
| Total | | $ | — |
| | $ | 0.6 |
| | $ | (0.8 | ) | |
| | | | | | | | |
| Year to date Dec. 31, 2018 | | | | | | | |
| Derivatives designated as cash flow hedges | | | | | | | |
| Interest rate | | $ | 1.6 |
| (a) | $ | — |
| | $ | — |
| |
| Total | | $ | 1.6 |
| | $ | — |
| | $ | — |
| |
| Other derivative instruments | | | | | | | |
| Commodity trading | | $ | — |
| | $ | — |
| | $ | 3.1 |
| (c) |
| Natural gas commodity | | — |
| | (4.1 | ) | (d) | (2.9 | ) | (d) |
| Total | | $ | — |
| | $ | (4.1 | ) | | $ | 0.2 |
| |
| | | | | | | | |
| Year to date Dec. 31, 2017 | | | | | | | |
| Derivatives designated as cash flow hedges | | | | | | | |
| Interest rate | | $ | 1.6 |
| (a) | $ | — |
| | $ | — |
| |
| Total | | $ | 1.6 |
| | $ | — |
| | $ | — |
| |
| Other derivative instruments | | | | | | | |
| Commodity trading | | $ | — |
| | $ | — |
| | $ | 0.4 |
| (c) |
| Natural gas commodity | | — |
| | 1.9 |
| (d) | (4.2 | ) | (d) |
| Total | | $ | — |
| | $ | 1.9 |
| | $ | (3.8 | ) | |
| |
(a) | Amounts are recorded to interest charges. |
| |
(b) | Amounts are recorded to O&M expenses. |
| |
(c) | Amounts are recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate. |
| |
(d) | Amounts for the year ended Dec. 31, 20162019, 2018 and Dec. 31, 20152017 included $0.2 million and $1.10 settlement gains or losses, $1.2 million of settlement losses and $0.4 million of settlement gains, respectively, on derivatives entered to mitigate natural gas price risk for electric generation recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset or liability, as appropriate. Such losses for the years ended Dec. 31, 2014 were immaterial. The remainingRemaining settlement losses for the years ended Dec. 31, 2016, 20152019, 2018 and 20142017 relate to natural gas operations and are recorded to cost of natural gas sold and transported. These losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset or liability, as appropriate. |
PSCo had no0 derivative instruments designated as fair value hedges during the years ended Dec. 31, 2016, 20152019, 2018 and 2014. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.2017.
Credit Related Contingent Features—Contract provisions for derivative instruments that PSCo enters into, including those recorded to the consolidated balance sheet at fair value, as well as those accounted for as normal purchase-normal sale contracts and therefore not reflected on the consolidated balance sheet,sheets, may require the posting of collateral or settlement of the contracts for various reasons, including if PSCo is unablePSCo’s credit ratings are downgraded below its investment grade credit rating by any of the major credit rating agencies, or for cross-default contractual provisions if there was a failure under other financing arrangements related to maintain its credit ratings. payment terms or other covenants.
At Dec. 31, 20162019 and 2015,2018, there were no0 derivative instruments in a liability position with such underlying contract provisions that required the posting of collateral or settlement of outstanding contracts if the credit ratings of PSCo were downgraded below investment grade.
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 no0 collateral posted related to adequate assurance clauses in derivative contracts as of Dec. 31, 20162019 and 2015.2018.
Recurring Fair Value Measurements—The following table presents, for each of the fair value hierarchy levels, PSCo’s derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2016:
| | | | | Dec. 31, 2016 | | Dec. 31, 2019 | | Dec. 31, 2018 |
| | | Fair Value | | | | | | | | Fair Value | | | | | | | | Fair Value | | | | | | |
| (Thousands of Dollars) | | Level 1 | | Level 2 | | Level 3 | | Fair Value Total | | Counterparty Netting (b) | | Total | |
| (Millions of Dollars) | | | Level 1 | | Level 2 | | Level 3 | | Fair Value Total | | Netting (a) | | Total | | Level 1 | | Level 2 | | Level 3 | | Fair Value Total | | Netting (a) | | Total |
| Current derivative assets | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Other derivative instruments: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Commodity trading | | $ | 1,124 |
| | $ | 5,453 |
| | $ | — |
| | $ | 6,577 |
| | $ | (5,137 | ) | | $ | 1,440 |
| | $ | 1.9 |
| | $ | 11.1 |
| | $ | 0.9 |
| | $ | 13.9 |
| | $ | (10.1 | ) | | $ | 3.8 |
| | $ | 2.3 |
| | $ | 65.0 |
| | $ | 0.1 |
| | $ | 67.4 |
| | $ | (28.2 | ) | | $ | 39.2 |
|
| Natural gas commodity | | — |
| | 7,778 |
| | — |
| | 7,778 |
| | — |
| | 7,778 |
| | — |
| | 3.4 |
| | — |
| | 3.4 |
| | — |
| | 3.4 |
| | — |
| | 3.4 |
| | — |
| | 3.4 |
| | — |
| | 3.4 |
|
| Total current derivative assets | | $ | 1,124 |
| | $ | 13,231 |
| | $ | — |
| | $ | 14,355 |
| | $ | (5,137 | ) | | 9,218 |
| | $ | 1.9 |
| | $ | 14.5 |
| | $ | 0.9 |
| | $ | 17.3 |
| | $ | (10.1 | ) | | 7.2 |
| | $ | 2.3 |
| | $ | 68.4 |
| | $ | 0.1 |
| | $ | 70.8 |
| | $ | (28.2 | ) | | 42.6 |
|
PPAs (a) | | | | | | | | | | | | 1,716 |
| |
| Current derivative instruments | | | | | | | | | | | | $ | 10,934 |
| | | | | | | | | | | | $ | 7.2 |
| | | | | | | | | | | | $ | 42.6 |
|
| Noncurrent derivative assets | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Other derivative instruments: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Natural gas commodity | | $ | — |
| | $ | 1,652 |
| | $ | — |
| | $ | 1,652 |
| | $ | — |
| | $ | 1,652 |
| |
| Commodity trading | | | $ | 0.4 |
| | $ | 8.1 |
| | $ | 1.1 |
| | $ | 9.6 |
| | $ | (9.6 | ) | | $ | — |
| | $ | — |
| | $ | 1.6 |
| | $ | — |
| | $ | 1.6 |
| | $ | (0.4 | ) | | $ | 1.2 |
|
| Total noncurrent derivative assets | | $ | — |
| | $ | 1,652 |
| | $ | — |
| | $ | 1,652 |
| | $ | — |
| | 1,652 |
| | $ | 0.4 |
| | $ | 8.1 |
| | $ | 1.1 |
| | $ | 9.6 |
| | $ | (9.6 | ) | | — |
| | $ | — |
| | $ | 1.6 |
| | $ | — |
| | $ | 1.6 |
| | $ | (0.4 | ) | | 1.2 |
|
PPAs (a) | | | | | | | | | | | | 1,746 |
| |
| Noncurrent derivative instruments | | | | | | | | | | | | $ | 3,398 |
| | | | | | | | | | | | $ | — |
| | | | | | | | | | | | $ | 1.2 |
|
| Current derivative liabilities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Other derivative instruments: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Commodity trading | | $ | 1,386 |
| | $ | 5,357 |
| | $ | 22 |
| | $ | 6,765 |
| | $ | (5,137 | ) | | $ | 1,628 |
| | $ | 1.7 |
| | $ | 16.7 |
| | $ | — |
| | $ | 18.4 |
| | $ | (13.1 | ) | | $ | 5.3 |
| | $ | 2.4 |
| | $ | 64.2 |
| | $ | — |
| | $ | 66.6 |
| | $ | (34.7 | ) | | $ | 31.9 |
|
| Natural gas commodity | | | — |
| | 3.4 |
| | — |
| | 3.4 |
| | — |
| | 3.4 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Total current derivative liabilities | | $ | 1,386 |
| | $ | 5,357 |
| | $ | 22 |
| | $ | 6,765 |
| | $ | (5,137 | ) | | 1,628 |
| | $ | 1.7 |
| | $ | 20.1 |
| | $ | — |
| | $ | 21.8 |
| | $ | (13.1 | ) | | 8.7 |
| | $ | 2.4 |
| | $ | 64.2 |
| | $ | — |
| | $ | 66.6 |
| | $ | (34.7 | ) | | 31.9 |
|
PPAs (a) | | | | | | | | | | | | 5,160 |
| |
PPAs (b) | | | | | | | | | | | | | — |
| | | | | | | | | | | | 2.7 |
|
| Current derivative instruments | | | | | | | | | | | | $ | 6,788 |
| | | | | | | | | | | | $ | 8.7 |
| | | | | | | | | | | | $ | 34.6 |
|
| Noncurrent derivative liabilities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
PPAs (a) | | | | | | | | | | | | $ | 7,828 |
| |
| Other derivative instruments: | | | | | | | | | | | | | | | | | | | | | | | | | |
| Commodity trading | | | $ | 0.4 |
| | $ | 47.0 |
| | $ | 14.7 |
| | $ | 62.1 |
| | $ | (9.6 | ) | | $ | 52.5 |
| | $ | — |
| | $ | 1.1 |
| | $ | — |
| | $ | 1.1 |
| | $ | (0.5 | ) | | $ | 0.6 |
|
| Total noncurrent derivative liabilities | | | $ | 0.4 |
| | $ | 47.0 |
| | $ | 14.7 |
| | $ | 62.1 |
| | $ | (9.6 | ) | | 52.5 |
| | $ | — |
| | $ | 1.1 |
| | $ | — |
| | $ | 1.1 |
| | $ | (0.5 | ) | | 0.6 |
|
| Noncurrent derivative instruments | | | | | | | | | | | | $ | 7,828 |
| | | | | | | | | | | | $ | 52.5 |
| | | | | | | | | | | | $ | 0.6 |
|
| |
(a) | In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, PSCo began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, PSCo qualified these contracts under the normal purchase exception. Based onthis qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.
|
| |
(b)
| PSCo 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, 2016.2019 and 2018. At both Dec. 31, 2016,2019 and 2018, derivative assets and liabilities include no0 obligations to return cash collateral orcollateral. At Dec. 31, 2019 and 2018, derivative assets and liabilities include the rights to reclaim cash collateral.collateral of $3.0 million and $6.5 million, respectively. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. |
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, 2015:
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Dec. 31, 2015 |
| | | Fair Value | | | | | | |
| (Thousands of Dollars) | | Level 1 | | Level 2 | | Level 3 | | Fair Value Total | | Counterparty Netting (b) | | Total |
| Current derivative assets | | | | | | | | | | | | |
| Other derivative instruments: | | | | | | | | | | | | |
| Commodity trading | | $ | 137 |
| | $ | 351 |
| | $ | — |
| | $ | 488 |
| | $ | (324 | ) | | $ | 164 |
|
| Natural gas commodity | | — |
| | 352 |
| | — |
| | 352 |
| | (286 | ) | | 66 |
|
| Total current derivative assets | | $ | 137 |
| | $ | 703 |
| | $ | — |
| | $ | 840 |
| | $ | (610 | ) | | 230 |
|
PPAs (a) | | | | | | | | | | | | 1,715 |
|
| Current derivative instruments | | | | | | | | | | | | $ | 1,945 |
|
| Noncurrent derivative assets | | | | | | | | | | | | |
| Other derivative instruments: | | | | | | | | | | | | |
| Commodity trading | | $ | — |
| | $ | 16 |
| | $ | — |
| | $ | 16 |
| | $ | — |
| | $ | 16 |
|
| Total noncurrent derivative assets | | $ | — |
| | $ | 16 |
| | $ | — |
| | $ | 16 |
| | $ | — |
| | 16 |
|
PPAs (a) | | | | | | | | | | | | 3,462 |
|
| Noncurrent derivative instruments | | | | | | | | | | | | $ | 3,478 |
|
| Current derivative liabilities | | | | | | | | | | | | |
| Derivatives designated as cash flow hedges: | | | | | | | | | | | | |
| Vehicle fuel and other commodity | | $ | — |
| | $ | 92 |
| | $ | — |
| | $ | 92 |
| | $ | — |
| | $ | 92 |
|
| Other derivative instruments: | | | | | | | | | | | | |
| Commodity trading | | 34 |
| | 325 |
| | — |
| | 359 |
| | (324 | ) | | 35 |
|
| Natural gas commodity | | — |
| | 3,850 |
| | — |
| | 3,850 |
| | (286 | ) | | 3,564 |
|
| Total current derivative liabilities | | $ | 34 |
| | $ | 4,267 |
| | $ | — |
| | $ | 4,301 |
| | $ | (610 | ) | | 3,691 |
|
PPAs (a) | | | | | | | | | | | | 5,190 |
|
| Current derivative instruments | | | | | | | | | | | | $ | 8,881 |
|
| Noncurrent derivative liabilities | | | | | | | | | | | | |
| Other derivative instruments: | | | | | | | | | | | | |
| Commodity trading | | $ | — |
| | $ | 33 |
| | $ | — |
| | $ | 33 |
| | $ | — |
| | $ | 33 |
|
| Total noncurrent derivative liabilities | | $ | — |
| | $ | 33 |
| | $ | — |
| | $ | 33 |
| | $ | — |
| | 33 |
|
PPAs (a) | | | | | | | | | | | | 12,987 |
|
| Noncurrent derivative instruments | | | | | | | | | | | | $ | 13,020 |
|
| |
(a)(b)
| In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, PSCo began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, PSCo qualified these contracts under the normal purchase exception. Based onthis qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. |
| |
(b)
| PSCo 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, 2015. At Dec. 31, 2015, 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 $10.9 million of losses, $0.1 million of gains and immaterial lossesgains recognized in earnings for level 3 commodity trading derivatives for the year ended Dec. 31, 2016. There were no changes in Level 3 recurring fair value measurements for the years ended Dec. 31, 20152019, 2018 and 2014.
2017, respectively, for Level 3 commodity trading derivatives.
PSCo recognizes transfers between levels as of the beginning of each period. There were no0 transfers of amounts between levels for derivative instruments for the years ended Dec. 31, 2016, 20152019, 2018 and 2014.2017.
