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, 20172019
OR
¨ ☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to .
Commission File Number 1-5924
TUCSON ELECTRIC POWER COMPANY
(Exact name of registrant as specified in its charter)
|
| | |
Commission File Number 1-5924 |
TUCSON ELECTRIC POWER COMPANYArizona | 86-0062700 |
(Exact name of registrant as specified in its charter) |
Arizona
(State or other jurisdiction of incorporation or organization) | | 86-0062700
(I.R.S. Employer Identification No.) |
88 East Broadway Boulevard, Tucson, AZ 85701
(Address of principal executive offices)(Zip Code)
|
Registrant's telephone number, including area code: (520) 571-4000
|
88 East Broadway Boulevard, Tucson, AZ85701
(Address of principal executive offices)(Zip Code)
Registrant's telephone number, including area code: (520) 571-4000
Securities registered pursuant to Section 12(b) of the Exchange Act: None
Securities registered pursuant to Section 12(g) of the Exchange Act: Common Stock, No Par Value (Title of Class)
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act of 1933.Act. Yes oNo x
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Exchange Act of 1934 (Exchange Act).Act. Yes oNo x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of each 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. (Check one): |
| | | | | | | |
Large Accelerated Filero | Accelerated Filero | Non-Accelerated Filerx | ☒ | Smaller Reporting Companyo | ☐ | Emerging Growth Companyo |
| | (do not check if a smaller reporting 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. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o☐ No x
State the aggregate market value of the voting and non-voting common equity held by non-affiliates: None
As of February 14, 2018,12, 2020, Tucson Electric Power Company had 32,139,434 shares of common stock, no par value, outstanding, all of which were held by UNS Energy Corporation, an indirect wholly owned subsidiary of Fortis Inc.
Documents incorporated by reference: None
Tucson Electric Power meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and is, therefore, filing portions of this Form 10-K with the reduced disclosure format specified in General Instruction I(2) of Form 10-K.
Table of Contents
DEFINITIONS
The abbreviations and acronyms used in the 20172019 Form 10-K are defined below:
INDUSTRY ACRONYMS AND CERTAIN DEFINITIONS |
| | |
| 2010 Reimbursement Agreement | | Reimbursement Agreement, dated December 14, 2010 between TEP, as borrower, and a financial institution |
20172015 Credit Agreement | | The 2015 Credit Agreement provides for a $250 million revolving credit and letter of credit facilities with a sublimit of $50 million; the credit agreement matures in 2020 |
| 2019 Credit Agreement | | The 2019 Credit Agreement provides for up to $225 million in term loans; the credit agreement matures in 2020 |
2019 Rate OrderCase | | A pending general rate order issued bycase filed with the ACC resultingby TEP in aApril 2019 requesting new rate structure for TEP, effective on February 27, 2017rates be implemented in May 2020 |
| ABR | | Alternate Base Rate |
| ACC | | Arizona Corporation Commission |
APSACC Refund Order | | An order issued by the ACC approving TEP’s proposal to return savings from the Company’s federal corporate income tax rate under the TCJA to its customers through a combination of a customer bill credit and a regulatory liability that reflects the deferral of the return of a portion of the savings, effective May 1, 2018 |
| ACE | | Affordable Clean Energy |
| ADEQ | | Arizona Public Service CompanyDepartment of Environmental Quality |
BARTAFUDC | | Best Available Retrofit TechnologyAllowance for Funds Used During Construction |
BBtuALJ | | Billion British thermal unit(s)Administrative Law Judge |
| AMT | | Alternative Minimum Tax |
| AOCI | | Accumulated Other Comprehensive Income |
| ARO | | Asset Retirement Obligation |
| CCR | | Coal Combustion Residuals |
| DG | | Distributed Generation |
| DSM | | Demand Side Management |
| ECA | | Environmental Compliance Adjustor |
| EDIT | | Excess Deferred Income Taxes |
| EE Standards | | Energy Efficiency Standards |
| EIM | | Energy Imbalance Market |
| EPA | | Environmental Protection Agency |
EPNGFASB | | El Paso Natural Gas Company, LLC.Financial Accounting Standards Board |
| FERC | | Federal Energy Regulatory Commission |
| FERC Refund Order | | An order issued by the FERC approving TEP's proposal of an overall transmission rate reduction reflecting the lower federal tax rate, effective March 21, 2018 |
| GAAP | | Generally Accepted Accounting Principles in the United States of America |
| GHG | | Greenhouse Gas |
| LFCR | | Lost Fixed Cost Recovery |
| LIBOR | | London Interbank Offered Rate |
| LOC | | Letter(s) of Credit |
| NERC | | North American Electric Reliability Corporation |
| NOPR | | Notice of Proposed Rulemaking |
| OATT | | Open Access Transmission Tariff |
| PBI | | Performance Based Incentives |
| PPA | | Power Purchase Agreement |
| PPFAC | | Purchased Power and Fuel Adjustment Clause |
| PSU | | Performance-Based Share Units |
|
| | |
| PURPA | | Public Utility Regulatory Policies Act |
| PV | | Photovoltaic |
| RCRA | | Resource Conservation and Recovery Act |
| REC | | Renewable Energy Credit |
| Regional Haze | | Regional Haze Regulation promulgated by the EPA to improve visibility at national parks and wilderness areas |
| RES | | Renewable Energy Standard |
| Retail Rates | | Rates designed to allow a regulated utility recovery of its costs of providing services and an opportunity to earn a reasonable return on its investment |
| RICE | | Reciprocating Internal Combustion Engine |
| RMC | | Risk Management Committee |
| RSU | | Restricted Share Units |
| SERP | | Supplemental Executive Retirement Plan |
| TCA | | Transmission Cost Adjustor |
| TCJA | | Tax Cuts and Jobs Act |
| TEAM | | Tax Expense Adjustor Mechanism |
| Tolling PPA | | A 20-year tolling PPA that TEP entered into in 2017 with SRP to purchase and receive all 550 MW of capacity, power, and ancillary services from Gila River Unit 2, which included a three-year option to purchase the unit |
| VEBA | | Voluntary Employee Beneficiary Association |
| VIE | | Variable Interest Entity |
ENTITIES AND GENERATING STATIONS |
| | |
| Fortis | | Fortis Inc., a corporation incorporated under the Corporations Act of Newfoundland and Labrador, Canada, whose principal executive offices are located at Fortis Place, Suite 1100, 5 Springdale Street, St. John's, NL A1E 0E4 |
| FortisUS | | Fortis intermediate holding company |
| Four Corners | | Four Corners Generating Station |
GAAP | | Generally Accepted Accounting Principles in the United States of America |
| Gila River | | Gila River Generating Station |
GWh | | Gigawatt-hour(s) |
kV | | Kilo-volt(s) |
kWh | | Kilowatt-hour(s) |
LFCR | | Lost Fixed Cost Recovery Mechanism |
LOC | | Letter(s) of Credit |
| Luna | | Luna Generating Station |
MMBtu | | Million British thermal units |
MW | | Megawatt(s) |
MWh | | Megawatt-hour(s) |
| Navajo | | Navajo Generating Station |
NBVOso Grande | | Net Book ValueA 250 MW nominal capacity wind-powered electric generation facility, which is under construction in southeastern New Mexico |
| PNM | | Public Service Company of New Mexico |
PPA | | Power Purchase Agreement |
PPFAC | | Purchased Power and Fuel Adjustment Clause |
PV | | Photovoltaic |
REC | | Renewable Energy Credit |
Regional Haze Rules | | Rules promulgated by the EPA to improve visibility at national parks and wilderness areas |
RES | | Renewable Energy Standard |
Retail Rates | | Rates designed to allow a regulated utility recovery of its cost of providing services and an opportunity to earn a reasonable return on its investment |
RICE | | Reciprocating Internal Combustion Engine |
| San Juan | | San Juan Generating Station |
SCR | | Selective Catalytic Reduction |
| SES | | Southwest Energy Solutions, Inc. |
| SJCC | | San Juan Coal Company |
SNCR | | Selective Non-Catalytic Reduction |
|
| | |
| Springerville | | Springerville Generating Station |
| Springerville Common Facilities | | Portion of the facilities at Springerville used in common with Springerville Unit 1 and Unit 2 |
| SRP | | Salt River Project Agricultural Improvement and Power District |
| Sundt | | H. Wilson Sundt Generating Station |
TCJA | | On December 22, 2017, the Tax Cuts and Jobs Act was signed into law enacting significant changes to the Internal Revenue Code including a reduction in the U.S. federal corporate income tax rate from 35% to 21% effective for tax years beginning after 2017 |
| TEP | | Tucson Electric Power Company, the principal subsidiary of UNS Energy Corporation |
Third-Party Owners | | Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-trustee under a separate trust agreement with each of Alterna Springerville LLC (Alterna) and LDVF1 TEP LLC (LDVF1) (Alterna and LDVF1, together with the Owner Trustees and Co-trustees, the Third-Party Owners) |
TSA | | Transmission Service Agreement |
| Tri-State | | Tri-State Generation and Transmission Association, Inc. |
UESUASTP | | UniSource Energy Services, Inc., a wholly-owned subsidiaryUniversity of UNS Energy Corporation,Arizona Science and the intermediate holding company established to own the operating companies UNS Electric, Inc. and UNS Gas, Inc.Technology Park |
| UNS Electric | | UNS Electric, Inc., an indirect wholly-owned subsidiary of UNS Energy Corporation |
| UNS Energy | | UNS Energy Corporation, the parent company of TEP, whose principal executive offices are located at 88 East Broadway Boulevard, Tucson, Arizona 85701 |
|
| | |
| UNS Energy Affiliates | | Affiliated subsidiaries of UNS Energy Corporation including UniSource Energy Services, Inc., UNS Electric, Inc., UNS Gas, Inc., and Southwest Energy Solutions, Inc. |
| UNS Gas | | UNS Gas, Inc., an indirect wholly-owned subsidiary of UNS Energy Corporation |
|
| | |
| AC | | Alternating Current |
| BBtu | | Billion British thermal unit(s) |
| GWh | | Gigawatt-hour(s) |
| kWh | | Kilowatt-hour(s) |
| MMBtu | | Million Metric British thermal units |
| MW | | Megawatt(s) |
| MWh | | Megawatt-hour(s) |
FORWARD-LOOKING INFORMATION
This Annual Report on Form 10-K contains forward-looking statements as defined by the Private Securities Litigation Reform Act of 1995. Tucson Electric Power Company (TEPTEP, or the Company)Company, is including the following cautionary statements to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by TEP in this Annual Report on Form 10-K. Forward-looking statements include statements concerning plans, objectives, goals, strategies, future events, future economic conditions, future operational or financial performance and underlying assumptions, and other statements that are not statements of historical facts. Forward-looking statements may be identified by the use of words such as anticipates, believes, estimates, expects, intends, may, plans, predicts, potential, projects, would, and similar expressions. From time to time, we may publish or otherwise make available forward-looking statements of this nature. All such forward-looking statements, whether written or oral, and whether made by or on behalf of TEP, are expressly qualified by these cautionary statements and any other cautionary statements which may accompany the forward-looking statements. In addition, TEP disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date of this report, except as may otherwise be required by the federal securities laws.
Forward-looking statements involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed therein. We express our estimates, expectations, beliefs, and projections in good faith and believe them to have a reasonable basis. However, we make no assurances that management’s estimates, expectations, beliefs, or projections will be achieved or accomplished. We have identified the following important factors that could cause actual results to differ materially from those discussed in our forward-looking statements. These may be in addition to other factors and matters discussed in: Part I, Item 1A. Risk Factors; Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations;Operations; and other parts of this report. These factors include: voter initiatives and state and federal regulatory and legislative decisions and actions, including changes in tax and energy policies and any change in the structure of utility service in Arizona resulting from the ACC's examination of the state's energy policies; changes in, and compliance with, environmental laws and regulatory decisions and policies that could increase operating and capital costs, reduce generatinggeneration facility output or accelerate generation facility retirements; the outcome of the general rate case filed with the ACC in April 2019; the outcome of the proposal filed with the FERC in May 2019 requesting revisions to TEP's OATT; regional economic and market conditions whichthat could affect customer growth and energy usage; changes in energy consumption by retail customers; weather variations affecting energy usage; our forecasts of peak demand and whether existing generation capacity and PPAs are sufficient to meet the expected demand plus reserve margin requirements; the cost of debt and equity capital and access to capital markets and bank markets;markets, which may affect our ability to raise additional capital and use the proceeds from any capital that we do raise as originally intended; the performance of the stock market and a changing interest rate environment, which affect the value of our pension and other postretirement benefit plan assets and the related contribution requirements and expenses; the potential inability to make additions to our existing high voltage transmission system; unexpected increases in operations and maintenance expense; resolution of pending litigation matters; changes in accounting standards; changes in our critical accounting policies and estimates; the ongoing impact of mandated energy efficiency and distributed generationDG initiatives; changes to long-term contracts; the cost of fuel and power supplies; the ability to obtain coal from our suppliers; cyber-attacks, data breaches, or other challenges to our information security, including our operations and technology systems; the performance of TEP's generation facilities; the development of our wind powered electric generation facility in southeastern New Mexico; participation in the EIM; and the impact of the Tax Cuts and Jobs ActTCJA on our financial condition and results of operations, including the assumptions we mademake relating thereto.
PART I
ITEM 1. BUSINESS
OVERVIEW OF BUSINESS
General
TEP and its predecessor companies have served the greater Tucson metropolitan area for 125127 years. TEP was incorporated in the State of Arizona in 1963. TEP is a regulated electric utility company serving approximately 422,000429,000 retail customers. TEP’s service territory covers 1,155 square miles and includes a population of over one million people in Pima County, as well as parts of Cochise County. TEP's principal business operations include generating, transmitting, and distributing electricity to its retail customers. In addition to retail sales, TEP sells electricity, transmission, and ancillary services to other utilities, municipalities, and energy marketing companies on a wholesale basis. TEP is subject to comprehensive state and federal regulation. The regulated electric utility operation is TEP's only segment.
TEP is a wholly owned subsidiary of UNS Energy, Corporation (UNS Energy), a utility services holding company. In 2014, UNS Energy was acquired by Fortis Inc. (Fortis) and becameis an indirect wholly owned subsidiary of Fortis which is a leader in the North American electric and gas utility business.
Regulated Utility Operations
TEP delivers electricity to retail customers in southern Arizona. TEP owns or has contracts for coal, natural gas, wind, and solar generation resources to provide electricity. This electricity, together with electricity purchased onin the wholesale market, is delivered over transmission lines which are part of the Western Interconnection, a regional grid in the United States. The electricity is then transformed to lower voltages and delivered to customers through TEP's distribution system.
TEP operates under a certificate of public convenience and necessity as regulated by the Arizona Corporation Commission (ACC),ACC, under which TEP is obligated to provide electricity service to customers within its service territory. The ACC establishes rates that are designed to allow a regulated utility recovery of its cost of providing services and an opportunity to earn a reasonable return on its investment (Retail Rates).
Customers
Electricity sold to retail and wholesale customers by class of customer and the average number of retail customers over the last three years were as follows: | | | (sales in GWh) | 2017 | | 2016 | | 2015 | 2019 | | 2018 | | 2017 | | 2016 | | 2015 |
| Electric Sales | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Residential | 3,786 | | 28 | % | | 3,724 |
| | 29 | % | | 3,724 |
| | 28 | % | 3,698 | | 22 | % | | 3,766 |
| | 24 | % | | 3,786 |
| | 29 | % | | 3,724 |
| | 29 | % | | 3,724 |
| | 28 | % |
| Commercial | 2,192 | | 17 | % | | 2,139 |
| | 17 | % | | 2,124 |
| | 15 | % | 2,077 | | 13 | % | | 2,136 |
| | 14 | % | | 2,192 |
| | 17 | % | | 2,139 |
| | 17 | % | | 2,124 |
| | 15 | % |
| Industrial, non-Mining | 1,939 | | 15 | % | | 2,006 |
| | 16 | % | | 2,063 |
| | 15 | % | 1,896 | | 11 | % | | 1,949 |
| | 12 | % | | 1,939 |
| | 15 | % | | 2,006 |
| | 16 | % | | 2,063 |
| | 15 | % |
| Industrial, Mining | 991 | | 8 | % | | 997 |
| | 8 | % | | 1,109 |
| | 8 | % | 1,057 | | 6 | % | | 1,033 |
| | 7 | % | | 991 |
| | 8 | % | | 997 |
| | 8 | % | | 1,109 |
| | 8 | % |
| Other | 18 | | — | % | | 30 |
| | — | % | | 33 |
| | — | % | 16 | | — | % | | 16 |
| | — | % | | 18 |
| | — | % | | 30 |
| | — | % | | 33 |
| | — | % |
| Total Retail Sales by Customer Class | 8,926 | | 68 | % | | 8,896 |
| | 70 | % | | 9,053 |
| | 66 | % | 8,744 | | 53 | % | | 8,900 |
| | 57 | % | | 8,926 |
| | 68 | % | | 8,896 |
| | 70 | % | | 9,053 |
| | 66 | % |
| Wholesale Sales, Long-Term | 587 | | 4 | % | | 463 |
| | 4 | % | | 750 |
| | 5 | % | 490 | | 3 | % | | 424 |
| | 3 | % | | 587 |
| | 4 | % | | 463 |
| | 4 | % | | 750 |
| | 5 | % |
Wholesale Sales, Short-Term | 3,630 | | 28 | % | | 3,308 |
| | 26 | % | | 3,928 |
| | 29 | % | 7,257 | | 44 | % | | 6,279 |
| | 40 | % | | 3,630 |
| | 28 | % | | 3,308 |
| | 26 | % | | 3,928 |
| | 29 | % |
| Total Electric Sales | 13,143 | | 100 | % | | 12,667 |
| | 100 | % | | 13,731 |
| | 100 | % | 16,491 | | 100 | % | | 15,603 |
| | 100 | % | | 13,143 |
| | 100 | % | | 12,667 |
| | 100 | % | | 13,731 |
| | 100 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Average Number of Retail Customers | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Residential | 381,399 | | 90 | % | | 378,991 |
| | 90 | % | | 376,439 |
| �� | 90 | % | 387,409 | | 90 | % | | 384,021 |
| | 90 | % | | 381,399 |
| | 90 | % | | 378,991 |
| | 90 | % | | 376,439 |
| | 90 | % |
| Commercial | 38,564 | | 9 | % | | 38,403 |
| | 9 | % | | 38,253 |
| | 9 | % | 38,838 | | 9 | % | | 38,642 |
| | 9 | % | | 38,564 |
| | 9 | % | | 38,403 |
| | 9 | % | | 38,253 |
| | 9 | % |
| Industrial, non-Mining | 520 | | — | % | | 580 |
| | — | % | | 588 |
| | — | % | 503 | | — | % | | 504 |
| | — | % | | 520 |
| | — | % | | 580 |
| | — | % | | 588 |
| | — | % |
| Industrial, Mining | 4 | | — | % | | 4 |
| | — | % | | 4 |
| | — | % | 4 | | — | % | | 4 |
| | — | % | | 4 |
| | — | % | | 4 |
| | — | % | | 4 |
| | — | % |
| Other | 1,879 | | 1 | % | | 1,866 |
| | 1 | % | | 1,857 |
| | 1 | % | 1,872 | | 1 | % | | 1,873 |
| | 1 | % | | 1,879 |
| | 1 | % | | 1,866 |
| | 1 | % | | 1,857 |
| | 1 | % |
| Total Retail Customers | 422,366 | | 100 | % | | 419,844 |
| | 100 | % | | 417,141 |
| | 100 | % | 428,626 | | 100 | % | | 425,044 |
| | 100 | % | | 422,366 |
| | 100 | % | | 419,844 |
| | 100 | % | | 417,141 |
| | 100 | % |
| |
(1) | Short-term wholesale sales increased due to the increase in generation capacity related to Gila River Unit 2. |
Retail Customers
TEP provides electric utility service to a diverse group of residential, commercial, industrial, and public sector customers. Major industries served include copper mining, cement manufacturing, defense, healthcare, education, military bases, and other governmental entities. TEP’s retail sales are influenced by several factors including economic conditions, seasonal weather patterns, Demand Side Management (DSM)DSM initiatives and the increasing use of energy-efficient products, and customer-sited Distributed Generation (DG).DG.
Local, regional, and national economic factors impact the growth in the number of customers in TEP’s service territory. In each of the past five years, TEP’s average number of retail customers increased by less than 1%. TEP expects the number of retail customers to increase at a rate of approximately 1% in 20182020 based on the estimated population growth in its service territory.
TEP’s retail sales volume in 20172019 was 8,926 gigawatt-hours (GWh),8,744 GWh, which is a decrease of 3.8%3% from 20132015 levels. During the past five years, mining load reductions and state requirements to reduce retail sales throughpromote energy efficiency and DG have resulted in lower sales volumes.
TEP’s mining customers make up 11% of total retail sales. TEP’s GWh sales to mining customers depend on a variety of factors including commodity prices, electricity prices, and the mines’ development of self-generating resources. TEP’s GWh sales to mining customers decreased by 8% from 2013 levels as a result of the decline in commodity prices requiring the mines to curtail production starting in 2016. TEP cannot predict future commodity prices or the impact they will have on mining production.
Wholesale Customers
TEP’s utility operations include the wholesale marketing of electricity to other utilities and power marketers. Wholesale sales transactions are made on both a firm and interruptible basis. A firm contract requires TEP to supply power on demand (except under limited emergency circumstances), while an interruptible contract allows TEP to stop supplying power under defined conditions.
Generally, TEP commits to future sales based on expected generation capability, forward prices, and generation costs using a diversified portfolio approach to provide a balance between long-term, mid-term, and spot energypower sales. TEP’s wholesale sales consist primarily of two types:
Long-Term Wholesale Sales
Contracts for long-term wholesale sales cover periods of one year or greater. TEP typically uses its own generation to serve the requirements of its long-term wholesale customers.
TEP’s long-term wholesale contract with Shell Energy North America expired in 2017. TEP's primary long-term wholesale sale contracts are presented in the table below: |
| | |
| Counterparty | | Contracts Expire |
Counterparty | | December 31, |
| Navajo Tribal Utility Authority | | 2022 |
| TRICO Electric Cooperative | | 2024 |
| Navopache Electric Cooperative | | 2041 |
Short-Term Wholesale Sales
Certain contracts for short-term wholesale sales cover periods of less than one year and obligate TEP to sell capacity or power at a fixed price. TEP also engages in short-term sales by selling power in the daily or hourly markets at fluctuating spot market prices and making other non-firm power sales. The majority of our revenues from short-term wholesale sales are passed through to TEP’s retail customers offsetting fuel and purchased power costs. TEP uses short-term wholesale sales as part of its hedging strategy to reduce customer exposure to fluctuating power prices.
Energy Imbalance Market
In May 2019, TEP signed an agreement with the California Independent System Operator indicating its intent to begin participating in the Energy Imbalance Market (EIM) by spring of 2022. Participation in the EIM is voluntary and available to all balancing authorities in the western United States. In order to participate in the EIM, TEP must demonstrate resource adequacy through a combination of owned or contracted resources. TEP's participation in the EIM is expected to: (i) reduce the costs to serve customers through more efficient dispatch of a larger and more diverse pool of resources; (ii) allow for more effective integration of renewables; and (iii) enhance reliability through improved system utilization and responsiveness.
Competition
Retail Customers
TEP is the primary electric service provider to retail customers within its service territory and operates under a certificate of public convenience and necessity as regulated by the ACC.
In 2018, the ACC opened a docket to evaluate several energy policies including retail competition for generation services. In 2019, the ACC staff prepared a draft of retail electric competition rules and workshops have been held on the subject. Such
rules have not been officially proposed and no changes have been made. The adoption of new policies or rules would be subject to rulemaking proceedings at the ACC. TEP cannot predict what additional steps, if any, the ACC may take to further evaluate retail competition in this docket.
Wholesale Customers
The Federal Energy Regulatory Commission (FERC) regulates rates for wholesale power sales and transmission services. TEP engages in long-term wholesale sales to optimize its generation resources. As a result of its wholesale power activity, TEP competes with other utilities, power marketers, and independent power producers in the wholesale markets.
Generation Facilities
As of December 31, 2017,2019, TEP owned 2,531 megawatts (MW)had 2,841 MW of nominal generation capacity, as set forth in the following table. Nominal capacityrating is based on current unit design basis net output, and measured in alternating current (AC) except for the solar generation which is measured in direct current (DC).AC. | | | | | Unit | | Date | | Resource | | Capacity | | Operating | | TEP’s Share | | Unit | | Date | | Capacity | | Operating | | TEP’s Share |
| Generation Source | | No. | | Location | | In Service | | Type | | MW | | Agent | | % | | MW | | No. | | Location | | In Service | | (MW) | | Agent | | % | | (MW) |
| Springerville | | 1 | | Springerville, AZ | | 1985 | | Coal | | 387 | | TEP | | 100 | | 387 |
| |
| Coal | | | |
Springerville (1) | | | 1 | | Springerville, AZ | | 1985 | | 387 | | TEP | | 100 | | 387 |
|
Springerville (1) | | 2 | | Springerville, AZ | | 1990 | | Coal | | 406 | | TEP | | 100 | | 406 |
| | 2 | | Springerville, AZ | | 1990 | | 406 | | TEP | | 100 | | 406 |
|
| San Juan | | 1 | | Farmington, NM | | 1976 | | Coal | | 340 | | PNM | | 50.0 | | 170 |
| | 1 | | Farmington, NM | | 1976 | | 340 | | PNM | | 50.0 | | 170 |
|
Navajo (2) | | 1 | | Page, AZ | | 1974 | | Coal | | 750 | | SRP | | 7.5 | | 56 |
| |
Navajo (2) | | 2 | | Page, AZ | | 1975 | | Coal | | 750 | | SRP | | 7.5 | | 56 |
| |
Navajo (2) | | 3 | | Page, AZ | | 1976 | | Coal | | 750 | | SRP | | 7.5 | | 56 |
| |
| Four Corners | | 4 | | Farmington, NM | | 1969 | | Coal | | 785 | | APS | | 7.0 | | 55 |
| | 4 | | Farmington, NM | | 1969 | | 785 | | APS | | 7.0 | | 55 |
|
| Four Corners | | 5 | | Farmington, NM | | 1970 | | Coal | | 785 | | APS | | 7.0 | | 55 |
| | 5 | | Farmington, NM | | 1970 | | 785 | | APS | | 7.0 | | 55 |
|
| Natural Gas | | | |
Gila River (2) | | | 2 | | Gila Bend, AZ | | 2003 | | 550 | | SRP | | 100 | | 550 |
|
| Gila River | | 3 | | Gila Bend, AZ | | 2003 | | Gas | | 550 | | Ethos Energy | | 75.0 | | 413 |
| | 3 | | Gila Bend, AZ | | 2003 | | 550 | | SRP | | 75.0 | | 413 |
|
| Luna | | 1 | | Deming, NM | | 2006 | | Gas | | 555 | | PNM | | 33.3 | | 185 |
| | 1 | | Deming, NM | | 2006 | | 555 | | PNM | | 33.3 | | 185 |
|
Sundt (3) | | 1 | | Tucson, AZ | | 1958 | | Gas/Oil | | 81 | | TEP | | 100 | | 81 |
| | 3 | | Tucson, AZ | | 1962 | | 104 | | TEP | | 100 | | 104 |
|
Sundt (3) | | 2 | | Tucson, AZ | | 1960 | | Gas/Oil | | 81 | | TEP | | 100 | | 81 |
| | 4 | | Tucson, AZ | | 1967 | | 156 | | TEP | | 100 | | 156 |
|
| Sundt | | 3 | | Tucson, AZ | | 1962 | | Gas | | 104 | | TEP | | 100 | | 104 |
| |
| Sundt | | 4 | | Tucson, AZ | | 1967 | | Gas | | 156 | | TEP | | 100 | | 156 |
| |
| Sundt Internal Combustion Turbines | | Tucson, AZ | | 1972-1973 | | Gas/Oil | | 50 | | TEP | | 100 | | 50 |
| | Tucson, AZ | | 1972-1973 | | 50 | | TEP | | 100 | | 50 |
|
| Sundt Reciprocating Internal Combustion Engine | | | 6-10 | | Tucson, AZ | | 2019 | | 94 | | TEP | | 100 | | 94 |
|
| DeMoss Petrie | | Tucson, AZ | | 2001 | | Gas | | 75 | | TEP | | 100 | | 75 |
| | Tucson, AZ | | 2001 | | 75 | | TEP | | 100 | | 75 |
|
| North Loop | | Tucson, AZ | | 2001 | | Gas | | 94 | | TEP | | 100 | | 94 |
| | Tucson, AZ | | 2001 | | 94 | | TEP | | 100 | | 94 |
|
| Springerville | | Springerville, AZ | | 2002-2014 | | Solar | | 16 | | TEP | | 100 | | 16 |
| |
| Tucson | | Tucson, AZ | | 2010-2014 | | Solar | | 13 | | TEP | | 100 | | 13 |
| |
| Ft. Huachuca | | Ft. Huachuca, AZ | | 2014-2017 | | Solar | | 22 | | TEP | | 100 | | 22 |
| |
Total TEP Capacity (4) | | 2,531 |
| |
| Solar | | | |
| Utility-Scale Renewables | | | Various | | 2002-2017 | | 47 | | TEP | | 100 | | 47 |
|
Total Capacity (3) | | | 2,841 |
|
| |
(1) | Springerville Generating Station (Springerville) Unit 2 is owned by San Carlos Resources, Inc., a wholly-owned subsidiary of TEP. |
| |
(2) | TEP along with the other participants at the Navajo Generating Facility (Navajo), plan to discontinue operations of Navajo Units 1-3 by the end ofpurchased Gila River Unit 2 in December 2019. |
| |
(3) | TEP plans to discontinue operations of Sundt Units 1 & 2 by the end of 2020. |
| |
(4)
| On December 20, 2017, San Juan Generating Station (San Juan) Unit 2In November 2019, Navajo was removed from service. TEP's 50%TEP held a 7.5% share of San Juan Unit 2'sin Navajo Units 1, 2, and 3 with a total nominal capacity was 170of 168 MW. In December 2019, Sundt Units 1 and 2 were removed from service. Sundt Units 1 and 2 had a total nominal capacity of 162 MW. |
Springerville Generating Station
TEP's other interests in Springerville include: (i) undivided interests in certain common facilities at Springerville (Springerville Common Facilities) made up of 67.8% of ownership interest and 32.2% of leased interest, that includes assets such as, but not limited to: administration building, roads, and well fields used to serve all four units at Springerville that cannot be proportioned to each unit; and (ii) an 82.95% ownership interest in the Springerville Coal Handling Facilities.
Springerville Common Facilities Leases
As of December 31, 2017, TEP holds two leveraged lease arrangements related to a 32.2% undivided interest in Springerville Common Facilities. The lease arrangements are scheduled to expire in January 2021 and have fair market value renewal options as well as fixed-price purchase options totaling $68 million.
See Note 6 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding the capital leases.
Springerville Units 3 and 4
Springerville Units 3 and 4 are each approximately 400 MW coal-fired generation facilities that are operated but not owned by TEP. These facilities are located at the same site as Springerville Units 1 and 2. TheTri-State, the lessee of Springerville Unit 3, compensates TEP for operating the facilities and pays an allocated portion of the fixed costs related to the Springerville Common Facilities and Springerville Coal Handling Facilities. TheSRP, the owner of Springerville Unit 4, owns 17.05% of the Springerville Coal Handling Facilities and pays TEP for a portion of the fixed costs allocated for the common facilities.
Renewable Energy Resources
The ACC’s Renewable Energy Standard (RES)RES requires Arizona regulated utilities to increase their use of renewable energy each year until it represents at least 15% of their total annual retail energy requirements by 2025, with DG accounting for 30% of the annual renewable energy
requirement. Arizona utilities must file an annual RES implementation plan for review and approval by the ACC. TEP plans to meet these requirements through a combination of utility-owned resources, Power Purchase Agreements (PPAs),PPAs, and customer-sited DG.
In 2019, the percentage of retail kWh sales attributable to the RES was approximately 16%, exceeding the 2019 requirement of 9%. The ACC approved a waiver of the 2019 DG requirement.
See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K and Rates and Regulations below for additional information regarding RES.
Owned Utility-Scale Renewable Resources
As of December 31, 2017,2019, TEP owned 5147 MW of photovoltaic (PV)PV solar generation capacity, measured in DC.AC. The solarfollowing table presents TEP's owned utility-scale renewable generation facilities are located on properties held under land easements and leases.resources: |
| | | | | | | | | | |
| Generation Source | | Location | | Date/Projected Date in Service | | In Service Capacity (MW) | | Under Development Capacity (MW) |
| Solar | | | | | | | | |
Fort Huachuca Phase I & II (1) | | Sierra Vista, AZ | | 2014-2017 | | 18 |
| | |
| Springerville | | Springerville, AZ | | 2004-2014 | | 14 |
| | |
UASTP Phase I & II (2) | | Tucson, AZ | | 2010-2011 | | 6 |
| | |
| Sundt Areva Solar Thermal | | Tucson, AZ | | 2014 | | 5 |
| | |
Solon Prairie Fire (2) | | Tucson, AZ | | 2012 | | 4 |
| | |
| Raptor Ridge | | Tucson, AZ | | 2021 | | | | 10 |
|
| Wind | | | | | | | | |
| Oso Grande Wind Project | | Chaves County, NM | | 2020 | | | | 250 |
|
| Total Capacity | | | | | | 47 |
| | 260 |
|
| |
(1) | TEP has a 30-year easement agreement to facilitate operations on behalf of the Department of the Army. |
| |
(2) | The UASTP I & II and Solon Prairie Fire are located on properties held under land easements and leases. |
Renewable Power Purchase Agreements
As of December 31, 2017,2019, TEP had renewable PPAs for 198156 MW measured in DC from solar resources and 80 MW measured in AC from wind resources and 4 MW measuredas presented in AC associated with the purchase of landfill gas.table below. The solar PPAs contain options that allow TEP to purchase all or part of the related project at a future date. The following table's capacity is measured in AC. |
| | | | | | | | | | |
| Generation Source | | Location | | Date/Projected Date in Service | | In Service Capacity (MW) | | Under Development Capacity (MW) |
| Solar | | | | | | | | |
| Red Horse | | Willcox, AZ | | 2015 | | 41 |
| | |
| Avalon I | | Sahuarita, AZ | �� | 2014 | | 29 |
| | |
| Avra Valley | | Marana, AZ | | 2012 | | 25 |
| | |
| Picture Rocks | | Marana, AZ | | 2012 | | 20 |
| | |
| Avalon II | | Sahuarita, AZ | | 2016 | | 16 |
| | |
| Valencia | | Tucson, AZ | | 2013 | | 10 |
| | |
| E.On Tech Park | | Tucson, AZ | | 2012 | | 5 |
| | |
| Gato Montes | | Tucson, AZ | | 2012 | | 5 |
| | |
| Small PPAs (<5MW) | | Various | | Various | | 5 |
| | |
Wilmot Solar (1) | | Sahuarita, AZ | | 2020 | | | | 100 |
|
| Wind | | | | | | | | |
| Macho Springs | | Deming, NM | | 2011 | | 50 |
| | |
| Red Horse Wind | | Willcox, AZ | | 2015 | | 30 |
| | |
| Borderlands Wind | | Catron County, NM | | 2021 | | | | 99 |
|
| Total Capacity | | | | | | 236 |
| | 199 |
|
| |
(1) | Wilmot Solar will be accompanied by 30 MW of energy storage. |
ACC PURPA Ruling
On December 17, 2019, the ACC issued a decision related to contract terms for qualifying facilities under PURPA. Congress enacted PURPA in 1978 in response to a national energy crisis. The FERC prescribes rules for the implementation of PURPA and state regulatory agencies implement PURPA. PURPA requires, among other things, that electric utilities enter into contracts to purchase power from facilities that qualify under PURPA at a price equivalent to the utility's avoided cost. The ACC's 2019 decision requires, among other things, that TEP's contracts to purchase power from qualifying facilities with renewable nameplate capacity over 100 kW include certain terms and conditions, including a minimum 18-year contract length and pricing based on TEP's long-term avoided cost. The Company cannot predict the impact of the ACC's ruling at this time.
Purchased Power
TEP purchases power from other utilities and power marketers. TEP may enter into contracts to purchase: (i) power under long-term contracts to serve retail load and long-term wholesale contracts; (ii) capacity or power during periods of planned outages or for peak summer load conditions; and (iii) power for resale to certain wholesale customers under load and resource management agreements. See Note 79 of Notes to Consolidated Financial Statements related to the commitment amount of purchased power in Part II, Item 8 of this Form 10-K.10-K related to purchased power commitments.
TEP typically uses its generation, supplemented by purchased power, to meet the summer peak demands of its retail customers. Due to its increasing natural gas and purchased power usage, TEP hedges a portion of its total energy price exposure with forward priced contracts. Certain of these contracts are at a fixed price per megawatt-hour (MWh)MWh and others are indexed to natural gas prices. TEP also purchases power in the daily and hourlymarkets markets: (i) to meet higher than anticipated demands, to coverdemands; (ii) during periods of generation outages,outages; or (iii) when doing so is more economical than generating its own power.
TEP is a member of a regional reserve-sharing organization and has reliability and power-sharing relationships with other utilities. These relationships allow TEP to call upon other utilities during emergencies, such as generation facility outages and system disturbances, and reducewhich reduces the amount of reserves TEP is required to carry.
Peak Demand and Future Resources
| | | (in MW) | 2017 | | 2016 | | 2015 | | 2014 | | 2013 | 2019 | | 2018 | | 2017 | | 2016 | | 2015 |
| Retail Customers | 2,415 |
| | 2,278 |
| | 2,222 |
| | 2,218 |
| | 2,230 |
| 2,367 |
| | 2,413 |
| | 2,415 |
| | 2,278 |
| | 2,222 |
|
In 2017,2019, TEP's generation and purchased resources were sufficient to meet total retail and long-term wholesale peak demand, while maintaining a reserve margin in compliance with reliability criteria set forth by the Western Electricity Coordinating Council, a regional council of North American Reliability Corporation (NERC).entity with delegated authority from NERC.
Peak demand occurs during the summer months due to the cooling requirements of retail customers in TEP’s service territory. Retail peak demand varies from year-to-year due to weather, energy conservation, DG, economic conditions, and other factors. Retail peak demand in 2019, 2018, and 2017 increased 6% compared towas higher than in 2016 and 2015 primarily due to unseasonably hot weather.warmer than normal summer temperatures.
Forecasted retail peak demand for 20182020 is 2,2702,325 MW compared with actual peak demand of 2,4152,367 MW in 2017.2019. TEP’s 20182020 estimated retail peak demand is based on weather patterns observed over a 10-year period and other factors, including estimates of customer usage. TEP believes that existing generation capacity and PPAs are sufficient to meet the expected demand and reserve margin requirements in 2018.2020.
Future Resources
As of December 31, 2017,2019, approximately 49%38% of TEP's generation capacity iswas from coal-fired generation. TEP is executing strategies and evaluating additional steps to reduce its dependency on coal-fired generation while still meeting its peak load requirements and maintaining affordable Retail Rates. TEP's five-year capital expenditure forecast includes investments related to Reciprocating Internal Combustion Engines (RICE) at H. Wilson Sundt Generating Station (Sundt) and the planned purchase of Gila River Generating Station (Gila River) Unit 2. These anticipated investments will provide replacement capacity for the planned early retirements of coal-fired and other generation resources.
See Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations, Factors Affecting Results of Operations of this Form 10-K for additional information regarding TEP's generation resources planned retirements and additions.
Fuel Supply
A summary of Fuel and Purchased Power resource information is provided below: | | | | Average Cost (cents per kWh) | | Percentage of Total kWh Resources | Average Cost (cents per kWh) | | Percentage of Total kWh Resources |
| | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 | 2019 | | 2018 | | 2017 | | 2019 | | 2018 | | 2017 |
| Coal | 2.41 |
| | 2.30 |
| | 2.44 |
| | 54 | % | | 62 | % | | 60 | % | 2.46 |
| | 2.44 |
| | 2.41 |
| | 41 | % | | 44 | % | | 54 | % |
| Gas | 3.06 |
| | 2.84 |
| | 3.35 |
| | 23 | % | | 25 | % | | 19 | % | |
| Natural Gas | | 2.33 |
| | 2.54 |
| | 3.06 |
| | 45 | % | | 42 | % | | 23 | % |
| Purchased Power, Non-Renewable | 3.78 |
| | 3.43 |
| | 3.04 |
| | 18 | % | | 8 | % | | 18 | % | 4.09 |
| | 4.32 |
| | 3.78 |
| | 10 | % | | 10 | % | | 18 | % |
| Purchased Power, Renewable | 6.67 |
| | 7.00 |
| | 9.82 |
| | 5 | % | | 5 | % | | 3 | % | 9.43 |
| | 9.41 |
| | 9.49 |
| | 4 | % | | 4 | % | | 5 | % |
| | | | | | | | 100 | % | | 100 | % | | 100 | % | | | | | | | 100 | % | | 100 | % | | 100 | % |
Coal Supply
Coal
The coal used for electric generation is low-sulfur, bituminous or sub-bituminous coal sourced from mines in Arizona and New Mexico. The table below provides information on the existing coal contracts that supply our generation stations. The average cost of coal per million metric British thermal unit (MMBtu),MMBtu, including transportation, was $2.37 in 2019, $2.33 in 2018, and $2.29 in 2017, $2.21 in 2016, and $2.34 in 2015.2017. | | | Station | | Coal Supplier | | 2017 Coal Consumption (tons in 000s) | | Contract Expiration | | Average Sulfur Content | | Coal Obtained From | | Coal Supplier | | 2019 Coal Consumption (tons in 000s) | | Contract Expiration Date | | Average Sulfur Content | | Coal Obtained From |
Springerville | | Peabody CoalSales | | 2,289 | | 2020 | | 1.0% | | Lee Ranch Mine/El Segundo Mine | | Peabody CoalSales | | 2,693 | | 2020 | | 1.0% | | Lee Ranch Mine/El Segundo Mine |
| Four Corners | | NTEC | | 285 | | 2031 | | 0.7% | | Navajo Mine | | NTEC | | 315 | | 2031 | | 0.7% | | Navajo Mine |
San Juan (1) | | San Juan Coal Co. | | 1,181 | | 2022 | | 0.8% | | San Juan Mine | | San Juan Coal Co. | | 588 | | 2022 | | 0.8% | | San Juan Mine |
| Navajo | | Peabody CoalSales | | 441 | | 2019 | | 0.6% | | Kayenta Mine | |
| |
(1) | ReflectsAn extension to the fuel consumption of San Juan Units 1 and 2. In December 2017, San Juan Unit 2 was removed from service.coal supply agreement is currently under negotiation. |
Coal-Fired Generation Facilities Operated by TEP
The coal supplies for Springerville Units 1 and 2 are transported approximately 200 miles by railroad from northwestern New Mexico. TEP expects coal reserves from the supplying mines to be sufficient to supplyfulfill the estimated requirements for each of the Springerville Units 1 and 2 for theirunits' estimated remaining lives.life.
Coal-Fired Generation Facilities Operated by Others
TEP also participates in jointly-owned coal-fired generation facilities at Four Corners Generating Station (Four Corners), the Navajo Generating Station (Navajo), and San Juan. Four Corners, which is operated by Arizona Public Service Company (APS),APS, and San Juan, which is operated by Public Service Company of New Mexico (PNM),PNM, are mine-mouth generation facilities located adjacent to the coal reserves. Navajo, which is operated by Salt River Project Agricultural Improvement and Power District (SRP), obtains its coal supply from the nearby Kayenta coal mine and receives deliveries on a dedicated electric rail delivery system. TEP expects coal reserves available to these threetwo jointly-owned generation facilities to be sufficient for the remaining lives of the stations.
Natural Gas Supply
TEP uses generation from its facilities fueled byThe table below provides information on the natural gas in additiontransportation agreements that deliver our natural gas to power from its coal-firedthe generation facilities and purchased power, to meet the summer peak demands of its retail customers and local reliability needs.stations. The average cost of natural gas per MMBtu, including transportation, was $2.20 in 2019, $2.92 in 2018, and $3.58 in 2017, $3.14 in 2016, and $3.49 in 2015.2017. |
| | | | |
| Station | | Natural Gas Transportation Counterparty | | Contract Expiration Date(s) |
| Gila | | Transwestern Pipeline Co./El Paso Natural Gas Company, LLC | | 2022-2040 |
| Luna | | El Paso Natural Gas Company, LLC | | 2022 |
| Sundt/RICE | | El Paso Natural Gas Company, LLC | | 2023-2040 |
| DeMoss Petrie | | Southwest Gas Corporation | | Retail Tariff |
| North Loop | | Southwest Gas Corporation | | Retail Tariff |
Sundt Generating Station
TEP has long-term firm agreements with El Paso Natural Gas Company, LLC. (EPNG) for transportation from the Permian and San Juan Basins to Sundt under firm transportation agreements. TEP also purchases firm gas transportation for Gila River Unit 3 from EPNG and Transwestern Pipeline Co., and for the Luna Generating Station (Luna) from EPNG. TEP purchasesplaced in service five natural gas from Southwest Gas Corporation under a retail tariffRICE units in December 2019, with the remaining five units scheduled to be placed in service in the first quarter of 2020, and retired Sundt Units 1 and 2 in November 2019. See Note 3 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for North Loop Generating Station's (North Loop) 94 MWadditional information on the RICE units.
Transmission and Distribution
TEP's distribution and transmission facilities are located in Arizona and New Mexico. These facilities are located on property owned by: (i) TEP; (ii) public entities; (iii) private entities; and (iv) Indian Nations. TEP's transmission and distribution systems included approximately 2,189 miles of transmission lines and 7,740 miles of distribution lines as of December 31, 2019.
TEP's transmission facilities transmit the output from TEP’s electric generation facilities to the Tucson area and power markets. The transmission system is part of the Western Interconnection, which includes the interconnected transmission systems of 14 western states, two Canadian provinces, and parts of Mexico. TEP's transmission system, together with contractual rights on other transmission systems, enables TEP to integrate and access generation resources to meet its customer load requirements. TEP's transmission and distribution systems included approximately 2,175 miles of transmission lines and 7,642 miles of distribution lines as of December 31, 2017.
Rates and Regulations
The ACC and the FERC each regulate portions of utility accounting practices and rates of TEP. The ACC regulates rates charged to retail customers, the siting of generation and transmission facilities, the issuance of securities, transactions with affiliated parties, and other utility matters. The ACC also enacts other regulations and policies that can affect TEP's business decisions and accounting practices. The FERC regulates termsrates and prices ofservices for electric transmission services and wholesale electricity sales.power sales in interstate commerce.
See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Factors Affecting Results of Operations and Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information that relates to rates and regulations that affect TEP including key provisions of its 2017 Rate Order.
2017 Rate Order
In February 2017, the ACC issued a rate order in the rate case filed by TEP in November 2015, which was based on a test year ended June 30, 2015 (2017 Rate Order). The 2017 Rate Order authorizes an annual increase in non-fuel revenue requirements of $81.5 million. New billing rates were effective starting on February 27, 2017.
Purchased Power and Fuel Adjustment Clause
The Purchased Power and Fuel Adjustment Clause (PPFAC) allows TEP recovery of its fuel, transmission, purchased power, and other similar costs allowed by the ACC to serve its retail load. The PPFAC consists of a forward component and a true-up component. The forward component adjusts for any costs over or under base fuel collection rates expected over a 12-month period. The true-up component reconciles any over/under collected amounts from the preceding 12-month period and is calculated to credit or recover these amounts from customers in the subsequent year.
As of December 31, 2017, TEP had over-collected fuel and purchased power costs by $9 million.Regulation
Renewable Energy Standard and Tariff
The ACC’s RES requires Arizona utilities to increase their use of renewable energy each year until it represents at least 15% of their total annual retail energy requirements in 2025, with DG accounting for 30% of the annual renewable energy requirement. Arizona utilities must file an annual RES implementation plan for review and approval by the ACC. The approved costs of carrying out this plan are recovered from retail customers through the RES surcharge. The associated lost revenues attributable to meeting DG targets will be partially recovered through the Lost Fixed Cost Recovery Mechanism (LFCR).
In 2017, the percentage of retail kilowatt-hour (kWh) sales from renewable energy was 13% of which approximately 10% was attributable to RES exceeding the 2017 requirement of 7%. The 2018 RES requirement is 8% of retail kWh sales. Compliance is determined through the ACC's review of TEP's annual RES implementation plan. As TEP no longer pays incentives to obtain DG Renewable Energy Credits (REC), which are used to demonstrate compliance with the DG requirement, the ACC approved a waiver of the 2017 and 2018 residential distributed renewable energy requirement.
Energy Efficiency StandardsStandard
Under the Energy EfficiencyEE Standards, (EE Standards), the ACC requires electric utilities to implement cost-effective programs to reduce customers' energy consumption. The EE Standards require increasing cumulative annual targeted retail kWh savings equal to 22% by 2020. As of December 31, 2017,2019, TEP’s cumulative annual energy savings was approximately 14%19%.
Distributed GenerationACC Rates
In 2016, theThe ACC held proceedings under the Valueestablishes rates that are designed to allow a regulated utility recovery of its cost of providing services and Cost of Distributed Generation (Value of DG) docketan opportunity to examine the ACC’s net metering rules and determine the value that utilities should pay DG customers who deliver electricity from rooftop solar systems back to the grid. Prior to thisearn a reasonable return on its investment. Retail Rates are generally established in rate case proceedings. TEP's last rate case proceeding the ACC’s net metering rules allowed DG customers who overproduced electricity to carry-over or “bank” excess electricity at a value equal to the full retail rate per kWh. Banked kWh could then be used by the customer to offset future energy usage that could not be met by their DG system.
In December 2016, the ACC approved an order that will begin to reform net meteringwas finalized in Arizona. The order adopts a number of net metering changes and policies, including:
placing DG customers2017. TEP is currently in a separate rate class;
grandfathering current DG customers under net metering rules and rate design for 20 years from interconnection application;
eliminating the banking of excess kWh for non-grandfathered DG customers; and
compensating non-grandfathered customers for their exported kWh based on the DG export rate in effect at the time of interconnection.
The initial compensation for DG exports will be based on a five-year historical average cost per kWh of TEP’s portfolio of owned and contracted utility-scale solar projects and will be established in a second phase of TEP'snew rate case (Phase 2). The DGproceeding which began in 2019 and is expected to be finalized in 2020.
exportpast regulatory decisions, TEP has cost recovery mechanisms that allow for more timely recovery of certain costs between rate will be updated each year and customers adopting solar will be compensated for 10 years atcase proceedings. These mechanisms are generally reset annually through separate filings with the rate in effect at the time they file an application for interconnection. An avoidedACC. TEP's cost methodology will also be developed for potential use in TEP’s next rate case. recovery mechanisms include:
| |
| • | PPFAC — a usage-based charge or credit that reflects changes in energy costs that are not recovered through base rates established in a rate case. |
| |
| • | REST — a usage-based charge that recovers the cost of complying with the RES. |
| |
| • | DSM — a usage-based charge that recovers the cost of energy efficiency programs that are designed to help TEP comply with the EE Standards. |
| |
| • | LFCR — a usage-based charge that partially offsets the revenue TEP loses when customers reduce their bills as a result of energy efficiency programs and DG system installations. |
| |
| • | ECA — a usage-based charge that recovers certain costs incurred at TEP's generation stations to comply with environmental regulations. |
See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Factors Affecting Results of Operations of this Form 10-K for additional information that relates to Phase 2.
FERC Compliance
In 2016, the FERC issued orders relating to certain late-filed Transmission Service Agreements (TSA), which resulted in TEP recording a liability and paying time-value refunds to the counterparties under these TSAs (FERC Refund Orders). In May 2017, the FERC informed TEP that the related investigation was closed. See Note 72 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information related to the FERC Refund Orders.on TEP's current rate case proceeding and cost recovery mechanisms.
ENVIRONMENTAL MATTERS
The Environmental Protection Agency (EPA)EPA regulates the amount of sulfur dioxide (SO2), nitrogen oxide (NOx), carbon dioxide (CO2), particulate matter, mercury, and other by-products produced by generation facilities. TEP may incur added costs to comply with future changes in federal and state environmental laws, regulations, and permit requirements at its generation facilities. Environmental laws and regulations are subject to a range of interpretations, which may ultimately be resolved by the courts. Because these laws and regulations continue to evolve, TEP is unable to predict the impact of the changing laws and regulations on its operations and consolidated financial results. TEP expects the recovery of the cost of environmental compliance through Retail Rates.
Refer to Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Liquidity and Capital Resources of this Form 10-K for additional information related to environmental laws and regulations as well as environmental compliance capital expenditures. See Note 9 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information on the Broadway-Pantano site.
National Ambient Air Quality Standards
In October 2015, the EPA released the final rule for the 8-hour U.S. National Ambient Air Quality Standards (NAAQS) for ozone (O3). The EPA lowered the standard from 75 parts per billion (ppb) to 70 ppb. If Pima Countyan area does not meet the standard, the county will bearea is designated as a “non-attainment” area and will needneeds to develop a plan to bring the air-shed into compliance. A “non-attainment” designation may slow economic growth in the region and impact ourTEP's ability to site new local generation. Arizona's recommendation ofArizona submitted recommendations for area designations (attainment, non-attainment, or unclassified) was submittedto the EPA in September 2016, and Pima County's was recommended2016. The EPA completed all area designations as an attainment area.
