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 2022 and 2021 financial statement items and year-to-year comparisons between 2022 and 2021. Discussion of 2020 financial statement items and year-to-year comparisons between 2021 and 2020 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, 2021.
Business Segments
As of December 31, 2022, 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) 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 was $155.2 million for 2022, an increase from $147.3 million for 2021.
Avista Utilities' net income decreased primarily due to increased operating costs, depreciation, and interest expense compared to 2021. These increased expenses were partially offset by higher utility margin, as well as benefits from our completed general rate cases including recognition of tax customer credits which resulted in lower income tax expense for 2022.
AEL&P net income increased slightly, primarily due to higher residential revenues compared to 2021.
The increase in net income at our other businesses was primarily due to an increase in the fair value of our investment in a biotechnology company, which stems from an investment that was originally focused on the development of biofuels. Their patented biological drug platform accelerates time to market for orally delivered antibody drugs and has advanced through testing stages, increasing the value of our investment.
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).
Colstrip Exit Plans
On January 16, 2023, we entered into an agreement with NorthWestern under which, subject to the terms and conditions in the agreement, we will transfer our 15 percent ownership in Colstrip Units 3 and 4, to NorthWestern. There is no monetary exchange included in the transaction. The transaction is scheduled to close on December 31, 2025, or such other date as the parties mutually agree upon. As included in the agreement, we will retain responsibility for site remediation expenses associated with conditions existing as of the close of the transaction.
See “Note 22 of the Notes to Consolidated Financial Statements” for further discussion on Colstrip and our agreement with NorthWestern.
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Liquidity and Increased Resource Pricing
Starting in December 2022, natural gas and power prices increased 5 to 8 times higher than normal, due to increased loads associated with colder than normal weather throughout the region, as well as natural gas pipeline constraints due to this increased demand. These increased prices led to increased liquidity needs for purchases of physical commodities as well as significant margin calls associated with future commodity activity and hedging arrangements. That, in turn, placed pressure on our available liquidity.
In response to these increased liquidity needs, we entered into additional credit agreements during the fourth quarter of 2022. These facilities are short term, and include a $150 million term loan expiring on March 30, 2023, a $100 million revolving line of credit expiring on November 28, 2023 and a $50 million letter of credit facility. See “Note 15 of the Notes to Consolidated Financial Statements” for further discussion on these credit agreements.
Our regulatory asset balances for our ERM, PCA and PGA deferral mechanisms increased significantly as a result of these increased prices. We expect these deferral amounts to be recovered in future customer rates through the regulatory process. See “Power Cost Deferrals and Recovery Mechanisms” and “Note 23 of the Notes to Consolidated Financial Statements” for further discussion on regulatory matters, including deferral mechanisms and associated balances.
The need to increase borrowings to fund these deferrals and margin calls, coupled with rising interest rates in 2022, increased interest expense.
Inflation
We are experiencing inflationary pressures in multiple areas of our business. Most notably, higher power and natural gas costs have impacted utility margin, labor and benefits costs increased, and higher gasoline and diesel costs increased the cost to operate our vehicle fleet. We cannot estimate how long inflation will remain at elevated levels. However, we are working to mitigate these pressures by monitoring the power and natural gas markets and following our various hedging and risk mitigation plans. We also have our Jackson Prairie natural gas storage facility, which we use to optimize our system and limit our exposure to high natural gas prices. While we have various regulatory deferral and recovery mechanisms for our power and natural gas costs and we expect to ultimately recover these costs (subject to Company/customer sharing bands within the ERM, PCA and Oregon PGA), there will be a delay between the initial purchase of the commodities and recovery of these costs.
In addition to the above, our interest costs increased (and are expected to be higher in 2023) due to higher interest rates than those approved in our most recent general rate cases, as well as increased borrowing needs for energy commodity transacting.
Regulatory Lag
Regulatory “lag” is inherent in utility ratemaking due to the delay between the investment in utility plant and/or the increase in costs and the receipt of an order of a public utility commission authorizing an increase in rates sufficient to recover such investments or costs. Regulatory lag can be mitigated to some extent by the incorporation of reasonably expected forward-looking information into an authorization of increased rates. However, there is no protection against unexpected inflation and increased interest rates, as were experienced in 2022 and are continuing into 2023. While we believe that the 2022 Washington general rate settlement will be helpful, some increases in our operating expenses and interest costs will have to be addressed in future rate cases. See “Regulatory Matters” for additional discussion of the general rate cases.
Supply Chain Delays
We continue to experience supply chain delays due to, among other things, the combined effects of the COVID-19 pandemic, inflation, and staffing shortages across multiple industries. These various issues have impacted the delivery times of some of our materials and equipment and have made some materials and equipment difficult to acquire in the needed quantities. So far, the delays are being proactively mitigated with minimal impact, as we have modified project plans in response to extended lead time for our materials; and in some cases we have been able to locate new suppliers in other parts of the country or internationally. However, any problems that could result from future delays may affect the ability of suppliers or contractors to perform, which could increase our operating costs and delay and/or increase the cost of our capital projects.
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Climate Change
There is a trend of increasing average temperatures that has had, and will likely continue to have, various direct and indirect impacts on our business. Direct impacts include, without limitation, variations in the amount and timing of energy demand throughout the year, variations in the level and timing of precipitation throughout the year and the resulting impact on the availability of hydroelectric resources at times of peak demand. Indirect impacts include, without limitation, federal, state and local legislation or regulation (in effect and proposed) that limits (or eliminates) the use of fossil-fuel for electric generation, as well as the use of natural gas for heating in residential and commercial buildings.
