UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
(Mark One)
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☒ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
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| FOR THE QUARTERLY PERIOD ENDED September 30, 20202021 OR |
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☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
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| FOR THE TRANSITION PERIOD FROM TO |
Commission file number 1-3701
AVISTA CORPORATION
(Exact name of Registrant as specified in its charter)
| | |
Washington |
| 91-0462470 |
(State or other jurisdiction of incorporation or organization) |
| (I.R.S. Employer
Identification No.) |
1411 East Mission Avenue, Spokane, Washington99202-2600
(Address of principal executive offices, including zip code)
Registrant’s telephone number, including area code: 509-489-0500-489-0500
None
(Former name, former address and former fiscal year, if changed since last report)
Securities registered pursuant to Section 12(b) of the Act:
| | | | |
Title of Each Class |
| Trading Symbol(s) |
| Name of Each Exchange on Which Registered |
Common Stock |
| AVA |
| New York Stock Exchange |
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days: Yes☒ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.
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Large accelerated filer | ☒ | Accelerated filer | ☐ |
Non-accelerated filer | ☐ | Smaller reporting company | ☐ |
Emerging growth company | ☐ |
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If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act ☐
Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act): Yes ☐ No ☒
As of October 30, 2020, 68,735,94831, 2021, 70,768,243 shares of Registrant’s Common Stock, no par value (the only class of common stock), were outstanding.
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AVISTA CORPORATION
AVISTA CORPORATION
INDEX
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AVISTA CORPORATION
ACRONYMS AND TERMS
(The following acronyms and terms are found in multiple locations within the document)
| | |
Acronym/Term | Meaning |
aMW | - | Average Megawatt - a measure of the average rate at which a particular generating source produces energy over a period of time |
AEL&P | - | Alaska Electric Light and Power Company, the primary operating subsidiary of AERC, which provides electric services in Juneau, Alaska |
AERC | - | Alaska Energy and Resources Company, the Company's wholly-owned subsidiary based in Juneau, Alaska |
AFUDC | - | Allowance for Funds Used During Construction; represents the cost of both the debt and equity funds used to finance utility plant additions during the construction period |
ASC | - | Accounting Standards Codification |
ASU | - | Accounting Standards Update |
Avista Capital | - | Parent company to the Company’s non-utility businesses, with the exception of AJT Mining Properties, Inc., which is a subsidiary of AERC. |
Avista Corp. | - | Avista Corporation, the Company |
Avista Utilities | - | Operating division of Avista Corp. (not a subsidiary) comprising the regulated utility operations in the Pacific Northwest |
Capacity | - | The rate at which a particular generating source is capable of producing energy, measured in KW or MW |
Cabinet Gorge | - | The Cabinet Gorge Hydroelectric Generating Project, located on the Clark Fork River in Idaho |
ColstripCETA
| - | Clean Energy Transformation Act |
Colstrip | - | The coal-fired Colstrip Generating Plant in southeastern Montana |
Cooling degree days | - | The measure of the warmness of weather experienced, based on the extent to which the average of high and low temperatures for a day exceeds 65 degrees Fahrenheit (annual degree days above historic indicate warmer than average temperatures) |
COVID-19 | - | Coronavirus disease 2019, a respiratory illness that was declared a pandemic in March 2020 |
Deadband or ERM
deadband | - | The first $4.0 million in annual power supply costs above or below the amount included in base retail rates in Washington under the ERM in the state of Washington |
EIM | - | Energy Imbalance Market |
Energy | - | The amount of electricity produced or consumed over a period of time, measured in KWh or MWh. Also, refers to natural gas consumed and is measured in dekatherms |
EPA | - | Environmental Protection Agency |
ERM | - | The Energy Recovery Mechanism, a mechanism for accounting and rate recovery of certain power supply costs accepted by the utility commission in the state of Washington |
FASB | - | Financial Accounting Standards Board |
FCA | - | Fixed Cost Adjustment, the electric and natural gas decoupling mechanism in Idaho |
FERC | - | Federal Energy Regulatory Commission |
GAAP | - | Generally Accepted Accounting Principles |
Heating degree days | - | The measure of the coldness of weather experienced, based on the extent to which the average of high and low temperatures for a day falls below 65 degrees Fahrenheit (annual degree days below historic indicate warmer than average temperatures). |
Hydro OneIPUC
| - | Hydro One Limited, based in Toronto, Ontario, Canada
|
IPUC
| -
| Idaho Public Utilities Commission |
JuneauKW, KWh
| - | The City and Borough of Juneau, Alaska
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KW, KWh
| -
| Kilowatt (1000 watts): a measure of generating power or capability. Kilowatt-hour (1000 watt hours): a measure of energy produced over a period of time |
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MPSC | - | Public Service Commission of the State of Montana |
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| | |
MW, MWh | - | Megawatt: 1000 KW. Megawatt-hour: 1000 KWh |
Noxon Rapids | - | The Noxon Rapids Hydroelectric Generating Project, located on the Clark Fork River in Montana |
OPUC | - | The Public Utility Commission of Oregon |
PCA | - | The Power Cost Adjustment mechanism, a procedure for accounting and rate recovery of certain power supply costs accepted by the utility commission in the state of Idaho |
PGA | - | Purchased Gas Adjustment |
PPA | - | Power Purchase Agreement |
RCA | - | The Regulatory Commission of Alaska |
REC | - | Renewable energy credit |
ROE | - | Return on equity |
ROR | - | Rate of return on rate base |
ROU | - | Right-of-use lease asset |
SEC | - | U.S. Securities and Exchange Commission |
TCJATherm
| - | The "Tax Cuts and Jobs Act," signed into law on December 22, 2017
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Therm
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| Unit of measurement for natural gas; a therm is equal to approximately one hundred cubic feet (volume) or 100,000 BTUs (energy) |
Watt | - | Unit of measurement of electric power or capability; a watt is equal to the rate of work represented by a current of one ampere under a pressure of one volt |
WUTC | - | Washington Utilities and Transportation Commission |
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AVISTA CORPORATION
Forward-Looking Statements
From time to time, we make forward-looking statements such as statements regarding projected or future:
| financial performance; strategic goals and objectives; business environment; and •
| financial performance;
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| •
| strategic goals and objectives;
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| •
| business environment; and
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These statements are based upon underlying assumptions (many of which are based, in turn, upon further assumptions). Such statements are made both in our reports filed under the Securities Exchange Act of 1934, as amended (including this Quarterly Report on Form 10-Q), and elsewhere. Forward-looking statements are all statements except those of historical fact including, without limitation, those that are identified by the use of words that include “will,” “may,” “could,” “should,” “intends,” “plans,” “seeks,” “anticipates,” “estimates,” “expects,” “forecasts,” “projects,” “predicts,” and similar expressions.
Forward-looking statements (including those made in this Quarterly Report on Form 10-Q) are subject to a variety of risks, uncertainties and other factors. Most of these factors are beyond our control and may have a significant effect on our operations, results of operations, financial condition or cash flows, which could cause actual results to differ materially from those anticipated in our statements. Such risks, uncertainties and other factors include, among others:
Utility Regulatory Risk
| state and federal regulatory decisions or related judicial decisions that affect our ability to recover costs and earn a reasonable return including, but not limited to, disallowance or delay in the recovery of capital investments, operating costs, commodity costs, interest rate swap derivatives, the ordering of refunds to customers and discretion over allowed return on investment; the loss of regulatory accounting treatment, which could require the write-off of regulatory assets and the loss of regulatory deferral and recovery mechanisms; •
| state and federal regulatory decisions or related judicial decisions that affect our ability to recover costs and earn a reasonable return including, but not limited to, disallowance or delay in the recovery of capital investments, operating costs, commodity costs, interest rate swap derivatives, the ordering of refunds to customers and discretion over allowed return on investment;
|
•
| the loss of regulatory accounting treatment, which could require the write-off of regulatory assets and the loss of regulatory deferral and recovery mechanisms;
|
Operational Risk
•
| pandemics (including the current COVID-19 pandemic), which could disrupt our business, as well as the global, national and local economy, resulting in a decline in customer demand, deterioration in the creditworthiness of our customers, increases in operating and capital costs, workforce shortages, delays in capital projects, disruption in supply chains, and disruption, weakness and volatility in capital markets. In addition, any of these factors could negatively impact our liquidity and limit our access to capital, among other implications;
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pandemics (including the current COVID-19 pandemic), which could disrupt our business, as well as the global, national and local economy, resulting in a decline in customer demand, deterioration in the creditworthiness of our customers, increases in operating and capital costs, workforce shortages, losses or disruptions in our workforce due to vaccine mandates, delays in capital projects, disruption in supply chains, and disruption, weakness and volatility in capital markets. In addition, any of these factors could negatively impact our liquidity and limit our access to capital, among other implications;
•
| wildfires ignited, or allegedly ignited, by Avista Corp. equipment or facilities could cause significant loss of life and property, thereby causing serious operational and financial harm to Avista Corp. and our customers;
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wildfires ignited, or allegedly ignited, by Avista Corp. equipment or facilities could cause significant loss of life and property or result in liability for resulting fire suppression costs, thereby causing serious operational and financial harm to Avista Corp. and our customers;
•
| severe weather or natural disasters, including, but not limited to, avalanches, wind storms, wildfires, earthquakes, snow and ice storms, that can disrupt energy generation, transmission and distribution, as well as the availability and costs of fuel, materials, equipment, supplies and support services;
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severe weather or natural disasters, including, but not limited to, avalanches, wind storms, wildfires, earthquakes, extreme temperature events, snow and ice storms, that could disrupt energy generation, transmission and distribution, as well as the availability and costs of fuel, materials, equipment, supplies and support services;
•
| explosions, fires, accidents, mechanical breakdowns or other incidents that could impair assets and may disrupt operations of any of our generation facilities, transmission, and electric and natural gas distribution systems or other operations and may require us to purchase replacement power or incur costs to repair our facilities;
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explosions, fires, accidents, mechanical breakdowns or other incidents that could impair assets and may disrupt operations of any of our generation facilities, transmission, and electric and natural gas distribution systems or other operations and may require us to purchase replacement power or incur costs to repair our facilities;
•
| explosions, fires, accidents or other incidents arising from or allegedly arising from our operations that could cause injuries to the public or property damage; |
•
| blackouts or disruptions of interconnected transmission systems (the regional power grid);
|
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| blackouts or disruptions of interconnected transmission systems (the regional power grid); terrorist attacks, cyberattacks or other malicious acts that could disrupt or cause damage to our utility assets or to the national or regional economy in general, including any effects of terrorism, cyberattacks, ransomware, or vandalism that damage or disrupt information technology systems; work-force issues, including changes in collective bargaining unit agreements, strikes, work stoppages, the loss of key executives, availability of workers in a variety of skill areas, and our ability to recruit and retain employees; increasing costs of insurance, more restrictive coverage terms and our ability to obtain insurance; delays or changes in construction costs, and/or our ability to obtain required permits and materials for present or prospective facilities; increasing health care costs and cost of health insurance provided to our employees and retirees; third party construction of buildings, billboard signs, towers or other structures within our rights of way, or placement of fuel containers within close proximity to our transformers or other equipment, including overbuild atop natural gas distribution lines; the loss of key suppliers for materials or services or other disruptions to the supply chain; adverse impacts to our Alaska electric utility (AEL&P) that could result from an extended outage of its hydroelectric generating resources or their inability to deliver energy, due to their lack of interconnectivity to any other electrical grids and the availability or cost of replacement power (diesel); changing river regulation or operations at hydroelectric facilities not owned by us, which could impact our hydroelectric facilities downstream; change in the use, availability or abundancy of water resources and/or rights needed for operation of our hydroelectric facilities; •
| terrorist attacks, cyberattacks or other malicious acts that could disrupt or cause damage to our utility assets or to the national or regional economy in general, including any effects of terrorism, cyberattacks, ransomware, or vandalism that damage or disrupt information technology systems;
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•
| work-force issues, including changes in collective bargaining unit agreements, strikes, work stoppages, the loss of key executives, availability of workers in a variety of skill areas, and our ability to recruit and retain employees;
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•
| increasing costs of insurance, more restrictive coverage terms and our ability to obtain insurance;
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•
| delays or changes in construction costs, and/or our ability to obtain required permits and materials for present or prospective facilities;
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•
| increasing health care costs and cost of health insurance provided to our employees and retirees;
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•
| third party construction of buildings, billboard signs, towers or other structures within our rights of way, or placement of fuel containers within close proximity to our transformers or other equipment, including overbuild atop natural gas distribution lines;
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•
| the loss of key suppliers for materials or services or other disruptions to the supply chain;
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•
| adverse impacts to our Alaska electric utility that could result from an extended outage of its hydroelectric generating resources or their inability to deliver energy, due to their lack of interconnectivity to any other electrical grids and the availability or cost of replacement power (diesel);
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•
| changing river regulation or operations at hydroelectric facilities not owned by us, which could impact our hydroelectric facilities downstream;
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•
| change in the use, availability or abundancy of water resources and/or rights needed for operation of our hydroelectric facilities;
|
Cyber and Technology Risk
| cyberattacks on the operating systems that are used in the operation of our electric generation, transmission and distribution facilities and our natural gas distribution facilities, and cyberattacks on such systems of other energy companies with which we are interconnected, which could damage or destroy facilities or systems or disrupt operations for extended periods of time and result in the incurrence of liabilities and costs; cyberattacks on the administrative systems that are used in the administration of our business, including customer billing and customer service, accounting, communications, compliance and other administrative functions, and cyberattacks on such systems of our vendors and other companies with which we do business, resulting in the disruption of business operations, the release of private information and the incurrence of liabilities and costs; changes in costs that impede our ability to implement new information technology systems or to operate and maintain current production technology; changes in technologies, possibly making some of the current technology we utilize obsolete or introducing new cyber security risks; insufficient technology skills, which could lead to the inability to develop, modify or maintain our information systems; •
| cyberattacks on the operating systems that are used in the operation of our electric generation, transmission and distribution facilities and our natural gas distribution facilities, and cyberattacks on such systems of other energy companies with which we are interconnected, which could damage or destroy facilities or systems or disrupt operations for extended periods of time and result in the incurrence of liabilities and costs;
|
•
| cyberattacks on the administrative systems that are used in the administration of our business, including customer billing and customer service, accounting, communications, compliance and other administrative functions, and cyberattacks on such systems of our vendors and other companies with which we do business, which could result in the disruption of business operations, the release of private information and the incurrence of liabilities and costs;
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•
| changes in costs that impede our ability to effectively implement new information technology systems or to operate and maintain current production technology;
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•
| changes in technologies, possibly making some of the current technology we utilize obsolete or introducing new cyber security risks;
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•
| insufficient technology skills, which could lead to the inability to develop, modify or maintain our information systems;
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Strategic Risk
•
| growth or decline of our customer base due to new uses for our services or decline in existing services, including, but not limited to, the effect of the trend toward distributed generation at customer sites;
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growth or decline of our customer base due to new uses for our services or decline in existing services, including, but not limited to, the effect of the trend toward distributed generation at customer sites;
•
| the potential effects of negative publicity regarding our business practices, whether true or not, which could hurt our reputation and result in litigation or a decline in our common stock price;
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the potential effects of negative publicity regarding our business practices, whether true or not, which could hurt our reputation and result in litigation or a decline in our common stock price;
•
| changes in our strategic business plans, which could be affected by any or all of the foregoing, including the entry into new businesses and/or the exit from existing businesses and the extent of our business development efforts where potential future business is uncertain;
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changes in our strategic business plans, which could be affected by any or all of the foregoing, including the entry into new businesses and/or the exit from existing businesses and the extent of our business development efforts where potential future business is uncertain;
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| wholesale and retail competition including alternative energy sources, growth in customer-owned power resource technologies that displace utility-supplied energy or that may be sold back to the utility, and alternative energy suppliers and delivery arrangements; entering into or growth of non-regulated activities may increase earnings volatility; the risk of municipalization or other forms of service territory reduction; •
| wholesale and retail competition including alternative energy sources, growth in customer-owned power resource technologies that displace utility-supplied energy or that may be sold back to the utility, and alternative energy suppliers and delivery arrangements;
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•
| entering into or growth of non-regulated activities may increase earnings volatility;
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•
| the risk of municipalization or other forms of service territory reduction;
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External Mandates Risk
| changes in environmental laws, regulations, decisions and policies, including present and potential environmental remediation costs and our compliance with these matters; the potential effects of initiatives, legislation or administrative rulemaking at the federal, state or local levels, including possible effects on our generating resources, prohibitions or restrictions on new or existing services, or restrictions on greenhouse gas emissions to mitigate concerns over global climate changes; political pressures or regulatory practices that could constrain or place additional cost burdens on our distribution systems through accelerated adoption of distributed generation or electric-powered transportation or on our energy supply sources, such as campaigns to halt fossil fuel-fired power generation and opposition to other thermal generation, wind turbines or hydroelectric facilities; failure to identify changes in legislation, taxation and regulatory issues that could be detrimental or beneficial to our overall business; policy and/or legislative changes in various regulated areas, including, but not limited to, environmental regulation, healthcare regulations and import/export regulations; •
| changes in environmental laws, regulations, decisions and policies, including present and potential environmental remediation costs and our compliance with these matters;
|
•
| the potential effects of initiatives, legislation or administrative rulemaking at the federal, state or local levels, including possible effects on our generating resources, prohibitions or restrictions on new or existing services, or restrictions on greenhouse gas emissions to mitigate concerns over global climate changes;
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•
| political pressures or regulatory practices that could constrain or place additional cost burdens on our distribution systems through accelerated adoption of distributed generation or electric-powered transportation or on our energy supply sources, such as campaigns to halt fossil fuel fired power generation and opposition to other thermal generation, wind turbines or hydroelectric facilities;
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•
| failure to identify changes in legislation, taxation and regulatory issues that could be detrimental or beneficial to our overall business;
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•
| policy and/or legislative changes in various regulated areas, including, but not limited to, environmental regulation, healthcare regulations and import/export regulations;
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Financial Risk
•
| weather conditions, which affect both energy demand and electric generating capability, including the impact of precipitation and temperature on hydroelectric resources, the impact of wind patterns on wind-generated power, weather-sensitive customer demand, and similar impacts on supply and demand in the wholesale energy markets;
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weather conditions, which affect both energy demand and electric generating capability, including the impact of precipitation and temperature on hydroelectric resources, the impact of wind patterns on wind-generated power, weather-sensitive customer demand, and similar impacts on supply and demand in the wholesale energy markets;
•
| our ability to obtain financing through the issuance of debt and/or equity securities, which could be affected by various factors including our credit ratings, interest rates, other capital market conditions and global economic conditions;
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our ability to obtain financing through the issuance of debt and/or equity securities, which could be affected by various factors including our credit ratings, interest rates, other capital market conditions and global economic conditions;
•
| changes in interest rates that affect borrowing costs, our ability to effectively hedge interest rates for anticipated debt issuances, variable interest rate borrowing and the extent to which we recover interest costs through retail rates collected from customers;
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changes in interest rates that affect borrowing costs, our ability to effectively hedge interest rates for anticipated debt issuances, variable interest rate borrowing and the extent to which we recover interest costs through retail rates collected from customers;
•
| changes in actuarial assumptions, interest rates and the actual return on plan assets for our pension and other postretirement benefit plans, which could affect future funding obligations, pension and other postretirement benefit expense and the related liabilities;
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changes in actuarial assumptions, interest rates and the actual return on plan assets for our pension and other postretirement benefit plans, which could affect future funding obligations, pension and other postretirement benefit expense and the related liabilities;
•
| the outcome of legal proceedings and other contingencies;
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the outcome of legal proceedings and other contingencies;
•
| economic conditions in our service areas, including the economy's effects on customer demand for utility services;
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economic conditions in our service areas, including the economy's effects on customer demand for utility services;
•
| economic conditions nationally may affect the valuation of our unregulated portfolio companies;
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economic conditions nationally may affect the valuation of our unregulated portfolio companies;
•
| declining energy demand related to customer energy efficiency, conservation measures and/or increased distributed generation;
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declining energy demand related to customer energy efficiency, conservation measures and/or increased distributed generation;
•
| changes in the long-term climate and weather could materially affect, among other things, customer demand, the volume and timing of streamflows required for hydroelectric generation, costs of generation, transmission and distribution. Increased or new risks may arise from severe weather or natural disasters, including wildfires;
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changes in the long-term climate and weather could materially affect, among other things, customer demand, the volume and timing of streamflows required for hydroelectric generation, costs of generation, transmission and distribution. Increased or new risks may arise from severe weather or natural disasters, including wildfires;
•
| industry and geographic concentrations which could increase our exposure to credit risks due to counterparties, suppliers and customers being similarly affected by changing conditions;
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industry and geographic concentrations which could increase our exposure to credit risks due to counterparties, suppliers and customers being similarly affected by changing conditions;
•
| deterioration in the creditworthiness of our customers;
|
deterioration in the creditworthiness of our customers;
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AVISTA CORPORATION
Energy Commodity Risk
| volatility and illiquidity in wholesale energy markets, including exchanges, the availability of willing buyers and sellers, changes in wholesale energy prices that could affect operating income, cash requirements to purchase electricity and natural gas, value received for wholesale sales, collateral required of us by individual counterparties and/or exchanges in wholesale energy transactions and credit risk to us from such transactions, and the market value of derivative assets and liabilities; default or nonperformance on the part of any parties from whom we purchase and/or sell capacity or energy; potential environmental regulations or lawsuits affecting our ability to utilize or resulting in the obsolescence of our power supply resources; explosions, fires, accidents, pipeline ruptures or other incidents that could limit energy supply to our facilities or our surrounding territory, which could result in a shortage of commodities in the market that could increase the cost of replacement commodities from other sources; •
| volatility and illiquidity in wholesale energy markets, including exchanges, the availability of willing buyers and sellers, changes in wholesale energy prices that could affect operating income, cash requirements to purchase electricity and natural gas, value received for wholesale sales, collateral required of us by individual counterparties and/or exchanges in wholesale energy transactions and credit risk to us from such transactions, and the market value of derivative assets and liabilities;
|
•
| default or nonperformance on the part of any parties from whom we purchase and/or sell capacity or energy;
|
•
| potential environmental regulations or lawsuits affecting our ability to utilize or resulting in the obsolescence of our power supply resources;
|
•
| explosions, fires, accidents, pipeline ruptures or other incidents that could limit energy supply to our facilities or our surrounding territory, which could result in a shortage of commodities in the market that could increase the cost of replacement commodities from other sources;
|
Compliance Risk
| changes in laws, regulations, decisions and policies at the federal, state or local levels, which could materially impact both our electric and gas operations and costs of operations; and the ability to comply with the terms of the licenses and permits for our hydroelectric or thermal generating facilities at cost-effective levels. •
| changes in laws, regulations, decisions and policies at the federal, state or local levels, which could materially impact both our electric and gas operations and costs of operations; and
|
•
| the ability to comply with the terms of the licenses and permits for our hydroelectric or thermal generating facilities at cost-effective levels.
|
Our expectations, beliefs and projections are expressed in good faith. We believe they are reasonable based on, without limitation, an examination of historical operating trends, our records and other information available from third parties. There can be no assurance that our expectations, beliefs or projections will be achieved or accomplished. Furthermore, any forward-looking statement speaks only as of the date on which such statement is made. We undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which such statement is made or to reflect the occurrence of unanticipated events. New risks, uncertainties and other factors emerge from time to time, and it is not possible for us to predict all such factors, nor can we assess the effect of each such factor on our business or the extent that any such factor or combination of factors may cause actual results to differ materially from those contained in any forward-looking statement.
Available Information
We file annual, quarterly and current reports and proxy statements with the SEC. The SEC maintains a website that contains these documents at www.sec.gov. We make annual, quarterly and current reports and proxy statements available on our website, www.avistacorp.com,https://investor.avistacorp.com/, as soon as practicable after electronically filing these documents with the SEC. Except for SEC filings or portions thereof that are specifically referred to in this report, information contained on these websites is not part of this report.
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PART I. Financial Information
Item 1. Condensed Consolidated Financial Statements
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
Avista Corporation
For the Three and Nine Months Ended September 30
Dollars in thousands, except per share amounts
(Unaudited)
| | | Three Months Ended September 30, | | | Nine Months Ended September 30, | | | Three Months Ended September 30, | | | Nine Months Ended September 30, | |
| | 2020 | | | 2019 | | | 2020 | | | 2019 | | | 2021 | | | 2020 | | | 2021 | | | 2020 | |
Operating Revenues: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Utility revenues: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Utility revenues, exclusive of alternative revenue programs | | $ | 276,351 | | | $ | 276,683 | | | $ | 944,146 | | | $ | 958,750 | | | $ | 306,398 | | $ | 276,351 | | $ | 1,019,756 | | $ | 944,146 | |
Alternative revenue programs | | | (3,972 | ) | | | 6,038 | | | | (4,023 | ) | | | 11,105 | | | | (10,499 | ) | | | (3,972 | ) | | | (13,069 | ) | | | (4,023 | ) |
Total utility revenues | | | 272,379 | | | | 282,721 | | | | 940,123 | | | | 969,855 | | | 295,899 | | 272,379 | | 1,006,687 | | 940,123 | |
Non-utility revenues | | | 267 | | | | 1,049 | | | | 1,345 | | | | 11,208 | | | | 108 | | | | 267 | | | | 445 | | | | 1,345 | |
Total operating revenues | | | 272,646 | | | | 283,770 | | | | 941,468 | | | | 981,063 | | | | 296,007 | | | | 272,646 | | | | 1,007,132 | | | | 941,468 | |
Operating Expenses: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Utility operating expenses: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Resource costs | | | 78,785 | | | | 98,324 | | | | 276,297 | | | | 324,110 | | | 102,133 | | 78,785 | | 327,390 | | 276,297 | |
Other operating expenses | | | 85,551 | | | | 80,112 | | | | 266,251 | | | | 251,810 | | | 85,625 | | 85,551 | | 267,233 | | 266,251 | |
Merger transaction costs | | | — | | | | — | | | | — | | | | 19,675 | | |
Depreciation and amortization | | | 53,953 | | | | 50,052 | | | | 169,282 | | | | 154,445 | | | 57,722 | | 53,953 | | 169,009 | | 169,282 | |
Taxes other than income taxes | | | 24,016 | | | | 23,455 | | | | 79,736 | | | | 78,306 | | | 25,440 | | 24,016 | | 82,223 | | 79,736 | |
Non-utility operating expenses: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Other operating expenses | | | 1,697 | | | | 1,450 | | | | 3,716 | | | | 15,137 | | | 843 | | 1,697 | | 3,186 | | 3,716 | |
Depreciation and amortization | | | 146 | | | | 134 | | | | 569 | | | | 498 | | | | 30 | | | | 146 | | | | 230 | | | | 569 | |
Total operating expenses | | | 244,148 | | | | 253,527 | | | | 795,851 | | | | 843,981 | | | | 271,793 | | | | 244,148 | | | | 849,271 | | | | 795,851 | |
Income from operations | | | 28,498 | | | | 30,243 | | | | 145,617 | | | | 137,082 | | | 24,214 | | 28,498 | | 157,861 | | 145,617 | |
Interest expense | | | 25,812 | | | | 25,859 | | | | 77,784 | | | | 77,021 | | | 26,547 | | 25,812 | | 78,982 | | 77,784 | |
Interest expense to affiliated trusts | | | 128 | | | | 334 | | | | 606 | | | | 1,042 | | | 102 | | 128 | | 317 | | 606 | |
Capitalized interest | | | (1,009 | ) | | | (1,089 | ) | | | (2,979 | ) | | | (3,118 | ) | | (1,102 | ) | | (1,009 | ) | | (3,033 | ) | | (2,979 | ) |
Merger termination fee | | | — | | | | — | | | | — | | | | (103,000 | ) | |
Other expense (income)-net | | | (2,168 | ) | | | 180 | | | | (2,019 | ) | | | (8,995 | ) | |
Other income-net | | | | (10,267 | ) | | | (2,168 | ) | | | (23,992 | ) | | | (2,019 | ) |
Income before income taxes | | | 5,735 | | | | 4,959 | | | | 72,225 | | | | 174,132 | | | 8,934 | | 5,735 | | 105,587 | | 72,225 | |
Income tax expense (benefit) | | | 859 | | | | (131 | ) | | | 1,472 | | | | 28,145 | | | | (5,432 | ) | | | 859 | | | | 9,130 | | | | 1,472 | |
Net income | | | 4,876 | | | | 5,090 | | | | 70,753 | | | | 145,987 | | | $ | 14,366 | | | $ | 4,876 | | | $ | 96,457 | | | $ | 70,753 | |
Net loss attributable to noncontrolling interests | | | — | | | | — | | | | — | | | | 216 | | |
Net income attributable to Avista Corp. shareholders | | $ | 4,876 | | | $ | 5,090 | | | $ | 70,753 | | | $ | 146,203 | | |
Weighted-average common shares outstanding (thousands), basic | | | 68,194 | | | | 66,265 | | | | 67,638 | | | | 65,964 | | | 70,054 | | 68,194 | | 69,582 | | 67,638 | |
Weighted-average common shares outstanding (thousands), diluted | | | 68,337 | | | | 66,351 | | | | 67,769 | | | | 66,050 | | | 70,129 | | 68,337 | | 69,722 | | 67,769 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Earnings per common share attributable to Avista Corp. shareholders: | | | | | | | | | | | | | | | | | |
Earnings per common share: | | | | | | | | | | | | | |
Basic | | $ | 0.07 | | | $ | 0.08 | | | $ | 1.05 | | | $ | 2.22 | | | $ | 0.21 | | | $ | 0.07 | | | $ | 1.39 | | | $ | 1.05 | |
Diluted | | $ | 0.07 | | | $ | 0.08 | | | $ | 1.04 | | | $ | 2.21 | | | $ | 0.20 | | | $ | 0.07 | | | $ | 1.38 | | | $ | 1.04 | |
The Accompanying Notes are an Integral Part of These Statements.
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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Avista Corporation
For the Three and Nine Months Ended September 30
Dollars in thousands
(Unaudited)
| | | Three Months Ended September 30, | | | Nine Months Ended September 30, | | | Three months ended September 30: | | | Nine Months Ended September 30, | |
| | 2020 | | | 2019 | | | 2020 | | | 2019 | | | 2021 | | | 2020 | | | 2021 | | | 2020 | |
Net income | | $ | 4,876 | | | $ | 5,090 | | | $ | 70,753 | | | $ | 145,987 | | | $ | 14,366 | | | $ | 4,876 | | | $ | 96,457 | | | $ | 70,753 | |
Other Comprehensive Income: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Change in unfunded benefit obligation for pension and other postretirement benefit plans - net of taxes of $58, $43, $171 and $128 respectively | | | 220 | | | | 162 | | | | 645 | | | | 483 | | |
Change in unfunded benefit obligation for pension and other postretirement benefit plans - net of taxes of $81, $58, $247 and $171 respectively | | | | 304 | | | | 220 | | | | 927 | | | | 645 | |
Total other comprehensive income | | | 220 | | | | 162 | | | | 645 | | | | 483 | | | | 304 | | | | 220 | | | | 927 | | | | 645 | |
Comprehensive income | | | 5,096 | | | | 5,252 | | | | 71,398 | | | | 146,470 | | | $ | 14,670 | | | $ | 5,096 | | | $ | 97,384 | | | $ | 71,398 | |
Comprehensive loss attributable to noncontrolling interests | | | — | | | | — | | | | — | | | | 216 | | |
Comprehensive income attributable to Avista Corporation shareholders | | $ | 5,096 | | | $ | 5,252 | | | $ | 71,398 | | | $ | 146,686 | | |
The Accompanying Notes are an Integral Part of These Statements.
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CONDENSED CONSOLIDATED BALANCE SHEETS
Avista Corporation
Dollars in thousands
(Unaudited)
| | | September 30, | | | December 31, | | | September 30, | | | December 31, | |
| | 2020 | | | 2019 | | | 2021 | | | 2020 | |
Assets: | | | | | | | | | | | | | | |
Current Assets: | | | | | | | | | | | | | | |
Cash and cash equivalents | | $ | 84,747 | | | $ | 9,896 | | | $ | 19,224 | | $ | 14,196 | |
Accounts and notes receivable-less allowances of $11,322 and $2,419, respectively | | | 108,118 | | | | 166,657 | | |
Accounts and notes receivable-less allowances of $12,360 and $11,387, respectively | | | 130,696 | | 163,772 | |
Materials and supplies, fuel stock and stored natural gas | | | 69,026 | | | | 66,583 | | | 87,203 | | 67,451 | |
Regulatory assets | | | 11,194 | | | | 21,851 | | | 37,768 | | 13,673 | |
Other current assets | | | 26,577 | | | | 40,142 | | | | 81,384 | | | | 84,885 | |
Total current assets | | | 299,662 | | | | 305,129 | | | 356,275 | | 343,977 | |
Net utility property | | | 4,930,359 | | | | 4,797,007 | | | 5,168,825 | | 4,991,612 | |
Goodwill | | | 52,426 | | | | 52,426 | | | 52,426 | | 52,426 | |
Non-current regulatory assets | | | 737,541 | | | | 670,802 | | | 875,952 | | 750,443 | |
Other property and investments-net and other non-current assets | | | 263,143 | | | | 257,092 | | | | 278,000 | | | | 263,639 | |
Total assets | | $ | 6,283,131 | | | $ | 6,082,456 | | | $ | 6,731,478 | | | $ | 6,402,097 | |
Liabilities and Equity: | | | | | | | | | | | | | | |
Current Liabilities: | | | | | | | | | | | | | | |
Accounts payable | | $ | 83,697 | | | $ | 110,219 | | | $ | 102,824 | | $ | 106,613 | |
Current portion of long-term debt | | | 52,000 | | | | 52,000 | | | 250,000 | | 0 | |
Short-term borrowings | | | 150,000 | | | | 185,800 | | | 199,075 | | 203,000 | |
Regulatory liabilities | | | 48,902 | | | | 51,715 | | | 75,559 | | 46,435 | |
Other current liabilities | | | 140,240 | | | | 130,979 | | | | 171,728 | | | | 149,831 | |
Total current liabilities | | | 474,839 | | | | 530,713 | | | 799,186 | | 505,879 | |
Long-term debt | | | 2,009,300 | | | | 1,843,768 | | | 1,898,235 | | 2,008,534 | |
Long-term debt to affiliated trusts | | | 51,547 | | | | 51,547 | | | 51,547 | | 51,547 | |
Pensions and other postretirement benefits | | | 199,912 | | | | 212,006 | | | 177,333 | | 211,880 | |
Deferred income taxes | | | 550,571 | | | | 528,513 | | | 634,215 | | 594,712 | |
Non-current regulatory liabilities | | | 773,641 | | | | 775,436 | | | 886,351 | | 784,820 | |
Other non-current liabilities and deferred credits | | | 240,470 | | | | 201,189 | | | | 182,975 | | | | 214,999 | |
Total liabilities | | | 4,300,280 | | | | 4,143,172 | | | | 4,629,842 | | | | 4,372,371 | |
Commitments and Contingencies (See Notes to Condensed Consolidated Financial Statements) | | | | | | | | | | | | | | |
Equity: | | | | | | | | | | | | | | |
Avista Corporation Shareholders’ Equity: | | | | | | | | | |
Common stock, no par value; 200,000,000 shares authorized; 68,734,461 and 67,176,996 shares issued and outstanding, respectively | | | 1,265,191 | | | | 1,210,741 | | |
Shareholders’ Equity: | | | | | | | |
Common stock, no par value; 200,000,000 shares authorized; 70,767,212 and
69,238,901 shares issued and outstanding, respectively | | | 1,349,960 | | 1,286,068 | |
Accumulated other comprehensive loss | | | (9,614 | ) | | | (10,259 | ) | | (13,451 | ) | | (14,378 | ) |
Retained earnings | | | 727,274 | | | | 738,802 | | | | 765,127 | | | | 758,036 | |
Total Avista Corporation shareholders’ equity | | | 1,982,851 | | | | 1,939,284 | | |
Total shareholders’ equity | | | | 2,101,636 | | | | 2,029,726 | |
Total liabilities and equity | | $ | 6,283,131 | | | $ | 6,082,456 | | | $ | 6,731,478 | | | $ | 6,402,097 | |
The Accompanying Notes are an Integral Part of These Statements.
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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
Avista Corporation
For the Nine Months Ended September 30
Dollars in thousands
(Unaudited)
| | | 2020 | | | 2019 | | | 2021 | | | 2020 | |
Operating Activities: | | | | | | | | | | | | | | |
Net income | | $ | 70,753 | | | $ | 145,987 | | | $ | 96,457 | | $ | 70,753 | |
Non-cash items included in net income: | | | | | | | | | | | | | | |
Depreciation and amortization | | | 169,851 | | | | 154,943 | | | 169,239 | | 169,851 | |
Deferred income tax provision and investment tax credits | | | (2,200 | ) | | | 10,219 | | | 18,645 | | (2,200 | ) |
Power and natural gas cost amortizations (deferrals), net | | | (6,470 | ) | | | (45,835 | ) | | (40,178 | ) | | (6,470 | ) |
Amortization of debt expense | | | 2,329 | | | | 2,008 | | | 2,068 | | 2,329 | |
Amortization of investment in exchange power | | | — | | | | 1,633 | | |
Stock-based compensation expense | | | 3,705 | | | | 8,951 | | | 3,173 | | 3,705 | |
Equity-related AFUDC | | | (5,030 | ) | | | (5,021 | ) | | (5,280 | ) | | (5,030 | ) |
Pension and other postretirement benefit expense | | | 25,010 | | | | 27,139 | | | 21,925 | | 25,010 | |
Other regulatory assets and liabilities and deferred debits and credits | | | 12,456 | | | | 1,871 | | | 2,597 | | 12,456 | |
Change in decoupling regulatory deferral | | | 3,340 | | | | (11,540 | ) | | 12,602 | | 3,340 | |
Gain on sale of METALfx (before payment of transaction costs) | | | — | | | | (6,477 | ) | |
Gain on sale of investments | | | (3,914 | ) | | | — | | | (1,816 | ) | | (3,914 | ) |
Other | | | 12,807 | | | | (5,095 | ) | | (12,697 | ) | | 12,807 | |
Contributions to defined benefit pension plan | | | (22,000 | ) | | | (22,000 | ) | | (42,000 | ) | | (22,000 | ) |
Cash paid for settlement of interest rate swap agreements | | | (33,499 | ) | | | (13,325 | ) | | (17,568 | ) | | (33,499 | ) |
Cash received for settlement of interest rate swap agreements | | | 324 | | — | |
Changes in certain current assets and liabilities: | | | | | | | | | | | | | | |
Accounts and notes receivable | | | 45,552 | | | | 54,554 | | | 24,521 | | 45,552 | |
Materials and supplies, fuel stock and stored natural gas | | | (2,444 | ) | | | (7,298 | ) | | (19,753 | ) | | (2,444 | ) |
Collateral posted for derivative instruments | | | 10,105 | | | | 64,770 | | | (9,944 | ) | | 10,105 | |
Income taxes receivable | | | 3,549 | | | | (9,116 | ) | | 10,663 | | 3,549 | |
Other current assets | | | 6,352 | | | | (2,307 | ) | | 7,902 | | 6,352 | |
Accounts payable | | | (23,328 | ) | | | (8,366 | ) | | (889 | ) | | (23,328 | ) |
Other current liabilities | | | 15,604 | | | | 4,796 | | | | 8,925 | | | | 15,604 | |
Net cash provided by operating activities | | | 282,528 | | | | 340,491 | | | | 228,916 | | | | 282,528 | |
| | | | | | | | | | | | | | |
Investing Activities: | | | | | | | | | | | | | | |
Utility property capital expenditures (excluding equity-related AFUDC) | | | (297,834 | ) | | | (320,964 | ) | | (322,808 | ) | | (297,834 | ) |
Issuance of notes receivable by subsidiaries | | | (4,343 | ) | | | (6,036 | ) | |
Issuance of notes receivable | | | (1,791 | ) | | (4,343 | ) |
Equity and property investments | | | (3,994 | ) | | | (10,031 | ) | | (12,621 | ) | | (3,994 | ) |
Proceeds from sale of METALfx (net of cash sold) | | | — | | | | 16,407 | | |
Proceeds from sale of investments | | | 6,644 | | | | — | | | 8,306 | | 6,644 | |
Other | | | (1,478 | ) | | | 309 | | | | 1,984 | | | | (1,478 | ) |
Net cash used in investing activities | | | (301,005 | ) | | | (320,315 | ) | | | (326,930 | ) | | | (301,005 | ) |
The Accompanying Notes are an Integral Part of These Statements.
