ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
HEI and Hawaiian Electric (in the case of Hawaiian Electric, only the information related to Hawaiian Electric and its subsidiaries):
The following discussion should be read in conjunction with the Consolidated Financial Statements and the related Notes that appear in Item 8 of this report. For information on factors that may cause HEI’s and Hawaiian Electric’s actual future results to differ from those currently contemplated by the relevant forward-looking statements, see “Cautionary Note Regarding Forward-Looking Statements” at the front of this report and “Risk Factors” in Item 1A. The general discussion of HEI’s consolidated results should be read in conjunction with the Electric utility and Bank segment discussions that follow.
HEI Consolidated
Executive overview and strategy. HEI is a holding company with operations primarily focused on Hawaii’s electric utility and banking sectors. In 2017, HEI formed Pacific Current to make investments in non-regulated renewable energy and sustainable infrastructure projects. HEI has three reportable segments—Electric utility, Bank, and Other.
Electric utility. Hawaiian Electric, Hawaii Electric Light and Maui Electric (Utilities) are regulated operating electric public utilities engaged in the production, purchase, transmission, distribution and sale of electricity on the islands of Oahu; Hawaii; and Maui, Lanai and Molokai, respectively.
Bank. ASB is a full-service community bank serving both consumer and commercial customers in the State of Hawaii and has 42 branches on the islands of Oahu (29), Maui (6), Hawaii (4), Kauai (2), and Molokai (1).
Other. The Other segment comprises the results of Pacific Current, which invests in non-regulated clean energy and sustainable infrastructure in the State of Hawaii to help reach the state’s sustainability goals, and HEI’s corporate-level operating, general and administrative expenses.
A major focus of HEI’s financial strategy is to grow core earnings/profitability at the Utilities, Bank and Pacific Current in a controlled risk manner and optimize operating, capital and tax efficiencies in order to support its dividend and deliver shareholder value. Together, HEI’s unique combination of power, sustainable investments, and financial services companies provides the Company with a strong balance sheet and the financial resources to invest in the strategic growth of its subsidiaries, while providing an attractive dividend for investors.
Recent developments—COVID-19. The Company remains focused on the continued safety and well-being of customers, employees, their families and the community. The Company’s mandatory work-from-home policy remains in effect for certain employees and this policy has not impaired the Company’s ability to serve customers and maintain effective internal controls over financial reporting. For personnel that cannot perform their work remotely, the Company has maintained safety protocols and policies to keep employees safe, while at the same time ensuring the reliability and resilience of its operations.
The Hawaii economy began to improve in the second half of 2021 as case counts declined and vaccination rates increased. However, the economic recovery experienced a setback early in the third quarter as the declining trend of daily COVID-19 case counts reversed and began a rapid increase, setting a pandemic high at that time, exceeding approximately 900 cases per day (7-day average) in early September. As a result of the rising cases, a number of preventative policies were enacted by state, county and private entities, which included limiting group sizes for indoor and outdoor activities, mandatory vaccinations or adherence to regular testing protocols, and proof of vaccination or negative COVID-19 test for entry into certain indoor venues under the state’s Safe Access program. Additionally, the governor of the State of Hawaii made an announcement in late August, recommending that tourists postpone their visit to Hawaii. These measures contributed to a significant decline in new cases, leading to a 7-day average of approximately 100 cases in early December.
Following the detection of the Omicron variant in Hawaii in early December, case counts have increased rapidly, reaching a high of approximately 4,666 new daily cases (7-day average) as of January 19, 2022. Since then, case counts have declined rapidly, reaching a 7-day average daily case count of 256 as of February 22, 2022. Although the severity of the Omicron variant appears to be significantly lower than the Delta variant, the higher case counts have led to an increase in hospitalizations.
Despite the case count spike from the Omicron variant, the state remains open for business. The Hawaii Safe Travels Program, allows domestic transpacific passengers to avoid mandatory quarantine with proof of vaccination or a negative COVID test taken within 72 hours prior to the flight into Hawaii. On January 3, 2022, the state reduced the mandatory quarantine period from ten days to five days, consistent with the guidance from the Centers for Disease Control and Prevention.
Hawaii vaccinations have steadily increased with over 75% of the state’s population fully vaccinated as of February 10, 2022 and 36% of those fully vaccinated received a third shot.
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Tourism numbers remain below pre-pandemic levels, primarily due to a delayed recovery in international travel. However, domestic travel has recovered significantly and are nearing pre-pandemic levels, with January 2022 average daily passenger counts at approximately 92% of January 2020 average daily passenger counts. Although the Hawaii economy experienced a temporary setback with the Delta and Omicron variants, the Company expects that the Hawaii economy will continue to improve in 2022. In 2021, kWh sales remained below pre-pandemic levels, but were 1.7% higher than 2020 due to increased economic activity following the loosening of restrictions and an increase in tourism. While the level of kWh sales does not affect Utility revenues due to decoupling, it may increase or decrease the price per kWh paid by customers. See “Decoupling” in Note 3 of the Consolidated Financial Statements for a discussion of the decoupling mechanism.
At the Bank, due to favorable credit trends and continued improvement in the economic environment, ASB recorded a $25.8 million negative provision for credit losses in 2021 compared to a provision for credit losses of $50.8 million in 2020. Net interest income increased $3.7 million to $237.2 million in 2021 due to higher earning assets, primarily related to growth in the investment securities portfolio that was principally funded by the growth in deposits. The higher net interest income from the higher average earning asset balances, PPP income, and lower funding costs was partly offset by the impact of a decrease in loan portfolio balances and lower earning asset yields as a result of the low interest rate environment.
For further discussion of the impact of the COVID-19 pandemic on the Utilities and the Bank, see “Recent Developments—COVID-19” in the Electric Utility and Bank sections below. There has been no material impact on the “Other” segment and Pacific Current as a result of the COVID-19 pandemic as the primary businesses of Pacific Current are supported by PPAs that provide for contractual cash flows with credit-worthy counterparties.
For a discussion regarding the impact of the economic conditions caused by the pandemic on the Company’s liquidity and capital resources, see discussion under “Financial Condition–Liquidity and capital resources,” contained in each of the “HEI Consolidated,” “Electric utility” and “Bank” sections of this MD&A.
Environmental, Social & Governance. At HEI, environmental, social and governance (ESG) principles and sustainability have long been embedded within all aspects of the Company’s activities and integral to the Company’s efforts to create value for all of its stakeholders. With all of its operations isolated in the middle of the Pacific Ocean, the Company’s long-term health and financial performance is inextricably linked with the strength of the Hawaii economy, its communities, and the environment. That is why long-term shareholder and broader stakeholder value are both served by the Company’s mission to be a catalyst for a better Hawaii.
In 2021, the Company identified a number of priorities that reflect the essential connection between the health of Hawaii’s environment, economy and communities and HEI’s long-term success. The key ESG priorities the Company is working to advance include:
•decarbonizing the Company’s operations and the broader Hawaii economy;
•promoting Hawaii’s economic health and improving affordability for all residents;
•ensuring reliability and resilience as the Company navigates the clean energy transition and adapts to a changing climate;
•advancing digitalization of the Company’s operations to better serve customers and increase efficiency while protecting against cyber-security challenges;
•promoting diversity, equity and inclusion both within the Company and in the ways the Company interacts with and impacts external stakeholders;
•increasing employee engagement; and
•identifying and integrating climate-related risks and opportunities throughout the Company’s planning and decision-making.
The Company has also focused on ensuring that ESG considerations are appropriately integrated into governance structures, strategies and risk management. This includes:
•Integration of Board oversight of important ESG matters into its existing governance structures and processes. This includes full Board review of ESG-related strategies, Audit & Risk Committee oversight of ESG risks, Compensation & Human Capital Management Committee responsibility for ESG-related compensation matters and human capital management and Nominating and Corporate Governance Committee responsibility for ensuring an appropriate board governance framework is in place with respect to ESG.
•Robust ESG expertise among board members, including directors with direct experience in renewable energy, climate change policy and strategy, environmental management and sustainable investing.
•Expanded ESG goals as part of HEI and Utility executive incentive compensation.
•ESG considerations explicitly woven into strategic planning efforts and enterprise risk management processes.
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The Company is committed to transparency and providing information to allow customers, community leaders, investors and other stakeholders understand how the Company’s strategies and operations advance ESG objectives and contribute to long-term stakeholder value creation.
The Company issued its first ESG report in September 2020. The report encompassed ESG policies, principles and results reported during 2019 across the Company’s two primary operating subsidiaries, Hawaiian Electric and ASB, and was aligned with Sustainability Accounting Standards Board (SASB) guidance—using the electric utilities standard for Hawaiian Electric, and the commercial banks, commercial finance, and mortgage finance standards for ASB. On April 22, 2021, the Company issued its second ESG report. This report continues to include SASB disclosures for Hawaiian Electric and ASB and incorporates disclosures regarding risks and opportunities related to climate change, as well as associated risk management and governance processes, based on recommendations from the Task Force on Climate-related Financial Disclosures. It also outlines key impacts for the Company under two climate scenarios, including a scenario targeted to limit global temperature rise to 2 degrees Celsius or lower. The Company’s ESG reports can be found at www.hei.com/esg.
HEI consolidated results of operations.
(dollars in millions, except per share amounts) 2021 % change 2020 % change 2019
Net income (loss) by segment:
Dividend payout ratio 60 % 73 % 64 %
In 2021, net income for HEI common stock increased 24% to $246 million ($2.25 diluted earnings per share), compared to $198 million ($1.81 diluted earnings per share) in 2020, due to $44 million higher net income at ASB and $8 million higher net income at the Utilities, partially offset by $4 million higher net loss at the “other” segment. The increase in ASB’s 2021 net income compared to 2020 was primarily due to a negative provision for credit losses as a result of improved credit quality as the local economy improved significantly from the prior year. Results for 2020 included the impact of the COVID-19 pandemic on the local and national economy, which resulted in higher provision for credit losses, lower net interest income due to a lower yield curve and additional noninterest expenses. The increase in the Utilities’ 2021 net income compared to 2020 was principally due to higher RAM and ARA revenues, which included the customer dividend and an offset of management audit savings delivered to customers and delivery of Hawaiian Electric ERP benefits commitment completed in 2020, partially offset by higher operating expenses. See “Electric utility,” “Bank,” and “HEI Consolidated—Other segment” sections below for additional information on year-to-year fluctuations.
The Company’s effective tax rate (combined federal and state income tax rates) was higher at 20% in 2021, compared to 17.0% in 2020, primarily due to an increase in income before income taxes in 2021, which reduces the rate impact of certain tax items, lower amortization in 2021 of the Utilities’ regulatory liability related to certain excess deferred income taxes resulting from the Tax Act’s decrease in the federal income tax rate and a decrease in excess tax benefits related to share-based awards in 2021. The factors leading to an increase in the effective tax rate were partially offset by higher nontaxable bank-owned life insurance and federal research and developments tax credit claims in 2021.
For a discussion of 2019 results, please refer to the “HEI consolidated results of operations” section in Item 7, “Management Discussion and Analysis of Financial Condition and Results of Operations—HEI Consolidated,” in the Company’s 2020 Form 10-K.
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Other segment. The “other” business segment (loss)/income includes results of the stand-alone corporate operations of HEI, ASB Hawaii, and Pacific Current.
(in millions) 2021 2020 Increase(decrease) Primary reason(s)
Revenue1 $ 4 $ 1 $ 3 Increase in other sales at Pacific Current subsidiaries.
Net loss $ (33) $ (29) $ (4)
1 Hamakua Energy’s sales to Hawaii Electric Light (a regulated affiliate) are eliminated in consolidation.
Economic conditions. The statistical data in this section is from public third-party sources that management believes to be reliable (e.g., Department of Business, Economic Development and Tourism (DBEDT), University of Hawaii Economic Research Organization (UHERO), Department of Health of the State of Hawaii, U.S. Bureau of Labor Statistics, Department of Labor and Industrial Relations (DLIR), Hawaii Tourism Authority (HTA), Honolulu Board of REALTORS® and national and local news media).
Hawaii’s tourism industry, a significant driver of Hawaii’s economy, suffered dramatically with a 73.8% reduction in total visitor arrivals in 2020 compared with 2019. Starting October 15, 2020, the state launched its Safe Travels Program that allows travelers to avoid the mandatory 14-day quarantine if they test negative for COVID-19 within 72 hours of departure. Effective July 8, 2021, domestic visitors can now bypass the mandatory quarantine or COVID-19 test by providing proof of vaccination. Since the launch of the Safe Travels Program, total daily passenger arrivals have steadily improved, but remain below pre-pandemic levels. For the fourth quarter of 2021, the average daily passenger count was 249.3% higher than the comparable period in the prior year, but still 22.2% below 2019. The recovery in total passenger counts from the low levels in 2020 thus far has been driven by domestic travelers, with international travelers remaining at low levels due to higher restrictions for international travelers, depending on country of origin. In December 2021, domestic passenger counts were down 0.3% compared to 2019 pre-COVID-19 levels, while international passenger counts were down 89.7% compared to 2019 pre-COVID-19 levels.
Hawaii’s seasonally adjusted unemployment rate in December 2021 was 5.7%, which was substantially lower compared to the December 2020 rate of 10.3%. The national unemployment rate in December 2021 was 3.9% compared to 6.7% in December 2020. Hawaii’s unemployment rate is expected to continue to improve now that restrictions on travel have been reduced significantly and increased vaccination rates should enable further reductions in business restrictions.
Hawaii real estate activity through December 2021, as indicated by Oahu’s home resale market, drove an increase in the median sales price of 9.2% for condominiums and 19.3% for single-family homes compared to the same period in 2020, with the December median single-family home price tying a record of $1,050,000 set in August. The number of closed sales was up 53.1% for condominiums and up 17.9% for single-family residential homes in 2021 compared to 2020.
Hawaii’s petroleum product prices reflect supply and demand in the Asia-Pacific region and the price of crude oil in international markets. The price of crude oil gradually increased during the 4th quarter of 2020 and the trend has continued during the first ten months of 2021.
At its December 15, 2021 meeting, the Federal Open Market Committee (FOMC) decided to maintain the federal funds rate target range of 0%-0.25%. The FOMC plans to continue to maintain an accommodative stance of monetary policy to achieve maximum employment and inflation at the rate of 2 percent over the long run. The Federal Reserve stated that it will decrease its holdings of Treasury securities and agency mortgage-backed securities at least at the current pace to sustain smooth market functioning and help foster accommodative financial conditions, thereby supporting the flow of credit to households and businesses.
The most recent forecast by UHERO, which was issued on December 17, 2021, forecasts full year 2021 real GDP growth of 5.8%, increase in total visitor arrivals of 149.2%, increase in real personal income of 0.8%, and an unemployment rate of 7.7%. This forecast reflects improvement of Hawaii’s economy after experiencing a downturn due to the Delta variant of COVID-19; however, the Omicron variant has set a new record in new daily virus cases and led to implementation of increased international travel restrictions. The international market is still anticipated to gradually return in 2022 once the Omicron
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situation clears. Real GDP growth in 2022 is forecasted to be 2.7% supported by a 22.8% increase in total visitor arrivals in 2022 to 8.3 million visitors and a decrease in the unemployment rate to 5.4%. However, a full economic recovery is still forecasted to be several years out and dependent on the ability to adapt to new COVID-19 threats.
