AMERICAN ELECTRIC POWER CO INC
ITEM 1. BUSINESS
GENERAL
Overview and Description of Material Subsidiaries
AEP was incorporated under the laws of the State of New York in 1906 and reorganized in 1925. It is a public utility holding company that owns, directly or indirectly, all of the outstanding common stock of its public utility subsidiaries and varying percentages of other subsidiaries.
The service areas of AEP’s public utility subsidiaries cover portions of the states of Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia. Transmission networks are interconnected with extensive distribution facilities in the territories served. The public utility subsidiaries of AEP have traditionally provided electric service, consisting of generation, transmission and distribution, on an integrated basis to their retail customers. Restructuring laws in Michigan, Ohio and the ERCOT area of Texas have caused AEP public utility subsidiaries in those states to unbundle previously integrated regulated rates for their retail customers. In Ohio, AEP’s regulated utility operates its distribution and transmission assets while its former generation assets are owned and operated by affiliates.
The member companies of the AEP System have contractual, financial and other business relationships with the other member companies, such as participation in the AEP System savings and retirement plans and tax returns, sales of electricity and transportation and handling of fuel. The companies of the AEP System also obtain certain accounting, administrative, information systems, engineering, financial, legal, maintenance and other services at cost from a common provider, AEPSC.
As of December 31, 2016, the subsidiaries of AEP had a total of 17,634 employees. Because it is a holding company rather than an operating company, AEP has no employees. The material subsidiaries of AEP are:
AEP Texas
Organized in Delaware in 1925, AEP Texas was formed by the merger of AEP Texas Central Company and AEP Texas North Company into AEP Utilities, Inc. on December 31, 2016. The merging parties retained their respective rate structures. Following the merger, AEP Utilities, Inc. changed its name to AEP Texas Inc. (AEP Texas). AEP Texas is engaged in the transmission and distribution of electric power to approximately 1,024,000 retail customers through REPs in west, central and southern Texas. As of December 31, 2016, AEP Texas had 1,500 employees. Among the principal industries served by AEP Texas are chemical and petroleum refining, chemicals and allied products, oil and natural gas extraction, food processing, metal refining, plastics and machinery equipment, agriculture and the manufacturing or processing of cotton seed products, oil products, precision and consumer metal products, meat products and gypsum products. The territory served by AEP Texas also includes several military installations and correctional facilities. AEP Texas is a member of ERCOT. AEP Texas is part of AEP’s Transmission and Distribution Utilities segment.
APCo
Organized in Virginia in 1926, APCo is engaged in the generation, transmission and distribution of electric power to approximately 957,000 retail customers in the southwestern portion of Virginia and southern West Virginia, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities and other market participants. APCo owns 6,640 MWs of generating capacity. APCo uses its generation to serve its retail and other customers. As of December 31, 2016, APCo had 1,845 employees. Among the principal industries served by APCo are paper, rubber, coal mining, textile mill products and stone, clay and glass products. APCo is a member of PJM. APCo is part of AEP’s Vertically Integrated Utilities segment.
I&M
Organized in Indiana in 1907, I&M is engaged in the generation, transmission and distribution of electric power to approximately 592,000 retail customers in northern and eastern Indiana and southwestern Michigan, and in supplying and marketing electric power at wholesale to other electric utility companies, rural electric cooperatives, municipalities and other market participants. I&M owns or leases 3,539 MWs of generating capacity, which it uses to serve its retail and other customers. As of December 31, 2016, I&M had 2,475 employees. Among the principal industries served are primary metals, transportation equipment, electrical and electronic machinery, fabricated metal products, rubber and chemicals and allied products, rubber products and transportation equipment. I&M is a member of PJM. I&M is part of AEP’s Vertically Integrated Utilities segment.
KPCo
Organized in Kentucky in 1919, KPCo is engaged in the generation, transmission and distribution of electric power to approximately 169,000 retail customers in eastern Kentucky, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities and other market participants. KPCo owns 1,060 MWs of generating capacity. KPCo uses its generation to serve its retail and other customers. As of December 31, 2016, KPCo had 550 employees. Among the principal industries served are petroleum refining, coal mining and chemical production. KPCo is a member of PJM. KPCo is part of AEP’s Vertically Integrated Utilities segment.
KGPCo
Organized in Virginia in 1917, KGPCo provides electric service to approximately 48,000 retail customers in Kingsport and eight neighboring communities in northeastern Tennessee. KGPCo does not own any generating facilities and is a member of PJM. It purchases electric power from APCo for distribution to its customers. As of December 31, 2016, KGPCo had 53 employees. KGPCo is part of AEP’s Vertically Integrated Utilities segment.
OPCo
Organized in Ohio in 1907 and re-incorporated in 1924, OPCo is engaged in the transmission and distribution of electric power to approximately 1,472,000 retail customers in Ohio. OPCo purchases energy and capacity at auction to serve generation service customers. As of December 31, 2016, OPCo had 1,582 employees. Among the principal industries served by OPCo are primary metals, chemicals and allied products, health services, electronic machinery, petroleum refining, and rubber and plastic products. OPCo is a member of PJM. OPCo is part of AEP’s Transmission and Distribution Utilities segment.
PSO
Organized in Oklahoma in 1913, PSO is engaged in the generation, transmission and distribution of electric power to approximately 548,000 retail customers in eastern and southwestern Oklahoma, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities, rural electric cooperatives and other market participants. PSO owns 3,940 MWs of generating capacity, which it uses to serve its retail and other customers. As of December 31, 2016, PSO had 1,110 employees. Among the principal industries served by PSO are paper manufacturing, natural gas and oil extraction, transportation, oil refining, health care and aerospace. PSO is a member of SPP. PSO is part of AEP’s Vertically Integrated Utilities segment.
SWEPCo
Organized in Delaware in 1912, SWEPCo is engaged in the generation, transmission and distribution of electric power to approximately 533,000 retail customers in northeastern and panhandle of Texas, northwestern Louisiana and western Arkansas and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities, rural electric cooperatives and other market participants. SWEPCo owns 5,225 MWs of generating capacity, which it uses to serve its retail and other customers. As of December 31, 2016, SWEPCo had 1,486 employees. Among the principal industries served by SWEPCo are natural gas and oil production, petroleum refining, manufacturing of pulp and paper, chemicals, food processing and metal refining. The territory served by SWEPCo also includes several military installations, colleges and universities. SWEPCo also owns and operates a lignite coal mining operation. SWEPCo is a member of SPP. SWEPCo is part of AEP’s Vertically Integrated Utilities segment.
WPCo
Organized in West Virginia in 1883 and reincorporated in 1911, WPCo provides electric service to approximately 41,000 retail customers in northern West Virginia. WPCo owns 780 MWs of generating capacity which it uses to serve its retail and other customers. WPCo is a member of PJM. As of December 31, 2016, WPCo had 57 employees. WPCo is part of AEP’s Vertically Integrated Utilities segment.
AEGCo
Organized in Ohio in 1982, AEGCo is an electric generating company. As of December 31, 2016 AEGCo owned 2,496 MWs of generating capacity. AEGCo sold a 1,186 MW natural gas-fired generating unit to an unaffiliated party in a transaction that closed in January 2017. As a result of the sale, AEGCo owns 1,310 MWs of generating capacity. AEGCo sells power at wholesale to I&M and KPCo. As of December 31, 2016, AEGCo had 66 employees. AEGCo is part of AEP’s Vertically Integrated Utilities segment.
AGR
Organized in Delaware in 2011, AGR is a competitive generation company that generates power and sells it into the market. AGR also engages in power trading activities. Pursuant to a Power Supply Agreement (PSA) between AGR and OPCo, AGR supplied capacity for OPCo’s switched and non-switched retail load for the period January 1, 2014 through May 31, 2015. As of December 31, 2016, AGR owned 6,875 MWs of generating capacity, with rights to an additional 1,186 MWs pursuant to a unit power agreement with AEGCo through 2017. AGR sold three generating units totaling 4,143 MWs to an unaffiliated party in a transaction that closed in January 2017. As a result of the sale, AGR owns 2,732 MWs of generating capacity. As of December 31, 2016, AGR had 842 employees (536 employees following the sale of generation). AGR is part of AEP’s Generation & Marketing segment.
AEPTHCo
Organized in Delaware in 2012, AEPTHCo is a holding company for AEP’s transmission operations joint ventures (Transmission Joint Ventures). AEPTHCo also owns AEPTCo, a holding company for the State Transcos. The State Transcos develop and own new transmission assets that are physically connected to the AEP System. Individual State Transcos (a) have obtained the approvals necessary to operate in Indiana, Kentucky, Michigan, Ohio, Oklahoma and West Virginia, subject to any applicable siting requirements, (b) are authorized to submit projects for commission approval in Virginia and (c) have been granted consent to enter into a joint license agreement that will support investment in Tennessee. The application for regulatory approval to operate in Louisiana is under consideration, while the application for regulatory approval to operate in Arkansas was denied. Neither AEPTCo nor its subsidiaries have any employees. Instead, AEPSC and certain AEP utility subsidiaries provide the services required by these entities. AEPTCo is part of the AEP Transmission Holdco segment.
Service Company Subsidiary
AEP also owns a service company subsidiary, AEPSC. AEPSC provides accounting, administrative, information systems, engineering, financial, legal, maintenance and other services at cost to AEP subsidiaries. The executive officers of AEP and certain of its public utility subsidiaries are employees of AEPSC. As of December 31, 2016, AEPSC had 5,805 employees.
The following table illustrates certain regulatory information with respect to the states in which the public utility subsidiaries of AEP operate:
(a)
Represents the percentage of public utility subsidiaries revenue from sales to retail customers to total public utility subsidiaries revenue for the year ended December 31, 2016.
(b)
Identifies the predominant authorized return on equity and may not include other, less significant, permitted recovery. Actual return on equity varies from authorized return on equity.
CLASSES OF SERVICE
The principal classes of service from which the public utility subsidiaries of AEP derive revenues and the amount of such revenues during the years ended December 31, 2016, 2015 and 2014 are as follows:
APCo
I&M
OPCo
PSO
SWEPCo
FINANCING
General
Companies within the AEP System generally use short-term debt to finance working capital needs. Short-term debt may also be used to finance acquisitions, construction and redemption or repurchase of outstanding securities until such needs can be financed with long-term debt. In recent history, short-term funding needs have been provided for by cash on hand and AEP’s commercial paper program. Funds are made available to subsidiaries under the AEP corporate borrowing program. Certain public utility subsidiaries of AEP also sell accounts receivable to provide liquidity. See Management’s Discussion and Analysis of Financial Condition and Results of Operations, included in the 2016 Annual Reports, under the heading entitled Financial Condition for additional information concerning short-term funding and access to bank lines of credit, commercial paper and capital markets.
AEP’s revolving credit agreements (which backstop the commercial paper program) include covenants and events of default typical for this type of facility, including a maximum debt/capital test. In addition, the acceleration of AEP’s payment obligations, or the obligations of certain of its major subsidiaries, prior to maturity under any other agreement or instrument relating to debt outstanding in excess of $50 million, would cause an event of default under these credit agreements. As of December 31, 2016, AEP was in compliance with its debt covenants. With the exception of a voluntary bankruptcy or insolvency, any event of default has either or both a cure period or notice requirement before
termination of the agreements. A voluntary bankruptcy or insolvency of AEP or one of its significant subsidiaries would be considered an immediate termination event. See Management’s Discussion and Analysis of Financial Condition and Results of Operations, included in the 2016 Annual Reports, under the heading entitled Financial Condition for additional information with respect to AEP’s credit agreements.
AEP’s subsidiaries have also utilized, and expect to continue to utilize, additional financing arrangements, such as securitization financings and leasing arrangements, including the leasing of coal transportation equipment and facilities.
ENVIRONMENTAL AND OTHER MATTERS
General
AEP subsidiaries are currently subject to regulation by federal, state and local authorities with regard to air and water-quality control and other environmental matters, and are subject to zoning and other regulation by local authorities. The environmental issues that management believes are potentially material to the AEP System are outlined below.
Clean Water Act Requirements
Operations for AEP subsidiaries are subject to the Federal Clean Water Act, which prohibits the discharge of pollutants into waters of the United States except pursuant to appropriate permits, and regulates systems that withdraw surface water for use in power plants. In 2014, the Federal EPA issued a final rule setting forth standards for existing power plants that is intended to reduce mortality of aquatic organisms pinned against a plant’s cooling water intake screen (impingement) or entrained in the cooling water. The standards affect all plants withdrawing more than two million gallons of cooling water per day and establish specific intake design and intake velocity standards meant to allow fish to avoid or escape impingement. Compliance with this standard is required within eight years of the effective date of the final rule. The standard for entrainment for existing facilities requires a site-specific evaluation of the available measures for reducing entrainment. Challenges to this final rule have been consolidated in the U.S. Court of Appeals for the Second Circuit, and additional changes could be made to this rule as a result of review by the court.
In November 2015, the Federal EPA issued a final rule to update the technology-based standards that govern discharges from new and existing power plants under the Clean Water Act’s National Pollutant Discharge Elimination System program. For additional information, see Management’s Discussion and Analysis of Financial Condition and Results of Operations under the headings entitled Environmental Issues.
Coal Ash Regulation
AEP’s operations produce a number of different coal combustion products, including fly ash, bottom ash, gypsum and other materials. Effective October 2015, the Federal EPA adopted a rule to regulate the disposal and beneficial re-use of coal combustion residuals, including fly ash and bottom ash generated at coal-fired electric generating units. The final rule requires certain standards for location, groundwater monitoring and dam stability to be met at landfills and certain surface impoundments at operating facilities on a schedule spanning approximately four years after publication of the final rule in the Federal Register. If existing disposal facilities cannot meet these standards, they will be required to close, but the time frame for closure may be extended if adequate alternative disposal options are not available. For additional information regarding the Federal EPA action taken to regulate the disposal and beneficial re-use of coal combustion residuals and the potential impact on operations, see Management’s Discussion and Analysis of Financial Condition and Results of Operations under the headings entitled Environmental Issues-Coal Combustion Residual Rule.
Clean Air Act Requirements
The CAA establishes a comprehensive program to protect and improve the nation’s air quality and control mobile and stationary sources of air emissions. The major CAA programs affecting AEP’s power plants are described below. The states implement and administer many of these programs and could impose additional or more stringent requirements.
AEP has made significant long-term investments in environmental controls to reduce air emissions from its power plants. Between 2000 and 2016, AEP invested approximately $8.5 billion in environmental controls, primarily related to CAA, that have significantly reduced emissions. From 2001 and including projections through 2017, AEP expects its emissions of mercury will be lower by approximately 8,300 pounds, a reduction of approximately 87%. Since 1990 and including projections through 2017, AEP expects its emissions of SO2 and NOx will be lower by approximately 1,460,000 tons and 560,000 tons, respectively, a reduction of approximately 94% and 89%, respectively.
The Acid Rain Program
The 1990 Amendments to the CAA include a cap-and-trade emission reduction program for SO2 emissions from power plants. By 2000, the program established a nationwide cap on power plant SO2 emissions of 8.9 million tons per year and required further reductions in 2010. The 1990 Amendments also contain requirements for power plants to reduce NOx emissions through the use of available combustion controls.
The success of the SO2 cap-and-trade program encouraged the Federal EPA and the states to use it as a model for other emission reduction programs. AEP continues to meet its obligations under the Acid Rain Program through the installation of controls, use of alternate fuels and participation in the emissions allowance markets. Subsequent programs developed by the Federal EPA have imposed more stringent SO2 and NOx emission reduction requirements than the Acid Rain Program on many AEP facilities. Additional controls and other actions have been taken to achieve compliance with these programs at these facilities.
National Ambient Air Quality Standards
The CAA requires the Federal EPA to review the available scientific data for criteria pollutants periodically and establish a concentration level in the ambient air for those substances that is adequate to protect the public health and welfare with an extra safety margin. The Federal EPA also can list additional pollutants and develop concentration levels for them. These concentration levels are known as national ambient air quality standards (NAAQS).
Each state identifies the areas within its boundaries that meet the NAAQS (attainment areas) and those that do not (nonattainment areas). Each state must develop a state implementation plan (SIP) to bring nonattainment areas into compliance with the NAAQS and maintain good air quality in attainment areas. All SIPs are submitted to the Federal EPA for approval. If a state fails to develop adequate plans, the Federal EPA develops and implements a plan. As the Federal EPA reviews the NAAQS and establishes new concentration levels, the attainment status of areas can change and states may be required to develop new SIPs. In 2008, the Federal EPA issued revised NAAQS for both ozone and fine particulate matter (PM2.5). The PM2.5 standard was remanded by the D.C. Circuit Court of Appeals, and a new rule was signed by the administrator in December 2012 that lowered the annual standard. A new ozone standard was adopted in 2015. The Federal EPA also adopted a new short-term standard for SO2 in 2010, a lower standard for NOx in 2010, and confirmed the existing standard for lead in 2016. The existing standard for carbon monoxide was retained in 2011. The states are in the process of developing new SIPs for the SO2, PM2.5 and ozone standards, which could result in more stringent emission limitations being imposed on AEP facilities.
In 2005, the Federal EPA issued the Clean Air Interstate Rule (CAIR), which required additional reductions in SO2 and NOx emissions from power plants and assists states developing new SIPs to meet the NAAQS. In August 2011, the Federal EPA issued a final rule to replace CAIR (the Cross State Air Pollution Rule (CSAPR)) that contains more stringent requirements to control SO2 and NOx emissions from fossil fuel-fired electric generating units in 27 states and the District of Columbia. Petitions for review were filed with the U.S. Court of Appeals for the District of Columbia Circuit, and CSAPR was vacated. That decision was subsequently reversed by the U.S. Supreme Court and remanded back to the U.S. Court of Appeals for further proceedings. The Federal EPA filed a motion to lift the stay and allow Phase I of CSAPR to take effect on January 1, 2015 and Phase II to take effect on January 1, 2017. The court granted the Federal EPA’s motion, an interim final rule has been issued, and the court has remanded certain state budgets to Federal EPA for further rulemaking while the rule remains in effect. Federal EPA has proposed more stringent NOx budgets for 23 states during the 2017 ozone season. For additional information regarding CSAPR, see Management’s Discussion and Analysis of Financial Condition and Results of Operations under the headings entitled Environmental Issues-Clean Air Act Requirements.