Fair Value of Long-Term Debt
As of Dec. 31, 2016 and 2015, other financial instruments for which the carrying amount did not equal fair value were as follows:value:
|
| | | | | | | | | | | | | | | | |
| | | 2019 | | 2018 |
| (Millions of Dollars) | | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value |
| Long-term debt, including current portion | | $ | 5,384.7 |
| | $ | 6,039.3 |
| | $ | 4,997.6 |
| | $ | 5,123.2 |
|
|
| | | | | | | | | | | | | | | | |
| | | 2016 | | 2015 |
| (Thousands of Dollars) | | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value |
Long-term debt, including current portion (a) | | $ | 4,216,206 |
| | $ | 4,491,570 |
| | $ | 4,105,596 |
| | $ | 4,376,875 |
|
| |
(a)
| Amounts reflect the classification of debt issuance costs as a deduction from the carrying amount of the related debt. See Note 2, Accounting Pronouncements for more information on the adoption of ASU No. 2015-03.
|
The fairFair value of PSCo’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. The fairFair value estimates are based on information available to management as of Dec. 31, 20162019 and 2015,2018, and given the observability of the inputs, to these estimates, the fair values presented for long-term debt have beenwere assigned aas Level 2.
| |
11. |
Rate Matters9. Benefit Plans and Other Postretirement Benefits |
Pending Regulatory Proceedings — CPUCPension and Postretirement Health Care Benefits
Xcel Energy, which includes PSCo, has several noncontributory, defined benefit pension plans that cover almost all employees. Generally, benefits are based on a combination of years of service, the employee’s average pay and, in some cases, social security benefits. Xcel Energy Inc.’s and PSCo’s policy is to fully fund into an external trust the actuarially determined pension costs recognized for ratemaking and financial reporting purposes, subject to the limitations of applicable employee benefit and tax laws.
Annual Electric Earnings Test — As partIn addition to the qualified pension plans, Xcel Energy maintains a SERP and a nonqualified pension plan. The SERP is maintained for certain executives that were participants in the plan in 2008, when the SERP was closed to new participants. The nonqualified pension plan provides benefits for compensation that is in excess of an annual earnings test,the limits applicable to the qualified pension plans, with distributions attributable to PSCo must share with customers earnings that exceedfunded by PSCo’s consolidated operating cash flows. The total obligations of the authorized ROE threshold of 9.83 percent for 2015 through 2017. The 2016 earnings test did not result in a material customer refund obligationSERP and nonqualified plan as of Dec. 31, 2016.2019 and 2018 were $39 million and $33 million, respectively, of which $3 million was attributable to PSCo will file its 2016 earnings test within both years. Xcel Energy recognized net benefit cost for financial reporting for the CPUCSERP and nonqualified plans of $4 million in April 2017. The final sharing obligation will be based2019 and 2018, respectively, of which $1 million was attributable to PSCo.
Xcel Energy Inc. and PSCo base the investment-return assumption on the CPUC approved tariff and could vary from the current estimate.
Electric, Purchased Gas and Resource Adjustment Clauses
DSM and the DSMCA — Energy efficiency and DSM costs are recovered through a combinationexpected long-term performance for each of the DSMCA ridersasset classes in their pension and base rates. DSMCA riders are adjusted biannually to capture program costs, performance incentives,postretirement health care portfolios. For pension assets, Xcel Energy Inc. and any over-PSCo consider the historical returns achieved by the asset portfolio over the past 20-years or under-recoveries are trued-uplonger period, as well as the long-term return levels projected and recommended by investment experts. Xcel Energy Inc. and PSCo continually review pension assumptions.
Pension cost determination assumes a forecasted mix of investment types over the long term.
Investment returns in 2019 were above the following year. Savings goalsassumed level of 6.84%;
Investment returns in 2018 were 400 GWhbelow the assumed level of 6.84%;
Investment returns in 20152017 were above the assumed level of 6.84%; and 2016 with incentives 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. For the years 2017 through 2020, the annual electric energy savings goal is 400 GWh per year with an annual spending limit of $84.3 million.
In February 2017, the CPUC approved2020, PSCo’s 2017-2018 DSM plan:expected investment-return assumption is 6.84%.
A 2017 DSM electric budgetPension plan and postretirement benefit assets are invested in a portfolio according to Xcel Energy Inc.’s and PSCo’s return, liquidity and diversification objectives to provide a source of $80.4 millionfunding for plan obligations and a natural gas budget of $13.1 million; and
A 2018 DSM electric budget of $77.7 million and a natural gas budget of $12.8 million.
REC Sharing — In 2011, the CPUC approved margin sharing on stand-alone REC transactions at 10 percent to PSCo and 90 percent to customers for 2014. In 2012, the CPUC approved an annual margin sharing on the first $20 million of margins on hybrid REC trades of 80 percentminimize contributions to the customersplan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the asset allocation given the long-term risk, return, correlation and 20 percent to PSCo. Marginsliquidity characteristics of each particular asset class. There were no significant concentrations of risk in excess ofany industry, index, or entity. Market volatility can impact even well-diversified portfolios and significantly affect the $20 million are to be shared 90 percentreturn levels achieved by the assets in any year.
State agencies also have issued guidelines to the customers and 10 percent to PSCo. The CPUC authorized PSCo to return to customers unspent carbon offset funds by crediting the RESA regulatory asset balance. PSCo credited to the RESA regulatory liability balance approximately $5.8 million and $5.5 million in 2016 and 2015, respectively. The cumulative credit to the RESA regulatory liability balance was $116.3 million and $110.6 million at Dec. 31, 2016 and Dec. 31, 2015, respectively. The credits include the customers’ sharefunding of REC trading margins and the unspent share of carbon offset funds. The current sharing mechanism, without modification, extends through Dec. 31, 2017.
| |
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:
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 2017 and 2060.postretirement benefit costs. PSCo is required to pay additional amounts depending on actual quantities shipped underfund postretirement benefit costs in irrevocable external trusts that are dedicated to the payment of these agreements.
postretirement benefits. These assets are invested in a manner consistent with the investment strategy for the pension plan.
The estimated minimum purchases for PSCo under these contracts as of Dec. 31, 2016, are as follows:
|
| | | | | | | | | | | | |
| (Millions of Dollars) | | Coal | | Natural gas supply | | Natural gas
storage and
transportation |
| 2017 | | $ | 241.2 |
| | $ | 293.6 |
| | $ | 117.8 |
|
| 2018 | | 143.1 |
| | 185.7 |
| | 69.0 |
|
| 2019 | | 68.6 |
| | 179.7 |
| | 37.1 |
|
| 2020 | | 48.5 |
| | 184.3 |
| | 36.6 |
|
| 2021 | | 49.6 |
| | 191.5 |
| | 34.4 |
|
| Thereafter | | 293.4 |
| | 171.2 |
| | 609.9 |
|
| Total | | $ | 844.4 |
| | $ | 1,206.0 |
| | $ | 904.8 |
|
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,ongoing investment strategy 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 2032 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 deliveredplan-specific investment recommendations that seek to minimize potential investment and capacity payments. Certain PPAs accounted forinterest rate risk as executory contracts also contain minimum energy purchase commitments. Capacitya 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 energy payments are typically contingent ona greater percentage of growth assets being allocated to plans having relatively lower funded status ratios.
Plan Assets
For each of the independent power producing entity meeting certain contract obligations, including plant availability requirements. Certain 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 $44.0 million, $69.5 million and $69.5 million in 2016, 2015 and 2014, respectively. At Dec. 31, 2016, the estimated future payments for capacity and energy that PSCo is obligated to purchase pursuant to these executory contracts, subject to availability, are as follows:fair value hierarchy levels, PSCo’s pension plan assets measured at fair value:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Dec. 31, 2019 (a) | | Dec. 31, 2018 (a) |
| (Millions of Dollars) | | Level 1 | | Level 2 | | Level 3 | | Measured at NAV | | Total | | Level 1 | | Level 2 | | Level 3 | | Measured at NAV | | Total |
| Cash equivalents | | $ | 45.6 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 45.6 |
| | $ | 53.0 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 53.0 |
|
| Commingled funds | | 497.0 |
| | — |
| | — |
| | 355.3 |
| | 852.3 |
| | 316.2 |
| | — |
| | — |
| | 326.1 |
| | 642.3 |
|
| Debt securities | | — |
| | 241.2 |
| | 1.5 |
| | — |
| | 242.7 |
| | — |
| | 242.3 |
| | — |
| | — |
| | 242.3 |
|
| Equity securities | | 29.7 |
| | — |
| | — |
| | — |
| | 29.7 |
| | 35.2 |
| | — |
| | — |
| | — |
| | 35.2 |
|
| Other | | (41.3 | ) | | 1.7 |
| | — |
| | (6.9 | ) | | (46.5 | ) | | 0.6 |
| | 2.0 |
| | — |
| | (9.9 | ) | | (7.3 | ) |
| Total | | $ | 531.0 |
| | $ | 242.9 |
| | $ | 1.5 |
| | $ | 348.4 |
| | $ | 1,123.8 |
| | $ | 405.0 |
| | $ | 244.3 |
| | $ | — |
| | $ | 316.2 |
| | $ | 965.5 |
|
|
| | | | | | | | |
| (Millions of Dollars) | | Capacity | | Energy (a) |
| 2017 | | $ | 24.3 |
| | $ | 4.4 |
|
| 2018 | | 20.1 |
| | — |
|
| 2019 | | 11.5 |
| | — |
|
| 2020 | | 3.0 |
| | — |
|
| 2021 | | 3.0 |
| | — |
|
| Thereafter | | 16.4 |
| | — |
|
| Total | | $ | 78.3 |
| | $ | 4.4 |
|
| |
(a) | Excludes contingent energy paymentsSee Note 8 for renewable energy PPAs.further information on fair value measurement inputs and methods. |
Additional energy payments under these PPAs and PPAs accounted for as operating leases will be required to meet expected future electric demand.
Leases— PSCo leases a variety of equipment and facilities used in the normal course of business. Three of these leases qualify as capital leases and are accounted for accordingly. 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 termFor each of the contract.
WYCO was formed as 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 operatesfair value hierarchy levels, PSCo’s proportionate allocation of 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 $127.0 million and $132.9 million of capital lease obligations recorded for the arrangement as of Dec. 31, 2016 and 2015, 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 leasetotal postretirement benefit plan assets that were approximately $8.1 million, $8.2 million, and $7.2 million for 2016, 2015 and 2014, respectively. Following is a summary of property held under capital leases:measured at fair value:
|
| | | | | | | | |
| (Millions of Dollars) | | Dec. 31, 2016 | | Dec. 31, 2015 |
| Gas storage facilities | | $ | 200.5 |
| | $ | 200.5 |
|
| Gas pipeline | | 20.7 |
| | 20.7 |
|
| Property held under capital leases | | 221.2 |
| | 221.2 |
|
| Accumulated depreciation | | (65.3 | ) | | (57.2 | ) |
| Total property held under capital leases, net | | $ | 155.9 |
| | $ | 164.0 |
|
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 $118.2 million, $130.5 million and $126.2 million for 2016, 2015 and 2014, respectively. These expenses include capacity payments for PPAs accounted for as operating leases of $102.4 million, $113.5 million and $110.1 million in 2016, 2015 and 2014, 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) | | Operating Leases | | PPA (a) (b) Operating Leases | | Total Operating Leases | | Capital Leases |
| 2017 | | $ | 11.0 |
| | $ | 96.3 |
| | $ | 107.3 |
| | $ | 25.7 |
|
| 2018 | | 10.2 |
| | 96.6 |
| | 106.8 |
| | 25.3 |
|
| 2019 | | 10.3 |
| | 97.5 |
| | 107.8 |
| | 25.1 |
|
| 2020 | | 10.3 |
| | 98.4 |
| | 108.7 |
| | 24.9 |
|
| 2021 | | 9.7 |
| | 99.4 |
| | 109.1 |
| | 23.8 |
|
| Thereafter | | 45.2 |
| | 483.7 |
| | 528.9 |
| | 462.7 |
|
| Total minimum obligation | | | | | | | | 587.5 |
|
| Interest component of obligation | | | | | | | | (431.6 | ) |
| Present value of minimum obligation | | | | | | | | $ | 155.9 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Dec. 31, 2019 (a) | | Dec. 31, 2018 (a) |
| (Millions of Dollars) | | Level 1 | | Level 2 | | Level 3 | | Measured at NAV | | Total | | Level 1 | | Level 2 | | Level 3 | | Measured at NAV | | Total |
| Cash equivalents | | $ | 20.3 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 20.3 |
| | $ | 17.0 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 17.0 |
|
| Insurance contracts | | — |
| | 45.4 |
| | — |
| | — |
| | 45.4 |
| | — |
| | 40.2 |
| | — |
| | — |
| | 40.2 |
|
| Commingled funds | | 61.9 |
| | — |
| | — |
| | 68.0 |
| | 129.9 |
| | 118.7 |
| | — |
| | — |
| | 35.8 |
| | 154.5 |
|
| Debt securities | | — |
| | 203.4 |
| | 1.0 |
| | — |
| | 204.4 |
| | — |
| | 159.7 |
| | — |
| | — |
| | 159.7 |
|
| Equity securities | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Other | | — |
| | 0.5 |
| | — |
| | — |
| | 0.5 |
| | — |
| | 0.7 |
| | — |
| | — |
| | 0.7 |
|
| Total | | $ | 82.2 |
| | $ | 249.3 |
| | $ | 1.0 |
| | $ | 68.0 |
| | $ | 400.5 |
| | $ | 135.7 |
| | $ | 200.6 |
| | $ | — |
| | $ | 35.8 |
| | $ | 372.1 |
|
| |
(a) | Amounts do not include PPAs accountedSee Note 8 for as executory contracts. |
| |
(b)
| PPA operating leases contractually expire through 2032.further information on fair value measurement inputs and methods. |
Variable Interest Entities— The accounting guidanceImmaterial assets were transferred in or out of Level 3 for consolidation2019. No assets were transferred in or out 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.Level 3 for 2018.
