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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:

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seek recovery of operating costs and capital investments, and

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seek the opportunity to earn reasonable returns as allowed by regulators.

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:

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short-term wholesale market prices and sales and purchase volumes,

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the level, availability and optimization of hydroelectric generation,

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the level, availability and optimization of thermal generation (including changes in fuel prices),

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retail loads, and

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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:

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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.

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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.

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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.

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a $34.9 million increase in sales of fuel due to thermal generation resource optimization activities.

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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.

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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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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:

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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).

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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.

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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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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:

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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.

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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.

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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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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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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:

•

employee demographics (including age, compensation and length of service by employees),

•

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.

Our annual net cash flows from operating activities usually do not fully support the amount required for annual utility capital expenditures. As such, from time-to-time, we need to access capital markets in order to fund these needs as well as fund maturing debt. See further discussion at “Capital Resources.”

We periodically file for rate adjustments for recovery of operating costs and capital investments and to seek the opportunity to earn reasonable returns as allowed by regulators.

Avista Utilities has regulatory mechanisms in place that provide for the deferral and recovery of the majority of power and natural gas supply costs. However, when power and natural gas costs exceed the levels currently recovered from retail customers, net cash flows are negatively affected. Factors that could cause purchased power and natural gas costs to exceed the levels currently recovered from our customers include, but are not limited to, higher prices in wholesale markets when we buy energy or an increased need to purchase power in the wholesale markets, and a lack of regulatory approval for higher

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authorized net power supply costs through general rate case decisions. Factors beyond our control that could result in an increased need to purchase power in the wholesale markets include, but are not limited to:

•

increases in demand (due to either climate change/weather or customer growth),

•

reduced snowpack or lower streamflows (due to climate change/weather) for hydroelectric generation,

•

unplanned outages at generating facilities, and

•

failure of third parties to deliver on energy or capacity contracts.

In addition to the above, Avista Utilities enters into derivative instruments to hedge our exposure to certain risks, including fluctuations in commodity market prices, foreign exchange rates and interest rates (for purposes of issuing long-term debt in the future). These derivative instruments often require collateral (in the form of cash or letters of credit) or other credit enhancements, or reductions or terminations of a portion of the contract through cash settlement, in the event of a downgrade in the Company's credit ratings or changes in market prices. In periods of price volatility, the level of exposure can change significantly. As a result, sudden and significant demands may be made against the Company's credit facilities and cash. See “Enterprise Risk Management – Credit Risk Liquidity Considerations” below.

We monitor the potential liquidity impacts of changes to energy commodity prices and other increased operating costs for our utility operations. We believe that we have adequate liquidity to meet such potential needs through our committed lines of credit.

Material contractual obligations arising in the normal course of business include energy purchase contracts, and contractual obligations related to generation facilities and transmission and distributions services. See "Note 13 of the Notes to Consolidated Financial Statements" for additional information related to these contractual obligations.

Additional capital resource requirements include borrowings and interest payment obligations (see "Notes 14-17 of the Notes to Consolidated Financial Statements"), lease obligations (see "Note 5 of the Notes to Consolidated Financial Statements"), pension and other postretirement benefit plan contributions (see "Note 11 of the Notes to Consolidated Financial Statements") and investment fund commitments (see "Note 6 of the Notes to Consolidated Financial Statements").

As of December 31, 2021, we had $82.0 million of available liquidity under the Avista Corp. committed line of credit and $25.0 million under the AEL&P committed line of credit. With our $400.0 million credit facility that expires in June 2026 and AEL&P's $25.0 million credit facility that expires in November 2024, we believe that we have adequate liquidity to meet our needs for the next 12 months.

Review of Consolidated Cash Flow Statement

2021 compared to 2020

Consolidated Operating Activities

Net cash provided by operating activities was $267.3 million for 2021 compared to $331.0 million for 2020. The decrease in net cash provided by operating activities primarily relates to an increase in power and natural gas cost deferrals (reflecting higher power and natural gas supply costs), which decreased cash flows by $51.8 million in 2021 compared to decreasing cash flows by $9.9 million in 2020. In addition, the provision for deferred taxes increased in 2021 less than it did during 2021, decreasing operating cash flows by $33.7 million compared to 2020. Finally, there was also an increase in pension contributions made during the year, from $22.0 million in 2020 to $42.0 million in 2021.

These decreases were partially offset by changes in certain current assets and liabilities, which increased cash flows by $26.3 million.

Consolidated Investing Activities

Net cash used in investing activities was $444.9 million for 2021, an increase compared to $410.7 million for 2020. During 2021, we paid $439.9 million for utility capital expenditures, compared to $404.3 million for 2020.

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Consolidated Financing Activities

Net cash provided by financing activities was $185.5 million for 2021 compared to $84.0 million for 2020. The increase in financing cash flows was primarily the result of changes in short-term borrowings of $63.8 million compared to 2020. In addition, there was an increase in proceeds from issuance of common stock of $17.8 million compared to 2020.

Capital Resources

Capital Structure

Our consolidated capital structure, including the current portion of long-term debt and short-term borrowings consisted of the following as of December 31, 2021 and 2020 (dollars in thousands):

Amount Percentof total Amount Percentof total

Current portion of long-term debt and leases $ 257,386 5.4 % $ 7,184 0.2 %

Our shareholders’ equity increased $125.0 million during 2021 primarily due to net income and the issuance of common stock, partially offset by dividends.

We need to finance capital expenditures and acquire additional funds for operations from time to time. The cash requirements needed to service our indebtedness, both short-term and long-term, reduce the amount of cash flow available to fund capital expenditures, purchased power, fuel and natural gas costs, dividends and other requirements.