Hazardous Air Pollutants
As a result of the 1990 Amendments to the CAA, the Federal EPA investigated hazardous air pollutant (HAP) emissions from the electric utility sector and submitted a report to Congress, identifying mercury emissions from coal-fired power plants as warranting further study. In 2011, the Federal EPA issued a final rule setting Maximum Achievable Control Technology (MACT) standards for new and existing coal and oil-fired utility units and New Source Performance Standards (NSPS) for emissions from new and modified power plants. Petitions for review of the MACT standards were denied by the U.S. Court of Appeals for the D.C. Circuit, but in 2014 the U.S. Supreme Court determined that Federal EPA acted unreasonably in refusing to consider costs in determining if it was appropriate and necessary to regulate hazardous air pollutant emissions from electric generating units. Federal EPA has issued a supplemental finding and the rule remains in effect. For additional information regarding MACT, see Management’s Discussion and Analysis of Financial Condition and Results of Operations under the headings entitled Environmental Issues-Clean Air Act Requirements.
Regional Haze
The CAA establishes visibility goals for certain federally designated areas, including national parks, and requires states to submit SIPs that will demonstrate reasonable progress toward preventing impairment of visibility in these areas (Regional Haze program). In 2005, the Federal EPA issued its Clean Air Visibility Rule (CAVR), detailing how the CAA’s best available retrofit technology requirements will be applied to facilities built between 1962 and 1977 that emit more than 250 tons per year of certain pollutants in specific industrial categories, including power plants.
PSO executed a settlement with the Federal EPA and the State of Oklahoma to comply with Regional Haze program requirements in Oklahoma, and the settlement is now codified in the Oklahoma SIP. PSO is in the process of implementing the requirements of the SIP. Federal EPA has disapproved portions of the Arkansas and Texas SIPs, and finalized a Federal Implementation Plan for Arkansas in 2016. For additional information regarding CAVR and the Regional Haze program requirements, see Management’s Discussion and Analysis of Financial Condition and Results of Operations under the headings entitled Environmental Issues-Clean Air Act Requirements.
Climate Change
AEP has taken action to reduce and offset CO2 emissions from its generating fleet and expects CO2 emissions from its operations to continue to decline due to the retirement of some of its coal-fired generation units, and actions taken to diversify the generation fleet and increase energy efficiency where there is regulatory support for such activities. AEP’s total projected CO2 emissions in 2017 (not including emissions from the Kyger Creek and Clifty Creek Plants) are approximately 90 million metric tons, a 46% reduction from AEP’s 2000 CO2 emissions of approximately 167 million metric tons. Federal EPA has taken action to regulate CO2 emissions from new and existing fossil fueled electric generating units under the existing provisions of the CAA. The Federal EPA published the Clean Power Plan in October 2015. Such actions, including the Clean Power Plan, are being legally challenged by numerous parties and final regulatory outcomes remain uncertain. In February 2016, the U.S. Supreme Court issued a stay on the final Clean Power Plan, including all of the deadlines for submission of initial or final state plans. The stay will remain in effect until a final decision is issued by the U.S. Court of Appeals for the District of Columbia Circuit and the U.S. Supreme Court considers any petition for review. For additional information regarding the Federal EPA action taken to regulate CO2 emissions, including the Clean Power Plan, see Management’s Discussion and Analysis of Financial Condition and Results of Operations under the headings entitled Environmental Issues-Climate Change, CO2 Regulation and Energy Policy.
Management expects emissions to continue to decline over time as AEP diversifies generating sources and operates fewer coal units. The projected decline in coal-fired generation is due to a number of factors, including the ongoing cost of operating older units, the relative cost of coal and natural gas as fuel sources, increasing environmental regulations requiring significant capital investments and changing commodity market fundamentals. Management’s strategy for this transformation includes diversifying AEP’s fuel portfolio and generating more electricity from natural gas, increasing energy efficiency and investing in renewable resources, where there is regulatory support.
AEP’s fossil fuel-fired generating units are large sources of CO2 emissions. If substantial additional CO2 emission reductions are required, there will be significant increases in capital expenditures and operating costs which would hasten the ultimate retirement of older, less-efficient, coal-fired units. To the extent additional investments are made to reduce CO2 emissions and receive regulatory approvals to increase rates, return on capital investment would have a positive effect on future earnings. Prudently incurred capital investments made by AEP subsidiaries in rate-regulated jurisdictions to comply with legal requirements and benefit customers are generally included in rate base for recovery and earn a return on investment. Management would expect these principles to apply to investments made to address new environmental requirements. However, requests for rate increases reflecting these costs can have adverse effects because regulators could limit the amount or timing of increased costs that AEP would recover through higher rates. For sales of energy into competitive markets, however, there is no such recovery mechanism.
Renewable Sources of Energy
The states AEP serves, other than Kentucky, West Virginia and Tennessee, have established mandatory or voluntary programs to increase the use of energy efficiency, alternative energy, or renewable energy sources.
At the end of 2016, the AEP operating companies had long-term contracts for 2,630 MWs of wind and 10 MWs of solar power delivering renewable energy to the companies’ customers. In addition, I&M completed construction of four solar projects that make up I&M’s 14.7 MW Clean Energy Solar Pilot Project (CESPP) that was approved by the Indiana Utility Regulatory Commission. This resulted in a total of 2,655 MWs of wind and solar in-service serving AEP’s regulated utilities. Management actively manages AEP’s compliance position and is on pace to meet the relevant requirements or benchmarks in each applicable jurisdiction.
The growth of AEP’s renewable portfolio reflects the company’s strategy to diversify its generation resources to provide clean energy options to customers that meet both energy and capacity needs. In addition to gradually reducing AEP’s reliance on coal-fueled generating units, the growth of renewables and natural gas helps AEP to maintain a diversity of generation resources.
The integrated resource plans filed with state regulatory commissions by AEP’s regulated utility subsidiaries reflect AEP’s renewable strategy to balance reliability and cost with customers’ desire for clean energy in a carbon-constrained world. The Company has committed significant capital investments to modernize the electric grid and integrate these new resources. Transmission assets of the AEP System interconnect approximately 9,000 MWs of renewable energy resources of third parties, and AEP’s transmission development initiatives are designed to facilitate the interconnection of additional renewable energy resources.
AEP Energy Supply LLC owns 311 MWs of wind capacity in Texas and sells its energy entitlement to third parties or liquidates at market. In 2016, AEP took several major steps in executing its strategic plan to develop and market a merchant distributed resource portfolio. AEP Renewables, LLC, was formed in April 2016 to develop and/or acquire large scale renewable projects backed with long-term contracts with credit worthy counterparties. In 2016, AEP Renewables, LLC brought into service a 26 MW solar project in Utah. The company also owns a 62 MW solar project in Nevada that was brought into service in 2017.
AEP OnSite Partners, LLC works directly with wholesale and large retail customers to provide tailored solutions to reduce their energy costs based upon market knowledge, innovative applications of technology and deal structuring capabilities. The company targets opportunities in distributed solar, combined heat and power, energy storage, waste heat recovery, energy efficiency, peaking generation and other energy solutions that create value for customers. AEP OnSite Partners, LLC pursues and develops behind the meter projects with credit-worthy customers. As of December 31, 2016, AEP OnSite Partners, LLC owned projects operating in six states, including 15 MWs of installed solar capacity and another 21 MWs of solar projects under construction in five states.
End Use Energy Efficiency
Beginning in 2008, AEP ramped up efforts to reduce energy consumption and peak demand through the introduction of additional energy efficiency and demand response programs. These programs, commonly and collectively referred to as demand side management, were implemented in jurisdictions where appropriate cost recovery was available. Since that time, AEP operating companies have implemented over 125 programs across the AEP service territory and in most of the states AEP serves. For the period 2008 through 2016, these programs have reduced annual consumption by over 6.0 million megawatt hours and peak demand by approximately 2,000 MWs. AEP estimates that its operating companies spent approximately $1 billion during that period to achieve these levels.
Energy efficiency and demand reduction programs have received regulatory support in most of the states AEP serves, and appropriate cost recovery will be essential for AEP operating companies to continue and expand these consumer offerings. Appropriate recovery of program costs, lost revenues, and an opportunity to earn a reasonable return ensures that energy efficiency programs are considered equally with supply side investments. As AEP continues to transition to a cleaner, more efficient energy future, energy efficiency and demand response programs will continue to play an important role in how the company serves its customers.
AEP believes its experience providing robust energy efficiency programs in several states positions the company to be a cost-effective provider of these programs as states develop their implementation plans.
Corporate Governance
In response to environmental issues and in connection with its assessment of AEP’s strategic plan, the Board of Directors continually reviews the risks posed by new environmental rules and requirements that could accelerate the retirement of coal-fired generation assets. The Board of Directors is informed of any new environmental regulations and proposed regulation or legislation that would affect the company. The Board’s Committee on Directors and Corporate Governance oversees the company’s annual Corporate Accountability Report, which includes information about the company’s environmental, financial and social performance.
Other Environmental Issues and Matters
The Comprehensive Environmental Response, Compensation and Liability Act of 1980 imposes costs for environmental remediation upon owners and previous owners of sites, as well as transporters and generators of hazardous material disposed of at such sites. See Note 6 to the financial statements entitled Commitments, Guarantees and Contingencies, included in the 2016 Annual Reports, under the heading entitled The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation for further information.
Environmental Investments
Investments related to improving AEP System plants’ environmental performance and compliance with air and water quality standards during 2014, 2015 and 2016 and the current estimate for 2017 are shown below. These investments include both environmental as well as other related spending. Estimated construction expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends and the ability to access capital. AEP expects to make substantial investments in future years in addition to the amounts set forth below in connection with the modification and addition of facilities at generation plants for environmental quality controls. Such future investments are needed in order to comply with air and water quality standards that have been adopted and have deadlines for compliance after 2016 or have been proposed and may be adopted. Future investments could be significantly greater if emissions reduction requirements are accelerated or otherwise become more onerous. The cost of complying with applicable environmental laws, regulations and rules is expected to be material to the AEP System. AEP typically recovers costs of complying with environmental standards from customers through rates in regulated jurisdictions. For AEP’s merchant generation units however, there is no such recovery mechanism. Failure to recover these costs could reduce future net income and cash flows and possibly harm AEP’s financial condition. See Management’s Discussion and Analysis of Financial Condition and Results of Operations under the heading entitled Environmental Issues and Note 6 to the financial statements, entitled Commitments, Guarantees and Contingencies, included in the 2016 Annual Reports, for more information regarding environmental expenditures in general.
(a)
Includes expenditures of the subsidiaries shown and other subsidiaries not shown. The figures reflect construction expenditures, not investments in subsidiary companies. Excludes discontinued operations and OPCo, which transferred all of its generation assets on December 31, 2013.
(b)
For APCo, the historical environmental investments above include the conversions of 470 MWs of coal generation to natural gas. The conversion was completed in 2016 as Clinch River Plant, Unit 1 and Unit 2 began operations as natural gas units in February 2016 and April 2016, respectively.
(c)
Estimated amounts are exclusive of debt AFUDC.
Management continues to refine the cost estimates of complying with air and water quality standards and other impacts of the environmental proposals. The following cost estimates for periods following 2017 will change depending on the timing of implementation and whether the Federal EPA provides flexibility in the final rules. These cost estimates will also change based on: (a) the states’ implementation of these regulatory programs, including the potential for state implementation plans (SIPs) or federal implementation plans (FIPs) that impose more stringent standards, (b) additional rulemaking activities in response to court decisions, (c) the actual performance of the pollution control technologies installed on the units, (d) changes in costs for new pollution controls, (e) new generating technology developments, (f) total MWs of capacity retired, replaced or sold, including the type and amount of such replacement capacity and (g) other factors.
For the Registrant Subsidiaries, excluding OPCo, management’s current ranges of estimates of environmental investments beginning in 2018, exclusive of debt AFUDC, are set forth below:
BUSINESS SEGMENTS
AEP’s Reportable Segments
AEP’s primary business is the generation, transmission and distribution of electricity. Within its Vertically Integrated Utilities segment, AEP centrally dispatches generation assets and manages its overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight. Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements.
AEP’s reportable segments and their related business activities are outlined below:
Vertically Integrated Utilities
•
Generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo.
Transmission and Distribution Utilities
•
Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by OPCo and AEP Texas.
•
OPCo purchases energy and capacity to serve SSO customers and provides transmission and distribution services for all connected load.
•
With the merger of TCC and TNC into AEP Utilities, Inc. to form AEP Texas, the Transmission and Distribution segment now includes activities related to the former AEP Utilities, Inc. that had been included in Corporate and Other.
AEP Transmission Holdco
•
Development, construction and operation of transmission facilities through investments in the State Transcos and Transmission Joint Ventures. These investments have PUCT-approved or FERC-approved returns on equity.
Generation & Marketing
•
Competitive generation in ERCOT and PJM.
•
Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO.
•
Contracted renewable energy investments and management services.
The remainder of AEP’s activities is presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. With the sale of AEPRO in November 2015, the activities related to the AEP River Operations segment have been moved to Corporate and Other for the periods presented. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.
VERTICALLY INTEGRATED UTILITIES
GENERAL
AEP’s vertically integrated utility operations are engaged in the generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo. AEPSC, as agent for AEP’s public utility subsidiaries, performs marketing, generation dispatch, fuel procurement and power-related risk management and trading activities on behalf of each of these subsidiaries.
ELECTRIC GENERATION
Facilities
As of December 31, 2016, AEP’s vertically integrated public utility subsidiaries owned or leased approximately 23,000 MWs of domestic generation. See Item 2 - Properties for more information regarding the generation capacity of vertically integrated public utility subsidiaries.
Fuel Supply
The following table shows the owned and leased generation sources by type (including wind purchase agreements), on an actual net generation (MWhs) basis, used by the Vertically Integrated Utilities:
A price increase/decrease in one or more fuel sources relative to other fuels, as well as the addition of renewable resources, may result in the decreased/increased use of other fuels. AEP’s overall 2016 fossil fuel costs for the Vertically Integrated Utilities remained flat on a dollar per MMBtu basis from 2015.
Coal and Lignite
AEP’s Vertically Integrated Utilities procure coal and lignite under a combination of purchasing arrangements including long-term contracts, affiliate operations and spot agreements with various producers and coal trading firms. Coal consumption in 2016 decreased from 2015 due to the decreased demand for coal-fired generation resulting from low natural gas prices, and the retirement of Northeastern 4 and Welsh 2 in 2016. Coal inventories ended the year at above-target levels on a system basis.
Management believes that the Vertically Integrated Utilities will be able to secure and transport coal and lignite of adequate quality and in adequate quantities to operate their coal and lignite-fired units. Through subsidiaries, AEP owns, leases or controls more than 3,722 railcars, approximately 468 barges, 12 towboats and a coal handling terminal with approximately 18 million tons of annual capacity to move and store coal for use in AEP generating facilities.
Spot market prices for coal started to strengthen in the second half of 2016. The increased spot coal prices reflect tighter supplies and increased demand for export coal. As of December 31, 2016, slightly less than half of the coal purchased by AEP’s subsidiaries was procured through term contracts. As those contracts expire or re-open for price adjustments, needed tonnage is replaced at current market prices as necessary. The price impact of this process is reflected in subsequent periods. The price paid for coal delivered in 2016 remained relatively flat from the prior year.
The following table shows the amount of coal and lignite delivered to the Vertically Integrated Utilities plants during the past three years and the average delivered price of coal purchased by the Vertically Integrated Utilities:
Total coal delivered to the plants (millions of tons)
30.0
37.3
41.0
Average cost per ton of coal delivered
$
45.92
$
45.36
$
46.65
The coal supplies at the Vertically Integrated Utilities plants vary from time to time depending on various factors, including, but not limited to, demand for electric power, unit outages, transportation infrastructure limitations, space limitations, plant coal consumption rates, availability of acceptable coals, labor issues and weather conditions, which may interrupt production or deliveries. As of December 31, 2016, the Vertically Integrated Utilities coal inventory was approximately 42 days of full load burn. While inventory targets vary by plant and are changed as necessary, the current coal inventory target for the Vertically Integrated Utilities is approximately 30 days.
Natural Gas
The Vertically Integrated Utilities consumed approximately 104 billion cubic feet of natural gas during 2016 for generating power. This represents an increase of 16% from 2015. Total gas consumption for the Vertically Integrated Utilities was higher year over year due to lower natural gas prices in the first half of 2016 and the addition of Clinch River, Units 1 and 2 and Big Sandy, Unit 1 as gas retrofitted units during the second quarter of 2016. Several of AEP’s natural gas-fired power plants are connected to at least two pipelines which allow greater access to competitive supplies and improve delivery reliability. A portfolio of term, monthly, seasonal, and daily supply and transportation agreements provide natural gas requirements for each plant, as appropriate. AEP’s natural gas supply agreements are entered into on a competitive basis and based on market prices.
The following table shows the amount of natural gas delivered to the Vertically Integrated Utilities plants during the past three years and the average delivered price of natural gas purchased by the Vertically Integrated Utilities.
Total natural gas delivered to the plants (billion cubic feet)
103.9
89.7
96.1
Average price per MMBtu of purchased natural gas
$
2.77
$
2.80
$
4.70
Nuclear
I&M has made commitments to meet the current nuclear fuel requirements of the Cook Plant. I&M has made and will make purchases of uranium in various forms in the spot, short-term and mid-term markets. I&M also continues to lease a portion of its nuclear fuel.