PPAsFunded Status — 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 termsComparisons of the contract, control over O&M, control over dispatchactuarially computed benefit obligation, changes in plan assets and funded status of electricity, historicalthe pension and estimated future fuelpostretirement health care plans for Xcel Energy are as follows:
|
| | | | | | | | | | | | | | | | |
| | | Pension Benefits | | Postretirement Benefits |
| (Millions of Dollars) | | 2019 | | 2018 | | 2019 | | 2018 |
| Change in Benefit Obligation: | | | | | | | | |
| Obligation at Jan. 1 | | $ | 1,229.3 |
| | $ | 1,334.2 |
| | $ | 376.5 |
| | $ | 429.2 |
|
| Service cost | | 25.6 |
| | 29.0 |
| | 0.5 |
| | 0.7 |
|
| Interest cost | | 51.6 |
| | 47.3 |
| | 15.6 |
| | 15.0 |
|
| Plan amendments | | — |
| | — |
| | — |
| | — |
|
| Actuarial loss (gain) | | 108.2 |
| | (96.5 | ) | | 12.7 |
| | (40.6 | ) |
| Plan participants’ contributions | | — |
| | — |
| | 6.6 |
| | 6.5 |
|
| Medicare subsidy reimbursements | | — |
| | — |
| | 1.6 |
| | 0.9 |
|
| Benefit payments | | (84.9 | ) | | (84.7 | ) | | (33.5 | ) | | (35.2 | ) |
| Obligation at Dec. 31 | | $ | 1,329.8 |
| | $ | 1,229.3 |
| | $ | 380.0 |
| | $ | 376.5 |
|
| Change in Fair Value of Plan Assets: | | | | | | | | |
| Fair value of plan assets at Jan. 1 | | $ | 965.5 |
| | $ | 1,079.4 |
| | $ | 372.1 |
| | $ | 406.4 |
|
| Actual return on plan assets | | 197.4 |
| | (50.9 | ) | | 51.0 |
| | (11.1 | ) |
| Employer contributions | | 45.8 |
| | 21.7 |
| | 4.3 |
| | 5.5 |
|
| Plan participants’ contributions | | — |
| | — |
| | 6.6 |
| | 6.5 |
|
| Benefit payments | | (84.9 | ) | | (84.7 | ) | | (33.5 | ) | | (35.2 | ) |
| Fair value of plan assets at Dec. 31 | | $ | 1,123.8 |
| | $ | 965.5 |
| | $ | 400.5 |
| | $ | 372.1 |
|
| Funded status of plans at Dec. 31 | | $ | (206.0 | ) | | $ | (263.8 | ) | | $ | 20.5 |
| | $ | (4.4 | ) |
| Amounts recognized in the Consolidated Balance Sheet at Dec. 31: | | | | | | | | |
| Noncurrent liabilities | | (206.0 | ) | | (263.8 | ) | | 20.5 |
| | (4.4 | ) |
| Net amounts recognized | | $ | (206.0 | ) | | $ | (263.8 | ) | | $ | 20.5 |
| | $ | (4.4 | ) |
| Significant Assumptions Used to Measure Benefit Obligations: | | | | | | | | |
| Discount rate for year-end valuation | | 3.49 | % | | 4.31 | % | | 3.47 | % | | 4.32 | % |
| Expected average long-term increase in compensation level | | 3.75 |
| | 3.75 |
| | N/A |
| | N/A |
|
| Mortality table | | Pri-2012 |
| | RP-2014 |
| | Pri-2012 |
| | RP-2014 |
|
Health care costs trend rate — initial: Pre-65 | | N/A |
| | N/A |
| | 6.00 | % | | 6.50 | % |
Health care costs trend rate — initial: Post-65 | | N/A |
| | N/A |
| | 5.10 | % | | 5.30 | % |
Ultimate trend assumption — initial: Pre-65 | | N/A |
| | N/A |
| | 4.50 | % | | 4.50 | % |
Ultimate trend assumption — initial: Post-65 | | N/A |
| | N/A |
| | 4.50 | % | | 4.50 | % |
| Years until ultimate trend is reached | | N/A |
| | N/A |
| | 3 |
| | 4 |
|
Accumulated benefit obligation for the pension plan was $1,267.2 million and 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 and 1,802 MW of capacity under long-term PPAs$1,183.3 million as of Dec. 31, 2016,2019 and 2015, respectively, with entities that have been determined to be variable interest entities. These agreements have expiration dates through the year 2032.2018, respectively.
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 fromNet Periodic Benefit Cost (Credit) — Net periodic benefit cost (credit) 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.
MGP Sites— PSCo is currently involved in investigating and/or remediating several MGP sites where regulated materials may have been deposited. PSCo has identified two sites where former MGP activities have or may have resulted in site contamination and are under current investigation and/or remediation. At some or all of these MGP sites, there are other parties that may have responsibility for some portion of any remediation. PSCo anticipates that the majority of the remediation at these sites will continue through at least 2017. PSCo had accrued $1.7 million for both of these sites at Dec. 31, 2016 and 2015, 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.
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 and disposal of coal combustion residuals (“CCR” or coal ash) as a nonhazardous waste. In December 2016, the Water Infrastructure Improvements for the Nation Act (WIIN Act) was signed into law, which includes provisions that allow the CCR rule to be implemented through a state or federal based permit program and that give the EPA direct enforcement authority. PSCo is in the process of evaluating whether the costs of implementing the CCR rule under the potential federal and/or state permit programs could have a material impact on the results of operations, financial position or cash flows.
In 2015, industry and environmental non-governmental organizations sought judicial review of the final CCR rule. In June 2016, the D.C. Circuit issued an order remanding and vacating certain elements of the rule as a result of partial settlements with these parties. A final court decision is anticipated in the first half of 2017. Until a final decision is reached in the case, it is uncertain whether the litigation or partial settlements will have any significant impact on results of operations, financial position or cash flows on PSCo. PSCo believes that these associated costs would be recoverable through regulatory mechanisms.
Federal Clean Water Act (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. PSCo estimates that the capital cost to comply with the ELG rule will range from $9 million to $21 million, and could change as PSCo continues to assess alternate compliance technologies. PSCo believes that compliance costs would be recoverable through regulatory mechanisms.
Federal CWA Section 316(b) — Section 316(b) of 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). The timing of compliance with the requirements will vary from plant-to-plant since the new rule does not have a final compliance deadline. PSCo does not anticipate the cost of compliance will have a material impact on the results of operations, financial position or cash flows.
Federal CWA Waters of the United States Rule —In June 2015, the EPA and the U.S. Army Corps of Engineers published a final rule that significantly expands the types of water bodies regulated under the CWA and broadens the scope of waters subject to federal jurisdiction. The expansion of the term “Waters of the U.S.” will subject more utility projects to federal CWA jurisdiction, thereby potentially delaying the siting of new generation projects, pipelines, transmission lines and distribution lines, as well as increasing project costs and expanding permitting and reporting requirements. 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 rulingservice cost component is expected by June 2017.
Air
GHG Emission Standard for Existing Sources (Clean Power Plan or CPP) — In 2015, a final rule was published by the EPA for GHG emission standards for existing power plants. Under the rule, states were required to develop implementation plans by September 2016, with the possibility of an extension to September 2018, or submit to a federal plan for the state prepared by the EPA. Amongincluded in other things, the rule requires that state plans include enforceable measures to ensure emissions from existing power plants achieve the EPA’s state-specific interim (2022-2029) and final (2030 and thereafter) emission performance targets. The CPP was challenged by multiple parties in the D.C. Circuit Court. In January 2016, the D.C. Circuit Court denied requests to stay the effectiveness of the rule. In February 2016, the U.S. Supreme Court issued an order staying the final CPP rule. In September 2016, the D.C. Circuit Court heard oral argumentsincome in the consolidated challenges to the CPP. The stay will remain in effect until the D.C. Circuit Court reaches its decisionstatement of income.
Components of net periodic benefit cost (credit) and the U.S. Supreme Court either declines to review the lower court’s decision or reaches a decision of its own. During the pendency of the stay, states are not required to submit implementation plansamounts recognized in other comprehensive income and the EPA will not enforce deadlines or issue a federal plan for any state. Colorado is continuing formal planning efforts.regulatory assets and liabilities:
PSCo has undertaken a number of initiatives that reduce GHG emissions and respond to state renewable and energy efficiency goals. The CPP could require additional emission reductions in Colorado. If the state plan does not provide credit for the investments PSCo has already made to reduce GHG emissions, or if it requires additional initiatives or emission reductions, then its requirements would potentially impose additional substantial costs. Until PSCo has more information about a SIP or the EPA finalizes its proposed federal plan for the states that do not develop related plans, PSCo cannot predict the costs of compliance with the final rule once it takes effect. PSCo believes compliance costs will be recoverable through regulatory mechanisms. If PSCo’s regulators do not allow recovery of all or a part of the cost of capital investment or the O&M costs incurred to comply with the CPP or cost recovery is not provided in a timely manner, it could have a material impact on results of operations, financial position or cash flows.
Implementation of the NAAQS for SO2 — The EPA adopted a more stringent NAAQS for SO2 in 2010. The EPA is requiring states to evaluate areas in three phases. The first phase includes areas near PSCo’s Pawnee plant. The Pawnee plant recently installed an SO2 scrubber to reduce SO2 emissions. In June 2016, the EPA issued final designations which found the area near the Pawnee plant is “unclassifiable.” It is anticipated that the area near the Pawnee plant will be able to show compliance with the NAAQS through air dispersion modeling performed by the Colorado Department of Public Health and Environment.
The areas near the remaining PSCo power plants, Comanche and Hayden, which utilize scrubbers to control SO2 emissions, will be evaluated in the next designation phase, ending December 2017. In late 2016, PSCo submitted air dispersion modeling to the Colorado Department of Public Health and Environment and the EPA which demonstrated that PSCo’s Comanche and Hayden plants comply with the NAAQS. If an area is designated nonattainment in 2020, the states will need to evaluate all SO2 sources in the area. The state would then submit an implementation plan, which would be due by 2022, designed to achieve the NAAQS by 2025. PSCo cannot evaluate the impacts until the designation of nonattainment areas is made and any required state plan has been developed. PSCo believes that should SO2 control systems require upgrades for a plant, compliance costs or the costs of alternative cost-effective generation will be recoverable through regulatory mechanisms and therefore does not expect a material impact on results of operations, financial position or cash flows.
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. The Denver Metropolitan Area is currently not meeting the prior ozone standard and will therefore not meet the new, more stringent, standard, however PSCo’s scheduled retirement of coal fired plants in Denver should help in any plan to mitigate non-attainment.
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, 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 ash-containment facilities such as bottom 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 an ARO for the retirement costs of natural gas mains and lines and for the retirement of above ground gas gathering, extraction 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 many small potential obligations associated with PCBs, mineral oil, storage tanks, lithium batteries, mercury and street lighting lamps. The electric and common general AROs include small obligations related to storage tanks and radiation sources.
In April 2015, the EPA published the final rule regulating the management and disposal of coal combustion byproducts (e.g., coal ash) as a nonhazardous waste to the Federal Register. The rule became effective in October 2015. The estimated costs to comply with the final rule were incorporated into the cash flow revisions in 2015.
A reconciliation of PSCo’s AROs for the years ended Dec. 31, 2016 and 2015 is as follows: |
| | | | | | | | | | | | | | | | | | | | |
| (Thousands of Dollars) | | Beginning Balance Jan. 1, 2016 | | Liabilities
Recognized | | Accretion | | Cash Flow Revisions (a) | | Ending Balance Dec. 31, 2016 (b) |
| Electric plant | | | | | | | | | | |
| Steam and other production asbestos | | $ | 38,676 |
| | $ | — |
| | $ | 1,877 |
| | $ | (103 | ) | | $ | 40,450 |
|
| Steam and other production ash containment | | 70,767 |
| | — |
| | 3,078 |
| | (1,245 | ) | | 72,600 |
|
| Wind production | | 1,992 |
| | — |
| | 19 |
| | 61 |
| | 2,072 |
|
| Electric distribution | | 1,130 |
| | — |
| | 45 |
| | 6,494 |
| | 7,669 |
|
| Other | | 1,054 |
| | 214 |
| | 46 |
| | 206 |
| | 1,520 |
|
| Natural gas plant | | | | | | | | | | |
| Gas transmission and distribution | | 122,168 |
| | — |
| | 5,009 |
| | 33,542 |
| | 160,719 |
|
| Other | | 3,925 |
| | — |
| | 155 |
| | — |
| | 4,080 |
|
| Common and other property | | | | | | | | | | |
| Common miscellaneous | | 796 |
| | — |
| | 28 |
| | (371 | ) | | 453 |
|
| Total liability | | $ | 240,508 |
| | $ | 214 |
| | $ | 10,257 |
| | $ | 38,584 |
| | $ | 289,563 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Pension Benefits | | Postretirement Benefits |
| (Millions of Dollars) | | 2019 | | 2018 | | 2017 | | 2019 | | 2018 | | 2017 |
| Service cost | | $ | 25.6 |
| | $ | 29.0 |
| | $ | 27.3 |
| | $ | 0.5 |
| | $ | 0.7 |
| | $ | 0.7 |
|
| Interest cost | | 51.6 |
| | 47.3 |
| | 50.6 |
| | 15.6 |
| | 15.0 |
| | 16.8 |
|
| Expected return on plan assets | | (68.5 | ) | | (68.5 | ) | | (68.5 | ) | | (18.9 | ) | | (22.7 | ) | | (21.9 | ) |
| Amortization of prior service credit | | (3.4 | ) | | (3.4 | ) | | (3.2 | ) | | (5.4 | ) | | (6.2 | ) | | (6.2 | ) |
| Amortization of net loss | | 25.4 |
| | 31.2 |
| | 28.3 |
| | 2.9 |
| | 4.0 |
| | 3.8 |
|
Settlement charge (a) | | 3.2 |
| | 4.5 |
| | — |
| | — |
| | — |
| | — |
|
| Net periodic pension cost (credit) | | 33.9 |
| | 40.1 |
| | 34.5 |
| | (5.3 | ) | | (9.2 | ) | | (6.8 | ) |
| Costs (credits) not recognized due to effects of regulation | | 3.5 |
| | (3.9 | ) | | (2.7 | ) | | 1.2 |
| | 1.8 |
| | — |
|
| Net benefit cost (credit) recognized for financial reporting | | $ | 37.4 |
| | $ | 36.2 |
| | $ | 31.8 |
| | $ | (4.1 | ) | | $ | (7.4 | ) | | $ | (6.8 | ) |
| Significant Assumptions Used to Measure Costs: | | | | | | | | | | | | |
| Discount rate | | 4.31 | % | | 3.63 | % | | 4.13 | % | | 4.32 | % | | 3.62 | % | | 4.13 | % |
| Expected average long-term increase in compensation level | | 3.75 |
| | 3.75 |
| | 3.75 |
| | N/A |
| | N/A |
| | N/A |
|
| Expected average long-term rate of return on assets | | 6.84 |
| | 6.84 |
| | 6.84 |
| | 4.50 |
| | 5.30 |
| | 5.80 |
|
| |
(a) | A settlement charge is required when the amount of all lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In 2016, AROs were revised for changes2019 and 2018, as a result of lump-sum distributions during the 2019 and 2018 plan years, PSCo recorded a total pension settlement charge of $3.2 million and $4.5 million in estimated cash flows2019 and the timing2018. A total of those cash flows. Changes$0.1 million and $0.2 million of that amount was recorded in the gas transmissionincome statement in 2019 and distribution AROs were mainly related to increased miles of gas mains.2018, respectively. |
Pension costs include an expected return impact for the current year that may differ from actual investment performance in the plan. Return assumption used for 2020 pension cost calculations is 6.84%.
