AVISTA CORPORATION 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 endedDecember 31, 2021 .
Business Segments
As ofDecember 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 ofAvista 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 endedDecember 31 (dollars in thousands): 2022 2021 2020 Avista Utilities$ 117,901 $ 125,558 $ 124,810 AEL&P 7,545 7,224 8,095 Other 29,730 14,552 (3,417 ) Net income$ 155,176 $ 147,334 $ 129,488 Executive Level Summary Overall Results
Net income was
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 OnJanuary 16, 2023 , we entered into an agreement withNorthWestern under which, subject to the terms and conditions in the agreement, we will transfer our 15 percent ownership in Colstrip Units 3 and 4, toNorthWestern . There is no monetary exchange included in the transaction. The transaction is scheduled to close onDecember 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
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Liquidity and Increased Resource Pricing
Starting inDecember 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 onMarch 30, 2023 , a$100 million revolving line of credit expiring onNovember 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 ourJackson 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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AVISTA CORPORATION 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 MattersGeneral Rate Cases We regularly review the need for electric and natural gas rate changes in each state in which we provide service. We will continue to file for rate adjustments to:
•
seek recovery of operating costs and capital investments, and
•
seek the opportunity to earn reasonable returns as allowed by regulators.
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.
Washington General Rate Cases and Other Proceedings
2019
InMarch 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, effectiveApril 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 ofColstrip Units 3 and 4 reflecting a remaining useful life throughDecember 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 ofColstrip , 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 ofColstrip .
Lastly, the order included the extension of electric and natural gas decoupling
mechanisms through
2020
InSeptember 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, effectiveOctober 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
OnDecember 12, 2022 , the WUTC issued an order approving the multi-party settlement agreement that was filed inJune 2022 . The parties to the settlement agreement included, in addition to us, the Staff of the WUTC, theAlliance of Western Energy Consumers , theNW Energy Coalition ,The Energy Project , Walmart,Small Business Utility Advocates andSierra Club . The Public Counsel Unit of theWashington 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. OnDecember 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
The approved rates are designed to increase annual base electric revenues by$38.0 million (or 6.9 percent), effective inDecember 2022 , and$12.5 million (or 2.1 percent), effective inDecember 2023 . The approved rates are designed to increase annual base natural gas revenues by$7.5 million (or 6.5 percent), effective inDecember 2022 , and$1.5 million (or 1.2 percent), effective inDecember 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 fromDecember 2022 toDecember 2024 .
In addition, the order approved a separate tracking mechanism and tariff for
purposes of recovering existing and prospective
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 inJuly 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. OnOctober 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 43
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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
2021
InSeptember 2021 , the IPUC approved the all party settlement agreement designed to increase annual base electric revenues by$10.6 million , or 4.3 percent, effectiveSeptember 1, 2021 , and$8.0 million , or 3.1 percent, effectiveSeptember 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, effectiveSeptember 1, 2021 , and increase annual base revenues by$0.9 million , or 2.2 percent, effectiveSeptember 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
InFebruary 2023 , we filed multiyear electric and natural gas general rate cases with the IPUC. If approved, new rates would be effective inSeptember 2023 andSeptember 2024 . The proposed rates are designed to increase annual base electric revenues by$37.5 million , or 13.6 percent, effective inSeptember 2023 , and$13.2 million , or 4.2 percent, effective inSeptember 2024 . For natural gas, the proposed rates are designed to increase annual base natural gas revenues by$2.8 million , or 6.0 percent, effectiveSeptember 2023 , and$0.1 million , or 0.3 percent, effectiveSeptember 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
InMarch 2020 , we filed a natural gas general rate case with the OPUC. Through several settlement stipulations the parties resolved all issues and, inDecember 2020 , the OPUC approved all stipulations. The new rates were designed to increase annual base revenue by$3.9 million , or 5.7 percent effectiveJanuary 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
InJanuary 2022 , a partial settlement stipulation addressing cost of capital issues was filed with the OPUC in our natural gas general rate case filed inOctober 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. InMarch 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 , effectiveAugust 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. 44
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AVISTA CORPORATION 2023General Rate Case
We expect to file our natural gas general rate case with the OPUC in the first quarter of 2023.
2022
InJuly 2022 , AEL&P filed an electric general rate case with theRegulatory 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 inSeptember 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 inOctober 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.
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. InOregon , 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 ofDecember 31, 2022 and$21.0 million as ofDecember 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: Percentage Increase / (Decrease) in Billed Jurisdiction PGA Effective Date Rates Washington November 1, 2020 (0.1)% November 1, 2021 10.6% July 1, 2022 12.6% November 1, 2022 12.3% Idaho November 1, 2020 0.7% September 1, 2021 13.5% February 1, 2022 8.1% July 1, 2022 10.5% November 1, 2022 12.7% Oregon November 1, 2020 2.8% November 1, 2021 9.6% November 1, 2022 16.9%
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 byAvista Utilities and the costs included in base retail rates. These differences primarily result from changes in:
•
short-term wholesale market prices and sales and purchase volumes,
•
the level, availability and optimization of hydroelectric generation,
•
the level, availability and optimization of thermal generation (including changes in fuel prices),
• retail loads, and
•
sales of surplus transmission capacity.
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For ourWashington 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 ofDecember 31, 2022 and a liability of$11.9 million as ofDecember 31, 2021 . The deferred power cost balance as ofDecember 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:
Deferred for
Future
Surcharge or Expense or
Rebate Benefit
Annual Power Supply Cost Variability to Customers to the Company
within +/-
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 aFCA inIdaho ) 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
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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AVISTA CORPORATION Idaho FCA Mechanism
In
Oregon Decoupling Mechanism and Earnings Sharing
InOregon , 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 ofDecember 31, 2022 and a regulatory asset of$15.2 million as ofDecember 31, 2021 . The decoupling liability as ofDecember 31, 2022 represents amounts due to customers.