The Company expects economic conditions to improve going forward; however, it is difficult to predict the future path of the pandemic. If economic conditions worsen from current levels or remain depressed for an extended period of time, it could have a material unfavorable impact on the Company’s financial position or results of operations in 2022.
See also “Recent Developments—COVID-19” in the “Electric utility” and “Bank” sections below for further discussion of the economic impact caused by the pandemic.
Liquidity and capital resources. As of December 31, 2021, HEI and Hawaiian Electric had approximately $54 million and nil of commercial paper outstanding, respectively, and Hawaiian Electric had $52 million of cash and cash equivalents.
As of December 31, 2021, there was no balance on HEI’s revolving credit facility and the available committed capacity under the revolving credit facility was $175 million (see Note 5 of the Consolidated Financial Statements). As of December 31, 2021, there was no balance on Hawaiian Electric’s revolving credit facility and the available committed capacity under the revolving credit facility was $200 million. On April 19, 2021, the term of Hawaiian Electric’s $75 million 364-day revolving credit agreement expired and was not renewed. As of December 31, 2021, ASB’s unused FHLB borrowing capacity was approximately $2.0 billion and ASB had unpledged investment securities of $2.5 billion that were available to be used as collateral for additional borrowing capacity.
As of December 31, 2021, the total amount of available borrowing capacity (net of commercial paper outstanding) under the Company’s committed lines of credit was approximately $321 million, which was a decrease of approximately $39 million compared to December 31, 2020.
The Company believes that its cash and cash equivalents, expected operating cash flow from subsidiaries, existing credit facilities, and access to the capital markets will be sufficient to meet the Company’s cash requirements over the next twelve months and beyond based on its current business plans. However, the Company expects that its liquidity will continue to be moderately impacted at the Utilities due to ongoing COVID-19 impacts to the local economy. For the Utilities, the elevated level of unemployment in the state and the moratorium on customer disconnections (which ended on May 31, 2021) have resulted in higher accounts receivable balances and bad debt expense and may result in higher write-offs in the future. As of December 31, 2021, approximately $38 million of the Utilities’ accounts receivables were 30 days past due. Of the over 30 days past due amounts, approximately 30% were on payment plans. The Company commenced its disconnection process on a tiered basis, starting in the third quarter of 2021, targeting the oldest and largest balances first, which is expected to reduce delinquent accounts receivable balances over time as payments are made. In addition to the cash flow impact from delayed collection of accounts receivable, lower kWh sales relative to the level of kWh sales approved in the last rate case generally result in delayed timing of cash flows, resulting in higher working capital requirements (see “Recent Developments—COVID-19” in the Electric utility section below). At this time, the delay in customer cash collections has not significantly affected the Company’s liquidity. The Company is prepared to address, if needed, the potential financing requirement related to the delayed timing of customer collections.
At ASB, liquidity remains at satisfactory levels, largely due to U.S. economic stimulus programs implemented as a result of COVID-19 that led to a substantial increase in customer deposits, which grew 11% and 18% in 2021 and 2020, respectively. ASB’s cash and cash equivalents was $251 million as of December 31, 2021, compared to $293 million as of December 31, 2020. ASB remains well above the “well capitalized” level under the FDIC Improvement Act prompt correction action capital category, and while the economic outlook has improved and is expected to continue to improve, there are still COVID-19 related business restrictions that remain in place that could create ongoing uncertainty regarding COVID-19’s impact on loan performance and the allowance for credit losses (see “Recent Developments — COVID-19” in the Bank section below).
To preserve and enhance the Company’s liquidity position and address higher working capital requirements, in light of the significant and ongoing uncertainty regarding the potential scale and duration of the COVID-19 pandemic and its impact on the global, national and local economy, the Company completed a number of financing actions in 2021.
•On May 14, 2021, HEI and Hawaiian Electric each entered into a separate agreement with a syndicate of nine financial institutions (the HEI Facility and Hawaiian Electric Facility, respectively, and together, the Facilities), to amend and restate their respective previously existing unsecured revolving credit agreements. The committed capacity under the HEI Facility was increased to $175 million from $150 million and its term was extended to May 14, 2026. On February 18, 2022, the PUC approved Hawaiian Electric's request to extend the term of the $200 million Hawaiian Electric Facility to May 14, 2026 from May 13, 2022.
•On September 29, 2021, HEI executed a $125 million private placement utilizing a delayed draw feature, which allows HEI to draw $75 million and $50 million at any time on or before December 29, 2021 and November 15, 2022, respectively. On December 29, HEI drew $75 million, the proceeds of which were primarily used to invest in the
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Utilities’ equity and support its capital expenditure program. Proceeds from the remaining $50 million are expected to be used to refinance a portion of HEI’s $150 million long-term notes maturing in November 2022 or for other general corporate purposes. The ability to draw at any time prior to the November 15, 2022 date will provide additional liquidity in the interim period. The notes bear interest at a weighted average rate of 3.10% and have a weighted average maturity of 15.7 years.
If further liquidity is deemed necessary, which is not contemplated at this time, the Utilities could also reduce the pace of capital spending related to non-essential projects. Additionally, the Company has the option to issue new shares rather than purchase currently outstanding shares on the open market to satisfy share issuances under its Dividend Reinvestment and Stock Purchase Plan (DRIP) program. The estimated amount of equity capital that could be raised by issuing new shares, rather than utilizing open market purchases, is estimated to be approximately $30 million on an annual basis, based on historical demand, but such future amount is dependent on a number of factors, including, without limitation, future share prices, number of shares/participants in the DRIP program, and the amount of new investment in HEI’s stock by DRIP participants.
HEI material cash requirements. HEI’s material cash requirements include: capital expenditures, labor and benefit costs, O&M expenses, fuel and purchase power costs, and debt and interest payments at the Utilities; investments in loans and investment securities at the Bank; labor and benefits costs, shareholder dividends and debt and interest payments at HEI; and HEI equity contributions to support Pacific Current’s sustainable infrastructure investments. Forecasted HEI consolidated “net cash used in investing activities” (excluding “investing” cash flows from ASB) for 2022 through 2026 consists primarily of the net capital expenditures of the Utilities principally related to maintaining and modernizing the grid to allow for the integration of more renewable energy, improved customer reliability, greater system efficiency and enhanced resilience. The Utilities’ capital expenditures are estimated to range from $2.0 billion to $2.2 billion over the next five years and are expected to be funded primarily through a combination of retained earnings and proceeds from debt issuance, and if required, contributions of equity from HEI to maintain the Utilities’ equity capitalization at approximately 58% (see also discussion regarding other material cash requirements under “Financial Condition–Liquidity and capital resources,” contained in the “Electric utility” and “Bank” sections below). In addition to the funds required for the Utilities’ construction programs and debt maturities, with respect to HEI, over the next five years, approximately $150 million will be required in 2022, $50 million in 2023, and $50 million in 2025 to repay maturing debt. Debt maturities are expected to be repaid with the proceeds from the issuance of commercial paper, bank borrowings, other medium- or long-term debt, issuance of common stock and/or dividends from subsidiaries. Additional debt and/or equity financing may be utilized to invest in the Utilities, Bank or Pacific Current; to pay down commercial paper or other short-term borrowings; to pay interest costs; or to fund unanticipated expenditures not included in the 2022 through 2026 forecast, such as increases in the costs of, or an acceleration of, the construction of capital projects of the Utilities or unanticipated utility capital expenditures. In addition, existing debt may be refinanced prior to maturity with additional debt or equity financing (or both).
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Selected short-term and long-term contractual obligations and commitments. Information about payments under the specified contractual obligations and commercial commitments of HEI and its subsidiaries was as follows:
(in millions) Less than1 year 1-3years 3-5years More than5 years Total
Contractual obligations
Investment in qualifying affordable housing projects $ — $ 34 $ 27 $ 2 $ 63
Short-term borrowings 54 — — — 54
Other bank borrowings 88 — — — 88
Operating leases
PPAs classified as leases 46 8 7 4 65
Service bureau contract, maintenance agreements and other 20 27 17 7 71
Hawaiian Electric open purchase order obligations1 93 39 8 — 140
Liabilities for uncertain tax positions — 8 — — 8
1Includes contractual obligations and commitments for capital expenditures and expense amounts.
The table above does not include other categories of obligations and commitments, such as deferred taxes, certain trade payables, amounts that will become payable in future periods under collective bargaining and other employment agreements and employee benefit plans, and potential refunds of amounts collected from ratepayers (e.g., under the earnings sharing mechanism). As of December 31, 2021, the fair value of the assets held in trusts to satisfy the obligations of the Company’s retirement benefit plans did not exceed the retirement benefit plans’ benefit obligation. Minimum funding requirements for retirement benefit plans have not been included in the tables above; however, see Note 10 of the Consolidated Financial Statements for 2022 estimated contributions.
See Note 3 of the Consolidated Financial Statements for a discussion of fuel and power purchase commitments. See Note 4 of the Consolidated Financial Statements for a further discussion of ASB’s commitments.
Operating activities provided net cash of $376 million in 2021 and $429 million in 2020. Investing activities used net cash of $1,180 million in 2021 and $1,414 million in 2020. In 2021, net cash used in investing activities was primarily due to purchases of available-for-sale and held-to-maturity investment securities, capital expenditures, and purchases of stock from Federal Home Loan Bank, partly offset by receipt of repayments from available-for-sale and held-to-maturity investment securities, proceeds from sale of available-for-sale investment securities, net decrease in loans held for investment, proceeds from sale of residential loans and redemption of stock from Federal Home Loan Bank. In 2020, net cash used in investing activities was primarily due to purchases of available-for-sale investment securities, capital expenditures, net increase in loans held for investment and purchases of held-to-maturity investment securities and stock from Federal Home Loan Bank, partly offset by receipt of repayments from available-for-sale and held-to-maturity investment securities, redemption of stock from Federal Home Loan Bank and proceeds from sale of available-for-sale investment securities.
Financing activities provided net cash of $756 million in 2021 and $1,116 million in 2020. In 2021, net cash provided by financing activities included net increases in deposits and proceeds from issuance of long-term debt, partly offset by payment of common and preferred stock dividends, repayment of long-term debt, short-term debt and net decreases in short-term borrowings. In 2020, net cash provided by financing activities included net increases in deposits and proceeds from issuance of long-term debt, short-term debt and other bank borrowings, partly offset by payment of common and preferred stock dividends, repayment of long-term debt, short-term debt and other bank borrowings and net decreases in short-term borrowings and other bank borrowing with original maturities of three months or less.
For a discussion of 2019 operating, investing and financing activities, please refer to the “Liquidity and capital resources” section in Item 7, “Management Discussion and Analysis of Financial Condition and Results of Operations—HEI Consolidated,” in the Company’s 2020 Form 10-K.
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Other than capital contributions from their parent company, intercompany services (and related intercompany payables and receivables), Hawaiian Electric’s periodic short-term borrowings from HEI (and related interest) and the payment of dividends to HEI, the electric utility and bank segments are largely autonomous in their operating, investing and financing activities. (See the electric utility and bank segments’ discussions of their cash flows in their respective “Liquidity and capital resources” sections below.) During 2021, Hawaiian Electric, ASB (through ASB Hawaii) and Hamakua Energy paid cash dividends to HEI of $112 million, $59 million and $1 million, respectively.
A portion of the net assets of Hawaiian Electric and ASB is not available for transfer to HEI in the form of dividends, loans or advances without regulatory approval. In the absence of an unexpected material adverse change in the financial condition of the electric utilities or ASB, such restrictions are not expected to significantly affect the operations of HEI, its ability to pay dividends on its common stock or its ability to meet its debt or other cash obligations. See Note 14 of the Consolidated Financial Statements.
The Company believes that its ability to generate cash, both internally from electric utility and banking operations and externally from issuances of equity and debt securities, as well as bank borrowings, is adequate to maintain sufficient liquidity to fund its contractual obligations and commercial commitments, its forecasted capital expenditures and investments, its expected retirement benefit plan contributions and other short-term and long-term material cash requirements. However, the COVID-19 pandemic continues to be an evolving situation, and the Company cannot predict the extent or duration of the outbreak, the future effects that it will have on the global, national or local economy, including the impact on the Company’s cost of capital and its ability to access additional capital, or the future impacts on the Company’s financial position, results of operations, and cash flows. See Item 1A. “Risk Factors” in Part I for further discussion of risks and uncertainties.
The consolidated capital structure of HEI (excluding deposit liabilities and other bank borrowings) was as follows:
(dollars in millions)
Short-term borrowings—other than bank $ 54 1 % $ 129 3 %
Preferred stock of subsidiaries 34 1 34 1
HEI’s commercial paper borrowings and line of credit facility were as follows:
(in millions) Averagebalance End-of-periodbalance December 31, 2020
Commercial paper $ 56 $ 54 $ 65
Line of credit draws — — —
Undrawn capacity under HEI’s line of credit facility1 — 175 150
1 On May 14, 2021, HEI amended and restated its previously existing revolving unsecured credit agreement to increase the capacity to $175 million from $150 million and extend its term to May 14, 2026. See Note 5 of the Consolidated Financial Statements.
Note: This table does not include Hawaiian Electric’s separate commercial paper issuances and line of credit facilities and draws, which are disclosed below under “Electric utility—Liquidity and capital resources” below. The maximum amount of HEI’s short-term commercial paper borrowings in 2021 was $129 million.
HEI utilizes short-term debt, typically commercial paper, to support normal operations, to refinance commercial paper, to retire long-term debt, to pay dividends and for other temporary requirements, including short-term financing needs of its subsidiaries. HEI also periodically makes short-term loans to Hawaiian Electric to meet Hawaiian Electric’s cash requirements, including the funding of loans by Hawaiian Electric to Hawaii Electric Light and Maui Electric, but no such short-term loans to Hawaiian Electric were outstanding as of December 31, 2021. HEI periodically utilizes long-term debt, historically unsecured indebtedness, to fund investments in and loans to its subsidiaries to support their capital improvement or other requirements, to repay long-term and short-term indebtedness and for other corporate purposes. As of December 31, 2021, HEI’s debt maturities in 2022 include $150 million of long-term debt that matures in November 2022. HEI has partially prefunded $50 million of this maturity through the $125 million private placement completed in September 2021. See Notes 5 and 6 of the Consolidated Financial Statements for a brief description of the Company’s loans.
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The rating of HEI’s commercial paper and debt securities could significantly impact the ability of HEI to sell its commercial paper and issue debt securities and/or the cost of such debt. As of February 11, 2022, the Fitch Ratings, Inc. (Fitch), Moody’s Investors Service (Moody’s) and S&P Global Ratings (S&P) ratings of HEI were as follows:
Fitch Moody’s S&P
Long-term issuer default, long-term and issuer credit, respectively BBB WR* BBB-
Commercial paper F3 P-2 A-3
Outlook Stable Stable Stable
* Moody’s long-term debt rating was withdrawn because HEI does not currently have any outstanding, publicly traded debt. Moody’s continues to rate Hawaiian Electric’s long-term debt. See ‘Electric utility–Liquidity and capital resources’ below.