In November 2017, the EPA published a final rule in the Federal Register establishing the initial Air Quality designations, for the 2015 Ozone Standard.of July 2018. The majority of Arizona counties, including Pima, were designated as "attainment" or "unclassified" except for portions of Gila, Maricopa, Pinal, and Yuma counties.
In 2018, Pima and Maricopa countiesCounty exceeded the 2015 NAAQS standard for which aO3 at one monitoring location. If the county continues to exceed the standard, the state could recommend an O3 non-attainment designation will be addressed in a separate, future action.for Pima County during the next review period.
Effluent Limitation Guidelines
In 2015, as part of the Clean Water Act, the EPA published the final Effluent Limitation Guidelines (ELG) setting standards and limitations for steam electric generation facility wastewater discharges. The ELG rule establishes discharge limitsnew or additional requirements for wastewater streams associated with fly ash, bottom ash, flue gas desulfurization, flue gas mercury control, and mercury-contaminated wastewater at those facilities that requiregasification of fuels such as coal and petroleum coke. In August 2017, in response to legal challenges, the EPA announced it began rulemaking proceedings to potentially revise the 2015 ELGs. In September 2017, the EPA postponed the earliest ELG compliance date for these waste streams from November 1, 2018 until November 1, 2020. In November 2019, the EPA published a National Pollution Discharge Elimination System (NPDES) with an effective date between November 2018 and November 2023. proposed ELG rule revision in the Federal Register.
With the exception of Four Corners, none of TEP's owned steam electric generation facilities are subject to the other TEP owned facilities require an NPDES permit and therefore are not affected.ELG standards. With regard to Four Corners, until a draft NPDES permit is proposed during the 2018-2023 time-frame, TEP cannot predict what will be required to control these discharges to be in compliance with the finalized effluent limitations at that facility. TEP does not anticipate a significant financial impact from these requirements.
In 2017, the EPA announced its decision to reconsiderfinalizes the ELG. The EPA also filed and was granted a motion requesting the U.S. Court of Appeals for the Fifth Circuit to hold the litigation challenging the Rule in abeyance while the Agency reconsiders the ELG, after which it will inform the Court of any portions of the ELG for which it seeks a remand so that it can conduct further rulemaking. As a result, the U.S. Court of Appeals for the Fifth Circuit approved a briefing schedule for the ELG that puts industry groups’ challenges on hold indefinitely.
TEP believesproposed rule revisions, it is in material compliance with applicable environmental laws and regulations. Refer to Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Liquidity and Capital Resources ofunclear how the revision will affect this Form 10-K for additional information related to environmental laws and regulations as well as environmental compliance capital expenditures.facility.
EMPLOYEESEMPLOYEES
As of December 31, 2017,2019, TEP had 1,5101,587 employees, of which approximately 671675 are represented by the International Brotherhood of Electrical Workers Local No. 1116.1116 (IBEW). The current collective bargaining agreements between the IBEW and TEP expire in July 2022 with wages in effect through December 2018.2022.
EXECUTIVEINFORMATION ABOUT OUR EXECUTIVE OFFICERS OF THE REGISTRANT
Executive Officers, who are elected annually by TEP’s Board of Directors, acting at the direction of the Board of Directors of UNS Energy, as of January 2, 2018,1, 2020, are as follows: | | | Name | | Age | | Position(s) Held | | Executive Officer Since | | Age | | Position(s) Held | | Executive Officer Since |
David G. Hutchens (1) | | 51 | | President and Chief Executive Officer | | 2007 | | 53 | | Chief Executive Officer | | 2007 |
Susan M. Gray (1) | | | 47 | | President and Chief Operating Officer | | 2015 |
Frank P. Marino (1) | | 53 | | Vice President and Chief Financial Officer | | 2013 | | 55 | | Senior Vice President and Chief Financial Officer | | 2013 |
Todd C. Hixon (1) | | | 53 | | Senior Vice President, General Counsel, Corporate Secretary, and Chief Compliance Officer | | 2011 |
| Erik B. Bakken | | 45 | | Vice President, Transmission and Distribution Planning and Environmental | | 2018 | | 47 | | Vice President, System Operations and Environmental | | 2018 |
Kentton C. Grant | | 59 | | Vice President, Rates and Planning | | 2007 | |
| Susan M. Gray | | 45 | | Vice President, Energy Delivery | | 2015 | |
Todd C. Hixon (1) | | 51 | | Vice President, General Counsel and Chief Compliance Officer | | 2011 | |
| Dallas J. Dukes | | | 52 | | Vice President, Energy Programs and Pricing | | 2019 |
| Cynthia A. Garcia | | | 52 | | Vice President, Energy Delivery | | 2020 |
| Mark C. Mansfield | | 62 | | Vice President, Energy Resources | | 2012 | | 64 | | Vice President, Energy Resources | | 2012 |
| Catherine E. Ries | | 58 | | Vice President, Customer and Human Resources | | 2007 | | 60 | | Vice President, Customer and Human Resources | | 2007 |
| Michael E. Sheehan | | | 52 | | Vice President, Resource Planning, Fuels, and Wholesale Marketing | | 2020 |
| Mary Jo Smith | | 60 | | Vice President, Public Policy and Rates | | 2015 | | 62 | | Vice President, Public Policy | | 2015 |
| Morgan C. Stoll | | 47 | | Vice President and Chief Information Officer | | 2016 | | 49 | | Vice President and Chief Information Officer | | 2016 |
Martha B. Pritz | | 56 | | Treasurer | | 2017 | | 58 | | Treasurer | | 2017 |
| Herlinda H. Kennedy | | 56 | | Corporate Secretary | | 2006 | |
| |
(1) | Member of the TEP Board of Directors. The directors of TEP are elected annually by TEP's sole shareholder, UNS Energy, acting at the direction of the Board of Directors of UNS Energy. |
SECSEC REPORTS AVAILABLE ON TEP'S WEBSITE
TEP makes available its annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports as soon as reasonably practical after it electronically files or furnishes them to the SecuritiesSEC. The SEC maintains a website at https://www.sec.gov that contains reports, proxy and Exchange Commission (SEC). Theseinformation statements, and other information regarding issuers that file electronically. TEP's reports are also available free of charge through TEP’s website address at https://www.tep.com/about/investors/investor-information/.
TEP is providing the address of TEP’sits website solely for the information of investors and does not intend for the address to be an active link. The information contained on TEP’s website is not a part of, or incorporated by reference into, any report or other filing by TEP filed with the SEC by TEP.SEC.
ITEM 1A.1A. RISK FACTORS
The business and financial results of TEP are subject to a number of risks and uncertainties, including those set forth below. These risks and uncertainties fall primarily into five major categories: revenues, regulatory, environmental, financial, and operational. Additional risks and uncertainties that are not currently known to TEP or that are not currently believed by TEP to be material may also harmnegatively impact TEP’s business and financial results.
REVENUES
A significant decrease in the demand for electricity in TEP's service area would negatively impact retail sales and adversely affect results of operations, net income, and cash flows at TEP.
National and local economic conditions have a significant impact on customer growth and overall retail sales in TEP’s service area. TEP anticipates an annual customer growth rate of 1% for the next five years.
Research and development activities are ongoing for new technologies that produce power and reduce power consumption. These technologies include renewable energy, customer-sited DG, appliances, equipment, battery storage, and control systems. Continued development and use of these technologies and compliance with the ACC's EE Standards and RES continue to have a negative impact on TEP’s use per customer and overall retail sales. TEP's use per customer declined by an average of 1%2% per year from 20132015 through 2017.2019.
The revenues, results of operations, and cash flows of TEP are seasonal and are subject to weather conditions and customer usage patterns, which are beyond the Company’s control.
TEP typically earns the majority of its operating revenue and net income in the third quarter because retail customers increase their air conditioning usage during the summer. Conversely, TEP’s first quarter net income is typically limited by relatively mild winter weather in itsTEP's retail service territory. Cool summers or warm winters may reduce customer usage, negatively affecting operating revenues, cash flows, and net income by reducing sales.
TEP is dependent on a small number of customers for a significant portion of future revenues. A reduction in the electricity sales to these customers would negatively affect our results of operations, net income, and cash flows.flows at TEP.
TEP’s ten largest customers represented 10% of total revenues in 2017.2019. TEP sells electricity to mines, military installations, and other large commercial and industrial customers. Retail sales volumes and revenues from these customers could decline as a result of, among other things: global, national, and local economic conditions; curtailments of customer operations due to unfavorable market conditions; military base reorganization or closure decisions by the federal government; the effects of energy efficiency and distributed generation;DG; or the decision by customers to self-generate all or a portion of their energy needs. A reduction in retail kWh sales by any one of TEP’s ten largest customers would negatively affect ourthe Company's results of operations, net income, and cash flows.
REGULATORY
TEPTEP's business is subjectsignificantly impacted by government legislation, regulation and oversight. TEP's inability to regulation by the ACC, which sets the Company’s Retail Rates and oversees many aspects ofrecover its business in ways that couldcosts, earn a reasonable return on its investments, or comply with current regulations would negatively affect the Company’sits results of operations, net income, and cash flows.
TEP's financial condition is influenced by how regulatory authorities, including the ACC and FERC, establish the rates TEP can charge customers and authorize rates of return, common equity levels, and the amount of costs that may be recovered from customers. The Company's ability to timely obtain rate adjustments that provide TEP with the opportunity to earn authorized rates of return depends upon timely regulatory action under applicable statutes and regulations, and cannot be guaranteed.
ACC—The ACC is a constitutionally created body composed of five elected commissioners.commissioners that has jurisdiction over rates for retail customers. Commissioners are elected state-wide for staggered four-year terms and are limited to serving a total of two consecutive terms. As a result, the composition of the commission, and therefore its policies, are subject to change every two years.
TEP’s Retail Rates consist of base rates and various rate adjustors that are intended to allow for timely recovery of certain costs between rate cases. The ACC is charged with setting Retail Rates at levels that are intended to allow TEP recovery of its cost of service and provide it with an opportunity to earn a reasonable rate of return. In setting TEP’s Retail Rates, the ACC could disallow the recovery of costs, not provide for the timely recovery of costs or increase regulatory oversight. If customers or regulators have or develop a negative opinion of the Company's utility services or the electric utility industry in general, this could negatively affect TEP's regulatory outcomes. The decisions made by the ACC on such matters impact the net income and cash flows of TEP.
Changes in federal energy regulation may negatively affect the results of operations, net income, and cash flows of TEP.
TEP is subject to the impact of comprehensive and changing governmental regulation at the federal level that continues to change the structure of the electric utility industry and the ways in which this industry is regulated. TEP is subject to regulation
by the FERC. FERC—The FERC has jurisdiction over rates for electric transmission in interstate commerce and rates for wholesale sales of electric power, including terms and prices of transmission services and sales of electricity at wholesale.
Owners and operators of bulk power systems, including TEP, are subject to mandatory transmissionreliability standards developed and enforced by NERC and subject to the oversight of the FERC. Compliance with modified or new transmissionreliability standards may
subject TEP to higher operating costs and increased capital costs. Failure to comply with the mandatory transmissionreliability standards could subject TEP to sanctions, including substantial monetary penalties.
Changes made to legislation, regulation, or regulatory structure could negatively affect TEP's results of operations, net income, and cash flows.
TEP incurs costs to comply with legislative and regulatory requirements and initiatives, such as those relating to clean energy requirements, the deployment of distributed energy resources, and implementation of programs for demand response, customer energy efficiency, and electric vehicles. New initiatives or changes to existing requirements could arise in the future through legislative, regulatory, or other initiatives (including ballot initiatives) on either a federal or state level.
In 2018, the ACC opened rulemaking dockets to evaluate possible modifications to various state energy policies, including renewable energy goals and retail competition for generation services. In 2019, the ACC staff prepared a draft of rules that, if adopted, would change the renewable energy goals requiring Arizona regulated utilities to acquire 45% of the retail energy it sells from renewable generation by 2035. Increases to the renewable energy goals could accelerate the Company's long-term resource diversification strategy and increase capital expenditures and operating expenses. TEP's ability to recover costs, including its investments, associated with these and other legislative and regulatory initiatives will, in large part, depend on the final form of legislative or regulatory requirements. Further increases to rates could negatively affect the affordability of the rates charged to customers, which may negatively affect TEP’s results of operations, net income, and cash flows. In addition, the ACC staff and two commissioners have prepared different drafts of retail competition rules for utilities in Arizona. These rules have not been officially proposed, but if such rules were adopted, retail competition could have a negative impact on the Company's retail sales. TEP cannot predict the final outcome of these proposals. The adoption of any new policies or rules would be subject to rulemaking proceedings at the ACC.
Changes in tax regulation may negatively affect the results of operations, net income, and cash flows of TEP.
The Company is subject to taxation by the various taxing authorities at the federal, state and local levels where it does business. Legislation or regulation could be enacted by any of these governmental authorities which could affect the Company’s tax positions.
In December 2017, the Tax Cuts and Jobs Act (TCJA) was signed into law which enacted significant changes to the Internal Revenue Code including a reduction in the U.S. federal corporate income tax rate from 35% to 21% effective for tax years beginning after 2017. Subsequently, the ACC opened a docket requesting that all regulated utilities submit proposals to address passing any ongoing benefits of the TCJA through to customers. TEP cannot predict the timing or extent of the regulatory treatment related to the TCJA impacts but any decrease in rates paid by customers would have a negative impact on operating cash flows.
ENVIRONMENTAL
TEP is subject to numerous environmental laws and regulations that may increase its cost of operations or expose it to environmental-related litigation and liabilities.Many of these regulations could have a significant impact on TEP due to its reliance on coal for electric generation.
Numerous federal, state, and local environmental laws and regulations affect present and future operations. Those laws and regulations include rules regarding air emissions of conventional pollutants and greenhouse gases, water use, wastewater discharges, solid waste, hazardous waste, and management of coal combustion residuals.CCR.
These laws and regulations can contribute to higher capital, operating, and other costs, particularly with regard to enforcement efforts focused on existing generation facilities and compliance standards related to new and existing generation facilities. These laws and regulations generally require TEP to obtain and comply with a wide variety of environmental licenses, permits, authorizations, and other approvals. Both public officials and private individuals may seek to enforce applicable environmental laws and regulations. Failure to comply with applicable laws and regulations may result in litigation, the imposition of fines, penalties, and a requirement by regulatory authorities for costly equipment upgrades.
Existing environmental laws and regulations may be revised and new environmental laws and regulations may be adopted or become applicable to ourthe Company's facilities. Increased compliance costs or additional operating restrictions from revised or additional regulation could have a negative effect on TEP's results of operations, particularly if those costs are not timely and fully recoverable from TEP customers. TEP’s obligation to comply with the EPA’s Regional Haze Rule requirementsthese laws and regulations as a participant or owner in theregulated facilities like Springerville, San Juan, and Four Corners, and Navajo, coupled with the financial impact of future climate change legislation, other environmental regulations, and other business considerations, could jeopardize the economic viability of these generation facilities. Additionally, these regulations may jeopardize continued generation facility operations or the ability of individual participants to meet their obligations and willingness to continue their participation in these facilities potentially resulting in an increased operational cost for the remaining participants.
TEP also is contractually obligated to pay a portion of the environmental reclamation costs incurred at generation facilities in which it has a minority interest and is obligated to pay similar costs at the mines that supply these generation facilities. While TEP has recorded the portion of its costs that can be determined at this time, the total costs for final reclamation at these sites are unknown and could be substantial.
Federal regulations limiting greenhouse gas emissions require a shift in generation from coal to natural gas and renewable generation and could increase TEP's cost of operations.
In 2015, the EPA issued the Clean Power Plan (CPP) limiting CO2 emissions from existing and new fossil-fueled generation facilities. The CPP establishes state-level CO2 emission rates and mass-based goals that apply to fossil fuel-fired generation. The plan requires CO2 emission reductions for existing facilities by 2030 and establishes interim goals that begin in 2022. In its current form, the CPP requires a shift in generation from coal to natural gas and renewables and could lead to the early retirement of coal-fired generation in Arizona and New Mexico within the 2022 to 2030 compliance time-frame. In 2017, the EPA issued a proposal to repeal the CPP and has not determined whether or not a replacement rule will be issued. TEP will
continue to work with the other Arizona and New Mexico utilities, as well as the appropriate regulatory agencies, to develop compliance strategies. TEP is unable to determine whether the current CPP will remain in effect or be modified or any final CPP rule will impact its facilities until all legal challenges have been resolved and the currently required state compliance plans are developed and approved by the EPA.
FINANCIAL
Early closure of TEP's coal-fired generation facilities could result in TEP recognizing regulatory impairments or increased cost of operations if recovery of TEP's remaining investments in such facilities and the costs associated with early closures are not permitted through rates charged to customers.
Some of TEP's coal-fired generation facilities will be closed before the end of their useful lives in response to economic conditions and/or recent or future changes in environmental regulation, including potential regulation relating to greenhouse gasGHG emissions. If any of the coal-fired generation facilities from which TEP obtains power are closed prior to the end of their useful life, TEP may need to seek recovery of the remaining net book value (NBV) and could incur added expenses relating to accelerated depreciation and amortization, decommissioning, reclamation and cancellation of long-term coal contracts of such generation facilities. As of December 31, 2017,2019, TEP's regulatory assets balance related to its planned early generation retirement costs was $84$68 million. In 2019, TEP filed a general rate case with the ACC which includes a request to recover certain early retirement costs related to Navajo and Sundt Units 1 and 2.
Volatility or disruptions in the financial markets, rising interest rates, or unanticipated financing needs, could:could increase TEP's financing costs;costs, limit access to the credit or bank markets;markets, affect the Company's ability to comply with financial covenants in debt agreements;agreements, and increase TEP's pension funding obligations. Such outcomes may negatively affect liquidity and TEP's ability to carry out the Company's financial strategy.
We rely on access to the bank markets and capital markets as a significant source of liquidity and for capital requirements not satisfied by the cash flows from ourTEP's operations. Market disruptions such as those experienced in 2008 and 2009 in the United States and abroad may increase ourthe Company's cost of borrowing or negatively affect ourTEP's ability to access sources of liquidity needed to finance ourthe Company's operations and satisfy ourits obligations as they become due. These disruptions may include turmoil in the financial services industry, including substantial uncertainty surrounding particular lending institutions and counterparties we do business with, unprecedented volatility in the markets, where our outstanding securities trade, and general economic downturns in ourTEP's utility service territories. If we areTEP is unable to access credit at reasonable rates, or if ourthe Company's borrowing costs dramatically increase, ourTEP's ability to finance ourits operations, meet our debt obligations, and execute ourits financial strategy could be negatively affected.
Increases in short-term interest rates would increase the cost of borrowing on TEP's tax-exempt variable rate debt obligations of $137 million as of December 31, 2017, and increase the cost of borrowings under itsTEP's credit facility.facilities. In addition, changing market conditions could negatively affect the market value of assets held in ourits pension and other postretirement defined benefit plans and may increase the amount and accelerate the timing of required future funding contributions.
Generation facility closings or changes in power flows into TEP's service territory could require us to redeem or defease some or all of the tax-exempt bonds issued for the Company's benefit. Thisbenefit, which could result in increased financing costs.
TEP has financed a substantial portion of utility plant assets with the proceeds of pollution control revenue bonds and industrial development revenue bonds issued by governmental authorities. Interest on these bonds is, subject to certain exceptions, excluded from gross income for federal tax purposes. This tax-exempt status is based, in part, on continued use of the assets for pollution control purposes or the local furnishing of power within TEP’s two-county retail service area.
As of December 31, 2017,2019, there were outstanding approximately $309$257 million aggregate principal amount of tax-exempt bonds that financed pollution control expenditures at TEP’s generation facilities. ShouldIn October 2020, $80 million aggregate principal amount of bonds mature. The remaining bonds may be redeemed at par commencing in the first quarter of 2022. The bonds would be subject to early redemption should certain of TEP’s generationgenerating facilities be retired and dismantled prior to maturity or the stated maturity dates of the related tax-exempt bonds, it is possible that some or all of the bonds financing such pollution control expenditures would be subject to earlyfirst redemption by TEP. Of the total amount outstanding, $37 million of the principal amount of the bonds can currently be redeemed at par upon notice to holders, and $272 million of the principal amount of the bonds has early redemption dates or final maturities ranging from 2019 to 2022.date.
In addition, as of December 31, 2017,2019, there were outstanding approximately $307$207 million aggregate principal amount of tax-exempt bonds that financed local furnishing facilities. Depending on changes that may occur to the regional generation mix in the desert southwest, to the regional bulk transmission network, or to the demand for retail power in TEP’s local service area, it is possible that TEP would no longer qualify as a local furnisher of power within the meaning of the Internal Revenue Code. If TEP could no longer qualify as a local furnisher of power, all of TEP’s tax-exempt local furnishing bonds could be subject to mandatory early redemption by TEP or defeasance to the earliest possible redemption date, and TEP could be required to pay additional amounts if interest on such bonds were no longer tax-exempt. Of the total tax-exempt local furnishing bonds
outstanding,TEP has $100 million of thein aggregate principal amount of the bonds can currentlythat may be redeemed at par upon notice to holders, and $207 million of the principal amount of theon or after October 2020. The remaining bonds has early redemptionmay be redeemed at par commencing on dates ranging from 2020first quarter of 2022 to first quarter of 2023.
OPERATIONAL
The operation of electric generation facilities and transmission and distribution systems involves risks and uncertainties that could result in reduced generation capability or unplanned outages that could negatively affect TEP’s results of operations, net income, and cash flows.
The operation of electric generation facilities and transmission and distribution systems involves certain risks and uncertainties, including equipment breakdown or failures, fires, weather, and other hazards, interruption of fuel supply, and lower than expected levels of efficiency or operational performance. Unplanned outages, including extensions of planned outages due to equipment failures or other complications, occur from time to time. They are an inherent risk of ourthe Company's business and can cause damage to ourits reputation. If TEP’s generation facilities or transmission and distribution systems operate below expectations, TEP’s operating results could be negatively affected or TEP's capital spending could be increased.
In addition, as coal-fired generation facilities are closed, the economic viability of coal mines and coal suppliers may be jeopardized. To date, several coal suppliers have declared bankruptcy and coal mines have been closed. As additional coal-fired generation facilities are closed, the availability of sufficient coal supplies could decrease and prices may increase, which could, in turn, negatively affect the viability of our remaining coal-fired generation facilities.
The operation of generation facilities and transmission systems on Indian lands may create operational and financial risks for TEP that, if realized, could negatively affect TEP’s results of operations, net income, and cash flows.
Certain jointly-owned facilities and portions of TEP's transmission lines are located on Indian lands pursuant to leases, land easements, or other rights-of-way that are effective for specified periods. TEP is unable to predict the final outcomes of pending and future approvals by the applicable sovereign governing bodies with respect to the cost of renewals and continued access to these leases, land easements and rights-of-way. If pending and future approvals are not obtained and if continued access to the facilities is not granted, it could negatively affect TEP's results of operations, net income, and cash flows.
TEP receives power from certain generation facilities that are jointly-owned andwith, or operated by, third parties. Therefore, TEP may not have the ability to affect the management or operations at such facilities which could negatively affect TEP’s results of operations, net income, and cash flows.
Certain of the generation facilities from which TEP receives power are jointly ownedjointly-owned with, or are operated by, third parties. TEP maydoes not have the sole discretion or any ability to affect the management or operations at such facilities. As a result of this reliance on other operators, TEP may not be able to ensure the proper management of the operations and maintenance of thesuch generation facilities. Further, TEP may have no ability or a limited ability to make determinations ondetermine how best to manage the changing economic conditions or environmental requirements whichthat may affect such facilities. A divergence in the interests of TEP and the co-owners or operators, as applicable, of such facilities could negatively impact the business and operations of TEP.
The effects of climate change may create operational and financial risks for TEP that, if realized, could negatively affect TEP's results of operations, net income, and cash flows.
Climate change may impact regional and global weather conditions and result in extreme weather events, including high temperatures, severe thunderstorms, drought, and wildfires. Changes in weather conditions or extreme weather events in TEP’s service territory or affecting TEP's remote generation facilities or transmission system may lead to service outages and business interruptions, which could result in an increase in capital expenditures and operating expenses. Any increases in severity and frequency of weather-related system outages could affect TEP's operations and system reliability. Although physical utility assets have been constructed and are operated and maintained to withstand severe weather, there can be no assurance that they will successfully do so in all circumstances. In addition, changes in weather conditions or extreme weather events outside of TEP's service territory could result in higher wholesale energy prices, insurance premiums, and other costs, which could negatively impact TEP's business and operations. Any of these situations could have a negative impact on TEP's results of operations, net income, and cash flows.
TEP is subject to physical attacks which could have a negative impact on the Company's business and results of operations.
As operatorsTEP’s generation, transmission, and distribution facilities are critical to the provision of critical energy infrastructure,electric service to our customers and provide the framework for our service infrastructure. TEP is facing a heightened risk of physical attacks on the Company's electric systems. OurThe Company's electric generation, transmission, and distribution assets and systems are geographically dispersed and are often in rural or unpopulated areas which makes it especially difficult to adequately detect, defend from, and respond to such attacks. The Company relies on the continued operation of its network infrastructure, which is part of an interconnected regional grid. Any significant interruption of these assets could prevent the Company from fulfilling its critical business
functions including delivering energy to customers. Security threats continue to evolve and adapt. TEP and our third-party vendors have been subject to, and will likely continue to be subject to, attempts to disrupt operations. Despite implementation of security measures, there can be no assurance that the Company will be able to prevent the disruption of our operations.
If, despite ourTEP's security measures, a significant physical attack occurred, we couldthe Company could: (i) have our operations disrupted and/or property damaged,damaged; (ii) experience loss of revenues, response costs, and other financial loss; and (iii) be subject to increased regulation, litigation, and damage to our reputation, anythe Company's reputation. Any of whichthese outcomes could have a negative impact on TEP's business and results of operations.
TEP is subject to cyber-attacks which could have a negative impact on the Company's business and results of operations.
TEP is facingCybercrime, which includes the use of malware, computer viruses, and other means for disruption or unauthorized access has increased in frequency, scope, and potential impact in recent years. The Company relies on the continued operation of sophisticated digital information technology systems and network infrastructure, which are part of an interconnected regional grid. TEP's operations technology systems face a heightened risk of cyber-attacks. Thecyber-attack due to the critical nature of the infrastructure, the Company's informationconnectivity to the Internet, and operations technology systems may be vulnerableinherent vulnerability to unauthorized accessdisability or failures due to hacking, viruses, acts of war or terrorism, and other causes. types of data security breaches.
TEP's operationsinformation technology systems and network infrastructure have direct control over certain aspects of the electric system,been subject, and will likely continue to be subject, to cyber-attacks from foreign or domestic sources attempting to gain unauthorized access to information and/or information systems or to disrupt utility operations through computer viruses and phishing attempts either directly or indirectly through its material vendors or related third parties. Furthermore, the Company's utility business requires access to sensitive customer data, including personal and credit information, in the ordinary course of business.
If, despite TEP's security measures, a significant cyber or data breach occurred, the Company could have:could: (i) ourhave operations disrupted, property damaged, and customer information stolen;stolen, and general business system and process interruption or compromise, including preventing TEP from servicing customers, collecting revenues or the recording, processing and/or reporting financial information correctly; (ii) experience loss of revenues, response costs, and other financial loss; and (iii) be subject to increased regulation, litigation, and damage to ourthe Company's reputation. Any of these outcomes could have a negative impact on TEP's business and results of operations. To date we have not experienced any material breaches or disruptions to our network, information systems, or our service operations.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2.2. PROPERTIES
Transmission facilitiesTEP's corporate headquarters is owned by TEP and third parties are located in Arizona and New Mexico and transmit the output from TEP’s electric generationTucson, Arizona. Operational support facilities at Four Corners, Navajo, San Juan, Springerville, Gila River, and Luna to thefor Tucson area. The transmission system is interconnected at various points in Arizona and New Mexico with other regional utilities. See Part I, Item 1. Business, Overview of Business of this Form 10-K for additional information regarding the transmission facilities.
TEP's generation facilities (except as noted below), administrative headquarters, warehouses and service centersoperations are located on land owned by TEP. The distribution and transmission facilities owned by TEP are located:and located in Tucson, Arizona.
on property owned by TEP;
under or over streets, alleys, highways, and other places in the public domain, as well as in national forests and state lands, under franchises,TEP has land easements or other rights-of-way which generally are subjectfor transmission facilities related to termination;
under or over private property as a result of land easements obtained primarily from the record holder of title; or
overSan Juan, Four Corners, and Navajo located on tribal lands under the grant of easement by the Secretary of the Interior or leased from IndianZuni, Navajo, and Tohono O’odham Nations.
Springerville is located on property held by TEP under a term patent with the State of Arizona.TEP, under separate sale and leaseback arrangements, leases a 32.2% undivided interest in the Springerville Common Facilities (which does not include land).
Four Corners and Navajo are located on properties held under land easements from the United States and under leases from the Navajo Nation. TEP, individually and in conjunction with PNM, in connection with San Juan, has acquired land rights, land easements, and leases for theSan Juan's generation facilities, the transmission lines, and a water diversion facility located on land owned by the Navajo Nation. TEP has also acquired land easements for transmission facilities related to San Juan, Four Corners, and Navajo located on tribal lands of the Zuni, Navajo, and Tohono O’odham Nations. TEP, in conjunction with PNM and Samchully Power & Utilities 1 LLC, holds an undivided ownership interest in the property on which Luna is located. TEP and UNS Electric, Inc. (UNS Electric), an affiliate subsidiary of TEP, own a 75% and 25%, respectively, undivided interest in Gila River Unit 3. Gila River Unit 3 is situated on land owned by TEP and UNS Electric, who also own a 25% undivided ownership interest in the common facilities at Gila River as tenants in common. TEP and UNS Electric, together with the remaining 75% common facilities owners have a free and clear title of all common facilities.
TEP’s rights under these various land easements and leases may be subject to defects such as:
possible conflicting grants or encumbrances due to the absence of, or inadequacies in, the recording laws or record systems of the Bureau of Indian Affairs (BIA) and the Indian Nations;
possible inability of TEP to legally enforce its rights against adverse claims and the Indian Nations without Congressional consent; or
failure or inability of the Indian tribesNations to protect TEP’s interests in the land easements and leases from disruption by the U.S. Congress, Secretary of the Interior, or other adverse claims.
These possible defects have not interfered, and are not expected to materially interfere, with TEP’s interest in and operation of its facilities.
Under separate ground lease agreements, TEP leased parcelsTEP's rights under land easements expire at various times in the future and renewal action by the applicable tribe or federal agencies will be required. The ultimate cost of landrenewal for certain of the rights-of-way for the following PV facilities:
the Solar Zone located at the UniversityCompany's transmission lines is uncertain. The principal owned and leased generation, distribution, and transmission facilities of Arizona Technology ParkTEP are described in Pima County, Arizona; and
the Bright Tucson Community Solar located in Pima County, Arizona.
In addition, TEP has a 30-year easement agreement related to a PV facility in Cochise County, Arizona. The easement is to facilitate the operations of a solar PV renewable energy generation system on behalf of the Department of the Army.
SeePart I, Item 1. Business, Overview of Business of this Form 10-K for additional information regarding generation facilities. and such descriptions are incorporated herein by reference.
ITEM 3.3. LEGAL PROCEEDINGS
TEP is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. The Company believes such normal and routine litigation will not have a material impact on its consolidatedoperations or financial results. TEP is also involved in other kinds of legal actions, some of which assert or may assert claims or seek to impose fines, penalties, and other costs in substantial amounts on TEP.
See Note 79 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II
ITEM 5.5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES
Market Information
TEP’s common stock is wholly-owned by UNS Energy and is not listed for trading on any stock exchange.
Dividends
TEP declared and paid dividends to UNS Energy of $70 million in 2017 and $50 million in 2016 and 2015.
ITEM 6.6. SELECTED FINANCIAL DATA
The following table provides selected financial data for the years 20132015 through 2017:2019: |
| | | | | | | | | | | | | | | | | | | |
| (in thousands) | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
| Income Statement Data | | | | | | | | | |
| Operating Revenues | $ | 1,340,935 |
| | $ | 1,234,995 |
| | $ | 1,306,544 |
| | $ | 1,269,901 |
| | $ | 1,196,690 |
|
| Net Income | 176,668 |
| | 124,438 |
| | 127,794 |
| | 102,338 |
| | 101,342 |
|
| Balance Sheet Data | | | | | | | | | |
| Total Utility Plant, Net | $ | 3,768,702 |
| | $ | 3,782,806 |
| | $ | 3,558,229 |
| | $ | 3,425,190 |
| | $ | 2,944,455 |
|
| Total Assets | 4,590,249 |
| | 4,449,989 |
| | 4,249,478 |
| | 4,119,830 |
| | 3,482,860 |
|
| Long-Term Debt, Net | 1,354,423 |
| | 1,453,072 |
| | 1,451,720 |
| | 1,361,828 |
| | 1,213,367 |
|
| Non-Current Capital Lease Obligations | 28,519 |
| | 39,267 |
| | 55,324 |
| | 69,438 |
| | 131,370 |
|
| Other Data | | | | | | | | | |
Ratio of Earnings to Fixed Charges (1) | 5.06 |
| | 3.69 |
| | 3.74 |
| | 2.56 |
| | 2.67 |
|
| |
(1)
| For purposes of this computation, earnings are defined as pre-tax earnings from continuing operations before minority interest, or income/loss from equity method investments, plus interest expense and amortization of debt discount and expense related to indebtedness. Fixed charges are interest expense, including amortization of debt discount, interest on operating lease payments, and expense on indebtedness, including capital lease obligations. |
See Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations for additional information. |
| | | | | | | | | | | | | | | | | | | |
| (in thousands) | 2019 | | 2018 | | 2017 | | 2016 | | 2015 |
| Income Statement Data | | | | | | | | | |
| Operating Revenues | $ | 1,418,338 |
| | $ | 1,432,618 |
| | $ | 1,340,935 |
| | $ | 1,234,995 |
| | $ | 1,306,544 |
|
| Net Income | 186,515 |
| | 188,323 |
| | 176,668 |
| | 124,438 |
| | 127,794 |
|
| Balance Sheet Data | | | | | | | | | |
| Total Utility Plant, Net | $ | 4,534,896 |
| | $ | 4,160,640 |
| | $ | 3,768,702 |
| | $ | 3,782,806 |
| | $ | 3,558,229 |
|
| Total Assets | 5,489,157 |
| | 5,159,207 |
| | 4,590,249 |
| | 4,449,989 |
| | 4,249,478 |
|
| Long-Term Debt, Net | 1,522,087 |
| | 1,615,252 |
| | 1,354,423 |
| | 1,453,072 |
| | 1,451,720 |
|
| Non-Current Finance Lease Obligations | 67,316 |
| | 19,773 |
| | 28,519 |
| | 39,267 |
| | 55,324 |
|
ITEM 7.7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Management’s Discussion and Analysis explains the results of operations, the general financial condition, and the outlook for TEP. It includes the following:
outlookoverview and strategies;
operating results in 2017 compared with 2016, and 2016 compared with 2015;
factors affecting our results of operations and outlook;operations;
results of operations;
liquidity and capital resources, includingincluding: (i) capital expenditures,expenditures; (ii) contractual obligations,obligations; and (iii) environmental matters;
critical accounting policies and estimates; and
recentnew accounting pronouncements.standards issued and not yet adopted.
Management’s Discussion and Analysis includes financial information prepared in accordance with Generally Accepted Accounting PrinciplesGAAP.
This section of this Form 10-K primarily discusses 2019 and 2018 items and year-to-year comparisons between 2019 and 2018. Discussions of 2017 activity and year-to-year comparisons between 2018 and 2017 that are not included in the United Statesthis Form 10-K can be found in Part II, Item 7. Management Discussion and Analysis of America (GAAP) financial measures. It also includes non-GAAP financial measures which should be viewed as a supplement to,Financial Condition and not a substitute for, financial measures presented in accordance with GAAP. Non-GAAP financial measures as presented herein may not be comparable to similarly titled measures used by other companies.Results of Operations of our 2018 Annual Report on Form 10-K.
Management’s Discussion and Analysis should be read in conjunction with Part 2,II, Item 6,6. Selected Financial Data and the Consolidated Financial Statements and Notes in Part II, Item 8 of this Form 10-K. For information on factors that may cause our actual future results to differ from those we currently seek or anticipate, see Forward-Looking Information at the front of this report and Part I, Item 1A. Risk Factors for additional information.
References in this discussion and analysis to "we" and "our" are to TEP.
OUTLOOK AND STRATEGIESOVERVIEW
Outlook and Strategies
TEP's financial prospectsperformance and outlook are affected by many factors, including: (i) global, national, regional, and local economic conditions; (ii) volatility in the financial markets; (iii) environmental laws and regulations; and (iv) other regulatory factors.and legislative actions. Our plans and strategies include the following:include:
Achieving constructive outcomes in our regulatory proceedings that will provide us: (i) recovery of our full cost of service and an opportunity to earn an appropriate return on our rate base investments; (ii) updated rates that provide more accurate price signals and a more equitable allocation of costs to our customers; and (iii) the ability to continue providing safe, affordable, and reliable service.
Continuing to focus on our long-term resource diversification strategy, including shiftingtransitioning from coalcarbon intensive sources to natural gas, renewables, anda more sustainable energy efficiencyportfolio, while providing reliability and rate stability for our customers, mitigating environmental impacts, complying with regulatory requirements, leveraging and improving our existing utility infrastructure, and maintaining financial strength. This long-term strategy includes a target of meetingachieving 30% of our customers’ energy needs with non-carbon emitting resources eight years ahead of our 2030 goal. We are currently working on new long-term goals based on carbon emission reductions as part of our integrated resource plan which we plan to file with the ACC during 2020. This resource strategy may be impacted by 2030.various energy policy proposals currently under consideration in Arizona.
Focusing on our core utility business through operational excellence, promoting economic development in our service territory, investing in infrastructure to ensure reliable service, and maintaining a strong community presence.
Operational and Financial Highlights
For 2017, Management's Discussion and Analysis includes the following notable items:
The ACC issued the 2017 Rate Order approving a non-fuel base rate increase of $81.5 million, a cost of equity component of 9.75%, and an equity ratio of approximately 50%. The new rates took effect on February 27, 2017.
The Navajo Nation approved a land lease extension that allows Navajo to operate through DecemberPerformance - 2019 and decommissioning activities to begin thereafter. As a result of the planned early retirement, we transferred $52 million of the facility's NBV and other related costs to a regulatory asset.
The FERC informed us that no further enforcement actions were necessary as the investigation related to the FERC Refund Orders had been closed. In addition, TEP and a counterparty, who had been a recipient of the time-value
refunds in complianceCompared with the FERC Refund Orders, entered into a settlement agreement which resulted in: (i) the counterparty paying TEP $8 million; and (ii) TEP dismissing a previously filed appeal.
In conjunction with a generation modernization project at Sundt, we will discontinue operation of Sundt Units 1 and 2 by the end of 2020. As a result of the planned early retirements, we transferred $32 million of the facilities' NBV to a regulatory asset.
We entered into a 20-year Tolling PPA with SRP to purchase and receive all 550 MW of capacity, power, and ancillary services from Gila River Unit 2. The Tolling PPA will allow us to continue to move toward its long-term goal of resource diversification. Our obligations under the agreement are contingent upon SRP's acquisition of Gila River Units 1 and 2, which is expected to be completed by March of 2018.
We purchased an additional 17.8% undivided ownership interest in Springerville Common Facilities for $38 million bringing its total ownership interest to 67.8%.
San Juan Unit 2 ceased operations in compliance with a State Implementation Plan (SIP) covering BART requirements for San Juan. TEP owns 50% of San Juan Unit 2 and applied excess depreciation reserves against the unrecovered NBV as approved in the 2017 Rate Order.
RESULTS OF OPERATIONS
The following discussion provides the significant items that affected TEP's results of operations in years ended December 31, 2017, 2016, and 2015, presented on an after-tax basis.
2017 compared with 20162018
TEP reported net income of $177$187 million in 20172019 compared with $124$188 million in 2016.2018. The increasedecrease of $53$1 million, or 43%1%, was primarily due to:
$52 million in higher retail revenue primarily due to an increase in rates as approved in the 2017 Rate Order and an increase in usage due to favorable weather;
$21 million in higher net income due to time-value FERC ordered refunds incurred in 2016 and the reversal of accrued refunds in 2017 related to late-filed TSAs. See Note 7 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information related to late-filed TSAs; and
$6 million in higher wholesale revenue primarily due to favorable pricing on wholesale contracts in 2017.
The increase was partially offset by:
$8 million in lower revenues related to the Springerville Unit 1 settlement in 2016. See Note 7 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information related to the settlement;
$7 million in higher income tax expense primarily due to the enactment of the TCJA in 2017 as well as changes to our valuation allowance for deferred tax assets in 2016. See Note 12 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information related to impacts of the TCJA on our financial results;
$611 million in higher depreciation and amortization expenses; and
$4 million in higher operations and maintenance expense resulting primarily from an increase in maintenance expense due to planned generation outages in 2017 and employee wages and benefits.
2016 compared with 2015
TEP reported net income of $124 million in 2016 compared with $128 million in 2015. The decrease of $4 million, or 3%, was primarily due to:
$13 million in lower net income associated with late-filed TSAs;
$6 million in higher depreciation and amortization expenses primarily related to an increase in asset base; and
$410 million in higher operations and maintenance expenses primarilyinterest expense related to an increasea debt issuance in outside servicesNovember 2018; and employee wages and benefits.
$8 million due to lower retail revenue primarily due to a decrease in usage related to unfavorable weather.
The decrease was partially offset by:
$8 million in higher revenues relatedAFUDC due to the Springerville Unit 1 settlementan increase in 2016;construction projects;
$67 million in lower income tax expense primarily due to EDIT amortization true-ups related to the TCJA and the recognition of additional AMT credits related to a revision in tax law guidance;
$7 million increase in value of company-owned life insurance as a result of favorable market conditions; and
$6 million in lower operations and maintenance expense related to planned generation outages in 2018 not recurring in 2019.
FACTORS AFFECTING RESULTS OF OPERATIONS
Several factors affect our current and future results of operations. The most significant factors are related to regulatory matters, generation resource diversification, and weather patterns.
Regulatory Matters
TEP is subject to comprehensive regulation. The discussion below contains material developments to those matters.
2019 ACC Rate Case
In April 2019, TEP filed a reduction ingeneral rate case with the valuation allowance for deferred tax assetsACC based on a test year ended December 31, 2018, to provide TEP with an opportunity to recover its full cost of service, including an appropriate return on its rate base investments, and enable TEP to continue to provide safe and reliable service.
TEP's key proposals of the rate case, adjusted for rebuttal testimony filed in November 2019 include:
a non-fuel retail revenue increase in projected taxable income; and
$4of $99 million, from higher LFCR revenues that partially offset lower retail sales.
Retail Revenues and Key Statistics
The following tables provide a reconciliation of Retail Revenues (GAAP) to Retail Margin Revenues (non-GAAP) and other key statistics impacting operating revenues: |
| | | | | | | | | | | | | | | | | |
| | Years Ended December 31, | | Increase (Decrease) | | Year Ended December 31 | | Increase (Decrease) |
| ($ in millions) | 2017 | | 2016 | | Percent | | 2015 | | Percent |
| Retail Revenues (GAAP) | $ | 1,041 |
| | $ | 990 |
| | 5.2 | % | | $ | 1,022 |
| | (3.1 | )% |
| Less recoveries from: | | | | | | | | | |
| Fuel and Purchased Power | 275 |
| | 305 |
| | (9.8 | )% | | 344 |
| | (11.3 | )% |
| DSM and RES Surcharge | 53 |
| | 54 |
| | (1.9 | )% | | 49 |
| | 10.2 | % |
Retail Margin Revenues (non-GAAP) (1) | $ | 713 |
| | $ | 631 |
| | 13.0 | % | | $ | 629 |
| | 0.3 | % |
| | | | | | | | | | |
Electric Sales (kWh in millions) | | | | | | | | | |
| Residential | 3,786 |
| | 3,724 |
| | 1.7 | % | | 3,724 |
| | — | % |
| Commercial | 2,192 |
| | 2,139 |
| | 2.5 | % | | 2,124 |
| | 0.7 | % |
| Industrial | 1,939 |
| | 2,006 |
| | (3.3 | )% | | 2,063 |
| | (2.8 | )% |
| Mining | 991 |
| | 997 |
| | (0.6 | )% | | 1,109 |
| | (10.1 | )% |
| Public Authorities | 18 |
| | 30 |
| | (40.0 | )% | | 33 |
| | (9.1 | )% |
| Total Retail Sales | 8,926 |
| | 8,896 |
| | 0.3 | % | | 9,053 |
| | (1.7 | )% |
| Wholesale Sales, Long-Term | 587 |
| | 463 |
| | 26.8 | % | | 750 |
| | (38.3 | )% |
| Wholesale Sales, Short-Term | 3,630 |
| | 3,308 |
| | 9.7 | % | | 3,928 |
| | (15.8 | )% |
| Total Electric Sales | 13,143 |
| | 12,667 |
| | 3.8 | % | | 13,731 |
| | (7.7 | )% |
| | | | | | | | | | |
Average Retail Rate (cents / kWh) | 11.66 |
| | 11.13 |
| | 4.8 | % | | 11.29 |
| | (1.4 | )% |
| Average Fuel and Purchased Power Rate | 3.08 |
| | 3.43 |
| | (10.2 | )% | | 3.80 |
| | (9.7 | )% |
| Average DSM and RES Surcharge Rate | 0.59 |
| | 0.61 |
| | (3.3 | )% | | 0.54 |
| | 13.0 | % |
| Total Average Retail Margin Rate | 7.99 |
| | 7.09 |
| | 12.7 | % | | 6.95 |
| | 2.0 | % |
| |
(1)
| Retail Margin Revenues, a non-GAAP financial measure, should not be considered as an alternative to Retail Revenues, which is determined in accordance with GAAP. Retail Margin Revenues exclude revenues collected from retail customers that are directly offset by expenses recorded in other line items. TEP believes the change in Retail Margin Revenues between periods provides useful information for investors and analysts because it demonstrates the underlying revenue trend and performance of our core utility business. Retail Margin Revenues represents the portion of retail operating revenues from kWh sales, LFCR revenues, DSM performance bonus, and other revenues available to cover the non-fuel operating expenses of our core utility business. |
Retail Revenues increased in 2017 compared with 2016 primarily due to higher Retail Margin Revenues related to an increase in rates as approved in the 2017 Rate Order and an increase in usage due to favorable weather in 2017. The increases were partially offset by a decreasereduction in base fuel revenue from Fuelof approximately $39 million for a net increase of $60 million over test year retail revenues;
a 7.49% return on original cost rate base of $2.7 billion, which includes a cost of equity of 10.00% and Purchased Power recoveriesan average cost of debt of 4.65%;
a capital structure for rate making purposes of approximately 53% common equity and 47% long-term debt;
a request to recover costs of changes in generation resources, including: (i) the retirement of Navajo and Sundt Units 1 and 2; and (ii) the replacement generation capacity associated with the purchase of Gila River Unit 2 and the installation of RICE units at Sundt;
a TEAM that would be updated for income tax changes that materially affect TEP’s authorized revenue requirement; and
a TCA mechanism, updated annually, allowing TEP to recover any changes in transmission costs approved by the FERC.
Hearings before an ALJ were held in January and February 2020. The hearing will resume in April 2020. TEP requested new rates to be implemented by May 1, 2020. We cannot predict the timing or outcome of the proceeding.
2019 FERC Rate Case
In 2019, the FERC issued an order approving TEP's proposed OATT revisions effective August 1, 2019, subject to refund.
Provisions of the order include, but are not limited to:
replacing TEP's stated transmission rates with a forward-looking formula rate;
a 10.4% return on equity; and
elimination of transmission rates that are bifurcated between high-voltage and lower-voltage facilities, as well as elimination of the bifurcated loss factor rate.
The requested forward-looking formula rate is intended to allow for more timely recovery of transmission-related costs. If this request is approved, transmission revenues would increase by $7 million. As part of the order, the FERC established hearing and settlement procedures, and all revisions to the OATT in the FERC order are subject to refund. As of December 31, 2019, TEP had reserved $4 million of wholesale revenues in Current Liabilities—Regulatory Liabilities on the Consolidated Balance Sheets as a result of lower PPFAC rates.the FERC proceedings. We cannot predict the outcome of the proceeding.
Retail Revenues decreasedAbandoned Plant Costs
Also in 2016 comparedMay 2019, TEP filed with 2015 primarily duethe FERC a request to recover through its OATT abandoned plant costs related to the abandoned Sahuarita, Arizona to Nogales, Arizona transmission line. TEP requested authorization to recover 100% of the approximately $9 million that we incurred in developing the transmission line. The filing requested that the abandoned plant costs be included in TEP's transmission rate. On September 19, 2019, the FERC issued an order allowing TEP to recover 50% of its costs in its formula rate and established hearing and settlement procedures. TEP incorporated the abandoned plant costs into our formula rate effective January 1, 2020, subject to refund. On September 26, 2019, the FERC issued an order consolidating the 2019 FERC Rate Case and Abandoned Plant Costs proceedings. TEP previously wrote off a portion of the deferred costs related to the Nogales transmission line. As of December 31, 2019, there was $4 million related to the Nogales transmission line recorded in Regulatory and Other Assets—Regulatory Assets on the Consolidated Balance Sheets.
Federal Income Tax Legislation
Arizona Corporation Commission
In December 2017, the ACC opened a docket requesting that all regulated utilities submit proposals to address passing the benefits of the TCJA through to customers. In 2018, the ACC approved TEP’s proposal to return savings from the Company’s federal corporate income tax rate under the TCJA to its customers through a combination of customer bill credits and a regulatory liability deferral that reflects the return of a portion of the savings, effective May 1, 2018 (ACC Refund Order). The refund represents the reduction in the federal corporate income tax rate and an estimate of EDIT amortization that will be trued-up annually for actuals. The bill credit was designed to return the refund amount to customers based on forecasted kWh sales for the calendar year. Any over or under collected amounts are deferred to a decreaseregulatory liability or asset and will be used to adjust the following year's bill credit amounts. Customer bill credits are trued-up annually to reflect actuals for both kWh sales and EDIT amortization. The refund amounts totaled $33 million in both 2019 and 2018. TEP filed an information filing with the ACC to establish a 2020 customer refund of $35 million. The refund will be returned to customers through a combination of a customer bill credit and a regulatory liability in 2020. The customer bill credit will account for 50% of the returned savings in 2020 and through the completion of our next rate case. TEP has proposed a TEAM to return the remaining deferred balance.
See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 and Liquidity and Capital Resources, Income Tax Position of this Form 10-K for additional information regarding the ACC Refund Order.
Federal Energy Regulatory Commission
In 2018, the FERC issued orders directing TEP to either: (i) submit proposed revisions to its stated transmission rates or stated transmission revenue from Fuel and Purchased Power recoveriesrequirements to reflect the change in the federal corporate income tax rate as a result of the TCJA; or (ii) show cause why it should not be required to do so (FERC Refund Order). In May 2018, TEP responded to the order and the FERC approved TEP's proposal of an overall transmission rate reduction of approximately 5.3%, reflecting the lower PPFACfederal tax rate, to be effective March 21, 2018. As a result, TEP recognized a reduction in Operating Revenues on the Consolidated Statements of Income of $1 million in 2018.
Also in 2018, the FERC issued a NOPR regarding the effect of the TCJA and related EDIT amortization. In November 2019, the FERC issued a final rule on the NOPR, which did not require TEP to update its stated transmission rates partially offsetto deduct or include EDIT in its rate base. As required by higher Retail Margin Revenues due to an increase in LFCR revenues.the final rule, TEP's 2019 FERC Rate Case addressed the effects of the TCJA and related EDIT amortization.
See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K, for additional information onregarding the PPFAC mechanism and LFCR revenues.FERC Refund Order.
Wholesale RevenuesArizona Energy Policy
Wholesale Revenues increased by $57 million, or 49%,In 2018, the ACC opened rulemaking dockets to evaluate possible modifications to various energy policies including existing renewable energy goals, integrated resource planning, and retail competition for generation services. In 2019 and 2020, the ACC staff and two commissioners prepared different drafts of retail electric competition rules. The ACC is expected to discuss those draft rules during upcoming workshops, but such rules have not been officially proposed and no changes have been made. We anticipate that the ACC will hold additional workshops in 2017 compared with 2016 primarily due to: (i) time-value FERC ordered refunds incurred in 2016 and the reversal of accrued refunds in 2017,2020 related to late-filed TSAs; (ii) favorable commodity pricing on the wholesale market; (iii) aretail electric competition and other energy-related policies. The adoption of new long-term wholesale contract that commenced in 2017; and (iv) an increase in short-term wholesale volumes.