See "Results of Operations -
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):
[[Image Removed: img149240862_4.jpg]]
Utility revenues increased atAvista 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 atAvista 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. 47
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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 completedIdaho andWashington 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 forAvista 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 forAvista 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. 48
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Results of Operations -
2022 compared to 2021
Utility Operating Revenues
The following graphs presentAvista Utilities' electric operating revenues and megawatt-hour (MWh) sales for the years endedDecember 31 (dollars in millions and MWhs in thousands):
[[Image Removed: img149240862_5.jpg]]
(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
[[Image Removed: img149240862_6.jpg]]
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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 endedDecember 31 (dollars in thousands): Electric Operating Revenues 2022 2021 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
•
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 ).
•
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 inSpokane 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, withSpokane 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.
•
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.
•
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 duringMarch 2022 which led to an increase in wholesale sales.
•
a
•
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.
•
an
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The following graphs presentAvista Utilities' natural gas operating revenues and therms delivered for the years endedDecember 31 (dollars in millions and therms in thousands):
[[Image Removed: img149240862_7.jpg]]
(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
[[Image Removed: img149240862_8.jpg]]
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
Natural Gas
Operating Revenues
2022 2021
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 51
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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
•
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 ).
•
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.
•
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 inSpokane 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. 52
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AVISTA CORPORATION Utility Resource Costs
The following graphs present
[[Image Removed: img149240862_9.jpg]]
Total electric resource costs in the graph above include intracompany resource
costs of
Total electric resource costs increased
•
a
•
an$81.6 million increase in fuel for generation primarily due to higher natural gas fuel prices (including increases inDecember 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. 53
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[[Image Removed: img149240862_10.jpg]]
Total natural gas resource costs in the graph above include intracompany
resource costs of
Total natural gas resource costs increased
•
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
Utility Margin
The following table reconcilesAvista 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 endedDecember 31 (dollars in thousands): Electric Natural Gas Intracompany Total 2022 2021 2022 2021 2022 2021 2022 2021
Operating revenues
458,905 337,866 339,886
242,789 (66,493 ) (87,366 ) 732,298 493,289
Utility margin
Electric utility margin increased
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 inWashington , compared to a$7.7 million pre-tax expense in 2021.
Natural gas utility margin increased primarily due to customer growth.
Intracompany revenues and resource costs represent purchases and sales of natural gas between our natural gas distribution operations and our electric generation operations (as fuel for our generation plants). These transactions are eliminated in the presentation of total results forAvista Utilities and in the consolidated financial statements but are included in the separate results for electric and natural gas presented above. 54
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Results of Operations -
2022 compared to 2021
Net income for AEL&P was
The following table presents AEL&P's operating revenues, resource costs and resulting utility margin for the years endedDecember 31 (dollars in thousands): Electric 2022 2021 Operating revenues$ 45,704 $ 45,366 Resource costs 3,564 3,834 Utility margin$ 42,140 $ 41,532 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 -
We have a defined benefit pension plan covering substantially all regular full-time employees atAvista Utilities that were hired prior toJanuary 1, 2014 . For substantially all regular non-union full-time employees atAvista Utilities who were hired on or afterJanuary 1, 2014 , a defined contribution 401(k) plan replaced the defined benefit pension plan. Union employees hired on or afterJanuary 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):
2022 2021 2020
Discount rate (exclusive of SERP) Pension discount rate 6.10 % 3.39 % 3.25 % 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
(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):
Effect on
Projected
Change in Benefit Effect on
Actuarial Assumption Assumption Obligation Pension Cost
Expected long-term return on plan assets (0.5 )% $ - * $ 3.8
Expected long-term return on plan assets 0.5 % - * (3.8 )
Discount rate (0.5 )% 28.8 5.0
Discount rate 0.5 % (26.2 ) 3.4
* 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 ofAvista Utilities . The primary source of operating cash flows forAvista Utilities is revenues from sales of electricity and natural gas. Significant uses of cash flows fromAvista 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. InDecember 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 duringDecember 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. 58
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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 inDecember 2022 , as discussed in "Executive Level Summary". In addition, there was an increase in proceeds from issuance of common stock of$47.8 million compared to 2021.
Capital Resources
Capital Structure
Our consolidated capital structure, including the current portion of long-term debt and short-term borrowings consisted of the following as ofDecember 31, 2022 and 2021 (dollars in thousands): December 31, 2022 December 31, 2021 Percent Percent Amount of total Amount of total Current portion of long-term debt and leases$ 21,084 0.4 %$ 257,386 5.4 % Short-term borrowings 463,000 8.8 % 284,000 6.0 % Long-term debt to affiliated trusts 51,547 1.0 % 51,547 1.1 % Long-term debt and leases 2,387,792 45.4 % 2,010,168 42.1 % Total debt 2,923,423 55.6 % 2,603,101 54.7 %Total Avista Corporation shareholders' equity 2,334,668 44.4 % 2,154,744 45.3 % Total$ 5,258,091 100.0 %$ 4,757,845 100.0 %
Our shareholders' equity increased
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. has a committed line of credit in the total amount of$400.0 million . InJune 2021 , we entered into an amendment that extends the expiration date toJune 2026 , with the option to extend for an additional one year period (subject to customary conditions).