Note: The above ratings reflect only the view, at the time the ratings are issued or affirmed, of the applicable rating agency, from whom an explanation of the significance of such ratings may be obtained. Such ratings are not recommendations to buy, sell or hold any securities; such ratings may be subject to revision or withdrawal at any time by the rating agencies; and each rating should be evaluated independently of any other rating.
There were no new issuances of common stock through the HEI DRIP, HEIRSP or the ASB 401(k) Plan in 2021, 2020, or 2019 and HEI satisfied the share purchase requirements of the DRIP, HEIRSP and ASB 401(k) Plan through open market purchases of its common stock.
Off-balance sheet arrangements. Although the Company and the Utilities have certain off-balance sheet arrangements, management has determined that it has no off-balance sheet arrangements that either have, or are reasonably likely to have, a current or future effect on the Company’s and the Utilities’ financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that are material to investors, including the following types of off-balance sheet arrangements:
1.obligations under guarantee contracts,
2.retained or contingent interests in assets transferred to an unconsolidated entity or similar arrangements that serve as credit, liquidity or market risk support to that entity for such assets,
3.obligations under derivative instruments, and
4.obligations under a material variable interest held by the Company or the Utilities in an unconsolidated entity that provides financing, liquidity, market risk or credit risk support to the Company or the Utilities, or engages in leasing, hedging or research and development services with the Company or the Utilities.
Material estimates and critical accounting policies. In preparing financial statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities and the reported amounts of revenues and expenses. Actual results could differ significantly from those estimates.
Material estimates that are particularly susceptible to significant change include the amounts reported for pension and other postretirement benefit obligations; contingencies and litigation; income taxes; regulatory assets and liabilities; electric utility unbilled revenues; allowance for credit losses; fair value; and asset retirement obligations (AROs). Management considers an accounting estimate to be material if it requires assumptions to be made that were uncertain at the time the estimate was made and changes in the assumptions selected could have a material impact on the estimate and on the Company’s results of operations or financial condition.
In accordance with SEC Release No. 33-8040, “Cautionary Advice Regarding Disclosure About Critical Accounting Policies,” management has identified the accounting policies it believes to be the most critical to the Company’s financial statements—that is, management believes that the policies discussed below are both the most important to the portrayal of the Company’s results of operations and financial condition, and currently require management’s most difficult, subjective or complex judgments. The policies affecting both of the Company’s two principal segments are discussed below and the policies affecting just one segment are discussed in the respective segment’s section of “Material estimates and critical accounting policies.” Management has reviewed the material estimates and critical accounting policies with the HEI Audit & Risk Committee and, as applicable, the Hawaiian Electric Audit & Risk Committee.
For additional discussion of the Company’s accounting policies, see Note 1 of the Consolidated Financial Statements and for additional discussion of material estimates and critical accounting policies, see the electric utility and bank segment discussions below under the same heading.
Pension and other postretirement benefits obligations. The Company’s benefit obligations and reported costs of providing retirement benefits are dependent upon numerous factors resulting from actual plan experience and assumptions about future experience. For example, retirement benefits costs are impacted by actual employee demographics (including age and compensation levels), the level of contributions to the plans, earnings and realized and unrealized gains and losses on plan assets, and changes made to the provisions of the plans. Costs may also be significantly affected by changes in key actuarial
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assumptions, including the expected return on plan assets, the discount rate and mortality. The Company’s accounting for retirement benefits under the plans in which the employees of the Utilities participate is also adjusted to account for the impact of decisions by the PUC. Changes in obligations associated with the factors noted above may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants.
The discount rate used to calculate the Company’s benefit obligations is a significant assumption that affects the Company’s benefit obligations. As of December 31, 2021, the discount rate for HEI and the Utilities’ qualified pension plan was 3.05%. Based on various assumptions in Note 10 of the Consolidated Financial Statements, sensitivities of the projected benefit obligation (PBO) and accumulated postretirement benefit obligation (APBO) as of December 31, 2021, associated with a change in the discount rate, were as follows and constitute “forward-looking statements”:
(dollars in millions)
Pension benefits
Other benefits
Also, see Notes 1 and 10 of the Consolidated Financial Statements.
Contingencies and litigation. The Company is subject to proceedings (including PUC proceedings), lawsuits and other claims. Management assesses the likelihood of any adverse judgments in or outcomes of these matters as well as potential ranges of probable losses, including costs of investigation. A determination of the amount of reserves required, if any, for these contingencies is based on an analysis of each individual case or proceeding often with the assistance of outside counsel. The required reserves may change in the future due to new developments in each matter or changes in approach in dealing with these matters, such as a change in settlement strategy.
In general, environmental contamination treatment costs are charged to expense, unless it is probable that the PUC would allow such costs to be recovered through future rates, in which case such costs would be capitalized as regulatory assets. Also, environmental costs are capitalized if the costs extend the life, increase the capacity, or improve the safety or efficiency of property; the costs mitigate or prevent future environmental contamination; or the costs are incurred in preparing the property for sale.
See Notes 1, 3 and 4 of the Consolidated Financial Statements.
Income taxes. Deferred income tax assets and liabilities are established for the temporary differences between the financial reporting bases and the tax bases of the Company’s assets and liabilities using tax rates expected to be in effect when such deferred tax assets or liabilities are realized or settled. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible.
Management evaluates its potential exposures from tax positions taken that have or could be challenged by taxing authorities. These potential exposures result because taxing authorities may take positions that differ from those taken by management in the interpretation and application of statutes, regulations and rules. Management considers the possibility of alternative outcomes based upon past experience, previous actions by taxing authorities (e.g., actions taken in other jurisdictions) and advice from its tax advisors. Management believes that the Company’s provision for tax contingencies is reasonable. However, the ultimate resolution of tax treatments disputed by governmental authorities may adversely affect the Company’s current and deferred income tax amounts.
See Note 12 of the Consolidated Financial Statements.
Following are discussions of the electric utility and bank segments. Additional segment information is shown in Note 2 of the Consolidated Financial Statements. The discussion concerning Hawaiian Electric should be read in conjunction with its consolidated financial statements and accompanying notes.
Electric utility
Executive overview and strategy. The Utilities provide electricity on all the principal islands in the state, other than Kauai, to approximately 95% of the state’s population, and operate five separate grids. The Utilities’ mission is to provide innovative energy leadership for Hawaii, to meet the needs and expectations of customers and communities, and to empower them with affordable, reliable and clean energy. The goal is to create a modern, resilient, flexible, and dynamic electric grid that enables an optimal mix of distributed energy resources, such as private rooftop solar, demand response, and grid-scale resources to
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enable the creation of smart, sustainable, resilient communities and achieve its decarbonization goals that are aligned with the statutory goal of 100% renewable energy by 2045.
Recent developments—COVID-19.
See also Recent developments—COVID-19 in HEI’s MD&A.
Starting in early December, new COVID-19 case counts, which now include the Omicron variant, started to increase and reached a high of 4,666 cases per day (7-day average) on January 19, 2022. Since then, case counts have declined rapidly, reaching a 7-day average daily case count of 256 as of February 22, 2022. Although case counts have increased, the severity of the disease appears to be lower than the Delta variant. As a result, the state and counties have generally not reinstituted the same restrictions that were put in place to manage the Delta variant. The economy remains open for business and the mandatory quarantine period for travelers who have not been vaccinated or who have not provided evidence of a negative COVID test has been reduced to five days. For the full year 2021, driven by the broader reopening of the economy, the demand for electricity has increased 1.7% from 2020 levels; however, the full year 2021 kWh sales are still 5.5% below the pre-pandemic level of kWh sales in 2019.
While the Utilities’ electric energy revenues have not been significantly impacted due to the decoupling mechanism, which allows recovery of the difference between PUC approved target revenues and recorded adjusted revenues regardless of the level of kWh sales, the timing of customer collections would be delayed (or accelerated) if the level of kWh sales decreases below (or increases above) the estimated kWh sales. See “Decoupling” in Note 3 of the Consolidated Financial Statements for a discussion of decoupling. As part of the annual review cycle, the Utilities submit bi-annual decoupling filings (fall and spring revenue report) to the PUC. The fall revenue report requests recovery by the utility (or refund to customers) of the difference between recorded adjusted revenues and target revenues under the RBA. The difference is collected or refunded through an adjustment to customer rates in the following year based on estimated sales, starting on January 1st of that following year, which has an impact on the timing of the Utilities’ cash flow. Additionally, although the Utilities’ decoupling mechanism allows for collection under the RBA, the RBA balance accrues interest only at the short-term debt rate from the last rate case (2.5% for Hawaiian Electric, 3.75% for Hawaii Electric Light and 3.0% for Maui Electric). As of December 31, 2021, the RBA balance was approximately $28.5 million, compared to $7.6 million as of December 31, 2020. The billed accounts receivable balance, net of allowance for doubtful accounts as of December 31, 2021, was $187 million, or 26.4% higher, than the billed account receivable balance as of December 31, 2020, due in part to higher fuel prices resulting in higher bills. The past due accounts receivable balance increased by $19 million, or 38%, since December 31, 2020 with a corresponding increase in the number of accounts past due by approximately 13% for the same period. The increase in accounts receivables was primarily driven by higher fuel prices, as well as lower cash receipts associated with the auto-enrollment of customers in payment plans, starting in July 2021 through mid-September 2021, under which the past due balances are recovered over a 12-18 month period. While the moratorium on customer disconnections ended on May 31, 2021, the Utilities initially focused its efforts on working with customers to enroll in payment plans and seek other bill assistance for customers through funding from non-profit organizations, as well as state and county relief programs. Starting in September 2021, the Utilities have begun the disconnection process for those customers that have not enrolled in payment plans or that have not adhered to their payment plans, beginning with the largest and oldest amounts in arrears. At this time, the delay in customer cash collections has not significantly affected the Utilities’ liquidity. The Utilities are prepared to address, if needed, the financing requirement related to the delayed timing of cash flows collected under the decoupling mechanism through the RBA and the modest slowing or reduction in accounts receivable collections from customers. See “Financial Condition—Liquidity and capital resources” for additional information.
The Utilities provide an essential service to the State of Hawaii, and have continued to operate to protect the health and safety of employees and customers and to ensure system reliability, and have been following the Governor’s directive that the Utilities take necessary measures to ensure they can operate in the normal course. The Utilities have also implemented certain aspects of their business continuity plans, which includes the activation of its Incident Management Team to closely manage the response to the pandemic and have implemented practices related to employee and facilities hygiene in order to ensure the reliability and resilience of their operations.
In the second quarter of 2020, the PUC approved the deferral of certain COVID-19 related costs, such as higher bad debt expense, higher financing costs, non-collection of late payment fees, increased personal protective equipment costs, and sequestration costs for mission-critical employees. As of December 31, 2021, these cumulative costs, which have been deferred and recorded as a regulatory asset, totaled approximately $27.8 million (see also discussion under Item 1A. “Risk Factors” and “Regulatory assets for COVID-19 related costs” in Note 3 of the Consolidated Financial Statements). The Utilities currently have approval to defer COVID-19 related costs through December 31, 2021 and will be seeking recovery of the deferred costs in a separate proceeding at a future date. Looking forward, while the distribution and administration of the COVID-19 vaccine has allowed for fewer restrictions and a broader reopening of the Hawaii economy, a worsening of COVID-19 case counts with the Omicron or other variants or a prolonged period of current or more severe COVID-19 restrictions could adversely affect the ability of the Utilities’ contractors, suppliers, IPPs, and other business partners to perform or fulfill their obligations timely, or
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at all, or require modifications to existing contracts, which could adversely affect the Utilities’ business, increase expenses, and impact the Utilities’ ability to achieve their RPS and other climate related goals. Additionally, while the state’s aggressive response to the pandemic has managed to control the spread of the coronavirus, the measures taken have had a negative economic impact on the state’s businesses and residents, which may influence the PUC’s actions regarding future rate increases. See “Item 1A. Risk Factors” in Part II for additional discussion of risks.
For a discussion regarding the impact of the economic conditions caused by the COVID-19 pandemic on the Utilities’ liquidity and capital resources, see discussion under “Financial Condition–Liquidity and capital resources.”
Performance-based regulations. On December 23, 2020, the PUC issued a D&O (PBR D&O) approving a new performance-based regulation framework (PBR Framework). See “Regulatory proceedings” under “Commitments and contingencies” in Note 3 of the Consolidated Financial Statements.
Transition to a decarbonized and sustainable energy future. The Utilities are fully committed to leading and enabling pathways to a decarbonized and sustainable energy future for Hawaii. The Utilities believe that a holistic approach to decarbonization is needed, and that such a strategy requires achieving the Utilities’ decarbonization and renewable energy commitments, facilitating and promoting beneficial electrification, and deploying carbon removal and offsets, among other levers, to reduce statewide emissions.
In the fourth quarter of 2021, the Utilities set a goal to cut carbon emissions from power generation 70% by 2030, compared to a 2005 baseline. The emissions covered by this goal include stack emissions from generation owned by Hawaiian Electric and IPPs who sell electricity to the Utilities. The 2030 commitment would provide a significant portion of the reduction the entire Hawaii economy needs to meet the U.S. target of cutting carbon emissions by at least 50% economy-wide by 2030. Hawaiian Electric has also committed to achieving net zero carbon emissions from power generation by 2045 or sooner. Key elements of the 2030 plan include the closure of the state’s last coal-fired IPP plant in 2022 upon expiry of the PPA, increasing rooftop solar by more than 50% over 2021 levels, retiring six fossil fuel generating units, adding at least 1 GW of renewable generation to what was already in place in 2021, increasing grid-scale and customer-owned storage, expanding geothermal resources, and creating customer incentives for using clean, lower-cost energy at certain times of the day and using less fossil-fueled energy at night. The retirement of fossil-fueled generating units to achieve the Utilities’ 70% decarbonization goal is consistent with state policy and supported by Hawaii State law. See “Forecast of capital expenditures—Liquidity and capital resources” for a discussion of potential capital expenditures related to decarbonization efforts.
On September 1, 2022, the last coal-fired IPP plant in the state, providing approximately 10% of Oahu’s generation, will cease operations, removing a significant amount of GHG emissions from the Utilities’ generation mix. The plant’s aging infrastructure could lead to more unscheduled outages compared to historic performance, which may impact system reliability. See “Retirement of the AES coal plant” in the “Risk Factor” section for additional information on the transition risks.
In anticipation of the retirement of the coal-fired IPP plant, the Utilities have developed plans, including contingency plans, to ensure reliable service through the transition period. These plans include the anticipated addition of ten renewable energy/storage projects, reserve capacity from existing generation sources, the acceleration of maintenance work during periods with anticipated higher reserve levels, multiple demand response/distributed energy resources programs and a proposed battery project. However, future events, including unexpected issues with existing generation, or supply chain issues and inflationary pressures, as well as federal policies related to solar panel imports, among other factors, delay in the commercial operation of new generation resources, could disrupt the ability of the Utilities to deliver reliable service. Also, see the “Developments in renewable energy efforts—New renewable PPAs” section below.
