ITEM 1A. RISK FACTORS
RISK FACTORS
The following factors could have a significant impact on our operations, results of operations, financial condition or cash flows. These factors could cause future results or outcomes to differ materially from those discussed in our reports filed with the SEC (including this Annual Report on Form 10-K), and elsewhere. Please also see “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.
Utility Regulatory Risk Factors
Regulators may not grant rates that provide timely or sufficient recovery of our costs or allow a reasonable rate of return for our shareholders.
Avista Utilities' annual operating expenses and the costs associated with incremental investments in utility assets continue to grow at a faster rate than revenue. Our ability to recover these expenses and capital costs depends on the adequacy and timeliness of retail rate increases allowed by regulatory agencies, as well as managing inflationary pressures. We expect to periodically file for rate increases with regulatory agencies to recover our expenses and capital costs and provide an opportunity to earn a reasonable rate of return for shareholders. If regulators do not grant rate increases or grant substantially lower rate increases than our requests in the future or if recovery of deferred expenses is disallowed, it could have a negative effect on our financial condition, results of operations or cash flows. See further discussion of regulatory matters in "Item 7. Management's Discussion and Analysis – Regulatory Matters."
In the future, we may no longer meet the criteria for continued application of regulatory accounting principles for all or a portion of our regulated operations.
If we could no longer apply regulatory accounting principles, we could be:
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required to write off our regulatory assets, and be
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precluded from the future deferral of costs or decoupled revenues not recovered through rates at the time such amounts are incurred, even if we are expected to recover these amounts from customers in the future.
See further discussion at "Note 1 of the Notes to Consolidated Financial Statements – Regulatory Deferred Charges and Credits."
Operational Risk Factors
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.
Our equipment may be the ignition source, or alleged cause of ignition, for wildfires and in the event of a fire caused by our equipment, we could potentially be held liable for resulting damages to life and property, as well as fire suppression costs. 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, the need to be self-insured or the need to consider non-traditional insurance coverage or other risk mitigation procedures. Wildfire risks may be exacerbated by increasing temperatures and/or decreasing precipitation due to climate change experienced in the region.
The COVID 19 pandemic is disrupting our business and could have a negative effect on our results of operations, financial condition and cash flows.
The COVID-19 pandemic is currently impacting 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
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capital resources. It is possible that the continued spread of COVID-19 and efforts to contain the virus may result in significant disruptions in various public, commercial or industrial activities, interruption to various supply chains upon which our operations depend, and cause 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 many ways, including, but not limited to:
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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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an increase in operating expenses and potential workforce disruption or losses resulting from compliance with state or federal vaccine mandates,
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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,
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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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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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possible reluctance on the part of regulatory commissions to 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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disruption, weakness and volatility in the financial markets, which could increase our costs to fund capital requirements, and
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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.
We cannot predict the duration and severity of the COVID-19 pandemic. The longer and more severe the business disruptions are, the greater the impact on our operations, results of operations, financial condition and cash flows will be.
We are subject to various operational and event risks.
Our operations are subject to operational and event risks that include:
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severe weather or natural disasters, including, but not limited to, avalanches, wind storms, wildfires, earthquakes, snow and ice storms, and heat waves due to normal weather variations as well as the impacts of climate change which could disrupt energy generation, transmission and distribution, as well as the availability and costs of materials, equipment, supplies, support services and general business operations,
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blackouts or disruptions of interconnected transmission systems (the regional power grid),
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unplanned outages at generating plants,
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changes in the availability and cost of purchased power, fuel and natural gas, including delivery constraints,
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explosions, fires, accidents, or mechanical breakdowns that could occur while operating and maintaining our generation, transmission and distribution systems,
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property damage or injuries to third parties caused by our generation, transmission and distribution systems,
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natural disasters that can disrupt energy generation, transmission and distribution, and general business operations,
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terrorist attacks or other malicious acts that may disrupt or cause damage to our utility assets or the vendors we utilize, and
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general workforce problems, including decreased employee engagement, which may impact strategy execution and negatively affect retention, ability to attract workers, and result in challenges in collective bargaining, possible work stoppages, and strikes. Retention of employees may also be negatively impacted by early retirements, insufficient remote work opportunities, and higher pay offered by national employers. Attractions of employees to support strategies may be affected by higher pay offered from other companies, more liberal remote work opportunities offered by other employers, and other work-life balance benefits afforded by other companies.
Disasters could affect the general economy, financial and capital markets, specific industries or our ability to conduct business. As protection against operational and event risks, we maintain business continuity and disaster recovery plans, maintain insurance coverage against some, but not all, potential losses and we seek to negotiate indemnification arrangements with contractors for certain event risks. However, insurance or indemnification agreements may not be adequate to protect us against liability, extra expenses and operating disruptions from all of the operational and event risks described above. In addition, we are subject to the risk that insurers and/or other parties will dispute or be unable to perform on their obligations to us. If insurance or indemnification agreements are unable to adequately protect us or reimburse us for out-of-pocket costs, it could have a material adverse effect on our results of operations, financial condition and cash flows.
Damage to facilities could be caused by severe weather or natural disasters, such as snow, ice, wind storms, wildfires, earthquakes or avalanches. The cost to implement rapid response or any repair to such facilities can be significant. Overhead electric lines are most susceptible to damage caused by severe weather and are not covered by insurance.
Adverse impacts to AEL&P could result from an extended outage of its hydroelectric generating resources or its inability to deliver energy, due to its lack of interconnectivity to any other electrical grids and the cost of replacement power (diesel).
AEL&P operates several hydroelectric power generation facilities and has diesel generating capacity from multiple facilities to provide backup service to firm customers when necessary; however, a single hydroelectric power generation facility, the Snettisham hydroelectric project, provides approximately two-thirds of AEL&P’s hydroelectric power generation. Any issues that negatively affect AEL&P's ability to generate or transmit power or any decrease in the demand for the power generated by AEL&P could negatively affect our results of operations, financial condition and cash flows.
Climate Change Risk Factors
A trend of increasing average temperatures and its effects could cause significant direct and indirect impacts on Avista’s operations and results of operations.
Climate change may exacerbate existing risks related to weather and weather-related events. Potential direct effects of climate change include changes in the timing and magnitude of snowpack and streamflow, impacting hydro generation; timing and magnitude of changes in electric and gas load; increased weather-related stress on, or damage to, energy infrastructure; increased frequency and intensity of extreme weather events that may impact energy generation and delivery.
Indirect impacts associated with climate change may include increased costs to generate electricity or secure natural gas and deliver energy to customers; impacts to the timing or amount of operating revenues; increased costs to maintain or construct energy infrastructure in adaptation to a changing climate; increased costs or inability to obtain insurance coverage; and regional impacts to the economy or financial conditions of our customers. Indirect impacts also include risks associated with new and emerging laws and regulations, which could have a material adverse impact on our business and results of operations. See further discussion at “Item 7. Management's Discussion and Analysis – Environmental Issues and Contingencies".
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Cyber and Technology Risk Factors
Cyberattacks, ransomware, terrorism or other malicious acts could disrupt our businesses and have a negative impact on our results of operations and cash flows.
In the course of our operations, we rely on interconnected technology systems for operation of our generating plants, electric transmission and distribution systems, natural gas distribution systems, customer billing and customer service, accounting and other administrative processes and compliance with various regulations. In addition, in the ordinary course of business, we collect and retain sensitive information including personal information about our customers and employees.