Committed Lines of Credit

Avista Corp. has a committed line of credit with various financial institutions in the total amount of $400.0 million. In June 2021, we entered into an amendment that extends the expiration date to June 2026, with the option to extend for an additional one year period (subject to customary conditions). As of December 31, 2021, there was $82.0 million of available liquidity under this line of credit.

The Avista Corp. credit facility contains customary covenants and default provisions, including a covenant which does not permit our ratio of “consolidated total debt” to “consolidated total capitalization” to be greater than 65 percent at any time. As of December 31, 2021, we were in compliance with this covenant with a ratio of 54.7 percent.

Balances outstanding and interest rates on borrowings (excluding letters of credit) under Avista Corp.'s committed line of credit were as follows as of and for the year ended December 31 (dollars in thousands):

Letters of credit outstanding at end of year (1) $ 34,000 $ 27,618

Maximum balance outstanding during the year $ 338,000 $ 310,000

Average balance outstanding during the year $ 208,629 $ 138,890

Average interest rate during the year 1.14 % 1.59 %

Average interest rate at end of year 1.11 % 1.22 %

(1)

Letters of credit represent off-balance sheet obligations.

AEL&P has a $25.0 million committed line of credit with an expiration date in November 2024. As of December 31, 2021, there was $25.0 million of available liquidity under this line of credit.

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The AEL&P credit facility contains customary covenants and default provisions including a covenant which does not permit the ratio of “consolidated total debt at AEL&P” to “consolidated total capitalization at AEL&P,” (including the impact of the Snettisham obligation) to be greater than 67.5 percent at any time. As of December 31, 2021, AEL&P was in compliance with this covenant with a ratio of 51.9 percent.

As of December 31, 2021, Avista Corp. and its subsidiaries were in compliance with all of the covenants of their financing agreements, and none of Avista Corp.'s subsidiaries constituted a “significant subsidiary” as defined in Avista Corp.'s committed line of credit.

In April 2020, we entered into a $100.0 million credit agreement with an expiration date of April 2021. We borrowed the entire $100.0 million available under this agreement in April 2020 and repaid the outstanding balance in April 2021. See "Note 15 of the Notes to Consolidated Financial Statements."

Long-Term Debt

In September 2021, we issued and sold $70.0 million of 2.90 percent first mortgage bonds due in 2051 pursuant to a bond purchase agreement with institutional investors in the private placement market. We issued and sold the remaining $70.0 million under this same bond agreement in December 2021. The total net proceeds from the sale of the bonds were used to repay a portion of the outstanding balance under our $400.0 million committed line of credit. In connection with the pricing of the first mortgage bonds in September 2021, we cash-settled four interest rate swap derivatives (notional aggregate amount of $45.0 million) and paid a net amount of $17.2 million, which will be amortized as a component of interest expense over the life of the debt. The effective interest rate of the first mortgage bonds is 3.63 percent, including the effects of the settled interest rate swap derivatives and issuance costs.

Common Stock

We issued common stock in 2021 for total net proceeds of $90.0 million. Most of these issuances came through our sales agency agreements under which the sales agents may offer and sell new shares of our common stock from time to time. We have board and regulatory authority to issue a maximum of 4.3 million shares, of which 2.1 million remain unissued as of December 31, 2021. In 2021, 2.2 million shares were issued under these agreements resulting in total net proceeds of $88.5 million.

2022 and 2023 Liquidity Expectations

During 2022, we expect to issue $400.0 million of long-term debt and $120.0 million of common stock in order to refinance $250 million of first mortgage bonds maturing on April 2, 2022 and to fund capital expenditures.

During 2023, we expect to issue $110 million of long-term debt and $110 million of common stock to fund planned capital expenditures.

After considering the expected issuances of long-term debt and common stock during 2022 and 2023, we expect net cash flows from operating activities, together with cash available under our committed line of credit agreements, to provide adequate resources to fund capital expenditures, dividends, and other contractual commitments.

Limitations on Issuances of Preferred Stock and First Mortgage Bonds

We are restricted under our Restated Articles of Incorporation, as amended, as to the additional preferred stock we can issue. As of December 31, 2021, we could issue $1.5 billion of preferred stock at an assumed dividend rate of 4.6 percent. We are not planning to issue preferred stock.

Under the Avista Corp. and the AEL&P Mortgages and Deeds of Trust securing Avista Corp.'s and AEL&P's first mortgage bonds (including Secured Medium-Term Notes), respectively, each entity may issue additional first mortgage bonds in an aggregate principal amount equal to the sum of:

•

66-2/3 percent of the cost or fair value (whichever is lower) of property additions of that entity which have not previously been made the basis of any application under that entity's Mortgage, or

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•

an equal principal amount of retired first mortgage bonds of that entity which have not previously been made the basis of any application under that entity's Mortgage, or

•

deposit of cash.

However, Avista Corp. and AEL&P may not individually issue any additional first mortgage bonds (with certain exceptions in the case of bonds issued on the basis of retired bonds) unless the particular entity issuing the bonds has “net earnings” (as defined in the respective Mortgages) for any period of 12 consecutive calendar months out of the preceding 18 calendar months that were at least twice the annual interest requirements on that entity's mortgage securities at the time outstanding, including the first mortgage bonds to be issued, and on all indebtedness of prior rank. As of December 31, 2021, property additions and retired bonds would have allowed, and the net earnings test would not have prohibited, the issuance of $1.8 billion in aggregate principal amount of additional first mortgage bonds at Avista Corp. and $38.2 million at AEL&P, at an assumed interest rate of 8 percent in each case. We believe that we have adequate capacity to issue first mortgage bonds to meet our financing needs over the next several years.

