ITEM 1. BUSINESS
OVERVIEW OF BUSINESS
General
TEP and its predecessor companies have served the greater Tucson metropolitan area for 126 years. TEP was incorporated in the State of Arizona in 1963. TEP is a regulated electric utility company serving approximately 425,000 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. UNS Energy is an indirect wholly owned subsidiary of Fortis Inc. (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 on 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), 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:
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 governmental entities. TEP’s retail sales are influenced by several factors including economic conditions, seasonal weather patterns, Demand Side Management (DSM) initiatives and the increasing use of energy-efficient products, and customer-sited 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 2019 based on the estimated population growth in its service territory.
TEP’s retail sales volume in 2018 was 8,900 gigawatt-hours (GWh), which is a decrease of 3% from 2014 levels. During the past five years, mining load reductions and state requirements to promote energy efficiency and DG have resulted in lower sales volumes.
TEP’s mining customers make up 7% 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-generation resources. TEP’s GWh sales to mining customers have decreased by 9% from 2014 levels as a result of the decline in commodity prices causing the mines to curtail production starting in 2016. TEP cannot predict future commodity prices or the impact they will have on mining production and TEP’s sales to mining customers.
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 power 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 primary long-term wholesale sale contracts are presented in the table below:
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. Short-term wholesale sales increased in 2018 due to the increase in generation capacity related to Gila River Generating Station (Gila River) Unit 2.
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 August 2018, the ACC opened a docket to evaluate several energy policies including retail competition for generation services. A workshop was held related to retail competition in
December 2018. 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, 2018, TEP had 3,076 megawatts (MW) of nominal generation capacity, as set forth in the following table. Nominal capacity is based on unit design net output and measured in alternating current (AC).
(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 Station (Navajo), plans to discontinue operations of Navajo by the end of 2019.
(3)
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 includes a three-year option to purchase the unit (Tolling PPA).
(4)
TEP plans to discontinue operations of H. Wilson Sundt Generating Station (Sundt) Units 1 & 2 by the end of 2020.
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. Tri-State Generation and Transmission Association, Inc. (Tri-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.
Salt River Project Agricultural Improvement and Power District (SRP), 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) 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, PPAs, and customer-sited DG.
In 2018, the percentage of retail kilowatt-hour (kWh) sales attributable to the RES was approximately 14%, exceeding the 2018 requirement of 8%. The ACC approved a waiver of the 2018 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, 2018, TEP owned 46 MW of photovoltaic (PV) solar generation capacity, measured in AC. The following table presents TEP's owned utility-scale renewable generation resources:
(1)
TEP has a 30-year easement agreement to facilitate operations on behalf of the Department of the Army.
(2)
The University of Arizona Science and Technology Park (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, 2018, TEP had renewable PPAs for 159 MW from solar resources, 80 MW from wind resources, and 4 MW associated with the purchase of landfill gas as presented in the 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.
(1)
Purchase of landfill gas for use at Sundt.
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 8 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 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. 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) and others are indexed to natural gas prices. TEP also purchases power in the daily and hourly markets to meet higher than anticipated demands, to cover generation outages, or 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 facility outages and system disturbances, and reduce the amount of reserves TEP is required to carry.
Peak Demand and Future Resources
Peak Demand
In 2018, 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).
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 2018 was comparable to 2017 but significantly higher than peak demand in 2014 through 2016 primarily due to warmer than normal summer temperatures.
Forecasted retail peak demand for 2019 is 2,305 MW compared with actual peak demand of 2,413 MW in 2018. TEP’s 2019 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 2019.
Future Resources
As of December 31, 2018, approximately 40% of TEP's generation capacity, including owned and leased resources, was 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 natural gas Reciprocating Internal Combustion Engine (RICE) units to be placed in service at Sundt and the planned purchase of 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:
Coal Supply
The coal used for generation is low-sulfur, bituminous or sub-bituminous coal 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), including transportation, was $2.33 in 2018, $2.29 in 2017, and $2.21 in 2016.
(1)
In October 2018, Westmoreland Coal Company (WCC), the owner of San Juan Coal Company (SJCC), filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code. TEP believes it has adequate resource capacity to meet its near-term load obligations in the event WCC’s operations at the San Juan Mine are curtailed. See Note 8 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding WCC's bankruptcy.
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 to be sufficient to supply the estimated requirements for Springerville Units 1 and 2 for their remaining lives.
Coal-Fired Generation Facilities Operated by Others
TEP also participates in jointly-owned coal-fired generation facilities at Four Corners Generating Station (Four Corners), Navajo, and San Juan Generating Station (San Juan). Four Corners, which is operated by Arizona Public Service Company (APS), and San Juan, which is operated by Public Service Company of New Mexico (PNM), are mine-mouth generation facilities located adjacent to the coal reserves. Navajo, which is operated by SRP, obtains its coal supply from the nearby Kayenta coal mine and receives deliveries on a dedicated electric railroad delivery system. TEP expects coal reserves available to these three jointly-owned generation facilities to be sufficient for the remaining lives of the stations.
Natural Gas Supply
The table below provides information on the natural gas transportation agreements that deliver our natural gas to the generation stations. The average cost of natural gas per MMBtu, including transportation, was $2.92 in 2018, $3.58 in 2017, and $3.14 in 2016.
Transmission and Distribution
Transmission facilities owned by TEP and third parties are located in Arizona and New Mexico and transmit the output from TEP’s electric generation facilities to the Tucson area. TEP's 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 2,189 miles of transmission lines and 7,680 miles of distribution lines as of December 31, 2018.
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 terms and prices of transmission services and wholesale electricity sales.
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 regulation that affect TEP.
TEP Rate Case
The ACC issued orders in the rate case filed by TEP in November 2015, which was based on a test year ended June 30, 2015, in two phases. Provisions of the first phase authorized an annual increase in TEP's non-fuel revenue requirement of $81.5 million, effective February 27, 2017 (2017 Rate Order). The ACC deferred matters related to net metering and rate design for new DG customers to a second phase of TEP's rate case proceedings (Phase 2).
In 2018, the ACC issued an order establishing an export rate that replaced net metering for excess solar generation, effective October 1, 2018 (Phase 2 Order). Residential and small commercial customers who apply to interconnect their solar generation systems to TEP's distribution system after the date of the order will no longer qualify for net metering.
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 rate is adjusted annually each April 1st for the subsequent 12-month period unless 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.
As of December 31, 2018, TEP had an over-collected PPFAC balance of $17 million.
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 are partially recovered through the Lost Fixed Cost Recovery (LFCR) mechanism.
Energy Efficiency Standards
Under the Energy Efficiency 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. The associated lost revenues attributable to meeting these targets are partially recovered through the LFCR mechanism. As of December 31, 2018, TEP’s cumulative annual energy savings was approximately 16%.
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. In May 2017, the FERC informed TEP that the related investigation was closed. See Note 8 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information related to FERC compliance associated with these transmission contracts.
ENVIRONMENTAL MATTERS
The Environmental Protection Agency (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.
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 an area does not meet the standard, the area is designated as a “non-attainment” and needs to develop a plan to bring the air-shed into compliance. A “non-attainment” designation may slow economic growth in the region and impact TEP's ability to site new local generation. Arizona submitted recommendations for area designations (attainment, non-attainment, or unclassified) to the EPA in September 2016. The EPA completed all area designations as 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 County exceeded the 2015 NAAQS standard for O3 at one monitoring location. If the county continues to exceed the standard, the state could recommend an O3 non-attainment designation 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 new or additional requirements for wastewater streams associated with fly ash, bottom ash, flue gas desulfurization, flue gas mercury control, and gasification 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.
With the exception of Four Corners, none of TEP's owned steam electric generation facilities are subject to the ELG standards. With regard to Four Corners, until the EPA indicates how it intends to change the ELG for bottom ash transport water, it is unclear how the reconsideration will affect this waste stream, and what controls may be required.
TEP believes 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 of this Form 10-K for additional information related to environmental laws and regulations as well as environmental compliance capital expenditures.
EMPLOYEES
As of December 31, 2018, TEP had 1,528 employees, of which approximately 634 are represented by the International Brotherhood of Electrical Workers Local No. 1116 (IBEW). The current collective bargaining agreements between the IBEW and TEP expire in July 2022 with wages in effect through December 2022.
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 1, 2019, are as follows:
(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.
SEC REPORTS AVAILABLE
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 Securities and Exchange Commission (SEC). The SEC maintains an internet site at http://www.sec.gov that contains reports, proxy and information statements and other information regarding issuers that file electronically. TEP's reports are also available free of charge through TEP’s website address at www.tep.com/about/investors/.