Cyberattacks, ransomware, terrorism or other malicious acts could damage, destroy or disrupt these systems for an extended period of time. The energy sector, particularly electric and natural gas utility companies have become the subject of cyberattacks with increased frequency. Our administrative and operating networks are targeted by hackers on a regular basis. Additionally, the facilities and systems of clients, suppliers and third party service providers could be vulnerable to the same cyber or terrorism risks as our facilities and systems and such third party systems may be interconnected to our systems both physically and technologically. Therefore, an event caused by cyberattacks, ransomware or other malicious act at an interconnected third party could impact our business and facilities similarly. Any failure, unexpected, or unauthorized use of technology systems could result in the unavailability of such systems, and could result in a loss of operating revenues, an increase in operating expenses and costs to repair or replace damaged assets. Any of the above could also result in the loss or release of confidential customer and/or employee information or other proprietary data that could adversely affect our reputation and competitiveness, could result in costly litigation and negatively impact our results of operations. These cyberattacks have become more common and sophisticated and, as such, we could be required to incur costs to strengthen our systems and respond to emerging concerns.
Terrorist attacks could also be directed at our physical electric and natural gas facilities, as well as technology systems or at an interconnected third party, which could result in disruption to our systems.
There are various risks associated with technology systems such as hardware or software failure, communications failure, data distortion or destruction, unauthorized access to data, misuse of proprietary or confidential data, unauthorized control through electronic means, programming mistakes and other deliberate or inadvertent human errors.
Our technology may become obsolete or we may not have sufficient resources to manage our technology.
Our technology may become obsolete before the end of its useful life. In addition, custom technology that is heavily relied upon by us may not be maintained and updated appropriately due to resource restraints, or other factors, which could cause technology failures or give rise to additional operational or security risks. Technology failures could result in significant adverse effects on our operations, results of operations, financial condition and cash flows.
We may be adversely affected by our inability to successfully implement certain technology projects.
There are inherent risks associated with replacing and changing systems, which could have a material adverse effect on our results of operations, financial condition and cash flows. Finally, there is the risk that we ultimately do not complete a project and will incur contract cancellation or other costs, which could be significant.
Strategic Risk Factors
Our strategic business plans, which may be affected by any or all of the foregoing, may change, including the entry into new businesses and/or the exit from existing businesses and/or the curtailment of our business development efforts where potential future business is uncertain.
Our strategic business plans could be affected by or result in any of the following:
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disruptive innovations in the marketplace may outpace our ability to compete or manage our risk,
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customers may have a choice in the future over the sources from which to receive their energy and we may not be able to compete,
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potential difficulties in integrating acquired operations and in realizing expected opportunities, diversions of management resources and losses of key employees, challenges with respect to operating new businesses and other unanticipated risks and liabilities,
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non-regulated investments may increase earnings volatility,
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market or other conditions that could adversely affect our operations or require changes to our business strategy and could result in reduced assets and net income,
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potential reputational risk arising from repeated general rate case filings, degradation in the quality of service, or from failed strategic investments and opportunities, which could erode shareholder, customer and community satisfaction with the Company, and
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the risk of municipalization or other form of service territory reduction.
External Mandates Risk Factors
External mandate risk involves forces outside the Company, which may include significant changes in customer expectations, disruptive technologies that result in obsolescence of our business model and government action that could impact the Company.
Actions or limitations to address concerns over long-term climate change, both globally and within our utilities' service areas, may affect our operations and financial performance.
Legislative, regulatory and advocacy efforts at the local, state, national and international levels concerning climate change and other environmental issues could have significant impacts on our operations. The electric and natural gas utility industries are frequently affected by proposals to curb greenhouse gas and other air emissions. Various regulatory and legislative proposals have been made to limit or further restrict byproducts of combustion, including that resulting from the use of natural gas by our customers. In addition, regionally, there are a number of regulatory and legislative initiatives that have been passed which are designed to limit greenhouse gas emissions and increase the use of renewable sources of energy. Such legislation could restrict the operation and raise the costs of our power generation resources as well as the distribution of natural gas to our customers.
We expect continuing activity in the future and we are evaluating the extent to which potential changes to environmental laws and regulations may:
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increase the operating costs of generating plants,
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increase the lead time and capital costs for the construction of new generating plants,
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require modification of our existing generating plants,
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require existing generating plant operations to be curtailed or shut down,
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reduce the amount of energy available from our generating plants,
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restrict the types of generating plants that can be built or contracted with,
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require construction of specific types of generation plants at higher cost, and
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increase the cost or limit our ability to distribute natural gas to customers.
See “Item 7. Management's Discussion and Analysis – Environmental Issues and Contingencies" for discussion regarding environmental and other issues which may affect our operations, including legislation that was recently passed in Washington State.
We have contingent liabilities, including certain matters related to potential environmental liabilities, and cannot predict the outcome of these matters.
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In the normal course of our business, we have matters that are the subject of ongoing litigation, mediation, investigation and/or negotiation. We cannot predict the ultimate outcome or potential impact of any particular issue, including the extent, if any, of insurance coverage or that amounts payable by us may be recoverable through the ratemaking process. We are subject to environmental regulation by federal, state and local authorities related to our past, present and future operations. See “Note 22 of the Notes to Consolidated Financial Statements” for further details of these matters.
Import tariffs could lead to increased prices on raw materials that are critical to our business.
Tariffs and other restrictions on trade with foreign countries could significantly increase the prices of raw materials that are critical to our business, such as steel poles or wires. In addition, tariffs and trade restrictions could have a similar impact on our suppliers and certain customers, which could have a negative impact on our financial condition, results of operations and cash flows.
See "Item 7. Management's Discussion and Analysis – Environmental Issues and Contingencies" and "Forward-Looking Statements" for discussion of or reference to additional external mandates which could have a material adverse effect on our results of operations, financial condition and cash flows.
Financial Risk Factors
Weather (temperatures, precipitation levels, wind patterns and storms) has a significant effect on our results of operations, financial condition and cash flows. These effects could increase as climate changes occur.
Weather impacts are described in the following subtopics:
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certain retail electricity and natural gas sales,
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the cost of natural gas supply, and
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the cost of power supply.
Certain retail electricity and natural gas sales volumes vary directly with changes in temperatures. We normally have our highest retail (electric and natural gas) energy sales during the winter heating season in the first and fourth quarters of the year. We also have high electricity demand for air conditioning during the summer (third quarter). In general, warmer weather in the heating season and cooler weather in the cooling season will reduce our customers’ energy demand and our retail operating revenues. The revenue and earnings impact of weather fluctuations is somewhat mitigated by our decoupling mechanisms; however, we could experience liquidity constraints during the period between when decoupling revenue is earned and when it is subsequently collected from customers through retail rates.
The cost of natural gas supply is impacted by both supply-side factors (amount of natural gas production, level of natural gas in storage, volumes of natural gas imports and exports, regulatory restraints or costs on natural gas production and delivery) and demand-side factors (variations in winter and summer weather, level of economic growth, availability and prices of other fuels). Prices tend to increase with higher demand during periods of cold weather. Inter-regional natural gas pipelines and competition for supply can allow demand-driven price volatility in other regions of North America to affect prices in the Pacific Northwest. Increased costs adversely affect cash flows when we purchase natural gas for retail supply at prices above the amount allowed for recovery in retail rates. We defer differences between actual natural gas supply costs and the amount currently recovered in retail rates and we are generally allowed to recover substantially all of these differences after regulatory review. However, these deferred costs require cash outflows from the time of natural gas purchases until the costs are later recovered through retail sales.