Utility Capital Expenditures

We are making capital investments at our utilities to enhance service and system reliability for our customers and replace aging infrastructure. The following table summarizes our actual and expected capital expenditures as of and for the year ended December 31, 2021 (in thousands):

Avista Utilities AEL&P

2021 Actual capital expenditures

Expected total annual capital expenditures (by year)

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The following graph shows Avista Utilities' expected capital expenditures for 2022 by category (in millions):

These estimates of capital expenditures are subject to continuing review and adjustment. Actual expenditures may vary from our estimates due to factors such as changes in business conditions, construction schedules and environmental requirements.

Non-Regulated Investments and Capital Expenditures

We are making investments and capital expenditures at our other businesses including those related to economic development projects in our service territory that demonstrate the latest energy and environmental building innovations and house several local college degree programs. In addition, we are making investments in emerging technology companies and venture capital funds. The following table summarizes our actual and expected investments and capital expenditures at our other businesses as of and for the year ended December 31, 2021 (in thousands):

Other

2021 Actual investments and capital expenditures

Expected total annual investments and capital expenditures (by year)

These estimates of investments and capital expenditures are subject to continuing review and adjustment. Actual expenditures may vary from our estimates due to factors such as changes in business conditions or strategic plans.

See “Liquidity” for information regarding other material cash requirements for 2022 and thereafter.

Pension Plan

We contributed $42.0 million to the pension plan in 2021. We expect to contribute a total of $82.0 million to the pension plan in the period 2022 through 2026, with an annual contribution of $42.0 million for 2022 and $10.0 million from 2023 to 2026.

The final determination of pension plan contributions for future periods is subject to multiple variables, most of which are beyond our control, including changes to the fair value of pension plan assets, changes in actuarial assumptions (in particular

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the discount rate used in determining the benefit obligation), or changes in federal legislation. We may change our pension plan contributions in the future depending on changes to any variables, including those listed above.

See "Note 11 of the Notes to Consolidated Financial Statements" for additional information regarding the pension plan.

Credit Ratings

Our access to capital markets and our cost of capital are directly affected by our credit ratings. In addition, many of our contracts for the purchase and sale of energy commodities contain terms dependent upon our credit ratings. See “Enterprise Risk Management – Credit Risk Liquidity Considerations” and “Note 7 of the Notes to Consolidated Financial Statements.”

The following table summarizes our credit ratings as of February 22, 2022:

Standard & Poor's (1) Moody's (2)

Corporate/Issuer rating BBB Baa2

Senior Secured Debt A- A3

Senior Unsecured Debt BBB Baa2

(1)

Standard & Poor’s lowest “investment grade” credit rating is BBB-.

(2)

Moody’s lowest “investment grade” credit rating is Baa3.

A security rating is not a recommendation to buy, sell or hold securities. Each security rating is subject to revision or withdrawal at any time by the assigning rating organization. Each security rating agency has its own methodology for assigning ratings, and, accordingly, each rating should be considered in the context of the applicable methodology, independent of all other ratings. The rating agencies provide ratings at the request of Avista Corp. and charge fees for their services.

Dividends

See "Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities" for a detailed discussion of our dividend policy and the factors which could limit the payment of dividends.

Competition

Our electric and natural gas distribution utility business has historically been recognized as a natural monopoly. In each regulatory jurisdiction, our rates for retail electric and natural gas services (other than specially negotiated retail rates for industrial or large commercial customers, which are subject to regulatory review and approval) are generally determined on a “cost of service” basis. Rates are designed to provide, after recovery of allowable operating expenses and capital investments, an opportunity for us to earn a reasonable return on investment as allowed by our regulators.

In retail markets, we compete with various rural electric cooperatives and public utility districts in and adjacent to our service territories in the provision of service to new electric customers. We have entered into a number of service territory agreements with certain rural electric cooperatives and public utility districts, approved in applicable jurisdictions, to set forth conditions under which one or the other utility will provide service to customers. Alternative energy technologies, including customer-sited solar, wind or geothermal generation, or energy storage may also compete with us for sales to existing customers. Advances in power generation, energy efficiency, energy storage and other alternative energy technologies could lead to more wide-spread usage of these technologies, thereby reducing customer demand for the energy supplied by us. This reduction in usage and demand would reduce our revenue and negatively impact our financial condition including possibly leading to our inability to fully recover our investments in generation, transmission and distribution assets. Similarly, our natural gas distribution operations compete with other energy sources including heating oil, propane and other fuels.

Certain natural gas customers could bypass our natural gas system, reducing both revenues and recovery of fixed costs. To reduce the potential for such bypass, we price natural gas services, including transportation contracts, competitively and have varying degrees of flexibility to price transportation and delivery rates by means of individual contracts. These individual contracts are subject to state regulatory review and approval. We have long-term transportation contracts with several of our largest industrial customers under which the customer acquires its own commodity while using our infrastructure for delivery.

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Such contracts reduce the risk of these customers bypassing our system in the foreseeable future and minimizes the impact on our earnings.

Customers may have a choice in the future over the sources from which to receive their energy. In order to effectively compete for our customers in the future, we continue to strive to create value through product and service offerings. We are also attempting to enhance the effectiveness and ease of our customer interactions with us by tailoring our internal company initiatives to focus on choices for our customers to increase their overall satisfaction with the Company.

Also, non-utility businesses are developing new technologies and services to help energy consumers manage energy in new ways that may improve productivity and could alter demand for the energy we sell.