For additional information regarding climate change, recent effects of climate change on our operations and results of operations, and legislation and/or regulation designed to mitigate climate change, see “Environmental Issues and Contingencies.”
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.
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 approving 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 incorporated 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.
Included in the WUTC order was the acceleration of depreciation of Colstrip Units 3 and 4 reflecting 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.
2020 General Rate Cases
In September 2021, the WUTC issued an order approving a partial multi-party settlement agreement and resolved all other remaining issues. The approved rates were designed to increase annual base electric revenues by $13.6 million, or 2.6 percent of base revenues, and annual natural gas base revenues by $8.1 million, or 7.7 percent of base revenues, effective October 1, 2021. The revenue increases were based on a 9.4 percent ROE with a common equity ratio of 48.5 percent and a ROR of 7.12 percent.
While base rates increased, there was no increase in billed rates because of the use of offsetting tax benefits.
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The WUTC's order approved recovery of capital additions including investments in advanced metering infrastructure, wildfire resiliency, joining the Western EIM, and other projects. The WUTC disallowed $2.5 million of costs associated with Colstrip SmartBurn technology.
The WUTC order also approved the Company's request to defer incremental wildfire expenses incurred during 2021, as well as a wildfire balancing account to track expenses associated with wildfire resiliency going forward.
2022 General Rate Cases
On December 12, 2022, the WUTC issued an order approving the multi-party settlement agreement that was filed in June 2022. The parties to the settlement agreement included, in addition to us, the Staff of the WUTC, the Alliance of Western Energy Consumers, the NW Energy Coalition, The Energy Project, Walmart, Small Business Utility Advocates and Sierra Club. The Public Counsel Unit of the Washington Attorney General’s Office (Public Counsel), while a party to the rate cases, did not join in the settlement agreement. The settlement agreement was reached after negotiation of all issues but is “results-focused” -- that is, it represents agreement among all parties (except Public Counsel) as to our overall revenue requirement, without specifying the details of any component except the rate of return on rate base.
On December 22, 2022, Public Counsel filed a Petition for Reconsideration requesting the WUTC to reconsider its ruling on the settlement agreement. Public Counsel’s primary issue is related to the “results-focused” approach used by the settling parties and approved by the WUTC. Public Counsel argues that the WUTC order approving this approach denied Public Counsel the right to offer evidence in opposition to a settlement or particular components, because there was no other way to oppose a “results-focused” revenue requirement with sufficient support. Public Counsel also argues that this procedure may effectively prevent parties in future rate cases from exercising their rights to oppose settlements.
On January 30, 2023, the WUTC issued an order denying the Petition for Reconsideration, stating Public Counsel was afforded every opportunity to exercise its rights to oppose the settlement, and reiterated that the end results of the settlement produced rates that were equitable, fair, just, reasonable and sufficient.
The approved rates are designed to increase annual base electric revenues by $38.0 million (or 6.9 percent), effective in December 2022, and $12.5 million (or 2.1 percent), effective in December 2023. The approved rates are designed to increase annual base natural gas revenues by $7.5 million (or 6.5 percent), effective in December 2022, and $1.5 million (or 1.2 percent), effective in December 2023.
To mitigate the overall impact of the revenue increases on customers, we will offset part of the 2022 base rate request with a tax customer credit. The total estimated benefits of this credit, $27.6 million for electric customers and $12.5 million for natural gas customers, will be returned over a two-year period from December 2022 to December 2024.
In addition, the order approved a separate tracking mechanism and tariff for purposes of recovering existing and prospective Colstrip costs.
The WUTC approved an ROR on rate base of 7.03 percent, but the settlement does not specify an explicit ROE, cost of debt or capital structure.
These general rate cases require a subsequent review of capital projects included in rates and a refund of revenues related to imprudent expenditures or those that are not used and useful.
Washington Engrossed Substitute Senate Bill 5295
This bill, which was signed into law and became effective in July 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, and specifies various 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
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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. The 2022 general rate cases, discussed above, are consistent with this legislation.
Idaho General Rate Cases and Other Proceedings
2021 General Rate Cases
In September 2021, the IPUC approved the all party settlement agreement 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 settlement agreement was 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 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 rates over the two-year plan.
The settlement was based on a 9.4 percent ROE with a common equity ratio of 50 percent and a ROR of 7.05 percent.
2023 General Rate Cases
In February 2023, we filed multiyear electric and natural gas general rate cases with the IPUC. If approved, new rates would be effective in September 2023 and September 2024.
The proposed rates are designed to increase annual base electric revenues by $37.5 million, or 13.6 percent, effective in September 2023, and $13.2 million, or 4.2 percent, effective in September 2024.
For natural gas, the proposed rates are designed to increase annual base natural gas revenues by $2.8 million, or 6.0 percent, effective September 2023, and $0.1 million, or 0.3 percent, effective September 2024.
The proposed electric and natural gas revenue increase requests are based on a ROR of 7.59 percent, with a common equity ratio of 50 percent and a ROE of 10.25 percent.
Ongoing capital infrastructure investment (including replacement of wood poles and natural gas distribution pipe, continued investment in the wildfire resiliency plan, and technology) is the main driver of the proposed increases.
The IPUC has up to nine months to review the general rate case filings and issue a decision.