The cost of power supply can be significantly affected by weather, and therefore is subject to trends in climate change. Precipitation (consisting of snowpack, its water content and runoff pattern plus rainfall) and other streamflow conditions (such as regional water storage operations) significantly affect hydroelectric generation capability. Variations in hydroelectric generation inversely affect our reliance on market purchases and thermal generation. To the extent that hydroelectric generation is less than normal, significantly more costly power supply resources must be acquired and the ability to realize net benefits
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from surplus hydroelectric wholesale sales is reduced. Wholesale prices also vary based on wind patterns as wind generation capacity is material in the Pacific Northwest but its contribution to supply is inconsistent.
The price of power in the wholesale energy markets tends to be higher during periods of high regional demand, such as occurs with temperature extremes. Climate change may increase the frequency and magnitude of temperature extremes. We may need to purchase power in the wholesale market during peak price periods. The price of natural gas as fuel for natural gas-fired electric generation also tends to increase during periods of high demand which are often related to temperature extremes. We may need to purchase natural gas fuel in these periods of high prices to meet electric demands. The cost of power supply during peak usage periods may be higher than the retail sales price or the amount allowed in retail rates by our regulators. To the extent that power supply costs are above the amount allowed currently in retail rates, the difference is partially absorbed by the Company in current expense and is partially deferred or shared with customers through regulatory mechanisms.
The price of power tends to be lower during periods with excess supply, such as the spring when hydroelectric conditions are usually at their maximum and various facilities are required to operate to meet environmental mandates. Oversupply can be exacerbated when intermittent resources such as wind generation are producing output that may be supported by price subsidies. In extreme situations, we may be required to sell excess energy at negative prices.
As a result of these combined factors, our net cost of power supply – the difference between our costs of generation and market purchases, reduced by our revenue from wholesale sales – varies significantly because of weather.
We rely on regular access to financial markets but we cannot assure favorable or reasonable financing terms will be available when we need them.
Access to capital markets is critical to our operations and our capital structure. We have significant capital requirements that we expect to fund, in part, by accessing capital markets. As such, the state of financial markets and credit availability in the global, United States and regional economies impacts our financial condition. We could experience increased borrowing costs or limited access to capital on reasonable terms.
We access long-term capital markets to finance capital expenditures, repay maturing long-term debt and obtain additional working capital from time-to-time. Our ability to access capital on reasonable terms is subject to numerous factors and market conditions, many of which are beyond our control. If we are unable to obtain capital on reasonable terms, it may limit or prohibit our ability to finance capital expenditures and repay maturing long-term debt. Our liquidity needs could exceed our short-term credit availability and lead to defaults on various financing arrangements. We would also likely be prohibited from paying dividends on our common stock.
Performance of the financial markets could also result in significant declines in the market values of assets held by our pension plan and/or a significant increase in the pension liability (which impacts the funded status of the plan) and could increase future funding obligations and pension expense.
We rely on credit from financial institutions for short-term borrowings. We need adequate levels of credit with financial institutions for short-term liquidity. There is no assurance that we will have access to credit beyond the expiration dates of our committed line of credit agreements. These agreements contain customary covenants and default provisions.
Any default on the lines of credit or other financing arrangements of Avista Corp. or any of our “significant subsidiaries,” if any, could result in cross-defaults to other agreements of such entity, and/or to the line of credit or other financing arrangements of any other of such entities. Any defaults could also induce vendors and other counterparties to demand collateral. In the event of any such default, it would be difficult for us to obtain financing on reasonable terms to pay creditors or fund operations. We would also likely be prohibited from paying dividends on our common stock.
We hedge a portion of our interest rate risk with financial derivative instruments. If market interest rates decrease below the interest rates we have locked in, this will result in a liability related to our interest rate swap derivatives, which can be significant. We may be required to post cash or letters of credit as collateral depending on fluctuations in the fair value of the
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derivative instruments. Settlement of interest rate swap derivative instruments in a liability position could require a significant amount of cash, which could negatively impact our liquidity and short-term credit availability and increase interest expense over the term of the associated debt.
Downgrades in our credit ratings could impede our ability to obtain financing, adversely affect the terms of financing and impact our ability to transact for or hedge energy resources. If we do not maintain our investment grade credit rating with the major credit rating agencies, we could expect increased debt service costs, limitations on our ability to access capital markets or obtain other financing on reasonable terms, and requirements to provide collateral (in the form of cash or letters of credit) to lenders and counterparties. In addition, credit rating downgrades could reduce the number of counterparties willing to do business with us or result in the termination of outstanding regulatory authorizations for certain financing activities.
Credit risk may be affected by industry concentration and geographic concentration.
We have concentrations of suppliers and customers in the electric and natural gas industries including:
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electric and natural gas utilities,
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electric generators and transmission providers,
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oil and natural gas producers and pipelines,
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financial institutions including commodity clearing exchanges and related parties, and
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energy marketing and trading companies.
We have concentrations of credit risk related to our geographic location in the western United States and western Canada energy markets. These concentrations of counterparties and concentrations of geographic location may affect our overall exposure to credit risk because the counterparties may be similarly affected by changes in conditions.
Energy Commodity Risk Factors
Energy commodity price changes affect our cash flows and results of operations.
Energy commodity pricescan be volatile. We rely on energy markets and other counterparties for energy supply, surplus and optimization transactions and commodity price hedging. A combination of factors exposes our operations to commodity price risks, including:
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our obligation to serve our retail customers at rates set through the regulatory process - we cannot decline to serve our customers and we cannot change retail rates to reflect current energy prices unless and until we receive regulatory approval,
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customer demand, which is beyond our control because of weather, customer choices, prevailing economic conditions and other factors,
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some of our energy supply cost is fixed by the nature of the energy-producing assets or through contractual arrangements (however, a significant portion of our energy resource costs are not fixed), and
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the potential non-performance by commodity counterparties, which could lead to replacement of the scheduled energy or natural gas at higher prices.
Because we must supply the amount of energy demanded by our customers and we must sell it at fixed rates and only a portion of our energy supply costs are fixed, we are subject to the risk of buying energy at higher prices in wholesale energy markets (and the risk of selling energy at lower prices if we are in a surplus position). Electricity and natural gas in wholesale markets are commodities with historically high price volatility. Changes in wholesale energy prices affect, among other things, the cash requirements to purchase electricity and natural gas for retail customers or wholesale obligations and the market value of derivative assets and liabilities.
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When we enter into fixed price energy commodity transactions for future delivery, we are subject to credit terms that may require us to provide collateral to wholesale counterparties related to the difference between current prices and the agreed upon fixed prices. These collateral requirements can place significant demands on our cash flows or borrowing arrangements. Price volatility can cause collateral requirements to change quickly and significantly.
Cash flow deferrals related to energy commodities can be significant. We are permitted to collect from customers only amounts approved by regulatory commissions. However, our costs to provide energy service can be much higher or lower than the amounts currently billed to customers. We are permitted to defer income statement recognition and recovery from customers for some of these differences, which are recorded as deferred charges with the opportunity for future recovery through retail rates. These deferred costs are subject to review for prudence and potential disallowance by regulators, who have discretion as to the extent and timing of future recovery or refund to customers.
Power and natural gas costs higher than those recovered in retail rates negatively impact cash flows. Amounts that are not allowed for deferral or which are not approved to become part of customer rates affect our results of operations.
Even if our regulators ultimately allow us to recover deferred power and natural gas costs, our operating cash flows can be negatively affected until these costs are recovered from customers.