Hawaii’s renewable portfolio standard law requires electric utilities to meet an RPS of 30%, 40%, 70% and 100% by December 31, 2020, 2030, 2040 and 2045, respectively. Hawaii law has also established a target of sequestering more atmospheric carbon and greenhouse gases than emitted within the state by 2045. The Utilities’ strategies and plans are fully aligned in meeting these targets.
The Utilities have made significant progress on the path to clean energy and have been successful in achieving RPS goals. TheUtilities reached its 2015 RPS goal two years early and exceeded the 30% RPS target for 2020, achieving an RPS of 34.5% that year. In 2021, the Utilities achieved an RPS of 38.4%. The Utilities will continue to actively procure additional renewable energy post-2021 and expect to meet or exceed the next statutory RPS goal of 40% in advance of the 2030 compliance year. (See “Developments in renewable energy efforts” below).
If the Utilities are not successful in meeting the RPS targets as mandated by law, the PUC could assess a penalty of $20 for every MWh that an electric utility is deficient. Based on the level of electricity sales in 2021, a 1% shortfall in meeting the 2030 RPS requirement of 40% would translate into a penalty of approximately $1.7 million. The PUC has the discretion to reduce the penalty due to events or circumstances that are outside an electric utility’s reasonable control, to the extent the event or circumstance could not be reasonably foreseen and ameliorated. In addition to penalties under the RPS law, failure to meet the
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mandated RPS targets would be expected to result in a higher proportion of fossil fuel-based generation than if the RPS target had been achieved, which in turn would be expected to subject the Utilities to limited commodity fossil fuel price exposure under a fuel cost risk-sharing mechanism. The fuel cost risk-sharing mechanism apportions 2% of the fuel cost risk to the utilities (and 98% to ratepayers) and has a maximum exposure (or benefit) of $3.7 million. Conversely, the Utilities have incentives under PIMs that provide a financial reward for accelerating the achievement of renewable generation as a percentage of total generation, including customer supplied generation. The Utilities may earn a reward for the amount of system generation above the interpolated statutory RPS goal at $20/MWh in 2022, $15/MWh in 2023, and $10/MWh for the remainder of the multi-year rate period.
The Utilities are fully aligned with, and supportive of, state policy to achieve a decarbonized future and have made significant progress in reducing emissions through renewable energy and electrification. This alignment with state policy is reflected in management compensation programs and the Utilities’ long-range plans, which include aspirational targets in order to catalyze action and accelerate the transition away from fossil fuels throughout its operations at a pace more rapid than dictated by current law. The long-range plans, including aspirational targets, serve as guiding principles in the Utilities’ continued transformation, and are updated regularly to adapt to changing technology, costs and other factors. While there is no financial penalty for failure to achieve the Utilities’ long-range aspirational objectives, the Utilities recognize that there are environmental and social costs from the continued use of fossil fuels.
The State of Hawaii’s policy is supported by the regulatory framework and includes a number of mechanisms designed to maintain the Utilities’ financial stability during the transition toward the state’s decarbonized future. Under the sales decoupling mechanism, the Utilities are allowed to recover from customers, target test year revenues, independent of the level of kWh sales, which have generally declined (with the exception of 2019 and the first quarter of 2020), as privately-owned distributed energy resources have been added to the grid and energy efficiency measures have been put into place. Other regulatory mechanisms under the new PBR framework reduce some of the regulatory lag during the multi-year rate plan (MRP), such as the annual revenue adjustment to provide annual changes in utility revenues and the exceptional project recovery mechanism, which allows the Utilities to recover and earn on certain approved eligible projects placed into service. See “Regulatory proceedings” under “Commitments and contingencies” and “Decoupling” in Note 3 of the Consolidated Financial Statements.
Integrated Grid Planning. Achieving high levels of renewable energy and a carbon free electric system will require modernizing the grid through coordinated energy system planning in partnership with local communities and stakeholders. To accomplish this, the Utilities are implementing an innovative systems approach to energy planning intended to yield the most cost-effective renewable energy and decarbonization pathways that incorporates customer and stakeholder input.
The IGP utilizes an inclusive and transparent Stakeholder Engagement model to provide an avenue for interested parties to engage with the Utilities and contribute meaningful input throughout the IGP process. The IGP Stakeholder Council, Technical Advisory Panel and Working groups have been established and meet regularly to provide feedback and input on specific issues and process steps in the IGP. The Utilities submitted an updated IGP work plan to the PUC in January 2021. In August 2021, the Utilities submitted their Revised Inputs and Assumptions to the PUC for review and approval, marking the significant progress made through the stakeholder engagement phase of the IGP process. Once approved by the PUC, the next phase of the process, which includes the development of long-range integrated grid plans, will begin.
Demand response programs. Pursuant to PUC orders, the Utilities are developing an integrated Demand Response (DR) Portfolio Plan that will enhance system operations and reduce costs to customers. The reduction in cost for the customer will take the form of either rates or incentive-based programs that will compensate customers for their participation individually, or by way of engagements with turnkey service providers that contract with the Utilities to aggregate and deliver various grid services on behalf of participating customers and their distributed assets.
On June 9, 2021, the PUC issued an order providing guidance to the third Grid Service RFP filed on February 23, 2021. The proposed Grid Service RFP focused only on Oahu and is seeking 60MW of grid services with focus on capacity reduction similarly in response to the potential reserve shortfall from the AES coal plant retirement scheduled on September 1, 2022. The Utilities filed a final draft and received PUC approval to proceed on August 3, 2021. The Utilities subsequently issued an approved Grid Services RFP and the bids were due on October 13, 2021. The Utilities made their final selections on November 10, 2021 and commenced negotiations immediately after. The Utilities are targeting to execute GSPA contracts in early 2022 and file to the PUC for approval.
On June 8, 2021, the PUC approved the new program, Emergency Demand Response Program (EDRP), a battery storage incentive program to dispatch electricity between 6 p.m. to 8 p.m. daily from participating residential and commercial customers, to address the potential reserve shortfalls following the AES coal plant retirement. The PUC approved EDRP for 50MW on Oahu with an incentive budget not to exceed $34 million, which will be recovered via a surcharge cost recovery mechanism over a 10-year amortization. The Utilities’ implementation plan was approved by the PUC on June 30, 2021, and the Utilities subsequently filed the updated EDRP tariffs on July 1, 2021. As of December 31, 2021, the Utilities have received and approved the applications totaling approximately 3.47 MW.
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Grid modernization. The overall goal of the Grid Modernization Strategy is to deploy modern grid investments at an appropriate priority, sequence and pace to cost-effectively maximize flexibility, minimize the risk of redundancy and obsolescence, deliver customer benefits and enable greater distributed energy resources and renewable energy integration. Under the Grid Modernization Strategy, the Utilities expect that new technology will help increase adoption of private rooftop solar and make use of rapidly evolving products, including storage and advanced inverters. The Utilities are implementing Phase 1 of their Grid Modernization Strategy (proportional deployment), which received PUC approval on March 25, 2019. The estimated cost for this initial phase is approximately $86 million and is expected to be incurred over five years. As of December 31, 2021, approximately $36 million has been incurred to date under Phase 1 and is currently being recovered under the Exceptional Project Recovery Mechanism (formerly known as MPIR adjustment mechanism) until such costs are included in base rates. The Utilities have deployed over 50,000 advanced meters since the beginning of deployment and is working with the PUC on plans to expand Phase 1 to cover full service territory.
The Utilities filed an application with the PUC on September 30, 2019 for an Advanced Distribution Management System (ADMS) as part of the second phase of their Grid Modernization Strategy implementation. However, on December 30, 2019, the PUC suspended the Utilities’ application for the Advanced Distribution Management System pending the Utilities’ filing of a supplemental application for the broad deployment of field devices. This supplement and update to the Grid Mod Phase 2 field devices application was filed on March 31, 2021. The estimated cost for the implementation over five years of the ADMS and field devices, which includes capital, deferred and O&M costs, is $105 million. A PUC order was issued on April 27, 2021, unsuspending and resuming consideration of the Phase 2 Application. The Utilities filed the reply statement of position on October 15, 2021, completing the discovery phase of the docket. On November 16, 2021, the PUC suspended the Utilities’ ADMS and Phase 2 field device application to focus the Utilities’ attention on completing Phase 1. The Utilities filed a Motion for Reconsideration with the PUC in response to the suspension, but was denied. The PUC subsequently clarified that the Utilities may resume the Phase 2 docket no earlier than six months before Phase 1 is scheduled to be complete. Phase 1 is currently scheduled to finish by the end of 2023; however, the PUC is considering expanding the scope of Phase 1 meter installations to full service territory deployment, with proposed completion dates of the third quarter of 2024 or the second quarter of 2025. Resumption of the Phase 2 proceeding would likely commence six months prior to the completion date selected by the PUC.
Community-based renewable energy. In December 2017, the PUC adopted a community-based renewable energy (CBRE) program framework which allows customers who cannot, or chose not to, take advantage of private rooftop solar to receive the benefits of renewable energy to help offset their monthly electric bills and support clean energy for Hawaii. The program has two phases.
The first phase, which commenced in July 2018, totals 8 MW of solar photovoltaic (PV) only with one credit rate for each island, closed on April 9, 2020.
The second phase, which commenced on April 9, 2020, allows up to 235 MW across all Hawaiian Electric service territories in two tranches for small (under 250 kW) and large system sizes to encourage a variety of system sizes. To provide opportunities for low- to moderate-income (LMI) customers to participate in the program, separate project proposals may be submitted specifically targeting LMI customers.
Eight RFPs were required by order: one each for Oahu, Maui, Hawaii Island, Molokai, and Lanai, and LMI-specific RFPs for Oahu, Maui, and Hawaii Island. LMI projects do not have a size cap nor do they decrease the 235 MW capacity available to other projects.
For Lanai, the Utilities proposed to combine the previously issued Variable Renewable Dispatchable Generation Paired with Energy Storage RFP and the CBRE RFP to optimize the benefits of procuring renewable energy, spurring development and increasing the likelihood of success of the CBRE Program on Lanai. See “Developments in renewable energy efforts–Requests for renewable proposals, expressions of interest, and information” for additional information.
On November 22, 2021, CBRE RFPs for Molokai and Lanai were issued and are currently accepting proposals through February 15, 2022. On February 8, 2022, the PUC approved, subject to modifications, the CBRE and LMI CBRE RFPs for Oahu, Maui, and Hawaii Island. The Utilities filed the final RFPs with the PUC on February 23, 2022.
For small CBRE projects less than 250 kW in size, the Utilities are planning to accept projects over a four-month period on a first come first served basis as soon as the PUC approves the Utilities’ final tariff and contracts, filed on September 8, 2020. The PUC reserved 30 MW as well as a small amount of unallocated capacity from Phase 1 for small projects in Phase 2 on Oahu, Maui and Hawaii Island. If applications exceed the program capacity for that island, then a reverse auction process called Competitive Credit Rate Procurement will be triggered to allocate project capacity and determine the credit rate. The Utilities have developed a CBRE Portal where customers can subscribe to a project once the Subscriber Organization has added their project to the portal.
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Microgrid services tariff proceeding. In enacting Act 200 of 2018, the Hawaii legislature found that Hawaii’s residents and businesses were vulnerable to disruptions in the islands’ energy systems caused by extreme weather events or other disasters, and stated its belief that the use of microgrids would build energy resiliency into Hawaii’s communities, thereby increasing public safety and security.The purpose of Act 200 was therefore to encourage and facilitate the development and use of microgrids through the establishment of a standard microgrid services tariff. In July 2018, pursuant to Act 200, the PUC opened a proceeding to investigate the establishment of a microgrid services tariff. In August 2019, the PUC issued an order prioritizing items for resolution in the docket and directed the Parties to establish working groups (the “Working Group”) to address issues identified by the PUC.
On March 30, 2020, the Utilities filed a Draft Microgrid Services Tariff and updated language for various distributed energy resources Rules. On November 30, 2020, the PUC held a technical conference to present its proposed redlines to the Utilities’ Draft Microgrid Services Tariff and related documents. On February 1, 2021, the Working Group filed its Draft Microgrid Tariff reflecting areas of consensus and disagreement among the Parties. On May 17, 2021, the PUC issued an order directing the Utilities to submit the Microgrid Services Tariff and appendices as modified by the PUC. The PUC further stated its intent to issue a separate order to govern the next phase of the Microgrid Tariff proceeding. On May 27, 2021, the Utilities filed the Microgrid Service Tariff.
On September 21, 2021, the PUC provided guidance for Phase 2 of the Microgrid Tariff proceeding, specifically identifying the objective for Phase 2 to promote self-sufficiency and resilience among microgrid project operators, as well as to further streamline the Microgrid Services Tariff where applicable. Furthermore, the PUC instructed Parties to recommend priority topics, along with supporting rationale to better inform the topics that will be discussed during this phase of the proceeding, which the parties submitted by October 21, 2021.
Decoupling. See “Decoupling” in Note 3 of the Consolidated Financial Statements for a discussion of decoupling.
Regulated returns. As part of the PBR Framework’s annual review cycle, the Utilities track their rate-making ROACEs as calculated under the earnings sharing mechanism, which includes only items considered in establishing rates. At year-end, each utility’s rate-making ROACE is compared against its ROACE allowed by the PUC to determine whether earnings sharing has been triggered. The D&O in the PBR proceeding modified the earnings sharing mechanism to a symmetric arrangement. Effective with annual earnings for 2021, the earnings sharing will be triggered for achieved rate-making ROACE outside of a 300 basis points dead band above and below the current authorized rate-making ROACE of 9.5% for each of the Utilities. Earnings sharing credits or recoveries will be included in the biannual report (formally known as annual decoupling filing) to be filed with the PUC in the spring of the following year. Results for 2021, 2020, and 2019 did not trigger the earnings sharing mechanism for the Utilities.
Actual and PUC-allowed returns, as of December 31, 2021, were as follows:
% Rate-making Return on rate base (RORB)* ROACE** Rate-making ROACE***
* Based on recorded operating income and average rate base, both adjusted for items not included in determining electric rates.
** Recorded net income divided by average common equity.
*** ROACE adjusted to remove items not included by the PUC in establishing rates, such as incentive compensation.
The factors contributing to the difference gap between PUC-allowed ROACEs and the ROACEs actually achieved prior to the establishment of PBR include the exclusion of certain expenses from rates (for example, incentive compensation and charitable contributions), the recognition of annual RAM revenues on June 1 annually rather than on January 1, and return on capital additions since the last rate case in excess of indexed escalations. As a result of the D&O in the PBR proceeding, the Utilities are allowed to recognize previously established RAM adjustment and ARA revenues on January 1 of each year.
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Results of operations.