Wholesale Revenues decreased by $50 million,policies or 30%, in 2016 compared with 2015 primarily due to: (i) time-value FERC ordered refunds incurred in 2016; (ii) decreased volumes and market prices of both short-term and long-term wholesale sales resulting from unfavorable market conditions; and (iii) termination of a firm contractrules would be subject to rulemaking proceedings at the end of May 2016.
Short-term wholesale revenues are primarily relatedACC. We would seek the ACC's approval to ACC jurisdictional assets and are returned to retail customers by crediting the revenues against fuel and purchased power costs eligible for recovery through the PPFAC.
Other Revenues
Other Revenues decreased by $3 million, or 2%, in 2017 compared with 2016 primarily due to a Springerville Unit 1 settlement agreement in 2016. The decrease was partially offset by an increase in reimbursed costs to TEP from SRP, the owner of Springerville Unit 4, related to planned generation outages of the facility in 2017. See Note 7 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information related to the Springerville Unit 1 settlement.
Other Revenues increased by $10 million, or 8%, in 2016 compared with 2015 primarily due to the Springerville Unit 1 settlement agreement in 2016. The increase was offset by a decrease in reimbursed costs to TEP from Tri-State Generation and Transmission Association, Inc. (Tri-State), the lessee of Springerville Unit 3, and SRP related to planned generation outages at Springerville Units 3 and 4 in 2015.
Operating Expenses
Fuel and Purchased Power Expense
Fuel and Purchased Power Expense, which includes PPFAC recovery treatment, increased by $5 million, or 1%, in 2017 compared with 2016 primarily due to an increase in Purchased Power volumes that replaced lower Coal-Fired Generation output, and an increase in average fuel cost per kWh (see table below). The increases were partially offset by reduced recovery of PPFAC costs as a result of changes in PPFAC rates. See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information on the PPFAC mechanism.
Fuel and Purchased Power Expense, which includes PPFAC recovery treatment, decreased by $75 million, or 15%, in 2016 compared with 2015 primarily due to a decrease in: (i) Purchased Power, Non-Renewable volumes; (ii) Coal-Fired Generation output; and (iii) average cost fuel and purchased power per kWh (see table below). The decrease was partially offset by an increase in Gas-Fired Generation output.
TEP’s sources of energy are detailed in the following table: |
| | | | | | | | | | | | | | |
| | Years Ended December 31, | | Increase (Decrease) | | Year Ended December 31, | | Increase (Decrease) |
| (kWh in millions) | 2017 | | 2016 | | Percent | | 2015 | | Percent |
| Sources of Energy | | | | | | | | | |
| Coal-Fired Generation | 7,530 |
| | 8,310 |
| | (9.4 | )% | | 8,584 |
| | (3.2 | )% |
| Gas-Fired Generation | 3,237 |
| | 3,283 |
| | (1.4 | )% | | 2,723 |
| | 20.6 | % |
| Utility-Owned Renewable Generation | 83 |
| | 68 |
| | 22.1 | % | | 65 |
| | 4.6 | % |
| Total Generation | 10,850 |
| | 11,661 |
| | (7.0 | )% | | 11,372 |
| | 2.5 | % |
| Purchased Power, Non-Renewable | 2,471 |
| | 1,126 |
| | 119.4 | % | | 2,627 |
| | (57.1 | )% |
| Purchased Power, Renewable | 646 |
| | 666 |
| | (3.0 | )% | | 452 |
| | 47.3 | % |
| Total Generation and Purchased Power | 13,967 |
| | 13,453 |
| | 3.8 | % | | 14,451 |
| | (6.9 | )% |
TEP’s average fuel cost of generated power and the average cost of purchased power per kWh are detailed in the following table: |
| | | | | | | | | | | | | | |
| | Years Ended December 31, | | Increase (Decrease) | | Year Ended December 31, | | Increase (Decrease) |
| (cents per kWh) | 2017 | | 2016 | | Percent | | 2015 | | Percent |
| Average Fuel Cost of Generated Power | | | | | | | | | |
| Coal | 2.41 |
| | 2.30 |
| | 4.8 | % | | 2.44 |
| | (5.7 | )% |
| Natural Gas | 3.06 |
| | 2.84 |
| | 7.7 | % | | 3.35 |
| | (15.2 | )% |
| Average Cost of Purchased Power | | | | | | | | | |
| Purchased Power, Non-Renewable | 3.78 |
| | 3.43 |
| | 10.2 | % | | 3.04 |
| | 12.8 | % |
| Purchased Power, Renewable | 6.67 |
| | 7.00 |
| | (4.7 | )% | | 9.82 |
| | (28.7 | )% |
Operations and Maintenance Expense
Operations and Maintenance Expense increased by $6 million, or 2%, in 2017 compared with 2016 primarily due to an increase in: (i) maintenance expense related to planned generation outages and an increase in employee wages and benefits. The increase was partially offset by a decrease in RES and DSM program expenses.
Operations and Maintenance Expense increased by$9 million, or 3%, in 2016 compared with 2015 primarily due to an increase in: (i) maintenance expense related to planned generation outages, outside services, and employee wages and benefits; and (ii) an increase in RES and DSM program expenses.
RES and DSM program expenses are fully recovered through the cost recovery mechanisms and have no impact on earnings.
Other Income (Deductions)
Other Income (Deductions) increased by $9 million in 2017 compared with 2016 primarily due to a settlement agreement in 2017 related to late-filed TSAs. See Note 7 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K.
There were no significant changes to Other Income (Deductions) in 2016 compared with 2015.
Income Tax Expense
Income Tax Expense increased by $41 million, or 70%, in 2017 compared with 2016 primarily due to the increase in earnings before tax, the enactment of the TCJA in December 2017, and a reduction in the valuation allowance for deferred tax assets in 2016. See Note 12 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information related to impacts of the TCJA on our financial results.
Income Tax Expense decreased by $12 million, or 17%, in 2016 compared with 2015 primarily due to the decrease in earnings before tax income and a reduction in the valuation allowance for deferred tax assets based on an increase in projected taxable income.
FACTORS AFFECTING RESULTS OF OPERATIONS
Regulatory Matters
TEP is subject to comprehensive regulation. The discussion below contains material developments to those matters.
2017 Rate Order
In February 2017, the ACC issued a rate order in the rate case filed by TEP in November 2015. TEP's rate filing was based on a test year ended June 30, 2015. The 2017 Rate Order approved new rates that went into effect on February 27, 2017.
The provisions of the 2017 Rate Order include, but are not limited to:
a non-fuel base rate increase of $81.5 million which includes $15 million of operatingrecover any costs related to the 50.5% undivided interest in Springerville Unit 1 purchased by TEP in September 2016;
a 7.04% return on original cost rate base of approximately $2 billion;
a cost of equity component of 9.75% and a cost of debt component of 4.32%;
a capital structure for rate making purposes of approximately 50% common equity and 50% long-term debt;
adoption of TEP's proposed depreciation and amortization rates, which include a reduction in the depreciable life for San Juan Unit 1; and
approval of a request to apply excess depreciation reserves against the unrecovered NBV of San Juan Unit 2 and the coal handling facilities at Sundt due to early retirement.
The ACC deferred matters related to net metering and rate design for new DG customers to Phase 2, which is currently expected to be completed in the first half of 2018.energy policies or requirements. TEP cannot predict the outcome of these proceedings. See Phase 2 Proceedings below.
Distributed Generation
In 2016, the ACC held proceedings under the Value and Cost of DG docket to examine the ACC’s net metering rules and determine the value that utilities should pay DG customers who deliver electricity from rooftop solar systems back to the grid. Prior to these proceedings, the ACC’s net metering rules allowed DG customers who over-produced electricity to carry-overmatters or “bank” excess electricity at a value equal to the full retail rate per kWh. Banked kWh could then be used by customers to offset future energy usage that could not be met by their DG system.
In December 2016, the ACC approved an order that will begin to reform net metering in Arizona. The order adopts a number of net metering changes and policies, including:
placing DG customers in a separate rate class;
grandfathering current DG customers under net metering rules and rate design for 20 years from interconnection application;
eliminating the banking of excess kWh for non-grandfathered DG customers;
compensating non-grandfathered customers for their exported kWh for 10 years at the DG export rate in effect at the time of interconnection;
updating the DG export rate annually; and
developing an avoided cost methodology for calculating the DG export rate in the utility’s next rate case.
The initial DG export rate will be established in Phase 2. See Phase 2 Proceedings below.
Phase 2 Proceedings
In March 2017, TEP filed direct testimony in its Phase 2 proceedings addressing rate design for new DG customers. The proposals include options for either a Time-Of-Use (TOU) energy rate with a basic customer service charge plus a monthly grid access fee based on the size of the DG system; or a TOU energy rate with a basic customer service charge plus a charge based on the highest hourly demand during the month. TEP also proposed that: (i) new DG customers receive a bill credit for excess energy exported to the grid at an initial rate of 9.7 cents/kWh; (ii) the DG export rate be updated based on a five-year rolling average cost of the company’s owned and contracted utility scale renewable energy projects; (iii) customers who submit DG applications prior to the ACC’s Phase 2 decision be grandfathered under current net metering rules and rate design for a period of 20 years from the date of interconnection of their DG system; and (iv) customers who install DG after the ACC’s Phase 2 decision be compensated for 10 years at the rate in effect at the time they file an application for interconnection. A final ACC decision is currently expected in the first half of 2018. TEP cannot predict the outcome of these proceedings.
Federal Income Tax Legislation
On December 22, 2017, the President of the United States of America signed into law the TCJA, which enacted significant changes to the Internal Revenue Code including a reduction in the U.S. federal corporate income tax rate from 35% to 21% effective for tax years beginning after 2017. TEP has revalued its deferred tax assets and liabilities at the new federal corporate income tax rate as of the date of enactment of the TCJA. We are still in the process of analyzing the ongoing impacts of the TCJA on our operations. See Note 12 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding current year impacts of the TCJA.
In December 2017, the ACC opened a docket related to the TCJA. On February 6, 2018, the ACC ordered utilities to file within 60 days either: (i) an application for a tax adjustor mechanism; (ii) an intent to file a rate case within 90 days; or (iii) any other
application to address the effects of the TCJA. TEP expects to file a tax adjustor proposal with the ACC prior to the deadline addressing the method it will use to pass through TCJA benefits to its customers. TEP will defer the ACC jurisdictional tax benefits as a regulatory liability until the proceedings are finalized.
TEP offsets its net operating loss carryforwards against taxable income and does not expect to make federal income tax payments until 2020. Any interim return of benefits to customers related to the TCJA would have a negative impact on TEP's operating cash flows.
TEP cannot predict the outcome of these proceedings or the impact on the Company's financial position or results of operations.
Generation Resources
As of December 31, 2017, approximately 49% of TEP's peak generation capacity was sourced from coal-fired generation resources. As part of TEP's long-term diversification strategy, TEP is evaluating additional steps to reduce its reliance on coal-fired generation.
Integrated Resource PlanDiversification
TEP’s long-term strategy is to shift to a more diverse, sustainable energy portfolio is described in its Integrated Resource Plan (IRP) filed in April 2017 with the ACC. TEP's 2017 IRP discusses continuing efforts to diversify its generation portfolio including expanding renewable energy and natural gas-fired resources while reducing reliance on coal-fired generatinggeneration resources. TEP's existing coal-fired generation fleet faces a number of uncertainties impacting the viability of continued operations, including changing state and federal law and energy policies, competition from other resources, fuel supply and land lease contract extensions, environmental regulations, and, for jointly owned facilities, the willingness of other owners to continue their participation. Given this uncertainty, TEP may consider options that include changes in generation facility ownership shares, unit shutdowns, or the sale of generation assets to third-parties. TEP will seek regulatory recovery for amounts that would not otherwise be recovered, if any, as a result of these actions.
As of December 31, 2019, approximately 38% of our generation capacity was from coal-fired generation.
See Part I, Item 1. Business, Overview of Business and Liquidity and Capital Resources,Environmental Matters of this Form 10-K for additional information regarding generation facility operations.
Arizona Energy Modernization Plan
The ACC will be considering adoption ofa new energy policy for Arizona that would establish a goal of clean energy sources making up at least 80% of the state’s electricity generation portfolio by 2050. The adoption of a new policy is subject to a rulemaking proceeding at the ACC. TEP cannot predict the outcome of this proposal or the impact on the Company's financial position or results of operations.
Navajo Generating Station
In 2017, the Navajo Nation approved a land lease extension which allows TEP and the co-owners of Navajo to continue operations through Decemberretired the generation station in November 2019 and beginbegan decommissioning activities. TEP expects the majority of decommissioning activities thereafter. We areto be completed by 2024 with monitoring activities continuing through 2054. TEP is currently recovering Navajothe capital and operating costs in base rates using a useful life through 2030. As a result of 2030 for Navajo. Due to the planned early retirement, TEP requested recovery of final retirement costs over a 10-year period in the 2019 Rate Case. As of December 31, 2019, the net book value of Navajo $52was $42 million, of the facility's NBV, andwith estimated other related costs were reclassified from Utility Plant, Net to Regulatory Assets on the Consolidated Balance Sheets as of December 31, 2017. We plan to seek recovery of all unrecovered costs in our next ACC rate case. $4 million.
See Note 2 and Note 3 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K, for additional information related toregarding the planned early retirement of Navajo.
Sundt Generating Station
In 2017,2018, the Pima County Department of Environmental Quality approved TEP's air permit. Under the air permit, TEP submitted an Applicationis allowed to place in service 10 RICE units. TEP placed in service five of the PDEQ relatedRICE units in December 2019, and the remaining five are scheduled to a generation modernization project at Sundt.be placed in service in the first quarter of 2020. In conjunction withaddition, TEP was required to retire Sundt Units 1 and 2 in November 2019. TEP is currently recovering the project, TEP will discontinue operationcapital and operating costs in base rates using useful lives of 2028 and 2030 of Sundt Units 1 and 2, byrespectively. Due to the end of 2020. As a result of the planned early retirement, $31 millionTEP requested recovery of final retirement costs over a 10-year period in the facilities' NBV was reclassified from Utility Plant, Net to Regulatory Assets on the Consolidated Balance Sheets as2019 Rate Case. As of December 31, 2017. We plan to seek recovery2019, the net book value of all unrecoveredSundt Units 1 and 2 was $26 million, with estimated other related costs in our next ACC rate case. See Note 2 for additional information regarding the 2017 Rate Order.of $1 million.
Under the project outlined in the Application, TEP will invest in 190 MW of RICE generators scheduled for commercial operation between June 2019 through March 2020. The RICE generatorsunits are expected to balance the variability of intermittent renewable energy resources and will replace 162 MW of nominal net generatinggeneration capacity from Sundt Units 1 and 2, which arewere less efficient and lacklacked the quick start, fast ramp capabilities of the RICE generators. units.
See Note 2 and Note 3 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K, for additional information related toregarding the planned early retirement of Sundt Units 1 and 2.
Gila River Generating Station
In 2017, TEP entered into a 20-year Tollingtolling PPA with SRP to purchase and receive all 550 MW of capacity, power, and ancillary services from Gila River Unit 2, which included a three-year option to purchase the unit (Tolling PPA). TEP’s obligations underTEP completed the Tolling PPA are contingent upon SRP's acquisitionpurchase of Gila River Units 1 and 2. In October 2017, SRP entered into a separate agreement with a third party to acquire Gila River Units 1 and 2 that is expected to be completed by March 2018 (Gila Acquisition). If the Gila Acquisition is terminated for any reason, either TEP or SRP may terminate the Tolling PPA without cost or penalty by providing written notice to the other party. The Tolling PPA provides TEP with an option to purchase Gila River Unit 2 during a three-year period beginning onin December 2019 for $165 million. We have requested recovery of the date the Gila Acquisition is completed. TEP's purchase option price for Gila River Unit 2 is expectedpurchase in the 2019 Rate Case.
We expect the additional 550 MW of capacity, power, and ancillary services to be $165 million, but is dependent upon SRP's final purchase price. The Tolling PPAallow us to continue to move toward our long-term goal of resource diversification as it will replace coal-fired generation scheduledlost due to early retirements.
See Note 8 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K, for early retirementadditional information regarding the Tolling PPA.
Weather Patterns
Weather and provide near term opportunities forother factors cause seasonal fluctuations in the sales intoof power. TEP's summer peaking load occurs during the wholesale market.
Long-Term Wholesale Sales
Navopache Electric Cooperative
In January 2017, a new long-term contract between TEP and NEC became effective. The contract expires atthird quarter of the endyear when cooling demand is higher, which results in higher revenue during such period. By contrast, lower sales of 2041. TEP served 80%power occur during the first quarter of NEC’s load requirementsthe year, due to mild winter weather in 2017 and expects to serve 100% beginning in 2018. In 2017, revenues fromour retail service territory. Seasonal fluctuations affect the NEC contract accounted for 8%comparability of total Wholesale Revenues on the Consolidated Statementsour results of Income.operations.
Interest Rates
See Part II, Item 7A. Quantitative and Qualitative Disclosures about Market Risk of this Form 10-K for information regarding interest rate risks and its impact on earnings.
RESULTS OF OPERATIONS
Significant drivers of TEP's results of operations that do not have a significant impact on net income include:
| |
| • | Cost Recovery Mechanisms — TEP records operating revenue related to cost recovery mechanisms that allow for more timely recovery of fuel and purchase power costs and certain operations and maintenance costs between rate case proceedings. These mechanisms, which include PPFAC, REST and DSM, are generally reset annually through separate filings with the ACC. See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information on cost recovery mechanisms. |
| |
| • | Short-Term Wholesale Sales — Revenues related to short-term wholesale sales are primarily related to ACC jurisdictional generation assets and are returned to retail customers by offsetting revenues against fuel and purchased power costs eligible for recovery through the PPFAC cost recovery mechanism. |
| |
| • | Springerville Units 3 and 4 — Operations and maintenance expenses related to Springerville Units 3 and 4 are reimbursed by Tri-State, the lessee of Springerville Unit 3, and SRP, the owner of Springerville Unit 4, through participant billings recorded in Operating Revenues on the Consolidated Statements of Income. |
The following discussion provides the significant drivers that affected TEP's results of operations for the year ended 2019 compared to 2018 presented on a pre-tax basis.
Operating Revenues
TEP reported operating revenues of $1,418 million in 2019 compared with $1,433 million in 2018. The decrease of $15 million, or 1%, was primarily due to:
$37 million in lower fuel and purchase power recoveries as a result of lower PPFAC rates; and
$11 million in lower retail revenue primarily due to a decrease in customer usage related to unfavorable weather.
The decrease was partially offset by:
$24 million in higher participant billings related to Springerville Units 3 & 4;
$6 million in higher RES and DSM cost recoveries as a result of higher program expenses; and
$3 million in higher short-term wholesale sales.
The following table provides key statistics impacting operating revenues: |
| | | | | | | | | | | | | | |
| | Years Ended December 31, | | Increase (Decrease) | | Year Ended December 31, | | Increase (Decrease) |
| (kWh in millions) | 2019 | | 2018 | | Percent | | 2017 | | Percent |
Electric Sales (kWh) | | | | | | | | | |
| Retail Sales | 8,744 |
| | 8,900 |
| | (1.8 | )% | | 8,926 |
| | (0.3 | )% |
| Wholesale Sales, Long-Term | 490 |
| | 424 |
| | 15.6 | % | | 587 |
| | (27.8 | )% |
| Wholesale Sales, Short-Term | 7,257 |
| | 6,279 |
| | 15.6 | % | | 3,630 |
| | 73.0 | % |
| Total Electric Sales | 16,491 |
| | 15,603 |
| | 5.7 | % | | 13,143 |
| | 18.7 | % |
| | | | | | | | | | |
Average Revenue per kWh (Cents/kWh) | | | | | | | | | |
| Retail | 11.12 |
| | 11.48 |
| | (3.1 | )% | | 11.39 |
| | 0.8 | % |
| Wholesale | 3.13 |
| | 3.46 |
| | (9.5 | )% | | 3.21 |
| | 7.8 | % |
| | | | | |
|
| | | | |
| Total Retail Customers | 428,626 |
| | 425,044 |
| | 0.8 | % | | 422,366 |
| | 0.6 | % |
Operating Expenses
Fuel and Purchased Power Expense
TEP reported fuel and purchased power expense of $506 million in 2019 compared with $543 million in 2018. The decrease of $37 million, or 7%, was primarily due to:
$53 million in lower PPFAC recoveries primarily due to changes in the PPFAC rate and an increase in deferral of eligible costs.
The decrease was partially offset by:
$6 million in higher fuel expense primarily due to realized losses on hedging contracts resulting from lower natural gas prices;
$5 million in higher transmission costs primarily due to an increase in transmission purchases and increased transmission rates; and
$3 million in higher purchased power primarily due to an increase in volume.
The following table provides key statistics impacting fuel and purchase power: |
| | | | | | | | | | | | | | |
| | Years Ended December 31, | | Increase (Decrease) | | Year Ended December 31, | | Increase (Decrease) |
| (kWh in millions) | 2019 | | 2018 | | Percent | | 2017 | | Percent |
| Sources of Energy | | | | | | | | | |
| Coal-Fired Generation | 7,046 |
| | 7,208 |
| | (2.2 | )% | | 7,530 |
| | (4.3 | )% |
| Gas-Fired Generation | 7,714 |
| | 6,738 |
| | 14.5 | % | | 3,237 |
| | 108.2 | % |
| Utility-Owned Renewable Generation | 75 |
| | 82 |
| | (8.5 | )% | | 83 |
| | (1.2 | )% |
| Total Generation | 14,835 |
| | 14,028 |
| | 5.8 | % | | 10,850 |
| | 29.3 | % |
| Purchased Power, Non-Renewable | 1,709 |
| | 1,624 |
| | 5.2 | % | | 2,471 |
| | (34.3 | )% |
| Purchased Power, Renewable | 643 |
| | 652 |
| | (1.4 | )% | | 646 |
| | 0.9 | % |
| Total Generation and Purchased Power | 17,187 |
| | 16,304 |
| | 5.4 | % | | 13,967 |
| | 16.7 | % |
| (cents per kWh) | | | | | | | | | |
| Average Fuel Cost of Generated Power | | | | | | | | | |
| Coal | 2.46 |
| | 2.44 |
| | 0.8 | % | | 2.41 |
| | 1.2 | % |
Natural Gas (1) | 2.33 |
| | 2.54 |
| | (8.3 | )% | | 3.06 |
| | (17.0 | )% |
| Average Cost of Purchased Power | | | | | | | | | |
| Purchased Power, Non-Renewable | 4.09 |
| | 4.32 |
| | (5.3 | )% | | 3.78 |
| | 14.3 | % |
| Purchased Power, Renewable | 9.43 |
| | 9.41 |
| | 0.2 | % | | 9.49 |
| | (0.8 | )% |
| |
(1) | Includes realized gains and losses from hedging activity. |
Operations and Maintenance Expense
TEP reported operations and maintenance expense of $378 million in 2019 compared with $362 million in 2018. The increase of $16 million, or 4%, in 2019 was primarily due to:
$22 million in higher reimbursable maintenance expense related to Springerville Units 3 and 4; and
$3 million in higher expenses related to an increase in employee wages and benefits and outside services.
The increase was partially offset by $8 million in lower expense related to planned generation outages in 2018 not recurring in 2019.
Depreciation and Amortization Expense
Depreciation and amortization expense increased by $12 million, or 7%, in 2019 compared with 2018 primarily due to an increase in asset base.
Other Income (Expense)
TEP reported other expense of $62 million in 2019 compared with $57 million in 2018. The increase of $5 million, or 9%, in 2019 compared with 2018 was primarily due to:
$11 million in higher Gila River Unit 2 demand charges, which are recovered through the PPFAC and accounted for as finance lease interest expense; and
$10 million in higher interest expense related to debt issued in November 2018.
The increase was partially offset by:
$10 million in higher AFUDC due to an increase in construction projects; and
$8 million increase in the value of company-owned life insurance as a result of favorable market conditions.
Income Tax Expense
TEP reported income tax expense of $34 million in 2019 compared with $43 million in 2018. The decrease of $9 million, or 21%, in 2019 compared with 2018 was primarily due to:
$3 million in lower tax expense due to EDIT amortization true-ups related to the TCJA;
$3 million in AMT credits recognized in the first quarter of 2019 related to a revision in tax law guidance; and
$3 million in lower tax expense due to a decrease in earnings.
LIQUIDITY AND CAPITAL RESOURCES
Liquidity
Cash flows may vary during the year with cash flows from operations being typically the lowest in the first quarter of the year and highest in the third quarter due to TEP’s summer peaking load. We will use our revolving credit facilityagreements as needed to assist in fundingfund our business activities. We believe that we have sufficient liquidity under our revolving credit facilityagreements to meet short-term working capital needs and to provide credit enhancement as necessary under energy procurement and hedging agreements. The availability and terms under which TEP haswe have access to external financing depends on a variety of factors, including itsour credit ratings and conditions in the overallbank and capital markets.
| | | (in millions) | December 31, 2017 | December 31, 2019 |
| Cash and Cash Equivalents | $ | 38 |
| $ | 10 |
|
Amount Available under Revolving Credit Facility (1) | 215 |
| |
Amount Available under Credit Agreements (1) | | 310 |
|
| Total Liquidity | $ | 253 |
| $ | 320 |
|
| |
(1) | TEP's revolving credit facilityThe 2015 Credit Agreement provides for $250 million of revolving credit commitments and a Letter of Credit (LOC)LOC sublimit of $50 million. TEP requested and was granted two one-year extensions. The newmillion with a maturity date isof October 2022. The 2019 Credit Agreement provides for a $225 million term loan with a maturity date of December 2020. |
Future Liquidity Requirements
We expect to meet all of our financial obligations and other anticipated cash outflows for the foreseeable future. These obligations and anticipated cash outflows include, but are not limited toto: (i) dividend payments,payments; (ii) debt maturities,maturities; and (iii) obligations as detailedincluded in the Contractual Obligations and forecasted Capital Expenditures tablesbelow.
See Part III,II, Item 7A. Quantitative and Qualitative Disclosures about Market Risk for additional information regarding TEP's market risks and Note 67of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding TEP's financing arrangements.
Summary of Cash Flows
Effective December 31, 2017, TEP early adopted accounting guidance that requires entities to show the changes in the total of cash, cash equivalents, and restricted cash or restricted cash equivalents on the cash flow statement. The new accounting guidance is applied retrospectively affecting all periods presented. The table below incorporates the new accounting guidance and presents net cash provided by (used for) operating, investing and financing activities and its effect on cash, cash equivalents, and restricted cash:activities: | | | | Years Ended | | Increase (Decrease) | | Year Ended | | Increase (Decrease) | Years Ended | | Increase (Decrease) | | Year Ended | | Increase (Decrease) |
| (in millions) | 2017 | | 2016 | | Percent | | 2015 | | Percent | 2019 | | 2018 | | Percent | | 2017 | | Percent |
| Operating Activities | $ | 448 |
| | $ | 425 |
| | 5.4 | % | | $ | 365 |
| | 16.4 | % | $ | 414 |
| | $ | 457 |
| | (9.4 | )% | | $ | 448 |
| | 2.0 | % |
| Investing Activities | (392 | ) | | (373 | ) | | 5.1 | % | | (501 | ) | | (25.5 | )% | (654 | ) | | (433 | ) | | 51.0 | % | | (392 | ) | | 10.5 | % |
| Financing Activities | (50 | ) | | (69 | ) | | (27.5 | )% | | 120 |
| | * |
| 115 |
| | 79 |
| | 45.6 | % | | (50 | ) | | 258.0 | % |
| Net Increase (Decrease) | 6 |
| | (17 | ) | | * |
| | (16 | ) | | 6.3 | % | (125 | ) | | 103 |
| | * |
| | 6 |
| | * |
|
| Beginning of Period | 43 |
| | 60 |
| | (28.3 | )% | | 76 |
| | (21.1 | )% | 153 |
| | 50 |
| | 206.0 | % | | 43 |
| | 16.3 | % |
End of Period (1) | $ | 49 |
| | $ | 43 |
| | 14.0 | % | | $ | 60 |
| | (28.3 | )% | $ | 28 |
| | $ | 153 |
| | (81.7 | )% | | $ | 49 |
| | 212.2 | % |
* Not meaningful
| |
(1) | Calculated on rounded data and may not tiecorrespond exactly to amounts on the Consolidated Statements of Cash Flows. |
Operating Activities
2017 compared with 2016
In 2017, netNet cash flows provided by operating activities increaseddecreased by $23$43 million in 2019 compared with 20162018 primarily due to: (i) higher net incomea decrease in recovery of PPFAC costs as a result of changes in the PPFAC rate; (ii) a settlement payment for final mine reclamation settlement associated with the early retirement of Navajo; (iii) lower retail sales primarily due to a decrease in usage related to an increase in rates as approved in the 2017 Rate Order and an increase in residential usage due to favorableunfavorable weather; and (ii) $8 million in cash proceeds received in January 2017 from a settlement agreement.
The increase was partially offset by: (i) an ACC approved PPFAC credit that began returning a temporary over-collected PPFAC balance to customers in February 2017; (ii) $12.5 million received in September 2016 related to a settlement for operating costs of Springerville Unit 1 not occurring in 2017; and (iii)(iv) changes in working capital related to the timing of billing collections and payments.
See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K, 2017 Rate Order and Note 7, FERC Matters and Claims Related to Springerville Generating Station Unit 1 for additional information.
2016 compared with 2015
In 2016, net cash flows provided by operating activities increased by $60 million compared with 2015 primarily due to a:The decrease was partially offset by: (i) over-collected fuel and purchased power costs under the PPFAC mechanism; (ii)a decrease in cash paid for pension funding as a result of favorable market conditions; and other postretirement benefits funding; (iii) $12.5 million increase(ii) a decrease in cash proceedsamounts returned to customers through bill credits related to the settlement of operating costs related to Springerville Unit 1 incurred on behalf of the Third-Party Owners; and (iv) change in working capital related to the timing of billing collections and payments.
The increase was partially offset by an increase of $11 million in cash paid for incentive compensation in 2016 not occurring in 2015. As a result of the Fortis acquisition in 2014, payments scheduled to be paid in the first quarter of 2015 under the annual incentive compensation plan were accelerated and paid in the third quarter of 2014.TCJA.
Investing Activities
2017 compared with 2016
In 2017, netNet cash flows used for investing activities increased by $19$221 million in 2019 compared with 20162018 primarily due to an increase in cash paid for capital expenditures and forto: (i) the purchase of RECs.
See Note 6 of Notes to Consolidated Financial StatementsGila River Unit 2 in Part II, Item 8 of this Form 10-K for additional information on Springerville capital lease purchases.
2016 compared with 2015
In 2016, net cash flows used for investing activities decreased by $127 million compared with 2015 primarily due to a decrease in cash paid for capital expenditures including generation assets and construction costs in 2015 for a new 500kV transmission line not occurring in 2016.
The decrease was partially offset by: (i) cash proceeds received in 2015 from the sale of an undivided ownership interest in Springerville Coal Handling Facilities not occurring in 2016;December 2019; and (ii) an increase in cash paid in 2016payments for the purchase of RECs.Oso Grande project in 2019.
Financing Activities
2017 compared with 2016
In 2017, net cash flows used for financing activities decreased by $19 million compared with 2016 primarily due to an increase in proceeds borrowed, net of repayments, under our revolving credit facility. The decrease was partially offset by an increase in dividends paid to UNS Energy.
2016 compared with 2015
In 2016, netNet cash flows provided by financing activities decreasedincreased by $189$36 million in 2019 compared with 20152018 primarily due toto: (i) higher proceeds from credit facility borrowings, net of repayments; and (ii) a decrease in: (i)in cash dividend payments to UNS Energy. The increase was partially offset by lower proceeds received from the issuance of long-term debt, and term loans, net of repayments made; and (ii) equity contributions from UNS Energy. Proceeds received in 2015 were used to purchase or retire certain tax-exempt long-term debt. The decrease was partially offset by a decrease in cash paid in 2016, net of proceeds borrowed, under our revolving credit facilities.
See Note 6 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K, Debt Issuance and Redemption for additional information.repayments.
Sources of Liquidity
Short-Term Investments
Our short-term investment policy governs the investment of excess cash balances. We periodically review and update this policy in response to market conditions. As of December 31, 2017, TEP's2019, TEP had no short-term investments included highly-rated and liquid money market funds.investments.
Access to Revolving Credit FacilityAgreements
We have access to working capital through a revolvingour credit agreement with lenders. TEP expects that amountsagreements.
Amounts borrowed from the 2019 Credit Agreement were used (i) to complete the purchase of Gila River Unit 2 Generating Station; (ii) to make payments for the construction of the Oso Grande project; and (iii) for other general corporate purposes. As of December 31, 2019, there was $60 million available under the credit agreement2019 Credit Agreement. As of February 12, 2020, there were no amounts available under the 2019 Credit Agreement. Prepaid amounts under the 2019 Credit Agreement may not be reborrowed.
Amounts borrowed from the 2015 Credit Agreement will be used for working capital and other general corporate purposes and that LOCs will be issued from time to time to support energy procurement, hedging transactions, and hedging transactions.other business activities. As of December 31, 2017, $2152019, there was $250 million was available under the revolving credit commitments and LOC facility.2015 Credit Agreement. In January 2020, TEP delivered $12 million in LOCs pursuant to TEP taking ownership of Oso Grande under the build-transfer agreement. As of February 14, 2018, $23212, 2020, there was $173 million was available under the revolving credit commitments and LOC facility.2015 Credit Agreement.
For details
We are exposed to adverse changes in interest rates to the extent that we rely on variable rate financing.
See Note 67 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding our credit agreements.
Debt Financing
We use debt financing to meet a portion of our capital needs and lower our overall cost of capital. We are exposed to adverse changes in interest rates to the extent that we rely on variable rate financing. Our cost of capital is also affected by our credit ratings.
In 2016, the ACC issued an order granting TEP financing authority.authority (2016 Financing Authority). The order extends and expands the previous financing authority by: (i) extending authority from December 2016 to December 2020; (ii) increasing the outstanding long-term debt limitation from $1.7 billion to $2.2 billion; (iii) allowing parent equity contributions of up to $400 million; and (iv) continuing the interest rate hedging authority. As of February 12, 2020, our long-term debt was $1,614 million.
We anticipate raising additional capitalTEP will be submitting an application for a new financing authority with the ACC in the second halffirst quarter of 2018 to: (i) refinance tax-exempt local furnishing bonds that are subject to mandatory tender for purchase in November 2018; (ii) refinance callable tax-exempt pollution control bonds backed by an LOC which expires in February 2019; and (iii) ensure adequate revolving credit capacity. 2020.
TEP has, from time to time,
refinanced or repurchased portions of its outstanding debt before scheduled maturity. Depending on market conditions, TEPwe may refinance other debt issuances or make additional debt repurchases in the future.
In January 2015,November 2019, TEP purchased $130 millionredeemed at par a series of fixed rate tax-exempt bonds with an aggregate principal amount of unsecured$15 million prior to the maturity of the bonds.
We anticipate issuing long-term debt in 2020 to: (i) refinance the borrowings under the 2019 Credit Agreement; (ii) redeem tax-exempt Industrial Development Revenue Bonds issued in June 2008 by the Industrial Development Authority of Pima County, Arizonabonds; (iii) make payments for the benefitconstruction of TEPthe Oso Grande project; and the bonds were not remarketed. The multi-modal bonds had an original maturity date of September 2029. In September 2017 the bonds were retired.(iv) for general corporate purposes.
Credit Ratings
Credit ratings affect our access to capital markets and supplemental bank financing. In April 2017,As of December 31, 2019, credit ratings from S&P Global Ratings upgraded TEP’s credit rating onand Moody’s Investors Service for our senior unsecured debt towere A- from BBB+. As of December 31, 2017, the credit rating remained unchanged. As of December 31, 2017, Moody’s Investors Service credit ratings for TEP’s senior unsecured debt was A3.and A3, respectively.
TEP'sOur credit ratings are dependent on a number of factors, both quantitative and qualitative, and are subject to change at any time. The disclosure of these credit ratings is not a recommendation to buy, sell, or hold TEP securities. Each rating should be evaluated independently of any other ratings.
Certain of TEP's debt agreements contain pricing based on TEP’sour credit ratings. A change in TEP’s credit ratings can cause an increase or decrease in the amount of interest TEP payswe pay on itsour borrowings, and the amount of fees it payswe pay for its LOCs and unused commitments.
Debt Covenants
Under certain agreements, should TEP fail to maintain compliance with covenants, lenders could accelerate the maturity of all amounts outstanding. As of December 31, 2017,2019, TEP was in compliance with these covenants.
We do not have any provisions in any of our debt or lease agreements that would cause an event of default or cause amounts to become due and payable in the event of a credit rating downgrade.
ContributionContributions from Parent
TEP received noUNS Energy made equity contributions to TEP of $50 million in 20172019 and 2016.2018. The proceeds provided additional liquidity to TEP. In January 2020, UNS Energy made an equity contribution to TEP of $180 million in 2015.$125 million. The contributionsproceeds were used in part for the construction of the Oso Grande project.
In 2020, we expect to repay revolving credit loans, redeem bonds,receive additional equity contributions from UNS Energy. The proceeds are expected to be used for: (i) investments in generation, transmission, and provide additional liquidity to TEP.distribution assets; and (ii) general corporate purposes.
Dividends Paid to Parent
TEP declared and paid $70$75 million in dividends to UNS Energy in 20172019 and $50$85 million in 2016 and 2015.2018.
Master Trading Agreements
TEP conducts its wholesale marketing and risk management activities under certain master trading agreements. Under these agreements, TEP may be required to post credit enhancements in the form of cash or an LOCLOCs due to exposures exceeding unsecured credit limits provided to TEP, changes in contract values, changes in TEP’s credit ratings, or material changes in TEP’s creditworthiness. As of December 31, 2017,2019, TEP had posted no$2 million cash or LOCs as a credit enhancementsenhancement with one of its counterparties. As of February 12, 2020, there was no collateral posted.
Capital Expenditures
TEP's routine capital expenditures include funds used for customer growth, system reinforcement, replacements and betterments, and costs to comply with environmental rules and regulations. In 2017,2019, total capital expenditures of $346$608 million includedincluded: (i) the purchase of an additional 17.8% undivided interestGila River Unit 2 in Springerville Common Facilities.December 2019; (ii) payments for Oso Grande; and (iii) other investments in generation, transmission, and distribution assets. In 2016,2018, total capital expenditures of $335$393 million included the purchase of the remaining ownership interestinvestments in Springerville Unit 1. In 2015, total capital expenditures of $500 million, included the purchase of an undivided ownership interest in Springerville Unit 1 and the remaining ownership interest in the Springerville Coal Handling Facilities.
We expect capital requirements to increase in 2018 and 2019 to reflect our investment in generatinggeneration assets and an enhanced metering and distribution network. Capital requirements are expected to level off from 2020 through 2022 as we focus on sustaining operations and renewable energy.
Our forecasted capital expenditures presented below for years ended December 31 exclude amounts for AFUDC and other non-cash items: | | | (in millions) | 2018 | | 2019 | | 2020 | | 2021 | | 2022 | 2020 | | 2021 | | 2022 | | 2023 | | 2024 |
| Generation Facilities: | | | | | | | | | | | | | | | | | | |
Renewable Energy | $ | 11 |
| | $ | 18 |
| | $ | 5 |
| | $ | 108 |
| | $ | — |
| $ | 346 |
| | $ | 31 |
| | $ | — |
| | $ | — |
| | $ | — |
|
Other Generation Facilities | 163 |
| | 284 |
| | 79 |
| | 75 |
| | 51 |
| 198 |
| | 64 |
| | 38 |
| | 63 |
| | 47 |
|
| Total Generation Facilities | 174 |
| | 302 |
| | 84 |
| | 183 |
| | 51 |
| 544 |
| | 95 |
| | 38 |
| | 63 |
| | 47 |
|
Transmission and Distribution | 194 |
| | 184 |
| | 202 |
| | 167 |
| | 152 |
| 291 |
| | 356 |
| | 319 |
| | 270 |
| | 145 |
|
General and Other (1)(4) | 99 |
| | 88 |
| | 67 |
| | 96 |
| | 65 |
| 138 |
| | 122 |
| | 60 |
| | 53 |
| | 49 |
|
| Total Capital Expenditures | $ | 467 |
| | $ | 574 |
| | $ | 353 |
| | $ | 446 |
| | $ | 268 |
| $ | 973 |
| | $ | 573 |
| | $ | 417 |
| | $ | 386 |
| | $ | 241 |
|
| |
(1) | Includes investments in renewable energy that will allow us to continue to move toward our long-term strategy of shifting to a more diverse, sustainable energy portfolio. In January 2020, TEP made a payment of $226 million for Oso Grande under the build-transfer agreement. |
| |
(2) | Includes the commitment to purchase Springerville Common Facilities. |
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(3) | Includes investments in transmission capacity and system reinforcements. |
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(4) | Includes cost for information technology, fleet, facilities, and communication equipment. |
These estimates are subject to continuing review and adjustment. Actual capital expenditures may differ from these estimates due to fluctuations in business and market conditions, construction schedules, possible early plant closures, changes in generation resources, environmental requirements, state or federal regulations, new or changing commitments, and other factors. We expect to pay for forecasted capital expenditures with internally generated funds and external financings, which may include issuances of long-term debt, other borrowings, or other borrowings.equity contributions.
Contractual Obligations
The following table summarizes our material contractual obligations as of December 31, 2017:2019: | | | | | | Payments Due by Period | | | Payments Due by Period |
| (in millions) | Total | | Less than 1 Year | | 1-3 Years | | 3-5 Years | | More than 5 Years | Total | | Less than 1 Year | | 1-3 Years | | 3-5 Years | | More than 5 Years |
| Long-Term Debt |
| | | | | | | | |
| | | | | | | | |
Principal (1) | $ | 1,466 |
| | $ | 100 |
| | $ | 117 |
| | $ | 250 |
| | $ | 999 |
| $ | 1,614 |
| | $ | 80 |
| | $ | 250 |
| | $ | 150 |
| | $ | 1,134 |
|
Interest (2) | 650 |
| | 60 |
| | 115 |
| | 95 |
| | 380 |
| 943 |
| | 71 |
| | 122 |
| | 100 |
| | 650 |
|
Capital Lease Obligations (3) | 42 |
| | 12 |
| | 30 |
| | — |
| | — |
| |
Operating Leases (4) | 8 |
| | 1 |
| | 2 |
| | 2 |
| | 3 |
| |
Land Easements and Rights-of-Way (5) | 89 |
| | 1 |
| | 3 |
| | 3 |
| | 82 |
| |
Leases (3)(4) | | 86 |
| | 18 |
| | 68 |
| | — |
| | — |
|
| Purchase Obligations: |
| | | | | | | | |
| | | | | | | | |
Fuel, Including Transportation (6) | 549 |
| | 82 |
| | 156 |
| | 67 |
| | 244 |
| |
Fuel, Including Transportation (5) | | 455 |
| | 94 |
| | 101 |
| | 66 |
| | 194 |
|
| Purchased Power | 29 |
| | 29 |
| | — |
| | — |
| | — |
| 8 |
| | 8 |
| | — |
| | — |
| | — |
|
| Transmission | 59 |
| | 19 |
| | 27 |
| | 5 |
| | 8 |
| 63 |
| | 21 |
| | 30 |
| | 6 |
| | 6 |
|
Renewable Purchase Power Agreements (7) | 985 |
| | 64 |
| | 127 |
| | 126 |
| | 668 |
| |
RES Performance-Based Incentives (8) | 83 |
| | 8 |
| | 15 |
| | 14 |
| | 46 |
| |
Acquisition of Springerville Common Facilities (9) | 68 |
| | — |
| | — |
| | 68 |
| | — |
| |
Other Long-Term Liabilities: (10) (11) |
| | | | | | | | | |
| Restricted and Performance-Based Stock Units | 8 |
| | 2 |
| | 6 |
| | — |
| | — |
| |
Renewable Power Purchase Agreements (6) | | 857 |
| | 63 |
| | 126 |
| | 125 |
| | 543 |
|
RES Performance-Based Incentives (7) | | 69 |
| | 8 |
| | 14 |
| | 14 |
| | 33 |
|
Land Easements and Rights-of-Way (8) | | 87 |
| | 1 |
| | 3 |
| | 4 |
| | 79 |
|
Build-Transfer Agreement (9) | | 338 |
| | 338 |
| | — |
| | — |
| | — |
|
Other Long-Term Liabilities: (10)(11) | |
| | | | | | | | |
| RSU and PSU | | 12 |
| | 5 |
| | 7 |
| | — |
| | — |
|
Pension and Other Postretirement Benefits (12) | 78 |
| | 17 |
| | 12 |
| | 13 |
| | 36 |
| 74 |
| | 19 |
| | 12 |
| | 12 |
| | 31 |
|
| Total Contractual Obligations | $ | 4,114 |
| | $ | 395 |
| | $ | 610 |
| | $ | 643 |
| | $ | 2,466 |
| $ | 4,606 |
| | $ | 726 |
| | $ | 733 |
| | $ | 477 |
| | $ | 2,670 |
|
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(1) | $37 million of TEP’s variable rate bonds are backed by an LOC issued pursuant to the 2010 Reimbursement Agreement, which expires in February 2019. Although the variable rate bond matures in 2032, the above table reflects a redemption or repurchase of such bond in February 2019 as though the LOC terminates without replacement upon expiration of the 2010 Reimbursement Agreement. TEP's 2013 tax-exempt variable rate Industrial Development Revenue Bonds (IDRB), which have an aggregate principal amount of $100 million and mature in 2032, are subject to mandatory tender for purchase in November 2018. The bonds |
were reclassified to Current Maturities of Long-Term Debt on the Consolidated Balance Sheets in 2017. Total long-term debt is not reduced by $10 million of related unamortized debt issuance costs or $2 million of unamortized original issue discount.
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(2)
| Excludes interest on revolving credit facilities and includes interest on TEP's 2013 tax-exempt IDRBs through the end of the current five-year term. |
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(2) | Excludes interest on credit agreements. |
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(3) | TEP leases an interest in Springerville Common Facilities, land, rail cars, and communication tower space with remaining terms up to 22 years. In December 2019, TEP exercised its option to purchase the interests in the Springerville Common Facilities by January 2021, the expiration date of the leases, for $68 million. See Note 8 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding our leases. |
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(4) | Effective with commercial operation of Springerville Unit 3 in July 2006 and Unit 4 in December 2009, Tri-State and SRP began reimbursingreimburse TEP for various operating costs related to the common facilitiesSpringerville Common Facilities, on an ongoing basis. The common facilities include assets leased by TEP at Springerville. TEP was reimbursed for $9$6 million of operating costs in 20172019 by SRP and Tri-State related to the Springerville Common Facilities and expectsdoes not expect any material changes to be reimbursed $8 million of operating coststhe reimbursement amount in 2018. Capital Lease Obligations do2020. The obligation balance does not reflect any reduction associated with thisthe reimbursement. Our capital lease obligation balances decline over time as scheduled capital lease payments are made by TEP. |
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(4)
| Primarily represents leases for land, rail cars, and office facilities with varying terms, provisions, and expiration dates through 2036. |
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(5) | Have varying terms and provisions and reflect expiration dates through 2054. In November 2017, the Navajo Nation approved an extension for the use of their land that commences in December 2019 and ends in December 2054. The Navajo Nation has until December 2018 to select one of five different rental payments options provided for in the extension. The table above includes TEP's 7.5% ownership share of the option which, in management's opinion, is most probable to occur. The total obligation estimated under this option is $8 million commencing in 2019 through 2053. See Note 7 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding Land Easements and Rights-of-Way. |
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(6)
| Excludes TEP’s liability for final mine reclamation costs related to coal mines that supply generation facilities, in which TEP has an ownership interest but does not operate, as the timing of payments has not been determined. In January 2018, TEP entered into a transportation agreement with EPNG to extend the expiration date of the existing agreement from April 2018 to April 2023. Estimated future payments not included in the table above are: $4 million in 2018; $5 million in 2019 through 2022; and $1 million through the end of the contract. See Note 79 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding TEP’s share of reclamation costs. |
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(7)(6)
| TEP enters into long-term renewable PPAs which require TEP to purchase 100% of certain renewable energy generation facilitiesfacilities' output once commercial operation status is achieved. While TEP is not required to make payments under these contracts if power is not delivered, the table above includes estimated future payments based on expected power deliveries. See Note 79 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding PPAs. |
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(8)(7)
| TEP has entered into REC purchase agreements to purchase the environmental attributes from retail customers with solar installations. Payments for the RECs are termed Performance-Based Incentives (PBI)PBI and are paid in contractually agreed upon intervals (usually quarterly) based on metered renewable energy production. See Note 79 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding PBIs. |
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(9)(8)
| In December 2017, TEP purchased one of the Springerville Common Facilities Leases that had an initial term ending December 2017. The remaining two leases have an initial term ending January 2021, subject to optional renewal periods of two or more years. TEP may renew the two leases or exercise its remaining fixed-price purchase options.Have varying terms and provisions and reflect expiration dates through 2054. See Note 69 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding Springerville Common Facilities Leases.Land Easements and Rights-of-Way. |
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(9) | TEP entered into an agreement to develop a wind-powered electric generation facility with costs of $384 million. See Note 9 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding the Build-Transfer Agreement. |
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(10) | Excludes Asset Retirement Obligations (ARO)AROs of $46$107 million expected to occur through 2044.2048. |
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(11) | Excludes unrecognized tax benefits of $13$18 million. At this time, we are unable to make a reasonably reliable estimate of the timing of payments in individual years in connection with these tax liabilities. |
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(12) | Represents TEP’s expected contributions to pension plans in 2018,2020, expected benefit payments for its unfunded Supplemental Executive Retirement Plan (SERP),SERP, and expected other postretirement benefit costs to cover medical and life insurance claims as determined by the plans’ actuaries. Due to the significant impact that returns on plan assets and changes in discount rates might have on payment obligation amounts, other contributions beyond 20182020 are excluded. |
Off-Balance Sheet Arrangements
Other than the unrecorded contractual obligations in the table above, we do not have any arrangements or relationships with entities that are not consolidated into the financial statements.
Income Tax Position
Tax legislation previously in effect included provisions that made qualified property placed in service starting in 2010 eligible for bonus depreciation forTEP did not make any U.S. federal or Arizona state income tax purposes. In addition, the IRS had issued guidance relatedpayments during 2019 due to the treatment of expenditures to maintain, replace, or improve property. These provisions were an acceleration of tax benefits we otherwise would have received over 20 years and createdexisting net operating loss and tax credit carryforwards that could have been used to offset future taxable income. As a result, we didin those jurisdictions. Based on its remaining tax carryforward balances, the Company does not pay any federal or state income taxes in 2017. Under the TCJA, we will not be eligible for bonus depreciation
for property placed in service after 2017, which will accelerate utilization of net operating loss carryforwards. We offset net operating loss carryforwards against taxable income and do not expect to makeanticipate making U.S. federal or state income tax payments until 2020.of a material nature for the next several years.
In December 2017, the ACC opened a docket requesting that all regulated utilities submit proposals to address passing the benefits ofUnder the TCJA, AMT credit carryforwards will either be refunded or TEP will use them to offset U.S. federal income tax liabilities through the Company's 2021 tax year. TEP received an AMT credit refund of $14 million in 2019, and will receive $7 million in 2020, and $3 million each in 2021 and 2022. Alternatively, TEP will utilize those amounts to customers. Any decrease in rates charged to customers related tooffset U.S. federal tax liabilities that would otherwise result through the TCJA would have a negative impact on TEP's operating cash flows. On February 6,Company's 2021 tax year.
In 2018, the ACC ordered utilitiesRefund Order was approved effective May 1, 2018. The refund amount, after the EDIT amortization true-up, totaled $33 million, which was passed back to file within 60 days either: (i)customers through a bill credit in 2018. Customer bill credits are trued-up annually to reflect actual kWh sales and EDIT amortization. We filed an application for a tax adjustor mechanism; (ii) an intent to file a rate case within 90 days; or (iii) any other application to address the effects of the TCJA. TEP expects to file a tax adjustor proposal with the ACC prior to establish the deadline.2019 customer refund of $33 million, of which 75% was passed back to customers through a bill credit in 2019. TEP cannot predictfiled an application with the outcomeACC to establish a 2020 customer refund of these proceedings or$35 million. We will continue to return savings to customers through a combination of a bill credit and a regulatory liability. The customer bill credit will account for 50% of the impact onreturned savings in 2020 and through the Company's financial position or resultscompletion of operations.our next rate case. The portion of savings not returned through a bill credit will be deferred as a regulatory liability and returned to customers through our next rate case, which was filed in April 2019.
See Note 14 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding the TCJA.
Environmental Matters
The EPA regulates the amount of SO2, NOx, CO2, particulate matter, mercury, and other by-products produced by generation facilities. We may incur additional costs to comply with future changes in federal and state environmental laws, regulations, and permit requirements at itsour generation facilities. Environmental laws and regulations are subject to a range of interpretations, which may ultimately be resolved by the courts. Because these laws and regulations continue to evolve, we are unable to predict the impact of the changing laws and regulationsthey may have on itsour operations and consolidated financial results. Complying with these changes may reduce operating efficiency and increase capital and operating costs. See Note 9 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information on the Broadway-Pantano site.