In
In
InDecember 2022 , we entered into a term loan, in the amount of$100 million with a maturity date ofMarch 30, 2023 . The initial agreement included an option to add an additional$50 million in principal as an incremental facility, which we exercised inDecember 2022 , bringing the total aggregate amount to$150 million . 59
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InDecember 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
Amount Letters of Credit Available
Aggregate Amount Outstanding Outstanding (1) Liquidity
Line of Credit expiring
June 2026 $ 400,000 $ 313,000 $ 35,563 $ 51,437
Line of Credit expiring
November 2023 100,000 - N/A 100,000
Term Loan due March 2023 150,000 150,000 N/A -
Letter of Credit Facility 50,000 N/A 18,500 31,500
Total $ 700,000 $ 463,000 $ 54,063 $ 182,937
(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.
TheAvista 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 ofDecember 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
2022 2021
$400 million line of credit, expiring June 2026
Maximum balance outstanding during the year $ 345,000 $ 338,000
Average balance outstanding during the year 205,947
208,629
Average interest rate during the year 3.06 % 1.14 % Average interest rate at end of year 5.31 % 1.11 %$100 million line of credit, expiringNovember 2023 Maximum balance outstanding during the period (1)$ 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 (
AEL&P AEL&P has a$25.0 million committed line of credit with an expiration date inNovember 2024 . As ofDecember 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 ofDecember 31, 2022 , AEL&P was in compliance with this covenant with a ratio of 50.8 percent. As ofDecember 31, 2022 ,Avista Corp. and its subsidiaries were in compliance with all of the covenants of their financing agreements, and none ofAvista Corp.'s subsidiaries constituted a "significant subsidiary" as defined inAvista Corp.'s committed line of credit.
Long-Term Debt
InMarch 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 inMarch 2022 . InApril 2022 , the Company used the remainder of the proceeds, as well as 60
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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 inMarch 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 ofDecember 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 ofDecember 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 theAvista Corp. and the AEL&P Mortgages and Deeds of Trust securingAvista 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 ofDecember 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 atAvista 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. 61
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AVISTA CORPORATION 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 endedDecember 31, 2022 (dollars in thousands):Avista Utilities
AEL&P
2022 Actual capital expenditures Capital expenditures (per the Consolidated Statement of Cash Flows)
$ 443,373 Expected total annual capital expenditures (by year) 2023 $ 475,000$ 16,000 2024 475,000 14,000 2025 475,000 16,000
The following graph shows
[[Image Removed: img149240862_11.jpg]]
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 endedDecember 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) 2023$ 15,000 2024 13,000 2025 13,000
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
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
Standard & Poor's (1) Moody's (2)
Corporate/Issuer rating BBB Baa2
Senior Secured Debt A- A3
Senior Unsecured Debt BBB Baa2
(1)
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
Dividends
See "Item 5. Market for Registrant's Common Equity, Related Stockholder Matters
and Issuer Purchases of
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
•
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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AVISTA CORPORATION • 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.
We track multiple economic indicators affecting the three largest metropolitan statistical areas in ourAvista Utilities service area:Spokane, Washington ,Coeur d'Alene, Idaho , andMedford, 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 inSpokane andMedford are near the national average, whileCoeur 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 theU.S. as a whole. Nonfarm employment (seasonally adjusted) in our service areas increased in 2022. InSpokane, Washington employment increased 4.4 percent with gains in all major sectors. Employment increased 2.8 percent inCoeur d'Alene, Idaho , reflecting gains in all major sectors except financial activities. InMedford, 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. InSpokane the unemployment rate was 5.5 percent in 2021 and fell to 4.6 percent in 2022; inCoeur d'Alene the rate fell from 4.3 percent in 2021 to 3.3 percent in 2022; and inMedford the rate fell from 5.4 percent in 2021 to 4.4 percent in 2022. TheU.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.
AlthoughJuneau 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 ofJuneau's economic data may significantly lag the period of this filing. The Quarterly Census of Employment and Wages forJuneau 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 forAvista 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 ourWashington service area. See further discussion regarding these natural gas regulations as included in "Environmental Issues and Contingencies" below. 65
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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:
•
assumptions relating to weather and economic and competitive conditions,
•
internal analysis of company-specific data, such as energy consumption patterns,
• internal business plans,
•
an assumption that we will incur no material loss of retail customers due to self-generation or retail wheeling, and
•
an assumption that demand for electricity and natural gas as a fuel for mobility will for now be immaterial.
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:
•
increasing the operating costs of generating plants and other assets,
•
increasing the lead time and capital costs for the construction of new generating plants and other assets,
•
requiring modification of our existing generating plants,
•
requiring existing generating plant operations to be curtailed or shut down,
•
reducing the amount of energy available from our generating plants,
•
restricting the types of generating plants that can be built or contracted with,
•
requiring construction of specific types of generation plants at higher cost, and
•
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, theWashington State Legislature passed the CETA, which requiresWashington utilities to eliminate the costs and benefits associated with coal-fired resources from their retail electric sales byDecember 31, 2025 . This requirement would effectively prohibit sales of energy produced by coal-fired generation toWashington retail customers afterDecember 31, 2025 . In addition, CETA establishes the policy ofWashington State that all retail sales of electricity toWashington customers must be carbon-neutral byJanuary 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 throughDecember 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 onColstrip , which are unique to those owners ofColstrip who serveWashington customers. See "Colstrip" section and "Note 22 of the Notes to Consolidated Financial Statements" for further details on the impacts of CETA onColstrip and our plans to exitColstrip through our agreement withNorthWestern . 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, inOctober 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 theWashington 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
Some highlights of our approved plan include:
•
Beginning in 2022, serving 40 percent of our
•
Energy efficiency targets to reduce
•
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.