2021 vs. 2020
2021 2020 Increase (decrease) (dollars in millions, except per barrel amounts)
$ 2,540 $ 2,265 $ 275 Revenues. Net increase largely due to:
$ 139 higher fuel costs offset by lower kWh generated1
5 higher other revenues from activities billed to third parties
3 higher PIMs revenue
475 474 1 Operation and maintenance expense. Net increase largely due to:
7 more generating facility overhauls and maintenance work performed
2 Customer bill forgiveness and assistance in the fourth quarter of 2021
(6) lower Pearl Harbor environmental reserves in 2021
8.1 % 8.1 % — % Return on average common equity
1The rate schedules of the electric utilities currently contain ECRCs through which changes in fuel oil prices and certain components of purchased energy costs are passed on to customers.
2The rate schedules of the electric utilities currently contain PPACs through which changes in purchase power expenses (except purchased energy costs) are passed on to customers.
3kWh sales were higher when compared to prior year largely due to recovery from the effects of the COVID-19 pandemic. Although international visitor arrivals have not recovered, increases in domestic travel, easing of restrictions, and high vaccination rates led to sales slowly rebounding as the year progressed but remained lower than pre-pandemic levels in 2019.
Hawaiian Electric’s effective tax rate (combined federal and state income tax rates) in 2021 and 2020 was slightly higher at 20% in 2021, compared to 19%, primarily due to the lower amortization in 2021 of the Utilities’ regulatory liability related to certain excess deferred income taxes resulting from the Tax Act’s decrease in the federal income tax rate and a decrease in excess tax benefits related to share-based awards in 2021. These increases were partly offset by federal research and development tax claims in 2021.
For a discussion of 2019 results, please refer to the “Results of operations” section in Item 7, “Management Discussion and Analysis of Financial Condition and Results of Operations—Electric utility,” in the Company’s 2020 Form 10-K.
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The net book value (cost less accumulated depreciation) of utility property, plant and equipment (PPE) as of December 31, 2021 amounted to $4.8 billion, of which approximately 26% related to generation PPE, 65% related to transmission and distribution PPE, and 9% related to other PPE. Approximately 8% of the total net book value relates to generation PPE that has been deactivated or that the Utilities plan to deactivate or decommission.
Regulatory proceedings. On December 23, 2020, the PBR D&O was issued, establishing a new PBR Framework. The PBR Framework implemented a five-year multi-year rate period (MRP), during which there will be no general rate case applications. In the fourth year of the MRP, the PUC will comprehensively review the PBR Framework to determine if any modifications or revisions are appropriate. See also “Regulatory proceedings” in Note 3 of the Consolidated Financial Statements.
Developments in renewable energy efforts. Developments in the Utilities’ efforts to further their renewable energy strategy include renewable energy projects discussed in Note 3 of the Consolidated Financial Statements and the following:
New renewable PPAs.
•In December 2014, the PUC approved a PPA for Renewable As-Available Energy dated October 3, 2013 between Hawaiian Electric and Na Pua Makani Power Partners, LLC (NPM) for a proposed 24-MW wind farm on Oahu. In August 2020, the project was energized and commissioning of all wind turbines was completed. However, the project was paused due to a conductor deficiency. Hawaiian Electric reconductored the 46kV circuit and in December 2020, the project reached commercial operation.
NPM received its Incidental Take Permit from the Department of Fish and Wildlife Service on September 7, 2018. Keep the North Shore Country (KNSC) has appealed this decision and the case has been transferred to the Hawaii Supreme Court. On June 17, 2020, KNSC filed a Motion for Stay Upon Appeal. On August 10, 2020, KNSC’s Motion for Stay Upon Appeal was denied. Oral arguments were held before the court on April 1, 2021, and the case is ready for decision making.
KNSC and Kahuku Community Association (KCA) have also petitioned to appeal NPM’s Conditional Use Permits issued by the Honolulu Department of Planning and Permitting. On August 6, 2020, the Zoning Board of Appeals (ZBA) granted NPM’s Motions to Dismiss the Appeal Petitions of KNSC and KCA. On November 17, 2020, the ZBA dismissed the appeals. On November 24, 2020, KNSC and KCA appealed the dismissal to the circuit court. The circuit court affirmed the ZBA’s dismissal of the appeals on June 30, 2021. On July 1, 2021, KNSC and KCA appealed that decision to the Hawaii Intermediate Court of Appeals where briefing is currently ongoing. The briefing was scheduled to conclude on January 28, 2022.
Life of the Land (LOL) filed a Motion for Relief to argue the PUC’s approval for NPM PPA was invalid and should be revised. Hawaiian Electric and the Consumer Advocate filed an opposition to this motion for relief. A hearing on the motion for relief was held on November 22, 2019. On April 16, 2020, the PUC issued an order denying LOL’s Motion for Relief. On April 27, 2020, LOL filed a Notice of Appeal of the PUC’s order with the Supreme Court of the State of Hawaii. In June 2021, the Supreme Court denied LOL’s appeal.
•On December 31, 2019, Hawaii Electric Light and PGV entered into an Amended and Restated Power Purchase Agreement (ARPPA), subject to approval by the PUC. The ARPPA extends the term of the existing PPA by 25 years to 2052, expands the firm capacity of the facility to 46 MW and delinks the pricing for energy delivered from the facility from fossil fuel prices to reduce cost to customers. On March 31, 2021, the PUC suspended the docket pending the completion of a supplemental environmental review under the Hawaii Environmental Policy Act (HEPA). On November 2, 2021, the Office of Planning and Sustainable Development of the State of Hawaii (OPSD) sent a letter (November 2nd Letter) to the Honorable Mitch Roth, County of Hawaii, identifying the Planning Department for the County of Hawaii to be the accepting agency and approving authority for any required HEPA review. Shortly thereafter, the PUC lifted the suspension of the docket and stating the docket was ready for decision-making, however, the PUC gave the parties a chance to brief the PUC if they disagreed that the docket was ready for decision-making. On November 15, 2021 Puna Pono Alliance responded alleging that any decision should occur after PGV’s completed supplemental environmental review is available and sent a letter to Mayor Roth questioning OPSD’s authority to issue the November 2nd Letter. On December 8, 2021 Mayor Roth sent a letter to OPSD requesting clarification on OPSD’s determination that the County of Hawaii’s Planning Department is correctly identified as the accepting authority.
•The Utilities’ renewable energy goals depend, in large part, on the success of renewable projects developed and operated by independent power producers. Beginning in 2017, the Utilities embarked on an ambitious procurement effort, selecting multiple solar plus storage efforts to help reach the Utilities renewable portfolio standards goals as well as to assist the Utilities in retiring fossil fuel generation. Several of the recently procured projects have experienced delays or have been declared null and void by the independent power producers due to a number of issues, including supply chain disruptions caused by impacts from the COVID-19 pandemic, solar product detentions at U.S.
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ports of entry ordered by the U.S. Customers and Border Protection agency, and unforeseen site conditions which resulted in unanticipated project costs or in some cases the inability to effectively use previously identified project sites. Significant project delays or failures of these projects increase the risk of the Utilities not meeting the renewable portfolio standards or other climate related goals, eligibility for performance incentive mechanisms associated with the speed of increasing renewable generation, and the ability to retire fossil fuel units.
Tariffed renewable resources.
•As of December 31, 2021, there were approximately 550 MW, 117 MW and 131 MW of installed distributed renewable energy technologies (mainly PV) at Hawaiian Electric, Hawaii Electric Light and Maui Electric, respectively, for tariff-based private customer generation programs, namely Standard Interconnection Agreement, Net Energy Metering, Net Energy Metering Plus, Customer Grid Supply, Customer Self Supply, Customer Grid Supply Plus and Interim Smart Export. As of December 31, 2021, an estimated 32% of single-family homes on the islands of Oahu, Hawaii and Maui have installed private rooftop solar systems, and approximately 20% of the Utilities’ total customers have solar systems.
•The Utilities began accepting energy from feed-in tariff projects in 2011. As of December 31, 2021, there were 43 MW, 3 MW and 6 MW of installed feed-in tariff capacity from renewable energy technologies at Hawaiian Electric, Hawaii Electric Light and Maui Electric, respectively.
Biofuel sources.
•In July 2018, the PUC approved Hawaiian Electric’s three-year biodiesel supply contract with Pacific Biodiesel Technologies, LLC (PBT) to supply 2 million to 4 million gallons of biodiesel at Hawaiian Electric’s Schofield Generating Station and the Honolulu International Airport Emergency Power Facility (HIA Facility) and any other generating unit on Oahu, as necessary. The PBT contract became effective on November 1, 2018, and has been extended for one year through December 2022. Hawaiian Electric also has a spot buy contract with PBT to purchase additional quantities of biodiesel at or below the price of diesel. Some purchases of “at parity” biodiesel have been made under the spot purchase contract, which was extended through June 2023. On June 30, 2021, the Utilities issued an RFP for all fuels, including biodiesel, for supply commencing January 1, 2023. The Utilities and PBT signed an agreement on December 13, 2021 for supply of biodiesel on all islands commencing January 1, 2023, subject to PUC approval.
•Hawaiian Electric has a contingency supply contract with REG Marketing & Logistics Group, LLC to also supply biodiesel to any generating unit on Oahu in the event PBT is not able to supply necessary quantities. This contingency contract has been extended to November 2022, and will continue with no volume purchase requirements.
Requests for renewable proposals, expressions of interest, and information.
•Under a request for proposal process governed by the PUC and monitored by independent observers, in February 2018, the Utilities issued RFPs for 220 MW of renewable generation on Oahu, 50 MW of renewable generation on Hawaii Island, and 60 MW of renewable generation on Maui. As of December 31, 2021, summarized information for a total of 8 PPAs is as follows:
The Utilities have received PUC approvals to recover the total projected annual payment of $63.6 million for the eight PPAs through the PPAC to the extent such costs are not included in base rates.
•In continuation of their February 2018 request for proposal process, the Utilities issued their Stage 2 Renewable RFPs for Oahu, Maui and Hawaii Island and Grid Services RFP on August 22, 2019. Final awards for the renewable projects were made on May 8, 2020. Final awards for the grid services projects were made starting in January 2020. On Oahu, seven solar-plus-storage projects and one standalone storage project totaling approximately 281 MW of generation and 1.8 GWh of storage were selected. On Maui, three solar-plus-storage projects and one standalone storage project totaling approximately 100 MW of generation and 560 MWh of storage were selected. On Hawaii Island, two solar-plus-storage projects and one standalone storage project totaling approximately 72 MW of generation and 492 MWh of
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storage were selected. Two Utility Self-Build projects were among those selected; a 40-MW, 160-MWh standalone energy storage system on Maui and a 12-MW, 12-MWh storage system on Hawaii Island. Three renewable plus storage projects voluntarily withdrew from the process prior to execution of a power purchase agreement for various reasons, including change in circumstances for the developer and a misunderstanding of contract requirements. As of December 31, 2021, the Utilities had filed 10 PPAs, 2 grid services purchase agreements (GSPA) and 2 applications for commitments of funds for capital expenditures for approval of the utility self-build projects with the PUC. On October 25, 2021, one solar-plus-storage project on Hawaii Island was declared null and void by the developer. On December 6, 2021, one solar-plus-storage project on Oahu was declared null and void by the developer. On January 14, 2022, the Utilities filed an additional solar plus storage PPA for approval for 42 MW of generation and 168 MWh of storage.
A summary of the 9 PPAs that are still under active development, is as follows:
* See further discussion under “Review of Interconnection Process and Kapolei Energy Storage Power Purchase Agreement” below.
As of December 31, 2021, seven projects that have been approved by the PUC remain in development – six solar-plus-storage PPAs (257 MW) and one standalone storage PPA (185 MW). The total projected annual payment of $95.8 million for these PPAs will be recovered through the PPAC to the extent such costs are not included in base rates. On February 15, 2022, the Utilities filed letters with the PUC requesting approval of amendments to two of the previously-approved PPAs for Stage 2, one on Oahu and one on Maui, that address delays and price increase due to the COVID-19 pandemic and the global supply-chain crisis, as well as other market conditions that have arisen during the development of these projects.
A summary of the GSPAs that were approved by PUC in December 2020 is as follows:
Hawaii Electric Light 6.0 — 3.2 4.0
A summary of the utility self-build projects that are pending PUC approval is as follows:
•On November 27, 2019, the Utilities issued RFPs for renewable generation paired with energy storage on the islands of Lanai and Molokai. The Utilities were seeking PV paired with storage or small wind (specified as 100 kW turbines or smaller) on Molokai and PV paired with storage on Lanai. The RFP on Lanai was postponed on January 14, 2020 to allow the Utility to re-evaluate the scope of the RFP in response to announced plans to remove two large resorts from the grid. Proposals for the Molokai RFP were received on February 14, 2020. In light of a PUC order issued on April 9, 2020 in the CBRE docket, the Utilities proposed in their July 9, 2020 filing to combine the previously issued and subsequently postponed Lanai RFP with the CBRE RFP described in the order to optimize the benefits of procuring renewable energy, spurring development and increasing the likelihood of success of the CBRE program on Lanai. On May 21, 2021, the PUC approved the proposed combined Lanai RFP. On October 15, 2020, the Utilities selected one project from the Molokai RFP for a total of 4.5 MW of solar and 24 MWh of storage. The developer, however,
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declined to accept the award. On August 25 and 31, 2021, the Utilities filed proposed final drafts of the CBRE RFPs, which included three dedicated Low-to-Moderate-Income RFPs on Oahu, Maui and Hawaii, three Tranche 1 RFPs on Oahu, Maui and Hawaii, a Molokai CBRE RFP, and a combined Lanai Variable and CBRE RFP. On November 22, 2021, CBRE RFPs for Molokai and Lanai were opened. On February 8, 2022, the PUC approved, subject to modifications, the CBRE and LMI CBRE RFPs for Oahu, Maui, and Hawaii island. The Utilities filed the final RFPs with the PUC on February 23, 2022.
• The PUC issued a letter to the Utilities requesting development with a Stage 3 RFP on Hawaii Island on January 21, 2021. In accordance with guidance provided by the PUC in a subsequent letter on April 20, 2021, the Utilities filed the Hawaii Island Grid Needs Assessment on July 15, 2021 and the draft RFP, including model contracts for PV+BESS, wind+BESS, standalone storage, firm renewable generation, and distributed energy resources aggregators on October 15, 2021. The requirements in the Stage 3 RFP are guided by the results of the Grid Needs Assessment. On February 22, 2022, the PUC sent a letter to the Utilities directing them to develop Stage 3 RFPs for Oahu and Maui. The Utilities are currently evaluating next steps.
•On November 17, 2021, the Utilities filed a request with the PUC to develop an RFP for firm renewable generation for Oahu. On December 22, 2021, the PUC issued guidance to the Utilities on proceeding with such RFP. The Utilities are developing the RFP requirements and plan to file a draft RFP in the first quarter of 2022.
Review of Interconnection Process and Kapolei Energy Storage Power Purchase Agreement.