In wholesale markets, competition for available electric supply is influenced by the:

•

localized and system-wide demand for energy,

•

type, capacity, location and availability of generation resources, and

•

variety and circumstances of market participants.

These wholesale markets are regulated by the FERC, which requires electric utilities to:

•

transmit power and energy to or for wholesale purchasers and sellers,

•

enlarge or construct additional transmission capacity for the purpose of providing these services, and

•

transparently price and offer transmission services without favor to any party, including the merchant functions of the utility.

Participants in the wholesale energy markets include:

•

other utilities,

•

federal power marketing agencies,

•

energy marketing and trading companies,

•

independent power producers,

•

financial institutions, and

•

commodity brokers.

Economic Conditions and Utility Load Growth

The general economic data, on both national and local levels, contained in this section is based, in part, on independent government and industry publications, reports by market research firms or other independent sources. While we believe that these publications and other sources are reliable, we have not independently verified such data and can make no representation as to its accuracy.

Avista Utilities

We track multiple economic indicators affecting the three largest metropolitan statistical areas in our Avista Utilities service area: Spokane, Washington, Coeur d'Alene, Idaho, and Medford, Oregon. The key indicators are employment change and unemployment rates. On an annual basis, 2021 showed positive job growth with lower unemployment rates in all three metropolitan areas. This reflects the on-going recovery from the 2020 COVID-19 induced recession. The unemployment rates in Spokane and Medford are near the national average, while Coeur d’Alene is lower. Other leading indicators, such as initial unemployment claims and residential building permits, signal continued growth over the next 12 months. Considering all relevant indicators, we expect economic growth in our service area in 2022 to be in-line with the U.S. as a whole.

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Reflecting the on-going recovery from the COVID-19 recession, nonfarm employment (seasonally adjusted) in our eastern Washington, northern Idaho and southwestern Oregon metropolitan service areas increased in 2021. In Spokane, Washington employment increased 3.8 percent with gains in all major sectors except manufacturing; information; financial activities; and government. Employment increased 5.3 percent in Coeur d'Alene, Idaho, reflecting gains in all major sectors except mining and logging; manufacturing; and government. In Medford, Oregon, employment increased 2.7 percent, with gains in all major sectors except information and government. U.S. nonfarm sector employment increased 2.7 percent over the same period.

Changes in the unemployment rate in 2021 reflect a gradual recovery from the COVID-19 recession. In Spokane the unemployment rate was 8.8 percent in 2020 and fell to 4.9 percent in 2021; in Coeur d'Alene the rate fell from 6.9 percent in 2020 to 3.6 percent in 2021; and in Medford the rate fell from 7.8 percent in 2020 to 5.3 percent in 2021. The U.S. unemployment rate fell from 8.1 percent in 2020 percent to 5.3 percent in 2021.

Alaska Electric Light and Power Company

Our AEL&P service area is centered in Juneau. Although Juneau is Alaska’s state capital, it is not a metropolitan statistical area. This means breadth and frequency of economic data is more limited. Therefore, the dates of Juneau's economic data may significantly lag the period of this filing.

The Quarterly Census of Employment and Wages for Juneau shows employment increased 1.4 percent between the first half of 2020 and first half of 2021. There were employment gains in all major sectors, except trade, transportation, and utilities; information; financial activities; professional and business services; and other services. Government employment increased 2.3 percent during this period; this sector accounted for 41 percent of total employment in 2020. Between 2020 and 2021, the unemployment rate fell from 6.6 percent to 4.5 percent.

Forecasted Customer and Load Growth

Based on our forecast for 2022 through 2026 for Avista Utilities' service area, we expect annual electric customer growth to average 1.2 percent, within a forecast range of 0.8 percent to 1.6 percent. We expect annual natural gas customer growth to average 1.4 percent, within a forecast range of 0.8 percent to 2.0 percent. We anticipate retail electric load growth to average 0.6 percent, within a forecast range of 0.2 percent and 1.0 percent. We expect natural gas load growth to average 0.9 percent, within a forecast range of 0.4 percent and 1.4 percent. The forecast ranges reflect (1) the inherent uncertainty associated with the economic assumptions on which forecasts are based and (2) the historic variability of natural gas customer and load growth. These natural gas forecast ranges do not reflect the uncertainty regarding new natural gas laws or regulations that could be effective in future periods. See further discussion regarding these natural gas regulations as included in "Environmental Issues and Contingencies" below.

In AEL&P's service area, we expect no growth in residential, commercial and government customers for the period 2021 through 2024. We anticipate average annual total load growth will be in a narrow range around 0.5 percent, with residential load growth averaging 1.0 percent and no growth in commercial and government load. Residential load growth reflects (1) existing customers switching from diesel generated heat to electric heat pumps, and (2) an increase in the residential use of electric vehicles.

The forward-looking statements set forth above regarding retail load growth are based, in part, upon purchased economic forecasts and publicly available population and demographic studies. The expectations regarding retail load growth are also based upon various assumptions, including:

•

assumptions relating to weather and economic and competitive conditions,

•

internal analysis of company-specific data, such as energy consumption patterns,

•

internal business plans,

•

an assumption that we will incur no material loss of retail customers due to self-generation or retail wheeling, and

•

an assumption that demand for electricity and natural gas as a fuel for mobility will for now be immaterial.

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Changes in actual experience can vary significantly from our projections.

See also "Competition" above for a discussion of competitive factors that could affect our results of operations in the future.

