UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2018
or
¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
001-03280 | 84-0296600 | |
(Commission File Number) | (I.R.S. Employer Identification No.) | |
(Registrant, State of Incorporation or Organization, Address of Principal Executive Officers and Telephone Number) |
Public Service Company of Colorado |
(a Colorado corporation) |
1800 Larimer, Suite 1100 |
Denver, CO 80202 |
303-571-7511 |
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. x Yes ¨ No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. ¨ Yes x No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x Yes ¨ No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 and Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). x Yes ¨ No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulations S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company”, and “emerging growth company” in Rule 12b-2 of the Exchange Act. ¨ Large accelerated filer ¨ Accelerated filer x Non-accelerated filer ¨ Smaller Reporting Company ¨ Emerging growth company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). ¨ Yes x No
As of Feb. 22, 2019, 100 shares of common stock, par value $0.01 per share, were outstanding, all of which were held by Xcel Energy Inc., a Minnesota corporation.
DOCUMENTS INCORPORATED BY REFERENCE
The information required by Item 14 of Form 10-K is set forth under the heading “Independent Registered Public Accounting Firm – Audit and Non-Audit Fees” in Xcel Energy Inc.’s definitive Proxy Statement for the 2019 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about April 1, 2019. Such information set forth under such heading is incorporated herein by this reference hereto.
Public Service Company of Colorado meets the conditions set forth in General Instructions I(1)(a) and (b) of Form 10-K and is therefore filing this form with reduced disclosure format permitted by General Instruction I(2).
1
TABLE OF CONTENTS
Index
PART I | |
Item 1 — Business | |
Item 1A — Risk Factors | |
Item 1B — Unresolved Staff Comments | |
Item 2 — Properties | |
Item 3 — Legal Proceedings | |
Item 4 — Mine Safety Disclosures | |
PART II | |
Item 6 — Selected Financial Data | |
Item 9A — Controls and Procedures | |
Item 9B — Other Information | |
PART III | |
Item 11 — Executive Compensation | |
Item 14 — Principal Accountant Fees and Services | |
PART IV | |
Item 15 — Exhibits, Financial Statement Schedules | |
Item 16 — Form 10-K Summary | |
This Form 10-K is filed by PSCo. PSCo is a wholly owned subsidiary of Xcel Energy Inc. Additional information on Xcel Energy is available in various filings with the SEC. This report should be read in its entirety.
2
PART I
Item l — Business
ABBREVIATIONS AND INDUSTRY TERMS
Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former) | |
NSP-Minnesota | Northern States Power Company, a Minnesota corporation |
NSP-Wisconsin | Northern States Power Company, a Wisconsin corporation |
PSCo | Public Service Company of Colorado |
SPS | Southwestern Public Service Company |
Utility subsidiaries | NSP-Minnesota, NSP-Wisconsin, PSCo and SPS |
WYCO | WYCO Development, LLC |
Xcel Energy | Xcel Energy Inc. and subsidiaries |
Federal and State Regulatory Agencies | |
CPUC | Colorado Public Utilities Commission |
D.C. Circuit | United States Court of Appeals for the District of Columbia Circuit |
DOT | United States Department of Transportation |
EPA | United States Environmental Protection Agency |
FERC | Federal Energy Regulatory Commission |
IRS | Internal Revenue Service |
NERC | North American Electric Reliability Corporation |
PHMSA | Pipeline and Hazardous Materials Safety Administration |
SEC | Securities and Exchange Commission |
Electric, Purchased Gas and Resource Adjustment Clauses | |
DSM | Demand side management |
DSMCA | Demand side management cost adjustment |
ECA | Retail electric commodity adjustment |
GCA | Gas cost adjustment |
PCCA | Purchased capacity cost adjustment |
PSIA | Pipeline system integrity adjustment |
RESA | Renewable energy standard adjustment |
SCA | Steam cost adjustment |
TCA | Transmission cost adjustment |
WCA | Windsource® cost adjustment |
Other | |
AFUDC | Allowance for funds used during construction |
ARAM | Average rate assumption method |
ARO | Asset retirement obligation |
ASU | FASB Accounting Standards Update |
Boulder | City of Boulder, CO |
C&I | Commercial and Industrial |
CACJA | Clean Air Clean Jobs Act |
CCR | Coal combustion residuals |
CEP | Colorado Energy Plan |
CIG | Colorado Interstate Gas Company, LLC |
Corps | U.S. Army Corps of Engineers |
CPCN | Certificate of public convenience and necessity |
CWA | Clean Water Act |
CWIP | Construction work in progress |
DRC | Development Recovery Company |
ELG | Effluent limitations guidelines |
ETR | Effective tax rate |
FASB | Financial Accounting Standards Board |
GAAP | Generally accepted accounting principles |
GHG | Greenhouse gas |
IPP | Independent power producing entity |
ITC | Investment tax credit |
MGP | Manufactured gas plant |
Moody’s | Moody’s Investor Services |
Native load | Customer demand of retail and wholesale customers whereby a utility has an obligation to serve under statute or long-term contract. |
NAV | Net asset value |
NOL | Net operating loss |
O&M | Operating and maintenance |
Post-65 | Post-Medicare |
PPA | Purchased power agreement |
Pre-65 | Pre-Medicare |
PTC | Production tax credit |
PV | Photovoltaic |
REC | Renewable energy credit |
ROE | Return on equity |
RTO | Regional Transmission Organization |
SERP | Supplemental executive retirement plan |
SPP | Southwest Power Pool, Inc. |
Standard & Poor’s | Standard & Poor’s Ratings Services |
TCJA | 2017 federal tax reform enacted as Public Law No: 115-97, commonly referred to as the Tax Cuts and Jobs Act |
VaR | Value at Risk |
VIE | Variable interest entity |
WOTUS | Waters of the U.S. |
Measurements | |
Bcf | Billion cubic feet |
KV | Kilovolts |
KWh | Kilowatt hours |
MMBtu | Million British thermal units |
MW | Megawatts |
MWh | Megawatt hours |
3
Forward-Looking Statements
Except for the historical statements contained in this report, the matters discussed herein are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements, assumptions and other statements are intended to be identified in this document by the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” “will,” “would” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we expressly disclaim any obligation to update any forward-looking information. The following factors, in addition to those discussed elsewhere in this Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2018 (including risk factors listed from time to time by PSCo in reports filed with the SEC, including “Risk Factors” in Item 1A of this Annual Report on Form 10-K hereto), could cause actual results to differ materially from management expectations as suggested by such forward-looking information: changes in environmental laws and regulations; climate change and other weather natural disaster and resource depletion, including compliance with any accompanying legislative and regulatory changes; ability to recover costs from customers; reductions in our credit ratings and the cost of maintaining certain contractual relationships; general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of PSCo and its subsidiaries to obtain financing on favorable terms; availability or cost of capital; our customers’ and counterparties’ ability to pay their debts to us; assumptions and costs relating to funding our employee benefit plans and health care benefits; tax laws; operational safety; successful long-term operational planning; commodity risks associated with energy markets and production; rising energy prices; costs of potential regulatory penalties; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; fuel costs; and employee work force and third party contractor factors.
Where To Find More Information
PSCO is a wholly owned subsidiary of Xcel Energy Inc., and Xcel Energy’s website address is www.xcelenergy.com. Xcel Energy makes available, free of charge through its website, its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after the reports are electronically filed with or furnished to the SEC. The SEC maintains an internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically at http://www.sec.gov.
COMPANY OVERVIEW
PSCo was incorporated in 1924 under the laws of Colorado. PSCo conducts business in Colorado and generates, purchases, transmits, distributes and sells electricity in addition to purchasing, transporting, distributing and selling natural gas to retail customers and transporting customer-owned natural gas.
 | |||
PSCo | |||
Electric customers | 1.5 million | ||
Natural gas customers | 1.4 million | ||
Consolidated earnings contribution | 35% to 45% | ||
Total assets | $17.3 billion | ||
Electric generating capacity | 5,685 MW | ||
Gas storage capacity | 27.1 Bcf | ||
4
ELECTRIC UTILITY OPERATIONS
Electric Operating Statistics
Year Ended Dec. 31 | |||||||||||
2018 | 2017 | 2016 | |||||||||
Electric sales (Millions of KWh) | |||||||||||
Residential | 9,438 | 9,107 | 9,272 | ||||||||
Large C&I | 6,566 | 6,449 | 6,371 | ||||||||
Small C&I | 12,973 | 12,796 | 12,890 | ||||||||
Public authorities and other | 270 | 274 | 268 | ||||||||
Total retail | 29,247 | 28,626 | 28,801 | ||||||||
Sales for resale | 7,403 | 4,851 | 4,672 | ||||||||
Total energy sold | 36,650 | 33,477 | 33,473 | ||||||||
Number of customers at end of period | |||||||||||
Residential | 1,271,423 | 1,252,376 | 1,235,378 | ||||||||
Large C&I | 337 | 340 | 337 | ||||||||
Small C&I | 161,713 | 160,406 | 159,299 | ||||||||
Public authorities and other | 54,160 | 54,110 | 54,048 | ||||||||
Total retail | 1,487,633 | 1,467,232 | 1,449,062 | ||||||||
Wholesale | 52 | 43 | 34 | ||||||||
Total customers | 1,487,685 | 1,467,275 | 1,449,096 | ||||||||
Electric revenues (Millions of Dollars) | |||||||||||
Residential | $ | 1,025.1 | $ | 1,033.3 | $ | 1,063.5 | |||||
Large C&I | 406.8 | 421.1 | 414.8 | ||||||||
Small C&I | 1,191.2 | 1,227.9 | 1,204.9 | ||||||||
Public authorities and other | 50.5 | 52.8 | 54.1 | ||||||||
Total retail | 2,673.6 | 2,735.1 | 2,737.3 | ||||||||
Wholesale | 179.4 | 168.0 | 152.4 | ||||||||
Other electric revenues | 178.2 | 100.7 | 159.7 | ||||||||
Total electric revenues | $ | 3,031.2 | $ | 3,003.8 | $ | 3,049.4 | |||||
KWh sales per retail customer | 19,660 | 19,510 | 19,876 | ||||||||
Revenue per retail customer | $ | 1,797 | $ | 1,864 | $ | 1,889 | |||||
Residential revenue per KWh | 10.86 | ¢ | 11.35 | ¢ | 11.47 | ¢ | |||||
Large C&I revenue per KWh | 6.20 | 6.53 | 6.51 | ||||||||
Small C&I revenue per KWh | 9.18 | 9.60 | 9.35 | ||||||||
Total retail revenue per KWh | 9.14 | 9.55 | 9.50 | ||||||||
Wholesale revenue per KWh | 2.42 | 3.46 | 3.26 | ||||||||
5
Energy Sources 2018
*Distributed generation from the Solar*Rewards® program is not included (approximately 387 million KWh for 2018).
Energy Source Statistics
In 2018 and 2017, of PSCo’s total energy generation, 70% was owned and 30% was purchased.
Renewable Sources
PSCo’s renewable energy portfolio includes wind, hydroelectric, and solar power from both owned generating facilities and PPAs. As of Dec. 31, 2018, PSCo was in compliance with its applicable renewable portfolio standards. Renewable percentages will vary year over year based on local weather, system demand and transmission constraints.
PSCo
Renewable energy as a percentage of PSCo’s total:
2018 | 2017 | |||||
Wind | 23.8 | % | 23.7 | % | ||
Hydroelectric and solar | 3.6 | 3.9 | ||||
Renewable | 27.4 | % | 27.6 | % | ||
Wind — PSCo has 19 PPAs ranging from two MW to over 300 MW. PSCo owns and operates the Rush Creek wind farm which has 600 MW, net, of capacity.
• | PSCo had approximately 3,160 MW and 2,560 MW of wind energy on its system at the end of 2018 and 2017, respectively. |
• | Average cost per MWh of wind energy under these contracts was approximately $43 and $42 for 2018 and 2017, respectively. |
• | Rush Creek became operational in December 2018. The 2019 average cost per MWh is expected to be $29. |
Non-Renewable Sources
Delivered cost per MMBtu of each significant category of fuel consumed for owned electric generation and the percentage of total fuel requirements represented by each category of fuel:
Coal | Natural Gas | |||||||||||||
Cost | Percent | Cost | Percent | |||||||||||
2018 | $ | 1.45 | 62 | % | $ | 3.74 | 38 | % | ||||||
2017 | 1.56 | 70 | 3.82 | 30 | ||||||||||
Weighted average cost per MMBtu of all fuels for owned electric generation was $2.33 in 2018 and $2.25 in 2017.
See Items 1A and 7 for further information.
Coal — Inventory maintained (in days):
Normal | Dec. 31, 2018 Actual | Dec. 31, 2017 Actual (a) | ||
35 - 50 | 48 | 48 | ||
(a) | Milder weather, purchase commitments and low power and natural gas prices impacted coal inventory levels. |
Coal requirements (in million tons) were 9.4 in 2018 and 10.0 in 2017. Coal supply as a percentage of requirements for 2019 is 8.4 million tons or 83% of contracted coal supply. The general coal purchasing objective is to contract for approximately 75% of year one requirements, 40% of year two requirements and 20% of year three requirements.
Contracted coal transportation as a percentage of requirements in 2019 and 2020 is 100%.
Natural Gas — Natural gas supplies, transportation and storage services for power plants are procured to provide an adequate supply of fuel. Remaining requirements are procured through a liquid spot market. Generally, natural gas supply contracts have variable pricing that is tied to natural gas indices. Natural gas supply and transportation agreements include obligations for the purchase and/or delivery of specified volumes or payments in lieu of delivery.
Contracts and commitments at Dec. 31:
(Millions of Dollars) | Gas Supply (a) | Gas Transportation and Storage (b) | ||||||
2018 | $ | 412 | $ | 589 | ||||
2017 | 545 | 620 | ||||||
Year of Expiration | 2021 - 2023 | 2019 - 2040 | ||||||
(a) | The majority of natural gas supply under contract is covered by a long-term agreement with Anadarko Energy Services Company and the balance of natural gas supply contracts have variable pricing features tied to changes in various natural gas indices. PSCo hedges a portion of that risk through financial instruments. See Note 9 to the consolidated financial statements for further information. |
(b) | For incremental supplies, there are limited on-site fuel storage facilities, with a primary reliance on the spot market. |
Capacity and Demand
Uninterrupted system peak demand for PSCo’s electric utility for the last two years is as follows:
System Peak Demand (in MW) | ||||||||
2018 | 2017 | |||||||
6,718 | July 10 | 6,671 | July 19 | |||||
The peak demand typically occurs in the summer. The increase in peak load from 2017 to 2018 is partly due to warmer weather in 2018.
6
Public Utility Regulation
Summary of Regulatory Agencies and Areas of Jurisdiction — PSCo is regulated by the CPUC with respect to its facilities, rates, accounts, services and issuance of securities. PSCo is regulated by the FERC for its wholesale electric operations, accounting practices, hydroelectric licensing, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with the NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce. PSCo is not presently a member of an RTO and does not operate within an RTO energy market. However, PSCo does make certain sales to other RTO’s, including SPP. PSCo makes wholesale electric sales at cost-based prices to customers inside PSCo’s balancing authority area and at market-based prices to customers outside PSCo’s balancing authority area as authorized by the FERC.
Fuel, Purchased Energy and Conservation Cost-Recovery
Mechanisms —
• | ECA — Recovers fuel and purchased energy costs. Short-term sales margins are shared with retail customers through the ECA. The ECA is revised quarterly. |
• | PCCA — Recovers purchased capacity payments. |
• | SCA — Recovers the difference between PSCo’s actual cost of fuel and costs recovered under its steam service rates. The SCA rate is revised quarterly. |
• | DSMCA — Recovers DSM, interruptible service costs and performance initiatives for achieving energy savings goals. |
• | RESA — Recovers the incremental costs of compliance with the RES with a maximum of 2% of the customer’s bill. |
• | WCA — Recovers costs for customers who choose renewable resources. |
• | TCA — Recovers costs for transmission investment outside of rate cases. |
• | CACJA — Recovers costs associated with the CACJA. |
PSCo recovers fuel and purchased energy costs from its wholesale electric customers through a fuel cost adjustment clause approved by the FERC. The wholesale customers pay their jurisdictional allocation of production costs through a fully forecasted formula rate with true-up.
Energy Sources and Transmission Service Providers
PSCo expects to meet its system capacity requirements through electric generating stations, power purchases, new generation facilities, DSM options and expansion of generation plants.
Purchased Power — PSCo purchases power from other utilities and IPPs. Long-term purchased power contracts for dispatchable resources typically require capacity charge and energy charges. PSCo also contracts to purchase power for both wind and solar resources. PSCo makes short-term purchases to meet system load and energy requirements, replace owned generation, meet operating reserve obligations or obtain energy at a lower cost.
Purchased Transmission Services — In addition to using its own transmission system, PSCo has contracts with regional transmission service providers to deliver energy to its customers.
Wind Development — In 2018, PSCo completed construction and placed in service its Rush Creek 600 MW wind farm in Colorado.
CEP — In September 2018, the CPUC approved PSCo’s preferred CEP portfolio, which included the retirement of two coal-fired generation units, Comanche Unit 1 (in 2022) and Comanche Unit 2 (in 2025), and the following additions:
Total Capacity | PSCo's Ownership | |||
Wind generation | 1,100 MW | 500 MW | ||
Solar generation | 700 MW | — | ||
Battery storage | 275 MW | — | ||
Natural gas generation | 380 MW | 380 MW | ||
PSCo’s investment is expected to be approximately $1 billion, including transmission to support the increase in renewable generation in the state. This investment includes the 500 MW Cheyenne Ridge Wind Farm and the 345 KV generation tie line, as well as the Shortgrass Substation. CPCNs for these projects were filed in December 2018. A CPUC decision is anticipated by May 2019. CPCNs for the natural gas facility are anticipated to be filed by mid-2019.
Boulder Municipalization — In 2011, Boulder passed a ballot measure authorizing the formation of an electric municipal utility, subject to certain conditions. Subsequently, there have been various legal proceedings in multiple venues with jurisdiction over Boulder’s plan. In 2014, the Boulder City Council passed an ordinance to establish an electric utility. PSCo challenged the formation of this utility and the Colorado Court of Appeals ruled in PSCo’s favor, vacating a lower court decision. In June 2018, the Colorado Supreme court rejected Boulder’s request to dismiss the case and remanded it to the Boulder District Court.
Boulder has filed multiple separation applications with the CPUC, which have been challenged by PSCo and other intervenors. In September 2017, the CPUC issued a written decision, agreeing with several key aspects of PSCo’s position. The CPUC has approved the designation of some electrical distribution assets for transfer, subject to Boulder completing certain filings. Those filings were submitted in the fourth quarter of 2018. Subsequently, various parties requested the CPUC commence additional processes; the form of such processes is currently under consideration. In the fourth quarter of 2018, Boulder’s City Council also adopted an Ordinance authorizing Boulder to begin negotiations for the acquisition of certain property or to otherwise condemn that property after Feb. 1, 2019. In the first quarter of 2019, Boulder sent PSCo a Notice of Intent to acquire certain electric distribution assets.
Boulder does not have authorization from the CPUC to initiate a condemnation proceeding at this time.
Wholesale and Commodity Marketing Operations
PSCo conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy related products. PSCo uses physical and financial instruments to minimize commodity price and credit risk and hedge sales and purchases. PSCo also engages in trading activity unrelated to hedging and sharing of any margins is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement.
7
NATURAL GAS UTILITY OPERATIONS
Natural Gas Operating Statistics
Year Ended Dec. 31 | |||||||||||
2018 | 2017 | 2016 | |||||||||
Natural gas deliveries (Thousands of MMBtu) | |||||||||||
Residential | 97,409 | 88,843 | 90,941 | ||||||||
C&I | 40,467 | 37,305 | 38,093 | ||||||||
Total retail | 137,876 | 126,148 | 129,034 | ||||||||
Transportation and other | 155,281 | 124,211 | 117,462 | ||||||||
Total deliveries | 293,157 | 250,359 | 246,496 | ||||||||
Number of customers at end of period | |||||||||||
Residential | 1,300,826 | 1,284,644 | 1,269,338 | ||||||||
C&I | 101,036 | 100,802 | 100,718 | ||||||||
Total retail | 1,401,862 | 1,385,446 | 1,370,056 | ||||||||
Transportation and other | 7,891 | 7,649 | 7,261 | ||||||||
Total customers | 1,409,753 | 1,393,095 | 1,377,317 | ||||||||
Natural gas revenues (Millions of Dollars) | |||||||||||
Residential | $ | 649.9 | $ | 652.9 | $ | 611.8 | |||||
C&I | 244.5 | 247.6 | 228.1 | ||||||||
Total retail | 894.4 | 900.5 | 839.9 | ||||||||
Transportation and other | 120.2 | 94.7 | 117.8 | ||||||||
Total natural gas revenues | $ | 1,014.6 | $ | 995.2 | $ | 957.7 | |||||
MMBtu sales per retail customer | 98.35 | 91.05 | 94.18 | ||||||||
Revenue per retail customer | $ | 638 | $ | 650 | $ | 613 | |||||
Residential revenue per MMBtu | 6.67 | 7.35 | 6.73 | ||||||||
C&I revenue per MMBtu | 6.04 | 6.64 | 5.99 | ||||||||
Transportation and other revenue per MMBtu | 0.77 | 0.76 | 1.00 | ||||||||
Capability and Demand
Natural gas supply requirements are categorized as firm or interruptible (customers with an alternate energy supply).