|
| | | | | | | | | | | | | | | | |
| | | Pension Benefits | | Postretirement Benefits |
| (Millions of Dollars) | | 2019 | | 2018 | | 2019 | | 2018 |
| Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: | | | | | | | | |
| Net loss | | $ | 481.5 |
| | $ | 530.8 |
| | $ | 44.6 |
| | $ | 66.9 |
|
| Prior service credit | | (3.8 | ) | | (7.2 | ) | | (9.9 | ) | | (15.3 | ) |
| Total | | $ | 477.7 |
| | $ | 523.6 |
| | $ | 34.7 |
| | $ | 51.6 |
|
| Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates: | | | | | | | | |
| Current regulatory assets | | $ | 22.3 |
| | $ | 25.8 |
| |
| | $ | — |
|
| Noncurrent regulatory assets | | 452.1 |
| | 497.5 |
| | 34.7 |
| | 51.6 |
|
| Deferred income taxes | | 0.8 |
| | 0.1 |
| | — |
| | — |
|
| Net-of-tax accumulated other comprehensive income | | 2.5 |
| | 0.2 |
| | — |
| | — |
|
| Total | | $ | 477.7 |
| | $ | 523.6 |
| | $ | 34.7 |
| | $ | 51.6 |
|
|
| | | | | | | | |
(b)
Measurement date | There were no ARO liabilities settled during the year ended | Dec. 31, 2016. |
|
| | | | | | | | | | | | | | | | |
| (Thousands of Dollars) | | Beginning Balance Jan. 1, 2015 | | Accretion | | Cash Flow Revisions (a) | | Ending Balance Dec. 31, 2015 (b) |
| Electric plant | | | | | | | | |
| Steam and other production asbestos | | $ | 36,856 |
| | $ | 1,820 |
| | $ | — |
| | $ | 38,676 |
|
| Steam and other production ash containment | | 61,885 |
| | 2,769 |
| | 6,113 |
| | 70,767 |
|
| Wind production | | 2,095 |
| | 18 |
| | (121 | ) | | 1,992 |
|
| Electric distribution | | 1,182 |
| | 47 |
| | (99 | ) | | 1,130 |
|
| Other | | 1,150 |
| | 46 |
| | (142 | ) | | 1,054 |
|
| Natural gas plant | | | | | | | | |
| Gas transmission and distribution | | 117,474 |
| | 4,694 |
| | — |
| | 122,168 |
|
| Other | | 3,886 |
| | 153 |
| | (114 | ) | | 3,925 |
|
| Common and other property | | | | | | | | |
| Common miscellaneous | | 768 |
| | 28 |
| | — |
| | 796 |
|
| Total liability | | $ | 225,296 |
| | $ | 9,575 |
| | $ | 5,637 |
| | $ | 240,508 |
|
| 2019 | |
(a)
| In 2015, AROs were revised for changes in estimated cash flows and the timing of those cash flows. Changes in the ash containment ARO were mainly related to the final coal ash rule mentioned above. |
| |
(b)
| There were no ARO liabilities recognized or settled during the year ended Dec. 31, 2015.2018 | | Dec. 31, 2019 | | Dec. 31, 2018 |
Cash Flows — Cash funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other calculations prescribed by the funding requirements of income tax and other pension-related regulations. Required contributions were made in 2017 - 2020 to meet minimum funding requirements. Total voluntary and required pension funding contributions across all 4 of Xcel Energy’s pension plans were as follows:
Indeterminate AROs— Outside$150 million in January 2020, of the knownwhich $50 million was attributable to PSCo;
$154 million in 2019, of which $46 million was attributable to PSCo;
$150 million in 2018, of which $22 million was attributable to PSCo; and recorded asbestos AROs,
$162 million in 2017, of which $18 million was attributable to PSCo.
The postretirement health care plans have no funding requirements 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, 2016. Therefore, an ARO has not been recorded for these facilities.
Removal Costs — PSCo records a regulatory liability for the plant removal costs of generation, transmissionthan fulfilling benefit payment obligations, when claims are presented and distribution facilities thatapproved. Additional cash funding requirements are recovered currently in rates. Generally, the accrual of future non-ARO removal obligations is not required. However, long-standing ratemaking practices approvedprescribed by applicablecertain state and federal rate regulatory commissions have allowed provisionsauthorities.
Xcel Energy expects to contribute approximately $10 million during 2020, of which amounts attributable to PSCo will be 0.
Xcel Energy, which includes PSCo, contributed:
$15 million during 2019, of which $4 million was attributable to PSCo;
$11 million during 2018, of which $5 million was attributable to PSCo; and
$20 million during 2017, of which $5 million was attributable to PSCo.
Targeted asset allocations:
|
| | | | | | | | | | | | |
| | | Pension Benefits | | Postretirement Benefits |
| | | 2019 | | 2018 | | 2019 | | 2018 |
| Domestic and international equity securities | | 37 | % | | 35 | % | | 15 | % | | 18 | % |
| Long-duration fixed income securities | | 30 |
| | 32 |
| | — |
| | — |
|
| Short-to-intermediate fixed income securities | | 14 |
| | 16 |
| | 72 |
| | 70 |
|
| Alternative investments | | 17 |
| | 15 |
| | 9 |
| | 8 |
|
| Cash | | 2 |
| | 2 |
| | 4 |
| | 4 |
|
| Total | | 100 | % | | 100 | % | | 100 | % | | 100 | % |
Plan Amendments — The Xcel Energy Pension Plan and Xcel Energy Inc. Nonbargaining Pension Plan (South), which includes PSCo, were amended in 2017 to reduce supplemental benefits for such costs in historical depreciation rates. These removal costs have accumulated overnon-bargaining participants as well as to allow the transfer of a numberportion of years based on varying rates as authorized bynon-qualified pension obligations into the appropriate regulatory entities. Givenqualified plans.
In 2018, the long time periods overPSCo postretirement plan was amended to add the 5% cash balance formula.
In 2019, there were no plan amendments made which affected 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, 2016 and 2015 were $367 million and $364 million, respectively.projected benefit obligation.
Projected Benefit Payments
PSCo’s projected benefit payments:
|
| | | | | | | | | | | | | | | | |
| (Millions of Dollars) | | Projected Pension
Benefit Payments | | Gross Projected
Postretirement
Health Care
Benefit Payments | | Expected Medicare
Part D Subsidies | | Net Projected
Postretirement
Health Care
Benefit Payments |
| 2020 | | $ | 82.0 |
| | $ | 30.5 |
| | $ | 1.9 |
| | $ | 28.6 |
|
| 2021 | | 81.9 |
| | 30.3 |
| | 2.0 |
| | 28.3 |
|
| 2022 | | 82.3 |
| | 29.8 |
| | 2.1 |
| | 27.7 |
|
| 2023 | | 82.7 |
| | 29.4 |
| | 2.2 |
| | 27.2 |
|
| 2024 | | 82.4 |
| | 28.8 |
| | 2.2 |
| | 26.6 |
|
| 2025-2029 | | 402.9 |
| | 129.9 |
| | 12.1 |
| | 117.8 |
|
Legal ContingenciesDefined Contribution Plans
Xcel Energy, which includes PSCo, maintains 401(k) and other defined contribution plans that cover most employees. Total expense to these plans for PSCo was approximately $11 million in 2019 and 2018, respectively, and $10 million in 2017.
|
|
| 10. Commitments and Contingencies |
Legal
PSCo is involved in various litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves 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 sometimesmay be 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 CommercialGas Trading Litigation
Pacific Northwest FERC Refund Proceeding —A complaint with the FERC posed that sales madee prime is a wholly owned subsidiary of Xcel Energy Inc. e prime was in the Pacific Northwestbusiness of natural gas trading and marketing but has not engaged in 2000natural gas trading or marketing activities since 2003. Multiple lawsuits involving multiple plaintiffs seeking monetary damages were commenced against e prime and 2001 through bilateral contractsits affiliates, including Xcel Energy, between 2003 and 2009 alleging fraud and anticompetitive activities in conspiring to restrain the trade of natural gas and manipulate natural gas prices. Cases were unjustall consolidated in the U.S. District Court in Nevada.
NaN cases remain active which include an MDL matter consisting of a Colorado purported class (Breckenridge) and unreasonable undera Wisconsin purported class (Arandell Corp.).
Breckenridge/Colorado — In February 2019, the Federal Power Act. The City of Seattle (the City) alleged between $34 millionMDL panel remanded Breckenridge back to $50 millionthe U.S. District Court in sales with PSCo were subject to refund.Colorado.
Arandell Corp. — In 2003,February 2019, the FERC terminated the proceeding, although itcase was later remanded back to the FERCU.S. District Court in 2007 by the U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit).Wisconsin.
In May 2015, the FERC rejected the City’s claim that any of the sales made resulted in an excessive burden andXcel Energy has concluded that the City failed to establish a causal link between any contracts and any claimed unlawful market activity. In February 2016, the City appealed this decision to the Ninth Circuit.loss is remote for both remaining lawsuits.
In October 2016, a settlement was reached that resolved all outstanding claims between and among the City and the respondents, including PSCo. Settlement terms required PSCo to pay the City $15,000 and the City to withdraw its pending appeal with the Ninth Circuit. These terms have been met, bringing this matter to a close.
Line Extension Disputes — In December 2015, Development Recovery Company (DRC)the DRC filed a lawsuit seeking monetary damages in the Denver StateDistrict 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.agreements. The dispute involves assigned interests in those claims by over fifty50 developers. In May 2016,February 2018, the district court granted PSCo’sColorado Supreme Court denied DRC’s petition to appeal the Denver District Court’s dismissal of the lawsuit, effectively terminating this litigation. However, in January 2018, DRC filed a new lawsuit in Boulder County District Court, asserting a single claim that PSCo was required to file its line extension agreements with the CPUC but failed to do so.
This claim is similar to the arguments previously raised by the DRC. PSCo filed a motion to dismiss this claim, which was granted in May 2018. The DRC subsequently filed an appeal to the Colorado Court of Appeals. In November 2019, the Colorado Court of Appeals issued an opinion affirming dismissal of the lawsuit concluding that jurisdiction over this dispute resides withbased upon lack of subject matter jurisdiction. The Colorado Court of Appeals did not address the CPUC. In June 2016, DRC filed a noticesecond issue based upon issue preclusion. Finally, the Colorado Court of appeal.Appeals remanded the case to the Boulder District Court to consider PSCo’s request for an award of costs, which it concluded does not include attorneys’ fees. The matter has been fully briefed and plaintiff has requested oral arguments. DRC also brought a proceeding before the CPUC as assignee on behalf of two developers, Ryland Homes and Richmond Homes of Colorado. In March 2016, the ALJ issued an order rejecting DRC’s claims for additional allowances and refunds. In June 2016, the ALJ’s determination was approved by the CPUC. DRC did not file a requestpetition for reconsideration beforea Writ of Certiorari to the CPUC contestingColorado Supreme Court by the decision, but filedDec. 26, 2019 deadline effectively terminating this litigation.
Environmental
New and changing federal and state environmental mandates can create financial liabilities for PSCo, which are normally recovered through the regulated rate process.
Site Remediation— Various federal and state environmental laws impose liability where hazardous substances or other regulated materials have been released to the environment. PSCo may sometimes pay all or a portion of the cost to remediate sites where past activities of PSCo’s predecessors or other parties have caused environmental contamination. Environmental contingencies could arise from various situations, including sites of former MGPs; and third-party sites, such as landfills, for which PSCo is alleged to have sent wastes to that site.
MGP, Landfill or Disposal Sites— PSCo is cooperating with the City of Denver on an appealenvironmental investigation of the Rice Yards Site in Denver, District CourtColorado, which had various historic industrial uses by multiple parties, including railroad, maintenance shop, scrap metal yard, and MGP operations.
The area is being redeveloped into residential and commercial mixed uses, and PSCo is in August 2016. DRC fileddiscussions with the current property owner regarding legal claims related to the Rice Yards Site.
In addition, PSCo is currently investigating or remediating 2 other MGP, landfill or other disposal sites across its brief in February 2017 and PSCo’s answer brief will be due March 2017.
service territories.
PSCo has concludedrecognized its best estimate of costs/liabilities that will result from final resolution of these issues, however, the outcome and timing is unknown. In addition, there may be insurance recovery and/or recovery from other potentially responsible parties, offsetting a lossportion of costs incurred.
Environmental Requirements — Water and Waste
Coal Ash Regulation— PSCo’s operations are subject to federal and state laws that impose requirements for handling, storage, treatment and disposal of solid waste.Under the CCR Rule, utilities are required to complete groundwater sampling around their CCR landfills and surface impoundments. Currently, PSCo has 6 regulated ash units in operation.