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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)
Avista Corporation
For the Nine Months Ended September 30
Dollars in thousands
(Unaudited)
| | | 2020 | | | 2019 | | | 2021 | | | 2020 | |
Financing Activities: | | | | | | | | | | | | | | |
Net increase (decrease) in short-term borrowings | | $ | (35,800 | ) | | $ | 17,000 | | | $ | 66,000 | | $ | (35,800 | ) |
Proceeds from issuance of long-term debt | | | 165,000 | | | | — | | | 70,000 | | 165,000 | |
Maturity of long-term debt and finance leases | | | (2,129 | ) | | | (1,995 | ) | | (2,223 | ) | | (2,129 | ) |
Issuance of common stock, net of issuance costs | | | 53,356 | | | | 42,899 | | | 61,345 | | 53,356 | |
Cash dividends paid | | | (82,281 | ) | | | (76,772 | ) | | (88,204 | ) | | (82,281 | ) |
Other | | | (4,818 | ) | | | (1,510 | ) | | | (3,876 | ) | | | (4,818 | ) |
Net cash provided by (used in) financing activities | | | 93,328 | | | | (20,378 | ) | |
Net cash provided by financing activities | | | | 103,042 | | | | 93,328 | |
| | | | | | | | | | | | | | |
Net increase (decrease) in cash and cash equivalents | | | 74,851 | | | | (202 | ) | |
Net increase in cash and cash equivalents | | | 5,028 | | 74,851 | |
| | | | | | | | | | | | | | |
Cash and cash equivalents at beginning of period | | | 9,896 | | | | 14,656 | | | | 14,196 | | | | 9,896 | |
| | | | | | | | | | | | | | |
Cash and cash equivalents at end of period | | $ | 84,747 | | | $ | 14,454 | | | $ | 19,224 | | | $ | 84,747 | |
The Accompanying Notes are an Integral Part of These Statements.
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CONDENSED CONSOLIDATED STATEMENTS OF EQUITY
Avista Corporation
For the Three and Nine Months Ended September 30
Dollars in thousands
(Unaudited)
| | | Three Months Ended September 30, | | | Nine Months Ended September 30, | | | Three Months Ended September 30, | | | Nine Months Ended September 30, | |
| | 2020 | | | 2019 | | | 2020 | | | 2019 | | | 2021 | | | 2020 | | | 2021 | | | 2020 | |
Common Stock, Shares: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Shares outstanding at beginning of period | | | 67,913,265 | | | | 66,111,317 | | | | 67,176,996 | | | | 65,688,356 | | | 69,666,667 | | 67,913,265 | | 69,238,901 | | 67,176,996 | |
Shares issued | | | 821,196 | | | | 597,672 | | | | 1,557,465 | | | | 1,020,633 | | | | 1,100,545 | | | | 821,196 | | | | 1,528,311 | | | | 1,557,465 | |
Shares outstanding at end of period | | | 68,734,461 | | | | 66,708,989 | | | | 68,734,461 | | | | 66,708,989 | | | | 70,767,212 | | | | 68,734,461 | | | | 70,767,212 | | | | 68,734,461 | |
Common Stock, Amount: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Balance at beginning of period | | $ | 1,234,901 | | | $ | 1,157,024 | | | $ | 1,210,741 | | | $ | 1,136,491 | | | $ | 1,303,411 | | $ | 1,234,901 | | $ | 1,286,068 | | $ | 1,210,741 | |
Equity compensation expense | | | 824 | | | | 1,931 | | | | 3,502 | | | | 8,426 | | | 893 | | 824 | | 3,540 | | 3,502 | |
Issuance of common stock, net of issuance costs | | | 29,466 | | | | 27,970 | | | | 53,356 | | | | 42,899 | | | 45,656 | | 29,466 | | 61,345 | | 53,356 | |
Payment of minimum tax withholdings for share-based payment awards | | | — | | | | — | | | | (2,408 | ) | | | (891 | ) | | | — | | | | — | | | | (993 | ) | | | (2,408 | ) |
Balance at end of period | | | 1,265,191 | | | | 1,186,925 | | | | 1,265,191 | | | | 1,186,925 | | | | 1,349,960 | | | | 1,265,191 | | | | 1,349,960 | | | | 1,265,191 | |
Accumulated Other Comprehensive Loss: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Balance at beginning of period | | | (9,834 | ) | | | (7,545 | ) | | | (10,259 | ) | | | (7,866 | ) | | (13,755 | ) | | (9,834 | ) | | (14,378 | ) | | (10,259 | ) |
Other comprehensive income | | | 220 | | | | 162 | | | | 645 | | | | 483 | | | | 304 | | | | 220 | | | | 927 | | | | 645 | |
Balance at end of period | | | (9,614 | ) | | | (7,383 | ) | | | (9,614 | ) | | | (7,383 | ) | | | (13,451 | ) | | | (9,614 | ) | | | (13,451 | ) | | | (9,614 | ) |
Retained Earnings: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Balance at beginning of period | | | 749,971 | | | | 734,555 | | | | 738,802 | | | | 644,595 | | | 780,310 | | 749,971 | | 758,036 | | 738,802 | |
Net income attributable to Avista Corporation shareholders | | | 4,876 | | | | 5,090 | | | | 70,753 | | | | 146,203 | | |
Cash dividends paid on common stock | | | (27,573 | ) | | | (25,619 | ) | | | (82,281 | ) | | | (76,772 | ) | |
Balance at end of period | | | 727,274 | | | | 714,026 | | | | 727,274 | | | | 714,026 | | |
Total Avista Corporation shareholders’ equity | | | 1,982,851 | | | | 1,893,568 | | | | 1,982,851 | | | | 1,893,568 | | |
Noncontrolling Interests: | | | | | | | | | | | | | | | | | |
Balance at beginning of period | | | — | | | | — | | | | — | | | | 825 | | |
Net loss attributable to noncontrolling interests | | | — | | | | — | | | | — | | | | (216 | ) | |
Deconsolidation of noncontrolling interests related to sale of METALfx | | | — | | | | — | | | | — | | | | (609 | ) | |
Net income | | | 14,366 | | 4,876 | | 96,457 | | 70,753 | |
Cash dividends on common stock | | | | (29,549 | ) | | | (27,573 | ) | | | (89,366 | ) | | | (82,281 | ) |
Balance at end of period | | | — | | | | — | | | | — | | | | — | | | | 765,127 | | | | 727,274 | | | | 765,127 | | | | 727,274 | |
Total equity | | $ | 1,982,851 | | | $ | 1,893,568 | | | $ | 1,982,851 | | | $ | 1,893,568 | | | $ | 2,101,636 | | | $ | 1,982,851 | | | $ | 2,101,636 | | | $ | 1,982,851 | |
Dividends declared per common share | | $ | 0.4050 | | | $ | 0.3875 | | | $ | 1.2150 | | | $ | 1.1625 | | | $ | 0.4225 | | | $ | 0.4050 | | | $ | 1.2675 | | | $ | 1.2150 | |
The Accompanying Notes are an Integral Part of These Statements.
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AVISTA CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
The accompanying condensed consolidated financial statements of Avista Corp. as of and for the interim periods ended September 30, 20202021 and September 30, 20192020 are unaudited; however, in the opinion of management, the statements reflect all adjustments necessary for a fair statement of the results for the interim periods. All such adjustments are of a normal recurring nature. The condensed consolidated financial statements have been prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. The Condensed Consolidated Statements of Income for the interim periods are not necessarily indicative of the results to be expected for the full year. These condensed consolidated financial statements do not contain the detail or footnote disclosure concerning accounting policies and other matters which would be included in full fiscal year consolidated financial statements; therefore, they should be read in conjunction with the Company's audited consolidated financial statements included in the Company's Annual Report on Form 10-K for the year ended December 31, 2019 (20192020 (2020 Form 10-K).
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Business
Avista Corp. is primarily an electric and natural gas utility with certain other business ventures. Avista Utilities is an operating division of Avista Corp., comprising its regulated utility operations in the Pacific Northwest. Avista Utilities provides electric distribution and transmission, and natural gas distribution services in parts of eastern Washington and northern Idaho. Avista Utilities also provides natural gas distribution service in parts of northeastern and southwestern Oregon. Avista Utilities has electric generating facilities in Washington, Idaho, Oregon and Montana. Avista Utilities also supplies electricity to a small number of customers in Montana, most of whom are employees who operate the Company's Noxon Rapids generating facility.
AERC is a wholly-owned subsidiary of Avista Corp. The primary subsidiary of AERC is AEL&P, which comprises Avista Corp.'s regulated utility operations in Alaska.
Avista Capital, a wholly owned non-regulated subsidiary of Avista Corp., is the parent company of all of the subsidiary companies in the non-utility businesses, with the exception of AJT Mining Properties, Inc., which is a subsidiary of AERC. See Note 17 for business segment information. See Note 19 for discussion of the sale of METALfx, an unregulated subsidiary of the Company.
Basis of Reporting
The condensed consolidated financial statements include the assets, liabilities, revenues and expenses of the Company and its subsidiaries and other majority owned subsidiaries and variable interest entities for which the Company or its subsidiaries are the primary beneficiaries. Intercompany balances were eliminated in consolidation. The accompanying condensed consolidated financial statements include the Company’s proportionate share of utility plant and related operations resulting from its interests in jointly owned plants.
Regulation
The Company is subject to state regulation in Washington, Idaho, Montana, Oregon and Alaska. The Company is also subject to federal regulation primarily by the FERC, as well as various other federal agencies with regulatory oversight of particular aspects of its operations.
Derivative Assets and Liabilities
Derivatives are recorded as either assets or liabilities on the Condensed Consolidated Balance Sheets measured at estimated fair value.
The WUTC and the IPUC issued accounting orders authorizing Avista Corp. to offset energy commodity derivative assets or liabilities with a regulatory asset or liability. This accounting treatment is intended to defer the recognition of mark-to-market gains and losses on energy commodity transactions until the period of delivery. Realized benefits and costs result in adjustments to retail rates through
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AVISTA CORPORATION
PGAs, the ERM in Washington, the PCA mechanism in Idaho, and periodic general rate cases. The resulting regulatory assets associated with energy commodity derivative instruments have been concluded to be probable of recovery through future rates.
Substantially all forward contracts to purchase or sell power and natural gas are recorded as derivative assets or liabilities at estimated fair value with an offsetting regulatory asset or liability. Contracts that are not considered derivatives are accounted for on the accrual basis until they are settled or realized unless there is a decline in the fair value of the contract that is determined to be other-than-temporary.
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AVISTA CORPORATION
For interest rate swap derivatives, Avista Corp. records all mark-to-market gains and losses in each accounting period as assets and liabilities, as well as offsetting regulatory assets and liabilities, such that there is no income statement impact. The interest rate swap derivatives are risk management tools similar to energy commodity derivatives. Upon settlement of interest rate swap derivatives, the cash payments made or received are recorded as a regulatory asset or liability and are subsequentlyis amortized as a component of interest expense over the lifeterm of the associated debt. The settledCompany records an offset of interest rate swap derivatives are also included as a partderivative assets and liabilities with regulatory assets and liabilities, based on the prior practice of Avista Corp.'s cost of debt calculation forthe commissions to provide recovery through the ratemaking purposes.process.
The Company has multiple master netting agreements with a variety of entities that allow for cross-commodity netting of derivative agreements with the same counterparty (i.e. power derivatives can be netted with natural gas derivatives). In addition, some master netting agreements allow for the netting of commodity derivatives and interest rate swap derivatives for the same counterparty. The Company does not have any agreements which allow for cross-affiliate netting among multiple affiliated legal entities. The Company nets all derivative instruments when allowed by the agreement for presentation in the Condensed Consolidated Balance Sheets.
Fair Value Measurements
Fair value represents the price that would be received when selling an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Energy commodity derivative assets and liabilities, deferred compensation assets, as well as derivatives related to interest rate swaps and foreign currency exchange contracts, are reported at estimated fair value on the Condensed Consolidated Balance Sheets. See Note 12 for the Company’s fair value disclosures.
Contingencies
Contingencies
The Company has unresolved regulatory, legal and tax issues which have inherently uncertain outcomes. The Company accrues a loss contingency if it is probable that a liability has been incurred and the amount of the loss or impairment can be reasonably estimated. The Company also discloses loss contingencies that do not meet these conditions for accrual if there is a reasonable possibility that a material loss may be incurred. See Note 16 for further discussion of the Company's commitments and contingencies.
COVID-19
In March, April and May 2020, the Company filed applications with the OPUC, IPUC and WUTC for authorization to defer certain incremental COVID-19 related costs, net of any decreased costs and other benefits. In Alaska, a Senate Bill was signed into law that provides for deferral and recovery of incremental COVID-19 related costs subject to approval by the RCA.
In July 2020, the IPUC issued an order that allows the Company to defer certain net COVID-19 related costs and benefits. As such the Company has deferred approximately $2.5 million in incremental bad debt expense for the nine months ended September 30, 2020.
In October 2020, the OPUC approved the Company’s deferred accounting application to defer certain net COVID-19 related costs and benefits. The Company expects to file a stipulation associated with this deferred accounting order in the fourth quarter of 2020, which will detail the specifics of the deferral. As of September 30, 2020, the Company has not deferred any costs attributable to Oregon.
No response has yet been received from the WUTC. Accordingly, the Company has not been deferring costs attributable to Washington.
The respective regulatory authorities will determine the appropriateness and prudency of any deferred expenses when the Company seeks recovery. See “Regulatory Deferred Charges and Credits” in Note 1 of Consolidated Financial Statements in the 2019 Form 10-K.
NOTE 2. NEW ACCOUNTING STANDARDS
ASU No. 2016-12 "Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments"
On January 1, 2020, the Company adopted ASU 2016-13, which replaces the incurred loss impairment methodology in previous GAAP with a methodology that reflects expected credit losses, and requires consideration of a broader range of reasonable and
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supportable information to inform credit loss estimates. The Company analyzed its financial instruments within the scope of this guidance, primarily trade receivables, and it did not haveThere are no new accounting standards with a material impact to the Company's financial statements and does not require additional disclosure in these Notes to the Condensed Consolidated Financial Statements.Company.
ASU 2018-13 "Fair Value Measurement (Topic 820)"
In August 2018, the FASB issued ASU No. 2018-13, which amends the fair value measurement disclosure requirements of ASC 820. The requirements of this ASU include additional disclosure regarding the range and weighted average used to develop significant unobservable inputs for Level 3 fair value estimates and the elimination of certain other previously required disclosures, such as the narrative description of the valuation process for Level 3 fair value measurements. This ASU became effective on January 1, 2020 and the requirements of this ASU did not have a material impact on the Company's fair value disclosures. See Note 12 for the Company's fair value disclosures.
ASU No. 2018-14 "Compensation - Retirement Benefits - Defined Benefit Plans - General (Subtopic 715-20)"
In August 2018, the FASB issued ASU No. 2018-14, which amends ASC 715 to add, remove and/or clarify certain disclosure requirements related to defined benefit pension and other postretirement plans. The additional disclosure requirements are primarily narrative discussion of significant changes in the benefit obligations and plan assets. The removed disclosures are primarily information about accumulated other comprehensive income expected to be recognized over the next year and the effects of changes associated with assumed health care costs. This ASU is effective for periods beginning after December 15, 2021 and early adoption is permitted. The Company is in the process of evaluating this standard; however, it has determined that it will not early adopt this standard as of September 30, 2020.
NOTE 3. BALANCE SHEET COMPONENTS
Materials and Supplies, Fuel Stock and Stored Natural Gas
Inventories of materials and supplies, fuel stock and stored natural gas are recorded at average cost for our regulated operations and the lower of cost or marketnet realizable value for our non-regulated operations and consisted of the following as of September 30, 20202021 and December 31, 20192020 (dollars in thousands):
| | | | | | | | |
| | September 30, | | | December 31, | |
| | 2021 | | | 2020 | |
Materials and supplies | | $ | 58,238 | | | $ | 53,258 | |
Fuel stock | | | 5,154 | | | | 4,658 | |
Stored natural gas | | | 23,811 | | | | 9,535 | |
Total | | $ | 87,203 | | | $ | 67,451 | |
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| | September 30, | | | December 31, | |
| | 2020 | | | 2019 | |
Materials and supplies | | $ | 50,599 | | | $ | 47,402 | |
Fuel stock | | | 4,919 | | | | 4,875 | |
Stored natural gas | | | 13,508 | | | | 14,306 | |
Total | | $ | 69,026 | | | $ | 66,583 | |
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Other Current Assets
Other current assets consisted of the following as of September 30, 20202021 and December 31, 20192020 (dollars in thousands):
| | | September 30, | | | December 31, | | | September 30, | | | December 31, | |
| | 2020 | | | 2019 | | | 2021 | | | 2020 | |
Collateral posted for derivative instruments after netting with outstanding derivative liabilities | | $ | 0 | | | $ | 4,434 | | | $ | 10,604 | | $ | 4,336 | |
Prepayments | | | 15,078 | | | | 19,652 | | | 18,523 | | 24,411 | |
Income taxes receivable | | | 6,951 | | | | 11,047 | | | 39,151 | | 49,814 | |
Other | | | 4,548 | | | | 5,009 | | | | 13,106 | | | 6,324 | |
Total | | $ | 26,577 | | | $ | 40,142 | | | $ | 81,384 | | $ | 84,885 | |
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Net Utility Property
Net utility property, which is recorded at original cost net of accumulated depreciation, consisted of the following as of September 30, 20202021 and December 31, 20192020 (dollars in thousands):
| | | September 30, | | | December 31, | | | September 30, | | | December 31, | |
| | 2020 | | | 2019 | | | 2021 | | | 2020 | |
Utility plant in service | | $ | 6,677,671 | | | $ | 6,462,993 | | | $ | 7,067,842 | | $ | 6,809,797 | |
Construction work in progress | | | 209,098 | | | | 164,941 | | | | 204,384 | | | 175,767 | |
Total | | | 6,886,769 | | | | 6,627,934 | | | 7,272,226 | | 6,985,564 | |
Less: Accumulated depreciation and amortization | | | 1,956,410 | | | | 1,830,927 | | | | 2,103,401 | | | 1,993,952 | |
Total net utility property | | $ | 4,930,359 | | | $ | 4,797,007 | | | $ | 5,168,825 | | $ | 4,991,612 | |
Other Property and Investments-Net and Other Non-Current Assets
Other property and investments-net and other non-current assets consisted of the following as of September 30, 20202021 and December 31, 20192020 (dollars in thousands):
| | | | | | | | |
| | September 30, | | | December 31, | |
| | 2021 | | | 2020 | |
Operating lease ROU assets | | $ | 70,578 | | | $ | 71,891 | |
Equity investments | | | 83,496 | | | | 59,318 | |
Finance lease ROU assets | | | 44,607 | | | | 47,338 | |
Non-utility property | | | 19,248 | | | | 19,508 | |
Notes receivable | | | 14,759 | | | | 14,454 | |
Investment in affiliated trust | | | 11,547 | | | | 11,547 | |
Deferred compensation assets | | | 9,917 | | | | 9,174 | |
Assets held for sale (1) | | | 0 | | | | 3,462 | |
Other | | | 23,848 | | | | 26,947 | |
Total | | $ | 278,000 | | | $ | 263,639 | |
| | September 30, | | | December 31, | |
| | 2020 | | | 2019 | |
Operating lease ROU assets | | $ | 71,972 | | | $ | 69,746 | |
Finance lease ROU assets | | | 48,249 | | | | 50,980 | |
Non-utility property | | | 22,397 | | | | 27,159 | |
Equity investments | | | 56,448 | | | | 51,258 | |
Investment in affiliated trust | | | 11,547 | | | | 11,547 | |
Notes receivable | | | 14,265 | | | | 14,060 | |
Deferred compensation assets | | | 9,030 | | | | 8,948 | |
Other | | | 29,235 | | | | 23,394 | |
Total | | $ | 263,143 | | | $ | 257,092 | |
During the second quarter of 2021, the Company sold certain subsidiary assets associated with the Spokane Steam Plant.
Other Current Liabilities
Other current liabilities consisted of the following as of September 30, 20202021 and December 31, 20192020 (dollars in thousands):
| | | | | | | | |
| | September 30,
2021 | | | December 31,
2020 | |
Accrued taxes other than income taxes | | $ | 42,945 | | | $ | 45,099 | |
Derivative liabilities | | | 24,797 | | | | 14,008 | |
Employee paid time off accruals | | | 28,321 | | | | 26,495 | |
Accrued interest | | | 29,278 | | | | 17,083 | |
Pensions and other postretirement benefits | | | 10,970 | | | | 11,987 | |
Other | | | 35,417 | | | | 35,159 | |
Total other current liabilities | | $ | 171,728 | | | $ | 149,831 | |
| | September 30, 2020 | | | December 31, 2019 | |
Accrued taxes other than income taxes | | $ | 41,136 | | | $ | 36,965 | |
Employee paid time off accruals | | | 25,796 | | | | 22,343 | |
Accrued interest | | | 29,608 | | | | 16,486 | |
Current portion of pensions and other postretirement benefits | | | 9,202 | | | | 8,826 | |
Derivative liabilities | | | 4,398 | | | | 10,928 | |
Other current liabilities | | | 30,100 | | | | 35,431 | |
Total other current liabilities | | $ | 140,240 | | | $ | 130,979 | |
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Other Non-Current Liabilities and Deferred Credits
Other non-current liabilities and deferred credits consisted of the following as of September 30, 20202021 and December 31, 20192020 (dollars in thousands):
| | | September 30, 2020 | | | December 31, 2019 | | | September 30,
2021 | | December 31,
2020 | |
Operating lease liabilities | | $ | 70,758 | | | $ | 65,565 | | | $ | 69,475 | | $ | 67,716 | |
Finance lease liabilities | | | 49,549 | | | | 51,750 | | | 46,501 | | 48,815 | |
Deferred investment tax credits | | | 30,021 | | | | 30,444 | | | 29,452 | | 29,866 | |
Asset retirement obligations | | | 19,743 | | | | 20,338 | | | 16,425 | | 17,194 | |
Derivative liabilities | | | 56,498 | | | | 19,685 | | | 5,580 | | 37,427 | |
Other | | | 13,901 | | | | 13,407 | | | | 15,542 | | | 13,981 | |
Total | | $ | 240,470 | | | $ | 201,189 | | | $ | 182,975 | | $ | 214,999 | |
Regulatory Assets and Liabilities
Regulatory assets and liabilities consisted of the following as of September 30, 20202021 and December 31, 20192020 (dollars in thousands):
| | | | | | | | | | | | | | | | |
| | September 30, 2021 | | | December 31, 2020 | |
| | Current | | | Non-Current | | | Current | | | Non-Current | |
Regulatory Assets | | | | | | | | | | | | |
Energy commodity derivatives | | $ | 11,159 | | | $ | 0 | | | $ | 2,073 | | | $ | 5,722 | |
Decoupling surcharge | | | 9,036 | | | | 12,641 | | | | 7,123 | | | | 17,123 | |
Deferred natural gas costs | | | 9,967 | | | | 4,758 | | | | 2,308 | | | | 0 | |
Deferred power costs | | | 7,606 | | | | 4,043 | | | | 1,775 | | | | 1,562 | |
Pension and other postretirement benefit plans | | | 0 | | | | 192,220 | | | | 0 | | | | 198,746 | |
Interest rate swaps | | | 0 | | | | 195,909 | | | | 0 | | | | 214,851 | |
Deferred income taxes (1) | | | 0 | | | | 242,782 | | | | 0 | | | | 108,517 | |
Settlement with Coeur d'Alene Tribe | | | 0 | | | | 39,205 | | | | 0 | | | | 40,043 | |
AFUDC above FERC allowed rate | | | 0 | | | | 45,093 | | | | 0 | | | | 47,393 | |
Demand side management programs | | | 0 | | | | 3,124 | | | | 0 | | | | 3,814 | |
Utility plant to be abandoned | | | 0 | | | | 29,684 | | | | 0 | | | | 28,916 | |
COVID-19 deferrals | | | 0 | | | | 15,648 | | | | 0 | | | | 8,166 | |
Other regulatory assets | | | 0 | | | | 90,845 | | | | 394 | | | | 75,590 | |
Total regulatory assets | | $ | 37,768 | | | $ | 875,952 | | | $ | 13,673 | | | $ | 750,443 | |
Regulatory Liabilities | | | | | | | | | | | | |
Income tax related liabilities (1) | | $ | 52,843 | | | $ | 475,607 | | | $ | 14,952 | | | $ | 399,677 | |
Deferred power costs | | | 10,512 | | | | 9,136 | | | | 20,299 | | | | 17,570 | |
Decoupling rebate | | | 2,717 | | | | 10,283 | | | | 1,447 | | | | 1,519 | |
Utility plant retirement costs | | | 0 | | | | 344,061 | | | | 0 | | | | 325,832 | |
Interest rate swaps | | | 0 | | | | 16,757 | | | | 0 | | | | 15,046 | |
COVID-19 deferrals | | | 0 | | | | 12,673 | | | | 0 | | | | 10,949 | |
Other regulatory liabilities | | | 9,487 | | | | 17,834 | | | | 9,737 | | | | 14,227 | |
Total regulatory liabilities | | $ | 75,559 | | | $ | 886,351 | | | $ | 46,435 | | | $ | 784,820 | |
(1) In 2021, the Company received regulatory approval in all jurisdictions to change to flow-through tax treatment of certain basis adjustments, which was $128.8 million as of September 30, 2021.
| | September 30, 2020 | | | December 31, 2019 | |
| | Current | | | Non-Current | | | Current | | | Non-Current | |
Regulatory Assets | | | | | | | | | | | | | | | | |
Energy commodity derivatives | | $ | 0 | | | $ | 0 | | | $ | 6,310 | | | $ | 264 | |
Decoupling surcharge | | | 8,414 | | | | 16,742 | | | | 12,098 | | | | 14,806 | |
Pension and other postretirement benefit plans | | | 0 | | | | 200,829 | | | | 0 | | | | 208,754 | |
Interest rate swaps | | | 0 | | | | 232,088 | | | | 0 | | | | 168,594 | |
Deferred income taxes | | | 0 | | | | 99,289 | | | | 0 | | | | 95,752 | |
Settlement with Coeur d'Alene Tribe | | | 0 | | | | 40,349 | | | | 0 | | | | 41,332 | |
AFUDC above FERC allowed rate | | | 0 | | | | 44,504 | | | | 0 | | | | 40,749 | |
Demand side management programs | | | 0 | | | | 4,147 | | | | 0 | | | | 12,170 | |
Utility plant to be abandoned | | | 0 | | | | 27,200 | | | | 0 | | | | 31,291 | |
Other regulatory assets | | | 2,780 | | | | 72,393 | | | | 3,443 | | | | 57,090 | |
Total regulatory assets | | $ | 11,194 | | | $ | 737,541 | | | $ | 21,851 | | | $ | 670,802 | |
Regulatory Liabilities | | | | | | | | | | | | | | | | |
Income tax related liabilities | | $ | 13,598 | | | $ | 397,082 | | | $ | 23,803 | | | $ | 407,549 | |
Deferred natural gas costs | | | 0 | | | | 0 | | | | 3,189 | | | | 0 | |
Deferred power costs | | | 22,384 | | | | 17,166 | | | | 14,155 | | | | 23,544 | |
Decoupling rebate | | | 1,663 | | | | 2,583 | | | | 255 | | | | 2,398 | |
Provision for rate refund (Washington remand case) | | | 5,967 | | | | 0 | | | | 3,565 | | | | 0 | |
Utility plant retirement costs | | | 0 | | | | 322,129 | | | | 0 | | | | 312,403 | |
Interest rate swaps | | | 0 | | | | 15,409 | | | | 0 | | | | 17,088 | |
Other regulatory liabilities | | | 5,290 | | | | 19,272 | | | | 6,748 | | | | 12,454 | |
Total regulatory liabilities | | $ | 48,902 | | | $ | 773,641 | | | $ | 51,715 | | | $ | 775,436 | |
NOTE 4. REVENUE
ASC 606 defines the core principle of theThe revenue recognition model is thatcontained in ASC 606 requires an entity shouldto identify the various performance obligations in a contract, allocate the transaction price among the performance obligations and recognize revenue when (or as) the entity satisfies each performance obligation.
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Utility Revenues
Revenue from Contracts with Customers
General
The majority of Avista Corp.’s revenue is from rate-regulated sales of electricity and natural gas to retail customers, which has two performance obligations, (1) having service available for a specified period (typically a month at a time) and (2) the delivery of energy to customers. The total energy price generally has a fixed component (basic charge) related to having service available and a usage-based component, related to the delivery and consumption of energy. The commodity is sold and/or delivered to and consumed by the customer simultaneously, and the provisions of the relevant utility commission authorization determine the charges the Company may bill the customer. Given that all revenue recognition criteria are met upon the delivery of energy to customers, revenue is recognized immediately at that time.
Revenues from contracts with customers are presented in the Condensed Consolidated Statements of Income in the line item "Utility revenues, exclusive of alternative revenue programs."
Non-Derivative Wholesale Contracts
The Company has certain wholesale contracts which are not accounted for as derivatives and, accordingly, are within the scope of ASC 606 and considered revenue from contracts with customers. Revenue is recognized as energy is delivered to the customer or the service is available for a specified period of time, consistent with the discussion of rate-regulated sales above.
Alternative Revenue Programs (Decoupling)
ASC 606 retained existing GAAP associated with alternative revenue programs, which specified that alternative revenue programs are contracts between an entity and a regulator of utilities, not a contract between an entity and a customer. GAAP requires that an entity present revenue arising from alternative revenue programs separately from revenues arising from contracts with customers on the face of the Condensed Consolidated Statements of Income. The Company's decoupling mechanisms (also known as a FCA in Idaho) qualify as alternative revenue programs. Decoupling revenue deferrals are recognized in the Condensed Consolidated Statements of Income during the period they occur (i.e. during the period of revenue shortfall or excess due to fluctuations in customer usage), subject to certain limitations, and a regulatory asset or liability is established that will be surcharged or rebated to customers in future periods. GAAP requires that for any alternative revenue program, like decoupling, the revenue must be expected to be collected from customers within 24 months of the deferral to qualify for recognition in the current period Condensed Consolidated Statement of Income. Any amounts included in the Company's decoupling program that are not expected to be collected from customers within 24 months are not recorded in the financial statements until the period in which revenue recognition criteria are met. The amounts expected to be collected from customers within 24 months represents an estimate that must be made by the Company on an ongoing basis due to it being based on the volumes of electric and natural gas sold to customers on a go-forward basis.
Derivative Revenue
Most wholesale electric and natural gas transactions (including both physical and financial transactions), and the sale of fuel are considered derivatives, which are specifically scoped out of ASC 606. As such, these revenues are disclosed separately from revenue from contracts with customers. Revenue is recognized for these items upon the settlement/expiration of the derivative contract. Derivative revenue includes those transactions that are entered into and settled within the same month.
Other Utility Revenue
Other utility revenue includes rent, revenues from the pre-apprentice training school, sales of materials, late fees and other charges that do not represent contracts with customers. Other utility revenue also includes the provision for earnings sharing and the deferral and amortization of refunds to customers associated with the TCJA.sharing. This revenue is scoped out of ASC 606, as this revenue does not represent items where a customer is a party that has contracted with the Company to obtain goods or services that are an output of the
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Company’s ordinary activities in exchange for consideration. As such, these revenues are presented separately from revenue from contracts with customers.
Other Considerations for Utility Revenues
Gross Versus Net Presentation
Revenues and resource costs from Avista Utilities’ settled energy contracts that are “booked out” (not physically delivered) are reported on a net basis as part of derivative revenues.
Utility-related taxes collected from customers (primarily state excise taxes and city utility taxes) are taxes that are imposed on Avista Utilities as opposed to being imposed on its customers; therefore, Avista Utilities is the taxpayer and records these transactions on a gross basis in revenue from contracts with customers and operating expense (taxes other than income taxes). The utility-related taxes collected from customers at AEL&P are imposed on the customers rather than AEL&P; therefore, the customers are the taxpayers and AEL&P is acting as their agent. As such, these transactions at AEL&P are presented on a net basis within revenue from contracts with customers.
Utility-related taxes that were included in revenue from contracts with customers were as follows for the three and nine months ended September 30 (dollars in thousands):
| Three months ended September 30, | | | Nine months ended September 30, | |
| 2020 | | | 2019 | | | 2020 | | | 2019 | |
Utility-related taxes | $ | 12,411 | | | $ | 11,867 | | | $ | 43,989 | | | $ | 43,644 | |
| | | | | | | | | | | | | | | |
| Three months ended September 30, | | | Nine months ended September 30, | |
| 2021 | | | 2020 | | | 2021 | | | 2020 | |
Utility-related taxes | $ | 13,816 | | | $ | 12,411 | | | $ | 46,971 | | | $ | 43,989 | |
Non-Utility Revenues
Revenue from Contracts with Customers
Non-utility revenue from contracts with customers is derived from contracts with one performance obligation. Prior to its sale in April 2019 (See Note 19 for further discussion on the sale of METALfx), METALfx had one performance obligation, the delivery of a product, and revenues were recognized when the risk of loss transferred to the customer, which occurred when products were shipped. The Steam Plant Kitchen and Brew Pub serves food and beverages to customers, its one performance obligation, and recognizes revenues at the time of service to the customer.
Significant Judgments and Unsatisfied Performance Obligations
The only significant judgments involving revenue recognition are estimates surrounding unbilled revenue and receivables from contracts with customers and estimates surrounding the amount of decoupling revenues that will be collected from customers within 24 months (discussed above).
The Company has certain capacity arrangements, where the Company has a contractual obligation to provide either electric or natural gas capacity to its customers for a fixed fee. Most of these arrangements are paid for in arrears by the customers and do not result in deferred revenue and only result in receivables from the customers. The Company does have one capacity agreement where the customer makes payments throughout the year, and depending on the timing of the customer payments, it can result in an immaterial amount of deferred revenue or a receivable from the customer.year. As of September 30, 2020,2021, the Company estimates it had unsatisfied capacity performance obligations of $2.4$18.8 million, which will be recognized as revenue in future periods as the capacity is provided to the customers. These performance obligations are not reflected in the financial statements, as the Company has not received payment for these services.