Maximum daily send-out (firm and interruptible) and occurrence date for PSCo:
2018 | 2017 | |||||||
MMBtu | Date | MMBtu | Date | |||||
1,903,878 | (a) | Feb. 20 | 1,948,167 | Jan. 5 | ||||
(a) | Decrease in MMBtu output due to milder winter temperatures in 2018. |
Natural gas is purchased from independent suppliers, generally based on market indices that reflect current prices, and is delivered under transportation agreements with interstate pipelines. These agreements provide for firm deliverable pipeline capacity of 1,834,843 MMBtu per day. This amount includes 871,418 MMBtu of natural gas held under third-party underground storage agreements.
PSCo also operates three company-owned underground storage facilities, which provide approximately 43,500 MMBtu of natural gas on peak days. The balance required to meet firm peak day sales obligations is primarily purchased at PSCo’s city gate meter stations.
Natural Gas Supply and Costs
PSCo actively seeks natural gas supply, transportation and storage alternatives to yield a diversified portfolio which provides increased flexibility, decreased interruption and financial risk and economical rates. In addition, PSCo conducts natural gas price hedging activities approved by their respective state commissions.
Average delivered cost per MMBtu of natural gas for regulated retail distribution was $3.20 and $3.45 in 2018 and 2017, respectively.
PSCo has natural gas supply transportation and storage agreements that include obligations for the purchase and/or delivery of specified volumes or to make payments in lieu of delivery. As of Dec. 31, 2018, PSCo was committed to approximately $1.1 billion of obligations under contracts, which expire in various years from 2019 - 2029.
Public Utility Regulation
Summary of Regulatory Agencies and Areas of Jurisdiction — PSCo is regulated by the CPUC with respect to its facilities, rates, accounts, services and issuance of securities. PSCo holds a FERC certificate that allows it to transport natural gas in interstate commerce without PSCo becoming subject to full FERC jurisdiction. PSCo is subject to the DOT and CPUC with regards to pipeline safety compliance.
8
Purchased Natural Gas and Conservation Cost-Recovery
Mechanisms —
• | GCA — Recovers the costs of purchased natural gas and transportation to meet customer requirements and is revised quarterly to allow for changes in natural gas rates. |
• | DSMCA — Recovers costs of DSM and performance initiatives to achieve various energy savings goals. |
• | PSIA — Recovers costs for transmission and distribution pipeline integrity management programs. |
GENERAL
Seasonality
Demand for electric power and natural gas is affected by seasonal differences in the weather. In general, peak sales of electricity occur in the summer months and peak sales of natural gas occur in the winter months. As a result, the overall operating results may fluctuate substantially on a seasonal basis. Additionally, PSCo’s operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer.
See Item 7 for further information.
Competition
PSCo is a vertically integrated utility subject to traditional cost-of-service regulation by state public utilities commissions. PSCo is subject to public policies that promote competition and development of energy markets. PSCo’s industrial and large commercial customers have the ability to generate their own electricity. In addition, customers may have the option of substituting other fuels or relocating their facilities to a lower cost region.
Customers have the opportunity to supply their own power with distributed generation including, but not limited to, solar generation and in most jurisdictions can currently avoid paying for most of the fixed production, transmission and distribution costs incurred to serve them. Several states, including PSCo, have policies designed to promote the development of solar and other distributed energy resources through incentive policies. With these incentives and federal tax subsidies, distributed generating resources are potential competitors to PSCo’s electric service business.
The FERC has continued to promote competitive wholesale markets through open access transmission and other means. As a result, PSCo and its wholesale customers can purchase the output from generation resources of competing wholesale suppliers and use the transmission systems of Xcel Energy Inc.’s utility subsidiaries on a comparable basis to serve their native load.
FERC Order No. 1000 seeks to establish competition for construction and operation of certain new electric transmission facilities. State utilities commissions have also created resource planning programs that promote competition for electricity generation resources used to provide service to retail customers.
PSCo has franchise agreements with cities subject to periodic renewal; however, a city could seek alternative means to access electric power or gas, such as municipalization.
While facing these challenges, PSCo believes its rates and services are competitive with the alternatives currently available.
ENVIRONMENTAL MATTERS
PSCo’s facilities are regulated by federal and state environmental agencies that have jurisdiction over air emissions, water quality, wastewater discharges, solid wastes and hazardous substances. Various company activities require registrations, permits, licenses, inspections and approvals from these agencies. PSCo has received all necessary authorizations for the construction and continued operation of its generation, transmission and distribution systems. PSCo’s facilities have been designed and constructed to operate in compliance with applicable environmental standards and related monitoring and reporting requirements. However, it is not possible to determine when or to what extent additional facilities or modifications of existing or planned facilities will be required as a result of changes to environmental regulations, interpretations or enforcement policies or what effect future laws or regulations may have upon PSCo’s operations. PSCo may be required to incur capital expenditures in the future to comply with requirements for remediation of MGP and other legacy sites. The scope and timing of these expenditures cannot be determined until more information is obtained regarding the need for remediation at legacy sites.
The Denver North Front Range Nonattainment Area does not meet either the 2008 or 2015 ozone National Ambient Air Quality Standard. Colorado will continue to consider further reductions available in the non-attainment area as it develops plans to meet ozone standards. Gas plants which operate in PSCo’s non-attainment area may be required to improve or add controls, implement further work practices and/or implement enhanced emissions monitoring as part of future Colorado state plans.
There are significant present and future environmental regulations to encourage use of clean energy technologies and regulate emissions of GHGs. PSCo has undertaken numerous initiatives to meet current requirements and prepare for potential future regulations, reduce GHG emissions and respond to state renewable and energy efficiency goals. If future environmental regulations do not provide credit for the investments PSCo has already made or if they require additional initiatives or emission reductions, substantial costs may be incurred.
The EPA, as an alternative to the Clean Power Plan, has proposed a new regulation that, if adopted, would require implementation of heat rate improvement projects at our coal-fired power plants. It is not known what those costs might be until a final rule is adopted and state plans are developed to implement a final regulation. PSCo believes, based on prior state commission practice, the cost of these initiatives or replacement generation would be recoverable through rates.
PSCo is committed to addressing climate change and potential climate change regulation through efforts to reduce its GHG emissions in a balanced, cost-effective manner. Starting in 2011, PSCo began reporting GHG emissions under the EPA’s mandatory GHG Reporting Program.
EMPLOYEES
As of Dec. 31, 2018, PSCo had 2,426 full-time employees and no part-time employees, of which 1,904 were covered under collective-bargaining agreements.
Item 1A — Risk Factors
Xcel Energy, which includes PSCo, is subject to a variety of risks, many of which are beyond our control. Risks that may adversely affect the business, financial condition, results of operations or cash flows are described below. These risks should be carefully considered together with the other information set forth in this report and future reports that Xcel Energy files with the SEC.
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Oversight of Risk and Related Processes
A key accountability of the Board of Directors is the oversight of material risk, and our Board of Directors employs an effective process for doing so. Management and the Board of Directors have responsibility for overseeing the identification and mitigation of key risks.
Management identifies and analyzes risks to determine materiality and other attributes such as timing, probability and controllability. Identification and analysis occurs formally through a key risk assessment process by senior management, the financial disclosure process, hazard risk management procedures and internal auditing and compliance with financial and operational controls. Management also identifies and analyzes risk through its business planning process and development of goals and key performance indicators, which include risk identification to determine barriers to implementing our strategy. The business planning process also identifies areas in which there is a potential for a business area to assume inappropriate risk to meet goals, and determines how to prevent inappropriate risk-taking.
At a threshold level, PSCo has a robust compliance program and promotes a culture of compliance, including tone at the top. The process for risk mitigation includes adherence to our code of conduct and compliance policies, operation of formal risk management structures and overall business management to mitigate the risks inherent in the implementation of strategy. Building on this culture of compliance, management further mitigates risks through formal risk management structures, including management councils, risk committees and services of corporate areas such as internal audit, corporate controller and legal.
Management communicates regularly with the Board of Directors and key stakeholders regarding risk. Senior management presents and communicates a periodic risk assessment to the Board of Directors. The presentation and the discussion of the key risks provide information on the risks management believes are material, including the earnings impact, timing, likelihood and controllability. Oversight of cybersecurity risks by the Operations, Nuclear, Environmental and Safety Committee includes receiving independent outside assessments of cybersecurity maturity and assessment of plans.
Overall, the Board of Directors approaches oversight, management and mitigation of risk as an integral and continuous part of its governance of PSCo. Processes are in place to ensure appropriate risk oversight, as well as identification and consideration of new risks. The Board of Directors regularly reviews management’s key risk assessment informed by these processes, and analyzes areas of existing and future risks and opportunities.
Risks Associated with Our Business
Operational Risks
Our natural gas and electric transmission and distribution operations involve numerous risks that may result in accidents and other operating risks and costs.
Our natural gas transmission and distribution activities include inherent hazards and operating risks, such as leaks, explosions, outages and mechanical problems. Our electric transmission and distribution activities also include inherent hazards and operating risks such as contact, fire and outages which could cause substantial financial losses. These natural gas and electric risks could result in loss of life, significant property damage, environmental pollution, impairment of our operations and substantial losses. We maintain insurance against some, but not all, of these risks and losses. The occurrence of these events, if not fully covered by insurance, could have a material effect on our results of operations, financial condition or cash flows.
Additionally, for natural gas costs that may be required in order to comply with potential new regulations, including the Pipeline Safety Act, could be significant.
The Pipeline Safety Act requires verification of pipeline infrastructure records by pipeline owners and operators to confirm the maximum allowable operating pressure of lines located in high consequence areas or more-densely populated areas. We have programs in place to comply with the Pipeline Safety Act and for systematic infrastructure monitoring and renewal over time. A significant incident could increase regulatory scrutiny and result in penalties and higher costs of operations.
The PHMSA is responsible for administering the DOT’s national regulatory program to assure the safe transportation of natural gas, petroleum and other hazardous materials by pipelines. The PHMSA continues to develop regulations and other approaches to risk management to assure safety in design, construction, testing, operation, maintenance, and emergency response of natural gas pipeline infrastructure.
Our utility operations are subject to long-term planning risks.
Most electric utility investments are planned to be used for decades. Transmission and generation investments typically have long lead times and are planned well in advance of when they are brought in-service subject to long-term resource plans. These plans are based on numerous assumptions such as: sales growth, customer usage, commodity prices, economic activity, costs, regulatory mechanisms, customer behavior, available technology and public policy.
The electric utility sector is undergoing a period of significant change. For example, increases in appliance, lighting and energy efficiency, wider adoption and lower cost of renewable generation and distributed generation, shifts away from coal generation to decrease carbon dioxide emissions and increasing use of natural gas in electric generation driven by lower natural gas prices.
Customer adoption of these technologies and increased energy efficiency could result in excess transmission and generation resources as well as stranded costs if PSCo is not able to fully recover the costs and investments. These changes also introduce additional uncertainty into long-term planning which gives rise to a risk that the magnitude and timing of resource additions and growth in customer demand may not coincide, and that the preference for the types of additions may change from planning to execution. In addition, we are subject to longer-term availability of the natural resource inputs such as coal, natural gas, uranium and water to cool our facilities. Lack of availability of these resources could jeopardize long-term operations of our facilities or make them uneconomic to operate.
Changing customer expectations and technologies are requiring significant investments in advanced grid infrastructure. This increases the exposure to potential outdating of technologies and resultant risks. The inability of coal mining companies to attract capital could disrupt longer-term supplies. Decreasing use per customer driven by appliance and lighting efficiency and the availability of cost-effective distributed generation places downward pressure on sales growth. This may lead to under recovery of costs, excess resources to meet customer demand and increases in electric rates. Finally, multiple states may not agree as to the appropriate resource mix and the differing views may lead to costs incurred to comply with one jurisdiction that are not recoverable across all of the jurisdictions served by the same assets.
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We are subject to commodity risks and other risks associated with energy markets and energy production.
If fuel costs increase, customer demand could decline and bad debt expense may rise, which could have a material impact on our results of operations. While we have fuel clause recovery mechanisms, higher fuel costs could significantly impact our results of operations if costs are not recovered. Delays in the timing of the collection of fuel cost recoveries could impact our cash flows. Low fuel costs have a positive impact on sales, however low oil and natural gas prices could negatively impact oil and gas production activities and subsequently our sales volumes and revenue.
A significant disruption in supply could cause us to seek alternative supply services at potentially higher costs or suffer increased liability for unfulfilled contractual obligations. Significantly higher energy or fuel costs relative to sales commitments have a negative impact on our cash flows and potentially result in economic losses. Potential market supply shortages may not be fully resolved through alternative supply sources and could cause disruptions in our ability to provide electric and/or natural gas services to our customers. Failure to provide service due to disruptions may also result in fines, penalties or cost disallowances through the regulatory process.
We also engage in wholesale sales and purchases of electric capacity, energy and energy-related products as well as natural gas. In many markets, emission allowances and/or RECs are also needed to comply with various statutes and commission rulings. As a result we are subject to market supply and commodity price risk. Commodity price changes can affect the value of our commodity trading derivatives. We mark certain derivatives to estimated fair market value on a daily basis. Actual settlements can vary significantly from estimated fair values recorded and significant changes from the assumptions underlying our fair value estimates could cause earnings variability.
As we are a subsidiary of Xcel Energy Inc., we may be negatively affected by events impacting the credit or liquidity of Xcel Energy Inc. and its affiliates.
If Xcel Energy Inc. were to become obligated to make payments under various guarantees and bond indemnities or to fund its other contingent liabilities, or if either Standard & Poor’s or Moody’s were to downgrade Xcel Energy Inc.’s credit rating below investment grade, Xcel Energy Inc. may be required to provide credit enhancements in the form of cash collateral, letters of credit or other security to satisfy part or potentially all of these exposures. If either Standard & Poor’s or Moody’s were to downgrade Xcel Energy Inc.’s debt securities below investment grade, it would increase Xcel Energy Inc.’s cost of capital and restrict its access to the capital markets. This could limit Xcel Energy Inc.’s ability to contribute equity or make loans to us, or may cause Xcel Energy Inc. to seek additional or accelerated funding from us in the form of dividends. If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.
As of Dec. 31, 2018, Xcel Energy Inc. and its utility subsidiaries had approximately $15.8 billion of long-term debt and $1.4 billion of short-term debt and current maturities. Xcel Energy Inc. provides various guarantees and bond indemnities supporting some of its subsidiaries by guaranteeing the payment or performance by these subsidiaries for specified agreements or transactions.
Xcel Energy also has other contingent liabilities resulting from various tax disputes and other matters. Xcel Energy Inc.’s exposure under the guarantees is based upon the net liability of the relevant subsidiary under the specified agreements or transactions. The majority of Xcel Energy Inc.’s guarantees limit its exposure to a maximum amount that is stated in the guarantees. As of Dec. 31, 2018, Xcel Energy had guarantees outstanding with a maximum stated amount of approximately $17.8 million and immaterial exposure. Xcel Energy also had additional guarantees of $51.1 million at Dec. 31, 2018 for performance and payment of surety bonds for the benefit of itself and its subsidiaries, with total exposure that cannot be estimated at this time. If Xcel Energy Inc. were to become obligated to make payments under these guarantees and bond indemnities or become obligated to fund other contingent liabilities, it could limit Xcel Energy Inc.’s ability to contribute equity or make loans to us, or may cause Xcel Energy Inc. to seek additional or accelerated funding from us in the form of dividends. If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.
We are a wholly owned subsidiary of Xcel Energy Inc. Xcel Energy Inc. can exercise substantial control over our dividend policy and business and operations and may exercise that control in a manner that may be perceived to be adverse to our interests.
All of the members of our Board of Directors, as well as many of our executive officers, are officers of Xcel Energy Inc. Our Board makes determinations with respect to a number of significant corporate events, including the payment of our dividends.
We have historically paid quarterly dividends to Xcel Energy Inc. In 2018, 2017 and 2016 we paid $375.3 million, $333.9 million and $336.6 million of dividends to Xcel Energy Inc., respectively. If Xcel Energy Inc.’s cash requirements increase, our Board of Directors could decide to increase the dividends we pay to Xcel Energy Inc. to help support Xcel Energy Inc.’s cash needs. This could adversely affect our liquidity. The most restrictive dividend limitation for PSCo is imposed by its credit facility, which limits the debt-to-total capitalization ratio. See Note 5 to the consolidated financial statements for further information.
Financial Risks
Our profitability depends on our ability to recover costs from our customers and changes in regulation may impair our ability to recover costs from our customers.
We are subject to comprehensive regulation by federal and state utility regulatory agencies, including siting and construction of facilities, customer service and the rates that we can charge customers.
The profitability of our operations is dependent on our ability to recover the costs of providing energy and utility services and earn a return on our capital investment. Our rates are generally regulated and based on an analysis of our costs incurred in a test year. We are subject to both future and historical test years depending upon the regulatory jurisdiction. Thus, the rates we are allowed to charge may or may not match our costs at any given time. Rate regulation is premised on providing an opportunity to earn a reasonable rate of return on invested capital. In a continued low interest rate environment there has been pressure pushing down ROE. There can also be no assurance that our regulatory commission will judge all of our costs to be prudent, which could result in disallowances, or that the regulatory process always result in rates that will produce full recovery.
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Changes in the long-term cost-effectiveness or changes to the operating conditions of our assets may result in early retirements of utility facilities and while regulation typically provides relief for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs leaving all or a portion of these asset costs stranded. Higher than expected inflation or tariffs may increase costs of construction and operations. Rising fuel costs could increase the risk that we will not be able to fully recover our fuel costs from our customers. Furthermore, there could be changes in the regulatory environment that would impair our ability to recover costs historically collected from our customers, or these factors could cause us to exceed commitments made regarding cost caps and result in less than full recovery. Overall, management currently believes prudently incurred costs are recoverable given the existing regulatory mechanisms in place.
Adverse regulatory rulings or the imposition of additional regulations could have an adverse impact on our results of operations and materially affect our ability to meet our financial obligations, including debt payments.
Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships.
We cannot be assured that our current ratings will remain in effect, or that a rating will not be lowered or withdrawn by a rating agency. Significant events including a disallowance of costs, significantly lower returns on equity or equity ratios or impacts of tax policy changes may impact our cash flows and credit metrics, potentially resulting in a change in our credit ratings. In addition, our credit ratings may change as a result of the differing methodologies or change in the methodologies used by the various rating agencies.
Any downgrade could lead to higher borrowing costs and could impact our ability to access capital markets. Also, we may enter into contracts that require the posting of collateral or settlement of applicable contracts if credit ratings fall below investment grade.
We are subject to capital market and interest rate risks.
Utility operations require significant capital investment. As a result, we frequently need to access capital markets. Any disruption in capital markets could have a material impact on our ability to fund our operations. Capital markets are global and impacted by issues and events throughout the world. Capital market disruption events and financial market distress could prevent us from issuing short-term commercial paper, issuing new securities or cause us to issue securities with unfavorable terms and conditions, such as higher interest rates.
Higher interest rates on short-term borrowings with variable interest rates could also have an adverse effect on our operating results. Changes in interest rates may also impact the fair value of the debt securities in the pension funds, as well as our ability to earn a return on short-term investments of excess cash.
We are subject to credit risks.
Credit risk includes the risk that our customers will not pay their bills, which may lead to a reduction in liquidity and an increase in bad debt expense. Credit risk is comprised of numerous factors including the price of products and services provided, the overall economy and local economies in the geographic areas we serve, including local unemployment rates.