We capitalized $33$4 million in 2017, $402019 and $9 million in 2016, and $33 million in 20152018 in costs incurred to comply with environmental rules and regulations. In addition, we recorded environmental compliance related operations and maintenance expenses of $5 million in 2017 and2019, $6 million in 2016 and 2015. We expect capital expenditures of $9 million in 2018, and do not$5 million in 2017. We expect environmental compliance related capital expenditures to be materialof $3 million in 2020, $1 million in years 20192021 through 2022.2023, and $2 million in 2024. TEP will request recovery from its customers of the costs of environmental compliance through cost recovery mechanisms and Retail Rates.
Regional Haze RulesRegulations
The EPA's Regional Haze Rules requirerule requires emission controls known as Best Available Retrofit Technology (BART) forreductions from certain industrial facilities emitting air pollutants that reduce visibility in national parks and wilderness areas. The rule calls for all states to establish goals and emission reduction strategies for improving visibility.visibility in these areas. States must submit these goals and strategies to the EPA for approval. Because Navajo and Four Corners are located on land leased from the Navajo Nation, they are not subject to state oversight; the EPA oversees regional haze planning for these generation facilities.
In the western United States, Regional Haze BART determinations have focused on controls for NOx, often resulting in a requirement to install Selective Catalytic Reduction (SCR). The BART provisions do not apply to Springerville Units 1 and 2 since they were constructedapproval in the 1980s, afterform of a State Implementation Plan (SIP), and must review and submit revisions to the time frame as designated by the rules. Other provisions of the Regional Haze Rules requiring further emission reductions are not likely to impact Springerville operations until after 2021. SIP on a periodic basis.
In December 2016, the EPA signed a final rule entitled "Protection of Visibility: Amendments to Requirements for State Plans." Amongthat, among other things, changed the rule changes thesubmittal date for submittal of the next Regional Haze implementation planSIP revisions from 2018 to 2021. The ADEQ began to develop a control strategy with a focus on making reasonable progress
toward the national visibility goal. In July 2019, the ADEQ notified TEP that Springerville and Sundt had been selected for potential emissions controls evaluation.
TEP will work with the ADEQ to prepare and submit the evaluations. Based on recentcurrent Regional Haze requirement time-frames, TEP anticipates that impacts, if any, to Springervillethe facilities will likely occur three to five years after the 2021 planSIP submittal date. TEP cannot predict the ultimate outcome of these matters.
Sundt Generating Station
TEP permanently eliminated coal as a fuel sourcematters at Sundt to comply with a EPA ruling related to BART.
Four Corners Generating Station
In December 2013, APS, on behalf of the co-owners of Four Corners, notified the EPA that they have chosen an alternative BART compliance strategy. As a result, APS closed Units 1, 2, and 3 in December 2013 and agreed to install SCR on Units 4 and 5. TEP owns 7% of Four Corners Units 4 and 5. TEP's estimated share of NOx emissions control costs to comply with the rules is $44 million in capital expenditures and $2 million in annual operations and maintenance expenses. The SCR projects are scheduled to be completed by July 2018.
Navajo Generating Station
In August 2014, the EPA published a final Federal Implementation Plan (FIP) which provides that one unit at Navajo will be shut down by 2020, SCR or the equivalent will be installed on the remaining two units by 2030, and conventional coal-fired generation will cease by December 2044. The final BART rule includes options that accommodate potential ownership changes at the facility. The facility has until December 2019 to notify the EPA of how it will comply with the FIP.
In June 2017, the Navajo Nation approved a land lease extension which allows TEP and the co-owners of Navajo to continue operations through December 2019 and begin decommissioning activities thereafter. As a result of the early retirement of Navajo, TEP and the co-owners will no longer be responsible for implementing the FIP. See Note 1 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information related to the early retirement of Navajo.
San Juan Generating Station
In October 2014, the EPA published a final rule approving a revised State Implementation Plan (SIP) covering BART requirements for San Juan, which included: (i) the closure of Units 2 and 3 by December 2017; and (ii) the installation of Selective Non-Catalytic Reduction (SNCR) on Units 1 and 4. TEP owns 50% of Units 1 and 2. PNM, the operator of San Juan, completed the installation of SNCR in February 2016 and ceased operations at Units 2 and 3 in December 2017.
In 2017, TEP applied excess depreciation reserves against the unrecovered NBV as approved in the 2017 Rate Order. See Note 2 and Note 3 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K foradditional information on the early retirement of San Juan Unit 2.time.
Greenhouse Gas Regulation
In August 2015, the EPA issued the CPPClean Power Plan (CPP) limiting CO2 emissions from existing and new fossil fueledfuel-based generation facilities. The CPP establishes state-level CO2 emission rates and mass-based goals that apply to fossil fuel-firedfuel-based generation. The plan targets CO2 emissions reductions for existing facilities by 2030 and establishes interim goals that begin in 2022.
In October 2017,June 2019, the EPA issued a proposal to repealrepealed the CPP, and in December 2017,replaced it with the EPA issued an Advance Notice of Proposed Rulemaking (ANPRM) soliciting information about the intent to replace the CPP with aACE rule, establishing new emissions guidelines. The new rule rebalances the roles between the states and the EPA. Under the new rule, the EPA would set emission guidelines based on the Best System of Emission Reduction (BSER) for GHG emissions. The BSER for GHG emissions from existing coal-fired generation facilities is defined as heat-rate (efficiency) improvements that can be applied at the source. The states would then use these emission guidelines to establish state performance standards, considering source specific factors such as the remaining useful life of an individual unit.
Effective September 2019, states will have three years to submit plans to the EPA establishing performance standards. The EPA has 12 months to act on a complete state submittal. If a state plan is not approved, or a state fails to submit a plan within the allotted three years, the EPA would have two years to issue a federal plan.
Legal challenges to the rule could delay the effectiveness and implementation of the new rule. TEP does not anticipate a material impact to its generation facilities at this time as a result of the rule. TEP will continue to work with the other Arizona and New Mexico utilities, as well as the appropriate regulatory agencies, to develop appropriate responses to the EPA's proposals and compliance strategies as needed. TEP is unable to determine the impact to its facilities until all legal challenges have been resolved and any new regulations have been promulgated.
Coal Combustion Residuals Regulation
In April 2015, the EPA issued a final rule requiring disposal of coal ash and other coal combustion residualsCCR to be managed as a solid waste under Subtitle D of the Resource Conservation and Recovery Act (RCRA Subtitle D)RCRA for disposal in landfills and/or surface impoundments. We estimate ourOur share of costs to comply at Four Corners is estimated to be $2$3 million, at Springerville. Thethe majority of the costs arewhich is expected to be capital expenditures associated with site preparation and installation of the groundwater monitoring well system. We also expect to incur additional operating costs for on-going groundwater monitoringTEP and eventual site closure activities. Similarly, we currently estimate our sharethe co-owners of costs to be $5 million at Four Corners, $3 million at Navajo and less than $1 million at San Juan,retired the majority of which are capital expenditures.generation station in November 2019.
In December 2016, Congress approved the Water Infrastructure Improvements for the Nation (WIIN) Act, which authorizes the States to establish permit programs under RCRA Subtitle D for implementing regulation for Coal Combustion Residuals (CCR).CCR. In response to the WIIN Act and RCRA rulemaking petitions, the EPA has indicated that it intends to conduct two phases of CCR rule revisions. In July 2018, the EPA signed a Phase 1, Part 1 final rule which: (i) revised groundwater protection standards for rule-specific constituents without maximum containment levels; (ii) incorporated risk-based changes under an EPA-approved state permit program or an EPA permit program; and (iii) extended certain closure deadlines. In response to challenges to this rule, the EPA filed a motion to voluntarily remand the rule but not vacate it. On March 13, 2019, the U.S. Court of Appeals for the D.C. Circuit Court issued an order granting the EPA's motion, allowing the EPA nine months to undertake new rulemaking. In August 2019, the EPA issued the Phase 2 rule revision proposal. TEP is currently working with other affected utilities anddoes not anticipate a material impact on operations or financial results from the Arizona Department of Environmental Quality to explore the possibility of developing a State administered program to enforce CCR regulation.
See Capital Expenditures above for TEP's forecasted environmental compliance costs.anticipated proposed rule revisions.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of financial statements in accordance with GAAP requires management to apply accounting policies and to make estimates and assumptions that affect results of operations and the amounts of assets and liabilities reported in the financial statements and related notes. Management believes that the areas described below require significant judgment in the application of accounting policy or in making estimates and assumptions that are inherently uncertain and that may change in subsequent periods. Additional information on TEP’s other significant accounting policies can be found in Note 1 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K.
Accounting for Regulated Operations
We account for our regulated electric operations in accordance with accounting standards that allow the actions of our regulators, the ACC, and the FERC to be reflected in our financial statements. Regulator actions may cause us to capitalize certain costs that would be included as an expense, or in Accumulated Other Comprehensive Income (AOCI),AOCI, in the current period by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in Retail Rates or in rates charged to wholesale customers through transmission tariffs. Regulatory liabilities
generally represent expected future costs that have already been collected from customers or amounts that are expected to be returned to customers through billing reductions in future periods. We evaluate regulatory assets and liabilities each period and believe future recovery or settlement is probable. Our assessment includes consideration of recent rate orders, historical regulatory treatment of similar costs, and changes in the regulatory and political environment. If management's assessment is ultimately different than actual regulatory outcomes, the impact on our results of operations, financial position, and future cash flows could be material.
As of December 31, 2017,2019, regulatory liabilities net of regulatory assets onin the balance sheet totaled $218$108 million. There are no current or expected proposals or changes in the regulatory environment that impact our ability to apply accounting guidance for regulated operations. If we conclude, in a future period, that our operations no longer meet the criteria in this guidance, we would reflect our pension and other postretirement plan regulatory pension assets or liabilities in AOCI and recognize the impact of other regulatory assets and liabilities in the income statement, bothstatement. The impact of whichthis change would be material to our financial statements. See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding regulatory matters.
Accounting for Asset Retirement Obligations
GAAP requires us to record the fair value of a liability for a legal obligation to retire a long-lived tangible asset in the period in which the liability is incurred. This includes obligations resulting from conditional future events. We incur legal obligations as a result of environmental regulations imposed by State and Federal regulators, contractual agreements, and other factors. To estimate the liability, management must use judgment and assumptions in: determining whether a legal obligation exists to remove assets; estimating the probability of a future event for a conditional obligation; estimating the fair value of the cost of removal; estimating when final removal will occur; and estimating the credit-adjusted risk-free interest rates to be used to discount the future liabilities. Changes that may arise over time with regard to these assumptions and determinations will change amounts recorded in the future as expense for AROs. TEP primarily defers costs associated with its legal AROs as regulatory assets because these costs are included in depreciation rates approved for recovery by the ACC. Deferred costs are amortized over the life of the underlying asset.
TEP identified legal obligations to retire generation facilities specified in land leases for its jointly-owned Navajo and Four Corners facilities. These stations reside on land leased from the Navajo Nation. The provisions of the leases require the lessees to remove the facilities upon request of the Navajo Nation at expiration of the leases. TEP also has certain environmental obligations at Luna, San Juan, Sundt and Springerville. TEP estimates that its share of the AROs to remove the Navajo and Four Corners facilities and settle the Luna, San Juan, Sundt, Gila River, and Springerville environmental and contractual obligations will be approximately $155 million at the retirement dates. Additionally, TEP entered into land lease agreements or land easement agreements with certain land owners for the installation of PV assets. The provisions of the PV land leases or land easements require TEP to remove the PV facilities upon expiration of the agreements. In addition, TEP is required to dispose or recycle the PV assets under the Resource Conservation and Recovery Act. TEP's ARO related to the PV assets is estimated to be approximately $31 million at the retirement dates. No other legal obligations to retire generation plant assets have been identified.
TEP has various transmission and distribution lines that operate under land easements and rights-of-way that contain end dates and may contain site restoration clauses. TEP operates transmission and distribution lines as if they will be operated in perpetuity and will continue to be used or sold without land remediation. As such, there are no AROs for these assets.
The total net present value of TEP's ARO liability was $46 million as of December 31, 2017. ARO liabilities are reported in Regulatory and Other Liabilities—Other on the Consolidated Balance Sheets. See Note 3 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding AROs.
Additionally, the authorized depreciation rates for TEP include a component designed to accrue the future costs of retiring assets for which no legal obligations exist. The accumulated balances as of December 31, 2017, represent non-legal ARO accruals, less actual removal costs incurred, net of salvage proceeds realized, and are recorded as a regulatory liability on the balance sheet. See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding future cost of removal.
Pension and Other Postretirement Benefit Plan Assumptions
TEP records the underfunded amount for its pension and other postretirement obligations as a liability and a regulatory asset to reflect expected recovery of pension and other postretirement obligations through the rates charged to retail customers. As the funded status, discount rates, and actuarial facts change, the liability may vary significantly in future years. Key assumptions used include:
discount rates used to determine obligations;
expected returns on plan assets;
compensation increases;
mortality assumptions; and
healthcare cost trend rates.
Discount Rates
As of December 31, 2017, TEP discounted its future pension plan obligations at 3.7% and its other postretirement plan obligations at a rate of 3.6%. The discount rate for future pension plan and other postretirement plan obligations is determined annually based on the rates currently available on high-quality, non-callable, long-term bonds. The discount rate is based on a corporate yield curve using an average yield between the 60th and 90th percentile of AA-graded U.S. corporate bonds with future cash flows that match the timing and amount of expected future benefit payments.
Expected Returns on Plan Assets
To establish the expected return on assets assumption, TEP reviews the asset allocation and develops return assumptions for each asset class based on advice from an investment consultant and the pension’s actuary that includes both historical performance analysis and forward-looking views of the financial markets. As of December 31, 2017, TEP assumed that its pension plans’ assets would generate a long-term rate of return of 7%.
Compensation Increases
As of December 31, 2017, TEP used a rate of compensation increase of 2.75% to measure pension obligations.
Mortality
The RP-2014 mortality table projected with improvement scale MP-2017 with 15-year convergence and 0.75% long-term rate was utilized to measure the December 31, 2017 pension obligations, whereas improvement scales MP-2016 was utilized for the December 31, 2016 measurement.
Healthcare Cost Trend Rates
TEP used a current year healthcare cost trend rate of 7.6% in valuing its other postretirement benefit obligation as of December 31, 2017. This rate reflects both market conditions and historical experience.
Sensitivity Analysis
The table below shows the effect on TEP's 2017 expense and obligation of a 100 basis point change to its assumptions: |
| | | | | | | | | | | | | | | |
| | Effect on Expense | | Effect on Obligation |
| | Increase | | Decrease | | Increase | | Decrease |
| (in millions) | December 31, 2017 |
| Change to Pension | | | | | | | |
| Discount Rate | $ | (6 | ) | | $ | 7 |
| | $ | (65 | ) | | $ | 83 |
|
| Long-Term Rate of Return on Plan Assets | (4 | ) | | 4 |
| | N/A |
| | N/A |
|
| Change to Other Postretirement Benefits | | | | | | | |
| Discount Rate | — |
| | 1 |
| | (8 | ) | | 10 |
|
| Long-Term Rate of Return on Plan Assets | — |
| | — |
| | N/A |
| | N/A |
|
| Healthcare Cost Trend Rate | 1 |
| | (1 | ) | | 7 |
| | (6 | ) |
In 2018, TEP will incur pension costs of approximately $10 million and other postretirement benefit costs of approximately $6 million. TEP expects to charge approximately $16 million of these costs to operations and maintenance expense, $4 million to capital, and $4 million as a reduction of other expense. TEP expects to make pension plan contributions of $11 million in 2018. In 2018, TEP expects to make benefit payments to retirees under the retiree benefit plan of approximately $5 million and contributions to the Voluntary Employee Beneficiary Association (VEBA) trust of approximately $1 million, net of distributions.
SeeNote 8 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for further details regarding TEP's pension plan and other postretirement benefit plan expenses and obligations.
Accounting for Derivative Instruments and Hedging Activities
Commodity Derivative Contracts
TEP enters into forward contracts to purchase or sell capacity or energy at contract prices over a given period of time, typically for one month, three months, or one year, within established limits to meet forecasted load requirements or to take advantage of favorable market opportunities. In general, TEP enters into forward purchase contracts when market conditions provide the opportunity to purchase energy for its load at prices that are below the marginal cost of its supply resources or to supplement its own resources (e.g., during plant outages and summer peaking periods). TEP enters into forward sales contracts when it forecasts that it will have excess supply and the market price of energy exceeds its marginal cost. TEP enters into forward gas commodity price swap agreements to lock in fixed prices on a portion of forecasted gas purchases and to hedge the price risk associated with forward PPAs that are indexed to natural gas prices.
For all commodity derivative instruments that do not meet the normal purchase or normal sale scope exception, we recognize derivative instruments as either assets or liabilities on the balance sheet and measure those instruments at fair value. Unrealized gains and losses on commodity derivative contracts entered into for retail customer load are recorded as either a regulatory asset or regulatory liability on the balance sheet based on our ability to recover the costs of hedging activities entered into to mitigate energy price risk for retail customers. There are no current or expected proposals or changes in the regulatory environment that impact the probability of future recovery of these assets through the PPFAC mechanism.
The market prices used to determine fair values for TEP’s derivative instruments as of December 31, 2017, are estimated based on various factors including broker quotes, exchange prices, over the counter prices, and time value.
TEP manages the risk of counterparty default by performing financial credit reviews, setting limits, monitoring exposures, requiring collateral when needed, and using a standardized agreement, which allows for the netting of current period exposures to and from a single counterparty.
Interest Rate Swaps
TEP hedges the cash flow risk associated with unfavorable changes in the variable interest rates tied to London Interbank Offered Rate (LIBOR) on the Springerville Common Facilities lease. As of December 31, 2017, approximately $18 million of variable rate lease debt for the Springerville Common Facilities lease had been hedged through an amortizing interest rate swap expiring in January 2020.
Revenue Recognition
TEP’s retail revenues, which are recognized in the period that electricity is delivered and consumed by customers, include unbilled revenue based on an estimate of kWh delivered at the end of each period. Unbilled revenues are dependent upon a number of factors that require management’s judgment, including estimates of retail sales and customer usage patterns. The unbilled revenue is estimated by comparing the estimated kWh delivered to the kWh billed to our retail customers. The excess of estimated kWh delivered over kWh billed is allocated to the retail customer classes based on estimated usage by each customer class. We then record revenue for each customer class based on the various Retail Rates for each customer class. Due to the seasonal fluctuations of TEP’s actual load, unbilled revenues increase during the spring and summer and decrease during the fall and winter. A provision for uncollectible accounts, associated with retail revenues, is recorded as a component of operations and maintenance expense.
Income Taxes
Due to the differences between GAAP and income tax laws, many transactions are treated differently for income tax purposes than they are in the financial statements. We account for this difference by recording deferred income tax assets and liabilities using the effective income tax rate as of our balance sheet date. TEP records income tax liabilities based on TEP's taxable income as reported in the consolidated tax return of FortisUS.
A valuation allowance is established against deferred tax assets for which management believes it is more likely than not that the deferred asset will not be realized. In making this judgment, management evaluates all available evidence and gives more weight to objective verifiable evidence. TEP recorded no valuation allowance as of December 31, 2019. See Note 14 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding income taxes.
Plant Asset Depreciable Lives
TEP has significant investments in electric generation assets and electric transmission and distribution assets. We calculate depreciation expense based on our estimate of the useful lives of our plant assets and expected net removal costs. The useful lives of plant assets are further detailed in Note 3 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K. Changes to depreciation estimates resulting from a change of estimated service life or removal costs could have a significant impact on the amount of depreciation expense recorded in the income statement. The ACC approves depreciation
rates for all generation and distribution assets. Depreciation rates for such assets cannot be changed without the ACC's approval. TEP's transmission assets are subject to the jurisdiction of the FERC. See Note 1 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding depreciation rates.
Accounting for Asset Retirement Obligations
TableGAAP requires us to record the fair value of Contentsa liability for a legal obligation to retire a long-lived tangible asset in the period in which the liability is incurred. This includes obligations resulting from conditional future events. We incur legal obligations as a result of environmental regulations imposed by state and federal regulators, contractual agreements, and other factors. To estimate the liability, management must use judgment and assumptions in determining or estimating: (i) whether a legal obligation exists to remove assets; (ii) the probability of a future event for a conditional obligation; (iii) the fair value of the cost of removal; (iv) when final removal will occur; and (v) the credit-adjusted risk-free interest rates to be used to discount the future liabilities. Changes that may arise over time with regard to our judgment and assumptions will change amounts recorded in the future as expense for AROs. When a new obligation is recorded, the cost of the liability is capitalized by increasing the carrying amount of the related long-lived asset and subsequently amortized over the life of the underlying asset. Accretion of the liability and amortization of the associated asset are deferred as regulatory assets because these costs are expected to be recovered through depreciation rates.
Income Taxes
DueTEP identified legal obligations to retire generation facilities specified in land leases for its jointly-owned Navajo and Four Corners facilities. These stations reside on land leased from the Navajo Nation. The provisions of the leases require the lessees to remove the facilities upon request of the Navajo Nation at expiration of the leases. TEP also has certain environmental obligations at Gila River, Luna, San Juan, Sundt and Springerville. TEP estimates that its share of the AROs to remove the Navajo and Four Corners facilities and settle the Luna, San Juan, Sundt, Gila River, and Springerville environmental and contractual obligations will be approximately $220 million at the retirement dates. Additionally, TEP entered into land lease agreements or land easement agreements with certain landowners for the installation of PV assets. The provisions of the PV land leases or land easements require TEP to remove the PV facilities upon expiration of the agreements. In addition, TEP is required to properly dispose or recycle the PV assets under RCRA. We estimated our ARO related to the differences between GAAPPV assets to be approximately $19 million at the retirement dates. We have identified no other legal obligations to retire generation plant assets.
TEP has various transmission and income tax laws, many transactionsdistribution lines that operate under land easements and rights-of-way that contain end dates and may contain site restoration clauses. TEP operates transmission and distribution lines as if they will be operated in perpetuity and will continue to be used or sold without land remediation. As such, there are treated differentlyno AROs for income tax purposes than they are in the financial statements. We account for this difference by recording deferred income tax assets and liabilities using the effective income tax rate asthese assets.
The total net present value of our balance sheet date. TEP records income tax liabilities basedARO liability recorded in Other on TEP's taxable income as reported in the consolidated tax return of FortisUS, Inc., a Fortis intermediate holding company (FortisUS).
A valuation allowance is established against deferred tax assets for which management believes it is more likely than not that the deferred asset will not be realized. In making this judgment, management evaluates all available evidence and gives more weight to objective verifiable evidence. TEP recorded no valuation allowanceConsolidated Balance Sheets was $107 million as of December 31, 2017.2019. See Note 123 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding AROs.
Additionally, ACC approved depreciation rates for TEP include a component designed to accrue the future costs of retiring assets for which no legal obligations exist. The accumulated balances are recorded as a regulatory liability and represent non-legal estimated cost of removal accruals, less actual removal costs incurred, net of salvage proceeds realized. See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding future net cost of removal.
Pension and Other Postretirement Benefit Plan Assumptions
TEP records the underfunded amount for its pension and other postretirement obligations as a liability. Amounts not yet recognized in the income taxes.statement are recorded as a regulatory asset or liability to reflect expected recovery or refund of pension and other postretirement obligations through rates charged to retail customers. As the funded status, discount rates, and actuarial facts change, the liability may vary significantly in future years. Key assumptions used include:
discount rates used to determine obligations;
expected returns on plan assets;
compensation increases;
mortality assumptions; and
healthcare cost trend rates.
Discount Rates
As of December 31, 2019, TEP discounted its future pension plan obligations at 3.6% and its other postretirement plan obligations at a rate of 3.3%. The discount rate for future pension plan and other postretirement plan obligations is determined annually based on the rates currently available on high-quality, non-callable, long-term bonds. The discount rate is based on a corporate yield curve using an average yield between the 60th and 90th percentile of AA-graded U.S. corporate bonds with future cash flows that match the timing and amount of expected future benefit payments.
Expected Returns on Plan Assets
To establish the expected return on assets assumption, TEP reviews the asset allocation and develops return assumptions for each asset class based on advice from an investment consultant and the pension’s actuary that includes both historical performance analysis and forward-looking views of the financial markets. As of December 31, 2019, TEP assumed that its pension plans’ assets would generate a long-term rate of return of 6.75%.
Compensation Increases
As of December 31, 2019, TEP used a rate of compensation increase of 2.8% to measure pension obligations.
Mortality
The PRI-2012 mortality table projected with improvement scale MP-2019 with 15-year convergence and a 0.75% long-term rate was utilized to measure the December 31, 2019 pension obligations, whereas RP-2014 mortality table projected with improvement scale MP-2018 was utilized for the December 31, 2018 measurement.
Healthcare Cost Trend Rates
TEP used a current year healthcare cost trend rate range between 6.3% and 7.5% in valuing its other postretirement benefit obligation as of December 31, 2019. This rate reflects both market conditions and historical experience.
Sensitivity Analysis
The table below shows the effect on TEP's expense and obligation of a 100 basis point change to its assumptions as of December 31, 2019: |
| | | | | | | | | | | | | | | |
| | Effect on Expense | | Effect on Obligation |
| (in millions) | Increase | | Decrease | | Increase | | Decrease |
| Change to Pension | | | | | | | |
| Discount Rate | $ | (6 | ) | | $ | 7 |
| | $ | (71 | ) | | $ | 89 |
|
| Long-Term Rate of Return on Plan Assets | (4 | ) | | 4 |
| | N/A |
| | N/A |
|
| Change to Other Postretirement Benefits | | | | | | | |
| Discount Rate | — |
| | — |
| | (8 | ) | | 10 |
|
| Long-Term Rate of Return on Plan Assets | — |
| | — |
| | N/A |
| | N/A |
|
| Healthcare Cost Trend Rate | 1 |
| | (1 | ) | | 7 | | (6 | ) |
In 2020, TEP will incur pension costs of $11 million and other postretirement benefit costs of $4 million. TEP expects to record: (i) $16 million to operations and maintenance expense; (ii) $4 million to capital; and (iii) $5 million to other income. In 2020, TEP expects to make: (i) pension plan contributions of $11 million; (ii) benefit payments to retirees under the retiree benefit plan of $5 million; and (iii) contributions to the VEBA trust of $1 million, net of distributions.
See Note 10 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for further details regarding TEP's pension plan and other postretirement benefit plan expenses and obligations.
Accounting for Derivative Instruments and Hedging Activities
Commodity Derivative Contracts
TEP enters into forward contracts to purchase or sell capacity or energy at contract prices over a given period of time, typically for one month, three months, one year, or three years, within established limits to meet forecasted load requirements or to take advantage of favorable market opportunities. In general, TEP enters into forward purchase contracts when market conditions provide the opportunity to purchase energy for its load at prices that are below the marginal cost of its supply resources or to
supplement its own resources (e.g., during plant outages and summer peaking periods). TEP enters into forward sales contracts when it forecasts that it will have excess supply, and the market price of energy exceeds its marginal cost. TEP enters into forward gas commodity price swap agreements to lock in fixed prices on a portion of forecasted natural gas purchases and to hedge the price risk associated with forward PPAs that are indexed to natural gas prices.
For all commodity derivative instruments that do not meet the normal purchase or normal sale scope exception, we recognize derivative instruments as either assets or liabilities in the balance sheet and measure those instruments at fair value. Unrealized gains and losses on commodity derivative contracts entered into for retail customer load are recorded as either a regulatory asset or liability in the balance sheet based on our ability to recover the costs of hedging activities entered into to mitigate energy price risk for retail customers. There are no current or expected proposals or changes in the regulatory environment that impact the probability of future recovery of these assets through the PPFAC mechanism.
The market prices used to determine fair values for TEP’s derivative instruments as of December 31, 2019, are estimated based on various factors including broker quotes, exchange prices, over the counter prices, and time value.
TEP manages the risk of counterparty default by performing financial credit reviews, setting limits, monitoring exposures, requiring collateral when needed, and using a standardized agreement, which allows for the netting of current period exposures to and from a single counterparty.
RECENTLYNEW ACCOUNTING STANDARDS ISSUED ACCOUNTING PRONOUNCEMENTSAND NOT YET ADOPTED
For a discussion of new accounting pronouncements affecting TEP, see Note 131 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K.
ITEM 7A.7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
TEP’s financial statements are exposed to certain market risks whichthat can impactaffect asset and liability fair value, results of operations, and cash flows. TEP's significant market risks are primarily associated with interest rates, commodity and coal prices, and extension of credit to counterparties. TEP may enter into interest rate swaps and financing transactions to manage changes in interest rates. TEP has a Risk Management CommitteeRMC responsible for the oversight of commodity price risk and credit risk related to wholesale energy marketing and power procurement activities. To limit TEP’s exposure to commodity price risk, the Risk Management CommitteeRMC sets trading and hedging policies and limits, which are reviewed frequently to respond to constantly changing market conditions. To limit TEP’s exposure to credit risk, the Risk Management CommitteeRMC reviews counterparty credit exposure as well as credit policies and limits.
See Forward-Looking Information for additional information.limits on a regular basis.
Interest Rate Risk
Long-Term Debt
TEP is exposed to interest rate risk resulting from changes in interest rates on certain variable rate debt obligations. TEP had $137 million in tax-exempt variable rate debt outstanding as of December 31, 2017. The outstanding debt included one series of bonds for which interest rates are reset weekly and one series of bonds for which interest rates are reset monthly. The weighted average weekly rate (including LOC fees and remarketing fees) was 1.76% in 2017 and 1.33% in 2016. The average weekly interest rate ranged from 1.53% - 2.68% in 2017 and 0.93% - 1.76% in 2016. The monthly rate is based on a percentage of an index equal to one-month LIBOR plus a credit spread. The average monthly rate was 1.41% in 2017 and 1.01% in 2016. The monthly rate ranged from 1.08% - 1.58% in 2017 and 0.83% - 1.08% in 2016.
TEP is subject to volatility in its tax-exempt variable rate debt. A 100 basis point increase in average interest rates on this debt, over a twelve-month period, would result in a decrease in TEP’s pre-tax net income of approximately $1 million.
TEP had $21 million of variable rate debt outstanding related to the Springerville Common Facilities capital lease obligation as of December 31, 2017. TEP has one fixed-for-floating interest rate swap in place to hedge the floating interest rate risk associated with a portion of the capital lease obligation. The notional amount of the swap was $18 million as of December 31, 2017.
Interest Rate Swap
To adjust the value of TEP’s interest rate swap, classified as a cash flow hedge, to fair value in Other Comprehensive Income, TEP recorded the following net unrealized gains: |
| | | | | | | | | | | |
| (in millions) | 2017 | | 2016 | | 2015 |
| Net Unrealized Gains | $ | 1 |
| | $ | 1 |
| | $ | 1 |
|
Credit FacilitiesAgreements
TEP is subject to interest rate risk resulting from changes in interest rates on borrowings under its credit agreement.agreements. The interest rate paid on borrowings is variable. RevolvingAmounts borrowed under the credit borrowingsagreements are made on either the basis of a spread over LIBOR or an Alternate Base Rate (ABR).ABR. As a result, TEP may experience significant volatility in the rates paid on LIBOR borrowings under its credit agreements.
The 2019 Credit Agreement is a 364-day credit agreement that provides for up to $225 million in term loans, which could be drawn in up to two drawings. As of December 31, 2019, TEP had borrowed $165 million under the 2019 Credit Agreement. As of February 12, 2020, TEP had borrowed $225 million under the 2019 Credit Agreement.
The 2015 Credit Agreement is scheduled to mature in October 2022 and provides for up to $250 million in credit borrowings. As of December 31, 2019, TEP had no revolving credit facilities.borrowings under the 2015 Credit Agreement. In January 2020, TEP delivered $12 million in LOCs pursuant to TEP taking ownership of Oso Grande under the build-transfer agreement. As of February 12, 2020, there was $173 million available under the 2015 Credit Agreement.
Commodity and Coal Price Risk
TEP is exposed to market fluctuations in electricity, natural gas, and coal prices as a result of its obligation to serve retail customer load in its regulated service territory and long-term wholesale contracts. TEP's load and generatinggeneration facilities represent substantial underlying commodity positions. ExposuresExposure to commodity prices consist mainlyprimarily of variations in the price of fuel required to generate electricity and wholesale electricity that is purchased and sold.sold in retail and wholesale markets. Commodity and coal prices may be subject to significant price changes as supply and demand are impacted by, among other unpredictable factors, weather, market liquidity, generatinggeneration facility availability, customer usage, storage, and transmission and transportation constraints. Under the guidance of the Risk Management Committee (RMC), TEP mitigates a portion of its commodity price risk through the use of commodity contracts, which include forwards, options,financial swaps, and other agreements, to effectively secure future supply, fix fluctuating commodity prices, or sell future production generally at fixed prices. TEP's exposure to commodity and coal price risk is limited by its ability to include these costs in regulated rates through its PPFAC mechanism, which is subject to review annually by the ACC. See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information related to the PPFAC mechanism.
Certain commodity contracts qualify as derivatives and are recorded at fair value. The changes in fair value of such contracts have a high correlation to price changes in the hedged commodities. The following table shows the changes in fair value of our derivative positions: | | | (in millions) | 2017 | | 2016 | | 2015 | 2019 | | 2018 | | 2017 |
| Unrealized Net Gain (Loss) Recorded to Regulatory (Assets) Liabilities | $ | (18 | ) | | $ | 12 |
| | $ | 6 |
| $ | (45 | ) | | $ | (9 | ) | | $ | (18 | ) |
TEP's derivative contracts mature on various dates through 2029. The table below displays the valuation methodologies and maturities of TEP’s derivative contracts by source of fair value: | | | | Unrealized Gain (Loss) of TEP’s Hedging Activities | Unrealized Gain (Loss) of TEP’s Hedging Activities |
| | Maturity 0 – 6 months | | Maturity 6 – 12 months | | Maturity over 1 yr. | | Total Unrealized Gain (Loss) | Maturity 0 – 6 months | | Maturity 6 – 12 months | | Maturity over 1 yr. | | Total Unrealized Gain (Loss) |
| (in millions) | December 31, 2017 | December 31, 2019 |
| Prices Actively Quoted | $ | — |
| | $ | (7 | ) | | $ | (8 | ) | | $ | (15 | ) | $ | (11 | ) | | $ | (13 | ) | | $ | (46 | ) | | $ | (70 | ) |
Sensitivity Analysis of Derivatives
TEP uses sensitivity analysis to measure the potential impact of favorable and unfavorable changes in market prices on the fair value of its derivative contracts. TEP records unrealized gains and losses as either a regulatory asset or regulatory liability. As contracts settle, the unrealized gains and losses are reversed and realized gains or losses are recorded to the PPFAC. For TEP's derivatives related to the purchase and sale of electricity,power, a 10% change in the market price of purchased power would affect unrealized positions reported as a regulatory asset or regulatory liability by approximately $1 million; for$7 million. For derivatives related to the natural gas price hedges, a 10% change in the market price of energy would affect unrealized positions reported as a regulatory asset or liability by approximately $38$25 million.
Coal Supply Agreements
TEP is subject to fuel price risk from changes in the price of coal used to fuel its coal-fired generation facilities. This risk is mitigated through the use of long-term coal supply agreements with limited price movement. CoalTEP's coal supply agreements expire from 2020 through 2031. TEP is currently negotiating its coal supply agreement scheduled to expire in 2020. TEP expects coal reserves from the supplying mines to be sufficient to fulfill the estimated requirements for each coal-fired generation facility's estimated remaining life. See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Liquidity and Capital Resources and Note 79 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information.
Credit Risk
TEP is exposed to credit risk in its energy-related marketing activities related to potential non-performance by counterparties. TEP manages the risk of counterparty default by performing financial credit reviews, setting limits, monitoring exposures,
requiring collateral when needed, and using standard agreements which allow for the netting of current period exposures to and from a single counterparty. Counterparty credit exposure is calculated by adding any outstanding receivable, (netnet of amounts payable if a netting agreement exists)exists, to the mark-to-market value of any forward contracts. If exposure exceeds credit limits or contractual collateral thresholds, weTEP may request that a counterparty provide credit enhancement in the form of cash collateral or an LOC.
TEP has entered into short-term and long-term transactions related to its wholesale marketing and gas hedging activities with various counterparties. As of December 31, 2017,2019, TEP’s total credit exposure was approximately $12$10 million. TEP had approximately $1$4 million of exposure to non-investment grade counterparties.
As of December 31, 2017,2019, TEP had $2 million of cash posted as collateral to provide credit enhancement to a counterparty. As of February 12, 2020, there was no cash collateral nor LOCs as credit enhancements with its counterparties, andposted. As of December 31, 2019, TEP holdsheld approximately $6$4 million in collateral from its wholesale counterparties.
ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Report of Independent Registered Public Accounting FirmREPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholder and the Board of Directors of
Tucson Electric Power Company
Tucson, AZArizona
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheetsheets of Tucson Electric Power Company and subsidiaries (the "Company") as of December 31, 2017,2019 and 2018, the related consolidated statements of income, comprehensive income, changes in stockholder’s equity, and cash flows, for each of the yearthree years in the period ended December 31, 2017,2019, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017,2019 and 2018, and the results of its operations and its cash flows for each of the yearthree years in the period ended December 31, 2017,2019, 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 |
| Deloitte & Touche LLP |
| Phoenix, Arizona |
February 15, 201812, 2020 |
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholder of Tucson Electric Power Company:
We have audited the accompanying consolidated balance sheets of Tucson Electric Power Companyserved as of December 31, 2016, and the related consolidated statements of income, comprehensive income, changes in stockholder’s equity and cash flows for each of the two years in the period ended December 31, 2016. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.auditor since 2017.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provided a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Tucson Electric Power Company at December 31, 2016, and the consolidated results of their operations and their cash flows for each of the two years in the period ended December 31, 2016, in conformity with U.S. generally accepted accounting principles.
|
|
/s/ Ernst & Young LLP |
Ernst & Young LLP |
Calgary, Canada |
February 16, 2017 |
TUCSON ELECTRIC POWER COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(Amounts in thousands)
| | | | Years Ended December 31, | Years Ended December 31, |
| | 2017 | | 2016 | | 2015 | 2019 | | 2018 | | 2017 |
| Operating Revenues | | | | | | $ | 1,418,338 |
| | $ | 1,432,618 |
| | $ | 1,340,935 |
|
| Retail | $ | 1,040,682 |
| | $ | 989,580 |
| | $ | 1,021,543 |
| |
| Wholesale | 174,742 |
| | 117,341 |
| | 167,020 |
| |
| Other | 125,511 |
| | 128,074 |
| | 117,981 |
| |
| Total Operating Revenues | 1,340,935 |
| | 1,234,995 |
| | 1,306,544 |
| |
| | | | | | | |
| Operating Expenses | | | | | | | | | | |
| Fuel | 285,551 |
| | 289,862 |
| | 305,559 |
| 358,394 |
| | 351,749 |
| | 285,551 |
|
| Purchased Power | 136,425 |
| | 85,354 |
| | 124,764 |
| 137,977 |
| | 134,914 |
| | 136,425 |
|
| Transmission and Other PPFAC Recoverable Costs | 36,239 |
| | 23,781 |
| | 24,798 |
| 52,261 |
| | 46,595 |
| | 36,239 |
|
| Increase (Decrease) to Reflect PPFAC Recovery Treatment | (32,660 | ) | | 21,064 |
| | 39,787 |
| (42,836 | ) | | 9,885 |
| | (32,660 | ) |
| Total Fuel and Purchased Power | 425,555 |
| | 420,061 |
| | 494,908 |
| 505,796 |
| | 543,143 |
| | 425,555 |
|
| Operations and Maintenance | 360,302 |
| | 353,905 |
| | 345,356 |
| 377,563 |
| | 361,963 |
| | 360,302 |
|
| Depreciation | 152,874 |
| | 146,097 |
| | 138,093 |
| 169,042 |
| | 158,310 |
| | 152,874 |
|
| Amortization | 22,255 |
| | 22,498 |
| | 19,261 |
| 27,706 |
| | 26,052 |
| | 22,255 |
|
| Taxes Other Than Income Taxes | 53,623 |
| | 49,303 |
| | 49,623 |
| 55,642 |
| | 55,006 |
| | 53,623 |
|
| Total Operating Expenses | 1,014,609 |
| | 991,864 |
| | 1,047,241 |
| 1,135,749 |
| | 1,144,474 |
| | 1,014,609 |
|
| | | | | | | |
| Operating Income | 326,326 |
| | 243,131 |
| | 259,303 |
| 282,589 |
| | 288,144 |
| | 326,326 |
|
| Other Income (Deductions) | | | | | | |
| Interest Income | 742 |
| | 111 |
| | 93 |
| |
| Other Income | 14,128 |
| | 5,636 |
| | 6,647 |
| |
| Other Expense | (3,344 | ) | | (3,019 | ) | | (2,833 | ) | |
| Appreciation (Depreciation) in Value of Investments | 2,791 |
| | 2,147 |
| | (142 | ) | |
| Total Other Income (Deductions) | 14,317 |
| | 4,875 |
| | 3,765 |
| |
| | | | | | | |
| Other Income (Expense) | | | | | | |
| Interest Expense | | | | | | (88,511 | ) | | (67,620 | ) | | (65,290 | ) |
| Long-Term Debt | 62,018 |
| | 62,015 |
| | 61,159 |
| |
| Capital Leases | 2,554 |
| | 3,356 |
| | 3,994 |
| |
| Other Interest Expense | 718 |
| | 531 |
| | 1,134 |
| |
| Interest Capitalized | (2,078 | ) | | (1,710 | ) | | (2,732 | ) | |
| Total Interest Expense | 63,212 |
| | 64,192 |
| | 63,555 |
| |
| Income Before Income Taxes | 277,431 |
| | 183,814 |
| | 199,513 |
| |
| Allowance For Borrowed Funds | | 5,744 |
| | 3,151 |
| | 2,078 |
|
| Allowance For Equity Funds | | 15,222 |
| | 8,117 |
| | 5,322 |
|
| Other, Net | | 5,524 |
| | (487 | ) | | 8,995 |
|
| Total Other Income (Expense) | | (62,021 | ) | | (56,839 | ) | | (48,895 | ) |
| | | | | | | |
| Income Before Income Tax Expense | | 220,568 |
| | 231,305 |
| | 277,431 |
|
| Income Tax Expense | 100,763 |
| | 59,376 |
| | 71,719 |
| 34,053 |
| | 42,982 |
| | 100,763 |
|
| Net Income | $ | 176,668 |
| | $ | 124,438 |
| | $ | 127,794 |
| $ | 186,515 |
| | $ | 188,323 |
| | $ | 176,668 |
|
The accompanying notes are an integral part of these financial statements.
TUCSON ELECTRIC POWER COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Amounts in thousands)
| | | | Years Ended December 31, | Years Ended December 31, |
| | 2017 | | 2016 | | 2015 | 2019 | | 2018 | | 2017 |
| Comprehensive Income | | | | | | | | | | |
| Net Income | $ | 176,668 |
| | $ | 124,438 |
| | $ | 127,794 |
| $ | 186,515 |
| | $ | 188,323 |
| | $ | 176,668 |
|
| Other Comprehensive Income | | | | | | |
| Other Comprehensive Income (Loss) | | | | | | |
| Net Changes in Fair Value of Cash Flow Hedges: | | | | | | | | | | |
| Net of Income Tax (Expense) Benefit of $(305), $(420), and $(821) | 485 |
| | 652 |
| | 1,261 |
| |
| Net of Income Tax (Expense) Benefit of $(44), $(121), and $(305) | | 133 |
| | 364 |
| | 485 |
|
| Supplemental Executive Retirement Plan Adjustments: | | | | | | | | | | |
| Net of Income Tax (Expense) Benefit of $637, $399, and $(63) | (2,156 | ) | | (643 | ) | | 101 |
| |
| Total Other Comprehensive Income, Net of Tax | (1,671 | ) | | 9 |
| | 1,362 |
| |
| Net of Income Tax (Expense) Benefit of $1,059, $(747), and $637 | | (3,190 | ) | | 2,026 |
| | (2,156 | ) |
| Total Other Comprehensive Income (Loss), Net of Tax | | (3,057 | ) | | 2,390 |
| | (1,671 | ) |
| Total Comprehensive Income | $ | 174,997 |
| | $ | 124,447 |
| | $ | 129,156 |
| $ | 183,458 |
| | $ | 190,713 |
| | $ | 174,997 |
|
The accompanying notes are an integral part of these financial statements.
TUCSON ELECTRIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in thousands)
| | | | Years Ended December 31, | Years Ended December 31, |
| | 2017 | | 2016 | | 2015 | 2019 | | 2018 | | 2017 |
| Cash Flows from Operating Activities | | | | | | | | | | |
| Net Income | $ | 176,668 |
| | $ | 124,438 |
| | $ | 127,794 |
| $ | 186,515 |
| | $ | 188,323 |
| | $ | 176,668 |
|
| Adjustments to Reconcile Net Income To Net Cash Flows from Operating Activities: | | | | | | |
| Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | | | |
| Depreciation Expense | 152,874 |
| | 146,097 |
| | 138,093 |
| 169,042 |
| | 158,310 |
| | 152,874 |
|
| Amortization Expense | 22,255 |
| | 22,498 |
| | 19,261 |
| 27,706 |
| | 26,052 |
| | 22,255 |
|
| Amortization of Debt Issuance Costs | 2,349 |
| | 2,853 |
| | 3,043 |
| 2,326 |
| | 2,339 |
| | 2,349 |
|
| Use of Renewable Energy Credits for Compliance | 25,453 |
| | 17,618 |
| | 19,731 |
| 37,141 |
| | 32,350 |
| | 25,453 |
|
| Deferred Income Taxes | 100,762 |
| | 59,367 |
| | 72,026 |
| 41,614 |
| | 56,066 |
| | 100,762 |
|
| Pension and Other Postretirement Benefits Expense | 16,039 |
| | 15,338 |
| | 18,588 |
| 17,762 |
| | 15,303 |
| | 16,039 |
|
| Pension and Other Postretirement Benefits Funding | (14,430 | ) | | (13,459 | ) | | (30,682 | ) | (16,749 | ) | | (26,673 | ) | | (14,430 | ) |
| Allowance for Equity Funds Used During Construction | (5,322 | ) | | (4,522 | ) | | (5,352 | ) | (15,222 | ) | | (8,117 | ) | | (5,322 | ) |
| FERC Transmission Refund Payable | (4,878 | ) | | 4,878 |
| | — |
| — |
| | — |
| | (4,878 | ) |
| Regulatory Deferral, ACC Refund Order | | 7,705 |
| | (1,562 | ) | | — |
|
| Changes in Current Assets and Current Liabilities: | | | | | | | | | | |
| Accounts Receivable | (13,219 | ) | | 7,809 |
| | (3,019 | ) | 9,238 |
| | (26,729 | ) | | (13,219 | ) |
| Materials, Supplies, and Fuel Inventory | 175 |
| | 7,627 |
| | (8,758 | ) | (16,236 | ) | | (2,357 | ) | | 175 |
|
| Regulatory Assets | (3,942 | ) | | (12,147 | ) | | 18,002 |
| (20,934 | ) | | (4,080 | ) | | (3,942 | ) |
| Other Current Assets | | (475 | ) | | (1,746 | ) | | (751 | ) |
| Accounts Payable and Accrued Charges | 9,790 |
| | 14,284 |
| | (13,917 | ) | (27,776 | ) | | 33,536 |
| | 9,790 |
|
| Income Taxes Receivable | | 6,072 |
| | (13,004 | ) | | — |
|
| Regulatory Liabilities | (20,227 | ) | | 18,012 |
| | 10,921 |
| (1,626 | ) | | 14,028 |
| | (20,227 | ) |
| Other, Net | 3,977 |
| | 14,777 |
| | (797 | ) | 8,140 |
| | 15,187 |
| | 4,728 |
|
| Net Cash Flows—Operating Activities | 448,324 |
| | 425,468 |
| | 364,934 |
| 414,243 |
| | 457,226 |
| | 448,324 |
|
| Cash Flows from Investing Activities | | | | | | | | | | |
| Capital Expenditures | (345,617 | ) | | (250,360 | ) | | (333,841 | ) | (607,593 | ) | | (392,522 | ) | | (345,617 | ) |
| Purchase, Springerville Coal Handling Facilities Lease Assets | — |
| | — |
| | (120,312 | ) | |
| Purchase, Springerville Unit 1 Assets | — |
| | (85,000 | ) | | (45,753 | ) | |
| Purchase Intangibles, Renewable Energy Credits | (51,179 | ) | | (40,949 | ) | | (29,184 | ) | (51,699 | ) | | (51,327 | ) | | (51,179 | ) |
| Proceeds from Sale, Springerville Coal Handling Facilities | — |
| | — |
| | 23,656 |
| |
| Contributions in Aid of Construction | 4,983 |
| | 3,432 |
| | 4,517 |
| 6,607 |
| | 10,817 |
| | 4,983 |
|
| Note Receivable | | (1,000 | ) | | — |
| | — |
|
| Net Cash Flows—Investing Activities | (391,813 | ) | | (372,877 | ) | | (500,917 | ) | (653,685 | ) | | (433,032 | ) | | (391,813 | ) |
| Cash Flows from Financing Activities | | | | | | | | | | |
| Proceeds from Borrowings, Revolving Credit Facility | 70,000 |
| | — |
| | 148,000 |
| — |
| | 171,000 |
| | 70,000 |
|
| Repayments of Borrowings, Revolving Credit Facility | (35,000 | ) | | — |
| | (233,000 | ) | — |
| | (206,000 | ) | | (35,000 | ) |
| Proceeds from Borrowings, Term Loan | — |
| | — |
| | 130,000 |
| 165,000 |
| | — |
| | — |
|
| Repayments of Borrowings, Term Loan | — |
| | — |
| | (130,000 | ) | |
| Proceeds from Issuance, Long-Term Debt | — |
| | — |
| | 299,019 |
| |
| Repayments, Long-Term Debt | — |
| | — |
| | (208,600 | ) | |
Proceeds from Issuance, Long-Term Debt—Net of Discount | | — |
| | 298,869 |
| | — |
|
| Repayments of Long-Term Debt | | (14,700 | ) | | (136,700 | ) | | — |
|
| Dividends Paid to Parent | (70,000 | ) | | (50,000 | ) | | (50,000 | ) | (75,000 | ) | | (85,000 | ) | | (70,000 | ) |
| Payments of Capital Lease Obligations | (15,571 | ) | | (14,079 | ) | | (13,464 | ) | |
| Payment of Debt Issuance/Retirement Costs | (245 | ) | | (183 | ) | | (3,942 | ) | |
| Payments of Finance Lease Obligations | | (10,890 | ) | | (10,930 | ) | | (15,571 | ) |
| Payment of Debt Issuance Costs | | (757 | ) | | (3,265 | ) | | (245 | ) |
| Contribution from Parent | — |
| | — |
| | 180,000 |
| 50,000 |
| | 50,000 |
| | — |
|
| Other, Net | 481 |
| | (4,871 | ) | | 1,458 |
| 1,514 |
| | 1,078 |
| | 481 |
|
| Net Cash Flows—Financing Activities | (50,335 | ) | | (69,133 | ) | | 119,471 |
| 115,167 |
| | 79,052 |
| | (50,335 | ) |
| Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash | 6,176 |
| | (16,542 | ) | | (16,512 | ) | (124,275 | ) | | 103,246 |
| | 6,176 |
|
| Cash, Cash Equivalents, and Restricted Cash, Beginning of Period | 43,325 |
| | 59,867 |
| | 76,379 |
| 152,747 |
| | 49,501 |
| | 43,325 |
|
| Cash, Cash Equivalents, and Restricted Cash, End of Period | $ | 49,501 |
| | $ | 43,325 |
| | $ | 59,867 |
| $ | 28,472 |
| | $ | 152,747 |
| | $ | 49,501 |
|
The accompanying notes are an integral part of these financial statements.