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 January 2022, a partial settlement stipulation addressing cost of capital issues was filed with the OPUC in our natural gas general rate case filed in October 2021. 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.
In March 2022, a second settlement stipulation was filed with the OPUC that addressed, and resolved, all other remaining issues, and was subsequently approved by the OPUC. The settlement is designed for an overall revenue increase of $1.6 million, effective August 22, 2022. The agreement was a “black box”, with the only component of the revenue requirement explicitly stated is the previously-agreed upon cost of capital. The parties also agreed that certain tax credits of approximately $3.0 million will be passed through to customers to mitigate the base revenue increase.
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2023 General Rate Case
We expect to file our natural gas general rate case with the OPUC in the first quarter of 2023.
Alaska Electric Light and Power Company
2022 General Rate Case
In July 2022, AEL&P filed an electric general rate case with the Regulatory Commission of Alaska (RCA). The RCA approved an interim base rate increase of 4.5 percent (designed to increase annual electric revenues by $1.6 million), effective in September 2022. AEL&P also requested a permanent base rate increase of an additional 4.5 percent (designed to increase annual electric revenues by $1.6 million), which, if approved, could take effect in October 2023. The proposed revenue increase request is based on a 13.45 percent ROE with a common equity ratio of 60.7 percent and a ROR of 10.0 percent.
The RCA must rule on permanent rate increases within 450 days (approximately 15 months) from the date of filing.
Avista Utilities
Purchased Gas Adjustments
PGAs are designed to pass through changes in natural gas costs to 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 $52.1 million as of December 31, 2022 and $21.0 million as of December 31, 2021. These deferred natural gas cost balances represent amounts due from customers.
The following PGAs went into effect in our various jurisdictions during 2020 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 pending future prudence review and eventual recovery or rebate through retail rates. The power supply costs deferred include certain differences 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.
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For our Washington customers, the ERM is an accounting method used to track certain differences between actual power supply costs, net of the margin on wholesale sales of energy and fuel, and the amount included in base retail rates. Total net deferred power costs under the ERM were an asset of $30.5 million as of December 31, 2022 and a liability of $11.9 million as of December 31, 2021. The deferred power cost balance as of December 31, 2022 represents amounts due from customers.
Under the ERM, we absorb the cost or receive 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, we make 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 surcharge balance as of December 31, 2022 exceeded $30 million and as a result, we expect our April 2023 filing to contain a proposed rate surcharge to be received from customers over a one-year period, with new rates effective July 1, 2023.
We have a PCA mechanism in Idaho that allows us to modify electric rates on October 1 of each year with IPUC approval. Under the PCA mechanism, we defer 90 percent of the difference between certain actual net power supply expenses and the amount included in base retail rates for our Idaho customers. The October 1 rate adjustments recover or rebate power supply costs deferred during the preceding July-June twelve-month period. Total net power supply costs deferred under the PCA mechanism were assets of $16.3 million as of December 31, 2022 and $10.8 million as of December 31, 2021. 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' usage. In each of our jurisdictions, our electric and natural gas revenues are adjusted so as to be based on the number of customers in certain customer rate classes and assumed “normal” kilowatt hour and therm sales, rather than being based on actual kilowatt hour and therm sales. The difference between revenues based on the number of customers and “normal” sales and revenues based on actual usage is deferred and either surcharged or rebated to customers beginning in the following year. Only residential and certain commercial customer classes are included in our decoupling mechanisms.
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.
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. Through our 2022 general rate cases, we modified the earnings test so that if we earn more than 0.5 percent higher than the ROR authorized by the WUTC in the multi-year rate plan, these excess revenues would be deferred and later refunded to customers.
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Idaho FCA Mechanism
In Idaho, the IPUC approved the extensions of FCAs for electric and natural gas through March 31, 2025.
Oregon Decoupling Mechanism and Earnings Sharing
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 Balances
Total net cumulative decoupling deferrals among all jurisdictions was a regulatory liability of $18.2 million as of December 31, 2022 and a regulatory asset of $15.2 million as of December 31, 2021. The decoupling liability as of December 31, 2022 represents amounts due to customers.
See “Results of Operations - Avista Utilities” for further discussion of the amounts recorded to operating revenues in 2022 and 2021 related to the decoupling mechanisms.
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.
2022 compared to 2021
The following graph shows the total change in net income for 2022 to 2021, as well as the various factors that caused such change (dollars in millions):
Utility revenues increased at Avista Utilities primarily due to higher natural gas PGA rates, higher electric and natural gas customer usage due to weather, and customer growth for both electric and natural gas. Wholesale revenues also increased due to an increase in sales prices, as well as increased wholesale electric volumes.
Utility resource costs increased at Avista Utilities primarily due to increased market prices for purchased power and natural gas. See “Executive Level Summary” for further discussion of increased energy commodity market prices.
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The increase in utility operating expenses was primarily due to increases in labor and benefits costs, insurance costs, outside service expenses and information technology costs. Inflation broadly impacted our other operating expenses. See “Executive Level Summary” for discussion of inflation, which caused expenses to increase from 2021 to 2022.
Utility depreciation and amortization increased primarily due to additions to utility plant.
Income tax expense decreased primarily due to the recognition of income taxes related to our completed Idaho and Washington general rate cases in late 2021 which allowed for flow through treatment of certain tax items. Our effective tax rate for 2022 was negative 12.5 percent. See “Note 13 of the Notes to Condensed Consolidated Financial Statements” for further details and a reconciliation of our effective tax rate.