TEP is providing the address of TEP’s 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 filed with the SEC by TEP.
ITEM 1A.
ITEM 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 negatively 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% per year from 2014 through 2018.
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, first quarter net income is typically limited by relatively mild winter weather in TEP'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 results of operations, net income, and cash flows at TEP.
TEP’s ten largest customers represented 11% of total revenues in 2018. 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; 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 the Company's results of operations, net income, and cash flows.
REGULATORY
TEP's business is significantly impacted by government legislation, regulation and oversight. Changes made to legislation and regulation could negatively affect the Company’s 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 that has jurisdiction over rates for retail customers. Commissioners are elected state-wide for staggered four-year terms and are limited to serving two consecutive terms. As a result, the composition of the commission, and therefore its policies, are subject to change every two years.
•
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 transmission standards developed and enforced by NERC and subject to the oversight of the FERC. Compliance with modified or new transmission standards may subject TEP to higher operating costs and increased capital costs. Failure to comply with the mandatory transmission standards could subject TEP to sanctions, including substantial monetary penalties.
In addition, 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 demand response and customer energy efficiency programs. 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. Any such initiatives or changes could accelerate the Company's long-term resource diversification strategy and significantly increase capital expenditures and operating expenses. TEP would seek to recover the costs associated with any such requirements through rates. 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, and whether the associated ratemaking mechanisms can be adjusted in a timely manner. 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.
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.
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 coal generation.
Numerous federal, state, and local environmental laws and regulations affect present and future operations. Those laws and regulations include rules regarding air emissions, water use, wastewater discharges, solid waste, hazardous waste, and management of coal combustion residuals.
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 the 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 fully recoverable from TEP customers. TEP’s obligation to comply with the EPA’s Regional Haze Regulations (Regional Haze) requirements as a participant or owner in the Springerville, San Juan, 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.
Regulations limiting greenhouse gas emissions may be enacted, which would require an accelerated shift from fossil fuel-based generation to renewable generation that 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 fuel-based generation facilities. In its current form, the CPP requires a shift in generation that could lead to the early retirement of coal-fired generation in Arizona and New Mexico. In 2017, the EPA issued a proposal to repeal the CPP and in 2018 published the proposed Affordable Clean Energy rule that is meant to replace the CPP. The EPA anticipates finalizing the rule in early 2019. Under the proposed rule, the EPA would set emission guidelines for Greenhouse Gas (GHG) emissions. The states would then use these emission guidelines to establish standards of performance within their jurisdictions considering source specific factors such as the remaining useful life of an individual unit. TEP will continue to work with other Arizona and New Mexico utilities, as well as the appropriate regulatory agencies, to develop compliance strategies. TEP is unable to determine the impact the final rule will have on its facilities until all legal challenges have been resolved and the required state compliance plans are
developed and approved by the EPA. The proposed rule and any other regulations that result in costs associated with an accelerated shift from fossil fuel-based generation towards renewable generation could increase the Company's costs of operations.
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 gas 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, 2018, TEP's regulatory assets balance related to its planned early generation retirement costs was $72 million.
Volatility or disruptions in the financial markets, rising interest rates, or unanticipated financing needs, could increase TEP's financing costs, limit access to the credit or bank markets, affect the Company's ability to comply with financial covenants in debt 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 bank markets and capital markets as a significant source of liquidity and for capital requirements not satisfied by the cash flows from TEP's operations. Market disruptions such as those experienced in 2008 and 2009 in the United States and abroad may increase the Company's cost of borrowing or negatively affect TEP's ability to access sources of liquidity needed to finance the Company's operations and satisfy its 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, and general economic downturns in TEP's utility service territories. If TEP is unable to access credit at reasonable rates, or if the Company's borrowing costs dramatically increase, TEP's ability to finance its operations, meet debt obligations, and execute its financial strategy could be negatively affected.
Increases in short-term interest rates would increase the cost of borrowings under TEP's credit facility. In addition, changing market conditions could negatively affect the market value of assets held in its 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, 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, 2018, there were outstanding approximately $272 million aggregate principal amount of tax-exempt bonds that financed pollution control expenditures at TEP’s generation facilities. Should certain of TEP’s generation facilities be retired and dismantled prior to 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 early redemption by TEP. The bonds have early redemption dates or final maturities ranging from 2019 to 2022.
In addition, as of December 31, 2018, there were outstanding approximately $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. The bonds have early redemption dates ranging from 2020 to 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 the Company's business and can cause damage to its 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.
TEP receives power from certain generation facilities that are jointly-owned with, 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-owned with, or operated by, third parties. TEP does not have the sole discretion 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 such generation facilities. Further, TEP may have limited ability to determine how best to manage the changing economic conditions or environmental requirements that 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 operators of critical energy infrastructure, TEP is facing a heightened risk of physical attacks on the Company's electric systems. The 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.
If, despite TEP's security measures, a significant physical attack occurred, the Company could have: (i) operations disrupted and/or property damaged; (ii) experience loss of revenues, response costs, and other financial loss; and (iii) be subject to increased regulation, litigation, and damage to the Company's reputation. Any of these 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 facing a heightened risk of cyber-attacks. The Company's information and operations technology systems may be vulnerable to unauthorized access due to hacking, viruses, acts of war or terrorism, and other causes. TEP's operations technology systems have direct control over certain aspects of the electric system, and 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: (i) operations disrupted, property damaged, and customer information stolen; (ii) experience loss of revenues, response costs, and other
financial loss; and (iii) be subject to increased regulation, litigation, and damage to the Company's reputation. Any of these outcomes could have a negative impact on TEP's business and results of operations.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2.
ITEM 2. PROPERTIES
The principal owned and leased generation, distribution, and transmission facilities of TEP are described in Part I, Item 1. Business, Overview of Business and such descriptions are incorporated herein by reference.
TEP's generation facilities (except as noted below), administrative headquarters, warehouses and service centers are located on land owned by TEP. TEP owned distribution and transmission facilities are located: (i) on property owned by TEP; (ii) under or over streets, alleys, highways, and other places in the public domain, as well as in national forests and state lands, under franchises, land easements, or other rights-of-way, which generally are subject to termination; (iii) under or over private property as a result of land easements obtained primarily from the record holder of title; or (iv) over tribal lands under the grant of easement by the Secretary of the Interior or leased from Indian Nations.
TEP has 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. 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, acquired land rights, land easements, and leases for San Juan's generation facilities, transmission lines, and water diversion facility located on land owned by the Navajo Nation. TEP, in conjunction with PNM and Samchully Power & Utilities 1 LLC, holds an undivided ownership interest in the property on which Luna Generating Station (Luna) is located.
TEP’s rights under 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 and the Indian Nations;
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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 Nations 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.
ITEM 3.
ITEM 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 operations 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 8 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information.
ITEM 4.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II
ITEM 5.
ITEM 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.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The following table provides selected financial data for the years 2014 through 2018:
ITEM 7.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Management’s Discussion and Analysis explains the results of operations, the financial condition, and the outlook for TEP. It includes the following:
•
outlook and strategies;
•
results of operations for 2018 compared with 2017, and 2017 compared with 2016;
•
factors affecting our results of operations and outlook;
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liquidity and capital resources including capital expenditures, contractual obligations, and environmental matters;
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critical accounting policies and estimates; and
•
new accounting standards issued and not yet adopted.
Management’s Discussion and Analysis includes financial information prepared in accordance with Generally Accepted Accounting Principles (GAAP) in the United States of America.
Management’s Discussion and Analysis should be read in conjunction with Part II, Item 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 STRATEGIES
TEP's financial prospects 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 and legislative actions. Our plans and strategies include the following:
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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 and reliable service.
•
Continuing to focus on our long-term resource diversification strategy, including transitioning from carbon intensive sources to a more sustainable energy portfolio, while providing 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 meeting 30% of our customers’ energy needs with non-carbon emitting resources by 2030. This resource strategy may be impacted by 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 2018, Management's Discussion and Analysis includes the following notable items:
•
The ACC Refund Order, reflecting the lower federal income tax rate, was approved and resulted in a total customer refund of $33 million in 2018. The refund was returned to customers through a bill credit effective May 1, 2018. TEP will continue to return savings to customers through a combination of a bill credit and a regulatory liability in 2019 and through the completion of our next rate case, which is expected to be filed in April 2019.
•
We responded to the FERC Refund Order with a proposed overall transmission rate reduction, reflecting the lower federal income tax rate. The FERC approved our proposal 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.