Environmental Issues and Contingencies

We are subject to environmental regulation by federal, state and local authorities. The generation, transmission, distribution, service and storage facilities in which we have ownership interests or which we may need to acquire or develop are subject to environmental laws, regulations and rules relating to construction permitting, air emissions, water quality, fisheries, wildlife, endangered species, avian interactions, wastewater and stormwater discharges, waste handling, natural resource protection, historic and cultural resource protection, and other similar activities. These laws and regulations require the Company to make substantial investments in compliance activities and to acquire and comply with a wide variety of environmental licenses, permits, approvals and settlement agreements. These items are enforceable by public officials and private individuals. Some of these regulations are subject to ongoing interpretation, whether administratively or judicially, and are often in the process of being modified. We conduct periodic reviews and audits of pertinent facilities and operations to enhance compliance and to respond to or anticipate emerging environmental issues. The Company's Board of Directors has established a committee to oversee environmental issues and to assess and manage environmental risk.

We monitor legislative and regulatory developments at different levels of government for environmental issues, particularly those with the potential to impact the operation of our generating plants and other assets. We continue to be subject to increasingly stringent or expanded application of environmental and related regulations from all levels of government.

Environmental laws and regulations may restrict or impact our business activities in many ways, including, but not limited to, by:

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increasing the operating costs of generating plants and other assets,

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increasing the lead time and capital costs for the construction of new generating plants and other assets,

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requiring modification of our existing generating plants,

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requiring existing generating plant operations to be curtailed or shut down,

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reducing the amount of energy available from our generating plants,

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restricting the types of generating plants that can be built or contracted with,

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requiring construction of specific types of generation plants at higher cost, and

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increasing costs of distributing, or limiting our ability to distribute, electricity and/or natural gas.

Compliance with environmental laws and regulations could result in increases to capital expenditures and operating expenses. We intend to seek recovery of any such costs through the ratemaking process.

Washington Clean Energy Transformation Act (CETA)

In 2019, the Washington State Legislature passed the CETA, which requires Washington utilities to eliminate the costs and benefits associated with coal-fired resources from their retail electric sales by December 31, 2025. This requirement would effectively prohibit sales of energy produced by coal-fired generation to Washington retail customers after December 31, 2025. In addition, CETA establishes the policy of Washington State that all retail sales of electricity to Washington customers must be carbon-neutral by January 1, 2030 and requires that each electric utility demonstrate compliance with this standard by using electricity from renewable and other non-emitting resources for 100 percent of the utility’s retail electric load over consecutive multi-year compliance periods; provided, however, that through December 31, 2044 the utility may satisfy up to 20 percent of this requirement with specified payments, credits and/or investments in qualifying energy transformation projects. The law has direct, specific impacts on Colstrip, which are unique to those owners of Colstrip who serve Washington customers. See “Colstrip” section and "Note 22 of the Notes to Consolidated Financial Statements" for further details on the impacts of CETA on Colstrip and our continued participation in Colstrip. Our hydroelectric and biomass generation facilities can be used to

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comply with the CETA’s clean energy standards. We intend to seek recovery of any costs associated with the clean energy legislation and regulations through the regulatory process.

As required under CETA, in October 2021, we filed our first Clean Energy Implementation Plan (CEIP) with the WUTC. This filing triggered comments from interested parties in January 2022, with WUTC action to follow thereafter in 2022. We must file a CEIP with the WUTC every four years.

Our CEIP is a road map of specific actions we propose to take over the next four years (2022-2025) to show the progress being made toward clean energy goals and the equitable distribution of benefits and burdens to all customers as established by the CETA, which was passed by the Washington legislature and enacted into law in 2019. CETA requires electric supply to be greenhouse gas neutral by 2030 and 100 percent renewable or generated from zero-carbon resources by 2045.

Some highlights of our CEIP include:

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Beginning in 2022, we plan to serve 80 percent of our Washington customer demand with owned and purchased renewable energy, then increase this target by 5 percent every two years.

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To minimize rate impacts as we transition to cleaner energy, we are proposing to sell some of our renewable energy credits (RECs) on the open market through 2029. In 2030, we will utilize 100 percent of RECs on behalf of our customers, rather than selling RECs on the open market.

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The plan sets energy efficiency targets to reduce customer load by approximately 2 percent over the next four years by 204,305 megawatt hours through incentives and programs to lower energy use without impacting the customer.

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Our demand response target is to lower peak demand by 30 megawatts in periods of extreme heat or cold as an effort to eliminate the need for future resources.

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We have proposed a variety of initiatives to promote the equitable distribution of the benefits and burdens of renewable energy and are still working to find the best way to achieve these goals.

While the CEIP represents our current objectives, it is subject to change from time to time in the future as circumstances warrant including direct input from the WUTC.

Policies Related to Climate Change

Legal and policy changes responding to concerns about long-term global climate changes, and the potential impacts of such changes, could have a significant effect on our business. Our operations could be affected by changes in laws and regulations intended to mitigate the risk of, or alter, global climate changes, including restrictions on the operation of our power generation resources and obligations or limitations imposed on the sale of natural gas. Changing temperatures and precipitation, including snowpack conditions, affect the availability and timing of streamflows, which impact hydroelectric generation. Extreme weather events could increase fire risks, service interruptions, outages and maintenance costs. Changing temperatures could also change the magnitude and timing of customer demand.

Federal Regulatory Actions

In June 2019, the EPA released the final version of the Affordable Clean Energy (ACE) rule, the replacement for the Clean Power Plan (Federal CPP). The final ACE rule finalized the repeal of the Federal CPP and comprised the EPA’s determination of the Best System of Emissions Reduction (BSER) for existing coal-fired power plants as heat rate efficiency improvements based on a range of “candidate technologies”.