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Disaggregation of Total Operating Revenue
The following table disaggregates total operating revenue by segment and source for the three and nine months ended September 30 (dollars in thousands):
| | | | | | | | | | | | | | | | |
| | Three months ended September 30, | | | Nine months ended September 30, | |
| | 2021 | | | 2020 | | | 2021 | | | 2020 | |
Avista Utilities | | | | | | | | | | | | |
Revenue from contracts with customers | | $ | 266,789 | | | $ | 240,036 | | | $ | 886,078 | | | $ | 827,071 | |
Derivative revenues | | | 28,087 | | | | 24,075 | | | | 91,151 | | | | 79,361 | |
Alternative revenue programs | | | (10,499 | ) | | | (3,972 | ) | | | (13,069 | ) | | | (4,023 | ) |
Deferrals and amortizations for rate refunds to customers | | | (156 | ) | | | 1,742 | | | | 2,664 | | | | 1,216 | |
Other utility revenues | | | 2,531 | | | | 1,683 | | | | 7,348 | | | | 5,484 | |
Total Avista Utilities | | | 286,752 | | | | 263,564 | | | | 974,172 | | | | 909,109 | |
AEL&P | | | | | | | | | | | | |
Revenue from contracts with customers | | | 9,065 | | | | 8,797 | | | | 32,331 | | | | 30,900 | |
Deferrals and amortizations for rate refunds to customers | | | (48 | ) | | | (48 | ) | | | (143 | ) | | | (143 | ) |
Other utility revenues | | | 130 | | | | 66 | | | | 327 | | | | 257 | |
Total AEL&P | | | 9,147 | | | | 8,815 | | | | 32,515 | | | | 31,014 | |
| | | | | | | | | | | | |
Other revenues | | | 108 | | | | 267 | | | | 445 | | | | 1,345 | |
Total operating revenues | | $ | 296,007 | | | $ | 272,646 | | | $ | 1,007,132 | | | $ | 941,468 | |
| | Three months ended September 30, | | | Nine months ended September 30, | |
| | 2020 | | | 2019 | | | 2020 | | | 2019 | |
Avista Utilities | | | | | | | | | | | | | | | | |
Revenue from contracts with customers | | $ | 240,036 | | | $ | 234,534 | | | $ | 827,071 | | | $ | 820,438 | |
Derivative revenues | | | 24,075 | | | | 33,372 | | | | 79,361 | | | | 99,628 | |
Alternative revenue programs | | | (3,972 | ) | | | 6,038 | | | | (4,023 | ) | | | 11,105 | |
Deferrals and amortizations for rate refunds to customers | | | 1,742 | | | | (927 | ) | | | 1,216 | | | | 3,720 | |
Other utility revenues | | | 1,683 | | | | 1,914 | | | | 5,484 | | | | 7,550 | |
Total Avista Utilities | | | 263,564 | | | | 274,931 | | | | 909,109 | | | | 942,441 | |
AEL&P | | | | | | | | | | | | | | | | |
Revenue from contracts with customers | | | 8,797 | | | | 7,687 | | | | 30,900 | | | | 27,043 | |
Deferrals and amortizations for rate refunds to customers | | | (48 | ) | | | (48 | ) | | | (143 | ) | | | (143 | ) |
Other utility revenues | | | 66 | | | | 151 | | | | 257 | | | | 514 | |
Total AEL&P | | | 8,815 | | | | 7,790 | | | | 31,014 | | | | 27,414 | |
Other | | | | | | | | | | | | | | | | |
Revenue from contracts with customers | | | 3 | | | | 731 | | | | 521 | | | | 10,402 | |
Other revenues | | | 264 | | | | 318 | | | | 824 | | | | 806 | |
Total other | | | 267 | | | | 1,049 | | | | 1,345 | | | | 11,208 | |
Total operating revenues | | $ | 272,646 | | | $ | 283,770 | | | $ | 941,468 | | | $ | 981,063 | |
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Utility Revenue from Contracts with Customers by Type and Service
The following table disaggregates revenue from contracts with customers associated with the Company's electric operations for the three and nine months ended September 30 (dollars in thousands):
| | | 2020 | | | 2019 | | | 2021 | | | 2020 | |
| | Avista Utilities | | | AEL&P | | | Total Utility | | | Avista Utilities | | | AEL&P | | | Total Utility | | | Avista
Utilities | | | AEL&P | | | Total Utility | | | Avista
Utilities | | | AEL&P | | | Total Utility | |
Three months ended September 30: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
ELECTRIC OPERATIONS | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Revenue from contracts with customers | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Residential | | $ | 85,494 | | | $ | 3,150 | | | $ | 88,644 | | | $ | 78,548 | | | $ | 2,764 | | | $ | 81,312 | | | $ | 94,803 | | $ | 3,080 | | $ | 97,883 | | $ | 85,494 | | $ | 3,150 | | $ | 88,644 | |
Commercial and governmental | | | 79,242 | | | | 5,582 | | | | 84,824 | | | | 81,352 | | | | 4,857 | | | | 86,209 | | |
Commercial | | | 86,228 | | 5,920 | | 92,148 | | 79,242 | | 5,582 | | 84,824 | |
Industrial | | | 28,472 | | | | 0 | | | | 28,472 | | | | 28,453 | | | | 0 | | | | 28,453 | | | 28,843 | | 0 | | 28,843 | | 28,472 | | 0 | | 28,472 | |
Public street and highway lighting | | | 1,845 | | | | 65 | | | | 1,910 | | | | 1,849 | | | | 66 | | | | 1,915 | | | | 1,877 | | | | 65 | | | | 1,942 | | | | 1,845 | | | | 65 | | | | 1,910 | |
Total retail revenue | | | 195,053 | | | | 8,797 | | | | 203,850 | | | | 190,202 | | | | 7,687 | | | | 197,889 | | | 211,751 | | 9,065 | | 220,816 | | 195,053 | | 8,797 | | 203,850 | |
Transmission | | | 5,938 | | | | 0 | | | | 5,938 | | | | 4,058 | | | | 0 | | | | 4,058 | | | 7,372 | | 0 | | 7,372 | | 5,938 | | 0 | | 5,938 | |
Other revenue from contracts with customers | | | 4,551 | | | | 0 | | | | 4,551 | | | | 5,860 | | | | 0 | | | | 5,860 | | | | 11,610 | | | | 0 | | | | 11,610 | | | | 4,551 | | | | 0 | | | | 4,551 | |
Total electric revenue from contracts with customers | | $ | 205,542 | | | $ | 8,797 | | | $ | 214,339 | | | $ | 200,120 | | | $ | 7,687 | | | $ | 207,807 | | | $ | 230,733 | | | $ | 9,065 | | | $ | 239,798 | | | $ | 205,542 | | | $ | 8,797 | | | $ | 214,339 | |
Nine months ended September 30: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
ELECTRIC OPERATIONS | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Revenue from contracts with customers | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Residential | | $ | 272,231 | | | $ | 13,236 | | | $ | 285,467 | | | $ | 266,826 | | | $ | 12,340 | | | $ | 279,166 | | | $ | 292,714 | | $ | 13,379 | | $ | 306,093 | | $ | 272,231 | | $ | 13,236 | | $ | 285,467 | |
Commercial and governmental | | | 226,876 | | | | 17,479 | | | | 244,355 | | | | 236,973 | | | | 14,515 | | | | 251,488 | | |
Commercial | | | 243,370 | | 18,768 | | 262,138 | | 226,876 | | 17,479 | | 244,355 | |
Industrial | | | 77,999 | | | | 0 | | | | 77,999 | | | | 79,946 | | | | 0 | | | | 79,946 | | | 80,983 | | 0 | | 80,983 | | 77,999 | | 0 | | 77,999 | |
Public street and highway lighting | | | 5,474 | | | | 185 | | | | 5,659 | | | | 5,648 | | | | 188 | | | | 5,836 | | | | 5,598 | | | | 184 | | | | 5,782 | | | | 5,474 | | | | 185 | | | | 5,659 | |
Total retail revenue | | | 582,580 | | | | 30,900 | | | | 613,480 | | | | 589,393 | | | | 27,043 | | | | 616,436 | | | 622,665 | | 32,331 | | 654,996 | | 582,580 | | 30,900 | | 613,480 | |
Transmission | | | 14,121 | | | | 0 | | | | 14,121 | | | | 13,460 | | | | 0 | | | | 13,460 | | | 15,668 | | 0 | | 15,668 | | 14,121 | | 0 | | 14,121 | |
Other revenue from contracts with customers | | | 13,256 | | | | 0 | | | | 13,256 | | | | 18,433 | | | | 0 | | | | 18,433 | | | | 24,282 | | | | 0 | | | | 24,282 | | | | 13,256 | | | | 0 | | | | 13,256 | |
Total electric revenue from contracts with customers | | $ | 609,957 | | | $ | 30,900 | | | $ | 640,857 | | | $ | 621,286 | | | $ | 27,043 | | | $ | 648,329 | | | $ | 662,615 | | | $ | 32,331 | | | $ | 694,946 | | | $ | 609,957 | | | $ | 30,900 | | | $ | 640,857 | |
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The following table disaggregates revenue from contracts with customers associated with the Company's natural gas operations for the three and nine months ended September 30 (dollars in thousands):
| | | | | | | | | | | | | | | | |
| | Three months ended September 30, | | | Nine months ended September 30, | |
| | 2021 | | | 2020 | | | 2021 | | | 2020 | |
| | Avista Utilities | | | Avista Utilities | | | Avista Utilities | | | Avista Utilities | |
NATURAL GAS OPERATIONS | | | | | | | | | | | | |
Revenue from contracts with customers | | | | | | | | | | | | |
Residential | | $ | 21,197 | | | $ | 20,835 | | | $ | 142,401 | | | $ | 139,833 | |
Commercial | | | 10,055 | | | | 9,340 | | | | 65,428 | | | | 62,883 | |
Industrial and interruptible | | | 1,477 | | | | 1,538 | | | | 5,520 | | | | 5,276 | |
Total retail revenue | | | 32,729 | | | | 31,713 | | | | 213,349 | | | | 207,992 | |
Transportation | | | 1,921 | | | | 1,656 | | | | 6,177 | | | | 5,747 | |
Other revenue from contracts with customers | | | 1,406 | | | | 1,125 | | | | 3,937 | | | | 3,375 | |
Total natural gas revenue from contracts with customers | | $ | 36,056 | | | $ | 34,494 | | | $ | 223,463 | | | $ | 217,114 | |
| | 2020 | | | 2019 | |
| | Avista Utilities | | | Avista Utilities | |
Three months ended September 30: | | | | | | | | |
NATURAL GAS OPERATIONS | | | | | | | | |
Revenue from contracts with customers | | | | | | | | |
Residential | | $ | 20,835 | | | $ | 20,271 | |
Commercial and governmental | | | 9,340 | | | | 10,093 | |
Industrial and interruptible | | | 1,538 | | | | 1,000 | |
Total retail revenue | | | 31,713 | | | | 31,364 | |
Transmission | | | 1,656 | | | | 1,925 | |
Other revenue from contracts with customers | | | 1,125 | | | | 1,125 | |
Total natural gas revenue from contracts with customers | | $ | 34,494 | | | $ | 34,414 | |
Nine months ended September 30: | | | | | | | | |
NATURAL GAS OPERATIONS | | | | | | | | |
Revenue from contracts with customers | | | | | | | | |
Residential | | $ | 139,833 | | | $ | 125,543 | |
Commercial and governmental | | | 62,883 | | | | 60,056 | |
Industrial and interruptible | | | 5,276 | | | | 3,730 | |
Total retail revenue | | | 207,992 | | | | 189,329 | |
Transmission | | | 5,747 | | | | 6,448 | |
Other revenue from contracts with customers | | | 3,375 | | | | 3,375 | |
Total natural gas revenue from contracts with customers | | $ | 217,114 | | | $ | 199,152 | |
NOTE 5. DERIVATIVES AND RISK MANAGEMENT
Energy Commodity Derivatives
Avista Corp. is exposed to market risks relating to changes in electricity and natural gas commodity prices and certain other fuel prices. Market risk is, in general, the risk of fluctuation in the market price of the commodity being traded and is influenced primarily by supply and demand. Market risk includes the fluctuation in the market price of associated derivative commodity instruments. Avista Corp. utilizes derivative instruments, such as forwards, futures, swap derivatives and options, in order to manage the various risks relating to these commodity price exposures. Avista Corp. has an energy resources risk policy and control procedures to manage these risks.
As part of Avista Corp.'s resource procurement and management operations in the electric business, Avista Corp. engages in an ongoing process of resource optimization, which involves the economic selection from available energy resources to serve Avista Corp.'s load obligations and the use of these resources to capture available economic value through wholesale market transactions. These include sales and purchases of electric capacity and energy, fuel for electric generation, and derivative contracts related to capacity, energy and fuel. Such transactions are part of the process of matching resources with load obligations and hedging a portion of the related financial risks. These transactions range from terms of intra-hour up to multiple years.
As part of its resource procurement and management of its natural gas business, Avista Corp. makes continuing projections of its natural gas loads and assesses available natural gas resources including natural gas storage availability. Natural gas resource planning typically includes peak requirements, low and average monthly requirements and delivery constraints from natural gas supply locations to Avista Corp.’s distribution system. However, daily variations in natural gas demand can be significantly different than monthly demand projections. On the basis of these projections, Avista Corp. plans and executes a series of transactions to hedge a portion of its projected natural gas requirements through forward market transactions and derivative instruments. These transactions
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may extend as much as three natural gas operating years (November through October) into the future. Avista Corp. also leaves a significant portion of its natural gas supply requirements unhedged for purchase in short-term and spot markets.
Avista Corp. plans for sufficient natural gas delivery capacity to serve its retail customers for a theoretical peak day event. Avista Corp. generally has more pipeline and storage capacity than what is needed during periods other than a peak-day. Avista Corp. optimizes its natural gas resources by using market opportunities to generate economic value that mitigates the fixed costs. Avista Corp. also optimizes its natural gas storage capacity by purchasing and storing natural gas when prices are traditionally lower, typically in the summer, and withdrawing during higher priced months, typically during the winter. However, if market conditions and prices indicate that Avista Corp. should buy or sell natural gas at other times during the year, Avista Corp. engages in optimization transactions to capture value in the marketplace. Natural gas optimization activities include, but are not limited to, wholesale market sales of surplus natural gas supplies, purchases and sales of natural gas to optimize use of pipeline and storage capacity, and participation in the transportation capacity release market.
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The following table presents the underlying energy commodity derivative volumes as of September 30, 2021 that are expected to be delivered in each respective year (in thousands of MWhs and mmBTUs):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Purchases | | | Sales | |
| | Electric Derivatives | | | Gas Derivatives | | | Electric Derivatives | | | Gas Derivatives | |
Year | | Physical
(1)
MWh | | | Financial
(1)
MWh | | | Physical
(1)
mmBTUs | | | Financial
(1)
mmBTUs | | | Physical
(1)
MWh | | | Financial
(1)
MWh | | | Physical
(1)
mmBTUs | | | Financial
(1)
mmBTUs | |
Remainder 2021 | | | 0 | | | | 31 | | | | 4,891 | | | | 24,320 | | | | 18 | | | | 103 | | | | 2,587 | | | | 13,033 | |
2022 | | | 123 | | | | 0 | | | | 2,250 | | | | 52,353 | | | | 216 | | | | 370 | | | | 2,260 | | | | 28,898 | |
2023 | | | 0 | | | | 0 | | | | 0 | | | | 18,825 | | | | 0 | | | | 0 | | | | 1,360 | | | | 7,060 | |
2024 | | | 0 | | | | 0 | | | | 0 | | | | 2,275 | | | | 0 | | | | 0 | | | | 1,370 | | | | 0 | |
2025 | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 1,115 | | | | 0 | |
As of September 30, 2021, there are 0 expected deliveries of energy commodity derivatives after 2025.
The following table presents the underlying energy commodity derivative volumes as of December 31, 2020 that are expected to be delivered in each respective year (in thousands of MWhs and mmBTUs):
| | | Purchases | | | Sales | | | Purchases | | | Sales | |
| | Electric Derivatives | | | Gas Derivatives | | | Electric Derivatives | | | Gas Derivatives | | | Electric Derivatives | | | Gas Derivatives | | Electric Derivatives | | Gas Derivatives | |
Year | | Physical (1) MWh | | | Financial (1) MWh | | | Physical (1) mmBTUs | | | Financial (1) mmBTUs | | | Physical (1) MWh | | | Financial (1) MWh | | | Physical (1) mmBTUs | | | Financial (1) mmBTUs | | | Physical
(1)
MWh | | Financial
(1)
MWh | | Physical
(1)
mmBTUs | | Financial
(1)
mmBTUs | | Physical
(1)
MWh | | Financial
(1)
MWh | | Physical
(1)
mmBTUs | | Financial
(1)
mmBTUs | |
Remainder 2020 | | | 0 | | | | 262 | | | | 8,502 | | | | 32,730 | | | | 38 | | | | 409 | | | | 2,138 | | | | 12,650 | | |
2021 | | | 0 | | | | 123 | | | | 6,380 | | | | 54,455 | | | | 0 | | | | 307 | | | | 2,840 | | | | 34,710 | | | 1 | | 224 | | 10,353 | | 65,188 | | 17 | | 451 | | 5,448 | | 39,273 | |
2022 | | | 0 | | | | 0 | | | | 450 | | | | 17,080 | | | | 0 | | | | 0 | | | | 0 | | | | 6,020 | | | 0 | | 0 | | 450 | | 25,525 | | 0 | | 0 | | 1,360 | | 12,030 | |
2023 | | | 0 | | | | 0 | | | | 0 | | | | 2,700 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | 0 | | 0 | | 0 | | 4,950 | | 0 | | 0 | | 1,360 | | 900 | |
2024 | | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | | 1,370 | | 0 | |
2025 | | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | | 1,115 | | 0 | |
As of September 30,December 31, 2020, there are 0 expected deliveries of energy commodity derivatives after 2023.2025.
The following table presents
(1)Physical transactions represent commodity transactions in which Avista Corp. will take or make delivery of either electricity or natural gas; financial transactions represent derivative instruments with delivery of cash in the
underlying energyamount of the benefit or cost but with no physical delivery of the commodity,
derivative volumessuch as
of December 31, 2019 that are expected to be delivered in each respective year (in thousands of MWhs and mmBTUs): | | Purchases | | | Sales | |
| | Electric Derivatives | | | Gas Derivatives | | | Electric Derivatives | | | Gas Derivatives | |
Year | | Physical (1) MWh | | | Financial (1) MWh | | | Physical (1) mmBTUs | | | Financial (1) mmBTUs | | | Physical (1) MWh | | | Financial (1) MWh | | | Physical (1) mmBTUs | | | Financial (1) mmBTUs | |
2020 | | | 2 | | | | 442 | | | | 9,813 | | | | 78,803 | | | | 133 | | | | 1,724 | | | | 2,984 | | | | 37,848 | |
2021 | | | 0 | | | | 0 | | | | 153 | | | | 25,523 | | | | 0 | | | | 246 | | | | 1,040 | | | | 13,108 | |
2022 | | | 0 | | | | 0 | | | | 225 | | | | 4,725 | | | | 0 | | | | 0 | | | | 0 | | | | 675 | |
As of December 31, 2019, there are 0 expected deliveries of energy commodity derivatives after 2022.
(1)
| Physical transactions represent commodity transactions in which Avista Corp. will take or make delivery of either electricity or natural gas; financial transactions represent derivative instruments with delivery of cash in the amount of the benefit or cost but with no physical delivery of the commodity, such as futures, swap derivatives, options, or forward contracts.
|
The electric and natural gas derivative contracts above will be included in either power supply costs or natural gas supply costs during the period they are scheduled to be delivered and will be included in the various deferral and recovery mechanisms (ERM, PCA and PGAs), or in the general rate case process, and are expected to be collected through retail rates from customers.
Foreign Currency Exchange Derivatives
A significant portion of Avista Corp.’s natural gas supply (including fuel for power generation) is obtained from Canadian sources. Most of those transactions are executed in U.S. dollars, which avoids foreign currency risk. A portion of Avista Corp.’s short-term natural gas transactions and long-term Canadian transportation contracts are committed based on Canadian currency prices. The short-
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termshort-term natural gas transactions are settled within 60 days with U.S. dollars. Avista Corp. hedges a portion of the foreign currency risk by purchasing Canadian currency exchange derivatives when such commodity transactions are initiated. The foreign currency exchange derivatives and the unhedged foreign currency risk have not had a material effect on Avista Corp.’s financial condition, results of operations or cash flows and these differences in cost related to currency fluctuations are included with natural gas supply costs for ratemaking.
The following table summarizes the foreign currency exchange derivatives that Avista Corp. has outstanding as of September 30, 20202021 and December 31, 20192020 (dollars in thousands):
| | | September 30, 2020 | | | December 31, 2019 | | | September 30,
2021 | | | December 31,
2020 | |
Number of contracts | | | 24 | | | | 20 | | | 22 | | 22 | |
Notional amount (in United States dollars) | | $ | 5,887 | | | $ | 5,932 | | | $ | 7,692 | | $ | 3,860 | |
Notional amount (in Canadian dollars) | | | 7,777 | | | | 7,828 | | | 9,739 | | 4,949 | |
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Interest Rate Swap Derivatives
Avista Corp. is affected by fluctuating interest rates related to a portion of its existing debt, and future borrowing requirements. Avista Corp. hedges a portion of its interest rate risk with financial derivative instruments, which may include interest rate swap derivatives and U.S. Treasury lock agreements. These interest rate swap derivatives and U.S. Treasury lock agreements are considered economic hedges against fluctuations in future cash flows associated with anticipated debt issuances.
The following table summarizes the unsettled interest rate swap derivatives that Avista Corp. has outstanding as of September 30, 20202021 and December 31, 20192020 (dollars in thousands):
Balance Sheet Date | | Number of Contracts | | | Notional Amount | | | Mandatory Cash Settlement Date |
September 30, 2020 | | | 4 | | | | 45,000 | | | 2021 |
| | | 11 | | | | 120,000 | | | 2022 |
| | | 1 | | | | 10,000 | | | 2023 |
December 31, 2019 | | | 7 | | | | 70,000 | | | 2020 |
| | | 3 | | | | 35,000 | | | 2021 |
| | | 10 | | | | 110,000 | | | 2022 |
| | | | | | | | | | |
Balance Sheet Date | | Number of
Contracts | | | Notional
Amount | | | Mandatory
Cash Settlement
Date |
September 30, 2021 | | | 13 | | | $ | 140,000 | | | 2022 |
| | | 2 | | | | 20,000 | | | 2023 |
| | | 1 | | | | 10,000 | | | 2024 |
December 31, 2020 | | | 4 | | | $ | 45,000 | | | 2021 |
| | | 11 | | | | 120,000 | | | 2022 |
| | | 1 | | | | 10,000 | | | 2023 |
The fair value of outstanding interest rate swap derivatives can vary significantly from period to period depending on the total notional amount of swap derivatives outstanding and fluctuations in market interest rates compared to the interest rates fixed by the swaps. Avista Corp. is required to make cash payments to settle the interest rate swap derivatives when the fixed rates are higher than prevailing market rates at the date of settlement. Conversely, Avista Corp. receives cash to settle its interest rate swap derivatives when prevailing market rates at the time of settlement exceed the fixed swap rates.
In connection with the pricing of first mortgage bonds that were issued during the third quarter, effective June 30, 2020 the Company settled 7 interest rate swap derivatives (notional aggregate amount of $70.0 million), for a net amount of $33.5 million. The Company paid this amount in July 2020. See Note 1 for the regulatory treatment of settled interest rate swaps.
Summary of Outstanding Derivative Instruments
The amounts recorded on the Condensed Consolidated Balance Sheet as of September 30, 20202021 and December 31, 20192020 reflect the offsetting of derivative assets and liabilities where a legal right of offset exists.
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The following table presents the fair values and locations of derivative instruments recorded on the Condensed Consolidated Balance Sheet as of September 30, 20202021 (in thousands):
| | Fair Value | |
Derivative and Balance Sheet Location | | Gross Asset | | | Gross Liability | | | Collateral Netted (1) | | | Net Asset (Liability) on Balance Sheet | |
Foreign currency exchange derivatives | | | | | | | | | | | | | | | | |
Other current liabilities | | $ | 7 | | | $ | (52 | ) | | $ | 0 | | | $ | (45 | ) |
Interest rate swap derivatives | | | | | | | | | | | | | | | | |
Other non-current liabilities and deferred credits | | | 0 | | | | (66,598 | ) | | | 10,100 | | | | (56,498 | ) |
Energy commodity derivatives | | | | | | | | | | | | | | | | |
Other current assets | | | 27,305 | | | | (22,188 | ) | | | (4,551 | ) | | | 566 | |
Other property and investments-net and other non-current assets | | | 8,221 | | | | (3,976 | ) | | | (1,072 | ) | | | 3,173 | |
Other current liabilities | | | 136 | | | | (4,534 | ) | | | 0 | | | | (4,398 | ) |
Total derivative instruments recorded on the balance sheet | | $ | 35,669 | | | $ | (97,348 | ) | | $ | 4,477 | | | $ | (57,202 | ) |
| | | | | | | | | | | | | | | | | | | Fair Value | | Derivative and Balance Sheet Location | | Gross
Asset | | | Gross
Liability | | | Collateral
Netted | | | Net Asset
(Liability)
on Balance
Sheet | | Foreign currency exchange derivatives | | | | | | | | | | | | | Other current liabilities | | $ | 0 | | | $ | (86 | ) | | $ | 0 | | | $ | (86 | ) | Interest rate swap derivatives | | | | | | | | | | | | | Other property and investments-net and other non-current assets | | | 2,477 | | | | 0 | | | | 0 | | | | 2,477 | | Other current liabilities | | | 2,072 | | | | (20,732 | ) | | | 0 | | | | (18,660 | ) | Energy commodity derivatives | | | | | | | | | | | | | Other current assets | | | 49,933 | | | | (42,664 | ) | | | 0 | | | | 7,269 | | Other property and investments-net and other non-current assets | | | 12,587 | | | | (5,895 | ) | | | 0 | | | | 6,692 | | Other current liabilities | | | 12,539 | | | | (30,933 | ) | | | 12,343 | | | | (6,051 | ) | Other non-current liabilities and deferred credits | | | 108 | | | | (5,688 | ) | | | 0 | | | | (5,580 | ) | Total derivative instruments recorded on the balance sheet | | $ | 79,716 | | | $ | (105,998 | ) | | $ | 12,343 | | | $ | (13,939 | ) |
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| (1)
| Positive amounts represent cash collateral posted by the Company with other counterparties and negative amounts represent an obligation to return cash to the Company’s counterparties under master netting and collateral agreements.
|
The following table presents the fair values and locations of derivative instruments recorded on the Condensed Consolidated Balance Sheet as of December 31, 20192020 (in thousands):
| | | Fair Value | | | Fair Value | |
Derivative and Balance Sheet Location | | Gross Asset | | | Gross Liability | | | Collateral Netted | | | Net Asset (Liability) on Balance Sheet | | | Gross
Asset | | | Gross
Liability | | | Collateral
Netted | | | Net Asset
(Liability)
on Balance
Sheet | |
Foreign currency exchange derivatives | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Other current assets | | $ | 97 | | | $ | 0 | | | $ | 0 | | | $ | 97 | | | $ | 30 | | $ | 0 | | $ | 0 | | $ | 30 | |
Interest rate swap derivatives | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Other current assets | | | 589 | | | | 0 | | | | 0 | | | | 589 | | |
Other current liabilities | | | 238 | | | | (9,379 | ) | | | 1,316 | | | | (7,825 | ) | | 0 | | (19,575 | ) | | 8,050 | | (11,525 | ) |
Other non-current liabilities and deferred credits | | | 725 | | | | (24,677 | ) | | | 5,454 | | | | (18,498 | ) | | 952 | | (32,190 | ) | | 0 | | (31,238 | ) |
Energy commodity derivatives | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Other current assets | | | 416 | | | | (245 | ) | | | 0 | | | | 171 | | | 9,203 | | (8,306 | ) | | 0 | | 897 | |
Other property and investments-net and other non-current assets | | | 6,369 | | | | (5,446 | ) | | | 0 | | | | 923 | | | 1,755 | | (1,159 | ) | | 0 | | 596 | |
Other current liabilities | | | 34,760 | | | | (41,241 | ) | | | 3,378 | | | | (3,103 | ) | | 11,037 | | (14,007 | ) | | 487 | | (2,483 | ) |
Other non-current liabilities and deferred credits | | | 28 | | | | (1,215 | ) | | | 0 | | | | (1,187 | ) | | | 1,725 | | | (8,043 | ) | | | 129 | | | (6,189 | ) |
Total derivative instruments recorded on the balance sheet | | $ | 43,222 | | | $ | (82,203 | ) | | $ | 10,148 | | | $ | (28,833 | ) | | $ | 24,702 | | $ | (83,280 | ) | | $ | 8,666 | | $ | (49,912 | ) |
Exposure to Demands for Collateral
Avista Corp.'s derivative contracts often require collateral (in the form of cash or letters of credit) or other credit enhancements, or reductions or terminations of a portion of the contract through cash settlement. In the event of a downgrade in Avista Corp.'s credit ratings or changes in market prices, additional collateral may be required. In periods of price volatility, the level of exposure can change significantly. As a result, sudden and significant demands may be made against Avista Corp.'s credit facilities and cash. Avista Corp. actively monitors the exposure to possible collateral calls and takes steps to mitigate capital requirements.
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The following table presents Avista Corp.'s collateral outstanding related to its derivative instruments as of September 30, 20202021 and December 31, 20192020 (in thousands):
| | | | | | | | |
| | September 30, | | | December 31, | |
| | 2021 | | | 2020 | |
Energy commodity derivatives | | | | | | |
Cash collateral posted | | $ | 22,947 | | | $ | 4,953 | |
Letters of credit outstanding | | | 21,500 | | | | 23,500 | |
Balance sheet offsetting | | | 12,343 | | | | 616 | |
Interest rate swap derivatives | | | | | | |
Cash collateral posted (offset by net derivative positions) | | | 0 | | | | 8,050 | |
| | September 30, | | | December 31, | |
| | 2020 | | | 2019 | |
Energy commodity derivatives | | | | | | | | |
Cash collateral posted | | $ | — | | | $ | 7,812 | |
Letters of credit outstanding | | | 21,500 | | | | 17,400 | |
Balance sheet offsetting | | | (5,623 | ) | | | 3,378 | |
Interest rate swap derivatives | | | | | | | | |
Cash collateral posted | | | 10,100 | | | | 6,770 | |
Balance sheet offsetting | | | 10,100 | | | | 6,770 | |
Certain of Avista Corp.’s derivative instruments contain provisions that require Avista Corp. to maintain an "investment grade" credit rating from the major credit rating agencies. If Avista Corp.’s credit ratings were to fall below "investment grade," it would be in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing collateralization on derivative instruments in net liability positions.
The following table presents the aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position and the amount of additional collateral Avista Corp. could be required to post as of September 30, 20202021 and December 31, 20192020 (in thousands):
| | | | | | | | |
| | September 30, | | | December 31, | |
| | 2021 | | | 2020 | |
Interest rate swap derivatives | | | | | | |
Liabilities with credit-risk-related contingent features | | | 20,732 | | | | 50,813 | |
Additional collateral to post | | | 20,732 | | | | 42,763 | |
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| | September 30, | | | December 31, | |
| | 2020 | | | 2019 | |
Energy commodity derivatives | | | | | | | | |
Liabilities with credit-risk-related contingent features | | $ | 3 | | | $ | 814 | |
Additional collateral to post | | | 3 | | | | 814 | |
Interest rate swap derivatives | | | | | | | | |
Liabilities with credit-risk-related contingent features | | | 66,598 | | | | 34,056 | |
Additional collateral to post | | | 56,498 | | | | 26,912 | |
NOTE 6. PENSION PLANS AND OTHER POSTRETIREMENT BENEFIT PLANS
Avista Utilities
Avista Utilities’ maintained the same pension and other postretirement plans during the nine months ended September 30, 20202021 as those described as of December 31, 2019. The Company’s funding policy is to contribute at least the minimum amounts that are required to be funded under the Employee Retirement Income Security Act, but not more than the maximum amounts that are currently deductible for income tax purposes.2020. The Company contributed $22$42 million in cash to the pension plan for the nine months ended September 30, 2020 and does 0t expect any further contributions2021, the full amount it expects to contribute in 2020.
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The Company uses a December 31 measurement date for its defined benefit pension and other postretirement benefit plans. The following table sets forth the components of net periodic benefit costs for the three and nine months ended September 30 (dollars in thousands):
| | | Pension Benefits | | | Other Postretirement Benefits | | | Pension Benefits | | | Other Postretirement Benefits | |
| | 2020 | | | 2019 | | | 2020 | | | 2019 | | | 2021 | | | 2020 | | | 2021 | | | 2020 | |
Three months ended September 30: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Service cost | | $ | 5,549 | | | $ | 4,948 | | | $ | 982 | | | $ | 754 | | | $ | 6,412 | | $ | 5,549 | | $ | 1,062 | | $ | 982 | |
Interest cost | | | 6,968 | | | | 7,134 | | | | 1,524 | | | | 1,140 | | | 6,528 | | 6,968 | | 1,305 | | 1,524 | |
Expected return on plan assets | | | (8,625 | ) | | | (7,913 | ) | | | (590 | ) | | | (616 | ) | | (9,835 | ) | | (8,625 | ) | | (509 | ) | | (590 | ) |
Amortization of prior service cost | | | 75 | | | | 75 | | | | (275 | ) | | | (275 | ) | | 75 | | 75 | | (275 | ) | | (275 | ) |
Net loss recognition | | | 1,678 | | | | 2,553 | | | | 1,243 | | | | 1,299 | | | | 1,592 | | | | 1,678 | | | | 777 | | | | 1,243 | |
Net periodic benefit cost | | $ | 5,645 | | | $ | 6,797 | | | $ | 2,884 | | | $ | 2,302 | | | $ | 4,772 | | | $ | 5,645 | | | $ | 2,360 | | | $ | 2,884 | |
Nine months ended September 30: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Service cost | | $ | 16,645 | | | $ | 14,770 | | | $ | 2,941 | | | $ | 2,279 | | | $ | 18,912 | | $ | 16,645 | | $ | 2,967 | | $ | 2,941 | |
Interest cost | | | 20,906 | | | | 21,372 | | | | 4,563 | | | | 3,676 | | | 19,638 | | 20,906 | | 3,990 | | 4,563 | |
Expected return on plan assets | | | (26,375 | ) | | | (23,681 | ) | | | (1,810 | ) | | | (1,945 | ) | | (29,314 | ) | | (26,375 | ) | | (1,967 | ) | | (1,810 | ) |
Amortization of prior service cost | | | 225 | | | | 225 | | | | (825 | ) | | | (825 | ) | | 225 | | 225 | | (825 | ) | | (825 | ) |
Net loss recognition | | | 5,011 | | | | 7,394 | | | | 3,729 | | | | 3,874 | | | | 5,103 | | | | 5,011 | | | | 3,196 | | | | 3,729 | |
Net periodic benefit cost | | $ | 16,412 | | | $ | 20,080 | | | $ | 8,598 | | | $ | 7,059 | | | $ | 14,564 | | | $ | 16,412 | | | $ | 7,361 | | | $ | 8,598 | |
Total service costs in the table above are recorded to the same accounts as labor expense. Labor and benefits expense is recorded to various projects based on whether the work is a capital project or an operating expense. Approximately 40 percent of all labor and benefits is capitalized to utility property and 60 percent is expensed to utility other operating expenses.
The non-service portion of costs in the table above are recorded to other expense below income from operations in the Condensed Consolidated Statements of Income or capitalized as a regulatory asset. Approximately 40 percent of the costs are capitalized to regulatory assets and 60 percent is expensed to the income statement.
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NOTE 7. INCOME TAXES
In accordance with interim reporting requirements, the Company uses an estimated annual effective tax rate for computing its provisions for income taxes. An estimate of annual income tax expense (or benefit) is made each interim period using estimates for annual pre-tax income, income tax adjustments, and tax credits. The estimated annual effective tax rates do not include discrete events such as tax law changes, examination settlements, accounting method changes, or adjustments to tax expense or benefits attributable to prior years. Discrete events are recorded in the interim period in which they occur or become known. The estimated annual tax rate is applied to year-to-date pre-tax income to determine income tax expense (or benefit) for the interim period consistent with the annual estimate. In subsequent interim periods, income tax expense (or benefit) for the period is computed as the difference between the year-to-date amount reported for the previous interim period and the current period’s year-to-date amount.
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The following table summarizes the significant factors impacting the difference between our effective tax rate and the federal statutory rate for the three and nine months ended September 30 (dollars in thousands):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three months ended September 30, | | | Nine months ended September 30, | |
| | 2021 | | | 2020 | | | 2021 | | | 2020 | |
Federal income taxes at statutory rates | | $ | 1,876 | | | | 21.0 | % | | $ | 1,204 | | | | 21.0 | % | | $ | 22,173 | | | | 21.0 | % | | $ | 15,167 | | | | 21.0 | % |
Increase (decrease) in tax resulting from: | | | | | | | | | | | | | | | | | | | | | | | | |
Tax effect of regulatory treatment of utility
plant differences | | | (3,277 | ) | | | (36.7 | ) | | | (2,427 | ) | | | (42.3 | ) | | | (9,721 | ) | | | (9.2 | ) | | | (7,244 | ) | | | (10.0 | ) |
State income tax expense | | | 143 | | | | 1.6 | | | | (363 | ) | | | (6.3 | ) | | | 975 | | | | 0.9 | | | | 539 | | | | 0.7 | |
Non-plant excess deferred turnaround (1) | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | (8,476 | ) | | | (11.8 | ) |
Settlement of prior year tax returns | | | (400 | ) | | | (4.5 | ) | | | 524 | | | | 9.1 | | | | (400 | ) | | | (0.4 | ) | | | 1,565 | | | | 2.2 | |
Flow through related to deduction of meters
and mixed service costs (2) | | | (5,277 | ) | | | (59.0 | ) | | | 0 | | | | 0 | | | | (5,277 | ) | | | (5.0 | ) | | | 0 | | | | 0 | |
Settlement of equity awards | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 909 | | | | 0.9 | | | | 165 | | | | 0.2 | |
Other | | | 1,503 | | | | 16.8 | | | | 1,921 | | | | 33.5 | | | | 471 | | | | 0.4 | | | | (244 | ) | | | (0.3 | ) |
Total income tax expense (benefit) | | $ | (5,432 | ) | | | (60.8 | )% | | $ | 859 | | | | 15.0 | % | | $ | 9,130 | | | | 8.6 | % | | $ | 1,472 | | | | 2.0 | % |
| | Three months ended September 30, | | | Nine months ended September 30, | |
| | 2020 | | | 2019 | | | 2020 | | | 2019 | |
Federal income taxes at statutory rates | | $ | 1,204 | | | | 21.0 | % | | $ | 1,041 | | | | 21.0 | % | | $ | 15,167 | | | | 21.0 | % | | $ | 36,554 | | | | 21.0 | % |
Increase (decrease) in tax resulting from: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Tax effect of regulatory treatment of utility plant differences | | | (2,427 | ) | | | (42.3 | ) | | | (2,139 | ) | | | (43.1 | ) | | | (7,244 | ) | | | (10.0 | ) | | | (6,358 | ) | | | (3.7 | ) |
State income tax expense | | | (363 | ) | | | (6.3 | ) | | | (800 | ) | | | (16.1 | ) | | | 539 | | | | 0.7 | | | | 851 | | | | 0.5 | |
Settlement of prior year tax returns | | | 524 | | | | 9.1 | | | | (604 | ) | | | (12.2 | ) | | | 1,565 | | | | 2.2 | | | | 1,995 | | | | 1.1 | |
Acquisition costs | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | (1,712 | ) | | | (1.0 | ) |
Non-plant excess deferred turnaround (1) | | | 0 | | | | 0 | | | | (20 | ) | | | (0.4 | ) | | | (8,476 | ) | | | (11.8 | ) | | | (5,621 | ) | | | (3.2 | ) |
Tax loss on sale of METALfx | | | 0 | | | | 0 | | | | (13 | ) | | | (0.2 | ) | | | 0 | | | | 0 | | | | (1,272 | ) | | | (0.7 | ) |
Valuation allowance | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 1,245 | | | | 0.7 | |
Settlement of equity awards | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 165 | | | | 0.2 | | | | 612 | | | | 0.4 | |
Other | | | 1,921 | | | | 33.5 | | | | 2,404 | | | | 48.4 | | | | (244 | ) | | | (0.3 | ) | | | 1,851 | | | | 1.1 | |
Total income tax expense | | $ | 859 | | | | 15.0 | % | | $ | (131 | ) | | | (2.6 | )% | | $ | 1,472 | | | | 2.0 | % | | $ | 28,145 | | | | 16.2 | % |
(1)
| In March 2020, the WUTC approved an all-party settlement agreement related to electric tax benefits that were set aside for Colstrip in the 2020 general rate case order. In the approved settlement agreement, the parties agreed to utilize approximately $10.9 million ($8.4 million when tax-effected) of the electric tax benefits to offset costs associated with accelerating the depreciation of Colstrip Units 3 & 4, to reflect a remaining useful life of those units through December 31, 2025. In the second quarter 2020, the Company recorded a one-time increase to depreciation expense with an offsetting decrease to income tax expense. |
In March 2019, the IPUC approved an all-party settlement agreement related to electric tax benefits that were set aside for Colstrip in the 2020 general rate case order. In the approved settlement agreement, the parties agreed to utilize approximately $6.4$10.9 million ($5.18.4 million when tax-effected) of the electric tax benefits to offset costs associated with accelerating the depreciation of Colstrip Units 3 & 4, to reflect a remaining useful life of those units through December 31, 2027.2025. In the second quarter 2019,2020, the Company recorded a one-time increase to depreciation expense with an offsetting decrease to income tax expense.