•
As a result of SRP completing the Gila Acquisition, TEP had $164 million recorded in Capital Lease Obligations and Utility Plant Under Capital Leases on the Consolidated Balance Sheets as of December 31, 2018, related to the 20-
year Tolling PPA. The amount represents the fair value of the unit, which was determined based on SRP's purchase price. The additional 550 MW of capacity, power, and ancillary services will allow us to continue to move toward our long-term goal of resource diversification.
•
The ACC issued the Phase 2 Order. The order established, among other things, an initial export rate that replaced net metering for excess solar generation for customers who applied for interconnection to TEP's distribution system after the date of the order. The new rate went into effect October 1, 2018.
•
TEP issued and sold $300 million aggregate principal amount of senior unsecured notes and redeemed $137 million of variable rate tax-exempt bonds. As of December 31, 2018, all of TEP's debt was unsecured.
RESULTS OF OPERATIONS
Weather and other factors cause seasonal fluctuations in the sales of power. TEP's summer peaking load occurs during the third quarter of the year when cooling demand is higher, which results in higher revenue during such period. By contrast, lower sales of power occur during the first quarter of the year, due to mild winter weather in our retail service territory. Seasonal fluctuations affect the comparability of our results of operations across quarters.
The following provides a discussion of the significant items that affected TEP's results of operations in years ended December 31, 2018, 2017, and 2016, presented on an after-tax basis.
2018 compared with 2017
TEP reported net income of $188 million in 2018 compared with $177 million in 2017. The increase of $11 million, or 6%, was primarily due to:
•
$41 million in lower income tax expense due to the reduction of the federal effective income tax rate primarily related to the enactment of the TCJA. See Note 13 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;
•
$12 million in higher retail revenue primarily due to an increase in rates as approved in the 2017 Rate Order that took effect February 27, 2017; and
•
$3 million in higher Allowance for Funds Used During Construction (AFUDC) related to the increase in construction projects.
The increase was partially offset by:
•
$27 million in lower retail revenue associated with the ACC Refund Order to return savings related to the TCJA to customers. The order was effective May 1, 2018. 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 ACC Refund Order;
•
$8 million in lower income from a settlement agreement and reversal of accrued refunds related with late-filed TSAs in 2017. See Note 8 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information related to late-filed TSAs;
•
$8 million in higher depreciation and amortization expenses; and
•
$7 million in higher operations and maintenance expense resulting primarily from an increase in maintenance expense related to planned generation outages in 2018 and an increase in employee wages and benefits expense.
2017 compared with 2016
TEP reported net income of $177 million in 2017 compared with $124 million in 2016. The increase of $53 million, or 43%, was primarily due to:
•
$52 million in higher retail revenue primarily due to an increase in rates as approved in the 2017 Rate Order that took effect February 27, 2017, and 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 8 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:
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$8 million in lower revenues related to the Springerville Unit 1 settlement in 2016. See Note 8 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 13 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;
•
$6 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.
Retail Revenues and Key Statistics
The following table provides key statistics impacting operating revenues:
Operating Revenues increased in 2018 compared with 2017 primarily due to: (i) an increase in short-term wholesale sales resulting from an increase in available system capacity related to Gila River Unit 2; (ii) an increase in revenue from fuel and purchased power recoveries as a result of higher PPFAC rates; and (iii) higher retail revenues related to an increase in rates as approved in the 2017 Rate Order that took effect February 27, 2017. The increase was partially offset by: (i) the return of savings related to the TCJA to customers; (ii) a 2017 reversal of an accrual related to the FERC ordered refunds for late-filed TSAs; and (iii) a decrease in billings to third-party participants in Springerville Units 3 and 4 primarily related to planned generation outages of Unit 4 in 2017.
Operating Revenues increased in 2017 compared with 2016 primarily due to: (i) higher retail 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; (ii) time-value FERC ordered refunds incurred in 2016 and the reversal of accrued refunds in 2017 related to late-filed TSAs; (iii) an increase in short-term wholesale sales resulting from favorable commodity pricing on the wholesale market; and (iv) a new long-term wholesale contract that commenced in 2017. The increase was partially offset by a decrease in revenue from fuel and purchased power recoveries as a result of lower PPFAC rates.
Short-term wholesale revenues are primarily related to the 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. Revenues related to Springerville Units 3 and 4 are primarily reimbursements by Tri-State, the lessee of Springerville Unit 3, and SRP, the owner of Springerville Unit 4, with the corresponding expense recorded in Operating Expenses on the Consolidated Statements of Income.
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.
Operating Expenses
Fuel and Purchased Power Expense
Fuel and Purchased Power Expense, which includes the PPFAC recovery treatment, increased by $118 million, or 28%, in 2018 compared with 2017 primarily due to an increase in: (i) generation output; (ii) recovery of PPFAC costs as a result of changes in the PPFAC rate; and (iii) the average cost of Purchased Power, Non-Renewables. The increase was partially offset by a decrease in: (i) Purchased Power, Non-Renewable volumes; and (ii) the average cost of Natural Gas.
Fuel and Purchased Power Expense, which includes the PPFAC recovery treatment, increased by $5 million, or 1%, in 2017 compared with 2016 primarily due to an increase in: (i) Purchased Power, Non-Renewables volumes that replaced lower Coal-Fired Generation output; and (ii) average fuel cost per kWh. The increase was partially offset by reduced recovery of the PPFAC costs as a result of changes in the PPFAC rate.
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.
The following table presents TEP's sources of energy and average cost of power by type:
Operations and Maintenance Expense
Operations and Maintenance Expense increased by $2 million, or less than 1%, in 2018 compared with 2017 primarily due to: (i) an increase in maintenance expense related to planned generation outages; (ii) an increase in employee wages and benefits expense; and (iii) a sales tax refund that occurred in 2017. The increase was partially offset by a decrease in: (i) maintenance expense at Springerville Units 3 and 4; (ii) RES and DSM program expenses; and (iii) other general expenses.
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 (ii) employee wages and benefits expense. The increase was partially offset by a decrease in RES and DSM program expenses.
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, with corresponding amounts recorded in Operating Revenues on the Consolidated Statements of Income. Expenses related to RES and DSM programs are collected from customers with corresponding amounts recorded in Operating Revenues on the Consolidated Statements of Income.
See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information on RES and DSM.
Depreciation and Amortization Expense
Depreciation and Amortization Expense increased by $9 million, or 5%, in 2018 compared with 2017 primarily due to an increase in asset base.
Depreciation and Amortization Expense increased by $7 million, or 4%, in 2017 compared with 2016 primarily due to an increase in capital expenditures and other impacts as a result of the 2017 Rate Order.
Other Income (Expense)
Other Income (Expense) decreased by $8 million, or 16%, in 2018 compared with 2017 primarily due to proceeds received from a settlement agreement related to late-filed TSAs in 2017.
Other Income (Expense) increased by $10 million, or 18%, in 2017 compared with 2016 primarily due to proceeds received from a settlement agreement related to late-filed TSAs in 2017.
See Note 8 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information related to late-filed TSAs.
Income Tax Expense
Income Tax Expense decreased by $58 million, or 57%, in 2018 compared with 2017 primarily due to: (i) the reduction of the federal corporate income tax rate related to the enactment of the TCJA; and (ii) a decrease in earnings before tax expense.
Income Tax Expense increased by $41 million, or 70%, in 2017 compared with 2016 primarily due to: (i) the increase in earnings before tax expense; (ii) the enactment of the TCJA in December 2017; and (iii) a reduction in the valuation allowance for deferred tax assets in 2016.
See Note 13 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.
FACTORS AFFECTING RESULTS OF OPERATIONS
Regulatory Matters
TEP is subject to comprehensive regulation. The discussion below contains material developments to those matters.
TEP Rate Case
Provisions of the 2017 Rate Order, which were effective February 27, 2017, include, but are not limited to:
•
a non-fuel base rate increase of $81.5 million, a cost of equity component of 9.75%, and a cost of debt component of 4.32%; and
•
adoption of TEP's proposed depreciation and amortization rates, which include a reduction in the depreciable life for San Juan Unit 1.
The ACC deferred matters related to net metering and rate design for new DG customers to Phase 2.
Phase 2 Order
On September 20, 2018, the ACC issued an order related to the Phase 2 proceedings. The Phase 2 Order established, among other things, an export rate that replaced net metering for excess solar generation. Residential and small commercial customers who applied to interconnect their solar generating systems to TEP's distribution system after the date of the order no longer qualify for net metering. Customers who applied before the date of the order, and complete interconnection within a specified
time frame, were grandfathered under previous net metering rules for a period of 20 years from the date of interconnection of their solar generation systems. Provisions of the Phase 2 Order for new DG customers include:
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an option to select from existing Time-of-Use rate schedules;
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a monthly bill credit for customer solar generation exported to TEP's grid calculated using an export rate approved by the ACC; and
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an annual update to the export rate based on TEP's actual solar PPA and generation facilities costs, which are expected to decline. The export rate at the time of customers' applications to interconnect will be locked for 10 years. The initial export rate was set at 9.64 cents per kWh.