Fluctuating energy commodity prices and volumes in relation to our energy risk management process can cause volatility in our cash flows and results of operations. We engage in active hedging and resource optimization practices to reduce energy cost volatility and economic exposure related to commodity price fluctuations. We routinely enter into contracts to hedge a portion of our purchase and sale commitments for electricity and natural gas, as well as forecasted excess or deficit energy positions and inventories of natural gas. We use physical energy contracts and derivative instruments, such as forwards, futures, swaps and options traded in the over-the-counter markets or on exchanges. If market prices decrease compared to the prices we have locked in with our energy commodity derivatives, this will result in a liability related to these derivatives, which can be significant. As a result of price fluctuations, we may be required to post significant amounts of cash or letters of credit as collateral depending on fluctuations in the fair value of the derivative instruments.
We do not attempt to fully hedge our energy resource assets or our forecasted net positions for various time horizons. To the extent we have positions that are not hedged, or if hedging positions do not fully match the corresponding purchase or sale, fluctuating commodity prices could have a material effect on our operating revenues, resource costs, derivative assets and liabilities, and operating cash flows. In addition, actual loads and resources typically vary from forecasts, sometimes to a significant degree, which require additional transactions or dispatch decisions that impact cash flows.
The hedges we enter into are reviewed for prudence by our various regulators and any deferred costs (including those as a result of our hedging transactions) are subject to review for prudence and potential disallowance by regulators.
Generation plants may become obsolete. We rely on a variety of generation and energy commodity market sources to fulfill our obligation to serve customers and meet the demands of our counterparty agreements. Some of our generation sources, such as coal, may become obsolete or be prematurely retired through regulatory action or legislation. This could result in higher commodity costs to replace the lost generation, as well as higher costs to retire the generation source before the end of its expected life. See “Item 7. Management's Discussion and Analysis – Environmental Issues and Contingencies" for discussion regarding environmental and other issues surrounding Colstrip, including the requirement that we cannot serve Washington electricity customers after 2025 with Colstrip.
Compliance Risk Factors
There have been numerous changes in legislation, related administrative rulemakings, and Executive Orders, including periodic audits of compliance with such rules, which may adversely affect our operational and financial performance.
We expect to continue to be affected by legislation at the national, state and local level, as well as by administrative rules and requirements published by government agencies, including but not limited to the FERC, the EPA and state regulators. We are
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also subject to NERC and WECC reliability standards. The FERC, the NERC and the WECC perform periodic audits of the Company. Failure to comply with the FERC, the NERC, or the WECC requirements can result in financial penalties.
Future legislation, administrative rules or Executive Orders could have a material adverse effect on our operations, results of operations, financial condition and cash flows.
ITEM 1B. UNRESOLVED STAFF COMMENTS
As of the filing date of this Annual Report on Form 10-K, we have no unresolved comments from the staff of the SEC.
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ITEM 2. PROPERTIES
AVISTA UTILITIES
Substantially all of Avista Utilities' properties are subject to the lien of Avista Corp.'s mortgage indenture.
Avista Utilities' electric properties, located in the states of Washington, Idaho, Montana and Oregon, include the following:
Generation Properties
No. ofUnits NameplateRating(MW) (1) PresentCapability(MW) (2)
Hydroelectric Generating Stations (River)
Washington:
Idaho:
Montana:
Thermal Generating Stations (cycle, fuel source)
Washington:
Kettle Falls GS (combined-cycle, wood waste) (4) 1 50.7 53.5
Kettle Falls CT (combined-cycle, natural gas) (4) 1 7.2 6.9
Northeast CT (simple-cycle, natural gas) 2 61.8 64.8
Boulder Park GS (simple-cycle, natural gas) 6 24.6 24.6
Idaho:
Rathdrum CT (simple-cycle, natural gas) 2 166.5 166.5
Montana:
Oregon:
Coyote Springs 2 (combined-cycle, natural gas) 1 295.0 295.0
(1)
Nameplate rating, also referred to as “installed capacity,” is the manufacturer’s assigned power capability under specified conditions.
(2)
Present capability is the maximum capacity of the plant under standard test conditions without exceeding specified limits of temperature, stress and environmental conditions. Information is provided as of December 31, 2021.
(3)
For Cabinet Gorge, we have water rights permitting generation up to 265 MW. However, if natural stream flows will allow for generation above our water rights, we are able to generate above our water rights. If natural stream flows only allow for generation at or below 265 MW, we are limited to generation of 265 MW. The present capability disclosed above represents the capability based on maximum stream flow conditions when we are allowed to generate above our water rights.
(4)
These generating stations can operate as separate single-cycle plants or combined-cycle with the natural gas plant providing exhaust heat to the wood boiler to increase efficiency.
(5)
Jointly owned; data refers to our 15 percent interest. See “Item 7. Management’s Discussion and Analysis of Financial Condition – Colstrip” for information related to Colstrip Units 3 & 4.
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Electric Distribution and Transmission Plant
Avista Utilities owns and operates approximately 19,300 miles of primary and secondary electric distribution lines providing service to retail customers. We have an electric transmission system of approximately 700 miles of 230 kV line and approximately 1,600 miles of 115 kV line. We also own an 11 percent interest in approximately 500 miles of a 500 kV line between Colstrip, Montana and Townsend, Montana. Our transmission and distribution systems also include numerous substations with transformers, switches, monitoring and metering devices and other equipment.
The 230 kV lines are the backbone of our transmission grid and are used to transmit power from generation resources, including Noxon Rapids, Cabinet Gorge and the Mid-Columbia hydroelectric projects, to the major load centers in our service area, as well as to transfer power between points of interconnection with adjoining electric transmission systems. These lines interconnect at various locations with the BPA, Grant County PUD, PacifiCorp, NorthWestern Energy and Idaho Power Company and serve as points of delivery for power from generating facilities outside of our service area, including Colstrip, Coyote Springs 2 and the Lancaster Plant.
These lines also provide a means for us to optimize resources by entering into short-term purchases and sales of power with entities within and outside of the Pacific Northwest.
The 115 kV lines provide for transmission of energy and the integration of smaller generation facilities with our service-area load centers, including the Spokane River hydroelectric projects, the Kettle Falls projects, Rathdrum CT, Boulder Park GS and the Northeast CT. These lines interconnect with the BPA, Chelan County PUD, the Grand Coulee Project Hydroelectric Authority, Grant County PUD, NorthWestern Energy, PacifiCorp and Pend Oreille County PUD. Both the 115 kV and 230 kV interconnections with the BPA are used to transfer energy to facilitate service to each other’s customers that are connected through the other’s transmission system. We hold a long-term transmission agreement with the BPA that allows us to serve our native load customers that are connected through the BPA’s transmission system.
Natural Gas Plant
Avista Utilities has natural gas distribution mains of approximately 3,500 miles in Washington, 2,100 miles in Idaho and 2,400 miles in Oregon. We have natural gas transmission mains of approximately 75 miles in Washington and 15 miles in Oregon. Our natural gas system includes numerous regulator stations, service distribution lines, monitoring and metering devices, and other equipment.
We own a one-third interest in Jackson Prairie, an underground natural gas storage field located near Chehalis, Washington. See "Part 1 – Item 1. Business – Avista Utilities – Natural Gas Operations" for further discussion of Jackson Prairie.
ALASKA ELECTRIC LIGHT AND POWER COMPANY
Substantially all of AEL&P's utility properties are subject to the lien of the AEL&P mortgage indenture.