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Table(2)With the approval of ContentsAVISTA CORPORATION
2019 Tax Return
In October 2020, the Company filed its 2019 tax return including multipleIdaho and Washington general rate cases in September 2021, a change in accounting methods for tax. These changes will be re-characterizing certain previous capital expenditurestax methodology resulted in recognizing a flow through benefit related to expense for tax purposes. The resulting effect will increase deferred taxes by approximately $62 million. The Company intends to use the increase in deferred taxes as a tax credit to customers in order to offset potential base rate increases associated with general rate case filings.
meters and mixed service costs. NOTE 8. COMMITTED LINES OF CREDIT
Avista Corp.
Avista Corp. has a committed line of credit with various financial institutions in the total amount of $400.0$400.0 million. During the second quarter,In June 2021, the Company amended and extended, for one additional year, the revolvingentered into an amendment to its committed line of credit agreement for a revisedthat extends the expiration date of April 2022,to June 2026, with the option to extend for an additional one year period. period (subject to customary conditions). The committed line of credit is secured by non-transferable first mortgage bonds of the Company issued to the agent bank that would only become due and payable in the event, and then only to the extent, that the Company defaults on its obligations under the committed line of credit.
Balances outstanding and interest rates of borrowings (excluding letters of credit) under the Company’s revolving committed line of credit were as follows as of September 30, 20202021 and December 31, 20192020 (dollars in thousands):
| | | | | | | | |
| | September 30, | | | December 31, | |
| | 2021 | | | 2020 | |
Balance outstanding at end of period (1) | | $ | 269,000 | | | $ | 102,000 | |
Letters of credit outstanding at end of period | | $ | 25,618 | | | $ | 27,618 | |
Average interest rate at end of period | | | 1.09 | % | | | 1.22 | % |
| | September 30, | | | December 31, | |
| | 2020 | | | 2019 | |
Balance outstanding at end of period | | $ | 50,000 | | | $ | 182,300 | |
Letters of credit outstanding at end of period | | $ | 25,573 | | | $ | 21,473 | |
Average interest rate at end of period | | | 1.20 | % | | | 2.64 | % |
(1)
As of September 30, 2020 and December 31, 2019, the borrowings2021 there was $269.0 million outstanding under Avista Corp.'sthe committed line of credit; however, $199.1 million was classified as short-term borrowings and the remaining $69.9 million was classified as long-term debt on the
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Condensed Consolidated Balance Sheet due to the Company's intention to refinance such amount on a long-term basis. The amount classified as long-term debt will be refinanced through the issuance and sale of first mortgage bonds in December 2021 pursuant to a bond purchase agreement entered into in September 2021. See Note 10 for further discussion of the bond purchase agreement and the refinancing of short-term debt on a long-term basis. The entire outstanding amount of the committed line of credit wereas of December 31, 2020 was classified as short-term borrowings on the Condensed Consolidated Balance Sheet.borrowings.
AEL&P
AEL&P
AEL&P has a committed line of credit in the amount of $25.0$25.0 million that expires in November 2024. As2024. There were 0 borrowings as of September 30, 20202021 and $1.0 million as of December 31, 2019, there were borrowings of $0 and $3.5 million, respectively,2020, and there were 0 letters of credit outstanding under this committed line of credit.credit as of September 30, 2021 and December 31, 2020. The committed line of credit is secured by non-transferable first mortgage bonds of AEL&P issued to the agent bank that would only become due and payable in the event, and then only to the extent, that AEL&P defaults on its obligations under the committed line of credit.
NOTE 9. CREDIT AGREEMENT
OnIn April 6, 2020, the Company entered into a one-year Credit Agreement with U.S. Bank National Association, as Lender and Administrative Agent, and CoBank, ACB, as Lender,various financial institutions, in the amount of $100 million at an interest rate of 1-Month LIBOR plus 125 basis points with an expiration date of April 5, 2021. Indebtedness under this agreement is unsecured.
The Credit Agreement contains customary covenants and default provisions, including a covenant not to permit the ratio of "consolidated total debt" to "consolidated total capitalization" of Avista Corp. to be greater than 65 percent at any time.
$100.0 million. The Company has borrowed the entire $100$100.0 million available under this agreement, which is being used to provide additional liquidity. The borrowing can be prepaid; however,in April 2020 and repaid the amount prepaid cannot be re-borrowed.outstanding balance in April 2021.
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NOTE 10. LONG-TERM DEBT
On September 30, 2020,28, 2021, the Company issued and sold $165.0$70.0 million of 3.072.90 percent first mortgage bonds due in 20502051 pursuant to a bond purchase agreement with institutional investors in the private placement market. The Company expects to issue and sell an additional $70.0 million of first mortgage bonds under this bond purchase agreement on December 1, 2021. In connection with the pricing of the first mortgage bonds in June 2020,September 2021, the Company cash-settled 74 interest rate swap derivatives (notional aggregate amount of $70.0$45.0 million) and paid a net amount of $33.5$17.2 million, which will be amortized as a component of interest expense over the life of the debt. The Company paid this amount in July 2020. See Note 5 for a discussion of interest rate swap derivatives.
The total net proceeds from the sale of the new bonds will be used to repay a portion of the borrowings outstanding under the Company’s $400.0$400.0 million committed line of credit. Because the Company is refinancing short-term debt on a long-term basis, the Company has classified $69.9 million of the committed line of credit and repay maturingthat is expected to be paid off with the net proceeds of the first mortgage bonds to be issued in December as long-term debt of $52.0 million.debt.
NOTE 11. LONG-TERM DEBT TO AFFILIATED TRUSTS
In 1997, the Company issued Floating Rate Junior Subordinated Deferrable Interest Debentures, Series B, with a principal amount of $51.5$51.5 million to Avista Capital II, an affiliated business trust formed by the Company. Avista Capital II issued $50.0$50.0 million of Preferred Trust Securities with a floating distribution rate of LIBOR plus 0.875 percent, calculated and reset quarterly.
The distribution rates paid were as follows during the nine months ended September 30, 20202021 and the year ended December 31, 2019:2020:
| | | September 30, | | | December 31, | | | September 30, | | | December 31, | |
| | 2020 | | | 2019 | | | 2021 | | | 2020 | |
Low distribution rate | | | 1.12 | % | | | 2.79 | % | | 0.99 | % | | 1.10 | % |
High distribution rate | | | 2.79 | % | | | 3.61 | % | | 1.10 | % | | 2.79 | % |
Distribution rate at the end of the period | | | 1.12 | % | | | 2.79 | % | | 0.99 | % | | 1.10 | % |
Concurrent with the issuance of the Preferred Trust Securities, Avista Capital II issued $1.5$1.5 million of Common Trust Securities to the Company. The Preferred Trust Securities may be redeemed at the option of Avista Capital II at any time and mature on June 1, 2037. In December 2000, the Company purchased $10.0$10.0 million of these Preferred Trust Securities.
The Company owns 100 percent of Avista Capital II and has solely and unconditionally guaranteed the payment of distributions on, and redemption price and liquidation amount for, the Preferred Trust Securities to the extent that Avista Capital II has funds available for such payments from the respective debt securities. Upon maturity or prior redemption of such debt securities, the Preferred Trust
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Securities will be mandatorily redeemed. The Company does not include these capital trusts in its consolidated financial statements as Avista Corp. is not the primary beneficiary. As such, the sole assets of the capital trusts are $51.5$51.5 million of junior subordinated deferrable interest debentures of Avista Corp., which are reflected on the Condensed Consolidated Balance Sheets. Interest expense to affiliated trusts in the Condensed Consolidated Statements of Income represents interest expense on these debentures.
NOTE 12. FAIR VALUE
The carrying values of cash and cash equivalents, accounts and notes receivable, accounts payable, and short-term borrowings are reasonable estimates of their fair values. Long-term debt (including current portion and material capitalfinance leases) and long-term debt to affiliated trusts are reported at their carrying value on the Condensed Consolidated Balance Sheets.Sheets, which may be different from the estimated fair value. See below for the estimated fair value of long-term debt and long-term debt to affiliated trusts.
The fair value hierarchy prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to fair values derived from unobservable inputs (Level 3 measurement).
The three levels of the fair value hierarchy are defined as follows:
Level 1 – Quoted prices are available in active markets for identical assets or liabilities. Active markets are those in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis.
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Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, but which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.
Level 3 – Pricing inputs include significant inputs that are generally unobservable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.
Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values incorporates various factors that not only include the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters of credit), but also the impact of Avista Corp.’s nonperformance risk on its liabilities.
The following table sets forth the carrying value and estimated fair value of the Company’s financial instruments not reported at estimated fair value on the Condensed Consolidated Balance Sheets as of September 30, 20202021 and December 31, 20192020 (dollars in thousands):
| | | | | | | | | | | | | | | | |
| | September 30, 2021 | | | December 31, 2020 | |
| | Carrying
Value | | | Estimated
Fair Value | | | Carrying
Value | | | Estimated
Fair Value | |
Long-term debt (Level 2) | | $ | 963,500 | | | $ | 1,162,759 | | | $ | 963,500 | | | $ | 1,189,824 | |
Long-term debt (Level 3) | | | 1,130,000 | | | | 1,263,916 | | | | 1,060,000 | | | | 1,235,248 | |
Snettisham finance lease obligation (Level 3) | | | 49,549 | | | | 55,000 | | | | 51,750 | | | | 58,700 | |
Long-term debt to affiliated trusts (Level 3) | | | 51,547 | | | | 43,815 | | | | 51,547 | | | | 43,815 | |
| | September 30, 2020 | | | December 31, 2019 | |
| | Carrying Value | | | Estimated Fair Value | | | Carrying Value | | | Estimated Fair Value | |
Long-term debt (Level 2) | | $ | 963,500 | | | $ | 1,177,454 | | | $ | 963,500 | | | $ | 1,124,649 | |
Long-term debt (Level 3) | | | 1,112,000 | | | | 1,265,095 | | | | 947,000 | | | | 1,048,440 | |
Snettisham finance lease obligation (Level 3) | | | 52,450 | | | | 60,500 | | | | 54,550 | | | | 58,000 | |
Long-term debt to affiliated trusts (Level 3) | | | 51,547 | | | | 41,238 | | | | 51,547 | | | | 41,238 | |
These estimates of fair value of long-term debt and long-term debt to affiliated trusts were primarily based on available market information, which generally consists of estimated market prices from third party brokers for debt with similar risk and terms. The price ranges obtained from the third party brokers consisted of par valuesmarket prices of 80.0085.00 percent to 143.51,139.35 percent of the principal
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amount, where a par valuemarket price of 100.0 percent (adjusted for unamortized discount or premium) represents the carrying value recorded on the Condensed Consolidated Balance Sheets. Level 2 long-term debt represents publicly issued bonds with quoted market prices; however, due to their limited trading activity, they are classified as Level 2 because brokers must generate quotes and make estimates if there is no trading activity near a period end. Level 3 long-term debt consists of private placement bonds and debt to affiliated trusts, which typically have no secondary trading activity. Fair values in Level 3 are estimated based on market prices from third party brokers using secondary market quotes for debt with similar risk and terms to generate quotes for Avista Corp. bonds. Due to the unique nature of the Snettisham finance lease obligation, the estimated fair value of these items was determined based on a discounted cash flow model using available market information. The Snettisham finance lease obligation was discounted to present value using the Morgan Markets A Ex-Fin discount rate as published on September 30, 20202021 and December 31, 2019.2020.
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The following table discloses by level within the fair value hierarchy the Company’s assets and liabilities measured and reported on the Condensed Consolidated Balance Sheets as of September 30, 20202021 and December 31, 20192020 at fair value on a recurring basis (dollars in thousands):
| | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | | Level 2 | | | Level 3 | | | Counterparty
and Cash
Collateral
Netting (1) | | | Total | |
September 30, 2021 | | | | | | | | | | | | | | | |
Assets: | | | | | | | | | | | | | | | |
Energy commodity derivatives | | $ | 0 | | | $ | 75,059 | | | $ | 0 | | | $ | (61,098 | ) | | $ | 13,961 | |
Level 3 energy commodity derivatives: | | | | | | | | | | | | | | | |
Natural gas exchange agreement | | | 0 | | | | 0 | | | | 108 | | | | (108 | ) | | | 0 | |
Interest rate swap derivatives | | | 0 | | | | 4,549 | | | | 0 | | | | (2,072 | ) | | | 2,477 | |
Deferred compensation assets: | | | | | | | | | | | | | | | |
Mutual Funds: | | | | | | | | | | | | | | | |
Fixed income securities (2) | | | 1,888 | | | | 0 | | | | 0 | | | | 0 | | | | 1,888 | |
Equity securities (2) | | | 7,916 | | | | 0 | | | | 0 | | | | 0 | | | | 7,916 | |
Total | | $ | 9,804 | | | $ | 79,608 | | | $ | 108 | | | $ | (63,278 | ) | | $ | 26,242 | |
Liabilities: | | | | | | | | | | | | | | | |
Energy commodity derivatives | | $ | 0 | | | $ | 74,023 | | | $ | 0 | | | $ | (73,441 | ) | | $ | 582 | |
Level 3 energy commodity derivatives: | | | | | | | | | | | | | | | |
Natural gas exchange agreement | | | 0 | | | | 0 | | | | 11,157 | | | | (108 | ) | | | 11,049 | |
Foreign currency exchange derivatives | | | 0 | | | | 86 | | | | 0 | | | | 0 | | | | 86 | |
Interest rate swap derivatives | | | 0 | | | | 20,732 | | | | 0 | | | | (2,072 | ) | | | 18,660 | |
Total | | $ | 0 | | | $ | 94,841 | | | $ | 11,157 | | | $ | (75,621 | ) | | $ | 30,377 | |
December 31, 2020 | | | | | | | | | | | | | | | |
Assets: | | | | | | | | | | | | | | | |
Energy commodity derivatives | | $ | — | | | $ | 23,645 | | | $ | — | | | $ | (22,152 | ) | | $ | 1,493 | |
Level 3 energy commodity derivatives: | | | | | | | | | | | | | | | |
Natural gas exchange agreement | | | — | | | | — | | | | 75 | | | | (75 | ) | | | — | |
Foreign currency exchange derivatives | | | — | | | | 30 | | | | — | | | | — | | | | 30 | |
Interest rate swap derivatives | | | — | | | | 952 | | | | — | | | | (952 | ) | | | — | |
Deferred compensation assets: | | | | | | | | | | | | | | | |
Mutual Funds: | | | | | | | | | | | | | | | |
Fixed income securities (2) | | | 2,471 | | | | — | | | | — | | | | — | | | | 2,471 | |
Equity securities (2) | | | 6,228 | | | | — | | | | — | | | | — | | | | 6,228 | |
Total | | $ | 8,699 | | | $ | 24,627 | | | $ | 75 | | | $ | (23,179 | ) | | $ | 10,222 | |
Liabilities: | | | | | | | | | | | | | | | |
Energy commodity derivatives | | $ | — | | | $ | 23,030 | | | $ | — | | | $ | (22,768 | ) | | $ | 262 | |
Level 3 energy commodity derivatives: | | | | | | | | | | | | | | | |
Natural gas exchange agreement | | | — | | | | — | | | | 8,485 | | | | (75 | ) | | | 8,410 | |
Interest rate swap derivatives | | | — | | | | 51,765 | | | | — | | | | (9,002 | ) | | | 42,763 | |
Total | | $ | — | | | $ | 74,795 | | | $ | 8,485 | | | $ | (31,845 | ) | | $ | 51,435 | |
| | Level 1 | | | Level 2 | | | Level 3 | | | Counterparty and Cash Collateral Netting (1) | | | Total | |
September 30, 2020 | | | | | | | | | | | | | | | | | | | | |
Assets: | | | | | | | | | | | | | | | | | | | | |
Energy commodity derivatives | | $ | — | | | $ | 35,662 | | | $ | — | | | $ | (31,923 | ) | | $ | 3,739 | |
Foreign currency exchange derivatives | | | — | | | | 7 | | | | — | | | | (7 | ) | | | — | |
Deferred compensation assets: | | | | | | | | | | | | | | | | | | | | |
Mutual Funds: | | | | | | | | | | | | | | | | | | | | |
Fixed income securities (2) | | | 2,498 | | | | — | | | | — | | | | — | | | | 2,498 | |
Equity securities (2) | | | 5,824 | | | | — | | | | — | | | | — | | | | 5,824 | |
Total | | $ | 8,322 | | | $ | 35,669 | | | $ | — | | | $ | (31,930 | ) | | $ | 12,061 | |
Liabilities: | | | | | | | | | | | | | | | | | | | | |
Energy commodity derivatives | | $ | — | | | $ | 27,024 | | | $ | — | | | $ | (26,300 | ) | | $ | 724 | |
Level 3 energy commodity derivatives: | | | | | | | | | | | | | | | | | | | | |
Natural gas exchange agreement | | | — | | | | — | | | | 3,674 | | | | — | | | | 3,674 | |
Foreign currency exchange derivatives | | | — | | | | 52 | | | | — | | | | (7 | ) | | | 45 | |
Interest rate swap derivatives | | | — | | | | 66,598 | | | | — | | | | (10,100 | ) | | | 56,498 | |
Total | | $ | — | | | $ | 93,674 | | | $ | 3,674 | | | $ | (36,407 | ) | | $ | 60,941 | |
December 31, 2019 | | | | | | | | | | | | | | | | | | | | |
Assets: | | | | | | | | | | | | | | | | | | | | |
Energy commodity derivatives | | $ | — | | | $ | 41,546 | | | $ | — | | | $ | (40,452 | ) | | $ | 1,094 | |
Level 3 energy commodity derivatives: | | | | | | | | | | | | | | | | | | | | |
Natural gas exchange agreement | | | — | | | | — | | | | 27 | | | | (27 | ) | | | — | |
Foreign currency exchange derivatives | | | — | | | | 97 | | | | — | | | | — | | | | 97 | |
Interest rate swap derivatives | | | — | | | | 1,552 | | | | — | | | | (963 | ) | | | 589 | |
Deferred compensation assets: | | | | | | | | | | | | | | | | | | | | |
Mutual Funds: | | | | | | | | | | | | | | | | | | | | |
Fixed income securities (2) | | | 2,232 | | | | — | | | | — | | | | — | | | | 2,232 | |
Equity securities (2) | | | 6,271 | | | | — | | | | — | | | | — | | | | 6,271 | |
Total | | $ | 8,503 | | | $ | 43,195 | | | $ | 27 | | | $ | (41,442 | ) | | $ | 10,283 | |
Liabilities: | | | | | | | | | | | | | | | | | | | | |
Energy commodity derivatives | | $ | — | | | $ | 45,144 | | | $ | — | | | $ | (43,830 | ) | | $ | 1,314 | |
Level 3 energy commodity derivatives: | | | | | | | | | | | | | | | | | | | | |
Natural gas exchange agreement | | | — | | | | — | | | | 3,003 | | | | (27 | ) | | | 2,976 | |
Interest rate swap derivatives | | | — | | | | 34,056 | | | | — | | | | (7,733 | ) | | | 26,323 | |
Total | | $ | — | | | $ | 79,200 | | | $ | 3,003 | | | $ | (51,590 | ) | | $ | 30,613 | |
(1)26
| The Company is permitted to net derivative assets and derivative liabilities with the same counterparty when a legally enforceable master netting agreement exists. In addition, the Company nets derivative assets and derivative liabilities against any payables and receivables for cash collateral held or placed with these same counterparties.
|
(2)
| These assets are included in other property and investments-net and other non-current assets on the Condensed Consolidated Balance Sheets.
|
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(1)The Company is permitted to net derivative assets and derivative liabilities with the same counterparty when a legally enforceable master netting agreement exists. In addition, the Company nets derivative assets and derivative liabilities against any payables and receivables for cash collateral held or placed with these same counterparties.
(2)These assets are included in other property and investments-net and other non-current assets on the Condensed Consolidated Balance Sheets.
The difference between the amount of derivative assets and liabilities disclosed in respective levels in the table above and the amount of derivative assets and liabilities disclosed on the Condensed Consolidated Balance Sheets is due to netting arrangements with certain counterparties. See Note 5 for additional discussion of derivative netting.
To establish fair value for energy commodity derivatives, the Company uses quoted market prices and forward price curves to estimate the fair value of energy commodity derivative instruments included in Level 2. In particular, electric derivative valuations are performed using market quotes, adjusted for periods in between quotable periods. Natural gas derivative valuations are estimated using New York Mercantile Exchange pricing for similar instruments, adjusted for basin differences, using market quotes. Where observable inputs are available for substantially the full term of the contract, the derivative asset or liability is included in Level 2.
To establish fair values for interest rate swap derivatives, the Company uses forward market curves for interest rates for the term of the swaps and discounts the cash flows back to present value using an appropriate discount rate. The discount rate is calculated by third party brokers according to the terms of the swap derivatives and evaluated by the Company for reasonableness, with consideration given to the potential non-performance risk by the Company. Future cash flows of the interest rate swap derivatives are equal to the fixed interest rate in the swap compared to the floating market interest rate multiplied by the notional amount for each period.
To establish fair value for foreign currency derivatives, the Company uses forward market curves for Canadian dollars against the US dollar and multiplies the difference between the locked-in price and the market price by the notional amount of the derivative. Forward foreign currency market curves are provided by third party brokers. The Company's credit spread is factored into the locked-in price of the foreign exchange contracts.
Deferred compensation assets and liabilities represent funds held by the Company in a Rabbi Trust for an executive deferral plan. These funds consist of actively traded equity and bond funds with quoted prices in active markets. The balance disclosed in the table above excludes cash and cash equivalents of $0.5$0.1 million and $0.4$0.5 million as of September 30, 20202021 and December 31, 2019,2020, respectively.
Level 3 Fair Value
The following table presents the quantitative information which was used to estimate the fair values of the Level 3 assets and liabilities above as of September 30, 20202021 (dollars in thousands):
| | | | | | | | | | |
|
| Fair Value
(Net) at |
|
| Valuation |
| Unobservable |
| Range and Weighted |
|
| September 30, 2021 |
|
| Technique |
| Input |
| Average Price |
Natural gas exchange agreement |
| $ | (11,049 | ) |
| Internally derived weighted average cost of gas |
| Forward purchase |
| $2.41 - $3.83/mmBTU
$2.92 Weighted Average |
|
|
|
|
|
|
| Forward sales prices |
| $2.40 - $8.25/mmBTU
$4.96 Weighted Average |
|
|
|
|
|
|
| Purchase volumes |
| 130,000 - 310,000 mmBTUs |
|
|
|
|
|
|
| Sales volumes |
| 75,000 - 310,000 mmBTUs |
| | Fair Value (Net) at | | | Valuation | | Unobservable | | Range and Weighted |
| | September 30, 2020 | | | Technique | | Input | | Average Price |
Natural gas exchange agreement | | $ | (3,674 | ) | | Internally derived weighted average cost of gas | | Forward sales prices | | $2.51 - $4.77/mmBTU $3.97 Weighted Average |
| | | | | | | | Sales volumes | | 140,000 - 310,000 mmBTUs |
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The following table presents activity for energy commodity derivative assets (liabilities) measured at fair value using significant unobservable inputs (Level 3) for the three and nine months ended September 30 (dollars in thousands):
| | Natural Gas Exchange Agreement | | | Power Exchange Agreement | | | Total | |
Three months ended September 30, 2020: | | | | | | | | | | | | |
Balance as of July 1, 2020 | | $ | (2,628 | ) | | $ | — | | | $ | (2,628 | ) |
Total gains or (losses) (realized/unrealized): | | | | | | | | | | | | |
Included in regulatory assets/liabilities (1) | | | (1,046 | ) | | | — | | | | (1,046 | ) |
Settlements | | | — | | | | — | | | | — | |
Ending balance as of September 30, 2020 (2) | | $ | (3,674 | ) | | $ | — | | | $ | (3,674 | ) |
Three months ended September 30, 2019: | | | | | | | | | | | | |
Balance as of July 1, 2019 | | $ | (2,992 | ) | | $ | — | | | $ | (2,992 | ) |
Total gains or (losses) (realized/unrealized): | | | | | | | | | | | | |
Included in regulatory assets/liabilities (1) | | | (133 | ) | | | — | | | | (133 | ) |
Settlements | | | (9 | ) | | | — | | | | (9 | ) |
Ending balance as of September 30, 2019 (2) | | $ | (3,134 | ) | | $ | — | | | $ | (3,134 | ) |
Nine months ended September 30, 2020: | | | | | | | | | | | | |
Balance as of January 1, 2020 | | $ | (2,976 | ) | | $ | — | | | $ | (2,976 | ) |
Total gains or (losses) (realized/unrealized): | | | | | | | | | | | | |
Included in regulatory assets/liabilities (1) | | | (952 | ) | | | — | | | | (952 | ) |
Settlements | | | 254 | | | | — | | | | 254 | |
Ending balance as of September 30, 2020 (2) | | $ | (3,674 | ) | | $ | — | | | $ | (3,674 | ) |
Nine months ended September 30, 2019: | | | | | | | | | | | | |
Balance as of January 1, 2019 | | $ | (2,774 | ) | | $ | (2,488 | ) | | $ | (5,262 | ) |
Total gains or (losses) (realized/unrealized): | | | | | | | | | | | | |
Included in regulatory assets/liabilities (1) | | | 8,015 | | | 436 | | | | 8,451 | |
Settlements | | | (8,375 | ) | | | 2,052 | | | | (6,323 | ) |
Ending balance as of September 30, 2019 (2) | | $ | (3,134 | ) | | $ | — | | | $ | (3,134 | ) |
| | | | |
|
| Natural Gas
Exchange
Agreement |
|
Three months ended September 30, 2021: |
|
|
|
Balance as of June 30, 2021 |
| $ | (6,078 | ) |
Total gains or (losses) (realized/unrealized): |
|
|
|
Included in regulatory assets/liabilities (1) | All gains and losses are included in other regulatory assets and liabilities. There were no gains and losses included in either net income or other comprehensive income during any of the periods presented in the table above.
|
| (4,971 | ) |
Settlements |
|
| 0 |
|
Ending balance as of September 30, 2021 (2) | There were no purchases, issuances
| $ | (11,049 | ) |
Three months ended September 30, 2020: |
|
|
|
Balance as of June 30, 2020 |
| $ | (2,628 | ) |
Total gains or transfers from other categories(losses) (realized/unrealized): |
|
|
|
Included in regulatory assets/liabilities (1) |
|
| (1,046 | ) |
Settlements |
|
| 0 |
|
Ending balance as of any derivatives instruments during the periods presentedSeptember 30, 2020 (2) |
| $ | (3,674 | ) |
Nine months ended September 30, 2021: |
|
|
|
Balance as of December 31, 2020 |
| $ | (8,410 | ) |
Total gains (realized/unrealized): |
|
|
|
Included in the table above.regulatory assets/liabilities (1) |
|
| (1,482 | ) |
Settlements |
|
| (1,157 | ) |
Ending balance as of September 30, 2021 (2) |
| $ | (11,049 | ) |
Nine months ended September 30, 2020: |
|
|
|
Balance as of December 31, 2019 |
| $ | (2,976 | ) |
Total gains (realized/unrealized): |
|
|
|
Included in regulatory assets/liabilities (1) |
|
| (952 | ) |
Settlements |
|
| 254 |
|
Ending balance as of September 30, 2020 (2) |
| $ | (3,674 | ) |
(1)All gains and losses are included in other regulatory assets and liabilities. There were no gains and losses included in either net income or other comprehensive income during any of the periods presented in the table above.
(2)There were no purchases, issuances or transfers from other categories of any derivatives instruments during the periods presented in the table above.
NOTE 13. COMMON STOCK
During the second quarterThe Company has board and regulatory authority to issue 3.9 million shares of 2020,common stock in public offerings. Of this number, the Company entered into 4 separate sales agency agreements under which the sales agents may offer and sell new shares of the Company’s common stock from time to time. The Company issued 0.81.1 million shares and 1.4 million shares during the three and nine months ended September 30, 2020,2021, respectively, under the new sales agency agreements. These agreements provide forrelating to the Company's periodic offering of a maximum of approximately 3.2program, leaving 2.5 million shares of which approximately 1.8 million shares remain unissued as of September 30, 2020.authorized to be issued.
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NOTE 14. ACCUMULATED OTHER COMPREHENSIVE LOSS
Accumulated other comprehensive loss, net of tax, consisted of the following as of September 30, 20202021 and December 31, 20192020 (dollars in thousands):
| | | | | | | | |
| | September 30,
2021 | | | December 31,
2020 | |
Unfunded benefit obligation for pensions and other postretirement benefit plans -
net of taxes of $3,575 and $3,822, respectively | | $ | 13,451 | | | $ | 14,378 | |
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| | September 30, 2020 | | | December 31, 2019 | |
Unfunded benefit obligation for pensions and other postretirement benefit plans - net of taxes of $2,556 and $2,727, respectively | | $ | 9,614 | | | $ | 10,259 | |
The following table details the reclassifications out of accumulated other comprehensive loss to net income by component for the three and nine months ended September 30 (dollars in thousands):
| | | | | | | | | | | | | | | | |
| | Amounts Reclassified from Accumulated Other
Comprehensive Loss | |
| | Three months ended September 30, | | | Nine months ended September 30, | |
Details about Accumulated Other Comprehensive Loss Components
(Affected Line Item in Statement of Income) | | 2021 | | | 2020 | | | 2021 | | | 2020 | |
Amortization of defined benefit pension and
postretirement benefit items | | | | | | | | | | | | |
Amortization of net prior service cost (a) | | $ | (200 | ) | | $ | (200 | ) | | $ | (600 | ) | | $ | (600 | ) |
Amortization of net loss (a) | | | 2,369 | | | | 3,120 | | | | 8,299 | | | | 9,341 | |
Adjustment due to effects of regulation (a) | | | (1,784 | ) | | | (2,642 | ) | | | (6,525 | ) | | | (7,925 | ) |
Total before tax (b) | | | 385 | | | | 278 | | | | 1,174 | | | | 816 | |
Tax expense (b) | | | (81 | ) | | | (58 | ) | | | (247 | ) | | | (171 | ) |
Net of tax (b) | | $ | 304 | | | $ | 220 | | | $ | 927 | | | $ | 645 | |
(a)These accumulated other comprehensive loss components are included in the computation of net periodic pension cost (see Note 6 for additional details).
| | Amounts Reclassified from Accumulated Other Comprehensive Loss | |
| | Three months ended September 30, | | | Nine months ended September 30, | |
Details about Accumulated Other Comprehensive Loss Components (Affected Line Item in Statement of Income) | | 2020 | | | 2019 | | | 2020 | | | 2019 | |
Amortization of defined benefit pension items | | | | | | | | | | | | | | | | |
Amortization of net prior service cost (a) | | $ | (200 | ) | | $ | (200 | ) | | $ | (600 | ) | | $ | (600 | ) |
Amortization of net loss (a) | | | 3,120 | | | | 3,852 | | | | 9,341 | | | | 11,268 | |
Adjustment due to effects of regulation (a) | | | (2,642 | ) | | | (3,447 | ) | | | (7,925 | ) | | | (10,057 | ) |
Total before tax (b) | | | 278 | | | | 205 | | | | 816 | | | | 611 | |
Tax expense (b) | | | (58 | ) | | | (43 | ) | | | (171 | ) | | | (128 | ) |
Net of tax (b) | | $ | 220 | | | $ | 162 | | | $ | 645 | | | $ | 483 | |
| (b) Description is also the affected line item on the Condensed Consolidated Statement of Income. | These accumulated other comprehensive loss components are included in the computation of net periodic pension cost (see Note 6 for additional details).
|
| (b)
| Description is also the affected line item on the Condensed Consolidated Statement of Income
|
NOTE 15. EARNINGS PER COMMON SHARE ATTRIBUTABLE TO AVISTA CORP. SHAREHOLDERS
The following table presents the computation of basic and diluted earnings per common share attributable to Avista Corp. shareholders for the three and nine months ended September 30 (in thousands, except per share amounts):
| | | Three months ended September 30, | | | Nine months ended September 30, | | | Three months ended September 30, | | | Nine months ended September 30, | |
| | 2020 | | | 2019 | | | 2020 | | | 2019 | | | 2021 | | | 2020 | | | 2021 | | | 2020 | |
Numerator: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Net income attributable to Avista Corp. shareholders | | $ | 4,876 | | | $ | 5,090 | | | $ | 70,753 | | | $ | 146,203 | | |
Net income | | | $ | 14,366 | | | $ | 4,876 | | | $ | 96,457 | | | $ | 70,753 | |
Denominator: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Weighted-average number of common shares outstanding-basic | | | 68,194 | | | | 66,265 | | | | 67,638 | | | | 65,964 | | | 70,054 | | 68,194 | | 69,582 | | 67,638 | |
Effect of dilutive securities: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Performance and restricted stock awards | | | 143 | | | | 86 | | | | 131 | | | | 86 | | | | 75 | | | | 143 | | | | 140 | | | | 131 | |
Weighted-average number of common shares outstanding-diluted | | | 68,337 | | | | 66,351 | | | | 67,769 | | | | 66,050 | | | | 70,129 | | | | 68,337 | | | | 69,722 | | | | 67,769 | |
Earnings per common share attributable to Avista Corp. shareholders: | | | | | | | | | | | | | | | | | |
Earnings per common share: | | | | | | | | | | | | | |
Basic | | $ | 0.07 | | | $ | 0.08 | | | $ | 1.05 | | | $ | 2.22 | | | $ | 0.21 | | | $ | 0.07 | | | $ | 1.39 | | | $ | 1.05 | |
Diluted | | $ | 0.07 | | | $ | 0.08 | | | $ | 1.04 | | | $ | 2.21 | | | $ | 0.20 | | | $ | 0.07 | | | $ | 1.38 | | | $ | 1.04 | |
There were 0 shares excluded from the calculation because they were antidilutive.
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NOTE 16. COMMITMENTS AND CONTINGENCIES
In the course of its business, the Company becomes involved in various claims, controversies, disputes and other contingent matters, including the items described in this Note. Some of these claims, controversies, disputes and other contingent matters involve litigation or other contested proceedings. For all such matters, the Company intends to vigorously protect and defend its interests and pursue its rights. However, no assurance can be given as to the ultimate outcome of any particular matter because litigation and other contested proceedings are inherently subject to numerous uncertainties. For matters that affect Avista Utilities’ or AEL&P's operations, the Company intends to seek, to the extent appropriate, recovery of incurred costs through the ratemaking process.
2015 Washington General Rate Cases
In January 2016, the Company received an order (Order 05) that concluded its electric and natural gas general rate cases that were originally filed with the WUTC in February 2015. New electric and natural gas rates were effective on January 11, 2016.
PC Petition for Judicial Review
In March 2016, Public Counsel (PC) filed in Thurston County Superior Court a Petition for Judicial Review of the WUTC's Order 05 and Order 06. In April 2016, this matter was certified for review directly by the Court of Appeals, an intermediate appellate court in the State of Washington.
In August 2018, the Court of Appeals issued a "Published Opinion" (Opinion) which concluded that the WUTC's use of an attrition allowance to calculate Avista Corp.'s rate base violated Washington law. In the Opinion, the Court stated that because the projected additions to rate base in the future were not "used and useful" for service at the time the request for the rate increase was made, they may not lawfully be included in the Company's rate base to justify a rate increase. Accordingly, the Court concluded that the WUTC erred in including an attrition allowance in the calculation of Avista Corp.’s electric and natural gas rate base. The Court noted, however, that the law does not prohibit an attrition allowance in the calculation, for ratemaking purposes, of recoverable operating and maintenance expense. Since the WUTC order provided one lump sum attrition allowance without distinguishing what portion was for rate base and which was for operating and maintenance expenses or other considerations, the Court struck all portions of the attrition allowance attributable to Avista Corp.'s rate base and reversed and remanded the case for the WUTC to recalculate Avista Corp.’s rates without including an attrition allowance in the calculation of rate base.
In March 2020, the Company received an order from the WUTC that will require it to refund $8.5 million to electric and natural gas customers. The Company will refund $4.9 million to electric customers and $3.6 million to natural gas customers. The Company previously recorded a customer refund liability of $3.6 million in 2019.
Boyds Fire (State of Washington Department of Natural Resources (DNR) v. Avista)
In August 2019, the Company was served with a complaint, captioned “State of Washington Department of Natural Resources v. Avista Corporation,” seeking recovery up to $4.4$4.4 million for fire suppression and investigation costs and related expenses incurred in connection with a wildfire that occurred in Ferry County, Washington in August 2018. Specifically, theThe complaint alleges that the fire, which became known as the “Boyds Fire,” was caused by a dead ponderosa pine tree falling into an overhead distribution line, and that
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Avista Corp. was negligent in failing to identify and remove the tree before it came into contact with the line. Avista Corp. disputes that the tree in question was the cause of the fire and that it was negligent in failing to identify and remove it. Additional lawsuits have subsequently been filed by private landowners seeking property damages, and holders of insurance subrogation claims seeking recovery of insurance proceeds paid.
All four suitsThe lawsuits were filed in the Superior Court of Ferry County, Washington.Washington and subsequently consolidated into a single action. The Company intends to vigorously defend itself in the litigation. However, the Company cannot predict the outcome of these matters.