The new DG customers will receive bill credits for their solar generation exported into our grid. These bill credits will be calculated using the export rate approved by the ACC and will be recorded in Purchased Power on the Consolidated Statements of Income. We expect to recover these costs through the PPFAC up to an amount equal to market prices with any remaining cost being recovered through the RES surcharge. In addition, TEP's power sales to the new DG customers will be calculated based on the respective Time-of-Use rate and will be recorded in Operating Revenues on the Consolidated Statements of Income. DG customers grandfathered under the net metering rules will continue to have their solar generation netted against the kWhs they consume. The net sales are recorded in Operating Revenues on the Consolidated Statements of Income.
TEP does not expect the change resulting from the replacement of net metering to have a material impact on the Company's results of operations in the near term. See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding the Phase 2 Order.
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 the ACC Refund Order effective May 1, 2018. The refund represents the reduction in the federal corporate income tax rate and an estimate of Excess Deferred Income Taxes (EDIT) amortization trued up annually for actuals. For 2018, the refund amount, after the EDIT amortization true-up, totaled $33 million. The 2018 bill credit was designed to return the refund amount to customers based on forecasted kWh sales. Any over or under collected amounts are deferred to a regulatory asset or liability and will be used to adjust the 2019 bill credit amounts.
Customer bill credits are trued-up annually to reflect actuals for kWh sales and EDIT amortization. TEP filed an application with the ACC to establish the 2019 customer refund of $34 million. The refund will be returned to customers through a combination of a customer bill credit and a regulatory liability in 2019. TEP is allowed to defer 25% of the 2019 refund into a regulatory liability and 50% of any additional refunds in future years until the refunds are incorporated into its next rate case. TEP plans to file its next rate case in April 2019.
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 requirements 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 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 Notice of Proposed Rulemaking (NOPR) regarding the effect of the TCJA and related EDIT amortization. TEP cannot predict the final outcome of the NOPR or the impact on TEP's 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 the FERC Refund Order and the NOPR.
Generation Resources
TEP’s long-term strategy is to shift to a more diverse, sustainable energy portfolio including expanding renewable energy and natural gas-fired resources while reducing reliance on coal-fired generation 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, 2018, approximately 40% of our generation capacity, including owned and leased resources, 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 Policy
In August 2018, the ACC opened a rulemaking docket to evaluate several energy policies. The docket will review possible modifications to existing renewable energy, energy efficiency requirements, and retail competition for generation services. The adoption of new policies would be subject to rulemaking proceedings at the ACC. We would seek the ACC's approval to recover any costs related to any new energy policies or requirements. TEP cannot predict the outcome of this matter 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 December 2019 and begin decommissioning activities thereafter. We are currently recovering Navajo capital and operating costs in base rates using a useful life through 2030. We plan to seek recovery of all unrecovered costs in our next ACC rate case, which is expected to be filed in April 2019.
See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K, for additional information regarding the planned early retirement of Navajo.
Sundt Generating Station
In 2017, TEP submitted an Air Quality Permit Application to the Pima County Department of Environmental Quality related to a generation modernization project at Sundt (PDEQ Application). Under the project, TEP will place in service 10 natural gas RICE units with a total nominal generation capacity of 190 MW. The final permit was issued in December 2018. Construction is underway with the RICE units scheduled for commercial operation by the end of the first quarter of 2020.
The RICE units will balance the variability of intermittent renewable energy resources and will replace 162 MW of nominal net generation capacity from Sundt Units 1 and 2, which are less efficient and lack the quick start, fast ramp capabilities of the RICE units. TEP will discontinue operation of Sundt Units 1 and 2 prior to start-up of the first RICE unit. We plan to seek recovery of all unrecovered costs for Sundt Units 1 and 2 in our next ACC rate case.
See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K, for additional information regarding the planned early retirement of Sundt Units 1 and 2.
Gila River Generating Station
In 2017, TEP entered into the Tolling PPA, which includes a three-year option to purchase Gila River Unit 2. TEP’s obligations under the agreement were contingent upon SRP's completion of acquisition of Gila River Units 1 and 2 from third-parties (Gila Acquisition). SRP completed the Gila Acquisition in May 2018. As a result, TEP had $164 million recorded in both Capital Lease Obligations and Utility Plant Under Capital Leases on the Consolidated Balance Sheets as of December 31, 2018. The amount reflects the fair value of the unit, which was determined based on SRP's purchase price. TEP anticipates exercising its option to purchase Gila River Unit 2 in December 2019 for approximately $164 million. Over the expected 20-month lease term, TEP will pay a monthly demand charge consisting of: (i) a fixed capacity charge of approximately $1 million, and (ii) an operating fee to compensate SRP for the non-fuel costs of operating Gila River Unit 2. TEP recovers the monthly capacity charge and operating fee through the PPFAC.
The additional 550 MW of capacity, power, and ancillary services from the Tolling PPA will allow us to continue to move toward our long-term goal of resource diversification as it will replace coal-fired generation scheduled for early retirement. TEP sells the capacity from the Tolling PPA into the wholesale market on a short-term basis with the associated revenues credited to the PPFAC.
See Note 7 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K, for additional information regarding the Tolling PPA.
Interest Rates
See Part II, Item 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
TEP’s financial statements are exposed to certain market risks that can affect 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 Committee 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 Committee 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 Committee reviews counterparty credit exposure as well as credit policies and 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 has $14 million of variable rate debt outstanding related to the Springerville Common Facilities capital lease obligation as of December 31, 2018. TEP has a 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 $12 million as of December 31, 2018.
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 (loss), TEP recorded the following net unrealized gains:
Credit Facilities
TEP is subject to interest rate risk resulting from changes in interest rates on borrowings under its credit agreement. The interest rate paid on borrowings is variable. Revolving credit borrowings are made on either the basis of a spread over LIBOR or an Alternate Base Rate (ABR). As a result, TEP may experience significant volatility in the rates paid on LIBOR borrowings under its revolving credit facilities.
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 generating facilities represent substantial underlying commodity positions. Exposure to commodity prices consist primarily of variations in the price of fuel required to generate electricity that is purchased and sold in the 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, generating facility availability, customer usage, storage, and transmission and transportation constraints. Under the guidance of the Risk Management Committee, TEP mitigates a portion of its commodity price risk through the use of commodity contracts, which include forwards, options, 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 by the ACC. See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8
ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Report of Independent Registered Public Accounting Firm
To the Stockholder and the Board of Directors of
Tucson Electric Power Company
Tucson, Arizona
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Tucson Electric Power Company and subsidiaries (the "Company") as of December 31, 2018 and 2017, 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, 2018, 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, 2018 and 2017, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2018, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
We have served as the Company's auditor since 2017.
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 statements of income, comprehensive income, changes in stockholder’s equity and cash flows of Tucson Electric Power Company for the year 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 audit.
We conducted our audit 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 audit 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 audit provided a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated results of operations and cash flows of Tucson Electric Power Company for the year ended December 31, 2016, in conformity with U.S. generally accepted accounting principles.
TUCSON ELECTRIC POWER COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(Amounts in thousands)
The accompanying notes are an integral part of these financial statements.
TUCSON ELECTRIC POWER COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Amounts in thousands)
The accompanying notes are an integral part of these financial statements.
TUCSON ELECTRIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in thousands)
The accompanying notes are an integral part of these financial statements.
TUCSON ELECTRIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Amounts in thousands, except share data)
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)
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)
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 425,000 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's proportionate share of jointly-owned facilities is recorded in Utility Plant on the Consolidated Balance Sheets, and its proportionate share of the 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. Most notably, TEP combined captions on the Consolidated Statements of Income by reclassifying similar line items into a single line item as follows:
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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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), and if it is the primary beneficiary of the VIE. The primary beneficiary is required to consolidate the VIE when the variable interest holder 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 enters 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 the 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, 2018, the carrying amount of assets and liabilities in the balance sheet that relates to variable interests under long-term PPAs is predominantly related to working capital accounts and generally represents 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 cost recovery mechanisms. See Note 2 for additional information related to cost recovery mechanisms.
NEW ACCOUNTING STANDARDS ISSUED AND ADOPTED
The following new authoritative accounting guidance issued by the Financial Accounting Standards Board (FASB) has been adopted as of January 1, 2018. 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.