Credit risk also includes the risk that various counterparties that owe us money or product will become insolvent and/or breach their obligations. Should the counterparties fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected and incur losses.
We may at times have direct credit exposure in our short-term wholesale and commodity trading activity to financial institutions trading for their own accounts or issuing collateral support on behalf of other counterparties. We may also have some indirect credit exposure due to participation in organized markets, such as the California Independent System Operator, SPP, PJM Interconnection, LLC, Midcontinent Independent Transmission System Operator, Inc. and the ERCOT, in which any credit losses are socialized to all market participants.
We have additional indirect credit exposures to financial institutions in the form of letters of credit provided as security by power suppliers under various purchased power contracts. If any of the credit ratings of the letter of credit issuers were to drop below investment grade, the supplier would need to replace that security with an acceptable substitute. If the security were not replaced, the party could be in default under the contract.
Increasing costs of our defined benefit retirement plans and employee benefits may adversely affect our results of operations, financial condition or cash flows.
We have defined benefit pension and postretirement plans that cover most of our employees. Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements related to these plans. Estimates and assumptions may change. In addition, the Pension Protection Act changed the minimum funding requirements for defined benefit pension plans. Therefore, our funding requirements and related contributions may change in the future. Also, the payout of a significant percentage of pension plan liabilities in a single year due to high retirements or employees leaving PSCo could trigger settlement accounting and could require PSCo to recognize incremental pension expense related to unrecognized plan losses in the year liabilities are paid.
Increasing costs associated with health care plans may adversely affect our results of operations.
Our self-insured costs of health care benefits for eligible employees have increased in recent years. Increasing levels of large individual health care claims and overall health care claims could have an adverse impact on our operating results, financial condition and cash flows. Changes in industry standards utilized in key assumptions (e.g., mortality tables) could have a significant impact on future liabilities and benefit costs. Legislation related to health care could also significantly change our benefit programs and costs.
Federal tax law may significantly impact our business.
PSCo collects through regulated rates estimated federal, state and local tax payments. Changes to federal tax law may benefit or adversely affect our earnings and customer costs. Changes to tax depreciable lives and the value of various tax credits may change the economics of resources and our resource selections. There could be timing delays before regulated rates provide for realization of the tax changes in revenues. In addition, certain IRS tax policies such as the requirement to utilize normalization may impact our ability to economically deliver certain types of resources relative to market prices.
Macroeconomic Risks
Economic conditions impact our business.
Our operations are affected by local, national and worldwide economic conditions. Growth in customers and sales are correlated with economic conditions.
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Economic conditions may be impacted by insufficient financial sector liquidity leading to potential increased unemployment, which may impact customers’ ability to pay timely, increase customer bankruptcies, and may lead to additional bad debt expense.
Further, worldwide economic activity impacts the demand for basic commodities necessary for utility infrastructure, which may impact our ability to acquire sufficient supplies. We operate in a capital intensive industry and federal policy on trade could significantly impact the cost of materials we use. We could be at risk for higher costs for materials and our workforce. There may be delays before these additional costs can be recovered in rates.
Our operations could be impacted by war, acts of terrorism, and threats of terrorism or disruptions due to events.
Our generation plants, fuel storage facilities, transmission and distribution facilities and information and control systems may be targets of terrorist activities. Any disruption could impact operations or result in a decrease in revenues and additional costs to repair and insure our assets. These disruptions could have a material impact on our financial condition, results of operations or cash flows. The potential for terrorism has subjected our operations to increased risks and could have a material effect on our business. We have already incurred increased costs for security and capital expenditures in response to these risks.
The insurance industry has also been affected by these events and the availability of insurance may decrease. In addition, insurance may have higher deductibles, higher premiums and more restrictive policy terms.
A disruption of the regional electric transmission grid, interstate natural gas pipeline infrastructure or other fuel sources, could negatively impact our business, our brand and reputation. Because our facilities are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by the actions of a neighboring utility or an event (e.g., severe storm, severe temperature extremes, wildfires, generator or transmission facility outage, pipeline rupture, railroad disruption, operator error, sudden and significant increase or decrease in wind generation or a disruption of work force) within our operating systems or on a neighboring system. Any such disruption could result in a significant decrease in revenues and significant additional costs to repair assets, which could have a material impact on our results of operations, financial condition or cash flows.
A cyber incident or security breach could have a material effect on our business.
We operate in an industry that requires the continued operation of sophisticated information technology, control systems and network infrastructure. In addition, we use our systems and infrastructure to create, collect, use, disclose, store, dispose of and otherwise process sensitive information, including company data, customer energy usage data, and personal information regarding customers, employees and their dependents, contractors and other individuals.
Our generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets, as well as information processed in our systems (e.g., information regarding our customers, employees, operations, infrastructure and assets) could be affected by cyber security incidents, including those caused by human error.
Our industry has begun to see an increased volume and sophistication of cyber security incidents from international activist organizations, Nation States and individuals. Cyber security incidents could harm our businesses by limiting our generating, transmitting and distributing capabilities, delaying our development and construction of new facilities or capital improvement projects to existing facilities, disrupting our customer operations or causing the release of customer information, all of which could expose us to liability.
Our generation, transmission systems and natural gas pipelines are part of an interconnected system. Therefore, a disruption caused by the impact of a cyber security incident of the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources of our third party service providers’ operations, could also negatively impact our business.
Our supply chain for procurement of digital equipment may expose software or hardware to these risks and could result in a breach or significant costs of remediation. In addition, such an event would likely receive federal and state regulatory scrutiny. We are unable to quantify the potential impact of cyber security threats or subsequent related actions. These potential cyber security incidents and regulatory action could result in a material decrease in revenues and may cause significant additional costs (e.g., penalties, third party claims, repairs, insurance or compliance) and potentially disrupt our supply and markets for natural gas, oil and other fuels.
We maintain security measures to protect our information technology and control systems, network infrastructure and other assets. However, these assets and the information they process may be vulnerable to cyber security incidents, including the resulting disability, or failures of assets or unauthorized access to assets or information. If our technology systems or those of our third-party service providers were to fail or be breached, we may be unable to fulfill critical business functions. We are unable to quantify the potential impact of cyber security incidents on our business, our brand, and our reputation. The cyber security threat is dynamic and evolves continually, and our efforts to prioritize network monitoring may not be effective given the constant changes to threat vulnerability.
Our operating results may fluctuate on a seasonal and quarterly basis and can be adversely affected by milder weather.
Our electric and natural gas utility businesses are seasonal, and weather patterns can have a material impact on our operating performance. Demand for electricity is often greater in the summer and winter months associated with cooling and heating. Because natural gas is heavily used for residential and commercial heating, the demand depends heavily upon weather patterns. A significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. Unusually mild winters and summers could have an adverse effect on our financial condition, results of operations or cash flows.
Our operations use third party contractors in addition to employees to perform periodic and on-going work.
We rely on third party contractors to perform work for operations, maintenance and construction. We have contractual arrangements with these contractors which typically include performance standards, progress payments, insurance requirements and security for performance.
Cyber security breaches have at times exploited third party equipment or software in order to gain access. Poor vendor performance could impact ongoing operations, restoration operations, our reputation and could introduce financial risk or risks of fines.
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Public Policy Risks
We may be subject to legislative and regulatory responses to climate change, with which compliance could be difficult and costly.
Legislative and regulatory responses related to climate change and new interpretations of existing laws create financial risk as our facilities may be subject to additional regulation at either the state or federal level in the future. Such regulations could impose substantial costs on our system.
We may be subject to climate change lawsuits. An adverse outcome could require substantial capital expenditures and could possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant. Such payments or expenditures could affect results of operations, financial condition or cash flows if such costs are not recovered through regulated rates.
Although the United States has not adopted any international or federal GHG emission reduction targets, many states and localities may continue to pursue climate policies in the absence of federal mandates. All of the steps that PSCo has taken to date to reduce GHG emissions, including energy efficiency measures, adding renewable generation or retiring or converting coal plants to natural gas, occurred under state-endorsed resource plans, renewable energy standards and other state policies. While those actions likely would have put PSCo in a good position to meet federal or international standards being discussed, the lack of federal action does not adversely impact these state-endorsed actions and plans.
If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material effect on our financial condition, results of operations or cash flows.
Increased risks of regulatory penalties could negatively impact our business.
The Energy Act increased civil penalty authority for violation of FERC statutes, rules and orders. The FERC can impose penalties of up to $1.3 million per violation per day, particularly as it relates to energy trading activities for both electricity and natural gas. In addition, NERC electric reliability standards and critical infrastructure protection requirements are mandatory and subject to potential financial penalties. Additionally, the PHMSA, Occupational Safety and Health Administration and other federal agencies have penalty authority. In the event of serious incidents, these agencies have become more active in pursuing penalties. Some states have the authority to impose substantial penalties. If a serious reliability or safety incident did occur, it could have a material effect on our financial condition, results of operations or cash flows.
Environmental Risks
We are subject to environmental laws and regulations, with which compliance could be difficult and costly.
We are subject to environmental laws and regulations that affect many aspects of our operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances. Laws and regulations require us to obtain permits, licenses, and approvals and to comply with a variety of environmental requirements.
Environmental laws and regulations can also require us to restrict or limit the output of facilities or the use of certain fuels, shift generation to lower-emitting, install pollution control equipment, clean up spills and other contamination and correct environmental hazards. Environmental regulations may also lead to shutdown of existing facilities.
Failure to meet requirements of environmental mandates may result in fines or penalties. We may be required to pay all or a portion of the cost to remediate (i.e., clean-up) sites where our past activities, or the activities of other parties, caused environmental contamination.
We are subject to mandates to provide customers with clean energy, renewable energy and energy conservation offerings. It could have a material effect on our results of operations, financial condition or cash flows. If our regulators do not allow us to recover the cost of capital investment or the O&M costs incurred to comply with the requirements.
In addition, existing environmental laws or regulations may be revised, and new laws or regulations may be adopted. We may also incur additional unanticipated obligations or liabilities under existing environmental laws and regulations.
We are subject to physical and financial risks associated with climate change and other weather, natural disaster and resource depletion impacts.
Climate change can create physical and financial risk. Physical risks include changes in weather conditions and extreme weather events.
Our customers’ energy needs vary with weather. To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease. Increased energy use due to weather changes may require us to invest in generating assets, transmission and infrastructure. Decreased energy use due to weather changes may result in decreased revenues. Extreme weather conditions in general require system backup, costs, and can contribute to increased system stress, including service interruptions. Extreme weather conditions creating high energy demand may raise electricity prices, increasing the cost of energy we provide to our customers.
Severe weather impacts our service territories, primarily when thunderstorms, flooding, tornadoes, wildfires and snow or ice storms occur. To the extent the frequency of extreme weather events increases, this could increase our cost of providing service. Periods of extreme temperatures could impact our ability to meet demand. Changes in precipitation resulting in droughts or water shortages could adversely affect our operations. Drought conditions also contribute to the increase in wildfire risk from our electric generation facilities. While we carry liability insurance, given an extreme event, if PSCo was found to be liable for wildfire damages, amounts that potentially exceed our coverage could negatively impact our results of operations, financial condition or cash flows. Drought or water depletion could adversely impact our ability to provide electricity to customers and increase the price paid for energy. We may not recover all costs related to mitigating these physical and financial risks.
Climate change may impact a region’s economy, which could impact our sales and revenues. The price of energy has an impact on the economic health of our communities. The cost of additional regulatory requirements, such as regulation of GHG, could impact the availability of goods and prices charged by our suppliers which would normally be borne by consumers through higher prices for energy and purchased goods. To the extent financial markets view climate change and emissions of GHGs as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less than ideal terms and conditions.
Item 1B — Unresolved Staff Comments
None.
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Item 2 — Properties
Virtually all of the utility plant property of PSCo is subject to the lien of its first mortgage bond indenture.
Station, Location and Unit | Fuel | Installed | MW (a) | |||||
Steam: | ||||||||
Comanche-Pueblo, CO (b) | ||||||||
Unit 1 | Coal | 1973 | 325 | |||||
Unit 2 | Coal | 1975 | 335 | |||||
Unit 3 | Coal | 2010 | 500 | (c) | ||||
Craig-Craig, CO, 2 Units (d) | Coal | 1979 - 1980 | 82 | (e) | ||||
Hayden-Hayden, CO, 2 Units | Coal | 1965 - 1976 | 233 | (f) | ||||
Pawnee-Brush, CO, 1 Unit | Coal | 1981 | 505 | |||||
Cherokee-Denver, CO, 1 Unit | Natural Gas | 1968 | 310 | |||||
Combustion Turbine: | ||||||||
Blue Spruce-Aurora, CO, 2 Units | Natural Gas | 2003 | 264 | |||||
Cherokee-Denver, CO, 3 Units | Natural Gas | 2015 | 576 | |||||
Fort St. Vrain-Platteville, CO, 6 Units | Natural Gas | 1972 - 2009 | 968 | |||||
Rocky Mountain-Keenesburg, CO, 3 Units | Natural Gas | 2004 | 580 | |||||
Various locations, 6 Units | Natural Gas | Various | 171 | |||||
Hydro: | ||||||||
Cabin Creek-Georgetown, CO | ||||||||
Pumped Storage, 2 Units | Hydro | 1967 | 210 | |||||
Various locations, 9 Units | Hydro | Various | 26 | |||||
Wind: | ||||||||
Rush Creek, CO, 300 units | Wind | 2018 | 600 | (g) | ||||
Total | 5,685 | |||||||
(a) | Summer 2018 net dependable capacity. |
(b) | In 2018, the CPUC approved early retirement of PSCo’s Comanche Units 1 and 2 in 2022 and 2025, respectively. |
(c) | Based on PSCo’s ownership interest of 67% of Unit 3. |
(d) | Craig Unit 1 is expected to be retired early in 2025. |
(e) | Based on PSCo’s ownership interest of 10%. Craig Unit 1 is expected to be retired early in 2025. |
(f) | Based on PSCo’s ownership interest of 76% of Unit 1 and 37% of Unit 2. |
(g) | Generation capability is based on the maximum output level of wind units, including the Rush Creek Wind Project. Capacity is attainable only when wind conditions are sufficiently available (on-demand net dependable capacity is zero). |
Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2018:
Conductor Miles | ||
345 KV | 4,062 | |
230 KV | 12,053 | |
138 KV | 91 | |
115 KV | 5,051 | |
Less than 115 KV | 78,446 | |
PSCo had 232 electric utility transmission and distribution substations at Dec. 31, 2018.
Natural gas utility mains at Dec. 31, 2018:
Miles | ||
Transmission | 2,081 | |
Distribution | 22,518 | |
Item 3 — Legal Proceedings
PSCo is involved in various litigation matters that are being defended and handled in the ordinary course of business. Assessment of whether a loss is probable or is a reasonable possibility, and whether a loss or a range of loss is estimable, often involves a series of complex judgments regarding future events. Management maintains accruals for losses that are probable of being incurred and subject to reasonable estimation. Management may be unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to, when (1) damages sought are indeterminate, (2) proceedings are in the early stages or (3) matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.
See Note 11 to the consolidated financial statements, Item 1 and Item 7 for further information.
Item 4 — Mine Safety Disclosures
None.
PART II
Item 5 — Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
PSCo is a wholly owned subsidiary of Xcel Energy Inc. and there is no market for its common equity securities. See Note 5 to the consolidated financial statements for further information.
The dividends declared during 2018 and 2017 were as follows:
(Millions of Dollars) | 2018 | 2017 | ||||||
First quarter | $ | 95.4 | $ | 87.1 | ||||
Second quarter | 100.3 | 84.0 | ||||||
Third quarter | 103.5 | 88.6 | ||||||
Fourth quarter | 91.5 | 76.2 | ||||||
Item 6 — Selected Financial Data
This is omitted per conditions set forth in general instructions I (1)(a) and (b) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).
Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations
Discussion of financial condition and liquidity for PSCo is omitted per conditions set forth in general instructions I(1)(a) and (b) of Form 10-K for wholly owned subsidiaries. It is replaced with management’s narrative analysis and the results of operations for the current year as set forth in general instructions I(2)(a) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).
15
Non-GAAP Financial Measures
The following discussion includes financial information prepared in accordance with GAAP, as well as certain non-GAAP financial measures such as electric margin, natural gas margin and ongoing earnings. Generally, a non-GAAP financial measure is a measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are adjusted from measures calculated and presented in accordance with GAAP. PSCo’s management uses non-GAAP measures for financial planning and analysis, for reporting of results, in determining performance-based compensation and communicating its earnings outlook to analysts and investors. Non-GAAP financial measures are intended to supplement investors’ understanding of our performance and should not be considered alternatives for financial measures presented in accordance with GAAP. These measures are discussed in more detail below and may not be comparable to other companies’ similarly titled non-GAAP financial measures.
Electric and Natural Gas Margins
Electric margin is presented as electric revenues less electric fuel and purchased power expenses. Natural gas margin is presented as natural gas revenues less the cost of natural gas sold and transported. Expenses incurred for electric fuel and purchased power and the cost of natural gas are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues.
Management believes electric and natural gas margins provide the most meaningful basis for evaluating our operations because they exclude the revenue impact of fluctuations in these expenses. These margins can be reconciled to operating income, a GAAP measure, by including other operating revenues, cost of sales-other, O&M expenses, conservation and DSM expenses, depreciation and amortization and taxes (other than income taxes).
Earnings Adjusted for Certain Items (Ongoing Earnings)
Ongoing earnings reflect adjustments to GAAP earnings (net income) for certain items.
Management uses these non-GAAP financial measures to evaluate and provide details of PSCo’s core earnings and underlying performance. Management believes these measurements are useful to investors to evaluate the actual and projected financial performance and contribution of PSCo.
Results of Operations
PSCo’s net income was approximately $551.7 million for 2018, compared with approximately $494.1 million for 2017. The increase was driven by higher natural gas margins largely due to a natural gas rate increase, higher electric margins (before the impact of the TCJA) reflecting favorable weather and sales growth, and additional AFUDC associated with the Rush Creek wind project. These items were partially offset by higher O&M expenses, interest charges, depreciation expense and property taxes.
Electric Margin
Electric revenues and fuel and purchased power expenses are impacted by fluctuations in the price of natural gas and coal used in the generation of electricity. However, these price fluctuations have minimal impact on electric margin due to fuel recovery mechanisms that recover fuel expenses.
Electric revenues and margin before and after the impact of TCJA:
(Millions of Dollars) | 2018 | 2017 | ||||||
Electric revenues before TCJA impact | $ | 3,095.4 | $ | 3,003.8 | ||||
Electric fuel and purchased power | (1,157.2 | ) | (1,126.7 | ) | ||||
Electric margin before TCJA impact | $ | 1,938.2 | $ | 1,877.1 | ||||
TCJA impact (offset as a reduction in income tax) | (64.2 | ) | — | |||||
Electric margin | $ | 1,874.0 | $ | 1,877.1 | ||||
Electric Margin
(Millions of Dollars) | 2018 vs. 2017 | |||
Retail sales growth (excluding weather impact) | $ | 16.4 | ||
DSM program revenues (offset by expenses) | 14.1 | |||
Non-fuel riders | 12.9 | |||
Estimated impact of weather | 12.8 | |||
Other, net | 4.9 | |||
Total increase in electric margin before TCJA impact | $ | 61.1 | ||
TCJA impact (offset as a reduction in income tax) | (64.2 | ) | ||
Total decrease in electric margin | $ | (3.1 | ) | |
Natural Gas Margin
Total natural gas expense varies with changing sales and the cost of natural gas. However, fluctuations in the cost of natural gas have minimal impact on natural gas margin due to natural gas cost recovery mechanisms.