AEL&P's utility electric properties, located in Alaska include the following:
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Generation Properties and Transmission and Distribution Lines
No. ofUnits NameplateRating(MW) (1) PresentCapability(MW) (2)
Hydroelectric Generating Stations
Diesel Generating Stations
(1)
Nameplate rating, also referred to as “installed capacity,” is the manufacturer’s assigned power capability under specified conditions.
(2)
Present capability is the maximum capacity of the plant under standard test conditions without exceeding specified limits of temperature, stress and environmental conditions. Information is provided as of December 31, 2021.
(3)
AEL&P does not own this generating facility but has a PPA under which it has the right to purchase, and the obligation to pay for (whether or not energy is received), all of the capacity and energy of this facility. See further information at "Part 1. Item 1. Business – Alaska Electric Light and Power Company."
In addition to the generation properties above, AEL&P owns 61 miles of transmission lines, which are primarily comprised of 69 kV line, and 184 miles of distribution lines.
ITEM 3. LEGAL PROCEEDINGS
See “Note 22 of Notes to Consolidated Financial Statements” for information with respect to legal proceedings.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
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PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Avista Corp. Market Information and Dividend Policy
Avista Corp.'s common stock is listed on the New York Stock Exchange under the ticker symbol “AVA.” As of January 31, 2022, there were 6,574 registered shareholders of our common stock.
Avista Corp.'s Board of Directors considers the level of dividends on our common stock on a recurring basis, taking into account numerous factors including, without limitation:
•
our results of operations, cash flows and financial condition,
•
the success of our business strategies, and
•
general economic and competitive conditions.
Avista Corp.'s net income available for dividends is generally derived from our regulated utility operations (Avista Utilities and AEL&P).
The payment of dividends on common stock could be limited by:
•
certain covenants applicable to preferred stock (when outstanding) contained in the Company’s Restated Articles of Incorporation, as amended (currently there are no preferred shares outstanding),
•
certain covenants applicable to the Company's outstanding long-term debt and committed line of credit agreements (see "Item 7. Management's Discussion and Analysis - Capital Resources" for compliance with these covenants),
•
the hydroelectric licensing requirements of section 10(d) of the FPA (see “Note 1 of Notes to Consolidated Financial Statements”), and
•
certain requirements under the OPUC approval of the AERC acquisition in 2014. The OPUC's AERC acquisition order requires Avista Utilities to maintain a capital structure of no less than 35 percent common equity (inclusive of short-term debt). This limitation may be revised upon request by the Company with approval from the OPUC.
For additional information, see “Notes 1 and 19 of Notes to Consolidated Financial Statements.”
For information with respect to securities authorized for issuance under equity compensation plans, see “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.”
ITEM 6. [REMOVED AND RESERVED]
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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
This section of this Annual Report on Form 10-K generally discusses 2021 and 2020 financial statement items and year-to-year comparisons between 2021 and 2020. Discussion of 2019 financial statement items and year-to-year comparisons between 2020 and 2019 that are not included in this Form 10-K can be found in "Management's Discussion and Analysis of Financial Conditions and Results of Operations" in Part II, Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2020.
Business Segments
As of December 31, 2021, we have two reportable business segments, Avista Utilities and AEL&P. We also have other businesses which do not represent a reportable business segment and are conducted by various direct and indirect subsidiaries of Avista Corp. See "Part I, Item 1. Business – Company Overview" for further discussion of our business segments.
The following table presents net income (loss) attributable to Avista Corp. shareholders for each of our business segments (and the other businesses) for the year ended December 31 (dollars in thousands):
Executive Level Summary
Overall Results
Net income attributable to Avista Corp. shareholders was $147.3 million for 2021, an increase from $129.5 million for 2020.
Avista Utilities' net income increased primarily due to general rate cases, including the impact of the timing of recognition of income taxes, and non-decoupled revenue growth and customer growth. These increases were partially offset by higher power supply costs, increased other operating expenses, and increased depreciation due to plant additions during the year. In addition, 2020 included an accrual for customer refunds related to the outcome of our 2015 Washington General rate case, an accrual for disallowed replacement power during an unplanned outage at Colstrip and a contribution to the Colstrip community fund, all of which decreased net income in 2020.
AEL&P net income decreased slightly, primarily due to higher other operating costs compared to 2020.
The increase in net income at our other businesses was primarily due to increased net investment gains in 2021.
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).
Summer 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 these times 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
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authorized resource costs due to higher volumes of energy and fuel purchased and higher market prices of each. In 2021, we recognized a pre-tax expense of $7.7 million under the ERM, compared to $6.2 million of pre-tax benefit recognized in 2020.
These hot conditions had minimal impact on reported revenues, as the majority of the increase in revenues associated with the increased usage was offset with adjustments under the decoupling mechanisms that cover a majority of our customers.
COVID-19 Pandemic
The COVID-19 pandemic is impacting our business, as well as the global, national and local economies. However, through 2021 the economies in our service territory have opened, and the impacts of the pandemic have been less severe than 2020. The pandemic has affected and may continue to affect our operations, results of operations, financial condition, liquidity and cash flows in the following ways:
Operations
We continue 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. 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.
It is possible that COVID-19 could have a negative impact on the ability of suppliers or contractors to perform, which could increase operating costs and delay and/or increase the costs of capital projects.
Results of Operations
We observed economic recovery and improvement in employment during 2021. We received accounting orders 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. COVID-19 deferred regulatory assets and liabilities as of December 31, 2021 and December 31, 2020 were as follows:
December 31, December 31,
Financial Condition, Liquidity and Cash Flows
After considering the impacts of COVID-19, and the planned issuances of long-term debt and equity during 2022, 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.
We cannot predict the duration and severity of the COVID-19 pandemic or if emerging variants will result in the reimplementation of economic restrictions. The longer and more severe the economic restrictions and business disruption, the greater the impact on our operations, results of operations, financial condition and cash flows.
General Rate Cases and Regulatory Lag
We experienced regulatory lag during 2021 and we expect this to continue through the end of 2022 due to our continued investment in utility infrastructure. In 2021, we concluded general rates cases in each of our jurisdictions. The settlement of these cases provided rate relief in 2021. Going forward, we will continue to strive to reduce the regulatory timing lag and more closely align our earned returns with those authorized by 2023. This will require adequate and timely rate relief in all our jurisdictions. We have filed multi-year electric and natural gas general rate cases in Washington in January 2022. See "Regulatory Matters" for additional discussion of the general rate cases.
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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 will 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.
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.
Avista Utilities
Washington General Rate Cases and Other Proceedings
2019 General Rate Cases
In March 2020, we received an order from the WUTC that approved a partial multi-party settlement. The approved rates were 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 incorporate a 9.4 percent return on equity (ROE) with a common equity ratio of 48.5 percent and a rate of return (ROR) on rate base 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.
Included in the WUTC order is the acceleration of depreciation of Colstrip Units 3 & 4 to reflect a remaining useful life through December 31, 2025. The order utilized certain electric tax benefits associated with the 2018 tax reform to partially offset these increased costs. The order also set 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. See “Colstrip” section for further information on on-going issues and disputes regarding the eventual closure of Colstrip.
Lastly, the order included 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 will not be decoupled until included in a future test period.
2020 General Rate Cases
In September 2021, we received an order from the WUTC that approved a partial multi-party settlement and resolved all remaining issues for the electric and natural gas general rate cases with the WUTC. 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 1, 2021. The revenue increases incorporate 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.