Revenue from Contracts with Customers
TEP adopted accounting guidance that requires recognition of revenue when a customer obtains control of promised goods or services in an amount that reflects the consideration to which the company expects to be entitled. The Company continues to recognize revenue for tariff-based sales to retail and wholesale customers, which represent TEP’s primary source of revenue, as power is delivered. TEP adopted the new guidance using the modified retrospective approach. There was no adjustment identified or recorded to the opening balance of retained earnings on adoption. The Company applied the new revenue guidance to contracts with customers that were not completed at the date of initial application, January 1, 2018. The new guidance requires disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. See Note 4 for additional disclosure related to TEP's operating revenues.
Compensation-Retirement Benefits
TEP adopted accounting guidance that requires an employer to disaggregate the service cost component from the other components of net periodic benefit cost. TEP no longer capitalizes the non-service cost components of net periodic benefit cost as part of inventory or plant in service and presents non-service costs in Other, Net on the Consolidated Statements of Income.
Derivatives and Hedging
TEP early adopted accounting guidance that simplifies the application of hedge accounting through changes to both the designation and measurement guidance and is intended to enable the Company to better portray the economics of its risk management activities in its financial statements.
Reclassification of Certain Tax Effects
TEP early adopted accounting guidance that permits reclassification of certain tax effects resulting from the TCJA from AOCI to retained earnings. TEP applied the guidance as of the beginning of the period of adoption. On adoption, TEP recorded a one-time reclassification of $1 million from Accumulated Other Comprehensive Loss to Retained Earnings on the Consolidated
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Balance Sheets as a result of income tax effects due to the reduction in the U.S. federal statutory tax rate. See Note 13 for additional disclosure related to the TCJA.
NEW ACCOUNTING STANDARDS ISSUED AND NOT YET ADOPTED
The following new authoritative accounting guidance issued by the FASB has not yet been adopted and reflected in TEP’s financial statements as of December 31, 2018. Unless otherwise indicated, TEP is currently assessing the impacts such guidance may have (which could be material) on TEP’s financial position, results of operations, cash flows, and disclosures, as well as the potential to early adopt where applicable. Updates not listed below were assessed and either determined to not be applicable or are expected to have an insignificant impact on TEP’s financial position, results of operations, cash flows, and disclosures.
Leases
In February 2016, the FASB issued an ASU that requires lessees to recognize a lease liability, initially measured at the present value of future lease payments, and a 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. The standard was effective for periods beginning January 1, 2019, and may be applied retrospectively to each prior period presented or retrospectively with the cumulative effect recognized as an adjustment to retained earnings as of the date of initial application. TEP adopted this ASU on January 1, 2019, applied the transition provisions of the new standard as of the adoption date, and will not retrospectively adjust prior periods.
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. In addition, TEP elected a practical expedient that permitted entities to not evaluate existing land easements that were not previously accounted for as leases. The new lease guidance will be applied on a prospective basis to all new or modified land easements after January 1, 2019. Finally, TEP utilized the hindsight practical expedient in transition to determine the lease term.
TEP’s leasing activities accounted for as operating leases primarily relate to rail cars, land, and communication towers. Adoption of the ASU resulted in recognition of additional right-of-use assets and lease liabilities of approximately $8 million. The Company does not expect the new ASU to affect its results of operations or cash flows.
During the implementation process, TEP planned modifications to its processes and control activities related to gathering contracts and contract review requirements associated with accounting for leases.
Internal-Use Software
In August 2018, the FASB issued an ASU that clarifies accounting for implementation costs incurred in a cloud computing arrangement that is a service contract. Under the new guidance, customers apply the same criteria for capitalizing implementation costs as they would for an arrangement that has a software license. The ASU also provides specific requirements for the classification and presentation of the capitalized implementation costs and the related amortization of those costs. The standard is effective for periods beginning January 1, 2020, and should be applied either retrospectively or prospectively after the date of adoption. TEP early adopted this ASU prospectively effective January 1, 2019.
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 management'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 as a result of environmental 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
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 the lease. TEP primarily defers the accretion and depreciation expense associated with its legal AROs into a regulatory asset 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.
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 regarding 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 on the balance sheet and reconciles their sum to the cash flow statement:
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. Restricted cash included in Current Assets-Other represents 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:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 8 for additional information regarding the settlement of the Third-Party Owners' claims.
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 AFUDC, less contributions in aid of construction.
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 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 in Allowance For Borrowed Funds on the Consolidated Statements of Income. The capitalized cost for equity funds is recorded in Allowance For Equity Funds on the Consolidated Statements of Income.
The average AFUDC rates on regulated construction expenditures are included in the table below:
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:
Utility Plant Under Capital Leases
TEP finances a portion of the Springerville Common Facilities with capital leases. In addition, TEP has a Tolling PPA related to Gila River Unit 2 that is accounted for as a capital lease. Capital lease expense related to Gila River Unit 2 is recorded in Purchased Energy on the Consolidated Statements of Income. Capital lease expense related to Springerville Common Facilities is recorded in Amortization Expense and Interest Expense on the Consolidated Statements of Income. See Note 3 for additional information regarding utility plant and Note 7 for additional information related to the terms of these transactions.
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. If the associated software is no longer useful or impaired, the carrying value is reduced and recorded as an expense on the income statement.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
EVALUATION OF ASSETS FOR IMPAIRMENT
Long-lived assets and investments are evaluated for impairment whenever events or changes in circumstances indicate that an asset’s carrying amount may not be recoverable. If estimated future undiscounted cash flows are less than the carrying amount, the Company estimates the fair value and records an impairment for the amount 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 useful 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 subject to re-evaluation and can change over time.
DEFERRED FINANCING COSTS
Costs 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.
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.
OPERATING REVENUES
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 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 electric meters on a systematic basis throughout the month. In general, TEP's contracts have payment terms of 10 to 20 days from the date the bill is rendered. TEP considers any payment not received by the due date delinquent and charges the customer a late payment fee. No component of the 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's variable consideration includes revenues that are subject to refund. 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 variable consideration in the transaction price to the extent it is probable that changes in its estimate will not result in significant reversals of revenue in subsequent periods. See Note 4 for the disaggregation of TEP's 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 are partially recovered through the LFCR mechanism.
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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 Operating 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.
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. See Note 2 for additional information regarding regulatory matters. The table below does not include PBI activity and summarizes the balance of TEP's RECs which are included in Regulatory and Other Assets-Other on the Consolidated Balance Sheets:
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 on 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 Interest Expense on the Consolidated Statements of Income.
TEP accounts for federal energy credits generated prior to 2012 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. Federal energy credits generated since 2012 are deferred as regulatory liabilities and amortized as a reduction in income tax expense over the tax life of the underlying asset. 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. TEP had $6 million and $7 million in federal energy credits as of December 31, 2018 and 2017, respectively. 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 obligation for the pension plans. TEP recognizes a regulatory asset to the extent these future costs are probable of recovery in 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 9 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 12 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, to: (i) meet forecasted load and reserve requirements; (ii) reduce exposure to energy commodity price volatility; and (iii) hedge interest rate risk exposure. Derivative instruments that do not meet the normal purchase or normal sale scope exception are recognized as either assets or liabilities on 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 on the income statement.
For derivatives designated as hedging contracts, TEP formally assesses, at inception, 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 12 for additional information regarding derivative instruments.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
NOTE 2. REGULATORY MATTERS
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 the Company's business decisions and accounting practices. The FERC regulates terms and prices of transmission services and wholesale electricity sales.
TEP RATE CASE
Provisions of the 2017 Rate Order, which were effective February 27, 2017, included, but are not limited to:
•
a non-fuel base rate increase of $81.5 million; and
•
adoption of TEP's proposed depreciation and amortization rates, which included a reduction in the depreciable life for San Juan Unit 1.
The ACC deferred matters related to net metering and rate design for new DG customers to a second phase of TEP's rate case (Phase 2).
Phase 2 Order
On September 20, 2018, the ACC issued an order related to Phase 2 proceedings. The Phase 2 Order established, among other things, an export rate that replaced net metering. Residential and small commercial customers who apply to interconnect their solar generation systems to TEP's distribution system after the date of the order will no longer qualify for net metering. Customers who applied before the date of the order, and complete interconnection within a specified time frame, were grandfathered under previous net metering rules for a period of 20 years from the date of interconnection of their solar generation system.
Provisions of the Phase 2 Order for new DG customers include:
•
an option to select from existing Time-of-Use rate schedules;
•
a monthly bill credit for customer excess solar generation exported to TEP's grid calculated using an export rate approved by the ACC; and
•
an annual update to the export rate based on TEP's actual solar PPA and generation facilities costs, which are expected to decline. The export rate at the time of customers' applications to interconnect will be locked for 10 years. The initial export rate was set at 9.64 cents per kWh.
