ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
This section of this Annual Report on Form 10-K generally discusses 2020 and 2019 financial statement items and year-to-year comparisons between 2020 and 2019. Discussion of 2018 financial statement items and year-to-year comparisons between 2019 and 2018 that are not included in this Form 10-K can be found in "Management's Discussion and Analysis of Financial Conditions and Results of Operations" in Part II, Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2019.
Business Segments
As of December 31, 2020, we have two reportable business segments, Avista Utilities and AEL&P. We also have other businesses which do not represent a reportable business segment and are conducted by various direct and indirect subsidiaries of Avista Corp. See "Part I, Item 1. Business – Company Overview" for further discussion of our business segments.
The following table presents net income (loss) attributable to Avista Corp. shareholders for each of our business segments (and the other businesses) for the year ended December 31 (dollars in thousands):
Executive Level Summary
Overall Results
Net income attributable to Avista Corp. shareholders was $129.5 million for 2020, a decrease from $197.0 million for 2019.
Avista Utilities' net income decreased primarily due to the receipt, in the first quarter of 2019, of a $103 million termination fee from Hydro One (see "Note 25 of the Notes to Consolidated Financial Statements"), which was partially offset by associated expenses of $19.7 million pre-tax. In addition, our earnings decreased due to higher operating expenses, which was partially offset by higher utility margin due to lower power supply costs, rate relief in Washington and Oregon and customer growth. In addition, utility margin was impacted by lower commercial and industrial loads associated with COVID-19.
AEL&P net income increased slightly, primarily due to higher sales volumes to residential and commercial customers in 2020 as a result of cooler than usual weather.
The decrease in net income at our other businesses was primarily due to the sale of METALfx in 2019. In addition, we had impairment losses and the write-off of a note receivable in 2020, which was partially offset by net investment gains associated with our equity investments.
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).
COVID-19 Pandemic
The COVID-19 pandemic is impacting our business, as well as the global, national and local economies. It is likely that the continued spread of COVID-19 and efforts to contain the virus will continue to cause an economic slowdown, resulting in significant disruptions in various public, commercial or industrial activities and causing employee absences which could interfere with operation and maintenance of the Company’s facilities. These circumstances have affected and will likely continue to adversely affect our operations, results of operations, financial condition and cash flows in the following ways:
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Operations
We provide critical services to our customers. Accordingly, it is paramount that we keep our employees who operate our business safe so that we continue to provide reliable service. We implemented business continuity plans in the context of this pandemic. We believe that we will continue to be able to conduct our utility operations effectively and provide safe and reliable service to our customers.
We have taken precautions concerning employee and facility hygiene, imposed travel limitations on employees and directed our employees to work remotely whenever possible. Protocols have been established and implemented to protect employees and the public when work requires public interaction.
During 2020, we experienced supply chain delays due to the effects of the COVID-19 pandemic that have impacted the delivery times of some of our materials and equipment, with delays ranging from a couple weeks up to eight weeks in some cases. At this time, the delays are being managed with minimal impact. The issues that could potentially result from future delays are being proactively mitigated through several planning and review activities, but could have an impact on our planned projects going forward.
Although we have not experienced any significant issues to date, it is possible that COVID-19 could have a negative impact on the ability of vendors or contractors to perform, which could increase operating costs and delay and/or increase the costs of capital projects.
Results of Operations
In the year ended December 31, 2020, when compared to normal, there was a decrease of approximately 3 percent on overall electric load, consisting of approximately a 6 percent decrease in commercial and a 9 percent decrease in industrial loads, which was partially offset by an increase of 3 percent in residential load. We expect a gradual economic recovery and prolonged high unemployment that will depress load and customer growth into 2021. We have decoupling and other regulatory mechanisms in Washington, Idaho and Oregon, which mitigate the impact of changes in loads and revenues for residential and certain commercial customer classes. There are limitations on increases in decoupling surcharges in a particular year and revenue recognition criteria established by GAAP. Although we expect to ultimately recognize all decoupling revenue, there can be a delay in revenue recognition. Over 90 percent of our utility revenue is covered by regulatory mechanisms.
We have suspended customer disconnections and late fees for non-payment in our jurisdictions except in Idaho, as the IPUC approved resuming disconnections and late fees. In Washington, there is a moratorium on disconnections until April 30, 2021 and a moratorium on late fees until October 27, 2021. In Oregon, there is a moratorium on disconnections and late fees for non-payment until at least October 1, 2021.
We are offsetting some of the negative impacts of COVID-19 at Avista Utilities with cost savings and benefits from the Coronavirus Aid, Relief, and Economic Security Act (the CARES Act), described below. We have received accounting orders in each of our jurisdictions to defer the recognition of COVID-19 expenses as well as identified cost savings of other COVID-19 related benefits. See “Note 1 of Notes to Consolidated Financial Statements.” As of December 31, 2020, we had deferred a net benefit to customers of $2.8 million for all jurisdictions. However, we expect to defer a net expense to customers in 2021 for COVID-19 related items.
CARES Act
In March 2020, the CARES Act, an economic stimulus package in response to COVID-19, was signed into law. The CARES Act contains corporate income tax provisions, including providing temporary changes regarding the prior and future utilization of net operating losses, temporary suspension of certain payment requirements for the employer portion of social security taxes, and the creation of certain refundable employee retention credits.
Financial Condition, Liquidity and Cash Flows
For 2021, we expect our net cash flows from operations to decrease compared to the prior year, primarily due to lower revenues from retail sales of electricity and natural gas and lower payments from customers.
We do not expect the impact of COVID-19 to change our estimate of utility capital expenditures for 2021.
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As of December 31, 2020, we had$270.4 million of available liquidity under the Avista Corp. $400.0 million committed line of credit and $24.0 million under the AEL&P committed line of credit.
After considering the impacts of COVID-19, including expected lower net operating cash flows compared to 2020, and the issuances of long-term debt and equity during 2021, we expect net cash flows from operations, together with cash available under our committed lines of credit, to provide adequate resources to fund capital expenditures, dividends, and other contractual commitments.
We cannot predict the duration and severity of the COVID-19 pandemic. The longer and more severe the economic restrictions and business disruption is, the greater the impact on our operations, results of operations, financial condition and cash flows will be.
General Rate Cases and Regulatory Lag
We experienced regulatory lag during 2020 and we expect this to continue through the end of 2022 due to our continued investment in utility infrastructure and because we delayed filings in our Washington and Idaho jurisdictions. In October 2020, we filed general rates cases in Washington and we also filed a natural gas general rate case in Oregon in March (with new rates effective on January 16, 2021). In addition, we filed general rate cases in Idaho on January 29, 2021 (see "Regulatory Matters"). We expect these cases to provide rate relief in 2021 and start reducing regulatory lag. Going forward, we will continue to strive to reduce the regulatory timing lag and more closely align our earned returns with those authorized by 2023. This will require adequate and timely rate relief in our jurisdictions. See "Regulatory Matters" for additional discussion of the general rate cases.
Regulatory Matters
General Rate Cases
We regularly review the need for electric and natural gas rate changes in each state in which we provide service. We will continue to file for rate adjustments to:
• seek recovery of operating costs and capital investments, and
• seek the opportunity to earn reasonable returns as allowed by regulators.
With regards to the timing and plans for future filings, the assessment of our need for rate relief and the development of rate case plans takes into consideration short-term and long-term needs, as well as specific factors that can affect the timing of rate filings. Such factors include, but are not limited to, in-service dates of major capital investments and the timing of changes in major revenue and expense items.
Avista Utilities
Washington General Rate Cases and Other Proceedings
2015 General Rate Cases
In January 2016, we received an order that concluded our electric and natural gas general rate cases that were originally filed with the WUTC in February 2015.
PC Petition for Judicial Review
In March 2016, PC filed in Thurston County Superior Court a Petition for Judicial Review of the WUTC's Orders. In April 2016, this matter was certified for review directly by the Court of Appeals, an intermediate appellate court in the State of Washington.
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In August 2018, the Court of Appeals issued a "Published Opinion" (Opinion) which concluded that the WUTC's use of an attrition allowance to calculate Avista Corp.'s rate base violated Washington law. In the Opinion, the Court stated that because the projected additions to rate base in the future were not "used and useful" for service at the time the request for the rate increase was made, they may not lawfully be included in our rate base to justify a rate increase. Accordingly, the Court concluded that the WUTC erred in including an attrition allowance in the calculation of our electric and natural gas rate base. The Court noted, however, that the law does not prohibit an attrition allowance in the calculation, for ratemaking purposes, of recoverable operating and maintenance expense. Since the WUTC order provided one lump sum attrition allowance without distinguishing what portion was for rate base and which was for operating and maintenance expenses or other considerations, the Court struck all portions of the attrition allowance attributable to our rate base and reversed and remanded the case for the WUTC to recalculate our rates without including an attrition allowance in the calculation of rate base.
In March 2020, we received an order from the WUTC that requires us to refund $8.5 million to electric and natural gas customers. We are refunding $4.9 million to electric customers and $3.6 million to natural gas customers, which is being refunded over a twelve-month period that began on April 1, 2020. We previously recorded a customer refund liability of $3.6 million in 2019.
2019 General Rate Cases
In March 2020, we received an order from the WUTC that approved a partial multi-party settlement agreement that contemplated rates designed to increase annual base electric revenues by $28.5 million, or 5.7 percent, and annual natural gas base revenues by $8.0 million, or 8.5 percent, effective April 1, 2020. The designed revenue increases were based on a 9.4 percent return on equity (ROE) with a common equity ratio of 48.5 percent and a rate of return (ROR) on rate base of 7.21 percent.
As part of the WUTC order, we are returning approximately $40 million from the ERM rebate to customers over a two-year period. The ERM rebate includes approximately $3 million that was disallowed by the WUTC for the cost of replacement power during an unplanned outage at the Colstrip generating facility in 2018. The WUTC directed us to return a larger portion of the ERM rebate during the first year to achieve a net-zero billed impact to electric customers.