For purposes of the storage of high-level radioactive waste in the form of spent nuclear fuel, I&M completed modifications to its spent nuclear fuel storage pool more than 10 years ago. I&M entered into an agreement to provide for onsite dry cask storage of spent nuclear fuel to permit normal operations to continue. I&M is scheduled to conduct further dry cask loading and storage projects on an ongoing periodic basis. I&M completed its initial loading of spent nuclear fuel into the dry casks in 2012, which consisted of 12 casks (32 spent nuclear fuel assemblies contained within each). The second loading of spent nuclear fuel into dry casks was completed in 2015, which consisted of 16 casks. The third dry cask loading is expected to occur in 2018.
Nuclear Waste and Decommissioning
As the owner of the Cook Plant, I&M has a significant future financial commitment to dispose of spent nuclear fuel and decommission and decontaminate the plant safely. The cost to decommission a nuclear plant is affected by NRC regulations and the spent nuclear fuel disposal program. The most recent decommissioning cost study was completed in 2015. The estimated cost of decommissioning and disposal of low-level radioactive waste for the Cook Plant was $1.6 billion in 2015 non-discounted dollars. As of December 31, 2016, the total decommissioning trust fund balance for the Cook Plant was approximately $1.9 billion. The balance of funds available to eventually decommission Cook Plant will differ based on contributions and investment returns. The ultimate cost of retiring the Cook Plant may be materially different from estimates and funding targets as a result of the:
•
Escalation of various cost elements (including, but not limited to, general inflation and the cost of energy).
•
Further development of regulatory requirements governing decommissioning.
•
Technology available at the time of decommissioning differing significantly from that assumed in studies.
•
Availability of nuclear waste disposal facilities.
•
Availability of a United States Department of Energy facility for permanent storage of spent nuclear fuel.
Accordingly, management is unable to provide assurance that the ultimate cost of decommissioning the Cook Plant will not be significantly different than current projections. AEP will seek recovery from customers through regulated rates if actual decommissioning costs exceed projections. See Note 6 to the financial statements, entitled Commitments, Guarantees and Contingencies under the heading Nuclear Contingencies, included in the 2016 Annual Reports, for information with respect to nuclear waste and decommissioning.
Low-Level Radioactive Waste
The Low-Level Waste Policy Act of 1980 mandates that the responsibility for the disposal of low-level radioactive waste rests with the individual states. Low-level radioactive waste consists largely of ordinary refuse and other items that have come in contact with radioactive materials. Michigan does not currently have a disposal site for such waste available. I&M cannot predict when such a site may be available. However, the states of Utah and Texas have licensed low level radioactive waste disposal sites which currently accept low level radioactive waste from Michigan waste generators. There is currently no set date limiting I&M’s access to either of these facilities. The Cook Plant has a facility onsite designed specifically for the storage of low level radioactive waste. In the event that low level radioactive waste disposal facility access becomes unavailable, then low level radioactive waste can be stored onsite at this facility.
Counterparty Risk Management
The Vertically Integrated Utilities segment also sells power and enters into related energy transactions with wholesale customers and other market participants. As a result, counterparties and exchanges may require cash or cash related instruments to be deposited on transactions as margin against open positions. As of December 31, 2016, counterparties posted approximately $9 million in cash, cash equivalents or letters of credit with AEPSC for the benefit of AEP’s public utility subsidiaries (while, as of that date, AEP’s public utility subsidiaries posted approximately $57 million with counterparties and exchanges). Since open trading contracts are valued based on market prices of various commodities, exposures change daily. See Management’s Discussion and Analysis of Financial Condition and Results of Operations, included in the 2016 Annual Reports, under the heading entitled Quantitative and Qualitative Disclosures About Market Risk for additional information.
Certain Power Agreements
I&M
The Unit Power Agreement between AEGCo and I&M, dated March 31, 1982, provides for the sale by AEGCo to I&M of all the capacity (and the energy associated therewith) available to AEGCo at the Rockport Plant. Whether or not power is available from AEGCo, I&M is obligated to pay a demand charge for the right to receive such power (and an energy charge for any associated energy taken by I&M). The agreement will continue in effect until the last of the lease terms of Unit 2 of the Rockport Plant have expired (currently December 2022) unless extended in specified circumstances.
Pursuant to an assignment between I&M and KPCo, and a unit power agreement between AEGCo and KPCo, AEGCo sells KPCo 30% of the capacity (and the energy associated therewith) available to AEGCo from both units of the Rockport Plant. KPCo has agreed to pay to AEGCo the amounts that I&M would have paid AEGCo under the terms of the Unit Power Agreement between AEGCo and I&M for such entitlement. The KPCo unit power agreement expires in December 2022.
OVEC
AEP and several nonaffiliated utility companies jointly own OVEC. The aggregate equity participation of AEP in OVEC is 43.47%. Under the Inter-Company Power Agreement, which defines the rights of the owners and sets the power participation ratio of each, the sponsoring companies are entitled to receive and are obligated to pay for all OVEC capacity (approximately 2,400 MWs) in proportion to their respective power participation ratios. The aggregate power participation ratio of APCo, I&M and OPCo is 43.47%. The Inter-Company Power Agreement terminates in June 2040. The proceeds from the sale of power by OVEC are designed to be sufficient for OVEC to meet its operating expenses and fixed costs and to provide a return on its equity capital. AEP and the other owners have authorized environmental investments related to their ownership interests. OVEC financed capital expenditures totaling $1.3 billion in connection with the engineering and construction of flue gas desulfurization projects and the associated scrubber waste disposal landfills at its two generation plants through debt issuances, including tax-advantaged debt issuances. Both OVEC generation plants are operating with the new environmental controls in service. OPCo attempted to assign its rights and obligations under the Inter-Company Power Agreement to an affiliate as part of its transfer of its generation assets and liabilities in keeping with corporate separation required by Ohio law. OPCo failed to obtain the consent to assignment from the other owners of OVEC and therefore filed a request with the PUCO seeking authorization to maintain its ownership of OVEC. In December 2013, the PUCO approved OPCo’s request, subject to the condition that energy from the OVEC entitlements are sold into the day-ahead or real-time PJM energy markets, or on a forward basis through a bilateral arrangement. In November 2016, the PUCO approved OPCo’s request to approve a cost-based purchased power agreement (PPA) rider, effective in January 2017, that would initially be based upon OPCo’s contractual entitlement under the Inter-Company Agreement which is approximately 20% of OVEC’s capacity. Some parties filed a rehearing challenge to the PUCO decision which was denied. Separately, OPCo filed a proposal to replace the PPA rider with a bypassable rate mechanism that involves serving non-shopping load with the OVEC contractual entitlement, which remains pending at this time.
ELECTRIC DELIVERY
General
Other than AEGCo, AEP’s vertically integrated public utility subsidiaries own and operate transmission and distribution lines and other facilities to deliver electric power. See Item 2 - Properties for more information regarding the transmission and distribution lines. Most of the transmission and distribution services are sold to retail customers of AEP’s vertically integrated public utility subsidiaries in their service territories. These sales are made at rates approved by the state utility commissions of the states in which they operate, and in some instances, approved by the FERC. See Item 1. Business - Vertically Integrated Utilities - Regulation - Rates. The FERC regulates and approves the rates for both wholesale transmission transactions and wholesale generation contracts. The use and the recovery of costs associated with the transmission assets of the AEP vertically integrated public utility subsidiaries are subject to the rules, principles, protocols and agreements in place with PJM and SPP, and as approved by the FERC. See Item 1. Business - Vertically Integrated Utilities - Regulation - FERC. As discussed below, some transmission services also are separately sold to non-affiliated companies.
Other than AEGCo, AEP’s vertically integrated public utility subsidiaries hold franchises or other rights to provide electric service in various municipalities and regions in their service areas. In some cases, these franchises provide the utility with the exclusive right to provide electric service within a specific territory. These franchises have varying provisions and expiration dates. In general, the operating companies consider their franchises to be adequate for the conduct of their business. For a discussion of competition in the sale of power, see Item 1. Business - Vertically Integrated Utilities - Competition.
Transmission Agreement
APCo, I&M, KGPCo, KPCo and WPCo own and operate transmission facilities that are used to provide transmission service under the PJM OATT and are parties to the TA. OPCo, a subsidiary in AEP’s Transmission and Distribution Utilities segment, is also a party to the TA. The TA defines how the parties to the agreement share the revenues associated with their transmission facilities and the costs of transmission service provided by PJM. The TA has been approved by the FERC.
TCA, OATT, and ERCOT Protocols
PSO, SWEPCo and AEPSC are parties to the TCA. Under the TCA, a coordinating committee is charged with the responsibility of (a) overseeing the coordinated planning of the transmission facilities of the parties to the agreement, including the performance of transmission planning studies, (b) the interaction of such subsidiaries with independent system operators and other regional bodies interested in transmission planning and (c) compliance with the terms of the OATT filed with the FERC and the rules of the FERC relating to such tariff. Pursuant to the TCA, AEPSC has responsibility for monitoring the reliability of their transmission systems and administering the OATT on behalf of the other parties to the agreement. The TCA also provides for the allocation among the parties of revenues collected for transmission and ancillary services provided under the OATT. These allocations have been determined by the FERC-approved OATT for the SPP.
Regional Transmission Organizations
AEGCo, APCo, I&M, KGPCo, KPCo and WPCo are members of PJM, and PSO and SWEPCo are members of the SPP (both FERC-approved RTOs). RTOs operate, plan and control utility transmission assets in a manner designed to provide open access to such assets in a way that prevents discrimination between participants owning transmission assets and those that do not.
REGULATION
General
AEP’s vertically integrated public utility subsidiaries’ retail rates and certain other matters are subject to traditional cost-based regulation by the state utility commissions. AEP’s vertically integrated public utility subsidiaries are also subject to regulation by the FERC under the Federal Power Act with respect to wholesale power and transmission service transactions. I&M is subject to regulation by the NRC under the Atomic Energy Act of 1954, as amended, with respect to the operation of the Cook Plant. AEP and its vertically integrated public utility subsidiaries are also subject to the regulatory provisions of EPACT, much of which is administered by the FERC.
Rates
Historically, state utility commissions have established electric service rates on a cost-of-service basis, which is designed to allow a utility an opportunity to recover its cost of providing service and to earn a reasonable return on its investment used in providing that service. A utility’s cost of service generally reflects its operating expenses, including operation and maintenance expense, depreciation expense and taxes. State utility commissions periodically adjust rates pursuant to a review of (a) a utility’s adjusted revenues and expenses during a defined test period and (b) such utility’s level of investment. Absent a legal limitation, such as a law limiting the frequency of rate changes or capping rates for a period of time, a state utility commission can review and change rates on its own initiative. Some states may initiate reviews at the request of a utility, customer, governmental or other representative of a group of customers. Such parties may, however, agree with one another not to request reviews of or changes to rates for a specified period of time.
Public utilities have traditionally financed capital investments until the new asset is placed in service. Provided the asset was found to be a prudent investment, it was then added to rate base and entitled to a return through rate recovery. Given long lead times in construction, the high costs of plant and equipment and volatile capital markets, management is actively pursuing strategies to accelerate rate recognition of investments and cash flow. AEP representatives continue to engage state commissioners and legislators on alternative ratemaking options to reduce regulatory lag and enhance certainty in the process. These options include pre-approvals, a return on construction work in progress, rider/trackers, formula rates and the inclusion of future test-year projections into rates.
The rates of AEP’s vertically integrated public utility subsidiaries are generally based on the cost of providing traditional bundled electric service (i.e., generation, transmission and distribution service). Historically, the state regulatory frameworks in the service area of the AEP vertically integrated public utility subsidiaries reflected specified fuel costs as part of bundled (or, more recently, unbundled) rates or incorporated fuel adjustment clauses in a utility’s rates and tariffs. Fuel adjustment clauses permit periodic adjustments to fuel cost recovery from customers and therefore provide protection against exposure to fuel cost changes.
The following state-by-state analysis summarizes the regulatory environment of certain major jurisdictions in which AEP’s vertically integrated public utility subsidiaries operate. Several public utility subsidiaries operate in more than one jurisdiction. See Note 4 to the financial statements, entitled Rate Matters, included in the 2016 Annual Reports, for more information regarding pending rate matters.
Indiana
I&M provides retail electric service in Indiana at bundled rates approved by the IURC, with rates set on a cost-of-service basis. Indiana provides for timely fuel and purchased power cost recovery through a fuel cost recovery mechanism.
Oklahoma
PSO provides retail electric service in Oklahoma at bundled rates approved by the OCC. PSO’s rates are set on a cost-of-service basis. Fuel and purchased energy costs are recovered or refunded by applying fuel adjustment and other factors to retail kilowatt-hour sales.
Virginia
APCo currently provides retail electric service in Virginia at unbundled generation and distribution rates, currently frozen, approved by the Virginia SCC. Virginia generally allows for timely recovery of fuel costs through a fuel adjustment clause. In addition to base rates and fuel cost recovery, APCo is permitted to recover a variety of costs through rate adjustment clauses including transmission services provided at OATT rates based on rates established by the FERC.
West Virginia
APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC, with rates set on a combined cost-of-service basis. West Virginia generally allows for timely recovery of fuel costs through an expanded net energy cost which trues-up to actual expenses.
FERC
Under the Federal Power Act, the FERC regulates rates for interstate power sales at wholesale, transmission of electric power, accounting and other matters, including construction and operation of hydroelectric projects. The FERC regulations require AEP’s vertically integrated public utility subsidiaries to provide open access transmission service at FERC-approved rates, and AEP has approved cost-based formula transmission rates on file at FERC. The FERC also regulates unbundled transmission service to retail customers. In addition, the FERC regulates the sale of power for resale in interstate commerce by (a) approving contracts for wholesale sales to municipal and cooperative utilities and (b) granting authority to public utilities to sell power at wholesale at market-based rates upon a showing that the seller lacks the ability to improperly influence market prices. AEP’s vertically integrated public utility subsidiaries have market-based rate authority from the FERC, under which much of their wholesale marketing activity takes place. The FERC requires each public utility that owns or controls interstate transmission facilities to, directly or through an RTO, to file an open access network and point-to-point transmission tariff that offers services comparable to the utility’s own uses of its transmission system. The FERC also requires all transmitting utilities, directly or through an RTO, to establish an Open Access Same-time Information System, which electronically posts transmission information such as available capacity and prices, and requires utilities to comply with Standards of Conduct that prohibit utilities’ transmission employees from providing non-public transmission information to the utility’s marketing employees.
The FERC oversees RTOs, entities created to operate, plan and control utility transmission assets. FERC Order 2000 prescribes certain characteristics and functions of acceptable RTO proposals. AEGCo, APCo, I&M, KGPCo, KPCo and WPCo are members of PJM. PSO and SWEPCo are members of SPP.
The FERC has jurisdiction over the issuances of securities of most of AEP’s public utility subsidiaries, the acquisition of securities of utilities, the acquisition or sale of certain utility assets and mergers with another electric utility or holding company. In addition, both the FERC and state regulators are permitted to review the books and records of any company within a holding company system.
COMPETITION
The vertically integrated public utility subsidiaries of AEP, like the electric industry generally, face competition in the sale of available power on a wholesale basis, primarily to other public utilities and power marketers. Federal policy generally fosters competition in the wholesale market by creating a generation market and mandates that all generators have equal access to transmission services. As a result, more generators participate in this market. The principal factors in competing for wholesale sales are price (including fuel costs), reliability of service, and availability of capacity and power.
Technology advancements, increased demand for clean energy, changing consumer behaviors, low-priced and abundant natural gas, and regulatory and public policy reforms are among the catalysts for transformation within the industry that impact competition for AEP’s vertically integrated public utility subsidiaries. AEP’s vertically integrated public utility subsidiaries also compete with self-generation and with distributors of other energy sources, such as natural gas, fuel oil, renewables and coal, within their service areas. The primary factors in such competition are price, reliability of service and the capability of customers to utilize alternative sources of energy other than electric power. With respect to competing generators and self-generation, the public utility subsidiaries of AEP believe that they currently maintain a competitive position.
Changes in regulatory policies and advances in newer technologies for batteries or energy storage, fuel cells, microturbines, wind turbines and photovoltaic solar cells are reducing costs of new technology to levels that are making them competitive with some central station electricity production. The costs of photovoltaic solar cells in particular have continued to become increasingly competitive. The ability to maintain relatively low cost, efficient and reliable operations and to provide cost-effective programs and services to customers are significant determinants of AEP’s competitiveness.
While the adoption rate of distributed generation in AEP’s service areas has not reached the levels seen in other parts of the country, AEP’s vertically integrated utility companies are focused on providing customers with more choices by working with regulators and policymakers to expand, and potentially accelerate, renewable energy offerings. Such additional customer choices consider not only long-term cost, but are also focused on expanding resource diversity. This includes proposed new revenue structures that enable deployment of advanced technologies and resources. In 2015, AEP formed an Enterprise Technology Council to develop and deploy new programs and services designed to receive regulatory support. The vertically integrated public utility subsidiaries of AEP believe that the reliability of their service, the limited ability of customers to substitute other economical sources for electric power and their ability to cost-effectively deploy advanced technologies, such as solar, on a large scale place them in a favorable competitive position.
In the event that alternative generation resources are mandated, subsidized or encouraged through legislation or regulation or otherwise are economically competitive and added to the available generation supply, such resources could displace a higher marginal cost fossil plant, which could reduce the price at which market participants sell their electricity. These events could cause AEP to retire generating capacity prior to the end of its estimated useful life. AEP typically recovers undepreciated plant balances and associated operating costs, each including a return, from customers through regulated rates in regulated jurisdictions. Failure to recover these costs could reduce future net income and cash flows and possibly harm financial condition.
Recent changes in the global economy have led to increased competition for many industrial customers in the United States, including those served by the AEP System. Industrial customers that are downsizing or reorganizing often close a facility based upon its costs, which may include, among other things, the cost of electric power. The vertically integrated public utility subsidiaries of AEP work with such customers to meet their business needs. For example, various off-peak or interruptible supply options may be provided pursuant to tariffs filed with, and approved by, the various state commissions. The vertically integrated public utility subsidiaries of AEP also work with customers that seek to source more of their electric power from renewable resources. Depending on the jurisdiction, customers may have access to green power tariffs. In other instances, AEP purchases renewable power that is available to all customers in a specific jurisdiction.