Labor Day Windstorm
OnGeneral
In September 7, 2020, a severe windstorm swept throughoccurred in eastern Washington and northern Idaho. The extreme weather event resulted in customer outages wasand the proximate cause of multiple wildfires in the region and impacted electric utilities throughout the Pacific
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Northwest. With respect to wildfires, the Company’s investigation determined that the primary cause of the fires was extreme high winds. To date, the Company has not found any evidence that the fires were caused by any deficiencies in its equipment, maintenance activities or vegetation management practices. However, theThe Company has become aware of instances where, during the course of the storm, otherwise healthy trees and limbs, located in areas outside its maintenance right-of-way, broke under the extraordinary wind conditions and caused damage to its energy delivery system at or near what is believed to be the potential area of origin of a wildfire. Those instances include what has been referred to as: the Babb Road fire (near Malden and Pine City, Washington); the Christensen Road fire (near Airway Heights, Washington); and the Mile Marker 49 fire (near Orofino, Idaho). These wildfires covered, in total, approximately 22,000 acres. The Company currently estimates approximately 230 residential, commercial and other structures were impacted. Parallel investigations by applicable state agencies including the Washington Department of Natural Resources, are ongoing, and the Company is cooperating with those efforts. With respect to the Christensen Road Fire and the Mile Marker 49 Fire, the Company’s investigation determined that the primary cause of the fires was extreme high winds. To date, the Company has not found any evidence that the fires were caused by any deficiencies in its equipment, maintenance activities or vegetation management practices. See further discussion below regarding the Babb Road Fire.
In addition to the instances identified above, the Company is aware of a 5-acre fire that occurred in Colfax, Washington, which damaged several residential structures. The Company’s investigation has founddetermined that the Company’s facilities were not involved in the ignition of this fire in any way.
The Company contends that there is no evidence of negligence and the Company intends to vigorously defend any claims for damages that may be asserted against it with respect to the wildfires arising out of the extreme wind event.
Babb Road Fire
On May 14, 2021 the Company learned that the DNR had completed its investigation and issued a report on the Babb Road Fire. The Babb Road fire covered approximately 15,000 acres and destroyed approximately 220 structures. There are no reports of personal injury or death resulting from the fire.
The DNR report concluded, among other things, that
the fire was ignited when a branch of a multi-dominant Ponderosa Pine tree was broken off by the wind and fell on an Avista Corp. distribution line;
the tree was located approximately 30 feet from the center of Avista Corp.’s distribution line and approximately 20 feet beyond Avista Corp.’s right-of-way;
the tree showed some evidence of insect damage, damage at the top of the tree from porcupines, a small area of scarring where a lateral branch/leader (LBL) had apparently broken off in the past, and some past signs of Gall Rust disease.
The DNR report concluded as follows: “It is my opinion that because of the unusual configuration of the tree, and its proximity to the powerline, a closer inspection was warranted. A nearer inspection of the tree should have revealed the cut LBL ends and its previous failure, and necessitated determination of the failure potential of the adjacent LBL, implicated in starting the Babb Road Fire.”
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The DNR report acknowledged that, other than the multi-dominant nature of the tree, the conditions mentioned above would not have been easily visible without close-up inspection of, or cutting into, the tree. The report also acknowledged that, while the presence of multiple tops would have been visible from the nearby roadway, the tree did not fail at a v-fork due to the presence of multiple tops. The Company contends that applicable inspection standards did not require a closer inspection of the otherwise healthy tree, nor was the Company in any way negligent with respect to its maintenance, inspection or vegetation management practices. The Company intends to vigorously defend any such assertion, if made. At this time, no material claims have been asserted against Avista Corp. for damages resulting from the Babb Road Fire.
Colstrip
The Washington CETA imposes deadlines by which coal-fired resources, such as Colstrip, must be excluded from the rate base of Washington utilities and by which electricity from such resources may no longer be delivered to Washington retail customers. Not all of the co-owners of Colstrip Units 3 & 4 are Washington utilities subject to CETA, and the co-owners have differing needs for the generating capacity of these units. Accordingly, business disagreements have arisen among the co-owners, including, but not limited to, disagreements as to the shut-down date or dates of these units. These business disagreements, in turn, have led to disagreements as to the interpretation of the Ownership and Operating Agreement, including, but not limited to, the rights of the co-owners to discontinue operations of, or otherwise terminate their interest in, Unit 3 and/or Unit 4. The Ownership and Operating Agreement contains an arbitration clause that dictates a dispute resolution process to address and resolve these disagreements through an arbitration conducted in Spokane, Washington. At least one owner, Talen Montana, has challenged the validity of the arbitration clause contained in the Ownership and Operating Agreement on the basis that it is not consistent with recently-enacted amendments to Montana Code Section 27-5-323 which requires, among other things, that an arbitration be conducted in Montana. A majority of the owners of Colstrip (including the Company) initiated legal proceedings in Washington to compel arbitration in accordance with the Ownership and Operating Agreement, which proceedings were subsequently removed and transferred to Montana Federal District Court, as well as legal proceedings in Montana to challenge the constitutionality of the amendments to Montana Code Section 27-5-323.
In addition to amending Montana Code Section 27-5-323, during the course of the 2021 legislative session the Montana Legislature passed Senate Bill 266, which amended Montana’s Consumer Protection Act (MC 30-14-103 et seq.) to make (i) the failure or refusal of an owner of Colstrip to fund its share of operating costs, and (ii) conduct by one or more of the owners of Colstrip to bring about permanent closure of a generating unit of Colstrip without seeking and obtaining the unanimous consent of the owners, an unfair or deceptive act or practice in the conduct of trade or commerce under Montana’s Consumer Protection Act. A majority of the owners of Colstrip (including the Company) initiated legal proceedings to challenge the constitutionality of Senate Bill 266. On October 13, 2021, the United States District Court for the District of Montana issued a preliminary injunction finding it likely that Senate Bill 266 unconstitutionally violates both the Contracts Clause and the Commerce Clause of the United States Constitution. The Company will continue to vigorously defend and protect its interests (and those of its stakeholders) in this and all other legal proceedings relating to Colstrip.
The Company is not able to predict the outcome, nor an amount or range of potential impact in the event of an outcome that is adverse to the Company’s interests.
National Park Service (NPS) - Natural and Cultural Damage Claim
In March 2017, the Company accessed property managed by the National Park Service (NPS) to prevent the imminent failure of a power pole that was surrounded by flood water in the Spokane River. The Company voluntarily reported its actions to the NPS several days later. Thereafter, in March 2018, the NPS notified the Company that it might seek recovery for unspecified costs and damages allegedly caused during the incident pursuant to the System Unit Resource Protection Act (SURPA), 54 U.S.C. 100721 et seq. In January 2021, the United States Department of Justice (DOJ) requested that the Company and the DOJ renew discussions relating to the matter. In July 2021, the DOJ communicated that it may seek damages of approximately $2 million in connection with the incident for alleged damage to "natural and cultural resources". In addition, the DOJ indicated that it may seek treble damages under the SURPA and state law, bringing its total potential claim to approximately $6 million.
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The Company disputes the position taken by the DOJ with respect to the incident, as well as the nature and extent of the DOJ’s alleged damages, and will vigorously defend itself in any litigation that may arise with respect to the matter. The Company and the DOJ have agreed to engage in discussions to understand their respective positions and determine whether a resolution of the dispute may be possible. However, the Company cannot predict the outcome of the matter.
Rathdrum, Idaho Natural Gas Incident
On October 28, 2021, there was an incident in Rathdrum Idaho involving the Company’s natural gas infrastructure. The incident occurred after a third party damaged those facilities during the course of excavation work. The incident resulted in a fire which destroyed one residence and resulted in minor injuries to the occupants. At this time, the Company is unable to predict the likelihood of a claim arising out of the matter, nor an amount or range of a potential loss, if any, in the event of such a claim.
Other Contingencies
In the normal course of business, the Company has various other legal claims and contingent matters outstanding. The Company believes that any ultimate liability arising from these actions will not have a material impact on its financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant. See "Note 2122 of the Notes to Consolidated Financial Statements" in the 20192020 Form 10-K for additional discussion regarding other contingencies.
NOTE 17. INFORMATION BY BUSINESS SEGMENTS
The business segment presentation reflects the basis used by the Company's management to analyze performance and determine the allocation of resources. The Company's management evaluates performance based on income (loss) from operations before income taxes as well as net income (loss) attributable to Avista Corp. shareholders.. The accounting policies of the segments are the same as those described in the summary of significant accounting policies. Avista Utilities' business is managed based on the total regulated utility operation; therefore, it is considered one segment. AEL&P is a separate reportable business segment, as it has separate financial reports that are reviewed in detail by the Chief Operating Decision Maker and its operations and risks are sufficiently different from Avista Utilities and the other businesses at AERC that it cannot be aggregated with any other operating segments. The Other category, which is not a reportable segment, includes other investments and operations of various subsidiaries, as well as certain other operations of Avista Capital.
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The following table presents information for each of the Company’s business segments (dollars in thousands):
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Avista
Utilities | | | Alaska
Electric
Light and
Power
Company | | | Total Utility | | | Other | | | Intersegment
Eliminations
(1) | | | Total | |
For the three months ended September 30, 2021: | | | | | | | | | | | | | | | | | | |
Operating revenues | | $ | 286,752 | | | $ | 9,147 | | | $ | 295,899 | | | $ | 108 | | | $ | 0 | | | $ | 296,007 | |
Resource costs | | | 101,109 | | | | 1,024 | | | | 102,133 | | | | 0 | | | | 0 | | | | 102,133 | |
Other operating expenses | | | 82,006 | | | | 3,619 | | | | 85,625 | | | | 843 | | | | 0 | | | | 86,468 | |
Depreciation and amortization | | | 55,039 | | | | 2,683 | | | | 57,722 | | | | 30 | | | | 0 | | | | 57,752 | |
Income (loss) from operations | | | 23,416 | | | | 1,563 | | | | 24,979 | | | | (765 | ) | | | 0 | | | | 24,214 | |
Interest expense (2) | | | 25,015 | | | | 1,523 | | | | 26,538 | | | | 132 | | | | (21 | ) | | | 26,649 | |
Income taxes | | | (6,371 | ) | | | 18 | | | | (6,353 | ) | | | 921 | | | | 0 | | | | (5,432 | ) |
Net income | | | 9,086 | | | | 41 | | | | 9,127 | | | | 5,239 | | | | 0 | | | | 14,366 | |
Capital expenditures (3) | | | 107,519 | | | | 1,462 | | | | 108,981 | | | | 373 | | | | 0 | | | | 109,354 | |
For the three months ended September 30, 2020: | | | | | | | | | | | | | | | | | | |
Operating revenues | | $ | 263,564 | | | $ | 8,815 | | | $ | 272,379 | | | $ | 267 | | | $ | 0 | | | $ | 272,646 | |
Resource costs | | | 77,843 | | | | 942 | | | | 78,785 | | | | 0 | | | | 0 | | | | 78,785 | |
Other operating expenses | | | 82,151 | | | | 3,400 | | | | 85,551 | | | | 1,697 | | | | 0 | | | | 87,248 | |
Depreciation and amortization | | | 51,499 | | | | 2,454 | | | | 53,953 | | | | 146 | | | | 0 | | | | 54,099 | |
Income (loss) from operations | | | 28,284 | | | | 1,790 | | | | 30,074 | | | | (1,576 | ) | | | 0 | | | | 28,498 | |
Interest expense (2) | | | 24,277 | | | | 1,561 | | | | 25,838 | | | | 131 | | | | (29 | ) | | | 25,940 | |
Income taxes | | | 1,060 | | | | 59 | | | | 1,119 | | | | (260 | ) | | | 0 | | | | 859 | |
Net income (loss) | | | 5,546 | | | | 268 | | | | 5,814 | | | | (938 | ) | | | 0 | | | | 4,876 | |
Capital expenditures (3) | | | 105,494 | | | | 2,860 | | | | 108,354 | | | | 803 | | | | 0 | | | | 109,157 | |
For the nine months ended September 30, 2021: | | | | | | | | | | | | | | | | | | |
Operating revenues | | $ | 974,172 | | | $ | 32,515 | | | $ | 1,006,687 | | | $ | 445 | | | $ | 0 | | | $ | 1,007,132 | |
Resource costs | | | 324,464 | | | | 2,926 | | | | 327,390 | | | | 0 | | | | 0 | | | | 327,390 | |
Other operating expenses | | | 257,333 | | | | 9,900 | | | | 267,233 | | | | 3,186 | | | | 0 | | | | 270,419 | |
Depreciation and amortization | | | 161,332 | | | | 7,677 | | | | 169,009 | | | | 230 | | | | 0 | | | | 169,239 | |
Income (loss) from operations | | | 149,670 | | | | 11,162 | | | | 160,832 | | | | (2,971 | ) | | | 0 | | | | 157,861 | |
Interest expense (2) | | | 74,423 | | | | 4,571 | | | | 78,994 | | | | 392 | | | | (87 | ) | | | 79,299 | |
Income taxes | | | 4,932 | | | | 1,819 | | | | 6,751 | | | | 2,379 | | | | 0 | | | | 9,130 | |
Net income | | | 80,861 | | | | 4,816 | | | | 85,677 | | | | 10,780 | | | | 0 | | | | 96,457 | |
Capital expenditures (3) | | | 318,354 | | | | 4,454 | | | | 322,808 | | | | 938 | | | | 0 | | | | 323,746 | |
For the nine months ended September 30, 2020: | | | | | | | | | | | | | | | | | | |
Operating revenues | | $ | 909,109 | | | $ | 31,014 | | | $ | 940,123 | | | $ | 1,345 | | | $ | 0 | | | $ | 941,468 | |
Resource costs | | | 274,468 | | | | 1,829 | | | | 276,297 | | | | 0 | | | | 0 | | | | 276,297 | |
Other operating expenses | | | 256,570 | | | | 9,681 | | | | 266,251 | | | | 3,716 | | | | 0 | | | | 269,967 | |
Depreciation and amortization | | | 161,934 | | | | 7,348 | | | | 169,282 | | | | 569 | | | | 0 | | | | 169,851 | |
Income (loss) from operations | | | 137,219 | | | | 11,337 | | | | 148,556 | | | | (2,939 | ) | | | 0 | | | | 145,617 | |
Interest expense (2) | | | 73,449 | | | | 4,709 | | | | 78,158 | | | | 393 | | | | (161 | ) | | | 78,390 | |
Income taxes | | | 460 | | | | 1,840 | | | | 2,300 | | | | (828 | ) | | | 0 | | | | 1,472 | |
Net income (loss) | | | 69,130 | | | | 4,991 | | | | 74,121 | | | | (3,368 | ) | | | 0 | | | | 70,753 | |
Capital expenditures (3) | | | 291,417 | | | | 6,417 | | | | 297,834 | | | | 1,389 | | | | 0 | | | | 299,223 | |
Total Assets: | | | | | | | | | | | | | | | | | | |
As of September 30, 2021: | | $ | 6,345,036 | | | $ | 269,061 | | | $ | 6,614,097 | | | $ | 123,355 | | | $ | (5,974 | ) | | $ | 6,731,478 | |
As of December 31, 2020: | | $ | 6,035,340 | | | $ | 268,971 | | | $ | 6,304,311 | | | $ | 109,658 | | | $ | (11,872 | ) | | $ | 6,402,097 | |
| | Avista Utilities | | | Alaska Electric Light and Power Company | | | Total Utility | | | Other | | | Intersegment Eliminations (1) | | | Total | |
For the three months ended September 30, 2020: | | | | | | | | | | | | | | | | | | | | | | | | |
Operating revenues | | $ | 263,564 | | | $ | 8,815 | | | $ | 272,379 | | | $ | 267 | | | $ | 0 | | | $ | 272,646 | |
Resource costs | | | 77,843 | | | | 942 | | | | 78,785 | | | | 0 | | | | 0 | | | | 78,785 | |
Other operating expenses | | | 82,151 | | | | 3,400 | | | | 85,551 | | | | 1,697 | | | | 0 | | | | 87,248 | |
Depreciation and amortization | | | 51,499 | | | | 2,454 | | | | 53,953 | | | | 146 | | | | 0 | | | | 54,099 | |
Income (loss) from operations | | | 28,284 | | | | 1,790 | | | | 30,074 | | | | (1,576 | ) | | | 0 | | | | 28,498 | |
Interest expense (2) | | | 24,277 | | | | 1,561 | | | | 25,838 | | | | 131 | | | | (29 | ) | | | 25,940 | |
Income taxes | | | 1,060 | | | | 59 | | | | 1,119 | | | | (260 | ) | | | 0 | | | | 859 | |
Net income (loss) attributable to Avista Corp. shareholders | | | 5,546 | | | | 268 | | | | 5,814 | | | | (938 | ) | | | 0 | | | | 4,876 | |
Capital expenditures (3) | | | 105,494 | | | | 2,860 | | | | 108,354 | | | | 803 | | | | 0 | | | | 109,157 | |
For the three months ended September 30, 2019: | | | | | | | | | | | | | | | | | | | | | | | | |
Operating revenues | | $ | 274,931 | | | $ | 7,790 | | | $ | 282,721 | | | $ | 1,049 | | | $ | 0 | | | $ | 283,770 | |
Resource costs | | | 98,397 | | | | (73 | ) | | | 98,324 | | | | 0 | | | | 0 | | | | 98,324 | |
Other operating expenses (4) | | | 76,749 | | | | 3,363 | | | | 80,112 | | | | 1,450 | | | | 0 | | | | 81,562 | |
Depreciation and amortization | | | 47,631 | | | | 2,421 | | | | 50,052 | | | | 134 | | | | 0 | | | | 50,186 | |
Income (loss) from operations | | | 28,998 | | | | 1,780 | | | | 30,778 | | | | (535 | ) | | | 0 | | | | 30,243 | |
Interest expense (2) | | | 24,634 | | | | 1,596 | | | | 26,230 | | | | 149 | | | | (186 | ) | | | 26,193 | |
Income taxes | | | 125 | | | | 82 | | | | 207 | | | | (338 | ) | | | 0 | | | | (131 | ) |
Net income (loss) attributable to Avista Corp. shareholders | | | 5,966 | | | | 197 | | | | 6,163 | | | | (1,073 | ) | | | 0 | | | | 5,090 | |
Capital expenditures (3) | | | 118,141 | | | | 2,836 | | | | 120,977 | | | | 920 | | | | 0 | | | | 121,897 | |
For the nine months ended September 30, 2020: | | | | | | | | | | | | | | | | | | | | | | | | |
Operating revenues | | $ | 909,109 | | | $ | 31,014 | | | $ | 940,123 | | | $ | 1,345 | | | $ | 0 | | | $ | 941,468 | |
Resource costs | | | 274,468 | | | | 1,829 | | | | 276,297 | | | | 0 | | | | 0 | | | | 276,297 | |
Other operating expenses | | | 256,570 | | | | 9,681 | | | | 266,251 | | | | 3,716 | | | | 0 | | | | 269,967 | |
Depreciation and amortization | | | 161,934 | | | | 7,348 | | | | 169,282 | | | | 569 | | | | 0 | | | | 169,851 | |
Income (loss) from operations | | | 137,219 | | | | 11,337 | | | | 148,556 | | | | (2,939 | ) | | | 0 | | | | 145,617 | |
Interest expense (2) | | | 73,449 | | | | 4,709 | | | | 78,158 | | | | 393 | | | | (161 | ) | | | 78,390 | |
Income taxes | | | 460 | | | | 1,840 | | | | 2,300 | | | | (828 | ) | | | 0 | | | | 1,472 | |
Net income (loss) attributable to Avista Corp. shareholders | | | 69,130 | | | | 4,991 | | | | 74,121 | | | | (3,368 | ) | | | 0 | | | | 70,753 | |
Capital expenditures (3) | | | 291,417 | | | | 6,417 | | | | 297,834 | | | | 1,389 | | | | 0 | | | | 299,223 | |
For the nine months ended September 30, 2019: | | | | | | | | | | | | | | | | | | | | | | | | |
Operating revenues | | $ | 942,441 | | | $ | 27,414 | | | $ | 969,855 | | | $ | 11,208 | | | $ | 0 | | | $ | 981,063 | |
Resource costs | | | 325,615 | | | | (1,505 | ) | | | 324,110 | | | | 0 | | | | 0 | | | | 324,110 | |
Other operating expenses (4) | | | 261,934 | | | | 9,551 | | | | 271,485 | | | | 15,137 | | | | 0 | | | | 286,622 | |
Depreciation and amortization | | | 147,208 | | | | 7,237 | | | | 154,445 | | | | 498 | | | | 0 | | | | 154,943 | |
Income (loss) from operations | | | 130,200 | | | | 11,309 | | | | 141,509 | | | | (4,427 | ) | | | 0 | | | | 137,082 | |
Interest expense (2) | | | 73,214 | | | | 4,787 | | | | 78,001 | | | | 885 | | | | (823 | ) | | | 78,063 | |
Income taxes | | | 25,722 | | | | 1,825 | | | | 27,547 | | | | 598 | | | | 0 | | | | 28,145 | |
Net income attributable to Avista Corp. shareholders | | | 139,086 | | | | 4,825 | | | | 143,911 | | | | 2,292 | | | | 0 | | | | 146,203 | |
Capital expenditures (3) | | | 313,747 | | | | 7,218 | | | | 320,965 | | | | 1,104 | | | | 0 | | | | 322,069 | |
Total Assets: | | | | | | | | | | | | | | | | | | | | | | | | |
As of September 30, 2020: | | $ | 5,916,490 | | | $ | 269,907 | | | $ | 6,186,397 | | | $ | 108,681 | | | $ | (11,947 | ) | | $ | 6,283,131 | |
As of December 31, 2019: | | $ | 5,713,268 | | | $ | 271,393 | | | $ | 5,984,661 | | | $ | 113,390 | | | $ | (15,595 | ) | | $ | 6,082,456 | |
Intersegment eliminations reported as interest expense represent intercompany interest.
(2)Including interest expense to affiliated trusts.
(3)The capital expenditures for the other businesses are included in other investing activities on the Condensed Consolidated Statements of Cash Flows.
(1)
| Intersegment eliminations reported as interest expense represent intercompany interest.
|
(2)
| Including interest expense to affiliated trusts.
|
(3)
| The capital expenditures for the other businesses are included in other investing activities on the Condensed Consolidated Statements of Cash Flows.
|
(4)
| Other operating expenses for Avista Utilities for the nine months ended September 30, 2019 include merger transaction costs which are separately disclosed on the Condensed Consolidated Statements of Income.
|
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NOTE 18. TERMINATION OF PROPOSED ACQUISITION BY HYDRO ONE
On July 19, 2017, Avista Corp. entered into a Merger Agreement that provided for Avista Corp. to become an indirect, wholly-owned subsidiary of Hydro One, subject to the satisfaction or waiver of specified closing conditions, including approval by regulatory agencies. Hydro One, based in Toronto, is Ontario’s largest electricity transmission and distribution provider.
Termination of the Merger Agreement
Due to the denial of the proposed merger by certain of the Company's regulatory commissions, on January 23, 2019, Avista Corp., Hydro One and certain subsidiaries thereof, entered into a Termination Agreement indicating their mutual agreement to terminate the Merger Agreement, effective immediately. Pursuant to the terms of the Termination Agreement, Hydro One paid Avista Corp. a $103 million termination fee on January 24, 2019. The termination fee was used for reimbursing the Company's transaction costs incurred from 2017 to 2019. The balance of the termination fee remaining after payment of 2019 transaction costs and applicable income taxes was used for general corporate purposes and reduced the Company's need for external financing. The 2019 costs totaled $19.7 million pre-tax and included financial advisers' fees, legal fees, consulting fees and employee time.
NOTE 19. SALE OF METALfx
In April 2019, Bay Area Manufacturing, Inc., a non-regulated subsidiary of Avista Corp., entered into a definitive agreement to sell its interest in METALfx to an independent third party. The transaction was a stock sale for a total cash purchase price of $17.5 million plus cash on-hand, subject to customary closing adjustments. The transaction closed on April 18, 2019, and as of that date the Company has no further involvement with METALfx.
The purchase price of $17.5 million, as adjusted, was divided among the security holders of METALfx, including the minority shareholder, pro rata based on ownership (Avista Corp. owned 89.2 percent of the equity of METALfx). As required under the purchase agreement, $1.2 million (7 percent of the purchase price) will be held in escrow for 24 months from the closing of the transaction to satisfy certain indemnification obligations.
When all escrow amounts are released, the sale transaction will provide cash proceeds to Avista Corp., net of payments to the minority holder, contractually obligated compensation payments and other transaction expenses, of $16.5 million and result in a net gain of $2.3 million recognized in the nine months ended September 30, 2019. The Company expects to receive the full amount of its portion of the escrow accounts; therefore, the full amounts have been included in the gain calculation. The gross gain is included in "Other income," the transaction expenses paid are included in "Non-utility Other operating expenses" and any taxes associated with the sale are included in "Income tax expense" on the Condensed Consolidated Statements of Income.
Prior to the completion of the sales transaction, METALfx was not a reportable business segment and was included in other in the business segment footnote at Note 17. This transaction does not meet the criteria for discontinued operations as it does not represent a strategic shift that will have a major effect on the Company's ongoing operations.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and Board of Directors of
Avista Corporation
Spokane, Washington
Results of Review of Interim Financial Information
We have reviewed the accompanying condensed consolidated balance sheet of Avista Corporation and subsidiaries (the "Company") as of September 30, 2020,2021, the related condensed consolidated statements of income, comprehensive income, and equity for the three-month and nine-month periods ended September 30, 20202021 and 20192020, and of cash flows for the nine-month periods ended September 30, 20202021 and 20192020, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.
We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheet of the Company as of December 31, 2019,2020, and the related consolidated statements of income, comprehensive income, equity, and cash flows for the year then ended (not presented herein); and in our report dated February 25, 2020,23, 2021, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2019,2020, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.
Basis for Review Results
This interim financial information is the responsibility of the Company's management. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our reviews in accordance with standards of the PCAOB. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the PCAOB, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
/s/ Deloitte & Touche LLP
Portland, Oregon
November 3, 20202, 2021
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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Management’s Discussion and Analysis of Financial Condition and Results of Operations has been prepared in accordance with GAAPthe SEC’s Regulation S-K for interim financial information and with the instructions to Form 10-Q. The interimThis Management’s Discussion and Analysis of Financial Condition and Results of Operations does not contain the full detail or analysis whichthat would be included inaccompany financial statements for a full fiscal year Form 10-K;year; therefore, it should be read in conjunction with the Company's 20192020 Form 10-K.
Business Segments
Our business segments have not changed during the nine months ended September 30, 2020.2021. See the 20192020 Form 10-K as well as “Note 17 of the Notes to Condensed Consolidated Financial Statements” for further information regarding our business segments.
The following table presents net income attributable to Avista Corp. shareholders for each of our business segments (and the other businesses) for the three and nine months ended September 30 (dollars in thousands):
| | | | | | | | | | | | | | | | |
| | Three months ended September 30, | | | Nine months ended September 30, | |
| | 2021 | | | 2020 | | | 2021 | | | 2020 | |
Avista Utilities | | $ | 9,086 | | | $ | 5,546 | | | $ | 80,861 | | | $ | 69,130 | |
AEL&P | | | 41 | | | | 268 | | | | 4,816 | | | | 4,991 | |
Other | | | 5,239 | | | | (938 | ) | | | 10,780 | | | | (3,368 | ) |
Net income | | $ | 14,366 | | | $ | 4,876 | | | $ | 96,457 | | | $ | 70,753 | |
| | Three months ended September 30, | | | Nine months ended September 30, | |
| | 2020 | | | 2019 | | | 2020 | | | 2019 | |
Avista Utilities | | $ | 5,546 | | | $ | 5,966 | | | $ | 69,130 | | | $ | 139,086 | |
AEL&P | | | 268 | | | | 197 | | | | 4,991 | | | | 4,825 | |
Other | | | (938 | ) | | | (1,073 | ) | | | (3,368 | ) | | | 2,292 | |
Net income attributable to Avista Corp. shareholders | | $ | 4,876 | | | $ | 5,090 | | | $ | 70,753 | | | $ | 146,203 | |
Executive Level Summary
Overall Results
Net income attributable to Avista Corp. shareholders was $4.9 million for the three months ended September 30, 2020,2021 increased compared to $5.1 million for the three months ended September 30, 2019.2020 primarily due to increased net income at our other businesses, and timing of recognition of income taxes. These items were partially offset by higher power supply costs and a $2.5 million write off of Colstrip SmartBurn assets disallowed in the Washington general rate case. Net income was $70.8 million for the nine months ended September 30, 2020,2021 increased compared to $146.2 million for2020 primarily due to an increase in utility margin as a result of general rate increases, timing of recognition of income taxes, and non-decoupled revenue growth and customer growth. These increases were partially offset by higher power supply costs. In addition, the nine months ended September 30, 2019.
Avista Utilities' net income for the three and nine months ended September 30, 2020 decreased compared to the three and nine months ended September 30, 2019. For the third quarter, our earnings decreased due to higher operating expenses, primarily from increased bad debt, and decreased loads resulting from COVID-19, which was partially offset by higher utility margin due to lower power supply costs, rate relief in Washington and Oregon, and customer growth. For the year-to-date, earnings were lower than in 2019 primarily due to the receipt, in the first quarter of 2019, of a $103 million termination fee from Hydro One (see "Note 18 of the Notes to Condensed Consolidated Financial Statements") which was partially offset by associated expenses of $19.7 million pre-tax. In addition, in the first nine months of 2020, we recordedincluded an accrual for customer refunds related to the outcome of theour 2015 Washington general rate cases, outcome (see "Regulatory Matters"), an accrual for disallowed replacement power during an unplanned outage at Colstrip (see "Regulatory Matters"). Forand a contribution to the year-to-date period, we also had anColstrip community fund.
The increase in other operating expenses and depreciation and amortization, which were partially offset by a decrease in our income tax expense and resource costs.
AEL&P net income increased slightly, primarily due to higher sales volumes to residential and commercial customers in 2020 as a result of cooler than usual weather.
The decrease in net income at our other businesses for the year-to-date was primarily due to increased earnings from our investments during the sale of METALfx in 2019. In addition, we had impairment lossessecond and the write-off of a note receivable in the first three quarters of 2020, which was partially offset by investment gains associated with our equity investments.third quarters.
More detailed explanations of the fluctuations are provided in the results of operations and business segment discussions (Avista Utilities, AEL&P, and the other businesses) that follow this section.
39Summer Weather Conditions
The Pacific Northwest experienced hot and dry weather conditions throughout the second and third quarters of 2021 compared to normal weather conditions for this time of year. These weather conditions resulted in higher than usual customer loads, as well as lower than usual hydroelectric generation. In these periods, we often have excess generation to sell into the wholesale markets, which benefits our net power supply costs. This did not occur at expected levels in 2021 primarily due to the hot and dry weather conditions throughout the Pacific Northwest.
As a result of our lower than normal hydroelectric generation capability and in order to serve higher than usual loads, we were required to rely more heavily than usual on purchased power and our thermal generation, which in turn resulted in higher than authorized resource costs due to higher volumes of energy and fuel purchased and higher market prices of each. For the nine-months
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ended September 30, 2021 we have recognized a pre-tax expense of $7.1 million under the ERM, compared to a $5.9 million pre-tax benefit recognized in the first nine months of 2020.
These hot conditions had a minimal impact on revenues, as the majority of the increase in revenues associated with increased usage was offset with decoupling revenues due to the decoupling mechanisms that cover a majority of our customers.
COVID-19 Global Pandemic
The COVID-19 global pandemic is currently impacting all aspects ofhas impacted our business, as well as the global, national and local economies. It is likely thatHowever, as we progress through 2021, the continued spreadeconomies in our service territory have opened, and we expect the impacts of COVID-19the pandemic to be less severe than 2020. This was the case through the third quarter. The pandemic has affected and efforts to contain the virus willmay continue to cause an economic slowdown and possibly a recession, resulting in significant disruptions in various public, commercial or industrial activities and causing employee absences which could interfere with operation and maintenance of the Company’s facilities. These circumstances have affected and will likely continue to adversely affect our operations, results of operations, financial condition, liquidity and cash flows in the following ways:
Operations
We provide critical services to our customers. Accordingly, it is paramount that we keep our employees who operate our business safe so that we continue to provide reliable service. We implemented business continuity plans in the context of this global pandemic. We believe that we will continue to be able to conduct our utility operations effectively and provide safe and reliable service to our customers.
We have taken precautions concerning employee and facility hygiene, imposed travel limitations on employees and directed our employees to work remotely whenever possible. Protocols have been established and implemented to protect employees and the public when work requires public interaction.
During the third quarter of 2020, we continued to experience supply chain delays due to the effects of the COVID-19 pandemic that have impacted the delivery times of some of our materials and equipment, with delays ranging from a couple weeks up to eight weeks in some cases. At this time, the delays are being managed with minimal impact. The issues that could potentially result from future delays are being proactively mitigated through several planning and review activities, but could have an impact on our planned projects going forward.
Although we have not experienced any significant issues to date, it is possible that COVID-19 could have a negative impact on the ability of vendors or contractors to perform, which could increase operating costs and delay and/or increase the costs of capital projects.
Results of Operations
In the three months ended September 30, 2020, when compared to normal, there was a decrease of approximately 2 percent on overall electric load, which consisted of approximately a 6 percent decrease in both commercial and industrial, which was partially offset by an increase of 5 percent in residential. We expect a gradualcontinued economic recovery and prolonged high unemployment that will depress load and customer growth intoimprovement in employment through the remainder of 2021. We have decoupling and other regulatory mechanisms in Washington, Idaho and Oregon, which mitigate the impact of changes in loads and revenues for residential and certain commercial customer classes. There are limitations on increases in decoupling surcharges in a particular year and revenue recognition criteria established by GAAP. Although we expect to ultimately recognize all decoupling revenue, there can be a delay in revenue recognition. Over 90 percent of our utility revenue is covered by regulatory mechanisms.
Customer disconnections for non-payment have resumed in all jurisdictions.
We have suspended customer disconnections and late fees for non-payment; however, in Idaho, the IPUC approved resuming disconnections and late fees. Due to the economic downturn, our bad debt expense increased by $4.7 million in the third quarter and $8.0 million for the nine months ended September 30, 2020 as compared to our original forecast. We expect bad debt expense to increase by an additional $3.5 million for the remainder of 2020 as compared to our original forecast. In the first nine months of 2020, we deferred $2.5 million of the incremental bad debt expense related to our Idaho operations.
We expect to offset some of the negative impacts of COVID-19 at Avista Utilities with cost savings and benefits from the Coronavirus Aid, Relief, and Economic Security Act (the CARES Act). We have filed petitions for anreceived accounting orderorders in each of our jurisdictions to defer the recognition of COVID-19 expenses as well as identified cost savings of other COVID-19 related benefits. See “Note 1COVID-19 deferred cumulative regulatory assets and liabilities as of NotesSeptember 30, 2021 and December 31, 2020 were as follows (dollars in thousands):
| | | | | | | | |
| | September 30, | | | December 31, | |
| | 2021 | | | 2020 | |
Regulatory asset | | $ | 15,648 | | | $ | 8,166 | |
Regulatory liability | | | (12,673 | ) | | | (10,949 | ) |
Total | | $ | 2,975 | | | $ | (2,783 | ) |
Several vaccine mandates have been issued by various governmental entities. To the extent that governmental mandates are applicable to Condensed Consolidated Financial Statements.”
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CARES Act
In March 2020, the CARES Act, an economic stimulus package in responseus, we are assessing our options as to COVID-19, was signed into law. The CARES Act contains corporate income tax provisions, including providing temporary changes regarding the prior and future utilization of net operating losses, temporary suspension of certain payment requirements for the employer portion of social security taxes, and the creation of certain refundable employee retention credits. We expecthow to be able to utilize $6.6 million ($7.9 million pre-tax) of benefits from the CARES Act to offset increased costs associatedcomply with the COVID-19 pandemic. The benefitsmandates while minimizing the impact on our operations. If we expectmandate vaccines, it could result in a loss of employees which could cause disruption to utilize are primarily derived from net operating loss carrybacks.operations.
Financial Condition, Liquidity and Cash Flows
For 2020, we expect our net cash flows from operations to decrease primarily due to lower revenues from retail sales of electricity and natural gas and lower payments from customers.
We do not expect the impact of COVID-19 to change our estimate of utility capital expenditures for 2020.
As of September 30, 2020, we had $324.4 million of available liquidity under the Avista Corp. $400.0 million committed line of credit and $25.0 million under the AEL&P committed line of credit. In April 2020, we entered into a one-year credit agreement with two financial institutions in the amount of $100.0 million. We borrowed the entire $100.0 million available under this agreement.
After considering the impacts of COVID-19, including lower net operating cash flows, and the issuances of long-term debt and equity during 2020,2021, we expect net cash flows from operations, together with cash available under our committed lines of credit, and the $100.0 million borrowed under the new credit agreement, to provide adequate resources to fund capital expenditures, dividends, and other contractual commitments.
In addition to any of the issues identified above, weWe cannot predict the duration and severity of the COVID-19 global pandemic.pandemic or if emerging variants will result in the reimplementation of economic restrictions. The longer and more severe the economic restrictions and business disruption, is, the greater the impact on our operations, results of operations, financial condition and cash flows will be.flows.
Executive Order re Securing the United States Bulk Power System
In May 2020, the President of the United States signed an Executive Order titled “Securing the United States Bulk-Power System.” The executive order purports to limit the acquisition, importation, transfer or installation of bulk power system equipment sourced from foreign adversaries. At this time, and pending future rulemaking, the full scope of the order is not yet known. We are currently evaluating the potential impacts of the order, and will seek recovery of any associated costs through the ratemaking process.
Regulatory Matters
General Rate Cases
We regularly review the need for electric and natural gas rate changes in each state in which we provide service. We expect to continue to file for rate adjustments to:
seek recovery of operating costs and capital investments, and seek the opportunity to earn reasonable returns as allowed by regulators. 36
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| seek recovery of operating costs and capital investments, and
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| •
| seek the opportunity to earn reasonable returns as allowed by regulators.
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With regards to the timing and plans for future filings, the assessment of our need for rate relief and the development of rate case plans takes into consideration short-term and long-term needs, as well as specific factors that can affect the timing of rate filings. Such factors include, but are not limited to, in-service dates of major capital investments and the timing of changes in major revenue and expense items.
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Avista Utilities
Washington General Rate Cases
2015 General Rate Cases
In January 2016, we received an order that concluded our electric and natural gas general rate cases that were originally filed with the WUTC in February 2015. New electric and natural gas rates were effective on January 11, 2016.
PC Petition for Judicial Review
In March 2016, PC filed in Thurston County Superior Court a Petition for Judicial Review of the WUTC's Orders. In April 2016, this matter was certified for review directly by the Court of Appeals, an intermediate appellate court in the State of Washington.