• In February 2021, the PUC initiated a docket for the purposes of reviewing the status and interconnection progress of various utility-related renewable projects (i.e. Stage 1 and Stage 2 RFP PPAs and CBRE) and the Utilities’ transition plans for the expiration of the AES power purchase agreement, the retirement of the Kahului Power Plant, and other fossil fuel power plant transition plans, as needed. The Utilities filed initial status updates on the project timelines, steps needed for each of the renewable projects to achieve commercial operation and steps the Utilities are taking to address projected extensions of guaranteed commercial operation dates (GCOD) for renewable projects under development, which are due to a variety of factors, including those outside of the control of the Utilities. The PUC subsequently held status conferences on the Utilities’ updates. In April 2021, the PUC issued an Order directing the Utilities to establish regulatory liabilities for the difference between the on-peak avoided cost and the unit price included in the applications for approval of the renewable project PPAs, effective with the GCOD included in the applications (the earliest GCOD included in the applications is July 2021) or from the date of the Order for CBRE Phase 1 projects. The amount of regulatory liabilities to be recorded in future periods are not determinable at this time and would be affected by a number of factors, including the length of the GCOD extension period, the monthly on-peak avoided cost, as well as the factors described above. The Utilities filed a Motion for Reconsideration of the entire Order, or in the alternative to clarify that at most the PUC is directing the Utilities to track the information and not record the information at this time. The Utilities further requested a Stay of the Order pending resolution of the Motion. The Utilities maintain that extensions of GCODs are allowed under the PUC-approved contracts and that the Order has the unintended consequence of imposing penalties against the Utilities without due process. In May 2021, the PUC issued an order clarifying its Order and directed the Utilities to track costs to consumers caused by the perceived delay of renewable projects, and that the PUC does not intend to, at this time, impose any penalties on the Utilities. The full text of the Order, Motion for Reconsideration and request for a Stay of the Order, and clarification Order can be found on the PUC website at dms.puc.hawaii.gov/dms (Docket No. 2021-0024).
• Also in April 2021, the PUC approved the Kapolei Energy Storage (KES) PPA (one of the PPAs as a result of the Stage 2 Renewable RFP process) (KES Decision and Order), subject to nine conditions, including the Utilities forgoing the second portion of the PIM rewards amounting up to $1.7 million for the Stage 1 RFP PPAs, removing grid constraints for the Utilities’ CBRE Phase 2 projects and for existing and new distributed energy programs, financial retirement of Hawaiian Electric generating units by specified dates and adjusting target revenues at the retirement dates for such retirements, and a requirement to charge the batteries in the project using significant levels of renewable energy generation. The financial retirement of the generating units described in the KES Decision and Order is contrary to the intent of Hawaii Revised Statutes §269-6(d), which encourages the recovery of stranded costs for the retirement of fossil fuel generation, and contrary to the regulatory compact under which in return for agreeing to commit capital necessary to allow utilities to meet their obligation to serve, utilities are assured recovery of their investment and a fair opportunity to earn a reasonable return on the capital prudently committed to the business. Hawaiian Electric filed a Motion for Reconsideration and Stay of the Decision and Order due to potentially significant financial and operational impacts. In May 2021, the PUC granted, in part, Hawaiian Electric’s Motion for Reconsideration and Stay. In this Order, the PUC addressed a number of Hawaiian Electric’s concerns, including removing the condition of the Utilities foregoing the PIM award from Stage 1 RFP projects, agreeing to address grid constraint concerns in respective DER and CBRE dockets and not in the KES docket, removing the minimum
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thresholds of charging energy coming from renewable energy generation and corresponding deadlines associated with these thresholds and modifying the condition on financial retirement of generating units. The PUC indicated the net book value of generating assets would be addressed at the time of retirement. The full text of the KES Decision and Order and the Motion for Reconsideration and Stay with respect thereto, and the Order granting, in part, Hawaiian Electric’s Motion for Reconsideration can be found on the PUC website at dms.puc.hawaii.gov/dms (Docket No. 2020-0136).
Legislation and regulation. Congress and the Hawaii legislature periodically consider legislation that could have positive or negative effects on the Utilities and their customers. Also see “Environmental regulation” in “Item 1. Business” and Note 3 of the Consolidated Financial Statements.
Fuel contracts. The fuel contract entered into in January 2019, by the Utilities and PAR Hawaii Refining, LLC (PAR Hawaii), for the Utilities’ low sulfur fuel oil (LSFO), high sulfur fuel oil (HSFO), No. 2 diesel, and ultra-low sulfur diesel (ULSD) requirements was approved by the PUC, and became effective on April 28, 2019 and terminates on December 31, 2022. This contract is a requirement contract with no minimum purchases. If PAR Hawaii is unable to provide LSFO, HSFO, diesel and/or ULSD the contract allows the Utilities to purchase LSFO, HSFO, diesel and/or ULSD from another supplier. On June 30, 2021, the Utilities issued two RFPs for all fuels for supply commencing January 1, 2023. On February 1, 2022, the Utilities and PAR Hawaii entered into a fuel supply contract commencing January 1, 2023 and Second Amendment to the existing fuel contract to amend tier-1 volumes. The Second Amendment will take effect contingent upon PUC’s approval. The costs incurred under the contract with PAR Hawaii are recovered in the Utilities’ respective ECRCs.
On June 9, 2020, the Utilities and PAR Hawaii entered into a First Amendment to the fuel contract. The First Amendment amends only the LSFO pricing to create a two-tiered structure based on volume, with all tier-1 LSFO up to the tier-1 maximum to be purchased exclusively from PAR Hawaii at the established pricing, and purchases in excess of that volume (tier-2) either from PAR Hawaii at the established pricing, or from an alternative supplier. On August 4, 2020, the PUC approved the First Amendment, which has an effective date of July 15, 2020, on an interim basis. The PUC’s approval order allows the recovery of such costs associated with the First Amendment through the ECRC to the extent that the costs are not recovered in base rates. The PUC intends to review whether the First Amendment is reasonable and in the public interest in the final decision, but it will not subject the recovery of the costs between the interim decision and the final decision to retroactive disallowances.
Army privatization. On October 30, 2020, the PUC approved Hawaiian Electric’s 50-year contract with the U.S. Army to own, operate and maintain the electric distribution system serving the U.S. Army’s 12 installations on Oahu, including Schofield Barracks, Wheeler Army Airfield, Tripler Army Medical Center, Fort Shafter, and Army housing areas. Hawaiian Electric will acquire the Army’s existing distribution system for a stated purchase price of $16.3 million, under the approved contract, and will pay the Army in the form of a monthly credit against the monthly utility services charge over the 50-year term of the contract. The final purchase price is subject to Hawaiian Electric completing its due diligence and evaluation of the assets being acquired.
Hawaiian Electric will take ownership and all responsibilities for operation and maintenance of the system on March 1, 2022 for a 50-year term, after a one-year transition period. Under the contract, Hawaiian Electric will make initial capital upgrades over the first six years of the contract and replacement of aging infrastructure over the 50-year term. In addition to its regular monthly electricity bill, the Army will pay Hawaiian Electric a monthly utility services charge to cover operations and maintenance expenses and provide recovery for capital upgrades, capital replacements, and the existing distribution system based on a rate of return determined by the PUC for regulated utility investments, as well as depreciation expense. A preliminary assessment estimated the capital needs of approximately $40 million in the first six years of the contract. The PUC requires Hawaiian Electric to file regular periodic reports on the activities and investments in fulfillment of the contract and will review the major projects planned on behalf of the Army. The annual impact on Hawaiian Electric’s earnings is not expected to be material and will depend on a number of factors, including the amount and timing of capital upgrades and capital replacement.
Liquidity and capital resources. As of December 31, 2021, there were no amounts outstanding on Hawaiian Electric’s revolving credit facility and under its commercial paper program and the total amount of available borrowing capacity under the Utilities’ committed line of credit was $200 million.
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Hawaiian Electric expects that its liquidity will continue to be moderately impacted at the Utilities due to ongoing COVID-19 impacts to the local economy. Compared to pre-pandemic levels, delinquent accounts receivable balances have increased, which could result in higher write-offs in the future, and kWh sales have generally declined, both of which impact the timing of cash flows and creates higher working capital requirements. However, the Utilities’ liquidity and access to capital remains adequate and is expected to remain adequate. As of December 31, 2021, the total amount of available borrowing capacity (net of commercial paper outstanding) under the Utilities’ committed lines of credit and cash and cash equivalents was approximately $252 million.
The moratorium on customer disconnections was lifted on May 31, 2021. Starting in the third quarter of 2021, the Utilities commenced the disconnection process on a tiered basis, targeting the oldest and largest balances first, which is expected to reduce delinquent accounts receivable balances over time and accelerate cash collections.
Hawaiian Electric’s consolidated capital structure was as follows:
(dollars in millions)
Short-term borrowings $ — — % $ 50 1 %
Information about Hawaiian Electric’s commercial paper borrowings, borrowings from HEI, and line of credit facility were as follows:
(in millions) Averagebalance End-of-periodbalance December 31, 2020
Short-term borrowings1
Commercial paper $ 8 $ — $ —
Line of credit draws — — —
Borrowings from HEI — — —
Undrawn capacity under line of credit facilities2 — 200 275
1The maximum amount of external short-term borrowings by Hawaiian Electric during 2021 was approximately $52 million. At December 31, 2021, Hawaii Electric Light and Maui Electric had short-term borrowings from Hawaiian Electric of $1 million and nil, respectively, which intercompany borrowings are eliminated in consolidation. In addition to the short-term borrowings above, on January 15, 2021, Hawaiian Electric paid off the $50 million term loan dated as of May 19, 2020 (see Note 5 of the Consolidated Financial Statements).
2On April 19, 2021, Hawaiian Electric’s $75 million 364-day revolving credit agreement expired and was not renewed.
Hawaiian Electric utilizes short-term debt, typically commercial paper, to support normal operations, to refinance short-term debt and for other temporary requirements. Hawaiian Electric also borrows short-term from HEI for itself and on behalf of Hawaii Electric Light and Maui Electric, and Hawaiian Electric may borrow from or loan to Hawaii Electric Light and Maui Electric on a short-term basis. The intercompany borrowings among the Utilities, but not the borrowings from HEI, are eliminated in the consolidation of Hawaiian Electric’s financial statements. The Utilities periodically utilize long-term debt, borrowings of the proceeds of special purpose revenue bonds (SPRBs) issued by the State of Hawaii Department of Budget and Finance (DBF) and the issuance of privately placed unsecured senior notes bearing taxable interest, to finance the Utilities’ capital improvement projects, or to repay short-term borrowings used to finance such projects. The PUC must approve issuances, if any, of equity and long-term debt securities by the Utilities.
Credit agreement. On April 19, 2021, Hawaiian Electric’s $75 million 364-day revolving credit agreement expired and was not renewed. On May 14, 2021, Hawaiian Electric entered into an agreement with a syndicate of nine financial institutions, to amend and restate its previously existing $200 million unsecured revolving credit agreement (Hawaiian Electric Facility). As of December 31, 2021, no amounts were outstanding under the facility. On February 18, 2022, the PUC approved Hawaiian Electric's request to extend the term of the $200 million Hawaiian Electric Facility to May 14, 2026 from May 13, 2022. See Note 5 of the Consolidated Financial Statements.
Credit ratings. On March 17, 2021, S&P upgraded Hawaiian Electric’s issuer credit rating to “BBB” from “BBB-,” upgraded the short-term and commercial paper ratings to “A-2” from “A-3” and revised the outlook to stable from positive. The rating upgrade was primarily based on Hawaiian Electric’s strong financial measures, strength of the cumulative value of the
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regulatory protections, and S&P’s assessment of its stand-alone credit profile as sufficient to rate Hawaiian Electric higher than HEI.
On April 20, 2021, Moody’s upgraded Hawaiian Electric’s senior unsecured rating and issuer rating to “Baa1” from “Baa2” and revised the outlook to stable from positive. The rating upgrade reflects Hawaiian Electric’s considerable progress in adding renewable resources to its energy supply mix and the improving regulatory relationship with the PUC. On June 25, 2021, Fitch affirmed Hawaiian Electric’s “BBB+” long-term issuer default rating, “F2” short-term issuer default rating and stable outlook.
As of February 11, 2022, the Fitch, Moody’s and S&P ratings of Hawaiian Electric were as follows:
Fitch Moody’s S&P
Commercial paper F2 P-2 A-2
Senior unsecured debt/special purpose revenue bonds A- Baa1 *
Cumulative preferred stock (selected series) * Baa3 *
Outlook Stable Stable Stable
* Not rated.
Note: The above ratings reflect only the view, at the time the ratings are issued or affirmed, of the applicable rating agency, from whom an explanation of the significance of such ratings may be obtained. Such ratings are not recommendations to buy, sell or hold any securities; such ratings may be subject to revision or withdrawal at any time by the rating agencies; and each rating should be evaluated independently of any other rating.
SPRBs. Special purpose revenue bonds (SPRBs) have been issued by the Department of Budget and Finance of the State of Hawaii (DBF) to finance (and refinance) capital improvement projects of Hawaiian Electric and its subsidiaries, but the sources of their repayment are the non-collateralized obligations of Hawaiian Electric and its subsidiaries under loan agreements and notes issued to the DBF, including Hawaiian Electric’s guarantees of its subsidiaries’ obligations.
On May 24, 2019, the PUC approved the Utilities’ request to issue SPRBs in the amounts of up to $70 million, $2.5 million and $7.5 million for Hawaiian Electric, Hawaii Electric Light and Maui Electric, respectively, prior to June 30, 2020, to finance the Utilities’ capital improvement programs. Pursuant to this approval, on October 10, 2019, the DBF issued, at par, Series 2019 SPRBs in the aggregate principal amount of $80 million with a maturity of October 1, 2049. As of December 31, 2021, Hawaiian Electric had $3 million of undrawn funds remaining with the trustee. Hawaii Electric Light and Maui Electric had no undrawn funds as of December 31, 2021.
On June 10, 2019, the Hawaii legislature authorized the issuance of up to $700 million of SPRBs ($400 million for Hawaiian Electric, $150 million for Hawaii Electric Light and $150 million for Maui Electric), with PUC approval, prior to June 30, 2024, to finance the Utilities’ multi-project capital improvement programs (2019 Legislative Authorization).
On February 9, 2021, the PUC approved the Utilities’ request to issue SPRBs (up to $100 million, $35 million and $45 million for Hawaiian Electric, Hawaii Electric Light and Maui Electric, respectively) through 2022, with the proceeds to be used to finance the Utilities’ multi-project capital improvement programs. The PUC also approved the use of the expedited approval procedure to request the issuance and sale of the remaining/unused amount of SPRBs authorized by the 2019 Legislative Authorization (i.e., total not to exceed up to $400 million for Hawaiian Electric, up to $150 million for Hawaii Electric Light, and up to $150 million for Maui Electric) during the period January 1, 2023 through June 30, 2024.
Bank loans. On January 15, 2021, Hawaiian Electric paid off the $50 million term loan drawn on May 19, 2020.