TUCSON ELECTRIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Amounts in thousands, except share data)
| | | | December 31, | December 31, |
| | 2017 | | 2016 | 2019 | | 2018 |
| ASSETS | | | | | | |
| Utility Plant | | | | | | |
| Plant in Service | $ | 5,780,805 |
| | $ | 5,975,139 |
| $ | 6,663,912 |
| | $ | 6,020,469 |
|
| Utility Plant Under Capital Leases | 84,870 |
| | 167,413 |
| |
| Utility Plant Under Finance Leases | | 151,467 |
| | 248,635 |
|
| Construction Work in Progress | 160,288 |
| | 129,955 |
| 303,488 |
| | 258,965 |
|
| Total Utility Plant | 6,025,963 |
| | 6,272,507 |
| 7,118,867 |
| | 6,528,069 |
|
| Accumulated Depreciation and Amortization | (2,193,656 | ) | | (2,385,053 | ) | (2,506,686 | ) | | (2,293,783 | ) |
| Accumulated Amortization of Capital Lease Assets | (63,605 | ) | | (104,648 | ) | |
| Accumulated Amortization of Finance Lease Assets | | (77,285 | ) | | (73,646 | ) |
| Total Utility Plant, Net | 3,768,702 |
| | 3,782,806 |
| 4,534,896 |
| | 4,160,640 |
|
| | | | | | | |
| Investments and Other Property | 51,260 |
| | 45,020 |
| 62,136 |
| | 50,952 |
|
| | | | | | | |
| Current Assets | | | | | | |
| Cash and Cash Equivalents | 37,701 |
| | 35,962 |
| 9,762 |
| | 138,114 |
|
| Accounts Receivable, Net | 137,932 |
| | 124,934 |
| 154,847 |
| | 172,367 |
|
| Fuel Inventory | 25,059 |
| | 25,887 |
| 23,731 |
| | 22,783 |
|
| Materials and Supplies | 103,981 |
| | 97,126 |
| 121,542 |
| | 107,990 |
|
| Regulatory Assets | 93,960 |
| | 56,340 |
| 138,412 |
| | 106,725 |
|
| Derivative Instruments | 3,187 |
| | 4,966 |
| 3,596 |
| | 3,929 |
|
| Other | 10,777 |
| | 13,793 |
| 21,416 |
| | 25,571 |
|
| Total Current Assets | 412,597 |
| | 359,008 |
| 473,306 |
| | 577,479 |
|
| Regulatory and Other Assets | | | | | |
|
| Regulatory Assets | 293,551 |
| | 225,453 |
| 326,860 |
| | 293,078 |
|
| Derivative Instruments | 8,826 |
| | 330 |
| 2,763 |
| | 8,402 |
|
| Other | 55,313 |
| | 37,372 |
| 89,196 |
| | 68,656 |
|
| Total Regulatory and Other Assets | 357,690 |
| | 263,155 |
| 418,819 |
| | 370,136 |
|
| Total Assets | $ | 4,590,249 |
| | $ | 4,449,989 |
| $ | 5,489,157 |
| | $ | 5,159,207 |
|
The accompanying notes are an integral part of these financial statements.
(Continued)
TUCSON ELECTRIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Amounts in thousands, except share data)
| | | | December 31, | December 31, |
| | 2017 | | 2016 | 2019 | | 2018 |
| CAPITALIZATION AND OTHER LIABILITIES | | | | | | |
| Capitalization | | | | | | |
| Common Stock Equity: | | | | | | |
| Common Stock (No Par Value, 75,000,000 Shares Authorized, 32,139,434 Shares Outstanding as of December 31, 2017 and 2016) | $ | 1,296,539 |
| | $ | 1,296,539 |
| |
| Common Stock (No Par Value, 75,000,000 Shares Authorized, 32,139,434 Shares Outstanding as of December 31, 2019 and 2018) | | $ | 1,396,539 |
| | $ | 1,346,539 |
|
| Capital Stock Expense | (6,357 | ) | | (6,357 | ) | (6,357 | ) | | (6,357 | ) |
| Retained Earnings | 380,076 |
| | 273,408 |
| 595,792 |
| | 484,277 |
|
| Accumulated Other Comprehensive Loss | (6,226 | ) | | (4,555 | ) | (7,771 | ) | | (4,714 | ) |
| Total Common Stock Equity | 1,664,032 |
| | 1,559,035 |
| 1,978,203 |
| | 1,819,745 |
|
| Preferred Stock (No Par Value, 1,000,000 Shares Authorized, None Outstanding as of December 31, 2017 and 2016) | — |
| | — |
| |
| Capital Lease Obligations | 28,519 |
| | 39,267 |
| |
| Preferred Stock (No Par Value, 1,000,000 Shares Authorized, None Outstanding as of December 31, 2019 and 2018) | | — |
| | — |
|
| Finance Lease Obligations | | 67,316 |
| | 19,773 |
|
| Long-Term Debt, Net | 1,354,423 |
| | 1,453,072 |
| 1,522,087 |
| | 1,615,252 |
|
| Total Capitalization | 3,046,974 |
| | 3,051,374 |
| 3,567,606 |
| | 3,454,770 |
|
| Current Liabilities | | | | | | |
| Current Maturities of Long-Term Debt | 100,000 |
| | — |
| 80,330 |
| | — |
|
| Borrowings Under Revolving Credit Facility | 35,000 |
| | — |
| |
| Capital Lease Obligations | 10,749 |
| | 51,765 |
| |
| Borrowings Under Credit Agreements | | 165,000 |
| | — |
|
| Finance Lease Obligations | | 17,086 |
| | 172,510 |
|
| Accounts Payable | 97,367 |
| | 89,797 |
| 136,465 |
| | 133,012 |
|
| Accrued Taxes Other than Income Taxes | 40,706 |
| | 37,639 |
| 42,741 |
| | 41,686 |
|
| Accrued Employee Expenses | 30,929 |
| | 29,465 |
| 32,567 |
| | 34,339 |
|
| Accrued Interest | 14,750 |
| | 14,508 |
| 16,700 |
| | 17,927 |
|
| Regulatory Liabilities | 89,024 |
| | 76,069 |
| 96,017 |
| | 95,094 |
|
| Customer Deposits | 24,865 |
| | 25,778 |
| 24,568 |
| | 27,650 |
|
| Derivative Instruments | 10,667 |
| | 2,641 |
| 27,615 |
| | 18,137 |
|
| Other | 18,119 |
| | 17,837 |
| 23,678 |
| | 21,555 |
|
| Total Current Liabilities | 472,176 |
| | 345,499 |
| 662,767 |
| | 561,910 |
|
| Regulatory and Other Liabilities | | | | | | |
| Deferred Income Taxes, Net | 300,258 |
| | 529,148 |
| 432,484 |
| | 369,705 |
|
| Regulatory Liabilities | 516,438 |
| | 300,700 |
| 477,495 |
| | 512,425 |
|
| Pension and Other Postretirement Benefits | 133,799 |
| | 131,630 |
| 133,452 |
| | 117,472 |
|
| Derivative Instruments | 17,907 |
| | 2,629 |
| 48,697 |
| | 19,361 |
|
| Other | 102,697 |
| | 89,009 |
| 166,656 |
| | 123,564 |
|
| Total Regulatory and Other Liabilities | 1,071,099 |
| | 1,053,116 |
| 1,258,784 |
| | 1,142,527 |
|
| | | | | | | |
| Commitments and Contingencies |
| |
|
| |
|
| | | | | | | |
| Total Capitalization and Other Liabilities | $ | 4,590,249 |
| | $ | 4,449,989 |
| $ | 5,489,157 |
| | $ | 5,159,207 |
|
The accompanying notes are an integral part of these financial statements.
(Concluded)
TUCSON ELECTRIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDER'S EQUITY
(Amounts in thousands)
| | | | Common Stock | | Capital Stock Expense | | Retained Earnings | | Accumulated Other Comprehensive Loss | | Total Stockholder's Equity | Common Stock | | Capital Stock Expense | | Retained Earnings | | Accumulated Other Comprehensive Loss | | Total Stockholder's Equity |
| Balances as of December 31, 2014 | $ | 1,116,539 |
| | $ | (6,357 | ) | | $ | 111,523 |
| | $ | (5,926 | ) | | $ | 1,215,779 |
| |
| Balances as of December 31, 2016 | | $ | 1,296,539 |
| | $ | (6,357 | ) | | $ | 273,408 |
| | $ | (4,555 | ) | | $ | 1,559,035 |
|
| Net Income | | | | | | 176,668 |
| | | | 176,668 |
|
| Other Comprehensive Loss, Net of Tax | | | | | | | | (1,671 | ) | | (1,671 | ) |
| Dividends Declared to Parent | | | | | | (70,000 | ) | | | | (70,000 | ) |
| Balances as of December 31, 2017 | | 1,296,539 |
| | (6,357 | ) | | 380,076 |
| | (6,226 | ) | | 1,664,032 |
|
| Net Income | | | | | 127,794 |
| | | | 127,794 |
| | | | | 188,323 |
| | | | 188,323 |
|
| Other Comprehensive Income, Net of Tax | | | | | | | 1,362 |
| | 1,362 |
| | | | | | | 2,390 |
| | 2,390 |
|
| Dividends Declared to Parent | | | | | (50,000 | ) | | | | (50,000 | ) | | | | | (85,000 | ) | | | | (85,000 | ) |
| Contribution from Parent | 180,000 |
| | | | | | | | 180,000 |
| 50,000 |
| | | | | | | | 50,000 |
|
| Balances as of December 31, 2015 | 1,296,539 |
| | (6,357 | ) | | 189,317 |
| | (4,564 | ) | | 1,474,935 |
| |
| Adoption of ASU, Cumulative Effect Adjustment | | | | | | 878 |
| | (878 | ) | | — |
|
| Balances as of December 31, 2018 | | 1,346,539 |
| | (6,357 | ) | | 484,277 |
| | (4,714 | ) | | 1,819,745 |
|
| Net Income | | | | | 124,438 |
| | | | 124,438 |
| | | | | 186,515 |
| | | | 186,515 |
|
| Other Comprehensive Income, Net of Tax | | | | | | | 9 |
| | 9 |
| |
| Other Comprehensive Loss, Net of Tax | | | | | | | | (3,057 | ) | | (3,057 | ) |
| Dividends Declared to Parent | | | | | (50,000 | ) | | | | (50,000 | ) | | | | | (75,000 | ) | | | | (75,000 | ) |
| Adoption of ASU, Cumulative Effect Adjustment | | | | | 9,653 |
| | | | 9,653 |
| |
| Balances as of December 31, 2016 | 1,296,539 |
| | (6,357 | ) | | 273,408 |
| | (4,555 | ) | | 1,559,035 |
| |
| Net Income | | | | | 176,668 |
| | | | 176,668 |
| |
| Other Comprehensive Income, Net of Tax | | | | | | | (1,671 | ) | | (1,671 | ) | |
| Dividends Declared to Parent | | | | | (70,000 | ) | | | | (70,000 | ) | |
| Balances as of December 31, 2017 | $ | 1,296,539 |
| | $ | (6,357 | ) | | $ | 380,076 |
| | $ | (6,226 | ) | | $ | 1,664,032 |
| |
| Contribution from Parent | | 50,000 |
| | | | | | | | 50,000 |
|
| Balances as of December 31, 2019 | | $ | 1,396,539 |
| | $ | (6,357 | ) | | $ | 595,792 |
| | $ | (7,771 | ) | | $ | 1,978,203 |
|
The accompanying notes are an integral part of these financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1.NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
TEP is a regulated utility that generates, transmits, and distributes electricity to approximately 422,000429,000 retail customers in a 1,155 square mile area in southeastern Arizona. TEP also sells electricity to other utilities and power marketing entities, located primarily in the western United States. TEP is a wholly owned subsidiary of UNS Energy, a utility services holding company. UNS Energy is an indirect wholly owned subsidiary of Fortis.
BASIS OF PRESENTATION
TEP's consolidated financial statements and disclosures are presented in accordance with GAAP, including specific accounting guidance for regulated operations. The consolidated financial statements include the accounts of TEP and its subsidiaries. In the consolidation process, accounts of the parent and subsidiaries are combined and intercompany balances and transactions are eliminated. TEP jointly owns several generation and transmission facilities with both affiliated and non-affiliated entities. TEP'sThe Company records its proportionate share ofof: (i) jointly-owned facilities is recorded in Utility Plant on the Consolidated Balance Sheets,Sheets; and its proportionate share of the(ii) operating costs associated with these facilities is included in the Consolidated Statements of Income. See Note 3 for additional information regarding utility plant.
Certain amounts from prior periods have been reclassified to conform to the current year presentation.
Accounting for Regulated Operations
TEP applies accounting standards that recognize the economic effects of rate regulation. As a result, TEP capitalizes certain costs that would be recorded as expense or in AOCI by unregulated companies.Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in Retail Rates or in rates charged to wholesale customers through transmission tariffs. Regulatory liabilities generally represent expected future costs that have already been collected from customers or amounts that are expected to be returned to customers through billing reductions in future periods.
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. TEP evaluates regulatory assets and liabilities each period and believes future recovery or settlement is probable. If future recovery of costs ceases to be probable, the assets would be written off as a charge to current period earnings or AOCI. See Note 2 for additional information regarding regulatory matters.
TEP applies regulatory accounting as the following conditions exist:
An independent regulator sets rates;
The regulator sets the rates to recover the specific enterprise’s costs of providing service; and
Rates are set at levels that will recover the entity’s costs and can be charged to and collected from ratepayers.
Variable Interest Entities
TEP regularly reviews contracts to determine if it has a variable interest in an entity, if that entity is a Variable Interest Entity (VIE),VIE, and if itTEP is the primary beneficiary of the VIE. The primary beneficiary is required to consolidate the VIE when the variable interest holderit has: (i) the power to direct activities that most significantly impact the economic performance of the VIE; and (ii) the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIE.
TEP routinely entershas entered into long-term renewable PPAs with various entities. Some of these entities are VIEs due to the long-term fixed price component in the agreements. These PPAs effectively transfer commodity price risk to TEP, the buyer of the power, creating a variable interest. TEP has determined it is not a primary beneficiary of these VIEs as it lacks the power to direct the activities that most significantly impact the economic performance of the VIEs. TEP reconsiders whether it is a primary beneficiary of the VIEs on a quarterly basis.
As of December 31, 2017,2019, the carrying amountamounts of assets and liabilities in the balance sheet that relatesrelate to variable interests under long-term PPAs isare predominantly related to working capital accounts and generally representsrepresent the amounts owed by TEP for the deliveries associated with the current billing cycle. TEP's maximum exposure to loss is limited to the cost of replacing the power if the providers do not meet the production guarantee. However, the exposure to loss is mitigated as the Company would likely recover these costs through retail customer cost recovery mechanisms. See Note 2 for additional information related to cost recovery mechanisms.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
RECENTLYNEW ACCOUNTING STANDARDS ISSUED AND ADOPTED ACCOUNTING PRONOUNCEMENTS
EffectiveThe following new authoritative accounting guidance issued by the FASB has been adopted as of January 1, 2017, 2019. Unless otherwise indicated, adoption of the new guidance in each instance had an insignificant impact on TEP’s financial position, results of operations, cash flows, and disclosures.
Leases
TEP adopted accounting guidance that requires the Companylessees to measure inventoryrecognize a lease liability, initially measured at the lowerpresent value of costfuture lease payments, and net realizable value. Net realizable value isa right-of-use asset for all leases with a lease term greater than 12 months. The new lease standard also requires additional quantitative and qualitative disclosures for both lessees and lessors. TEP applied the estimated selling pricetransition provisions of the new standard as of the adoption date and did not retrospectively adjust prior periods. In addition, TEP elected a package of practical expedients that allowed it to not reassess: (i) whether existing contracts are or contain a lease; (ii) the lease classification of existing leases; or (iii) the initial direct costs for existing leases. Furthermore, TEP elected a practical expedient that permitted it to not evaluate existing land easements that were not previously accounted for as leases. The new lease guidance has been applied on a prospective basis to all new or modified land easements since January 1, 2019. Finally, TEP utilized the hindsight practical expedient in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The adoption of this change in accounting principletransition provisions to determine the lease term. TEP did not have any impactidentify or record an adjustment to the opening balance of retained earnings on TEP's financial position or results of operations as the Company recovers the cost of inventory through its rates.adoption. See Note 8 for additional disclosure about TEP’s leasing arrangements.
Effective December 31, 2017, Internal-Use Software
TEP early adopted accounting guidance that
requires entities to showclarifies accounting for implementation costs incurred in a cloud computing arrangement that is a service contract. Under the
changes innew guidance, customers apply the
total of cash, cash equivalents,same criteria for capitalizing implementation costs as they would for an arrangement that has a software license. The guidance also provides specific requirements for the classification and
restricted cash or restricted cash equivalents on the cash flow statement. As a result, TEP no longer presents transfers between cash and cash equivalents and restricted cash and restricted cash equivalents on the cash flow statement. On adoption, using the retrospective method of transition, TEP's Consolidated Statements of Cash Flows included the following adjustments: |
| | | | | | | | | | | |
| | As Filed | | Adoption of ASU Impacts | | As Adjusted |
| (in millions) | Year Ended December 31, 2016 |
| Net Cash Flows—Operating Activities | $ | 425 |
| | $ | — |
| | $ | 425 |
|
| Net Cash Flows—Investing Activities | (376 | ) | | 3 |
| | (373 | ) |
| Net Cash Flows—Financing Activities | (69 | ) | | — |
| | (69 | ) |
| Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash | (20 | ) | | 3 |
| | (17 | ) |
| Cash, Cash Equivalents, and Restricted Cash, Beginning of Period | 56 |
| | 4 |
| | 60 |
|
| Cash, Cash Equivalents, and Restricted Cash, End of Period | $ | 36 |
| | $ | 7 |
| | $ | 43 |
|
|
| | | | | | | | | | | |
| (in millions) | Year Ended December 31, 2015 |
| Net Cash Flows—Operating Activities | $ | 365 |
| | $ | — |
| | $ | 365 |
|
| Net Cash Flows—Investing Activities | (503 | ) | | 2 |
| | (501 | ) |
| Net Cash Flows—Financing Activities | 120 |
| | — |
| | 120 |
|
| Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash | (18 | ) | | 2 |
| | (16 | ) |
| Cash, Cash Equivalents, and Restricted Cash, Beginning of Period | 74 |
| | 2 |
| | 76 |
|
| Cash, Cash Equivalents, and Restricted Cash, End of Period | $ | 56 |
| | $ | 4 |
| | $ | 60 |
|
The standard impacted the presentation of the cash flow statement but didcapitalized implementation costs and the related amortization of those costs. TEP adopted the standard prospectively.
NEW ACCOUNTING STANDARDS ISSUED AND NOT YET ADOPTED
New authoritative accounting guidance issued by the FASB was assessed and either determined to not be applicable or is expected to have an insignificant impact on TEP'sTEP’s financial position, or results of operations.operations, cash flows, and disclosures.
USE OF ACCOUNTING ESTIMATES
Management uses estimates and assumptions when preparing financial statements according to GAAP. These estimates and assumptions affect:
assets and liabilities in the balance sheet at the dates of the financial statements;
disclosures about contingent assets and liabilities at the dates of the financial statements; and
revenues and expenses in the income statement during the periods presented.
Because these estimates involve judgments based upon the Company'smanagement's evaluation of relevant facts and circumstances, actual results may differ from these estimates.
Asset Retirement Obligations
TEP has identified legal AROs related to the retirement of certain generation assets. Additionally, TEP incurred AROs related to its PV assets as a result of entering into variousenvironmental regulations, decommissioning agreements, and land leases or land easement agreements. Liabilities are recorded for legal AROs in the period in which they are incurred if it can be reasonably estimated. When a new obligation is recorded, the cost of the liability is capitalized by increasing the carrying amount of the related long-lived asset. The increase in the liability due to the passage of time is recorded by recognizing accretion expense in Operations and Maintenance Expense on the Consolidated Statements of Income. Capitalized cost is depreciated over the useful life of the related asset or, when applicable, the term of
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
the lease. TEP primarily defers the accretion and depreciation expense associated with its legal AROs asinto a regulatory assetsasset or liability account based on the ACC approval of these costs in its depreciation rates.
Depreciation rates also include a component for estimated future removal costs that have not been identified as legal obligations. TEP recovers estimated future removal costs in Retail Rates and records an obligation for estimated costs of removal as regulatory liabilities.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Contingencies
Reserves for specific legal proceedings are established when the likelihood of an unfavorable outcome is probable and the amount of loss can be reasonably estimated. Significant judgment is required in predicting the outcome of these suits and claims, many of which take years to complete. TEP identifies certain other legal matters where the Company believes an unfavorable outcome is reasonably possible or no estimate of possible losses can be made. All contingencies are regularly reviewed to determine whether the likelihood of loss has changed and to assess whether a reasonable estimate of the loss or range of loss can be made.
CASH AND CASH EQUIVALENTS
TEP considers all highly liquid investments with a remaining maturity of three months or less at acquisition to be cash equivalents.
RESTRICTED CASH
Restricted cash includes cash balances restricted regardingwith respect to withdrawal or usage based on contractual or regulatory considerations. The following table presents the line items and amounts of cash, cash equivalents, and restricted cash reported onin the balance sheet and reconciles their sum to the cash flow statement: |
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2019 | | 2018 | | 2017 |
| Cash and Cash Equivalents | $ | 10 |
| | $ | 138 |
| | $ | 38 |
|
| Restricted Cash included in: | | | | | |
| Investments and Other Property | 16 |
| | 14 |
| | 11 |
|
| Current Assets—Other | 2 |
| | 1 |
| | 1 |
|
| Total Cash, Cash Equivalents, and Restricted Cash | $ | 28 |
| | $ | 153 |
| | $ | 50 |
|
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2017 | | 2016 | | 2015 |
| Cash and Cash Equivalents | $ | 38 |
| | $ | 36 |
| | $ | 56 |
|
| Restricted Cash included in: | | | | | |
| Investments and Other Property | 11 |
| | 7 |
| | 4 |
|
| Current Assets, Other | 1 |
| | — |
| | — |
|
| Total Cash, Cash Equivalents, and Restricted Cash | $ | 50 |
| | $ | 43 |
| | $ | 60 |
|
Restricted cash included in Investments and Other Property on the Consolidated Balance Sheets represents cash contractually required to be set aside to pay TEP's share of mine reclamation costs at San Juan.Juan and various contractual agreements. Restricted cash included in Current Assets—Other represents cash required to be set aside by various contractual agreements.the current portion of TEP's share of San Juan's mine reclamation costs.
ALLOWANCE FOR DOUBTFUL ACCOUNTS
TEP records an allowance for doubtful accounts to reduce accounts receivable for amounts estimated to be uncollectible. The allowance is determined based on historical bad debt patterns, retail sales, and economic conditions. Accounts receivable are charged-off in the period in which the receivable is deemed uncollectible. The change in the balance of the Allowance for Doubtful Accounts included in Accounts Receivable, Net on the Consolidated Balance Sheets is summarized as follows: |
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2019 | | 2018 | | 2017 |
| Beginning of Period | $ | 5 |
| | $ | 5 |
| | $ | 5 |
|
| Additions Charged to Cost and Expense | 4 |
| | 3 |
| | 3 |
|
| Write-offs | (3 | ) | | (3 | ) | | (3 | ) |
| End of Period | $ | 6 |
| | $ | 5 |
| | $ | 5 |
|
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2017 | | 2016 | | 2015 |
| Beginning of Period | $ | 5 |
| | $ | 27 |
| | $ | 5 |
|
| Additions Charged to Cost and Expense | 3 |
| | 4 |
| | 2 |
|
| Write-offs | (3 | ) | | (3 | ) | | (3 | ) |
| Provision for Springerville Unit 1, Third-Party Owners | — |
| | (23 | ) | | 23 |
|
| End of Period | $ | 5 |
| | $ | 5 |
| | $ | 27 |
|
The allowance for doubtful accounts decreased in 2016 due to the settlement and release of asserted claims between TEP and the Third-Party Owners related to Springerville Unit 1. See Note 7 for additional information regarding the settlement of the Third-Party Owners' claims.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
INVENTORY
TEP values materials, supplies, and fuel inventory at the lower of weighted average cost and net realizable value. Materials and supplies consist of generation, transmission, and distribution construction and repair materials. The majority of TEP's inventory will be recovered in rates charged to ratepayers. Handling and procurement costs (such as labor, overhead costs, and transportation costs) are capitalized as part of the cost of the inventory.
UTILITY PLANT
Utility plant includes the business property and equipment that supports electric service, consisting primarily of generation, transmission, and distribution facilities. Utility plant is reported at original cost. Original cost includes materials and labor, contractor services, construction overhead (when applicable), and an Allowance for Funds Used During Construction (AFUDC),AFUDC, less contributions in aid of construction.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The cost of repairs and maintenance, including planned generation overhauls, are expensed to Operations and Maintenance Expense on the Consolidated Statements of Income as costs are incurred.
When TEP determines it is probable that a utility plant asset will be abandoned or retired early, the cost of that asset is removed from utility plant-in-service and is recorded as a regulatory asset if recovery is probable. When TEP retires a unit of regulated property, accumulated depreciation is reduced by the original cost plus removal costs less any salvage value. There is no impact to the income statement.
AFUDC and Capitalized Interest
AFUDC reflects the cost of debt and equity funds used to finance construction and is capitalized as part of the cost of regulated utility plant. AFUDC amounts are capitalized and amortized through depreciation expense as a recoverable cost in Retail Rates. The capitalized interest that relates to debt is recorded as a reduction in Interest ExpenseAllowance For Borrowed Funds on the Consolidated Statements of Income. The capitalized cost for equity funds is recorded in Other IncomeAllowance For Equity Funds on the Consolidated Statements of Income.
The average AFUDC rates on regulated construction expenditures are included in the table below: |
| | | | | | | | |
| | 2019 | | 2018 | | 2017 |
| Average AFUDC Rates | 7.86 | % | | 7.12 | % | | 7.31 | % |
|
| | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| Average AFUDC Rates | 7.31 | % | | 7.47 | % | | 6.12 | % |
Depreciation
Depreciation is recorded for owned utility plant on a group method straight-line basis at depreciation rates based on the economic lives of the assets. See Note 3 for additional information regarding utility plant. The ACC approves depreciation rates for all generation and distribution assets. Transmission assets are subject to the jurisdiction of the FERC. Depreciation rates are based on average useful lives and include estimates for salvage value and removal costs.
Below are the summarized average annual depreciation rates for all utility plant: |
| | | | | | | | |
| | 2019 | | 2018 | | 2017 |
| Average Annual Depreciation Rates | 3.08 | % | | 3.13 | % | | 2.97 | % |
|
| | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| Average Annual Depreciation Rates | 2.97 | % | | 2.85 | % | | 2.83 | % |
Utility Plant Under Capital Leases
TEP finances a portion of the Springerville Common Facilities with capital leases. Capital lease expense is recorded in Amortization Expense and in Interest Expense—Capital Leases on the Consolidated Statements of Income. See Note 3 for additional information regarding utility plant and Note 6 for additional information related to the lease terms.
Computer Software and Cloud Computing Costs
Costs incurred to purchase and develop internal use computer software and cloud computing arrangements that include a software license are capitalized and amortized over the estimated economic life of the product. Implementation costs incurred in a cloud computing arrangement that is a service contract are included in Regulatory and Other Assets—Other on the Consolidated Balance Sheets and amortized over the life of the service agreement. Amortization expense is presented in Operations and Maintenance Expense on the Consolidated Statements of Income. If the associated software is no longer useful or impaired, the carrying value is reduced and recorded as an expense onin the income statement.
EVALUATION OF ASSETS FOR IMPAIRMENT
Long-lived assets and investments are evaluated for impairment whenever events or changes in circumstances indicate thethat an asset’s carrying value of the assetsamount may not be impaired.recoverable. If expectedestimated future undiscounted cash flows (without discounting) are less than the carrying amount, the Company estimates the fair value of the asset,and records an impairment loss is recognized iffor the impairment is other-than-temporaryamount by which the carrying value exceeds the fair value. For these estimates, TEP may consider data from multiple valuation methods, including data from market participants. The Company exercises judgment to: (i) estimate the future cash flows and the lossuseful lives of long-lived assets; and (ii) determine the Company’s intent to use the assets. TEP’s intent to use or dispose of assets is not recoverable through rates.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
subject to re-evaluation and can change over time.
DEFERRED FINANCING COSTS
Using the effective interest method, costsCosts to issue debt are deferred and amortized to interest expense on a straight-line basis over the life of the debt. Deferred debt issuance costs are presented in the balance sheet as a direct deduction from the carrying value of the associated debt liability. These costs include underwriters’ commissions, discounts or premiums, and other costs such as legal, accounting, regulatory fees, and printing costs.
TEP accounts for debt issuance costs related to credit facility arrangements as an asset.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The gains and losses on reacquired debt associated with regulated operations are deferred and amortized to interest expense over the remaining life of the original debt.
LEASES
When a contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration, a right-of-use asset and lease liability are recognized. TEP measures the right-of-use asset and lease liability at the present value of future lease payments, excluding variable payments based on usage or performance. TEP calculates the present value using the rate implicit in the lease or a lease-specific secured interest rate based on the lease term. TEP has lease agreements with lease components (e.g., rent, real estate taxes and insurance costs) and nonlease components (e.g., common area maintenance costs), which are accounted for as a single lease component. TEP includes options to extend a lease in the lease term when it is reasonably certain that the option will be exercised. Leases with an initial term of twelve months or less are not recorded in the balance sheet.
OPERATING REVENUES
Revenues related toTEP earns the salemajority of energy are recognized when services or commodities are delivered to customers. The billing forits revenues from the deliverysale of power to retail and wholesale customers based on regulator-approved tariff rates. Most of the Company's contracts have a single performance obligation, the delivery of power. TEP satisfies the performance obligation over time as power is delivered and control is transferred to the customer. The Company bills for power sales based on the reading of theirelectric meters which occurs on a systematic basis throughout the month. Operating revenues include an estimate for unbilled revenuesIn general, TEP's contracts have payment terms of 10 to 20 days from service that has been provided butthe date the bill is rendered. TEP considers any payment not billedreceived by the end of an accounting period. Atdue date delinquent and charges the endcustomer a late payment fee. No component of the month,transaction price is allocated to unsatisfied performance obligations.
TEP has certain contracts with variable transaction pricing that require it to estimate the resulting variable consideration. TEP estimates variable consideration at the most likely amount to which the Company expects to be entitled and recognizes a refund liability until TEP is certain that the Company will be entitled to the consideration. The Company includes estimated amounts of energy delivered sincevariable consideration in the last meter reading are estimated and the corresponding unbilled revenue is calculated using average customer Retail Rates.
Alternative revenue programs allow utilities to adjust future rates in response to past activities or completed events, if certain criteria are met. TEP charges customers the ACC-authorized tarifftransaction price plus separate ACC-authorized surcharges. TEP has identified its LFCR mechanism and DSM performance incentive as alternative revenues. The LFCR mechanism provides for recovery of certain non-fuel costs that would go unrecovered due to reduced retail kWh sales as a result of implementing ACC-approved energy efficiency programs and customer-installed DG. The LFCR surcharge is assessed as a percentage of the customer’s bill. Revenue recognition related to the LFCR mechanism creates a regulatory asset until such time as theextent it is probable that changes in its estimate will not result in significant reversals of revenue is collected. For recovery of the LFCR regulatory asset, TEP is required to file an annual LFCR adjustment request with the ACCin subsequent periods. See Note 4 for the LFCR revenues recognized in the prior year. The recovery is subject to a year-over-year cap of 2%disaggregation of TEP's applicable retail revenues, as approved in the 2017 Rate Order. In addition, the ACC approves a new DSM surcharge annually, which is effective June 1 of each year, to compensate TEP for the costs to design and implement cost-effective energy efficiency and demand response programs until such costs are reflected in TEP’s non-fuel base rates as well as a performance incentive. TEP collects the DSM surcharge on a per kWh basis for residential customers and on a percentage of bill basis for non-residential customers. See Note 2 for additional information regarding regulatory matters.
For purchased power and wholesale sales contracts that are settled financially, TEP nets the purchased power contracts with the sales contracts and reflects the amount in Wholesale Revenues on the Consolidated Statements of Income.
TEP recognizes monthly management fees in Other Revenues on the Consolidated Statements of Income as the operator of Springerville Unit 3 on behalf of Tri-State and Springerville Unit 4 on behalf of SRP. Additionally, Other Revenues includes reimbursements from Tri-State and SRP for various operating expenses at Springerville and for the use of the Springerville Common Facilities and Springerville Coal Handling Facilities. The offsetting expenses are recorded in their respective line items on the income statement based on the nature of services provided. As the operating agent for Tri-State, TEP may earn performance incentives based on unit availability which are recognized in Other Revenues on the Consolidated Statements of Income in the period earned.Operating Revenues.
PURCHASED POWER AND FUEL ADJUSTMENT CLAUSE
TEP recovers the actual fuel, purchased power, and transmission costs to provide electric service to retail customers through base fuel rates and through a PPFAC mechanism. The ACC periodically adjusts the PPFAC rate at which TEP recovers these costs. The difference between costs recovered through rates and actual fuel, purchased power, transmission, and other approved costs to provide retail electric service is deferred. Cost over-recoveries are deferred as regulatory liabilities and cost under-recoveries are deferred as regulatory assets. See Note 2 for additional information regarding regulatory matters.
RENEWABLE ENERGY AND ENERGY EFFICIENCY PROGRAMS
The ACC’s RES requires Arizona regulated utilities to increase their use of renewable energy each year until it represents at least 15% of their total annual retail energy requirements by 2025, with DG accounting for 30% of the annual renewable energy requirement. Arizona utilities must file an annual RES implementation plan for review and approval by the ACC. The approved costs of carrying out this plan are recovered from retail customers through the RES surcharge. The associated lost revenues attributable to meeting DG targets will beare partially recovered through the LFCR mechanism.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
TEP is required to implement cost-effective DSM programs to comply with the ACC’s EE Standards. The EE Standards provide regulated utilities a DSM surcharge to recover from retail customers the costs to implement DSM programs. The EE Standards require increasing annual targeted retail kWh savings equal to 22% by 2020. The associated lost revenues attributable to meeting these targets are partially recovered through the LFCR mechanism.
Any RES or DSM surcharges collected above or below the costs incurred to implement the plans are deferred and reflected in the balance sheet as a regulatory liability or asset. TEP recognizes RES and DSM surcharge revenue in RetailOperating Revenues on the Consolidated Statements of Income in amounts necessary to offset recognized qualifying expenditures.
RENEWABLE ENERGY CREDITS
The ACC measures compliance with the RES requirements through RECs. A REC represents one kWh generated from renewable resources. When TEP purchases renewable energy, the premium paid above the market cost of conventional power equals the REC cost recoverable through the RES surcharge. As described above, the market cost of conventional power is recoverable through the PPFAC mechanism.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
When RECs are purchased, TEP records the cost of the RECs (an indefinite-lived intangible asset) as other assets and a corresponding regulatory liability to reflect the obligation to use the RECs for future RES compliance. When RECs are reported to the ACC for compliance with RES requirements, TEP recognizes purchased power expense and other revenues in an equal amount. TEP had $42 million and $24 millionSee Note 2 for additional information regarding regulatory matters. The table below summarizes the balance of TEP's RECs as of December 31, 2017 and 2016, respectively. RECsthat are included in Regulatory and Other Assets—Other on the Consolidated Balance Sheets. See Note 2 for additional information regarding regulatory matters.Sheets: |
| | | | | | | |
| | December 31, |
| (in millions) | 2019 | | 2018 |
| Beginning of Period | $ | 55 |
| | $ | 42 |
|
| Purchased | 45 |
| | 45 |
|
| Used for Compliance | (37 | ) | | (32 | ) |
| End of Period | $ | 63 |
| | $ | 55 |
|
TEP expenses the cost of internally developed RECs, including PBI activity that is not included in the table above and recoverable through the RES surcharge.
TAXES OTHER THAN INCOME TAXES
TEP acts as a conduit or collection agent for sales taxes, utility taxes, franchise fees, and regulatory assessments. Trade receivables are recorded as the Company bills customers for these taxes and assessments. Simultaneously, liabilities payable to governmental agencies are recorded in the balance sheet for these taxes and assessments. These amounts are not reflected in the income statement.
INCOME TAXES
Due to the difference between GAAP and income tax laws, many transactions are treated differently for income tax purposes than for financial statement presentation purposes. Temporary differences are accounted for by recording deferred income tax assets and liabilities onin the balance sheet. These assets and liabilities are recorded using enacted income tax rates expected to be in effect when the deferred tax assets and liabilities are realized or settled. TEP reduces deferred tax assets by a valuation allowance when, in the opinion of management, it is more likely than not that some portion, or the entire deferred income tax asset, will not be realized.
Tax benefits are recognized when it is more likely than not that a tax position will be sustained upon examination by the tax authorities based on the technical merits of the position. The tax benefit recorded is the largest amount that is more than 50% likely to be realized upon ultimate settlement with the tax authority, assuming full knowledge of the position and all relevant facts. Interest expense accruals relating to income tax obligations are recorded in Other Interest Expense on the Consolidated Statements of Income.
TEP accounts for federal energy credits generated prior to 20122013 using the grant accounting model. The credit is treated as deferred revenue, which is recognized over the depreciable life of the underlying asset. The deferred tax benefit of the credit is treated as a reduction to income tax expense in the year the credit arises. TEP had an aggregate liability balance of $6 million and $7 million related to federal energy credits generated prior to 2013 included in Other on the Consolidated Balance Sheets as of December 31, 2019 and 2018, respectively. Federal energy credits generated since 20122013 are deferred as regulatory liabilities and amortized as a reduction in income tax expense over the tax life of the underlying asset. TEP had an aggregate liability balance of $2 million and $6 million related to federal energy credits generated since 2013 included in Regulatory Liabilities on the Consolidated Balance Sheets as of December 31, 2019 and 2018, respectively. Income tax expense attributable to the reduction in tax basis is accounted for in the year the federal energy credit is generated and is deferred as a regulatory asset. All other federal and state income tax credits are treated as a reduction to income tax expense in the year the credit arises.
TEP records income tax liabilities based on TEP's taxable income as reported in the consolidated tax return of FortisUS.
PENSION AND OTHER POSTRETIREMENT BENEFITS
TEP sponsors noncontributory, defined benefit pension plans for substantially all employees and certain affiliate employees. Benefits are based on years of service and average compensation. The Company also provides limited healthcare and life insurance benefits for retirees.
The Company recognizes the underfunded status of defined benefit pension plans as a liability in the balance sheet. The underfunded status is measured as the difference between the fair value of the pension plans’ assets and the projected benefit
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
obligation for the pension plans. TEP recognizes a regulatory asset to the extent these future costs are probable of recovery in
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
the rates charged to retail customers. The Company expects recovery of these costs over the estimated service lives of employees.
Additionally, TEP maintains a SERP for senior management. Changes in SERP benefit obligations are recognized as a component of AOCI.
Pension and other postretirement benefit expenses are determined by actuarial valuations based on assumptions that the Company evaluates annually. See Note 810 for additional information regarding the employee benefit plans.
FAIR VALUE
As defined under GAAP, fair value is the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal market or in the most advantageous market when no principal market exists. Adjustments to transaction prices or quoted market prices may be required in illiquid or disorderly markets in order to estimate fair value. Different valuation techniques may be appropriate under the circumstances to determine the value that would be received to sell an asset or paid to transfer a liability in an orderly transaction. Market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange, and not under duress. Nonperformance or credit risk is considered in determining fair value. Considerable judgment may be required in interpreting market data used to develop the estimates of fair value. Accordingly, estimates of fair value presented herein are not necessarily indicative of the amounts that could be realized in a current or future market exchange. See Note 1113 for additional information regarding fair value.
DERIVATIVE INSTRUMENTS
The Company uses various physical and financial derivative instruments, including forward contracts, financial swaps, and call and put options, toto: (i) meet forecasted load and reserve requirements, torequirements; (ii) reduce exposure to energy commodity price volatility,volatility; and to(iii) hedge interest rate risk exposure. Derivative instruments that do not meet the normal purchase or normal sale scope exception will beare recognized as either assets or liabilities onin the balance sheet and are measured at fair value. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation.
Commodity derivatives used in normal business operations that are settled by physical delivery, among other criteria, are eligible for, and may be designated as, normal purchases or normal sales. Normal purchases or normal sales contracts are not recorded at fair value and settled amounts are recognized as cost of fuel, energy, and capacity onin the income statement.
For derivatives designated as hedging contracts, TEP formally assesses, at inception, and thereafter, whether the hedging contract is highly effective in offsetting changes in the hedged item. Also, TEP formally documents hedging activity by transaction type and risk management strategy.
For derivatives not designated as hedging contracts, the settled amount is generally included in regulated rates. Accordingly, the net unrealized gains and losses associated with interim price movements on contracts that are accounted for as derivatives and probable of inclusion in regulated rates are recorded as regulatory assets and liabilities. See Note 1113 for additional information regarding derivative instruments.
NOTE 2.REGULATORY MATTERS
The ACC and the FERC each regulate portions of the utility accounting practices and rates of TEP. The ACC regulates rates charged to retail customers, the siting of generation and transmission facilities, the issuance of securities, transactions with affiliated parties, and other utility matters. The ACC also enacts other regulations and policies that can affect the Company's business decisions and accounting practices. The FERC regulates termsrates and prices ofservices for electric transmission services and wholesale electricity sales.power sales in interstate commerce.
20172019 ACC RATE ORDERCASE
In February 2017,April 2019, TEP filed a general rate case with the ACC issuedbased on a test year ended December 31, 2018.
TEP's key proposals of the rate ordercase, adjusted for rebuttal testimony filed in November 2019 include:
a non-fuel retail revenue increase of $99 million, partially offset by a reduction in base fuel revenue of approximately $39 million for a net increase of $60 million over test year retail revenues;
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
a 7.49% return on original cost rate base of $2.7 billion, which includes a cost of equity of 10.00% and an average cost of debt of 4.65%;
a request to recover costs of changes in generation resources, including: (i) the retirement of Navajo and Sundt Units 1 and 2; and (ii) the replacement generation capacity associated with the purchase of Gila River Unit 2 and the installation of RICE units at Sundt;
a TEAM that would be updated for income tax changes that materially affect TEP’s authorized revenue requirement; and
a TCA mechanism, updated annually, allowing TEP to recover any changes in transmission costs approved by the FERC.
Hearings before an ALJ were held in January and February 2020. The hearing will resume in April 2020. TEP requested new rates that took effect February 27, 2017. to be implemented by May 1, 2020.
TEP cannot predict the timing or outcome of the proceeding.
2019 FERC RATE CASE
In 2019, the FERC issued an order approving TEP's proposed OATT revisions effective August 1, 2019, subject to refund.
Provisions of the 2017 Rate Orderorder include, but are not limited to:
replacing TEP's stated transmission rates with a non-fuel baseforward-looking formula rate;
a 10.4% return on equity; and
elimination of transmission rates that are bifurcated between high-voltage and lower-voltage facilities, as well as elimination of the bifurcated loss factor rate.
The requested forward-looking formula rate increaseis intended to allow for more timely recovery of $81.5 million, which includes $15transmission related costs. As part of the order, the FERC established hearing and settlement procedures, and all revisions to the OATT in the FERC order are subject to refund. As of December 31, 2019, TEP had reserved $4 million of operating costs related towholesale revenues in Current Liabilities—Regulatory Liabilities on the 50.5% undivided interest in Springerville Unit 1 purchased by TEP in September 2016;
Consolidated Balance Sheets as a 7.04% return on original cost rate base, which includes a costresult of equity component of 9.75% and a cost of debt component of 4.32%;
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
adoption of TEP's proposed depreciation and amortization rates, which include a reduction in the depreciable life for San Juan Unit 1; and
approval of a request to apply excess depreciation reserves against the unrecovered NBV of San Juan Unit 2 and the coal handling facilities at Sundt due to early retirement.
The ACC deferred matters related to net metering and rate design for new DG customers to Phase 2, which is currently expected to be completed in the first half of 2018.FERC proceedings. TEP cannot predict the outcome of thesethe proceeding.
Abandoned Plant Costs
Also in May 2019, TEP filed with the FERC a request to recover through its OATT abandoned plant costs related to the abandoned Sahuarita, Arizona to Nogales, Arizona transmission line. TEP requested authorization to recover 100% of the approximately $9 million that it incurred in developing the transmission line. The filing requests that the abandoned plant costs be included in TEP's transmission rate. On September 19, 2019, the FERC issued an order allowing TEP to recover 50% of its costs in its formula rate and established hearing and settlement procedures. TEP plans to incorporate the abandoned plant costs into its formula rate effective January 1, 2020, subject to refund. On September 26, 2019, the FERC issued an order consolidating the 2019 FERC Rate Case and Abandoned Plant Costs proceedings. In 2012, TEP wrote-off a portion of the deferred costs related to the Nogales transmission line. As of December 31, 2019, there was $4 million related to the Nogales transmission line recorded in Regulatory and Other Assets—Regulatory Assets on the Consolidated Balance Sheets.
FEDERAL TAX LEGISLATION - ACC DOCKET
Arizona Corporation Commission
In December 2017, the ACC opened a docket requesting that all regulated utilities submit proposals to address passing the ongoing benefits of the TCJA through to customers. In 2018, the ACC issued the ACC Refund Order. The ACC Refund Order represents the reduction in the federal corporate income tax rate and an estimate of EDIT amortization that will be trued-up annually for actuals. The bill credit was designed to return the refund amount to customers based on forecasted kWh sales for the calendar year. Any over or under collected amounts are deferred to a regulatory liability or asset and will be used to adjust the following year's bill credit amounts. Customer bill credits are trued-up annually to reflect actuals for both kWh sales and EDIT amortization. TEP will actively participate in this docket and workfiled an information filing with the ACC to reach an equitable solution.establish a 2020 customer refund of $35 million. The Company cannot predictrefund will be returned to customers through a combination of a customer bill credit and a regulatory liability in 2020. The customer bill credit will account for 50% of the outcomereturned savings in 2020 and through the completion of these proceedings or how they may impact resultsour next rate case.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The table below summarizes the current or future years. regulatory asset (liability) balance related to the ACC Refund Order: |
| | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2019 | | 2018 |
| Beginning of Period | $ | 4 |
| | $ | — |
|
| ACC Approved Refund (Reduction in Operating Revenues) | (34 | ) | | (33 | ) |
| Amount Returned to Customers Through Bill Credits | 22 |
| | 37 |
|
| Regulatory Deferral | 8 |
| | — |
|
| End of Period | $ | — |
| | $ | 4 |
|
See Note 1214 for additional information regarding the TCJA.
Federal Energy Regulatory Commission
In 2018, the FERC issued the FERC Refund Order. In May 2018, TEP responded to the order and the FERC approved TEP's proposal of an overall transmission rate reduction of approximately 5.3%, reflecting the lower federal tax rate, to be effective March 21, 2018. As a result, TEP recognized a reduction in Operating Revenues on the Consolidated Statements of Income of $1 million in 2018.
Also in 2018, the FERC issued a NOPR regarding the effect of the TCJA and related EDIT amortization on rates. In November 2019, the FERC issued a final rule on the NOPR which required TEP to address the effect of the TCJA and related EDIT amortization in its next FERC rate case. As required by the final rule, TEP's 2019 FERC Rate Case addressed the effects of the TCJA and related EDIT amortization.
See Note 14 for additional information regarding the TCJA.
COST RECOVERY MECHANISMS
TEP has received regulatory decisions that allow for more timely recovery of certain costs through the recovery mechanisms described below.
Purchased Power and Fuel Adjustment Clause
TEP's PPFAC rate is adjusted annually each April 1st and goes into effect for the subsequent 12-month period unless the schedule is modified by the ACC. The PPFAC rate includes: (i) a forward component which is calculated by taking the difference between forecasted fuel and purchased power costs and the amount of those costs established in Retail Rates; and (ii) a true-up component that reconciles the difference between actual costs and those recovered in the preceding 12-month period. The PPFAC bank balance was over-collected by $9 million and $38 million as of December 31, 2017 and 2016, respectively.
In February 2017, the ACC approved a PPFAC credit to begin returning the over-collected PPFAC bank balance to customers. The table below presents TEP'ssummarizes the PPFAC rates approved by the ACC:regulatory asset (liability) balance: |
| | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2019 | | 2018 |
| Beginning of Period | $ | (17 | ) | | $ | (9 | ) |
| Deferred Fuel and Purchased Power Costs | 31 |
| | 2 |
|
PPFAC Refunds (Recoveries) (1) | 22 |
| | (10 | ) |
| End of Period | $ | 36 |
| | $ | (17 | ) |
|
| | | |
Period(1) | | Cents per kWh |
In March 2017 through March 2018 | | (0.20 | ) |
May 2016 through February 2017 | | 0.15 |
|
April 2015 through April 2016 | | 0.68 |
|
October 2014 through March 2015 | | 0.50 |
2019, the ACC approved a PPFAC credit as part of TEP's annual rate adjustment request. |
Environmental Compliance Adjustor
The ECA allows for the recovery of capital carrying costs and incremental operations and maintenance costs related to environmental investments, provided that they are not already recovered in base rates or recovered through another commission-approved mechanism.
The eligible costs for the ECA are subject to a cap equal to 0.5% of total annual retail revenue. The Company recognized $2 million in 2019, $3 million in 2018, and $1 million in 2017 related to the return on company-owned environmental investments included in Operating Revenues on the Consolidated Statements of Income.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Renewable Energy Standard
The ACC’s RES requires Arizona regulated utilities to increase their use of renewable energy each year until it represents at least 15% of their total annual retail energy requirements by 2025, with DG accounting for 30% of the annual renewable energy requirement. Arizona utilities mustare required to file an annual RES implementation plan for review and approval by the ACC.
In January 2018,September 2019, the ACC approved TEP's 20182019 RES implementation plan with a budget amount of $54$55 million. The recovery funds the following: (i) the above market cost of renewable power purchases; (ii) previously awarded performance-based incentives for customer-installed DG; and (iii) various other program costs. TEPThe Company recognized less than$1 million in 2019, and $1 million in 2018 and 2017 of revenue in 2017 as a return on company-owned solar projects. The return on company-owned solar projects is included in Operating Revenues on the Consolidated Statements of Income. TEP is no longer requesting recovery on company-owned solar projects through the RES mechanism and plans to requestrequests recovery of these types of costs through its rate case process. TEP suspended its rooftop solar program effective December 2016, but requested approval of a community solar program. The ACC is expected to consider this program in Phase 2 of TEP's rate case.
In 2017,2019, the percentage of TEP's retail kWh sales attributable to the RES was approximately 10%16%, exceeding the overall 20172019 RES requirement of 7%9%. Compliance is determined through the ACC's review of TEP's annual RES implementation plan. As TEP no longer pays incentives to obtain DG RECs, which are used to demonstrate compliance with the DG requirement, theThe ACC approved athe waiver of the 2017 and 2018 residential distributed renewable energy2019 DG requirement.
Energy Efficiency Standards
Under the EE Standards, the ACC requires electric utilities to implement cost-effective programs to reduce customers' energy consumption. The EE Standards require increasing cumulative annual targeted retail kWh savings equal to 22% by 2020. As of
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2017, TEP’s2019, TEP's cumulative annual energy savings werewas approximately 14%19%.
TEP is required to implement cost-effective DSM programs to comply with the ACC’s EE Standards. The EE Standards provide regulated utilities a DSM surcharge to recover from retail customers the costs to implement DSM programs, as well as an annual performance incentive. TEP records its annual DSM performance incentive for the prior calendar year in the first quarter of each year. TEP recorded $2 million in both2019, 2018, and 2017 and 2016, and $3 million in 2015 related to performance included in RetailOperating Revenues on the Consolidated Statements of Income.
In February 2016,2019, the ACC approved TEP's 2016TEP’s 2018 energy efficiency implementation plan with a budget of approximately $22$23 million, which was partially offset by applying $8 million of previously recovered carryover funds. TEP has been approved to collect the remaining $14 million from retail customersis collected through the DSM surcharge. Energy savings realized through the programs will count toward meeting the EE Standards and the associated lost revenue will be partially recovered through the LFCR mechanism.
In June 2016, TEP notified the ACC that it would not file a 2017 energy efficiency implementation plan and instead continue the 2016 level of recovery through the end of 2017. TEP reduced its costs and incentive levels for certain programs in order to minimize any potential under-collected DSM balance at the end of 2017.
In August 2017, TEP submitted its application for the 2018 energy efficiency implementation plan with a budget of $23 million and requested a waiver of the 2018 EE Standard. TEP expects to receive a decision on its 2018 energy efficiency implementation plan in the first half of 2018.
Lost Fixed Cost Recovery Mechanism
The LFCR mechanism provides for recovery of certain non-fuel costs that would go unrecovered due to reduced retail kWh sales as a result of implementing ACC-approved energy efficiency programs and customer-installed DG. TEP records a regulatory asset and recognizes LFCR revenues when the amounts are verifiable regardless of when the lost retail kWh sales occur. TEP is required to make an annual filing with the ACC requesting recovery of the LFCR revenues recognized in the prior year. The recovery is subject to a year-over-year increase cap of 2% of TEP's applicable retail revenues, as approved inrevenues.
The table below summarizes the 2017 Rate Order.