•
ANamed 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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AVISTA CORPORATION Federal Regulatory Actions InJune 2019 , theEPA 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 theEPA '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". InJanuary 2021 , theU.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit ) vacated the ACE Rule and remanded the record back to theEPA for further consideration consistent with its opinion, finding that theEPA 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. InFebruary 2021 , theEPA moved for a partial stay of the Court's mandate, noting that no Section 111(d) rule should go into effect until theEPA conducted new rulemaking in response to theJanuary 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. InApril 2021 , numerous parties requested theSupreme Court's review of the D.C. Circuit'sJanuary 2021 decision, and inOctober 2021 , the Supreme Court granted such review. InJune 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 theEPA in the Federal CPP exceeded the powers granted to the agency byCongress . The Court's decision left open the question of whether, and to what extent, theEPA can seek to curb greenhouse gas emissions through methods other than generation shifting. At this time, theEPA 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 theD.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
InSeptember 2016 , theWashington State Department of Ecology adopted theClean Air Rule (CAR) to cap and reduce greenhouse gas (GHG) emissions across theState of Washington in pursuit of the State's GHG goals, which were enacted in 2008 by theWashington State Legislature . In response, the Company,Cascade Natural Gas Corporation , NW Natural andPuget Sound Energy jointly filed actions in both theEastern District ofWashington and inThurston County Superior Court , challenging the CAR. InJanuary 2020 , theWashington 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 toThurston 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 theKettle 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. TheWashington State Department of Commerce reviews the standard every five years. InSeptember 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. 68
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Washington Climate Commitment Act
In 2021, theWashington 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 theWashington Department of Ecology (Ecology) to develop regulations implementing the cap and trade program and related efforts. Ecology recently issued final rules that became effectiveNovember 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.
InApril 2022 , theWashington 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, inNovember 2022 , SBCC approved new building and energy codes for residential housing, requiring new residential buildings inWashington 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 inJuly 2023 .
Oregon Legislation and Regulatory Actions
Climate Protection Plan
InMarch 2020 ,Oregon GovernorKate Brown issued Executive Order No. 20-04, "Directing State Agencies to Take Actions toReduce and Regulate Greenhouse Gas Emissions." The Executive Order launched rulemaking proceedings for everyOregon agency with jurisdiction over greenhouse gas (GHG)-related matters, with the aim of reducingOregon's overall GHG emissions to 80 percent below 1990 levels by 2050. This Executive Order led to theOregon Department of Environmental Quality developing cap and reduce rules known as the Climate Protection Program (CPP). The CPP, which became effective inJanuary 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. InMarch 2022 , we, along with the utilitiesNW Natural andCascade 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
LikeWashington ,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 inthe 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 inOregon , 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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InOregon , legislation was enacted in 2016 which requires Portland General Electric and PacifiCorp to remove coal-fired generation from theirOregon rate base by 2030. This legislation does not directly relate toAvista Corp. becauseAvista Corp. is not an electric utility inOregon . However, because these two utilities, along withAvista Corp. , hold minority interests inColstrip , the legislation could indirectly impactAvista Corp. , though specific impacts cannot be reasonably predicted at this time. While the legislation requires Portland General Electric and PacifiCorp to eliminateColstrip 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 fromColstrip to other states. We cannot predict the eventual outcome of actions arising from this legislation at this time or estimate the effect thereof onAvista 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 theClark Fork River under a 45-yearFERC operating license forCabinet 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 theU.S. Fish and Wildlife Service , Native American tribes and the states ofIdaho andMontana on the lowerClark Fork River , consistent with requirements of theFERC license. Recent efforts in this program include the development of a permanent fish passage facility atCabinet Gorge dam, as well as fish capture facilities on tributaries to theClark Fork River . TheU.S. Fish and Wildlife Service issued an updated CriticalHabitat Designation for bull trout in 2010 that includes the lowerClark Fork River , as well as portions of theCoeur d'Alene basin within ourSpokane River Project area, and issued a final Bull Trout Recovery Plan under theESA . Regional efforts are underway evaluating the potential of re-establishing anadromous fish above previously blocked areas, including the Spokane River, which is upstream fromGrand 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 inAugust 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 theClark Fork River exceed state ofIdaho and federal water quality numeric standards downstream ofCabinet 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 theFERC license for theClark 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 is a coal-fired generating plant in southeasternMontana 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 arePuget Sound Energy, Inc. , Portland General Electric Company,NorthWestern , Pacificorp andTalen Montana, LLC (which is also the operator of the plant). InJanuary 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). InJanuary 2023 , we entered into an agreement withNorthWestern to transfer our ownership ofColstrip . See "Note 22 of the Notes to Consolidated Financial Statements" for further discussion of the agreement.
Coal Ash Management/Disposal
In 2015, theEPA 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. InAugust 2018 , the D.C. Circuit struck down provisions of the rule. InDecember 2019 , a proposed revision to the rule was published in theFederal 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. TheColstrip 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) withMontana 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 theColstrip plant through an ongoing public process. The AOC also requires theColstrip 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 HoldingPond 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 ofColstrip , including us, have a coal contract that runs throughDecember 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
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AVISTA CORPORATION Enterprise Risk Management The material risks to our businesses are discussed in "Item 1A. Risk Factors," "Forward-Looking Statements," as well as "Environmental Issues and Contingencies." The following discussion focuses on our mitigation processes and procedures to address these risks.
We consider the management of these risks an integral part of managing our core businesses and a key element of our approach to corporate governance.