Taxable debt. On January 31, 2019, the Utilities received PUC approval (January 2019 Approval) to issue the remaining authorized amounts under the PUC approval received in April 2018 (April 2018 Approval) in 2019 through 2020 (Hawaiian Electric up to $205 million and Hawaii Electric Light up to $15 million of taxable debt), as well as a supplemental increase to authorize the issuance of additional taxable debt to finance capital expenditures, repay long-term and/or short term debt used to finance or refinance capital expenditures, and/or to reimburse funds used for payment of capital expenditures, and to refinance the Utilities’ 2004 junior subordinated deferrable interest debentures (QUIDS) prior to maturity. In addition, the January 2019 Approval authorized the Utilities to extend the period to issue additional taxable debt from December 31, 2021 to December 31, 2022. The new total “up to” amounts of taxable debt requested to be issued through December 31, 2022 are $410 million, $150 million and $130 million for Hawaiian Electric, Hawaii Electric Light and Maui Electric, respectively.
Pursuant to the approval, on January 14, 2021, the Utilities drew $115 million of proceeds using a delayed draw feature under a private placement executed on October 29, 2020. The proceeds were used to finance capital expenditures and reimburse funds used for the payment of capital expenditures.
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As of December 31, 2021, Hawaiian Electric, Hawaii Electric Light, and Maui Electric have $135 million, $85 million, and $45 million, respectively, of remaining taxable debt to issue prior to December 31, 2022. See summary table below.
(in millions) Hawaiian Electric Hawaii Electric Light Maui Electric
Total “up to” amounts of taxable debt authorized through 2022 $ 410 $ 150 $ 130
Less:
Taxable debt authorized and issued in 2018 under April 2018 Approval 75 15 10
Remaining authorized amounts $ 135 $ 85 $ 45
On September 30, 2021, the Utilities requested PUC approval through the expedited approval process to issue taxable debt (Hawaiian Electric up to $30 million, Hawaii Electric Light up to $30 million and Maui Electric up to $35 million) prior to December 31, 2022. On December 13, 2021, the Utilities submitted an updated letter request to modify Hawaiian Electric’s request to up to $50 million from the original up to $30 million.
Equity. In October 2018, the Utilities received PUC approval for the supplemental increase to issue and sell additional common stock in the amounts of up to $280 million for Hawaiian Electric and up to $100 million each for Hawaii Electric Light and Maui Electric, with the new total “up to” amounts of $430 million for Hawaiian Electric and $110 million each for Hawaii Electric Light and Maui Electric, and to extend the period authorized by the PUC to issue and sell common stock from December 31, 2021 to December 31, 2022. As of December 31, 2021, Hawaiian Electric, Hawaii Electric Light, and Maui Electric have $221.4 million, $93.7 million, and $63.2 million, respectively, of remaining common stock to issue prior to December 31, 2022. See summary table below.
(in millions) Hawaiian Electric Hawaii Electric Light Maui Electric
Cash flows. The following table reflects the changes in cash flows for the twelve months ended December 31, 2021
compared to the twelve months ended December 31, 2020:
Years ended December 31
Net cash provided by (used in) financing activities 4,764 29,675 (24,911)
Net cash provided by operating activities: The decrease in net cash provided by operating activities was primarily driven by lower cash receipts from customers due to the impact of the pandemic and timing in receipts of payments, and higher cash paid for fuel stock due to higher fuel oil prices and volume purchased, partially offset by lower cash paid for accounts payable due to timing .
Net cash used in investing activities: The decrease in net cash used in investing activities was primarily driven by a decrease in capital expenditures related to construction activities.
Net cash provided by financing activities: The decrease in net cash provided by financing activities was primarily driven by lower net cash from long-term and short-term debts.
For a discussion of 2019 operating, investing and financing activities, please refer to the “Liquidity and capital resources” section in Item 7, “Management Discussion and Analysis of Financial Condition and Results of Operations—Electric utility,” in the Company’s 2020 Form 10-K.
Material cash requirements. Material cash requirements of the Utilities include O&M expenses, including labor and benefit costs, fuel and purchase power costs, repayment of debt and interest payments, operating lease obligations, its forecasted
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capital expenditures and investments, its expected retirement benefit plan contributions and other short-term and long-term material cash requirements. The cash requirements for O&M, fuel and purchase power costs, debt and interest payments, and operating lease obligations are generally funded through the collection of the Utilities’ revenue requirement established in the last rate case and other mechanisms established under the regulatory framework. The cash requirements for capital expenditures are generally funded through retained earnings, the issuance of debt, and contributions of equity from HEI and generally recovered through the Utilities’ revenue requirement or other capital recovery mechanisms over time. The Utilities believe that their ability to generate cash is adequate to maintain sufficient liquidity to fund their material cash requirements. However, the COVID-19 pandemic is an evolving situation, and the Utilities cannot predict the extent or duration of the outbreak, the future effects that it will have on the global, national or local economy, including the impacts on the Utilities’ ability, as well as the cost, to access additional capital, or the future impacts on the Utilities’ financial position, results of operations, and cash flows. See Item 1A. “Risk Factors” in Part I for further discussion of risks and uncertainties.
Forecast of capital expenditures. For the five-year period 2022 through 2026, the Utilities forecast up to $2.1 billion of net capital expenditures, which could change over time based upon external factors such as the timing and scope of environmental regulations and/or unforeseen delays in permitting and timing of PUC decisions. Approximately $1.30 billion is related to replacement and modernization of generation, transmission and distribution assets; approximately $0.5 billion is related to climate-related projects to transition to renewable energy or mitigate climate impacts by increasing the resilience of the system, and approximately $0.3 billion for targeted efforts to improve reliability. Proceeds from the issuance of equity and long-term debt, cash flows from operating activities, temporary increases in short-term borrowings and existing cash and cash equivalents are expected to provide the funds needed for the net capital expenditures, to pay down commercial paper or other short-term borrowings, as well as to fund any unanticipated expenditures not included in the 2022 to 2026 forecast (such as increases in the costs or acceleration of capital projects, or unanticipated capital expenditures that may be required by new environmental laws and regulations).
Management periodically reviews capital expenditure estimates and the timing of construction projects. These estimates may change significantly as a result of many considerations, including changes in economic conditions, changes in forecasts of kWh sales and peak load, the availability of purchased power and changes in expectations concerning the construction and ownership of future generation units, the availability of generating sites and transmission and distribution corridors, the need for fuel infrastructure investments, the ability to obtain adequate and timely rate increases, escalation in construction costs, the effects of opposition to proposed construction projects and requirements of environmental and other regulatory and permitting authorities.
Selected short-term and long-term contractual obligations and commitments. The following table presents aggregated information about total payments due from the Utilities during the indicated periods under the specified contractual obligations and commitments:
December 31, 2021 Payments due by period
(in millions) Less than 1 year 1-3years 3-5years More than 5 years Total
Operating leases
PPAs classified as leases 46 8 7 4 65
Open purchase order obligations 1 93 39 8 — 140
Liabilities for uncertain tax positions — 2 — — 2
1 Includes contractual obligations and commitments for capital expenditures and expense amounts.
The table above does not include other categories of obligations and commitments, such as deferred taxes, trade payables, amounts that will become payable in future periods under collective bargaining and other employment agreements and employee benefit plans and potential refunds of amounts collected from ratepayers (e.g., under the earnings sharing mechanism). As of December 31, 2021, the fair value of the assets held in trusts to satisfy the obligations of the Utilities’ retirement benefit plans did not exceed the retirement benefit plans’ benefit obligation. Minimum funding requirements for retirement benefit plans have not been included in the table above. See Note 10 of the Consolidated Financial Statements for retirement benefit plan obligations and estimated contributions for 2022.
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See “Biofuel sources” in the “Developments in renewable energy efforts” section above for additional information for fuel oil purchase obligation. See Notes 3 and 8 of the Consolidated Financial Statements for a discussion of power purchase commitments and operating leases obligations, respectively.
Competition. Although competition in the generation sector in Hawaii is moderated by the scarcity of generation sites, various permitting processes and lack of interconnections to other electric utilities, the PUC has promoted a more competitive electric industry environment through its decisions concerning competitive bidding and distributed generation. An increasing amount of generation is provided by IPPs and customer distributed generation.
Competitive bidding. In December 2006, the PUC issued a decision that included a final competitive bidding framework, which became effective immediately. The final framework states, among other things, that: (1) a utility is required to use competitive bidding to acquire a future generation resource or a block of generation resources unless the PUC finds bidding to be unsuitable; (2) the framework does not apply in certain situations identified in the framework; (3) waivers from competitive bidding for certain circumstances will be considered; (4) the utility is required to select an independent observer from a list approved by the PUC whenever the utility or its affiliate seeks to advance a project proposal (i.e., in competition with those offered by bidders); (5) the utility may consider its own self-bid proposals in response to generation needs identified in its RFP; and (6) for any resource to which competitive bidding does not apply (due to waiver or exemption), the utility retains its traditional obligation to offer to purchase capacity and energy from a Qualifying Facility (QF) at avoided cost upon reasonable terms and conditions approved by the PUC.
Technological developments. New emerging and breakthrough technological developments (e.g., the commercial development of long-duration energy storage, grid-forming and black starting inverters in low inertia power systems, microgrids, distributed generation, grid modernization, electrification of transportation, implement predictive analytics using artificial intelligence machine learning algorithms to help assess the state of health of utility assets and prevent premature failure, and the diversification of generation from renewable sources) may impact the Utilities’ future competitive position, results of operations, financial condition and liquidity. The Utilities continue to seek prudent opportunities to develop, test, pilot, and implement technologies that align with their technical and business plans and support clean energy and decarbonized goals, while ensuring reliability and resilience as the Utilities adapt to a changing climate.
Environmental matters. See “Electric utility—Regulation—Environmental regulation” under “Item 1. Business” and “Environmental regulation” in Note 3 of the Consolidated Financial Statements.
Commitments and contingencies. See Item 1A. Risk Factors, and Note 3 of the Consolidated Financial Statements for a discussion of important commitments and contingencies.
Off-balance sheet arrangements. See “Off-balance sheet arrangements” above in HEI Consolidated section.
Material estimates and critical accounting policies. Also see “Material estimates and critical accounting policies” above in HEI Consolidated section.
Regulatory assets and liabilities. The Utilities are regulated by the PUC. In accordance with accounting standards for regulatory operations, the Company’s and the Utilities’ financial statements reflect assets, liabilities, revenues and costs of the Utilities based on current cost-based rate-making regulations. The actions of regulators, including the PBR Framework, can affect the timing of recognition of revenues, expenses, assets and liabilities.
Regulatory liabilities represent amounts collected from customers for costs that are expected to be incurred in the future, or amounts collected in excess of costs incurred that are refundable to customers. Regulatory assets represent incurred costs that have been deferred because their recovery in future customer rates is probable. As of December 31, 2021, the consolidated regulatory liabilities and regulatory assets of the Utilities amounted to $997 million and $566 million, respectively, compared to $960 million and $767 million as of December 31, 2020, respectively. Regulatory liabilities and regulatory assets are itemized in Note 3 of the Consolidated Financial Statements. Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as changes in the applicable regulatory environment. Because current rates include the recovery of regulatory assets existing as of the last rate case and rates in effect allow the Utilities to earn a reasonable rate of return, management believes that the recovery of the regulatory assets as of December 31, 2021 is probable. This determination assumes continuation of the current political and regulatory climate in Hawaii and is subject to change in the future.
Management believes that the operations of the Utilities, including the impact of the newly approved PBR Framework, currently satisfy the criteria for regulatory accounting. If events or circumstances should change so that those criteria are no longer satisfied, the Utilities expect that their regulatory assets, net of regulatory liabilities, would be charged to the statement of income in the period of discontinuance, which may result in a material adverse effect on the Company’s and the Utilities’ results of operations, financial condition and liquidity.
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Revenues. Electric utility revenues are based on rates authorized by the PUC and include revenues applicable to estimated energy consumed in the accounting period, but not yet billed to customers (Unbilled revenues), and RBA revenues or refunds for the difference between PUC-approved target revenues and recorded adjusted revenues, which delinks revenues from kWh sales. Unbilled revenues represent an estimate of energy consumed by customers subsequent to the date of the last meter reading to the end of the current reporting period. As of December 31, 2021, Unbilled revenues, net of allowance for doubtful accounts, amounted to $129 million and the RBA revenue recognized in 2021 amounted to $20 million.
Asset retirement obligations. The Utilities recognize AROs at present value of expected costs to retire long-lived assets from service, which is estimated using a discounted cash flow model that relies on significant estimates and assumptions about future decommissioning costs, inflationary rates, and the estimated date of decommissioning. The estimated future cash flows are discounted using a credit-adjusted risk-free rate to reflect the risk associated with decommissioning the assets. The Utilities have not recorded AROs for assets that are expected to operate indefinitely or where the Utilities cannot estimate a settlement date (or range of potential settlement dates.) As such, ARO liabilities are not recorded for certain asset retirement activities, including various Utility-owned generating facilities and certain electric transmission, distribution and telecommunication assets resulting from easements over property not owned by the Utilities.
Changes in estimated costs, timing of decommissioning or other assumptions used in the calculation could cause material revision on the recorded liabilities. As of December 31, 2021 and December 31, 2020, the Utilities’ AROs totaled $11.1 million and $10.7 million, respectively.
Bank
Executive overview and strategy. ASB, headquartered in Honolulu, Hawaii, is a full-service community bank serving both consumer and commercial customers. ASB is one of the largest financial institutions in Hawaii and ended 2021 with assets of $9 billion and net income of $101 million, compared to assets of $8 billion and net income of $58 million in 2020.
ASB provides a wide range of financial products and services, and in order to remain competitive and continue building core franchise value, ASB is focused on making banking easier for the customer and developing and introducing new products and services in order to meet market needs. Additionally, the banking industry is constantly changing and ASB is making the investments in people and technology necessary to adapt and remain competitive, facilitate process improvements in order to deliver a continuously better experience for its customers, and be a more efficient bank. ASB’s continued focus has been on efficient growth to maximize profitability and capital efficiency, as well as control expenses. The current economic crisis from the COVID-19 pandemic altered the strategies ASB set out to achieve. Key strategies to drive organic growth include:
1.deepening customer relationships through the redesign of branch-centric approaches as transactions and engagement migrate to other channels;
2.building out product and service offerings to open new segments;
3.online and remotely-assisted account opening capabilities as there is a much more rapid and pervasive adoption of online and mobile banking by Hawaii banking customers; and
4.prioritizing efficiency actions to gain earnings leverage on organic growth.
The interest rate environment and the quality of ASB’s assets will continue to influence its financial results. A lowering of interest rates across the yield curve as a result of the pandemic’s impact on the economy has negatively affected ASB’s net interest margin and initially impacted credit losses. With the reopening of the economy and government stimulus assistance, asset quality has improved. The potential for further compression of ASB’s net interest margin if interest rates remain at current low levels is a risk that is actively managed.
As part of its interest rate risk management process, ASB uses simulation analysis to measure net interest income sensitivity to changes in interest rates (see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk”). ASB then employs strategies to limit the impact of changes in interest rates on net interest income. ASB’s key strategies to manage interest rate risk include:
1.attracting and retaining low-cost deposits, particularly those in non-interest bearing transaction accounts;
2.diversifying the loan portfolio with higher-spread, shorter-maturity loans and/or variable rate loans;
3.focusing investment growth in securities that exhibit less extension risk (i.e., risk of longer average lives) as rates rise.