In January 2021, the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit) vacated the ACE Rule and remanded the record back to the EPA for further consideration consistent with its opinion, finding that the EPA misinterpreted the Clean Air Act when it determined that the language of Section 111 barred consideration of emissions reduction options that were not applied at the source. The Court also vacated the repeal of the Federal CPP. In February 2021, the EPA moved for a partial stay of the Court’s mandate, noting that no Section 111(d) rule should go into effect until the EPA conducted new rulemaking in response to the January 2021 decision. The Court subsequently issued an order withholding issuance of the mandate with respect to the repeal of the Federal CPP and directing issuance of the mandate “in the normal course” for the vacatur of the replacement portion of the rule. In April 2021, numerous parties requested the Supreme Court’s review of the

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D.C. Circuit’s January 2021 decision, and in October 2021, the Supreme Court granted such review. Oral arguments are scheduled for February 2022 in this case.

Given the status of the EPA’s rulemaking, we cannot reasonably predict the timing, outcome or applicability of these issues with respect to any of the Company's generation resources.

Washington Legislation and Regulatory Actions

Clean Air Rule

In September 2016, the Washington State Department of Ecology adopted the Clean Air Rule (CAR) to cap and reduce greenhouse gas (GHG) emissions across the State of Washington in pursuit of the State’s GHG goals, which were enacted in 2008 by the Washington State Legislature. In response, the Company, Cascade Natural Gas Corporation, NW Natural and Puget Sound Energy jointly filed actions in both the Eastern District of Washington and in Thurston County Superior Court, challenging the CAR.

In January 2020, the Washington State Supreme Court issued a decision holding that the CAR was invalid as to non-emitters, such as natural gas distributors, but could be enforced against direct emitters, such as natural gas generation plants. The Court has remanded the matter to Thurston County Superior Court, where it has been stayed by the Court. At this time, we are continuing to evaluate the potential impact of the surviving portion of the rule, if any, to our generation facilities, should their emissions exceed the rule’s compliance threshold. The rule is not intended to apply to the Kettle Falls Generating Station. We plan to seek recovery of any costs related to compliance with the surviving portion of the CAR through the ratemaking process.

Emissions Performance Standard

Washington also applies a GHG emissions performance standard to electric generation facilities used to serve retail loads in their jurisdictions, whether the facilities are located within its state or elsewhere. The emissions performance standard prevents utilities from constructing or purchasing generation facilities, or entering into power purchase agreements of five years or longer duration to purchase energy produced by plants that, in any case, have emission levels higher than 1,100 pounds of GHG per MWh. The Washington State Department of Commerce reviews the standard every five years. In September 2018, it adopted a new standard of 925 pounds of GHG per MWh. We intend to seek recovery of costs related to ongoing and new requirements through the ratemaking process.

Washington Climate Commitment Act

In 2021, the legislature passed the Climate Commitment Act, which establishes a cap and invest program to help achieve Washington’s greenhouse gas limits by 2050. The Washington Department of Ecology is responsible for the implementation and the start of this program by January 1, 2023, including the adoption of annual allowance budgets for the first compliance period of the program by October 1, 2022. There are various rule making proceedings regarding the details of the program pending before the Department of Ecology. We will actively monitor and participate in these rulemakings as they proceed but cannot reasonably predict how these programs may impact our facilities at this time.

Oregon Legislation and Regulatory Actions

Climate Protection Plan

In March 2020, Oregon Governor Kate Brown issued Executive Order No. 20-04, “Directing State Agencies to Take Actions to Reduce and Regulate Greenhouse Gas Emissions.” The Executive Order launched rulemaking proceedings for every Oregon agency with jurisdiction over greenhouse gas-related matters, with the aim of reducing Oregon’s overall GHG emissions to 80 percent below 1990 levels by 2050. Oregon agencies, including the Oregon Department of Environmental Quality (ODEQ) and the OPUC, issued reports discussing general intent to carry out the Executive Order.

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The ODEQ subsequently developed cap and reduce rules known as the Climate Protection Program (Oregon CPP). Final rules were adopted by the Environmental Quality Commission (EQC) in December 2021 and become effective in 2022. The Oregon CPP originally proposed emission reduction targets of at least 45 percent below 1990 levels by 2035 and at least 80 percent below 1990 levels by 2050, in accordance with Executive Order 20-04. However, during the December 2021 ODEQ presentation to the EQC, substantial changes were made to the final version of the Oregon CPP, as compared to the version of the Oregon CPP that was open for public comment. One of the most significant items revises the emissions cap and mandates emissions reductions of at least 50 percent by 2035 and 90 percent by 2050. We are evaluating the potential impacts of these regulations. Compliance efforts to meet the Oregon CPP emissions reduction goals could materially impact our Oregon natural gas business.

The OPUC has opened a Natural Gas Fact-Finding effort to analyze the potential natural gas utility bill impacts that may result from limiting GHG emissions of regulated natural gas utilities under the ODEQ’s Oregon CPP and to identify appropriate regulatory tools to mitigate potential customer impacts. According to the OPUC Staff, the ultimate goal of the Fact-Finding Docket will be to inform future policy decisions and other key analyses to be considered in 2022. We expect the OPUC Staff will present a final report on the Fact-Finding effort to the OPUC in late spring of 2022 with recommendations for further OPUC engagement later in 2022.