Risk management includes identifying and measuring various forms of risk that may affect the Company. We have an enterprise risk management process for managing risks throughout our organization. Our Board of Directors and its Committees take an active role in the oversight of risk affecting the Company. Our risk management department facilitates the collection of risk information across the Company, providing senior management with a consolidated view of the Company's major risks and risk mitigation measures. Each area identifies risks and implements the related mitigation measures. The enterprise risk process supports management in identifying, assessing, quantifying, managing and mitigating the risks. Despite all risk mitigation measures, however, risks are not eliminated.
Our primary identified categories of risk exposure are:
• Utility regulatory • External mandates • Operational • Financial • Climate Change • Energy commodity • Cyber and Technology • Compliance • Strategic
Our primary categories of risks are described in "Item 1A. Risk Factors."
Utility Regulatory Risk
Regulatory risk is mitigated through a separate regulatory group which communicates with commission regulators and staff regarding the Company's business plans and concerns. The regulatory group also considers the regulator's priorities and rate policies and makes recommendations to senior management on regulatory strategy for the Company. Oversight of our regulatory strategies and policies is performed by senior management and our Board of Directors. See "Regulatory Matters" for further discussion of regulatory matters affecting our Company. Operational Risk To manage operational and event risks, we maintain emergency operating plans, business continuity and disaster recovery plans, maintain insurance coverage against some, but not all, potential losses and seek to negotiate indemnification arrangements with contractors for certain event risks. In addition, we design and follow detailed vegetation management and asset management inspection plans, which help mitigate wildfire and storm event risks, as well as identify utility assets which may be failing and in need of repair or replacement. We also have an Emergency Operating Center, which is a team of employees that plan for and train to deal with potential emergencies or unplanned outages at our facilities, resulting from natural disasters or other events. To prevent unauthorized access to our facilities, we have both physical and cyber security in place. To address the risk related to fuel cost, availability and delivery restraints, we have an energy resources risk policy, which includes our wholesale energy markets credit policy and control procedures to manage energy commodity price and credit risks. Development of the energy resources risk policy includes planning for sufficient capacity to meet our customer and wholesale energy delivery obligations. See further discussion of the energy resources risk policy below.
Oversight of the operational risk management process is performed by the
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AVISTA CORPORATION Climate Change Risk Multiple departments at the Company work to mitigate risks related to climate change. Climate change adds uncertainty to existing risks that we have historically managed and mitigated. These efforts are reflected in electric and gas operations, investments in assets and asset reliability and resiliency across the Company's operations. Power Supply staff, as a regular course of business, monitor items such as snowpack and broader precipitation conditions, patterns and modeled or predicted climate change. These and other assessments are incorporated into our IRP processes. Environmental Affairs, Governmental Affairs and other departments monitor policy and regulatory developments that may relate to climate change in order to engage these efforts constructively and prepare for compliance matters. The Company has created four councils that are centered around its primary focus areas: our customers, our people, perform and invent.The Perform Council is an interdisciplinary team of management and other employees of the Company which regularly meets to discuss, assess and manage current issues associated with the Company's performance. A key area of focus for thePerform Council is potential risks and opportunities associated with long-term global climate change. Among other things, thePerform Council :
•
facilitates internal and external communications regarding climate change and related issues,
•
analyzes policy effects, anticipates opportunities and evaluates strategies for the Company,
•
develops recommendations on climate related policy positions and action plans, and
•
provides direction and oversight with respect to the Company's clean energy goals.
In addition, issues concerning climate-related risk and the Company's clean energy goals are reviewed and regularly discussed by the Board of Directors. The Board'sEnvironmental, Technology and Operations Committee regularly reviews and discusses environmental and climate related risks, and advises the full Board on any critical or emerging risks and/or related policies. Likewise, the Audit Committee provides oversight of the Company's climate-related disclosures.
Cyber and Technology Risk
We mitigate cyber and technology risk through trainings and exercises at all levels of the Company.The Environmental, Technology and Operations Committee of our Board of Directors along with senior management are regularly briefed on security policy, programs and incidents. Annual cyber and physical training and testing of employees are included in our enterprise security program. Our enterprise business continuity program facilitates business impact analysis of core functions for development of emergency operating plans, and coordinates annual testing and training exercises. Technology governance is led by senior management, which includes new technology strategy, risk planning and major project planning and approval. The technology project management office and enterprise capital planning group provide project cost, timeline and schedule oversight. In addition, there are independent third party audits of our critical infrastructure security program and our business risk security controls. We have a Technology department dedicated to securing, maintaining, evaluating and developing our information technology systems. There are regular training sessions for the technology and security team. This group also evaluates the Company's technology for obsolescence and makes recommendations for upgrading or replacing systems as necessary. Additionally, this group monitors for intrusion and security events that may include a data breach or attack on our operations.
Strategic Risk
Oversight of our strategic risk is performed by the Board of Directors and
senior management. We have a Chief Strategy Officer who leads strategic
initiatives, to search for and evaluate opportunities for the Company and makes
recommendations to senior management. We not only focus on whether opportunities
are financially viable, but also consider whether these opportunities fall
within our core policies and our core business strategies. We mitigate our
reputational risk primarily through a focus on adherence to our core policies,
including our Code of Conduct, maintaining an appropriate Company culture and
tone at the top, and through communication and engagement with our external
stakeholders.
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AVISTA CORPORATION External Mandates Risk Oversight of our external mandate risk mitigation strategies is performed by theEnvironmental, Technology and Operations Committee of our Board of Directors and senior management. We have aPerform Council which meets internally to assess the potential impacts of climate policy to our business and to identify strategies to plan for change. Our Environmental, Social and Governance program creates a framework that is intended to attract investment, enhancement of our brand, and promotion of sustainable long-term growth. We also have employees dedicated to actively engage and monitor federal, state and local government positions and legislative actions that may affect us or our customers.