Included in the WUTC order is the acceleration of depreciation of Colstrip Units 3 & 4 to reflect a remaining useful life through December 31, 2025. The order utilizes certain electric tax benefits associated with the 2018 tax reform to partially offset these increased costs. The order also sets aside $3 million for community transition efforts to mitigate the impacts of the eventual closure of Colstrip, half funded by customers and half funded by our shareholders. See “Colstrip” section for further information on the eventual closure of Colstrip. We recorded this liability and recognized the shareholder portion of the expense in the first quarter of 2020.
Lastly, the order included the extension of electric and natural gas decoupling mechanisms through March 31, 2025, with one modification in that new customers added after any test period would not be decoupled until included in a future test period.
2020 General Rate Cases
In October 2020, we filed electric and natural gas general rate cases with the WUTC. We have requested an overall increase in base electric revenues of $44.2 million (or 8.3 percent), which would be entirely offset by a tax credit to customers of the same amount. Additionally, we have requested an overall increase in base natural gas revenues of $12.8 million (or 12.2 percent), which would be entirely offset by a tax credit to customers of the same amount for a period of time. The revenue increases are based on a 9.9 percent ROE with a common equity ratio of 50 percent and a ROR of 7.43 percent.
Included in our general rate case requests are the recovery of our Advanced Metering Infrastructure (AMI) project costs. AMI project costs represented 42 percent of our electric base rate request and 54 percent of our natural gas base rate request.
Idaho General Rate Cases and Other Proceedings
2017 General Rate Cases
In December 2017, the IPUC approved a settlement agreement between us and other parties to our electric and natural gas general rate cases. New rates were effective on January 1, 2018 and January 1, 2019.
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The settlement agreement was a two-year rate plan and had the following electric and natural gas base rate changes each year, which were designed to result in the following increases in annual revenues (dollars in millions):
Electric Natural Gas
The settlement agreement was based on a ROR of 7.61 percent with a common equity ratio of 50.0 percent and a 9.5 percent ROE.
2019 General Rate Case
In October 2019, Avista Corp. and all parties to our electric general rate case reached a settlement agreement that was approved by the IPUC. New rates went into effect on December 1, 2019.
The rates that went into effect are designed to decrease annual base electric revenues by $7.2 million (or 2.8 percent), effective December 1, 2019. The settlement revenue decreases are based on a 9.5 percent ROE with a common equity ratio of 50 percent and a ROR on rate base of 7.35 percent, which is a continuation of current levels. This outcome is in line with our expectations.
The primary element of the difference in the agreed upon base revenues in the settlement agreement from our original request is that the settlement includes the continued recovery of costs for our wind generation power purchase agreements, which will include Palouse Wind and Rattlesnake Flat, through the PCA mechanism rather than through base rates.
2021 General Rate Cases
In January 2021, we filed electric and natural gas general rate cases with the IPUC. The proposal is a two-year rate plan, with new rates taking effect September 1, 2021 and September 1, 2022. The electric and natural gas requests are based on a proposed ROR on rate base of 7.30 percent with a common equity ratio of 50 percent and a 9.9 percent ROE.
Avista’s request, if approved, is designed to increase annual electric base revenues by $24.8 million or 10.1 percent effective September 1, 2021 and $8.7 million or 3.2 percent effective September 1, 2022. We are, however, proposing to apply a tax credit to customers that would fully offset the increase for September 1, 2021, resulting in no bill change for customers for a period of time. For natural gas, the rate request is designed to increase annual base revenues by $0.05 million or 0.1 percent effective September 1, 2021 and $1.0 million, or 2.2 percent effective September 1, 2022. The tax credit to customers for natural gas would more than fully offset the September 1, 2021 increase, resulting in a rate reduction for all customers, and would continue for a ten-year period. We are proposing to offset the majority of the increase for the September 1, 2022 rate change with other deferred customer credits.
Oregon General Rate Cases and Other Proceedings
2019 General Rate Case
In October 2019, the OPUC approved the all-party settlement agreements filed in the third quarter of 2019. New rates were effective on January 15, 2020.
OPUC approved rates that are designed to increase annual natural gas billed revenues by $3.6 million, or 4.2 percent.
The OPUC’s decision reflects a ROR on rate base of 7.24 percent, with a common equity ratio of 50 percent and a 9.4 percent ROE.
In addition, the approved settlement agreements included agreement among the parties to an independent review of our interest rate hedging practices, with any recommendations based on the results and findings in the final report to be applicable only on a prospective basis and do not apply to any prior interest rate hedging activity. In 2020, an independent review of our interest rate hedging practices was completed with no material recommended changes to our hedging practices.
2020 General Rate Case
In March 2020, we filed a natural gas general rate case with the OPUC.
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Through several settlement stipulations the parties resolved all issues in the general rate case and in December 2020, the OPUC approved the three settlement stipulations.
These stipulations approved by the OPUC increased annual base revenue by $3.9 million, or 5.7 percent effective January 16, 2021. The approved ROE is 9.4 percent, with a common equity ratio of 50 percent and a ROR of 7.24 percent.
2021 General Rate Case
We expect to file a natural gas general rate case with the OPUC in the second half of 2021.
AMI Project
In March 2016, the WUTC granted our Petition for an Accounting Order to defer and include in a regulatory asset the undepreciated value of our existing Washington electric meters for the opportunity for later recovery. This accounting treatment is related to our ongoing project to replace our existing electric meters with new two-way digital meters and the related software and support services through our AMI project in Washington State. As of December 31, 2020, the estimated future undepreciated value for the existing electric meters was $21.9 million. In September 2017, the WUTC also approved our request to defer the undepreciated net book value of existing natural gas encoder receiver transmitters (ERT) (consistent with the accounting treatment we obtained on our existing electric meters) that are being retired as part of the AMI project. As of December 31, 2020, the estimated future undepreciated value for the existing natural gas ERTs was $3.9 million.
In September 2017, the WUTC approved a Petition to defer the depreciation expense associated with the AMI project, along with a carrying charge. We have included a request to seek recovery of our AMI costs in our 2020 Washington general rate cases.
Alaska Electric Light and Power Company
AEL&P is required to file its’ next general rate case by August 30, 2021.
Avista Utilities
Purchased Gas Adjustments
PGAs are designed to pass through changes in natural gas costs to Avista Utilities' customers with no change in utility margin (operating revenues less resource costs) or net income. In Oregon, we absorb (cost or benefit) 10 percent of the difference between actual and projected natural gas costs included in base retail rates for supply that is not hedged. Total net deferred natural gas costs among all jurisdictions were a net asset of $1.4 million as of December 31, 2020 and a liability of $3.2 million as of December 31, 2019. These deferred natural gas cost balances represent amounts due to customers.
The following PGAs went into effect in our various jurisdictions during 2018 through 2020:
Jurisdiction PGA Effective Date Percentage Increase / (Decrease) in Billed Rates
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Power Cost Deferrals and Recovery Mechanisms
Deferred power supply costs are recorded as a deferred charge or liability on the Consolidated Balance Sheets for future prudence review and recovery or rebate through retail rates. The power supply costs deferred include certain differences between actual net power supply costs incurred by Avista Utilities and the costs included in base retail rates. These differences primarily result from changes in:
• short-term wholesale market prices and sales and purchase volumes,
• the level, availability and optimization of hydroelectric generation,
• retail loads, and
• sales of surplus transmission capacity.
For our Washington customers, the ERM is an accounting method used to track certain differences between Avista Utilities' actual power supply costs, net of wholesale sales and sales of fuel, and the amount included in base retail rates. Total net deferred power costs under the ERM were a liability of $37.9 million as of December 31, 2020 and $37.0 million as of December 31, 2019. These deferred power cost balances represent amounts due to customers.
Under the ERM, Avista Utilities absorbs the cost or receives the benefit from the initial amount of power supply costs in excess of or below the level in retail rates, which is referred to as the deadband. The annual (calendar year) deadband amount is $4.0 million.
The following is a summary of the ERM:
within +/- $0 to $4 million (deadband) 0% 100%
higher by $4 million to $10 million 50% 50%
lower by $4 million to $10 million 75% 25%
higher or lower by over $10 million 90% 10%
Under the ERM, Avista Utilities makes an annual filing on or before April 1 of each year to provide the opportunity for the WUTC staff and other interested parties to review the prudence of and audit the ERM deferred power cost transactions for the prior calendar year.
Pursuant to WUTC requirements, should the cumulative deferral balance exceed $30 million (in either direction), we must make a filing with the WUTC to adjust customer rates to either return the balance to customers or recover the balance from customers. The cumulative rebate balance exceeded $30 million and as a result, our 2019 filing contained a proposed rate refund. The ERM proceeding was considered with our 2019 general rate case proceeding and a refund was approved and is being returned to customers over a two-year period that began on April 1, 2020. See further discussion in the section "Washington General Rate Cases" above.
Avista Utilities has a PCA mechanism in Idaho that allows us to modify electric rates on October 1 of each year with IPUC approval. Under the PCA mechanism, we defer 90 percent of the difference between certain actual net power supply expenses and the amount included in base retail rates for our Idaho customers. The October 1 rate adjustments recover or rebate power supply costs deferred during the preceding July-June twelve-month period. Total net power supply costs deferred under the PCA mechanism were an asset of $2.5 million as of December 31, 2020 and $0.3 million as of December 31, 2019. These deferred power cost balances represent amounts due from customers.
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Decoupling and Earnings Sharing Mechanisms
Decoupling (also known as a FCA in Idaho) is a mechanism designed to sever the link between a utility's revenues and consumers' energy usage. In each of our jurisdictions, Avista Utilities' electric and natural gas revenues are adjusted so as to be based on the number of customers in certain customer rate classes and assumed "normal" kilowatt hour and therm sales, rather 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 order the WUTC approved an extension of the mechanisms for an additional five-year term through March 31, 2025, with one modification in that new customers added after any test period would not be decoupled until included in a future test period.
The decoupling mechanisms each include an after-the-fact earnings test. At the end of each calendar year, separate electric and natural gas earnings calculations are made for the calendar year just ended. These earnings tests reflect actual decoupled revenues, normalized power supply costs and other normalizing adjustments. If we earn more than our authorized ROR in Washington, 50 percent of excess earnings are rebated to customers through adjustments to existing decoupling surcharge or rebate balances.
Idaho FCA Mechanism
In Idaho, the IPUC approved the extensions of FCAs for electric and natural gas (similar in operation and effect to the Washington decoupling mechanisms) through March 31, 2025.