FEDERAL 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 the ACC Refund Order effective May 1, 2018. The refund represents the reduction in the federal corporate income tax rate and an estimate of EDIT amortization trued up annually for actuals. The refund amount, after the EDIT amortization true-up, totaled $33 million. The 2018 bill credit was designed to return the refund amount to customers based on forecasted kWh sales for the calendar year 2018. Any over or under collected amounts are deferred to a regulatory liability or asset and will be used to adjust the 2019 bill credit amounts.
The table below summarizes the regulatory asset (liability) balance related to the ACC Refund Order:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Customer bill credits are trued-up annually to reflect actuals for kWh sales and EDIT amortization. TEP filed an application with the ACC to establish the 2019 customer refund of $34 million. The refund will be returned to customers through a combination of a customer bill credit and a regulatory liability in 2019.
See Note 13 for additional information regarding the TCJA.
Federal Energy Regulatory Commission
In 2018, the FERC issued the FERC Refund Order. TEP submitted a proposal for an overall transmission rate reduction of approximately 5.3%, reflecting the lower federal tax rate, effective March 21, 2018 which was approved by the FERC. As a result, TEP recognized a reduction in Operating Revenues on the Consolidated Statements of Income of $1 million in 2018.
In addition, the FERC issued a NOPR regarding the effect of the TCJA and related EDIT amortization. TEP cannot predict the final outcome of the NOPR or the impact on TEP's financial statements.
See Note 13 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 for the subsequent 12-month period unless 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 table below summarizes the PPFAC regulatory asset (liability) balance:
(1)
The ACC approved a PPFAC credit to begin returning the over-collected PPFAC balance to customers for the period of March 2017 through April 2018.
Environmental Compliance Adjustor
The Environmental Compliance Adjustor (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 $3 million in 2018 and $1 million in both 2017 and 2016 related to the return on company-owned environmental investments included in Operating Revenues on the Consolidated Statements of Income.
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 are required to file an annual RES implementation plan for review and approval by the ACC.
In January 2018, the ACC approved TEP's 2018 RES implementation plan with a budget amount of $54 million. The recovery funds the following: (i) the above market cost of renewable power purchases; (ii) previously awarded incentives for customer-installed DG; and (iii) various other program costs. In 2018, TEP recognized $1 million of revenue 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
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
and plans to request recovery of these types of costs through its rate case process. As part of the Phase 2 Order, the ACC approved a separate residential community solar program for TEP.
In July 2018, TEP submitted its application for approval of the 2019 RES implementation plan with a budget amount of $55 million. The Company cannot predict when the ACC will consider its 2019 RES implementation plan.
In 2018, the percentage of TEP's retail kWh sales attributable to the RES was approximately 14%, exceeding the overall 2018 RES requirement of 8%. The ACC approved a waiver of the 2018 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 December 31, 2018, TEP’s cumulative annual energy savings were approximately 16%.
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 each of 2018, 2017, and 2016 related to the performance incentive in Operating Revenues on the Consolidated Statements of Income.
TEP is currently operating under the ACC approved 2016 energy efficiency implementation plan. On February 6, 2019, the ACC approved TEP’s 2018 energy efficiency implementation plan with a budget of approximately $23 million, which will be collected through the DSM surcharge.
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 cap of 2% of TEP's applicable retail revenues, as approved in the 2017 Rate Order.
TEP recorded regulatory assets and recognized LFCR revenues of $26 million in 2018, $22 million in 2017, and $18 million in 2016. LFCR revenues are included in Operating Revenues on the Consolidated Statements of Income.
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:
(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, 2018, 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 13 for additional information regarding income taxes.
(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)
Property taxes are recorded 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)
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)
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.
(7)
Represents federal energy credits generated after 2011 that are amortized over the tax life of the underlying asset.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 related to the EDIT balances, 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 8 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:
(1)
Primarily represents computer software. Unamortized computer software costs were $73 million and $59 million as of December 31, 2018 and 2017, respectively. The amortization of computer software costs was $24 million in 2018, $19 million in 2017, and $17 million in 2016. 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) million as of December 31, 2018 and 2017.
(3)
In May 2018, TEP recorded capital lease obligations related to the Tolling PPA. See Note 7 for additional information regarding the Tolling PPA and Springerville leases.
(4)
Represents a composite of the depreciation rates of assets within each major class of utility plant and is based on the 2015 depreciation study available for the major classes of Plant in Service. TEP implemented new depreciation rates effective March 1, 2017, as approved in the 2017 Rate Order.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Utility Plant Under Capital Leases
All assets included in Utility Plant Under Capital Leases are used in generation operations and amortized over the primary lease term. The following table shows the amount of lease expense incurred for capital leases:
Springerville Acquisition
In December 2017, TEP purchased an undivided interest in the Springerville Common Facilities. As of December 31, 2018, Utility Plant Under Capital Leases represented 32.2% undivided interests in certain Springerville Common Facilities. See Note 7 for additional information regarding the Springerville capital lease purchases.
JOINTLY-OWNED FACILITIES
As of December 31, 2018, TEP was a participant in the following jointly-owned generation facilities and transmission systems:
(1)
TEP also has a 7.5% ownership interest in Navajo. Navajo's NBV is classified as a regulatory asset. See Note 2 for additional information related to Navajo's NBV.
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
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. See Note 2 for additional information related to the planned early retirement of Navajo.
Sundt Generating Station
In 2018, TEP's PDEQ Application was approved. Under the project outlined in the PDEQ Application, TEP will place in service 10 natural gas RICE units with a total nominal generation capacity of 190 MW. The RICE units are scheduled for commercial operation by the end of the first quarter of 2020.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Consistent with the approved PDEQ Application, TEP plans to early retire Sundt Units 1 and 2 prior to start-up of the first RICE unit. 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.
ASSET RETIREMENT OBLIGATIONS
The 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:
(1)
Primarily related to closure of the ash landfill at Springerville.
(2)
Primarily related to changes in expected cost estimates for certain generation facilities.
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. As of December 31, 2018, TEP's variable consideration included revenues that are subject to refund.
DISAGGREGATION OF REVENUES
The following table presents the disaggregation of TEP’s Operating Revenues on the Consolidated Statements of Income by type of service:
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. Once the usage is estimated, TEP applies the anticipated rate and records revenue. Unbilled revenues 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
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
cash collections results in billed and unbilled accounts receivable balances on the balance sheet. See Note 5 for components of Accounts Receivable, Net on the Consolidated Balance Sheets.
In January 2018, TEP began to recognize a provision for revenues subject to refund, which reduced operating revenues, and a current regulatory liability for savings expected to be returned to customers from the Company’s federal income tax reduction under the TCJA. In April 2018, the ACC approved the ACC Refund Order effective May 1, 2018. As a result of the ACC Refund Order, the Company returned savings to customers through a bill credit. See Note 2 for more information regarding the ACC Refund Order.
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 March 2018, the FERC issued the FERC Refund Order. In May 2018, TEP responded to the FERC Refund Order and proposed an overall transmission rate reduction. As a result, TEP began accruing a current regulatory liability and reduction in wholesale revenues. In November 2018, the FERC approved TEP's proposed revisions to its stated transmission rates. The related revenue subject to refund recorded did not have a material impact on TEP's financial position or results of operations. See Note 2 for more information regarding the FERC Refund Order.
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. As the operating agent for Springerville Units 3 and 4, TEP may be required to refund its monthly fee based on unit availability. 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 on the income statement based on the nature of services provided.
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 12 for information regarding derivative instruments.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
NOTE 5. ACCOUNTS RECEIVABLE
The following table presents the components of Accounts Receivable, Net on the Consolidated Balance Sheets:
(1)
Includes $8 million and $9 million as of December 31, 2018 and 2017, respectively, of receivables related to revenue from derivative instruments.
(2)
In 2018, Customer Accounts Receivable increased due to higher wholesale sales as a result of the increase in available system capacity related to Gila River Unit 2.
NOTE 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, UNS Energy Affiliates). These transactions include: (i) the sale and purchase of power and transmission services; (ii) common cost allocations; and (iii) the provision of corporate and other labor 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:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table presents the components of related party transactions included in the Consolidated Statements of Income:
(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 approved rates through the applicable Open Access Transmission Tariff.
(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% 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 $5 million in 2018 and $6 million in 2017 and 2016.
(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 one of TEP's generation facilities.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
NOTE 7. DEBT, CREDIT FACILITY, AND CAPITAL LEASE OBLIGATIONS
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:
(1)
Variable rate debt for which rates were reset monthly. The weighted average interest rate was calculated based on a percentage of an index equal to one-month LIBOR plus a credit spread. The interest rate for 2018 was calculated through the redemption date.