In August 2018, the Court of Appeals issued a "Published Opinion" (Opinion) which concluded that the WUTC's use of an attrition allowance to calculate Avista Corp.'s rate base violated Washington law. In the Opinion, the Court stated that because the projected additions to rate base in the future were not "used and useful" for service at the time the request for the rate increase was made, they may not lawfully be included in our rate base to justify a rate increase. Accordingly, the Court concluded that the WUTC erred in including an attrition allowance in the calculation of our electric and natural gas rate base. The Court noted, however, that the law does not prohibit an attrition allowance in the calculation, for ratemaking purposes, of recoverable operating and maintenance expense. Since the WUTC order provided one lump sum attrition allowance without distinguishing what portion was for rate base and which was for operating and maintenance expenses or other considerations, the Court struck all portions of the attrition allowance attributable to our rate base and reversed and remanded the case for the WUTC to recalculate our rates without including an attrition allowance in the calculation of rate base.
In March 2020, we received an order from the WUTC that requires us to refund $8.5 million to electric and natural gas customers. We are refunding $4.9 million to electric customers and $3.6 million to natural gas customers. We previously recorded a customer refund liability of $3.6 million in 2019. The refund will be returned to customers over a twelve-month period that began on April 1, 2020.
2019 General Rate Cases
In March 2020, we received an order from the WUTC that approved thea partial multi-party settlement agreement that was filed in November 2019.agreement. The approved rates arewere designed to increase annual base electric revenues by $28.5 million, or 5.7 percent, and annual natural gas base revenues by $8.0 million, or 8.5 percent, effective April 1, 2020. The revenue increases are based onincorporate a 9.4 percent return on equity (ROE)ROE with a common equity ratio of 48.5 percent and a rate of return on rate (ROR) baseROR of 7.21 percent.
As part of the WUTC order, we are returning approximately $40 million from the ERM rebate to customers over a two-year period. The ERM rebate includes approximately $3 million that was recently disallowed by the WUTC for the cost of replacement power during an unplanned outage at the Colstrip generating facility in 2018. The WUTC directed us to return a larger portion of the ERM rebate during the first year to achieve a net-zero billed impact to electric customers.
Included in the WUTC order iswas the acceleration of depreciation of Colstrip Units 3 & 4 to reflect a remaining useful life through December 31, 2025. The order utilizesutilized certain electric tax benefits associated with the 2018 tax reform to partially offset these increased costs. The order also sets aside $3 million for community transition efforts to mitigate the impacts of the eventual closure of Colstrip, half funded by customers and half funded by our shareholders. We recorded this liability and recognized the shareholder portion of the expense in the first quarter of 2020. The funds were issued to the Montana Community Fund in the first quarter of 2021.
Lastly, the order includesincluded the extension of electric and natural gas decoupling mechanisms through March 31, 2025, with one modification in that new customers added after any test period wouldwill not be decoupled until includedthose customers are embedded in a futurerate case test period.year.
2020 General Rate Cases
In September 2021, we received an order from the WUTC that approved a partial multi-party settlement agreement and resolved all other remaining issues. The approved rates are designed to increase annual base electric revenues by $13.6 million, or 2.6 percent, and annual natural gas base revenues by $8.1 million, or 7.7 percent, effective October 2020,1, 2021. The revenue increases are based on a 9.4 percent ROE with a common equity ratio of 48.5 percent and a ROR of 7.12 percent.
While base rates increased, there was no increase in billed rates at this time because of the use of offsetting tax benefits. With the approval of these customer tax credits, the company recognized an adjustment in the third quarter.
The WUTC's order approved recovery of capital additions including investments in advanced metering infrastructure, wildfire resiliency, joining the Western Energy Imbalance Market, and other projects. The WUTC disallowed $2.5 million of costs associated with Colstrip SmartBurn technology.
The WUTC order also approves the Company's request to defer incremental wildfire expenses incurred from January 1, 2021 to September 30, 2021, as well as the Company's use of a wildfire balancing account to track the level of expense associated with wildfire resiliency going forward.
2022 General Rate Cases
We expect to file multi-year electric and natural gas general rate cases with the WUTC in the first quarter of 2022.
Washington Engrossed Substitute Senate Bill 5295
This bill, which was signed into law and is effective as of July 25, 2021, is designed to promote multi-year rate plans and performance-based rate making for electric and natural gas utilities. The bill includes a number of provisions such as required multi-year rate plans from 2-4 years in length, methodologies the WUTC may use to minimize regulatory lag and/or adjust for under earning
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and starts an investigation into Performance Based Ratemaking Metrics, an initial move that may help to modify the historical test-year ratemaking construct. On October 20, 2021, the WUTC issued a notice of opportunity to comment on a proposed work plan to be conducted in various phases between 2021 and 2025, initially focusing on Performance Based Ratemaking and identifying performance metrics. Thereafter, the WUTC will address revenue adjustment mechanisms and performance incentives in the context of multi-year rate plans. The new law leaves much to the discretion of the WUTC, and we cannot predict the extent to which the WUTC will embrace the options now permitted.
Idaho General Rate Cases
2021 General Rate Cases
In January 2021, we filed electric and natural gas general rate cases with the WUTC. We have requested an overallIPUC.
In September 2021, the IPUC approved the all party settlement agreement. The approved rates under the settlement agreement are designed to increase inannual base electric revenues of $44.2by $10.6 million, (or 8.3 percent), which would be entirely offset by a tax creditor 4.3 percent, effective September 1, 2021, and $8.0 million, or 3.1 percent, effective September 1, 2022. For natural gas, the proposed rates under the settlement agreement are designed to customers of the same amount.
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Additionally, we have requested an overall increase indecrease annual base natural gas revenues by $1.6 million, or 3.7 percent, effective September 1, 2021, and increase annual base revenues by $0.9 million, or 2.2 percent, effective September 1, 2022. The parties have agreed to use the customer tax credits, related to flow through of $12.8 million (or 12.2 percent), which would be entirelycertain tax items, included in our original filing to offset by a tax creditoverall proposed changes to customers ofelectric and natural gas rates over the same amount. two-year plan.
The revenue increases aresettlement is based on a 9.99.4 percent ROE with a common equity ratio of 50 percent and a ROR of 7.437.05 percent.
Included in our general rate case requests are the recovery of our Advanced Metering Infrastructure (AMI) Project costs. AMI project costs represented 42 percent of our electric base rate request and 54 percent of our natural gas base rate request.
See “Note 7 of the Notes to Condensed Consolidated Financial Statements” for further discussion on the tax credit to customers.
Idaho General Rate Cases
2019 General Rate Cases
In October 2019, Avista Corp. and all parties to our electric general rate case reached a settlement agreement that was approved by the IPUC. New rates went into effect on December 1, 2019.
The rates that went into effect are designed to decrease annual base electric revenues by $7.2 million (or 2.8 percent), effective December 1, 2019. The settlement revenue decreases are based on a 9.5 percent ROE with a common equity ratio of 50 percent and a ROR on rate base of 7.35 percent, which is a continuation of current levels. This outcome is in line with our expectations.
The primary element of the difference in the agreed upon base revenues in the settlement agreement from our original request is that the settlement includes the continued recovery of costs for our wind generation power purchase agreements, which will include Palouse Wind and Rattlesnake Flat, through the PCA mechanism rather than through base rates.
2021 General Rate Cases
We expect to file electric and natural gas general rate cases with the IPUC in the first quarter of 2021. We delayed the filing of this case in order to capture in rates a level of plant and costs that will be more reflective of the rate effective period.
Oregon General Rate Cases
2019 General Rate Case
In October 2019, the OPUC approved the all-party settlement agreements filed in the third quarter of 2019. New rates went into effect on January 15, 2020.
OPUC approved rates that are designed to increase annual natural gas billed revenues by $3.6 million, or 4.2 percent.
The OPUC’s decision reflects a ROR on rate base of 7.24 percent, with a common equity ratio of 50 percent and a 9.4 percent ROE, both of which represent a continuation of existing authorized levels.
In addition, the approved settlement agreements included agreement among the parties to a future independent review of our interest rate hedging practices, with any recommendations based on the results and findings in the final report to be applicable only on a prospective basis and do not apply to any prior interest rate hedging activity.
2020 General Rate Case
In March 2020, we filed a natural gas general rate case with the OPUC. We have requested an overall increase in base natural gas rates of 9.8 percent (designed to increase annual natural gas revenues by $6.8 million). Our request was based on a proposed ROR on rate base of 7.50 percent with a common equity ratio of 50 percent and a 9.9 percent ROE.
Through several settlement stipulations the parties have resolved all issues in the general rate case. The settlements arecase and in December 2020, the OPUC approved the settlement stipulations.
These stipulations approved by the OPUC were designed to increase annual base revenue by $4.4$3.9 million, or 6.35.7 percent, effective January 15,16, 2021. The agreed-uponapproved ROE is 9.4 percent, with a common equity ratio of 50 percent and a proposed ROR of 7.24 percent. The settlements are before the OPUC, and we expect an order in the fourth quarter of 2020.
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AMI Project2021 General Rate Case
In March 2016, the WUTC granted our Petition for an Accounting Order to defer and include in a regulatory asset the undepreciated value of our existing Washington electric meters for the opportunity for later recovery. This accounting treatment is related to our ongoing project to replace our existing electric meters with new two-way digital meters and the related software and support services through our AMI project in Washington State. As of September 30, 2020, the estimated future undepreciated value for the existing electric meters was $21.8 million. In September 2017, the WUTC also approved our request to defer the undepreciated net book value of existing natural gas encoder receiver transmitters (ERT) (consistent with the accounting treatment we obtained on our existing electric meters) that are being retired as part of the AMI project. As of September 30, 2020, the estimated future undepreciated value for the existing natural gas ERTs was $2.3 million.
In September 2017, the WUTC approved a Petition to defer the depreciation expense associated with the AMI project, along with a carrying charge. We have included a request to seek recovery of our AMI costs in our 2020 Washington general rate cases.
In May 2017,On October 22, 2021, we filed Petitions with the IPUC and the OPUC requesting a depreciable life of 12.5 years for the meter data management system (MDM) related to the AMI project. Both the IPUC and the OPUC approved our request. In addition, in connection with the 2017 Idaho electricnatural gas general rate case with the settling parties agreedOPUC that, if approved, would allow us to cost recoveryrecover costs for ongoing natural gas infrastructure and other investments without increasing customer bills. The proposal is designed to increase overall natural gas base revenue by $3.8 million and is based on a proposed rate of Idaho's sharereturn of 7.35 percent with a common equity ratio of 50 percent and a 9.9 percent return on equity. We have proposed that the increase be fully offset for a two-year period with tax customer credits (related to the flow through of certain tax items) of the MDM system, effective January 1, 2019. In connection with the approval of the Oregonsame amount.
AEL&P
Alaska General Rate Case
AEL&P is required to file its next general rate case settlement, the OPUC approved cost recovery of Oregon's share of the MDM system, effective November 1, 2017.by August 30, 2022.
Avista Utilities
Purchased Gas Adjustments
PGAs are designed to pass through changes in natural gas costs to Avista Utilities' customers with no change in utility margin (operating revenues less resource costs) or net income. In Oregon, we absorb (cost or benefit) 10 percent of the difference between
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actual and projected natural gas costs included in retail rates for supply that is not hedged. Total net deferred natural gas costs among all jurisdictions was an assetwere assets of $1.7$14.7 million and $1.4 million as of September 30, 20202021 and a net liability of $3.2 million as of December 31, 2019.2020, respectively.
Power Cost Deferrals and Recovery Mechanisms
The ERM is an accounting method used to track certain differences between Avista Utilities' actual power supply costs, net of wholesale sales and sales of fuel, and the amount included in base retail rates for our Washington customers. Under the ERM, Avista Utilities makes an annual filing on or before April 1 of each year to provide the opportunity for the WUTC staff and other interested parties to review the prudence of and audit the ERM deferred power cost transactions for the prior calendar year. See the 20192020 Form 10-K for a full discussion of the mechanics of the ERM and the various sharing bands. Total net deferred power costs under the ERM were a liabilityliabilities of $39.6$19.6 million and $37.9 million as of September 30, 2020, compared to a liability of $37.0 million as of2021 and December 31, 2019.2020, respectively. These deferred power cost balances represent amounts due to customers. Pursuant to WUTC requirements, should the cumulative deferral balance exceed $30 million in the rebate or surcharge direction, we must make a filing with the WUTC to adjust customer rates to either return the balance to customers or recover the balance from customers.
The cumulative rebate balance exceeds $30 million and as a result, our 2019 filing contained a proposed rate refund. The ERM proceeding was considered with our 2019 general rate case proceeding and a refund was approved and is being returned to customers over a two-year period that began on April 1, 2020. See further discussion in the section "Washington General Rate Cases" above.
Avista Utilities has a PCA mechanism in Idaho that allows us to modify electric rates on October 1 of each year with IPUC approval. Under the PCA mechanism, we defer 90 percent of the difference between certain actual net power supply expenses and the amount included in base retail rates for our Idaho customers. The October 1 rate adjustments recover or rebate power supply costs deferred during the preceding July-June twelve-month period. Total net power supply costs deferred under the PCA mechanism were assets of $0.7$11.6 million as of September 30, 20202021 and $0.3$2.5 million as of December 31, 2019.2020. These deferred power cost balances represent amounts due from customers.
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Decoupling and Earnings Sharing Mechanisms
Decoupling (also known as an FCA in Idaho) is a mechanism designed to sever the link between a utility's revenues and consumers' energy usage. In each of our jurisdictions, Avista Utilities' electric and natural gas revenues are adjusted so as to be based on the number of customers in certain customer rate classes and assumed "normal" kilowatt hour and therm sales, rather than being based on actual kilowatt hour and therm sales. The difference between revenues based on the number of customers and "normal" sales and revenues based on actual usage is deferred and either surcharged or rebated to customers beginning in the following year. Only residential and certain commercial customer classes are included in our decoupling mechanisms. See the 20192020 Form 10-K for a discussion of the mechanisms in each jurisdiction.
Total net cumulative decoupling deferrals among all jurisdictions were regulatory assets of $20.9$8.7 million as of September 30, 20202021 and $24.3$21.3 million as of December 31, 2019.2020. These decoupling assets represent amounts due from customers. Total net earnings sharing balances among all jurisdictions were regulatory liabilities of $0.7 million as of September 30, 2020 and December 31, 2019. These earnings sharing liabilities represent amounts due to customers.
See "Results of Operations - Avista Utilities" for further discussion of the amounts recorded to operating revenues in 20202021 and 20192020 related to the decoupling and earnings sharing mechanisms.
COVID-19 Deferrals
See “Note 1 of the Notes to Condensed Consolidated Financial Statements” for discussion on COVID-19 deferrals.
Results of Operations - Overall
The following provides an overview of changes in our Condensed Consolidated Statements of Income. More detailed explanations are provided, particularly for operating revenues and operating expenses, in the business segment discussions (Avista Utilities, AEL&P, and the other businesses) that follow this section.
The balances included below for utility operations reconcile to the Condensed Consolidated Statements of Income.
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Three months ended September 30, 20202021 compared to the three months ended September 30, 20192020
The following graph shows the total change in net income attributable to Avista Corp. shareholders for the third quarter of 20202021 compared to the third quarter of 2019,2020, as well as the various factors that caused such change (dollars in millions):
Utility revenues decreasedincreased at Avista Utilities when compared to the third quarter of 2019. The decrease2020. This was primarily a result of a decrease in sales of fuel and wholesale natural gas sales, both of which were a result of our optimization activities. There was a decrease in electric decoupling revenue primarily due to the amortization of decoupling surcharges from prior years and current year decoupling rebates to residential customers due to higher usage compared to normal. The above decreases were partially offset by an overall increase in electric load of 0.5 percent when compared towarmer weather than the third quarter of 2019, which consisted of a 7 percent increase in residential load2020, customer growth, and decreases of 5 percent and 3 percent in commercial and industrial load, respectively. AEL&P'sreduced COVID-19 restrictions. In addition, utility revenues increased from an increase in sales volumes due to weather that was cooler than the prior year.general rate increases in Oregon.
Utility resource costs decreasedincreased at Avista Utilities due to lowerincreased purchased power, fuel for generation and other fuel costs, as well as lowerhigher natural gas purchases. See "Summer Weather Conditions" in the Executive Level Summary above for further discussion on the increase in net power supply expenses. There was also an increase at AEL&P due to an increase in deferred power supply expenses.
Utility operating expenses slightly increased when compared to the third quarter of 2020. This increase includes $2.5 million of SmartBurn technology assets disallowed for recovery through rates in the Washington 2020 rate case final order. This additional expense was offset by $1.9 million of deferred incremental wildfire expenses incurred from January 1, 2021 to September 30, 2021 as approved by WUTC, as well as a decrease in bad debt expense when compared to the third quarter of 2020. During the third quarter of 2020, we had only received regulatory approval to defer COVID-19 related bad debt expense in our Idaho jurisdiction, whereas we deferred COVID-19 related bad debt expense for Washington and Oregon jurisdictions during the third quarter of 2021.
Utility depreciation and amortization increased primarily due to additions to utility plant.
Income tax expense decreased primarily due to a change in tax methodology to a flow through method, as accepted by IPUC and WUTC through our general rate cases. See “Note 7 of the Notes to Condensed Consolidated Financial Statements” for further details and a reconciliation of our effective tax rate.
The increase in other was primarily related to net investment gains during the third quarter of 2021, compared to net investment losses during the third quarter of 2020.
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Nine months ended September 30, 2021 compared to the nine months ended September 30, 2020
The following graph shows the total change in net income for the nine months ended September 30, 2021 compared to the nine months ended September 30, 2020, as well as various factors that caused such change (dollars in millions):
Utility revenues increased at Avista Utilities primarily due increased loads from non-decoupled customers as a result of reduced COVID-19 restrictions during the nine months ended September 30, 2021 and weather that was warmer than normal and the prior year. In addition, utility revenues increased due to general rate increases in Washington, Idaho and Oregon and customer growth. During the first nine months of 2020, there was a $4.9 million decrease to revenue due to the outcome of the 2015 Washington general rate cases.
Utility resource costs increased at Avista Utilities due to increased purchased power, fuel for generation and other fuel costs, as well as higher natural gas purchases. See "Summer Weather Conditions" in the Executive Level Summary above for further discussion of the increased net power supply costs. There was an increase at AEL&P due to an increase in deferred power supply expenses.
The increase in utility operating expenses was primarily due to increases in bad debt expense, which were partially offset by decreases in Avista Utilities’ generation and distribution operating and maintenance costs.
Utility depreciation and amortization increased due to additions to utility plant.
costs at Avista Utilities, as well as a $2.5 million write off of Colstrip SmartBurn technology assets disallowed under the 2020 Washington general rate case. The increase in other was primarily related to a decrease in net loss on investments in the third quarter of 2020 compared to the third quarter of 2019.
Income taxes increased primarily due toincreases were partially offset by an annual book to tax return adjustment that increased expenses in the third quarter of 2020 compared to a favorable adjustment in 2019.
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Nine months ended September 30, 2020 compared to the nine months ended September 30, 2019
The following graph shows the total change in net income attributable to Avista Corp. shareholders foraccrual during the nine months ended September 30, 2020 compared to the nine months ended September 30, 2019, as well as the various factors that caused such change (dollars in millions):
Utility revenues decreased at Avista Utilities primarily due to an overall decrease in electric load of 3 percent when compared to the year-to-date 2019, which consisted of a 6 percent and a 5 percent decrease in commercial and industrial load, respectively. The decreases in commercial and industrial were partially offset by a 1 percent increase in residential electric load when compared to the year-to-date 2019. The outcome from the 2015 Washington general rate cases decreased revenue by $4.9 million. The above decreases were partially offset by an increase from electric and natural gas decoupling rates, higher PGA rates and customer growth. AEL&P's revenues increased from an increase in sales volumes due to weather that was cooler than the prior year.
Non-utility revenues decreased due to the sale of METALfx, which occurred in April 2019.
Utility resource costs decreased at Avista Utilities due to lower fuel for generation and other fuel costs, as well as lower natural gas purchases. There was an increase at AEL&P due to an increase in deferred power supply expenses.
The increase in utility operating expenses was due to an increase at Avista Utilities primarily related to increases in generation and distribution operating and maintenance costs, an accrual for disallowed replacement power during an unplanned outage at Colstrip (see "Regulatory Matters"), and an increasea decrease in bad debt expense. There was a decrease in utility operating expenses due to a $7.0 million donation commitment made in the second quarter of 2019 that was a one-time donation.
The merger transaction costs are relatedexpense when compared to the proposed (now terminated) acquisition by Hydro One. There were no additional costsnine months ended September 30, 2020. During the first nine months of 2020, we had only received regulatory approval to defer COVID-19 related bad debt expense in 2020 relating to this matter.our Idaho jurisdiction, whereas we deferred COVID-19 related bad debt expense for all jurisdictions during the first nine months of 2021.
Utility depreciation and amortization increaseddecreased primarily due to additionsa one-time increase to utility plant.Also, indepreciation expense during the second quarterfirst nine months of 2020 as we were able to utilize approximately $10.6$10.9 million ($8.4 million when tax-effected) of electric tax benefits to offset costs associated with accelerating the depreciation of Colstrip Units 3 & 4 based on a settlement in Washington. This amount was recorded as a one-time increasemostly offset by additions to
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depreciation expense in the second quarter of 2020 and was offset with a decrease in income tax expense. In the second quarter of 2019, a similar item was recorded in Idaho in the amount of $6.4 million ($5.1 million when tax-effected).
The merger termination fee was related to the termination of the proposed Hydro One acquisition.
Income taxes decreasedincreased primarily due to a decrease in income before taxes. Our effective tax rate was 2.0 percent forexpense during the nine months ended September 30, 2020 compared to 16.2 percent for nine months ended September 30, 2019. The tax rate was lower in both 2020 and 2019 duerelated to the offset of $8.4 million of deferred income taxes against accelerated depreciation for Colstrip based on a settlement in Washington and an increase in pre-tax earnings. This was offset by a change in tax methodology to flow through method for certain items in 2021, as provided in the 2019 Washingtonaccepted by IPUC and WUTC through our general rate case settlement, whichcases. Our effective tax rate was recorded in8.6 percent for the second quarter 2020. This amounted to $8.4 million in 2020 as first nine months of 2021
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compared to $5.1 million in 2019.2.0 percent for the first nine months of 2020. See "Note“Note 7 of the Notes to Condensed Consolidated Financial Statements"Statements” for further details and a reconciliation of our effective tax rate.
The increase in other was primarily related to net investment gains during the first nine months of 2021, compared to net investment losses during the first nine months of 2020. Additionally, other increased due to the sale of certain subsidiary assets associated with the Spokane Steam Plant during the first nine months of 2021.
Non-GAAP Financial Measures
The following discussion for Avista Utilities includes two financial measures that are considered “non-GAAP financial measures”: electric utility margin and natural gas utility margin. In the AEL&P section, we include a discussion of utility margin, which is also a non-GAAP financial measure.
Generally, a non-GAAP financial measure is a numerical measure of a company's financial performance, financial position or cash flows that excludes (or includes) amounts that are included (excluded) in the most directly comparable measure calculated and presented in accordance with GAAP. Electric utility margin is electric operating revenues less electric resource costs, while natural gas utility margin is natural gas operating revenues less natural gas resource costs. The most directly comparable GAAP financial measure to electric and natural gas utility margin is utility operating revenues as presented in "Note 17 of the Notes to Condensed Consolidated Financial Statements."
The presentation of electric utility margin and natural gas utility margin is intended to enhance the understanding of operating performance. We use these measures internally and believe they provide useful information to investors in their analysis of how changes in loads (due to weather, economic or other conditions), rates, supply costs and other factors impact our results of operations. Changes in loads, as well as power and natural gas supply costs, are generally deferred and recovered from customers through regulatory accounting mechanisms. Accordingly, the analysis of utility margin generally excludes most of the change in revenue resulting from these regulatory mechanisms. We present electric and natural gas utility margin separately below for Avista Utilities since each business has different cost sources, cost recovery mechanisms and jurisdictions, so we believe that separate analysis is beneficial. These measures are not intended to replace utility operating revenues as determined in accordance with GAAP as an indicator of operating performance. Reconciliations of operating revenues to utility margin are set forth below.
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Results of Operations - Avista Utilities
Three months ended September 30, 20202021 compared to the three months ended September 30, 20192020
Utility Operating Revenues
The following graphs present Avista Utilities' electric operating revenues and megawatt-hour (MWh) sales for the three months ended September 30, 20202021 and 20192020 (dollars in millions and MWhs in thousands):
(1)
| (1) This balance includes public street and highway lighting, which is considered part of retail electric revenues, and deferrals/amortizations to customers related to federal income tax law changes. |
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retail electric revenues.Total electric operating revenues in the graph above include intracompany sales of $10.2$9.4 million and $8.5$10.2 million for the three months ended September 30, 20202021 and 2019,2020, respectively.
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The following table presents the current year deferrals and the amortization of prior year decoupling balances that are reflected in utility electric operating revenues for the three months ended September 30 (dollars in thousands):
| | | | | | | | |
| | Electric Decoupling Revenues | |
| | 2021 | | | 2020 | |
Current year decoupling deferrals (a) | | $ | (9,508 | ) | | $ | (1,316 | ) |
Amortization of prior year decoupling deferrals (b) | | | (3,667 | ) | | | (4,067 | ) |
Total electric decoupling revenue | | $ | (13,175 | ) | | $ | (5,383 | ) |
| | Electric Decoupling Revenues | |
| | 2020 | | | 2019 | |
Current year decoupling deferrals (a) | | $ | (1,316 | ) | | $ | 5,361 | |
Amortization of prior year decoupling deferrals (b) | | | (4,067 | ) | | | 563 | |
Total electric decoupling revenue | | $ | (5,383 | ) | | $ | 5,924 | |
Positive amounts are increases in decoupling revenue in the current year and will be surcharged to customers in future years. Negative amounts are decreases in decoupling revenue in the current year and will be rebated to customers in future years.
(b)Positive amounts are increases in decoupling revenue in the current year and are related to the amortization of rebate balances that resulted in prior years and are being refunded to customers (causing a corresponding decrease in retail revenue from customers) in the current year. Negative amounts are decreases in decoupling revenue in the current year and are related to the amortization of surcharge balances that resulted in prior years and are being surcharged to customers (causing a corresponding increase in retail revenue from customers) in the current year.
(a)
| Positive amounts are increases in decoupling revenue in the current year and will be surcharged to customers in future years. Negative amounts are decreases in decoupling revenue in the current year and will be rebated to customers in future years.
|
(b)
| Positive amounts are increases in decoupling revenue in the current year and are related to the amortization of rebate balances that resulted in prior years and are being refunded to customers (causing a corresponding decrease in retail revenue from customers) in the current year. Negative amounts are decreases in decoupling revenue in the current year and are related to the amortization of surcharge balances that resulted in prior years and are being surcharged to customers (causing a corresponding increase in retail revenue from customers) in the current year.
|
Total electric revenues decreased $6.9increased $22.8 million for the third quarter of 20202021 as compared to the third quarter of 2019.2020. The primary fluctuations that occurred during the period were as follows:
| •
| a $4.9 million increase in retail electric revenue due to an increase in revenue per MWh (increased revenues $4.3 million) and an increase in total MWhs sold (increased revenues $0.6 million).
|
a $16.7 million increase in retail electric revenue due to an increase in MWhs sold (increased revenues by $12.9 million) and an increase in retail rates (increased revenues by $3.8 million).
| o
| The increase in total retail MWhs sold was primarily the result of an increase in residential sales volumes and customer growth. This was partially offset by a decrease in commercial and industrial sales volumes mostly due to COVID-19 impacts. In addition, weather was warmer than normal and warmer than the prior year, which increased cooling loads. Compared to the third quarter of 2019, residential electric use per customer increased 5 percent,
|
oThe increase in total retail MWhs sold was primarily the result of weather that was warmer than normal and the prior year, which increased cooling loads, and customer growth. Also, there was a lifting of COVID-19 restrictions during parts of the third quarter of 2021, which contributed to the increased loads for our commercial customers. Compared to the third quarter of 2020, residential electric use per customer increased 8 percent and commercial use per customer increased 5 percent. Cooling degree days in Spokane were 40 percent above normal and 35 percent above the third quarter of 2020.
oRetail rates increased primarily from passthrough rate changes, which do not have an impact on utility margin, such as the residential exchange program, low income rate assistance program, the ERM and PCA amortization rates and decoupling.
a $3.9 million increase in wholesale electric revenues due to an increase in sales prices (increased revenues $8.5 million), partially offset by a decrease in sales volumes (decreased revenues $4.6 million). The fluctuation of volumes in the current year was due to our need to utilize our thermal generation assets more than normal due to lower than normal hydroelectric generation and increased customer loads. This limited our opportunities to sell generation in the wholesale power markets as compared to the third quarter of 2020.
a $7.8 million increase in sales of fuel as part of thermal generation resource optimization activities.
a $7.8 million decrease in electric decoupling revenue. The rebates in 2021 resulted from higher than normal usage from residential and non-residential customers because of weather that was warmer than normal.
a $2.2 million increase in other revenues, primarily due to transmission revenue.
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| | commercial use per customer decreased 6 percent and industrial use per customer decreased 1 percent. Cooling degree days in Spokane were 5 percent above normal and 26 percent above the prior year. Heating degree days in Spokane were 36 percent below normal, and 44 percent below the third quarter of 2019.
|
| o
| The increase in revenue per MWh was primarily due to an increase in decoupling rates (as there was a decoupling surcharge in 2020 compared to a decoupling rebate in 2019) and also a general rate increase in Washington, effective April 1, 2020. This was partially offset by a general rate decrease in Idaho, effective December 1, 2019.
|
| •
| a $0.6 million increase in wholesale electric revenues due to an increase in sales prices (increased revenues $2.0 million), partially offset by a decrease in sales volumes (decreased revenues $1.4 million). The fluctuation in volumes was primarily the result of how much we were able to optimize our generation assets as compared to the prior year.
|
| •
| a $4.6 million decrease in sales of fuel as part of thermal generation resource optimization activities.
|
| •
| an $11.3 million decrease in electric decoupling revenue primarily due to the amortization of decoupling surcharges from prior years and current year decoupling rebates to residential customers due to higher usage compared to normal, partially related to the Stay-at-Home orders from the Washington government and warmer than normal weather. The above amounts were partially offset by decoupling surcharges to non-residential customers as commercial usage was down compared to normal during the third quarter primarily due to COVID-19 impacts.
|
| •
| a $3.6 million increase in other primarily related to an increase in transmission revenue and the amortization of the 2015 remand accrual.
|
The following graphs present Avista Utilities' natural gas operating revenues and therms delivered for the three months ended September 30, 20202021 and 20192020 (dollars in millions and therms in thousands):
(1)
| (1) This balance includes interruptible and industrial revenues, which are considered part of retail natural gas revenues, and deferrals/amortizations to customers related to federal income tax law changes. |
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retail natural gas revenues.Total natural gas operating revenues in the graph above include intracompany sales of $13.8$16.3 million and $14.1$13.8 million for the three months ended September 30, 20202021 and 2019,2020, respectively.
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The following table presents the current year deferrals and the amortization of prior year decoupling balances that are reflected in utility natural gas operating revenues for the three months ended September 30 (dollars in thousands):
| | | | | | | | |
| | Natural Gas Decoupling Revenues | |
| | 2021 | | | 2020 | |
Current year decoupling deferrals (a) | | $ | 2,458 | | | $ | 1,540 | |
Amortization of prior year decoupling deferrals (b) | | | 218 | | | | (129 | ) |
Total natural gas decoupling revenue | | $ | 2,676 | | | $ | 1,411 | |
| | Natural Gas Decoupling Revenues | |
| | 2020 | | | 2019 | |
Current year decoupling deferrals (a) | | $ | 1,540 | | | $ | (422 | ) |
Amortization of prior year decoupling deferrals (b) | | | (129 | ) | | | 535 | |
Total natural gas decoupling revenue | | $ | 1,411 | | | $ | 113 | |
Positive amounts are increases in decoupling revenue in the current year and will be surcharged to customers in future years. Negative amounts are decreases in decoupling revenue in the current year and will be rebated to customers in future years.
| (b) Positive amounts are increases in decoupling revenue in the current year and are related to the amortization of rebate balances that resulted in prior years and are being refunded to customers (causing a corresponding decrease in retail revenue from customers) in the current year. Negative amounts are decreases in decoupling revenue in the current year and are related to the amortization of surcharge balances that resulted in prior years and are being surcharged to customers (causing a corresponding increase in retail revenue from customers) in the current year. (a)
| Positive amounts are increases in decoupling revenue in the current year and will be surcharged to customers in future years. Negative amounts are decreases in decoupling revenue in the current year and will be rebated to customers in future years.
|
(b)
| Positive amounts are increases in decoupling revenue in the current year and are related to the amortization of rebate balances that resulted in prior years and are being refunded to customers (causing a corresponding decrease in retail revenue from customers) in the current year. Negative amounts are decreases in decoupling revenue in the current year and are related to the amortization of surcharge balances that resulted in prior years and are being surcharged to customers (causing a corresponding increase in retail revenue from customers) in the current year.
|
Total natural gas revenues decreased $3.2increased $2.2 million for the third quarter of 20202021 as compared to the third quarter of 2019.2020. The primary fluctuations that occurred during the period were as follows:
| a $1.0 million increase in natural gas retail revenues (including industrial, which is included in other) due primarily to an increase in retail rates. oRetail rates increased due to a general rate increase in Oregon, effective January 16, 2021, and a purchased gas adjustment rate increase in Idaho, effective September 1, 2021 (which does not impact utility margin). a $0.2 million decrease in wholesale natural gas revenues due to a decrease in volumes of excess gas sold in the wholesale market (decreased revenues $19.5 million), mostly offset by an increase in prices (increased revenues $19.3 million). Differences between revenues and costs from sales of resources in excess of retail load requirements and from resource optimization are accounted for through the PGA mechanisms. a $1.3 million increase in natural gas decoupling revenue primarily due to higher surcharges in the third quarter of 2021. This resulted from lower than normal usage in the third quarter of 2021 because of weather that was warmer than normal. •
| a $0.3 million increase in natural gas retail revenues (including industrial, which is included in other) due to an increase in retail rates (increased revenues $3.2 million), mostly offset by a decrease in volumes (decreased revenues $2.9 million).
|
| o
| Retail rates increased from higher PGA rates, decoupling rate increases and general rate increases in Oregon, effective January 15, 2020 and Washington, effective April 1, 2020.
|
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| o
| Retail natural gas sales volumes decreased in the third quarter of 2020 as compared to the third quarter of 2019 primarily due to lower commercial and industrial usage related to COVID-19, as well as lower residential usage. The residential usage decrease was primarily related to weather that was warmer than the prior year and warmer than normal which decreased heating loads. The decrease in usage was partially offset by customer growth in the third quarter. Compared to the third quarter of 2019, residential use per customer decreased 10 percent, commercial use per customer decreased 22 percent and industrial use per customer decreased 6 percent. Heating degree days in Spokane were 36 percent below normal and 44 percent below the third quarter of 2019. Heating degree days in Medford were 57 percent below normal and 79 percent below the third quarter of 2019.
|
| •
| a $5.7 million decrease in wholesale natural gas revenues due to a decrease in volumes (decreased revenues $6.0 million), partially offset by an increase in prices (increased revenues $0.3 million). Differences between revenues and costs from sales of resources in excess of retail load requirements and from resource optimization are accounted for through the PGA mechanisms.
|
| •
| a $1.3 million increase in natural gas decoupling revenue primarily related to decoupling surcharges in the third quarter 2020 resulting from weather that was warmer than normal and lower commercial usage due to COVID-19 impacts.
|
The following table presents Avista Utilities' average number of electric and natural gas retail customers for the three months ended September 30, 20202021 and 2019:2020:
| | | | | | | | | | | | | | | | |
| | Electric Customers | | | Natural Gas Customers | |
| | 2021 | | | 2020 | | | 2021 | | | 2020 | |
Residential | | | 356,846 | | | | 350,831 | | | | 332,403 | | | | 327,073 | |
Commercial | | | 44,117 | | | | 43,510 | | | | 36,329 | | | | 36,074 | |
Interruptible | | | — | | | | — | | | | 44 | | | | 40 | |
Industrial | | | 1,204 | | | | 1,297 | | | | 191 | | | | 239 | |
Public street and highway lighting | | | 680 | | | | 629 | | | | — | | | | — | |
Total retail customers | | | 402,847 | | | | 396,267 | | | | 368,967 | | | | 363,426 | |
| | Electric Customers | | | Natural Gas Customers | |
| | 2020 | | | 2019 | | | 2020 | | | 2019 | |
Residential | | | 350,831 | | | | 343,345 | | | | 327,073 | | | | 319,634 | |
Commercial | | | 43,510 | | | | 42,846 | | | | 36,074 | | | | 35,604 | |
Interruptible | | | — | | | | — | | | | 40 | | | | 43 | |
Industrial | | | 1,297 | | | | 1,301 | | | | 239 | | | | 243 | |
Public street and highway lighting | | | 629 | | | | 615 | | | | — | | | | — | |
Total retail customers | | | 396,267 | | | | 388,107 | | | | 363,426 | | | | 355,524 | |
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Utility Resource Costs
The following graphs present Avista Utilities' resource costs for the three months ended September 30, 20202021 and 20192020 (dollars in millions):
Total electric resource costs in the graph above include intracompany resource costs of $13.8$16.3 million and $14.1$13.8 million for the three months ended September 30, 2021 and 2020, and 2019, respectively.
Total electric resource costs decreased $14.2increased $24.4 million for the third quarter of 20202021 as compared to the third quarter of 2019.2020. The primary fluctuations that occurred during the period were as follows:
| •
| a $2.6 million decrease in power purchased due to a decrease in wholesale prices (decreased costs $6.1 million), partially offset by an increase in the volume of power purchases (increased costs $3.5 million). The fluctuation in volumes was primarily the result of how much we were able to optimize our generation assets as compared to the prior year.
|
a $8.4 million increase in power purchased due to an increase in wholesale prices (increased costs $10.1 million), partially offset by a decrease in the volume of power purchases (decreased costs $1.7 million). The fluctuation in volumes was primarily the result of differences in the available opportunities for us to optimize our generation assets as compared to the prior year.
| •
| a $5.7 million decrease in fuel for generation primarily related to lower thermal generation due to higher hydroelectric generation as compared to the third quarter of 2019. There was also a decrease in total MWhs sold (which required less fuel for electric generation).
|
a $18.1 million increase in fuel for generation primarily related to lower hydroelectric generation and increased retail sales volumes, which required increased thermal generation. Also, there were higher natural gas prices during the third quarter of 2021 as compared to 2020.
| •
| a $2.5 million decrease in other fuel costs. This represents fuel and the related derivative instruments that were purchased for generation but were later sold when conditions indicated that it was more economical to sell the fuel as part of the resource optimization process. When the fuel or related derivative instruments are sold, that revenue is included in sales of fuel.
|
a $4.3 million increase in other fuel costs. This represents fuel and the related derivative instruments that were purchased for generation but were later sold when conditions indicated that it was more economical to sell the fuel as part of the resource optimization process. When the fuel or related derivative instruments are sold, that revenue is included in sales of fuel.
| •
| a $3.3 million decrease in other electric resource costs, primarily related to increased amortizations associated with the Washington ERM and a residential exchange credit.
|
a $6.6 million decrease in other electric resource costs, primarily related to the deferral of increased power supply costs above authorized.