Natural gas revenues and margin before and after the impact of the TCJA:
(Millions of Dollars) | 2018 | 2017 | ||||||
Natural gas revenues before TCJA impact | $ | 1,044.8 | $ | 995.2 | ||||
Cost of natural gas sold and transported | (428.4 | ) | (458.7 | ) | ||||
Natural gas margin before TCJA impact | $ | 616.4 | $ | 536.5 | ||||
TCJA impact (offset as a reduction in income tax) | (30.2 | ) | — | |||||
Natural gas margin | $ | 586.2 | $ | 536.5 | ||||
Natural Gas Margin
(Millions of Dollars) | 2018 vs. 2017 | |||
Retail rate increase | $ | 50.1 | ||
Infrastructure and integrity riders | 14.9 | |||
Estimated impact of weather | 8.0 | |||
Retail sales growth (excluding weather impact) | 2.8 | |||
DSM program revenues (offset by expenses) | 2.6 | |||
Other, net | 1.5 | |||
Total increase in natural gas margin before TCJA impact | $ | 79.9 | ||
TCJA impact (offset as a reduction in income tax) | (30.2 | ) | ||
Total increase in natural gas margin | $ | 49.7 | ||
16
Non-Fuel Operating Expenses and Other Items
O&M Expenses — O&M expenses increased $26.7 million, or 3.5%, for 2018. Significant changes are summarized below:
(Millions of Dollars) | 2018 vs. 2017 | |||
Distribution costs | $ | 13.0 | ||
Natural gas systems damage prevention | 7.2 | |||
Business systems and contract labor | 6.7 | |||
Plant generation costs | (1.4 | ) | ||
Other, net | 1.2 | |||
Total increase in O&M expenses | $ | 26.7 | ||
• | Distribution costs reflect higher maintenance expenses, including vegetation management; and |
• | Business systems and contract labor costs increased due to growing network and storage needs, cybersecurity, initiatives to support our customer strategy, and initiatives to improve business processes. |
DSM Program Expenses — DSM program expenses increased $17.2 million, or 13.8%, for 2018. The increase was due to increases in conservation programs to help customers reduce energy use. DSM expenses are generally recovered concurrently through riders and base rates. Timing of recovery may vary from when costs are incurred.
Taxes (Other than Income Taxes) — Taxes (other than income taxes) increased $6.2 million, or 3.2%, for 2018 compared with 2017. The increase was primarily due to higher property taxes.
Depreciation and Amortization — Depreciation and amortization increased $89.6 million, or 19.0%, for 2018 compared with 2017. The increase was primarily driven by capital investments and additional amortization of a prepaid pension asset related to TCJA settlements, which were offset by lower income taxes (approximately $75 million).
AFUDC, Equity and Debt — AFUDC increased by $37.4 million for 2018 compared with 2017. The increase was primarily due to the Rush Creek wind project and other capital investments.
Interest Charges — Interest charges increased by $17.2 million, or 9.0%, for 2018 compared with 2017. The increase was primarily due to higher debt levels to fund capital investments, partially offset by refinancing at lower interest rates.
Income Taxes — Income tax expense decreased $138.5 million for 2018. The decrease was primarily due to a lower federal tax rate due to the TCJA and lower pretax earnings, an increase in plant-related regulatory difference related to ARAM (net of deferrals), 2018 non-plant excess accumulated deferred income tax amortization, 2018 wind PTCs; partially offset by a one-time, non-cash, income tax expense related to the impacts of tax reform in 2017. The ETR was 17.1% for 2018 compared with 33.8% for 2017. The lower ETR in 2018 was largely due to the adjustments above.
Regulation
FERC and State Regulation — The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, hydro facility licensing, natural gas transportation, asset transactions and mergers, accounting practices and certain other activities of PSCo, including enforcement of NERC mandatory electric reliability standards. State and local agencies have jurisdiction over many of PSCo’s activities, including regulation of retail rates and environmental matters.
Xcel Energy, which includes PSCo, attempts to mitigate the risk of regulatory penalties through formal training on prohibited practices and a compliance function that reviews interaction with the markets under FERC and Commodity Futures Trading Commission jurisdictions. Public campaigns are conducted to raise awareness of the public safety issues of interacting with our electric systems. While programs to comply with regulatory requirements are in place, there is no guarantee the compliance programs or other measures will be sufficient to ensure against violations. Decisions by these regulators can significantly impact PSCo’s results of operations.
Tax Reform — Regulatory Proceedings
In December 2017, the TCJA was signed into law, enacting significant changes to the Internal Revenue Code, including a reduction of the corporate income tax rate from 35% to 21% and a resulting reduction in deferred tax assets and liabilities. As a result of IRS requirements and past regulatory treatment of income taxes in the determination of regulated rates, the impacts of TCJA are primarily recognized as a regulatory liability. Treatment of these tax benefits, (e.g., degree to which benefits will be used to refund currently effective rates and/or used to mitigate other costs and potential future rate increases) is subject to regulatory approval. Concluded and ongoing regulatory TCJA proceedings:
Utility Service | Approval Date | Additional Information | ||
Natural Gas | December 2018 | In February 2018, the administrative law judge recommended approval of a TCJA settlement agreement, which included a $20 million reduction to PSCo’s provisional rates effective March 1, 2018. In September 2018, PSCo revised its 2018 TCJA benefit estimate to $24 million and requested an equity ratio of 56% to offset the negative impact of the TCJA on credit metrics. In December 2018, the CPUC approved an equity ratio of 54.6% and utilized the remainder of the TCJA benefit to reduce an existing prepaid pension asset. The CPUC also ordered 2018 excess non-plant ADIT benefits of $11.1 million be utilized to accelerate amortization of the prepaid pension asset. | ||
Electric | June 2018 October 2018 | In 2018, the CPUC approved a TCJA settlement agreement that included a customer refund of $42 million in 2018, with the remainder of the $59 million of TCJA benefits to be used to accelerate the amortization of an existing prepaid pension asset. For 2019, the expected customer refund is estimated to be $67 million, and amortization of the prepaid pension asset is estimated to be $34 million. Impacts of the TCJA for 2020 and future years are expected to be addressed in a future electric rate case. | ||
17
Pending and Recently Concluded Regulatory Proceedings
Mechanism | Utility Service | Amount Requested (in millions) | Filing Date | Approval | Additional Information | |||||
PSCo (CPUC) | ||||||||||
Multi-Year Rate Case | Natural Gas | $139 | June 2017 | Received | Proposed annual revenue request of $139 million over three years, $63 million for 2018. Requested an ROE of 10.0% and an equity ratio of 55.25%. In August 2018, CPUC approved an increase of $46 million (prior to TCJA impacts). The interim decision included application of a 2016 historic test year, a 13-month average rate base, an ROE of 9.35%, an equity ratio of 54.6% and provided no return on the prepaid pension asset. In December 2018, CPUC issued the final ruling which upheld the interim decision and finalized the TCJA impacts. In October 2018, the CPUC approved a settlement to extend the PSIA rider through 2021. | |||||
DSM Incentive | Electric & Natural Gas | $11 | April 2018 | Received | PSCo earned an electric and natural gas DSM incentive of $9 million and $2 million, respectively, for achieving its 2017 savings goals. | |||||
Item 7A — Quantitative and Qualitative Disclosures About Market Risk
Derivatives, Risk Management and Market Risk
PSCo is exposed to a variety of market risks in the normal course of business. Market risk is the potential loss that may occur as a result of adverse changes in the market or fair value of a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk.
See Note 9 to the consolidated financial statements for further information.
PSCo is exposed to the impact of adverse changes in price for energy and energy-related products, which is partially mitigated by the use of commodity derivatives. In addition to ongoing monitoring and maintaining credit policies intended to minimize overall credit risk, management takes steps to mitigate changes in credit and concentration risks associated with its derivatives and other contracts, including parental guarantees and requests of collateral. While PSCo expects that the counterparties will perform under the contracts underlying its derivatives, the contracts expose PSCo to some credit and non-performance risk.
Distress in the financial markets may impact counterparty risk, the fair value of the securities in the pension fund and PSCo’s ability to earn a return on short-term investments.
Commodity Price Risk — PSCo is exposed to commodity price risk in its electric and natural gas operations. Commodity price risk is managed by entering into long and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products and fuels used in generation and distribution activities. Commodity price risk is also managed through the use of financial derivative instruments. PSCo’s risk management policy allows it to manage commodity price risk within each rate-regulated operation per commission approved hedge plans.
Wholesale and Commodity Trading Risk — PSCo conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. PSCo’s risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee.
At Dec. 31, 2018, fair values by source for net commodity trading contract assets were as follows:
Futures / Forwards | |||||||||||||||||||||||
(Millions of Dollars) | Source of Fair Value | Maturity Less Than 1 Year | Maturity 1 to 3 Years | Maturity 4 to 5 Years | Maturity Greater Than 5 Years | Total Futures/ Forwards Fair Value | |||||||||||||||||
PSCo | 2 | $ | 0.8 | $ | 0.5 | $ | — | $ | — | $ | 1.3 | ||||||||||||
2 — Prices based on models and other valuation methods.
Changes in the fair value of commodity trading contracts before the impacts of margin-sharing for the years ended Dec. 31 were as follows:
(Millions of Dollars) | 2018 | 2017 | ||||||
Fair value of commodity trading net contract assets outstanding at Jan. 1 | $ | 0.5 | $ | (0.2 | ) | |||
Contracts realized or settled during the period | (7.8 | ) | (0.8 | ) | ||||
Commodity trading contract additions and changes during the period | 8.6 | 1.5 | ||||||
Fair value of commodity trading net contract assets outstanding at Dec. 31 | $ | 1.3 | $ | 0.5 | ||||
At Dec. 31, 2018, a 10% increase in market prices for commodity trading contracts would decrease pretax income by approximately $0.2 million, whereas a 10% decrease would increase pretax income by approximately $0.2 million. At Dec. 31, 2017, a 10% increase in market prices for commodity trading contracts would increase pretax income by approximately $0.6 million, whereas a 10% decrease would decrease pretax income by approximately $0.6 million.
PSCo’s wholesale and commodity trading operations measure the outstanding risk exposure to price changes on transactions, contracts and obligations using VaR. VaR expresses the potential change in fair value on the outstanding transactions, contracts and obligations over a particular period of time under normal market conditions.
VaRs for the NSP-Minnesota and PSCo commodity trading operations, calculated on a consolidated basis using a Monte Carlo simulation with a 95% confidence level and a one-day holding period, were as follows:
(Millions of Dollars) | Year Ended Dec. 31 | VaR Limit | Average | High | Low | |||||||||||||||
2018 | $ | 4.83 | $ | 6.00 | $ | 0.62 | $ | 5.63 | $ | 0.06 | ||||||||||
2017 | 0.18 | 3.00 | 0.21 | 0.66 | 0.04 | |||||||||||||||
In November 2018, management temporarily increased the VaR limit to accommodate a 10-year transaction. NSP-Minnesota has been systematically hedging the transaction and the consolidated VaR returned below $3 million in January 2019.
18
Interest Rate Risk — PSCo is subject to interest rate risk. PSCo’s risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives such as swaps, caps, collars and put or call options.
A 100 basis point change in the benchmark rate on PSCo’s variable rate debt would impact annual pretax interest expense by approximately $3.1 million in 2018 and no impact in 2017.
See Note 9 to the consolidated financial statements for further information.
Credit Risk — PSCo is also exposed to credit risk. Credit risk relates to the risk of loss resulting from counterparties’ nonperformance on their contractual obligations. PSCo maintains credit policies intended to minimize overall credit risk and actively monitors these policies to reflect changes and scope of operations.
At Dec. 31, 2018, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $11.5 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $7.6 million. At Dec. 31, 2017, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $17.4 million, while a decrease in prices of 10% would have resulted in an increase in credit exposure of $5.5 million.
PSCo conducts credit reviews for all counterparties and employ credit risk controls, such as letters of credit, parental guarantees, master netting agreements and termination provisions. Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. Distress in the financial markets could increase PSCo’s credit risk.
Fair Value Measurements
PSCo uses derivative contracts such as futures, forwards, interest rate swaps and options to manage commodity price and interest rate risk. Derivative contracts, with the exception of those designated as normal purchase-normal sale contracts, are reported at fair value. PSCo’s investments held in rabbi trusts, pension and other postretirement funds are also subject to fair value accounting.
See Notes 9 and 10 to the consolidated financial statements for further information.
Commodity Derivatives — PSCo continuously monitors the creditworthiness of the counterparties to its commodity derivative contracts and assesses each counterparty’s ability to perform on the transactions. Given the typically short duration of these contracts, the impact of discounting commodity derivative assets for counterparty credit risk was not material to the fair value of commodity derivative assets at Dec. 31, 2018.
Adjustments to fair value for credit risk of commodity trading instruments are recorded in electric revenues. Credit risk adjustments for other commodity derivative instruments are recorded as other comprehensive income or deferred as regulatory assets and liabilities. Classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. The impact of discounting commodity derivative liabilities for credit risk was immaterial at Dec. 31, 2018.
Item 8 — Financial Statements and Supplementary Data
See Item 15-1 for an index of financial statements included herein.
See Note 15 to the consolidated financial statements for further information.
19
Management Report on Internal Controls Over Financial Reporting
The management of PSCo is responsible for establishing and maintaining adequate internal control over financial reporting. PSCo’s internal control system was designed to provide reasonable assurance to Xcel Energy Inc.’s and PSCo’s management and board of directors regarding the preparation and fair presentation of published financial statements.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
PSCo management assessed the effectiveness of PSCo’s internal control over financial reporting as of Dec. 31, 2018. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework (2013). Based on our assessment, we believe that, as of Dec. 31, 2018, PSCo’s internal control over financial reporting is effective at the reasonable assurance level based on those criteria.
/s/ BEN FOWKE | /s/ ROBERT C. FRENZEL | |
Ben Fowke | Robert C. Frenzel | |
Chairman and Chief Executive Officer | Executive Vice President, Chief Financial Officer | |
Feb. 22, 2019 | Feb. 22, 2019 | |
20
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholder of
Public Service Company of Colorado
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Public Service Company of Colorado and subsidiaries (the "Company") as of December 31, 2018 and 2017, the related consolidated statements of income, comprehensive income, cash flows and, common stockholder's equity for each of the three years in the period ended December 31, 2018, and the related notes and the schedule listed in the Index at Item 15 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ DELOITTE & TOUCHE LLP |
Minneapolis, Minnesota |
February 22, 2019 |
We have served as the Company’s auditor since 2002. |
21
PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(amounts in millions)
Year Ended Dec. 31 | ||||||||||||
2018 | 2017 | 2016 | ||||||||||
Operating revenues | ||||||||||||
Electric | $ | 3,031.2 | $ | 3,003.8 | $ | 3,049.4 | ||||||
Natural gas | 1,014.6 | 995.2 | 957.7 | |||||||||
Steam and other | 40.4 | 43.5 | 40.7 | |||||||||
Total operating revenues | 4,086.2 | 4,042.5 | 4,047.8 | |||||||||
Operating expenses | ||||||||||||
Electric fuel and purchased power | 1,157.2 | 1,126.7 | 1,196.4 | |||||||||
Cost of natural gas sold and transported | 428.4 | 458.7 | 425.4 | |||||||||
Cost of sales — steam and other | 15.3 | 16.1 | 15.9 | |||||||||
Operating and maintenance expenses | 787.5 | 760.8 | 759.7 | |||||||||
Demand side management program expenses | 142.2 | 125.0 | 118.2 | |||||||||
Depreciation and amortization | 561.1 | 471.5 | 443.6 | |||||||||
Taxes (other than income taxes) | 201.9 | 195.7 | 196.3 | |||||||||
Total operating expenses | 3,293.6 | 3,154.5 | 3,155.5 | |||||||||
Operating income | 792.6 | 888.0 | 892.3 | |||||||||
Other income, net | 2.1 | 7.8 | 1.1 | |||||||||
Allowance for funds used during construction — equity | 56.4 | 29.8 | 18.6 | |||||||||
Interest charges and financing costs | ||||||||||||
Interest charges — includes other financing costs of $6.5, $6.3 and $6.3, respectively | 207.9 | 190.7 | 181.6 | |||||||||
Allowance for funds used during construction — debt | (22.2 | ) | (11.4 | ) | (7.0 | ) | ||||||
Total interest charges and financing costs | 185.7 | 179.3 | 174.6 | |||||||||
Income before income taxes | 665.4 | 746.3 | 737.4 | |||||||||
Income taxes | 113.7 | 252.2 | 273.9 | |||||||||
Net income | $ | 551.7 | $ | 494.1 | $ | 463.5 | ||||||
See Notes to Consolidated Financial Statements
22
PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(amounts in millions)
Year Ended Dec. 31 | ||||||||||||
2018 | 2017 | 2016 | ||||||||||
Net income | $ | 551.7 | $ | 494.1 | $ | 463.5 | ||||||
Other comprehensive income (loss) | ||||||||||||
Pension and retiree medical benefits: | ||||||||||||
Net pension and retiree medical losses arising during the period, net of tax of $0, $0, and ($0.1), respectively | — | — | (0.2 | ) | ||||||||
— | — | (0.2 | ) | |||||||||
Derivative instruments: | ||||||||||||
Reclassification of losses to net income, net of tax of $0.4, $0.6, and $0.7, respectively | 1.2 | 1.0 | 1.0 | |||||||||
1.2 | 1.0 | 1.0 | ||||||||||
Other comprehensive income | 1.2 | 1.0 | 0.8 | |||||||||
Comprehensive income | $ | 552.9 | $ | 495.1 | $ | 464.3 | ||||||
See Notes to Consolidated Financial Statements
23
PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(amounts in millions)
Year Ended Dec. 31 | |||||||||||
2018 | 2017 | 2016 | |||||||||
Operating activities | |||||||||||
Net income | $ | 551.7 | $ | 494.1 | $ | 463.5 | |||||
Adjustments to reconcile net income to cash provided by operating activities: | |||||||||||
Depreciation and amortization | 566.1 | 475.6 | 446.2 | ||||||||
Deferred income taxes | 23.8 | 207.8 | 222.0 | ||||||||
Allowance for equity funds used during construction | (56.4 | ) | (29.8 | ) | (18.6 | ) | |||||
Provision for bad debts | 16.4 | 14.3 | 14.1 | ||||||||
Net realized and unrealized hedging and derivative transactions | (6.2 | ) | 2.4 | 1.3 | |||||||
Changes in operating assets and liabilities: | |||||||||||
Accounts receivable | (42.8 | ) | (2.2 | ) | (14.2 | ) | |||||
Accrued unbilled revenues | (17.7 | ) | 1.3 | (20.9 | ) | ||||||
Inventories | (20.1 | ) | (9.1 | ) | 0.2 | ||||||
Prepayments and other | 12.8 | 0.2 | 68.7 | ||||||||
Accounts payable | 68.7 | 20.4 | 38.4 | ||||||||
Net regulatory assets and liabilities | (14.6 | ) | (22.6 | ) | 4.2 | ||||||
Other current liabilities | (12.9 | ) | 71.8 | 1.9 | |||||||
Pension and other employee benefit obligations | (44.2 | ) | (16.5 | ) | (10.6 | ) | |||||
Other, net | (16.3 | ) | (5.9 | ) | (29.9 | ) | |||||
Net cash provided by operating activities | 1,008.3 | 1,201.8 | 1,166.3 | ||||||||
Investing activities | |||||||||||
Utility capital/construction expenditures | (1,577.2 | ) | (1,445.9 | ) | (1,095.2 | ) | |||||
Proceeds from insurance recoveries | — | — | 0.6 | ||||||||
Investments in utility money pool arrangement | (634.0 | ) | (954.0 | ) | (444.0 | ) | |||||
Repayments from utility money pool arrangement | 654.0 | 934.0 | 444.0 | ||||||||
Other, net | — | (0.7 | ) | (1.5 | ) | ||||||
Net cash used in investing activities | (1,557.2 | ) | (1,466.6 | ) | (1,096.1 | ) | |||||
Financing activities | |||||||||||
Proceeds from (repayments of) short-term borrowings, net | 307.0 | (129.0 | ) | 115.0 | |||||||
Borrowings under utility money pool arrangement | 780.0 | 40.0 | 524.5 | ||||||||
Repayments under utility money pool arrangement | (780.0 | ) | (40.0 | ) | (524.5 | ) | |||||
Proceeds from issuance of long-term debt | 691.1 | 393.8 | 244.5 | ||||||||
Repayments of long-term debt | (300.0 | ) | — | (129.5 | ) | ||||||
Capital contributions from parent | 252.1 | 335.6 | 38.8 | ||||||||
Dividends paid to parent | (375.3 | ) | (333.9 | ) | (336.6 | ) | |||||
Other, net | (0.1 | ) | (0.1 | ) | — | ||||||
Net cash provided by (used in) financing activities | 574.8 | 266.4 | (67.8 | ) | |||||||
Net change in cash and cash equivalents | 25.9 | 1.6 | 2.4 | ||||||||
Cash and cash equivalents at beginning of period | 7.5 | 5.9 | 3.5 | ||||||||
Cash and cash equivalents at end of period | $ | 33.4 | $ | 7.5 | $ | 5.9 | |||||
Supplemental disclosure of cash flow information: | |||||||||||
Cash paid for interest (net of amounts capitalized) | $ | (187.2 | ) | $ | (175.0 | ) | $ | (171.7 | ) | ||
Cash (paid) received for income taxes, net | (115.8 | ) | (7.7 | ) | 22.8 | ||||||
Supplemental disclosure of non-cash investing transactions: | |||||||||||
Accrued property, plant and equipment additions | $ | 142.1 | $ | 199.1 | $ | 81.1 | |||||
Inventory transfers to property, plant and equipment | 37.2 | 26.6 | 40.8 | ||||||||
Allowance for equity funds used during construction | 56.4 | 29.8 | 18.6 | ||||||||