SEASONALITY
The sale of electric power is generally a seasonal business. In many parts of the country, demand for power peaks during the hot summer months, with market prices also peaking at that time. In other areas, power demand peaks during the winter. The pattern of this fluctuation may change due to the nature and location of AEP’s facilities and the terms of power sale contracts into which AEP enters. In addition, AEP has historically sold less power, and consequently earned less income, when weather conditions are milder. Unusually mild weather in the future could diminish AEP’s results of operations. Conversely, unusually extreme weather conditions could increase AEP’s results of operations.
TRANSMISSION AND DISTRIBUTION UTILITIES
GENERAL
This segment consists of the transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEP Texas and OPCo. OPCo is engaged in the transmission and distribution of electric power to approximately 1,472,000 retail customers in Ohio. AEP Texas is engaged in the transmission and distribution of electric power to approximately 1,024,000 retail customers through REPs in west, central and southern Texas.
AEP’s transmission and distribution utility subsidiaries own and operate transmission and distribution lines and other facilities to deliver electric power. See Item 2 - Properties for more information regarding the transmission and distribution lines. Most of the transmission and distribution services are sold to retail customers of AEP’s transmission and distribution utility subsidiaries in their service territories. These sales are made at rates approved by the PUCT for AEP Texas and by the PUCO and the FERC for OPCo. The FERC regulates and approves the rates for wholesale transmission transactions. As discussed below, some transmission services also are separately sold to non-affiliated companies.
AEP’s transmission and distribution utility subsidiaries hold franchises or other rights to provide electric service in various municipalities and regions in their service areas. In some cases, these franchises provide the utility with the exclusive right to provide electric service. These franchises have varying provisions and expiration dates. In general, the operating companies consider their franchises to be adequate for the conduct of their business.
The use and the recovery of costs associated with the transmission assets of the AEP transmission and distribution utility subsidiaries are subject to the rules, protocols and agreements in place with PJM and ERCOT, and as approved by the FERC. In addition to providing transmission services in connection with power sales in their service areas, AEP’s transmission and distribution utility subsidiaries through RTOs also provide transmission services for non-affiliated companies.
Transmission Agreement
OPCo, together with APCo, I&M, KGPCo, KPCo and WPCo, is a party to the TA. The TA defines how the parties to the agreement share the cost of their transmission facilities. The TA has been approved by the FERC.
Regional Transmission Organizations
OPCo is a member of PJM, a FERC-approved RTO. RTOs operate, plan and control utility transmission assets in a manner designed to provide open access to such assets in a way that prevents discrimination between participants owning transmission assets and those that do not. AEP Texas is a member of ERCOT.
REGULATION
OPCo provides distribution and transmission services to retail customers within its service territory at cost-based rates approved by the PUCO or by the FERC. AEP Texas provides transmission and distribution service on a cost-of-service basis at rates approved by the PUCT and wholesale transmission service under tariffs approved by the FERC consistent with PUCT rules. Transmission and distribution rates are established on a cost-of-service basis, which is designed to allow a utility an opportunity to recover its cost of providing service and to earn a reasonable return on its investment used in providing that service. The cost of service generally reflects operating expenses, including operation and maintenance expense, depreciation expense and taxes. Utility commissions periodically adjust rates pursuant to a review of (a) a utility’s adjusted revenues and expenses during a defined test period and (b) such utility’s level of investment.
FERC
Under the Federal Power Act, the FERC regulates rates for transmission of electric power, accounting and other matters. The FERC regulations require AEP to provide open access transmission service at FERC-approved rates, and it has approved cost-based formula transmission rates on file at FERC. The FERC also regulates unbundled transmission service to retail customers. The FERC requires each public utility that owns or controls interstate transmission facilities to, directly or through an RTO, file an open access network and point-to-point transmission tariff that offers services comparable to the utility’s own uses of its transmission system. The FERC also requires all transmitting utilities, directly or through an RTO, to establish an Open Access Same-time Information System, which electronically posts transmission information such as available capacity and prices, and requires utilities to comply with Standards of Conduct that prohibit utilities’ transmission employees from providing non-public transmission information to the utility’s marketing employees. In addition, both the FERC and state regulators are permitted to review the books and records of any company within a holding company system.
SEASONALITY
The delivery of electric power is generally a seasonal business. In many parts of the country, demand for power peaks during the hot summer months. In other areas, power demand peaks during the winter months. The pattern of this fluctuation may change due to the nature and location of AEP’s transmission and distribution facilities. In addition, AEP transmission and distribution has historically delivered less power, and consequently earned less income, when weather conditions are milder. In Texas, and to a lesser extent, in Ohio, unusually mild weather in the future could diminish AEP’s results of operations. Conversely, unusually extreme weather conditions could increase AEP’s results of operations.
AEP TRANSMISSION HOLDCO (AEPTHCO)
GENERAL
AEPTHCo is a holding company for (a) AEPTCo, which is the direct holding company for the State Transcos and (b) AEP’s Transmission Joint Ventures.
AEPTCo
AEPTCo wholly owns the State Transcos:
•
AEP Appalachian Transmission Company, Inc. (APTCo)
•
AEP Indiana Michigan Transmission Company, Inc. (IMTCo)
•
AEP Kentucky Transmission Company, Inc. (KTCo)
•
AEP Ohio Transmission Company, Inc. (OHTCo)
•
AEP West Virginia Transmission Company, Inc. (WVTCo)
•
AEP Oklahoma Transmission Company, Inc. (OKTCo)
•
AEP Southwestern Transmission Company, Inc. (SWTCo)
The State Transcos are independent of, but respectively overlay, the following of AEP’s existing electric utility operating companies: APCo, I&M, KPCo, KGPCo, OPCo, PSO, SWEPCo, and WPCo. The State Transcos develop, own, operate, and maintain their respective transmission assets. Assets of the State Transcos interconnect to transmission facilities owned by the aforementioned operating companies and unaffiliated transmission owners within the footprints of PJM and SPP. APTCo, IMTCo, KTCo, OHTCo, and WVTCo are located within PJM. OKTCo and SWTCo are located within SPP.
IMTCo, KTCo, OHTCo, OKTCo, and WVTCo have received all necessary approvals for formation and currently own and operate transmission assets in their respective jurisdictions. In December 2016, the Virginia SCC and WVPSC granted consent for APCo and APTCo to enter into a joint license agreement that will support APTCo investment in the state of Tennessee. An application for regulatory approval for SWTCo is under consideration in Louisiana.
The State Transcos are regulated for rate-making purposes exclusively by FERC and earn revenues through tariff rates charged for the use of their electric transmission systems. The State Transcos establish transmission rates each year through formula rate filings with FERC. The rate filings calculate the revenue requirement needed to cover the costs of operation and debt service and to earn an allowed return on equity. These rates are then included in OATT for SPP and PJM.
The State Transcos own, operate, maintain and invest in transmission infrastructure in order to maintain and enhance system integrity and grid reliability, grid security, safety, reduce transmission constraints and facilitate interconnections of new generating resources and new wholesale customers, as well as enhance competitive wholesale electricity markets. A key part of AEP’s business is replacing and upgrading transmission facilities, assets and components of the existing AEP System as needed to maintain reliability.
The State Transcos provide the capability to replace and upgrade existing facilities. The State Transcos are geographically diverse and have assets in service or under construction across two RTOs and in six states, with additional states planned or pending approval. As of December 31, 2016, the State Transcos had $4.1 billion of transmission assets in-service with plans to construct approximately $ 4.4 billion of additional transmission assets through 2019. Management anticipates the need for extensive additional investment in transmission infrastructure within PJM and SPP to maintain the required level of grid reliability, resiliency, security and efficiency and to address an aging transmission infrastructure. Management also foresees the need to construct additional transmission facilities based on changes in generating resources, such as wind or solar projects, generation additions or retirements, and additional new customer interconnections. AEP will continue its investment to enhance physical and cyber security of assets, and are also investing in improving the telecommunication network that supports the operation and control of the grid.
AEPTHCO JOINT VENTURE INITIATIVES
AEP has established joint ventures with other electric utility companies for the purpose of developing, building, and owning transmission assets that seek to improve reliability and market efficiency and provide transmission access to remote generation sources in North America (Transmission Joint Ventures).
The Transmission Joint Ventures currently include:
(a)
ETT is undertaking multiple projects and the completion dates will vary for those projects. ETT’s investment in completed, current and future projects in ERCOT over the next ten years is expected to be $3.5 billion. Future projects will be evaluated on a case-by-case basis. ETT’s approved return on equity of 9.6% will go into effect in March 2017.
(b)
AEP owns 25% of Prairie Wind Transmission, LLC (Prairie Wind) through its ownership interest in Electric Transmission America, LLC. which is a 50/50 joint venture with Berkshire Hathaway Energy (formerly known as MidAmerican Energy) and AEP.
(c)
The Pioneer project consists of approximately 286 miles of new 765 kV transmission lines, which is estimated to cost $1.1 billion at completion. Pioneer is developing the first 66-mile segment jointly with Northern Indiana Public Service Company at a total estimated cost of $386 million. The projected completion date for the first 66-mile segment is 2018. The projected completion dates for the remaining segments have not been determined.
(d)
AEP owns 87.5% of RITELine Indiana, LLC (RITELine IN) through its ownership interest in RITELine Transmission Development, LLC (RTD) and AEP Transmission Holding Company, LLC (AEPTHCo). AEP owns 12.5% of RITELine Illinois, LLC (RITELine IL) through its ownership interest in RTD. RTD is a 50/50 joint venture with Exelon Transmission Company, LLC and AEPTHCo.
(e)
RITELine IN is a consolidated variable interest entity. RTD received an order from the FERC in October 2011 granting incentives for the RITELine IN and RITELine IL projects. The projects and other segments that are electrically equivalent in nature will continue to be submitted for consideration in the interregional planning process between PJM and MISO as dictated by emerging system needs.
(f)
AEP owns 86.5% of Transource Missouri, Transource West Virginia, Transource Maryland and Transource Pennsylvania through its ownership interest in Transource Energy, LLC (Transource). Transource is a joint venture with AEPTHCo and Great Plains Energy formed to pursue competitive transmission projects. AEPTHCo and Great Plains Energy own 86.5% and 13.5% of Transource, respectively.
(g)
The ROE represents the weighted average approved return on equity based on the costs of two projects developed by Transource Missouri; the $65 million Iatan-Nashua project (10.3%) and the $246 million Sibley-Nebraska City project (11.3%).
(h)
In August 2016, Transource Maryland and Transource Pennsylvania received approval from the PJM Interconnection Board to construct portions of a transmission project located in both Maryland and Pennsylvania. The project is expected to go in service in 2020.
(i)
In November 2016, Transource Maryland and Transource Pennsylvania submitted a filing at FERC requesting approval of a 10.4% base ROE plus a 0.50% ROE adder for RTO participation and a 0.50% ROE adder for risk.
(j)
RITELine IN, Transource Missouri, Transource West Virginia, Transource Maryland and Transource Pennsylvania are consolidated joint ventures by AEP. Therefore, the investment value listed reflects applicable income taxes that are the responsibility of AEP. All other investments in this schedule are joint ventures that are not consolidated by AEP. Therefore, these investment values listed do not reflect income taxes that are the responsibility of AEP.
AEP’s joint ventures do not have employees. Business services for the joint ventures are provided by AEPSC and other AEP subsidiaries and the joint venture partners. During 2016 approximately 598 AEPSC employees and 292 operating company employees provided service to one or more joint ventures.
REGULATION
The State Transcos and the Transmission Joint Ventures located outside of ERCOT establish transmission rates annually through forward looking formula rate filings with the FERC pursuant to FERC-approved implementation protocols. The protocols include a transparent, formal review process to ensure the updated transmission rates are prudently incurred and reasonably calculated.
The State Transcos’ and the Transmission Joint Ventures’ (where applicable) rates are included in the respective OATT for PJM and SPP. An OATT is the FERC rate schedule that provides the terms and conditions for transmission and related services on a transmission provider’s transmission system. The FERC requires transmission providers such as PJM and SPP to offer transmission service to all eligible customers (for example, load-serving entities, power marketers, generators and customers) on a non-discriminatory basis.
The FERC-approved formula rates establish the annual transmission revenue requirement (ATRR) and transmission service rates for transmission owners in annual rate base filings with FERC. The formula rates establish rates for a one-year period based on the current projects in-service and proposed projects for a defined timeframe. The formula rates also include a true-up calculation for the previous year’s billings, allowing for over/under-recovery of the transmission owner’s ATRR. PJM and SPP pay the transmission owners their ATRR for use of their facilities and bill transmission customers taking service under the PJM and SPP OATTs, based on the terms and conditions in the respective OATT for the service taken.
The formula rate mechanism allows for a return on equity of 11.49% based on a capital structure of up to 50% equity for APTCo, IMTCo, KTCo, OHTCo and WVTCo. OKTCo and SWTCo are allowed a return on equity of 11.2% based on a capital structure of up to 50% equity. The authorized returns on equity for the State Transcos are commensurate with the FERC-authorized returns on equity in the PJM and SPP OATTs, respectively, for AEP’s utility subsidiaries.
In October 2016, several parties filed a joint complaint with FERC claiming the base return on common equity used by various AEP affiliates in calculating formula transmission rates under the PJM OATT is excessive and should be reduced from 10.99% to 8.32%, effective upon the date of the complaint. In November 2016, AEP affiliates filed an application with the FERC to modify the FERC formula transmission rate calculation, including adjustments for certain tax issues and a switch from historic to estimated expenses with a proposed effective date of January 1, 2017. The rates will be implemented based upon the date provided in the pending FERC order, subject to refund.
In the annual rate base filings described above, the State Transcos in aggregate filed rate base totals of $3.2 billion in 2016, $2.3 billion for 2015 and $1.4 billion for 2014. The total transmission revenue requirement filed in the ATRR, including prior year over/under-recovery of revenue and associated carrying charges, for 2016, 2015, and 2014 was $555 million, $363 million and $231 million, respectively.
The rates of ETT, which is located in ERCOT, are determined by the PUCT. ETT sets its rates through a combination of base rate cases and interim Transmission Costs of Services (TCOS) filings. ETT may file interim TCOS filings semi-annually to update its rates to reflect changes in its net invested capital.
Effective March 2017, the Transmission Joint Ventures have approved returns on equity ranging from 9.6% to 12.8% based on equity capital structures ranging from 40% to 60%.
GENERATION & MARKETING
GENERAL
The AEP Generation & Marketing segment subsidiaries consist of competitive nonutility generating assets, a wholesale energy trading and marketing business and a retail supply and energy management business. The largest subsidiary in the Generation & Marketing segment is AGR. Through year end 2016 AGR owned 6,752 MWs of generating capacity, with rights to an additional 1,186 MWs pursuant to a unit power agreement (see below). In January 2017, AGR sold 4,143 MWs of generation capacity to an unaffiliated third party and terminated the 1,186 MW unit power agreement. As a result of the sale, AGR currently owns 2,732 MWs of generating capacity. Other subsidiaries in this segment own or have the right to receive power from additional generation assets. See Item 2 - Properties for more information regarding the generation assets of the Generation & Marketing segment. AGR is a competitive generation subsidiary.
With respect to wholesale energy trading and marketing business, AEP Generation & Marketing segment subsidiaries enter into short-term and long-term transactions to buy or sell capacity, energy and ancillary services in ERCOT, SPP, MISO and PJM. These subsidiaries sell power into the market and engage in power, natural gas, coal and emissions allowances risk management and trading activities.
These activities primarily involve the purchase and sale of electricity (and to a lesser extent, natural gas, coal and emissions allowances) under forward contracts at fixed and variable prices. These contracts include physical transactions, exchange-traded futures, and to a lesser extent, over-the-counter swaps and options. The majority of forward contracts are typically settled by entering into offsetting contracts. These transactions are executed with numerous counterparties or on exchanges.
With respect to the retail supply and energy management business, AEP Energy is a retail energy supplier that supplies electricity and/or natural gas to residential, commercial, and industrial customers. AEP Energy provides various energy solutions in Illinois, Pennsylvania, Delaware, Maryland, New Jersey, Ohio and Washington, D.C. AEP Energy also provides demand-side management solutions nationwide. AEP Energy had approximately 430,000 customer accounts as of December 31, 2016.
AEP Energy Supply LLC owns 311 MWs of wind capacity in Texas and sells its energy entitlement to third parties or liquidates at market. In 2016, AEP took several major steps in executing its strategic plan to develop and market a merchant distributed resource portfolio. AEP Renewables, LLC was formed in April 2016 to develop and/or acquire large scale renewable projects backed with long-term contracts with credit worthy counterparties. In 2016, AEP Renewables, LLC brought into service a 26 MW solar project in Utah. The company also owns a 62 MW solar project in Nevada that was brought into service in 2017.
AEP OnSite Partners, LLC works directly with wholesale and large retail customers to provide tailored solutions to reduce their energy costs based upon market knowledge, innovative applications of technology and deal structuring capabilities. The company targets opportunities in distributed solar, combined heat and power, energy storage, waste heat recovery, energy efficiency, peaking generation and other energy solutions that create value for customers. AEP OnSite Partners, LLC pursues and develops behind the meter projects with credit-worthy customers and appropriate agreements. As of December 31, 2016, AEP OnSite Partners, LLC owned projects operating in six states, including 15 MWs of installed solar capacity and another 21 MWs of solar projects under construction in five states.