Emissions Performance Standard

Like Washington, Oregon applies a GHG emissions performance standard to electric generation facilities, requiring that any new baseload natural gas plant, non-base load natural gas plant, and non-generating facility reduce its net carbon dioxide emissions 17% below the most efficient combustion-turbine plant in the United States. The Oregon Energy Facility Siting Council issues rules periodically to update the standard, as more efficient power plants are built in other states. The standard can be met by any combination of efficiency, cogeneration, and offsets from carbon dioxide mitigation measures. We have thermal generation located in Oregon, and as such this standard applies to that facility. We intend to seek recovery of costs related to ongoing and new requirements through the ratemaking process.

Clean Electricity and Coal Transition Act

In Oregon, legislation was enacted in 2016 which requires Portland General Electric and PacifiCorp to remove coal-fired generation from their Oregon rate base by 2030. This legislation does not directly relate to Avista Corp. because Avista Corp. is not an electric utility in Oregon. However, because these two utilities, along with Avista Corp., hold minority interests in Colstrip, the legislation could indirectly impact Avista Corp., though specific impacts cannot be reasonably predicted at this time. While the legislation requires Portland General Electric and PacifiCorp to eliminate Colstrip from their rates, they would be permitted to sell the output of their shares of Colstrip into the wholesale market or, as is the case with PacifiCorp, reallocate generation from Colstrip to other states. We cannot predict the eventual outcome of actions arising from this legislation at this time or estimate the effect thereof on Avista Corp.; however, we intend to continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to our generation assets.

Clean Air Act (CAA)

The CAA creates numerous requirements for our thermal generating plants. Colstrip, Kettle Falls GS, Coyote Springs and Rathdrum CT all require CAA Title V operating permits. The Boulder Park GS, Northeast CT and a number of other operations require minor source permits or simple source registration permits. We have secured these permits and certify our compliance with Title V permits on an annual basis. These requirements can change over time as the CAA or applicable implementing regulations are amended and new permits are issued. We actively monitor legislative, regulatory and other program developments of the CAA that may impact our facilities.

Threatened and Endangered Species and Wildlife

A number of species of fish in the Northwest are listed as threatened or endangered under the Federal Endangered Species Act. We are implementing fish protection measures at our hydroelectric project on the Clark Fork River under a 45-year FERC operating license for Cabinet Gorge and Noxon Rapids (issued in 2001) that incorporates a comprehensive settlement

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agreement. The restoration of native salmonid fish, including bull trout, a threatened species, is a key part of the agreement. The result is a collaborative native salmonid restoration program with the U.S. Fish and Wildlife Service, Native American tribes and the states of Idaho and Montana on the lower Clark Fork River, consistent with requirements of the FERC license. Recent efforts in this program include the development of a permanent fish passage facility at Cabinet Gorge dam, as well as fish capture facilities on tributaries to the Clark Fork River. The U.S. Fish & Wildlife Service issued an updated Critical Habitat Designation for bull trout in 2010 that includes the lower Clark Fork River, as well as portions of the Coeur d'Alene basin within our Spokane River Project area, and issued a final Bull Trout Recovery Plan under the ESA. Regional efforts are underway evaluating the potential of re-establishing anadromous fish above previously blocked areas, including the Spokane River, which is upstream from Grand Coulee dam.

Various statutory authorities, including the Migratory Bird Treaty Act, have established penalties for the unauthorized take of migratory birds. Because we operate facilities that can pose risks to a variety of such birds, we have developed and follow an avian protection plan.

We are also aware of other threatened and endangered species and issues related to them that could be impacted by our operations and we make every effort to comply with all laws and regulations relating to these threatened and endangered species. We expect costs associated with these compliance efforts to be recovered through the ratemaking process.

Cabinet Gorge Total Dissolved Gas Abatement Plan

Dissolved atmospheric gas levels (referred to as "Total Dissolved Gas" or "TDG") in the Clark Fork River exceed state of Idaho and federal water quality numeric standards downstream of Cabinet Gorge particularly during periods when excess river flows must be diverted over the spillway. Under the terms of the Clark Fork Settlement Agreement as incorporated in the FERC license for the Clark Fork Project, we work in consultation with agencies, tribes and other stakeholders to address this issue through structural modifications to the spillgates, monitoring and analysis. After extensive testing, Clark Fork Settlement Agreement stakeholders have agreed that no further spillway modifications are justified. For the remainder of the FERC License term, we will continue to mitigate remaining impacts of TDG while periodically considering the potential for new approaches to further reduce TDG. We continue to work with stakeholders to determine the degree to which TDG abatement impacts future mitigation obligations. We have sought, and intends to continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to this issue.

Other

For other environmental issues and other contingencies see “Note 22 of the Notes to Consolidated Financial Statements.”

Colstrip

Colstrip is a coal-fired generating plant in southeastern Montana that includes four units and which is owned by six separate entities. We have a 15 percent ownership interest in Units 3 & 4. The other owners are Puget Sound Energy, Inc., Portland General Electric Company, NorthWestern Corporation, Pacificorp and Talen Montana, LLC (which is also the operator of the plant). In January 2020, the owners of Units 1 & 2, in which the Company has no ownership, closed those two units. The owners of Units 3 & 4 currently share operating and capital costs pursuant to the terms of an operating agreement among them (the Ownership and Operation Agreement).

Depreciation of Colstrip Assets

We received orders from the IPUC and WUTC allowing us to accelerate the depreciation of our 15 percent ownership interest in Colstrip to 2027 for Idaho and 2025 for Washington.