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 during 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
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In January 2022, we filed multi-year electric and natural gas general rate cases with the WUTC. The proposed rates are designed to increase annual base electric revenues by $52.9 million (or 9.6 percent of base revenues), effective in December 2022, and $17.1 million (or 2.8 percent of base revenues), effective in December 2023. For natural gas, the proposed rates are designed to increase annual base natural gas revenues by $10.9 million (or 9.5 percent of base revenues), effective in December 2022, and $2.2 million (or 1.7 percent of base revenues), effective in December 2023.
We are proposing to offset part of the base rate request with a Residual Tax Customer Credit that arose out of the Company’s Washington electric and natural gas general rate cases that went into effect on October 1, 2021. The order for those general rate cases stipulated that the residual tax customer credit was to be flowed through to customers over a 10-year period beginning in 2023; however, we are now proposing that this credit be incrementally flowed through to customers over a two-year period. The estimated benefits to customers of this credit would be $25.5 million for electric customers and $12.5 million for natural gas customers over a two-year period from December 2022 to December 2024.
The proposed electric and natural gas revenue increase requests are based on a 10.25 percent ROE with a common equity ratio of 48.5 percent and a rate of ROR base of 7.3 percent. Increasing fixed expenses and ongoing capital investments (including replacement of wood poles and natural gas distribution pipe, continued investment in the wildfire resiliency plan, and technology) were the main drivers of proposed increases. As a part of the multi-year rate plan, if approved, we would not file a new general rate case for a new rate plan to be effective prior to December 2024. The WUTC has up to eleven months to review the general rate case filings and issue a decision.
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 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 and Other Proceedings
2021 General Rate Cases
In January 2021, we filed electric and natural gas general rate cases with the IPUC.
In September 2021, the IPUC approved the all party settlement agreement. The approved rates under the settlement agreement are designed to increase annual base electric revenues by $10.6 million, or 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 decrease 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 tax customer credits, related to flow through of certain tax items, included in our original filing to offset overall proposed changes to electric and natural gas rates over the two-year plan.
The settlement incorporates 9.4 percent ROE with a common equity ratio of 50 percent and a ROR of 7.05 percent.
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2023 General Rate Cases
We expect to file electric and natural gas general rate cases with IPUC in the first half of 2023.
Oregon General Rate Cases and Other Proceedings
2020 General Rate Case
In March 2020, we filed a natural gas general rate case with the OPUC. Through several settlement stipulations the parties resolved all issues and, in December 2020, the OPUC approved all stipulations.
The new rates were designed to increase annual base revenue by $3.9 million, or 5.7 percent effective January 16, 2021, reflecting an ROE of 9.4 percent, with a common equity ratio of 50 percent and a ROR of 7.24 percent.
2021 General Rate Case
In October 2021, we filed a natural gas general rate case with the OPUC. The proposal is designed to increase overall natural gas base revenue by $3.8 million and is based on a proposed ROR of 7.35 percent with a common equity ratio of 50 percent and a 9.9 percent ROE. 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 same amount.
In January 2022, a partial settlement stipulation was filed with the OPUC that addressed cost of capital issues. The parties agreed to an overall ROR of 7.05 percent based on a 50 percent common equity ratio and ROE of 9.4 percent.
Alaska Electric Light and Power Company
AEL&P is required to file its next general rate case 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 actual and projected natural gas costs included in base retail rates for supply that is not hedged. Total net deferred natural gas costs among all jurisdictions were a net asset of $21.0 million as of December 31, 2021 and $1.4 million as of December 31, 2020. These deferred natural gas cost balances represent amounts due from customers.
The following PGAs went into effect in our various jurisdictions during 2019 through 2022:
Jurisdiction PGA Effective Date PercentageIncrease/ (Decrease) inBilledRates
Power Cost Deferrals and Recovery Mechanisms
Deferred power supply costs are recorded as a deferred charge or liability on the Consolidated Balance Sheets for future prudence review and recovery or rebate through retail rates. The power supply costs deferred include certain differences
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between actual net power supply costs incurred by Avista Utilities and the costs included in base retail rates. These differences primarily result from changes in:
•
short-term wholesale market prices and sales and purchase volumes,
•
the level, availability and optimization of hydroelectric generation,
•
the level, availability and optimization of thermal generation (including changes in fuel prices),
•
retail loads, and
•
sales of surplus transmission capacity.
For our Washington customers, 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. Total net deferred power costs under the ERM were liabilities of $11.9 million as of December 31, 2021 and $37.9 million as of December 31, 2020. These deferred power cost balances represent amounts due to customers.
Under the ERM, Avista Utilities absorbs the cost or receives the benefit from the initial amount of power supply costs in excess of or below the level in retail rates, which is referred to as the deadband. The annual (calendar year) deadband amount is $4.0 million.
The following is a summary of the ERM:
within +/- $0 to $4 million (deadband) 0% 100%
higher by $4 million to $10 million 50% 50%
lower by $4 million to $10 million 75% 25%
higher or lower by over $10 million 90% 10%
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.
Pursuant to WUTC requirements, should the cumulative deferral balance exceed $30 million (in either 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 as of December 31, 2019 exceeded $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 an asset of $10.8 million as of December 31, 2021 and $2.5 million as of December 31, 2020. These deferred power cost balances represent amounts due from customers.
Decoupling and Earnings Sharing Mechanisms
Decoupling (also known as a 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
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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.
Washington Decoupling and Earnings Sharing
In our 2019 Washington general rate cases, the WUTC approved an extension of the mechanisms for an additional five-year term through March 31, 2025, with one modification in that new customers added after any test period would not be decoupled until included in a future test period.
The decoupling mechanisms each include an after-the-fact earnings test. At the end of each calendar year, separate electric and natural gas earnings calculations are made for the calendar year just ended. These earnings tests reflect actual decoupled revenues, normalized power supply costs and other normalizing adjustments. If we earn more than our authorized ROR in Washington, 50 percent of excess earnings are rebated to customers through adjustments to existing decoupling surcharge or rebate balances. We have proposed to modify this earnings test in our 2022 general rate case, so that if the Company earns more than 0.5 percent higher than the ROR authorized by the WUTC in the multi-year rate plan, the Company would defer these excess revenues and later return them to customers.
Idaho FCA Mechanism
In Idaho, the IPUC approved the extensions of FCAs for electric and natural gas through March 31, 2025.
Oregon Decoupling Mechanism
In Oregon, we have a decoupling mechanism for natural gas. An earnings review is conducted on an annual basis. In the annual earnings review, if we earn more than 100 basis points above our allowed return on equity, one-third of the earnings above the 100 basis points would be deferred and later rebated to customers.
Cumulative Decoupling and Earnings Sharing Balances
Total net cumulative decoupling deferrals among all jurisdictions were regulatory assets of $15.2 million as of December 31, 2021 and $21.3 million as of December 31, 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 December 31, 2021 and December 31, 2020. 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 2021 and 2020 related to the decoupling and earnings sharing mechanisms.
COVID-19 Deferrals
See “Note 1 of the Notes to Consolidated Financial Statements” for discussion on COVID-19 deferrals.
Results of Operations - Overall
The following provides an overview of changes in our 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.
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2021 compared to 2020
The following graph shows the total change in net income attributable to Avista Corp. shareholders for 2021 to 2020, as well as the various factors that caused such change (dollars in millions):
Utility revenues increased at Avista Utilities primarily due to increased loads from non-decoupled customers as a result of reduced COVID-19 restrictions during 2021, as well as weather that was warmer than normal and warmer than the prior year. In addition, utility revenues increased due to general rate increases in Oregon (effective January 16, 2021) and Washington (effective April 1, 2020), as well as customer growth. In addition, in 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 increased net power supply costs.