(2)
Variable rate debt for which rates were reset weekly. The weighted average interest rate was calculated using a weighted average and includes LOC fees and remarketing fees. The interest rate for 2018 was calculated through the redemption date.
(3)
As of December 31, 2018, all of TEP's debt is unsecured.
Debt Issuances and Redemptions
Fixed Rate Debt
In November 2018, TEP issued and sold $300 million aggregate principal amount of senior unsecured notes. TEP may redeem the notes prior to June 1, 2048, with a make-whole premium plus accrued interest. On or after June 1, 2048, TEP may redeem the notes at par plus accrued interest.
Variable Rate Debt
In December 2018, TEP redeemed at par a series of variable rate tax-exempt bonds with an aggregate principal amount of $37 million prior to the maturity of the bonds. The bonds were backed by an LOC issued pursuant to the 2010 Reimbursement Agreement which was scheduled to expire in February 2019. In connection with the redemption of the related bonds, the $37 million LOC and the associated 2010 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
CREDIT FACILITY
TEP's unsecured credit agreement with a maturity date of October 2022 included in Current Liabilities on the Consolidated Balance Sheets consists of the following:
(1)
Interest rates and fees under the credit facility are based on a pricing grid tied to TEP's credit rating.
TEP expects that amounts borrowed under the credit agreement will be used for working capital and other general corporate purposes. TEP will issue LOCs from time to time to support energy procurement and hedging transactions. As of February 14, 2019, there was $250 million available under the revolving credit commitments and LOC facilities.
CAPITAL LEASE OBLIGATIONS
The following table details Capital Lease Obligations on the Consolidated Balance Sheets:
Gila River Unit 2
In 2017, TEP entered into the Tolling PPA agreement, which includes a three-year option to purchase Gila River Unit 2. TEP’s obligations under the agreement were contingent upon the Gila Acquisition, which SRP completed in May 2018. As a result, TEP recorded an increase to both capital lease obligations and utility plant. TEP anticipates exercising its option to purchase Gila River Unit 2 in December 2019 for approximately $164 million, the fair value of the unit as determined based on SRP's purchase price. Over the expected 20-month lease term, TEP will pay a monthly demand charge consisting of: (i) a fixed capacity charge of approximately $1 million, and (ii) an operating fee to compensate SRP for the non-fuel costs of operating Gila River Unit 2. TEP recovers the monthly demand charge through the PPFAC.
Utility Plant Under Capital Leases on the Consolidated Balance Sheets reflects a balance related to the Tolling PPA of $164 million as of December 31, 2018.
Springerville Unit 1 Capital Lease Purchase
In September 2016, TEP purchased an undivided interest in Springerville Unit 1 for $85 million, bringing its total ownership of the assets to 100% for a total generation capacity of 387 MW. See Note 8 for more information regarding the settlement agreement relating to Springerville Unit 1.
Springerville Common Facilities Leases
As of December 31, 2018, the Springerville Common Facilities Leases include two leases with initial terms ending January 2021 and fixed price purchase options totaling $68 million. Under the two leases, TEP has options to: (i) renew the leases for periods of two or more years at fair market value; or (ii) exercise the fixed price purchase options under these contracts. In addition, TEP entered into agreements with Tri-State, the lessee of Springerville Unit 3, and SRP, the owner of Springerville Unit 4, that contain the following conditions that become effective if the Common Facilities Leases are not renewed: (i) TEP will exercise the purchase options under these contracts; (ii) SRP will be obligated to buy a 14% undivided interest in the facilities; and (iii) Tri-State will be obligated to either: (a) buy a 14% undivided interest in the facilities; or (b) continue to make
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
payments to TEP for the use of these facilities. If renewed, Tri-State and SRP will each pay 14% of the new fair market value rent.
In December 2017, TEP purchased 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
TEP entered into an interest rate swap agreement in 2006 that hedges a portion of the floating interest rate risk associated with the Springerville Common Facilities lease debt. 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, 2018, consisted of a notional amount of $12 million on which interest was fixed by the swap and a notional amount of $2 million of debt that was not hedged. The applicable margin was 2.00% and 1.88% as of December 31, 2018 and 2017, respectively.
TEP recorded the interest rate swap as a cash flow hedge for financial reporting purposes. See Cash Flow Hedges in Note 12 for additional information.
DEBT MATURITIES
Long-term debt, including revolving credit facilities classified as long-term, and capital lease obligations mature on the following dates:
(1)
Total long-term debt excludes $11 million of related unamortized debt issuance costs and $3 million of unamortized original issue discount.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
NOTE 8. COMMITMENTS AND CONTINGENCIES
COMMITMENTS
As of December 31, 2018, TEP had the following unconditional, minimum purchase obligations and operating leases:
(1)
Primarily represents leases for land, rail cars, and communication towers with varying terms, provisions, and expiration dates through 2041. TEP's operating lease expense totaled $1 million in 2018 and 2017 and $2 million in 2016.
(2)
Land easements and rights-of-way have varying terms and provisions and reflect expiration dates through 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. PBI 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 2019 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.
In October 2018, Westmoreland Coal Company (WCC), the owner of San Juan Coal Company (SJCC), filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code. PNM, the operator of San Juan, has an existing Coal Supply Agreement (CSA) with WCC to supply coal to San Juan. TEP is not a party to the CSA, but has minimum purchase obligations under a joint participation agreement. WCC is expected to provide adequate liquidity to support continued operations at the San Juan Mine throughout the restructuring process. TEP believes it has adequate resource capacity to meet its near-term load obligations in the event WCC’s operations at the San Juan Mine are curtailed. TEP cannot currently predict the outcome of this matter or the long-term impacts on operations at San Juan.
TEP has firm transportation agreements with capacity sufficient to meet its load requirements. These agreements expire in various years between 2019 and 2040.
Purchased Power
TEP has contracts with utilities and other energy suppliers for purchased power to: (i) meet system load and energy requirements; (ii) replace generation from company-owned units under maintenance and during 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 second quarter of 2019. 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, 2018.
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 2019 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
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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.
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 and 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 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.
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) challenging several unrelated mining plan modification approvals, including two issued in 2008 related to SJCC 's San Juan Mine. The petition alleges various National Environmental Policy Act (NEPA) violations against the OSM, 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 to sever 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 OSM so the OSM may prepare a new environmental 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’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. In May 2018, the OSM released a draft EIS for public comment which was open through July 2018. TEP cannot currently predict the outcome of this matter or the range of its potential impact.
Mine Reclamation at Generation 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 $66 million upon expiration of the coal supply agreements, which expire between 2019 and 2031. The Consolidated Balance Sheets reflect a total liability related to mine reclamation of $36 million and $34 million as of December 31, 2018 and 2017, respectively.
Amounts recorded for final mine reclamation are subject to various assumptions, such as estimations of reclamation costs, the dates 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
TEP’s PPFAC allows the Company to pass through final mine reclamation costs, as a component of fuel costs, to retail customers. Therefore, TEP classifies these costs as a regulatory asset 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 to the coal suppliers.
FERC Compliance
In 2015 and 2016, TEP self-reported to the FERC Office of Enforcement (OE) that the Company had not timely filed certain FERC-jurisdictional agreements. In 2016, as a result of the FERC Refund Orders and ongoing discussions with the OE, TEP recorded a liability for the time-value refunds with a corresponding offset in revenues on its financial statements. In 2016, Operating Revenues on the Consolidated Statements of Income reflected a $22 million reduction in revenues, 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 January 2017, in accordance with the agreement, the counterparty paid TEP $8 million, which TEP recorded in Other Income on the Consolidated Statements of Income and dismissed the appeal with prejudice.
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 Operating Revenues on the Consolidated Statements of Income.
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 no 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, 2018, there have been no such payment defaults under any of the participation agreements. The Navajo participation agreement expires in 2019, San Juan in 2022, Four Corners in 2041, and Luna in 2046.
NOTE 9. EMPLOYEE BENEFIT PLANS
PENSION BENEFIT PLANS
TEP has three noncontributory, defined benefit pension plans. Benefits are based on years of service and average compensation. Two of the plans cover the majority of TEP's employees. The Company funds those plans by contributing at least the minimum amount required under 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.
TEP funds its other postretirement benefits for classified employees through a VEBA. TEP contributed $3 million in 2018 and 2017 and $2 million in 2016 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 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 on the balance sheet:
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, 2018 and 2017. The table below presents the status of all of TEP’s pension and other postretirement benefit plans. All plans had projected benefit obligations in excess of the fair value of plan assets for each period presented:
(1)
TEP expects to contribute $11 million to the pension plans in 2019.