Oregon Decoupling Mechanism
In February 2016, the OPUC approved the implementation of a decoupling mechanism for natural gas, similar to the Washington and Idaho mechanisms described above. The decoupling mechanism became effective on March 1, 2016. There was an opportunity for interested parties to review the mechanism and recommend changes, if any, by September 2019. Changes related to deferral interest rates were recommended by the parties in our 2019 general rate case and were implemented effective January 15, 2020. In Oregon, an earnings review is conducted on an annual basis. In the annual earnings review, if we earn more than 100 basis points above our allowed return on equity, one-third of the earnings above the 100 basis points would be deferred and later rebated to customers.
Cumulative Decoupling and Earnings Sharing Balances
Total net cumulative decoupling deferrals among all jurisdictions were regulatory assets of $21.3 million as of December 31, 2020 and $24.3 million as of December 31, 2019. These decoupling assets represent amounts due from customers. Total net earnings sharing balances among all jurisdictions were regulatory liabilities of $0.7 million as of December 31, 2020 and December 31, 2019. These earnings sharing liabilities represent amounts due to customers.
See "Results of Operations - Avista Utilities" for further discussion of the amounts recorded to operating revenues in 2019 and 2020 related to the decoupling and earnings sharing mechanisms.
COVID-19 Deferrals
See “Note 1 of the Notes to Consolidated Financial Statements” for discussion on COVID-19 deferrals.
Results of Operations - Overall
The following provides an overview of changes in our Consolidated Statements of Income. More detailed explanations are provided, particularly for operating revenues and operating expenses, in the business segment discussions (Avista Utilities, AEL&P and the other businesses) that follow this section.
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2020 compared to 2019
The following graph shows the total change in net income attributable to Avista Corp. shareholders for 2020 to 2019, as well as the various factors that caused such change (dollars in millions):
Utility revenues decreased at Avista Utilities primarily due to an overall decrease in electric load of 2 percent when compared to the year ended December 31, 2019, which consisted of a 6 percent and a 5 percent decrease in commercial and industrial load, respectively. The decreases in commercial and industrial were partially offset by a 1 percent increase in residential electric load when compared to the year ended December 31, 2019. The above decreases were partially offset by an increase from electric and natural gas decoupling rates, higher PGA rates and customer growth. AEL&P's revenues increased from an increase in sales volumes due to weather that was cooler than the prior year.
Non-utility revenues decreased due to the sale of METALfx, which occurred in April 2019. See "Note 26 of the Notes to Consolidated Financial Statements" for further discussion.
Utility resource costs decreased at Avista Utilities due to lower fuel for generation and other fuel costs, as well as lower natural gas purchases. There was an increase at AEL&P due to an increase in deferred power supply expenses.
The increase in utility operating expenses was due to an increase at Avista Utilities primarily related to increases in generation and distribution operating and maintenance costs, and an accrual for disallowed replacement power during an unplanned outage at Colstrip (see "Regulatory Matters"). These were partially offset by a $7.0 million donation commitment made in the second quarter of 2019 that was a one-time donation.
The merger transaction costs are related to the proposed (now terminated) acquisition by Hydro One. There were no additional costs in 2020 relating to this matter.
Utility depreciation and amortization increased due to additions to utility plant.Also, in the second quarter of 2020 we were able to utilize $10.9 million ($8.4 million when tax-effected) of electric tax benefits to offset costs associated with accelerating the depreciation of Colstrip Units 3 & 4 based on a settlement in Washington. This amount was recorded as a one-time increase to depreciation expense in the second quarter of 2020 and was offset with a decrease in income tax expense. In the second quarter of 2019, a similar item was recorded in Idaho in the amount of $6.4 million ($5.1 million when tax-effected).
The merger termination fee was related to the termination of the proposed Hydro One acquisition. There were no additional amounts received in 2020 relating to this matter.
Income taxes decreased primarily due to a decrease in income before taxes. Our effective tax rate was 5.2 percent for the year ended December 31, 2020, compared to 13.8 percent for the year ended December 31, 2019. The tax rate decreased in 2020 compared to 2019 due to the offset of deferred income taxes against accelerated depreciation for Colstrip as provided in the
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2019 Washington general rate case settlement, which was recorded in the second quarter 2020. This amounted to $8.4 million in 2020 as compared to $5.1 million in 2019. See "Note 12 of the Notes to Consolidated Financial Statements" for further details and a reconciliation of our effective tax rate.
Non-GAAP Financial Measures
The following discussion for Avista Utilities includes two financial measures that are considered “non-GAAP financial measures,” electric utility margin and natural gas utility margin. In the AEL&P section, we include a discussion of utility margin, which is also a non-GAAP financial measure.
Generally, a non-GAAP financial measure is a numerical measure of a company's financial performance, financial position or cash flows that excludes (or includes) amounts that are included (excluded) in the most directly comparable measure calculated and presented in accordance with GAAP. Electric utility margin is electric operating revenues less electric resource costs, while natural gas utility margin is natural gas operating revenues less natural gas resource costs. The most directly comparable GAAP financial measure to electric and natural gas utility margin is utility operating revenues as presented in "Note 24 of the Notes to Consolidated Financial Statements."
The presentation of electric utility margin and natural gas utility margin is intended to enhance understanding of our operating performance. We use these measures internally and believe they provide useful information to investors in their analysis of how changes in loads (due to weather, economic or other conditions), rates, supply costs and other factors impact our results of operations. Changes in loads, as well as power and natural gas supply costs, are generally deferred and recovered from customers through regulatory accounting mechanisms. Accordingly, the analysis of utility margin generally excludes most of the change in revenue resulting from these regulatory mechanisms. We present electric and natural gas utility margin separately below for Avista Utilities since each business has different cost sources, cost recovery mechanisms and jurisdictions, so we believe that separate analysis is beneficial. These measures are not intended to replace utility operating revenues as determined in accordance with GAAP as an indicator of operating performance. Reconciliations of operating revenues to utility margin are set forth below.
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Results of Operations - Avista Utilities
2020 compared to 2019
Utility Operating Revenues
The following graphs present Avista Utilities' electric operating revenues and megawatt-hour (MWh) sales for the years ended December 31 (dollars in millions and MWhs in thousands):
Total electric operating revenues in the graph above include intracompany sales of $36.4 million and $48.0 million for 2020 and 2019, respectively.
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The following table presents the current year deferrals and the amortization of prior year decoupling balances that are reflected in utility electric operating revenues for the years ended December 31 (dollars in thousands):
Electric Operating Revenues
Current year decoupling deferrals (a) $ 11,449 $ 9,744
Amortization of prior year decoupling deferrals (b) (15,810 ) (1,045 )
Total electric decoupling revenue $ (4,361 ) $ 8,699
Total electric revenues decreased $34.5 million for 2020 as compared to 2019. The primary fluctuations that occurred during the period were as follows:
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The following graphs present Avista Utilities' natural gas operating revenues and therms delivered for the years ended December 31 (dollars in millions and therms in thousands):
Total natural gas operating revenues in the graph above include intracompany sales of $49.6 million and $65.4 million for 2020 and 2019, respectively.
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The following table presents the current year deferrals and the amortization of prior year decoupling balances that are reflected in natural gas operating revenues for the years ended December 31 (dollars in thousands):
Natural Gas Operating Revenues
Current year decoupling deferrals (a) $ 1,797 $ (3,270 )
Amortization of prior year decoupling deferrals (b) (1,250 ) 4,184
Total natural gas decoupling revenue $ 547 $ 914
Total natural gas revenues decreased $11.4 million for 2020 as compared to 2019. The primary fluctuations that occurred during the period were as follows:
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Utility Resource Costs
The following graphs present Avista Utilities' resource costs for the years ended December 31 (dollars in millions):
Total electric resource costs in the graph above include intracompany resource costs of $49.6 million and $65.4 million for 2020 and 2019, respectively.
Total electric resource costs decreased $52.6 million for 2020 as compared to 2019. The primary fluctuations that occurred during the period were as follows:
• a $12.0 million decrease in other fuel costs.
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Total natural gas resource costs in the graph above include intracompany resource costs of $36.4 million and $48.0 million for 2020 and 2019, respectively.
Total natural gas resource costs decreased $20.7 million for 2020 as compared to 2019. The primary fluctuations that occurred during the period were as follows:
Utility Margin
The following table reconciles Avista Utilities' operating revenues, as presented in "Note 24 of the Notes to Consolidated Financial Statements" to the Non-GAAP financial measure utility margin for the years ended December 31 (dollars in thousands):
Electric Natural Gas Intracompany Total
Electric utility margin increased $18.1 million and natural gas utility margin increased $9.4 million.
For 2020, we had a $6.2 million pre-tax benefit under the ERM in Washington, compared to a $4.4 million benefit for 2019. In addition, electric utility margin was positively impacted by a general rate increase in Washington, effective April 1, 2020 and customer growth. The above increase was partially offset by lower commercial and industrial loads in 2020, mainly due to COVID-19. A portion of the commercial loads and all of the industrial loads are not covered by our decoupling mechanisms. Also, in the first quarter of 2020 we had an accrual for customer refunds of $1.4 million related to our 2015 Washington general rate case that was remanded back to the WUTC during 2019. See "Regulatory Matters" for further discussion.
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Natural gas utility margin increased primarily due to general rate increases in Oregon, effective January 15, 2020 and Washington, effective April 1, 2020 and customer growth. These increases were partially offset by an accrual for customer refunds of $3.5 million related to our 2015 Washington general rate case that was remanded back to the WUTC during 2019. See "Regulatory Matters" for further discussion.
Intracompany revenues and resource costs represent purchases and sales of natural gas between our natural gas distribution operations and our electric generation operations (as fuel for our generation plants). These transactions are eliminated in the presentation of total results for Avista Utilities and in the consolidated financial statements but are included in the separate results for electric and natural gas presented above.
Results of Operations - Alaska Electric Light and Power Company
2020 compared to 2019
Net income for AEL&P was $8.1 million for the year ended December 31, 2020, compared to $7.5 million for 2019.