PSCo is remoteconducting groundwater sampling and, where appropriate, initiating the assessment of corrective measures and evaluating whether corrective action is required at any CCR landfills or surface impoundments. In 2019, groundwater monitoring consistent with respectthe CCR Rule was conducted. Statistically significant increase above background concentration was detected at 4 locations. Subsequently, assessment monitoring samples were collected, and PSCo is evaluating the results to determine whether corrective action is required. Until PSCo completes its assessment, it is uncertain what impact, if any, there will be on the operations, financial condition or cash flows.
In August 2018, the United States Court of Appeals for the District of Columbia Circuit ruled that the EPA cannot allow utilities to continue to use unlined impoundments (including clay lined impoundments) for the storage or disposal of coal ash. In November 2019, the EPA proposed rules in response to this matterdecision that, if finalized in their current form, may require PSCo to expedite closure of 1 coal ash impoundment.
Closure costs for existing impoundments are included in the calculation of the ARO liability.
See Note 10 for further information.
Federal CWA WOTUS Rule —In 2015, the EPA and U.S. Army Corps of Engineers published a final rule that significantly broadened the scope of waters under the CWA that are subject to federal jurisdiction, referred to as “WOTUS”. In 2019, the service agreements were developedEPA repealed the 2015 rule and published a draft replacement rule. Until a final rule is issued, PSCo cannot estimate potential impacts, but anticipates costs will be recoverable through regulatory mechanisms.
Federal CWA ELG — In 2015, the EPA issued a final ELG rule for power plants that discharge treated effluent to implement CPUC approved tariffssurface waters as well as utility-owned landfills that receive CCRs. In 2017, the EPA delayed the compliance date for flue gas desulfurization wastewater and bottom ash transport until November 2020. After 2020, PSCo has complied with the tariff provisions. Also, ifestimates that ELG compliance will cost approximately $1.5 million to complete. The EPA, however, is conducting a loss were sustained,rulemaking process to revise certain effluent limitations and pretreatment standards, which may impact compliance costs. PSCo believes it would be allowed to recoveranticipates these costs will be fully recoverable through traditional regulatory mechanisms.
Federal CWA Section 316(b) — The amount or rangefederal CWA requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available for minimizing impingement and entrainment of aquatic species. PSCo estimates the likely cost for complying with impingement and entrainment requirements is immaterial. PSCo anticipates these costs will be fully recoverable through regulatory mechanisms.
Environmental Requirements — Air
Regional Haze Rules — The regional haze program requires sulfur dioxide, nitrogen oxide and particulate matter emission controls at power plants to reduce visibility impairment in dispute is presently unknownnational parks and no accrual haswilderness areas. The program includes reasonable further progress. The requirements of the first regional haze plans developed by Colorado have been approved and implemented.
AROs — AROs have been recorded for this matter.
Other Contingencies
See Note 11 for further discussion.
| |
13. | Regulatory Assets and Liabilities |
PSCo’s assets.
PSCo’s consolidated financial statements are prepared in accordance with the applicable accounting guidance,AROs were 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.
The components of regulatory assets shown on the consolidated balance sheets of PSCo at Dec. 31, 2016 and 2015 are:follows:
|
| | | | | | | | | | | | | | | | | | | | | |
| (Thousands of Dollars) | | See Note(s) | �� | Remaining
Amortization Period | | Dec. 31, 2016 | | Dec. 31, 2015 |
| Regulatory Assets | | | | | | Current | | Noncurrent | | Current | | Noncurrent |
Pension and retiree medical obligations (a) | | 8 |
| | Various | | $ | 27,270 |
| | $ | 568,258 |
| | $ | 29,260 |
| | $ | 497,973 |
|
| Recoverable deferred taxes on AFUDC recorded in plant | | 1 |
| | Plant lives | | — |
| | 151,022 |
| | — |
| | 144,953 |
|
| Depreciation differences | | 1 |
| | Pending rate case | | 15,363 |
| | 90,426 |
| | 14,221 |
| | 99,835 |
|
Net AROs (b) | | 1, 12 |
| | Plant lives | | — |
| | 78,050 |
| | — |
| | 62,948 |
|
| Purchased power contract costs | | 12 |
| | Term of related contract | | 1,035 |
| | 29,029 |
| | 1,319 |
| | 29,143 |
|
Conservation programs (c) | | 1, 11 |
| | One to two years | | 9,262 |
| | 6,986 |
| | 8,466 |
| | 6,947 |
|
| Losses on reacquired debt | | 4 |
| | Term of related debt | | 1,203 |
| | 6,120 |
| | 1,421 |
| | 6,957 |
|
Contract valuation adjustments (d) | | 10 |
| | Term of related contract | | 3,444 |
| | 6,082 |
| | 9,376 |
| | 9,526 |
|
| Gas pipeline inspection costs | | 12 |
| | Two years | | — |
| | 4,405 |
| | 3,611 |
| | — |
|
| Property tax | | | | Various | | 9,393 |
| | 1,653 |
| | 21,558 |
| | 14,428 |
|
| CACJA recovery rider | | | | Less than one year | | 24,260 |
| | — |
| | — |
| | 20,020 |
|
| Other | | | | Various | | 12,553 |
| | 16,398 |
| | 2,840 |
| | 13,545 |
|
| Total regulatory assets | | | | | | $ | 103,783 |
| | $ | 958,429 |
| | $ | 92,072 |
| | $ | 906,275 |
|
|
| | | | | | | | | | | | | | | | |
| | | 2019 |
(Millions of Dollars) | | Jan. 1, 2019 | | Accretion | | Cash Flow Revisions (a) | | Dec. 31, 2019 (b) |
| Electric | | | | | | | | |
| Steam, hydro and other production | | $ | 102.2 |
| | $ | 4.9 |
| | $ | (7.3 | ) | | $ | 99.8 |
|
| Wind | | 14.5 |
| | 0.8 |
| | 1.1 |
| | 16.4 |
|
| Distribution | | 13.4 |
| | 0.6 |
| | — |
| | 14.0 |
|
| Miscellaneous | | 3.2 |
| | — |
| | (3.2 | ) | | — |
|
| Natural gas | | | | | | | | |
| Transmission and distribution | | 200.9 |
| | 8.9 |
| | (19.4 | ) | | 190.4 |
|
| Miscellaneous | | 4.0 |
| | 0.1 |
| | (1.2 | ) | | 2.9 |
|
| Common | | | | | | | | |
| Miscellaneous | | 0.5 |
| | — |
| | — |
| | 0.5 |
|
| Total liability | | $ | 338.7 |
| | $ | 15.3 |
| | $ | (30.0 | ) | | $ | 324.0 |
|
| |
(a) | Includes $4.2 millionIn 2019, AROs were revised for changes in timing and $4.4 millionestimates of regulatory assetscash flows. Changes in gas transmission and distribution AROs were primarily related to increased gas line mileage and number of services, which were more than offset by decreased inflation rates. Changes in steam, hydro, and other production AROs primarily related to the nonqualified pension plan,cost estimates to remediate ponds at production facilities. |
| |
(b) | There were no ARO amounts incurred or settled in 2019. |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2018 |
(Millions of Dollars) | | Jan. 1, 2018 | | Amounts Incurred (a) | | Amounts Settled (b) | | Accretion | | Cash Flow Revisions (c) | | Dec. 31, 2018 |
| Electric | | | | | | | | | | | | |
| Steam, hydro and other production | | $ | 103.2 |
| | $ | — |
| | $ | (7.1 | ) | | $ | 4.7 |
| | $ | 1.4 |
| | $ | 102.2 |
|
| Wind | | 2.1 |
| | 12.3 |
| | — |
| | 0.1 |
| | — |
| | 14.5 |
|
| Distribution | | 7.9 |
| | — |
| | — |
| | 0.3 |
| | 5.2 |
| | 13.4 |
|
| Miscellaneous | | 1.4 |
| | — |
| | (0.1 | ) | | 0.1 |
| | 1.8 |
| | 3.2 |
|
| Natural gas | | | | | | | | | | | | |
| Transmission and distribution | | 228.9 |
| | — |
| | — |
| | 9.3 |
| | (37.3 | ) | | 200.9 |
|
| Miscellaneous | | 3.9 |
| | — |
| | — |
| | 0.1 |
| | — |
| | 4.0 |
|
| Common | | | | | | | | | | | | |
| Miscellaneous | | 0.4 |
| | — |
| | — |
| | 0.1 |
| | — |
| | 0.5 |
|
| Total liability | | $ | 347.8 |
| | $ | 12.3 |
| | $ | (7.2 | ) | | $ | 14.7 |
| | $ | (28.9 | ) | | $ | 338.7 |
|
| |
(a) | Amounts incurred related to the Rush Creek wind farm, which was placed in service in 2018. |
| |
(b) | Amounts settled related to closure of certain ash containment facilities. |
| |
(c) | In 2018, AROs were revised for changes in timing and estimates of cash flows. Changes in gas transmission and distribution AROs were primarily related to increased gas line mileage and number of services, which $0.4were more than offset by increased discount rates. Changes in electric distribution AROs were primarily related to increased labor costs. |
Indeterminate AROs— Outside of the recorded asbestos AROs, other plants or buildings may contain asbestos due to the age of many of PSCo’s facilities, but no confirmation or measurement of the cost of removal could be determined as of Dec. 31, 2019. Therefore, an ARO has not been recorded for these facilities.
Removal Costs — PSCo records a regulatory liability for the plant removal costs that are recovered currently in rates. Removal costs have accumulated based on varying rates as authorized by the appropriate regulatory entities. PSCo has estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates. Removal costs as of Dec. 31, 2019 and 2018 were $350.8 million and $344.4 million, respectively.
Leases
PSCo evaluates contracts that may contain leases, including PPAs and arrangements for the use of office space and other facilities, vehicles and equipment. Under ASC Topic 842, adopted by PSCo on Jan. 1, 2019, a contract contains a lease if it conveys the exclusive right to control the use of a specific asset. A contract determined to contain a lease is evaluated further to determine if the arrangement is a finance lease.
ROU assets represent PSCo's rights to use leased assets. Starting in 2019, the present value of future operating lease payments is recognized in current and noncurrent operating lease liabilities. These amounts, adjusted for any prepayments or incentives, are recognized as operating lease ROU assets.
Most of PSCo’s leases do not contain a readily determinable discount rate. Therefore, the present value of future lease payments is generally calculated using the estimated incremental borrowing rate (weighted-average of 4.1%). PSCo has elected to utilize the practical expedient under which non-lease components, such as asset maintenance costs included in payments, are not deducted from minimum lease payments for the purposes of lease accounting and disclosure.
Leases with an initial term of 12 months or less are classified as short-term leases and are not recognized on the consolidated balance sheet.
Operating lease ROU assets:
|
| | | | |
| (Millions of Dollars) | | Dec. 31, 2019 |
| PPAs | | $ | 585.1 |
|
| Other | | 68.7 |
|
| Gross operating lease ROU assets | | 653.8 |
|
| Accumulated amortization | | (79.8 | ) |
| Net operating lease ROU assets | | $ | 574.0 |
|
In 2019, ROU assets for finance leases are included in other noncurrent assets, and the present value of future finance lease payments is included in other current liabilities and other noncurrent liabilities. Prior to 2019, finance leases were included in property, plant and equipment, the current portion of long-term debt and long-term debt.
PSCo’s most significant finance lease activities are related to WYCO, a joint venture with CIG, to develop and lease natural gas pipeline, storage and compression facilities. Xcel Energy Inc. has a 50% ownership interest in WYCO. WYCO leases its facilities to CIG, and CIG operates the facilities, providing natural gas storage and transportation services to PSCo under separate service agreements.
PSCo accounts for its Totem natural gas storage service and Front Range pipeline arrangements with CIG and WYCO, respectively, as finance leases.