Interest expense increased due to higher interest rates associated with inflation, as well as increased borrowings during the fourth quarter of 2022 associated with energy commodity markets. See “Executive Level Summary” for further discussion of additional borrowings and inflation.
The increase in other was primarily related to an increase in the fair value of our investment in a biotechnology company, which stems from an investment that was originally focused on the development of biofuels. Their patented biological drug platform accelerates time to market for orally delivered antibody drugs and has advanced through testing stages, increasing the value of our investment. See “Note 7 of the Notes to Condensed Consolidated Financial Statements” for further discussion of our investment gains.
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 portion of our business has different cost sources, cost recovery mechanisms and jurisdictions, so we believe that separate analysis is beneficial. These measures are not intended to replace utility operating revenues as determined in accordance with GAAP as an indicator of operating performance. Reconciliations of operating revenues to utility margin are set forth below.
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Results of Operations - Avista Utilities
2022 compared to 2021
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.
Total electric operating revenues in the graph above include intracompany sales of $11.7 million and $28.7 million for 2022 and 2021, respectively.
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The following table presents the current year deferrals and the amortization of prior year decoupling balances that are reflected in utility electric operating revenues for the years ended December 31 (dollars in thousands):
Electric OperatingRevenues
Current year decoupling deferrals (a) $ (24,943 ) $ (6,053 )
Amortization of prior year decoupling deferrals (b) (6,901 ) (13,472 )
Total electric decoupling revenue $ (31,844 ) $ (19,525 )
(a)
Positive amounts are increases in decoupling revenue in the current year and will be surcharged to customers in future years. Negative amounts are decreases in decoupling revenue in the current year and will be rebated to customers in future years.
(b)
Positive amounts are increases in decoupling revenue in the current year and are related to the amortization of rebate balances that resulted in prior years and are being refunded to customers (causing a corresponding decrease in retail revenue from customers) in the current year. Negative amounts are decreases in decoupling revenue in the current year and are related to the amortization of surcharge balances that resulted in prior years and are being surcharged to customers (causing a corresponding increase in retail revenue from customers) in the current year.
Total electric revenues increased $139.7 million for 2022 as compared to 2021. The primary fluctuations that occurred during the period were as follows:
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a $33.6 million increase in retail electric revenues due to an increase in total MWhs sold (increased revenues $67.1 million), partially offset by a decrease in revenue per MWh (decreased revenues $33.5 million).
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The increase in total retail MWhs sold was primarily the result of residential customer growth, as well as increased customer use in the winter months due to weather that was colder than the prior year. Heating degree days in Spokane during 2022 were 4 percent above historical average, compared to 7 percent below historical average in 2021. This was partially offset by decreased usage in summer months as the weather was cooler than the prior year, with Spokane cooling degree days at 33 percent above historical average compared to 73 percent above historical average in the prior year. Compared to 2021, use per residential customer increased 3.5 percent, and use per commercial customer increased 0.3 percent.
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The decrease in revenue per MWh was primarily due to 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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an $89.5 million increase in wholesale electric revenues due to an increase in sales prices (increased revenues $52.9 million), and an increase in sales volumes (increased revenues $36.6 million). The fluctuation of volumes was due to increased hydroelectric generation and plant availability compared to the prior year which allowed us additional opportunity to optimize our generation assets. In addition, we joined the Western EIM during March 2022 which led to an increase in wholesale sales.
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a $20.6 million increase in sales of fuel due to thermal generation resource optimization activities.
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a $12.3 million decrease in electric decoupling revenue. The rebates in 2022 resulted from higher than normal usage from residential customers primarily due to colder weather in the winter months.
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an $8.4 million increase in other electric revenue, primarily due to increases in transmission revenues.
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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.
Total natural gas operating revenues in the graph above include intracompany sales of $54.8 million and $58.6 million for 2022 and 2021, 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) $ 2,493 $ 11,129
Amortization of prior year decoupling deferrals (b) (4,006 ) 1,761
Total natural gas decoupling revenue $ (1,513 ) $ 12,890
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(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 $110.2 million for 2022 as compared to 2021. The primary fluctuations that occurred during the period were as follows:
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a $104.8 million increase in retail natural gas revenues (including industrial, which is included in other) due to higher retail rates (increased revenues $64.8 million), and higher sales volumes (increased revenues $40.0 million).
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Retail rates increased due to PGA rate increases in all jurisdictions (which do not impact utility margin). The increase in PGA rates reflects higher natural gas commodity prices.
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Retail natural gas sales increased primarily due to higher residential and commercial usage due to colder weather, as well as residential and commercial customer growth. Compared to 2021, residential use per customer increased 8.7 percent and commercial use per customer increased 11.8 percent. Heating degree days in Spokane were 11 percent above 2021.
•
a $19.9 million increase in wholesale natural gas revenues due to an increase in prices (increased revenues $56.4 million) partially offset by a decrease in volumes (decreased revenues $36.5 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.
•
a $14.4 million decrease in decoupling revenues primarily due to decreased surcharges in the current year associated with increased usage compared to 2021. In addition, we were able to recognize decoupling amounts related to 2021 that we were unable to recognize during the prior year due to our inability to collect them within 24 months.
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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 $54.8 million and $58.6 million for 2022 and 2021, respectively.
Total electric resource costs increased $121.0 million for 2022 as compared to 2021. The primary fluctuations that occurred during the period were as follows:
•
a $33.6 million increase in power purchased due to an increase in wholesale prices (increased costs by $29.0 million), and an increase in the volume of power purchases (increased costs by $4.6 million). In particular, prices increased significantly during the fourth quarter of 2022 as discussed in “Executive Level Summary”.