The following table presents AEL&P's operating revenues, resource costs and resulting utility margin for the years ended December 31 (dollars in thousands):
Electric
Electric revenues increased for 2020 primarily due to higher sales volumes to residential and commercial customers for 2020 as compared to 2019. This resulted from weather that was cooler than the prior year, as well as more hydroelectric generation than 2019.
AEL&P had low hydroelectric generation during the year ended December 31, 2019, which limited energy provided to their interruptible customers. A portion of the sales to interruptible customers is used to reduce the overall cost of power to AEL&P's firm customers. When interruptible sales are below a certain threshold, AEL&P recognizes a regulatory asset and records a reduction to deferred power supply costs (resource costs) to reflect a future billable amount to its firm customers when the cost of power rates are reset. During the year ended December 31, 2020, hydroelectric generation returned to normal levels, which resulted in more resource costs compared to the year ended December 31, 2019.
Results of Operations - Other Businesses
2020 compared to 2019
The net loss from these operations was $3.4 million for 2020 compared to net income of $5.5 million for 2019. In 2020, we had impairment losses on some of our investments and the write-off of a note receivable. This is compared to 2019 that resulted in net investment gains, primarily related to the sale of METALfx. See "Note 26 of the Notes to Consolidated Financial Statements" for further discussion of the sale of METALfx.
Accounting Standards to be Adopted in 2021
At this time, we are not expecting the adoption of accounting standards to have a material impact on our financial condition, results of operations and cash flows in 2021. For information on accounting standards adopted in 2020 and accounting standards expected to be adopted in future periods, see “Note 2 of the Notes to Consolidated Financial Statements.”
Critical Accounting Policies and Estimates
The preparation of our consolidated financial statements in conformity with GAAP requires us to make estimates and assumptions that affect amounts reported in the consolidated financial statements. Changes in these estimates and assumptions are considered reasonably possible and may have a material effect on our consolidated financial statements and thus actual results could differ from the amounts reported and disclosed herein. The following accounting policies represent those that our
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management believes are particularly important to the consolidated financial statements and require the use of estimates and assumptions:
Pension Plans and Other Postretirement Benefit Plans - Avista Utilities
We have a defined benefit pension plan covering substantially all regular full-time employees at Avista Utilities that were hired prior to January 1, 2014. For substantially all regular non-union full-time employees at Avista Utilities who were hired on or after January 1, 2014, a defined contribution 401(k) plan replaced the defined benefit pension plan. Union employees hired on or after January 1, 2014 are still covered under the defined benefit pension plan.
The Finance Committee of the Board of Directors approves investment policies, objectives and strategies that seek an appropriate return for the pension plan and it reviews and approves changes to the investment and funding policies.
We have contracted with an independent investment consultant who is responsible for monitoring the individual investment managers. The investment managers’ performance and related individual fund performance is reviewed at least quarterly by an internal benefits committee and by the Finance Committee to monitor compliance with our established investment policy objectives and strategies.
Our pension plan assets are invested in debt securities and mutual funds, trusts and partnerships that hold marketable debt and equity securities, real estate and absolute return funds. In seeking to obtain a return that aligns with the funded status of the pension plan, the investment consultant recommends allocation percentages by asset classes. These recommendations are reviewed by the internal benefits committee, which then recommends their adoption by the Finance Committee. The Finance Committee has established target investment allocation percentages by asset classes and also investment ranges for each asset class. The target investment allocation percentages are typically the midpoint of the established range. See “Note 11 of the Notes to Consolidated Financial Statements” for the target investment allocation percentages.
We also have a Supplemental Executive Retirement Plan (SERP) that provides additional pension benefits to certain executive officers and others whose benefits under the pension plan are reduced due to the application of Section 415 of the Internal Revenue Code of 1986 and the deferral of salary under deferred compensation plans.
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Pension costs (including the SERP) were $22.3 million for 2020, $26.9 million for 2019 and $22.8 million for 2018. 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:
• the amount of cash contributions we make to the pension plan,
• the actual return on pension plan assets,
• expected return on pension plan assets,
• 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.
In accordance with accounting standards, changes in pension plan obligations associated with these factors may not be immediately recognized as pension costs in our Consolidated Statements of Income, but we generally recognize the change in future years over the remaining average service period of pension plan participants. As such, our costs recorded in any period may not reflect the actual level of cash benefits provided to pension plan participants.
We revise the key assumption of the discount rate each year. In selecting a discount rate, we consider yield rates at the end of the year for highly rated corporate bond portfolios with cash flows from interest and maturities similar to that of the expected payout of pension benefits.
The expected long-term rate of return on plan assets is reset or confirmed annually based on past performance and economic forecasts for the types of investments held by our plan.
The following chart reflects the assumptions used each year for the pension discount rate (exclusive of the SERP), the expected long-term return on plan assets and the actual return on plan assets and their impacts to the pension plan associated with the change in assumption (dollars in millions):
Discount rate (exclusive of SERP)
Increase/(decrease) to projected benefit obligation $ 62.6 $ 41.7 $ (54.7 )
Return on plan assets (a)
Expected long-term return on plan assets 5.50 % 5.90 % 5.50 %
Increase/(decrease) to pension costs $ 2.5 $ (2.2 ) $ 2.2
Actual return on plan assets, net of fees 15.20 % 20.40 % (7.00 )%
Actual gain/(loss) on plan assets $ 96.6 $ 109.9 $ (41.0 )
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The following chart reflects the sensitivities associated with a change in certain actuarial assumptions by the indicated percentage (dollars in millions):
Expected long-term return on plan assets (0.5 )% $ — * $ 3.2
Expected long-term return on plan assets 0.5 % — * (3.2 )
*Changes in the expected return on plan assets would not affect our projected benefit obligation.
We provide certain health care and life insurance benefits for substantially all of our retired employees. We accrue the estimated cost of postretirement benefit obligations during the years that employees provide service.
Liquidity and Capital Resources
Overall Liquidity
Avista Corp.'s consolidated operating cash flows are primarily derived from the operations of Avista Utilities. The primary source of operating cash flows for Avista Utilities is revenues from sales of electricity and natural gas. Significant uses of cash flows from Avista Utilities include the purchase of power, fuel and natural gas, and payment of other operating expenses, taxes and interest, with any excess being available for other corporate uses such as capital expenditures and dividends.
We design operating and capital budgets to control operating costs and to direct capital expenditures to choices that support immediate and long-term strategies, particularly for our regulated utility operations. In addition to operating expenses, we have continuing commitments for capital expenditures for construction and improvement of utility facilities.
Our annual net cash flows from operating activities usually do not fully support the amount required for annual utility capital expenditures. As such, from time-to-time, we need to access capital markets in order to fund these needs as well as fund maturing debt. See further discussion at “Capital Resources.”
We periodically file for rate adjustments for recovery of operating costs and capital investments and to seek the opportunity to earn reasonable returns as allowed by regulators.
Avista Utilities has regulatory mechanisms in place that provide for the deferral and recovery of the majority of power and natural gas supply costs. However, when power and natural gas costs exceed the levels currently recovered from retail customers, net cash flows are negatively affected. Factors that could cause purchased power and natural gas costs to exceed the levels currently recovered from our customers include, but are not limited to, higher prices in wholesale markets when we buy energy or an increased need to purchase power in the wholesale markets, and a lack of regulatory approval for higher authorized net power supply costs through general rate case decisions. Factors beyond our control that could result in an increased need to purchase power in the wholesale markets include, but are not limited to:
• increases in demand (due to either weather or customer growth),
• lower streamflows for hydroelectric generation,
• unplanned outages at generating facilities, and
• failure of third parties to deliver on energy or capacity contracts.
In addition to the above, Avista Utilities enters into derivative instruments to hedge our exposure to certain risks, including fluctuations in commodity market prices, foreign exchange rates and interest rates (for purposes of issuing long-term debt in the future). These derivative instruments often require collateral (in the form of cash or letters of credit) or other credit enhancements, or reductions or terminations of a portion of the contract through cash settlement, in the event of a downgrade in the Company's credit ratings or changes in market prices. In periods of price volatility, the level of exposure can change
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significantly. As a result, sudden and significant demands may be made against the Company's credit facilities and cash. See “Enterprise Risk Management – Credit Risk Liquidity Considerations” below.
We monitor the potential liquidity impacts of changes to energy commodity prices and other increased operating costs for our utility operations. We believe that we have adequate liquidity to meet such potential needs through our committed lines of credit.
As of December 31, 2020, we had $270.4 million of available liquidity under the Avista Corp. committed line of credit and $24.0 million under the AEL&P committed line of credit. With our $400.0 million credit facility that expires in April 2022 and AEL&P's $25.0 million credit facility that expires in November 2024, we believe that we have adequate liquidity to meet our needs for the next 12 months.
Review of Consolidated Cash Flow Statement
2020 compared to 2019
Consolidated Operating Activities
Net cash provided by operating activities was $331.0 million for 2020 compared to $398.2 million for 2019. The decrease in net cash provided by operating activities primarily relates to a termination fee of $103.0 million (less transaction costs and income taxes of $19.7 million and $15.7 million, respectively) received in 2019 upon the termination of the proposed Hydro One transaction. For further information, see "Note 25 of the Notes to Consolidated Financial Statements.” In addition, the settlement of interest rate swaps decreased operating cash flows as we paid a net amount of $33.5 million during 2020 compared to $13.3 million paid during 2019. As compared to 2019, certain net current assets and liabilities decreased cash flow by $96.0 million, mostly due to an increase in income taxes receivable related to the CARES Act and a Strategic Tax Review by the Company. In addition, cash flow for collateral posted for derivative instruments decreased due to settlement of interest rate swaps in 2020.
The decreases above, were partially offset by power and natural gas deferrals which decreased during 2020 due to lower natural gas prices during the year (which decreased cash flows by $9.9 million as compared to a decrease to operating cash flows of $45.9 million in 2019). In addition, provision for deferred income taxes increased during 2020 (increased cash flows by $44.9 million as compared to an increase to operating cash flows of $15.1 million in 2019).
Consolidated Investing Activities
Net cash used in investing activities was $410.7 million for 2020, a decrease compared to $445.5 million for 2019. During 2020, we paid $404.3 million for utility capital expenditures, compared to $442.5 million for 2019. In addition, in 2020, we received proceeds from the sale of equity investments (net of cash sold and amounts held in escrow) of $6.8 million. The decreases to cash used in investing activities were partially offset by the sale of METALfx in 2019, in which we received $16.5 million of proceeds. For further information, see "Note 26 of the Notes to Consolidated Financial Statements."