Finance lease ROU assets:
|
| | | | | | | | |
| (Millions of Dollars) | | Dec. 31, 2019 | | Dec. 31, 2018 |
| Gas storage facilities | | $ | 200.5 |
| | $ | 200.5 |
|
| Gas pipeline | | 20.7 |
| | 20.7 |
|
| Gross finance lease ROU assets | | 221.2 |
| | 221.2 |
|
| Accumulated amortization | | (82.4 | ) | | (76.2 | ) |
| Net finance lease ROU assets | | $ | 138.8 |
| | $ | 145.0 |
|
Components of lease expense:
|
| | | | | | | | | | | | |
| (Millions of Dollars) | | 2019 | | 2018 | | 2017 |
| Operating leases | | | | | | |
| PPA capacity payments | | $ | 98.0 |
| | $ | 96.6 |
| | $ | 96.1 |
|
Other operating leases (a) | | 14.4 |
| | 14.0 |
| | 12.5 |
|
Total operating lease expense (b) | | $ | 112.4 |
| | $ | 110.6 |
| | $ | 108.6 |
|
| Finance leases | | | | | | |
| Amortization of ROU assets | | $ | 6.2 |
| | $ | 5.6 |
| | $ | 5.3 |
|
| Interest expense on lease liability | | 18.7 |
| | 19.5 |
| | 20.3 |
|
| Total finance lease expense | | $ | 24.9 |
| | $ | 25.1 |
| | $ | 25.6 |
|
| |
(a) | Includes short-term lease expense of $1.3 million, is included in the current asset at Dec. 31, 2016$1.5 million and 2015,$1.0 million for 2019, 2018 and 2017, respectively. |
| |
(b) | Includes amounts recordedPPA capacity payments are included in electric fuel and purchased power on the consolidated statements of income. Expense for future recovery of AROs.other operating leases is included in O&M expense and electric fuel and purchased power. |
Commitments under operating and finance leases as of Dec. 31, 2019:
|
| | | | | | | | | | | | | | | | |
| (Millions of Dollars) | | PPA (a) (b) Operating Leases | | Other Operating Leases | | Total
Operating Leases | | Finance Leases |
| 2020 | | $ | 95.9 |
| | $ | 13.2 |
| | $ | 109.1 |
| | $ | 24.8 |
|
| 2021 | | 96.4 |
| | 12.6 |
| | 109.0 |
| | 23.6 |
|
| 2022 | | 82.6 |
| | 11.6 |
| | 94.2 |
| | 20.5 |
|
| 2023 | | 70.0 |
| | 10.9 |
| | 80.9 |
| | 20.3 |
|
| 2024 | | 62.6 |
| | 11.0 |
| | 73.6 |
| | 20.1 |
|
| Thereafter | | 226.0 |
| | 18.1 |
| | 244.1 |
| | 399.7 |
|
| Total minimum obligation | | 633.5 |
| | 77.4 |
| | 710.9 |
| | 509.0 |
|
| Interest component of obligation | | (95.0 | ) | | (12.5 | ) | | (107.5 | ) | | (370.2 | ) |
| Present value of minimum obligation | | $ | 538.5 |
| | $ | 64.9 |
| | 603.4 |
| | 138.8 |
|
| Less current portion | | | | | | (85.8 | ) | | (6.9 | ) |
| Noncurrent operating and finance lease liabilities | | | | | | $ | 517.6 |
| | $ | 131.9 |
|
| | | | | | | | | |
| Weighted-average remaining lease term in years | | | | | | 7.9 |
| | 38.7 |
|
| |
(a) | Amounts do not include PPAs accounted for as executory contracts and/or contingent payments, such as energy payments on renewable PPAs. |
| |
(c)(b)
| Includes costsPPA operating leases contractually expire at various dates through 2032. |
Commitments under operating and finance leases as of Dec. 31, 2018:
|
| | | | | | | | | | | | | | | | |
| (Millions of Dollars) | | PPA (a) (b) Operating Leases | | Other Operating Leases | | Total
Operating Leases | | Finance Leases |
| 2019 | | $ | 95.5 |
| | $ | 10.8 |
| | $ | 106.3 |
| | $ | 24.9 |
|
| 2020 | | 95.9 |
| | 10.7 |
| | 106.6 |
| | 24.8 |
|
| 2021 | | 96.4 |
| | 9.5 |
| | 105.9 |
| | 23.6 |
|
| 2022 | | 82.6 |
| | 8.4 |
| | 91.0 |
| | 20.5 |
|
| 2023 | | 70.0 |
| | 8.1 |
| | 78.1 |
| | 20.3 |
|
| Thereafter | | 288.6 |
| | 53.4 |
| | 342.0 |
| | 420.4 |
|
| Total minimum obligation | | | | | | | | 534.5 |
|
| Interest component of obligation | | | | | | | | (389.5 | ) |
| Present value of minimum obligation | | | | | | $ | 145.0 |
|
| |
(a) | Amounts do not include PPAs accounted for conservation programs, as wellexecutory contracts and/or contingent payments, such as incentives allowed in certain jurisdictions.energy payments on renewable PPAs. |
| |
(d)(b)
| Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.PPA operating leases contractually expire at various dates through 2032. |
PPAs and Fuel Contracts
The componentsNon-Lease PPAs— PSCo has entered into PPAs with other utilities and energy suppliers with various expiration dates through 2034 for purchased power to meet system load and energy requirements and operating reserve obligations. In general, these agreements provide for energy payments, based on actual energy delivered and capacity payments. Certain PPAs accounted for as executory contracts contain minimum energy purchase commitments.
Included in electric fuel and purchased power expenses for PPAs accounted for as executory contracts were payments for capacity of regulatory liabilities shown$12.0 million, $20.9 million and $25.2 million in 2019, 2018 and 2017, respectively.
Capacity and energy payments are contingent on the consolidated balance sheetsIPP meeting contract obligations, including plant availability requirements. Certain contractual payments are adjusted based on market indices. The effects of PSCo at Dec. 31, 2016 and 2015 are:
|
| | | | | | | | | | | | | | | | | | | | | |
| (Thousands of Dollars) | | See Note(s) | | Remaining
Amortization Period | | Dec. 31, 2016 | | Dec. 31, 2015 |
| Regulatory Liabilities | | | | | | Current | | Noncurrent | | Current | | Noncurrent |
| Plant removal costs | | 1, 12 |
| | Plant lives | | $ | — |
| | $ | 367,440 |
| | $ | — |
| | $ | 364,291 |
|
| Renewable resources and environmental initiatives | | 11, 12 |
| | Various | | 3,600 |
| | 67,728 |
| | 3,311 |
| | 40,988 |
|
| Investment tax credit deferrals | | 1, 7 |
| | Various | | — |
| | 18,797 |
| | — |
| | 20,515 |
|
| Deferred income tax adjustment | | 1 |
| | Various | | — |
| | 16,260 |
| | — |
| | 16,891 |
|
| Gain from asset sales | | | | Pending rate case | | — |
| | 1,469 |
| | — |
| | — |
|
| PSCo earnings test | | 11 |
| | One to two years | | 8,300 |
| | 914 |
| | 42,868 |
| | 9,472 |
|
| Deferred electric, natural gas and steam production costs | | 1 |
| | Less than one year | | 35,123 |
| | — |
| | 66,696 |
| | — |
|
Conservation programs (a) | | 1, 11 |
| | Less than one year | | 24,077 |
| | — |
| | 33,460 |
| | — |
|
| Gas pipeline inspection costs | | 12 |
| | Less than one year | | 5,108 |
| | — |
| | 1,140 |
| | 4,273 |
|
| Low income discount program | | | | Less than one year | | 881 |
| | — |
| | 1,393 |
| | — |
|
| Other | | | | Various | | 24,021 |
| | 40,325 |
| | 3,955 |
| | 14,991 |
|
Total regulatory liabilities (b) | | | | | | $ | 101,110 |
| | $ | 512,933 |
| | $ | 152,823 |
| | $ | 471,421 |
|
| |
(a)
| Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. |
| |
(b)
| Revenue subject to refund of $2.4 million and $9.1 million for 2016 and 2015, respectively, is included in other current liabilities. |
price adjustments on financial results are mitigated through purchased energy cost recovery mechanisms.
At Dec. 31, 20162019, the estimated future payments for capacity that PSCo is obligated to purchase pursuant to these executory contracts, subject to availability, were as follows:
|
| | | | |
| (Millions of Dollars) | | Capacity |
| 2020 | | $ | 3.2 |
|
| 2021 | | 3.2 |
|
| 2022 | | 3.2 |
|
| 2023 | | 3.2 |
|
| 2024 | | 3.2 |
|
| Thereafter | | 10.4 |
|
| Total | | $ | 26.4 |
|
Fuel Contracts — PSCo has entered into various long-term commitments for the purchase and 2015,delivery of a significant portion of its coal and natural gas requirements. These contracts expire between 2020 and 2060. PSCo is required to pay additional amounts depending on actual quantities shipped under these agreements.
Estimated minimum purchases under these contracts as of Dec. 31, 2019:
|
| | | | | | | | | | | | |
| (Millions of Dollars) | | Coal | | Natural gas supply | | Natural gas storage and
transportation |
| 2020 | | $ | 155.7 |
| | $ | 287.3 |
| | $ | 116.0 |
|
| 2021 | | 66.6 |
| | 252.7 |
| | 113.3 |
|
| 2022 | | 44.1 |
| | 102.5 |
| | 113.4 |
|
| 2023 | | 22.4 |
| | 52.6 |
| | 65.7 |
|
| 2024 | | 22.9 |
| | 2.9 |
| | 35.0 |
|
| Thereafter | | 71.3 |
| | — |
| | 537.7 |
|
| Total | | $ | 383.0 |
| | $ | 698.0 |
| | $ | 981.1 |
|
VIEs
Under certain PPAs, PSCo purchases power from IPPs for which PSCo is required to reimburse fuel costs, or to participate in tolling arrangements under which PSCo procures the natural gas required to produce the energy that it purchases. PSCo has determined that certain IPPs are VIEs. PSCo is not subject to risk of loss from the operations of these entities, and no significant financial support is required other than contractual payments for energy and capacity.
PSCo evaluated each of these VIEs for possible consolidation, including review of qualitative factors such as the length and terms of the contract, control over O&M, control over dispatch of electricity, historical and estimated future fuel and electricity prices, and financing activities. PSCo concluded that these entities are not required to be consolidated in its consolidated financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance. PSCo had approximately $28 million1,442 MW and $54 million1,571 MW of PSCo’s regulatory assets represented past expenditures not currently earning a return, respectively. This amount primarily includes certain expenditures associatedcapacity under long-term PPAs at Dec. 31, 2019 and 2018, respectively, with renewable resources and environmental initiatives.
entities that have been determined to be VIEs. These agreements have expiration dates through 2032.
| |
14. |
| 11. Other Comprehensive Income |
Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31, 2016 and 2015 were as follows:31:
|
| | | | | | | | | | | | |
| | | Year Ended Dec. 31, 2016 |
| (Thousands of Dollars) | | Gains and Losses on Cash Flow Hedges | | Defined Benefit and Postretirement Items | | Total |
| Accumulated other comprehensive loss at Jan. 1 | | $ | (23,836 | ) | | $ | — |
| | $ | (23,836 | ) |
| Other comprehensive loss before reclassifications | | — |
| | (223 | ) | | (223 | ) |
| Losses reclassified from net accumulated other comprehensive loss | | 1,056 |
| | 3 |
| | 1,059 |
|
| Net current period other comprehensive income (loss) | | 1,056 |
| | (220 | ) | | 836 |
|
| Accumulated other comprehensive loss at Dec. 31 | | $ | (22,780 | ) | | $ | (220 | ) | | $ | (23,000 | ) |
| | | | | | | |
|
| | | | |
| | | Year Ended Dec. 31, 2015 |
| (Thousands of Dollars) | | Gains and Losses on Cash Flow Hedges |
| Accumulated other comprehensive loss at Jan. 1 | | $ | (23,878 | ) |
| Other comprehensive loss before reclassifications | | (30 | ) |
| Losses reclassified from net accumulated other comprehensive loss | | 72 |
|
| Net current period other comprehensive income | | 42 |
|
| Accumulated other comprehensive loss at Dec. 31 | | $ | (23,836 | ) |
Reclassifications from accumulated other comprehensive loss for the years ended Dec. 31, 2016 and 2015 were as follows:
|
| | | | | | | | | |
| | | Amounts Reclassified from Accumulated
Other Comprehensive Loss | |
| (Thousands of Dollars) | | Year Ended Dec. 31, 2016 | | Year Ended Dec. 31, 2015 | |
| Losses (gains) on cash flow hedges: | | | | | |
| Interest rate derivatives | | $ | 1,618 |
| (a) | $ | 54 |
| (a) |
| Vehicle fuel derivatives | | 86 |
| (b) | 57 |
| (b) |
| Total, pre-tax | | 1,704 |
| | 111 |
| |
| Tax benefit | | (648 | ) | | (39 | ) | |
| Total, net of tax | | 1,056 |
| | 72 |
| |
| Defined benefit pension and postretirement losses (gains): | | | | | |
| Amortization of net losses | | 5 |
| (c) | — |
| |
| Total, pre-tax | | 5 |
| | — |
| |
| Tax benefit | | (2 | ) | | — |
| |
| Total, net of tax | | 3 |
| | — |
| |
| Total amounts reclassified, net of tax | | $ | 1,059 |
| | $ | 72 |
| |
|
| | | | | | | | | | | | |
| | | 2019 |
| (Millions of Dollars) | | Gains and Losses on Cash Flow Hedges | | Defined Benefit and Postretirement Items | | Total |
| Accumulated other comprehensive loss at Jan. 1 | | $ | (25.3 | ) | | $ | (0.2 | ) | | $ | (25.5 | ) |
| Other comprehensive loss before reclassifications (net of taxes of $0 and $0.1, respectively) | | — |
| | 0.4 |
| | 0.4 |
|
| Losses (gains) reclassified from net accumulated other comprehensive loss: | | | | | | |
| Interest rate derivatives (net of taxes of $0.4 and $0, respectively) | | 1.2 |
| (a) | — |
| | 1.2 |
|
| Amortization of net actuarial gains (net of taxes of $0 and $(0.9), respectively) | | — |
| | (2.7 | ) | (b) | (2.7 | ) |
| Net current period other comprehensive income (loss) | | 1.2 |
| | (2.3 | ) | | (1.1 | ) |
| Accumulated other comprehensive loss at Dec. 31 | | $ | (24.1 | ) | | $ | (2.5 | ) | | $ | (26.6 | ) |
| |
(a) | Included in interest charges. |
| |
(b) | Included in O&M expenses. |
| |
(c)
| Included in the computation of net periodic pension and postretirement benefit costs. See Note 89 for details regarding these benefit plans.further information. |
|
| | | | | | | | | | | | |
| | | 2018 |
| (Millions of Dollars) | | Gains and Losses on Cash Flow Hedges | | Defined Benefit and Postretirement Items | | Total |
| Accumulated other comprehensive loss at Jan. 1 | | $ | (26.5 | ) | | $ | (0.2 | ) | | $ | (26.7 | ) |
| Losses reclassified from net accumulated other comprehensive loss: | | | | | | |
| Interest rate derivatives (net of taxes of $0.4 and $0, respectively) | | 1.2 |
| (a) | — |
| | 1.2 |
|
| Net current period other comprehensive income | | 1.2 |
| | — |
| | 1.2 |
|
| Accumulated other comprehensive loss at Dec. 31 | | $ | (25.3 | ) | | $ | (0.2 | ) | | $ | (25.5 | ) |
| |
15.(a) | Included in interest charges. |
|
|
| 12. 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 - The regulated electric utility segment generates electricity which is transmitted and distributed in Colorado. This segment includes sales for resale and provides wholesale transmission service to various entities in the United States. Regulated electric utility also includes PSCo’s wholesale commodity and trading operations. |
| |
| • | Regulated Natural Gas - The regulated natural gas utility segment transports, stores and distributes natural gas in portions of Colorado. |
PSCo presents Other, which 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 arewith revenues below the necessary quantitative thresholds and are therefore included in the all other category.thresholds. Those operating segments primarily includeincludes 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.