To prevent the threat of municipalization, we work to build strong relationships with the communities we serve through, among other things:
•
communication and involvement with local business leaders and community organizations,
•
providing customers with a multitude of limited income initiatives, including energy fairs, senior outreach, low income workshops, mobile outreach strategy and a Low Income Rate Assistance Plan,
•
tailoring our internal company initiatives to focus on choices for our customers, to increase their overall satisfaction with the Company, and
•
engaging in the legislative process in a manner that fosters the interests of our customers and the communities we serve.
Financial Risk
Our financial risk is impacted by many factors. Several of these risks include regulation and rates, weather, access to capital markets, interest rate risk, credit risk, and foreign exchange risk. We have aTreasury department that monitors our daily cash position and future cash flow needs, as well as monitoring market conditions to determine the appropriate course of action for capital financing and/or hedging strategies. Oversight of our financial risk mitigation strategies is performed by senior management and theFinance Committee of our Board of Directors.
Regulation and Rates
Our Regulatory Affairs department is critical in mitigation of financial risk as they have regular communications with state commission regulators and staff and they monitor and develop rate strategies for the Company. Rate strategies, such as decoupling, help mitigate the impacts of revenue fluctuations due to weather, conservation or the economy.
Weather Risk
To partially mitigate the risk of financial under-performance due to weather-related factors, we developed decoupling rate mechanisms that were approved by theWashington ,Idaho andOregon commissions. Decoupling mechanisms are designed to break the link between a utility's revenues and consumers' energy usage and instead provide revenue based on the number of customers, thus mitigating a large portion of the risk associated with lower customer loads. See "Regulatory Matters" for further discussion of our decoupling mechanisms.
Access to Capital Markets
Our capital requirements rely to a significant degree on regular access to
capital markets. We actively engage with rating agencies, banks, investors and
state public utility commissions to understand and address the factors that
support access to capital markets on reasonable terms. We manage our capital
structure to maintain a financial risk profile that we believe these parties
will deem prudent. We forecast cash requirements to determine liquidity needs,
including sources and variability of cash flows that may arise from our spending
plans or from external forces, such as changes in energy prices or interest
rates. Our financial and operating forecasts consider various metrics that
affect credit ratings. Our regulatory strategies include working with state
public utility commissions and filing for rate changes as appropriate to meet
financial performance expectations.
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AVISTA CORPORATION Interest Rate Risk Uncertainty about future interest rates causes risk related to a portion of our existing debt, our future borrowing requirements, and our pension and other post-retirement benefit obligations. We manage debt interest rate exposure by limiting our variable rate debt to a percentage of total capitalization of the Company. We hedge a portion of our interest rate risk on forecasted debt issuances with financial derivative instruments. TheFinance Committee of our Board of Directors periodically reviews and discusses interest rate risk management processes and the steps management has undertaken to control interest rate risk. Our Risk Management Committee (RMC) also reviews our interest rate risk management plan. Additionally, interest rate risk is managed by monitoring market conditions when timing the issuance of long-term debt and optional debt redemptions and establishing fixed rate long-term debt with varying maturities. Our interest rate swap derivatives are considered economic hedges against the future forecasted interest rate payments of our long-term debt. Interest rates on our long-term debt are generally set based on underlyingU.S. Treasury rates plus credit spreads, which are based on our credit ratings and prevailing market prices for debt. The interest rate swap derivatives hedge against changes in theU.S. Treasury rates but do not hedge the credit spread. Even though we work to manage our exposure to interest rate risk by locking in certain long-term interest rates through interest rate swap derivatives, if market interest rates decrease below the interest rates we have locked in, this will result in a liability related to our interest rate swap derivatives, which can be significant. However, through our regulatory accounting practices similar to our energy commodity derivatives, any interim mark-to-market gains or losses are offset by regulatory assets and liabilities. Upon settlement of interest rate swap derivatives, the cash payments made or received are recorded as a regulatory asset or liability and are subsequently amortized as a component of interest expense over the life of the associated debt. The settled interest rate swap derivatives are also included as a part ofAvista Corp.'s cost of debt calculation for ratemaking purposes.
The following table summarizes our interest rate swap derivatives outstanding as
of
December 31, December 31,
2022 2021
Number of agreements 5 16
Notional amount $ 50,000 $ 170,000 Mandatory cash settlement dates 2023 to 2024 2022 to 2024
Short-term derivative assets (1)
-
Long-term derivative assets (1) 2,648 1,149
Short-term derivative liability (1) (52 ) (24,026 )
Long-term derivative liability (1) - (78 )
(1)
There are offsetting regulatory assets and liabilities for these items on the Consolidated Balance Sheets in accordance with regulatory accounting practices.