REGULATION
AGR is a public utility under the Federal Power Act, and is subject to FERC’s exclusive ratemaking jurisdiction over wholesale sales of electricity and the transmission of electricity in interstate commerce. Under the Federal Power Act, FERC has the authority to grant or deny market-based rates for sales of energy, capacity and ancillary services to ensure that such sales are just and reasonable. FERC granted AGR market-based rate authority in December 2013. FERC’s jurisdiction over ratemaking also includes the authority to suspend the market-based rates of utilities (including AGR, which is a public utility as defined by the FERC) and set cost-based rates if FERC subsequently determines that such utility can exercise market power, create barriers to entry or engage in abusive affiliate transactions. Periodically, AGR is required to file a market power update to show that it continues to meet FERC’s standards with respect to generation market power and other criteria used to evaluate whether it continues to qualify for market-based rates. Other matters subject to FERC jurisdiction include, but are not limited to, review of mergers, and dispositions of jurisdictional facilities and acquisitions of securities of another public utility or an existing operational generating facility.
Specific operations of AGR are also subject to the jurisdiction of various other Federal, state, regional and local agencies, including Federal and state environmental protection agencies. AGR is also regulated by the PUCT for transactions inside ERCOT. Additionally, AGR is subject to mandatory reliability standards promulgated by the North American Electric Reliability Corporation, with the approval of FERC.
COMPETITION
The AEP Generation & Marketing segment subsidiaries face competition for the sale of available power, capacity and ancillary services. The principal factors of impact are electricity and fuel prices, new market entrants, construction or retirement of generating assets by others and technological advances in power generation. Because most of AGR’s remaining generation is coal-fired, lower relative natural gas prices will favor competitors that have a higher concentration of natural gas fueled generation. Other factors impacting competitiveness include environmental regulation, transmission congestion or transportation constraints at or near generation facilities, inoperability or inefficiencies, outages and deactivations and retirements at generation facilities.
Technology advancements, increased demand for clean energy, changing consumer behaviors, low-priced and abundant natural gas, and regulatory and public policy reforms are among the catalysts for transformation within the industry that impact competition for AEP’s Generation & Marketing segment. AGR also competes with self-generation and with distributors of other energy sources, such as natural gas, fuel oil, renewables and coal, within their service areas. The primary factors in such competition are price, unit availability and the capability of customers to utilize sources of energy other than electric power.
Changes in regulatory policies and advances in newer technologies for batteries or energy storage, fuel cells, microturbines, wind turbines and photovoltaic solar cells are reducing costs of new technology to levels that are making them competitive with some central station electricity production. The ability to maintain relatively low cost, efficient and reliable operations and to provide cost-effective programs and services to customers are significant determinants of AGR’s competitiveness. The costs of photovoltaic solar cells in particular have continued to become increasingly competitive.
In the event that alternative generation resources are mandated, subsidized or encouraged through climate legislation or regulation or otherwise are economically competitive and added to the available generation supply, such resources could displace a higher marginal cost fossil plant, which could reduce the price at which market participants sell their electricity. These events could cause AGR to retire generating capacity prior to the end of its estimated useful life.
Changes in the global economy have led to increased competition for many industrial customers in the United States, including those served by the Generation & Marketing segment. Industrial customers that are downsizing or reorganizing often close a facility based upon its costs, which may include, among other things, the cost of electric power. The Generation & Marketing segment works with such customers to meet their business needs through, for example, providing various off-peak or interruptible supply options. The Generation & Marketing segment also works with customers that seek to source more of their electric power from renewable resources.
SEASONALITY
The sale of electric power is generally a seasonal business. In many parts of the country, demand for power peaks during the hot summer months, with market prices also peaking at that time. In other areas, power demand peaks during the winter months. The pattern of this fluctuation may change.
Fuel Supply
The following table shows the generation sources by type, on an actual net generation (MWhs) basis, used by the Generation & Marketing segment, not including AGR’s ownership of the Oklaunion generating unit:
A price increase/decrease in one or more fuel sources relative to other fuels, as well as the addition of renewable resources, may result in the decreased/increased use of other fuels.
Coal and Consumables
AGR procures coal and consumables needed to burn the coal under a combination of purchasing arrangements including long-term and spot contracts with various producers and coal trading firms. As contracts expire, they are replaced, as needed, with contracts at market prices. Coal and consumable inventories remain adequate to meet generation requirements.
Management believes that AGR will be able to secure and transport coal and consumables of adequate quality and in adequate quantities to operate their coal fired units. AGR, through its contracts with third party transporters, has the ability to adequately move and store coal and consumables for use in its generating facilities. AGR plants consumed 10.4 million tons of coal in 2016.
The coal supplies at AGR plants vary from time to time depending on various factors, including, but not limited to, demand for electric power, unit outages, transportation infrastructure limitations, space limitations, plant coal consumption rates, coal quality, availability of acceptable coals, labor issues and weather conditions, which may interrupt production or deliveries. AGR aims to maintain the coal inventory of its managed plants in the range of 15 to 40 days of full load burn. As of December 31, 2016, the coal inventory of AGR was above target.
Natural Gas
Despite the availability of natural gas due to the increased shale supply, the U.S. pipeline infrastructure remains a limiting factor in the expansion of natural gas-fired generation. A portfolio of term, monthly, seasonal firm and daily peaking purchase and transportation agreements (that are entered into on a competitive basis and based on market prices) supplies natural gas requirements for each plant, as appropriate. AGR plants consumed 100 billion cubic feet of natural gas in 2016, an increase of approximately 8.7% from 2015.
Counterparty Risk Management
Counterparties and exchanges may require cash or cash related instruments to be deposited on these transactions as margin against open positions. As of December 31, 2016, counterparties posted approximately $19 million in cash, cash equivalents or letters of credit with AEP for the benefit of AEP’s Generation & Marketing segment subsidiaries (while, as of that date, AEP’s Generation & Marketing segment subsidiaries posted approximately $142 million with counterparties and exchanges). Since open trading contracts are valued based on market prices of various commodities, exposures change daily. See Management’s Discussion and Analysis of Financial Condition and Results of Operations, included in the 2016 Annual Reports, under the heading entitled Quantitative and Qualitative Disclosures About Market Risk for additional information.
Certain Power Agreements
As of December 31, 2016, the assets utilized in this segment included approximately 310 MWs of company-owned domestic wind power facilities, 177 MWs of domestic wind power from long-term purchase power agreements and 355 MWs of coal-fired capacity which was obtained through an agreement effective through 2027 that transfers the interest of AEP Texas in the Oklaunion power station to AEP Energy Partners, Inc. The power obtained from the Oklaunion Power Station is marketed and sold in ERCOT.
EXECUTIVE OFFICERS OF AEP
The following persons are executive officers of AEP. Their ages are given as of February 21, 2017. The officers are appointed annually for a one-year term by the board of directors of AEP.
Nicholas K. Akins
Chairman of the Board, President and Chief Executive Officer
Age 56
Chairman of the Board since January 2014, President since January 2011and Chief Executive Officer since November 2011.
Lisa M. Barton
Executive Vice President - Transmission
Age 51
Executive Vice President - Transmission of AEPSC since August 2011.
Paul Chodak, III
Executive Vice President - Utilities
Age 53
Executive Vice President - Utilities since January 2017. Was President and Chief Operating Officer of I&M from July 2010 to December 2016.
David M. Feinberg
Executive Vice President, General Counsel and Secretary
Age 47
Executive Vice President since January 2013. Was Senior Vice President, General Counsel and Secretary from January 2012 to December 2012.
Lana L. Hillebrand
Executive Vice President and Chief Administrative Officer
Age 56
Chief Administrative Officer since December 2012 and Senior Vice President from December 2012 to December 2016. Previously served as South Region leader-Senior Partner at Aon Hewitt from 2010 to 2012.
Mark C. McCullough
Executive Vice President - Generation
Age 57
Executive Vice President - Generation of AEPSC since January 2011.
Charles R. Patton
Executive Vice President - External Affairs
Age 57
Executive Vice President - External Affairs since January 2017. Was President and Chief Operating Officer of APCo from June 2010 to December 2016.
Robert P. Powers
Vice Chairman
Age 63
Vice Chairman since January 2017. Was Executive Vice President and Chief Operating Officer from November 2011 to December 2016.
Brian X. Tierney
Executive Vice President and Chief Financial Officer
Age 49
Executive Vice President and Chief Financial Officer since October 2009.
Charles E. Zebula
Executive Vice President - Energy Supply
Age 56
Executive Vice President - Energy Supply since January 2013. Was Senior Vice President - Investor Relations and Treasurer from September 2008 to December 2012.
ITEM 1A. RISK FACTORS
In addition to other disclosures within this report, including Management’s Discussion and Analysis of Financial Condition and Results of Operations, and other documents filed with the SEC from time to time, the following factors should be considered in evaluating the Registrants. Such factors could affect actual results of operations and cause results to differ substantially from those currently expected or sought. As indicated below, many of the following risk factors apply to AEP and several or all of the Registrant Subsidiaries and, accordingly, such risk factors should be read to include the applicable Registrants.
GENERAL RISKS OF REGULATED OPERATIONS AND STATE RESTRUCTURING
AEP may not be able to recover the costs of substantial planned investment in capital improvements and additions. (Applies to all Registrants)
AEP’s business plan calls for extensive investment in capital improvements and additions, including the installation of environmental upgrades and retrofits, construction of additional transmission facilities, modernizing existing infrastructure as well as other initiatives. AEP’s public utility subsidiaries currently provide service at rates approved by one or more regulatory commissions. If these regulatory commissions do not approve adjustments to the rates charged, affected AEP subsidiaries would not be able to recover the costs associated with their planned extensive investment. This would cause financial results to be diminished.
Regulated electric revenues, earnings and results are dependent on federal and state regulation that may limit AEP’s ability to recover costs and other amounts. (Applies to all Registrants)
The rates customers pay to AEP regulated utility businesses are subject to approval by the FERC and the respective state utility commissions of Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia. In certain instances, AEP’s applicable regulated utility businesses may agree to negotiated settlements related to various rate matters that are subject to regulatory approval. AEP cannot predict the ultimate outcomes of any settlements or the actions by the FERC or the respective state commissions in establishing rates.
If regulated utility earnings exceed the returns established by the relevant commissions, retail electric rates may be subject to review and possible reduction by the commissions, which may decrease future earnings. Additionally, if regulatory bodies do not allow recovery of costs incurred in providing service on a timely basis, it could reduce future net income and cash flows and negatively impact financial condition. Similarly, if recovery or other rate relief authorized in the past is overturned or reversed on appeal, future earnings could be negatively impacted. Any regulatory action or litigation outcome that triggers a reversal of a regulatory asset or deferred cost, including fuel and related costs, generally results in an impairment to the balance sheet and a charge to the income statement of the company involved. See Note 4 of the Notes to Consolidated Financial Statements entitled Rate Matters for information regarding rate proceedings.
AEP’s transmission investment strategy and execution bears certain risks associated with these activities. (Applies to all Registrants)
Management expects that a growing portion of AEP’s earnings in the future will be derived from transmission investments and activities. FERC policy currently favors the expansion and updating of the transmission infrastructure within its jurisdiction. If FERC were to adopt a different policy, if states were to limit or restrict such policies, or if transmission needs do not continue or develop as projected, AEP’s strategy of investing in transmission could be impacted. Management believes AEP’s experience with transmission facilities construction and operation gives AEP an advantage over other competitors in securing authorization to install, construct and operate new transmission lines and facilities. However, there can be no assurance that PJM, SPP or other RTOs will authorize new transmission projects or will award such projects to AEP.
In October 2016, several parties filed a joint complaint with the FERC claiming that the base return on common equity used by various AEP affiliates in calculating formula transmission rates under the PJM Open Access Transmission Tariff (OATT) is excessive and should be reduced from 10.99% to 8.32%, effective upon the date of the complaint. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition.
If the FERC were to lower the rate of return it has authorized for AEP’s transmission investments and facilities, or if one or more states were to successfully limit FERC jurisdiction on recovery of costs on transmission investment and its return, it could reduce future net income and cash flows and negatively impact financial condition.
Changes in technology and regulatory policies may lower the value of electric utility facilities and franchises. (Applies to all Registrants)
AEP primarily generates electricity at large central facilities and delivers that electricity to customers over its transmission and distribution facilities to customers usually situated within an exclusive franchise. This method results in economies of scale and generally lower costs than newer technologies such as fuel cells and microturbines, and distributed generation using either new or existing technology. Other technologies, such as light emitting diodes (LEDs), increase the efficiency of electricity and, as a result, lower the demand for it. Changes in regulatory policies and advances in batteries or energy storage, wind turbines and photovoltaic solar cells are reducing costs of new technology to levels that are making them competitive with some central station electricity production and delivery. The ability to maintain relatively low cost, efficient and reliable operations, to establish fair regulatory mechanisms and to provide cost-effective programs and services to customers are significant determinants of AEP’s competitiveness. Further, in the event that alternative generation resources are mandated, subsidized or encouraged through climate legislation or regulation or otherwise are economically competitive and added to the available generation supply, such resources could displace a higher marginal cost fossil plant, which could reduce the price at which market participants sell their electricity. This occurrence could then reduce the market price at which all generators in that region would be able to sell their output and could adversely affect AEP’s financial condition, results of operations and cash flows, which could also result in an impairment of certain long-lived assets.
AEP may not recover costs incurred to begin construction on projects that are canceled. (Applies to all Registrants)
AEP’s business plan for the construction of new projects involves a number of risks, including construction delays, nonperformance by equipment and other third party suppliers, and increases in equipment and labor costs. To limit the risks of these construction projects, AEP and its subsidiaries enter into equipment purchase orders and construction contracts and incur engineering and design service costs in advance of receiving necessary regulatory approvals and/or siting or environmental permits. If any of these projects are canceled for any reason, including failure to receive necessary regulatory approvals and/or siting or environmental permits, significant cancellation penalties under the equipment purchase orders and construction contracts could occur. In addition, if any construction work or investments have been recorded as an asset, an impairment may need to be recorded in the event the project is canceled.
AEP is exposed to nuclear generation risk. (Applies to AEP and I&M)
Through I&M, AEP owns the Cook Plant. It consists of two nuclear generating units for a rated capacity of 2,191 MWs, or about 7% of the generating capacity in the AEP System. AEP and I&M are, therefore, subject to the risks of nuclear generation, which include the following:
•
The potential harmful effects on the environment and human health due to an adverse incident/event resulting from the operation of nuclear facilities and the storage, handling and disposal of radioactive materials such as spent nuclear fuel.
•
Limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with nuclear operations.
•
Uncertainties with respect to contingencies and assessment amounts triggered by a loss event (federal law requires owners of nuclear units to purchase the maximum available amount of nuclear liability insurance and potentially contribute to the coverage for losses of others).
•
Uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives.
There can be no assurance that I&M’s preparations or risk mitigation measures will be adequate if these risks are triggered.
The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could necessitate substantial capital expenditures at nuclear plants. In addition, although management has no reason to anticipate a serious nuclear incident at the Cook Plant, if an incident did occur, it could harm results of operations or financial condition. A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or licensing of any domestic nuclear unit. Moreover, a major incident at any nuclear facility in the U.S. could require AEP or I&M to make material contributory payments.
Costs associated with the operation (including fuel), maintenance and retirement of nuclear plants continue to be more significant and less predictable than costs associated with other sources of generation, in large part due to changing regulatory requirements and safety standards, availability of nuclear waste disposal facilities and experience gained in the operation of nuclear facilities. Costs also may include replacement power, any unamortized investment at the end of the useful life of the Cook Plant (whether scheduled or premature), the carrying costs of that investment and retirement costs. The ability to obtain adequate and timely recovery of costs associated with the Cook Plant is not assured.
The different regional power markets in which AEP subsidiaries compete or will compete in the future have changing market and transmission structures, which could affect performance in these regions. (Applies to all Registrants)
Results are likely to be affected by differences in the market and transmission structures in various regional power markets. The rules governing the various regional power markets, including SPP and PJM, may also change from time to time which could affect costs or revenues. Because the manner in which RTOs will evolve remains unclear, management is unable to assess fully the impact that changes in these power markets may have on the business.
AEP could be subject to higher costs and/or penalties related to mandatory reliability standards. (Applies to all Registrants)
As a result of EPACT, owners and operators of the bulk power transmission system are subject to mandatory reliability standards promulgated by the North American Electric Reliability Corporation and enforced by the FERC. The standards are based on the functions that need to be performed to ensure the bulk power system operates reliably and are guided by reliability and market interface principles. Compliance with new reliability standards may subject AEP
to higher operating costs and/or increased capital expenditures. While management expects to recover costs and expenditures from customers through regulated rates, there can be no assurance that the applicable commissions will approve full recovery in a timely manner. If AEP were found not to be in compliance with the mandatory reliability standards, AEP could be subject to sanctions, including substantial monetary penalties, which likely would not be recoverable from customers through regulated rates.
AEP may be negatively impacted by changes in federal income tax policy. (Applies to all Registrants)
AEP is impacted by the United States federal income tax policy, including corporate income tax laws. Both the new federal administration and the Republicans in the House of Representatives have made public statements in support of comprehensive tax reform, including significant changes to the United States corporate income tax laws. Management is currently unable to predict whether these reform discussions will result in any significant changes to existing tax laws, or if any such changes would have a cumulative positive or negative impact on AEP. A reduction in the federal statutory tax rate could result in an accelerated return of deferred federal income taxes to customers. This and other changes in the United States federal income tax laws could have an adverse effect on cash flow, financial condition, and liquidity.
Collection of revenues in Texas is concentrated in a limited number of REPs. (Applies to AEP)
Revenues from the distribution of electricity in the ERCOT area of Texas are collected from REPs that supply the electricity AEP distributes to REP customers. Currently, AEP does business with approximately one hundred REPs. In 2016, AEP Texas’ largest REP accounted for 18% of its operating revenue, its second largest REP accounted for 18% of its operating revenue and its third largest REP accounted for 10% of its operating revenue. Adverse economic conditions, structural problems in the Texas market or financial difficulties of one or more REPs could impair the ability of these REPs to pay for services or cause them to delay such payments. AEP depends on these REPs for timely remittance of payments. Any delay or default in payment could reduce future cash flows and negatively impact financial condition.