•
an $81.6 million increase in fuel for generation primarily due to higher natural gas fuel prices (including increases in December 2022 as discussed in “Executive Level Summary”) and increased thermal generation.
•
a $21.2 million increase in other fuel costs. This represents fuel and the related derivative instruments that were purchased for generation but later sold when conditions indicated that it was more economical to sell the fuel as part of the resource optimization process. When the fuel or related derivative instruments are sold, that revenue is included in sales of fuel.
•
a $15.4 million decrease in other electric resource costs, primarily related to the deferral of increased power supply costs above authorized under the ERM and PCA mechanisms.
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AVISTA CORPORATION
Total natural gas resource costs in the graph above include intracompany resource costs of $11.7 million and $28.7 million for 2022 and 2021, respectively.
Total natural gas resource costs increased $97.1 million for 2022 as compared to 2021. The primary fluctuations that occurred during the period were as follows:
•
a $102.5 million increase in natural gas purchased due to increases in the price of natural gas (increased costs by $122.2 million) which was partially offset by a decrease in total therms purchased (decreased costs $19.7 million).
•
a $5.4 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 $18.7 million and natural gas utility margin increased $13.1 million.
Electric utility margin increased primarily due to the impacts of general rate cases, as well as customer growth. This was partially offset by an increase in net power supply costs as compared to the prior year. For 2022, we had a $10.9 million pre-tax expense under the ERM in Washington, compared to a $7.7 million pre-tax expense in 2021.
Natural gas utility margin increased primarily due to customer growth.
Intracompany revenues and resource costs represent purchases and sales of natural gas between our natural gas distribution operations and our electric generation operations (as fuel for our generation plants). These transactions are eliminated in the presentation of total results for Avista Utilities and in the consolidated financial statements but are included in the separate results for electric and natural gas presented above.
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Results of Operations - Alaska Electric Light and Power Company
2022 compared to 2021
Net income for AEL&P was $7.5 million for the year ended December 31, 2022, compared to $7.2 million for 2021.
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 2022 primarily due to higher sales volumes to residential customers and decreased resource costs for 2022 as compared to 2021.
Results of Operations - Other Businesses
2022 compared to 2021
Our other businesses had net income of $29.7 million for 2022 compared to net income of $14.6 million for 2021. The increase in net income primarily relates to an increase in the fair value of our investment in a biotechnology company, which stems from an investment that was originally focused on the development of biofuels. Their patented biological drug platform accelerates time to market for orally delivered antibody drugs and has advanced through testing stages, increasing the value of our investment.
Accounting Standards to be Adopted in 2023
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 2023. For more information on accounting standards expected to be adopted in future periods, see "Note 2 of the Notes to the 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 ASC 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 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 no longer met the criteria to apply regulatory accounting or no longer allowed recovery of these costs, we would 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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•
Equity investments, specifically valuations performed to determine the fair value of certain investment holdings, require judgement in the selection of assumptions used to estimate fair value of investments for which there is not a quoted active market price. We primarily use a market approach to determine fair value of an investment, and transactions involving comparable securities may need to be adjusted to estimate our investment's fair value. See “Notes 7 and 18 of the Notes to Consolidated Financial Statements” for further discussion of our equity investments and method for determining their fair value.
•
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. To the extent material, 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 12 of the Notes to Consolidated Financial Statements” for further discussion of these individual plans.
Pension costs (including the SERP) were $22.8 million for 2022, $19.3 million for 2021 and $22.3 million for 2020. Included in our 2022 pension costs is $11.8 million of settlement costs, which were deferred as a regulatory asset and therefore do not impact our net income for the year. See “Note 12 of the Notes to Consolidated Financial Statements” for further discussion of pension settlement accounting treatment. 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.
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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.
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 $ (198.3 ) $ (15.6 ) $ 62.6
Return on plan assets (a)
Expected long-term return on plan assets 5.80 % 5.40 % 5.50 %
Increase/(decrease) to pension costs $ (3.0 ) $ 0.7 $ 2.5
Actual return on plan assets, net of fees (21.80 )% 7.10 % 15.20 %
Actual gain (loss) on plan assets $ (163.9 ) $ 50.4 $ 96.6
(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 )% $ — * $ 3.8
Expected long-term return on plan assets 0.5 % — * (3.8 )
*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 regularly file for rate adjustments for recovery of operating costs and capital investments and to seek the opportunity to earn reasonable returns.
We have 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 customers, net cash flows
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are negatively affected. Factors that could cause purchased power and natural gas costs to exceed the levels currently recovered from customers under base rates include, but are not limited to, higher prices in wholesale markets and/or an increased need to purchase power in the wholesale markets, and a lack of regulatory approval for higher authorized net power supply costs. 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 weather (possibly due to climate change) or customer growth),
•
reduced snowpack or lower streamflows (due to weather (possibly due to climate change)) 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, we enter into derivative instruments to hedge exposure to certain risks, including fluctuations in commodity prices, foreign exchange rates and interest rates (for purposes of issuing long-term debt in the future). These derivative instruments periodically require us to post collateral (in the form of cash or letters of credit) or other credit enhancements or to reduce or terminate a portion of the contract through cash settlement, in the event of a downgrade in our 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 our cash on hand and credit facilities. 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. In December 2022, increased energy commodity market prices significantly impacted our liquidity, resulting in us entering new credit agreements. See “Executive Level Summary” for further discussion on increased commodity prices and liquidity impacts.