We estimate that a 10 basis point increase in forward variable interest rates as ofDecember 31, 2022 would increase the interest rate swap derivative net liability by$1.0 million , while a 10 basis point decrease would decrease the interest rate swap derivative net liability by$0.7 million . We estimated that a 10 basis point increase in forward variable interest rates as ofDecember 31, 2021 would have increased the interest rate swap derivative net liability by$5.3 million , while a 10 basis point decrease would decrease the interest rate swap derivative net liability by$5.4 million . The interest rate on$51.5 million of long-term debt to affiliated trusts is adjusted quarterly, reflecting current market rates. Amounts borrowed under our committed line of credit agreements have variable interest rates. 75
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The following table shows our long-term debt (including current portion) and
related weighted-average interest rates, by expected maturity dates as of
2023 2024 2025 2026 2027 Thereafter Total Fair Value Fixed rate long-term debt (1)
$ 13,500 $ 15,000 $ - $ - $ -$ 2,285,000 $ 2,313,500 $ 1,848,361 Weighted-average interest rate 7.35 % 3.44 % - - - 4.21 % 4.22 % Variable rate long-term debt to affiliated trusts - - - - -$ 51,547 $ 51,547 $ 42,836 Weighted-average interest rate - - - - - 5.64 % 5.64 % (1)
These balances include the fixed rate long-term debt of
Our pension plan is exposed to interest rate risk because the value of pension obligations and other post-retirement obligations varies directly with changes in the discount rates, which are derived from end-of-year market interest rates. In addition, the value of pension investments and potential income on pension investments is partially affected by interest rates because a portion of pension investments are in fixed income securities. Oversight of our pension plan investment strategies is performed by theFinance Committee of the Board of Directors, which approves investment and funding policies, objectives and strategies that seek an appropriate return for the pension plan. We manage interest rate risk associated with our pension and other post-retirement benefit plans by investing a targeted amount of pension plan assets in fixed income investments that have maturities with similar profiles to future projected benefit obligations. See "Note 12 of the Notes to Consolidated Financial Statements" for further discussion of our investment policy associated with the pension plan assets. Credit Risk
Counterparty Non-Performance Risk
We enter into bilateral transactions with various counterparties. We also trade energy and related derivative instruments through clearinghouse exchanges.
Counterparty non-performance risk relates to potential losses that we would incur as a result of non-performance of contractual obligations by counterparties to deliver energy or make financial settlements.
Changes in market prices may dramatically alter the size of credit risk with counterparties, even when we establish conservative credit limits. Should a counterparty fail to perform, we may be required to honor the underlying commitment or to replace existing contracts with contracts at then-current market prices.
We seek to mitigate credit risk by:
•
transacting through clearinghouse exchanges,
•
entering into bilateral contracts that specify credit terms and protections against default,
•
applying credit limits and duration criteria to existing and prospective counterparties,
•
actively monitoring current credit exposures,
•
asserting our collateral rights with counterparties, and
•
carrying out transaction settlements timely and effectively.
The extent of transactions conducted through exchanges has increased, as many
market participants have shown a preference toward exchange trading and have
reduced bilateral transactions. We actively monitor the collateral required by
such exchanges to effectively manage our capital requirements.
Counterparties' credit exposure to us is dynamic in normal markets and may
change significantly in more volatile markets. The amount of potential default
risk to us from each counterparty depends on the extent of forward contracts,
unsettled transactions, interest rates and market prices. There is a risk that
we do not obtain sufficient additional collateral from counterparties that are
unable or unwilling to provide it.
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Credit Risk Liquidity Considerations
To address the impact on our operations of energy market price volatility, our hedging practices for electricity (including fuel for generation) and natural gas extend beyond the current operating year. Executing this extended hedging program may increase credit risk and demands for collateral. Our credit risk management process is designed to mitigate such credit risks through limit setting, contract protections and counterparty diversification, among other practices. Credit risk affects demands on our capital. We are subject to limits and credit terms that counterparties may assert to allow us to enter into transactions with them and maintain acceptable credit exposures. Many of our counterparties allow unsecured credit at limits prescribed by agreements or their discretion. Capital requirements for certain transaction types involve a combination of initial margin and market value margins without any unsecured credit threshold. Counterparties may seek assurances of performance from us in the form of letters of credit, prepayment or cash deposits. Credit exposure can change significantly in periods of commodity price and interest rate volatility. As a result, sudden and significant demands may be made against our credit facilities and cash. We actively monitor the exposure to possible collateral calls and take steps to minimize capital requirements. As ofDecember 31, 2022 , we had cash deposited as collateral of$171.6 million and letters of credit of$49.4 million outstanding related to our energy contracts. Price movements and/or a downgrade in our credit ratings could impact further the amount of collateral required. See "Credit Ratings" for further information. For example, in addition to limiting our ability to conduct transactions, if our credit ratings were lowered to below "investment grade" based on our positions outstanding atDecember 31, 2022 (including contracts that are considered derivatives and those that are considered non-derivatives), we would potentially be required to post the following additional collateral (dollars in thousands):December 31, 2022 Additional collateral taking into account contractual thresholds $
48,144
Additional collateral without contractual thresholds
63,340
Under the terms of interest rate swap derivatives that we enter into periodically, we may be required to post cash or letters of credit as collateral depending on fluctuations in the fair value of the instrument. As ofDecember 31, 2022 , we had interest rate swap agreements outstanding with a notional amount totaling$50.0 million and we had deposited no cash as collateral for these interest rate swap derivatives. If our credit ratings were lowered to below "investment grade" based on our interest rate swap derivatives outstanding atDecember 31, 2022 , we would potentially be required to post the following additional collateral (dollars in thousands): December 31, 2022 Additional collateral taking into account contractual thresholds (1) $ - Additional collateral without contractual thresholds 52
(1)
This amount is different from the amount disclosed in "Note 8 of the Notes to Consolidated Financial Statements" because, while this analysis includes contracts that are not considered derivatives in addition to the contracts considered in Note 8, this analysis also takes into account contractual threshold limits that are not considered in Note 8.