RISKS RELATED TO MARKET, ECONOMIC OR FINANCIAL VOLATILITY AND OTHER RISKS
AEP’s financial performance may be adversely affected if AEP is unable to successfully operate facilities or perform certain corporate functions. (Applies to all Registrants)
Performance is highly dependent on the successful operation of generation, transmission and distribution facilities. Operating these facilities involves many risks, including:
•
Operator error and breakdown or failure of equipment or processes.
•
Operating limitations that may be imposed by environmental or other regulatory requirements.
•
Labor disputes.
•
Compliance with mandatory reliability standards, including mandatory cyber security standards.
•
Information technology failure that impairs AEP’s information technology infrastructure or disrupts normal business operations.
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Information technology failure that affects AEP’s ability to access customer information or causes loss of confidential or proprietary data that materially and adversely affects AEP’s reputation or exposes AEP to legal claims.
•
Fuel or water supply interruptions caused by transportation constraints, adverse weather such as drought, non-performance by suppliers and other factors.
•
Catastrophic events such as fires, earthquakes, explosions, hurricanes, tornados, ice storms, terrorism (including cyber-terrorism), floods or other similar occurrences.
•
Fuel costs and related requirements triggered by financial stress in the coal industry.
Physical attacks or hostile cyber intrusions could severely impair operations, lead to the disclosure of confidential information and damage AEP’s reputation. (Applies to all Registrants)
AEP and its regulated utility businesses face physical security and cybersecurity risks as the owner-operators of generation, transmission and distribution facilities and as participants in commodities trading. AEP and its regulated utility businesses own assets deemed as critical infrastructure, the operation of which is dependent on information technology systems. Further, the computer systems that run these facilities are not completely isolated from external networks. Parties that wish to disrupt the U.S. bulk power system or AEP operations could view these computer systems, software or networks as targets for cyber attack. In addition, the electric utility business requires the collection of sensitive customer data, as well as confidential employee and shareholder information, which is subject to electronic theft or loss.
A security breach of AEP or its regulated utility businesses’ physical assets or information systems, AEP’s competitors, interconnected entities in RTOs and ISOs, or regulators could impact the operation of the generation fleet and/or reliability of the transmission and distribution system or subject AEP and its regulated utility businesses to financial harm associated with theft or inappropriate release of certain types of information, including sensitive customer, vendor, employee, trading or other confidential data. A successful cyber attack on the systems that control generation, transmission, distribution or other assets could severely disrupt business operations, preventing service to customers or collection of revenues. The breach of certain business systems could affect the ability to correctly record, process and report financial information. A major cyber incident could result in significant expenses to investigate and repair security breaches or system damage and could lead to litigation, fines, other remedial action, heightened regulatory scrutiny and damage to AEP’s reputation. In addition, the misappropriation, corruption or loss of personally identifiable information and other confidential data could lead to significant breach notification expenses and mitigation expenses such as credit monitoring. For these reasons, a significant cyber incident could reduce future net income and cash flows and negatively impact financial condition.
In an effort to reduce the likelihood and severity of cyber intrusions, AEP has a comprehensive cyber security program designed to protect and preserve the confidentiality, integrity and availability of data and systems. In addition, AEP is subject to mandatory cyber security regulatory requirements. However, cyber threats continue to evolve and adapt, and, as a result, there is a risk that AEP could experience a successful cyber attack despite current security posture and regulatory compliance efforts.
If AEP is unable to access capital markets on reasonable terms, it could reduce future net income and cash flows and negatively impact financial condition. (Applies to all Registrants)
AEP relies on access to capital markets as a significant source of liquidity for capital requirements not satisfied by operating cash flows. Volatility and reduced liquidity in the financial markets could affect AEP’s ability to raise capital and fund capital needs, including construction costs and refinancing maturing indebtedness. Certain sources of debt and equity capital expressed increasing unwillingness to invest in companies, such as AEP, that rely on fossil fuels. If sources of capital for AEP disappear, capital costs could increase materially. Restricted access to capital markets and/or increased borrowing costs could reduce future net income and cash flows and negatively impact financial condition.
Downgrades in AEP’s credit ratings could negatively affect its ability to access capital and/or to operate the power trading businesses. (Applies to all Registrants)
The credit ratings agencies periodically review AEP’s capital structure and the quality and stability of earnings. Any negative ratings actions could constrain the capital available to AEP and could limit access to funding for operations. AEP’s business is capital intensive, and AEP is dependent upon the ability to access capital at rates and on terms management determines to be attractive. If AEP’s ability to access capital becomes significantly constrained, AEP’s interest costs will likely increase and could reduce future net income and cash flows and negatively impact financial condition.
AEP’s power trading business relies on the investment grade ratings of AEP’s individual public utility subsidiaries’ senior unsecured long-term debt or on the investment grade ratings of AEP. Most counterparties require the creditworthiness of an investment grade entity to stand behind transactions. If those ratings were to decline below investment grade, AEP’s ability to operate the power trading business profitably would be diminished because AEP would likely have to deposit cash or cash-related instruments which would reduce future net income and cash flows and negatively impact financial condition.
AEP has no income or cash flow apart from dividends paid or other payments due from its subsidiaries. (Applies to AEP)
AEP is a holding company and has no operations of its own. Its ability to meet its financial obligations associated with its indebtedness and to pay dividends on its common stock is primarily dependent on the earnings and cash flows of its operating subsidiaries, primarily its regulated utilities, and the ability of its subsidiaries to pay dividends to, or repay loans from, AEP. Its subsidiaries are separate and distinct legal entities that have no obligation (apart from loans from AEP) to provide AEP with funds for its payment obligations, whether by dividends, distributions or other payments. Payments to AEP by its subsidiaries are also contingent upon their earnings and business considerations. AEP indebtedness and common stock dividends are structurally subordinated to all subsidiary indebtedness.
AEP’s operating results may fluctuate on a seasonal or quarterly basis and with general economic and weather conditions. (Applies to all Registrants)
Electric power generation is generally a seasonal business. In many parts of the country, demand for power peaks during the hot summer months, with market prices also peaking at that time. In other areas, power demand peaks during the winter. As a result, overall operating results in the future may fluctuate substantially on a seasonal basis. The pattern of this fluctuation may change depending on the terms of power sale contracts that AEP enters into. In addition, AEP has historically sold less power, and consequently earned less income, when weather conditions are milder. Unusually mild weather in the future could reduce future net income and cash flows and negatively impact financial condition. In addition, unusually extreme weather conditions could impact AEP’s results of operations in a manner that would not likely be sustainable.
Further, deteriorating economic conditions generally result in reduced consumption by customers, particularly industrial customers who may curtail operations or cease production entirely, while an expanding economic environment generally results in increased revenues. As a result, prevailing economic conditions may reduce future net income and cash flows and negatively impact financial condition.
Volatility in the securities markets, interest rates, and other factors could substantially increase defined benefit pension and other postretirement plan costs and the costs of nuclear decommissioning. (Applies to all Registrants and to AEP and I&M with respect to the costs of nuclear decommissioning)
The costs of providing pension and other postretirement benefit plans are dependent on a number of factors, such as the rates of return on plan assets, discount rates, the level of interest rates used to measure the required minimum funding levels of the plan, changes in actuarial assumptions, future government regulation, changes in life expectancy, and the frequency and amount of AEP’s required or voluntary contributions made to the plans. Changes in actuarial assumptions and differences between the assumptions and actual values, as well as a significant decline in the value of investments that fund the pension and other postretirement plans, if not offset or mitigated by a decline in plan liabilities, could increase pension and other postretirement expense, and AEP could be required from time to time to fund the pension plan with significant amounts of cash. Such cash funding obligations could have a material impact on liquidity by reducing cash flows and could negatively affect results of operations. Additionally, I&M holds a significant amount of assets in its nuclear decommissioning trusts to satisfy obligations to decommission its nuclear plant. The rate of return on assets held in those trusts can significantly impact both the costs of decommissioning and the funding requirements for the trusts.
Failure to attract and retain an appropriately qualified workforce could harm results of operations. (Applies to all Registrants)
Certain events, such as an aging workforce without appropriate replacements, mismatch of skillset or complement to future needs, or unavailability of contract resources may lead to operating challenges and increased costs. The challenges include lack of resources, loss of knowledge and a lengthy time period associated with skill development. In this case, costs, including costs for contractors to replace employees, productivity costs and safety costs, may rise. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect the ability to manage and operate the business. If AEP is unable to successfully attract and retain an appropriately qualified workforce, future net income and cash flows may be reduced.
Changes in the price of commodities, emission allowances for criteria pollutants and the costs of transport may increase AEP’s cost of producing power or decrease the amount received from selling power, impacting financial performance. (Applies to all Registrants)
AEP is exposed to changes in the price and availability of coal and the price and availability to transport coal. AEP has existing contracts of varying durations for the supply of coal, but as these contracts end or if they are not honored, AEP may not be able to purchase coal on terms as favorable as the current contracts. Similarly, AEP is exposed to changes in the price and availability of emission allowances. AEP uses emission allowances based on the amount of coal used as fuel and the reductions achieved through emission controls and other measures. As long as current environmental programs remain in effect, AEP has sufficient emission allowances to cover the majority of the projected needs for the next two years and beyond. If the Federal EPA attempts to further reduce interstate transport, and it is acceptable by the courts, additional costs may be incurred either to acquire additional allowances or to achieve further reductions in emissions. If AEP needs to obtain allowances, those purchases may not be on as favorable terms as those under the current environmental programs. AEP’s risks relative to the price and availability to transport coal include the volatility of the price of diesel which is the primary fuel used in transporting coal by barge.
AEP also owns natural gas-fired facilities which exposes AEP to market prices of natural gas. Historically, natural gas prices have tended to be more volatile than prices for other fuel sources. Recently however, the availability of natural gas from shale production has lessened price volatility. AEP’s ability to make sales at a profit is highly dependent on the price of natural gas. As the price of natural gas falls, other market participants that utilize natural gas-fired generation will be able to offer electricity at increasingly competitive prices relative to AEP’s sales prices, so the margins realized from sales will be lower and, on occasion, AEP may need to curtail operation of marginal plants. Management expects the availability of shale natural gas and issues related to its accessibility will have a long-term material effect on the price and volatility of natural gas.
Prices for coal, natural gas and emission allowances have shown material swings in the past. Changes in the cost of coal, emission allowances or natural gas and changes in the relationship between such costs and the market prices of power could reduce future net income and cash flows and negatively impact financial condition.
In addition, actual power prices and fuel costs will differ from those assumed in financial projections used to value trading and marketing transactions, and those differences may be material. As a result, as those transactions are marked to market, they may impact future results of operations and cash flows and impact financial condition.
AEP is subject to physical and financial risks associated with climate change. (Applies to all Registrants)
Climate change creates physical and financial risk. Physical risks from climate change may include an increase in sea level and changes in weather conditions, such as changes in precipitation and extreme weather events. Customers’ energy needs vary with weather conditions, primarily temperature and humidity. For residential customers, heating and cooling represent their largest energy use. To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of the changes.
Increased energy use due to weather changes may require AEP to invest in additional generating assets, transmission and other infrastructure to serve increased load. Decreased energy use due to weather changes may affect financial condition through decreased revenues. Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system stress, including service interruptions. Weather conditions outside of the AEP service territory could also have an impact on revenues. AEP buys and sells electricity depending upon system needs and market opportunities. Extreme weather conditions creating high energy demand on AEP’s own and/or other systems may raise electricity prices as AEP buys short-term energy to serve AEP’s own system, which would increase the cost of energy AEP provides to customers.
Severe weather impacts AEP’s service territories, primarily when thunderstorms, tornadoes, hurricanes, floods and snow or ice storms occur. To the extent the frequency of extreme weather events increases, this could increase AEP’s cost of providing service. Changes in precipitation resulting in droughts, water shortages or floods could adversely affect operations, principally the fossil fuel generating units. A negative impact to water supplies due to long-term drought conditions or severe flooding could adversely impact AEP’s ability to provide electricity to customers, as well as increase the price they pay for energy. AEP may not recover all costs related to mitigating these physical and financial risks.
To the extent climate change impacts a region’s economic health, it may also impact revenues. AEP’s financial performance is tied to the health of the regional economies AEP serves. The price of energy, as a factor in a region’s cost of living as well as an important input into the cost of goods and services, has an impact on the economic health of the communities within the AEP System.
Management cannot predict the outcome of the legal proceedings relating to AEP’s business activities. (Applies to all Registrants)
AEP is involved in legal proceedings, claims and litigation arising out of its business operations, the most significant of which are summarized in Note 6 of the Notes to Financial Statements entitled Commitments, Guarantees and Contingencies. Adverse outcomes in these proceedings could require significant expenditures that could reduce future net income and cash flows and negatively impact financial condition.
RISKS RELATED TO OWNING AND OPERATING GENERATION ASSETS AND SELLING POWER
Costs of compliance with existing environmental laws are significant. (Applies to all Registrants)
Operations are subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, natural resources and health and safety. Approximately 82% of the electricity generated by the AEP System is produced by the combustion of fossil fuels. Emissions of nitrogen and sulfur oxides, mercury and particulates from fossil fueled generation plants are subject to increased regulations, controls and mitigation expenses. Compliance with these legal requirements requires AEP to commit significant capital toward environmental monitoring, installation of pollution control equipment, emission fees and permits at all AEP facilities and could cause AEP to retire generating capacity prior to the end of its estimated useful life. These expenditures have been significant in the past, and management expects that they will continue to be significant in order to comply with the current and proposed regulations. Costs of compliance with environmental regulations could reduce future net income and negatively impact financial condition, especially if emission and/or discharge limits are tightened, more extensive permitting requirements are imposed or additional substances become regulated. Although AEP typically recovers expenditures for pollution control technologies, replacement generation, undepreciated plant balances and associated operating costs from customers through regulated rates in regulated jurisdictions, there can be no assurance that AEP will recover the remaining costs associated with such plants. Failure to recover these costs could reduce future net income and cash flows and possibly harm financial condition. For AEP’s sales of energy from competitive units, there is no such cost-recovery mechanism. As a result, AEP may not recover costs through the market and may be forced to shut competitive units down. The costs of compliance for AEP’s competitive units could reduce future net income and cash flows and possibly harm financial condition.
Regulation of CO2 emissions could materially increase costs to AEP and its customers or cause some electric generating units to be uneconomical to operate or maintain. (Applies to all Registrants)
In 2014, the Federal EPA issued standards for new, modified and reconstructed units, and a guideline for the development
of state implementation plans that would reduce carbon emissions from existing utility units. The standards and guidelines were finalized in 2015, and have been challenged by several dozen states as well as industry groups and other stakeholders. The U.S. Supreme Court has stayed the implementation of the guidelines for existing sources, known as the Clean Power Plan, until a final decision is issued by the courts.
CO2 standards could require significant increases in capital expenditures and operating costs and could impact the dates for retirement of AEP’s coal-fired units. AEP typically recovers costs of complying with new requirements such as the potential CO2 and other greenhouse gases emission standards from customers through regulated rates in regulated jurisdictions. For AEP’s sales of energy into the markets, however, there is no such recovery mechanism. Failure to recover these costs, should they arise, could reduce future net income and cash flows and possibly harm financial condition.
Courts adjudicating nuisance and other similar claims in the future may order AEP to pay damages or to limit or reduce emissions. (Applies to all Registrants)
In the past, there have been several cases seeking damages based on allegations of federal and state common law nuisance in which AEP, among others, were defendants. In general, the actions allege that emissions from the defendants’ power plants constitute a public nuisance. The plaintiffs in these actions generally seek recovery of damages and other relief. If future actions are resolved against AEP, substantial modifications of AEP’s existing coal-fired power plants could be required and AEP might be required to limit or reduce emissions. Such remedies could require AEP to purchase power from third parties to fulfill AEP’s commitments to supply power to AEP customers. This could have a material impact on costs. In addition, AEP could be required to invest significantly in additional emission control equipment, accelerate the timing of capital expenditures, pay damages or penalties and/or halt operations. While management believes such costs should be recoverable from customers as costs of doing business in AEP jurisdictions where generation rates are set on a cost of service basis, without such recovery, those costs could reduce future net income and cash flows and harm financial condition. Moreover, results of operations and financial position could be reduced due to the timing of recovery of these investments and the expense of ongoing litigation.
AEP’s results of operations and cash flows may be negatively affected by a lack of growth or slower growth in the number of customers, or decline in customer demand or number of customers. (Applies to all Registrants)
Growth in customer accounts and growth of customer usage each directly influence demand for electricity and the need for additional power generation and delivery facilities. Customer growth and customer usage are affected by a number of factors outside the control of AEP, such as mandated energy efficiency measures, demand-side management goals, distributed generation resources and economic and demographic conditions, such as population changes, job and income growth, housing starts, new business formation and the overall level of economic activity.
Certain regulatory and legislative bodies have introduced or are considering requirements and/or incentives to further reduce energy consumption. Additionally, technological advances or other improvements in or applications of technology could lead to declines in per capita energy consumption. Some or all of these factors, could impact the demand for electricity.
Profitability is impacted by AEP’s continued authorization to sell power at market-based rates. (Applies to all Registrants)
FERC has granted AGR, APCo, I&M, KPCo, OPCo, PSO and SWEPCo authority to sell electricity at market-based rates. FERC reserves the right to revoke or revise this market-based rate authority if it subsequently determines that one or more of these companies can exercise market power in transmission or generation, create barriers to entry or engage in abusive affiliate transactions. Each company that has obtained market-based rate authority from FERC must file a market power update every three years to show that they continue to meet FERC’s standards with respect to generation market power and other criteria used to evaluate whether entities qualify for market-based rates. The loss of market-based rate authority by any of these entities, especially by AGR, could have a material adverse effect on results of operations.