Coal Ash Management/Disposal

In 2015, the EPA issued a final rule regarding coal combustion residuals (CCRs), also termed coal combustion byproducts or coal ash (Colstrip produces this byproduct). The CCR rule has been the subject of ongoing litigation. In August 2018, the D.C. Circuit struck down provisions of the rule. In December 2019, a proposed revision to the rule was published in the Federal Register to address the D.C. Circuit's decision. The rule includes technical requirements for CCR landfills and surface

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impoundments under Subtitle D of the Resource Conservation and Recovery Act, the nation's primary law for regulating solid waste. The Colstrip owners developed a multi-year compliance plan to address the CCR requirements along with existing state obligations expressed through the 2012 Administrative Order on Consent (AOC) with Montana Department of Environmental Quality (MDEQ). These requirements continue despite the 2018 federal court ruling.

The AOC requires MDEQ to review Remedy and Closure plans for all parts of the Colstrip plant through an ongoing public process. The AOC also requires the Colstrip owners to provide financial assurance, primarily in the form of surety bonds, to secure each owner’s pro rata share of various anticipated closure and remediation obligations. We are responsible for our share of two major areas: the Plant Site Area and the Effluent Holding Pond Area. Generally, the plans include the removal of Boron, Chloride, and Sulfate from the groundwater, closure of the existing ash storage ponds, and installation of a new water treatment system to convert the facility to a dry ash storage. We recently adjusted our share of the posted surety bonds to $17.3 million. This amount will be updated annually, with expected obligations decreasing over time as remediation activities are completed.

Colstrip Coal Contract

Colstrip is supplied with fuel from adjacent coal reserves under coal supply and transportation agreements. Several of the co-owners of Colstrip, including us, have a coal contract that runs through December 31, 2025.

Colstrip Arbitration, Litigation, and Other Contingencies

See "Note 22 of the Notes to Consolidated Financial Statements" for disputes, arbitration, litigations and other contingencies related to Colstrip. We continue to assess the best options for Colstrip in conjunction with our co-owners. We intend to seek recovery of any costs associated with Colstrip through the ratemaking process.

Enterprise Risk Management

The material risks to our businesses are discussed in "Item 1A. Risk Factors," "Forward-Looking Statements," as well as "Environmental Issues and Contingencies." The following discussion focuses on our mitigation processes and procedures to address these risks.

We consider the management of these risks an integral part of managing our core businesses and a key element of our approach to corporate governance.

Risk management includes identifying and measuring various forms of risk that may affect the Company. We have an enterprise risk management process for managing risks throughout our organization. Our Board of Directors and its Committees take an active role in the oversight of risk affecting the Company. Our risk management department facilitates the collection of risk information across the Company, providing senior management with a consolidated view of the Company’s major risks and risk mitigation measures. Each area identifies risks and implements the related mitigation measures. The enterprise risk process supports management in identifying, assessing, quantifying, managing and mitigating the risks. Despite all risk mitigation measures, however, risks are not eliminated.

Our primary identified categories of risk exposure are:

• Utility regulatory • External mandates

• Operational • Financial

• Climate Change • Energy commodity

• Cyber and Technology • Compliance

• Strategic

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Our primary categories of risks are described in "Item 1A. Risk Factors."

Utility Regulatory Risk

Regulatory risk is mitigated through a separate regulatory group which communicates with commission regulators and staff regarding the Company’s business plans and concerns. The regulatory group also considers the regulator’s priorities and rate policies and makes recommendations to senior management on regulatory strategy for the Company. Oversight of our regulatory strategies and policies is performed by senior management and our Board of Directors. See “Regulatory Matters” for further discussion of regulatory matters affecting our Company.

Operational Risk

To manage operational and event risks, we maintain emergency operating plans, business continuity and disaster recovery plans, maintain insurance coverage against some, but not all, potential losses and seek to negotiate indemnification arrangements with contractors for certain event risks. In addition, we design and follow detailed vegetation management and asset management inspection plans, which help mitigate wildfire and storm event risks, as well as identify utility assets which may be failing and in need of repair or replacement. We also have an Emergency Operating Center, which is a team of employees that plan for and train to deal with potential emergencies or unplanned outages at our facilities, resulting from natural disasters or other events. To prevent unauthorized access to our facilities, we have both physical and cyber security in place.

To address the risk related to fuel cost, availability and delivery restraints, we have an energy resources risk policy, which includes our wholesale energy markets credit policy and control procedures to manage energy commodity price and credit risks. Development of the energy resources risk policy includes planning for sufficient capacity to meet our customer and wholesale energy delivery obligations. See further discussion of the energy resources risk policy below.

Oversight of the operational risk management process is performed by the Environmental, Technology and Operations Committee of our Board of Directors and from senior management with input from each operating department.

Climate Change Risk

Multiple departments at the Company work to mitigate risks related to climate change. Climate change adds uncertainty to existing risks that we have historically managed and mitigated. These efforts are reflected in electric and gas operations, investments in assets and asset reliability and resiliency across the Company’s operations, and in more specific efforts, such as the Wildfire Resiliency Plan. Power Supply staff, as a regular course of business, monitor items such as snowpack and broader precipitation conditions, patterns and modeled or predicted climate change. These and other assessments are incorporated into our IRP processes. Environmental Affairs, Governmental Affairs and other departments monitor policy and regulatory developments that may relate to climate change in order to engage these efforts constructively and prepare for compliance matters.

The Company has created four councils that are centered around its primary focus areas: our customers, our people, performance and invention. The Perform Council is an interdisciplinary team of management and other employees of the Company which regularly meets to discuss, assess and manage current issues associated with the Company’s performance. A key area of focus for the Perform Council is potential risks and opportunities associated with long-term global climate change. Among other things, the Perform Council:

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facilitates internal and external communications regarding climate change and related issues,

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