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Total natural gas resource costs in the graph above include intracompany resource costs of $10.2$9.4 million and $8.5$10.2 million for the three months ended September 30, 2021 and 2020, and 2019, respectively.
Total natural gas resource costs decreased $5.1increased $0.6 million for the third quarter of 20202021 as compared to the third quarter of 20192020 primarily due to the following:
| a $2.4 million increase in natural gas purchased due to an increase in the price of natural gas (increased costs $25.3 million), mostly offset by a decrease in volumes (decreased costs $22.9 million). The decrease in volumes was primarily from a decrease in wholesale sales. a $1.8 million decrease from net amortizations and deferrals of natural gas costs. •
| a $4.2 million increase in natural gas purchased due to an increase in the price of natural gas (increased costs $12.3 million), partially offset by a decrease in volumes (decreased costs $8.1 million).
|
| •
| a $9.2 million decrease from net amortizations and deferrals of natural gas costs.
|
Utility Margin
The following table reconciles Avista Utilities' operating revenues, as presented in "Note 17 of the Notes to Condensed Consolidated Financial Statements" to the Non-GAAP financial measure utility margin for the three months ended September 30, 20202021 and 20192020 (dollars in thousands):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Electric | | | Natural Gas | | | Intracompany | | | Total | |
| | 2021 | | | 2020 | | | 2021 | | | 2020 | | | 2021 | | | 2020 | | | 2021 | | | 2020 | |
Operating revenues | | $ | 248,110 | | | $ | 225,416 | | | $ | 64,299 | | | $ | 62,107 | | | $ | (25,657 | ) | | $ | (23,959 | ) | | $ | 286,752 | | | $ | 263,564 | |
Resource costs | | | 89,894 | | | | 65,527 | | | | 36,872 | | | | 36,275 | | | | (25,657 | ) | | | (23,959 | ) | | | 101,109 | | | | 77,843 | |
Utility margin | | $ | 158,216 | | | $ | 159,889 | | | $ | 27,427 | | | $ | 25,832 | | | $ | — | | | $ | — | | | $ | 185,643 | | | $ | 185,721 | |
| | Electric | | | Natural Gas | | | Intracompany | | | Total | |
| | 2020 | | | 2019 | | | 2020 | | | 2019 | | | 2020 | | | 2019 | | | 2020 | | | 2019 | |
Operating revenues | | $ | 225,416 | | | $ | 232,320 | | | $ | 62,107 | | | $ | 65,266 | | | $ | (23,959 | ) | | $ | (22,655 | ) | | $ | 263,564 | | | $ | 274,931 | |
Resource costs | | | 65,527 | | | | 79,698 | | | | 36,275 | | | | 41,354 | | | | (23,959 | ) | | | (22,655 | ) | | $ | 77,843 | | | $ | 98,397 | |
Utility margin | | $ | 159,889 | | | $ | 152,622 | | | $ | 25,832 | | | $ | 23,912 | | | $ | — | | | $ | — | | | $ | 185,721 | | | $ | 176,534 | |
Electric utility margin increased $7.3decreased $1.7 million and natural gas utility margin increased $1.9$1.6 million.
Electric utility margin increaseddecreased primarily due to a decrease inincreased net power supply costs as compared to the prior year as costs in the prior year were higher than those recovered through our rates (authorized costs), whereas in 2020 they were lower than authorized costs.year. For the third quarter of 2020,2021, we had a $0.3$3.8 million pre-tax benefitexpense under the ERM in Washington, compared to a $2.4$0.3 million pre-tax expensebenefit for the third quarter of 2019. We also had customer growth and general rate increases2020. The increase in Washington, effective April 1, 2020, which contributed to additional margin. The above increases were partially offset by lower commercial and industrial loads, mainlynet power supply costs was due to COVID-19, and a portion of these loads, primarily industrial loads, are not covered by our decoupling mechanisms.
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Natural gas utility margin increased primarily due to a general rate increase in Oregon, effective January 15, 2020 and Washington, effective April 1, 2020,16, 2021 and customer growth.
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Intracompany revenues and resource costs represent purchases and sales of natural gas between our natural gas distribution operations and our electric generation operations (as fuel for our generation plants). These transactions are eliminated in the presentation of total results for Avista Utilities and in the condensed consolidated financial statements but are included in the separate results for electric and natural gas presented above.
Nine months ended September 30, 20202021 compared to the nine months ended September 30, 20192020
Utility Operating Revenues
The following graphs present Avista Utilities' electric operating revenues and megawatt-hour (MWh) sales for the nine months ended September 30, 20202021 and 20192020 (dollars in millions and MWhs in thousands):
(1)
| This balance includes public street and highway lighting, which is considered part of retail electric revenues, and deferrals/amortizations to customers related to federal income tax law changes.
|
(1)This balance includes public street and highway lighting, which is considered part of retail electric revenues.
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Total electric operating revenues in the graph above include intracompany sales of $25.1$21.9 million and $34.3$25.1 million for the nine months ended September 30, 20202021 and 2019,2020, respectively.
The following table presents the current year deferrals and the amortization of prior year decoupling balances that are reflected in utility electric operating revenues for the nine months ended September 30 (dollars in thousands):
| | | | | | | | |
| | Electric Decoupling Revenues | |
| | 2021 | | | 2020 | |
Current year decoupling deferrals (a) | | $ | (9,947 | ) | | $ | 9,657 | |
Amortization of prior year decoupling deferrals (b) | | | (10,461 | ) | | | (12,333 | ) |
Total electric decoupling revenue | | $ | (20,408 | ) | | $ | (2,676 | ) |
| | Electric Decoupling Revenues | |
| | 2020 | | | 2019 | |
Current year decoupling deferrals (a) | | $ | 9,657 | | | $ | 7,839 | |
Amortization of prior year decoupling deferrals (b) | | | (12,333 | ) | | | 2,172 | |
Total electric decoupling revenue | | $ | (2,676 | ) | | $ | 10,011 | |
Positive amounts are increases in decoupling revenue in the current year and will be surcharged to customers in future years. Negative amounts are decreases in decoupling revenue in the current year and will be rebated to customers in future years.
(b)Positive amounts are increases in decoupling revenue in the current year and are related to the amortization of rebate balances that resulted in prior years and are being refunded to customers (causing a corresponding decrease in retail revenue from customers) in the current year. Negative amounts are decreases in decoupling revenue in the current year and are related to the amortization of surcharge balances that resulted in prior years and are being surcharged to customers (causing a corresponding increase in retail revenue from customers) in the current year.
(a)
| Positive amounts are increases in decoupling revenue in the current year and will be surcharged to customers in future years. Negative amounts are decreases in decoupling revenue in the current year and will be rebated to customers in future years.
|
(b)
| Positive amounts are increases in decoupling revenue in the current year and are related to the amortization of rebate balances that resulted in prior years and are being refunded to customers (causing a corresponding decrease in retail revenue from customers) in the current year. Negative amounts are decreases in decoupling revenue in the current year and are related to the amortization of surcharge balances that resulted in prior years and are being surcharged to customers (causing a corresponding increase in retail revenue from customers) in the current year.
|
Total electric revenues decreased $33.0increased $48.3 million for the first nine months of 20202021 as compared to the first nine months of 2019.2020. The primary fluctuations that occurred during the period were as follows:
| •
| a $6.8 million decrease in retail electric revenue due to a decrease in total MWhs sold (decreased revenues $18.2 million), partially offset by an increase in revenue per MWh (increased revenues $11.4 million).
|
a $40.1 million increase in retail electric revenue due to an increase in total MWhs sold (increased revenues $33.8 million) and an increase in revenue per MWh (increased revenues $6.3 million).
oThe increase in total retail MWhs sold was primarily the result of weather that was warmer than normal and the prior year in the second and third quarters, which increased cooling loads. Also, there was a lifting of COVID-19 restrictions during the second and third quarters of 2021, which contributed to the increased loads, and customer growth. In addition, during the first quarter of 2021, weather was colder than the prior year, which increased heating loads. Compared to the first nine months of 2020, residential electric use per customer and commercial use per customer each increased 5 percent. Cooling degree days in Spokane were 73 percent above normal and first nine months of 2020. Heating degree days in Spokane were 9 percent below normal, and 2 percent below the first nine
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| months of 2020. See "Summer Weather Conditions" in the Executive Level Summary above for discussion of the dry, hot weather conditions experienced in 2021. oRetail rates increased from a general rate increase in Washington, effective April 1, 2020 and from passthrough rate changes, which do not have an impact on utility margin, such as the residential exchange program, low income rate assistance program, the ERM and PCA amortization rates and decoupling. a $4.5 million decrease in wholesale electric revenues due to a decrease in sales volumes (decreased revenues $10.8 million), partially offset by an increase in sales prices (increased revenues $6.3 million). a $27.2 million increase in sales of fuel as part of thermal generation resource optimization activities. a $17.7 million decrease in electric decoupling revenue. This was mainly because the first nine months of 2020 had surcharges to non-residential customers, which had lower usage due to COVID-19 restrictions. In 2021, there are rebates to residential customers due to higher than normal usage from warmer than normal weather, as well as the lifting of COVID-19 restrictions. a $3.3 million increase in other primarily because in the first nine months of 2020, we accrued $1.4 million for customer refunds related to our 2015 Washington general rate case. We also had higher transmission revenues in 2021, resulting in a $1.5 million increase. o
| The decrease in total retail MWhs sold was primarily the result of a decrease in sales volumes to commercial customers and Washington industrial customers due to a combination of impacts associated with COVID-19, as well as weather that was milder than normal and the prior year during the first nine months of the year. These were partially offset by residential and commercial customer growth. Compared to the first nine months of 2019, residential electric use per customer decreased 1 percent, commercial use per customer decreased 7 percent and industrial use per customer increased 1 percent. The industrial increase was all related to Idaho as Washington saw a 9 percent decrease in industrial use per customer. Heating degree days in Spokane were 8 percent below normal and 11 percent below the first nine months of 2019. Cooling degree days were 2 percent above normal, but 12 percent below the first nine months of 2019.
|
| o
| The increase in revenue per MWh was primarily due to an increase in decoupling rates (as there was a decoupling surcharge in 2020 compared to a decoupling rebate in 2019) and a general rate increase in Washington, effective April 1, 2020. This was partially offset by a general rate decrease in Idaho, effective December 1, 2019.
|
| •
| a $15.4 million decrease in sales of fuel as part of thermal generation resource optimization activities.
|
| •
| a $12.7 million decrease in electric decoupling revenue primarily related to the amortization of decoupling surcharges from prior years. This was partially offset by decoupling surcharges for non-residential customers as commercial usage was down compared to normal during the second and third quarters due to COVID-19 impacts. In addition, weather was milder than normal in the first half of 2020, which also resulted in decoupling surcharges.
|
The following graphs present Avista Utilities' natural gas operating revenues and therms delivered for the nine months ended September 30, 20202021 and 20192020 (dollars in millions and therms in thousands):
(1)
| (1) This balance includes interruptible and industrial revenues, which are considered part of retail natural gas revenues, and deferrals/amortizations to customers related to federal income tax law changes. |
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retail natural gas revenues.Total natural gas operating revenues in the graph above include intracompany sales of $37.8$42.8 million and $44.4$37.8 million for the nine months ended September 30, 20202021 and 2019,2020, respectively.
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The following table presents the current year deferrals and the amortization of prior year decoupling balances that are reflected in utility natural gas operating revenues for the nine months ended September 30 (dollars in thousands):
| | | | | | | | |
| | Natural Gas Decoupling Revenues | |
| | 2021 | | | 2020 | |
Current year decoupling deferrals (a) | | $ | 5,348 | | | $ | 641 | |
Amortization of prior year decoupling deferrals (b) | | | 1,991 | | | | (1,988 | ) |
Total natural gas decoupling revenue | | $ | 7,339 | | | $ | (1,347 | ) |
| | Natural Gas Decoupling Revenues | |
| | 2020 | | | 2019 | |
Current year decoupling deferrals (a) | | $ | 641 | | | $ | (3,390 | ) |
Amortization of prior year decoupling deferrals (b) | | | (1,988 | ) | | | 4,483 | |
Total natural gas decoupling revenue | | $ | (1,347 | ) | | $ | 1,093 | |
Positive amounts are increases in decoupling revenue in the current year and will be surcharged to customers in future years. Negative amounts are decreases in decoupling revenue in the current year and will be rebated to customers in future years.
(b)Positive amounts are increases in decoupling revenue in the current year and are related to the amortization of rebate balances that resulted in prior years and are being refunded to customers (causing a corresponding decrease in retail revenue from customers) in the current year. Negative amounts are decreases in decoupling revenue in the current year and are related to the amortization of surcharge balances that resulted in prior years and are being surcharged to customers (causing a corresponding increase in retail revenue from customers) in the current year.
(a)
| Positive amounts are increases in decoupling revenue in the current year and will be surcharged to customers in future years. Negative amounts are decreases in decoupling revenue in the current year and will be rebated to customers in future years.
|
(b)
| Positive amounts are increases in decoupling revenue in the current year and are related to the amortization of rebate balances that resulted in prior years and are being refunded to customers (causing a corresponding decrease in retail revenue from customers) in the current year. Negative amounts are decreases in decoupling revenue in the current year and are related to the amortization of surcharge balances that resulted in prior years and are being surcharged to customers (causing a corresponding increase in retail revenue from customers) in the current year.
|
Total natural gas revenues decreased $16.1increased $18.6 million for the first nine months of 20202021 as compared to the first nine months of 2019.2020. The primary fluctuations that occurred during the period were as follows:
| •
| an $18.7 million increase in natural gas retail revenues due to an increase in retail rates (increased revenues $31.4 million), partially offset by a decrease in volumes (decreased revenues $12.7 million).
|
a $5.4 million increase in natural gas retail revenues (including industrial, which is included in other) due to an increase in volumes sold (increased revenues $3.8 million) and an increase in retail rates (increased revenues $1.6 million).
| o
| Retail rates increased from higher PGA rates, decoupling rate increases and general rate increases in Oregon, effective January 15, 2020 and Washington, effective April 1, 2020.
|
oRetail natural gas sales volumes increased in the first nine months of 2021 as compared to the first nine months of 2020 primarily due to higher commercial and industrial usage, as well as customer growth. Compared to the first nine months of 2020, residential use per customer decreased 1 percent and commercial and industrial use per customer each increased 2 percent. Heating degree days in Spokane were 9 percent below normal, and 2 percent below the first nine months of 2020. Heating degree days in Medford were 6 percent below normal and the first nine months of 2020.
| o
| Retail natural gas sales decreased in the first nine months of 2020 as compared to the first nine months of 2019 primarily due to lower residential, commercial and industrial usage, partially offset by customer growth. Compared
|
oRetail rates increased due to general rate increases in Oregon, effective January 16, 2021 and Washington, effective April 1, 2020. There was also a purchased gas adjustment rate increase in Idaho, effective September 1, 2021 (which does not impact utility margin).
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| | wholesale revenues were consistent, with a decrease in wholesale natural gas revenues due to a decrease in volumes of excess gas sold in the wholesale market (decreased revenues $41.5 million), offset by an increase in prices (increased revenues $41.5 million). Differences between revenues and costs from sales of resources in excess of retail load requirements and from resource optimization are accounted for through the PGA mechanisms. a $8.6 million increase in natural gas decoupling revenue primarily because in 2020, we were amortizing decoupling surcharges, whereas in 2021, we are amortizing decoupling rebates. In addition, there were increases to decoupling revenue in the second and third quarters of 2021 due to weather that was warmer than normal. a $4.9 million increase in other because in the first nine months of 2020, we accrued $3.6 million for customer refunds related to our 2015 Washington general rate case. to the first nine months of 2019, residential use per customer decreased 8 percent, commercial use per customer decreased 12 percent and industrial use per customer decreased 11 percent. Heating degree days in Spokane were 8 percent below normal, and 11 percent below the first nine months of 2019. Heating degree days in Medford were normal, but 4 percent below the first nine months of 2019.
|
| •
| a $28.7 million decrease in wholesale natural gas revenues due to a decrease in prices (decreased revenues $22.8 million) and a decrease in volumes (decreased revenues $5.9 million). Differences between revenues and costs from sales of resources in excess of retail load requirements and from resource optimization are accounted for through the PGA mechanisms.
|
| •
| a $2.4 million decrease in natural gas decoupling revenue primarily related to the amortization of decoupling surcharges from prior years. Also, during the first quarter, there were decoupling rebates to customers and this was partially offset by customer surcharges during the second and third quarters, mainly due to weather that was milder than normal and due to the impacts of COVID-19.
|
| •
| the $2.1 million decrease in other natural gas revenues was primarily related to a $3.6 million accrual for customer refunds related to our 2015 Washington general rate case that was remanded back to the WUTC during 2019. See "Regulatory Matters" for further discussion.
|
The following table presents Avista Utilities' average number of electric and natural gas retail customers for the nine months ended September 30, 20202021 and 2019:2020:
| | Electric Customers | | | Natural Gas Customers | |
| | 2020 | | | 2019 | | | 2020 | | | 2019 | |
Residential | | | 349,890 | | | | 343,875 | | | | 326,568 | | | | 320,084 | |
Commercial | | | 43,399 | | | | 42,881 | | | | 36,139 | | | | 35,715 | |
Interruptible | | | — | | | | — | | | | 40 | | | | 44 | |
Industrial | | | 1,297 | | | | 1,307 | | | | 240 | | | | 241 | |
Public street and highway lighting | | | 639 | | | | 607 | | | | — | | | | — | |
Total retail customers | | | 395,225 | | | | 388,670 | | | | 362,987 | | | | 356,084 | |
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| | | | | | | | | | | | | | | | |
| | Electric Customers | | | Natural Gas Customers | |
| | 2021 | | | 2020 | | | 2021 | | | 2020 | |
Residential | | | 355,613 | | | | 349,890 | | | | 331,441 | | | | 326,568 | |
Commercial | | | 44,064 | | | | 43,399 | | | | 36,425 | | | | 36,139 | |
Interruptible | | | — | | | | — | | | | 42 | | | | 40 | |
Industrial | | | 1,208 | | | | 1,297 | | | | 191 | | | | 240 | |
Public street and highway lighting | | | 664 | | | | 639 | | | | — | | | | — | |
Total retail customers | | | 401,549 | | | | 395,225 | | | | 368,099 | | | | 362,987 | |
Utility Resource Costs
The following graphs present Avista Utilities' resource costs for the nine months ended September 30, 20202021 and 20192020 (dollars in millions):
Total electric resource costs in the graph above include intracompany resource costs of $37.8$42.8 million and $44.4$37.8 million for the nine months ended September 30, 2021 and 2020, and 2019, respectively.
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Total electric resource costs decreased $46.0increased $45.9 million for the first nine months of 20202021 as compared to the first nine months of 2019.2020. The primary fluctuations that occurred during the period were as follows:
| an $19.8 million increase in power purchased due to an increase in wholesale prices (increased costs $16.2 million) and an increase in the volume of power purchases (increased costs $3.6 million). The fluctuation in volumes was primarily the result of differences in the available opportunities for us to optimize our generation assets as compared to the prior year. Additionally, during the second and third quarters of 2021, we had increased customer loads and lower than normal hydroelectric generation as a result of excessive heat in the Pacific Northwest, which contributed to our need to purchase power. See "Summer Weather Conditions" in the Executive Level Summary above. an $26.4 million increase in fuel for generation primarily related to higher natural gas prices. In addition, there was lower hydroelectric generation and increased sales volumes during the second and third quarters, which required increased thermal generation. a $19.9 million increase in other fuel costs. This represents fuel and the related derivative instruments that were purchased for generation but were later sold when conditions indicated that it was more economical to sell the fuel as part of the resource optimization process. When the fuel or related derivative instruments are sold, that revenue is included in sales of fuel. a $20.3 million decrease in other electric resource costs, primarily related to the deferral of increased power supply costs above authorized. There was also increased amortizations associated with the Washington ERM. 
| •
| a $10.6 million decrease in power purchased due to a decrease in wholesale prices (decreased costs $11.6 million), partially offset by an increase in the volume of power purchases (increased costs $1.0 million). The fluctuation in volumes was primarily the result of changes in how we were able to optimize our generation assets as compared to the prior year.
|
| •
| a $15.5 million decrease in fuel for generation primarily related to lower thermal generation due to higher hydroelectric generation as compared to the first nine months of 2019. There was also a decrease in total MWhs sold (which required less fuel for electric generation).
|
| •
| an $8.5 million decrease in other fuel costs. This represents fuel and the related derivative instruments that were purchased for generation but were later sold when conditions indicated that it was more economical to sell the fuel as part of the resource optimization process. When the fuel or related derivative instruments are sold, that revenue is included in sales of fuel.
|
| •
| an $11.3 million decrease in other electric resource costs, primarily related to increased amortizations associated with the Washington ERM, a residential exchange credit and demand side management programs.
|
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Total natural gas resource costs in the graph above include intracompany resource costs of $25.1$21.9 million and $34.3$25.1 million for the nine months ended September 30, 2021 and 2020, and 2019, respectively.
Total natural gas resource costs decreased $20.9increased $5.9 million for the first nine months of 20202021 as compared to the first nine months of 2019.2020 primarily due to the following:
a $13.0 million increase in natural gas purchased due to an increase in the price of natural gas (increased costs $57.6 million), mostly offset by a decrease in volumes (decreased costs $44.6 million). The primary fluctuations that occurred during the period were as follows:decrease in volumes was primarily from a decrease in wholesale sales.
a $7.2 million decrease from net amortizations and deferrals of natural gas costs.
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| •
| a $54.5 million decrease in natural gas purchased due to a decrease in the price of natural gas (decreased costs $44.1 million) and a decrease in volumes purchased (decreased costs $10.4 million).
|
| •
| a $33.7 million increase from net amortizations and deferrals of natural gas costs, primarily due to a spike in natural gas prices during the first quarter of 2019 from a natural gas supply disruption in Canada, which resulted in a significant amount of PGA deferrals during that period.
|
Utility Margin
The following table reconciles Avista Utilities' operating revenues, as presented in "Note 17 of the Notes to Condensed Consolidated Financial Statements" to the Non-GAAP financial measure utility margin for the nine months ended September 30, 2021 and 2020 (dollars in thousands):
| | | Electric | | | Natural Gas | | | Intracompany | | | Total | | | Electric | | | Natural Gas | | | Intracompany | | | Total | |
| | 2020 | | | 2019 | | | 2020 | | | 2019 | | | 2020 | | | 2019 | | | 2020 | | | 2019 | | | 2021 | | | 2020 | | | 2021 | | | 2020 | | | 2021 | | | 2020 | | | 2021 | | | 2020 | |
Operating revenues | | $ | 685,409 | | | $ | 718,378 | | | $ | 286,612 | | | $ | 302,709 | | | $ | (62,912 | ) | | $ | (78,646 | ) | | $ | 909,109 | | | $ | 942,441 | | | $ | 733,709 | | | $ | 685,409 | | | $ | 305,165 | | | $ | 286,612 | | | $ | (64,702 | ) | | $ | (62,912 | ) | | $ | 974,172 | | | $ | 909,109 | |
Resource costs | | | 193,150 | | | | 239,143 | | | | 144,230 | | | | 165,118 | | | | (62,912 | ) | | | (78,646 | ) | | $ | 274,468 | | | $ | 325,615 | | | | 239,050 | | | | 193,150 | | | | 150,116 | | | | 144,230 | | | | (64,702 | ) | | | (62,912 | ) | | | 324,464 | | | | 274,468 | |
Utility margin | | $ | 492,259 | | | $ | 479,235 | | | $ | 142,382 | | | $ | 137,591 | | | $ | — | | | $ | — | | | $ | 634,641 | | | $ | 616,826 | | | $ | 494,659 | | | $ | 492,259 | | | $ | 155,049 | | | $ | 142,382 | | | $ | — | | | $ | — | | | $ | 649,708 | | | $ | 634,641 | |
Electric utility margin increased $13.0$2.4 million and natural gas utility margin increased $4.8$12.7 million.
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For the first nine months of 2020, we had a $5.9 million pre-tax benefit under the ERM in Washington, compared to a $1.1 million pre-tax benefit for the first nine months of 2019. For the full year of 2020, we expect to be in a benefit position under the ERM within the 90 percent customer/10 percent Company sharing band. In addition, electricElectric utility margin was positively impacted byincreased primarily due to customer growth and a general rate increase in Washington, effective April 1, 2020 and customer growth. The above increase was partially offset by lower commercial and industrial loads in2020. In addition, the second and thirdfirst three quarters of 2020 mainly due to COVID-19. A portion of the commercial loads and all of the industrial loads are not covered by our decoupling mechanisms. Also, in the first quarter of 2020 we hadincluded an accrual for customer refunds of $1.4 million related to our 2015 Washington general rate case thatcase. This was remanded backpartially offset by an increase in net power supply costs as compared to the WUTC during 2019. See "Regulatory Matters"prior year due, in part, to the hot, dry weather conditions experienced in 2021 (see "Summer Weather Conditions" in the Executive Level Summary above). For the first nine months of 2021, we had a $7.1 million pre-tax expense under the ERM in Washington, compared to a $5.9 million pre-tax benefit for further discussion.the first nine months of 2020.
Natural gas utility margin increased primarily due to a general rate increasesincrease in Oregon, effective January 15, 202016, 2021 and Washington, effective April 1, 2020, and customer growth. These increases were partially offset byAlso, the first quarter of 2020 included an accrual for customer refunds of $3.6 million related to our 2015 Washington general rate case that was remanded back to the WUTC during 2019. See "Regulatory Matters" for further discussion.case.
Intracompany revenues and resource costs represent purchases and sales of natural gas between our natural gas distribution operations and our electric generation operations (as fuel for our generation plants). These transactions are eliminated in the presentation of total results for Avista Utilities and in the condensed consolidated financial statements but are included in the separate results for electric and natural gas presented above.
Results of Operations - Alaska Electric Light and Power Company
Three months ended September 30, 20202021 compared to the three months ended September 30, 20192020 and nine months ended September 30, 20202021 compared to the nine months ended September 30, 20192020
Net income for AEL&P was $0.3less than $0.1 million for the three months ended September 30, 2020 compared to $0.2 million2021 and $0.3 for the three months ended September 30, 2019.2020. Net income was $4.8 million for the nine months ended September 30, 2021 compared to $5.0 million for the nine months ended September 30, 2020 compared to $4.8 million for the nine months ended September 30, 2019.2020.
The following table presents AEL&P's operating revenues, resource costs and resulting utility margin for the three and nine months ended September 30, 2021 and 2020 (dollars in thousands):
| | | | | | | | | | | | | | | | |
| | Three months ended September 30, | | | Nine months ended September 30, | |
| | 2021 | | | 2020 | | | 2021 | | | 2020 | |
Operating revenues | | $ | 9,147 | | | $ | 8,815 | | | $ | 32,515 | | | $ | 31,014 | |
Resource costs | | | 1,024 | | | | 942 | | | | 2,926 | | | | 1,829 | |
Utility margin | | $ | 8,123 | | | $ | 7,873 | | | $ | 29,589 | | | $ | 29,185 | |
| | Three months ended September 30, | | | Nine months ended September 30, | |
| | 2020 | | | 2019 | | | 2020 | | | 2019 | |
Operating revenues | | $ | 8,815 | | | $ | 7,790 | | | $ | 31,014 | | | $ | 27,414 | |
Resource costs (benefit) | | | 942 | | | | (73 | ) | | | 1,829 | | | | (1,505 | ) |
Utility margin | | $ | 7,873 | | | $ | 7,863 | | | $ | 29,185 | | | $ | 28,919 | |
Electric revenuesUtility margin increased slightly for the third quarter of 20202021, primarily due to higher sales volumes to residential and commercial customers for 2020 as2021 compared to 2019. This resulted from weather that was cooler than the prior year, as well as more hydroelectric generation than the third quarter of 2019.2020.
AEL&P had low hydroelectric generation during the first three quarters of 2019, which limited energy provided to their interruptible customers. A portion of the sales to interruptible customers is used to reduce the overall cost of power to AEL&P's firm customers. When interruptible sales are below a certain threshold, AEL&P recognizes a regulatory asset and records a reduction to deferred power supply costs (resource costs) to reflect a future billable amount to its firm customers when the cost of power rates are reset. During the first three quarters of 2020, hydroelectric generation returned to normal levels, which resulted in less resource costs compared to the first three quarters of 2019. While the COVID-19 pandemic and a challenged Alaska economy may introduce unpredictability into the remainder of 2020, AEL&P has the capacity to manage costs.
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Results of Operations - Other Businesses
Our other businesses had net income of $5.2 million for the three months ended September 30, 2021 compared to a net loss of $0.9 million for the three months ended September 30, 2020 compared to a net loss of $1.1 million for the three months ended September 30, 2019. A net loss of $3.4 million2020. Net income was recognized for the nine months ended September 30, 2020 compared to net income of $2.3$10.8 million for the nine months ended September 30, 2019.2021 compared to a net loss of $3.4 million for the nine months ended September 30, 2020.
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The increase in net income primarily relates to net investment gains during the first three quarters of 2020, we had impairment losses on some of our investments and the write-off of a note receivable.nine months ended September 30, 2021. This is compared to the first three quarters of 20192020 that resulted in net investment gains, primarily relatedlosses. In addition, 2021 net income increased due to the sale of METALfx. See “Note 19certain subsidiary assets associated with the Spokane Steam Plant during the second quarter of 2021. During the Notes to Condensed Consolidated Financial Statements”first nine months of 2020 there was an impairment loss and an accrual for further discussion on the sale of METALfx.bad debt.
Critical Accounting Policies and Estimates
The preparation of our consolidated financial statements in conformity with GAAP requires us to make estimates and assumptions that affect amounts reported in the consolidated financial statements. Changes in these estimates and assumptions are considered reasonably possible and may have a material effect on our consolidated financial statements and thus, actual results could differ from the amounts reported and disclosed herein. Our critical accounting policies that require the use of estimates and assumptions were discussed in detail in the 20192020 Form 10-K and have not changed materially.
Liquidity and Capital Resources
Overall Liquidity
We expect that COVID-19 will have a negative impact on our overall liquidity. For 2020, we expect our net cash flows from operations to decrease primarily due to lower expected revenues from retail sales of electricity and natural gas and lower payments from customers.
In response to potential liquidity needs, in April 2020, we entered into a $100 million credit agreement, see "Note 9 of the Notes to Condensed Consolidated Financial Statements."
Other than COVID-19 impacts, ourOur sources of overall liquidity and the requirements for liquidity have not materially changed in the nine months ended September 30, 2020.2021. See the 20192020 Form 10-K for further discussion.
In April 2021, we repaid our $100 million credit agreement.
As of September 30, 2020,2021, we had $324.4$105.4 million of available liquidity under the Avista Corp. committed line of credit and $25.0 million under the AEL&P committed line of credit. After considering the impacts of COVID-19, withWith our $400.0 million credit facility that expires in April 2022June 2026 and AEL&P's $25.0 million credit facility that expires in November 2024, we believe that we have adequate liquidity to meet our needs for the next 12 months.
Review of Cash Flow Statement
Operating Activities
Net cash provided by operating activities was $228.9 million for the nine months ended September 30, 2021, compared to $282.5 million for the nine months ended September 30, 2020 compared to $340.5 million for the nine months ended September 30, 2019.2020. The decrease in net cash provided by operating activitiesis primarily relatesdue to a termination fee of $103.0 million (less transaction costs and income taxes of $19.7 million (pre-tax) and $15.7 million, respectively,an increase in 2019) received in 2019 upon the termination of the Hydro One transaction. In addition, we settled interest rate swaps during 2020 and paid a net amount of $33.5 million, compared to a net cash paid of $13.3 million for interest rate swap settlements in 2019.
The above decrease in net cash provided by operating activities was partially offset by power and natural gas cost deferrals, which decreased during 2020 due to lower natural gas prices during the year, which decreased cash flows by $6.5$40.2 million, as compared to a decrease to operating cash flows of $45.8$6.5 million in 2019. As2020. Additionally, during the nine months ended September 30, 2021 we contributed $42.0 million to the pension plan, compared to 2019,$22.0 million in 2020. Additionally, changes in certain net current assets and liabilities decreased cash provided by $41.6operating activities by $34.0 million.
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Investing Activities
Net cash used in investing activities was $326.9 million for the nine months ended September 30, 2021, compared to $301.0 million for the nine months ended September 30, 2020,2020. During the nine months ended September 30, 2021, we paid $322.8 million for utility capital expenditures compared to $320.3$297.8 million for the nine months ended September 30, 2019. During the nine months ended September 30, 2020, we paid $297.8 million for utility capital expenditures compared to $321.02020.
Financing Activities
Net cash provided by financing activities was $103.0 million for the nine months ended September 30, 2019. Also, during 2020, we received proceeds from the sale of equity investments (net of cash sold and amounts held in escrow) of $6.6 million.
Financing Activities
Net2021, compared to net cash provided by financing activities wasof $93.3 million for the nine months ended September 30, 2020, compared to cash used of $20.4 million for2020. In the nine months ended September 30, 2019. During the third quarter of 2020,2021, we issued long-term debt of $165.0 million. See “Note 10 of Notesincreased our short term borrowings by $66.0 million, compared to Condensed Consolidated Financial Statements” for further discussion on the issuance of long-term debt. In addition, during the nine months ended September 30, 2020 we decreased our short-termdecreasing short term borrowings by $35.8 million as comparedin 2020. This was offset by a decrease in the issuance of long term debt during the period, from $165.0 million in 2020 to an increase$70.0 million in our short-term borrowings2021.
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Capital Resources
Our consolidated capital structure, including the current portion of long-term debt and short-term borrowings consisted of the following as of September 30, 20202021 and December 31, 20192020 (dollars in thousands):
| | September 30, 2020 | | | December 31, 2019 | |
| | Amount | | | Percent of total | | | Amount | | | Percent of total | |
Current portion of long-term debt and leases (1) | | $ | 59,122 | | | | 1.4 | % | | $ | 58,928 | | | | 1.4 | % |
Short-term borrowings | | | 150,000 | | | | 3.4 | % | | | 185,800 | | | | 4.4 | % |
Long-term debt to affiliated trusts | | | 51,547 | | | | 1.2 | % | | | 51,547 | | | | 1.2 | % |
Long-term debt and leases (1) | | | 2,129,606 | | | | 48.7 | % | | | 1,961,083 | | | | 46.7 | % |
Total debt | | | 2,390,275 | | | | 54.7 | % | | | 2,257,358 | | | | 53.8 | % |
Total Avista Corporation shareholders’ equity | | | 1,982,851 | | | | 45.3 | % | | | 1,939,284 | | | | 46.2 | % |
Total | | $ | 4,373,126 | | | | 100.0 | % | | $ | 4,196,642 | | | | 100.0 | % |
| | | | | | | | | | | | | | | | | | | September 30, 2021 | | | December 31, 2020 | | | | Amount | | | Percent
of total | | | Amount | | | Percent
of total | | Current portion of long-term debt and leases | | $ | 257,337 | | | | 5.6 | % | | $ | 7,184 | | | | 0.2 | % | Short-term borrowings | | | 199,075 | | | | 4.3 | % | | | 203,000 | | | | 4.6 | % | Long-term debt to affiliated trusts | | | 51,547 | | | | 1.1 | % | | | 51,547 | | | | 1.2 | % | Long-term debt and leases | | | 2,014,212 | | | | 43.5 | % | | | 2,125,065 | | | | 48.0 | % | Total debt | | | 2,522,171 | | | | 54.5 | % | | | 2,386,796 | | | | 54.0 | % | Total Avista Corporation shareholders’ equity | | | 2,101,636 | | | | 45.5 | % | | | 2,029,726 | | | | 46.0 | % | Total | | $ | 4,623,807 | | | | 100.0 | % | | $ | 4,416,522 | | | | 100.0 | % |
(1)
| Lease amounts of $7.1 million and $120.3 million for current and long-term, respectively, are included in other current liabilities and other non-current liabilities and deferred credits on the Condensed Consolidated Balance Sheets.
|
Our shareholders’ equity increased $43.6$71.9 million during the first nine months of 20202021 primarily due to net income and the issuance of common stock, which was partially offset by dividends.
We need to finance capital expenditures and acquire additional funds for operations from time to time. The cash requirements needed to service our indebtedness, both short-term and long-term, reduce the amount of cash flow available to fund capital expenditures, purchased power, fuel and natural gas costs, dividends and other requirements.
Committed Lines of Credit
Avista Corp. has a committed line of credit with various financial institutions in the total amount of $400.0 million. DuringIn June 2021, we entered into an amendment that extends the second quarter, we amended and extended, for one additional year, the revolving line of credit agreement for a revised expiration date of April 2022,to June 2026, with the option to extend for an additional one year period.period (subject to customary conditions). The committed line of credit is secured by non-transferable first mortgage bonds we issued to the agent bank that would only become due and payable in the event, and then only to the extent, that we default on our obligations under the committed line of credit.
The Avista Corp. credit facility contains customary covenants, and default provisions, including a covenant which does not permit our ratio of “consolidated total debt” to “consolidated total capitalization” to be greater than 65 percent at the end of any time.fiscal quarter, and customary events of default, including a Change in Control (as defined in the agreement). As of September 30, 2020,2021, we were in compliance with this covenant with a ratio of 54.754.5 percent.
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AEL&P has a $25.0 million committed line of credit that expires in November 2024. As of September 30, 2020,2021, there were no borrowings or letters of credit outstanding under this committed line of credit.
The AEL&P credit facility contains customary covenants and default provisions including a covenant which does not permit the ratio of “consolidated total debt at AEL&P” to “consolidated total capitalization at AEL&P” (including the impact of the Snettisham obligation) to be greater than 67.5 percent at any time. As of September 30, 2020,2021, AEL&P was in compliance with this covenant with a ratio of 52.451.3 percent.