TEP recorded regulatory assets and recognized LFCR revenues
of $22 millionrecognized in
2017, $18 million in 2016, and $12 million in 2015. LFCR revenues are included in RetailOperating Revenues on the Consolidated Statements of
Income.Income: |
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2019 | | 2018 | | 2017 |
| LFCR Revenues | $ | 33 |
| | $ | 26 |
| | $ | 22 |
|
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
REGULATORY ASSETS AND LIABILITIES
Regulatory assets and liabilities recorded in the balance sheet are summarized in the table below: | | | | Remaining Recovery Period (years) | | December 31, | Remaining Recovery Period (years) | | December 31, |
| ($ in millions) | | 2017 | | 2016 | | 2019 | | 2018 |
| Regulatory Assets | | | | | | | | |
| Pension and Other Postretirement Benefits (Note 8) | Various | | $ | 126 |
| | $ | 128 |
| |
Early Generation Retirement Costs (1) | Various | | 84 |
| | — |
| |
Income Taxes Recoverable through Future Rates (2) | Various | | 40 |
| | 29 |
| |
| Pension and Other Postretirement Benefits (Note 10) | | Various | | $ | 135 |
| | $ | 126 |
|
| Derivatives (Note 13) | | 10 | | 72 |
| | 27 |
|
| Early Generation Retirement Costs | | Various | | 68 |
| | 72 |
|
| Lost Fixed Cost Recovery | | 2 | | 46 |
| | 35 |
|
Income Taxes Recoverable through Future Rates (1) | | Various | | 38 |
| | 47 |
|
| Under Recovered Purchased Energy Costs | | 1 | | 36 |
| | — |
|
Property Tax Deferrals (2) | | 1 | | 24 |
| | 23 |
|
Final Mine Reclamation and Retiree Healthcare Costs (3) | 20 | | 31 |
| | 27 |
| 19 | | 19 |
| | 29 |
|
| Lost Fixed Cost Recovery | 1 | | 29 |
| | 23 |
| |
Property Tax Deferrals (4) | 1 | | 24 |
| | 23 |
| |
Springerville Unit 1 Leasehold Improvements (5) | 6 | | 14 |
| | 17 |
| |
Sundt Coal Handling Facilities (6) | N/A | | — |
| | 14 |
| |
Springerville Unit 1 Leasehold Improvements (4) | | 4 | | 9 |
| | 11 |
|
| Other Regulatory Assets | Various | | 40 |
| | 20 |
| Various | | 18 |
| | 30 |
|
| Total Regulatory Assets | | 388 |
| | 281 |
| | 465 |
| | 400 |
|
| Less Current Portion | 1 | | 94 |
| | 56 |
| 1 | | 138 |
| | 107 |
|
| Total Non-Current Regulatory Assets | | $ | 294 |
| | $ | 225 |
| | $ | 327 |
| | $ | 293 |
|
| | | Regulatory Liabilities | | | | | | | | |
Income Taxes Payable through Future Rates (2)(1) | Various | | $ | 353 |
| | $ | 3 |
| Various | | $ | 327 |
| | $ | 354 |
|
Net Cost of Removal (7)(5) | Various | | 180 |
| | 270 |
| Various | | 164 |
| | 171 |
|
| Renewable Energy Standard | Various | | 44 |
| | 32 |
| Various | | 59 |
| | 52 |
|
Deferred Investment Tax Credits (8)(6) | Various | | 14 |
| | 23 |
| Various | | 3 |
| | 7 |
|
| Purchased Power and Fuel Adjustment Clause | 1 | | 9 |
| | 38 |
| |
| Over Recovered Purchased Energy Costs | | Various | | — |
| | 17 |
|
| Other Regulatory Liabilities | Various | | 5 |
| | 11 |
| Various | | 20 |
| | 6 |
|
| Total Regulatory Liabilities | | 605 |
| | 377 |
| | 573 |
| | 607 |
|
| Less Current Portion | 1 | | 89 |
| | 76 |
| 1 | | 96 |
| | 95 |
|
| Total Non-Current Regulatory Liabilities | | $ | 516 |
| | $ | 301 |
| | $ | 477 |
| | $ | 512 |
|
| |
(1) | Includes the NBV and other related costs of Navajo and Sundt Units 1 and 2 reclassified from Utility Plant, Net on the Consolidated Balance Sheets due to the planned early retirement of the facilities. As of December 31, 2017, Navajo and Sundt Units 1 and 2 are being fully recovered in base rates using various useful lives through 2030. See Note 3 for additional information related to the planned early retirement of Navajo and Sundt Units 1 and 2. |
| |
(2)
| Amortized over the life of the assets. The balances include changes related to the revaluation of tax assets and liabilities as a result of the TCJA. See Note 1 and Note 1214 for additional information regarding income taxes. |
| |
(3)(2)
| Represents costs associated with TEP’s jointly-owned facilities at San Juan, Four Corners, and Navajo. TEP recognizes these costs at future value and is permitted to fully recover these costs through the PPFAC mechanism. The majority of final mine reclamation costs are expected to occur through 2037. |
| |
(4)
| Property taxes are recordedRecorded as a regulatory asset based on historical ratemaking treatment allowing regulated utilities recovery of property taxes on a pay-as-you-go or cash basis. TEP records a liability to reflect the accrual for financial reporting purposes and an offsetting regulatory asset to reflect recovery for regulatory purposes. This asset is fully recovered in rates with a recovery period of approximately six months. |
| |
(5)(3)
| Represents costs associated with TEP’s jointly-owned facilities at San Juan, Four Corners, and Navajo. TEP recognizes these costs at future value and is permitted to fully recover these costs on a pay-as-you-go basis through the PPFAC mechanism. The majority of final mine reclamation costs are expected to occur through 2038. |
| |
(4) | Represents investments TEP made, which were previously recorded in Plant in Service on the Consolidated Balance Sheets, to ensure that the facilities continued to provide safe, reliable service to TEP's customers. TEP received ACC authorization to recover leasehold improvement costs at Springerville Unit 1 over a 10-year amortization period. |
| |
(6)(5)
| In June 2014, the EPA issued a final rule that required TEP to either: (i) install, by mid-2017, SNCR and dry sorbent injection if Sundt Unit 4 continued to use coal as a fuel source; or (ii) permanently eliminate coal as a fuel source as a better-than-BART alternative by the end of 2017. In March 2016, TEP notified the EPA of its decision to permanently eliminate coal as a fuel source, and transferred the NBV of the Sundt Coal Handling Facilities to a regulatory asset. TEP applied excess depreciation reserves against the unrecovered NBV as approved in the 2017 Rate Order. |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
| |
(7)
| Represents an estimate of the future cost of retirement, net of salvage value. These are amounts collected through revenue for transmission, distribution, generation plant, and general and intangible plant which are not yet expended. As a result of the 2017 Rate Order, $87 million was transferred from Net Cost of Removal to Accumulated Depreciation and Amortization to reflect the impact of the revised depreciation study on the estimated cost of removal. |
| |
(8)(6)
| Represents federal energy credits generated after 2011 that are amortized over the tax life of the underlying asset. |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Early Generation Retirement Costs
Navajo Generating Station
In 2017, the Navajo Nation approved a land lease extension allowing TEP and the co-owners of Navajo to continue operations through December 2019 and begin decommissioning activities thereafter. TEP and the co-owners of Navajo retired the generation station in November 2019, with related decommissioning activities continuing through 2054. TEP is currently recovering the capital and operating costs in base rates using a useful life of 2030 for Navajo. Due to the early retirement, TEP requested recovery of final retirement costs over a 10-year period in the 2019 Rate Case.
Sundt Generating Station
In 2018, the Pima County Department of Environmental Quality approved TEP's air permit application. Under the project outlined in the application, TEP is placing in service 10 RICE units and was required to retire Sundt Units 1 and 2 in November 2019. TEP is currently recovering the capital and operating costs in base rates using useful lives of 2028 and 2030 for Sundt Units 1 and 2, respectively. Due to the early retirement, TEP requested recovery of final retirement costs over a 10-year period in the 2019 Rate Case. See Note 3 for additional information on the RICE units.
Regulatory Assets and Liabilities
Regulatory assets are either being collected or are expected to be collected through Retail Rates. With the exception of Early Generation Retirement Costs and Springerville Unit 1 Leasehold Improvements, TEP does not earn a return on regulatory assets. Regulatory liabilities represent items that TEP either expects to pay to customers through billing reductions in future periods or plans to use for the purpose for which they were collected from customers. With the exception of over-recovered PPFAC costs and Income Taxes Payable through Future Rates, TEP does not pay a return on regulatory liabilities.
FERC COMPLIANCE
In 2016, the FERC issued orders relating to certain late-filed TSAs, which resulted in TEP recording a liability and paying time-value refunds to the counterparties of these TSAs. In May 2017, the FERC informed TEP that the related investigation was closed. See Note 7 for additional information related to FERC compliance associated with these transmission contracts.
IMPACTS OF REGULATORY ACCOUNTING
If TEP determines that it no longer meets the criteria for continued application of regulatory accounting, TEP would be required to write off its regulatory assets and liabilities related to those operations not meeting the regulatory accounting requirements. Discontinuation of regulatory accounting could have a material impact on TEP's financial statements.
NOTE 3.UTILITY PLANT AND JOINTLY-OWNED FACILITIES
UTILITY PLANT
The following table shows Plant in Service on the Consolidated Balance Sheets by major class: | | | | Annual Depreciation Rate (4) | | Average Remaining Life in Years (4) | | December 31, | Annual Depreciation Rate (3) | | Average Remaining Life in Years (3) | | December 31, |
| ($ in millions) | | 2017 | | 2016 | | 2019 | | 2018 |
| Plant in Service | | | | | | | | |
| Generation Plant | 3.19% | | 25 | | $ | 2,548 |
| | $ | 2,866 |
| 3.19% | | 20 | | $ | 3,065 |
| | $ | 2,667 |
|
| Transmission Plant | 1.48% | | 32 | | 1,001 |
| | 1,024 |
| 1.69% | | 37 | | 1,060 |
| | 1,010 |
|
| Distribution Plant | 1.56% | | 36 | | 1,632 |
| | 1,512 |
| 1.56% | | 31 | | 1,784 |
| | 1,692 |
|
| General Plant | 5.89% | | 12 | | 389 |
| | 381 |
| 5.89% | | 20 | | 477 |
| | 409 |
|
Intangible Plant, Software Costs, and Other (1) | Various | | Various | | 207 |
| | 185 |
| Various | | Various | | 271 |
| | 239 |
|
| Plant Held for Future Use | — | | — | | 4 |
| | 7 |
| — | | — | | 7 |
| | 3 |
|
Total Plant in Service (2) | | $ | 5,781 |
| | $ | 5,975 |
| | $ | 6,664 |
| | $ | 6,020 |
|
| | | | | | |
Utility Plant Under Capital Leases (3) | | $ | 85 |
| | $ | 167 |
| |
| |
(1) | Primarily represents computer software. Unamortized computer software costs were $59$78 million and $52$73 million as of December 31, 20172019 and 2016,2018, respectively. The amortization ofAmortized computer software costs waswere $26 million in 2019, $24 million in 2018, and $19 million in 2017, $17 million in 2016, and $14 million in 2015.2017. Computer software is being amortized over its expected useful life ranging from three to five years for smaller application software and average remaining life of three years for large enterprise software. |
| |
(2) | Includes plant acquisition adjustments of $(134)$(211) million and $(139)$(134) million as of December 31, 20172019 and 2016,2018, respectively. |
| |
(3) | In December 2017, TEP completed the purchase of an undivided ownership interest in the Springerville Common Facilities. See Note 6 for additional information regarding the Springerville leases. |
| |
(4)
| Represents a composite of the depreciation rates of assets within each major class of utility plant and is basedBased on the 2015 depreciation study available for the major classes of Plant in Service. TEP implemented new depreciation ratesService, effective March 1, 2017, as approved by the ACC as part of the 2017 TEP Rate Order. TEP implemented new depreciation rates for Transmission Plant, based on the 2018 depreciation study, effective August 1, 2019, as approved in the 20172019 FERC Rate Order.Case. |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Gila River Unit 2
In 2017, TEP entered into a 20-year tolling PPA with SRP to purchase and receive all 550 MW of capacity, power, and ancillary services from Gila River Unit 2, which included a three-year option to purchase the unit. The Tolling PPA was accounted for as a finance lease. See Note 8 for additional information regarding TEP's leases. In December 2019, TEP completed its purchase of Gila River Unit 2 for $165 million. The purchase increased Plant in Service and Material and Supplies and decreased Utility Plant Under CapitalFinance Leases on the Consolidated Balance Sheets as of December 31, 2019.
All assets includedRICE Units
Under the air permit approved by the Pima County Department of Environmental Quality, TEP placed in
Utilityservice 5 natural gas RICE units in December 2019. As a result, Plant
Under Capital Leasesin Service on the Consolidated Balance Sheets increased by $82 million. An additional 5 units are
usedscheduled to be placed in
generation operations and amortized over the primary lease term. The following table shows the amount of lease expense incurred for capital leases: |
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2017 | | 2016 | | 2015 |
| Lease Expense | | | | | |
| Interest Expense included in: | | | | | |
| Interest Expense, Capital Leases | $ | 3 |
| | $ | 3 |
| | $ | 4 |
|
| Amortization of Capital Lease Assets included in: | | | | | |
| Operating Expenses, Fuel | — |
| | — |
| | 2 |
|
| Operating Expenses, Amortization | 6 |
| | 5 |
| | 6 |
|
| Total Lease Expense | $ | 9 |
| | $ | 8 |
| | $ | 12 |
|
Springerville Acquisitions
In September 2016, TEP purchased an undivided interest in Springerville Unit 1. The purchase increased TEP's total ownership interest to 100%. In December 2017, TEP purchased an undivided interestservice in the Springerville Common Facilities. first quarter of 2020. The 10 units have a planned total nominal generation capacity of 188 MW.
JOINTLY-OWNED FACILITIES
As of December 31, 2017, Utility Plant Under Capital Leases represented a 32.2% undivided interest in certain Springerville Common Facilities. See Note 6 for additional information regarding the Springerville capital lease purchases.
JOINTLY-OWNED FACILITIES
As of December 31, 2017,2019, TEP was a participant in the following jointly-owned generation facilities and transmission systems: |
| | | | | | | | | | | | | | | | | |
| (in millions) | Ownership Percentage | | Plant in Service | | Construction Work in Progress | | Accumulated Depreciation | | Net Book Value |
| San Juan Unit 1 | 50.0% | | $ | 289 |
| | $ | 1 |
| | $ | (193 | ) | | $ | 97 |
|
| Four Corners Units 4 and 5 | 7.0% | | 175 |
| | 5 |
| | (77 | ) | | 103 |
|
| Luna | 33.3% | | 57 |
| | — |
| | (1 | ) | | 56 |
|
| Gila River Unit 3 | 75.0% | | 200 |
| | 2 |
| | (61 | ) | | 141 |
|
| Gila River Common Facilities | 43.8% | | 71 |
| | — |
| | (23 | ) | | 48 |
|
| Springerville Coal Handling Facilities | 83.0% | | 208 |
| | — |
| | (90 | ) | | 118 |
|
| Transmission Facilities | Various | | 545 |
| | 5 |
| | (295 | ) | | 255 |
|
| Total | | | $ | 1,545 |
| | $ | 13 |
| | $ | (740 | ) | | $ | 818 |
|
|
| | | | | | | | | | | | | | | | | |
| (in millions) | Ownership Percentage | | Plant in Service | | Construction Work in Progress | | Accumulated Depreciation | | Net Book Value |
| San Juan Unit 1 | 50.0% | | $ | 274 |
| | $ | 6 |
| | $ | 83 |
| | $ | 197 |
|
| Four Corners Units 4 and 5 | 7.0% | | 113 |
| | 54 |
| | 79 |
| | 88 |
|
| Luna | 33.3% | | 55 |
| | — |
| | 3 |
| | 52 |
|
| Gila River Unit 3 | 75.0% | | 203 |
| | 3 |
| | 60 |
| | 146 |
|
| Gila River Common Facilities | 18.8% | | 25 |
| | — |
| | 8 |
| | 17 |
|
| Springerville Coal Handling Facilities | 83.0% | | 202 |
| | — |
| | 81 |
| | 121 |
|
| Transmission Facilities | Various | | 483 |
| | 5 |
| | 247 |
| | 241 |
|
| Total | | | $ | 1,355 |
| | $ | 68 |
| | $ | 561 |
| | $ | 862 |
|
As participants in these jointly-owned facilities, TEP is responsible for its share of operating and capital costs for the above facilities. The Company accounts for its share of operating expenses and utility plant costs related to these facilities using proportionate consolidation.
RETIREMENTS
San Juan Generating Station
In October 2014, the EPA published a final rule approving a SIP covering BART requirements for San Juan, which included the closure of Units 2 and 3 by December 2017. TEP is a participant in San Juan Units 1 and 2. Given the closure of Units 2 and 3 and the desire of certain participants to exit their ownership in San Juan, PNM, TEP, and the other participants negotiated restructured ownership agreements which became effective upon the sale of San Juan Coal Company (SJCC) stock in January 2016. Under the new restructured ownership agreements, TEP and the other remaining participants have the option to exit their remaining ownership interests in San Juan as of June 30, 2022.
In 2017, TEP recorded the early retirement San Juan Unit 2 and applied excess depreciation reserves against the unrecovered NBV as approved in the 2017 Rate Order. The Consolidated Balance Sheets reflect a $224 million decrease in Plant in Service and Accumulated Depreciation and Amortization related to San Juan Unit 2. On December 20, 2017, San Juan Unit 2 was removed from service. See Note 2 for additional information regarding the 2017 Rate Order.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Navajo Generating Station
In 2017, the Navajo Nation approved a land lease extension which allows TEP and the co-owners of Navajo to continue operations through December 2019 and begin decommissioning activities thereafter. TEP is currently recovering Navajo's capital and operating costs in base rates using a useful life of 2030. As a result of the planned early retirement of Navajo, $52 million of the facility's NBV and other related costs were reclassified from Utility Plant, Net to Regulatory Assets on the Consolidated Balance Sheets as of December 31, 2017. See Note 2 for additional information related to the planned early retirement of Navajo.
Sundt Generating Station
In March 2016, TEP notified the EPA of its decision to permanently eliminate coal as a fuel source to comply with the EPA rules and transferred the NBV of the coal handling facilities at Sundt to a regulatory asset. As approved in the 2017 Rate Order, TEP applied excess depreciation reserves against the regulatory asset as of December 31, 2017. See Note 2 for additional information regarding the 2017 Rate Order.
In 2017, TEP submitted an Air Quality Permit Application (Application) to the Pima County Department of Environmental Quality (PDEQ) related to a generation modernization project at Sundt that will add generation capacity in the form of RICE generators in 2019 and 2020. As part of the Application, TEP plans to early retire Sundt Units 1 and 2 by the end of 2020. TEP is currently recovering capital and operating costs for Sundt Units 1 and 2 in base rates using useful lives of 2028 and 2030, respectively. As a result of the planned early retirement, $31 million of the facilities' NBV was reclassified from Utility Plant, Net to Regulatory Assets on the Consolidated Balance Sheets as of December 31, 2017. See Note 2 for additional information related to the planned early retirement of Sundt Units 1 and 2.
ASSET RETIREMENT OBLIGATIONS
The liability accrual of AROs is primarily related to generation and PV assets and is included in Regulatory and Other Liabilities—Other on the Consolidated Balance Sheets. The following table reconciles the beginning and ending aggregate carrying amounts of ARO accruals on the Consolidated Balance Sheets: | | | | December 31, | December 31, |
| (in millions) | 2017 | | 2016 | 2019 | | 2018 |
| Beginning of Period | $ | 33 |
| | $ | 32 |
| $ | 72 |
| | $ | 46 |
|
| Liabilities Incurred | 3 |
| | — |
| — |
| | 10 |
|
Liabilities Settled | (1 | ) | | — |
| (2 | ) | | — |
|
| Regulatory Deferral/Accretion Expense | 2 |
| | 2 |
| 2 |
| | 3 |
|
Revisions to the Present Value of Estimated Cash Flows (1)(2) | 9 |
| | (1 | ) | 35 |
| | 13 |
|
| End of Period | $ | 46 |
| | $ | 33 |
| $ | 107 |
| | $ | 72 |
|
| |
(1) | Primarily related to the retirement of Navajo. |
| |
(2) | Primarily related to changes in expected costdue to revised estimates andof the accelerationtiming of asset retirement datescash flows required to settle future liabilities of certain generation facilities. |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
NOTE 4. REVENUE
TEP earns the majority of its revenues from the sale of power to retail and wholesale customers based on regulator-approved tariff rates. Most of the Company's contracts have a single performance obligation, the delivery of power. TEP has certain contracts with variable transaction pricing that require it to estimate the expected consideration.
DISAGGREGATION OF REVENUES
The following table presents the disaggregation of TEP’s Operating Revenues on the Consolidated Statements of Income by type of service: |
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2019 | | 2018 | | 2017 |
| Retail | $ | 972 |
| | $ | 1,022 |
| | $ | 1,017 |
|
| Wholesale | 247 |
| | 238 |
| | 152 |
|
| Other Services | 124 |
| | 100 |
| | 103 |
|
| Revenues from Contracts with Customers | 1,343 |
| | 1,360 |
| | 1,272 |
|
| Alternative Revenues | 35 |
| | 28 |
| | 24 |
|
| Other | 40 |
| | 45 |
| | 45 |
|
| Total Operating Revenues | $ | 1,418 |
| | $ | 1,433 |
| | $ | 1,341 |
|
Retail Revenues
TEP’s tariff-based sales to residential, commercial, and industrial customers are regulated by the ACC and recognized when power is delivered at the amount of consideration that the Company expects to receive in exchange. Retail revenues include an estimate for unbilled revenues from service that has been provided but not billed by the end of an accounting period. At the end of the month, amounts of power delivered since the last meter reading are estimated and the corresponding unbilled revenue is calculated using anticipated Retail Rates. Unbilled revenues are dependent upon a number of factors that require management’s judgment including estimates of retail sales, customer usage patterns, and pricing. Unbilled revenues primarily increase during the spring and summer months and decrease during the fall and winter months due to the seasonal fluctuations of TEP’s actual load. The timing of revenue recognition, billings, and cash collections results in billed and unbilled accounts receivable balances in the balance sheet. See Note 5 for components of Accounts Receivable, Net on the Consolidated Balance Sheets.
Wholesale Revenues
TEP’s operations include the wholesale marketing of electricity and transmission to other utilities and power marketers, which may include capacity, power, transmission, and ancillary services. When TEP promises to provide distinct services within a contract, the Company identifies one or more performance obligations. The Company recognizes revenue for wholesale and transmission sales at FERC-approved rates based on demand (for capacity) or the reading of meters (for power). For contracts with multiple performance obligations, all deliverables are eligible for recognition in the month of production; therefore, it is not necessary to allocate the transaction price among the identified performance obligations. For purchased power and wholesale sales contracts that are settled financially, TEP nets the purchased power contracts with the sales contracts and reflects the amount in Operating Revenues on the Consolidated Statements of Income.
In May 2019, TEP filed a proposal with the FERC requesting revisions to its OATT. The filing proposed replacing TEP's stated transmission rates with a forward-looking formula rate. Effective August 2019, the FERC authorized TEP to bill the proposed rate revisions, subject to refund. TEP began to recognize a provision for revenues subject to refund for the estimate of revenues that are probable for refund. See Note 2 for more information regarding the FERC rate case.
Other Services Revenues
Other Services Revenues primarily include fees earned as operator of Springerville Units 3 and 4, miscellaneous service-related revenues, and reimbursement of various operating expenses for the use of the Springerville Common Facilities by Springerville Units 3 and 4 and the Springerville Coal Handling Facilities by Springerville Unit 3. When TEP recognizes revenue for reimbursement of Springerville Common Facilities and Springerville Coal Handling Facilities' operating expenses, the associated expenses are recorded in their respective line items in the income statement based on the nature of services provided.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Alternative Revenues
Alternative revenue programs allow utilities to adjust future rates in response to past activities or completed events if certain criteria established by a regulator are met. TEP has identified its LFCR mechanism and DSM performance incentive as alternative revenues. The LFCR mechanism provides for recovery of certain non-fuel costs that would go unrecovered due to reduced retail kWh sales as a result of implementing ACC-approved energy efficiency programs and customer-installed DG. The LFCR surcharge is assessed as a percentage of the customer’s bill. Revenue recognition related to the LFCR mechanism creates a regulatory asset until such time as the revenue is collected. For recovery of the LFCR regulatory asset, TEP is required to file an annual LFCR adjustment request with the ACC for the LFCR revenues recognized in the prior year. The recovery is subject to a year-over-year cap of applicable retail revenues of 2%. In addition, the ACC approves a new DSM surcharge annually, which is effective June 1 of each year, to compensate TEP for the costs to design and implement cost-effective energy efficiency and demand response programs until such costs are reflected in TEP’s non-fuel base rates as well as a performance incentive. TEP collects the DSM surcharge on a per kWh basis for residential customers and on a percentage of bill basis for non-residential customers. See Note 2 for additional information regarding these cost recovery mechanisms.
Other Revenues
Other Revenues include gains and losses on derivative contracts, late and returned payment finance charges, and lease income. See Note 13 for information regarding derivative instruments and Note 8 for information regarding lease income.
NOTE 4.5. ACCOUNTS RECEIVABLE
The following table presents the components of Accounts Receivable, Net on the Consolidated Balance Sheets: | | | | December 31, | December 31, |
| (in millions) | 2017 | | 2016 | 2019 | | 2018 |
Customer | $ | 81 |
| | $ | 74 |
| $ | 92 |
| | $ | 99 |
|
| Due from Affiliates (Note 5) | 7 |
| | 9 |
| |
| Unbilled | 39 |
| | 34 |
| |
| Customer, Unbilled | | 42 |
| | 45 |
|
| Due from Affiliates (Note 6) | | 8 |
| | 8 |
|
| Other | 16 |
| | 13 |
| 19 |
| | 25 |
|
| Allowance for Doubtful Accounts | (5 | ) | | (5 | ) | (6 | ) | | (5 | ) |
| Accounts Receivable, Net | $ | 138 |
| | $ | 125 |
| $ | 155 |
| | $ | 172 |
|
| |
(1) | Includes $5 million and $8 million as of December 31, 2019 and 2018, respectively, of receivables related to revenue from derivative instruments. |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
NOTE 5.6. RELATED PARTY TRANSACTIONS
TEP engages in various transactions with Fortis, UNS Energy, and its affiliated subsidiaries including UNS Electric, Inc. (UNS Electric), UNS Gas, Inc. (UNS Gas), and Southwest Energy Solutions, Inc. (SES) (collectively,the UNS Energy Affiliates).Affiliates. These transactions includeinclude: (i) the sale and purchase of power and transmission services,services; (ii) common cost allocations,allocations; and (iii) the provision of corporate and other labor relatedlabor-related services.
The following table presents the components of related party balances included in Accounts Receivable, Net and Accounts Payable on the Consolidated Balance Sheets: | | | | December 31, | December 31, |
| (in millions) | 2017 | | 2016 | 2019 | | 2018 |
| Receivables from Related Parties | | | | | | |
| UNS Electric | $ | 5 |
| | $ | 7 |
| $ | 6 |
| | $ | 7 |
|
| UNS Gas | 2 |
| | 2 |
| 2 |
| | 1 |
|
| Total Due from Related Parties | $ | 7 |
| | $ | 9 |
| $ | 8 |
| | $ | 8 |
|
| | | | | | | |
| Payables to Related Parties | | | | | | |
| SES | $ | 3 |
| | $ | 2 |
| $ | 2 |
| | $ | 2 |
|
| UNS Electric | | 1 |
| | 1 |
|
| UNS Gas | | — |
| | 1 |
|
| UNS Energy | 1 |
| | — |
| 1 |
| | 1 |
|
| Total Due to Related Parties | $ | 4 |
| | $ | 2 |
| $ | 4 |
| | $ | 5 |
|
The following table presents the components of related party transactions included in the Consolidated Statements of Income: | | | | Years Ended December 31, | Years Ended December 31, |
| (in millions) | 2017 | | 2016 | | 2015 | 2019 | | 2018 | | 2017 |
| Goods and Services Provided by TEP to Affiliates | | | | | | | | | | |
Transmission Revenues, UNS Electric (1) | $ | 7 |
| | $ | 7 |
| | $ | 6 |
| $ | 7 |
| | $ | 6 |
| | $ | 7 |
|
Wholesale Revenues, UNS Electric (1) | — |
| | — |
| | 2 |
| 1 |
| | 1 |
| | — |
|
Control Area Services, UNS Electric (2) | 3 |
| | 2 |
| | 2 |
| 4 |
| | 3 |
| | 3 |
|
Common Costs, UNS Energy Affiliates (3) | 16 |
| | 14 |
| | 12 |
| 19 |
| | 18 |
| | 16 |
|
Corporate Services, Fortis Affiliates (4) | 2 |
| | — |
| | — |
| — |
| | — |
| | 2 |
|
| | | | | | | | | | | |
| Goods and Services Provided by Affiliates to TEP | | | | | | | | | | |
Wholesale Revenues, UNS Electric (1) | — |
| | 1 |
| | 1 |
| |
Supplemental Workforce, SES (5) | 15 |
| | 14 |
| | 16 |
| 15 |
| | 15 |
| | 15 |
|
Corporate Services, UNS Energy (6) | 5 |
| | 7 |
| | 7 |
| 6 |
| | 6 |
| | 5 |
|
Corporate Services, UNS Energy Affiliates (7) | 5 |
| | 4 |
| | 1 |
| 4 |
| | 7 |
| | 5 |
|
Capacity Charges, UNS Gas (8) | | 1 |
| | 1 |
| | — |
|
| |
(1) | TEP and UNS Electric sell power and transmission services to each other. Wholesale power is sold at prevailing market prices, while transmission services are sold at FERC approvedFERC-approved rates through the applicable Open Access Transmission Tariff.OATT. |
| |
(2) | TEP charges UNS Electric for control area services under a FERC-approved Control Area Services Agreement. |
| |
(3) | Common costs (information systems, facilities, etc.) are allocated on a cost-causative basis and recorded as revenue by TEP. The method of allocation is deemed reasonable by management and is reviewed by the ACC as part of the rate case process. |
| |
(4) | TEP provides non-tariffed goods and services to Fortis affiliate companies at the higher of fully burdened cost or fair market value. |
| |
(5) | SES provides supplemental workforce and meter-reading services to TEP based on related party service agreements. The charges are based on cost of services performed and deemed reasonable by management. |
| |
(6) | Costs for corporate services at UNS Energy are allocated to its subsidiaries using the Massachusetts Formula, an industry accepted method of allocating common costs to affiliated entities. TEP's allocation is approximately 82%83% of UNS Energy's allocated costs. Corporate Services, UNS Energy includes legal, audit, and Fortis Management fees. TEP's share of Fortis' management fees were $6 million in both 2017 and 2016, and $5 million in 2015. |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Corporate Services, UNS Energy includes legal, audit, and Fortis' management fees. TEP's share of Fortis' management fees were $6 million in 2019, $5 million in 2018, and $6 million in 2017.
| |
(7) | Costs for corporate services (e.g., finance, accounting, tax, legal, and information technology) and other labor services for UNS Energy Affiliates are directly assigned to the benefiting entity at a fully burdened cost when possible. |
| |
(8) | UNS Gas charges TEP for natural gas capacity used to supply 1 of TEP's generation facilities. |
CONTRIBUTIONCONTRIBUTIONS FROM PARENT
UNS Energy made noIn January 2020, an equity contributions tocontribution of $125 million was received by TEP in 2017 or 2016. TEP received a contribution from UNS Energy of $180 million in 2015. The contributions were used to repay revolving credit loans, redeem bonds, purchase additional generation capacity, and provide additional liquidity to TEP.Energy.
DIVIDENDS PAID TO PARENT
TEP declared and paid $70 million in dividends to UNS Energy in 2017 and $50 million in both 2016 and 2015.
NOTE 6.7. DEBT AND CREDIT FACILITY, AND CAPITAL LEASE OBLIGATIONSAGREEMENTS
DEBT
Long-term debt matures more than one year from the date of the financial statements. The following table presents the components of Long-Term Debt, Net on the Consolidated Balance Sheets: |
| | | | | | | | | | | |
| | | | | | December 31, |
| ($ in millions) | Interest Rate | | Maturity Date | | 2019 | | 2018 |
| Notes | | | | | | | |
| 2011 Notes | 5.15% | | 2021 | | $ | 250 |
| | $ | 250 |
|
| 2012 Notes | 3.85% | | 2023 | | 150 |
| | 150 |
|
| 2014 Notes | 5.00% | | 2044 | | 150 |
| | 150 |
|
| 2015 Notes | 3.05% | | 2025 | | 300 |
| | 300 |
|
| 2018 Notes | 4.85% | | 2048 | | 300 |
| | 300 |
|
Tax-Exempt Local Furnishings Bonds (1) | | | | | | | |
| 2010 Pima A | 5.25% | | 2040 | | 100 |
| | 100 |
|
| 2012 Pima A | 4.50% | | 2030 | | 16 |
| | 16 |
|
| 2013 Pima A | 4.00% | | 2029 | | 91 |
| | 91 |
|
Tax-Exempt Pollution Control Bonds (2) | | | | | | | |
| 2009 Pima A | 4.95% | | 2020 | | 80 |
| | 80 |
|
| 2009 Coconino A | 5.13% | | 2032 | | — |
| | 15 |
|
| 2012 Apache A | 4.50% | | 2030 | | 177 |
| | 177 |
|
Total Long-Term Debt (3) | | | | | 1,614 |
| | 1,629 |
|
| Less Unamortized Discount and Debt Issuance Costs | | | | | 12 |
| | 14 |
|
| Less Current Maturities of Long-Term Debt | | | | | 80 |
| | — |
|
| Total Long-Term Debt, Net | | | | | $ | 1,522 |
| | $ | 1,615 |
|
|
| | | | | | | | | | | |
| | | | | | December 31, |
| ($ in millions) | Interest Rate | | Maturity Date | | 2017 | | 2016 |
| Notes | | | | | | | |
| 2011 Notes | 5.15% | | 2021 | | $ | 250 |
| | $ | 250 |
|
| 2012 Notes | 3.85% | | 2023 | | 150 |
| | 150 |
|
| 2014 Notes | 5.00% | | 2044 | | 150 |
| | 150 |
|
| 2015 Notes | 3.05% | | 2025 | | 300 |
| | 300 |
|
| Tax-Exempt Local Furnishings Bonds | | | | | | | |
| 2010 Pima A | 5.25% | | 2040 | | 100 |
| | 100 |
|
| 2012 Pima A | 4.50% | | 2030 | | 16 |
| | 16 |
|
| 2013 Pima A | 4.00% | | 2029 | | 91 |
| | 91 |
|
2013 Apache A (1) | 1.41% | | 2032 | | 100 |
| | 100 |
|
| Tax-Exempt Pollution Control Bonds | | | | | | | |
| 2009 Pima A | 4.95% | | 2020 | | 80 |
| | 80 |
|
| 2009 Coconino A | 5.13% | | 2032 | | 15 |
| | 15 |
|
2010 Coconino A (2) | 1.76% | | 2032 | | 37 |
| | 37 |
|
| 2012 Apache A | 4.50% | | 2030 | | 177 |
| | 177 |
|
Total Long-Term Debt (3) | | | | | 1,466 |
| | 1,466 |
|
| Less Unamortized Discount and Debt Issuance Costs | | | | | 12 |
| | 13 |
|
Less Current Maturities of Long-Term Debt (1) | | | | | 100 |
| | — |
|
| Total Long-Term Debt, Net | | | | | $ | 1,354 |
| | $ | 1,453 |
|
| |
(1) | The 2010 Pima A bonds are variable rate debt for which rates are reset monthly. The interest rate is calculated using a weighted average basedcan be redeemed at par on a percentageor after October 2020. TEP has the option to redeem the remaining bonds at par on dates ranging from first quarter of an index equal2022 to one-month LIBOR plus a credit spread. The bonds are subject to mandatory tender for purchase in November 2018, and were reclassified to Current Maturitiesfirst quarter of Long-Term Debt on the Consolidated Balance Sheets as of December 31, 2017.2023. |
| |
(2) | The 2009 Pima A bonds are variable rate debt for which rates are reset weekly.mature in October 2020. The interest rate is calculated using a weighted average and includes LOC fees and remarketing fees. The2012 Apache A bonds are backed by an LOC issued pursuant tomay be redeemed at par in the 2010 Reimbursement Agreement, which expires in February 2019.first quarter of 2022. |
| |
(3) | As of December 31, 2017,2019, all of TEP's debt is unsecured, with the exception of the 2010 Coconino A variable rate bonds, which are backed by an LOC.unsecured. |
Issuances and Redemptions
Fixed Rate Debt
In November 2019, TEP redeemed at par a series of fixed rate tax-exempt bonds with an aggregate principal amount of $15 million prior to the maturity of the bonds.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
DEBT ISSUANCES AND REDEMPTIONS
Fixed Rate Debt
In February 2015,November 2018, TEP issued and sold $300 million aggregate principal amount of senior unsecured notes. TEP may redeem the notes prior to December 2024,June 1, 2048, with a make-whole premium plus accrued interest. On or after December 2024,June 1, 2048, TEP may redeem the notes at par plus accrued interest.
In January 2015, TEP purchased $130 million aggregate principal amount of unsecured tax-exempt IDRBs issued in June 2008 by the Industrial Development Authority (IDA) of Pima County, Arizona for the benefit of TEP. The bonds were not remarketed and were subsequently retired in September 2017.
Variable Rate Debt
In August 2015,December 2018, TEP redeemed twoat par a series of variable rate tax-exempt bonds at par with an aggregate principal amount of $79$37 million prior to maturity.the maturity of the bonds. The bonds were backed by an LOC issued pursuant to the 2010 Reimbursement Agreement which expired in February 2019. In September 2015, TEP terminatedconnection with the redemption of the related bonds, the $37 million LOC and the associated LOCs issued2010 Reimbursement Agreement were terminated.
In November 2018, TEP redeemed at par a series of variable rate tax-exempt bonds with an aggregate principal amount of $100 million prior to the maturity of the bonds. The bonds were subject to mandatory tender for purchase in November 2018.
Maturities
Long-term debt matures on the following dates: |
| | | |
| (in millions) | Long-Term Debt (1) |
| 2020 | $ | 80 |
|
| 2021 | 250 |
|
| 2022 | — |
|
| 2023 | 150 |
|
| 2024 | — |
|
| Thereafter | 1,134 |
|
| Total | $ | 1,614 |
|
| |
(1) | Total long-term debt excludes $10 million of related unamortized debt issuance costs and $2 million of unamortized original issue discount. |
CREDIT AGREEMENTS
Amounts borrowed under credit agreements are recorded in Borrowings Under Credit Agreements on the Consolidated Balance Sheets.
2019 Credit Agreement
In December 2019, TEP entered into an unsecured credit agreement with a revolving credit facility.maturity date of December 2020 that provides for term loans. Terms are as follows: CREDIT FACILITY |
| | | | | | | | | | | | | | | | | |
| | | | | | | | Weighted Average Interest Rate | | | |
| | Capacity | | Borrowed (1) | | Available | | | Pricing |
| (in millions) | December 31, 2019 |
| Term Loan | $ | 225 |
| | $ | 165 |
| | $ | 60 |
| | 4.75 | % | | LIBOR + 0.550% | or ABR + 0.00% |
| |
(1) | All amounts borrowed will be due and payable by December 2020. |
The 2019 Credit Agreement is intended to supplement TEP's liquidity during a period of increased capital spending and to provide funds: (i) to complete the purchase of Gila River Unit 2 Generating Station; (ii) to make payments for the construction of the Oso Grande project; and (iii) for other general corporate purposes. Amounts paid or repaid may not be reborrowed. As of February 12, 2020, 0 amount was available as the term loan had been fully drawn. See Note 3 and Note 9 for additional information on the purchase of Gila River Unit 2 and Oso Grande, respectively.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
2015 Credit Agreement
In October 2015, TEP entered into an unsecured credit agreement which replaced its previous credit agreements. The credit facility included: (i) a borrowing capacity of $250 million in revolving credit commitments; (ii) an LOC facility with a sublimit of $50 million; and (iii) an original maturity date of October 2020 with a provision allowing TEP to request up to twoone-year maturity extensions.2022 that provides for revolving credit commitments and LOC facilities. Terms are as follows: |
| | | | | | | | | | | | | | | | | | | | | |
| | Capacity | | Sub-Limit LOC | | Borrowed | | Available | | Weighted Average Interest Rate | | Pricing (1) |
| (in millions) | December 31, 2019 |
| Revolver and LOC | $ | 250 |
| | $ | 50 |
| | $ | — |
| | $ | 250 |
| | — | % | | LIBOR + 1.000% | or ABR + 0.00% |
As permitted by the credit agreement, TEP requested and was granted twoone-year extensions. The facility's new maturity date is October 2022. |
| | | | | | | | | | | | | | | | | | | | | |
| (in millions) | December 31, 2018 |
| Revolver and LOC | $ | 250 |
| | $ | 50 |
| | $ | — |
| | $ | 250 |
| | — | % | | LIBOR + 1.000% | or ABR + 0.00% |
| |
(1) | Interest rates and fees are based on a pricing grid tied to TEP's credit rating. |
Interest rates and fees under the credit facility are based on a pricing grid tied to TEP’s credit ratings. The interest rate currently in effect on borrowings is LIBOR plus 1.00% for Eurodollar loans or ABR with no spread for ABR loans.
TEP expects that amountsAmounts borrowed under the credit agreement2015 Credit Agreement will be used for working capital and other general corporate purposes and thatpurposes. LOCs will be issued from time to time to support energy procurement, hedging transactions, and hedging transactions. Asother business activities.
In January 2020, TEP delivered $12 million in LOCs pursuant to TEP taking ownership of December 31, 2017, TEP had $35 million borrowings outstanding included in Current Liabilities onOso Grande under the Consolidated Balance Sheets.build-transfer agreement. As of February 14, 2018,12, 2020, there was $232$173 million available under the revolving credit commitments and LOC facilities.
TEP's previous credit agreements provided for a total of $270 million in revolving credit commitments, LOCs supporting variable-rate, tax-exempt bonds, and a $130 million term loan commitment, with original expiration dates of November 2016 and November 2015, respectively.
2010 REIMBURSEMENT AGREEMENT
In December 2010, a $37 million LOC was issued to support certain variable rate tax-exempt bonds pursuant to the 2010 Reimbursement Agreement. The LOC has an expiration date of February 2019. Fees are payable on the aggregate outstanding amount of the LOC at a rate of 0.75% per annum based on TEP's current credit ratings.
COVENANT COMPLIANCE
Certain of TEP's credit and long-term debt agreements contain restrictive covenants, including restrictions on additional indebtedness, liens to secure indebtedness, mergers, sales of assets, transactions with affiliates, and restricted payments. As of December 31, 2017, TEP was in compliance with the terms of its credit and long-term debt agreements.
CAPITAL LEASE OBLIGATIONS
The following table details Capital Lease Obligations on the Consolidated Balance Sheets: |
| | | | | | | |
| | December 31, |
| (in millions) | 2017 | | 2016 |
| Capital Lease Obligations | $ | 39 |
| | $ | 91 |
|
| Less Current Obligations Under Capital Leases | 11 |
| | 52 |
|
| Total Capital Lease Obligations, Non-Current | $ | 28 |
| | $ | 39 |
|
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) NOTE 8. LEASES
Springerville Unit 1 Capital Lease Purchases
In January 2015, upon expiration of the lease term, TEP purchased leased interests comprising 24.8% of Springerville Unit 1, representing 96 MW of capacity, forleases an aggregate purchase price of $46 million, the appraised value. With the completion of the purchase, TEP owned 49.5% of Springerville Unit 1, or 192 MW of capacity.
In September 2016, TEP purchased the remaining undivided interest in Springerville Unit 1Common Facilities, land, rail cars, and communication tower space with remaining terms of one to 22 years. Most leases include one or more options to renew, with renewal terms that may extend a lease term for $85 million, bringing its total ownershipup to 15 years. Certain lease agreements include rental payments adjusted periodically for inflation or require TEP to pay real estate taxes, insurance, maintenance, or other operating expenses associated with the lease premises.
TEP’s leases are included in the balance sheet as follows: |
| | | | | |
| (in millions) | Lease Type | | December 31, 2019 |
| Lease Assets | | | |
| Utility Plant Under Finance Leases | Finance | | $ | 151 |
|
| Accumulated Amortization of Finance Lease Assets | Finance | | (77 | ) |
| Regulatory and Other Assets, Other | Operating | | 8 |
|
| Lease Liabilities | | | |
| Current Liabilities, Finance Lease Obligations | Finance | | 17 |
|
| Finance Lease Obligations | Finance | | 67 |
|
| Current Liabilities, Other | Operating | | 1 |
|
| Regulatory and Other Liabilities, Other | Operating | | 6 |
|
Springerville Common Facilities Leases
TEP finances a portion of the assetsSpringerville Common Facilities with finance leases. In December 2019, TEP elected to 100% and total generating capacity to 387 MW. See Note 7 for more information regarding the settlement agreement relating to Springerville Unit 1.
Springerville Coal Handling Facilities Lease Purchase
In April 2015, upon expiration of the lease term, TEP purchased an 86.7% undivided ownership interest in the Springerville Coal Handling Facilities at the fixed purchase price of $120 million, bringing its total ownership of the assets to 100%. Upon purchase of the leased interest, TEP reduced Capital Lease Obligations on the Consolidated Balance Sheets for the purchase price.
In May 2015, SRP, the owner of Springerville Unit 4, purchased from TEP a 17.05%32.2% undivided interest in the Springerville Coal Handling Facilities for approximately $24 million.
Springerville Common Facilities Leases
Asby January 2021 for $68 million. The lease assets are amortized over the estimated life of December 31, 2017, the Springerville Common Facilities Leases include two leases with a total fixed price purchase optionsunderlying plant because ownership of $68 million and initial terms ending January 2021.
Under the two leases, TEP has options to: (i) renewplant transfers at the leases for periodsend of two or more years; or (ii) exercise the fixed price purchase options under these contracts.lease term. In addition, TEP entered intohas agreements with Tri-State, the lessee of Springerville Unit 3, and SRP, the owner of Springerville Unit 4, that contain the following conditions if the Common Facilities Leases are not renewed: (i)should TEP will exercisecomplete the purchase options under these contracts; (ii)of the Springerville Common Facilities: (i) SRP will be obligated to buy a 14% undivided interest in the facilities; and (iii)(ii) Tri-State will be obligated to either: (a) buy a 14% undivided interest in the facilities; or (b) continue to make payments to TEP for the use of these facilities.
Gila River Unit 2
In December 2017, TEP purchasedMay 2018, TEP recorded an increase to finance lease assets and obligations related to a 17.8% undivided interest in the Springerville Common Facilities for$38 million, bringing its total ownership of the assets to 67.8%. Upon purchase of the leased interest, TEP reduced Current Lease Obligations on the Consolidated Balance Sheets by $36 million.
Springerville Common Facilities Lease Interest Rate Swap
TEP20-year Tolling PPA with SRP, entered into an interest rate swap agreement in 2006 that hedges a portion2017, to purchase and receive all 550 MW of the floating interest rate risk associated with the Springerville Common Facilities lease debt.capacity, power, and ancillary services from Gila River Unit 2. The swap has the effect of fixing the benchmark LIBOR rate on a portion of the amortizing principal balance. The swap matures in January 2020 with interest on the lease debt payable at a swapped rate of 5.77% plus an applicable margin per the lease agreement. The lease debt outstanding as of December 31, 2017 consisted of a notional amount of $18 million on which interest was fixed by the swap and a notional amount of $3 million of debt that was not hedged. The applicable margin was 1.88% as of December 31, 2017 and 2016.
TEP recorded the interest rate swap as a cash flow hedge for financial reporting purposes. See Cash Flow Hedges in Note 11 for additional information.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
DEBT MATURITIESTolling PPA included a three-year option to purchase the unit. TEP exercised its option and subsequently purchased Gila River Unit 2 in December 2019 at which time the lease asset and obligation were removed.
Long-term debt, including revolving credit facilities classified as long-term, and capitalThe following table presents the components of TEP’s lease obligations mature on the following dates:cost: |
| | | | | | | | | | | |
| (in millions) | Long-Term Debt(1) | | Capital Lease Obligations | | Total Debt Maturities(2) |
| 2018 | $ | 100 |
| | $ | 11 |
| | $ | 111 |
|
| 2019 | 37 |
| | 11 |
| | 48 |
|
| 2020 | 80 |
| | 18 |
| | 98 |
|
| 2021 | 250 |
| | — |
| | 250 |
|
| 2022 | — |
| | — |
| | — |
|
| Total 2018 - 2022 | 467 |
| | 40 |
| | 507 |
|
| Thereafter | 999 |
| | — |
| | 999 |
|
| Less: Imputed Interest | — |
| | (1 | ) | | (1 | ) |
| Total | $ | 1,466 |
| | $ | 39 |
| | $ | 1,505 |
|
|
| | | |
| | Year Ended |
| (in millions) | December 31, 2019 |
| Finance | |
Amortization of Leased Assets (1) | $ | 13 |
|
Interest on Lease Liabilities (2) | 13 |
|
| Operating | 1 |
|
| Variable | 16 |
|
| Short Term | 1 |
|
| Total Lease Cost | $ | 44 |
|
| |
(1) | $37TEP deferred $6 million in amortization related to Gila River Unit 2 in Regulatory and Other Assets—Regulatory Assets based on PPFAC recovery of TEP’s variable rate bonds are backed by an LOC issued pursuant to the 2010 Reimbursement Agreement, which expires in February 2019. Although the variable rate bond matures in 2032, the above table reflects a redemption or repurchase of such bond in 2019 as though the LOC terminates without replacement upon expiration of the 2010 Reimbursement Agreement. TEP's 2013 tax-exempt variable rate IDRBs, which have an aggregate principal amount of $100 million and mature in 2032, are subject to mandatory tender for purchase in November 2018.fixed capacity payment. |
| |
(2) | Total long-term debt excludes $10Finance lease interest expense is recorded in Interest Expense on the Consolidated Statements of Income. In 2018, lease interest expense related to Gila River Unit 2 was recorded in Purchased Power on the Consolidated Statements of Income. Finance lease interest expense related to Gila River Unit 2 was $12 million of related unamortized debt issuance costs and $2 million of unamortized original issue discount.for the year ended December 31, 2019. TEP purchased Gila River Unit 2 in December 2019. |
TEP has a 20-year lease for energy storage with variable payments contingent on performance, which is expected to commence by the fourth quarter of 2020.
As of December 31, 2019, TEP had the following future minimum lease payments, excluding payments to lessors for variable costs: |
| | | | | | | | | | | |
| (in millions) | Finance Leases | | Operating Leases | | Total |
| 2020 | $ | 18 |
| | $ | 1 |
| | $ | 19 |
|
| 2021 | 68 |
| | 1 |
| | 69 |
|
| 2022 | — |
| | 1 |
| | 1 |
|
| 2023 | — |
| | 1 |
| | 1 |
|
| 2024 | — |
| | 1 |
| | 1 |
|
| Thereafter | — |
| | 4 |
| | 4 |
|
| Total Lease Payments | 86 |
| | 9 |
| | 95 |
|
| Less Imputed Interest | 2 |
| | 2 |
| | 4 |
|
| Total Lease Obligations | 84 |
| | 7 |
| | 91 |
|
| Less Current Portion | 17 |
| | 1 |
| | 18 |
|
| Total Non-Current Lease Obligations | $ | 67 |
| | $ | 6 |
| | $ | 73 |
|
The following table presents TEP's lease terms and discount rate related to its leases: |
| | |
| December 31, 2019 |
| Weighted-Average Remaining Lease Term (years) | |
| Finance Leases | 1 |
|
| Operating Leases | 12 |
|
| Weighted-Average Discount Rate | |
| Finance Leases | 2.2 | % |
| Operating Leases | 4.1 | % |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table presents TEP's cash flow information related to its leases: |
| | | |
| | Year Ended |
| (in millions) | December 31, 2019 |
| Cash Paid for Amounts Included in the Measurement of Lease Liabilities | |
| Operating Cash Flows used for Finance Leases | $ | 13 |
|
| Operating Cash Flows used for Operating Leases | 1 |
|
| Financing Cash Flows used for Finance Leases | 11 |
|
| Investing Cash Flows used for Finance Leases | 164 |
|
See Note 12 for non-cash transactions that resulted in recognition of right-of-use assets in exchange for lease liabilities.
In addition, TEP leases limited office facilities and utility property to others with remaining terms of four to thirteen years. Most leases include 1 or more options to renew, with renewal terms that may extend a lease term for up to three years.
Operating lease income for the year ended December 31, 2019, was $1 million. TEP's expected operating lease payments to be received as of December 31, 2019, are $1 million in each of 2020 through 2024 and thereafter.
DISCLOSURES RELATED TO PERIODS PRIOR TO ADOPTION OF THE NEW LEASE STANDARD
As of December 31, 2018, future minimum lease payments were as follows: |
| | | | | | | |
| (in millions) | Capital Leases | | Operating Leases |
| 2019 | $ | 187 |
| | $ | 1 |
|
| 2020 | 20 |
| | 1 |
|
| 2021 | — |
| | 1 |
|
| 2022 | — |
| | 1 |
|
| 2023 | — |
| | 1 |
|
| Thereafter | — |
| | 5 |
|
| Total Lease Payments | 207 |
| | $ | 10 |
|
| Less: Imputed Interest | 14 |
| | |
| Total Lease Obligations | 193 |
| | |
| Less: Current Portion | 173 |
| | |
| Total Non-Current Lease Obligations | $ | 20 |
| | |
TEP's operating lease cost was $1 million for the year ended December 31, 2018.