Material contractual obligations that demand cash arise in the normal course of business including energy purchase contracts and contractual obligations related to generation facilities and transmission and distributions services. See “Note 14 of the Notes to Consolidated Financial Statements” for additional information related to these contractual obligations.
Additional demands for cash include payments of borrowings and interest payments (see “Notes 15-17 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 12 of the Notes to Consolidated Financial Statements”) and investment fund commitments (see “Note 6 of the Notes to Consolidated Financial Statements”).
See discussion in “Capital Resources” below for available liquidity under our credit facilities. With our available liquidity under these agreements, we believe that we have adequate liquidity to meet our needs for the next 12 months.
Review of Consolidated Cash Flow Statement
2022 compared to 2021
Consolidated Operating Activities
Net cash provided by operating activities was $124.2 million for 2022 compared to $267.3 million for 2021. The decrease in net cash provided by operating activities primarily relates to an increase in cash collateral posted for derivative investments, which decreased cash flows by $141.0 million in 2022 compared to $17.6 million in 2021. Collateral calls increased significantly during December 2022, associated with increases in power and natural gas prices (see discussion in “Executive Level Summary”). During 2022 there was also an increase in power and natural gas cost deferrals (reflecting higher power and natural gas supply costs), which decreased cash flows by $78.4 million in 2022 compared to decreasing cash flows by $51.8 million in 2021. In addition, the provision for deferred taxes decreased operating cash flows in 2022 by $18.2 million compared to increasing operating cash flows by $11.2 million in 2021.
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These decreases in operating cash flows were partially offset by an increase in the decoupling deferrals, which increased operating cash flows by $33.5 million compared to $6.1 million in 2021.
Consolidated Investing Activities
Net cash used in investing activities was $460.2 million for 2022, an increase compared to $444.9 million for 2021. During 2022, we paid $452.0 million for utility capital expenditures, compared to $439.9 million for 2021.
Consolidated Financing Activities
Net cash provided by financing activities was $327.3 million for 2022 compared to $185.5 million for 2021. The increase in financing cash flows was primarily the result of increases in short-term borrowings of $98.0 million compared to 2021. Increased borrowing needs in 2022 were a direct result of increased power and natural gas prices experienced in December 2022, as discussed in “Executive Level Summary”. In addition, there was an increase in proceeds from issuance of common stock of $47.8 million compared to 2021.
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, 2022 and 2021 (dollars in thousands):
Amount Percentof total Amount Percentof total
Our shareholders’ equity increased $179.9 million during 2022 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.
Short Term Borrowings
Avista Corp.
Avista Corp. has a committed line of credit 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).
In December 2022, we experienced increases in commodity prices that resulted in needs for additional liquidity. See “Executive Level Summary” for further discussion on this market volatility and liquidity impacts.
In November 2022, we entered into a revolving credit agreement in the amount of $50 million with a maturity date in November 2023. In December 2022, the agreement was amended to add an additional $50 million, bringing the new aggregate total to $100 million.
In December 2022, we entered into a term loan, in the amount of $100 million with a maturity date of March 30, 2023. The initial agreement included an option to add an additional $50 million in principal as an incremental facility, which we exercised in December 2022, bringing the total aggregate amount to $150 million.
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In December 2022, we entered into a continuing letter of credit agreement in the aggregate amount of $50 million. Either party may terminate the agreement at any time.
The following table summarizes the balances outstanding and available liquidity as of December 31, 2022 (dollars in thousands):
(1)
Letters of credit are not reflected on the Consolidated Balance Sheets. If a letter of credit were drawn upon by the holder, we would have an immediate obligation to reimburse the bank that issued that letter.
The Avista Corp. credit facilities contain customary covenants and default provisions, including a change in control (as defined in the agreements). The events of default under each of the credit facilities also include a cross default from other indebtedness (as defined) and in some cases other obligations. Some of these agreements also include 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, 2022, we were in compliance with this covenant with a ratio of 55.6 percent.
Balances outstanding and interest rates on borrowings (excluding letters of credit) under Avista Corp.'s lines of credit were as follows as of and for the year ended December 31 (dollars in thousands):
$400 million line of credit, expiring June 2026
Maximum balance outstanding during the year $ 345,000 $ 338,000
Average interest rate during the year 3.06 % 1.14 %
Average interest rate at end of year 5.31 % 1.11 %
$100 million line of credit, expiring November 2023
Maximum balance outstanding during the period (1) $ 77,000 N/A
Average balance outstanding during the period (1) 15,656 N/A
Average interest rate during the period (1) 7.56 % N/A
Average interest rate at end of year N/A N/A
(1)
The period is from the date the agreement was entered (November 30, 2022) to the end of 2022.
AEL&P
AEL&P has a $25.0 million committed line of credit with an expiration date in November 2024. As of December 31, 2022, there was $25.0 million of available liquidity under this line of credit.
The AEL&P credit facility contains customary covenants and default provisions including a covenant which does not permit the ratio of “consolidated total debt at AEL&P” to “consolidated total capitalization at AEL&P,” (including the impact of the Snettisham obligation) to be greater than 67.5 percent at any time. As of December 31, 2022, AEL&P was in compliance with this covenant with a ratio of 50.8 percent.
As of December 31, 2022, 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.