See Notes to Consolidated Financial Statements
24
PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(amounts in millions, except share and per share)
Dec. 31 | ||||||||
2018 | 2017 | |||||||
Assets | ||||||||
Current assets | ||||||||
Cash and cash equivalents | $ | 33.4 | $ | 7.5 | ||||
Accounts receivable, net | 310.3 | 294.4 | ||||||
Accounts receivable from affiliates | 80.8 | 14.7 | ||||||
Investments in utility money pool arrangement | — | 20.0 | ||||||
Accrued unbilled revenues | 313.5 | 295.8 | ||||||
Inventories | 197.4 | 214.5 | ||||||
Regulatory assets | 120.6 | 77.3 | ||||||
Derivative instruments | 42.6 | 3.2 | ||||||
Prepayments and other | 23.8 | 35.7 | ||||||
Total current assets | 1,122.4 | 963.1 | ||||||
Property, plant and equipment, net | 15,120.0 | 14,025.8 | ||||||
Other assets | ||||||||
Regulatory assets | 1,010.7 | 950.3 | ||||||
Derivative instruments | 1.2 | 1.0 | ||||||
Other | 37.2 | 27.4 | ||||||
Total other assets | 1,049.1 | 978.7 | ||||||
Total assets | $ | 17,291.5 | $ | 15,967.6 | ||||
Liabilities and Equity | ||||||||
Current liabilities | ||||||||
Current portion of long-term debt | $ | 406.2 | $ | 305.6 | ||||
Short-term debt | 307.0 | — | ||||||
Accounts payable | 503.4 | 492.9 | ||||||
Accounts payable to affiliates | 46.0 | 58.7 | ||||||
Regulatory liabilities | 67.3 | 66.1 | ||||||
Taxes accrued | 202.0 | 222.5 | ||||||
Accrued interest | 43.2 | 48.6 | ||||||
Dividends payable to parent | 91.5 | 76.2 | ||||||
Derivative instruments | 34.6 | 7.3 | ||||||
Other | 101.5 | 92.3 | ||||||
Total current liabilities | 1,802.7 | 1,370.2 | ||||||
Deferred credits and other liabilities | ||||||||
Deferred income taxes | 1,719.3 | 1,644.5 | ||||||
Deferred investment tax credits | 25.3 | 27.8 | ||||||
Regulatory liabilities | 2,021.5 | 1,933.5 | ||||||
Asset retirement obligations | 338.7 | 347.8 | ||||||
Derivative instruments | 0.6 | 3.5 | ||||||
Customer advances | 168.1 | 162.6 | ||||||
Pension and employee benefit obligations | 275.3 | 287.8 | ||||||
Other | 50.4 | 58.9 | ||||||
Total deferred credits and other liabilities | 4,599.2 | 4,466.4 | ||||||
Commitments and contingencies | ||||||||
Capitalization | ||||||||
Long-term debt | 4,591.4 | 4,302.7 | ||||||
Common stock — 100 shares authorized of $0.01 par value; 100 shares outstanding at Dec. 31, 2018 and 2017, respectively | — | — | ||||||
Additional paid in capital | 4,340.5 | 4,032.8 | ||||||
Retained earnings | 1,983.2 | 1,822.2 | ||||||
Accumulated other comprehensive loss | (25.5 | ) | (26.7 | ) | ||||
Total common stockholder’s equity | 6,298.2 | 5,828.3 | ||||||
Total liabilities and equity | $ | 17,291.5 | $ | 15,967.6 | ||||
See Notes to Consolidated Financial Statements
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PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
(amounts in millions, except share data)
Common Stock | Accumulated Other Comprehensive Income (Loss) | Total Common Stockholder’s Equity | ||||||||||||||||||||
Shares | Par Value | Additional Paid In Capital | Retained Earnings | |||||||||||||||||||
Balance at Dec. 31, 2015 | 100 | $ | — | $ | 3,620.8 | $ | 1,523.2 | $ | (23.8 | ) | $ | 5,120.2 | ||||||||||
Net income | 463.5 | 463.5 | ||||||||||||||||||||
Other comprehensive income | 0.8 | 0.8 | ||||||||||||||||||||
Common dividends declared to parent | (327.4 | ) | (327.4 | ) | ||||||||||||||||||
Contribution of capital by parent | 12.4 | 12.4 | ||||||||||||||||||||
Balance at Dec. 31, 2016 | 100 | $ | — | $ | 3,633.2 | $ | 1,659.3 | $ | (23.0 | ) | $ | 5,269.5 | ||||||||||
Net income | 494.1 | 494.1 | ||||||||||||||||||||
Other comprehensive income | 1.0 | 1.0 | ||||||||||||||||||||
Common dividends declared to parent | (335.9 | ) | (335.9 | ) | ||||||||||||||||||
Contribution of capital by parent | 399.6 | 399.6 | ||||||||||||||||||||
Adoption of ASU No. 2018-02 | 4.7 | (4.7 | ) | — | ||||||||||||||||||
Balance at Dec. 31, 2017 | 100 | $ | — | $ | 4,032.8 | $ | 1,822.2 | $ | (26.7 | ) | $ | 5,828.3 | ||||||||||
Net income | 551.7 | 551.7 | ||||||||||||||||||||
Other comprehensive income | 1.2 | 1.2 | ||||||||||||||||||||
Common dividends declared to parent | (390.7 | ) | (390.7 | ) | ||||||||||||||||||
Contribution of capital by parent | 307.7 | 307.7 | ||||||||||||||||||||
Balance at Dec. 31, 2018 | 100 | $ | — | $ | 4,340.5 | $ | 1,983.2 | $ | (25.5 | ) | $ | 6,298.2 | ||||||||||
See Notes to Consolidated Financial Statements | ||||||||||||||||||||||
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. | Summary of Significant Accounting Policies |
General — 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 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 3 for further information.
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.
PSCo has evaluated the impact of events occurring after Dec. 31, 2018 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation.
Use of Estimates — PSCo uses estimates based on the best information available in recording transactions and balances resulting from business operations. Estimates are used on items such 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. Recorded estimates are revised when better information becomes available or when actual amounts can be determined. Those revisions can affect operating results.
Regulatory Accounting — PSCo accounts for 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 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 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 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 results of operations, financial condition or cash flows.
See Note 4 for further information.
Income Taxes — PSCo accounts for income taxes using the asset and liability method, which requires deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. PSCo defers income taxes for all temporary differences between pretax financial and taxable income, and between the book and tax bases of assets and liabilities. PSCo uses the tax rates that are scheduled to be in effect when the temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the period that includes the enactment date.
The effects of PSCo’s tax rate changes are generally subject to a normalization method of accounting. Therefore, the revaluation of most of its net deferred taxes upon a tax rate reduction results in the establishment of a net regulatory liability which will be refundable to utility customers over the remaining life of the related assets. A tax rate increase would result in the establishment of a similar regulatory asset.
Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize it over the book depreciable lives of the related property. The requirement to defer and amortize tax credits only applies to federal ITCs related to public utility property. Utility rate regulation also has resulted in the recognition of certain regulatory assets and liabilities related to income taxes.
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.
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 in the consolidated statements of income.
Xcel Energy Inc. and its subsidiaries, including PSCo, file consolidated federal income tax returns as well as consolidated 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 state 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 8 for further information.
Property, Plant and Equipment and Depreciation — Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and AFUDC. The cost of plant retired is charged to accumulated depreciation and amortization. Amounts recovered in rates for future removal costs are recorded as regulatory liabilities. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance costs are charged to expense as incurred. Maintenance and replacement of items determined to be less than a unit of property are charged to operating expenses as incurred. Planned 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.
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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 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% in 2018, 2.7% in 2017 and 2.6% in 2016.
See Note 3 for further information.
AROs — PSCo accounts for AROs under accounting guidance that requires a liability for the fair value of an ARO to be recognized in the period in which it is incurred if it can be reasonably estimated, with the offsetting associated asset retirement costs capitalized as a long-lived asset. The liability is generally increased over time by applying the effective interest method of accretion, and the capitalized costs are depreciated over the useful life of the long-lived asset. Changes resulting from revisions to the timing or amount of expected asset retirement cash flows are recognized as an increase or a decrease in the ARO. PSCo also recovers through rates certain future plant removal costs in addition to AROs. The accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability.
See Note 11 for further information.
Benefit Plans and Other Postretirement Benefits — PSCo maintains pension and postretirement benefit plans for eligible employees. Recognizing the cost of providing benefits and measuring the projected benefit obligation of these plans requires management to make various assumptions and estimates.
Certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are deferred as regulatory assets and liabilities, rather than recorded as other comprehensive income, based on regulatory recovery mechanisms.
See Note 10 for further information.
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 are regularly adjusted as estimates are revised and remediation proceeds. If other participating potentially 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.
Future costs of restoring sites are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses. Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability.
See Note 11 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 6 for further information.
Cash and Cash Equivalents — PSCo considers 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, 2018 and 2017, the allowance for bad debts was $20.5 million and $19.6 million, respectively.
Inventory — Inventory is recorded at average cost. As of Dec. 31, 2018, materials and supplies, fuel and natural gas inventory were $61.9 million, $69.5 million and $66.0 million, respectively. As of Dec. 31, 2017, materials and supplies, fuel and natural gas inventory were $68.9 million, $73.9 million and $71.7 million, respectively.
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 plan assets, published trading data and pricing models, generally using the most observable inputs available, are utilized to estimate fair value for each security.
See Notes 9 and 10 for further information.
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. 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.
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.
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Normal Purchases and Normal Sales — PSCo enters into contracts for the 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 9 for further information.
Commodity Trading Operations — All applicable gains and losses related to commodity 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 9 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 under GAAP. These mechanisms arise from costs imposed upon the utility by action of a regulator or legislative body related to an environmental, public safety or other mandate. When certain criteria are met, such as 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 the 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 in the period earned.
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 been collected from customers.
Emission Allowances — Emission allowances are recorded at cost plus broker commission fees. The inventory accounting model is utilized for all emission allowances and sales of these allowances are included in electric revenues.
RECs — Cost of RECs that are utilized for compliance purposes is recorded as electric fuel and purchased power expense. PSCo records that cost as a regulatory asset when the amount is recoverable in future rates.
Sales of RECs are recorded in electric revenues on a gross basis. The cost of these RECs and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense.
2. | Accounting Pronouncements |
Recently Issued
Leases — In 2016, the FASB issued Leases, Topic 842 (ASU No. 2016-02), which requires balance sheet recognition of right-of-use assets and lease liabilities for most leases. Adoption will occur on Jan. 1, 2019 utilizing the package of transition practical expedients provided by the new standard, including carrying forward prior conclusions of whether agreements existing before the adoption date contain leases, and whether existing leases are operating or capital/finance leases. PSCo expects to utilize other expedients offered by the new standard and Leases, Topic 842 (ASU No. 2018-11), including elections to not recognize short term leases on the consolidated balance sheet for certain classes of assets and to implement the standard on a prospective basis. PSCo’s implementation of the new guidance is substantially complete, and is expected to result in the recognition of right-of-use assets and lease liabilities in the first quarter of 2019 for operating leases for the use of real estate, equipment and certain natural gas generating facilities operated under PPAs. The implementation is not expected to have a significant impact on PSCo’s consolidated financial statements, other than first-time recognition of these operating leases on the consolidated balance sheet.
Recently Adopted
Revenue Recognition — In 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 implemented the guidance on a modified retrospective basis on Jan. 1, 2018. Results for reporting periods beginning after Dec. 31, 2017 are presented in accordance with Topic 606, while prior period results have not been adjusted and continue to be reported in accordance with prior accounting guidance. The implementation did not have a material impact on PSCo’s consolidated financial statements, other than increased disclosures regarding revenues related to contracts with customers.
Classification and Measurement of Financial Instruments — In 2016, the FASB issued Recognition and Measurement of Financial Assets and Financial Liabilities, Subtopic 825-10 (ASU No. 2016-01), which eliminated the available-for-sale classification for marketable equity securities and also replaced the cost method of accounting for non-marketable equity securities with a model for recognizing impairments and observable price changes. PSCo implemented the guidance on Jan. 1, 2018 and the adoption impacts were not material.
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Presentation of Net Periodic Benefit Cost — In 2017, the FASB issued Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, Topic 715 (ASU No. 2017-07), which establishes that only the service cost portion of pension cost may be presented as a component of operating income. In addition, only the service cost portion of pension cost is eligible for capitalization. As a result of regulatory accounting treatment, a similar amount of pension cost, including non-service components, will be recognized consistent with historical ratemaking and the impacts of adoption are limited to changes in classification of non-service costs in the consolidated statement of income.
PSCo implemented the new guidance on Jan. 1, 2018. As a result, $2.1 million and $2.7 million of pension costs were retrospectively reclassified from O&M expenses to other income, net on the consolidated income statement for 2017 and 2016, respectively. PSCo used benefit cost amounts disclosed for prior periods as the basis for retrospective application.
3. | Plant, Property and Equipment |
Major classes of property, plant and equipment:
(Millions of Dollars) | Dec. 31, 2018 | Dec. 31, 2017 | ||||||
Property, plant and equipment | ||||||||
Electric plant | $ | 13,604.5 | $ | 12,627.6 | ||||
Natural gas plant | 4,387.6 | 4,102.1 | ||||||
Common and other property | 1,023.7 | 1,022.3 | ||||||
Plant to be retired (a) | 321.9 | 11.0 | ||||||
CWIP | 573.3 | 1,014.3 | ||||||
Total property, plant and equipment | 19,911.0 | 18,777.3 | ||||||
Less accumulated depreciation | (4,791.0 | ) | (4,751.5 | ) | ||||
$ | 15,120.0 | $ | 14,025.8 | |||||
(a) | In 2018, the CPUC approved early retirement of PSCo’s Comanche Units 1 and 2 in approximately 2022 and 2025, respectively. PSCo also expects Craig Unit 1 to be retired early in 2025. Amounts are presented net of accumulated depreciation. |
Joint Ownership of Generation, Transmission and Gas Facilities
Jointly owned assets as of Dec. 31, 2018:
(Millions of Dollars) | Plant in Service | Accumulated Depreciation | CWIP | Percent Owned | |||||||||||
Electric Generation: | |||||||||||||||
Hayden Unit 1 | $ | 152.8 | $ | 76.5 | $ | — | 76 | % | |||||||
Hayden Unit 2 | 148.9 | 68.0 | — | 37 | |||||||||||
Hayden Common Facilities | 40.8 | 20.9 | — | 53 | |||||||||||
Craig Units 1 and 2 | 81.0 | 40.0 | — | 10 | |||||||||||
Craig Common Facilities | 39.1 | 20.9 | — | 7 | |||||||||||
Comanche Unit 3 | 886.3 | 130.7 | — | 67 | |||||||||||
Comanche Common Facilities | 27.9 | 2.5 | 0.1 | 82 | |||||||||||
Electric Transmission: | |||||||||||||||
Transmission and other facilities | 182.8 | 63.2 | 0.7 | Various | |||||||||||
Gas Transportation: | |||||||||||||||
Rifle, CO to Avon, CO | 21.5 | 7.2 | 0.1 | 60 | |||||||||||
Gas Tran Compressor | 8.4 | 0.9 | — | 50 | |||||||||||
Total | $ | 1,589.5 | $ | 430.8 | $ | 0.9 | |||||||||
PSCo’s share of operating expenses and construction expenditures are 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, 2018 | Dec. 31, 2017 | |||||||||||||||||
Regulatory Assets | Current | Noncurrent | Current | Noncurrent | |||||||||||||||||
Pension and retiree medical obligations | 10 | Various | $ | 26.1 | $ | 559.0 | $ | 28.0 | $ | 565.3 | |||||||||||
Depreciation differences | One to thirteen years | 17.5 | 107.0 | 19.8 | 69.4 | ||||||||||||||||
Recoverable deferred taxes on AFUDC recorded in plant | Plant lives | — | 101.9 | — | 87.0 | ||||||||||||||||
Net AROs (a) | 1, 11 | Plant lives | — | 98.9 | — | 80.5 | |||||||||||||||
Excess deferred taxes - TCJA | 8 | Various | — | 62.0 | — | 53.9 | |||||||||||||||
Purchased power contract costs | Term of related contract | 1.7 | 26.3 | 1.3 | 28.0 | ||||||||||||||||
Property tax | Various | 5.6 | 9.8 | — | 16.1 | ||||||||||||||||
Conservation programs (b) | 1 | One to two years | 7.3 | 6.5 | 7.0 | 5.5 | |||||||||||||||
Losses on reacquired debt | Term of related debt | 1.2 | 3.7 | 1.2 | 4.9 | ||||||||||||||||
Gas pipeline inspection costs | One to two years | 0.7 | 3.1 | 1.8 | 7.8 | ||||||||||||||||
Contract valuation adjustments (c) | 1, 9 | Term of related contract | 2.6 | — | 6.0 | 2.6 | |||||||||||||||
Recoverable purchased natural gas and electric energy costs | Less than one year | 51.2 | — | 7.6 | — | ||||||||||||||||
Other | Various | 6.7 | 32.5 | 4.6 | 29.3 | ||||||||||||||||
Total regulatory assets | $ | 120.6 | $ | 1,010.7 | $ | 77.3 | $ | 950.3 | |||||||||||||
(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. |
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Components of regulatory liabilities:
(Millions of Dollars) | See Note(s) | Remaining Amortization Period | Dec. 31, 2018 | Dec. 31, 2017 | ||||||||||||||||
Regulatory Liabilities | Current | Noncurrent | Current | Noncurrent | ||||||||||||||||
Deferred income tax adjustments and TCJA refunds (a) | 8 | Various | $ | 0.8 | $ | 1,441.6 | $ | — | $ | 1,469.3 | ||||||||||
Plant removal costs | 1, 11 | Plant lives | — | 344.4 | — | 346.2 | ||||||||||||||
Effects of regulation on employee benefit costs (b) | Various | — | 126.9 | — | 35.7 | |||||||||||||||
Renewable resources and environmental initiatives | Various | — | 54.0 | — | 56.2 | |||||||||||||||
ITC deferrals (c) | 1 | Various | — | 27.5 | — | 9.1 | ||||||||||||||
Deferred electric, natural gas and steam production costs | Less than one year | 7.2 | — | 29.0 | — | |||||||||||||||
Conservation programs (d) | 1 | Less than one year | 29.8 | — | 21.2 | — | ||||||||||||||
Other | Various | 29.5 | 27.1 | 15.9 | 17.0 | |||||||||||||||
Total regulatory liabilities (e) | $ | 67.3 | $ | 2,021.5 | $ | 66.1 | $ | 1,933.5 | ||||||||||||
(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 TCJA benefits approved by the CPUC to offset the prepaid pension asset at Dec. 31, 2018. |
(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 and $0.0 million for 2018 and 2017, respectively, is included in other current liabilities. |
At Dec. 31, 2018 and 2017, approximately $50 million and $44 million, respectively, of PSCo’s regulatory assets represented past expenditures not earning a return. Amounts primarily related to property taxes, renewable resources and environmental initiatives.
5. | Borrowings and Other Financing Instruments |
Short-Term Borrowings
Money Pool — Xcel Energy Inc. and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings between the utility subsidiaries. Xcel Energy Inc. may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy Inc. Money pool borrowings for PSCo were as follows:
Three Months Ended Dec. 31, 2018 | Year Ended Dec. 31 | |||||||||||||||
(Amounts in Millions, Except Interest Rates) | 2018 | 2017 | 2016 | |||||||||||||
Borrowing limit | $ | 250 | $ | 250 | $ | 250 | $ | 250 | ||||||||
Amount outstanding at period end | — | — | — | — | ||||||||||||
Average amount outstanding | 26 | 25 | — | 21 | ||||||||||||
Maximum amount outstanding | 96 | 156 | 20 | 141 | ||||||||||||
Weighted average interest rate, computed on a daily basis | 2.27 | % | 1.93 | % | 0.92 | % | 0.73 | % | ||||||||
Weighted average interest rate at end of period | N/A | 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:
Three Months Ended Dec. 31, 2018 | Year Ended Dec. 31 | |||||||||||||||
(Amounts in Millions, Except Interest Rates) | 2018 | 2017 | 2016 | |||||||||||||
Borrowing limit | $ | 700 | $ | 700 | $ | 700 | $ | 700 | ||||||||
Amount outstanding at period end | 307 | 307 | — | 129 | ||||||||||||
Average amount outstanding | 87 | 55 | 54 | 24 | ||||||||||||
Maximum amount outstanding | 309 | 309 | 268 | 154 | ||||||||||||
Weighted average interest rate, computed on a daily basis | 2.64 | % | 2.28 | % | 1.08 | % | 0.70 | % | ||||||||
Weighted average interest rate at end of period | 2.95 | 2.95 | N/A | 0.95 | ||||||||||||
Letters of Credit — PSCo uses letters of credit, typically with terms of one-year, to provide financial guarantees for certain operating obligations. As of Dec. 31, 2018 and 2017, there were $10 million and $3 million letters of credit outstanding, respectively under the credit facility. Amounts approximate their fair value.