See Note 12 for non-cash transactions that resulted in recognition of right-of-use assets in exchange for lease liabilities.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
NOTE 7.9. COMMITMENTS AND CONTINGENCIES
COMMITMENTS
Unconditional Purchase Obligations
As of December 31, 2017,2019, TEP had the following firm, non-cancellable,unconditional minimum purchase obligations and operating leases:obligations: |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (in millions) | 2020 | | 2021 | | 2022 | | 2023 | | 2024 | | Thereafter | | Total |
| Fuel, Including Transportation | $ | 94 |
| | $ | 61 |
| | $ | 40 |
| | $ | 33 |
| | $ | 33 |
| | $ | 194 |
| | $ | 455 |
|
| Purchased Power | 8 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 8 |
|
| Transmission | 21 |
| | 16 |
| | 14 |
| | 3 |
| | 3 |
| | 6 |
| | 63 |
|
| Renewable Power Purchase Agreements | 63 |
| | 63 |
| | 63 |
| | 63 |
| | 62 |
| | 543 |
| | 857 |
|
| RES Performance-Based Incentives | 8 |
| | 7 |
| | 7 |
| | 7 |
| | 7 |
| | 33 |
| | 69 |
|
Land Easements and Rights-of-Way (1) | 1 |
| | 2 |
| | 1 |
| | 1 |
| | 3 |
| | 79 |
| | 87 |
|
| Total Purchase Commitments | $ | 195 |
| | $ | 149 |
| | $ | 125 |
| | $ | 107 |
| | $ | 108 |
| | $ | 855 |
| | $ | 1,539 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (in millions) | 2018 | | 2019 | | 2020 | | 2021 | | 2022 | | Thereafter | | Total |
| Fuel, Including Transportation | $ | 82 |
| | $ | 83 |
| | $ | 73 |
| | $ | 43 |
| | $ | 24 |
| | $ | 244 |
| | $ | 549 |
|
| Purchased Power | 29 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 29 |
|
| Transmission | 19 |
| | 19 |
| | 8 |
| | 4 |
| | 1 |
| | 8 |
| | 59 |
|
| Renewable Power Purchase Agreements | 64 |
| | 64 |
| | 63 |
| | 63 |
| | 63 |
| | 668 |
| | 985 |
|
| RES Performance-Based Incentives | 8 |
| | 8 |
| | 7 |
| | 7 |
| | 7 |
| | 46 |
| | 83 |
|
Operating Leases (1) | 1 |
| | 1 |
| | 1 |
| | 1 |
| | 1 |
| | 3 |
| | 8 |
|
| Land Easements and Rights-of-Way | 1 |
| | 1 |
| | 1 |
| | 2 |
| | 2 |
| | 82 |
| | 89 |
|
| Total Purchase Commitments | $ | 204 |
| | $ | 176 |
| | $ | 153 |
| | $ | 120 |
| | $ | 98 |
| | $ | 1,051 |
| | $ | 1,802 |
|
| |
(1) | Primarily represents leases for land, rail cars,Land easements and office facilities withrights-of-way have varying terms and provisions and reflect expiration dates through 2036. TEP's operating lease expense totaled $1 million in 2017, $2 million in 2016, and $3 million in 2015.2054. |
Costs for Purchased Power, Transmission, and Fuel, Including Transportation, are recoverable from customers through the PPFAC mechanism. A portion of the costs of PPAs are recoverable through the PPFAC, with the balance of costs recoverable through the RES tariff. PBIsPBI costs are recoverable through the RES tariff. See Note 2 for information on ACC approved cost recovery mechanisms.
Fuel, Including Transportation
TEP has long-term agreements for the purchase and delivery of coal with various expiration dates between 2020 and 2031. Amounts paid under these contracts depend on actual quantities purchased and delivered. Some of these agreements include price adjustment components that will affect future costs.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
TEP has firm transportation agreements with capacity sufficient to meet its load requirements. These agreements expire in various years between 20182022 and 2040. In January 2018, TEP entered into a transportation agreement with EPNG extending the expiration date of the existing agreement from April 2018 to April 2023. Estimated future payments not included in the table above are: $4 million in 2018; $5 million in 2019 through 2022; and $1 million through the end of the contract.
Purchased Power
TEP has contracts with utilities and other energy suppliers for purchased power toto: (i) meet system load and energy requirements,requirements; (ii) replace generation from company-owned units under maintenance and during outages,outages; and (iii) meet operating reserve obligations. In general, these contracts provide for capacity and energy payments based on actual power taken under the contracts with various expiration dates through the fourthsecond quarter of 2018.2020. Certain of these contracts are at a fixed price per MW and others are indexed to natural gas prices. The commitment amounts included in the table above are based on projected market prices as of December 31, 2017.2019.
Transmission
TEP has agreements with other utilities to purchase transmission services over lines that are part of the Western Interconnection, a regional grid in the United States. These agreements expire in various years between 20192020 and 2030.
Renewable Power Purchase Agreements
TEP enters into long-term renewable PPAs which require TEP to purchase 100% of certain renewable energy generation facilities output once commercial operation status is achieved. While TEP is not required to make payments under the agreements if power is not delivered, estimated future payments are included in the table above. These agreements expire in various years between 2027 and 2036.
RES Performance-Based Incentives
TEP has entered into REC purchase agreements to purchase the environmental attributes from retail customers with solar installations. Payments for the RECs are termed PBIs and are paid in contractually agreed-upon intervals (usually quarterly) based on metered renewable energy production. These agreements expire in various years between 2020 and 2034.
Land Easements and Rights-of-Way
Land Easements and Rights-of-Way have varying terms and provisions, and various expiration dates through 2054. 63
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Build-Transfer Agreement
In November 2017,March 2019, TEP entered into a build-transfer agreement to develop a 250 MW nominal capacity wind-powered electric generation facility, which is under construction in southeastern New Mexico (Oso Grande) with estimated costs of approximately $384 million. In January 2020, TEP took ownership of Oso Grande. Construction commenced in the Navajo Nation approved an extension for the usethird quarter of their land. The extension, signed by TEP and the co-owners of Navajo, commences in December 2019 and ends inis expected to be completed for operation by December 2054. The Navajo Nation has until December 2018 to select one2020. TEP made payments under the build-transfer agreement of five different rental payments options provided for in the extension. The table above includes TEP's 7.5% ownership share of the option which, in management's opinion, is most probable to occur. The total obligation estimated under this option is $8$47 million commencing in 2019 through 2053. Under the remaining payment options, TEP's share of estimated total payment obligation ranges from $3and $226 million to $8 million with various payment schedules with dates ranging from 2019 through 2053.in January 2020.
CONTINGENCIES
Legal Matters
TEP is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. TEP believes such normal and routine litigation will not have a material impact on its operations or consolidated financial results. TEP is also involved in other kinds of legal actions, some of which assert or may assert claims or seek to impose fines, penalties, and other costs in substantial amounts on TEP and are disclosed below.
Claims Related to Springerville Generating Station Unit 1
In February 2016, TEP entered into an agreement with the Third-Party Owners for the settlement and release of asserted claims and the purchase and sale of beneficial interests in Springerville Unit 1 (Agreement). In September 2016, TEP received FERC authorization to complete the transactions contemplated in the Agreement. In accordance with the Agreement, TEP purchased the Third-Party Owners’ undivided interest in Springerville Unit 1 for $85 million. As also provided for in the Agreement, TEP received $12.5 million from the Third-Party Owners in full satisfaction of all previously unreimbursed operating costs, which TEP recorded in Operating Revenues—Other on the Consolidated Statements of Income. Following the purchase, all outstanding disputes, pending litigation, and arbitration proceedings between TEP and the Third-Party Owners were dismissed with prejudice.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Claims Related to San Juan Generating Station
WildEarth Guardians
In 2013, WildEarth Guardians (WEG) filed a Petition for Review in the U.S. District Court for the District of Colorado against the Office of Surface Mining (OSM)Reclamation and Enforcement (OSMRE) challenging several unrelated mining plan modification approvals, including two issued in 2008 related to SJCC 'sWestmoreland San Juan mine.Mining LLC's (as successor to SJCC) existing San Juan Mine. The petition alleges various National Environmental Policy Act (NEPA) violations against the OSM,OSMRE, including: (i) failure to provide requisite public notice and participation; and (ii) failure to analyze certain environmental impacts. WEG’s petition seeks various forms of relief, including voiding and remanding the various mining modification approvals, enjoining the federal defendants from re-issuing the approvals until they can demonstrate compliance with the NEPA, and enjoining operations at the affected mines.SJCC intervened in this matter and was granted its motion tosever its claims from the lawsuit and transfer venue to the U.S. District Court for the District of New Mexico, where this matter is now pending. In July 2016, the federal defendants filed a motion asking that the matter be voluntarily remanded to the OSMOSMRE so the OSMOSMRE may prepare a new environmental impact statementEnvironmental Impact Statement (EIS) under the NEPA regarding the impacts of the San Juan Mine mining plan approval. In August 2016, the court issued an order granting the motion for remand to conduct further environmental analysis and complete an EIS by August 31, 2019. The order provides that: (i) the OSM’sOSMRE’s decision approving the mining plan will remain in effect during this process; or (ii) if the EIS is not completed by August 31, 2019, then the approved mine plan will immediately be vacated, absent further court order. TEP cannot currently predict the outcome of this matter or the range of its potential impact.
Claims Related to Four Corners Generating Station
Endangered Species Act
On April 20, 2016, several environmental groups filed30, 2019, the OSMRE issued a lawsuit in the U.S. District Court for the District of Arizona against the OSM and other federal agencies under the Endangered Species Act (ESA) alleging that the OSM’s reliance on the Biological Opinion and Incidental Take Statement prepared in connection with a federal environmental review were not in accordance with applicable law. The environmental review was undertaken as part of the U.S. Department of the Interior’s review processnecessary to allow for the effectiveness of lease amendments and related rights-of-way renewals for Four Corners. This review process also required separate environmental impact evaluations under the NEPA and culminated in the issuance of afinal Record of Decision justifying(ROD) on the agency action extendingFinal EIS released March 15, 2019. The Final EIS contemplates continued mining at the life of Four CornersSan Juan Mine in annual quantities similar to those currently being provided through 2033. The Assistant Secretary for Land and Minerals Management approved the adjacent Navajo Mine. In addition,mining plan outlined in the lawsuit alleges that these federal agencies violated both the ESA and the NEPAROD in providing the federal approvals necessary to extend operations at Four Corners and Navajo Mine past July 6, 2016. The lawsuit seeks various forms of relief, includingAugust 2019. TEP is not a finding that the federal defendants violated the ESA and the NEPA by issuing the Record of Decision, setting aside and remanding the Biological Opinion and Record of Decision, and enjoining the federal defendants from authorizing any elements of the Four Corners and Navajo Mine pending compliance with NEPA. In July 2016, the defendants answered the complaint and APS, the operator of Four Corners, filed a motion to interveneparty in this matter. APS’ motion was grantedmatter but does own 50% of Unit 1 at San Juan. San Juan is scheduled for early retirement in August 2016. In September 2016, Navajo Transitional Energy Company, LLC (NTEC),2022. TEP does not anticipate any significant impact on the company that owns the Navajo Mine, filed a motioncost of coal at San Juan related to intervene for the purpose of dismissing the lawsuit based on NTEC’s tribal sovereign immunity. In September 2017, the court granted NTEC’s motion to dismiss and dismissed the case with prejudice. In November 2017, the plaintiffs appealed to the U.S. Court of Appeals for the Ninth Circuit the District Court’s decision to dismiss the case. TEP cannot currently predict the outcome of this matter or the range of its potential impact.matter.
Mine Reclamation at GeneratingGeneration Facilities Not Operated by TEP
TEP pays ongoing mine reclamation costs related to coal mines that supply generation facilities in which TEP has an ownership interest but does not operate. TEP is also liable for a portion of final mine reclamation costs upon closure of the mines servicing Navajo, San Juan, and Four Corners. TEP’s share of reclamation costs at all three mines is expected to be $61 million upon expiration of the coal supply agreements, which expire between 2019 and 2031. The Consolidated Balance Sheets reflect a total liability related to reclamation of $34 million and $26 million as of December 31, 2017 and 2016, respectively.
Amounts recorded for final mine reclamation are subject to various assumptions, such as estimations of reclamation costs, the datestiming when final reclamation will occur, and the expected inflation rate.As these assumptions change, TEP will prospectively adjust the expense amounts for final reclamation over the remaining coal supply agreements’ terms. TEP does not believe that recognition of its final reclamation obligations will be material to TEP in any single year because recognition will occur over the remaining terms of its coal supply agreements.
TEP’s PPFAC allows the Company to pass through final mine reclamation costs, as a component of fuel costs, to retail customers. Therefore, TEP classifiesdefers these costs as a regulatory assetexpenses until recovered from rate payers by increasing the regulatory asset and the reclamation liability over the remaining life of the coal supply agreements and recovers the regulatory asset through the PPFAC as final mine reclamation costs are paid out.
San Juan and Four Corners
TEP is liable for a portion of final mine reclamation costs upon closure of the mines servicing San Juan and Four Corners. TEP’s estimated share of mine reclamation costs at both mines is $57 million upon expiration of the related coal supply agreements, which expire in 2022 and 2031, respectively. An aggregate liability balance related to San Juan and Four Corners final mine reclamation of $36 million and $31 million as of December 31, 2019 and 2018, respectively, was recorded in Other on the coal suppliers.Consolidated Balance Sheets. See Note 2 for additional information related to final mine reclamation costs.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
FERC ComplianceNavajo
In 2015December 2019, TEP entered into an agreement with the owner and 2016,operator of the Kayenta Mine and the third-party owners of Navajo for the settlement and release of asserted claims associated with the early retirement of Navajo. During 2019, TEP self-reportedpaid $17 million related to the FERC Officeretirement of Enforcement (OE) that the Company had not timely filed certain FERC-jurisdictional agreements. TEP conducted comprehensive internal reviews of its compliance with the FERC filing requirements (Compliance Reviews), and made compliance filings with the FERC Office of Energy Market Regulation. This included the filing of several TSAs entered into between 2003 and 2015 that contained certain deviations from TEP’s standard service agreement form.
In 2016,Navajo which includes $8 million paid for final mine reclamation costs as a result of the FERC Refund Orders and ongoing discussions with the OE,settlement. As of December 31, 2019, TEP recorded ahad 0 liability for the time-value refunds with a corresponding offset in revenues on its financial statements in 2016. In 2016, Wholesale Revenues on the Consolidated Statementsbalance related to Navajo final mine reclamation. A liability balance related to Navajo final mine reclamation of Income reflected $22$5 million and, as of December 31, 2016, Current Liabilities—Other on the Consolidated Balance Sheets reflected $5 million related to the time-value refunds.
In June 2016, to preserve its rights, TEP petitioned the U.S. Court of Appeals for the District of Columbia Circuit to review the FERC Refund Orders. In January 2017, TEP and one of the TSA counterparties entered into a settlement agreement regarding the FERC Refund Orders. In accordance with the agreement, the counterparty paid TEP $8 million, which TEP2018, was recorded in Other Income on the Consolidated Statements of Income and dismissed the appeal with prejudice in January 2017.
In May 2017, the FERC informed TEP that: (i) no further enforcement actions were necessary regarding the late-filed TSAs; and (ii) the related investigation was closed. As management no longer believed a loss was probable, TEP reversed the $5 million remaining balance related to potential time-value refunds in Current Liabilities—Other on the Consolidated Balance Sheets, offsetting Wholesale Revenues on the Consolidated Statements of Income.Sheets.
Performance Guarantees
TEP has joint participation agreements with participants at Navajo, San Juan, Four Corners, and Luna. The participants in each of the generation facilities, including TEP, have guaranteed certain performance obligations. Specifically, in the event of payment default, each non-defaulting participant has agreed to bear its proportionate share of expenses otherwise payable by the defaulting participant. In exchange, the non-defaulting participants are entitled to receive their proportionate share of the generation capacity of the defaulting participant. With the exception of Four Corners, there is no0 maximum potential amount of future payments TEP could be required to make under the guarantees. The maximum potential amount of future payments is $250 million at Four Corners. As of December 31, 2017,2019, there have been no0 such payment defaults under any of the participation agreements. The Navajo participation agreement expiresexpired in 2019, but certain performance obligations continue through the decommissioning of the generating station. The San Juan participation agreement expires in 2022, Four Corners in 2041, and Luna in 2046.
Environmental Matters
TEP is subject to federal, state, and local environmental laws and regulations regarding air and water quality, renewable portfolio standards, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species, and other environmental matters that have the potential to impact TEP's current and future operations. Environmental laws and regulations are subject to a range of interpretations, which may ultimately be resolved by the courts. Because these laws and regulations continue to evolve, TEP is unable to predict the impact of the changing laws and regulations on its operations and consolidated financial results. TEP expects to recover the cost of environmental compliance from its ratepayers. TEP believes it is in compliance with applicable environmental laws and regulations in all material respects.
Broadway-Pantano Site
The Water Quality Assurance Revolving Fund (WQARF) imposes liability on parties responsible for, in whole or in part, the presence of hazardous substances at a site. Those who released, generated, or disposed of hazardous substances at a contaminated site, or transported to or owned such contaminated site, are among the Potentially Responsible Parties (PRP). PRPs may be strictly liable for clean-up. The ADEQ is administering a remediation plan to delineate and then apportion costs among anticipated adverse parties in the Broadway-Pantano WQARF site, a hazardous waste site in Tucson, Arizona, which includes the Broadway North and South Landfills. Collectively, these landfills were in operation from 1953 and 1973. TEP's Eastloop substation and a portion of a related transmission line are located on two parcel adjacent to these landfills. On November 8, 2019, the ADEQ notified TEP that it considers TEP to be a PRP with respect to the Broadway-Pantano WQARF site. TEP does not expect this matter to have a material impact on its financial statements, however, the overall investigation and remediation plan have not been finalized.
NOTE 8.10. EMPLOYEE BENEFIT PLANS
PENSION BENEFIT PLANS
TEP has three3 noncontributory, defined benefit pension plans. Benefits are based on years of service and average compensation. TwoNaN of the plans cover the majority of TEP's employees. The Company funds those plans by contributing at least the minimum amount required under Internal Revenue Service (IRS)IRS regulations. TEP also maintains a SERP for executive management.
OTHER POSTRETIREMENT BENEFITS PLAN
TEP provides limited healthcare and life insurance benefits for retirees. Active TEP employees may become eligible for these benefits if they reach retirement age while working for TEP or an affiliate.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
TEP funds its other postretirement benefits for classified employees through a VEBA. TEP contributed $1 million in 2019 and $3 million in 2017, $2 million in 2016,2018 and $4 million in 20152017 to the VEBA. Other postretirement benefits for unclassified employees are self-funded.
REGULATORY RECOVERY
TEP records changes in non-SERP pension and other postretirement defined benefit plans, not yet reflected in net periodic benefit cost, as a regulatory asset or liability, as such amounts are probable of future recovery or refund in the rates charged to retail customers. Changes in the SERP obligation, not yet reflected in net periodic benefit cost, are recorded in Other Comprehensive Income (Loss) since SERP expense is not currently recoverable in rates.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table presents pension and other postretirement benefit amounts (excluding tax balances) included onin the Consolidated Balance Sheets:balance sheet: |
| | | | | | | | | | | | | | | |
| | Pension Benefits | | Other Postretirement Benefits |
| | December 31, |
| (in millions) | 2019 | | 2018 | | 2019 | | 2018 |
| Regulatory Assets | $ | 135 |
| | $ | 126 |
| | $ | — |
| | $ | — |
|
| Regulatory Liabilities | — |
| | — |
| | (1 | ) | | (3 | ) |
| Accrued Employee Expenses | (2 | ) | | (1 | ) | | (2 | ) | | (3 | ) |
| Pension and Other Postretirement Benefits | (77 | ) | | (63 | ) | | (56 | ) | | (54 | ) |
| Accumulated Other Comprehensive Loss, SERP | 10 |
| | 6 |
| | — |
| | — |
|
| Net Amount Recognized | $ | 66 |
| | $ | 68 |
| | $ | (59 | ) | | $ | (60 | ) |
|
| | | | | | | | | | | | | | | |
| | Pension Benefits | | Other Postretirement Benefits |
| | December 31, |
| (in millions) | 2017 | | 2016 | | 2017 | | 2016 |
| Regulatory Assets | $ | 121 |
| | $ | 123 |
| | $ | 5 |
| | $ | 5 |
|
| Accrued Employee Expenses | (1 | ) | | (1 | ) | | (2 | ) | | (2 | ) |
| Pension and Other Postretirement Benefits | (71 | ) | | (69 | ) | | (63 | ) | | (63 | ) |
| Accumulated Other Comprehensive Loss, SERP | 9 |
| | 6 |
| | — |
| | — |
|
| Net Amount Recognized | $ | 58 |
| | $ | 59 |
| | $ | (60 | ) | | $ | (60 | ) |
OBLIGATIONS AND FUNDED STATUS
The Company measured the actuarial present values of all defined benefit pension and other postretirement benefit obligations as of December 31, 20172019 and 2016.2018. The table below presents the status of all of TEP’s pension and other postretirement benefit plans.
All plans havehad projected benefit obligations in excess of the fair value of plan assets for each period presented: | | | | Pension Benefits | | Other Postretirement Benefits | Pension Benefits | | Other Postretirement Benefits |
| | Years Ended December 31, | Years Ended December 31, |
| (in millions) | 2017 | | 2016 | | 2017 | | 2016 | 2019 | | 2018 | | 2019 | | 2018 |
| Change in Benefit Obligation | | | | | | | | | | | | | | |
| Beginning of Period | $ | 424 |
| | $ | 394 |
| | $ | 79 |
| | $ | 78 |
| $ | 440 |
| | $ | 475 |
| | $ | 74 |
| | $ | 82 |
|
| Actuarial Loss | 42 |
| | 20 |
| | 1 |
| | — |
| |
| Actuarial (Gain) Loss | | 76 |
| | (42 | ) | | 4 |
| | (8 | ) |
| Interest Cost | 15 |
| | 15 |
| | 2 |
| | 2 |
| 18 |
| | 16 |
| | 3 |
| | 2 |
|
| Service Cost | 13 |
| | 12 |
| | 4 |
| | 4 |
| 13 |
| | 15 |
| | 4 |
| | 5 |
|
| Benefits Paid | (19 | ) | | (17 | ) | | (4 | ) | | (5 | ) | (23 | ) | | (23 | ) | | (6 | ) | | (5 | ) |
| Plan Amendments | | 1 |
| | (1 | ) | | — |
| | (2 | ) |
| End of Period | 475 |
| | 424 |
| | 82 |
| | 79 |
| 525 |
| | 440 |
| | 79 |
| | 74 |
|
| Change in Fair Value of Plan Assets | | | | | | | | | | | | | | |
| Beginning of Period | 354 |
| | 336 |
| | 14 |
| | 13 |
| 376 |
| | 403 |
| | 17 |
| | 17 |
|
| Actual Return on Plan Assets | 59 |
| | 27 |
| | 2 |
| | 1 |
| 81 |
| | (25 | ) | | 4 |
| | (1 | ) |
| Benefits Paid | (19 | ) | | (17 | ) | | (4 | ) | | (5 | ) | (22 | ) | | (23 | ) | | (6 | ) | | (5 | ) |
Employer Contributions (1) | 9 |
| | 8 |
| | 5 |
| | 5 |
| 11 |
| | 21 |
| | 6 |
| | 6 |
|
| End of Period | 403 |
| | 354 |
| | 17 |
| | 14 |
| 446 |
| | 376 |
| | 21 |
| | 17 |
|
| Funded Status at End of Period | $ | (72 | ) | | $ | (70 | ) | | $ | (65 | ) | | $ | (65 | ) | $ | (79 | ) | | $ | (64 | ) | | $ | (58 | ) | | $ | (57 | ) |
| |
(1) | TEP expects to contribute $11 million to the pension plans and $1 million to the VEBA trust in 2018.2020. |
The $85 million increase in the pension benefit obligation was driven by a significant decrease in discount rates as a result of a decrease in interest rates. The $70 million increase in the pension plan assets was due to positive equity returns and fixed income returns as a result of a decline in interest rates.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table provides the components of TEP’s regulatory assets and accumulated other comprehensive loss that have not been recognized as components of net periodic benefit cost as of the dates presented: |
| | | | | | | | | | | | | | | |
| | Pension Benefits | | Other Postretirement Benefits |
| | Years Ended December 31, |
| (in millions) | 2019 | | 2018 | | 2019 | | 2018 |
| Net (Gain) Loss | $ | 145 |
| | $ | 133 |
| | $ | 1 |
| | $ | (1 | ) |
| Prior Service Cost (Benefit) | — |
| | — |
| | (2 | ) | | (2 | ) |
|
| | | | | | | | | | | | | | | |
| | Pension Benefits | | Other Postretirement Benefits |
| | Years Ended December 31, |
| (in millions) | 2017 | | 2016 | | 2017 | | 2016 |
| Net Loss | $ | 129 |
| | $ | 128 |
| | $ | 5 |
| | $ | 6 |
|
| Prior Service Cost (Benefit) | 1 |
| | — |
| | (1 | ) | | (1 | ) |
The accumulated benefit obligation aggregated for all pension plans is $428was $476 million and $384$402 million as of December 31, 20172019 and 2016,2018, respectively. TwoAll of the pension plans had accumulated benefit obligations in excess of plan assets as of both December 31, 2017, compared to three as of December 31, 2016, as a result of market gains on plan assets in 2017.2019 and 2018. The following table
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
includes information for the pension plans with accumulated benefit obligations in excess of pension plan assets: | | | | December 31, | December 31, |
| (in millions) | 2017 | | 2016 | 2019 | | 2018 |
| Accumulated Benefit Obligation | $ | 237 |
| | $ | 384 |
| $ | 476 |
| | $ | 230 |
|
| Fair Value of Plan Assets | 206 |
| | 354 |
| 446 |
| | 202 |
|
Beginning in 2016, theThe Company elected to measuremeasures service and interest costs by applying the specific spot rates along the yield curve to the plans' liability cash flows. Prior to 2016, the Company measured service and interest costs for pension and other postretirement benefits utilizing a single weighted-average discount rate derived from the yield curve used to measure the plan obligations. TEP believes the new approach provides a more precise measurement of service and interest costs by aligning the timing of the plans' liability cash flows to the corresponding spot rates on the yield curve. This change does not affect the measurement of its plan obligations nor the funded status. TEP accounted for this change as a change in accounting estimate, and accordingly, accounted for it on a prospective basis. Net periodic benefit plan cost includes the following components: |
| | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | Other Postretirement Benefits |
| | Years Ended December 31, |
| (in millions) | 2019 | | 2018 | | 2017 | | 2019 | | 2018 | | 2017 |
| Service Cost | $ | 13 |
| | $ | 15 |
| | $ | 13 |
| | $ | 4 |
| | $ | 5 |
| | $ | 4 |
|
Non-Service Cost | | | | | | | | | | | |
| Interest Cost | 18 |
| | 16 |
| | 15 |
| | 3 |
| | 2 |
| | 2 |
|
| Expected Return on Plan Assets | (26 | ) | | (28 | ) | | (25 | ) | | (2 | ) | | (1 | ) | | (1 | ) |
| Amortization of Net (Gain) Loss | 8 |
| | 7 |
| | 8 |
| | — |
| | — |
| | — |
|
| Net Periodic Benefit Cost | $ | 13 |
| | $ | 10 |
| | $ | 11 |
| | $ | 5 |
| | $ | 6 |
| | $ | 5 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | Other Postretirement Benefits |
| | Years Ended December 31, |
| (in millions) | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 |
| Service Cost | $ | 13 |
| | $ | 12 |
| | $ | 12 |
| | $ | 4 |
| | $ | 4 |
| | $ | 4 |
|
| Interest Cost | 15 |
| | 15 |
| | 17 |
| | 2 |
| | 2 |
| | 3 |
|
| Expected Return on Plan Assets | (25 | ) | | (23 | ) | | (23 | ) | | (1 | ) | | (1 | ) | | (1 | ) |
| Amortization of Net Loss | 8 |
| | 7 |
| | 7 |
| | — |
| | — |
| | — |
|
| Net Periodic Benefit Cost | $ | 11 |
| | $ | 11 |
| | $ | 13 |
| | $ | 5 |
| | $ | 5 |
| | $ | 6 |
|
Approximately 18%The non-service components of the net periodic benefit cost wasare included in Other, Net on the Consolidated Statements of Income. In 2019 and 2018, TEP capitalized 21% and 19% of service cost, respectively, as a cost of construction and the remainder was included in income.construction.
The changes in plan assets and benefit obligations recognized as regulatory assets or in AOCI were as follows: | | | | Pension Benefits | | Other Postretirement Benefits | Pension Benefits | | Other Postretirement Benefits |
| | Regulatory Asset | | AOCI | | Regulatory Asset | Regulatory Asset | | AOCI | | Regulatory Asset |
| (in millions) | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 | 2019 | | 2018 | | 2017 | | 2019 | | 2018 | | 2017 | | 2019 | | 2018 | | 2017 |
| Current Year Actuarial (Gain) Loss | $ | 5 |
| | $ | 15 |
| | $ | 5 |
| | $ | 3 |
| | $ | 1 |
| | $ | — |
| | $ | (1 | ) | | $ | — |
| | $ | (4 | ) | $ | 16 |
| | $ | 12 |
| | $ | 5 |
| | $ | 4 |
| | $ | (1 | ) | | $ | 3 |
| | $ | 1 |
| | $ | (6 | ) | | $ | (1 | ) |
| Amortization of Net Loss | (7 | ) | | (7 | ) | | (7 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| (8 | ) | | (7 | ) | | (7 | ) | | (1 | ) | | — |
| | — |
| | — |
| | — |
| | — |
|
| Prior Service Credit (Cost) | | — |
| | — |
| | — |
| | 1 |
| | (1 | ) | | — |
| | — |
| | (2 | ) | | — |
|
| Total Recognized (Gain) Loss | $ | (2 | ) | | $ | 8 |
| | $ | (2 | ) | | $ | 3 |
| | $ | 1 |
| | $ | — |
| | $ | (1 | ) | | $ | — |
| | $ | (4 | ) | $ | 8 |
| | $ | 5 |
| | $ | (2 | ) | | $ | 4 |
| | $ | (2 | ) | | $ | 3 |
| | $ | 1 |
| | $ | (8 | ) | | $ | (1 | ) |
For all pension plans, TEP amortizes prior service costs on a straight-line basis over the average remaining service period of employees expected to receive benefits under the plans. Estimated amortization from regulatory assets into net periodic benefit cost in 2018 includes the following: |
| | | | | | | |
| (in millions) | Pension Benefits | | Other Postretirement Benefits |
| Net Loss | $ | 7 |
| | $ | — |
|
Net periodic benefit cost is subject to various assumptions and determinations, such as the discount rate, the rate of compensation increase, and the expected return on plan assets. Changes that may arise over time with regard to these assumptions and determinations will change amounts recorded in the future as net periodic benefit cost.
TEP uses a combination of sources in selecting the expected long-term rate-of-return-on-assets assumption, including an investment return model. The model used provides a “best-estimate” range over 20 years from the25th percentile to the 75th percentile. The model, used as a guideline for selecting the overall rate-of-return-on-assets assumption, is based on forward-looking return expectations only. The above method is used for all asset classes.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table includes the weighted average assumptions used to determine benefit obligations: |
| | | | | | | |
| | Pension Benefits | | Other Postretirement Benefits |
| | 2019 | | 2018 | | 2019 | | 2018 |
| Discount Rate | 3.6% | | 4.5% | | 3.3% | | 4.3% |
| Rate of Compensation Increase | 2.8% | | 2.8% | | N/A | | N/A |
|
| | | | | | | |
| | Pension Benefits | | Other Postretirement Benefits |
| | 2017 | | 2016 | | 2017 | | 2016 |
| Discount Rate | 3.7% | | 4.2% | | 3.6% | | 4.0% |
| Rate of Compensation Increase | 2.8% | | 2.8% | | N/A | | N/A |
The following table includes the weighted average assumptions used to determine net periodic benefit costs: |
| | | | | | | | | | | |
| | Pension Benefits | | Other Postretirement Benefits |
| | 2019 | | 2018 | | 2017 | | 2019 | | 2018 | | 2017 |
| Discount Rate, Service Cost | 4.7% | | 3.8% | | 4.4% | | 4.5% | | 3.8% | | 4.3% |
| Discount Rate, Interest Cost | 4.2% | | 3.4% | | 3.7% | | 4.0% | | 3.2% | | 3.3% |
| Rate of Compensation Increase | 2.8% | | 2.8% | | 2.8% | | N/A | | N/A | | N/A |
| Expected Return on Plan Assets | 7.0% | | 7.0% | | 7.0% | | 7.0% | | 7.0% | | 7.0% |
|
| | | | | | | | | | | |
| | Pension Benefits | | Other Postretirement Benefits |
| | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 |
| Discount Rate, Service Cost | 4.4% | | 4.8% | | 4.2% | | 4.3% | | 4.6% | | 3.9% |
| Discount Rate, Interest Cost | 3.7% | | 3.9% | | 4.2% | | 3.3% | | 3.4% | | 3.9% |
| Rate of Compensation Increase | 2.8% | | 3.0% | | 3.0% | | N/A | | N/A | | N/A |
| Expected Return on Plan Assets | 7.0% | | 7.0% | | 7.0% | | 7.0% | | 7.0% | | 7.0% |
Healthcare cost trend rates are assumed to decrease gradually from next year to the year the ultimate rate is reached: |
| | | |
| | December 31, |
| | 2019 | | 2018 |
| Next Year (Pre-65) | 6.3% | | 6.5% |
| Next Year (Post-65) | 7.5% | | 7.8% |
| Ultimate Rate Assumed (Pre-65 and Post-65) | 4.5% | | 4.5% |
| Year Ultimate Rate is Reached (Pre-65) | 2037 | | 2037 |
| Year Ultimate Rate is Reached (Post-65) | 2037 | | 2037 |
|
| | | |
| | December 31, |
| | 2017 | | 2016 |
| Next Year | 7.6% | | 7.6% |
| Ultimate Rate Assumed | 4.5% | | 4.5% |
| Year Ultimate Rate is Reached | 2036 | | 2037 |
Assumed healthcare cost trend rates significantly affect the amounts reported for healthcare plans. A one-percentage-point change in assumed healthcare cost trend rates would have the following effects on the amounts: |
| | | | | | | |
| | One-Percentage- Point Increase | | One-Percentage- Point Decrease |
| (in millions) | December 31, 2017 |
| Increase (Decrease) on Total Service and Interest Cost Components | $ | 1 |
| | $ | (1 | ) |
| Increase (Decrease) on Other Postretirement Benefits Obligation | 7 |
| | (6 | ) |
PENSION PLAN AND OTHER POSTRETIREMENT BENEFIT ASSETS
TEP calculates the fair value of plan assets on December 31, the measurement date. Asset allocations, by asset category, on the measurement date were as follows: |
| | | | | | | | | | | |
| | Pension | | Other Postretirement Benefits |
| | 2019 | | 2018 | | 2019 | | 2018 |
| Asset Category | | | | | | | |
| Equity Securities | 46 | % | | 45 | % | | 65 | % | | 60 | % |
| Fixed Income Securities | 45 | % | | 45 | % | | 33 | % | | 38 | % |
| Real Estate | 8 | % | | 8 | % | | — | % | | — | % |
| Other | 1 | % | | 2 | % | | 2 | % | | 2 | % |
| Total | 100 | % | | 100 | % | | 100 | % | | 100 | % |
|
| | | | | | | | | | | |
| | Pension | | Other Postretirement Benefits |
| | 2017 | | 2016 | | 2017 | | 2016 |
| Asset Category | | | | | |
| Equity Securities | 46 | % | | 49 | % | | 63 | % | | 60 | % |
| Fixed Income Securities | 45 | % | | 41 | % | | 35 | % | | 35 | % |
| Real Estate | 7 | % | | 8 | % | | — | % | | 2 | % |
| Other | 2 | % | | 2 | % | | 2 | % | | 3 | % |
| Total | 100 | % | | 100 | % | | 100 | % | | 100 | % |
As of December 31, 2017,2019, the fair value of VEBA trust assets was $21 million, of which $7 million were fixed income investments and $14 million were equities. As of December 31, 2018, the fair value of VEBA trust assets was $17 million, of which $6$7 million were fixed income investments and $11 million were equities. As of December 31, 2016, the fair value of VEBA trust assets was $14 million, of which $5 million were fixed income investments and $9$10 million were equities. The VEBA trust assets are primarily Level 2.2 assets within the fair value hierarchy described below. There are no0 Level 3 assets in the VEBA trust.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following tables present the fair value measurements of pension plan assets by level within the fair value hierarchy: |
| | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Total |
| (in millions) | December 31, 2019 |
| Asset Category | | | | | | | |
| Cash Equivalents | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | 2 |
|
| Equity Securities: | | | | | | | |
| United States Large Cap | — |
| | 55 |
| | — |
| | 55 |
|
| United States Small Cap | — |
| | 21 |
| | — |
| | 21 |
|
| Non-United States | — |
| | 80 |
| | — |
| | 80 |
|
| Global | — |
| | 51 |
| | — |
| | 51 |
|
| Fixed Income | — |
| | 199 |
| | — |
| | 199 |
|
| Real Estate | — |
| | 10 |
| | 23 |
| | 33 |
|
| Private Equity | — |
| | — |
| | 5 |
| | 5 |
|
| Total | $ | 2 |
| | $ | 416 |
| | $ | 28 |
| | $ | 446 |
|
| | | | Level 1 | | Level 2 | | Level 3 | | Total | December 31, 2018 |
| (in millions) | December 31, 2017 | |
| Asset Category | | | | | | | | | | | | | | |
| Cash Equivalents | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 1 |
| $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 1 |
|
| Equity Securities: | | | | | | | | | | | | | | |
| United States Large Cap | — |
| | 66 |
| | — |
| | 66 |
| — |
| | 45 |
| | — |
| | 45 |
|
| United States Small Cap | — |
| | 19 |
| | — |
| | 19 |
| — |
| | 17 |
| | — |
| | 17 |
|
| Non-United States | — |
| | 72 |
| | — |
| | 72 |
| — |
| | 67 |
| | — |
| | 67 |
|
| Global | — |
| | 30 |
| | — |
| | 30 |
| — |
| | 42 |
| | — |
| | 42 |
|
| Fixed Income | — |
| | 179 |
| | — |
| | 179 |
| — |
| | 167 |
| | — |
| | 167 |
|
| Real Estate | — |
| | 9 |
| | 21 |
| | 30 |
| — |
| | 9 |
| | 22 |
| | 31 |
|
| Private Equity | — |
| | — |
| | 6 |
| | 6 |
| — |
| | — |
| | 6 |
| | 6 |
|
| Total | $ | 1 |
| | $ | 375 |
| | $ | 27 |
| | $ | 403 |
| $ | 1 |
| | $ | 347 |
| | $ | 28 |
| | $ | 376 |
|
| | | | | | | | | |
| (in millions) | December 31, 2016 | |
| Asset Category | | | | | | | | |
| Cash Equivalents | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 1 |
| |
| Equity Securities: | | | | | | |
|
| |
| United States Large Cap | — |
| | 61 |
| | — |
| | 61 |
| |
| United States Small Cap | — |
| | 18 |
| | — |
| | 18 |
| |
| Non-United States | — |
| | 67 |
| | — |
| | 67 |
| |
| Global | — |
| | 28 |
| | — |
| | 28 |
| |
| Fixed Income | — |
| | 144 |
| | — |
| | 144 |
| |
| Real Estate | — |
| | 9 |
| | 19 |
| | 28 |
| |
| Private Equity | — |
| | — |
| | 7 |
| | 7 |
| |
| Total | $ | 1 |
| | $ | 327 |
| | $ | 26 |
| | $ | 354 |
| |
Level 1 cash equivalents are based on observable market prices and are comprised of the fair value of commercial paper, money market funds, and certificates of deposit.
Level 2 investments comprise amounts held in commingled equity funds, United States bond funds, and real estate funds. Valuations are based on active market quoted prices for assets held by each respective fund.
Level 3 real estate investments values are generally determined by appraisals conducted in accordance with accepted appraisal guidelines, including consideration of projected income and expenses of the property as well as recent sales of similar properties.
Level 3 private equity funds are classified as funds-of-funds. They are valued based on individual fund manager valuation models.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table presents a reconciliation of changes in the fair value of pension plan assets classified as Level 3 in the fair value hierarchy. There were no0 transfers in or out of Level 3. |
| | | | | | | | | | | |
| (in millions) | Private Equity | | Real Estate | | Total |
| Balance as of December 31, 2017 | $ | 6 |
| | $ | 21 |
| | $ | 27 |
|
| Actual Return on Plan Assets: | | | | |
|
|
| Assets Held at Reporting Date | 2 |
| | 1 |
| | 3 |
|
| Purchases, Sales, and Settlements | (2 | ) | | — |
| | (2 | ) |
| Balance as of December 31, 2018 | 6 |
| | 22 |
| | 28 |
|
| Actual Return on Plan Assets: | | | | | |
| Assets Held at Reporting Date | 1 |
| | 1 |
| | 2 |
|
| Purchases, Sales, and Settlements | (2 | ) | | — |
| | (2 | ) |
| Balance as of December 31, 2019 | $ | 5 |
| | $ | 23 |
| | $ | 28 |
|
|
| | | | | | | | | | | |
| (in millions) | Private Equity | | Real Estate | | Total |
| Balance as of December 31, 2015 | $ | 7 |
| | $ | 18 |
| | $ | 25 |
|
| Actual Return on Plan Assets: | | | | |
|
|
| Assets Held at Reporting Date | 1 |
| | 1 |
| | 2 |
|
| Purchases, Sales, and Settlements | (1 | ) | | — |
| | (1 | ) |
| Balance as of December 31, 2016 | 7 |
| | 19 |
| | 26 |
|
| Actual Return on Plan Assets: | | | | | |
| Assets Held at Reporting Date | 1 |
| | 2 |
| | 3 |
|
| Purchases, Sales, and Settlements | (2 | ) | | — |
| | (2 | ) |
| Balance as of December 31, 2017 | $ | 6 |
| | $ | 21 |
| | $ | 27 |
|
Pension Plan Investments
Investment Goals
Asset allocation is the principal method for achieving each pension plan’s investment objectives while maintaining appropriate levels of risk. TEP considers the projected impact on benefit security of any proposed changes to the current asset allocation policy. The expected long-term returns and implications for pension plan sponsor funding are reviewed in selecting policies to ensure that current asset pools are projected to be adequate to meet the expected liabilities of the pension plans. TEP expects to use asset allocation policies weighted most heavily to equity and fixed income funds, while maintaining some exposure to real estate and opportunistic funds. Within the fixed income allocation, long-duration funds may be used to partially hedge interest rate risk.
Risk Management
TEP recognizes the difficulty of achieving investment objectives in light of the uncertainties and complexities of the investment markets. The Company recognizes some risk must be assumed to achieve a pension plan’s long-term investment objectives. In establishing risk tolerances, the following factors affecting risk tolerance and risk objectives will be considered: (i) plan status; (ii) plan sponsor financial status and profitability; (iii) plan features; and (iv) workforce characteristics. TEP determined that the pension plans can tolerate some interim fluctuations in market value and rates of return in order to achieve long-term objectives. TEP tracks each pension plan’s portfolio relative to the benchmark through quarterly investment reviews. The reviews consist of a performance and risk assessment of all investment categories and on the portfolio as a whole. Investment managers for the pension plan may use derivative financial instruments for risk management purposes or as part of their investment strategy. Currency hedges may also be used for defensive purposes.
Relationship between Plan Assets and Benefit Obligations
The overall health of each plan will be monitored by comparing the value of plan obligations (both Accumulated Benefit Obligation and Projected Benefit Obligation) against the fair value of assets and tracking the changes in each. The frequency of this monitoring will depend on the availability of plan data, but will be no less frequent than annually via actuarial valuation.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Target Allocation Percentages
The current target allocation percentages for the major asset categories of the plan follow. Each plan allows a variance of +/- 2% from targets before funds are automatically rebalanced. |
| | | |
| | Pension | | Other Postretirement Benefits |
| | December 31, 2019 |
| Cash/Treasury Bills | —% | | 2% |
| Equity Securities: | | | |
| United States Large Cap | 12% | | 39% |
| United States Small Cap | 5% | | 5% |
| Non-United States Developed | —% | | 7% |
| Non-United States Emerging | —% | | 9% |
| Global Equity | 26% | | —% |
| Global Infrastructure | 3% | | —% |
| Fixed Income | 45% | | 38% |
| Real Estate | 8% | | —% |
| Private Equity | 1% | | —% |
| Total | 100% | | 100% |
|
| | | |
| | Pension | | Other Postretirement Benefits |
| | December 31, 2017 |
| Cash/Treasury Bills | —% | | 2% |
| Equity Securities: | | | |
| United States Large Cap | 16% | | 39% |
| United States Small Cap | 5% | | 5% |
| Non-United States Developed | 14% | | 7% |
| Non-United States Emerging | 4% | | 9% |
| Global Equity | 4% | | —% |
| Global Infrastructure | 3% | | —% |
| Fixed Income | 45% | | 38% |
| Real Estate | 8% | | —% |
| Private Equity | 1% | | —% |
| Total | 100% | | 100% |
Pension Fund Descriptions
For each type of asset category selected by the Pension Committee, TEP's investment consultant assembles a group of third-party fund managers and allocates a portion of the total investment to each fund manager. In the case of the private equity fund, TEP's investment consultant directs investments to a private equity manager that invests in third-parties’ funds.
ESTIMATED FUTURE BENEFIT PAYMENTS
TEP expects the following benefit payments to be made by the plans, which reflect future service, as appropriate. |
| | | | | | | | | | | | | | | | | | | | | | | |
| (in millions) | 2020 | | 2021 | | 2022 | | 2023 | | 2024 | | 2025-2029 |
| Pension Benefits | $ | 26 |
| | $ | 26 |
| | $ | 26 |
| | $ | 27 |
| | $ | 28 |
| | $ | 147 |
|
| Other Postretirement Benefits | 5 |
| | 5 |
| | 5 |
| | 5 |
| | 5 |
| | 25 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| (in millions) | 2018 | | 2019 | | 2020 | | 2021 | | 2022 | | 2023-2027 |
| Pension Benefits | $ | 21 |
| | $ | 22 |
| | $ | 23 |
| | $ | 24 |
| | $ | 25 |
| | $ | 137 |
|
| Other Postretirement Benefits | 5 |
| | 5 |
| | 5 |
| | 6 |
| | 6 |
| | 30 |
|
DEFINED CONTRIBUTION PLAN
TEP offers a defined contribution savings plan to all eligible employees. The Internal Revenue Code identifiesplan meets the plan as aIRS required standards for 401(k) qualified 401(k) plan.plans. Participants direct the investment of contributions to certain funds in their account. The Company matches part of a participant’s contributions to the plan. TEP made matching contributions to the plan of $6 million in 2017, and $52019, $7 million in both 20162018, and 2015.$6 million in 2017.
NOTE 9.11. SHARE-BASED COMPENSATION
2015 SHARE UNIT PLAN
The Human Resources and Governance Committee (Committee) of UNS Energy approved and UNS Energy's Board of Directors ratified the 2015 Share Unit Plan (Plan) effective January 2015. Under the Plan, key employees, including executive officers of UNS Energy and its subsidiaries, may be granted long-term incentive awards of performance-based share units (PSUs)PSUs and time-based restricted share units (RSUs)RSUs annually. Each PSU and RSU granted is valued based on one1 share of Fortis common stock traded on the Toronto Stock Exchange, converted to U.S. dollars. UNS Energy allocates the obligation and expense for this plan to its subsidiaries based on the Massachusetts Formula. UNS Energy accounts for forfeitures as they occur.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table represents PSUs and RSUs awarded by UNS Energy: |
| | | | | | | | |
| | 2019 | | 2018 | | 2017 |
| PSUs | 66,978 |
| | 54,426 |
| | 68,126 |
|
| RSUs | 33,489 |
| | 27,213 |
| | 34,063 |
|
|
| | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| PSUs | 68,126 |
| | 66,974 |
| | 47,776 |
|
| RSUs | 34,063 |
| | 33,488 |
| | 23,888 |
|
The awards are classified as liability awards based on the cash settlement feature. Liability awards are measured at their fair value at the end of each reporting period and will fluctuate based on the price of Fortis' common stock as well as the level of achievement of the financial performance criteria. The awards are payable on the third anniversary of the grant date. TEP's allocated share of probable payout was $9$12 million and $4$9 million as of December 31, 20172019 and 2016,2018, respectively.
TEP's allocated portion of compensation expense is recognized in Operations and Maintenance Expense on the Consolidated Statements of Income. Compensation expense associated with unvested PSUs and RSUs is recognized on a straight-line basis over the minimum required service period in an amount equal to the fair value on the measurement date or each reporting period. TEP recorded $4 million in 2017,2019, $2 million in 2016,2018, and $1$4 million in 20152017 based on its share of UNS Energy's compensation expense.