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:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The accumulated benefit obligation aggregated for all pension plans was $402 million and $428 million as of December 31, 2018 and 2017, respectively. Two of the pension plans had accumulated benefit obligations in excess of plan assets as of both December 31, 2018 and December 31, 2017. The following table includes information for the pension plans with accumulated benefit obligations in excess of pension plan assets:
The Company measures service and interest costs by applying the specific spot rates along the yield curve to the plans' liability cash flows. Net periodic benefit plan cost includes the following components:
The non-service components of net periodic benefit cost are included in Other, Net on the Consolidated Statements of Income. Approximately 19% of the 2018 service cost and approximately 18% of the 2017 net periodic benefit cost was capitalized as a cost of construction.
The changes in plan assets and benefit obligations recognized as regulatory assets or in AOCI were as follows:
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 2019 includes the following:
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 the 25th 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:
The following table includes the weighted average assumptions used to determine net periodic benefit costs:
Healthcare cost trend rates are assumed to decrease gradually from next year to the year the ultimate rate is reached:
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:
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:
As of December 31, 2018, the fair value of VEBA trust assets was $17 million, of which $7 million were fixed income investments and $10 million were equities. As of December 31, 2017, the fair value of VEBA trust assets was $17 million, of which $6 million were fixed income investments and $11 million were equities. The VEBA trust assets are primarily Level 2 assets within the fair value hierarchy described below. There are no 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 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 no transfers in or out of Level 3.
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 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.
DEFINED CONTRIBUTION PLAN
TEP offers a defined contribution savings plan to all eligible employees. The plan meets the IRS required standards for 401(k) qualified 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 $7 million in 2018, $6 million in 2017, and $5 million in 2016.
NOTE 10. 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 (PSU) and time-based restricted share units (RSU) annually. Each PSU and RSU granted is valued based on one 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table represents PSUs and RSUs awarded by UNS Energy:
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 million as of December 31, 2018 and 2017.
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 $2 million in 2018, $4 million in 2017, and $2 million in 2016 based on its share of UNS Energy's compensation expense.
NOTE 11. SUPPLEMENTAL CASH FLOW INFORMATION
CASH TRANSACTIONS
(1)
TEP did not pay federal or state income taxes due to net operating loss carryforwards offsetting taxable income.
NON-CASH TRANSACTIONS
Other significant non-cash investing and financing activities that affected recognized assets and liabilities but did not result in cash receipts or payments were as follows:
(1)
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)
Represents an accrual for future cost of retirement net of salvage values that does not impact earnings. As approved in the 2017 TEP Rate Order, TEP implemented new depreciation reserves and rates effective March 1, 2018. See Note 2 for additional information.
NOTE 12. 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 on a recurring basis classified in their entirety based on the lowest level of input that is significant to the fair value measurement:
(1)
Cash Equivalents and Restricted Cash represent amounts held in money market funds, certificates of deposit, and insured cash sweep accounts 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) entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the Consolidated Balance Sheets.
(3)
The Interest Rate Swap is valued using an income valuation approach based on the 6-month LIBOR and is included in Derivative Instruments on the Consolidated Balance Sheets.
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.
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.
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 has an interest rate swap agreement that expires in January 2020. The after-tax unrealized gains and losses on cash flow hedge activities are reported in the statement of comprehensive income. The estimated loss expected to be reclassified to earnings within the next twelve months is not material to TEP's financial position or results of operations.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The table below presents realized losses recorded to Interest Expense as well as total Interest Expense on the Consolidated Statements of Income:
As of December 31, 2018, the total notional amount of the interest rate swap was $12 million.
Energy Derivative Contracts, Regulatory Recovery
TEP enters 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 are deferred as a regulatory asset or a regulatory liability. The table below presents the unrealized gains and losses recorded to a regulatory asset or a regulatory liability on the balance sheet:
Energy Derivative Contracts, No Regulatory Recovery
TEP enters into certain energy contracts that are considered derivatives but do not qualify for regulatory 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:
Derivative Volumes
As of December 31, 2018, TEP had energy contracts that will settle on various expiration dates through 2029. The following table presents volumes associated with the energy contracts:
Level 3 Fair Value Measurements
The following tables provide quantitative information regarding significant unobservable inputs in TEP’s Level 3 fair value measurements:
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
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
regulatory asset or regulatory liability, or as a component of other comprehensive income (loss), rather than in the income statement.
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:
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 measurements 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, LOC, 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 $41 million as of December 31, 2018, compared with $27 million as of December 31, 2017. As of December 31, 2018, TEP had no LOCs as credit enhancements with its counterparties. If the credit risk contingent features were triggered on December 31, 2018, TEP would have been required to post an additional $41 million of collateral of which $16 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. 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.
The use of different estimation methods and/or market assumptions may yield different estimated fair value amounts. The following table includes the face value and estimated fair value of TEP's long-term debt:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
NOTE 13. 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 2018 and 35% in 2017 and 2016 to pre-tax income due to the following:
Income Tax Expense included on the Consolidated Income Statement consists of the following:
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 federal corporate income tax rate from 35% to 21% effective for tax years beginning after 2017. In addition, the TCJA provided modifications to bonus depreciation rules and limitations on the deductibility of interest expense, both of which include carve-outs for regulated utilities.
As a result of the TCJA, the Company was required to revalue its deferred tax assets and liabilities at the new federal corporate income tax rate as of the date of enactment. 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 was established. TEP is amortizing the EDIT balance in accordance with applicable federal income tax laws, which require the amortization of a majority of the balance over the remaining life of the related plant.
In 2018, ACC Refund Orders were approved requiring TEP to share EDIT amortization of the ACC-jurisdictional assets with customers. The EDIT activity of $6 million was amortized from Regulatory Liabilities on the Consolidated Balance Sheets as of December 31, 2018. 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, 2018, TEP had a receivable of $13 million related to the AMT credit carryforwards in Current Assets-Other on the Consolidated Balance Sheets.
In 2018, the Company recorded $2 million of income tax expense related to the estimated impact of sequestration on future AMT credit refunds. In January 2019, the IRS revised its previously-issued guidance on this matter and announced that future
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
AMT credit refunds will no longer be subject to sequestration. As a result, the Company anticipates receiving additional AMT credit refunds of $2 million in future periods.
In August 2018, the IRS proposed regulations on bonus depreciation. Based on the proposed regulation, the Company adjusted its estimated provision for its 2017 tax year and the results of such adjustment did not have a material impact on TEP's financial position or results of operations. TEP's accounting for the income tax effects of the bonus depreciation provisions included in the TCJA has been completed as of December 31, 2018.
The significant components of deferred income tax assets and liabilities consist of the following:
TEP recorded no valuation allowance against credit and net operating loss carryforward deferred income tax assets as of December 31, 2018 and 2017. 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, 2018, TEP had the following carryforward amounts:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Uncertain Tax Positions
A reconciliation of the beginning and ending balances of unrecognized tax benefits follows:
Unrecognized tax benefits, if recognized, would reduce income tax expense by less than $1 million as of December 31, 2018 and 2017.
TEP recorded no interest expense during 2018 and 2017 related to uncertain tax positions. In addition, TEP had no interest payable and no penalties accrued as of December 31, 2018 and 2017.
TEP has been audited by the IRS through tax year 2010. TEP's 2011 to 2018 tax years are open for audit by federal and state tax agencies.
The balance in unrecognized tax benefits could change in the next 12 months as a result of the IRS audit, but the Company is unable to determine the amount of change.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Concluded)
NOTE 14. 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.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 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 - 15(e) or Rule 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 are effective as of December 31, 2018.
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, 2018. 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, 2018, 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, there has been no change in TEP’s internal control over financial reporting during the fourth quarter of 2018 that has materially affected, or is reasonably likely to materially affect, TEP’s internal control over financial reporting. During 2018, we designed modifications to our internal control over financial reporting related to gathering contracts and contract review requirements associated with accounting for leases.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10.
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.
ITEM 11. EXECUTIVE COMPENSATION
Information required by Item 11 is omitted pursuant to General Instruction I(2)(c) of Form 10-K.
ITEM 12.
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.
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.
ITEM 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
The Audit and Risk Committee has considered whether the provision of services to TEP by Deloitte & 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 for professional services:
Audit Fees includes fees for audit services for 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 in 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 the TCJA and valuation procedures in 2018 and ASC 606 Revenue Recognition in 2017.
Tax Fees includes fees for research and development services with respect to tax credits in 2017.
All Other Fees includes fees for consulting services with respect to regulatory filings in 2017.
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.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
ITEM 16. FORM 10-K SUMMARY
Not Applicable.
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 14, 2019
/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.