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Credit Facility — 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.
Features of PSCo’s credit 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) | ||||||||
2018 | 2017 | |||||||||
46 | % | 44 | % | $ | 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. |
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 indebtedness in an aggregate principal amount exceeding $75 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, 2018, PSCo was in compliance with all financial covenants.
PSCO had the following committed credit facilities available as of Dec. 31, 2018 (millions):
Credit Facility (a) | Drawn (b) | Available | ||||||||
$ | 700 | $ | 317 | $ | 383 | |||||
(a) | This credit facility matures in June 2021. |
(b) | Includes letters of credit and outstanding commercial paper. |
All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. PSCo had no direct advances on the facility outstanding at Dec. 31, 2018 and 2017.
Long-Term Borrowings
Generally, 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 for refinanced debt are deferred and amortized over the life of the new issuance.
Long-term debt obligations for PSCo as of Dec. 31:
(Millions of Dollars) | Maturity Range | Interest Rate Range 2018 | Interest Rate Range 2017 | 2018 | 2017 | |||||||||
Capital lease obligations | 2025-2060 | 11.20% - 14.30% | 11.20% - 14.30% | $ | 145 | $ | 151 | |||||||
Mortgage bonds | 2019-2048 | 2.25% - 6.50% | 2.25% - 6.50% | 4,900 | 4,500 | |||||||||
Unamortized discount | (14 | ) | (13 | ) | ||||||||||
Unamortized debt issuance cost | (33 | ) | (29 | ) | ||||||||||
Current maturities | (406 | ) | (306 | ) | ||||||||||
Total | $ | 4,592 | $ | 4,303 | ||||||||||
Maturities of long-term debt:
(Millions of Dollars) | ||||
2019 | $ | 400 | ||
2020 | 400 | |||
2021 | — | |||
2022 | 300 | |||
2023 | 250 | |||
2018 financings:
Amount | Financing Instrument | Interest Rate | Maturity Date | ||||
$350 million | First mortgage bonds | 3.70 | % | June 15, 2028 | |||
350 million | First mortgage bonds | 4.10 | June 15, 2048 | ||||
2017 financings:
Amount | Financing Instrument | Interest Rate | Maturity Date | ||||
$400 million | First mortgage bonds | 3.80 | % | June 15, 2047 | |||
Deferred Financing Costs — Deferred financing costs of approximately $33 million and $29 million, net of amortization, are presented as a deduction from the carrying amount of long-term debt as of Dec. 31, 2018 and 2017, respectively. PSCo is amortizing these financing costs over the remaining maturity periods of the related debt.
Dividend Restrictions — PSCo’s dividends are subject to the FERC’s jurisdiction, which prohibits the payment of dividends out of capital accounts. Dividends are solely to be paid from retained earnings.
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6. | Revenues |
Revenue is classified by the type of goods/services rendered and market/customer type. PSCo’s operating revenues (subsequent to adoption of the revised revenue guidance) consists of the following:
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 | ||||||||
7. | Preferred Stock |
PSCo has authorized the issuance of preferred stock.
Preferred Shares Authorized | Par Value | Preferred Shares Outstanding | ||||||
10,000,000 | $ | 0.01 | — | |||||
8. | Income Taxes |
Federal Tax Reform — In 2017, the TCJA was signed into law. The key provisions impacting Xcel Energy (which includes PSCo), generally beginning in 2018, include:
• | 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 section 199 manufacturing deduction; and |
• | Reduced deductions for meals and entertainment as well as state and local lobbying. |
Xcel Energy estimated the effects of the 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 PSCo in December 2017 included:
• | $1.1 billion ($1.5 billion grossed-up for tax) of reclassifications of plant-related excess deferred taxes to regulatory liabilities upon valuation at the new 21% federal rate. The regulatory liabilities will be amortized consistent with IRS normalization requirements, resulting in customer refunds over the average remaining life of the related property; |
• | $54 million and $50 million of reclassifications (grossed-up for tax) of excess deferred taxes for non-plant related deferred tax assets and liabilities, respectively, to regulatory assets and liabilities; and |
• | $18 million of total estimated income tax benefit related to the federal tax reform implementation, and a $4 million reduction to net income related to the allocation of Xcel Energy Services Inc.’s tax rate change on its deferred taxes. |
Xcel Energy accounted for the state tax impacts of federal tax reform based on enacted state tax laws. Any future state tax law changes related to the TCJA will be accounted for in the periods state laws are enacted.
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 - 2014 | October 2019 | |
2015 | September 2019 | |
2016 | September 2020 | |
2017 | September 2021 | |
In 2012, the IRS commenced an examination of tax years 2010 and 2011, including the 2009 carryback claim. In 2017, Xcel Energy and the Office of Appeals reached an agreement and the benefit related to the agreed upon portions was recognized. PSCo did not accrue any income tax benefit related to this adjustment. In the second quarter of 2018, the Joint Committee on Taxation completed its review and took no exception to the agreement. As a result, the remaining unrecognized tax benefit was released and recorded as a payable to the IRS.
In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013. In the third quarter of 2017, the IRS concluded the audit of tax years 2012 and 2013 and proposed an adjustment that would impact Xcel Energy’s NOL and ETR. Xcel Energy filed a protest with the IRS. As of Dec. 31, 2018, the case has been forwarded to the Office of Appeals and Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of this issue; however, the outcome and timing of a resolution is unknown.
In the fourth quarter of 2018, the IRS began an audit of tax years 2014 - 2016, however no 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, 2018, 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 — 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 to the taxing authority to an earlier period.
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Unrecognized tax benefits - permanent vs temporary:
(Millions of Dollars) | Dec. 31, 2018 | Dec. 31, 2017 | ||||||
Unrecognized tax benefit — Permanent tax positions | $ | 5.4 | $ | 4.0 | ||||
Unrecognized tax benefit — Temporary tax positions | 4.9 | 6.1 | ||||||
Total unrecognized tax benefit | $ | 10.3 | $ | 10.1 | ||||
Changes in unrecognized tax benefits:
(Millions of Dollars) | 2018 | 2017 | 2016 | |||||||||
Balance at Jan. 1 | $ | 10.1 | $ | 19.7 | $ | 17.4 | ||||||
Additions based on tax positions related to the current year | 1.1 | 1.9 | 2.7 | |||||||||
Reductions based on tax positions related to the current year | (0.3 | ) | (1.5 | ) | — | |||||||
Additions for tax positions of prior years | 0.4 | 4.4 | 0.5 | |||||||||
Reductions for tax positions of prior years | (0.1 | ) | (14.4 | ) | (0.9 | ) | ||||||
Settlements with taxing authorities | (0.9 | ) | — | — | ||||||||
Balance at Dec. 31 | $ | 10.3 | $ | 10.1 | $ | 19.7 | ||||||
Unrecognized tax benefits were reduced by tax benefits associated with NOL and tax credit carryforwards:
(Millions of Dollars) | Dec. 31, 2018 | Dec. 31, 2017 | ||||||
NOL and tax credit carryforwards | $ | (5.6 | ) | $ | (4.0 | ) | ||
Net deferred tax liability associated with the unrecognized tax benefit amounts and related NOLs and tax credits carryforwards were $2.0 million and $(0.3) million for Dec. 31, 2018 and Dec. 31, 2017, respectively.
As the IRS Appeals and federal audit progress and state audits resume, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $8.7 million in the next 12 months.
Payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards.
Interest payable related to unrecognized tax benefits:
(Millions of Dollars) | 2018 | 2017 | 2016 | |||||||||
Payable for interest related to unrecognized tax benefits at Jan. 1 | $ | (0.3 | ) | $ | (1.1 | ) | $ | (0.4 | ) | |||
Interest (expense) income related to unrecognized tax benefits | (0.4 | ) | 0.8 | (0.7 | ) | |||||||
Payable for interest related to unrecognized tax benefits at Dec. 31 | $ | (0.7 | ) | $ | (0.3 | ) | $ | (1.1 | ) | |||
No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2018, 2017 or 2016.
Other Income Tax Matters — NOL amounts represent 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) | 2018 | 2017 | ||||||
Federal NOL carryforward | $ | — | $ | 67.6 | ||||
Federal tax credit carryforwards | 35.0 | 29.8 | ||||||
State NOL carryforwards | 484.7 | 679.2 | ||||||
State tax credit carryforwards, net of federal detriment (a) | 16.9 | 16.8 | ||||||
Valuation allowances for state credit carryforwards, net of federal benefit (b) | (8.9 | ) | (7.3 | ) | ||||
(a) | State tax credit carryforwards are net of federal detriment of $4.5 million as of Dec. 31, 2018 and 2017. |
(b) | Valuation allowances for state tax credit carryforwards were net of federal benefit of $2.4 million and $1.9 million as of Dec. 31, 2018 and 2017, respectively. |
Federal carryforward periods expire between 2021 and 2038 and state carryforward periods expire between 2019 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.
Effective income tax rate for years ended Dec. 31:
2018 | 2017 (a) | 2016 (a) | |||||||
Federal statutory rate | 21.0 | % | 35.0 | % | 35.0 | % | |||
State income tax on pretax income, net of federal tax effect | 3.7 | % | 3.0 | % | 3.0 | % | |||
Increases (decreases) in tax from: | |||||||||
Regulatory differences - ARAM (b) | (3.0 | ) | (0.1 | ) | (0.1 | ) | |||
Regulatory differences - other utility plant items | (1.7 | ) | (0.9 | ) | (0.5 | ) | |||
Amortization of excess nonplant deferred taxes | (1.4 | ) | — | — | |||||
Tax credits recognized, net of federal income tax expense | (0.9 | ) | (0.9 | ) | (0.7 | ) | |||
Wind PTCs recognized | (0.6 | ) | — | — | |||||
Regulatory differences - Deferral of ARAM (c) | 0.2 | — | — | ||||||
Change in unrecognized tax benefits | 0.1 | 0.2 | — | ||||||
Tax reform | — | (2.4 | ) | — | |||||
Other, net | (0.3 | ) | (0.1 | ) | 0.4 | ||||
Effective income tax rate | 17.1 | % | 33.8 | % | 37.1 | % | |||
(a) | Prior periods have been reclassified to conform to current year presentation. |
(b) | ARAM is a method to flow back excess deferred taxes to customers. |
(c) | ARAM has been deferred when regulatory treatment has not been established. As Xcel Energy received direction from its regulatory commissions regarding the return of excess deferred taxes to customers, the ARAM deferral was reversed. This resulted in a reduction to tax expense with a corresponding reduction to revenue. |
Components of income tax expense for the years ended Dec. 31:
(Millions of Dollars) | 2018 | 2017 | 2016 | |||||||||
Current federal tax expense | $ | 79.5 | $ | 40.4 | $ | 45.3 | ||||||
Current state tax expense | 14.2 | 14.6 | 8.7 | |||||||||
Current change in unrecognized tax (benefit) expense | (1.3 | ) | (7.8 | ) | 0.7 | |||||||
Deferred federal tax expense | 4.9 | 176.4 | 195.1 | |||||||||
Deferred state tax expense | 16.6 | 22.5 | 27.2 | |||||||||
Deferred change in unrecognized tax expense (benefit) | 2.3 | 8.9 | (0.3 | ) | ||||||||
Deferred ITCs | (2.5 | ) | (2.8 | ) | (2.8 | ) | ||||||
Total income tax expense | $ | 113.7 | $ | 252.2 | $ | 273.9 | ||||||
Components of deferred income tax expense as of Dec. 31:
(Millions of Dollars) | 2018 | 2017 | 2016 | |||||||||
Deferred tax expense (benefit) excluding items below | $ | 74.8 | $ | (1,244.7 | ) | $ | 230.9 | |||||
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities | (50.6 | ) | 1,453.1 | (8.4 | ) | |||||||
Tax expense allocated to other comprehensive income, net of adoption of ASU No. 2018-02, and other | (0.4 | ) | (0.6 | ) | (0.5 | ) | ||||||
Deferred tax expense | $ | 23.8 | $ | 207.8 | $ | 222.0 | ||||||
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Components of the net deferred tax liability as of Dec. 31:
(Millions of Dollars) | 2018 | 2017 | ||||||
Deferred tax liabilities: | ||||||||
Differences between book and tax bases of property | $ | 1,860.1 | $ | 1,790.1 | ||||
Regulatory assets | 251.1 | 252.4 | ||||||
Pension expense | 33.9 | 60.0 | ||||||
Other | 13.1 | 3.7 | ||||||
Total deferred tax liabilities | $ | 2,158.2 | $ | 2,106.2 | ||||
Deferred tax assets: | ||||||||
Regulatory liabilities | $ | 336.3 | $ | 338.0 | ||||
NOL carryforward | 18.2 | 39.3 | ||||||
Tax credit carryforward | 51.9 | 39.3 | ||||||
Tax credit valuation allowances | (8.9 | ) | — | |||||
Deferred ITCs | 6.3 | 6.9 | ||||||
Other employee benefits | 2.8 | 6.8 | ||||||
Rate refund | 9.3 | 0.9 | ||||||
Other | 23.0 | 30.5 | ||||||
Total deferred tax assets | $ | 438.9 | $ | 461.7 | ||||
Net deferred tax liability | $ | 1,719.3 | $ | 1,644.5 | ||||
9. | 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 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.
• | 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:
Cash equivalents — The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted NAV.
Interest rate derivatives — The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.
Commodity derivatives — The methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2 classification. When contractual settlements relate to inactive delivery locations or extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable forecasts of forward prices and volatilities on a valuation is evaluated, and may result in Level 3 classification.
Derivative Instruments Fair Value Measurements
PSCo enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to manage risk in connection with changes in interest rates, utility commodity prices and vehicle fuel prices.
Interest Rate Derivatives — PSCo enters into various instruments that effectively fix the interest payments on certain floating rate debt obligations or effectively fix the yield or price on a specified benchmark interest rate for an anticipated debt issuance for a specific period. These derivative instruments are generally designated as cash flow hedges for accounting purposes.
As of Dec. 31, 2018, 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. No amounts related to the ineffectiveness of cash flow hedges were recorded for the years ended Dec. 31, 2018 and 2017.
As of Dec. 31, 2018, there were no 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.
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Gross notional amounts of commodity forwards and options at Dec. 31:
(Amounts in Millions) (a)(b) | 2018 | 2017 | ||||
MWh of electricity | 24.4 | 22.3 | ||||
MMBtu of natural gas | 48.4 | 13.4 | ||||
(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, 2018, seven of PSCo’s 10 most significant counterparties for these activities, comprising $63.8 million or 63% of this credit exposure, had investment grade credit ratings from Standard & Poor’s, Moody’s or Fitch Ratings. Three of the 10 most significant counterparties, comprising $14.4 million or 14% 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. Eight of these significant counterparties are municipal or cooperative electric entities, or other utilities.
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) | 2018 | 2017 | 2016 | |||||||||
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1 | $ | (26.5 | ) | $ | (22.8 | ) | $ | (23.8 | ) | |||
After-tax net realized losses on derivative transactions reclassified into earnings | 1.2 | 1.0 | 1.0 | |||||||||
Adoption of ASU. 2018-02 (a) | — | (4.7 | ) | — | ||||||||
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31 | $ | (25.3 | ) | $ | (26.5 | ) | $ | (22.8 | ) | |||
(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 Ended Dec. 31, 2018 | ||||||||
Other derivative instruments | ||||||||
Natural gas commodity | $ | — | $ | 8.0 | ||||
Total | $ | — | $ | 8.0 | ||||
Year Ended Dec. 31, 2017 | ||||||||
Other derivative instruments | ||||||||
Natural gas commodity | $ | — | $ | (10.9 | ) | |||
Total | $ | — | $ | (10.9 | ) | |||
Year Ended Dec. 31, 2016 | ||||||||
Other derivative instruments | ||||||||
Natural gas commodity | — | 2.1 | ||||||
Total | $ | — | $ | 2.1 | ||||
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 Ended 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 Ended 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 | ) | ||||||
Year Ended Dec. 31, 2016 | |||||||||||||
Derivatives designated as cash flow hedges | |||||||||||||
Interest rate | $ | 1.6 | (a) | $ | — | $ | — | ||||||
Vehicle fuel and other commodity | 0.1 | (b) | — | — | |||||||||
Total | $ | 1.7 | $ | — | $ | — | |||||||
Other derivative instruments | |||||||||||||
Commodity trading | $ | — | $ | — | $ | (0.3 | ) | (c) | |||||
Natural gas commodity | — | 10.3 | (d) | (5.8 | ) | (d) | |||||||
Total | $ | — | $ | 10.3 | $ | (6.1 | ) | ||||||
(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, 2018, 2017 and 2016 included $1.2 million of settlement losses, $0.4 million of settlement gains and $0.2 million of settlement losses, 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, 2018, 2017 and 2016 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 no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2018, 2017 and 2016.
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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, 2018 and 2017, there were no 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 no collateral posted related to adequate assurance clauses in derivative contracts as of Dec. 31, 2018 and 2017.
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, 2018 and 2017:
Dec. 31, 2018 | Dec. 31, 2017 | |||||||||||||||||||||||||||||||||||||||||||||||
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 | $ | 2.3 | $ | 65.0 | $ | 0.1 | $ | 67.4 | $ | (28.2 | ) | $ | 39.2 | $ | 0.5 | $ | 4.5 | $ | — | $ | 5.0 | $ | (3.5 | ) | $ | 1.5 | ||||||||||||||||||||||
Natural gas commodity | — | 3.4 | — | 3.4 | — | 3.4 | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||
Total current derivative assets | $ | 2.3 | $ | 68.4 | $ | 0.1 | $ | 70.8 | $ | (28.2 | ) | 42.6 | $ | 0.5 | $ | 4.5 | $ | — | $ | 5.0 | $ | (3.5 | ) | 1.5 | ||||||||||||||||||||||||
PPAs (b) | — | 1.7 | ||||||||||||||||||||||||||||||||||||||||||||||
Current derivative instruments | $ | 42.6 | $ | 3.2 | ||||||||||||||||||||||||||||||||||||||||||||
Noncurrent derivative assets | ||||||||||||||||||||||||||||||||||||||||||||||||
Other derivative instruments: | ||||||||||||||||||||||||||||||||||||||||||||||||
Commodity trading | $ | — | $ | 1.6 | $ | — | $ | 1.6 | $ | (0.4 | ) | $ | 1.2 | $ | — | $ | 1.5 | $ | — | $ | 1.5 | $ | (0.5 | ) | $ | 1.0 | ||||||||||||||||||||||
Total noncurrent derivative assets | $ | — | $ | 1.6 | $ | — | $ | 1.6 | $ | (0.4 | ) | 1.2 | $ | — | $ | 1.5 | $ | — | $ | 1.5 | $ | (0.5 | ) | 1.0 | ||||||||||||||||||||||||
PPAs (b) | — | — | ||||||||||||||||||||||||||||||||||||||||||||||
Noncurrent derivative instruments | $ | 1.2 | $ | 1.0 | ||||||||||||||||||||||||||||||||||||||||||||
Current derivative liabilities | ||||||||||||||||||||||||||||||||||||||||||||||||
Other derivative instruments: | ||||||||||||||||||||||||||||||||||||||||||||||||
Commodity trading | $ | 2.4 | $ | 64.2 | $ | — | $ | 66.6 | $ | (34.7 | ) | $ | 31.9 | $ | 0.4 | $ | 4.3 | $ | — | $ | 4.7 | $ | (3.4 | ) | $ | 1.3 | ||||||||||||||||||||||
Natural gas commodity | — | — | — | — | — | — | — | 1.0 | — | 1.0 | — | 1.0 | ||||||||||||||||||||||||||||||||||||
Total current derivative liabilities | $ | 2.4 | $ | 64.2 | $ | — | $ | 66.6 | $ | (34.7 | ) | 31.9 | $ | 0.4 | $ | 5.3 | $ | — | $ | 5.7 | $ | (3.4 | ) | 2.3 | ||||||||||||||||||||||||
PPAs (b) | 2.7 | 5.0 | ||||||||||||||||||||||||||||||||||||||||||||||
Current derivative instruments | $ | 34.6 | $ | 7.3 | ||||||||||||||||||||||||||||||||||||||||||||
Noncurrent derivative liabilities | ||||||||||||||||||||||||||||||||||||||||||||||||
Other derivative instruments: | ||||||||||||||||||||||||||||||||||||||||||||||||
Commodity trading | $ | — | $ | 1.1 | $ | — | $ | 1.1 | $ | (0.5 | ) | $ | 0.6 | $ | — | $ | 1.4 | $ | — | $ | 1.4 | $ | (0.6 | ) | $ | 0.8 | ||||||||||||||||||||||
Total noncurrent derivative liabilities | $ | — | $ | 1.1 | $ | — | $ | 1.1 | $ | (0.5 | ) | 0.6 | $ | — | $ | 1.4 | $ | — | $ | 1.4 | $ | (0.6 | ) | 0.8 | ||||||||||||||||||||||||
PPAs (b) | — | 2.7 | ||||||||||||||||||||||||||||||||||||||||||||||
Noncurrent derivative instruments | $ | 0.6 | $ | 3.5 | ||||||||||||||||||||||||||||||||||||||||||||
(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, 2018 and 2017. At both Dec. 31, 2018 and 2017, derivative assets and liabilities include no obligations to return cash collateral. At Dec. 31, 2018 and 2017, derivative assets and liabilities include the rights to reclaim cash collateral of $6.5 million and $0 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 on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. |
There were $0.1 million of gains, immaterial gains and immaterial losses recognized in earnings for the years ended Dec. 31, 2018, 2017 and 2016, respectively, for Level 3 commodity trading derivatives.