NOTE 10.12. SUPPLEMENTAL CASH FLOW INFORMATION
CASH TRANSACTIONS |
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2019 | | 2018 | | 2017 |
| Interest Paid, Net of Amounts Capitalized | $ | 80 |
| | $ | 67 |
| | $ | 61 |
|
Income Tax Refunds (1) | (14 | ) | | — |
| | — |
|
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2017 | | 2016 | | 2015 |
| Interest, Net of Amounts Capitalized | $ | 61 |
| | $ | 61 |
| | $ | 65 |
|
Income Taxes (1) | — |
| | — |
| | — |
|
| |
(1) | TEP did not pay federal or state income taxes due to net operating lossreceived a refund of AMT credit carryforwards offsetting taxable income.in 2019. See Note 14 for additional information regarding AMT. |
NON-CASH TRANSACTIONS
Other significant non-cash investing and financing activities that affected recognizedresulted in recognition of assets and liabilities but did not result in cash receipts or payments were as follows: |
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2017 | | 2016 | | 2015 |
Net Cost of Removal Increase (Decrease) (1) | $ | (88 | ) | | $ | 8 |
| | $ | 1 |
|
| Accrued Capital Expenditures | 24 |
| | 29 |
| | 28 |
|
| Commitment to Purchase Capital Lease Interests | — |
| | 36 |
| | — |
|
Asset Retirement Obligations Increase (Decrease) (2) | 10 |
| | (1 | ) | | 3 |
|
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2019 | | 2018 | | 2017 |
| Finance Leases | $ | 67 |
| | $ | 164 |
| | $ | — |
|
| Accrued Capital Expenditures | 40 |
| | 31 |
| | 24 |
|
Asset Retirement Obligations Increase (Decrease) (1) | 26 |
| | 20 |
| | 10 |
|
Operating Leases (2) | 8 |
| | — |
| | — |
|
| Renewable Energy Credits | 3 |
| | 3 |
| | 2 |
|
Net Cost of Removal Increase (Decrease) (3) | (10 | ) | | (4 | ) | | (88 | ) |
| |
(1) | Represents an accrual for future cost of retirement net of salvage values that does not impact earnings. In the 2017 Rate Order, the ACC authorized a new depreciation study for TEP modifying its depreciation reserves and rates. See Note 2 for additional information. |
| |
(2)
| The non-cash additions to AROs and related capitalized assets represent a revision of estimated asset retirement cost due to changes in timing and amount of the expected future AROs. |
| |
(2) | On January 1 2019, TEP adopted accounting guidance that requires lessees to recognize a lease liability and a right-of-use asset for all leases with a lease term greater than 12 months. TEP applied the transition provisions of the new standard as of the adoption date and did not retrospectively adjust prior periods. |
| |
(3) | Represents an accrual for future cost of retirement net of salvage values that does not impact earnings. |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
NOTE 11.13. FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS
TEP categorizes financial instruments into the three-level hierarchy based on inputs used to determine the fair value. Level 1 inputs are unadjusted quoted prices for identical assets or liabilities in an active market. Level 2 inputs include quoted prices for similar assets or liabilities, quoted prices in non-active markets, and pricing models whose inputs are observable, directly or indirectly. Level 3 inputs are unobservable and supported by little or no market activity. Transfers between levels are recorded at the end of a reporting period. There were no transfers between levels in the periods presented.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
FINANCIAL INSTRUMENTS MEASURED AT FAIR VALUE ON A RECURRING BASIS
The following tables present, by level within the fair value hierarchy, TEP’s assets and liabilities accounted for at fair value through net income on a recurring basis classified in their entirety based on the lowest level of input that is significant to the fair value measurement: |
| | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Total |
| (in millions) | December 31, 2017 |
| Assets | |
Cash Equivalents(1) | $ | 30 |
| | $ | — |
| | $ | — |
| | $ | 30 |
|
Restricted Cash(1) | 12 |
| | — |
| | — |
| | 12 |
|
Energy Derivative Contracts, Regulatory Recovery(2) | — |
| | 9 |
| | — |
| | 9 |
|
Energy Derivative Contracts, No Regulatory Recovery(2) | — |
| | — |
| | 3 |
| | 3 |
|
| Total Assets | 42 |
| | 9 |
| | 3 |
| | 54 |
|
| Liabilities | | | | | | | |
Energy Derivative Contracts, Regulatory Recovery(2) | — |
| | (26 | ) | | — |
| | (26 | ) |
Energy Derivative Contracts, No Regulatory Recovery(2) | — |
| | — |
| | (1 | ) | | (1 | ) |
Interest Rate Swap(3) | — |
| | (1 | ) | | — |
| | (1 | ) |
| Total Liabilities | — |
| | (27 | ) | | (1 | ) | | (28 | ) |
| Total Assets (Liabilities), Net | $ | 42 |
| | $ | (18 | ) | | $ | 2 |
| | $ | 26 |
|
|
| | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Total |
| (in millions) | December 31, 2019 |
| Assets | |
Restricted Cash (1) | $ | 18 |
| | $ | — |
| | $ | — |
| | $ | 18 |
|
Energy Derivative Contracts, Regulatory Recovery (2) | — |
| | 3 |
| | — |
| | 3 |
|
Energy Derivative Contracts, No Regulatory Recovery (2) | — |
| | 3 |
| | — |
| | 3 |
|
| Total Assets | 18 |
| | 6 |
| | — |
| | 24 |
|
| Liabilities | | | | | | | |
Energy Derivative Contracts, Regulatory Recovery (2) | — |
| | (76 | ) | | — |
| | (76 | ) |
| Total Liabilities | — |
| | (76 | ) | | — |
| | (76 | ) |
| Total Assets (Liabilities), Net | $ | 18 |
| | $ | (70 | ) | | $ | — |
| | $ | (52 | ) |
| | | (in millions) | December 31, 2016 | December 31, 2018 |
| Assets | | |
Cash Equivalents(1) | $ | 23 |
| | $ | — |
| | $ | — |
| | $ | 23 |
| $ | 55 |
| | $ | — |
| | $ | — |
| | $ | 55 |
|
Restricted Cash(1) | 7 |
| | — |
| | — |
| | 7 |
| 15 |
| | — |
| | — |
| | 15 |
|
Energy Derivative Contracts, Regulatory Recovery(2) | — |
| | 3 |
| | — |
| | 3 |
| — |
| | 10 |
| | — |
| | 10 |
|
Energy Derivative Contracts, No Regulatory Recovery(2) | — |
| | — |
| | 2 |
| | 2 |
| — |
| | — |
| | 2 |
| | 2 |
|
| Total Assets | 30 |
| | 3 |
| | 2 |
| | 35 |
| 70 |
| | 10 |
| | 2 |
| | 82 |
|
| Liabilities | | | | | | | | | | | | | | |
Energy Derivative Contracts, Regulatory Recovery(2) | — |
| | (2 | ) | | (1 | ) | | (3 | ) | — |
| | (35 | ) | | (2 | ) | | (37 | ) |
Interest Rate Swap(3) | — |
| | (2 | ) | | — |
| | (2 | ) | |
| Total Liabilities | — |
| | (4 | ) | | (1 | ) | | (5 | ) | — |
| | (35 | ) | | (2 | ) | | (37 | ) |
| Total Assets (Liabilities), Net | $ | 30 |
| | $ | (1 | ) | | $ | 1 |
| | $ | 30 |
| $ | 70 |
| | $ | (25 | ) | | $ | — |
| | $ | 45 |
|
| |
(1) | Cash Equivalents and Restricted Cash represent amounts held in money market funds and certificates of deposit valued at cost, including interest,, which approximates fair market value. Cash Equivalents are included in Cash and Cash Equivalents on the Consolidated Balance Sheets. Restricted Cash is included in Investments and Other Property and in Current Assets—Other on the Consolidated Balance Sheets. |
| |
(2) | Energy Derivative Contracts include gas swap agreements (Level 2) and forward purchased power and sales contracts (Level 3)2 as of December 31, 2019 and Level 3 as of December 31, 2018) entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the Consolidated Balance Sheets. The valuation techniques are described below. |
| |
(3)
| The Interest Rate Swap is valued using an income valuation approach based on the 6-month LIBORIn 2019, Derivative Contract Liabilities increased primarily due to decreases in forward market prices of natural gas and is includedincreases in Derivative Instruments on the Consolidated Balance Sheets.volume. |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
All energy derivative contracts are subject to legally enforceable master netting arrangements to mitigate credit risk. TEP presents derivatives on a gross basis in the balance sheet. The tables below present the potential offset of counterparty netting and cash collateral. | | | | Gross Amount Recognized in the Balance Sheets | | Gross Amount Not Offset in the Balance Sheets | | Net Amount | Gross Amount Recognized in the Balance Sheets | | Gross Amount Not Offset in the Balance Sheets | | Net Amount |
| | | Counterparty Netting of Energy Contracts | | Cash Collateral Received/Posted | | | Counterparty Netting of Energy Contracts | | Cash Collateral Received/Posted | |
| (in millions) | December 31, 2017 | December 31, 2019 |
| Derivative Assets | | | | | | | | | | | | | | |
| Energy Derivative Contracts | $ | 12 |
| | $ | 10 |
| | $ | — |
| | $ | 2 |
| $ | 6 |
| | $ | 4 |
| | $ | — |
| | $ | 2 |
|
| Derivative Liabilities | | | | | | | | | | | | | | |
| Energy Derivative Contracts | (27 | ) | | (10 | ) | | — |
| | (17 | ) | (76 | ) | | (4 | ) | | (2 | ) | | (70 | ) |
| Interest Rate Swap | (1 | ) | | — |
| | — |
| | (1 | ) | |
| | | (in millions) | December 31, 2016 | December 31, 2018 |
| Derivative Assets | | | | | | | | | | | | | | |
| Energy Derivative Contracts | $ | 5 |
| | $ | 2 |
| | $ | — |
| | $ | 3 |
| $ | 12 |
| | $ | 11 |
| | $ | — |
| | $ | 1 |
|
| Derivative Liabilities | | | | | | | | | | | | | | |
| Energy Derivative Contracts | (3 | ) | | (2 | ) | | — |
| | (1 | ) | (37 | ) | | (11 | ) | | — |
| | (26 | ) |
| Interest Rate Swap | (2 | ) | | — |
| | — |
| | (2 | ) | |
DERIVATIVE INSTRUMENTS
TEP enters into various derivative and non-derivative contracts to reduce exposure to energy price risk associated with its natural gas and purchased power requirements. The objectives for entering into such contracts include: (i) creating price stability; (ii) meeting load and reserve requirements; and (iii) reducing exposure to price volatility that may result from delayed recovery under the PPFAC mechanism. In addition, TEP enters into derivative and non-derivative contracts to optimize the system's generation resources by selling power in the wholesale market for the benefit of the Company's retail customers.
The Company primarily applies the market approach for recurring fair value measurements. When TEP has observable inputs for substantially the full term of the asset or liability or uses quoted prices in an inactive market, it categorizes the instrument in Level 2. TEP categorizes derivatives in Level 3 when an aggregate pricing service or published prices that represent a consensus reporting of multiple brokers is used.
For both purchased power and natural gas prices, TEP obtains quotes from brokers, major market participants, exchanges, or industry publications and relies on its own price experience from active transactions in the market. The Company primarily uses one set of quotations each for purchased power and natural gas and then validates those prices using other sources. TEP believes that the market information provided is reflective of market conditions as of the time and date indicated.
Published prices for energy derivative contracts may not be available due to the nature of contract delivery terms such as non-standard time blocks and non-standard delivery points. In these cases, TEP applies adjustments based on historical price curve relationships, transmission costs, and line losses.
TEP also considers the impact of counterparty credit risk using current and historical default and recovery rates, as well as its own credit risk using credit default swap data.
The inputs and the Company's assessments of the significance of a particular input to the fair value measurements require judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. TEP reviews the assumptions underlying its price curves monthly.
Cash Flow Hedges
To mitigate the exposure to volatility in variable interest rates on debt, TEP hashad an interest rate swap agreement that expiresexpired in January 2020. TEP had a purchased powerAs of December 31, 2019, the total notional amount of the interest rate swap to hedge the cash flow risk associated with a long-term power supply agreement which expired in September 2015.was $6 million. NaN notional amount remained as of February 12, 2020. The after-tax unrealized gains and losses on cash flow hedge activities arewere reported in the statement of comprehensive income. The estimated loss expected to be reclassified to earnings within the next twelve months is estimatedand the realized loss recorded to be $1 million.Interest Expense on the Consolidated Statements of Income are not material to TEP's financial position or results of operations.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Realized losses from cash flow hedges are shown in the following table: |
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2017 | | 2016 | | 2015 |
| Capital Lease Interest Expense | $ | 1 |
| | $ | 1 |
| | $ | 2 |
|
| Purchased Power | — |
| | — |
| | 1 |
|
As of December 31, 2017, the total notional amount of the interest rate swap was $18 million.
Energy Derivative Contracts, Regulatory Recovery
TEP recordsenters into energy contracts that are considered derivatives and qualify for regulatory recovery. The realized gains and losses on these energy contracts are recovered through the PPFAC mechanism and the unrealized gains and losses on energy purchase contracts that are recoverable through the PPFAC mechanism on the balance sheetdeferred as a regulatory asset or a regulatory liability rather than reportingliability. The table below presents the transactionunrealized gains and losses recorded to a regulatory asset or a regulatory liability in the income statement or in the statement of other comprehensive income, as shown in the following table:balance sheet: | | | | Years Ended December 31, | Years Ended December 31, |
| (in millions) | 2017 | | 2016 | | 2015 | 2019 | | 2018 | | 2017 |
| Unrealized Net Gain (Loss) Recorded to Regulatory (Assets) Liabilities | $ | (18 | ) | | $ | 12 |
| | $ | 6 |
| |
Unrealized Net Loss (1) | | $ | (45 | ) | | $ | (9 | ) | | $ | (18 | ) |
| |
(1) | In 2019, unrealized net loss on regulatory recoverable derivative contracts increased primarily due to decreases in forward market prices of natural gas and increases in volume. |
Energy Derivative Contracts, No Regulatory Recovery
TEP enters into certain energy contracts that qualify asare considered derivatives but do not meet thequalify for regulatory recovery criteria.recovery. The Company records unrealized gains and losses for these contracts in the income statement unless a normal purchase or normal sale election is made. For contracts that meet the trading definition, as defined in the PPFAC plan of administration, TEP must share 10% of any realized gains with retail customers through the PPFAC mechanism. The table below presents amounts recorded in Operating Revenues on the Consolidated Statements of Income: |
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2019 | | 2018 | | 2017 |
| Operating Revenues | $ | 6 |
| | $ | 5 |
| | $ | 5 |
|
Derivative Volumes
As of December 31, 2017,2019, TEP hashad energy contracts that will settle on various expiration dates through 2029. The following table presents volumes associated with the energy contracts were as follows:contracts: |
| | | | | |
| | December 31, |
| | 2019 | | 2018 |
| Power Contracts GWh | 4,740 |
| | 1,743 |
|
| Gas Contracts BBtu | 122,779 |
| | 146,933 |
|
|
| | | | | |
| | December 31, |
| | 2017 | | 2016 |
| Power Contracts GWh | 2,589 |
| | 2,610 |
|
Gas Contracts BBtu (1) | 137,952 |
| | 12,355 |
|
| |
(1)
| Increase in volume of gas contracts is a result of the planned early retirement of certain coal-fired generation. To reduce exposure to energy price risk associated with natural gas, the Company entered into longer term gas contracts increasing its overall volume outstanding in 2017. See Note 3 for additional information related to the planned early retirement of coal-fired generation. |
Level 3 Fair Value Measurements
As of December 31, 2019, TEP does not have any Level 3 assets and liabilities balances remaining. The following tables providetable provides quantitative information regarding significant unobservable inputs in TEP’s Level 3 fair value measurements: |
| | | | | | | | | | | | | | | | | | | |
| | Valuation Approach | | Fair Value of | | Unobservable Inputs | | Range of Unobservable Inputs |
| | | Assets | | Liabilities | | |
| (in millions) | December 31, 2018 |
| Forward Power Contracts | Market approach | | $ | 3 |
| | $ | (2 | ) | | Market price per MWh | | $ | 16.80 |
| | $ | 47.05 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | Valuation | | Fair Value of | | | | Range of |
| | Approach | | Assets | | Liabilities | | Unobservable Inputs | | Unobservable Input |
| (in millions) | December 31, 2017 |
| Forward Power Contracts | Market approach | | $ | 3 |
| | $ | (1 | ) | | Market price per MWh | | $ | 17.65 |
| | $ | 34.60 |
|
| | | | | | | | | | | | |
| (in millions) | December 31, 2016 |
| Forward Power Contracts | Market approach | | $ | 2 |
| | $ | (1 | ) | | Market price per MWh | | $ | 20.90 |
| | $ | 40.00 |
|
Changes in one or more of the unobservable inputs could have a significant impact on the fair value measurement depending on the magnitude of the change and the direction of the change for each input. The impact of changes to fair value, including changes from unobservable inputs, are subject to recovery or refund through the PPFAC mechanism and are reported as a regulatory asset or regulatory liability, or as a component of other comprehensive income (loss), rather than in the income statement.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table presents a reconciliation of changes in the fair value of net assets and liabilities classified as Level 3 in the fair value hierarchy and the gains (losses) attributable to the change in unrealized gains (losses) relating to assets (liabilities) still held at the end of the period: |
| | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2019 | | 2018 |
| Beginning of Period | $ | 1 |
| | $ | 2 |
|
| Gains (Losses) Recorded | | | |
| Regulatory Assets or Liabilities, Derivative Instruments | (12 | ) | | (4 | ) |
| Operating Revenues | 5 |
| | 5 |
|
| Settlements | 1 |
| | (2 | ) |
Transfers Out of Level 3 (1) | 5 |
| | — |
|
| End of Period | $ | — |
| | $ | 1 |
|
| | | | |
| Gains (Losses), Assets (Liabilities) Still Held | $ | — |
| | $ | 1 |
|
|
| | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2017 | | 2016 |
| Beginning of Period | $ | 1 |
| | $ | (2 | ) |
| Gains (Losses) Recorded | | | |
| Regulatory Assets or Liabilities, Derivative Instruments | 1 |
| | 2 |
|
| Wholesale Revenues | 4 |
| | 4 |
|
| Settlements | (4 | ) | | (3 | ) |
| End of Period | $ | 2 |
| | $ | 1 |
|
| | | | |
| Gains (Losses), Assets (Liabilities) still held | $ | 2 |
| | $ | 1 |
|
| |
(1) | Transferred from Level 3 to Level 2 because observable market data became available for the assets and liabilities. |
CREDIT RISK
The use of contractual arrangements to manage the risks associated with changes in energy commodity prices creates credit risk exposure resulting from the possibility of non-performance by counterparties pursuant to the terms of their contractual obligations. TEP enters into contracts for the physical delivery of power and natural gas which contain remedies in the event of non-performance by the supply counterparties. In addition, volatile energy prices can create significant credit exposure from energy market receivables and subsequent measurementmeasurements at fair value.
TEP has contractual agreements for energy procurement and hedging activities that contain certain provisions requiring TEP and its counterparties to post collateral under certain circumstances. These circumstances include: (i) exposures in excess of unsecured credit limits; (ii) credit rating downgrades; or (iii) a failure to meet certain financial ratios. In the event that such credit events were to occur, the Company, or its counterparties, would have to provide certain credit enhancements in the form of cash, a LOC,LOCs, or other acceptable security to collateralize exposure beyond the allowed amounts.
TEP considers the effect of counterparty credit risk in determining the fair value of derivative instruments that are in a net asset position, after incorporating collateral posted by counterparties, and then allocates the credit risk adjustment to individual contracts. TEP also considers the impact of its credit risk on instruments that are in a net liability position, after considering the collateral posted, and then allocates the credit risk adjustment to the individual contracts.
The value of all derivative instruments in net liability positions under contracts with credit risk-related contingent features, including contracts under the normal purchase normal sale exception, was $27$100 million as of December 31, 2017,2019, compared with $8$41 million as of December 31, 2016.2018. As of December 31, 2017,2019, TEP had no LOCs$2 million of cash posted as collateral to provide credit enhancements with its counterparties.enhancement which was reflected in Current Assets—Other on the Consolidated Balance Sheets. As of February 12, 2020, there was 0 collateral posted. If the credit risk contingent features were triggered on December 31, 2017,2019, TEP would have been required to post an additional $27$98 million of collateral of which $12$19 million relates to outstanding net payable balances for settled positions.
FINANCIAL INSTRUMENTS NOT CARRIED AT FAIR VALUE
The fair value of a financial instrument is the market price to sell an asset or transfer a liability at the measurement date. TEP uses the following methods and assumptions for estimating the fair value of financial instruments:
Borrowings under revolving credit facilities approximate fair value due to the short-term nature of these financial instruments. These items have been excluded from the table below.
For long-term debt, TEP uses quoted market prices, when available, or calculates the present value of the remaining cash flows as of the balance sheet date. When calculating present value, the Company uses current market rates for bonds with similar characteristics such as credit rating and time-to-maturity. TEP considers the principal amounts of variable rate debt outstanding to be reasonable estimates of the fair value. The Company also incorporates the impact of its own credit risk using a credit default swap rate.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The use of different estimation methods and/or market assumptions may yield different estimated fair value amounts. The following table includes the facenet carrying value and estimated fair value of TEP's long-term debt: |
| | | | | | | | | | | | | | | | | |
| | | | Net Carrying Value | | Fair Value |
| | Fair Value Hierarchy | | December 31, |
| (in millions) | | 2019 | | 2018 | | 2019 | | 2018 |
| Liabilities | | | | | | | | | |
| Long-Term Debt, including Current Maturities | Level 2 | | $ | 1,602 |
| | $ | 1,615 |
| | $ | 1,755 |
| | $ | 1,672 |
|
|
| | | | | | | | | | | | | | | | | |
| | Fair Value Hierarchy | | Face Value | | Fair Value |
| | | | December 31, |
| (in millions) | | | 2017 | | 2016 | | 2017 | | 2016 |
| Liabilities | | | | | | | | | |
| Long-Term Debt, including Current Maturities | Level 2 | | $ | 1,466 |
| | $ | 1,466 |
| | $ | 1,547 |
| | $ | 1,472 |
|
NOTE 12.14. INCOME TAXES
Income tax expense differs from the amount of income tax determined by applying the United States statutory federal income tax rate of 21% in 2019 and 2018 and 35% in 2017 to pre-tax income due to the following: |
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2019 | | 2018 | | 2017 |
| Federal Income Tax Expense at Statutory Rate | $ | 46 |
| | $ | 49 |
| | $ | 97 |
|
| State Income Tax Expense, Net of Federal Deduction | 9 |
| | 9 |
| | 9 |
|
| Federal/State Tax Credits | (6 | ) | | (10 | ) | | (9 | ) |
| Allowance for Equity Funds Used During Construction | (3 | ) | | (1 | ) | | (2 | ) |
| Impact of Enactment, TCJA | — |
| | — |
| | 7 |
|
| Excess Deferred Income Taxes | (9 | ) | | (6 | ) | | — |
|
| Impact of AMT Sequestration | (2 | ) | | 2 |
| | — |
|
| Other | (1 | ) | | — |
| | (1 | ) |
| Total Federal and State Income Tax Expense | $ | 34 |
| | $ | 43 |
| | $ | 101 |
|
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2017 | | 2016 | | 2015 |
| Federal Income Tax Expense at Statutory Rate | $ | 97 |
| | $ | 64 |
| | $ | 70 |
|
| State Income Tax Expense, Net of Federal Deduction | 9 |
| | 6 |
| | 8 |
|
| Federal/State Tax Credits | (9 | ) | | (8 | ) | | (8 | ) |
| Allowance for Equity Funds Used During Construction | (2 | ) | | (1 | ) | | (1 | ) |
| Deferred Tax Asset Valuation Allowance | — |
| | (2 | ) | | 1 |
|
| Impact of Enactment, TCJA | 7 |
| | — |
| | — |
|
| Other | (1 | ) | | — |
| | 2 |
|
| Total Federal and State Income Tax Expense | $ | 101 |
| | $ | 59 |
| | $ | 72 |
|
Income tax expenseTax Expense included inon the income statementConsolidated Statements of Income consists of the following: |
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2019 | | 2018 | | 2017 |
| Current Income Tax Expense | | | | | |
| Federal | $ | (8 | ) | | $ | (13 | ) | | $ | — |
|
| State | — |
| | — |
| | — |
|
| Total Current Income Tax Expense | (8 | ) | | (13 | ) | | — |
|
| Deferred Income Tax Expense | | | | | |
| Federal | 41 |
| | 53 |
| | 98 |
|
| Federal Investment Tax Credits | (4 | ) | | (6 | ) | | (6 | ) |
| State | 5 |
| | 9 |
| | 9 |
|
| Total Deferred Income Tax Expense | 42 |
| | 56 |
| | 101 |
|
| Total Federal and State Income Tax Expense | $ | 34 |
| | $ | 43 |
| | $ | 101 |
|
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2017 | | 2016 | | 2015 |
| Current Income Tax Expense | | | | | |
| Federal | $ | — |
| | $ | — |
| | $ | — |
|
| State | — |
| | — |
| | — |
|
| Total Current Income Tax Expense | — |
| | — |
| | — |
|
| Deferred Income Tax Expense | | | | | |
| Federal | 98 |
| | 60 |
| | 66 |
|
| Federal Investment Tax Credits | (6 | ) | | (6 | ) | | (6 | ) |
| State | 9 |
| | 5 |
| | 12 |
|
| Total Deferred Income Tax Expense | 101 |
| | 59 |
| | 72 |
|
| Total Federal and State Income Tax Expense | $ | 101 |
| | $ | 59 |
| | $ | 72 |
|
On December 22, 2017, the President of the United States of America signed into law the TCJA, which enacted significant changes to the Internal Revenue Code including a reduction in the U.S. federal corporate income tax rate from 35% to 21% effective for tax years beginning after 2017.
In addition, the TCJA provides modifications2018, ACC Refund Orders were approved requiring TEP to bonus depreciation rules and limitations on the deductibility of interest expense, both of which include carve-outs for regulated utilities. The Company was required to revalue its deferred tax assets and liabilities at the new federal corporate income tax rate asshare EDIT amortization of the dateACC-jurisdictional assets with customers. The EDIT activity of enactment of the TCJA. This resulted in a net decrease to deferred income tax liabilities. Since the Company believes it is probable that a significant portion of the decrease will be returned to customers through future rates, a regulatory liability$9 million was established. The impacts of the new tax law to the Company's financial results included: (i) a $7 million increase to Income Tax Expense on the Consolidated Statements of Income in 2017; and (ii) a $343 million net increase toamortized from Regulatory Liabilities and a $336 million net decrease to Deferred Income Tax Liabilities on the Consolidated Balance Sheets as of December 31, 2017.2019. See Note 2 for additional information regarding the ACC Refund Order and the FERC NOPR.
Under the TCJA, AMT credit carryforwards will be refunded if not used to offset federal income tax liabilities. As of December 31, 2019, TEP had a receivable of $7 million related to the AMT credit carryforwards in Current Assets—Other on the Consolidated Balance Sheets.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
In 2018, the Company recorded $2 million of income tax expense related to the estimated impact of sequestration on future AMT credit refunds. In 2019, TEP is stillreversed the $2 million in income tax expense, as the process of evaluatingAMT credit refunds were no longer subject to sequestration due to the bonus depreciation carve-out for regulated utilities and anticipates further clarification from the IRS. TEP has recorded an estimated provision for bonus depreciation for its fixed assets placed in service between September 27, 2017 and December 31, 2017, which impacts TEP’s Operating Loss Carryforward Deferred Tax Asset and Plant Deferred Tax Liability.IRS revising previously issued guidance.
The significant components of deferred income tax assets and liabilities consist of the following: |
| | | | | | | |
| | December 31, |
| (in millions) | 2019 | | 2018 |
| Gross Deferred Income Tax Assets | | | |
| Finance Lease Obligations | $ | 21 |
| | $ | 48 |
|
| Operating Loss Carryforwards, Net | 3 |
| | 23 |
|
| Customer Advances and Contributions in Aid of Construction | 19 |
| | 16 |
|
| AMT Credit | 7 |
| | 13 |
|
| Other Postretirement Benefits | 15 |
| | 15 |
|
| Investment Tax Credit Carryforward | 34 |
| | 34 |
|
| Income Taxes Recoverable Through Future Rates | 81 |
| | 87 |
|
| Other | 79 |
| | 60 |
|
| Total Gross Deferred Income Tax Assets | 259 |
| | 296 |
|
| Deferred Tax Assets Valuation Allowance | — |
| | — |
|
| Gross Deferred Income Tax Liabilities | | | |
| Plant, Net | (602 | ) | | (552 | ) |
| Plant Abandonments | (17 | ) | | (18 | ) |
| Finance Lease Assets, Net | (18 | ) | | (44 | ) |
| Pensions | (17 | ) | | (19 | ) |
| Income Taxes Payable Through Future Rates | (9 | ) | | (12 | ) |
| Other | (28 | ) | | (21 | ) |
| Total Gross Deferred Income Tax Liabilities | (691 | ) | | (666 | ) |
| Deferred Income Taxes, Net | $ | (432 | ) | | $ | (370 | ) |
|
| | | | | | | |
| | December 31, |
| (in millions) | 2017 | | 2016 |
| Gross Deferred Income Tax Assets | | | |
| Capital Lease Obligations | $ | 10 |
| | $ | 35 |
|
| Operating Loss Carryforwards, Net | 56 |
| | 129 |
|
| Customer Advances and Contributions in Aid of Construction | 14 |
| | 20 |
|
| Alternative Minimum Tax Credit | 26 |
| | 25 |
|
| Other Postretirement Benefits | 15 |
| | 23 |
|
| Emission Allowance Inventory | 3 |
| | 9 |
|
| Investment Tax Credit Carryforward | 34 |
| | 32 |
|
| Income Taxes Recoverable Through Future Rates | 88 |
| | — |
|
| Other | 47 |
| | 60 |
|
| Total Gross Deferred Income Tax Assets | 293 |
| | 333 |
|
| Deferred Tax Assets Valuation Allowance | — |
| | — |
|
| Gross Deferred Income Tax Liabilities | | | |
| Plant, Net | (518 | ) | | (774 | ) |
| Plant Abandonments | (21 | ) | | — |
|
| Capital Lease Assets, Net | (5 | ) | | (24 | ) |
| Pensions | (16 | ) | | (26 | ) |
| Income Taxes Payable Through Future Rates | (10 | ) | | — |
|
| Other | (23 | ) | | (38 | ) |
| Total Gross Deferred Income Tax Liabilities | (593 | ) | | (862 | ) |
| Deferred Income Taxes, Net | $ | (300 | ) | | $ | (529 | ) |
TEP recorded no0 valuation allowance against credit and net operating loss carryforward deferred income tax assets as of December 31, 20172019 and 2016.2018. Management believes TEP will produce sufficient taxable income in the future to realize credit and net operating loss carryforwards before they expire.
As of December 31, 2017,2019, TEP had the following carryforward amounts: |
| | | | | |
| (in millions) | Amount | | Expiring Year |
| Federal Net Operating Loss | $ | 17 |
| | 2034 - 35 |
| State Credits | 9 |
| | 2022 - 29 |
| AMT Credit | 7 |
| | None |
| Investment Tax Credits | 34 |
| | 2031 - 37 |
|
| | | | | |
| (in millions) | Amount | | Expiring Year |
| Federal Net Operating Loss | $ | 263 |
| | 2031-35 |
| State Credits | 8 |
| | 2021-29 |
| Alternative Minimum Tax Credit | 26 |
| | None |
| Investment Tax Credits | 34 |
| | 2031-37 |
Uncertain Tax Positions
A reconciliation of the beginning and ending balances of unrecognized tax benefits follows: |
| | | | | | | |
| | December 31, |
| (in millions) | 2019 | | 2018 |
| Beginning of Period | $ | 16 |
| | $ | 13 |
|
| Additions Based on Tax Positions Taken in the Current Year | 2 |
| | 3 |
|
| End of Period | $ | 18 |
| | $ | 16 |
|
|
| | | | | | | |
| | December 31, |
| (in millions) | 2017 | | 2016 |
| Beginning of Period | $ | 12 |
| | $ | 5 |
|
| Additions Based on Tax Positions Taken in the Current Year | 7 |
| | 7 |
|
| Reduction to Positions, TCJA | (6 | ) | | — |
|
| End of Period | $ | 13 |
| | $ | 12 |
|
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Unrecognized tax benefits, if recognized, would reduce income tax expense by less than $1 million as of December 31, 20172019 and 2016.2018.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
TEP recorded no0 interest expense during 2017, 2016, or 20152019 and 2018 related to uncertain tax positions. In addition, TEP had no0 interest payable and no0 penalties accrued as of December 31, 20172019 and 2016.2018.
TEP has been audited by the IRS through tax year 2010. TEP is not currently underTEP's 2011 to 2018 tax years are open for audit by any federal orand state tax agencies. The balance
A decrease of $17 million in unrecognizedthe Company's uncertain tax benefitsposition obligations could occur within the next twelve months pending the outcome of an application for change in accounting method filed with the next 12 months as a resultIRS.
TAX SHARING AGREEMENT
Under the terms of IRS audits, but the Company is unable to determine the amount of change.
NOTE 13.RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
tax sharing agreement with UNS Energy, TEP considers the applicability and impact of all Accounting Standard Updates (ASU) issued by the Financial Accounting Standards Board (FASB). The following updates have been issued, but have not yet been adopted by TEP. Updates not listed below were assessed and either determined to not be applicable or are expected to have a minimal impact on TEP's consolidated financial position, results of operations, or disclosures.
REVENUE FROM CONTRACTS WITH CUSTOMERS
In May 2014, the FASB issued an ASU intended to enable users of financial statements to better understand and consistently analyze an entity's revenues across industries and transactions. The ASU was effective for annual and interim periods beginning January 1, 2018 and permits two implementation approaches: (i) retrospective application; or (ii) modified retrospective application by recognizing the cumulative effect of initially applying the guidance as an adjustmentreceived $14 million in 2019 related to the opening balance of retained earnings on the date of adoption supplemented by additional disclosures. TEP adopted this ASU on January 1, 2018 using the modified retrospective approach,Federal income tax returns and did not identify or record any adjustment0 payments in 2018 related to the opening balance of retained earnings on adoption. Under the new standard, recognition of revenue occurs when a customer obtains control of promised goods or services. In addition, the ASU requires disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The adoption of this ASU did not affect revenue recognition for tariff-based sales to retail and wholesale customers, which represent TEP's primary source of revenue. Accordingly, the adoption of this standard did not have a material effect on TEP's financial statements. However, the presentation and disclosure requirements of the ASU will result in a change in the presentation of revenues on TEP's2017 Federal income statement as well as expanded disclosures.tax returns.
LEASES
In February 2016, the FASB issued an ASU that will require the recognition of leased assets and liabilities by lessees for those leases classified as operating leases under current GAAP. The standard is effective for periods beginning January 1, 2019, and is to be applied using a modified retrospective approach with practical expedient options. Early adoption is permitted. TEP is evaluating the impact of this ASU to its financial statements and disclosures.
COMPENSATION—RETIREMENT BENEFITS
In March 2017, the FASB issued an ASU to improve the presentation of net periodic benefit cost for pension and other postretirement benefits. TEP adopted this ASU on January 1, 2018, the effective date of the ASU. Effective in the first quarter of 2018, TEP will no longer capitalize the non-service cost components of net periodic benefit cost as part of inventory or plant in service and will present non-service costs retrospectively in Other Income—Other Expense on the Consolidated Statements of Income. The adoption of the ASU did not have a material impact on the Company's financial position or results of operations.
DERIVATIVES AND HEDGING
In August 2017, the FASB issued an ASU that enables entities to better align their risk management activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance and the presentation of hedge results. The ASU expands an entity's ability to apply hedge accounting to non-financial and financial risk components and simplify fair value hedges of interest rate risk. The ASU eliminates the requirement to separately measure and report hedge ineffectiveness and generally requires the entire change in the fair value of a hedging instrument to be presented in the same income statement line as the hedged item. The amendments to the ASU also ease hedge documentation and effectiveness assessments requirements under previous guidance. The standard is effective for fiscal years beginning January 1, 2019. Early adoption is permitted. The ASU is expected to have minimal impact to TEP's financial statements and disclosures.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Concluded)
NOTE 14.15. QUARTERLY FINANCIAL DATA (UNAUDITED)
TEP's quarterly financial information is unaudited, but, in management’s opinion, includes all adjustments necessary for a fair presentation. TEP's utility business is seasonal in nature. Peak sales periods for TEP generally occur during the summer. Accordingly, comparisons among quarters of a year may not represent overall trends and changes in operations. |
| | | | | | | | | | | | | | | |
| | First Quarter | | Second Quarter | | Third Quarter | | Fourth Quarter |
| (in millions) | 2019 |
| Operating Revenue | $ | 333 |
| | $ | 326 |
| | $ | 441 |
| | $ | 318 |
|
| Operating Income | 43 |
| | 67 |
| | 134 |
| | 39 |
|
| Net Income | 26 |
| | 42 |
| | 98 |
| | 21 |
|
| | | | | | | | |
| | 2018 |
| Operating Revenue | $ | 275 |
| | $ | 354 |
| | $ | 460 |
| | $ | 344 |
|
| Operating Income | 43 |
| | 83 |
| | 126 |
| | 36 |
|
| Net Income | 24 |
| | 58 |
| | 95 |
| | 11 |
|
|
| | | | | | | | | | | | | | | |
| | First Quarter | | Second Quarter | | Third Quarter | | Fourth Quarter |
| (in millions) | 2017 |
| Operating Revenue | $ | 268 |
| | $ | 352 |
| | $ | 417 |
| | $ | 304 |
|
| Operating Income | 37 |
| | 107 |
| | 138 |
| | 44 |
|
| Net Income | 21 |
| | 61 |
| | 82 |
| | 13 |
|
| | | | | | | | |
| | 2016 |
| Operating Revenue | $ | 243 |
| | $ | 317 |
| | $ | 394 |
| | $ | 281 |
|
| Operating Income | 12 |
| | 72 |
| | 122 |
| | 37 |
|
| Net Income (Loss) | (1 | ) | | 41 |
| | 72 |
| | 12 |
|
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
TEP’s Chief Executive Officer (principal executive officer) and Chief Financial Officer (principal financial officer) supervised and participated in TEP’s evaluation of its disclosure controls and procedures as such term is defined under Rule 13a – 13a–15(e) orand Rule 15d – 15d–15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act), as of the end of the period covered by this report. Disclosure controls and procedures are controls and procedures designed to ensure that information required to be disclosed in TEP’s periodic reports filed or submitted under the Exchange Act, is recorded, processed, summarized, and reported within the time periods specified in the United States Securities and Exchange Commission’s rules and forms. These disclosure controls and procedures are also designed to ensure that information required to be disclosed by TEP in the reports that it files or submits under the Exchange Act is accumulated and communicated to management, including the principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Based upon the evaluation performed, TEP’s Chief Executive Officer and Chief Financial Officer concluded that TEP’s disclosure controls and procedures arewere effective as of December 31, 2017.
While TEP continually strives to improve its disclosure controls and procedures to enhance the quality of its financial reporting, there has been no change in TEP’s internal control over financial reporting during the fourth quarter of 2017 that has materially affected, or is reasonably likely to materially affect, TEP’s internal control over financial reporting.2019.
Management’s Report on Internal Control Over Financial Reporting
TEP’s management is responsible for establishing and maintaining adequate internal control over financial reporting. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of TEP’s internal control over financial reporting as of December 31, 2017.2019. In making this assessment, management used the criteria set forth by the 2013 Committee of Sponsoring Organizations Internal Control – Integrated Framework.
Based on management’s assessment using those criteria, management has concluded that, as of December 31, 2017,2019, TEP’s internal control over financial reporting was effective.
Changes in Internal Control Over Financial Reporting
While TEP continually strives to improve its disclosure controls and procedures to enhance the quality of its financial reporting, thereThere has been no change in TEP’s internal control over financial reporting during the fourth quarter of 20172019 that has materially affected, or is reasonably likely to materially affect, TEP’s internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information required by Item 10 is omitted pursuant to General Instruction I(2)(c) of Form 10-K.
ITEM 11. EXECUTIVE COMPENSATION
Information required by Item 11 is omitted pursuant to General Instruction I(2)(c) of Form 10-K.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Information required by Item 12 is omitted pursuant to General Instruction I(2)(c) of Form 10-K.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
Information required by Item 13 is omitted pursuant to General Instruction I(2)(c) of Form 10-K.
ITEM 14.14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Pre-Approved Policies and Procedures
Rules adopted by the SEC in order to implement requirements of the Sarbanes-Oxley Act of 2002 require public company audit committees to pre-approve audit and non-audit services. UNS Energy’s Audit and Risk Committee has adopted a policy pursuant to which audit, audit-related, tax, and other services are pre-approved by category of service. Recognizing that situations may arise where it is in the Company’s best interest for the auditor to perform services in addition to the annual audit of the Company’s financial statements, the policy sets forth guidelines and procedures with respect to approval of the four categories of service designed to achieve the continued independence of the auditor when it is retained to perform such services for UNS Energy. The policy requires the Audit and Risk Committee to be informed of each service and does not include any delegation of the Audit and Risk Committee’s responsibilities to management. The Audit and Risk Committee may delegate to the Chair of the Audit and Risk Committee the authority to grant pre-approvals of audit and non-audit services requiring Audit and Risk Committee approval where the Audit and Risk Committee Chair believes it is desirable to pre-approve such services prior to the next regularly scheduled Audit and Risk Committee meeting. The decisions of the Audit and Risk Committee Chair to pre-approve any such services from one regularly scheduled Audit Committee meeting to the next shall be reported to the Audit and Risk Committee.
Fees
Effective May 4, 2017, Ernst and Young LLP (EY) was dismissed as the independent auditor and replaced with Deloitte & Touche LLP (Deloitte) as the Company’s independent registered public accounting firm. The Audit and Risk Committee has considered whether the provision of services to TEP by Deloitte and EY,& Touche LLP (Deloitte), beyond those rendered in connection with their audit and review of TEP’s financial statements, is compatible with maintaining their independence as auditor.
The following table details principal accountant fees paid to Deloitte and EY for professional services during 2017 and 2016:services: |
| | | | | | | |
| | Deloitte | | EY |
| (in thousands) | 2017 | | 2016 |
| Audit Fees | $ | 1,145 |
| | $ | 1,484 |
|
| Audit-Related Fees | 17 |
| | — |
|
| Tax Fees | 68 |
| | 100 |
|
| All Other Fees | 24 |
| | — |
|
| Total | $ | 1,254 |
| | $ | 1,584 |
|
|
| | | | | | | |
| (in thousands) | 2019 | | 2018 |
Audit Fees (1) | $ | 924 |
| | $ | 1,268 |
|
Audit-Related Fees (2) | 100 |
| | 140 |
|
Tax Fees (3) | 25 |
| | — |
|
| Total | $ | 1,049 |
| | $ | 1,408 |
|
| |
(1) | Audit Fees includes fees billed, or expected to be billed, by Deloitte, for professional services for the financial statement audits of TEP's consolidated financial statements included in its Annual Report on Form 10-K and review services of TEP's consolidated financial statements included in its Quarterly Reports on Form 10-Q. Audit Fees also includes services provided by Deloitte in |
Audit Fees includes fees for audit services for TEP's consolidated financial statements included in its Annual Report on Form 10-K and review services82
connection with comfort letters, consents, and other services related to SEC matters, financing transactions, and statutory and regulatory audits.
Audit-Related Fees includes fees for consulting services with respect to ASC 606 Revenue Recognition.
Tax Fees includes fees for research and development services with respect to tax credits in 2017 and tax appeals in 2016.
All Other Fees includes fees for consulting services with respect to regulatory filings. | |
(2) | Audit-Related Fees are fees billed, or expected to be billed, by Deloitte for assurance and related services that are reasonably related to the performance of the audit or review of the financial statements and are not included in Audit Fees reported above. The fees are for additional procedures for nonrecurring material transactions in 2019 and 2018. |
| |
(3) | Tax Fees are fees billed by Deloitte for professional services related to tax planning and tax strategy. |
All services performed by our principal accountant are approved in advance by the Audit and Risk Committee in accordance with the Audit and Risk Committee’s pre-approval policy for services provided by the Independent Registered Public Accounting Firm.
PART IV
ITEM 15.15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES |
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| (a) | (1) | Consolidated Financial Statements as of December 31, 20172019 and 2016,2018, and for each of the three years in the period ended December 31, 2017:2019: | |
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| | (2) | Financial Statement Schedule | |
| | | All schedules have been omitted because they are either not applicable, not required, or the information required to be set forth therein is included on the Consolidated Financial Statements or notes thereto. | |
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| | (3) | Exhibits | |
| | | Reference is made to the Exhibit Index commencing on page 8685. | |
ITEM 16. FORM 10-K SUMMARY
Not Applicable.
|
| | |
| Exhibit Index |
| Exhibit No. | | Description |
| | Agreement and Plan of Merger, dated as of December 11, 2013, among FortisUS Inc., Color Acquisition Sub Inc., UNS Energy Corporation and solely for purposes of Section 5.5(a) and 8.15, Fortis Inc. (Form 8-K, dated December 12, 2013, File No. 1-05924 - Exhibit 2.1). |
| | |
| | First Amendment to the Agreement and Plan of Merger, dated as of August 14, 2014, by and among FortisUS Inc., Color Acquisition Sub Inc. and UNS Energy Corporation (Form 8-K, dated August 14, 2014, File No. 1-05924 - Exhibit 2.2). |
| | |
| | Restated Articles of Incorporation of TEP, filed with the ACC on August 11, 1994, as amended by Amendment to Article Fourth of our Restated Articles of Incorporation, filed with the ACC on May 17, 1996. (Form 10-K for the year ended December 31, 1996, File No. 1-05924 - Exhibit No 3(a)). |
| | | |
| | TEP Articles of Amendment filed with the ACC on September 3, 2009 (Form 10-K for the year ended December 31, 2010, File No. 1-05924 - Exhibit 3(a)). |
| | | |
| | Bylaws of TEP, as amended as of August 12, 2015 (Form 10-Q for the quarter ended September 30, 2015, File No. 1-05924 - Exhibit 3). |
| | | |
| | Amendment to Articles of Incorporation of UNS Energy Corporation, creating series of Limited Voting Junior Preferred Stock (Form 8-K dated August 12, 2015, File No. 1-05924 - Exhibit 3.2). |
| | | |
| | Indenture of Trust, dated as of October 1, 2009, between The Industrial Development Authority of the County of Pima and U.S. Bank Trust National Association authorizing Pollution Control Revenue Bonds, 2009 Series A (Tucson Electric Power Company Navajo Project). (Form 8-K dated October 13, 2009, File No. 1-05924 - Exhibit 4(A)). |
| | | |
| | Loan Agreement, dated as of October 1, 2009, between The Industrial Development Authority of the County of Pima and TEP relating to Pollution Control Revenue Bonds, 2009 Series A (Tucson Electric Power Company San Juan Project). (Form 8-K dated October 13, 2009, File No. 1-05924 - Exhibit 4(B)). |
| | | |
| | Indenture of Trust, dated as of October 1, 2009, between Coconino County, Arizona Pollution Control Corporation and U.S. Bank Trust National Association authorizing Pollution Control Revenue Bonds, 2009 Series A (Tucson Electric Power Company Navajo Project). (Form 8-K dated October 13, 2009, File No. 1-05924 - Exhibit 4(C)). |
| | |
| | Loan Agreement, dated as of October 1, 2009, between Coconino County, Arizona Pollution Control Corporation and TEP relating to Pollution Control Revenue Bonds, 2009 Series A (Tucson Electric Power Company Navajo Project). (Form 8-K dated October 13, 2009, File No. 1-05924 - Exhibit 4(D)). |
| | |
| | Indenture of Trust, dated as of October 1, 2010, between the Industrial Development Authority of the County of Pima and U.S. Bank Trust National Association, authorizing Industrial Development Revenue Bonds, 2010 Series A (Tucson Electric Power Company Project). (Form 8-K dated October 8, 2010, File No. 1-05924 Exhibit 4(a)). |
| | | |
| | Loan Agreement, dated as of October 1, 2010, between the Industrial Development Authority of the County of Pima and TEP, relating to Industrial Development Revenue Bonds, 2010 Series A (Tucson Electric Power Company Project). (Form 8-K dated October 8, 2010, File No. 1-05924 - Exhibit 4(b)). |
| | | |
| | Indenture of Trust, dated as of December 1, 2010, between the Coconino County, Arizona Pollution Control Corporation and U.S. Bank Trust National Association authorizing Pollution Control Bonds, 2010 Series A (Tucson Electric Power Company Navajo Project). (Form 8-K dated December 17, 2010, File No. 1-05924 - Exhibit 4(c)). |
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|
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| | Loan Agreement, dated as of December 1, 2010, between the Coconino County, Arizona Pollution Control Corporation and TEP relating to Pollution Control Bonds, 2010 Series A (Tucson Electric Power Company Navajo Project). (Form 8-K dated December 17, 2010, File No. 1-05924 - Exhibit 4(d)). |
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| | Indenture of Trust, dated as of March 1, 2012, between The Industrial Development Authority of the County of Apache and U.S. Bank Trust National Association, authorizing Pollution Control Revenue Bonds, 2012 Series A (Tucson Electric Power Company Project). (Form 8-K dated March 21, 2012, File No. 1-05924 - Exhibit 4(a)). |
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| | Loan Agreement, dated as of March 1, 2012, between The Industrial Development Authority of the County of Apache and TEP, relating to Pollution Control Revenue Bonds, 2012 Series A (Tucson Electric Power Company Project). (Form 8-K dated March 21, 2012, File No. 1-05924 - Exhibit 4(b)). |
| | | |
| | Indenture of Trust, dated as of June 1, 2012, between The Industrial Development Authority of the County of Pima and U.S. Bank Trust National Association, authorizing Industrial Development Revenue Bonds, 2012 Series A (Tucson Electric Power Company Project). (Form 8-K dated June 21, 2012, File No. 1-05924 - Exhibit 4(a)). |
| | | |
| | Loan Agreement, dated as of June 1, 2012, between The Industrial Development Authority of the County of Pima and TEP, relating to Industrial Development Revenue Bonds, 2012 Series A (Tucson Electric Power Company Project). (Form 8-K dated June 21, 2012, File No. 1-05924 - Exhibit 4(b)). |
| | | |
| | Indenture of Trust, dated as of March 1, 2013, between The Industrial Development Authority of the County of Pima and U.S. Bank Trust National Association, authorizing Industrial Development Revenue Bonds, 2013 Series A (Tucson Electric Power Company Project). (Form 8-K dated March 14, 2013, File No. 1-05924 - Exhibit 4(a)). |
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| | Loan Agreement, dated as of March 1, 2013, between The Industrial Development Authority of the County of Pima and TEP, relating to Industrial Development Revenue Bonds, 2013 Series A (Tucson Electric Power Company Project). (Form 8-K dated March 14, 2013, File No. 1-05924 - Exhibit 4(b)). |
| | | |
| | Indenture of Trust, dated as of November 1, 2013, between The Industrial Development Authority of the County of Apache and U.S. Bank Trust National Association, authorizing Industrial Development Revenue Bonds, 2013 Series A (Tucson Electric Power Company Springerville Project). (Form 8-K dated November 14, 2013, File No. 1-05924 - Exhibit 4(a)). |
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| | Loan Agreement, dated as of November 1, 2013, between The Industrial Development Authority of the County of Apache and Tucson Electric Power Company, relating to Industrial Development Revenue Bonds, 2013 Series A (Tucson Electric Power Company Springerville Project). (Form 8-K dated November 14, 2013, File No. 1-05924 - Exhibit 4(b)). |
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| | Lender Rate Mode Covenants Agreement, dated as of November 1, 2013, between Tucson Electric Power Company and STI Institutional & Government, Inc. (Form 8-K dated November 14, 2013, File No. 1-05924 - Exhibit 4(c)). |
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| | Amendment, dated May 26, 2015, between Tucson Electric Power Company, STI Institutional & Government, Inc., and Branch Banking and Trust Company, to Lender Rate Made Covenants Agreement, dated November 1, 2013 (Form 10-Q for the quarter ended June 30, 2015, File No. 1-05924 - Exhibit 4). |
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| | Indenture, dated November 1, 2011, between Tucson Electric Power Company and U.S. Bank National Association, as trustee, authorizing unsecured Notes (Form 8-K dated November 8, 2011, File 1-05924 - Exhibit 4.1). |
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| | Officers Certificate, dated November 8, 2011, authorizing 5.15% Notes due 2021.2021 (Form 8-K dated November 8, 2011, File No. 1-05924 - Exhibit 4.2). |
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| | Officers Certificate, dated September 14, 2012, authorizing 3.85% Notes due 2023.2023 (Form 8-K dated September 14, 2012, File No. 1-05924 - Exhibit 4.1). |
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| | Officer's Certificate, dated March 10, 2014, authorizing 5.00% Senior Notes due 2044 (Form 8-K dated March 10, 2014, File No. 1-05924 - Exhibit 4.1). |
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| | Officer's Certificate, dated February 27, 2015, authorizing 3.05% Senior Notes due 2025 (Form 8-K dated February 27, 2015, File No. 1-05924 - Exhibit 4(a)). |
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| | Reimbursement Agreement,Officer's Certificate, dated as of December 14, 2010, among TEP, as Borrower, the financial institutions from time to time, parties thereto and JPMorgan Chase Bank, N.A., as Administrative Agent and as Issuing Bank. (Form 8-K dated December 17, 2010, File No. 1-05924 - Exhibit 4(a)).November 29, 2018, authorizing 4.85% Senior Notes due 2048. |
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| | Amendment No. 1 to Reimbursement Agreement, dated as of February 11, 2014 among TEP, as Borrower, the financial institutions from time to time, parties thereto and JPMorgan Chase Bank, N.A., as Administrative Agent and as Issuing Bank (Form 10-K for the year ended December 31, 2013, File No. 1-05924 - Exhibit 4(t)(2)). |
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| | Credit Agreement, dated as of October 15, 2015, among Tucson Electric Power Company, MUFG Union Bank, N.A. as Administrative Agent, and a group of lenders (Form 8-K dated October 15, 2015, File No. 1-05924 - Exhibit 4.1). |
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| | ComputationCredit Agreement, dated as of RatioDecember 11, 2019, among Tucson Electric Power Company, Truist Bank, as Administrative Agent, and a group of Earnings to Fixed Charges.lenders (Form 8-K dated December 11, 2019, File No. 1-05924 - Exhibit 4.1). |
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| | Consent of Deloitte & Touche LLP, Independent Registered Public Accounting Firm. |
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| | Power of Attorney. |
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| | Certification Pursuant to Section 302 of the Sarbanes-Oxley Act, by David G. Hutchens. |
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| | Certification Pursuant to Section 302 of the Sarbanes-Oxley Act, by Frank P. Marino. |
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| | Statements of Corporate Officers (pursuant to Section 906 of the Sarbanes-Oxley Act of 2002). |
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| 101.INS | | XBRL Instance Document. |
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| 101.SCH | | XBRL Taxonomy Extension Schema Document. |
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| 101.CAL | | XBRL Taxonomy Extension Calculation Linkbase Document. |
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| 101.LAB | | XBRL Taxonomy Extension Label Linkbase Document. |
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| 101.PRE | | XBRL Taxonomy Extension Presentation Linkbase Document. |
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| 101.DEF | | XBRL Taxonomy Extension Definition Linkbase Document. |
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| 104 | | The cover page from the Company's Annual Report on Form 10-K for the year ended December 31, 2019, formatted in Inline XBRL and contained in Exhibit 101 |
| | |
| * | | Previously filed as indicated and incorporated herein by reference. |
| ** | | Pursuant to Item 601(b)(32)(ii) of Regulation S-K, this certificate is not being “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended. |
SIGNATURES
Pursuant to the requirements of section 13 or 15(b) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. |
| | | |
| | | | TUCSON ELECTRIC POWER COMPANY |
| | | | (Registrant) |
| | | | |
| Date: | February 15, 201812, 2020 | | /s/ Frank P. Marino |
| | | | Frank P. Marino |
| | | | Sr. Vice President, Chief Financial Officer, and Director |
| | | | (Principal Financial Officer and Principal Accounting 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 and on the dates indicated. |
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| Date: | February 15, 201812, 2020 | | /s/ David G. Hutchens** |
| | | | David G. Hutchens |
| | | | President, Chief Executive Officer and Director |
| | | | (Principal Executive Officer) |
| | | | |
| Date: | February 15, 201812, 2020 | | /s/ Frank P. Marino |
| | | | Frank P. Marino |
| | | | Sr. Vice President, Chief Financial Officer, and Director |
| | | | (Principal Financial Officer and Principal Accounting Officer) |
| | | | |
| Date: | February 15, 201812, 2020 | | /s/ Todd C. Hixon** |
| | | Susan M. Gray |
| | | President, Chief Operating Officer, and Director |
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| Date: | February 12, 2020 | | * |
| | | | Todd C. Hixon |
| | | | Director |
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Date: | February 15, 2018 | *By: | /s/ Frank P. Marino |
| | | | Frank P. Marino |
| | | | *As attorney-in-fact for each of the persons indicatedAttorney-in-fact |