Long-Term Debt
In March 2022, we issued and sold $400.0 million of 4.00 percent first mortgage bonds due in 2052 through a public offering. The total net proceeds from the sale of the bonds were used to repay the borrowings outstanding under the Company’s $400.0 million committed line of credit in March 2022. In April 2022, the Company used the remainder of the proceeds, as well as
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borrowings on committed line of credit to pay $250.0 million of maturing debt. In connection with the pricing of the first mortgage bonds in March 2022, we cash-settled thirteen interest rate swap derivatives (notional aggregate amount of $140.0 million) and paid a net amount of $17.0 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 4.32 percent, including the effects of the settled interest rate swap derivatives and issuance costs.
Common Stock
We issued common stock in 2022 for total net proceeds of $137.8 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, with the balance related to compensation plans. We have board and regulatory authority to issue a maximum of 5.6 million shares, of which 2.3 million remain unissued as of December 31, 2022. In 2022, 3.3 million shares were issued under these agreements resulting in total net proceeds of $137.2 million.
2023 Liquidity Expectations
During 2023, we expect to issue up to $200 million of long-term debt and $120 million of common stock to fund planned capital expenditures and decrease short-term borrowings. We also plan to increase the capacity of our $400 million credit facility to $500 million in the second quarter.
After considering the expected issuances of long-term debt and common stock during 2023, we expect net cash flows from operating activities (including recovery of deferred power and natural gas costs and return of margin deposits made with counterparties), together with cash available under our credit facilities, 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, 2022, we could issue $1.4 billion of preferred stock at an assumed dividend rate of 7.6 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
•
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, 2022, property additions and retired bonds would have allowed, and the net earnings test would not have prohibited, the issuance of $1.4 billion in aggregate principal amount of additional first mortgage bonds at Avista Corp. and $40.4 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.
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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, 2022 (dollars in thousands):
Avista Utilities AEL&P
2022 Actual capital expenditures
Expected total annual capital expenditures (by year)
The following graph shows Avista Utilities' expected capital expenditures for 2023-2025 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, venture capital
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funds, and other business ventures. 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, 2022 (dollars in thousands):
Other
2022 Actual investments and capital expenditures
Investments and capital expenditures $ 14,172
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 2023 and thereafter.
Pension Plan
We contributed $42.0 million to the pension plan in 2022. We expect to contribute a total of $50.0 million to the pension plan in the period 2023 through 2027, with an annual contribution of $10.0 million.
The final determination of pension plan contributions for future periods is subject to multiple variables, most of which are beyond our control, including changes to the fair value of pension plan assets, changes in actuarial assumptions (in particular the discount rate used in determining the benefit obligation), or changes in federal legislation. We may change our pension plan contributions in the future depending on changes to any variables, including those listed above.
See “Note 12 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 8 of the Notes to Consolidated Financial Statements.”
The following table summarizes our credit ratings as of February 21, 2023:
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
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“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 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. 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 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
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•
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, 2022 showed positive job growth with lower unemployment rates in all three metropolitan areas. 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 slowing growth over the next 12 months. Considering all relevant indicators, we expect economic growth in our service area in 2023 to be in-line with the U.S. as a whole.
Nonfarm employment (seasonally adjusted) in our service areas increased in 2022. In Spokane, Washington employment increased 4.4 percent with gains in all major sectors. Employment increased 2.8 percent in Coeur d'Alene, Idaho, reflecting gains in all major sectors except financial activities. In Medford, Oregon, employment increased 1.0 percent, with gains in all major sectors except trade, transportation, and utilities; manufacturing; information; and professional and business services. U.S. nonfarm sector employment increased 4.0 percent over the same period.
In Spokane the unemployment rate was 5.5 percent in 2021 and fell to 4.6 percent in 2022; in Coeur d'Alene the rate fell from 4.3 percent in 2021 to 3.3 percent in 2022; and in Medford the rate fell from 5.4 percent in 2021 to 4.4 percent in 2022. The U.S. unemployment rate fell from 5.4 percent in 2021 percent to 3.6 percent in 2022. Data regarding local and national unemployment rates were determined by and obtained from third parties. We have made no independent determination or verification of this data or any investigation into the methodologies used to determine the data.
Alaska Electric Light and Power Company
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 8.7 percent between the first half of 2021 and first half of 2022. This high growth reflects an employment recovery following the pandemic induced job losses. There were employment gains in all major sectors, except financial activities and government. Government employment declined 0.8 percent during this period; this sector accounted for 39 percent of total employment in the second half of 2022. Between 2021 and 2022, the unemployment rate fell from 4.7 percent to 3.0 percent.
Forecasted Customer and Load Growth
Based on our forecast for 2023 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 1.3 percent, within a forecast range of 0.4 percent to 2.2 percent. We anticipate retail electric load growth to average 0.4 percent, within a forecast range of 0 percent and 0.8 percent. We expect natural gas load growth to average 1.0 percent, within a forecast range of 0.4 percent and 1.6 percent. The forecast ranges reflect (1) the inherent uncertainty associated with the economic assumptions on which forecasts are based; (2) the historic variability of natural gas customer and load growth; and (3) new restrictions on natural gas connections in our Washington service area. See further discussion regarding these natural gas regulations as included in “Environmental Issues and Contingencies” below.
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In AEL&P's service area, we expect no growth in residential, commercial and government customers in 2023. We anticipate average total load growth will decrease 1.6 percent, with residential load growth decreasing 1.9 percent, commercial load decreasing 1.3 percent, and government load decreasing 1.6 percent.