Foreign Currency Risk
A significant portion of our utility natural gas supply (including fuel for electric generation) is obtained from Canadian sources. Most of those transactions are executed inU.S. dollars, which avoids foreign currency risk. A portion of our short-term natural gas transactions and long-term Canadian transportation contracts are committed based on Canadian currency prices. The short-term natural gas transactions are typically settled within sixty days withU.S. dollars. We hedge a portion of the foreign currency risk by purchasing Canadian currency exchange derivatives when such commodity transactions are initiated. This risk has not had a material effect on our financial condition, results of operations or cash flows and these differences in cost related to currency fluctuations are included with natural gas supply costs for ratemaking. Further information for derivatives and fair values is disclosed at "Note 8 of the Notes to Consolidated Financial Statements" and "Note 18 of the Notes to Consolidated Financial Statements." 77
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AVISTA CORPORATION Energy Commodity Risk We mitigate energy commodity risk primarily through our energy resources risk policy, which includes oversight from the RMC and oversight from the Audit Committee and theEnvironmental, Technology and Operations Committee of our Board of Directors. In conjunction with the oversight committees, our management team develops hedging strategies, detailed resource procurement plans, resource optimization strategies and long-term integrated resource planning to mitigate some of the risk associated with energy commodities. The various plans and strategies are monitored daily and developed with quantitative methods. Our energy resources risk policy includes our wholesale energy markets credit policy and control procedures to manage energy commodity price and credit risks. Nonetheless, adverse changes in commodity prices, generating capacity, customer loads, regulation and other factors may result in losses of earnings, cash flows and/or fair values. We measure the volume of monthly, quarterly and annual energy imbalances between projected power loads and resources. The measurement process is based on expected loads at fixed prices (including those subject to retail rates) and expected resources to the extent that costs are essentially fixed by virtue of known fuel supply costs or projected hydroelectric conditions. To the extent that expected costs are not fixed, either because of volume mismatches between loads and resources or because fuel cost is not locked in through fixed price contracts or derivative instruments, our risk policy guides the process to manage this open forward position over a period of time. Normal operations result in seasonal mismatches between power loads and available resources. We are able to vary the operation of generating resources to match parts of intra-hour, hourly, daily and weekly load fluctuations. We use the wholesale power markets, including the natural gas market as it relates to power generation fuel, to sell projected resource surpluses and obtain resources when deficits are projected. We buy and sell fuel for thermal generation facilities based on comparative power market prices and marginal costs of fueling and operating available generating facilities and the relative economics of substitute market purchases for generating plant operation. To address the impact on our operations of energy market price volatility, our hedging practices for electricity (including fuel for generation) and natural gas extend beyond the current operating year. Executing this extended hedging program may increase our credit risks. Our credit risk management process is designed to mitigate such credit risks through limit setting, contract protections and counterparty diversification, among other practices. Our projected retail natural gas loads and resources are regularly reviewed by operating management and the RMC. To manage the impacts of volatile natural gas prices, we seek to procure natural gas through a diversified mix of spot market purchases and forward fixed price purchases from various supply basins and time periods. We have an active hedging program that extends into future years with the goal of reducing price volatility in our natural gas supply costs. We use natural gas storage capacity to support high demand periods and to procure natural gas when price spreads are favorable. Securing prices throughout the year and even into subsequent years mitigates potential adverse impacts of significant purchase requirements in a volatile price environment. The following table presents energy commodity derivative fair values as a net asset or (liability) as ofDecember 31, 2022 that are expected to settle in each respective year (dollars in thousands). There are no expected deliveries of energy commodity derivatives after 2025: Purchases Sales Electric Derivatives Gas Derivatives Electric Derivatives Gas Derivatives Year Physical (1) Financial (1) Physical (1)
Financial (1) Physical (1) Financial (1) Physical (1)
Financial (1)
2023 $ 1,120 $ - $ (33,150 ) $ 62,753 $ (2,374 ) $ (20,018 ) $ 17,166 $ (137,585 )
2024 - - 162 (3,879 ) - - (4,968 ) (5,790 )
2025 - - 135 (220 ) - - (2,924 ) (701 )
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The following table presents energy commodity derivative fair values as a net asset or (liability) as ofDecember 31, 2021 that were expected to settle in each respective year (dollars in thousands). There were no expected deliveries of energy commodity derivatives after 2025: Purchases Sales Electric Derivatives Gas Derivatives Electric Derivatives Gas Derivatives Year Physical (1) Financial (1) Physical (1) Financial (1) Physical (1) Financial (1) Physical (1) Financial (1) 2022$ (269 ) $ - $ (260 ) $ 6,198 $ 650 $ 1,572$ (3,479 ) $ (16,859 ) 2023 - - (54 ) 1,964 - - (1,612 ) (757 ) 2024 - - (34 ) 296 - - (1,603 ) 5 2025 - - - - - - (1,146 ) - (1) Physical transactions represent commodity transactions where we will take or make delivery of either electricity or natural gas; financial transactions represent derivative instruments with delivery of cash in the amount of the benefit or cost but with no physical delivery of the commodity, such as futures, swap derivatives, options, or forward contracts. The above electric and natural gas derivative contracts will be included in either power supply costs or natural gas supply costs during the period they are delivered and will be included in the various deferral and recovery mechanisms (ERM, PCA, and PGAs), or in the general rate case process, and are expected to eventually be collected through retail rates from customers.
See "Item 1. Business - Electric Operations" and "Item 1. Business - Natural Gas
Operations," for additional discussion of the risks associated with
Compliance Risk
Compliance risk is mitigated through separate Regulatory and Environmental Compliance departments that monitor legislation, regulatory orders and actions to determine the overall potential impact to our Company and develop strategies for complying with the various rules and regulations. We also engage outside attorneys and consultants, when necessary, to help ensure compliance with laws and regulations. Oversight of our compliance risk strategy is performed by senior management, including our Chief Compliance Officer, and theEnvironmental, Technology and Operations Committee and the Audit Committee of our Board of Directors. See "Item 1. Business, Regulatory Issues" through "Item 1. Business, Reliability Standards" and "Environmental Issues and Contingencies" for further discussion of compliance issues that impact our Company.
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