Recent Developments—COVID-19. See also Recent developments—COVID-19 in HEI’s MD&A.
The Hawaii economy improved significantly in 2021, compared to 2020, due to the impact of stimulus programs and the loosening of business restrictions; however, the Hawaii economy experienced temporary setbacks with increased COVID-19 case counts stemming from the Delta variant in the third quarter of 2021 and the Omicron variant at the end of 2021. Although new daily case counts have continued to rise into early 2022 with a peak in late January, hospitalization rates have remained
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below rates experienced with the Delta variant, and as a result, the state and counties have not reinstituted the same level of restrictions that were put in place earlier in the pandemic and the Hawaii economy remains largely open for business.
Consistent with the improvement in the Hawaii economy in 2021, the bank’s performance improved in 2021, relative to 2020, with net interest income after provision for credit losses improving to $263.1 million for the year ended December 31, 2021, compared to $182.7 million for the year ended December 31, 2020, primarily driven by a negative provision for credit losses. Net interest margin declined to 2.91% for the year ended December 31, 2021, compared to 3.29% for the year ended December 31, 2020. The lower net interest margin was driven by the continued low interest rate environment that resulted in new loan origination rates remaining below existing portfolio yields. In addition, a change in the mix of earning assets, with a higher proportion of earning assets composed of investment securities which have a lower yield than the loan portfolio. The growth in the investment portfolio was driven by the growth in deposits, which grew at a faster pace than the loan portfolio resulting in excess liquidity being used to purchase investment securities. In the fourth quarter of 2021, the Bank’s net interest margin was 2.79% compared to 2.90% and 3.12% for the quarters ended September 30, 2021 and December 31, 2020, respectively.
For the year ended December 31, 2021, the investment securities portfolio increased approximately $900 million, or 41%, as deposit growth of $785 million, or 11%, which included funds from stimulus programs that were provided to individuals and businesses, continued to outpace loan growth. The growth in the investment securities portfolio and fees from the PPP program contributed to higher interest income, partially offsetting the effect of lower loan portfolio balances and earning asset yields on a year-to-date basis.
In response to COVID-19, ASB made short-term loan modifications to borrowers who were generally payment current at the time of relief. As of December 31, 2021, approximately $0.6 million of loans remained in their active deferral period. Approximately $9.0 million of loans were not able to resume their contractual payments and were considered delinquent as of December 31, 2021.
ASB recorded a negative provision for credit losses in 2021 due to improved credit quality in the commercial, commercial real estate and consumer loan portfolios and overall lower net charge offs as a result of an improving economic outlook. For the year ended December 31, 2021, ASB recorded a negative provision for credit losses of $25.8 million, compared to a provision for credit losses of $50.8 million for the year ended December 31, 2020. The provision for credit losses in future quarters will be dependent on future economic conditions and changes to borrower credit quality at that time.
In 2021, ASB collected higher fee income compared to 2020 as certain fees were waived during the second and third quarter of 2020 to accommodate the hardships facing its customers. The Bank restarted its normal fee practices in the fourth quarter of 2020 and continued throughout 2021. Noninterest expenses that were considered direct and incremental COVID-19 related costs were lower in 2021 compared to 2020.
In 2021, ASB reopened three branches that were temporarily closed during the start of the pandemic, as digital branches, which provide digital solutions such as full-service ATMs and access to expert bankers through videoconferencing tools while allowing the Bank to have a more efficient physical footprint. ASB continues to evaluate its branch network to determine whether further changes may be appropriate given its customers’ use of other banking channels.
ASB’s senior management team continually addresses the impacts to the operations and business of the Bank as a result of the pandemic and meets regularly with ASB’s board of directors to keep them apprised of the impacts of the COVID-19 pandemic.
The CARES Act was signed into law on March 27, 2020. The CARES Act provided over $2 trillion in economic assistance for American workers, families, and small businesses, and job preservation for American industries. The PPP was established under the CARES Act and implemented by the United States Small Business Administration (SBA) to provide a direct incentive for small businesses to keep their workers on the payroll as a result of the COVID-19 crisis. The Paycheck Protection Program Flexibility Act was signed into law on June 5, 2020 and the Economic Aid Act was signed into law on December 27, 2020, which amended some of the prior rules and guidelines of the CARES Act. The Economic Aid Act established a second round of PPP, reopening the PPP for first-time borrowers and allowing for a second draw for businesses that meet more restrictive eligibility criteria to target businesses hardest hit by the pandemic.Loans issued through the PPP are 100% federally guaranteed and have a maturity of 2-5 years, depending on when the loan was made, at a fixed interest rate of 1%. Loan payments will be deferred until the earlier of (a) the date that the forgiven amount is remitted to the lender by the SBA; or (b) 10 months from the date the covered period ends. The SBA will forgive all loan amounts to a particular small business if such small business is compliant with the terms and conditions of the PPP. Small businesses generally have 24 weeks from disbursement of the loan to incur allowable expenses such as payroll costs, interest on mortgages, rent and utility expenses that would be covered by the loan forgiveness rules, with 60% of the loan forgiveness needing to be for payroll costs. Small businesses may receive partial forgiveness if they do not spend the entirety of their PPP loan on eligible expenses, or if less than 60% of the loan disbursement is spent on payroll costs. Employers had until December 31, 2020 to restore their workforce, or,
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for a PPP loan made after December 27, 2020, before the last day of the Covered Period. Lenders processed and approved the PPP loans under delegated authority of the SBA. As an existing SBA certified lender, ASB worked with a number of small businesses, both customers and non-customers, to complete the loan application forms so that these businesses could participate in the program. During the first round of PPP, the Bank secured more than $370 million in PPP loans for approximately 4,100 small businesses that supported over 40,000 jobs, ASB received processing fees totaling approximately $13 million and started recognizing these fees over the life of the loans. During the second round of PPP, ASB secured more than $175 million for approximately 2,200 small businesses that supported more than 20,000 jobs; ASB received processing fees of approximately $9 million. The remaining PPP loans outstanding as of December 31, 2021 was $69 million.
Other provisions of the CARES Act provides that a financial institution may elect to suspend the requirements under accounting principles generally accepted in the United States of America (GAAP) for certain loan modifications that would otherwise be categorized as a TDR and any related impairment for accounting purposes. See Note 4 of the Consolidated Financial Statements and “Economic conditions” in the “HEI Consolidated” section above.
ASB continues to maintain its low-risk profile, strong balance sheet and straightforward community banking business model.
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Results of operations.
•2021 vs. 2020
(in millions) 2021 2020 Increase(decrease) Primary reason(s)
Average deposit yields decreased from 16 basis points to 6 basis points
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(in millions) 2021 2020 Increase(decrease) Primary reason(s)
Gain on sale of investment securities, net 1 9 (8)
Return on average equity2 13.8 % 8.1 % 5.7 %
1 Higher operating expenses, which were considered direct and incremental COVID-19 related costs, included approximately $2.5 million of incremental compensation expense and $2.0 million of enhanced cleaning and sanitation costs.
2 Calculated using the average daily balance.
For a discussion of 2019 results, please refer to the “Results of operations” section in Item 7, “Management Discussion and Analysis of Financial Condition and Results of Operations—Bank,” in the Company’s 2020 Form 10-K.
See Note 4 of the Consolidated Financial Statements for further information about ASB.
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Average balance sheet and net interest margin. The following table provides a summary of average balances, including major categories of interest-earning assets and interest-bearing liabilities:
Assets:
Investment securities
Loans
Liabilities and Shareholder’s Equity:
Noninterest bearing liabilities:
1Includes loans held for sale, at lower of cost or fair value, of $23.0 million, $20.5 million and $6.3 million as of December 31, 2021, 2020 and 2019, respectively.
2Includes recognition of net deferred loan fees of $14.3 million, $4.9 million and $0.2 million for 2021, 2020 and 2019 respectively, together with interest accrued prior to suspension of interest accrual on nonaccrual loans.
3For 2021, 2020 and 2019, the taxable-equivalent basis adjustments made to the table above were not material.
4Defined as net interest income, on a fully taxable equivalent basis, as a percentage of average total interest-earning assets.
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The following table shows the effect on net interest income of (1) changes in interest rates (change in weighted-average interest rate multiplied by prior year average balance) and (2) changes in volume (change in average balance multiplied by prior period weighted-average interest rate). Any remaining change is allocated to the above two categories on a pro rata basis.
(in thousands) Rate Volume Total Rate Volume Total
Interest income
Investment securities
Loans
Interest expense
Earning assets, costing liabilities, contingencies and other factors. Earnings of ASB depend primarily on net interest income, which is the difference between interest earned on earning assets and interest paid on costing liabilities. The interest rate environment has been impacted by disruptions in the financial markets over a period of several years. In 2020, the Federal Open Market Committee lowered its federal funds rate target range to 0% - 0.25% in response to the financial crisis caused by the COVID-19 pandemic, which resulted in a decrease in ASB’s net interest income and net interest margin. A prolonged low interest rate environment may continue to negatively impact ASB’s net interest income and net interest margin.
Loans and mortgage-backed securities are ASB’s primary earning assets.
Loan portfolio. ASB’s loan volumes and yields are affected by market interest rates, competition, demand for financing, availability of funds and management’s responses to these factors. See “Loans” in Note 4 of the Consolidated Financial Statements for a composition of ASB’s loan portfolio.
The increase in the loan portfolio balance in 2021 was primarily due to growth in the residential and commercial real estate loan portfolio balances. The growth in the residential loan portfolio balance was due to ASB’s decision to portfolio a larger portion of the residential mortgage loan production and reduce the amount of residential loans sold in the secondary market. The growth in the commercial real estate loan portfolio was due to ASB’s continued effort to diversify its loan portfolio with higher-spread, shorter-maturity loans and/or variable rate loans. The decrease in the commercial loan portfolio was due to paydown of the PPP loans which decreased from $300 million at December 31, 2020 to $69 million at December 31, 2021.
The increase in the loans balance in 2020 was primarily due to growth in the commercial, commercial real estate and HELOC loan portfolio balances, which were the portfolios targeted as ASB continued its loan growth strategy of diversifying the loan portfolio with higher-spread, shorter-maturity loans and/or variable rate loans.
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The following table summarizes loans held for investment based upon contractually scheduled principal payments allocated to the indicated maturity categories:
(in millions)
Residential land– Fixed 1 19 — — 20
Residential land – Adjustable — — — — —
Total residential land 1 19 — — 20
Commercial construction – Fixed — 15 1 — 16
Commercial construction – Adjustable 31 10 — 34 75
Residential construction – Fixed 11 — — — 11
Residential construction – Adjustable — — — — —
Total residential construction 11 — — — 11
Consumer – Adjustable 3 10 1 — 14
Home equitylines of credit. The home equity lines of credit (HELOC) portfolio makes up 16% of the total loan portfolio and is generally an interest-only revolving loan for a 10-year period, after which time the HELOC outstanding balance converts to a fully amortizing variable-rate term loan with a 20-year amortization period. Borrowers also have a “Fixed Rate Loan Option” to convert a part of their available line of credit into a 5, 7 or 10-year fully amortizing fixed-rate loan with level principal and interest payments. As of December 31, 2021, approximately 36% of the portfolio balances were amortizing loans under the Fixed Rate Loan Option. A HELOC loan is typically in a subordinate lien position to a borrower’s first mortgage loan, however, approximately 57% of ASB’s HELOC loan portfolio is in a first lien position.
Attention had been given by regulators and rating agencies to the potential for increased exposure to credit losses associated with HELOCs that were originated during the period of rapid home price appreciation between 2003 and 2007 as they have reached the end of their 10-year, interest-only payment periods. Once the interest only payment period has ended, payments are reset to include principal repayments along with interest. ASB does not have a large exposure to HELOCs originated between 2003 and 2007. Nearly all of ASB’s HELOC originations prior to 2008 consisted of amortizing equity lines that have structured principal payments during the draw period. These older equity lines represent 1% of the HELOC portfolio.
Loan portfolio risk elements. When a borrower fails to make a required payment on a loan and does not cure the delinquency promptly, the loan is classified as delinquent. If delinquencies are not cured promptly, ASB normally commences a collection action, including foreclosure proceedings in the case of real estate secured loans. In a foreclosure action, the property collateralizing the delinquent debt is sold at a public auction in which ASB may participate as a bidder to protect its interest. If
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ASB is the successful bidder, the property is classified as real estate owned until it is sold. As of December 31, 2021 and 2020, ASB had nil real estate acquired in settlement of loans.
In addition to delinquent loans, other significant lending risk elements include: (1) loans which accrue interest and are 90 days or more past due as to principal or interest, (2) loans accounted for on a nonaccrual basis (nonaccrual loans), and (3) loans on which various concessions are made with respect to interest rate, maturity, or other terms due to the inability of the borrower to service the obligation under the original terms of the agreement (troubled debt restructured loans). ASB loans that were 90 days or more past due on which interest was being accrued as of December 31, 2021 and 2020 were immaterial or nil. The following table sets forth certain information with respect to nonaccrual loans:
(dollars in thousands)
Real estate:
Commercial construction — —
Residential construction — —
Nonaccrual loans to loans receivable, net 0.86 % 0.89 %
Allowance for credit losses to nonaccrual loans 1.58x 2.14x
In 2021, nonaccrual loans decreased $2.4 million primarily due to decreases in commercial real estate, commercial, consumer and HELOC nonaccrual loans of $3.4 million, $3.0 million, $2.1 million and $1.8 million, respectively, partly offset by an increase in residential 1-4 family nonaccrual loans of $7.9 million. The increase in residential nonaccrual loans was attributed to customers that could not resume contractual payments after their deferral period was completed.
In 2020, nonaccrual loans increased $17.7 million primarily due to an increase in commercial real estate nonaccrual loans of $18.5 million. The increase in commercial real estate nonaccrual loans was primarily attributed to one commercial credit.
See “Allowance for credit losses” in Note 4 of the Consolidated Financial Statements for information with respect to nonperforming assets.
Allowance for credit losses. See “Allowance for credit losses” in Note 4 of the Consolidated Financial Statements for the tables which sets forth the allocation of ASB’s allowance for credit losses. On January 1, 2020, ASB adopted Accounting Standards Update (ASU) 2016-13, Financial Instruments - Measurement of Current Expected Credit Losses on Financial Instruments, modifying the accounting for the allowance for credit losses from an incurred loss model to an expected loss model (see Note 1, “Summary of Significant Accounting Policies” of the Consolidated Financial Statements). With the adoption of ASU 2016-13, ASB added $19.4 million to the allowance for credit losses on January 1, 2020. During 2021, ASB recorded a negative provision for credit losses related to the allowance for credit losses of $26.4 million primarily due to decreased reserves for the commercial real estate, commercial and consumer loan portfolios for improved credit quality in those loan portfolios and a lower personal unsecured loan portfolio balance, which has a higher loss rate than other loan portfolios. During 2020, ASB recorded a provision for credit losses related to the allowance for credit losses of $49.8 million primarily due to increased reserves for the commercial, commercial real estate and consumer loan portfolios for expected credit deterioration due to the COVID-19 pandemic and additional loss reserves to cover net loan charge-offs.
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