Revenues and results of operations from selling power are subject to market risks that are beyond AEP’s control. (Applies to all Registrants)
AEP sells power from its generation facilities into the spot market and other competitive power markets on a contractual basis. AEP also enters into contracts to purchase and sell electricity, natural gas, emission allowances and coal as part of its power marketing and energy trading operations. With respect to such transactions, the rate of return on capital investments is not determined through mandated rates, and revenues and results of operations are likely to depend, in large part, upon prevailing market prices for power in regional markets and competitive markets. These market prices can fluctuate substantially over relatively short periods of time. Sales margins may erode as markets mature and there may be diminished opportunities for gain should volatility decline. In addition, the FERC, which has jurisdiction over wholesale power rates, as well as RTOs that oversee some of these markets, may impose price limitations, bidding rules and other mechanisms in these markets. Power supply and other similar agreements entered into during extreme market conditions may subsequently be held to be unenforceable by a reviewing court or the FERC. Fuel and emissions prices may also be volatile, and the price AEP can obtain for power sales may not change at the same rate as changes in fuel and/or emissions costs. These factors could reduce margins and therefore diminish revenues and results of operations. Volatility in market prices for fuel and power may result from:
•
Weather conditions, including storms.
•
Economic conditions.
•
Outages of major generation or transmission facilities.
•
Seasonality.
•
Power usage.
•
Illiquid markets.
•
Transmission or transportation constraints or inefficiencies.
•
Availability of competitively priced alternative energy sources.
•
Demand for energy commodities.
•
Natural gas, crude oil and refined products and coal production levels.
•
Natural disasters, wars, embargoes and other catastrophic events.
•
Federal, state and foreign energy and environmental regulation and legislation and/or incentives.
•
RTO market structures.
Commodity trading and marketing activities are subject to inherent risks which can be reduced and controlled but not eliminated. (Applies to all Registrants)
The exposure of AEP’s power trading activities is managed by establishing and enforcing risk limits and risk management procedures. These risk limits and risk management procedures may not work as planned and cannot eliminate the risks associated with these activities. As a result, management cannot predict the impact that AEP’s energy trading and risk management decisions may have on AEP’s business, operating results or financial position.
AEP routinely has open trading positions in the market, within guidelines set by AEP, resulting from the management of AEP’s trading portfolio. To the extent open trading positions exist, fluctuating commodity prices can improve or diminish financial results and financial position.
AEP’s power trading risk management activities, including power sales agreements with counterparties, rely on projections that depend heavily on judgments and assumptions by management of factors such as the future market prices and demand for power and other energy-related commodities. These factors become more difficult to predict and the calculations become less reliable the further into the future these estimates are made. Even when policies and procedures are followed and decisions are made based on these estimates, results of operations may be impacted if the judgments and assumptions underlying those calculations prove to be inaccurate.
AEP’s power trading activities also expose AEP to risks of commodity price movements. To the extent that AEP’s power trading does not hedge the price risk associated with the generation it owns, or controls, AEP would be exposed to the risk of rising and falling spot market prices.
In connection with these trading activities, AEP routinely enters into financial contracts, including futures and options, over-the counter options, financially-settled swaps and other derivative contracts. These activities expose AEP to risks from price movements. If the values of the financial contracts change in a manner AEP does not anticipate, it could harm financial position or reduce the financial contribution of trading operations.
Parties with whom AEP has contracts may fail to perform their obligations, which could harm AEP’s results of operations. (Applies to all Registrants)
AEP is exposed to the risk that counterparties that owe AEP money or power could breach their obligations. Should the counterparties to these arrangements fail to perform, AEP may be forced to enter into alternative hedging arrangements or honor underlying commitments at then-current market prices that may exceed AEP’s contractual prices, which would cause financial results to be diminished and AEP might incur losses. Although estimates take into account the expected probability of default by a counterparty, actual exposure to a default by a counterparty may be greater than the estimates predict.
AEP relies on electric transmission facilities that AEP does not own or control. If these facilities do not provide AEP with adequate transmission capacity, AEP may not be able to deliver wholesale electric power to the purchasers of AEP’s power. (Applies to all Registrants)
AEP depends on transmission facilities owned and operated by other nonaffiliated power companies to deliver the power AEP sells at wholesale. This dependence exposes AEP to a variety of risks. If transmission is disrupted, or transmission capacity is inadequate, AEP may not be able to sell and deliver AEP wholesale power. If a region’s power transmission infrastructure is inadequate, AEP’s recovery of wholesale costs and profits may be limited. If restrictive transmission price regulation is imposed, the transmission companies may not have sufficient incentive to invest in expansion of transmission infrastructure.
The FERC has issued electric transmission initiatives that require electric transmission services to be offered unbundled from commodity sales. Although these initiatives are designed to encourage wholesale market transactions, access to transmission systems may not be available if transmission capacity is insufficient because of physical constraints or because it is contractually unavailable. Management also cannot predict whether transmission facilities will be expanded in specific markets to accommodate competitive access to those markets.
OVEC may require additional liquidity and other capital support. (Applies to AEP, APCo, I&M and OPCo)
AEP and several nonaffiliated utility companies own OVEC. The Inter-Company Power Agreement (ICPA) defines the rights and obligations and sets the power participation ratio of the parties to it. Under the ICPA, parties are entitled to receive and are obligated to pay for all OVEC capacity (approximately 2,400 MW) in proportion to their respective power participation ratios. The aggregate power participation ratio of APCo, I&M and OPCo is 43.47%. If a party fails to make payments owed by it under the ICPA, OVEC may not have sufficient funds to honor its payment obligations, including its ongoing operating expenses as well as its indebtedness. OVEC has outstanding indebtedness of approximately $1.5 billion.
Recently, a nonaffiliated party to the ICPA announced its intention to exit its merchant business and that it may pursue restructuring or bankruptcy. This party’s aggregate power participation ratio is approximately 8% under the ICPA. As a result of this announcement and other related developments, Moody’s downgraded OVEC’s rating and left them on negative outlook for possible downgrade, Fitch revised OVEC’s outlook to negative, while S&P affirmed OVEC’s rating and stable outlook.
If OVEC does not have sufficient funds to honor its payment obligations, there is risk that APCo, I&M and/or OPCo may need to make payments in addition to their power participation ratio payments. Further, if OVEC’s indebtedness is accelerated for any reason, there is risk that APCo, I&M and/or OPCo may be required to pay some or all of such accelerated indebtedness in amounts equal to their aggregate power participation ratio of 43.47%. Also, as a result of the Moody’s and Fitch actions, OVEC’s ability to access capital markets on terms as favorable as previously may diminish and its financing costs may rise.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2. PROPERTIES
GENERATION FACILITIES
As of December 31, 2016 the AEP System owned (or leased where indicated) generation plants, all situated in the states in which AEP’s electric utilities serve retail customers, where applicable, with net maximum power capabilities (winter rating) shown in the following tables:
Vertically Integrated Utilities Segment
(a)
Rockport, Unit 2 is leased.
(b)
The capacity and output of this plant was under contract to (and its financial impact was included with) AGR. The contract was terminated as a result of the sale of Lawrenceburg in January 2017.
(a)
In 2016, Clinch River, Units 1 and 2 boilers were converted to natural gas.
NA Not applicable.
(a)
Rockport, Unit 2 is leased.
The following table provides operating information related to the Cook Plant:
(a)
In 2016, Big Sandy, Unit 1 boiler was converted to natural gas.
(b)
KPCo owns a 50% interest in the Mitchell Units. WPCo owns the remaining 50%. Figures presented reflect only the portion owned by KPCo.
(a)
Northeastern, Unit 4 was retired in April 2016.
(b)
Jointly-owned with AEP Texas and non-affiliated entities. Figures presented reflect only the portion owned by PSO.
(a)
Jointly-owned with nonaffiliated entity(ies). Figures presented reflect only the portion owned by SWEPCo. The Arkansas jurisdictional portion of SWEPCo’s interest in Turk is not in rate base.
(b)
Welsh, Unit 2 was retired in April 2016.
WPCo
Plant Name
Units
State
Fuel Type
Net Maximum
Capacity (MWs)
Year Plant
or First Unit Commissioned
Mitchell (a)
WV
Steam - Coal
Total MWs
(a)
A portion of WPCo’s interest in the Mitchell Units is not in rate base. KPCo owns the remaining 50%. Figures presented reflect only the portion owned by WPCo.
Generation & Marketing Segment
(a)
Darby, Waterford and Gavin Plants were sold to an unaffiliated party in January 2017.
(b)
Jointly-owned with nonaffiliated entities, one of which has announced its intention to close its unit in 2018. Figures presented reflect only the portion owned by AGR.
(c)
AGR had contractual rights to a natural gas-fired 1,186 MW generating unit located in Lawrenceburg, IN. The contract was terminated when the Lawrenceburg plant was sold in January 2017.
(d)
In February 2017, AEP signed an agreement to purchase Dynegy Corporation’s ownership share of Conesville Plant Unit 4. Simultaneously, AEP signed an agreement with Dynegy Corporation to sell AEP’s ownership share of the Zimmer Plant. The transactions are expected to close in the second quarter of 2017, subject to FERC approval and are not expected to have a material impact on net income, cash flows and financial condition.
In 2016, AEP Generation & Marketing segment contracted 26 MWs of solar power in Utah and 16 MWs of solar power in the states of Hawaii, Ohio, Minnesota, New Hampshire, New York and Vermont.
In addition to the AGR and Domestic Independent Power generation set forth above, a subsidiary in the Generation & Marketing segment has contractual rights through 2027 from AEP Texas to 355 MWs from the Oklaunion Generating Plant, a coal-fired unit located in Vernon, TX. AEP Texas co-owns the Oklaunion Generating Plant with PSO and several non-affiliated entities.
TRANSMISSION AND DISTRIBUTION FACILITIES
The following tables set forth the total overhead circuit miles of transmission and distribution lines of the AEP System and its operating companies.
Vertically Integrated Utilities Segment
Transmission and Distribution Utilities Segment
AEP Transmission Holdco Segment
The following table sets forth the total overhead circuit miles of transmission lines of certain wholly-owned and joint venture-owned entities:
TITLE TO PROPERTY
The AEP System’s generating facilities are generally located on lands owned in fee simple. The greater portion of the transmission and distribution lines of the AEP System has been constructed over lands of private owners pursuant to easements or along public highways and streets pursuant to appropriate statutory authority. The rights of AEP’s public utility subsidiaries in the realty on which their facilities are located are considered adequate for use in the conduct of their business. Minor defects and irregularities customarily found in title to properties of like size and character may exist, but such defects and irregularities do not materially impair the use of the properties. AEP’s public utility subsidiaries generally have the right of eminent domain which permits them, if necessary, to acquire, perfect or secure titles to or easements on privately held lands used or to be used in their utility operations. Legislation in Ohio and Virginia has restricted the right of eminent domain previously granted for power generation purposes.
SYSTEM TRANSMISSION LINES AND FACILITY SITING
Laws in the states of Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Tennessee, Texas, Virginia and West Virginia require prior approval of sites of generating facilities and/or routes of high-voltage transmission lines. AEP has experienced delays and additional costs in constructing facilities as a result of proceedings conducted pursuant to such statutes and in proceedings in which AEP’s operating companies have sought to acquire rights-of-way through condemnation. These proceedings may result in additional delays and costs in future years.
CONSTRUCTION PROGRAM
With input from its state utility commissions, the AEP System continuously assesses the adequacy of its transmission, distribution, generation and other facilities to plan and provide for the reliable supply of electric power and energy to its customers. In this assessment process, assumptions are continually being reviewed as new information becomes available and assessments and plans are modified, as appropriate. AEP forecasts approximately $5.7 billion of construction expenditures for 2017. Estimated construction expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends, weather and the ability to access capital. For additional information on AEP’s construction program, see Management’s Discussion and Analysis of Financial Condition and Results of Operations, included in the 2016 Annual Reports, under the heading entitled Budgeted Construction Expenditures.
POTENTIAL UNINSURED LOSSES
Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including liabilities relating to damage to AEP’s generation plants and costs of replacement power. Unless allowed to be recovered through rates, future losses or liabilities which are not completely insured could reduce net income and impact the financial conditions of AEP and other AEP System companies. For risks related to owning a nuclear generating unit, see Note 6 to the financial statements entitled Commitments, Guarantees and Contingencies under the heading Nuclear Contingencies for information with respect to nuclear incident liability insurance.
ITEM 3. LEGAL PROCEEDINGS
For a discussion of material legal proceedings, see Note 6 to the financial statements, entitled Commitments, Guarantees and Contingencies, incorporated by reference in Item 8.
ITEM 4. MINE SAFETY DISCLOSURE
The Federal Mine Safety and Health Act of 1977 (Mine Act) imposes stringent health and safety standards on various mining operations. The Mine Act and its related regulations affect numerous aspects of mining operations, including training of mine personnel, mining procedures, equipment used in mine emergency procedures, mine plans and other matters. SWEPCo, through its ownership of Dolet Hills Lignite Company (DHLC), a wholly-owned lignite mining subsidiary of SWEPCo, is subject to the provisions of the Mine Act.
The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) requires companies that operate mines to include in their periodic reports filed with the SEC, certain mine safety information covered by the Mine Act. Exhibit 95 “Mine Safety Disclosure Exhibit” contains the notices of violation and proposed assessments received by DHLC under the Mine Act for the quarter ended December 31, 2016.
PART II
ITEM 5. MARKET FOR REGISTRANTS’ COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
AEP
In addition to the discussion below, the remaining information required by this item is incorporated herein by reference to the material under AEP Common Stock and Dividend Information and Note 14 to the financial statements entitled Financing Activities under the heading Dividend Restrictions in the 2016 Annual Report.
APCo, I&M, OPCo, PSO and SWEPCo
The common stock of these companies is held solely by AEP. The information regarding the amounts of cash dividends on common stock paid by these companies to AEP during 2016, 2015 and 2014 are incorporated by reference to the material under Statements of Changes in Common Shareholder’s Equity and Note 14 to the financial statements entitled Financing Activities under the heading Dividend Restrictions in the 2016 Annual Reports.
During the quarter ended December 31, 2016, neither AEP nor its publicly-traded subsidiaries purchased equity securities that are registered by AEP or its publicly-traded subsidiaries pursuant to Section 12 of the Exchange Act.
ITEM 6. SELECTED FINANCIAL DATA
AEP
The information required by this item is incorporated herein by reference to the material under Selected Consolidated Financial Data in the 2016 Annual Reports.
APCo, I&M, OPCo, PSO and SWEPCo
Omitted pursuant to Instruction I(2)(a). Management’s narrative analysis of the results of operations and other information required by Instruction I(2)(a) is incorporated herein by reference to the material under Management’s Discussion and Analysis of Financial Condition and Results of Operations in the 2016 Annual Reports.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
AEP
The information required by this item is incorporated herein by reference to the material under Management’s Discussion and Analysis of Financial Condition and Results of Operations in the 2016 Annual Reports.
APCo, I&M, OPCo, PSO and SWEPCo
Omitted pursuant to Instruction I(2)(a). Management’s narrative analysis of the results of operations and other information required by Instruction I(2)(a) is incorporated herein by reference to the material under Management’s Discussion and Analysis of Financial Condition and Results of Operations in the 2016 Annual Reports.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
AEP, APCo, I&M, OPCo, PSO and SWEPCo
The information required by this item is incorporated herein by reference to the material under Management’s Discussion and Analysis of Financial Condition and Results of Operations - Quantitative and Qualitative Disclosures about Market Risk in the 2016 Annual Reports.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
AEP, APCo, I&M, OPCo, PSO and SWEPCo
The information required by this item is incorporated herein by reference to the financial statements and financial statement schedules described under Item 15 herein.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
AEP, APCo, I&M, OPCo, PSO and SWEPCo
Information required by this item is set forth under the caption Proposal to Ratify the Appointment of the Independent Registered Public Accounting Firm in the 2017 Proxy Statement, which is incorporated by reference into this item.
ITEM 9A. CONTROLS AND PROCEDURES
During 2016, management, including the principal executive officer and principal financial officer of each of American Electric Power Company, Inc. (“AEP”), Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company (each a “Registrant” and collectively the “Registrants”) evaluated each respective Registrant’s disclosure controls and procedures. Disclosure controls and procedures are defined as controls and other procedures of the Registrant that are designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act are recorded, processed, summarized, and reported within the time periods specified in the Commission’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act is accumulated and communicated to each Registrant’s management, including the principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.
As of December 31, 2016, these officers concluded that the disclosure controls and procedures in place are effective and provide reasonable assurance that the disclosure controls and procedures accomplished their objectives. The Registrants continually strive to improve their disclosure controls and procedures to enhance the quality of their financial reporting and to maintain dynamic systems that change as events warrant.
There have been no changes in the Registrants’ internal control over financial reporting (as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the fourth quarter 2016 that materially affected, or is reasonably likely to materially affect, the Registrants’ internal control over financial reporting.
Management assessed and reported on the effectiveness of its internal control over financial reporting as of December 31, 2016. As a result of that assessment, management determined that there were no material weaknesses as of December 31, 2016 and, therefore, concluded that each Registrant’s internal control over financial reporting was effective.
Additional information required by this item of the Registrants is incorporated by reference to Management’s Report on Internal Control over Financial Reporting, included in the 2016 Annual Report of each Registrant.
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
APCo, I&M, OPCo, PSO and SWEPCo
Omitted pursuant to Instruction I(2)(c).
AEP
Directors, Director Nomination Process and Audit Committee
Certain of the information called for in this Item 10, including the information relating to directors, is incorporated herein by reference to AEP’s definitive proxy information statement (which will be filed with the SEC pursuant to Regulation 14A under the Exchange Act) relating to 2017 Annual Meeting of Shareholders (the 2017 Annual Meeting) including under the captions “Election of Directors,” “Section 16(a) Beneficial Ownership Reporting Compliance,” “AEP’s Board of Directors and Committees,” “Directors” and “Shareholder Nominees for Directors.”
Executive Officers
Reference also is made to the information under the caption Executive Officers of AEP in Part I, Item 1 of this report.
Code of Ethics
AEP’s Principles of Business Conduct is the code of ethics that applies to AEP’s Chief Executive Officer, Chief Financial Officer and principal accounting officer. The Principles of Business Conduct is available on AEP’s website at www.aep.com. The Principles of Business Conduct will be made available, without charge, in print to any shareholder who requests such document from Investor Relations, American Electric Power Company, Inc., 1 Riverside Plaza, Columbus, Ohio 43215.