PSCo recognizes transfers between levels as of the beginning of each period. There were no transfers of amounts between levels for derivative instruments for the years ended Dec. 31, 2018, 2017 and 2016.
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Fair Value of Long-Term Debt
As of Dec. 31, other financial instruments for which the carrying amount did not equal fair value:
2018 | 2017 | |||||||||||||||
(Millions of Dollars) | Carrying Amount | Fair Value | Carrying Amount | Fair Value | ||||||||||||
Long-term debt, including current portion | $ | 4,997.6 | $ | 5,123.2 | $ | 4,608.3 | $ | 5,024.8 | ||||||||
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, 2018 and 2017, and given the observability of the inputs, fair values presented for long-term debt were assigned as Level 2.
10. | 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 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, 2018 and 2017 were $33 million and $37 million, respectively, of which $3 million and $3 million were attributable to PSCo. Xcel Energy recognized net benefit cost for financial reporting for the SERP and nonqualified plans of $4 million in 2018 and $5 million in 2017, of which $1 million in each year was attributable to PSCo.
In 2016, Xcel Energy established rabbi trusts to provide partial funding for future distributions of the SERP and its deferred compensation plan. Rabbi trust funding of deferred compensation plan distributions attributable to PSCo will be supplemented by PSCo’s consolidated operating cash flows.
Xcel Energy has a contributory health and welfare benefit plan that provides health care and death benefits to certain Xcel Energy retirees.
• | Xcel Energy discontinued subsidizing health care benefits for nonbargaining employees of the former NCE, which includes PSCo employees, who retired after June 30, 2003. |
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 2018 were below the assumed level of 6.84%; |
• | Investment returns in 2017 were above the assumed level of 6.84%; |
• | Investment returns in 2016 were below the assumed level of 6.84%; and |
• | In 2019, 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 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 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.
Plan Assets
The following presents, for each of the fair value hierarchy levels, PSCo’s pension plan assets measured at fair value:
Dec. 31, 2018 (a) | Dec. 31, 2017 (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 | $ | 53.0 | $ | — | $ | — | $ | — | $ | 53.0 | $ | 67.2 | $ | — | $ | — | $ | — | $ | 67.2 | ||||||||||||||||||||
Commingled funds | 316.2 | — | — | 326.1 | 642.3 | 363.4 | — | — | 355.5 | 718.9 | ||||||||||||||||||||||||||||||
Debt securities | — | 242.3 | — | — | 242.3 | — | 263.8 | — | — | 263.8 | ||||||||||||||||||||||||||||||
Equity securities | 35.2 | — | — | — | 35.2 | 37.8 | — | — | — | 37.8 | ||||||||||||||||||||||||||||||
Other | 0.6 | 2.0 | — | (9.9 | ) | (7.3 | ) | (9.9 | ) | 1.4 | — | 0.2 | (8.3 | ) | ||||||||||||||||||||||||||
Total | $ | 405.0 | $ | 244.3 | $ | — | $ | 316.2 | $ | 965.5 | $ | 458.5 | $ | 265.2 | $ | — | $ | 355.7 | $ | 1,079.4 | ||||||||||||||||||||
(a) | See Note 9 for further information on fair value measurement inputs and methods. |
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The following presents, 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, 2018 (a) | Dec. 31, 2017 (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 | $ | 17.0 | $ | — | $ | — | $ | — | $ | 17.0 | $ | 25.7 | $ | — | $ | — | $ | — | $ | 25.7 | ||||||||||||||||||||
Insurance contracts | — | 40.2 | — | — | 40.2 | — | 43.5 | — | — | 43.5 | ||||||||||||||||||||||||||||||
Commingled funds | 118.7 | — | — | 35.8 | 154.5 | 130.2 | — | — | — | 130.2 | ||||||||||||||||||||||||||||||
Debt securities | — | 159.7 | — | — | 159.7 | — | 175.4 | — | — | 175.4 | ||||||||||||||||||||||||||||||
Equity securities | — | — | — | — | — | 30.7 | — | — | — | 30.7 | ||||||||||||||||||||||||||||||
Other | — | 0.7 | — | — | 0.7 | — | 0.9 | — | — | 0.9 | ||||||||||||||||||||||||||||||
Total | $ | 135.7 | $ | 200.6 | $ | — | $ | 35.8 | $ | 372.1 | $ | 186.6 | $ | 219.8 | $ | — | $ | — | $ | 406.4 | ||||||||||||||||||||
(a) | See Note 9 for further information on fair value measurement inputs and methods. |
No assets were transferred in or out of Level 3 for 2018 or 2017.
Funded Status — Comparisons of the actuarially computed benefit obligation, changes in plan assets and funded status of the pension and postretirement health care plans for Xcel Energy are as follows:
Pension Benefits | Postretirement Benefits | |||||||||||||||
(Millions of Dollars) | 2018 | 2017 | 2018 | 2017 | ||||||||||||
Change in Benefit Obligation: | ||||||||||||||||
Obligation at Jan. 1 | $ | 1,334.2 | $ | 1,251.8 | $ | 429.2 | $ | 421.8 | ||||||||
Service cost | 29.0 | 27.3 | 0.7 | 0.7 | ||||||||||||
Interest cost | 47.3 | 50.6 | 15.0 | 16.8 | ||||||||||||
Plan amendments | — | (1.1 | ) | — | — | |||||||||||
Actuarial loss | (96.5 | ) | 83.5 | (40.6 | ) | 18.3 | ||||||||||
Plan participants’ contributions | — | — | 6.5 | 6.0 | ||||||||||||
Medicare subsidy reimbursements | — | — | 0.9 | 1.0 | ||||||||||||
Benefit payments | (84.7 | ) | (77.9 | ) | (35.2 | ) | (35.4 | ) | ||||||||
Obligation at Dec. 31 | $ | 1,229.3 | $ | 1,334.2 | $ | 376.5 | $ | 429.2 | ||||||||
Change in Fair Value of Plan Assets: | ||||||||||||||||
Fair value of plan assets at Jan. 1 | $ | 1,079.4 | $ | 1,004.2 | $ | 406.4 | $ | 393.5 | ||||||||
Actual return on plan assets | (50.9 | ) | 135.6 | (11.1 | ) | 37.0 | ||||||||||
Employer contributions | 21.7 | 17.5 | 5.5 | 5.3 | ||||||||||||
Plan participants’ contributions | — | — | 6.5 | 6.0 | ||||||||||||
Benefit payments | (84.7 | ) | (77.9 | ) | (35.2 | ) | (35.4 | ) | ||||||||
Fair value of plan assets at Dec. 31 | $ | 965.5 | $ | 1,079.4 | $ | 372.1 | $ | 406.4 | ||||||||
Funded status of plans at Dec. 31 | $ | (263.8 | ) | $ | (254.8 | ) | $ | (4.4 | ) | $ | (22.8 | ) | ||||
Amounts recognized in the Consolidated Balance Sheet at Dec. 31: | ||||||||||||||||
Noncurrent liabilities | (263.8 | ) | (254.8 | ) | (4.4 | ) | (22.8 | ) | ||||||||
Net amounts recognized | $ | (263.8 | ) | $ | (254.8 | ) | $ | (4.4 | ) | $ | (22.8 | ) | ||||
Significant Assumptions Used to Measure Benefit Obligations: | ||||||||||||||||
Discount rate for year-end valuation | 4.31 | % | 3.63 | % | 4.32 | % | 3.62 | % | ||||||||
Expected average long-term increase in compensation level | 3.75 | 3.75 | N/A | N/A | ||||||||||||
Mortality table | RP-2014 | RP-2014 | RP-2014 | RP-2014 | ||||||||||||
Health care costs trend rate — initial: Pre-65 | N/A | N/A | 6.50 | % | 7.00 | % | ||||||||||
Health care costs trend rate — initial: Post-65 | N/A | N/A | 5.30 | % | 5.50 | % | ||||||||||
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 | 4 | 5 | ||||||||||||
Accumulated benefit obligation for the pension plan was $1,183.3 million and $1,285.0 million as of Dec. 31, 2018 and 2017, respectively.
39
Net Periodic Benefit Cost (Credit) — Net periodic benefit cost (credit) other than the service cost component is included in other income in the consolidated statement of income.
Components of net periodic benefit cost (credit) and the amounts recognized in other comprehensive income and regulatory assets and liabilities:
Pension Benefits | Postretirement Benefits | |||||||||||||||||||||||
(Millions of Dollars) | 2018 | 2017 | 2016 | 2018 | 2017 | 2016 | ||||||||||||||||||
Service cost | $ | 29.0 | $ | 27.3 | $ | 25.9 | $ | 0.7 | $ | 0.7 | $ | 0.8 | ||||||||||||
Interest cost | 47.3 | 50.6 | 55.4 | 15.0 | 16.8 | 18.1 | ||||||||||||||||||
Expected return on plan assets | (68.5 | ) | (68.5 | ) | (70.8 | ) | (22.7 | ) | (21.9 | ) | (22.3 | ) | ||||||||||||
Amortization of prior service credit | (3.4 | ) | (3.2 | ) | (3.2 | ) | (6.2 | ) | (6.2 | ) | (6.3 | ) | ||||||||||||
Amortization of net loss | 31.2 | 28.3 | 26.8 | 4.0 | 3.8 | 1.9 | ||||||||||||||||||
Settlement charge (a) | 4.5 | — | — | — | — | — | ||||||||||||||||||
Net periodic pension cost (credit) | 40.1 | 34.5 | 34.1 | (9.2 | ) | (6.8 | ) | (7.8 | ) | |||||||||||||||
Costs (credits) not recognized due to effects of regulation | (3.9 | ) | (2.7 | ) | 3.4 | 1.8 | — | — | ||||||||||||||||
Net benefit cost (credit) recognized for financial reporting | $ | 36.2 | $ | 31.8 | $ | 37.5 | $ | (7.4 | ) | $ | (6.8 | ) | $ | (7.8 | ) | |||||||||
Significant Assumptions Used to Measure Costs: | ||||||||||||||||||||||||
Discount rate | 3.63 | % | 4.13 | % | 4.66 | % | 3.62 | % | 4.13 | % | 4.65 | % | ||||||||||||
Expected average long-term increase in compensation level | 3.75 | 3.75 | 4.00 | N/A | N/A | N/A | ||||||||||||||||||
Expected average long-term rate of return on assets | 6.84 | 6.84 | 6.84 | 5.80 | 5.80 | 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 2018, as a result of lump-sum distributions during the 2018 plan years, PSCo recorded a total pension settlement charge of $4.5 million in 2018, the majority of which was not recognized due to the effects of regulation. |
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 2019 pension cost calculations is 6.84%.
Pension Benefits | Postretirement Benefits | |||||||||||||||
(Millions of Dollars) | 2018 | 2017 | 2018 | 2017 | ||||||||||||
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: | ||||||||||||||||
Net loss | $ | 530.8 | $ | 543.7 | $ | 66.9 | $ | 77.8 | ||||||||
Prior service credit | (7.2 | ) | (10.6 | ) | (15.3 | ) | (21.5 | ) | ||||||||
Total | $ | 523.6 | $ | 533.1 | $ | 51.6 | $ | 56.3 | ||||||||
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 | $ | 25.8 | $ | 27.7 | $ | — | ||||||||||
Noncurrent regulatory assets | 497.5 | 505.1 | 51.6 | 56.3 | ||||||||||||
Deferred income taxes | 0.1 | 0.1 | — | — | ||||||||||||
Net-of-tax accumulated other comprehensive income | 0.2 | 0.2 | — | — | ||||||||||||
Total | $ | 523.6 | $ | 533.1 | $ | 51.6 | $ | 56.3 | ||||||||
Measurement date | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | ||||
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 2016 - 2019 to meet minimum funding requirements. Total voluntary and required pension funding contributions across all four of Xcel Energy’s pension plans were as follows:
• | $150 million in January 2019, of which $43 million was attributable to PSCo; |
• | $150 million in 2018, of which $22 million was attributable to PSCo; |
• | $162 million in 2017, of which $18 million was attributable to PSCo; and |
• | $125 million in 2016, of which $17 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.
Xcel Energy expects to contribute approximately $11 million during 2019, of which amounts attributable to PSCo will be zero.
Xcel Energy, which includes PSCo, contributed:
• | $11 million during 2018, of which $5 million was attributable to PSCo; |
• | $20 million during 2017, of which $5 million was attributable to PSCo; and |
• | $18 million during 2016, of which $5 million was attributable to PSCo. |
40
Targeted asset allocations:
Pension Benefits | Postretirement Benefits | |||||||||||
2018 | 2017 | 2018 | 2017 | |||||||||
Domestic and international equity securities | 35 | % | 34 | % | 18 | % | 24 | % | ||||
Long-duration fixed income securities | 32 | 32 | — | — | ||||||||
Short-to-intermediate fixed income securities | 16 | 18 | 70 | 60 | ||||||||
Alternative investments | 15 | 14 | 8 | 9 | ||||||||
Cash | 2 | 2 | 4 | 7 | ||||||||
Total | 100 | % | 100 | % | 100 | % | 100 | % | ||||
Plan Amendments — Xcel Energy, which includes PSCo, amended the Xcel Energy Inc. Nonbargaining Pension Plan (South) in 2017 to reduce supplemental benefits for non-bargaining participants as well as to allow the transfer of a portion of non-qualified pension obligations into the qualified plans. In 2016, the annual credits contributed to the PSCo Bargaining Plan retirement spending account increased.
In 2018 and 2017, there were no plan amendments made which affected the 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 | ||||||||||||
2019 | $ | 81.2 | $ | 31.6 | $ | 2.0 | $ | 29.6 | ||||||||
2020 | 80.9 | 31.7 | 2.1 | 29.6 | ||||||||||||
2021 | 82.4 | 31.6 | 2.2 | 29.4 | ||||||||||||
2022 | 82.8 | 31.5 | 2.3 | 29.2 | ||||||||||||
2023 | 83.4 | 31.0 | 2.4 | 28.6 | ||||||||||||
2024-2028 | 410.2 | 141.5 | 13.0 | 128.5 | ||||||||||||
Defined 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 2018 and $10 million in 2017 and 2016.
11. | 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 complex judgments about future events. Management maintains accruals for 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 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.
Line Extension Disputes — In December 2015, the DRC filed a lawsuit seeking monetary damages in the Denver District Court, stating PSCo failed to award proper allowances and refunds for line extensions to new developments pursuant to the terms of electric and gas service agreements. The dispute involves claims by over fifty developers. In February 2018, the Colorado 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 substantially similar to the arguments previously raised by DRC. PSCo filed a motion to dismiss this claim, which was granted in May 2018. DRC subsequently filed an appeal to the Colorado Court of Appeals with its opening brief in January 2019 and PSCo filed its answer brief in February 2019. It is uncertain when a decision will be rendered.
PSCo has concluded that a loss is remote with respect to both of these matters as the service agreements were developed to implement CPUC approved tariffs and PSCo has complied with the tariff provisions. If a loss were sustained, PSCo believes it would be allowed to recover costs through traditional regulatory mechanisms. Amount or range in dispute is presently unknown and no accrual has been recorded for this matter.
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 currently investigating or remediating three MGP, landfill or other disposal sites across its service territories, and these activities will continue through at least 2019. PSCo accrued $0.6 million as of Dec. 31, 2018 and an immaterial amount as of Dec. 31, 2017 for these sites. There may be insurance recovery and/or recovery from other potentially responsible parties, offsetting some portion 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. In 2015, the EPA published the CCR Rule. Litigation was brought challenging the rule in the D.C. Circuit.
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Under the CCR Rule, utilities are required to complete groundwater sampling around their CCR landfills and surface impoundments. PSCo has identified at least two sites where statistically significant increases over established groundwater standards exist in the groundwater near landfills and/or impoundments. PSCo has completed removal of CCR from these impoundments and plans to close these landfills. By the end of 2019, only six of PSCo’s regulated ash units are expected to be in operation. PSCo is conducting additional groundwater sampling and will evaluate whether corrective action is required at any CCR landfills or surface impoundments.
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 D.C. 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. Litigation is ongoing regarding the deadline for closing or retrofitting these impoundments.
Federal CWA WOTUS Rule — In 2015, the EPA and Corps published a final rule that significantly broadened the scope of waters under the CWA that are subject to federal jurisdiction, referred to as “WOTUS”. The Rule has been subject to significant litigation and is currently stayed in a portion of the country. PSCo cannot estimate potential impacts until the legal and administrative processes are finalized, but expects 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 surface 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 estimates that ELG compliance will cost approximately $1.5 million to complete. The EPA, however, is conducting a rulemaking process to potentially revise the effluent limitations and pretreatment standards, which may impact compliance costs. PSCo anticipates these costs will be fully recoverable through regulatory mechanisms.
Federal CWA Section 316(b) — The federal CWA requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available for minimizing impingement and entrainment of aquatic species. PSCo anticipates these costs will be fully recoverable through regulatory mechanisms.
AROs — AROs have been recorded for PSCo’s assets.
PSCo’s AROs were as follows:
Dec. 31, 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 were more than offset by increased discount rates. Changes in electric distribution AROs were primarily related to increased labor costs. |
Dec. 31, 2017 | ||||||||||||||||||||
(Millions of Dollars) | Jan. 1, 2017 | Amounts Settled (a) | Accretion | Cash Flow Revisions (b) | Dec. 31, 2017 (c) | |||||||||||||||
Electric | ||||||||||||||||||||
Steam, hydro, and other production | $ | 113.1 | $ | (24.1 | ) | $ | 5.1 | $ | 9.1 | $ | 103.2 | |||||||||
Wind | 2.1 | — | — | — | 2.1 | |||||||||||||||
Distribution | 7.7 | — | 0.2 | — | 7.9 | |||||||||||||||
Miscellaneous | 1.5 | (0.2 | ) | 0.1 | — | 1.4 | ||||||||||||||
Natural gas | ||||||||||||||||||||
Transmission and distribution | 160.7 | — | 6.7 | 61.5 | 228.9 | |||||||||||||||
Miscellaneous | 4.1 | (0.4 | ) | 0.2 | — | 3.9 | ||||||||||||||
Common | ||||||||||||||||||||
Miscellaneous | 0.4 | — | — | — | 0.4 | |||||||||||||||
Total liability | $ | 289.6 | $ | (24.7 | ) | $ | 12.3 | $ | 70.6 | $ | 347.8 | |||||||||
(a) | Amounts settled related to asbestos abatement projects, closure of certain ash containment facilities, and removal and proper disposal of storage tanks and other above ground equipment. |
(b) | In 2017, AROs were revised for changes in timing and estimates of cash flows. Changes in gas transmission and distribution AROs were primarily related to increased labor costs. |
(c) | There were no ARO amounts incurred in 2017. |
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, 2018. Therefore, an ARO has not been recorded for these facilities.