Consolidated Financing Activities
Net cash provided by financing activities was $84.0 million for 2020 compared to $42.5 million for 2019. The increase in financing cash flows was primarily the result of changes in short-term borrowings of $21.4 million compared to 2019. In addition, there was a decrease in maturing long-term debt and finance leases of $37.9 million compared to 2019. The above increases were partially offset by a decrease in proceeds from the issuance of long-term debt of $15.0 million compared to 2019.
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Capital Resources
Capital Structure
Our consolidated capital structure, including the current portion of long-term debt and short-term borrowings, and excluding noncontrolling interests, consisted of the following as of December 31, 2020 and 2019 (dollars in thousands):
Amount Percent of total Amount Percent of total
Current portion of long-term debt and leases $ 7,184 0.2 % $ 58,928 1.4 %
Our shareholders’ equity increased $90.4 million during 2020 primarily due to net income and the issuance of common stock, partially offset by dividends.
We need to finance capital expenditures and acquire additional funds for operations from time to time. The cash requirements needed to service our indebtedness, both short-term and long-term, reduce the amount of cash flow available to fund capital expenditures, purchased power, fuel and natural gas costs, dividends and other requirements.
Committed Lines of Credit
Avista Corp. has a committed line of credit with various financial institutions in the total amount of $400.0 million that expires in April 2022. As of December 31, 2020, there was $270.4 million of available liquidity under this line of credit.
The Avista Corp. credit facility contains customary covenants and default provisions, including a covenant which does not permit our ratio of “consolidated total debt” to “consolidated total capitalization” to be greater than 65 percent at any time. As of December 31, 2020, we were in compliance with this covenant with a ratio of 54.0 percent.
Balances outstanding and interest rates on borrowings (excluding letters of credit) under Avista Corp.'s committed line of credit were as follows as of and for the year ended December 31 (dollars in thousands):
Letters of credit outstanding at end of year $ 27,618 $ 21,473
Maximum balance outstanding during the year $ 310,000 $ 221,000
Average balance outstanding during the year $ 138,890 $ 148,616
Average interest rate during the year 1.59 % 3.05 %
Average interest rate at end of year 1.22 % 2.64 %
In November of 2019, AEL&P renewed its $25.0 million committed line of credit with a new expiration date in November 2024. As of December 31, 2020, there was $24.0 million of available liquidity under this line of credit.
The AEL&P credit facility contains customary covenants and default provisions including a covenant which does not permit the ratio of “consolidated total debt at AEL&P” to “consolidated total capitalization at AEL&P,” (including the impact of the Snettisham obligation) to be greater than 67.5 percent at any time. As of December 31, 2020, AEL&P was in compliance with this covenant with a ratio of 53.0 percent.
As of December 31, 2020, Avista Corp. and its subsidiaries were in compliance with all of the covenants of their financing agreements, and none of Avista Corp.'s subsidiaries constituted a “significant subsidiary” as defined in Avista Corp.'s committed line of credit.
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In April 2020, we entered into a $100.0 million credit agreement with an expiration date of April 2021. We borrowed the entire $100.0 million available under this agreement. In April 2021, we intend to pay the full amount outstanding with a draw on our committed line of credit. See "Note 15 of the Notes to Consolidated Financial Statements."
Long-Term Debt
In September 2020, we issued and sold $165.0 million of 3.07 percent first mortgage bonds due in 2050 pursuant to a bond purchase agreement with institutional investors in the private placement market. The total net proceeds from the sale of the bonds were used to repay maturing long-term debt of $52.0 million and repay a portion of the outstanding balance under our $400.0 million committed line of credit. In connection with the pricing of the first mortgage bonds in June 2020, we cash-settled seven interest rate swap derivatives (notional aggregate amount of $70.0 million) and paid a net amount of $33.5 million. 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.
Equity Issuances
We issued equity in 2020 for total net proceeds of $72.2 million. Most of these issuances came through our sales agency agreements under which the sales agents may offer and sell new shares of our common stock from time to time. We have board and regulatory authority to issue a maximum of 3.2 million shares, of which 1.3 million remain unissued as of December 31, 2020. In 2020, 1.9 million shares were issued under these agreements resulting in total net proceeds of $70.6 million.
2021 Liquidity Expectations
During 2021, we expect to issue approximately $120.0 million of long-term debt and up to $75.0 million of equity in order to refinance maturing long-term debt and fund planned capital expenditures.
After considering the expected issuances of long-term debt and equity during 2021, we expect net cash flows from operating activities, together with cash available under our committed line of credit agreements, to provide adequate resources to fund capital expenditures, dividends, and other contractual commitments.
Limitations on Issuances of Preferred Stock and First Mortgage Bonds
We are restricted under our Restated Articles of Incorporation, as amended, as to the additional preferred stock we can issue. As of December 31, 2020, we could issue $2.8 billion of preferred stock at an assumed dividend rate of 4.8 percent. We are not planning to issue preferred stock.
Under the Avista Corp. and the AEL&P Mortgages and Deeds of Trust securing Avista Corp.'s and AEL&P's first mortgage bonds (including Secured Medium-Term Notes), respectively, each entity may issue additional first mortgage bonds in an aggregate principal amount equal to the sum of:
• deposit of cash.
However, Avista Corp. and AEL&P may not individually issue any additional first mortgage bonds (with certain exceptions in the case of bonds issued on the basis of retired bonds) unless the particular entity issuing the bonds has “net earnings” (as defined in the respective Mortgages) for any period of 12 consecutive calendar months out of the preceding 18 calendar months that were at least twice the annual interest requirements on that entity's mortgage securities at the time outstanding, including the first mortgage bonds to be issued, and on all indebtedness of prior rank. As of December 31, 2020, property additions and retired bonds would have allowed, and the net earnings test would not have prohibited, the issuance of $1.7 billion in aggregate principal amount of additional first mortgage bonds at Avista Corp. and $36.1 million at AEL&P. We believe that we have adequate capacity to issue first mortgage bonds to meet our financing needs over the next several years.
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Utility Capital Expenditures
We are making capital investments at our utilities to enhance service and system reliability for our customers and replace aging infrastructure. The following table summarizes our actual and expected capital expenditures as of and for the year ended December 31, 2020 (in thousands):
Avista Utilities AEL&P
2020 Actual capital expenditures
Expected total annual capital expenditures (by year)
The following graph shows Avista Utilities' expected capital expenditures for 2021 by category (in millions):
These estimates of capital expenditures are subject to continuing review and adjustment. Actual expenditures may vary from our estimates due to factors such as changes in business conditions, construction schedules and environmental requirements.
Non-Regulated Investments and Capital Expenditures
We are making investments and capital expenditures at our other businesses including those related to economic development projects in our service territory that demonstrate the latest energy and environmental building innovations and house several local college degree programs. In addition, we are making investments in emerging technology companies and venture capital
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funds. The following table summarizes our actual and expected investments and capital expenditures at our other businesses as of and for the year ended December 31, 2020 (in thousands):
Other
2020 Actual investments and capital expenditures
Expected total annual investments and capital expenditures (by year)
These estimates of investments and capital expenditures are subject to continuing review and adjustment. Actual expenditures may vary from our estimates due to factors such as changes in business conditions or strategic plans.
See “Contractual Obligations” for information regarding other material cash requirements for 2021 and thereafter.
Off-Balance Sheet Arrangements
As of December 31, 2020, we had $27.6 million in letters of credit outstanding under our $400 million committed line of credit, compared to $21.5 million as of December 31, 2019.
Pension Plan
We contributed $22.0 million to the pension plan in 2020. We expect to contribute a total of $150.0 million to the pension plan in the period 2021 through 2025, with an annual contribution of $42.0 million for 2021 and 2022 and $22.0 million from 2023 to 2025.
The final determination of pension plan contributions for future periods is subject to multiple variables, most of which are beyond our control, including changes to the fair value of pension plan assets, changes in actuarial assumptions (in particular the discount rate used in determining the benefit obligation), or changes in federal legislation. We may change our pension plan contributions in the future depending on changes to any variables, including those listed above.
See "Note 11 of the Notes to Consolidated Financial Statements" for additional information regarding the pension plan.
Credit Ratings
Our access to capital markets and our cost of capital are directly affected by our credit ratings. In addition, many of our contracts for the purchase and sale of energy commodities contain terms dependent upon our credit ratings. See “Enterprise Risk Management – Credit Risk Liquidity Considerations” and “Note 7 of the Notes to Consolidated Financial Statements.”
The following table summarizes our credit ratings as of February 23, 2021:
Standard & Poor’s (1) Moody’s (2)
Corporate/Issuer rating BBB Baa2
Senior secured debt A- A3
Senior unsecured debt BBB Baa2
(1) Standard & Poor’s lowest “investment grade” credit rating is BBB-.
(2) Moody’s lowest “investment grade” credit rating is Baa3.
A security rating is not a recommendation to buy, sell or hold securities. Each security rating is subject to revision or withdrawal at any time by the assigning rating organization. Each security rating agency has its own methodology for assigning ratings, and, accordingly, each rating should be considered in the context of the applicable methodology, independent of all other ratings. The rating agencies provide ratings at the request of Avista Corp. and charge fees for their services.
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Dividends
See "Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities" for a detailed discussion of our dividend policy and the factors which could limit the payment of dividends.
Contractual Obligations
The following table provides a summary of future contractual obligations as of December 31, 2020 (dollars in millions):
Avista Utilities:
Short-term borrowings 202 — — — — —
Other businesses (consolidated) total contractual obligations (7) 15 6 6 20 2 —
The remainder of our other obligations are related to the net mark-to-market fair value of outstanding unsettled interest rate swap derivatives as of December 31, 2020. The values will change each period depending on fluctuations in market interest rates and could become either assets or liabilities until the period of settlement. Also, the amounts in the table above are not reflective of cash collateral of $8.1 million that is already posted with counterparties against the outstanding interest rate swap derivatives. See “Note 7 of the Notes to Consolidated Financial Statements” for further discussion of our interest rate swaps.