If any substantive amendments to the Principles of Business Conduct are made or any waivers are granted, including any implicit waiver, from a provision of the Principles of Business Conduct, to its Chief Executive Officer, Chief Financial Officer or principal accounting officer, AEP will disclose the nature of such amendment or waiver on AEP’s website, www.aep.com, or in a report on Form 8-K.
Section 16(a) Beneficial Ownership Reporting Compliance
The information required by this item is incorporated herein by reference to information contained in the definitive proxy statement of AEP for the 2017 Annual Meeting.
ITEM 11. EXECUTIVE COMPENSATION
APCo, I&M, OPCo, PSO and SWEPCo
Omitted pursuant to Instruction I(2)(c).
AEP
The information called for by this Item 11 is incorporated herein by reference to AEP’s definitive proxy statement (which will be filed with the SEC pursuant to Regulation 14A under the Exchange Act) relating to the 2017 Annual Meeting including under the captions “Compensation Discussion and Analysis,” “Executive Compensation”, “Director Compensation” and “2016 Director Compensation Table”. The information set forth under the subcaption “Human Resources Committee Report” and “Audit Committee Report” should not be deemed filed nor should it be incorporated by reference into any other filing under the Securities Act of 1933, as amended, or the Exchange Act except to the extent AEP specifically incorporates such report by reference therein.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
APCo, I&M, OPCo, PSO and SWEPCo
Omitted pursuant to Instruction I(2)(c).
AEP
The information relating to Security Ownership of Certain Beneficial Owners is incorporated herein by reference to AEP’s definitive proxy statement (which will be filed with the SEC pursuant to Regulation 14A under the Exchange Act) relating to 2017 Annual Meeting under the caption “Share Ownership of Certain Beneficial Owners and Management” and “Share Ownership of Directors and Executive Officers.”
EQUITY COMPENSATION PLAN INFORMATION
The following table summarizes the ability of AEP to issue common stock pursuant to equity compensation plans as of December 31, 2016:
NA Not applicable.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
APCo, I&M, OPCo, PSO and SWEPCo
Omitted pursuant to Instruction I(2)(c).
AEP
The information called for by this Item 13 is incorporated herein by reference to AEP’s definitive proxy statement (which will be filed with the SEC pursuant to Regulation 14A under the Exchange Act) relating to the 2017 Annual Meeting under the captions “Transactions with Related Persons” and “Director Independence.”
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
AEP
The information called for by this Item 14 is incorporated herein by reference to AEP’s definitive proxy statement (which will be filed with the SEC pursuant to Regulation 14A under the Exchange Act) relating to the 2017 Annual Meeting under the captions “Audit and Non-Audit Fees,” “Audit Committee Report” and “Policy on Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of the Independent Auditor.”
APCo, I&M, OPCo, PSO and SWEPCo
Each of the above is a wholly-owned subsidiary of AEP and does not have a separate audit committee. A description of the AEP Audit Committee pre-approval policies, which apply to these companies, is contained in the definitive proxy statement of AEP for the 2017 Annual Meeting of shareholders. The following table presents directly billed fees for professional services rendered by Deloitte & Touche LLP for the audit of these companies’ annual financial statements for the years ended December 31, 2016 and 2015, and fees directly billed for other services rendered by Deloitte & Touche LLP during those periods. Deloitte & Touche LLP also provides additional professional and other services to the AEP System, the cost of which may ultimately be allocated to these companies though not billed directly to them. For a description of these fees and services, see the description of principal accounting fees and services for AEP, above.
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
The following documents are filed as a part of this report:
1.
FINANCIAL STATEMENTS:
The following financial statements have been incorporated herein by reference pursuant to Item 8.
AEP and Subsidiary Companies:
Reports of Independent Registered Public Accounting Firm; Management’s Report on Internal Control over Financial Reporting; Consolidated Statements of Income for the years ended December 31, 2016, 2015 and 2014; Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2016, 2015 and 2014; Consolidated Statements of Changes in Equity for the years ended December 31, 2016, 2015 and 2014; Consolidated Balance Sheets as of December 31, 2016 and 2015; Consolidated Statements of Cash Flows for the years ended December 31, 2016, 2015 and 2014; Notes to Financial Statements of Registrants.
APCo, I&M and OPCo:
Consolidated Statements of Income for the years ended December 31, 2016, 2015 and 2014; Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2016, 2015 and 2014; Consolidated Statements of Changes in Common Shareholder’s Equity for the years ended December 31, 2016, 2015 and 2014; Consolidated Balance Sheets as of December 31, 2016 and 2015; Consolidated Statements of Cash Flows for the years ended December 31, 2016, 2015 and 2014; Notes to Financial Statements of Registrants; Report of Independent Registered Public Accounting Firm; Management’s Report on Internal Control over Financial Reporting.
PSO:
Statements of Income for the years ended December 31, 2016, 2015 and 2014; Statements of Comprehensive Income (Loss) for the years ended December 31, 2016, 2015 and 2014; Statements of Changes in Common Shareholder’s Equity for the years ended December 31, 2016, 2015 and 2014; Balance Sheets as of December 31, 2016 and 2015; Statements of Cash Flows for the years ended December 31, 2016, 2015 and 2014; Notes to Financial Statements of Registrants; Report of Independent Registered Public Accounting Firm; Management’s Report on Internal Control over Financial Reporting.
SWEPCo:
Consolidated Statements of Income for the years ended December 31, 2016, 2015 and 2014; Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2016, 2015 and 2014; Consolidated Statements of Changes in Equity for the years ended December 31, 2016, 2015 and 2014; Consolidated Balance Sheets as of December 31, 2016 and 2015; Consolidated Statements of Cash Flows for the years ended December 31, 2016, 2015 and 2014; Notes to Financial Statements of Registrants; Report of Independent Registered Public Accounting Firm; Management’s Report on Internal Control over Financial Reporting.
2. FINANCIAL STATEMENT SCHEDULES:
Page Number
Financial Statement Schedules are listed in the Index of Financial Statement Schedules. (Certain schedules have been omitted because the required information is contained in the notes to financial statements or because such schedules are not required or are not applicable). Reports of Independent Registered Public Accounting Firm.
S-1
3. EXHIBITS:
Exhibits for AEP, APCo, I&M, OPCo, PSO and SWEPCo are listed in the Exhibit Index beginning on page E-1 and are incorporated herein by reference.
E-1
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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.
American Electric Power Company, Inc.
By:
/s/ Brian X. Tierney
(Brian X. Tierney, Executive Vice President
and Chief Financial Officer)
Date: February 22, 2017
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.
Signature
Title
Date
(i)
Principal Executive Officer:
/s/ Nicholas K. Akins
Chairman of the Board,
Chief Executive Officer and Director
February 22, 2017
(Nicholas K. Akins)
(ii)
Principal Financial Officer:
/s/ Brian X. Tierney
Executive Vice President and Chief Financial Officer
February 22, 2017
(Brian X. Tierney)
(iii)
Principal Accounting Officer:
/s/ Joseph M. Buonaiuto
Senior Vice President, Controller and Chief Accounting Officer
February 22, 2017
(Joseph M. Buonaiuto)
(iv)
A Majority of the Directors:
*Nicholas K. Akins
*David J. Anderson
*J. Barnie Beasley, Jr.
*Ralph D. Crosby, Jr.
*Linda A. Goodspeed
*Thomas E. Hoaglin
*Sandra Beach Lin
*Richard C. Notebaert
*Lionel L. Nowell, III
*Stephen S. Rasmussen
*Oliver G. Richard, III
*Sara Martinez Tucker
*By:
/s/ Brian X. Tierney
February 22, 2017
(Brian X. Tierney, Attorney-in-Fact)
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
Appalachian Power Company
Ohio Power Company
Public Service Company of Oklahoma
Southwestern Electric Power Company
By:
/s/ Brian X. Tierney
(Brian X. Tierney, Executive Vice President and Chief Financial Officer)
Date: February 22, 2017
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. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
Signature
Title
Date
(i)
Principal Executive Officer:
/s/ Nicholas K. Akins
Chairman of the Board, Chief Executive Officer and Director
February 22, 2017
(Nicholas K. Akins)
(ii)
Principal Financial Officer:
/s/ Brian X. Tierney
Vice President, Chief Financial Officer and Director
February 22, 2017
(Brian X. Tierney)
(iii)
Principal Accounting Officer:
/s/ Joseph M. Buonaiuto
Controller and Chief Accounting Officer
February 22, 2017
(Joseph M. Buonaiuto)
(iv)
A Majority of the Directors:
*Nicholas K. Akins
*Lisa M. Barton
*Paul Chodak III
*David M. Feinberg
*Lana L. Hillebrand
*Mark C. McCullough
*Charles R. Patton
*Robert P. Powers
Brian X. Tierney
*By:
/s/ Brian X. Tierney
February 22, 2017
(Brian X. Tierney, Attorney-in-Fact)
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
Indiana Michigan Power Company
By:
/s/ Brian X. Tierney
(Brian X. Tierney, Executive Vice President
and Chief Financial Officer)
Date: February 22, 2017
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. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
Signature
Title
Date
(i)
Principal Executive Officer:
/s/ Nicholas K. Akins
Chairman of the Board, Chief Executive Officer and Director
February 22, 2017
(Nicholas K. Akins)
(ii)
Principal Financial Officer:
/s/ Brian X. Tierney
Vice President, Chief Financial Officer and Director
February 22, 2017
(Brian X. Tierney)
(iii)
Principal Accounting Officer:
/s/ Joseph M. Buonaiuto
Controller and Chief Accounting Officer
February 22, 2017
(Joseph M. Buonaiuto)
(iv)
A Majority of the Directors:
*Nicholas K. Akins
*Lisa M. Barton
*Nicholas M. Elkins
*Thomas A. Kratt
*Marc E. Lewis
*David A. Lucas
*Mark C. McCullough
*Robert P. Powers
*Carla E. Simpson
*Toby L. Thomas
Brian X. Tierney
*By:
/s/ Brian X. Tierney
February 22, 2017
(Brian X. Tierney, Attorney-in-Fact)
INDEX OF FINANCIAL STATEMENT SCHEDULES
S-1
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
American Electric Power Company, Inc.:
We have audited the consolidated financial statements of American Electric Power Company, Inc. and subsidiary companies (the “Company”) as of December 31, 2016 and 2015, and for each of the three years in the period ended December 31, 2016, and the Company's internal control over financial reporting as of December 31, 2016, and have issued our reports thereon dated February 27, 2017; such consolidated financial statements and reports are included in the Company’s 2016 Annual Report and are incorporated herein by reference. Our audits also included the financial statement schedules of the Company listed in Item 15. These financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
/s/ Deloitte & Touche LLP
Columbus, Ohio
February 27, 2017
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of
Appalachian Power Company
Indiana Michigan Power Company
Ohio Power Company
Public Service Company of Oklahoma
Southwestern Electric Power Company
We have audited the financial statements of Appalachian Power Company and subsidiaries, Indiana Michigan Power Company and subsidiaries, Ohio Power Company and subsidiaries, Public Service Company of Oklahoma, and Southwestern Electric Power Company and subsidiaries (collectively the “Companies”) as of December 31, 2016 and 2015, and for each of the three years in the period ended December 31, 2016, and have issued our reports thereon dated February 27, 2017; such financial statements and reports are included in the Companies’ 2016 Annual Reports and are incorporated herein by reference. Our audits also included the financial statement schedule of each of the Companies listed in Item 15. These financial statement schedules are the responsibility of the Companies’ management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
/s/ Deloitte & Touche LLP
Columbus, Ohio
February 27, 2017
S-2
SCHEDULE I
AMERICAN ELECTRIC POWER COMPANY, INC. (Parent)
CONDENSED FINANCIAL INFORMATION
CONDENSED STATEMENTS OF INCOME
For the Years Ended December 31, 2016, 2015 and 2014
(in millions, except per-share and share amounts)
See Condensed Notes to Condensed Financial Information beginning on page S-7.
S-3
SCHEDULE I
AMERICAN ELECTRIC POWER COMPANY, INC. (Parent)
CONDENSED FINANCIAL INFORMATION
CONDENSED BALANCE SHEETS
ASSETS
December 31, 2016 and 2015
(in millions)
See Condensed Notes to Condensed Financial Information beginning on page S-7.
S-4
SCHEDULE I
AMERICAN ELECTRIC POWER COMPANY, INC. (Parent)
CONDENSED FINANCIAL INFORMATION
CONDENSED BALANCE SHEETS
LIABILITIES AND EQUITY
December 31, 2016 and 2015
(dollars in millions)
See Condensed Notes to Condensed Financial Information beginning on page S-7.
S-5
SCHEDULE I
AMERICAN ELECTRIC POWER COMPANY, INC. (Parent)
CONDENSED FINANCIAL INFORMATION
CONDENSED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2016, 2015 and 2014
(in millions)
See Condensed Notes to Condensed Financial Information beginning on page S-7.
S-6
SCHEDULE I
AMERICAN ELECTRIC POWER COMPANY, INC. (Parent)
INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL INFORMATION
1. Summary of Significant Accounting Policies
2. Commitments, Guarantees and Contingencies
3. Financing Activities
4. Related Party Transactions
S-7
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
The condensed financial information of Parent is required as a result of the restricted net assets of AEP consolidated subsidiaries exceeding 25% of AEP consolidated net assets as of December 31, 2016. Parent is a public utility holding company that owns all of the outstanding common stock of its public utility subsidiaries and varying percentages of other subsidiaries, including joint ventures and equity investments. The primary source of income for Parent is equity in its subsidiaries’ earnings. Its major source of cash is dividends from the subsidiaries. Parent borrows the funds for the money pool that is used by the subsidiaries for their short-term cash needs.
Income Taxes
Parent files a consolidated federal income tax return with its subsidiaries. AEP System’s current consolidated federal income tax is allocated to AEP System companies so that their current tax expense reflects a separate return result for each company in the consolidated group. The tax benefit of Parent is allocated to its subsidiaries with taxable income.
2. COMMITMENTS, GUARANTEES AND CONTINGENCIES
Parent and its subsidiaries are parties to environmental and other legal matters. For further discussion of commitments, guarantees and contingencies, see Note 6 in the 2016 Annual Reports.
3. FINANCING ACTIVITIES
The following details long-term debt outstanding as of December 31, 2016 and 2015:
Long-term Debt
Long-term debt outstanding as of December 31, 2016 is payable as follows:
S-8
Short-term Debt
Parent’s outstanding short-term debt was as follows:
December 31,
Type of Debt
Outstanding
Amount
Weighted Average
Interest Rate
Outstanding
Amount
Weighted Average
Interest Rate
(in millions)
(in millions)
Commercial Paper
$
1,040.0
1.02
%
$
125.0
0.81
%
Total Short-term Debt
$
1,040.0
$
125.0
4. RELATED PARTY TRANSACTIONS
Payments on Behalf of Subsidiaries
Due to occasional time sensitivity and complexity of payments, Parent makes certain insurance, tax and benefit payments on behalf of subsidiary companies. Parent is then fully reimbursed by the subsidiary companies.
Short-term Lending to Subsidiaries
Parent uses a commercial paper program to meet the short-term borrowing needs of subsidiaries. The program is used to fund both a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds certain nonutility subsidiaries. In addition, the program also funds, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in either money pool for regulatory or operational reasons. The program also allows some direct borrowers to invest excess cash with Parent.
Interest expense related to Parent’s short-term borrowing is included in Interest Expense on Parent’s statements of income. Parent incurred interest expense for amounts borrowed from subsidiaries of $2 million, $2 million and $413 thousand for the years ended December 31, 2016, 2015 and 2014, respectively.
Interest income related to Parent’s short-term lending is included in Interest Income on Parent’s statements of income. Parent earned interest income for amounts advanced to subsidiaries of $10 million, $4 million and $4 million for the years ended December 31, 2016, 2015 and 2014, respectively.
Global Borrowing Notes
Parent issued long-term debt, portions of which were loaned to its subsidiaries. Parent pays interest on the global notes, but the subsidiaries accrue interest for their share of the global borrowing and remit the interest to Parent. Interest income related to Parent’s loans to subsidiaries is included in Interest Income on Parent’s statements of income. Parent earned interest income on loans to subsidiaries of $1 million, $1 million and $3 million for the years ended December 31, 2016, 2015 and 2014, respectively.
S-9
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
(a)
Recoveries offset by reclasses to other assets and liabilities.
(b)
Uncollectible accounts written off.
(a)
Recoveries offset by reclasses to other assets and liabilities.
(b)
Uncollectible accounts written off.
(a)
Recoveries offset by reclasses to other assets and liabilities.
(b)
Uncollectible accounts written off.
(c)
Recoveries on previous reserve balance.
S-10
(a)
Recoveries offset by reclasses to other assets and liabilities.
(b)
Uncollectible accounts written off.
(a)
Recoveries offset by reclasses to other assets and liabilities.
(b)
Uncollectible accounts written off.
(c)
Recoveries on previous reserve balance.
(a)
Recoveries offset by reclasses to other assets and liabilities.
(b)
Uncollectible accounts written off.
(c)
Recoveries on previous reserve balance.
S-11
EXHIBIT INDEX
The documents listed below are being filed or have previously been filed on behalf of the Registrants shown and are incorporated herein by reference to the documents indicated and made a part hereof. Exhibits (“Ex”) not identified as previously filed are filed herewith. Exhibits designated with a dagger (†) are management contracts or compensatory plans or arrangements required to be filed as an Exhibit to this Form. Exhibits designated with an asterisk (*) are filed herewith.
E-1
E-2
E-3
E-4
E-5
E-6
E-7
E-8
E-9
‡ Certain instruments defining the rights of holders of long-term debt of the registrants included in the financial statements of registrants filed herewith have been omitted because the total amount of securities authorized thereunder does not exceed 10% of the total assets of registrants. The registrants hereby agree to furnish a copy of any such omitted instrument to the SEC upon request.
E-10