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:
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assumptions relating to weather and economic and competitive conditions,
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internal analysis of company-specific data, such as energy consumption patterns,
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internal business plans,
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an assumption that we will incur no material loss of retail customers due to self-generation or retail wheeling, and
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an assumption that demand for electricity and natural gas as a fuel for mobility will for now be immaterial.
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.
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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 plans to exit Colstrip through our agreement with NorthWestern. Our hydroelectric and biomass generation facilities can be used to 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). 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 (GHG) neutral by 2030 and 100 percent renewable or generated from zero-carbon resources by 2045.
In June 2022, our CEIP was approved by the WUTC.
Some highlights of our approved plan include:
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Beginning in 2022, serving 40 percent of our Washington retail customer demand with renewable (or zero carbon) energy, then increase this target to 62.5 percent by the end of 2025.
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Energy efficiency targets to reduce Washington retail customer load by approximately 2 percent over the next four years through incentives and programs to lower energy use without impacting the customer.
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A set of 14 Customer Benefit Indicators to ensure the equitable distribution of energy and non-energy benefits and reduction of burden to all customers and named communities.
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A Named Communities Investment Fund that will invest up to $5 million annually in projects, programs and initiatives that directly benefit customers residing in historically disadvantaged and vulnerable communities.
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. We are required to file a CEIP every four years.
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.
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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 D.C. Circuit’s January 2021 decision, and in October 2021, the Supreme Court granted such review. In June 2022, the Supreme Court reversed the D.C. Circuit and found that, under the major questions doctrine, the generation shifting approach to controlling greenhouse gas emissions used by the EPA in the Federal CPP exceeded the powers granted to the agency by Congress.
The Court's decision left open the question of whether, and to what extent, the EPA can seek to curb greenhouse gas emissions through methods other than generation shifting. At this time, the EPA has not released a proposed successor rule to the Federal CPP, nor has it sought to amend the ACE Rule, which is still subject to the D.C. Circuit Court's January 2021 decision. Consequently, 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 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.
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Washington Climate Commitment Act
In 2021, the Washington legislature passed the Climate Commitment Act (CCA) which establishes a cap and trade program to reduce greenhouse gas emissions and achieve the greenhouse gas limits previously established under state law. The CCA directs the Washington Department of Ecology (Ecology) to develop regulations implementing the cap and trade program and related efforts. Ecology recently issued final rules that became effective November 1, 2022. These rules implement a cap on greenhouse gas emissions, provide mechanisms for the sale and tracking of tradable emissions allowances and establish additional compliance and accountability measures. Our electric and natural gas businesses will be impacted by these regulations. The CCA is intended to be consistent with CETA for electric utilities covered by both rules and is not intended to create a secondary financial burden in addition to the costs of complying with CETA. We are continuing to evaluate the impact of these rules on our operations and costs of providing service. We intend to seek recovery of costs associated with implementing the CCA through the ratemaking process.
Washington State Building Codes
In April 2022, the Washington State Building Code Council (SBCC) approved a revised energy code that requires most new commercial buildings and large multifamily buildings to install all-electric space heating. However, an amendment to the code does allow for natural gas to supplement electric heat pumps. Additionally, in November 2022, SBCC approved new building and energy codes for residential housing, requiring new residential buildings in Washington to use electricity as the primary heating source. The State Legislature has the opportunity to reject or alter these new codes during their Regular Session. If there is no action by the Legislature, the new codes will take effect in July 2023.
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 (GHG)-related matters, with the aim of reducing Oregon’s overall GHG emissions to 80 percent below 1990 levels by 2050. This Executive Order led to the Oregon Department of Environmental Quality developing cap and reduce rules known as the Climate Protection Program (CPP). The CPP, which became effective in January 2022, outlines GHG emissions reduction goals of 50 percent by 2035 and 90 percent by 2050 from the 1990 baseline. The first three-year compliance period is 2022 through 2024. We are subject to the CPP and, pursuant to the rule, we are required to make our first compliance filing in 2025. We intend to seek recovery of compliance costs related to the CPP through the ratemaking process.
In March 2022, we, along with the utilities NW Natural and Cascade Natural Gas, filed a lawsuit requesting judicial review of the CPP. This action was subsequently consolidated with a lawsuit filed by several other parties, and remains pending.
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 percent 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
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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 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 and 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.
Inflation Reduction Act (IRA)
The IRA was signed into law in August 2022. Among the provisions included in the act are a new corporate alternative minimum tax, which is applicable to corporations with average adjusted financial statement income over a three-year period in excess of $1 billion, as well as tax incentives for clean energy. We do not expect the corporate alternative minimum tax to impact our results. The tax incentives for clean energy could result in potential opportunities, however we cannot reasonably estimate the future impact.
Cabinet Gorge Total Dissolved Gas Abatement Plan
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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 and 4. The other owners are Puget Sound Energy, Inc., Portland General Electric Company, NorthWestern, Pacificorp and Talen Montana, LLC (which is also the operator of the plant). In January 2020, the owners of Units 1 and 2, in which the Company has no ownership, closed those two units. The owners of Units 3 and 4 currently share operating and capital costs pursuant to the terms of an operating agreement among them (the Ownership and Operation Agreement). In January 2023, we entered into an agreement with NorthWestern to transfer our ownership of Colstrip. See “Note 22 of the Notes to Consolidated Financial Statements” for further discussion of the agreement.
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 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.
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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.