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The above contractual obligations do not include income tax payments. Also, asset retirement obligations (ARO) are not included above and payments associated with these have historically been less than $2 million per year. There are approximately $17.2 million remaining asset retirement obligations as of December 31, 2020.
In addition to the contractually obligated cash outflows disclosed above, we will incur additional operating costs and capital expenditures in future periods for which we are not contractually obligated as part of our normal business operations.
Competition
Our utility electric and natural gas distribution business has historically been recognized as a natural monopoly. In each regulatory jurisdiction, our rates for retail electric and natural gas services (other than specially negotiated retail rates for industrial or large commercial customers, which are subject to regulatory review and approval) are generally determined on a “cost of service” basis. Rates are designed to provide, after recovery of allowable operating expenses and capital investments, an opportunity for us to earn a reasonable return on investment as allowed by our regulators.
In retail markets, we compete with various rural electric cooperatives and public utility districts in and adjacent to our service territories in the provision of service to new electric customers. Alternative energy technologies, including customer-sited solar, wind or geothermal generation, or energy storage may also compete with us for sales to existing customers. Advances in power generation, energy efficiency, energy storage and other alternative energy technologies could lead to more wide-spread usage of these technologies, thereby reducing customer demand for the energy supplied by us. This reduction in usage and demand would reduce our revenue and negatively impact our financial condition including possibly leading to our inability to fully recover our investments in generation, transmission and distribution assets. Similarly, our natural gas distribution operations compete with other energy sources including heating oil, propane and other fuels.
Certain natural gas customers could bypass our natural gas system, reducing both revenues and recovery of fixed costs. To reduce the potential for such bypass, we price natural gas services, including transportation contracts, competitively and have varying degrees of flexibility to price transportation and delivery rates by means of individual contracts. These individual contracts are subject to state regulatory review and approval. We have long-term transportation contracts with several of our largest industrial customers under which the customer acquires its own commodity while using our infrastructure for delivery. Such contracts reduce the risk of these customers bypassing our system in the foreseeable future and minimizes the impact on our earnings.
Customers may have a choice in the future over the sources from which to receive their energy. In order to effectively compete for our customers in the future, we continue to strive to create value through product and service offerings. We are also attempting to enhance the effectiveness and ease of our customer interactions with us by tailoring our internal company initiatives to focus on choices for our customers to increase their overall satisfaction with the Company.
Also, non-utility businesses are developing new technologies and services to help energy consumers manage energy in new ways that may improve productivity and could alter demand for the energy we sell.
In wholesale markets, competition for available electric supply is influenced by the:
• localized and system-wide demand for energy,
• type, capacity, location and availability of generation resources, and
• variety and circumstances of market participants.
These wholesale markets are regulated by the FERC, which requires electric utilities to:
• transmit power and energy to or for wholesale purchasers and sellers,
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Participants in the wholesale energy markets include:
• other utilities,
• federal power marketing agencies,
• energy marketing and trading companies,
• independent power producers,
• financial institutions, and
• commodity brokers.
Economic Conditions and Utility Load Growth
The general economic data, on both national and local levels, contained in this section is based, in part, on independent government and industry publications, reports by market research firms or other independent sources. While we believe that these publications and other sources are reliable, we have not independently verified such data and can make no representation as to its accuracy.
Avista Utilities
We track multiple economic indicators affecting the three largest metropolitan statistical areas in our Avista Utilities service area: Spokane, Washington, Coeur d'Alene, Idaho, and Medford, Oregon. The key indicators are employment change and unemployment rates. On an annual basis, 2020 showed negative job growth with higher unemployment rates in all three metropolitan areas. This reflects the impact of the COVID-19 induced recession that started in the first quarter of 2020. However, the unemployment rates in Spokane and Medford are still above the national average. Other leading indicators, such as initial unemployment claims and residential building permits, signal a return to growth over the next 12 months. Considering all relevant indicators, we expect economic growth in our service area in 2021 to be in-line with the U.S. as a whole.
Due to the COVID-19 recession, nonfarm employment (seasonally adjusted) in our eastern Washington, northern Idaho, and southwestern Oregon metropolitan service areas declined in 2020. In Spokane, Washington employment declined 4.2 percent with losses in all major sectors except professional and business services. Employment declined 3.8 percent in Coeur d'Alene, Idaho, reflecting losses all major sectors except manufacturing; trade, transportation, and utilities; information; financial services; and education and health. In Medford, Oregon, employment declined 4 percent, with losses in all major sectors except financial activities and education and health services. U.S. nonfarm sector jobs declined 5.7 percent over the same period.
Changes in the unemployment rate in 2020 reflect the impact of the COVID-19 recession. In Spokane the unemployment rate was 5.4 percent in 2019 and increased to 9.2 percent in 2020; in Coeur d'Alene the rate increased from 3.6 percent in 2019 to 7.3 percent in 2020; and in Medford the rate increased from 4.3 percent in 2019 to 8.4 percent in 2020. The U.S. unemployment rate increased from 3.7 in 2019 percent to 8.1 percent in 2020.
Alaska Electric Light and Power Company
Our AEL&P service area is centered in Juneau. Although Juneau is Alaska’s state capital, it is not a metropolitan statistical area. This means breadth and frequency of economic data is more limited. Therefore, the dates of Juneau's economic data may significantly lag the period of this filing.
The Quarterly Census of Employment and Wages for Juneau shows employment declined 10.5 percent between the first half of 2019 and first half of 2020. There were employment losses in all major sectors, except construction. Government employment declined 3.1 percent during this period; this sector accounted for 37 percent of total employment in 2019. Between 2019 and 2020, the unemployment rate increased from 4.4 percent to 6.9 percent.
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Forecasted Customer and Load Growth
Based on our forecast for 2021 through 2024 for Avista Utilities' service area, we expect annual electric customer growth to average 1.0 percent, within a forecast range of 0.6 percent to 1.4 percent. We expect annual natural gas customer growth to average 1.2 percent, within a forecast range of 0.6 percent to 1.8 percent. We anticipate retail electric load growth to average 0.5 percent, within a forecast range of 0.2 percent and 0.8 percent. We expect natural gas load growth to average 1.1 percent, within a forecast range of 0.6 percent and 1.6 percent. The forecast ranges reflect (1) the inherent uncertainty associated with the economic assumptions on which forecasts are based and (2) the historic variability of natural gas customer and load growth.
In AEL&P's service area, we expect no significant growth in residential, commercial and government customers for the period 2021 through 2024. We anticipate average annual total load growth will be in a narrow range around 0.3 percent, with residential load growth averaging 0.6 percent and commercial and government growth near 0 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 business plans,
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 are subject to environmental laws relating to site conditions, air emissions, wastewater and stormwater discharges, waste handling, and other similar activities. 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 and productivity of our generating plants and other assets.
Environmental laws and regulations may restrict or impact our business activities in many ways, including, but not limited to:
• increase the operating costs of generating plants;
• require modification of our existing generating plants;
• require existing generating plant operations to be curtailed or shut down;
• reduce the amount of energy available from our generating plants;
• restrict the types of generating plants that can be built or contracted with;
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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.
Clean Energy Commitment
In April 2019, we announced a goal to serve our customers with 100 percent clean electricity by 2045 and to have a carbon-neutral supply of electricity by the end of 2027. To help achieve our goals and add to our clean electricity portfolio, in the last three years, we have implemented three renewable energy projects on behalf of our customers: the Community Solar project (0.4 MW) in Spokane Valley, Washington (owned by Avista Corp.), the Solar Select project (28 MW) in Lind, Washington (PPA), and the Rattlesnake Flat Wind project (144 MW) in Adams County, Washington (PPA). These resources are in addition to our existing clean hydroelectric generation, biomass generation, and additional wind and solar projects.
To achieve our clean energy goals, we expect that energy storage and other technologies, which are either not currently available or are not cost-effective under a lowest reasonable cost regulatory standard, will advance such that it will allow us to meet our goals while also maintaining reliability and affordability for our customers. If the required technology is not available or not affordable in the future, we may not meet our goals in the desired timeframe. Meeting our clean energy goals may also require accommodation from economic regulatory agencies insofar as the Company may need to acquire emission offsets to meet its goals. See the discussion in Item 1 under “Electric Resources” for more information on our existing clean electricity sources and efforts to achieve these goals.
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 increase or decrease customer demand.
Avista 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 the Perform Council, is potential risks and opportunities associated with long-term global climate change. Among other things, the Perform Council:
In addition to the Perform Council, issues concerning climate-related risk and the Company’s clean energy goals are reviewed and regularly discussed by the Board of Directors. The Board’s Environmental, 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 climate-related disclosures in the Company’s financial statements.
Federal Regulatory Actions
In June 2019, the EPA released the final version of the Affordable Clean Energy (ACE) rule, the replacement for the Clean Power Plan (CPP). The final ACE rule combined three distinct EPA actions:
First, EPA finalized the repeal of the CPP. The CPP was comprised of three “building blocks” identified by the EPA as follows:
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Notably, the second and third building blocks, responsible for the majority of projected emission reductions, were premised on “beyond the fence” measures to reduce emissions.
Second, the EPA finalized the ACE rule, which comprised the EPA’s determination of the Best System of Emissions Reduction (BSER) for existing coal-fired power plants and procedures that would govern States’ promulgation of standards of performance for such plants within their borders. EPA set the final BSER as heat rate efficiency improvements based on a range of “candidate technologies” that can be applied to a plant's operating units and requires that each State determine which apply to each coal-fired unit based on consideration of remaining useful plant life. Contrary to the CPP, ACE relied solely on emission reductions from the specific source, or “inside the fence.”
Lastly, the ACE rule included implementing regulations for State plans.
In January 2021, the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit) vacated the ACE Rule and remanded the record back to the EPA for further consideration consistent with its opinion, finding that the EPA misinterpreted the Clean Air Act when it determined that the language of Section 111 barred consideration of emissions reduction options that were not applied at the source. The Court also vacated the repeal of the CPP. The EPA will now act on remand, and it is unclear what next steps the EPA will take. Given the complex and uncertain legal record with respect to the CPP, and the confirmation testimony of the incoming EPA Administrator that the Court’s ruling was an opportunity for the EPA to “take a clean slate” in this area, we expect new rulemaking in the future.