|
| | | | | | | | | | | | | | | | | | | | |
| (Thousands of Dollars) | | Regulated
Electric | | Regulated
Natural Gas | | All Other | | Reconciling
Eliminations | | Consolidated
Total |
| 2016 | | | | | | | | | | |
Operating revenues (a) | | $ | 3,049,352 |
| | $ | 957,721 |
| | $ | 40,723 |
| | $ | — |
| | $ | 4,047,796 |
|
| Intersegment revenues | | 275 |
| | 110 |
| | — |
| | (385 | ) | | — |
|
| Total revenues | | $ | 3,049,627 |
| | $ | 957,831 |
| | $ | 40,723 |
| | $ | (385 | ) | | $ | 4,047,796 |
|
| | | | | | | | | | | |
| Depreciation and amortization | | $ | 337,583 |
| | $ | 101,663 |
| | $ | 4,309 |
| | $ | — |
| | $ | 443,555 |
|
| Interest charges and financing costs | | 136,274 |
| | 37,881 |
| | 431 |
| | — |
| | 174,586 |
|
| Income tax expense (benefit) | | 228,825 |
| | 45,960 |
| | (867 | ) | | — |
| | 273,918 |
|
| Net income | | 383,973 |
| | 75,426 |
| | 4,092 |
| | — |
| | 463,491 |
|
|
| | | | | | | | | | | | |
| (Millions of Dollars) | | 2019 | | 2018 | | 2017 |
| Regulated Electric | | | | | | |
Operating revenues (a) | | $ | 3,033.0 |
| | $ | 3,031.2 |
| | $ | 3,003.8 |
|
| Intersegment revenues | | 0.4 |
| | 0.3 |
| | 0.3 |
|
| Total operating revenue | | $ | 3,033.4 |
| | $ | 3,031.5 |
| | $ | 3,004.1 |
|
| Depreciation and amortization | | 454.9 |
| | 415.6 |
| | 353.6 |
|
| Interest charges and financing costs | | 173.7 |
| | 142.3 |
| | 138.6 |
|
| Income tax expense | | 45.0 |
| | 103.0 |
| | 243.6 |
|
| Net income | | 464.9 |
| | 428.6 |
| | 370.6 |
|
| Regulated Natural Gas | | | | | | |
Operating revenues (a) | | $ | 1,160.9 |
| | $ | 1,014.6 |
| | $ | 995.2 |
|
| Intersegment revenues | | 0.4 |
| | 0.6 |
| | 0.4 |
|
| Total operating revenue | | $ | 1,161.3 |
| | $ | 1,015.2 |
| | $ | 995.6 |
|
| Depreciation and amortization | | 141.4 |
| | 140.6 |
| | 113.2 |
|
| Interest charges and financing costs | | 49.7 |
| | 42.9 |
| | 40.2 |
|
| Income tax expense | | 32.6 |
| | 13.1 |
| | 18.4 |
|
| Net income | | 119.4 |
| | 121.4 |
| | 107.8 |
|
| All Other | | | | | | |
Operating revenues (a) | | $ | 43.3 |
| | $ | 40.4 |
| | $ | 43.5 |
|
| Depreciation and amortization | | 6.1 |
| | 4.9 |
| | 4.7 |
|
| Interest charges and financing costs | | 0.8 |
| | 0.5 |
| | 0.5 |
|
| Income tax (benefit) | | 2.0 |
| | (2.4 | ) | | (9.8 | ) |
| Net (loss) income | | (6.5 | ) | | 1.7 |
| | 15.7 |
|
| | | | | | | |
| Consolidated Total | | | | | | |
Operating revenues (a) | | $ | 4,238.0 |
| | $ | 4,087.1 |
| | $ | 4,043.2 |
|
| Intersegment revenues | | (0.8 | ) | | (0.9 | ) | | (0.7 | ) |
| Total operating revenue | | $ | 4,237.2 |
| | $ | 4,086.2 |
| | $ | 4,042.5 |
|
| Depreciation and amortization | | 602.4 |
| | 561.1 |
| | 471.5 |
|
| Interest charges and financing costs | | 224.2 |
| | 185.7 |
| | 179.3 |
|
| Income tax expense | | 79.6 |
| | 113.7 |
| | 252.2 |
|
| Net income | | 577.8 |
| | 551.7 |
| | 494.1 |
|
|
| | | | | | | | | | | | | | | | | | | | |
| (Thousands of Dollars) | | Regulated Electric | | Regulated Natural Gas | | All Other | | Reconciling Eliminations | | Consolidated Total |
| 2015 | | | | | | | | | | |
Operating revenues (a) | | $ | 3,115,257 |
| | $ | 1,006,666 |
| | $ | 41,590 |
| | $ | — |
| | $ | 4,163,513 |
|
| Intersegment revenues | | 301 |
| | 67 |
| | — |
| | (368 | ) | | — |
|
| Total revenues | | $ | 3,115,558 |
| | $ | 1,006,733 |
| | $ | 41,590 |
| | $ | (368 | ) | | $ | 4,163,513 |
|
| | | | | | | | | | | |
| Depreciation and amortization | | $ | 311,122 |
| | $ | 96,384 |
| | $ | 4,161 |
| | $ | — |
| | $ | 411,667 |
|
| Interest charges and financing costs | | 136,397 |
| | 34,935 |
| | 576 |
| | — |
| | 171,908 |
|
| Income tax expense (benefit) | | 234,873 |
| | 44,192 |
| | (625 | ) | | — |
| | 278,440 |
|
| Net income | | 391,257 |
| | 74,267 |
| | 1,278 |
| | — |
| | 466,802 |
|
|
| | | | | | | | | | | | | | | | | | | | |
| (Thousands of Dollars) | | Regulated Electric | | Regulated Natural Gas | | All Other | | Reconciling Eliminations | | Consolidated Total |
| 2014 | | | | | | | | | | |
Operating revenues (a) | | $ | 3,125,937 |
| | $ | 1,215,324 |
| | $ | 41,888 |
| | $ | — |
| | $ | 4,383,149 |
|
| Intersegment revenues | | 339 |
| | 180 |
| | — |
| | (519 | ) | | — |
|
| Total revenues | | $ | 3,126,276 |
| | $ | 1,215,504 |
| | $ | 41,888 |
| | $ | (519 | ) | | $ | 4,383,149 |
|
| | | | | | | | | | | |
| Depreciation and amortization | | $ | 285,968 |
| | $ | 89,186 |
| | $ | 4,048 |
| | $ | — |
| | $ | 379,202 |
|
| Interest charges and financing costs | | 124,118 |
| | 29,987 |
| | 535 |
| | — |
| | 154,640 |
|
| Income tax expense (benefit) | | 208,095 |
| | 50,874 |
| | (15,378 | ) | | — |
| | 243,591 |
|
| Net income | | 349,793 |
| | 84,324 |
| | 21,071 |
| | — |
| | 455,188 |
|
| |
(a) | Operating revenues include $13$4.5 million, $13$4.4 million and $14$5.9 million of intercompany revenue for the years ended Dec. 31, 2016, 20152019, 2018 and 2014,2017, respectively. See Note 1613 for further discussion of related party transactions by reportable segment.information. |
| |
16. |
| 13. Related Party Transactions |
Xcel Energy Services Inc. provides management, administrative and other services for the subsidiaries of Xcel Energy Inc., including PSCo. The services are provided and billed to each subsidiary in accordance with service agreements executed by each subsidiary. PSCo uses services provided by Xcel Energy Services Inc. whenever possible. Costs are charged directly to the subsidiary and are allocated if they cannot be directly assigned.
Xcel Energy Inc., NSP-Minnesota, PSCo and SPS have established a utility money pool arrangement.
See Note 45 for further discussion.information.
The table below contains significantSignificant affiliate transactions among the companies and related parties for the years ended Dec. 31:
|
| | | | | | | | | | | | |
| (Millions of Dollars) | | 2019 | | 2018 | | 2017 |
| Operating revenues: | | | | | | |
| Electric | | $ | — |
| | $ | — |
| | $ | 1.4 |
|
| Other | | 4.5 |
| | 4.4 |
| | 4.5 |
|
| Operating expenses: | | | | | | |
| Other operating expenses — paid to Xcel Energy Services Inc. | | 531.9 |
| | 518.7 |
| | 485.1 |
|
| Interest expense | | 0.4 |
| | — |
| | — |
|
| Interest income | | 0.2 |
| | — |
| | — |
|
|
| | | | | | | | | | | | |
| (Thousands of Dollars) | | 2016 | | 2015 | | 2014 |
| Operating revenues: | | | | | | |
| Electric | | $ | 8,809 |
| | $ | 8,632 |
| | $ | 9,614 |
|
| Other | | 4,525 |
| | 4,441 |
| | 4,441 |
|
| Operating expenses: | | | | | | |
| Purchased power | | 56 |
| | — |
| | 23 |
|
| Other operating expenses — paid to Xcel Energy Services Inc. | | 446,086 |
| | 414,620 |
| | 454,250 |
|
| Interest expense | | 149 |
| | 211 |
| | 158 |
|
| Interest income | | — |
| | 45 |
| | 61 |
|
Accounts receivable and payable with affiliates at Dec. 31 were:31:
|
| | | | | | | | | | | | | | | | |
| | | 2019 | | 2018 |
| (Millions of Dollars) | | Accounts
Receivable | | Accounts
Payable | | Accounts
Receivable | | Accounts
Payable |
| NSP-Minnesota | | $ | 18.8 |
| | $ | — |
| | $ | 17.9 |
| | $ | — |
|
| NSP-Wisconsin | | — |
| | 0.2 |
| | — |
| | 0.2 |
|
| SPS | | 0.4 |
| | — |
| | 0.7 |
| | — |
|
| Other subsidiaries of Xcel Energy Inc. | | 33.5 |
| | 43.7 |
| | 62.2 |
| | 45.8 |
|
| | | $ | 52.7 |
| | $ | 43.9 |
| | $ | 80.8 |
| | $ | 46.0 |
|
|
| | | | | | | | | | | | | | | | |
| | | 2016 | | 2015 |
| (Thousands of Dollars) | | Accounts
Receivable | | Accounts
Payable | | Accounts
Receivable | | Accounts
Payable |
| NSP-Minnesota | | $ | 7,669 |
| | $ | — |
| | $ | 4,419 |
| | $ | — |
|
| NSP-Wisconsin | | 974 |
| | — |
| | 71 |
| | — |
|
| SPS | | 745 |
| | — |
| | 414 |
| | — |
|
| Other subsidiaries of Xcel Energy Inc. | | 33 |
| | 98,797 |
| | 5 |
| | 76,643 |
|
| | | $ | 9,421 |
| | $ | 98,797 |
| | $ | 4,909 |
| | $ | 76,643 |
|
| |
17. |
| 14. Summarized Quarterly Financial Data (Unaudited) |
|
| | | | | | | | | | | | | | | | |
| | | Quarter Ended |
| (Thousands of Dollars) | | March 31, 2016 | | June 30, 2016 | | Sept. 30, 2016 | | Dec. 31, 2016 |
| Operating revenues | | $ | 1,057,841 |
| | $ | 909,852 |
| | $ | 1,059,177 |
| | $ | 1,020,926 |
|
| Operating income | | 223,190 |
| | 180,629 |
| | 315,605 |
| | 170,197 |
|
| Net income | | 115,874 |
| | 87,344 |
| | 173,607 |
| | 86,666 |
|
| | | | | Quarter Ended | | Quarter Ended |
| (Thousands of Dollars) | | March 31, 2015 | | June 30, 2015 | | Sept. 30, 2015 | | Dec. 31, 2015 | |
| (Millions of Dollars) | | | March 31, 2019 | | June 30, 2019 | | Sept. 30, 2019 | | Dec. 31, 2019 |
| Operating revenues | | $ | 1,135,450 |
| | $ | 952,521 |
| | $ | 1,044,704 |
| | $ | 1,030,838 |
| | $ | 1,223.0 |
| | $ | 910.0 |
| | $ | 1,044.3 |
| | $ | 1,059.9 |
|
| Operating income | | 215,400 |
| | 195,176 |
| | 315,174 |
| | 173,951 |
| | 209.9 |
| | 162.7 |
| | 284.3 |
| | 199.9 |
|
| Net income | | 110,966 |
| | 98,500 |
| | 173,081 |
| | 84,255 |
| | 138.8 |
| | 101.5 |
| | 204.5 |
| | 133.0 |
|
|
| | | | | | | | | | | | | | | | |
| | | Quarter Ended |
| (Millions of Dollars) | | March 31, 2018 | | June 30, 2018 | | Sept. 30, 2018 | | Dec. 31, 2018 |
| Operating revenues | | $ | 1,073.3 |
| | $ | 911.9 |
| | $ | 1,060.7 |
| | $ | 1,040.3 |
|
Operating income (a) | | 206.9 |
| | 189.3 |
| | 276.9 |
| | 119.5 |
|
| Net income | | 133.7 |
| | 122.3 |
| | 207.1 |
| | 88.6 |
|
| |
(a) | In 2018, PSCo implemented ASU No. 2017-07 related to net periodic benefit cost, which resulted in retrospective reclassification of pension costs from O&M expense to other income. |
|
|
| Item 9 — Changes in and Disagreements with Accountants on Accounting and Financial Disclosure |
None.
Item 9 — Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A — Controls and Procedures
|
|
| 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)CEO and chief financial officer (CFO),CFO, allowing timely decisions regarding required disclosure.
As of Dec. 31, 2016,2019, based on an evaluation carried out under the supervision and with the participation of PSCo’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that PSCo’s disclosure controls and procedures were effective.
Internal Control Over Financial Reporting
No changechanges in PSCo’s internal control over financial reporting has occurred during the most recent fiscal quarter that has materially affected, or isare 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, 20162019 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 PSCo’s 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 plans to initiate deployment of work management systems modules, including the conversion of existing work management systems, to this same system during 2017. In connection with this ongoing implementation, PSCoover Financial Reporting, which is updating its internal control over financial reporting, as necessary, to accommodate modifications to its business processes and accounting systems. PSCo does not believe that this implementation will have an adverse effect on its internal control over financial reporting.
contained in Item 8 herein.
This annual report does not include an attestation report of PSCo’s independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by PSCo’s independent registered public accounting firm pursuant to the rules of the SEC that permit PSCo to provide only management’s report in this annual report.
Item 9B — Other Information |
|
| 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) I(1)(a) and (b) of Form 10-K for wholly-owned subsidiaries.
|
|
| ITEM 10 — DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE |
Item 10 — Directors, Executive Officers and Corporate Governance |
|
| ITEM 11 — EXECUTIVE COMPENSATION |
Item 11 — Executive Compensation |
|
| ITEM 12 — SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS |
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 13 — CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE |
Information required under this Item is contained in Xcel Energy Inc.’s definitive Proxy Statement for its 20172020 Annual Meeting of Shareholders, which is incorporated by reference.