The increase in utility operating expenses was primarily due to increases in insurance, information technology, and labor and benefits costs at Avista Utilities, as well as a $2.5 million write off of Colstrip SmartBurn technology assets disallowed under the Washington general rate case settled during 2021. The increases were partially offset by an accrual recorded in 2020 for disallowed replacement power during an unplanned outage at Colstrip.
Utility depreciation and amortization increased primarily due to additions to utility plant during the period. This was partially offset by a one-time increase to depreciation expense in 2020 as we were able to utilize $10.9 million ($8.4 million when tax-effected) of electric tax benefits to offset costs associated with accelerating the deprecation of Colstrip based on a settlement in Washington.
Income taxes increased primarily due to a decrease in tax expense during 2020 related 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 the flow through method for certain items in 2021, as accepted by IPUC and WUTC through our general rate cases. Our effective tax rate was 7.5 percent in 2021 compared to 5.2 percent in 2020. See “Note 12 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 2021, compared to net investment losses experienced during 2020 (including impairment and write off of notes receivable). Additionally, other increased due to the gain on sale of certain subsidiary assets associated with the Spokane Steam Plant in 2021.
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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 24 of the Notes to Consolidated Financial Statements."
The presentation of electric utility margin and natural gas utility margin is intended to enhance understanding of our 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.
Results of Operations - Avista Utilities
2021 compared to 2020
Utility Operating Revenues
The following graphs present Avista Utilities' electric operating revenues and megawatt-hour (MWh) sales for the years ended December 31 (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.
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Total electric operating revenues in the graph above include intracompany sales of $28.7 million and $36.4 million for 2021 and 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 years ended December 31 (dollars in thousands):
Electric OperatingRevenues
Current year decoupling deferrals (a) $ (6,053 ) $ 11,449
Amortization of prior year decoupling deferrals (b) (13,472 ) (15,810 )
Total electric decoupling revenue $ (19,525 ) $ (4,361 )
(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)
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. 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.
Total electric revenues increased $79.6 million for 2021 as compared to 2020. The primary fluctuations that occurred during the period were as follows:
•
a $43.0 million increase in retail electric revenues due to an increase in total MWhs sold (increased revenues $34.3 million), as well as an increase in revenue per MWh (increased revenues $8.7 million).
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•
The increase in total retail MWhs sold was primarily the result of weather that was warmer than normal throughout the summer months, which increased cooling loads. Cooling degree days in Spokane during 2021 were 73 percent above historical norms, compared to 2 percent above historical norms in 2020. Also, there was a lifting of COVID-19 restrictions throughout 2021, which contributed to the increased loads and customer growth. Compared to 2020, use per residential customer increased 2.2 percent, and use per commercial customer increased 4.0 percent.
•
The increase in revenue per MWh was primarily due to base rate increases in Washington, effective April 1, 2020, as well as 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 $12.5 million increase in wholesale electric revenues due to an increase in sales prices (increased revenues $20.5 million), partially offset by a decrease in sales volumes (decreased revenues $8.0 million). The fluctuation of volumes 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, which limited our opportunities to sell generation in the wholesale power markets compared to 2020.
•
a $34.9 million increase in sales of fuel due to thermal generation resource optimization activities.
•
a $15.1 million decrease in electric decoupling revenue. This is primarily due to 2020 resulting in surcharges to non-residential customers, which had lower usage due to COVID-19 restrictions. In 2021, we experienced a rebate position due to higher than normal usage from warmer than normal weather in the cooling season, as well as lifting COVID-19 restrictions.
•
a $4.5 million increase in other revenues primarily due to an increase in transmission revenues of $2.8 million as well as an accrual for customer refunds recorded in 2020 for $1.4 million related to our 2015 Washington general rate case.
The following graphs present Avista Utilities' natural gas operating revenues and therms delivered for the years ended December 31 (dollars in millions and therms in thousands):
(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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AVISTA CORPORATION
Total natural gas operating revenues in the graph above include intracompany sales of $58.6 million and $49.6 million for 2021 and 2020, respectively.
The following table presents the current year deferrals and the amortization of prior year decoupling balances that are reflected in natural gas operating revenues for the years ended December 31 (dollars in thousands):
Natural GasOperating Revenues
Current year decoupling deferrals (a) $ 11,129 $ 1,797
Amortization of prior year decoupling deferrals (b) 1,761 (1,250 )
Total natural gas decoupling revenue $ 12,890 $ 547
(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 increased $37.4 million for 2021 as compared to 2020. The primary fluctuations that occurred during the period were as follows:
•
a $14.3 million increase in retail natural gas revenues (including industrial, which is included in other) due to higher retail rates (increased revenues $11.0 million), and higher sales volumes (increased revenues $3.3 million).
•
Retail rates increased due to general rate increases in Oregon (effective January 16, 2021), and Washington (effective April 1, 2020). Increases were also due to PGA rate increases, which do not impact utility margin.
•
Retail natural gas sales increased primarily due to higher commercial and industrial usage, as well as slight residential customer growth.
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an $8.4 million increase in wholesale natural gas revenues due to an increase in prices (increased revenues $67.2 million) offset by a decrease in volumes (decreased revenues $58.8 million) due to fewer resource optimization opportunities. 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.
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AVISTA CORPORATION
•
a $12.4 million increase in decoupling revenues primarily increased in decoupling revenues related to warmer weather in 2021 compared to 2020. In addition, during 2020 we were amortizing decoupling surcharges, whereas in 2021 we are amortizing decoupling rebates.
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a $2.9 million increase in other revenues primarily related to an accrual in 2020 of $3.6 million for customer refunds related to our 2015 Washington general rate case.
Utility Resource Costs
The following graphs present Avista Utilities' resource costs for the years ended December 31 (dollars in millions):
Total electric resource costs in the graph above include intracompany resource costs of $58.6 million and $49.6 million for 2021 and 2020, respectively.
Total electric resource costs increased $73.3 million for 2021 as compared to 2020. The primary fluctuations that occurred during the period were as follows:
•
a $21.2 million increase in power purchased due to an increase in wholesale prices (increased costs by $18.6 million), and an increase in the volume of power purchases (increased costs by $2.6 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. Additionally, over the summer months 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 at increased prices. See "Summer Weather Conditions" in the Executive Level Summary above.
•
a $48.4 million increase in fuel for generation primarily due to a decrease in hydroelectric generation requiring additional thermal generation. There was also an increase in natural gas prices in 2021 compared to 2020.
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a $25.7 million increase in other fuel costs. This represents fuel and the related derivative instruments that were purchased for generation but 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 $22.0 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.
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AVISTA CORPORATION
Total natural gas resource costs in the graph above include intracompany resource costs of $28.7 million and $36.4 million for 2021 and 2020, respectively.
Total natural gas resource costs increased $24.9 million for 2021 as compared to 2020. The primary fluctuations that occurred during the period were as follows:
•
a $38.7 million increase in natural gas purchased due to increases in the price of natural gas (increased costs by $100.0 million) which was partially offset by a decrease in total therms purchased (decreased costs $61.3 million).
•
a $13.8 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 24 of the Notes to Consolidated Financial Statements" to the Non-GAAP financial measure utility margin for the years ended December 31 (dollars in thousands):
Electric Natural Gas Intracompany Total
Electric utility margin increased $6.2 million and natural gas utility margin increased $12.5 million.