Given the status of the EPA’s rulemaking, we cannot reasonably predict the timing, outcome or applicability of these issues with respect to any of Avista’s generation resources.
Washington Legislation and Regulatory Actions
Energy Independence Act (EIA)
The EIA in Washington requires electric utilities with over 25,000 customers to acquire qualified renewable energy resources and/or renewable energy credits equal to 15 percent of the utility's total retail load in Washington in 2020. The EIA also requires these utilities to meet biennial energy conservation targets. Failure to comply with renewable energy and efficiency standards could result in penalties of $50 per MWh or greater assessed against a utility for each MWh it is deficient in meeting a standard. We meet the requirements of the EIA through a variety of renewable energy generating means, including, but not limited to, some combination of qualifying hydroelectric upgrades, wind, biomass and renewable energy credits.
Clean Air Rule
In September 2016, Ecology adopted the Clean Air Rule (CAR) to cap and reduce greenhouse gas (GHG) emissions across the State of Washington in pursuit of the State’s GHG goals, which were enacted in 2008 by the Washington State Legislature. The CAR applies to sources of annual GHG emissions in excess of 100,000 tons for the first compliance period of 2017 through 2019; this threshold incrementally decreases to 70,000 metric tons beginning in 2035. The rule affects stationary sources and transportation fuel suppliers, as well as natural gas distribution companies. Ecology originally identified approximately 30 entities that would be regulated under the CAR. Parties covered by the regulation will be required to reduce emissions by 1.7 percent annually until 2035. Compliance can be demonstrated by achieving emission reductions and/or surrendering Emission Reduction Units (ERU), which are generated by parties that achieve reductions greater than required by the rule. Allowable ERUs can also take the form of renewable energy credits from renewable resources located in Washington, carbon emission offsets, and allowances acquired from an organized cap and trade market, such as the one operating in California. In addition to the CAR's applicability to our burning of fuel as an electric utility, the CAR would apply to us as a natural gas distribution
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company, for the emissions associated with the use of the natural gas we provide our customers who are not already covered under the regulation.
In September 2016, Avista Corp., Cascade Natural Gas Corp., NW Natural and Puget Sound Energy (PSE) (collectively, Petitioners) jointly filed an action in the U.S. District Court for the Eastern District of Washington challenging Ecology’s promulgated CAR. The four companies also filed litigation in Thurston County Superior Court.
The case in the U.S. District Court has been stayed while the state court case proceeded. On December 15, 2017, the Thurston County Superior Court issued a ruling invalidating the CAR. Ecology subsequently appealed the ruling, and the Washington State Supreme Court accepted review. On January 16, 2020, the Washington State Supreme Court issued a decision holding that the CAR was invalid as to non-emitters, such as natural gas distributors, but could be enforced against direct emitters, such as natural gas generation plants. The Court has remanded the matter to Thurston County Superior Court, where claims previously raised before, but not addressed by, that court may be revised with respect to, among other issues, alleged procedural infirmities. At this time, we are evaluating the potential impact of the surviving portion of the rule, if any, to our generation facilities, should their emissions exceed the rule’s compliance threshold. The rule is not intended to apply to the Kettle Falls Generating Station. We plan to seek recovery of any costs related to compliance with the surviving portion of the CAR through the ratemaking process.
Clean Energy Transformation Act
In 2019, the Washington State Legislature passed the CETA, which requires Washington utilities to eliminate the costs and benefits associated with coal-fired resources from their retail electric sales by December 31, 2025. This requirement would effectively prohibit sales of energy produced by coal-fired generation to Washington retail customers after December 31, 2025. In addition, CETA establishes the policy of Washington State that all retail sales of electricity to Washington customers must be carbon-neutral by January 1, 2030 and requires that each electric utility demonstrate compliance with this standard by using electricity from renewable and other non-emitting resources for 100 percent of the utility’s retail electric load over consecutive multi-year compliance periods; provided, however, that through December 31, 2044 the utility may satisfy up to 20 percent of this requirement with specified payments, credits and/or investments in qualifying energy transformation projects. The law has direct, specific impacts on Colstrip, which are unique to those owners of Colstrip who serve Washington customers. See “Colstrip” section for further details on the impacts of CETA on Colstrip. Our hydroelectric and biomass generation facilities can be used to comply with the CETA’s clean energy standards. CETA also effectuated changes to laws governing the WUTC. Several Washington agencies have established regulations under the CETA to guide implementation, and further rulemaking is ongoing. We intend to seek recovery of any costs associated with the clean energy legislation and regulations through the regulatory process.
Washington Policy Statement
In conjunction with the CETA, on January 31, 2020, the WUTC issued a policy statement concerning the treatment of used and useful plant in the context of rate filings, including in multi-year rate plans. The policy statement intends to achieve four goals:
•ensure general consistency with longstanding ratemaking practices, principles, and standards;
•maintain flexibility in ratemaking;
•avoid overly prescriptive guidance; and
•support streamlined processes.
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
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levels higher than 1,100 pounds of GHG per MWh. The Washington State Department of Commerce reviews the standard every five years. In September 2018, it adopted a new standard of 925 pounds of GHG per MWh. We intend to seek recovery of costs related to ongoing and new requirements through the ratemaking process.
GHG Reduction Targets
The State of Washington has adopted non-binding targets to reduce GHG emissions. The State enacted its targets with an expectation of reaching the targets through a combination of renewable energy standards, eventual carbon pricing mechanisms, such as cap and trade regulation or a carbon tax, and assorted “complementary policies.” However, no specific reductions are mandated as yet. The State’s targets, originally enacted in 2008, have been evaluated by state institutions against the aims of the Paris Climate Accord of 2016, which include limiting the increase in the global average temperatures to at least below 2 degrees Celsius above pre-industrial levels and pursuing efforts to restrict the temperature increase to 1.5 degrees Celsius above pre-industrial levels. The ultimate targets would achieve greenhouse gas emissions reductions of 95% below 1990 levels by 2050, with the remaining 5% being offset for the state to achieve net-zero emissions. These targets will be used to inform future climate change legislation. We cannot reasonably predict how the state legislature may propose to meet the State's targets in the future. We intend to seek recovery of any new costs associated with these reduction targets, or any new reduction targets, through the regulatory process.
Oregon Legislation and Regulatory Actions
GHG Reduction Targets
The State of Oregon has adopted non-binding targets to reduce GHG emissions. The State enacted its targets with an expectation of reaching the targets through a combination of renewable energy standards, eventual carbon pricing mechanisms, such as cap and trade regulation or a carbon tax, and assorted “complementary policies.” However, no specific reductions are mandated as yet. The State’s targets have been evaluated by state institutions against the aims of the Paris Climate Accord of 2016, which include limiting the increase in global average temperatures to at least below 2 degrees Celsius above pre-industrial levels and pursuing efforts to restrict the temperature increase to 1.5 degrees Celsius above pre-industrial levels. In March 2020, Oregon Governor Kate Brown issued Executive Order No. 20-04, “Directing State Agencies to Take Actions to Reduce and Regulate Greenhouse Gas Emissions.” The Executive Order launched rulemaking proceedings for every Oregon agency with jurisdiction over greenhouse gas-related matters, with the aim of reducing Oregon’s overall GHG emissions to 80% below 1990 levels by 2050. Oregon agencies, including the Department of Environmental Quality (DEQ) and the Public Utility Commission, issued reports discussing general intent to carry out the Executive Order. DEQ is tasked with developing rules for a cap and reduce program that would apply to our natural gas distribution business in Oregon. The agency initiated informal and broad stakeholder consultation in June 2020, and, along with other agencies, is now moving into formal rulemaking. We cannot reasonably predict the impact of regulatory proceedings arising from the Executive Order, nor how the state legislature may undertake additional requirements or revise the State's targets in the future. We intend to seek recovery of any new costs associated with these reduction targets, or any new reduction targets, through the regulatory process.
Emissions Performance Standard
Like Washington, Oregon applies a GHG emissions performance standard to electric generation facilities, requiring that any new baseload natural gas plant, non-base load natural gas plant, and non-generating facility reduce its net carbon dioxide emissions 17% below the most efficient combustion-turbine plant in the United States. The Oregon Energy Facility Siting Council issues rules periodically to update the standard, as more efficient power plants are built in other states. The standard can be met by any combination of efficiency, cogeneration, and offsets from carbon dioxide mitigation measures. We intend to seek recovery of costs related to ongoing and new requirements through the ratemaking process.
Clean Electricity and Coal Transition Act
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In Oregon, legislation was enacted in 2016 which requires Portland General Electric and PacifiCorp to remove coal-fired generation from their Oregon rate base by 2030. This legislation does not directly relate to Avista Corp. because Avista Corp. is not an electric utility in Oregon. However, because these two utilities, along with Avista Corp., hold minority interests in Colstrip, the legislation could indirectly impact Avista Corp., though specific impacts cannot be reasonably predicted at this time. While the legislation requires Portland General Electric and PacifiCorp to eliminate Colstrip from their rates, they would be permitted to sell the output of their shares of Colstrip into the wholesale market or, as is the case with PacifiCorp, reallocate generation from Colstrip to other states. We cannot predict the eventual outcome of actions arising from this legislation at this time or estimate the effect thereof on Avista Corp.; however, we intend to continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to our generation assets.
Clean Air Act (CAA)
The CAA creates numerous requirements for our thermal generating plants. Colstrip, Kettle Falls GS, Coyote Springs and Rathdrum CT all require CAA Title V operating permits. The Boulder Park GS, Northeast CT and a number of other operations require minor source permits or simple source registration permits. We have secured these permits and certify our compliance with Title V permits on an annual basis. These requirements can change over time as the CAA or applicable implementing regulations are amended and new permits are issued. We actively monitor legislative, regulatory and other program developments of the CAA that may impact our facilities.