Balances outstanding and interest rates of borrowings under Avista Corp.'s committed line of credit were as follows as of and for the nine months ended September 30 (dollars in thousands):
| | | | | | | | |
| | 2021 | | | 2020 | |
Borrowings outstanding at end of period | | $ | 269,000 | | | $ | 50,000 | |
Letters of credit outstanding at end of period | | $ | 25,618 | | | $ | 25,573 | |
Maximum borrowings outstanding during the period | | $ | 338,000 | | | $ | 257,000 | |
Average borrowings outstanding during the period | | $ | 190,641 | | | $ | 178,537 | |
Average interest rate on borrowings during the period | | | 1.15 | % | | | 1.28 | % |
Average interest rate on borrowings at end of period | | | 1.09 | % | | | 1.20 | % |
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| | 2020 | | | 2019 | |
Borrowings outstanding at end of period | | $ | 50,000 | | | $ | 169,000 | |
Letters of credit outstanding at end of period | | $ | 25,573 | | | $ | 18,603 | |
Maximum borrowings outstanding during the period | | $ | 257,000 | | | $ | 190,000 | |
Average borrowings outstanding during the period | | $ | 178,537 | | | $ | 114,331 | |
Average interest rate on borrowings during the period | | | 1.28 | % | | | 3.31 | % |
Average interest rate on borrowings at end of period | | | 1.20 | % | | | 3.26 | % |
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As of September 30, 2020,2021, Avista Corp. and its subsidiaries were in compliance with all of the covenants of their financing agreements, and none of Avista Corp.'s subsidiaries constituted a “significant subsidiary” as defined in Avista Corp.'s committed line of credit.
In April 2020, we entered into a $100.0 million credit agreement with an expiration date of April 2021. We borrowed the entire $100.0 million available under this agreement. See "Note 9 of the Notes to Condensed Consolidated Financial Statements."
The credit agreement contains customary covenants and default provisions, including a covenant not to permit the ratio of “consolidated total debt” to “consolidated total capitalization” of Avista Corp. to be greater than 65 percent at any time. As of September 30, 2020, we were in compliance with this covenant with a ratio of 54.7 percent.
Liquidity Expectations
During the third quarter of 2020,2021, we issued $165.0expect to issue approximately $140 million of long-term debt (see “Note 10and $90 million of the Notes to Condensed Consolidated Financial Statements). No further debt issuances are planned for 2020. During 2020, we expect to issue aboutcommon stock (including $70.0 million of equity (including $53.4long-term debt and $61.3 million of common stock issued during the nine months ended September 30, 2020)2021). During 2022, we expect to maintain an appropriate capital structure. We intend to use the proceeds from ourissue approximately $370 million of long-term debt and equity issuances$90 million of common stock in order to refinance $250 million of maturing long-term debt and fund planned capital expenditures and for other general corporate purposes.expenditures.
After considering the impacts of COVID-19, including the expectation of lower net operating cash flows, and theexpected issuances of long-term debt and equitycommon stock during 2020,2021, we expect net cash flows from operations, together with cash available under our committed lines of credit to provide adequate resources to fund capital expenditures, dividends, and other contractual commitments.
Capital Expenditures
We are making capital investments to enhance service and system reliability for our customers and replace aging infrastructure. Our estimatedWe expect Avista Utilities capital expenditures increasedto $450 million in 2021, and about $445 million for 2020 from $405 millioneach of 2022 and 2023 to $430 million due to highersupport continued customer growth and storm related capital. Our estimates for 2021 and 2022 have not materially changed during the nine months ended September 30, 2020.maintain our system to provide safe, reliable energy to our customers. See the 20192020 Form 10-K for further information on our expected capital expenditures.
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Off-Balance Sheet Arrangements
As of September 30, 2020,2021, we had $25.6 million in letters of credit outstanding under our $400.0 million committed line of credit, compared to $21.5$27.6 million as of December 31, 2019.2020.
Pension Plan
Avista Utilities
In the nine months ended September 30, 20202021 we contributed $22.0$42.0 million to the pension plan, and we do not expect furtherfulfilling our expected contributions in 2020.for 2021. We expect to contribute a total of $128.0$108 million to the pension plan in the period 20212022 through 2024,2025, with annual contributions of $42.0$42 million in 2021 and 2022 and $22.0$22 million in 2023 and 2024.to 2025.
The final determination of pension plan contributions for future periods is subject to multiple variables, most of which are beyond our control, including changes to the fair value of pension plan assets, changes in actuarial assumptions (in particular the discount rate used in determining the benefit obligation), or changes in federal legislation. We may change our pension plan contributions in the future depending on changes to any variables, including those listed above.
See "Note 6 of the Notes to Condensed Consolidated Financial Statements" for additional information regarding the pension plan.
Contractual Obligations
Our future contractual obligations have not materially changed during the nine months ended September 30, 2020,2021, except for the following:
| In June 2021, we amended our committed line of credit agreement to extend the expiration date until June 2026. In September 2021, we issued $70.0 million of first mortgage bonds under a bond purchase agreement and we expect to issue an additional $70.0 million under this agreement in December 2021. •
| in April 2020, we entered into a $100.0 million credit agreement with a maturity date of April 2021. See “Note 9 of the Notes to Condensed Consolidated Financial Statements.”
|
| •
| in June 2020, we extended the $400.0 million committed line of credit with an expiration date of April 2022. See "Note 8 of the Notes to Condensed Consolidated Financial Statements."
|
| •
| on September 30, 2020, the Company issued and sold $165.0 million of 3.07 percent first mortgage bonds due in 2050 pursuant to a bond purchase agreement with institutional investors in the private placement market. See “Note 10 of the Notes to Condensed Consolidated Financial Statements.”
|
See the 20192020 Form 10-K for our contractual obligations.
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Environmental Issues and Contingencies
Our environmental issues and contingencies disclosures have not materially changed during the nine months ended September 30, 20202021 except as discussed below:
Coal Ash Management/DisposalClean Energy Commitment
In 2015,April 2019, we announced a goal to serve our customers with 100 percent clean electricity by 2045 and to have a carbon-neutral supply of electricity by the EPA issuedend of 2027. To help achieve our goals and add to our clean electricity portfolio we have implemented renewable energy projects on behalf of our customers, including the Solar Select project (28 MW) in Lind, Washington (PPA) and the Rattlesnake Flat Wind project (144 MW) in Adams County, Washington (PPA). We also entered into a final rule regarding coal combustion residuals (CCRs), also termed coal combustion byproducts or coal ash. The CCR rule has been the subject of ongoing litigation. In August 2018, the D.C. Circuit struck down provisionsPPA for an additional 5 percent of the rule. Colstrip,output from Chelan PUD’s hydroelectric projects. The contract with Chelan PUD begins in 2024. These resources are in addition to our existing clean hydroelectric generation, biomass generation, and other wind and solar projects.
To achieve our clean energy goals, we expect that energy storage and other technologies, which are either not currently available or are not cost-effective under a lowest reasonable cost regulatory standard, will advance such that those technologies will assist us in meeting our goals while also maintaining reliability and affordability for our customers. If the required technology is not available or not affordable in the future, we may not meet our goals in the desired timeframe. Meeting our clean energy goals may also require accommodation from economic regulatory agencies insofar as the Company may need to acquire emission offsets to meet its goals.
Washington Clean Energy Implementation Plan
In October 2021, Avista Utilities filed its first Clean Energy Implementation Plan (CEIP) with the WUTC. This filing will trigger comments from interested parties in early 2022, with WUTC action to follow thereafter in 2022.
Our CEIP is a road map of specific actions we propose to take over the next four years (2022-2025) to show the progress being made toward clean energy goals established by the Clean Energy Transformation Act (CETA), which was passed by the Washington legislature and enacted into law in 2019. CETA requires electric supply to be greenhouse gas neutral by 2030 and 100 percent renewable or generated from zero-carbon resources by 2045.
Some highlights of Avista’s CEIP include:
Beginning in 2022, we plan to serve 80 percent of our Washington customer demand with renewable energy, then increase this target by 5 percent every two years.
To minimize rate impacts as we transition to cleaner energy, we are proposing to sell some of our renewable energy credits (RECs) on the behalf of customers through 2029. In 2030, we will utilize 100 percent of RECs on behalf of our customers, rather than selling RECs on the open market. Our proposed plan to sell these renewable attributes should lower rates by 1 percent each year.
The plan sets energy efficiency targets to reduce customer load by approximately 2 percent over the next four years by 204,305 megawatt hours through incentives and programs to lower energy use without impacting the customer.
Our demand response target is to lower peak demand by 30 megawatts in periods of extreme heat or cold as an effort to eliminate the need for future resources.
We have proposed a 15 percent ownervariety of Units 3 & 4, produces this byproduct. In December 2019, a proposed revisioninitiatives to promote the rule was publishedequitable distribution of the benefits and burdens of renewable energy.
While the CEIP represents our current objectives, it is subject to change from time to time in the Federal Register to address the D.C. Circuit's decision. The rule includes technical requirements for CCR landfills and surface impoundments under Subtitle D of the Resource Conservation and Recovery Act, the nation's primary law for regulating solid waste. The Colstrip owners developed a multi-year compliance plan to address the CCR requirements with existing state obligations expressed largely by the 2012 Administrative Order on Consent (AOC) with Montana Department of Environmental Quality (MDEQ). These requirements continue despite the 2018 federal court ruling.future as circumstances warrant.
The AOC requires MDEQ provide an ongoing public process which recently approved the Remedy and Closure plans for the three major areas of Colstrip. The AOC also requires the Colstrip owners to provide financial assurance primarily in the form of surety bonds, to secure each owner’s pro rata share of various anticipated closure and remediation obligations. Avista Corp. is responsible for
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Climate Change
Federal Regulatory Actions
In January 2021, the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit) vacated the Affordable Clean Energy Rule and remanded the record back to the EPA for further consideration consistent with its shareopinion. The Court also vacated the repeal of two major areas; the Plant Site AreaClean Power Plan (CPP). Subsequently, the EPA indicated, in a February 12, 2021 Memorandum from Acting Assistant Administrator Joseph Goffman that “…EPA understands the decision as leaving neither of those rules, and thus no CAA section 111(d) regulation, in place with respect to greenhouse gas (GHG) emissions from electric generating units (EGUs). As a practical matter, the reinstatement of the CPP would not make sense.”
Washington Climate Commitment Act
In 2021, the legislature passed the Climate Commitment Act, which establishes a cap and invest program to help achieve Washington’s greenhouse gas limits by 2050. The Washington Department of Ecology is responsible for the implementation and the Effluent Holding Pond (EHP) Area. Generally,start of this program by January 1, 2023, including the plans includeadoption of annual allowance budgets for the removal of Boron, Chloride, and Sulfate from the groundwater, closurefirst compliance period of the existing ash storage ponds,program by October 1, 2022. There are various rule making proceedings regarding the details of the program pending before the Department of Ecology. We will actively monitor and installationparticipate in these rulemakings as they proceed but cannot reasonably predict how these programs may impact our facilities at this time.
Oregon Executive Order 20-04
On March 10, 2020, the governor of Oregon issued an Executive Order (EO) establishing GHG emissions reduction goals of at least 45 percent below 1990 emission levels by 2035 and at least 80 percent below 1990 emission levels by 2050 and directed state agencies and commissions to facilitate such GHG emission goals targeting a new water treatmentvariety of sources and industries. Although the EO does not specifically direct actions of natural gas distribution businesses like Avista, the OPUC is directed to prioritize proceedings and activities that advance decarbonization in the utility sector, mitigate energy burden experienced by utility customers and ensure system reliability and resource adequacy. The EO also directs other agencies to convert the facility to a dry ash storage. Avista Corp. has posted three surety bonds totaling approximately $23 million. This amount will be updated annually, decreasing over time as remediation activities are completed.
Washington Legislationcap and Regulatory Actions
GHG Reduction Targets
The State of Washington has adopted non-binding targets to reduce GHG (Greenhouse Gas) emissions. emissions from transportation fuels and all other liquid and gaseous fuels, including natural gas, adopt building energy efficiency goals for new building construction, reduce methane gas emissions from landfills and food waste, and submit a proposal for adoption of state goals for carbon sequestration and storage by Oregon’s forest, wetlands and agricultural lands.
The State enacted its targets with an expectation of reaching the targets through a combination of renewable energy standards, eventual carbon pricing mechanisms, such as cap and trade regulation or a carbon tax, and assorted “complementary policies.” However, no specific reductions are mandated as yet. The State’s targets, originally enacted in 2008, have been evaluated by state institutions against the aims of the Paris Climate Accord of 2016, which include limiting the increase in the global average temperatures to at least below 2 degrees Celsius above pre-industrial levels and pursuing efforts to restrict the temperature increase to 1.5 degrees Celsius above pre-industrial levels. In 2020, the Legislature adjusted the state’s targets, accordingly. Under Washington law, GHG emissions should be reduced to being 95% below 1990 levels (or to five million metric tons) by 2050, with the state achieving net zero emissions by that year. We intend to seek recovery of any new costs associated with these reduction targets, or any new reduction targets, through the regulatory process.
Oregon Legislation and Regulatory Actions
GHG Reduction Targets
The State of Oregon has adopted non-binding targets to reduce GHG emissions. The State enacted its targets with an expectation of reaching the targets through a combination of renewable energy standards, eventual carbon pricing mechanisms, such as cap and trade regulation or a carbon tax, and assorted “complementary policies.” However, no specific reductions are mandated as yet. The State’s targets have been evaluated by state institutions against the aims of the Paris Climate Accord of 2016, which include limiting the increase in global average temperatures to at least below 2 degrees Celsius above pre-industrial levels and pursuing efforts to restrict the temperature increase to 1.5 degrees Celsius above pre-industrial levels. In March 2020, Oregon Governor Kate Brown issued Executive Order No. 20-04, “Directing State Agencies to Take Actions to Reduce and Regulate Greenhouse Gas Emissions.” The Executive Order launches rulemaking proceedings for every Oregon agency with jurisdiction over greenhouse gas-related matters, with the aim of reducing Oregon’s overall GHG emissions to 80% below 1990 levels by 2050. Oregon agencies, including the Department of Environmental Quality (DEQ) and the Public Utility Commission, issued reports discussing general intent to carry out the Executive Order. DEQ(ODEQ) is tasked with developing rules for a cap and reduce programrules known as the Climate Protection Program (CPP). Final rules are expected to be considered for adoption by the Environmental Quality Commission in December 2021 and become effective in 2022. The OPUC has opened a Natural Gas Fact-Finding effort to analyze the potential natural gas utility bill impacts that would applymay result from limiting GHG emissions of regulated natural gas utilities under the ODEQ’s CPP and to Avista’s gas distribution businessidentify appropriate regulatory tools to mitigate potential customer impacts. According to the OPUC Staff, the ultimate goal of the Fact-Finding Docket will be to inform future policy decisions and other key analyses to be considered in Oregon. The agency initiated informal2022, after the CPP is in place. We expect the OPUC Staff will present a final report on the Fact-Finding effort to the OPUC in February 2022 with recommendations for further OPUC engagement later in 2022.
See the 2020 Form 10-K for further discussion of environmental issues and broad stakeholder consultation in June 2020, which will continue duringcontingencies.
Other
TSA Security Directive
In July 2021, the remainderDepartment of 2020 and shift into formal rulemaking. We cannot reasonably predict what regulatory proceedings will arise from the Executive Order, nor how the state legislature may undertake additional requirements or revise the State's targets in the future. We intend to seek recovery of any new costs associated with these reduction targets, or any new reduction targets,Homeland Security, acting through the regulatory process.
Cabinet Gorge Total Dissolved Gas Abatement Plan
Dissolved atmosphericTransportation Security Administration (TSA), announced the issuance of a security directive that requires owners and operators of TSA-designated critical pipeline facilities that transport hazardous liquids and natural gas levels (referred to as "Total Dissolved Gas" or "TDG") in the Clark Fork River exceed stateimplement specified protections against cyber intrusions. The security directive requires designated owners and operators of Idaho and federal water quality numeric standards downstream of Cabinet Gorge particularly during periods when excess river flows must be diverted over the spillway. Under the terms of the Clark Fork Settlement Agreement as incorporated in Avista Corp.’s FERC license for the Clark Fork Project, Avista Corp. works in consultation with agencies, tribessuch facilities to implement specific mitigation measures to protect against ransomware attacks and other stakeholdersknown threats to address this issue through structural modifications to the spillgates, monitoringinformation and analysis. After extensive testing, Clark Fork Settlement Agreement stakeholders have agreed that no further spillway modifications are justified. For the remainder of the FERC License term, Avista Corp. will continue to mitigate remaining impacts of TDG while considering the potential for new approaches to further reduce TDG. operational technology systems, develop and implement a cybersecurity contingency and recovery plan and conduct a cybersecurity architecture design review.
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The Company continues to work with stakeholders to determineis assessing the degreeextent to which TDG abatement reduces future mitigation obligations.its facilities are or may be affected, directly or indirectly, by the directive. The Company has sought,is engaged in a continuous program of testing and intends to continue to seek recovery, throughupdating its cybersecurity measures. As reported in the ratemaking process,2020 Form 10-K, the Company’s natural gas distribution facilities, as well as most of all operating and capitalized costs related to this issue.
Hazardous Air Pollutants (HAPs)
In April 2016, the Mercury Air Toxic Standards (MATS), an EPA rule for coal-and oil-fired sources, became effective for all Colstrip units. Colstrip has already implemented applicable MATS control measures to complyits gas-fired generation facilities, are interconnected with the MATS rule,gas transportation systems of several interstate gas pipelines.
Colstrip
Colstrip is a coal-fired generating plant in southeastern Montana that includes four units and continues to monitor potential changeswhich is owned by six separate entities. We have a 15 percent ownership interest in Units 3 & 4 and provide financing for our ownership interest in the rule to determine additional compliance obligations, if any. Colstrip performs compliance assurance stack testing on a quarterly basis to meetproject. The other owners are Puget Sound Energy, Portland General Electric, PacifiCorp, NorthWestern Energy and Talen Montana (which is also the MATS site-wide limitation for Particulate Matter (PM) emissions (0.03 lbs./MMBtu)operator of the plant). In June 2018,January 2020, the Montana Departmentowners of Environmental Quality (MDEQ) was notified of a PM emission deviation by Talen Montana, LLC (Talen), the plant operator, for the testing performedUnits 1 & 2, in June 2018. As a result, Unit 3 was promptly removed from service. For similar reasons, Unit 4 was removed from service in June 2018.
Talen proposed, and the MDEQ acknowledged, that limited operationwhich we have no ownership, closed those two units. The owners of Units 3 & 4 for the evaluation of a corrective action and/or data gathering related to potential corrective action was a prudent approach to solving the issue. An extensive inspection was conducted including: the coal supply, coal mills, boiler, combustion, ductwork, air preheater, scrubbers,currently share operating and the stack. Talen implemented cleaning, adjustments, troubleshooting, testing, and other corrective actions. As a part of the corrective action, new flow balancing plates were installed in all Unit 3 & 4 scrubber vessels to further enhance PM removal efficiency. PM testing in September 2018 on Units 3 & 4 demonstrated compliance with the MATS. Both of these compliance tests were witnessed by the MDEQ. With the passing of the PM testing with MATS compliance, Talen, the Colstrip Operator returned both Units 3 & 4 to service in September 2018.
Duecapital costs pursuant to the June 2018 failure to meet the MATS standard, Colstrip Units 3 & 4 were subject to potential MDEQ enforcement action. In lieuterms of such an action, in December 2019, Talen and MDEQ entered a Stipulated Consent Decree providing for a cash penalty, partially offset by anoperating agreement by Talen to fund specified Supplemental Environmental Projects, as well as additional monitoring activities. The total amount of the cash penalty allocable to the Company is not material. However, PacifiCorp, PSE, and the Company engaged in a consolidated proceeding before the WUTC to determine the recoverability of replacement power costs incurred during the period that Units 3 & 4 were out of service. In March 2020, the Company received an order from the WUTC, which, among other outcomes, rebated approximately $3 million that was disallowed by the Commission for the cost of replacement power during the unplanned outage at Colstrip in 2018.
Colstrip Coal Contract
Colstrip, which is operated by Talen, is supplied with fuel from adjacent coal reserves under coal supply and transportation agreements. The contract for coal supply extended through 2019. Several of the co-owners of Colstrip, including the Company, have since negotiated an extension to the coal contract that runs through December 31, 2025. In January 2020, the Staff of the WUTC submitted a Petition to Initiate Joint Investigation to the WUTC to investigate the contract. In their petition, the WUTC Staff is proposing one proceeding involving the three joint owners of Colstrip Units 3 & 4 and the focus of their proposed investigation is to review the overall prudency of the new contract and any production tax credits associated with the contract. In March 2020, the WUTC denied the WUTC Staff’s position.
PSE Sale of Its Share of Colstrip Unit 4
In December 2019, PSE announced that it had entered into an agreement to sell its share of Colstrip Unit 4 to NorthWestern Energy, along with certain related transmission rights and assets. The agreement was subject to approval by the WUTC and Montana Public Service Commission. In October 2020, the parties terminated the agreement.
Wildfire Resiliency Plan
We are implementing additional measures to enhance our ability to mitigate the potential for, and impact of, wildfires within our service territories. Building on prevention and response strategies that have been in place many years, we created a new
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comprehensive 10-year Wildfire Resiliency Plan that includes improved defense strategies and operating practices for a more resilient system.
We have spent the last year developing the Wildfire Resiliency Plan through a series of internal workshops, industry research and engagement with state and local fire agencies. Improvements to infrastructure and operational practices were identified as key components to the plan. These key components are categorized into the following categories: grid hardening, vegetation management, situational awareness, operations and emergency response, and worker and public safety.
We expect to spend approximately $330 million implementing the plan components over the life of the 10-year plan. We filed deferred accounting requests in Washington and Idaho to defer the cost of the wildfire resiliency plan and seek recovery in future rate filings.
See “Note 16 of the Notes to Condensed Consolidated Financial Statements” for further discussion on wildfires.
Request for Proposals for Renewable Energy
We are seeking proposals from renewable energy project developers who are capable of constructing, owning,pending arbitration proceedings, recent Montana legislation, and operating upother matters related to 120 average MWs (aMWs) whether through one or multiple proposals with a minimum net annual output of 20 aMW. We are not considering a self-build option for this facility or facilities.
Our intent is to secureColstrip. See also the output from renewable generation resources, including electricity, capacity and associated environmental attributes. Our interest in acquiring new renewable energy resources is to offset market purchases and fossil-fuel thermal generation. This is consistent with our 2020 Integrated Resource Plan which identifies that the utility will consider acquiring additional resources if such resources have lower long-term cost than electric market alternatives.
See the 2019 Form 10-K for further discussion of environmental issues and contingencies.Colstrip.
Enterprise Risk Management
The material risks to our businesses, and our mitigation process and procedures to address these risks, were discussed in our 20192020 Form 10-K and have not materially changed during the nine months ended September 30, 2020, other than the changes noted due to COVID-19.2021. See the 20192020 Form 10-K.
Financial Risk
Our financial risks have not materially changed during the nine months ended September 30, 2020, other than the changes noted due to COVID-19.2021. Refer to the 20192020 Form 10-K. The financial risks included below are required interim disclosures, even if they have not materially changed from December 31, 2019.
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Interest Rate Risk
We use a variety of techniques to manage our interest rate risks. We have an interest rate risk policy and have established a policy to limit our variable rate exposures to a percentage of total capitalization. Additionally, interest rate risk is managed by monitoring market conditions when timing the issuance of long-term debt and optional debt redemptions and establishing fixed rate long-term debt with varying maturities. See "Note 5 of the Notes to Condensed Consolidated Financial Statements" for a summary of our interest rate swap derivatives outstanding as of September 30, 20202021 and December 31, 20192020 and the amount of additional collateral we would have to post in certain circumstances. In addition, see "Regulatory Matters" for a discussion of commitments we made in Oregon surrounding the independent review of our interest rate hedging practices.
Credit Risk
Avista Utilities' contracts for the purchase and sale of energy commodities can require collateral in the form of cash or letters of credit. As of September 30, 2020, we had no cash deposited as collateral and letters of credit of $21.5 million outstanding related to our energy derivative contracts. Price movements and/or a downgrade in our credit ratings could impact further the amount of collateral required. See “Credit Ratings” in the 2019 Form 10-K for further information. For example, in addition to limiting our ability to conduct transactions, if our credit ratings were lowered to below “investment grade” based on our positions outstanding at September 30, 2020 (including contracts that are considered derivatives and those that are considered non-derivatives), we would potentially be required to post the following additional collateral (in thousands):
| | September 30, 2020 | |
Additional collateral taking into account contractual thresholds | | $ | 3,376 | |
Additional collateral without contractual thresholds | | | 3,906 | |
Under the terms of interest rate swap derivatives that we enter into periodically, we may be required to post cash or letters of credit as collateral depending on fluctuations in the fair value of the instrument. A downgrade in our credit ratings could further impact the amount of collateral required. See “Credit Ratings” in the 2020 Form 10-K for further information. As of September 30, 2020,2021, we had interest rate swap derivatives outstanding with a notional amount totaling $175.0$170.0 million and we had no cash deposited as collateral in the amount of $10.1 million and no letters of credit outstanding for these interest rate swap derivatives. If our credit ratings were lowered to below “investment grade” based on our interest rate swap derivatives outstanding at September 30, 2020,2021, we would potentially be required to post the following additional collateral (in thousands):
| | | September 30, 2020 | | | September 30, 2021 | |
Additional collateral taking into account contractual thresholds | | $ | 17,220 | | | $ | 9,040 | |
Additional collateral without contractual thresholds | | | 56,498 | | | | 20,732 | |
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Energy Commodity Risk
Our energy commodity risks have not materially changed during the nine months ended September 30, 2020, except as discussed below and the COVID-19 related risks.2021. See the 20192020 Form 10-K. The following table presents energy commodity derivative fair values as a net asset or (liability) as of September 30, 20202021 that are expected to settle in each respective year (dollars in thousands). There are no expected deliveries of energy commodity derivatives after 2023.2025.
| | Purchases | | | Sales | |
| | Electric Derivatives | | | Gas Derivatives | | | Electric Derivatives | | | Gas Derivatives | |
Year | | Physical (1) | | | Financial (1) | | | Physical (1) | | | Financial (1) | | | Physical (1) | | | Financial (1) | | | Physical (1) | | | Financial (1) | |
Remainder 2020 | | $ | (4 | ) | | $ | 1,468 | | | $ | (610 | ) | | $ | 8,898 | | | $ | (183 | ) | | $ | (3,045 | ) | | $ | (1,281 | ) | | $ | (5,805 | ) |
2021 | | | — | | | | 386 | | | | 332 | | | | 14,204 | | | | — | | | | 277 | | | | (2,280 | ) | | | (10,483 | ) |
2022 | | | — | | | | — | | | | 343 | | | | 3,401 | | | | — | | | | — | | | | — | | | | (884 | ) |
2023 | | | — | | | | — | | | | — | | | | 230 | | | | — | | | | — | | | | — | | | | — | |
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| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Purchases | | | Sales | |
| | Electric Derivatives | | | Gas Derivatives | | | Electric Derivatives | | | Gas Derivatives | |
Year | | Physical (1) | | | Financial (1) | | | Physical (1) | | | Financial (1) | | | Physical (1) | | | Financial (1) | | | Physical (1) | | | Financial (1) | |
Remainder 2021 | | $ | 4 | | | $ | 1,538 | | | $ | 1,932 | | | $ | 13,271 | | | $ | (11 | ) | | $ | (3,299 | ) | | $ | (1,961 | ) | | $ | (16,291 | ) |
2022 | | | (306 | ) | | | — | | | | 1,118 | | | | 18,477 | | | | 624 | | | | (3,104 | ) | | | (4,416 | ) | | | (17,146 | ) |
2023 | | | — | | | | — | | | | — | | | | 4,938 | | | | — | | | | — | | | | (1,789 | ) | | | (1,184 | ) |
2024 | | | — | | | | — | | | | — | | | | 598 | | | | — | | | | — | | | | (1,838 | ) | | | — | |
2025 | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | (1,166 | ) | | | — | |
The following table presents energy commodity derivative fair values as a net asset or (liability) as of December 31, 20192020 that are expected to be delivered in each respective year (dollars in thousands). There are no expected deliveries of energy commodity derivatives after 2022.2025.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Purchases | | | Sales | |
| | Electric Derivatives | | | Gas Derivatives | | | Electric Derivatives | | | Gas Derivatives | |
Year | | Physical (1) | | | Financial (1) | | | Physical (1) | | | Financial (1) | | | Physical (1) | | | Financial (1) | | | Physical (1) | | | Financial (1) | |
2021 | | $ | 2 | | | $ | (414 | ) | | $ | (87 | ) | | $ | 10,549 | | | $ | (15 | ) | | $ | 716 | | | $ | (2,152 | ) | | $ | (10,672 | ) |
2022 | | | — | | | | — | | | | 247 | | | | 1,920 | | | | — | | | | — | | | | (1,697 | ) | | | (1,536 | ) |
2023 | | | — | | | | — | | | | — | | | | (122 | ) | | | — | | | | — | | | | (1,599 | ) | | | (42 | ) |
2024 | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | (1,673 | ) | | | — | |
2025 | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | (1,219 | ) | | | — | |
| | Purchases | | | Sales | |
| | Electric Derivatives | | | Gas Derivatives | | | Electric Derivatives | | | Gas Derivatives | |
Year | | Physical (1) | | | Financial (1) | | | Physical (1) | | | Financial (1) | | | Physical (1) | | | Financial (1) | | | Physical (1) | | | Financial (1) | |
2020 | | $ | 19 | | | $ | 2,063 | | | $ | (895 | ) | | $ | 10,929 | | | $ | (422 | ) | | $ | (7,448 | ) | | $ | (1,634 | ) | | $ | (8,922 | ) |
2021 | | | — | | | | — | | | | 15 | | | | 2,666 | | | | — | | | | (26 | ) | | | (1,187 | ) | | | (1,941 | ) |
2022 | | | — | | | | — | | | | 35 | | | | 180 | | | | — | | | | — | | | | — | | | | (5 | ) |
Physical transactions represent commodity transactions in which we will take or make delivery of either electricity or natural gas; financial transactions represent derivative instruments with delivery of cash in the amount of the benefit or cost but with no physical delivery of the commodity, such as futures, swap derivatives, options, or forward contracts.
(1)
| Physical transactions represent commodity transactions in which we will take or make delivery of either electricity or natural gas; financial transactions represent derivative instruments with delivery of cash in the amount of the benefit or cost but with no physical delivery of the commodity, such as futures, swap derivatives, options, or forward contracts.
|
The above electric and natural gas derivative contracts will be included in either power supply costs or natural gas supply costs during the period they are delivered and will be included in the various deferral and recovery mechanisms (ERM, PCA, and PGAs), or in the general rate case process, and are expected to eventually be collected through retail rates from customers.
Future Resource Needs
2021 Electric Integrated Resource Plan
In April 2021, we filed our 2021 Electric Integrated Resource Plan (IRP) with the WUTC and the IPUC. Then on April 30th, we filed an amended IRP to include the results of the 2020 Renewable RFP. The WUTC and the IPUC review the IRPs and give the public the opportunity to comment. The WUTC and the IPUC do not approve or disapprove of the content in the IRPs; rather they acknowledge the IRPs are prepared in accordance with applicable standards.
Highlights of the 2021 IRP include the following expectations and/or assumptions:
We have adequate resources between owned and contractually controlled generation, when combined with conservation and market purchases, to meet customer demand through October 2026. Our first long-term capacity deficit, net of energy efficiency, begins in October 2026 and is 247 MW by January 2027.
New renewable energy, energy storage, demand response, energy efficiency, and upgrades to existing hydropower and biomass plants are integral to our plan.
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Retail sales and residential use per customer forecasts are slightly higher as compared to the 2020 IRP projections. We anticipate customer load growth of 0.3 percent per year.
Assumes Colstrip will exit the portfolio in view of the Washington CETA requirement to exit the plant by 2025 and as suggested by an economic analysis of the plant compared to alternative resources, although an exit strategy for the plant has not been developed at this time.
New natural gas-fired peaking units are the most economic means to meet the capacity shortfall in 2027 since long-term energy storage is not yet available or as cost effective as initially estimated in the 2020 IRP.
Demand response programs begin in 2025 and grow to 72 MW by 2045.
Our first new renewable resource identified in the IRP is in 2025, as a wind project located in Montana. Actual resource selection will be determined by a future RFP.
The resource strategy moves us closer to achieving our corporate clean electricity goal to provide customers with 100 percent net clean electricity by 2027. Net clean energy is defined as either 100 percent non-carbon emitting resources or investing in or acquiring carbon offsets to net-out emissions created from carbon emitting resources. The addition of natural gas peaking units in 2027 would require us to purchase carbon offsets.
Item 3. Quantitative and Qualitative Disclosures about Market Risk
The information required by this item is set forth in the Enterprise Risk Management section of "Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations" and is incorporated herein by reference.
Item 4. Controls and Procedures
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
The Company has disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended) (Act) that are designed to ensure that information required to be disclosed in the reports it files or submits under the Act is recorded, processed, summarized and reported on a timely basis. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Company in the reports that it files or submits under the Act is accumulated and communicated to the Company’s management, including its principal executive and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure. With the participation of the Company’s principal executive officer and principal financial officer, the Company's management evaluated its disclosure controls and procedures as of the end of the period covered by this report. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon this evaluation, the Company’s principal executive officer and principal financial officer have concluded that the Company’s disclosure controls and procedures are effective at a reasonable assurance level as of September 30, 2020.2021.
There have been no changes in the Company's internal control over financial reporting that occurred during the third quarter of 20202021 that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.
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PART II. Other Information
Item 1. Legal Proceedings
See “Note 16 of Notes to Condensed Consolidated Financial Statements” in “Part I. Financial Information Item 1. Condensed Consolidated Financial Statements.”
Item 1A. Risk Factors
Refer to the 20192020 Form 10-K for disclosure of risk factors that could have a significant impact on our results of operations, financial condition or cash flows and could cause actual results or outcomes to differ materially from those discussed in our reports filed with the SEC (including this Quarterly Report on Form 10-Q), and elsewhere. These risk factors have not materially changed from the disclosures provided in the 20192020 Form 10-K with the exception of the following:
Wildfires ignited, or allegedly ignited, by Avista Corp. equipment or facilities, could cause significant loss of life and property, thereby causing serious operational and financial harm to Avista Corp. and our customers.
Our equipment may be the ignition, or alleged cause of ignition, source for wildfires and in the event of a fire caused by our equipment, we could be held liable for resulting damages to life and property. Also, wildfires could lead to extended operational outages of our equipment while we wait for the wildfire to be extinguished before restoring power, and the cost to implement rapid response or any repair to such facilities could be significant. Any wildfires caused by our equipment could cause significant damage to our reputation, which could erode shareholder, customer and community satisfaction with our Company. In addition, wildfires caused by our equipment could lead to increased insurance costs, loss of insurance coverage, or the need to be self-insured.
The COVID 19 global pandemic is disrupting our business and could have a negative effect on our results of operations, financial condition and cash flows.
The COVID-19 global pandemic is currently impacting all aspects of our business, as well as the global, national and local economy. We cannot predict the full extent to which COVID-19 will impact our operations, results of operations, cash flows, financial condition or capital resources. It is possible that the continued spread of COVID-19 and efforts to contain the virus will continue to cause an economic slowdown, and possibly a recession, resulting in significant disruptions in various public, commercial or industrial activities and causing employee absences which could interfere with operation and maintenance of the Company’s facilities. Any of these circumstances could adversely affect our operations, results of operations, financial condition and cash flows in the followingmany ways, including, but not limited to:
| a decrease in customer demand and revenues due to a reduction in economic activity, an increase in operating expenses, including bad debt expense due to our customers’ inability to pay amounts due to us, an increase in operating expenses and potential workforce disruption or losses resulting from compliance with state or federal vaccine mandates, increased costs and/or reduced revenue associated with interruptions in operations due to federal and state vaccine mandates, including but not limited to employee strikes, protests, retirements or resignations, and additional costs associated with ensuring business continuity, a decrease in net operating cash inflows, which could negatively impact our liquidity and limit our ability to fund capital expenditures, dividends, and other contractual commitments, a negative impact on the ability of suppliers, vendors or contractors to perform, which could increase costs and delay capital projects, possible reluctance on the part of regulatory commissions to approve our requests to defer and recover increased expenses, delays in regulatory filings and the regulatory approval process, which could impact our ability to timely recover our operating expenses and costs associated with investments in utility assets, an increase in cyber and technology risks, including the impact on internal controls, due to a significant number of employees working remotely, disruption, weakness and volatility in the financial markets, which could increase our costs to fund capital requirements, and possible limited access to the capital markets, that could require us to seek alternative sources of funding for operations and for working capital, any of which could increase our cost of capital. •
| A decrease in customer demand and revenues due to a reduction in economic activity and possibly a recession,
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| An increase in operating expenses, including bad debt expense due to our customers’ inability to pay amounts due to us,
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| A negative impact on the ability of suppliers, vendors or contractors to perform, which could increase costs and delay capital projects,
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| Regulatory commissions may not approve our requests to defer and recover increased expenses,
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| Delays in regulatory filings and the regulatory approval process, which could impact our ability to timely recover our operating expenses and costs associated with investments in utility assets,
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| An increase in cyber and technology risks, including the impact on internal controls, due to a significant number of employees working remotely,
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| A decrease in the fair value of pension plan assets or an increase in the pension liability, which could increase future pension plan funding requirements,
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| A decrease in the fair value of non-utility investments, which could result in losses or impairment,
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| A decrease in net operating cash inflows, which could negatively impact our liquidity and limit our ability to fund capital expenditures, dividends, and other contractual commitments,
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| Disruption, weakness and volatility in the financial markets, which could increase our costs to fund capital requirements,
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| To the extent that access to the capital markets is adversely affected, we may need to consider alternative sources of funding for operations and for working capital, any of which could increase our cost of capital.
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We cannot predict the duration and severity of the COVID-19 global pandemic. The longer and more severe the economic restrictions and business disruption is,disruptions are, the greater the impact on our operations, results of operations, financial condition and cash flows will be.
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In addition to these risk factors, see also “Forward-Looking Statements” for additional factors which could have a significant impact on our operations, results of operations, financial condition or cash flows and could cause actual results to differ materially from those anticipated in such statements.
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Item 6. Exhibits
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SIGNATURE
Pursuant to the requirements 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.
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| AVISTA CORPORATION |
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Date: | November 3, 20202, 2021 |
| /s/ Mark T. Thies |
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| Mark T. Thies |
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| Executive Vice President, Chief Financial Officer, and Treasurer (Principal Financial Officer) |
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