Electric utility margin increased primarily due to customer growth and a general rate increase in Washington, effective April 1, 2020. In addition, 2020 included an accrual for customer refunds of $1.4 million related to our 2015 Washington general rate case. This was partially offset by an increase in net power supply costs as compared to the 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 2021, we had a $7.7 million pre-tax expense under the ERM in Washington, compared to a $6.2 million pre-tax benefit in 2020.
Natural gas utility margin increased primarily due to general rate increases in Oregon (effective January 16, 2021) and Washington (effective April 1, 2020) as well as customer growth. The 2020 accrual for customer refunds of $3.5 million related to our 2015 Washington general rate case also contributed to the increase year over year.
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
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AVISTA CORPORATION
presentation of total results for Avista Utilities and in the 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
2021 compared to 2020
Net income for AEL&P was $7.2 million for the year ended December 31, 2021, compared to $8.1 million for 2020. This decrease was primarily due a $1.0 million increase in other operating expenses.
The following table presents AEL&P's operating revenues, resource costs and resulting utility margin for the years ended December 31 (dollars in thousands):
Electric
Utility margin increased slightly for 2021 primarily due to higher sales volumes to residential and commercial customers for 2021 as compared to 2020.
Results of Operations - Other Businesses
2021 compared to 2020
Our other businesses had net income of $14.6 million for 2021 compared to net loss of $3.4 million for 2020. The increase in net income primarily relates to net investment gains during 2021.
Accounting Standards to be Adopted in 2022
At this time, we are not expecting the adoption of accounting standards to have a material impact on our financial condition, results of operations and cash flows in 2022. For information on accounting standards adopted in 2021 and accounting standards expected to be adopted in future periods, see “Note 2 of the Notes to Consolidated Financial Statements.”
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. The following accounting policies represent those that our management believes are particularly important to the consolidated financial statements and require the use of estimates and assumptions:
•
Regulatory accounting, in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 980, Regulated Operations, among other things, requires that costs and/or obligations that, in our judgement, are probable of recovery through rates charged to our customers, but are not yet reflected in rates, not be reflected in our Consolidated Statements of Income until the period in which they are reflected in rates and matching revenues are recognized. Meanwhile, these costs and/or obligations are deferred and reflected on our Consolidated Balance Sheets as regulatory assets or liabilities. We generally receive regulatory orders before deferring costs as regulatory assets and liabilities; however, in certain instances in which we have regulatory precedent, we may not request an order before deferring the costs. If we were no longer allowed to apply regulatory accounting or no longer allowed recovery of these costs, we could be required to recognize significant write-offs of regulatory assets and liabilities in the Consolidated Statements of Income. See "Notes 1, 4 and 23 of the Notes to Consolidated Financial Statements" for further discussion of our regulatory accounting policy and mechanisms.
•
Pension Plans and Other Postretirement Benefit Plans, discussed in further detail below.
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•
Contingencies, related to unresolved regulatory, legal and tax issues as to which there is inherent uncertainty for the ultimate outcome of the respective matter. We accrue a loss contingency if it is probable that an asset is impaired or a liability has been incurred and the amount of the loss or impairment can be reasonably estimated. We also disclose losses that do not meet these conditions for accrual, if there is a reasonable possibility that a potential loss may be incurred. For all material contingencies, we have made a judgment as to the probability of a loss occurring and as to whether or not the amount of the loss can be reasonably estimated. However, no assurance can be given as to the ultimate outcome of any particular contingency. See "Notes 1 and 22 of the Notes to Consolidated Financial Statements" for further discussion of our commitments and contingencies.
Pension Plans and Other Postretirement Benefit Plans - Avista Utilities
We have a defined benefit pension plan covering substantially all regular full-time employees at Avista Utilities that were hired prior to January 1, 2014. For substantially all regular non-union full-time employees at Avista Utilities who were hired on or after January 1, 2014, a defined contribution 401(k) plan replaced the defined benefit pension plan. Union employees hired on or after January 1, 2014 are still covered under the defined benefit pension plan. See “Note 11 of the Notes to Consolidated Financial Statements” for further discussion of these individual plans.
Pension costs (including the SERP) were $19.3 million for 2021, $22.3 million for 2020 and $26.9 million for 2019. Of our pension costs (excluding the SERP), approximately 60 percent are expensed and 40 percent are capitalized consistent with labor charges. The costs related to the SERP are expensed. Our costs for the pension plan are determined in part by actuarial formulas that are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience.
Pension costs are affected by among other things:
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employee demographics (including age, compensation and length of service by employees),
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the amount of cash contributions we make to the pension plan,
•
the actual return on pension plan assets,
•
expected return on pension plan assets,
•
discount rate used in determining the projected benefit obligation and pension costs,
•
assumed rate of increase in employee compensation,
•
life expectancy of participants and other beneficiaries, and
•
expected method of payment (lump sum or annuity) of pension benefits.
We have to make estimates and assumptions as to many of these factors. In accordance with accounting standards, changes in pension plan obligations associated with these factors may not be immediately recognized as pension costs in our Consolidated Statements of Income, but we generally recognize the change in future years over the remaining average service period of pension plan participants. As such, our costs recorded in any period may not reflect the actual level of cash benefits provided to pension plan participants.
We revise the key assumption of the discount rate each year. In selecting a discount rate, we consider yield rates at the end of the year for highly rated corporate bond portfolios with cash flows from interest and maturities similar to that of the expected payout of pension benefits.
The expected long-term rate of return on plan assets is reset or confirmed annually based on past performance and economic forecasts for the types of investments held by our plan.
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The following chart reflects the assumptions used each year for the pension discount rate (exclusive of the SERP), the expected long-term return on plan assets and the actual return on plan assets and their impacts to the pension plan associated with the change in assumption (dollars in millions):
Discount rate (exclusive of SERP)
Increase/(decrease) to projected benefit obligation $ (15.6 ) $ 62.6 $ 41.7
Return on plan assets (a)
Expected long-term return on plan assets 5.40 % 5.50 % 5.90 %
Increase/(decrease) to pension costs $ 0.7 $ 2.5 $ (2.2 )
Actual return on plan assets, net of fees 7.10 % 15.20 % 20.40 %
(a)
The SERP has no plan assets. The plan assets in this disclosure are for the pension plan only.
The following chart reflects the sensitivities associated with a change in certain actuarial assumptions by the indicated percentage (dollars in millions):
Expected long-term return on plan assets (0.5 )% $ — * $ 3.6
Expected long-term return on plan assets 0.5 % — * (3.6 )
*Changes in the expected return on plan assets would not affect our projected benefit obligation.
We provide certain health care and life insurance benefits for substantially all of our retired employees. We accrue the estimated cost of postretirement benefit obligations during the years that employees provide service.
Liquidity and Capital Resources
Overall Liquidity
Avista Corp.'s consolidated operating cash flows are primarily derived from the operations of Avista Utilities. The primary source of operating cash flows for Avista Utilities is revenues from sales of electricity and natural gas. Significant uses of cash flows from Avista Utilities include the purchase of power, fuel and natural gas, and payment of other operating expenses, taxes and interest, with any excess being available for other corporate uses such as capital expenditures and dividends.
We design operating and capital budgets to control operating costs and to direct capital expenditures to projects that support immediate and long-term strategies, particularly for our regulated utility operations. In addition to operating expenses, we have continuing commitments for capital expenditures for construction and improvement of utility facilities.