Threatened and Endangered Species and Wildlife
A number of species of fish in the Northwest are listed as threatened or endangered under the Federal Endangered Species Act. Efforts to protect these and other species have not significantly impacted generation levels at our hydroelectric facilities, nor operations of our thermal plants or electrical distribution and transmission system. We are implementing fish protection measures at our hydroelectric project on the Clark Fork River under a 45-year FERC operating license for Cabinet Gorge and Noxon Rapids (issued in 2001) that incorporates a comprehensive settlement agreement. The restoration of native salmonid fish, including bull trout, is a key part of the agreement. The result is a collaborative native salmonid restoration program with the U.S. Fish and Wildlife Service, Native American tribes and the states of Idaho and Montana on the lower Clark Fork River, consistent with requirements of the FERC license. The U.S. Fish & Wildlife Service issued an updated Critical Habitat Designation for bull trout in 2010 that includes the lower Clark Fork River, as well as portions of the Coeur d'Alene basin within our Spokane River Project area, and issued a final Bull Trout Recovery Plan under the ESA. Issues related to these activities are expected to be resolved through the ongoing collaborative effort of our Clark Fork and Spokane River FERC licenses.
Various statutory authorities, including the Migratory Bird Treaty Act, have established penalties for the unauthorized take of migratory birds. Because we operate facilities that can pose risks to a variety of such birds, we have developed and follow an avian protection plan.
We are also aware of other threatened and endangered species and issues related to them that could be impacted by our operations and we make every effort to comply with all laws and regulations relating to these threatened and endangered species. We expect costs associated with these compliance efforts to be recovered through the ratemaking process.
Cabinet Gorge Total Dissolved Gas Abatement Plan
Dissolved atmospheric gas levels (referred to as "Total Dissolved Gas" or "TDG") in the Clark Fork River exceed state of Idaho and federal water quality numeric standards downstream of Cabinet Gorge particularly during periods when excess river flows must be diverted over the spillway. Under the terms of the Clark Fork Settlement Agreement as incorporated in Avista Corp.’s FERC license for the Clark Fork Project, Avista Corp. works 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, Avista Corp. will continue to mitigate remaining impacts of TDG while considering the potential for new approaches to further reduce TDG. The Company continues to work with stakeholders to determine the degree to which TDG
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abatement reduces future mitigation obligations. The Company has sought, and intends to continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to this issue.
Other
For other environmental issues and other contingencies see “Note 22 of the Notes to Consolidated Financial Statements.”
Colstrip
Colstrip is a coal-fired generating plant in southeastern Montana that includes four units and which is owned by six separate entities. We have a 15 percent ownership interest in Units 3 & 4 and provide financing for our ownership interest in the project. The other owners are Puget Sound Energy, Portland General Electric, NorthWestern Energy, Pacificorp and Talen Montana (which is also the operator of the plant). In January 2020, the owners of Units 1 & 2, in which we have no ownership, closed those two units. The owners of Units 3 & 4 currently share operating and capital costs pursuant to the terms of an operating agreement among them (the Ownership and Operation Agreement).
CETA imposes deadlines by which coal-fired resources, such as Colstrip, must be excluded from the rate base of Washington utilities and by which electricity from such resources may no longer be delivered to Washington retail customers. See “Environmental Issues and Contingencies – Climate Change – Washington Legislation and Regulatory Actions – Clean Energy Transformation Act”. These deadlines are reflected in our IRPs and those of other Washington utilities. Not all of the co-owners of Colstrip Units 3 & 4 are Washington utilities subject to CETA, and the co-owners have differing needs for the generating capacity of these units. Accordingly, business disagreements have arisen among the co-owners, including, but not limited to, disagreements as to the shut-down date or dates of these units. These business disagreements, in turn, have led to disagreements as to the interpretation of various provisions of the Ownership and Operating Agreement, including, but not limited to, provisions relating to the termination by a co-owner of its interests in Unit 3 and/or Unit 4. Meanwhile, while the units are still being operated, related disagreements have arisen over the 2021 operating budget that could extend to future budgets. If these disagreements cannot be resolved to the satisfaction of all owners, it is possible that one or more issues will be arbitrated in accordance with the terms of the Ownership and Operation Agreement. In that case, the outcome of any such proceeding could have financial implications for any future decisions we may make with respect to our ownership interest in Colstrip Units 3 & 4. Other impacts of the CETA and its implementing regulations are discussed in the Environmental Issues and Contingencies section.
Depreciation of Colstrip Assets
We have received orders from the IPUC and WUTC allowing us to accelerate the depreciation of our 15 percent ownership interest in Colstrip Units 3 & 4 to 2027 for Idaho and 2025 for Washington. Our remaining investment in Colstrip Units 3 & 4 as of December 31, 2020 was $107.6 million.
Coal Ash Management/Disposal
In 2015, the EPA issued a final rule regarding coal combustion residuals (CCRs), also termed coal combustion byproducts or coal ash (Colstrip produces this byproduct). The CCR rule has been the subject of ongoing litigation. In August 2018, the D.C. Circuit struck down provisions of the rule. In December 2019, a proposed revision to the rule was published in the Federal Register to address the D.C. Circuit's decision. The rule includes technical requirements for CCR landfills and surface impoundments under Subtitle D of the Resource Conservation and Recovery Act, the nation's primary law for regulating solid waste. The Colstrip owners developed a multi-year compliance plan to address the CCR requirements along with existing state obligations expressed through the 2012 Administrative Order on Consent (AOC) with Montana Department of Environmental Quality (MDEQ). These requirements continue despite the 2018 federal court ruling.
The AOC requires MDEQ to review Remedy and Closure plans for all parts of the Colstrip plant through an ongoing public process. The AOC also requires the Colstrip owners to provide financial assurance, primarily in the form of surety bonds, to secure each owner’s pro rata share of various anticipated closure and remediation obligations. We are responsible for our share of two major areas: the Plant Site Area and the Effluent Holding Pond Area. Generally, the plans include the removal of Boron, Chloride, and Sulfate from the groundwater, closure of the existing ash storage ponds, and installation of a new water treatment system to convert the facility to a dry ash storage. We recently adjusted our share of the posted surety bonds to approximately
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$20 million. This amount will be updated annually, with expected obligations decreasing over time as remediation activities are completed.
Colstrip Coal Contract
Colstrip is supplied with fuel from adjacent coal reserves under coal supply and transportation agreements. Several of the co-owners of Colstrip, including us, have negotiated an extension to the coal contract that runs through December 31, 2025.
Other Colstrip Matters
We continue to assess the best options for Colstrip in conjunction with our co-owners. We intend to seek recovery of any costs associated with Colstrip regulatory matters.
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
• Cyber and Technology • Energy commodity
• Strategic • Compliance
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.
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To address the risk related to fuel cost, availability and delivery restraints, we have an energy resources risk policy, which includes our wholesale energy markets credit policy and control procedures to manage energy commodity price and credit risks. Development of the energy resources risk policy includes planning for sufficient capacity to meet our customer and wholesale energy delivery obligations. See further discussion of the energy resources risk policy below.
Oversight of the operational risk management process is performed by the Environmental, Technology and Operations Committee of our Board of Directors and from senior management with input from each operating department.
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 of our external stakeholders.
External Mandates Risk
Oversight of our external mandate risk mitigation strategies is performed by the Environmental, Technology and Operations Committee of our Board of Directors and senior management. We have a Perform Council which meets internally to assess the potential impacts of climate policy to our business and to identify strategies to plan for change. Our ESG 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:
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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 a Treasury 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 the Finance Committee of our Board of Directors.
Regulation and Rates
Our Regulatory 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 the Washington, Idaho and Oregon 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.
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. The Finance 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 underlying U.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 the U.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 of Avista Corp.'s cost of debt calculation for ratemaking purposes.
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The following table summarizes our interest rate swap derivatives outstanding as of December 31, 2020 and December 31, 2019 (dollars in thousands):
December 31, December 31,
Number of agreements 16 20
Short-term derivative assets (1) $ — $ 589
Short-term derivative liability (1) (2) (11,525 ) (7,825 )
We estimate that a 10 basis point increase in forward LIBOR interest rates as of December 31, 2020 would increase the interest rate swap derivative net liability by $5.9 million, while a 10 basis point decrease would decrease the interest rate swap derivative net liability by $6.1 million.
We estimated that a 10 basis point increase in forward LIBOR interest rates as of December 31, 2019 would have increased the interest rate swap derivative net liability by $5.1 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.
The following table shows our long-term debt (including current portion) and related weighted-average interest rates, by expected maturity dates as of December 31, 2020 (dollars in thousands):
Weighted-average interest rate — — — — — 1.10 % 1.10 %
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 the Finance 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 11 of the Notes to Consolidated Financial Statements" for further discussion of our investment policy associated with the pension assets.
Credit Risk
Counterparty Non-Performance Risk
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.
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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 enter into bilateral transactions with various counterparties. We also trade energy and related derivative instruments through clearinghouse exchanges.
We seek to mitigate credit risk by:
• transacting through clearinghouse exchanges,
• 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.
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 of December 31, 2020, we had cash deposited as collateral of $5.0 million and letters of credit of $23.5 million outstanding related to our energy derivative contracts. Price movements and/or a downgrade in our credit ratings could impact further the amount of collateral required. See “Credit Ratings” for further information. For example, in addition to limiting our ability to conduct transactions, if our credit ratings were lowered to below “investment grade” based on our positions outstanding at December 31, 2020 (including contracts that are considered derivatives and those that are considered non-derivatives), we would potentially be required to post the following additional collateral (in thousands):
Additional collateral taking into account contractual thresholds $ 11,772
Additional collateral without contractual thresholds 14,575
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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 of December 31, 2020, we had interest rate swap agreements outstanding with a notional amount totaling $175.0 million and we had deposited cash in the amount of $8.1 million 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 at December 31, 2020, we would potentially be required to post the following additional collateral (in thousands):
Additional collateral taking into account contractual thresholds (1) $ 11,540
Additional collateral without contractual thresholds 42,763
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 in U.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 with U.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 7 of the Notes to Consolidated Financial Statements” and “Note 18 of the Notes to Consolidated Financial Statements.”
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 the Environmental, 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.
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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 of December 31, 2020 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
The following table presents energy commodity derivative fair values as a net asset or (liability) as of December 31, 2019 that were expected to settle in each respective year (dollars in thousands). There were no expected deliveries of energy commodity derivatives after 2022:
Purchases Sales
Electric Derivatives Gas Derivatives Electric Derivatives Gas Derivatives
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 Energy Commodities.
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
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our Chief Compliance Officer, and the Environmental, 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.