Item 14 — Principal Accountant Fees and Services
The information |
|
| ITEM 14 — PRINCIPAL ACCOUNTANT FEES AND SERVICES |
FromForm 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 20172020 Annual Meeting of StockholdersShareholders which definitive Proxy Statement is expected to be filed with the SEC on or about April 4, 2017.6, 2020. Such information set forth under such heading is incorporated herein by this reference hereto.
PART IV
Item 15 — Exhibits, Financial Statement Schedules |
|
ITEM 15—EXHIBITS, FINANCIAL STATEMENT SCHEDULES |
|
| |
1.1 | Consolidated Financial Statements: |
| | |
| Management Report on Internal Controls Over Financial Reporting — For the year ended Dec. 31, 2016.2019. |
| | Report of Independent Registered Public Accounting Firm — Financial Statements |
| | Consolidated Statements of Income — For the three years ended Dec. 31, 2016, 2015,2019, 2018 and 2014.2017. |
| | Consolidated Statements of Comprehensive Income — For the three years ended Dec. 31, 2016, 2015,2019, 2018 and 2014.2017. |
| | Consolidated Statements of Cash Flows — For the three years ended Dec. 31, 2016, 2015,2019, 2018 and 2014.2017. |
| | Consolidated Balance Sheets — As of Dec. 31, 20162019 and 2015.2018. |
| | Consolidated Statements of Common Stockholder’s Equity — For the three years ended Dec. 31, 2016, 20152019, 2018 and 2014.2017. |
| Consolidated Statements of Capitalization — As of Dec. 31, 2016 and 2015. |
| | |
2.2 | Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2016, 2015,2019, 2018 and 2014.2017. |
3. | Exhibits |
|
| 3 | Exhibits |
| * | Indicates incorporation by reference |
| + | Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors |
t
| Certain portions of this agreement have been omitted pursuant to a request for confidential treatment and have been filed separately with the SEC. |
|
| | | | |
| Exhibit Number | Description | Report or Registration Statement | SEC File or Registration Number | Exhibit Reference |
| Purchase and Sale Agreement by and between Riverside Energy Center, LLC and Calpine Development Holdings, Inc., as Sellers, and PSCo, as Purchaser, dated as of April 2, 2010 (excluding certain schedules and exhibits referred to in the agreement, as amended, which the Registrant agrees to furnish supplemental to the SEC upon request) (Exhibit 2.01 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended June 30, 2010). |
3.01* | | PSCo Form 10-Q for the quarter ended Sept. 30, 2017 | 001-03280
| 3.01 |
3.02* | | PSCo Form 10-Q/A10-K for the quarteryear ended Sept. 30, 2013 (file no. 001-03280)).Dec. 31, 2018 | 001-03280
| 3.02 |
4.01* | Trustee, providing for the issuance of First Collateral Trust Bonds (Form 10-Q, Sept. 30, 1993 — Exhibit 4(a)). |
4.02* | Indentures supplemental to Indenture dated as of Oct. 1, 1993, between PSCo and Morgan Guaranty Trust Company of New York, as trustee: |
|
| | | | |
Dated as of | | Previous Filing:
Form; Date or
file no.
| Xcel Energy Inc. Form S-3 dated April 18, 2018 | Exhibit
No.
|
Nov. 1, 1993001-03034 | | S-3, (33-51167) | | 4(b)(2) |
Jan. 1, 1994 | | 10-K, 1993 | | 4(b)4(d)(3) |
Sept. 2, 1994 | | 8-K, September 1994 | | 4(b) |
Nov. 1, 1996 | | 10-K, 1996 (001-03280) | | 4(b)(3) |
Feb. 1, 1997 | | 10-Q, March 31, 1997 (001-03280) | | 4(a) |
April 1, 1998 | | 10-Q, March 31, 1998 (001-03280) | | 4(b) |
Aug. 15, 2002 | | 10-Q, Sept. 30, 2002 (001-03280) | | 4.03 |
Aug. 1, 2005 | | PSCo 8-K, Aug. 18, 2005 (001-03280) | | 4.02 |
|
| |
4.03* | 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). |
4.04* | Financing Agreement between Adams County, Colorado and PSCo, dated as of Aug. 1, 2005 relating to $129.5 million Adams County, Colorado Pollution Control Refunding Revenue Bonds, 2005 Series A (Exhibit 4.01 to PSCo Current Report on Form 8-K, dated Aug. 18, 2005, file no. 001-03280). |
4.05* | Supplemental Indenture, dated Aug. 1, 2007 between PSCo and U.S. Bank Trust National Association, as successor Trustee, (Exhibit 4.01 to creating $350 million principal amount of 6.25% First Mortgage Bonds, Series due 2037 | PSCo Form 8-K (file no. 001-03280) dated Aug. 18, 2007).8, 2007 |
| 001-03280 | 4.01 |
| |
4.06* | | PSCo Form 8-K of PSCo dated Aug. 6, 2008 (file no. 001-03280)). | 001-03280 | 4.01 |
4.07* | | PSCo Form 8-K of PSCo dated May 28, 2009 (file no. 001-03280)). | 001-03280 | 4.01 |
4.08* | | PSCo Form 8-K of PSCo dated Nov. 18,8, 2010 (file no. 001-03280)). | 001-03280 | 4.01 |
4.09* | | PSCo Form 8-K of PSCo dated Aug. 9, 2011 (file no. 001-03280)). | 001-03280 | 4.01 |
4.10* | | PSCo Form 8-K dated Sept. 11, 2012 (file no. 001-03280)). | 001-03280 | 4.01 |
4.11* | | PSCo Form 8-K of PSCo dated March 26, 2013 (file no. 001-03280)). | 001-03280 | 4.01 |
4.12* | | PSCo Form 8-K of PSCo dated March 10, 2014 (file no. 001-03280)). | 001-03280 | 4.01 |
4.13* | | PSCo Form 8-K of PSCo dated May 12, 2015 (file no. 001-03280)). | 001-03280 | 4.01 |
4.14* | | PSCo Form 8-K of PSCo dated June 13, 2016 (file no. 001-03280)). | 001-03280 | 4.01 |
10.01*+ | | PSCo Form 8-K dated June 19, 2017 | 001-03280 | 4.01 |
| | PSCo Form 8-K dated June 21, 2018 | 001-03280 | 4.01 |
|
| | | | |
| | PSCo Form 8-K dated March 13, 2019 | 001-03280 | 4.01 |
| | PSCo Form 8-K dated August 13, 2019 | 001-03280 | 4.01 |
| | Xcel Energy Inc. Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).2008 | 001-03034 | 10.02 |
10.02* | | Xcel Energy Inc. Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).2008 | 001-03034 | 10.05 |
10.03* | | Xcel Energy Inc. Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).2008 | 001-03034 | 10.08 |
10.04* | | Xcel Energy Inc. Form U5B (file no. 001-03034) dated Nov. 16, 2000).2000 | 001-03034 | H-1 |
10.05* | | Xcel Energy Inc. Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).2008 | 001-03034 | 10.17 |
10.06* | Amended and Restated Coal Supply Agreement entered into Oct. 1, 1984 but made effective as of Jan. 1, 1976 between PSCo and Amax Inc. on behalf of its division, Amax Coal Co. (Form 10-K (file no. 001-03280) Dec. 31, 1984 — Exhibit 10(c)(1)). |
10.07* | First Amendment to Amended and Restated Coal Supply Agreement entered into May 27, 1988 but made effective Jan. 1, 1988 between PSCo and Amax Coal Co. (Form 10-K (file no. 001-03280) Dec. 31, 1988 — Exhibit 10(c)(2)). |
10.08* | | Xcel Energy Inc. Form 8-K of Xcel Energy (file no. 001-03034) dated Dec. 3, 2004).2004 | 001-03034 | 99.02 |
10.09* | Settlement Agreement among PSCo and Concerned Environmental and Community Parties, dated Dec. 3, 2004 (Exhibit 99.03 |
10.10*+ | AmendmentExhibit 10.02 dated Aug. 26, 2009 to the | Xcel Energy Senior Executive Severance and Change-in-Control Policy (Exhibit 10.06 toInc. Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009).2009 | 001-03034 | 10.06 |
10.11* | | Xcel Energy Inc. Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009).2009 | 001-03034 | 10.08 |
10.12* | |
|
| |
10.13*+ | 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, | Xcel Energy Inc. Definitive Proxy Statement to Xcel Energy (file no. 001-03034) dated April 6, 2010).2010 | 001-03034 | Appendix A |
10.14* | | Xcel Energy Inc. Definitive Proxy Statement (file no. 001-03034) filed Apr.dated April 5, 2011).2011 | 001-03034 | Appendix A |
10.15* | | Xcel Energy Inc. Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).2008 | 001-03034 | 10.07 |
10.16* | | 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).2011 | 001-03034 | 10.17 |
10.17* | | Xcel Energy Senior Executive Severance and Change-in-Control Policy (Exhibit 10.18 toInc. Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2011).2011 | 001-03034 | 10.18 |
10.18* | | 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).2013 | 001-03034 | 10.01 |
10.19* | | Xcel Energy Senior Executive Severance and Change-in-Control Policy (Exhibit 10.02 toInc. Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended March 31, 2013).2013 | 001-03034 | 10.02 |
10.20* | First | 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).2013 | 001-03034 | 10.22 |
10.21* | 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). |
10.22*+ | 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). |
10.23*+ | 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). |
10.24*+ | | Xcel Energy Inc. Form 8-K of dated May 20, 2015 | 001-03034 | 10.02 |
| | Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2016 | 001-03034 | 10.01 |
| | Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2016 | 001-03034 | 10.01 |
| | Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2017 | 001-03034 | 10.01 |
| | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2017 | 001-03034 | 10.30 |
| | Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2018 | 001-03034 | 10.01 |
10.25* | | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018 | 001-03034 | 10.34 |
| |
10.26*+Plan | 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).2018 | 001-03034 | 10.35 |
10.27* | | 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).2018 | 001-03034 | 10.36 |
10.28*+ | 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). |
10.29* | SecondThird Amended and Restated Credit Agreement, dated as of June 20, 20167, 2019 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, MUFG Bank, Ltd., and The Bank of Tokyo-Mitsubishi UFJ, Ltd.Citibank, N.A., as Documentation Agents. (Exhibit 99.03 to Form 8-K of Xcel Energy dated June 20, 2016 (file no. 001-03034)). |
10.30*+Agents | 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).8-K dated June 7, 2019 | 001-03034 | 99.03 |
10.31* | | Xcel Energy Inc. Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2016). |
|
| 2019 | 001-03034 | 10.33 |
| Statement of Computation of Ratio of Earnings to Fixed Charges. |
| Consent of Independent Registered Public Accounting Firm. |
| |
| |
| |
| 101.INS | Statement pursuant to Private Securities Litigation Reform Act of 1995.XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document |
101101.SCH | The following materials from PSCo’s Annual Report on Form 10-K for the year ended Dec. 31, 2016 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.Schema |
| 101.CAL | XBRL Calculation |
|
| | | | |
| 101.DEF | XBRL Definition |
| 101.LAB | XBRL Label |
| 101.PRE | XBRL Presentation |
| 104 | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) |
SCHEDULE II
PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
YEARS ENDED DEC.Public Service Co. of Colorado and Subsidiaries Valuation and Qualifying Accounts Years Ended Dec. 31 2016, 2015 AND 2014
(amounts in thousands)
|
| | | | | | | | | | | | | | | | | | | |
| | | | Additions | | | | |
| | Balance at Jan. 1 | | Charged to Costs and Expenses | | Charged to Other Accounts(a) | | Deductions from Reserves(b) | | Balance at Dec. 31 |
| Allowance for bad debts: | | | | | | | | | |
| 2016 | $ | 20,122 |
| | $ | 14,121 |
| | $ | 4,447 |
| | $ | 19,078 |
| | $ | 19,612 |
|
| 2015 | 23,122 |
| | 13,052 |
| | 5,175 |
| | 21,227 |
| | 20,122 |
|
| 2014 | 22,505 |
| | 17,005 |
| | 6,240 |
| | 22,628 |
| | 23,122 |
|
|
| | | | | | | | | | | | |
| | | Allowance for bad debts |
| (Millions of Dollars) | | 2019 | | 2018 | | 2017 |
| Balance at Jan. 1 | | $ | 20.5 |
| | $ | 19.6 |
| | $ | 19.6 |
|
| Additions charged to costs and expenses | | 16.5 |
| | 16.4 |
| | 14.3 |
|
Additions charged to other accounts (a) | | 5.8 |
| | 4.7 |
| | 4.0 |
|
Deductions from reserves (b) | | (21.8 | ) | | (20.2 | ) | | (18.3 | ) |
| Balance at Dec. 31 | | $ | 21.0 |
| | $ | 20.5 |
| | $ | 19.6 |
|
| |
(a) | Recovery of amounts previously written off. |
| |
(b) | Deductions relaterelated primarily to bad debt write-offs. |
|
|
| Item 16 — Form 10-K Summary |
None.
SIGNATURES
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. 24, 201721, 2020 |
| /s/ ROBERT C. FRENZEL |
| | | Robert C. Frenzel |
| | | Executive Vice President, Chief Financial Officer and Director |
| | | (Principal Financial Officer) |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities on the date indicated above.
|
| | |
| /s/ BEN FOWKE | | /s/ DAVID L. EVESALICE K. JACKSON |
| Ben Fowke | | David L. EvesAlice K. Jackson |
| Chairman, Chief Executive Officer and Director | | President and Director |
| (Principal Executive Officer) | | |
| | | |
| /s/ ROBERT C. FRENZEL | | /s/ JEFFREY S. SAVAGE |
| Robert C. Frenzel | | Jeffrey S. Savage |
| Executive Vice President, Chief Financial Officer and Director | | Senior Vice President, Controller |
| (Principal Financial Officer) | | (Principal Accounting Officer) |
| | | |
/s/ MARVIN E. MCDANIEL, JR.DAVID L. EVES | | |
Marvin E. McDaniel, Jr.David L. Eves | | |
| Executive Vice President, Group President, Utilities and Director | | |
SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(D) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT
PSCo has not sent, and does not expect to send, an annual report or proxy statement to its security holder.