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Removal Costs — PSCo records a regulatory liability for the plant removal costs that are recovered currently in rates. These 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, 2018 and 2017 were $344 million and $346 million, respectively.
Leases — PSCo has three leases accounted for as capital leases. The assets and liabilities of a capital lease are recorded at the lower of fair market value of the leased asset or the present value of future lease payments and are amortized over the term of the contract.
WYCO is a joint venture between Xcel Energy Inc. and CIG to develop and lease natural gas pipeline, storage and compression facilities. Xcel Energy Inc. has a 50% ownership interest in WYCO, and PSCo has no direct ownership interest. 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 arrangement with CIG as a capital lease. As a result, PSCo had $120.0 million and $123.8 million of capital lease obligations as of Dec. 31, 2018 and 2017, respectively.
PSCo records amortization for its capital lease assets as electric fuel and purchased power and cost of natural gas sold and transported on the consolidated statements of income. Total amortization expense under capital lease assets was approximately $5.6 million, $5.3 million and $8.1 million for 2018, 2017 and 2016, respectively.
Property held under capital leases:
(Millions of Dollars) | Dec. 31, 2018 | Dec. 31, 2017 | ||||||
Gas storage facilities | $ | 200.5 | $ | 200.5 | ||||
Gas pipeline | 20.7 | 20.7 | ||||||
Property held under capital leases | 221.2 | 221.2 | ||||||
Accumulated depreciation | (76.2 | ) | (70.6 | ) | ||||
Total property held under capital leases, net | $ | 145.0 | $ | 150.6 | ||||
Remaining leases, primarily for office space, railcars, generating facilities, vehicles, aircraft and power-operated equipment, are accounted for as operating leases.
Total expenses (including capacity payments) under operating lease obligations for PSCo and the corresponding capacity payments for PPAs accounted for as operating leases for the year ended Dec. 31:
(Millions of Dollars) | 2018 | 2017 | 2016 | |||||||||
Total expense | $ | 110.6 | $ | 108.6 | $ | 118.2 | ||||||
Capacity payments | 96.6 | 96.1 | 102.4 | |||||||||
Included in the future commitments under operating leases are estimated future capacity payments under PPAs that have been accounted for as operating leases.
Future commitments under operating and capital leases:
(Millions of Dollars) | Operating Leases | PPA (a) (b) Operating Leases | Total Operating Leases | Capital Leases | ||||||||||||
2019 | $ | 10.8 | $ | 95.5 | $ | 106.3 | $ | 24.9 | ||||||||
2020 | 10.7 | 95.9 | 106.6 | 24.8 | ||||||||||||
2021 | 9.5 | 96.4 | 105.9 | 23.6 | ||||||||||||
2022 | 8.4 | 82.6 | 91.0 | 20.5 | ||||||||||||
2023 | 8.1 | 70.0 | 78.1 | 20.3 | ||||||||||||
Thereafter | 53.4 | 288.6 | 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 as executory contracts. |
(b) | PPA operating leases contractually expire through 2034. |
Non-Lease PPAs — PSCo has entered into PPAs with other utilities and energy suppliers with expiration dates through 2034 for purchased power to meet system load and energy requirements and meet operating reserve obligations. In general, these agreements provide for energy payments, based on actual energy delivered and capacity payments. Certain PPAs accounted for as executory contracts contain minimum energy purchase commitments.
Capacity and energy payments are contingent on the IPP meeting 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 $20.9 million, $25.2 million and $44.0 million in 2018, 2017 and 2016, respectively.
At Dec. 31, 2018, 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 | |||
2019 | $ | 12.3 | ||
2020 | 3.3 | |||
2021 | 3.2 | |||
2022 | 3.2 | |||
2023 | 3.2 | |||
Thereafter | 9.8 | |||
Total | $ | 35.0 | ||
Fuel Contracts — PSCo has entered into various long-term commitments for the purchase and delivery of a significant portion of its coal and natural gas requirements. These contracts expire between 2019 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, 2018:
(Millions of Dollars) | Coal | Natural gas supply | Natural gas storage and transportation | |||||||||
2019 | $ | 133.1 | $ | 342.6 | $ | 116.7 | ||||||
2020 | 86.4 | 261.6 | 115.1 | |||||||||
2021 | 55.6 | 251.8 | 113.0 | |||||||||
2022 | 32.5 | 113.0 | 113.1 | |||||||||
2023 | 24.8 | 59.9 | 65.5 | |||||||||
Thereafter | 104.3 | — | 544.0 | |||||||||
Total | $ | 436.7 | $ | 1,028.9 | $ | 1,067.4 | ||||||
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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 1,571 MW of capacity under long-term PPAs at both Dec. 31, 2018 and 2017 with entities that have been determined to be VIEs. These agreements have expiration dates through 2032.
12. | Other Comprehensive Income |
Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31:
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 | ) | |||
2017 | ||||||||||||
(Millions of Dollars) | Gains and Losses on Cash Flow Hedges | Defined Benefit and Postretirement Items | Total | |||||||||
Accumulated other comprehensive loss at Jan. 1 | $ | (22.8 | ) | $ | (0.2 | ) | $ | (23.0 | ) | |||
Losses reclassified from net accumulated other comprehensive loss: | ||||||||||||
Interest rate derivatives (net of taxes of $0.6 and $0, respectively) | 1.0 | (a) | — | 1.0 | ||||||||
Net current period other comprehensive income | 1.0 | — | 1.0 | |||||||||
Adoption of ASU No. 2018-02 (b) | (4.7 | ) | — | (4.7 | ) | |||||||
Accumulated other comprehensive loss at Dec. 31 | $ | (26.5 | ) | $ | (0.2 | ) | $ | (26.7 | ) | |||
(a) | Included in interest charges. |
(b) | In 2017, PSCo implemented ASU No. 2018-02 related to the TCJA, which resulted in reclassification of certain credit balances within net accumulated other comprehensive loss to retained earnings. |
13. | 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.
• | 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. |
• | All Other - Revenues from operating segments not included above are below the necessary quantitative thresholds are included in the all other category. Those primarily include steam revenue, appliance repair services and nonutility real estate activities. |
Asset and capital expenditure information is not provided for PSCo’s reportable segments because as an integrated electric and natural gas utility, PSCo operates significant assets that are not dedicated to a specific business segment, and reporting assets and capital expenditures by business segment would require arbitrary and potentially misleading allocations which may not necessarily reflect the assets that would be required for the operation of the business segments on a stand-alone basis.
To report income from operations for regulated electric and regulated natural gas utility segments, the majority of costs are directly assigned to each segment. However, some costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation allocators. A general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising.
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PSCo’s segment information:
(Millions of Dollars) | 2018 | 2017 | 2016 | |||||||||
Regulated Electric | ||||||||||||
Operating revenues (a) | $ | 3,031.2 | $ | 3,003.8 | $ | 3,049.4 | ||||||
Intersegment revenues | 0.3 | 0.3 | 0.3 | |||||||||
Total operating revenue | $ | 3,031.5 | $ | 3,004.1 | $ | 3,049.7 | ||||||
Depreciation and amortization | 415.6 | 353.6 | 337.6 | |||||||||
Interest charges and financing costs | 142.3 | 138.6 | 136.3 | |||||||||
Income tax expense | 103.0 | 243.6 | 228.8 | |||||||||
Net income | 428.6 | 370.6 | 384.0 | |||||||||
Regulated Natural Gas | ||||||||||||
Operating revenues (a) | $ | 1,014.6 | $ | 995.2 | $ | 957.7 | ||||||
Intersegment revenues | 0.6 | 0.4 | 0.1 | |||||||||
Total operating revenue | $ | 1,015.2 | $ | 995.6 | $ | 957.8 | ||||||
Depreciation and amortization | 140.6 | 113.2 | 101.7 | |||||||||
Interest charges and financing costs | 42.9 | 40.2 | 37.9 | |||||||||
Income tax expense | 13.1 | 18.4 | 46.0 | |||||||||
Net income | 121.4 | 107.8 | 75.4 | |||||||||
All Other | ||||||||||||
Operating revenues (a) | $ | 40.4 | $ | 43.5 | $ | 40.7 | ||||||
Depreciation and amortization | 4.9 | 4.7 | 4.3 | |||||||||
Interest charges and financing costs | 0.5 | 0.5 | 0.4 | |||||||||
Income tax (benefit) | (2.4 | ) | (9.8 | ) | (0.9 | ) | ||||||
Net income | 1.7 | 15.7 | 4.1 | |||||||||
Consolidated Total | ||||||||||||
Operating revenues (a) | $ | 4,087.1 | $ | 4,043.2 | $ | 4,048.2 | ||||||
Intersegment revenues | (0.9 | ) | (0.7 | ) | (0.4 | ) | ||||||
Total operating revenue | $ | 4,086.2 | $ | 4,042.5 | $ | 4,047.8 | ||||||
Depreciation and amortization | 561.1 | 471.5 | 443.6 | |||||||||
Interest charges and financing costs | 185.7 | 179.3 | 174.6 | |||||||||
Income tax expense | 113.7 | 252.2 | 273.9 | |||||||||
Net income | 551.7 | 494.1 | 463.5 | |||||||||
(a) | Operating revenues include $4.4 million, $5.9 million and $13.3 million of intercompany revenue for the years ended Dec. 31, 2018, 2017 and 2016, respectively. See Note 14 for further information. |
14. | 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 5 for further information.
Significant affiliate transactions among the companies and related parties for the years ended Dec. 31:
(Millions of Dollars) | 2018 | 2017 | 2016 | |||||||||
Operating revenues: | ||||||||||||
Electric | $ | — | $ | 1.4 | $ | 8.8 | ||||||
Other | 4.4 | 4.5 | 4.5 | |||||||||
Operating expenses: | ||||||||||||
Other operating expenses — paid to Xcel Energy Services Inc. | 518.7 | 485.1 | 446.1 | |||||||||
Interest expense | — | — | 0.1 | |||||||||
Accounts receivable and payable with affiliates at Dec. 31:
2018 | 2017 | |||||||||||||||
(Millions of Dollars) | Accounts Receivable | Accounts Payable | Accounts Receivable | Accounts Payable | ||||||||||||
NSP-Minnesota | $ | 17.9 | $ | — | $ | 7.7 | $ | — | ||||||||
NSP-Wisconsin | — | 0.2 | — | — | ||||||||||||
SPS | 0.7 | — | 0.3 | — | ||||||||||||
Other subsidiaries of Xcel Energy Inc. | 62.2 | 45.8 | 6.7 | 58.7 | ||||||||||||
$ | 80.8 | $ | 46.0 | $ | 14.7 | $ | 58.7 | |||||||||
15. | Summarized Quarterly Financial Data (Unaudited) |
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 | 206.9 | 189.3 | 276.9 | 119.5 | ||||||||||||
Net income | 133.7 | 122.3 | 207.1 | 88.6 | ||||||||||||
Quarter Ended | ||||||||||||||||
(Millions of Dollars) | March 31, 2017 | June 30, 2017 | Sept. 30, 2017 | Dec. 31, 2017 | ||||||||||||
Operating revenues | $ | 1,080.5 | $ | 930.9 | $ | 1,030.3 | $ | 1,000.8 | ||||||||
Operating income (a) | 212.9 | 193.3 | 326.5 | 155.3 | ||||||||||||
Net income | 111.5 | 100.6 | 186.1 | 95.9 | ||||||||||||
(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.
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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 and chief financial officer, allowing timely decisions regarding required disclosure. As of Dec. 31, 2018, based on an evaluation carried out under the supervision and with the participation of PSCo’s management, including the chief executive officer and chief financial officer, of the effectiveness of its disclosure controls and the procedures, the chief executive officer and chief financial officer have concluded that PSCo’s disclosure controls and procedures were effective.
Internal Control Over Financial Reporting
No change in PSCo’s internal control over financial reporting has occurred during the most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, PSCo’s internal control over financial reporting. PSCo maintains internal control over financial reporting to provide reasonable assurance regarding the reliability of the financial reporting. PSCo has evaluated and documented its controls in process activities, general computer activities, and on an entity-wide level. During the year and in preparation for issuing its report for the year ended Dec. 31, 2018 on internal controls under section 404 of the Sarbanes-Oxley Act of 2002, PSCo conducted testing and monitoring of its internal control over financial reporting. Based on the control evaluation, testing and remediation performed, PSCo did not identify any material control weaknesses, as defined under the standards and rules issued by the Public Company Accounting Oversight Board and as approved by the SEC and as indicated in Management Report on Internal Controls herein.
This annual report does not include an attestation report of PSCo’s independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by PSCo’s independent registered public accounting firm pursuant to the rules of the SEC that permit PSCo to provide only management’s report in this annual report.
Item 9B — Other Information
None.
PART III
Items 10, 11, 12 and 13 of Part III of Form 10-K have been omitted from this report for PSCo in accordance with conditions set forth in general instructions I (1) (a) and (b) of Form 10-K for wholly-owned subsidiaries.
Item 10 — Directors, Executive Officers and Corporate Governance
Item 11 — Executive Compensation
Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13 — Certain Relationships and Related Transactions, and Director Independence
Information required under this Item is contained in Xcel Energy Inc.’s Proxy. Statement for its 2019 Annual Meeting of Shareholders, which is incorporated by reference.
Item 14 — Principal Accountant Fees and Services
Information required by Item 14 of From 10-K is set forth under the heading “Independent Registered Public Accounting Firm - Audit and Non-Audit Fees” in Xcel Energy Inc.’s definitive Proxy Statement for the 2019 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about April 1, 2019. Such information set forth under such heading is incorporated herein by this reference hereto.
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PART IV
Item 15 — Exhibits, Financial Statement Schedules
1 | Consolidated Financial Statements: |
Management Report on Internal Controls Over Financial Reporting — For the year ended Dec. 31, 2018. | |
Report of Independent Registered Public Accounting Firm — Financial Statements | |
Consolidated Statements of Income — For the three years ended Dec. 31, 2018, 2017, and 2016. | |
Consolidated Statements of Comprehensive Income — For the three years ended Dec. 31, 2018, 2017, and 2016. | |
Consolidated Statements of Cash Flows — For the three years ended Dec. 31, 2018, 2017, and 2016. | |
Consolidated Balance Sheets — As of Dec. 31, 2018 and 2017. | |
Consolidated Statements of Common Stockholder’s Equity — For the three years ended Dec. 31, 2018, 2017 and 2016. | |
2 | Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2018, 2017, and 2016. |
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 |
3.01* | PSCo Form 10-Q for the quarter ended Sept. 30, 2017 | 001-03280 | 3.01 | |
4.01* | Xcel Energy Inc. Form S-3 dated April 18, 2018 | 001-03034 | 4(d)(3) | |
4.02* | PSCo Form 8-K dated July 13, 1999 | 001-03280 | 4.1 4.2 | |
4.03* | PSCo Form 8-K dated Aug. 8, 2007 | 001-03280 | 4.01 | |
4.04* | PSCo Form 8-K dated Aug. 6, 2008 | 001-03280 | 4.01 | |
4.05* | PSCo Form 8-K dated May 28, 2009 | 001-03280 | 4.01 | |
4.06* | PSCo Form 8-K dated Nov. 8, 2010 | 001-03280 | 4.01 | |
4.07* | PSCo Form 8-K dated Aug. 9, 2011 | 001-03280 | 4.01 | |
4.08* | PSCo Form 8-K dated Sept. 11, 2012 | 001-03280 | 4.01 | |
4.09* | PSCo Form 8-K dated March 26, 2013 | 001-03280 | 4.01 | |
4.10* | PSCo Form 8-K dated March 10, 2014 | 001-03280 | 4.01 | |
4.11* | PSCo Form 8-K dated May 12, 2015 | 001-03280 | 4.01 | |
4.12* | PSCo Form 8-K dated June 13, 2016 | 001-03280 | 4.01 | |
4.13* | PSCo Form 8-K dated June 19, 2017 | 001-03280 | 4.01 | |
4.14* | PSCo Form 8-K dated June 21, 2018 | 001-03280 | 4.01 | |
10.01*+ | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008 | 001-03034 | 10.02 | |
47
10.02*+ | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008 | 001-03034 | 10.05 | |
10.03*+ | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008 | 001-03034 | 10.08 | |
10.04*+ | Xcel Energy Inc. Form U5B dated Nov. 16, 2000 | 001-03034 | H-1 | |
10.05*+ | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008 | 001-03034 | 10.17 | |
Xcel Energy Inc. Form 8-K dated Dec. 3, 2004 | 001-03034 | 99.02 | ||
10.07*+ | Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2009 | 001-03034 | 10.06 | |
10.08*+ | Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2009 | 001-03034 | 10.08 | |
10.09*+ | Xcel Energy Inc. Definitive Proxy Statement dated April 6, 2010 | 001-03034 | Schedule 14A | |
10.10*+ | Xcel Energy Inc. Definitive Proxy Statement dated April 6, 2010 | 001-03034 | Schedule 14A | |
10.11*+ | Xcel Energy Inc. Definitive Proxy Statement dated April 5, 2011 | 001-03034 | Schedule 14A | |
10.12*+ | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008 | 001-03034 | 10.07 | |
10.13*+ | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2011 | 001-03034 | 10.17 | |
10.14*+ | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2011 | 001-03034 | 10.18 | |
10.15*+ | Xcel Energy Inc. Form 10-Q for the quarter ended March 31, 2013 | 001-03034 | 10.01 | |
10.16*+ | Xcel Energy Inc. Form 10-Q for the quarter ended March 31, 2013 | 001-03034 | 10.02 | |
10.17*+ | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2013 | 001-03034 | 10.21 | |
10.18*+ | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2013 | 001-03034 | 10.22 | |
10.19*+ | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2013 | 001-03034 | 10.23 | |
10.20*+ | Xcel Energy Inc. Definitive Proxy Statement dated April 6, 2015 | 001-03034 | Schedule 14A | |
10.21*+ | Xcel Energy Inc. Form 8-K dated May 20, 2015 | 001-03034 | 10.02 | |
10.22*+ | Xcel Energy Inc. Form 8-K dated May 20, 2015 | 001-03034 | 10.03 | |
10.23*+ | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2015 | 001-03034 | 10.28 | |
10.24*+ | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2015 | 001-03034 | 10.29 | |
10.25*+ | Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2016 | 001-03034 | 10.01 | |
Xcel Energy Inc. Form 8-K dated June 20, 2016 | 001-03034 | 99.03 | ||
10.27*+ | Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2016 | 001-03034 | 10.01 | |
10.28*+ | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2016 | 001-03034 | 10.27 | |
10.29*+ | Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2017 | 001-03034 | 10.1 | |
10.30*+ | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2017 | 001-03034 | 10.30 | |
10.31*+ | Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2018 | 001-03034 | 10.01 | |
10.32*+ | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018 | 001-03034 | 10.34 | |
10.33*+ | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018 | 001-03034 | 10.35 | |
10.34*+ | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018 | 001-03034 | 10.36 | |
48
101 | The following materials from PSCo’s Annual Report on Form 10-K for the year ended Dec. 31, 2018 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) Notes to Consolidated Financial Statements, (vii) document and entity information, and (viii) Schedule II. |
SCHEDULE II
PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
YEARS ENDED DEC. 31, 2018, 2017 AND 2016
Allowance for bad debts | |||||||||||
(Millions of Dollars) | 2018 | 2017 | 2016 | ||||||||
Balance at Jan. 1 | $ | 19.6 | $ | 19.6 | $ | 20.1 | |||||
Additions Charged to Costs and Expenses | 16.4 | 14.3 | 14.1 | ||||||||
Additions Charged to Other Accounts (a) | 4.7 | 4.0 | 4.5 | ||||||||
Deductions from Reserves (b) | (20.2 | ) | (18.3 | ) | (19.1 | ) | |||||
Balance at Dec. 31 | $ | 20.5 | $ | 19.6 | $ | 19.6 | |||||
(a) | Recovery of amounts previously written off. |
(b) | Deductions relate primarily to bad debt write-offs. |
Item 16 — Form 10-K Summary
None.
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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. 22, 2019 | /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/ ALICE K. JACKSON | |
Ben Fowke | Alice 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/ DAVID L. EVES | ||
David L. Eves | ||
Executive Vice President 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.
50